Historically, Germany’s natural gas supply has been largely based on imports from Russia. In 2020, the Russian share of German natural gas imports was 55%, followed by Norway (31%) and the Netherlands (13%) . Russian imports reached Germany via three large pipeline systems that connect the Siberian natural gas fields with Europe. These are Nord Stream 1, which runs through the Baltic Sea to Germany, the Yamal-Europe pipeline, which runs through Belarus and Poland to Germany, and the widely ramified Ukraine pipeline system, which can transport natural gas to Germany in a branch via Slovakia and the Czech Republic . The Nord Stream 2 pipeline, which runs parallel to Nord Stream 1, was completed in 2021, but the approval process for commissioning was halted shortly before the Russian invasion of Ukraine .
As a result of the Russian invasion, natural gas deliveries via Nord Stream 1 have fallen to 350 GWh/day at the time of the finalisation of these article (beginning of August), which is about 20% of the potential capacity . Since then the gas deliveries through Nord Stream stopped and the pipelines are no longer useable due to explosions. No Russian natural gas is currently being delivered to Germany via the pipeline system through Ukraine and via Yamal-Europe as well .
Planned LNG terminals
In order to compensate for supply shortfalls and to reduce dependence on Russian gas supplies and generally diversify gas imports, the German government wants to build terminals for LNG. Due to the tense situation with a view to the next winters, the LNG Acceleration Act (LNGG) was passed to enable the planning and construction of LNG terminals in the short term . Among other things, this includes exemptions from the environmental impact assessment or the shortening of the duration of public participation.
|FSRU Brunsbüttel||50 TWh/a||FSRU (state-owned)||End of 2022||Gasunie|
|Terminal Brunsbüttel||80 – 100 TWh/a||Land-based terminal||2026||Gasunie|
|FSRU Wilhelmshaven 1||50 TWh/a||FSRU (state-owned)||End of 2022||Uniper|
|FSRU Wilhelmshaven 2||Kapazität nicht bekannt||FSRU (private)||2023||NWO|
|FSRU Wilhelmshaven 3||Kapazität nicht bekannt||FSRU (private)||2023||Eon, TES|
|Terminal Wilhelmshaven||160 – 200 TWh/a||Land-based terminal||2025||TES|
|FSRU Stade||50 TWh/a||FSRU (state-owned)||End of 2023||Hanseatic Energy Hub|
|Terminal Stade||130 TWh/a||Land-based terminal||2026||Hanseatic Energy Hub|
|FSRU Hamburg||Currently no information, is considered unlikely|
|FSRU Lubmin 1||50 TWh/a||FSRU (state-owned)||End of 2023||RWE, Stena-Power|
|FSRU Lubmin 2 (not in the LNGG)||45 TWh/a||FSRU (private)||End of 2022||Deutsche ReGas|
The implementation of the projects at the Rostock and Hamburg sites is considered unlikely . With regard to the Brunsbüttel, Wilhelmshaven and Stade sites, it is assumed that the FSRUs there will serve as a temporary solution until the planned land-based terminals are completed . Subsequently, LNG imports are to come into the country via these completely on land infrastructures in the medium to long term. The Lubmin site is not suitable for the construction of a land-based terminal because the water depth is too shallow . However, as relevant gas pipelines for the supply of eastern and south-eastern Germany run from here, it is assumed that it will also be possible to land LNG here via FSRUs in the longer term. No capacities are known for the FSRUs Wilhelmshaven 2 and 3. For the following evaluation, it is assumed that these amount to 50 TWh/a each, in line with the other FSRUs.
Most important terms
LNG – Liquefied Natural Gas: Natural gas is cooled to minus 163°C and liquefied. This significantly increases the volumetric energy density and enables it to be transported by ship. In the port of import, the LNG is then vaporised again and fed into the natural gas grid in a gaseous state.
FSRU – Floating Storage and Regasification Unit: Floating facility at which LNG tankers can dock and discharge the loaded LNG. Storage and regasification take place on the FSRU. The gas is then injected into the gas grid via a connecting pipeline to the mainland.
Land-based terminal: LNG terminal permanently installed on land, usually with several berths. The complete infrastructure for storage, regasification and injection of the gas is located on land.
Potential fossil fuel service life
Against the background of Germany’s climate neutrality target by 2045, these significant planned capacities for LNG imports raise the question of how long these terminals are expected to be needed for the import of fossil LNG. At the same time, it is also of interest whether these capacities are sufficient to compensate for a possible complete loss of Russian gas supplies in the short to medium term.
To be able to estimate this, we compare the future natural gas demand of different target scenarios (climate neutrality in Germany in 2045) with the expected future non-Russian imports via pipeline and LNG (and Germany’s own production).
In 2020, just under 550 TWh of Germany’s natural gas demand was provided by non-Russian sources. Of this, 343 TWh was imported from Norway, 143 TWh from the Netherlands and 18 TWh from other European countries by pipeline. In addition, 44 TWh of natural gas were produced in Germany . Since these European countries are planning to reduce production in the future, the 550 TWh of natural gas supplied in 2020 cannot be assumed to be constant for the future. In order to be able to represent the possible future non-Russian gas supply, data from the Ten-Year Network Development Plan (TYNDP) 2018 of ENTSOG  is therefore used with regard to the future development of gas production volumes in the corresponding countries. Within the framework of this evaluation, it is assumed that imports to Germany will develop in direct proportion to the development of natural gas production in these countries.
With regard to the capacities of the LNG terminals, it is assumed that at the locations where land terminals are built, the FSRUs will be dismantled at the time of terminal completion. For Lubmin, the capacities of the FSRUs are classified as available for the entire period for the reasons mentioned above.
It should be noted that neither possible expansions of production in response to a lack of Russian deliveries nor possible additional LNG imports to Germany via terminals in other European countries are taken into account. These could increase the values given in Figure 2 under “Non-Russian pipeline imports”. In combination with the LNG capacities described, this results in the potential for the provision of gas from non-Russian sources over time.
In order to be able to classify the described future import volumes, we consider the historical natural gas demand in Germany. This was 1016 TWh in 2021, an increase of 51 TWh compared to 2020, which can be explained mainly by the economic recovery after the Corona crisis year 2020 . In the period from January to July 2022, natural gas consumption was 18 % below the level of the previous year . On the one hand, this can be explained by a higher average temperature and correspondingly lower heating demand in the months of January and February . The strong decrease in the summer months is probably due to savings in industry as a result of high gas prices. If this trend were to continue until the end of the year, this would result in an annual gas consumption of 829 TWh, which is indicated by a dashed line in Figure 2. A decrease in gas consumption in this range would thus also be in line with the goals of the EU’s Gas Saving Plan, which envisages a 15% reduction in gas consumption in the period from 1 August 2022 to 31 March 2023 .
In order to be able to put the expected future import capacities as well as the historical gas demand in relation to the future development of the gas demand, three energy system studies from the year 2021, which show this gas demand in a resolution of 5-year steps, are used for the period from 2025. These are the “Ariadne Report – Germany on the Way to Climate Neutrality 2045” , the “dena Leitstudie Aufbruch Klimaneutralität”  and “Klimaneutrales Deutschland 2045” . An average value of the corresponding scenarios was calculated from . In the other two studies, there is no subdivision into further scenarios, so that the values for the scenarios dena KN100  and Agora KND2045  are given here. It must be taken into account that these scenarios were created before the current developments in the course of the war against Ukraine. With regard to the effects of these current developments on long-term gas demand, no reliable data and information are available at this stage.
Convertibility of the LNG terminals
With regard to the future operation of the land-based terminals with climate-neutral hydrogen and hydrogen derivatives mentioned in the LNG Acceleration Act, it is worth taking a look at the convertibility of the LNG terminals to such green gases. Since investment decisions have to be made at the moment – triggered by the crisis – which can lead to lock-in effects, it is important to consider the convertibility of the terminals already in the current planning phase. A lock-in effect in this context describes a situation in which, due to a lack of technical or financial convertibility, terminals are operated with LNG for longer than would be beneficial for achieving the German climate targets. The technical and financial effort required for a conversion is strongly dependent on the green gas to be landed (see Box – Potential green energy sources for import via ship).
Potential green energy sources for import via ship
Methane – CH4: Produced synthetically from green hydrogen and a carbon source, then liquefied and could use the infrastructure for LNG imports.
Ammonia – NH3: Produced from green hydrogen and nitrogen captured from the air via industrially established processes and liquefied for transport. Can be used directly as a raw material and energy carrier. Otherwise, the nitrogen must be split off again in a cracker.
Liquid hydrogen – LH2: Analogous to LNG/green methane and ammonia, hydrogen is cooled to a boiling point of minus 253°C, liquefied and thus made transportable by sea. Due to the very low boiling point, more energy must be used for this than for ammonia or methane. On the other hand, conversion losses that occur with these energy sources can be avoided.
Methanol – CH4O: Is present in a liquid state at ambient temperature and can therefore be transported with less effort than NH3, CH4 and LH2. It can be used directly as an energy source. It is also an important intermediate product in the chemical industry.
Liquid Organic Hydrogen Carrier – LOHC: A group of organic substances such as cyclohexane, which exist in liquid form at room temperature and serve as a medium for hydrogen transport. In the port of import, hydrogen is split off from the LOHC and the dehydrated form of the LOHC is transported back to the port of export.
If liquefied synthetic methane is imported in the future, this would be possible with the same infrastructure as LNG. A conversion of the plants would not be necessary and a mixed operation of importing LNG and synthetic methane would be feasible in a transitional phase.
If synthetic energy sources are imported in the form of green ammonia, the additional costs for retrofitting are likely to be in the range of 10-20% of the original investment sum [11, 21]. On the one hand, the pumps that pump the energy source into the storage tanks have to be replaced. On the other hand, it is also necessary to adapt the regasification system and the boil-off gas handling system. If the tanks are not already designed for ammonia in the form of stronger foundations, they can only be used with lower capacity due to the specifically higher weight of ammonia . Overall, however, the technical and financial expenditure is relatively limited, as large parts of the infrastructure can continue to be used without adjustments . With an expected investment volume of about one billion euros for the land-based terminal in Brunsbüttel , for example, this would also be relevant conversion costs even in absolute terms.
Due to greater differences in physical properties, there are also greater technical requirements when converting LNG terminals to liquid hydrogen (LH2). Hydrogen only exists in liquid form at minus 253°C, whereas minus 163°C is sufficient for natural gas. This results, for example, in significantly higher requirements for the tanks with regard to thermal insulation [11, 22]. With regard to explosion protection, the requirements for LH2 are also significantly higher than those for LNG . There are differing opinions on whether retrofitting the plant to LH2 is technically possible [11, 22]. Since this would also require the replacement of long-lasting large components, such a conversion would probably not be economically viable, regardless of the technical feasibility. For this reason, the VDI (The Association of German Engineers), among others, recommends designing such a plant for LH2 from the outset .
If energy carriers such as LOHC or methanol are used, which are in a liquid state at ambient temperature, regasification plants are no longer needed. In the case of LOHC, this would require dehydrogenation plants to separate the hydrogen from the LOHC and storage facilities for the dehydrogenated LOHC .
It can be stated that the use of the planned terminals is in principle also possible with green gases and energy carriers. Depending on which energy source is to be imported, however, it is advisable to design relevant components of the plant accordingly in order to avoid expensive conversions.
Lock-in effects would probably be possible above all in a future development in which LH2 proves to be the dominant form of transport and a lack of availability of alternative green energy sources such as ammonia results. In such a scenario, the difficulties of retrofitting LNG terminals to LH2 could ensure a fossil fuel useful life of these terminals that would go beyond what is permissible to achieve the German climate targets. However, since, as shown in Figure 3, ammonia and LOHC are expected to have lower transport costs compared to LH2 , such a scenario seems unlikely.
Terminals for green energy imports
In addition to the possibility of converting LNG terminals to green gases, which has just been discussed, we will also consider how the capacities of the planned terminals compare with the expected demand for green hydrogen and hydrogen derivatives. For this purpose, the demand of the dena KN100 scenario is used, which shows demand values for the period from 2030 .
This is compared with the theoretically free capacities in the LNG terminals according to the previous evaluation. For each year, the scenario with the highest gas demand is selected in order to avoid overestimating the free capacities. Since it is not known which energy source will be imported in the future, it is assumed for simplicity that the capacity for green gases corresponds to that for LNG. Furthermore, it is assumed for the rough estimate that fossil LNG and green gases can be landed at the same time via a terminal. This would only be technically possible if synthetic methane is chosen as the green gas, if parallel infrastructures are to be avoided.
The rapid provision of FSRUs for the import of LNG and the subsequent completion of land-based terminals should secure Germany’s supply of natural gas in the coming years. If all the projects considered for the above evaluation are realised, it can be expected that after the completion of all FSRUs, security of supply can be ensured from the end of 2023 even in the event of a complete absence of Russian natural gas supplies. By this time, however, a relevant shortage situation would be expected, which would probably lead to restrictions and price increases.
In the further course of time, however, it seems realistic that relevant overcapacities for the import of LNG already exist before 2030. If all projects are realised in the currently known capacity, this will result from a further decline in demand for fossil natural gas in the future. If, according to this evaluation, natural gas imports by pipeline continue beyond 2030, LNG imports could be completely eliminated from 2035 to 2039 at the earliest.
Since it is likely that energy sources – which will then be climate-neutral – will also have to be imported to Germany by sea in the future, it should be technically and economically possible to convert the planned LNG terminals to green energy sources. On the other hand, there would be a threat of lock-in effects that could lead to imports of LNG beyond the period permitted under Germany’s climate targets.
Depending on the green energy carrier to be imported, the technical and financial challenges differ, so it is important to take this into account at the planning stage. In the case of LH2 in particular, however, a corresponding conversion is likely to be difficult. That green energy sources can be imported via the terminals now planned seems rather likely due to less problematic alternatives such as green ammonia or synthetic methane, despite some challenges.
If the LNG capacities that become available were to be converted or changed over accordingly, the entire demand for hydrogen and derivatives could be met via these terminals until beyond 2040. Even after that, the capacities should be sufficient in view of own production and imports via pipeline, so that no further terminals would be necessary and probably not all terminals would have to be converted.
The contents listed here are based on results from the project “Trans4ReaL – Scientific Transfer Research for Real Laboratories on Sector Coupling and Hydrogen Technologies” (funded by the German Federal Ministry of Economics and Climate Protection; funding reference 03EWT001A) as well as from the project “TransHyDE-Sys – System Analysis on Transport Solutions for Green Hydrogen” (funded by the German Federal Ministry of Education and Research; funding reference 03HY201D). The responsibility for the content of this publication lies with the authors.
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