9 TYNDP 2026 Scenario results //

This chapter provides an overview of the evolution of energy supply in the European Union within the TYNDP 2026 scenarios. It begins with total primary energy supply¹ in NT+ Scenario, setting out the overall decarbonisation trajectory characterised by declining fossil fuel use, increasing energy efficiency, and the expansion of renewable energy sources. Across this chapter, the study of the economic variants (LEV and HEV) highlights how different macroeconomic conditions primarily affect the scale of the energy system while leaving the structural transformation largely unchanged. The chapter then covers the evolution of the fossil fuel share, followed by a comprehensive analysis of electricity supply as a key vector of decarbonisation, including generation mix and flexibility needs.

The next dedicated sections subsequently address the transformation of gas and methane supply, the scale‑up of hydrogen and the flexibility of operation in this vector, the role of e‑fuels and biomass, and the evolution of energy imports, providing a consistent cross‑carrier view of how different energy vectors contribute to the transition. Finally, the chapter includes a targeted sensitivity analysis focusing on hydrogen supply to complement the economic variants. This analysis assesses the robustness of the central scenario with respect to uncertainties in the balance between domestic production and imports.

The European energy supply decarbonises through the development of renewable capacities and implementation of energy efficiency measures. In the NT+ scenario, total primary energy supply is reduced by 16.87 % by 2030 and 20.3 % by 2050 compared to 2023 levels, despite increasing demand for electricity and synthetic fuels. This decline is driven primarily by the replacement of fossil fuels with more efficient low‑carbon technologies and by structural efficiency gains across end‑use sectors. Figure 49 illustrates the evolution of the EU27 primary energy supply mix in absolute terms. Fossil fuels decline rapidly over the period, with coal nearly phased out by 2035 and oil and natural gas volumes reduced by around 90 % by 2050 compared to 2023. Natural gas progressively shifts from a dominant energy carrier to a residual and adequacy‑oriented role, supporting system flexibility and security of supply rather than serving as a primary energy source.

In parallel, Renewable Energy Sources (RES) expand substantially. Wind and solar increase more than twofold by 2030 and reach approximately seven‑ to eight‑fold their 2023 levels by 2050, becoming the backbone of the EU energy system. Biomass and renewable gases (biomethane, biogas and synthetic methane) grow steadily, supporting decarbonisation in sectors that are more difficult to electrify.

While Figure 49 highlights the absolute decline in fossil energy volumes, Figure 50 shows the corresponding structural transformation of the energy mix. By 2050, RES account for roughly 70 % of total primary energy supply, with wind and solar alone representing more than 35 % of the total mix, compared to less than 5 % in 2023. Nuclear energy remains relatively stable in absolute terms over the long term, but its share of total primary energy declines, reflecting the faster expansion of renewable generation. Hydropower remains broadly constant, continuing to provide a stable and dispatchable renewable contribution.

The NT+ scenario serves as the main reference for this exercise, reflecting existing national policies and announced measures. Since the Economic Variants are derived from NT, they differ with NT+ Scenario when comparing total primary energy or carriers affected by the gap-filling methodology (explained in the associated chapter from the methodology report). To better assess the economic variants in those two sections, the NT Benchmark (NT BM)² was developed to be used as an ancillary reference. NT Benchmark positions itself between the HEV and the LEV, enabling a systematic exploration of sensitivities related to macro‑economic developments.

As shown in Figure 51, higher economic growth in HEV results in a larger energy system, with higher absolute primary energy supply volumes across most energy carriers, particularly electricity-based renewables, hydrogen and biomethane. Fossil fuel demand declines more slowly in absolute terms, especially in hard-to-abate industrial and transport segments, leading to higher residual use of oil and natural gas in 2035 and 2040. Conversely, LEV results in a smaller energy system.

Lower industrial activity and transport demand significantly reduce oil and natural gas consumption, while renewable deployment proceeds at lower absolute volumes. The overall energy mix remains structurally similar to NT.

Figure 52 shows the percentage contribution of fossil fuels, nuclear, and RES (including biomass, wind, solar, hydro, and other RES) to total primary energy supply.

Figure 52 confirms that economic growth assumptions primarily affect absolute volumes rather than the relative composition of the energy mix. Across all variants, RES consistently dominate primary energy supply by 2040, indicating that the direction of the energy transition remains robust under different macro-economic conditions. Overall, the comparison shows that economic growth assumptions primarily affect total energy volumes, rather than the direction of the energy transition. HEV and LEV define upper and lower bounds for demand, investment and system sizing, supporting future robustness testing of scenario outcomes within the TYNDP framework.

TYNDP scenarios show a pronounced shift in the primary energy supply towards renewable sources (Figure 53). In the NT+ Scenario, the share of RES in the total primary energy supply reaches 72 % by 2050. Renewable supply is dominated by wind and solar photovoltaic generation, complemented by biomass and energy recovered from waste. Low‑carbon sources, notably nuclear energy and blue hydrogen, also contribute to the decarbonisation of the energy system. Together, these sources account for around 18 % of the total primary energy supply in the NT+ Scenario. In parallel, the share of fossil fuels declines significantly over time. By 2050, coal represents only 0.2 % of the total primary energy supply, while oil accounts for 4.4 %. The remaining oil demand is largely concentrated in hard‑to‑abate segments, including international aviation and maritime bunkering, as well as non‑energy uses.

The evolution of the primary energy supply mix reflects a structural transition from a system historically dominated by fossil fuels to one largely based on RES. Although fossil fuels currently account for around 70 % of the primary energy supply, their role is steadily diminishing as the energy system is reshaped by electrification, efficiency improvements and the large-scale deployment of renewable generation. By 2040 and beyond, renewables will form the backbone of the primary energy supply, with fossil fuels being confined increasingly to residual demand in specific sectors where substitution remains challenging. This shift is fundamental to the long-term decarbonisation trajectory and has significant implications for infrastructure planning, system flexibility and security of supply.

Under the LEV, fossil fuel use remains higher, primarily driven by a stronger persistence of oil consumption. In contrast, the HEV shows a comparatively higher reliance on fossil fuels linked to natural gas, associated with higher energy demand under stronger economic growth.

In the NT+ scenario, one of the main vectors for the decarbonisation of the energy system is electricity: final demand nearly doubles by 2050, variable renewables supply most energy, and a portfolio of firm low‑carbon generation and flexibility options help ensure adequacy under increasingly climate‑dependent operating conditions. As can be seen in Figure 23, total electricity demand is expected to increase, driven by direct higher shares of electrification and an expansion in the production of renewable fuels through electrolysis. By 2050, the electricity required for electrolysis is expected to represent around 20 % of the total electricity demand in the NT+ scenario. The generation figures presented in this chapter therefore reflect total electricity requirements, encompassing both final consumption and electrolysis-related demand.

Figure 55 distinguishes final electricity consumption (including transmission and distribution losses) from electricity demand for hydrogen and synthetic fuel production via electrolysis. The NT+ scenario assumes a rapid decarbonisation of electricity generation over the assessment horizon, as illustrated in Figure 56. By 2035, around 96 % of total electricity generation in the EU27, (including electricity used for electrolysis) is expected to be delivered by RES (i. e. wind, solar), nuclear and gas-fired power plants supplied with renewable and decarbonised gases. Toward 2050, variable RES become the backbone of the electricity system, accounting for around 75 % of total electricity generation, compared with 53 % in 2030 and 30.7 % in 2025. Firm low‑carbon technologies continue to complement variable generation, ensuring system adequacy and security of supply. As a result, electricity generation is nearly fully decarbonised by 2050, with only a very limited residual contribution from carbon‑emitting sources.

Meeting the strong growth in electricity demand requires a substantial expansion of generation and storage capacity across all target years (Figure 57). Wind and solar capacities increase sharply, reaching around 1,086 GW in 2030 and 2,041 GW by 2040. This expansion is essential to meet decarbonisation, energy efficiency, and renewable energy targets, as well as to supply electricity for renewable fuel production to replace fossil fuels. While wind and solar represent the dominant capacity additions, they are complemented by other RES such as hydro and biomass, with hydro remaining the most significant among them. Firm low‑carbon capacities, notably nuclear and hydrogen‑fired power plants, remain an integral part of the system, ensuring adequacy and resilience in a system with high shares of variable renewables (Figure 57).

Coal and lignite are progressively phased out under the combined effect of national phase‑out policies and increasing CO₂ prices along the ETS trajectory, becoming almost negligible in electricity generation from 2030 onwards. Gas‑fired power generation undergoes a structural change in its system role. While total electricity generation from gas decreases significantly towards 2050 (Figure 58), gas‑based technologies increasingly provide flexibility rather than baseload energy.

Methane is progressively decarbonised through rising shares of biomethane and synthetic methane, while hydrogen‑fired power plants expand substantially over time (Figure 59).

The declining average full‑load hours of both methane‑ and hydrogen‑fired power plants (Figure 60) reflect their evolving role as dispatchable and adequacy-providing resources, activated primarily during periods of low renewable generation. Despite lower utilisation levels, these units remain essential in covering prolonged periods of scarce renewable output, during which they can be fully dispatched.

High shares of variable renewable generation are supported by a diverse portfolio of flexibility solutions. Short‑term flexibility is provided by batteries, pumped hydro storage, demand‑side response, flexible operation of electrolysers, and electric vehicle charging, including vehicle‑to‑grid (V2G) services (Figure 61). These flexibility options substantially reduce the need for thermal generation to operate at high load factors, shifting its role towards system adequacy.

For longer periods of time where flexibility needs arise, such as weeks where Dunkelflaute conditions are given, the use of cross-border interconnections and dispatchable resources ensure system adequacy. In this context, interconnectors and gas and hydrogen-based technologies play a central role in providing flexibility and ensuring supply.

Potential limitations that may affect the feasibility of the identified flexibility options should be further and more thoroughly assessed in forthcoming TYNDP scenario cycles, as well as in complementary assessments such as the European Resource Adequacy Assessment (ERAA).

Flexibility requirements are expected to increase, together with the diversity of technologies contributing to their provision. The electrification of the heating sector and the continued deployment of wind and solar generation will increase the climate dependency of the electricity system. At the same time, the effects of global warming on weather variability are already observable. Consequently, the decarbonisation of the electricity mix must be accompanied by the parallel development of flexibility solutions in order to preserve security of supply. The extent of the flexibility needs and the development of technologies to meet depend on the scenario assumptions. The scenario shows a joint usage of upstream flexibility (generation side) and downstream flexibility (consumer side) to adequate for the evolving needs of the electricity system.

The development of prosumer behaviours will result in a high development of residential batteries and V2G services providing short term storage solutions. Finally, the need to produce synthetic fuels to help achieve decarbonisation targets may also offer the opportunity of seasonal flexibility by coupling the electricity and hydrogen systems. Electrolysis and hydrogen storage will then be beneficial to the security of the energy system.

The scenario shows a flexible consumer behaviour, with PV-connected household batteries and bidirectional usage of electric vehicles. In addition to that, utility-scale batteries are used in the same order of magnitude as hydro pump storages. As a takeaway, the results of this exercise show that system adequacy is ensured through a combination of storage, demand-side flexibility and firm generation.

The increasing relevance of climate conditions for system operation is illustrated through detailed simulations of representative weather situations. In Figures 62, 63 and 64 below, hourly dispatch results for 2040 show how the system maintains balance during periods of high winter demand as well as during prolonged episodes of low wind and solar generation (Dunkelflaute).

These examples highlight the critical contribution of firm low‑carbon generation, storage, and demand‑side flexibility in preserving security of supply under stressed operating conditions.

Overall, the NT+ scenario illustrates a credible pathway towards a highly electrified, nearly fully decarbonised, and climate‑resilient European power system by 2050, in which large‑scale deployment of renewable energy is complemented by firm low‑carbon generation and an expanding portfolio of flexibility solutions to ensure long‑term security of supply.

Electricity supply variants are designed as economic stress‑tests of the central scenario, providing a structured assessment of how alternative demand and cost trajectories affect the evolution of the electricity generation mix, the role of firm capacity, and the level of flexibility required to ensure system adequacy and security of supply. The variants explore the robustness of the electricity system under lower (LEV) and higher (HEV) electricity demand and electrification assumptions compared with the National Trends + (NT+) scenario (Figure 65).

Across all variants, electricity plays a central role in the decarbonisation of the European energy system, driven by direct electrification and the growing use of electricity for the production of renewable and synthetic fuels through electrolysis.

Differences between variants primarily affect the scale and timing of capacity deployment, rather than the overall direction of system transformation.

The generation mix remains strongly aligned across variants (Figure 66). Variable RES (wind and solar) provide the dominant share of electricity generation in all cases. By 2035, wind and solar jointly account for approximately 65–70 % of total generation, increasing further towards 2040. The HEV variant shows a slightly lower renewable share, reflecting higher levels of dispatchable generation required to meet peak demand and flexibility needs.

Electricity supply scope of the Economic Variants confirms a rapid phase‑out of fossil fuel‑based electricity generation (Figure 67):

The HEV variant shows the highest reliance on dispatchable capacity and flexibility, reflecting higher electricity demand and peak load levels, while the LEV variant relies more strongly on variable renewables and downstream flexibility (Figure 68 and Figure 69).

Hourly dispatch simulations demonstrate that, across the variants and target years, the electricity system is able to maintain balance during periods of high demand and during extended periods of low wind and solar generation. Firm dispatchable low‑carbon generation, storage technologies, and demand‑side flexibility jointly ensure adequacy, highlighting the resilience of the system architecture assumed in the scenarios.

Overall, the electricity supply variants confirm that:

Figure 70 provides an overview of the methane supply in the NT+ scenario together with the current figures. Total methane supply declines steadily towards 2050, reaching approximately half of the 2030 level. While domestic natural gas production decreases continuously and is almost phased out by 2050, domestic biomethane production increases substantially, reaching around 800 TWh / year and becoming the largest component of methane supply.

Over the same period, imports of natural gas decline significantly, falling from nearly 2,500 TWh / year in 2030 to approximately 600 TWh / year in 2050. Domestic e‑methane production plays only a minor role throughout the period, whereas imports of e‑methane increase steadily towards 2050.

As shown in Figure 71 and Figure 72. The increasing share of biomethane and e methane, primarily produced domestically, more than compensates for the decline in domestic natural gas production.

The reduction in methane imports highlights the importance of domestic renewable methane production for enhancing the energy independence of the EU. Furthermore, the growing share of renewable gases in the gas system underlines their crucial role in the decarbonisation of the EU energy system.

The main differences between the variants and the NT+ scenario are observed in the total methane supply. The high economic variant exhibits the highest demand, while the low economic variant shows the lowest. As domestic supplies of natural gas and biomethane are fixed based on the data assumptions, the only factor contributing to these differences is the level of imported natural gas.

Today hydrogen is mainly used as a feedstock in the chemical and fertiliser industry in the EU. The Hydrogen is mainly produced with SMR / Autothermal Reforming (ATR) (90 %) while the remaining volumes are from by-products from other industrial processes (8 %) and only a small fraction is produced with water electrolyses or reforming with CCS. In the NT+ scenario, the EU energy system increasingly integrates hydrogen as an energy carrier towards 2050. As described in detail in the demand section the hydrogen consumption growth is expected in energy conversion (power generation, synthetic fuels production), and its role as a feedstock in industrial processes will grow as well, but in a more limited way.

As shown in Figure 74, the supply of hydrogen is growing from around 250 TWh in 2030 to more than 1,600 TWh in 2050. The hydrogen in the NT+ scenario is mainly produced by electrolysers in EU, while imports via ships or pipelines as well as SMR with CCS will be less used sources. SMR without CCS and Pyrolysis were hardly used and only present in a few countries.

The share of imported hydrogen is highest in 2030 (27 %) and lowest in 2035 (18 %), but in absolute figures the volume of imports increases from 69 TWh in 2030 to 237 TWh in 2050 (see Figure 75).

Table 2 below shows the hydrogen corridors used and the origins of the imported hydrogen.

In the initial target years (2030 and 2035), pipeline imports are limited to Italy and Ukraine, with Italy accounting for the largest share. By 2040, additional infrastructure will become operational, notably the Morocco–Spain connection, enabling hydrogen transport to Europe. Furthermore, a connection to the United Kingdom will support system balancing within the EU. In both 2040 and 2050, the UK is expected to function as an additional hydrogen supply source for the EU.

Table 3 presents import hydrogen volumes transported via ships, including their points of arrival. The data shows that the Netherlands, Belgium, and Germany act as early movers in the import of ammonia (liquefied hydrogen) and remain the dominant importers across all target years.

France is expected to scale up its ammonia imports at a later stage but will reach substantial import volumes by 2040 and 2050. Greece and Italy are projected to begin ammonia imports around 2040. In contrast, Poland remains the smallest importer throughout all considered target years.

Figure 76 shows the results for the high and low economic variants. Overall, the difference in total hydrogen (H₂) supply between the two variants is relatively small.

However, more pronounced differences appear when comparing the composition of H₂ supply. In the low economic variant, green hydrogen production via P2G increases, whereas it declines in the high economic variant. By contrast, both hydrogen imports and H₂ production via steam methane reforming (SMR) are higher in the high economic variant than in the low variant.

This indicates that higher electricity demand in the high economic variant shifts hydrogen production away from P2G, as electricity becomes a scarce / expensive resource. Instead, supply is increasingly met through imports and SMR-based production.

To support the hydrogen network, that in the startup phase is characterised by a baseload demand and dispatchable supply, hydrogen storages plays a critical balancing role. In the future the hydrogen system is supposed to see a higher need for flexibility when hydrogen for heating will introduce temperature dependent demand. Renewable hydrogen supply through electrolysis will be weather dependent. Furthermore, hydrogen will enable increasing flexibility in the electricity system, through dispatchable power plants to run at peak times. There is still great uncertainty as to what the optimum portfolio of flexibility will be. The figure below illustrates EU hydrogen storage capacity in working gas volume alongside annual dispatchable volumes (represented by the withdrawal volumes), highlighting the importance of storage in meeting system needs.

Figure 77 shows that hydrogen storage assets are actively utilised across all target years. When considering storage cycles, 2030 stands out with the highest utilisation, exceeding four full cycles per year, while in later years this decreases to around three cycles annually. Even so, this represents significantly higher utilisation compared to traditional seasonal methane storage facilities, which typically operate at much lower cycling frequencies (seasonal balance).

Flexibility from hydrogen storages in the Economic Variants

In Figure 78 the hydrogen storage capacity and usage is displayed for the economic variants. For the variant we see a change where the storage usage is lower for the low economic variant while the High Economic variant is more or less in line with the NT+ scenario which indicate a higher demand for flexibility in a high economy.

The demand and supply of e‑liquids and e‑methane are modelled endogenously. Demand can be met either through direct imports of e‑liquids or e‑methane, or through domestic synthesis based on biogenic CO₂ and hydrogen (H₂). Consequently, total domestic production of e‑methane and e‑liquids is constrained by the availability of captured biogenic CO₂. Figure 79 illustrates the total supply of e‑liquids and e‑methane, differentiated between imports and domestic production. In the NT+ scenario, most of the e‑fuel consumption consists of e‑liquids, while the use of e‑methane remains limited.

A slight majority of the e‑liquids is produced within Europe, rather than imported. E-fuels – and particularly e-liquids – play an important role in meeting future energy demand. However, domestic production of e-liquids requires substantial quantities of hydrogen as a feedstock. In addition to hydrogen, a carbon source is necessary for fuel synthesis. The required amounts of captured biogenic CO₂ therefore represent a key limiting factor for domestic e-fuel production (see Figure 80). Data on biogenic CO₂ availability and capture were collected from the TSOs.

Biomass is used for a range of applications and serves different purposes across the scenarios. It is consumed directly as final energy for heating and industrial processes, and it is also used as a feedstock for the production of biofuels, biomethane, and electricity. Through these conversion processes, biomass is transformed into secondary energy carriers that are subsequently used in end‑use sectors such as transport, heating, and other applications.

Looking ahead, both the use and the role of biomass are expected to change. In particular, biomethane and biogases are projected to shift away from local electricity generation and heat production toward direct injection into the methane grid or use as a feedstock replacing natural gas. This development is illustrated in Figure 81. Over the period shown, the most significant changes occur in the allocation of biomass between final energy demand and its major consumption sectors. Notably, the share of biomass used for electricity and heat generation declines over time, accompanied by corresponding increases in the shares allocated to the production of biofuels and biomethane. By contrast, the direct use of biomass as final energy shows a slight decline. Overall, the figure indicates that the dominant trend is a growing use of biomass for the production of bioliquids and biomethane.

Figures for the production and imports of biofuels were collected from the TSOs based on their NECPs and best estimates. Figure 82 shows that the supply of biodiesel and biomethane is projected to approximately double between 2030 and 2050.

In addition, their share of domestic production is expected to increase, while the share of imports will decline, even though the total imported volume continues to rise. In contrast, the supply of biogas is expected to remain largely unchanged over the same period. The same values for biofuels were used in the economic variants, which is why no additional graph for the variants is shown.

In the NT+ scenario, the combination of ambitious energy efficiency measures and deeper integration across energy systems substantially reduces import needs. Moreover, a strong expansion of indigenous renewable capacities further diminishes future reliance on energy imports (Figure 83).

System integration plays a central role in fostering clean energy production and strengthening energy independence. As integration across energy systems increases, the EU energy system progressively relies on domestically produced renewable sources to meet its energy demand. This enables the large-scale development of indigenous production capacities, significantly reducing dependence on coal, oil, and gas.

Added to this is the ambitious implementation of energy efficiency measures. As a result, the need for carbon‑intensive energy imports declines markedly over time. Overall, the scenarios show a substantial reduction in energy imports compared to current levels. In the NT+ scenario, this downward trend is already clearly visible by 2030.

In the variant, only slight changes are observed compared to the main scenario. The corresponding import levels are illustrated in the Figure 84 below.

A higher share of oil imports in the HEV scenario compared to the NT+ and LEV scenarios reflects higher overall energy demand. Similarly, higher hydrogen imports in the HEV scenario relative to NT+ and LEV are driven by both increased hydrogen demand and lower domestic hydrogen production, as less electricity is available in the EU for P2G processes. Due to the specific representation of the electricity sector within the modelling framework, electricity imports and exports cannot be treated consistently with other energy carriers. In particular, the electricity system modelling differs from that of other carriers as it explicitly includes the power systems of selected non‑EU27 countries. In addition, fixed cross‑border exchanges between the EU27 and certain third countries are embedded in the model setup.

As a consequence, electricity import and export flows are not reported in aggregate form but are instead provided at country level through the dedicated KPI dashboard file.

According to ACER TYNDP Scenarios Framework Guidelines, ENTSOs shall provide, among others, a qualitative assessment of how the scenarios would be impacted by the uncertainty around the main selected assumptions and drivers.

On the demand side, the TYNDP 2026 scenarios introduce two Economic Variants, representing higher and lower economic growth assumptions for the 2035- and 2040-time horizons. These variants primarily assess the sensitivity of energy demand across sectors to different economic conditions.

On the supply side, an additional sensitivity analysis is performed specifically on hydrogen supply mix structure across all target years as the development of energy supply mix and the role of different supply sources is also characterised by uncertainty.

This analysis does not aim to explore the full range of supply-side uncertainties. Instead, it focuses on a specific aspect of the supply structure through a dedicated sensitivity applied to the base NT+ scenario.

To complement economic demand variants, and to support the robustness of the NT+ scenario, this chapter presents a sensitivity analysis focusing on the distribution of hydrogen supply between domestic production and import sources. This sensitivity builds on supply-side considerations explored in earlier TYNDP Scenario editions, where scenarios with a higher reliance on hydrogen imports were assessed, and applies them in a targeted manner to the Central Scenario.

National NT+ datasets describe a range of potential hydrogen supply options. The TYNDP modelling framework determines how these options are utilised to meet hydrogen demand, resulting in a base case with a stronger contribution from domestic production compared to imports.

Long-term import contracts, as described in Chapter 6 of the TYNDP 2026 Scenarios Methodology Report, represent one possible element of hydrogen supply arrangements. In the Central Scenario, long-term contracts are assumed for 50 % of hydrogen import capacity. These contracted volumes are modelled with zero marginal import costs, reflecting their limited flexibility to adjust to short-term changes in domestic hydrogen demand. Import capacity above this threshold is modelled using corridor-specific marginal import costs. Further methodological details are provided in the TYNDP Scenario Methodology Report.

This chapter presents a sensitivity analysis in which the share of inelastic supply (LTC band) is increased to 80 % of import capacity (LTC80). The objective is to assess how changes in the level of in-elastic import volumes affect the utilisation of domestic production and import routes, thereby testing the robustness of the base scenario outcomes. This sensitivity does not constitute an alternative supply-side scenario.

When setting the level for sensitivity analysis ENTSOs took into consideration indicative non-binding direction outlined in the EU strategy communication REPower Plan, which refers to 50 / 50 split between non-EU import and EU production share in 2030. In this context, the hydrogen system could very well develop in the direction of the current gas system. This would mean the hydrogen imports based on long-term contracts (LTC) with Take-or-Pay clauses and utilisation rates of the import capacity at least 70 – 90 %. These LTCs are an important market-based tool as it splits the significant commodity and capacity risks between the infrastructure operator and infrastructure users. Hence LTCs ensure the use of import infrastructure and security of ­supply.

This sensitivity shows a different supply mix, where more hydrogen is imported into the EU. Compared to the reference year, the imported volumes increase across all corridors, as shown in Figure 85.

In contrast, the market share of EU supply sources drops, both for electrolysis and SMR production. However, the market share of domestic hydrogen supply sources is dominant, particularly renewable production. Import share reaches in target year 2030 43 percent in the variant with the declining trend to 20 percent share in 2050 target year against 27 percent share in 2030 and 15 percent share in 2050 in the central scenario.

Import shares in this variant are comparable to the lower end of the range assumed in the previous TYNDP 2024 scenario edition (Figure 86, Figure 87).

Ship imports of hydrogen in the form of ammonia do not have the allocation to the specific country source as ammonia as commodity is part of the world market. Ammonia import capacities into EU27 (receiving terminals) are based on the TYNDP 2024 projects.

The difference in supply assumptions also has implications for the dispatch of hydrogen CCGTs and OCGTs. On average, the running hours of these facilities increase, but this is primarily driven by the model topology. In the Scenario 2026 Modelling exercise the assumption was implemented that long-term contracts for imports are modelled at zero marginal costs to allow the hydrogen pipeline imports.

As a consequence of this solution, these higher shares of hydrogen pipeline imports will reduce fuel cost for hydrogen CCGTs and subsequently increase power plant dispatch. Supply capacities were not changed for the LTC 80 sensitivity. Consequently, the higher import volumes translate into lower full load hours for the domestic supply sources like electrolysis and steam methane reforming (SMR). The dispatch of electrolysis capacity (P2G) slightly decreases compared to the reference scenario but remains within a range of 2,500 – 3,500 hours per year (Figure 88 and Figure 89).

See in Figure 90 that the curtailment of renewable electricity generation (i.e. solar and wind) increases marginally.

Percentage changes of the analysed parameters – P2G full load hours and change of curtailment of EU27 PV and wind RES generation can be observed in Figure 90. There is higher change in the SMR full load hours parameter, but as the share of SMR on the overall hydrogen supply is less than 10 % in 2040 and 2050, this change is not significant in total terms. Share of the hydrogen imports EU27 does not exceed the 33% share to cover expected demand in 2035, 2040, 2050 thus the EU’s goal of achieving energy independence from the need to import energy raw materials from third parties is not threatened. Still, most of the hydrogen demand can be covered via domestic production within EU through all target years.