9 TYNDP 2026 Scenario results //

Demand results are structured around a clear distinction between final energy demand and total energy consumption, and between the National Trends (NT) data collection and the target‑compliant NT+ scenario.

Final energy demand refers to energy consumed by end‑use sectors such as households, buildings, industry, transport and agriculture, based on data collected primarily through the Energy Transition Model (ETM) (see TYNDP 2026 Scenarios Methodology Report Chapter 4). These values reflect nationally reported trends and policies. Final energy demand in the NT data collection is presented by sector and energy carrier, highlighting the main structural developments over time. The chapter then turns to the results of the gap-filling exercise in section 9.1.1, which adjusts final energy demand to ensure consistency with EU climate and energy targets.

This step marks the transition from NT data collection to NT+ scenario and highlights the resulting reductions in fossil fuel use and changes in the energy mix.

The final part focuses on total energy consumption by carrier. Total consumption combines final demands for electricity, hydrogen with additional demand generated endogenously by the market model optimisation, including demands for power generation, hydrogen production, hybrid heat pumps and synthetic fuel production. These total consumption levels form the basis for the supply ­result presentation in the following subchapter. Comparisons between the Economic Variants, the NT data collection and subsequent NT+ central scenario are made throughout to illustrate the effect of different economic assumptions.

In this section, final energy demand refers to energy values collected from electricity and gas TSOs in the NT data collection, mainly through the ETM. These values are presented before the application of the gap‑filling methodology. Within the TYNDP 2026 Scenario Building process, the NT data collection shows a decreasing trend in the final energy demand when compared to Eurostat’s final energy consumption for 2019 and 2023. This reduction reflects the impact of national policy and market developments, in particular the latest NECPs of each Member State.

At EU27 level, between 2023 and 2050 overall final energy demand across all sectors excluding the energy sector decreases by 18 %, falling from 12,160 TWh in 2023 to 9,990 TWh in 2050. The downward trend is evident already in 2030 (11,960 TWh, ~ 2 % below 2023), confirming the long-term EU policy trajectory.

Figure 4¹ presents the final energy demand by energy carrier for the NT data collection and for 2019, 2023, 2030, 2035, 2040 and 2050.

When applying the calculation principles of the EU Energy Efficiency Directive (EED), the long-term trend intensifies. In line with the EED methodology, several ETM sectors are excluded from the calculation of final energy consumption. These sectors are industry non-energetic uses, refineries (energetic and non-energetic), international shipping, and other non-energetic sectors. They are hereafter referred to as “Others (not included in Final Energy Consumption (FEC) target)”. More information regarding the sectors excluded from FEC is available in the visualisation platform². Under the EED framework, final energy demand reaches 10,080 TWh in 2030 and declines further to 8,240 TWh in 2050 from 10,470 TWh registered in 2023.

Figure 5 presents the final energy demand and its sectoral distribution³ for all target years for the NT data collection.

In the TYNDP 2026 process, two economic variants are considered: the High Economic Variant (HEV) and the Low Economic Variant (LEV) (for details on the implemented approach, refer to Scenario Methodology Report, Chapter 10). Their FED deviates from the NT data collection by – 1 % and + 1.2 % in the mid-term (2035) and – 0.9 % and + 1 % in the long-term (2040). Table 1a) provides a detailed breakdown of the FED per carrier. Table 1b) shows that even though the sum of FED is only varying by about 1 % across the variants, the variation of individual carriers is up to 10 times higher. In the HEV, electricity, hydrogen, heat, biomass and ammonia demand is increased compared to NT. Methane, solids and liquids demand is decreased.

In the LEV the situation is vice versa. This is consistent with the premise that electrification and the transition to more sustainable technologies are accelerated in the HEV, while this transformation is slower in the HEV. There is an interplay between the level of economic activity and the changes in the technology mix. In each variant scenario, those changes are pulling the total FED in opposite directions. For example, in the HEV, the higher economic activity will be offset by an increased market share of more efficient technologies. This explains why, in sum, we see small changes of the total FED.

Figure 6 shows a graphical representation of both variants FED against the NT data collection for all carriers and target years.

Additionally, Figure 7 details the sectoral breakdown⁴ for the economic variants as well as the final energy demand calculated following EED criteria.

Households and buildings require energy for lighting, power, cooking, heating and cooling⁵. Today, most of the energy consumption comes from fossil fuels. To meet the climate ambitions for 2030 and beyond, a vast transition of the building sector is needed. This will not only decrease energy demand but also improve living standards.

Most of the energy demand in the built environment is associated with heating. Figure 8 and Figure 9 illustrate how the market share of different space heating technologies in households develops over time in the National Trends scenario and the economic variants⁶ based on ETM inputs (i. e., the technology mix for space heating in percentage terms and the number of households in future scenario). The market share of each technology is a proxy of the number of installed units in EU27. Today the use of conventional boilers is dominant. This dominance reduces over time, when heat pumps (HPs) and district heating become more prominent.

The share of homes that use a traditional gas boiler drops from 41 % in the reference year to approximately 10 % in 2050. Gas boilers in 2050 make use of renewable gas like biomethane and hydrogen.

HPs offer increased efficiency by making use of ambient heat. Furthermore, hybrid heat pumps (HHPs) can provide also flexibility to the electricity system, by switching to gas (methane or hydrogen) in cold winter days, during grid congestion or when there is insufficient renewable electricity available. By 2040 the households’ market share of HPs (electric and hybrid) has grown to around 45 % (41 – 49 % in the economic variants). In the following years, this market share is assumed to increase further, to up to 57 % by 2050.

Through changes in heating technology and increased efficiency, the NT data collection shows a sharp decrease in overall energy demand for households and buildings. This is illustrated by Figure 10. By 2050, final energy demand declines by roughly 20 % compared to 2023, despite an increase in the number of dwellings and increased energy demand for Datacentres. This increased energy efficiency is the result of both an ambitious renovation rate and the use of more efficient appliances like heat pumps. The use of oil and coal will almost completely disappear. Gas demand also shows a sharp decline. Part of the methane demand is replaced with hydrogen. For the methane demand that remains, the share of renewable gas (i. e. biomethane) will increase over time.

The share of electricity in total energy demand increases from 37 % in 2023 up to 59 % in 2050. This is mainly driven by the increased use of HPs for space heating and hot water⁷. The role of district heating (heat) also increases, from 9 % in 2023 up to 12 % in 2050.

The economy variants show slight variations in the energy mix for the built environment. This is illustrated in Figure 11. The HEV shows a lower market share for fossil fuels (i. e. natural gas). The role of renewables like electricity, district heating and hydrogen is more important. The LEV shows the opposite.

European industry has a high demand for energy and raw materials. It is also characterised by strong heterogeneity, with significant differences in demand across subsectors. The basic industries for steel, chemicals, and refining account for the largest share of the industry’s energy and raw material consumption. Smaller industry sectors might also face specific challenges to reduce emissions, for instance regarding high temperature processes (i. e. glass, ceramics, brick production).

Any shift within the industry – who decarbonises when and how – will have a major impact on future energy demand. The evolution of the energy demand for the different industrial subsectors is illustrated in Figure 12⁸.

The NT data collection shows a rather stable industrial energy consumption, as shown in Figure 13⁹. Fossil fuels like oil, coal and gas decline over time. The electrification rate increases from one-third in the reference year 2023 to more than half in 2050. Hydrogen’s importance grows¹⁰, especially in sectors that are challenging to decarbonise, such as those requiring temperatures above 200 degrees Celsius, making electrification difficult. Industries such as steel, cement, aluminium, and petrochemical production are examples where hydrogen plays a crucial role.

Figure 14 provides a comparison of industrial demand between National Trends and the economic variants. The HEV assumes higher industrial activity, which results in an increase in energy demand of approximately 7 %. This increase is primarily accounted for by renewables like electricity and hydrogen. The LEV shows opposite dynamics.

As the EU production of fossil transport fuels reduces over time, the energetic use in refineries also declines. Furthermore, up to 2050 the energy consumption in refineries becomes more renewable. This is illustrated in Figure 15. Today refinery gasses¹¹ are the most prominent energy source, complemented by natural gas. Towards 2050 the role of hydrogen becomes more prominent.

Which is in part produced out of the refinery gasses (post-combustion CCS) that are currently used directly as a fuel. The HEV shows a reduction in energy consumption by refineries compared to NT, as presented in Figure 16. This is primarily driven by a lower production of transport fuels, which is linked to an increased electrification rate in road transport in this variant. The LEV shows an opposite trend.

Regarding non-energy consumption within industry, current usage predominantly involves liquids and methane, serving mainly two purposes: the production of chemicals, particularly liquid-based petrochemicals for plastics, and manufacturing of fertilisers, with ammonia being a key component produced through Steam Methane Reforming (SMR).

The non-energetic use of liquids (oil products) drops significantly, but remains the primary energy carrier until 2040, after which renewables (ammonia, hydrogen, biomass) take the lead, driving the transition in the feedstock sector. Different assumptions regarding economic growth lead to increased or decreased industrial production, which translates to differences in non-energetic use. This is illustrated in Figure 17 and Figure 18.

The transport sector is undergoing a sustained and structural energy transition driven by environmental imperatives, energy security concerns, and the strategic objective of reducing dependence on fossil fuels. This transformation is characterised by a broad set of measures aimed at enabling sustainable mobility, improving energy efficiency, and progressively decarbonising transport systems across all modes. While the transformation unfolds at different speeds and with varying technological pathways across transport segments, the overall direction is consistent: electricity emerges as the primary energy carrier wherever direct electrification is technically and economically feasible, with hydrogen assuming a complementary role in applications with higher energy requirements or operational constraints (See Figure 19).

At the centre of the scenario lies the systematic decarbonisation of transport, supported by technological innovation, policy intervention, and evolving consumer preferences. While certain transport sectors such as maritime shipping and aviation will remain heavy to decarbonise also in the long term, the rapid deployment of EVs represents a key pillar of this shift, enabled by continued improvements in battery performance, declining costs, supportive regulatory frameworks, and increased awareness of air quality and climate impacts. In recent years, EVs have experienced strong sales growth, observed across European markets. From a demand-side perspective, uptake is primarily driven by the need to reduce local air pollution, enhance energy efficiency, and lower CO₂ emissions.

Across NT data collection and economic variants, overall transport energy demand declines over time as a result of efficiency gains, improved vehicle technologies, and structural changes in mobility. Differences between the HEV and LEV are primarily reflected in the pace of change (See Figure 20). Higher investment levels and faster technology diffusion in the HEV scenario accelerate fleet renewal and fossil fuel displacement, while the LEV scenario follows a similar trajectory with delayed uptake and a more gradual reduction in energy demand.

Passenger cars lead the transition in all scenarios. Oil use declines sharply, while electricity and hydrogen play an important role. The HEV scenario shows faster electrification and lower residual fossil fuel use, whereas the LEV scenario retains conventional vehicles for longer.

Buses follow a similar pathway but with a more balanced role for hydrogen. Hydrogen gains relevance for longer routes and higher utilisation needs. The HEV scenario enables faster deployment of both electric and hydrogen buses, while the LEV scenario shows a more gradual transition with continued reliance on conventional fuels in the medium term.

Trucks transition more slowly due to operational challenges. Electricity grows mainly in short- and medium-haul applications, while hydrogen becomes increasingly important for long-distance freight transport. The HEV scenario places greater emphasis on hydrogen, reflecting earlier infrastructure availability and stronger investment capacity. In the LEV scenario, the shift away from oil is slower, and alternative technologies penetrate the fleet more gradually.

Vans show strong electrification potential, especially in ­urban logistics and last-mile delivery. Electricity increasingly replaces conventional fuels, supported by predictable ­driving patterns. Hydrogen plays only a limited role. Differences between scenarios are mainly related to timing, with the HEV scenario achieving faster electrification and the LEV scenario lagging slightly behind.

Rail transport is already largely electrified and continues to strengthen this position. Electricity remains the dominant energy carrier in all scenarios, while hydrogen appears as a niche solution for non-electrified lines. The HEV scenario supports a faster reduction of residual oil use, while the LEV scenario maintains limited fossil fuel use for longer.

Maritime shipping and aviation remain the most challenging sectors to decarbonise. In shipping, electricity is largely confined to short-distance and port-related activities, while hydrogen gains relevance over time, especially under favourable economic conditions. Aviation shows limited penetration of electricity and hydrogen with decarbonisation driven primarily by Sustainable Aviation Fuels (SAF). Differences between scenarios are comparatively small, reflecting persistent technological and operational constraints.

Agriculture, while accounting for a relatively limited share of energy demand, relies significantly on fossil fuels for machinery, irrigation, and heating. Historically, oil has dominated energy use on farms (more than 50 % share in 2019), powering tractors, harvesters, and grain dryers. In addition, the energy demand of greenhouse (horticulture) operation amounts to a significant share in this sector in certain countries.

However, as global decarbonisation targets tighten and energy costs fluctuate, the sector is undergoing a profound transformation toward cleaner, more sustainable sources, as shown in as shown in Figure 21.

In the NT data collection, the overall energy demand for agriculture is expected to gradually decrease from around 300 TWh in 2030 to around 260 TWh in 2050. The share of oil is also steadily decreasing throughout the years (although it remains the most important energy carrier throughout the analysed time horizon) and is partially replaced by electricity – driven by the electrification of farm equipment and the adoption of precision agriculture technologies. The demand for biofuels increases slightly, while heat demand decreases throughout the years. Methane demand remains stable, while other carriers (coal, hydrogen, ammonia and others) are insignificant for energetic use in agriculture.

Overall, the difference between the NT data collection and the Economic Variants is rather limited regarding energy demand in agriculture as shown in Figure 22.

Final electricity consumption shows a substantial increase throughout all target years. This growth is primarily driven by Europe’s progressive shift away from fossil fuels, reflecting the region’s commitment to improving energy efficiency and advancing decarbonisation.
Looking at final electricity demand, a strong and continuous increase is observed across all target years when assessed under the EED. Starting from 2,380 TWh in 2023, demand rises to around 2,920 TWh in the short term (2030), reaches 3,710 TWh in the long term (2040) and further increases to 4,220 TWh by 2050, corresponding to increases of 23 %, 56 % and 77 %, respectively.
This increasing trend is observed in the variants too, although its magnitude varies depending on economic assumptions. In the HEV, electrification is even more pronounced, with final electricity demand increasing by 8 % in the medium term (2035) and 8.4 % in the long term (2040) relative to the NT data collection. This additional growth is mainly driven by further electrification within the industrial sector. However, the widespread implementation of efficiency measures helps moderate the scale of this increase. In contrast, the LEV projects a decline in final electricity demand of 8.4 % by 2035 and 8.4 % by 2040 compared to the NT data collection.

Within this overall increase, growth is not evenly distributed across sectors. The transport sector shows the strongest growth in final electricity demand over time. Between 2023 and 2030, the expansion of this demand in the transport sector is particularly notable. Currently dominated by oil as its main energy source, the sector is undergoing a major transition towards electric mobility. This trend continues through 2050. From 2030 to 2050 the electricity demand in the transport sector increases by a factor of 3.5. This shift not only eliminates local emissions but also improves energy efficiency, given that electric motors are significantly more efficient than internal combustion engines.
Despite the strong growth of final electricity demand in the transport sector, the ranking of sectors by electricity consumption remains largely unchanged across scenarios and target years. The built environment sector represents the largest share of electricity consumption, followed by industry and transport. This is mainly driven by the widespread deployment of HP, which efficiently provide heating and cooling using electricity, as well as by improvements in appliance efficiency and building insulation. In addition, the built environment also includes the growing electricity consumption associated with ICT related activities. The continued digitalisation of the economy (including datacentre expansion and cloud‑based services) further increases the electricity demand within this sector, consolidating its dominant contribution across all scenarios.

Methane final demand shows a near-term stabilisation followed by a long-term decline (Figure 25). In the NT data collection, methane demand in 2030 remains close to the level observed in 2023, at 2,255 TWh compared to 2,238 TWh in 2023. This is substantially below the 2019 reference level of 2,657 TWh. In 2030, demand remains concentrated in the built environment and industry, which together account for around 80 % of total methane demand.

Beyond 2030, methane demand declines substantially, mainly due to reduced demand in the built environment sector and in energetic use in industry. In the NT data collection, total methane demand falls to around 1,097 TWh in 2050. The built environment shows the largest absolute reduction, decreasing from around 1,072 TWh in 2030 to around 376 TWh in 2050. This reflects the increasing electrification of heating, fuel switching and improvements in energy efficiency. Industrial methane demand also declines steadily, from around 743 TWh in 2030 to around 346 TWh in 2050, although it remains significant throughout the period due to continued process-related uses and limited alternatives in certain industrial applications.

Other sectors show more mixed developments. Agriculture remains broadly stable over time, while demand in the “Others” category changes only moderately. While methane demand decreases across most sectors, transport shows a clear increase compared to the historical reference years, rising from 38 TWh in 2023 to around 108 TWh in 2030 and remaining above historical levels until 2050. This increase is mainly driven by international maritime transport, reflecting the limited availability of alternative decarbonisation options in this sector and a growing reliance on methane-based fuels. However, transport remains relatively small compared to the built environment and industry.

In the economic variants, differences are most visible in the built environment and industry sectors, where methane demand is most sensitive to assumptions on electrification, fuel switching and efficiency improvements (Figure 26). In 2040, methane demand in the built environment ranges from around 527 TWh in the HEV to around 728 TWh in the LEV, compared to around 622 TWh in the NT. Industrial methane demand ranges from around 470 TWh in the HEV to around 537 TWh in the LEV, compared to around 509 TWh in the NT. This reflects the economic variant assumptions: the HEV shows stronger reductions in methane demand, while the LEV shows a slower decline and higher residual methane use. Agricultural methane demand remains relatively stable across scenarios and over time.

Hydrogen final demand increases strongly over time, rising from 212 TWh in 2030 to 1,071 TWh in 2050 in the NT data collection (Figure 27). This growth is mainly driven by industrial and non-energetic uses of hydrogen. In the sectoral breakdown, this is reflected both in the industry category and in the “Others” category, which mainly includes non-energetic industrial uses and refinery-related demand. Together, these two categories account for around 80 % of hydrogen demand in 2030 and remain the dominant components throughout the period.

After 2030, hydrogen demand expands substantially. Demand in the Others category increases from 113 TWh in 2030 to 438 TWh in 2050, while industrial hydrogen demand rises from 58 TWh to 407 TWh over the same period. This reflects the growing role of hydrogen in industrial decarbonisation, both as an energy carrier and as a feedstock replacing fossil-based inputs in hard-to-abate sectors and refinery-related applications.

Hydrogen demand also increases in transport, from 32 TWh in 2030 to 170 TWh in 2050. While this growth is significant, transport remains smaller than the industrial and non-energetic demand categories. Demand in the built environment rises, too, from 9 TWh in 2030 to 55 TWh in 2050, while agricultural demand remains negligible. Hydrogen therefore does not become a mass energy carrier across all final demand sectors but is concentrated in hard-to-abate industrial, non-energetic and select transport applications.

In the economic variants, differences are most visible in industry and Others (Figure 28). In 2040, industrial hydrogen demand ranges from around 229 TWh in the LEV to around 317 TWh in the HEV, compared to around 275 TWh in the NT. Demand in the Others category ranges from around 270 TWh in the LEV to around 302 TWh in the HEV, compared to around 287 TWh in the NT. This reflects the economic variant assumptions, with the HEV showing higher hydrogen uptake and the LEV showing slower deployment. The overall sectoral structure remains similar across variants, with demand concentrated mainly in industrial energy use, non-energetic uses, refinery-related demand and, to a lesser extent, transport.

Biomass in this context covers solid bioenergy used as a final energy carrier, primarily in the built environment and industry, with additional use in agriculture and for non‑energy applications. As biomass in the ETM is represented only as solids, there is no explicit biomass entry for the transport sector in this breakdown. The “Other (non‑FEC)” category is mainly driven by non‑energetic uses of biomass in the chemical industry and related process applications.

As shown in Figure 29, total biomass demand in the NT dataset decreases progressively from 2030 to 2050, although the reduction is moderate. Final biomass use in the built environment remains the largest component over the period but declines from 491 TWh in 2030 to 304 TWh in 2050, reflecting the gradual replacement of solid biomass heating and efficiency improvements.

Industrial biomass demand stays relatively stable in aggregate terms, at about 261 TWh in 2030 and 258 TWh in 2050, with only a temporary dip in 2035 – 2040. Agricultural biomass use increases slightly over time, from 28 TWh in 2030 to 33 TWh in 2050 but remains small in absolute terms. In parallel, biomass in “Other (non‑FEC)” grows steadily from 76 TWh in 2030 to 172 TWh in 2050, indicating an increasing role of biomass as a non‑energetic feedstock, mainly in the chemical industry. Overall, the sectoral composition gradually shifts from a dominance of built‑environment use towards a more balanced distribution between buildings, industry and non‑FEC uses.

The Economic Variants introduce a moderate spread around the NT values for 2035 and 2040, as illustrated in Figure 30. For agriculture, biomass demand is identical across LEV, NT and HEV (around 29 TWh in 2035 and 30 TWh in 2040). In the built environment, differences are limited: biomass demand ranges from 442 – 444 TWh in 2035 and 408 – 413 TWh in 2040, with NT lying between LEV and HEV in both years. The largest variations appear in industrial biomass use and other non‑FEC biomass. In 2035, industrial demand spans from 216 TWh (LEV) to 251 TWh (HEV), compared to 233 TWh in NT; by 2040, it ranges from 221 TWh (LEV) to 255 TWh (HEV), with NT at 237 TWh.

Non‑FEC biomass follows a similar pattern, with 86 – 96 TWh (LEV–HEV) in 2035 and 97 – 117 TWh in 2040, compared to 90 TWh and 107 TWh in NT. Despite these differences in absolute levels, all three datasets (NT, LEV and HEV) preserve the overall trend of gradually declining biomass use in the built environment, relatively stable industrial use, and increasing biomass deployment and the use cases excluded from the final energy demand as per the EED.

Heat as an energy carrier represents centralised heat delivered to final consumers via district heating networks. It is mainly used in the residential and tertiary sectors (combined here as “Built Environment”), in Industry and in Agriculture. Other forms of heat demand – such as space heating supplied by individual heat pumps or boilers – are not reported under the “heat” energy carrier but are captured indirectly via the final energy delivered in the form of electricity, hydrogen, methane or other fuels. Heat is also not used in the transport sector in this framework, which is why transport does not appear in the sectoral breakdown.

As shown in Figure 31, total final energy demand for heat in the NT dataset remains relatively stable over time, at around 540 –550 TWh per year between 2030 and 2050. The Built Environment is the largest user of district‑heating‑based heat, with demand increasing from 343 TWh in 2030 to 358 TWh in 2050. Industrial heat demand via district heating remains broadly stable, fluctuating between 160 TWh in 2030 and 169 TWh in 2050, while Agriculture accounts for a comparatively small and declining share, from 20 TWh in 2030 to 9 TWh in 2050. Overall, the sectoral composition changes only marginally, indicating that the role of district heating within the different end‑use sectors does not fundamentally shift over the period.

The Economic Variants introduce a similarly moderate spread around the NT values for 2035 and 2040, as depicted in Figure 32. In the high economic variant (HEV), total heat demand is higher than in NT, with additional consumption mainly visible in the Built Environment and Industry: for 2035, built‑environment heat demand rises from 338 TWh (NT) to 349 TWh (HEV) and industrial demand from 160 TWh to 169 TWh; in 2040, the corresponding values are 348 TWh vs. 357 TWh (Built Environment) and 154 TWh vs. 163 TWh (Industry).

In the low economic variant (LEV), total heat demand is slightly lower, particularly in Industry and, to a lesser extent, in the Built Environment: in 2035, industrial demand falls to 152 TWh and built‑environment demand to 335 TWh, and in 2040 to 145 TWh and 339 TWh respectively. Agricultural heat demand is higher in LEV and HEV than in NT but remains small in absolute terms. Despite these level differences, all three datasets (NT, LEV, HEV) show a broadly stable trajectory for district‑heating‑based heat demand and maintain a very similar sectoral structure over time.

Gap-filling refers to the methodology applied to shift from the NECP- and policy-aligned NT data collection to the EED target-compliant NT+ scenario. In line with this methodology, solids and subsequently liquids demand were reduced at country level, while demand for other carriers and conversion demand remained unchanged. Further information on the methodology can be found in Chapter 10 of the Methodology Report, while Chapter 10.2 of the Scenario Report provides additional context on the EED target. The dashboard provides country-level results. The TSO Survey in Annex I of the Scenario Report provides further information on the alignment of the NT data collection with national policies.

Gap-filling affects (1) overall FEC levels, (2) final demand for solids and liquids, and (3) the composition of carriers within overall final energy consumption. The applied reductions are largest in 2030 and decline over time, as the methodology carries the 2030 limits for solids and liquids forward to later horizons.

The results are shown in Figure 33 and Figure 34. Regarding overall FEC levels, EU27 final energy consumption decreases from 10,081 TWh (867.0 Mtoe) in the 2030 NT data collection to 8,866 TWh (762.5 Mtoe) in the NT+ scenario, corresponding to a reduction of 1,215 TWh (104.5 Mtoe, – 12.1 %)

The impact of gap-filling becomes smaller over time as fossil fuel demand already declines in the underlying NT data collection. By 2050, EU27 final energy consumption declines by only 178 TWh (15.3 Mtoe, – 2.2 %), from 8,244 TWh (708.9 Mtoe) in the NT data collection to 8,066 TWh (693.5 Mtoe) in the NT+ scenario.

In 2030, liquids decrease by 1,034 TWh (– 88.9 Mtoe, – 29.3 % of liquids demand), while solids decrease by 181 TWh (– 15.6 Mtoe, – 86.6 %). By 2050, the reduction reaches 148 TWh (– 12.8 Mtoe, – 12.0 %) for liquids and 30 TWh (– 2.6 Mtoe, – 74.2 %) for solids. Methane demand remains unchanged across all horizons, as reductions in solids and liquids were sufficient to meet the targets.

The reduction in solids and liquids affects the composition of final energy consumption. In 2030, the share of liquids in EU27 final energy consumption decreases from around 35 % in the NT data collection to 28 % in the NT+ scenario, while the combined share of electricity and hydrogen correspondingly increases from around 30 % to 34 %. By 2050, the impact on the overall carrier composition becomes smaller, as fossil fuel demand is already substantially reduced in the underlying NT data collection.

In contrast to final energy consumption, which captures only the energy delivered to end-users, the total demand presented in the following sections covers energy use across all modelled conversion steps. It combines final energy demands collected in the ETM with additional consumption of energy carriers in power and CHP generation and in sector coupling conversion processes (such as electrolysis, hydrogen-to-power and heat production). Taken together, these elements provide a system-wide view of how much of each carrier is used within the modelled energy system, as reported in the Supply Tool.

Storage operation (including charging and discharging of batteries and other storage technologies) is not counted as additional yearly net demand in these totals, since storages are modelled cyclically with no net consumption or injection over the year.

In addition to the yearly total energy consumption, this section also reports the peak values of electricity, hydrogen and methane demands and loads based on the model results for NT+ and the variants to reflect the peak infrastructure utilisation. Where relevant, the impact of storage operation on peak load is also captured in this analysis.

Peak demand comprises components derived from final energy consumption: native electricity demand, hybrid heat pumps (HHPs) and passenger EVs. For passenger electric vehicles (pEVs), part of the peak may be scheduled for flexibility purposes, reflecting the modelling of flexible charging rather than pure transport needs.

Peak load represents the full system load as seen by the electricity network. In addition to peak demand, it includes all modelled conversion and flexibility uses, such as market‑coupled and shared RES electrolysers, charging of batteries and other storage technologies, and electricity consumption related to sector‑coupling processes (e. g. heat production).

While peak final demand for hydrogen consists of only native demand and hydrogen used in hybrid heat pumps, peak load of the hydrogen system also includes other demands and loads, such as injections into hydrogen storage, hydrogen use in power and CHP‑heat generation and hydrogen demand for SNG and e‑liquid production.

Methane in the model is used for hybrid heat pumps, power and CHP‑heat generation and hydrogen production via SMR and pyrolysis. The “native” methane demand profile (final consumption) is not endogenously modelled but taken from an ENTSOG data collection.

Peak load for methane is constructed by superimposing the model‑dependent time profiles of methane use (for power / CHP, HHPs and SMR / pyrolysis) on top of this native methane peak. This provides an overall methane peak load and for the selected weather year, average contributions of each component.

As a consequence, methane peak load may be somewhat overestimated, since the peak of native methane demand is not required to coincide in time with the peak of the model‑driven methane uses. In addition, storage-related load is not considered.

For each carrier and target year, hourly profiles are available for three weather years. The reported peak loads are obtained by summing the relevant components to build a system load profile and then selecting the highest hourly value for electricity and the highest daily value for the gases across the three weather years. The average values shown for each component refer to the average contribution over the selected weather year in which the overall system peak occurs.

Total electricity demand in the NT+ scenario almost doubles, increasing from 3,420 TWh in 2030 to 6,320 TWh in 2050. This increase of around 2,900 TWh reflects the combined effect of end‑use electrification, the expansion of electric mobility, and the growing role of electricity in hydrogen and synthetic fuel production, supporting the system’s decarbonisation beyond direct electrification. Figure 35 shows total electricity demand in the NT+ scenario for the EU‑27.

As shown in Figure 35, all main components of electricity consumption increase over time, with particularly strong growth in passenger electric vehicles and Power‑to‑Gas (P2G). While native electricity demand increases from 3,040 TWh in 2030 to 4,070 TWh in 2050, electricity consumption for passenger electric vehicles grows to 570 TWh in 2050. Over the same period, electricity use in P2G expands by a factor of seven, from 225 TWh in 2030 to 1,630 TWh in 2050.

In the Economic Variants, electricity demand deviates from NT+ in line with the variant methodology. In 2035, native electricity demand ranges from 3,104 TWh in LEV to 3,618 TWh in HEV, compared to 3,370 TWh in NT+. By 2040, it increases to 3,378 TWh (LEV), 3,659 TWh (NT+) and 3,937 TWh (HEV).

The same pattern appears for passenger electric vehicles (pEVs): electricity use for pEVs is 236 TWh (LEV), 274 TWh (NT+) and 310 TWh (HEV) in 2035, rising to 339 TWh, 391 TWh and 441 TWh respectively in 2040. These differences reflect the scaling down (LEV) or scaling up (HEV) of electrified end‑uses in the variant construction.

For modelled conversion sectors, the impact of variant assumptions is more nuanced. Electricity consumption in P2G is higher in LEV than in NT+ or HEV, at 698 TWh (LEV), 603 TWh (NT+) and 530 TWh (HEV) in 2035, and 1,064 TWh, 963 TWh and 860 TWh in 2040. This reflects the higher relative availability of electricity in LEV given the static supply capacities, which allows more electricity to be channelled into hydrogen production. In HEV, the general scarcity of both electricity and hydrogen reduces the utilisation of P2G despite higher overall activity levels. Electricity demand for hybrid heat pumps (HHPs) remains comparatively small in all cases, but shows the same direction of change: in 2035, it is 25 TWh (LEV), 23 TWh (NT+) and 23 TWh (HEV), and in 2040 it reaches 36 TWh, 37 TWh and 32 TWh respectively, with lower availability of electricity in HEV slightly dampening HHP operation. Figure 36 shows total electricity consumption under the LEV and HEV for the EU27.

Beyond total annual demand, peak electricity demand provides key insights for system operation. Two peak metrics are considered: peak electricity demand, which includes native demand and a limited set of flexible loads¹⁴ (EVs and HHPs) that still represent final demand of electricity, and peak electricity load, which additionally incorporates further flexible uses through conversion of energy such as P2G, pumped storage and battery charging.

Figure 37 and Figure 38 present the maximum peak demand and peak load, respectively, for each target year across the three weather scenarios, together with the average contribution of each component in the peak scenario.

In the NT+ scenario, peak demand increases over time, reaching 538 GW in 2030, 632 GW in 2035, 725 GW in 2040 and 851 GW in 2050. When additional flexible and controllable components are included, peak load increases further, by a 15 % in the short term (621 GW in 2030) and almost doubling in the long term (1,272 GW in 2050).

The comparison between peak and average values shows that the influence of flexible loads in the peak becomes increasingly significant over time. While native demand presents limited differences between average and peak values, flexible components show much stronger deviations, particularly in the long term. By 2050, the contribution of flexible technologies at peak hours becomes comparable to that of the native load, despite their more moderate average contribution. Historically, peak demand has been driven by temperature‑dependent uses and typically occurs in winter, often in January. Despite the inclusion of flexible loads peak values remain in winter as native demand continues to play a dominant role.

While the peak demand and peak load remain in winter, its timing within the day changes. Peak demand (with limited flexibility) typically occurs during evening hours, whereas peak load (including a broader set of flexible components) shifts towards midday.

This reflects the interaction of flexible demand with renewable generation profiles and price signals. Figure 39 and Figure 40 show the maximum peak demand and peak load, respectively, for the weather scenarios identified to have the highest peaks, comparing the LEV and HEV variants with the NT+ scenario. Both figures also include the average contribution of each component in the peak scenario. As seen, peak demand vary with economic assumptions.

In 2035, peak demand ranges from 581 GW in LEV to 681 GW in HEV, compared to 632 GW in NT+. By 2040, it increases to 671 GW (LEV), 725 GW (NT+) and 789 GW (HEV). A similar pattern is observed for peak load, with higher absolute values due to the inclusion of additional flexible components. However, as the installed capacities remain fixed across variants, the difference in peak load across variants results primarily from the adjusted native demands. Peak load reaches 764 GW (LEV) and 849 GW (HEV) in 2035, rising to 970 GW (LEV) and 1,070 GW (HEV) in 2040.

Hydrogen applications are found in the end use sectors, but also in energy conversion like power generation or synthetic fuel production. Figure 41 illustrates the total use of hydrogen. Most of the demand consists of final demand for energetic and non-energetic use (mainly as feedstock in industry). In part this contains existing demand where grey onsite hydrogen production is replaced with externally energy from electrolysis or imports. Additionally, the NT+ scenario sees an increased hydrogen volume needed for synthetic products such as ammonia and sustainable aviation fuels or as feedstock in chemical processes. Hydrogen use in power generation also increases. As hydrogen fired power plants are primarily used for balancing the electricity system, these run for relatively few hours per year. Consequently, the annual demand quantity is rather low.

Figure 42 provides a comparison of total hydrogen demand National Trends+ and the economic variants. Generally, the final demand for hydrogen is lower in LEV and higher in HEV, as defined in the economic variants methodology. Total demand in the variants, however, is rather similar to NT+.

This is explained by the fact that energy supply capacities were not changed in economic variants. Consequently, a lower final demand in the LEV means that there is relatively more hydrogen available at lower costs enabling a higher utilisation of hydrogen in the modelled sector-coupling elements and for conversion like the production of synfuels, the provision of heat and for power generation. For the HEV the inverse of this behaviour can be observed. An exception is hydrogen demand for heat production, which also increases in the HEV compared to NT+. This is mainly driven by more frequent operation of hydrogen-fired CHPs as peaker plants under higher electricity demand and unchanged generation capacities. Higher electricity prices also increase the use of gases in hybrid heat pumps, further contributing to the rise in hydrogen demand for heating.

Final hydrogen demand shows limited variability within the year, as illustrated in Figure 43. This can be explained by the dominance of industry and mobility sectors, which are not weather dependent. As opposed to the methane system, where the residential and tertiary sectors have a rather large market share. For example, final hydrogen demand (native demand + hydrogen demand for HHPs) in the NT+ scenario increases from on average 1,296 GWh / d to a peak of around 1,476 GWh / d in 2035, and from around 3,220 GWh / d to a peak of around 3,772 GWh / d in 2050. Hydrogen use in hybrid heat pumps remains limited across all horizons and contributes only marginally to overall hydrogen final demand.

Figure 44 shows the load of the hydrogen system on a peak day, which considers final demand as well as demand for conversion and storage. While native hydrogen demand remains the largest component in most cases, conversion demand can become equally as important or even dominant during specific system situations. The utilisation of hydrogen fired power plants is particularly dependent on conditions in the electricity market, except for CHPs with must-run conditions. During periods of high renewable generation, most gas power plants are likely to operate only to a limited extent. The yearly average load of these facilities is rather small, due to relatively low full-load hours during the year. However, during dark periods with little wind, hydrogen power plants will operate intensively, which translates to a high load on peak days.

Consequently, hydrogen demand for power generation can become a major contributor to hydrogen system peaks. In the peak day of WS065 of 2040, 1,880 GWh are used for power generation, compared to a native demand of 2,301 GWh.

Hydrogen supply can also drive peak load of the hydrogen system. During periods with high renewable generation and high electrolysis output, excess hydrogen can be injected into storage, increasing total hydrogen system load, as shown in Figure 44. Sometimes the load from electrolysis supply leads to higher peaks than the peak demand situation, as shown for 2050. In contrast to the peak load days in 2035 and 2040, which are largely driven by hydrogen demand in power generation during tight market conditions and therefore show relatively limited storage injections, the 2030 and 2050 peaks are associated with surplus renewable generation, high electrolysis output, increased storage injections and greater conversion of hydrogen into synfuels.

For the economic variants in 2035 and 2040, peak load dynamics similar to NT+ can be observed, where peak situations are likewise primarily driven by hydrogen demand for power generation during tight market conditions. Figure 45 compares average load and peak load in the hydrogen system in the economic variants to the NT+ scenario. In the average-load cases, native hydrogen demand remains the dominant component of system load and increases from LEV to NT+ and further to HEV, in line with the economic variant assumptions.

In 2040, for example, average native hydrogen demand increases from around 1.9 TWh / d in the LEV to 2.3 TWh / d in the HEV. Part of this increase is then offset by changes in conversion demand, particularly for power generation and e-liquids production, resulting in smaller differences in total system load between the variants than differences in native demand alone would suggest. Figure 45 shows individual weather years (those with the highest peaks), whereas the previously discussed annual TEC figures are based on weighted averages across weather years.

Total methane demand in the NT+ case declines strongly over time, falling from around 3,200 TWh in 2030 to about 1,500 TWh in 2050. This reflects a structural shift away from methane in end‑use sectors, only partially offset by continued use in power generation, district heating and low‑carbon hydrogen production. Figure 46 shows total methane demand in the NT+ scenario for the EU27, broken down into final energy demand and the main conversion uses.

All main methane demand components decrease over the time horizon, but at different speeds. Final energy demand from the ETM (excluding district heating and hybrid heat pumps) falls from 2,224 TWh in 2030 to 1,032 TWh in 2050, illustrating the progressive substitution of methane in buildings, industry and other end‑uses. Methane use in power generation drops from 604 TWh to 156 TWh between 2030 and 2050, and its use for heat production in district heating (including CHPs and HHPs) declines from 311 TWh to 138 TWh. In parallel, methane demand for low‑carbon hydrogen production (blue SMR and pyrolysis) first increases, from 48 TWh in 2030 to 127–110 TWh in 2035–2040, and then reaches 206 TWh by 2050, while residual grey SMR use is phased out by 2050.

In the Economic Variants, methane demand diverges from NT+ in line with the methodology in Chapter 11 of the TYNDP 2026 Scenarios Methodology Report. In these variants, sustainable options such as electrification and hydrogen are scaled up or down, and methane‑based technologies are the first to compensate for these changes in final demand. In the low‑economic variant (LEV), final methane demand (excluding district heating and HHPs) is 1,949 TWh in 2035 and 1,635 TWh in 2040, slightly above NT+ (1,852 TWh and 1,499 TWh). In the high‑economic variant (HEV), it is lower, at 1,767 TWh in 2035 and 1,367 TWh in 2040, reflecting faster phase‑out of methane‑based technologies in end‑use sectors despite higher activity levels, as depicted in Figure 47.

Conversion uses of methane show a stronger spread across variants, driven by differences in native electricity and hydrogen demand. In 2035, methane use for power generation ranges from 146 TWh in LEV to 510 TWh in HEV, compared to 281 TWh in NT+. By 2040, the range is 69–375 TWh (LEV–HEV), with NT+ at 190 TWh. District‑heating‑related methane demand falls between 224 TWh (LEV) and 266 TWh (HEV) in 2035 and between 151 TWh and 199 TWh in 2040, versus 237 TWh and 177 TWh in NT+. Methane use for low‑carbon hydrogen production via blue SMR and pyrolysis follows the same pattern: 26 TWh (LEV) to 141 TWh (HEV) in 2035, and 46 TWh to 159 TWh in 2040, compared to 127 TWh and 110 TWh in NT+. Residual grey SMR remains small in all cases but is lowest in LEV (1–2 TWh) and highest in HEV (28 TWh in 2035 and 17 TWh in 2040), with NT+ at 9 TWh in both years.

Overall, lower native electricity and hydrogen demand in LEV reduce the utilisation of gas‑fired power plants, methane‑based heat generation and SMR capacities, keeping total methane use below what would result from a like‑for‑like replacement of sustainable options. In HEV, higher native electricity and hydrogen demands lead to more frequent operation of gas‑fired plants, higher methane use in district heating and increased SMR‑related methane consumption, despite higher fuel and carbon prices.

As a result, conversion‑related methane use is significantly higher in HEV than in NT+, even though the long‑term trend of declining methane use is preserved in all variants.

Figure 48 provides a comparison on peak and average load on the methane system for National Trends +. Most sectors show a substantial difference between peak and average load, with steam methane reforming being the only exception. This illustrated the vast amount of flexibility that the gas system provides. Final demand has a strong seasonal profile with high load peaks in winter, due to the role of methane in residential and tertiary heating.

In the long term, the gas system remains important for seasonal flexibility, for instance with the use of hybrid heat pumps. Gas also provides flexibility to the electricity system via gas fired power plants, which are dispatched when supply from solar and wind is insufficient. Over time, the peak use for power plants reduces, in part due to a transition towards hydrogen in dispatchable generation.