5 Supply //

The Heat demand for district heating is taken from the ETM and covers the residential and tertiary, industrial, and agricultural sectors. In the supply tool (chapter 5.5), the heat demand from the ETM is converted into the required primary energy inputs by applying the technology and energy carrier information collected in an additional data collection together with target year specific efficiencies.

The additional data collection provides the shares of district heat supplied by the main sources (electricity, methane, liquids, biomass and biofuels, solids, renewables and waste heat, and hydrogen boilers) as well as the corresponding conversion efficiencies, for each country, sector, and year. It also covers Combined Heat and Power (CHP), including fuel splits (i. e. which carriers fuel CHPs) and CHP performance parameters for useful heat and electricity. Electricity used for district heating is reflected via a combined efficiency that captures the mix of heat pumps and electric boilers.

The calculation of the primary energy carriers needed to supply the thermal energy follows the same logic as before, but with added granularity. For each country, sector, and year, the useful heat from the ETM is allocated to the reported supply sources using the shares from the district heating supply dataset. These volumes are then converted into energy inputs by applying the reported efficiencies (or the coefficient of performance for electricity).

The only exception to this ex-ante calculation of fuel offtake is CHP fuel use. CHP units are modelled explicitly in the dispatch model, and their fuel consumption is determined endogenously as part of the optimisation process rather than being pre calculated. The allocation of CHP fuel offtake between power and heat is based on the country level information on CHP fuel splits and efficiencies, as provided in the additional data collection.

Fuel costs are a key assumption as they determine the merit order of the electricity generation units, and, consequently, the electricity dispatch and resulting marginal electricity costs. Projections of fuel costs and CO₂ prices depend not only on global energy demand and supply, but also on ­European and global policies.

Commodity costs cover the costs of different categories of fuels (nuclear, different kinds of coal, natural gas and other relevant gases, and different kinds of oil) and CO₂, which are used in the various processes of the TYNDP 2026 Scenario Building. These costs are stated for the relevant target years of this study (2030, 2035, 2040 and 2050) and are converted to 2024 euro values using the Harmonised Index of ­Consumer Prices (HICP), as shown in Table 5.

Some commodities’ costs (biomethane, heavy and light oil and blended gas (the gas blend of biomethane, synthetic gasses and natural gas in the system) are calculated as a weighted average of the costs of the methane carriers present in the system: fossil natural gas, biomethane, and SNG. These weights reflect the share of each carrier in the total European methane supply for each target year.

The CO₂ prices used in the model are those recommended by the European Commission for use in the NECPs by the different EU countries.

The cost of the gas blend used in the scenarios is calculated as a weighted average of the costs of the methane carriers present in the system, which are fossil natural gas, biomethane, and SNG. These weights reflect the share of each carrier in the total European methane supply in each target year.

Total methane demand is compiled from three sources:

In parallel, TSOs provided their assumptions on national biomethane production, Synthetic Natural Gas (SNG) production (and SNG imports), and domestic methane production as it was described in the data collection chapter. It should be noted here that the synthetic fuel sector is modelled explicitly; therefore the domestic production figures from the data collection also act as a proxy and, representing a theoretical upper limit of what the model could determine as optimal domestic production.

From these inputs, the annual shares of biomethane, SNG, and fossil methane in the overall methane system are calculated. These shares serve as the weights for the blended cost. Where intermediate years or missing entries occur, values are linearly interpolated. All costs are expressed in 2024 euros.

The resulting gas blend cost is computed by multiplying each carrier’s cost by its supply share and summing across carriers. This blended commodity cost is used system-wide; CO₂ costs are added separately according to the CO₂ price trajectory and carrier-specific emission factors. In the economic variants, both the commodity costs (including the gas blend) and the CO₂ price are consistently adjusted to assess sensitivity to cost assumptions, an. The blended gas cost is recomputed using the same weighting approach.

The assumptions on power generation Capital Expenditures (CAPEX) and Operating Expenditures (OPEX) are primarily based on the Danish Energy Agency’s Technology Catalogue for the Generation of Electricity and District Heating, excluding offshore wind, electrolysers, pipelines and battery technologies. Cost assumptions for offshore wind, electrolysers, pipelines and battery technologies were derived from other sources, such as the North Sea Wind Power Hub’s “Pathway 2.0 Study”, Elia’s “Blueprint for the Belgian electricity system” and National Renewable Energy Laboratory’s “Annual Technology Baseline”. CAPEX and OPEX assumptions are available on the download site of the Scenarios 2026 website.­

Similarly to the commodity costs, these costs are shown for the relevant target years and are converted to 2024 euro values using the Harmonised Index of Consumer Prices (HICP) .

Due to the new regulatory requirements, an investment model was not required as in the TYNDP 2024 Scenario Building process. This means that the entire modelling process was carried out using a pure dispatch model. Therefore, technology costs assumptions were developed in this exercise to offer support to the downstream processes of the TYNDP.

The Supply Tool is an Excel-based dashboard that consolidates all relevant inputs and model outputs, providing a consistent view of energy balances and the carbon budget (as referenced in section 5.6). Its main purpose is to connect fixed final energy demand (derived from the scenario input data) with the primary energy required to supply that demand. This taking into account all conversion processes, domestic production, and imports.

As many energy carriers are converted into others (e. g. electricity into hydrogen, hydrogen into ammonia or other synthetic fuels, and hydrogen back into electricity, etc.), it is often difficult to distinguish between final and primary energy when considering o individual model component in isolation.

The Supply Tool therefore acts as a bookkeeping layer, keeping track of how fixed final energy demands are met by upstream energy carriers, and of the origin of those carriers (domestic production versus imports).

On the demand side, the Supply Tool uses fixed exogenous data as inputs for the modelling chain. These are not optimised by the dispatch model; they represent scenario assumptions on final or useful energy consumption. The main demand-side inputs include:

These demands provide the “fixed side” of the equation, specifying how much energy must ultimately be delivered in each target year, by carrier and by use.

The role of the dispatch model is then to determine the least-cost way of supplying these fixed demands under given availabilities, marginal costs, and technical constraints. In doing so, the market model generates endogenous fuel and carrier flows (e. g. how much gas is burned for power generation, how much electricity is used for electrolysis and how much hydrogen is converted into synthetic fuels, etc.). These flows are then imported into the Supply Tool as part of the supply-side picture.

On the supply side, the Supply Tool combines:

For each carrier, the Supply Tool aggregates all uses from the modelling chain. Taking natural gas as an example:

These components are added together to obtain the total gas demand. This total is then compared with the collected domestic gas production data. The difference between the total demand and the domestic production is interpreted as the required import volume. The same logic is applied analogously to other carriers (e. g. hydrogen, liquids and ammonia).

The Supply Tool constructs a full energy balance at both country and EU level by combining fixed final demands with modelled conversion flows and exogenous production constraints, . For each carrier, it provides:

In this way, the Supply Tool makes the following explicit:

All balances and indicators are produced for the scenario years 2030, 2035, 2040, and 2050.

The carbon budget in the TYNDP scenarios focuses on the period from 2030 to 2050. The cumulative emissions of greenhouse gases (GHG) during this period are compared with the suggested budget and the reduction targets set out in the EU Climate Law. This aligns with the carbon budget in the Impact Assessment (IA) for the EC’s agreed 2040 climate target.

The carbon budget ensures that the EU contributes to the global reductions in carbon emissions.

This indicative 2030 – 2050 GHG budget is fully compatible with the long-term temperature goals of the Paris Agreement, which aim to keep the global temperature rise well below 2 °C. However, according to Eurostat data, the EU only contributes around 8 % to global emissions, meaning that contributions from the rest of the world regarding carbon reductions are crucial to achieving the Paris Agreement goal.

The carbon budget for the scenarios is set at 16 GtCO2-equivalent in the period from 2030 to 2050. According to the IA this value is consistent with the European Climate Law and fully compatible with the Paris Agreement. The carbon budget includes domestic EU emissions, international intra-EU aviation and maritime transport, and 50 % of international extra-EU maritime transport, all of which are subject to the monitoring, reporting and verification (MRV) process.

EU Climate Law sets out targets to comply with, namely reducing net GHG emissions by at least 55 % in 2030 compared to 1990 levels, and achieving climate neutrality by 2050.

In March 2026, the EU adopted a political agreement on a binding target of reducing net GHG emissions by 90 % by 2040 with a domestic target of reducing emissions by 85 %, and allowing up to 5 % to be offset by international carbon credits.

An adequate contribution of up to 5 % is expected. Therefore, a check on an 85 % reduction in 2040 will be relevant in the TYNDP scenarios.

The cumulative net emissions of GHG are calculated for the period from 2030 to 2050. Net emissions are calculated for each year during this period. As most of the data are calculated only for the years 2030, 2035, 2040 and 2050, the values for the intermediate years are determined by interpolation.

The calculations for emissions and removals can primarily be divided into the elements shown in Table 10 below, which illustrates the structure of the emissions and removals ­accounting framework.

Energy emissions

These include CO₂ and non-CO₂ gases from sectors such as energy industries, manufacturing, and transport, as well as fugitive emissions.

Non-energy emissions

These include CO₂ and non-CO₂ gases from sectors such as industrial processes and product use, agriculture and waste. These emissions are sourced from the NECPs and from EC’s IA report (2024) using the figures provided for the S3 scenario.

As non-energy emissions from materials and industrial processes fall outside the scope of the scenarios, they are not directly estimated. Accordingly, non-energy consumption is excluded from the ETM emissions calculation, and data from the IA and NECP reports are used instead to ensure that these emissions are not double counted.

Removals

Removals are incorporated as negative terms in the carbon budget and are combined with emissions derived from primary energy consumption. The removals include carbon captured and stored underground (CCS), as well as those from Land Use, Land-Use Change and Forestry (LULUCF). Carbon captured and used (CCU) in synthetic fuel production is counted as neutral since the carbon is released again when the synthetic fuel is burned. However, the capacity to capture the carbon is included in the total CCS capacity.

The European Scientific Advisory Board on Climate Change (ESABCC) sets an upper limit on the total amount of CO₂ that can be captured in the EU, regardless of what happens to it. In other words, all CO₂ capture flows are included in this cap, regardless of whether the CO₂ is stored underground permanently (CCS / BECCS) or used in synthetic fuel production (CCU). In the Supply Tool, the sum of (i) CO₂ captured for synthetic fuel pathways, (ii) CCS volumes collected in the data, and (iii) an additional indicative “slack” term for CCS (representing uncertainty and missing national details) must be less than or equal to the ESABCC capture limit (425 Mt / year).

Synthetic fuels themselves are modelled under a conservative but simplifying assumption that they are net-zero (or low-carbon) fuels at the point of use. This means that for every unit of CO₂ emitted when synthetic fuels are burned biogenic carbon capture and storage (BECCS) balances this elsewhere in the system. In other words, the combustion emissions of synthetic fuels are offset in advance by biogenic CCS. For accounting purposes, the carbon source used for producing synthetic fuel (whether fossil, biogenic, or from direct air capture) is treated equivalently, provided that the net effect is balanced through BECCS at system level.

This balance is enforced by linking the synthetic fuel production to the availability of BECCS across the EU. The CO₂ required for synthetic fuel production is compared to the EU27 BECCS potential reported in the second data collection. Synthetic fuel production is limited so that the total CO₂ required for synthetic fuels does not exceed this BECCS potential. Only in years where the BECCS potential remains after covering the CO₂ related to synthetic fuels is the remaining BECCS counted as a net negative emission in the carbon budget. In years where the BECCS potential is exhausted by the synthetic fuel production, synthetic fuels are still treated as net zero, but no additional negative emissions from BECCS are booked.

In addition to CO₂ capture related to synthetic fuels, the carbon budget includes other CCS volumes and an indicative slack term. Explicitly reported CCS and BECCS figures from data collections and other scenario sources are included as removals where they correspond to permanent carbon storage. An additional non-country-specific slack term is introduced to reflect the uncertainty around future CCS deployment, and to allow aggregate capture up to the ESABCC technical limit, even where detailed national data is missing. Together, these CCS / BECCS contributions, subject to the ESABCC cap and after accounting for CO₂ capture related to synthetic fuels, form the non-synthetic fuel part of capture-related removals.

LULUCF is treated separately. Net removals from the LULUCF sector, representing CO₂ fluxes between soils, biomass and the atmosphere, are taken from the IA and NECPs and ­entered directly as negative emissions in the Supply Tool.

The methodology reflects the EU Climate Law, which only covers part of the international transport. This means that it covers only 50 % of extra EU international shipping, as well as intra-EU flights and flights departing from the EU to European Economic Area (EEA) non-EU countries, the United Kingdom, and Switzerland.

The carbon budget methodology starts with ETM fuel ­consumption, applies fuel-specific CO₂ emission factors, and takes into account shares of biofuel and synthetic fuel using TSO data. These emissions are then adjusted using discount factors to reflect the intra-EEA share of international transport. The factors are 45 % for aviation³ and 35 % for maritime navigation. These factors are derived from Joint Research Centre’s Integrated Database of the European Energy ­System (JRC IDEES) 2023⁴, and an additional 50 % discount is applied to the remaining share of navigation emissions.

It is assumed that both international shipping and international aviation will follow EU regulation in the future, and that they will therefore use low emissions fuel.

For 2030, emissions from international aviation and maritime transport are benchmarked against the EU‑wide estimated range of 106 –154.1 MtCO₂eq, corresponding to emissions covered under the EU ETS, as reported in the EU‑wide assessment of the final updated National Energy and Climate Plans. This range reflects the estimated emissions from international transport within the scope of EU climate policy, including intra‑EU aviation and the relevant share of maritime transport emissions regulated under EU law. For subsequent years, projections from the IA are used as a reference.

In the model, hydrogen imports are represented by two cost bands. Together, these import cost bands represent the main market dynamics that are expected to dominate the future trade of non-EU hydrogen imports.

Long-term contracts (LTC) with take-or-pay obligations are expected to be essential for the economic viability of infrastructure and investments in non-EU hydrogen import. Exporting countries, particularly those with a comparably low internal demand for renewable hydrogen, will require long-term off-take commitments. In an economic dispatch model such as that used for the TYNDP 2026 Scenarios, LTCs are represented as inelastic hydrogen supply, reflecting the contractual obligation to deliver predefined volumes irrespective of short-term market conditions. As a simplification, these flows are assumed to be non-price-responsive and are therefore modelled as an inelastic import component with a cost of 0 € / MWh. Due to the sector-coupled set-up, this representation can propagate into the electricity market by lowering the implied cost of hydrogen as a fuel and thereby affecting the merit-order position and dispatch of hydrogen-based generation.

In contrast, spot market-driven hydrogen imports that occur depending on their competitiveness with domestic EU hydrogen production. This allows them to flexibly react to economic signals of domestic hydrogen supply scarcity and fluctuating hydrogen demand. Since an economic dispatch model is used, the supply cost of market-driven hydrogen imports is modelled using the corresponding marginal production and transport costs.

Marginal production and transport costs are estimated using the EWI Global PtX Cost Tool in its version released in June 2025.

The cost calculation in the EWI tool, uses baseline investment cost assumptions are used (which can be baseline or optimistic), affecting all production units investment costs in the origin countries. For hydrogen pipeline costs and shipping charter rates, the medium-cost options are selected from the available ranges (high-cost new, low-cost new, repurposing for pipelines; medium-cost, high-cost, low-cost for shipping). Greenfield infrastructure is assumed instead of retrofitting, because consistent information on the ­proportion of retrofitting for individual projects is unavailable.

In any case, pipeline costs represent only a relatively small proportion of the total costs in the tool. The tool’s option that prioritises power generation over Power-­to-X is not activated, because it would allocate the best renewable energy potential in each country to domestic electricity demand first and only use second-best sites for hydrogen production. As the analysis relies on proxy data for renewable potential, this option is not considered appropriate here.

Several adjustments have been made to the default ­methodology of the EWI tool in relation to the weighted average cost of capital (WACC), as the original WACC ­values are uneven and reflect current conditions rather than future developments. The new values use today’s ­country-specific country default spreads and risk premiums⁶. For Tunisia, Algeria’s WACC (15.6 %) is used as a proxy for the higher ­Tunisian value (21.1 %). For Ukraine, Romania’s WACC (12.8 %) is used for the period 2040 – 2050 instead of Ukraine’s (24.8 %), and an average of the Romanian and Ukrainian WACC values is used for 2035.

The hydrogen import costs for the flexible import band are then derived by selecting specific cost components from the EWI tool. For hydrogen imported via pipeline, the calculation includes the levelised cost of electricity used to operate the electrolyser (i. e. electricity as feedstock) and the pipeline transport costs. Fixed operation and maintenance costs (FOM) and electrolyser CAPEX are not included. For hydrogen imported in the form of ammonia, the calculation includes the levelised cost of hydrogen used as feedstock to produce ammonia, the electricity costs for ammonia synthesis, transport costs for ammonia, the electricity and fuel costs for ammonia cracking, storage costs, and the costs associated with losses along the chain. FOM and CAPEX for ammonia production and cracking are disregarded.

Additionally, a water cost of 0.27 € / MWh is added, consistent with the value used in the previous cycle. All values originally expressed in US dollars are converted to euros using the average 2023 exchange rate (1 EUR = 1.0831 USD). Together, these elements form the basis for the marginal hydrogen import costs applied to the higher-cost import band in the model.

The NT+ scenario and Economic Variants use the import ­capacities from projects submitted to the TYNDP 2024 (excluding cancelled projects), considering maximum ­theoretical flow potentials for pipeline imports and import potentials applying the “lesser of” rule for shipped ­hydrogen and ammonia imports.

Additional potential reflecting national long-term strategies and political views beyond the reported projects (see Table) is only made available to the model in the SOS loop.

LTC and spot market-driven imports are reflected using two different cost bands. This division represents a split between an inelastic part (LTC) and a flexible part. For both the NT+ scenario and the Economic Variants, the LTC represents 50 % of the maximum theoretical import pipeline flow potential, calculated based on the hourly supply profile. This is shown conceptually for a seven-day period, below. The remaining flow potential is considered fully flexible and available at marginal costs. For ammonia imports, the LTC represents 50 % of the import potential when the “lesser of” rule is applied.

Hydrogen supply sensitivity

In addition to the 50 % LTC band selected for the NT+ scenario and the Economic Variants stress tests, further sensitivity analysis is conducted on the hydrogen supply mix structure. In this case, the LTC band for non-EU imports is varied as an exploratory exercise in the NT+ scenario’s results when alternative assumptions are applied to all modelled target years. This sensitivity analysis is intended as an exploratory exercise on the hydrogen supply structure. For reference, it considers the indicative direction outlined in the REPowerEU Plan, which refers to a 50 / 50 split between non-EU imports and EU production by 2030, with the aim of moving away from importing Russian fossil fuels into EU.

The narrative and results of this supply sensitivity analysis, which increases the LTC share for all non-EU import corridors to 80 %, are discussed further in the Scenario Report.

This illustrative sensitivity analysis (see Figure 6) does not affect the definition or interpretation of the central NT+ ­scenario. The assumptions, narrative and results of this sensitivity analysis are discussed separately in the Scenario Report.