Scenario Results

The level of detail provided for each scenario depends on the approach to building the data set.

The National Trends bottom-up collection uses gas and electricity demand data from TSOs in line with draft NECPs. The final energy demand supplied by other primary fuels, such as that for heat and transport, is not available to TSOs; therefore sector by sector energy demand splits cannot be reported. The bottom up data is based on member state draft NECPs, this underpins the assumption that the bottom up gas and electricity demand data contributes fairly towards the EU28 Clean Energy Package targets for 2030; 32 % renewable energy along with 32.5 % energy efficiency.

The new top-down scenario building approach provides the ENTSOs with new opportunities to report on total primary energy and the sector splits for final energy demand. The top-down energy modelling approach evolves in five year steps from historical energy balance data, so it is possible to report on the sectoral final energy demand over time.

5.1 Demand

Note: All gas figures are expressed in gross calorific value. Where needed, external scenario figures have been converted to gross calorific values by applying a factor of 110 %.

5.1.1 Final Energy Demand

The chart below shows the total energy sector demand for the storylines Distributed Energy and Global Ambition. A key driver in how the final energy demand volumes are derived is a EU28 target specifying a 32.5 % reduction in final use energy demand by 2030 compared to 2005. The final use demand for the EU28 according to DEE2012/27/EU(10309/18)5 should be around 11,100 TWh. The final use energy demand figure does not include the energy requirement for non-energy uses. When this adjustment is taken into account, final energy demand in 2030 for Distributed Energy is 10,800 TWh and Global Ambition 10,900 TWh.

Final energy demand can achieve ambitious reductions in energy volume due to changes to end user devices and energy efficiency measures. The scenario storylines capture themes such as, but not limited to:

  • Converting from less efficient heating options to heat pump technologies, such as gas, electric and hybrid (electric heat pump associated with condensing gas boiler)
  • Switching from low efficiency transport options to more efficient modes of transport
  • Energy efficiency product standards; continue to deliver energy efficiency gains for end-user appliances
  • In the built environment, thermal insulation reduces demand for heat, while ensuring comfort level are maintained
  • Behavioural changes where consumers actively reduce demand either by utilising more public transport or modifying heating and cooling comfort levels.
Figure 6

Figure 6: Final energy demand in Cop21 scenarios

Although overall final energy demand is decreasing, gas and electricity show different trends. For gas, at least until 2025 as well as for electricity in the long-run, the energy demand growth is driven by factors such as underlying gross domestic product (GDP) growth, additional energy demand from low temperature heat and transport sectors as these sectors switch away from carbon-intensive fuels, such as coal and oil. The storylines assume that at an EU level underlying GDP growth is tempered by the strong energy efficiency measures, so that final energy demand (which includes electricity demand) is reduced to meet the EU28 32.5 % energy efficiency target for 2030.

The National Trends energy figures are based on the TSO data compatible with the latest available data from member state NECPs. The annual energy volumes come from national forecasts, that are summed to provide information at EU28 level.

5.1.2 Direct Electricity Demand6

The scenarios show that higher direct electrification of final use demand across all sectors results in increase in the need for electricity generation.

Distributed Energy is the scenario storyline with the highest annual electricity demand hitting around 3,800 TWh by 2040.

The results for scenarios show that there is the potential for year on year growth for EU28 direct electricity demand. The table provides annual EU-28 electricity demand volumes and the associated growth rate for the specified periods.

6 Direct Electricity Demand refers to the electricity end use in sectors such as residential, tertiary, transport and industry.

ScenarioEU-28 Annual Electricity Demand (TWh)CAGR
Historical Demand3,086
National Trends3,2373,5540.3 %0.6 %
Global Ambition3,2833,4760.4 %0.5 %
Distributed Energy3,4643,8290.8 %0.9 %

Table 3: Annual EU-28 electricity demand volumes and the associated growth rate

The growth rates for the storylines show that by 2040 National Trends is centrally positioned in terms of growth between the two more-ambitious top-down scenarios Distributed Energy and Global Ambition. The main reason for the switch in growth rates is due to the fact that Global ambition has the strongest levels of energy efficiency, whereas for Distributed Energy strong electricity demand growth is linked to high electrification from high uptake of electric vehicles and heat pumps, dominating electrical energy efficiency gains.

Peak electricity demand is defined as the highest single hourly power demand (GW) within a given year. Peak demand growth in the future will be impacted in a number of ways, for example;

  • The roll out of smart metering, these may provide more opportunities for time of use supplier charging, so consumers can make more efficient choices.
  • High growth rates for passenger electric vehicles lead to pressures on the electrical grid, both at distribution and transmission levels. The scenarios assume that there is an inherent level of smart charging that shifts consumer behaviour away from peak periods.
  • Electric and hybrid heat pumps. The demand time series created are weather dependent. The results show that electric heat pumps can add pressure to demand; i.e. there is more heat demand when outside temperatures are low. There are a number of options to support direct electric heating, such as, thermal storage, or hybrid heating systems. For example: Hybrid systems can help mitigate the adverse impact on the electricity grid by switching to gas during extreme cold periods (typically less than 5°C).
  • New peak demand changes may stem from additional new baseload demand, such as data centres, especially as digitalisation continues to sweep across the globe.
Figure 7

Figure 7: Direct electricity demand per scenario 2030 and 2040 (EU28)

The hourly demand charts show that the historical effects of GDP and energy efficiency continue influence electricity demand growth in industry, tertiary and residential sectors. The scenarios show that direct electrification of transport and heating sectors starts to have a significant impact on the hourly profiles.

It is clear from the future demand profile composition that the impact of electric vehicles is noticeable across each season. The impact for heat pumps is however dependent on the outside weather temperature. It can be seen that there is a reduced demand for heat in the summer, but electrified water heating remains part of the composition during summer periods.

Figure 8

Figure 8: Example winter hourly demand profile for a single market node – impact of direct electrification in heating and transport sectors

Figure 9

Figure 9: Example summer hourly demand profile for a single market node – impact of direct electrification in heating and transport sectors

Peak demand for electricity grows between 2030 and 2040 for each storyline. The electrification of heat and transport are two significant drivers in growth of electricity peak demand. The storyline assumptions mean that GDP related peak demand growth is moderated by energy efficiency. The impact of demand side response on peak electricity is modelled as a priced demand side response unit directly in the ENTSO-E power market tools.

The National Trends demand profiles are developed from the TSOs input based on latest available member state draft NECPs and where available national projections for 2040. For the top-down scenarios the ENTSOs assume a high uptake of smart charging for transport, which will moderate peak demand growth rates. The demand profiles account for outside temperature and the impact on peak demand; this is important as the share of electricity within the heating sector increases.

Annual Peak Demand (GW)
National Trends5686251.0 %
Global Ambition5435700.5 %
Distributed Energy5726441.2 %

Table 4: Annual EU-28 electricity peak demand and the ­associated growth rate for the specified periods

For the top-down scenarios there is rational spread in peak demand growth rates between 2030 and 2040. Global Ambition is the scenario with the lowest levels of heat pumps, coupled with higher energy efficiency, the effect is that the scenario has the lowest peak demand growth between 2030 & 2040. In Distributed Energy the main driver for higher peak demand is the higher rates of electrification across all sectors, however, it is important to note this can provide additional opportunities for demand side response, such as vehicle to grid or demand flexibilities at domestic level.

The peak demand growth rate in National Trends between 2030 and 2040 indicates a 1.0 % year on year growth in peak demand. The growth rate for National Trends lies firmly in between the demand growth rates for Distributed Energy and Global Ambition. The spread in peak demand provides an opportunity for all three scenarios to enhance the understanding on the long-term impacts for the European transmission system.

Figure 10

Figure 10: Peak electricity demand (GW) per scenario 2030 and 2040

Direct electrification of transport and heat

Electrification of heat and transport are two key areas necessary to decarbonise the European energy system. The information received from the TSOs and the COP21 scenarios show that electric vehicles and heat pumps have the greatest impact on electricity demand. The charts show how the scenario electric vehicles and heat pumps compare to external scenarios referenced in the chart as “range”.

The scenarios aim to reduce emissions in line with the European targets and COP21 pathways. To achieve ambitious emission reductions in the heating sector a shift away from fossil fuels is required. The scenarios show that moving away from oil and coal is a quick win to reduce emissions in heating sector. The top-down and bottom up scenarios highlight the need for consumers to change how they heat their homes and businesses. The scenarios require a large shift towards electric and hybrid heat pumps, which reduce both primary energy demand and final use energy demand due to the impact of heat pump co-efficient of performance. Heat pump technologies are used for space heating and sanity water heating.


Distributed Energy has the highest electrification with 245 Million electric vehicles and around 50 million heat pumps by 2040. The volumes relating to electric vehicles and heat pumps provide insight into why the Distributed Energy electricity demand reaches 3,800 TWh by 2040.

Global Ambition is a scenario where there is strong uptake of electric vehicles reaching around 200 million by 2040 but lower heat pump uptake at around 25 million devices. The scenario assumes more uptake of alternative low carbon heating to ensure that the emissions levels for the scenarios are achieved.

The National Trends scenario is based on TSO data and shows that there is a lower level of ambition for electrification of the transport sector around 100 million electric vehicles with around 60 million heat pumps by 2040.

The scenario numbers for electric vehicles and electric and hybrid heat pumps technologies are shown on the charts. The shaded area represents a range of minimum and maximum values from third party studies, see section 8 for further information. The charts show that the input assumptions for heat pumps and electric vehicles numbers lie within credible values.

Figure 11
Figure 11 b

Figure 11: Number of Electric and Plug-in Hybrid Passenger Vehicles (above) and Number of Electric and Hybrid Heat Pumps (below) compared to a range based on analysis of third party reports

5.1.3 Gas Demand

Total gas demand7 is split up into final demand (residential, tertiary, industry incl. non-energy uses and transport) and demand for power generation. While scenarios can show a decrease or increase for the total gas demand, the different sectors can evolve independently and in different directions.

By 2030, National Trends has the lowest total gas demand. In contrary to that, Global Ambition and Distributed Energy reach higher decarbonisation levels of the energy system with more gas. This is due to a faster switch from carbon-intensive fuels, such as coal and oil, to gas, but also due to higher shares of renewable and decarbonised gases in the gas mix.

When comparing the sectoral split, all scenarios register a decrease in the residential and tertiary sector, but the uptake of gas demand in the transport sector can compensate parts of it in the COP21 Scenarios. These trends remain until 2040, resulting in lower demand for all scenarios with National Trends and Distributed Energy below 4,000 TWh (−20 % compared to today’s level). Percentage-wise the transport sector has the highest change from 2020 to 2040. In all scenarios, gas demand for transport increases, most significantly in Global Ambition.

It is worth mentioning, that the development of final gas demand differs from region to region. Due to a high dependency on coal, gas demand for heating increases in Central and Eastern Europe, whereas other regions head towards more electrification in the private heating sector. To give an example coal has a share of up to 50 % in the heating sector and 80 % in the power generation in Poland.

A switch from carbon-intensive coal to natural gas with lower carbon intensity by 2025, results in 290 TWh additional gas demand. However, this would lead to emissions reduction in electricity generation of up to 150 MtCO2. At least until 2030 gas demand for power generation is increasing with the level of decarbonisation and electricity demand. Therefore, Distributed Energy as the scenario with the highest electricity demand has up to 42,7 % more gas demand for power generation than National Trends with the lowest gas demand for electricity generation. Same trend can be seen for 2040.

7 Total gas demand can also be referred to as “Gross Inland Consumption” of gas as done by Eurostat

Figure 12

Figure 12: Sectoral breakdown of total gas demand in EU28

Peak demand generally follows the annual trends

The high daily-peak and 2-week demand requirements8 reflect the changing nature of residential and commercial demand, as temperature-dependent space heating typically drives peak gas consumption. As a result, final demand for peak day and 2-week decreases in all scenarios due to efficiency measures with with the largest decrease in Distributed Energy, due to a higher penetration of electrical heat pumps. National Trends observes the most limited change as consumers have invested in more traditional technologies, although they are considered less efficient.

8 The “2-week demand” refers to a two-week period during a cold spell with very low temperatures resulting in high heating demand

Figure 13

Figure 13: Gas demand in high demand cases (Peak, 2-Week cold spell, Dunkelflaute*)

* “Kalte Dunkelflaute” or just “Dunkelflaute” (German for “cold dark doldrums”) expesses a climate case, where in addition to a 2-week cold spell, variable RES electricity generation is low due to the lack of wind and sunlight.

The gas system can support the high development of variable RES.

The significant development of variable electricity RES capacities in both scenarios influences the role of the gas infrastructure to back-up the variable power generation. With significant variable RES-E capacities in the energy system, the gas demand may be impacted by Dunkelflaute events more often and more intensely.

Decarbonisation of the energy system comes with an uptake of the hydrogen demand

As a consequence of an increasing volume of hydrogen generation, the COP 21 scenarios consider contrasted development of the hydrogen demand that could materialise to make use of this potential:

  • Distributed Energy scenario considers a higher penetration of P2G technologies with significant volumes produced more locally and thus a similar development of the Hydrogen demand.
  • Global Ambition scenario considers a more centralised decarbonisation where the Hydrogen demand is mainly driven by the need for pre-combustion decarbonisation with a partial shift of the final demand to Hydrogen.
Figure 14

Figure 14: Methane and hydrogen demand in COP21 scenarios

5.2 Supply

5.2.1 Primary energy supply

For the COP21 Scenarios, the overall energy mix becomes carbon-neutral by 2050. To fully decarbonize, both COP21 Scenarios register a significant increase in both renewables and further CO2 removal technologies, while reducing primary energy demand. Whereas both scenarios reach similar levels of demand decrease of around 42 % to 43 %, the RES share in Global Ambition reaches 64 % by 2050 but is still outbid by Distributed Energy with a RES share of 80 %.

The vast majority of energy is from renewables. Wind, solar and hydro cover roughly 45 % of primary energy demand in Europe in Distributed Energy and above 31 % in Global Ambition, while nuclear contributes approximately 10 % in both scenarios. Biomass and energy from waste materials contribute significantly – in Distributed Energy they cover 35 % and in Global Ambition 33 % of the primary energy mix. Biomass can be directly used in industrial processes, or as feedstock to produce biofuels or biomethane – both can be used in all sectors, with a main focus in power generation, transport and heating.

Since coal is phased out already by 2040, remaining demand is covered by oil, nuclear and gas imports. The increase in renewable energy production results in declining import shares, from 55 % to 60 % nowadays, to ca. 20 % in Distributed Energy and 36 % in Global Ambition9.

A key enabler for the transition is the conversion of wind and solar power to P2G, which balances the variable electricity supply with energy demand and allows utilization of energy sourced from renewable electricity in final consumption sectors when there is no electricity demand.

9 For the calculation of import shares, it is assumed that all oil and nuclear energy is imported in 2050.

Figure 15

Figure 15: Primary energy mix in Distributed Energy and its RES-share (Solids: coal, lignite, peat and coke)

5.2.2 Electricity

In the COP21 Scenarios, the electricity mix becomes carbon neutral by 2040. In EU-28, electricity from renewable sources meets up to 63 % of power demand in 2030 and 83 % in 2040. Variable renewables (wind and solar) play a key role in this transition, as their share in the electricity mix grows to over 40 % by 2030 and over 55 % by 2040.

The remaining renewable capacity consists of biofuels and hydro. All figures stated above exclude power dedicated for P2X use, which is assumed to be entirely from curtailed RES, and newly build renewables that are not grid-connected, and therefore not considered in this representation.

Figure 16

Figure 16: Percentage share of electricity demand covered by RES

There is an increase in renewable capacity foreseen in all scenarios…
… but the speed of the uptake is contingent on the storyline associated with each scenario.

Distributed Energy is the scenario with the highest investment in generation capacity, driven mainly by the highest level of electrical demand. Distributed Energy mainly focuses on the development of Solar PV, this technology has the lowest load factor, as result Solar PV installed capacity will be higher compared to offshore or onshore wind, to meet the same energy requirement. The scenario shows a larger growth in Onshore Wind after 2030.

In 2030, 13 % of electricity is produced from Solar and 28 % from wind, 41 % in total. In 2040 17 % of the electricity is generated from solar and 41 % from wind 58 % in total. The scenario also sees the least amount of electricity produced from nuclear out of the three scenarios, providing 15 % of electricity in 2030 and 9 % in 2040.

Global Ambition has a lower electricity demand, with a general trend of higher nuclear and reduced prices for offshore wind. Consequently, the capacity required for this scenario is the lowest as more energy is produced per MW of installed capacity in offshore wind, and nuclear is used as base load technology providing 18 % of energy in 2030 and reducing to 10 % in 2040. In 2030, 10 % of electricity is produced from Solar and 30 % from wind, 40 % in total. In 2040 12 % of the electricity is generated from solar and 44 % from wind 56 % in total.

National Trends is the policy-based scenario. The variable renewable generation is somewhere between the two top down scenarios. In 2030, 12 % of electricity is produced from Solar and 29 % from wind, 41 % in total. In 2040 14 % of the electricity is generated from solar and 41 % from wind 55 % in total. A lot of electricity is still produced from nuclear in 2030 20 % reducing to 12.5 % in 2040, this makes National Trends the scenario with the highest nuclear production in all timeframes.

Shares of coal for electricity generation decrease across all scenarios. This is due to national policies on coal phase-out, such as stated by UK and Italy or planned by Germany. Coal generation moves from 10 % in 2025, to 4 % – 6 % in 2030 and negligible amounts in 2040 which represents an almost complete phase out of coal.

Gas, however, has a share of 22 % in 2025, which reduces in 2030 to a range of 12 % – 18 %, and finally a share of 9 % –12 % in 2040. It is important to note that the level of decarbonised and renewable gases in the gas mix, increases to 13 % in 2030 and 54 % in 2040. Distributed Energy starts to show a need for CCS in 2040, which will lead to negative emissions in plants burning biomethane.

Considerations on Other Non-Renewables (mainly smaller scale CHPs) source are important for decarbonisation. As it stands, carbon-based fuels are still widely used in CHP plants throughout Europe. This includes oil, lignite, coal and gas. In order to follow the thermal phase-out storylines, oil, coal and lignite should be phased out by 2040 and replaced with cleaner energy sources. Gas will contribute to decarbonisation by increasing shares of renewable and decarbonised gas.

Other RES contains generation technologies such as marine, small biofuel and geothermal. The generation from this collection of technologies remains stable in all scenarios.

Generation from hydro increases in 2030 due to an increase in capacity from 145 GW in 2025 to 174 GW in 2030, but remains stable after 2030. As hydro potential is determined by very specific conditions, therefore bottom up data is used for all scenarios.

The scenarios include repowering of renewable generation technologies from 2025 until 2040 with higher full load hours.

Thermal capacities are reduced, not only due to national phase-out policies, but the fact that some generation units will no longer be economically viable due to reduced running hours or will reach the end of their lifetime.

Figure 17

Figure 17: Electricity generation mix (TWh)

Figure 18

Figure 18: Electricity capacity mix (GW)

The scenarios show that there is potential for demand side technologies and batteries to take part in the market and help to smoothen demand peaks and level prices. Whilst the energy from these technologies may be low, it shows potential to reduce generation from carbon based peaking units, supporting decarbonisation, contributing towards system adequacy at lower costs and helping to integrate increasing variable renewables.

Distributed Energy shows the highest increase in usage of these technologies in 2030, whilst the other scenarios show relatively moderate to low usage. Distributed Energy shows more use of demand side resources as the cost of residential solar and battery systems are discounted. In 2040, there is a much larger increase in use of battery technologies in all scenarios, the most noticeable are Distributed Energy and National Trends.

Figure 19

Figure 19: Peak load, demand side response & battery technology (TWh)

5.2.3 Gas Gas supply potentials

Indigenous production: contrasted views captured by the COP 21 scenarios

All scenarios consider a similar decrease of the conventional indigenous production. However, the assumptions on the indigenous renewable gas generation, such as biomethane and P2G differ across the scenarios:

  • 2020 and 2025 rely on Best Estimates from the TSOs. Due to the decreasing domestic conventional gas production and rather stable gas demand, gas imports will increase.
  • National Trends relies on bottom-up data for the indigenious production for natural gas (including unconventional gas, such as shale gas) and biomethane. Additionaly, P2G is added assuming that curtailed electricity will be used to produce hydrogen and synthetic methane.
  • Distributed Energy considers a significant uptake of decentralised renewable gas generation to account for 65 % of the EU gas consumption in 2050. Considering a gradually decreasing gas demand after 2025, gas imports decrease by 70 % compared to today’s level.
  • Global Ambition scenario considers the uptake of renewable gas generation capacities to a lesser extent with a more import oriented vision and large scale decarbonisation. Imports represent 70 % of the EU gas consumption in 2050. Considering a gradually decreasing gas demand after 2025, gas imports decrease by 30 % compared to today’s level.

The contrasted approach towards the supply configurations is essential when assessing the infrastructure for the next twenty years since it directly impacts the way the European gas system is used.

Enough gas potential to satisfy the EU demand until 2050

All scenarios consider a maximum utilisation of indigenous production in the European gas supply mix until 2050. The supply potential assessment run by ENTSOG and discussed with stakeholders in July 201910 concludes that for all ­scenarios, the import potentials are high enough to ensure the supply and demand adequacy of the EU until 2050. This is despite the decline of the conventional indigenous production. In this regard, it can be highlighted that the Dutch Government has decided to stop production at ­Groningen, Europe’s largest onshore natural gas field, by 2022. Additionally, the supply mix will be further diversified with new sources looking towards 2050.

Furthermore, whilst Norwegian supply is produced in Europe, it is considered as an import source to the EU since Norway is not a Member of the European Union.

The import supply mix will be dominated by gas from Russia, Norway and LNG.

Even though the supply mix will be diversified, the import supply mix will still be dominated by the current three largest supply sources: Russia, Norway and liquefied natural gas (LNG). These sources will be dependent on market prices, and the supply chain’s adaptation of the growing demand for decarbonised gases.

Figures 20, 21 and 22 highlight the adequacy of scenario specific gas demand and supply. Supply is split into three categories:

  • Total EU indigenous Production covers all domestic production of conventional natural gas, biomethane and P2G for both hydrogen and methane.
  • Minimum Extra-EU Supply Potentials: minimum gas imports based on long-term contracts and their assumed prolongation
  • Additional Supply Potential: additional gas imports options which will be used based on arbitrage

All scenarios show enough supply potentials to meet the future demand.

Figure 20
Figure 21
Figure 22
Figure 22 b

Figure 20–22: National Trends, Distributed Energy, Global Ambition Gas supply composition

A technology neutral approach

The decarbonisation of the gas supply can be done in many ways. Gas can either be produced from renewable energy such as biomethane or hydrogen from P2G, but it can also be decarbonised from conventional natural gas with different technologies such as steam methane reforming (associated with carbon capture and sequestration process) or pyrolysis.

Each technology comes with its level of decarbonisation that is considered in the computation of the GHG emissions of each scenario to keep track of their carbon budget expenses. For instance, biomethane can be considered as carbon neutral or carbon negative if associated with CCS (therefore included in Bio-Energy Carbon Capture and Sequestration (BECCS) category). However, CCS processes come with efficiency factors to account for the part of the CO2 that cannot be captured in the process and that is therefore released in the atmosphere.

In order to capture all possible impacts of the development of one or another technology, the scenarios come with contrasted assumptions regarding the penetration of renewable or decarbonised gases in the supply mix of the EU.

A source neutral approach

TYNDP 2020 scenarios consider contrasted possible developments of the gas demand including different gas qualities. The ENTSOs have improved their methodology and introduced a more detailed breakdown of the gas demand between methane and hydrogen.

However, there are different technological ways both these demands can be satisfied. Methane and hydrogen demands can of course primarily be satisfied respectively by methane and hydrogen production. On one hand, depending on the penetration of the different generation technologies, methane can be decarbonised to generate hydrogen and therefore satisfy the hydrogen demand. On the other hand, hydrogen can be methanised to create methane and therefore satisfy the methane demand. It should be noted that any conversion process comes with an efficiency factor considered when building the scenarios.

In line with the neutral approach of ENTSOG towards the infrastructure submitted to TYNDP, the scenarios are technology neutral. Therefore, unless a piece of infrastructure is actually commissioned no choice is made by ENTSOG and the scenarios do not pre-empt the location of the conversion of the gas supply to satisfy the demand. The conversion could therefore be centralised at transmission level or be decentralised at city/consumer gate. National Trends

The gas supply mix considered in National Trends reflects the current European targets and respective Member States’ draft NECPs. The level of information regarding the gas supply mix can be very different depending on how the targets are set in the draft NECPs. Thus, due to lack of consistency between the draft NECPs, the gas supply mix for National Trends is not split into different gas qualities. In any case, based on information available for demand and national production, National Trends shows an increasing import dependency for gas, peaking in 2030 with 4,300 TWh and then decreasing down to 3,000 TWh in 2040 (500 TWh below 2015).

Figure 23

Figure 23: Gas source composition: National Trends Distributed Energy Scenario

As a decentralised scenario, Distributed Energy considers a high level of indigenous production of renewable gas. Imports are reduced by 70 % between 2020 and 2050, accounting for 2,000 TWh in 2040, and 1,100 TWh in 2050. The level of imports is the lowest of all the scenarios. Thus, reaching carbon neutrality by 2050 means that the remaining imports, whether renewable or to be decarbonised is limited to 1,100 TWh of the gas supply. However, aiming for decarbonisation requires a significant increase in renewable electricity generation to meet the P2G demand.

Figure 24

Figure 24: Gas source composition: Distributed Energy Global Ambition Scenario

As a centralised scenario, Global Ambition considers a higher level of total imports for energy, with a 30 % decrease of the gas imports by 2050 compared to current levels (−1,100 TWh). The increasing imports, up to 4,000 TWh in 2030, compensate for the decline of the conventional indigenous production. To reach carbon neutrality in 2050, the gas imports to be decarbonised or renewable by then must be of a larger scale than in Distributed Energy (2,700 TWh/y).

Figure 25

Figure 25: Gas source composition: Global Ambition

5.3 Sector Coupling: Capacity and Generation for P2G

Distributed Energy has a significantly higher demand for EU produced hydrogen and synthetic methane than Global Ambition in 2030 and 2040. The Distributed Energy storyline assumes a reduction by 70 % of gas imports by 2050 (from 4,000 TWh in 2020 down to 1,200 TWh in 2050) combined with the decarbonisation of the gas supply.

Distributed Energy and Global Ambition have a specific demand for domestically produced hydrogen. In these scenarios, power to gas plants are operated outside the energy markets, using dedicated renewables, but the curtailed electricity from the market is used to feed these power-to-gas plants. National Trends does not have a specific top down demand for hydrogen, therefore the Power to Gas plants are built solely based on curtailed renewables.

In the COP21 scenarios, the main source used for electrolysis is offshore wind, but where regional constraints exist, onshore wind and solar PV will be the alternative. The generation profiles match the capacities build. There is more RES capacity in Distributed Energy 2040 therefore it is natural that there is more curtailed energy in this scenario.

Figure 26

Figure 26: Capacities for Hydrogen Production

Figure 27

Figure 27: Power to Gas Generation Mix

5.4 Reduction in overall EU28 CO2 Emissions and necessary measures

Following the EU’s long-term goal, National Trend is treated to reach 80 % to 95 % decarbonisation by 2050. Although the commonly agreed target for 2030 is 40 % GHG emission reduction, the latest adoptions to the 2030 climate and energy framework (32,5 % improvement in energy efficiency, 32 % share for renewable energy) will consequently result in higher GHG emissions reductions. This is also shown by the European Commission’s Long-term Strategy Scenarios. On the other hand, the COP21 scenarios go for carbon neutrality by 2050, as suggested by the latest IPCC Special Report11 and targeted by the European Commission.

11 IPCC special report on the impacts of global warming of 1.5° C above pre-industrial levels and related global greenhouse gas emission pathways, Intergovernmental Panel on Climate Change, 2018

As mentioned in Section 5.2.1, both COP21 Scenarios show a significant decrease in primary energy demand with increasing shares of renewables, mainly biomass and variable sources (both for direct use and P2G production). Whereas electricity generation has already faced some level of transition, other carriers such as gas need to follow. ENTSOs’ scenario building exercise shows that to decarbonise all sectors as well as all fuel types, additional measures such as CCU/S, also in combination with bioenergy, are needed. Full decarbonisation also needs the contribution of non-energy related sectors, such as the decarbonisation of agriculture/meat production and further afforestation. It should be noted, that for GHG emissions related to non-CO2 emissions (e. g. methane emissions) and LULUFC, ENTSOs’ scenarios rely on the average given by the 1.5TECH and 1.5LIFE scenarios of the European Commission’s Long-term Strategy.

Figure 28

Figure 28: GHG emissions reduction pathways until 2050

Electricity Generation

In 2030 the electricity sector produces emissions of between 393 and 414 MtCO2, a reduction of around 75 % as compared to 1990. In the COP21 Scenarios, the electricity mix becomes carbon neutral by 2040 with emissions of 46 MtCO2 in Distributed Energy and 40 MtCO2 in Global Ambition. In this case both scenarios have the gas before coal merit order, but as the demand is higher in Distributed Energy, there is more consumption of both gas and coal. However, to meet the ambitious targets for electricity generation, fuel input into small scale CHP, mainly gas, needs to be 90 % decarbonised. Moreover, in Distributed Energy also CCU/S needs to be applied to CCGTs by 2040.

National Trends sees emissions of 182 MtCO2, on target with the 2° C scenarios shown in the Long-term Strategy from the European Commission.

Figure 29

Figure 29: CO2 emissions reduction pathways until 2050

Gas supply

Gas as an energy carrier with increasing shares of renewable and decarbonised gases plays a key role in the decarbonisation of the economy. Biomethane and renewable gases produced via P2G do not have CO2 emissions, but if CCU/S (post-combustive or during the production of biomethane) is applied their consumption can even lead to negative emissions. Apart from indigenously produced renewable gases, also the consumed natural gas needs to be decarbonised with carbon capture technologies, either pre-combustive in combination with steam methane reforming or methane pyrolysis, or post-combustive in large-scale industrial sites or power plants. However, post-combustive CCS may mostly be applied to large scale process such as industrial sites or power plants and its carbon capture rate is usually around 90 %.

In Distributed Energy in 2050, 65 % of the gas will be renewable, but for the other 35 % need to be decarbonised with carbon capture technologies: in 2050, to be carbon-neutral, 90 MtCO2 need to be captured during the conversion of natural gas into hydrogen and additionally 50 MtCO2 need to be removed post-combustive at industrial sites.

Figure 30 shows the emissions related to the consumption of gases and the average carbon intensity (in kgCO2/kWh) of the gas mix in Distributed Energy. Due to above mentioned restrictions for post-combustive CCS, the CO2 intensity of the gas mix decreases by 87 % in Distributed Energy by 2050 compared to conventional natural gas.

Due to higher imports, Global Ambition sees a broader need for CCU/S to decarbonise the gas mix to reach carbon neutrality. If natural gas is used as a feedstock to produce the needed hydrogen, 170 MtCO2 need to be captured and stored or used. Additionally, 170 MtCO2 need to be removed post-combustive. Furthermore, 150 MtCO2 needs to be captured from bioenergy, which allows for negative emissions. The CO2 intensity of gas decreases by 80 % in Global Ambition in 2050 compared to conventional natural gas.

In this context the ENTSOs’ assumptions on the need and application of CCS are guided by the European Commission’s Long-term Strategy and its most ambitious 1.5° C scenarios: 1.5LIFE and 1.5TECH see the necessity of 281 to 606 MtCO2 captured.

Figure 30

Figure 30: Decarbonisation path of gas in Distributed Energy

Figure 31

Figure 31: Decarbonisation path of gas in Global Ambition