Green Hydrogen – the Big Unknown in the EU Power System

Author: ICIS Editorial


This story has originally been published for ICIS Long-Term Power Analytics subscribers on 23 April 2020 at 18:00 CET.

Hydrogen produced by electrolysis is expected to expand over the next 30 years, which will have a significant effect on European power markets. We analysed the impact of between 1 and 35 GW of hydrogen electrolyser capacity being added in the EU between 2020 and 2030.

Since the increased electricity demand cannot be fully covered by renewables, the scenarios lead to higher thermal generation, emissions and power prices in most European countries. In Germany and France, power prices could increase by up to €5/MWh in 2030, while in Scandinavia the power price could increase up to €20/MWh in the extreme scenario.


The production of hydrogen based on electrolysis and powered by mostly renewable electricity (so called green hydrogen) can provide flexibility and storage capacity for power markets and also enables so-called sector coupling: replacing grey hydrogen or natural gas in the industry, transport and heating sectors. Grey hydrogen describes hydrogen that is produced from natural gas, which currently account for nearly 50% of worldwide demand. Just 4% is currently produced with electrolysers, according to IRENA.

Therefore, many European countries have included green hydrogen in their energy transition plans and published hydrogen strategies with ambitious targets (e.g. Netherlands 3-4 GW electrolysers in 2030, Germany 3-5 GW electrolyser in 2030). Moreover, several publications and studies forecast that green hydrogen will play a major role in reaching the EU climate goal to be GHG neutral in 2050 (IRENA, Hydrogen Council, Fraunhofer). We also record that an increasing number of utilities and other market participants perceive hydrogen as a viable solution and attribute to hydrogen a high potential to change the supply in power and heats as well as the transport and industry sectors.


We modelled electrolyser as power demand, which consumes electricity when the power price is below a specific response price, representing the profitability limit. This can be seen similar to the marginal costs of power plants. The higher the response price the more often the electrolyser is used, i.e. the power price need to fall below this limit to operate the electrolyser profitable. We furthermore assume that green hydrogen is profitable when its variable costs are below the variable costs of grey hydrogen.

The produced green hydrogen can be used in several use cases:

  • Replace grey hydrogen in industry and transport
  • Replace natural gas in heating and industry
  • Storing electricity as a battery for the power system

For the latter, green hydrogen is injected into the gas grid and at a later point in time used to generate electricity in gas turbines for the power system. In general, the more conversion steps are taken the higher the losses. Burning hydrogen in gas power plants or in a hydrogen cell means losing another 50% of the energy. We will discuss all possibilities in the results chapter and explain why its a misconception that green hydrogen is a way to decarbonise the power system.

Cost of Hydrogen

  • The cost of grey hydrogen is calculated out of the efficiency of steam reforming and national gas prices. Today the Levelized Costs of Hydrogen (LCOH) for green hydrogen are still much higher than those for grey hydrogen, but it is expected that green hydrogen will become competitive in 2030.
  • Increasing gas prices will further improve the competitiveness of green hydrogen.
  • To reach national and EU wide targets we assume that the construction of green hydrogen plants will be incentivised until green hydrogen becomes profitable.

Variable Costs

We modelled three different response prices representing different technical use cases. These use cases could for example represent the transformation into hydrogen (power-to-hydrogen), methane (power-to-gas) or synthetic fuels (power-to-fuels). Nevertheless, in the model we assumed that there will be an equal share of electrolyser with a low, medium and high response price.

Electrolyser Capacities

The estimation for the electrolyser capacities until 2050 are based on the EU report “A Clean Planet for all – A European long-term strategic vision for a prosperous, modern, competitive and climate neutral economy”, as well as on the Fraunhofer Hydrogen Roadmap and national hydrogen targets for the capacities in 2030. Between these years we assumed a linear interpolation of growth. Based on these capacities we created three expansion scenarios with the following capacity assumptions:

Base Scenario Combo Scenario Tech Scenario
2019 0.6 GW 1.7 GW 2.9 GW
2030 7 GW 20 GW 35 GW
2050 18 GW 352 GW 511 GW

The increasing share of renewable generated electricity in the EU power mix enables the production of additional green hydrogen on top of the current electricity demand. In general, additional electrolysers improve the flexibility and utilisation of the power system after the thermal phase-outs of base-load nuclear, coal and lignite power plants. We assume that first the direct hydrogen demand, mostly from the industry, would be covered before hydrogen is fed into the gas grid. This is possible until there is around 10% hydrogen in the gas grid. If more than 10% of the natural gas in the grid is replaced with hydrogen, it is possible to inject additional hydrogen based methane. Nevertheless, governments stress that a climate neutral Europe would need to import significant amounts of hydrogen as domestic renewable resources would not be able to cover to whole primary energy demand.

For our scenarios we distributed the electrolyser capacities in Europe based on the renewable energy capacities including hydro and bio in each country, following the basic idea that the more renewable generation the better the conditions for electrolysers producing green hydrogen. We use the same ambitious renewables extension plans for all three hydrogen scenarios in line with current policies.

Impact on the Generation Mix

The additional power demand caused by hydrogen will be covered by nearly all other energy sources. The biggest share of the additional demand is covered by natural gas power plants providing the flexibility to produce when it is needed. Whether the utilisation of solar and wind increases depends on how often they had to be switched off before because of grid restriction or lower demand as supply. For Germany, both onshore and offshore wind realize higher utilisation whereas the solar generation is mostly constant in all scenarios. Only water reservoirs and pumped storages generate less as they naturally compete with hydrogen as a storage technology.

Higher Emissions

It is important to take a deeper look into emissions as this is a controversial topic. First, we want to make transparent how much emissions are set free for green and grey hydrogen. Second, we look at the emissions of the power sector and how they change with increasing installations of electrolysers and third, we analyse what additional hydrogen means for other sectors.

The more renewables there are installed, the lower the emissions of the power sector and the lower the emissions of green hydrogen. Nevertheless, as no country produces its electricity just with renewables the production of green hydrogen also leads to emissions. Our calculation shows that the emissions from producing hydrogen with gas (grey hydrogen) in comparison to the emissions from producing hydrogen with the current electricity mix (green hydrogen) are still lower. Nevertheless, going forward in 2030 the hydrogen production with the EU power mix will lead to significant lower emissions as using grey hydrogen.

  • Emissions of gas steam reforming
    • 2020: 8.41 kg CO2/kg H2
  • Emission of electrolysis with German energy mix
    • 2020: 12.14 kg CO2/kg H2
    • 2030: 10.05 kg CO2/kg H2
  • Emissions of electrolysis with EU energy mix
    • 2020: 8.86 kg CO2/kg H2
    • 2030: 6.289 kg CO2/kg H2

With additional green hydrogen the demand for electricity increases. Higher power demand leads to more generation from nearly all fuel types, especially thermal generation. This is reflected in higher emission numbers in the hydrogen scenarios, although the changes stay below 15 mt per year in Europe. Only hydro generation slightly decreases as the pump storage capacities are used less. The predominant share of additional emissions due to electrolyser demand comes from Germany followed by Great Britain, the Netherlands, Italy and Spain.

The usage of green hydrogen over grey hydrogen shifts emissions to the power sector as presented above. Furthermore, the overall emissions of green hydrogen will be higher until enough renewables are installed in the power system to push emissions below 8.41 kg CO2/kg H2. Nevertheless, in other sectors hydrogen can replace emissions and above all avoid local emissions such as in the transport and heating sector. Especially towards 2030 when emissions of green hydrogen are significantly lower, the cross-sectoral balance is positive and green hydrogen can be used to replace oil and reduce the carbon footprint.

Utilisation of installed electrolysers

We also analysed the utilisation of installed electrolysers. We see a strong cannibalization: the more hydrogen is installed, the lower the full load hours. This is the case between the scenarios as well as comparing 2020 with 2030. Due to higher price levels in 2030, expansive hydrogen runs more in 2030 compared to 2020.

  • In 2020, the country with the best conditions is France. About 5,500 full load hours can be reached with the most efficient technologies. Nevertheless, the less efficient electrolysers run in just 1,700 and 650 full load hours.
  • In comparison, in Spain the full load hours with the most efficient technology are about 4,500.
  • Until 2030 the full load hours of Germany, UK, the Netherlands and France increase and reach about 6,000, whereas in Spain and Italy the full load hours are just about 5,000 and 4,000 for the most efficient electrolysers.
  • We see that the more renewables there are installed, the more often the prices drop below the variables costs of electrolysers which increases the full load hours.

Power Prices Impact

  • Last but not least we want to shed light on the impact on power prices which differ strongly between the countries. In Germany, we forecast an annual average price increase of up to €5/MWh for the years 2027 to 2030 in the most ambitious hydrogen scenario.
  • France is in a similar range followed by Great Britain and Spain that are slightly less sensitive. With very little hydrogen capacity in Poland, the price movement is also very limited.
  • In Scandinavian countries like Norway or Sweden, green hydrogen could lead to an increase of the power price of up to €20/MWh in the late 2020s. An interesting effect can be seen in 2020 where little hydrogen capacities have a strong effect on the low Norwegian power prices.
  • You can see the German forecast in the graph below; to see other countries please subsribe to the ICIS Long-term Power Analytics 


  • In most European countries like Germany and France power prices increase up to €5/MWh in the ambitious scenario
  • In the Scandinavian countries green hydrogen has a significant impact on the prices. Power prices can increase up to €20/MWh in the extreme scenario
  • Green hydrogen shift emissions from non-ETS covered sectors to the ETS power sector

Sebastian Braun is Senior Analyst and Quantitative Team Lead at Power and Carbon Markets at ICIS. He can be reached at

Philipp Hesel is Junior Analyst – EU Carbon & Power Markets at ICIS. He can be reached at

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