This is an extract from a recent report titled “The Future of Renewable Hydrogen in the European Union” by the Belfer Center for Science and International Affairs, Harvard Kennedy School.
Hydrogen Supply and Demand
EU hydrogen demand stands at 7.8 Mt, equivalent to about 11% of global demand. Refining and fertilisers account for 3.9 Mt (50%) and 2.4 Mt (30%), respectively. Consumption for energy and transportation accounts for about 1.2%. Germany and the Netherlands are the largest consumers of hydrogen, accounting for over a third of EU demand with 1.7 Mt (22%) and 1.3 Mt (17%), respectively. Countries with demands of 0.5 Mt or more include Poland, Spain, Italy, Belgium, and France. The remaining member states collectively account for about 25% of the total demand, with national demands below 0.2 Mt each.
Germany has the largest hydrogen production capacity with 2.4 Mt/yr (21%), followed by the Netherlands with 1.7 Mt/yr (15%) and Poland with 1.4 Mt/yr (12%). Italy, France, Spain, and Belgium have capacities above 0.5 Mt/yr and amount to 27% of the total. Overall, EU hydrogen demand is mainly met by captive productions— hydrogen produced and used directly within integrated industrial sites owned by a single organisation—as the 2020 EU’s Fuel Cells and Hydrogen Observatory (FCHO) report highlights. About 88% of the total capacity is captive; merchant facilities that account for the remaining 12% often supply single customers, resulting in small and localised markets. This market structure not only limits hydrogen availability to new players, but it is also responsible for the lack of an integrated infrastructure across the EU—one of the key challenges facing hydrogen deployment at scale.
The EU’s Hydrogen Strategy
In July 2020, the European Commission (EC) published the EU’s hydrogen strategy, a three-phased plan (2020-24, 2024-30, and 2030-50) that prioritises renewable hydrogen produced by wind- and solar-powered water electrolysis. The plan acknowledges that other forms of low-carbon hydrogen, such as blue hydrogen (SMR+CCS), could play a role in developing hydrogen markets, but only as an interim solution in the short- to medium-term.
For the first two phases, the strategy defines deployment targets for electrolyzers of 6 GW by 2024 and 40 GW by 2030, which the EC estimates would allow the production of about 10 Mt/yr of hydrogen. The third phase is even more ambitious and aims to deploy renewable hydrogen at scale for all hard-to-abate sectors. Yet the strategy does not set any specific supply target either for internal production or imports, leaving unclear how member states could meet long-term demand.
Renewable Hydrogen Potential
This section analyzes renewable hydrogen potentials for each country to assess the viability of each reference scenario.
Renewable Hydrogen Potentials in the EU and Trade Partners
The detailed quantitative analysis of renewable hydrogen potentials for each country shows that only a small number of member states could become regional exporters, and that no member state has the potential to develop into an export champion. All EU member states have moderate or low potential. Central European countries such as Germany and the Netherlands have the lowest, while countries in the EU’s periphery such as Spain, Portugal, Ireland, and the Baltic States have the largest, ranging from 4 to 22 Mt/yr.
In contrast, neighbouring countries like Morocco and Norway and long-distance partners like Australia and the United States all have the potential to emerge as global export champions. Morocco dominates with more than 161 Mt/yr among regional partners, followed by Norway and Iceland with about 16 Mt/yr each. Turkey and Albania’s potentials are significantly limited by the low cost-competitiveness of their renewable energy resources. Finally, potentials for Australia and the United States are orders of magnitude larger than any other country considered, with 2,733 Mt/yr and 1,810 Mt/yr, respectively.
Our analysis reveals that fifteen member states would not be able to meet internal future hydrogen demands. Countries like Germany, the Netherlands, and Italy are constrained by low renewable energy resources and/or land availability, as well as intense competition for renewable electricity in other sectors. Only a few EU countries—Portugal, Spain, and France in the south, Ireland in the northwest, Finland and the Baltic States in the northeast—have potentials that could fulfill internal demand and allow them to emerge as regional exporters. These uneven renewable hydrogen potentials across the EU highlight, once more, the key role cross-border cooperation and infrastructure planning will play in enabling fully functioning hydrogen markets in all reference scenarios. Finally, the large production potentials in regional and long-distance partners greatly exceed future EU hydrogen demand making both the Regional and Long-Distance Import scenarios viable. As for the Hydrogen Independence scenario, overall viability depends on whether excess production by EU regional exporters can fill the gap of the more than half of member states who cannot meet internal demand.
Hydrogen Independence Scenario
The EU’s combined renewable hydrogen production potential of 106 Mt/yr is higher than the projected demand of 76 Mt/yr, confirming the viability of the Hydrogen Independence scenario. At the same time, our analysis shows that in order for this scenario to materialize, key requirements must be met:
• At least two-thirds of the EU demand (48 Mt/yr) must be fulfilled from production by member states who have the potential to evolve into regional exporters.
• As much as one-third of total demand (up to 28 Mt/yr) must be met by each country’s self-consumption.
Renewable Hydrogen Cost Curves
In this section, we analyze renewable hydrogen cost curves to assess the relative competitiveness of the three reference scenarios.
In general, cost curves are graphs of production costs as a function of total quantities produced. In free-market economies, stakeholders optimize production by minimizing costs associated with each level of production. In order to highlight key cost-competitiveness factors between reference scenarios, production costs in each curve are also represented as a function of renewable electricity, electrolysis, and operating costs.
Cost Curves in the Hydrogen Independence Scenario
EU renewable hydrogen cost curves elucidate the competitiveness of both the Hydrogen Independence scenario and overall EU hydrogen production in the scenarios that include imports. Depending on how much hydrogen can be produced internally at a competitive price, EU production will supply a larger or smaller share of total demand compared to imports. Renewable hydrogen cost curves for the member states that have the potential to become regional exporters show significant differences in production costs between EU countries, ranging from 2.7 to 4.4 USD/kg. Ireland, Cyprus, and Portugal have the most competitive potentials with production costs below 3 USD/kg thanks to wind energy resources with high capacity factors. On the other hand, Romania and Hungary have the least competitive potentials due to solar energy with low capacity factors that lead to production costs of over 4 USD/kg.
Cost Curves in the Regional and Long-Distance Reference Scenarios
In line with the Hydrogen Independence scenario, cost curves for regional and long-distance partners reveal a wide range of production costs —from 2.5 to 4.4 USD/kg, but with much larger production potentials at costs below 3 USD/kg. Only Australia has a significant share of its overall potential (13%) above 4 USD/kg. Despite similar production cost ranges, regional and long-distance partners have significantly larger competitive renewable hydrogen potentials than EU countries.
Renewable Hydrogen Markets
This section assesses future hydrogen markets based on supply costs (production plus transportation costs), trade flows, and investment needs for each reference scenario.
The MIGHTY model considers future EU demand, renewable hydrogen potential, cost curves, and transportation costs to optimize hydrogen trades between countries in each scenario. As discussed, hydrogen’s preferred transportation option is still unclear. Hence, the model considers two transportation alternatives for each of the reference scenarios (Hydrogen Independence [HI], Regional Imports [RI], and Long-Distance Imports [LDI]).
- Hydrogen gas pipelines plus liquefied hydrogen shipping (LH2). Hydrogen is dispatched as a compressed gas between continental countries and as liquefied hydrogen by sea.
- Hydrogen gas pipelines plus ammonia shipping (NH3). Hydrogen is dispatched as compressed gas between continental countries and as ammonia by before being reconverted to hydrogen on arrival.
Hydrogen Supply Costs
Our analysis shows how meeting EU renewable hydrogen demand would cost between 253 billion and 293 billion USD per year.
Overall, scenarios where hydrogen is shipped as ammonia result in lower supply costs, thanks to both lower transportation costs (shipping ammonia is significantly less costly than shipping liquefied hydrogen) and higher volumes from producers with lower costs than those in EU countries. Renewable hydrogen imports from outside the EU could lower overall supply costs between 6% and 12%, even when higher transportation costs are accounted for. Long-distance partners, however, provide no additional cost optimization opportunities because the higher transportation costs increasingly offset lower production costs. Hence, if cost considerations are prioritized, the Regional Imports scenario is the optimal route for meeting future renewable hydrogen demand in the EU at the lowest cost possible.
Renewable Hydrogen Trade Flows
International trade of renewable hydrogen plays a significant role in all reference scenarios. Based on our analysis, trade between countries would cover between almost 70% and 86% of EU overall demand. To elucidate the associated market dynamics, we developed flow diagrams for each reference scenario, connecting supply with demand.
- Hydrogen Independence Scenario
In the Hydrogen Independence scenario, renewable hydrogen trades between member states would account for almost 70% of demand, while the remainder would be self-consumption. Almost all hydrogen would be dispatched by pipeline, resulting in similar trade flows between countries regardless of the sea shipping choice. In this scenario, two regions—the Iberian Peninsula and the Baltic States— and two member states—Ireland and Denmark—would supply nearly nine out of ten kilograms of renewable hydrogen traded within the EU. The Iberian Peninsula would become the largest export region, with Spain and Portugal dispatching around 23 Mt/yr of renewable hydrogen to Italy, France, Germany, and Belgium. In the east, the Baltic States would supply nearly 11 Mt/yr of renewable hydrogen to other member states, with Denmark supplying about 5 Mt/yr mainly to the Netherlands and Germany. Only Ireland would deliver by ship about 12 Mt/yr to the continent.
- Regional Imports Scenario
When considering imports from regional partners, overall supply costs decrease between 6% and 12%. In part this is because lower cost internal trade between member states and imports from regional partners account for up to 86% of EU overall demand. Shipped hydrogen represents a more significant fraction of demand here than it does in the Hydrogen Independence scenario, and trade flows change considerably depending on the shipping choice. The lower transportation costs associated with ammonia shipping increase imports from regional partners to 63 Mt/yr, while the costlier shipping of liquefied hydrogen limits imports to 47 Mt/yr.
- Long-Distance Imports Scenario
Our analysis shows that adding long-distance partners would increase the share of EU demand supplied by trades between EU countries and regional and long-distance partners up to 86%. Long-distance imports, however, would only play a meaningful role if competitive shipping costs were available. Long-distance imports are largely uncompetitive with liquefied hydrogen shipping and amount to about 0.1 Mt/yr, while they increase to 17 Mt/yr with ammonia shipping. In the latter case, the United States could become the largest supplier of renewable hydrogen to the EU with 17 Mt/yr. Despite Australia’s vast potential and highly competitive production costs, their imports cannot enter the supply mix due to the high transportation costs.
Investments between 2 trillion and 2.4 trillion USD in renewables, electrolysis, and enabling infrastructure would be needed to meet future EU renewable hydrogen demand. Hydrogen imports could lower total investment needs by 9% to 13%, but they would also change the physical allocation with significant market consequences.
In all scenarios, investments in renewables and electrolysis account for more than 80% of overall CAPEX, reaching 90% in the Hydrogen Independence case. Investments in renewables are lower in the Regional and Long-Distance Imports scenarios for two reasons. Countries like Morocco and the United States can rely on solar power, while key EU producers like Ireland, Denmark, and the Baltic States would need to deploy costlier wind power because they lack competitive solar resources. In addition, higher capacity factors for renewable energy resources in regional and long-distance partners would reduce overall investment needs.
Since underlying assumptions and estimations may vary over time due to multiple external factors, it is crucial to conduct sensitivity analyses on key variables and evaluate possible impacts on overall results. For example, in the past, technological cost reductions have been faster than anticipated in some cases, like with solar photovoltaics, and slower in other cases. As discussed, the MIGHTY model identifies key trade partners for meeting EU hydrogen demands at the lowest possible cost. Hence, renewable hydrogen production and transportation costs, a function of investment costs, are key drivers in the reference scenarios’ results. Consequently, a ±50% sensitivity analysis on investment costs for renewable energy, electrolysers, pipelines, and hydrogen shipping is carried out. In addition, a ±50% sensitivity to the cost of capital, represented by the overall discount rate, is also carried out.
The sensitivity analyses show that while overall supply costs change significantly, the impact on the reference scenario rankings is negligible. The overall implications and considerations remain the same, because all the scenarios are affected consistently by the sensitivity analyses. For example, if electrolyzers were 50% cheaper than in the reference case, supply costs would decrease about 20% across all scenarios.
Across all the scenarios, the cost of capital is the variable with the highest impact on overall supply costs, followed by renewable energy and electrolyzer investment costs. The sensitivity analysis shows how a 4% discount rate (50% lower than the base case) would reduce supply costs to between 2.5 and 2.9 USD/kg, from 3.3 to 3.9 USD/kg. This trend highlights how policy measures aimed at reducing the cost of capital could be particularly effective in increasing competitiveness and driving adoption at scale.
Finally, changes in transportation costs with respect to the base case have only minor impacts on overall supply costs. At the same time, cheaper-than-expected shipping could result in more considerable reductions in overall supply costs than cheaper-than-expected pipelines because shipping would allow for more imports at lower production costs. On the other hand, if transportation costs were to be more expensive, the EU could limit the impact by reducing trade and developing its domestic resources. Both considerations can only be elucidated thanks to the MIGHTY model, which optimizes overall supply costs based on production potentials and transportation costs.
The complete report can be accessed here