The Case for Recalibrating Europe’s Hydrogen Strategy
Introduction
In the five years since the European Commission unveiled its 2020 European Hydrogen Strategy, the European Union’s (EU’s) hydrogen market has captured significant global attention from policymakers and industry stakeholders. By taking the lead in developing a renewable hydrogen industry through progressive policies, targets, and technological innovation, the EU has showcased both the immense potential and the substantial challenges of this transition. Executing this vision has proved difficult, with many early expectations — such as rapid progress, cost reductions, and broad offtake applications — now proven to be overly ambitious or unattainable in the short term.
Kickstarting decarbonization of hard-to-electrify sectors will require robust support for offtakers through financial incentives, clear sectoral mandates, realistic infrastructure planning, and a stable regulatory framework that strengthens industry confidence and reassures investors. By mobilizing investors and developers through a pragmatic, implementation-focused approach, the EU can accelerate the scaling of its renewable hydrogen industry and solidify its leadership in the global energy transition. This in turn will support the Commission’s interlinked objectives to drive industrial competitiveness and domestic job creation across the bloc in line with its recently released Clean Industrial Deal.
This report evaluates the current state of the EU hydrogen market and provides policymakers with a set of implementation-oriented policy levers and strategic choices to consider. We focus on five key pillars:
- Achievable supply and demand projections
- Directing focus to hard-to-electrify sectors
- Balancing carrots and sticks to drive offtake
- Aligning public funding to policy objectives
- Guiding industry with a stable regulatory environment
1. Supply and demand of renewable hydrogen in Europe
Key takeaways:
- Supply and Demand Gap: Current renewable hydrogen production is only 0.02 million tonnes per year (Mtpa), far below the EU’s unrealistic consumption targets of 20 Mtpa by 2030. We project regulated demand from existing policy measures to range between 2.2 and 2.8 Mtpa by 2030, driven by mandates in industry and transportation. Our Accelerated Transition Scenario suggests up to 7.0 Mtpa of demand could materialize.
- Strategic Use of Imports: Imports can complement domestic supply to bridge short-term supply gaps while domestic production scales.
- Planning Infrastructure around Demand: Accelerating infrastructure investments for imported and intra-EU traded hydrogen derivatives will ensure the creation of resilient supply chains for key demand markets (NL, FR, BE, DE).
To meet climate goals, the European Union has sought to scale both the production and consumption of renewable hydrogen — a cornerstone of its strategy to decarbonize industry and heavy transport. According to the IEA’s Hydrogen Production Database, current production levels stand at just 0.02 million tonnes per year (Mtpa), highlighting the slow progress toward meeting the targets set by the Renewable Energy Directive (RED III). This shortfall underscores the urgent need for a delivery-focused approach to accelerate domestic production and secure stable international supply chains to meet additional demand.
Driven by sector-specific mandates under RED III, demand for renewable hydrogen in the EU is expected to increase significantly over the next 5 years. We modeled two scenarios to understand how this could materialize:
- Baseline Scenario – Assumes full implementation of RED III mandates.[1]
- Accelerated Transition Scenario (ATS) – Envisions greater sectoral ambition, including voluntary demand beyond mandates.
As shown in Exhibit 1, total demand is projected to range between 3.7 Mtpa and 7.0 Mtpa by 2030, through the combination of mandated demand across existing consumption within industry, transportation, and potential demand if realized under the Accelerated Transition Scenario.
RED III mandates are expected to drive demand between 2.2 Mtpa and 2.8 Mtpa, far below the EU Hydrogen Strategy’s 10 Mtpa target. As the industry mandate is applied to existing users of hydrogen, this demand is expected to be driven by ammonia production, chemicals, and refinery processes. However, despite refineries consuming the greatest amount of hydrogen out of all sectors, hydrogen accounting methodologies impact how much of this consumption is subject to RED III’s renewable fuel of non-biologic origin (RFNBO) mandates.
Currently, most hydrogen produced in refineries is derived from byproduct gases and used for conventional transport fuels which reduces the volume of enforceable demand under RFNBO mandates. With the current methodology, refinery consumption subject to mandates by 2030 is estimated to be approximately 0.8 Mtpa, although this volume could be expanded due to the individual transposition of RED III by Member States. As an example, Belgium is considering the inclusion of hydrogen use in the processing of conventional transport fuels (known as the ‘refinery route’) as a vector to accelerate its hydrogen industry. However, it is important to note that mandates applied in this fashion will count toward transportation targets and will not affect the volume of industry consumption mandated.
The role of shipping and steel as additional demand
Looking beyond mandates, additional demand — driven primarily by the steel and maritime sectors — is expected to range from 1.5 Mtpa to 4.2 Mtpa.
While falling underneath the European Commission’s definition of industry, steelmaking currently uses a negligible amount of hydrogen, meaning the majority of production is not required to transition to RFNBOs. However, steelmaking has emerged as a significant demand driver among new uses for hydrogen, since steel has few options to decarbonize[2]. This transition is further accelerated by surging demand for certified green steel from automakers, construction firms, and industrial buyers aiming to meet strict sustainability targets. In addition to the overall CO2 abatement potential, it is likely the desire to shift to hydrogen steel is also brought about by concerns of industrial competitiveness, with hydrogen-steel providing relief from growing ETS carbon prices for conventional steelmaking and the phase-out of free allowances by 2034. The EU has also shown an appetite to fund hydrogen-steel, allocating some of the largest grants under the Innovation Fund to these projects.[3] It is imperative that policymakers further incentivize the use of renewable hydrogen within low-carbon steelmaking, as many companies are considering the use of unabated natural gas in the interim, which could undermine real climate benefits while prolonging reliance on imported fossil fuels.
Similarly, aside from hydrogen derivatives, the maritime sector has few scalable alternatives for decarbonization. The International Maritime Organization (IMO) is actively working to reduce greenhouse gas (GHG) emissions from shipping, targeting net-zero emissions by 2050. One of its proposed measures includes a global carbon levy and a fuel standard, requiring at least 5% — and striving for 10% — of the energy used by international shipping to come from renewable fuels and sources by 2030. Domestically, maritime activities were recently included under the ETS, and the EU passed the FuelEU legislation implementing decarbonization targets for the sector. If implemented fully, these policies will significantly influence renewable hydrogen’s uptake, driving additional demand outside of RED III.
Complementing domestic supply with imports
While domestic production is expected to scale this decade, hydrogen trade will play an essential role in closing short- to medium-term supply gaps, enabling early decarbonization, and positioning the EU as a lead market in the global hydrogen landscape. Despite ongoing project development, the current European hydrogen project pipeline is unlikely to solely meet anticipated demand. As illustrated for the Accelerated Transition Scenario in Exhibit 2, the projected supply-demand gap in 2030 is estimated to range between 1.9 Mtpa and 4.3 Mtpa, given the current trajectory of project completion. This highlights a significant shortfall that could delay climate-aligned progress and hinder industrial adoption.
However, there is also a plausible scenario where domestic supply could scale to meet RED III 2030 mandated volumes. With projected domestic hydrogen supply reaching a maximum of 2.7 Mtpa and RED III mandates requiring between 2.2 and 2.8 Mtpa, production could theoretically cover the lower end of mandated demand. Even if this scenario materializes, significant uncertainties remain, including the volatility of electricity prices and timeline to build continental hydrogen pipelines. Moreover, any disruption in project execution, infrastructure bottlenecks, or unforeseen regulatory challenges could push the EU into a supply deficit, necessitating imports to fill the gap. If domestic production does scale effectively while demand remains at the lower end of projections, Europe may be able to achieve self-sufficiency to meet regulatory requirements. However, this achievement comes with limited flexibility to support voluntary demand beyond mandates. Implementation of the recently released Clean Industrial Deal’s supply and demand-side oriented actions should increase the attractiveness of domestic production. In either scenario, enabling increased supply will require increased disbursement of funds, explored later in section 4.
Given high domestic hydrogen production costs and competition for renewable electricity across the bloc, strategic imports can provide a practical and cost-effective solution to meet the EU’s scaling demand for green fuels and feedstocks. Finished hydrogen derivatives (e.g., fertilizers, synthetic sustainable aviation fuels [eSAFs], e-ammonia, e-methanol, and hydrogen-produced direct reduced iron [DRI]) are more likely to meet this demand given the high cost and commercial immaturity of cracking. Balancing cost-effective imports with domestic industrialization is key: in the case of DRI, imported green iron can complement the growth of EU green steel while enabling flexibility for domestic growth and economic transitions. In parallel to imported derivatives, intra-EU trade from regions with ideal renewable energy conditions can serve to fill supply gaps in high-demand regions, with the objective to ensure a steady and affordable supply for Europe’s heavy industry and transport sectors.
Planning hydrogen infrastructure around key demand centers
As shown in Exhibit 3, RED III-mandated demand is concentrated in Northwest Europe, particularly in Germany, the Netherlands, France, and Belgium; countries with strong industrial bases that will rely heavily on hydrogen to decarbonize heavy industry and transportation sectors. Meanwhile, additional hydrogen demand is expected to emerge primarily from the steel and maritime sectors, placing countries with large steelmaking industries and key maritime bunkering hubs at the forefront of additional demand growth.
Not all these demand centers will be collocated with optimal renewable electricity resources, necessitating a considered approach to the distribution and transportation of hydrogen derivatives across the continent. A robust infrastructure network is essential for integrating imported hydrogen into Europe’s domestic supply chain. Investments in import terminals, pipelines, and storage facilities, will be key enablers for hydrogen distribution across sectors and geographies, ensuring that supply reaches offtakers efficiently. Intra-European trade will also play a pivotal role, allowing cost-advantaged production hubs —such as the Iberian Peninsula and Nordic regions — to transport hydrogen to high-demand industrial centers in Northwest Europe. By accelerating these infrastructure investments, the EU can the create foundations of a stable and resilient hydrogen market, which will in turn enhance economic competitiveness and secure pathways to long-term industrial decarbonization.
2. Prioritizing hard-to-electrify sectors
Key takeaway: Public and private investments should be directed to steelmaking, fertilizers, refining, aviation, and shipping; sectors where hydrogen provides the most decarbonization value. Allocating resources to low-impact uses like heating and light-duty vehicles represents inefficient use of scarce public funds and risks delaying necessary transitions through electrification and energy efficiency measures.
While Europe undeniably needs to scale its renewable hydrogen supply chains, this can be done strategically and pragmatically, focusing on use cases where hydrogen is essential for decarbonization.
It’s time to retire any lingering misconceptions of hydrogen as a Swiss army knife for economy-wide decarbonization. Hydrogen — when produced renewably — can enable Europe’s heavy transport and industrial sectors to decarbonize and will reduce the region’s dependence on imported natural gas. However, with renewable fuels and feedstocks both expensive and relatively scarce, policymaker support for hydrogen should focus and direct funding only to hard-to-electrify sectors in parallel with support for electrification and energy efficiency measures. Demand-side investments and policies should prioritize hydrogen applications in steelmaking, e-fuels, fertilizers, and refining to maximize emissions reductions, efficiently leverage public funds and ensure these high-impact industries are empowered to transition to renewable hydrogen.
Advocating for hydrogen’s use in applications with low emissions reduction potential risks eroding public trust in its role as a net-zero solution and delaying critical transitions from fossil fuels to electrification. Applications for hydrogen such as building heating, power generation, or light-duty vehicle refueling would be better served by investments in energy efficiency or direct electrification.
Citing economic and technical barriers to fuel-switching, many large European steel, chemicals, shipping, and aviation companies have resisted moving toward renewable hydrogen and are increasingly investing in natural gas as a transition molecule. Considering the limited public funds available and economic headwinds for industry, a cost-effective approach must be pursued to maintain forward momentum and drive investments in decarbonization. As industry wavers, now is the time for policymakers to implement existing sectoral transition roadmaps and ensure regulatory signals — such as the RED III mandates — are transposed rapidly and in full.
3. Balancing carrots and sticks to drive offtake
Key takeaway:
- Implementing a complementary ‘carrots’ and ‘sticks’ approach can enhance the economic viability of renewable hydrogen production and consumption in the bloc. RED III mandates, sector-specific penalties (e.g., ReFuelEU), monetized EU Allowances (EUAs) and rising ETS costs represent cost-effective measures that can increase willingness-to-pay for renewable hydrogen if implemented cohesively, which reduces reliance on expensive subsidizes.
- Ensuring consistent and timely implementation of sectoral mandates is the most effective way to stimulate demand, allowing policymakers to steer investment to priority sectors.
- This should be coupled with targeted distribution of funds along sectoral lines through competitive mechanisms like the European Hydrogen Bank and proposed Industrial Decarbonisation Bank.
Stimulating demand for renewable hydrogen in sectors where electrification isn’t possible can be achieved through a complementary ‘carrots’ and ‘sticks’ approach to enhance the economic viability of renewable hydrogen as a driver of decarbonization within the bloc. While subsidies are an important tool for early-stage market development, they do not have to completely close the price disparity between renewable hydrogen and incumbent fuels and feedstocks. Policymakers need to consider the effectiveness of multiple mechanisms at their disposal, leveraging market mechanisms such as mandates and the EU Emissions Trading System (ETS) to reduce reliance on expensive subsidies. Doubling down and scaling such mechanisms would be most cost-effective solution to accelerate industrial decarbonization, although this is likely not feasible with current political and market limitations.
The RED III mandates—if fully implemented by EU Member States—can significantly boost demand for RFNBOs within priority sectors. By increasing the willingness to pay (WTP) for renewable hydrogen and associated technologies, these mandates can help drive private investment into the hydrogen value chain. Member States have an opportunity to design penalties that can raise the WTP for industrial hydrogen consumers, as shown in Exhibit 5. Enforceable mandates also provide clear direction for investors and can inform project bankability. When implemented cohesively with subsidies, this can bridge the remaining gap and protect European consumers from experiencing additional inflationary pressure while renewable hydrogen markets mature. Member States have until the end of May 2025 to transpose the directive into national legislation, and it is imperative that these quotas are supported with strong, enforceable penalties for non-compliance to protect the decarbonization intent of the RNFBO targets.
Supplementary sector-specific penalties, such as those for aviation under ReFuelEU, can create additional economic incentives for industries to transition from fossil fuels to RFNBOs. Over time, as ETS costs rise, WTP will increase further, narrowing the price gap between grey and renewable hydrogen. Additionally, the near-term ability to monetize excess EU Allowances (EUAs) allocated to renewable hydrogen production can enhance the financial viability of these projects, further boosting WTP and market readiness.[4]
Neglecting to issue penalties under RED III carries risks of delaying the transition to net-zero technologies if public support is insufficient to influence business decisions. Germany has confirmed that it will not issue obligations or quotas to meet RED III targets, relying on subsidies to incentivize firms to make the switch. A ‘carrots-only’ approach could increase uncertainty for investors who may find it more difficult to trust ongoing subsidy support (prone to changing funding priorities) compared with factoring in the compliance costs for sectoral mandates. While carbon-pricing under the ETS and other EU-level regulation will push up the willingness-to-pay, this is unlikely to reassure investors in the near term and suggests that Germany may not be able to meet RED III’s 2030 goals.
Moreover, without equal and unilateral treatment of emissions-reduction obligations across the European market (and international suppliers through measures like the Carbon Border Adjustment mechanism), incumbent industry leaders are likely to continue to delay offtake decisions for renewable hydrogen which will stifle investment decisions on the supply side. Delaying the transition to net-zero technologies also increases the risk of misplaced investments in solutions with carbon lock-in that will become stranded assets in the decades to come as the world decarbonizes.
4. Aligning public funding to policy objectives
Key takeaways:
- Public Funding Gap: Current funding commitments fall short of what is needed to achieve the EU’s hydrogen and climate objectives. Approximately €13,9 billion in public funding will be needed to implement RED III mandates and an extra €31,7 to enable faster decarbonization under the Accelerated Transition Scenario.
- Unlocking Private Investment: Public funding could unlock approximately €251 billion in private capital expenditures. This is equivalent to a 7x leverage effect in mobilizing private investment from public funds.
- Slow Deployment: Despite €21,4 billion in relevant committed funds from the Commission and Member States, only €3 billion in public funding has been disbursed to renewable hydrogen projects and end-users.
- Geographic Focus: A near-term focus on key demand centers can kickstart the decarbonization of major industrial centers, although a more equitable EU-wide distribution of public funding will be required in the long term to effectively scale hydrogen adoption across all Member States.
Like all markets around the world, the initial optimism surrounding Europe’s renewable hydrogen sector was driven by expectations of rapid cost reductions. However, these expectations have not materialized, and the high cost of renewable hydrogen compared to fossil-based alternatives remains a significant barrier. As illustrated above in Exhibit 5, sustained public support will be an essential component in bridging the cost gap and stimulating demand in key sectors.
Public funding needed to bridge the willingness-to-pay gap
Between 2025 and 2030, we estimate that approximately €13,9 billion in public funding will be needed to implement RED III mandates, primarily in fertilizer and other industrial sectors (Exhibit 6).[5] To realize our Accelerated Transition Scenario (ATS), this funding would need to grow to over 3x the amount to increase financing for demand-side mechanisms. The public funding calculated represents the amount that would be needed to bridge the gap between the cost of a renewable, hydrogen-based fuel and its fossil-produced incumbent. While these cost projections were calculated with European production in mind, imported green commodities may offer cost-savings which decreases the total funding required.
Shipping and steel emerge as the primary sectors requiring financial support to unlock the Accelerated Transition Scenario's additional demand volumes. Overall, an estimated €45,6 billion in public funding would be required, which could unlock approximately €276 billion in private capital expenditures. This is equivalent to a 7x leverage effect in mobilizing private investment from public funds.
Committed funding and regional distribution
While public funding has the potential to catalyze private sector investment, current funding commitments fall short of what is needed to achieve the EU’s hydrogen and climate objectives. Despite significant amounts being earmarked by the European Commission and Member States through mechanisms such as Contracts for Difference (CfDs), H2Global, auctions, and the European Hydrogen Bank (EHB), actual funds deployed to date remain limited (Exhibit 7). These programs should be reviewed to understand deployment delays and accelerate disbursement of funds to priority sectors. It is important to note that the recently proposed Industrial Decarbonisation Bank (aiming for €100 billion in funding) represents the ideal vehicle to support the accelerated transition of Europe’s heavy-emitting sectors.
Funding is currently heavily concentrated in three countries – Germany, the Netherlands, and France. As demonstrated in Exhibit 3, these countries are key demand centers that require funding to meet their demand; but this leaves 55% of European hydrogen production without the same degree of funding. For example, Poland and Belgium comprise 19% of current consumption, mainly driven by ammonia production, and Spain and Italy’s hydrogen consumption will grow in the maritime and steel sector respectively. Overall, a more balanced distribution of funding is necessary to support hydrogen development across a wider range of Member States, particularly those that can offer competitive pricing and facilitate intra-EU hydrogen trade, such as the Iberian Peninsula and Nordic region.
Addressing the market’s economic realities
To overcome the economic challenges facing the nascent hydrogen sector, policymakers need to recalibrate their approach to how much sustained financial support will be required to support decarbonization of hard-to-electrify sectors. With decarbonization competing against other public interests, scarce public funding needs to be thoughtfully allocated to hard-to-electrify sectors and high-impact first-mover projects. While demonstration-stage funding has supported many small renewable hydrogen projects across the EU thus far, achieving RED III mandates or unlocking additional demand may require a different approach for the second von der Leyen Commission term (2025-2030).
Policymakers can expedite the release and utilization of €18 billion in undisbursed funding that is already committed across multiple EU and Member State programs. These programs should be subject to a pragmatic review to ensure that these funds can be leveraged efficiently to drive uptake of renewable hydrogen in priority end-use sectors. This may include a near-term focus on large demand centers and supporting first-mover suppliers in regions with strong renewable energy credentials. Ultimately, European policymakers should consider a more equitable long-term approach to address geographic imbalances in funding support across the bloc.
Ensuring public funding is strategically aligned with EU policy objectives is crucial to catalyze private investment, drive innovation, and scale up renewable hydrogen adoption across the EU. A well-coordinated approach will be critical to transforming Europe’s hydrogen ambitions into a fully realized industrial and economic opportunity, and policymakers need to decide the speed and scale they want to realize by 2030. Achieving faster sectoral decarbonization (as illustrated in the Accelerated Transition Scenario) will require a substantial increase in investment and broader utilization of other market-based mechanisms to resolve coordination failures within Europe’s renewable hydrogen market.
5. Guiding industry with a stable regulatory environment
Key takeaway: It is critical that the EU upholds its robust RFNBO regulations to provide the investment certainty required to finance projects for 2030 commissioning. Maintaining a stable and predictable regulatory framework is essential for driving long-term market growth, encouraging innovation, and solidifying the EU’s position as a global leader in the renewable hydrogen industry.
As the EU implements its new Clean Industrial Deal to address the competitiveness concerns raised in the 2024 Draghi Report, it should ensure that its regulatory frameworks are transparent, cross-referenced and unfaltering in climate ambition. As this pertains to kickstarting a hydrogen industry, Europe needs to hold the line on its global climate leadership and not relax its world-leading regulations. It is paramount to maintain a stable regulatory environment, not the least to provide investment certainty which is critical for developing renewable hydrogen value chains. Investors are currently planning project development and delivery decisions for a 2030 project horizon and any further regulatory uncertainty will make 2030 targets unachievable.
Reopening the RFNBO Delegated Acts will delay investment decisions and risk the creation of an industry with questionable sustainability credentials. Similarly, emissions guardrails must be maintained by ensuring the regulatory framework for low-carbon hydrogen is robust and holistic as we’ve examined in earlier analysis.
A path forward for policymakers
Now is the time for the European Commission and Member States to translate conceptual policies, rules, and funding mechanisms into effective tools to scale the EU renewable hydrogen market over the next five years. We recommend policymakers consider the following levers to drive forward market creation and implementation:
Joint Actions by European Policymakers:
- Support Priority End-Use Sectors: Increase funding for cost-effective demand mechanisms such as CfDs, tenders, and auctions; designing and communicating a program of individual funding rounds for high-impact sectors (e.g., utilizing the EHB or proposed Industrial Decarbonisation Bank to support steel, fertilizer, aviation and maritime end-users).
- Accelerate Funding Deployment: Where prudent, expedite the release and utilization of €18 billion in undisbursed funding. Expand funding within Member States that have been unable to allocate sufficient support, and/or expand EU-level programs to address the shortfall.
- Consider Aligning Public Funding with Climate and Clean Industrial Deal Goals: As demonstrated in our Accelerated Transition Scenario, scaling public funding to €46 billion can unlock €276 billion in private industry investments to accelerate decarbonization of hard-to-electrify sectors. The Industrial Decarbonisation Bank would be well-placed to drive an accelerated transition within these sectors.
- Develop Hydrogen Infrastructure: Boost EU and national funding for hydrogen import infrastructure and intra-EU trade, recalibrating infrastructure roll-out requirements to focus on realistic demand volumes within industrial clusters.
Actions by the European Commission:
- Articulate a Clear Vision: Provide updated guidance to Member States and the hydrogen industry, focusing on hard-to-electrify sectors and maintaining confidence in regulatory frameworks.
- Adjust to Market Realities: Recalibrate expectations from the unrealistic 20 Mtpa target to approximately 2.2 – 2.8 Mtpa under RED III mandates and 1.5 – 4.2 Mtpa of additional demand by 2030 under our Accelerated Transition Scenario.
- Strengthen Emissions Guardrails: Hold the line on RFNBO regulations and ensure robust and complementary accounting frameworks are put in place for low-carbon hydrogen to ensure consistency and credibility.
Actions by Member States:
- Transpose RED III Mandates: Implement enforceable quotas with strong penalties for non-compliance before May 2025 to protect the intent of RFNBO targets.
- Set Pragmatic National Targets: Define realistic production, electrolyzer capacity, and infrastructure goals in National Energy and Climate Plans (NECPs).
- Align Market Rules Across States: Coordinate the transposition of the Hydrogen and Decarbonised Gas Market Package to create a unified and functional hydrogen market.
Appendix A: Scenario assumptions for demand
Mandates
Industry: RED III-stimulated demand for industry was based on current hydrogen consumption from the European Hydrogen Observatory projected out to 2030. Sectors included within the category of ‘industry’ include refining, ammonia, methanol, other chemicals, industrial heat, steel, and other industry. Byproduct hydrogen was removed from current consumption.
Hydrogen consumption within refining introduces a special case within RED III mandates. Under the existing policy, hydrogen produced via byproduct is not included in the total amount of hydrogen subject to the 42% RFNBO industry consumption mandate. Refineries use a large amount of byproduct hydrogen, from production of styrene, ethylene, and most notably, through catalytic naphtha reforming. It was assumed that hydrogen produced outside of byproduct (such as steam methane reformation or partial oxidation) represented 56% of refinery hydrogen demand. Additionally, RED III states that hydrogen used to process “conventional transport fuels” can count toward the 1% transportation target rather than the industry target. It was assumed that 66% of intentionally produced hydrogen was used to produce transport fuels and does not fall under industry mandates. Additional refinery considerations included a -0.7% CAGR decrease in production due to a phase-out of refining in line with the broader energy transition.
The total volume of intentionally produced, non-byproduct hydrogen was assessed, and the 42% mandate was applied as per Article 22a of RED III.
Transportation: Transportation mandates were calculated using the overall energy demand for transportation in the European Union. Data was used from Eurostat for current energy demand and a 2030 projection from the European Environment Agency.
Aviation was assumed to require hydrogen to meet the 1.2% sub mandate for synthetic SAF within Annex I of ReFuelEU. Aviation within the transportation mandate accounted for the 1.5x multiplier in Article 27 of RED III.
Maritime was assumed to meet the 1.2% mandate within Article 25 of RED III. Maritime within the transportation mandate accounted for the 1.5x multiplier in Article 27 of RED III.
Other transportation RFNBO consumption was based on the total energy consumption mandated under RED III (1% of total energy) less the aviation and maritime sectors. Other transportation accounted for the 2x multiplier in Article 27 of RED III.
Accelerated Transition Scenario
The Accelerated Transition Scenario (ATS) was considered for priority sectors for hydrogen use.
Aviation
Aviation demand for hydrogen was estimated in consultation with RMI experts on demand projects for 2030 ranging from 0.5 to 1.0 million tons of hydrogen required.
Fertilizers
Fertilizer demand under the ATS was determined by calculating the amount of renewable ammonia (and subsequently hydrogen) needed to satisfy the “green hydrogen pathway” of 50% carbon intensity reduction by 2030 published by Fertilizers Europe. Data for ammonia production was based on fertilizer consumption data from the International Fertilizer Association, correcting for import and exports using Fertilizers Europe estimations.
Maritime
Maritime demand for hydrogen was determined by assuming maritime fuel use would be in line with the International Maritime Organization Greenhouse Gas Reduction Strategy target of 5% of energy demand met through zero-emission fuels by 2030, assuming 90% of zero-emission fuel is met through hydrogen-derived products.
Refining
Refinery demand under the ATS was determined by assuming the proportion of intentionally produced hydrogen that is produced renewably will follow the clean consumption for refining pathways under the IEA Net Zero Emissions scenario.
Steel
Steel demand under the ATS was found by assuming all H2-DRI and H2-ready DRI projects in the project pipeline reach operation and use between 50% to 100% hydrogen by 2030. Hydrogen demand for DRI was assumed to be 0.055 tonnes hydrogen per tonne DRI.
Appendix B: WTP Methodology and assumptions
Any monetary values found in literature or calculated through modeling that are expressed in USD were converted to EUR for analysis.
Aviation:
Costs
SAF production costs were calculated using an RMI model which includes the hydrogen feedstock price as an operating expense, other costs include bio feedstocks, CO2, energy feedstocks, operations & maintenance, and capital costs.
Parity
Parity with incumbent jet fuel is based on the current market price from IATA; at the time of writing the jet fuel price was $782/tonne.
WTP
WTP for SAF is based on the minimum expected fine for not meeting ReFuelEU mandates, as set by ReFuelEU. The fine for failure to comply for aircraft operators is required to be no less than twice as high as the average price per tonne of aviation fuel, as stated by Article 12 of the ReFuelEU regulation. Since no synthetic SAF is required until 2030, there is likely no actual penalty until then. The penalty is used as an approximation for how aircraft operators would approach procurement until 2030. Penalties affecting fuel suppliers in 2030 would be based on the price of synthetic SAF rather than the average aviation fuel price, likely pushing the WTP much higher than currently calculated.
Fertilizers:
Costs
Hydrogen conversion to ammonia was calculated using an RMI model with additional costs for ammonia storage included. Assumes Haber Bosch production of 0.3 Mt NH3.
Parity
Parity with the incumbent is based on the price of Northwest European grey ammonia produced today as published by S&P. Future prices of grey ammonia were determined assuming a decrease in natural gas costs to levels pre-Russian invasion of Ukraine.
WTP
WTP was assessed by calculating the current and future prices of grey ammonia with added carbon costs from the ETS. ETS costs were calculated using an RMI model.
Maritime:
Costs
Hydrogen conversion to ammonia and methanol was calculated using an RMI model. A surplus of FuelEU credits pooled and included as a production subsidy have a value of $222/tonne VLSFO-eq. The ammonia and methanol production costs are converted to $/tonne VLSFO-equivalent using an ammonia energy density of 5.22 kWh/kg, methanol density of 5.54 kWh/kg, and VLSFO energy density of 11.38 kWh/kg from Ship and Bunker.
Parity
Parity with the incumbent is based on the price of VLSFO fuel in the market today as published by Ship & Bunker; at the time of writing the market price was $680/tonne.
WTP
WTP is based on parity with the incumbent VLSFO fuel with the addition of the FuelEU penalty and ETS carbon cost for the use of VLSFO in Europe; $33.5/tonne VLSFO-eq. for the 2025 FuelEU penalty; $128/tonne VLSFO-eq. for the ETS cost.
Refining:
Costs
Hydrogen production via electrolysis and dedicated renewables was calculated using an RMI model.
Parity
Parity with the incumbent is based on the production cost of gas-based hydrogen today according to the European Hydrogen Observatory, Future prices of grey hydrogen were determined assuming a decrease in natural gas costs to level pre-Russian invasion of Ukraine.
WTP
WTP was assessed by calculating the current and future prices of grey hydrogen with added carbon costs from the ETS. ETS costs were calculated using an RMI model.
Steel:
Costs
Steel production costs are calculated using an RMI model which includes the price of the hydrogen feedstock as an operating expense; other costs include energy feedstocks, metallics, operations & maintenance, material transport, and capital costs.
Parity
Parity with the incumbent is based on the spot market price of Hot Rolled Coil (HRC), assumed to reflect the price of HRC produced from a blast furnace-basic oxygen furnace integrated steel mill. At time of writing, the spot market price for HRC was $688/tonne.
WTP
WTP comes from applying a green premium to the parity price with BF-BOF steel. Based on market data and internal analysis the green premium is assumed to be 30%.
Overview:
Appendix C: Methodology to estimate public and private funding
Public funding needed to bridge WTP gap
Funding to bridge the WTP gap was found by estimating the cost of renewable fuel minus the WTP as shown above. This was done for both 2024 and 2025, expected to linearly change over time. The volume of fuel supported was assumed to be zero in 2024, incrementally increasing year over year by the size of an archetypical project, assuming exponential growth of projects deployed, until capped at the demand volume calculated for each sector using the methodology in Appendix A. A given year’s gap value was multiplied by the equivalent yearly demand value and summed to estimate the total amount of funding needed from now until 2030.
Total investments needed
The total capital needed to enable mandates and the Accelerated Transition Scenario was found using archetype projects for refining, steel, fertilizers, maritime, aviation, and an archetype for hydrogen projects for general use. The deployment of each of these projects was assumed to occur year over year until the demand found using the methodology in Appendix A was reached. That amount of projects was then multiplied by the assumed CAPEX cost for each archetypical project to find the total investments needed. The public funding needed from the previous section is expected to unlock private funds that can reach this total investment figure.
Project archetypes:
Sector
Commodity
Size
Units
Capital investment needed (billion EUR)
Installation hydrogen requirement (ktpa H2)
Aviation
eSAF
50
ktpa eSAF
1.50
26
Fertilizers
eAmmonia
278
ktpa NH3
2.62
50
Maritime
eAmmonia
300
ktpa NH3
2.62
54
Maritime
eMethanol
150
ktpa MeOH
1.16
29
Refining
Renewable hydrogen
20
ktpa H2
0.75
20
Steel
Crude steel
2,500
ktpa crude steel
7.40
138
Other
Renewable hydrogen
20
ktpa H2
0.75
20
Funding in the EU
To determine the state of public funding in the EU, we investigated EU-level and Member State-level funding data from Hydrogen Europe’s Clean Hydrogen Monitor, the European Court of Auditor’s Special report 11/2024 on renewable hydrogen policy, the Innovation Fund Project Portfolio, the Recovery and Resilience Scoreboard, and various press releases on public funding. We determined the amount that had been earmarked for hydrogen in priority sectors using schemes designed to close the cost gap (CfDs, hydrogen premiums, etc.), and the amount of these funds that had been deployed (contracts signed or awarded to specific projects).
Endnotes
[1] RED III mandates are subject to national transposition by EU Member States and will differ in execution. RED III mandates 42% of industry consumption and 1% of transportation energy to be from RFNBOs, however the distribution among industries is up to the discretion of the Member States. This is already apparent, as draft legislation in the Netherlands excludes ammonia production from the obligation, and Belgium is pursuing the “refinery route” (applying transportation requirements to refineries). Transposition variation will affect the strength of the demand signal and the overall volumes mandated in each sector.
[2] Using hydrogen offsets a substantial amount of carbon in comparison to other uses: at a rate of up to 33,6 kg of carbon dioxide (CO2) abated per kg of renewable hydrogen used compared to 11 kg of CO2 avoided in most applications.
[3] €250 million has been granted to Stegra (formerly H2 Green Steel) and €143 million to HYBRIT. Stegra’s grant ranks the 2nd highest of all Innovation Fund grants and 1st among hydrogen-related projects. HYBRIT ranks 5th among hydrogen related projects.
[4] Free allocation of EUAs will be phased out, fully ending in 2034. Monetization of these allowances will be an early consideration.
[5] The required public funding to close the premium for renewable hydrogen is determined by the difference between the production cost of renewable hydrogen-based commodities and the willingness to pay (WTP), along with the estimate volume of demand. Our WTP calculations consider the cost of incumbent fossil-based alternatives, along with any additional penalties imposed under regulatory frameworks such as the EU ETS and FuelEU Maritime (for shipping), based on the carbon intensity of existing fuels. For more details, refer to Appendix B and C.
In the five years since the European Commission unveiled its 2020 European Hydrogen Strategy, the European Union’s (EU’s) hydrogen market has captured significant global attention from policymakers and industry stakeholders. By taking the lead in developing a renewable hydrogen industry through progressive policies, targets, and technological innovation, the EU has showcased both the immense potential and the substantial challenges of this transition. Executing this vision has proved difficult, with many early expectations — such as rapid progress, cost reductions, and broad offtake applications — now proven to be overly ambitious or unattainable in the short term.
Kickstarting decarbonization of hard-to-electrify sectors will require robust support for offtakers through financial incentives, clear sectoral mandates, realistic infrastructure planning, and a stable regulatory framework that strengthens industry confidence and reassures investors. By mobilizing investors and developers through a pragmatic, implementation-focused approach, the EU can accelerate the scaling of its renewable hydrogen industry and solidify its leadership in the global energy transition. This in turn will support the Commission’s interlinked objectives to drive industrial competitiveness and domestic job creation across the bloc in line with its recently released Clean Industrial Deal.
This report evaluates the current state of the EU hydrogen market and provides policymakers with a set of implementation-oriented policy levers and strategic choices to consider. We focus on five key pillars:
- Achievable supply and demand projections
- Directing focus to hard-to-electrify sectors
- Balancing carrots and sticks to drive offtake
- Aligning public funding to policy objectives
- Guiding industry with a stable regulatory environment
Key takeaways:
- Supply and Demand Gap: Current renewable hydrogen production is only 0.02 million tonnes per year (Mtpa), far below the EU’s unrealistic consumption targets of 20 Mtpa by 2030. We project regulated demand from existing policy measures to range between 2.2 and 2.8 Mtpa by 2030, driven by mandates in industry and transportation. Our Accelerated Transition Scenario suggests up to 7.0 Mtpa of demand could materialize.
- Strategic Use of Imports: Imports can complement domestic supply to bridge short-term supply gaps while domestic production scales.
- Planning Infrastructure around Demand: Accelerating infrastructure investments for imported and intra-EU traded hydrogen derivatives will ensure the creation of resilient supply chains for key demand markets (NL, FR, BE, DE).
To meet climate goals, the European Union has sought to scale both the production and consumption of renewable hydrogen — a cornerstone of its strategy to decarbonize industry and heavy transport. According to the IEA’s Hydrogen Production Database, current production levels stand at just 0.02 million tonnes per year (Mtpa), highlighting the slow progress toward meeting the targets set by the Renewable Energy Directive (RED III). This shortfall underscores the urgent need for a delivery-focused approach to accelerate domestic production and secure stable international supply chains to meet additional demand.
Driven by sector-specific mandates under RED III, demand for renewable hydrogen in the EU is expected to increase significantly over the next 5 years. We modeled two scenarios to understand how this could materialize:
- Baseline Scenario – Assumes full implementation of RED III mandates.[1]
- Accelerated Transition Scenario (ATS) – Envisions greater sectoral ambition, including voluntary demand beyond mandates.
As shown in Exhibit 1, total demand is projected to range between 3.7 Mtpa and 7.0 Mtpa by 2030, through the combination of mandated demand across existing consumption within industry, transportation, and potential demand if realized under the Accelerated Transition Scenario.
RED III mandates are expected to drive demand between 2.2 Mtpa and 2.8 Mtpa, far below the EU Hydrogen Strategy’s 10 Mtpa target. As the industry mandate is applied to existing users of hydrogen, this demand is expected to be driven by ammonia production, chemicals, and refinery processes. However, despite refineries consuming the greatest amount of hydrogen out of all sectors, hydrogen accounting methodologies impact how much of this consumption is subject to RED III’s renewable fuel of non-biologic origin (RFNBO) mandates.
Currently, most hydrogen produced in refineries is derived from byproduct gases and used for conventional transport fuels which reduces the volume of enforceable demand under RFNBO mandates. With the current methodology, refinery consumption subject to mandates by 2030 is estimated to be approximately 0.8 Mtpa, although this volume could be expanded due to the individual transposition of RED III by Member States. As an example, Belgium is considering the inclusion of hydrogen use in the processing of conventional transport fuels (known as the ‘refinery route’) as a vector to accelerate its hydrogen industry. However, it is important to note that mandates applied in this fashion will count toward transportation targets and will not affect the volume of industry consumption mandated.
The role of shipping and steel as additional demand
Looking beyond mandates, additional demand — driven primarily by the steel and maritime sectors — is expected to range from 1.5 Mtpa to 4.2 Mtpa.
While falling underneath the European Commission’s definition of industry, steelmaking currently uses a negligible amount of hydrogen, meaning the majority of production is not required to transition to RFNBOs. However, steelmaking has emerged as a significant demand driver among new uses for hydrogen, since steel has few options to decarbonize[2]. This transition is further accelerated by surging demand for certified green steel from automakers, construction firms, and industrial buyers aiming to meet strict sustainability targets. In addition to the overall CO2 abatement potential, it is likely the desire to shift to hydrogen steel is also brought about by concerns of industrial competitiveness, with hydrogen-steel providing relief from growing ETS carbon prices for conventional steelmaking and the phase-out of free allowances by 2034. The EU has also shown an appetite to fund hydrogen-steel, allocating some of the largest grants under the Innovation Fund to these projects.[3] It is imperative that policymakers further incentivize the use of renewable hydrogen within low-carbon steelmaking, as many companies are considering the use of unabated natural gas in the interim, which could undermine real climate benefits while prolonging reliance on imported fossil fuels.
Similarly, aside from hydrogen derivatives, the maritime sector has few scalable alternatives for decarbonization. The International Maritime Organization (IMO) is actively working to reduce greenhouse gas (GHG) emissions from shipping, targeting net-zero emissions by 2050. One of its proposed measures includes a global carbon levy and a fuel standard, requiring at least 5% — and striving for 10% — of the energy used by international shipping to come from renewable fuels and sources by 2030. Domestically, maritime activities were recently included under the ETS, and the EU passed the FuelEU legislation implementing decarbonization targets for the sector. If implemented fully, these policies will significantly influence renewable hydrogen’s uptake, driving additional demand outside of RED III.
Complementing domestic supply with imports
While domestic production is expected to scale this decade, hydrogen trade will play an essential role in closing short- to medium-term supply gaps, enabling early decarbonization, and positioning the EU as a lead market in the global hydrogen landscape. Despite ongoing project development, the current European hydrogen project pipeline is unlikely to solely meet anticipated demand. As illustrated for the Accelerated Transition Scenario in Exhibit 2, the projected supply-demand gap in 2030 is estimated to range between 1.9 Mtpa and 4.3 Mtpa, given the current trajectory of project completion. This highlights a significant shortfall that could delay climate-aligned progress and hinder industrial adoption.
However, there is also a plausible scenario where domestic supply could scale to meet RED III 2030 mandated volumes. With projected domestic hydrogen supply reaching a maximum of 2.7 Mtpa and RED III mandates requiring between 2.2 and 2.8 Mtpa, production could theoretically cover the lower end of mandated demand. Even if this scenario materializes, significant uncertainties remain, including the volatility of electricity prices and timeline to build continental hydrogen pipelines. Moreover, any disruption in project execution, infrastructure bottlenecks, or unforeseen regulatory challenges could push the EU into a supply deficit, necessitating imports to fill the gap. If domestic production does scale effectively while demand remains at the lower end of projections, Europe may be able to achieve self-sufficiency to meet regulatory requirements. However, this achievement comes with limited flexibility to support voluntary demand beyond mandates. Implementation of the recently released Clean Industrial Deal’s supply and demand-side oriented actions should increase the attractiveness of domestic production. In either scenario, enabling increased supply will require increased disbursement of funds, explored later in section 4.
Given high domestic hydrogen production costs and competition for renewable electricity across the bloc, strategic imports can provide a practical and cost-effective solution to meet the EU’s scaling demand for green fuels and feedstocks. Finished hydrogen derivatives (e.g., fertilizers, synthetic sustainable aviation fuels [eSAFs], e-ammonia, e-methanol, and hydrogen-produced direct reduced iron [DRI]) are more likely to meet this demand given the high cost and commercial immaturity of cracking. Balancing cost-effective imports with domestic industrialization is key: in the case of DRI, imported green iron can complement the growth of EU green steel while enabling flexibility for domestic growth and economic transitions. In parallel to imported derivatives, intra-EU trade from regions with ideal renewable energy conditions can serve to fill supply gaps in high-demand regions, with the objective to ensure a steady and affordable supply for Europe’s heavy industry and transport sectors.
Planning hydrogen infrastructure around key demand centers
As shown in Exhibit 3, RED III-mandated demand is concentrated in Northwest Europe, particularly in Germany, the Netherlands, France, and Belgium; countries with strong industrial bases that will rely heavily on hydrogen to decarbonize heavy industry and transportation sectors. Meanwhile, additional hydrogen demand is expected to emerge primarily from the steel and maritime sectors, placing countries with large steelmaking industries and key maritime bunkering hubs at the forefront of additional demand growth.
Not all these demand centers will be collocated with optimal renewable electricity resources, necessitating a considered approach to the distribution and transportation of hydrogen derivatives across the continent. A robust infrastructure network is essential for integrating imported hydrogen into Europe’s domestic supply chain. Investments in import terminals, pipelines, and storage facilities, will be key enablers for hydrogen distribution across sectors and geographies, ensuring that supply reaches offtakers efficiently. Intra-European trade will also play a pivotal role, allowing cost-advantaged production hubs —such as the Iberian Peninsula and Nordic regions — to transport hydrogen to high-demand industrial centers in Northwest Europe. By accelerating these infrastructure investments, the EU can the create foundations of a stable and resilient hydrogen market, which will in turn enhance economic competitiveness and secure pathways to long-term industrial decarbonization.
2. Prioritizing hard-to-electrify sectors
Key takeaway: Public and private investments should be directed to steelmaking, fertilizers, refining, aviation, and shipping; sectors where hydrogen provides the most decarbonization value. Allocating resources to low-impact uses like heating and light-duty vehicles represents inefficient use of scarce public funds and risks delaying necessary transitions through electrification and energy efficiency measures.
While Europe undeniably needs to scale its renewable hydrogen supply chains, this can be done strategically and pragmatically, focusing on use cases where hydrogen is essential for decarbonization.
It’s time to retire any lingering misconceptions of hydrogen as a Swiss army knife for economy-wide decarbonization. Hydrogen — when produced renewably — can enable Europe’s heavy transport and industrial sectors to decarbonize and will reduce the region’s dependence on imported natural gas. However, with renewable fuels and feedstocks both expensive and relatively scarce, policymaker support for hydrogen should focus and direct funding only to hard-to-electrify sectors in parallel with support for electrification and energy efficiency measures. Demand-side investments and policies should prioritize hydrogen applications in steelmaking, e-fuels, fertilizers, and refining to maximize emissions reductions, efficiently leverage public funds and ensure these high-impact industries are empowered to transition to renewable hydrogen.
Advocating for hydrogen’s use in applications with low emissions reduction potential risks eroding public trust in its role as a net-zero solution and delaying critical transitions from fossil fuels to electrification. Applications for hydrogen such as building heating, power generation, or light-duty vehicle refueling would be better served by investments in energy efficiency or direct electrification.
Citing economic and technical barriers to fuel-switching, many large European steel, chemicals, shipping, and aviation companies have resisted moving toward renewable hydrogen and are increasingly investing in natural gas as a transition molecule. Considering the limited public funds available and economic headwinds for industry, a cost-effective approach must be pursued to maintain forward momentum and drive investments in decarbonization. As industry wavers, now is the time for policymakers to implement existing sectoral transition roadmaps and ensure regulatory signals — such as the RED III mandates — are transposed rapidly and in full.
3. Balancing carrots and sticks to drive offtake
Key takeaway:
- Implementing a complementary ‘carrots’ and ‘sticks’ approach can enhance the economic viability of renewable hydrogen production and consumption in the bloc. RED III mandates, sector-specific penalties (e.g., ReFuelEU), monetized EU Allowances (EUAs) and rising ETS costs represent cost-effective measures that can increase willingness-to-pay for renewable hydrogen if implemented cohesively, which reduces reliance on expensive subsidizes.
- Ensuring consistent and timely implementation of sectoral mandates is the most effective way to stimulate demand, allowing policymakers to steer investment to priority sectors.
- This should be coupled with targeted distribution of funds along sectoral lines through competitive mechanisms like the European Hydrogen Bank and proposed Industrial Decarbonisation Bank.
Stimulating demand for renewable hydrogen in sectors where electrification isn’t possible can be achieved through a complementary ‘carrots’ and ‘sticks’ approach to enhance the economic viability of renewable hydrogen as a driver of decarbonization within the bloc. While subsidies are an important tool for early-stage market development, they do not have to completely close the price disparity between renewable hydrogen and incumbent fuels and feedstocks. Policymakers need to consider the effectiveness of multiple mechanisms at their disposal, leveraging market mechanisms such as mandates and the EU Emissions Trading System (ETS) to reduce reliance on expensive subsidies. Doubling down and scaling such mechanisms would be most cost-effective solution to accelerate industrial decarbonization, although this is likely not feasible with current political and market limitations.
The RED III mandates—if fully implemented by EU Member States—can significantly boost demand for RFNBOs within priority sectors. By increasing the willingness to pay (WTP) for renewable hydrogen and associated technologies, these mandates can help drive private investment into the hydrogen value chain. Member States have an opportunity to design penalties that can raise the WTP for industrial hydrogen consumers, as shown in Exhibit 5. Enforceable mandates also provide clear direction for investors and can inform project bankability. When implemented cohesively with subsidies, this can bridge the remaining gap and protect European consumers from experiencing additional inflationary pressure while renewable hydrogen markets mature. Member States have until the end of May 2025 to transpose the directive into national legislation, and it is imperative that these quotas are supported with strong, enforceable penalties for non-compliance to protect the decarbonization intent of the RNFBO targets.
Supplementary sector-specific penalties, such as those for aviation under ReFuelEU, can create additional economic incentives for industries to transition from fossil fuels to RFNBOs. Over time, as ETS costs rise, WTP will increase further, narrowing the price gap between grey and renewable hydrogen. Additionally, the near-term ability to monetize excess EU Allowances (EUAs) allocated to renewable hydrogen production can enhance the financial viability of these projects, further boosting WTP and market readiness.[4]
Neglecting to issue penalties under RED III carries risks of delaying the transition to net-zero technologies if public support is insufficient to influence business decisions. Germany has confirmed that it will not issue obligations or quotas to meet RED III targets, relying on subsidies to incentivize firms to make the switch. A ‘carrots-only’ approach could increase uncertainty for investors who may find it more difficult to trust ongoing subsidy support (prone to changing funding priorities) compared with factoring in the compliance costs for sectoral mandates. While carbon-pricing under the ETS and other EU-level regulation will push up the willingness-to-pay, this is unlikely to reassure investors in the near term and suggests that Germany may not be able to meet RED III’s 2030 goals.
Moreover, without equal and unilateral treatment of emissions-reduction obligations across the European market (and international suppliers through measures like the Carbon Border Adjustment mechanism), incumbent industry leaders are likely to continue to delay offtake decisions for renewable hydrogen which will stifle investment decisions on the supply side. Delaying the transition to net-zero technologies also increases the risk of misplaced investments in solutions with carbon lock-in that will become stranded assets in the decades to come as the world decarbonizes.
4. Aligning public funding to policy objectives
Key takeaways:
- Public Funding Gap: Current funding commitments fall short of what is needed to achieve the EU’s hydrogen and climate objectives. Approximately €13,9 billion in public funding will be needed to implement RED III mandates and an extra €31,7 to enable faster decarbonization under the Accelerated Transition Scenario.
- Unlocking Private Investment: Public funding could unlock approximately €251 billion in private capital expenditures. This is equivalent to a 7x leverage effect in mobilizing private investment from public funds.
- Slow Deployment: Despite €21,4 billion in relevant committed funds from the Commission and Member States, only €3 billion in public funding has been disbursed to renewable hydrogen projects and end-users.
- Geographic Focus: A near-term focus on key demand centers can kickstart the decarbonization of major industrial centers, although a more equitable EU-wide distribution of public funding will be required in the long term to effectively scale hydrogen adoption across all Member States.
Like all markets around the world, the initial optimism surrounding Europe’s renewable hydrogen sector was driven by expectations of rapid cost reductions. However, these expectations have not materialized, and the high cost of renewable hydrogen compared to fossil-based alternatives remains a significant barrier. As illustrated above in Exhibit 5, sustained public support will be an essential component in bridging the cost gap and stimulating demand in key sectors.
Public funding needed to bridge the willingness-to-pay gap
Between 2025 and 2030, we estimate that approximately €13,9 billion in public funding will be needed to implement RED III mandates, primarily in fertilizer and other industrial sectors (Exhibit 6).[5] To realize our Accelerated Transition Scenario (ATS), this funding would need to grow to over 3x the amount to increase financing for demand-side mechanisms. The public funding calculated represents the amount that would be needed to bridge the gap between the cost of a renewable, hydrogen-based fuel and its fossil-produced incumbent. While these cost projections were calculated with European production in mind, imported green commodities may offer cost-savings which decreases the total funding required.
Shipping and steel emerge as the primary sectors requiring financial support to unlock the Accelerated Transition Scenario's additional demand volumes. Overall, an estimated €45,6 billion in public funding would be required, which could unlock approximately €276 billion in private capital expenditures. This is equivalent to a 7x leverage effect in mobilizing private investment from public funds.
Committed funding and regional distribution
While public funding has the potential to catalyze private sector investment, current funding commitments fall short of what is needed to achieve the EU’s hydrogen and climate objectives. Despite significant amounts being earmarked by the European Commission and Member States through mechanisms such as Contracts for Difference (CfDs), H2Global, auctions, and the European Hydrogen Bank (EHB), actual funds deployed to date remain limited (Exhibit 7). These programs should be reviewed to understand deployment delays and accelerate disbursement of funds to priority sectors. It is important to note that the recently proposed Industrial Decarbonisation Bank (aiming for €100 billion in funding) represents the ideal vehicle to support the accelerated transition of Europe’s heavy-emitting sectors.
Funding is currently heavily concentrated in three countries – Germany, the Netherlands, and France. As demonstrated in Exhibit 3, these countries are key demand centers that require funding to meet their demand; but this leaves 55% of European hydrogen production without the same degree of funding. For example, Poland and Belgium comprise 19% of current consumption, mainly driven by ammonia production, and Spain and Italy’s hydrogen consumption will grow in the maritime and steel sector respectively. Overall, a more balanced distribution of funding is necessary to support hydrogen development across a wider range of Member States, particularly those that can offer competitive pricing and facilitate intra-EU hydrogen trade, such as the Iberian Peninsula and Nordic region.
Addressing the market’s economic realities
To overcome the economic challenges facing the nascent hydrogen sector, policymakers need to recalibrate their approach to how much sustained financial support will be required to support decarbonization of hard-to-electrify sectors. With decarbonization competing against other public interests, scarce public funding needs to be thoughtfully allocated to hard-to-electrify sectors and high-impact first-mover projects. While demonstration-stage funding has supported many small renewable hydrogen projects across the EU thus far, achieving RED III mandates or unlocking additional demand may require a different approach for the second von der Leyen Commission term (2025-2030).
Policymakers can expedite the release and utilization of €18 billion in undisbursed funding that is already committed across multiple EU and Member State programs. These programs should be subject to a pragmatic review to ensure that these funds can be leveraged efficiently to drive uptake of renewable hydrogen in priority end-use sectors. This may include a near-term focus on large demand centers and supporting first-mover suppliers in regions with strong renewable energy credentials. Ultimately, European policymakers should consider a more equitable long-term approach to address geographic imbalances in funding support across the bloc.
Ensuring public funding is strategically aligned with EU policy objectives is crucial to catalyze private investment, drive innovation, and scale up renewable hydrogen adoption across the EU. A well-coordinated approach will be critical to transforming Europe’s hydrogen ambitions into a fully realized industrial and economic opportunity, and policymakers need to decide the speed and scale they want to realize by 2030. Achieving faster sectoral decarbonization (as illustrated in the Accelerated Transition Scenario) will require a substantial increase in investment and broader utilization of other market-based mechanisms to resolve coordination failures within Europe’s renewable hydrogen market.
5. Guiding industry with a stable regulatory environment
Key takeaway: It is critical that the EU upholds its robust RFNBO regulations to provide the investment certainty required to finance projects for 2030 commissioning. Maintaining a stable and predictable regulatory framework is essential for driving long-term market growth, encouraging innovation, and solidifying the EU’s position as a global leader in the renewable hydrogen industry.
As the EU implements its new Clean Industrial Deal to address the competitiveness concerns raised in the 2024 Draghi Report, it should ensure that its regulatory frameworks are transparent, cross-referenced and unfaltering in climate ambition. As this pertains to kickstarting a hydrogen industry, Europe needs to hold the line on its global climate leadership and not relax its world-leading regulations. It is paramount to maintain a stable regulatory environment, not the least to provide investment certainty which is critical for developing renewable hydrogen value chains. Investors are currently planning project development and delivery decisions for a 2030 project horizon and any further regulatory uncertainty will make 2030 targets unachievable.
Reopening the RFNBO Delegated Acts will delay investment decisions and risk the creation of an industry with questionable sustainability credentials. Similarly, emissions guardrails must be maintained by ensuring the regulatory framework for low-carbon hydrogen is robust and holistic as we’ve examined in earlier analysis.
A path forward for policymakers
Now is the time for the European Commission and Member States to translate conceptual policies, rules, and funding mechanisms into effective tools to scale the EU renewable hydrogen market over the next five years. We recommend policymakers consider the following levers to drive forward market creation and implementation:
Joint Actions by European Policymakers:
- Support Priority End-Use Sectors: Increase funding for cost-effective demand mechanisms such as CfDs, tenders, and auctions; designing and communicating a program of individual funding rounds for high-impact sectors (e.g., utilizing the EHB or proposed Industrial Decarbonisation Bank to support steel, fertilizer, aviation and maritime end-users).
- Accelerate Funding Deployment: Where prudent, expedite the release and utilization of €18 billion in undisbursed funding. Expand funding within Member States that have been unable to allocate sufficient support, and/or expand EU-level programs to address the shortfall.
- Consider Aligning Public Funding with Climate and Clean Industrial Deal Goals: As demonstrated in our Accelerated Transition Scenario, scaling public funding to €46 billion can unlock €276 billion in private industry investments to accelerate decarbonization of hard-to-electrify sectors. The Industrial Decarbonisation Bank would be well-placed to drive an accelerated transition within these sectors.
- Develop Hydrogen Infrastructure: Boost EU and national funding for hydrogen import infrastructure and intra-EU trade, recalibrating infrastructure roll-out requirements to focus on realistic demand volumes within industrial clusters.
Actions by the European Commission:
- Articulate a Clear Vision: Provide updated guidance to Member States and the hydrogen industry, focusing on hard-to-electrify sectors and maintaining confidence in regulatory frameworks.
- Adjust to Market Realities: Recalibrate expectations from the unrealistic 20 Mtpa target to approximately 2.2 – 2.8 Mtpa under RED III mandates and 1.5 – 4.2 Mtpa of additional demand by 2030 under our Accelerated Transition Scenario.
- Strengthen Emissions Guardrails: Hold the line on RFNBO regulations and ensure robust and complementary accounting frameworks are put in place for low-carbon hydrogen to ensure consistency and credibility.
Actions by Member States:
- Transpose RED III Mandates: Implement enforceable quotas with strong penalties for non-compliance before May 2025 to protect the intent of RFNBO targets.
- Set Pragmatic National Targets: Define realistic production, electrolyzer capacity, and infrastructure goals in National Energy and Climate Plans (NECPs).
- Align Market Rules Across States: Coordinate the transposition of the Hydrogen and Decarbonised Gas Market Package to create a unified and functional hydrogen market.
Appendix A: Scenario assumptions for demand
Mandates
Industry: RED III-stimulated demand for industry was based on current hydrogen consumption from the European Hydrogen Observatory projected out to 2030. Sectors included within the category of ‘industry’ include refining, ammonia, methanol, other chemicals, industrial heat, steel, and other industry. Byproduct hydrogen was removed from current consumption.
Hydrogen consumption within refining introduces a special case within RED III mandates. Under the existing policy, hydrogen produced via byproduct is not included in the total amount of hydrogen subject to the 42% RFNBO industry consumption mandate. Refineries use a large amount of byproduct hydrogen, from production of styrene, ethylene, and most notably, through catalytic naphtha reforming. It was assumed that hydrogen produced outside of byproduct (such as steam methane reformation or partial oxidation) represented 56% of refinery hydrogen demand. Additionally, RED III states that hydrogen used to process “conventional transport fuels” can count toward the 1% transportation target rather than the industry target. It was assumed that 66% of intentionally produced hydrogen was used to produce transport fuels and does not fall under industry mandates. Additional refinery considerations included a -0.7% CAGR decrease in production due to a phase-out of refining in line with the broader energy transition.
The total volume of intentionally produced, non-byproduct hydrogen was assessed, and the 42% mandate was applied as per Article 22a of RED III.
Transportation: Transportation mandates were calculated using the overall energy demand for transportation in the European Union. Data was used from Eurostat for current energy demand and a 2030 projection from the European Environment Agency.
Aviation was assumed to require hydrogen to meet the 1.2% sub mandate for synthetic SAF within Annex I of ReFuelEU. Aviation within the transportation mandate accounted for the 1.5x multiplier in Article 27 of RED III.
Maritime was assumed to meet the 1.2% mandate within Article 25 of RED III. Maritime within the transportation mandate accounted for the 1.5x multiplier in Article 27 of RED III.
Other transportation RFNBO consumption was based on the total energy consumption mandated under RED III (1% of total energy) less the aviation and maritime sectors. Other transportation accounted for the 2x multiplier in Article 27 of RED III.
Accelerated Transition Scenario
The Accelerated Transition Scenario (ATS) was considered for priority sectors for hydrogen use.
Aviation
Aviation demand for hydrogen was estimated in consultation with RMI experts on demand projects for 2030 ranging from 0.5 to 1.0 million tons of hydrogen required.
Fertilizers
Fertilizer demand under the ATS was determined by calculating the amount of renewable ammonia (and subsequently hydrogen) needed to satisfy the “green hydrogen pathway” of 50% carbon intensity reduction by 2030 published by Fertilizers Europe. Data for ammonia production was based on fertilizer consumption data from the International Fertilizer Association, correcting for import and exports using Fertilizers Europe estimations.
Maritime
Maritime demand for hydrogen was determined by assuming maritime fuel use would be in line with the International Maritime Organization Greenhouse Gas Reduction Strategy target of 5% of energy demand met through zero-emission fuels by 2030, assuming 90% of zero-emission fuel is met through hydrogen-derived products.
Refining
Refinery demand under the ATS was determined by assuming the proportion of intentionally produced hydrogen that is produced renewably will follow the clean consumption for refining pathways under the IEA Net Zero Emissions scenario.
Steel
Steel demand under the ATS was found by assuming all H2-DRI and H2-ready DRI projects in the project pipeline reach operation and use between 50% to 100% hydrogen by 2030. Hydrogen demand for DRI was assumed to be 0.055 tonnes hydrogen per tonne DRI.
Appendix B: WTP Methodology and assumptions
Any monetary values found in literature or calculated through modeling that are expressed in USD were converted to EUR for analysis.
Aviation:
Costs
SAF production costs were calculated using an RMI model which includes the hydrogen feedstock price as an operating expense, other costs include bio feedstocks, CO2, energy feedstocks, operations & maintenance, and capital costs.
Parity
Parity with incumbent jet fuel is based on the current market price from IATA; at the time of writing the jet fuel price was $782/tonne.
WTP
WTP for SAF is based on the minimum expected fine for not meeting ReFuelEU mandates, as set by ReFuelEU. The fine for failure to comply for aircraft operators is required to be no less than twice as high as the average price per tonne of aviation fuel, as stated by Article 12 of the ReFuelEU regulation. Since no synthetic SAF is required until 2030, there is likely no actual penalty until then. The penalty is used as an approximation for how aircraft operators would approach procurement until 2030. Penalties affecting fuel suppliers in 2030 would be based on the price of synthetic SAF rather than the average aviation fuel price, likely pushing the WTP much higher than currently calculated.
Fertilizers:
Costs
Hydrogen conversion to ammonia was calculated using an RMI model with additional costs for ammonia storage included. Assumes Haber Bosch production of 0.3 Mt NH3.
Parity
Parity with the incumbent is based on the price of Northwest European grey ammonia produced today as published by S&P. Future prices of grey ammonia were determined assuming a decrease in natural gas costs to levels pre-Russian invasion of Ukraine.
WTP
WTP was assessed by calculating the current and future prices of grey ammonia with added carbon costs from the ETS. ETS costs were calculated using an RMI model.
Maritime:
Costs
Hydrogen conversion to ammonia and methanol was calculated using an RMI model. A surplus of FuelEU credits pooled and included as a production subsidy have a value of $222/tonne VLSFO-eq. The ammonia and methanol production costs are converted to $/tonne VLSFO-equivalent using an ammonia energy density of 5.22 kWh/kg, methanol density of 5.54 kWh/kg, and VLSFO energy density of 11.38 kWh/kg from Ship and Bunker.
Parity
Parity with the incumbent is based on the price of VLSFO fuel in the market today as published by Ship & Bunker; at the time of writing the market price was $680/tonne.
WTP
WTP is based on parity with the incumbent VLSFO fuel with the addition of the FuelEU penalty and ETS carbon cost for the use of VLSFO in Europe; $33.5/tonne VLSFO-eq. for the 2025 FuelEU penalty; $128/tonne VLSFO-eq. for the ETS cost.
Refining:
Costs
Hydrogen production via electrolysis and dedicated renewables was calculated using an RMI model.
Parity
Parity with the incumbent is based on the production cost of gas-based hydrogen today according to the European Hydrogen Observatory, Future prices of grey hydrogen were determined assuming a decrease in natural gas costs to level pre-Russian invasion of Ukraine.
WTP
WTP was assessed by calculating the current and future prices of grey hydrogen with added carbon costs from the ETS. ETS costs were calculated using an RMI model.
Steel:
Costs
Steel production costs are calculated using an RMI model which includes the price of the hydrogen feedstock as an operating expense; other costs include energy feedstocks, metallics, operations & maintenance, material transport, and capital costs.
Parity
Parity with the incumbent is based on the spot market price of Hot Rolled Coil (HRC), assumed to reflect the price of HRC produced from a blast furnace-basic oxygen furnace integrated steel mill. At time of writing, the spot market price for HRC was $688/tonne.
WTP
WTP comes from applying a green premium to the parity price with BF-BOF steel. Based on market data and internal analysis the green premium is assumed to be 30%.
Overview:
Appendix C: Methodology to estimate public and private funding
Public funding needed to bridge WTP gap
Funding to bridge the WTP gap was found by estimating the cost of renewable fuel minus the WTP as shown above. This was done for both 2024 and 2025, expected to linearly change over time. The volume of fuel supported was assumed to be zero in 2024, incrementally increasing year over year by the size of an archetypical project, assuming exponential growth of projects deployed, until capped at the demand volume calculated for each sector using the methodology in Appendix A. A given year’s gap value was multiplied by the equivalent yearly demand value and summed to estimate the total amount of funding needed from now until 2030.
Total investments needed
The total capital needed to enable mandates and the Accelerated Transition Scenario was found using archetype projects for refining, steel, fertilizers, maritime, aviation, and an archetype for hydrogen projects for general use. The deployment of each of these projects was assumed to occur year over year until the demand found using the methodology in Appendix A was reached. That amount of projects was then multiplied by the assumed CAPEX cost for each archetypical project to find the total investments needed. The public funding needed from the previous section is expected to unlock private funds that can reach this total investment figure.
Project archetypes:
Sector
Commodity
Size
Units
Capital investment needed (billion EUR)
Installation hydrogen requirement (ktpa H2)
Aviation
eSAF
50
ktpa eSAF
1.50
26
Fertilizers
eAmmonia
278
ktpa NH3
2.62
50
Maritime
eAmmonia
300
ktpa NH3
2.62
54
Maritime
eMethanol
150
ktpa MeOH
1.16
29
Refining
Renewable hydrogen
20
ktpa H2
0.75
20
Steel
Crude steel
2,500
ktpa crude steel
7.40
138
Other
Renewable hydrogen
20
ktpa H2
0.75
20
Funding in the EU
To determine the state of public funding in the EU, we investigated EU-level and Member State-level funding data from Hydrogen Europe’s Clean Hydrogen Monitor, the European Court of Auditor’s Special report 11/2024 on renewable hydrogen policy, the Innovation Fund Project Portfolio, the Recovery and Resilience Scoreboard, and various press releases on public funding. We determined the amount that had been earmarked for hydrogen in priority sectors using schemes designed to close the cost gap (CfDs, hydrogen premiums, etc.), and the amount of these funds that had been deployed (contracts signed or awarded to specific projects).
Endnotes
[1] RED III mandates are subject to national transposition by EU Member States and will differ in execution. RED III mandates 42% of industry consumption and 1% of transportation energy to be from RFNBOs, however the distribution among industries is up to the discretion of the Member States. This is already apparent, as draft legislation in the Netherlands excludes ammonia production from the obligation, and Belgium is pursuing the “refinery route” (applying transportation requirements to refineries). Transposition variation will affect the strength of the demand signal and the overall volumes mandated in each sector.
[2] Using hydrogen offsets a substantial amount of carbon in comparison to other uses: at a rate of up to 33,6 kg of carbon dioxide (CO2) abated per kg of renewable hydrogen used compared to 11 kg of CO2 avoided in most applications.
[3] €250 million has been granted to Stegra (formerly H2 Green Steel) and €143 million to HYBRIT. Stegra’s grant ranks the 2nd highest of all Innovation Fund grants and 1st among hydrogen-related projects. HYBRIT ranks 5th among hydrogen related projects.
[4] Free allocation of EUAs will be phased out, fully ending in 2034. Monetization of these allowances will be an early consideration.
[5] The required public funding to close the premium for renewable hydrogen is determined by the difference between the production cost of renewable hydrogen-based commodities and the willingness to pay (WTP), along with the estimate volume of demand. Our WTP calculations consider the cost of incumbent fossil-based alternatives, along with any additional penalties imposed under regulatory frameworks such as the EU ETS and FuelEU Maritime (for shipping), based on the carbon intensity of existing fuels. For more details, refer to Appendix B and C.
While Europe undeniably needs to scale its renewable hydrogen supply chains, this can be done strategically and pragmatically, focusing on use cases where hydrogen is essential for decarbonization.
It’s time to retire any lingering misconceptions of hydrogen as a Swiss army knife for economy-wide decarbonization. Hydrogen — when produced renewably — can enable Europe’s heavy transport and industrial sectors to decarbonize and will reduce the region’s dependence on imported natural gas. However, with renewable fuels and feedstocks both expensive and relatively scarce, policymaker support for hydrogen should focus and direct funding only to hard-to-electrify sectors in parallel with support for electrification and energy efficiency measures. Demand-side investments and policies should prioritize hydrogen applications in steelmaking, e-fuels, fertilizers, and refining to maximize emissions reductions, efficiently leverage public funds and ensure these high-impact industries are empowered to transition to renewable hydrogen.
Advocating for hydrogen’s use in applications with low emissions reduction potential risks eroding public trust in its role as a net-zero solution and delaying critical transitions from fossil fuels to electrification. Applications for hydrogen such as building heating, power generation, or light-duty vehicle refueling would be better served by investments in energy efficiency or direct electrification.
Citing economic and technical barriers to fuel-switching, many large European steel, chemicals, shipping, and aviation companies have resisted moving toward renewable hydrogen and are increasingly investing in natural gas as a transition molecule. Considering the limited public funds available and economic headwinds for industry, a cost-effective approach must be pursued to maintain forward momentum and drive investments in decarbonization. As industry wavers, now is the time for policymakers to implement existing sectoral transition roadmaps and ensure regulatory signals — such as the RED III mandates — are transposed rapidly and in full.
Key takeaway:
- Implementing a complementary ‘carrots’ and ‘sticks’ approach can enhance the economic viability of renewable hydrogen production and consumption in the bloc. RED III mandates, sector-specific penalties (e.g., ReFuelEU), monetized EU Allowances (EUAs) and rising ETS costs represent cost-effective measures that can increase willingness-to-pay for renewable hydrogen if implemented cohesively, which reduces reliance on expensive subsidizes.
- Ensuring consistent and timely implementation of sectoral mandates is the most effective way to stimulate demand, allowing policymakers to steer investment to priority sectors.
- This should be coupled with targeted distribution of funds along sectoral lines through competitive mechanisms like the European Hydrogen Bank and proposed Industrial Decarbonisation Bank.
Stimulating demand for renewable hydrogen in sectors where electrification isn’t possible can be achieved through a complementary ‘carrots’ and ‘sticks’ approach to enhance the economic viability of renewable hydrogen as a driver of decarbonization within the bloc. While subsidies are an important tool for early-stage market development, they do not have to completely close the price disparity between renewable hydrogen and incumbent fuels and feedstocks. Policymakers need to consider the effectiveness of multiple mechanisms at their disposal, leveraging market mechanisms such as mandates and the EU Emissions Trading System (ETS) to reduce reliance on expensive subsidies. Doubling down and scaling such mechanisms would be most cost-effective solution to accelerate industrial decarbonization, although this is likely not feasible with current political and market limitations.
The RED III mandates—if fully implemented by EU Member States—can significantly boost demand for RFNBOs within priority sectors. By increasing the willingness to pay (WTP) for renewable hydrogen and associated technologies, these mandates can help drive private investment into the hydrogen value chain. Member States have an opportunity to design penalties that can raise the WTP for industrial hydrogen consumers, as shown in Exhibit 5. Enforceable mandates also provide clear direction for investors and can inform project bankability. When implemented cohesively with subsidies, this can bridge the remaining gap and protect European consumers from experiencing additional inflationary pressure while renewable hydrogen markets mature. Member States have until the end of May 2025 to transpose the directive into national legislation, and it is imperative that these quotas are supported with strong, enforceable penalties for non-compliance to protect the decarbonization intent of the RNFBO targets.
Supplementary sector-specific penalties, such as those for aviation under ReFuelEU, can create additional economic incentives for industries to transition from fossil fuels to RFNBOs. Over time, as ETS costs rise, WTP will increase further, narrowing the price gap between grey and renewable hydrogen. Additionally, the near-term ability to monetize excess EU Allowances (EUAs) allocated to renewable hydrogen production can enhance the financial viability of these projects, further boosting WTP and market readiness.[4]
Neglecting to issue penalties under RED III carries risks of delaying the transition to net-zero technologies if public support is insufficient to influence business decisions. Germany has confirmed that it will not issue obligations or quotas to meet RED III targets, relying on subsidies to incentivize firms to make the switch. A ‘carrots-only’ approach could increase uncertainty for investors who may find it more difficult to trust ongoing subsidy support (prone to changing funding priorities) compared with factoring in the compliance costs for sectoral mandates. While carbon-pricing under the ETS and other EU-level regulation will push up the willingness-to-pay, this is unlikely to reassure investors in the near term and suggests that Germany may not be able to meet RED III’s 2030 goals.
Moreover, without equal and unilateral treatment of emissions-reduction obligations across the European market (and international suppliers through measures like the Carbon Border Adjustment mechanism), incumbent industry leaders are likely to continue to delay offtake decisions for renewable hydrogen which will stifle investment decisions on the supply side. Delaying the transition to net-zero technologies also increases the risk of misplaced investments in solutions with carbon lock-in that will become stranded assets in the decades to come as the world decarbonizes.
4. Aligning public funding to policy objectives
Key takeaways:
- Public Funding Gap: Current funding commitments fall short of what is needed to achieve the EU’s hydrogen and climate objectives. Approximately €13,9 billion in public funding will be needed to implement RED III mandates and an extra €31,7 to enable faster decarbonization under the Accelerated Transition Scenario.
- Unlocking Private Investment: Public funding could unlock approximately €251 billion in private capital expenditures. This is equivalent to a 7x leverage effect in mobilizing private investment from public funds.
- Slow Deployment: Despite €21,4 billion in relevant committed funds from the Commission and Member States, only €3 billion in public funding has been disbursed to renewable hydrogen projects and end-users.
- Geographic Focus: A near-term focus on key demand centers can kickstart the decarbonization of major industrial centers, although a more equitable EU-wide distribution of public funding will be required in the long term to effectively scale hydrogen adoption across all Member States.
Like all markets around the world, the initial optimism surrounding Europe’s renewable hydrogen sector was driven by expectations of rapid cost reductions. However, these expectations have not materialized, and the high cost of renewable hydrogen compared to fossil-based alternatives remains a significant barrier. As illustrated above in Exhibit 5, sustained public support will be an essential component in bridging the cost gap and stimulating demand in key sectors.
Public funding needed to bridge the willingness-to-pay gap
Between 2025 and 2030, we estimate that approximately €13,9 billion in public funding will be needed to implement RED III mandates, primarily in fertilizer and other industrial sectors (Exhibit 6).[5] To realize our Accelerated Transition Scenario (ATS), this funding would need to grow to over 3x the amount to increase financing for demand-side mechanisms. The public funding calculated represents the amount that would be needed to bridge the gap between the cost of a renewable, hydrogen-based fuel and its fossil-produced incumbent. While these cost projections were calculated with European production in mind, imported green commodities may offer cost-savings which decreases the total funding required.
Shipping and steel emerge as the primary sectors requiring financial support to unlock the Accelerated Transition Scenario's additional demand volumes. Overall, an estimated €45,6 billion in public funding would be required, which could unlock approximately €276 billion in private capital expenditures. This is equivalent to a 7x leverage effect in mobilizing private investment from public funds.
Committed funding and regional distribution
While public funding has the potential to catalyze private sector investment, current funding commitments fall short of what is needed to achieve the EU’s hydrogen and climate objectives. Despite significant amounts being earmarked by the European Commission and Member States through mechanisms such as Contracts for Difference (CfDs), H2Global, auctions, and the European Hydrogen Bank (EHB), actual funds deployed to date remain limited (Exhibit 7). These programs should be reviewed to understand deployment delays and accelerate disbursement of funds to priority sectors. It is important to note that the recently proposed Industrial Decarbonisation Bank (aiming for €100 billion in funding) represents the ideal vehicle to support the accelerated transition of Europe’s heavy-emitting sectors.
Funding is currently heavily concentrated in three countries – Germany, the Netherlands, and France. As demonstrated in Exhibit 3, these countries are key demand centers that require funding to meet their demand; but this leaves 55% of European hydrogen production without the same degree of funding. For example, Poland and Belgium comprise 19% of current consumption, mainly driven by ammonia production, and Spain and Italy’s hydrogen consumption will grow in the maritime and steel sector respectively. Overall, a more balanced distribution of funding is necessary to support hydrogen development across a wider range of Member States, particularly those that can offer competitive pricing and facilitate intra-EU hydrogen trade, such as the Iberian Peninsula and Nordic region.
Addressing the market’s economic realities
To overcome the economic challenges facing the nascent hydrogen sector, policymakers need to recalibrate their approach to how much sustained financial support will be required to support decarbonization of hard-to-electrify sectors. With decarbonization competing against other public interests, scarce public funding needs to be thoughtfully allocated to hard-to-electrify sectors and high-impact first-mover projects. While demonstration-stage funding has supported many small renewable hydrogen projects across the EU thus far, achieving RED III mandates or unlocking additional demand may require a different approach for the second von der Leyen Commission term (2025-2030).
Policymakers can expedite the release and utilization of €18 billion in undisbursed funding that is already committed across multiple EU and Member State programs. These programs should be subject to a pragmatic review to ensure that these funds can be leveraged efficiently to drive uptake of renewable hydrogen in priority end-use sectors. This may include a near-term focus on large demand centers and supporting first-mover suppliers in regions with strong renewable energy credentials. Ultimately, European policymakers should consider a more equitable long-term approach to address geographic imbalances in funding support across the bloc.
Ensuring public funding is strategically aligned with EU policy objectives is crucial to catalyze private investment, drive innovation, and scale up renewable hydrogen adoption across the EU. A well-coordinated approach will be critical to transforming Europe’s hydrogen ambitions into a fully realized industrial and economic opportunity, and policymakers need to decide the speed and scale they want to realize by 2030. Achieving faster sectoral decarbonization (as illustrated in the Accelerated Transition Scenario) will require a substantial increase in investment and broader utilization of other market-based mechanisms to resolve coordination failures within Europe’s renewable hydrogen market.
5. Guiding industry with a stable regulatory environment
Key takeaway: It is critical that the EU upholds its robust RFNBO regulations to provide the investment certainty required to finance projects for 2030 commissioning. Maintaining a stable and predictable regulatory framework is essential for driving long-term market growth, encouraging innovation, and solidifying the EU’s position as a global leader in the renewable hydrogen industry.
As the EU implements its new Clean Industrial Deal to address the competitiveness concerns raised in the 2024 Draghi Report, it should ensure that its regulatory frameworks are transparent, cross-referenced and unfaltering in climate ambition. As this pertains to kickstarting a hydrogen industry, Europe needs to hold the line on its global climate leadership and not relax its world-leading regulations. It is paramount to maintain a stable regulatory environment, not the least to provide investment certainty which is critical for developing renewable hydrogen value chains. Investors are currently planning project development and delivery decisions for a 2030 project horizon and any further regulatory uncertainty will make 2030 targets unachievable.
Reopening the RFNBO Delegated Acts will delay investment decisions and risk the creation of an industry with questionable sustainability credentials. Similarly, emissions guardrails must be maintained by ensuring the regulatory framework for low-carbon hydrogen is robust and holistic as we’ve examined in earlier analysis.
A path forward for policymakers
Now is the time for the European Commission and Member States to translate conceptual policies, rules, and funding mechanisms into effective tools to scale the EU renewable hydrogen market over the next five years. We recommend policymakers consider the following levers to drive forward market creation and implementation:
Joint Actions by European Policymakers:
- Support Priority End-Use Sectors: Increase funding for cost-effective demand mechanisms such as CfDs, tenders, and auctions; designing and communicating a program of individual funding rounds for high-impact sectors (e.g., utilizing the EHB or proposed Industrial Decarbonisation Bank to support steel, fertilizer, aviation and maritime end-users).
- Accelerate Funding Deployment: Where prudent, expedite the release and utilization of €18 billion in undisbursed funding. Expand funding within Member States that have been unable to allocate sufficient support, and/or expand EU-level programs to address the shortfall.
- Consider Aligning Public Funding with Climate and Clean Industrial Deal Goals: As demonstrated in our Accelerated Transition Scenario, scaling public funding to €46 billion can unlock €276 billion in private industry investments to accelerate decarbonization of hard-to-electrify sectors. The Industrial Decarbonisation Bank would be well-placed to drive an accelerated transition within these sectors.
- Develop Hydrogen Infrastructure: Boost EU and national funding for hydrogen import infrastructure and intra-EU trade, recalibrating infrastructure roll-out requirements to focus on realistic demand volumes within industrial clusters.
Actions by the European Commission:
- Articulate a Clear Vision: Provide updated guidance to Member States and the hydrogen industry, focusing on hard-to-electrify sectors and maintaining confidence in regulatory frameworks.
- Adjust to Market Realities: Recalibrate expectations from the unrealistic 20 Mtpa target to approximately 2.2 – 2.8 Mtpa under RED III mandates and 1.5 – 4.2 Mtpa of additional demand by 2030 under our Accelerated Transition Scenario.
- Strengthen Emissions Guardrails: Hold the line on RFNBO regulations and ensure robust and complementary accounting frameworks are put in place for low-carbon hydrogen to ensure consistency and credibility.
Actions by Member States:
- Transpose RED III Mandates: Implement enforceable quotas with strong penalties for non-compliance before May 2025 to protect the intent of RFNBO targets.
- Set Pragmatic National Targets: Define realistic production, electrolyzer capacity, and infrastructure goals in National Energy and Climate Plans (NECPs).
- Align Market Rules Across States: Coordinate the transposition of the Hydrogen and Decarbonised Gas Market Package to create a unified and functional hydrogen market.
Appendix A: Scenario assumptions for demand
Mandates
Industry: RED III-stimulated demand for industry was based on current hydrogen consumption from the European Hydrogen Observatory projected out to 2030. Sectors included within the category of ‘industry’ include refining, ammonia, methanol, other chemicals, industrial heat, steel, and other industry. Byproduct hydrogen was removed from current consumption.
Hydrogen consumption within refining introduces a special case within RED III mandates. Under the existing policy, hydrogen produced via byproduct is not included in the total amount of hydrogen subject to the 42% RFNBO industry consumption mandate. Refineries use a large amount of byproduct hydrogen, from production of styrene, ethylene, and most notably, through catalytic naphtha reforming. It was assumed that hydrogen produced outside of byproduct (such as steam methane reformation or partial oxidation) represented 56% of refinery hydrogen demand. Additionally, RED III states that hydrogen used to process “conventional transport fuels” can count toward the 1% transportation target rather than the industry target. It was assumed that 66% of intentionally produced hydrogen was used to produce transport fuels and does not fall under industry mandates. Additional refinery considerations included a -0.7% CAGR decrease in production due to a phase-out of refining in line with the broader energy transition.
The total volume of intentionally produced, non-byproduct hydrogen was assessed, and the 42% mandate was applied as per Article 22a of RED III.
Transportation: Transportation mandates were calculated using the overall energy demand for transportation in the European Union. Data was used from Eurostat for current energy demand and a 2030 projection from the European Environment Agency.
Aviation was assumed to require hydrogen to meet the 1.2% sub mandate for synthetic SAF within Annex I of ReFuelEU. Aviation within the transportation mandate accounted for the 1.5x multiplier in Article 27 of RED III.
Maritime was assumed to meet the 1.2% mandate within Article 25 of RED III. Maritime within the transportation mandate accounted for the 1.5x multiplier in Article 27 of RED III.
Other transportation RFNBO consumption was based on the total energy consumption mandated under RED III (1% of total energy) less the aviation and maritime sectors. Other transportation accounted for the 2x multiplier in Article 27 of RED III.
Accelerated Transition Scenario
The Accelerated Transition Scenario (ATS) was considered for priority sectors for hydrogen use.
Aviation
Aviation demand for hydrogen was estimated in consultation with RMI experts on demand projects for 2030 ranging from 0.5 to 1.0 million tons of hydrogen required.
Fertilizers
Fertilizer demand under the ATS was determined by calculating the amount of renewable ammonia (and subsequently hydrogen) needed to satisfy the “green hydrogen pathway” of 50% carbon intensity reduction by 2030 published by Fertilizers Europe. Data for ammonia production was based on fertilizer consumption data from the International Fertilizer Association, correcting for import and exports using Fertilizers Europe estimations.
Maritime
Maritime demand for hydrogen was determined by assuming maritime fuel use would be in line with the International Maritime Organization Greenhouse Gas Reduction Strategy target of 5% of energy demand met through zero-emission fuels by 2030, assuming 90% of zero-emission fuel is met through hydrogen-derived products.
Refining
Refinery demand under the ATS was determined by assuming the proportion of intentionally produced hydrogen that is produced renewably will follow the clean consumption for refining pathways under the IEA Net Zero Emissions scenario.
Steel
Steel demand under the ATS was found by assuming all H2-DRI and H2-ready DRI projects in the project pipeline reach operation and use between 50% to 100% hydrogen by 2030. Hydrogen demand for DRI was assumed to be 0.055 tonnes hydrogen per tonne DRI.
Appendix B: WTP Methodology and assumptions
Any monetary values found in literature or calculated through modeling that are expressed in USD were converted to EUR for analysis.
Aviation:
Costs
SAF production costs were calculated using an RMI model which includes the hydrogen feedstock price as an operating expense, other costs include bio feedstocks, CO2, energy feedstocks, operations & maintenance, and capital costs.
Parity
Parity with incumbent jet fuel is based on the current market price from IATA; at the time of writing the jet fuel price was $782/tonne.
WTP
WTP for SAF is based on the minimum expected fine for not meeting ReFuelEU mandates, as set by ReFuelEU. The fine for failure to comply for aircraft operators is required to be no less than twice as high as the average price per tonne of aviation fuel, as stated by Article 12 of the ReFuelEU regulation. Since no synthetic SAF is required until 2030, there is likely no actual penalty until then. The penalty is used as an approximation for how aircraft operators would approach procurement until 2030. Penalties affecting fuel suppliers in 2030 would be based on the price of synthetic SAF rather than the average aviation fuel price, likely pushing the WTP much higher than currently calculated.
Fertilizers:
Costs
Hydrogen conversion to ammonia was calculated using an RMI model with additional costs for ammonia storage included. Assumes Haber Bosch production of 0.3 Mt NH3.
Parity
Parity with the incumbent is based on the price of Northwest European grey ammonia produced today as published by S&P. Future prices of grey ammonia were determined assuming a decrease in natural gas costs to levels pre-Russian invasion of Ukraine.
WTP
WTP was assessed by calculating the current and future prices of grey ammonia with added carbon costs from the ETS. ETS costs were calculated using an RMI model.
Maritime:
Costs
Hydrogen conversion to ammonia and methanol was calculated using an RMI model. A surplus of FuelEU credits pooled and included as a production subsidy have a value of $222/tonne VLSFO-eq. The ammonia and methanol production costs are converted to $/tonne VLSFO-equivalent using an ammonia energy density of 5.22 kWh/kg, methanol density of 5.54 kWh/kg, and VLSFO energy density of 11.38 kWh/kg from Ship and Bunker.
Parity
Parity with the incumbent is based on the price of VLSFO fuel in the market today as published by Ship & Bunker; at the time of writing the market price was $680/tonne.
WTP
WTP is based on parity with the incumbent VLSFO fuel with the addition of the FuelEU penalty and ETS carbon cost for the use of VLSFO in Europe; $33.5/tonne VLSFO-eq. for the 2025 FuelEU penalty; $128/tonne VLSFO-eq. for the ETS cost.
Refining:
Costs
Hydrogen production via electrolysis and dedicated renewables was calculated using an RMI model.
Parity
Parity with the incumbent is based on the production cost of gas-based hydrogen today according to the European Hydrogen Observatory, Future prices of grey hydrogen were determined assuming a decrease in natural gas costs to level pre-Russian invasion of Ukraine.
WTP
WTP was assessed by calculating the current and future prices of grey hydrogen with added carbon costs from the ETS. ETS costs were calculated using an RMI model.
Steel:
Costs
Steel production costs are calculated using an RMI model which includes the price of the hydrogen feedstock as an operating expense; other costs include energy feedstocks, metallics, operations & maintenance, material transport, and capital costs.
Parity
Parity with the incumbent is based on the spot market price of Hot Rolled Coil (HRC), assumed to reflect the price of HRC produced from a blast furnace-basic oxygen furnace integrated steel mill. At time of writing, the spot market price for HRC was $688/tonne.
WTP
WTP comes from applying a green premium to the parity price with BF-BOF steel. Based on market data and internal analysis the green premium is assumed to be 30%.
Overview:
Appendix C: Methodology to estimate public and private funding
Public funding needed to bridge WTP gap
Funding to bridge the WTP gap was found by estimating the cost of renewable fuel minus the WTP as shown above. This was done for both 2024 and 2025, expected to linearly change over time. The volume of fuel supported was assumed to be zero in 2024, incrementally increasing year over year by the size of an archetypical project, assuming exponential growth of projects deployed, until capped at the demand volume calculated for each sector using the methodology in Appendix A. A given year’s gap value was multiplied by the equivalent yearly demand value and summed to estimate the total amount of funding needed from now until 2030.
Total investments needed
The total capital needed to enable mandates and the Accelerated Transition Scenario was found using archetype projects for refining, steel, fertilizers, maritime, aviation, and an archetype for hydrogen projects for general use. The deployment of each of these projects was assumed to occur year over year until the demand found using the methodology in Appendix A was reached. That amount of projects was then multiplied by the assumed CAPEX cost for each archetypical project to find the total investments needed. The public funding needed from the previous section is expected to unlock private funds that can reach this total investment figure.
Project archetypes:
Sector
Commodity
Size
Units
Capital investment needed (billion EUR)
Installation hydrogen requirement (ktpa H2)
Aviation
eSAF
50
ktpa eSAF
1.50
26
Fertilizers
eAmmonia
278
ktpa NH3
2.62
50
Maritime
eAmmonia
300
ktpa NH3
2.62
54
Maritime
eMethanol
150
ktpa MeOH
1.16
29
Refining
Renewable hydrogen
20
ktpa H2
0.75
20
Steel
Crude steel
2,500
ktpa crude steel
7.40
138
Other
Renewable hydrogen
20
ktpa H2
0.75
20
Funding in the EU
To determine the state of public funding in the EU, we investigated EU-level and Member State-level funding data from Hydrogen Europe’s Clean Hydrogen Monitor, the European Court of Auditor’s Special report 11/2024 on renewable hydrogen policy, the Innovation Fund Project Portfolio, the Recovery and Resilience Scoreboard, and various press releases on public funding. We determined the amount that had been earmarked for hydrogen in priority sectors using schemes designed to close the cost gap (CfDs, hydrogen premiums, etc.), and the amount of these funds that had been deployed (contracts signed or awarded to specific projects).
Endnotes
[1] RED III mandates are subject to national transposition by EU Member States and will differ in execution. RED III mandates 42% of industry consumption and 1% of transportation energy to be from RFNBOs, however the distribution among industries is up to the discretion of the Member States. This is already apparent, as draft legislation in the Netherlands excludes ammonia production from the obligation, and Belgium is pursuing the “refinery route” (applying transportation requirements to refineries). Transposition variation will affect the strength of the demand signal and the overall volumes mandated in each sector.
[2] Using hydrogen offsets a substantial amount of carbon in comparison to other uses: at a rate of up to 33,6 kg of carbon dioxide (CO2) abated per kg of renewable hydrogen used compared to 11 kg of CO2 avoided in most applications.
[3] €250 million has been granted to Stegra (formerly H2 Green Steel) and €143 million to HYBRIT. Stegra’s grant ranks the 2nd highest of all Innovation Fund grants and 1st among hydrogen-related projects. HYBRIT ranks 5th among hydrogen related projects.
[4] Free allocation of EUAs will be phased out, fully ending in 2034. Monetization of these allowances will be an early consideration.
[5] The required public funding to close the premium for renewable hydrogen is determined by the difference between the production cost of renewable hydrogen-based commodities and the willingness to pay (WTP), along with the estimate volume of demand. Our WTP calculations consider the cost of incumbent fossil-based alternatives, along with any additional penalties imposed under regulatory frameworks such as the EU ETS and FuelEU Maritime (for shipping), based on the carbon intensity of existing fuels. For more details, refer to Appendix B and C.
Key takeaways:
- Public Funding Gap: Current funding commitments fall short of what is needed to achieve the EU’s hydrogen and climate objectives. Approximately €13,9 billion in public funding will be needed to implement RED III mandates and an extra €31,7 to enable faster decarbonization under the Accelerated Transition Scenario.
- Unlocking Private Investment: Public funding could unlock approximately €251 billion in private capital expenditures. This is equivalent to a 7x leverage effect in mobilizing private investment from public funds.
- Slow Deployment: Despite €21,4 billion in relevant committed funds from the Commission and Member States, only €3 billion in public funding has been disbursed to renewable hydrogen projects and end-users.
- Geographic Focus: A near-term focus on key demand centers can kickstart the decarbonization of major industrial centers, although a more equitable EU-wide distribution of public funding will be required in the long term to effectively scale hydrogen adoption across all Member States.
Like all markets around the world, the initial optimism surrounding Europe’s renewable hydrogen sector was driven by expectations of rapid cost reductions. However, these expectations have not materialized, and the high cost of renewable hydrogen compared to fossil-based alternatives remains a significant barrier. As illustrated above in Exhibit 5, sustained public support will be an essential component in bridging the cost gap and stimulating demand in key sectors.
Public funding needed to bridge the willingness-to-pay gap
Between 2025 and 2030, we estimate that approximately €13,9 billion in public funding will be needed to implement RED III mandates, primarily in fertilizer and other industrial sectors (Exhibit 6).[5] To realize our Accelerated Transition Scenario (ATS), this funding would need to grow to over 3x the amount to increase financing for demand-side mechanisms. The public funding calculated represents the amount that would be needed to bridge the gap between the cost of a renewable, hydrogen-based fuel and its fossil-produced incumbent. While these cost projections were calculated with European production in mind, imported green commodities may offer cost-savings which decreases the total funding required.
Shipping and steel emerge as the primary sectors requiring financial support to unlock the Accelerated Transition Scenario's additional demand volumes. Overall, an estimated €45,6 billion in public funding would be required, which could unlock approximately €276 billion in private capital expenditures. This is equivalent to a 7x leverage effect in mobilizing private investment from public funds.
Committed funding and regional distribution
While public funding has the potential to catalyze private sector investment, current funding commitments fall short of what is needed to achieve the EU’s hydrogen and climate objectives. Despite significant amounts being earmarked by the European Commission and Member States through mechanisms such as Contracts for Difference (CfDs), H2Global, auctions, and the European Hydrogen Bank (EHB), actual funds deployed to date remain limited (Exhibit 7). These programs should be reviewed to understand deployment delays and accelerate disbursement of funds to priority sectors. It is important to note that the recently proposed Industrial Decarbonisation Bank (aiming for €100 billion in funding) represents the ideal vehicle to support the accelerated transition of Europe’s heavy-emitting sectors.
Funding is currently heavily concentrated in three countries – Germany, the Netherlands, and France. As demonstrated in Exhibit 3, these countries are key demand centers that require funding to meet their demand; but this leaves 55% of European hydrogen production without the same degree of funding. For example, Poland and Belgium comprise 19% of current consumption, mainly driven by ammonia production, and Spain and Italy’s hydrogen consumption will grow in the maritime and steel sector respectively. Overall, a more balanced distribution of funding is necessary to support hydrogen development across a wider range of Member States, particularly those that can offer competitive pricing and facilitate intra-EU hydrogen trade, such as the Iberian Peninsula and Nordic region.
Addressing the market’s economic realities
To overcome the economic challenges facing the nascent hydrogen sector, policymakers need to recalibrate their approach to how much sustained financial support will be required to support decarbonization of hard-to-electrify sectors. With decarbonization competing against other public interests, scarce public funding needs to be thoughtfully allocated to hard-to-electrify sectors and high-impact first-mover projects. While demonstration-stage funding has supported many small renewable hydrogen projects across the EU thus far, achieving RED III mandates or unlocking additional demand may require a different approach for the second von der Leyen Commission term (2025-2030).
Policymakers can expedite the release and utilization of €18 billion in undisbursed funding that is already committed across multiple EU and Member State programs. These programs should be subject to a pragmatic review to ensure that these funds can be leveraged efficiently to drive uptake of renewable hydrogen in priority end-use sectors. This may include a near-term focus on large demand centers and supporting first-mover suppliers in regions with strong renewable energy credentials. Ultimately, European policymakers should consider a more equitable long-term approach to address geographic imbalances in funding support across the bloc.
Ensuring public funding is strategically aligned with EU policy objectives is crucial to catalyze private investment, drive innovation, and scale up renewable hydrogen adoption across the EU. A well-coordinated approach will be critical to transforming Europe’s hydrogen ambitions into a fully realized industrial and economic opportunity, and policymakers need to decide the speed and scale they want to realize by 2030. Achieving faster sectoral decarbonization (as illustrated in the Accelerated Transition Scenario) will require a substantial increase in investment and broader utilization of other market-based mechanisms to resolve coordination failures within Europe’s renewable hydrogen market.
As the EU implements its new Clean Industrial Deal to address the competitiveness concerns raised in the 2024 Draghi Report, it should ensure that its regulatory frameworks are transparent, cross-referenced and unfaltering in climate ambition. As this pertains to kickstarting a hydrogen industry, Europe needs to hold the line on its global climate leadership and not relax its world-leading regulations. It is paramount to maintain a stable regulatory environment, not the least to provide investment certainty which is critical for developing renewable hydrogen value chains. Investors are currently planning project development and delivery decisions for a 2030 project horizon and any further regulatory uncertainty will make 2030 targets unachievable.
Reopening the RFNBO Delegated Acts will delay investment decisions and risk the creation of an industry with questionable sustainability credentials. Similarly, emissions guardrails must be maintained by ensuring the regulatory framework for low-carbon hydrogen is robust and holistic as we’ve examined in earlier analysis.
A path forward for policymakers
Now is the time for the European Commission and Member States to translate conceptual policies, rules, and funding mechanisms into effective tools to scale the EU renewable hydrogen market over the next five years. We recommend policymakers consider the following levers to drive forward market creation and implementation:
Joint Actions by European Policymakers:
- Support Priority End-Use Sectors: Increase funding for cost-effective demand mechanisms such as CfDs, tenders, and auctions; designing and communicating a program of individual funding rounds for high-impact sectors (e.g., utilizing the EHB or proposed Industrial Decarbonisation Bank to support steel, fertilizer, aviation and maritime end-users).
- Accelerate Funding Deployment: Where prudent, expedite the release and utilization of €18 billion in undisbursed funding. Expand funding within Member States that have been unable to allocate sufficient support, and/or expand EU-level programs to address the shortfall.
- Consider Aligning Public Funding with Climate and Clean Industrial Deal Goals: As demonstrated in our Accelerated Transition Scenario, scaling public funding to €46 billion can unlock €276 billion in private industry investments to accelerate decarbonization of hard-to-electrify sectors. The Industrial Decarbonisation Bank would be well-placed to drive an accelerated transition within these sectors.
- Develop Hydrogen Infrastructure: Boost EU and national funding for hydrogen import infrastructure and intra-EU trade, recalibrating infrastructure roll-out requirements to focus on realistic demand volumes within industrial clusters.
Actions by the European Commission:
- Articulate a Clear Vision: Provide updated guidance to Member States and the hydrogen industry, focusing on hard-to-electrify sectors and maintaining confidence in regulatory frameworks.
- Adjust to Market Realities: Recalibrate expectations from the unrealistic 20 Mtpa target to approximately 2.2 – 2.8 Mtpa under RED III mandates and 1.5 – 4.2 Mtpa of additional demand by 2030 under our Accelerated Transition Scenario.
- Strengthen Emissions Guardrails: Hold the line on RFNBO regulations and ensure robust and complementary accounting frameworks are put in place for low-carbon hydrogen to ensure consistency and credibility.
Actions by Member States:
- Transpose RED III Mandates: Implement enforceable quotas with strong penalties for non-compliance before May 2025 to protect the intent of RFNBO targets.
- Set Pragmatic National Targets: Define realistic production, electrolyzer capacity, and infrastructure goals in National Energy and Climate Plans (NECPs).
- Align Market Rules Across States: Coordinate the transposition of the Hydrogen and Decarbonised Gas Market Package to create a unified and functional hydrogen market.
Appendix A: Scenario assumptions for demand
Mandates
Industry: RED III-stimulated demand for industry was based on current hydrogen consumption from the European Hydrogen Observatory projected out to 2030. Sectors included within the category of ‘industry’ include refining, ammonia, methanol, other chemicals, industrial heat, steel, and other industry. Byproduct hydrogen was removed from current consumption.
Hydrogen consumption within refining introduces a special case within RED III mandates. Under the existing policy, hydrogen produced via byproduct is not included in the total amount of hydrogen subject to the 42% RFNBO industry consumption mandate. Refineries use a large amount of byproduct hydrogen, from production of styrene, ethylene, and most notably, through catalytic naphtha reforming. It was assumed that hydrogen produced outside of byproduct (such as steam methane reformation or partial oxidation) represented 56% of refinery hydrogen demand. Additionally, RED III states that hydrogen used to process “conventional transport fuels” can count toward the 1% transportation target rather than the industry target. It was assumed that 66% of intentionally produced hydrogen was used to produce transport fuels and does not fall under industry mandates. Additional refinery considerations included a -0.7% CAGR decrease in production due to a phase-out of refining in line with the broader energy transition.
The total volume of intentionally produced, non-byproduct hydrogen was assessed, and the 42% mandate was applied as per Article 22a of RED III.
Transportation: Transportation mandates were calculated using the overall energy demand for transportation in the European Union. Data was used from Eurostat for current energy demand and a 2030 projection from the European Environment Agency.
Aviation was assumed to require hydrogen to meet the 1.2% sub mandate for synthetic SAF within Annex I of ReFuelEU. Aviation within the transportation mandate accounted for the 1.5x multiplier in Article 27 of RED III.
Maritime was assumed to meet the 1.2% mandate within Article 25 of RED III. Maritime within the transportation mandate accounted for the 1.5x multiplier in Article 27 of RED III.
Other transportation RFNBO consumption was based on the total energy consumption mandated under RED III (1% of total energy) less the aviation and maritime sectors. Other transportation accounted for the 2x multiplier in Article 27 of RED III.
Accelerated Transition Scenario
The Accelerated Transition Scenario (ATS) was considered for priority sectors for hydrogen use.
Aviation
Aviation demand for hydrogen was estimated in consultation with RMI experts on demand projects for 2030 ranging from 0.5 to 1.0 million tons of hydrogen required.
Fertilizers
Fertilizer demand under the ATS was determined by calculating the amount of renewable ammonia (and subsequently hydrogen) needed to satisfy the “green hydrogen pathway” of 50% carbon intensity reduction by 2030 published by Fertilizers Europe. Data for ammonia production was based on fertilizer consumption data from the International Fertilizer Association, correcting for import and exports using Fertilizers Europe estimations.
Maritime
Maritime demand for hydrogen was determined by assuming maritime fuel use would be in line with the International Maritime Organization Greenhouse Gas Reduction Strategy target of 5% of energy demand met through zero-emission fuels by 2030, assuming 90% of zero-emission fuel is met through hydrogen-derived products.
Refining
Refinery demand under the ATS was determined by assuming the proportion of intentionally produced hydrogen that is produced renewably will follow the clean consumption for refining pathways under the IEA Net Zero Emissions scenario.
Steel
Steel demand under the ATS was found by assuming all H2-DRI and H2-ready DRI projects in the project pipeline reach operation and use between 50% to 100% hydrogen by 2030. Hydrogen demand for DRI was assumed to be 0.055 tonnes hydrogen per tonne DRI.
Appendix B: WTP Methodology and assumptions
Any monetary values found in literature or calculated through modeling that are expressed in USD were converted to EUR for analysis.
Aviation:
Costs
SAF production costs were calculated using an RMI model which includes the hydrogen feedstock price as an operating expense, other costs include bio feedstocks, CO2, energy feedstocks, operations & maintenance, and capital costs.
Parity
Parity with incumbent jet fuel is based on the current market price from IATA; at the time of writing the jet fuel price was $782/tonne.
WTP
WTP for SAF is based on the minimum expected fine for not meeting ReFuelEU mandates, as set by ReFuelEU. The fine for failure to comply for aircraft operators is required to be no less than twice as high as the average price per tonne of aviation fuel, as stated by Article 12 of the ReFuelEU regulation. Since no synthetic SAF is required until 2030, there is likely no actual penalty until then. The penalty is used as an approximation for how aircraft operators would approach procurement until 2030. Penalties affecting fuel suppliers in 2030 would be based on the price of synthetic SAF rather than the average aviation fuel price, likely pushing the WTP much higher than currently calculated.
Fertilizers:
Costs
Hydrogen conversion to ammonia was calculated using an RMI model with additional costs for ammonia storage included. Assumes Haber Bosch production of 0.3 Mt NH3.
Parity
Parity with the incumbent is based on the price of Northwest European grey ammonia produced today as published by S&P. Future prices of grey ammonia were determined assuming a decrease in natural gas costs to levels pre-Russian invasion of Ukraine.
WTP
WTP was assessed by calculating the current and future prices of grey ammonia with added carbon costs from the ETS. ETS costs were calculated using an RMI model.
Maritime:
Costs
Hydrogen conversion to ammonia and methanol was calculated using an RMI model. A surplus of FuelEU credits pooled and included as a production subsidy have a value of $222/tonne VLSFO-eq. The ammonia and methanol production costs are converted to $/tonne VLSFO-equivalent using an ammonia energy density of 5.22 kWh/kg, methanol density of 5.54 kWh/kg, and VLSFO energy density of 11.38 kWh/kg from Ship and Bunker.
Parity
Parity with the incumbent is based on the price of VLSFO fuel in the market today as published by Ship & Bunker; at the time of writing the market price was $680/tonne.
WTP
WTP is based on parity with the incumbent VLSFO fuel with the addition of the FuelEU penalty and ETS carbon cost for the use of VLSFO in Europe; $33.5/tonne VLSFO-eq. for the 2025 FuelEU penalty; $128/tonne VLSFO-eq. for the ETS cost.
Refining:
Costs
Hydrogen production via electrolysis and dedicated renewables was calculated using an RMI model.
Parity
Parity with the incumbent is based on the production cost of gas-based hydrogen today according to the European Hydrogen Observatory, Future prices of grey hydrogen were determined assuming a decrease in natural gas costs to level pre-Russian invasion of Ukraine.
WTP
WTP was assessed by calculating the current and future prices of grey hydrogen with added carbon costs from the ETS. ETS costs were calculated using an RMI model.
Steel:
Costs
Steel production costs are calculated using an RMI model which includes the price of the hydrogen feedstock as an operating expense; other costs include energy feedstocks, metallics, operations & maintenance, material transport, and capital costs.
Parity
Parity with the incumbent is based on the spot market price of Hot Rolled Coil (HRC), assumed to reflect the price of HRC produced from a blast furnace-basic oxygen furnace integrated steel mill. At time of writing, the spot market price for HRC was $688/tonne.
WTP
WTP comes from applying a green premium to the parity price with BF-BOF steel. Based on market data and internal analysis the green premium is assumed to be 30%.
Overview:
Appendix C: Methodology to estimate public and private funding
Public funding needed to bridge WTP gap
Funding to bridge the WTP gap was found by estimating the cost of renewable fuel minus the WTP as shown above. This was done for both 2024 and 2025, expected to linearly change over time. The volume of fuel supported was assumed to be zero in 2024, incrementally increasing year over year by the size of an archetypical project, assuming exponential growth of projects deployed, until capped at the demand volume calculated for each sector using the methodology in Appendix A. A given year’s gap value was multiplied by the equivalent yearly demand value and summed to estimate the total amount of funding needed from now until 2030.
Total investments needed
The total capital needed to enable mandates and the Accelerated Transition Scenario was found using archetype projects for refining, steel, fertilizers, maritime, aviation, and an archetype for hydrogen projects for general use. The deployment of each of these projects was assumed to occur year over year until the demand found using the methodology in Appendix A was reached. That amount of projects was then multiplied by the assumed CAPEX cost for each archetypical project to find the total investments needed. The public funding needed from the previous section is expected to unlock private funds that can reach this total investment figure.
Project archetypes:
Sector
Commodity
Size
Units
Capital investment needed (billion EUR)
Installation hydrogen requirement (ktpa H2)
Aviation
eSAF
50
ktpa eSAF
1.50
26
Fertilizers
eAmmonia
278
ktpa NH3
2.62
50
Maritime
eAmmonia
300
ktpa NH3
2.62
54
Maritime
eMethanol
150
ktpa MeOH
1.16
29
Refining
Renewable hydrogen
20
ktpa H2
0.75
20
Steel
Crude steel
2,500
ktpa crude steel
7.40
138
Other
Renewable hydrogen
20
ktpa H2
0.75
20
Funding in the EU
To determine the state of public funding in the EU, we investigated EU-level and Member State-level funding data from Hydrogen Europe’s Clean Hydrogen Monitor, the European Court of Auditor’s Special report 11/2024 on renewable hydrogen policy, the Innovation Fund Project Portfolio, the Recovery and Resilience Scoreboard, and various press releases on public funding. We determined the amount that had been earmarked for hydrogen in priority sectors using schemes designed to close the cost gap (CfDs, hydrogen premiums, etc.), and the amount of these funds that had been deployed (contracts signed or awarded to specific projects).
Endnotes
[1] RED III mandates are subject to national transposition by EU Member States and will differ in execution. RED III mandates 42% of industry consumption and 1% of transportation energy to be from RFNBOs, however the distribution among industries is up to the discretion of the Member States. This is already apparent, as draft legislation in the Netherlands excludes ammonia production from the obligation, and Belgium is pursuing the “refinery route” (applying transportation requirements to refineries). Transposition variation will affect the strength of the demand signal and the overall volumes mandated in each sector.
[2] Using hydrogen offsets a substantial amount of carbon in comparison to other uses: at a rate of up to 33,6 kg of carbon dioxide (CO2) abated per kg of renewable hydrogen used compared to 11 kg of CO2 avoided in most applications.
[3] €250 million has been granted to Stegra (formerly H2 Green Steel) and €143 million to HYBRIT. Stegra’s grant ranks the 2nd highest of all Innovation Fund grants and 1st among hydrogen-related projects. HYBRIT ranks 5th among hydrogen related projects.
[4] Free allocation of EUAs will be phased out, fully ending in 2034. Monetization of these allowances will be an early consideration.
[5] The required public funding to close the premium for renewable hydrogen is determined by the difference between the production cost of renewable hydrogen-based commodities and the willingness to pay (WTP), along with the estimate volume of demand. Our WTP calculations consider the cost of incumbent fossil-based alternatives, along with any additional penalties imposed under regulatory frameworks such as the EU ETS and FuelEU Maritime (for shipping), based on the carbon intensity of existing fuels. For more details, refer to Appendix B and C.
Now is the time for the European Commission and Member States to translate conceptual policies, rules, and funding mechanisms into effective tools to scale the EU renewable hydrogen market over the next five years. We recommend policymakers consider the following levers to drive forward market creation and implementation:
Joint Actions by European Policymakers:
- Support Priority End-Use Sectors: Increase funding for cost-effective demand mechanisms such as CfDs, tenders, and auctions; designing and communicating a program of individual funding rounds for high-impact sectors (e.g., utilizing the EHB or proposed Industrial Decarbonisation Bank to support steel, fertilizer, aviation and maritime end-users).
- Accelerate Funding Deployment: Where prudent, expedite the release and utilization of €18 billion in undisbursed funding. Expand funding within Member States that have been unable to allocate sufficient support, and/or expand EU-level programs to address the shortfall.
- Consider Aligning Public Funding with Climate and Clean Industrial Deal Goals: As demonstrated in our Accelerated Transition Scenario, scaling public funding to €46 billion can unlock €276 billion in private industry investments to accelerate decarbonization of hard-to-electrify sectors. The Industrial Decarbonisation Bank would be well-placed to drive an accelerated transition within these sectors.
- Develop Hydrogen Infrastructure: Boost EU and national funding for hydrogen import infrastructure and intra-EU trade, recalibrating infrastructure roll-out requirements to focus on realistic demand volumes within industrial clusters.
Actions by the European Commission:
- Articulate a Clear Vision: Provide updated guidance to Member States and the hydrogen industry, focusing on hard-to-electrify sectors and maintaining confidence in regulatory frameworks.
- Adjust to Market Realities: Recalibrate expectations from the unrealistic 20 Mtpa target to approximately 2.2 – 2.8 Mtpa under RED III mandates and 1.5 – 4.2 Mtpa of additional demand by 2030 under our Accelerated Transition Scenario.
- Strengthen Emissions Guardrails: Hold the line on RFNBO regulations and ensure robust and complementary accounting frameworks are put in place for low-carbon hydrogen to ensure consistency and credibility.
Actions by Member States:
- Transpose RED III Mandates: Implement enforceable quotas with strong penalties for non-compliance before May 2025 to protect the intent of RFNBO targets.
- Set Pragmatic National Targets: Define realistic production, electrolyzer capacity, and infrastructure goals in National Energy and Climate Plans (NECPs).
- Align Market Rules Across States: Coordinate the transposition of the Hydrogen and Decarbonised Gas Market Package to create a unified and functional hydrogen market.
Mandates
Industry: RED III-stimulated demand for industry was based on current hydrogen consumption from the European Hydrogen Observatory projected out to 2030. Sectors included within the category of ‘industry’ include refining, ammonia, methanol, other chemicals, industrial heat, steel, and other industry. Byproduct hydrogen was removed from current consumption.
Hydrogen consumption within refining introduces a special case within RED III mandates. Under the existing policy, hydrogen produced via byproduct is not included in the total amount of hydrogen subject to the 42% RFNBO industry consumption mandate. Refineries use a large amount of byproduct hydrogen, from production of styrene, ethylene, and most notably, through catalytic naphtha reforming. It was assumed that hydrogen produced outside of byproduct (such as steam methane reformation or partial oxidation) represented 56% of refinery hydrogen demand. Additionally, RED III states that hydrogen used to process “conventional transport fuels” can count toward the 1% transportation target rather than the industry target. It was assumed that 66% of intentionally produced hydrogen was used to produce transport fuels and does not fall under industry mandates. Additional refinery considerations included a -0.7% CAGR decrease in production due to a phase-out of refining in line with the broader energy transition.
The total volume of intentionally produced, non-byproduct hydrogen was assessed, and the 42% mandate was applied as per Article 22a of RED III.
Transportation: Transportation mandates were calculated using the overall energy demand for transportation in the European Union. Data was used from Eurostat for current energy demand and a 2030 projection from the European Environment Agency.
Aviation was assumed to require hydrogen to meet the 1.2% sub mandate for synthetic SAF within Annex I of ReFuelEU. Aviation within the transportation mandate accounted for the 1.5x multiplier in Article 27 of RED III.
Maritime was assumed to meet the 1.2% mandate within Article 25 of RED III. Maritime within the transportation mandate accounted for the 1.5x multiplier in Article 27 of RED III.
Other transportation RFNBO consumption was based on the total energy consumption mandated under RED III (1% of total energy) less the aviation and maritime sectors. Other transportation accounted for the 2x multiplier in Article 27 of RED III.
Accelerated Transition Scenario
The Accelerated Transition Scenario (ATS) was considered for priority sectors for hydrogen use.
| Aviation | Aviation demand for hydrogen was estimated in consultation with RMI experts on demand projects for 2030 ranging from 0.5 to 1.0 million tons of hydrogen required. |
| Fertilizers | Fertilizer demand under the ATS was determined by calculating the amount of renewable ammonia (and subsequently hydrogen) needed to satisfy the “green hydrogen pathway” of 50% carbon intensity reduction by 2030 published by Fertilizers Europe. Data for ammonia production was based on fertilizer consumption data from the International Fertilizer Association, correcting for import and exports using Fertilizers Europe estimations. |
| Maritime | Maritime demand for hydrogen was determined by assuming maritime fuel use would be in line with the International Maritime Organization Greenhouse Gas Reduction Strategy target of 5% of energy demand met through zero-emission fuels by 2030, assuming 90% of zero-emission fuel is met through hydrogen-derived products. |
| Refining | Refinery demand under the ATS was determined by assuming the proportion of intentionally produced hydrogen that is produced renewably will follow the clean consumption for refining pathways under the IEA Net Zero Emissions scenario. |
| Steel | Steel demand under the ATS was found by assuming all H2-DRI and H2-ready DRI projects in the project pipeline reach operation and use between 50% to 100% hydrogen by 2030. Hydrogen demand for DRI was assumed to be 0.055 tonnes hydrogen per tonne DRI. |
Appendix B: WTP Methodology and assumptions
Any monetary values found in literature or calculated through modeling that are expressed in USD were converted to EUR for analysis.
Aviation:
Costs
SAF production costs were calculated using an RMI model which includes the hydrogen feedstock price as an operating expense, other costs include bio feedstocks, CO2, energy feedstocks, operations & maintenance, and capital costs.
Parity
Parity with incumbent jet fuel is based on the current market price from IATA; at the time of writing the jet fuel price was $782/tonne.
WTP
WTP for SAF is based on the minimum expected fine for not meeting ReFuelEU mandates, as set by ReFuelEU. The fine for failure to comply for aircraft operators is required to be no less than twice as high as the average price per tonne of aviation fuel, as stated by Article 12 of the ReFuelEU regulation. Since no synthetic SAF is required until 2030, there is likely no actual penalty until then. The penalty is used as an approximation for how aircraft operators would approach procurement until 2030. Penalties affecting fuel suppliers in 2030 would be based on the price of synthetic SAF rather than the average aviation fuel price, likely pushing the WTP much higher than currently calculated.
Fertilizers:
Costs
Hydrogen conversion to ammonia was calculated using an RMI model with additional costs for ammonia storage included. Assumes Haber Bosch production of 0.3 Mt NH3.
Parity
Parity with the incumbent is based on the price of Northwest European grey ammonia produced today as published by S&P. Future prices of grey ammonia were determined assuming a decrease in natural gas costs to levels pre-Russian invasion of Ukraine.
WTP
WTP was assessed by calculating the current and future prices of grey ammonia with added carbon costs from the ETS. ETS costs were calculated using an RMI model.
Maritime:
Costs
Hydrogen conversion to ammonia and methanol was calculated using an RMI model. A surplus of FuelEU credits pooled and included as a production subsidy have a value of $222/tonne VLSFO-eq. The ammonia and methanol production costs are converted to $/tonne VLSFO-equivalent using an ammonia energy density of 5.22 kWh/kg, methanol density of 5.54 kWh/kg, and VLSFO energy density of 11.38 kWh/kg from Ship and Bunker.
Parity
Parity with the incumbent is based on the price of VLSFO fuel in the market today as published by Ship & Bunker; at the time of writing the market price was $680/tonne.
WTP
WTP is based on parity with the incumbent VLSFO fuel with the addition of the FuelEU penalty and ETS carbon cost for the use of VLSFO in Europe; $33.5/tonne VLSFO-eq. for the 2025 FuelEU penalty; $128/tonne VLSFO-eq. for the ETS cost.
Refining:
Costs
Hydrogen production via electrolysis and dedicated renewables was calculated using an RMI model.
Parity
Parity with the incumbent is based on the production cost of gas-based hydrogen today according to the European Hydrogen Observatory, Future prices of grey hydrogen were determined assuming a decrease in natural gas costs to level pre-Russian invasion of Ukraine.
WTP
WTP was assessed by calculating the current and future prices of grey hydrogen with added carbon costs from the ETS. ETS costs were calculated using an RMI model.
Steel:
Costs
Steel production costs are calculated using an RMI model which includes the price of the hydrogen feedstock as an operating expense; other costs include energy feedstocks, metallics, operations & maintenance, material transport, and capital costs.
Parity
Parity with the incumbent is based on the spot market price of Hot Rolled Coil (HRC), assumed to reflect the price of HRC produced from a blast furnace-basic oxygen furnace integrated steel mill. At time of writing, the spot market price for HRC was $688/tonne.
WTP
WTP comes from applying a green premium to the parity price with BF-BOF steel. Based on market data and internal analysis the green premium is assumed to be 30%.
Overview:
Appendix C: Methodology to estimate public and private funding
Public funding needed to bridge WTP gap
Funding to bridge the WTP gap was found by estimating the cost of renewable fuel minus the WTP as shown above. This was done for both 2024 and 2025, expected to linearly change over time. The volume of fuel supported was assumed to be zero in 2024, incrementally increasing year over year by the size of an archetypical project, assuming exponential growth of projects deployed, until capped at the demand volume calculated for each sector using the methodology in Appendix A. A given year’s gap value was multiplied by the equivalent yearly demand value and summed to estimate the total amount of funding needed from now until 2030.
Total investments needed
The total capital needed to enable mandates and the Accelerated Transition Scenario was found using archetype projects for refining, steel, fertilizers, maritime, aviation, and an archetype for hydrogen projects for general use. The deployment of each of these projects was assumed to occur year over year until the demand found using the methodology in Appendix A was reached. That amount of projects was then multiplied by the assumed CAPEX cost for each archetypical project to find the total investments needed. The public funding needed from the previous section is expected to unlock private funds that can reach this total investment figure.
Project archetypes:
Sector
Commodity
Size
Units
Capital investment needed (billion EUR)
Installation hydrogen requirement (ktpa H2)
Aviation
eSAF
50
ktpa eSAF
1.50
26
Fertilizers
eAmmonia
278
ktpa NH3
2.62
50
Maritime
eAmmonia
300
ktpa NH3
2.62
54
Maritime
eMethanol
150
ktpa MeOH
1.16
29
Refining
Renewable hydrogen
20
ktpa H2
0.75
20
Steel
Crude steel
2,500
ktpa crude steel
7.40
138
Other
Renewable hydrogen
20
ktpa H2
0.75
20
Funding in the EU
To determine the state of public funding in the EU, we investigated EU-level and Member State-level funding data from Hydrogen Europe’s Clean Hydrogen Monitor, the European Court of Auditor’s Special report 11/2024 on renewable hydrogen policy, the Innovation Fund Project Portfolio, the Recovery and Resilience Scoreboard, and various press releases on public funding. We determined the amount that had been earmarked for hydrogen in priority sectors using schemes designed to close the cost gap (CfDs, hydrogen premiums, etc.), and the amount of these funds that had been deployed (contracts signed or awarded to specific projects).
Endnotes
[1] RED III mandates are subject to national transposition by EU Member States and will differ in execution. RED III mandates 42% of industry consumption and 1% of transportation energy to be from RFNBOs, however the distribution among industries is up to the discretion of the Member States. This is already apparent, as draft legislation in the Netherlands excludes ammonia production from the obligation, and Belgium is pursuing the “refinery route” (applying transportation requirements to refineries). Transposition variation will affect the strength of the demand signal and the overall volumes mandated in each sector.
[2] Using hydrogen offsets a substantial amount of carbon in comparison to other uses: at a rate of up to 33,6 kg of carbon dioxide (CO2) abated per kg of renewable hydrogen used compared to 11 kg of CO2 avoided in most applications.
[3] €250 million has been granted to Stegra (formerly H2 Green Steel) and €143 million to HYBRIT. Stegra’s grant ranks the 2nd highest of all Innovation Fund grants and 1st among hydrogen-related projects. HYBRIT ranks 5th among hydrogen related projects.
[4] Free allocation of EUAs will be phased out, fully ending in 2034. Monetization of these allowances will be an early consideration.
[5] The required public funding to close the premium for renewable hydrogen is determined by the difference between the production cost of renewable hydrogen-based commodities and the willingness to pay (WTP), along with the estimate volume of demand. Our WTP calculations consider the cost of incumbent fossil-based alternatives, along with any additional penalties imposed under regulatory frameworks such as the EU ETS and FuelEU Maritime (for shipping), based on the carbon intensity of existing fuels. For more details, refer to Appendix B and C.
Any monetary values found in literature or calculated through modeling that are expressed in USD were converted to EUR for analysis.
Aviation:
| Costs | SAF production costs were calculated using an RMI model which includes the hydrogen feedstock price as an operating expense, other costs include bio feedstocks, CO2, energy feedstocks, operations & maintenance, and capital costs. |
| Parity | Parity with incumbent jet fuel is based on the current market price from IATA; at the time of writing the jet fuel price was $782/tonne. |
| WTP | WTP for SAF is based on the minimum expected fine for not meeting ReFuelEU mandates, as set by ReFuelEU. The fine for failure to comply for aircraft operators is required to be no less than twice as high as the average price per tonne of aviation fuel, as stated by Article 12 of the ReFuelEU regulation. Since no synthetic SAF is required until 2030, there is likely no actual penalty until then. The penalty is used as an approximation for how aircraft operators would approach procurement until 2030. Penalties affecting fuel suppliers in 2030 would be based on the price of synthetic SAF rather than the average aviation fuel price, likely pushing the WTP much higher than currently calculated. |
Fertilizers:
| Costs | Hydrogen conversion to ammonia was calculated using an RMI model with additional costs for ammonia storage included. Assumes Haber Bosch production of 0.3 Mt NH3. |
| Parity | Parity with the incumbent is based on the price of Northwest European grey ammonia produced today as published by S&P. Future prices of grey ammonia were determined assuming a decrease in natural gas costs to levels pre-Russian invasion of Ukraine. |
| WTP | WTP was assessed by calculating the current and future prices of grey ammonia with added carbon costs from the ETS. ETS costs were calculated using an RMI model. |
Maritime:
| Costs | Hydrogen conversion to ammonia and methanol was calculated using an RMI model. A surplus of FuelEU credits pooled and included as a production subsidy have a value of $222/tonne VLSFO-eq. The ammonia and methanol production costs are converted to $/tonne VLSFO-equivalent using an ammonia energy density of 5.22 kWh/kg, methanol density of 5.54 kWh/kg, and VLSFO energy density of 11.38 kWh/kg from Ship and Bunker. |
| Parity | Parity with the incumbent is based on the price of VLSFO fuel in the market today as published by Ship & Bunker; at the time of writing the market price was $680/tonne. |
| WTP | WTP is based on parity with the incumbent VLSFO fuel with the addition of the FuelEU penalty and ETS carbon cost for the use of VLSFO in Europe; $33.5/tonne VLSFO-eq. for the 2025 FuelEU penalty; $128/tonne VLSFO-eq. for the ETS cost. |
Refining:
| Costs | Hydrogen production via electrolysis and dedicated renewables was calculated using an RMI model. |
| Parity | Parity with the incumbent is based on the production cost of gas-based hydrogen today according to the European Hydrogen Observatory, Future prices of grey hydrogen were determined assuming a decrease in natural gas costs to level pre-Russian invasion of Ukraine. |
| WTP | WTP was assessed by calculating the current and future prices of grey hydrogen with added carbon costs from the ETS. ETS costs were calculated using an RMI model. |
Steel:
| Costs | Steel production costs are calculated using an RMI model which includes the price of the hydrogen feedstock as an operating expense; other costs include energy feedstocks, metallics, operations & maintenance, material transport, and capital costs. |
| Parity | Parity with the incumbent is based on the spot market price of Hot Rolled Coil (HRC), assumed to reflect the price of HRC produced from a blast furnace-basic oxygen furnace integrated steel mill. At time of writing, the spot market price for HRC was $688/tonne. |
| WTP | WTP comes from applying a green premium to the parity price with BF-BOF steel. Based on market data and internal analysis the green premium is assumed to be 30%. |
Overview:
Public funding needed to bridge WTP gap
Funding to bridge the WTP gap was found by estimating the cost of renewable fuel minus the WTP as shown above. This was done for both 2024 and 2025, expected to linearly change over time. The volume of fuel supported was assumed to be zero in 2024, incrementally increasing year over year by the size of an archetypical project, assuming exponential growth of projects deployed, until capped at the demand volume calculated for each sector using the methodology in Appendix A. A given year’s gap value was multiplied by the equivalent yearly demand value and summed to estimate the total amount of funding needed from now until 2030.
Total investments needed
The total capital needed to enable mandates and the Accelerated Transition Scenario was found using archetype projects for refining, steel, fertilizers, maritime, aviation, and an archetype for hydrogen projects for general use. The deployment of each of these projects was assumed to occur year over year until the demand found using the methodology in Appendix A was reached. That amount of projects was then multiplied by the assumed CAPEX cost for each archetypical project to find the total investments needed. The public funding needed from the previous section is expected to unlock private funds that can reach this total investment figure.
Project archetypes:
| Sector | Commodity | Size | Units | Capital investment needed (billion EUR) | Installation hydrogen requirement (ktpa H2) |
| Aviation | eSAF | 50 | ktpa eSAF | 1.50 | 26 |
| Fertilizers | eAmmonia | 278 | ktpa NH3 | 2.62 | 50 |
| Maritime | eAmmonia | 300 | ktpa NH3 | 2.62 | 54 |
| Maritime | eMethanol | 150 | ktpa MeOH | 1.16 | 29 |
| Refining | Renewable hydrogen | 20 | ktpa H2 | 0.75 | 20 |
| Steel | Crude steel | 2,500 | ktpa crude steel | 7.40 | 138 |
| Other | Renewable hydrogen | 20 | ktpa H2 | 0.75 | 20 |
Funding in the EU
To determine the state of public funding in the EU, we investigated EU-level and Member State-level funding data from Hydrogen Europe’s Clean Hydrogen Monitor, the European Court of Auditor’s Special report 11/2024 on renewable hydrogen policy, the Innovation Fund Project Portfolio, the Recovery and Resilience Scoreboard, and various press releases on public funding. We determined the amount that had been earmarked for hydrogen in priority sectors using schemes designed to close the cost gap (CfDs, hydrogen premiums, etc.), and the amount of these funds that had been deployed (contracts signed or awarded to specific projects).
Endnotes
[1] RED III mandates are subject to national transposition by EU Member States and will differ in execution. RED III mandates 42% of industry consumption and 1% of transportation energy to be from RFNBOs, however the distribution among industries is up to the discretion of the Member States. This is already apparent, as draft legislation in the Netherlands excludes ammonia production from the obligation, and Belgium is pursuing the “refinery route” (applying transportation requirements to refineries). Transposition variation will affect the strength of the demand signal and the overall volumes mandated in each sector.
[2] Using hydrogen offsets a substantial amount of carbon in comparison to other uses: at a rate of up to 33,6 kg of carbon dioxide (CO2) abated per kg of renewable hydrogen used compared to 11 kg of CO2 avoided in most applications.
[3] €250 million has been granted to Stegra (formerly H2 Green Steel) and €143 million to HYBRIT. Stegra’s grant ranks the 2nd highest of all Innovation Fund grants and 1st among hydrogen-related projects. HYBRIT ranks 5th among hydrogen related projects.
[4] Free allocation of EUAs will be phased out, fully ending in 2034. Monetization of these allowances will be an early consideration.
[5] The required public funding to close the premium for renewable hydrogen is determined by the difference between the production cost of renewable hydrogen-based commodities and the willingness to pay (WTP), along with the estimate volume of demand. Our WTP calculations consider the cost of incumbent fossil-based alternatives, along with any additional penalties imposed under regulatory frameworks such as the EU ETS and FuelEU Maritime (for shipping), based on the carbon intensity of existing fuels. For more details, refer to Appendix B and C.
[1] RED III mandates are subject to national transposition by EU Member States and will differ in execution. RED III mandates 42% of industry consumption and 1% of transportation energy to be from RFNBOs, however the distribution among industries is up to the discretion of the Member States. This is already apparent, as draft legislation in the Netherlands excludes ammonia production from the obligation, and Belgium is pursuing the “refinery route” (applying transportation requirements to refineries). Transposition variation will affect the strength of the demand signal and the overall volumes mandated in each sector.
[2] Using hydrogen offsets a substantial amount of carbon in comparison to other uses: at a rate of up to 33,6 kg of carbon dioxide (CO2) abated per kg of renewable hydrogen used compared to 11 kg of CO2 avoided in most applications.
[3] €250 million has been granted to Stegra (formerly H2 Green Steel) and €143 million to HYBRIT. Stegra’s grant ranks the 2nd highest of all Innovation Fund grants and 1st among hydrogen-related projects. HYBRIT ranks 5th among hydrogen related projects.
[4] Free allocation of EUAs will be phased out, fully ending in 2034. Monetization of these allowances will be an early consideration.
[5] The required public funding to close the premium for renewable hydrogen is determined by the difference between the production cost of renewable hydrogen-based commodities and the willingness to pay (WTP), along with the estimate volume of demand. Our WTP calculations consider the cost of incumbent fossil-based alternatives, along with any additional penalties imposed under regulatory frameworks such as the EU ETS and FuelEU Maritime (for shipping), based on the carbon intensity of existing fuels. For more details, refer to Appendix B and C.