Rethinking Germany's hydrogen-led transition / Chapter 1
Germany’s hydrogen strategy — a reset in progress
Key findings
Germany’s 2045 hydrogen demand is likely to be at or below the lower end of official scenario ranges.
Green hydrogen is failing to achieve the cost reductions needed to be competitive, while blue hydrogen costs will always depend on volatile gas prices.
Vested interests played a documented role in shaping Germany's oversized hydrogen ambitions.
To reduce costs and compete in the long term, German industrial sectors may need to import clean hydrogen derivatives rather than hydrogen itself — further reducing the need for hydrogen pipelines.
Germany has the largest and most ambitious national hydrogen strategy in Europe. It aims to deliver not only decarbonisation, but industrial growth, technological leadership and energy system resilience. Green hydrogen sits at the centre of this vision, though the strategy increasingly allows for low-carbon alternatives, including blue hydrogen, to support scale-up.¹ The challenge lies in building supply, demand and transport infrastructure simultaneously. Costs remain higher than the current willingness to pay, while supply volumes are still limited. To bridge this gap, Germany has deployed a range of regulations and public finance mechanisms to build the market in parallel. But the strategy rests on two key assumptions: broad cross-sector adoption and substantial cost declines. Both are becoming increasingly uncertain.
Supply push becomes demand pull
Germany announced its initial hydrogen strategy in 2020. It updated it in 2023 to target 10 gigawatts (GW) of domestic electrolyser capacity and 95–130 terawatt-hours (TWh) of annual hydrogen demand by 2030, of which 50–70% is expected to be supplied by imports. Since 2023, there has been a further shift in approach, with the original, larger-scale supply-push build out of production and transport capacity swapped for a more cautious demand-pull approach. This is in response to slow implementation, with an insufficient number of announced hydrogen production projects reaching final investment decision. Developers’ constraints include high project costs, strict EU definitions (renewable fuels of non-biological origin) for green hydrogen and investors seeking long-term offtake agreements.
Official acknowledgement
In September 2025, the Federal Ministry for Economic Affairs and Energy (BMWE) commissioned a monitoring report on Germany’s energy transition. The section on hydrogen is a meta-study of existing modelled scenarios and further updates the shift towards more flexible targets, widening beyond green hydrogen to include blue and other types of hydrogen. At the report’s launch, Energy Minister Katherina Reiche emphasised the need to focus on sectors with a high willingness to pay for hydrogen and a need to build out infrastructure “step by step”, alongside bankable demand. The monitoring report acknowledges that currently there is “hardly any market demand” and the 10GW domestic target seems “hardly achievable given the current project pipeline”. It also reiterates the high uncertainty in future hydrogen demand. Hanna Schumacher, head of the hydrogen and gas infrastructure department in the economy ministry, said in October 2025 that “the hydrogen ramp-up has not worked as well as we had hoped so far”, adding: “It may also make sense not to do things quite so quickly and not quite so much.”
What is Germany's Hydrogen Acceleration Act?
Germany’s strategy previously focused on hydrogen made from renewable energy (green hydrogen). But high costs and uncertain supply have opened the door to blue hydrogen, produced from natural gas with carbon capture and storage (CCS). Germany’s Hydrogen Acceleration Act, passed by parliament in February 2026, has formalised this shift. The legislation designates blue hydrogen as being in the “overriding public interest”, effectively giving such projects equal access to accelerated permitting as green hydrogen.
But this strategy deepens Germany’s infrastructure exposure, adding a network of carbon dioxide pipelines to the planned hydrogen backbone. It also expands reliance on CCS, a technology with prohibitive costs and historical underperformance. Most worryingly for Germany’s energy security, the legislation could lock in natural gas to create blue hydrogen. This would increase the country’s vulnerability to supply shocks and volatile gas prices.
In February 2026, the German parliament passed the Hydrogen Acceleration Act to speed up deployment of hydrogen production and supply infrastructure (such as electrolysers, import terminals, storage facilities and pipelines). It grants priority status to qualifying projects based on “overriding public interest” and defines binding deadlines, digitalisation requirements and fast-track legal procedures. The bill had been delayed for months amid intense lobbying pressure to expand its scope. Amendments to look beyond solely green hydrogen were accepted, meaning blue (and natural) hydrogen, renewable fuels of non-biological origin and power-to-liquid projects will qualify. However, the government rejected proposals to include industrial hydrogen usage (such as steel furnaces) on the basis that downstream project support was not the intention of this bill.
The case for importing derivatives
With the size of the hydrogen economy increasingly uncertain, focus should shift from marginal production costs to total system costs. IEEFA recommends focusing less on importing green hydrogen and more on its derivatives, which are needed to decarbonise certain industrial manufacturing processes. These include e-methanol (for plastics, fuel and other chemicals), e-ammonia (for fertilisers and fuel) and green hot briquetted iron (for steel).² By importing these products instead of producing them domestically, Germany could decarbonise parts of its industry at lower overall system cost while preserving industrial activity in the long term. This may be politically sensitive and could be framed as ceding German industry. But where jobs are already being lost to global competition despite substantial subsidies, the trade-off merits serious examination. Hanna Schumacher, head of the hydrogen and gas infrastructure department in the economy ministry, said in October 2025: “We will focus on imports, perhaps even more so than the last government because it is more cost-effective overall.”
The Thyssenkrupp case illustrates the challenge. In 2023, the EU approved up to €2 billion in German state aid for the company to develop a new hydrogen-ready direct reduction plant. Yet in 2024, the company still announced that it would cut 11,000 jobs. Today the plant is delayed and will run on natural gas rather than green hydrogen when it finally comes online. A recent study by Agora Industry found that integrating green iron imports could cut steelmaking costs in Europe by 12–15% by 2040.
Lower costs would stem from three factors:
- Reduced need for a new network of costly hydrogen pipelines and storage facilities within Germany, lowering capital needs and limiting utilisation risk.
- Decreased domestic electricity demand, which — in a marginal pricing system where gas often sets the price — could lower electricity costs economy-wide.
- Some countries can produce hydrogen-based products more cheaply than Germany can domestically, though transport costs still matter.
The downside is less upstream economic activity located in Germany and a greater reliance on international supply chains. Risk is mitigated, however, by the fact that production is viable anywhere with strong renewables resources, making meaningful supply diversification more achievable than with conventional energy imports. Collaboration at the EU level could also help to structure and secure those partnerships.
This shift reflects an inevitable economic trend — energy-intensive upstream production processes are naturally pulled towards centres with cheaper input costs. Whereas in the past this meant geographies with vast fossil fuel reserves, now and going forward it means countries with more abundant renewables resources. In IEEFA’s view, a recalibrated strategy that acknowledges and pre-emptively adapts to this reality is more likely to protect the future competitiveness of German industry than one that resists it.
Vested interests and a long-overdue reset
Germany’s difficulties are not entirely unique. A parallel reset of hydrogen expectations and plans has been taking place across the EU. A July 2024 report from the European Court of Auditors called for a hydrogen reality check and for the European Commission to “make strategic choices on the way ahead without creating new strategic dependencies”.
What EU institutions are now acknowledging has been argued for years by analysts, academics and civil society groups. Their concerns centre on two related problems — the lack of robust scientific assumptions around hydrogen, and the role of lobbying from vested interests (including gas and petrochemicals companies) in inflating hydrogen expectations.
Demand projections: Outdated, oversized and uncertain
Germany currently uses hydrogen in petrochemical refining and the production of hydrogen derivatives, mainly ammonia (for fertiliser) and methanol (for chemicals and fuel). BMWE’s monitoring report estimates that Germany’s current hydrogen demand is as much as 60TWh per year, almost entirely from fossil fuel production.³ Germany’s 2024 hydrogen production of around 1.7 million tonnes generated approximately 20 million tonnes of carbon dioxide, or about 3% of the country’s total annual greenhouse gas emissions.⁴
The monitoring report is direct about where the market stands today: “There is virtually no market-driven demand for renewable or low-carbon hydrogen in Europe. Market ramp-up is being managed at the national and EU levels through regulatory requirements and support instruments.” As well as the Emissions Trading System and Carbon Border Adjustment Mechanism, other EU measures to stimulate hydrogen demand include quotas for minimum use of renewables in the Renewable Energy Directive (RED II and RED III) and financial support for certain sectors under the Important Projects of Common European Interest. German measures include federal funding for industrial decarbonisation (Dekarbonisierung der Industrie & Bundesförderung Industrie und Klimaschutz) and climate protection agreements (Klimaschutzverträge). While these measures can help to stimulate demand to an extent, sustainable market-driven demand will ultimately require improved fundamentals.
Will Germany's hydrogen demand fall short of government forecasts?
Germany still plans a system-wide role for hydrogen. But analysing potential demand across sectors suggests that government forecasts are overoptimistic. IEEFA expects that hydrogen will not play a meaningful role for heating and transport. Germany will also likely use hydrogen power plants less than anticipated because of their high expense and low efficiency. This leaves industrial applications. A report from the Federal Ministry for Economic Affairs and Energy suggests uncertainty about industrial demand. IEEFA therefore estimates that Germany’s 2045 hydrogen demand will likely be at or below the lower end of official scenario ranges.
There is recognition within Germany that the country’s hydrogen forecasts are unrealistic. A member of the German government’s National Hydrogen Council warned last year that the country’s hydrogen targets will likely be missed. Both supply and demand are falling well below expectations, the president of Germany’s Federal Court of Auditors said in October 2025. To avoid overburdening the federal budget, he called on the government to “act now and fundamentally revise its hydrogen strategy”.
Where hydrogen will and won’t scale
Hydrogen is no longer expected to play a significant role in transport or buildings. This has been clear since 2020, as electric vehicles and heat pumps (in particular) have demonstrated falling costs, superior efficiency and strong growth. Any demand that does materialise in these sectors will likely be driven by regulatory quotas — for shipping and aviation fuels, for example — or exceptional cases such as off-grid heating.
In the power sector, hydrogen-ready plants have been touted as a solution to “dunkelflaute” periods of extended low solar and wind output, when the grid needs firm backup (typically in winter). However, hydrogen power plants will likely play a smaller role than originally planned and should not be expected to provide baseload generation. Their high expense and low efficiency, as well as the development of alternatives over the coming decades (more energy storage, stronger grid interconnections, demand-side management and increased system flexibility) significantly constrain their realistic contribution.
That leaves industrial applications such as chemicals production, steel and process heat generation. These sub-sectors currently rely on fossil fuels or grey hydrogen and could potentially switch to low-carbon hydrogen-based processes.⁵ The monitoring report scenarios suggest significant uncertainty about the extent of hydrogen demand here. Process heat could largely be decarbonised at lower cost through electrification, except in the highest temperature cases. The final result will depend largely on the future affordability and availability of clean hydrogen supply, as well as regulatory incentives supporting investment.
A blind spot also exists. The novel approach outlined previously, of importing green hydrogen derivatives (e-methanol, e-ammonia and green iron) rather than producing them domestically, would mean the associated hydrogen gas demand is swapped out and replaced with demand for the derivatives themselves. This has not yet been modelled in detailed scenarios for the industrial sector because the prevailing assumption has been that sufficient domestic clean hydrogen supply would make it unnecessary. However, this assumption is now hard to reconcile with auditor warnings. If it breaks down, hydrogen gas demand projections across the industrial sector may be substantially overstated, significantly weakening the case for pipeline infrastructure.
IEEFA’s adjusted demand estimates
Many of the existing scenarios do not reflect the above findings, meaning that projected green hydrogen demand is often unrealistically high. By applying these simple findings to existing projections, IEEFA estimates that Germany’s 2045 hydrogen demand is far more likely to sit at the bottom end of the monitoring report’s normative scenarios range (163–605 TWh), near the midpoint of the exploratory scenarios range (71–262TWh) and well below the range in the Federal Ministry for Economic Affairs and Climate Action’s 2024 system development strategy (360–500TWh).
Germany needs to rethink and downsize its hydrogen infrastructure plans around a substantially lower demand baseline.
While more detailed analysis is required to test and refine assumptions, it is clear that Germany needs to rethink and downsize its hydrogen infrastructure plans around a substantially lower demand baseline. Failure to do so risks overspending on hydrogen infrastructure, pushing up energy prices and locking in natural gas through blue hydrogen or hydrogen-ready gas plants that fail to switch to hydrogen. This would undermine Germany’s energy security and climate commitments and have sizeable fiscal consequences.
Hydrogen supply
Although Germany’s hydrogen demand outlook remains uncertain, it is clear that the country will meet most of it with imports, whether of hydrogen gas or hydrogen derivatives. This requires international supply chains, as well as terminals, pipelines and trucks in Germany. Under the EU’s hydrogen strategy, Germany, Belgium and the Netherlands will account for around 60% of the bloc’s hydrogen imports. The strategy identifies five possible supply corridors: South2, via North Africa and Southern Europe; H2Med, via Southwest Europe and North Africa; the North Sea; the Nordic and Baltic regions; and the Central European Hydrogen Corridor, via East and Southeast Europe.
While imports are expected to be cheaper, Germany aims to retain some domestic production for resilience, flexibility and technological know-how. The monitoring report notes that this trade-off is “also a political decision”. Its analysed scenarios vary widely, with imports accounting for 26–92% of hydrogen supply in 2045.
Domestic production
Germany’s target of 10GW of electrolyser capacity by 2030 is towards the top of the range of analysed scenarios in the monitoring report (2–12GW). As of 2025, only 1.2–1.3GW of projects were at final investment decision stage and another 7–12 GW were in planning, according to the monitoring report. On any reasonable construction timeline, the 10GW target is no longer credible. In October 2025, the German Federal Court of Auditors highlighted that according to the German Energy Agency, “less than 5GW of projects have a high to medium probability of being implemented by 2030".
International supply
Germany has allocated €4.4 billion to using the H2Global mechanism for procuring imports of green hydrogen and derivatives. The mechanism uses a double auction model to first buy internationally at the lowest possible price, then sell domestically to the highest bidder. Public funds initially cover the gap between these two prices, stimulating the market. In 2024, Germany awarded its first green hydrogen tender to fertiliser producer Fertiglobe. The company will supply Germany with at least 259,000 tonnes of green ammonia from Egypt between 2027 and 2033 for a total cost of €397 million. H2Global operator Hintco is now progressing a larger second auction round, partly jointly funded by the German and Dutch governments, with five lots totalling €2.9 billion.
Germany is pursuing bilateral green hydrogen tenders with both Canada and Australia. In January 2026, German utility Uniper announced a binding offtake agreement to purchase up to 500,000 tons of green ammonia per year from AM Green in India, certified for European use as a renewable fuel of non-biological origin, though commercial terms remain confidential.
The overall picture of international supply is one of tentative, early-stage commitments. Downsizing and cancellations have also started to creep in. Namibia’s Hyphen Hydrogen Energy project was one of the more advanced green ammonia supply projects targeting Germany. In September 2025, however, German utility RWE withdrew from the project entirely, having initially planned to import 300,000 tonnes of ammonia per year from 2027. The withdrawal signals how even committed players with established supply plans are stepping back, reflecting a broader reluctance to lock in long-term hydrogen offtake without greater demand certainty.
Import infrastructure
Germany plans to build or adapt its existing import terminals to be ammonia-ready. It has already made meaningful progress:
- Stade: Hanseatic Energy Hub is constructing a terminal to import liquefied natural gas (LNG) and later ammonia, targeting operation by 2027.
- Wilhelmshaven: Uniper is planning an ammonia import terminal and cracker plant.
- Hamburg: Mabanaft and Air Products are planning New Energy Gate Hamburg, an ammonia import terminal and cracker facilities at the Port of Hamburg, targeting 2028 operation.
- Brunsbüttel: The German LNG Terminal is constructing an ammonia-ready LNG terminal to be operational (importing LNG) from 2027.
Germany has had less success in developing hydrogen import pipelines, which fall within scope of the European Network of Transmission System Operators for Gas’s European Hydrogen Backbone project:
- In September 2024, Equinor halted its plans for a (blue) hydrogen export pipeline from Norway to Germany. “The hydrogen pipeline hasn't proved to be viable. That also implies that hydrogen production plans are also put aside,” a spokesperson said at the time, citing a lack of firm long-term commitments from European buyers to import hydrogen.
- The H2Med pipeline via Portugal, Spain and France to Germany is progressing as an EU Project of Common Interest, targeting operation from 2030 at the earliest.
Hydrogen cost projections
Prices have failed to come down as projected since 2020. Germany’s strategy originally envisioned green hydrogen as the energy carrier of the future, economically competitive with alternative decarbonisation solutions in time to justify the infrastructure that is already being built. But the cost gap has proven persistent, leading Germany to broaden its targets and include blue hydrogen alongside green — a decision that carries its own set of risks.
The delivered price in Germany reflects several stacked cost layers, each of which adds to the competitiveness gap between clean hydrogen and the incumbent fossil fuels it needs to displace or electrified alternatives it competes with:
- Production costs (highly variable, depending on method; see Table 2)
- Transport and storage costs (infrastructure such as pipelines, terminals, tanks)
- Any other levied taxes and charges (such as grid fees)
These costs may be partly offset by any subsidies or contract for difference payments offered to producers/consumers at either a national or EU level.
The monitoring report references recent modelling from the Institute of Energy Economics (EWI) at the University of Cologne, which puts the cost of domestic green hydrogen production in Germany at approximately €244/megawatt-hour, or around €7.30/kg. EWI projects this will fall to around €200/megawatt-hour in 2030, or roughly €6/kg. For context, grey hydrogen currently costs around €3/kg. Although the outlook for green hydrogen improves by 2050, it is unlikely to reach parity with the current cost of hydrogen produced using fossil fuels.
Table 2 summarises the cost components and projected ranges for grey, blue and green hydrogen production. The blue hydrogen data illustrate why it seems increasingly attractive to policymakers facing green hydrogen's cost persistence. At best around €4/kg in Europe today, it appears closer to the grey baseline. But blue hydrogen costs remain sensitive to gas prices, carbon capture performance/costs and carbon pricing for uncaptured emissions, meaning its 2050 trajectory is highly uncertain. For example, a meaningful carbon price at that point in time could erode much of blue hydrogen's apparent advantage.
Imports could offer partial relief. By 2030, EWI estimates that green hydrogen pipeline imports from Morocco, Spain or Finland will likely be cheaper than domestic production. Shipped imports from countries like Canada, Mexico or Australia will be more expensive, however, with conversion and transport losses adding materially to final delivered costs. Under a more targeted strategy, imported derivatives such as ammonia or methanol could prove more economical at a system level by using existing port infrastructure and reducing the need for costly new hydrogen pipelines.
The cost picture that emerges is consistent and uncomfortable. Green hydrogen has not followed the cost reduction curves that might justify the scale of Germany's infrastructure commitment. Blue hydrogen looks more affordable on paper but remains structurally dependent on gas markets, carbon capture and carbon pricing assumptions that are far from settled. Neither is on a trajectory that closes the competitiveness gap with direct electrification in the sectors where electrification is feasible.
Notes
¹ Green hydrogen is produced from water using renewable energy. Blue hydrogen is produced from natural gas with carbon capture. Other potential low-carbon colours are referenced in Germany and the EU, but this remains an evolving area. Clean hydrogen refers to renewable and low-carbon hydrogen.
² The precursor for steel production is known as hot briquetted iron, which is processed from iron ore. When green hydrogen is used instead of fossil fuel in this process, its by-product is water instead of carbon dioxide, substantially reducing carbon footprint.
³ This section draws significantly from BMWE’s monitoring report, which references numerous scenarios of hydrogen demand to give a very wide range of Germany’s possible hydrogen demand in 2045, highlighting the high uncertainty of adoption across different sectors. The report includes exploratory trend scenarios, which may not achieve climate targets, alongside so-called normative scenarios, which do. The report notes that discrepancies between the two are growing and that this generally indicates a “risk of failing to meet the targets if no [corrective] action is taken”.
⁴ IEEFA estimate based on data from the Fraunhofer Institute, the International Energy Agency and German Environment Agency.
⁵ Grey hydrogen is produced from unabated natural gas.