Key findings

Germany’s hydrogen demand is likely to fall at or below the lower end of official projections, as direct electrification provides a more cost-competitive decarbonisation pathway for heating, transport, and power. The current financing model for the hydrogen core network shifts costs onto taxpayers as uptake falls short, creating pressure on policymakers to sustain pipeline utilisation rather than resizing the network to match demand. Failure to meet optimistic hydrogen demand projections could require around €45 billion in additional public funding, which equates to roughly €1,000 per German taxpayer. Prioritising imports of hydrogen derivatives for hard-to-electrify sectors can reduce infrastructure needs, lower system costs, and protect long-term industrial competitiveness.

Germany’s hydrogen strategy — a reset in progress

Germany possesses the largest and most ambitious national hydrogen strategy in Europe, aiming for 10 gigawatts (GW) of domestic electrolyser capacity and 95–130 terawatt-hours (TWh) of annual demand by 2030. However, implementation has slowed, and the strategy has shifted from a supply-push to a more cautious demand-pull approach. Current project pipelines suggest the 10GW target is hardly achievable, with only around 1.2–1.3GW of projects having reached a final investment decision stage by 2025. Developers face constraints including high project costs, strict EU definitions for green hydrogen, and a lack of long-term offtake agreements.

Demand projections: Outdated, oversized and uncertain

Analysing potential demand across sectors suggests that official government forecasts are overoptimistic. Hydrogen is no longer expected to play a significant role in transport or buildings, where electric vehicles and heat pumps have demonstrated superior efficiency and falling costs. IEEFA estimates that Germany’s 2045 hydrogen demand is likely to sit at the bottom of official normative ranges (163–605 TWh) or near the midpoint of exploratory scenarios (71–262 TWh). Industrial applications in chemicals and steel remain the primary potential users, but even here, demand projections may be overstated if the country shifts towards importing green hydrogen derivatives rather than producing them domestically.

Hydrogen cost projections

Green hydrogen production costs have failed to decline as projected. Current domestic production in Germany costs approximately €7.30/kg, and while this is projected to fall to around €6/kg by 2030, it is unlikely to reach parity with the current cost of hydrogen produced using fossil fuels. Blue hydrogen, at roughly €4/kg, appears more affordable on paper but remains structurally dependent on volatile gas markets, carbon capture performance, and future carbon pricing. Shipped imports from countries such as Australia or Canada are expected to be more expensive due to conversion and transport losses, whereas pipeline imports from Morocco or Spain may offer cheaper alternatives by 2030.

The fiscal wager behind Germany’s hydrogen-led transition

The financing model for the hydrogen core network assumes near-full utilisation by 2040, using a regulated cost-recovery model. To keep early fees marketable, they are capped at €25 per kilowatt of booked capacity, with shortfalls deferred into a state-backed credit facility known as the amortisation account. If hydrogen demand grows quickly, costs are recovered from users; however, if uptake remains weak, the burden shifts to the public. If the account is not settled by 2055, the state is legally obligated to cover at least 76% of any outstanding balance. Under a plausible limited-demand scenario, unrecovered costs falling to the state could amount to €34.7 billion.

A cautionary fiscal tale: LNG and Deutsche Energy Terminal

Germany’s recent expansion of liquefied natural gas (LNG) infrastructure provides a concrete illustration of these risks. Despite rapid commissioning, LNG terminal utilisation remained structurally weak, averaging just 36.3% in 2025. The state-owned operator, Deutsche Energy Terminal (DET), is backed by up to €4.1 billion in state guarantees to absorb losses. Independent analysis suggests total public exposure could reach €17 billion once extended contracts and compensation mechanisms are fully accounted for, highlighting how contingent liabilities can migrate to the public balance sheet when infrastructure is built ahead of demand.

How a “€19.8 billion” hydrogen network costs over €50 billion

Public debate often understates the true cost of the hydrogen core network by focusing on the €19.8 billion construction estimate. Regulatory modelling shows the full regulated cost base actually approaches €50 billion when including decades of interest, administrative costs, unrecovered book values on repurposed lines, and ongoing operating expenditure. Recent reports from network operators suggest procurement overspends and project revisions will add at least a further €5 billion to the final bill, with only 4% of the pipeline currently completed.

Policy creep: Defending the hydrogen bet

As green hydrogen costs remain high, policymakers are entering a phase of “policy creep,” where policy is expanded primarily to protect infrastructure commitments made under optimistic assumptions. This includes the Hydrogen Acceleration Act of 2026, which designates blue hydrogen as being in the “overriding public interest.” This shift risks layering a second expensive infrastructure system for carbon dioxide transport on top of the hydrogen backbone, potentially locking in gas dependency and requiring open-ended demand subsidies to keep the network operational.

Recommendations

IEEFA recommends that Germany ensure the amortisation account does not dictate demand policy; any new demand-side support should require independent assessment of its decarbonisation value. Pipeline expansion should be gated to verified industrial offtake and supply commitments rather than speculative volumes. The regulator should publish a transparent 2055 repayment path and trigger automatic policy reviews if utilisation falls below defined thresholds. Furthermore, hydrogen deployment should be coordinated with the run-off of LNG guarantees to avoid simultaneously underwriting two infrastructure systems. Finally, the government should prioritise the development of import corridors for derivatives like ammonia or methanol, which can use existing port infrastructure and bypass the costly pipeline network.