Rethinking Germany's hydrogen-led transition

Germany faces a uniquely challenging net-zero balancing act. Unlike peers with smaller industrial footprints, Germany must not only meet legally binding climate targets and rebuild energy security, but also preserve energy-intensive manufacturing and export competitiveness. The central challenge is therefore how to decarbonise without hollowing out the industrial base that underpins its economic model.

Green hydrogen, produced from renewable energy, has been presented as a bridge between these objectives. It promises deep emissions reductions in sectors such as steel and chemicals while preserving industrial production that cannot easily electrify. At the same time, the German government expects that hydrogen produced domestically or imported from a diverse group of international partners will strengthen energy security in the wake of Russia’s full-scale invasion of Ukraine.

The logic is compelling, but delivering hydrogen at scale requires costly infrastructure be built ahead of confirmed demand. The centrepiece of the infrastructure buildout is Germany’s hydrogen core network, a pipeline system connecting demand centres with domestic production and import terminals. Public debate often describes this as a €19.8 billion construction project, yet the true cost is substantially higher. Regulatory modelling suggests the total commitment optimistically approaches €50 billion, once financing, repurposed assets and maintenance are included. Recent reports suggest this figure already needs revising upwards. With just 4% of the pipeline completed, network operators project that procurement overspends will add at least €5 billion to the final bill.

The scale of that commitment would be manageable if hydrogen were on a credible path to economic competitiveness. Demand would follow organically, the pipeline would fill, transport fees would recover costs, and public backstops would remain theoretical. But green hydrogen remains persistently expensive — a fact that is increasingly recognised. Less well understood is the true cost of the infrastructure required to deliver it, and who will ultimately foot the bill. To answer that, we must examine the financial architecture.

A state-backed credit facility known as the amortisation account supports the hydrogen core network. The facility absorbs early revenue shortfalls with the expectation that balances will be repaid over time through transport fees. If hydrogen demand grows as regulators plan, costs can be gradually recovered from network users. If uptake remains weak, paying the accumulated credit balance falls on public backstops, transferring the burden onto taxpayers. The state is legally obligated to cover at least 76% of any unrecovered balance by 2055. Who pays for the pipeline therefore depends on a single variable: utilisation.

In practice, this means whether Germany’s hydrogen demand meets optimistic targets. Pipeline financing is calibrated for hydrogen achieving system-wide relevance by 2040. This would require hydrogen penetrate district heating, baseload power generation, low-temperature industrial processes and potentially even large parts of the transport sector. In each of these areas, electrification and established technologies already offer more cost-effective decarbonisation pathways. IEEFA's sectoral analysis of Germany's hydrogen demand outlook suggests the true picture is far more constrained than official projections acknowledge. Setting aside transport, heating and most power generation as unsuitable, demand in 2045 is much more likely to fall at or below the very bottom of official scenario ranges. 

Early market developments point in the same direction, suggesting hydrogen is unlikely to achieve universal relevance. Germany's 2030 target of 10 gigawatts of domestic electrolyser capacity looks distant, with only around an eighth of that having reached final investment decision. Sections of pipeline built so far also sit largely unused, with no customers connected and no supply contracted.

The fiscal implications are jarring. Across the expenditure channels this report examines, the difference between a rapid and limited hydrogen rollout conservatively amounts to €45 billion in additional public funding requirements, or €1,000 per German taxpayer, driven primarily by €34.7 billion in unrecovered pipeline costs. The remainder reflects support for hydrogen-ready power plants and extended reliance on liquefied natural gas infrastructure as an insurance mechanism.

The greater fiscal risk is arguably not stranded infrastructure, but infrastructure that works just well enough to lock in economy-wide, open-ended demand subsidies. 

Yet a potentially greater long-term risk to public finances exists. As the cost realities of green hydrogen come into focus, blue hydrogen is quietly being positioned as a fallback. Produced from methane with carbon capture, it appears cheaper on paper, ostensibly offering policymakers a way to sustain demand and protect network utilisation. In practice, however, blue hydrogen would layer a second infrastructure bet on top of the first while re-anchoring hydrogen production in the same volatile gas markets Germany seeks to move away from. 

Blue hydrogen also remains structurally more expensive than direct electrification and struggles to compete with incumbent fossil fuels absent prolonged policy support. If switching to blue still fails to close the competitiveness gap, policymakers must then choose between accepting dual stranded infrastructures and intervening to sustain demand. The former would be a large but finite fiscal shock, the latter a slower but indefinite drain on public finances. 

The greater fiscal risk is arguably not stranded infrastructure, but infrastructure that works just well enough to lock in economy-wide, open-ended demand subsidies — tying public finances to the uncertain path of hydrogen prices.