Germany’s hydrogen backbone gets approval amid market hesitations and high costs

Germany has approved a continent‑scale hydrogen backbone that, for now, exists largely on paper and in pipes rather than in paying customers. According to Energy News, the Federal Network Agency (Bundesnetzagentur) has authorised a 9,040‑kilometre hydrogen core network with estimated investment of €18.9 billion to be delivered through 2032; roughly 400 kilometres are already operational but industrial customers have signed exactly zero transport contracts. According to the Bundesnetzagentur press release, about 60% of the core grid will be converted from existing natural‑gas pipelines and 40% newly built.

The approval marks an unmistakable bet: create the infrastructure first in the expectation that supply, price declines and demand will follow. Industry participants and network operators are already moving to implement that design. ONTRAS Gastransport GmbH says it will construct roughly 600 kilometres of hydrogen transport lines in eastern and central Germany, and trade body FNB‑Gas describes the approved core network as Europe’s largest hydrogen backbone aimed at linking production, storage and consumption nodes. The European Hydrogen Backbone concept and the “Land of Hydrogen” initiative likewise present the network as essential to making hydrogen available for industry, mobility and energy services.

But the market reality remains stark. Energy News reports that, despite the infrastructure approvals and conversion work , including the Lubmin conversion of the Nord Stream 1 route by Gascade, which the article says cost hundreds of millions , no industrial offtake contracts have been secured. Production economics are the barrier. Management consultant Matthias Deeg is quoted quantifying the gap: green hydrogen production currently costs roughly €5–8 per kilogram, while many energy‑intensive sectors need prices below about €2/kg to compete with fossil fuels. That price differential is already altering investment decisions: ArcelorMittal cancelled planned direct‑reduction plants in Bremen and Eisenhüttenstadt and lignite operator LEAG shelved electrolyser plans, according to the reporting.

Policy responses have therefore sought to de‑risk the infrastructure side rather than wait for market signals. Energy News says the Federal Network Agency has put in place a uniform network charge of €25 per kilowatt‑hour for the ramp‑up phase to stabilise financing for network operators even in the absence of demand. That regulatory approach recognises that conventional market signals alone are unlikely to reconcile the timing mismatch between pipeline readiness and industrial willingness to switch fuels.

Analysts caution the commercial window is long. Research by Deloitte and the Öko‑Institut, cited in the lead coverage, projects green hydrogen reaching price competitiveness only around 2040. That horizon forces a dilemma for industrial asset owners: retrofit new plants now for eventual hydrogen compatibility at added cost, or lock in fossil‑fuel designs that are cheaper today. Extended delivery schedules for parts of the network , OSW notes some sections may slip to 2037 , lengthen the period during which network operators bear stranded‑asset risk while manufacturers defer procurement.

The technical logic behind conversion is sensible: repurposing 60% of existing pipeline corridors lowers capital intensity compared with wholly greenfield builds and leverages sites such as Lubmin where offshore wind cabling, planned electrolysers and import links converge. But conversion accelerates the “chicken‑and‑egg” problem: operators convert and certify assets without secured offtake, on the assumption that visible infrastructure will stimulate corporate procurement. Government and regional politicians frame the issue as one of framework conditions and market‑risk reduction rather than engineering shortfalls; Brandenburg’s Minister of Economic Affairs Daniel Keller, as reported, has urged policies that lower the market risks for buyers and suppliers.

The practical consequences for Europe’s industrial decarbonisation strategy are immediate. If hydrogen prices remain above levels compatible with core industrial margins, announced electrolyser projects and producer capacity will not translate into contracted volumes, delaying domestic demand formation and potentially hollowing out related manufacturing supply chains. Industry watchers warn that prolonged high prices could discourage long‑lead investments in electrolyser manufacturing and hydrogen logistics, even as renewable generation expands.

Germany’s approved network therefore represents a necessary but insufficient condition for a hydrogen economy. The pipes and conversions demonstrate that technical constraints are being resolved; the remaining constraint is economic. Until production costs come down substantially, carbon prices rise decisively, or targeted offtake mechanisms and policy instruments materialise to bridge the gap, the newly authorised hydrogen highway will stand largely as physical proof of intent rather than as the backbone of industrial decarbonisation.