When Statkraft announced the abrupt termination of its 40 MW Mo i Rana electrolyser order with Nel ASA, it underscored a stark truth: even within a hydropower-rich nation, green hydrogen projects are buckling under today’s economic headwinds. Once billed as a poster child for decarbonising heavy industry, the €35 million‐plus Mo i Rana facility was designed to leverage Norway’s abundant renewable electricity to produce clean hydrogen for nearby steel and chemical plants. Yet Statkraft’s leadership concluded that no commercially viable model could be built in the current landscape of high capital costs, volatile power prices, and rising interest rates.
From the outset, Mo i Rana faced the familiar hydrogen-sector dilemma of long project gestation and uncertain offtake. Nel, the century-old electrolyser pioneer, saw NOK 120 million evaporate from its order backlog overnight, contributing to a 44 percent year-on-year plunge in quarterly revenue and a swing into deep net losses. Its alkaline electrolyser division revenues fell by nearly 70 percent as flagship orders were deferred or cancelled. In response, Nel has idled production lines and slashed operating expenses, while analysts have trimmed price targets to unprecedented lows. Such retrenchment signals that core equipment suppliers are no longer insulated from market retrenchment—they are at its epicenter.
Statkraft’s withdrawal follows a growing pattern of gigawatt-scale hydrogen hubs being downsized or abandoned. Across Europe, only one in five announced projects is expected to reach a final investment decision by 2030. Over 29 GW of capacity—equivalent to some 750 electrolysers the size of Mo i Rana—has already been stalled or scrapped. The root causes converge on three critical barriers: absent firm offtake contracts, underdeveloped transport infrastructure, and the compound effect of higher financing costs.
First, without long-term hydrogen purchase agreements, project finance simply will not stack up. Electrolysers require continuous, off-peak renewable power to approach the sub-€3/kg production costs needed for competitiveness against grey hydrogen or direct electrification. Yet wholesale electricity prices in the Nordics and neighbouring markets have oscillated between €30 and €80/MWh over the past two years, making yield projections precarious. In contrast, one industry study found that a two-percentage-point rise in interest rates can inflate the levelised cost of energy by nearly 20 percent, precisely the dynamic at play as central banks grapple with inflation.
Second, the absence of a dedicated hydrogen network adds both capital and operational drag. Norway’s pipeline system, optimised for natural gas, cannot carry high-purity hydrogen without costly retrofits. Storage facilities for seasonal or grid-balancing buffers are virtually non-existent, forcing producers to either build standalone buffer tanks or rely on expensive ammonia conversion and marine export routes—options that drive per-kilogram costs higher still. Remote projects like Mo i Rana, hence, face double penalties: a lack of nearby industrial demand and steep logistics bills to ship product elsewhere.
Third, the financing environment has hardened dramatically since Europe’s early hydrogen hype cycle. In the wake of post-pandemic supply-chain snarls and geopolitical shocks, developers now confront equipment inflation of up to 25 percent on stainless-steel and rare-earth inputs. Banks and institutional investors, once eager to back flagship green projects, have pulled back in the absence of robust policy guarantees. Even in the U.S., where the Inflation Reduction Act offers generous tax credits for hydrogen producers, analysts warn that demand is unlikely to materialise at scale without parallel mandates or purchase-price support.
Norwegian policymakers are responding in kind. The latest industrial white paper bars hydrogen from its previous “mission‐critical” status, recasting it as one option within a diversified low-carbon portfolio. Several high-profile schemes have quietly fizzled: Shell’s Aukra blue-hydrogen plan was shelved when anchor customers failed to emerge, and concept studies for distributed hydrogen hubs in Hellesylt and Hammerfest never progressed beyond front-end engineering. Even Statkraft, flush with government backing, is pivoting toward smaller, integrated applications—such as hydrogen blending at existing gas turbines—rather than standalone gigaprojects.
Across the EU, officials still champion hydrogen’s potential to decarbonise steel, chemicals, and long-haul transport. Yet regulatory ambiguity around what qualifies as “green” hydrogen, coupled with delayed implementation of certification and tracking schemes, has sapped private-sector confidence. Proposed instruments like contracts-for-difference and hydrogen blending mandates remain mired in political negotiation, leaving would-be developers in limbo.
Statkraft’s volte-face serves as a cautionary tale: grand targets alone will not vault hydrogen from niche pilot to mainstream workhorse. Instead, the sector needs a more coordinated architecture of guaranteed offtake, concentrated “hydrogen valleys” co-locating production and industrial demand, and tailored financing vehicles to absorb technology and market risk. Absent these structural remedies, the hydrogen bubble may well burst, leaving policymakers to contend with the fallout of unfulfilled ambitions—and stranded assets—in a cleaner energy future that many still hope to realise.
