Hydrogen has been positioned across South-East Europe as a strategic bridge between energy security, industrial decarbonisation and European integration. National strategies, pilot projects and policy roadmaps have converged around hydrogen as a future-proof solution capable of absorbing surplus renewables, decarbonising heavy industry and anchoring new investment cycles. Yet the ownership exit of Russian oil assets and the consequent repricing of gas have quietly undermined the economic foundations on which many of these hydrogen strategies were built. In the new energy landscape, hydrogen in South-East Europe is no longer a question of technological readiness alone; it is a question of fuel economics, capital risk and timing.
At the core of the issue lies a simple but uncomfortable reality. Most hydrogen strategies in the region implicitly assumed a return to stable, moderately priced natural gas. That assumption no longer holds. As gas pricing becomes structurally volatile and increasingly linked to global LNG markets, the economics of hydrogen—particularly blue hydrogen—shift decisively, forcing a reassessment of investment priorities.
The original hydrogen premise in see
South-East Europe entered the hydrogen debate later than Western Europe, but with strong political enthusiasm. The region’s comparative advantages appeared compelling. Gas infrastructure was already in place, industrial demand was concentrated in fertilisers, chemicals and metals, and renewable potential—particularly solar and wind—was significant. Hydrogen was framed as an extension of existing systems rather than a disruptive alternative.
Blue hydrogen, produced from natural gas with carbon capture, emerged as the preferred transitional pathway. It promised lower capital intensity, faster deployment and compatibility with existing gas assets. Pre-crisis cost models assumed natural gas prices of €15–20/MWh, carbon costs below €50 per tonne, and stable long-term contracts. Under those assumptions, blue hydrogen could be produced at €1.8–2.2 per kilogram, competitive with grey hydrogen and attractive for industrial users.
These assumptions shaped project pipelines, feasibility studies and political commitments. What they underestimated was the structural nature of gas repricing after the withdrawal of Russian energy influence.
Gas repricing and the collapse of blue hydrogen economics
The post-2022 gas market has not reverted to its historical equilibrium. Even as headline European prices eased, South-East Europe has remained structurally exposed to volatility, transport constraints and risk premiums. Forward price expectations for the late 2020s now cluster around €30–45/MWh, with winter stress scenarios pushing significantly higher.
This repricing fundamentally alters hydrogen economics. For blue hydrogen, feedstock gas accounts for the majority of production cost. At €35–40/MWh, the levelised cost of blue hydrogen rises sharply to €3.0–3.5 per kilogram, even before accounting for full carbon capture costs and residual emissions penalties.
At these levels, blue hydrogen loses its transitional advantage. It becomes more expensive than many green hydrogen import scenarios projected for the early 2030s and struggles to compete with electrification alternatives in several industrial applications.
For project developers, this shift is not marginal; it is existential. Business models built on thin margins collapse under gas volatility. Financing assumptions fail, and offtake agreements become harder to secure without state guarantees.
Stranded capex risk in hydrogen infrastructure
The repricing of gas transforms hydrogen CAPEX from a growth opportunity into a potential stranded asset risk. Electrolysers, reformers, carbon capture units and hydrogen-ready pipelines require large upfront investment. In South-East Europe, typical electrolyser CAPEX ranges between €900 and €1,200 per kilowatt, while blue hydrogen reforming and capture systems add hundreds of millions in project-level costs.
Under stable pricing assumptions, these investments could be amortised over long operating lives. Under volatile gas pricing, payback periods extend dramatically, and utilisation risk rises. Projects become dependent on subsidies, contracts-for-difference or guaranteed offtake at administratively set prices.
For public budgets, this creates a dilemma. Supporting hydrogen development under these conditions implies long-term fiscal commitments that may outlast the political cycle. Without support, projects stall.
Green hydrogen: Not yet cheap, but increasingly credible
Paradoxically, gas repricing has improved the relative position of green hydrogen. While still capital-intensive, green hydrogen economics are driven primarily by electricity prices and electrolyser costs rather than fuel volatility. As renewable costs continue to fall and power market integration improves, green hydrogen becomes more predictable.
In South-East Europe, utility-scale renewable electricity can already be generated at €35–45/MWh in favourable locations. At these levels, green hydrogen production costs are estimated at €2.8–3.5 per kilogram, depending on capacity factors and financing conditions. While still higher than historical blue hydrogen assumptions, these costs are now competitive with repriced blue hydrogen.
Importantly, green hydrogen costs are expected to decline further. By the early 2030s, green hydrogen delivered into SEE markets from southern Mediterranean or domestic renewable hubs could reach €2.5–3.0 per kilogram, undercutting gas-based alternatives.
Industrial demand under pressure
For industrial consumers, hydrogen was never an abstract climate concept; it was a cost line. Fertiliser producers, steelmakers and chemical plants evaluate hydrogen on the basis of reliability and price. Gas repricing has already strained competitiveness. Adding hydrogen at elevated cost compounds the challenge.
In fertiliser production, feedstock costs dominate. A shift from grey to blue hydrogen at €3.0–3.5 per kilogram raises ammonia production costs by 20–30%, rendering many SEE plants uncompetitive against imports. Steel decarbonisation faces similar constraints, with hydrogen-based direct reduction requiring price points well below current levels to be viable.
Absent significant border protection or carbon contracts-for-difference, industrial hydrogen demand in South-East Europe risks remaining marginal throughout the 2020s.
Infrastructure timing and sequencing
Hydrogen strategies often assume rapid infrastructure deployment. In practice, timing matters more than ambition. Pipelines, storage and blending facilities require regulatory clarity, standardisation and scale. Gas repricing introduces hesitation. Investors delay commitments, waiting for clearer signals on long-term gas and power prices.
This delay creates a sequencing problem. Without infrastructure, hydrogen demand cannot materialise. Without demand, infrastructure cannot be financed. In South-East Europe, this circular dependency is particularly acute due to smaller market size and higher perceived risk.
Fiscal exposure and policy trade-offs
Supporting hydrogen under gas repricing conditions implies trade-offs. Subsidies allocated to hydrogen are not available for grid reinforcement, storage or energy efficiency. Each euro spent on making blue hydrogen viable is a euro not spent on reducing gas exposure directly.
From a fiscal perspective, supporting hydrogen at current cost levels could require operating support of €1.0–1.5 per kilogram for a decade or more. For a modest industrial hydrogen programme of 100,000 tonnes per year, this translates into annual public support of €100–150 million, a significant burden for SEE budgets.
Outlook to 2030
By 2030, hydrogen in South-East Europe is likely to follow a bifurcated path. Blue hydrogen will struggle to scale beyond pilot projects unless gas prices fall structurally or receive heavy state support. Green hydrogen will advance more slowly but on firmer economic ground, particularly where linked to export corridors or niche industrial demand.
Gas repricing ensures that hydrogen will not be a cheap substitute for fossil fuels in the near term. Instead, it becomes a strategic option whose deployment must be carefully targeted to avoid stranded capital.
Hydrogen as a stress test of energy realism
The repricing of gas following the exit of Russian energy influence has transformed hydrogen from a political slogan into an economic stress test. It forces South-East Europe to confront the limits of transition narratives detached from fuel economics.
Hydrogen remains part of the region’s long-term future, but its role will be narrower, more selective and more expensive than early strategies suggested. In this sense, hydrogen mirrors the broader energy transition after Russian exit: ambition constrained by reality, and success dependent on sequencing rather than speed.