Hydrogen has been positioned across South-East Europe as a bridge between energy security, industrial decarbonisation and European integration. National strategies, pilot projects and policy roadmaps have converged on hydrogen as a future-proof solution for absorbing surplus renewables, decarbonising heavy industry and anchoring new investment cycles. The ownership exit of Russian oil assets and the resulting repricing of gas have undermined the economic assumptions behind parts of those strategies.
Most regional hydrogen plans implicitly relied on a return to stable, moderately priced natural gas. That assumption has weakened as gas pricing has become structurally volatile and more closely linked to global LNG markets. The shift changes hydrogen economics, particularly for blue hydrogen, and requires a reassessment of investment priorities.
Hydrogen assumptions built around pre-crisis gas costs
South-East Europe entered the hydrogen debate later than Western Europe but with strong political enthusiasm. The region’s comparative advantages were described as including existing gas infrastructure, industrial demand concentrated in fertilisers, chemicals and metals, and renewable potential—especially solar and wind. Hydrogen was framed as an extension of existing systems rather than a disruptive alternative.
Blue hydrogen, produced from natural gas with carbon capture, was presented as a transitional pathway. It was expected to deliver 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 production costs were estimated at €1.8–2.2 per kilogram. The models described this level as competitive with grey hydrogen and attractive for industrial users. Those inputs were used to shape project pipelines, feasibility studies and political commitments.
Forward gas prices raise blue hydrogen costs
The post-2022 gas market has not returned to historical equilibrium. Even where headline European prices eased, South-East Europe remained exposed to volatility, transport constraints and risk premiums. Forward price expectations for the late 2020s cluster around €30–45/MWh, with winter stress scenarios pushing significantly higher.
This repricing changes the cost structure for blue hydrogen because feedstock gas accounts for most production costs. At €35–40/MWh, levelised blue hydrogen costs rise to €3.0–3.5 per kilogram. The estimate applies even before incorporating full carbon capture costs and residual emissions penalties.
At those levels, blue hydrogen is described as losing its transitional advantage. It becomes more expensive than many green hydrogen import scenarios projected for the early 2030s and faces difficulty competing with electrification options in several industrial applications.
Financing pressure and stranded asset risk for infrastructure
The shift affects project developers by altering business-model viability under gas volatility. Financing assumptions are described as failing when margins compress, while securing offtake becomes harder without state guarantees. Developers face increased uncertainty over whether projects can be financed on expected terms.
The repricing also changes how investors view hydrogen capital expenditure as potential stranded asset risk. Electrolysers, reformers, carbon capture units and hydrogen-ready pipelines require large upfront investment. In South-East Europe, electrolyser CAPEX is described as ranging from €900 to €1,200 per kilowatt, while blue hydrogen reforming and capture systems add hundreds of millions in project-level costs.
Under stable pricing assumptions, investments could be amortised over long operating lives; under volatile gas pricing, payback periods extend and utilisation risk rises. Projects become more dependent on subsidies, contracts-for-difference or guaranteed offtake at administratively set prices.
Green hydrogen economics tied to power prices
Gas repricing has improved the relative position of green hydrogen in the region’s cost comparisons. While green hydrogen remains capital-intensive, its economics depend primarily on electricity prices and electrolyser costs rather than fuel volatility. As renewable costs fall and power-market integration improves, green hydrogen is described as becoming more predictable.
In South-East Europe, utility-scale renewable electricity can already be generated at €35–45/MWh in favourable locations. At those electricity prices, green hydrogen production costs are estimated at €2.8–3.5 per kilogram, depending on capacity factors and financing conditions. These levels are still above earlier blue-hydrogen assumptions but are described as competitive with repriced blue hydrogen.
The source projections also indicate further cost declines for green hydrogen. 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 constrained by higher delivered prices
Hydrogen demand in fertilisers, steelmaking and chemicals is treated as a cost line rather than an abstract climate objective. Fertiliser producers, steelmakers and chemical plants evaluate hydrogen based on reliability and price. With gas repricing already straining competitiveness, adding higher-cost hydrogen compounds the challenge.
In fertiliser production, feedstock costs dominate the economics described in the source material. A shift from grey to blue hydrogen at €3.0–3.5 per kilogram is stated to raise ammonia production costs by 20–30%. This is described as rendering many SEE plants uncompetitive against imports.
Steel decarbonisation faces similar constraints in the source account because hydrogen-based direct reduction requires price points well below current levels to be viable. Without significant border protection or carbon contracts-for-difference, industrial hydrogen demand in South-East Europe is described as likely to remain marginal throughout the 2020s.
Infrastructure rollout depends on regulatory clarity and demand signals
Hydrogen strategies often assume rapid infrastructure deployment, but the source material highlights that timing matters more than ambition. Pipelines, storage and blending facilities require regulatory clarity, standardisation and scale before they can support demand growth. Gas repricing introduces hesitation that delays investor commitments while they wait for clearer signals on long-term gas and power prices.
This delay creates a sequencing problem: without infrastructure, demand cannot materialise; without demand, infrastructure cannot be financed. In South-East Europe this circular dependency is described as particularly acute due to smaller market size and higher perceived risk.
Budget trade-offs under current cost levels
The source material describes trade-offs when supporting hydrogen under conditions of repriced gas supply costs. Subsidies allocated to hydrogen are not available for grid reinforcement, storage or energy efficiency measures elsewhere in energy-system planning.
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 an industrial programme of 100,000 tonnes per year, that implies annual public support of €100–150 million, characterised as a significant burden for SEE budgets.
Projected divergence by 2030 based on scaling limits
The outlook to 2030 in the source describes a bifurcated path for South-East European hydrogen markets. Blue hydrogen would struggle to scale beyond pilot projects unless gas prices fall structurally or receive heavy state support. Green hydrogen would advance more slowly but on firmer economic ground where linked to export corridors or niche industrial demand.
The source characterises gas repricing as ensuring that hydrogen will not be a cheap substitute for fossil fuels in the near term. Instead it is described as becoming a strategic option requiring targeted deployment to avoid stranded capital risks across infrastructure investments.
Russian energy exit linked to broader market stress
The source links the repricing of gas after the exit of Russian energy influence to a shift in how hydrogen is assessed in economic terms rather than policy framing alone. It describes this change as transforming hydrogen from a political slogan into an economic stress test tied to fuel economics constraints.
The role of hydrogen is described as narrower, more selective and more expensive than early strategies suggested within South-East Europe’s transition plans through sequencing rather than speed.