By the end of this decade, South-Eastern Europe’s electricity systems will look fundamentally different from today. The direction of change is not in doubt: higher renewable penetration, tighter climate constraints, deeper regional integration. What remains uncertain is the pathway. The region stands at a fork between three plausible market trajectories, each defined not by technology alone, but by policy coordination, grid investment, and institutional choices.
These scenarios are not forecasts. They are structured outcomes based on current trends and decisions already underway.
Scenario one: Integrated flexibility and managed transition
In this scenario, SEE accelerates grid reinforcement, market coupling, and flexibility deployment. Cross-border capacity availability improves materially, approaching or exceeding the 70 percent benchmark on key interconnectors. Intraday and balancing markets deepen, allowing flexibility to flow regionally. Storage capacity expands rapidly, reaching 5–8 percent of peak demand by 2030 across the region, while industrial demand response becomes commercially significant.
Renewables grow steadily, with wind and solar reaching 35–45 percent of annual generation in several SEE markets. Hydropower remains central but is managed explicitly as a flexibility resource. Gas capacity is retained as a balancing backbone but operates at very low load factors, compensated through well-designed availability mechanisms.
Price volatility persists but is moderated. Extreme spikes become rarer, and average wholesale prices converge toward continental levels, clustering in the €60–80/MWh range under normal conditions. Industrial competitiveness improves, and investment risk premiums decline.
This scenario requires coordinated action and political trust. It delivers the lowest long-term system cost and the highest resilience, but it demands institutional maturity.
Scenario two: Fragmented transition and volatility lock-in
In this trajectory, renewable deployment continues, but grid and market integration lag. Cross-border capacity remains constrained, market coupling is incomplete, and national capacity mechanisms proliferate without coordination. Storage and demand response scale slowly due to weak investment signals.
Renewables reach 30–40 percent penetration, but flexibility gaps widen. Hydropower variability and declining coal utilisation increase reliance on gas and imports during stress events. Price volatility intensifies, with frequent spikes above €200–300/MWh and occasional extreme events.
Average prices remain structurally high, often exceeding €90–100/MWh, reflecting congestion, risk premiums, and inefficient balancing. Industrial investment hesitates, and political pressure for price intervention grows.
This scenario is the path of least resistance. It avoids hard coordination decisions but locks the region into chronic volatility and higher costs.
Scenario three: Security-first retrenchment
In this scenario, volatility triggers a political backlash. Governments prioritise national security of supply over market integration. Capacity mechanisms are expanded to preserve legacy assets, particularly coal and lignite, under the banner of sovereignty. Renewable growth slows due to grid constraints and permitting fatigue.
Prices stabilise in the short term but at a high level. Public subsidies rise to support state-owned utilities and maintain employment. Carbon exposure increases, and decarbonisation targets slip. Over time, systems become less competitive and more fiscally burdensome.
This scenario offers short-term political comfort at the cost of long-term economic decline and isolation from European market evolution.
Strategic implications
The difference between these scenarios is not technology. It is governance. All three futures are technically feasible. Only one is economically efficient and resilient.
Quantitatively, the cost gap between scenarios is large. Over the period to 2030, cumulative system costs under the fragmented scenario could exceed the integrated pathway by €20–30 billion across SEE, once higher fuel burn, volatility, and subsidy costs are included. The security-first path would cost even more over time due to inefficiency and stranded assets.
The integrated flexibility scenario requires upfront investment but delivers compounding benefits. Reduced volatility lowers financing costs, improved price convergence attracts industry, and regional optimisation reduces redundancy.
South-Eastern Europe’s electricity future is therefore not predetermined. It will be shaped by decisions made in the next three to five years. The region can become a stabilising corridor between Central Europe and the Mediterranean, or a persistent volatility zone.
The physics of the system are clear. The economics are increasingly quantified. What remains uncertain is political alignment. By 2030, that uncertainty will have resolved into one of these trajectories. The cost of choosing poorly will be visible on every electricity bill and in every deferred investment decision.
By virtu.energy
