As the decade progresses, the electricity systems in South-Eastern Europe (SEE) are poised for significant transformation. This evolution is characterized by increasing integration of renewable energy sources, stringent climate policies, and enhanced regional collaboration. However, the specific trajectory of this transition remains uncertain, with three distinct scenarios emerging based on current trends and policy decisions.
The first scenario envisions an integrated flexibility and managed transition. In this model, SEE countries prioritize grid enhancements, market coupling, and the deployment of flexible energy resources. Cross-border capacity is expected to improve significantly, potentially reaching or surpassing 70% on key interconnectors. The development of intraday and balancing markets will facilitate regional flexibility, while storage capacity is projected to grow to between 5% and 8% of peak demand by 2030. This scenario anticipates that renewable energy will comprise 35% to 45% of annual generation in several markets, with hydropower being utilized as a flexibility resource alongside gas as a balancing agent operating at low load factors.
Price stability is also a hallmark of this scenario, with average wholesale prices likely to align more closely with continental levels, settling in the €60 to €80 per megawatt-hour range under typical conditions. Such a framework would enhance industrial competitiveness and lower investment risk premiums, although it necessitates coordinated political action and institutional maturity.
The second scenario presents a fragmented transition and volatility lock-in. Here, while renewable energy deployment continues, the integration of grids and markets lags significantly. Cross-border capacity remains limited, leading to incomplete market coupling and the proliferation of uncoordinated national capacity mechanisms. As a result, storage solutions and demand response initiatives develop slowly due to insufficient investment signals. In this context, renewable penetration may reach 30% to 40%, but flexibility challenges will become more pronounced.
This scenario foresees heightened price volatility with frequent spikes exceeding €200 to €300 per megawatt-hour during stress events. Average prices could remain structurally elevated above €90 to €100 per megawatt-hour due to congestion and inefficient balancing practices. Consequently, industrial investments may stall amid growing political pressures for price interventions.
The third scenario outlines a security-first retrenchment. In response to rising volatility, governments may prioritize national energy security over broader market integration. This could lead to expanded capacity mechanisms aimed at preserving legacy assets like coal and lignite under sovereignty claims. The growth of renewables may decelerate due to grid limitations and permitting challenges. While prices might stabilize in the short term, they are likely to do so at high levels, necessitating increased public subsidies for state-owned utilities.
This approach risks long-term economic decline as carbon exposure rises and decarbonization targets falter. Over time, such systems may become less competitive and financially burdensome.
The strategic implications of these scenarios underscore that governance—not technology—will dictate the region’s future. All three outcomes are technically feasible; however, only one offers economic efficiency and resilience. The cumulative costs associated with fragmented systems could exceed those of integrated pathways by €20 billion to €30 billion by 2030 due to higher fuel consumption and volatility costs. The security-first model may incur even greater financial burdens over time due to inefficiencies.
Ultimately, South-Eastern Europe’s electricity landscape is not predetermined but will be shaped by critical decisions made in the coming years. The region stands at a crossroads: it can either emerge as a stabilizing corridor between Central Europe and the Mediterranean or remain trapped in cycles of volatility. The choices made now will have lasting impacts visible in electricity bills and investment decisions well into the future.
