As the energy landscape in South-Eastern Europe (SEE) evolves, the region is poised for significant transformation by 2030. The anticipated changes are driven by an increase in renewable energy sources, stricter climate policies, and enhanced regional cooperation. However, the path to this new energy reality is not straightforward, with three distinct market scenarios emerging based on current trends and policy decisions.
The first scenario, termed “Integrated flexibility and managed transition,” envisions a robust acceleration in grid enhancement and market integration. In this scenario, cross-border capacity utilization is expected to improve significantly, potentially surpassing the 70 percent threshold on critical interconnectors. This would facilitate deeper intraday and balancing markets, enabling a more flexible energy flow across borders. By 2030, storage capacity could account for 5-8 percent of peak demand in the region, while industrial demand response becomes an essential component of the market.
Renewable energy generation is projected to rise steadily, with wind and solar contributing between 35-45 percent of total annual output in various SEE markets. Hydropower will continue to play a vital role, but its management will focus on flexibility rather than just generation. Natural gas will still serve as a backup resource but will operate at minimal load factors due to improved availability mechanisms. While price volatility will remain a factor, it is expected to moderate, with wholesale prices stabilizing between €60-80/MWh under typical conditions.
This scenario emphasizes the necessity of coordinated political action and institutional maturity to achieve lower long-term system costs and enhance resilience within the electricity market.
The second scenario presents a contrasting view: “Fragmented transition and volatility lock-in.” Here, renewable growth continues but is hampered by inadequate grid infrastructure and incomplete market integration. Cross-border capacity remains limited, leading to fragmented national capacity mechanisms that lack coordination. As a result, storage solutions and demand response develop slowly due to insufficient investment signals.
In this environment, renewable penetration may reach 30-40 percent; however, flexibility challenges become more pronounced. Increased reliance on gas imports during peak demand periods becomes necessary as hydropower variability rises alongside declining coal usage. Price volatility intensifies significantly under this scenario, with frequent spikes exceeding €200-300/MWh leading to average prices often hovering around €90-100/MWh due to congestion and inefficient market balancing.
This trajectory represents a path of least resistance but risks entrenching chronic volatility and elevated costs within the regional electricity market.
The third scenario focuses on “Security-first retrenchment,” where government responses to market volatility prioritize national supply security over regional integration efforts. This approach may lead to expanded capacity mechanisms aimed at preserving aging assets like coal and lignite plants under national sovereignty claims. Consequently, renewable energy growth could stall due to grid limitations and regulatory fatigue.
While this strategy might stabilize prices temporarily at high levels through increased public subsidies for state-owned utilities, it raises concerns about carbon exposure and the potential slippage of decarbonization targets. Over time, such an approach may render energy systems less competitive and more financially burdensome.
The strategic implications across these scenarios highlight that governance—not technology—will determine the future landscape of SEE’s electricity markets. The cost disparities among these pathways are substantial; projections indicate that cumulative costs associated with fragmented approaches could exceed integrated strategies by €20-30 billion through 2030 when accounting for increased fuel consumption and subsidy expenditures. The security-first model may incur even greater long-term costs due to inefficiencies.
Ultimately, South-Eastern Europe’s electricity future hinges on critical decisions made in the coming years. The region has the potential to serve as a stabilizing corridor between Central Europe and the Mediterranean or risk becoming an area characterized by persistent volatility. Clarity regarding governance structures will be paramount as stakeholders navigate these complex dynamics leading up to 2030.
