The evolving dynamics of South-East Europe’s power markets reveal a significant disconnect between the creation of system value and the mechanisms for capturing revenue. As the region’s energy landscape becomes increasingly interdependent, the challenge lies in aligning market remuneration with the benefits derived from assets that enhance grid stability and mitigate volatility. Current market structures tend to focus on national frameworks that are energy-centric and historically oriented, failing to adequately reward investments that contribute to long-term system resilience.
Historically, value in these markets was primarily associated with the production of energy at low marginal costs, particularly from coal, lignite, and hydroelectric sources. However, today’s power systems require a shift in perspective; value is now generated through the prevention of failures during critical stress events. This involves maintaining frequency stability and managing shocks effectively, which provides cross-border advantages yet remains inadequately compensated under existing remuneration frameworks.
The economic implications of this misalignment are substantial. For instance, during winter stress events, price spikes can reach between €300 and €600 per megawatt-hour (MWh), leading to widespread costs amounting to hundreds of millions of euros due to emergency imports and operational curtailments. The assets that can reduce these risks—by even a small margin—are delivering value that far surpasses their typical market revenues under normal conditions.
Transmission infrastructure exemplifies this issue vividly. A new 400 kV line may cost between €300 million and €500 million but only slightly reduce congestion frequency from a national regulator’s viewpoint. Conversely, from a regional trading perspective, this same investment can yield benefits such as compressing peak spreads by €20 to €40/MWh and generating annual congestion rents of €30 million to €70 million on impacted corridors. The disparity in perceived value highlights how investors often capture only a fraction of the benefits their projects provide across broader markets.
Flexibility resources like grid-scale batteries face similar challenges. These assets can prevent extreme balancing prices but often operate under domestic rules that cap their remuneration. A 100 MW/400 MWh battery might realize 50% to 70% of its annual earnings before interest, taxes, depreciation, and amortization (EBITDA) within just 200 hours each year while remaining inactive otherwise. This inconsistency in revenue discourages necessary investments in flexibility solutions where they are most needed.
The provision of synchronous generation also contributes to this mismatch as thermal units remain critical for inertia and voltage support. While their operations help stabilize the grid—reducing balancing activation volumes—their own revenue potential diminishes as system stability increases. This creates an inherent contradiction where stabilizing assets earn less in a more reliable environment.
Quantitative assessments reveal that annual balancing costs across several South-East European systems have surged into the range of €200 million to €400 million, with winter months accounting for over half of total expenditures. Consumers predominantly shoulder these costs through tariffs while assets that alleviate balancing requirements receive minimal direct compensation, indicating a systemic preference for instability over stability.
Cross-border investments further complicate this landscape; when one market invests in stabilizing measures such as grid enhancements or flexible operations, neighboring markets benefit from reduced volatility without compensating the originating investors adequately. Over time, this leads to underinvestment in essential regional public goods and escalates risks associated with abrupt market failures.
Current trading patterns reflect these underlying tensions. Forward curves consistently embed winter risk premiums despite adequate near-term supply levels. The observed peak-to-baseload spreads of €40 to €60/MWh during winter highlight not only anticipated scarcity but also uncertainty regarding the availability of stabilizing resources when required.
From an investment perspective, this structural mismatch necessitates higher expected returns due to increased risk perceptions. Projects that would otherwise be viable based on system value alone struggle against stringent merchant revenue benchmarks, leading to delays or reductions in investment activities—a cycle that perpetuates volatility within the market.
Policy responses have not kept pace with these evolving realities. Existing capacity mechanisms often remain narrowly focused on national objectives without addressing regional interdependencies adequately. Ancillary service markets undervalue rapid response capabilities while congestion income allocation fails to reflect the distribution of benefits across interconnected systems.
For traders operating within this environment, understanding these dynamics translates into both opportunities and risks as persistent volatility remains unaddressed due to insufficient stabilizing investments. While some players may profit from stress events, others face exposure to extreme pricing fluctuations—a scenario that ultimately undermines market confidence and discourages long-term contracting efforts.
In summary, South-East Europe’s power sector is at a crossroads; it must evolve its remuneration frameworks to acknowledge and distribute the value derived from stability or risk enduring heightened volatility characterized by sharp price spikes and reactive crisis interventions. Addressing this mismatch is crucial for fostering a resilient energy market capable of meeting both current demands and future challenges effectively.
