Historically, value in these markets was derived from energy production at low marginal costs, primarily from coal, lignite, and hydro sources. However, the landscape has shifted. Today, the creation of value hinges on the ability to avert failures during extreme stress events. Assets that maintain frequency stability or mitigate shocks are now recognized for their cross-border benefits, yet market structures still prioritize payments based on energy delivered rather than crises averted.
The economic implications of this misalignment are profound. During winter stress periods, price spikes can reach €300–500/MWh, with isolated areas experiencing costs exceeding €600/MWh. A single week of severe cold can lead to system-wide expenses amounting to hundreds of millions of euros due to emergency imports and balancing interventions. Consequently, assets that can marginally reduce the likelihood or impact of such events provide value far greater than their typical market revenues during stable conditions.
Transmission infrastructure exemplifies this challenge. For instance, a new 400 kV line may require an investment of €300–500 million but only slightly decrease congestion frequency from a national regulator’s viewpoint. However, from a regional trading perspective, this same line could compress peak spreads by €20–40/MWh and lower winter risk premiums significantly, translating to annual savings of €30–70 million in congestion rents. The dispersed nature of these benefits complicates the investment landscape, as investors often see only a fraction of the overall value generated.
Flexibility assets face similar challenges. Grid-scale batteries and pumped hydro systems can prevent extreme pricing fluctuations but are often constrained by domestic market rules that limit their remuneration potential. A 100 MW / 400 MWh battery may derive 50-70% of its annual earnings during fewer than 200 hours each year while remaining idle otherwise. This inconsistency in revenue generation discourages necessary investments in flexibility solutions.
Moreover, the role of synchronous generation and inertia provision exacerbates the existing mismatch. Remaining thermal units contribute significantly to system stability by providing inertia and voltage support but simultaneously diminish their own earnings potential as they stabilize the grid. The paradox lies in the fact that more stable systems yield lower prices for these stabilizing assets.
Quantitative evidence highlights this disparity in balancing costs across various SEE systems, which have surged into the €200–400 million range annually, with winter months accounting for over 50% of total expenditures. Consumers bear much of this cost through tariffs while stability-enhancing assets receive minimal direct compensation.
Cross-border effects further complicate the situation. Investments in stabilizing assets by one system can benefit neighboring markets through reduced volatility and lower prices; however, there is no mechanism to transfer these benefits back to the original investor. This lack of incentive leads to underinvestment in regional public goods and increases the risk of sudden market failures.
The trading environment reflects these structural challenges. Forward curves indicate persistent winter risk premiums despite adequate near-term supply forecasts. The observed peak-to-baseload spreads during winter months range from €40–60/MWh, driven not only by expected scarcity but also by uncertainty surrounding the availability of stabilizing assets when needed.
From an investor’s perspective, this systemic mismatch necessitates higher returns on projects that would otherwise be viable based on system value alone. The result is delayed or scaled-back investments that perpetuate volatility and inflate prices—creating a feedback loop that markets struggle to address independently.
Regulatory responses have not kept pace with these market realities. Capacity mechanisms remain largely national and energy-focused, while ancillary service markets undervalue rapid response capabilities and substitutes for inertia. As SEE markets become increasingly interconnected, these misalignments incur higher costs.
For traders operating within this framework, volatility presents both opportunities and risks. Insufficient stabilizing investments lead to persistent price fluctuations that can benefit those positioned to capitalize on stress events while penalizing others exposed to extreme pricing scenarios. Over time, excessive volatility undermines market confidence and raises hedging costs, ultimately discouraging long-term contracts.
In conclusion, South-East Europe’s power system now predominantly generates value by mitigating tail risks but continues to compensate primarily for average output levels. Addressing this fundamental mismatch through enhanced regional coordination or revised market designs is crucial; otherwise, underinvestment will persist alongside heightened volatility and sporadic crisis management interventions. Understanding these dynamics is essential for stakeholders aiming to navigate the complexities of power trading in this evolving landscape.
