The power markets in Southeast Europe (SEE) are undergoing significant changes as the traditional dynamics of energy supply and demand shift. The decline in system inertia, primarily due to the retirement of synchronous coal and lignite units, is driving a repricing of balancing risks and intraday market options. This transition highlights the increasing importance of rapid-response capabilities in maintaining market stability and managing price volatility.
Inertia plays a critical role in stabilizing frequency fluctuations within the power grid. Historically, large synchronous generators provided essential resistance to frequency deviations, allowing time for backup reserves to engage. However, the reduction of synchronous inertia by approximately 25–35% over the past decade—especially pronounced in Romania and Bulgaria—has led to faster frequency excursions following disturbances. Consequently, system operators are compelled to procure more frequent and immediate balancing actions to address these challenges.
The impact on market pricing is evident, particularly in balancing prices. Previously, winter balancing prices typically ranged from €60–120/MWh. However, during peak stress periods, these prices have surged to €250–400/MWh, with extreme spikes exceeding €500/MWh. These price increases are not merely a reflection of fuel costs but rather indicative of the scarcity of fast-ramping resources and inertia-like services. As the availability of synchronous generation diminishes, the marginal balancing units have shifted towards higher-priced alternatives such as batteries and emergency imports.
Intraday markets are also adjusting to this evolving landscape. Forecast errors that were once manageable through inertia now result in immediate price adjustments. During high-demand winter periods, intraday spreads between day-ahead and within-day products can widen significantly, often reaching €40–80/MWh, and sometimes exceeding €100/MWh under corridor constraints. This trend reflects a growing reluctance among traders to commit to positions before resolving inertia-related uncertainties.
The correlation between declining inertia and increased price volatility is becoming more pronounced. Data indicates that days characterized by high renewable energy penetration and low synchronous capacity experience intraday price variances that are 2–3 times greater than similar demand days five years prior. This asymmetric variance poses challenges for traders who must navigate limited downside risks while facing potential upward price pressures due to scarcity of responsive resources.
As balancing procurement volumes rise alongside prices, system operators across SEE have increased their activation of secondary and tertiary reserves by an estimated 30–40% compared to pre-coal-exit levels. This escalation has significant cost implications, with annual balancing expenses now reaching hundreds of millions of euros across several systems, particularly during winter months when demand peaks.
The decline in inertia is also reshaping asset values within the market. Fast-response technologies like batteries are capturing a larger share of balancing revenues despite their lower energy throughput. A battery system with 50–100 MW capacity can generate most of its annual revenue during just 200–300 hours coinciding with low-inertia events. Current capital expenditure levels for such assets stand at around €500–700 thousand per MWh, indicating a reliance on high scarcity pricing rather than utilization rates.
Hydropower assets capable of rapid response are similarly experiencing repricing benefits. Units that can deliver 100–200 MW within minutes command premium prices during periods of high demand, even if their overall generation remains stable. Conversely, slower-ramping thermal units are losing value as they contribute less effectively to system responsiveness.
The presence of transmission constraints further exacerbates these dynamics. When cross-border balancing options are limited, domestic systems must rely on local resources, resulting in sharp spikes in balancing prices. Traders exposed to imbalance charges face nonlinear losses that drive up risk premiums in forward peak products. Currently, the spread between peak and baseload pricing during winter quarters often reaches €40–50/MWh, reflecting both demand and inertia risks.
The economic transition away from coal units introduces additional complexities into the market framework. As these units retire for economic reasons rather than technical ones, the exit of inertia occurs more rapidly than the commissioning of replacement flexibility solutions. This timing risk is evident in forward market curves extending beyond Y+2, which show widening uncertainty bands regarding the pace at which inertia-like services will be replaced by emerging technologies such as storage solutions or synchronous condensers.
The strategic implications for market participants are profound. Balancing and intraday markets have evolved into central mechanisms for value creation and risk management rather than residual functions. Static hedging strategies that overlook real-time response constraints may underperform significantly. Successful trading desks now integrate factors such as weather correlations, synchronous capacity availability, and corridor access into their intraday positioning strategies.
The message for investors is equally clear: assets that enhance frequency stability—such as batteries and pumped hydro upgrades—are essential components for modern power systems. Their deployment will help mitigate volatility and reduce overall balancing costs; however, until these technologies are implemented at scale, markets will continue to incur premiums for responsive capacity. In Southeast Europe, the ongoing decline in inertia has already been reflected in market prices, raising questions about how long this window of scarcity will persist before structural solutions catch up.
