Wholesale electricity prices in Hungary, Romania, Bulgaria, Serbia and parts of the Western Balkans entered an unprecedented volatility regime during 2024. Day-ahead prices regularly exceeded €400/MWh, with extreme hours approaching €1,000/MWh. The price formations were not described as isolated anomalies, but as the visible outcome of a structural imbalance building over more than a decade.
Scarcity-driven pricing under seasonal stress conditions
System-level simulations indicate that Southeastern Europe no longer operates as a peripheral extension of the Central European electricity market. Instead, it has evolved into a structurally constrained zone where marginal scarcity pricing dominates when hydrological, thermal, or network stress coincides with seasonal demand peaks. The simulations contrast this with Western or Nordic markets, where redundancy in generation and transmission absorbs shocks. Southeastern Europe is described as having limited buffers on both the supply and network sides.
Generation mix and summer 2024 heatwave constraints
The generation mix is identified as central to the problem across the region. Large parts remain dependent on aging thermal assets, including lignite and coal units approaching the end of their technical lives, alongside hydropower exposed to hydrological volatility. During summer 2024, prolonged heatwaves coincided with weak hydrological inflows, reducing hydro availability at the same time cooling demand increased system loads. Thermal availability was constrained by maintenance backlogs, fuel logistics, and environmental constraints.
Simulations show that small absolute deficits can translate into extreme price outcomes. In Hungary, an incremental shortage of approximately 600 MW during peak hours was sufficient to move prices from already elevated levels into extreme territory. The described sensitivity reflects a system operating at the edge of adequacy. Under these conditions, the loss of a single large unit, reduced imports, or a binding transmission constraint can trigger scarcity pricing across the coupled zone.
Cross-border limits and propagation of scarcity
Import capacity is described as becoming less reliable as a price-stabilising mechanism. Cross-border flows into Southeastern Europe are constrained not only by physical transmission limits but also by simultaneous scarcity in neighbouring markets. During 2024, Central Europe faced tight conditions during several heat-driven demand peaks, reducing export availability into the Southeast when it was most needed. In such conditions, market coupling does not equalise prices downward; scarcity is described as propagating across borders.
Transmission congestion and effective capacity below nominal levels
Network constraints further compound volatility in the region. Although Southeastern Europe is formally integrated into the Single Day-Ahead Coupling framework, effective transmission capacity is described as often falling well below nominal levels. Congestion management practices, security margins and operational limitations regularly reduce available transfer capacity on critical corridors linking Hungary, Romania, Croatia, and the Western Balkans. Even when theoretical capacity exists, non-intuitive flow patterns can occur.
The simulations describe cases where high-price zones export power while neighbouring zones import at extreme prices. This outcome is characterised as counterintuitive but consistent with constrained network optimisation. The effect is linked to how operational constraints shape actual transfer capability during stressed periods.
Capacity additions and limits of generation-only solutions
The analysis states that expanding generation capacity alone does not resolve the issue unless additions are both large and system-relevant. Simulation results indicate that adding 3 GW of new generation capacity at the regional level would not have been sufficient to normalise prices during 2024 stress events. The finding challenges an assumption that incremental renewable additions automatically translate into price relief. In a constrained system, new capacity not deliverable at the right time or location is described as displacing other generation during off-peak hours while leaving scarcity hours largely unchanged.
Solar deployment timing versus evening and late-afternoon spikes
The report highlights implications for solar-heavy deployment strategies in Southeastern Europe. Photovoltaic capacity has grown rapidly, particularly in Romania, Bulgaria, and Serbia. However, summer price spikes occurred during evening and late-afternoon hours when solar output was declining while demand remained elevated. Without firming capacity, storage or demand-side flexibility, additional solar is described as contributing little to alleviating peak scarcity.
The analysis also links this deployment pattern to potential increases in intraday volatility when firming or flexibility resources are not added alongside solar generation. The timing mismatch between output decline and sustained demand is presented as a key factor behind those spike periods.
Bidding behaviour versus lack of marginal capacity under constraints
Market power has been cited as a potential explanation for extreme prices, but quantitative analysis suggests its role is secondary in this setting. When supply bids are capped at levels corresponding to inefficient fossil fuel production costs, peak prices remain extremely high. The analysis indicates that scarcity pricing is not primarily driven by strategic bidding behaviour under these conditions. Instead it points to an absence of sufficient marginal capacity to meet demand when constraints bind.
In such an environment, even perfectly competitive markets are described as clearing at extreme prices due to scarcity conditions rather than bid strategies alone. This framing connects price outcomes directly to adequacy under constrained operation.
Adequacy-focused implications for planning and investment needs
The findings describe implications for investors, system planners and policymakers tied to structural adequacy rather than fuel costs alone. The marginal price is described as no longer set by gas or coal input economics but by the value of lost load implicit in a system operating close to physical limits. The analysis links this shift to consequences for industrial competitiveness, long-term power purchase agreements and bankability of new generation assets.
Industrial consumers across the region are described as adjusting operational strategies in response to price volatility through load shifting, self-generation and behind-the-meter storage. The analysis states that while these responses may be rational at firm level they do little to address system-wide adequacy challenges. It also notes potential impacts on system inertia and predictability if deployed without coordination.
Coordinated investment across generation, transmission and flexibility
The report underscores coordinated investment across three dimensions: generation additions with dispatchable or firmed capability for scarcity hours; transmission investments increasing effective cross-border capacity; and flexibility resources integrating storage and demand response at scale. Transmission focus is described as targeting elimination of structural bottlenecks rather than incremental reinforcements alone. Flexibility integration is presented as necessary to reshape load profiles and reduce peak stress.
Absent coordinated action, Southeastern Europe is described as risking a persistent high-price regime marked by extreme spikes when weather, fuel availability or network conditions deteriorate. In this scenario, price volatility is described as becoming a structural feature rather than a transitional anomaly affecting investment decisions across energy-intensive sectors supporting regional industry.
Role of market coupling in transmitting scarcity signals
The 2024 price events are described as revealing a system design gap rather than a market failure. Market coupling is characterised as efficiently transmitting scarcity signals without creating them. The challenge identified for Southeastern Europe is whether those signals will be met with investment in adequacy, flexibility and network resilience or whether extreme prices will recur during every period of system stress.