Wholesale electricity prices in Southeastern Europe entered an unprecedented volatility regime during 2024, repeatedly reaching levels that were historically associated only with crisis scenarios. Day-ahead prices across Hungary, Romania, Bulgaria, Serbia, and parts of the Western Balkans regularly exceeded €400/MWh, with extreme hours approaching €1,000/MWh. These price formations were not episodic anomalies but the visible outcome of a deeper structural imbalance that had been building across the regional power system for more than a decade.
The most important insight emerging from system-level simulations is that Southeastern Europe no longer behaves as a peripheral extension of the Central European electricity market. Instead, it has evolved into a structurally constrained zone where marginal scarcity pricing dominates price formation whenever hydrological, thermal, or network stress coincides with seasonal demand peaks. Unlike Western or Nordic markets, where redundancy in generation and transmission absorbs shocks, Southeastern Europe operates with limited buffers on both the supply and network sides.
At the core of the problem lies the region’s generation mix. Large parts of Southeastern Europe remain heavily dependent on aging thermal assets, lignite and coal units approaching the end of their technical lives, and hydropower systems that are increasingly exposed to hydrological volatility. During the summer of 2024, prolonged heatwaves coincided with weak hydrological inflows, reducing hydro availability precisely when cooling demand pushed system loads upward. Thermal availability was constrained by maintenance backlogs, fuel logistics, and increasingly binding environmental constraints, leaving system operators with a narrow dispatch margin.
Simulations indicate that even relatively small absolute deficits translate into extreme price outcomes. In the Hungarian system alone, an incremental shortage of approximately 600 MW during peak hours was sufficient to push prices from already elevated levels into extreme territory. This sensitivity reflects a system that is effectively operating at the edge of adequacy, where the loss of a single large unit, a reduction in imports, or a binding transmission constraint can trigger scarcity pricing across the entire coupled zone.
Import capacity, traditionally viewed as a safety valve for the region, has become increasingly unreliable 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 itself experienced tight conditions during several heat-driven demand peaks, reducing export availability into the Southeast precisely when it was most needed. In such conditions, market coupling does not equalise prices downward; instead, scarcity propagates across borders, amplifying volatility.
Network constraints further compound these dynamics. While the region is formally integrated into the Single Day-Ahead Coupling framework, effective transmission capacity often falls well below nominal levels. Congestion management practices, security margins, and operational limitations regularly reduce available transfer capacity, particularly on critical corridors linking Hungary, Romania, Croatia, and the Western Balkans. Even when theoretical capacity exists, non-intuitive flow patterns can emerge, resulting in situations where high-price zones export power while neighbouring zones import at extreme prices, a phenomenon that appears counterintuitive but is entirely consistent with constrained network optimisation.
Crucially, expanding generation capacity alone does not resolve the problem unless additions are both large and system-relevant. Simulation results show that even the addition of 3 GW of new generation capacity at the regional level would not have been sufficient to normalise prices during the 2024 stress events. This finding challenges a common policy assumption that incremental renewable additions automatically translate into price relief. In a constrained system, new capacity that is not deliverable at the right time or location simply displaces other generation during off-peak hours while leaving scarcity hours largely untouched.
This is particularly relevant for solar-heavy deployment strategies. Southeastern Europe has seen rapid growth in photovoltaic capacity, especially in Romania, Bulgaria, and Serbia, yet summer price spikes occurred precisely during evening and late-afternoon hours when solar output was declining but demand remained elevated. Without firming capacity, storage, or demand-side flexibility, additional solar capacity contributes little to alleviating peak scarcity and may even increase intraday volatility.
Market power has frequently been cited as a potential explanation for extreme prices, yet quantitative analysis suggests its role is secondary. When supply bids are capped at levels corresponding to inefficient fossil fuel production costs, peak prices remain extremely high. This indicates that scarcity pricing is not primarily driven by strategic bidding behaviour but by the absence of sufficient marginal capacity to meet demand under constrained conditions. In such an environment, even perfectly competitive markets would clear at extreme prices.
The implications for investors, system planners, and policymakers are profound. Southeastern Europe is entering a phase where electricity prices are increasingly determined by structural adequacy rather than fuel costs alone. The marginal price is no longer set by gas or coal input economics but by the value of lost load implicit in a system operating close to its physical limits. This has material consequences for industrial competitiveness, long-term power purchase agreements, and the bankability of new generation assets.
Industrial consumers across the region have already begun adjusting operational strategies in response to price volatility, including load shifting, self-generation, and behind-the-meter storage. However, these responses, while rational at the firm level, do little to resolve system-wide adequacy challenges and may even reduce system inertia and predictability if deployed in an uncoordinated manner.
From an infrastructure perspective, the findings underscore the necessity of coordinated investment across three dimensions simultaneously. Generation additions must include dispatchable or firmed capacity capable of responding during scarcity hours. Transmission investments must increase effective, not just nominal, cross-border capacity, with a focus on eliminating structural bottlenecks rather than incremental reinforcements. Flexibility resources, including storage and demand response, must be integrated at scale to reshape load profiles and reduce peak stress.
Absent such coordinated action, Southeastern Europe risks locking itself into a persistent high-price regime, punctuated by extreme spikes whenever weather, fuel availability, or network conditions deteriorate. In such a scenario, price volatility becomes a structural feature rather than a transitional anomaly, reshaping investment decisions across the energy-intensive sectors that underpin the region’s industrial base.
What the 2024 price events ultimately revealed is not a market failure but a system design gap. Market coupling efficiently transmitted scarcity signals; it did not create them. The challenge now facing Southeastern Europe is whether those signals will be met with commensurate investment in adequacy, flexibility, and network resilience, or whether extreme prices will become the new normal during every period of system stress.
