The evolution of the electricity market in Southeast Europe (SEE) presents a complex landscape where renewable energy is increasingly significant, yet thermal generation remains the primary driver of pricing. As of early April 2026, renewable sources, particularly hydro, solar, and wind, contribute nearly 45% of total output during peak demand periods. Despite this growing share, it is the thermal plants—primarily coal and gas—that continue to establish the marginal prices during most trading hours.
Recent data highlights this trend: day-ahead electricity prices across key markets in SEE fluctuated between €84 and €91/MWh. Specific market prices included Hungary (HUPX) at €91.29/MWh, Serbia (SEEPEX) at €90.42/MWh, Romania (OPCOM) at €87.93/MWh, and Bulgaria (IBEX) at €84.58/MWh. These prices predominantly reflect the operational costs associated with thermal generation rather than the near-zero marginal costs of renewables.
The reliance on thermal generation for price setting stems from inherent characteristics of renewable energy sources. For instance, solar power capacity has surpassed 3.9 GW, but its availability is limited to daylight hours, while wind generation contributes around 1.9 GW and exhibits variability that often misaligns with peak demand periods. Hydropower, although flexible, faces constraints related to reservoir management and environmental conditions. Consequently, these limitations necessitate a continued dependency on dispatchable thermal units for balancing supply and demand.
On days of observed pricing dynamics, coal generation was recorded at approximately 4,843 MW, complemented by gas plants contributing around 2,502 MW. Together, these thermal units accounted for over a quarter of total electricity production and were pivotal in determining market clearing prices during tight supply scenarios.
The economic framework surrounding thermal power generation significantly influences overall electricity pricing. Gas-fired plants illustrate this interplay through their operational efficiency and fuel cost dynamics; current gas benchmarks hover around €52/MWh. With typical efficiencies ranging from 50% to 55%, the effective fuel cost for gas-based electricity production falls between €95 and €105/MWh, excluding carbon costs. When factoring in CO₂ pricing—around €70–75 per tonne, equating to an additional €25–35/MWh—the marginal cost for gas-fired generation can escalate to between €120 and €140/MWh.
This theoretical cost structure often contrasts with actual market prices due to several factors: not all gas units operate at full marginal cost due to fixed long-term contracts or variations in efficiency; coal plants may provide cheaper marginal supply depending on current coal prices; and renewable output can depress market prices when it reduces the need for thermal dispatch.
The competitive landscape for coal-fired generation remains robust in SEE, particularly as coal prices have recently decreased by about 5%. This trend enables coal units to frequently underbid gas in merit order during specific periods. Countries like Serbia and Bulgaria benefit from local lignite resources that offer a relatively low-cost fuel option.
The interaction between coal and gas within the merit order creates a nuanced price environment. During times of moderate demand coupled with high renewable output, coal can set lower marginal prices. Conversely, as demand peaks or renewable output diminishes—especially during evening hours when solar contributions decline—gas units become predominant in balancing the system, leading to higher price spikes.
The EU Emissions Trading System (ETS) adds complexity by imposing carbon costs that disproportionately affect higher-emission coal plants compared to gas counterparts. Currently priced emissions lead to additional costs of approximately €60–80/MWh for coal versus about €25–35/MWh for gas, thus narrowing coal’s competitive edge over time.
The ongoing reliance on thermal generation reflects not only economic considerations but also energy security concerns within the region. As such, while renewable capacities expand and emissions intensity decreases overall, fossil fuels remain integral to current market operations.
The forward market indicates expectations of sustained reliance on thermal generation with projected power prices for 2026 hovering around €113–114/MWh. These figures encapsulate anticipated market conditions influenced by ongoing fuel price fluctuations and potential policy shifts regarding renewables.
The transition towards a more sustainable energy model will necessitate substantial advancements in storage technology capable of managing intermittent renewable outputs effectively. Additionally, enhancing demand-side flexibility through industrial load management could align consumption patterns more closely with renewable availability.
This transitional phase highlights a market where traditional fossil fuel mechanisms continue to dominate pricing despite increasing renewable contributions—a scenario that may persist until significant investments are made in flexibility solutions across the region.
The implications for decarbonization are profound; achieving deeper emissions reductions will require not only an expansion of renewable infrastructure but also a comprehensive transformation in how electricity pricing mechanisms function within this evolving landscape.
Southeast Europe’s current energy dynamics serve as a microcosm of broader European trends—characterized by high levels of renewable integration alongside entrenched thermal price-setting practices—indicating that substantial structural adaptations are essential for future progress.
