The electricity market in Southeast Europe (SEE) is currently characterized by a significant paradox: while renewable energy sources, particularly hydro, solar, and wind, are increasingly contributing to the generation mix—approaching approximately 45% on peak days—the marginal pricing continues to be dictated by thermal generation. This reliance on coal and gas units remains prevalent across most trading hours, underscoring a structural contradiction within the region’s energy landscape.
A recent data analysis from early April 2026 illustrates this dynamic vividly. Day-ahead prices in key SEE markets were observed within a narrow range of €84–91/MWh. Specific figures include 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. Notably, these prices do not take into account the near-zero production costs associated with renewable energy but rather reflect the expenses incurred by the last unit dispatched to satisfy demand, which is predominantly thermal.
The ongoing reliance on thermal marginal pricing stems from inherent characteristics of renewable energy generation. Solar power generation has surpassed 3.9 GW during daylight hours but is not dispatchable at will. Wind energy, contributing around 1.9 GW, is subject to variability and does not consistently align with peak demand periods. Hydropower, while more flexible, is limited by reservoir management and hydrological conditions. Consequently, these factors necessitate the continued operation of thermal plants to balance supply and demand effectively.
On the day in question, coal generation was recorded at approximately 4,843 MW, with gas contributing around 2,502 MW. Together, these thermal sources accounted for more than a quarter of total output and played a crucial role in determining market prices during times of tight supply.
The cost structure associated with thermal generation directly impacts electricity pricing. Gas-fired plants are particularly influenced by fuel costs, carbon pricing, and operational efficiency metrics. With gas benchmarks hovering around €52/MWh, typical plant efficiencies between 50–55% imply that fuel costs for electricity generation range from €95–105/MWh, excluding carbon costs. When including CO₂ expenses—currently estimated at around €70–75 per tonne, translating to an additional €25–35/MWh—the marginal cost for gas-fired generation can reach between €120–140/MWh.
Despite these theoretical margins, actual market prices often fall below these levels due to various factors. For instance, long-term fuel contracts may prevent all gas units from operating at full marginal cost, and coal plants can sometimes provide marginal supply at lower short-term costs based on current coal prices and their operational characteristics. Furthermore, renewable output during certain hours can suppress prices by lessening the need for thermal dispatch.
The relevance of coal-fired generation remains pronounced within this context. Recent trends show a decline in coal prices—approximately 5% drop in API2 benchmarks—which allows coal units to compete favorably against gas in the merit order during specific periods. This competitive edge is especially evident in nations like Serbia and Bulgaria that possess substantial coal capacity and rely on domestic lignite as a cost-effective fuel source.
The interplay between coal and gas within the merit order creates a complex price structure. During times of moderate demand coupled with high renewable output, coal units may set lower marginal prices; conversely, as demand rises or renewable generation decreases, gas units typically take precedence, leading to increased prices. This fluctuation is particularly noticeable during evening peaks when solar output diminishes and gas-fired generation becomes essential for system balance.
Additions to this framework include carbon pricing mechanisms such as the EU Emissions Trading System (ETS), which imposes costs that disproportionately affect coal due to its higher emissions intensity. Current EUA levels of around €70–75/t impose additional costs of approximately €60–80/MWh on coal plants compared to about €25–35/MWh for gas units. This dynamic narrows coal’s cost advantage over time and gradually shifts the merit order towards gas and low-carbon alternatives.
The ongoing reliance on thermal generation raises significant implications for market behavior and investment strategies within the region. Renewable generators find their revenues primarily tied to fossil fuel costs rather than their own production economics; thus, while high renewable output may depress prices temporarily, overall price levels remain closely linked to thermal generation costs.
This situation presents a complex landscape for thermal generators as well. Although they continue to set prices during peak demand periods and capture considerable margins, they face mounting operational challenges stemming from declining load factors and regulatory pressures aimed at reducing emissions. Increased penetration of renewables results in less frequent dispatching of thermal plants, diminishing their utilization rates and revenue streams while still ensuring their critical role in balancing the electricity system.
The forward market reflects these underlying dynamics with power forward prices for calendar year 2026 trading around €113–114/MWh. These levels indicate expectations of sustained reliance on thermal generation alongside ongoing carbon pricing pressures while factoring in current fuel cost assumptions and anticipated market developments related to renewable expansion and policy changes.
The correlation between power prices and fuel markets introduces volatility into the system; fluctuations in global LNG dynamics or shifts in carbon pricing can significantly impact electricity prices almost immediately. This volatility presents both risks and opportunities for market participants engaged in trading or hedging activities.
A transition away from thermal marginal pricing will necessitate substantial changes within the system structure itself. Key components of this transition include large-scale storage deployment capable of shifting renewable output over time as well as enhancing demand-side flexibility through strategies like industrial load management and electrification efforts that align demand with renewable supply patterns.
However, many of these solutions are still nascent within the SEE region; until they achieve adequate scale, thermal generation will likely continue to dictate marginal pricing despite its declining share in total generation capacity. This transitional environment reflects a coexistence of older paradigms alongside emerging trends where pricing mechanisms have yet to adapt fully to shifts in the generation mix.
The implications for decarbonization are profound; although increasing renewable capacity contributes to lowering overall emissions intensity, persistent thermal marginal pricing indicates that fossil fuels remain integral to the system’s operation. Achieving deeper decarbonization goals will require not only expanding renewable capacity but also rethinking how electricity is priced and dispatched across markets.
The SEE market serves as an important indicator of broader European trends given its combination of rising renewable capacity alongside significant thermal infrastructure coupled with limited storage options—conditions likely mirrored across various regions throughout Europe. The dynamics observed here—especially regarding high renewable penetration coexisting with thermal price-setting—are expected to persist until flexible solutions are fully integrated into the energy system.
A comprehensive understanding of these dynamics is crucial for stakeholders across the energy sector as asset values increasingly hinge not only on generation profiles but also on positions within merit orders along with exposure to fuel and carbon costs amid evolving market conditions.
The SEE power market remains entrenched in a transitional phase where renewables are reshaping supply curves without yet redefining marginal pricing structures. The pace and direction of this transition will depend significantly on investments in flexibility measures alongside developments within fuel markets and regulatory frameworks adapting to new realities.
