The SEE electricity market is increasingly defined by a structural contradiction. Renewable generation—led by hydro, solar and, to a lesser extent, wind—now represents a substantial share of total output, approaching ~45% on peak days. Yet despite this transformation in the generation mix, price formation remains decisively anchored in thermal generation, with coal and gas units continuing to set the marginal price across most trading hours.
The data snapshot from early April 2026 captures this dynamic with clarity. Day-ahead prices across key SEE markets clustered within a relatively tight band of €84–91/MWh, with Hungary (HUPX) clearing at €91.29/MWh, Serbia (SEEPEX) at €90.42/MWh, Romania (OPCOM) at €87.93/MWh, and Bulgaria (IBEX) at €84.58/MWh. These values do not reflect renewable production costs, which are effectively near zero at the margin. Instead, they reflect the cost of the last unit required to meet demand—almost invariably a thermal plant.
This persistence of thermal marginal pricing is rooted in the fundamental characteristics of renewable generation. Solar output, now exceeding 3.9 GW in the system, is highly concentrated during daylight hours and cannot be dispatched at will. Wind, contributing roughly 1.9 GW, is inherently variable and often poorly correlated with demand peaks. Hydropower, while flexible, is constrained by reservoir management and hydrological conditions. Together, these limitations mean that renewable generation cannot consistently meet demand across all hours, necessitating the continued operation of dispatchable thermal units.
Coal and gas plants therefore remain the system’s balancing backbone. On the observed day, coal generation stood at approximately 4,843 MW, while gas contributed around 2,502 MW, together representing more than a quarter of total output. More importantly, these units operate at the margin during periods of tight supply, determining the clearing price for the entire market.
The cost structure of these thermal units directly translates into power prices. Gas-fired generation, in particular, reflects the interplay between fuel costs, carbon pricing and operational efficiency. With gas benchmarks around €52/MWh, and assuming typical plant efficiencies of 50–55%, the implied fuel cost component of electricity generation lies in the range of €95–105/MWh before accounting for carbon costs. Adding CO₂ costs—currently around €70–75 per tonne, and translating to approximately €25–35/MWh depending on plant emissions intensity—pushes the marginal cost of gas-fired generation into the €120–140/MWh range under full load conditions.
However, observed market prices are often lower than these theoretical marginal costs, reflecting a combination of factors. First, not all gas units operate at full marginal cost due to long-term fuel contracts or efficiency variations. Second, coal plants, despite higher emissions, can provide marginal supply at lower short-term cost depending on coal prices and plant characteristics. Third, renewable output during certain hours suppresses prices by reducing the need for thermal dispatch.
Coal-fired generation remains particularly relevant in this context. With coal prices showing a declining trend—recently falling by approximately 5% in API2 benchmarks—and lower fuel costs relative to gas, coal units can undercut gas in the merit order during certain periods. This dynamic is especially pronounced in countries with significant coal capacity, such as Serbia and Bulgaria, where domestic lignite provides a relatively low-cost fuel source.
The interaction between coal and gas in the merit order creates a layered price structure. During periods of moderate demand and high renewable output, coal units may set the marginal price, resulting in lower overall price levels. As demand increases or renewable output declines, gas units move to the margin, pushing prices higher. This transition is clearly visible in intraday price patterns, where evening peaks—coinciding with the decline in solar output—often see prices rise sharply as gas-fired generation is required to balance the system.
Carbon pricing adds another dimension to this structure. The EU Emissions Trading System (ETS) imposes a cost on carbon emissions that disproportionately affects coal generation due to its higher emissions intensity. At current EUA levels of €70–75/t, coal plants face an additional cost of approximately €60–80/MWh, compared to €25–35/MWh for gas. This narrows the cost advantage of coal and, over time, shifts the merit order toward gas and eventually low-carbon alternatives.
Despite this, coal remains competitive in the SEE region due to structural factors, including domestic resource availability and existing infrastructure. The continued operation of coal plants therefore reflects not only cost considerations but also energy security concerns and the slower pace of transition compared to Western Europe.
The persistence of thermal marginal pricing has significant implications for market behavior and investment strategies. For renewable generators, it means that revenue is still largely determined by fossil fuel costs rather than their own production economics. While high renewable output can depress prices during certain hours, the overall price level remains linked to thermal generation costs, providing a degree of revenue stability.
For thermal generators, the situation is more complex. While they continue to set prices and capture high margins during peak periods, they face increasing operational challenges due to declining load factors and regulatory pressure. As renewable penetration increases, thermal plants are dispatched less frequently, reducing their overall utilization and revenue. However, their role in balancing the system ensures that they remain indispensable, at least in the medium term.
Forward markets reflect this underlying structure. Power forward prices for calendar year 2026 are trading around €113–114/MWh, indicating expectations of continued reliance on thermal generation and sustained carbon pricing. These forward levels incorporate both current fuel cost assumptions and anticipated market dynamics, including renewable expansion and potential policy changes.
The linkage between power prices and fuel markets also introduces volatility. Changes in gas prices, driven by global LNG dynamics, or shifts in carbon pricing can have immediate and significant impacts on electricity prices. This creates both risks and opportunities for market participants, particularly those engaged in trading and hedging activities.
The transition away from thermal marginal pricing will require a fundamental shift in system structure. Large-scale deployment of storage, capable of shifting renewable output across time, is a critical component of this transition. Demand-side flexibility, including industrial load management and electrification strategies, can also reduce reliance on thermal generation by aligning demand with renewable supply.
However, these solutions are still in the early stages of deployment in the SEE region. Until they reach sufficient scale, thermal generation will continue to define the marginal price, even as its share of total generation declines. This creates a transitional market environment in which old and new paradigms coexist, with pricing mechanisms lagging behind changes in the generation mix.
The implications for decarbonisation are significant. While increasing renewable capacity reduces overall emissions intensity, the persistence of thermal marginal pricing means that fossil fuels continue to play a central role in the system. Achieving deeper decarbonisation will require not only expanding renewable capacity but also transforming the mechanisms through which electricity is priced and dispatched.
In this context, the SEE market can be seen as a leading indicator of broader European trends. The region’s combination of growing renewable capacity, significant thermal infrastructure and limited storage mirrors conditions that are emerging across other parts of the continent. The dynamics observed here—particularly the coexistence of high renewable penetration and thermal price-setting—are likely to persist until flexibility solutions are fully integrated into the system.
For investors, understanding this dynamic is essential. The value of assets is increasingly determined not just by their generation profile, but by their position within the merit order and their exposure to fuel and carbon costs. Assets that can operate flexibly, respond to price signals and integrate with emerging technologies are likely to outperform in this evolving landscape.
The SEE power market is therefore not yet post-thermal. It is a system in transition, where renewables are reshaping the supply curve but have not yet redefined the marginal price. The timing and trajectory of this transition will depend on the pace of investment in flexibility, the evolution of fuel and carbon markets, and the ability of policymakers to adapt market structures to a new reality.
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