The expansion of renewable energy across South-East Europe has altered the generation mix, reshaped intraday price patterns and introduced new forms of volatility. Yet at the core of the market, one fundamental relationship remains largely intact: electricity prices continue to be anchored to fossil fuel costs—primarily gas—and to carbon pricing under the EU Emissions Trading System. This structural linkage persists even as renewable penetration rises, reflecting the continued role of thermal generation in setting marginal prices.
The dataset from early April 2026 offers a clear illustration of this dynamic. Day-ahead prices across the region settled within a relatively narrow range of €84–91/MWh, despite significant variation in renewable output and cross-border flows. These price levels align closely with the cost structure of thermal generation rather than the near-zero marginal cost of renewables. The implication is straightforward: renewables influence volatility and timing, but thermal assets still define the price floor.
Gas remains the primary marginal fuel across much of the region, particularly during evening peak hours and periods of low renewable output. With benchmark gas prices around €52/MWh, the cost of electricity generation from combined-cycle gas turbines (CCGTs) can be estimated by adjusting for plant efficiency. Assuming efficiency in the range of 50–55%, the fuel cost component alone translates into approximately €95–105/MWh of electricity output. This figure represents the baseline upon which additional costs are layered.
Carbon pricing under the EU ETS introduces a second critical component. With EUA prices currently in the range of €70–75 per tonne, gas-fired generation incurs an additional cost of approximately €25–35/MWh, depending on emissions intensity. For coal-fired generation, the impact is even more pronounced, with carbon costs reaching €60–80/MWh due to higher emissions factors. When combined with fuel costs, these carbon charges significantly influence the position of thermal units within the merit order.
The resulting marginal cost stack places gas-fired generation in the €120–140/MWh range under full cost conditions. However, observed market prices are typically lower, reflecting partial load operation, contract structures and the influence of lower-cost generation—particularly coal and hydro—during certain periods. Nevertheless, the underlying linkage between power prices and fuel/carbon costs remains evident, particularly during peak demand hours when gas units are required to balance the system.
Coal continues to play a significant role in SEE price formation, particularly in countries with domestic lignite resources such as Serbia and Bulgaria. While coal faces higher carbon costs, its lower fuel cost can make it competitive with gas under certain conditions. This dual-fuel dynamic creates a layered merit order in which coal and gas compete to set the marginal price depending on demand, renewable output and fuel price movements.
The interaction between gas and coal is further complicated by carbon pricing. As EUA prices rise, the cost advantage of coal diminishes, gradually shifting the merit order toward gas. This process is uneven across the region, reflecting differences in plant efficiency, fuel supply and regulatory frameworks. In markets where coal remains dominant, price sensitivity to carbon costs is particularly pronounced, creating an additional channel through which EU policy influences local electricity prices.
The persistence of thermal marginal pricing has important implications for renewable generators. Despite producing electricity at near-zero marginal cost, their revenues are determined by the market clearing price, which is set by thermal units. This creates a form of implicit subsidy, where renewable generators benefit from higher prices driven by fossil fuel costs. However, this benefit is increasingly offset by declining capture prices as renewable penetration rises and negative pricing events become more frequent.
Forward markets provide further insight into the expected evolution of this relationship. Power forward contracts for calendar year 2026 are trading around €113–114/MWh, reflecting expectations of continued reliance on thermal generation and sustained carbon pricing. These forward levels incorporate assumptions about fuel costs, renewable expansion and policy developments, offering a market-based view of future price dynamics.
The linkage between power and fuel markets also introduces a high degree of volatility. Gas prices are influenced by global factors, including LNG supply, geopolitical developments and weather conditions. Carbon prices, meanwhile, are shaped by EU policy, market expectations and macroeconomic conditions. Changes in either of these variables can have immediate and significant impacts on electricity prices, creating both risks and opportunities for market participants.
This volatility is particularly relevant in the context of cross-border trading. As SEE markets are increasingly integrated with Central and Western Europe, price movements in one region can quickly propagate to others. Gas price shocks, for example, can raise electricity prices across multiple markets simultaneously, while carbon price increases affect all EU-linked systems. This interconnectedness amplifies the impact of fuel and carbon markets on SEE electricity prices.
The structural linkage to fossil fuels also has implications for industrial competitiveness. Electricity prices in SEE influence the cost base of energy-intensive industries, many of which are exposed to international competition. The introduction of mechanisms such as the Carbon Border Adjustment Mechanism (CBAM) further reinforces the importance of aligning electricity costs with carbon policy, as imported goods are subject to carbon-related charges.
For policymakers, this creates a complex balancing act. On one hand, carbon pricing is a key tool for driving decarbonisation. On the other, it raises electricity prices and can impact industrial competitiveness. Managing this trade-off requires careful design of support mechanisms, including compensation schemes for affected industries and investment in low-carbon generation and flexibility.
The transition away from fossil-linked pricing will depend on the development of alternative marginal technologies. Large-scale storage, capable of shifting renewable output across time, is a critical component of this transition. As storage capacity increases, it can begin to displace thermal units in the merit order, reducing the influence of gas and carbon costs on price formation.
Demand-side flexibility offers another pathway. By aligning consumption with periods of high renewable output, it can reduce reliance on thermal generation and dampen price volatility. Electrification of heating, transport and industry, combined with smart demand management, has the potential to reshape load profiles and reduce peak demand pressures.
However, these changes will take time to materialize. In the near to medium term, thermal generation will continue to play a central role in balancing the system, ensuring that power prices remain linked to fuel and carbon markets. The pace of change will depend on the speed of investment in storage, grid infrastructure and demand-side solutions, as well as the evolution of policy frameworks.
The SEE region is therefore in a transitional phase, where new and old paradigms coexist. Renewable capacity is expanding rapidly, but the mechanisms that determine prices remain rooted in the fossil fuel system. This creates a hybrid market structure, characterized by renewable-driven volatility and thermal-driven price levels.
For investors and market participants, understanding this structure is essential. The value of assets is increasingly determined by their exposure to fuel and carbon costs, as well as their ability to respond to price signals. Hedging strategies, portfolio diversification and active market participation are becoming critical components of risk management.
The persistence of fossil-linked pricing should not be seen as a failure of the energy transition, but as a reflection of its current stage. The system is evolving, but not yet transformed. As flexibility solutions scale and market design adapts, the influence of thermal generation is likely to diminish. Until then, gas and carbon will remain the key drivers of electricity prices in SEE.
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