The power trading landscape in South-East Europe (SEE) for 2026 is poised to be significantly influenced by three critical variables that overshadow individual national policies: the European gas price, the CO₂ pricing mechanism, and hydrological conditions. These elements will dictate not only the thermal output of power generation but also the dynamics of coal consumption across the region. As trading strategies evolve, market participants will need to focus on the interactions between hydro-rich periods and times of thermal scarcity, rather than relying solely on average baseload figures.
Forecasts for 2026 indicate that European gas prices will average around €30/MWh throughout the year, with summer months potentially dipping to €26/MWh under favorable conditions. This pricing serves as a crucial benchmark for gas-dependent markets like Greece and influences cross-border trading in the Balkans during scarcity periods. Concurrently, CO₂ price projections range from €83/t to €91/t, with expectations that it may reach €100/t as emissions caps tighten and free allocations decrease. This scenario suggests a higher thermal price floor compared to pre-2021 levels, even if gas prices remain below peak crisis levels.
In modeling day-ahead prices, if the TTF gas price averages €30/MWh and a modern combined-cycle gas turbine (CCGT) operates at an efficiency of 55%, the fuel cost component approximates €55/MWh. When accounting for an average CO₂ cost of €90/t and its associated emissions factor, this adds approximately €32/MWh to costs. Including operational and maintenance costs of about €3–6/MWh leads to a marginal cost band for gas-setting hours between €90–95/MWh. Notably, any surge in gas prices above €40/MWh or sustained CO₂ levels testing €100/t could further elevate these costs.
Coal markets within the EU are acutely sensitive to CO₂ pricing due to their higher emissions factors. For instance, a typical hard coal unit with an emissions factor of around 0.90 tCO₂/MWh incurs a CO₂ cost close to €81/MWh before considering fuel and operational expenses. Consequently, coal will increasingly function as a scarcity resource in 2026—activated only when necessary—resulting in price spikes rather than contributing to a stable baseload supply. Furthermore, lignite-heavy systems outside of the EU may appear more economical but still face vulnerabilities tied to EU-linked thermal pricing influenced by CO₂ costs.
Hydrological conditions represent another layer impacting market dynamics in 2026. The volatility inherent in SEE’s hydrology means that forecasts should be expressed as probability bands rather than fixed figures. In years with adequate precipitation, hydro zones can export more frequently, thus mitigating thermal generation needs and lowering average prices. Conversely, during dry spells where hydro output diminishes, reliance on thermal generation increases significantly—raising both average prices and market volatility. This volatility can present lucrative opportunities within intraday trading but poses risks for economies reliant on imports.
The anticipated trading price scenarios for SEE suggest that in a base hydrology year with stable gas and CO₂ prices, baseload prices could range from €85–110/MWh while peak hours might exceed €120/MWh under low wind conditions coupled with constrained imports. In contrast, favorable hydro years could compress baseload prices toward €70–95/MWh while maintaining attractive intraday spreads due to daily fluctuations in hydro availability and system constraints. Conversely, adverse hydro conditions could push baseload prices upward toward €110–160/MWh during extended dry periods.
Forecasting thermal output alongside coal supply becomes essential as these factors are intertwined across SEE markets. Countries like Greece benefit from their ability to quickly ramp up thermal generation due to their LNG access and robust interconnections; this allows them to act as marginal exporters during tight supply scenarios in the Balkans. In contrast, lignite-dependent nations may struggle with logistics and availability issues despite having access to significant lignite reserves.
As coal mining logistics become increasingly critical indicators of market stability entering 2026, regions with weak stockpiles or maintenance backlogs will likely see diminished capacity for thermal generation to offset hydro shortfalls—reflected in wider forward spreads and heightened reliance on imports at EU-linked rates. Conversely, stable mining operations can help mitigate import dependencies during dry spells.
Trading strategies for 2026 will center around three key spread structures: seasonal spreads between hydro-rich summer baseload purchases versus winter sales when flexibility wanes; intraday ramp spreads capturing evening demand surges; and cross-border congestion spreads that capitalize on regional price differences amid constrained interconnections during droughts.
The overarching implications of this pricing model indicate that stability in 2026 is contingent upon normal hydrological conditions and sustained gas pricing near the projected €30/MWh threshold. Any disruption—whether from rising gas prices or unfavorable weather patterns—could drive import prices into the range of €120–160/MWh during peak demand periods due to elevated CO₂ costs maintaining a high thermal floor.
In summary, market participants must closely monitor interactions between gas prices, CO₂ expectations, and early-season hydrology signals as they prepare for trading dynamics in South-East Europe throughout 2026.
