The power trading landscape in Southeast Europe (SEE) is poised for significant shifts by 2026, driven by a triad of critical factors: European gas prices, CO₂ emission costs, and hydrological conditions. These elements will play a more decisive role than individual national policies in shaping market dynamics. The interplay between these variables will dictate the operational strategies of utilities and energy companies across the region, particularly in how they manage thermal output and coal utilization.
Forecasts for European gas prices suggest an average near €30/MWh for 2026, with summer levels potentially dropping to around €26/MWh under favorable conditions. This pricing framework will establish the thermal floor for gas-dependent markets like Greece, influencing broader Balkan trading patterns during scarcity periods. Concurrently, CO₂ prices are expected to range from €83/t to €91/t, with some analysts predicting a potential rise above €100/t as emissions caps tighten. This elevated CO₂ pricing indicates a higher baseline cost for thermal generation compared to pre-2021 levels, even if gas prices remain below crisis peaks.
To model day-ahead price formations effectively, the established thermal floor can be analyzed using these inputs. For instance, if TTF averages at €30/MWh and a modern combined cycle gas turbine (CCGT) operates at 55% efficiency, the fuel cost would approximate €55/MWh. Adding the CO₂ component—estimated at around €32/MWh when factoring in emissions from gas generation—brings the marginal cost for gas-setting hours to a range of €90–95/MWh. This margin could widen significantly if gas prices exceed €40/MWh or if CO₂ costs hit sustained highs of €100/t.
Coal markets within the EU are acutely sensitive to CO₂ pricing due to higher emission factors associated with coal-fired generation. A typical hard coal unit emits approximately 0.90 tCO₂/MWh at a CO₂ price of €90/t, resulting in significant costs that elevate operational expenses. Consequently, coal may increasingly function as a scarcity resource in 2026, clearing only when necessary for grid stability but doing so at elevated costs that drive price spikes rather than contributing to baseload generation.
Hydrological conditions add another layer of complexity to market dynamics. The variability of hydroelectric output in SEE means that the region’s power supply can fluctuate dramatically based on weather patterns. In years with favorable hydrology, hydro resources can export more frequently, suppressing thermal generation and lowering average prices. Conversely, during dry spells, reduced hydro output necessitates greater reliance on thermal generation, which can lead to increased price volatility and higher average costs.
Given these variables, a coherent price forecast for SEE in 2026 must encompass multiple scenarios rather than a singular estimate. In a base case with stable hydrology and gas prices around €30/MWh coupled with CO₂ averaging between €83–91/t, baseload prices in EU-linked zones are likely to cluster between €85–110/MWh. Peak hours could see prices exceed €120/MWh during periods of low wind and constrained imports. In contrast, adverse hydrological conditions could push baseload prices up to €110–160/MWh during prolonged droughts or low wind scenarios.
The relationship between thermal output forecasting and coal supply becomes increasingly intertwined as 2026 approaches. Countries like Greece, which rely heavily on natural gas and have robust interconnections, can quickly adjust thermal output to meet demand spikes. This flexibility positions Greece as a potential marginal exporter during tight market conditions. In contrast, lignite-heavy systems in the Western Balkans may struggle with logistical constraints that limit their ability to ramp up production during dry periods.
Coal mining logistics will serve as an important indicator of market reliability going into 2026. If lignite systems face challenges such as low stockpiles or maintenance issues, their capacity to substitute for hydro shortfalls diminishes significantly. This scenario would manifest through wider forward spreads and increased import reliance at EU-linked pricing levels. Conversely, stable logistics would allow lignite systems to mitigate import dependency during dry spells.
Trading strategies in 2026 will likely center around three primary spread structures: seasonal spreads between hydro and thermal generation; intraday ramp spreads capturing evening demand surges; and cross-border congestion spreads that capitalize on regional discrepancies during peak demand periods.
For policymakers and industrial stakeholders, understanding this multifaceted pricing model is crucial. Stability in power prices will hinge on maintaining normal hydrological conditions and keeping gas prices within the projected band of €30/MWh. Any disruptions—whether from rising gas costs or adverse weather—could lead to significantly higher import prices during peak demand hours.
The key indicators shaping the trading landscape in 2026 will not be confined to simple price forecasts but will involve analyzing the interactions between CO₂ expectations, gas pricing trends, and early-season hydrological assessments. The outcomes of these factors will ultimately determine whether SEE operates primarily on its established thermal floor or experiences frequent deviations due to supply constraints.
