South-East Europe’s 2026 power price formation will be dominated by a three-variable stack that has become more binding than any single national policy lever: the European gas price level that sets the marginal fuel cost for the region’s gas fleets, the CO₂ price that lifts the thermal floor in every EU-linked bidding zone and therefore in import pricing even for non-EU neighbors, and the hydrology regime that determines whether hydro systems are exporters that compress prices or importers that amplify scarcity. In 2026, the region’s thermal output and coal burn will respond to these variables much more than to “installed capacity” narratives, and trading opportunities will be driven by the spread structure between hydro-rich hours and thermal-scarcity hours rather than by average baseload alone.
A workable base assumption for 2026 starts with the gas and CO₂ curve because these are the two inputs that determine the marginal cost of the unit that sets prices in tight hours across interconnected markets. European gas forecasters entering 2026 cluster around a TTF average near €30/MWh for the year, with summer levels closer to €26/MWh in benign conditions. This matters because it anchors the thermal floor for gas-setting markets such as Greece and, via cross-border trading, for a wide part of the Balkans in scarcity hours. On CO₂, market analysts’ 2026 averages span roughly €83/t to around €91/t, with some strategists expecting the market to test €100/t during 2026 as the cap tightens and free allocations decline. The practical interpretation is that 2026 is a higher-floor year than the pre-2021 period, even if gas remains materially below the crisis peaks.
Once those two inputs are set, you can model a first-order “thermal floor” for day-ahead price formation. If TTF averages €30/MWh and a modern CCGT runs at 55% net efficiency, the fuel cost component is about €55/MWh electric. If CO₂ averages €90/t and the gas emission factor is roughly 0.35 tCO₂/MWh, the CO₂ component is about €32/MWh. Adding a conservative variable O&M and balancing uplift of €3–6/MWh, the marginal cost band for gas-setting hours clusters around €90–95/MWh in the base case, with obvious upside if either gas spikes above €40/MWh or CO₂ tests €100/t for sustained periods. This is why a “stable” gas year does not necessarily mean a “low” power year: the CO₂ layer keeps the floor elevated, and volatility shifts the realized capture price around that floor.
Coal-setting markets in the EU are even more sensitive to CO₂ because the emission factor is higher. A typical hard coal unit emitting around 0.90 tCO₂/MWh at €90/t carries a CO₂ cost of roughly €81/MWh before fuel and O&M are added. That is why coal, where it remains in the stack, increasingly behaves like a scarcity-only unit in 2026: it clears when needed for adequacy, but it does so at very high marginal cost, pushing price spikes rather than setting a low baseload. This is also why lignite-heavy non-EU systems can appear “cheaper” on paper but still face import-price exposure: the import price they must pay is formed by EU-linked thermal with CO₂, not by their domestic fuel cost.
Hydrology is the second layer that determines how often the market sits on the thermal floor versus how often it is compressed by hydro output. The 2026 hydro outlook is best framed as probability bands because SEE hydro is volatile and increasingly prone to extremes. In wet-to-normal hydro regimes, hydro zones export more frequently and suppress thermal hours, pulling baseload averages down and flattening peak spreads. In dry regimes, hydro output falls and—more importantly—hydro flexibility disappears, forcing thermal to provide both energy and balancing, which raises not only the average but the volatility. That volatility is now monetizable in intraday and balancing markets, but it is also economically destabilizing for import-dependent economies.
A coherent trading-price forecast for SEE in 2026 therefore needs to be expressed as a scenario set rather than a single number. In a base hydrology year with gas around €30/MWh and CO₂ averaging €83–91/t, SEE baseload prices in EU-linked zones in the region tend to cluster in a broad band around €85–110/MWh, with peak hours regularly printing above €120/MWh when wind is low and imports are constrained. In an upside hydro year, the baseload band compresses toward €70–95/MWh, but intraday spreads can remain attractive because hydro still arbitrages within the day and system constraints still create local congestion and evening ramps. In a downside hydro year, especially if summer drought coincides with low wind regimes, the baseload band shifts upward toward €110–160/MWh for sustained periods, and the peak-hour tail becomes meaningfully fatter, with scarcity hours printing far above baseload as interconnector capacity becomes the bottleneck rather than generation capacity.
This is where thermal output forecasting and coal mining supply become inseparable. Across SEE, the thermal fleet is still the adequacy backstop, but its ability to respond differs sharply by country. Greece, as a gas-heavy system with LNG access and strong interconnection, can ramp thermal quickly and therefore often becomes a marginal exporter in tight Balkan hours. That means Greek gas economics often cap or drive scarcity pricing for the southern Balkans, with the marginal export price reflecting gas plus CO₂ plus opportunity cost. In contrast, lignite-heavy systems in the Western Balkans can raise output materially in dry years, but they are constrained by mine deliverability and unit availability. In practical terms, the market doesn’t care how much lignite is “in the ground.” It cares how many tonnes can be delivered to the boilers without a logistics failure, and how many hours the older units can run without forced outages once dispatch intensity rises.
Coal mining and supply therefore becomes a market indicator in itself. When lignite systems enter 2026 with weak stockpiles, high strip-ratio stress, or maintenance backlogs, the probability that thermal can fully substitute for hydro shortfalls declines. The market expresses that not in an abstract risk premium but in wider forward spreads, higher scarcity-hour pricing, and greater reliance on imports at EU-linked marginal costs. Conversely, when mine-to-plant logistics are stable, lignite systems can suppress import dependence in dry periods, which reduces the number of hours that clear at the gas-plus-CO₂ floor.
Trading opportunities in 2026 will be concentrated in three spread structures. The first is the hydro-to-thermal seasonal spread: buying summer baseload in hydro-rich conditions and selling winter baseload when hydro flexibility is weakest and heating demand raises peak risk. The second is the intraday ramp spread: capturing the evening ramp premium in solar-heavy zones where solar collapses output late afternoon and thermal or imports must fill the gap, a pattern that becomes more valuable when CO₂ is high. The third is the cross-border congestion spread: monetizing differences between Balkan zones when interconnectors bind, especially in dry hydro periods when multiple countries are simultaneously short and the marginal price is set by the most constrained import path rather than by the cheapest generator.
For policymakers and industrial buyers, the macro implication of this price model is that 2026 will feel “stable” only if hydro is at least normal and if gas remains near the €30/MWh forecast band. If either variable breaks upward—gas spikes, or hydro fails—the region’s import price in tight hours rapidly converges toward €120–160/MWh outcomes because the CO₂ layer keeps the thermal floor high. For heavy industry, that translates into a higher probability of margin compression in winter and in summer drought episodes. For fiscal authorities, it raises the probability of tariff-smoothing interventions, which then become budget issues rather than utility issues.
The main forward indicator set for 2026 trading, therefore, is not a single “price forecast” but the interaction of CO₂ expectations, gas forward levels, and early-season hydrology signals. CO₂ forecasts around €83–91/t average with plausible tests of €100/t imply that even a moderate gas year produces a relatively high thermal floor in scarcity hours. That makes hydro availability and coal mining reliability the decisive factors that determine whether SEE spends 2026 clearing on that floor occasionally or frequently.
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