South-East Europe’s power price formation in 2026 is expected to be shaped by three linked inputs: the European gas price level that sets marginal fuel costs for gas fleets, the CO2 price that lifts the thermal floor in EU-linked bidding zones and affects import pricing for non-EU neighbors, and hydrology that determines whether hydro output compresses prices or contributes to scarcity. The interaction of these variables is expected to influence thermal dispatch and coal burn more than narratives about installed capacity. Trading opportunities are projected to depend on spreads between hydro-rich hours and thermal-scarcity hours rather than on average baseload alone.
Gas and CO2 set the thermal floor in tight hours
A base assumption for 2026 starts with the gas and CO2 curve because both determine the marginal cost of the unit setting prices during tight hours across interconnected markets. European gas forecasters cluster around a TTF average near €30/MWh for 2026, with summer levels closer to €26/MWh under benign conditions. This is described as anchoring the thermal floor for gas-setting markets such as Greece and, through cross-border trading, for parts of the Balkans during scarcity periods.
On CO2, analysts’ 2026 averages are described as spanning roughly €83/t to around €91/t, with some strategists expecting tests of €100/t during 2026 as the cap tightens and free allocations decline. The implication in the source material is that 2026 represents a higher-floor year than the pre-2021 period even if gas remains below crisis peaks. With these inputs set, a first-order “thermal floor” can be modeled for day-ahead price formation.
If TTF averages €30/MWh and a modern CCGT operates at 55% net efficiency, the fuel cost component is estimated at about €55/MWh electric. With CO2 averaging €90/t and an emission factor of roughly 0.35 tCO2/MWh, the CO2 component is estimated at about €32/MWh. Adding 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.
The source material also points to upside scenarios where either gas exceeds €40/MWh or CO2 tests €100/t for sustained periods. It describes this as a reason that a stable gas year does not necessarily translate into a low power year because the CO2 layer keeps the floor elevated. Volatility is expected to shift realized capture prices around that thermal floor.
Coal marginal costs rise with higher CO2 sensitivity
The same framework is described as applying to coal-setting outcomes, with coal markets in the EU characterized as more sensitive to CO2 due to higher emission factors. A typical hard coal unit emitting around 0.90 tCO2/MWh at €90/t is estimated to carry a CO2 cost of roughly €81/MWh, before adding fuel and O&M. In this setup, coal is described as increasingly behaving like a scarcity-only unit in 2026.
The source material states that coal clears when needed for adequacy but at very high marginal cost, which is expected to push price spikes rather than set low baseload levels. It also links this mechanism to import-price exposure for lignite-heavy non-EU systems, where import pricing is formed by EU-linked thermal generation with CO2 rather than domestic fuel costs. This connects regional price outcomes to EU-linked thermal marginal costs.
Hydrology determines whether thermal hours dominate
The second major layer in 2026 price formation is hydrology, which determines how often markets trade on the thermal floor versus how often hydro output compresses prices. The source material frames the 2026 hydro outlook as probability bands because SEE hydro is volatile and prone to extremes. In wet-to-normal regimes, hydro zones are described as exporting more frequently, suppressing thermal hours and pulling baseload averages down while flattening peak spreads.
In dry regimes, hydro output falls and hydro flexibility disappears, forcing thermal plants to provide both energy and balancing. This is described as raising not only average prices but also volatility. The source material notes that volatility can be monetized in intraday and balancing markets while also being economically destabilizing for import-dependent economies.
A coherent forecast for SEE in 2026 is therefore presented as scenarios rather than a single number. In a base hydrology year with gas around €30/MWh and CO2 averaging €83–91/t, baseload prices in EU-linked zones are described as clustering around €85–110/MWh, with peak hours regularly above €120/MWh when wind is low and imports are constrained.
An upside hydrology scenario is described as compressing the baseload band toward €70–95/MWh, while intraday spreads may remain attractive due to continued hydro arbitrage within the day alongside local congestion and evening ramps driven by system constraints. A downside scenario—especially if summer drought coincides with low wind—shifts baseload toward €110–160/MWh for sustained periods, with peak-hour tails extending higher when interconnector capacity becomes the bottleneck rather than generation capacity.
Thermal response depends on country fleets and coal deliverability
The ability of thermal fleets to respond is described as differing sharply by country even though thermal remains an adequacy backstop across SEE. Greece is characterized as a gas-heavy system with LNG access and strong interconnection that can ramp quickly, often making it a marginal exporter during tight Balkan hours. In this context, Greek gas economics are described as capping or driving scarcity pricing for southern Balkans through an export marginal price reflecting gas plus CO2 plus opportunity cost.
The source material contrasts this with lignite-heavy systems in parts of the Western Balkans that can raise output materially in dry years but face constraints from mine deliverability and unit availability. It states that market outcomes depend on how many tonnes can be delivered to boilers without logistics failure and how many hours older units can run without forced outages once dispatch intensity rises. Thermal output forecasting is therefore linked directly to coal supply conditions.
Lignite stockpiles influence scarcity frequency and cross-border spreads
The source material describes coal mining supply as an indicator for market conditions in 2026: when lignite systems enter with weak stockpiles, high strip-ratio stress, or maintenance backlogs, the probability that thermal can fully substitute for hydro shortfalls declines. It says this shows up through wider forward spreads, higher scarcity-hour pricing, and greater reliance on imports priced at EU-linked marginal costs rather than through an abstract risk premium alone.
If mine-to-plant logistics remain stable, lignite systems are described as suppressing import dependence during dry periods by reducing the number of hours clearing at the gas-plus-CO2 floor. The trading implications are presented through spread structures rather than single-price targets. These structures include seasonal hydro-to-thermal spreads, intraday ramp spreads tied to solar output patterns, and cross-border congestion spreads when interconnectors bind.
Seasonal, intraday ramp, and congestion spreads in 2026 trading
The first spread structure described is a hydro-to-thermal seasonal spread: buying summer baseload when hydro conditions are rich and selling winter baseload when hydro flexibility weakens and heating demand raises peak risk. The second is an intraday ramp spread designed around evening ramp premiums in solar-heavy zones where solar collapses late afternoon and thermal or imports fill the gap. The source material says this pattern becomes more valuable when CO2 levels are high.
The third spread structure described involves cross-border congestion spreads between Balkan zones when interconnectors bind. It highlights dry hydro periods when multiple countries are simultaneously short, describing marginal pricing as set by the most constrained import path rather than by the cheapest generator available in isolation across zones.
Forward indicators combine CO2 expectations, gas levels, and early hydrology signals
The source material presents policy-relevant implications tied to whether hydro remains normal alongside gas staying near its forecast band of about €30/MWh. If either variable breaks upward—gas spikes or hydro fails—it describes import prices in tight hours converging toward outcomes of €120–160/MWh, attributing this to a persistent high thermal floor from CO2 levels. For heavy industry it links this setup to higher probabilities of margin compression during winter and summer drought episodes.
The forward indicator set for 2026 trading is described as interactions among CO2 expectations, gas forward levels, and early-season hydrology signals rather than a single price forecast. With CO2 forecasts averaging around €83–91/t and plausible tests of €100/t, even a moderate gas year is described as producing a relatively high thermal floor during scarcity hours. Under this framework, hydro availability and coal mining reliability are presented as decisive factors determining whether SEE clears on that floor occasionally or more frequently throughout 2026.
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