Hydropower will be the decisive swing factor for South-East Europe in 2026 because it is simultaneously energy, seasonal storage, and the region’s cheapest source of flexibility. The market has increasingly learned that the same installed hydro fleet can produce two radically different economic outcomes depending on inflows: in a wet year, hydro compresses day-ahead prices, reduces import bills, and stabilises balancing; in a dry year, hydro becomes a scarcity amplifier that raises thermal burn, increases imports, and spikes volatility. Serbia sits at the center of this dynamic because its power system combines a large hydro portfolio with exposure to regional trading, while its macroeconomy is sensitive to electricity import costs whenever hydro underdelivers.
Serbia’s hydro backbone is concentrated in the EPS fleet, which operates 16 hydropower plants with total installed capacity of about 3,015 MW. In 2024, hydro produced about 32.2% of EPS electricity output, and long-run averages over 2010–2024 indicate hydro generation around 10.6 TWh annually, equivalent to roughly one third of the utility’s production in normal hydrology. In 2025 drought conditions, public-sector expectations indicated hydro generation could fall toward roughly 8 TWh, with cumulative generation around 6.5 TWh through early autumn, implying a stress-year deficit versus the normal band. Those numbers matter for 2026 not only as history but as calibration: they define the likely range of outcomes for Serbia if hydrology swings from normal to dry.
The right way to forecast 2026 hydro is to start from the two drivers that actually set revenue and system security: reservoir starting levels at the end of winter and the regional price regime shaped by CO₂, gas, and cross-border scarcity. On pricing, the European carbon market is a meaningful proxy for how expensive marginal thermal generation will be. In mid-January 2026, EU carbon permits traded around €90–92 per tonne, a level that supports a structurally higher marginal cost for coal- and gas-fired generation across interconnected markets. That matters because SEE day-ahead prices increasingly “inherit” a European price floor in tight hours. When the marginal unit is thermal and CO₂ is near €90+, hydro’s value is no longer just its average MWh; it is its ability to replace those expensive hours and to sell balancing services into volatility.
On the hydrology side, 2026 begins with a broadly constructive winter adequacy context in Europe, and hydro reservoir levels in parts of the continent have been described as higher than previous years. That does not guarantee a wet summer, but it reduces the probability that 2026 starts in an acute scarcity posture. For Serbia, this is important because the first quarter often sets the reservoir trajectory for the year. If reservoirs exit winter with strong levels, Serbia can arbitrage water across the spring–summer period, keeping imports low and preserving flexibility for peak hours.
A Serbia-centered base-case for 2026 therefore assumes hydro normalisation relative to the 2025 drought year, not because rainfall must be high, but because the probability-weighted expectation after an extreme year tends to revert toward the mean. In that base-case band, Serbia’s hydro output gravitates toward roughly 9.5–11.0 TWh for the year, with EPS hydro returning close to its ~10.6 TWh long-run average. In market terms, that output volume is less important than what it does to the price curve. Normal hydro pushes down the number of “import hours” and compresses peak spreads. It also improves ancillary services availability because hydro provides fast ramping and reserve in a way thermal units increasingly struggle to do economically.
An upside hydrology case for 2026 is a genuinely wet year that restores reservoirs early and sustains inflows through late spring. In that scenario Serbia can exceed the long-run band, with hydro plausibly moving toward 11.5–13.0 TWh. The economic effect is two-stage. First, Serbia reduces thermal dispatch and imports, improving the external balance and lowering pressure on electricity tariffs. Second, Serbia gains export optionality into neighboring deficit zones in peak periods, which can generate revenue even if domestic prices are lower on average because export volumes and balancing value rise. The trading implication is that Serbia’s capture price can remain attractive despite a lower average price environment because hydro can be timed into regional scarcity hours rather than dumped into off-peak.
A downside hydrology case for 2026 is a continuation of stress conditions into summer, producing another low-inflow year. In that scenario Serbia’s hydro can slip back into the 7.5–9.0 TWh band, similar to or only modestly better than the 2025 drought profile. This is the scenario that matters for macro risk, because it is the one that converts hydrology into inflation and fiscal pressure. Low hydro forces higher thermal dispatch, higher imports, and higher day-ahead prices. It also increases balancing costs because the system loses flexible hydro just as solar and wind variability must be managed. In 2026, that downside case is more dangerous than in earlier years because the European price floor is higher and volatility is structurally higher due to larger shares of variable renewables in the region.
To translate these hydrology bands into macro-financial indicators, the key variable is the marginal import requirement in peak months. Serbia’s import exposure is not linear with hydro shortfall. When hydro falls below a certain threshold, imports rise sharply because thermal and cross-border flows become binding constraints. A rough but useful stress metric is that a hydro shortfall of 2–3 TWh versus the normal band typically forces Serbia into a higher import posture for a material share of the year’s tight hours. If the “import-hour” price is €110–150/MWh in a CO₂-supported environment, a 2 TWh incremental import requirement translates into an external cash cost of €220–300 million, while 3 TWh pushes toward €330–450 million, before considering hedging, bilateral contracting, and capacity constraints. The macro implication is that drought years can materially widen the current account deficit and raise fiscal pressure if the government chooses to smooth retail tariffs.
Market price trends in 2026 amplify this. With CO₂ around €90–92/t, the marginal thermal cost in the region is structurally higher, and the day-ahead curve becomes more convex in tight hours. Hydro benefits from convexity because its value rises faster than average prices when volatility increases. In other words, the same MWh can be worth materially more when sold as peak-shaping and reserve than when sold as baseload. This is why, in 2026, hydro-heavy utilities should be assessed less on annual volume alone and more on how much “dispatchable water” they have in the hours when the region is short.
That dispatchable water increasingly monetises through trading and balancing. Balancing markets and ancillary service procurement across the region are evolving, and cross-border balancing is becoming more valuable as the grid integrates more wind and solar. Hydro’s core advantage is that it can deliver ramping and reserve without the fuel cost volatility that thermal plants face. In a normal hydro year, Serbia can supply more secondary and tertiary reserves domestically and reduce the cost of balancing imports. In a dry year, Serbia not only loses energy; it loses reserve, and that reserve must be procured at higher cost from thermal units or imported through interconnectors. This is where hydro becomes a system cost lever, not just a generation asset.
The SEE regional comparison reinforces Serbia’s role. Albania, for example, is structurally hydro-dominant and therefore experiences even greater volatility. The Drin cascade alone is around 1,350 MW under KESH management, with an average annual production of roughly 4,000 GWh, meaning Albania’s supply-security and price profile can swing dramatically with hydrology. When Albania is wet, it exports and depresses regional prices; when it is dry, it imports and pulls prices up. Romania, with larger and more diversified generation, often acts as a stabiliser, while Bulgaria’s hydro interacts with nuclear and thermal dispatch to shape cross-border flows. Serbia sits between these systems, so its hydro outcome affects not only domestic prices but also the marginal flows into Bosnia and Herzegovina, North Macedonia, Montenegro, and parts of Hungary and Romania depending on corridor constraints and hourly spreads.
A practical 2026 forecast for trading behavior therefore follows directly from the hydrology bands. In the base-case 9.5–11.0 TWh Serbia hydro year, Serbia’s system tends to be neutral-to-modest exporter in shoulder seasons and modest importer in tight winter evenings, with balancing costs manageable and the forward curve less prone to stress spikes. In the upside 11.5–13.0 TWh year, Serbia can export more consistently in spring and early summer, the day-ahead price curve flattens, and ancillary service availability improves, which reduces the system cost of integrating wind and solar. In the downside 7.5–9.0 TWh year, Serbia becomes a more consistent importer in peak months, volatility rises sharply, and balancing costs increase, with a higher probability of policy intervention through tariff smoothing.
For investors and policymakers, the most important micro indicator to watch through early 2026 is reservoir trajectory after winter. If reservoirs exit Q1 strong, the probability-weighted forecast shifts upward and Serbia’s import-risk premium compresses. If reservoirs exit Q1 weak, the probability-weighted forecast shifts toward the downside band and the market begins pricing higher summer scarcity spreads. The second key micro indicator is the CO₂ and gas forward regime. With CO₂ already near €90–92/t, any additional upward pressure raises the thermal floor and increases the marginal value of hydro flexibility even if hydro volumes are only average.
The economic conclusion for Serbia in 2026 is that hydro is less a “renewable generation share” story and more a macro stabilisation story. In a normal or wet year, hydro reduces imports, lowers inflation transmission, and strengthens utility cash flow through both energy and balancing revenues. In a dry year, hydro shortfall quickly becomes an external-balance and fiscal issue because higher imports and higher price volatility force either tariff pass-through or budget-supported smoothing. The market in 2026 will price this more aggressively than it did a decade ago because volatility is structurally higher and the thermal cost floor is structurally higher. That is why the 2026 hydro forecast must be treated as a probability band with explicit macro-financial implications rather than a single production estimate.
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