The electricity balance for Serbia projects 6,931GWh of imports in 2026, about 14% lower than in 2025. Exports are forecast at 7,410GWh, roughly 2% higher than the previous year. On that basis, Serbia would finish the year with a physical net surplus of around 479GWh.
The projected surplus does not indicate that imported power is unnecessary. The small difference between exports and imports reflects large cross-border exchanges used to cover hourly production gaps and to respond to thermal-plant availability, hydrology conditions and renewable variability, alongside shifting regional prices.
Import volumes versus physical net position
Gross imports are estimated at about 23% of projected final electricity consumption of 29,972GWh. Combined trade flows in both directions are expected to total close to 14.34TWh. This volume profile places Serbia in a role as a regional trading, transit and balancing market.
The commercial outcome depends more on the prices of imports and exports than on the annual net position. Electricity can be exported when hydro output is high, wind generation is favourable or domestic consumption is lower, then repurchased during winter evenings, drought periods or outages at higher prices.
A net exporter in physical terms can still face an unfavourable financial trading result. The key driver is the spread between the average export price and the cost of electricity imported during deficit hours.
Wholesale price exposure and procurement cost scenarios
Using an illustrative average import price of €80/MWh, Serbia’s planned gross imports would be valued at approximately €555m. At €100/MWh, the value rises to about €693m, and at €130/MWh it reaches approximately €901m. These figures are scenario values rather than forecasts of the actual import bill.
Purchases are executed through bilateral contracts, exchanges, balancing arrangements and different delivery products. The calculation nonetheless indicates the scale of Serbia’s exposure to regional wholesale price levels.
An additional €10/MWh across the planned import volume would add roughly €69m to gross procurement expenditure. A €20/MWh increase would raise costs by about €139m, before considering hedging, export revenues and the timing of individual transactions.
Operational drivers for Elektroprivreda Srbije imports
Elektroprivreda Srbije (EPS), the dominant producer and supplier, treats electricity imports as both an operational tool and a liquidity risk. EPS’s generation mix remains centred on lignite-fired thermal plants and hydropower, with wind and solar contributing but still at smaller levels.
Imports become necessary when lignite output, coal quality, thermal-unit availability or hydrological conditions deteriorate. They are also used commercially when electricity available in neighbouring markets is cheaper than the marginal cost of domestic generation.
The plan envisages reducing imports from about 8.1TWh in 2025 to 6.93TWh in 2026. That reduction depends on stronger domestic production and improved generating-unit availability, leaving limited room for underperformance.
Hydrology flexibility and thermal availability risks
A prolonged outage at one large thermal unit can create several hundred gigawatt-hours of replacement demand. If such an outage coincides with low temperatures or weak regional renewable output, EPS may need to buy during the most expensive market hours.
The wholesale price structure can amplify these costs. Imports during solar-rich afternoon periods may be relatively inexpensive, while purchases during cold, low-wind evening peaks are considerably more costly. For that reason, annual import volumes alone do not capture financial exposure without corresponding hourly price data.
Renewables growth changes import timing and price shape
Hydropower provides flexibility because reservoir plants can cover peak demand and react quickly to system conditions. Its effectiveness depends on water inflows and reservoir management, so weak hydrology can both reduce low-cost domestic production and increase reliance on expensive imports.
Lignite generation offers a firmer base but introduces risks tied to mining disruptions, lower coal quality, environmental constraints and ageing thermal units that can reduce availability. As a result, import exposure is linked not only to renewable development speed but also to the operational condition of existing assets.
The expansion of wind and solar will alter how imports are shaped over time, but the technologies are not interchangeable. Wind typically has a higher capacity factor and can generate during winter and overnight periods when solar output is unavailable, which can reduce some seasonal and evening import needs while still remaining weather-dependent for system value.
Differing roles of wind versus solar generation
Solar reduces daytime demand for thermal generation and imports, particularly in spring and summer. Large solar volumes can create midday surpluses without resolving evening deficits, leading to exports during low-priced solar hours followed by imports after sunset at higher prices.
This price-shape risk becomes more significant as renewable capacity grows. Serbia has reached around 1,232MW of installed wind and solar capacity compared with just over 400MW several years earlier, while its strategic target is about 3.5GW by 2030.
Batteries under a planned state solar programme
The planned 1GW state solar programme with battery storage could affect Serbia’s daytime electricity balance. The impact on import reduction depends on how large the storage component is and how it is dispatched.
Batteries can shift part of solar surplus into evening hours, reduce peak purchases and provide balancing services. They cannot cover prolonged winter shortages or several consecutive days of weak renewable generation unless storage duration and energy capacity are exceptionally large.
Ties with neighbouring markets and cross-border capacity limits
Serbia’s interconnection includes links with Hungary, Romania, Bulgaria, North Macedonia, Montenegro, Bosnia and Herzegovina, Croatia and Albania. This enables access to multiple generation systems combining nuclear, hydro, coal, gas, wind and solar resources across different markets.
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Categorising imports: scheduled purchases to transit flows
The analysis of Serbia’s import volumes should separate four components: scheduled commercial purchases, balancing energy, emergency assistance and transit-related flows. Combining these into a single annual number obscures differences in why cross-border exchanges occur.
Certain volumes reflect commercial optimisation or transit flows rather than domestic shortage conditions. Electricity may enter Serbia from one market and leave toward another as traders capture price differences while Serbia provides transmission routing.
Price formation links through HUPX via Hungary interconnector
[HUPX]
Southeast Europe pricing effects on industry procurement
The financial consequences extend beyond EPS because large industrial consumers receive offers partly tied to SEEPEX prices, regional forwards, balancing costs and suppliers’ assessment of import risk. Higher replacement costs ultimately appear in new commercial contracts even when regulated household tariffs adjust more slowly.
Sectors including steel, copper, cement, chemicals, mining and food processing face particular exposure because they cannot easily stop production during expensive hours. Their procurement strategies therefore need to account for hourly and seasonal risks similar to those affecting the national system.
PPA design considerations for solar-only versus wind profiles
A diversified wind-solar portfolio combined with grid supply, flexible consumption and appropriately sized battery storage is described as a route toward reducing exposure during expensive periods. The relevant measure is not only the share of annual demand contracted from renewables but also the residual hourly position left open to market prices.
Carbon documentation implications for exporters serving European customers
Sensitivity around a projected 479GWh net-export outcome
The expected net-export position of around 479GWh should not be treated as insulation from external markets because it represents only about 1.6% of projected final consumption. The balance remains sensitive to relatively small changes in domestic generation or demand levels.
A weaker hydrological year, delayed thermal overhaul or major generating-unit failure could remove the projected surplus quickly. In such circumstances imports could rise above 6.93TWh, potentially during periods when regional prices are elevated.
Avoiding involuntary high-price hour imports as strategic focus shifts remain within balance logic
The strategic objective described is not elimination of electricity imports because complete self-sufficiency would require costly generation and reserve capacity that might remain underused under normal conditions. Interconnection supports access to cheaper electricity while enabling outage management and participation in regional trade.
The more important objective stated is reducing involuntary imports during high-price hours through reliable thermal generation during transition periods, disciplined hydro management, a balanced wind-and-solar portfolio supported by storage where needed. Grid infrastructure strength and flexible industrial demand are also identified as factors affecting residual exposure despite an annual net-export position.
