Serbia expects to import approximately 6.93TWh of electricity in 2026, confirming that cross-border purchases remain an essential part of the country’s power-market structure even when annual exports exceed imports.
The official electricity balance projects imports of 6,931GWh, about 14% lower than in 2025, and exports of 7,410GWh, roughly 2% higher. Serbia would consequently end the year with a modest physical net surplus of around 479GWh.
That surplus does not mean the country is independent of imported electricity. The narrow gap between exports and imports shows that Serbia exchanges large volumes with neighbouring markets to manage hourly production deficits, thermal-plant availability, hydrology, renewable variability and changing regional prices.
Gross imports are equivalent to around 23% of projected final electricity consumption of 29,972GWh. Combined cross-border trade in both directions should approach 14.34TWh, giving Serbia an increasingly important role as a regional trading, transit and balancing market.
The commercial outcome will depend less on the annual net position than on the prices at which Serbia imports and exports. Electricity may be exported during periods of high hydro production, favourable wind output or lower domestic consumption, only to be repurchased during winter evenings, droughts or outages at substantially higher prices.
A country can therefore be a net exporter in physical terms while recording an unfavourable financial trading result. The central variable is the spread between the average export price and the cost of electricity imported during deficit hours.
At an illustrative average import price of €80/MWh, Serbia’s planned gross electricity imports would be worth approximately €555m. The value rises to about €693m at €100/MWh and approximately €901m at €130/MWh.
These are scenario values rather than a forecast of the actual import bill. Purchases are made through bilateral contracts, exchanges, balancing arrangements and different delivery products. The calculation nevertheless illustrates the scale of Serbia’s exposure to regional wholesale prices.
Every additional €10/MWh across the planned import volume would add approximately €69m to gross procurement expenditure. A €20/MWh increase would raise the cost by roughly €139m, before accounting for hedging, export revenues and the timing of individual transactions.
For Elektroprivreda Srbije, the country’s dominant producer and supplier, electricity imports are both an operational tool and a major liquidity risk. EPS’s generation portfolio remains centred on lignite-fired thermal plants and hydropower, with wind and solar making a growing but still smaller contribution.
Imports become necessary when lignite production, 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 planned reduction in imports from approximately 8.1TWh in 2025 to 6.93TWh in 2026 depends on stronger domestic production and improved generating-unit availability. The margin for underperformance remains limited.
A prolonged outage at one large thermal unit can create several hundred gigawatt-hours of replacement demand. When that outage coincides with low temperatures or weak regional renewable production, EPS may be forced to purchase electricity during the most expensive market hours.
The cost is amplified by the structure of wholesale prices. Imports during solar-rich afternoon periods can be relatively inexpensive. Imports during cold, low-wind evening peaks are considerably more costly. Annual import volumes therefore reveal little about the true financial exposure without corresponding hourly price data.
Hydropower gives Serbia valuable flexibility because reservoir plants can cover peak demand and respond rapidly to system conditions. Its contribution, however, depends on water inflows and reservoir management. Weak hydrology can simultaneously reduce low-cost domestic production and increase the need for expensive imports.
Lignite generation provides a firmer production base but carries its own risks. Mining disruptions, lower coal quality, environmental constraints and ageing thermal units can reduce availability. Serbia’s import exposure is consequently linked as much to the operational condition of its existing fleet as to the speed of new renewable development.
The expansion of wind and solar will gradually change the shape of imports, but the two technologies should not be treated as equivalent.
Wind generation typically has a higher capacity factor and can produce during winter, overnight and in periods when solar output is unavailable. Its production profile can therefore reduce some of Serbia’s more expensive seasonal and evening imports. Wind also contributes differently to regional balancing and system value, although output remains weather-dependent.
Solar reduces daytime demand for thermal generation and imports, particularly during spring and summer. Large volumes of solar can, however, create midday surpluses without resolving evening deficits. Serbia may export electricity during low-priced solar hours and import it back after sunset at a higher price.
This price-shape risk becomes more important as renewable capacity grows. Serbia has reached approximately 1,232MW of installed wind and solar capacity, compared with just over 400MW several years ago, while the strategic target is around 3.5GW by 2030.
New capacity should reduce the requirement for fossil-based generation and lower some import needs. The actual result will depend on technology mix, grid availability, storage capacity, curtailment and the operational flexibility of EPS’s thermal and hydro portfolio.
The planned 1GW state solar programme with battery storage could materially affect Serbia’s daytime electricity balance. Its contribution to import reduction will depend on how the storage component is sized and dispatched.
Batteries can move part of the 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.
The economics of the programme should therefore be measured against avoided imports during high-price hours rather than only annual renewable production. One megawatt-hour discharged during an evening peak may be materially more valuable than one megawatt-hour generated when regional markets are oversupplied.
Serbia’s position is strengthened by its extensive interconnection with Hungary, Romania, Bulgaria, North Macedonia, Montenegro, Bosnia and Herzegovina, Croatia and Albania. This gives market participants access to several generation systems with different combinations of nuclear, hydro, coal, gas, wind and solar.
Hungary connects Serbia with Central European price formation and the liquid HUPX market. Romania and Bulgaria add exposure to nuclear, hydro and renewable generation. Montenegro and Bosnia and Herzegovina introduce strong hydrological variation, while North Macedonia and Albania provide additional north-south trading routes.
Cross-border access allows Serbia to purchase electricity when neighbouring prices are lower, even when domestic generation could theoretically meet demand. Not all imports should therefore be interpreted as evidence of an energy shortage.
Some volumes represent commercial optimisation, transit flows or simultaneous trading across different borders. Electricity can enter Serbia from one market and leave towards another, with traders capturing price differences and Serbia providing the transmission route.
The limiting factor is available cross-border capacity. Transmission rights become more valuable during regional shortages, precisely when energy prices are also rising. The delivered cost of imported electricity consequently includes both the energy price and the cost of securing transmission capacity.
Congestion can prevent Serbia from accessing the cheapest neighbouring source. Even when lower-priced electricity exists elsewhere in Southeast Europe, insufficient capacity on the relevant border may force purchases through a more expensive route.
The country’s imports should therefore be analysed through four separate components: scheduled commercial purchases, balancing energy, emergency assistance and transit-related flows. Combining them into one annual number hides the different economic reasons behind cross-border exchanges.
The financial consequences extend beyond EPS. Large industrial consumers receive electricity offers based partly on 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.
Steel, copper, cement, chemicals, mining, food processing and other continuous-process industries are particularly exposed because they cannot easily stop production during expensive hours. Their electricity procurement strategies must account for the same hourly and seasonal risks faced by the national system.
Long-term power purchase agreements can reduce part of this exposure, but contract design is critical. A solar-only PPA may cover daytime consumption while leaving the buyer exposed during winter evenings. Wind provides a different and often more valuable generation profile but cannot guarantee constant supply.
A diversified wind-solar portfolio, combined with grid supply, flexible consumption and appropriately sized battery storage, offers a more credible route towards reducing exposure to imports during expensive periods. The relevant measure is not simply the percentage of annual demand contracted from renewable sources, but the residual hourly position left open to the market.
For exporters serving European customers, electricity sourcing also has a carbon and documentation dimension. Serbia’s thermal-heavy generation mix means that the origin, metering and contractual allocation of renewable electricity increasingly influence product-carbon reporting and commercial access to lower-carbon supply chains.
Serbia’s expected 479GWh net-export position should therefore not be presented as proof that the electricity system is insulated from external markets. It represents only about 1.6% of projected final consumption, leaving the balance sensitive to relatively small changes in domestic generation or demand.
A weaker hydrological year, delayed thermal overhaul or major generating-unit failure could eliminate the projected surplus quickly. Imports would then rise above 6.93TWh, potentially during a period of elevated regional prices.
Better hydrology, stronger lignite and thermal performance, lower consumption or faster renewable commissioning could increase exports and reduce purchases. Even in such a year, imports would remain commercially useful whenever neighbouring electricity is cheaper than domestic production.
The strategic objective is not to eliminate electricity imports. Complete self-sufficiency would require costly generation and reserve capacity that might remain underused during normal conditions. Interconnection allows Serbia to access cheaper electricity, manage outages and participate in regional trade.
The more important objective is to reduce involuntary imports during high-price hours. That requires reliable thermal generation during the transition, disciplined hydro management, a balanced wind-and-solar portfolio, storage, stronger grid infrastructure and more flexible industrial demand.
Serbia’s 6.93TWh import plan is therefore a measure of system flexibility and a warning about residual exposure. The country can remain a net exporter over the full year while still depending heavily on regional electricity during critical hours. The financial strength of that position will be determined by the timing and price of cross-border transactions, not by the annual physical balance alone.
