EPS Output Falls Again, Serbia Covers Gap With Imports
Serbia's state power utility produced nearly 15% less electricity over three years, and the shortfall is increasingly covered by imports during a summer heatwave and record demand.
- EPS produced 30,356 GWh of electricity in 2025, nearly 15% less than in 2023.
- The shortfall is increasingly covered by imports during a summer heatwave and record demand.
- Coal deliveries from the Kolubara basin fell from about 100,000 to just over 60,000 tonnes per day.
- The SRCE watchdog blames poor mine management and delayed plant overhauls for the decline.
Elektroprivreda Srbije, Serbia’s state power utility, produced 30,356 gigawatt-hours of electricity in 2025, nearly 15% less than the 34,720 gigawatt-hours it generated in 2023, and the shortfall is increasingly covered by imports. The trend is flagged by SRCE, an organisation that tracks the domestic energy system.
The decline is not a one-off. After 34,720 gigawatt-hours in 2023, output fell to 31,861 gigawatt-hours in 2024 and then to 30,356 in 2025. That is a continuous slide even though the new B3 unit at the Kostolac thermal plant, with a capacity of 350 megawatts, came online in the meantime and was meant to lift the system’s available capacity. Instead of growth, the balance shows a gap that is being closed by buying power on the market.
Why is output falling and who pays the difference?
Coal is the key reason. Deliveries from the Kolubara mining basin fell from about 100,000 tonnes per day to just over 60,000, while the quality of the coal reaching the Nikola Tesla thermal power plant, the core of the EPS generation portfolio, has also deteriorated. When the fuel is both scarcer and weaker, the units run below their design output and hourly generation drops.
SRCE traces the causes to poor management of the mines, delayed plant overhauls and inadequate planning. These are operational problems rather than market ones: they stem from how coal logistics and maintenance are run, not from an external shock beyond the company’s control. The gap between generated and required energy is ultimately paid by EPS through imports, and the cost of those imports feeds through to households and businesses via their bills.
A comparison with earlier years shows the scale. A loss of nearly 15% of output over three years is not statistical noise but a structural decline that shifts the position of EPS: from a net exporter in years with good hydrology and full mines, the company becomes a net buyer in the critical months.
Imports at the most expensive moment
The drop in production coincides with a summer heatwave and high demand, when regional electricity prices are typically at their peak. Air conditioners and cooling systems break consumption records in July, and that is exactly when the domestic system has the least of its own generation to cover them. Purchases are therefore made when the kilowatt-hour is most expensive, making imports doubly unfavourable, both in volume and in price.
For a system that leaned on cheap domestic coal as a comparative advantage for decades, switching to imported energy in peak months changes the whole economic logic. Supply stability remains, because the shortfall is covered, but the price of that stability rises. The question is no longer whether there is power, but how much it costs that an ever larger share of it has to be bought from abroad.
Does the current cost of imports worry you more, or the fact that domestic production has shrunk for the third year running?
