Montenegro’s 2025 electricity import bill has become one of the strongest warnings in the regional power market. State-owned utility EPCG imported 1,341 GWh of electricity during the year and spent about €142 million on market purchases. The cause was not a single short-term imbalance. It was the combined effect of thermal outage, weak hydrology and demand running above plan. The prolonged shutdown of TPP Pljevlja, which was offline for more than eight months during environmental modernisation, forced EPCG to replace around 780 GWh of output that would normally have come from a plant covering about 40% of Montenegro’s annual electricity demand.
Hydrology added a second layer of pressure. EPCG had to secure another 320 GWh because of lower hydropower production. HPP Perucica, with installed capacity of 307 MW, reached only 64% of planned output, while HPP Piva, at 342 MW, achieved around 75% of target. Consumption reached 2,909 GWh, about 4% above forecast, adding roughly 73 GWh of additional import needs. For a small system, these deviations are not marginal. They move directly into cash flow, working capital and sovereign energy security.
The financial impact was immediate. EPCG posted a €92 million net loss in 2025, compared with an €11 million profit a year earlier. The company’s recovery in 2026 has been equally revealing: first-quarter profit rose to €36.5 million from €10.2 million, and management expects full-year earnings of around €38 million, with projections rising toward €143 million by 2030. Those numbers show how sensitive Montenegro’s power-sector earnings are to domestic generation availability and import exposure.
The core risk is structural. Montenegro has attractive renewable resources, a strategic position on regional corridors and a transmission system connected to Bosnia and Herzegovina, Serbia, Albania and Italy. But its domestic balance still depends heavily on the availability of a single thermal asset and two large hydropower plants. When one large block is offline and hydro underperforms, EPCG becomes a buyer in a regional market where prices can move sharply higher during heatwaves, outages or evening scarcity.
That is why grid investment and generation diversification are not separate themes. CGES is already moving on transmission upgrades, including the €39 million Perucica and Pljevlja substation modernisation programme, which could create capacity for around 550 MW of new renewable connections. The separate cross-border upgrade using high-temperature low-sag conductors is expected to lift the Trebinje–Perucica–Podgorica–Vau i Dejes corridor to around 600 MW. These projects matter because import dependence can only be reduced if new renewable capacity can actually connect and if cross-border flow capacity can be used efficiently.
EPCG’s own investment programme points in the same direction. The company is expanding the Gvozd wind farm with a 21 MW second phase, backed by a €25 million EBRD loan, while also investing around €40 million in the A8 unit at HPP Perucica, adding 58.5 MW. These assets will not remove market risk, but they reduce the concentration risk that became visible during Pljevlja’s downtime.
Montenegro’s 2025 import shock should therefore be read as a balance-sheet event, not just an operational episode. A power system with high single-asset dependence pays for outages twice: first through lost domestic production, then through purchases at regional market prices. The next phase of Montenegro’s energy strategy will be judged by its ability to convert wind, solar, hydro upgrades and grid CAPEX into lower import volatility and stronger EPCG earnings quality.
