Montenegro’s state-controlled power utility Elektroprivreda Crne Gore entered 2026 with a much clearer picture of what went wrong in the previous year. The company imported 1,341 GWh of electricity in 2025, paying about €142mn for power that had to replace lost domestic generation, weaker hydrology and higher-than-planned consumption. For a small electricity system built around one coal plant and two large hydro assets, the scale of the import bill was not just an accounting shock. It was a stress test for the country’s entire generation model.
The central trigger was the prolonged outage of TPP Pljevlja, Montenegro’s only thermal power plant and normally one of the pillars of domestic supply. The plant was out of regular operation for more than eight months because of reconstruction works, including the ecological upgrade that has become central to Montenegro’s attempt to keep the asset technically and environmentally viable. EPCG said around 780 GWh of last year’s imports were directly linked to the suspension of production at Pljevlja, underlining how exposed the national balance becomes when a single baseload facility is removed from the system.
That exposure was amplified by hydrology. EPCG’s two main hydro plants, HPP Perućica and HPP Piva, did not deliver close to planned output. Perućica, with installed capacity of 307 MW, produced only around 64 per cent of planned volumes, while Piva, with 342 MW, reached roughly 75 per cent of its plan. Together, the two hydro assets normally provide flexibility and a natural hedge against import dependence. In 2025, they became part of the problem rather than the solution, forcing the company to buy an additional 320 GWh to compensate for weaker-than-expected inflows.
The result was a year in which EPCG faced pressure from all sides: a major thermal outage, weaker hydro generation, higher consumption and a market in which imported electricity could not be passed through fully to regulated domestic customers. Electricity consumption in Montenegro reached 2,909 GWh, or 104 per cent of the planned level, requiring another 73 GWh of imports. In a larger and more diversified power system, that would be uncomfortable but manageable. In Montenegro’s case, it pushed the company into one of the weakest financial years in its recent history.
EPCG reported a net loss of €92mn in 2025, reversing from a net profit of €11mn a year earlier. The swing was not caused by a single bad trading position or one-off cost. It reflected the structural mismatch between domestic tariff policy, import exposure and production concentration. When EPCG buys power on the regional or European market and sells to domestic customers under politically sensitive price conditions, the company effectively absorbs the difference. In 2025, that difference became too large to hide inside normal operating results.
The balance sheet showed the impact. Long-term borrowing costs rose to €141mn, compared with €96mn in 2024, while short-term liabilities increased to €192.5mn, from €111mn a year earlier. EPCG had to rely on new loans to finance imports and maintain supply continuity. In practical terms, the company used its balance sheet to protect consumers and the wider economy from the full cost of a difficult production year. That may have softened the immediate political and social impact, but it transferred the pressure into debt, liquidity and future capital allocation.
The deeper issue is that Montenegro’s electricity system still depends heavily on a narrow asset base. TPP Pljevlja typically produces about 40 per cent of the electricity consumed in the country. That makes its technical availability a national energy-security variable, not merely a corporate operating matter. When Pljevlja is running, EPCG has a much stronger domestic supply position. When it is offline, the company must lean on imports, hydrology and regional market liquidity. In a year of weak hydro conditions, the system quickly loses its buffer.
This matters for investors because EPCG is not only a utility. It is one of the most important state-linked corporate platforms in Montenegro, with implications for public finance, energy transition, industrial competitiveness and the country’s EU accession pathway. The government controls 98.5 per cent of the company, meaning EPCG’s financial performance has a quasi-sovereign dimension. A loss of €92mn does not automatically become a budget cost, but it affects the state’s room for manoeuvre, especially when the company must continue investing in generation, grid-linked projects and environmental compliance.
The investment programme did not stop during the difficult year. EPCG continued spending on the ecological reconstruction of TPP Pljevlja, renewable energy projects and preparation of future assets. That creates a delicate capital-allocation problem. The company needs to invest more aggressively in new capacity to reduce future import exposure, yet high import costs and debt growth can weaken precisely the financial base needed to fund that transition. For lenders and project partners, the question is no longer only whether Montenegro has renewable potential. It is whether EPCG and the wider system can sequence investments without creating a new layer of financial stress.
The renewable pipeline is therefore becoming more strategic. Projects such as Gvozd wind farm, solar developments around Slano, Krupac and the Željezara site, as well as preparatory work on hydro projects such as Kruševo and Otilovići, are no longer just energy-transition initiatives. They are part of a financial hedge against import dependence. Every additional megawatt of bankable domestic generation reduces the exposure to regional spot prices, hydrology risk and unexpected outages at legacy assets. But renewables also bring their own integration demands: balancing capacity, grid readiness, dispatch forecasting, storage and commercial structures capable of managing intermittency.
The 2025 result also highlights the importance of thermal-asset transition timing. Montenegro cannot treat TPP Pljevlja purely as a legacy coal plant scheduled for gradual political retirement, because the system still relies on it heavily. Nor can it ignore the environmental and EU-alignment pressure that comes with keeping the plant online. The ecological reconstruction is designed to extend operational viability, but the financial shock of its outage shows that future maintenance, compliance works or operational restrictions must be planned with much stronger replacement-capacity coverage.
EPCG’s improved first-quarter result in 2026, with net profit rising to €36.5mn from €10.2mn in the same period of 2025, suggests that the 2025 loss may not define the company’s medium-term trajectory. The government has indicated expectations that EPCG could return to a net profit of around €38mn this year, with profit potentially rising gradually toward €143mn by 2030. Those forecasts depend on several assumptions: the return of Pljevlja to regular operation, stronger hydrology, lower import requirements, controlled operating costs and the successful delivery of new generation assets.
For the Montenegrin power market, the lesson is direct. EPCG’s €142mn import bill was not simply the cost of one difficult year. It was the price of insufficient redundancy in a system where thermal generation, hydro variability and retail price policy remain tightly linked. The company can recover earnings when production normalises, but the strategic risk remains unless Montenegro accelerates the build-out of diversified domestic capacity, reinforces system flexibility and gives EPCG a clearer commercial framework for managing import-price shocks.
The country’s energy transition will therefore be judged less by headline renewable announcements and more by whether new projects materially reduce exposure to import bills of the type seen in 2025. Montenegro has strong hydro foundations, meaningful wind and solar potential, and a state utility with a central role in the market. What it lacks is a larger margin of safety. EPCG’s latest figures show that the cost of that missing margin is no longer theoretical. In 2025, it was measured in 1,341 GWh of imported electricity, €142mn of external power purchases and a €92mn loss that turned a generation problem into a balance-sheet warning.
