Montenegro continues to have some of the lowest household electricity prices in Europe, with the average final tariff standing at 9.98 euro cents per kWh in 2025, despite rising investment requirements, electricity import costs and major works at the country’s power facilities.
According to energy regulator REGAGEN, Montenegro’s household electricity price was around one-third of the 28.96 cents/kWh EU average. Only Turkey, Georgia, Kosovo and Bosnia and Herzegovina recorded lower prices in the regulator’s comparison. Neighbouring markets were more expensive, with household electricity averaging 11.61 cents/kWh in North Macedonia, 11.75 cents in Albania and 11.90 cents in Serbia. Croatia recorded 16.58 cents, Slovenia 21.21 cents and Greece 23.78 cents. Hungary, the EU member with the lowest price in the comparison, stood at 10.82 cents/kWh.
Household electricity prices remain broadly stable
Montenegro’s household electricity price has changed relatively little for around 15 years, despite fluctuations in European wholesale prices, network investment costs and environmental compliance expenses. The state-owned utility EPCG has indicated that it does not plan to raise electricity prices for customers in 2026.
Approximately half of a typical household electricity bill represents electricity supplied by EPCG through higher- and lower-tariff periods. The remainder consists of transmission and distribution charges, other regulated components and VAT.
Pljevlja shutdown drives 2025 losses
The financial pressure on the electricity system became particularly clear in 2025, when EPCG recorded a loss of approximately €92.1mn. The main operational disruption was the shutdown of the Pljevlja thermal power plant, which remained unavailable for around eight months during reconstruction and environmental works.
With Pljevlja out of operation and hydrological conditions weaker, EPCG had to replace a substantial amount of domestic generation with imported electricity. The utility spent approximately €146mn on electricity imports in 2025, paying an average of about €106/MWh. Electricity supplied to households through the energy component of the regulated bill was priced at approximately €55/MWh. EPCG also obtained around €78.5mn in dedicated borrowing to finance electricity imports.
EPCG returns to profit in early 2026
The company’s financial performance improved sharply when generation conditions recovered. By the end of the first quarter of 2026, EPCG reported approximately €36.5mn in profit, €53.4mn in EBITDA and a positive energy balance of approximately 453 GWh. The results nevertheless demonstrate the sensitivity of EPCG’s earnings to hydrology, thermal generation, electricity imports and regional wholesale prices. The Pljevlja reconstruction also improved environmental performance. EPCG reported significant reductions in measured SO₂ and NOx emissions, and the plant subsequently returned to operation.
CBAM affects electricity export revenues
The EU Carbon Border Adjustment Mechanism (CBAM) has added another cost factor for electricity exports towards the European market. EPCG estimated that CBAM reduced the value of electricity sold during the first quarter of 2026 by approximately €13mn. The utility reported an average selling price of approximately €103.65/MWh during the period, while the positive difference between electricity sales and purchases was around €48mn.
EPCG plans €646mn energy investment programme
EPCG has identified a direct project portfolio of approximately 639 MW/MWp, with planned investment of around €646mn. The programme includes solar, wind, hydropower upgrades and battery storage, diversifying the sources of new generation and system flexibility. Solar installations have expanded particularly rapidly. By April 2026, EPCG’s solar programmes covered approximately 9,786 buildings and represented 111.7 MWp of installed photovoltaic capacity.
The completed Solari 3000+/500+ programme represented around 34 MWp, while approximately 54.7 MWp had been installed through Solari 5000+, with additional capacity planned. EPCG has reported more than 10,000 users across its solar programmes. The original Solari 5000+ programme envisaged approximately 70 MW of capacity and investment of around €70mn.
Solar returns depend on prices and grid constraints
An indicative 70 MW solar portfolio, with investment of €60mn–€70mn, could generate close to 100 GWh annually at an annual yield of approximately 1,400–1,500 MWh per installed MW. A base case based on realised electricity values of €60–€65/MWh would support a project return of approximately 6–8%. Higher capture prices and lower installed costs could lift returns towards 9–11%.
Curtailment would have a direct effect on project economics. A 5% loss of annual solar output could reduce equity returns by around 0.5–1 percentage point, depending on leverage and tariff structure. A 10% curtailment level combined with weaker midday prices could reduce equity IRR by approximately 2 percentage points or more. A 12–18-month grid-connection delay could reduce equity IRR by roughly 1.5–3 percentage points, as capital would remain committed without producing revenue.
Gvozd wind complex expands
The Gvozd wind complex is expected to reach approximately 75 MW after expansion. The EBRD initially provided €82mn in financing for the original project and later approved another €26mn for the capacity extension. The expanded project is expected by the EBRD to produce approximately 186 GWh annually, while EPCG’s broader assumptions for Gvozd I and II indicate approximately 226.8 GWh of annual generation from roughly 75.6 MW.
An investment envelope of approximately €105mn–€115mn for about 75 MW, combined with annual generation of 190–225 GWh and electricity prices of €70–€80/MWh, could support project-level returns of around 8–11%. Under stronger capture prices, high availability and limited curtailment, equity returns could reach the low double digits. Wind is less exposed than solar to daytime price cannibalisation, although transmission capacity and grid-connection timing remain relevant. A 3–5% curtailment scenario would have a visible but manageable effect on project economics. A 12-month grid delay could reduce equity IRR by around 1 percentage point, while an 18-month delay, particularly alongside interest during construction and cost inflation, could reduce returns by approximately 1.5–2 percentage points.
Perućica expansion adds 58.5 MW
EPCG plans an eighth generating unit at HE Perućica, providing approximately 58.5 MW of additional capacity and around 50 GWh of annual energy production. The project has €40mn in KfW financing, with a 15-year maturity and five-year grace period. The additional hydropower capacity would provide generation flexibility, allowing electricity production to shift towards higher-priced periods while supporting the integration of variable solar and wind generation.
Željezara battery project targets system flexibility
EPCG’s proposed Željezara battery project is modelled at approximately 60 MW/240 MWh, with investment of around €48mn. Project assumptions indicate potential annual revenue of approximately €16.7mn and EBITDA of close to €16.1mn.
The projected results depend on future spreads between low- and high-priced electricity periods, balancing-market revenues and regulatory treatment. The combination of renewable generation, hydropower and battery storage is intended to reduce EPCG’s exposure to costly electricity imports while increasing domestic generation capacity and system flexibility.
Transmission revenues to reduce future consumer charges
Transmission infrastructure also provides a potential offset for consumers. CGES generated revenues from transmission infrastructure and the submarine electricity interconnector with Italy during 2022–2025 that exceeded the regulator-approved requirement by approximately €100mn. Under Montenegro’s regulatory methodology, that surplus is expected to reduce the transmission component paid by domestic consumers during the 2027–2029 regulatory period.
Montenegro’s household electricity tariff therefore remains at 9.98 cents/kWh, substantially below both the European Union average and prices in neighbouring markets, while EPCG simultaneously faces major investment requirements and continued exposure to generation and electricity-market costs.
