Montenegro continues to offer households some of the cheapest electricity in Europe, preserving a politically and economically important advantage even after a year in which the state-owned power utility absorbed heavy import costs, recorded a substantial loss and accelerated one of the largest investment programmes in the country’s energy sector in decades.
The average final household electricity price in Montenegro, including taxes and VAT, stood at 9.98 euro cents per kWh in 2025. That was roughly one-third of the 28.96 cents per kWh average across the European Union, according to Montenegro’s energy regulator REGAGEN. Only Turkey, Georgia, Kosovo and Bosnia and Herzegovina recorded lower household prices in the comparison used by the regulator.
Electricity in neighbouring markets was already more expensive. Average household prices were approximately 11.61 cents/kWh in North Macedonia, 11.75 cents in Albania and 11.90 cents in Serbia, while Croatia stood at 16.58 cents, Slovenia at 21.21 cents and Greece at 23.78 cents. Even Hungary, which maintained the lowest household electricity price among EU members in the comparison, was slightly above Montenegro at 10.82 cents/kWh.
The difference is unusually large for a country whose electricity system has faced rising investment requirements and considerable exposure to volatile regional wholesale markets. Montenegro’s household electricity price has changed little for roughly 15 years, despite substantial movements in European wholesale prices, network investment costs and the cost of environmental compliance.
EPCG has so far maintained that position in 2026. The state-owned utility has indicated that it does not plan to increase the price of electricity supplied to customers this year, extending a strategy that has effectively insulated households from much of the volatility seen elsewhere in Europe.
The sustainability of that model increasingly depends on what happens behind the retail tariff.
Around half of a typical household electricity bill relates to the energy supplied by EPCG through higher and lower tariff periods. The remainder includes transmission and distribution charges, other regulated components and VAT. That distinction gives Montenegro more flexibility than a simple comparison between wholesale and retail electricity prices might suggest, but it also means the financial burden of keeping final bills low is distributed across several parts of the energy system.
The pressure became particularly visible in 2025, when EPCG recorded a loss of approximately €92.1mn. The principal operational shock was the prolonged shutdown of the Pljevlja thermal power plant, which was unavailable for around eight months while reconstruction and environmental works were carried out.
Pljevlja is too large relative to Montenegro’s electricity system to disappear from the generation mix without consequences. With the plant unavailable and hydrology also weaker than required, EPCG had to replace a substantial volume of domestic production with imported electricity.
The company spent approximately €146mn purchasing electricity from abroad in 2025, paying an average of about €106/MWh, while electricity supplied to households through the energy component of the regulated bill was priced at roughly €55/MWh. EPCG also took approximately €78.5mn of dedicated borrowing to finance electricity imports.
The numbers expose the central tension in Montenegro’s electricity model. Low household tariffs are economically attractive for consumers and help moderate headline inflation, but they become expensive when domestic generation is disrupted and EPCG is forced to buy electricity in the regional market at prices substantially above those embedded in retail supply.
That exposure is magnified because Montenegro’s electricity system depends on a relatively concentrated portfolio. Large hydropower plants provide valuable low-cost and flexible generation, but output varies with rainfall. Pljevlja provides thermal baseload but creates carbon, environmental and regulatory exposure. Until recently, wind and solar capacity remained too small to materially alter the balance.
EPCG’s first-quarter performance in 2026 demonstrated how quickly that equation can reverse when generation conditions improve. The company reported approximately €36.5mn of profit by the end of March, EBITDA of about €53.4mn and a positive energy balance of approximately 453 GWh, compared with the severe deficit experienced during 2025.
This recovery does not eliminate the structural problem. It reinforces how sensitive EPCG’s earnings remain to hydrology, thermal availability, electricity imports and regional market prices.
The reconstruction of Pljevlja was therefore more than an environmental compliance project. The plant remains a critical part of security of supply even as Montenegro expands renewable generation. EPCG says emissions performance improved significantly after the reconstruction, with measured SO₂ and NOx emissions falling sharply relative to previous levels. The plant has subsequently returned to production, although its operating economics are becoming more complex as European carbon rules increasingly affect regional electricity pricing.
The European Union’s Carbon Border Adjustment Mechanism adds another layer of uncertainty. EPCG estimated that the introduction of CBAM reduced the value of electricity it sold during the first quarter of 2026 by approximately €13mn, because carbon-intensive electricity exported towards the EU market is indirectly discounted to reflect the cost faced by importers. EPCG reported an average selling price of approximately €103.65/MWh during the period and a positive difference between electricity sales and purchases of around €48mn.
For Montenegro, CBAM creates an unusual situation. Pljevlja may remain valuable for domestic energy security while simultaneously becoming less competitive as an export-oriented generating asset. That makes new renewable capacity increasingly important not simply for decarbonisation, but for protecting EPCG’s commercial margins.
The investment programme now under development is large relative to both EPCG and Montenegro’s electricity market. EPCG has identified a direct project portfolio of approximately 639 MW/MWp, representing investment of around €646mn. The programme spans rooftop and utility-scale solar, wind, hydropower upgrades and battery storage rather than relying on a single generation technology.
Solar has developed fastest in terms of distributed installations. By April 2026, EPCG’s solar programmes had reached approximately 9,786 buildings with 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 still planned. EPCG has reported more than 10,000 users across its solar programmes.
The original Solari 5000+ programme envisaged around 70 MW of capacity and an investment of approximately €70mn. Distributed solar has an important economic advantage for Montenegro because electricity is produced close to consumption and installations can be completed incrementally rather than waiting for a single large power plant.
Its system value, however, should not be confused with that of wind.
Solar production is concentrated around daytime hours and is increasingly correlated across installations. As penetration rises, Montenegro will face the same issue emerging elsewhere in southern Europe: large volumes of solar electricity arrive at similar times, pushing down midday prices and potentially creating local congestion.
An indicative investment case for a 70 MW solar portfolio costing €60mn–€70mn would therefore depend heavily on capture prices rather than headline wholesale averages. At an annual yield of roughly 1,400–1,500 MWh per installed MW, such a portfolio could generate close to 100 GWh annually. A base case using realised power values around €60–€65/MWh would support a project return broadly in the 6–8% range, while stronger capture prices and lower installed costs could lift returns towards 9–11%.
Curtailment becomes increasingly material above that level of penetration. A 5% loss of annual solar output can reduce equity returns by roughly 0.5–1 percentage point, depending on leverage and tariff structure, while 10% curtailment combined with weaker midday prices could cut equity IRR by around 2 percentage points or more. A 12–18 month grid-connection delay would have a similar effect, potentially reducing equity IRR by around 1.5–3 percentage points as capital remains committed without generating revenue.
Wind presents a different profile.
The Gvozd wind complex is expected to reach around 75 MW after expansion. The EBRD initially provided €82mn of financing for the original project and subsequently approved another €26mn for the capacity extension. The expanded project is expected to produce approximately 186 GWh annually according to the EBRD, while EPCG’s broader project assumptions for Gvozd I and II indicate approximately 226.8 GWh of annual generation from roughly 75.6 MW.
That implies a much higher capacity factor than solar and gives wind a different role in Montenegro’s generation portfolio. Wind output is less concentrated around midday and can complement both hydropower and solar production. Its curtailment risk should therefore be considered separately rather than extrapolated from photovoltaic projects.
Using a financing and investment envelope around €105mn–€115mn for approximately 75 MW, with output around 190–225 GWh, a normalised power-price environment of €70–€80/MWh could support a project-level return in roughly the 8–11% range, depending on operating costs and financing structure. Under an upside case involving stronger capture prices, high availability and limited curtailment, equity returns could move into the low double digits.
Wind is less vulnerable than solar to daytime price cannibalisation, but transmission capacity and connection timing remain relevant. A 3–5% curtailment scenario would have a manageable but visible impact on project economics. A 12-month grid delay could reduce equity IRR by around 1 percentage point, while an 18-month delay, particularly if combined with interest during construction and cost inflation, could reduce returns by approximately 1.5–2 percentage points.
Montenegro’s hydropower portfolio adds another element that pure solar-and-wind markets do not possess. EPCG plans an eighth generating unit at HE Perućica, with approximately 58.5 MW of additional capacity and an expected annual energy contribution of around 50 GWh. KfW financing amounts to €40mn, with a 15-year maturity and five-year grace period.
The value of the project is not simply its annual electricity production. Additional hydro capacity provides flexibility, enabling Montenegro to shift generation towards higher-priced hours and respond more effectively to intermittent solar and wind output.
Battery storage is intended to perform a similar function.
EPCG’s proposed Željezara battery project is modelled at approximately 60 MW/240 MWh, with investment of around €48mn. Company project assumptions indicate potential annual revenue of approximately €16.7mn and EBITDA close to €16.1mn, although those numbers are highly dependent on future spreads between low- and high-priced hours, balancing-market revenues and regulatory treatment.
Those economics illustrate the changing character of Montenegro’s electricity system. The next investment cycle is not only about adding megawatts. The value increasingly comes from deciding when electricity is generated, stored or sold.
This matters directly for household tariffs.
More domestic renewable generation lowers EPCG’s exposure to expensive imports, while hydro flexibility and battery storage can reduce the need to purchase electricity during the most expensive hours. Successful execution therefore provides the financial space needed to preserve comparatively low retail tariffs without repeatedly sacrificing EPCG’s balance sheet.
The opposite scenario is more difficult. A prolonged period of poor hydrology, another significant thermal outage or delayed renewable projects would leave EPCG exposed to imports while continuing to supply households at some of the lowest prices in Europe.
Transmission charges may provide some offsetting relief. CGES generated revenues from transmission infrastructure and the submarine electricity interconnector with Italy during 2022–2025 that exceeded the regulator-approved requirement by around €100mn. Under Montenegro’s regulatory methodology, that surplus is expected to reduce the transmission component charged to domestic consumers during the 2027–2029 regulatory period.
This could allow the final electricity bill to remain relatively stable even as investment requirements elsewhere in the system increase. The benefit, however, comes from previously generated transmission income rather than a structural reduction in the cost of producing electricity.
Montenegro is consequently entering a period in which one of Europe’s lowest household electricity prices will coexist with one of the largest energy investment programmes the country has undertaken.
The present 9.98 cents/kWh household price is valuable economically. Cheap electricity supports disposable household income, moderates inflation and improves the operating environment for domestic businesses. It is also increasingly disconnected from the replacement cost of new generation, the volatility of imported electricity and the financing requirements associated with grid modernisation.
EPCG’s ability to maintain that gap will increasingly depend on execution rather than political willingness alone. The utility has already demonstrated the cost of generation shortages through its €146mn import bill and €92mn loss in 2025. The rapid return to profitability in early 2026 showed the corresponding value of domestic generation.
The investment arithmetic is therefore becoming clearer. Wind brings higher capacity factors and comparatively favourable system value. Solar offers rapid and scalable capacity but faces greater capture-price and curtailment risk as penetration rises. Hydropower remains Montenegro’s key flexibility asset, while storage provides the mechanism needed to convert intermittent renewable generation into electricity available when prices and system demand are highest.
Keeping electricity close to 10 cents/kWh for households will be considerably easier with several hundred megawatts of additional domestic generation and storage operating on time. Without that capacity, the difference between what EPCG pays on regional markets and what Montenegrin households pay at home will remain one of the most important financial exposures in the country’s energy system.
