Montenegro’s Pljevlja thermal power complex generated around 442,000 MWh of electricity between June and August, accounting for about 65% of EPCG’s total production during the period and underscoring the country’s continued dependence on coal despite an expanding renewable-energy pipeline.
The plant operated at an average output of around 200 MW, producing approximately 4,800 MWh per day, according to data released by state power utility EPCG.
EPCG valued the three-month output at more than €51 million.
Buying the same volume on Hungary’s HUPX electricity market would have cost around €57.4 million at prevailing prices, according to the utility, before accounting for cross-border transmission capacity and other import-related costs.
The comparison highlights Pljevlja’s continuing economic importance to Montenegro’s power system, particularly during periods of weak hydropower production.
Montenegro has substantial hydro capacity, but generation can vary sharply depending on rainfall and reservoir conditions.
During dry periods, the country can become significantly more reliant on electricity imports unless Pljevlja is operating.
That exposure makes the thermal plant both a system-security asset and one of Montenegro’s largest long-term energy-policy challenges.
Coal generation will face increasing pressure as Montenegro aligns with European Union climate and carbon-market rules.
The country is preparing for deeper integration with the European electricity market while simultaneously developing wind, solar and storage projects designed to reduce dependence on both coal and imported electricity.
EPCG is currently expanding its renewable portfolio, including the Gvozd wind complex.
Construction of the 21-MW Gvozd 2 extension is under way, while additional solar and battery projects are planned.
But the latest Pljevlja figures show the scale of the replacement challenge.
Gvozd 2 is expected to produce around 63 GWh annually, compared with the 442 GWh generated by Pljevlja in only three summer months.
Replacing coal therefore requires not only additional renewable capacity but also storage, grid reinforcement and sufficient flexible generation to manage periods of weak wind, solar or hydro output.
The economics will become increasingly important as carbon costs rise.
Montenegro is not yet fully exposed to the EU Emissions Trading System, but the country’s accession process and regional carbon-market reforms point toward progressively higher costs for carbon-intensive generation.
The Carbon Border Adjustment Mechanism also increases the commercial value of verifiable low-carbon electricity for companies exporting electricity-intensive products into the European Union.
That creates a strategic tension for EPCG.
Pljevlja currently protects the company and the national system against high wholesale prices and hydrological risk, yet continued reliance on the plant could become progressively more expensive as carbon pricing and environmental obligations tighten.
EPCG’s own comparison with HUPX illustrates the current value of domestic generation.
The utility calculated that importing the equivalent volume would have cost at least €6 million more before transmission and congestion charges.
That does not include the environmental and future carbon liabilities associated with operating the coal plant, however.
The central policy challenge is therefore timing.
Closing or sharply reducing output from Pljevlja before sufficient replacement capacity is available could increase import dependence and wholesale-price exposure.
Keeping it operating for too long could raise environmental compliance and carbon costs.
The summer production data show that Montenegro has not yet reached the point where coal can be removed from the system without a significant replacement strategy.
For EPCG, the next phase of renewable investment will need to be measured not only by installed megawatts but by how quickly new generation, storage and grid flexibility can replace the firm energy currently supplied by Pljevlja.
