EPCG discloses €333m legacy renewable payments, showing how long-term tariff gaps can outlast support policies

Montenegro’s power sector is carrying the bill for earlier efforts to accelerate renewables deployment, according to a disclosure from state utility EPCG. The company says €333 million has already been paid out to privileged renewable generators under legacy incentive arrangements—contracts that remain in place and continue to shape finances well beyond their original policy purpose.

The payments were made, EPCG said, mainly because the older feed-in tariff structures guaranteed purchases of electricity from renewable projects. Under that mechanism, much of the procurement cost sits with the utility first and then is transferred through the regulated electricity system to end-users via retail pricing.

Možura Wind Farm becomes a case study in tariff mismatch

EPCG pointed to the Možura Wind Farm as a central example of how the economics can diverge between what generators receive and what consumers ultimately pay. It cited 753,503 MWh of generation producing total payments of about €72.3 million, implying an average purchase price near €96/MWh.

EPCG contrasted that with its assessment of what end-users receive for the same volume: deliveries valued at roughly €44–45/MWh. That comparison yields a negative spread exceeding €38.5 million within Montenegro’s domestic supply system.

Downstream revenue falls short of procurement costs

Looking across the wider portfolio described by EPCG, the utility said it had generated only around €140 million in downstream revenue from selling electricity purchased under those same arrangements to consumers. The gap illustrates what EPCG frames as a structural mismatch between contract procurement costs and regulated retail pricing levels.

The company also emphasized that these contractual frameworks are still active. In particular, key agreements—especially those tied to Možura—extend until 2031, meaning above-market or administratively set tariffs remain locked in for several more years.

Pushing risk onto the public system—and why 2022 didn’t fully change it

EPCG argued that this model effectively transferred market risk away from producers and toward the public system. Renewable generators benefit from guaranteed returns under fixed or administratively determined purchasing terms while EPCG absorbs volatility created by differences between procurement costs and regulated supply tariffs.

The utility added that producers could opt into market-based sales instead of remaining on guaranteed schemes; however, it said they largely stayed with the guaranteed structure because it offered more predictable returns.

EPCG further linked its assessment to distortions seen during the 2022 energy crisis. It noted that spot prices on exchanges such as Hungary’s HUPX briefly exceeded contracted tariffs—creating a nominal positive spread of about €21.6 million. But EPCG said this effect was largely limited to that single year; excluding 2022, it claims cumulative comparisons turn negative, reinforcing its view that current outcomes do not reflect a sustainable market-based setup.

A broader regional lesson for long-duration obligations

Within Montenegro’s energy transition context, EPCG presented the situation as part of a wider regional pattern: early renewable support mechanisms intended to speed up capacity additions can evolve into long-duration financial commitments. In systems where end-user prices are regulated and wholesale market pass-through is constrained, those obligations can persist even after policy objectives have shifted toward integration and market functioning.

This report references disclosures by Elektroprivreda Crne Gore about EPCG’s payment burden under legacy renewable incentive contracts.