The first half of May 2026 highlighted the exposure of Southeast Europe to aging lignite and coal-fired assets, even as policy discussions increasingly reference renewables, storage and grid integration. Coal generation across the broader HU+SEE system fell by approximately 260 MW, while power prices rose across the region. Serbia’s SEEPEX averaged €101.61/MWh, Montenegro’s BELEN was €98.76/MWh, Bulgaria’s IBEX reached €104.98/MWh, and Romania’s OPCOM climbed to €115.88/MWh.
The price movement coincided with a market environment where firm capacity became harder to replace quickly with alternative flexibility. Coal plants remain politically important, but their operational and financial performance has been deteriorating.
Ugljevik and Gacko: losses and compressed margins
RiTE Ugljevik in the Republic of Srpska returned to service in early May after months of inactivity linked to coal-supply and operational problems. The company reported a €18.3 million loss in the first quarter of 2026 after revenue fell from €18.8 million a year earlier to €2.2 million. Expenses remained above €20 million.
The same period also reflected how fuel and mining-related failures can interrupt output beyond routine variability. When mining preparation, overburden removal or fuel supply issues prevent operation, a plant stops providing baseload service and can become a contingent liability for the system.
RiTE Gacko showed a different scale of deterioration but similar pressure on earnings. The company posted only around €50,000 net profit in the first quarter of 2026, down from €440,000 in the same period of the previous year, despite revenue of €24.3 million. Expenses rose to roughly €24.2 million, leaving almost no earnings buffer.
This margin compression is relevant for coal assets facing additional disruptions such as equipment failure or shifts in coal quality. It also applies to costs tied to environmental compliance, wage pressure, carbon-related trade effects, fuel logistics disruptions and forced outages.
State support signals: Comsar Energy RS and Ugljevik Istok 2
The Republic of Srpska moved into further intervention to support its coal infrastructure through acquisitions. It decided to acquire Comsar Energy RS and its Ugljevik Istok 2 concession for more than €120 million. The transaction was presented as part of maintaining coal-related capacity.
The decision reflects how state involvement can expand when operational reliability declines or when coal assets require additional backing to remain functional within the power system.
Pljevlja and EPS: mixed utility performance across hydro-coal systems
In Montenegro, Pljevlja faced financial strain through the coalmine’s performance alongside utility results from EPCG. The coalmine recorded significantly lower profit in 2025, while EPCG reported a €92 million loss in 2025 before returning to stronger profitability in the first quarter of 2026.
The pattern illustrated the interaction between hydro output and coal exposure inside hydro-coal utility structures. Strong hydrology can improve overall earnings, but coal-related risks remain structurally difficult for balancing profitability.
In Serbia, coal remains central to the national power system, increasing the scale of market exposure compared with other countries in the region. EPS reported higher profit in 2025 and posted €129 million profit in the first quarter of 2026. Even so, market direction continued to point toward rising pressure on lignite-based generation.
Four drivers behind the regional coal stress
The Western Balkans’ coal problem was described as having four layers: technical, financial, regulatory and market-based factors. On the technical side, many units are old and maintenance-heavy and are linked to mines with declining operational efficiency.
The financial layer centers on continuous capital needs to keep plants operating, including mine expansion, overburden removal, environmental upgrades, spare parts procurement, workforce costs and debt restructuring. These requirements compete with investment needs for renewables, storage and grid development.
The regulatory layer includes EU accession processes, Energy Community obligations and environmental compliance requirements that reduce commercial comfort around coal-heavy systems. CBAM-linked trade effects were also cited as contributing to pressure on coal-reliant structures.
The market-based layer reflects changing dispatch patterns as solar expands across daytime periods while coal remains needed during evening peaks and winter scarcity. That combination can reduce operating predictability even when availability requirements remain in place.
Market volatility: implications for traders and system flexibility needs
The region’s power balance has been affected by how quickly firm capacity can tighten when major lignite units experience outages or reduced output availability. A sudden outage at a major unit can tighten regional supply conditions rapidly, particularly when nuclear or hydro output is also weak.
The May data described that environment as lower firm generation alongside higher gas generation and rising prices despite weaker demand conditions across the market.
This setting also affects electricity trading risk profiles by increasing price volatility tied to reliability events at lignite plants. It also increases uncertainty around how quickly replacement flexibility can be deployed when multiple sources underperform simultaneously.
Replacement portfolios: storage, flexible hydro and grid reinforcement priorities
Renewable developers face a dual signal from coal instability: declining coal reliability supports arguments for new renewable capacity alongside battery storage and other flexible resources. At the same time, weak grid planning and slower replacement of firm capacity can raise system risk levels including curtailment and balancing costs.
The replacement approach described for Western Balkan systems goes beyond substituting one generation type with another. It includes coordinated portfolios covering wind, solar, storage, hydro optimization, grid reinforcement, demand response, flexible gas where necessary and industrial PPAs.
Batteries and flexible hydro were highlighted as gaining strategic importance because historical coal services included inertia, voltage support, reserve capacity and dispatchability. Renewables may not provide comparable services without grid-forming inverter capabilities supported by storage systems, advanced control arrangements and strengthened transmission networks.
Employment impacts and fiscal exposure from transition delays
A further constraint is that coal plants continue to support employment and local economies through mines and thermal facilities that are among major employers in their regions. Any transition involving these assets requires social and financial planning alongside energy-sector modelling.
Delaying transition was also linked to continued cost accumulation through underinvestment in replacement flexibility over time. That can increase the likelihood of emergency imports, forced public support measures and politically difficult tariff adjustments when reliability gaps emerge.
The discussion also noted that assets appearing inexpensive because capital costs are already sunk can become costly once outages occur alongside mining failures and environmental liabilities being accounted for properly.
From security asset toward managed decline: Ugljevik-Gacko-Pljevlja signals
The situation across RiTE Ugljevik’s financial deterioration after early-May restart issues was paired with margin compression at RiTE Gacko during the first quarter of 2026. Montenegro’s Pljevlja-linked coalmine profitability weakness in 2025 alongside EPCG’s €92 million loss was cited as another indicator within a broader hydro-coal context.
Together with ongoing reliance on coal-heavy systems in Serbia—where EPS posted higher profits including €129 million in the first quarter of 2026—the developments were presented as evidence that coal is moving from an operational security role toward managed decline challenges within regional power markets.
The central question raised was whether governments and utilities use remaining operating windows for financing credible replacement capacity or whether they continue spending those windows on keeping older assets running until failures become more expensive than transition measures themselves.
Elevated by Energy.Clarion.Engineer
