Coal is no longer only an environmental liability in the Western Balkans. It is becoming a financial stability problem for utilities, governments and energy markets.
The first half of May 2026 showed how exposed the region remains to aging lignite and coal-fired assets, even as policy language increasingly shifts toward renewables, storage and grid integration. Coal generation across the broader HU+SEE system fell by approximately 260 MW, while prices still rose sharply across the region. Serbia’s SEEPEX averaged €101.61/MWh, Montenegro’s BELEN stood at €98.76/MWh, Bulgaria’s IBEX reached €104.98/MWh, and Romania’s OPCOM climbed to €115.88/MWh.
That price movement matters because it shows a system losing cheap firm capacity faster than replacement flexibility can fully absorb. Coal plants remain politically important, but their operational and financial quality is deteriorating.
The clearest example is RiTE Ugljevik in the Republic of Srpska. The plant returned online in early May after months of inactivity caused by coal-supply and operational problems. Its financial position deteriorated sharply: the company reported a €18.3 million loss in the first quarter of 2026 after revenue collapsed from €18.8 million a year earlier to only €2.2 million, while expenses remained above €20 million.
This is not a normal cyclical downturn. It is a structural warning. When a coal plant cannot operate because mining preparation, overburden removal or fuel supply fails, it stops functioning as baseload and becomes a contingent liability.
The Republic of Srpska’s decision to acquire Comsar Energy RS and its Ugljevik Istok 2 concession for more than €120 million shows the scale of state intervention now required to keep coal infrastructure alive. What once looked like generation security increasingly resembles fiscal exposure.
RiTE Gacko shows a softer but equally important deterioration. The company posted only around €50,000 net profit in the first quarter of 2026, down from €440,000 in the same period last year, despite revenue of €24.3 million. Expenses rose to roughly €24.2 million, leaving almost no earnings buffer.
That thin margin is important. Coal plants with almost no profitability buffer are vulnerable to any additional shock: equipment failure, coal-quality deterioration, environmental costs, wage pressure, carbon-related trade impacts, fuel logistics disruptions or forced outage.
Montenegro faces a similar problem through Pljevlja. 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 mixed performance shows the tension inside hydro-coal utility systems: strong hydrology can improve earnings, but coal exposure remains structurally difficult.
For Serbia, the issue is larger because coal remains central to the national power system. EPS reported higher profit in 2025 and €129 million profit in the first quarter of 2026, but the broader market direction still points toward rising pressure on lignite-based generation. Profitability today does not remove transition risk tomorrow.
The Western Balkan coal problem has four layers.
The first is technical. Many plants are old, maintenance-heavy and tied to mines with declining operational efficiency. Outages increasingly have market-wide consequences because firm capacity is still needed during low hydro, low wind or evening peak periods.
The second is financial. Coal assets require continuous capital just to remain operational. Mine expansion, overburden removal, environmental upgrades, spare parts, workforce costs and debt restructuring all compete with investment needs in renewables, storage and grids.
The third is regulatory. EU accession, Energy Community obligations, environmental compliance and CBAM-linked trade effects are steadily reducing the commercial comfort zone around coal-heavy systems.
The fourth is market-based. As solar expands, coal plants face weaker utilization during midday periods but remain needed during evening and winter scarcity. That reduces their operating logic: they must stay available but may run less predictably.
This is a difficult financial model.
Baseload coal economics work best when plants run steadily at high load factors. A system with growing solar and wind requires flexibility, ramping and reserve capability. Old lignite units were not built for that role.
The consequence is increasingly unattractive: high fixed costs, lower operating predictability, more maintenance stress and rising political sensitivity.
For governments, this creates a sovereign-risk issue. Coal utilities often sit close to public balance sheets. When plants fail, the state frequently steps in through guarantees, concession acquisitions, liquidity support or regulated tariff decisions. That means energy transition risk can become fiscal risk.
For banks, coal-linked exposure becomes harder to justify. Even where lending is not directly for coal generation, exposure to utilities, industrial offtakers or public infrastructure linked to coal systems carries transition risk. Credit committees increasingly ask whether cash flows depend on assets that may face declining utilization, higher compliance costs or regulatory restrictions.
For electricity traders, coal instability means higher volatility. A sudden outage at a major lignite unit can tighten the regional stack quickly, especially when nuclear or hydro output is also weak. The May data showed exactly that type of environment: lower firm generation, higher gas generation and rising prices despite weaker demand.
For renewable developers, coal instability is a double-edged signal. On one side, declining coal reliability strengthens the case for new renewable capacity, battery storage and flexible assets. On the other, weak grid planning and slow replacement of firm capacity can increase system risk, curtailment and balancing costs.
The investment answer is not simply “replace coal with solar”. That is too narrow.
Western Balkan systems need coordinated replacement portfolios: wind, solar, storage, hydro optimization, grid reinforcement, demand response, flexible gas where necessary, and industrial PPAs. Coal capacity cannot be removed without replacing both energy and system services.
This is why battery storage and flexible hydro are gaining strategic importance. Coal plants historically provided inertia, voltage support, reserve capacity and dispatchability. Renewables alone do not automatically provide the same services unless supported by grid-forming inverters, storage, advanced control systems and stronger transmission networks.
The political challenge is that coal plants still support employment and local economies. Mines and thermal plants are often among the largest employers in their regions. Any serious transition therefore requires social and financial planning, not only energy modelling.
Yet delaying the transition does not remove the cost. It may increase it.
Each year of underinvestment in replacement flexibility raises the probability of emergency imports, forced public support and politically difficult tariff adjustments. Coal assets that appear cheap because their capital costs are already sunk can become expensive when outages, mining failures and environmental liabilities are counted properly.
The Western Balkans are approaching that point.
The financial instability of Ugljevik, the margin compression at Gacko, the volatility around Pljevlja, and the continuing reliance on coal-heavy systems in Serbia all point to a region where coal is moving from security asset to managed decline problem.
The strategic issue is not whether coal disappears immediately. It will not.
The real question is whether governments and utilities use the remaining coal operating window to finance credible replacement capacity, or whether they spend that window keeping old assets alive until failures become more expensive than transition itself.
Elevated by Energy.Clarion.Engineer
