While hydropower determines how fat the margins are in wet years, coal and lignite still determine whether the lights stay on at scale in much of South-East Europe. Serbia, Bosnia and Herzegovina, Bulgaria, Greece, Romania and North Macedonia all continue to rely on coal-fired thermal power plants (TPPs) for a substantial share of baseload. Behind every gigawatt of thermal capacity sits a network of lignite mines, overburden removal systems, conveyor belts and rail sidings that consume billions in CAPEX and OPEX. As the region moves toward decarbonisation, the economics of those coal supply chains — tonnes mined, unit costs, strip ratios, rehabilitation liabilities — are becoming as important as the heat rates of the power stations they feed.
Serbia is a good starting point because its coal system is both large and still expanding in some basins. In 2022 EPS extracted 34.6 million tonnes of lignite from the Kolubara and Kostolac basins, with overburden-to-coal ratios of 2.7 cubic metres per tonne in Kolubara and 4.0 cubic metres per tonne in Kostolac. Even in 2023, when operational difficulties temporarily reduced output, the Kolubara basin alone still delivered around 22 million tonnes, supplying the Nikola Tesla A and B, Kolubara A and Morava plants that jointly generate more than half of Serbia’s electricity. Drmno, the key mine for the Kostolac B plant, produced 9.2 million tonnes in 2023 and is being expanded toward a 12 million-tonne annual capacity; by late December 2025 it had reached a new annual record above 9.9 million tonnes. EPS’s own financial data show that coal production in the first half of 2024 reached 14.48 million tonnes, up seven percent year-on-year, confirming that Serbia is not yet in structural coal decline.
The CAPEX behind those numbers is substantial. The Kolubara mining system has consumed billions of euros in cumulative investment in bucket-wheel excavators, conveyor lines, spreaders, power supply and environmental mitigation. Annual sustaining CAPEX in Serbia’s lignite mines runs well into the tens of millions of euros for equipment overhauls and environmental projects alone, while cash OPEX covers thousands of workers, diesel, electrical power for mining machinery and materials. At the same time, Serbia’s geological endowment is large. Coal reserves are estimated at around 7.1 billion tonnes, primarily lignite, which has historically underpinned the argument that coal is the country’s cheapest domestic energy source. For EPS, however, the economic equation is shifting: while the cash cost per tonne at the pit remains relatively low, adding the cost of environmental compliance, ash disposal, dust suppression and CO₂ pricing at the power-plant level steadily erodes the cost advantage relative to new renewables.
Bosnia and Herzegovina’s coal sector is smaller but, in relative terms, even more important to its power system. The country produced 13.3 million tonnes of lignite in 2022, most of it burned in TPPs located near mines, and also exported a record 0.83 million tonnes of lignite that year. Lignite and brown coal production comes from a patchwork of mines supplying EPBiH and EP HZHB plants, but many of those mines are geologically and economically stressed, with high production costs and legacy labour structures. The Zenica mine, for example, with almost 600 employees, is being shut down because it cannot produce coal at viable prices. When hydrology weakened and coal supplies faltered in 2023, EPBiH’s generation dropped, import needs rose, and the utility posted an all-time-high loss of around €169 million, despite the presence of sizeable lignite reserves. Bosnia’s challenge is that while its coal reserves are abundant — around 2.3 billion tonnes — the combination of ageing mines, high strip ratios, deep seams and rising environmental pressures pushes up unit costs and undercuts the long-standing narrative of ultra-cheap lignite.
Bulgaria’s Maritsa East complex shows what a mature lignite basin looks like at scale. Mini Maritsa Iztok operates the country’s largest lignite field, supplying nearly all of Bulgaria’s coal-fired power generation. Saleable coal output reached 35.5 million tonnes in 2022, up 25.5 percent on 2021, and the four Maritsa-linked power plants together historically accounted for more than 90 percent of the nation’s coal-based electricity. In 2023, thermal power plants provided 29 percent of Bulgaria’s 35.86 TWh of electricity, meaning coal-fired output was roughly 10.4 TWh, with lignite mines bearing the brunt of the fuel supply. Yet the profitability picture is shifting. TPP Maritsa East 2, the only state-owned plant in the complex, registered a €52 million loss in 2024 after a modest profit in 2023 and a windfall of about €600 million in 2022 during the energy crisis. Coal volumes remained high, but lower wholesale prices and rising CO₂ and maintenance costs crushed margins. For Bulgaria as for Bosnia and Serbia, this demonstrates that coal mine metrics cannot be viewed in isolation from power-plant economics; the marginal euro of lignite CAPEX increasingly competes with renewables and flexibility investments.
Greece offers a live snapshot of coal retreat under pressure. PPC’s joint output from its lignite mines in 2023 was about 9.5 million tonnes, feeding plants in Western Macedonia and Megalopolis. But the electricity they produced is shrinking fast. Coal power production in the first nine months of 2024 dropped to record lows, and lignite-fired generation accounted for only 3.2 TWh in 2024, about 15 percent of PPC’s output, with fossil gas plants producing much more. In 2023, combined fossil gas and lignite generation in Greece was 19.2 TWh, but the lignite share was at its lowest level since the 1970s. CO₂ data make the direction even clearer: in 2024 lignite plants emitted 4.33 million tonnes of CO₂, while gas plants emitted about 8.1 million tonnes, meaning that the country is already structurally substituting lignite with gas and renewables. PPC itself now describes its strategy as a transformation from lignite giant to “powertech” firm centred on renewables and flexible gas, and coal-mine CAPEX has shifted from expansion to closure and land-rehabilitation spending.
North Macedonia, though much smaller, is in a similar transition phase. In 2023 it had 824 MW of coal-fired capacity in two thermal power plants, fed by domestic lignite mines that historically provided the bulk of national electricity. Total domestic production in 2024 was 6.13 TWh, with coal still supplying a significant share, but the government has already committed to replacing lignite with a combination of gas, solar, wind and hydro, backed by around €3 billion of investments to 2040. That transformation implies a gradual winding down of mine CAPEX and a rising burden of reclamation and just-transition costs for coal regions.
Romania’s coal story is more complex, because lignite and hard coal play a smaller but still politically sensitive role in a mixed system dominated by hydro, nuclear and gas. Installed coal capacity is being phased out under the national recovery plan, but as of 2025 Bucharest is negotiating with the European Commission to extend the lifetime of 2.6 GW of coal plants beyond the planned 2026 phase-out deadline because replacement projects are delayed. Coal mines in the Oltenia basin still produce several million tonnes per year for CE Oltenia’s plants, but reinvestment is increasingly directed toward joint gas-and-solar projects developed with partners such as OMV Petrom and Tinmar. From an investor standpoint, Romanian coal mines are now best analysed not as long-term production assets but as short-lived transitional suppliers whose CAPEX focus is on safety, environmental compliance and closure preparation rather than capacity expansion.
From a regional macro view, the numbers add up quickly. Serbia’s 34–35 million tonnes, Bulgaria’s 35.5 million tonnes, Bosnia and Herzegovina’s 13.3 million tonnes and Greece’s 9.5 million tonnes together account for around 90 million tonnes of coal and lignite annually, the bulk of which is burned in power plants. Add Romania and North Macedonia and the SEE coal system easily exceeds 100 million tonnes per year of production feeding perhaps 70–80 TWh of coal-based generation, depending on utilisation and plant efficiency. Every tonne mined implies energy content, but also cash OPEX for labour and energy, capital for machinery and pits, and future liabilities for reclamation.
The economics of this coal supply chain are under growing strain. On the cost side, strip ratios are rising as the easiest seams are exhausted, equipment fleets are ageing, and safety standards are tightened. Environmental regulations are increasing the cost of dust control, water treatment and ash handling. On the revenue side, wholesale prices have fallen from the extremes of 2022, and CO₂ prices remain high, eroding margin per megawatt-hour at coal plants even in lignite-rich systems. In Bulgaria, the swing from a €600 million profit for Maritsa East 2 in 2022 to a €52 million loss in 2024 captures how quickly margins can evaporate when market prices normalise but fixed and regulatory costs remain elevated. In Bosnia, coal supply issues and weak hydrology fed straight through to a nine-figure loss at EPBiH, confirming that mine productivity is now a central credit variable, not a footnote.
CAPEX decisions in the coal sector are therefore being made in a very different context than a decade ago. Expansionary CAPEX aimed at opening new pits or significantly increasing capacity is becoming rare; most investment is either sustaining CAPEX to keep existing mines safe and operational for the remainder of their shortened lives, or transition CAPEX linked to environmental compliance and reclamation. For example, in Serbia, EPS is still investing in extending Drmno’s capacity, but in parallel it is directing far larger sums into hydro refurbishment and new solar capacity. In North Macedonia and Greece, mine-closure spending is being bundled with EU just-transition funds to redevelop coal regions with renewables, storage and new industrial uses, as seen in PPC’s redevelopment plans in Western Macedonia.
For investors and lenders, the key insight is that coal and lignite mines in South-East Europe are shifting from growth assets to managed-decline assets, but they still underpin a significant chunk of baseload generation and therefore cash flow for the next decade. Debt structures linked directly to mine operations will increasingly be scrutinised for tenor alignment with realistic closure dates, for environmental and social risk coverage and for their interaction with power-plant economics and carbon policy. Equity exposure will be priced with a growing risk premium for regulatory change and stranded-asset potential.
At the same time, coal remains politically and socially sensitive. Mines in Kolubara, Kostolac, Maritsa, Tuzla and Pljevlja provide tens of thousands of direct jobs and anchor local economies. Any accelerated phase-down without credible replacement investment would carry social and political risks. That reality explains why Serbia is still expanding some mines even as it builds renewables, why Bulgaria is fighting to keep parts of the Maritsa complex operating, and why Romania is negotiating extensions for 2.6 GW of coal capacity beyond 2026.
In the end, the story of coal for TPPs in South-East Europe is one of tension between legacy and transition. On one side stand massive lignite reserves, sunk CAPEX, established mining communities and power stations that still provide dispatchable, system-critical megawatts. On the other side stand rising CO₂ costs, competitive renewables, tightening EU policy and investors that increasingly favour low-carbon infrastructure. Over the next decade, the region’s coal mines will not disappear overnight, but their role will change fundamentally. They will move from being engines of expansion to carefully managed sources of residual baseload, gradually replaced by a mix of hydro, gas, wind, solar and storage. For anyone analysing the SEE power sector through an investor or policy lens, the key is to understand that these mines are neither dead nor future-proof. They sit at the heart of a financial and operational balancing act that will shape electricity prices, security of supply and balance-sheet risk in South-East Europe well into the 2030s.