In South-East Europe, coal and lignite continue to play a pivotal role in energy production, particularly as hydropower’s influence fluctuates with seasonal variations. Countries such as Serbia, Bosnia and Herzegovina, Bulgaria, Greece, Romania, and North Macedonia heavily depend on coal-fired thermal power plants (TPPs) for a significant portion of their baseload electricity generation. The intricate supply chains supporting these power plants involve extensive networks of lignite mines, conveyor systems, and logistical infrastructure that require substantial capital and operational expenditures. As the region progresses towards decarbonization, understanding the economics of these coal supply chains—comprising extraction volumes, production costs, and environmental liabilities—has become increasingly critical.
Serbia serves as a notable case study due to its expansive coal mining framework. In 2022, Electric Power Industry of Serbia (EPS) extracted 34.6 million tonnes of lignite from the Kolubara and Kostolac basins. Despite some operational challenges in 2023 that temporarily affected output levels, the Kolubara basin alone produced approximately 22 million tonnes that year. The Drmno mine associated with the Kostolac B plant is projected to expand its capacity to 12 million tonnes annually by late 2025. EPS reported a coal production increase to 14.48 million tonnes in the first half of 2024 compared to the previous year, indicating that Serbia’s coal sector remains robust amid ongoing transitions.
The capital investment required for maintaining these operations is significant. The Kolubara mining system has absorbed billions of euros in investments for equipment upgrades and environmental compliance initiatives. While Serbia boasts substantial lignite reserves estimated at around 7.1 billion tonnes—historically regarded as a low-cost domestic energy source—the increasing costs associated with environmental regulations and CO₂ pricing are reshaping EPS’s economic calculations regarding coal.
In contrast, Bosnia and Herzegovina’s coal sector is smaller yet critically important to its energy landscape. The country produced 13.3 million tonnes of lignite in 2022 while also exporting 0.83 million tonnes. However, many mines are facing geological limitations and economic pressures that hinder profitability. For instance, the Zenica mine is shutting down due to unviable production costs despite having abundant reserves estimated at around 2.3 billion tonnes. A decline in hydrological conditions led EPBiH to record an unprecedented loss of approximately €169 million in 2023.
Bulgaria’s Maritsa East complex exemplifies a mature lignite basin operating at scale. In 2022, it generated saleable coal output of 35.5 million tonnes, supporting over 90% of Bulgaria’s coal-based electricity generation historically. However, profitability is under pressure; TPP Maritsa East 2 experienced a €52 million loss in early 2024 following substantial profits during the energy crisis in previous years due to falling wholesale prices and rising operational costs.
Meanwhile, Greece showcases a rapid retreat from coal reliance as PPC reported a joint output from its lignite mines at about 9.5 million tonnes in 2023. However, this has translated into diminishing electricity production from coal sources; by early 2024, lignite accounted for only about 15% of PPC’s output as gas generation surged ahead. This shift aligns with PPC’s strategic pivot towards renewable energy solutions.
North Macedonia is navigating similar transitions with two TPPs operating on domestic lignite supplies while planning investments exceeding €3 billion towards gas and renewable energy sources by 2040—a clear indication of intent to phase out lignite dependency.
Romania presents a more complex scenario where both lignite and hard coal have diminished roles within an energy mix dominated by hydroelectricity and nuclear power. The government plans to phase out installed coal capacity but seeks extensions for some plants beyond their slated closure dates due to delays in replacement projects.
Collectively, these countries contribute roughly over 100 million tonnes annually from their coal sectors, generating about 70–80 TWh of electricity depending on operational efficiency levels. However, rising strip ratios due to resource depletion alongside stringent environmental regulations are significantly increasing operational costs across the board.
The evolving landscape calls for reevaluated capital expenditure strategies within the sector; expansionary investments are becoming less common as focus shifts toward sustaining existing operations while ensuring compliance with environmental standards. This trend is evident in Serbia where EPS balances investments between extending existing capacities while also channeling funds into renewable projects.
For stakeholders involved in financing or investing within this sector, it is crucial to recognize that these mines are transitioning from growth-oriented assets towards managed decline scenarios while still underpinning essential baseload generation for the foreseeable future. As such, debt structures must align with realistic closure timelines while accounting for emerging regulatory risks that could impact asset valuation.
The social implications remain vital; many communities rely on these mines for employment opportunities which complicates any accelerated phase-out without adequate replacement strategies being put into place.
This duality between legacy systems reliant on extensive reserves versus emerging pressures from environmental policies will shape the future dynamics of South-East Europe’s power markets significantly over the next decade.
