January’s electricity price dynamics in South-East Europe resulted in a redistribution of value across the electricity value chain. Elevated and volatile wholesale prices did not benefit all participants in the same way. Instead, the month highlighted structural advantages and exposed long-standing vulnerabilities in different parts of the market.
Merchant thermal generation and scarcity rents
Merchant thermal generators were among the main short-term beneficiaries, with gas-fired and lignite-based plants capturing the largest upside. During cold spells, gas units frequently set the marginal price. Operators with flexible dispatch capability monetised price spikes above €120–130/MWh while running at high load factors.
In systems including Serbia, Romania and Bulgaria, lignite plants benefited disproportionately where regulated or legacy fuel cost structures applied. Their marginal costs remained far below clearing prices during January. The plants were positioned to extract scarcity rents linked to winter demand and limited cross-border capacity.
Cross-border trading and congestion income
Cross-border traders and congestion rent beneficiaries were closely tied to the thermal winners. Transmission system operators and market participants positioned on constrained interconnections captured significant congestion income during January. Persistent bottlenecks on north–south and east–west corridors kept spreads between SEE hubs and Central European markets wide during peak stress hours.
Traders with physical access rights and flexible portfolios were able to arbitrage those spreads. Meanwhile, TSOs accumulated congestion revenues that materially exceeded off-winter averages. The pattern reflected how interconnection constraints shaped regional price differentials during high-demand periods.
Hydropower gains from reservoir flexibility
Hydropower operators also emerged as partial winners, though outcomes depended on operational flexibility. Overall hydro availability was uneven across the region. Plants with reservoir flexibility were able to time generation into peak price hours.
This approach allowed hydropower to capture outsized value per megawatt-hour in January. Even moderate volumes sold into €110–130/MWh price windows improved revenue profiles compared with average-year assumptions. The effect was therefore linked to when output was delivered rather than total availability alone.
Retail suppliers under fixed-price obligations
Retail suppliers and utilities with fixed-price obligations were among the most exposed groups. Suppliers tied to regulated tariffs or long-term fixed-price contracts faced a widening gap between procurement costs and retail revenues. In several Western Balkan markets, January reinforced expectations of later tariff adjustments due to short-term losses in supply portfolios.
State-owned suppliers faced additional pressure as wholesale volatility translated into balance-sheet strain. The month increased implicit fiscal exposure where utilities remained state-backed and politically constrained in adjusting prices. This dynamic connected wholesale uncertainty to downstream financial outcomes.
Industrial consumers face higher input costs
Energy-intensive industrial consumers were another clear losing group in January. Large industrial off-takers exposed to spot or index-linked contracts faced materially higher electricity input costs during the month. This compressed margins across sectors including metals, construction materials and chemicals.
For exporters competing against producers in lower-priced Western European markets, January pricing widened competitiveness gaps rather than narrowing them. The impact was tied to contract structures that left industrial buyers more directly exposed to spot or index movements during winter volatility.
Renewables, especially merchant solar, lag market upside
Some renewable generators underperformed relative to broader market conditions, particularly merchant solar. Seasonal solar output was structurally low in January, limiting the ability of solar-heavy portfolios to benefit from price spikes. Wind performed better in selected periods, but variability still constrained overall capture of peak-event upside.
Many renewable assets did not fully take advantage of high-price hours, especially where curtailment or grid constraints applied. As a result, participation in scarcity pricing depended on both resource availability and operational limitations affecting delivery into constrained periods.
Indirect impacts on public finances and consumers
The month also shifted costs toward public finances and consumers through indirect channels. Household tariffs did not immediately reflect January wholesale prices everywhere, but the month added pressure to future regulatory decisions. Deferred pass-through increases created fiscal exposure linked to how quickly retail prices could adjust.
This was particularly relevant in systems where utilities remained state-backed and faced political constraints on adjusting prices. In those cases, wholesale volatility fed into longer-term budgetary and regulatory pressures rather than being absorbed immediately by end-user tariffs.