January 2026 served as a critical examination of the electricity markets in South-East Europe, revealing the intricate balance between renewable energy sources and traditional generation methods. The month was characterized by significant fluctuations in wholesale electricity prices, which surged due to a combination of cold weather, limited solar production, and constrained interconnections. This scenario highlighted the varying contributions of wind and solar energy to the region’s power supply and price formation during winter months.
Throughout January, day-ahead electricity prices ranged from €65 to €75/MWh during milder weather, escalating to peaks exceeding €120/MWh, with some market hubs reaching close to €130/MWh amid colder conditions. This marked a notable increase in weekly averages, which jumped from the high €80s to the €110–115/MWh range within just one week—an increase of over 20%. Such price volatility indicates substantial stress within the electricity market, affecting revenue streams and risk profiles across various sectors.
The primary catalyst for these price changes was an increase in heating demand across countries such as Serbia, Romania, and Bulgaria, coinciding with diminished solar energy output. Despite ongoing expansions in photovoltaic capacity, solar generation during January typically struggled to exceed load factors of 10-12%, often dipping into single digits during extended periods of cloud cover. In contrast, wind energy demonstrated greater resilience with load factors ranging from 30% to 40% for optimally located projects. Hydropower contributed some stability; however, its impact was limited due to reservoir constraints and inconsistent inflows.
The reliance on gas-fired generation during peak demand periods proved significant. Even in systems where lignite or hydropower predominates annual energy production, gas plants frequently set the marginal price during winter peaks. With short-run marginal costs for gas exceeding €90–100/MWh throughout January, electricity prices mirrored this volatility. Consequently, while renewable sources did not underperform outright, they were unable to displace gas at critical moments when demand surged.
This pricing environment created distinct distributional effects within the market. Dispatchable thermal generators capitalized on high prices whenever they exceeded variable costs, while utilities operating under regulated or fixed retail tariffs faced financial strain. Energy-intensive industries that relied on spot or indexed contracts encountered significantly higher electricity costs, compressing profit margins during a time of typically lower seasonal demand. In this context, renewables appeared less effective in stabilizing the market amidst winter pressures.
The events of January necessitate a reevaluation of how renewable energy’s value is perceived within the system. While solar and wind are often categorized together in policy discussions, their operational characteristics differ markedly. Solar’s limitations are primarily temporal; it produces less energy precisely when demand—and prices—are highest during winter months. For instance, a 100 MW solar installation operating at a 10% load factor would generate approximately 7.4 GWh over January, yielding revenues below €0.9 million even at peak prices. Conversely, a similar capacity of wind energy at a 35% load factor could produce around 26 GWh, significantly enhancing revenue potential during high-demand periods.
Wind’s contribution to system stability was evident; its output aligned more closely with peak demand hours compared to solar generation. When wind production was robust during cold spells, price spikes were moderated; conversely, weak wind output resulted in increased reliance on gas-fired generation. This dynamic underscores why flexible thermal assets were favored over solar during this period and highlights wind’s unique role in winter market conditions.
Hydropower also played a strategic role by acting as an arbitrage tool during high-price hours but remains largely built out in the region. Future renewable capacity additions must seek to replicate this flexibility to enhance system reliability during winter months.
The findings from January also expose limitations within current market structures and support mechanisms for renewables. Existing schemes often compensate megawatt-hours uniformly without regard for when they are produced—treating summer solar output equivalently to winter wind generation despite their differing system values. This approach can misalign investment incentives towards generating capacity that lacks reliability during peak demand times.
To address these challenges moving forward, several strategies are recommended: first, aligning renewable procurement with system-integrated assets such as hybrid configurations that combine wind with battery storage or firmed solar backup can enhance availability during peak stress periods. Second, implementing seasonal differentiation in remuneration could better reflect the scarcity of winter electricity by providing higher compensation for projects that perform well during these critical months.
Additionally, long-term power purchase agreements (PPAs) that integrate renewable output with firming mechanisms could transform renewables into effective hedging instruments for industrial consumers facing cost pressures during winter peaks. Lastly, improving cross-border integration through targeted grid investments would facilitate better price stabilization across interconnected markets by allowing surplus renewables from one area to support neighboring regions experiencing shortages.
The lessons learned from January emphasize that mere capacity growth is insufficient as a measure of progress within South-East Europe’s energy landscape. The region can add substantial solar capacity yet still experience elevated winter prices if that capacity fails to engage effectively with market demands at critical times. The challenge lies in enhancing market designs that promote reliability and flexibility among renewables rather than diluting their impact through neutral incentives.
