January 2026 functioned as a concentrated stress period for South-East Europe electricity markets, compressing winter dynamics that typically spread across a longer timeframe. During the month, wholesale prices rose sharply and became more volatile. The pattern was tied to repeated switches to gas-linked marginal pricing during cold weather, periods of low solar output and constrained cross-border flows.
Across the region, day-ahead prices ranged from €65–75/MWh during milder conditions to spikes above €120/MWh. Several hubs cleared close to €130/MWh during colder spells. Weekly averages increased rapidly in early January, with regional means moving from the high-€80s into the €110–115/MWh band within a week, a change of more than 20%.
Weather-driven demand and renewable output patterns
The immediate driver was weather. Heating-related demand increased across Serbia, Romania and Bulgaria, while solar generation fell to seasonal lows. Even with expanding photovoltaic capacity, January solar load factors in SEE rarely exceeded 10–12%, and often fell into single digits during prolonged cloud cover.
Wind output was variable but had higher system relevance in winter terms, with winter load factors in the 30–40% range for well-sited projects. Hydropower offered some support, but reservoir constraints and uneven inflows limited its ability to suppress prices across the full month. Under these conditions, gas-fired units repeatedly set the marginal price.
Gas-linked marginal costs and winter price formation
The role of gas is described as structural exposure in SEE systems. Even where domestic lignite or hydro dominates average annual generation, gas plants often sit at the margin during winter peaks. In January, gas-linked short-run marginal costs moved well above €90–100/MWh, and electricity prices followed that level.
This produced a pricing environment in which renewables did not disappear in absolute terms but did not displace gas at the margin when demand and scarcity conditions tightened. The result was a redistribution of value across market participants and supply types. It also highlighted differences between wind and solar contributions to winter price outcomes.
Impacts on utilities and industrial consumers
When prices rose above variable costs, dispatchable thermal generators captured scarcity rents. Utilities facing regulated or fixed retail tariffs absorbed losses during periods of elevated wholesale prices. Energy-intensive industrial consumers exposed to spot or indexed contracts saw materially higher power input costs.
The higher costs affected margins in sectors including metals, construction materials and chemicals during a period of weak seasonal demand. Renewables were described as having a more mixed role: they could be insulated from price risk when supported by fixed contracts, but were structurally limited in stabilising the system during winter stress events.
Wind versus solar system value in January
The month prompted a more granular view of renewable system value rather than treating wind and solar as interchangeable categories. Solar output in SEE is lowest when electricity prices are highest because January represents winter electricity conditions with higher system value than summer output. As a result, many solar assets captured only part of potential upside because they were not generating during peak stress hours.
A 100 MW solar plant running at a 10% load factor over January would produce about 7.4 GWh. Even if all output cleared at €120/MWh, gross revenue would be under €0.9 million. By comparison, the same capacity of wind operating at a 35% load factor would generate about 26 GWh, increasing exposure to winter prices and contributing to peak-hour supply.
Hydropower buffering and limits on expansion
Hydropower buffering and limits on expansion
The distinction between renewable technologies was also linked to hydropower behaviour. Reservoir-based hydro acted as an arbitrage tool by concentrating generation into hours when prices exceeded €110–130/MWh. Even modest volumes were associated with disproportionate revenue and system benefit.
The article notes that SEE hydropower capacity is largely built out, making its role more about optimisation than expansion. The question for new renewable capacity is therefore how additional projects can replicate winter-relevant flexibility rather than only add annual energy.
Support design and seasonal remuneration gaps
The month also highlighted limits in current market and support designs. Most renewable support schemes remunerate electricity volumes uniformly regardless of production timing. A megawatt-hour generated at noon in July is treated as economically equivalent to one produced during a January evening peak, despite large differences in system value.
This uniformity was described as steering investment toward assets that add energy but not firmness. The implication for policy is that adding capacity without addressing winter system value would allow January-type price patterns to persist even as annual renewable shares rise.
Policy levers cited for winter system value
A first lever described is shifting renewable procurement toward system-integrated configurations. Hybrid designs combining wind with battery storage or solar with firmed backup are presented as ways to improve availability during peak stress hours. A 50 MW wind farm paired with 20–30 MWh of storage is cited as capable of reshaping its revenue profile and affecting marginal pricing during winter evenings.
A second lever involves seasonal differentiation in remuneration. The month is framed around the idea that January represents scarce electricity periods, with seasonal or hourly weighting proposed for contracts under difference or premium schemes. Under this approach, wind projects with stronger winter profiles would receive higher effective remuneration than summer-weighted solar portfolios.
PPA structures, industrial hedging and cross-border constraints
A third point raised relates to renewables as hedging instruments for industrial demand. Industrial consumers experienced January as a cost shock rather than a transition benefit in the description provided. Long-term PPAs combining renewable output with firming mechanisms are presented as converting renewables into winter price hedges rather than green add-ons.
The example given is an industrial off-taker consuming 500 GWh annually, where partial coverage of winter peaks at fixed prices could stabilise margins more effectively than relying on annual average pricing alone. Cross-border integration is also cited: January price divergence across SEE markets reflected congestion as well as supply differences.
Curtailment of regional price dampening by limited interconnection
The description states that renewable surpluses in one system could not reliably dampen prices in neighbouring markets due to limited interconnection capacity. It also says grid investments targeted at renewable-heavy corridors would increase the regional price-stabilising effect of wind and hydro during winter stress events rather than confining benefits within national borders.
Capacity growth versus marginal engagement at peak hours
The article concludes that capacity growth alone is not sufficient as a progress metric under these conditions. It states that South-East Europe can add gigawatts of solar capacity while still experiencing €120–130/MWh winter prices if new generation does not engage with the system at the margin. Wind is described as already engaging more effectively due to its winter-weighted production profile.
The final framing provided is that January 2026 did not indicate renewables failing outright; it indicated misalignment between deployment patterns and system needs under winter conditions. It reiterates that winter-relevant generation and flexibility determine prices in SEE electricity markets, with wind, hydro and firmed configurations reducing reliance on gas at the margin while solar without integration does not.