January 2026 acted as a concentrated stress test for South-East Europe’s electricity markets, compressing into a single winter month many of the structural dynamics that usually unfold over an entire year. Wholesale prices moved sharply higher and became markedly more volatile, not because renewable capacity was absent in headline terms, but because the system repeatedly reverted to gas-linked marginal pricing during periods of cold weather, low solar output and constrained cross-border flows. The outcome was a redistribution of value that exposed, in quantitative terms, the very different system roles played by wind and solar in the SEE region and clarified which types of renewable investment actually influence winter price formation.
Across the region, January day-ahead prices oscillated between €65–75/MWh during milder periods and repeated spikes above €120/MWh, with several hubs clearing close to €130/MWh during cold spells. Weekly averages rose sharply in early January, with regional means moving from the high-€80s into the €110–115/MWh range within a single week, a step-change of more than 20 %. These are not marginal fluctuations; they represent a level of price stress that materially alters revenue, cost and risk profiles across the electricity value chain.
The immediate trigger was weather. Heating-driven demand increased across Serbia, Romania, Bulgaria and neighbouring systems, while solar output fell to seasonal lows. Even where installed photovoltaic capacity is expanding rapidly, January solar load factors in SEE rarely exceed 10–12 %, and often drop into single digits during prolonged cloud cover. Wind output, by contrast, was variable but materially higher in system terms, with winter load factors in the 30–40 % range for well-sited projects. Hydropower provided some buffering, but reservoir constraints and uneven inflows limited its ability to suppress prices across the entire month. Under these conditions, gas-fired units repeatedly set the marginal price, transmitting gas market volatility directly into electricity clearing levels.
This marginal role of gas matters because SEE systems remain structurally exposed to it. Even where domestic lignite or hydro dominates average annual generation, gas plants often sit at the margin during winter peaks. With gas-linked short-run marginal costs moving well above €90–100/MWh during January, electricity prices followed. The result was a pricing environment in which renewables did not fail in absolute terms, but failed to displace gas at the margin when it mattered most.
The distributional effects of this pricing pattern were stark. Dispatchable thermal generators captured scarcity rents whenever prices exceeded their variable costs, while utilities with regulated or fixed retail tariffs absorbed losses. Energy-intensive industrial consumers exposed to spot or indexed contracts faced materially higher power input costs, compressing margins in metals, construction materials and chemicals precisely during a period of weak seasonal demand. Against this backdrop, renewables played a more ambiguous role: insulated from price risk where supported by fixed contracts, but structurally limited in their ability to stabilise the system during winter stress.
January therefore forces a more granular assessment of renewable system value. Solar and wind are often grouped together in policy discourse, but their January performance in SEE demonstrates that they interact with the power system in fundamentally different ways.
Solar’s limitation is not ideological; it is temporal. January electricity in South-East Europe is winter electricity, and winter electricity has a materially higher system value than summer output. Solar generation is lowest precisely when prices are highest. Even with merchant exposure, many solar assets captured only a fraction of January price upside simply because they were not producing during peak stress hours. A 100 MW solar plant operating at a 10 % load factor over January delivers roughly 7.4 GWh for the month. Even if all of that output cleared at €120/MWh, gross revenue would be under €0.9 million. By contrast, the same capacity of wind operating at a 35 % load factor delivers 26 GWh, tripling revenue exposure to winter prices and, more importantly, contributing materially to peak-hour supply.
Wind’s system value in January was therefore not just a function of volume, but of timing. Wind output coincided more closely with periods of high demand and high prices, increasing the probability that wind generation actually displaces gas at the margin. Where wind output was strong during cold spells, price spikes were visibly muted; where it was weak, gas-fired generation filled the gap. This relationship is critical for understanding why January rewarded flexible thermal assets more than solar, and why wind occupies a structurally different position in winter market dynamics.
Hydropower further reinforces this distinction. Reservoir-based hydro acted as a high-value arbitrage tool, concentrating output into hours when prices exceeded €110–130/MWh. Even modest volumes delivered disproportionate revenue and system benefit. However, hydro capacity in SEE is largely built out, and its role is one of optimisation rather than expansion. The question for renewables is therefore how new capacity can replicate, at least partially, this winter-relevant flexibility.
January also exposed the limits of current market and support designs. Most renewable support schemes in the region remunerate megawatt-hours uniformly, regardless of when they are produced. A solar megawatt-hour at noon in July and a wind megawatt-hour during a January evening peak are treated as economically equivalent, even though their system value differs by an order of magnitude. January prices demonstrate that this neutrality is not benign; it actively steers investment toward assets that add energy but not firmness.
The implications for policy and market design are concrete. If SEE systems continue to add renewable capacity without addressing winter system value, January-type price patterns will persist even as annual renewable shares rise. The first corrective lever is to reorient renewable procurement toward system-integrated assets. Hybrid configurations combining wind with battery storage, or solar with firmed backup, directly address the January problem by increasing the probability that renewable output is available during peak stress hours. A 50 MW wind farm paired with even 20–30 MWh of storage can materially reshape its revenue profile and its impact on marginal pricing during winter evenings.
A second lever is seasonal differentiation in remuneration. January made clear that winter electricity is scarce electricity. Introducing seasonal or hourly weighting into contracts for difference or premium schemes would reprice this scarcity explicitly. Wind projects with strong winter profiles would receive higher effective remuneration, while purely summer-weighted solar portfolios would face weaker incentives. Over time, this would rebalance the renewable mix toward assets that actually reduce winter price volatility.
Third, January underlines the role of renewables as hedging instruments for industrial demand. Many industrial consumers experienced January as a cost shock rather than a transition benefit. Structuring long-term PPAs that combine renewable output with firming mechanisms can convert renewables into winter price hedges rather than green add-ons. For a large industrial off-taker consuming 500 GWh annually, even partial coverage of winter peaks at fixed prices can stabilise margins more effectively than annual average pricing.
Cross-border integration is another critical dimension. January price divergence across SEE markets reflected not just supply differences, but congestion. Renewable surpluses in one system could not reliably dampen prices in neighbouring markets due to limited interconnection. Grid investments targeted specifically 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.
Perhaps the most important lesson from January is that capacity growth alone is no longer a sufficient metric of progress. South-East Europe can add gigawatts of solar capacity and still experience €120–130/MWh winter prices if that capacity does not engage with the system at the margin. Wind, by virtue of its winter-weighted production profile, already does so more effectively. The policy challenge is to amplify this advantage through market design rather than dilute it through neutral incentives.
January 2026 did not signal a failure of renewables. It signalled a misalignment between renewable deployment and system needs. The month demonstrated, with quantitative clarity, that winter-relevant generation and flexibility determine prices in SEE electricity markets. Wind, hydro and firmed renewable configurations reduce reliance on gas at the margin; solar, without integration, does not. As long as this distinction is blurred in policy and investment frameworks, winter price stress will remain a defining feature of the region’s power markets, regardless of how impressive annual renewable penetration figures appear on paper.
By virtu.energy
