February output shifts: solar weaker, flexibility takes the lead
In February 2026, solar generation across Southeast Europe showed a winter transition paradox: output was constrained by seasonal irradiation, yet its marginal effects on prices and operational balancing became more pronounced. The key signal came from Greece, where variable renewable generation fell by -12.87% to an average of 76 GWh/day, driven largely by weaker solar conditions. Rather than simply lowering renewable volumes, the reduced solar availability changed daylight price formation by lifting the price floor during hours when solar typically suppresses prices. That shift increased reliance on flexible supply, with hydro rising by +69.07% over the same period.
Merit-order effects vary by market size and flexibility
Across the region, solar’s influence remained uneven rather than uniform. Italy recorded a +17.98% increase in renewable output, a figure that includes both solar and wind, while solar continues to dominate Italy’s renewable profile even in winter due to its extensive installed base. Despite higher renewable output, Italian spot prices declined only -13.76% to €114.41/MWh, indicating that demand scale and system absorption limited marginal price dislocations compared with the Balkans. The contrast underscores that solar’s impact is determined less by absolute generation and more by where it sits in the merit order.
Serbia highlights how small shares can move spot prices
Serbia illustrates how even a limited solar footprint can materially affect trading outcomes when system conditions make the market sensitive to daylight supply swings. Solar remained a small component within a broader renewables share of just 6.88%, yet the combined increase in solar and wind of +23.10% coincided with a sharp -41.92% drop in spot prices to €68.61/MWh. In this setting, solar functions as a marginal disruptor rather than bulk energy supply, displacing higher-cost lignite and imports during limited daylight windows. For project planning teams, this points to the importance of local dispatch interactions when forecasting revenue and price capture.
Intraday structure: less “duck curve” amplitude, tighter spreads
February also reinforced a distinct seasonal trading profile for markets transitioning out of winter peak demand patterns. Solar did not dominate baseload price formation in February, but it continued to define intraday structures through midday compression that was visible even outside summer conditions. With reduced solar amplitude compared with high-solar periods, the spread between peak and off-peak hours narrowed, effectively flattening the classic “duck curve” effect seen in higher-solar systems. For traders and risk managers, this typically means tighter intraday spreads while increasing sensitivity to short-term weather variability.
Balancing burden shifts: hydro response versus cross-border flows
The operational consequences of weaker solar extended beyond price formation into balancing behavior across different grid configurations. In Greece, hydro compensated for solar weakness, while in markets with less flexible capacity the adjustment occurred through imports. Italy’s net imports increased by 3,803.32 GWh (+36.89%), highlighting how larger systems often use cross-border flows to smooth renewable variability rather than relying solely on domestic flexibility resources. For utilities and system operators preparing grid modernization roadmaps, these patterns emphasize that expanding variable renewables changes not only generation portfolios but also balancing procurement logic.
Revenue capture pressure grows as winter production aligns with lower-priced hours
From a revenue perspective, February reinforced the structural challenge of solar capture prices under variable irradiation conditions. Even when output declines in winter, solar generation tends to coincide with lower-priced hours because it is still present during daylight periods when it can suppress marginal pricing relative to surrounding intervals. As more capacity is added across Southeast Europe, this effect is expected to intensify for producers facing both lower winter volumes and compressed prices during production windows. The resulting divergence between average market prices and realized solar revenues is likely to be a central input into CAPEX planning assumptions and contracting models.
Procurement strategies evolve: structured offtake alignment and hybrid BESS concepts
These dynamics are beginning to influence investment and contracting approaches among industrial offtakers across Southeast Europe. Buyers are increasingly aligning procurement with solar production profiles to target lower midday prices through structured agreements rather than treating market exposure as purely passive. Developers are simultaneously exploring hybridization—pairing solar with battery energy storage systems—to shift energy delivery into higher-value evening hours where price formation may be less compressed by daylight supply effects. Without added flexibility from storage or other controllable resources, standalone assets face greater revenue volatility as intraday price sensitivity to weather increases.
Grid integration remains a constraint as midday congestion risk builds
While February conditions did not produce widespread curtailment, the underlying signals for grid integration constraints remain visible for developers planning next phases of deployment. As solar capacity expands—particularly in Romania, Bulgaria, and Greece—midday congestion risks are expected to intensify during periods when daylight generation increases faster than local network capacity can accommodate it. The current ability to absorb solar output without forced reductions reflects winter operating conditions rather than long-term readiness for peak-solar months. In summer scenarios, limited storage availability alongside insufficient grid expansion could translate into curtailment events and deeper price cannibalization.
Implications for studies, EPC preparation, and execution readiness
The February evidence suggests that future project development across wind/solar portfolios will require stronger integration between technical studies and commercial design assumptions about intraday behavior. For engineering teams preparing feasibility work and EPC preparation packages, forecasting must account for merit-order positioning effects on daylight pricing as well as balancing pathways that may rely on hydro response or cross-border imports depending on local flexibility constraints. For investors and utilities updating CAPEX planning frameworks, the key takeaway is that revenue outcomes will increasingly depend on flexibility procurement—through battery energy storage systems or other controllable resources—and on interconnection capacity readiness rather than only installed MW targets.
Overall, February 2026 shows that winter solar in Southeast Europe is already shaping intraday market structure: Greece saw hydro surge (+69.07%) after solar weakness (-12.87% variable renewables), Italy absorbed higher renewables (+17.98%) with muted price movement (-13.76% to €114.41/MWh), Serbia demonstrated outsized price sensitivity despite a 6.88% renewables share (spot down -41.92% to €68.61/MWh), and Italy’s net imports rose by 3,803.32 GWh (+36.89%)—together pointing to tighter coupling between generation planning, balancing operations, transmission modernization priorities, and storage-enabled contracting.