In week 16 of 2026, power prices across South-East Europe (SEE) experienced a notable increase, reflecting a complex market landscape increasingly influenced by renewable energy dynamics. The rise in prices is juxtaposed with a backdrop of declining demand and a significant oversupply of renewable generation, leading to tighter regional price spreads.
On the Hungarian HUPX market, baseload prices averaged €110.47/MWh, marking an increase of €18.3/MWh compared to the previous week. This trend was mirrored in Central Western Europe, where German baseload prices surged to €109.09/MWh, Austria reached €107.98/MWh, and Italy North traded at €124.85/MWh. Within SEE, Romania’s average price stood at €105.40/MWh, Bulgaria at €98.31/MWh, Greece at €93.82/MWh, while Serbia’s SEEPEX recorded the lowest major market price at €90.96/MWh.
The most striking development was the compression of regional price spreads, particularly the Hungary-Germany differential, which plummeted to just €1.38/MWh from €19.71/MWh in the prior week, the lowest since August 2025. This shift indicates a temporary alignment between SEE markets and Central Europe, primarily driven by an oversupply of renewable energy rather than enhanced interconnection capacity.
Despite the overall price increases, volatility persisted in the market. The HUPX noted 8 hours of negative pricing, down from 22 hours previously, while peak hourly prices soared to €278/MWh. This volatility underscores a market increasingly characterized by intraday fluctuations rather than stable baseload pricing.
A critical factor influencing these trends was a marked change in the supply-demand balance across SEE. Total electricity consumption dipped to 28,863 MW, the lowest level since September, attributed to a temperature rise of +3.4°C and an increase in distributed solar generation from prosumers. Demand notably decreased in Romania and Serbia, whereas Greece saw a slight uptick.
The supply side saw substantial growth in renewable generation, with wind output climbing to 3,047 MW, up by 1,143 MW week-on-week, exceeding seasonal norms by 23%. Solar generation also reached impressive levels, peaking at 8,198 MW, contributing to an overall increase of approximately 1.75 GW in renewable supply compared to the previous week.
Conversely, conventional generation remained low; coal-fired output was reported at 4,477 MW, slightly higher than before, while gas-fired generation fell to 3,144 MW. Hydro generation saw a more significant decline to 6,783 MW, operating at 14% below seasonal averages, reflecting reduced inflows in the Danube basin.
This contrast between rising renewable output and diminishing hydro availability signals a transformative shift within SEE power markets. Short-term pricing is increasingly dictated by variable renewable sources rather than traditional dispatchable units like coal and gas that are no longer consistently setting marginal prices.
The changes were evident in regional trade dynamics as well; SEE transitioned from a net importing position of -1,172 MW to a net exporting position of +195 MW, indicating a swing of about 1,367 MW. Bulgaria led export growth with an increase of +870 MW, followed by Romania with +232 MW. However, Serbia continued as a net importer at -245 MW, highlighting its reliance on thermal generation amidst limited renewable integration.
This improved regional balance has reduced dependency on imports from the CORE region. Cross-border flows from Austria and Slovakia into Hungary and Slovenia fell to their lowest levels since March 2025 during periods of surplus solar generation in SEE markets. In several midday instances, these flows reversed direction, illustrating how solar-driven dynamics are reshaping transmission patterns.
The ongoing exports towards Ukraine and Moldova have remained significant despite decreasing volumes, maintaining a 29-week streak of positive exports that serve as a stabilizing force during peak evening hours by preventing extreme price spikes above €200/MWh.
The fuel markets also played a role in shaping these developments; the CEGH gas price dropped further to €44.9/MWh, down by €4.4/MWh week-on-week, reaching its lowest point in seven weeks. Meanwhile, carbon prices increased to €74.9/t, marking a nine-week high. This combination enhanced clean spark spreads for gas-fired units outside Greece but did not lead to increased generation due to continued displacement by renewables.
This disconnect between improved margins for generation and actual dispatch reflects a significant structural change within the market; gas-fired plants are increasingly utilized as backup capacity rather than for baseload or mid-merit generation. Coal units continue to contribute significantly—especially in Serbia where output rose by +292 MW—but are operating below historical levels due to economic constraints and environmental regulations.
The observed developments reinforce the emergence of a distinct “duck curve” profile across SEE markets: midday periods are characterized by oversupply leading to suppressed prices due to high solar output while evening hours remain reliant on imports and dispatchable resources resulting in sharper price spikes. This intraday volatility is expected to intensify with additional renewable capacity coming online across the region.
The interplay between expanding renewables, decreasing demand, and limited transmission capacity will be pivotal for future price formation in SEE markets. While short-term pricing will likely align with broader European trends, regional spreads may continue to compress during high renewable output periods with potential decoupling events stemming from local congestion or weather-induced supply fluctuations.
This evolving landscape necessitates increased flexibility as a key asset class within energy markets. Enhanced storage systems, rapid response gas units, and robust cross-border trading capabilities will be essential for capitalizing on intraday price variations. For countries like Serbia that remain heavily reliant on imports during peak demand periods, transitioning toward greater renewable integration will require substantial investments in both generation capacity and system balancing infrastructure.
The developments observed in week 16 highlight not merely another cycle of pricing but signify an ongoing structural transformation within SEE power markets—one where renewable energy is emerging as the primary influence shaping both pricing mechanisms and trade flows.
