Negative prices push southeastern Europe's renewables into active trading
Deepening negative price episodes are forcing SE European renewable generators to trade intraday positions rather than rely on fixed contracts.
Negative power prices have begun forcing renewable operators in southeastern Europe into active intraday trading, Montel reported on Thursday (2026-09-17), as a pricing dynamic long familiar in Germany and France spreads deeper into grid systems with fewer tools to handle it.6
The frequency data gives the trend its shape. Germany recorded negative power prices during 10% of hours in the first eight months of 2026, double the 5% rate seen across all of 2024 and up from 3% in 2023, according to The Economist. The same forces driving that acceleration, surplus renewable output against insufficient storage, are present across the region.3
The scale of the problem emerged on Sunday (2026-04-26). Germany, France and Hungary all recorded intraday prices below EUR -400/MWh as renewable output surged against weak demand, with the bloc-wide low reaching EUR -500/MWh, Montel reported. Hungary's presence in that episode alongside the two largest western European markets marks how far the negative price zone already reaches.4
For southeastern European operators, the commercial exposure is direct. Fixed-price power purchase agreements offer revenue certainty when negative episodes are occasional. As those episodes multiply, generators on market-reference or merchant contracts face a recurring decision: sell output forward before prices collapse, or absorb the hit. That is what Montel's framing of active trading means in practice, not a strategic upgrade but a defensive necessity.6,1
Europe's PPA market registered the strain earlier this year. Deals covering 15 GW were signed across the continent in 2025, around 20% fewer than the year before, as a market Pexapark COO Luca Pedretti described as "inundated with renewables" that suppressed capture rates and made standard fixed-price structures harder to pencil out, he told the Montel Plugged In podcast on Thursday (2026-04-09). Battery-linked deals have since emerged as the fastest-growing PPA segment, a direct commercial response to the timing gap between peak generation and saleable output.5
Storage deployment is growing but uneven. European grids installed a record 8.8 GWh of battery capacity in 2024, ten times the rate in 2020, partly driven by the arbitrage opportunity negative prices create: charge at negative cost, discharge during peak demand hours, The Economist reported. Southeastern Europe has built less of this buffer than the western core, and that gap is part of why its operators are encountering the active-trading requirement now.3
German power front-month fell 6.91% to €161.21/MWh by Monday's close (2026-09-21), with the ICE Endex TTF front-month dropping 7.87% to €73.27/MWh in the same session. The concurrent selloff reflects supply-side pressure across the continent. A weaker gas price reduces the backstop value of gas-fired generation in hours when renewables run hard, leaving spot prices more exposed to any output surge. [Live prices]
Germany spent roughly $200 billion on its energy transition over two decades, The Economist reported, and still produces hours that impose pricing penalties on the very generators the transition depends on. Southeastern Europe is building that same renewable base now, with less developed hedging markets, thinner liquidity and a storage pipeline that lags its generation ambitions.2,3
For project financiers underwriting new southeastern European renewable capacity, the live question is whether PPA structures have evolved quickly enough to price active trading as an operating cost. A developer who gets this wrong will find out when the next sustained negative price episode hits, not when the deal closes.6,5