Southeast Europe’s electricity market entered a new structural phase during CW21, with renewable volatility, negative-price risk, cross-border balancing pressures and transmission bottlenecks increasingly replacing traditional thermal generation as drivers of regional power pricing.
Market signals across Serbia, Romania, Hungary, Bulgaria, Croatia and Greece indicate the region is moving away from a conventional coal-and-hydro operating model. The shift is linked to changing roles for wind generation, solar output, interconnection availability and balancing flexibility in determining pricing dynamics.
Week 19 to Week 21 price reversal across major SEE markets
The transition’s speed was reflected in a sharp reversal in regional electricity prices between Week 19 and Week 21. During Week 19, prices rose above €100/MWh across nearly all major SEE markets as wind output weakened, thermal dispatch increased and gas-linked marginal pricing returned.
Italy recorded average weekly baseload prices of €131.47/MWh, while Romania reached €123.34/MWh, Hungary €122.62/MWh, Croatia €117.37/MWh, Bulgaria €111.41/MWh, Serbia €111.36/MWh and Greece €106.30/MWh.
Serbia saw one of the largest increases, with average weekly prices rising by approximately 29.25%. The move was associated with sensitivity to renewable intermittency and cross-border balancing flows.
Only days later, the market reversed again. By 20 May 2026, renewable generation recovered across much of Southeast Europe as temperatures increased, and regional spot prices fell substantially.
Wind-driven swings and divergence between spot and forward pricing
The correction pace highlighted how SEE electricity markets increasingly behave like short-cycle balancing systems rather than stable thermal-based pricing environments. Wind-generation volatility was a key factor behind the renewed price moves.
On 18 May, regional power prices surged after wind output collapsed across parts of Central and Southeast Europe. Hungarian Week 21 baseload forwards traded near €118.5/MWh, while June 2026 contracts remained above €113/MWh, despite short-term spot-market weakness.
This divergence between spot and forward pricing pointed to ongoing expectations for long-term structural tightness during temporary renewable oversupply conditions.
Carbon prices and negative-price events in the Balkan market structure
EU Allowance (EU ETS) prices stabilized near €75.6/tCO₂ during CW21. The level continued to support higher thermal generation costs across coal-dependent Southeast European markets.
As EU ETS pressure intensifies further during the second half of the decade, carbon pricing is increasingly embedded into SEE electricity pricing structures. This was noted for Serbia, Bosnia and Herzegovina, North Macedonia and parts of Romania and Bulgaria still reliant on coal generation.
A further CW21 development was the emergence of negative-price logic within Southeast Europe. Negative prices and near-zero intraday pricing events were described as no longer limited to Western European markets.
Week 20: Serbian price drop alongside wind recovery and hydropower collapse
Week 20 data showed Serbian electricity prices falling by approximately 12.5% week-on-week as renewable generation improved. Wind generation rose sharply from previous lows during the same period.
Hydropower output simultaneously collapsed by nearly 50%, increasing net imports by more than 251% week-on-week. The combination was cited as reflecting a structural paradox for SEE electricity systems under variable renewables.
Batteries move from integration tool to merchant balancing asset
The volatility described in CW21 was linked to a shift in battery storage’s role from optional capacity to strategic necessity. Battery energy storage systems emerged as one of the dominant investment themes during CW21.
Across Southeast Europe, storage projects were described as being developed not only for renewable integration but also as merchant trading and balancing assets targeting arbitrage opportunities across volatility, intraday spreads and negative pricing events.
In Montenegro, Elektroprivreda Crne Gore advanced planning tied to approximately 500 MWh of battery-storage capacity. In Romania, Nofar Energy accelerated plans for approximately 860 MWh of battery storage projects.
Transmission congestion becomes central constraint; new wind and solar developments
CW21 also identified transmission infrastructure as a key bottleneck for Southeast Europe’s energy transition. Renewable project pipelines across Serbia, Romania, Bulgaria, Croatia and Montenegro were described as expanding faster than transmission-system modernization.
Investors increasingly view grid congestion and curtailment risk as among the most important bankability issues for new renewable projects. The scale of pipeline activity included plans for Alibunar 1 and 2 wind projects in Serbia by end-June from SANY Renewable Energy.
SANY Renewable Energy confirmed construction timing for Alibunar 1 and 2 by the end of June . Montenegro’s Elektroprivreda Crne Gore moved forward with trial operations at the 55 MW Gvozd wind farm expected to generate approximately 150 GWh annually.
Romania’s solar licence and hydropower refurbishment contract
Romania remained the most active renewable investment market in the region during CW21. DRI received a commercial operating licence for its 126 MW Văcărești solar park near Bucharest.
The same period included hydropower activity described as supporting balancing needs in renewable-heavy systems. Romania’s Hidroelectrica signed a €188.5 million refurbishment contract for the Râul Mare Retezat hydropower plant .
Gas-linked repricing risk amid LNG-driven volatility; investment needs this decade
The source also highlighted gas as a risk premium across the region despite renewables’ influence on short-term spot pricing. It said Southeast Europe’s power markets remain structurally connected to European gas pricing through marginal generation costs and balancing requirements.
A European Commission analysis published during CW21 warned that post-Russian European gas markets are becoming more volatile due to LNG dependence and changing electricity-gas linkages . For Southeast Europe, gas price shocks were described as able to rapidly reprice electricity markets during periods of low wind or hydro output.
The investment implications cited for regional decarbonization suggested Southeast Europe may require between €50 billion and €80 billion of cumulative energy-system investment this decade. The capital was described as concentrating in transmission infrastructure, battery storage, renewable generation, balancing capacity, interconnections, digital grid systems and flexible hydro modernization .
