Electricity demand across South East Europe increased as summer consumption began to rise, while average day-ahead power prices fell in most markets. During Week 24, regional demand reached approximately 15.85 TWh, a weekly increase of 4.6%. Variable renewable generation climbed by 16.6% to 3.64 TWh, with solar output at 2.23 TWh and wind production around 1.40 TWh.
In the same period, the price pattern contrasted with expectations under a traditional seasonal model. Stronger renewable output changed market dynamics and helped contain prices even as demand increased. The shift was reflected across multiple national day-ahead markets in Week 24.
Week 24 day-ahead price moves across regional power markets
Serbia recorded one of the largest corrections, with average day-ahead prices falling 21.5% to approximately €78.22/MWh. Bulgaria’s average price declined 7.2% to €93.58/MWh, while Croatia fell 7.3% to €92.02/MWh. Romania decreased 4.7% to €97.38/MWh, and Hungary dropped 4.3% to €98.71/MWh.
Italy remained structurally more expensive despite a 3.8% decline, averaging €123.17/MWh. Greece was the exception, with a 2.6% increase to €91.53/MWh. Türkiye stayed an outlier with an exceptionally low average price of €22.85/MWh, supported by strong domestic renewable and thermal generation.
Generation mix shifts and implications for dispatchable flexibility
The mid-June pricing pattern indicated that South East Europe is not operating as a purely thermal-based market. Market assessments historically emphasized lignite availability, hydrological conditions, gas prices, import dependence, and utility regulation. Price formation increasingly reflected solar-driven daytime compression, wind-related volatility, hydrological conditions affecting evening ramping needs, and cross-border congestion.
Total generation changes also showed a layered system rather than a full replacement of legacy assets. Wind and solar output rose significantly, while hydropower generation declined by 7.5% to around 3.70 TWh. Thermal generation increased by 8.7% to approximately 4.52 TWh, including coal and lignite output up by 24.4% to around 2.14 TWh. Gas-fired generation fell slightly by 2.4% to roughly 2.38 TWh.
Bulgaria and Romania expand battery projects tied to market value
Bulgaria’s price decline coincided with stronger renewable output and growing export activity alongside rapid battery expansion capacity growth. The commissioning of a 602 MWh battery system developed by Solarpro and CATL marked a milestone in the country’s storage build-out. A proposed expansion at the Tenevo renewable hub would add 246 MW / 512.5 MWh.
Bulgaria’s storage additions align with a shift toward solar-plus-storage trading activity with export potential described in the regional market context. Romania is pursuing similar infrastructure development through the Gura battery storage project, where the first phase of 150 MW has been commissioned with a planned total of 250 MW / 500 MWh. Romania’s role extends beyond its domestic market due to its position connecting Hungary, Bulgaria, Serbia, Moldova, and Ukraine, as well as the Black Sea corridor.
Türkiye pricing dynamics and Italy’s role in cross-border flows
Türkiye saw electricity demand rise by 3.8% to 6.74 TWh, while maintaining one of the lowest average electricity prices in the region due to strong renewable generation and robust domestic supply. The regional picture described is one of fragmentation rather than convergence into a single market structure.
The drivers cited for price differences include domestic generation strength, regulatory frameworks, interconnection capacity, fuel availability, and currency conditions across countries including Türkiye and other regional markets.
The grid bottleneck factor as renewables scale up
The physical grid is highlighted as a limiting element as renewable deployment accelerates in South East Europe. While announced renewable projects are expected to change the generation mix, grid flexibility is described as insufficient for an efficient transition.
The economics of new projects are influenced by transmission bottlenecks, delayed substations, connection queues, permitting challenges, and immature balancing markets. In this context, a project that appears profitable based on annual average prices may become less attractive when curtailment risks, negative prices, and connection delays are considered properly.
Hydrology-driven variability across Balkans hydropower systems
A key variable across multiple countries is hydrology supporting or weakening hydropower output depending on wet or dry conditions. Albania, Bosnia and Herzegovina, Montenegro, Croatia, Serbia, Romania, and Bulgaria rely heavily on hydrological conditions for hydro generation behavior.
The described impact in wet years includes support for exports, suppression of prices, and reduced thermal generation; in dry years it includes exposure to import dependence, increased coal generation, and pressure on public finances.
Thermal outages and virtual power plant aggregation in Montenegro
An example of how disruptions can affect finances is provided by Montenegro’s TPP Pljevlja outage. The outage forced EPCG to increase electricity purchases, placing pressure on its balance sheet.
The episode is linked to exposure factors including coal availability, imports, hydrological variability, and tariff policies mentioned for the country context.
EPCG is also pursuing a virtual power plant platform designed to integrate more than 10,000 prosumers and approximately 100 MW of rooftop solar capacity. The initiative is described as reflecting growing importance of aggregation and digital energy management for distributed resources.
Pumped storage planning in Serbia alongside EPS reforms and tariffs
The future energy sector direction for Serbia is described as depending on sequencing across EPS reforms, tariff adjustments, coal fleet reliability improvements, renewable integration, and large-scale storage investments.
Pumped-storage development such as Đerdap 3 is cited as an essential component for future balancing economics in the Western Balkans rather than only symbolic investment activity.
Evolving EU policy influence on financing prospects for coal and renewables
Evolving European Union policy frameworks are described as reshaping how energy assets are valued across South East Europe through CBAM emissions pricing mechanisms and renewable auctions among other measures listed in the regional policy set: state-aid regulations, grid codes, guarantees of origin, and market integration initiatives.
The financing prospects for coal and lignite plants are described as deteriorating gradually in terms of export competitiveness even while they may continue contributing to security of supply under some circumstances.
Lenders’ focus shifts toward curtailment risk and hybrid storage value
Lenders’ evaluation models are adapting toward factors including curtailment risks, grid access conditions, merchant price exposure assumptions, balancing costs, storage integration opportunities, and regulatory uncertainty.
A smaller hybrid renewable project combining storage with secure grid access is described as potentially more bankable than a larger standalone project lacking flexibility under these assessment criteria.
Batteries versus pumped hydro plus virtual power plants for flexibility needs
The role of wind within this framework is highlighted alongside solar exposure to midday price compression effects as solar deployment accelerates further in the region context described.
The characteristics cited for wind include different generation hours compared with solar output and stronger winter performance that can contribute greater system value under certain market conditions where winter adequacy concerns persist alongside hydrological variability.
