Negative prices in Croatia coincide with limited battery deployment
Croatia logged 257 hours of negative electricity prices in 2025, compared with 196 hours in 2024. The negative-price periods were concentrated in spring and on sunny Sundays, when solar output was high and demand was comparatively low. Battery capacity in Croatia was only about 11 MW as of March 2026.
The pattern reflects the interaction between additional solar generation and the availability of flexibility. With more low-cost midday output, price cannibalisation can deepen when storage or flexible demand is not available. Generators may produce more electricity while receiving less revenue per megawatt-hour during these periods. Negative pricing indicates that the system is valuing flexibility more than uncontrolled daytime production.
Cyprus faces evening supply risk as solar output declines
Cyprus has more than 1,000 MW of conventional generation and more than 1,000 MW of solar capacity. This scale supports adequate supply during daylight hours. The risk shifts to the early evening, when temperatures and air-conditioning demand remain high while photovoltaic generation falls rapidly.
The government expects 120 MW of storage to be installed by January 2027. The planned capacity targets the gap between sustained evening demand and declining solar output.
Romania advances utility-scale battery financing for grid services
Romania is moving from operational needs toward projects that can be financed at utility scale. Aukera secured a €48.5 million financing package for the second phase of its Gura Ialomiței battery. The package includes €40 million of CAPEX financing and an €8.5 million VAT facility.
The expansion adds 100 MW/200 MWh, taking the full project to 250 MW/500 MWh. Disclosed CAPEX debt for the second phase equates to approximately €200 per kWh. PPC Renewables Romania is also developing a battery at the Fântânele-Vest wind farm with a capacity of 45.72 MW/91.44 MWh.
The PPC Renewables project is budgeted at €18.8 million, equivalent to about €206 per kWh. The EU Modernisation Fund is contributing roughly 8.3% of total project cost. The disclosed unit-cost figures for the two projects provide a comparable reference point for two-hour storage in the region.
Batteries support multiple market functions beyond day-night shifting
Batteries can be used for more than day-night arbitrage based on shifting energy from midday to evening demand. They can provide balancing services, frequency response, congestion management, intraday optimisation and reduced imbalance costs. A solar-linked battery shifts midday output toward the evening peak, aligning generation with later demand patterns.
A wind-linked system performs different functions, including smoothing forecast deviations, capturing curtailed generation and improving delivery against scheduled market positions. Wind’s higher capacity factor and less concentrated generation profile require a different revenue model from solar-linked storage.
Contracting structures and regulatory rules shape bankability
The ability to finance storage depends on how revenue streams are contracted across different services and market arrangements. Pure merchant arbitrage faces exposure to future spread compression as additional storage enters the market. Projects supported by grid-service agreements, capacity remuneration or renewable-hybrid benefits can support more predictable debt repayment.
Regulatory treatment also affects whether a technically sound battery becomes financeable. Items cited include connection rights, charging rules, double taxation of imported and exported electricity, access to balancing markets and treatment under renewable support schemes. Croatia’s decision to suspend market premiums during negative-price periods is already strengthening incentives for storage.
A shift from generation adequacy to flexibility requirements across Southeast Europe
The region’s transition is described as moving from a generation shortage toward a flexibility shortage. The next stage of renewable build-out will be defined not only by installed megawatts but also by how effectively electricity can be moved from production hours to the hours when the system values it.
