By 2025 solar photovoltaic generation has firmly graduated from niche to structural in the South-East European energy mix. Across the region, PV now produces measurable terawatt-hour volumes, depresses midday prices, reshapes import/export saldos and dramatically increases the need for balancing energy as grids adjust to steeper intraday swings. The story is not uniform by country, but the pattern is unmistakable: solar is altering when electricity is consumed and traded, not just how much is generated over a year, and that shift has direct implications for utilities, industrial consumers, system operators and investors.
Greece remains the undisputed regional solar leader. In 2025, installed solar capacity in Greece exceeds 7.8 gigawatts (GW), generating annual output in excess of 13 to 14 terawatt-hours (TWh) under typical irradiation patterns. On clear spring and summer days, solar alone often meets 30–35 percent of instantaneous demand during midday peaks, pushing wholesale prices sharply lower in those hours and sending surplus power toward neighbouring Balkan and Italian markets. The midday surpluses in Greece have become a defining feature of the regional price curve: peak solar production hours correspond to some of the most negative or lowest prices on South-East European spot markets. For export saldo, Greece has moved from occasional surplus in early 2020s into persistent net export position during daytime hours, directly attributable to solar plus wind growth.
Bulgaria, close behind, has also seen rapid PV growth. By mid-2025 Bulgarian installed PV capacity stands at around 4.8 GW, up substantially from just over 3.5 GW at the start of 2023. Correspondingly, annual solar output is now in the 6–6.5 TWh range, accounting for more than 15 percent of Bulgaria’s total electricity generation. Combined with steady nuclear base load and significant lignite and gas capacity, this solar output has materially improved Bulgaria’s net export saldo; in the first nine months of 2025 Bulgaria’s net electricity exports into neighbouring grids reached close to 11 TWh, up year-on-year by a double-digit percent, and solar surpluses played a visible role in that performance during spring-summer months. On certain peak days, Bulgarian solar contributes roughly 25–30 percent of instantaneous generation, exerting downward pressure on daytime market prices and increasing midday export volumes.
Romania’s solar capacity is also scaling fast. In 2025 Romania has installed about 4.1 GW of PV, producing some 5.5–6 TWh annually and covering just over 8 percent of total generation in a year where solar conditions are near the national average. Solar output has become a key determinant of intraday flows: Romanian net exports on sunny days spike between 10:00 and 16:00 when solar output is strongest, while evening and early-morning imports remain shaped by gas and nuclear flexibility. The annual export saldo remains tied more closely to hydro and nuclear than to PV alone, but solar has clearly shifted the shape of Romania’s imports and exports, carving out a predictable midday surplus window that did not exist a decade ago.
Croatia’s solar fleet is smaller but growing rapidly. As of 2025, Croatia has roughly 1.1 GW of installed PV capacity, producing about 1.4–1.6 TWh a year. This accounts for roughly 7–8 percent of national generation but has already cut peak import needs in midday hours during low-hydro years. Croatia’s export balance still swings with hydro conditions and wider regional prices, but solar has begun to influence domestic load curves and reduced reliance on imports in summer months.
In the Western Balkans, solar is emerging from a low base, but growth rates and near-term pipelines signal structural change. Serbia’s installed PV capacity was roughly 400–450 MW by mid-2025, up from less than 200 MW in 2023. Even with annual output per installed megawatt in the 1.1–1.3 megawatt-hours range, this level of PV produces nearly 0.5 TWh per year—still under one percent of EPS’s total generation but enough to noticeably cut daytime demand peaks and reduce midday marker prices. Montenegro’s prosumer and utility PV fleet, including nearly 100 MW installed by EPCG Solar Gradnja and other projects by 2025, produces around 0.12–0.15 TWh per year, which is small relative to Montenegro’s 2.8–3.2 TWh total consumption, yet highly concentrated in distribution networks where it trims midday peak loads. North Macedonia’s PV fleet—around 650–700 MW installed—produces an estimated 0.85–0.9 TWh per year, meaningfully reducing midday grid demand and slightly easing import pressure in what is otherwise a tightly balanced system.
Albania, with roughly 350 MW of PV installed by 2025, produces about 0.55–0.6 TWh annually. While under ten percent of Albania’s hydro-dominated generation, solar adds important diversification, lowering the volume of high-cost imports required in dry years and reducing reliance on rainfall alone. Across the Western Balkans combined, solar generation now sits at more than 2.5–3 TWh annually, meaning it has crossed the threshold from “negligible” to “material” in regional short-term energy balance assessments.
When these national outputs are aggregated across South-East Europe, solar is now producing roughly 30–32 TWh annually—a figure that is still below hydropower’s roughly 70–75 TWh output on average, but well above previous expectations for this stage of transition. More importantly from a strategic perspective, solar is no longer wait-and-see: it is a driver of regional import/export saldos, was visibly responsible for lowering daytime net imports (or raising net exports) in multiple countries in 2024–2025, and is materially influencing wholesale price formation in all major intraday market zones.
Yet solar’s impact is not purely positive: it directly increases the need for balancing energy and flexibility investments. The reason is simple physics: PV output is highly time-concentrated. On a regional scale, collectively installed solar can ramp from near zero before sunrise to multi-gigawatt peaks by late morning, then fall just as rapidly at sunset. In a hypothetical 2025 SEE subregion with around 15–16 GW of total installed PV, the combined ramp between 07:00 and noon on a clear spring day can exceed 6–7 GW—meaning the rest of the system must quickly respond with flexible capacity to maintain frequency and voltage stability. In the evening decline, the same magnitude must again be managed, often while demand is still rising as industrial and residential loads return.
The first balancing response in SEE remains hydropower. Reservoir and cascade hydro plants in Serbia, Bosnia and Herzegovina, Montenegro, Bulgaria and Romania are already the core flexibility asset. These units are capable of rapid upward and downward regulation, and they provide a natural complement to solar’s variability because they are dispatchable and zero-fuel. Their role has grown over the past two years: hydropower operators increasingly prioritise reserve capacity during sharp solar ramps rather than using all available water for energy alone. This operational shift, however, comes with its own trade-offs. In hydrologically tight years, hydro balancing reserves are constrained because reservoirs are managed for energy yield rather than ancillary services. That implies an inherent limit on how much hydro can be tapped purely for flexibility without creating future energy supply risk.
Gas-fired plants are the second pillar of balancing energy. Greece and Romania, in particular, rely on modern combined-cycle and open-cycle gas units to pick up residual demand as solar fades toward dusk and on cloudy days. Domestic gas fleets in Croatia and Bulgaria also serve this role to a degree. The economics here are changing: these plants are generating fewer energy megawatt-hours in a high-solar world, but they are earning an increasing share of their revenues from capacity markets and ancillary services because their pricing strength comes from availability rather than volume. Seen from a utility perspective, this turns gas plants into strategic flexibility assets with higher value per megawatt-hour when deployed in the right markets.
Cross-border grids and transmission flows serve as a third balancing lever. Excess daytime solar in one country can be exported into neighbouring systems, reducing the need for local balancing. This has been particularly evident between Greece and Bulgaria on sunny days, and between Romania and Hungary when Romanian solar surpluses emerge. However, as solar penetrations rise across more connected SEE systems, the ability to simply export surpluses to absorption markets is diminishing. When eastern Croatia, northern Greece, southern Bulgaria and western Romania all have high solar output on the same day, cross-border exports become a routing optimisation problem rather than a true system dump valve.
Market design itself is adjusting. Day-ahead markets are incorporating more granular pricing that reflects midday solar saturation, and intraday markets are becoming more active as traders arbitrage between forecast solar peaks and residual demand. Balancing markets are emerging where fast-response assets are compensated for providing reserve capacity during steep ramps. This shift creates new revenue streams for flexible plant operators, storage systems and demand-side aggregators because they are paid not just for energy delivered but for flexibility delivered at critical moments.
Storage is quickly taking centre stage in CAPEX planning. Battery energy storage systems (BESS), both utility-scale and behind-the-meter, are now among the most actively financed segments of the regional power sector. Developers and utilities alike are consciously targeting storage deployments that can soak up midday PV surplus and deliver it at peak times—with 2025 pipelines in Bulgaria, Greece and Romania collectively exceeding two to three gigawatts of storage capacity under development. These systems reduce curtailment, lower balancing costs, and help stabilise pricing, and their value increases steeply at penetration levels above five to seven gigawatts of PV because simple bilateral grid flows no longer suffice to manage sharp ramps.
From an investor perspective, the solar transition in SEE is not just a volume game; it is a timing and flexibility game. Solar output is now large enough to shift import/export saldos, reduce fuel and carbon costs, and depress daytime prices, but it also makes balancing energy and rapid response assets far more valuable. Revenues are being redefined: wind and solar earn when they produce, but hydro, gas and storage earn when they respond. Electricity markets are beginning to price that distinction explicitly, rewarding capacity that can follow the sun’s movements with premium spreads.
In practical terms, solar in 2025 is already improving annual energy independence for many SEE countries, materially cutting high-cost imports and strengthening export volumes in sunny hours. Yet it is also sharpening intraday volatility, steepening ramps, and forcing grid operators and investors to prioritise balancing energy and flexible capacity. The true economic value of each megawatt of PV now depends not only on how much it produces over a year, but on how well the broader system can manage the shape of its output. Those utilities, industrial buyers and markets that understand and invest in both solar and flexibility will capture the greatest advantage in the decade through 2030.
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