South-East Europe’s power market shifts: wind and solar now drive volatility, making flexibility—and batteries—the next test

In South-East Europe, the defining change in the power market by the first quarter of 2026 is no longer simply that more wind and solar are being built. The shift that matters for investors and utilities is that these resources have become large enough to influence how prices form, how electricity moves across borders, how thermal plants are dispatched and what it costs to balance the system—making flexibility the central operational question for the region.

Week 16 illustrated how renewables are reshaping market behaviour

The report’s Week 16 snapshot shows the new dynamics clearly. Total variable renewable output across the region rose 21.7% week on week, driven by a 74.6% jump in wind output, while solar generation fell 9.4%. That combination—an asymmetric renewable profile—helps explain why volatility is increasingly being driven by weather patterns rather than fuel costs alone.

While this weekly pattern sits within a broader trend, the underlying message is consistent: wind and solar have continued to gain structural weight after a record 2025 across Europe. That year marked the first time fossil generation was overtaken by wind and solar in the EU, with solar growth in particular changing intraday price shapes and affecting the economics of flexible generation. Ember’s latest European electricity review frames this as part of a durable shift in the generation stack rather than a temporary weather-driven anomaly.

Country differences remain, but volatility is becoming systemic

For South-East Europe, Q1 2026 looks more uneven than in north-western Europe, but the direction is similar. Greece is showing a larger renewable imprint on market behaviour than only a few years ago. Romania remains heavily influenced by wind variability, especially when hydro faces pressure. Bulgaria and Croatia are increasingly exposed to how intermittent generation interacts with cross-border trade. Serbia is earlier in its transition, but its pipeline is now large enough that wind, solar—and eventually storage—could move from peripheral contributors to price-setting assets over the next few years.

Serbia’s renewables association reports installed renewable capacity of 3,709.5 MW, including 13 wind farms totalling 824.2 MW. It also describes solar expansion from a very low historical base into a multi-gigawatt project pipeline.

Wind shocks and solar pressure point to different flexibility needs

A key market point highlighted in the report is that wind and solar do not affect systems in the same way. Wind increasingly delivers the largest upside and downside shocks in weekly generation patterns across SEE. In Week 16 coverage cited by the report, Türkiye’s renewable output rose 70% week on week almost entirely due to wind; Greece saw wind generation more than double; Romania and Hungary experienced steep wind declines that tightened local supply and pushed prices higher; Serbia recorded the largest relative increase in total renewable output again mainly because of wind.

Solar behaves differently: it may be less explosive week-to-week, but it has growing influence on daytime pricing—particularly during spring and summer through price suppression. The challenge for SEE is that solar capacity growth is beginning to outpace investment in flexibility. The result can include deeper midday price compression, more frequent curtailment risk in some markets and steeper evening ramps that must be covered by gas, hydro imports or coal and lignite where those resources remain available.

The report ties these dynamics to broader European warnings about persistent volatility across day-ahead, intraday and balancing timeframes. Weather-driven volatility is described as becoming a defining feature of market behaviour.

Gas prices fell sharply—but power prices rose because variability drove dispatch

Week 16 also matters because it shows how market outcomes can diverge from fuel signals. Even though gas prices fell sharply, power prices rose across much of SEE because system operation was being driven by renewable and hydro variability rather than fuel alone. Wind surged while solar weakened; hydro output fell 3.45% regionally; thermal generation had to rebalance internally.

This points to a new structure for regional markets: renewable output can no longer be treated as an overlay on top of an otherwise thermal system. Instead, it becomes a main factor forcing other parts of the system to move.

The transition shifts from building capacity to building flexibility

The most important Q1 2026 trend described in the report is therefore not just renewable growth but a transition from a capacity story toward a flexibility story. In earlier years—particularly during much of regional discussion around auctions, pipelines and installed megawatts—the focus was on adding generation capacity. In 2026, however, investors face a different question: whether systems can absorb additional waves of wind and solar without turning volatility into chronic disorder.

The report links this question to multiple pressures arriving at once: rising wind and solar capacity; growing importance of interconnectors; ageing or repositioning thermal fleets; less predictable hydrology; and demand becoming more fragmented by country and season. In such conditions, adding renewables alone does not guarantee lower system cost.

Late-2026 risk hinges on whether flexibility scales fast enough

The outlook for the rest of 2026 is described as constructive for renewable volumes but mixed for market outcomes depending on system tightness. In a base case scenario cited by the report, average annual power prices ease gradually from crisis-era extremes but remain volatile within weeks and within days as midday solar pressure deepens during spring and summer while windy episodes create sharp but temporary price collapses in selected zones.

In a tighter system case described as another scenario for late 2026 into early 2027, lack of flexibility becomes dominant even if more renewables are added. Under this view, scarcity pricing does not disappear; instead it coexists with higher intraday and balancing volatility—prices fall more often during high-output hours but spike more abruptly when wind drops or solar fades or when cross-border imports tighten.

Batteries move from optional technology to required market architecture

For investors and utilities, the implication drawn from these dynamics is direct: in SEE markets today, wind and solar are reshaping adjacent asset values across categories such as gas (as flexible responders), cross-border capacity (as a volatility release valve), hydro (as dispatchable stabiliser) and storage (as an essential bridge between low-cost renewables growth and bankable market structures).

The report argues that battery storage should not be treated as niche technology but as part of market architecture—determining whether renewable power can be monetised more evenly across the day; whether balancing costs remain manageable; whether thermal plants can shift gradually toward reserve roles rather than constant stabilisation; and whether investors view renewable-heavy markets as scalable rather than simply volatile.

Europe’s storage scale-up meets SEE’s need for time-shifting

The broader European backdrop cited by SolarPower Europe indicates that EU battery storage additions reached 27.1 GWh in 2025—signalling scale-up beyond pilot-stage rhetoric—with expectations for rapid growth later this decade still outlined by industry outlooks referenced in the report.

This matters for SEE because conditions described align with where batteries tend to become economically relevant: rising renewable penetration; sharp intraday swings; increased risk of negative or near-zero midday pricing risk in some hours; and growing value for fast-response balancing services.

Week 16 supports why batteries could reduce curtailment risk

The report frames Week 16 as evidence of what batteries could change if penetration were higher: with wind up sharply (74.6%), solar down (9.4%), hydro down (3.45%) and thermal plants stepping in while cross-border flows shifted materially—prices still rose despite lower gas prices because balance depended heavily on thermal flexibility and imports rather than time-shifting stored energy.

Batteries are described as not replacing seasonal storage or transmission expansion or baseload roles immediately; instead their near-term value lies in time-shifting solar output across hours, smoothing wind shocks, supporting ancillary services, reducing balancing costs and improving revenue quality for renewable portfolios.

Romania leads emerging BESS momentum; Greece follows with curtailment risk

The most advanced storage story identified by reporting cited in the article is Romania’s emerging grid-scale BESS activity over recent months supported by companies including Enery, Mass Group, Electrica, Eurowind and PPC Group—positioning Romania among Europe’s busiest emerging storage markets according to project reporting referenced by the text.

The article also points to separate project reporting indicating a battery near Iași sized at 200 MW / 400 MWh alongside additional utility-scale developments moving toward construction.

Greece is presented as second major regional story but with a slightly different profile shaped by policy support, maturing pipelines and growing curtailment risk realities reported around late 2025 into early 2026. The text cites interest including standalone projects such as a proposed 330 MW / 790 MWh scheme in Thessaly targeting completion in Q2 2026 alongside ongoing investor interest in Greek storage platforms.

Serbia’s storage cycle starts at project level before scaling system-wide

Serbia is described as earlier in its storage cycle even though elements are now visible through project-level integration trends tied to its expanding renewables build-out—especially its accelerating solar pipeline from very low levels historically.

The report cites project reporting including a connection-approved hybrid proposal combining about 270 MW of solar with around 72 MWh battery capacity alongside broader multi-gigawatt solar pipeline development supported by private capital interest in renewables.

The article characterises Serbia’s near-term battery role less as widespread deployment yet more about integrating optionality into projects first—then using those capabilities later for route-to-market tools before they mature into standalone flexibility assets at larger scale.

Ahead through late-2026: acceleration depends on financing quality—and grid readiness

The forecast through rest of 2026 described here expects acceleration but uneven take-off across countries. In its base case view: Romania continues leading execution alongside Greece; Serbia adds more hybrid structures combining solar with storage; Bulgaria and Croatia proceed selectively where balancing or ancillary-service economics justify it. Financing availability remains linked to high-quality projects where route-to-market structures are credible and grid connection progress has been made—though overall deployment would still be below what would be needed to transform system behaviour fully.

An upside case depends on falling battery costs plus supportive rules plus stronger evidence that curtailment avoidance or balancing value can be captured quickly—conditions under which batteries could begin changing not only individual project economics but also broader price shapes by narrowing some steep intraday spreads while improving renewable capture prices if regulation keeps pace with deployment growth signals described at European level.

A slower case retains familiar obstacles including grid connection queues; uncertain ancillary-service pricing mechanisms; underdeveloped capacity remuneration frameworks; bankability concerns; permitting friction—and warns that if these delays persist then SEE may keep adding wind and solar faster than flexibility arrives. That would likely worsen volatility structurally before improvements appear later rather than stopping renewable growth altogether while reducing system value increases dependence on gas plants again alongside coal resources where available plus hydro imports or cross-border balancing reliance.

Why this matters beyond power trading: industrial competitiveness depends on stable costs

The report connects battery investment directly with industrial policy considerations: regions combining lower-cost renewables with improving storage penetration become more credible locations for electrified industry expansion—including data infrastructure—and export-oriented manufacturing ambitions referenced indirectly through its reasoning about cost stability credibility versus volatility-driven uncertainty when flexibility lags behind renewables additions.

A Q1 2026 conclusion: batteries are no longer optional for scaling renewables safely

Taken together with Week 16 evidence about how variability drove dispatch needs even when gas prices fell sharply—and with warnings about persistent weather-driven volatility—the conclusion drawn by Q1 2026 analysis is straightforward: South-East Europe has crossed a threshold where batteries are no longer optional at system level if scaling wind and solar without amplifying instability remains an objective for policymakers and market participants alike.