South-East Europe’s onshore wind build-out is shifting from headline capacity targets toward operational value during the cold season, according to an analysis of the January–February 2026 project pipeline. The signal is most visible in Montenegro and Greece, where new and expanded wind assets are being positioned as winter stabilizers. Yet the same study stresses that structural constraints prevent wind from taking over the marginal role from gas during system stress. For developers and grid planners, the message is clear: seasonal diversification is improving, while adequacy at the margin still depends on fast balancing resources.
Montenegro’s Gvozd 2 expansion targets winter diversification
The leading project in the region is the Gvozd 2 wind farm expansion in Montenegro, scheduled for completion toward the end of 2026. The upgrade will raise total installed capacity at the site to 75.6 MW, with expected annual generation of approximately 210 GWh. That output is estimated to be sufficient to supply more than 35,000 households. Importantly for execution planning, the expansion is designed as a continuation of an existing operating asset, enabling developers to rely on established grid connections, access roads, and operational experience.
From a system perspective, the study frames Gvozd 2 less as an incremental megawatt story and more as a seasonal profile intervention. Montenegro’s power system is described as hydro-heavy but exposed to hydrological volatility, which can tighten supply during low-inflow periods. Winter-weighted wind output is therefore treated as diversification precisely when hydro inflows are weakest. This complementarity is also cited as a reason wind remains strategically attractive even as solar compresses average pricing during summer months.
Greece accelerates wind volumes amid grid and flexibility limits
Greece’s pipeline represents the largest near-term volume expansion across South-East Europe. In 2025 alone, Greece added approximately 340 MW of new wind capacity, corresponding to around EUR 420 million in investment. Beyond that build, a further 1.1 GW of wind projects is reported as under construction or contractually secured, with most expected to come online within the next 12 to 18 months. The renewed acceleration follows earlier delays linked to permitting bottlenecks and grid congestion challenges.
The analysis links Greece’s wind resurgence to market reform and grid planning choices that reduce curtailment risk. New projects are increasingly sited in areas with improved export capability or co-located with other renewables, which can help manage network constraints during high-output periods. Even so, a structural limitation remains: wind output variability is high and system flexibility has not scaled at the same pace as installed capacity. For operators and investors, this creates a planning requirement that goes beyond turbine commissioning dates and into balancing capability readiness.
Price formation shows abrupt switching back to gas
Across South-East Europe, wind’s influence on price formation follows a consistent pattern tied to sustained weather regimes. During prolonged high-wind periods—especially in winter—wind generation suppresses peak prices and reduces reliance on gas-fired units. In January 2026, wind availability contributed to moderation of peak pricing in several markets during specific hours. However, when output declines or forecast uncertainty rises, systems revert quickly to gas and imports rather than transitioning gradually.
This behavior highlights a distinction between energy adequacy and capacity adequacy at the margin. The study notes that wind improves energy supply but does not guarantee enough controllable capability when sudden demand spikes or cross-border congestion events occur. Without sufficient storage or fast-ramping demand response, wind cannot be relied upon to cover those marginal moments. As a result, gas remains indispensable as the marginal balancing resource even when wind is providing strong seasonal support.
Grid integration constraints interact with legacy baseload
Grid integration limits are also central to how wind performs operationally across the region. In Bulgaria and parts of Greece, nuclear and coal baseload are described as constraining downward flexibility during high-wind output periods. That can lead to curtailment or exports when generation exceeds what inflexible units can accommodate economically or technically. In lower-wind periods, the same inflexibility increases reliance on imports and gas as systems swing back toward dispatchable supply.
For utilities and transmission operators, this implies that adding wind without addressing ramping behavior and network constraint management can amplify volatility rather than smooth it. Wind therefore interacts with legacy baseload assets in ways that can dampen some swings while intensifying others depending on operating conditions. These dynamics are particularly relevant for grid modernization roadmaps that must align interconnection planning with operational flexibility requirements.
Contracting structures support revenue stability but not marginal pricing
The pipeline described in the analysis increasingly relies on contracted revenue structures for financing discipline. These include long-term power purchase agreements and support schemes that reduce merchant exposure for developers while improving predictability for project cash flows. However, contracting does not change system-level marginal dynamics that determine how prices respond when wind output falls or forecasts deteriorate.
For traders and market participants, this distinction matters: wind can stabilize producer revenues without necessarily stabilizing market prices across all hours. The study’s conclusion characterizes wind’s role in South-East Europe as maturing into a seasonal stabilizer rather than a structural price-setter. Its value is highest during winter months and sustained weather regimes, while limitations emerge during rapid transitions, forecast errors, and peak stress events.
Broader implications for developers and grid planners
Taken together, Montenegro’s Gvozd 2 expansion approach and Greece’s larger near-term pipeline underline a development shift toward brownfield extensions and faster execution pathways where grid access already exists. At the same time, persistent flexibility gaps—particularly storage availability and fast-ramping demand response—remain a binding constraint on how much wind can reshape marginal pricing during stress events. For investors preparing EPC readiness plans and procurement schedules, these findings point to the need for integrated planning across generation delivery timelines and balancing capability build-out.
Overall, South-East Europe’s winter-focused wind strategy appears set to improve energy diversity while leaving gas central to margin setting until flexibility scales alongside renewable deployment. The next phase of project development will likely hinge on whether transmission modernization efforts and operational tools can keep pace with variable generation profiles across both hydro-heavy systems like Montenegro’s and baseload-constrained grids such as those described in Bulgaria and parts of Greece.