The European Electricity Review 2026 highlights a significant shift in the energy landscape of Southeast Europe (SEE) as the region grapples with the implications of integrating renewable energy sources. The report indicates that, for the first time, wind and solar generation surpassed fossil fuel output across the EU in 2025. This transition is particularly pressing for SEE, where traditional coal-based power systems are being challenged by market dynamics, carbon pricing, and cross-border electricity flows influenced by renewable sources in other European countries.
In 2025, renewables accounted for nearly half of total electricity generation in the EU, but this growth was not uniform. Northern and Western Europe advanced rapidly in deploying renewable technologies and enhancing flexibility, while SEE remained heavily reliant on lignite and aging coal infrastructure. Consequently, this disparity has resulted in a growing divide within the synchronized European electricity market: low-cost renewable energy increasingly dictates pricing in SEE, pushing domestic coal operations to the periphery or out of service entirely.
Countries such as Serbia, Bosnia and Herzegovina, North Macedonia, and parts of Bulgaria are experiencing immediate financial impacts due to this market shift. Coal power plants that previously operated as baseload facilities now face reduced operating hours and increased maintenance costs per megawatt-hour (MWh), alongside rising carbon exposure from indirect effects of the Emissions Trading System (ETS). Even plants outside the EU ETS are affected as market coupling introduces carbon-priced electricity into local price structures, further compressing margins for lignite producers.
A crucial takeaway from the Ember review is that price-setting authority is changing in SEE. The record solar output in 2025 has flattened daytime prices across Europe, while wind energy’s increasing contribution has extended low-price periods into off-peak times. This situation places additional stress on thermal units in SEE that lack flexibility and raises opportunity costs for hydropower during dry seasons when reservoirs cannot effectively manage demand fluctuations.
Despite hydropower’s role as a stabilizing force in SEE—especially in countries like Montenegro and Croatia—the review warns of growing risks associated with hydro variability due to climate change. Inconsistent inflows across several SEE basins have heightened reliance on imports during peak demand hours. As EU renewables expand further, these imports become cheaper during periods of high solar generation but can spike during system stress events, leading to increased intraday price volatility. The absence of adequate storage solutions exacerbates this vulnerability within SEE grids.
While there was an uptick in wind and solar installations within SEE between 2024 and 2025—led by Romania and Bulgaria’s solar projects and advancements in onshore wind capacity in Croatia and Serbia—simply increasing capacity is no longer sufficient for market success. Current market conditions favor flexibility over mere megawatt additions; thus, investments in battery storage systems, fast-ramping gas units, and grid-scale demand response mechanisms will be critical for capturing value within a landscape dominated by variable renewable resources.
Structural limitations pose challenges to realizing these investments fully. Transmission bottlenecks—both internal to countries and at cross-border interconnections—hinder the ability to export surplus renewable energy or import competitively priced power effectively. As balancing markets remain underdeveloped across parts of SEE, failure to upgrade infrastructure could lead to higher curtailment rates as domestic solar capacity grows while still incurring scarcity costs during evening demand spikes when flexibility is lacking.
The role of coal is evolving within this context; it is transitioning from a baseload source to a contingency resource. Governments are beginning to categorize coal assets within cold-reserve or strategic frameworks to maintain supply security through the late 2020s. The economic rationale behind this shift suggests that maintaining coal units for emergency use may be more cost-effective than sustaining them as baseload providers amid an increasingly competitive environment dominated by zero-marginal-cost renewables. However, any reserve compensation must be structured transparently and limited temporally to avoid deterring investment into cleaner alternatives.
Natural gas appears positioned as a transitional fuel rather than a primary growth driver within SEE’s energy landscape. Despite overall declines in EU gas generation due to increased electrification from renewables displacing gas-fired plants during many hours, new gas projects should focus on peaking capacities rather than mid-merit operations to align with shifting utilization trends driven by rising renewable penetration both domestically and regionally.
The interconnected nature of regional markets means that SEE increasingly reflects broader European decarbonization trends through market coupling mechanisms. Price fluctuations resulting from surges in German or Italian solar output directly impact SEE electricity prices; conversely, during continental stress events like cold snaps or low wind conditions across Europe, SEE faces import scarcity challenges. Thus, ensuring regional flexibility alongside high-quality interconnections becomes paramount for securing energy stability moving forward.
Investment strategies must adapt accordingly: enhancing grid infrastructure through digitalization emerges as a key priority alongside developing storage solutions such as batteries or pumped hydro where feasible. Furthermore, evolving market designs must explicitly reward flexibility services beyond traditional energy pricing mechanisms; systems that fail to do so risk incurring higher security costs through inefficient thermal dispatch practices.
For policymakers navigating this transition landscape in SEE, aligning local strategies with EU objectives is critical; delays could result in escalating fiscal pressures without safeguarding competitiveness amidst rapid changes occurring throughout regional power markets. Accelerating renewables deployment without incorporating necessary flexibility measures could lead to increased operational volatility and curtailment risks.
In summary, Southeast Europe finds itself at a crossroads where fossil fuels no longer anchor its power system—a reality already established throughout much of Europe by 2025. The European Electricity Review 2026 affirms that adaptation within SEE markets is imperative; the pressing question remains how swiftly institutions can respond to align their capital allocations with emerging priorities centered around wind, solar generation capabilities alongside enhanced grid flexibility.
