At first glance, ACER Decision No. 08/2026, adopted on 22 June 2026, appears to be a highly technical regulatory update. In reality, however, it carries significant implications for the future of Southeast Europe’s electricity market. The decision approves the first amendment to the Regional Coordination Centre (RCC) Regional Sizing of Reserve Capacity Methodology, establishing a framework that will increasingly influence how reserve capacity, balancing resources, system flexibility and cross-border deliverability are valued across the region. As electricity systems become more dependent on variable renewable generation, the ability to maintain operational security is emerging as one of the most important drivers of market value.
The most important signal for Southeast Europe can be summarised in a single figure: 99.99%. ACER approved the use of a one-year historical imbalance record for all system operation regions while setting the South-East Europe System Operation Region (SEE SOR) reliability parameters at 99.99% for both positive and negative imbalances. In practical terms, this means that reserve-capacity calculations must be designed to cover almost all historically observed system imbalance events. Such a high reliability threshold places Southeast Europe among the most conservatively treated regions in Europe and demonstrates a clear regulatory preference for operational security over aggressive cost optimisation.
This is not a minor technical adjustment. It reflects a broader shift in how policymakers view the region’s electricity system. Rather than assuming that market forces alone can ensure reliability, regulators are increasingly focusing on reserve adequacy, system resilience and the ability to respond to unexpected imbalances. ACER acknowledged that the methodology has not yet been fully implemented and that limited operational experience justifies the use of highly conservative parameters, particularly in regions where transmission constraints, reserve geography and rapid system changes can make balancing more difficult.
The decision aligns closely with recent market developments across Southeast Europe. ACER’s separate 2026 monitoring report on cross-zonal capacity and flexibility highlighted the severe price spikes experienced during the summer of 2024, when electricity prices in some evening hours approached €1,000/MWh. Those events were driven by a combination of heatwave demand, solar generation decline after sunset, reduced hydropower availability, limited storage resources, constrained cross-border transmission capacity and shortages of flexible generation. The report demonstrated that flexibility is no longer a secondary market feature—it has become a critical component of system security.
A distinction must also be made between the formal SEE System Operation Region and the broader market reality. The RCC structure is centred on SEleNe CC, with participation from ESO EAD, IPTO and Terna, while coordination arrangements also involve Transelectrica on key regional interfaces. However, actual market dynamics extend well beyond these formal structures, encompassing Hungary, Romania, Bulgaria, Greece, Croatia, Slovenia, the Western Balkans, Ukraine and links to Central Europe. Although ACER’s decision operates within the RCC framework, its practical effects will be felt across this much wider trading and balancing corridor.
One of the most important amendments concerns reserve-sharing arrangements between transmission system operators. Under the new framework, short-term assessments of reserve-sharing availability must be implemented within 24 months of notification to the relevant RCC, while participating TSOs must notify the RCC within one week of establishing such agreements. This introduces a more structured and transparent approach to regional reserve cooperation, ensuring that reserve-sharing arrangements move beyond theoretical calculations and become operationally validated resources.
The commercial significance of this change should not be underestimated. Reserve sharing only delivers value when reserve capacity can actually be transported and activated where it is needed. To address this issue, ACER approved the use of more granular geographical delineation when determining minimum reserve requirements. This allows RCCs to account for internal transmission constraints, cross-border bottlenecks, different load-frequency control configurations and regional network limitations. The result is a stronger focus on physically deliverable reserves rather than theoretical capacity that exists only on paper.
For investors and project developers, these developments are reshaping traditional approaches to renewable-energy valuation. Solar projects can no longer be assessed solely through annual generation forecasts and average market prices. Their value increasingly depends on forecast accuracy, imbalance exposure, curtailment risk, storage integration, firming arrangements and access to balancing markets. Wind projects face a different set of opportunities and challenges. Their generation profile often aligns better with evening demand patterns, but their commercial value remains heavily dependent on grid access, balancing responsibilities and the ability to contribute to reserve adequacy.
The decision also strengthens the investment case for battery energy storage systems (BESS), pumped-storage hydropower, flexible hydro assets, demand-response programs and fast-start thermal generation. ACER explicitly notes that system operation regions may rely on measures such as demand response, renewable curtailment, load shedding and balancing energy bids submitted through European balancing platforms when reserve requirements are exceeded. This means that flexibility assets will increasingly derive value not only from energy-price arbitrage but also from their ability to support system adequacy, reserve provision, congestion management and operational reliability.
Another major feature of the decision is its emphasis on transparency. RCCs will be required to publish key information relating to reserve-sharing agreements, including participating TSOs, reserve types, reserve volumes, affected load-frequency control blocks and assessment results. This effectively transforms reserve cooperation from a largely technical process into a visible market indicator. Traders, lenders, industrial consumers and infrastructure investors will gain a clearer understanding of where reserve resources exist and how much flexibility is available within different parts of the regional system.
Although the direct legal impact on Serbia, Montenegro, Bosnia and Herzegovina, Albania and North Macedonia is limited because the decision is addressed to ENTSO-E and applies within the EU RCC framework, its practical significance is substantial. The Western Balkans remain closely connected to EU electricity markets through extensive cross-border trading, transmission interconnections and future market-coupling initiatives. As regional integration deepens, non-EU transmission system operators will increasingly be evaluated based on their ability to provide real-time system visibility, high-quality operational data, reserve coordination capabilities and effective congestion-management practices.
The lessons from the 21 June 2024 regional grid disturbance, which affected Albania, Bosnia and Herzegovina, Montenegro and Croatia, reinforce this point. The final ENTSO-E investigation identified shortcomings related to regional observability and the limited availability of corrective measures during system stress. These findings underline the growing importance of operational coordination and data exchange as electricity systems become more interconnected and more dependent on variable renewable generation.
The broader investment message is clear: Southeast Europe is transitioning from an energy-focused market to a flexibility-focused market. The region still requires substantial renewable-energy investment, but generation capacity alone is no longer sufficient. Future market success will depend on investments in reserve markets, cross-border balancing mechanisms, energy storage, dynamic grid management, advanced operational planning and improved transmission infrastructure. Flexibility is becoming a strategic resource rather than a supporting service.
This shift is particularly relevant for Serbia’s growing solar-plus-storage pipeline, Montenegro’s Gvozd wind project expansion, proposed pumped-storage developments such as Bistrica and Đerdap 3, and emerging battery-storage projects across the region. ACER’s decision strengthens the argument that storage and flexible resources should be viewed not merely as merchant opportunities but as essential infrastructure supporting system reliability. Investors and lenders will increasingly evaluate projects based on their ability to reduce imbalance costs, improve operational stability, satisfy dispatch requirements and participate in balancing and ancillary-service markets.
The implications extend directly to renewable-energy developers. Projects relying solely on optimistic merchant-price assumptions may face growing challenges. In a market where solar generation depresses daytime prices while evening scarcity drives premium pricing, revenue performance will depend increasingly on technical integration, forecasting quality, controllability, storage deployment and market participation capabilities. Projects lacking these attributes may experience lower capture prices, greater volatility and higher financing costs.
Ultimately, the strongest message from ACER’s decision is that reserve sizing has become a market signal. The adoption of the 99.99% reliability threshold demonstrates a commitment to maintaining system security in an increasingly complex electricity landscape. At the same time, it raises important questions regarding cost allocation and efficiency. Higher reliability standards provide stronger protection against system stress, but they also require greater investment in reserves, flexibility resources and operational coordination. The central challenge for Southeast Europe in the coming years will therefore be balancing two equally important objectives: increasing reliability while ensuring that the cost of reliability is allocated transparently and efficiently among transmission operators, generators, storage providers, traders and end consumers.
