ACER’s Decision No 08/2026, adopted on 22 June 2026, looks technical at first glance, but for Southeast Europe it has a direct market meaning: reserve capacity, balancing flexibility and cross-border deliverability are becoming central to how the region’s electricity risk will be priced. The decision approves the first amendment to the Regional Coordination Centre Regional Sizing of Reserve Capacity Methodology, the framework under which RCCs support regional reserve-sizing tasks across system operation regions. ACER’s legal basis is the EU Electricity Regulation, which gives RCCs tasks of regional relevance, including regional sizing of reserve capacity.
The most important SEE-specific number is 99.99%. ACER approved a one-year historical imbalance record for all system operation regions, while setting the South-East Europe SOR reliability parameters at X = 99.99% for positive imbalances and Y = 99.99% for negative imbalances. That means the regional sizing exercise must be calibrated to cover almost all historically observed LFC block imbalance events in both upward and downward directions. SEE is therefore treated very conservatively, only below Central Europe’s 100% / 100% and aligned with South-West Europe at 99.99% / 99.99%.
For SEE, that is not a marginal technical setting. It signals that the region’s reserve adequacy problem is now being framed through operational security rather than cheap optimisation. ACER explicitly acknowledged that the methodology has not yet been implemented in any SOR and that the lack of practical experience justifies conservative parameters, especially where instantaneous imbalances can be larger than the 15-minute resolution used in the methodology, and where limited cross-zonal capacity or reserve geography prevents easy netting of opposite imbalances.
This fits the market reality seen in Southeast Europe over the past two years. ACER’s separate 2026 monitoring report on cross-zonal capacity and flexibility in SEE showed that summer 2024 price spikes reached up to €1,000/MWh in some evening hours, driven by solar drop-off, heatwave demand, weak flexible resources, lower hydrology, reduced gas-fired availability, limited storage and constrained cross-zonal capacity into the region. For that assessment, ACER defined Southeast Europe more broadly as Slovenia, Croatia, Hungary, Romania, Bulgaria and Greece, which is wider than the formal SEE SOR used in RCC legal architecture.
That distinction matters. The formal SEE RCC structure is centred on SEleNe CC, with ESO EAD, IPTO and Terna as participating TSOs, and coordination arrangements involving Transelectrica on the BG-RO interface. The wider market reality, however, runs through Hungary, Romania, Bulgaria, Greece, Croatia, Slovenia and their links with the Western Balkans, Ukraine, Italy and Central Europe. ACER’s decision sits in the formal RCC framework, but its practical impact will be felt through a wider SEE trading and balancing corridor.
The decision also introduces a more flexible but stricter logic for reserve sharing. Where TSOs establish sharing agreements between LFC blocks, the short-term assessment of available sharing amounts must be implemented within 24 months of notification to the relevant RCC, and TSOs must notify the RCC within one week after establishing such an agreement. For SEE, this creates a clearer timeline for turning reserve-sharing arrangements into operationally assessed capacity rather than informal or static cooperation.
The commercial effect is important. Reserve sharing can reduce total system costs only when the shared reserve is actually deliverable across the grid. ACER’s amendment allowing geographical delineation in the determination of minimum reserve capacity is therefore highly relevant for SEE. The decision allows RCCs to use a more granular geographical scope, taking account of different LFC configurations, internal constraints and cross-zonal transmission limits. This directly addresses the risk of “paper reserves” that look available in a regional calculation but cannot be physically delivered during stressed evening ramps, hydro shortages, outages or congestion events.
For investors, this pushes a new line into renewable and storage bankability models. Solar projects in SEE cannot be assessed only through day-ahead price capture and average annual output. Their system value now depends increasingly on imbalance exposure, forecast accuracy, curtailment risk, firming contracts, storage pairing and access to balancing markets. Wind has a different profile from solar and should not be treated by analogy: its higher evening and seasonal contribution can carry greater system value in certain SEE nodes, but that value still depends on grid access, balancing responsibility and reserve deliverability.
The methodology also strengthens the case for batteries, pumped storage, flexible hydro, demand response and fast-start thermal capacity. ACER notes that SORs may rely on measures such as demand response, load shedding, renewable curtailment and balancing energy bids on EU balancing platforms to cover imbalances beyond the sized reserve volume. That means the future value stack for flexibility in SEE will not come only from arbitrage between low midday solar prices and high evening prices. It will also come from reserve adequacy, imbalance management, congestion relief and the ability to support operational security.
The decision also confirms a transparency shift. RCCs must publish key information on reserve-sharing agreements, including the SOR, dates, contracting TSOs, involved LFC blocks, reserve type and reserve volume per direction. ACER also requires publication of the results of the short-term assessment of sharing availability as part of the RCC reporting framework. For market participants, this is useful because it turns reserve cooperation into observable infrastructure. Traders, storage developers, industrial offtakers and lenders will be able to see more clearly where reserve-sharing arrangements exist and how much capacity is being treated as regionally available.
For Serbia, Montenegro and the Western Balkans, the direct legal effect is limited because ACER’s decision is addressed to ENTSO-E and sits inside the EU RCC framework. But the practical relevance is significant. EU SEE countries exchange electricity with non-EU neighbours, especially the Western Balkans and Ukraine, through explicit cross-zonal capacity auctions, and ACER noted that EU exports to Ukraine and the Western Balkans increased net demand in exporting EU SEE member states during summer 2024, contributing to peak-hour price pressure.
That gives Serbia’s EMS, Montenegro’s CGES, Bosnia and Herzegovina’s NOSBiH, Albania’s OST and North Macedonia’s MEPSO a clear strategic signal. As SEE market coupling, balancing integration and EU accession alignment deepen, Western Balkan TSOs will be judged less by nominal interconnection capacity and more by real-time observability, data quality, reserve coordination, congestion management and emergency cooperation. The 21 June 2024 grid incident, which affected Albania, Bosnia and Herzegovina, Montenegro and Croatia, reinforced the same point: the final ENTSO-E report identified insufficient regional visibility and limited available measures during voltage decline as part of the system-security problem.
The wider investment implication is that SEE is moving from an energy-only transition to a flexibility-led transition. Building more renewable capacity is no longer enough. The region needs reserve markets, cross-border balancing, storage procurement, dynamic line ratings, better outage coordination, stronger common grid models and operational data exchange. ACER’s 2026 SEE flexibility report already pointed to constrained cross-zonal capacity, insufficient flexible resources and the need to improve use of the existing network through operational changes and targeted investments.
This is particularly relevant for Serbia’s planned solar-plus-battery portfolio, Montenegro’s Gvozd wind expansion, pumped-storage concepts such as Bistrica and Đerdap 3, and regional battery projects seeking bankable revenue stacks. The ACER decision strengthens the commercial argument that storage and flexible generation should be valued not only as merchant arbitrage assets, but as reserve-quality infrastructure. Lenders will increasingly ask whether projects can reduce imbalance exposure, support system adequacy, meet metering and dispatch requirements, and participate in balancing or ancillary-service frameworks.
The decision also sends a warning to RES developers relying only on optimistic capture-price assumptions. In a region where solar depresses midday prices and evening ramps drive scarcity, revenue will increasingly depend on technical integration. Projects with weak forecasting, poor grid connection studies, no firming strategy and no access to balancing-market upside will face wider discount rates. Projects with storage, controllability, data transparency and credible TSO interface will carry a stronger bankability premium.
The strongest SEE reading is therefore clear: ACER has turned reserve sizing into a regional market signal. The approved 99.99% threshold for SEE supports security, but it also raises the cost discipline question. High reserve coverage can protect the system, yet ACER itself warned that covering very high percentages of historical imbalances may not always be the best trade-off between operational security and cost efficiency. That tension will define the next phase of the SEE power market: reliability must rise, but the cost of reliability must be allocated transparently across TSOs, generators, storage assets, traders and final consumers.
