European regulatory and technical developments are pointing to a market built around aggregators, demand response, peer-to-peer trading, electric-vehicle charging, energy communities and digitally controlled distributed assets. For Southeast Europe, the shift could change how electricity market economics are calculated compared with models centred on large power plants, wholesale trading and transmission capacity.
Two September developments illustrate the direction. EU energy regulator ACER revised frameworks for the European MARI and PICASSO balancing platforms, adding alternative qualification routes intended to make participation more accessible to smaller flexibility providers. In parallel, Slovenian distribution company Elektro Ljubljana highlighted a European framework for assessing how peer-to-peer electricity trading affects distribution grids.
Taken separately, the measures were presented as technical. Together, they indicate a structural change in which thousands of smaller electricity assets could be coordinated into portfolios that can participate commercially in power markets.
Balancing platforms adjust qualification for smaller flexibility providers
European balancing markets were historically designed around power stations able to increase or decrease production when system operators required additional flexibility. Hydropower plants and thermal generators dominated that role, with large battery installations increasingly involved. Systems are now accumulating millions of smaller flexible assets across consumption and generation.
Flexible resources include factories that can temporarily modify production schedules and refrigeration systems that can shift consumption without affecting temperatures. Commercial buildings can adjust heating and cooling, while electric vehicles can delay charging. Industrial boilers can respond to electricity prices, and distributed generators can alter exports.
Individually, many of these assets are usually too small to participate meaningfully in wholesale balancing markets. Aggregated digitally, they can operate like a virtual power plant. ACER’s revised balancing-market framework is positioned as commercially important for enabling that aggregation.
The updated approach includes traditional activation testing alongside ex-post verification and fast-track qualification. It gives national transmission operators additional ways to assess whether balancing-service providers can reliably deliver promised flexibility. The objective includes reducing qualification procedures designed around conventional generators from becoming disproportionate barriers for smaller participants.
A testing example in the framework contrasts a company controlling 10 MW at a single power station with an aggregator delivering the same capacity through hundreds of factories, commercial loads, EV chargers or distributed generators. Lower qualification barriers could increase the number of assets able to generate balancing-market revenues across Romania, Bulgaria, Greece, Hungary, Croatia and Slovenia.
Aggregators coordinate distributed flexibility as a service
The opportunity described for the region is not limited to increased participation in European balancing platforms. It also involves creating an intermediary industry focused on coordinating distributed flexibility rather than owning all underlying assets.
In this model, aggregators do not necessarily own the assets they control. Software monitors electricity prices, balancing requirements, network constraints and customer operating conditions to decide when individual assets should increase or reduce consumption or production.
A factory could earn electricity-market revenue without becoming an electricity trader. An aggregator could identify short periods when part of the factory’s electricity consumption can be reduced, combine that flexibility with dozens of other industrial sites and submit the resulting portfolio into the balancing market.
The customer would receive part of the revenue while the aggregator manages forecasting, dispatch, market participation and settlement. The same coordination approach could extend to supermarkets, warehouses, water utilities, telecom infrastructure and commercial buildings.
Electric vehicles are highlighted as a key element within this setup. A fleet of several thousand vehicles represents a substantial load even if most vehicles do not need continuous charging. Charging software can determine whether electricity consumption occurs immediately or several hours later as long as vehicles are sufficiently charged when needed.
Peer-to-peer trading links local grid constraints to market value
A second development is occurring lower in the electricity system through changes affecting how value is determined by location within distribution networks. Traditional wholesale electricity markets largely set value based on time and bidding zone. Increasing distributed generation makes location inside the distribution network more relevant.
Two identical MWh can have different system values depending on whether generation occurs behind a congested transformer or where spare capacity exists. Peer-to-peer trading and energy communities make this issue visible because transactions still depend on physical distribution infrastructure.
If many participants export simultaneously, voltage can rise and local lines or transformers may become constrained. Coordinated local consumption aligned with local generation can reduce electricity flows through higher network levels. The new CWA 50784:2026 framework highlighted by Elektro Ljubljana addresses assessment of peer-to-peer transactions using data exchange, interoperability, grid visibility and measurable performance indicators .
The framework is described as moving energy communities beyond sharing solar production between participants toward approaches that can be measured and integrated into grid operations . The next stage is grid-aware electricity sharing in which local electricity acquires a location value linked to both wholesale prices and local network conditions.
Smart meters support settlement data for flexibility markets
The transition also changes the economic role of smart meters beyond billing improvements, remote reading and network management. High-frequency consumption data enables suppliers and aggregators to understand when customers can provide flexibility rather than only measuring how much electricity was used.
A conventional bill measures consumption while a flexibility platform asks how much of that consumption could have occurred at another time. That difference becomes commercially valuable for dynamic tariffs, automated demand response, peer-to-peer settlement, energy communities and local flexibility markets.
This creates an emerging business category focused on meter-data management. Companies processing millions of consumption points, forecasting behaviour and converting information into dispatch instructions could sit between electricity customers, suppliers, aggregators and network operators.
Dynamic tariffs combine price signals with congestion and charging constraints
Dynamic tariffs allow consumers to respond to electricity-market prices rather than paying a fixed price throughout the day. Price-based optimisation alone creates risks if large numbers of electric vehicles receive identical signals indicating low prices at specific times such as 2 a.m., potentially producing new demand peaks.
The more advanced model combines multiple signals for optimisation. A fleet-management platform might consider wholesale electricity price, local network congestion, distribution charges, balancing-market opportunities and deadlines by which each vehicle must be charged.
The optimisation problem shifts from identifying when electricity is cheapest to determining when and where consumption is most valuable to the entire system . This defines an emerging flexibility economy based on timing and location rather than only commodity pricing.
Southeast Europe has flexible loads tied to grid investment timing
Southeast Europe has characteristics that could make these markets commercially significant. Electricity systems across the region include large industrial consumers, district-heating systems, water utilities, commercial refrigeration facilities tied to tourism infrastructure and increasingly large EV-charging portfolios.
Many loads contain some degree of flexibility while countries face rising costs related to network reinforcement and integrating distributed renewable generation. Using flexibility cannot eliminate grid investment but it can change when and where investment is required within distribution networks.
A transformer constrained for only a few dozen hours each year may not immediately require replacement if consumption can be shifted during those periods. A distribution network experiencing midday solar congestion may benefit more from flexible local demand than from additional grid infrastructure .
A new value chain connects coordination software with physical assets
The emerging market described would produce a value chain different from the traditional utility model. Generators would still sell electricity while traders manage wholesale-market positions and grid operators maintain networks.
Another group of companies would monetize flexibility coordination together with information flows. Aggregators combine distributed assets while software providers optimise consumption; energy communities organise local generation and demand; EV platforms control charging; smart-meter systems provide settlement data; distribution operators may procure local flexibility; industrial consumers could become market participants without changing core businesses .
This regulatory architecture being developed includes ACER’s balancing reforms addressing how smaller distributed assets enter European balancing markets . It also includes Slovenia’s work around peer-to-peer trading addressing interaction between distributed transactions and physical distribution networks . The next step described is connecting these two layers so that one asset can provide multiple forms of value across local coordination through aggregators into European balancing markets .
The issues identified include avoiding double counting and determining which market has priority when multiple parties seek access to the same flexibility. Addressing those points would require new contractual arrangements, metering systems and market rules . The region’s investment opportunities are described as shifting toward digital coordination connecting assets already attached to the system rather than only new generation or transmission buildouts .
