Southeast Europe’s electricity market is developing a second commercial layer in which the value of electricity is tied not only to the megawatt-hour, but also to the ability to change where, when and how electricity is consumed or produced. Recent regulatory and technical developments in Europe point to markets built around aggregators, demand response, peer-to-peer trading, electric-vehicle charging, energy communities and digitally controlled distributed assets. In September, two developments highlighted this shift: ACER revised balancing-market frameworks and Elektro Ljubljana promoted a framework for assessing peer-to-peer trading impacts on distribution grids.
ACER balancing reforms and qualification routes for smaller flexibility providers
European balancing markets were historically designed around power stations able to increase or decrease production when system operators needed additional flexibility. Hydropower plants, thermal generators and large battery installations have dominated that role. At the same time, electricity systems are accumulating millions of smaller flexible assets such as factories that can modify production schedules, refrigeration systems that can shift consumption without affecting temperatures, and commercial buildings that can adjust heating and cooling.
Other flexible resources include electric vehicles that can delay charging, industrial boilers that can respond to electricity prices, and distributed generators that can alter exports. Individually, these assets are usually too small to participate meaningfully in wholesale balancing markets. Aggregated digitally, they can behave like a virtual power plant.
ACER’s revised frameworks for the European MARI and PICASSO balancing platforms introduce alternative qualification routes intended to make participation more accessible to smaller flexibility providers. The revised approach combines traditional activation testing with ex-post verification and fast-track qualification. It gives national transmission operators additional ways to determine whether balancing-service providers can reliably deliver promised flexibility.
The objective includes preventing qualification procedures designed around conventional generators from becoming disproportionate barriers for smaller participants. A company controlling 10 MW at a single power station is described as relatively straightforward to test, while an aggregator controlling the same capacity through hundreds of factories, commercial loads, EV chargers or distributed generators faces different technical and administrative challenges. Lower qualification barriers could therefore increase the number of assets capable of generating balancing-market revenues in Romania, Bulgaria, Greece, Hungary, Croatia and Slovenia.
Aggregators coordinate distributed flexibility as a service
The shift described for Southeast Europe centres on intermediaries that coordinate flexible assets rather than owning them. Aggregators do not necessarily own the assets they control; their business is coordinating them. 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 by reducing part of its consumption during short periods identified by an aggregator. The aggregator could combine such flexibility with dozens of other industrial sites and offer the resulting portfolio into the balancing market. The customer receives part of the revenue while the aggregator manages forecasting, dispatch, market participation and settlement.
The same coordination model could extend beyond industrial sites to supermarkets, warehouses, water utilities, telecom infrastructure and commercial buildings. Electric vehicles are highlighted as potentially important because a fleet of several thousand vehicles represents a substantial electricity load even if most vehicles do not need continuous charging. Charging software can decide whether a vehicle consumes electricity immediately or several hours later, provided it is sufficiently charged when needed.
That timing difference is described as flexibility that becomes potentially tradeable once aggregated. This coordination approach links distributed resources to balancing-market participation through portfolios assembled by aggregators.
CWA 50784:2026 framework links peer-to-peer trading with distribution grid impacts
A second development is occurring lower in the electricity system through changes affecting distribution networks. Traditional wholesale electricity markets largely determine value according to time and bidding zone, while increasing distributed generation makes location inside the distribution network more important. The source describes how two identical megawatt-hours may have different system values depending on whether generation occurs behind a congested transformer or where spare network capacity exists.
Peer-to-peer trading and energy communities expose this location effect because financial transactions still rely on physical distribution infrastructure. If many participants export simultaneously, voltage can increase and local lines or transformers can become constrained. Conversely, coordinated local consumption aligned with local generation can reduce electricity flowing through higher network levels.
The European framework CWA 50784:2026, highlighted by Elektro Ljubljana, provides a methodology for assessing peer-to-peer electricity transactions using data exchange, interoperability, grid visibility and measurable performance indicators. The framework is presented as moving energy communities away from sharing solar production between participants toward systems that can be measured and integrated into grid operations.
The next stage described is grid-aware electricity sharing in which local electricity acquires a location value alongside wholesale price signals. A commercial district example includes rooftop solar, EV chargers, heat pumps and large consumers where strong solar periods could allow EV fleets to increase charging or buildings to shift cooling demand into those hours. Instead of curtailing generation or reinforcing the grid, a distribution operator could procure local flexibility coordinated by an aggregator using verified consumption and generation data from smart meters.
Smart-meter data supports dynamic tariffs, demand response and settlement
The transition also changes the economic role of smart meters beyond billing improvements, remote reading and network management. High-frequency consumption data allows suppliers and aggregators to understand when customers can provide flexibility. A conventional bill measures consumption while a flexibility platform asks how much of that consumption could have occurred at another time.
The difference between actual timing and alternative timing is described as commercially valuable for dynamic tariffs, automated demand response, peer-to-peer settlement, energy communities and local flexibility markets. This creates an emerging business category around meter-data management in which companies processing millions of consumption points can forecast behaviour and convert information into dispatch instructions between customers, suppliers, aggregators and network operators.
Dynamic tariffs combine price signals with congestion and balancing opportunities
Dynamic tariffs allow consumers to respond to electricity-market prices rather than paying one fixed price throughout the day. The source also describes risks from price-based optimisation alone if thousands of electric vehicles receive the same signal indicating low prices at 2 a.m., potentially leading to simultaneous charging and replacement of one demand peak with another. It therefore describes an advanced model that combines several signals.
A fleet-management platform example includes considering wholesale electricity price, local network congestion, distribution charges, balancing-market opportunities and the time by which each vehicle must be charged. In this model the optimisation problem shifts from determining when electricity is cheapest to determining when and where consumption is most valuable to the entire system.
Southeast Europe’s flexibility resources span industry, networks and electrification
Southeast Europe is described as having substantial untapped flexibility based on characteristics across electricity systems in the region. These systems include large industrial consumers, district-heating systems, water utilities, commercial refrigeration facilities linked to tourism infrastructure and increasingly large EV-charging portfolios. Many loads are described as containing some degree of flexibility.
The source also notes rising costs associated with network reinforcement and integrating distributed renewable generation across countries in the region. Using flexibility cannot eliminate grid investment but can change when and where investment is required. Examples include transformers constrained for only a few dozen hours each year potentially not needing 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 according to the source description. The economic calculation is therefore presented as shifting from building capacity for every possible peak toward combining infrastructure with digitally managed flexibility.
A new value chain connects aggregators with distribution operators and European balancing markets
The emerging market described would create a value chain different from the traditional utility model while keeping roles for generators selling electricity, traders managing wholesale-market positions and grid operators maintaining networks. Another group of companies would increasingly monetise flexibility information and coordination through aggregators combining distributed assets and software providers optimising consumption. Energy communities would organise local generation and demand while EV platforms would control charging.
Smart-meter systems would provide settlement data and distribution operators may procure local flexibility according to the source description. Industrial consumers could become participants in electricity markets without changing their core businesses through these coordination mechanisms.
The source links regulatory work on both layers by stating that ACER’s balancing reforms address how smaller distributed assets enter European balancing markets while Slovenia’s work on peer-to-peer trading addresses interactions between distributed transactions and physical distribution networks. It describes connecting these layers so an electricity consumer could provide flexibility locally to a distribution operator, nationally through an aggregator and indirectly to European balancing markets.
The same physical asset could generate multiple forms of value while issues such as avoiding double counting and determining priority when multiple parties seek access to the same flexibility would require new contractual arrangements, metering systems and market rules. The source ends by stating that investment opportunities in Southeast Europe would not be limited only to new wind farms, solar projects, batteries or transmission lines because value would increasingly come from digital coordination connecting assets already attached to the system.