Southeast Europe’s electricity market is beginning to develop a second commercial layer in which the valuable commodity is no longer only the megawatt-hour, but the ability to change where, when and how electricity is consumed or produced.
Recent regulatory and technical developments in Europe point towards a market increasingly built around aggregators, demand response, peer-to-peer trading, electric-vehicle charging, energy communities and digitally controlled distributed assets.
For Southeast Europe, that could gradually change the economics of electricity markets that have traditionally revolved around large power plants, wholesale trading and transmission capacity.
Two developments in September illustrate the shift.
EU energy regulator ACER has revised the frameworks governing the European MARI and PICASSO balancing platforms, introducing alternative qualification routes intended to make participation more accessible to smaller flexibility providers.
At the same time, Slovenian distribution company Elektro Ljubljana has highlighted a new European framework for assessing how peer-to-peer electricity trading affects distribution grids, helping move local electricity sharing from pilot projects towards systems that can be measured and integrated into grid operations.
Taken separately, the measures appear technical.
Together, they point towards a more significant structural change: thousands of smaller electricity assets could increasingly be coordinated into commercially useful portfolios.
From generators to aggregators
European balancing markets were historically designed around power stations capable of increasing or decreasing production when system operators needed additional flexibility.
Hydropower plants, thermal generators and, increasingly, large battery installations have dominated that role.
But electricity systems are accumulating millions of smaller flexible assets.
Factories can temporarily modify production schedules. Refrigeration systems can shift consumption without affecting temperatures. Commercial buildings can adjust heating and cooling. Electric vehicles can delay charging. Industrial boilers can respond to electricity prices. Distributed generators 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.
That is where ACER’s latest balancing-market changes become commercially important.
The revised framework introduces traditional activation testing alongside ex-post verification and fast-track qualification, giving national transmission operators additional ways to determine whether balancing-service providers can reliably deliver promised flexibility.
The objective is partly to prevent qualification procedures designed around conventional generators from becoming disproportionate barriers for smaller participants.
This could reduce one of the less visible obstacles facing aggregation businesses.
A company controlling 10 MW at a single power station is relatively straightforward to test. An aggregator controlling the same capacity through hundreds of factories, commercial loads, EV chargers or distributed generators faces a substantially different technical and administrative challenge.
Lower qualification barriers could therefore increase the number of assets capable of generating balancing-market revenues.
For electricity markets in Romania, Bulgaria, Greece, Hungary, Croatia and Slovenia, the opportunity is not simply greater participation in European balancing platforms.
It is the creation of an entirely new intermediary industry.
Electricity flexibility becomes a service
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, then decides when individual assets should increase or reduce consumption or production.
A factory could therefore 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 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 model could eventually extend to supermarkets, warehouses, water utilities, telecom infrastructure and commercial buildings.
Electric vehicles could become particularly important.
A fleet of several thousand vehicles represents a substantial electricity load, but most vehicles do not need to charge continuously.
Charging software can decide whether a vehicle should consume electricity immediately or several hours later, provided it is sufficiently charged when needed.
That difference in timing is flexibility.
Once aggregated, it becomes potentially tradeable.
The distribution grid becomes part of the market
The second emerging development is occurring lower in the electricity system.
Traditional wholesale electricity markets largely determine the value of electricity according to time and bidding zone.
But increasing distributed generation means location inside the distribution network is becoming more important.
Two identical megawatt-hours may have different system values if one is generated behind a congested transformer while another is produced where the network has spare capacity.
Peer-to-peer electricity trading and energy communities expose this problem particularly clearly.
A household or company can financially sell locally generated electricity to another participant, but that transaction still relies on physical distribution infrastructure.
If many participants export simultaneously, voltage can increase and local lines or transformers can become constrained.
Conversely, local consumption coordinated with local generation can reduce electricity flowing through higher network levels.
The new CWA 50784:2026 framework highlighted by Elektro Ljubljana addresses precisely this issue.
It provides a methodology for assessing peer-to-peer electricity transactions using data exchange, interoperability, grid visibility and measurable performance indicators.
That is important because it moves energy communities away from the simple concept of sharing solar production between participants.
The next stage is grid-aware electricity sharing.
Local electricity acquires a location value
A mature local electricity market could eventually send participants signals reflecting both wholesale electricity prices and local network conditions.
Imagine a commercial district with rooftop solar, EV chargers, heat pumps and several large electricity consumers.
During periods of strong solar generation, the local grid may benefit if EV fleets increase charging or commercial buildings shift cooling demand into those hours.
Instead of curtailing generation or reinforcing the grid, a distribution operator could potentially procure local flexibility.
The aggregator would coordinate participating assets.
The energy community would provide local generation.
Smart meters would provide verified consumption and generation data.
Software would determine the optimal response.
The electricity market would effectively gain another layer beneath traditional wholesale trading.
This creates opportunities for local flexibility markets, in which distribution operators procure congestion relief or voltage support from assets located in specific parts of their networks.
Several European countries are already experimenting with such models.
For Southeast Europe, where distribution systems will increasingly have to absorb distributed solar, EV charging and electrification of heating, the concept could become particularly relevant.
Smart meters become commercial infrastructure
The transition also changes the economic role of smart meters.
Utilities frequently present smart-meter programmes primarily as improvements in billing, remote reading and network management.
Their larger value could eventually lie elsewhere.
High-frequency consumption data allows suppliers and aggregators to understand when customers can provide flexibility.
A conventional electricity bill measures consumption.
A flexibility platform asks a different question: how much of that consumption could have occurred at another time?
That difference becomes commercially valuable.
Smart-meter infrastructure can therefore support dynamic tariffs, automated demand response, peer-to-peer settlement, energy communities and local flexibility markets.
This creates another emerging business category around meter-data management.
Companies capable of processing millions of consumption points, forecasting behaviour and converting that information into dispatch instructions could occupy a strategically important position between electricity customers, suppliers, aggregators and network operators.
Dynamic tariffs need smarter optimisation
Dynamic tariffs are another component of the emerging system.
They allow consumers to respond to electricity-market prices rather than paying one fixed price throughout the day.
But price-based optimisation alone creates new risks.
If thousands of electric vehicles receive the same signal that electricity becomes cheap at 2 a.m., they could all begin charging simultaneously.
A new demand peak could simply replace the old one.
The more advanced model therefore combines several signals.
A fleet-management platform might consider the wholesale electricity price, local network congestion, distribution charges, balancing-market opportunities and the time by which every vehicle must be charged.
The optimisation problem is no longer simply:
When is electricity cheapest?
It becomes:
When and where is electricity consumption most valuable to the entire system?
That difference defines the emerging flexibility economy.
Southeast Europe has substantial untapped flexibility
The region has several characteristics that could make these markets commercially significant.
Electricity systems across Southeast Europe contain large industrial consumers, district-heating systems, water utilities, commercial refrigeration, tourism infrastructure and increasingly large EV-charging portfolios.
Many of those loads contain some degree of flexibility.
Countries also face rising costs associated with network reinforcement and integrating distributed renewable generation.
Using flexibility cannot eliminate the need for grid investment.
But it can change when and where investment is required.
A transformer constrained for only a few dozen hours each year may not immediately need replacement if consumption can be shifted during those specific periods.
Similarly, a distribution network experiencing midday solar congestion may benefit more from flexible local demand than from additional grid infrastructure.
The economic calculation therefore changes from building capacity for every possible peak towards combining infrastructure with digitally managed flexibility.
A new electricity-market value chain
The emerging market could produce a value chain substantially different from the traditional utility model.
Generators will still sell electricity.
Traders will still manage wholesale-market positions.
Grid operators will still maintain networks.
But another group of companies will increasingly monetise flexibility, information and coordination.
Aggregators will combine distributed assets.
Software providers will optimise consumption.
Energy communities will organise local generation and demand.
EV platforms will control charging.
Smart-meter systems will provide settlement data.
Distribution operators may procure local flexibility.
And industrial consumers could become electricity-market participants without changing their core businesses.
This is already visible in the regulatory architecture now being developed.
ACER’s balancing reforms address how smaller distributed assets can enter European balancing markets.
Slovenia’s work around peer-to-peer electricity trading addresses how distributed transactions interact with physical distribution networks.
The next step is connecting the two worlds.
An electricity consumer could eventually provide flexibility locally to a distribution operator, nationally through an aggregator and indirectly to European balancing markets.
The same physical asset could therefore generate multiple forms of value.
The critical question will be avoiding double counting and determining which market has priority when several parties want access to the same flexibility.
Those issues will require new contractual arrangements, metering systems and market rules.
But they also represent commercial opportunities.
Southeast Europe’s electricity market is therefore entering a phase in which investment opportunities will not be limited to another wind farm, solar project, battery or transmission line.
Increasingly, value will come from the digital layer connecting assets already attached to the system.
The region’s next power-market winners may not necessarily own the most generation.
They may control the software that decides when thousands of other assets consume, produce or stop consuming electricity.
