Serbia is moving towards a more competitive market for electricity aggregation, with regulators preparing rules that would allow customers to change the company responsible for monetising their flexible consumption or distributed energy assets.
The Energy Agency of the Republic of Serbia, AERS, is consulting until Sept. 30 on new rules governing supplier switching, collective supplier switching and aggregator switching for electricity customers with full-supply contracts.
The change appears procedural, but its commercial significance is larger.
An aggregator’s product is not electricity supply itself. It combines flexible demand, generation or other controllable resources from multiple customers and offers the resulting portfolio into electricity markets.
Creating a defined mechanism for changing aggregator therefore begins to separate aggregation from the traditional supplier relationship.
For industrial consumers, that could eventually create competition over who manages their flexibility.
A new service alongside electricity supply
Serbia’s electricity Market Code already recognises aggregators within the market framework.
EMS allows an aggregator to submit a single balancing bid for its aggregation group, while eligible balancing-service providers can include generators, aggregators, storage operators and final customers, subject to technical qualification.
That creates the foundations for a new electricity-services market.
A factory could continue buying power from one supplier while another specialist company manages flexible loads such as pumps, compressors, heating, cooling or other equipment capable of temporarily altering consumption.
The commercial question shifts from:
Who supplies my electricity?
to:
Who can obtain the highest value from the flexibility inside my factory?
If several aggregators compete for those portfolios, customers can compare revenue-sharing arrangements, optimisation services and contractual terms.
Aggregators need portfolios, not power plants
The business model is attractive because expansion does not necessarily require owning generation.
An aggregator can build a portfolio by contracting with electricity consumers and controlling agreed parts of their demand.
Hundreds of smaller resources can then be combined into one market-facing asset.
For Serbian industry, that could gradually turn unused operational flexibility into an additional revenue stream.
For energy companies, it creates a new customer-acquisition market.
Existing suppliers could add aggregation to their electricity contracts, while independent companies could specialise in demand response, industrial optimisation or virtual power plants.
Technology companies could supply the forecasting, telemetry and automated control systems behind them.
Switching rules matter commercially
The ability to leave an aggregator is important because flexibility contracts can otherwise become sticky.
Industrial consumers may be reluctant to give a third party operational access to equipment unless contractual exit procedures, data responsibilities and switching arrangements are clearly defined.
Standardised switching lowers some of that friction.
It could also make aggregators compete more aggressively over customer portfolios rather than treating each relationship as a long-term bespoke arrangement.
The comparison with electricity retail is useful.
Competition in supply became meaningful when switching became operationally manageable.
Aggregation could follow a similar path.
Serbia is still at an early stage, and the existence of rules does not itself guarantee a liquid demand-response market.
Customers must still have controllable loads, adequate metering and communications infrastructure, while balancing resources remain subject to technical requirements.
But the institutional architecture is becoming clearer.
The next competition in Serbia’s electricity market may therefore not only be over who sells the cheapest megawatt-hour.
It could increasingly be over who controls the customer’s flexible megawatt and how much revenue they can extract from it.
ADEX common trading limit could improve capital efficiency for SEE power traders
Power traders active across Serbia, Hungary and Slovenia are preparing for a new common intraday trading environment that could improve how trading limits and working capital are managed across the three markets.
Under the ADEX integration, the continuous intraday markets operated through SEEPEX, HUPX and BSP SouthPool are due to move into a common M7 trading environment, with launch planned for October 2026.
The visible change is a common trading interface.
The more interesting commercial change lies behind it.
European Commodity Clearing, ECC, plans to replace existing market-specific trading limits with a single ADEX trading limit covering the participating markets.
That could make capital allocation more efficient for regional traders.
One limit across three markets
A trading company active on several exchanges traditionally has to manage operational limits market by market.
That can fragment available trading capacity even when the same company and clearing structure sit behind all of those positions.
Under the new ADEX setup, market participants will still need admission to each market they want to trade.
Physical settlement, financial settlement, margining, products and reporting also remain market-specific.
The reform therefore does not create one fully pooled clearing system.
But trading-limit management becomes common.
That distinction matters.
A regional trading desk could manage its available limit across Serbia, Hungary and Slovenia through one ADEX framework instead of maintaining separate market-specific limits.
The result should be greater operational flexibility in deciding where trading capacity is used.
Treasury becomes part of the market advantage
The development highlights a less visible part of electricity trading: collateral and treasury management.
Trading opportunities are only useful if a company has sufficient limits and collateral to execute them.
During volatile periods, collateral requirements can become a major constraint, particularly for smaller trading houses.
Companies therefore increasingly compete not only on price forecasting but also on how efficiently they use credit lines, guarantees and clearing-bank capacity.
A harmonised trading limit can make that process easier, although it does not remove underlying margin requirements.
ECC has told participants to coordinate with their clearing banks before migration because existing limits will not transfer automatically.
That creates work for treasury departments, clearing members and banks as well as traders.
Common infrastructure changes regional trading
ADEX’s shared M7 environment will also support harmonised connectivity and a new WebSocket API.
That lowers some of the operational friction associated with maintaining separate trading infrastructure across neighbouring markets.
For larger traders, the benefit may be incremental.
For smaller or expanding regional players, common infrastructure could reduce the technological cost of operating across several exchanges.
The business opportunity extends to trading-software vendors providing order management, automated execution, limit monitoring and treasury tools.
Regional integration is therefore moving beyond conventional market coupling.
The next stage is increasingly about the infrastructure behind trading: common systems, common limits, APIs, clearing relationships and more efficient use of capital.
For power traders, the scarce commodity is sometimes not electricity.
It is the financial capacity needed to trade it.
Romania puts a price on scarce grid access as connection capacity becomes a balance-sheet issue
Romania is turning access to scarce electricity-grid capacity into an increasingly capital-intensive part of energy development, raising the cost of holding speculative projects and increasing the commercial value of projects that can demonstrate financing and secure a connection.
Transmission operator Transelectrica has launched the infrastructure for allocating available grid capacity through competitive procedures, while regulator ANRE has significantly increased the financial guarantees required from developers.
For the 2026 allocation process, applicants must provide a guarantee of €20,000 per MW of requested capacity.
A 100-MW project would therefore need a €2 million participation guarantee simply to enter the allocation process.
That changes project development economics.
Grid capacity joins land and permits as a core project asset
Renewable development has traditionally focused on acquiring land, securing environmental and construction permits and arranging financing.
In congested markets, those assets are worth little without somewhere to inject the electricity.
Romania is therefore moving grid access closer to the centre of project valuation.
Transelectrica’s platform accepts capacity applications, validates financial guarantees and prepares eligible projects for the auction process.
The first 2026 application round ran from July 1 to July 14.
The objective is to allocate scarce network capacity to projects with sufficient financial commitment rather than allowing large volumes of speculative applications to occupy the connection queue.
Guarantees become significant
ANRE has tightened other parts of the connection regime as well.
For qualifying projects, the financial guarantee associated with securing a connection approval has been increased from 5% to 20% of the connection tariff excluding VAT.
Developers seeking establishment authorisations also face an additional guarantee of €30/kW of installed capacity, subject to the applicable regulatory conditions.
That means grid strategy now has direct implications for project financing.
Developers may need additional bank guarantees, credit lines or equity commitments substantially earlier in the development cycle.
A weakly capitalised developer can no longer reserve large volumes of connection capacity at minimal financial cost.
The connection queue becomes investable due diligence
This also changes renewable-energy M&A.
An investor buying a Romanian project will increasingly need to understand not only whether a grid approval exists but also the financial obligations attached to retaining it.
A project with a secured and financially supported grid position could command a very different valuation from one still waiting for uncertain connection capacity.
Technical due diligence therefore expands into grid-rights due diligence.
Investors will need to examine auction obligations, guarantees, connection tariffs, project deadlines and the conditions under which guarantees can be called.
Banks will also become more involved.
Guarantee instruments for grid applications and licensing create a potentially material banking product around project development before construction financing begins.
Romania is trying to clear speculative capacity
The tougher rules respond to a substantial queue of proposed projects.
ANRE’s supporting analysis showed hundreds of projects representing tens of gigawatts of requested evacuation capacity were moving through the connection-study process, while only a small proportion of projects backed by the previous 5% guarantee had advanced to later permitting and construction stages.
The regulator’s answer is financial discipline.
Developers must put more capital at risk earlier.
That should help distinguish projects intending to build from projects whose main value comes from reserving scarce network space.
The result is a fundamental shift in renewable development economics.
Romanian grid capacity is no longer just an engineering constraint.
It is becoming a scarce commercial resource with an explicit financial cost attached to securing it.
Croatia shortens balancing products as flexibility becomes easier to sell
Croatia has shortened the time commitment required to sell balancing capacity, a technical market change that could broaden participation beyond power plants capable of guaranteeing reserve availability for an entire day.
Transmission operator HOPS launched a new balancing platform on Sept. 15, accompanied by revised procurement rules for aFRR and mFRR balancing capacity and energy.
The most commercially important change is the structure of capacity procurement.
Instead of offering reserve capacity for an entire day, providers can now bid into six four-hour blocks through day-ahead procurement.
That makes the product substantially more compatible with flexible electricity demand.
Four hours is easier to sell than 24
An industrial site may be able to guarantee that a particular process is flexible from midday to 1600 hours.
It may not be able to promise the same flexibility throughout an entire day.
An EV fleet may have significant controllable charging demand overnight but little availability during daytime operations.
A commercial building may have flexibility during particular occupancy periods.
Long reserve products can exclude these resources because they cannot reliably commit for the full period.
Four-hour blocks lower that barrier.
The resource still has to satisfy HOPS’ qualification and contractual requirements, but once qualified it can target the periods when its flexibility is genuinely available.
That could improve the economics of demand response and aggregated portfolios.
Automation becomes more important
HOPS has also changed balancing-energy bidding.
Bids can be submitted for individual Market Time Units and modified until 25 minutes before the relevant MTU begins.
Providers can communicate with the platform through either a graphical interface or machine-to-machine connectivity.
That creates another commercial opportunity.
As gate closure moves closer to real time and products become more granular, manual bidding becomes less efficient.
Aggregators and balancing-service providers need software capable of constantly forecasting asset availability and automatically updating market positions.
A portfolio containing industrial loads, EV charging and distributed assets may change significantly within a few hours.
Automated bidding allows those changes to be reflected in the market.
Flexibility gets a better-shaped product
The shift illustrates a broader principle in electricity-market design.
Sometimes the barrier to demand response is not the absence of flexible assets.
It is that the market product was designed around conventional generators.
A large power plant can often commit reserve capacity for long periods.
A portfolio of consumers has operational limits that change throughout the day.
Shorter products allow the market to fit the asset rather than forcing the asset to imitate a conventional generator.
That can increase competition for balancing capacity without necessarily requiring additional physical generation.
Croatia prepares for European balancing integration
The platform is also part of Croatia’s preparation for connection to European balancing systems.
HOPS expects to connect to PICASSO for aFRR and MARI for mFRR during 2027.
But the immediate market impact is domestic.
Croatia has made balancing capacity easier to slice into periods that match the availability of new flexibility providers.
That creates potential opportunities for aggregators, industrial consumers, EV fleets and automated trading platforms.
The next expansion of balancing supply may therefore come not only from building another flexible power asset.
It could come from designing market products that allow existing flexibility to compete.
Data centres could become flexible power customers as EU rules move beyond energy efficiency
Europe is beginning to treat data centres not only as large electricity consumers but as potential participants in power-system flexibility, a shift that could change how major digital infrastructure projects negotiate electricity supply and grid connections.
The European Commission on Sept. 21 proposed a common EU rating system for data centres and opened consultation on possible minimum performance standards, with legislation planned for 2027.
The policy is emerging as Europe simultaneously tries to expand computing infrastructure and manage its effect on electricity networks.
The EU aims to roughly triple data-centre capacity by 2035.
The power sector will have to accommodate that growth.
The commercial question is increasingly whether data centres should simply receive large firm grid connections or become more active electricity-system participants.
From constant load to flexible customer
Data centres have traditionally been treated as highly reliable baseload consumers.
Operators want electricity available continuously because computing services cannot simply shut down when the grid is constrained.
But not every part of data-centre electricity consumption is necessarily equally inflexible.
Some computing workloads can potentially be shifted in time or geographically.
Cooling systems contain thermal flexibility.
Backup electricity infrastructure can provide additional controllability under carefully managed conditions.
A facility can also coordinate on-site generation, electricity procurement and other energy systems.
The result is a potentially different type of large industrial consumer.
Instead of requesting 100 MW of uninterrupted capacity and leaving the grid operator to manage the consequences, a future data-centre project could increasingly need to demonstrate how much of its load is genuinely firm and how much can respond to system conditions.
Grid connection becomes part of data-centre design
That could matter substantially in Southeast Europe.
EU-member markets including Romania, Greece, Bulgaria, Croatia and Slovenia are simultaneously trying to connect renewable generation, electrify transport and industry and attract digital investment.
Network capacity cannot always expand at the same speed as new demand.
Data-centre flexibility can therefore acquire a direct commercial value.
A project able to reduce demand during rare periods of network stress may be easier and cheaper for the electricity system to accommodate than an identical project requiring maximum consumption under all conditions.
That could eventually influence where projects locate and how grid-connection agreements are structured.
A new service market forms around the data centre
The trend opens opportunities well beyond data-centre operators themselves.
Aggregators could manage flexible data-centre loads.
Energy-management companies could optimise power consumption across computing, cooling and auxiliary systems.
Electricity suppliers could combine power procurement with flexibility services.
Grid operators could potentially contract controllable demand rather than treating data centres entirely as passive load.
Engineering companies will increasingly have to design electrical and cooling systems with these operating modes in mind.
The data centre therefore becomes another potential virtual power plant resource — but with the primary business remaining digital services rather than electricity.
Waste heat adds another revenue and efficiency layer
The Commission’s policy also emphasises reuse of waste heat.
Data centres continuously reject substantial quantities of heat through their cooling systems.
Where suitable district-heating or industrial demand exists nearby, some of that energy can potentially become useful rather than being discharged to the environment.
That links digital infrastructure with another emerging electricity-market trend: power-to-heat and sector coupling.
Site selection could increasingly depend not only on fibre connectivity and electricity supply but on whether nearby energy systems can use the facility’s waste heat.
The power contract could change
The conventional data-centre energy strategy focuses heavily on securing sufficient electricity and managing its cost and carbon profile.
The next generation may add another dimension.
Large customers could increasingly need an energy strategy covering:
how much electricity they need, when they need it, how quickly demand can change and what the grid will pay for that flexibility.
The Commission explicitly argues that sustainable and flexible data centres able to adjust consumption to grid conditions can lower system costs, improve grid stability and help integrate renewable electricity.
For Southeast Europe’s emerging digital infrastructure markets, that creates a different commercial proposition.
The next data-centre electricity contract may not only price the megawatt-hours the facility consumes.
It may also price the megawatts it agrees not to consume when the power system needs them most.
