Southeast Europe’s electricity market is entering a new phase in which some of the most valuable assets may increasingly sit outside the power plants themselves.
Powered by Virtu.Energy
Software platforms capable of controlling generation and demand, specialist companies that optimise merchant revenues and organised marketplaces for longer-term electricity contracts are becoming increasingly important to how power assets are financed, operated and traded.
Three developments in Greece and the wider region illustrate this shift.
Greek energy group METLEN is expanding its virtual power plant capabilities following its acquisition of energy-software company Joule and its jHub platform.
Slovenian trader GEN-I says its early experience in Bulgaria shows that commercial performance can differ by as much as 30% depending on the quality of the optimiser controlling a flexible electricity asset.
Meanwhile, the Hellenic Energy Exchange, HEnEx, is recording strong growth in participation on its bilateral-contract platform as generators, suppliers and industrial buyers look for more structured ways to manage electricity exposure beyond short-term spot markets.
Individually, these developments address different parts of the electricity value chain.
Together, they point to the same broader conclusion.
The next competitive advantage in Southeast European power may increasingly depend on who controls an asset, how intelligently it is traded and how efficiently future electricity revenues are contracted.
From individual plants to integrated portfolios
METLEN’s acquisition of Joule illustrates the first part of this transition.
The jHub platform is being developed to manage a broader mix of renewable generation, conventional plants, storage and large electricity consumers within integrated portfolios.
This takes aggregation beyond its traditional regional role.
Early electricity aggregators primarily represented renewable generators in wholesale and balancing markets, helping manage forecasting errors and allowing smaller plants to avoid building their own trading and market-access operations.
The emerging model is considerably broader.
Renewable generation can be combined with flexible consumption, conventional assets and storage so that an entire portfolio increasingly behaves like one virtual power plant.
The commercial objective is no longer simply to maximise the revenue generated by each asset independently.
Instead, the focus is on maximising the value of the portfolio as a whole.
If renewable generation falls unexpectedly, another asset within the portfolio can respond.
A flexible industrial customer could reduce demand.
A battery could discharge.
A thermal unit could adjust output where economically and technically appropriate.
The software identifies the available response and converts physical operating constraints into commercial decisions.
That represents a materially different business model from conventional energy supply.
The key capabilities increasingly include forecasting, telemetry, automated dispatch, market access and real-time optimisation.
The physical asset remains essential, but a growing share of the value sits in the digital layer that controls it.
Energy software moves into M&A strategies
METLEN’s move also suggests that digital capabilities may increasingly be acquired rather than developed entirely in-house.
Electricity companies have traditionally expanded through purchases of generation capacity, customer portfolios or trading businesses.
The next acquisition cycle could increasingly target energy software companies.
Building a sophisticated energy-management platform from the ground up requires years of development, market integration and operating data.
Acquiring an established technology platform can provide faster access to the digital infrastructure needed to manage increasingly complex electricity portfolios.
That makes regional energy-software companies strategically significant.
As Romania, Bulgaria, Croatia and Serbia create larger roles for aggregation and flexible demand, companies capable of controlling thousands of distributed assets could become attractive acquisition targets for utilities, traders and infrastructure groups seeking regional expansion.
Their value may not be measured solely through software licence revenue.
The greater strategic value could lie in their ability to make hundreds of separate physical assets operate commercially like one controllable power plant.
The optimiser becomes part of project bankability
The second structural change concerns the company responsible for operating that portfolio in electricity markets.
GEN-I’s reported Bulgarian experience suggests a performance gap of as much as 30% between different optimisation approaches.
The figure is a company observation rather than an independently established market average, but the underlying investment issue remains important.
Flexible assets with identical technical characteristics can produce significantly different financial results depending on how they are traded.
Market selection matters.
So does the timing of bids.
Forecasting accuracy matters.
Asset-state management also matters.
Technical limits and equipment degradation need to be incorporated into dispatch decisions.
A weak optimiser can leave significant revenue unrealised even when the underlying equipment performs exactly as designed.
That changes the way lenders may approach due diligence.
Banks financing flexible electricity projects increasingly need to assess more than equipment warranties, EPC contracts and grid connections.
They may also need to assess the optimiser itself.
A lender could examine how long the company has operated in the relevant electricity market, what historical performance it can demonstrate, how its algorithms respond to changing market conditions and whether it has sufficient financial strength to support revenue guarantees.
The optimisation agreement therefore begins to resemble a core project contract.
Revenue floors and profit sharing emerge
That becomes particularly important as the regional market moves towards more sophisticated commercial structures.
Pure merchant optimisation leaves investors exposed to future electricity-market conditions.
A revenue-floor agreement transfers part of that exposure to the optimiser.
A tolling structure can move even more market risk away from the investor.
Profit-sharing arrangements sit between the two.
Under a typical model, the owner receives an agreed base level of revenue while the optimiser retains part of the upside generated above predefined thresholds.
This can align incentives while providing greater revenue visibility.
But such agreements are only as strong as the counterparty providing the guarantee.
A small technology company may have a strong algorithm but insufficient balance-sheet capacity to support a multi-year minimum-revenue commitment.
A larger trader or utility may be able to combine digital optimisation with liquidity, credit support and access to multiple markets.
That potentially favours further consolidation.
The future market may therefore divide between specialised software firms, large optimisation counterparties and integrated utilities capable of combining both capabilities.
For project investors, selecting the optimiser increasingly becomes part of the investment decision itself.
Merchant revenues become harder to forecast
The importance of optimisation is likely to increase as competition develops.
Early flexible assets can earn unusually high revenues in markets where the supply of balancing and optimisation services is limited.
Those returns rarely remain unchanged.
Greater competition can narrow arbitrage spreads and reduce balancing-service revenues.
Market rules also evolve.
The optimiser therefore cannot depend on a single trading strategy.
It needs to move continuously between available opportunities.
That favours algorithmic execution and multi-market access.
The physical plant becomes one component of a broader trading system capable of deciding whether value is highest in the day-ahead market, intraday trading, balancing services or another flexibility product.
This is where software capability and financial credibility increasingly intersect.
The optimiser must be smart enough to capture revenue and strong enough to stand behind its contractual commitments.
Bilateral markets become more organised
The third trend is emerging around the way longer-term electricity risk is contracted.
HEnEx said on October 21 that its bilateral-contract platform had reached 29 members, while the number of offers increased 88% year on year to 64.
Those offers represented 54.4 TWh, although the figure reflects offered energy rather than completed transactions.
Expressions of interest increased 78% to 48, while 24 offers were accepted.
The numbers remain modest compared with the largest European forward markets, but the direction is significant.
Southeast European electricity trading has developed strong short-term market infrastructure.
Day-ahead and intraday exchanges are becoming increasingly interconnected and liquid.
Longer-term contract markets, however, remain much less standardised.
Generators, suppliers and industrial consumers often rely on private negotiations, brokers and established bilateral relationships.
That creates friction.
A generator looking for a five-year buyer may not know which industrial customers are currently seeking the same product.
An industrial company may receive only a limited number of proposals because potential sellers do not know that it is looking.
An organised bilateral platform can reduce that information gap.
Contract structure becomes part of the commodity
The HEnEx figures also demonstrate why longer-term electricity procurement cannot be reduced to a single headline price.
Around 60% of negotiations involved price, while 42% concerned contract duration and 29% the generation profile.
That matters because the value of electricity increasingly depends on its shape.
A flat annual profile is not equivalent to solar-heavy daytime production.
A three-year contract carries different risks from a ten-year agreement.
An industrial buyer may want only part of its consumption fixed while leaving the remainder exposed to short-term markets.
A generator may similarly prefer several counterparties rather than one long-term buyer.
This creates a more sophisticated portfolio approach to bilateral contracts.
The emerging market is therefore not simply about PPAs.
It is about building a structured contract marketplace where duration, generation profile, price formula and credit terms become components of the electricity product itself.
From digital noticeboard towards regional marketplace
HEnEx plans to expand regional participation and strengthen its offer-matching capabilities.
That could prove to be the more important development.
A platform that simply publishes offers functions mainly as a digital noticeboard.
A platform that actively identifies compatible buyers and sellers begins to operate more like an organised contract market.
Over time, this can promote standardisation.
Common contract durations and delivery profiles become easier to compare.
Greater standardisation improves liquidity.
Higher liquidity can attract additional participants.
The process can create network effects similar to those that helped develop short-term electricity exchanges.
For Southeast Europe, this would fill an important gap between increasingly liquid spot trading and completely bespoke bilateral agreements.
Three businesses, one regional shift
The METLEN, GEN-I and HEnEx developments therefore represent different layers of the same transition.
METLEN/Joule addresses control.
The question is how to combine physical generation, demand and flexibility into one optimised digital portfolio.
GEN-I addresses performance and financial risk.
The question is how effectively that portfolio is traded and which counterparty can provide bankable revenue protection.
HEnEx addresses contracting infrastructure.
The question is how participants manage longer-term exposure once they move beyond spot-market trading.
Together, these layers form an increasingly complete market architecture:
asset → digital control → optimisation → contract → financing.
That architecture could become one of the defining themes of Southeast European electricity markets during the next investment cycle.
Regional implications
Greece is currently providing many of the clearest examples because it has relatively advanced retail, trading and aggregation markets.
But the opportunity is regional.
Romania is developing one of Southeast Europe’s largest flexibility markets and is already attracting specialist optimisation providers.
Bulgaria is generating early operating experience in merchant asset optimisation.
Croatia is opening wider participation for independent aggregators and redesigning its balancing market.
Serbia is creating the legal and operational separation between electricity supply and independent aggregation.
Montenegro is developing TSO- and DSO-level flexibility frameworks.
As these markets mature, physical electricity assets will increasingly require the same digital and commercial infrastructure now emerging in Greece.
That could create a new class of regional energy companies.
Some may own relatively little generation themselves.
Their core assets could instead be software platforms, flexible customer portfolios, trading algorithms, optimisation contracts and counterparty relationships.
The next electricity asset may be intangible
The traditional electricity-sector investment question was relatively straightforward:
- Who owns the plant?
- The next cycle adds several additional questions.
- Who controls the plant?
- Who trades it?
- Who carries the merchant risk?
- Who finds the counterparty?
- Who guarantees the revenue?
- And who owns the data required to make those decisions?
These questions move part of power-sector value away from physical infrastructure and towards intangible capabilities.
The power plant remains essential.
But increasingly, it is only the starting point.
The next phase of Southeast Europe’s electricity market may be defined by companies capable of connecting physical assets to software, software to trading strategies and trading strategies to bankable long-term contracts.
Powered by Virtu.Energy
