Southeast Europe’s electricity market is entering a phase in which value is increasingly tied to capabilities beyond power plants. Software that controls generation and demand, specialist optimisers and organised marketplaces for longer-term electricity contracts are becoming more important to the financing and operation of power assets. Developments in Greece and across the region illustrate this shift.
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Greek energy group METLEN is expanding its virtual power plant capabilities after acquiring energy-software company Joule and its jHub platform. Slovenian trader GEN-I says its early experience in Bulgaria shows that commercial performance can vary by as much as 30% depending on the quality of the optimiser managing a flexible electricity asset. Meanwhile, the Hellenic Energy Exchange (HEnEx) reports sharply rising participation on its bilateral-contract platform, as generators, suppliers and industrial buyers seek more structured ways to manage exposure beyond short-term spot markets.
These developments concern different parts of the electricity value chain, but each highlights the growing importance of asset control, trading and the contracting of future electricity revenues. The competitive advantage in Southeast European power may increasingly depend on who controls an asset, how effectively it is traded and how future revenues are contracted.
Digital control links generation, demand and storage
METLEN’s acquisition of Joule illustrates the shift towards managing power assets as integrated portfolios. The jHub platform is being developed to coordinate renewable generation, conventional plants, storage and large electricity consumers. This expands the traditional role of aggregation, in which early aggregators mainly represented renewable generators in wholesale and balancing markets, managed forecasting errors and helped smaller plants avoid building their own trading operations.
In the broader model, renewable generation can be combined with flexible consumption, conventional assets and storage so that a portfolio operates more like a single virtual power plant. The aim is to increase the value of the portfolio as a whole, rather than maximise each asset’s revenue independently. If renewable output falls unexpectedly, for example, an industrial customer could reduce demand, a battery could discharge or a thermal unit could adjust its output where economically and technically appropriate.
Software identifies the available response and translates physical operating constraints into commercial decisions. The required capabilities include forecasting, telemetry, automated dispatch, market access and real-time optimisation. Physical assets remain essential, but an increasing share of their value lies in the digital systems that control them.
Energy software becomes an acquisition target
METLEN’s move also points to digital capabilities being obtained through acquisitions rather than built in-house. Electricity companies have traditionally expanded by buying generation capacity, customer portfolios or trading businesses, but the next acquisition cycle could increasingly include software companies. Developing a sophisticated energy-management system from scratch can require years of work on technology, market integration and operating data.
Buying an existing platform can provide faster access to the digital infrastructure needed to manage more complex portfolios, making regional energy-software companies strategically valuable. As Romania, Bulgaria, Croatia and Serbia give aggregation and flexible demand larger roles, companies able to control thousands of distributed assets could attract interest from utilities, traders and infrastructure groups seeking regional expansion.
The value of these companies may extend beyond software-licence revenue. It could also lie in their ability to make hundreds of separate physical assets operate commercially as one controllable power plant.
Optimisation affects project performance and financing
GEN-I’s reported experience in Bulgaria highlights the role of the company operating a portfolio in electricity markets. The trader has observed performance differences of up to 30% between optimisation approaches; this is a company observation, not an independently established market average. The underlying investment issue is that flexible assets with identical technical characteristics can deliver different financial results depending on how they are traded.
Market selection, bid timing and forecasting accuracy all matter, as does the management of asset condition. Dispatch decisions also need to account for technical limits and equipment degradation. A weak optimiser can leave revenue unrealised even when the equipment performs as designed.
This changes the scope of lender due diligence for flexible electricity projects. In addition to equipment warranties, engineering, procurement and construction (EPC) contracts and grid connections, banks may need to assess the optimiser. Relevant questions include how long the company has operated in the market, what past performance it can demonstrate, how its algorithms respond to changing conditions and whether it has the financial strength to support revenue guarantees.
As a result, the optimisation agreement is becoming a core project contract. For project investors, selecting the optimiser is increasingly part of the investment decision.
Revenue guarantees and merchant exposure
More sophisticated commercial structures are emerging alongside optimisation. Pure merchant optimisation leaves investors exposed to future electricity-market conditions, while a revenue-floor agreement transfers part of that exposure to the optimiser. A tolling structure can shift even more market risk away from the investor, with profit-sharing arrangements sitting between the two.
Under a typical profit-sharing model, the owner receives an agreed base level of revenue, while the optimiser keeps part of the upside above predefined thresholds. This aligns incentives and improves revenue visibility, but the strength of such arrangements depends on 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, potentially favouring consolidation. The market may therefore include specialised software firms, large optimisation counterparties and integrated utilities able to combine both. Competition is also likely to grow: early flexible assets can earn unusually high returns where balancing and optimisation services are in limited supply, but increased competition can narrow arbitrage spreads and reduce balancing-service revenues.
Market rules also change, so an optimiser cannot depend on a single trading strategy and must move between opportunities. Algorithmic execution and access to multiple markets can help the physical plant form part of a broader trading system that chooses among the day-ahead market, intraday trading, balancing services and other flexibility products. The optimiser must be able to capture revenue and have the financial strength to support its contractual commitments.
HEnEx platform expands bilateral contracting
HEnEx reported on October 21 that its bilateral-contract platform had reached 29 members. The number of offers rose 88% year on year to 64, representing 54.4 TWh of offered energy, rather than completed transactions. Expressions of interest increased 78% to 48, and 24 offers were accepted.
These figures remain modest beside large European forward markets, but they show growth in a segment that is less standardised than Southeast Europe’s short-term electricity trading. Day-ahead and intraday exchanges are increasingly interconnected and liquid, while longer-term contracts are often arranged through private negotiations, brokers and bilateral relationships involving generators, suppliers and industrial consumers.
That process can make it difficult for participants to find suitable counterparties. A generator seeking a five-year buyer may not know which industrial customers are looking for that product, while an industrial company may receive few proposals if sellers do not know it is seeking supply. An organised bilateral platform can reduce this information gap.
Contract terms shape the electricity product
HEnEx’s figures also indicate that longer-term procurement is not determined by a single headline price. About 60% of negotiations involved price, while 42% concerned contract duration and 29% the generation profile. The shape of the electricity supply matters: a flat annual profile differs from solar-heavy daytime generation, and a three-year contract carries different risks from a ten-year agreement.
An industrial buyer may choose to fix only part of its consumption and leave the rest exposed to short-term markets. A generator may also prefer to contract with several counterparties rather than a single long-term buyer. These choices create a portfolio approach to bilateral contracts.
The emerging market extends beyond power purchase agreements (PPAs). It involves a structured contract marketplace in which duration, profile, price formula and credit terms form part of the electricity product itself.
Regional participation and market infrastructure
HEnEx plans to broaden regional participation and improve its offer-matching capabilities. A platform that only publishes offers functions mainly as a digital noticeboard; one that actively identifies compatible buyers and sellers moves closer to an organised contract market. Over time, standardisation could make common contract durations and delivery profiles easier to compare.
Greater standardisation can support liquidity, while higher liquidity can attract more participants, creating network effects similar to those that helped develop short-term exchanges. For Southeast Europe, this would address a gap between liquid spot trading and fully bespoke bilateral deals.
The developments at METLEN and Joule, GEN-I and HEnEx concern different layers of the same shift. METLEN/Joule focuses on controlling physical generation, demand and flexibility through a digital portfolio; GEN-I’s experience highlights performance and financial risk, including the counterparty’s ability to provide bankable revenue protection. HEnEx is developing infrastructure for participants to manage longer-term exposure beyond spot-market trading.
Together, these elements link assets to digital control, optimisation, contracts and financing. Greece currently provides many of the clearest examples, supported by 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 producing early operating experience in merchant asset optimisation. Croatia is widening participation for independent aggregators and redesigning its balancing market, while Serbia is establishing the legal and operational separation between electricity supply and independent aggregation. Montenegro is developing flexibility frameworks at transmission system operator (TSO) and distribution system operator (DSO) levels.
Intangible capabilities gain importance
As these markets mature, physical electricity assets will increasingly require the digital and commercial infrastructure now emerging in Greece. This could create a new class of regional energy companies that own little generation but build their businesses around software platforms, flexible customer portfolios, trading algorithms, optimisation contracts and counterparty relationships.
Traditional electricity investment focused on who owned the plant. The next cycle adds questions about who controls and trades it, who carries merchant risk, who finds the counterparty, who guarantees revenue and who owns the data needed to make those decisions. These considerations shift some power-sector value from physical infrastructure towards intangible capabilities, while leaving the power plant essential.
The next phase of Southeast Europe’s electricity market may be shaped by companies that connect physical assets to software, software to trading strategies, and trading strategies to bankable long-term contracts.
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