Southeast Europe’s electricity market is entering a phase in which valuable capabilities increasingly extend beyond power plants. Software that controls generation and demand, specialists that optimise merchant revenues, and marketplaces for longer-term electricity contracts are becoming central to how assets are financed and operated. Developments involving Greece, Bulgaria and the wider 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 early experience in Bulgaria shows that the commercial performance of a flexible electricity asset can vary by as much as 30%, depending on the quality of its optimiser. Meanwhile, the Hellenic Energy Exchange (HEnEx) reports sharply rising participation on its bilateral-contract platform as generators, suppliers and industrial buyers seek structured ways to manage exposure beyond short-term spot markets.
Digital platforms bring generation, demand and flexibility together
METLEN’s acquisition of Joule illustrates the move towards integrated portfolios. The jHub platform is being developed to manage a wider mix of renewable generation, conventional plants, storage and large electricity consumers. This takes aggregation beyond its traditional regional role of representing renewable generators in wholesale and balancing markets.
Early electricity aggregators managed forecasting errors and helped smaller plants avoid setting up their own trading operations. The emerging model combines renewable generation with flexible consumption, conventional assets and storage, so a portfolio can operate increasingly like a single virtual power plant. The commercial aim is to maximise the value of the portfolio as a whole, rather than the revenue of each asset in isolation.
If renewable output falls unexpectedly, another asset in the portfolio can respond. An industrial customer could reduce demand, a battery could discharge, or a thermal unit could adjust output where economically and technically appropriate. Software identifies the available response and translates physical operating constraints into commercial decisions.
This differs materially from conventional energy supply. Key capabilities include forecasting, telemetry, automated dispatch, market access and real-time optimisation. Physical assets remain essential, but an increasing share of value lies in the digital layer that controls them.
Software acquisitions and optimiser performance
METLEN’s move also points to digital capabilities being obtained through acquisitions rather than developed in-house. Electricity companies have traditionally expanded by buying generation capacity, customer portfolios or trading businesses; future acquisitions could increasingly target software companies. Building a sophisticated energy-management system from scratch requires years of development, market integration and operating data, while an existing platform can provide faster access to infrastructure for managing complex portfolios.
Regional energy-software companies may therefore have strategic value. As Romania, Bulgaria, Croatia and Serbia expand the roles of aggregation and flexible demand, companies able to control thousands of distributed assets could attract utilities, traders and infrastructure groups seeking regional growth. Their value may extend beyond software-licence revenue to the ability to make hundreds of separate physical assets operate commercially like one controllable power plant.
The second structural change concerns the company that operates a portfolio in electricity markets. GEN-I’s reported experience in Bulgaria indicates a performance gap of as much as 30% between optimisation approaches. This is a company observation, not an independently established market average, but it highlights how flexible assets with identical technical characteristics can produce different financial results depending on how they are traded.
Market selection, bid timing and forecasting accuracy all matter, as does management of asset state. Dispatch decisions also need to account for technical limits and equipment degradation. A weak optimiser can leave significant revenue unrealised even when the equipment performs as designed.
Optimisation contracts, revenue risk and market competition
This has implications for lender due diligence. Banks financing flexible electricity projects may need to assess not only equipment warranties, EPC contracts and grid connections, but also the optimiser. They could examine the company’s operating history in the relevant electricity market, its demonstrated performance, how its algorithms respond to changing market conditions, and whether it has the financial strength to support revenue guarantees.
The optimisation agreement is beginning to resemble a core project contract as more sophisticated commercial structures develop across the region. Pure merchant optimisation leaves investors exposed to future electricity-market conditions, while a revenue-floor agreement transfers some of that exposure to the optimiser. A tolling structure can shift more market risk away from the investor, with profit-sharing arrangements between these models.
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 can align incentives and improve revenue visibility, but the contract is only as strong as the counterparty behind the guarantee. A small technology company may have a strong algorithm but insufficient balance-sheet capacity for a multi-year minimum-revenue commitment; a larger trader or utility may combine digital optimisation with liquidity, credit support and access to multiple markets.
That could favour consolidation, with the market potentially divided among specialist software firms, large optimisation counterparties and integrated utilities able to combine both. For project investors, choosing the optimiser is increasingly part of the investment decision. Its importance may rise as competition narrows arbitrage spreads and reduces balancing-service revenues, while market rules continue to evolve.
Early flexible assets can earn unusually high revenues where the supply of balancing and optimisation services is limited, but those returns rarely remain unchanged. Optimisers cannot rely on a single trading strategy and need to move between opportunities, favouring algorithmic execution and access to multiple markets. A power plant becomes one component of a broader trading system that can select among the day-ahead market, intraday trading, balancing services and other flexibility products.
Software capability and financial credibility intersect in this model: the optimiser needs to capture revenue and be strong enough to honour contractual commitments. The emerging market may therefore involve specialised software firms, larger counterparties and utilities that combine optimisation with financial support.
HEnEx expands its bilateral-contract platform
The third development concerns how participants contract longer-term electricity risk. On October 21, HEnEx said its bilateral-contract platform had reached 29 members, while the number of offers had risen 88% year on year to 64. Those offers represented 54.4 TWh of offered energy, rather than completed transactions. Expressions of interest increased 78% to 48, and 24 offers were accepted.
The figures remain modest compared with large European forward markets, but they show growth in a segment that is less standardised than Southeast Europe’s short-term trading infrastructure. Day-ahead and intraday exchanges are increasingly interconnected and liquid, while longer-term contracts are often arranged through private negotiations, brokers and bilateral relationships among generators, suppliers and industrial consumers. That can create friction when potential buyers and sellers do not know that the other side is seeking a particular product.
An organised bilateral platform can reduce this information gap. A generator looking for a five-year buyer may not know which industrial customers want the same product, while an industrial company may receive few proposals because potential sellers do not know it is seeking supply. HEnEx plans to expand regional participation and strengthen its offer-matching capabilities.
Contract terms shape the electricity product
HEnEx’s figures also show that longer-term procurement involves more than a headline price. Around 60% of negotiations concerned price, 42% related to contract duration and 29% to the generation profile. The shape of supply increasingly affects its value: a flat annual profile differs from solar-heavy daytime production, and a three-year contract carries different risks from a ten-year agreement.
An industrial buyer may want to fix only part of its consumption and leave the rest exposed to short-term markets. A generator may likewise seek several counterparties rather than one long-term buyer, creating a portfolio approach to bilateral contracts. The developing market is not limited to power purchase agreements (PPAs); it concerns a structured contract marketplace in which duration, profile, price formula and credit terms form part of the electricity product.
A platform that only publishes offers functions mainly as a digital noticeboard, while one that actively matches compatible buyers and sellers begins to operate more like an organised contract market. Over time, common contract durations and delivery profiles could become easier to compare, supporting standardisation and liquidity. Greater liquidity can attract further participants, creating network effects similar to those that supported the development of short-term exchanges.
For Southeast Europe, this could fill a gap between liquid spot trading and fully bespoke bilateral deals. The METLEN/Joule development concerns control: combining physical generation, demand and flexibility in an optimised digital portfolio. GEN-I’s experience concerns performance and financial risk: how effectively that portfolio is traded and which counterparty can provide bankable revenue protection.
Regional markets develop the supporting infrastructure
HEnEx’s role concerns contracting infrastructure and how participants manage longer-term exposure beyond spot-market trading. Together, these areas form a market architecture connecting assets, digital control, optimisation, contracts and financing. This combination could become a defining theme for Southeast European electricity markets over the next investment cycle.
Greece is providing some of the clearest examples, with relatively advanced retail, trading and aggregation markets, but the opportunity is regional. Romania is developing one of Southeast Europe’s largest flexibility markets and already attracting specialist optimisation providers. Bulgaria is building early operating experience in merchant asset optimisation.
Croatia is opening wider participation to independent aggregators and redesigning its balancing market. Serbia is establishing the legal and operational separation between electricity supply and independent aggregation. Montenegro is developing flexibility frameworks at both transmission system operator (TSO) and distribution system operator (DSO) level.
As these markets mature, physical electricity assets will increasingly need the digital and commercial infrastructure now emerging in Greece. This could create a new class of regional energy companies, some of which will own little generation themselves. Their core assets may instead be software platforms, flexible customer portfolios, trading algorithms, optimisation contracts and counterparty relationships.
Digital and commercial capabilities extend beyond the plant
The traditional electricity-sector investment question was who owns the plant. The next cycle adds questions about who controls it, who trades it, who carries merchant risk, who finds the counterparty, who guarantees revenue and who owns the data required to make those decisions. These issues shift part of the power sector’s value from physical infrastructure towards intangible capabilities.
The power plant remains essential, but it is increasingly only the starting point. 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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