Southeast Europe’s power market is moving into a phase where value increasingly comes from capabilities beyond the power plants themselves. Software that manages generation and demand, specialists that optimise merchant revenues and organised platforms for longer-term electricity contracts are taking a more central role in asset financing and operation.
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Developments involving Greece’s METLEN and Hellenic Energy Exchange (HEnEx), alongside the experience of Slovenian trader GEN-I in Bulgaria, illustrate the shift. METLEN is expanding its virtual power plant capabilities after acquiring energy-software company Joule and its jHub platform. GEN-I says the commercial performance of a flexible electricity asset in Bulgaria can vary by as much as 30% according to the quality of its optimiser.
HEnEx, meanwhile, has recorded strong growth in participation on its bilateral-contract platform, as generators, suppliers and industrial buyers seek more structured ways to manage electricity exposure beyond short-term spot markets. Each development addresses a different part of the electricity value chain. Together, they highlight the growing importance of who controls an asset, how effectively it is traded and how future revenues are contracted.
Integrated portfolios bring assets under digital control
METLEN’s acquisition of Joule illustrates the move from managing individual plants to overseeing integrated portfolios. The jHub platform is being developed to manage a broader mix of renewable generation, conventional plants, storage and large electricity consumers. This extends aggregation beyond its traditional regional role.
Early electricity aggregators mainly represented renewable generators in wholesale and balancing markets. They managed forecasting errors and helped smaller plants avoid the cost of setting up their own trading operations. The developing model combines renewable generation with flexible consumption, conventional assets and storage, allowing the portfolio to operate increasingly like a single virtual power plant.
The commercial goal 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 portfolio resource may respond. A flexible industrial customer could cut demand, a battery could discharge, or a thermal unit could adjust output where economically and technically appropriate.
Software identifies the available response and turns physical operating constraints into commercial decisions. This differs materially from conventional energy supply. Forecasting, telemetry, automated dispatch, market access and real-time optimisation become core capabilities, while a growing share of value sits in the digital layer that controls the physical asset.
Energy software becomes an acquisition target
METLEN’s move also indicates that energy companies may increasingly acquire digital capabilities rather than build them internally. Historically, electricity companies expanded by buying generation capacity, customer portfolios or trading businesses. The next acquisition cycle could place greater emphasis on software companies.
Developing a sophisticated energy-management system from scratch takes years of development, market integration and operating data. Buying an established technology platform can provide faster access to the digital infrastructure needed to manage increasingly complex portfolios. This makes regional energy-software companies strategically valuable.
Romania, Bulgaria, Croatia and Serbia are giving aggregation and flexible demand a larger role. Companies able to control thousands of distributed assets could become acquisition targets for utilities, traders and infrastructure groups seeking regional expansion. Their value may extend beyond software licence revenue to the ability to make hundreds of separate assets operate commercially like one controllable power plant.
Optimisers become part of project bankability
A second structural change concerns the company that operates a portfolio in electricity markets. GEN-I’s reported experience in Bulgaria points to a performance gap of up to 30% between different optimisation approaches. The figure is a company observation, not an independently established market average, but it highlights an important investment issue: assets with identical technical specifications can produce very different financial results depending on how they are traded.
Performance depends on market selection, bid timing and forecast accuracy, as well as management of the asset’s operating state. Dispatch decisions also need to account for technical limits and equipment degradation. A weak optimiser may leave substantial revenue unrealised even when the equipment performs as designed.
This affects 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 provider’s operating history in the relevant market, its demonstrated performance, how its algorithms respond to changing conditions and whether it has the financial capacity to support revenue guarantees.
The optimisation agreement is consequently beginning to resemble a core project contract. That matters as the region adopts more sophisticated commercial structures. Pure merchant optimisation leaves investors exposed to future electricity-market conditions, while a revenue-floor agreement transfers part of that exposure to the optimiser and a tolling structure can shift still more market risk away from the investor.
Revenue guarantees and profit sharing develop
Profit-sharing arrangements sit between pure merchant optimisation and tolling. In a typical model, the owner receives an agreed base level of revenue, while the optimiser keeps a share of the upside above predefined thresholds. This aligns incentives and improves revenue visibility, but the strength of the arrangement depends on the counterparty providing the guarantee.
A small technology company may have a strong algorithm but lack the 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. This could encourage consolidation.
The market may develop into distinct groups: specialised software firms, large optimisation counterparties and integrated utilities able to combine both capabilities. For project investors, choosing an optimiser is increasingly part of the investment decision.
Competition makes merchant revenues less predictable
Optimisation is likely to become more important as competition increases. Early flexible assets can earn unusually high revenues when the supply of balancing and optimisation services is limited, but those returns rarely remain unchanged. Greater competition can narrow arbitrage spreads and reduce balancing-service revenues, while market rules also continue to evolve.
Optimisers therefore cannot depend on a single trading strategy and must move continuously between opportunities. This favours algorithmic execution and access to multiple markets. The physical plant becomes one element of a broader trading system that determines whether value is greatest in the day-ahead market, intraday trading, balancing services or another flexibility product.
Software capability and financial credibility intersect in this model. The optimiser needs to capture revenue effectively and have the strength to honour its contractual commitments.
HEnEx platform expands bilateral contracting
A third trend concerns the way longer-term electricity risks are contracted. On October 21, HEnEx reported 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; that volume does not represent 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 their direction is significant. Southeast Europe has developed substantial short-term trading infrastructure, with increasingly interconnected and liquid day-ahead and intraday exchanges, while longer-term contract markets remain far less standardised.
Generators, suppliers and industrial consumers often depend on private negotiations, brokers and bilateral relationships. This can make it difficult for a generator seeking a five-year buyer to identify industrial customers looking for the same product. An industrial company may also receive only a small number of proposals if potential sellers do not know it is seeking supply.
An organised bilateral platform can reduce that information gap. The HEnEx figures also show that longer-term procurement involves more than a headline price: around 60% of negotiations concerned price, 42% contract duration and 29% the generation profile.
Contract terms shape the electricity product
The shape of electricity supply is increasingly important to its value. A flat annual profile is not equivalent to daytime production weighted towards solar, 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 prefer several counterparties to a single long-term buyer. This creates a portfolio approach to bilateral contracts. The developing market is not limited to PPAs; it involves a structured contract marketplace in which duration, profile, price formula and credit terms are components of the electricity product.
HEnEx aims to build a regional marketplace
HEnEx plans to widen regional participation and improve its offer-matching capabilities. A platform that only publishes offers functions mainly as a digital noticeboard, while one that actively identifies compatible buyers and sellers begins to operate more like an organised contract market.
Over time, this could support standardisation by making common contract durations and delivery profiles easier to compare. Greater standardisation improves liquidity, and higher liquidity attracts more participants. That process can generate the network effects that helped develop short-term exchanges.
For Southeast Europe, such a platform could fill a gap between liquid spot trading and fully bespoke bilateral deals.
Three developments point to a shared market shift
The developments involving METLEN, GEN-I and HEnEx cover different layers of the same transition. METLEN and Joule address control: how to combine physical generation, demand and flexibility in one digitally optimised portfolio. GEN-I addresses performance and financial risk: how effectively a portfolio is traded and which counterparty can provide bankable revenue protection.
HEnEx addresses contracting infrastructure: how market participants manage longer-term exposure beyond spot trading. Together, the layers form an emerging market architecture linking assets, digital control, optimisation, contracts and financing.
Regional markets develop flexibility infrastructure
Greece is providing many of the clearest examples because its retail, trading and aggregation markets are relatively advanced, but the opportunity extends across the region. Romania is developing one of Southeast Europe’s largest flexibility markets and is already attracting specialist optimisation providers. Bulgaria is building early operating experience in merchant asset optimisation.
Croatia is widening participation for 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 TSO and DSO level.
As these markets mature, physical electricity assets will increasingly require the digital and commercial infrastructure now emerging in Greece. This could give rise to 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.
Intangible capabilities add to the value of power assets
The traditional electricity-sector investment question was who owned the plant. The next investment cycle adds questions about who controls and trades it, who carries merchant risk, who finds the counterparty and who guarantees revenue. It also raises the question of who owns the data needed 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 able to connect physical assets to software, software to trading strategies, and those strategies to bankable long-term contracts.
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