A conventional power plant produces far more than megawatt-hours. Its rotating machinery provides inertia, its excitation system supports voltage, its fault current helps protection systems operate and, in some cases, the plant can provide black-start capability. Historically, these services came bundled with electricity generation and were rarely priced separately.
The growth of inverter-based wind and solar generation is changing that model. Renewable plants can provide many of the same advanced grid services, but only when their equipment, inverters and control systems are specifically designed for them.
Southeast Europe still has a significant base of synchronous generation, meaning its transition is less advanced than in some northern European markets. However, periods of high renewable output are already reducing the number of thermal units operating in Greece, Romania, Bulgaria and other regional markets.
The critical question is therefore not simply the annual generation mix, but the most challenging operating hour. When large numbers of synchronous machines are offline, can the system withstand a major fault or sudden generation loss without excessive frequency or voltage deviations?
From engineering requirement to market product
Inertia can be supplied through physical assets such as synchronous condensers or simulated through fast inverter controls. Batteries equipped with grid-forming technology can respond rapidly and help establish voltage and frequency references in weak parts of the network.
Hydropower units can sometimes operate in synchronous-condensing mode, while renewable inverters can provide reactive power and voltage support even when active electricity production is limited, depending on their technical configuration.
These capabilities, however, are not free. Oversized inverters, synchronous condensers and battery operating headroom can reduce the revenue available from energy trading and other services.
If transmission system operators require these capabilities, they must determine whether they should be mandated through grid codes, procured through competitive markets or secured through long-term contracts at specific constrained locations.
That decision will directly affect project bankability, technology selection and investment economics.
Where scarcity will appear first
System-strength challenges are highly dependent on location. Islands, remote renewable-generation zones and weak transmission corridors are likely to encounter stability problems before strongly meshed networks.
This also means that retiring thermal power plants may retain strategic value even after they stop producing electricity. Existing sites often have valuable grid connections and synchronous equipment. A coal-fired power plant that has ceased commercial generation could potentially continue supporting the network through a synchronous condenser, reactive-power equipment or black-start capability.
This creates an unusual redevelopment opportunity. Brownfield generation sites could become system-services hubs, combining batteries, synchronous condensers, STATCOMs and grid-forming inverters.
Their value would no longer come from fuel supply or electricity production, but from their strategic position within the network.
Southeast Europe’s energy-transition planning should therefore examine which conventional power assets can be repurposed rather than assuming that retirement means complete removal from the electricity system.
Bankability and procurement
Investors need clearly defined and measurable products. “Grid support” is too broad a concept for project finance. Contracts need to specify response speed, duration, fault performance, availability, testing requirements and penalties.
Revenue certainty may also need to extend beyond standard balancing contracts because specialised equipment can have limited alternative uses.
Competitive tenders can work when several technologies are capable of addressing the same system need. At unique or highly constrained locations, however, direct regulated procurement may remain necessary.
Batteries are likely to benefit from this emerging market, but not every BESS installation is automatically capable of providing grid-forming services. Inverter specifications, control systems, operating reserves and commissioning procedures all matter.
A project originally designed primarily for energy arbitrage may require additional equipment or redesign to satisfy system-stability requirements. As a result, OEM capabilities and commissioning performance will become increasingly important commercial differentiators.
A new definition of capacity
The broader lesson is that power-system adequacy cannot be measured solely by the number of megawatts installed.
Two assets with identical active-power ratings can make very different contributions to system stability. One may provide fast frequency response, voltage control or black-start capability, while another may provide none of these services.
Southeast European electricity markets will therefore increasingly need to value inertia, fast frequency response, voltage support, black start and grid strength explicitly.
That will create new revenue opportunities for batteries, renewable projects, hydro facilities and specialised grid assets. At the same time, it will reveal the hidden value that conventional thermal fleets historically provided without a separate market price.
The transition to a more renewable power system will be more credible if these services are identified and procured before conventional units retire.
The next generation of Southeast European capacity markets and ancillary-service mechanisms will therefore need to answer a broader question than simply how much electricity an asset can produce: what kind of electrical system can that asset help keep stable?
