A conventional power plant provides more than electricity. Its rotating machinery contributes inertia, excitation systems support voltage, and fault current supports protection system operation. Some plants can also offer black-start capability to restore parts of the grid after major outages.
For decades, these grid-support services were largely bundled with generation and seldom traded with a separate market value. The expansion of inverter-based wind and solar is changing that model across power systems.
Renewable plants can deliver similar support functions only when their inverters, control systems and related equipment are specifically designed and configured for those tasks. Where such capabilities are not engineered into the plant design, the services may not be available when needed.
Operating hours and system response requirements
Southeast Europe retains a substantial fleet of synchronous generators, so its transition is less advanced than in some northern European systems. Even so, periods of high renewable output have already reduced thermal-unit commitment in Greece, Romania, Bulgaria and other regional markets.
The relevant issue is not the annual generation mix alone. It is the most demanding operating hour when large numbers of synchronous machines are offline.
In those conditions, system operators must assess whether the grid can withstand a major fault, sudden generation loss or other disturbances without unacceptable frequency and voltage deviations. This requirement links grid stability performance to the availability of specific technical capabilities.
Engineering options for inertia, voltage and black-start
Inertia can be supplied by synchronous condensers or partially replicated through fast inverter controls. Batteries using grid-forming technology can respond rapidly to disturbances and help establish voltage and frequency references in weak network areas.
Hydropower plants can sometimes run in synchronous-condensing mode. Renewable inverters can also provide reactive power and voltage support even when active-power output is constrained.
Providing these functions can carry an economic cost for project developers. Oversized inverters, synchronous condensers and reserved battery capacity may reduce equipment available for energy arbitrage or other commercial services.
How transmission operators procure grid-support services
Developers therefore need clarity on how grid-support services will be compensated. Transmission system operators may set requirements through grid codes, procure services via competitive markets, or secure them through long-term contracts at strategically important network locations.
The procurement approach affects project bankability, technology selection and investment returns. Investors typically require clearly defined products rather than broad descriptions of “grid support” for financeability.
Contracts need to specify response speed, duration, availability, performance requirements, testing procedures and penalties. Revenue certainty may also need to extend beyond conventional balancing arrangements because specialised grid equipment can have limited alternative uses.
Location-specific scarcity and repurposing conventional assets
Grid-strength and stability challenges are highly location-specific. Islands, remote renewable-generation zones and weak transmission corridors are likely to experience them before strongly meshed parts of the network.
This pattern can create opportunities for retiring thermal power plants. Even if a coal or gas unit stops producing electricity commercially, its site may retain valuable grid infrastructure and synchronous equipment.
The location could potentially be repurposed for synchronous-condensing services, reactive-power support, black-start capability or battery storage. Such redeployment could enable brownfield system-services hubs combining batteries, synchronous condensers, STATCOMs and grid-forming inverters.
Bankability requirements for batteries and other technologies
Southeast Europe’s energy-transition strategies should assess which conventional assets can be repurposed before treating retirement as complete removal from the power system. For investors, product definitions become central when grid-support services are intended to become financeable revenue streams.
Batteries are likely to benefit from this emerging market, but not every BESS installation can automatically provide grid-forming services. Inverter ratings, control architecture, available operating headroom and commissioning procedures all influence whether stability requirements can be met.
A battery designed primarily for energy arbitrage may require additional equipment or a different operating strategy before it can satisfy system-stability needs. As a result, OEM technology choices, control capabilities and commissioning performance could become commercial differentiators.
A broader definition of capacity for adequacy
Power-system adequacy cannot be measured solely in megawatts under these evolving requirements. Two assets with identical active-power ratings may contribute differently to system stability depending on whether they provide fast frequency response, voltage control or black-start capability.
Southeast European markets will therefore increasingly need explicit valuation for inertia, fast frequency response, voltage support, black start and grid strength. This would create revenue opportunities for batteries, renewable generators, hydropower facilities, synchronous condensers and other specialised assets.
It would also highlight the value that conventional thermal fleets historically provided without receiving a clearly identifiable market payment. The transition toward higher shares of renewables depends on identifying, valuing and procuring these services before conventional synchronous generators retire.
The next generation of Southeast European capacity and ancillary-service markets will therefore need to ask more than how much electricity an asset can produce. The question becomes what kind of power system that asset helps keep stable.
