A conventional power plant produces much more than electricity. Its rotating machinery provides inertia, its excitation systems support voltage, and its fault current helps protection systems respond correctly. Some plants can also provide black-start capability, allowing parts of the grid to be restored after a major outage.
For decades, these services were effectively bundled with electricity generation and rarely received a separate market value. The rapid expansion of inverter-based wind and solar generation is now changing that model.
Renewable plants can provide many of the same grid-support services, but only when their inverters, control systems and other equipment are specifically designed and configured to do so.
Southeast Europe still has a substantial fleet of synchronous generators, so its transition is not as advanced as in some northern European power systems. However, periods of high renewable output are already reducing thermal-unit commitment in Greece, Romania, Bulgaria and other regional markets.
The key issue is therefore not simply the annual generation mix. It is the most demanding operating hour.
When large numbers of synchronous machines are offline, can the system withstand a major fault, sudden generation loss or other disturbance without unacceptable frequency and voltage deviations?
From engineering requirement to market product
There are several ways to provide these capabilities.
Inertia can come from synchronous condensers or be partially replicated through fast inverter controls. Batteries equipped with grid-forming technology can respond rapidly to disturbances and help establish voltage and frequency references in weak parts of the network.
Hydropower plants can sometimes operate in synchronous-condensing mode, while renewable inverters can provide reactive power and voltage support even when their active-power output is limited.
But these capabilities have an economic cost.
Oversized inverters, synchronous condensers and reserved battery capacity can reduce the amount of equipment available for energy arbitrage or other commercial services. Developers therefore need visibility on how these services will be compensated.
Transmission system operators may choose to impose technical requirements through grid codes, procure services through competitive markets or secure them through long-term contracts at strategically important network locations.
The procurement model will directly affect project bankability, technology selection and investment returns.
Where scarcity will appear first
Grid-strength and stability problems are highly location-specific. Islands, remote renewable-generation zones and weak transmission corridors are likely to encounter them before strongly meshed parts of the network.
This creates an unexpected opportunity for retiring thermal power plants.
Even when a coal or gas plant 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.
This creates the possibility of brownfield system-services hubs combining batteries, synchronous condensers, STATCOMs and grid-forming inverters.
Their strategic value would no longer depend on fuel availability or electricity generation. Instead, it would come from their location within the transmission network and their ability to provide services that the system needs.
Southeast Europe’s energy-transition strategies should therefore assess which conventional assets can be repurposed before treating their retirement as complete removal from the power system.
Bankability and procurement
Investors need clearly defined products if grid-support services are to become financeable.
“Grid support” is too broad for a project-finance model. Contracts need to specify response speed, duration, availability, performance requirements, testing procedures and penalties.
Revenue certainty may also need to extend beyond conventional balancing contracts because specialised grid equipment can have limited alternative uses.
Competitive tenders can be effective when multiple technologies can solve the same system problem. At unique network locations, however, direct regulated procurement or long-term contracting may be more appropriate.
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 matter. A battery designed primarily for energy arbitrage may require additional equipment or a different operating strategy before it can satisfy system-stability requirements.
As a result, OEM technology, control capabilities and commissioning performance could become important commercial differentiators.
A new definition of capacity
The broader implication is that power-system adequacy can no longer be measured solely in megawatts.
Two assets with identical active-power ratings may make very different contributions to system stability. One could provide fast frequency response, voltage control and black-start capability, while another may provide none of these services.
Southeast European markets will therefore increasingly need to place explicit value on inertia, fast frequency response, voltage support, black start and grid strength.
That will create new revenue opportunities for batteries, renewable generators, hydropower facilities, synchronous condensers and other specialised assets.
At the same time, it will expose the hidden value that conventional thermal fleets historically provided without receiving a clearly identifiable market payment.
The transition toward a more renewable electricity system will be more credible if these services are identified, valued and procured before conventional synchronous generators retire.
The next generation of Southeast European capacity and ancillary-service markets will therefore need to ask a broader question than how much electricity an asset can produce.
The real question will be what kind of power system that asset can help keep stable.
