National Power Grid Transition from Physical to Synthetic Inertia
In electric power systems, Rotational Synchronous Inertia (RSI) refers to the electromechanical kinetic energy stored in the large rotating masses of generators within power stations that are synchronized to the grid. Every generator in every hydroelectric, fossil-fueled, and nuclear power station has its own RSI, and grid RSI is also contributed to by large synchronous industrial motors on the client side of the same HVAC grid. All generators connected to the same synchronous grid rotate in precise synchronization, producing a constant-frequency AC electricity source: 50 Hz in Australia and 60 Hz in North America. RSI is a physical property defined by the formula H = E/S_Rated, where the inertia constant H, expressed in seconds, indicates how long a machine can supply its rated power using its own stored kinetic energy.
That stored energy is the grid's shock absorber. When a large generator unexpectedly trips, the system frequency dips. Synchronous rotating masses automatically and instantaneously release kinetic energy, slowing the Rate of Change of Frequency (RoCoF). This instantaneous automatic reaction provides a time buffer that buys grid operators precious seconds, typically 5 to 10 seconds, to bring online supplementary generation or activate emergency responses such as load shedding before cascading failures or blackouts occur.
For more than a century, this RSI function was provided automatically because it was, in a sense, a natural by-product of the manual operation of large rotating machines that generated electricity. Today, solar photovoltaics, wind power, and batteries do not provide their own rotating RSI in the same way that rotating synchronous machines do. Solar panels and wind turbines are decoupled from the HVAC grid frequency and lack the heavy, spinning metal that would naturally absorb disturbances. This does not mean that future grids will operate with less inertia; that would lead to blackouts. Rather, so-called "Synthetic Inertia" (SI) will have to be supplied by other means to replace RSI. Stability, or "System Strength," will become an explicit service: measured, remunerated, localized, and sometimes provided by assets that were seen only as load or as intermittent generation.
Most inverters have historically operated in grid-following (GFL) mode. A GFL inverter acts as a controlled current source: it tracks the voltage and frequency signals already established by the grid and injects power accordingly, but it does not create those signals itself, and it must immediately disconnect during a blackout. Because GFL inverters merely follow the grid, they cannot replace RSI inertia, dampen power oscillations, or help restart the power grid after a failure. Grid-forming (GFM) inverters are different. They act as independent voltage and frequency sources that actively establish and maintain the grid's local voltage and frequency, provide Synthetic Inertia (SI) by drawing on battery reserves, and can power-island sections of the grid or facilitate grid restart after an outage.
When Does Lack of RSI Become a Problem?
There is no universal threshold applicable to all grids. The range 20–30% non-synchronous penetration is often cited, but this interpretation is simplistic: it corresponds to the level at which several operators historically began to take the issue seriously. ERCOT in Texas, for example, began analysing the impact on system inertia when instantaneous wind penetration reached about 30%. What matters is not only the share of inverter-based resources but also the amount of synchronous machinery still online, the size of the synchronous area, the largest possible grid contingency, interconnector capacity, available fast-frequency reserves, and protection settings.
The issue becomes unavoidable once electricity without inertia reaches roughly 50–70%. The grid can remain stable, but it can no longer be operated as before. In a traditionally designed grid, operators often have to keep a minimum number of synchronous machines online, even when their energy is not needed, simply to provide inertia, short-circuit power, voltage control, and a frequency reference. This leads to curtailment of renewable generation in favour of rotating machines.
The metric to manage is RoCoF, the rate of change of frequency, measured in hertz per second. Inertia requirements, whether physical or synthetic, are calculated from three elements: the size of the largest possible incident, the nominal frequency, and the maximum tolerated RoCoF.
South Australia: The Operational Proof
South Australia was the first grid in Australia to shut down all transmission-grid-connected coal-fired power stations in 2016 and all transmission-grid-connected diesel-fired power stations in 2024. As of May 2026, SA still has 3 GW of fossil-fueled capacity across 11 gas-fired power stations with 50 RSI generators. Since August 2025, AEMO's mandate requires only 1 of those 50 gas-fired generators to be operational during normal NEM operations, down from 2.
The cost of the mandate shows up as curtailment. In 2025, the SA grid curtailed 10.8% (1,672 GWh) of SA's Operational Demand from utility-scale wind and solar, while total gas-fired generation contributed 19.4% (3,023 GWh). From January to May 2026, under the reduced mandate, curtailment was 8.7% (562 GWh) and gas-fired generation was 14.4% (935 GWh).
SA is the only GW-scale interconnected grid in the world with a legislated 2027 goal of net 100% Renewable Energy using exclusively solar, wind, and battery assets. Technically, SA met its 2027 goal for the first time by the end of calendar year 2025, and it was the only NEM region with no System Strength Shortfalls in 2025. The grid remained stable thanks to a combination of batteries with grid-forming inverters and high-performance SI control systems, two interconnectors, 4 synchronous condensers, advanced controls, and operational constraints.
The flagship asset is the Hornsdale Power Reserve (HPR). Installed in 2017 as Australia's first utility-scale battery with GFL inverters at 100 MW/129 MWh, HPR was upgraded in 2020 to 150 MW/193.5 MWh with GFM inverters and high-performance SI control systems, including the earliest version of Tesla's Virtual Machine Mode. AEMO, Neoen, Tesla, ElectraNet, and the SA Government tested and verified HPR's performance over a 2-year period. In 2022, HPR became the first utility-scale GFM/SI BESS in the world to be awarded a wide range of Frequency Control Ancillary Services (FCAS), including Black Start.
The secret to SA's success is deploying GFM/SI batteries across a 6-layer model. Front of the Meter: (1) transmission-grid-connected utility-scale solar, wind, and GFM/SI batteries, and (2) distribution-grid-connected community-scale batteries. Behind the Meter: (3) industrial-scale, (4) commercial-scale, (5) residential-scale, and (6) BEV/microgrid-scale. Millions of high-performance two-way digital GFM/SI batteries deployed across a grid add a level of tuned intelligence to a grid that was formerly powered by 10–20 large, manually operated, centralised, one-way RSI power stations.
Why SI Outperforms RSI
Speed outperforms inertia. The inertia constant of a synchronous machine provides a passive buffer of typically 2 to 8 seconds that slows frequency decline, but resolving the underlying contingency then requires operator action measured in minutes at a minimum. GFM inverters can respond with SI within 2 to 200 milliseconds, and no manual operator intervention is required to resolve the contingency.
Intelligence outperforms mass. RSI synchronous machines provide inertia and fault current but lack the adaptability and sophisticated control capabilities of GFM/SI batteries. A GFM/SI battery emulates the behavior of synchronous machines while offering synthetic inertia, fast frequency response, voltage regulation, reactive power, oscillation damping, fault ride-through, Black Start, and controlled power islanding, all while still shifting energy. Such batteries do not merely store electricity; they also provide continuity of service and resilience.
Distributed automated response outperforms centralised manual control. The more electrically distant a resource is, the less effectively it provides "on-site" inertia for local loads, and the far ends of distribution networks are the most sensitive to voltage variations. In a village at the end of a line, a well-controlled GFM/SI battery can reduce voltage drops during peaks, absorb solar surplus, provide rapid response during an incident, and enable controlled islanding of critical loads. It does not merely store electricity; it electrically strengthens a weak portion of the grid. The point is reinforced by 2025 FNET/GridEye data showing regional RoCoF in California can be up to six times higher than average interconnection values.
Markets Are Catching Up
On January 22, 2026, the four German transmission system operators launched the Momentanreserve, or instant reserve: a specialized exchange connecting sellers and buyers of inertia services, open to both electromechanical RSI from rotating machines and SI from GFM inverters. For 2026–2028, published fixed prices are about €805–888.5 per MW-s per year for the premium product and €76–109.5 per MW-s per year for the basic product. Ireland can now operate at about 75% System Non-Synchronous Penetration and aims to reach 95% by around 2030. ERCOT has developed the concept of critical inertia, the minimum level that allows the system to withstand the simultaneous loss of its two largest units, evaluated at 2,750 MW, and relies on fast frequency response rather than synchronous mandates.
One emerging practice underpins all of this: real-time inertia measurement. Operators can no longer simply estimate inertia from a list of online power plants; they must dynamically measure and forecast the system's state. NREL and ORNL are working on methods for simultaneous estimation of inertia and frequency response in grids with high penetration of inverter-based resources.
Spain and Portugal are currently drawing lessons from the blackout of April 28, 2025. It would be misleading to say that the blackout was caused simply by "too many renewables" or "not enough inertia." The final ENTSO-E report instead identifies a combination of uncontrolled voltage rise, loss of voltage and reactive power control, oscillations, rapid reductions in generation, and cascading disconnections once the balance was compromised. At the time of the incident, renewables accounted for about 78% of Iberian generation, with nearly 60% solar. The main lesson is that grids relying on a high share of electricity without inertia must urgently strengthen voltage and reactive power control.
GFM/SI Limitations
GFM/SI inverters also have limitations compared to RSI spinning machines. Traditional generators can output 500% to 700% of their rated current for several cycles to help clear faults; because of the sensitivity of power electronics, GFM inverters typically allow only 10% to 30% overcurrent surges. SI inertia support is energy-limited by the battery's State of Charge. Emulating very high levels of SI can cause oscillatory instability in the grid, requiring carefully tuned damping mechanisms. GFM/SI inverters also require good cybersecurity, interoperability, and performance assurance practices. These are mainly standardization issues that should be resolved in the coming years, and South Australia's operating record suggests they are manageable, but they are real.
The Takeaway
In the future, grid stability will be an explicit service, not merely the assumed by-product of the RSI mass of rotating machines. This service will be measured, remunerated, localized, and sometimes provided by equipment that, ten years ago, was seen only as load or as intermittent generation. The most important battery services may not always be measured in kilowatt-hours, but in frequency support, voltage support, reactive power, inertia response, and continuity of service. South Australia offers the replicable model; Germany's inertia market shows where the economics are heading.
Based on Gauthier, P. & Noonan, J., "National Power Grid Transition from Physical to Synthetic Inertia," White Paper v2.2, June 2026.
