Voltage, inertia and the Iberian blackout part 2: faulty PV inverter crashed the grid

The Iberian blackout demonstrated the importance of voltage control and reactive power, and how a weak grid, with poor controls, was brought down by a single faulty solar inverter. In this second part of my analysis of the Iberian blackout, I examine the specific technical causes of the incident. Where technical concepts such as frequency, voltage, and oscillation dynamics are not explained here, they are covered in Part 1, which outlines the physical principles and control challenges in modern grids.

This blog is based on a concise but informative report produced by Red Eléctrica de España (“REE”), the Spanish Transmission System Operator (“TSO”), which is more accessible than the much longer government report (available only in Spanish – rough English translation here).

The key messages from the REE report are:

• The blackout was triggered by a PV inverter–induced voltage oscillation
• Inappropriate disconnections of wind and solar generation, and widespread failure of reactive power support, escalated the disturbance
• REE relied on static controls and failed to deploy dynamic response assets
• Grid code non-compliance was widespread among renewables, conventional generators, and even REE itself (via non-compliant transformers)
• The collapse exposes systemic risks in low-inertia grids with high levels of inverter-based resources (“IBRs”) and inadequate voltage control

It is notable that, despite confident denials from some renewables advocates in the immediate aftermath, it was in fact a malfunctioning solar installation that triggered the voltage oscillation initiating the collapse. Wind and solar generators failed to meet fault ride-through obligations, and both inverter-based and conventional generators failed to provide the required reactive power support. Crucially, conventional generators did not trip prematurely – they remained online until system conditions breached their design tolerances.

The Iberian grid was already in a weakened state, owing to insufficient synchronous generation and excessive reliance on inverter-based renewables. The system failed to withstand a fault that originated with a single solar inverter. This was not an unavoidable technical event – it was the result of systemic underestimation of voltage control risks, poor compliance enforcement, and REE’s failure to schedule or deploy sufficient dynamic voltage support.

This blackout would not have occurred in a conventional, high-synchronous grid. The rush to decarbonise the power system without adequate attention to resilience and enforcement has created an atmosphere of complacency. That complacency – shared by policymakers, regulators, and parts of the renewables industry – led directly to a system-wide collapse that cost eleven lives.

Summary of the events leading up to the Iberian blackout

Below is the 18-point summary of events that can be found in the REE report, which is says are based on the best available information at the time of writing. These are described as having “occurred in succession and some of them individually could be assimilated to an N-1 scenario” (an “N-1 scenario” refers to a system’s ability to withstand the failure of a single component without causing a disruption in service. “N” represents the total number of components, and the “minus one” (N-1) indicates that one component is removed, either due to failure or planned outage. This principle is crucial for maintaining grid reliability and ensuring a continuous power supply):

1. Forced oscillation at 0.6 Hz, possibly originating in a photovoltaic power plant in the province of Badajoz, triggers system-altering protocolized actions. Shunt reactors are operated, lines are coupled due to oscillations, and schedules are modified. (N-1)
2. Natural oscillation at 0.2 Hz triggers further system-altering protocolised actions. Shunt reactors are operated, lines are coupled due to oscillations, and schedules are adjusted. (N-2)
3. Generation under P.O. 7.4 does not absorb the required reactive power. (N-3)
4. Variations in RCW generation during active power regulation affect voltage control and many of them don´t fulfil their obligations. (N-4)
5. The conventional generation requested after the oscillations was not connected
6. Generation loss in distribution: P < 1 MW and self-consumption of 435 MW before 12:32:57 (N-5)
7. Inappropriate tripping of a generation transformer in Granada (N-6)
8. Inappropriate tripping of solar thermal generation (Badajoz) and tripping of photovoltaic (Badajoz) without point-of-interconnection data from transmission network (N-7)
9. Inappropriate tripping of a photovoltaic power plant connected also in the province of Badajoz but in a different transmission substation (N-8)
10. Tripping of three wind farms (Segovia) without point-of-interconnection data from transmission network
11. Tripping of one wind farm and a PV plant located at the province of Huelva, without point-of-interconnection data from transmission network
12. Inappropriate tripping of photovoltaic power plant in Seville (N-9)
13. Inappropriate tripping a PV generation located in the province of Cáceres (N-10)
14. Tripping of PV generation connected to a 220 kV substation located in the province of Badajoz, without point-of-interconnection data from transmission network
15. Tripping of one CCGT unit located at Valencia (N-11)
16. Load shedding of pumping units and loads due to underfrequency results in increased system voltage
17. The HVDC link operating in constant power mode continues exporting 1,000 MW to France
18. Tripping of Nuclear Power Plant. (N-12)

This list misses out some transformer trips early in the scheme of events which I think should have been included.

More detailed assessment of the events of 28 April: Before the incident began

Earlier in the day, and indeed in the preceding days, there had been various frequency oscillations on both the Iberian grid and wider European power grids. These were described as normal, although I question whether they are desirable – it is normal to see cyclists running red lights in London, but it doesn’t make it any less illegal, or less of a threat to pedestrians. A wider lesson from this fiasco might be to consider whether these types of oscillations are signals of a weak grid and should not be tolerated the way that they are.

In any case, some of these fluctuations were attributed to the effects of solar ramping creating rapid changes in both the generation mix and supply-demand profile, with much of the solar being connected to lower voltage networks rather than the transmission system, and therefore looks like a reduction in demand to the high voltage grid. This phenomenon led to frequency deviations and voltage oscillations.

As noted in part 1 – these are not causal in the sense that frequency oscillations do not cause voltage oscillations or vice versa, despite phrasing in the REE report suggesting otherwise. The REE report was either not written by a native English speaker or translated from a Spanish language equivalent and these statements are likely to be mis-translations. Both frequency and voltage oscillations can be caused by the same grid disturbance but they do not cause each other (the sun can cause plants to grow and people to get sunburn, but plants growing does not cause sunburn and vice versa!)

In any case, these fluctuations in frequency and voltage caused overall voltage levels at various points on the grid to drop. As the voltage recovered a couple of transformers tripped, which REE speculated was a result of their taps not being adapted quickly enough in response to the increase in voltage.

Transformer taps are a means of changing the voltage transformation by bypassing some of the windings. A tap changer is the mechanical (or solid-state) device that switches between taps. There are two types:

• Off-load tap changers which can only be changed when the transformer is de-energised
• On-load tap changers which can adjust the voltage while the transformer is operating, which is crucial for real-time voltage regulation

In transmission and distribution networks, on-load tap changers are essential for maintaining voltage within required limits, particularly as load and generation fluctuate throughout the day.

At mid-day, the system was described as being compliant with normal operational procedures, notwithstanding the frequency oscillations of 0.2 Hz that had been identified. These were being damped at 20%.

REE says at this point there were no signs of the trouble to follow. I wonder if we are not ignoring underlying instability as possibly evidenced by these low frequency oscillations, an fooling ourselves into thinking the grid is stable, when fundamentally it only looks stable in a superficial way – statutory limits are being met but underneath the grid is actually quite weak.

Things start to go wrong just after mid-day

REE describes, the Genesis of the blackout as an atypical 0.6 Hz frequency oscillation that lasted 4 minutes and 42 seconds, which coincided with a reduction from 20% to 5% of the damping of the 0.2 Hz oscillation. Damping decay is logarithmic – with 20% damping the amplitude of the oscillation drops rapidly with about a 72% reduction in each cycle, however with 5% damping the amplitude decays much less, falling only around 28% per cycle.

This new 0.6 Hz oscillation caused a drop in voltage and a voltage oscillation with an amplitude of up to 35 kV (the report says 30 kV the cites a 375 – 410 kV range which is clearly 35 kV). This oscillation is described as being caused by a solar PV plant in Badajoz. 375–410 kV range refers to the fluctuating envelope of voltage during the oscillation. In other words, voltage was oscillating around a new (lower) midpoint, not just overshooting once and recovering. If the nominal voltage was 400 kV:

• The system began oscillating with a peak-to-peak amplitude of ~30–35 kV
• Meaning voltages temporarily swung between as low as 375 kV and as high as 410 kV
• That’s serious — most systems have tight voltage stability margins

These oscillations appeared most strongly on the interconnector corridor, which makes sense as it’s a long, low-damping HVDC route with significant power flow.

In response to this disturbance, REE enacted four pre-established measures:

• Coupling of 400 kV power lines to reduce system impedance
• Reduction of export capacity to France by 800 MW to 1,500 MW
• Setting the interconnector to France into constant power mode with a setpoint of 1,000 MW
• Disconnection of shunt reactors

Coupling lines reduces impedance which raises the voltage stability margin. This action is almost always a sensible response, as it

• Creates parallel paths for current, lowering the effective impedance
• This reduces voltage drop for a given current, improving voltage support
• It also helps damp oscillations, since more paths distribute power flows more evenly

Reducing exports by 800 MW relieves stress on voltage. This seems counterintuitive at first because the interconnector in question is dc and should be immune to frequency/voltage interactions, however the converter station on the Iberian side must draw real power from the ac grid and deliver it to the dc interconnector. If the grid is exporting 1,800 MW during a voltage sag, as voltage drops current must rise to maintain constant power export. This exacerbates the voltage drop and can overload nearby equipment since the interconnector is trying to suck power out of a grid that’s already sagging.

Therefore, reducing the export means less current is drawn from a weakened grid, relieving voltage stress. This also helps reduce power flow oscillations along long HV lines.

Switching to constant power mode at 1,000 MW might also appear to make things worse again. Before the voltage disturbance, the interconnector was running in voltage-dependent mode. When Iberian voltage dropped, export power fell slightly, helping to stabilise the grid. Switching to constant power mode at a lower setpoint fixes export at a manageable level, ensures France continues to receive power, avoiding disturbance propagation across the border, and keeps the converter operating within a known, controllable regime.

This can be an attractive option because once the load has been reduced and the voltage improved by other means, it is desirable for the interconnector to remain stable, avoid switching behaviour (voltage-following converters can respond unpredictably under low-inertia conditions), and not feed back instability into France. Flexibility is traded for stability.

As noted in my previous blog, shunt reactors absorb reactive power when voltage rises, helping to limit further voltage increases. Disengaging them means they stop limiting the rise in voltage, allowing it to increase more on the upward cycle, and therefore mitigates low voltage conditions. Impedance is lower when shunt reactors are disengaged.

While all of these actions seem sensible on the surface, they are static actions that were not adequate in what was a dynamic situation. These responses raise voltage in general, but do nothing to address the oscillation’s frequency content, timing mismatches or the phase angle instability across the network.

REE should have considered a more dynamic response, for example:

• dynamic voltage control via STATCOMs or fast synchronous condensers
• allowing interconnectors to respond dynamically (eg based on frequency or voltage magnitude and phase)
• using wide-area damping controllers to detect and suppress low-frequency oscillations

While REE’s actions were temporarily successful, the 0.6 Hz oscillation reappeared within a few minutes, with an accompanying voltage drop and voltage oscillations of 380-405 kV. As REE tried to dampen this recurrence of the 0.6 Hz oscillation, a new 0.2 Hz oscillation was detected. This was accompanied by voltage fluctuations of up to 28 kV at the Almaraz 400 kV substation.

At this point the 0.6 Hz frequency band was examined more closely and it was determined that there had been oscillations in this range since 10:30 that morning. Again, REE took the same static response measures (this time excluding the disconnection of shunt reactors). Transmission lines were coupled, exports to France were cut further and exports to Portugal were also reduced. As a result, voltage began to increase, although unevenly as these actions had different response times. At 12:22, REE began to connect shunt reactors to limit the voltage increase.

At the same time, there was an unexpected increase in demand which was later determined to be a reduction in generation connected to distribution networks. This was likely a response to negative intraday power prices making this generation uneconomic. This increase in transmission system demand led to a reduction of exports to France – which appears to be the main mechanism for balancing the system – decreasing the flow of power towards the interconnectors and causing an increase in voltage on the transmission system.

At this point, REE decided to call on some additional CCGTs to provide support to the network. Unfortunately the units were cold and required several hours to warm up and synchronise – they were not able to connect before the blackout started and ultimately were not used for that reason.

REE says that there were no over-voltages on the system at this point, but there were voltage oscillations.

Between 12:32:00 and 12:32:57 exports to France fell from 1,500 MW in a quasi-linear manner. This coincided with a number of events on the grid:

• IBRs reduced output in line with scheduled dispatch, leading to a reduction in reactive power actions since these units operate under power factor control, however many IBRs fail to meet their power factor obligations under the grid codes
• More disconnection of distribution-connected generation causing transmission system demand to rise further, amplifying the previous increase in voltage
• Transmission lines consumed and released less reactive power, reducing impedance and also increasing voltage
• Some conventional generators failed to meet their reactive power obligations under the grid codes, which had a significant impact on voltage

At 12:32:57 there was a trip on the 220 kV side of 400/220 kV generation transformer in Granada. A 400/220 kV generation transformer is a step-down transformer used to connect a power station that generates electricity at 400 kV to a lower-voltage 220 kV network. If a trip occurs on the 220 kV side it means a protection system detected a fault or abnormal condition on that side and automatically disconnected the transformer or circuit at the 220 kV terminals. This could have been an internal transformer fault, a fault in downstream 220 kV equipment (lines, breakers, or substations), or a protective system error (eg an overly sensitive relay or coordination fault).

If the 220 kV side is part of the generator’s plant this is likely a generator-side issue (eg fault in auxiliary transformers, local switchgear, or poor protection design).  In this case, it may point to inadequate fault ride-through capability, or bad coordination with grid events. However, if the 220 kV side is part of the grid it’s a grid-side fault or protection event – the generator may have been exporting power, but the grid-side equipment or protections caused the disconnection. This would fall under the transmission system operator’s responsibility, or a distribution company if relevant. In practice, Spain’s grid is meshed and centrally operated, so REE likely owns and maintains the 220 kV side.

A trip on 220 kV side means the generator’s ability to export power is reduced or cut off. If the transformer was the only export path, the generator would be disconnected from the system even if the unit itself was operating normally. This might also increase stress on the 400 kV system, especially during oscillations, which is why the report highlights it.

This was a collector substation which is a type of substation used primarily in renewable energy installations to aggregate (or “collect”) electricity generated by multiple smaller generating units before sending it to the transmission or distribution network, eg lots of wind turbines or solar panels. The individual generation units are connected to a local internal network that feeds into a collector substation which then steps up the voltage (eg from 33 kV or 66 kV to 132 kV or 220 kV) and exports the combined power to the grid via a transmission or distribution substation.

REE speculates that the transformer tripped due to a faulty tap setting – as the system recovered from previously low voltages, the tap changers may not have responded quickly enough to the increasing voltage. Given the voltage levels at the time, the disconnection of the transformer meant it was not compliant with the grid codes.

19 seconds later, 727 MW of solar generation in the Badajoz region tripped off, reducing both active and reactive power. The grid was still operating within its normal operating parameters, so these units failed to meet their fault ride-through obligations. Within a second, three windfarms tripped in Segovia. Within the following seconds, more wind and solar tripped amounting to 834 MW in a 650 ms window. These units were in Badajoz, Huelva, Seville and Cáceres. Analysis of the RoCoF (rate of change of frequency) data suggest that 1,150 MW might have disconnected during this time.

These units were primarily located in the south of Spain, leading to a reduction in south-to-north flows, and causing the interconnector with France to change direction and begin to supply northern Spain.

By this time more than 2 GW of renewable generation had been lost from the grid across the various trips and unexpected price-based disconnections. The impact of the reduced reactive power control from these assets was exacerbated since a couple of conventional generators in the southern and central regions of Spain failed to meet their reactive power obligations under the grid codes.

In addition to the voltage impact of these disconnections, grid frequency fell. With each new disconnection, voltage increased and frequency decreased.

At 12:33:19 maximum imports from France were reached (3,807 MW) with 4,609 through the ac links. This statement is very confusing since on the REE website it says the Spain-France capacity is 2600/2700 MW (there is a different import vs export capacity). While the Baixas–Santa Llogaia HVDC link is commonly cited as having a 2,000 MW capacity, REE’s own data suggests that over 3,800 MW was flowing via “the HVDC network” at the time of the blackout.

This implies either a higher technical limit than advertised, or the presence of additional HVDC capacity not clearly documented in public sources (possibly Baixas-Vich). The ambiguity in published interconnector data — even from official sources — highlights how opaque Europe’s physical grid topology can be, despite its centrality to energy security. I have written to REE requesting clarification and will update this blog if I receive a satisfactory response.

In any case, the drop in grid frequency in Spain caused a lack of synchronisation with the French grid.

At this point, there is both load disconnection and pumped hydro trips. IBRs continue to trip with each new generator trip causing frequency to fall further. As frequency falls below 49.5 Hz, CCGTs begin to trip – it is notable that conventional generation (particularly gas units) did not trip until frequency fell below the proscribed limits ie unlike many renewable generators, they did not violate their fault ride-through obligations.

With frequency falling below 49.5 Hz, 2,000 MW of pumped hydro trips. When it falls to 48.3 Hz a further 588 MW of pumped hydro disconnects and load shedding of industrial consumers continues down to 49 Hz by which time 1,402 MW of load is lost. This disconnection of demand causes voltage to increase.

The interconnector with Morocco tripped at this point.

Then there are some further confusing comments about interconnection with France: “When the frequency reaches 48.46 Hz, the ac interconnection lines with France trip preventing expanding the incident further into France and to facilitate its availability for the restoration. The HVDC link, which was in constant power mode, does not disconnect and continues exporting 1.000 MW to France.”

Yet on the previous page we were told that the interconnectors were importing to Spain from France to compensate for the loss of generation in the south of Spain. And we were told the ac lines tripped (loss of synchronisation). If the ac lines had already tripped due to loss of synchronisation, how could they be said to trip again moments later? And how was the HVDC line suddenly exporting when the Spanish grid was so short the frequency was falling?

This may suggest that the constant power mode enacted on the HVDC in response to the initial 0.6 Hz oscillation over-rode the import mode and pushed the interconnector back into exports. If this was the case it was a very unhelpful setting that increased the stress on the Spanish grid.

Even more confusingly, after telling us the HVDC link did not disconnect, the report tells us that “from this moment onwards, the Spanish and Portuguese systems are isolated”.

In any case, at this time the frequency fell to 47.79 Hz causing a nuclear reactor and then several CCGTs trip and then we are told the HVDC line to France tripped, so at this point Iberia truly was islanded. At 12:33:24 the Spanish grid collapsed and at 12:33:27 voltage fell below 1 kV and there was a total system blackout.

A solar PV fault ultimately brought down the Iberian power grid

A solar inverter was the initial cause of the fault but poor grid code compliance and poor decision-making by REE made this a fatal fault. To summarise, the main events were:

1. A PV inverter caused some frequency oscillations and a drop in voltage including voltage oscillations
2. Two substations in Zaragosa tripped due to transformer taps not adapting fast enough to the increase in voltage after the system responded to the drop caused by (1). These substations at the 55 kV level do not appear to be owned by REE
3. Renewables generators fail to respond to power factor requirements and conventional generators fail to respond to reactive power requirements set out in the grid codes
4. REE fails to schedule enough thermal units for reactive power and initially responds to voltage issues with static rather than dynamic means (as we discussed yesterday with the car up the hill analogy)
5. Lots of wind and solar (PV and thermal) trips inappropriately ie failing to meet fault ride-though obligations. No conventional generation trips until normal operating conditions are breached
6. Voltage falls outside tolerances for conventional generation and frequency falls below 49.5 Hz causing these generators to start to trip further reducing frequency
7. Cascading failure leads to full voltage collapse and blackout

As with the 2019 blackout in Great Britain this event was characterised by poor compliance with grid codes, although to a much more severe extent. Non-compliance appears to be widespread, particularly for renewable generators, many of which failed both the meet power factor obligations and fault ride-though obligations – the latter being more serious. Conventional generators failed to meet reactive power requirements, and even REE seems to have been operating non-compliant transformers.

In addition, REE made several serious errors (aside from not monitoring grid code compliance). It failed to schedule enough reactive power provision at the day-ahead stage. It relied too heavily on static voltage response in a dynamic situation (possibly because it did not understand what was happening in real time) and it failed to react fast enough when the system began to move outside normal parameters.

It is somewhat disappointing that REE does not address code compliance in its recommendations. The system operator is pushing for new additions to the Operating Procedure (the Spanish grid code) but does not address the question of compliance – these new obligations could and not be met by non-compliant generators.

Importance of enhanced voltage control in low-inertia grids

While the REE report states that the 28 April blackout “was not due to an inertia issue,” this shouldn’t be taken as exoneration of low-inertia system conditions. Rather, it exposes a more subtle and arguably more serious, systemic weakness – the erosion of voltage stability and dynamic controllability in high-IBR, low-synchronous environments.

In traditional grids, inertia provides a stabilising buffer against rapid frequency changes by passively resisting acceleration or deceleration of the grid’s rotational mass. But inertia alone doesn’t stabilise voltage – this is done through the ability of synchronous generators to supply reactive power, fault current, and voltage stiffness, often without needing explicit control actions.

As conventional generators are displaced by IBRs which lack rotating mass and don’t produce reactive power inherently, voltage becomes a weak point. While frequency tends to dominate public and regulatory discussions, voltage instability is often the faster and more dangerous mode of failure, and it played a key role in Spain’s blackout.

Critically, inverter-based resources disconnected before the frequency fell to critical levels, driven by voltage instability and local power quality. That in turn triggered a cascade – as solar and wind generation dropped off, frequency was pulled down and voltage also fell. The frequency reductions rather than voltage then caused conventional generators to trip as well, and the system spiralled into a full blackout.

This shows that:

• Voltage support is no longer a secondary consideration in high-IBR systems, it is essential to stability
• Voltage and frequency are coupled, but voltage excursions can occur first, and the loss of voltage support can lead to frequency collapse, not the other way around
• IBRs are not just passive victims of instability, they can actively contribute to it and even cause it if their controls are not properly tuned to the system they’re operating in

The Spanish blackout should be a wake-up call for system operators in any region with growing shares of non-synchronous generation, because it shows that low inertia magnifies other vulnerabilities. Even if low inertia isn’t the direct cause of a blackout, it reduces system stiffness and weakens voltage control, making the grid more susceptible to disturbances.

Stable frequency alone does not guarantee grid resilience – without proper voltage support and fault ride-through capability, especially from IBRs, a power system can appear healthy on one axis while becoming dangerously fragile on another. This is important when considering whether inertia limits can be lowered. And it is essential if considering wider use of inverter-based batteries for inertia support to ensure that they are fully grid code compliant. The compliance issues identified in GB in 2019 and now in Spain are a huge red flag that regulators should clamp down on.

While we talk about “inertia” as if it’s a single quantifiable value (usually in GVA·s), the term is often a proxy for a much wider set of stabilising properties that synchronous machines provide naturally, because if their physical and electrical characteristics. IBRs, particularly batteries can be very good at providing specific services such as fast frequency response, but they lack the default, location-sensitive, and passive characteristics that synchronous machines provide.

The REE report says the blackout wasn’t caused by “inertia”. Technically, it wasn’t caused by a low frequency event, but the system lacked synchronous damping, so the initial voltage instability was not naturally absorbed. It lacked voltage stiffness, so inverter mis-behaviour propagated rapidly, and it lacked a robust synchronous reference, which exacerbated control loop instability. So while “inertia” as a number might not have been the issue, the absence of synchronous behaviour absolutely was.

And it is no coincidence that when the fault propagated into high inertia France it was quickly contained and power to the area was rapidly restored, unlike in low inertia Spain which suffered a full collapse. This could be paraphrased as high-synchronous-generation France vs the high IBR grid in Spain.

Beware of the normalisation of deviance

The other key conclusion is that, just because a grid is operating within its statutory or grid code parameters, this does not mean it is stable, and to suggest it is could be seen as pretty complacent – in power system operation, “within limits” is not the same as “under control”. Grid code thresholds and statutory frequency or voltage bands are designed to define the outer boundaries of acceptable behaviour, not to guarantee stability – a system that is technically compliant but exhibits persistent oscillations, erratic inverter response, or poor damping, may be inherently unstable as Spain demonstrated on 28 April.

This is essentially the normalisation of deviance, a concept borrowed from engineering risk analysis and famously used in discussions about the Challenger disaster. It describes how the absence of immediate failure becomes evidence that the system must be safe, even if warning signs are accumulating. In her analysis of the Challenger disaster, sociologist Diane Vaughan used it to explain the repeated choice of NASA officials to fly the space shuttle despite a dangerous design flaw with the O-rings. Vaughan describes the phenomenon as occurring when people within an organisation become so insensitive to deviant practice that it no longer feels wrong. Insensitivity occurs insidiously and sometimes over years because disaster does not happen until other critical factors line up.

In this context, describing the 0.2 Hz oscillations as normal, is a literal example of the normalisation of deviance. In Spain, oscillations were present and had been for some time, damping was poor, and IBRs were failing to respond correctly, yet the system was declared “within parameters”. Sustained or growing oscillations indicate that the system is injecting energy into disturbances, and not absorbing or damping them. If damping rations are low then disturbances take longer to settle giving them more time to interact with protection systems, destabilise inverter controls, or trigger cascading responses.

So while the amplitude of the 0.2 Hz frequency swings were small, their persistence and poor damping were red flags.

A rush to net zero and a complacent attitude to voltage control and code compliance led Spain’s grid to collapse

The key messages we should take away from the Iberian blackout are:

• Poorly configured inverters can cause catastrophic failures in weak grids
• More attention needs to be paid to voltage control and not just managing frequency
• There needs to be better monitoring of grid code compliance
• The normalisation of deviance often leads to disaster

Fundamentally, TSOs, regulators and energy ministries need to ensure they are not so blinded by their net zero goals that they compromise grid stability, particularly by allowing a gradual erosion of standards that eventually exceeds what grids can cope with. Eleven people lost their lives in the Iberian blackout, so it is vital that the right lessons are learned to avoid any repeat either in Spain or elsewhere.