Inside The Iberian Grid Collapse: What Really Went Wrong

On April 28, 2025, the Iberian Peninsula experienced a dramatic blackout. At exactly 12:33:30, a cascading failure disconnected the grids of Spain and Portugal from the wider European electricity system, plunging millions into darkness. We now have not the hot takes of the usual anti-renewables rabble, but the 192-page report from Spain on the causes.

Occurring at midday, the event took place under conditions typical of spring: mild weather, moderate electricity demand, and abundant renewable generation. This combination created atypically low wholesale electricity prices, with significant amounts of renewable energy being curtailed, but the blackout was not a renewable-energy-driven event.

Rather, it was the result of multiple layers of insufficient planning, inadequate voltage management, and poorly managed grid dynamics. 50% of the allocation of responsibility was to human failures in planning, 30% to legacy generation not performing as it was designed to do, and 20% to renewables exiting the system because they weren’t configured to deal with the scenario, once again a human failure more than a technology failure.

In my previous examination, From Darkness to Light, I discussed the well-orchestrated black-start procedures that successfully restarted the Iberian grid. That article emphasized the critical role of hydroelectric plants, which have unique autonomous restart capabilities, as well as coordinated islanding strategies that gradually re-established voltage and frequency stability. The April 28 event reinforced how important these black-start-capable hydroelectric facilities remain, even as battery storage and advanced inverter-based resources begin to assume more prominent roles in future recovery plans. For the black start, the grid operators in Spain and Portugal were prepared and executed it well. But the report makes clear that they failed to prevent the requirement for the black start in the first place.

To fully understand the blackout, it is crucial to look beyond restoration and into the conditions that precipitated it. On that morning, the system faced persistent voltage fluctuations and unusual frequency oscillations. The grid was already showing signs of strain due to structural and operational factors: specifically, a lack of dynamic voltage regulation capacity and poor oscillation damping. As system conditions evolved throughout the morning, several smaller oscillation events were successfully managed but indicated a troubling lack of system stability. By noon, grid conditions had become increasingly volatile, driven by interactions between changes in renewable generation output, particularly solar, and shifts in electricity import-export balances with France.

The sequence that led to total grid failure began shortly after 12:30 PM. The system experienced a rapid increase in voltage across many transmission nodes. This voltage rise was initially manageable but then escalated rapidly, causing the disconnection of several renewable generation facilities, not primarily due to issues inherent to wind or solar power, but rather due to inadequate voltage management and system protections at these facilities. These disconnections significantly exacerbated voltage instability and led to further tripping at shared generation evacuation substations, predominantly renewable-connected substations in southern and southwestern Spain.

Within approximately 30 seconds, successive waves of generation loss occurred due to cascading overvoltage conditions and, subsequently, underfrequency trips. These generation losses were due to the inability of the broader grid system, including substations and interconnection infrastructures, to manage voltage spikes effectively. The report explicitly notes that the majority of tripping occurred at evacuation infrastructure jointly used by multiple renewable generators, facilities designed with fixed power factor control rather than dynamic voltage regulation. This lack of voltage management capability, combined with inadequate grid code enforcement and weak damping equipment deployment, triggered an escalating series of voltage and frequency disturbances culminating in complete system collapse.

Would this catastrophic scenario have unfolded similarly in a grid dominated by fossil generation? The report clearly indicates it would likely not have, but not specifically because fossil generation is superior. Rather, the key advantage of traditional synchronous generators is their inherent inertia and the dynamic reactive power capabilities that accompany conventional turbine generators. These characteristics provide a substantial buffer against rapid voltage swings and frequency disturbances. However, reverting to fossil generation is neither sustainable nor necessary. The future energy system can replicate and even surpass these stability characteristics through strategic use of advanced inverter technologies, grid-forming resources, and dynamic voltage stabilization equipment.

Reflecting on the incident, the investigating committee recommended several critical measures. First and foremost, the immediate implementation of a dynamic voltage control requirement across all generation types is urgently needed. Renewable facilities currently operate primarily under static power factor arrangements, limiting their responsiveness during grid disturbances. Introducing dynamic voltage control by renewable plants, akin to the regulation currently applied to thermal plants, would substantially mitigate risks of future cascading failures.

Furthermore, the committee emphasized significant investments in advanced grid-stabilizing hardware such as synchronous compensators, STATCOMs, and FACTS systems. These technologies provide continuous, responsive, and dynamic voltage and frequency support, capabilities that must be thoughtfully added to renewable-rich grids. Deploying these devices strategically throughout the transmission network, particularly at points vulnerable to voltage fluctuations, will dramatically enhance system stability and resilience.

Updating regulatory frameworks is also essential. Current grid codes focus narrowly on steady-state voltage thresholds, inadequately addressing rapid transient voltage increases. The committee advocates for grid code revisions to include clearer standards on ride-through capabilities during rapid voltage escalations, ensuring that inverter-based generation resources remain operational during transient events rather than disconnecting prematurely.

In addition, the committee highlighted needed market reforms. The blackout revealed that negative intraday market pricing led to abrupt changes in renewable generation, causing sharp system fluctuations and contributing to instability. Adjusting market structures, including delays in intraday market closures or introducing mechanisms that moderate abrupt renewable output changes, can enhance operational flexibility and grid stability.

Cybersecurity and digital resilience were also addressed, despite no direct cyberattack evidence being found. The committee recommended tighter cybersecurity regulation for all grid-connected facilities, especially medium and smaller operators currently not covered by stringent cyber-compliance standards. Enhancing data accuracy, monitoring, and real-time situational awareness capabilities for grid operators will improve responses in future grid emergencies.

Finally, enhancing demand-side engagement and accelerating storage deployment were identified as critical elements of resilience. Increasing industrial and commercial electrification boosts baseline demand, improving the operational environment and voltage management conditions of the grid. Simultaneously, battery storage and hybrid renewable-storage projects provide essential services, including frequency and voltage support during disturbances.

Organizational recommendations included the establishment of a fully independent national energy regulator with enhanced oversight capabilities. Ambiguities in ownership and responsibility structures, particularly at shared renewable evacuation infrastructure, contributed to operational confusion and delays during crisis conditions. Clear regulatory oversight can streamline future responses and clarify accountability for critical grid infrastructure.

In summary, the April 28 blackout was not simply a renewable-energy-driven failure. Instead, it exposed broader systemic vulnerabilities in grid planning, operational management, voltage stability enforcement, and market dynamics. Renewable energy was neither the cause nor the problem, but the incident underscores the urgent need to ensure renewable-rich grids embody robust voltage and frequency management capabilities traditionally provided by synchronous fossil generators. The future, however, clearly belongs to renewables supported by advanced inverter technologies, dynamic voltage stabilization hardware, smart market structures, and robust regulatory frameworks.

Undoubtedly the Global Power System Consortium (GPST), co-founded by Mark O’Malley, currently Leverhulme professor of power systems at Imperial College London, has been engaged with the discussion and will be dissecting the lessons for years. Expect lots of power engineering PhDs to spin out of this exploring different complex aspects and potential approaches. Expect the lessons learned to shape grid operations globally. Certainly I’ve been returning to my conversation with O’Malley (part 1, part 2) time and again, including this morning as I discussed the report with infrastructure investment clients in Toronto.

The earlier success in rapidly restarting the grid after the blackout is a testament to the industry’s capability for effective emergency response. However, avoiding recurrence of such an event requires strategic investments, regulatory reform, technological upgrades, and systemic planning improvements.