What we know about the blackout in Spain and Portugal
On April 28, 2025, a massive and sudden blackout disrupted electricity supply across most of Spain and parts of Portugal, with some ripple effects reaching southern France. The outage, which began around 12:30 p.m. CEST, resulted in the loss of approximately 15 GW of power in Spain — about 60% of the country’s demand at the time. Power was restored progressively, but full service took nearly 24 hours in some regions. The blackout led to severe disruptions in transportation, communications, and emergency services and was associated with at least eight reported fatalities.
Why did it happen?
Initial assessments suggest a complex convergence of technical and structural issues rather than a single point of failure. Key theories include:
- Grid decoupling and frequency instability: A cascade of disconnections possibly due to localized frequency deviations may have separated the Iberian grid from the European grid, removing critical balancing power flows.
- High penetration of renewables: With over 80% of Spain’s electricity coming from renewables (especially solar and wind) at the time, the grid lacked inertia typically provided by synchronous generators, making it vulnerable to disturbances.
- Low inertia and lack of fast frequency response: The absence of sufficient inertia and rapid response mechanisms limited the grid’s ability to absorb frequency fluctuations.
These causes are not mutually exclusive — in fact, they may have acted in concert. The high share of solar photovoltaics and limited inertia likely created fertile ground for instability, particularly under certain meteorological conditions. A plausible hypothesis, supported by academic research, points to the role of resonant frequency excitation. Electric power grids have natural eigenfrequencies (typically between 0.1–5 Hz), which can be excited by input fluctuations at matching frequencies. On a sunny day with fast-moving clouds, the intermittent shading of solar panels can produce power output oscillations that could align with these grid eigenfrequencies.
When such oscillations persist even briefly (e.g., over 30 seconds), they can excite resonance in the grid, causing disproportionate swings in frequency. As this happens, inverters — designed to protect themselves and the grid — begin disconnecting, rapidly shrinking the supply side and worsening the imbalance. Other grid-connected assets, including flexible demand and generation units, may also trip offline in response to abnormal frequency conditions, further amplifying the instability. Since the grid was heavily reliant on the generation of renewables at the time, it lacked sufficient inertia — meaning it could not absorb fast frequency fluctuations effectively. This made the system more vulnerable to oscillations and resonance. Compounding the issue, hydroelectric generation was at its lowest level recorded for the month of April — likely due to scheduled maintenance — removing one of the few remaining dispatchable, inertia-providing resources from the system and eliminating a critical buffer that might have helped contain frequency swings and prevent cascading failures.
Market mechanisms
Preventing large-scale blackouts in low-inertia, high-renewable grids will require the deployment of market-based mechanisms that incentivize flexibility, responsiveness, and coordination across the power system. In Australia, modeling by the Australian Electricity Market Operator suggests that unlocking distributed energy resource (DER) and virtual power plant (VPP) integration could save approximately AUD 834 million between 2027 and 2050 through avoided system costs. In the U.K., the government’s Smart Systems and Flexibility Plan 2021 estimated that energy system cost savings from flexibility could reach GBP 30 billion–GBP 70 billion by 2050, benefiting both grid operators and consumers through deferred infrastructure investment and optimized dispatch.
- Flexibility markets reward DERs, storage, and flexible loads for adjusting their output or consumption in response to real-time grid needs. For these markets to function effectively, they require close coordination between transmission system operators (TSOs) and distribution system operators — as demonstrated in the U.K. — to define service requirements and available capacity. While most flexibility is currently procured through long-term contracts, intraday flexibility markets are being piloted to address short-term renewable variability, led by platforms such as NODES, Piclo, and EPEX SPOT.
- VVPs enable the aggregation of rooftop solar, batteries, EV chargers, and controllable loads into a single, dispatchable resource that can participate in energy and ancillary service markets. In the U.K., VPPs are already active in wholesale and balancing markets, supported by progressive regulatory frameworks. In Spain, VPPs can access both day-ahead and intraday markets via the Iberic Market Operator with a 0.1-MW minimum bid but remain excluded from ancillary services due to a 1-MW minimum asset threshold and limited aggregator rights. Although aligned with EU directives in principle, recent reports show that Spain’s regulatory readiness for demand-side aggregation remains moderate, with market readiness lagging due to infrastructure and prequalification barriers.
Technology solutions
As less synchronous generators provide power to a renewable grid, the need for new sources of inertia grows. Legacy large-scale assets like hydroelectric generation and combined cycle gas turbines will remain key contributors for grid stability, but grid operators must have a suite of solutions to ensure power reliability, including both real and virtual inertia.
- Grid-forming inverters can be paired with generating or storage assets to stabilize the grid on a seconds timescale. Unlike traditional grid-following inverters, grid-forming inverters create a reference signal that they can feed back to the grid. These inverters can be programmed to provide droop control, act as a virtual synchronous machine, or provide virtual oscillator controls. However, since these tools utilize programmed algorithms, there must be coordination across devices in large-scale grid implementation, and piloting such projects is still at an early stage.
- Flywheels store energy in the form of kinetic rotational energy and provide high-power energy storage. When connected to the grid, flywheels acts as a real source of mechanical inertia, making them a critical complimentary tool to virtual inertia technology. Even when grid-forming inverters are deployed at scale as a proven technology, redundancy in the form of mechanical inertia will protect against disruptions in case of failure. Flywheels are a mature technology with a high cycle life and fast response time, making them ideal for grid stability applications. However, their limited energy storage duration and relatively high costs have confined use to niche or hybrid applications, and grid-scale deployments remain relatively few.
- Synchronous condensers are rotating machines that stabilize voltage and frequency disturbances by providing reactive power and inertia. They act as replacements for synchronous generators without generating active power and offer dynamic support to the grid without software dependency. However, synchronous condensers are higher cost and take more space than inverters. This technology will act as a bridge solution while rotating generating assets are retired and grid-forming inverters are piloted.
- High-voltage DC (HVDC) transmission can act as a preventive measure for disruptions in electricity supply, especially connecting large loads across long distances. While an entire DC grid would require too much investment, new generation projects with HVDC transmission would isolate instability by removing frequency deviations and provide a stable source of capacity to the grid. While HVDC is currently an expensive endeavor, increased adoption will lead to standardization and improved economies of scale.
Most grids have been designed to transmit and distribute centralized generation, with contingency planned for single failures across the network; however, increasingly distributed generation and storage bring about new issues threatening grid stability. Technologies that can replace inertia lost by retired assets are varied, and a stable grid will need to implement multiple sources of mechanical and artificial inertia so that failures are minimized. Regulations that incentivize grid stability services play a critical role in technology adoption and encourage distributed resource participation. While regulatory frameworks supporting VPP integration are advancing in regions like the U.S., Australia, and parts of Europe, many electricity systems still impose entry barriers — such as high-capacity thresholds, restrictive aggregator requirements, and underdeveloped real-time flexibility markets — that limit VPP access to ancillary and wholesale services. Overcoming these regulatory and structural constraints is essential to fully realize the value of VPPs.
Lux Take
This incident highlights the need for increased emphasis on replacing lost inertia on the grid, and utilities clients forming their own grid stability strategies should place high priority on demonstrating grid-forming inverters, starting with small pilots and moving toward scale deployments. Though implementation in large-scale grid systems is still minimal, such demonstrations have already been successful in larger island grids with a high penetration of renewables such as Hawaii. To support more deployment of grid-stabilizing infrastructure, TSOs should mandate redundancy in both real and virtual inertia in regions with a high reliance on intermittent renewables. While simultaneous failures across a network are unlikely, these incidences will become more common for renewables-heavy grids.
