The Iberian BESS paradox

On a Monday in April 2025, 60 million people across Spain and Portugal lost power. The blackout was no minor technical accident, and it exposed the Achilles’ heel of the Iberian energy transition. The system collapsed because it lacked sufficient storage, because synchronous generators were being displaced, and because the interconnection with France remains a bottleneck.

Curtailment of renewables in Spain had been on the rise already, before a spike following the April 2025 blackout and related tightening of operational controls. Despite accelerated deployment of energy storage, Aurora Energy Research still forecasts more than 3 TWh of curtailment per year up to 2027.

One year on from the Iberian Peninsula blackout, the market’s response has been ambitious, but remains incomplete. Since then, installed battery capacity in Spain has grown 589% from 28 MW to 193 MW. Yet in that same period, 5,414 GWh of renewable electricity was curtailed. Never have we produced so much clean energy and wasted so much. The blackout and its aftermath raised system operating costs 49%.

Batteries are arriving, but curtailment is getting worse. This happens when storage projects cannot get a connection offer reflecting the risk they absorb.

Regulatory architecture is responding. Spanish regulator CNMC published its flexible access framework. Portugal’s ERSE published Directive 3/2025, establishing a non-firm connection regime for generation and storage. Neither has so far produced a single bankable battery energy storage system (BESS) project. Hundreds of megawatts of grid-scale storage remain stuck in connection queues. The compensation structure is missing.

Flexible connection

Grid access in both markets runs on firm-access logic. Projects are assessed on peak injection capacity and receive a connection point based on the assumption they will inject at that level whenever they choose.

This made sense for grids built around dispatchable generation. It fails for storage, because the value of a battery system is its ability to change when and how much it injects. A firm-access connection treats that flexibility as a liability rather than the service it provides, pricing storage the same way as solar, without a mechanism for developer compensation for connecting where the grid needs help.

Spanish grid operator Red Eléctrica curtails renewables at constrained nodes. That curtailment signal does not translate into a differentiated connection product. A BESS developer might be willing to connect at a congested node, absorb curtailment from local solar and dispatch when the constraint clears. There is simply no contract structure that lets a developer price it, put it in a financial model and hand that model to a lender. The CNMC framework names the concept, but the compensation mechanism is absent.

Portugal’s situation is more acute. ERSE published Directive 3/2025, which allows projects to connect at congested nodes if they accept curtailment risk. On paper, the logic is sound. No standalone generation or storage project has been connected under it, because ERSE has not published the tariff structure that makes the trade-off financially rational.

A functioning non-firm BESS connection requires three elements: a connection agreement that specifies curtailment conditions, a tariff discount based on expected curtailment frequency to reflect the nodal risk the developer absorbs, and access to a flexibility service market that compensates dispatch during peak constraint periods. These three elements together allow a developer to model cashflows, stress-test curtailment scenarios and present a bankable project to a lender. None are technically complex.

This has been tested. The UK’s “Connect and Manage” regime has used this logic since 2010, to allow generation to connect at constrained nodes before reinforcement works were complete. Ireland’s DS3 program has priced fast-frequency response and other system services at rates that make BESS viable at constrained nodes since 2018. Neither requires new transmission infrastructure as a prerequisite, both require a regulator to publish a payment structure and let the market respond. CNMC and ERSE have had the frameworks on paper for over a year without taking that step.

Demand growth

Data centers are entering queues in both markets, adding gigawatts of flat demand to a system where curtailment is growing by more than 100% per year. In July alone, curtailment can account for one third of the annual total. Firm-access was designed for centralized, predictable generation.

Curtailment risk is now a central driver of project valuation. Curtailment and negative pricing are two symptoms of the same structural problem: generation that cannot be absorbed, stored or priced out of the market. BESS developers price projects against capacity market revenues and ancillary service contracts but cannot price against a grid access product that does not exist. The projects that get built are those that can tolerate long queues and firm-access costs. Projects designed to solve the curtailment problem cannot get a connection offer that supports a positive net present value.

Grid reinforcement is the structural answer. Plans in both Spain and Portugal include upgrades targeting the nodes with the most concentrated curtailment. The Bay of Biscay submarine interconnection, now under construction, will raise Spain-France exchange capacity from 2.8 GW to 5 GW, but is seven to 10 years away. BESS projects with a development cycle of three to four years can absorb curtailment today. Aurora Energy Research predicts curtailment will persist above 3,000 GWh through 2027 under current reinforcement plans. Iberia cannot export its way out of the problem. Internal flexibility is the only near-term valve.

Data center connection requests already in the queue will land on the same nodes driving the curtailment. Without a compensation structure, CNMC and ERSE are making grid expansion a larger and more expensive problem than it needs to be.

About the author

João Correia is a renewable energy specialist with six years of experience in the Iberian market. He has developed a portfolio of over 1.3 GW in utility-scale solar, wind, and BESS projects across Iberia, with a focus on energy storage (BESS) and technical assessments in Portugal.

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