Spain’s electricity storage market is entering a critical regulatory phase as policymakers prepare the country’s first capacity auctions, currently expected in 2027.
While battery energy storage system (BESS) developers have long viewed the mechanism as a source of predictable revenues, analysts argue that its primary purpose should remain safeguarding system reliability rather than ensuring project profitability.
That distinction is likely to shape the design of one of Spain’s most consequential electricity market reforms. Key details remain under discussion, including auction volumes, pricing rules, firmness coefficients, technology quotas, and the balance between existing assets and new projects. Together, these decisions will determine whether batteries emerge as major beneficiaries or simply one competitor among several technologies capable of providing capacity.
According to Javier Pamos Serrano, Iberia Product Manager at Aurora Energy Research, the market should preserve technological neutrality rather than favor storage simply because it is considered essential for the energy transition.
“The capacity market is not designed to make battery projects financially viable,” Pamos said, arguing that the mechanism should address genuine security of supply requirements while minimizing costs to consumers.
That position reflects Spain’s relatively different starting point compared with several European markets. Unlike countries that face tighter generation margins, Spain continues to maintain a substantial combined cycle gas fleet capable of providing dispatchable capacity during periods of low renewable output. As a result, batteries are not entering a market where security of supply is immediately constrained.
This existing thermal capacity could significantly influence auction outcomes. If gas plants can deliver reliability services at lower cost, battery projects may secure only a limited share of capacity contracts, reducing the market’s importance as a long term revenue source for storage developers.
Spain has so far relied primarily on capital subsidies to support storage deployment instead of introducing long duration capacity mechanisms similar to Italy’s MACSE framework. That approach has limited long term regulatory commitments while helping contain costs, although it has also left investors seeking greater revenue certainty as battery deployment accelerates.
One of the most closely watched elements of the forthcoming market design is the firmness coefficient assigned to each technology. This parameter determines how much dependable capacity an asset is credited with during system stress events and therefore directly affects its competitiveness in capacity auctions.
For battery operators, that coefficient may ultimately prove more valuable than auction clearing prices. A conservative assessment of battery availability could reduce their effective participation regardless of falling technology costs or improving operational performance.
Aurora also points to international experience as evidence that capacity market design can produce unintended market outcomes.
In the United Kingdom, favorable capacity market signals encouraged rapid battery deployment. While that expansion strengthened system flexibility, it also intensified competition across balancing and ancillary service markets, compressing revenues as growing numbers of storage assets competed for limited opportunities.
Italy presents a different challenge. Under the MACSE framework, batteries contracted through the mechanism may operate differently from assets outside it because the transmission system operator manages contracted storage to meet network needs rather than maximize commercial returns. That structure could place non contracted batteries at a competitive disadvantage in ancillary service markets.
These examples illustrate that capacity mechanisms influence not only investment decisions but also broader electricity market dynamics. Rules governing dispatch, market participation, and operational control can materially affect revenue streams beyond capacity payments themselves.
Spain’s regulatory challenge therefore extends beyond determining how much capacity to procure. Policymakers must also avoid creating incentives that distort competition between storage, gas generation, hydroelectric facilities, and other flexible resources capable of supporting system reliability.
Recent grid events have reinforced the urgency of that debate. The widespread blackout that affected the Iberian electricity system intensified attention on operational resilience and accelerated discussions around voltage control, operating ramps, and more flexible grid connection requirements. While batteries are increasingly recognized as valuable flexibility assets, regulators continue to assess how their capabilities should be reflected within market rules.
At the same time, financing remains a significant obstacle. Unlike conventional generation assets with relatively predictable income streams, battery projects typically depend on multiple volatile revenue sources, including energy arbitrage, ancillary services, balancing markets, and potentially future capacity payments. That complexity complicates project financing and increases lender risk assessments.
Developers are therefore exploring commercial structures such as tolling agreements, hybrid power purchase agreements, and hedging arrangements to improve revenue certainty. The ability to combine these contracts with future capacity payments may ultimately prove more important for investment decisions than the capacity market alone.
