Joan Ramón Morante and Héctor Santcovsky

June 26, 2026

The energy transition is already a central pillar of the public agenda, with geopolitical, economic, social, and environmental implications. It entails rethinking supply, storage, and the role of transmission and distribution networks, with new actors—generators, consumers, and storage operators—and a forecast that electricity consumption will triple by 2050. This is an unprecedented transformation that requires revising infrastructure, regulatory frameworks, business models, and governance.

Fossil volatility versus renewable stability. The role of networks

Since the first oil crisis, fossil fuel prices have been subject to speculation, geopolitics, and armed conflicts, such as the war in Ukraine, generating decades of uncertainty for citizens, industries, and planners.

When most energy comes from the sun and wind, amortization, operation, and renewal costs will need to be fixed and controlled by authorities, since the raw material is universally available and its marginal cost is virtually zero. This opens the door to decoupling energy prices from geopolitical volatility.

The same applies to storing surpluses to cover 24/7 demand. Batteries, pumped hydro, or green hydrogen must be regulated with clear tariffs that prevent stored energy from becoming more expensive due to speculative logic, treating it as a public good rather than merely a business.

Transmission and distribution cease to be mere conductors of electrons and become the nervous system of a decarbonized economy. The ability to evacuate energy generated in rural, coastal, or offshore areas toward consumption centers will determine the pace and cost of the transition. A poorly planned grid can become the main bottleneck of the process.

Trapped between new models and grid capacity?

Self-consumption and energy communities democratize energy and reduce costs, but maintaining supply rights requires preserving “latent capacity” for emergencies. The European Commission will authorize Spain a ten-year capacity mechanism, with an estimated cost of €9 billion—equivalent to around 9 GW—on top of what is already paid for capacity and networks even without consumption.

Does this imply collusion between two parallel systems? Should large-scale storage not fulfill this role? There is a lack of a clear roadmap, beyond the PNIEC, on how the grid will evolve. Its absence explains episodes such as the recent blackout and fails to comply with recommendations from ENTSO, generating additional costs such as the €607 million announced by the MITECO on May 21 to reinforce the grid with synchronous compensators, following technical constraints that in 2025 exceeded €3 billion due to gas dependency.

Critical questions about the current model

Is the current grid structure adequate? Does the marginal pricing market reflect today’s reality? This model, where the price of all electricity is set by the cost of the last dispatched unit—usually a gas combined cycle—was designed in a context of dominant fossil generation. With zero-marginal-cost renewables, it generates unjustified rents for producers and inflates bills without reflecting real costs. How should it evolve toward 2050? Does the CNMC have sufficient capacity?

A European study by ENTSO-E and DSO-E points to a lack of planning in Spain and discrepancies among stakeholders. It calls for a single national grid development plan, coordinated between the system operator and companies, with a clear scenario for electrification, demand, and renewable deployment. Leading countries share territorially agreed planning with local entities, assessed substation by substation. A dynamic public map of grid capacity—with data on projects above 1 MW—is needed to avoid the collapse of saturated nodes.

Do current operational frameworks serve these changes? The blackout of April 28, 2025, and the ongoing extra costs to ensure stability are symptoms of structural cracks that cannot be fixed with patches. The fundamental question is whether Red Eléctrica de España, under the umbrella of SEPI, has the institutional framework, incentives, and regulatory independence needed to lead this transformation.

Concentration risks: the SEPI model and European alternatives

Concentrating everything within a single public entity is a high risk. The liberalization of telecommunications, railway unbundling, or the creation of independent grid operators in other countries show that functional and ownership separation generate more efficient systems oriented toward the public interest. Concentrating regulatory, operational, and ownership functions in one entity creates conflicts of interest and hinders independent oversight.

In Germany, four independent TSOs (TenneT, Amprion, 50Hertz, and TransnetBW) coordinate planning under the supervision of BNetzA. In France, RTE operates with full separation from EDF. In the United Kingdom, the system operator (NESO) has no ownership interests in the grid. ENTSO-E and ENTSO-G have highlighted Spain’s interconnection deficiencies with Europe as a key risk for security of supply in the Iberian Peninsula.

In Spain, grid management and energy planning reproduce tensions between the State and the autonomous communities. Regions with the greatest renewable potential—Aragon, Castile and León, Extremadura, Andalusia, Galicia—host large installations whose benefits and decision-making power reside at the state level or with large operators based in Madrid. This imbalance affects social acceptance of projects and the distribution of the transition’s benefits.

Planning of the transmission grid, an exclusive competence of the State through REE, does not always integrate territorial needs. State-level processing of projects without coordination with regional land-use planning generates conflicts, delays, and a perception of imposition. Genuine multilevel energy co-governance is needed.

What planning do we need?

There is no certainty about the exact path, but there is about the need to define the tools to plan it toward 2050. This roadmap cannot depend solely on current operators. A participatory, technically sound, and legitimate process is required to define:

  • Future institutional architecture: who operates, regulates, and plans, with what independence and accountability.

  • A market model adapted to a renewable-based system, replacing the marginalist scheme with contracts for difference, long-term auctions, or hybrid models with stable investment signals and no unjustified rents.

  • A review of the CNMC, which currently lacks the resources and mandate to oversee the system’s growing complexity.

  • A network financing and remuneration model that incentivizes investment without transferring undue risks to consumers.

  • Mechanisms to prevent speculation in energy storage.

The PNIEC sets commendable quantitative targets but lacks specificity in deployment mechanisms, regulatory instruments, and institutional governance needed to achieve them. Without that, they are aspirations, not commitments. The energy transition does not happen by itself: it requires bold political decisions, deep institutional reforms, and an informed and engaged society.

Power grids, quo vadis? The answer cannot wait.