Adapt or die: how does the Iran conflict affect my utility?
In 2022, 100 utilities closed — this year will decide who leads the next ten.
The conflict with Iran has blown up European energy stability. And the Spanish electricity market is no exception. Since the conflict began, the pool price has gone from 16 €/MWh (February) to 72 €/MWh (so far in March), reaching the highest level of the past year yesterday with an average of 136 €/MWh. In addition, the system's balancing services costs remain impossible to cover with hedging instruments, and the utilities that based their model on buying on the wholesale market and reselling at a margin are reliving what happened 4 years ago with the war in Ukraine.
Within this scenario of extreme volatility, a window of opportunity is opening for those who decide to stop being mere kilowatt intermediaries and start offering real value beyond buying cheap hedges for the coming months. Four years ago, exposure to gas was the biggest catalyst for self-consumption, in a context where we had not worked out the supply chain, the sector lacked technical maturity and storage prices were still out of range. Today, with 9.3 GW of solar self-consumption already installed in Spain, a recently approved aggregation regulation and a European flexibility market that will triple to 12 billion euros by 2030, the tools are there. The question is who moves first.
The war in Iran has caused the biggest energy disruption since 2022
On 28 February 2026, joint attacks by the United States and Israel against Iran triggered a military escalation that has shaken global energy markets. Iran responded with missile attacks on Gulf infrastructure, including Saudi Aramco's Ras Tanura refinery and the Ras Laffan LNG terminal. Between 1 and 2 March, the Iranian Revolutionary Guard closed the Strait of Hormuz, through which 20% of LNG exports normally pass, blocking the passage of 20 million barrels a day: the largest supply disruption in modern energy history, greater than the 1956 Suez crisis.
Brent went from around 63 $/barrel in January to a peak of close to 120 $ on 9 March, before falling back to 88 $ after Trump's comments about an imminent end to the conflict. European TTF gas (Title Transfer Facility) almost doubled, from around 32 €/MWh to a peak of 65 €/MWh, stabilising between 48 and 55 €/MWh in mid-March. The situation is aggravated by the low gas storage levels in the EU: just 46 bcm (30% of capacity), compared with 60 bcm in 2025 and 77 bcm in 2024.
Goldman Sachs raised its TTF forecast for April to 55 €/MWh (from 36 €/MWh), warning that a one-month closure of the Strait of Hormuz could push TTF to 74 €/MWh, and a two-month interruption above 100 €/MWh, levels not seen since the 2022 crisis. The OMIP futures markets for Spain reflect a dual reading: short-term panic but a degree of medium-term optimism. April 2026 futures are trading at 42.50 €/MWh and Q2 at 51.40 €/MWh. But hedging today is not cheap: those same quarterly futures were trading at 40-41 €/MWh a year ago for the equivalent quarters. Hedging now costs 25-27% more than in March 2025. And if the market gets it wrong and the conflict drags on, the consequences for utilities with fixed-price contracts could be catastrophic.
The Spanish pool soars and balancing costs remain the silent killer
The average daily pool price on OMIE jumped from 71.67 €/MWh in January to 136.86 €/MWh on 10 March, the highest level since February 2025. Intraday peaks exceeded 250 €/MWh between 21:00 and 23:00. The regulated PVPC tariff reached 394.27 €/MWh in the 20:00 to 21:00 slot that same day. The intraday pattern is extreme: solar pushes prices close to zero at midday, and the evening peak hours with marginal gas explode above 200 €/MWh.
But this spike caused by the Iran crisis lands on a pre-existing structural crisis. Since the national blackout of 28 April 2025, the system's balancing services (SSAA) have become the real margin destroyer. These balancing costs have gone from approximately 1 €/MWh in 2019 to 27.52 €/MWh in 2025, an increase of 351% in three years. The total cost of technical constraints reached 3.3 billion euros in 2025, with around 1.1 billion directly attributable to REE's post-blackout reinforced operation measures.
The main problem for utilities is that there are no hedging instruments for balancing services costs. While utilities can hedge their exposure to the pool price through OMIP futures, bilateral OTC contracts or PPAs, SSAA costs cannot be hedged. This turns every fixed-price contract into a bet on unpredictable system costs.
Fixed-price contracts are being redesigned: the traditional model cannot hold
The combined pressure of volatile pool prices and unhedged SSAA costs is transforming the way utilities structure their offers. Many fixed-price campaigns were frozen after the April 2025 blackout. The consultancy Evoltio warned of a high risk of repeating an episode similar to 2021, with possible contract breaches or extraordinary adjustments. Let us remember that the 2021 crisis led to the closure of 26 utilities in a single year, with around 100 small utilities closing in total.
The defensive responses have been varied. Many new contracts include SSAA pass-through clauses, setting a threshold (around 20 €/MWh) above which the excess is billed to the customer. Iberdrola has introduced annual SSAA review clauses. Gana Energía applied a 6% surcharge to cover these costs. Others have shortened commitment periods or added CPI escalation clauses.
The OCU found that utilities have quadrupled the fixed charges for contracted capacity, going from 24.40 €/household in 2021 to 83.10 €, in order to appear competitive on kWh price while recovering costs elsewhere. And when the CNMC explicitly banned utilities in June 2025 from modifying existing fixed-price contracts to pass on post-blackout SSAA costs, several were forced to reverse increases they had already announced, deepening their losses.
The competitive landscape remains intense despite these pressures. Spain has more than 534 active utilities, one of the highest numbers in Europe. In 2024, 7.25 million electricity company switches were recorded, an all-time record that affected 23.9% of consumers. But concentration is intensifying: the 5 big groups control 84.9% of the supply points in the domestic free market. The disruptive case is Octopus Energy, which surpassed 500,000 customers at the end of 2025 (from 35,000 in 2022), while Endesa and Naturgy lose share. Independent utilities without generation assets suffer the most acute pressure: worse hedging conditions, higher collateral requirements and no possibility of earning from balancing services as generators do.
Self-consumption and flexibility: from niche product to necessity
Spain now has 9.3 GW of accumulated solar self-consumption capacity across more than 500,000 installations, generating 10,550 GWh in 2025, approximately 4.1% of national electricity demand. Although new installations fell for the third consecutive year to around 1,139 MW (from the peak of 2,600 MW in 2022), the market is maturing, not dying. Behind-the-meter storage grew by 119% to 339 MWh in 2025. The average residential size rose to 5.5 kW, reflecting the electrification of heating and electric vehicle charging. And the April 2025 blackout caused a 105% increase in off-grid installations, reviving consumer interest in energy autonomy.
The economics of self-consumption remain attractive: an average saving per household of 1,007 €/year (an 84% reduction in the bill) with a payback period of 6.2 years on an investment of around 6,900 €. But the real story is in what comes after the installation.
Battery storage is no longer an expensive technology for early adopters. According to BloombergNEF, the cost of stationary storage batteries fell by 45% in 2025 alone, to 70 $/kWh at pack level. In three years it has halved. At these prices, a household with solar self-consumption that adds a physical battery does not need any utility to “store” its surplus in an accounting entry. It stores it itself. And it uses it when electricity is expensive, which is exactly when the system needs it most. For utilities, this means the customer with panels and a battery no longer depends on the pool during peak hours. Either you offer them something better than the market, or that customer disconnects from your value proposition.
The regulatory framework is now ready: RD 88/2026 and the era of the independent aggregator
The Spanish flexibility ecosystem received its most important regulatory boost with Royal Decree 88/2026, published on 12 February 2026. This regulation formally establishes, for the first time, the figure of the independent aggregator, completing the transposition of European Directive 2019/944.
The key points of this regulation are decisive. Aggregators can combine consumer loads, distributed generation and storage to participate in balancing markets. Consumers have the right to contract aggregation services without their utility's consent. Utilities with more than 200,000 customers are required to offer dynamic tariffs. And a national datahub is created that centralises the data of all supply points. REE has two months to design the aggregation procedures and utilities four months to adapt.
Added to this is the expansion of shared self-consumption from a 2 to 5 km radius (RD-ley 7/2025), the creation of the figure of the self-consumption manager for collective installations and the revision of the demand response rules. The SRAD (active demand response service) has allocated 1,725 MW for the first half of 2026, 50% more than in 2025. Five MITECO sandbox pilot projects are testing the practical mechanisms of local flexibility markets, citizen storage and independent aggregator models.
The market opportunity is enormous, but it demands speed
The confluence of crisis and regulation opens a window for utilities that act with commercial agility. The European demand-side flexibility market will grow from 4 billion to 12 billion euros by 2030 according to McKinsey. Spain is particularly well positioned: more than 99% smart meter penetration (the highest in Europe) in the residential segment, a *pipeline* of around 16 GW of utility-scale battery projects to 2030, and a PNIEC target of 19 GW of self-consumption by 2030, compared with the current 9.3 GW. There is widespread scepticism in the sector about the viability of these official targets. Meeting the Government's plan would require installing 2,000 MW a year, almost double the current 1,100 MW. However, even if the market moved more slowly and only half of that ambition were achieved, we would be looking at massive growth. For utilities, the impact is direct on their business model: what today represents barely 3-5% of their customer base will scale up to between 14% and 17% in the short term. It is a far from negligible shift in mix that will force an immediate redesign of commercial strategy.
Consumer willingness exists, but it is not well served. Only 56.9% of households say they are satisfied with their electricity provider, with price being the main complaint. 66% of households with solar panels plan to install a heat pump in the next three years. And 71% of households prioritise security in energy spending above other variables: a clear signal of demand for the kind of predictable, optimised energy management that flexibility products can offer.
There are already utilities proving that the model works. Nexus Energía, the sixth largest Spanish utility, partnered with Bamboo Energy to offer industrial demand response: the food distributor Distribuciones Monteverde achieved a 6% saving on its bill through the shifting of refrigeration loads. Soldelia manages community solar projects in Córdoba at a fixed price of 0.06 €/kWh with no upfront investment. Holaluz and Som Energía are building community energy platforms. These pioneers are turning flexibility from a regulatory concept into tangible value propositions for the customer.
React now or lose the game
In 2024, 7.25 million electricity company switches were recorded in Spain, an all-time record. And that was before Iran sent volatility soaring. What is coming will be worse. Every sharp rise in the pool is a customer rethinking their contract. The question is not whether there will be customer movement, but who captures them.
The Iran crisis has exposed a vulnerability that was already there: utilities built on simple margins of wholesale buying and retail reselling are increasingly less viable. Hedging costs on OMIP are 25% above where they were a year ago. Balancing services remain impossible to hedge. And the customer notices it on the bill.
But in parallel, the pieces for a different model are already on the table. Self-consumption exceeds 9 GW installed. Storage has become 45% cheaper in a single year. RD 88/2026 enables the independent aggregator. And the European flexibility market will triple to 12 billion euros by 2030.
The utilities that are right now offering those customers on the move a real value proposition of control and management of their assets — self-consumption, storage, consumption optimisation — are going to keep them. And once inside an energy services relationship, those customers do not switch for half a cent less per kWh.
Whoever does not capture them during this window of volatility will have to compete for them in a calm market where the only lever is price. And that is a war that utilities without generation assets cannot win.
The window between regulatory enablement and market saturation is narrow. This is not a strategic reflection for the next offsite. It is a decision that must be made this week.
