Spanish consumers paid an average of €19.36 for every megawatt-hour of electricity between January and September 2026 just to make the day-ahead market's schedule physically workable. That is the technical-constraints component of the final price, as published by Red Eléctrica (REE), the system operator, and it equals 20.3% of the €95.56/MWh average final price over those nine months. In the same months of 2024 the component was €8.72/MWh and 13.3% of the final price.
REE's own headline, in a press release of 2 October, was €3.614 billion of technical-constraint costs from 1 January to 30 September, 45% more than a year earlier. Much of the public argument about that number has turned on the "reinforced operation" REE adopted after the peninsular blackout of 28 April 2025, under which it schedules extra synchronous plant, mostly gas-fired combined-cycle units, to hold voltage. REE says that regime cost less than €275 million in the first nine months of 2026. On REE's figures, it was therefore under 7.6% of the constraints bill.
Rebuilding the bill from the price components
REE publishes, through its REData service, a monthly breakdown of the final electricity price into market, adjustment-service and capacity-payment components, each expressed in euros per megawatt-hour of closing energy, together with the closing energy itself. Multiplying the two constraint components (constraints resolved after the day-ahead market, in the base daily schedule known as PDBF, and constraints resolved in real time) by the monthly energy gives a cost series that can be compared across years.
For January to September 2026 that calculation gives €3.633 billion, within 0.5% of the €3.614 billion REE reported. For the same months of 2025 it gives €2.485 billion, against the €2.49 billion implied by REE's 45% growth rate. The match is close enough to use the series to look inside the total.
The nine-month totals rebuild as follows. In 2024 the constraints cost was €1.535 billion, or €8.72/MWh, against an energy-weighted day-ahead price of €54.06/MWh. In 2025 it was €2.485 billion, or €13.67/MWh and 16.7% of the final price, with day-ahead at €65.84. In 2026 it reached €3.633 billion, €19.36/MWh and 20.3%, with day-ahead at €75.30. Closing energy grew by 6.6% over the two years, from 176.1 TWh to 187.6 TWh, so nearly all of the 2.4-fold rise in cost came from the price per unit.
Two other features stand out. The split between the two phases has moved sharply. Constraints solved in the day-ahead schedule cost €3.103 billion in January to September 2026, 86% more than a year earlier, while real-time constraints fell 35% to €530 million. And the monthly profile is uneven. February and March 2026 cost €452 million and €546 million, the highest months in the series, when the day-ahead price averaged €17.92/MWh and €44.07/MWh. The PDBF component in March was €24.60/MWh, more than half of that month's day-ahead price.
Where the money went
Combined-cycle generation on the peninsular system rose from 18.8 TWh in January to September 2024 to 26.3 TWh in 2025 and 30.5 TWh in 2026, according to REE's generation data. Solar PV output rose from 36.2 TWh to 48.1 TWh over the same two years; wind was flat at around 41 TWh. In months when wind, hydro and solar clear most of the day-ahead market, gas units that the operator needs for voltage or reserve do not get scheduled through the market and have to be called on through the constraints process, where they are paid as bid.
That pay-as-bid feature is the core of REE's defence. In a press release of 23 July the operator said that in 2025 the energy it scheduled through constraints rose 47% while the cost rose 63%, because the energy was offered and paid at an average €165/MWh against a mean market price of €65.26/MWh. For January to September 2026 it gave €204.67/MWh for upward constraint energy against an arithmetic day-ahead average of €74.10/MWh. On those figures the premium of constraint energy over the market price widened from 2.53 times to 2.76 times. Energy needed for constraints rose 31.5% year on year, REE said, and the cost to demand 45%.
The pattern over the summer fits the regulator's reading. In its voltage-control monitoring report of 8 October (IS/DE/036/26), the Comisión Nacional de los Mercados y la Competencia (CNMC) said it had seen a reduction in combined-cycle units scheduled through constraints for voltage control, which it linked partly to more of those plants clearing in the day-ahead market in recent months. July to September 2026 had the three highest day-ahead prices in the series, at €103.44, €117.18 and €143.09/MWh, and combined-cycle output above 4.3 TWh in each month. The PDBF component fell to around €13/MWh in July and August.
September breaks the pattern. The PDBF component rose back to €20.37/MWh, and the month cost €477 million, second only to March. The CNMC report gives a reason that has little to do with the reinforced mode: constraint scheduling for other causes has increased. According to the operator, constraints for insufficient upward reserve mainly reflect deviations in renewable output, and constraints for contingencies reflect the geographic concentration of renewables and growing network flows, which require downward redispatch and sometimes upward redispatch to rebalance. REE also flagged more actions for low system damping and large imbalances. When gas is expensive, each megawatt-hour bought through that process costs more.
The reinforced mode in context
The CNMC report, drawing on REE data, puts the cost of reinforced operation at €516 million for May to December 2025 and €275 million for January to September 2026, about €64.5 million a month falling to €30.6 million, which it describes as a reduction of close to 53% in monthly terms. REE converts the 2026 figure into 2 cents a day for a regulated-tariff (PVPC) customer using 300 kWh a month.
The same conversion applied to the whole constraints component gives a larger figure. At the nine-month average of €19.36/MWh, a 300 kWh monthly consumption carries €5.81 a month of technical-constraint costs before taxes, or about 19 cents a day. PVPC customers are charged hourly components rather than the nine-month average, so this is an order of magnitude and not a bill line.
The regulatory work that is supposed to reduce the bill has moved slowly. The CNMC approved a new operating procedure for voltage control, P.O. 7.4, on 12 June 2025, under which facilities of 5 MW or more connected to the transmission network can volunteer to follow real-time voltage setpoints from the operator and be paid for it. Temporary changes to procedures 3.1, 3.2 and 7.2 to dampen sudden voltage swings followed in October 2025, were extended four times and were reformulated in a resolution of 19 January 2026. The setpoint mode only began operating with financial effect on 17 March 2026.
By the end of the second quarter, the CNMC's tables show 9,249 MW of installations under the renewables, cogeneration and waste regime (RECORE) enabled for real-time setpoints, against 80,675 MW still on basic power-factor control. Outside that regime, 14,601 MW was on setpoints and 30,744 MW on basic provision. Across both groups, 17.6% of capacity was following real-time setpoints, and 10.3% of RECORE capacity. The CNMC said enabled renewable capacity in the setpoint mode had grown by 5 GW in the previous three months. A second resolution, of 30 June 2026, raised the payment for the setpoint service, especially when a plant is not producing active power, and added a fixed-setpoint option for facilities of 1 MW or more. The new payment is due to apply from 1 November 2026 and the fixed-setpoint mode from March 2027.
Penalties for failing voltage-control obligations remain small next to the costs they are meant to discourage. The CNMC's table of payment obligations from penalties sums to about €2.09 million for January to June 2026 across all three provision types. TEI's estimate of constraint costs for the same six months is €2.40 billion.
The report also gives a measure of a problem specific to Spain's grid layout: shared evacuation networks ("mancomunadas"), where many renewable plants connect through one transmission node. Of roughly 200 such nodes studied, between 45% and 57% each month from January to June 2026 exceeded the P.O. 7.4 threshold of 1,000 MVArh a month of reactive energy flowing against the node's needs. The CNMC is leading a working group with REE and the owners of those shared assets.
Who pays
On 27 July 2026 the CNMC asked REE to analyse whether the current way of charging technical constraints to demand gives consumers appropriate signals and reflects costs correctly, with a view to a proposal for regulatory change. Retailers want the cost moved into a regulated, stable charge tied to network tariffs. The CNMC's response, in the October report, is that a regulated price set in advance needs careful operational design and could misjudge costs while the voltage-control service is still being rolled out and gas prices remain hard to forecast.
REE has pointed to grid investments instead. Its July release said that equipment for static and dynamic voltage control and oscillatory stability, included in recent amendments to the transmission plan, could reduce constraint costs by around 15%, and that the coming capacity-market auctions should push generators toward lower bids in the system-operator markets. The CNMC has separately asked REE, before the final 2025-2030 transmission plan, to report on voltage-control needs and resources and to propose an action plan.
Until any of that takes effect, the cost sits in the final price. REE's year-end figures for 2021 to 2025 show technical constraints rising every year, from €724 million to €3.347 billion. The first nine months of 2026 have already passed the 2025 total. REData returned no October price components when TEI queried it on 28 October.