Inside Spain's electricity market programs: who participates in each

Every megawatt-hour sold in Spain’s day-ahead market passes through a cascade of adjustments before reaching the grid. Technical constraints, intraday corrections, reserve assignments, and real-time balancing — each program reshapes who generates what and when.

The day-ahead market (PDBF) moves 434 TWh in a year — dwarfing every other program. But it is only the starting point. PDVP redistributes 23 TWh in each direction as the TSO resolves grid constraints. Intraday sessions add another 33 TWh of corrections across seven sessions. And the balancing programs (BS, RR, BT) provide the final real-time adjustments that keep frequency stable. This article maps who participates in each program, how much volume flows, and which technologies dominate — using I90 settlement data from March 2024 to February 2025.

PDBF: the day-ahead starting point

The day-ahead market determines who generates tomorrow. Every producer submits bids, OMIE clears the market, and the result is the PDBF — the base daily operating schedule.

Wind dominates with 118 TWh — 28% of all scheduled generation. Nuclear follows at 89 TWh, providing the baseload foundation that runs regardless of market conditions. Solar PV contributes 82 TWh, concentrated in daylight hours. These three technologies alone account for 69% of the day-ahead schedule.

Combined cycle gas, by contrast, schedules only 13 TWh — just 3% of the total. Gas cogeneration adds another 30 TWh. The day-ahead market tells a clear story: renewables and nuclear set the schedule, gas plays a supporting role. But this is only the first program in the cascade.

PDVP: who gains, who loses from constraints

The PDBF assumes a perfect grid. Reality is different. Transmission bottlenecks, voltage limits, and minimum generation requirements force the TSO (Red Eléctrica) to redispatch units — raising some, curtailing others. The result is the PDVP, the provisional viable program.

Combined cycle gas gains 16.9 TWh through constraint resolution — more than its entire PDBF schedule. This is the core of gas flexibility: when the grid needs generation where renewables cannot provide it, gas plants are the TSO’s primary tool. Nuclear adds another 4.5 TWh, typically from units that receive upward redispatch to cover specific grid zones.

On the other side, wind loses 9.4 TWh to curtailment. Solar PV loses 2.9 TWh, solar thermal 2.4 TWh. Hydro UGH drops 2.3 TWh. The pattern is consistent: variable renewables generate where they are built, not where the grid needs power. PDVP corrects for this mismatch, and the correction flows systematically toward gas.

PHF1: voluntary corrections reshape the schedule

After constraints, market participants can voluntarily adjust their positions through seven intraday sessions. PHF1, the first and largest session, opens at 15:40 the day before delivery — giving generators the first chance to respond to updated forecasts.

Combined cycle adds 3.7 TWh net through PHF1 — nearly all in the upward direction. Gas plants that held back capacity in the day-ahead now commit it at intraday prices. Nuclear adds 3.1 TWh through similar logic: plants that undercommitted in PDBF correct upward when they can.

Wind shows the most volatile profile: 2.5 TWh upward, 2.9 TWh downward. Forecast corrections go both ways — sometimes the wind blows harder than predicted, sometimes it doesn’t. Solar PV mirrors this symmetry at smaller scale. Gas cogeneration adds 1.4 TWh net, as industrial plants adjust generation to match real demand profiles.

Balancing: reserves for the final stretch

The last layer of the cascade provides real-time flexibility. Four programs handle different timescales: BS assigns secondary reserve bands, RTR resolves real-time constraints, RR provides replacement reserves, and BT delivers tertiary balancing energy.

Combined cycle gas dominates upward balancing across every program. RTR alone assigns 2.8 TWh of upward generation to gas — real-time constraint resolution that mirrors PDVP’s day-ahead pattern but at shorter notice. In BS, gas reserves 1.1 TWh of secondary band capacity, followed by hydro UGH at 645 GWh and solar PV at 502 GWh.

Wind dominates the downward side. In RR, wind absorbs -721 GWh of downward reserves — real-time curtailment when generation exceeds demand. BT adds another -260 GWh of downward wind adjustments. Hydro provides symmetric flexibility in both RR and BT, acting as a buffer that can ramp up or down with roughly equal volumes.

The cascade reveals who does what

Spain’s electricity market is not one market — it is a cascade of nine programs, each with its own logic, its own dominant technologies, and its own economics. The day-ahead market sets the starting point: wind, nuclear, and solar account for most of the scheduled volume. But every subsequent program shifts the balance toward flexible technologies.

Gas plants schedule 13 TWh in the day-ahead — modest compared to wind’s 118 TWh. Yet gas earns an additional 16.9 TWh through PDVP constraints, 3.6 TWh through intraday corrections, and 4.8 TWh across balancing services. By the time electricity is physically delivered, gas has nearly tripled its market footprint. Wind moves in the opposite direction: 9.4 TWh curtailed in PDVP, another 1.2 TWh reduced in balancing.

The I90 settlement data makes this visible because it records every program for every generating unit, every 15 minutes. The day-ahead headline — “renewables generated X% of electricity” — is only the first chapter.

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For a deep dive into how a single plant navigates every program, see How a Combined Cycle Plant Navigates Spain’s Electricity Markets. For company-level strategies, see Who Generates What in Spain?.

All data queried via the datons Python library. Run the same queries for any technology, unit, or program.