Iberdrola’s UK network launches £14m flexibility tender

Iberdrola is expanding distribution flexibility procurement in the UK through SP Electricity North West, which has opened a tender worth up to £14m across north-west England.

The tender is seeking 779MW of flexible capacity across 217 locations in Greater Manchester, Lancashire, and Cumbria. Requirements span low, high, and extra-high voltage networks, reflecting the spread of constraints now appearing across distribution systems as load and generation patterns change.

Distribution networks are moving away from a purely passive model in which reinforcement is the default answer to every capacity problem. Batteries, industrial loads, distributed generation, aggregators, EV charging assets, and other controllable resources can be paid to change behaviour at specific times and locations, allowing network operators to manage constraints more actively.

The north-west of England brings several forms of pressure together. EV charging, heat pumps, rooftop solar, industrial electrification, and local energy projects are changing both demand and export profiles. Some areas face evening peak demand constraints, while others may see voltage or reverse-flow issues linked to embedded generation.

Flexibility procurement can reduce or defer reinforcement where the constraint is limited by time, season, or operating condition. A transformer approaching its limit for a few dozen hours a year may not require the same immediate intervention as a feeder facing sustained growth. Paying flexible assets to respond during those constrained windows can give the network operator more choices while permanent upgrades are planned.

The practical test is dispatch reliability. Flexible capacity must be available in the right location, at the right time, and in a form that the network can verify. That requires accurate network models, forecasting, metering, communications, settlement systems, and clear rules for how providers are instructed and assessed.

The move towards common flexibility dispatch standards is therefore closely linked to tenders of this kind. If each network operator uses different processes, platforms, definitions, and data formats, participation becomes harder for providers and aggregators. A more consistent approach allows flexible assets to be developed, aggregated, and dispatched across wider areas without unnecessary duplication.

Hardware upgrades are developing in parallel. Low-voltage transformer retrofit trials are testing how existing assets can be operated more effectively as EV chargers, heat pumps, and solar generation create new load patterns and phase imbalance. Flexibility markets and asset-level technology upgrades are different tools, but both aim to release usable capacity before traditional reinforcement catches up with electrification.

For distribution system operators, the operational model is becoming more granular. The network can no longer be managed only through broad planning assumptions and historical load profiles. Local visibility, digital control, and flexible response are becoming necessary as the edge of the network becomes more active.

Participation will vary by asset type. Larger batteries and industrial demand can provide sizeable, measurable response, while domestic and small commercial assets may need aggregation to become useful at network scale. Aggregated flexibility can provide valuable capacity, but it introduces additional complexity around communications, customer behaviour, availability, and performance verification.

The £14m tender indicates that distribution flexibility is moving further into routine network operation. Reinforcement will still be needed where electrification creates sustained capacity growth, but flexibility can help manage the transition, reduce inefficient overbuilding, and support more targeted investment in cables, transformers, substations, and automation.