French distribution networks face two simultaneous pressures: a rising number of renewable generation connections and a structural increase in peak demand. Both create constraints on infrastructure and therefore reinforcement needs. At the same time, the growth of decentralised flexibility and falling costs for certain technologies offer an alternative to those reinforcements.
Our study quantifies that alternative at national scale, examines the mechanisms available to mobilise it, and identifies the friction points with existing national mechanisms.
National net value of €11 to 18 million a year
Flexibility creates value for a distribution system operator in two ways: deferring or avoiding a reinforcement in planning, and reducing the number or duration of outages in operations.
At national scale, annual gross value sits between €20 and 60 million. Once flexibility costs are deducted, net value falls to a range of €11 to 18 million a year. That is a useful order of magnitude: local flexibility is a real tool, but not a large pool.
Four configurations out of five keep a positive net value
- Injection constraints at primary substations: €1 to 3 million a year of net value, 15 to 30 cases annually.
- Injection constraints on the medium-voltage network: up to around €5 million a year, on a similarly limited number of cases.
- Withdrawal constraints at primary substations: €1.5 to 4 million a year, with high uncertainty since the result depends on the joint location of constraints and flexibility.
- Outages during works or incidents: €4 to 6 million a year, but spread across several thousand cases, so unit value is low.
The fifth configuration, constraints at MV/LV substations, is set aside. Its net value is close to zero: reinforcement of that equipment costs a few thousand euros, leaving too little headroom for flexibility to be the cheaper option.
Injection constraints are the most promising field. Supply is present by construction, since it is what creates the constraint, and implementation amounts to compensated curtailment without changing any end use.
Four mechanisms retained out of nine
Of nine mechanisms examined, four cover all the value-bearing configurations.
- Smart connection solutions, which use an existing contractual vehicle and act on the source of the constraint itself.
- An alternative cost share within regional renewable connection schemes, complementary to the above, letting future flexibility address injection constraints at primary substations.
- Direct contracting by the network operator, which opens competition to all flexibility but remains heavy, so should be reserved for high unit value cases where the depth of supply is sufficient.
- The DSO option, an opportunistic call on existing flexibility with no commitment on either side, suited to operational use.
Five mechanisms are rejected. A mobile-peak network tariff would create a national signal for a few dozen useful cases a year. A regulated purchase tariff and a day-ahead or intraday local market offer insufficient visibility. Direct investment by the operator in its own flexibility assets runs into statutory constraints preventing it from amortising the asset across other mechanisms.
The real difficulty is articulation with national mechanisms
Flexibility participating in both a local and a national mechanism raises three unresolved questions: managing a localised subset within an aggregated portfolio designed for national products, the collateral effects of activation at one scale on the other, and activation conflicts.
Windfall risks compound this, notably double payment for flexibility meeting a single need, or payment for flexibility that does not exist. Effectiveness will be decided by those coordination rules rather than by gross value.
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