Programs and markets are often treated as fundamentally different approaches to procuring flexibility, but in practice they are doing the same job. Both are ways of procuring capacity or demand reduction to meet a system need. The distinction between them is more about cadence: how often utilities need to procure flexibility and how dynamically they need DERs to respond as systems scale.
How scale changes the way flexibility is procured
Markets and programs both define participation rules, signal when and where flexibility is needed, and compensate resources for delivering capacity to the grid.
Programs are an effective way to procure flexibility particularly where predictability and long-term commitments are required. For DER owners with defined cost structures – such as industrial loads, commercial fleets, or storage assets – pre-agreed contracts provide stability and clear expectations.
For operators, this approach delivers dependable actions in locations where reliability margins are tight, supporting confident planning ahead of time.
Each activation – including when assets do not respond – adds to an operational evidence base. This reveals how different resources behave under real conditions.
Responding to more dynamic system needs
As systems scale, however, flexibility increasingly needs to be resolved across more locations, timeframes, and operating conditions. Long-term arrangements provide assurance and support planning, but on their own can be slower to adapt as system conditions shift.
Flexibility markets provide a more efficient way to do this. They use dynamic, location-based signals to reveal how DERs respond under live conditions.
Over time, this creates a feedback loop which builds confidence in which resources will deliver, where, and when. That confidence allows operators to refine assumptions closer to real time. That leads to reserving, releasing, or dispatching flexibility with less reliance on long-term estimates.
More frequent interaction also broadens participation. Some resources, such as electric vehicles, cannot commit months in advance but can respond when opportunities arise closer to delivery. As more DERs participate in ways that suit different system needs, the volume and quality of operational data grows. That data strengthens both long-term arrangements and near-term decision-making.
What repeated activation enables
The result is greater total flexible capacity and a system that becomes more predictable, responsive, and efficient over time.
Early flexibility markets in the UK ran only a few times a year. Now, more utilities are shifting to day-ahead markets, to meet system needs with greater precision. Some utilities are even using flex day-ahead markets to secure DER support for unplanned utility maintenance activities. This ensures that impacted electricity customers still receive reliable electric service during these maintenance events.
Over time, planning can then use this blended insight of long-term stability from programs and dynamic evidence from markets to adjust reinforcement and customer incentive decisions, and target engagement more effectively. Utilities can also gain better insight into which types of DER are best suited to different grid needs, supporting more informed portfolio planning.
Supporting tools such as VPPs and DERMS help deliver, coordinate, and verify procurement and activation of DERs in practice. This ensures that flexibility secured through either approach can be relied on when needed. When all of these elements work together, they generate more operational data, which in turn strengthens both programs and markets.
This is why the grid needs both. Running the same flexibility process at different cadences allows systems to scale without losing confidence. DERs can then become dependable resources that support both operational resilience and long-term affordability.
