Demand response was widely seen as a competitive solution for managing the grid. Its integration into the electricity market and settlement, however, remained a complex issue. Our study, based on 27 industry interviews and a review of the four most mature markets, France, the UK, California and PJM, together some 40 % of the global market, identified five parameters that set the pace and quality of that integration.
1. Valuation markets
Demand response had historically been valued on balancing markets or internally by utilities. That was changing fast, with regulators pushing for deeper integration into wholesale markets. In the US, FERC Order 745 made full-price payment commonplace. The wave of capacity mechanisms in Europe natively included demand response. At PJM, the creation of such a market in 2007 grew demand response from 2 GW to around 15 GW in five years, 10 % of total capacity, with that market concentrating 90 % of demand response revenue.
A further source of value was emerging: demand response as a flexibility asset for distribution networks. British DSO ENWL had launched a local tender to defer targeted investment, valuing curtailment at up to €74/kW in the first year.
2. Technical specifications
Constraints on demand response initially mirrored generation requirements on balancing markets: short response times, but few activations, around 50 hours a year in the UK. Opening larger markets changed the game. In 2011 PJM created capacity products with unlimited calls and durations extended to 10 hours. Loosening constraints sharply increases the potential of demand response, but transfers activation volume risk from the system operator to the provider.
3. Supplier back-payment
During a curtailment event the supplier generates as though nothing had happened but is not paid, since the energy was sold on the demand response market. Three answers coexisted.
- Imbalance-based back-payment: the supplier is paid the imbalance price but loses the retail price. Unsatisfactory, but requires almost no implementation effort. This was the UK position on STOR.
- Net Benefit Test: FERC Order 745 paid demand response the full spot price, with costs allocated pro rata across suppliers, but only where the operation benefits end customers.
- Structured back-payment: demand response is paid the spot price minus the retail price, the financial value of an unexercised call option. Neutral for the supplier and the wholesale market, but mechanically complex. This was the route chosen in France.
The difference is conceptual: the FERC scheme treats demand response as generating capacity, the other as an unexercised option.
4. Measurement and settlement
Unlike generation, demand response cannot be measured directly. Two structuring choices: metering, with either a dedicated fine-resolution meter per site or a statistical approach, the latter enabling fast residential growth but opening the door to free-riding; and baseline calculation, which should in theory be specific to each use. PJM offered six methods for capacity and eight for energy, subject to an error below 20 %, where the UK allowed only one.
5. Subsidy schemes
France was introducing a premium covering all sources of demand response, industrial and residential, technology neutral, averaging around €15/MWh and reaching €30/MWh, funded through the CSPE levy on electricity consumers.
These five parameters hold together. Integration that is too rigid caps market growth. Requirements that are too loose disturb the market, the settlement process and system security, for a limited-value, high-cost service.
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