Consumers become market players.
For most of electricity's history, the demand side of the market was passive. Utilities generated power. Customers consumed it. The only feedback loop was the monthly bill, which provided essentially no real-time price signal.
Demand response changed this by paying customers to reduce their electricity consumption during periods of high demand or high prices. If the grid is stressed and power is expensive, it's cheaper to pay a factory to shut down its production line for three hours than to build a peaker plant that runs 50 hours a year. Demand response treats electricity conservation as a supply-side resource — and prices it accordingly.
RTOs have developed sophisticated markets for demand response. Large industrial and commercial customers can bid their curtailment capacity into both day-ahead and real-time energy markets. A paper mill that can reduce consumption by 50 MW on 30 minutes' notice can bid that capability as if it were a generator — earning capacity payments for the commitment and energy payments when called.
The economics can be compelling. A large industrial customer might pay $60/MWh for power. If it gets paid $100/MWh to curtail during peak hours — effectively selling back power it would have consumed — it earns a $40 spread while still meeting its production goals by rescheduling or simply tolerating the interruption.
FERC Order 745 (2011) required RTOs to pay demand response at the full LMP — the same price as generator dispatch. This ruling, upheld by the Supreme Court in FERC v. Electric Power Supply Association (2016), established demand response as a full participant in wholesale electricity markets.
The demand response concept has evolved into the broader category of Distributed Energy Resources (DERs): solar panels, battery storage, electric vehicles, smart thermostats, and other equipment on the customer side of the meter that can provide services to the grid.
A cluster of 10,000 smart thermostats that can collectively reduce demand by 50 MW for an hour is functionally equivalent to a 50 MW demand response resource — but distributed across thousands of sites, with far greater flexibility and reliability. Virtual Power Plants aggregate these distributed resources, managing them as a portfolio to provide grid services.
The grid of the 2020s is increasingly bidirectional: electrons flow from the utility to the customer and back. Price signals flow in both directions. The distinction between "generator" and "customer" is becoming meaningfully blurred.
PJM, January 7, 2014 — the Polar Vortex. When a breakdown in the Arctic oscillation sent temperatures plunging across the eastern United States, PJM's real-time electricity demand reached its highest level in history. Natural gas pipelines froze, coal piles hardened, and generators that had reported themselves as available failed to produce. PJM issued emergency alerts and called on every available resource — including tens of thousands of enrolled demand response customers who had agreed, in exchange for capacity payments, to curtail their electricity use on short notice. Industrial facilities, commercial buildings, and large consumers reduced load when called. PJM later estimated that demand response resources delivered roughly 6,000 megawatts of relief during the emergency — the equivalent of six large power plants. The Polar Vortex became the operational proof case for demand response as a genuine reliability resource, reinforcing FERC's Order 745 requirement that ISOs compensate demand response at the full locational marginal price.
FERC — Order 745: Demand Response Compensation in Organized Wholesale Energy Markets PJM — Polar Vortex Review, June 2014