Demand Response: How Commercial and Industrial Facilities Get Paid to Reduce Load

There are hours each year when the electricity grid is stretched thin and every megawatt matters. In those hours, a facility willing to dial back its load is worth as much to the grid as a power plant, and grid operators will pay for it. Demand response (DR) is the set of programs that turn that willingness into revenue. For commercial and industrial sites with any operational flexibility, it can become a recurring line of income rather than a cost center, and it does not require generating a single kilowatt of your own.

This guide explains what demand response is, the difference between capacity and economic DR, how the programs actually pay, and the data you need to enrol and get settled correctly. The examples draw on Ontario's IESO market and the US PJM market, but the mechanics carry across most organized grids.

What demand response actually is

The US Department of Energy defines demand response as a short-term, voluntary decrease in electricity consumption by end-use customers, generally triggered by compromised grid reliability or high wholesale prices. In plain terms, the grid operator or utility asks you to reduce load for a defined window, and in exchange you receive a payment, a bill credit, or another form of compensation. A typical program gives about a day of notice, asks the customer to curtail for roughly four to six hours, and calls a limited number of events per year.

Crucially, demand response is not about permanent efficiency. It is about flexibility on specific high-value hours. You are not being asked to use less power all year. You are being asked to move or shed load during the handful of hours when the grid needs it most, and you are paid for standing ready to do so.

Capacity DR versus economic DR

Demand response splits into two broad families, and understanding the difference matters because they pay differently and carry different obligations.

Capacity (reliability) demand response

Capacity DR is a commitment made well in advance. You pledge that a certain amount of load will be available to curtail during an obligation period, and you receive a recurring availability payment for that pledge whether or not you are ever called. In exchange, you must perform when the grid operator dispatches you. Most demand response value in organized markets sits here. In PJM, for example, most demand response participates through the capacity market, known as the Reliability Pricing Model, earning recurring capacity payments plus additional energy payments based on performance during dispatches.

Economic (price-responsive) demand response

Economic DR carries no standing commitment. You curtail when the wholesale energy price rises above your threshold, and you are paid for the energy you reduce at the prevailing market price. There is no penalty for sitting out an event, but there is no availability payment either. Economic DR suits facilities that want to opt in opportunistically rather than lock in an obligation. Many sites run both: a capacity commitment for baseline revenue, plus economic curtailment when prices spike beyond the capacity obligation.

Ontario: the IESO Capacity Auction

Ontario runs demand response primarily through the IESO Capacity Auction, a competitive procurement in the IESO Resource Adequacy Framework that lets demand response, generation, storage, and imports compete to make capacity available. Successful participants receive a payment based on the auction clearing price for making their capacity available during a defined window of hours on each business day, an availability model with a performance obligation.

The value has climbed sharply. In results released in December 2025, the IESO acquired 1,833 MW of supply for summer 2026 and 1,125 MW for winter 2026-2027. Clearing prices hit records: 645.24 dollars per MW-day for summer and 725.31 dollars per MW-day for winter, nearly double the prior year's 332.39 and 139.00 dollars. Those numbers are why demand response has moved from a niche curiosity to a serious budget line for large Ontario facilities.

Individual sites rarely bid alone. The auction operates in whole-megawatt scale, so smaller loads typically aggregate through a registered market participant that combines several facilities into a single offer, handles the bidding, and manages settlement. That aggregation is what brings demand response within reach of mid-sized commercial buildings rather than only heavy industry.

The United States: PJM and the other ISO markets

In the US, each of the seven independent system operators and regional transmission organizations sponsors demand response programs, letting owners of curtailment capability bid into markets for energy, capacity, or grid-support services. PJM, which coordinates the grid across the mid-Atlantic and parts of the Midwest, is the largest of these markets for demand response.

Demand response is a meaningful slice of PJM's capacity. In the 2024/2025 delivery year, cleared demand response totaled roughly 8,064.7 MW of unforced capacity. Rules continue to evolve: beginning with the 2027/2028 delivery year, PJM widened the demand response availability window to 24 hours a day, which raised the capacity value of DR and lifted cleared volumes to 7,299 MW from 5,531 MW in the prior auction. More availability hours means a larger obligation, but also more payment.

How enrolment and payment work

Most facilities do not interface with the grid operator directly. They work through an aggregator, called a curtailment service provider (CSP) in PJM. According to PJM, CSPs aggregate customers' curtailment capability, register it with PJM, offer it into the appropriate market, submit load data to verify reductions, and receive payment from the grid operator. The split of that payment between the CSP and the facility is a private contract. The same intermediary model, under different names, operates in Ontario and other markets.

The typical enrolment path looks like this:

1. Assess flexibility: identify which loads you can curtail, by how much, and for how long without unacceptable disruption.
2. Establish a baseline: the program measures your reduction against a counterfactual of what you would have used, so an accurate baseline is the foundation of every payment.
3. Register through an aggregator or CSP: they combine your capability with others, handle market registration, and submit offers.
4. Commit to an obligation or opt in economically: choose a capacity commitment for recurring availability revenue, or economic participation for event-by-event payments.
5. Perform when dispatched: reduce load on the notice and duration the program specifies.
6. Get settled: the aggregator submits verified load data, and payment flows based on availability, activation, or both.

The data you need to participate

Demand response lives or dies on data quality, because every payment is settled against measured load. If your interval data is incomplete, inconsistent, or unreconciled with your bills, you cannot prove your baseline, you cannot verify your reduction, and you risk leaving revenue on the table or facing performance penalties. The essentials:

The uncomfortable reality is that most organizations discover their data is not ready the moment they try to enrol. Interval exports sit in one system, bills in another, and nobody has reconciled the two. That gap is where demand response revenue quietly leaks away.

How MartinAI helps

Demand response only pays if you can prove what you did, and proof requires clean, validated, whole-building data. MartinAI turns messy utility bills and interval data into a single, consistent record you can take into any DR program. It reads bills and interval feeds, checks them for gaps and inconsistencies, and reconciles measured load against what the utility billed, so your baseline stands up to scrutiny.

With that foundation in place, you can see which loads carry curtailment potential, quantify how many megawatts you can reliably offer, and track performance during events against a defensible baseline. Instead of scrambling to assemble data every time an aggregator asks for it, you keep a validated record ready to support enrolment, settlement, and reporting. That means no manual spreadsheet reconciliation and no disputes over whether the reduction actually happened.

The bottom line

Demand response pays commercial and industrial facilities to do something they can often afford to do anyway: reduce load for a few high-value hours a year. With Ontario capacity clearing prices at record levels and US markets expanding the role of flexible load, the revenue is real and growing. The barrier is rarely the willingness to curtail. It is the data needed to prove capability, establish a baseline, and settle accurately. Get the data right, and demand response turns idle flexibility into a dependable stream of income.