What is Demand Response?

Demand response is a more than 40-year old demand flexibility strategy that involves shifting demand to off-peak periods of usage. Since demand response began, the state of electric demand has evolved. Today, electricity demand in the U.S. is climbing faster than at any point in previous decades, driven by AI data centers, increasingly erratic weather patterns and temperature extremes, and electrification, which are now the dominant drivers of new load.

As such, the grid needs tools that can absorb that growth without a corresponding wave of new power plants. Demand response is the oldest and most proven of those tools: a coordinated way to reduce electricity use during the hours when the grid is under the most strain, and it’s becoming more valuable in maintaining energy security and minimizing operational and peak energy market costs as data centers reshape the load curve.

Read on to learn what demand response is, how it works, why it matters more than ever for today’s data center-driven demand surge, and what current data says about where the practice is headed.

 

In This Article

• What Is Demand Response?
• How Demand Response Works
• A Short History: From Radio Switches to AI Forecasting
• Why Demand Response Matters Now
• Demand Response and the Data Center Boom
• Demand Response by the Numbers
• Challenges Still Facing Demand Response
• FAQs
• Glossary of Demand Response Terms
• What is Demand Response? Conclusion

 

What Is Demand Response?

The Federal Energy Regulatory Commission (FERC) defines demand response as changes in electric usage by demand-side resources from their normal consumption patterns, made in response to changes in the price of electricity or peak demand. Demand response programs incentivize customer participation to help lower electricity use when wholesale prices spike or system reliability is at risk. In simple terms, demand response asks or pays customers to use less power, or to shift when they use it, during the specific hours when the grid needs relief most.

It differs from broader demand flexibility, which is an umbrella term defining any program that reshapes usage including EV managed charging, BYOD programs, and virtual power plants (VPPs), all of which parallel strategies like energy efficiency initiatives and time-of-use rates. Demand response is narrower: it’s event-based, targets peak or emergency periods, and typically compensates participants for their flexibility.

Historically, utilities met peak demand with peaker plants, natural gas units that run only a handful of hours per year. Peaker plants are costly to build, expensive to maintain relative to their limited runtime, and carbon-intensive. Demand response offers a lower-cost, lower-emission alternative by shifting or shedding load instead of adding generation.

 

How Demand Response Works

A demand response program generally follows the same sequence, regardless of utility size or region:

• Enrollment. Customers opt in a smart thermostat, water heater, EV charger, or other connected device, or a utility installs a dedicated control switch.
• Signal. When system operators anticipate a shortage of supply or a price spike, they issue a demand response event, typically communicated through an app, text, or automated device signal.
• Response. Enrolled devices cycle down, delay, or pause operation for the duration of the event, which usually runs one to a few hours. For example, thermostat demand response programs may shift the temperature set point to conserve energy during peak periods of demand.
• Incentive. Participants receive a bill credit, per-event payment, or rate discount in exchange for their participation.
• Measurement and verification. The utility or aggregator measures actual load reduction against a baseline to confirm the event delivered the expected relief.

There are two broad categories of assets, distributed energy resources (DERs) like solar, battery energy storage systems (BESS), electric vehicles, EVSE chargers, or smart home devices like thermostats or water heaters, that participate in these events:

• Utility-held assets, such as utility-owned batteries or solar, coordinated through a grid-facing distributed energy resource management system (DERMS).
• Behind-the-meter assets, including residential and commercial smart devices, coordinated by systems built specifically to manage disparate, customer-owned equipment at scale.

These DER assets are typically managed through a distributed energy resource management system (DERMS); utility-held assets are managed by Grid DERMS, while Grid-Edge DERMS are designed to manage BTM DER assets. Unfortunately, behind-the-meter devices are subject to variables like weather, customer overrides, and connectivity, rendering BTM DER assets as an unreliable resource. Fortunately, tools like Topline Demand Control, which combines Grid-Edge DERMS, AI, forecasting, and model predictive control are available to help utilities transform demand response into a dispatchable resource that is reliable and bankable rather than a rough estimate.

 

A Short History: From Radio Switches to AI Forecasting

Early demand response relied on one-way, then two-way, radio switches physically wired to HVAC units and water heaters. These systems could turn devices off but offered little visibility into whether they’d actually responded, and installation was labor- and capital-intensive. The rise of Wi-Fi-enabled smart thermostats, water heaters, and EV chargers changed that equation, letting utilities signal and confirm events remotely, in near real time, and with far less disruption to the customer.

Today, that evolution continues through forecasting functionality, which provides program operators an opportunity to anticipate device-level performance rather than simply hoping enrolled equipment responds as expected.

 

Why Demand Response Matters Now

U.S. electricity demand is projected to grow substantially through the decade’s end, driven by electrification, extreme weather, and data center buildout. That growth is arriving faster than new generation and transmission can be permitted and built, pushing up both wholesale prices and retail rates.

• Last year, U.S. investor-owned utilities requested about $18 billion in rate increases, the most since the mid-1980s, and regulators approved roughly two-thirds of that requested value, per Lawrence Berkeley National Laboratory data cited by Columbia University’s Center on Global Energy Policy.
• As of 2019, average U.S. electric energy demand has increased by 6%. Until 2025, average U.S. electric prices were approximately in line with the inflation rate; as of 2025 energy costs exceeded the inflation rate to nearly double the rate of inflation.
• Columbia researchers argue large-load flexibility, including data center load shaping, offers a way to manage peak demand without relying on costly, low-utilization generation.

Demand response also factors into decarbonization: reducing peak demand lowers the need for the grid’s least-efficient generation, since peaker plants and other fast-ramping resources are typically dispatched only during the highest-stress hours demand response is designed to blunt.

 

Demand Response & the Data Center Boom

Nowhere is the tension between new load and grid capacity sharper than in data center-heavy markets. Lawrence Berkeley National Laboratory researchers estimate data centers could consume roughly 10% to 15% of all U.S. electricity by 2030, up from about 5% in 2024.

Researchers at Princeton’s ORFEUS group modeled what that growth means for Texas specifically. Using ERCOT’s own load forecasts, they simulated adding 22 gigawatts of data center demand to the state’s 2030 grid and found that, without new supply, average wholesale prices rose 49%, from roughly $21 to $31 per megawatt-hour. When the model let data centers curtail load just 0.5% of annual hours, total costs during those specific peak hours fell by more than half, though the effect on annual average costs stayed modest, since demand response only applied to a small fraction of total hours in the year.

That tension is playing out in real-time grid operations, too. In the PJM Interconnection, the country’s largest wholesale market, demand-response aggregators have argued to FERC that utility rules restricting access to smart meter data have stranded gigawatts of potential demand response capacity; FERC sided with them in a related capacity-market ruling, finding PJM’s existing rules unreasonable given the reliability risk posed by data center-driven load growth. PJM has separately proposed requiring large new loads to secure their own power supply or accept curtailment, and it received emergency federal authorization in summer 2026 to curtail large loads, including data centers, during record heat waves.

 

Demand Response by the Numbers

• Roughly 10.7 million U.S. customers were enrolled in demand response electricity programs in 2024, nearly all of them residential, according to Statista.
• Resideo Grid Services data shows demand response events increased 173% from 2021 to 2024, even as the average enrolled device participated in only about 2% more events, reflecting more targeted, shorter dispatch.
• Average event duration fell from nearly three hours in 2021 to under 2.5 hours in 2024, a sign that better forecasting is letting utilities ask less of participants while still capturing the needed load reduction.
• The U.S. Department of Energy estimates the country needs 80 to 160 gigawatt-hours of virtual power plant capacity by 2030 to meet rising demand; existing capacity, most of it attributable to demand response, sits between 30 and 60 gigawatt-hours today.
• FERC’s annual Assessment of Demand Response and Advanced Metering report, published continuously since 2006, remains the federal government’s primary public benchmark for tracking retail and wholesale demand response potential nationwide.

 

Challenges Still Facing Demand Response

Despite decades of use, demand response participation in wholesale markets has stagnated or declined in some regions in recent years. A 2024 report from the Energy Systems Integration Group identified five structural gaps holding the resource back:

• Limited awareness and expertise. Many regulators, system operators, and customers lack familiarity with how modern demand response programs work.
• Market fragmentation. Inconsistent rules across wholesale and retail markets make it hard to scale participation.
• Onerous metering requirements. Individual load resources are often held to measurement standards designed for large-scale generation.
• Sparse performance data. System operators frequently lack detailed, public information on how demand response performed during actual emergency events, which erodes confidence in the resource.
• Weak financial incentives. Payment structures at the wholesale, utility, and consumer level often fail to reward long-term participation.

Customer-facing research reinforces the point: even as smart thermostat adoption has roughly doubled over the past eight years, only about 1 in 5 of those households participates in a demand response program, and more than half of non-participants say they’ve never heard of one or don’t believe their utility offers it, according to a Parks Associates and Resideo Grid Services study reported by Utility Dive. Comfort concerns, unfamiliarity with the technology, and program churn all remain real barriers, though the same research found that most participants who do enroll report events as barely noticeable once they experience one firsthand.

 

FAQs

Is demand response the same as a virtual power plant? No. A VPP coordinates a broader mix of DER assets including solar, batteries, EVs, and demand response devices to act like a single dispatchable power plant. Demand response is one resource type a VPP can draw on, but it’s narrower and event-based on its own.

Do demand response programs pay participants? Most do, typically through a recurring bill credit, a per-event payment, or a reduced rate.

Which devices are typically enrolled? Smart thermostats, electric water heaters, EV chargers, batteries, solar and more are the most common behind-the-meter devices; utility-scale batteries and solar can also participate as utility-held assets.

When do events happen? During periods of grid stress, most often summer afternoons and evenings or winter cold snaps, when supply is tightest relative to demand.

Can data centers participate? Yes, and interest is accelerating as data center load growth strains capacity in markets like PJM and ERCOT, typically by shifting or shedding compute load during a small number of peak hours per year.

Why has participation stalled in some wholesale markets? Research from the Energy Systems Integration Group points to fragmented market rules, weak financial incentives, limited public performance data, and low awareness among regulators and customers alike.

 

Glossary of Demand Response Terms

• Advanced metering: Meters that record usage at least hourly and report it to the utility at least daily, enabling more precise demand response measurement.
• Aggregator: A third-party company that enrolls and manages customer devices to participate in demand response or capacity markets.
• Baseline: The estimated usage a customer would have had absent a demand response event, used to verify actual load reduction.
• Behind-the-meter (BTM): Resources on the customer side of the utility meter, such as home batteries, thermostats, and EV chargers.
• Curtailment: A reduction in usage during a set period, often used interchangeably with a demand response event for large loads like data centers.
• Demand flexibility: The umbrella term for any program, including demand response, that reshapes when or how much electricity customers use.
• DERMS (distributed energy resource management system): Software that monitors, coordinates, and dispatches distributed energy resources.
• Grid-enhancing technologies (GETs): Hardware and software, such as dynamic line ratings, that increase existing transmission capacity without new construction.
• Load shedding: An involuntary, last-resort cut to electricity delivery, used to prevent a wider grid failure.
• Peaker plant: A power plant, typically gas-fired, built to run only during the highest-demand hours of the year.
• Virtual power plant (VPP): A network of distributed energy resources coordinated through software to act like a single power plant.

 

What is Demand Response? Conclusion

Demand response remains one of the fastest, lowest-cost tools available for managing a grid under mounting pressure from data centers, electrification, and extreme weather. As wholesale market rules evolve and forecasting technology improves, the resource that started with one-way radio switches is positioned to play an even larger role in keeping the grid (and electricity bills) in balance.

This blog was originally published on November 10, 2021 with updates made on August 27, 2026.