"Demand response is only for big industrial plants." Not since FERC Order 745.
Demand response started in the 1980s as an industrial product. A steel mill or a chemical plant would sign an interruptible tariff: in exchange for a discount on its base rate, the utility could cut its load with 15 minutes notice during peak. That model is still alive, but it is no longer the main story.
Since FERC Order 745 in 2011, residential demand response is paid the same wholesale price as a power plant for every kWh it shifts. That single regulatory change made it economic for utilities and third-party aggregators to enrol households at scale via smart thermostats, EV chargers, controllable water heaters and now home batteries. PJM had about 14,000 MW of demand response in its capacity market at the 2016/2017 peak, much of it residential and small-commercial; the program runs about 9,500 MW today after Capacity Performance tightening.
FERC Order 2222 (2020) goes a step further: aggregators can now bundle individual home devices and bid them directly into wholesale energy, capacity and ancillary markets. Implementation rolls out by ISO between November 2026 (ISO-NE) and 2030 (SPP). For households this is the moment when "the wholesale market is paying me" stops being a Texas oddity and starts working in most of the US.
The rest of this guide explains what residential DR programs already exist, what they pay, and what changes when Order 2222 reaches your ISO.
How three different DR products pay you to use less.
Residential DR in 2026 splits into three product families. Each one pays differently and asks different things of you. They can usually be stacked.
Direct load control
You let the utility (via a smart thermostat or a switch on your A/C compressor) raise your set point a few degrees or cycle your A/C on declared event days. You get a one-time enrolment incentive ($25 to $150) plus an annual or per-event credit. Examples: SCE Summer Discount Plan, BGE Peak Rewards, Duke Power Manager.
Peak Time Savings / Rebates
On a declared event day (5 to 20 per year), you earn typically $1 to $3 per kWh for every kWh below a baseline you reduce. No equipment installed; you decide what to turn off when the alert arrives. Examples: ComEd Peak Time Savings, ConEd Smart Usage Rewards, PG&E SmartRate.
Time-of-Use + free nights
Not strictly DR but the same incentive: prices vary by hour, often free or near-free overnight. Texas REPs lead this category; CA and NY default residential customers to TOU rates. Pairs powerfully with EV charging, smart appliances and battery storage.
The detail that surprises most readers. Stacking is allowed in most utility territories. A household in IL ComEd can enrol in Peak Time Savings AND a smart-thermostat program AND a hourly-priced supply plan. Each contributes a different revenue stream. Combined, an active household can earn $200 to $500 per year in DR-related payments without changing its underlying usage materially.
Residential DR programs and what they pay in 2026.
Selected high-volume utility and REP programs across the US, with typical annual household credit and the Order 2222 aggregator opportunity. Sources: utility program pages and ISO filings, verified May 2026.
| State | Program (utility / REP) | Typical $/yr credit | Order 2222 aggregator path |
|---|---|---|---|
| California | PG&E SmartRate, SCE Summer Discount, SDG&E Reduce Your Use | $80 to $250 | CAISO DR Auction Mechanism (since 2017) |
| Illinois | ComEd Peak Time Savings; Ameren Peak Time Rewards | $50 to $150 | PJM (Feb 2028) / MISO (Jun 2029) |
| New York | ConEd Smart Usage Rewards; National Grid PowerPerks; Central Hudson AppleSavings | $50 to $200 | NYISO DER Participation Model (since 2020) |
| Texas | REP free-nights and free-weekend plans; ERCOT EILS for commercial | 20 to 35% bill cut with EV | ERCOT state-jurisdictional; aggregator pilots |
| Maryland | BGE Peak Rewards; Pepco Energy Wise Rewards; Delmarva ESL | $50 to $150 | PJM (Feb 2028) |
| Massachusetts | Mass Save ConnectedSolutions (battery DR); Eversource peak shaving | $200 to $1,500 (battery) | ISO-NE (1 Nov 2026) |
| Ohio / Pennsylvania | Duke Power Manager, AEP gridSMART, PPL E-Power | $40 to $100 | PJM (Feb 2028) |
| Vermont | Green Mountain Power Bring Your Own Device, Tesla Powerwall DR | $850 over 10 yr per Powerwall | ISO-NE (1 Nov 2026) |
! Vertically-integrated utility territories
In the regulated Southeast, much of the Mountain West and the Pacific Northwest, residential DR is whatever the local utility offers and the state PUC approves. There is no organised wholesale market to bid into and no Order 2222 pathway. Programs typically exist (Duke Power Manager in NC/SC, Georgia Power Smart Usage, Southern California Edison residential DR) but per-household payouts tend to be smaller and aggregator competition is limited.
Why DR earns the same price as a power plant.
The economics that make residential DR work today depend on a single 2011 FERC ruling and the four mechanics that flow from it.
A Full LMP, not LMP minus retail
FERC Order 745 sets the dispatch payment to a DR resource at the full Locational Marginal Price, not net of the retail rate the customer would have paid. This is the rule the Supreme Court upheld in 2016 (EPSA v. FERC). Without it, residential DR aggregation was not economic.
B Capacity market double dip
In PJM, MISO, NYISO and ISO-NE, DR can also earn capacity-market revenue (a forward commitment to be available three years out). Stacking energy + capacity is what makes commercial aggregator DR programs viable.
C Baseline arithmetic
Compensation is paid against a baseline: typically your average usage in the 5 to 10 same-hour-of-day non-event days preceding the event. A household that already has low peak-hour usage has less baseline to reduce against, so the absolute payment is smaller.
D Aggregator economics
A third-party aggregator enrols thousands of households, smooths the per-event response across the portfolio, bids into the ISO, collects the wholesale payment, and shares with customers via enrolment incentives + per-event credits. The aggregator typically keeps 30 to 60% of the wholesale payment.
The takeaway: the residential payment you see (the $50 to $200 summer credit) is a fraction of the wholesale revenue your reduction earns. Aggregator margin, baseline conservatism and overhead consume most of the rest. Programs run by the utility directly tend to share more of the wholesale revenue but enrol fewer customers.
When DER aggregation comes to your ISO.
Order 2222 implementation is the single biggest expansion of residential energy-market participation since Order 745. The rollout is staggered by ISO.
ISO-NE live
First US ISO to fully implement Order 2222 DER aggregation. Effective for the ME, NH, VT, MA, RI, CT footprint. Aggregators can bundle home batteries, EV chargers and smart thermostats.
PJM live
PJM covers IL ComEd, OH, PA, NJ, MD, DC, VA, DE, WV, e-KY, NC, IN, MI. The largest US footprint and the highest 2026 to 2027 capacity prices, which means the biggest aggregator opportunity.
MISO live
15 states from ND/MN to LA, including Ameren in IL. Seasonal Planning Resource Auction structure adapts to DER aggregation.
SPP live
14 central states. CAISO and NYISO already had functionally equivalent DER programs in place since 2017 and 2020.
Three things the Order 2222 rollout actually changes
- A Aggregator competition opens up. Before Order 2222, residential DR was mostly run through the utility's own program. After implementation, third-party aggregators (Voltus, Enel X, AutoGrid, GoodLeap, Sunrun) can compete to enrol your devices. Expect program quality and per-household payouts to converge upward.
- B Home batteries become wholesale assets. A 13 kWh Tesla Powerwall or Enphase IQ battery can earn energy, capacity and ancillary revenue under Order 2222 aggregation. VT's GMP Powerwall program already shows the model works ($850 over 10 years per Powerwall in 2026 dollars); expect similar programs across ISO-NE, PJM and MISO post-rollout.
- C EV charging becomes the largest residential DR resource. A typical EV draws 7 to 11 kW while charging. Aggregating 100,000 EVs gives 700 to 1,100 MW of dispatchable load that can be paused or shifted with no inconvenience to the driver. Major automakers (Ford, GM, Tesla) and charging networks are building the necessary integrations now.
The wholesale market pays $1,000/MWh. Why do I only see $50/year?
Four structural reasons explain the gap between the headline wholesale price and the actual household payout. Understanding them helps you choose the right program and the right aggregator.
Events are rare
A typical residential DR program dispatches 5 to 20 events per year, each lasting 2 to 4 hours. Even at $1,000/MWh the total energy reduction per household is small (maybe 5 to 15 kWh per event, 50 to 150 kWh per year). The wholesale revenue per household is $50 to $200, before aggregator margin.
Baseline conservatism eats the payout
The ISO measures your reduction against a baseline that is intentionally conservative (typically the 5 highest of the last 10 same-hour-of-day non-event days). On a hot day when you would have used more anyway, your apparent reduction is overstated; on a mild day, understated. Net of statistical effects, the measured reduction is typically 60 to 80% of the actual reduction.
Aggregator margin and program overhead
A third-party aggregator takes typically 30 to 60% of the wholesale payment to cover enrolment marketing, baseline analytics, dispatch software, ISO settlement and profit. Utility-run programs share more of the wholesale revenue but enrol fewer customers and offer less granular dispatch.
Capacity revenue is the bigger pie
In PJM, MISO, NYISO and ISO-NE, the capacity-market revenue (forward payment for being available) is typically 2 to 5 times the energy-market revenue for a DR resource. Programs that stack both pay materially more than programs that only do dispatch. The $850/Powerwall/10-year payout in VT is partly capacity, partly energy + ancillary.
The honest summary: residential DR is real money but not transformative money for any single household. The transformative story is in aggregate: 10 million enrolled smart thermostats + 5 million home batteries + 50 million EVs in 2030 is a wholesale-scale resource that meaningfully tightens the supply-demand balance and could shave several billion dollars off the next PJM capacity auction.
Six things to do to actually get paid by the wholesale market.
Enrol in your utility's Peak Time program
ComEd Peak Time Savings (IL), ConEd Smart Usage Rewards (NY), BGE Peak Rewards (MD), PG&E SmartRate (CA). Typically free to enrol, no commitment, $50 to $200/yr in event credits.
Add a smart-thermostat direct-load-control program
SCE Summer Discount Plan, Duke Power Manager, BGE Smart Energy Rewards. One-time $25 to $150 enrolment incentive plus annual credit. Stackable with Peak Time programs.
If you have an EV, shop a Texas-style free-nights plan
In TX, OH, PA and other deregulated states, REPs and competitive suppliers offer time-of-use plans with free or near-free overnight rates. Power to Choose lists every TX option. EV households save 20 to 35% on bills.
If you have a home battery, look at BYOD programs
Mass Save ConnectedSolutions (MA), Green Mountain Power Bring Your Own Device (VT), ConEd Battery Storage Reward (NY). Per-Powerwall pay-outs of $200 to $1,500/yr depending on program design.
Track your ISO's Order 2222 rollout
ISO-NE 1 Nov 2026, PJM 1 Feb 2028, MISO 1 Jun 2029, SPP Q2 2030. Aggregator programs in your ISO will multiply after the date. Watch press releases from Voltus, Enel X, AutoGrid, GoodLeap, Sunrun and Tesla.
In regulated states, push your PUC
If you live in NC, SC, GA, AL, FL, ID, UT, WA or OR, there is no ISO and no Order 2222 path. Your utility's program is whatever the state PUC approved. State consumer-advocate offices (NC Public Staff, GA Utility Consumer Office, OUCC in OH/IN) take comments in rate cases.
Common questions about US demand response.
Demand response is when an electric customer (industrial, commercial or residential) agrees to reduce or shift electricity use at specific peak times in exchange for a payment or bill credit. The grid operator and the utility benefit because they avoid firing up the most expensive peaker plants and they reduce the risk of an outage during peak hours. You benefit because you get paid for being flexible.
Three common forms. (1) Smart-thermostat programs: your utility cycles your A/C up by a few degrees on hot afternoons, you earn a one-time enrolment incentive ($25 to $150) and a per-event credit. (2) Peak Time Savings / Rebates: on declared event days, you get paid (typically $1 to $3 per kWh) for every kWh below a baseline you reduce. (3) Time-of-Use rates: not strictly DR, but the price varies by hour, so the same incentive applies. Most US residential DR programs are aggregated and bid into a wholesale market by the utility or a third-party aggregator, paid for under FERC Order 745.
The strongest residential DR programs in 2026: California (CPUC-mandated PG&E SmartRate, SCE Summer Discount Plan, SDG&E Reduce Your Use), Illinois (ComEd Peak Time Savings, Ameren Peak Time Rewards), New York (ConEd Smart Usage Rewards, National Grid PowerPerks, Central Hudson AppleSavings), Texas (REP free-nights and weekend plans, ERCOT EILS for commercial), Maryland (BGE Peak Rewards, Pepco Energy Wise Rewards). Typical household saving: $50 to $200 per summer in California, $50 to $150 in PJM states, up to several hundred in time-of-use plans paired with EV charging.
FERC Order 745 (March 2011, upheld by the Supreme Court in EPSA v. FERC in 2016) requires US wholesale energy markets to compensate demand response at the full LMP when DR is dispatched, just like generation. Before Order 745, ISOs paid DR at "LMP minus the retail rate" (the customer was assumed to have already saved their retail cost by not using power). The new rule sharply increased the value of dispatchable DR and made it economic for aggregators to enrol residential customers at scale.
PJM had about 9,500 MW of registered DR capacity for the 2024/2025 delivery year, down from a 2016/2017 peak of about 14,000 MW. The reduction reflects Capacity Performance reforms post-2014 polar vortex that tightened the dispatch requirements (DR must perform during the most stringent emergency conditions, not just during forecast peaks). Source: PJM Demand Response Program. Residential DR through smart thermostats and Peak Time Savings makes up a small but growing slice.
Order 2222 (September 2020) requires every ISO and RTO to let aggregators bundle small DERs (residential batteries, smart thermostats, EV chargers, controllable water heaters) and bid them into wholesale energy, capacity and ancillary-service markets. Before Order 2222, DR could only participate through utility-run programs. Implementation rolls out by ISO: ISO-NE on 1 November 2026, PJM on 1 February 2028, MISO on 1 June 2029, SPP in Q2 2030. CAISO and NYISO already had functionally equivalent DER programs in place. Source: FERC Order 2222 fact sheet.
Texas Retail Electric Providers offer plans with structured time-of-use pricing: $0/kWh between 8 PM and 6 AM (or similar window), and a higher-than-average rate during the day. The plans only make sense if you can shift major loads (EV charging, dishwasher, laundry, HVAC pre-cooling) into the free window. For households with an EV that charges overnight, free-nights plans can produce 20 to 35% bill savings versus a flat-rate plan. They are listed on PUCT Power to Choose; always read the daytime rate and the kWh threshold rules.
Today, mostly no. Residential customers participate in DR through a utility program or a third-party aggregator who is registered with the ISO. The aggregator collects the wholesale payment and shares it with the customer through enrolment incentives and event credits. After FERC Order 2222 implementation (starting ISO-NE 1 Nov 2026), more aggregators will be able to access the wholesale market directly, which should grow residential DR participation and the per-household payout. Watch the rollout schedule in your ISO.
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