Case Study 03 · Residential · Virtual Power Plants
Getting paid to share your home battery: what virtual power plants really pay
A virtual power plant (VPP) is a group of home batteries, EV chargers, thermostats, and other devices that a utility or company can call on together when the grid is strained, much like a power plant. Battery owners in more than half of U.S. states can now join one and be paid for it (Clean Energy States Alliance). This case study runs one typical home battery through 17 programs, from Massachusetts to Hawaii, to answer the question most battery shoppers are asked by installers: how much will the grid pay me? We also look at the programs and market changes arriving over the next few years. Battery Economics has no affiliation with, sponsorship from, or endorsement by any utility, aggregator, installer, or battery manufacturer named here.
The short answer
Where you live matters more than which battery you buy. The same battery earns about $1,800 over 10 years in New York and about $11,205 in Connecticut, a sixfold spread for identical hardware.
No program pays for the battery on its own. The best, Connecticut, returns about 72% of a $15,647 battery in 10 years. The typical program returns about a quarter.
VPP pay and time-of-use savings add up. In Southern California, the two together recover about 68% of the cost. That’s better, but in our examples it still falls short of payback in 10 years.
The rules are shifting fast. Programs are moving from one-time rebates to pay-for-performance, several ended or face funding cliffs this year, and New York, New Jersey, Illinois, Maryland, and the big wholesale markets are opening new ways to get paid through 2030.
17
Residential battery programs modeled, in 14 states
$1.8k–$11k
10-year VPP value for the same 13.5 kWh battery
72%
Most any single program recovers of the battery’s cost in 10 years
$10–$300
Pay per kW-year across performance programs
What a VPP asks of your battery
On a hot summer afternoon, demand for electricity peaks and the grid turns to its most expensive power plants. A VPP gives the utility another option: it sends a signal to thousands of enrolled home batteries, which discharge together for two to four hours. To the grid, that looks like a power plant switching on. You’re paid for your share.
Most programs follow the same pattern. You enroll through your utility or battery maker’s app, choose how much of the battery to share, and agree to a season of events, usually summer afternoons and evenings. Many programs, such as Portland General Electric’s, let you keep a reserve for outages and won’t dispatch the battery before severe weather (PGE). Xcel’s Colorado program has a storm mode that overrides events (Xcel Energy).
What varies is how you’re paid. Broadly, there are four models.
Four ways a VPP pays you
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Many programs mix models. Connecticut pays a small enrollment incentive plus per-kW performance; Illinois pairs an upfront rebate with a per-kW dispatch payment. Program lists from CESA.
One battery, 17 programs
To compare them fairly, we use one reference battery: 13.5 kWh, installed for $15,647, the 2026 national average (EnergySage). The 30% federal tax credit that used to cut that price ended for batteries bought after 2025 (IRS). During a typical 3-hour event, the battery shares 80% of its stored energy, about 3.6 kW on average, and keeps the rest for backup. We add up what each program would pay over 10 years, or over its term if it’s shorter.
Ten-year VPP value for one 13.5 kWh battery, by program
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Reference battery: 13.5 kWh usable, 11.5 kW continuous output (Tesla Powerwall 3 class, Tesla), $15,647 installed, the 2026 national average (EnergySage). During a 3-hour event it shares 80% of its energy and keeps 20% in reserve, which averages 3.6 kW.
Duke’s monthly credit is the published maximum. Hawaiian Electric’s export credit is its own example for a 15 kWh battery and partly reflects energy you would otherwise use at home. DSGS pays aggregators, which keep a share. Totals are undiscounted, and rates are assumed to hold for the full period unless a shorter term is published.
Three programs stand apart. Connecticut’s Energy Storage Solutions pays $300 per kW each year for 10 years, and more for low-income and underserved households: $450 and $550 (Energy Storage CT). Duke Energy’s PowerPair in North Carolina combines a rebate of up to $5,400 on the battery with monthly credits for 8 years, but it requires new solar and its battery control program ends in December 2026 (PowerPair). Massachusetts’ ConnectedSolutions pays $275 per kW for summer performance with the rate locked for five summers; National Grid says participants average about $1,200 a year (National Grid), more than our reference battery earns because many homes enroll larger systems.
Most programs fall in a tight middle band: about $3,000 to $4,500 over 10 years, or a fifth to a quarter of the battery’s cost. That includes all three Arizona utilities, Utah, Colorado, Vermont, Oregon, Illinois, and New Orleans. New York’s new Bring Your Own Battery programs pay the least per kW, $50, which NYSERDA estimates at about $180 a year for a 13.5 kWh battery (NYSERDA).
The price per kilowatt is the number to compare
For programs that pay for performance, the key figure is dollars per kW per year. Multiply it by the average power your battery delivers during events to estimate your annual check. The range is enormous, from $10 in Illinois to $300 or more in Connecticut.
What each program pays per kilowatt, per year
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Rates for programs that pay on average kW delivered during events. California DSGS is the 3-hour price, before and after the 2026 bonus (CEC). ComEd’s $10 is per kW per season (Energy Choice Matters). Event rules from each program’s page and NYSERDA.
More pay usually means more work for the battery. Massachusetts can call up to 60 events a summer (National Grid), and Connecticut plans about 50 summer and 5 winter events (Energy Storage CT). New York utilities typically call 10 to 20 (NYSERDA). Each event uses a cycle of the battery’s warranted life and leaves less stored energy if an outage follows. Payments are typically based on your average performance, and in Arizona, skipping an event counts as zero kW for that event (APS). Opting out often costs more than it seems.
Illinois is a special case. Its per-kW pay is low, but the state’s new storage rebate of $300 per kWh ($4,050 for our battery) requires enrollment in the utility’s VPP (ComEd). Illinois buys most of the battery’s grid value upfront.
Stacking VPP pay with time-of-use savings
A battery can earn from a VPP and from the utility bill at the same time. In Case Study 01, the same battery saved between $2,000 and $8,000 over 10 years by charging cheaply and covering the house during high-price hours. Because most VPP events fall during those same hours, much of the two income streams can be combined.
Time-of-use savings plus VPP pay, over ten years
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TOU savings come from Case Study 01, same battery and house. We simply add them, assuming VPP events fall inside the peak hours the battery already discharges in. A program that pays only for exports beyond home use, or events on days the battery would otherwise sit idle, would change the total somewhat.
California assumes DSGS is refunded through 2035; without new funding it ends after October 2026 (CALSSA).
Stacking helps, and in Arizona and Colorado the VPP is worth more than the rate plan. But none of our four combined cases pays back the battery within 10 years. The best, a Southern California Edison customer on TOU-D-PRIME enrolled in the state’s Demand Side Grid Support (DSGS) program, recovers about 68%, and DSGS itself may not survive past this year. Backup power during outages, which we don’t put a price on, is what closes the rest of the gap for most buyers.
Not every pair works. Some programs require the battery to be charged only from solar (Xcel Energy), and Hawaiian Electric’s program requires a daily 2-hour export window (Hawaiian Electric). Each program sets its own rules for combining.
Programs we couldn’t price
Some of the largest VPPs don’t publish a rate for homeowners. Tesla Electric in Texas pays a monthly VPP credit and dispatches batteries during real-time price spikes in the state’s grid market, but it doesn’t publish a per-kW figure (Tesla). Puerto Rico’s Customer Battery Energy Sharing program, now permanent through 2028, pays through aggregators with terms that vary (LUMA). Sunrun’s CalReady VPP in California enrolls more than 56,000 customers (CESA), and Sunrun is also exporting from more than 1,000 homes in PG&E territory (Solar Power World). In these models, the company negotiates with the grid and passes along a share. You can’t see the rate card, so compare the total offer, not a per-kW price.
Six trends shaping VPP pay
1. From rebates to pay-for-performance
Connecticut’s April 2026 overhaul replaced most of its upfront incentive with higher yearly performance pay and ended passive dispatch for new customers (Energy Storage CT). Utilities want to pay for what shows up, not what’s promised.
2. Rebates tied to enrollment
Illinois’ storage rebate requires VPP participation (ComEd), and New York ties its storage incentive to its utility programs (Hoodline). Buying the battery increasingly means signing up the battery.
3. Paying more where the grid is tight
New Jersey’s proposed 150 MW program targets local congestion (Utility Dive), Green Mountain Power adds $100/kW in constrained areas (GMP), and Connecticut pays more at the grid edge. Location is becoming part of the price.
4. Opening the wholesale markets
Federal Order 2222 lets aggregated home devices sell into regional power markets. California has done it since 2024; New England and New York follow in late 2026, the mid-Atlantic PJM market in 2028 (PNNL). Texas is turning its 500 MW pilot into permanent rules (ERCOT).
5. Funding is fragile
Programs paid from annual budgets can disappear. California’s DSGS ends after October 2026 without new money (CALSSA), and Duke ends battery control credits in December. Tariff-based programs, like New York’s and Illinois’, tend to last longer.
6. Growing fast, from a small base
North American VPP capacity reached 37.5 GW in 2025, up 13.7%, with the residential share of wholesale VPP capacity rising to about 10% (Wood Mackenzie). The Department of Energy wants 80 to 160 GW by 2030 (DOE).
What’s coming in the next few years
The map will look different by 2028. Several new residential programs are scheduled to open, and the regional grid markets will begin accepting aggregations of home devices. The dates below are official targets; in this field, they often slip.
A few deserve attention if you live in these states. New Jersey proposed up to $200 per kW a year for 10 years, for up to 150 MW of home batteries, starting next year and giving way to an open-market VPP tariff in 2029 (Utility Dive). Illinois will open ComEd’s scheduled-dispatch VPP around March 2027 (Exelon), alongside the $300/kWh storage rebate. Maryland approved VPP and vehicle-to-grid pilots under its DRIVE Act, expected for summer 2027, with payment based on verified value (VGI Council). Virginia’s Dominion Energy is ramping up a VPP pilot that includes home batteries (Dominion Energy). In Minnesota, Xcel has proposed up to 200 MW of utility-owned distributed batteries, a reminder that utilities may build their own VPPs rather than pay customers (Xcel Energy).
The wholesale changes matter less for your first check than for the long run. As PJM, New York, and New England open their markets, aggregators will be able to earn from capacity, energy, and reserve markets at once. That should raise what the grid is willing to pay for a well-placed home battery, and it’s the business model behind hosted offers like the ones in Case Study 02.
Not just batteries
This case study focuses on batteries, but most VPPs enroll a wider set of devices. Smart thermostats have been the backbone of residential demand response for years. EV chargers can pause during a peak, and bidirectional chargers can send the car’s energy back to the home or grid. Heat pump water heaters can heat early and coast through a peak, and solar inverters and smart panels can shape exports or shed selected circuits.
Batteries are one member of a larger device family
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Batteries and EVs appear in VPP deployments 61% as often as smart thermostats, the incumbent device, and their share is growing (Wood Mackenzie). PG&E’s vehicle-to-everything (V2X) program offers $2,500 or more toward a bidirectional charger (PG&E).
A home with several of these devices can earn from several programs, and each device changes what the others are worth. A heat pump that pre-cools the house reduces the load the battery has to cover; an EV can be a second, larger battery. We’ll model those combinations with our sister sites, Drive Economics for EVs and Heatpump Economics for heating and cooling, in future case studies tied to specific regions.
Who this fits
A strong fit: households in Connecticut or Massachusetts, where the VPP alone can return well over half the battery’s cost, and in North Carolina if installing solar and a battery together before PowerPair closes.
A useful bonus: buyers who want backup power in Arizona, California, Colorado, Utah, Oregon, Vermont, New Orleans, or ComEd’s Illinois territory. The VPP adds a fifth to a quarter of the battery’s cost, more when combined with a TOU rate.
Not a reason to buy: in New York at $50 per kW, and anywhere the program is proposed or depends on annual funding. Enroll if you already own a battery; don’t count on the check to justify buying one.
Questions to ask before enrolling
How many events a year, how long, and at what hours? How is my payment measured if I skip one?
Can I keep a backup reserve, and will the program stop dispatching before a storm?
Is the rate locked, and for how many years? Is the program funded by a tariff or an annual budget?
Can I combine it with my TOU rate, solar export credits, and state rebates, or does one exclude another?
If I enroll through an installer or aggregator, what share of the payment do I receive?
Do events count against my battery warranty’s cycle or energy limit?
Method. Performance payments = rate × 3.6 kW average event output × years. Upfront payments use each program’s published formula for the reference battery (13.5 kWh, 11.5 kW continuous; 3.6 kW committed where a commitment is required; 5 kW for Hawaiian Electric’s 2-hour window). Portland General Electric: $1.70/kWh × 10.8 kWh × 15 events a year. Values are undiscounted and assume current rates continue for 10 years unless a shorter term is published. They are gross of any aggregator share and exclude battery degradation, taxes, and backup value. Illustrative estimates, not earnings predictions.
Program terms were collected in September 2026 from utility, program administrator, and regulatory sources, cross-checked against the CESA VPP program summary table (updated August 2026). Programs change often; confirm current terms with your utility before buying or enrolling.
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