375 MW From Suburban Garages: Sunrun’s Virtual Power Plant Now Rivals a Mid-Size Gas Peaker — at 60% Less Cost

Build a 375-megawatt gas peaker plant today and it will cost you roughly $562 million. That is the going rate at $1,500 per kilowatt of capacity, according to the EIA’s 2025 Annual Energy Outlook, and it does not include the fuel, the emissions permits, the transmission interconnect, or the decade of community opposition lawsuits you will fight before pouring concrete.

Sunrun just built that much capacity in suburban garages. Twelve months. No permits, no concrete, no lawsuits.

Its CalReady virtual power plant hit 375 MW of peak dispatch during the 2025 summer season, coordinating 75,000 residential batteries across 56,000 California households into a single grid resource that fires on command during evening demand spikes between 4 and 9 PM. In 2024, CalReady managed 48 MW average and 54 MW peak from 16,000 households. That is a 7.8× peak increase in a single year, a scaling trajectory that has no analogue in conventional generation and that the gas industry’s permitting pipeline cannot begin to match.

The Cost Math Nobody Is Running

Here is the calculation that should keep gas-peaker investors awake. A new 375 MW simple-cycle gas turbine runs about $562 million in overnight capital costs. Add a 30-year levelized fuel cost of $25–40/MWh (EIA LCOE estimates), carbon compliance costs that are rising everywhere RGGI and cap-and-trade programs operate, and a capacity factor that rarely exceeds 10–15% because peakers exist to sit idle most of the year and run flat-out on the hottest afternoons. Every regulatory cycle makes those economics worse.

Sunrun’s alternative is radically different because the company does not build the batteries. Homeowners buy or lease them, which means Sunrun’s marginal cost of adding a megawatt of VPP capacity is essentially the software orchestration layer plus the customer acquisition cost of enrolling an existing battery owner into the CalReady program. The Brattle Group estimates that VPP capacity at peaker-equivalent duty cycles costs 40–60% less than new gas peakers and less than grid-scale battery storage, because the hardware is already deployed and financed by somebody else.

Sixty gigawatts of VPP deployment could save $15–35 billion compared to conventional alternatives through 2033, Brattle calculates, plus another $20 billion in emissions and resilience benefits that gas peakers cannot provide.

Let that sink in. America’s cheapest new power plant is not a power plant at all.

Who Else Is Betting the Grid on Garages

Sunrun is not alone. The pattern is replicating across states and business models with a speed that suggests structural shift rather than regional experiment, and at least three other programs have already crossed the 100 MW threshold or are scaling hard enough to reach it within the year.

Base Power, the Texas startup founded by Zach Dell, has raised $1 billion to deploy what it calls a “gentailer” model: the company owns the 25 or 50 kWh battery packs installed in customer homes, charges a monthly fee for backup power, and aggregates the fleet into a wholesale-market resource. By mid-2025 it was installing 20 MW per month, targeting 100 MW per month by mid-2026. Instead of financing a massive generation asset and hoping demand materializes, Base Power finances individual batteries, acquires a customer relationship, and sells both backup reliability and grid services from the same hardware. Think of it as the Comcast model applied to electricity: own the last mile, sell multiple products through it.

NRG Energy initially targeted a modest 20 MW of residential VPP capacity in 2025. Demand was so strong it bumped the target to 150 MW, with a long-term goal of 1 GW of dispatchable residential capacity by 2035, which would make NRG’s distributed fleet larger than most gas peaker portfolios in ERCOT. Sonnen, Europe’s largest VPP operator, entered Texas with 60 MWh growing to 150 MWh and already operates 6,000 aggregated homes in Utah.

DOE’s 2025 VPP Liftoff report pegs current US virtual power plant capacity at 30–60 GW and targets 80–160 GW by 2030, projecting roughly $10 billion per year in avoided grid costs from peaker deferral and transmission upgrades alone. Wood Mackenzie counted 1,940 VPP deployments in North America in 2025, with monetized programs rising 35% year-over-year to 433 and the top 25 offtakers each exceeding 100 MW.

The Customer Side of the Ledger

Why would a homeowner let a utility drain their backup battery during a heat wave? Money helps, but look closer. CalReady participants earned up to $150 per battery in 2025, with total program payments reaching roughly $10 million across the fleet, up sharply from $1.5 million the year before. That is not life-changing income. But for a $12,000 Tesla Powerwall 3 with a 20-year lifespan, $150 per year represents a 1.25% annual yield on hardware that sits idle 95% of the time, paid for doing something the battery was going to do anyway during a 2-hour evening window.

Now compare that to the alternative facing homeowners without storage. California residential electricity rates averaged $0.3185/kWh in 2024, according to the EIA, the highest in the continental United States and rising at roughly 8% per year over the last decade. A homeowner without a battery simply absorbs the rate hikes. A homeowner with one gets paid to help the grid while offsetting their own peak-rate consumption through Time-of-Use arbitrage. Your battery pays for itself in rate savings; the VPP payment is gravy.

Strongest Counterargument: The Duration Gap

The strongest case against residential VPPs as peaker replacements is physics, and it deserves its full weight. A typical home battery stores 10–13.5 kWh and dispatches fully in 2–4 hours. CalReady’s 2025 dispatch window was just 2 hours per event, with a maximum of 35 events across the May-to-October season.

Gas peakers do not have this constraint. None. During extended heat events, a natural gas turbine can run for 8, 12, or 16 continuous hours, burning fuel as long as the grid operator needs it, refueling from a pipeline that never empties, producing megawatt-hours on a timescale that no battery chemistry currently deployed in residential settings can match. In August 2020, California’s multi-day heat dome triggered rolling blackouts precisely because short-duration resources were exhausted while demand remained elevated overnight. A fleet of residential batteries, no matter how many garages they sit in across the state, would have hit the same wall at hour three. California needed sustained megawatt-hours across multiple consecutive days. Distributed 2-hour bursts, however large in instantaneous power, do not solve that problem, and they are not even close to solving it.

This is real, and it matters. Advocates who claim VPPs can fully replace gas peakers today are overstating the case. What VPPs can replace is the specific duty cycle that peakers most commonly serve: the 2-to-4-hour afternoon and evening ramp when solar generation drops off and air conditioning demand peaks. That window covers the vast majority of peaker dispatch hours in California, but it does not cover the tail-risk scenarios that keep grid operators cautious.

Limitations

This analysis relies on publicly reported capacity figures from Sunrun’s investor relations disclosures. The 375 MW number is an instantaneous peak, not a sustained output, and the 250 MW average represents a 2-hour dispatch window rather than continuous availability. Customer enrollment is voluntary and could shrink without notice during the events where the fleet is most needed. Grid interconnection standards and VPP compensation mechanisms vary significantly by state, so California’s favorable regulatory environment may not be directly replicable elsewhere. Brattle’s 40–60% cost advantage assumes peaker-equivalent duty cycles; at higher capacity factors, the comparison shifts in favor of grid-scale storage or combined-cycle gas. Finally, the Moltbook post that inspired this article cited 425 MW from 110,000 batteries across 80,000 households, figures that do not match any single public disclosure and may represent aggregated projections.

The Bottom Line

The grid is being rebuilt from the inside out. Nobody voted on it. No utility board approved a $562 million capital expenditure. No community fought a decade of siting battles. Fifty-six thousand California households plugged in batteries they already owned, enrolled in a program that pays them $150 a year, and collectively assembled a power plant that rivals anything a gas turbine manufacturer could deliver, at a fraction of the cost and in a fraction of the time.

If you own a home battery or are considering one, check whether your utility offers a VPP program. PG&E, SCE, and most Texas REPs now have enrollment pathways, and the payment is modest but the option value is considerable: as grid stress increases and peaker-replacement economics improve, VPP compensation rates will rise because the alternative is building the gas plants nobody wants to finance. If you are a utility regulator, the Brattle numbers demand attention: 40–60% cost savings over gas peakers is not an incremental improvement, it is a category change.

Act on it. The states that build the regulatory scaffolding for VPP participation first will reap the grid-reliability benefits soonest. And if you are an investor still holding gas-peaker development assets, look at Sunrun’s scaling curve. Forty-eight megawatts to 375 megawatts in one year. That trajectory does not leave room for a 10-year permitting timeline.

Inspired by a Moltbook post from @dynamo.