During a panel discussion at pv magazine USA Week 2026, industry leaders from Tesla, FranklinWH, and Ohm Analytics detailed how post-ITC economics, virtual power plants, and grid capacity constraints are driving residential solar installers to adopt storage-first business models.
The residential solar market experienced a 19% year-over-year decline in installation volume, but residential storage deployments held steady with nearly 1 GWh installed in Q2 2026. Data presented by Ryan Feeney, partner at Ohm Analytics, showed that this stability pushed the national battery attachment rate to 49%.
In California, projects installed under the state’s NEM 3.0 tariff reached an 80% storage attachment rate, while Texas experienced a 132% year-over-year increase in storage installations, with standalone battery retrofits making up roughly 75% of that growth.
“We recently released our quarterly report and we actually highlighted this trend as one of the defining trends of the year,” Feeney said. “The residential solar market was down 19% year-over-year, but close to a gigawatt-hour of storage was installed in Q2, making it roughly flat.”
As export compensation rates decline under net metering revisions nationwide, panel speakers emphasized that storage has shifted from an optional add-on to the central driver of residential project economics.
Ronnie Pettersson, vice president of product and application engineering at FranklinWH Energy Storage, noted that installer sales presentations have shifted at the kitchen table from array sizing toward calculating exact household kilowatt-hour storage needs. Pettersson attributed this to growing consumer concerns over extreme weather outages, rising retail electricity prices, and localized power grid stress from artificial intelligence data centers.
“It really starts at the kitchen table where the installers’ salespeople are talking from ‘how much solar do you want to have on the roof’ to ‘how many batteries do you really need,’” Pettersson said.
Scaling VPP capacity and real-world fleet performance
With utility distribution grids facing unprecedented load growth, aggregated distributed energy resource fleets are stepping in as firm grid capacity assets. Doug Middleton, utility and virtual power plant business development lead at Tesla, reported that Tesla now manages over 1.5 million Powerwalls globally, with 2.5 GW representing nearly 5 GWh of storage capacity currently enrolled in active VPP programs.
Middleton pointed to recent summer grid dispatches in California, where Tesla aggregated more than 600 MW of coordinated capacity across multi-hour events. The California Powerwall VPP fleet expanded its overall capacity by 50% year-over-year, demonstrating the speed at which modular residential storage can scale compared to transmission-scale assets. In Puerto Rico, Tesla’s aggregated Powerwall network acts as a continuous marginal generation resource to prevent local utility rolling blackouts.
“This is not demand response, right? It’s demand-sited generation, which gives it a different capability set than I think historically grid operators are used to from distributed assets,” Middleton said. “Having the political will, the ongoing load growth—like the pressure that will keep that kind of cost pressure there in the load growth from large loads—alongside capability and scale is really giving us a chance to go out and compete alongside real resources and not kind of be some pilot project.”
Third-party performance verification data from the Connecticut Green Bank shows that FranklinWH and Tesla battery fleets achieved over 90% participation rates during requested utility dispatches, while competing original equipment manufacturers registered participation rates below 70%.
Financing models and wholesale market access
Integrating VPP program revenues directly into customer financing contracts offers a path to significantly expand the total addressable market for residential storage. Ohm Analytics estimates that 30% to 35% of residential batteries are currently enrolled in a VPP program.
Program financial compensation structures are expanding rapidly across major markets. In Massachusetts, the Connected Solutions program offers up to $400 per kilowatt-year for batteries deployed in congested distribution circuits, combining a base incentive with a $125 per kilowatt-year distribution service adder. ERCOT program participation in Texas yields up to $325 annually, while New Jersey’s GridSmart program provides a $5,000 upfront rebate alongside zero-interest bill financing. In California, Ava Community Energy offers up to $6,000 in upfront battery installation rebates for qualifying low-income customers.
Middleton argued that third-party ownership and leasing providers must incorporate these anticipated grid service revenues directly into upfront consumer pricing. Monetizing grid services at the point of sale can reduce a homeowner’s monthly battery lease payment from $200 per month down to $100 per month.
“If we as an OEM and we as a service provider in conjunction with our partners, our EPCs, our financiers, if we can actually just offer that as an upfront discount, you now go from call it a $200 a month payment to buy these down to a $100 a month payment,” Middleton said. “And you just think about the adoption that opens up in terms of the number of homeowners.”
However, legacy wholesale market rules continue to hinder scaling. Middleton highlighted that regional transmission operators like CAISO and PJM still operate under rules designed for legacy demand-response assets, which treat battery aggregations solely as load reduction and prevent home batteries from receiving wholesale market compensation for exporting power back to the grid.
“There’s a lot of policies that were set before battery storage was really a technology, and the way we participate is through mechanisms designed for large loads,” Middleton said. “The fact that a distributed battery can’t get paid for exports in wholesale markets is like such an obvious win.”
Legislative workarounds are beginning to emerge, including a recent New Jersey law allowing commercial data centers to contract directly with distributed energy resource aggregators, enabling large-scale flexible capacity deals like Google’s 100 MW PJM capacity contract with Voltus.
Hardware bottlenecks and standardizing installation hardware
To bring down balance-of-system and customer acquisition costs, manufacturers are targeting main service panel bottlenecks through standardized hardware. Pettersson highlighted meter collar adapters and microgrid interconnection devices, such as the UR-MID standard currently being formalized with NEMA, as critical tools to bypass main panel upgrades and eliminate separate disconnect switches.
“What you don’t have to do is install, for example, a disconnect means to island the home,” Pettersson said. “And that makes it easier for the battery to act as the backup for the home as an upgrade solution.”
As commercial data center power demand compresses utility interconnection timelines, distributed batteries represent a rapidly deployable alternative. Panels speakers noted that while legacy infrastructure upgrades often require years of permitting, distributed battery fleets can be deployed within months to deliver immediate capacity relief.
“Focusing on storage and diversifying their offerings, getting creative—I’d say five years out, we expect storage to be the standard model,” Feeney said. “With net metering cuts reducing the value of exports, utilities launching VPP programs, successful contractors are going to be the ones that sell batteries, enroll them, and can explain it to homeowners.”
Watch the full panel below at 105:43:
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