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The cost of keeping California’s power grid up and running is skyrocketing, and in turn, so are households’ energy bills. Virtual power plants, which harness the combined power of lots of rooftop solar systems, home batteries, EVs, and smart-home appliances, can help — especially if utilities use them to relieve pressure at counterintuitive “sweet spots” on the grid.
So finds a new report that examines how the state’s utilities can spend less on new infrastructure by occasionally paying homes and businesses to reduce power use or to inject energy into the system — a concept known as “load flexibility.” Think tank GridLab published the study in collaboration with Kevala, a grid-focused data analytics startup.
One of the main reasons utilities’ expenses are rising is that the companies are putting more money toward their distribution grids — the poles, wires, and transformers that deliver power from electrical substations to homes.
Spending on distribution grids has grown rapidly in the past decade, and made up 44% of total utility spending in 2023, according to data from Lawrence Berkeley National Laboratory. Most of that cash is going toward replacing aging equipment and keeping up with booming demand for electricity.
The distribution grid is an even greater expense in California, according to Ric O’Connell, founding executive director of GridLab. Utilities there must invest heavily in wildfire-prevention measures, and the state’s ambitious decarbonization goals mean the power system needs to support the rapid electrification of homes and vehicles.
If California can defer upgrades to its distribution system, it can produce savings for customers, O’Connell said.
“That’s where the money is,” he said. All things being equal, “deferring the greatest number of highest-cost grid upgrades will save the most money.”
And according to GridLab’s new study, the best way to defer the most upgrades is to find those grid sweet spots — specifically, the areas with circuits, transformers, and substations that are least strained — and rapidly scale up virtual power plant programs to serve them.
Kevala, the startup that partnered with GridLab on the study, has a decent idea of where those sweet spots might be, based on its past analyses of distribution grids in California and nationwide.
The new study looks at the ideal way to deploy the 3.5 gigawatts of “load shift” capacity that California hopes to add to its grid by 2030.
For the research, Kevala compiled data on every feeder line, substation transformer, and substation of California’s three biggest utilities from today through 2030. It then ran three scenarios for using that 3.5 GW of load flexibility to relieve strain on that infrastructure: spreading the VPP effort equally across the grid, targeting the most overloaded parts of the grid first, and prioritizing the least overloaded parts.
That last technique was by far the most cost-effective, the analysis showed. Putting it into practice could reduce grid costs passed on to utility customers by a total of $13.7 billion through 2030 — about $10 billion more than the alternative approaches.
The reason? Taking on the least overloaded circuits first allows the same amount of load flexibility to defer new investments across a wider swath of the low-voltage grid, O’Connell said. The strategy also happens to target more urban areas, where much of the grid is buried underground, making it more expensive and difficult to upgrade.
That result came as something of a surprise.
“At first, we thought you’re going to start with the most heavily overloaded circuits and allocate flexibility to those, and then work your way down,” O’Connell said. “But we found you basically exhaust your flexibility on a handful of circuits — and you’re basically not saving a lot of money.” For those instances, “maybe it makes sense to spend real money on poles and wires.”
VPPs may also struggle to meet the challenge of deferring investments in the most strained parts of the grid, he noted. The history of these efforts appears to bear that out.
For more than a decade, utilities and regulators have been working on so-called “non-wires alternatives” projects — using batteries, energy efficiency, and grid-responsive devices to defer the need for big grid upgrades. Since 2014, California state policy has required regulators and utilities to work toward building these “distributed energy resources” — DERs for short — into their multibillion-dollar annual spending plans.
But beyond some showcase projects like New York utility Con Edison’s Brooklyn-Queens Demand Management initiative, relatively few proposals have moved past the planning phase. In California, despite programs launched over the past decade, “nothing’s really happened,” O’Connell said. Critics say the lack of progress is largely because utilities have proposed grid projects that DERs couldn’t possibly solve within the timeframes and cost restrictions provided.
On the other hand, “there are many circuits that are overloaded on a few hours of very hot days. I just need a little bit of DERs to solve that,” O’Connell said. “If we have a limited amount of valuable load flexibility, we should sprinkle a little bit of it across these lightly overloaded circuits.”
Targeting the least overloaded circuits could also minimize the risk of VPPs falling short of the job, he said. Slightly overloaded transformers and power lines can undergo overload conditions for short periods of time without blowing up or breaking down.
Larger-scale non-wires alternative projects like those that have been targeted in the past have a slimmer margin of error, he said. Utilities have traditionally demanded that any DERs being deployed to solve those grid constraints be made available for that purpose to the exclusion of any other use.
That’s a tough sell for customers of the companies putting VPPs together. Most consumers buy batteries for emergency backup power or to store surplus solar power — not to turn them over completely to utility control.
Customers willing to enroll their EV chargers, air conditioners, water heaters, and other appliances in flexibility programs would likely balk at the idea of being unable to use their devices when they really need to. Past VPP initiatives show that customers are far less likely to stick with them if they aren’t able to “opt out” of particular dispatches when circumstances demand it — say, when they need to charge their EV quickly after work to take their kid to soccer practice, or keep the house cool when elderly relatives are visiting.
With less-overloaded parts of the grid, by contrast, “maybe we can get the utilities a little bit more relaxed about it,” O’Connell said. “They’re always worried about, ‘What if the DERs don’t show up?’”
There’s a big catch when it comes to putting insights like these into action, however, said Kevala CEO Aram Shumavon. Utilities in California and elsewhere haven’t yet built VPPs and DERs into how they plan investments. That makes it much harder for the companies to consider them as options — which means they wind up choosing the traditional grid upgrade instead.
That’s the safer tried-and-true choice — and utilities, with their “extreme aversion to quantify risk, struggle with making innovative decisions,” he said. “But we’re spending a lot of time right now on what feels like baby steps, compared to how this market as a whole will need to function.”
It’s taken years for California utilities to start using the inherent flexibility of these technologies to help with grid operation and planning. But now, after some experimentation, they’re starting to prove that EV charging hubs, distributed solar installations, and utility-scale batteries can operate to fit within the hour-by-hour constraints on the grids they’re connected to. Similar efforts are now underway with customer-owned batteries and home energy control systems.
Still, VPP and DER programs are simply not expanding fast enough to meet California’s needs, Shumavon contends. “Once you move it into a program or procurement that requires a larger amount of situational awareness, we are woefully behind where we should be as an industry.”
Even getting the grid data needed for VPP providers to know where their solar-charged batteries or controllable household loads could do the most good has been a challenge. State legislators recently killed a bill provision that would have required California’s three major utilities to share data to inform how VPPs can reduce grid costs.
But Shumavon thinks that utilities in California are coming around to the need to move faster. The “non-wires alternatives” concept arose decades ago, when electricity demand was largely flat across most of the United States, and utilities had little incentive to support an alternative to investing more in their grids, which is how they earn guaranteed profits.
But that situation has radically changed in the past few years. The AI boom requires grids to handle gigawatts of new power, and utility rates are rising across the country. “The risk they’re facing is that they can’t do the rate increases, and they still have to deploy more capital, which has an upward pressure on rates,” Shumavon said. “That’s the point at which politicians get angry.”
O’Connell agreed that “utilities are much more interested in doing this now. They’re seeing rate pressure being a much bigger deal for them now. Anything they can do, it means that billions less in capital spend will show up.”
But the recent study by GridLab and Kevala “wasn’t going to get into how you design the program and how you pay them,” he said. “It’s more like, ‘You can do this — let’s figure it out.’”
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