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Across California, hundreds of homes and businesses have signed up their solar panels, batteries, EVs, and appliances to be part of “virtual power plants” — networks of scattered energy resources that utilities can control to stave off blackouts and cut electricity prices.
Now, utilities are exploring another way to leverage VPPs: Strategically concentrating the systems in certain areas could let the companies defer expensive upgrades to nearby poles, wires, and other infrastructure. But first, utilities need to be 100% sure they can count on customer-owned assets without risking the grid’s reliability.
That’s the challenge that Northern California utility Pacific Gas & Electric is taking on with a pilot program it is running this summer and fall. PG&E has years of experience operating virtual power plants to reduce stress across the statewide grid. But the new Seasonal Aggregation of Versatile Energy (SAVE) program is testing how customers’ batteries and home energy controls can meet grid needs more precisely, down to the neighborhood level.
PG&E hasn’t said how many households it enlisted for the pilot, but in a March press release, the utility said it aimed to enroll up to 1,500 residential customers with solar-charged batteries from companies including Sunrun and up to 400 customers with smart electrical panels from startup Span.
The local “distribution” grids that serve those customers operate under a variety of conditions, including moments of peak demand that push some of the systems to their limits. Using home batteries and energy controls to delay upgrading those grids could make a big dent in the high and rising costs of electricity in California. In fact, a recent analysis indicates tapping the state’s nation-leading fleet of rooftop solar, backup batteries, and EVs for this task could save billions of dollars in grid upgrade costs.
PG&E isn’t delaying upgrades on the parts of the grid it’s testing just yet, said Trevor Udwin, the utility’s VPP and grid optimization manager. But the SAVE project will inform next steps to start doing this kind of proactive, VPP-integrated grid planning at a larger scale.
“At some point, we need to build trust,” Udwin said. “That means someone’s signing something” — a commitment to deliver the grid relief needed during specific times — ”and that a distribution planner is changing their operations based on that commitment.”
Distribution networks are distinct from the huge transmission lines that move the energy produced by power plants over long distances. Local distribution infrastructure instead carries power from substations — the big, fenced-in collections of equipment that lower the voltage of transmission-fed power — along main feeder lines, and eventually to the wires that connect to neighborhoods, homes, and businesses.
Until recently, utilities lacked technologies like smart meters and grid sensors to let them see what’s actually going on on those parts of their grids. That visibility is important, because these distribution networks have unique and fluctuating needs and characteristics — or load shapes, in industry parlance —that determine where and when they may be experiencing problems.
Without that transparency, the traditional utility fix has been to overbuild the system to reduce risks of overloads. But that’s getting expensive as demand for electricity rises. U.S. utilities invest more capital in their distribution grids than in any other part of their business, and those costs are increasing rapidly.
It could be much cheaper to instead get a cluster of customers to use less energy or send solar or battery power back to the grid during the handful of hours a particular distribution system is overloaded.
To test that capability, PG&E and its SAVE partners are using Sunrun’s batteries and Span’s smart electrical panels to modify how homes participating in the pilot consume and provide electricity to match the hour-by-hour constraints of the grid they’re connected to.
That’s an inherently time- and location-specific challenge, since different grid substations and circuits “may have very different load shapes, and they may peak differently at different hours,” Udwin said. And right now, very few utilities have deployed the data-collecting technology needed to reliably coordinate those interactions across their low-voltage distribution networks.
That technology, referred to as a distributed energy resource management system, or DERMS, does exist. California’s big utilities have run multiple DERMS pilot projects over the years, and PG&E has built a DERMS system that it’s using to manage a handful of EV charging hubs and utility-scale batteries participating in “load flexibility” pilots.
But PG&E hasn’t yet integrated that DERMS platform with the communications and controls technology it’s deploying with its SAVE partners, Udwin said. Instead, for this summer’s tests, PG&E is “building communications with the aggregators,” he said, interfacing with software from Lunar Energy and Tesla to control the batteries, and with Span’s software that keeps whole-home energy use below certain thresholds.
All of that software will be tasked with making sure homes with batteries, panels, and other equipment work together to add power or reduce draws at moments when that section of the grid is expected to experience excessive loads. But it also has to make sure it doesn’t leave customers unable to use their batteries and appliances when they need to, Udwin noted.
PG&E and its SAVE partners want to make sure they’re “serving their customers best, and that the load-shaping won’t negatively impact them,” Udwin said. To make that easier, PG&E is delivering its partners week-ahead and day-ahead load shape requests, he said. That gives Sunrun and Span an opportunity to prepare their customers for lengthy demands on their resources.
“They’re taking a really big risk with us,” he said. “I’m thrilled our partners are taking this leap.”
California was one of the first states to push utilities to integrate customer-owned solar, batteries, and flexible EV chargers and appliances into grid planning. Colorado, Hawaii, Illinois, Massachusetts, Minnesota, New York, and others have enacted similar policies over the past decade. The idea is to capture the grid value of distributed energy resources — solar, batteries, EVs, and smart thermostats, water heaters, and appliances that can shift when they use electricity — that homes and businesses are already buying.
Lots of utilities are already using these technologies to reduce system-wide electricity peaks. In fact, demand-response programs have existed for decades. But beyond a handful of projects, utilities have yet to leverage VPPs as a way to defer investments in their distribution grids.
Utilities don’t have much time to act on this opportunity for savings, said Aram Shumavon, CEO of grid analytics company Kevala. Even with these kinds of targeted VPPs in place, overloaded grid circuits will need to be upgraded sooner or later, he said. And once they are, VPPs can no longer defer those costs, evaporating the potential savings.
Missing out on those savings could hurt. A 2023 study by Kevala found that upgrading California’s distribution grids without deploying tech and programs to prevent EV charging from overloading local circuits could cost the state’s three big investor-owned utilities around $50 billion by 2035. Managing EVs to avoid those overloads, by contrast, could cut that price tag roughly in half, according to more recent studies.
Those savings should more than cover whatever utilities need to pay EV owners to commit to those managed charging constraints, Shumavon said. Eventually, the rising electricity demand from all those new EV-owning customers will increase utility revenues enough to cover those new grid costs, lowering rates for customers at large, he added.
To be clear, the lack of uniformity across different parts of the grid makes it hard to pinpoint the precise value of the VPPs the SAVE program is testing. Assessing that value is exceedingly complicated, given the enormous number of variables involved.
VPP advocates argue that utilities and regulators should avoid getting bogged down in those calculations and err in favor of encouraging customers to lend their spare power to help the grid. A new report from Kevala and think tank GridLab found that California could cut energy costs for consumers by up to $13.7 billion by 2030 by fully utilizing distributed resources like EVs and solar panels to defer grid upgrades.
However, utilities need to be able to prove out that a VPP’s benefits outweigh the expense of paying customers for access to their energy resources, Udwin said. “We want to find ways to shape for everything we can shape for — and do so cost-effectively. That’s the rub.”
PG&E is targeting low-income and disadvantaged communities for at least 60% of its SAVE test cases, Udwin said. There’s a sound rationale for that: Data shows that utilities have underinvested in the distribution infrastructure that serves these communities, which has restricted their ability to access rooftop solar and EV charging.
At the same time, PG&E is focusing on parts of the grid where its SAVE partners already have a concentration of customers. California has more rooftop solar, behind-the-meter batteries, and EVs than any other state, which provides a fertile field of latent resources to tap into, said Yang Yu, Sunrun’s director of business development for distributed power plants (another term for VPPs).
“Deploying assets in a small territory can make it difficult [for VPP programs] to reach scale, even with strong customer incentives like a free battery,” he said. But Sunrun has “a ton of assets already deployed,” he said. “That means that, within a specific region — say a substation or even specific feeders — we may have enough penetration at some point to do a local-level peak-load management.”
That’s not just more cost-effective than upgrading utility grids — it’s also faster. “We can stand up a [distributed power plant] in six months,” he said, which is what Sunrun has done for PG&E’s SAVE program.
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