Can virtual power plants relieve hot spots on neighborhood power grids?

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.”

Proving that VPPs can match local grid needs 

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.

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.