Dive Brief:

• Successful virtual power plants are reliable distributed resource aggregations that deliver targeted, predictable benefits for distribution or bulk power grids, a group of experts said Tuesday during a webinar organized by the Regulatory Assistance Project.
• Utilities increasingly see VPPs as affordability levers, too, said Kevin Brehm, who manages RMI’s carbon-free electricity practice. On the bulk system, they can decrease power demand when wholesale prices are high and reduce both capacity and transmission costs; on distribution grids, they can free up load interconnection headroom and help reduce, defer or avoid incremental system investments, he said.
• To scale customer participation in VPP programs and improve dispatchability, utilities and resource aggregators should provide robust and predictable compensation; use “revenue-grade metering” to measure performance and embed customer protections like penalty-free opt-out, said Bronte Payne, senior manager for policy at Sunrun.

Dive Insight:

VPPs are becoming more sophisticated as utilities and aggregators learn from early deployments and new resources enter the mix, said Brehm, whose team helped develop RMI’s comprehensive catalog of active U.S. VPP programs.

Brehm said VPPs based around residential batteries and active managed electric vehicle charging are growing particularly fast amid slower growth in thermostat-based programs. Multiple operational models have emerged, he added: Utility-run VPPs that compensate consumers directly or use third-party aggregators as intermediaries; “market participant” VPPs, in which resource aggregations participate directly in energy, capacity or ancillary markets; and “bring your own capacity” VPPs, an emerging model that Brehm described as a hybrid of the two.

For utilities, well-designed VPPs can improve reliability on constrained distribution grids or provide resilience benefits in areas prone to weather-related outages or load shedding, Brehm said. Consolidated Edison Co. of New York’s demand-response VPP is a good example of the former, while Puerto Rico utility Luma Energy’s Customer Battery Energy Sharing program typifies the latter, he said. 

VPPs continue to evolve, with new resource models like bidirectional electric vehicle charging on the horizon, Brehm added. An analysis commissioned by General Motors last month found vehicle-to-grid integration can deliver up to 15 times more value per vehicle than one-way managed charging.

“We would love to see more vehicle-to-grid participation in VPPs … I know some of the [auto manufacturers] are beginning to advocate and get a little restless,” Brehm said.

Nick Watson, director of flexible resource engineering at National Grid, said his utility is tapping distributed resource aggregations in 19 non-wires alternatives projects across its Massachusetts service territory. 

Watson said National Grid has 7.2 MW of active or committed capacity across two separate programs: ConnectedSolutions+, a residential- and small business program that leans on stationary batteries, EVs and other resources; and a more market-based front-of-meter framework for commercial and industrial customers.

ConnectedSolutions+ is an outgrowth of New England’s long-running ConnectedSolutions VPP that aggregates customer-sited resources in targeted areas of high need. In exchange for payments higher than standard ConnectedSolutions participants receive, ConnectedSolutions+ participants allow National Grid to dispatch their resources “a little bit more” and at different times of day that may reflect local demand peaks, such as Friday or Saturday evenings, Watson said.

Eversource, National Grid’s main investor-owned utility competitor in Massachusetts, has also been enrolling customers in ConnectedSolutions+.

After calculating the potential value of non-wires alternatives in constrained grid nodes, National Grid looks at factors like customer type and present ConnectedSolutions enrollment levels to determine whether ConnectedSolutions+ or the market-based framework — which requires a request for proposals process — makes more sense, Watson said.

“We screen for how much dispatchable resource we [already] have in a location,” Watson said. If the answer is ‘not much,’ an RFP may be needed.

Xcel Energy is also tapping multiple distributed resource frameworks to address emerging grid issues in Colorado, said Zach Pollock, the company’s director of grid strategy and emerging technologies.

With more than 1 GW of solar on its 7-GW Colorado system, much of it distributed on rooftops, Xcel is “starting to see some operational issues in terms of voltage swings and reverse power flow that we need to get ahead of,” he said. A corresponding reduction in the incremental value of midday solar has Xcel looking toward a “direct-participant model” that emphasizes DERs’ capacity value, he said.

“It really becomes about how do you leverage DERs not just to generate [renewable energy credits] … but really from a system perspective, how do you generate value for all the customers being asked to contribute to the cost of the grid,” Pollock said.

Xcel issued a competitive solicitation earlier this summer for the state-mandated Dispatchable Distributed Generation program, which will enroll megawatt-scale batteries “operating on a schedule to provide meaningful load reduction benefits” in areas with distribution-system constraints, Pollock said. 

Pollock said Xcel has also signed up “a few megawatts” for its Active VPP program, or AVPP, which aims to enroll 25 MW of behind-the-meter resources per year for five years. Though Xcel “reserves the right” to act as its own aggregator in the future, those resources will be managed for now by third-party aggregators, he said.

Xcel’s goal with AVPP is “let’s make this look like a four-hour battery … we don’t care what resources someone is going to bring us,” Pollock said.