Dive Brief:
- Virtual power plant deployment can help utilities avoid billions in new generation and transmission costs, but inadequate performance accountability and poor visibility into distribution networks are holding back wider VPP adoption, panelists said July 23 during a webinar presented by Heatmap Labs and Uplight.
- From a funding and procurement standpoint, VPPs should evolve to look more like a conventional electricity supply resource, said panelist Sam Hartnett, senior product marketing manager at Uplight.
- “If we can get to a point where there are [pay-for-performance] guarantees, [a VPP] can go into the core integrated resource plan and rate-case side of its utility rather than the demand-side management side,” Hartnett said.
Dive Insight:
U.S. VPP capacity ranged from 30 GW to 60 GW in 2023, depending on how the resource is defined, according to the Department of Energy’s VPP liftoff report. Most of that capacity comes from utility demand response programs focused on resources like smart thermostats, commercial and industrial loads, home batteries and managed electric vehicle charging, DOE found.
Successful VPPs use a variety of distributed resource types to create something greater than the sum of its parts, Hartnett said.
“A VPP should ideally include multiple classes of distributed energy resources and also multiple customer segments [operating as] one cohesive resource that performs like a conventional power plant,” he said.
Like a conventional power plant, a VPP should be able to set operating parameters for dispatch and planning across multiple timescales, ramp production up or down based on demand, deliver multiple grid services and dispatch against a specific capacity target throughout the year, Hartnett said.
Hartnett singled out a Puget Sound Energy VPP managed by Uplight as a possible model for future VPPs. The program is designed to aggregate demand response programs involving residential water heaters and other “bring your own device” loads, behavioral demand response, commercial and industrial demand response, energy storage and EV charging “as one unified resource … that allows distribution system operators to work hand-in-hand with [utility] supply and demand teams to say when and where to call dispatches,” Hartnett said.
During the largest of seven “flex events” highlighted in an RMI flipbook released last month, the PSE-Uplight VPP produced an average of 32 MW over three hours. PSE and Uplight hope to reach 100 MW capacity by next year, RMI said.
But as VPPs scale, they will require a degree of technical orchestration and “real-time situational awareness” far beyond most present-day demand response programs’ capabilities, said panelist Shuvo Chowdhury, vice president of technology and analytics at Marin County Energy.
The objective is a “scalpel” that can “finely mold and shape the [load] profile into something that is profitable for the system and the average customer,” he said, comparing a sophisticated VPP to an orchestral composition and standard demand response to “[banging] two rocks together to make music.”
Significant investments in distribution grids and metering technology are needed to achieve this, said panelist Eric Blank, chairman of the Colorado Public Utilities Commission.
Whereas grid operators can optimize generation and transmission resources on a “second-by-second basis…there is nothing comparable on the distribution side,” he said.
“With a couple of years and millions in investment, we can sort of maybe integrate [VPP] aggregators,” but achieving the same results at the individual customer level will require more time and far more money, Blank added.
Distribution system and customer-side investments should include device telemetry to gather robust data on distributed resources, such as battery state-of-charge and thermostat cycle time; advanced metering infrastructure to provide enough visibility into customers’ energy consumption to support robust, accurate load modeling that accounts for event-to-event variability in customer opt-out rates; and better integration with distribution grid management systems, which “historically are not tightly coupled [with behind-the-meter resources],” Hartnett said.
These investments can improve VPP capacity forecasting and increase utilities’ confidence that the resource will be there when it’s needed, Hartnett added.
VPP-enabling investments could also help avoid billions in generation and transmission outlays that would otherwise be required, making them worth the expense and effort, Blank said.
Colorado’s goal of nearly 1 million electric vehicles on the road by 2030 would double or triple the state’s coincident peak demand, he noted.
“If we lose control of that and everybody charges at the same time, it’s a $10 billion problem,” he said.
To improve VPPs’ actual and perceived reliability and ultimately enable their inclusion in utility IRPs, regulators should hold them to the same performance standards as traditional generation resources, including payment of liquidated damages if they fail to perform, Blank said.
A Colorado law passed earlier this year requires Xcel Energy, the state’s largest electric utility, to develop a performance-based VPP pilot and a plan for distribution system enhancements by early next year.
