By Herman K. Trabish
Virtual power plants can realize their full potential with improved control technologies, streamlined communications and customer-engaging compensation, utilities, providers and analysts agree.
VPPs are aggregations of distributed energy resources managed by sophisticated software to meet power system needs, including load reductions and system stability. By mid-2023, North America had more than 500 of them with up to 60 GW of total capacity, according to one estimate. By 2030, VPP flexible capacity could scale up to 160 GW and serve almost 20% of the projected 802 GW U.S. peak load, the Department of Energy says.
“Scaling up DER integration” into VPPs will face challenges, wrote DOE Loan Programs Office Director Jigar Shah in September 2022. But the obstacles are “far from intractable, and well-worth the cascade of benefits,” he added.
Even analysts whose research shows VPPs can be a key power system solution agree the challenges to scaling are real and are only beginning to be addressed.
To grow, VPPs can and must be “fully compensated for the value they can provide” and “customers need to trust that participating won’t inconvenience them,” said Brattle Group Principal Ryan Hledik, whose research has identified signifjcant VPP values. And vital VPP system stability services may require technology investments to “connect directly into utility control systems,” he added.
Scaling VPPs will likely impose new costs for operations technologies, VPP providers, utilities and analysts said. It will also require new planning processes that recognize the multiple new values of VPPs’ flexible DER elements, and confronting regulators with the need for system standardizations, many also agree.
Operational challenges
VPPs vary significantly by jurisdiction and provider, and there are no recognized communications standards to streamline their response to indicators that show a need for load reductions or system stability services.
Pacific Gas and Electric has “approximately 412 MW” of VPPs and is “actively looking to integrate more,” said company spokesperson Paul Doherty. Its VPPs are part of state, aggregator-led and utility-led programs with partners including Tesla, Sunrun and BMW, he added.
PG&E is implementing a new system-wide Advanced Distribution Management System coupled with a Distributed Energy Resource Management System, Doherty said. It is also investing in communications systems which “will enable incremental VPP use cases,” he added.
Rocky Mountain Power has standardized its Utah Wattsmart solar and battery VPP operations by establishing criteria battery manufacturers must meet to participate, said the utility’s Vice President of Customer Experience and Innovation William Comeau. It therefore “has no need for DERMS,” he added.
To qualify for Rocky Mountain Power’s load reduction and stability services programs, batteries must meet capacity, cycle life and daily charge-discharge capability criteria, Comeau said. With the Institute of Electrical and Electronics Engineers’ 2030.5 protocol for DER interconnection and 30 second interval data available to the utility, Rocky Mountain Power has full dispatch control of the VPP’s full value, he added.
“The IEEE 2030.5 DER interconnection standard could be a solution” for national interoperability between all DER and all system operators, agreed Scott Harden, chief technology officer for global innovation with power system technologies provider Schneider Electric. The American National Standards Institute or another national standards agency “could take the lead” to develop another standard to serve the same purpose, he said.
“The control room and communications technologies to scale VPPs have been available for a decade and are proven,” Harden continued. But scaling VPPs will require “development of a standardized open communications protocol and open DER registry to allow all DER to compete in retail market-like scenarios,” he said.
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