Analysts: Solving Three Key Issues Can Help Virtual Power Plants Scale Up and Unlock Multiple Benefits

For virtual power plants (VPPs) to reach their full potential, breakthroughs are needed in control technology, communication standardization, and customer incentive compensation. Utilities, service providers, and analysts agree on this.

A VPP is a solution that uses advanced software to aggregate and manage distributed energy resources to meet power system needs, including load reduction and system stability. According to one estimate, as of mid-2023, there were over 500 VPP projects in North America with a total capacity of up to 60 gigawatts. The U.S. Department of Energy (DOE) states that by 2030, VPP flexible capacity could expand to 160 gigawatts, meeting nearly 20% of the projected 802-gigawatt peak load in the U.S.

Jigar Shah, Director of the DOE Loan Programs Office, wrote in September 2022 that integrating distributed energy resources (DERs) into VPPs on a large scale will present challenges. But he added that these obstacles are "far from insurmountable, and worth pursuing because the benefits will be cascading."

Even analysts whose research shows VPPs can be key power system solutions acknowledge that scaling challenges are real and are only just beginning to be addressed.

Ryan Hledik, a principal at The Brattle Group, said that for VPPs to grow, they must "be adequately compensated for the value they can provide," and "customers need to be convinced that participating won't be an inconvenience." Hledik's research has identified significant VPP value. He added that VPPs providing critical system stability services may require technology investments to "directly interface with utility control systems."

VPP service providers, utilities, and analysts say that scaling VPPs will likely bring new operational technology costs, along with the need for new planning processes that recognize the multiple values of VPP flexible distributed energy elements and prompt regulators to address the need for system standardization. This is also a common consensus.

Operational challenges

VPPs vary significantly across jurisdictions and service providers, and there is currently no universally accepted communication standard to uniformly coordinate their response to load reduction or system stability service needs.

Paul Doherty, spokesperson for Pacific Gas and Electric Company (PG&E), said the company has "approximately 412 megawatts" of VPP capacity and is "actively seeking to integrate more." Its VPP programs include state-level, aggregator-led, and utility-led initiatives, with partners including Tesla, Sunrun, and BMW.

Doherty said PG&E is deploying a new system-level Advanced Distribution Management System (ADMS) along with a Distributed Energy Resource Management System (DERMS). The company is also investing in communication systems that will "support more VPP use cases."

William Comeau, Vice President of Customer Experience and Innovation at Rocky Mountain Power, said the company has standardized its Utah Wattsmart solar and battery VPP operations by establishing participation criteria that battery manufacturers must meet. As a result, the company "doesn't need to use a DERMS."

Comeau said that to qualify for Rocky Mountain Power's load reduction and stability service programs, batteries must meet standards for capacity, cycle life, and daily charge/discharge capability. Using the Institute of Electrical and Electronics Engineers (IEEE) 2030.5 DER interconnection protocol and 30-second interval data available to utilities, Rocky Mountain Power has been able to fully dispatch and control the entire value of its VPP.

Scott Harden, Chief Technology Officer for Global Innovation at Schneider Electric, agreed: "The IEEE 2030.5 DER interconnection standard could be the solution" for achieving nationwide interoperability between all distributed energy resources and all system operators. He said the American National Standards Institute (ANSI) or another national standards body "could take the lead" in developing another standard to achieve the same purpose.

Harden continued: "The control room and communication technology for VPP scaling has existed for a decade and has been proven." But VPP scaling will require "developing standardized open communication protocols and an open DER registry to allow all distributed energy resources to compete in a retail-market-like scenario."

Lon Huber, Senior Vice President of Pricing and Customer Solutions at Duke Energy, added that the company's newly approved 60-megawatt PowerPair pilot offers customers a $9,000 upfront incentive for purchasing batteries and allowing the utility limited control over them. But he also agreed that automated, interoperable communication and dispatch are "critical" to achieving "meaningful scale."

Darren Pai, spokesperson for Hawaiian Electric, said that to scale VPPs, the company will need "smarter, faster" control room and communication technology to enable visualization, control, and dynamic optimization.

Joshua Tom, Director of Customer Future at National Grid, added that VPPs are increasingly becoming part of the company's resource portfolio. He said additional control room and data management technology are both "very important" for further expanding their scale.

But Chris Rauscher, Head of Grid Services and VPP Business at Sunrun, said that "whether it's PG&E's sophisticated control room operations or Puerto Rico's relatively basic LUMA operations, both can support Sunrun's participation in VPP partnerships," and "there are no technology, metering, or software challenges."

Rauscher believes that claiming the need for more complex control room technology is "an excuse to delay scaling up VPP projects." However, he also acknowledged that Sunrun "dispatches its own DER fleet" and is not integrated with utility operations.

Brattle's Hledik added that to achieve "large-scale, real-time grid balancing services, VPPs may need direct access" to utility operating systems.

Martin Milani, CEO of Sunverge Energy, said that to provide system stability services, the Sunverge-Delmarva Power-PJM Interconnection 500-kilowatt VPP project in Elk Neck, Maryland, must meet PJM's "real-time operational requirements." He added that the project must provide two-second telemetry, two-second meter scanning, and aggregator response in under ten seconds.

Milani said: "Scaling VPPs and providing the full suite of system services will require state regulators to approve investments in faster telemetry, metering, and communication systems."

Nevertheless, Sunrun's Rauscher said: "Any utility considering resource procurement should compare the peak generation cost of VPPs with the cost of near-term alternatives."

However, attracting consumer participation in virtual power plants at the scale DOE and Brattle predict raises other issues. Utilities, VPP service providers, and analysts broadly agree on this.

Attracting participation with compensation

VPP distributed energy resources are typically customer-owned, making them cost-effective for utilities and system operators compared to traditional infrastructure investments. But many stakeholders say customer-owners must see the value proposition in participating.

Ed Smeloff, an independent consultant at the Center for Energy Efficiency and Renewable Technology, said: "The biggest issue right now is cultivating market drivers."

Smeloff said California's "Demand Side Grid Support program" is a driver for customer-owned DERs "moving toward full market participation" because it compensates VPP aggregators for using these resources to reduce load during peak demand periods. He added: "As interconnection rules and communication standards for larger VPPs providing more system services are developed, more market-integrated compensation mechanisms will also emerge."

Smeloff said: "Customers will also need to learn to trust that limited third-party control of their DERs won't harm the value of their investment and can lower their electricity bills." He added: "This will require utilities and aggregators to recognize that customers have different values and intentions for their DERs."

Pearl Donohoo-Vallett, Director of Regulatory Strategy and Services at Pepco Holdings, parent company of Delmarva Power, said the Delmarva Power-PJM-Sunverge pilot is facing this challenge. She added that Delmarva "provides batteries to customers for free, on the condition that the utility can control them when demand drives up prices, but customers want to keep the batteries for their own backup power."

Donohoo-Vallett said Delmarva is currently working to balance "customer needs and evolving system needs." She added that the more system services DERs provide, "the greater their value, and the higher the compensation to customers."

Duke Energy's Huber noted: "The economics of a scalable program must attract participation, but it must also be cost-effective for all utility customers."

But Benjamin Hertz-Shargel, Global Head of Grid Edge at Wood Mackenzie, responded that some current pricing given to VPP aggregators and DER customer-owners "does not provide an attractive price signal for participation."

Hertz-Shargel said grid operators in New York and New England compensate VPPs for wholesale energy capacity. But he added that compensation for distribution system value, such as National Grid's ConnectedSolutions program and Consolidated Edison's Distribution Load Relief program, would make "the value proposition to customers more attractive."

Mathew Sachs, Senior Vice President of Strategic Planning and Business Development at leading VPP service provider CPower, Jamie Charles, Policy Manager for Grid Services at Sunnova, Sunrun's Rauscher, and National Grid's Tom also all endorsed ConnectedSolutions and California's Demand Side Grid Support program.

Tom added that VPPs can also benefit customers through "time-of-use rates." He said, "Flexibility markets can recognize the timing and magnitude of demand created by local constraints and compensate aggregators for meeting that demand, while avoiding the costs of traditional infrastructure solutions."

Stakeholders agree that state regulators will play a central role in addressing compensation issues, including approving cost recovery for technology investments and setting customer compensation standards that encourage participation.

The role regulators can play

DOE's Shah acknowledged that Federal Energy Regulatory Commission (FERC) Order No. 2222 "opened the door for VPPs to compete in organized markets," but much work remains.

Sunrun's Rauscher said Order No. 2222 "started a useful conversation." It could "open wholesale markets within the next decade" and "serve as a lever for scaling VPPs," but Rauscher added that current regulatory efforts to further advance VPPs have "returned to the state regulatory and utility level."

Brattle's Hledik said state regulators can streamline scaling efforts by proactively conducting "jurisdiction-specific VPP market potential studies" and using those studies to "set VPP procurement targets." He added they can also improve the viability of VPP pilots through "innovative utility financial incentives" and "updating existing policies."

Pepco Holdings' Donohoo-Vallett said utilities can also help regulators understand "the need for foundational investments," namely upgrading control room and communication systems to high-speed levels to meet VPP scaling needs. He added: "These expenditures will help leverage the benefits of DERs and VPPs to achieve a more economical energy transition."

CPower's Sachs said long-term planning that identifies future load reduction or stability service market needs can enable VPP service providers to proactively build to meet those needs while also reducing costs. He added that service providers can proactively initiate significant investments in technology and customer acquisition and education where planners foresee these needs, and be ready to deliver system benefits faster and more cost-effectively to meet them.

Hertz-Shargel added that if planners recognize the full value of VPPs at both the transmission and distribution system levels, they will likely find that the costs avoided by scaling VPPs make them "more cost-effective than traditional resources."