Virtual Power Plants

Upwardly revised mid-range forecasts for peak power demand, rising utility capital investments and more common and costly extreme weather events are increasing pressure on the U.S. electric grid and underscoring the need to deploy virtual power plants at scale, the U.S. Department of Energy said this month.

Utilities, aggregators, regulators and other energy system stakeholders can enable deployment of 80 GW to 160 GW of VPP capacity by 2030 by encouraging expanded distributed energy resource adoption, simplifying VPP enrollment, standardizing VPP operations, and integrating VPPs into utility planning and wholesale markets, DOE said in its updated Pathways to Commercial Liftoff: Virtual Power Plants report.

To accelerate DER adoption and VPP deployment during President-elect Trump’s second term, stakeholders should focus on “nonpolitical” benefits like grid resilience, energy security, avoided costs, consumer choice and self-determination, experts told Utility Dive.

The United States had about 30 GW of VPP capacity in 2024, DOE said in the updated report, released on Jan. 1. That figure is lower and more precise than the “30 GW to 60 GW” capacity estimate provided in the original version of its VPP Liftoff report, published in September 2023.

DOE made the adjustment “based on Wood Mackenzie’s North America VPP Market Report, which estimates that there is 33 GW of VPP capacity in North America with the majority considered to be in the U.S.,” it said in the updated report.

Characterizing North American VPPs as “well past pilot scale,” Wood Mackenzie’s July 2024 report noted 1,459 operational or in-development VPP deployments participating in 321 market, utility and retailer programs.

But VPPs represent less than 20% of total DER capacity and remain dominated by residential thermostat and commercial and industrial demand response programs, Wood Mackenzie found.

As Republicans prepare to take full control of the federal government on Jan. 20, VPP advocates should look to messaging that has resonated with regulators, policymakers and consumers in GOP-controlled jurisdictions like Texas and Utah, said sonnen USA CEO Blake Richetta.

“If presented properly, VPPs can be viewed positively by both quote-unquote conservatives and quote-unquote progressives,” Richetta said. 

DOE’s updated liftoff report hailed the Wattsmart VPP, deployed in Republican-controlled Utah by Rocky Mountain Power in partnership with Richetta’s company, as “among the most advanced VPP[s] in the U.S. due to its degree of integration into the utility’s overall system operations and the wide array of use cases (grid services) of the battery aggregation.”

Grid-optimizing VPPs like Wattsmart appeal to progressives by enabling increased renewables deployment, but in Utah, policymakers and regulators were “so proud that they didn’t have to raise taxes or [utility] rates to make it happen,” he said. 

The potential for VPPs and even less sophisticated DER clusters to reduce grid stress — and related costs — from new data centers, factories and other large loads is another benefit with broad appeal, said Rábago Energy principal Karl Rábago. After factoring in lower line losses and avoided infrastructure costs, “a 5-MW distributed facility is almost as economical as a 500-MW [utility] facility,” he said.

Independent analyses bear out VPP advocates’ cost-reduction claims. An October 2024 study coauthored by AES Indiana and Camus Energy found a grid-optimized managed EV charging program could save “close to $1 billion in cost overruns over the next decade, with savings going directly to consumers,” DOE said in the updated liftoff report, while an April 2024 Brattle Group report said California could pass about $550 million of an estimated $755 million in annual avoided power system costs to consumers by deploying a wide mix of VPP programs.

 As localized, redundant energy resources, VPPs also improve energy security and resilience, which have broad support across the political spectrum, said Luminary Strategies founder and CEO Arushi Sharma Frank. But the idea of producing and consuming power locally, with less interference from governments and monopoly utilities, also happens to resonate in particular with conservatives, she added.

DER and VPP advocates anxious to boost adoption should also make space for the non-political levers DOE identified in the updated liftoff report, experts said. For example, streamlined program design and interoperability standards are crucial to remove barriers to wider VPP participation, according to Sharma Frank.

“The technical challenges are so much more important to get right than figuring out which political bucket this fits in,” she said

The Electric Reliability Council of Texas is considering doubling the size of a virtual power plant pilot project, in addition to making a slate of other changes aimed at growing the underutilized program.

The aggregated distributed energy resource pilot, or ADER, launched in 2022 with a goal to harness 80 MW of flexible resources, primarily batteries, on the ERCOT grid. But so far only Tesla and Bandera Electric Cooperative have brought aggregations to the grid, accounting for about 15 MW. 

The ADER project aims to evaluate the participation of aggregated distributed resources in the ERCOT wholesale market, but experts say initial limits on the program have kept it from achieving its goals.

Commissioner Jimmy Glotfelty has helped lead the ADER effort from the Public Utility Commission of Texas, working as a liaison to the task force which developed the initial rules for the pilot project with the grid operator.

“I’m happy with where we are,” Glotfelty told Utility Dive. “But there are some things which need to change” about how the program is set up. “Success, to me, is if in three years, or two years, we have 300 MW or 500 MW and it's a general part of the market system.”

At a time when Texas energy demand is rising and the state is rushing to add resources, lawmakers have taken an interest in the ADER program and how it can help keep the state’s electric grid reliable.

ERCOT Senior Vice President and Chief Operating Officer Woody Rickerson testified before the Texas Senate Committee on Business and Commerce in October, discussing challenges which have limited the ADER program. Whereas the grid operator has typically focused on larger, transmission-connected resources that might be 100 MW in size or larger, ADER focuses on pulling together resources around 0.1 MW in size, operating at lower voltages.

“That’s not something ERCOT has typically had any hand in,” Rickerson said. 

“It sounds like a lot of work to get 15 MW,” said Sen. Charles Schwertner, a Republican and chair of the Senate Committee on Business and Commerce. 

“It has been a lot of work, but I do think it has some potential,” Rickerson replied.

Difficulty in getting DER aggregations to respond to precise grid signals has been one barrier to their participation in the ERCOT market. “We’re opening up a new phase where there will be bigger signals so [aggregations] won’t have to be as precise,” Rickerson said.

There are also potential changes to how qualified scheduling entities, or QSEs, represent aggregations in the market. In ERCOT, QSE’s submit bids and offers to ERCOT on behalf of resource entities or load serving entities, charging fees for their service. And ERCOT does not allow aggregators to bundle aggregations across load zones, further raising costs for aggregators.

“That is the number one barrier to entry” to ADER participation, said Arushi Sharma Frank, founder of energy consulting firm Luminary Strategies. Sharma Frank participates on the Public Utility Commission of Texas’ ADER task force through her company, and formerly served as vice chair when she worked for Tesla.

While large, centralized generators have revenue potentials that are much larger than the cost of telemetry systems and other QSE costs, ADERs have a break-even point around 15 MW to 20 MW, Sharma Frank wrote on behalf of Tesla in 2023 in a task force memo. “This scale is at or above current QSE caps, which must be increased,” she wrote, referring to the ADER pilot’s initial limits. 

Sharma Frank says a host of barriers to entry have limited the ADER pilot’s size.

“We were far too conservative on Day One of the pilot because it was new,” she said. The 80 MW cap was too low, and it was split across eight settlement zones creating multiple smaller caps. Other limits — such as what services the pilot could provide to the ERCOT market — have also kept the program from fulfilling its potential, she said.

The caps and limits “create a depressing signal on market interest,” Sharma Frank said. “You can't create a model of what you could get out of a program at its zenith, if what the regulators give you up front is a bare fraction of that, and there's no certainty of opportunity.”

The commercial and strategic work required to pull off complex, multi-party relationships in the ERCOT market, like the ADER pilot, “fundamentally rests on there being such a huge number on the other side, of value, that all these folks can come in and sit at the same table and agree to split that value,” Sharma Frank said. “That's the opportunity that was missing.”

Glotfelty has also pressed for consumers to be able to register their equipment with the aggregator of their choosing. In particular, he has expressed concern that Tesla Powerwalls are only able to participate in the ADER project through a Tesla retail provider.

“We have an open market in Texas, and choosing how you want to be a part of a resource group should be part of that,” he said.

The task force is hoping to address many of the barriers with an update to the pilot’s governing documents. ERCOT has just completed a first pass of those changes and sent red lines of the governing documents back to the group. Those changes will be reviewed at a Dec. 18 meeting.

If the task force agrees with ERCOT’s changes, then the grid operator will complete a final review and the changes go to the commission for approval. The first quarter of next year seems to be the “right guess” for when that will happen, Sharma Frank said. She expects the market can respond to the ADER updates within a year because so much time has already been spent addressing technical issues.

The changes 

The first and second phases of the ADER pilot limited the combined registered capacity of all ADERs to 80 MW and subsequently split the services they could provide, 40 MW each between ERCOT’s ancillary non-spin and contingency reserve services. The grid operator is now proposing to increase those limits to 160 MW and 80 MW, respectively, “to allow the pilot to continue to grow and evolve,” according to task force workshop documents from the Nov. 18 meeting.

The proposed changes also include allowing aggregations to participate in the ADER project through a new Aggregated Non-Controllable Load Resource framework, or A-NCLR, which will accommodate more “blocky” responses from aggregations struggling to meet telemetry requirements.

“Blocky” refers to larger loads coming off the system in chunks, as opposed to smaller amounts of capacity.

NCLRs are typically large demand response resources on the ERCOT system that respond in bigger chunks than the 5-minute granular responses the ADER pilot initially required from devices.

“Some of the technical requirements for participation in some of the ancillary services are a little onerous,” Glotfelty said. “And they are onerous for a reason — to ensure that we could, in this first phase, aggregate different amounts of load across regions, and that we could find ways to ensure that the market signals and the pricing was set accurately.”

Now the task force is looking for ways to “tear down barriers” to resource participation, he said.

“The A-NCLR framework makes both communication to and from an aggregation of devices, and the response, easier and cheaper for the participants to provide, and more blocky in how ERCOT views it, which is just an extension of how ERCOT already receives blocky responses from large loads today,” Sharma Frank said.

The proposal also opens the door to bundling aggregations, Sharma Frank said.

“Because the response is blocky, the technical back-end work that one QSE has to do should decline sharply, and we should be able to take multiple entities’ aggregations through a single chain of command to ERCOT,” Sharma Frank said. “It would completely change the barrier-to-entry problem.”

As for issues of interoperability, and moving equipment from different manufacturers between aggregators, Sharma Frank expects those issues will be addressed as the market expands.

“The interoperability challenge in Texas is related to ... the suppression of economic growth value,” she said. Equipment manufacturers are not going to spend money to integrate with new providers if the revenue opportunity is small, she said.

Beyond batteries

The future of DER aggregations in Texas will hinge on the effective integration of resources and expanding what types of resources can be aggregated, John Padalino, chief administrative officer and general counsel of Bandera Electric Cooperative, told the Senate Business and Commerce committee. Bandera is one of the two ADER aggregations operating today, along with Tesla.

In 2017, Bandera developed Apolloware, an appliance-level electric meter that can provide real-time energy feedback, Padalino said. It can connect devices from different manufacturers while also meeting ERCOT’s telemetry requirements.

While a limited number Texas homes have battery backup systems, Padalino said about 1.3 million do have smart thermostats. “If we convert just 40,000 thermostats into registered ADER participants, we can achieve the 80 MW goal,” he told lawmakers.

For now, the ADER program is largely designed to accommodate small devices capable of dispatchable exports of energy to the system, Sharma Frank said. But the changes to allow for blockier load participation could mean more types of devices are enrolled.

NRG and Renew Home announced last month they are partnering to deploy hundreds of thousands of smart thermostats across Texas to support a residential virtual power plant with nearly 1 GW of capacity by 2035. The VPP is not a part of the ADER project but “speaks to a large-scale effort to increase our VPP capabilities in ERCOT,” NRG said in a statement. 

Reliant, NRG’s flagship retail electric provider in Texas, has an aggregation that is registered with the ADER pilot and is undergoing testing with ERCOT, the company said.

Sharma Frank said NRG’s announcement is “a follow on to the fact that ADER has created a roadmap for revenue certainty.”

“No one entity had ever successfully put out lots of megawatts from an aggregation of sub 1-MW sites. Now that we're actually doing it, ERCOT is learning a lot from that process and they're creating validation around the technology,” Sharma Frank said. “It has made the market opportunity more meaningful, scalable and more certain, because it's actually happening.

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By Virtual Peaker

Virtual power plants have taken on a new life, as technologies have evolved to support the complex technological ecosystem—the Internet of Things (IoT)—required to realize virtual power plant functionality. The Department of Energy (DOE) has called for an increase in national virtual power plant capacity from the current 30-60 GW of VPP capacity to 80-160 GW by 2030. The DOE identifies virtual power plants as any “connected aggregation of distributed energy resources (DERs)” that integrates and leverages renewable energy for demand flexibility initiatives like demand response, EV charging, BYOD programs, and more.

Through the use of a grid-edge distributed energy resource management system (DERMS), utilities can leverage the growing number of behind-the-meter DER asset adoptions to shift load to off-peak hours of usage, enhancing grid resiliency, while in turn defraying high peak energy costs from energy markets. Fortunately, with the right grid-edge DERMS, grid operators and program managers alike can increase virtual power plant capacity under one single solution, saving development time, minimizing annual recurring fees, and lowering employee training times while expediting program deployment.

Conservation Programs: Demand Response & EV Charging

Last year’s DOE report revealed that the 30-60 GWh of aggregate virtual power plant capacity currently available in the U.S. stems from demand response programs. Demand response is a conservation strategy that calls upon participants to mitigate usage during grid events, which typically correspond with temperature extremes. Likewise, EV charging programs similarly conserve energy, by shifting charging times to off-peak hours of usage. In both cases, energy saved is money saved: by minimizing the amount of power needed during peak hours of demand, utilities can enhance grid resiliency, while minimizing the need for costly peak energy purchases.

Grid Resiliency & Energy Arbitrage: Solar & Battery Programs

Solar and battery programs offer parallel opportunities for utilities to meet demand during peak periods of consumption. Using a grid-edge DERMS, utilities can aggregate excess ambient renewable energy to resupply the grid as needed. Similarly, just as demand response and EV charging shift usage to off-peak hours, battery charging periods can be adjusted to meet grid needs, presenting yet another opportunity for potential conservation or load shifting. Beyond this, battery programs in particular are useful for energy arbitrage, the practice of purchasing (or storing) power during off-peak hours to use during peak periods of demand. Doing so defrays high peak energy costs, while in turn providing a fresh supply of energy to meet demand.

The Challenges of Multi-Source Procurement

Virtual power plant strategies are driven by many factors from regulatory requirements to energy arbitrage and beyond. As such, some utilities feature internal silos unique to each specific program type, whether that’s demand response, EV charging, or more. Unfortunately, this can lead to a complex maze of single-solution services that are not designed to integrate and represent multiple instances of annually recurring fees. For example, if a utility utilizes multiple solutions for different demand flexibility programs, what happens if your solution provider closes? In some cases, that can lead to unhappy customers, missed revenue opportunities, and decreased grid resiliency. Additionally, a multi-source procurement strategy minimizes potential opportunities for utilities, while adding unnecessary costs.

All-Source v. Multi-Source Procurement Conclusion

Analysts report that increasing virtual power plant capacity by 2030 could help reduce costs in the power sector by $17b by the same year. Furthermore, as decentralized energy assets, virtual power plants can prove useful during volatile storm events, especially when infrastructure is badly damaged. Still, while virtual power plants are a provably valuable strategy, these benefits rapidly dwindle as administration costs mount.

With a multi-source solution, utilities face multiple fees and fee structures, including paying for APIs, integrations, and more to multiple third-party vendors. Likewise, multi-source virtual power plant strategies require multiple training; likely don’t share data easily, minimize forecasting potential; and slow programmatic deployment. Put another way: with the right grid-edge DERMS, the DERs necessary for your demand flexibility programs can be controlled, managed, and analyzed by one, integrated platform, allowing utilities to own the entire customer experience.

The growth of virtual power plants, which are large portfolios of consumer-owned distributed resources, is about to get a big boost.

VPPs could meet as much as 160 GW of the 200 GW of U.S. peak demand needs in 2030, and reduce power system costs by $10 billion annually, according to a 2023 report from the Department of Energy. But VPP growth could be limited by the lack of common standards in their aggregated distributed energy resource components, developers and advocates say.

Common standards allow utilities or aggregators to “orchestrate” diverse DER like rooftop solar, batteries and electric vehicles in a full range of power system services, proponents say.  

“Without interoperability standards, VPPs cannot reach scalability, affordability, and reliability as soon or as efficiently as they will be needed” to meet the coming variability, growing load and extreme weather events the power system faces, said Arshad Mansoor, CEO of the Electric Power Research Institute, which is leading two standardization initiatives. “Now is the time to bring VPP stakeholders together,” he added.

Standardized interoperability can help simplify and expand the needed adoption of DER and the needed integration of VPPs into utility planning and wholesale markets, the DOE report said.

System operators “must have visibility of connected DER devices, be able to signal the devices, and be confident they responded to the signal,” said Lon Huber, senior vice president, pricing and customer solutions, with Duke Energy. For that, “the entire VPP ecosystem should be standardized by a multi-stakeholder collaborative,” he added.

The big unanswered questions advocates are now confronting, however, are what the standards should be and what technologies will be needed to optimize performance. EPRI, international software platform provider Kraken and others are joining to acknowledge and answer these questions.

Flexibility becomes vital

Transportation, building and industrial electrification will lead to new electricity demand dynamics, including higher and more time-varying demand spikes, analysts agree.       

VPPs can make automatic small shifts in customer energy use to “when electricity is cheaper and cleaner,” said Ben Brown, CEO of Renew Home, which operates 3 GW of VPPs and is targeting 50 GW by 2030. “Demand flexibility across thousands of homes” is “a significant peak capacity resource” and “helps balance power system supply and demand,” he added.

VPPs are “likely the only way” to manage electrification “at a reasonable cost and on the timeline we need,” DOE Loan Programs Office Director Jigar Shah said in a recent interview.

With the enormous growth of electricity load, the flexibility of VPPs “is the only way to match demand and supply,” agreed Sunrun Head of Grid Services and VPPs Chris Rauscher. Demand from electrification will grow but VPPs “will consistently bring down the peak,” and “create incremental capacity” on the power system, he added.

VPP flexibility has also strenghtened resource adequacy in California and Arizona, relieved stress on transmission and distribution systems in New York, and reduced system costs for customers in Utah and Vermont, according to a September Rocky Mountain Institute report.

But “fully realizing” VPP flexibility will require full integration of VPPs into power system planning and operations, the report said. And device standards to ensure more consistent, reliable dispatch — and more accurate and timely dispatch signals are “critical” to VPP integration — it added.

The “potential $10 trillion” cost to upgrade the U.S. distribution system to meet current electrification goals can also be avoided by “a system that rewards flexibility,” said Kay Aikin, CEO of distribution level software solutions provider Introspective Systems.

Using flexible VPPs allows “staged distribution system investment” as load grows, Aikin said. “Many utilities are beginning to see VPPs relieve system congestion, and their interest in flexibility is growing,” she added.

A key step toward flexibility is DER interoperability standards, EPRI and other advocates say.

Standards to meet complexity

The aggregation of customer-owned devices at the distribution system level introduces a new complexity into power system and market operations, industry stakeholders agree.

Many, even in the electric power industry, do not realize how limited visibility into the distribution system is in today’s legacy distribution system, said Association of Edison Illuminating Companies Vice President, Technical Strategy, Elizabeth Cook. “Regulators and policymakers need to allow utility investments in foundational distribution system sensor and measuring technologies,” she added.

The communications technologies and software platforms now being used “are not dynamic enough” to capture the potential benefits of today’s dynamic DER technologies, Cook continued. But obtaining the needed distribution system baseline information and modeling data will require “a systematic overhaul” of technology and operations, she said.

To advance the overhaul, and enable VPPs to provide system flexibility and reliability, EPRI and Kraken are launching their Mercury initiative to develop interoperability guidelines and practices for DER, said Kraken Chief Marketing and Flexibility Officer Devrim Celal. The initiative will begin by developing a leadership group of VPP stakeholders, Celal said.

Like the Bluetooth Special Interest Group that was founded in 1998 and developed wireless device standards, VPP stakeholders will identify DER communications protocols, Celal said. The greater visibility and more accurate control of the component devices “will enable VPPs to better balance loads, reduce system congestion, and interact with wholesale markets,” he added.

An effort will follow to bring an even wider range of VPP stakeholders into EPRI’s Flexible Interoperable Technologies, or FLEXIT, initiative. The initative’s objective is to go beyond Mercury by simplifying DER integration “through standardizing service definitions and interfaces; and to develop a future-proof implementation strategy,” EPRI said.

“Diverse stakeholders including utilities, DER manufacturers, VPP aggregators, researchers, and government agencies, will help develop a public VPP aggregation and technical framework for a utility-to-aggregator interface,” EPRI’s Mansoor added.

Because current VPP-utility interfaces are unique to each aggregator or utility, VPP integration requires costly “custom software” and “months or years” to complete and implement, Mansoor said. “In the worst cases, the effort required outweighs the benefits,” but standardization and interoperability can change that, he added.

“VPPs are built and used now, but they will not be scalable, reliable, and affordable without standardization and interoperability,” Mansoor continued. “VPP flexibility will still be valuable as energy, capacity, and ancillary services, but manufacturers will not invest in enabling VPP products, and the value will not be fully integrated into markets,” he said.

Key stakeholders agree.

With multiple technologies working together, VPP deployment “can scale to serious numbers,” said Duke’s Huber. Standardization through “a multi-stakeholder collaboration” will allow the needed system visibility, controls and communications for “device discovery, device enrollment, device orchestration, and device data exchange” in VPPs at scale, he said.

Another effort to streamline VPP deployment is a model tariff designed by law firm Keyes and Fox for Solar United Neighbors “to set compensation at the full value of the service,” said Keyes and Fox Partner Beren Argetsinger. They also designed model legislation to expand VPPs into new jurisdictions, he added.

Further DER standardization is not necessary for Sunrun, which primarily provides residential solar-plus-storage VPPs that are already “operating at scale with reliability and predictability,” said Sunrun’s Rauscher. “Utility program administrators do, however, need to standardize software for automated notifications of the need for peak load reductions to aggregators and customers,” he added.

Other stakeholders see the need for more fully standardized interoperability among utilities, aggregators and DER technologies to enable VPPs to earn the full value they can provide.

From standards to value

More value will come as VPPs expand from residential solar and storage to the full range of smart customer-owned DER technologies with standardized interoperability, including electric vehicle chargers and smart thermostats and home appliances, aggregators and utilities said.

Currently, monetizing VPPs is largely limited to “the portion of value that doesn’t require advanced controls and communication,” said Brattle Group Principal Ryan Hledik. But “streamlined communications” allowing “improved interoperability” can make managing the “fragmented set of technologies and software packages” affordable, he added.

A grid edge distributed energy resources management system, or DERMS, can streamline communications, Hledik and other VPP advocates said.

A grid-edge DERMS is the middle layer between customer-owned devices and the dispatch of devices in response to utility signals, said Erika Diamond, senior vice president and head of customer solutions for DER aggregator EnergyHub. An aggregator’s software can make a VPP operational and cost-effective within months and relieves the utility of grid-edge complexities, she added.

A grid-edge DERMS can use aggregated DER “to replace traditional resources,” agreed Schneider Electric Digital Grid Product Marketing Manager Monika Jovic in a July webinar.

Different opinions among aggregators about the need for DERMS may depend on the DER components of a VPP.

Each utility wants to manage its distribution system resources differently, said Sunrun’s Rauscher. “Any utility in the country can have a VPP program today” using residential solar and storage because aggregators have already made the needed investment in independent software platforms, he added.

Sunrun can also manage DER other than solar and batteries and is integrating devices like smart thermostats and heat pumps, Rauscher continued. But “there is a cost for that,” and the longer-term revenue certainty does not justify the cost of integrating “with each individual utility software platform,” he added.

The Mercury and FlexIt initiatives are intended to establish interoperability standards that expand the range of potential VPP resources while returning value for the services they provided, other VPP stakeholders said.

“A solar and storage VPP may run without a DERMS, but a grid-edge DERMS could enable any DER device to be a grid asset,” Diamond said. “Utilities are adopting individual DER programs but don't know how to value a program that can dispatch the many different customer-owned DER across the distribution system 24/7 to meet system needs,” she added.

The visibility provided by a DERMS gives operators a “surgical” ability to use the customer-owned DER at specific locations in specific ways to meet specific needs, agreed Brattle’s Hledik. “Coordinating and simplifying” supply and demand balancing may not, though, streamline the integration of VPP operations with the many utility tariffs and programs and diverse markets, he said.

But standardization and interoperability will enable utilities to affordably scale VPP products so that markets will value and respond to them, EPRI’s Mansoor said. And that will lead to market rules that can integrate those products, he added.

“The power system is likely to need a lot of flexible resources in the coming decade,” EnergyHub’s Diamond said. “It will take all the flexible resources that are available,” and the projected value of that flexibility is likely to make VPPs “totally scalable and affordable,” she added.

The Mercury Initiative launches Dec. 5, the FlexIT Initiative will follow early in 2025, and as key power sector stakeholders join, their input will determine the course of the initiatives’ development, EPRI’s Mansoor said.

Technologies like device-level submetering and bidirectional electric vehicle charging create opportunities to deploy virtual power plants at scale in the near future, panelists said Sept. 16 on a webinar hosted by Advanced Energy United.

Successful VPPs like National Grid’s ConnectedSolutions and the California Energy Commission’s Demand Side Grid Support program demonstrate the benefits of simple, flexible and technology-inclusive program design, panelists from EnergyHub, PowerFlex and Ford Motor said.

But VPP uptake is held back in many markets by a lack of clear state policy directives, regulatory uncertainty, barriers to full wholesale market participation and continued risk aversion among utilities, they added.

Virtual power plants have tremendous potential to shape load and reduce stress on the grid during periods of peak demand, said panelist Carter Wood, who works on electric vehicle infrastructure policy at Ford.

Wood nodded to an April study from Brattle Group that found VPPs could meet 15% of California’s projected peak load in 2035, up from 3% today. That level of deployment — about 7.7 GW — could avoid $755 million in traditional power system costs and reduce consumers’ annual electricity bills by $550 million, the study found.

Bringing VPP capacity onto the grid takes far less time than building a new physical power plant, said panelist Nick Papanastassiou, director of market development and regulatory affairs for EnergyHub, a distributed energy resource management platform.

EnergyHub partnered with Ontario’s Independent Electricity System Operator to enroll more than 100,000 smart thermostat users in less than six months in a VPP that delivered 134 MW of load response in a single hour this summer, Papanastassiou said. 

Alongside stationary energy storage, solar arrays and other distributed energy resources, bidirectional-capable electric vehicles represent a massive future source of potential VPP capacity, said Raghav Murali, head of policy and compliance at PowerFlex, a clean energy infrastructure provider for commercial and industrial users. But achieving that potential would require the right policy and regulatory support in place, he added.

“[There is] a whole stack of technology that can be included in this business model, but there are regulatory barriers that need to be worked out,” Murali said.

As examples of policy and regulatory progress, Murali singled out recent Maryland legislation that requires utilities to submit vehicle-to-grid and VPP plans for regulator approval next year, and the California Energy Commission’s modification of DSGS rules that allows EVs to participate.

These efforts to enable more resource types to participate in VPPs are an important first step, but the notion of “NEM integrity” — the need to account for the sources of electrons exported to the grid — remains a barrier to EV participation in many VPPs, Murali said. 

Other barriers to wider VPP deployment — and uptake among consumers — include undervaluing of distributed energy resources’ potential grid benefits by utilities and grid operators and a broader information gap about VPPs benefits among utilities, Papanastassiou said.

“There is still a lot of education we can do as an industry,” he said.

More fundamentally, utilities tend to see “steel in the ground” as more profitable than leveraging distributed resources or other existing technologies to avoid current or future costs, Wood said. But “[they] are doing some great things despite … that disconnect,” he added.

Overcoming ongoing barriers for DERs to fully participate in wholesale markets, per the intent of FERC Order 2222, is crucial, Wood said. Minimum sizes for individual DERs participating in a DER aggregation and restrictive single-node aggregation rules are just two of the half dozen obstacles to the order’s full implementation, Guidehouse Insights said in a December 2023 white paper. Around a dozen states continue to prohibit distributed resources’ participation in wholesale markets.

The value of bidirectional-capable EVs is today realized almost entirely at the distribution grid level, but wholesale market bidding would expand the range of grid services available to them, Wood added.

VPP programs themselves should be designed from “a consumer-centric perspective” that drives enrollment and limits attrition, Papanastassiou said. Successful programs tend to give customers compelling incentives to participate, offer a simple enrollment process supported by effective marketing and operate in a way that doesn’t actively inconvenience participants, he said.

Consumer-centric design might not be comfortable for utilities accustomed to the traditional demand response paradigm, but streamlined, technology-inclusive VPPs like ConnectedSolutions show it’s possible, Murali said. VPP operators should avoid onerous terms and conditions that may deter participation, like stiff penalties for failure to meet performance criteria, while following the “8 ½ by 11 principle,” he said.

“If it’s too complicated to fit on a sheet of paper, it’s too complicated for customers to buy into,” he said.

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.

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.

Virtual power plants can affordably and reliably help to meet summer electricity demand on a U.S. grid that’s increasingly vulnerable to supply disruptions during extreme heat waves, RMI said in a report released earlier this month.

The more than 500 U.S. VPPs in operation today can be dispatched to meet summer grid needs in 2024, and new VPPs can be planned and deployed in as little as six to 12 months, making them available as soon as next summer, RMI said.

“We’re not trying to argue that VPPs are the only solution, but we want to make sure they have a place in that conversation,” said Kevin Brehm, a report co-author and manager in RMI’s carbon-free electricity practice.

Seven broad areas of the North American electric grid are at risk of weather-driven electricity supply shortfalls this summer, including portions of Texas, New England and the Midcontinent Independent System Operator territory, according to the North American Electric Reliability Corporation’s 2024 Summer Reliability Assessment.

Regional grids face even greater risks in the near future if utilities’ expectations for near-term demand growth bear out, RMI said. Grid planners expect peak demand growth of 38 GW through 2028, mostly driven by new manufacturing, industrial and data center facilities, Grid Strategies said in December.

Utilities can deploy VPPs much faster than new generation or transmission assets and reduce the longer-term need for significant new capital investments, RMI said. RMI cited Brattle Group research from last year that found U.S. utilities can meet resource adequacy needs and avoid $15 billion to $35 billion in conventional investments over 10 years by deploying 60 GW of VPP capacity.

RMI highlighted three utility VPP programs that achieved “peak coincident capacity” within 12 months:

• The Ontario Independent Electricity System Operator’s Save on Energy Peak Perks program, which enrolled 100,000 homes within six months last year and can reduce peak summer demand by up to 90 MW.
• The California Public Utility Commission’s Demand Side Grid Support VPP, an emergency reliability program for non-investor-owned utility customers that launched in 2022 and achieved 142 MW of committed capacity within a year.
• The aggregate distributed energy resources, or ADER, pilot in the Electric Reliability Council of Texas wholesale market, which launched in 2022 with an initial capacity of 80 MW. In December, ERCOT expanded the ADER pilot and cleared ADERs to participate in its contingency reserve service, RMI said.

VPP programs will become more diverse and sophisticated as a wider variety of distributed energy resources appear in volume at the grid edge, complementing foundational DERs like smart thermostats and commercial demand response, Brehm said. 

Last year, a PG&E and Sunrun VPP pilot enrolled 8,500 customer batteries within six months to address summer evening peaks while Rocky Mountain Power’s WattSmart program continues to dispatch thousands of customer batteries daily to manage demand peaks, RMI said.

Puget Sound Energy’s VPP programs use a wider array of DERs to meet summer peaks, including smart thermostats, behavioral load shaping, electric vehicles, water heaters and interruptible loads, RMI said. 

RMI provided more details on these and other U.S. VPP programs in a flipbook released last month.

Summer peaks will present the biggest seasonal challenge for most utilities and grid operators over the next decade, but lessons learned using VPPs to manage warm-season demand could be useful as cold-season electricity use increases, Brehm said.

Utilities and grid operators will need to “get clear on which DERs can be brought to bear most effectively to manage winter peaks,” which have different shapes, profiles and durations than summer peaks, he said. For example, smart thermostats “are a fantastic solution for summer peaks” but may not be as effective as batteries or EVs in winter, he added.

Though the longer-term success of VPP programs is contingent on DER adoption, technological advancements are likely to enhance their capabilities over time. Compared with current managed EV charging programs, which can only curtail the flow of electricity into plugged-in vehicles, bidirectional EV charging — or vehicle-to-grid — is a more versatile technology that can manage demand peaks and improve grid reliability during supply shortfalls, Brehm said

Well-designed virtual power plant programs integrate multiple energy technologies and vendors, streamline customer experiences during program enrollment and participation, operate for five years or longer and incentivize distributed energy resource adoption to drive further customer participation, RMI said in a flipbook released on June 12. 

The flipbook draws on 15 case studies from states and utilities across the United States, including California’s comprehensive Emergency Load Response and Demand Side Grid Response programs, Rocky Mountain Power’s solar- and battery-focused Wattsmart Battery program, Arizona Public Service’s Cool Rewards smart thermostat program and EV charging management programs operated by Duke Energy, DTE Energy and Xcel Energy. 

The case-study VPPs collectively provide 1.5 GW of capacity from 3.9 million enrolled customers, according to the flipbook.

The case studies show that utilities “don’t have to start from scratch” when designing and deploying VPPs, said Mary Tobin, an associate in RMI’s Carbon-Free Electricity practice and the flipbook’s lead author. Utility program managers can instead “look to their peers across the country [and] apply takeaways from the case studies that are most applicable,” she added.

Most of the VPP programs were developed to address specific utility needs, such as reliability, resiliency or decarbonization, showing that “there isn’t a one-size-fits-all VPP,” Tobin said. Some programs dispatch resources daily, she noted; Hawaiian Electric's Battery Bonus program reduces daily peak load on Oahu by 22 MW, the equivalent of 1% of the system’s installed firm capacity, according to the flipbook.

The flipbook also included three recommendations for “reimagined utility practices”: incorporate VPPs into generation and distribution planning, proactively engage policymakers and regulators around effective VPP policies like performance payments and “transform business practices” to enable more effective VPP design and operation.

While most of the case studies looked at programs serving residential customers, a handful incorporated commercial and industrial customers, including those managed by Portland General Electric, Puget Sound Energy and National Grid.

Those programs were effective in thinking about demand response more broadly by working with commercial customers to identify which connected loads could be reduced when signaled, Tobin said. This process involved more customer education but ultimately resulted in more flexible participation designs that worked for the enrollees, she added.

The flipbook was written with “utilities’ needs in mind” but offers value for utility regulators, grid operators and other electricity system stakeholders, Tobin said.

The impetus for the flipbook was RMI’s observation that utilities are increasingly interested in VPPs as tools to manage projected load growth, thermal generator retirements and higher summer peaks exacerbated by climate change, Tobin said. 

Because the prospect of setting up a VPP can be daunting for utilities that haven’t done it before, RMI wanted to include detailed guidance showing how utilities design VPPs, engage customers in them and use them to provide grid services alongside actionable case studies demonstrating how those actions look in practice across a variety of U.S. markets, she added.

“We hope this becomes a foundational resource to show how VPPs are addressing grid needs,” she said.

 

More than 16,200 residential solar-plus-storage systems will participate in Sunrun’s CalReady virtual power plant this summer, ready at a moment’s notice to supply power to the grid when demand peaks on hot evenings.

Participation in the virtual power plant, operated under the California Energy Commission’s Demand Side Grid Support Program, is nearly double the showing for Sunrun’s first-of-its-kind VPP pilot with PG&E last year. That collaboration resulted in “a real power plant” that peaked at 32 MW and averaged 27 MW over a two-hour peak every day for 90 days straight, Sunrun Head of Grid Services and VPPs Chris Rauscher told Utility Dive.

PG&E does not plan to collaborate with Sunrun on VPPs this year, but the companies are “exploring possibilities for future programs … PG&E sees VPPs as an essential part of California’s clean energy future and is actively looking to integrate more VPP resources into our portfolio and improve their performance as a reliable resource,” PG&E spokesperson Paul Doherty said. The utility expects to have approximately 412 MW of VPP resources this year, he added.

Like PG&E, Sunrun’s Rauscher believes VPPs are ready for prime time despite lingering misconceptions stemming in part from the distributed energy industry’s own marketing missteps. 

“We’ve shown that VPPs provide real value to the grid, utilities and customers, but historically [VPPs] have been victims of their own branding,” he said. Rather than “virtual,” Rauscher prefers “distributed” power plants.

Best practices for simpler, more customer-friendly VPPs

With abundant sunshine, high electricity rates, eco-conscious residents and aggressive decarbonization goals, California is ground zero for VPP adoption. The state hosted 24% of all North American VPP projects, Wood Mackenzie said in a report released March 29, 2023. 

But a Brattle Group report released earlier this year put California 34th out of 50 states in a broader measure of utility-led demand-response capacity, behind smaller states with more robust DR incentives for large agricultural, commercial and industrial users. Rauscher believes residential VPPs can help. 

Sunrun, which sells home solar, storage, EV charging and energy management systems, has nearly 1 million customers in the U.S. But the company needs help from utilities and state regulators to harness those resources into VPPs, Rauscher said.

“VPP programs can be overly complicated, and they don’t have to be,” he said.

Well-designed VPP programs typically cover entire states or utility territories, are “open-access or bring-your-own-device” rather than limited to a particular battery type, meter at the battery level and require no special utility software, Rauscher said. As an aggregator, he added, Sunrun has its own VPP management software and can bring “an entire fleet” of Sunrun subscribers to scale bring-your-own-device programs faster.

Straightforward financial incentive programs like CalReady or New England’s ConnectedSolutions can encourage customer participation in VPP programs, Rauscher said. 

State policy can set the stage for VPP growth as well. California’s solar attachment rate jumped from approximately 10% to 60% after the state enacted its storage-friendly NEM 3.0 net energy metering tariff in April 2023, according to a Lawrence Berkeley National Laboratory technical brief. 

Third-party ownership of solar-and-storage systems in California also surged from 11% to 52% during the same period, in part because larger home energy companies like Sunrun — which leases the majority of its systems — accounted for a higher share of installations, the brief said.

“Our primary customer type is not really an early adopter,” but rather a “busy family” looking to save money and access backup power, Rauscher said. Though financially beneficial in markets with performance-based incentives for home energy systems, VPP participation is often a secondary benefit for Sunrun’s customers, he said.

In Rauscher’s view, targeting early adopters is not the most efficient way to drive VPP participation at scale. He worries this approach could reinforce perceptions of VPPs as complex and inconvenient. It’s better, he said, to reassure customers that participation won’t cause any discomfort and won’t fully drain their batteries while ensuring “[they] don’t have to do anything” to enjoy its benefits.

Showing utilities the value of VPPs

Utilities, grid operators and policymakers are paying more attention to VPPs’ potential as the solar industry matures, driving changes in how and when power is produced and consumed, Rauscher said. High solar penetration on the CAISO grid, for example, means “PG&E has a new peak after sundown,” he noted.

Projected load growth is also sharpening the resource-adequacy case for VPPs, which can be assembled faster than a traditional power plant can be built — or time-of-use tariffs updated — and dispatched in seconds. The Sunrun-PG&E pilot took just six months to roll out, faster than “you [can] turn on any peaking resource in the 30-MW range,” Rauscher said.

Meanwhile, Sunrun’s PowerOn Puerto Rico VPP, the largest participant in the island territory’s Battery Emergency Demand Response Program, supports reliability on a grid that experiences frequent generator outages. When supply falters, Sunrun “pushes max power” from the VPP’s more than 2,000 batteries, giving local utility LUMA time to triage the grid without resorting to rolling blackouts, Rauscher said. 

That has happened “a dozen times since last fall,” Sunrun CEO Mary Powell said in a May 1 press release.

PowerOn Puerto Rico’s success shows that “any utility today can have a VPP program,” even one beset by grid reliability issues, Rauscher said. “[Every U.S.] utility is on a spectrum between PG&E and LUMA.”

Along with new research suggesting broader VPP adoption can defer the need for costly infrastructure upgrades — such as a May 2023 Brattle Group report that found 60 GW of VPP deployment could avoid $15 billion to $35 billion in otherwise-needed capacity investments in the next decade — these real-world “proof points” demonstrate VPPs’ value to utilities and grid operators, Rauscher said. 

Rauscher believes utilities, like their customers, ultimately favor simplicity and clarity when considering new systems and technologies. Fortunately, VPPs’ strongest present-day value proposition — flattening demand peaks — is easy to understand and easy for VPP aggregators like Sunrun to customize for different grids or consumption patterns, he said.

“It’s very easy for us to program batteries to charge during the duck curve,” and then discharge in staged cohorts “to knock down peaks sequentially,” Rauscher said. 

The “more sophisticated stuff,” such as locational value, frequency regulation and other grid services enabled by VPP programs like Utah’s Wattsmart, “should come after” peak-shaving and emergency response, he added. 

But Rauscher acknowledges that in a world where VPPs have truly gone mainstream, Sunrun won’t be the only successful model. 

“There should be room for all different approaches and designs,” he said.

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.

Duke Energy’s just approved 60 MW PowerPair pilot offers a $9,000 upfront incentive to customers who buy batteries and allow limited utility control of them, added Duke Energy Senior Vice President, Pricing and Customer Solutions, Lon Huber. But automated interoperable communications and dispatch “will be critical” to reaching “meaningful scale,” he agreed.

To scale VPPs, Hawaiian Electric will require “smarter, faster” control room and communications technologies for visibility, control and dynamic optimization, agreed company spokesperson Darren Pai.

VPPs are a growing part of National Grid's resource mix, National Grid Director, Future of Electric for Customers, Joshua Tom added. Additional control room and data management technologies are all "really important" to further scale them, he said.

But Chris Rauscher, head of grid services and VPPs for Sunrun, said, “both PG&E’s sophisticated control room operations and Puerto Rico’s LUMA’s fairly rudimentary operations allow partnering in Sunrun VPPs” and “there are no technical, metering or software challenges.”

According to Rauscher, the claim that more sophisticated control room technologies are necessary is “an excuse” for delaying expansion of VPP programs. Sunrun, however, “dispatches its own fleet of DER” without integrating into utility operations, he acknowledged. 

Brattle’s Hledik added that for “real-time grid balancing services at scale, VPPs may need to connect directly” with utility operations.

To provide system stability services, the Sunverge-Delmarva Power-PJM Interconnection 500 kW Elk Neck, Maryland, VPP had to meet PJM’s “real-time operational requirements,” said Sunverge Energy CEO Martin Milani. It had to provide two-second telemetry, two-second meter scans, and under ten-second aggregator responses, he added.

“Scaling VPPs and providing the full range of system services will require state regulator-approved investments in much faster telemetry and metering and communication systems,” Milani said.

Nevertheless, “any utility considering resource procurements should compare VPP peak generation costs with near term costs for alternatives,” Sunrun’s Rauscher said.

But attracting consumer participation in virtual power plants at the scale projected by DOE and Brattle raises other questions, utilities, VPP providers and analysts widely agree.

Compensation to attract participation

The VPP DER elements are typically owned by customers and therefore are bargains for utilities and system operators compared to traditional infrastructure investments, but customer-owners must see the value proposition in participating, many stakeholders said.

“The biggest issue now is developing market drivers,” said Ed Smeloff, independent consultant to the Center for Energy Efficiency and Renewable Technologies.

California’s Demand Side Grid Support program is “a driver toward full market participation” for customer-owned DER because it compensates VPP aggregators for using them to reduce loads at periods of very high demand, Smeloff said. “More market integrated compensation programs will evolve as interconnection codes and communications standards are developed for bigger-scale VPPs offering more system services,” he added.

“Customers also need to learn to trust that limited third party control of their DER will not compromise the value of their investments and will lower bills,” Smeloff said. “That will require utilities and aggregators to recognize customers have different values and intentions about DER,” he added.

The Delmarva Power-PJM-Sunverge pilot faces that exact challenge, said Pearl Donohoo-Vallett, director of regulatory strategy and services for Delmarva parent Pepco Holdings. Delmarva “gave batteries to customers at no charge in return for allowing utility control when demand drives prices high, but customers wanted the batteries for their own backup power,” she added.

Delmarva is now working to recognize both “customer needs and evolving system needs,” Donohoo-Vallett said. The more system services the DER meet, “the more value they have, and the higher the compensation to the customer,” she added.

“A scalable program’s economics must attract participation, but it has to be cost-effective” for all utility customers, Duke’s Huber noted.

But some pricing to VPP aggregators and DER customer-owners “does not provide a compelling price signal to participate,” responded Benjamin Hertz-Shargel, global head of grid edge for Wood Mackenzie.

New York and New England grid operators compensate VPPs for wholesale market capacity, Hertz-Shargel said. But compensation for distribution system value, like National Grid’s ConnectedSolutions program and Consolidated Edison’s Distribution Load Relief program, would “make the value proposition to customers more compelling,” he added.

ConnectedSolutions and California’s Demand Side Grid Support program were also endorsed by Mathew Sachs, senior vice president, strategic planning and business development for leading virtual power plant provider CPower, Sunnova Manager, Grid Services Policy, Jamie Charles, Sunrun’s Rauscher and National Grid’s Tom.

VPPs can also benefit customers “through time-varying rates,” Tom added. And “flexibility markets could identify the timing and magnitude of a need created by local constraints and compensate aggregators for meeting that need while avoiding the cost of a traditional infrastructure solution,” he said.

State regulators will be central to resolving compensation issues, in approving cost recovery for technology investments and in setting compensation for customers that encourage participation, stakeholders agreed.

What regulators can do

Federal Energy Regulatory Commission Order 2222 “opened the door for VPPs to compete” in organized markets, but work remains, DOE’s Shah acknowledged.

Order 2222 “started a good conversation,” said Sunrun’s Raucher. It could open wholesale markets “in the next decade,” and “be a lever for scaling VPPs,” but current regulatory efforts to further enable VPPs have “moved back to state regulators and utilities,” Rauscher added.

State regulators could streamline efforts to scale VPPs by proactively doing “jurisdiction-specific VPP market potential studies” and using them “to establish VPP procurement targets,” Brattle’s Hledik said. They could also make VPP pilots more viable with “innovative utility financial incentive mechanisms” and “updated existing policies,” he added.

Utilities can also help regulators understand “the need for foundational investments” to upgrade control rooms and communications with high-speed systems needed to scale VPPs, said Pepco Holdings’ Donohoo-Vallett. “Those expenditures will allow using the benefits of DER and VPPs for a more affordable energy transition,” he added.

Longer-term planning that identifies future market needs for load reductions or stability services enables VPP providers to build proactively to meet them and can also reduce costs, said CPower’s Sachs. Providers could then initiate expensive investments in technologies and customer acquisition and education where planners anticipate those needs and be ready to more quickly and cost-effectively offer system benefits to meet them, he added.

If the full VPP value stack at both the transmission and distribution system levels is recognized by planners, it is likely to show costs avoided by VPPs at scale make them “more cost effective than conventional resources,” Hertz-Shargel added.