Virtual power plants are having their moment

German utility RWE implemented the first known virtual power plant (VPP) in 2008, bringing together nine small hydroelectric plants with a total capacity of 8.6 megawatts. Typically, a VPP brings together many small components, such as rooftop solar, home batteries, and smart thermostats, into a single coordinated electrical system. The system meets the needs of the on-demand grid, whether by making stored energy available or reducing the energy consumption of smart devices during peak hours.

VPPs took off in the mid-2010s, but market conditions and technology weren’t quite right for them to take off. Demand for electricity was not high enough and existing sources (coal, natural gas, nuclear and renewables) were meeting demand and keeping prices stable. Additionally, despite the falling costs of hardware like solar panels and batteries, the software to connect and manage these resources was lagging, and there wasn’t much financial incentive to catch up.

But times have changed and less than a decade later, the stars are aligning in favor of VPPs. They are reaching a deployment inflection point and could play an important role in meeting energy demand over the next 5-10 years in a faster, cheaper and greener way than other solutions.

US electricity demand increases

U.S. electricity demand is expected to increase 25% by 2030 due to data center construction, electric vehicles, manufacturing and electrification, according to estimates from technology consultant ICF International.

At the same time, many bottlenecks make network expansion difficult. There is a delay of at least three to five years on new gas turbines. Hundreds of gigawatts of renewable energy languish in interconnection queues, where there is also a delay of up to five years. On the delivery side, there is a shortage of transformers that could take up to five years to resolve, as well as a shortage of transmission lines. This all adds up to a long, slow process to increase production and delivery capacity, and it’s not speeding up anytime soon.

“Powering electric vehicles, electric heating and data centers solely from traditional approaches would increase already high rates,” says Brad Heavner, executive director of the California Solar & Storage Association.

Enter the vast network of resources already active and connected to the network, and the perfect storm of factors that mean now is the time to scale them. Adel Nasiri, a professor of electrical engineering at the University of South Carolina, says the variability of data center and electric vehicle loads has increased, as has the deployment of grid-scale batteries and storage. There are more distributed energy resources than ever before, and the last decade has seen advances in grid management using autonomous controls.

But at the heart of it all is the technology that stores and distributes electricity on demand: batteries.

Advances in battery technology

Over the past 10 years, battery prices have fallen: the average price of lithium-ion batteries has fallen from US$715 per kilowatt-hour in 2014 to $115 per kWh in 2024. Their energy density has simultaneously increased thanks to a combination of advances in materials, optimization of battery cell design and improvements in the packaging of battery systems, says Oliver Gross, a senior researcher in energy storage and electrification at the car manufacturer Stellantis.

The biggest improvements have been in battery cathodes and electrolytes, with nickel-based cathodes beginning to be used about a decade ago. “In many ways, the cathode limits the capacity of the battery, so by unlocking higher-capacity cathode materials, we were able to take advantage of the higher intrinsic capacity of anodic materials,” says Greg Less, director of the Battery Lab at the University of Michigan.

Increasing the percentage of nickel in the cathode (compared to other metals) increases energy density, because nickel can contain more lithium per gram than materials like cobalt or manganese, exchanging more electrons and participating more fully in the redox reactions that move lithium in and out of the battery. The same goes for silicon, which has become more common in anodes. However, there is a trade-off: these materials cause more structural instability during the battery cycle.

The anode and cathode are surrounded by a liquid electrolyte. The electrolyte must be electrically and chemically stable when exposed to the anode and cathode to avoid safety risks such as thermal runaway, fires and rapid degradation. “The real revolution was the breakthroughs in chemistry that made the electrolyte stable compared to more reactive cathode materials in order to increase the energy density,” says Gross. Chemical compound additives, many based on sulfur and boron chemistry, for the electrolyte help create stable layers between it and the anode and cathode materials. “They form these protective layers very early in the manufacturing process so that the cell remains stable throughout its life. »

This progress has primarily been made on electric vehicle batteries, which differ from grid-scale batteries in that electric vehicles are often parked or unused, while grid batteries are constantly connected and must be ready to transfer energy. However, says Gross, “the same approaches that have helped increase our energy density in electric vehicles can also be applied to optimizing grid storage. The materials may be a little different, but the methodologies are the same.” The most popular cathode material for grid storage batteries currently is lithium iron phosphate, or LFP.

With these technical gains and lower costs, a domino effect was triggered: the more batteries deployed, the cheaper they cost, which fuels more deployments and creates positive feedback loops.

Areas that have experienced frequent power outages, such as parts of Texas, California and Puerto Rico, are a prime market for home batteries. Texas-based Base Power, which raised $1 billion in Series C funding in October, installs batteries in customers’ homes and becomes their retail electricity provider, charging the batteries when excess wind or solar power generation makes prices cheap, then selling that power back to the grid when demand increases.

However, there is still room for improvement. For broader adoption, Nasiri says, “the installed battery cost should be less than $100 per kWh for large VPP deployments.”

VPP software enhancements

The software infrastructure that once limited VPPs to pilot projects has become a robust digital infrastructure, making network-wide operation of VPPs possible. Advances in AI are key: Many VPPs now use machine learning algorithms to predict charging flexibility, solar and battery production, customer behavior, and grid stress events. This improves the capacity reliability of a VPP, which has historically been a major concern for grid operators.

While solar panels have advanced, VPPs have been held back until recently by a lack of similar advancements in the necessary software.Sun

Cybersecurity and interoperability standards continue to evolve. Interconnection processes and data visibility across many domains are inconsistent, making it difficult to effectively monitor and coordinate distributed resources. In short, while the technology and economics of VPPs are well in place, there is still work to be done to align regulation, infrastructure and market design.

In addition to technical and financial constraints, VPPs have long been hampered by regulations that prevented them from participating in energy markets like traditional producers. SolarEdge recently announced the enrollment of more than 500 megawatt hours of residential battery storage into its VPP programs. Tamara Sinensky, the company’s senior director of network services, says the biggest obstacle to achieving this milestone was not technical, but rather the design of the regulatory program.

California’s Demand Side Grid Support (DSGS) program, launching in mid-2022, pays homes, businesses and VPPs to reduce their electricity use or offload energy in the event of an emergency to the grid. “We have seen a massive increase in our VPP enrollment, primarily due to the DSGS program,” says Sinensky. Similarly, Sunrun’s VPP in Northern California supplied 535 megawatts of electricity from home batteries to the grid in July and saw a 400% increase in VPP participation compared to last year.

FERC Order 2222, issued in 2020, requires regional grid operators to allow VPPs to sell electricity, reduce load, or provide grid services directly to wholesale market operators, and to be paid the same market price as a traditional power plant for these services. However, many states and grid regions have not yet implemented processes to comply with FERC’s order. And because utilities benefit from grid expansion and not VPP deployment, they have no incentive to integrate VPPs into their operations. Utilities “view customer batteries as competitors,” Heavner says.

According to Nasiri, VPPs would have a significant impact on the grid if they achieve a penetration of 2 percent of market peak power. “Higher penetration, up to 5% for up to 4 hours, is required to have a significant impact on network planning and operational capacity,” he explains.

In other words, VPP operators have their work cut out for them to continue to unlock flexible capacity in homes, businesses and electric vehicles. Additional technical and policy advances could transform VPPs from a niche reliability tool to a key energy source and grid stabilizer for the energy tumult to come.