In 1950, the English mathematician Alan Turing devised what he called “the imitation game.” Later dubbed the Turing test, the experiment asks a human participant to conduct a conversation with an unknown partner and try to determine if it’s a computer or a person on the other end of the line. If the person can’t figure it out, the machine passes the Turing test.

Power grid operators are now preparing for their own version of the game. Virtual power plants, which concatenate small, distributed energy resources, are increasingly being tapped to balance electricity supply and demand. The question is: Can they do their job as well as conventional power plants?

Grid operators can now find out by running these power plants through a Turing-like test called the Huels. To pass the Huels test, the performance of a virtual power plant must be indistinguishable from that of a conventional power plant. A human grid operator serves as the judge.

Virtual power plant developer EnergyHub, based in Brooklyn, N.Y., developed the test and outlined it in a white paper released today. “What we’re really trying to do is fool the operators into feeling that these virtual power plants can act and feel and smell like conventional power plants,” says Paul Hines, chief scientist at EnergyHub. “This is a kind of first litmus test.”

What Are Virtual Power Plants (VPPs)?

The virtual-versus-conventional power plant question is a timely one. Virtual power plants, or VPPs, are networks of devices such as rooftop solar panels, home batteries, and smart thermostats that come together through software to collectively supply or conserve electricity.

Unlike conventional power generation systems, which might crank up one big gas plant when electricity demand peaks, VPPs tap into small, widely disbursed equipment. For example, a VPP might harness electricity from hundreds of plugged-in electric vehicles or rooftop solar panels. Or it might direct smart thermostats in homes or businesses to turn down heat or cooling systems to reduce demand.

The technology is emerging at a time when concerns over data centers’ electricity demand is hitting a fever pitch. The consultancy BloombergNEF estimates data-center energy demand in the United States will reach 106 gigawatts by 2035–a 36 percent jump from what it had projected just seven months ago.

How utilities and grid operators will meet the growing demand is unclear and faces challenges on many fronts. Turbines for natural gas plants are backordered, and new nuclear reactors are still years away. Wind and solar, while cheap and fast to build, don’t produce the 24/7 electricity that data centers demand and face an uphill political battle under the Trump administration.

All of this together has created an opening for VPPs, which could add gigawatts to the grid without significantly jacking up electricity rates. “It’s a political issue. If you said you’re going to get electricity costs under control, this is literally the only way to do it in 12 months,” says Jigar Shah, a clean energy investor at Multiplier in Washington, D.C., who led the U.S. Department of Energy’s Loan Programs Office under the Biden administration.

VPPs could also reduce utilities’ need to invest in distribution equipment, avoiding supply chain shortages and inflated costs, Shah says. “There is no other idea that you could possibly deploy in 12 months that would have that big of an impact,” he says.

According to a 2024 U.S. Department of Energy report, VPPs could provide between 80 and 160 gigawatts of capacity across the U.S. by 2030—enough to meet between 10 and 20 percent of peak grid demand.

How Can VPPs Gain Grid Operator Trust?

But first, VPP developers have to win over grid developers. Benchmarks like the Huels test are crucial to building that trust. “In order for us to build our reliance on VPPs, they do need to pass the Huels test, and operators need to be able to count on” the VPPs delivering power when called upon, said Lauren Shwisberg, a principal in the nonprofit research group Rocky Mountain Institute who co-authored a recent report on VPPs and was not involved in the development of the test.

Matthias Huels, an engineer who spent more than four years at EnergyHub, first came up with the idea for the test in 2024. After workshopping the idea with colleagues and, somewhat ironically, ChatGPT, Huels presented the concept to the company.

Huels designed the test subjectively. Currently, in its earliest iteration, it appears to follow a guideline akin to the Supreme Court’s “I know it when I see it” test for what distinguishes pornography from erotic art. That is to say: Passing the test depends on who’s judging. If a grid operator finds the power from a VPP as dependable as electricity from an actual power plant burning gas to produce electrons, then the VPP has passed.

There are four levels to the Huels test. To reach level 1, a VPP must be able to shave off demand from the grid by, for example, successfully scheduling smart thermostats to dial down when the grid faces maximum demand. To reach level 2, a VPP must be able to respond to market and grid data and dial down demand when prices hit a certain level or tap into solar panels or batteries when power is needed. Human decision makers are involved at these levels.

Passing the Huels test comes at level 3. That’s when a VPP can function automatically because it’s proven reliable enough to be indistinguishable from a gas peaker plant–the type of power station that comes online as backup only when the grid is under stress. Passing level 4 involves VPPs acting fully autonomously to adjust output based on a number of actively changing variables throughout the day.

“The imitation game that Alan Turing came up with was: Can a computer fool an interrogator to think it’s actually human even though it’s a computer,” Hines says. “We propose this idea of a test that would allow us to say: Can we fool a grid operator into thinking that the thing that’s actually solving their problems is this aggregation of many devices instead of a big gas plant?”

Can VPPs Mimic Gas Peaker Plants?

Peaker plants only generate power about 5 percent of the time over their lifespans. That makes them easier for VPPs to mimic because, like peaker plants, the limited amount of power that can be made available by demand response or harvested from batteries only provides bursts of power that last a few hours at a time.

Far more difficult is stacking up to a full-scale gas plant, which operates 65 percent of the time or more, or a nuclear plant, which usually operates at least 95 percent of the time. Getting there would involve equipping a VPP network with long-duration storage that could be powered up during the day when solar panels are at peak output and discharged all night long. “You start talking about VPPs with large amounts of batteries that can run 365 days per year,” Hines says. “That’s a road we can go down.”

EnergyHub has been putting its VPP systems through the Huels test. Last year, EnergyHub successfully ran trials with Arizona Public Service, Duke Energy in North Carolina, and National Grid in Massachusetts. In Arizona, EnergyHub’s software dialed into homes with solar panels and smart thermostats and ran air conditioners to “pre-cool” houses during the day when the sun was generating lots of electricity. This allowed the state’s biggest utility to reduce demand during peak hours when residents would typically return home from work to turn on televisions and crank up their air conditioners.

“You have too much power in the middle of the day because of solar, then the early evening comes and you get people ramping up their evening loads right as the solar is ramping down,” Hines says. “You need something that can feather through that schedule. We created something that can do this.”

That lands the company somewhere between a 2 and 3 on the Huels testing scale. Passing level 3 “is going to take a few years,” Hines says.

German utility RWE implemented the first known virtual power plant (VPP) in 2008, aggregating nine small hydroelectric plants for a total capacity of 8.6 megawatts. In general, a VPP pulls together many small components—like rooftop solar, home batteries, and smart thermostats—into a single coordinated power system. The system responds to grid needs on demand, whether by making stored energy available or reducing energy consumption by smart devices during peak hours.

VPPs had a moment in the mid-2010s, but market conditions and the technology weren’t quite aligned for them to take off. Electricity demand wasn’t high enough, and existing sources—coal, natural gas, nuclear, and renewables—met demand and kept prices stable. Additionally, despite the costs of hardware like solar panels and batteries falling, the software to link and manage these resources lagged behind, and there wasn’t much financial incentive for it to catch up.

But times have changed, and less than a decade later, the stars are aligning in VPPs’ favor. They’re hitting a deployment inflection point, and they could play a significant role in meeting energy demand over the next 5 to 10 years in a way that’s faster, cheaper, and greener than other solutions.

U.S. Electricity Demand Is Growing

Electricity demand in the United States is expected to grow 25 percent by 2030 due to data center buildouts, electric vehicles, manufacturing, and electrification, according to estimates from technology consultant ICF International.

At the same time, a host of bottlenecks are making it hard to expand the grid. There’s a backlog of at least three to five years on new gas turbines. Hundreds of gigawatts of renewables are languishing in interconnection queues, where there’s also a backlog of up to five years. On the delivery side, there’s a transformer shortage that could take up to five years to resolve, and a dearth of transmission lines. This all adds up to a long, slow process to add generation and delivery capacity, and it’s not getting faster anytime soon.

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

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

At the heart of it all, though, is the technology that stores and dispatches electricity on demand: batteries.

Advances in Battery Technology

Over the past 10 years, battery prices have plummeted: The average lithium-ion battery pack price fell 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 materials advancements, design optimization of battery cells, and improvements in the packaging of battery systems, says Oliver Gross, a senior fellow in energy storage and electrification at automaker Stellantis.

The biggest improvements have come in batteries’ cathodes and electrolytes, with nickel-based cathodes starting 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 have been able to take advantage of the intrinsic higher capacity of anode materials,” says Greg Less, the director of the University of Michigan’s Battery Lab.

Increasing the percentage of nickel in the cathode (relative to other metals) increases energy density because nickel can hold 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’s a trade-off: These materials cause more structural instability during the battery’s cycling.

The anode and cathode are surrounded by a liquid electrolyte. The electrolyte has to be electrically and chemically stable when exposed to the anode and cathode in order to avoid safety hazards like thermal runaway or fires and rapid degradation. “The real revolution has been the breakthroughs in chemistry to make the electrolyte stable against more reactive cathode materials to get the energy density up,” says Gross. Chemical compound additives—many of them 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 stays stable throughout its life.”

These advances have primarily been made on electric vehicle batteries, which differ from grid-scale batteries in that EVs are often parked or idle, while grid batteries are constantly connected and need to be ready to transfer energy. However, Gross says, “the same approaches that got our energy density higher in EVs can also be applied to optimizing grid storage. The materials might be a little different, but the methodologies are the same.” The most popular cathode material for grid storage batteries at the moment is lithium iron phosphate, or LFP.

Thanks to these technical gains and dropping costs, a domino effect has been set in motion: The more batteries deployed, the cheaper they become, which fuels more deployment and creates positive feedback loops.

Regions that have experienced frequent blackouts—like 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 at customers’ homes and becomes their retail power provider, charging the batteries when excess wind or solar production makes prices cheap, and then selling that energy back to the grid when demand spikes.

There is, however, still room for improvement. For wider adoption, says Nasiri, “the installed battery cost needs to get under $100 per kWh for large VPP deployments.”

Improvements in VPP Software

The software infrastructure that once limited VPPs to pilot projects has matured into a robust digital backbone, making it feasible to operate VPPs at grid scale. Advances in AI are key: Many VPPs now use machine-learning algorithms to predict load flexibility, solar and battery output, customer behavior, and grid stress events. This improves the dependability of a VPP’s capacity, which was historically a major concern for grid operators.

While solar panels have advanced, VPPs have been held back by a lack of similar advancement in the needed software until recently.Sunrun

Cybersecurity and interoperability standards are still evolving. Interconnection processes and data visibility in many areas aren’t consistent, making it hard to monitor and coordinate distributed resources effectively. In short, while the technology and economics for VPPs are firmly in place, there’s work yet to be done aligning regulation, infrastructure, and market design.

On top of technical and cost constraints, VPPs have long been held back by regulations that prevented them from participating in energy markets like traditional generators. SolarEdge recently announced enrollment of more than 500 megawatt-hours of residential battery storage in its VPP programs. Tamara Sinensky, the company’s senior manager of grid services, says the biggest hurdle to achieving this milestone wasn’t technical—it was regulatory program design.

California’s Demand Side Grid Support (DSGS) program, launched in mid-2022, pays homes, businesses, and VPPs to reduce electricity use or discharge energy during grid emergencies. “We’ve seen a massive increase in our VPP enrollments primarily driven by the DSGS program,” says Sinensky. Similarly, Sunrun’s Northern California VPP delivered 535 megawatts of power from home-based batteries to the grid in July, and saw a 400 percent increase in VPP participation from last year.

FERC Order 2222, issued in 2020, requires regional grid operators to allow VPPs to sell power, reduce load, or provide grid services directly to wholesale market operators, and get paid the same market price as a traditional power plant for those services. However, many states and grid regions don’t yet have a process in place to comply with the FERC order. And because utilities profit from grid expansion and not VPP deployment, they’re not incentivized to integrate VPPs into their operations. Utilities “view customer batteries as competition,” says Heavner.

According to Nasiri, VPPs would have a meaningful impact on the grid if they achieve a penetration of 2 percent of the market’s peak power. “Larger penetration of up to 5 percent for up to 4 hours is required to have a meaningful capacity impact for grid planning and operation,” he says.

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