What Will It Take to Build the Market for Virtual Power Plants?

Mark Dyson wants the energy industry to retire one of its favorite pieces of jargon. Dyson, a principal with Rocky Mountain Institute's electricity practice, thinks the industry has made a mistake by settling on the term “virtual power plant” to describe how grid-scale renewables and distributed energy resources together provide grid services.

“I hate the term ‘virtual power plant,’” he told Greentech Media in an interview on the sidelines of last week's Grid Edge Innovation Summit. “It’s not an accurate representation of where we need to go with the idea.” Dyson takes issue with both “virtual” and “power plant” in the coinage.

After all, said Dyson, there’s nothing virtual about steel, silicon, or lithium in the ground. And “power plant” made more sense in describing how the grid operated over the previous 100 years, not the 100 years to come.

We’re moving toward a grid with more devices, more decision-makers, said Dyson. “We shouldn’t think about replacing ‘power plants’ with ‘virtual power plants.’ We should think about building the grid up from aggregated resources.”

“Power plants” are familiar; they’re what utilities have always bought. “Utilities, and wholesale markets, shouldn’t want to buy power plants,” said Dyson. “They should want to buy reliable energy, peak capacity, flexibility and ancillary services.”

You don’t need to buy a power plant to get those services today. “My beef with the term ‘virtual power plant,’ is it makes sense for the narrowest possible use case,” he said. “We need to think bigger to grow the market.”

Growing the market with "clean energy portfolios"         

Instead of “virtual power plant,” Dyson and his team at RMI use “clean energy portfolios” to describe the same concept. They published a report in May, The Economics of Clean Energy Portfolios, that pitted natural-gas plants against upstart clean energy portfolios comprising grid-scale and behind-the-meter renewable energy resources.

The report attempted to quantify the size of the potential market for such clean energy portfolios. In one scenario, the authors looked at the results if the thermal plants (coal, nuclear, gas) likely to retire by 2030 were replaced with new natural gas plants or with clean energy portfolios.

If you replaced the thermal capacity expected to retire with new natural-gas plants, the net present value of the required gas capacity would be $700 billion.

If half of that capex and opex were instead invested in grid-scale renewables and distributed energy resources delivering the same services, it would yield a 2 percent to 5 percent cost savings and create a $350 billion market, including $100 billion for DERs, through 2030.

Barriers to growing the market

To unlock the potential market, work is needed to overcome barriers, according to utility and industry veterans Dyson brought together for a Grid Edge Innovation Summit workshop.

Marc Romito, director of customer technology at Arizona Public Service Company, said the industry needs standards and protocols enabling DERs — thermostats, batteries, rooftop solar, EVs — to communicate with one another as well as with APS’ Advanced Distribution Management System.

“That ecosystem has to be interoperable, and it has to speak up into a platform that is a system of systems because we don’t have 10,000 Homer Simpsons in operations control pushing buttons,” he said.

“We need 5G,” he added. The much faster data transmission rates possible on a 5G network will improve telemetry and interoperability between devices.

“Once we see that 5G environment, it’s going to be a game-changer,” he said. “We’ll see the embedded machine learning.”

Colton Ching, senior vice president of planning and technology at Hawaiian Electric Company (HECO), concurred on the need for industry standards.

“In our industry, there really isn’t a set of standards around field networks and the devices on them,” he said. “Which makes the dilemma of fitting things to work together so much harder.”

“And for utilities making investment choices,” he went on, “it's much more risky because we’re going to have to select the particular vendor and stick with their own standard in the hopes that they’re going to be the prevailing company.”

Audrey Lee, vice president of energy services at Sunrun, stressed the importance of data sharing.

“We’re at a bit of an impasse,” she said. “Aggregators don’t always have data; utilities have data.”

She added that utilities must be willing to share data on where the need is, such as a grid constraint, so that third parties and utilities can come to solutions together.

Ching said HECO is using an Integrated Grid Planning process to identify local constraints on the transmission and distribution system and prepare proposals for bids for generation resources.

“An additional procurement could be for non-wires alternatives, for aggregated projects, that can address a specific need and compensate them properly for providing that solution,” he said.