Two new reports are putting numbers to the state of virtual power plants and demand flexibility programs in the United States — and their potential when fully integrated into planning and operations.
According to RMI’s recent Power Shift report, electricity demand is expected to grow between 1.5% and 2.5% each year between now and 2035. And this will coincide with the retirement of fossil fuel generation that is no longer financially viable. The think tank anticipates that the country will need 155 gigawatts of new resources by 2030 to make up the shortfall.
While some of that will be met by new utility-scale solar, wind, other emerging clean technologies, and even new or revived nuclear, DERs have the potential to serve a whopping 60% of this demand, RMI found.
Mark Dyson, managing director of RMI’s carbon-free electricity program, emphasized that these benefits wouldn’t involve entirely new technologies, but rather “just software to take advantage of things that customers already have, like EVs and batteries and thermostats.”
VPPs, he added, are just one of several emerging technologies “that we see in maybe the pilot stage across the country, but have a pathway to really scale over the next six years.”
The use of a VPP, the researchers found, can reduce costs by 20% and emissions by 70%, when fully accounted for in power system planning and operations. Dollar-wise, that would amount to $140 saved per household per year — or system-wide savings of $468 million per year in avoided capital costs.
“It’s not just a peak capacity benefit,” Dyson said. “We show 10 bucks per month per household in our Colorado utility test case of savings that VPPs can provide to every customer, not just participating customers.”
There are also emissions savings. Scaling VPPs to meet load growth could save between 12 million and 28 million tons of carbon emissions by 2035.
This offers an update on the Department of Energy’s VPP liftoff report, released one year ago. That report found that if the U.S. increases its VPP capacity to 160 gigawatts by 2030, the country could meet up to 20% of its peak demand needs using DERs — and save $10 billion in annual grid costs. That report predated the VPP market’s moment of consolidation, with acquisitions by Budderfly, Uplight, and Ohmconnect since last December.
Adoption is complicated by the lack of an industry-wide consensus on how to define VPPs, much less how best to scale them.
But Dyson is hopeful. “The amount that utilities have learned and shown that they can meet the emerging needs of the power system with carbon free energy over the past 10 years has clearly exceeded their own expectations, and I think exceeded expectations for many of us in the industry, outside utilities as well,” he said.
Checking in on demand flexibility programs and rates
That said, there are dozens of programs attempting to take advantage of the DERs proliferating across the country.
Lawrence Berkeley National Lab’s Energy Markets and Policy department published an analysis of the state of demand flexibility programs and rates, a key element of aggregating DERs. These programs, the researchers said, can both reduce emissions and electricity costs; however, there is a lack of data on effectiveness.
The report, therefore, analyzed data from 148 programs and 93 rates, in an attempt to pinpoint the specific characteristics of programs and rates that promote demand demand flexibility in both residential and commercial buildings in the U.S.
The researchers found that smart thermostat and battery storage programs dominate the market, making up 84% of those analyzed. Of those, battery programs allow for more flexibility events than thermostat programs do, at a median of 60 events versus 15, respectively.
When it comes to incentives, there is also a divide by program type. While upfront incentives are common in all programs, smart thermostat programs typically offer retention incentives as well; most battery programs, meanwhile, skip the retention incentives but are likelier to offer performance incentives.
Of the 93 rates, 69 are dynamic, 27 are technology rates, and three are hybrids. Among the former, critical peak pricing rates are most common. Most are designed to reduce demand during summer peak — though the authors expect that programs will need to evolve beyond summer peaks to include winter peaks as well.
“Programs and rates will need to evolve over time to achieve a more fulsome vision of demand flexibility that involves the provision of a wider variety of grid services,” the researchers wrote. “In particular, program designs would need to change if the electrification of end uses shifts peak demand into winter mornings in cold regions.”
