Distributed energy resources are poised for “explosive growth” across the United States over the next five years. U.S. utilities “need to change, and are slowly changing,” how they plan, operate and maintain their distribution grids to adapt.
That’s how Ben Kellison, grid edge director at GTM Research, described the key challenges facing the country’s utilities at this week's Grid Edge Innovation Summit. (Watch the summit sessions here.)
GTM Research has been tracking the rapid growth of rooftop solar, small-scale combined heat and power (CHP) systems, residential smart thermostats, electric vehicles and behind-the-meter batteries across the U.S.
As of 2017, five classes of behind-the-meter DERs — distributed solar, small-scale CHP, residential smart thermostats, electric vehicles and energy storage — contributed 46.4 gigawatts of impact on the U.S. summer peak, according to Kellison. That’s not a huge number, compared to the 769-gigawatt summer peak load reached by the U.S. as a whole in 2016, according to U.S. Energy Information Administration data. But it’s still a valuable source of flexibility, if it can be utilized.
By 2023, that figure is expected to more than double to total 104 gigawatts of flexible capacity, Kellison said. That’s led by growth in distributed solar, along with a big increase in the capacity available from smart thermostats, and a rising share of EV charging. To put that into perspective, “just these five classes could equal together almost as much power as [Texas grid operator] ERCOT has registered for its bulk generating system,” he said.
“These are not all resources that can be dispatched in a moment’s notice,” Kellison cautioned. “Many have to be used in a portfolio approach.” For example, distributed solar, which makes up the majority of the DERs to be deployed, generates most of its energy at midday, while typical summer peaks occur later in the afternoon. Small-scale CHP systems, defined as less than 50 megawatts of generation capacity, will run according to the needs of their owners, not necessarily those of the utility.
GTM Research also took a conservative approach to valuing individual DERs, depending on their relative availability and match or mismatch with peak demand. For example, it derated the potential reduction capacity of the nearly 20 million two-way communicating smart thermostats deployed in the country to about eight-tenths of a kilowatt — less than the 1 to 2 kilowatts often cited as the potential load reduction from a residential.
GTM then reduced that figure by one-quarter, to account for the need to allow some customers to keep cycling their air conditioners during the hottest days of the summer. But even with these reductions, the country’s smart thermostat fleet still adds up to about 8 gigawatts, Kellison noted.
Electric vehicles, while fewer in number, contributed about 2 kilowatts apiece in peak load flexibility, or about 1.6 gigawatts of peak load reduction — if they can be controlled to stop charging during times of peak demand. And behind-the-meter batteries and other forms of energy storage added up to only 160 megawatts of capacity, 90 percent of it in California, a testament to its early stage of adoption and reliance on state incentives.
Utilities aren’t as threatened by the growth of DERs as they’ve been in the past, at least according to a GTM survey of utility executives conducted this year. Only 3 percent viewed them purely as a threat, while 44 percent labeled them an opportunity — although, to be fair, 55 percent of respondents chose “both a threat and an opportunity” as their answer.
Utilities are also engaging their customers on the DER front, at least in some form, Kellison said. More than 100 U.S. utilities have set up at least a “basic DER marketplace,” he said — some kind of online portal allowing customers to shop for energy-efficient appliances and services, and connecting them with utility rebates and third-party offers. These programs, offered via internally developed utility portals or by vendors such as EFI, Enervee, PlanetEcosystems or Simple Energy, now cover more than 60 million customers, or about 40 percent of the country, he said.
The biggest impact of DERs will be in how utilities plan, invest, operate and maintain their distribution grids, Kellison said. According to data GTM Research compiled from the Federal Energy Regulatory Commission, the country’s largest distribution utilities have continued to increase investment in distribution infrastructure, primarily in traditional structures, station equipment, power lines and transformers.
But these investment plans are largely focused on traditional measures of what’s needed to keep the grid running, designed to meet worst-case scenarios, and predicated on the fact that utilities have until recently had very little data on what’s actually happening on their low-voltage networks. “That also leads to common oversizing of equipment, by as much as 50 percent, and leads to a lot of waste in the process as well,” Kellison said.
As more and more customers invest in DERs, utilities need to integrate that data into their grid planning, he said. “If you know several customers are going to adopt storage, you might avert the need for an upgrade by incentivizing those customers to upgrade early.”
That’s the fundamental idea behind non-wires alternatives, or NWAs — a term coined by New York state to describe projects that allow utilities to earn some form of return on investing in DERs, many of them behind the meter, in lieu of infrastructure upgrades. As of the fourth quarter of 2017, 19 states had some form of NWA-type policy either in planning mode or in some stage of completion, accounting for more than 1.7 gigawatts spread across 141 projects.
Still, New York accounts for nearly half of all projects, and Oregon, Vermont and California account for all but 8 percent of the rest of them, he noted. “Most of the states involved are in pilot mode, and it will be several years before any of these are fully integrated” into utility planning processes, he said.
GTM Research has a “DER life-cycle process” to explain how utilities can integrate their legacy customer, analytics, operational and asset management software systems into those centered on DER integration. “This allows utilities to connect lots of different processes,” he said. “Customer systems have to feed into planning. Planning systems have to feed into operations. And operations eventually has to feed into O&M, which largely involves utilities doing maintenance on their own equipment, but may in the future involve them working more directly with customers.”
Finally, “we’re talking about a lot more data than we’re used to,” said Kellison. “To get to a point where we can identify and target these resources, we’re going to need new platforms,” such as distributed energy resource management systems, which can integrate data from multiple systems and sources and convert it into actionable intelligence for utilities.
“In some ways, that portion of this evolution is something like what we saw in...the late 2000s, when utilities spent billions to upgrade their GIS technology,” he said. “That same transformation has to happen in distribution planning and operations over the next five to 10 years.”