by Jeff St. John
July 02, 2020

This is the third installment in our five-part series on key trends influencing the grid edge, or the transformation of the electricity grid from a centralized, one-way delivery system to a networked system integrating distributed energy resources such as rooftop solar, behind-the-meter batteries, electric vehicles and flexible electricity loads. This installment focuses on the development of distributed energy resource management systems (DERMS)  technology integrations that can identify, monitor, manage and orchestrate multiple classes of renewables as an aggregated whole — and how the past decade of technology development and field trials are beginning to deliver on the DERMS promise. 

Distributed energy resources are the future of the power grid. Whether that future is one of increasing disruption or expanding value depends on how they’re managed. 

On the generation side, rooftop solar can cause grid breakdowns or be orchestrated via smart inverters to provide local stability and resiliency. Behind-the-meter batteries can act in ways that are blind to grid needs or maximize value and minimize disruptions. 

On the consumption side, electric vehicles can charge in ways that overwhelm local transformers or neighborhood substations, or they can be used to absorb the ebbs and flows of wind and solar power. Appliances such as water heaters and air conditioners could continue to strain the grid at times of peak consumption, or they could be more finely orchestrated to shift and shape loads to manage local grid needs.

Which of these distributed energy resource futures ultimately emerges — one of chaos, one of concerted action — will come down to "software orchestration and optimization,” says Elta Kolo, grid edge research content lead at Wood Mackenzie. The U.S. will have nearly 400 gigawatts of DER capacity on its grid by 2025; “We have to make sure we get the most out of them,” according to Kolo.

A distributed energy resource management system, or DERMS, has become a stand-in term for technologies that monitor, manage and orchestrate DERs at the utility-wide scale. But the DERMS term is often misapplied to technologies that lack the full range of capabilities required to reach that goal. 

A true DERMS is built on a “DER lifecycle management” framework, explains Ben Kellison, WoodMac's director of grid research. This starts with registering and interconnecting DERs in a system of record and monitoring them to ensure grid reliability and safety, a precursor to tapping their flexibility for positive grid values. This requires much more fine-grained visibility into distribution grids in order to allow utilities to tap DERs in the way they now control capacitor banks, voltage regulators and protective grid gear, and rely on them more completely as replacements for grid investments, also known as non-wires alternatives.

A DERMS platform needs to be able to aggregate DERs, whether by utilities themselves — Arizona Public Service’s work with EnergyHub is one example — or third-party aggregators such as SunrunStem and Enbala

Finally, new pricing and market structures are needed to allow DER owners and aggregators to earn money for these services. 

If that sounds like a lot to ask, it is. No utility has fully realized this vision. But many have been laying the groundwork for a full DERMS architecture, and such platforms are likely to become a central part of utility operations in the next decade.

Engaging the optimal route toward increasing DER capacity 

The first step in the DER revolution is ensuring that solar panels, home batteries and electric vehicles don’t disrupt the grids they're connected to. As we covered in last week’s GTM Squared, smart inverters and the technology standards for coordinating them are beginning to make that possible. 

“The second step is DERMS — you need the control systems to orchestrate and control these systems,” said Ajit Renjit, senior project manager leading at the Electric Power Research Institute. 

EPRI is working on multiple projects on this front, including one funded by the New York State Energy Research and Development Authority involving utility Central Hudson Gas & Electric, seeking ways to integrate large amounts of solar PV onto the grid.  

“In New York's Hudson Valley, they have megawatt-scale PV on the interconnection queue” facing transmission and distribution constraints, Renjit said. One option for developers is to pay for grid upgrades, but those can take years and cost millions of dollars. “Another option is a DERMS that can tell me when and where a grid constraint will happen" and control the solar to prevent the problem from arising. 

Utilities have been using load controls and variable pricing for decades to encourage customers to reduce or shift power consumption. But those programs are built to manage the high level of uncertainty involved in asking customers to voluntarily take action. DERMS, by contrast, has to be able to provide “firm grid services,” Renjit said.  After all, “if they don’t respond, your transformer is going to blow.” 

DERMS provider Smarter Grid Solutions is already orchestrating DER control with renewables in the U.K. In the U.S., SGS is working with Schneider Electric and General Electric to integrate its DERMS into Central Hudson’s distribution and transmission grids.

Operational visibility, integration and control is only the first step. The next is to put “contractual arrangements in place to assure these reliability services have been provided,” Renjit said.

That brings things back to the original challenge: "To run power flow on the distribution feeders, well, I need visibility into the distribution feeders, into what the DERs are doing. Most distribution utilities don’t have that yet” and need to make significant grid modernization investments to get there, Renjit said.

Putting it all together: Southern California Edison’s EASE project 

That doesn’t mean that utilities aren’t getting closer. Take Southern California Edison’s Electric Access System Enhancement project. Funded by a U.S. Energy Department grant and featuring partners including Smarter Grid Solutions, the California Energy Commission and DOE’s National Renewable Energy Laboratory, it’s building an “interoperable distributed control architecture” that’s now moving from computer modeling to real-world testing.   

“One of the big targets we’ve had to achieve is control of 10,000 DERs,” Chris Linn, Smarter Grid Solutions’ project manager, told Greentech Media. That’s a massive goal, one that has only been tested in lab simulations thus far. But SCE had already been working with SGS to deploy its platform, giving it a head start on understanding how its technology interacts with its grid operations systems. 

“They’re modeling PV production, and we’re managing both individual PV systems under DNP3 control and batteries under 2030.5 control,” he said, referring to two technology standards for grid and DER operations. 

Southern California Edison graphic explaining how Smarter Grid Solutions' DERMS technology can increase DER hosting capacity on distribution grids through active network management.

EASE is also tackling integration before DERs are connected, using a system that combines permitting and interconnection processes to avoid the “bottleneck of paperwork,” Linn said. That's a key part of DOE's goal to reduce barriers to DER adoption.

This system assigns each new DER a unique digital ID, with a “self-provisioning” process that connects them to SCE’s control platform, much like a home set-top box can be provisioned by the cable company, he said. “We take all these DERs that are now self-provisioned into our control system, and we bundle them up into services.” 

With its first two technology integration and lab test phases complete, SCE is moving into field trials in the Orange County city of Santa Ana, where SCE faces grid constraints. Project partner Kitu Systems, an internet-of-things company centered on energy, is already enlisting customers via a web portal and connecting them with the four DER installers working on the project. 

“We’re getting the whole communications piece of it working,” Kitu CEO Rick Kornfeld said. That includes direct utility-to-DER controls, as well as “grouping” devices that are situated behind individual transformers, feeder circuits and substations to respond independently to local events that centralized control platforms can’t act quickly enough to solve. “You may have a very large school with a solar system that’s driving voltage up at the end of the day, and there could be a different feeder connected to a building across the street that has an entirely different problem.” 

Beyond utility visibility and control over DERs, the EASE project will examine the prospect of aggregated DERs serving systemwide needs as well as local distribution operator needs, Linn said. “They’re going to run their power system model, and we’re going to emulate all these devices in a lab scenario, being incentivized through price signals [and] what’s going on at the distribution substation level. We’re building the next test environment for the project right now.”

California grid operator CAISO already allows DER aggregations to serve its wholesale energy markets, although the program has had relatively little participation to date. The concept of a distribution system operator market is still in its infancy, though it’s being pursued in states including Hawaii, New York and California. It has some vocal proponents, including former Federal Energy Regulatory Commission chairman Jon Wellinghoff

SCE is in the initial stages of deploying its overarching DERMS system. Its work on EASE indicates how it’s putting the pieces together to get there. But it and every other utility working toward this goal still have a lot of work ahead, including the challenge of merging the systems that manage DERs at the distribution level with how they can serve the bulk power system and become an integral part of long-range planning.

Stay tuned for a comprehensive examination of that challenge in the next installment of our series.