Between now and 2021, utilities will spend approximately $380 million on distributed energy resource management systems (DERMS), according to a recent report from GTM Research.
The investment has only “just begun,” according to study author and GTM Research grid analyst Andrew Mulherkar. GTM Research defines DERMS as “an operational technology system that monitors, forecasts, optimizes and ultimately dispatches distributed energy resources (DERs) under management directly by the utility or indirectly through an aggregator.”
While most of the first few DERMS investments are limited in scope and complexity, soon they will need to take an integrated approach to how they manage resources at the grid edge.
Many utilities already have existing demand response programs that include technology-specific grid-edge DER programs, such as for battery energy storage, smart thermostats or hot water heaters.
But utilities will eventually need a DERMS that can manage hundreds of thousands of devices from dozens of manufacturers to provide grid services. Essentially, utilities must invest in a software system that can take the complexity and increasing diversity of devices at the grid edge and turn that into a dependable grid resource.
“A DERMS should take a huge number of small, diverse assets and intelligently aggregate these assets to deliver grid services,” Seth Frader-Thompson, president and co-founder of EnergyHub, said of next-generation DER integration. “Creating synthetic grid services that are made up of lots of heterogeneous assets...stitched together delivers a robust, reliable grid resource.”
Scaling DERMS while still buying off-the-shelf
The roadmap for DER integration may begin with a hot water heater program to flatten out peaks in the afternoon, something that could potentially be served by an existing demand response platform. But then, the utility may want to use the same water heaters to manage issues on feeders with highsolarpenetration, and then incorporate other DERs that can provide the same services. For other utilities, customer-sited DERs may be required as part of non-wires alternatives being mandated by regulators at the distribution level.
“The problems that utilities are solving with DERs will change over time, and the DER technologies themselves are changing incredibly quickly,” said Frader-Thompson. “Utilities need a flexible platform that constantly evolves, and we like to partner with our clients to build a collaborative road map.”
That flexibility also means looking for a vendor that has actually integrated with various devices and different types of manufacturers, and not just those who say they can do it all.
It also requires a platform with a truly decentralized approach, one that applies advanced machine learning from the edge of the system inward, rather than just sending signals from the center outward. Many utilities will be using these systems on a daily basis, and not just for emergencies.
EnergyHub’s Mercury 3.0 DERMS, the latest upgrade to EnergyHub’s software-as-a-service platform, provides such a solution, allowing utilities to control an ecosystem of DERs in real time.
The new Mercury software can integrate into utility systems, such as the ADMS and customer information systems to support the DER lifecycle process from interconnection to modeling to settlement and customer billing.
“They need to know, ‘Can I really trust this?’ The Mercury 3.0 update was hardened through rigorous beta testing with a group of DER owners, and then through our wholesale power market programs,” said Frader-Thompson. “There’s a real benefit to taking this technology to utilities after it has been used in real-world scenarios to provide grid services, where we’ve already put our own capital at risk.”
A look beyond legacy systems
A decentralized approach usually involves taking advantage of customer-sited and utility-owned assets. For that, an existing centralized software platform may not really work, especially as customer assets proliferate at a dizzying clip.
In particular, legacy systems that are difficult to update may not be the best choice for the job, even if they can manage it. A software program needs to be able to integrate seamlessly with a stream of new vendors as the ecosystem develops, without overwhelming the utility’s IT team and existing IT architecture.
Many legacy systems were built to manage a small number of large assets, rather than hundreds of thousands of devices in a DER ecosystem. “You need a software system that is built to manage the complexity of that ecosystem,” said Frader-Thompson. “If you want a good DER program, you want a mix of vendors.”
This approach to DER integration means utilities can focus on what grid functions they need from their aggregations, such as defining the specific load shape they're looking for on certain feeders. Utilities can then ideally work with their vendors to find the best assets that would make up the virtual power plant, such as smart thermostats, stationary energy storage, EVs, hot water heaters or smart solar inverters.
Increasingly, utilities will need to be specific about not just the grid function they are seeking from the DERs, but also the transactional requirements of vendors, from enrollment to long-term customer service to how those vendors will best leverage the utility’s brand.
“It’s fundamentally different in terms of approach,” Frader-Thompson said of utilities taking a more collaborative approach to DER platforms with software vendors. “DER programs and the DERMS used to manage them should not be static.”