by Jeff St. John
January 30, 2018

This year’s DistribuTech conference in San Antonio showcased some of the big trends for utility and power grid industries, including a big focus on reliability after last year’s hurricanes in Texas, Florida and Puerto Rico; the ongoing efforts of grid giants like GE, ABB and Siemens to bring machine learning and artificial intelligence applications to the utility sphere; and the importance of microgrids as an outside-the-utility approach to distributed energy resource integration.

Big commercial and industrial customers have increasing incentive to invest in on-site generation and energy management. But ultimately, utilities with the largest growth in distributed energy will have to face the challenge of integrating it all into their everyday operations and long-range investment strategies. 

The common term for the technology to serve this utility task is the distributed energy resource management system, or DERMS. And according to GTM Research, while many companies may use the term to describe what they do for utilities or customers, only those technologies that can “manage the grid and DERs in real time” deserve the label. 

Last year, GTM Research applied this stringent test to its DERMS forecasts, primarily to exclude the world of technologies then applying the label in the market. As GTM Research grid research director Ben Kellison noted, “When the concept of DERMS is expanded to include all functions and processes relating to distributed energy resources (DERs), it loses its usefulness.” 

Leaving out all those not-quite-true-DERMS technologies and business categories made for a much smaller expectation for North American cumulative spending over the next few years -- a little more than $380 million from 2017 to 2021. That’s barely more than the $300+ million in venture capital investment raised by DERMS-related companies since 2010. 

This opportunity is locked up in a relatively small number of big utilities in states like Hawaii, California and Arizona that are facing the largest growth in rooftop solar and its impacts on grid operations, or those like New York that are pushing their utilities to become distribution system operators.

But as we learned at DistribuTech, most of these utilities have seen their plans for system-wide DERMS implementations scaled back by regulators and broken into smaller demonstration projects. That’s mainly on the grounds that utilities need to gather the data to show whether their DERMS will work at scale -- and at a cost that’s beneficial to ratepayers. 

Sunil Cherian, CEO of Spirae, has put a halt to what he called “utility DERMS” -- the large-scale extension of, or integrations with, the big advanced distribution management system (ADMS) platforms supplied by the world’s grid giants like GE, Siemens and ABB. “They can’t get their DERMS through their [public utility commissions]. That’s been very slow, and I think it will be slower” in the coming year, said Cherian.

Non-utility DERMS, by contrast, is “where most of our growth is coming” -- about two-thirds of Spirae’s business as of late. That’s been largely in the form of microgrids, from remote islands trying to add wind or solar to diesel generators, all the way to showcase projects like Richard Branson’s Necker Island (which was recently devastated by Hurricane Irma). 

Spirae is also working through channel partner Caterpillar to implement power systems at mines and other remote industrial sites, and on islands of the Philippines through its partner First Philippine Holdings. Spirae has turned to system integrators and tech vendors to reach these new markets, rather than going to market on its own as it would for a utility DERMS project, he said. 

Michael Carlson, president of Siemens Smart Grid North America, agreed that “we’ve got as much activity, and arguably more, deployment occurring with non-utilities.” Over the past few years, the German grid giant has introduced a line of microgrid controllers, largely aimed at giving commercial and industrial users the tools they need to island and reconnect from the grid. 

“Just in the last year have we seen the utilities wanting to provide and partner with their industrial customers. So the utilities are becoming, as we’ve expected, a customer for this as well.” Last week, Siemens unveiled an enterprise microgrid management platform to link its microgrids from a utility context, as implemented in its project at California’s Blue Lake Rancheria with Pacific Gas & Electric, as well as with its community microgrids in Brooklyn, New York. 

Building blocks of the future DERMS: Microgrids and virtual power plants 

Microgrids were a hot topic at DistribuTech, with Carlyle Group’s $500+ million fund for Dynamic Energy Networks to build projects using Schneider Electric’s controls technology. We’ve seen a lot of utilities and energy services providers bringing offerings to market, from Southern Company’s PowerSecure combining backup generators with batteries from Advanced Microgrid Solutions, or NRG Energy and Cummins combining natural gas and demand response. 

Most of these projects are relying on a combination of cheap natural gas and low upfront costs financed through power-purchase agreements to bring emergency backup power to a class of customers who couldn’t otherwise afford it. But by maintaining oversight and control over multiple units, these microgrid services operators can become masters of significant amounts of capacity for grid services and energy markets, depending on where they’re located and how much flexibility they’ve built into their system. 

Enchanted Rock is a Texas firm that’s built up a fleet of about 45 microgrids across the state, and it has been able to serve up enough flexibility from its 160 megawatts of diesel and 50 megawatts of natural-gas-fired turbines to earn tens of thousands of dollars per day in emergency response services for grid operator ERCOT, Clark Thompson, chief technology officer, told me in a Wednesday interview. It also cuts customers' "four coincident peaks" charges, and allows them to run on natural gas if the spark spread between those costs and current grid prices calls for it. 

Not all fossil-fuel-fired backup generators can serve as the foundation for a microgrid, but to date, commercial microgrids have relied on some core spinning mass generator to provide core stability. That’s not necessarily the case for virtual power plants, another formulation of DERs in the context of larger utility operations. VPPs are so named because they require a system that can aggregate, dispatch and respond to grid needs in a way that’s indistinguishable from a power plant connected to the transmission grid. 

That’s a good way to describe the 85 megawatts of capacity that is being gathered for Southern California Edison by behind-the-meter battery startup Stem. Larsh Johnson, chief technology officer, noted that it’s been able to monitor and manage its fleet of demand-charge-reducing batteries to keep those needs to about 20 percent of total available capacity. 

“In an aggregate sense, as we look across our portfolio, we have enough diversity to say we have 80 percent of the overall capacity available” for other grid needs, including its contracted use to meet the utility’s capacity needs, bidding into the state’s emerging markets for DERs, and potentially other uses as well. 

Vancouver, Canada-based Enbala is also getting into the solar-plus-storage realm in its latest VPPs, said Chief Technical Officer Michael Ratliff. Its latest with Alectra, a municipal utility serving about 1 million customers in Ontario, aimed at turning its existing solar PV, battery and EV-charging assets into a grid-responsive unit.   

That’s a different mix of assets for the startup, which has previously concentrated on aggregating pumps, motors, refrigerators and other commercial-industrial loads to serve split-second grid needs in multiple markets. But it’s part of Enbala's strategy to use VPPs as an “entree” into broader applications. “Our customers have a vision of where they want to go with DERMS going forward," said Ratliff.

Where true DERMS is happening

As for progress on a true DERMS system, this year’s DistribuTech saw several companies announce significant new contracts -- although most weren’t naming their utility partners. 

Enbala, for instance, announced Tuesday that it’s landed a second DERMS contract with an unnamed utility, as part of its role as DERMS provider for Swiss grid giant ABB. Enbala secured that role at last year’s DistribuTech. Ratliff noted that the company is also tapping the reactive power capabilities of smart inverters it’s connected to, in anticipation of using that capability to mitigate voltage challenges on distribution circuits. 

Smarter Grid Solutions, a Scottish startup with technology managing some 120 megawatts of grid-responsive generation and load in the U.K., has also been making inroads in the North American DERMS market. SGS' Bob Currie told me last week that the company has just closed the deal on a full-scale utility DERMS deployment with an unnamed North American utility. 

It’s a noteworthy win. The project is “not a pilot or a demo. It’s being paid for in the rate base,” said Currie. SGS beat out about 10 other competitors in an open solicitation for the contract, according to Zach Pollock, business development executive for SGS. 

Currie noted that SGS' project with New York utility Con Edison is also utilizing its Active Network Management platform to demonstrate value-stacking for DERs between the utility and a third-party developer, which fits some of the definitions of a DERMS platform. SGS is quite active in New York, where it has three projects with utilities under the state’s Reforming the Energy Vision initiative, as well as in California, where it’s helping Southern California Edison as part of a Department of Energy-funded project meant to reduce DER interconnection processing time from 15 days to five days. 

"We’ve been doing DERMS before DERMS was a thing,” said Currie, and SGS has a 10-year track record in the U.K. to commend it. “We’re at the point where a lot of what we’re doing we’ve already proven, and we’re just scaling it up.” 

Just what constitutes a DERMS platform is being worked out by the Smart Electric Power Alliance, which held a jam-packed workshop at DistribuTech that drew more than 150 industry participants to go over its proposed requirements document for applications seeking the title. 

As for where the utility demand for DERMS is emerging, Siemens’ Carlson said, “HECO is one of the best examples of that in the country right now, but they’re also one of the most extreme examples of penetration of distributed renewables.” Siemens has a head start in Hawaii, where it’s building its technology into utility Hawaiian Electric’s platform for monitoring and managing the increasingly significant levels of rooftop solar feeding into its distribution grid.

Southern California Edison, a utility that’s taken the lead in contracting for DERs as grid resources, has also picked Siemens’ DERMS software. Siemens and integration partner Omnetric promise to provide “data and visibility across the entire distribution network, from grid planning to market forecasting, for more effective management of DERs,” as well as to “allow the utility to better define, forecast and control customer-owned distributed energy resources across their territory,” with a first-phase implementation scheduled for early 2018. 

SCE is a particularly interesting case, given its role in creating utility procurements for DERs such as solar PV, energy storage and demand response at hundreds of megawatts in scale. SCE also has a grand evolution in mind for its software and controls, in the form of a grid operating system that integrates its legacy systems with a more flexible and fast-responding DER management system.