Power industry participants recently weighed in on the interplay between demand response and distributed energy resources.
Will DR compete with DERs? That was a question posed to panelists at the Smart Electric Power Alliance’s 2018 Grid Evolution Summit, which took place in Washington, D.C., from July 9-12.
“It’s a different value proposition,” said Judson Tillinghast, program consultant for renewable energy at investor-owned Arizona Public Service, at a panel discussion on July 11.
“In a DER world, it’s more letting the customers do that upfront cost and decide what technology they want to invest and how they want to manage their energy,” he said.
But with DR, there is “no upfront cost for a customer, but the customers can save money if they’re willing to forego a certain behavior, reduce load during certain timeframes, for a grid benefit,” Tillinghast said.
“So I think there’s a place for both of them,” he said.
Steve Hambric, vice president for distributed energy management at Itron, which offers energy and water resource management services, said he thinks of DR as an outcome, while DERs “are things that can deliver outcomes, so I don’t think one replaces the other.”
Panel moderator Brett Feldman, principal research analyst at Navigant Research, asked whether DERs make DR obsolete.
“I think that the traditional forms of demand response – what people have seen it as for the last thirty years plus or so -- that’s going to still exist and be important, depending on the region,” said panelist Brenda Chew, a research analyst at SEPA.
Chew brought up what she sees as a broader question, namely, what is the definition of DR these days against the backdrop of new technologies like electric vehicles and electric storage?
One of Chew’s roles at SEPA is to lead its annual utility survey. “We have collected data from utilities over the past twelve years on how much solar’s been deployed and over the past two years, we expanded to energy storage, as well as demand response.”
She said that SEPA has focused on “trying to get greater insight into how dispatchable demand response capacity is really available that utilities are calling upon.”
Preliminary results show that more than 150 utilities responded this past year and reported about 18.2 gigawatts of DR, “how much is available to be called upon,” she said. Final results are due to be published by September.
Chew said that “we’re really seeing that there’s growing interest and movement in more locational deployment of demand response and specifically as a form of non-wires solutions, non-wires alternatives.”
New York project
Chew specifically mentioned New York-based utility Central Hudson Gas & Electric’s “Peak Perks” program. The voluntary program is designed to replace capital-intensive investment in utility infrastructure related to growing peak demand for electricity with a lower-cost alternative to reduce power use when demands are highest.
“Through our CenHub Peak Perks program, we’ve identified areas and specific circuits that are approaching capacity on peak days and may require future upgrades to reliably serve customers when energy use is highest, typically on the hottest summer days when the use of air conditioning is maximized,” said Michael Mosher, President and Chief Executive Officer of Central Hudson, in a 2016 news release related to the rollout of the program.
“By working with our customers to control energy use in these locations on peak days, we are seeking to avoid or postpone system upgrades in these areas, ultimately saving money for all our customers,” he said.
The goal of the program is to reduce peak demand for power by 16 megawatts of electricity in the designated areas.
The program is part of New York’s Reforming the Energy Vision effort, which involves a shift away from the traditional utility model of centralized generation toward a more decentralized electric grid that relies increasingly on energy efficiency, demand resources and distributed generation.