The demand response industry is experiencing some growing pains, but it may be a good thing.

Energy efficiency is slowing load growth, cutting into demand response opportunities. Some utilities have chosen not to expand programs due to lower natural gas prices. And utilities with large demand response resources are struggling to find a holistic way to manage their flexible resource.

"Utilities have shaved off some of the peak opportunity for demand response," said Elta Kolo, a grid edge analyst at GTM Research and co-author of a recent report on the current demand response landscape. Growing the resource will require managing programs well, and keeping costs in check.

GTM Research this month published a report on the current demand response landscape, noting there was about 30 GW of demand response flexibility in 2015. The bulk of that is industrial and commercial, with about a third of it residential. Utilities are looking beyond just demand response when it comes to load management: DR is just a quarter of all demand side management, according to the report.

"You need to be able to leverage the flexibilities you have in your system," said Kolo. "Utilities have spent years building out these flexible resources and now is the time they have to strategize and decide what they're going to do with it …. they need to be able to manage their system more dynamically."

But utilities must also walk a fine line in developing and utilizing the resource. They must invest appropriately, keeping costs in check, while also ensuring their customers remain satisfied. 

Southern California Edison is an example of a utility still dialing it all in—the company has significant demand response resources, but its largest program has been losing participation for years. As the utility called frequent events, tens of thousands of customers abandoned the summertime discount plan, ultimately taking 45 MW of flexibility with them.

"There's a program flaw that needs to be fixed," said Kolo, stressing the need for optimizing comfort.

Program management is important: Attrition and fatigue

SCE activated 5,321 MW of demand response last year, and about a third of it came through its Summer Discount Plan Residential (SDP-R). But between 2011 and September 2016, the program shed almost 45,000 customers and 45 MW of capacity.

“The frequency and duration of dispatch for the SDP program has caused a significant reduction of the resource,” according to Kolo's report. And the problem compounds: she points out that even after reducing the number of dispatch hours last year, customer-requested attrition spiked. And, it turned out that “customers who de‐enrolled in 2016 were among the highest-performing customers in 2015.”

The average kW of capacity per service account dropped by almost a quarter, the result of responsive customers leaving the program.

The utility has responded with a series of fixes, but it is too soon to know if they will pay off. Last year, the utility lost 16,000 customers from the program, accounting for more than 15 MW.

"Customers are being called too often," said Kolo. "They need to focus the program on customer comfort."

SCE spokesman Justin Felles said SCE has been rolling out several changes, including reducing the number of events called, and working on the utility's outreach strategy.

Felles said SCE has "implemented a communication strategy geared towards retaining customers on the program by providing reminders throughout the year of their participation, why events are dispatched, where they can find the credits earned on their bill, tips for staying cool and a final message of appreciation."

As part of SCE's Aliso Canyon mitigation proposal, the utility reduced the mandatory minimum number of dispatched hours per year from 40 hours to 20 hours, and it is proposing to the California Public Utilities Commission to make that level permanent.

SCE also implemented event notification options, including a demand response mobile app where customers receive notification up to 30 minutes prior to the event being launched. And customers are offered four participation options that provide choices to either maximize their credits with a 100% participation option or increase their comfort levels by enrolling in a 50% option.

"With each plan, the customer can select the override option which allows them the ability to opt out of up to five event days per year," Felles said.

Keeping costs in check

Idaho Power began its demand response programs 15 years ago, and 10% of its peak demand can now be trimmed. The vast majority of its demand response resource is based around irrigation, but it also has 26 MW of capacity in its "Flex Peak Program," which targets about three dozen commercial and industrial customers.

Program costs and incentives last year totaled less than $1 million—and that's after the utility dumped EnerNOC. In 2015, state regulators allowed Idaho Power to operate its own demand response programs.

"While EnerNoc’s program was robust and cost-effective, customers will benefit if the company ...can deliver similarly reliable demand response at the same or less cost," regulators concluded.

"Idaho Power decided to continue the program themselves," said Kolo. "A large part of that was the cost. Just being able to manage the program themselves, is about half the cost of what EnerNOC was charging."

Partnering with aggregators and tech companies, and outsourcing engineering and management, has become fairly standard practice for utilities. And there is certainly value in that strategy, said Kolo, particularly in instances where the utility would be operating outside its strengths. But there may be more value in going it alone in some spots, once the experience is gained.

EnerNOC started working with Idaho Power in 2009, and ran demand response programs for the utility for a half dozen years.

"Especially for utilities that have never run a DR program before, third parties can bring a lot of knowledge to the table," said Kolo. "My guess is that what EnerNOC was offering was a little more complicated than what they needed."

But while Idaho Power's Flex Peak has 38 enrolled customers, the flip side of that is Baltimore Gas & Electric's behavioral demand response Smart Energy Rewards program. BGE's program has 1 million customers through automatic enrollment of any residential account with a smart meter.

Behavioral demand response may become more influential, Kolo said, as utilities use more gentle cues to get customers to reduce usage. The program, managed by Opower, can reduce peak loads by almost 20% and customers save between $5 and $8 per event. There is robust communication before and after events, to keep customers engaged and aware of their savings.

"There's a lot of computational power that goes into that," said Kolo. "From a broad perspective,they're leveraging the power of demand response."

Opportunities

Despite the challenges, GTM's demand response analysis finds plenty of room for opportunity as utilities begin to use demand response to manage daily operations.

Growing interest in electric vehicles could add significantly to utility load, increasing the opportunity for demand management. And customer-sited generation, while not a large factor in the short-term, will be a larger resource in the future.

"It takes a long time to build out residential programs. I think where there is opportunity is in the small commercial businesses, like large chain stores," said Kolo. "That's a market that is untapped at this moment."

There will also be changes in how demand response is utilized, she said. Traditionally built as an emergency resource, demand response will increasingly be used to alleviate constraints in specific areas and at certain times. And while the bulk of demand response resources are managed by just a few utilities, smaller providers are increasingly looking at what they can do to keep demand in check. Some 60% of the demand response surveyed by GTM came from 25 utilities (though the report does not include pilot programs).

“We have all this flexibility in the system," said Kolo. "Utilities spent so much time building up this resource, now they need to figure out how to leverage it in a better way in day-to-day operations."