Demand response can now do much more than lower electric power load, prompting utilities and system operators to take a new look at it.
Demand response (DR) was once an uncertain offer from a few big power users and residential customers to reduce load when notified by utilities or transmission system operators (TSOs). But there are now more than 13,600 MW of DR enrolled by utilities and about as much available to TSOs. Utilities reliably dispatched 78% of enrolled DR capacity — almost 10,700 MW — in 2016.
Two new reports take a look at where DR is now and where it's heading.
DR's role is expanding and its identity is changing. It is now “reductions, increases, or shifts” in load, according to the “2017 Utility Demand Response Market Snapshot,” released in October by the Smart Electric Power Alliance (SEPA) and Navigant Research.
Those load changes allow utilities and TSOs to respond to “time-varying changes in the cost of producing energy, shortages of distribution, transmission, or generation capacity, or unusually high or low voltage or frequency,” the paper reports.
Furthermore, the new DR, which incorporates a new toolbox of distributed energy resources (DER), is increasingly being used by TSOs as a market product alongside generation, according to “Demand Response; U.S. Wholesale DER Aggregation, Q3 2017” from GTM Research.
Some TSOs now offer capacity market, emergency response or ancillary services opportunities for DR, the quarterly update reports. But MISO, PJM and NYISO have joined CAISO and ERCOT in evaluating how system operators can take advantage of aggregated DER-as-DR.
Beyond load reduction
The SEPA-Navigant study shows DR also expanding on the distribution system. Forward-thinking utilities have been taking advantage of the load-reducing potential of air conditioning (AC) and water heaters for decades. But now more than 40% of utility respondents offer AC programs and 16% offer water heater programs.
Many utilities are moving to two-way communications technologies to improve participation, with 40% using email, 27% text messages and 12% using social media. Smart thermostat programs have been initiated by 24% of respondents and 9% offer behavioral DR programs.
But the new DR goes far beyond reducing load. Nearly 30% of utility respondents are using DER like energy storage, electric vehicles (EVs) and distributed generation “to help integrate high penetrations of DER,” according to the SEPA/Navigant report. Another 70% are planning or considering managed DER for control of grid “operability, reliability, and resiliency.”
The DER-as-DR future
As TSOs open their markets to aggregated DER-as-DR, its use to meet generation shortfalls caused by network congestion or capacity limits is growing, GTM Research reports. It is being delivered by industrial, commercial and residential customers through both utilities and private sector providers.
On the distribution system, there are revenue opportunities from investment in DER technology and in optimizing the flexibility of aggregated DER. A “next-generation energy system” will optimize DER to unlock “the consumerization of energy delivery,” GTM Research adds.
PJM, MISO and CAISO all called on emergency DR services in 2017, indicating the increasing potential of DR and distributed generation to meet system operators' needs, according Elta Kolo, lead author of the GTM Research report.
Price responsive demand (PRD) is “the next step forward,” Kolo said. PRD allows demand sensitive to real-time pricing to respond to price signals. As those customers move away from peak period usage, which is the most expensive generation, it will reduce system and customer costs, she added.
There was 500-plus MW of PRD committed in the most recent PJM capacity auction. It was the first time a market has seen enough participation to impact forecasting and planning, Kolo said. “It is likely other TSOs are looking at it, but PJM’s most recent ‘Demand Response Strategy’ makes explicit its intention to better understand dynamic energy management,” Kolo added.
With smart homes and customers engaged in actively managing their energy use, the right price signals can turn PRD into a tool “to benefit the overall operation of the grid,” San Diego Gas and Electric spokesperson Helen Gao told Utility Dive via email.
PRD will be valuable when tools allow a quick, reliable and locationally-specific response, Pacific Gas and Electric DR Programs Manager Franklin Fuchs added.
Both Gao, Fuchs and others see DR as one of several tools to reduce the need for new generation or even replace current peaker plants. But there are risks in relying on DR too much, they noted.
Customers called on to reduce their energy use “too frequently or for too long” may conclude compensation “is not worth it,” Fuchs said.
Southern California Edison spokesperson Robert Laffoon Villegas gave proof to those concerns, telling Utility Dive via email that customer engagement on DR has fallen off. More frequent use seems to have impacted “the willingness of customers, especially residential customers, to participate,” he said.
To benefit “both the grid and the customer,” DR needs to be simpler, more streamlined and automated, Laffoon Villegas said. Fuchs added that battery storage can “buffer” calls to reduce demand, “which should enable DR to expand.”
By the numbers
While South California Edison has seen a decline in customer engagement on DR, what do the broader findings of the SEPA/Navigant report show?
Navigant Principal Research Analyst Brett Feldman said some survey numbers highlight DR’s evolving value. Traditional one-way DR programs using customer A/C to reduce load had an enrolled capacity of 3,000 MW and a dispatched capacity of 1,823 MW in 2016. That 39% difference “shows it is either not being called on or there is a problem with it,” he said.
By comparison, smart thermostat programs reported an enrolled capacity of 2,384 MW and a dispatched capacity reduction of 2,289 MW (96% of enrolled capacity) for 2016.
Translating that capacity into people, the decades-old A/C-based DR has more than 2.6 million customers enrolled, SEPA reports. But U.S. utility smart thermostat offerings, including direct-install, self-install and bring your own thermostat (BYOT) programs had, by September 2017, led to more than two million smart thermostat installations. Navigant Research forecasts BYOT programs will enroll six million customers by 2024.
That shows “the high reliability of two-way communicating smart thermostats, changes in rates encouraging customer participation, and utility efforts to provide ‘set it and forget it’ options, the survey observes.
“It is another data point affirming that utilities are moving toward two-way devices,” Feldman said.
Utilities are also beginning to see the importance of advanced metering infrastructure (AMI) as a foundation for building two-way interactions, Feldman said. Less than one-third of respondents to the SEPA/Navigant survey (31%) are actively using AMI technologies in DR programs. But 65% have it, are implementing or are considering it. Only 4% of utilities have no interest.
The numbers are even higher for utilities looking at DR as a tool to integrate rising renewables penetrations, Feldman added. Only 29% have currently implemented DR to support renewables integration, but 70% are planning, researching or considering using it that way.
The numbers are almost as high for utilities looking to use DR as a location-specific non-wires solution (NWS), he noted. Once again, a small number have actually leveraged DR, but 60% are planning, researching or considering it.
In addition, private sector DER-as-DR providers are partnering with utilities at the cutting edge of DR technology.
EVs “are quickly becoming one of the largest flexible loads on the grid, with annual electricity consumption expected to reach 400 TWh/year by 2040,” the survey reports. Utilities have begun offering customers incentives to buy EVs and participate in managed charging programs that support grid operations.
Utilities are increasingly engaged in DR across a range of resources, but what will drive growth going forward?
Jeff Hamel, head of energy partnerships for smart thermostat provider Nest, said “a key next phase of growth” will be led by Demand Response Management System providers. They are “quickly becoming the go-to solution” for utilities, he emailed.
Green Charge Market Operations Manager Dave Margolius emailed that new levels of DR growth can emerge when TSOs enable “a more significant value stream.” A second driver will be “reduced market entry costs,” he added.
EnerNOC Western Regulatory Affairs Director Mona Tierney-Lloyd agreed. The key drivers of DR growth will be “a robust market opportunity” and “reasonable market participation rules” that offer “a clear path to payment,” she said.
The market opportunity will come from “a significant commercial/industrial customer base” and price signals that indicate the need for DR, she added. Payment must be based on clear performance metrics and rewarded in a time frame that does not leave customers frustrated.
A key barrier to DR is system operators forcing it into performance and compensation metrics established for generators. “There are structural, and in some cases, cultural, biases against DR, because it is not a baseload facility and cannot operate 24/7/365, cannot run for long periods of time or with great frequency,” Tierney-Lloyd emailed.
But it can — in conjunction with other DER — be used as a “targeted resource” to support TSOs’ integration of variable renewables, she added.
Advanced Microgrid Systems spokesperson Carly Sorrentino said customers’ demand for control of their own load is growing DR by making flexible load more available. “Nearly everything has a chip in it now,” she emailed. “If it is controllable, it can help support the grid.”
If given the opportunity, instead of being lumped in with traditional one-way DR, the new DR “would be a major asset for TSOs to cost effectively manage their grid,” Sorrentino said.
The promise of price-response
Green Charge’s Margolius, EnerNOC’s Tierney-Lloyd and AMS’s Sorrentino agreed that PRD represents a big step forward.
There is “tremendous value” because an increasing supply of assets can be “price responsive with low or nearly zero marginal cost,” Sorrentino said.
Margolius added that PRD can open “the full capability of energy storage” in energy and capacity markets because it optimizes the economics of both charging and discharging.
PRD works better in retail markets, Tierney-Lloyd said. Along with customer education, well-designed price signals “allow the customer to make rational decisions about whether or not to consume.” In wholesale markets, compensation tends to be too low to attract participants.
SEPA Research Analyst Brenda Chew stressed it is difficult to gauge how big the DR market could be. “There is a perception of complexity and, therefore, caution at utilities," she told Utility Dive.
"But DR is also part of a much wider range of programs and technologies and it is increasingly appealing to customers. It is not yet clear where it will all lead.”