Traditional Demand Response (DR) serves supply-demand imbalances, but today’s variable renewables and distributed energy resources (DER) make imbalances more common and new load flexibility allows utilities to adjust loads down instead of increasing generation.
Adjustable smart thermostats for air conditioning (A/C) and heating, grid integrated water heating, and managed electric vehicle (EV) charging will be gateways to a DR market that adds residential DER to traditional DR using commercial -industrial customers’ load, according to a new Brattle report. This more flexible load can protect against variability from rising levels of solar and wind generation.
And it’s that residential segment that will come to dominate the DR market in the next 10 years.
“Over 70% of the almost 60,000 MW of U.S. DR capability today is from the commercial and industrial customers with large, single point curtailable loads,” Brattle Group Principal Ryan Hledik, co-author of a June 2019 study on load flexibility potential, told Utility Dive. “But most of the 2030 load flexibility potential is in the residential segment as customers adopt smart automated home technologies.”
New marketing approaches and rates with price signals will accelerate customer adoption of DER, utilities and other power sector analysts agreed. But utilities and regulators must confront technical and market complexities to enable this transformation.
The challenge and the promise
The technical complexities in moving to more use of DER include getting the necessary system hardware and software in place. Hardware, like switches and sensors, and software, like advanced distribution management systems (ADMS) and distribution energy resources management systems (DERMS) will be needed to allow utility control rooms to see and manage DER. With the tools, utilities can adjust operations to take advantage of new resources.
The related market complexities include providing regulatory guidance to utilities, putting incentives to adopt DER in place for customers, and giving third parties the opportunity to act as DER aggregators. Regulators can move the market by allowing utilities to recover the costs of rebates to customers. They can also provide clear rules and compensation frameworks to third parties for bringing aggregated DER to market.
Nearly 200 GW of cost-effective load flexibility from existing DR and new DER could meet up to 20% of the estimated 2030 U.S. peak load, avoiding over $16 billion annually in system costs, Brattle reported. Existing incentives and technologies can deliver an estimated 120 GW of load flexibility. Solutions for utility operations complexities and market barriers are needed for the other 80 GW.
Creative utility planning and policies with market-driving incentives can deliver 40% of the total 200 GW load flexibility potential “by modernizing conventional programs,” according to Brattle. Program design can eliminate complexities and better reward utilities. Customers can be more effectively engaged with rate reductions or rebates for participation.
The other 60% of the 200 GW potential is in “emerging” load flexibility enabled by building automation technologies. With new technology standards, better analytics, and incentives targeting automation, flexibility will, by 2030, “be just another feature embedded in products customers buy, not something they have to be convinced to buy,” Hledik said.
The value of residential flexibility was estimated at $9 billion annually in a 2015 Rocky Mountain Institute (RMI) paper, RMI Principal and paper lead author Mark Dyson emailed Utility Dive. Brattle added the commercial-industrial (C&I), and transportation sectors to show more of “the value at stake.”
“In the future, generation is expected to be more complicated and less dispatchable and utilities will need to forecast both generation and load, without full control over either.”
Andy Lubershane
Director of Research, Energy impact Partners
The bulk of value through 2030 is in avoided capital expenditures for new generation, especially for energy rather than capacity, Brattle estimated. Avoided expenditures for transmission and distribution infrastructure, and for ancillary services, will add value.
Huge potential
From DR to load flexibility
DR doubled nationally between 2005 and 2015 and has now reached 59 GW, by far the biggest source of DER, Brattle found.
“Historically, utilities and grid managers could forecast their load, but had no control over it, but could use DR to turn power generation on and off to meet load,” Energy impact Partners (EIP) Director of Research Andy Lubershane told Utility Dive. EIP acts as a technology investor for 14 utilities and utility holding companies.
“In the future, generation is expected to be more complicated and less dispatchable and utilities will need to forecast both generation and load, without full control over either,” Lubershane said. “A more flexible and responsive load makes system balancing at least somewhat controllable.”
EIP expects load flexibility to become “one of the big power sector transformations in the next five years to ten years,” he added. It will involve “a complex technology stack.”
The technologies “are arriving,” but unevenly, he said. Residential and C&I consumers “are buying the end-user devices,” but utilities are only “beginning to think about tools they need for those devices to benefit both consumers and the grid.
“A large water tank with a wi-fi enabled smart controller is a big resource because heating can be ramped up or down almost instantaneously, so it can offer daily load shifting or frequency regulation.”
Ryan Hledik
Principal, Brattle Group
As variable generation and DER grow, control, automation, price-setting software and related technologies will become “mission critical” for utilities who want to take advantage of it as flexible load, Lubershane said.
Technologies that are proven but awaiting deployment are “the low hanging fruit” of load flexibility, Regulatory Assistance Project Senior Advisor Jim Lazar told Utility Dive. “There are 60 million electric water heaters in the country. The estimated 2 million being controlled shows they can be used. The other 58 million show there is work to do.”
A second category of load flexibility is available technology that lacks enabling policy or a compensation framework, Lazar said. Ice storage A/C, which circulates ice or chilled liquid to cool buildings, is used in only about 1% of big buildings, he said. It is a cost-effective source of flexibility and within reach if regulators “push utilities to offer rebates to drive competition and bring costs down.”
The third category is technology solutions for home automation and utility operational complexities that are not yet available or not yet fully realized, Lazar said.
The biggest DER
Flexible technologies
There are technologies in use and being piloted that utilities can use to make loads more flexible.
Smart thermostats have a presence in homes across the country and use of behind-the-meter batteries and EVs is emerging quickly as utilities recognize the opportunity and urgent need for managing new flexible loads.
Grid integrated water heating is a less recognized but “compelling” flexibility opportunity, Hledik said. “A large water tank with a wi-fi enabled smart controller is a big resource because heating can be ramped up or down almost instantaneously, so it can offer daily load shifting or frequency regulation.”
A/C load is a much bigger missed flexibility opportunity, Lazar said. Storage of water frozen or chilled with off-peak, low cost electricity and circulated to cool buildings when power is higer-priced is like battery storage for A/C.
The Ice Bear is the dominant ice energy storage product in the DER space. Of the approximately 265 providing just over 4 MW of ice energy storage to Southern California Edison, two at one youth center saved one municipality an estimated $4,000 in 2018, Ice Energy Operations Director Andrew Chang told Utility Dive.
Four large water chillers built by Austin Energy serve 67 customers, offset 19.2 MW, or 1%, of the 1,700 MW peak load, and save users an estimated $1 million per year, utility spokesperson Andrew Gallo told Utility Dive. The water is chilled overnight with low-cost wind from the Texas grid, allowing the utility to lower all customers’ costs by avoiding transmission charges and distribution system upgrades.
“The unique value of water heater and A/C loads is that the utility can control them at the circuit level,” Lazar said. “Commercial substations and residential circuits peak at different times and the utility can suppress those loads individually.”
An unappreciated flexible load
Flexible but dubious utilities
Utilities are moving from DR to load flexibility deliberately, with differing expectations and methods. Many remain dubious.
The Green Mountain Power (GMP) behind-the-meter battery load flexibility program is “a national model,” Lazar said. The Vermont utility and its customers “split the costs and benefits evenly.”
The program has attracted over 2,700 customers and now includes 11 MW of load flexibility through batteries, EV charging, water heaters and heat pumps, GMP spokesperson Kristin Kelly emailed Utility Dive. The battery programs have generated over $800,000 of net value for GMP customers since 2018 and provided participating customers with “thousands of hours of backup power.”
Arizona Public Service (APS) has moved in the last three years from DR programs for C&I customers to load flexibility programs for residential customers, APS Director of Resource Planning Jeff Burke told Utility Dive.
“When we started adding solar to our grid, we noticed changes in loads and load shapes and we recognized our existing fleet needed to be more flexible.”
Jeff Burke
Director of Resource Planning, Arizona Public Service
“When we started adding solar to our grid, we noticed changes in loads and load shapes and we recognized our existing fleet needed to be more flexible,” he said. “It is an evolution in resource planning to maintain a reliable system.”
Through its A/C program, APS accesses 10,000 internet-integrated residential smart thermostats to pre-cool homes and reduce peak demand. A pilot grid integrated water heater program targets a similar load shift. Still undetermined is “how many of our 1.2 million customers will enroll and how many will override utility controls,” Burke said.
Renewables-driven variability limiting the benefit of Xcel Energy Minnesota’s traditional DR program also turned it toward “new ways to make load more flexible,” Xcel manager of demand side strategy Shawn White told Utility Dive.
Xcel has pilots to get peak demand reductions but no system-wide load flexibility programs, White said. Programs reward businesses and residential customers for allowing direct utility control of air conditioners, smart thermostats and other devices.
The utility’s most recent integrated resource plan (IRP) proposed new “traditional programs” and “non-traditional opportunities” for load flexibility with DER. But, White said, Xcel-commissioned research by Brattle showed the value proposition in peak shaving and grid services may be limited until system changes and renewables penetrations accelerate.
Pepco Holdings has operated traditional voluntary participation, direct load control DR programs driven by price signals since the early 1980s, Steve Sunderhauf, Principal for its Utility of the Future effort, told Utility Dive.
“Direct load control is a firm and reliable resource and a price signal ties it directly to system conditions and gives the customer the option of not responding,” Sunderhauf said. “Significant value” has been validated by hourly data collected from Pepco’s advanced metering infrastructure and monetized in wholesale markets.
“The next step is working with plug and play DER technologies that can connect into the utility system,” Sunderhauf said. But “multiple smaller scale injection points will require things like smart inverters, battery storage, and EV chargers to provide flexibility to help manage power quality and power flows.”
Portland General Electric was an early leader in load flexibility, PGE manager for strategic marketing Kyle Barton emailed Utility Dive. Offerings include smart thermostat, rebate, grid integrated water heating, and smart EV charging programs, and a residential storage pilot program. A new 20,000 customer smart grid pilot will test price signals and incentives. A 2020 pilot will study the benefits of stacking flexible products, allowing EV charging, behind-the-meter storage, and grid integrated water heating to be part of a single aggregate flexible offering.
But there are challenges ahead, PGE Director of Retail Technology Strategy Conrad Eustis emailed Utility Dive. Switches with one-way communications used for traditional DR are inadequate to meet the needs of a high renewables future.
“To avoid customer impact, each load must ‘know’ when shifting will impact a specific customer and when the customer has flexibility to use more or less energy,” Eustis said. Home appliances with this capability “will take two decades” to scale. That would mean Brattle’s 200 GW load flexibility forecast for 2030 could probably not be implemented until 2050, and then only if there is “a standardized communication link between the utility and the customer.”
“For some transformative flexible technologies, states are not moving ahead, competition is lacking, and some utilities have operational tools that are state of the art for 1959.”
Jim Lazar
Senior Advisor, Regulatory Assistance Project
Load flexibility has been “the driving principle” of Hawaiian Electric Companies (HECO) planning since 2014, HECO head of operationalizing DER Richard Barone emailed Utility Dive. Implementation has been through “contracts between the Companies and third party DER aggregators.”
Eventually, the services “will play an essential role,” Barone said. The technologies needed “are advancing on the right trajectory” but “there are incredible complexities around internal operational processes” for orchestrating DER, rate design, and market development and “getting the economics right.”
Predictions
Brattle makes three predictions for load flexibility through 2030. The first is that “programs will get smarter before they get bigger.”
Traditional DR programs will continue to be key for meeting peak demand, Hledik said. “The most cost-effective flexibility option will be in modernizing programs with more effective marketing and updated program rules to allow utilities to get more out of what the system now has.”
The second prediction is that residential load flexibility capacity will become bigger than the capacity in the C&I sector, driven by residential customers’ adoption of DER that add up to enormous flexibility potential.
Finally, Brattle expects regulators to provide incentives vitally needed to drive growth.
“For some transformative flexible technologies, states are not moving ahead, competition is lacking, and some utilities have operational tools that are state of the art for 1959,” Lazar said. “Incentives can change that. There are complications and costs in deploying load flexibility, but not deploying it also has costs and complexities.”
