Demand response can be more than traditional load control if flexible power system support from programs aggregating customer-owned resources is properly valued, new research finds.
Utilities that recognize how price-based demand response, or PBDR, programs can change customer electricity usage through price signals may find them the most cost-effective planning option, a November 2023 Lawrence Berkeley National Laboratory, or LBNL, study found. But cost-effectiveness requires a complete analysis of factors that impact participation in and load reductions of PBDR programs, the study said.
Some utilities are beginning to see PBDR program benefits in optimizing dispatch with aggregated customer-owned distributed energy resources, or DER.
“The assumptions used in today’s long term resource and distribution system planning do not give full credit to [PBDR] for its impact on contingencies created by generation or transmission losses,” said Seth Frader-Thompson, president and CEO of software provider EnergyHub. “Huge amounts of historical performance data used in today’s software significantly reduces the reliability risk of cumulative response by millions of DER,” he added.
Others see PBDR’s value proposition as not yet achievable.
PBDR “is absolutely part of the system of the future, but that will require an evolution of what customers pay attention to” and “the new technology adoption curve has to change,” said Xcel Energy Senior Vice President, System Strategy, and Chief Planning Officer, Alice Jackson. “More customers have to be willing to arbitrage through price signals” and “the utility needs to make it easy,” she added.
The Energy Information Administration defines PBDR programs with time-varying rates, or TVR, as “designed to modify patterns of electricity usage, including the timing and level of electricity demand."
Traditional demand response, or DR, programs allowing utilities direct control of large customer loads like air conditioning will continue to be important, researchers and utilities agree. But the load flexibility from TVR-driven PBDR programs could be invaluable — if reliability and cost-effectiveness can be confirmed in real-world operating conditions, utilities insist. Advocates for price based demand response programs say that is happening.
Planning shortcomings
PBDR is used in many bulk system integrated resource plans, or IRPs, and some distribution system plans, “but assumptions about its value are not clear,” the LBNL authors reported.
Many utility system planners make “very critical unsupported quantitative assumptions” demand side resources’ value, and “lack an explanation of how rates are structured or why a level of PBDR was adopted,” said LBNL Research Scientist and study lead author Juan Pablo Carvallo.
Accurately valuing PBDR programs becomes more important as their costs become competitive with other resources, LBNL Energy Markets and Policy Department Strategic Advisor and paper co-author Lisa Schwartz added. PBDR programs include smart thermostats and appliances, EV and home battery chargers, and home water heating and heating and cooling systems, she added.
There are five key types of time-varying rates in PBDR, according to the Department of Energy.
Time of use, or TOU, rates set higher electricity prices during daily demand peaks. Real time pricing follows wholesale energy market prices. Variable peak pricing offers fixed prices a day ahead. Critical peak pricing increases pricing during limited atypically high demand hours. Critical peak rebates reward customers for reducing usage during those hours.
TOU rates were the most common found, critical peak pricing rates were somewhat used, and the more sophisticated rates were rarely used in the plans studied, LBNL reported.
Customers voluntarily choose “opt-in” TOU rates, but choose not to use “opt-out” TOU rates. Mandatory TOU rate offers provide no option. Brattle Group’s Arcturus survey of over 400 offerings, cited by LBNL, found opt-out participation was 85% “compared to 28% for opt-in” participation, the paper reported.
Plans frequently do not report those and other PBDR program factors, like whether customers have enabling technologies, Carvallo said. But they are critical to participation and load reduction rates, the key parameters in planners’ comparison of PBDR with more traditional energy and load reduction resources, which makes it unclear if better planning data could justify PBDR reliability and cost competitiveness, he added.
PBDR’s cost-effectiveness might also be better validated by the levelized cost of capacity proposed by the study as analogous to Lazard’s widely-known levelized cost of energy, Carvallo said. “It is a $/kW-year for each [PBDR] resource” and shows how a more “granular understanding” of PBDR is needed to accurately value it, he added.
PBDR’s distribution level value depends on it providing needed system services at specific times and locations to avoid costs for distribution system alternatives, added LBNL’s Schwartz. Utility pilots or programs at Southern California Edison, San Diego Gas and Electric, Xcel Energy, Consolidated Edison and Portland General Electric verify the potential, she said.
Regulators and utilities do not question PBDR’s potential, but they have other questions.
Utility doubts
Utilities and regulators recognize PBDR’s potential but lack verification of its reliability and cost-effectiveness.
“Major Michigan energy consumers like Hemlock Semiconductor, the largest load in Michigan, are starting to focus on savings possible by following market signals,” said Michigan Public Service Commission, or MPSC, Chair Dan Scripps. But before introducing new aggregated residential and C&I PBDR programs, regulators “must be certain the resources will show up and perform,” he added.
The MPSC is studying impacts of PBDR pilots because comparable energy efficiency programs show load reductions “saving over 1.5 times their cost and reducing usage over 2% per year,” he said.
But regulators “have a natural conservatism in planning,” Scripps said. The MPSC needs evidence from markets that customers and their aggregators will respond to price signals, and that “flexibility can protect reliability,” he added.
Salt River Project, or SRP, PBDR programs capture the utility challenge. About 45% of its 1 million residential customers are on different types of TOU price plans, said SRP Manager of Product Development Nathan Morey.
“There is more uncertainty with programs dependent on customer behaviors,” Morey said. “But over time, across a million customers, that can become more predictable and consistent, like an investment portfolio,” he added.
SRP’s 90,000 smart thermostats provide “about 100 MW of capacity the planners can call as peak hour capacity,” Morey continued. SRP’s goal now is to build other PBDR programs “more cost effective than alternative capacity resources,” he said.
“There is tremendous potential value in leveraging customer-side devices and resources,” Morey said. “But that will require years of developing consumer products, convincing consumers to participate, and building programs with the right incentives, and batteries and EV chargers will add to those challenges,” he added.
“Only PBDR programs using thermostats pass SRP cost effectiveness tests,” Morey continued. “Utilities want and need other types of PBDR to relieve the pressure from electrification, but there is not enough data on flexible loads at scale to develop good planning cost and value assumptions,” he said.
The recent Xcel Minnesota IRP proposed using PBDR to “offset acquiring over 2,100 MW of generation by 2030,” and “cost benefit analyses show most programs’ benefits are greater than their costs,” said Xcel’s Jackson. But “customers must choose to buy the technologies and participate in the programs, and the programs must perform like other generation or system operators cannot count on them,” she added.
Bigger PBDR programs that include a wider range of DER could support even greater reliability, Jackson acknowledged. But that will require better communications, utility control room, and customer technologies, she added.
Sacramento Municipal Utility District and Puget Sound Energy programs are only beginning to impact planning, their representatives reported. But Arizona Public Service, or APS, a leader in deployed PBDR programs, shows today’s limits.
“Cool Rewards allows utility control of thermostats within customer-set parameters and has scaled rapidly because it was designed to be as easy as possible and allow customer opt-outs,” said APS Director of Customer Technology Kerri Carnes. But “if those MWs don't show up in the hottest parts of the Arizona summer, there can be safety and health consequences for customers,” she added.
To be cost effective, PBDR program costs for customer compensation, administration, platform and marketing must be lower than costs for alternative generation or infrastructure, Karnes said. “Programs that contribute at the right time and have the most participation are more valuable and have higher value,” she added.
Making it work
Validation of PBDR’s potential is emerging, according to advocates of next generation demand response programs.
“Planning models often oversimplify the benefits” of PBDR performance, said Brattle Group Principal Ryan Hledik, who has led studies of load flexibility’s potential in building electrification. But “APS has more than half of its residential customers on voluntary TOU rates,” which shows “more participation can be achieved if DR is prioritized,” Hledik said.
“Arcturus data shows customers with TVR and enabling technologies like programmable thermostats do respond to price signals,” added rate design consultant Ahmad Faruqui, a former Brattle Group Principal. Good rate design that recognizes customer priorities “can produce even better participation and get more load reduction,” though programs “are still being developed and errors can happen,” he cautioned.
EnergyHub’s platform “handled at least 1,700 demand response events with about 1.25 million devices in 2023,” said Frader-Thompson. Many utility planners don’t yet understand that incremental uses of PBDR programs, if tracked and optimized in a very granular way to ensure the flexibility remains available, have “essentially zero marginal cost for customers already enrolled,” he added.
Where planners include PBDR in IRPs, “a utility demand-side management team has used software to optimize program flexibility and shown planners and operators how it can impact system conditions in real time,” Frader-Thompson continued. “The planning and operations teams understood, included programs in the IRP, and regulators saw the programs as reliable and cost-effective and approved the investments,” he said.
Utilities like APS and SRP are in that cycle today, though “distribution planners are a few years behind on determining the distribution system value,” Frader-Thompson added.
