Price-Based Demand Response Enters a New Phase, but Utilities and Regulators Still Need to Verify Its Potential

Demand response could go beyond traditional load control if the flexible power system support provided by aggregating customers' own resources is properly valued—this is the conclusion of the latest research.

A study released in November 2023 by Lawrence Berkeley National Laboratory (LBNL) shows that utilities could view price-based demand response (PBDR) programs as the most cost-effective planning option if they recognize how price signals change customer electricity usage behavior. However, the study also notes that determining cost-effectiveness depends on a complete analysis of various factors affecting PBDR program participation and load reduction.

Some utilities have begun to see the benefits of PBDR programs in optimizing the dispatch of aggregated customer-owned distributed energy resources (DER).

"The assumptions used in today's long-term resource and distribution system planning do not fully recognize the value of PBDR in emergencies caused by generation or transmission losses," said Seth Frader-Thompson, president and CEO of software provider EnergyHub. "The vast amount of historical performance data accumulated in existing software has significantly reduced the reliability risk of aggregating millions of DERs," he added.

There are also views that PBDR's value proposition is currently difficult to realize.

"PBDR is definitely part of the future system, but it requires an evolution in customer focus, and new technology adoption curves must change," said Alice Jackson, senior vice president of system strategy and chief planning officer at Xcel Energy. "More customers must be willing to arbitrage through price signals, and utilities need to make the process easy," she added.

The U.S. Energy Information Administration (EIA) defines PBDR programs using time-varying rates (TVR) as mechanisms "designed to change electricity usage patterns, including the timing and level of electricity use."

Researchers and utilities agree that traditional demand response (DR) programs, which allow utilities to directly control large customer loads such as air conditioners, will continue to play an important role. But utilities insist that the load flexibility provided by TVR-driven PBDR programs could be extremely valuable—provided their reliability and cost-effectiveness are confirmed in real operating environments. Advocates of price-based demand response programs say this validation is happening.

Planning-level shortcomings

LBNL authors report that PBDR has been used in many large-system integrated resource plans (IRP) and some distribution system plans, "but its value assumptions are not clear."

"Many utility system planners make 'very critical but unsupported quantitative assumptions' about the value of demand-side resources without explaining rate structures or why a certain level of PBDR is used," said Juan Pablo Carvallo, LBNL research scientist and lead author of the study.

Lisa Schwartz, strategic advisor in LBNL's Energy Markets and Policy department and co-author of the paper, added that as PBDR program costs become more competitive compared to other resources, accurately valuing them becomes increasingly important. She noted that PBDR programs cover smart thermostats and appliances, electric vehicle and home battery chargers, home water heating, and heating and cooling systems.

According to the U.S. Department of Energy (DOE), there are five main types of time-varying rates in PBDR.

Time-of-use (TOU) rates set higher prices during daily peak periods. Real-time pricing follows wholesale electricity market prices. Variable peak pricing sets fixed prices one day in advance. Critical peak pricing raises prices during limited periods of abnormally high demand. Critical peak rebates reward customers for reducing usage during these periods.

LBNL reports that TOU rates are most common in the plans studied, critical peak pricing has some use, and more granular rate types are rarely adopted.

Customers voluntarily choose "opt-in" TOU rates but often do not choose "opt-out" TOU rates. Mandatory TOU rates offer no choice. LBNL cites the Brattle Group's Arcturus survey covering more than 400 programs, reporting that "opt-out" participation is 85% "while 'opt-in' is only 28%."

Carvallo said planning documents often do not report the above and other PBDR program factors, such as whether customers have enabling technologies. But these factors are critical to participation and load reduction rates, which are key parameters for planners when comparing PBDR with traditional generation and load reduction resources. This makes it difficult to judge whether better planning data would be sufficient to demonstrate PBDR's reliability and cost competitiveness.

Carvallo also noted that PBDR's cost-effectiveness could be better validated through the capacity levelized cost proposed in the study, a metric similar to Lazard's well-known levelized cost of energy. "This is a dollar-per-kilowatt-year metric for each PBDR resource," indicating that a more "granular understanding" of PBDR is needed for accurate valuation, he added.

LBNL's Schwartz added that PBDR's value at the distribution level depends on its ability to provide needed system services at specific times and locations to avoid the costs of distribution system alternatives. She said utility pilots or programs at Southern California Edison, San Diego Gas and Electric, Xcel Energy, Consolidated Edison, and Portland General Electric validate this potential.

Regulators and utilities do not question PBDR's potential, but they have other concerns.

Utility concerns

Utilities and regulators recognize PBDR's potential but lack validation of its reliability and cost-effectiveness.

"Large energy users in Michigan, such as Hemlock Semiconductor, the state's largest load, have begun to focus on the possibility of savings by following market signals," said Dan Scripps, chairman of the Michigan Public Service Commission (MPSC). But before introducing new aggregated residential and commercial-industrial PBDR programs, regulators "must be confident that these resources will appear and perform," he added.

MPSC is studying the impacts of PBDR pilots because comparable energy efficiency programs show load reductions "save more than 1.5 times their costs and reduce annual electricity use by more than 2%," Scripps said.

But regulators "are inherently conservative in planning," Scripps said. MPSC needs evidence from the market that customers and their aggregators will respond to price signals and that "flexibility can ensure reliability," he added.

Salt River Project's (SRP) PBDR program illustrates the challenges utilities face. Nathan Morey, SRP product development manager, said about 45% of its 1 million residential customers are on different types of TOU rate plans.

"Programs that rely on customer behavior have more uncertainty," Morey said, "but over time, at the million-customer scale, this can become more predictable and consistent, like a portfolio," he added.

SRP's 90,000 smart thermostats "provide about 100 megawatts of capacity that planners can call on during peak periods," Morey continued. SRP's current goal is to develop other PBDR programs that are "more cost-effective than alternative capacity resources."

"There is huge potential value in using customer-side devices and resources," Morey said, "but it takes years to develop consumer products, convince consumers to participate, build programs with the right incentives, and batteries and EV chargers will add to these challenges," he added.

"Only PBDR programs using thermostats have passed SRP's cost-effectiveness test," Morey continued. "Utilities want and need other types of PBDR to relieve pressure from electrification, but currently there is insufficient data on scalable flexible load to develop good planning cost and value assumptions," he said.

Xcel Minnesota's recent IRP proposes using PBDR to "offset the need to acquire more than 2,100 megawatts of generation capacity by 2030," and "cost-benefit analysis shows benefits exceed costs for most programs," said Xcel's Jackson. But "customers must choose to purchase technology and participate, and programs must perform like other generation resources, otherwise system operators cannot rely on them," she added.

Jackson acknowledged that larger PBDR programs covering broader DER can support higher reliability. But this requires better communications, utility control rooms, and customer technology, she added.

Representatives from Sacramento Municipal Utility District and Puget Sound Energy reported that their programs are only beginning to influence planning. Arizona Public Service (APS), a leader in deploying PBDR programs, demonstrates current limitations.

"The Cool Rewards program allows the utility to control thermostats within customer-set parameters and has grown rapidly because it is designed to be as simple as possible and allows customers to opt out," said Kerri Carnes, APS director of customer technology. "But if those megawatts do not show up during Arizona's hottest summer days, it could have safety and health consequences for customers," she added.

Karnes said that to achieve cost-effectiveness, PBDR program costs for customer compensation, administration, platform, and marketing must be lower than the costs of alternative generation or infrastructure. "Programs that contribute at the right time and have the highest participation are more valuable and have higher value," she added.

Driving implementation

Advocates of next-generation demand response programs believe validation of PBDR's potential is emerging.

"Planning models often oversimplify the benefits of PBDR performance," said Ryan Hledik, principal at The Brattle Group, who has led research on load flexibility potential in building electrification. "But APS already has more than half of its residential customers on voluntary TOU rates," indicating that "if DR is prioritized, higher participation rates can be achieved," Hledik said.

"Arcturus data shows that customers on TVR with enabling technologies like programmable thermostats do respond to price signals," added Ahmad Faruqui, rate design consultant and former Brattle Group principal. Good rate design that recognizes customer priorities "can lead to better participation and more load reduction," although programs are "still evolving and mistakes can happen," he cautioned.

"The EnergyHub platform processed at least 1,700 demand response events in 2023, involving about 1.25 million devices," Frader-Thompson said. Many utility planners have not yet recognized that incremental use of PBDR programs—if tracked and optimized in a very granular way to ensure flexibility remains available—has "near-zero marginal cost" for enrolled customers, he added.

Where planners have included PBDR in IRPs, "utility demand-side management teams have used software to optimize program flexibility and show planners and operators how it affects system conditions in real time," Frader-Thompson continued. "Planning and operations teams understand this, include programs in the IRP, regulators see programs as reliable and cost-effective, and approve investments," he said.

Utilities like APS and SRP are now in this cycle, although "distribution planners are several years behind in determining distribution system value," Frader-Thompson added.