Price-based demand response enters a new era, but utilities and regulators still need to verify its potential

New research shows that demand response can go beyond traditional load control if flexible power system support that aggregates customer-owned resources is properly valued.

A study released in November 2023 by Lawrence Berkeley National Laboratory (LBNL) noted that utilities may find price-based demand response (PBDR) programs to be among the most cost-effective planning options if they recognize how these programs use price signals to change customer electricity usage behavior. However, the study emphasized that cost-effectiveness must be based on a complete analysis of factors affecting PBDR program participation and load reduction.

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

Seth Frader-Thompson, president and CEO of software provider EnergyHub, said, "The assumptions used in current long-term resource and distribution system planning do not fully recognize the role of PBDR in addressing emergencies caused by generation or transmission losses." He added, "The wealth of historical performance data in today's software significantly reduces the reliability risk of aggregated responses from millions of DERs."

There are also views that PBDR's value proposition is not yet easy to realize.

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

The U.S. Energy Information Administration (EIA) defines PBDR programs that use time-varying rates (TVR) as those "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 remain important. But utilities insist that load flexibility from TVR-driven PBDR programs could be extremely valuable—provided their reliability and cost-effectiveness are validated under real operating conditions. PBDR advocates say that validation is happening.

Planning gaps

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

Juan Pablo Carvallo, LBNL research scientist and lead author of the paper, said many utility system planners make "very critical but unsupported quantitative assumptions" about the value of demand-side resources and "lack explanations of rate structures or why a certain level of PBDR is used."

Lisa Schwartz, strategic advisor in LBNL's energy markets and policy department and co-author of the paper, added that accurate valuation becomes more important as PBDR program costs become more competitive compared with other resources. She noted that PBDR programs include smart thermostats, appliances, electric vehicle and home battery chargers, and home water heating and space 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 energy market prices.
• Variable peak pricing provides fixed prices one day in advance.
• Critical peak pricing raises prices during limited periods of exceptionally high demand.
• Critical peak rebates reward customers for reducing usage during those periods.

LBNL reports that among the programs studied, TOU rates were most common, critical peak pricing saw some use, and more complex rate types were rarely used.

Customers voluntarily choose "opt-in" TOU rates, but "opt-out" TOU rates are not chosen. Mandatory TOU rates offer no choice. LBNL cites the Brattle Group's Arcturus survey covering more than 400 programs, reporting an 85% participation rate for "opt-out" and a 28% participation rate for "opt-in."

Carvallo said these and other PBDR program factors, such as whether customers have enabling technologies, are often not reported in programs. But these factors are critical to participation and load reduction rates—key parameters planners use to compare PBDR with traditional energy and load reduction resources—making it difficult to determine whether better planning data could prove PBDR's reliability and cost competitiveness.

Carvallo also noted that PBDR's cost-effectiveness might be better validated through the levelized cost of capacity proposed in the study, a metric similar to Lazard's well-known levelized cost of energy. "It's dollars per kilowatt-year for each PBDR resource," he said, adding that a more "granular understanding" of PBDR is needed to value it accurately.

LBNL's Schwartz added that PBDR's distribution-level value 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 & Electric, Xcel Energy, Con Edison, and Portland General Electric validate this potential.

Utility skepticism

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

Dan Scripps, chair of the Michigan Public Service Commission (MPSC), said, "Large energy consumers in Michigan, such as Hemlock Semiconductor, the state's largest load, are beginning to look at the possibility of savings by following market signals." But he added that before introducing new aggregated residential and commercial and industrial PBDR programs, regulators "must ensure that resources will show up and perform well."

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

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

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

Morey said, "Programs that rely on customer behavior have more uncertainty." But he added, "Over time, across 1 million customers, this can become more predictable and consistent, like a portfolio."

Morey continued, SRP's 90,000 smart thermostats "provide about 100 megawatts of capacity that planners can call on during peak periods." SRP now aims to build other PBDR programs "to make them more cost-effective than alternative capacity resources."

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

Morey continued, "Only the PBDR program using thermostats has passed SRP's cost-effectiveness test. Utilities want and need other types of PBDR to ease electrification pressures, but there is insufficient data on large-scale flexible loads to develop good planning cost and value assumptions."

Xcel's Jackson said the recent Xcel Minnesota 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." But she added, "Customers must choose to buy the technology and participate, and programs must perform like other generation resources, or system operators cannot rely on them."

Jackson acknowledged that larger PBDR programs including a broader range of DERs could support higher reliability. But she added that this requires better communications, utility control rooms, and customer technologies.

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

Kerri Carnes, APS's director of customer technology, said, "Cool Rewards allows the utility to control thermostats within customer-set parameters and scaled quickly because it was designed to be as simple as possible and allows customers to opt out." But she added, "If those megawatts don't show up during the hottest periods of Arizona's summer, customers could face safety and health consequences."

Karnes said that to be cost-effective, PBDR programs' customer compensation, administration, platform, and marketing costs must be lower than the cost of alternative generation or infrastructure. She added, "Programs that contribute at the right times and have the highest participation are more valuable and have higher value."

Making it work

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

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

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

Frader-Thompson said EnergyHub's platform "handled at least 1,700 demand response events in 2023, involving about 1.25 million devices." He added that many utility planners do not yet understand that if the incremental use of PBDR programs is tracked and optimized at a very granular level to ensure flexibility remains available, then "the marginal cost for enrolled customers is essentially zero."

Frader-Thompson continued, "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. Planning and operations teams understood, included the programs in IRPs, regulators found the programs reliable and cost-effective, and approved investments."

Frader-Thompson added that utilities like APS and SRP are now in this cycle, although "distribution planners are a few years behind in valuing distribution system benefits."