Is Time-of-Use Pricing Not Enough? BGE and Other Utilities Expand Active Charge Management to Handle Surging EV Load

If not managed effectively, transportation electrification could become the most disruptive new electricity demand on the power system—a judgment widely shared by analysts and utility executives.

A 2023 study by the National Renewable Energy Laboratory (NREL) found that electric vehicle owners, despite facing longer charging times, still prefer lower-cost, more convenient home charging. However, to keep pace with the growth in EV charging and other customer demand, NREL found in a 2024 study that U.S. utilities had already invested more than $60 billion annually in distribution systems by 2021.

Pacific Gas and Electric (PG&E) CEO Patti Poppe acknowledged at the RE+ 2024 clean energy conference in September that this investment is necessary to "optimize, visualize, and control" new distribution system resources. But she also stressed that revenue from new electricity sales would "offset infrastructure investments" and "reduce bills for all customers by 2% to 3%."

According to a report just released by the Smart Electric Power Alliance (SEPA), using active charge management rather than time-of-use rates to shift charging to off-peak hours can save an additional approximately $300 per vehicle per year.

"It's becoming increasingly clear that time-of-use rates are no longer sufficient," said Brittany Blair, co-author of the report and senior analyst for research and industry at SEPA. "They are creating secondary peaks, which in turn cause distribution system congestion." She added that "active charge management" implemented by utilities and third parties "will be necessary to unlock the full potential of EVs and reduce distribution system impacts."

Pilot projects have proven that active charge management works, and utilities in Maryland and other states are moving to scale these programs. But key questions remain: Will state regulators and stakeholders accept the value proposition of distribution system modernization investments? And how can customers be willing to hand over control of charging to utilities or third parties?

The 'rebound peak' challenge

According to a report released in October 2024 by the Edison Electric Institute (EEI), the trade association for investor-owned utilities, the number of electric vehicles on U.S. roads could reach 78.5 million by 2035, up from just 4.5 million in 2023.

Although time-of-use rates can shift residential and commercial electricity use away from peak demand periods, a report just released by the Electric Power Research Institute (EPRI) argues that time-of-use rates are limited in managing EV charging. The research confirms that charging behavior often begins immediately after the discounted rate starts, creating so-called secondary peaks or "rebound peaks."

Chanel Parson, director of clean energy and demand response at Southern California Edison (SCE), said time-of-use rates "definitely help" because they limit system strain during the "main peak" period. But she acknowledged that a secondary peak quickly follows the end of the peak period.

Parson noted that if utilities are allowed to "orchestrate flexible loads to prevent local distribution system congestion," this secondary peak could be managed to "ramp in gradually." She added that if "there are incentives to encourage customer participation, whether from the utility or third-party aggregators," utility-managed charging could spread charging behavior across the off-peak hours of the time-of-use rate.

Kay Aikin, founder and chief product officer of consulting firm Dynamic Grid, said an approach that "phases distribution system investments with EV growth" could leverage new accelerated computing capabilities to transmit electricity market price information to local substations. She added that this "substation intelligence," while not yet widely tested, could manage charging through "charging price signals with preset customer parameters," thereby "eliminating direct utility control."

Another approach is the smart electrical panel—an energy management system that automatically cuts off charging when EV charging could exceed a home's rated service capacity, explained Stephen Kane, director of residential builder services at SPAN.

But he acknowledged that if multiple homes in a neighborhood charge EVs simultaneously, total load at the feeder or transformer level could still become a problem. "Utilities must be responsible for system-level load," Kane said.

Today, many stakeholders have come to realize that a proven solution is active management of charging by utilities or third parties.

Active charge management solutions

Analysts and utility executives agree that with more than 3 million EVs already on U.S. roads, charge management pilot programs need to be scaled before infrastructure upgrade costs begin to climb.

SEPA's Blair said that, as documented in the SEPA report, "utilities have already conducted enough active charge management pilots to understand their value and effectiveness."

Garrett Fitzgerald, SEPA's senior director of electrification and co-author of the report, noted that utilities do not need full control over EV charging. He said many utilities are beginning to realize that third-party aggregators with distributed energy resource management systems (DERMS) at the distribution system level can effectively execute signals from utility control rooms.

According to the SEPA report, a 2021 study by Arizona's Salt River Project, Pacific Gas and Electric's ChargeForward program in California, and National Grid's Charge Smart program in New York are examples of such utility progress.

"The vast majority of the value we are quantifying and designing customer compensation around comes from reducing system-wide peak energy costs," Fitzgerald said. But "the value varies by customer, and charge management can be optimized to focus on those customers who need to adjust their charging behavior, rather than adjusting all customers."

Kellen Schefter, senior director of electric transportation at EEI, agreed that utilities recognize that minimizing EV charging costs and maximizing their benefits through active management can put downward pressure on rates for all customers and improve system reliability.

Schefter continued, noting that a January 2024 study by Synapse Energy Economics showed that "revenues have exceeded the costs of charge management programs" and provided guidance on "the art of program design." "A program design that changes individual customer behavior may also need to be paired with time-of-use rates, a one-time bill credit at enrollment, or ongoing participation incentives distributed monthly or annually," he said.

Schefter said the EV advocacy coalition ChargeScape found that Duke Energy Carolinas' EV Complete home charging program and Xcel Energy Colorado's Charging Perks pilot used very different incentive approaches, yet both achieved good participation.

"Solutions that offer different options to meet different customer needs may be necessary," Schefter added. But "programs can now be scaled cost-effectively," and Baltimore Gas and Electric (BGE) is proving this—its newly approved program will serve up to 30,000 EV owners.

BGE program sets a new benchmark

In a presentation to RE+ attendees on September 10, Stephanie Leach, manager of strategic projects at BGE, explained that BGE's passive time-of-use charging pilot gave rise to its active EV Smart Charge Management (SCM) program in partnership with third-party aggregator WeaveGrid.

"EV charging load is now a major concern for nearly every large utility, because even in areas with low EV adoption, some high-adoption communities may exceed local system capacity," Leach continued. She added that WeaveGrid uses BGE's rate and system demand information to optimize charging at the grid edge based on EV owners' preset preferences.

"We are still advancing our benefit-cost analysis by modeling the costs of distribution system upgrades with and without charge management," Leach added.

Analysts generally agree that the cost of serving current and future EV charging demand could be high. But stakeholders also acknowledge that building out the distribution system to support active charge management also requires significant investment.

Managing charge management programs

Grid modernization regulatory proceedings and rate cases have shown that the costs of implementing and deploying charge management programs and technologies can put upward pressure on electricity rates.

Parson said SCE "is developing a large-scale charge management program that will include time-of-use rates, one-time cash incentives, and other incentives to cover equipment costs." She added that to meet California's 2045 net-zero target, more than 80% of expected electricity demand growth will require utilities to deploy DERMS, system-wide hardware and software, and grid-edge technologies.

To avoid passing costs on to non-EV owners, Parson said SCE is considering "grant funding and industry partnerships."

Mathias Bell, vice president of market development at WeaveGrid, said BGE's SCM pilot will expand to enroll 30,000 EV owners by 2027, but this will defer or minimize distribution system capital investments needed to handle EV charging load. Bell said WeaveGrid's EV management system and customer-facing DERMS reduce the need for utility investment at the grid edge.

"The pilot demonstrated a benefit-cost ratio of 1.58 under Maryland's jurisdiction-specific testing requirements, showing that benefits exceed program costs," Bell said. He added that "92% of the charging load managed through SCM adhered to the charging schedules set by BGE and WeaveGrid."

Bell said WeaveGrid is also working on active EV charge management with Portland General Electric in Oregon, Pacific Gas and Electric in California, Xcel Energy in Colorado, DTE in Detroit, and Southern Company's Georgia Power and Alabama Power subsidiaries.

Erika Diamond, senior vice president of customer solutions at grid-edge DERMS provider EnergyHub, agreed that active charge management is ready for scale.

"Managing charging is complex" because utility control rooms expect both "effective load shifting" and "customer satisfaction," Diamond said. But a full utility control room DERMS takes time to design and implement, while "grid-edge DERMS can be deployed in as little as weeks," which is why utility partnerships with aggregators are growing, she added.

Monika Jovic, product marketing manager for digital grid at Schneider Electric, confirmed in a July webinar that integrating DERMS into a utility control room can take six to nine months. Jovic said grid-edge DERMS, deployed and managed by third-party aggregators, can manage flexible distributed resources such as EV charging to "replace traditional resources."

Diamond said EnergyHub "has programs involving more than 100,000 devices" and "is working with utility planning, operations, and demand-side management teams." Its grid-edge DERMS combines utility control room information with its situational awareness at the distribution system level "to balance supply and demand and match load profiles," she added.

"Most utilities and aggregators have not yet quantified the full range of energy, capacity, and ancillary service value that charge management can provide beyond peak shaving," Diamond continued. Determining this full value may "require an evolution in the value paradigm for distributed resources," she said.