Time-varying electricity prices are not new. Certain electricity providers have offered residential customers some form of dynamic pricing for decades. But a growing number of utilities are turning to time-of-use, real-time, variable peak, or critical peak pricing models in response to changing market conditions and to accommodate or shape usage patterns related to new technologies.
According to the Energy Information Administration, about 860 utilities reported having customers enrolled in a dynamic pricing program in 2024. Of those, more than 620, including over 230 public power utilities, had a time-of-use rate. The most common TOU pricing is for commercial customers, but utilities that offer a residential TOU rate are on the rise. Research from The Brattle Group estimated that 15% of U.S. households were on time-variant electricity plans in 2025, up from just 4% in 2018.
Often, implementing these price plans requires utilities to deploy, upgrade, or replace grid technologies, from meters to the customer billing system. For many utilities, these investments provide returns in terms of delivering customer savings, reducing peak demand, and leveraging distributed and variable assets.
Encouraging Electrification
Concord Municipal Light Plant in Massachusetts first introduced opt-in TOU prices in 2008, shortly after installing advanced digital meters, to support customers who wanted to buy electric vehicles or install heat pumps or rooftop solar panels. Its initial enrollment drew fewer than 100 participants from its 8,300 customers.
In 2020, the town of Concord elevated the importance of electrification in its first Climate Action and Resilience Plan. But the increased use of electricity as an alternative to gas- and oil-fueled stoves, heating, and cars has an unwelcome side effect: higher electric bills.
CMLP, which serves a community about 15 miles northwest of Boston, also faces growing costs stemming from transmission and generation constraints. When peak demand increases, ISO New England often falls back on diesel generators to meet the need, which conflicts with the town’s environmental goals.
“Like many utilities, we had long relied on inclining block prices,” said Jason Bulger, director of CMLP. “We introduced TOU rates in 2008 as part of our effort to support customers and achieve our electrification goals. But as electric bills rose, TOU customers said they were feeling punished for doing what we asked them to do, which was use more electricity because it was a cleaner and more efficient energy option.”
Earlier this year, CMLP introduced a three-part time-of-day, or TOD, residential pricing plan that includes peak hours from 3–7 pm and “super off-peak” hours from 1–5 am.
“Overall, our goal is to encourage load shifting and provide greater benefits to customers with electric vehicles and heat pumps,” Bulger said.
The idea behind super off-peak periods is to persuade customers with EVs to charge their vehicles when demand, and wholesale electric prices, are lowest.
“Our hope is that our new TOD prices, which became effective in April 2026, better aligns incentives,” explained Laura Scott, assistant director for power supply and energy management at CMLP. “We want to continue promoting electrification while ensuring fairness, reducing peak demand, and supporting the city’s climate action plan.”
The public power utility decided to make the new prices opt-out rather than opt-in because its experience, as well as the experience of utilities across the country, had shown that few customers take the effort to enroll in a new program.
Now, nearly all CMLP’s 6,500 residential customers are on the TOD plan — only about 10 have chosen to opt out so far. CMLP priced the opt out rate 4% higher than the TOD rate to account for the tendency of high peak users to choose the opt out rate.
Transitioning to TOD prices required replacing all 8,300 customer meters with advanced digital meters and upgrading the utility’s billing software to more accurately track when electricity is used. Plans are underway to extend TOD pricing to the utility’s nearly 2,000 commercial and industrial customers.
In light of the success of this first phase of the TOD rollout, CMLP is also planning to refine its rate structures to create a greater difference between peak and off-peak prices, a move intended to more accurately reflect actual transmission costs. These might go into effect as early as 2027 and would represent a more finely tuned approach to time-variable rate design.
Providing Choice
In South Carolina, Santee Cooper has explored time-varying price structures for over three decades. The state-owned public power authority first introduced a residential TOU price in 1995 that required changing the customer’s meter and came with a higher monthly customer charge. There was no demand component in that price plan, and most residential customers stayed on the standard flat-price rate structure.
In 2022, Santee Cooper introduced a voluntary, opt-in pilot price plan for EV owners. About 100 customers signed up, and the plan helped EV owners pay far less for power when charging their vehicles during super off-peak periods.
In 2025, the utility ended its flat-price option, migrating residential customers to a demand billing option, with the choice of moving to a TOU rate. The demand billing plan included a demand charge based on the customer’s peak, while the TOU plan charged a higher price per kilowatt-hour during the system’s peak usage period.
The overwhelming majority of Santee Cooper’s residential customers, about 96%, are enrolled in the demand billing plan.
Some customers faced a learning curve on how demand charges work. The demand charge was set by multiplying a customer’s highest demand for electricity during one three-hour peak period each month by $8. Under this plan, a 3-kilowatt peak demand resulted in a monthly demand charge of $24, and a 6-kW peak cost $48. This charge was coupled with a reduced energy charge, in addition to the monthly customer charge, taxes, and fees.
Recognizing how important electric bill predictability is to customers, the public power utility has proposed a revised suite of time-variant residential price plans that, if approved by its board of directors, will go into effect in early 2027. A new version of the demand billing plan, called Balanced Demand Billing, will average peak demand over multiple days (instead of just one) so customers won’t see a disproportionate spike from one-off events, like throwing a party.
The utility developed the new pricing plan based on the usage patterns of two residential customer clusters: Year-round residents, who typically use a lot of energy fairly consistently throughout a month, and part-time residents, such as owners of vacation homes, who tend to use less electricity each month but have greater variability month to month.
“Reducing customer demand is an important strategy for us, so our goal was to get customers to lower usage during peak periods,” said Devin Ritter, pricing manager at Santee Cooper. “But we also wanted to be fair to customers. We needed to align prices with costs. Customers who are using a greater proportion of their energy during peak periods need to pay those extra costs.”
As it developed its new pricing proposals, Santee Cooper held customer focus groups, convened several open house meetings, and launched a comprehensive and award-winning communications plan, “Defeat the Peak. Bank the Savings,” that included a humorous video in which two families, the Santees and the Coopers, engage in friendly competition to see which can lower their peak demand — and electric bill — the most.
The public power utility also posted a price calculator on its website to help customers assess which of the two available plans was best for them.
Ritter expects that the new balanced demand plan will reduce residential customers’ billed peak demand by about 20%, from an average of approximately 5.2 kW to about 4.1 kW.
Ritter said this year’s effort to change prices incorporates an important lesson from Santee Cooper’s earlier forays into time-variant prices. “People don’t like to be told when to eat dinner. Instead, they need to be provided tools and options on what they could do, so they don’t feel boxed in.”
Automating Actions
Customers of all kinds are seeing how energy technologies and electric prices can work in concert.
MCE is a community choice aggregator providing clean electricity to an estimated 600,000 accounts in four Northern California counties — Marin, Contra Costa, Napa, and Solano — in and around the Bay area. It serves a peak load of about 1,400 megawatts with a mix of 60%–100% renewable energy.
MCE has offered time-differentiated prices for many years. Its business model is partly driven by the unusual circumstances of the wholesale electric market in Northern California, where an oversupply of solar generation during midday summer pushes wholesale prices below zero. Over a year, below-zero prices occur an estimated 5%–10% of the time.
In MCE’s experience, “TOU prices are a strong starting point for helping customers avoid higher-cost peak hours,” said Jenna Tenney, director of communications and community engagement.
Most of MCE’s TOU plans align with a peak period between 4 pm and 9 pm, though some plans have slightly different weekday peak hours.
“TOU rates provide a clear signal that electricity costs more during the 4 pm to 9 pm peak, when demand is high and solar production is low,” continued Tenney. “But the greatest impact comes when customers have simple tools, education, and incentives to shift their energy use easily.”
Tenney said MCE’s focus has been on keeping programs simple. “Pair price changes with clear education and meaningful cost-based incentives, and make sure data and billing systems can support them,” she shared.
In 2021, MCE piloted MCE Sync, in which participating customers could download a smartphone application that automated EV charging decisions. The program was opened to all customers in 2022. When electricity prices are lowest, typically during the middle of the day during the summer, the app automatically begins charging registered EVs that are plugged into its system. Roughly 6,000 customers are now on the program.
By automating the EV charging decision, Tenney said, MCE is following a set-it-and-forget-it approach that spares customers the need to track changing electricity prices or make decisions on a daily basis. “That makes MCE Sync a practical example of how dynamic pricing can turn a price signal into an easy customer action,” she said.
When California ISO, the state’s grid manager, needs extra electric capacity, MCE Sync can pause EV charging during peak hours as well. During one September heat wave, Tenney noted that participants shifted about 5 megawatt-hours of charging out of the 4–9 pm window, roughly equal to a day’s electricity use for 300 households.
“TOU strengthens MCE’s role in the community by turning local energy values into a customer-facing price signal,” Tenney said. “It helps customers see when electricity costs more, helps them shift use when they can, and connect everyday choices to affordability, reliability, and cleaner energy. That is the value of local control — prices and programs are designed around community priorities.”
