For utilities facing the rise of rooftop solar projects, plug-in electric vehicles, backup batteries and other types of distributed energy resources, mass-market demand charges are one of a few options for recovering costs from customers to keeping the grid running.
For most solar industry and utility consumer advocates, they’re a threat to be fought at every turn.
That’s how the demand-charge debate has played out in states over the past few years. Arizona Public Service tried to bring mandatory demand rates to all residential and small-commercial customers, but was fought back by consumer and solar advocates, and ultimately agreed to a settlement that made the rate purely optional. Eversource got Massachusetts regulators to approve a mandatory demand charge for residential solar customers in January, and it’s being challenged in court.
In a new white paper, the Alliance to Save Energy (ASE), a nonprofit research group, is proposing demand charges be adopted in some form as part of each smart-meter-enabled tariff or rate they pilot in the years to come. The logic: There’s got to be some way to link what it costs to keep the grid running in a renewable- and distributed-energy-rich future with what people pay to use it.
ASE’s call for demand charges is just one part of the multistage roadmap for careful, data-driven and customer-engaged rate design that it released Wednesday. The white paper, entitled “Forging a Path to the Modern Grid,” is the result of a two-year research effort. The so-called Rate Design Initiative included representatives from utilities, technology companies, regulatory experts, environmental groups, consumer advocates and other industry leaders.
As in previous scenarios, demand charges emerged as a topic of intense debate.
Amid the commonsense discussions around how to start pilot projects and educate customers, the call for demand charges “was the part of the paper that took the most discussion, the most thought,” said Natasha Vidangos, ASE’s director for research, in an interview. “There were people around the table who said, 'Absolutely not,' and people at utilities saying, 'Absolutely yes.'”
Vidangos added that “if designed right and piloted -- and we’re adamant about the importance of piloting and education campaigns -- and if people do respond to the demand-charge signal, it allows utilities greater stability of their revenues, and it offers increasing reliability to the grid.”
ASE suggests demand charges as the fifth action item on its list of suggestions for utilities, and only where advanced metering infrastructure (AMI) is fully deployed to deliver the granular usage data required. For those that do, the report suggests pilot projects to test “three-part rates” for all customers, including residential and small commercial customers.
Alongside volumetric pricing and fixed customer costs, demand charges that are “based on clear and demonstrable evidence of cost causation” and persuade customers to shift usage from high-cost to low-cost periods can help lower costs and improve energy efficiency, according to the paper.
“There are a lot of papers you’ll see out there that contrast demand charges and dynamic pricing,” said Vidangos. “We see them as complementary.”
Dynamic pricing, also known as time-of-use or variable pricing, adjusts the volumetric (cents per kilowatt-hour) prices that customers pay for energy, depending on the time of day or the month of the year. They’re the favored approach in California, Hawaii, Canada’s Ontario province, and other epicenters of mass-market residential rate reform.
ASE isn’t against dynamic pricing, Vidangos said. In fact, it recommends that utilities that haven’t yet deployed smart meters should start testing simple TOU rates, adjusted seasonally depending on local capacity-related and systemwide peak demand-related costs. Three-tier daily TOU rates are also part of its suggested recipe for smart-meter-enabled utility pilots.
But according to the utilities that helped craft ASE’s recommendations, the use of demand charges to achieve peak demand reduction “better reflects a customer’s actual use of the grid and contribution to system costs, and increases the economic efficiency of rate design.”
In large part, that’s because they can be designed to encourage customers to reduce their non-coincident peak usage, which impacts the sizing and load costs of the distribution circuits that serve them, as well as their coincident peak usage, or their maximum usage at times when the transmission grid at large is facing its peak.
Among the members disagreeing with that proposition, most argued that limiting non-coincident peak demand doesn’t align incentives with managing utility or system peaks, as well as being “difficult to manage and confusing for the average residential customer,” the report noted.
Demand charges have attained a negative reputation among consumer advocates, largely based on the worry that they could sock vulnerable customers with excessive bills. “There’s a concern that customers wouldn’t know how to respond to them,” Vidangos said.
“But there are examples out there, like Arizona Public Service, that have shown that customers who are well educated on it can use demand charges to their benefit,” she noted. The utility’s new opt-in program, while limited in scope, has shown “pretty clearly that people respond to the price signal and reduce their use during the peak time of the day.”
ASE also recommends that utilities consider multiple designs, such as seasonal- or time-of-day-specific windows for when demand charges will take effect, she said. “Demand charges can be set based on the highest 15-minute consumption or hourly consumption; it can be assessed all day or only at certain hours of the day.”
At the same time, the report noted that the choice of demand-charge structure -- such as the key question of whether to base the charge on coincident peak or non-coincident peak -- is an issue that lies beyond the scope of the paper. Answers to these questions should be based on "evidence presented regarding the efficiency and demand response effects of the approach proposed for the various components of costs for which rates are being designed.”
“The fundamental point is, we recommend taking a look at those new options,” Vidangos said, “In most parts of the United States, we’re still assessing tariffs based on a two-part tariff -- a fixed rate and a flat-rate volumetric charge. Increasingly, that is not working for the grid we want today, and it almost certainly won’t work for the grid we want for the future.”
