The California Public Utilities Commission (CPUC) has approved guidelines for utilities to use to design dynamic electricity rates, with one commissioner asking for more research on whether implementing such rates will leave some customers further behind financially.

The decision applies to Pacific Gas and Electric, Southern California Edison and San Diego Gas & Electric, which must propose dynamic rates in their general rate cases for approval by the CPUC.

And it comes just weeks after publicly owned utilities Sacramento Municipal Utility District and the Los Angeles Department of Water and Power outlined their challenges with implementing the practice in reports submitted with the California Energy Commission. (See Calif. Utilities Move Cautiously on Dynamic Pricing.) The dynamic rate design idea comes from the CEC’s load-management standards.

“This is an exciting proposed decision and it really marks another step … to support California’s long-term goals: grid reliability, electrification and affordability,” CPUC President Alice Reynolds said at the commission’s Aug. 28 voting meeting, during which the decision was approved.

Reynolds said the decision addresses key demand flexibility — or dynamic rate — design elements: marginal energy costs based on CAISO’s hourly load; day-ahead prices at default load aggregation points; marginal generation capacity costs; marginal distribution capacity costs; marginal transmission costs; non-marginal costs; and line-loss factors.

“Demand flexibility is one of the most important things we are doing as a state and will help provide additional resources that we can use,” Commissioner Darcie Houck said at the meeting. “I know a lot of time, effort and thought has gone into this decision.”

The goal of dynamic rates is to “motivate customers to shift electricity consumption away from high-demand periods, when polluting, peaking plants run and electricity is most expensive,” Commissioner John Reynolds added at the meeting. “Dynamic rates promise to achieve this by providing accurate price signals that reflect actual grid consumptions.”

However, as California moves from the approved guidelines to implementing these new rates, it is important to evaluate their effect on different types of customers, he said.

It may prove true that factors like income, whether a customer owns their home, or a customer’s climate zone could “substantially impact their ability to shift energy usage to lower-cost hours,” he said.

“We should evaluate these rate design changes to understand these consequences,” he said. “This is an equity concern that I think we need to attend to.”

In the decision, the commission said community choice aggregators (CCAs) should be able to either design their own dynamic rate or use their associated IOU’s dynamic rate. IOUs should describe how they will collaborate with CCAs on dynamic rates and programs, the commission said.

Marginal vs. Fixed Costs

In the decision, the commission said IOUs’ dynamic rates must include a marginal generation capacity cost (MGCC), which is the cost to procure and maintain sufficient generation capacity to reliably serve an incremental unit of electric demand at all times, including during peak demand and ramping periods.

The MGCC price “must account for costs associated with both peak and flexible capacity needs during periods of grid stress,” the commission wrote. An IOU’s proposal must include a price component that recovers an IOU’s MGCC revenues “to ensure that generation capacity costs are appropriately reflected in DF rates.”

“I expect the marginal costs on our grid to be much lower than our current electric retail rates,” John Reynolds said at the meeting.

The reason for that is that California’s electric system has many fixed costs, he said.

“For example, using more electricity does not really change the amount of money needed to trim vegetation to reduce wildfire risk,” he said.

Historically, the state recovers these fixed costs in the electricity rate, making that rate higher than the marginal costs of energy.

However, the modest fixed charge that the state already adopted still “does not fully cover our fixed costs of the system,” John Reynolds said.

“There will be debate about which costs are actually marginal and which are fixed, and that’s healthy, and we will need policy decisions resolving that debate,” he said.

“As we make policy decisions evaluating the nature of marginal costs, I expect that truly reflecting marginal costs in hourly prices will be lower rates and higher fixed charges,” he added. “These will be revenue neutral … and should actually lead to a lower overall cost grid.”

But fully moving to hourly marginal pricing will mean customers who can shift their usage will “have greater opportunities for bill savings than customers with inefficient appliances and leaking homes that don’t stay cool on hot days,” he said.

The large IOUs should use CAISO’s locational marginal prices at default load aggregation points in CAISO’s day-ahead market, CPUC staff said in the decision. This approach provides customers with a degree of rate certainty because electricity prices in the day-ahead market at default load aggregation point prices represent a majority of load-serving entities’ actual energy purchase costs, staff said.