Utilities are facing fewer kWh to bill as demand remains flat.

While the reasons for the diminishing number vary,  utilities and regulators face the conundrum to cover the costs for delivering electricity as sales diminish.  Proliferating rooftop solar and energy efficiency have also caused peak demand to grow.

With these hurdles in mind, utilities and regulators are increasingly turning to rate design options for residential and commercial and industrial consumers. California is at the forefront of these efforts as the state sets ambitious renewable energy and climate goals. Utilities are not only facing stagnant demand, but possible defection from consumers looking to secure clean energy. In particular, the C&I sector makes up two-thirds of the state's power demand, which means the right rate design could unlock potential for grid assets. 

In response, the California Public Utilities Commission and utilities are eyeing new types of rates for the C&I sector as they seek to answer two overarching questions:  What is the rate design utilities will support? And what will it take to get customer buy-in for that rate design?

What makes a good rate design

Four fundamental economic goals compose rate design, Severin Borenstein, an energy economist at the University of California at Berkeley said at a recent forum on rate design in California.

The first is to motivate customers to use electricity only when “it is valued more than the full additional cost to society,” he said. That is called “economic efficiency of consumption.”

Distributing costs fairly, based on “societal views of fairness” and enable equal access to electricity are two of the goals as well. And the fourth one allows power providers to recover all costs, “including the opportunity cost of capital.”

What this means is that inefficient rates can result in higher power prices and unwanted outcomes like lower electric vehicle adoption. For instance, inefficient pricing is already driving “regulatory arbitrage,” he added. Distributed energy resources (DERs) and demand-side energy management providers are marketing to customers who take advantage of the differential between the actual price and the efficient price.

As the marginal cost of electricity goes up, demand for it should go down, according to economic theory. Where they cross is the efficient price of electricity. For most utilities, that efficient price yields a revenue shortfall and the potential for declining revenue because much of their distribution system costs do not drop with demand, Borenstein said. To address this revenue shortfall, utilities and policymakers are shifting to time-varying pricing.

Fixed charges are another popular option, since they stabilize revenues, but they are oftentimes inadequate price signals and result in inefficient pricing.

Utilities have traditionally said that fixed costs should be recovered with fixed charges “is not grounded in economics,” Borenstein added. Charges should recover the marginal cost, which is a combination of fixed and variable costs.

Utilities appear to agree now with Borenstein. Russ Garawacki, director of pricing design for Southern California Edison, said that the per-kWh component of current rates make consumer bills and revenues “more volatile.”

Another option are demand charges. This particular rate design tends to stabilize both bills and revenues. But traditional demand charges are not the answer, Borenstein said.  These are typically based on the customer’s peak usage period, even if it does not coincide with the system’s peak. Many argue this “non-coincident demand charge” sends the wrong price signal to reduce system costs. Instead, policymakers have proposed demand charges for the customer’s peak usage during the system’s peak. But, in economic terms, this “coincident demand charge” still fails to match cost causation as well as dynamic pricing, Borenstein said. If the customer’s peak use is not precisely at the system peak, the CDC fails to address the actual level of system stress caused by the customer’s usage.

When composing the perfect rate, utilities and policymakers must take into account protecting revenues in order to address equity, access and bill volatility issues, Borenstein said.  

“The challenge is to maintain as efficient consumption incentives as possible while also addressing other policy goals,” he said. “The question is how to make the trade-offs.”

The C&I experimentation

C&I customers account for about two-thirds of California’s electricity consumption and could become powerful grid assets should the proper rate design compel them to adopt energy efficiency and self-generating technologies. This is the theme of a recent paper from the Regulatory Assistance Project (RAP).

Carl Linvill, one of the paper’s authors, said policymakers can use technologies and the principles of rate design to accomplish their purposes.

If rates convey to the customer what the power system needs, the price signals "will increase supply, decrease demand, and thus decrease market clearing prices for energy, capacity, and services,” according to the paper.

New sensor, communications and storage technologies allow stakeholders to respond to ​better price signals with "more granular decisions about their energy use,” the paper noted.

Time-varying rate designs that introduce “dynamic pricing options” are needed “to better align private choice with the public interest,” the paper noted. Real-time pricing “can further refine price signals” but will be less widely used because they “require more sophisticated energy management.”

The paper adds two “smart non-residential rate principles” for all customer classes. First, a fixed charge should only be for “the service drop, metering and billing costs. But for “the proximate transformer” and everything beyond “affected by the non-coincident usage of the customer,” the customer should pay through a non-coincident demand charge.

Such charges should be otherwise de-emphasized in favor of time-varying pricing for “all shared generation and transmission capacity costs.” Secondly, distribution system revenue needs should be met with time-varying prices that are specific by location.

“This recognizes that some costs are required to provide service at all hours, and that higher costs are incurred to size the system for peak demands.” Time-varying rates should include price signals that impact marginal costs and help align “controllable load, customer generation, and storage dispatch” with system needs.

And all rates should begin with “an easy-to-understand default tariff that does not require sophisticated energy management.” Tariffs with more refined price signals that “require active management” should be optional. And, finally, C&I rate design should allow for regular redesigns as technologies and system operations mature.

Current C&I rates from major California utilities will likely result in  “underinvestment in DER resources and under-utilization of DER resources,” RAP found. Public utility  Sacramento Municipal Utility District (SMUD) composed a rate design that meets most of these principles.

Existing real-time pricing tariffs, including SMUD's, are not a model for best practices, Linvill said. Instead, the rate design include matching fixed charges and non-coincident demand charge to cost causation, rewarding load diversity, addressing peak demand, establishing price signals that convey system cost, and including an optional real-time pricing tariff.

To demand charge or not to demand charge

Robert Levin, a staffer with the CPUC Energy Division, noted that more dynamic pricing is coming, and that only limited use of demand charges is appropriate. Demand charges fail to account for load diversity, he said. That can lead to an underestimate of the need for capacity because capacity used at different times is “not additive.”

Non-coincident demand charges are especially problematic for solar customers, he added. Rooftop solar customers’  maximum demand is likely on a cloudy day, but system peak is typically on a hot, sunny day. As a result, solar customers could be over-charged despite low coincident demand or under-credited for exported solar.

Tom Beach, principal consultant for solar advocacy group Crossborder Energy, agreed. He argued that non-coincident demand charge and monthly demand charges “are mostly a relic of obsolete metering” and supported the dynamic pricing ideas proposed by Levin and RAP.

Cathy Yap, a consultant representing the California Large Energy Consumers Association, defended the use of demand charges.

“Without demand charges, customers with low load factors can impose substantial fixed costs on the utility system and avoid paying fully for those capacity costs because their usage is so low,” Yap said.

Generation costs should be recovered through a rate design that combines time-varying prices and coincident demand charges, similar to ones offered by Pacific Gas and Electric and SCE for medium and large power users, she said.

CDC sends “a proper price signal during peak periods,” Yap said. Time-of-use rates cannot capture the full cost for capacity because customers are not charged for peak loads outside of the peak period.

Coincident demand charges also avoid the problem non-coincident demand charges pose for solar customers, ensuring the cost-burden of the ramp up to peak demand is not shifted to non-solar customers, she added.

Ahmad Faruqui, a principal for Brattle Group said energy "should be priced dynamically.” Grid costs should be recovered through demand charges because “capacity and energy are distinct and cannot be combined,” he added.

When customers connect to the grid, they buy a 24/7 call option on the grid, he said. They accept responsibility for power plants, transmission lines, substations, feeders, transformers, meters, and electric wires, he argued.

Looking ahead

Representatives from the private sector, including NEST, Energy Hub, eMotorWerks, Gerdau Steel, and Demand Energy stress the need for balance in rate design. Rates must meet utilities’ need to recover costs and customers’ need for simplicity, they say.

For instance, a rate design tools matrix from Strategen Consulting illustrates that balance.

“A balance between volumetric and demand based price signals is necessary and the weighting must be tailored specifically to each portion of the electric grid,” said Lon Huber, senior director of Strategen.

“Policymakers need to be extra diligent in rate design construction to avoid exploitation of crude or improperly designed price signals,” Huber added. “More sophisticated and balanced rates can maximize all the DER values and attract smart customer responses that benefit the entire system.