New regulations and legislation in 2022 will continue seeking rate designs with price signals that shift customer electricity usage to more effectively benefit both customers and the power system, utility and other analysts said.  

The growing roles of variable generation in the power supply and distributed energy resources (DER) in meeting demand make effective price signals to customers critical, the analysts agreed. The emerging consensus is toward rates with signals that will reduce costly system demand peaks and lower customer bills, recognize the value of DER in doing that, and increase access to new technologies and cost savings.

Utility and regulatory leaders have realized new power system dynamics require "prices to be smarter," Brattle Group Principal Sanem Sergici said. They are increasingly aware that effective price signals to customers are necessary "for utilities serious about load flexibility, decarbonization, electrification and reliability."

Similar new multi-part rate designs approved in last year's settlements with clean energy advocates for Duke Energy in North and South Carolina typify that realization.

"The power system is changing dramatically, but traditional rate design is limited to balancing historic and future cost recovery," Duke Energy Vice President, Rate Design and Strategic Solutions, Lon Huber said. "These new designs resolve that tension by addressing system cost to serve but offering dynamic incentives for emerging technologies that meet future system needs like peak demand or reliability."

Beyond policy work on rate design objectives, there are new rate design implementations, and they are leading to better insights into the value of price signals for utilities and customers, the utility and independent analysts said. Many of the resulting new proposals about rate design may shape DER and smart technology uses toward a cleaner, more affordable, more reliable power system, the analysts added.

Time-of-use rates mature

Beyond routine rate cases, there were over 150 rate design policy initiatives in 2021 addressing new time-of-use (TOU) or time-varying rate (TVR) structures, or DER and electric vehicle charging, according to Autumn Proudlove, North Carolina Clean Energy Technology Center (NCCETC) senior policy program director.

Innovative rate designs are part of policymakers' efforts to keep up with technology as the U.S. power system transitions into "an interconnected web" of DER-owning customers, NCCETC's Q3 2021 grid modernization policy update said.

"TOU rate designs are being developed that give customers price signals to adopt new technologies that serve changing system demand," Proudlove said. The rate designs may also include an incentive, like a rebate for a new technology, that saves the utility "more than the cost of the rebate" if the customer makes the investment, she added.

Managing electric vehicle charging with TOU rates that encourage off-peak charging is an emerging national trend, she added. Some states, like Hawaii and Minnesota, have proposed three-part TOU designs with on-peak and off-peak periods and a super off-peak very low rate after midnight, or a very high critical peak rate for charging during reliability challenges.

There is no doubt TOU rates have achieved acceptance, Brattle Group Principal Emeritus and rate design consultant Ahmad Faruqui told a Lawrence Berkeley National Laboratory group Dec. 10. Analysts are watching default TOU rate developments in many states like California, Minnesota and Michigan.

New customer access to energy efficiency and DER has "flattened demand" and "eroded" utility financial viability, Faruqui said. But regulators have rejected both fixed and demand charges and more complex and dynamic TVR because using them with limited customer and utility understanding and inadequate smart meter deployments risks higher customer or utility costs.

Default simple TOU rates are a starting point and his yet to be published update of his Arcturus meta-analysis, covering 397 TVR deployments, shows they can have "statistically significant" impacts on peak demand and customer costs, Faruqui added.

Two years of customer experience with three Maryland regulator-ordered TOU rate pilots generally confirmed the meta-analysis findings, said Brattle's Sergici.

The June 2019 to June 2021 pilots were deployed by Baltimore Gas and Electric, Pepco and Delmarva Power and Light, Brattle's Maryland study reported. Short three-hour to five-hour peak price periods make responding to the rates convenient and peak to off-peak price ratios of between 4.2:1 and 5.8:1 provide customers with incentives to shift usage, it added.

TOU rates reduced the utilities' summer peak demand anywhere from 9.3% to 13.7% during the two-year pilot and their non-summer demand from 4.9% to 5.4%, Brattle found. First-year average bill savings were between 5.3% and 9.7% and second-year savings were 2.3% to 7.5%.

Importantly, low- and moderate-income (LMI) customers responded similarly to non-LMI customers, Brattle reported. And customers expected to benefit from participation because of their ability to shift their energy usage saw bigger benefits than expected, it added. These findings suggested TOU rates can work for most pro-active customers, Brattle concluded.

There are still debates about how to address policy goals, but the Maryland pilots showed rate design can drive "equitable cost recovery while providing efficient price signals," Sergici said.

Emerging DER rates

Nearly two-thirds of utility executives believe DER will provide their companies with new revenue streams, according to a 2020 Utility Dive and Generac Grid Services survey. Half of those surveyed said DER can improve grid reliability and resilience, and 54% said they help utilities meet emissions reduction mandates.

DER-specific rate designs recognizing all their potential values to the grid can enable both utilities and customers to benefit, Proudlove said. There are likely to be over 31 GW of distributed solar and over 40 GW of energy storage by the end of 2022, according to the February 2021 Energy Information Adminstration Annual Energy Outlook. There will also be over 103 million smart meters deployed in 2022, EIA forecasted.

The rate design concept "is about seeing DER as a significant resource" and allowing all types of DER to work together, agreed Regulatory Assistance Project (RAP) Associate Mark LeBel, co-author of "Smart Rate Design for Distributed Energy Resources," RAP's Nov. 1 paper for Michigan regulators. 

Rate designs for DER should allocate costs fairly, and send price signals that optimize their use, are understood by customers, and can be administered by utilities, the RAP paper concluded. There are three broad approaches to DER-specific rate design, it added.

"Gradual evolution" requires "modest improvements," that lead eventually to full DER valuation, it said. "Advanced residential rate design" is more "aggressive," with default TVR that can lower system costs but ensure cost recovery. "Customer choice and stability" combines elements of both in a more complex multi-part rate design to balance customer and utility interests.

"None is exactly what DER advocates or utilities want," LeBel said. They are options intended as a framework to show the principles and potential "trade-offs" in a DER rate design that ultimately must be "jurisdiction-specific."

California's default TOU plan, Minnesota's Value of Solar Tariff and proposals in Arizona's Value and Cost of Distributed Generation proceeding suggest values of avoided costs for things like new generation and transmission and distribution system infrastructure that are not needed because of DER, RAP's paper added.

The Duke Energy rate design could also be "a model for other states," LeBel said. Its minimum monthly bill, grid access charge to large customers, and non-bypassable charge could both recover utility costs and be manageable for DER owners. In addition, its TOU rates, critical peak pricing (CPP) and incentive for a smart thermostat purchase can reduce both customer bills and peak demand, he added.

As agreed to in the settlements with clean energy advocates, Duke’s rate designs, available in January 2022 in South Carolina and January 2023 in North Carolina, have two components, said Huber, who helped structure them. One is "a foundational consistent rate structure," and the other is "technology-neutral dynamic incentives for forward-looking technologies that meet system values."

The rate includes TOU periods, a CPP and fixed charges, he said. The incentives are for investments in solar, electric heating and a commitment to limited utility control of a smart thermostat. But other incentives could come with commitments for utility control of other smart DER like batteries, EV chargers, or smart inverters that will lower peak demand or increase reliability, he added.

New incentives could come from the North Carolina Utilities Commission (NCUC)-ordered Comprehensive Rate Review. Duke is required to create "a roadmap for how Duke plans to evolve its rates over time" by March 31, 2022, the NCUC order said. A commission-ordered stakeholder process is taking up things like TOU rates, rates for DER, dynamic pricing and equity issues.

Commercial and industrial customers are "open to exploring new rate ideas" but want options, including keeping their current rates, said Maureen Quinlan, manager, distributed grid strategy, for global consultancy ICF, which is Duke's facilitator for the process. All customers want to "easily understand and predict their bills" and they want rates "to evolve" with evolving opportunities, she added.

Last July, the Arizona Corporation Commission ordered Arizona Public Service (APS), the state's dominant investor-owned utility, to develop a technology neutral tariff "for Summer 2022," said Lisa Schwartz, a senior program manager at Lawrence Berkeley National Laboratory (LBNL), which is providing technical assistance to the commission.

The objective is a rate structure to compensate DER like energy efficiency, demand response, storage and managed EV charging for their energy and capacity, and locational values and their values in providing ancillary and grid services like reserves and voltage support, an APS October 15, 2021, filing reported. 

And the utility gets "the potential to increase reliability and decrease peak demand," Schwartz added. APS will develop the rate's design through responses to its request for proposals for resources that have the specified values, due May 31, 2022.

Five new approaches

Many are thinking about more granular, very different, or untested approaches to rate design that can capture new values.

Following Hawaii's 2021 deployment, state legislative authorizations of performance-based ratemaking, which bases utilities' compensation on performance, is an emerging trend, NCCETC's Proudlove said. There are not yet results from Hawaii, but Connecticut, Illinois and North Carolina lawmakers have authorized regulators to study how to set and compensate performance standards, she said.

"The future is likely a spectrum of both more complex and simpler pricing offerings," Sacramento Municipal Utility District (SMUD) Manager of Distributed Energy Strategy Obadiah Bartholomy said. But a TVR might be designed to leverage customer-owned DER specifically to avoid utility spending.

A rate should differentiate between variable and fixed utility costs, but should also be affordable, protect low-income customers, maximize renewables use, and drive electrification, Mohit Chhabra, climate and clean energy program senior scientist with the Natural Resources Defense Council, said. That might require "a charge or a fee for the services from the grid."

New concepts are important to give customers options and the subscription rate concept, which allows customers to pay a fixed price for a fixed amount of electricity usage, may serve those who want stability and less involvement than TOU rates or CPP require, Brattle's Sergici said.

Private sector providers are working with utilities to pilot subscription rates, said Uplight Director, Market Development and Regulatory Innovation, Angela Amos. Preliminary Uplight results from "a large Midwestern utility" show customers got a 6% bill savings with subscription rates, and in a Duke Energy pilot, "we're seeing double digit peak demand usage reductions," she added.

The 2020 California Energy Commission (CEC) Load Management Standards Protocols initiative could be "a gamechanger" for subscriptions and other rate designs, Brattle's Sergici said. And the CEC's December 22, 2021, rulemaking required California utilities to make all time-varying rates available in a commission database to be used "seamlessly by customer devices for optimizing tariff usage."

This is expected to "encourage the use of technologies for automating utility-customer negotiations and end-use load management," the CEC draft final rulemaking said. This is a step toward "prices to devices" and the use of complex rates "in almost real-time," Sergici said. As the protocols evolve, rates need to become smarter "to drive customer smart technology investments and lead to a decarbonized future."

Automation "through sophisticated price signals sent directly to smart devices and requiring little customer effort is the end destination," LeBel said. "That is likely to come in 10 years to 20 years, sooner in states like California or Hawaii."

Southern California Edison is moving as fast as it can to identify and deploy smarter rate designs and technolgies because "we are already behind on our 2030 emissions reduction goals," said Erik Takayesu, the utility's vice president, asset strategy and planning. "And we need to accelerate because if we wait for problems to show up, it will be very difficult to protect reliability."