New time-of-use rate pilots in Maryland show how effective time-varying rates can be and also reveal an early step in the evolution of rate design.
Three Maryland investor-owned utility (IOU) pilots of new time-of-use (TOU) rates significantly reduced peak demand and customer bills, a September 2020 Brattle Group assessment found. The success was built on the power system's emerging transition to variable and distributed renewables and customers' greater access to enabling technologies and familiarity with responding to price signals, the study found.
"Rate designs differ widely in the accuracy of the price signals they send to customers, from flat rates to day-of real-time rates," said California Solar & Storage Association Regulatory Affairs Senior Advisor and rate design authority Scott Murtishaw. "The more precise the price signal, the more customers can help address variable energy sources with flexible loads and storage to accelerate decarbonization."
Maryland is ahead of other jurisdictions "on advanced metering and technologies that link customer savings opportunities to savings that benefit all ratepayers."
Jason M. Stanek
Chair, Maryland Public Service Commission
Maryland was ready for new rates because it had deployed smart meters, its customers were familiar with alternative rates, and distributed energy resources (DER) are growing there, said Brattle Principal Sanem Sergici, who led the study of the pilots. The success of these new rates moves Maryland along the energy transition trail that states from Hawaii and California to South Carolina have recently blazed.
Those states have shown that success with TOU rates can allow utilities to begin to integrate more variable and distributed generation and lead to more sophisticated time-varying rates. And those more sophisticated rates allow for higher penetrations of variable and distributed generation that further advance the energy transition.
Maryland's TOU pilots
A TOU rate's varying prices are higher during peak demand periods, which signals customers to shift usage to lower-priced off-peak periods. That can reduce the individual customer's bill. Reducing a utility's need to invest to meet rising peaks can also reduce all customers' bills.
In Maryland and many other states, TOU and other new rate designs are possible because of the deployment of advanced metering infrastructure (AMI). AMI's "digital link" between utilities and customers allows "expanded services" like home energy management, usage alerts and "time-varying" rates, the Edison Foundation reported in December 2019.
Maryland is ahead of other jurisdictions "on advanced metering and technologies that link customer savings opportunities to savings that benefit all ratepayers," Maryland Public Service Commission (PSC) Chair Jason M. Stanek emailed. And through the state's peak time rebates (PTR) program, put in place in 2008, customers learned "they can save money through reducing usage."
The PTR program rewards customers for voluntarily reducing usage when pre-notified of a coming demand spike and is "the most succesful such program in the U.S.," Brattle's Sergici said. "Since 2014, roughly 1.5 million Maryland customers have participated" in significantly reducing these intermittent critical peaks when demand is highest.
The PTR program's high customer satisfaction ratings "may have made the commission willing to offer more innovative programs," Sergici said. And a 2017 PSC order suggests commissioners saw an opportunity to prepare for their next challenge, she added.
With customer-sited DER emerging, Maryland can begin assessing the potential of time-varying rates' price signals to empower "customers, utilities and all other stakeholders," the order initiating the PC44 grid modernization docket said.
In response, Maryland IOUs, Baltimore Gas and Electric, Pepco and Delmarva Power and Light implemented still-ongoing TOU pilots that offered summer peak period rates four times to six times higher than off-peak rates, according Brattle's study of June 2019 through May 2020 impacts.
The customers who opted in represented significant portions of low- and moderate-income (LMI) and non-LMI demographics for small pilots, stakeholders agreed. Across all utility programs and customer types, summer peak demand was reduced 10.2% to 14.8%, non-summer peak demand fell 5.1% to 6.1%, and bills were reduced 5% to 10%, Brattle found.
Ratepayer advocates have often opposed TOU rates because they could disadvantage LMI customers with less usage flexibility and less access to enabling technologies, Brattle reported. But these results represent "conclusive evidence that LMI customers respond to the TOU prices by as much or nearly as much as non-LMI customers."
Brattle's findings were preliminary but significant, and suggest that rate designs follow the availability of technologies like AMI and customer familiarity with rate options, said former Maine utility commissioner and current Bernstein Shur energy and environmental attorney David Littell, who co-chaired the PC44 Rate Design Work Group.
The preliminary findings show TOU rates can impact some system costs, but more piloting and study are still needed, added attorney William Fields, lead ratepayer advocate on the pilots for the Maryland Office of People's Counsel.
About two-thirds of customers who opted in would have had bill decreases without changing their behavior but "found ways to get more savings," Sergici said. "That's important because customers typically only opt in if they already expect benefits and those benefits do not add real system value."
The initial PSC order specifically required opt-in pilots, "which seemed to be a signal the PSC will not move immediately to default TOU rates," she added. "But the success of the pilots, especially for LMI customers, could lead to another step."
Many states with rising variable and distributed renewables penetrations are piloting rate designs with "more complex and granular elements," said North Carolina Clean Energy Technology Center (NCCETC) Senior Policy Program Director Autumn Proudlove.
The Littell and Proudlove observations suggest rate designs evolve in response to the changing energy resource mix, access to enabling technologies, and customer readiness. Recent innovative rate design implementations suggest the same thing.
Other states are also demonstrating the evolution of rate designs.
South Carolina's 2019 Act 62, which capped DER growth without altering rate design, was not a sustainable approach to its growing DER penetration, stakeholders found. A potentially more durable rate design solution based on time-varying rates proposed by Duke Energy and DER advocates is now before South Carolina regulators.
The proposal combines a TOU rate and a more dynamic peak pricing version of Maryland's PTR rate with incentives for participation in Duke's demand response and energy efficiency programs. If approved, it could be an advanced rate design that grows DER, reduces utility peak demand challenges, and supports policy goals without imposing costs on other customers, Proudlove said.
"If the barriers to smart and enabling technologies and services are overcome, more customers might find the 'set it and forget it' simplicity of subscription rates more appealing, and utilities might be able to use them as effectively as other rate designs."
Senior Policy Program Director, North Carolina Clean Energy Technology Center
In October 2015, the Hawaii PUC changed the fixed retail rate compensating solar owning customers to a TOU rate design. It was intended to drive new solar owners to add battery storage. But batteries were expensive at the time and by May 2016 permits for solar installation were down 27.3% compared to the prior year.
An October 2017 TOU rate design restructuring was more successful. In the first nine months of 2020, 75.2% of metropolitan Honolulu region PV systems included battery storage, Pacific Business News reported in October 2020.
The TOU rates worked but "Hawaii waited too long to impose a solar rate design with smart price signals," Duke Energy Vice President for Rate Design and Strategic Solutions Lon Huber said at the time. "States need to get ahead of the solar penetration with forward-looking rate designs."
California, which has piloted TOU rates since 2003 and has already implemented a successful TOU rate for solar owners to drive battery growth, may be ready to "get ahead" on what appears to be a next step in rate design evolution.
To real-time pricing
California's next step to more dynamic time-varying rates could further demonstrate the link between rate design, the resource mix, enabling technologies and customer readiness, stakeholders said.
The state has been working to address demand spikes and high rates for decades, Brattle Principal Ahmad Faruqui, a student of rate design history, recalled.
Customer demand for lower bills led California to retail restructuring, but there were no enabling technologies or new energy resources that would lower rates, Faruqui said. After the 1999 to 2001 energy crisis, state policymakers retored regulation and "there was a push for more dynamic pricing and smart meters."
After years of the kind of piloting Maryland is doing now, and with its rapid growth of increasingly dynamic supply and demand, California may be ready for real-time pricing (RTP), Faruqui said. But implementation will depend on the availability of enabling technologies, he added.
"Customers who give utilities more control of their loads should benefit more financially for providing more system benefit, because key peak event days are very much 'Ask not what the grid can do for you, ask what you can do for the grid' events."
VP for Rate Design and Strategic Solutions, Duke Energy
Regulators in the California Energy Commission (CEC) and California Public Utilities Commission (CPUC) in various proceedings to prepare the state for a power mix to support its zero emissions goals, want to move ahead with RTP pilots, Brattle's Sergici said.
The CEC recognized RTP as a potential solution to load and supply variability and rising costs in its January 10 action initiating a stakeholder study of load management. In response, California's IOUs called for "comprehensive pilot studies that fully assess the costs and benefits of real-time rates," in their March 16 CEC filing.
RTP would be especially effective at addressing the price volatility from California's variable supply and flexible load, said California Solar & Storage Association's Murtishaw.
Over 100,000 Oklahoma Gas and Electric residential customers and over 40,000 residential Illinois customers have opted in for RTP rates, Murtishaw replied to a July 17 CPUC ruling rejecting a 2019 San Diego Gas and Electric territory-wide RTP proposal.
Almost 1.1 million California customers voluntarily participate in demand response programs, which shows they can respond to price signals, Murtishaw added in Aug. 31 testimony proposing a scaled-back RTP pilot.
A pilot would show RTP's favorable impacts on load, utility costs and customer bills, and lead to investment in the needed enabling automated technologies and aggregation services, Murtishaw said. But without those technologies and services, limited California customer experience with real-time pricing will lead to doubts from regulators and resistance from utilities.
RTP is "not essential" but it can cost-effectively address California's steep demand peaks, high price volatility from variable and distributed renewables, and unpredictable emergencies, he added. And with further deployment of enabling technologies and services RTP "will be more viable."
There is a next step in rate design evolution beyond RTP that may use those services and technologies to turn price signals around.
A newer type of rate design could eventually include the full range of options, from Maryland's basic TOU design to California' real time rates, or allow more sophisticated pricing to be implemented by utility experts.
Rate design is evolving toward time-varying rates, NCCETC's Proudlove acknowledged. But "if the barriers to smart and enabling technologies and services are overcome, more customers might find the 'set it and forget it' simplicity of subscription rates more appealing, and utilities might be able to use them as effectively as other rate designs."
Advanced TOU rates with peak pricing features "probably are not for everybody," said Duke's Huber, who proposed one of the first modern subscription rates for U.S. electric utilities. "But why are utilities only sending price signals to consumers? Utilities ought to have the opportunity to receive price signals and learn from their customers' choices," he said.
Subscription rates recognize that some customers will allow utilities limited control of their usage if the utilities provide smart technologies they can pre-set to their preferences, he added. "Underlying subscription rates would be very sophisticated rate designs managed by utilities."
Utility experts could optimize supply and demand in response to wholesale market prices and meet customer needs with the full range of available resources more cost effectively than most residential customers, he said.
The energy transition will require "every demand- and supply-side solution we have, and rate design-enabled load flexibility will be a key tool," Huber said. "Customers who give utilities more control of their loads should benefit more financially for providing more system benefit, because key peak event days are very much 'Ask not what the grid can do for you, ask what you can do for the grid' events."