The last decade has seen enormous change in how we generate electricity. In 2011, for example, U.S. solar photovoltaic capacity totaled 3.95 gigawatts (GW), including residential, commercial and utility-scale projects. As of 2021’s second quarter, that figure had hit more than 100 GW, and the U.S. Energy Information Administration expects solar to account for almost half of all new generating capacity in 2022.
Now, how we pay for that electricity is also beginning to change. State-level regulators are re-evaluating traditional rate-setting models that compensate utilities primarily based on how many new assets they can add to their distribution systems. New approaches look to maximize the value of solar, wind and other renewables by shifting utilities and consumers’ behaviors as society on the whole moves to reduce carbon emissions related to energy use.
These new rate approaches represent a historic shift. For more than a century, utilities have been incentivized to build new infrastructure by earning a guaranteed rate of return on their investments in it. This arrangement enabled the national grid to grow in tandem with the country’s energy needs. However, this method doesn’t support the growing need to address climate change with a more distributed network of renewable generation. Today, many state utility regulators address this need with plans meant to encourage consumers to reconsider how and when they use electricity and utilities to rethink their business models.
On the consumer side
Consumer-facing rate changes are primarily aimed at reducing electricity use during peak-demand periods. A classic scenario of a peak-demand challenge often occurs in the summer during late afternoon and early evening, when customers return home from work and dial up their air-conditioning systems. This is also the time when solar production begins to decline, which can lead to utilities having to fire up fossil fuel-based generation to make up the difference in required electricity.
Time-of-use (TOU) rates—also called time-varying rates—aren’t a new solution for reducing peak demand, but how utilities and regulators are looking at using them is changing. For one thing, peak periods are getting shorter. Earlier TOU iterations could include peak pricing that lasted 12–16 hours—no one is going to accept a plan that raises their prices during all their waking hours. Now, those higher rates might only be in place between, say, 4–9 p.m., when demand is truly at its highest. Rate designers also are looking to ensure that savings during off-peak periods are significant enough to truly encourage customers to shift their dishwasher or washing machine use to potentially less-convenient times.
Technology is assisting TOU approaches as smart appliances gain the ability to respond to electric utility pricing signals. Thermostats can be programmed to “pre-cool” a house by boosting the air conditioning an hour or two before a peak period begins and then setting back temperature setpoints when prices rise. Similarly, smart water heaters—typically a home’s biggest energy user—can automatically set their temperatures back when rates tick upward.
The need for this responsive approach will only become more important as electric vehicle (EV) adoption grows. Electric utilities in multiple states now offer EV drivers incentives for charging in off-peak times. In some cases, these involve a separate, dedicated meter for charging equipment. Charging equipment manufacturers have responded by adding app-based controls for owners that make scheduling vehicle charging as easy as a tap on a smartphone screen.
On the utility side of new rate-setting approaches, regulators in several states are exploring performance-based rate-making (PBR) plans, in which utilities’ compensation is based on meeting regulator-defined public policy goals. Hawaii has gone the farthest in this regard. Last year, Hawaiian Electric Industries Inc., parent of the three utilities that serve approximately 95% of the state’s population, began operating completely under a new PBR framework established by the Hawaii Public Utilities Commission.
The utilities will face a lower regulatory burden—for example, rate cases will extend over five years instead of the previous three. An annual revenue adjustment will limit utility revenue growth to the rate of inflation, along with guaranteed returns on specific expenditures, minus certain earnings shared with customers. However, additional provisions in the plan allow for increased earnings during the current five-year rate plan. These include rewards for adding renewables to the distribution system more quickly than scheduled under Hawaii’s 2045 target for 100% renewable generation.
Other states pursuing PBR approaches include Nevada, where utility commissioners have proposed performance-based incentives to encourage peak load reduction, transportation electrification and greenhouse gas emissions reductions. In addition, Minnesota, Connecticut, Illinois and North Carolina are also exploring how such a regulatory framework could benefit their residents while still supporting utility innovation.