In 2009, the Obama administration’s $8 billion Smart Grid Investment Grant program helped spawn a wave of smart meter deployments by utilities. An estimated 98 million units were installed by the end of 2019, with the majority for residential customers. Early enthusiasm for the devices has waned. Some regulators question whether utilities have fully thought out the value smart meters would bring to their customers and overall grid operations.

The first generation of meters using digital displays instead of old-school spinning dials were really only half-smart. These facilitated the introduction of automated meter reading (AMR) by enabling one-way communication between the meter and utility, eliminating meter-reader visits. In addition, these AMR meters can communicate outage and reconnection information to utility service offices.

To be fully smart, according to the U.S. Energy Information Administration, meters must allow two-way communications between utilities and their customers. They need to measure and record usage at least hourly and provide data to utilities and customers at least once a day. The most intelligent products are capable of real-time two-way communication and recording and transmitting instantaneous data.

With that broad range of capabilities in mind, smart meters were serving nearly 75% of U.S. households— 107 million smart meters in service—at the end of 2020, according to The Edison Foundation Institute for Electric Innovation, a research organization in Washington, D.C., supported by investor-owned utilities. That is up 9.1% from the end of 2019, with an anticipated increase to 115 million by the end of 2021, up 7.5%.

That uptick includes several significant utility efforts underway. Duke Energy, Charlotte, N.C., launched a two-year program in 2018 to add 3.7 million smart meters across its six-state service territory. Entergy, New Orleans, is adding more than 2 million devices across four states in a similarly timed rollout. In what it’s calling its largest capital project in its corporate history, New York’s Consolidated Edison is installing 4 million smart meters across New York City and Westchester County.

While a 9% growth rate might sound impressive, it’s actually down from the annual 11% growth seen between 2017 and 2019. In part, the slowdown resulted from federal funds running out. Having hit a 75% penetration rate, the market simply might not have as much room for continued aggressive growth. An added headwind is coming from some state regulators who want to see greater value from proposed utility rollouts.

In the last few years, Kentucky, Massachusetts, New Mexico and Virginia regulators rejected utility smart meter proposals. The general concern was that there wasn’t a strong enough argument for how new meters would provide value to ratepayers. In Kentucky, regulators were especially concerned that Louisville Gas & Electric and Kentucky Utilities sought to replace meters that were already baked into customer rates for another 15 years.

A report from the American Council for an Energy-Efficient Economy (ACEEE), underscores these concerns. In the organization’s 52 utilities, just two were making full use of smart meter capabilities to help reduce customer energy use and improve grid efficiency. ACEEE found that only Oregon’s Portland General Electric and Southern California Edison were leveraging smart meter functionality to provide six services the group identified as adding significant customer and operational benefits, including:

• Real-time energy-use feedback to customers
• Time-of-use rates
• Behavior-based programs with customer feedback and insights
• Program targeting, marketing and technical assistance using data disaggregation
• Grid-interactive efficient buildings
• Conservation voltage reduction or volt/VAR optimization

One reason that providing real-time energy use information to customers and time-of-use rates were most popular is that these services are the least data and back-end intensive. They use the meters’ real-time communications capabilities without requiring large modifications to distribution system operations or equipment.

It’s not surprising that supporting grid-interactive efficient buildings was the least prevalent use, given the level of technology required for building owners to shift loads to the grid. While this can be as simple as demand-response program participation, it also can involve on-site energy resources, such as solar panels and energy storage, to take loads off-grid based on a utility signal.

What’s common across these cases is a growing recognition of meters’ expanded role within distribution systems and new communications capabilities. Back in the spinning-dial days, they were simply an accounting tool. Now, they’re becoming a critical resource, providing data on overall distribution system operations. So, to build deployment business cases their regulators will accept, it seems utilities need to think beyond their billing departments and consider broader modernization efforts that bring value across their entire network.