For almost a century, electric meters served a single purpose: telling utilities how much power their customers had consumed. Over the last two decades, however, electric meters have transformed. The newest generation of these devices has more in common with the smartphone in your pocket than with the old-school meters that once hung at the service entrance of every U.S. home. That sophistication is expected to grow as electric utilities seek new ways to monitor and control activity throughout their increasingly dynamic distribution systems.
The first generation of smart meters arrived in the early 2000s in automated meter reading (AMR) rollouts. Utilities were able to make an easy business case to their regulators for the upgrades. Using basic communication capabilities, these meters could transmit kilowatt-hour (kWh) usage data to the utility automatically without requiring human meter readers.
During the Great Recession, grants awarded under the 2009 American Recovery and Reinvestment Act hastened this deployment. Many utilities received federal funding to beef up grid security and resilience, and smart meters were seen as key enablers in that effort. That was also when more futuristic use cases began making promises of demand-response programs that would allow utilities to control residential appliances. Meters were seen as the communications portals through which such commands would be received.
“Everybody 10–12 years ago poured a bunch of thought into how the meter would facilitate communication into the home, but the uptake on that has been really small,” said Ty Roberts, vice president of marketing for networked solutions at meter manufacturer Itron. “It’s still a bit of a holy grail for utilities.”
Meters offer a range of operational advantages beyond automating the meter-reading process. A second generation of enhanced smart meters hit the market in the last 8–10 years, as utilities began the development of advanced metering infrastructure (AMI). Meters became the utility’s eyes and ears into distribution-grid performance.
“It was really designed to be part of the utility cash register,” Roberts said, describing the meter’s initial business role. “It’s still that, but it’s now really a distribution grid sensor.”
As sensors, these newer meters already are proving their worth in helping utilities quickly identify outages—whether in ones and twos or across whole regions.
“The meter is now a key player in troubleshooting,” said Kenny O’Dell, marketing director, North America electric metering at Sensus, another meter manufacturer.
For example, meter data can help a utility identify whether problems are occurring with a customer’s panel or a transformer.
“Then you go up or down one transformer,” he said, explaining this process of elimination. “And then, you have a much better idea of what workers you need to send, with what equipment. What we’re trying to do is remove the guesswork.”
This kind of two-way communication in which the utility can poll customers’ meters for specific data also can aid voltage conservation efforts. By getting measurements on voltage, reactive power and other power characteristics, utilities can more confidently support voltages toward the lower end of what customer equipment can tolerate. This means lower powerline losses and more efficient overall operation.
Two-way communication also eliminates the need for workers to physically visit a home or business to disconnect or reconnect service. As well as aiding delinquent-payment management, customer moves and changes are easier to address. Now, someone moving into a home that has been vacant, for example, no longer has to make an appointment for a utility to turn service back on. Instead, a customer service representative can complete this operation remotely.
How such data gets passed back and forth between the meter and utility also has evolved over the years. While power line communication (PLC) dominated in early smart-meter deployments, radio-frequency mesh (RF mesh) now dominates the market. Looking at projects announced in the third quarter of 2018, Michael Kelly, a smart meter analyst for Navigant Research, said 75 percent were planning to implement RF mesh technology and 15 percent were opting for point-to-multipoint systems (P2MP). Cellular and PLC approaches came in at approximately 5 percent and 4 percent, respectively.
Aiding RF mesh designs is a new standard called Wi-SUN (wireless smart ubiquitous networks), which establishes a communications protocol enabling interoperability of participating manufacturers’ products on the same utility network. The standard, IEEE 802.15.4G, was published in 2012. Now, a first wave of standard-compliant products is coming to market from manufacturers such as Itron and Landis+Gyr.
“The idea was to enable an ecosystem of interoperability, the same way we now have with Wi-Fi and Bluetooth,” said Phil Beecher, president and CEO, Wi-SUN Alliance. “We’re just at the beginning of interoperability.”
Sensus, a leader in the electric meter industry, has taken a different approach and developed its own P2MP network called FlexNet, which uses dedicated frequency that is licensed from the Federal Communications Commission for its exclusive use. (RF mesh uses unlicensed spectrum, similar to that used in Wi-Fi communications.)
Both PLC- and cellular-based networks now primarily serve municipal and rural cooperative utilities. Though reliable, these designs operate with much smaller bandwidths, which limits the amount and speed of data communication. Additionally, older cellular networks may be forced to upgrade soon, as service providers are phasing out their support for the 2G and 3G communications used in such designs.
While capabilities of the latest generation meters may intrigue electric utilities, the decision to upgrade their systems isn’t theirs alone to make. Meters are considered utility assets, so they are paid for by ratepayers over a defined useful lifespan. State-level utility regulators have the final decision on such purchases. Utilities have to convince regulators that new meters will add sufficient value to their operations—eventually providing savings to customers.
In the past, meters might have been depreciated over 20 years. However, technology is evolving so quickly that regulators now may be allowing more frequent replacement. Even the first generation of AMR equipment—which might be only 10–15 years old—could be seen as at the end of its life.
“Generally, regulators are not putting these assets on the books for the same amount of time,” said Gary High, senior vice president for marketing and product management with Landis+Gyr. “Early versions didn’t have the granularity of the data, so often utilities can make their business case on new availability of technology.”
However, some see challenges for those who might have jumped on board early with an AMR deployment and now are eyeing the more sophisticated systems that have since come to market. For example, last spring, Massachusetts regulators denied plans from three investor-owned utilities to upgrade their AMR systems to an AMI design. The customer savings in a transition to AMR capabilities was easy to see when those proposals were made a decade or so ago, regulators stated. However, the financial advantages simply weren’t clear in the latest business arguments, so regulators sent utility planners back to their drawing boards to better outline how smart meters would fit into possible time-of-use pricing systems.
“For the utilities that have done AMR programs, if they’ve already mitigated the meter reading expense, that’s a big part of the business proposition you don’t have,” Itron’s Roberts said.
As a result, such rate cases boil down to what additional value an upgrade can provide to customers.
“But there’s more subjectivity with that,” he said.
In the future, upgrading meter capabilities could become easier for utilities. While past improvements—such as moving from mechanical meters to AMR devices and from those to AMI technology—have required an entirely new meter, that is changing. Instead, manufacturers are creating new feature sets as downloadable software, such as smartphone apps. They are also ensuring their meters have sufficient onboard central processing unit and storage capacity to handle future tasks. For example, O’Dell said the latest Sensus meters are shipping with only 20 percent of their storage capacity in use.
“So, we can add more things for years and years,” he said. “We’re going to give ourselves lots of room to grow. Someone’s going to think of something two years from now that no one’s thought about before.”
Itron is similarly focused on future-proofing, Roberts said.
“Our new generation is essentially completely software-based,” he said. “We can upgrade almost every part of it over the air. Our goal is to make all of it software-definable, so it can evolve.”
It’s a good thing these manufacturers are thinking ahead, because utilities likely will depend on meters’ data-gathering capabilities even more in the next 5–10 years. Distributed energy resources such as rooftop solar, behind-the-meter battery systems and electric vehicles all will need to be visible to utilities to ensure grid operations remain safe and secure.
“Utilities need to be able to see that activity,” Landis+Gyr’s High said. “Meters can sense power flows, as well, so utilities get a great deal more visibility into that activity. [With data,] utilities can tell a contractor, ‘yes, that service is live.’”
Meters eventually could help support kWh tracking for a new kind of electricity market. Roberts sees energy trading between utility customers with rooftop solar and neighbors who want to buy local as a smart-meter use case that could become a reality within the next decade.
“That absolutely could be a reality in the next 5–10 years,” he said. “We think the meter is key to that because it’s designed to be the utility’s sensor at the customer level.”