With old-school, electromechanical dial-based electricity meters rapidly going the way of the rotary-dial telephone, it won’t be long before “smart meters” are called, simply, “meters.” Otherwise known as advanced metering infrastructure (AMI), digital meters have rolled out by the millions over the last half-decade, and utilities are exploring the benefits their communications capabilities offer. But technology moves just as fast for smart meters as it does for smartphones, so both utilities and their regulators must plan for tomorrow’s advances to ensure today’s investments aren’t obsolete before they have been paid for.
The last few years may not have been great for the overall economy, but for meter-makers, business has boomed. Under the American Recovery and Reinvestment Act of 2009 (also known as the stimulus act), the Smart Grid Investment Grant (SGIG) program dedicated more than $3 billion to transmission and distribution grid upgrades, the largest portion of which—$2.2 billion, as of September 2013—has gone toward the purchase of 12.8 million meters (which works out to be about $173 per meter). An additional $1.4 billion or so has gone toward related communications and hardware assets.
As of July 2013, approximately 46 million smart meters are installed at U.S. homes and businesses, according to IEE, a program of the Edison Electric Institute’s nonprofit Edison Foundation. So, approximately 40 percent of U.S. households have smart meters, up from 33 percent in May 2012.
Dan Jacobson, a senior marketing manager with meter manufacturer Landis & Gyr, said those figures are slightly lower than the estimates he has seen, which find approximately 50 percent of the meters in operation incorporate some form of two-way communication (the general definition of what makes these devices “smart”). The earliest versions, called automatic meter readers (AMR), may simply supply usage data back to a utility billing office, eliminating the need for a monthly, in-person reading. Today’s top-of-the-line models, though, feature onboard wireless or cellular utility communication, enabling utilities to gather equipment-specific usage information and even control-connected appliances, based on customer demand-response agreements.
Utilities looking to deploy new meters must make the same kind of arguments to state regulators as they would for other distribution-system updates, justifying the technology’s benefits against the rate hikes needed to pay for the equipment. SGIG funds now are depleted. That means consumers will be picking up more of the tab, and regulators may be giving new programs greater scrutiny.
“Consumer and environmental benefits are the top two issues they are looking at,” Jacobson said, adding that this attention generally translates into support for investments that can boost a distribution system’s reliability and efficiency.
Efficiency benefits come in the form of the meters’ demand-response capabilities mentioned above, in addition to advanced voltage control. Reliability is improved with the new devices’ ability to alert utilities to outages or even warn of impending transformer failures before an outage occurs. Additionally, some utilities are piloting new billing options that are not possible without smart meters, such as prepaying for electricity service, similar to the way many cell phone users prepay for mobile services.
New meters are affecting the service territories where they have been deployed, according to “Utility-Scale Smart Meter Deployments,” an August report from IEE. For example, Oklahoma Gas & Electric is using meters to monitor voltages in an optimization plan expected to reduce its distribution-system load by 75 megawatts (MW) by 2018, and Pepco is implementing a peak energy-savings program that uses smart meters to send price signals to Delaware and Maryland customers during peak-demand periods. The effort is expected to provide the utility with 50 MW of demand-response reductions.
Regulators may need guidance, though, in determining how quickly to allow utilities to depreciate this rapidly advancing equipment, which has a direct effect on customer rates. Related regulations are evolving almost as quickly as the technology itself. In 2008, Congress cut the depreciation rate for all smart-grid-related technologies (including smart meters) to 10 years, from the standard 20 for other utility equipment. Then, in November 2012, the Internal Revenue Service ruled that utilities can treat smart meters as computers, cutting that 10-year depreciation schedule in half, down to five years.
This doesn’t mean, however, that electric utility customers should expect to see a new meter every five years. Instead, just as Windows computer users have gotten used to regular over-the-wires operating-system updates, utilities can make software and firmware upgrades remotely so utilities can leave physical meters in place longer.
“We’re trying to make sure that, not only do we try to help migrate them [to the new meters],” Jacobson said, “but also that the new technology we put out in the field has the capability to upgrade.”