Changing demands from regulators, customers, and shareholders are driving utilities toward better operational technologies to manage an increasingly complex grid. Advanced distribution management...
Special Section On Metering: Thinking Smart
to answer for their jurisdictions.
EPACT does not prescribe any particular approach, but generally specifies that rate schedules should reflect variances in the utility’s costs for generating or buying wholesale power at different times of day. The law provides four examples of time-based pricing mechanisms to guide utilities and PUCs: time-of-use (TOU) rates for peak, intermediate, and off-peak periods; critical-peak pricing, with peak-shaving discounts for certain peak days; real-time pricing, in which rates track wholesale prices through the day; and credits and incentives for commercial and industrial customers to enter load-curtailment schemes.
Thus, in effect, Section 1252 doesn’t force smart metering on the states, it forces them to think about it—and establishes a date-certain (January 2007) by which that thinking must begin. The outcome of these thought processes will depend on a range of variables that differ from region to region. Some states and utilities undoubtedly will decide the potential of advanced metering is not worth the cost to their ratepayers.
“Some utilities are saying, ‘It’s not my issue,’” says Doug Houseman, a principal with Capgemini in Detroit. “Their ratepayers are happy. They still have low rates and surplus generation, so they can put something together at the end of the year” to satisfy EPACT.
As energy costs rise, however, and neighboring utilities begin reaping operational and strategic benefits from AMI, the technology might gain momentum even in states where the business case has been unclear. “Six months or a year ago, [the] Ohio PUC wasn’t exactly in the vanguard of demand-response and advanced metering,” Dresselhuys says. “Now the state has started proceedings, and is getting the predictable ‘ah-has’ that come with it.”
The “ah-has” come from a broad spectrum of benefits, not all of which are immediately obvious (see Figure 1, “Parsing AMI Benefits,” p. 58). Metering savings are relatively modest, for example, while collections savings can be tremendous. This is partly because remote disconnect and reconnect can occur without sending a truck, and it allows virtually instant-on response when a delinquent customer makes a payment. Additionally, a more continuous flow of metering data allows customized billing intervals that better suit some customers.
“People who struggle hardest to pay their utility bills get paid weekly,” Houseman says. “Smart metering can make it easier for them to pay, by matching bills to pay periods.”
Additional significant savings come from the combination of outage restoration, field-force management, and vegetation management. “When an outage is reported, we may be able to ping neighboring meters and use a diagnostic algorithm to figure out what components are out,” Soethe says. “This might improve the productivity of repair crews.”
Such features bring economic benefits, but they also can contribute to overall reliability and customer-service quality.
“The business case is significantly more complex than just demand management,” Houseman says. “AMI is an enabler for a lot of things utilities might want to do. The question becomes how long can they wait before taking advantage of these features?”
In some cases, the answer might depend on strategic business factors. For example, consolidation trends could affect how utilities evaluate AMI