As utilities grapple with aging infrastructure and outage management, they are evaluating their GIS and considering the best way to keep up with the shifting demands of the electric-power industry...
Smart Meters on The March
New federal policies portend a wave of demand-response programs, and perhaps a new era in resource planning.
"The provision in the electricity title focuses state-level attention on demand response and smart metering."
Specifically, section 1252, titled "Smart Metering," directs utilities to offer time-based rate schedules and the necessary meters and communications technology to all customer classes within 18 months of the bill's enactment. Rate schedules are expected to reflect variances in the utility's costs for generating or purchasing wholesale power supplies. The legislation suggests four approaches to time-based pricing, including:
- Time-of-use pricing, in which the utility sets prices in advance for peak, intermediate, and off-peak periods;
- Critical-peak pricing, in which peak-shaving discounts may apply on certain peak days;
- Real-time pricing, in which prices fluctuate to follow wholesale-market prices as frequently as every hour; and
- Credits for large consumers under load-curtailment agreements.
Until now, smart metering has advanced in fits and starts in the U.S. utility industry. Its development was set back, in part, by retail deregulation processes that anticipated competitive service providers would install smart metering as a business investment. That didn't happen, however, and now Congress has signaled it wants incumbent distribution utilities to install smart meters.
Most utilities have resisted making such investments, largely because studies suggest the utility business case does not justify the cost of smart metering. A recent study by Madison Energy Consultants, for example, concluded that prices aren't volatile enough in the PJM market to justify the costs of implementing a demand-response program. 1 Other studies, however, have yielded more promising results—promising enough, in fact, to justify pilot projects to assess the aggregated benefits and costs of advanced metering. For example, major projects now are proceeding in several Mid-Atlantic states, through the Mid-Atlantic Demand Response Initiative (MADRI), and in California, under a demand-response rulemaking process the state PUC began in 2002.
Most states, however, have been slow to consider advanced metering. An important disincentive for smart metering has been the fact that only some of the benefits accrue directly to the distribution utility, which generally is expected to incur the costs.
"Utilities are still learning about the differences between advanced meters and the AMR drive-by systems," Delurey says. "The challenge with smart meters is that the business case and the policy case are both multifaceted. You get some benefits in system operations, outage restoration and control, marketing data and demand response. And some of the benefits leak outside the utility's service territory to other people."
Thus the demand-response pill tastes somewhat bitter, because demand-response programs ultimately reduce the utility's peak-capacity requirements, and therefore its potential ratebase.
"Cost recovery isn't enough," Delurey says. "Utilities are looking for ways to improve their earnings, or at least keep them from degrading."
Disincentives for investing in advanced metering especially are problematic in locations with deregulated retail markets, where the benefits for deploying advanced meters are spread even thinner than they are in vertically integrated markets.
"States that have introduced retail competition have to deal with the difficulty that the benefits to deploy advanced meters have been disaggregated, split up among distribution utilities and retailers," says Richard Sedano, a director with the Regulatory Assistance Project in