Deregulation Drives Need for Interval Metering

The changing landscape of the power generation market has resulted in an increased need for interval metering—also known as automated meter reading—which is the practice of utilities and end users to measure energy use in short time intervals.

Demand-response programs, particularly in New York and California, allow end users the option to voluntarily shed load at times when the electrical grid is overburdened. This yields significant savings, but makes these meters necessary tools of the process. In fact, where time-of-use rates are in effect, larger customers—typically over 1 MW—have already installed meters that record energy data every 15 minutes.

To encourage more users to participate, the New York State Energy Research and Development Authority offers $3,000 per installed meter. And while NYSERDA's program predominantly focuses on medium-to-large end users, the California Energy Commission has mandated a similar interval metering program for facilities using 200 kW or more. Consequently, 80% of California's electrical loads over 200 kW are now connected to some sort of interval meter.

"The Federal Energy Regulatory Commission (FERC) is pushing for more demand-responsive programs [in other states], but that's not going to happen without these meters," notes Lindsay Audin, president of Croton, N.Y.-based energy consulting firm Energywiz Inc.

But even if an end user is not eligible to formally participate in such a program, by installing meters that provide near real-time load data, a facility manager can shift load at peak times, thus minimizing the purchase of electricity during these costly periods. While this strategy is already beneficial, the advantages—and cost of failing to switch loads at peak times—will increase exponentially in the next couple years, as Audin says pricing structures will continue to shift due to changes in wholesale power pricing, some of which have resulted from deregulation.

For example, end users now typically see demand charges double at peak times. However, in the near future, wholesale prices—which eventually trickle down to retail rates—are expected to jump 10 to 20 times at these utility peaks.

"This is already starting to happen to varying degrees—depending on [geographical] regions—and more in older cities because they have the greatest transmission restraints," Audin explains. Such "locational marginal pricing" is already in effect in the Northeast and is being pushed by FERC.

Thus, failing to install and utilize meters may soon prove a costly proposition.

In many cases, unless a facility has its own setup, the utility acts as the gatekeeper of meter information. But in most deregulated states, end users have the right to access the data. However, utilities often charge for it in a range anywhere from a couple hundred dollars a year to $100 per month.

This being the case, one unresolved, but extremely important issue is whether the utility has a right to resell the data—something that Audin likens to the equivalent of a building's DNA. If such information were to be sold to vendors, the advantage—or disadvantage—to some end users would be the opportunity to learn about different products and services that may help a facility save energy. On the other hand, if power marketers gained access to this data, they could choose to avoid approaching facilities with poor load profiles.

Because deregulation laws are still taking shape, many states have yet to clarify this issue.

Regardless of whether an end user owns or purchases metering information, the next step is making sense of the data. A number of software programs are available, but Audin offers a free Microsoft Excel-based technique for visualizing interval meter data in 3-D. For more information, visit: www.energybuyer.org, for an article accessible at the site's "December 2001 Tip of the Month."