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By Betsy Loeff, contributing writer
Policy issues and technological developments mature along a predictable life cycle, says Alison Silverstein, a self-professed "recovering regulator" and a member of the Department of Energy's GridWise Architecture Council.
According to her, the cycle starts with a handful of visionaries talking among themselves. She calls this the "five-researchers-and-a-great-catch-phrase" stage. Next comes the conference coverage period, where people start hearing about the new developments, but the only folks cashing in are the consultants.
A toe-in-the-water phase follows. In the utility world, this phase may be characterized by pilots, trials, technology tests ... you get the idea. "God forbid anyone should spend any real money," Silverstein quips.
Eventually, the idea takes off. Utilities start deploying the technologies, and just about everyone takes notice.
This is the phase Silverstein sees smart-grid applications now entering, and she appears to be right. At two recent utility-oriented conferences -- Metering America and UTC Telecom 2007 -- smart grid chatter figured heavily in discussions about advanced metering infrastructure (AMI) and why its time has come.
Time to wise up
AMI is the "enabling technology for the intelligent grid of the future," says Chris Hickman, president of SiteControls, an asset-management solutions provider. The reason: AMI delivers valuable grid information for better energy-management decisions by utility staffers, as well as frequent interval data to support time-based rates and demand management programs that could help utilities deal with stressed systems.
Aging infrastructure is one of the major drivers for smart grid applications, says Bob Richardson, vice president of strategic projects for Distribution Control Systems Inc., makers of the TWACS by DCSI metering systems.
According to DOE estimates, electricity demand has increased by around 25 percent since 1990, while construction of transmission facilities dropped 30 percent. The resulting congestion has raised line losses, which were as low as 5 percent of electricity transmitted in 1970. They were 9.5 percent by 2001.
Thermal efficiency of power plants hasn't changed much since the 1960s, DOE sources note. For centralized power generation facilities, only about 33 percent of the energy units that go into a plant are converted into usable electricity. Distributed generation achieves efficiencies of 60 percent or more but, as of 2001, only 6 percent of the nation's electricity came from DG.
Meanwhile, the Energy Information Administration estimates that 281 gigawatts of new generating capacity will be needed by 2025 to meet the growing demand for electricity in the U.S. That's the equivalent of 937 new 300-megawatt power plants.
Lighten the load
Not surprisingly, there is increased interest in demand response programs that could cut peak loads and reduce the need for peaking capacity. Much of this stems from the Energy Policy Act of 2005, notes Grace Soderberg, assistant general counsel for the National Association of Regulatory Commissioners. She points out that EPAct makes it official policy of the nation to encourage time-based pricing and other forms of demand response.
To that end, state utility commissions were ordered to consider implementation of time-based rates and the advanced metering that supports them. But there is more than policy pushing the demand response drive.
According to DCSI's Richardson, the green movement has caught on with consumers, who are increasingly aware of their own carbon footprints and eager to do their part for increased energy efficiency and conservation. Hence, they're more receptive to energy consumption data that might help them make better energy decisions.
On the utility side, Richardson cites a long list of benefits that come when utilities "leverage advanced metering infrastructure to monitor the grid" and automate distribution system equipment. For instance, AMI helps utilities find "chronically overloaded or underutilized" transformers, so they can upgrade where needed and redeploy assets that aren't being used to their full capacity.
Likewise, AMI allows engineers to detect outages quickly and completely, see phase specificity for system balancing, and find power-quality problems such as voltage sags or spikes. This diagnostic ability -- when combined with automation devices -- could lead to what Richardson sees as a primary smart grid goal: a robust, self-healing network.
AMI may be well-developed technologically, but the automation devices are just now starting to emerge. Richardson reports that his company is rolling out a capacitor-bank switching transponder that lets utility system operators remotely control circuit voltage and cut system losses due to VARs. That gives utilities more power with which to serve customer loads, Richardson says.
Such uses of AMI communications technology used to be lumped under "operational benefits" in utility AMI business cases. Increasingly, however, these benefits fly under the smart grid banner.
That shift attests to GridWise wonk Silverstein's theory of how technological developments mature along a predictable life cycle, which she estimates to last about 20 years due to regulatory delays. And, according to Silverstein, the smart grid appears to be in year 10 or 12 of its evolution toward wide-spread adoption.
Betsy Loeff has been freelancing for the past 14 years from her home in Golden, Colo. She has been covering utilities for almost four years as a contributor to AMRA News, the monthly publication of the Automatic Meter Reading Association.
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