Demand-Side Management

Here's a scenario you may find familiar: Oil and gas prices rise as concerns about supplies worsen. Electricity rates begin a climb that seems unlikely to reverse itself. And consumer groups and government regulators both urge utilities to initiate programs that reward customers for using less, rather than more, electricity.

Though it could be describing the headlines of the past summer, this situation actually played out for the first time almost 30 years ago. In the late 1970s and early 1980s, during the days of our first energy crisis, utilities began providing incentives to customers who curtailed their electricity use. While some of these original demand-side management (DSM) plans have continued, most were dropped as fuel prices fell and deregulation was implemented. Now, a new generation of DSM efforts is taking hold, also driven by rising energy costs and capacity constraints, but powered by technologies that could help ensure broader acceptance and greater impact.

In their original incarnation, DSM programs focused primarily on larger industrial and commercial properties. The added investment in communications and controllers earned the greatest savings in curtailed energy use in these settings. Arrangements differed between utilities, but in most cases, owners paid lower rates, overall, by agreeing to cut back on electricity use during peak periods, sometimes with as little as 15 minutes warning.

A smaller number of plans also offered savings to residential customers. But it was expensive to provide the individual control mechanisms and, in some cases, separate meters for appliances such as hot-water heaters that might be particular targets for energy curtailment. As Harvey Sachs, a senior fellow at the Washington, D.C.-based American Council for an Energy Efficient Economy, noted, these projects required professional design and installation and relied on old-generation communications. In many cases, resulting savings were simply not enough to justify the expense.

With deregulation and the growth of merchant power plants, utilities turned to outsiders to take on the risk of developing new generating capacity. Fuel prices fell and states locked newly deregulated utilities into 10-year rate freezes, so consumers became complacent about their own electricity use.

“It was an era in which the economics triumphed over the engineers,” he said.

But the DSM tide has changed dramatically in the last few years. Fuel costs are rising, capacity constraints are forcing utilities to put expensive generating plants back on the drawing boards and those rate-hike deals are expiring, giving customers new reasons to consider cutting back demand.

“Now, we’re back in an era in which utilities are concerned about avoiding load growth,” Sachs said, adding that it can cost electricity suppliers up to $1,000 per kilowatt to add peaking-plant capacity, even before they start paying for fuel. “So, if I can get my customer to do something to avoid that demand, then I’ve got a reason to talk to that customer.”

Utilities are seeing more reasons to start those conversations almost every day. Flat-panel television sets and electronic gaming devices are pulling more juice out of the grid than ever, and the trend shows no sign of reversing anytime soon.

“We’re thinking demand is going to rise by 30 percent by 2030,” said Ed Legge, spokesperson for the Edison Electric Institute, a Washington, D.C.-based industry organization representing investor-owned electric utilities. “And this reflects all the fruit you can pick from the efficiency tree.”

New DSM efforts also are benefiting from new, relatively inexpensive technologies that enable two-way communication between utilities and their customers. Together, these sensors, controllers and other devices make up what’s now being called the “smart grid.” In pilot programs across the country, utilities are beginning to implement programs that allow customers access to real-time energy-use information and enable utilities to remotely set back air conditioners, dryers, refrigerators and other large appliances during peak-usage periods.

Leading the pack is Minneapolis-based Xcel Energy. In May, the utility launched an effort to turn Boulder, Colo., into the first “SmartGridCity,” a project Xcel says could end up costing $100 million by the time it is completed in December 2009. Approximately 50,000 new meters will be installed, along with an advanced, high-speed communications network. Additionally, the company will be upgrading four substations and 25 feeders, and adding power analyzers at each distribution transformer to speed identification and correction of system faults.

By essentially turning Boulder’s distribution grid into a giant supervisory control and data acquisition (SCADA) network, this project represents the path many see as the future of modern-day DSM efforts. However, unlike the first incarnation of these programs, utilities, not third-party energy-services companies, are taking control of both plan design and implementation.

“We want to be in on that business,” Legge said. “We feel like we’re the experts, and our companies are successful in implementing efforts.”

ROSS is a freelance writer located in Brewster, Mass. He can be reached at

About the Author

Chuck Ross

Freelance Writer

Chuck Ross has covered building and energy technologies and electric-utility business issues for a range of industry publications and websites for more than 25 years. Contact him at

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