Bringing power to the people could be more than just a 1960’s era goal for social change if promoters of localized electricity distribution systems—called “microgrids”—have their way. Seen as one approach for safely incorporating on-site renewable resources into the larger utility grid, microgrids are gaining new attention among both researchers and marketers.

A recent study from Boulder, Colo.-based Pike Research forecasts the market for microgrid systems will reach $2.1 billion annually by 2015, with a total of 3 gigawatts of microgrid-related capacity online. The growing interest in on-site power generation and load management is among the factors driving the trend, and today’s increasingly sophisticated control electronics are helping to enable it.

Microgrids may be powered by a combined heat and power (CHP) generator, a photovoltaic array, wind turbines or some combination of technologies. The idea isn’t new. The distribution system Thomas Edison designed for New York City was, essentially, a series of isolated microgrids powered by distributed generating stations, each serving its respective community. Economies of scale made Edison’s system obsolete, however, as utilities developed the centralized generation and transmission system we know today.

Although some commercial/industrial/institutional microgrid installations have been running since the mid-1950s, greater adoption of the approach has been stymied by utility concerns related to islanded power systems. The fear is that such systems could feed power back into the larger grid during utility outage, putting utility repair personnel at risk.

The Institute of Electrical and Electronics Engineers Standard 1547, Standard for Interconnecting Distributed Resources With Electric Power Systems, has helped address these concerns, and utilities now are exploring designs that would ensure safety and support their own efforts to develop demand-side management programs.

One such investigation is being led by the Consortium for Electric Reliability Technology Solutions (CERTS), a public/private partnership under the auspices of the Lawrence Berkeley National Laboratory. The group is testing a system that uses a single switch to disconnect a microgrid from the larger utility system. This approach negates the need for 1547-compliant switches at each individual energy source.

“The compliance made necessary by the standard will be met by the shutoff switch,” said Robert Lasseter, CERTS’ technical lead for the project. “To the utility, that switch meets the 1547 requirement.”

CERTS successfully implemented this approach at a test site supplied by the Columbus, Ohio-based utility AEP. CERTS’ first field demonstration is now under construction at the headquarters of the Sacramento Municipal Utility District, and in parallel, the U.S. Energy Department is installing a similar microgrid at a large California prison.

Lasseter said CHP systems are making microgrids attractive for larger buildings and campuses. Because facilities are able to make use of both the electricity this equipment generates and the heat it creates as a byproduct, they are capturing up to 90 percent of the energy produced. This high efficiency rating can make such systems cost-competitive on cost-per-installed-kilowatt basis against electricity delivered from central generating stations.

“We really don’t have the system developed down to the single-phase [residential] level yet. But I think there’s an enormous market at the commercial level,” he said.

One reason for that large potential microgrid market is that the systems can serve as backup resources when utility demand-side management incentives make flexible load management a financial goal. Advances are being made in this sector that can help facility energy managers maximize savings opportunities by automating load-shifting operations.

For example, Conshohocken, Pa.-based Viridity Energy has developed software that tracks a facility’s current demand, along with utility rate schedules, to create load-shedding profiles that can mean big savings during peak periods. Although the VPower system isn’t designed specifically for microgrid installations, such equipment can be tapped as a resource by this sophisticated tool.

“End-users usually have the ability to control some of their load,” said Allen Freifeld, the company’s senior vice president for external affairs. “If their resources include microgrid, we act as an interface between the user and the organized electrical grid.”

The kind of control Viridity’s system enables is only possible with advanced computing power. Utility rate schedules vary widely across the country, with rate-change lead times ranging from a day ahead to as little as four seconds ahead. Viridity’s software connects directly to facility energy-management systems, eliminating the need for manual oversight in such a rapidly shifting marketplace.

Viridity’s system doesn’t require a microgrid, and many clients benefit by simply cutting back lighting and cooling when they receive the software’s signal. However, Freifeld said the idea of distributed, independent grids was beginning to strike the collective imagination of facility managers seeking new ways to control rising energy costs.

“Microgrids are sort of transformational,” he said. “Customers are beginning to realize they can be active participants in the market and not just passive buyers.”

ROSS is a freelance writer located in Brewster, Mass. He can be reached at chuck@chuck-ross.com.