Demand side management (DSM) is the umbrella term for the various methods that power providers employ to get customers to curb consumption. It’s been around since the 1970s, notes Joseph Eto, a Lawrence Berkeley National Lab researcher who wrote a detailed history of it in 1996. He counts conservation education, energy audits, efficiency freebies, financial assistance and time-based tariffs among the forms of DSM utilities use.
Eto also covers the technological approaches designed to achieve objectives like load shifting, peak reduction and off-peak consumption increases.
Those technologies include:
A utility opens a breaker to drop electrical load in a highly disruptive manner and without the immediate approval of the energy consumer.
Traditional or Conventional Demand Response
During constrained periods, an electric utility or balancing authority sends out a curtailment request to a large energy consumer by phone, fax, or email. Having already agreed to comply in order to receive compensation, the site operator manually reduces the total consumption from devices at the facility for several hours.
Direct Load Control
A utility or system operator uses a real-time, two-way connection with the end-use customer to adjust load as needed. For utilities, this approach delivers increased flexibility as well as dramatically improved reliability, because there’s less uncertainty about response from the participating customer. You could call this DSM 2.0
DSM 3.0 and beyond
Obviously, since Eto was writing in 1996, he didn’t cover the dramatic changes that have
redefined the future of DSM. It goes way beyond load shedding and control to encompass the intelligent and continuous control of distributed energy resources.
This is the way our grid must evolve for several reasons. One is participant fatigue. If you control loads too often or indiscriminately, the customer will tire of the program and withdraw. What’s more, it’s hard to find large loads that are suitable for direct load control, as C&I customers can’t have loads interrupted without some constraints.
Another reason we must evolve is because the devices we can control have evolved. We’re not just managing loads anymore. Today, utilities can and should be looking at managing behind-the-meter storage systems and generation in addition to the loads themselves.
And, those same distributed energy resources (DERs) that are bringing utilities more control options also are presenting grid reliability challenges. Back when load control first started taking off in the 1980s, we had centralized generation and control within our power system. That’s changing, and it’s changing quickly. California is targeting 33 percent renewables by 2020 and 50 percent renewables by 2030. The renewable firming and peak shifting such changes will bring make control of DERs all the more crucial to maintaining grid reliability.
Consequently, we need continuous and bi-directional control. Control must be continuous because renewables are apt to stop and start suddenly, and it must be bi-directional because, sometimes, grid balance might require customer equipment and devices to use more power, not less, to achieve and maintain balance.
The right technology platform can unobtrusively capture and aggregate available loads, energy storage and renewable energy sources to form a network of continuously controlled resources. It can then intelligently and dynamically optimize and dispatch these energy resources to respond to the real-time needs of the power system – all without impacting customer operations.
To learn more about DER management, check out this white paper from Enbala. It explains why we need continuous, bidirectional control of distributed energy resources, and it also covers the technology requirements to seek out for precise, sustainable DER management.