We Use Many Names and Acronyms to Describe the Simple-Yet-Powerful Tool Called Demand-Side Management. It is not uncommon to find demand management, demand-side management, demand response and energy efficiency used interchangeably. Term confusion is common when we describe the features and functionalities of the intelligent grid.


Demand management requires that we consider both demand response and energy efficiency — activities that require extensive interactions between the customer and the utility. Lighting and temperature control account for almost 50% of the electricity consumed by end users. The Energy Information Administration's (EIA) “U.S. Household Electricity Report,” issued in 2005, reports that heating, ventilation and air conditioning (HVAC) accounted for 365 TWh, or 31% of the electricity consumed by U.S. households; electric water heating accounted for 100 TWh, or 9% of the electricity consumed; and another 2.5% is consumed with pool pumps, filters, hot tubs and pool heaters. Combined, the three categories are 42.5% of the consumption. Throw in lighting at 8.8%, and the total electricity consumption is 51.3%.

Commercial and industrial loads also consume a large percentage in these categories. Given the large percentage, it is readily apparent why there is a lot of interest in energy efficiency in demand-side management programs. Increasing efficiency by just a few percentage points brings about great savings in the need for new generation and delivery systems. Make it non-invasive and automatic to the point the end user is not aware, and it becomes very successful, which is where the advanced technologies are taking demand management.

Demand response influences the customer's use of electricity, allowing the utility to move from “knee-jerk” load shedding to dynamic real-time load shaping. Demand response is now a true demand-management tool. Our electrical infrastructure was built to meet the demands of that mythical July afternoon, which represents something like 10% of the maximum peak demand. Numerous studies have identified this time frame to be roughly 100 hours out of a yearly total of 8760 hours, or about 1% of the total year. We spend a great deal of our resources for that 1% of the time when the aggregate customer's demand exceeds the system's ability to meet that demand. We must think and act intelligently if we are to properly manage that peak demand.


Historically, we addressed periods of insufficient generation by load shedding with selected brownouts, followed by rolling blackouts. This approach is a holdover technology from the 20th century. Today's customers and regulators do not easily tolerate this “dump-the-load” response — especially now that we have tools that enable us to take another path.

Consider how we handled the potential power crisis during the California wildfires in 2007. The fires wreaked havoc with power supplies in Southern California when major transmission lines were lost. The San Diego Union-Tribune quoted Debra Reed, president and CEO of San Diego Gas & Electric (SDG&E), saying, “SDG&E came within minutes of having to curtail customer power.” Restoration of transmission lines combined with Web-based demand-response programs allowed the utility to avert shedding load. Chris Hickman, president of the Energy Services division of Site Controls (Austin, Texas, U.S.), recalls, “California issued an urgent call for emergency energy conservation. Site Controls responded, working collaboratively with its customers to reduce the strain on the grid by over 3 MWh in the affected area via Web-based technology with no or very low consequence to those businesses taking part.”

On the national plane, the Federal Energy Regulatory Commission (FERC) recently published its “2007 Assessment of Demand Response and Advanced Metering,” which reported that in 2006 the peak demand was roughly 851 GW. FERC credits the use of demand-response programs as being necessary for the reliable operation of electric markets during peak hours.


The long hot summer of 2006 broke peak load records across the country and stressed the system's ability to supply electrical power to customers. Demand reductions played a key role. These reductions were obtained with reliability-based demand-response programs, which include emergency demand-response programs, with capacity market programs, and with interruptible and curtailable rate incentives.

According to the North American Electric Reliability Corp. (NERC) in its “2007 Summer Assessment,” these programs accounted for something like 21,900 MW in 2006. EIA reports that actual peak reductions in 2005 amounted to 25.7 GW. EIA breaks that down into 15.4 GW through energy efficiency and 10.4 GW by load management. This is a large amount of electricity controlled by demand-response programs that can no longer be ignored. Contrast that to the days when a utility made announcements over the media for customers to reduce consumption. As we move forward, expect to hear terawatts creep into our vocabularies as we look for more customer solutions to our energy problems.

Changes in real-time pricing of electricity are driving the evolution of demand-response consumption patterns. FERC breaks demand response down into two primary categories: incentive based and time based. Incentive-based programs offer customers some form of monetary reward to reduce their electricity usage during periods of system need or stress by direct load control, by interruptible rates and by emergency-response programs. Time-based demand-response programs offer the customer varying rates for the time-of-day usage, which could be financially motivated as well. The customer saves money by selecting times other than prime time to consume power, rather than to curtail the use of power for a fee.


Demand-response programs take advantage of innovative technologies. Today, it is possible to audit a business's facilities and determine non-essential loads available for curtailment such as lighting, pumps, thermostats and HVAC equipment. Once identified, Web-based technology can be set up to control consumption. For instance, Hickman reports, “Site Controls can control more than 400 MW of peak load with over 220 MW characterized as immediately dispatchable with this generation-quality energy resource available on demand.”

EnerNOC (Boston, Massachusetts) is another company that participates in demand-response markets in New England, New York, Pennsylvania/New Jersey/Maryland, California, New Mexico and Florida. EnerNOC recently announced a 25-MW load-reduction agreement with Tampa Electric (Tampa, Florida) and a five-year agreement for 160 MW of load reduction with Southern California Edison (SCE; Rosemead, California). Partnering with Pacific Gas and Electric (PG&E; San Francisco, California), SCE and SDG&E, EnerNOC is providing customers a voluntary, penalty-free load reduction called the Negawatt Network. Participants are given high-incentive payments to curtail usage when requested by the utility. Companies like Site Controls and EnerNOC focus on commercial buildings. Office buildings, grocery stores, discount stores and others participate in demand-response programs by reducing noncritical loads. They receive payment from the utilities for the value of the electricity they didn't use as calculated by computer algorithms developed for this purpose.


Energy efficiency is another tool showing great promise as demand management evolves. FERC Commissioner Jon Wellinghoff, addressing the 2007 Grid Wise Interoperability Conference held in Albuquerque, New Mexico, U.S., commented that if we could get a 5% improvement in energy efficiency, we would not need to build 50 coal-fired generation plants. Energy efficiency reduces energy consumption both on and off peak through a more effective use of electricity. The message being sent is that every megawatt saved is a megawatt that doesn't need to be generated. Many would argue that reducing demand provides more value than increasing the supply, considering that no pollution or greenhouse gasses are produced.

Peter Kelly-Detwiler, senior vice president of Energy Technology Services for Constellation NewEnergy, said that new power plants cannot be built fast enough to meet the demand for power in some areas. Kelly-Detwiler sees the next technology revolution coming from the customer side of the meter. The greater the cooperation between utilities and the end user in reducing demand, the longer grid operators can postpone costly new additions to infrastructure. One can create a virtual power plant by essentially substituting more efficient energy-using equipment and smarter consumption strategies in place of new supply options. This is a more economically efficient approach as well, creating more economic output per dollar of input. With advanced technology, utilities can maintain or improve existing levels of services with less energy being consumed.

The Organization for Economic Co-operation and Development's (OECD) International Energy Agency (Paris, France) reports that electricity consumption globally for artificial illumination is roughly 8.9% of the total electricity consumption (about 970 TWh annually). It also accounts for 8% of the carbon dioxide emissions. OECD tells about an incandescent light bulb replacement program in South Africa (one of seven countries taking part in the World Bank's Efficient Lighting Initiative). The South African utility Eskom took part in this program as part of its demand-side management program to reduce the need for new generation. In three years, more than 10.6 million compact florescent light bulbs (CFL) were distributed. Five million of those CFLs were distributed through a door-to-door free exchange program. As of 2006, the CFL program has resulted in a savings of approximately 193 MW on Eskom's system. Because CFLs consume one-fourth to one-fifth the electricity of incandescent bulbs, lighting initiatives worldwide would provide huge energy savings.


“There is a lot of low-hanging fruit in the energy-efficiency arena,” says James Lee, president and CEO of Cimetrics (Boston, Massachusetts, U.S.). Buildings consume more than 40% of the total energy in the European Union and the United States. Lee points out that there are about 5 million commercial buildings accounting for about 15% of the total energy consumption in the United States. Only about 10% of the commercial buildings now have direct digital controls. Integrating information technology, building automation, energy management and power distribution into one backbone system would allow our commercial facilities to react intelligently to energy consumption.

Lee mentions the 450 Golden Gate Building project, the first large-scale commercial building automation and control networks (BACnet) demonstration project, proving the concept actually works. The 22-story 1.4 million-sq ft (130,000-sq m) Phillip Burton Federal Building and Courthouse in San Francisco has been in service for about 10 years using zone levels for energy management of lighting, HVAC systems and more than 9000 data points. In the process, the project is responsible for an estimated annual energy savings of $500,000.


Austin Energy is using the Comverge SuperStat programmable thermostats in a demand-management program called Power Partner. The idea is to cut Austin's summer peaks while keeping the customers comfortable. Roughly 21,000 single-family residential participants, 25,000 multiple family participants and 4000 small commercial participants are enrolled in Power Partner. Customers are saving 15% on their heating and cooling bills with this program. Austin Energy reports that Power Partner accounts for roughly 45 MW of peak capacity.

Gulf Power's GoodCents Select program is one of the oldest customer choice programs in service. Gulf Power and Comverge teamed up to provide customers with smart thermostats and incentive rates. Gulf Power reports that customers taking part in the program have reduced their summer electricity consumption by about 2 kW, while winter reductions have averaged 4 kW. In addition, customer surveys reported that 85% pay more attention to their electricity consumption and 81% say they have not significantly adjusted their lifestyle.

Comverge also offers other demand-response programs such as the virtual peaking capacity (VPC) program to utilities. Recently, Comverge announced it has been awarded VPC contracts with PacifCorp, SDG&E, ISO New England, Public Service Company of New Mexico and PG&E. Overall, these contracts represent roughly 495 MW.

The customer demand for electricity appears to be unquenchable. EIA reports the 2006 summer peak was 4% higher than the summer 2005 peak, which was 12.1% higher than the summer 2004 peak. In addition, the utilities are infrastructure challenged. The advanced technologies of the intelligent grid have solutions, but they require a shift in the way we think and do business, not to mention large capital expenditures. Demand management with demand response and energy efficiency is changing the dynamics in our industry today and far into the future.