August 19, 2011 | 6
On February 1, 2011 a sudden cold snap and severe winter storms sent electricity demand in Texas through the roof. In a single hour, temperatures dropped almost 30 degrees. And, as temperatures dropped, the state’s power plants were unable to keep up with the growing demand. The resulting series of blackouts affected millions of customers. They also illustrated the reasons behind the utility industry’s move toward distributed demand control throughout the United States. This move is a part of a bigger evolution in the nation’s electrical grid, where utilities are transforming from energy providers to energy partners.
This summer, the opposite problem – record setting heat – has again strained the Texas grid. But, utilities have been able to avoid more blackouts in part through voluntary conservation by state residents. By using forms of real-time communication with their customers, Texas utilities have managed shave off bits of their peak demand. Below is a short series of tweets by Austin Energy on August 5, when temperatures in central Texas hit 106 deg. F with sunny skies.
Figure: Austin Energy tweets on August 5, 2011
In the future, these conservation efforts could be taken a big step forward. By enabling active management of residential electricity demand through remote control and in-home systems, utilities could reduce the impact of or even eliminate events like the February blackouts. Often discussed under the umbrella of the “smart grid,” distributed demand response could give residents more control over their energy use and help accelerate the electric power industry’s evolution from energy provider to energy partner.
Demand Response – Large Electricity Users
This ability to manage customer energy demand is already used widely by utilities in the industrial and commercial sectors. In many locations, large commercial and industrial facilities agree to reduce or shift their electricity use in response to overall demand (and supply) in their region and in emergency situations. This type of curtailment was seen in Texas in February 2008, when a drop in wind power supply caused utilities to remove 1,100 megawatts (MW) of demand in 10 minutes, mostly from large interruptible customers. Utilities often compensate companies for this ‘demand response’ service by providing a payment for being on call, whether or not the customer is actually called upon, along with an additional payment when a demand response event occurs. This arrangement can be mutually beneficial, as it pays consumers to reduce peak power demand, which in turn helps utilities keep generation costs lower.
But, these demand response arrangements have traditionally been limited to large users of electricity, such as refining facilities or manufacturing centers. As technology has become more sophisticated, the potential for widespread application of load control for smaller customers has become a reality. In the residential sector, which represents 48% of the Texas (ERCOT) grid’s peak summer demand, utilities are beginning to incorporate distributed demand response as a means of managing electricity demand.
Distributed Residential Demand Response
Today, distributed residential demand response exists in rudimentary forms. For example, Maryland’s Baltimore Gas and Electric (BG&E) offers a Peak Rewards Cycling program in order to reduce their summer peak load. In this program, residents agree to allow BG&E to turn off their air conditioning units for short periods of time in exchange for a free programmable thermostat and other monetary incentives. More advanced approaches to distributed residential demand response are currently being tested in Austin, Texas in the Pecan Street Project’s Mueller Smart Grid Demonstration. The goal of this demonstration is to evaluate the effectiveness of home energy management systems and customer-based demand response for reducing electricity usage and manage peak demand.
Studies like the Pecan Street Project will help to develop a base of knowledge that will allow utilities to offer better-targeted incentives for residential users to reduce or shift their energy usage. Information gathered could allow for the optimization of technologies such as electric and thermal energy storage, further enabling distributed demand response. With 1,000 homes and businesses, this project is the largest and most comprehensive of its type in the US and it offers a glimpse of the future of the electricity (and building) industry.
From Provider to Partner
Residential demand response is indicative of a slowly occurring shift in the way people think about electricity. There has traditionally been a disconnect between the producer and consumer; people do not receive any feedback about their energy use behavior from the utility aside from a total on a monthly bill. New technologies could help to shift utilities from the role of energy provider to that of an energy partner, where both customers and utilities benefit from smarter energy management.
During the February storms, Texas utilities had few choices when it came to reducing electricity consumption and traditional demand response partnerships with companies and manufacturing facilities were not enough. In the future, utilities might be able to more precisely manage residential electricity use in order to minimize the impact of another cold snap (or heat wave). This could help to keep utility prices low, while opening up a new frontier in remote control and in-home energy management – giving customers more control over their energy use.
Contributing to this post were Charles R. Upshaw (a PhD student in Mechanical Engineering) & Joshua D. Rhodes (a PhD student in Civil Engineering). Both are members of the Webber Energy Group at The University of Texas at Austin.
A similar version of this post was published in July 2011 in Construction News – a Texas statewide newspaper.
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