THE CONCEPT OF DEMAND RESPONSE (DR) HAS BEEN AROUND FOR A LONG TIME. IN the 1990s, it was called demand side management. In the mid-1990s, a number of what we now call smart homes and at least two fully automated subdivisions were built - one in Arkansas and another in Georgia. They were ahead of their time then. Their time may be about to arrive.
DR is a means of reducing consumption of electricity on an interconnected grid. Businesses, industries and individual residential consumers are asked to reduce consumption and are provided technological tools to make this happen. It has been happening fairly routinely at the commercial and industrial (C&I) level for some time now, especially in places like California and the Northeastern states where electrical supply sometimes doesn't meet demand, especially at peak usage times - usually on hot summer days when air conditioning is in widespread use.
Several companies such as Comverge, Cannon Technologies - a division of Cooper Power Systems - and EnerNOC have built substantial businesses as aggregators of companies and private individuals who are willing to reduce their consumption during peak periods. These aggregated reductions can then be treated as a resource on the electrical grid, in that they represent power a utility does not have to generate and deliver. The utility then pays the aggregator for power not needed, thereby saving the cost of building additional, expensive peaking generation units. The numbers of residential consumers participating in these programs has not been large to this point - generally 10,000, or fewer in large cities.
Participation in such aggregation programs is voluntarily and participants receive rewards for doing so, frequently in the form of credits toward their overall electric bills. This system has worked well where applied, and aggregators claim they can save utilities about 40 percent of the cost of building new peaking plants.
Utilities also have created demand response aggregation systems of their own, contacting C&I customers and offering similar incentives for them to "shift load" from peak to off-peak times. In these cases, the utilities just notify the firms that have agreed to participate when they need to curtail their electrical usage. Sometimes utilities do the notifications themselves and sometimes they use outside firms such as Varolii Corporation (previously Par3 Communications) or 21st Century Communications.
An example of how such utility-operated DR systems work occurred a couple of years ago at Oklahoma Gas and Electric (OG&E), a major investor-owned utility headquartered in Oklahoma City. OG&E had not had a forced generation outage - and thus the need for curtailing normal usage - in more than 40 months. Normal peak load for OG&E in the winter months is about 3,200 MW and the company has 6,400 MW of total generating capacity, including its own power plants and other capacity under contract. Winter normally is a good time to do routine maintaniance, so operations took 1,500 MW off-line. That left 4,900 MW available - more than enough for normal winter demand. Then some unusual things started happening.
Phil Bartholomew, who is responsible for OG&E's load curtailment program, says he was on his way to work at 7:15 a.m. when his cell phone rang. It was operations calling and they had a major problem. That winter in Oklahoma was extremely dry, it hadn't rained in weeks. As a result, coal dust and other contaminents were being stirred up by winds near the generating plants. This dust was infiltrating major transmission facilities at the plants and causing them to trip off. The problem was multiplying across the state and the situation was getting critical. Operations wanted to know if Bartholomew could notify more than 500 people at nearly 100 large C&I customers involved in OG&E's voluntary load curtailment program and begin shedding load by 8 a.m. "We need it as soon as possible!" the caller added.
Bartholomew notified Varolii and by 9 a.m. the problem was solved. "Operations was feeling the curtailment effects," he said. "We dropped 154 MW of load. Just about everyone who was on the program complied and it was enough to get us through. We had no outages." By the time the crisis had ended, OG&E had lost another 1,500 MW of generating capacity to the very unusual dust storms. But the load curtailment, which began within 45 minutes of notification by operations, was sufficent in averting an even bigger problem.
IT'S MORE THAN JUST EMERGENCIES
The problem, and opportunity, for demand response is now much larger than the temporary problems such as those at OG&E. According to the U.S. Department of Energy's (DOE) Electricity Advisory Committee, in a report issued in January, the committee "has assessed the current electric power delivery system infrastructure and concludes that it will be unable to ensure a reliable, cost-effective, secure, and environmentally sustainable supply of electricity for the next two decades."
There are a wide range of reasons why the DOE committee believes the electrical supply in the United States will be unable to provide all the electricity needed over the next 20 years. They include aging infrastructure, generation constraints - especially opposition to building new coal or nuclear plants and new transmission capacity - and the length of time it will require for renewable energy to be fully developed and deployed.
The North American Electric Reliability Corporation (NERC) has projected that electric supply shortages could begin in California and the Northwest within the next year or two, migrate to New England and the Northeast shortly thereafter and could become widespread across the United States within 10 to 12 years.
This means that DR is about the only option left. Americans are going to have to get used to having less electricity available. This includes not only C&I customers, who have been dealing with DR for years now, but residential customers as well. This is what the so-called smart grid and home automation is all about, installing technology to encourage and enable consumers to monitor their electrical usage and use less of it. Time-of-use rates, where consumers would pay as much as 10 times more, under some proposals, during peak-load times, are also being enabled in more parts of the country.
With the costs of building the required new transmission and generation to ensure an adequate supply of electricity across the United States over the next 20 years running into the trillions of dollars, consumers now seem to face two options - which are neither in their hands, nor in the hands of the utilities. The first option is to pay much higher electric rates to enable utilities to collect and spend the money required to expand the existing grid and generation system. The second option is to agree to get along with less electricity. And consumers aren't likely to make those choices. Legislators and regulators will make the choices for them.
"Everybody wants to be able to have a finger on a control, their usage, and understand what their costs are at a given point in time," said Christopher Barron, vice president and chief information officer, CPS Energy. "We don't need legislators to tell us to do that, our customers are already doing that. We've responded with different applications that come close to demand side management, but nothing will allow us to truly get there until we get the smart meters deployed."
Whether that "everyone" Barron mentions includes the majority of the general public, however, remains to be seen. Some surveys indicate average consumers don't understand the issues, but aren't happy about either paying a lot more or letting Big Brother control their usage. How that plays out over the next 10 to 20 years is what intelligent utility, smart grid, smart meters and DR are all about. It should be interesting.
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