Ken Silverstein EnergyBiz Insider Editor-in-Chief

The problem could be solved in a number of ways that include building more generation, applying new efficiency standards and encouraging demand response programs. The latter essentially is a mechanism to send price signals to users to allow them to adjust their consumption. The benefit of that is residential, commercial and industrial users would pay less for energy while utilities could avoid having to buy power on expensive spot markets -- and all increasing the likelihood that the power keeps flowing.

While the ISO-New England (ISO-NE) would prefer to allow the market to solve the problem, it does have to intervene in the SW Connecticut matter. In that case, it has issued a request for proposal for 300 megawatts of emergency capacity. Presently, it has contracted with six suppliers for 260 megawatts that will come on line by 2007. Of that, about 20 percent is considered demand response resources.

The concept is a little esoteric, admits Bob Laurita, supervisor for demand response at ISO-NE. Most people think of emergency capacity -- the power that could be used during the most urgent times -- as a traditional power plant, or "iron in the ground." But, he is urging policymakers to expand their thinking to include demand response. "Market rules have to be written so that demand response can be the functional equivalent of conventional generation," the power exec said at a conference sponsored by Comverge.

Right now, energy saved through demand response programs is used for emergency capacity to make sure the lights always stay on. But the ultimate goal of ISO-NE is to reduce overall energy usage when the demand is highest. To do this, it plans to hold an auction next year so that generators and demand response providers alike can bid their resources into the system, all deliverable by 2010.

All resources will compete head-to-head, says Laurita. And if demand response is to win part of the bid, that product then has to be measured, tracked and understood. If it meets all thresholds, he adds that the energy optimization technique would be truly integrated into the generation mix that the system operators use when dispatching power.

Essex Power in Ontario, Canada has a different way of meeting its power needs during peak times. Because it was adversely affected by the 2003 Blackout, regulators there have put pressure on all energy companies to cut their usage. As such, Essex has implemented a demand response program that involves using distributed generation, or standby assets that have typically been used by businesses when power from the central generator and grid operator have failed. The distribution company is now seeking 2,500 megawatts of new electrical capacity evolving from demand side management.

Proactive Approaches

Ontario's issues are acute as the province has restructured its electricity market. Toward that end, it has a finite amount of generation resources that include aging nuclear assets as well as coal plants. Policymakers there have vowed to wean the province off of coal, which will be difficult to do given that it supplies 29 percent of the generation mix there. Nevertheless, such policy is the stated goal, meaning companies such as Essex have to devise innovative ideas to reduce power usage.

Basically, Essex rounded up all the distributed generators in the area and all under the blessing of the independent system operator there. According to CEO Ray Tracey, individual generators must be able to produce at least two megawatts of power to participate. All of those separate systems are then aggregated together.

And while their original purpose -- to supply emergency power for specific businesses -- will remain, they will still be available all day, every day to the distribution company. Tracey, who also spoke at the Comverge conference, estimates that an individual unit is used on average 200 hours a year.

"We've taken existing distributed generation assets and taken it over," says Tracey. "We maintain it and make it available to the wholesale market. We exercise this option during peak times when the province is stressed. This creates a payment stream to the owner and the asset is still available to them. The concept meets all the requirements to be a wholesale generator and our job is now to get more scale."

The New England and Ontario examples are noteworthy because of the influence of their respective independent system operators, or ISOs. The point is that the typical methods to bring on supplies during heightened demand have to be remodeled. ISOs are particularly well-suited to address demand response because they have the responsibility to maintain reliability. If supplies are inadequate, they must still satisfy demand -- the case in New England where the ISO there is taking an innovative approach to manage demand.

"It is very proactive for these ISOs to incorporate other ways to manage increasing consumption into their regional planning programs," says Vikki Cuddy, principal with The Structure Group. "Right now, regional planning addresses mostly supply but it is also important to recognize that demand is part of the equation."

Clearly, a need exists in some parts of the country for additional generation and transmission. In New England alone, more than 30 transmission projects are on the table. But not all such projects will get built and even if they do, they take time to implement. In any event, the Federal Energy Regulatory Commission says that there won't be enough to relieve the expected congestion in the coming years.

That's why demand response could become an increasingly valuable commodity. By utilizing it, system operators and utilities are able to become more efficient while customers get the benefit of lower bills.

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