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Tackling imbalance market demands -- True cost of variable supply

Activity is now underway on several fronts in the United States on what is emerging as the number one technical issue on integrating wind power into power systems -- how to account for the variability of wind power on the energy imbalance markets. Two new studies on integrating wind are both reporting that wind power is being unfairly penalised by new market structures, while in California complete exemption from imbalance penalties is being discussed.

The Utility Wind Interest Group (UWIG), an organisation of about 50 public and privately owned utilities, has hired Electrotek Concepts of New Jersey to analyse the impacts of intermittent resources on real-time operations of electric systems. Ed DeMeo, of Renewable Energy Consulting Services and the project manager for UWIG, says the $500,000 study will quantify the impacts of large-scale wind facilities on power system regulation, supply and load balancing, and scheduling functions. He says traditional utility system operators tend to resist resources, such as wind, that are not on call. "They worry they will get 100 MW at one point and zero MW at another. We have to show them that's not the case."

He says the study will look at the cost impact of intermittent wind power output on the day to day workings of power systems. Part of the data being used in the analysis comes from actual second-to-second operations of large wind farms in southwest Minnesota that have been feeding Xcel Energy's power system since 1998. Analysts will also look at corresponding data from conventional resources along with the decisions made during those times to balance the system.

"We'll attempt to infer from that the degree between the wind output and the changes to conventional resources and then translate that into costs that are attributable to intermittency of wind," DeMeo says. "That will give us an estimate of how much the value of wind is reduced by its intermittency."

NO WIND OFFSET NEEDED

Consultant Eric Hirst, who has completed a similar study, agrees that wind output should not be analysed in isolation, but aggregated with all loads and resources on a power system just as it is for other generators. "Aggregation is a powerful mechanism used by the electricity industry to lower costs to all consumers," Hirst says. "Such aggregation means that the system operator need not offset wind output on a megawatt-for-megawatt basis." When an unscheduled wind resource appears, he says system operators simply need to maintain average reliability performance.

DeMeo says preliminary results of the Xcel analysis, which looks at a system dominated by fossil fuel, will be ready in November. Another analysis involving the Bonneville Power Administration's hydroelectric system won't be completed until June 2002.

UWIG's study will also try to estimate the value of forecasting wind resources. "If people can develop reasonably accurate forecast procedures, that would make wind more valuable and more acceptable to utility operators," DeMeo says. Hirst confirms in his study that better forecasting and scheduling ahead of time rather than in real time will improve earnings for generators, but he also says that average revenue a MWh declines as the size of the wind resource increases in relation to the size of the electrical system.

Wind exempt

Meanwhile in California, an industry working group and the state's Independent System Operator (ISO) have agreed to revisions to the ISO's scheduling protocols and energy imbalance settlements that will not penalise new wind projects. The ISO controls the majority of California's web of transmission lines. The agreement will put a new forecasting system in place this year and tax wind generators $0.10/MWh to pay for it. Among other points in the agreement for wind projects are a monthly financial settlement of energy imbalances and an exemption from imbalance penalties.

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