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Huge buffalo ridge project in jeopardy

Future development of the largest wind project ever -- now being constructed at Buffalo Ridge in Minnesota -- could be in danger. Northern States Power (NSP) is arguing in the state's latest Integrated Resource Plan that it should be released from its obligation to build a further 400 MW of wind by 2002. NSP agreed to build 425 MW of wind and 125 MW of biomass in return for permission to store nuclear waste under the so-called Prairie Island settlement.

By late March, about one-fifth of the 107 MW of Z-40 turbines being installed by Enron Wind Corporation in the delayed Phase II of the project were operating, according to NSP. Some 20 machines, about 15 MW, can be seen running at the site. Originally, 20% of the development was to have been turning by the end of October, but NSP extended that deadline because of a delay in turbines arriving from California (Windpower Monthly, November 1997). All of the 143 turbines are to be on line by June 30.

NSP is only obliged to build the additional wind power if it is determined to be the "least cost" option by the utility commission. Based on the expected costs and performance of the 207.25 MW of wind plants now being built, NSP claims the 400 MW of wind generation would increase lifetime electric costs by $409 million above the least cost option.

In its Integrated Resource Plan (IEP) filing, wind power production is estimated at $35 a megawatt hour, compared to $33 for power from a natural gas-fired combined cycle turbine. Wind has additional cost penalties, says NSP, because backup generation is needed "to handle the intermittent nature of wind generation" and from incremental transmission expenses.

"Wind does not either improve the adequacy or reliability of utility service," the plan reads. "Indeed, because of its intermittent characteristics, it could be argued that wind impairs system reliability. In other words, unless backed by dispatchable resources, wind is not reliable."

Part of the cost calculation hinges on power pool capacity rules that penalise intermittent wind power. The Mid-Continent Area Power Pool (MAPP) planning region calculates an "accredited capacity" for all generators, based on their firm reliability during periods of peak demand. NSP assigned an accredited capacity of 20% for the projected wind farm, or 80 MW of firm capacity. The capacity factor for the project was estimated at 35%, resulting in an average capacity of 140 MW and annual production of 1.2 million MWh.

Because the accredited capacity is only 80 MW, NSP compares the wind project in its plan with an 80 MW gas turbine -- which provides firm capacity -- and enough system power to make up the rest of the annual 1.2 million MWh of energy. The system power would be from excess capacity in the MAPP region or bought from Manitoba Hydro.

Consultant Tom Wind, who is preparing a response to NSP's filing on behalf of the Izaak Walton League, says the plan leaves out many details, and that a thorough analysis is difficult at this time. The Izaak Walton League has filed a number of information requests from the utility.

False assumption

His first impression, though, is that NSP may be basing its accredited capacity assumptions for wind power on the Phase I Buffalo Ridge project, built by Kenetech in 1994. "To base their future performance on a wind farm that has had reliability problems is not fair," he says. "But from their perspective they may be being conservative." If the accredited capacity for the 400 MW of wind were higher, the utility would have to use a plant for comparison that had a larger firm capacity, which would result in higher prices. A 25% accredited capacity, for example, would require a 100 MW gas turbine to match the capital and operating costs of the wind plant.

Tom Wind is planning a 2.25 MW wind farm near Algona, Iowa, for an association of Iowa municipal utilities. For this project he estimates accredited capacities of 7-26% a month, with an annual average of 19%. Since winds are better at the Buffalo Ridge site, he expects the accredited capacity to be "quite a bit" better in Minnesota. Both Iowa and Minnesota wind farms have peak output in fall and spring, resulting in higher accredited capacities in those months. Summer output is lower, while electricity demand is higher, resulting in very low accredited capacities.

The expected cost of the gas turbine alternative also depends on future fuel prices and the cost and availability of excess capacity in the upper Midwest. The IRP is unclear on the assumptions used for both of these factors. The Izaak Walton League will be filing comments on the plan in May, and a decision from the Minnesota commission is not expected until next year.

NSP did seem to open a door for future wind development as part of restructuring legislation that may be heard next year. "The better approach," the plan reads, "is for the state to determine how it will want to develop renewables in a more competitive environment and to then develop requirements which are equally applicable to all Minnesota electric customers."

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