Utilities are challenged to integrate wind power and–for some–to provide electricity to a surprising customer: the wind farms
Imagine adding a 350-home subdivision to a 2,800-member rural electric cooperative service area that went 10 years with no new homes, and rarely adds more than a couple a year.
That essentially is what faces Jerry Healy, manager of Columbia Basin Electric Cooperative, based in Heppner, Oregon. But instead of houses, wind turbines are moving into the neighborhood.
Healy already has five wind projects in his north-central Oregon service area that he says buy “up to a half million kilowatt-hours of power from us a month.”
The newest, Shepherd Flats, will add up to 900 megawatts, and is expected to become Oregon’s largest wind farm.
“They are a huge new customer,” Healy says. “In winter, each turbine uses more electricity than an average-sized home.”
About 100 miles down the road in The Dalles, Jeff Davis, general manager of Wasco Electric Cooperative, can commiserate. His 2,980-member utility serves 11 different wind projects encompassing 572 turbines and 1,061 MW—and he is bracing for more. Another 1,100 MW are permitted or going through that process.
Wind development has been a boon for the local economy. As an example, revenues in Sherman County—home to all of the Wasco Electric projects—more than tripled in the past eight years.
Lease payments from wind developers also has been a lifesaver for farmers who have struggled to hold on to land that has been in their family for generations. Healy says the going rate he hears is $10,000 a year for each 1.5-MW turbine. It used to be $2,500, he notes.
As the physical landscape has changed, so has the make up of those two co-ops.
“The wind farms comprise our largest individual consumer,” Davis says, noting that together they account for 13 percent of his utility’s load. “They are a signficant part of the revenue of the co-op.”
While the power they draw is generated locally, most of the power they produce is shipped out of the area.
Electricity is needed to keep lubricants for the turbines warm, run the computers that reposition blades into the wind, and power offices and substations. All components are fully functioning even when the blades are not turning.
Dale Coyle, manager of Portland General Electric’s 450-MW Biglow Canyon Wind Farm, says that requires
5 to 20 kilowatts a turbine—comparable to the 10 to 20 kW used by a single-family home.
“If we can get one or two turning, we can power the site,” Coyle says. “We obviously want to generate more than we use. Last year was a bad wind year, producing 3 to 4 percent less than we’ve had in the past. This year is on a good pace. Forecasting is a big deal and a delicate process.”
The same is true for the utilities serving the wind farms—particularly in light of new two-tiered contracts with the region’s primary wholesale power supplier, the Bonneville Power Administration.
Beginning October 1, BPA will implement a new pricing structure. Tier 1 power—allocated based on each utility’s historic loads—will be priced at cost from power generated by the federal system. Any power BPA provides beyond that is Tier 2 and will be charged at market rates.
Healy says Shepherd Flats should pay the Tier 2 rates that Columbia Basin will be charged as soon as the wind farm is operational, rather than “all of our customers paying their electric bill.”
Wasco Electric is preparing a cost of service study and considering how to set up its billing structure, Davis says, noting “wind development will be a significant reason we move into Tier 2 power.”
Demand charges assessed by BPA due to system peaks from turbines cycling on and off also will be directly assigned to all wind developers, Healy says.
Caithness Energy—the Shepherd Flats developer—objects to Healy’s position and is trying to bypass the co-op and work with a neighboring investor-owned utility.
“That should be our load,” Healy says, noting he is considering legal action to protect his service territory boundaries.
Regulating the System
Power systems rely on a constant balance between power demand and power generation. If one exceeds the other, the lights can go out.
Regulating the system to maintain that balance will be the challenge faced by Golden Valley Electric Association when the Fairbanks, Alaska, utility brings its Eva Creek Wind Project online later this year.
“Load is a minor impact on what we are doing here,” says Greg Wyman, manager of construction services for GVEA. “Alaska is electrically islanded from the national grid, with a single T-line between Anchorage and Fairbanks.”
As wind output goes up and down, the utility will have to manage its other generation resources.
“We might have to shut down cheaper baseload plants to accept wind, or not accept our low-cost power from Anchorage,” Wyman says, noting Anchorage deliveries must be scheduled 24 hours in advance. “We might have to turn on an oil-fired generator.”
GVEA will own Eva Creek, giving it sole control to shut down one or more of the project’s 12 to 16 turbines to balance its load and manage the cost of its system.
“Any more than 24 to 27 megawatts would be uneconomical to integrate into the system,” Wyman notes.
The Bonneville Power Administration understands integration challenges. Last June, an abundance of wind coincided with record-breaking flows in the Columbia River. Since releasing water over spillways can be harmful to endangered fish, BPA gave power away to other producers to serve their customers, while curtailing their output.
Unlike other power generators, wind producers have economic incentives to run turbines even when free federal power is available to serve their loads.
With the region’s wind power expected to double by the end of 2013, and production tax credits on the line, the balancing act will become tougher.