Since 1999, the US wind industry has strongly disagreed with how transmission providers look at generating resources that cannot be called up on demand. Transmission suppliers see wind as an intermittent resource and, in most areas of the country, place hefty penalties on plant operators when scheduled energy is not delivered. Those penalties, known as generation imbalance charges, are costing wind plant owners a bundle -- as much as $0.10/kWh of undelivered energy in the Northwest -- and could slow the rapid growth the industry experienced in 2001.
"If wind generation is not firm, then the producer is required to get the generation to make it firm," says Jim Caldwell of the American Wind Energy Association (AWEA). "The cost is something approaching the current value of wind, so it doubles the cost just to deliver the power." AWEA's goal, he says, is to make wind a legitimate way to produce electricity without having to firm it up. "Without that, we'll never get penetration on the grid," Caldwell says.
The industry has made significant progress towards a solution with a recent filing by the California Independent System Operator (ISO) to the Federal Energy Regulatory Commission (FERC), which oversees transmission rules in the country. The California ISO is proposing to schedule wind resources using a wind energy forecasting model to average imbalances over a month -- and to waive generation imbalance penalties for wind resources. AWEA wants FERC to use the California model as a template for other transmission providers across the country.
"We are very excited about this deal in the sense of forming a tariff, a template, for the rest of the country," Caldwell says. "Rather than going utility by utility, tariff by tariff, in a game we can't win in the end, we are asking FERC to approve the settlement in California and use it as a template for the rest of the nation."
FERC's Order 888 sets the standard pro forma tariff in a deregulated world. It requires scheduling generation on the transmission system for each hour 24 hours in advance with the option to change the schedule one hour ahead. It was designed with large firm blocks of dispatchable power in mind. When the Midwest saw price spikes in 1999, says Caldwell, some generators found it cheaper and easier to default on delivery. So the industry decided to set damages for non-delivery of scheduled power.
Over the past two years, the wind industry has made progress in avoiding those damages. The Pennsylvania/
New Jersey/Maryland ISO, which actually touches on seven mid-Atlantic states, has a liquid transparent spot market in which wind can settle imbalances penalty free. In simple terms, if a generator schedules 100 MW, but delivers 105 MW, the additional 5 MW is sold at spot market prices. Conversely, if only 95 MW is delivered, the transmission system will make up the difference, again at spot market prices. According to Caldwell, this gives wind developers a fixed price revenue stream, which helps when securing financing for projects.
Other areas deal with the problem in other ways, says Caldwell. New York pretends wind has no imbalance between power promised and delivered and retroactively resets the schedule according to the actual meter read. The Electric Reliability Council of Texas uses dynamic scheduling to deliver energy imbalances across the state. But that limits wind sales basically to large utilities that have enough diversity of load and other generating resources to handle the ebb and flow from the wind resource.
The Northwest is considering something closer to the Pennsylvania/New Jersey/Maryland ISO model. Right now, if the delivery of power deviates from the schedule by plus or minus 1% or 3 MW, the generator has to pay an onerous penalty amounting to $100/MWh not delivered, says George Darr of the Bonneville Power Administration (BPA). He says BPA's power organisation, along with wind industry and renewables advocates, are asking BPA's transmission organisation for relief from the huge penalty by going to a second tier market rate.
In addition, like California, BPA is also looking at a wind forecasting model. "The direction we're approaching is for the hydro system to deal with wind," Darr says. "If we can predict wind better, we can also run the hydro system better, and it allows for better scheduling." Such a forecasting system, however, begs for a regional sponsor, he says. That could be BPA or it could eventually be the Regional Transmission Organisation (RTO) West, an ISO that Northwest transmission owners are still debating.
There is also the option for the FERC to get involved and make forecasting a basic requirement. That will effectively happen if the federal agency adopts the California model. In that state, wind farm owners will develop the wind forecasting system and the ISO will operate it. Wind generators will pay a forecasting fee of $0.10/MWh and will set transmission schedules according to the forecast. If the wind generators contribute to the costs and schedule according to the forecast, then generation imbalance penalties will be waived.
FERC is due to decide the issue in the first quarter of 2002. Even if the wind industry is successful, transmission issues like upgrades and expansion must still be dealt with. But those are issues for all players, not just for wind.