IPUC reduces size of wind projects than can qualify for PURPA rate
The Idaho Public Utilities Commission today is reducing the size of non-firmed wind projects that can qualify for a special rate paid small-power producers by regulated utilities such as Idaho Power. With today’s order, small, non-firm wind projects can be no larger than 100 kilowatts to qualify for the rate. The previous limit was 10 megawatts.
The order is in response to a petition from Idaho Power Company that it be granted a six- to nine-month suspension from its obligation under the federal Public Utility Regulatory Policies Act (PURPA) to buy energy generated by qualifying wind-powered projects.
Rather than granting the suspension, the commission is establishing the lower limit while it leaves the case open for further study. The 100 kW limit does not apply to all PURPA contracts, but only wind contracts that are not “firm,” meaning they cannot be backed up by an alternative energy source when wind fails to generate the amount of energy the wind developer commits to deliver to the power company. Also exempt from the 100 kW limit are non-firm projects that signed power purchase agreements with Idaho Power before July 1 or have submitted a completed interconnection application and paid the required fee, and have taken other substantial steps to further their projects.
The Public Utility Regulatory Policies Act of 1978 (PURPA) requires regulated electric utilities to buy renewable power from qualifying small-scale power production facilities. The act, in response to the energy crisis of the late 1970s, requires that electric utilities offer to buy power produced by small power producers at an “avoided cost rate” equal to the cost the electric utility avoids if it would have had to generate the power itself or purchase it from another source. State commissions establish the avoided cost rate that is paid to developers.
Idaho Power sought the moratorium to address the growing number of intermittent wind proposals it is receiving, which, the company claims, could impact the reliability of its transmission grid. Later, Idaho’s two other major regulated utilities, Avista and PacifiCorp (Utah Power) joined the case, seeking to be included in the moratorium.
To ensure system reliability, Idaho Power stated that intermittent wind resources must be “firmed” by back-up power. A company analysis concluded that in order to safely integrate 1,000 MW of intermittent wind generation, it would be necessary to concurrently add 640 MW of combustion turbines to provide capacity when wind resources were not operating.
Further, Idaho Power argued, the higher PURPA price awarded small wind developers, about $61 per MWh, artificially inflated the bids the company sought from large wind developers. However, in today’s order, the commission said it found no persuasive evidence that bids were affected by PURPA rates. Idaho Power also speculates that wind developers who have been unsuccessful in the company’s bid process may decide to reconfigure their projects from one large project to several smaller projects that would then fall under the 10MW limit and thus qualify for the more attractive PURPA rate.
The commission said it needed more time to study the impact of the wind projects on reliability for customers and to examine whether the higher price paid for PURPA wind projects is beneficial for customers who end up paying the cost of higher-priced energy. The commission left this case open, directing Idaho Power and other interested parties to file a proposed schedule for an initial workshop to identify issues and schedule further procedure.
“This commission is supportive of wind generation and believes that it is a proven renewable energy technology that can, when properly integrated and economically developed, be an important addition in the resource portfolio of Idaho’s electric utilities,” the commission said. “The concern we address in this order and case docket is the proper pricing of intermittent wind generation pursuant to federal obligation and the related utility integration costs that we find may not be fully reflected in the published avoided cost rates.”
In a case concluded last November, the commission determined the parameters of wind and geothermal contracts. At that time, the commission ruled that projects 10 average megawatts and smaller would qualify for the avoided cost rate. That ruling along with both federal and state legislation that provided financial incentives for wind projects, prompted what Idaho Power claims was an unforeseen number of wind projects that could negatively impact the company’s power supply costs and threaten the reliability of the electric grid. The company claims the commission has failed to include in the avoided cost calculation the cost associated with the back-up services needed to integrate intermittent wind resources on the utility’s grid.
Since last November, Idaho Power has signed contracts from wind developers totaling 61.5 MW and has applications pending before the commission for another 21.5 MW. The company has also received contracts from developers intending to pursue another 193 MW of wind projects. Before the completion of the 2004 case, Idaho Power had less than 1 MW of PURPA wind-powered generation under contract.
The money that Idaho Power pays wind developers is included as part of Idaho Power’s overall power supply cost that is eventually recovered from customers in the company’s power cost adjustment (PCA) process every spring. Customers will be impacted negatively, the company contends, because they will be reimbursing the company for power supply costs at the higher avoided-cost rate of about $61 per MWh.
“Based on the record established in this case the commission finds reason to believe that wind generation presents operational integration costs to a utility different from other PURPA qualified resources,” the commission said.
Wind developers argued that a performance band established by the commission in the 2004 case that penalizes wind producers for not falling within 90 to 110 percent of their projected output sufficiently deals with the firm vs. non-firm characteristics of wind.
In today’s order, the commission said the performance band “may not capture the integration requirements and operational demands placed on the utility by intermittent generation and that the integration costs associated with the same may not be fully reflected in the published avoided cost rates.” Federal PURPA law stipulates that no utility be required to pay more than its avoided cost.
Copies of this order along with other documents related to the case are available on the commission’s Web site at www.puc.idaho.gov. Click on “File Room,” and then on “Electric Cases,” and scroll down to Case No. IPC-E-05-22.