The Idaho Public Utilities Commission (PUC) has established new rules for renewable energy projects that enter into sales agreements with regulated utilities.
The rapid development of wind projects led utilities to petition the PUC in November 2010 to investigate the methods the commission uses to set the price that should be paid to renewable energy developers. Utilities complained that the federal Public Utility Regulatory Policies Act (PURPA) was forcing them to buy power they did not need at rates that were too high.
Congress passed PURPA in 1978 to encourage renewable energy development. The law requires regulated utilities to buy energy from qualifying renewable small-power projects, called qualifying facilities (QFs). Although the “must buy” provision of PURPA is a federal law, Congress left it to states to determine the rate to be paid to QF developers.
That rate, called an avoided-cost rate, is to be based on the cost the purchasing utility avoids by not having to generate the power itself or buy it from other sources. According to the PUC, because ratepayers end up paying for QF energy, the intent of PURPA is that, cost-wise, ratepayers are indifferent as to whether their utility uses more traditional sources of power or buys from qualifying renewable energy projects.
Under the new rules, the cap for wind and solar projects seeking the PUC’s published avoided-cost rates is 100 kW. The eligibility cap for all other QFs remains 10 MW. Wind and solar projects larger than 100 kW are eligible for a negotiated avoided-cost rate using each utility’s long-range growth plan as the basis for the negotiation.
The PUC denied an Idaho Power Co. proposal to use the Integrated Resource Plan (IRP)-based negotiated rate methodology for all QFs. The PUC also denied a proposal by Idaho Power that would relieve it from its PURPA mandatory purchase obligations by allowing it to curtail generation from some projects during certain periods of light customer load. The PUC said that while federal law allows curtailment under specified conditions, Idaho Power did not provide sufficient evidence to support its proposal.
Projects with published-rate contracts will be able to keep the renewable energy certificates (RECs) associated with their projects. Wind and solar projects larger than 100 kW and all projects larger than 10 MW with negotiated contracts using the IRP methodology will retain one-half of the RECs associated with their project, while the purchasing utility retains the other half.
Fuel-price forecasts and load forecasts will be updated on June 1 of each year so that the price paid to QFs more accurately reflects avoided cost. Until now, a large part of the rate paid to QFs was updated only when the Northwest Power Planning and Conservation Council issued an updated natural-gas price forecast. The new annual update will be based on natural-gas price forecasts provided by the federal Energy Information Administration’s Annual Energy Outlook.
The maximum contract length for sales agreements between utilities and QFs remains 20 years. Alternatives to a 20-year contract may be negotiated by the parties and considered by the commission.
New QF contracts will be paid for capacity based only on the project’s ability to deliver during peak hours and when a utility’s long-range plan shows the utility is capacity deficient. Currently, QFs are paid for both energy and capacity, the latter being potential surplus the utility may need during peak-load hours.
“Wind and solar are intermittent resources with unique characteristics,” the PUC says. “A 100 MW wind farm or solar project can be broken up into 10 MW pieces in order to maintain multiple published-rate contracts.” That, the commission said, no longer produces a rate that accurately reflects the value of the energy to the utility.
“Congress intended to allow PURPA cogeneration and small renewable projects to produce and sell power without the burden of being regulated as an electric utility,” the PUC adds. “Congress did not intend for multinational corporations to fund large wind farms for the benefit of their shareholders and the detriment of utility ratepayers. Indeed, PURPA transactions are intended to hold ratepayers harmless.”
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