The Idaho Public Utilities Commission Dec. 18 set rules for renewable power projects that enter into sales agreements with regulated utilities.
Utilities petitioned the commission in November 2010 to investigate the methods used to set the price that should be paid to renewable developers following the rapid development of wind energy projects in the state. The petition said that the federal Public Utility Regulatory Policies Act (PURPA), passed in 1978 to encourage renewable power development, was forcing them to buy power they did not need at rates that were too high.
PURPA 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, states were allowed to determine the rate, called an avoided-cost rate, to be paid to QF developers. 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 projects.
The new order includes:
- Setting a cap for wind and solar projects at 100 kW. The eligibility cap for all other QFs remains 10 average megawatts (aMW). Wind and solar projects larger than 100 kW are eligible for a negotiated avoided-cost rate using each utility’s Integrated Resource Plan as the basis for negotiation. IPUC denied a proposal by Idaho Power Co. to use the IRP-based negotiated rate methodology for all QFs.
- The commission 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 light loads. Regulators said the company did not show sufficient evidence to support its proposal.
- Under the new order, projects with published-rate contracts will be able to keep the Renewable Energy Certificates (RECs) associated with their projects. However, wind and solar projects larger than 100 kW and all projects larger than 10 aMW 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 every year on June 1 based on forecasts from the Energy Information Administration’s Annual Energy Outlook, instead of only when the Northwest Power Planning and Conservation Council issued an updated natural gas price forecast.
- The maximum contract length for sales agreements between utilities and QFs remain 20 years. Utilities wanted them to be five years. Alternatives may be negotiated by the parties and considered by the commission.
- The new order also requires that new QF contracts will be paid for capacity based only on the project’s ability to deliver during peak hours and when the utility’s long-range plan shows the utility is capacity deficient.
“This commission has a long history of encouraging PURPA development,” the commission said. “With the changes adopted herein, we believe that PURPA development can continue to thrive in a way that holds ratepayers harmless. QF projects that provide a utility with needed energy and capacity will be compensated accordingly. QF projects that are inconsistent and detrimental to a utility’s load and resource balance will also be compensated at a rate that reflects the costs that the QF allows the utility to avoid by purchasing its generation.”
To read the entire order, click here.
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