The Idaho Public Utilities Commission (the “PUC”) recently issued an order defining the parameters of power purchase agreements between an electric utility and the developers of new wind and geothermal power projects. U.S. Geothermal, Inc., et al. v. Idaho Power Company, Case Nos. IPC-E-04-8 and IPC-E-04-10, Order No. 29632 (No-vember 22, 2004). The developers claimed the utility re-quired contract terms that were contrary to the Public Utility Regulatory Policies Act (“PURPA”), which gener-ally requires electric utilities to purchase electricity from qualifying small power producers at an avoided-cost rate. Among other things, the developers objected to (1) penal-ties for failure to generate monthly output at between 90% and 110% of monthly projections (“90-110 Performance Band”), and (2) a metered energy test for determining whether the projects would fall within the PUC’s 10 MW maximum limit to qualify for the PUC’s published PURPA rates – rates for larger qualifying projects are determined on a project-specific basis. By a 2-1 vote, the PUC approved modified versions of both provisions.

The PUC noted a recent increase in applications from wind and geothermal projects seeking to qualify for PURPA rates. Unlike hydro and other traditional qualify-ing facilities, wind and geothermal projects generate elec-tricity on a far more intermittent basis. A wind facility’s generation “can literally fluctuate between zero and the machine’s maximum capacity on a minute-to-minute ba-sis” placing “significant demands on utility transmission  and distribution resources.” The geothermal project in this case would generate electricity from cooling geothermal water – a process that is highly efficient in the winter and less efficient in the summer due to seasonal variations in ambient air temperatures. To generate an annual average of 10 MW, output would range from 8 MW in the summer to 12 MW in the winter. The utility argued that the avoided cost rate for intermittent, “non-firm” energy was less than the rate for “firm” energy generation.

With respect to the 90-110 Performance Band, the PUC reduced the financial penalties proposed by the util-ity and increased the frequency with which the developers could revise their projections. As approved, for months in which output is less than 90% of projected output, the utility will purchase that month’s output at 85% of the market rate or at the contract rate, whichever is less. For months in which output is more than 110% of projected output, the power in excess of 110% will be purchased at 85% of the market rate or at the contract rate, whichever is less. The developers are required to initially provide one year of monthly generation estimates followed by revised estimates every three months.

With respect to the determination of whether a project falls within the 10 MW maximum limit to qualify for published PURPA rates, the PUC rejected the utility’s proposed metered energy test. Under that test, “if a [facility] meter reads greater than 10,000 kWh per hour, then the facility is greater than 10 MW and not entitled to published avoided cost rates.” Instead, the PUC deter-mined that to qualify for published PURPA rates, the  developer would have to demonstrate that, “under normal or average design conditions, the project will generate no more than 10 average megawatts in any given month,” and maximum monthly generation qualifying for published rates would be capped at the total number of hours in the month multiplied by 10 MW.

Robert A. Olson is a partner in the law firm of Brown, Olson & Gould P.C. which maintains a nationwide practice in energy law, public utility law and related commercial transactions. He can be reached at:

Brown, Olson & Gould, PC
2 Delta Drive, Suite 301
Concord, NH 03301

rolson@bowlaw.com | (603) 225-9716