Idaho Public Utilities Commission
Case No. IPC-E-10-51, -52, -53, -54 and -55, Order No. 32298
Case No. IPC-E-10-59 and -60, Order No. 32300
Case No. IPC-E-10-61 and -62, Order No. 32299
Case No. PAC-E-11-01, -02, -03, -04 and -05, Order No. 32302
July 27, 2011
Contact: Gene Fadness (208) 334-0339, 890-2712
Commission denies reconsidering 14 wind projects
The Idaho Public Utilities Commission today issued four orders declining reconsideration of its June 8 orders that said contracts for 14 wind projects were not completed in time to be eligible for the commission’s published rate.
Nine of the projects had proposed sales agreements with Idaho Power Company and five with PacifiCorp, which does business in eastern Idaho as Rocky Mountain Power.
The commission’s primary reason in declining to reconsider is that the contracts for all the projects were for more than 100 kW and became effective on or after the Dec. 14, 2010, the date on which wind and solar projects generating 100 kW or less could qualify for the commission’s published rates.
The commission lowered the eligibility cap for wind and solar projects from 10 MW to 100 kW in response to a complaint filed last November by Idaho’s three largest electric utilities that alleged large wind projects were being broken down or “disaggregated” into smaller 10 MW projects in order to qualify for the typically more attractive published rates rather than having to negotiate a rate with the utilities. The result, the utilities alleged, was a rapid increase in the number of wind applications forcing the utilities to buy power they did not need at rates that were not reasonable for customers. The cost of power generated from small-power developers is passed on to customers. The commission’s primary responsibility when reviewing these contracts is to ensure that utilities do not pay more for power purchased through this type of contract than they would if the utility generated the power itself or bought it elsewhere.
The developers of the wind projects petitioned for reconsideration, most alleging that
federal PURPA* law entitles developers to rates that are in effect on the date that a qualified developer commits to sell its output to an electric utility. In response, the commission stated that federal law allows states the flexibility to determine the date at which a legally enforceable obligation is incurred. The commission has determined that a legally enforceable obligation is incurred when both parties sign the power purchase agreements.
The developers also argued that the commission’s “bright line rule” that says an agreement is not enforceable unless it is executed by both parties does not conform to controlling Idaho case law regarding contract formation. The commission rejected that argument, asserting that energy sales agreements differ from a standard offer-and-acceptance contract. Idaho statutes dictate that PURPA agreements be subject to review and approval by the commission.
The developers also said the commission should consider grandfathering the projects under the previous size limit as it has done in previous cases. In response, the commission noted that the Supreme Court has said that regulatory bodies that perform legislative as well as judicial functions – as does the commission – are not bound by precedent and can alter their decisions as long as they are not arbitrary or capricious in doing so.
While the published rate is no longer available to these projects, developers have the option of negotiating with the utilities for a rate using the utility’s Integrated Resource Planning (IRP) process. The IRP methodology recognizes the individual generation characteristics of each project. It assesses when the project is capable of delivering its output against when the purchasing utility is most in need of the energy, resulting in a price that reflects the value of the energy to the utility. Using the IRP methodology does not negate the requirement of the utility, under PURPA, to buy output from qualifying renewable projects. Developers have the option of filing a complaint with the commission if they believe the utility is not negotiating in good faith or is in violation of its obligations under PURPA.
Projects denied reconsideration include:
Cotterel projects near Burley – The five projects, submitted by Cotterel Wind Energy Center LLC and owned by Shell, initially responded to a 2009 Idaho Power bid request as one large project of 150 MW. After an agreement was not reached, Cotterel submitted five PURPA contracts requesting the published avoided-cost rate for five 10-MW projects with a scheduled online date of Oct. 31, 2014. Under the commission’s published rate, annual energy payments by Idaho Power for the expected generation would have been about $26 million in 2015, increasing to about $46.8 million in 2033, or a total of $716.4 million over the 20-year term of the three agreements.
Rainbow projects near Declo – The two projects, called Rainbow Ranch and Rainbow West, are managed by American Wind Group LLC. Under the commission’s published rate, annual energy payments by Idaho Power for the expected generation from the Rainbow Ranch projects would have been about $7.2 million in 2013, increasing to about $14.1 million in 2032, or a total of $208.8 million over the 20-year term of the three agreements.
These agreements were signed on Dec. 14. The developer argued the Dec. 14 effective date was “vaguely written,” and that a reasonable person could believe that a contract effective on Dec. 14 could qualify for the published rate. The commission responded, “There is no other reasonable interpretation but that the change in the eligibility cap was in effect on the day that the commission declared it become effective – Dec. 14, 2010. There is nothing ambiguous or vague about when the new eligibility cap took effect.”
Grouse Creek projects near Lynn Utah – The two wind projects near Lynn, Utah (south of the City of Rocks national reserve in Idaho), were proposed by Brett Woodward of Wasatch Wind Intermountain LLC. The projects were originally one 65 MW project that was to be paid a rate negotiated between Idaho Power and the developer. However, due to federal permitting issues, the overall footprint of the project was reduced and submitted as two 10 average megawatt projects to be paid the published rate. Under the commission’s published rate, annual energy payments by Idaho Power for the expected generation would have been about $8.3 million in 2014, increasing to about $15.9 million in 2033, or a total of $236.4 million over the 20-year term of the three agreements.
Cedar Creek projects near Shelley – These five wind projects were proposed for southeast of Shelley in Bingham County by Cedar Creek Wind LLC. Cedar Creek and Rocky Mountain Power originally discussed the possibility of two 78 MW PURPA projects, but Cedar Creek said the avoided-cost rate calculated by Rocky Mountain rendered its projects uneconomical. Cedar Creek subsequently decided to reconfigure the projects into five 10 MW to qualify for the commission’s published rate.
In addition to the arguments stated above by other developers, Cedar Creek also argued that the commission did not give proper notice of its intent to require that project developers have fully executed contracts before Dec. 14 to be eligible for published rates. The commission responded that it did provide notice on Dec. 3 and that no party appealed that Dec. 3 order. Because no party appealed that order, the argument against it amounts to a collateral attack of a previously approved commission order.
A full text of the commission’s orders, along with other documents related to these cases, is 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 the case numbers cited above. Any appeal to the commission’s orders must be made to the Idaho Supreme Court.
* The federal Public Utility Regulatory Policies Act (PURPA) requires regulated utilities to buy power generated by qualifying facilities (QFs). The federal law requires state commissions to publish a rate that utilities must pay the developers for projects producing up to 100 kW. The published rate is to be based on “avoided-cost,” or the cost the purchasing utility avoids by not having to generate or buy from elsewhere the energy the PURPA project generates. States have the discretion to offer the published avoided cost rate at a capacity amount or “eligibility cap” higher than 100 kW. For wind and solar projects larger than 100 kW, the avoided-cost rate is to be negotiated between the purchasing utility and the developer using a cost formula approved by the commission. Other PURPA projects such as geothermal or anaerobic digesters have an eligibility cap of 10 MW or smaller to qualify for the published rate.