Idaho Public Utilities Commission

March 2, 2011

Case Nos. PAC-E-11-01, -02, -03, -04, -05, Order No. 32192

Contact: Gene Fadness (208) 334-0339, 890-2712


Agreements sought for Bingham County wind projects


Comments are being accepted through March 24 on application by PacifiCorp for state regulators to make a determination regarding sales agreements with five wind projects in Bingham County.


PacifiCorp, which does business as Rocky Mountain Power in eastern Idaho, seeks an Idaho Public Utilities Commission decision regarding proposed sales agreements between the utility and Cedar Creek Wind LLC of Bainbridge, Wash. The agreements are for 20 years with a targeted operation date of Oct. 1, 2012. Each would deliver up to 10 average megawatts monthly to the utility and be paid by PacifiCorp at a rate that is published by the Idaho Public Utilities Commission.


However, the applications for the projects were submitted to the commission after the Dec. 14, 2010, effective date of a commission order that reduced the eligibility cap on the size of wind and solar projects that can qualify for the commission’s published rate from 10-megawatts to 100 kilowatts. Cedar Creek claims the agreements were ready for execution well before the end of 2010, but actions by PacifiCorp delayed the agreements being finalized.


The temporary reduction in the eligibility cap came after Idaho’s three major investor-owned electric utilities said the rapid development of large wind projects that are broken up into smaller 10-MW projects in order to qualify for the published rate is circumventing utility planning process and creating system reliability and operational issues. The utilities claim that the “continuing and unchecked requirement” for them to acquire additional intermittent generation regardless of the need for additional energy “increases the price its customers must pay for their energy needs.”


Regulated utilities are required, under the provisions of the federal Public Utility Regulatory Policies Act (PURPA), to accept power generated from qualifying renewable facilities (QFs). (The commission’s reduction in the eligibility cap does not waive regulated utilities’ PURPA requirement to buy energy from wind and solar projects up to 80 MW, but the rate paid to the projects between 100 kW and 80 MW is negotiated between the utility and the developer using the published rate as a starting point for negotiation. For now, projects under 100 kW qualify for the posted rate.)


PURPA was passed by Congress in 1978 to encourage development of renewable energy technologies as alternatives to burning fossil fuels or building new power plants. The act requires that electric utilities offer to buy power produced from QFs at rates determined by the states. The rate to be paid the QFs, called an avoided-cost rate, is to be equal to the cost the utility avoids if it would have had to generate the power itself or purchase it from another source.


The commission must ensure the avoided-cost rate is reasonable for utility customers because 100 percent of the price utilities pay QFs is included in customer rates.  


“The magnitude of standard wind QF project development in Idaho has reached monumental levels and the current avoided published cost levels will have a significant impact on the net power cost portion of its Idaho and other jurisdiction customer’s rates,” PacifiCorp claims. In fact, the utility claims that if it is required to pay the avoided-cost rate, it will cost $10 million more per year for these five projects than if a rate could have been negotiated or a bid process initiated. If the commission approves the agreement, PacifiCorp is requesting that the $10 million in annual incremental expense be assigned to Idaho customers and not to customers in its six-state territory. That is in accordance with an earlier agreement between the six states and the utility that states QF contracts exceeding costs the utility would have otherwise incurred acquiring comparable resources be assigned to the state approving the contract.


The commission published rate proposed for the projects is a non-levelized rate that increases through the life of the contract. In 2013, the agreement’s proposed rate for normal load hours during normal seasons of the year is $67.51 per megawatt-hour, escalating to $128.50 per MWh in 2032. The rate varies to account for heavy and light load hours of the day and heavy and light load seasons of the year.


PacifiCorp said it is concerned about the number and size of projects that are breaking down otherwise large projects into smaller projects to qualify for published, rather than negotiated, rates. “These proposed projects are not small family or community-based developers doing a single project, but rather large-scale, sophisticated developers with legal and technical assets who have disaggregated large projects into multiple projects…” the utility claims.


Cedar Creek Wind states it attempted to negotiate a contract with PacifiCorp but the model used by the utility calculated a rate that was 35 percent below the commission published rate rendering the project uneconomic. The developer also disputes the utility’s claim that adding the total 133 MW nameplate capacity of the five projects at a single connection point can create system operational and reliability issues. If PacifiCorp were to absorb an additional 350 MWs of Idaho-based wind nameplate generation into its system, it would amount to only about 3.5 percent of PacifiCorp’s projected system peak load in 2011, Cedar Creek claims.


The agreements state PacifiCorp can curtail generation from the projects when generation on PacifiCorp’s total system approaches minimum levels needed to serve customers and further acceptance of the wind would have a detrimental effect on the utility’s ability to simultaneously manage generation from other resources. 


The agreements also state that it is up to the wind developer to work with Idaho Power’s business delivery unit to ensure that interconnection facilities and transmission upgrades are completed in time to meet the projects’ scheduled operation date. If the projects fail to meet their delivery dates, delay damages will be assessed.


Comments are accepted via e-mail by accessing the commission’s homepage at and clicking on "Comments & Questions About a Case." Fill in the case numbers (PAC-E-11-01, -02, -03, -04 or -05) and enter your comments. Comments can also be mailed to P.O. Box 83720, Boise, ID 83720-0074 or faxed to (208) 334-3762.