Idaho Public Utilities Commission
Case No. GNR-E-11-01, Order No. 32262
June 8, 2011
Contact: Gene Fadness (208) 334-0339, 890-2712
Eligibility cap for wind, solar projects stays at 100 kW
17 proposed wind projects must now negotiate with utilities for rates
The Idaho Public Utilities Commission has determined to leave the eligibility cap under which wind and solar projects can qualify for commission published rates at 100 kilowatts, instead of the 10-megawatt cap in place up until Dec. 14, 2010. Wind developers have preferred to be paid the commission’s published rate by the utilities that buy output from them because the rate is typically more attractive than a rate they would have to otherwise negotiate with utilities.
As a result of the commission’s decision, developers of 12 Idaho Power Company wind projects and five Rocky Mountain Power projects whose contracts were executed after the Dec. 14 deadline will not be eligible for published rates. However, the wind projects could still be developed under a rate negotiated between the project developers and the utilities. (The projects are detailed below.) Ten Idaho Power wind projects that were submitted just before the deadline have already been approved by the commission.
The commission said that continuing to allow wind projects larger than 100 kW to be paid the published rate does not benefit ratepayers. “If we allow the current trend to continue, customers may be forced to pay for resources at an inflated rate and, potentially, before the energy is actually needed by the utility to serve its customers,” the commission said. “This is clearly not in the public interest.”
Idaho’s three major regulated electric utilities petitioned the commission last November to reduce the 10 average MW eligibility cap because of the rapid development of large-scale wind projects that were “disaggregating” – breaking themselves down into smaller 10 MW projects – in order to qualify for the published rate. The utilities claimed that the rapid increase in the number of wind applications was forcing them to buy power they did not need at rates that are not reasonable for customers.
When combined, these projects can total up to 100 or 150 MW interconnecting at one delivery point, the utilities claim. For example, Idaho Power claimed it had about 470 MW of wind power online at the end of 2010. The utility claimed that with commission approval of a number of proposed wind contracts, Idaho Power would have 1,100 MW of wind generation on its system in the near term, which exceeds the amount of power used in its total system on the lightest energy-use days.
At the time of the November filing, PacifiCorp (doing business in eastern Idaho as Rocky Mountain Power) said it had 64 MW of wind contracts executed and another 358 MW proposed. More than 300 MW of the proposed contracts were once large wind projects that were disaggregated into smaller 10 MW projects to meet the commission’s published rate criteria, Rocky Mountain Power claimed.
The magnitude of PURPA wind 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,” Rocky Mountain stated.
PURPA, the Public Utility Regulatory Policies Act, requires regulated utilities to buy power generated by small qualifying projects (QFs) at rates based on “avoided-cost” – the cost the purchasing utility avoids by not having to generate or buy from elsewhere the energy the PURPA project generates. The published rate paid developers in recent years does not truly represent “avoided-cost,” the utilities claimed.
In response to the utilities’ petition, the commission initiated a proceeding, which included a two-day technical hearing and participation by 22 parties, to attempt to find ways that wind and solar projects could obtain a published rate that more accurately reflects the actual value of the energy produced. (Solar projects, while not yet developed in Idaho, are included because the potential for them to disaggregate.)
Commission staff and other parties attempted to establish criteria that would allow the commission more discretion in determining whether a QF was truly a small project as anticipated by PURPA or a larger project that had disaggregated. The commission declined to adopt the criteria, maintaining that the potential would still remain for the criteria to be circumvented. “Furthermore, a 100 kW threshold for wind and solar QFs provides a certainty to the parties in negotiations that disaggregation criteria would not,” the commission said.
While leaving the 100 kW cap in place, the commission is initiating another proceeding to investigate the methodology used to calculate the avoided-cost rate. “We believe it is more appropriate to first establish the just and reasonable avoided-cost rates before we implement procedures for obtaining the rate,” the commission said.
“While we recognize the impact that this decision will have on small wind and solar projects, it would be erroneous, and illegal pursuant to PURPA, for this commission to allow large projects to obtain a rate that is not an accurate reflection of the utility’s avoided cost for the purchase of QF generation,” the commission said.
The Northwest and Intermountain Power Producers Coalition argued that the 10 average MW cap has worked “remarkably well for Idaho.”
“We fundamentally think that it is unfortunate that the three utilities initiated this docket at all,” NIPPC said. “We believe that this docket has been an unnecessary exercise and that is because the system is not broken and, hence, it does not need to be fixed.”
The commission directed that the parties meet within 30 days to identify issues and establish a schedule for the commission’s inquiry into the avoided-cost methodology.
While the published rate is no longer available to the 17 wind projects, developers have the option of negotiating with utilities for a rate using the utilities’ Integrated Resource Planning (IRP) process. The IRP methodology, updated every two years, 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.
Below is a summary of the wind projects impacted by the commission’s decision to retain the 100 kW cap for projects submitted after Dec. 14.
Case Nos. IPC-E-10-51, -52, -53, -54 and -55; Order No. 32254
The five projects were proposed near Burley by Cotterel WindEnergy Center LLC, which is owned by Shell. Cotterel 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.
“From the commission’s perspective, a thorough review is appropriate and necessary prior to signing agreements that obligate ratepayers to payments in excess of $700 million over the 20-year term of these agreements,” the commission stated. “Indeed the commission has directed the utilities to assist the commission in its gatekeeper role when reviewing QF contracts.”
Case Nos. IPC-E-10-56, -57 and -58, Order No. 32255
Murphy Flat Mesa, Murphy Flat Energy and Murphy Flat Wind, developed by Brian Jackson of American Wind LLC, were each proposed to deliver up to 10 average MWs for 20 years with a targeted operation date of Dec. 31, 2012. Under the commission’s published rate, annual energy payments by Idaho Power for the expected generation would have been about $10.3 million in 2013, increasing to $20.2 million in 2032, or a total of $299 million over the 20-year term.
American Wind claimed the agreements were executed before the change in the eligibility cap. The commission does not consider a utility and its ratepayers obligated until both parties have completed their final reviews and signed the agreements, which, in this case, was Dec. 15. Further, American Wind stated that the federal government has “created special incentives for wind projects,” to stimulate jobs and support the national manufacturing industry. American Wind maintained the wind projects provide meaningful jobs and significant tax benefits. The three projects “are good for the future energy mix of the ratepayers of Idaho and they are good for the local economy and energy security of Idaho and the nation.”
However, the commission noted that the Idaho Supreme Court in the 1996 Rosebud Enterprises v. Idaho Power Co. decision, recognized that “a balance must be struck between the local public interest of a utility’s electric consumers and the national public interest in development of alternative energy sources.”
The commission’s primary responsibility is to ensure that the electric utilities it regulates deliver adequate and reliable energy at rates that are just and reasonable. “From the commission’s perspective, a thorough review is appropriate and necessary prior to signing agreements that obligate ratepayers to payments of nearly $300 million over the 20-year term of these agreements,” the commission stated.
Rainbow Ranch projects
Case Nos. IPC-E-10-59 and -60, Order No. 32256
These projects, near Declo, were also proposed by Jackson of American Wind LLC with a proposed operation date of Dec. 31, 2012.
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.
Grouse Creek projects
Case Nos. IPC-E-10-61 and -61, Order No. 32257
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
Case Nos. PAC-E-11-01, -02, -03, -04 and -05
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.
Cedar Creek claims that the five agreements were mature contracts with a meeting of the minds between the parties before the Dec. 14 deadline. Cedar Creeks claims that the commission staff’s “absolute cut-off date” is a misreading of a commission order and contrary to the law under PURPA.
A full text of the commission’s orders for all 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 above case numbers.
Interested parties may petition the commission for reconsideration by no later than June 29. Petitions for reconsideration must set forth specifically why the petitioner contends that the order is unreasonable, unlawful or erroneous. Petitions should include a statement of the nature and quantity of evidence the petitioner will offer if reconsideration is granted.
Petitions can be delivered to the commission at 472 W. Washington St. in Boise, mailed to P.O. Box 83720, Boise, ID, 83720-0074, or faxed to 208-334-3762.