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Home My WebLink About28542.docBEFORE THE IDAHO PUBLIC UTILITIES COMMISSION IN THE MATTER OF THE FILING BY AVISTA CORPORATION DBA AVISTA UTILITIES(WASHINGTON WATER POWER DIVISION OF AN UPDATE TO AVISTA’S 1997 ELECTRIC INTEGRATED RESOURCE PLAN (IRP) AND DRAFT REQUEST FOR PROPOSALS (RFP). )) )))) ) CASE NO. AVU-E-00-8 ORDER NO. 28542 On July 13, 2000, Avista Corporation dba Avista Utilities—Washington Water Power Division—Idaho (Avista; Company) filed an update to its 1997 Integrated Resource Plan (IRP) and a draft Request For Proposals (RFP) with the Idaho Public Utilities Commission (Commission). The RFP is an “all source” competitive bid based on the Company’s identified need for 300 MW of new electric power starting in 2004. The IRP update describes the Company’s loads and resources, overview of technically available resource options, and demonstrated need for resources. The Company in its filing states that it will consider any offer of resources including but not limited to, energy and capacity, energy efficiency, turnkey plans, construction—for Avista—of a generating plant on a site provided by the bidder, and construction by a bidder on a site furnished by Avista. As described in the RFP and IRP update, the Company’s resource need suggests that customers would benefit by a new resource with operational flexibility. The Company states that it is also examining other options for service provision including expanded use of customer load interruptibility agreements and time of use rates. Based on informal conversations with Avista, the Commission is apprised that the Company’s intention is to issue its RFP by August 24, 2000, and to file its 2000 electric Integrated Resource Plan later this year. The Company solicits comments on its filings from the Commission, the Commission Staff and the public. On July 21, 2000, the Commission issued a Notice of Filing in Case No. AVUE008 and established an August 11, deadline for the filing of written comments. The Commission Staff was the only party to file comments. As reflected in Staff comments, Avista’s updated 1997 IRP serves as a basis for the planned RFP. Staff notes that by prior Commission Order No. 22299, electric utilities are required to submit IRPs every two years. The Company in 1998 requested and by Commission Order No. 27636 issued July 23, 1998, the Commission granted Avista a one-year extension of its 1999 IRP filing requirement to August 2000. The Company’s updated load forecast was prepared in the summer of 1999. The electric energy forecast shows an annual average load of 1,013 aMW in 2001 increasing to 1159 aMW in 2009. The peak forecast shows 1,594 MW in 2001 with 1851 MW in the year 2009. The sale of the Centralia coal-fired plant, Staff notes, resulted in a loss of 201 MW of capacity and 177 aMW of annual energy from Avista’s resource portfolio. A short-term contract to replace the majority of lost generation started in July 2000 and extends through December 2003. Most of Avista’s existing purchase and sales agreements terminate by the year 2003. In examining the Company’s load-resource balance, Staff notes that the deficits appearing throughout the planning horizon are the same general magnitude as the purchase contracts which are expiring. Avista does not believe that its expiring contracts can be renewed or replaced by similar contracts. The Company does not believe that the need to acquire new resources can be eliminated by future contract purchases. The new load-resource balance for Avista shows that the Company is deficit, both for energy and capacity, beginning now and extending through the entire planning horizon. Deficits in 2000 are 395 MW of peak capacity and 237 aMW of energy. Deficits dropped to a low of 30 MW peak capacity and 149 aMW of energy in 2003 primarily due to the expiration of sales contracts. However, they quickly increase again to 430 MW of peak capacity and 370 aMW of energy in 2006, because of the ending of the contract hydro from the mid-Columbia PUD projects (Priest Rapids and Upper Wanapum). Avista is hopeful that contract extensions can be negotiated, but cannot include these resources in its planning without certainty of the contracts. Staff notes that Avista’s IRP includes both operating and planning reserves. Operating reserves are 5% of hydro generation and 7% of thermal generation, which are amounts required by the Western Systems Coordinating Council. Planning reserves are also included to account for cold weather, generator-forced outages and contingencies such as river freeze-up at hydroelectric plants. This provides the Company with about 15% reserves based on forecasted peak loads. Besides examining a simple load-resource balance, Staff states that Avista also performed extensive hourly modeling of its existing loads and resources. Both critical and normal hydro conditions were examined. New resources are expected to have an impact on the resource dispatch sequence because of the fuel supply and marginal cost. Both Staff and the Company recognize that natural gas prices are critical in a “buy or build” decision, and that future prices for new electric generation will be heavily influenced by the cost of gas. Avista forecasted electricity prices using a method that bases the price of electricity on forecasted gas prices and electric generation efficiencies using gas as fuel. The Company’s 1997 updated IRP identifies several resource options. Some of the options that the Company has discussed and that are under consideration are the following: Build a generating resource Purchase existing or new generation assets Complete system upgrades at generating facilities Negotiate a long-term power purchase agreement Buy in the short-term wholesale market Purchase the output of a generating or cogeneration facility Develop additional energy efficiency and demand side management (DSM) programs Buy energy efficiency through third-party developers Customer load shedding is also being considered, although it is not generally considered a firm resource. Retail load that can be interrupted or curtailed under specific circumstances can free-up temporary capacity and energy. The Company plans to explore those possibilities through contract negotiations through large customers. Avista reports that it is constantly assessing the markets in order to buy and sell power on an hourly and daily basis. Most marketers and utilities, however, do not want to commit to long-term sales due to uncertainty in the markets. Avista states that it needs a resource that can provide additional benefits in support of the existing generation system. What is needed, the Company states, is a resource that can be dispatched, follow load, and provides a capacity component. Avista points out that a natural gas fired electric generation plant is one example of a resource that could meet the Company’s needs. The Northwest Planning Council projects costs for natural gas-fired projects ranging from 41 to 43 mills. The Company reports that at this point in time the following resources will not pass the initial screening. The following costs are nominal life-cycle, levelized costs. Nuclear: Costs are over the 100 mills per kilowatt-hour range. The total cost and the lack of public acceptance make this resource option unacceptable. Coal: Costs are 80 to 90 mills. The total cost and cost uncertainty in air quality issues make this resource option unacceptable. Wind: Costs are 60 to 80 mills. There are indications that costs are declining but Avista studies show there are no favorable sites in its service territory so transmission costs would have to be added. Because wind is intermittent, the resource would also have to be discounted for lack of capacity component. This would make this resource option unacceptable. Geothermal: Costs are 80 to 100 mills making this resource option unacceptable. Solar: Costs are over 240 mills making this resource option unacceptable. While the Company’s preliminary screening is helpful in making general comparisons between various alternatives, Staff believes that the true test of whether they are viable will come once Avista receives and evaluates responses to its RFP. Although proposals for new generation may seem most likely, Staff believes the RFP should encourage innovation and creativity. Staff believes that DSM renewables, distributed generation, load management, voluntary curtailment and various other alternatives should be eligible to bid under the RFP and that should they be bid that they be fairly compared against new generation as well as against each other. All of Staff’s recommendations, both written and verbal, were addressed by the Company in a preparation of the final draft of the RFP. Staff, after thoroughly reviewing the Company’s updated 1997 IRP, believes that the release of the RFP seeking proposals for up to 300 MW of new power in 2004 is an appropriate action. Staff recommends that the filings of record and comments in Case No. AVU-E-00-8 be acknowledged and that the docket be closed. Staff apprises the Commission that the Company’s deadline for submitting proposals in response to its RFP was September 18, 2000. The Company received 32 proposals from 23 different parties. A total of 2900 MW were bid in response to the Company’s request for 300 MW. Avista plans to determine a preliminary short list by October 6, select a short list for negotiation by October 24, and make a final selection by November 3. The Company also plans to submit a final evaluation report to the Commission by January 15, 2001. COMMISSION FINDINGS The Commission notes that the Company’s filings in Case No. AVU-E-00-8 were informational and were not required by statute or Commission Order. The Company solicited only comment. Approval therefore is not necessary. The Company is commended for soliciting public input into its RFP process. The comment period having expired, the Commission finds it reasonable to close the docket in this case. O R D E R In consideration of the foregoing and as more particularly described above, IT IS HEREBY ORDERED and the Commission does hereby close the docket in Case No. AVU-E-00-8. THIS IS A FINAL ORDER. Any person interested in this Order may petition for reconsideration within twenty-one (21) days of the service date of this Order. Within seven (7) days after any person has petitioned for reconsideration, any other person may cross-petition for reconsideration. See Idaho Code § 61-626. DONE by Order of the Idaho Public Utilities Commission at Boise, Idaho this day of October 2000. DENNIS S. HANSEN, PRESIDENT MARSHA H. SMITH, COMMISSIONER PAUL KJELLANDER, COMMISSIONER ATTEST: Jean D. Jewell Commission Secretary vld/O:AVU-E-00-8_sw ORDER NO. 28542 1 Office of the Secretary Service Date October 10, 2000