961210.docx

DECISION MEMORANDUM
TO:COMMISSIONER NELSON
COMMISSIONER SMITH
COMMISSIONER HANSEN
MYRNA WALTERS
TONYA CLARK
DON HOWELL
STEPHANIE MILLER
DAVID SCHUNKE
RICK STERLING
TONY JONES
WAYNE HART
GARY RICHARDSON
WORKING FILE
FROM:SCOTT WOODBURY
DATE:DECEMBER 10, 1996
RE:CASE NO. IPC-E-95-8
1995 electric Integrated Resource Plan
On June 5, 1995, Idaho Power Company (Idaho Power; Company) filed its 1995 Electric Integrated Resource Plan (IRP) with the Idaho Public Utilities Commission (Commission).  The Company’s filing complies with the Commission’s direction in Order No. 22299 issued January 27, 1989 which requires Idaho Power to file a biennial resource management report (now IRP) describing the status of the Company’s electric resource planning.  A Notice of Filing in Case No. IPC-E-95-8 was issued by the Commission Secretary on June 21, 1995.
As a result of the Commission’s Order No. 25884 in Idaho Power Case No. IPC-E-93-28 the Company’s IRP is important and significant in the calculation of avoided costs for qualifying facilities greater than 1 megawatt (MW) in size pursuant to the Public Utility Regulatory Policies Act of 1978 (PURPA).  As an operative planning tool, the IRP also has significance for smaller QFs whose rates are published under the Surrogate Avoided Resource (SAR) methodology.
On July 17, 1995, Idaho Power filed an Application with the Commission in Case No. IPC-E-95-9 proposing an avoided cost IRP methodology, a proposed procedure and method for utilizing the Company’s IRP for calculating avoided costs.  Because of the generic implications of the filing, The Washington Water Power Company and PacifiCorp dba Utah Power & Light Company were made parties to the proceeding and interested parties were permitted to intervene.
On September 4, 1996, the Commission issued final Order No. 26576 in Case No. IPC-E-95-9 approving a Settlement Stipulation tendered by Staff and the utilities and deciding three unresolved issues.  The issues submitted for Commission resolution related to (1) the standard contract term over which QFs are entitled to receive the avoided cost rate [Commission Decision—five years], (2) whether levelized rates should be offered to QFs [Commission Decision—yes] and (3) whether PacifiCorp should be allowed to adjust the input data used in the Company’s IRP model to reduce PacifiCorp’s reserve margin from 12% to 10%. [Commission Decision—no—]  The Commission approved IRP methodology was found to more closely reflect the manner in which utilities acquire and price generation resources than did the use of a single, hypothetical power plant.
A Notice of Scheduling and Modified Procedure in Case No. IPC-E-95-8 was issued by the Commission Secretary on February 8, 1996.  Idaho Power was provided the opportunity to submit updated data and proposed changes to its 1995 IRP so as to facilitate and accommodate its use for calculation of avoided cost rates.  The Company made an additional filing on March 15, 1996.  The deadline for filing written comments or protests with respect to Idaho Power’s 1995 IRP was April 26, 1996.  The Commission Staff (Staff) and Rosebud Enterprises, Inc. were the only parties to file written comments.
Staff reviewed the Company’s 1995 IRP and recommends that it be accepted for filing.  Staff’s comments can be summarized as follows:
Regarding the Company’s Demand/Load Forecast Staff notes that a number of significant events in western Idaho have occurred since Idaho Power made the forecast, i.e., unforseen layoffs at Hewlett-Packard, restructuring (more layoffs) because of the West One merger, retrenchment at Micron Technology as a result of depressed chip prices, and problems at Morrison-Knudsen.
Regarding the Company’s reliance on DRI and perhaps other subscription services as a source of data, and because Idaho Power’s IRP will now be used to set avoided cost rates, Staff suggests that Idaho Power should provide a mechanism for public access and review of the data relied on.  Idaho Power in a May 9, 1996 response to Staff Comments states that to the extent permitted by licensing agreements, etc., the Company will continue to work with both forecasting services and the Commission Staff to allow access to forecast information as reasonably required.
To meet the forecast total load growth, resource additions totaling 369 average megawatts are included in the Company’s 20 year plan.  These additions are expected to be accomplished in a variety of ways, such as 30% (107 aMWh) from a combination of committed QFs, committed conservation, hydro upgrades, and efficiency improvements, 14% (51 aMWh) from market purchases, and 56% (202 aMWh) from thermal resources.
Regarding the Company’s proposal to satisfy part of forecast load growth with market purchases (51 aMWh), Staff notes that open market purchases of firm power as a means of supply and base-load is still a new and developing concept.  A variety of factors, including the degree to which deregulation occurs, and how soon, as well as the degree to which other utilities attempt to utilize market purchases, Staff contends, will have profound impact on the desirability of this action.  Idaho Power in response states that it has considerable experience in making substantial purchases and sales of firm power to supply loads.  Idaho Power fully intends to carefully monitor the developing availability of open market resources as a part of its least cost resource acquisition strategy.
Staff notes that the escalation rates used by Idaho Power for gas prices are nearly twice the rate of either general inflation or electricity prices.  Regarding gas price forecasts the Company in its response states that the range of uncertainty in gas prices was revised from 4.2%–6.25% in the March 19, 1995 draft IRP to 3.7%–6% in the final June 1995 IRP, with a base case gas price escalation rate of 4.35%.  The low end of the range was set to correspond to 0% real escalation.  The high end of the range, the Company states, was set equal to the gas price escalation assumed by the Commission and set in avoided cost rates for purchases from QFs smaller than 1 MW in Case No. IPC-E-93-28.  The Company states that it will carefully  monitor gas futures and other indicators of future gas prices for use in its next planning cycle.
Regarding gas-fired versus coal-fired resources the Company concludes that gas-fired generation is expected to be the more cost effective under both base case and low gas price assumptions.  The Company forecasts that neither however are needed in the near future.  Staff recommends and the Company agrees that advances in both technologies should continue to be monitored.
Staff notes that the Company’s 1995 IRP speaks very little of hydro relicensing.  Such relicensing, Staff contends, is an issue with tremendous consequence for both the Company and Idaho.  Staff expects this to be a substantial issue in subsequent IRPs.  The Company by way of response states that future review of both traditional utility-owned resources and open market purchases will need to take into consideration the evolving competitive market for electricity.
Regarding demand side management (DSM), the Company’s plans show expenditures for conservation declining rapidly from nearly $5 million in 1995 (less than 1% of gross revenues), to under $3 million in 1997-98 (less than one half of one percent of gross revenues), and only $239,000 (less 1/10 of one percent of gross revenues) in 2004 and beyond.  The decline in expenditures, Staff notes, is primarily related to a policy decision by the Company to increase the portion of resource costs that are paid by the customer, and decrease the portion paid by the Company.  By increasing the cost of participation for the customer, Staff contends that the Company is decreasing the penetration rate of the programs, and reducing the amount of DSM resources that will be purchased.  Staff voices concerns regarding the generally low levels of incentives the Company intends to provide, the use of the total resource cost test as the sole basis for including a resource in their screening process, and the fact that the differences between the options considered were so small that they exceeded the precision of the analysis methodology.  The Company addresses many of Staff’s DSM concerns in an April 1996 position paper entitled “A Sustainable Demand Side Management Policy in a Climate of Change.”
The Company expresses an interest in implementing a tariff rider or similar alternative to traditional financing for DSM measures.  Staff does not support the Company’s proposal given the decrease in Company DSM investment, and notes that the rider approved for Washington Water Power Company was associated with an investment for DSM programs that was equal to 1.5% of gross revenues.  Noting the changes occurring within the electric industry, Staff suggests and the Company agrees that the role and format of the IRP, as well as the Company’s Conservation Plan may need to be reexamined.
Staff contends that utility structures are changing and that utilities must adapt in order to remain competitive.  Staff sees the role of integrated resource planning changing significantly in the future as the industry changes.  New resource acquisition in the future, Staff suggests, will no longer consist primarily of company-owned generation or company-sponsored conservation.  New resources will likely include a much wider variety of choices.  Flexibility and the ability to quickly adapt to changes will become more important.  Risk management tools will become more valuable.
Regarding capacity reserves, Staff notes that prior to the Company’s 1995 IRP, IPCo’s capacity reserve consisted of a 6% planning reserve and a 6% operating reserve.  The 6% operating reserve has been retained, but the planning reserve has been reduced from 6% to 0.  Staff contends that it will extremely important to carefully monitor the available reserves in the future to insure that reliability is maintained and that customers are not jeopardized needlessly by the Company being forced to acquire very high priced resources to meet deficits.  Staff recommends that Idaho Power be required to periodically submit to the Commission information needed to track monthly capacity and energy reserve margins.
Noting that the IRP is to serve as an evaluation of all resource options, Staff reminds Idaho Power that company-owned resources are to be held to the same cost-effectiveness criteria as independently-owned resources.
Staff has reviewed the variables included in the Company’s IRP which are used in the calculation of avoided cost.  Staff believes that all of these variables fall within a reasonable range.
Rosebud in its comments contends that Idaho Power in its 1995 IRP makes numerous unrealistic assumptions for which the Company’s management and stockholder bear no apparent risk, i.e.:
•Natural gas prices
Unrealistic natural gas prices which do not recognize volatility, Rosebud contends, eliminates competition thereby justifying the need for future rate base plants when independent competitors are unable to build cheaper, non-rate based plants.  The IRP process and Commission approval, Rosebud contends, should guarantee Idaho Power’s ratepayers new resources at assumptions approved by the Commission.  Without such a guarantee to ratepayers, Rosebud contends that there is no incentive for Idaho Power to use the IRP process for other than the purpose of eliminating competition and building or purchasing solely rate based resources.
Rosebud notes that the Company’s IRP is totally silent on how and when during a two year process, the IRP planning process abandons high cost gas to permit other competitive alternatives from different generating technologies.
•Growth assumptions
Idaho Power continues, Rosebud contends, to hide the strong growth of load, which the utility has experienced since 1990, by artificially forecasting reductions in short-term power sales and relying on conservative growth assumptions which do not match actual Idaho Power reported growth.
•Elimination of independent resources
Rosebud notes that for purposes of determining resource need, the Company has assumed that it will not purchase the Cogeneration on Rosebud projects.  To the extent that the Company is ultimately required to purchase such resources, Rosebud contends that Idaho Power has exposed ratepayers to substantial risk of either purchasing unneeded resources, such as the Arizona purchase, or paying a higher price than otherwise required.
•Purchase of Arizona resources
Rosebud states that short-term (5 years) surplus purchases from rate base plants in other jurisdictions may be cheaper than building any project today, but contends that such purchases do not guarantee future stable rates.
By not building any new generation resource and relying on contract purchases, Rosebud contends that Idaho Power captures short-term benefits to shareholders which can only result in significantly higher rates in the future, as the Company’s growth continues to be at near record levels.  If the Company believes today that a need exists to purchases 105 MW of capacity for five years, Rosebud contends that its IRP should show after five years where the replacement resource will be acquired and assume the sole risk for future pricing at surplus rates justifying no new generation resource purchase today which otherwise locks in fuel and today’s construction costs.
By turning over the entire IRP process to Idaho Power’s management, Rosebud contends that the Commission has tacitly surrendered its responsibility to protect ratepayers from a monopoly.  If the Commission wishes to rely on the IRP maintained by Idaho Power for Commission policy determinations, Rosebud contends that the Commission is responsible to Idaho Power’s ratepayers that such IRP assumptions are in the ratepayers’ interest and not a tool to maximize Idaho Power’s shareholder returns.  Approving the IRP, Rosebud contends should not serve as a regulatory guarantee to Idaho Power for eliminating competition for non-Idaho Power projects and otherwise maximizing shareholder returns at ratepayers’ expense.
COMMISSION DECISION
Regarding IPCo 1995 electric Integrated Resource Plan
How does the Commission desire to handle the Company’s filing?
Acknowledge filing?  By letter or Minute Entry?
Re: Avoided cost implications
Re: QFs greater than 1 MW
Re: Staff recommendations
Public access and review of source data?
Continued role and format of IRP and Conservation Plan with restructuring of electric industry—initiate a docket to explore same?
DSM — shift away from grants/incentives
Tariff rider or similar alternatives to traditional financing of DSM measures
Hydro relicensing
Capacity reserves — reliability
Periodic informational filing (capacity/energy reserve margins)
Re:  Rosebud concerns
Is IRP being used as a tool to avoid utility purchases of non-utility resources?
Who should bear risk — ratepayers or shareholders/management?

Scott Woodbury
bls/M-ipce958.sw