GALE TESTIMONY.doc

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF IDAHO POWER )
COMPANY'S INTERIM AND PROSPECTIVE, )
HEDGING RESOURCE PLANNING, ) CASE NO. IPC-E-01-16
TRANSACTION PRICING, AND IDACORP )
ENERGY SERVICES (IES) AGREEMENT )
)

IDAHO POWER COMPANY

DIRECT TESTIMONY

OF

JOHN R. GALE

Q. Please state your name and business address.
A. My name is John R. Gale and my business address is 1221 West Idaho Street, Boise, Idaho.
Q. By whom are you employed and in what capacity?
A. I am employed by Idaho Power Company; as the Vice President of Regulatory Affairs.
Q. Please describe your work experience.
A. In October 1983, I accepted a position as Rate Analyst with Idaho Power Company. In March 1990, I was assigned to the Company’s Meridian District Office for one year where I held the position of Meridian Manager. In March 1991, I was promoted to Manager of Rates. In July 1997, I was named General Manager of Pricing and Regulatory Services. In March of 2001, I was promoted to Vice President of Regulatory Affairs. As Vice President of Regulatory Affairs, I am responsible for the overall coordination and direction of the department, including development of jurisdictional revenue requirements and class cost-of-service studies, preparation of rate design analyses, and administration of tariffs and customer contracts. In my current position, I am actively involved with restructuring activities throughout our service territory.
Q. What is the purpose of your testimony in this proceeding?
A. I will address the Commission's desire to more fully review the manner in which Idaho Power Company (“Idaho Power” or “the Company”) and IDACORP Energy Solutions, LP (“IES”) can conduct business for the benefit of Idaho Power's customers on both an interim and prospective basis. Additionally, I will speak to Idaho Power’s approach to providing resources to meet system loads during the near-term time period.
Q. Please summarize Idaho Power Company’s recommendation for the interim rules governing transactions between Idaho Power Company and IES.
A. Until such time as the Idaho Public Utilities Commission (“IPUC” or "Commission") makes a final determination that the existing rules should be changed, Idaho Power believes that the rules governing the conduct of transactions between Idaho Power and IES (including transfer prices) should be the same rules accepted by the Commission in Order No. 28596 issued in Case No. IPC-E-00-13. Idaho Power believes this approach is consistent with prior Commission decisions requiring that practices and rules adopted by the Commission remain in effect until changed by subsequent IPUC order.
The Agreement may need to be modified slightly to comply with the final order of the Federal Energy Regulatory Commission (“FERC”) approving the Electricity Supply Management Services Agreement (“the Agreement”) that was the subject of IPUC Order No. 28596. When the final order is received from FERC, if it is acceptable to Idaho Power, it will be filed with the IPUC. If any changes to the existing rules are necessitated by the FERC order, Idaho Power will make a filing to obtain Commission approval for such change.
Q. Please summarize the principals that Idaho Power believes should underlie the rules governing transactions between Idaho Power Company and IES.
A. The rules governing transactions between Idaho Power and IES should be designed to achieve (1) alignment of risk and reward, (2) sharing of the economic and market knowledge benefits of one trading operation, (3) protection against affiliate abuse, and (4) energy transfers at visible, verifiable market prices. I believe that a reasonable period of operating experience will demonstrate that the existing Electricity Supply Management Services Agreement between Idaho Power and IES will meet these criteria. A copy of the Agreement is included as Exhibit 1 to my testimony.
Q. Please describe the existing Electricity Supply Management Services Agreement.
A. Under the business arrangement memorialized in the Electricity Supply Management Services Agreement submitted to the FERC, the IPUC, and the Oregon Public Utility Commission ("OPUC"), IES will purchase surplus power from Idaho Power on a daily and real-time basis, and will make daily and real-time sales of electricity to Idaho Power to meet native load needs. All wholesale transactions between Idaho Power and IES will be at market prices. The Agreement also provides for IES to serve as a broker for Idaho Power transactions, which will be performed on a non-exclusive basis.
Q. Why did Idaho Power and IES develop the Agreement?
A. Idaho Power and IES developed the Agreement to respond to changes in the competitive wholesale electricity market and concerns expressed by Idaho Power's customers regarding the allocation of costs between operating and non-operating transactions in that market. Idaho Power’s goal is to prudently and cost-effectively participate in the wholesale electricity market for the benefit of the Company's retail customers. Idaho Power believes that there are significant cost savings and market risk mitigation benefits that are realized by contracting with IES to provide electricity marketing and other electricity supply management services to Idaho Power. The Agreement benefits Idaho Power’s customers by protecting them from the risk of speculative transactions while at the same time lowering Idaho Power’s administrative costs of participating in the market. Pursuant to a stipulation previously approved by the IPUC, Idaho Power will flow back $2,000,000 per year to reflect these estimated cost savings once the Agreement is approved by all appropriate regulatory authorities. The Agreement also enables Idaho Power, through advice given by IES, to apply greater expertise in the wholesale market, resulting in better optimization between cost and risk for customers.
This arrangement will protect Idaho Power’s retail customers from practices that FERC has characterized as "affiliate abuse". All transactions between Idaho Power and IES will be priced at market, as determined by published market indexes (daily transactions) or transactions with non-affiliates (real-time transactions). These market prices are not subject to manipulation by Idaho Power or IES. Real-time transactions are transactions up to 12 hours in duration (usually hourly transactions), while daily transactions are 24-hour transactions (usually next day transactions). Longer-term transactions may be brokered by IES or entered into directly with third parties by Idaho Power.
Q. Please describe the circumstances leading up to the Power Supply Management Agreement between Idaho Power and IES.
A. The Agreement is the outgrowth of a number of events that Idaho Power has experienced in its wholesale marketing activities coupled with the risks associated with Idaho Power’s unique generation resource supply mix. One of the unique characteristics of Idaho Power is its heavy reliance on hydro-based generation.
Q. Why is the Company’s hydro-based generation a factor in the evolution of the Agreement?
A. At one time, virtually all Idaho Power generation came from hydroelectric facilities on the Snake River. Because of the variations in streamflow conditions from year-to-year, the Company became active in the Northwest energy markets, buying from others during low water years and during the low streamflow periods within individual years, while selling its surplus power during periods when water was abundant.
Over the years, the Company added some thermal (coal-fired) plants, through joint ownership, to complement the hydro facilities. Nevertheless, in a normal water year hydro facilities still produce more than 60% of the generation on the Idaho Power system. Idaho Power continues to buy and sell in short-term markets to balance the system’s loads and resources. During the summer months, Idaho Power has relied and planned on short-term power purchases, rather than installing new generation, to serve the peak system loads. While this approach has been viewed as a long-term, least-cost solution, there is an added element of near-term risk that Idaho Power faces as an active participant in the wholesale market that many other utilities do not face.
As a hydro-based utility, Idaho Power is unique in its exposure to supply risk associated with its reliance on generation with an inherently unpredictable fuel source -- water. All electric utility companies (including Idaho Power) face volume risks associated with economic conditions and weather fluctuations. Loads can go up and down based upon a robust or sluggish economy. Furthermore, extreme temperatures can affect the load volume as well. For hydro utilities, there is an extra element of supply risk that the utility must manage. The additional risk is the uncertainty of the amount of generation available to meet load. Water storage is severely limited due to reservoir constraints. When the water is not available, there is no fuel to run the hydro plant. The fuel availability is an important distinction in comparing predominately hydro-based utilities and predominately thermal-based utilities. This supply risk introduces an added element of uncertainty for Idaho Power as a wholesale market participant.
Idaho Power’s hydro resources provide positive economic impacts to the utility and its customers because these plants operate with virtually a zero fuel cost. Under normal conditions, the total system generation cost for Idaho Power is among the very lowest for investor-owned utilities in the United States. As purchased power costs become more volatile, they become more important to the overall power supply costs of Idaho Power. The Company wants to protect its overall low cost status from the adverse impacts of high purchased power costs. By sheltering Idaho Power Company from the more speculative market transactions, the Agreement is designed to reduce the risks that Idaho Power faces as a wholesale market participant to help ensure that purchased power expenses do not upset Idaho Power’s favorable cost situation, to the detriment of Idaho Power’s retail customers.
Q. Please describe the emergence and growth of the Company’s trading activities.
A. The size and complexity of the wholesale markets for electricity have increased dramatically in the past few years, as has Idaho Power’s participation in those markets. In addition, the IPUC has approved a method to change Idaho Power’s rates that encourages Idaho Power to reduce wholesale power purchase costs for its retail customers.
In Idaho, prior to 1993, Idaho Power sold power to retail customers at fixed capacity and energy charges (that is, charges that were subject to adjustment in rate proceedings, but not through the operation of a fuel adjustment clause or similar provision). In 1993, following several years of drought conditions in which Idaho Power’s purchased power expenses substantially exceeded expectations, the IPUC approved Idaho Power’s request to add a Power Cost Adjustment (“PCA”) to the Company’s Idaho retail rate structure. The IPUC and the Company’s Idaho retail customers favored this arrangement because it enabled those customers to receive the benefit of more favorable water conditions in the form of reduced rates. With the implementation of the PCA, Idaho Power’s shareholders’ and customers’ interests became aligned, because they both shared in the savings and costs from operating transactions.
Historically, Idaho Power’s wholesale transactions primarily involved sales of Idaho Power resources that were temporarily surplus to Idaho Power’s retail customers’ needs, and purchases of generation needed to meet Idaho Power’s retail customers’ needs. Idaho Power refers to such purchases and sales as “operating” transactions. Then, in the mid-1990’s, as the wholesale power market continued its rapid expansion, Idaho Power identified increasing opportunities to engage in more speculative off-system transactions that were unrelated to the Company’s system resources. Idaho Power refers to such purchases and sales as “non-operating” transactions. In 1998, the Emerging Issues Task Force ("EITF") of the Financial Accounting Standards Board ("FASB") issued EITF98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities. EITF98-10 became effective for all fiscal quarters beginning with fiscal years that started after December 15, 1998. Idaho Power’s simultaneous participation in operating and non-operating transactions, along with the establishment of accounting and reporting standards for energy trading contracts by the Emerging Issues Task Force of the Financial Accounting Standards Board created the need for Idaho Power to separate the transactions for accounting and ratemaking purposes. Idaho Power adopted these standards on January 1, 1999.
Q. What was the accounting and ratemaking result of adopting these standards?
A. Since January 1, 1999, transactions related to balancing of system load and system resources and transactions related to system reliability are classified as “operating” and remain on settlement accounting. These transactions are recorded and maintained in an “operating” trading book that is separated from other trading transactions. Operating transactions meet the “energy contracts” definition of the Emerging Issues Task Force consensus opinion because they are expected to settle physically. Operating transactions continue to be booked in FERC Accounts 447 or 555 and are thus included for PCA reporting purposes.
Transactions not related to the balancing of the system load and resources are classified as “non-operating” or energy trading contracts and are required to be accounted for using mark-to-market, or fair value accounting. These transactions are maintained in “non-operating” trading books that are differentiated from one another by time periods; i.e., transactions that settle outside the “prompt” month, transactions that settle within the prompt month or sooner, and daily or real time transactions. The prompt month is the month following the current month. Non-operating transactions meet the “energy trading contracts” definition of the Emerging Issues Task Force consensus opinion and beginning in January 1, 1999 have been booked in FERC Account 421 and are thus excluded for PCA reporting purposes.
Purchases or sales are typically classified as operating or non-operating at the time of the transaction. As transactions close in real time, the operating system book needs to balance against the physical requirements of the loads and resources. Beginning one month prior to scheduled settlement, transactions between the operating and non-operating books occur at the appropriate market settlement price in order to start bringing the system into balance.
In Idaho Power’s 1999-2000 PCA case (Case No. IPC-E-99-3), some of Idaho Power’s larger customers expressed concern regarding Idaho Power’s operating and non-operating transactions and whether Idaho Power’s expenses and capital costs were being properly allocated between operating and non-operating transactions. In response to these concerns, the IPUC issued Order No. 28049 directing the parties to determine how best to address the issues raised by the customers. Subsequently, on February 14, 2000, the IPUC Commission Staff filed a report addressing some of the issues raised by the customers in the 1999-2000 PCA case. The IPUC acknowledged receipt of that report in Idaho Power’s 2000-2001 PCA case and encouraged the parties to address the issues further.
In further response to the concerns expressed in the above-cited cases, Idaho Power is moving its non-operating transactions into a separate entity. IES has been chosen as that entity. IES rents office space from someone other than Idaho Power, has its own employees, and is managed and operated independently from Idaho Power. Moving non-operating transactions to IES will substantially reduce the levels of support services currently provided by Idaho Power and will provide a clearer line of demarcation between the operating and non-operating electric marketing businesses of IDACORP, Inc. Upon final implementation of the Agreement, Idaho Power as an entity, will no longer participate in non-operating transactions, and the more speculative transactions that are currently non-operating transactions will be undertaken exclusively by a separate corporate entity, IES. Idaho Power adopted this structure to meet the concerns expressed by Idaho Power’s customers and the IPUC in the 1998-1999, 1999-2000, and 2000-2001 PCA cases.
Q. How is the wholesale electric market of today different from the one of yesteryear?
A. The wholesale market is becoming more complex. The decreased regulatory oversight and the increased volume of wholesale transactions between suppliers, marketers and consumers of bulk electricity has created an increasing demand for market participants to maintain a high level of market intelligence and understanding of market movements. The increasing availability of sophisticated financial instruments for managing price volatility risk for electricity transactions has further stimulated the burgeoning wholesale market for electricity. Regardless of the status of restructuring of the retail electric utility industry in the state of Idaho, this expanding wholesale market will continue to significantly affect the way Idaho Power operates in this changing environment.
While the expanding wholesale market has the potential to provide opportunities for increased price efficiency resulting from a larger and more diverse group of market participants and products, there are certainly greater costs and risks associated with managing power supplies within this new environment. The Agreement addresses these concerns by increasing Idaho Power’s access to expertise in the wholesale market, while protecting Idaho Power’s retail customers from speculative trading risks. Idaho Power believes that there are significant cost savings and market risk mitigation benefits that can be realized by this arrangement, which I describe in greater detail later in my testimony.
Q. What functions or activities are remaining with Idaho Power?
A. The Agreement alters the manner in which Idaho Power will transact in the wholesale market, but does not alter Idaho Power’s generation and reliability obligations. Under the Agreement, Idaho Power continues to own, operate and maintain its system resources and be responsible for system reliability. Idaho Power continues to dispatch system resources to match generation and load within the Idaho Power control area. The Agreement does not modify Idaho Power’s commitment or ability to manage and control its system resources in a manner that will provide Idaho Power’s customers with access to all available capacity and energy from Idaho Power’s system resources on a first-priority basis. Idaho Power will comply with its FERC-approved Code of Conduct in providing any non-power goods and services to IES, as well as any additional requirements governing transactions between affiliates that the state commissions may find to be appropriate.
Q. What functions are moving to IES?
A. Under the Agreement, IES provides wholesale marketing services to Idaho Power. IES and Idaho Power enter into daily and real-time purchases and sales, and IES serves as a non-exclusive broker for longer-term transactions (such transactions are entered into directly with third parties). Transactions between the two entities occur only when Idaho Power determines that such transactions would be beneficial for Idaho Power and its customers. This arrangement enables Idaho Power to balance its system load and resources. In addition, IES buys power from Idaho Power at market prices when Idaho Power determines that Idaho Power has surplus power for sale and that such sales would be beneficial to Idaho Power and its customers. All of the transactions between Idaho Power and IES are at market prices established in a manner that prevents either entity from benefiting at the expense of the other. IES obtains the transmission and ancillary services that are necessary to deliver Idaho Power’s purchases and sales to the agreed-upon destination. IES advises Idaho Power regarding desirable transactions to enter into, and serves as a non-exclusive broker for purchases and sales with a duration that exceeds one day. IES complies with the FERC’s Code of Conduct for its brokering activities.
In addition to the power purchases and sales described previously, the Agreement states that IES will provide Idaho Power various other non-power goods and services. IES advises Idaho Power regarding scheduling, hedging transactions, and risk management activities to minimize price volatility, among other things. In this role, IES among other things, confirms purchases and sales, administers market-based contracts, and coordinates scheduling of energy transactions in adherence with transaction protocols. IES also provides finance and accounting support and counter-party credit analysis for power marketing activities. Credit analysis has become an increasingly important activity for wholesale market participants, and requires the application of substantial expertise and resources to be done effectively. Idaho Power complies with the FERC’s Code of Conduct and the Statement of Policy and Code of Conduct accepted by the IPUC on an interim basis in Order No. 28596 in purchasing these and other non-power goods and services from IES.
Q. How do Idaho Power’s customers benefit under the Agreement with IES?
A. By entering into the Agreement with IES, Idaho Power believes that it will be able to lower its expenses, streamline staffing requirements, reduce the risks associated with power market volatility, and maintain its existing high level of system operating efficiency and reliability. These results will benefit Idaho Power’s retail customers.
Possibly the greatest benefit to Idaho Power’s customers, and one of the central reasons why Idaho Power developed this proposal, is the realignment of risk and reward under the proposed organization. Recent events have demonstrated that today’s more volatile energy markets can present significant risks for utilities and potentially for their customers. Under the Agreement, speculative transactions will be performed by IES for its own account rather than by Idaho Power. This assigns to IES, rather than to Idaho Power, the potential risks and rewards from these transactions. This arrangement benefits Idaho Power’s retail customers, because they are sheltered from the speculative market transactions of the affiliate IES. In addition, safeguards are being established to prevent speculation on behalf of the utility. System transactions will be directed toward balancing loads and resources while considering cost, reliability and risk. Idaho Power’s Oversight Manager will approve system transactions. The Oversight Manger’s decisions will be reviewed by the Corporate Risk Management Committee and subject to at least annual review by the IPUC Staff.
While retail customers lose the potential rewards of speculative transactions under this arrangement, this is more than offset by the reduction in risk from these transactions. As previously mentioned, Idaho Power has some of the lowest retail rates in the Nation, but experiences unique risks in participating in the wholesale electricity market. By protecting retail customers from the additional risks of speculative transactions, Idaho Power can better ensure that its purchased power expenses can be managed while maintaining a favorable rate environment for its customers.
Retail customers will enjoy the benefits of the market expertise that a full scale trading operation has to offer. The benefit manifests itself in the market advice that can be offered in developing the operating plans for the system and in the recommendations regarding potential system hedging transactions on behalf of the system. IES will be operating in virtually all of the Western markets for virtually all time frames. All of the market information gleaned during those operations will be available to Idaho Power for decision-making purposes. In addition, Idaho Power will obtain increased access to people familiar with sophisticated financial instruments intended to reduce risk and mitigate price volatility.
IES will assist Idaho Power in managing its system resources in an optimum manner. Dispatch decisions can be made using the best available market information. The information assists day-to-day operations, as well as longer-term decisions related to scheduled maintenance, river operations, and customer program coordination.
Customers further will benefit from the clearer separation of the non-power costs between Idaho Power and IES through organizational and reporting changes as well as the physical location move. Allocations will be replaced with verifiable direct cost assignments. These direct cost assignments will be in compliance with applicable IPUC and FERC Code of Conduct requirements.
Finally, Idaho Power’s customers will benefit from overall reduced costs that will flow through directly into jurisdictional revenue requirement determinations. The cost reduction is attributable to the ability to serve two entities with one trading operation instead of two. Both entities benefit by sharing the costs instead of replicating the corresponding organization and costs within each. As discussed above, Idaho Power has agreed to flow through to its Idaho retail customers $2,000,000/year in cost savings once the Agreement is approved by the necessary regulatory authorities, allowing these cost savings to occur.
Q. What protections are in place to prevent affiliate abuse?
A. Idaho Power recognizes that the IPUC and interested retail customers are concerned that inter-affiliate transactions do not create the opportunity for those affiliates to shift benefits from utility customers to shareholders. The Agreement recognizes and addresses these affiliate abuse concerns and includes measures that prevent affiliate abuse from occurring.
The market price to which Idaho Power and IES will tie the transaction price is an objective standard for the pricing of electricity that is not subject to manipulation by Idaho Power or IES.
For daily transactions, the market price will be determined based on published market indexes. The Agreement specifically references the Dow Jones Mid-Columbia Electricity Price Index (“Mid-C”) and the Dow Jones Palo Verde Price Index (“PV”). The Mid-C and PV Indexes are reliable and verifiable sources indicative of the prevailing market price, and are appropriate Indexes to use to determine the market price for daily electricity transactions. Mid-C and PV are two of the three major cash markets in the west. Mid-C is an active trading hub, with trading volumes comparable to those at PV. The Mid-C Index is widely used for indexed wholesale and retail transactions. For example, Idaho Power references the Mid-C Index for several of its retail contracts and tariffs, including non-firm prices for purchases from Qualifying Facilities. Exhibits 2 and 3 explain the Mid-C and PV Index categories that Dow Jones publishes, and the methodology that Dow Jones uses to calculate these indexes. As shown in that discussion, both the indexes and methodologies are comparable. For both indexes, prices are published daily based on actual transactions.
For real-time transactions, Idaho Power will determine the market price based on the weighted average of the real-time prices at which IES bought and sold power to non-affiliates. The average of these transactions is indicative of the market price at the time, and its use provides appropriate protection against affiliate abuse.
All energy transactions (buy or sell) that are not real-time or daily will be bilateral agreements with third parties and may be or may not be brokered by IES.
Q. Please provide an example to illustrate the transfer pricing in use.
A. If Idaho Power desired to purchase or sell power in June 2002 for the month of July 2002 (e.g., to meet expected peak loads), it would enter into a transaction directly with a third party or parties, or use IES’ brokering services to arrange such a third party transaction if warranted. If, during July 2002, Idaho Power desired to enter into a transaction for a particular day (e.g., to meet a sudden load increase due to hot weather), it would transact with IES, and the price for such transaction between Idaho Power and IES would be based on the Mid-C or PV index as appropriate. If, during a particular day in July 2002, Idaho Power desired to enter into a real-time transaction (e.g., to sell during off-peak hours power acquired in a daily transaction to meet on-peak needs), it would transact with IES, and the price for such transactions between Idaho Power and IES would be based on the weighted average of the real-time prices at which IES bought and sold power to non-affiliates.
To further protect against potential affiliate abuse, the Agreement provides for Idaho Power to designate an Oversight Manager to ensure that Idaho Power’s interests are protected. Idaho Power’s Oversight Manager will be an officer or senior manager in the Company, and will report directly to the Office of the Chief Executive Officer and to Idaho Power’s Risk Management Committee. The Idaho Power Oversight Manager will be responsible for coordinating with IES and providing a single decision-making point from Idaho Power concerning IES’s provision of the power marketing and system management services.
In addition to engaging in inter-affiliate purchases and sales, IES will provide brokering services to Idaho Power. These services will be provided in accordance with FERC’s Code of Conduct brokering rules (including the requirement that the brokering arrangement between IES and Idaho Power be non-exclusive), and thus do not present the potential for affiliate abuse. Finally, Idaho Power and IES will engage in the purchase and sale of non-power goods and services, as described above. These services will also be provided in accordance with FERC’s Code of Conduct rules for non-power goods and services. The combination of the FERC Code of Conduct rules and the outcome of the pending IPUC docket in codes of conduct should provide adequate comfort to the Commission that affiliate abuse is adequately mitigated.
Q. Please describe Idaho Power's resource planning process, beginning with long-term planning and ending with the "next-hour" decisions.
A. Idaho Power plans to serve its loads under the general guidance of its Integrated Resource Plan ("IRP"). The last such plan was filed with the Idaho Public Utilities Commission and the Oregon Public Utility Commission in June 2000. It was acknowledged by the IPUC in December 2000. The IRP is a long term (10 years) look at load and resources and emphasizes median water conditions for planning purposes. As might be expected, because of the median water assumption, the 2000 IRP necessarily relies more heavily on market purchases to provide energy in dry years than a resource plan that acquires system resources based upon critical water conditions.
Q. Please explain in more detail how planning for the near-term time period takes place.
A. Under the Company's existing IRP, the Company plans to cover its near-term energy deficiencies through short-term purchases in the wholesale market. Other alternatives to market purchases such as demand-side initiatives or supply-side options are evaluated against market purchases on an economic basis. Additionally, near-to-mid term market purchases are evaluated by the Company's Risk Management Committee as to the timing of such purchases. Typically, Idaho Power Company buys to meet expected system requirements and does not take speculative positions in the market.
The Company's planning process in the short-term is complicated by the dominance of hydro generation in the resource base. Until the snow packs are known for the year, it is very difficult to determine the extent and duration of the Company's system deficiencies.
Q. How does the assumption regarding water availability impact the planning process?
A. Idaho Power has historically planned on a median water condition. This means water availability is assumed to be the equivalent of the middle water condition among the historical group of water conditions. Planning on median water means that the Company is more dependent on market purchases for supply in low water years than it would be if its planning assumption was based on more critical water conditions. If the Company planned on less than median water conditions, it would typically add resources sooner than it would under median water planning and would have more capacity available on an ongoing basis. Of course, the additional capacity adds additional costs to the Company's base rates. The trade-off for customers under median water planning is increasing base rates on an ongoing basis through the PCA to mitigate rate spikes during poor water years.
Q. How would you propose to evaluate whether or not it is time to change the water assumption for planning purposes?
A. Idaho Power believes that the Company’s 2002 IRP should address the issue in detail.
Q. Does this conclude your testimony?
A. Yes, it does.

GALE, DI 9
Idaho Power Company