HOYD--PCA TESTIMONY.doc

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF THE APPLICATION )
OF IDAHO POWER COMPANY FOR A )
REFUNDABLE EMERGENCY ENERGY ) CASE NO. IPC-E-01-07
CHARGE FOR THE RECOVERY OF )
EXTRAORDINARY POWER SUPPLY )
EXPENSES. )
)
)
IN THE MATTER OF THE APPLICATION )
OF IDAHO POWER COMPANY FOR )
AUTHORITY TO IMPLEMENT AN EARLY ) CASE NO. IPC-E-01-11
POWER COST ADJUSTMENT RATE FOR )
ELECTRIC SERVICE TO CUSTOMERS IN )
THE STATE OF IDAHO FOR THE PERIOD )
MAY 1, 2001 THROUGH MAY 15, 2002 )
)

IDAHO POWER COMPANY

DIRECT TESTIMONY

OF

SHARON G. HOYD

Q. Please state your name, business address and present occupation.
A. My name is Sharon G. Hoyd and my business address is 350 N. Mitchell, Boise, Idaho. I am employed by IDACORP Energy, a subsidiary of IDACORP, as Vice President of Finance.
Q. What is your educational background?
A. I have a Bachelor’s degree in Business Administration and Psychology from Albertson College of Idaho. I have also obtained the Chartered Financial Analyst designation awarded by the Association for Investment Management and Research. In addition I have attended the Public Utilities Executive Course and various other continuing education courses over the course of my career.
Q. Would you please outline your business experience with Idaho Power Company?
A. I began my career with Idaho Power Company in July, 1984 in a temporary position within the Tax Department. In October, 1984 I was hired into a permanent position as an accountant in Corporate Accounting. In 1986 I moved to an accounting position in the Corporate Budgeting Department. In 1991 I was selected for a Business Analyst position in the Financial Services Department and was promoted to Manager of that department in 1992. In 1995 I was one of three managers temporarily assigned to develop a Finance Reorganization Plan and later that year became Controller assigned to the Bulk Power Business Unit. In 1997, when the Marketing Department was created, I became Controller of Marketing and Generation. In 1998 I was assigned the Corporate Controller position. I served in that position until summer of 2000 when I moved back to the Marketing Department as General Manager of Merchant Finance. In June of 2001, coinciding with the impending movement of energy trading from Idaho Power, I became Vice President of Finance at IDACORP Energy, IDACORP’s energy marketing subsidiary.
Q. Please describe the evolution of Idaho Power’s trading activity.
A. Prior to 1997, Idaho Power’s involvement in the wholesale markets was directly related to balancing the Idaho Power system. Temporary surpluses caused primarily by increased water volume or reduced load were sold in the wholesale markets, and temporary deficiencies primarily caused by decreased water or increased load was bought from the wholesale markets to serve our customers. Wholesale market participants primarily included other utilities also seeking to balance their systems, and transactions were made between utilities at agreed upon prices without the benefit of public disclosure to use as a benchmark. During this time the region was generally surplus and market price volatility was minimal.
In 1996, the Federal Energy Regulatory Commission (FERC) issued its Orders 888 and 889. These Orders, among other things, required the establishment of wholesale open access to transmission systems. To comply with the requirements set forth from FERC, Idaho Power had to do a great deal of internal restructuring. Transmission planning and control area operations had to be split from the power supply dispatching functions. All market information passed between these groups had to be posted publicly. Additionally, utilities were required to schedule their own transmission use through the public site in the same manner, without preference, as third parties. The changes being implemented as a result of these FERC Orders began to dramatically change the nature of the wholesale electricity markets. Marketers, brokers, commodity dealers and others began buying and selling electricity, expanding by hundreds the number of entities participating in the power markets. These new market participants were not interested in the physical delivery of power for purposes of balancing resources with load but were instead interested in buying and selling contracts for purposes of profiting from market price movement. Another signal of the commoditization of electricity markets was the development of the New York Mercantile Exchange (NYMEX) standardized electricity forward contract which led to market price visibility and the further development of electricity derivative products.
As the power markets evolved, Idaho Power management recognized the need to evolve its practices of buying and selling power to competently compete in this new market. Idaho Power began in late 1996 to rebuild its power supply department. Many power supply analysts and dispatchers were given new titles as traders and the Company began the process of transforming its utility power supply operation into a commodity trading operation. This process involved hiring expertise from commodity trading, risk, accounting and other related professions on both a permanent and consulting basis to assist in developing the appropriate processes. Throughout the course of 1997 there were parallel paths progressing. The trading group, while having expertise in the physical flow of power, expanded their knowledge of the financial implications of the market forces at work and the financial derivative products that could be created to supplement the traditional physical commodity. The accounting group was charged with developing risk policies and procedures appropriate for a trading operation and to develop a methodology for tracking the speculative trading transactions separately from the traditional buying and selling of energy for system balancing purposes.
Along with the organizational and market changes, Idaho Power changed internal processes related to buying and selling power. In evaluating processes, Idaho Power had three primary considerations: 1) maintain the reliability and efficiency of the utility system, 2) seize market opportunities for commodity trading and 3) maintain the lowest possible cost for achieving 1 and 2. The resulting process designed to achieve these three goals has evolved over the last four years, but the foundation has remained the same.
Idaho Power has always maintained one trading floor that is responsible for utility purchases and sales as well as all commodity trading transactions. By having the same traders transact for the utility as well as for the trading entity, Idaho Power’s retail customers benefit from the market expertise that a full scale trading operation has to offer. Utility transactions, by their nature, will be occurring within the northwest region only at times when Idaho Power is either surplus or deficit. The current trading operation transacts multiples of the utility volume in the western, southern, northern and eastern regions and is able to use this expertise in managing the utility system.
Q. Please describe the evolution of accounting requirements for energy transactions.
A. Throughout 1997 and 1998, the accounting industry, strongly encouraged by the Securities Exchange Commission, was proceeding with the development of more stringent accounting rules related to derivative transactions. The Securities Exchange Commission, because of several derivative disasters, started requiring more comprehensive disclosure of market risks from publicly traded companies. This disclosure was required beginning with the 1998 10-K. The Financial Accounting Standards Board (FASB), because of the increased development of derivative products, developed comprehensive accounting requirements designed to make accounting for derivative products and hedging more complete and consistently applied. Also, recognizing the increased risk related to the changes in the electricity industry, primarily the increase in energy trading activities, the FASB had the Emerging Issues Task Force (EITF) promulgate generally accepted accounting principles (GAAP) for distinguishing between the traditional utility business of buying and selling energy for purposes of utility operations and the trading business of buying and selling electricity for the speculative purposes of capturing profit driven from market price movement. Statement of Financial Accounting Standards (SFAS) 133, SFAS 138 and EITF 98-10 are the resulting accounting requirements from the FASB’s work. EITF 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities, was required to be adopted by fiscal year 1999. SFAS 133, Accounting for Derivative Instruments and Hedging Activities and SFAS 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities (an amendment of FASB Statement No. 133), was required to be adopted by fiscal year 2001.
EITF 98-10 was written to give clarification between energy contracts and energy trading contracts for accounting purposes. SFAS 133 and SFAS 138 were written to ensure that all obligations with market price exposure are reflected in the financial statements. Following is a summary of the definitions and requirements of EITF 98-10, SFAS 133 and SFAS 138:
1. EITF 98-10 is effective for all fiscal years beginning after December 15, 1998. SFAS 133 (as amended) and SFAS 138 are effective for all fiscal quarters of all fiscal years beginning after June 15, 2000.
2. SFAS 133 and 138 address accounting for derivative instruments, including certain derivative instruments embedded in other contracts, and hedging activities.
3. SFAS 133 stipulates that derivatives are assets or liabilities and that fair value (mark to market) is the only relevant measure for derivatives. Changes in fair value for derivatives not designated as hedges are recorded in current earnings. The Balance Sheet reflects the current fair value for the asset or liability. Special “hedge” accounting is restricted to only certain items qualifying for fair value, cash flow or foreign currency hedges.
4. The definition of “derivative” for SFAS 133 purposes broadly defines financial instruments or other contracts as derivatives if they exhibit all three of the following characteristics:
a. An underlying and a notional amount or payment provision. An underlying is a price or rate of an asset or liability but not the asset or liability itself (for instance, a specified interest rate, security price, commodity price, index of prices or rates, etc.). A notional amount refers to the number of units specified in a derivative instrument, such as number of megawatt-hours. A payment provision refers to a fixed or determinable settlement if the underlying behaves in a certain way.
b. No or minimal initial net investment.
c. The contract terms require or permit net settlement (the contract can readily be settled net by a means outside the contract, for instance, a contract that can settle for cash without the actual delivery of electricity).
5. EITF 98-10 distinguishes between energy contracts and energy trading contracts. Energy contracts refer to contracts entered into for the purchase or sale of electricity or gas. Energy trading contracts refer to contracts entered into with the objective of generating profits on or from exposure to changes in market prices. The criteria for designating between energy contracts and energy trading contracts is defined in EITF 98-10.
6. Under the rules stipulated in EITF 98-10 and prior to the adoption of SFAS 133 and SFAS 138, contracts designated as non-trading contracts were to be accounted for in accordance with an entity’s existing policies. After the adoption of SFAS 133 and SFAS 138, contracts are to first be evaluated for derivative status using the guidelines provided therein. If a contract is not defined as a derivative under SFAS 133 and SFAS 138, then the energy trading contracts criteria defined in EITF 98-10 must be applied. Only if contracts are not defined as derivatives under the SFAS 133 and SFAS 138 criteria and are not defined as energy trading contracts under the EITF 98-10 criteria are they to be accounted for under the traditional method of accounting for utility energy contracts. All other contracts must be accounted for using the new methods outlined in SFAS 133, SFAS 138 and EITF 98-10. The traditional method of accounting for utility transactions is referred to as settlement accounting, or, recognizing the revenue or expense in income in the month of settlement. Under settlement accounting there is no balance sheet recognition of these transactions beyond the current months accounts receivable or payable. Therefore, a transaction entered into that encompasses more than the current period (a multi-month or multi-year deal) is only recognized in the financial statements a month at a time as the energy is delivered and subsequently billed.
7. All transactions meeting the definition of derivative under SFAS 133 or SFAS 138, or meeting the criteria for energy trading contracts under EITF 98-10 may not be accounted for using settlement accounting. These transactions, with the exception of transactions meeting certain defined hedge criteria, must be marked to market, that is, measured at fair value determined as of the balance sheet date. The resulting gains and losses are reported in the income statement and separately disclosed in the financial statements or footnotes. The largest impact of fair value accounting occurs with multi-period transactions. The change in fair value of the entire transaction (all periods of the transaction) is recorded in current income, with the accumulated market value gain or loss being reflected on the balance sheet. The impact of this is the recording of fluctuating profits and losses of multiple period transactions in the current period.
Q. Please describe the changes in accounting for Idaho Power’s energy purchases and sales.
A. Over the course of 1997 and 1998, Idaho Power expanded the volumes of its trading activity while still continuing to buy and sell for the system needs. During the course of the 1996-1997 PCA audit and the 1997-1998 PCA audit, Idaho Power discussed with the IPUC Staff (Staff) the need to account for the trading activity separately from the utility activity. Staff were concerned that risks associated with commodity trading could potentially be passed through to the ratepayers in the PCA adjustment. During the course of the annual PCA audits, Staff ensured there were no costs related to the trading activity being born by the ratepayer but Staff and interested parties still requested that the transactions be separated. Beginning January, 1999, with the implementation of EITF 98-10, Idaho Power implemented a new accounting policy that separately identified and booked the trading transactions as non-operating activity, no longer included as an element of the PCA calculation. This change in reporting was described in the 1998-1999 PCA Order 28049. Pursuant to that case, Idaho Power also worked with Staff and interested parties to conduct a workshop to further explain and investigate the new accounting implementation.
Early in 1999, with the adoption of EITF 98-10, the Idaho Power Risk Management Committee (RMC) set forth guidelines for utility transactions between operating and non-operating functions. Those guidelines were discussed in depth along with the new accounting rules at the PCA workshop conducted in 1999. These guidelines were then reaffirmed in July, 2000. Following are the procedures that were established:
Classifying transactions:
1. Purchases or sales will be classified by the trader at the time of the transaction. The trading group will not assume forward market risk by the operating book. In unique circumstances, management may approve forward transactions at fixed prices for the operating book if operating and market circumstances indicate this to be a prudent decision. Any forward transaction entered into for the system must be documented and signed by the Senior VP of Marketing and Generation and the VP of Finance and Treasurer or two designated alternates from the Risk Management Committee. Forward transactions are defined for this purpose as transactions for any month beyond the prompt month for the system.
2. Transactions related to the balancing of system load and system resources and transactions related to system reliability are classified as operating transactions. These transactions are recorded and maintained in an operating book that is separated from other trading transactions. The trading group, under the guidance of the Senior VP of Marketing and Generation, has the authority to enter into these transactions as necessary to prudently manage the utility system beginning one month prior to the settlement month and continuing through the last day of the settlement month. Operating transactions meet the “energy contracts” definition of the Emerging Issues Task Force consensus opinion. Operating transactions are included for PCA reporting purposes.
3. Transactions not related to the balancing of system load and resources are classified as non-operating. These transactions are maintained in non-operating trading books that are differentiated from one another by time periods – long-term, intra-month and real time. Non-operating transactions meet the “energy trading contracts” definition of the Emerging Issues Task Force consensus opinion. Non-operating transactions are excluded for PCA reporting purposes.
4. Prior to settlement, transactions occur between the operating and non-operating books at the appropriate market settlement price or third party quote in order to start bringing the system into balance at the lowest cost. The market settlement price to use for term and intra-month transfers between the operating and non-operating books will follow the formula detailed below. Any transfers made in real-time will be transacted at the average of all real-time transaction prices entered into on the day in question at the appropriate delivery point and hour.
Following is the transfer pricing formula currently and historically used for daily transactions between operating and non-operating. This is the same formula discussed in the 1999 workshop and audited in the 1998-1999 PCA case, the 1999-2000 PCA case, and the 2000-2001 PCA case.
Purchases (using Mid-C Index for intramonth deals, using Mid-C quote for term deals)
Transfer Cost = (Mid-CLL x Total LL MWh) + (Mid-CHL x Total HL MWh) + Transmission Cost where ‘Transmission Cost’ is the sum of firm transmission tariff rate of a transmission provider that has available transmission capacity from Mid-C and cost of transmission losses charged by the transmission provider.
Sales (using Mid-C Index for intramonth deals, using Mid-C quote for term deals)
Transfer Cost = (Mid-CLL price x Total LL MWh) + (Mid-CHL Price x Total HL MWh) - Transmission Cost where ‘Transmission Cost’ is the sum of firm transmission tariff rate of a transmission provider that has available transmission capacity to Mid-C and cost of transmission losses charged by the transmission provider.
Purchases (using Palo Verde Index for intramonth deals, using Palo Verde quote for term deals)
Transfer Cost = (Palo VerdeLL Price x Total LL MWh) + (Palo VerdeHL Price x Total HL MWh) + Transmission Cost where ‘Transmission Cost’ is the sum of firm transmission tariff rate of a transmission provider that has available transmission capacity from Palo Verde and cost of transmission losses charged by the transmission provider.
Sales (using Palo Verde Index for intramonth deals, using Palo Verde quote for term deals)
Transfer Cost = (Palo VerdeLL Price x Total LL MWh) + (Palo VerdeHL Price x Total HL MWh) - Transmission Cost where ‘Transmission Cost’ is the sum of firm transmission tariff rate of a transmission provider that has available transmission capacity to Palo Verde and cost of transmission losses charged by the transmission provider.
The transfer pricing formula applied to real time transactions is also the same as originally defined, however, prior to December, 2000 there were relatively few real time transactions occurring between operating and non-operating. Prior to December, 2000, all real time transactions were classified as operating with the exception of a relatively few closed (offsetting purchase and sale) transactions that could be specifically identified as non-operating.
Q. When the Idaho Commission approved the transfer pricing methodology by Order No. 28596 in Case No. IPC-E-00-13, did the Company change its real-time transaction classification process?
A. Yes. With the IPUC approval of the Electricity Supply Management Agreement, the Company believed the process needed to change in order to be in compliance with the procedures outlined in the agreement. Our non-operating real-time volumes were increasing rapidly with substantial real time business occurring in the volatile California markets and other markets not relevant to Idaho Power Company’s operation. In order to correctly align the credit and market risks of this increasing real time non-operating business and to ensure the real time traders did not have the ability to mis-classify transactions for the benefit of either the operating or non-operating book, the characterization of real time transactions was reversed to classify the majority of the deals as non-operating. The real-time operating business was accounted for by transferring volumes between the operating and non-operating books at the weighted average price of relevant non-operating transactions (real-time transactions occurring at system points).
Q. Why did you choose the Mid-C index as the transfer price for daily transactions?
A. When determining what the pricing mechanism should be for transactions between operating and non-operating there were several goals.
1. The price must be fair to both operating (utility function) and to non-operating (the trading function).
2. The price must be a relevant representation of market.
3. The price must be able to be consistently applied.
4. The price must be insulated from manipulation.
5. The price must not transfer risks of the trading operation to the utility function.
In meeting these goals the Dow Jones Mid-C index became the obvious choice. Mid-Columbia (Mid-C) is the closest trading hub to the Idaho Power system. The Mid-C hub is widely recognized by market participants as the delivery point in the Northwest most actively traded and most representative of the Northwest market. All northwest market participants transact at Mid-C and often set prices at the Dow Jones Daily Mid-C index. Dow Jones publishes daily commodity price indexes for a variety of commodities at a variety of hubs. Dow Jones chooses the hubs based on volume of business transacted at these locations and the ability to easily trade in and out of positions and has, for some time, published daily Mid-C index prices for the preceding day.
By using daily, externally produced, index prices at a liquid market hub, Idaho Power personnel have no ability to manipulate the price. The use of an index from highly liquid market hub published the day after the trading day eliminates any criticism that the trading function might advantage itself through knowledge of the utility system’s position. The use of objective market pricing for transactions between affiliates is essential to allow both the customers of the utility and shareholders of the company to feel assured that the relationship between the affiliates is arms length and cannot be manipulated to the unfair benefit of one over the other.
Additionally, by using the Mid-C index as the pricing point, the utility is not subject to the volatility of non-operating transactions occurring in other regions. Non-Operating transactions realized volume growth from 1999 to 2000 of 68%. Much of this growth was achieved by non-operating activities moving into new regions. There have been non-operating transactions as far east as Iowa, as far north as Alberta and as far south as California and New Mexico. In 2001 the non-operating activity has expanded its geographic presence even more. By moving into new regions, the non-operating system begins taking on new risks, such as additional credit risk and market risk driven by the physical constraints and volatility in those regions. By tying operating/non-operating transfer pricing to the Mid-C index, the operating book is assured of a price based on relevant markets and is not incurring the risks or costs of markets outside of the region.
Also, because there are published Mid-C index prices every day, the pricing methodology can be applied consistently.
Finally, the operating book and the non-operating book must know the price of the transaction at the time of the transaction. Without this knowledge it is impossible to manage the market risk associated with the transaction. Index priced transactions tied to the Dow Jones Mid-C index are very common in the market place. The commonality of these transactions indicates that they are able to be hedged, meaning a financial transaction can be entered into that will offset the market risk of the index pricing. Without having a visible, liquid market index to price the financial hedge, the market risk is very difficult to mitigate.
Q. Why is real-time transfer pricing based on a weighted average pricing methodology?
A. In determining the methodology used for real-time transfers, the same criteria applied.
1. The price must be fair to both the operating (the utility function) and to non-operating (the trading function).
2. The price must be a relevant representation of market.
3. The price must be able to be consistently applied.
4. The price must be insulated from manipulation.
5. The price must not transfer risks of the trading operation to the utility function
Real-time markets do not have the advantage of a published index. Therefore, a transfer price was developed using the weighted average pricing (WAP) of all non-operating deals relevant to the system (utility) market. The WAP is a method that is fair to both the operating and non-operating functions because both are impacted equally by the pricing volatility occurring within an hour. This process cannot be manipulated because all relevant transactions are used for the transfer calculation. Also, by utilizing only those transactions occurring at system points, a relevant representation of the market is created. In this way the operating book is not subject to the risks of price volatility in markets outside the region as trading activity continues to expand.
Q. Did Idaho Power use the transfer pricing methodology described above in its calculation of costs included in the April, 2000 through February, 2001 PCA calculation?
A. Yes.
Q. In your opinion, are the costs included in the PCA filing, Case No. IPC-E-01-11, for the period April, 2000 through February, 2001, fair, just and reasonable?
A. Yes.
Q. Does this conclude your testimony?
A. Yes.

HOYD, DI 6
Idaho Power Company