PrehearingMemo.doc

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF THE IDAHO POWER
COMPANY APPLICATION FOR A
REFUNDABLE EMERGENCY ENERGY
CHARGE FOR THE RECOVERY OF
EXTRAORDINARY POWER SUPPLY
EXPENSES.
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CASE NO. IPC-E-01-7

IN THE MATTER OF THE IDAHO POWER
COMPANY APPLICATION FOR AUTHORITY
TO IMPLEMENT A POWER COST
ADJUSTMENT (PCA) RATE FOR ELECTRIC
SERVICE FROM MAY 1, 2001 THROUGH MAY
15, 2002. )
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CASE NO. IPC-E-01-11

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

STAFF’S PREHEARING MEMORANDUM

COMES NOW the Staff of the Idaho Public Utilities Commission by and through its counsel and submits this prehearing memorandum for the Commission’s consideration. The purpose of the prehearing memorandum is to outline the disputed issues between the Staff and Idaho Power in these cases to be heard August 28-30, 2001.
PROCEDURAL HISTORY
On May 1, 2001, the Commission authorized Idaho Power to immediately recover approximately $186.3 million of the Company’s $227.4 million request through the PCA mechanism. Order No. 28722. The Commission deferred recovery of approximately $59 million pending an evidentiary hearing to examine the following issues: trading practices (to include hedging, transmission and wheeling charges, Mid-C pricing, and the use of weighted average pricing), the November trading event, and the Company’s resource planning. Id. at 17.
The Commission issued two scheduling Orders that set out the parameters for filing prefiled testimony and exhibits. Per Order No. 28738, Idaho Power filed its prefiled direct testimony on June 22, 2001; Staff and Intervenors submitted prefiled direct testimony on July 20, 2001; and the Company filed its prefiled rebuttal testimony on August 7, 2001. On August 7, 2001, the Intervenors Idaho Rivers United, Idaho Rural Council, and Mary McGown filed a Notice of Withdrawal in these proceedings.
On or about August 24, 2001, the Commission granted a Joint Motion for Bifurcation of Proceeding in Case No. IPC-E-01-16. Order No. 28831. Under this bifurcation, the only issues in Case No. IPC-E-01-16 to be considered at the August 28-30, 2001 hearing would be the interim requirements for the Company’s trading practices (including hedging, Mid-C pricing, weighted average pricing, and transmission charges) from March 1, 2001 until the date the Commission issues its final order in Phase I of Case No. IPC-E-01-16. A second phase in Case No. IPC-E-01-16 will consist of a collaborative process in which the Parties will attempt to reach a consensus on the remaining issues identified by the Commission. These prospective issues include Idaho Power’s marketing Agreement with IDACORP Energy Services (IES) (a.k.a. IDACORP Energy or “IE”); flexible resource planning; and the policies, procedures and safeguards that should be instituted by Idaho Power to manage market risk in the future.
I. Lack of Authority
Idaho Power relies on a prior Commission Order as justification for implementing the Mid-C pricing mechanism for day-ahead transactions and an average for real-time transactions during the 2000-2001 PCA year. In Order No. 28596 issued December 19, 2000, the Commission approved a Service Agreement regulating the conduct and governing the transactions between IES and Idaho Power. However, the explicit terms of the Agreement provide that it does not become effective until the state regulatory Commissions of Idaho and Oregon both approve the Agreement in addition to the Federal Energy Regulatory Commission (FERC). Staff Exh. No. 117, p.7 (Agreement at ¶ 9 at p. 4). The Agreement states that it “shall not become effective until the commissions have issued their respective final orders approving the Agreement or any future amendments.” Id. at ¶ 9.
By its own terms, the Agreement did not become effective until the Oregon PUC and FERC approved the Agreement. FERC conditionally approved the Agreement effective April 28, 2001 and required Idaho Power to refile the pricing mechanism for real-time transactions to conform with prior FERC approvals. Staff Exh. No. 118 (95 FERC ¶ 61,147 (2001)). The Oregon PUC did not issue its approval until at least July 3, 2001. Staff Exh. No. 120. Thus, under the terms of the Agreement, it was not effective until July 3, 2001 – well after the end of the 2000-2001 PCA year. Carlock, Dir. at 17.
Absent these Commissions’ approvals, Idaho Power itself purchased power for its own use in the 2000-2001 PCA year. Because Idaho Power was still responsible and bore the risk for power purchases, it is inappropriate and unreasonable to charge ratepayers $51 million more than the cost of the purchased power. The manner in which the transactions were recorded created the price differential that made use of the Mid-C pricing for day-ahead and real-time transactions inappropriate and unreasonable. Proper safeguards must be and should have been implemented before using the Mid-C pricing structure.
II. Selective Implementation of Provisions of the IPCo-IES Agreement is Unfair
The Company suggests that Staff is reneging on its approval of the IPCo-IES Service Agreement. Staff only wishes to implement what it contracted for: 1) the effective date based on proper authorization, 2) safeguards against affiliate manipulation, 3) receipt of the annual payment, and 4) continued audit review of the reasonableness of using the pricing mechanism. The Company has selectively implemented portions of the Agreement prior to its explicit effective date. It is unfair for the Company to only implement portions of the Agreement that benefit the Company while the ratepayer benefits were not implemented.
Although the Company implemented the pricing mechanism contained in the Agreement, it has insisted the other provisions had not yet taken effect. Id. at 22-23. These other provisions -- $2 million annual credit to customers, Idaho Power Oversight manager, implementation of audit tracking mechanisms – were safeguards to insulate customers from potential affiliate abuse. Id. at 23. Essentially, the Company is arguing that the Service Agreement was effective as to its use of the Mid-C pricing index but not as to the customer safeguard provisions.
In the meantime, the non-system (which became IE no earlier than July 3, 2001) activities used Idaho Power system’s trading certificate, the utility’s name recognition and regulatory assets until IE conditionally received its FERC power marketing license on April 28, 2001. Lord, Dir. at 24-25. During the 2000-2001 PCA year, ratepayers were not protected from speculative activities of non-system operations because the regulated utility (with its trading certificate) was legally responsible for completing the transactions. Id. Without Idaho Power standing behind all of IE’s (or “the non-system’s”) transactions, IE would not have received any profits prior to April 28, 2001. Moreover, the speculative non-system transactions indicate that transfer prices to regulated customers were at higher prices than what the Company paid for the same product (i.e., day-ahead power).
If Idaho Power is granted the $59 million in dispute, the non-system operations (which became IE no earlier than July 3, 2001) would have effectively been allowed to:
charge ratepayers more than the actual cost of purchased power;

use Idaho Power’s physical assets free of charge;

use the regulated utility’s trading certificate, thus using the regulated utility’s credit rating and name recognition, while leaving ratepayers ultimately responsible for delivery or payment on risky transactions;

allow profits to remain with a non-system operation even though it was not yet authorized to operate as a separate affiliate. The risks ultimately remained with the system (i.e., the Company), resulting in unreasonable risk/reward responsibilities and tradeoffs.

benefit from an Agreement not yet in effect by using its pricing methodology but not providing the contracted-for safeguards and the $2 million annual payment intended to partially reflect lower costs attributed to ratepayers.

None of this was authorized by the Service Agreement. The bottom line is that ratepayers were liable for speculative risk but did not enjoy any of the benefits, were charged prices that were higher than costs, and went uncompensated for the non-system’s use of utility assets supported by ratepayer rates.
III. Lower of Cost or Market is the Appropriate Pricing Structure
The validity of the Mid-C index itself is not an issue in dispute. Dr. Peseau argues in his rebuttal testimony, and Staff agrees, that the Mid-C index is a justifiable and valid index. Peseau, Dir. Reb. at 7. The real issue is whether Idaho Power’s operations (i.e., near total reliance on day-ahead purchases to meet shortfalls) and its recording of transactions when it applied the Mid-C index, along with the type of transaction the Company utilized to meet native load, allow use of the Mid-C index as a pricing mechanism between affiliates to be representative and reasonable. Carlock, Dir. at 23-24. This is particularly troublesome because the Mid-C index does not reflect the actual cost of resources purchased to meet system needs. If Idaho Power has no long-term transactions and nearly all day-ahead transactions, the Mid-C index will be applied to all the Company’s day-ahead transactions rather than booking the term transactions “at cost.” Id. at 8. This affords no opportunity for ratepayers to lock in a price lower than the day-ahead market price and no opportunity to beat the day-ahead market price average. The best that ratepayers can hope to pay for all day-ahead transactions is the average market price. Ratepayers receive no benefit from risk management services if the Company executes no term transactions and daily average market transactions establish cost.
Approval of the Mid-C index pricing mechanism in Case No. IPC-E-00-13 was prefaced on the continued review and ongoing improvements to the process. This is no change to the process that has always been followed between the Staff and Idaho Power for any PCA review. This process reviews the prior year’s PCA results for reasonableness in the annual true-up audit. The cost recovery at issue here is part of the true-up portion of the PCA. The Staff annual PCA audit and the Company’s requirement to demonstrate the continued reasonableness of market pricing were safeguards proposed and adopted by parties as part of the workshops and Stipulation in IPC-E-00-13. According to Ms. Carlock, it would not have been acceptable to Staff and other parties to endorse a 5-year contract between the parties without the burden remaining on the Company to show the continued reasonableness of the Mid-C index as a pricing surrogate. Carlock, Dir. at 19-20.
If price volatility, the number of transactions, and the recording of those transactions had allowed for a reasonable and representative surrogate, Staff would not be taking issue with using the Mid-C index as a pricing surrogate. However, using the “lower or cost or market” test for purchases and the “higher of cost or market” test for sales, the Mid-C index was representative only during the months of August and September 2000 – just two of the eleven months in the PCA period. Id. at 25. Staff is charged with reviewing the pricing and accounting practices for reasonableness for all PCA transactions irrespective of the collateral IES Agreement, whose future terms do not replace the PCA audit.
During the workshops in Case No. IPC-E-00-13, the Company assured Staff and parties that their system operations (transactions for Idaho Power) would not change once the Agreement was implemented. Id. Staff’s endorsement of using the Mid-C Index as a pricing surrogate was contingent upon similar Company operations or a risk management analysis showing day-ahead activity was best for customers. Idaho Power’s elimination of long-term hedging transactions in peak winter months was not a small change in operations. It forced the utility to purchase heavily from the day-ahead spot market, which contributed to distorting the reasonableness of the Mid-C index as a pricing surrogate.
During the 2000-2001 PCA year, the application of the Mid-C index was not a reasonable surrogate. As the market changed and the relationship between Idaho Power’s affiliated interests changed, it was possible for the pricing mechanism to be reasonable at one point in time but not another. The growing volume and price volatility of transactions increased the potential that the Mid-C index would not be a reasonable surrogate. This exacerbated the differences between the surrogate or market price and the actual cost of the affiliate beyond an acceptable band, causing use of the market price as a surrogate to no longer be reasonable. Carlock, Dir. at 23-24. Because the index surrogate did not reasonably reflect the actual cost of the affiliate operation, the difference between higher transfer prices and actual costs must be assigned to Idaho Power’s non-regulated operations. To this end, Staff recommends non-recovery of the $51,234,902. Carlock, Dir. at 21.
The simple fact is that even if the Agreement had been in effect, the Company did not comply with the agreed upon documentation, oversight manager, $2 million customer credit, and audit tracking mechanisms safeguards necessary to justify the reasonableness of its market-priced transactions. Carlock, Dir. at 20.
Intra-month and Day-Ahead Transfer Pricing
In auditing the PCA intra-month purchase data, Staff did NOT find the index market price to be reflective of a reasonable price surrogate between the system and non-system purchases. The non-system purchases were less costly overall than the system purchases priced at market index. Staff Exhibit Nos. 122-127. Since these transactions were with a speculative arm within Idaho Power, the Company must show the continued reasonableness of the transfer prices. Carlock, Dir. at 6.
Proper use of an index as a surrogate will not produce extraordinarily high profits for an affiliate. Use of a market index represents the average price paid in the market for the product. By its nature, the market price will not be consistently beat. Since Idaho Power’s records indicate that its speculative arm consistently outperformed the Mid-C market price, there must be a flaw or faulty safeguard related to the use of the market index when applied to the transaction activity recorded. Any safeguards established were not operational or did not function properly. The lower of cost or market pricing mechanism for purchases is the best and possibly the only feasible way to be assured that customers are not harmed by affiliate abuse or manipulative powers. The lower of cost or market pricing should be used until the requisite safeguards are in place. Therefore, to compensate for this disparity between the actual cost and the surrogate Mid-C price, Staff proposes to modify the pricing mechanism for the 2000-2001 PCA year for intra-month to more accurately reflect an appropriate cost. More specifically, Staff recommends that purchases by the speculative arm of Idaho Power for the system be priced at the lower of cost or market. The lower-of-cost or market for purchases and the higher-of-cost or market for sales is the standard default pricing mechanism used for regulated entities when a proper pricing mechanism between affiliate entities has not been justified. Furthermore, Staff recommends that the cost be based on the daily weighted average of the price actually paid for the day-ahead power by the non-operating book.
Staff believes that the weighted average price for day-ahead transactions is fair and reasonable. It provides incentive to make sure that all trades are sound and reasonable for both the system and non-system transactions with minimal ability to game or manipulate the price. Substantially greater margins on similar transactions for a non-regulated entity compared to a regulated entity is an indicator of an improper pricing mechanism. Id. at 24-25.
For the months of December 2000, January 2001 and February 2001, Staff believes that the day-ahead power purchased from the non-operating system to the system should be re-priced at the daily weighted average price paid by the non-operating system. That way, the system pays exactly what the non-operating system pays, which is appropriate because IDACORP Energy did not yet exist. The non-operating system of the regulated utility should not be allowed to profit substantially from the regulated system of the same utility. Carlock, Dir. at 24.
Consistent with the adjustment for the detailed audit for the three months listed above, Staff determined that the rest of the day-ahead transactions for the PCA year should be repriced using a weighted average monthly cost of non-operating system transactions. While not as precise as a daily price, Staff believes average monthly weighting is fairly representative because it reflects the price and volume of each transaction during the month. The months of August and September 2000 did not have adjustments because the transfer prices were already at the lower-of-cost or market when compared to the weighted average monthly price for purchases, and at the higher-of-cost or market for sales. The net Idaho jurisdictional adjustment is a $51,234,902 benefit to customers. Carlock, Dir. at 25-26.
Real Time Transfer Pricing
During the 2000-2001 PCA year, the Company changed the way the real-time transactions were priced. In the past, the transactions always flowed through the system at their actual cost. Now, however, the transactions are priced based on the weighted average of all real-time transactions that touch the Idaho Power system on an hourly basis.
According to Staff’s analysis, this change in pricing resulted in significant overcharges and underpayments. To account for these disparities, Staff recommends that the real-time purchase transactions for the months of December 2000 through February 2001 be repriced to the lower of the non-system’s cost or market price. Staff also recommends repricing the real time sale transactions for the same months using the higher of sales price or market. Staff believes that purchases and sales should be kept separate and that the system should receive the benefit of the best price – particularly since IES had not yet become a separate entity. The net adjustment, before the jurisdictional and sharing allocations, and without the effect of interest on the deferral balance, for real time transactions is ($4,666,381.95). Carlock, Dir. at 26-27.
FERC did not approve the pricing mechanism for real-time transactions in the IES Agreement. FERC required the Agreement to be modified to require: 1) IES to sell power to Idaho Power at the lowest price for energy sold to Idaho Power by non-affiliates, and 2) Idaho Power to sell power to IES at a price that is no lower than the price Idaho Power charges non-affiliates. Staff Exh. No. 118 (95 FERC ¶ 61,147 (2001)). On May 14, 2001, Idaho Power and IES filed the requisite change to its pricing of real-time transactions, but as of this date has not received FERC confirmation of approval. Carlock, Dir. at 17.
IV. It Was Unreasonable for Idaho Power to Maintain Little or No Hedging
Staff asserts that the Company substantially limited system long-term or hedging (i.e., in excess of one month) contracts after November 2000. These were replaced with more volatile (and usually more expensive) day-ahead market purchases. Moreover, Idaho Power made no long-term system purchases for itself in January and February 2001 even though 80% of non-system purchases for the same time period were term transactions. Carlock, Dir. at 7. In other words, the system and non-system were essentially betting against one another to the system’s (i.e., ratepayer’s) detriment. Staff finds this particularly troublesome because the Company (which included both the regulated and the speculative entities) was aware of generating shortfalls as outlined in its 2000 IRP and that its system would need to rely more heavily on day-ahead markets. As the Commission noted in its Order No. 28722, reducing “the use of long-term contracts . . . places over-reliance on the spot market and exposes utilities to possible exercise of market power by wholesale power sellers during periods of short supply.” Order No. 28722 at 13 citing California PX v. FERC, 245 F.2d 1110 (9th Cir. 2001). Given the low water conditions, Idaho Power would likely be in short supply of hydro-generation. The significant reduction of long-term hedging contracts placed greater reliance on the highly volatile short-term markets (e.g., day-ahead and real-time markets) with their unreasonable Mid-C pricing mechanism. In other words, the lack of hedging exacerbated the pricing issues to the detriment of ratepayers.
The Company did not retain or did not perform cost analyses or risk analyses to show that the change in operations was prudent. The non-operating system should be entitled to retain profits received for risks actually incurred. However, using a market price as a surrogate when the costs are lower for the recorded purchase transactions is an inequitable application of market pricing. The transfer (paper) profits should not be retained by the non-system operation when the risk and pricing detriment are left with system customers.
Staff argues that while the non-system operation may execute additional and potentially more risky deals, the direction and the existence of system transactions should be consistent but on a more conservative scale. Because the non-system operation executed term transactions, the system (serving native load) should also have had some corresponding transactions within its risk bands. Id. at 8. No risk band analysis was provided nor is it apparent it was performed. Absent term transactions, the power purchases were shifted to day-ahead transactions and priced at the volatile market index rather than at a fixed rate.
This apparent failure to use long-term transactions and properly hedge subjected ratepayers to greater market volatility and risk. By comparison, Staff found during the months of May 2000 through February 2001, the Company’s non-system term purchases with third parties ranged between 66% and 81% of the non-system’s total purchases. Staff Exh. 110, p. 1. Idaho Power’s elimination or reduction in term transactions, resulting in increased reliance on day-ahead markets, is one factor that Staff believes has contributed to the overall increase in costs to ratepayers.

V. Transmission and Wheeling Charges
Staff is concerned that the non-system speculative arm of Idaho Power is utilizing the Company’s transmission facilities without proper benefit or compensation to the regulated utility and its customers. Transmission arbitrage occurs where a discrepancy between two pricing points exists such that the transaction can be entered into to capture the difference as profit with little or no risk. Transmission services are transferred to the non-system speculative arm of Idaho Power at cost. Lord, Dir. at 26. The entity then transfers power purchased for Idaho Power at the Idaho border based on the Mid-C index price – not the border price. Since the transportation price is known, the speculative arm can determine whether Idaho border prices are less than the representative market price plus transmission. If there is a differential, the speculative arm collects that differential as a profit. This profit is risk-free and is not shared with ratepayers. Id.
Staff could not quantify the amount owed to ratepayers for non-system or speculative use of Idaho Power’s transmission facilities. However, Mr. Gale’s rebuttal testimony indicates that Idaho Power is currently negotiating with IDACORP Energy for payment of such previously unquantified benefits. The Company indicates that it hopes to inform the Commission of the resultant amount, which will benefit ratepayers, at the August 28-30, 2001 hearings. Gale, Dir. Reb. at 8.
VI. November Trading Event
During the PCA audit, Staff identified a 75 MWh term transaction (the “November Trading Event”) for the regulated system for January 2001 that was ordered in the November 21, 2000 Risk Management Committee (RMC) minutes, but was never completed by the trading entity. When a purchase was subsequently made to meet this need, the market price of power had substantially increased. The Company should not be allowed to recover the approximate $8 million in higher-priced replacement power once they had identified the need for it but failed to follow through on its purchase. Carlock, Dir. at 29.
The Company claims that the apparent oversight in the RMC minutes is “a record keeping issue and not one of execution.” Gale, Dir. Reb. at 5. Idaho Power argues the transaction was not completed because the RMC changed its decision later during the same meeting. Staff does not find this explanation persuasive because the Company’s operating plans showed that under nearly every scenario the system would be short in January and thus supported a term transaction. Carlock, Dir. at 28. No other information was found in the RMC meeting minutes or retained by the Company justifying the RMC’s decision NOT to make the January term transaction.
Darrel Anderson, Vice President – Finance & Treasurer of Idaho Power Company, explained that the system did not need to purchase power for January 2001 because it had a net long position of 1,300 MW through the balance of the 2000-2001 PCA year despite net short positions of 80 MW in December 2000 and 63 MW in January 2001. Anderson, Dir. at 5. To illustrate that Idaho Power did not need the 75 MWh transaction in question, Mr. Anderson pointed to a transaction executed during the week of November 30, 2000 that sold some of the Company’s First Quarter 2001 length and purchased Third Quarter 2001. However, Ms. Carlock testified that these transactions are not mutually exclusive and Idaho Power could have packaged a deal that accomplished the desired price spread without exposing the regulated system to spot market purchases during a time period in which it was already short. Carlock, Dir. at 30. As if this First Quarter/Third Quarter transaction was not already troublesome, it should be noted that the Company was buying for the Third Quarter when Idaho Power was forecasted to be long in September. Carlock, Dir. at 31.
The Company ignored the possibility that power prices could increase further given that January is a peak winter usage month. Assuming the Company did in fact halt the execution of the term transaction, it purposely left customers exposed to a known volatile spot market during a period the Company knew it would be short in order to lock in a price spread seven months out. Absent documentation of its rationale, the Company’s subsequent decision not to place the term transaction simply looks like a bad decision that was contrary to the prudent decision originally made. These detrimental costs should not be recovered from customers and should be absorbed by the non-system operations. Carlock, Dir. at 29.
SUMMARY
The Company wants it all: Mid-C index transfer pricing without the promised safeguards or $2 million payment to customers, to allow its non-system to mark up transferred power $51 million even though it was not a legally separate entity, and to have ratepayers to bear speculative risk yet share none of the rewards. At best the Company engaged in poor record keeping; at worst it was negligent in failing to hedge against market volatility during periods it was known to be short of power.
During the 2000-2001 PCA, wholesale power trading was performed under Idaho Power’s authority and the Company assumed all counterparty credit risk for speculative transactions. Until the Commissions and FERC approved the Agreement between IES and Idaho Power, all power purchases were made by Idaho Power not IES. Because Idaho Power was purchasing energy for itself, ratepayers should not pay a price for that power that is significantly higher than its cost, even if the “price” was the market index.
The Company is being unreasonable to demand that it use a pricing methodology that was not yet in effect while not providing the agreed-upon safeguards and the $2 million annual payment intended to protect and benefit ratepayers authorized by the same Order. Moreover, it is unconscionable for the Company to insist that it be allowed to use a pricing methodology that overcharges ratepayers $51 million for power purchased in-house by the utility.
In Order No. 28722 the Commission granted nearly three-quarters of Idaho Power’s $227.4 million request. The Company has not shown its actions in these disputed matters to be reasonable or prudent. Consequently, Staff requests that the Commission deny approval of the remaining $59 million at issue and use of the Mid-C index until the promised safeguards are in place.

Respectfully submitted this 24th day of August 2001.

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Lisa D. Nordstrom
Deputy Attorney General
Attorney for Commission Staff

M:IPC0107_11_16.prehearingmemo_ln2
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