20000113Comment.doc

BRAD PURDY
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
[phone]

Street Address for Express Mail:
472 W WASHINGTON
BOISE ID 83702-5983

Attorney for the Commission Staff

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF THE APPLICATION OF IDAHO POWER COMPANY FOR AUTHORITY TO IMPLEMENT THE POWER COST ADJUSTMENT RATE FOR ELECTRIC SERVICE TO CUSTOMERS IN THE STATE OF IDAHO FOR THE PERIOD MAY 16, 1999 THROUGH MAY 15, 2000.
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CASE NO. IPC-E-99-3

COMMENTS OF THE
COMMISSION STAFF

COMES NOW the Staff of the Idaho Public Utilities Commission, by and through its attorney of record, Brad Purdy, Deputy Attorney General, and in response to the Notice of Application and Notice of Modified Procedure, issued on April 21, 1999, submits the following comments.
On April 15, 1999, the Idaho Power Company filed an Application for approval of Tariff Schedule 55 implementing a power cost adjustment (PCA) of -0.2143 cents per kWh and related tariffs incorporating the PCA adjustment for the period May 16, 1999 through May 15, 2000. Staff has reviewed the Companys Application and has the following comments.

FORECAST

Attachment A to these comments graphically illustrates the forecast of Net Power Supply Costs (NPSC). The projected runoff of 7.36 million acre-feet of water into Brownlee Reservoir during the April through July time period corresponds with expected annual net power supply costs of $23,311,842. The forecast also includes PURPA Qualifying Facility (QF) expenses which were determined to be $47,574,344 in Order No. 27997, Case No. IPC-E-98-13 and the forecast is reduced by FMC second block revenue which is forecasted at the normalized level of $9,074,032. FMC second block energy is excluded from PCA treatment by Commission order. The sum of these three items result in a Staff forecasted PCA expense of $61,812,154 for the PCA year. These calculations are shown in the box near the bottom of Attachment A. The Company forecasted the same annual cost. (Testimony of Gregory Said, pg. 4, line 15)
One change has been included by both the Company and Staff in this years forecast methodology. QF expense is forecasted at the expected level rather than the normalized level as has been done in all previous PCAs. This was approved by the Commission in Order No. 27997. One effect of forecasting QF expense at the expected level is that if the forecast is accurate, the following years true-up will be minimized. Another effect of including expected QF expense in the forecast is that in the year that the change is made, this years PCA, two years QF expense differences are recovered from rate payers. Last years QF expense difference from base is included in the true-up since it was not forecast and this years QF expense difference is included in this years forecast. This is a good year to make this change because in spite of the additional QF expense, rates can still be reduced. This is possible due to a great runoff forecast for the coming year and an advantageous true-up from last year due to a dramatic improvement in water conditions after last years April 1, runoff forecast.

TRUE-UP
Attachment B to these comments is the calculation of last years true-up. April of the trueup year reflects the final month of the old FMC contract which affects firm load calculations and secondary/second block revenues. The new contract was effective May 1, 1998, and is appropriately reflected in all other months of the true-up year. The change in the FMC contract also caused the Idaho jurisdictional energy allocator to change from 84.9% to 85.0%. Staff calculates the Idaho jurisdictional share of the non-QF power supply expense true-up to be
$-35,888,240 and the Idaho jurisdictional share of the QF power supply expense true-up to be $19,448,452. With accrued interest at 6 percent, the total true-up amounts to $-15,292,281.

(i.e., a rate reduction) The Company calculated the same true-up amount as Staff. (Testimony of Gregory Said, page 5, line 25)
A significant change in true-up methodology was made starting with the month of January 1999. A new accounting standard, EITF 98-10, was implemented. The accounting standard requires that a separation be made on the books of the Company between energy sales and purchases made for operating purposes and other energy sales and purchases made for non-operating purposes. Operating purposes include sales from system resources, system load balancing, system reliability transactions and hedging for system purposes. Non-operating purposes encompass all non-system transactions. In the current case, the Company proposes to use these definitions to include system operating transactions in the PCA and to exclude non-operating transactions from PCA treatment.
The lack of a workable definition applied at the time of the transaction caused the inability to make this separation in last years PCA true-up and led to the capture within the mechanism of operating and non-operating transactions. It has been and continues to be Staffs position that the risks associated with non-operating transactions should not be passed on to customers. The implementation of the EITF 98-10 standard has the potential to provide the separation Staff desires. For the purposes of this case, Staff is willing to accept the separations proposed by the Company for January, February and March 1999. Staff intends to review the effect of the standards on future PCA calculations again during 1999 since the procedure should be more mature and there will be more data to review. Due to the potential impact on the PCA of the classification of energy transactions as operating or non-operating, the Companys classifications and procedures should be reviewed in every PCA case.
The Company has established the following guidelines in the implementation of EITF
98-10 as it relates to the PCA:
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 transaction at fixed prices for the operating book if operating and market circumstances indicate this to be a prudent decision.

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. 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.

STAFF AUDIT
Staff audited the actual results, month by month, of six line items. These line items are: actual fuel expense, non-firm purchase power expense, QF expense, surplus sales revenue, FMC secondary revenue, and system firm load. As a result of that audit, Staff found that all six items were correct as presented.

In mid-year 1997, the Company began very substantial power marketing activities. As part of the PCA, the dollar amounts of surplus sales and non-firm purchases in the PCA year are compared to normalized amounts from the base condition and 90 percent of the difference is deferred. If increases in surplus sales revenue exceed increases in non-firm purchase costs, ratepayers benefit. If the opposite is true, ratepayers are surcharged and shareholders benefit. The true-up portion of the PCA calculates this difference because these categories of expense and revenue are expected to, and do, vary under differing water conditions. In isolation, good water conditions increase surplus sales and decrease surplus purchases while poor water conditions do the opposite. Changes in surplus sales and purchases due to water conditions are not easily distinguishable or, in the end, completely distinguishable from changes caused by marketing. For the first 9 months of the PCA, these revenues and costs are captured in the PCA, and the profits and losses are shared with customers. With the implementation of EITF 98-10, the months of January, February and March 1999 do not have the non-operating power marketing transactions included in the PCA. With the limited number of months and the recent implementation of EITF 98-10, Staff is unable to reach any firm conclusions about future effects of removing the non-operating power marketing transactions from the PCA. The Surplus Sales and Purchases for January, February and March 1999 appear reasonable, and Staff accepts these amounts as filed. Before the next PCA is filed, Staff will perform a more extensive audit of the non-operating power marketing transactions and Electricity Sales and Purchases from energy trading transactions.

PCA RATE
Attachment C reduces the forecast and true-up amounts previously identified to an energy rate. The forecast component is calculated as -.0727 cents per kWh and the true-up component of the rate is calculated to be -.1416 cents per kWh. The total rate adjustment from utility base rates is the sum of these two which is -.2143 cents per kWh. The total rate adjustment from existing rates, which include a .1598 cents per kWh surcharge, is -.3741 cents per kWh.

CUSTOMER CLASS DECREASES
Attachment D, page 1, shows the revenue requirement and percentage decreases from base rates by rate schedule associated with Staffs proposed rate change. In the bottom right hand corner the average Idaho jurisdictional rate decrease is shown to be 5.49 %. Attachment D,
page 2, shows the same information except the decreases are measured from existing rates. Measured from existing rates, the average Idaho jurisdictional rate decrease is 9.20 %.

COMPARISON OF LAST YEAR VERSUS THIS YEAR
Attachment E compares the components of last years PCA rate increase with the components that make up this years proposed rate decrease. Last years rate increase was approximately $34 million and the proposed decrease this year is approximately $40 million dollars.

STAFF RECOMMENDATION

Staff has reviewed the Companys filing and found the methods, representations and calculations to be correct and in compliance with the Commissions Orders as they relate to the PCA. Staff recommends approval of the revised tariffs filed as part of the Companys Application in this proceeding. Staff supports the Companys proposal that these changes be effective May 16, 1999.

Respectfully submitted this day of May, 1999.

_______________________________
Brad Purdy
Deputy Attorney General

Technical Staff: Keith Hessing
Kathy Stockton

KH:jo\comments\ipce993.bp

STAFF COMMENTS 1 May 7, 1999