SAID--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

GREGORY W. SAID

Q. Please state your name and business address.
A. My name is Gregory W. Said 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 Director of Revenue Requirement within the Pricing and Regulatory Services Department.
Q. What is your educational background?
A. In May of 1975, I received a Bachelor of Science Degree with honors in Mathematics from Boise State University. In 1996, I completed the University of Idaho's Public Utilities Executive Course in Moscow, Idaho. I have also attended numerous seminars and conferences on accounting and finance issues related to the utility industry and have attended seminars and courses involving public utility regulation.
Q. Could you please describe your business experience with Idaho Power Company?
A. In 1980, after a few years of employment with the State of Idaho, I became employed by the Resource Planning Department of Idaho Power Company. In 1989, I was offered and I accepted a position in the Company's Rate Department. In 1994, I was asked to become the Meridian District Manager for a one-year cross-training opportunity. In 1995, I returned to my position in the Rate Department. In October of 1996 I was promoted to Director of Revenue Requirement in the Pricing & Regulatory Services department, a position I currently hold. I have presented testimony before the Idaho and Oregon regulatory agencies addressing various issues on numerous occasions.
Q. Please describe your experience with the Company with regard to the Company's power supply costs.
A. My first responsibility with the Company in 1980 was to develop the Secondary Transactions Simulation Model for use in determining the average net power supply expenses associated with multiple hydro conditions as well as the expenses associated with each hydro condition.
In December 1981, the Company applied for an increase in its general revenue requirement in Case No. U-1006-185. The Secondary Transactions Simulation Model became the basis for determining the Company’s normalized net power supply expenses in that revenue requirement proceeding.
In the next general revenue requirement proceeding, Case No. U-1006-265, filed in September of 1985, I was the Company’s power supply witness providing direct and rebuttal testimony as well as direct testimony upon rehearing. At the same time, I was also the power supply witness in the Company’s Oregon jurisdictional filing.
In 1988, the Company applied for a temporary rate increase because of drought conditions. Once again, I was the Company witness addressing power supply issues.
In August of 1988, after nine years in the Resource Planning Department, I was offered and I accepted a position in the Company’s Rate Department. With the Company’s application for a temporary rate increase in 1992, my responsibilities as a witness were expanded, but I continued to be the Company’s witness concerning power supply expenses.
Q. When was the concept of a Power Cost Adjustment (PCA) introduced?
A. In 1992, several parties urged the Company and the Commission to implement some form of rate mechanism for tracking power supply expenses. The Commission issued Order No. 24308 (in Case No. IPC-E-92-10) stating that the PCA issue would be analyzed in a formal proceeding initiated for that purpose or in the course of the Company’s next general rate case. Exhibit 1 is a copy of Order No. 24308.
Q. As a result of Case No. IPC-E-92-10 and Order No. 24308, how did the Company initially address the issue of a Power Cost Adjustment?
A. During the IPC-E-92-10 proceeding, Mr. Marshall, the Chief Executive Officer of Idaho Power Company at that time, stated that the Company would conduct an independent investigation of the complexities of a Power Cost Adjustment, submit a report of Company findings, and solicit constructive comments from the parties and Commission Staff. Immediately after Order No. 24308 was issued, Mr. Marshall assigned the Rate Department (now known as Pricing and Regulatory Services) the responsibility of developing a Power Cost adjustment methodology that would be appropriate for Idaho Power Company if it was determined that the Company should have such an adjustment.
My combined Resource Planning Department and Rate Department experience uniquely qualified me to design a Power Cost Adjustment that would impact customers rates based upon changes in the Company’s net power supply expenses.
Q. Were you responsible for the PCA investigation, in which the Company prepared a report delineating an appropriate Power Cost Adjustment methodology for Idaho Power Company?
A. Yes. On September 11, 1992, the Company filed its “Power Cost Adjustment Analysis” report with the Idaho Public Utilities Commission. At that time the Company also distributed copies of the report to interested parties. Exhibit 2 is a copy of that report.
Q. After distributing the report, did you solicit comments from interested parties and Staff?
A. Yes. There were a number of conversations about the Company’s report with interested parties and Staff. The conversations primarily involved clarification of details within the report. In general, the parties continued to be in favor of implementing a PCA for Idaho Power Company.
Q. When did the Company apply for authority to implement a Power Cost Adjustment in its Idaho jurisdiction?
A. The Company filed its application for authority to implement a PCA in Idaho on November 24, 1992. The Case number was IPC-E-92-25.
Q. Were you a witness in that case?
A. Yes, I was.
Q. In that proceeding, did you state what you believe the primary objective of a Power Cost Adjustment should be?
A. I stated that the primary objective of a Power Cost Adjustment should be to provide a simple and understandable mechanism that closely matches revenues (resulting from rates) to the actual power supply expenses incurred by the Company. I went on to state that the objective could be met by identifying a variable component of a customer’s rate that reflects the variable expenses of providing energy to serve the customer’s load. That variable component would change as the cost of energy changed. As a result, proper and understandable price/cost signals would be sent to customers. When the Company’s net power supply expenses were higher, the Power Cost adjustment would allow for the corresponding rate component to be adjusted to a higher level. Conversely, when the Company’s net power supply expenses were lower, the rate component would be lowered.
Q. Please give a general description of the Power Cost Adjustment that you recommended in 1992.
A. The Power Cost Adjustment that I recommended in 1992 provided for an annual adjustment in rates to be made after April 1 each year based upon an estimate of the projected April 1 through March 31 annual variable cost of providing energy to firm loads. The power cost rate component would remain in effect for one year (May 16 through May 15). Any difference between estimated and actual annual variable costs of providing energy to firm loads would be trued-up by deferring the actual monthly expenses or revenues as they differed from the estimate. The deferred expenses or revenues would be amortized in the following annual power cost adjustment period (again May 16 through May 15 of the following year.)
Q. Does the general description of the Power Cost Adjustment that you recommended in 1992 accurately describe the Power Cost Adjustment that was approved by the Idaho Commission?
A. The general description does describe the Power Cost Adjustment that was approved by the Idaho Commission with minor clarification. The general description that I have provided suggests that 100 percent of the deviations of actual PCA expenses from normalized levels would be reflected in PCA rate changes. The Commission, however, approved power cost rate adjustments that reflected only 90 percent of the deviations of actual PCA expenses from normalized levels except for deviations in CSPP expenses which are reflected at 100 percent.
Q. What are the PCA components that the Commission approved for inclusion as the annual variable cost of providing energy to firm loads?
A. The PCA components are fuel expenses (FERC account 501), purchased power expenses including cogeneration and small power production (FERC account 555); surplus sales revenues (FERC account 447) and Astaris (formerly FMC) second block revenues.
Q. Are transmission and wheeling charges included as a PCA component?
A. No. Transmission and wheeling revenues and expenses are reported in FERC Account Nos. 456 and 565 respectively, which are not PCA FERC accounts.
Q. Initially, what information was required to implement the PCA?
A. In order to implement the PCA, the Commission quantified a base determination of PCA component values. Normalized fuel expenses were quantified as $70,592,600. Normalized purchased power expenses excluding CSPP were quantified as $5,074,900. Normalized CSPP expenses were quantified as $32,031,600. Normalized surplus sales revenues were quantified as $42,833,500 and normalized FMC secondary load revenue was quantified as $14,101,280. The normalized net PCA expenses were $50,764,320, which was the sum of fuel and purchased power expenses including CSPP less the surplus sales and FMC secondary load revenues.
Q. Were any rate changes required to implement the PCA?
A. Yes. Because FMC’s secondary load was interruptible and would be treated as a dispatchable resource based upon variable cost, the second block rate was re-established at 23 mills per kilowatt-hour. The FMC primary block rates were also adjusted to ensure that the overall FMC revenue remained the same.
Q. When did the Commission approve the use of a PCA for Idaho Power Company?
A. The Commission issued Order No. 24806 in Case No. IPC-E-92-25 approving a PCA for Idaho Power Company on March 29, 1993. Exhibit 3 is a copy of Order No. 24806.
Q. How did the Commission describe the approved PCA mechanism?
A. In Order No. 24806, the Commission stated:
“The mechanism we approve has the following basic elements: It is based on annual forecasted power supply costs; deviations from predicted annual power supply expense are deferred and trued-up in a subsequent year; interest is accrued on deferrals; an efficiency incentive shares variations in power supply costs from a base case between ratepayers and the Company on a 90-10 ratio; a procedure to guard against rate shock is included; power supply costs associated with changes in load are factored out of the PCA; rate changes mandated by the PCA are recovered by an equal cents per kilowatt hour allocation, and; proposed changes to the FMC rate structure are approved."
Q. Have PCA computations ever been changed by the Commission?
A. The PCA methodology still includes only fuel, purchased power, surplus sales, and Astaris (formerly "FMC") components. Deviations in expenses are still tracked at 90 percent with the exception of CSPP expenses that are tracked at 100 percent. The load adjustment within the PCA has not been modified.
Although the Commission has not changed the basic PCA methodology, there have been four specific computational changes to the PCA that I consider significant. Three of the computational changes involved correction or updating of PCA constants. Two of these updates were the result of cases secondary to the actual PCA proceedings. All four computational changes were approved on a prospective basis.
Q. What was the first of the computational changes to the PCA authorized by Commission order?
A. The first computational change was to correct an erroneous PCA constant. This occurred during the Company's 1996 annual PCA filing, which was offered as Case No. IPC-E-96-5.
In that case, the Company noted that it had erroneously filed the 1995 PCA calculation (and all previous PCA calculations) using a system sales number rather than the appropriate Idaho jurisdictional sales number. The Company calculated the 1996 PCA using the Idaho jurisdictional sales number and requested that this be approved in addition to an adjustment to the true-up balance by re-calculating the 1995 PCA with the appropriate value. In their comments opposing parties argued that the Company was attempting to use retroactive ratemaking for purposes of the PCA. Additionally, parties commented that the Commission, in Order 24806, had specifically limited the time period for the true-up deferral, stating that the differences between projected power supply costs and actual power supply costs are to be deferred for later true-up and those differences are to be accumulated during the 12-month period that a specific PCA forecast would be in effect.
In response to Staff and intervener comments, the Company suggested that a fair solution would be to postpone the correction of this error until the following year and prospectively. In Order No. 26455 (Exhibit 4) the Commission found the following:
"The Commission has reviewed the filings of record, including comments and Company response. The Commission acknowledges that Staff and ICIP support the Company alternative proposal to defer implementation of the change in true-up methodology until next year. The Commission agrees that it is more appropriate and reasonable to calculate the true-up component of the PCA by dividing the deferred expense balance by the Idaho jurisdictional sales volume rather than the normalized system firm load. We find that use of normalized system firm load in prior calculations has resulted in the Company under recovering approximately $333,274 in the 1993-94 true-up and $2,171,661 in the 1994-95 true-up. We agree with the Company that both the utility and its customers should be treated with fairness by this Commission. We find that the alternative proposal, offered by way of settlement, to defer implementation of the change in true-up methodology until next year’s true-up presents a fair, just and equitable result. The resultant PCA rate adjustment from base is -1.635 (mill/kWh) which we find includes the accounting errors identified by Staff in its comments and the related minor changes to the calculation. We find the resulting PCA adjustment to be fair, just and reasonable."
Q. When was the second computational change to the PCA?
A. The second computational change to the PCA was the updating of another PCA constant, which was necessitated after the Company, and its largest customer, FMC (now, Astaris) entered into a new contract. As a result of the contract (dated December 31, 1997), the Company requested that the PCA calculation reflect the new FMC second block revenues as identified by the new contract. At the time of the Company's 1998 annual PCA filing, a joint application to approve the contract between the two companies was pending before the Commission (Case No. IPC-E-97-13). No parties were in opposition to the new contract when the Company filed its annual PCA case (Case No. IPC-E-98-5.) The Commission issued Order No. 27516 (Exhibit 5) approving the Company's request to have the current FMC second block revenues reflected in the PCA forecast equation. Once again the computational change was prospective.
Q. In Case No. IPC-E-98-5, did the Company identify another PCA constant that might require updating?
A. Yes. In the 1998 filing, the Company noted that the QF constant in the PCA calculation was not reflective of actual costs and should be reviewed in the near future, but did not request any changes to the 1998 QF quantification.
Q. Was further action taken on this issue?
A. Yes. As a result of a separate filing, Case No. IPC-E-98-13, the Company requested a change to the then insufficient QF constant. The third computational change approved in Order No. 27997 (Exhibit 6) was to update the QF constant previously identified during the 1998 PCA filing.
Q. What drove the need for a fourth computational change to the PCA?
A. The fourth computational change occurred as a result of the Financial Accounting Standards Emerging Issues Task Force determination (EITF-98-10). On March 18, 1999, the Company notified the Commission of the accounting changes (Exhibit 7 - Mr. Gale's Letter to Ms. Miller.) Confirmation of the notification letter was received on April 7, 1999 (Exhibit 8 - Ms. Miller's Letter to Mr. Gale.) In Order No. 28049 (Exhibit 9) issued in the 1999 PCA case (Case No. IPC-E-99-3) the Commission directed the Staff to coordinate with the Company and other interested parties to:
"determine, informally, how best to address the issue. Those parties might consider conducting a workshop. If necessary, any or all of them are free to petition this Commission to initiate a formal case. Regardless, we expect that some written work product will ultimately emanate from the efforts of the parties containing an analysis of the issue and a recommendation regarding what action, if any, is needed by this Commission."
A workshop was held at the offices of Idaho Power Company in Boise on September 23, 1999 to address the issue. Following the workshop, Staff generated a memorandum (Exhibit 10 - Memorandum dated February 14, 2000) that summarized the outcome of the workshop, which was presented to the Commission. In Order No. 28358 (Exhibit 11) issued as a result of the Company's 2000 annual PCA filing, (Case No. IPC-E-00-6) the Commission acknowledged the Staff Memorandum addressing the accounting change concerns raised by opposing parties and their request to initiate a separate proceeding to review the current method for compensating Idaho Power and its shareholders for operating Idaho Power and stated that this request was "outside the scope of this proceeding." New accounting rules were established which included guidelines to separate "energy contracts" from "energy trading contracts" for purposes of accounting, including accounting of revenues and expenses for the annual PCA.
Q. What additional changes did the Company make that related to the accounting issue?
A. The Company filed an application with the Commission for approval of an agreement for electricity supply and management services between Idaho Power Company and IDACORP Energy Solutions, LP. (See Exhibit 12, Notice of Application, Case No. IPC-E-00-13.) This agreement would further remove the "non-operating transactions" (e.g. wholesale power market sales that do no involve sales from the system resources and are not related to balancing system loads and resources) from the Company's accounting. A Stipulation was issued (Exhibit 13) which specifically defined the terms under which the two entities (Idaho Power Company and IDACORP Energy Solutions, LP) would operate within the Agreement for Electricity Supply and Management Services. The Commission, in Order No. 28596, Case No. IPC-E-00-13 (Exhibit 14) which followed the Company's issuance of the signed Stipulation, found that:
"public interest was well served by the procedure adopted in this case, i.e. the two public workshops and an opportunity for written comments. The resultant Stipulation, we find, has improved the underlying Agreement and dispensed with the necessity of further proceedings. IDAPA 31.01.01.204. We note that the ICIP, while not signing the Stipulation, expressly states that it does not object to the continued use of Modified Procedure in this case. We accept the case as fully submitted and find that we have an adequate record to fully consider the issues presented by the Company's Application.

Regarding the IPCo/IES Agreement, we find that the Agreement establishes a reasonable and transparent structure for prioritizing, protecting and serving native load requirements. We are convinced that the Agreement gives the Company's native load customers priority and the economic use and dispatch of Company generation resources, transmission and distribution facilities. In distinguishing between operating and non-operating transactions, it also provides a reasonable means of assuring that the Company's native load customers are not saddled with those risks unrelated to providing regulated utility services."
Q. Has the Commission ever issued an order, which expands the accounts that are to be included in the Company's PCA methodology?
A. No.
Q. Does the Commission require that the Company file a monthly PCA true-up report?
A. Yes, IPUC Order 24806 requires Idaho Power to file a PCA true-up report monthly and at the end of a PCA year the final monthly true-up report is used as an Exhibit in the Company's annual PCA filing. Exhibit 15 is a representative copy of the monthly true-up report provided to the Commission in Case No. IPC-E-01-07. The report tracks the actual PCA component revenues and expenses compared to the previous year’s projections, month by month with the differences accumulated in a deferred account (FERC Account 182.3). Carrying charges are then applied monthly.
Q. Are the utility’s PCA revenues and expenses reported on a system basis in the PCA report?
A. Yes, the report begins with system values for PCA revenues and expenses, which are adjusted to reflect the efficiency incentive (90% sharing) and the Idaho retail jurisdictional percentage (85% allocation). The only exception as previously stated is the efficiency incentive applied to Cogeneration and Small Power Producers payments that is 100% before it is jurisdictionally allocated. These sharing percentages and allocation factors are set forth in Order 24806.
Q. Please describe in detail the computations set out in the PCA true-up report.
A. Referring to Exhibit 15, lines 5-7 quantify the anticipated revenues to be derived from PCA rates resulting from the previous PCA year forecast of net power supply expenses. Lines 10-13 quantify and value the difference in actual total system firm load and normalized total system firm load as set in the last general revenue requirements case. Lines 16-36 quantify the difference between actual fuel expense (FERC Account 501), non-firm purchased power expense (FERC Account 555), less surplus sales revenue (FERC Account 447) and Astaris second block revenue (FERC Account 442) as compared to base levels for the same items as set in the last general revenue requirements case. Lines 38-47 quantify the difference in actual cogeneration and small power purchased power (FERC Account 555) and the base level set in the last general revenue requirements case. Lines 52-58 reflect the monthly increment and the accumulated balance of the total PCA component expenses to be deferred. Lines 62-68 reflect the monthly computation of interest (carrying charge) and the accumulated interest balance. Line 70 reflects the total balance of PCA component expenses deferred including interest to be recovered in the next PCA rate case.
Q. What is the source of the total system revenues and expenses contained in the monthly report?
A. The Financial Accounting Department obtains this information monthly from the actual books and records of the Company.
Q. The Commission has ordered the deferral of $51,234,902 relating to what the Commission refers to as issues concerning “trading practices.” Please explain your understanding of the derivation of the $51,234,902. The Company booked $185,649,095 in the PCA true-up account.
A. As I understand the "trading practices" issues, the Commission has deferred approval of booked expenses amounting to $51,234,902, which are related to the pricing of transactions involving certain day-ahead, and real-time power purchases for the utility operating system. Ms. Hoyd has informed me that these purchases were priced as required by IPUC Order 28358 and the Report to the Idaho Public Utilities Commission on Workshop Concerning Energy Trading Contracts and Power Cost Adjustment dated February 14, 2000. Staff re-priced those transactions using a new methodology contending that the actual cost for those purchases should be reduced. Based upon this new methodology, staff reduced the total booked true-up amount of $185,649,095 by $51,234,902.
Q. The Commission has also ordered the deferral of $7,976,701 relating to what the Commission refers to as issues concerning “the November Transaction”. Please explain your understanding as to the derivation of the $7,976,701.
A. The $7,976,701 relating to the "November Transaction Issue" is a Staff computation of cost savings the Company could have realized had it timed a purchase transaction for the system differently. Mr. Anderson’s testimony discusses in detail the events surrounding this transaction. The $7,976,701 amount is based upon the assumption that the purchase should have taken place when the prices were lower. Based upon this quantification the total true-up amount of $185,649,095 was reduced by $7,976,701, resulting in a reduction of the PCA true-up balance by this amount.
Q. In your opinion, are these two adjustments appropriate deductions from the true-up amount of $185,649,095?
A. No, based upon my understanding of the PCA methodology and the explanations provided by Mr. Anderson, Ms. Hoyd and Mr. Gale, the $59,211,603, which has been deferred, should be approved by the Commission for inclusion in the PCA true-up.
Q. Does this conclude your testimony?
A. Yes, it does.
SAID, DI 3
Idaho Power Company

GALE, DI 1
IDAHO POWER COMPANY