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HomeMy WebLinkAbout20040601Decision Memo.pdfDECISION MEMORANDUM TO:COMMISSIONER KJELLANDER CO MMISSI 0 NER SMITH CO MMISSI 0 NER HANSEN COMMISSION SECRETARY COMMISSION STAFF LEGAL FROM:SCOTT WOODBURY DATE:MAY 27, 2004 SUBJECT:CASE NO. PAC-03-5 - TAX AUDIT PAYMENTS AND SURCHARGE CASE NO. P AC-04-2 - BP A REGIONAL EXCHANGE CREDITS STIPULATIONS AND PROPOSED SETTLEMENT Case No. PAC-03-5 - Background On March 31 , 2003 , PacifiCorp dba Utah Power & Light Company (PacifiCorp; Company) filed an Application with the Idaho Public Utilities Commission (Commission) for an accounting Order allowing PacifiCorp to defer, for regulatory purposes (a) excess costs incurred for forward power purchases made for the summer of 2002, and (b) federal and state payments made in 2002 resulting from Internal Revenue Service Income Tax Audits. Reference Idaho Code ~ 61-524, System of Accounts. On December 21 , 2003, following an informal stay of proceedings, the Company filed an amended Application with the Commission (a) removing its request for deferred accounting authority for summer 2002 excess power purchase costs, (b) providing additional and amended information regarding 2002-2003 tax audit payments, and ( c) requesting approval of a 16-month Schedule 93 surcharge to collect the income tax audit-related payments and to recover a projected under-collection in the present Schedule 93 surcharge for recovery of authorized excess power costs. Reference Order No. 29034, June 8 , 2002. PacifiCorp requests approval of deferred regulatory accounting for federal and state income tax payments made in 2002-2003 resulting from the conclusion of Internal Revenue Service Income Tax Audits for tax years 1994 through 1998, in which the IRS made its final determination of the adjustments to the Company s income tax obligations. Such payments DECISION MEMORANDUM attributable to PacifiCorp s regulated utility operations amounted to approximately $54 million. The revenue requirement associated with the 2002-2003 federal and state tax audit determination payments attributable to Idaho is $4 198 000. See Application, Exhibit No.2 (revised). These IRS audit-related payments, the Company contends, are a legitimate cost of doing business as previously recognized by the Commission. The Company cited Utah Power Light Company, Case No. U-I009-157, Order No. 20523 (May 29, 1986), in which the Commission determined that if the Company could show it paid a liability arising from an IRS Audit , " we will allow it to submit tariffs to recover this alleged liability from its ratepayers as a legitimate expense assuming the audit assessment was not payable from a reserve already accumulated. Also citing In the Matter of the Investigation of the Effects of Revisions of the Federal Income Tax Code Upon the Cost of Service of Regulated Utilities, Case No. U-1500-164, Order No. 21302 (July 1 1987), wherein following passage of the 1986 Tax Reform Act which reduced corporate income tax rates, the Commission allowed the Company to recover the Idaho jurisdictional portion of approximately $25 million paid in 1987 following an IRS audit of 1983 and 1984 taxes. The Company contends the audit payments, which it seeks authority to defer in this case, were not paid from a reserve already funded by Idaho ratepayers. PacifiCorp proposes to account for the federal and state income tax payments, for regulatory purposes, in the following manner: income tax payments will be credited to Account 409, Income Taxes, thereby decreasing the recorded income tax expense, and debiting Account 182.399, Regulatory Assets. Deferred accounting treatment for regulatory purposes, PacifiCorp contends, is an appropriate, just and reasonable means of providing the Company an opportunity to seek recovery of the federal and state IRS audit-related income tax payments incurred by the Company. In its amended Application the Company includes a request for approval of proposed electric service Schedule 93 (proposed Schedule 93) to collect the income tax audit-related payments described in its amended Application and to address the over-collection or under- collection of excess power costs currently being recovered under present electric service Schedule 93 (present Schedule 93). The Company requests that the proposed Schedule 93 be effective immediately upon the expiration of the present Schedule 93 (June 8, 2004). Present Schedule 93 provides that, subject to Commission review and approval, the surcharge may DECISION MEMORANDUM continue at a revised rate to reflect any under-collection or over-collection of the authorized surcharge amount.Order No. 29034, June 8, 2002.Current estimates of the power cost collection under the existing surcharge project an under-collection of approximately $200 000 as of June 8, 2004. PacifiCorp s proposed Schedule 93 includes the projected under-collection of power costs in addition to the requested collection of income tax audit-related payments. approved, the power costs under-collection of approximately $200 000 will be revised based on current actual data prior to implementation of proposed Schedule 93. The deferred amounts collected through the surcharge will not include a carrying charge. The proposed Schedule 93 is designed to recover from tariff customers, on a uniform percentage basis of revenue from each rate schedule, the deferred amounts over a period of approximately 16 months. Proposed Schedule 93 would be applied to customers' bills for electric usage commencing June 08, 2004. Utilizing a test period for the 12-months ending March 31, 2003 , Application Exhibit No.6 shows the effects of proposed Schedule 93 by rate schedule and a worksheet containing derivation of the cents per kilowatt hour surcharges for each rate schedule. For residential customers, the implementation of proposed Schedule 93 would result in a price reduction from current prices averaging 3.3%. Excluding special contracts, commercial and industrial customers would see a price reduction averaging 3.5%. Irrigation customers would see a price reduction averaging 3.6%. The overall effect on Idaho tariff customers would be a price reduction from current levels averaging 3.5%. If the current surcharge is allowed to expire as scheduled on June 08 , 2004, a rate decrease of approximately 5% from current levels will result. The price changes set out in the Company s Application, the Company notes, do not reflect any impact of reductions to the levels of BP A credits that are expected to occur in 2004. On February 4, 2004, the Commission issued Notices of Original and Amended Application, Modified Procedure and Intervention Deadline in Case No. P AC-03-5. Parties requesting and granted intervention were the Idaho Irrigation Pumpers Association, Inc. (Order No. 29438) and the City of Firth (Order No. 29439). Included in the Commission s February 4th Notice was a public notice that Commission Staff had apprised the Commission of its intent to hold public workshops in this matter and to engage in subsequent settlement discussions with the Company and other parties of record. Reference IDAPA 31.01.01.271-279. DECISION MEMORANDUM On March 23 , 2004, the Commission issued Notices of Public Workshop and Comment/Protest Deadline in Case No. PAC-03-5. Public workshops were held on April 21 2004 in Preston, Idaho and on April 22, 2004 in Rexburg, Idaho. The purpose of the workshops was to give customers the opportunity to hear from Commission Staff regarding the Company Application and to ask questions of Staff and Company representatives. The deadline for filing written comments was April 30, 2004. Comments were filed by Commission Staff and a number of the Company s customers. All customers except one oppose the tax audit expense surcharge. Staff Comments Staff in its comments noted that in conjunction with the public workshop held in Rexburg on April 22, Staff met with PacifiCorp, the Idaho Irrigation Pumpers Association and the City of Firth (parties to the case) to discuss possible settlement of the issues. IDAP 31.01.01.272. As reflected in Staff comments: The issues currently subject to resolution in this case are limited to determining the appropriate amount and timing of additional tax expense incurred in 2002 and 2003 that should be subject to recovery. These tax expenses result from IRS audit of Company tax returns filed in 1994 through 1998. The Company has proposed to recover $4.2 million in additional tax expenses over a 16-month period beginning June 8, 2004. The effective date of June 8 is significant because the majority of the 2004 irrigation season remains and it is on that date that the existing Power Cost Surcharge (PCS) expires. The Company indicates that the 16-month recovery period is somewhat arbitrary but is designed to span two irrigation seasons and limit the impact the tax surcharge will have on rates. In addition to its Application to recover tax audit expenses, the Company filed an application on April 21 , 2004, Case No. PAC-04-, to reduce BP A regional exchange credits. The credit reduction reflects both the annual change in BP A credits and the recovery of a negative credit balance booked in 2003/2004. The negative credit balance totaling approximately $5. million results from PacifiCorp continuing to provide a BP credit to its customers in 2003/2004 in excess of the credit amount actually received from BP A. The Company proposes to eliminate this negative balance by reducing the BP A credit provided to customers over a three-year period beginning on June 8, 2004. The final component of customer rates scheduled to change on June 8 , 2004 is a small change in the Rate Mitigation Adjustment (RMA) and a PCS true- up increment reflecting over or under recovery of power supply costs during the 2002-2004 surcharge period. These changes were agreed to by DECISION MEMORANDUM Stipulation of the parties and approved by the Commission in Case No. P AC- 02-1 (Order No. 29034) originally establishing the Power Cost Surcharge. Given the numerous rate and credit changes either scheduled or proposed with an effective date of June 8, 2004, Staff believes a comprehensive settlement can be reached that will resolve all of the issues described above and result in a single rate change in 2004. The majority of PacifiCorp Idaho customers could see a slight decrease or no change compared to rates paid during 2003/2004. 230 customers (Schedule 6A (3.6%) and Schedule 8 (2.95%)) would see a slight increase due to changes in the RMA and BPA credits. Case No. P AC-04-2 - Background On April 21, 2004, PacifiCorp filed an Application with the Commission for approval of reductions in the Bonneville Power Administration (BP A) regional exchange credits. The proposed revisions to the Company s electric Schedule 34 will revise the kilowatt hour credit adjustment for all qualifying kilowatt hours of residential and/or farm use. As a regional utility, PacifiCorp is entitled to participate in the Residential Exchange Program (REP), which extends the benefits of low-cost federal power to residential and small farm consumers served by investor-owned utilities in the region. Section 5c of the Northwest Power Act, 16 D.C. ~ 839(c). The REP is administered by the Bonneville Power Administration. In 2000 BP A offered the region s investor-owned utilities the option of entering into a settlement of the REP (REP Settlement) in lieu of the traditional REP. All the regions ' investor-owned utilities , including PacifiCorp, entered into the REP Settlement. Upon initiation of the REP program, and as required by the REP Settlement, the Company established balancing accounts, tracking the differences in the program credits provided to the Company s customers and the monetary payments received from BP A pursuant to the REP Settlement. As of September 2003, the Idaho balancing accounting showed a deficit of $5.7 million (i., PacifiCorp paid out $5.7 million more in benefits to Idaho residential and small farm customers than PacifiCorp had received from BP A). Following discussions with the Commission Staff, the Idaho Irrigation Pumpers Association, and irrigation customers, the Company decided to seek Commission authorization to correct the deficit in the BP A balancing account in a manner that would ease the customer impact of elimination of the deficit. PacifiCorp proposes to reduce the BP A credit by one-third of the $5.7 million, thereby recovering the negative balance over a three-year period. DECISION MEMORANDUM Additionally, the credit is being reduced to match the level of the annual credit received from BP A with the annual credit passed on to Idaho residential and small farm customers. This reduces the credit by an additional $597 000 per year. The proposed annual reduction for a three-year period would therefore total $2,496 000 ($1 899 000 plus $597 000). Additional adjustments to the BP A credit may be necessary in order to achieve the targeted zero balance in the BP A balancing account by September 30, 2006. PacifiCorp in its filing submits the following exhibits providing additional support for the relief requested: a. Application Table A: Table A shows the net impact by rate schedule of the proposed revision to Schedule 34 including the expiration of the power cost surcharge (Schedule 93) and the implementation of the year 3 rate mitigation adjustment (Schedule 94); b. Application Table B: Table B reflects the calculation of proposed Schedule 34 based on normalized 12 months ended March 31 , 2003; Application Table C: Table C is a balancing account study reflecting the Company s BP A balancing account history for fiscal year 2002-2003. The Table shows the $5.7 million deficit as of September 2003; and d. Application Table D: Table D reflects the Company s Schedule 34 and shows the proposed tariff changes. PacifiCorp requests that the proposed reduction to the Schedule 34 BP A credit be effective on June 8, 2004. The Company requests that the Commission enter an Order authorizing the reduction of the Schedule 34 BP A credit by an annual amount of $2,496 000 for a three-year period, in order to eliminate the $5.7 million deficit currently reflected in the Company s balancing account and to further reflect the net effect of the annual credit received from BP A with the annual credit passed on to Idaho residential and small farm customers. On May 5 2004, the Commission issued Order No. 29489 and Notices of Application and Modified Procedure in Case No. PAC-04-2. The Commission consolidated the case with Case No. PAC-03-5 and established a comment deadline of May 20 2004. The Commission s Order and Notice contained the following language PacifiCorp in its Application moves to consolidate its filing in Case No. P AC-04-2 with the currently pending PacifiCorp Case No. P AC-03- 5. The Company s PAC-03-5 filing is a Company request to recover additional federal and state tax payments made pursuant to IRS audit. A DECISION MEMORANDUM consolidation of the two cases would allow implementation of the net effect of the two referenced dockets at the same time. Original and Supplemental Stipulations - Case Nos. P AC-03-5 and P AC-04- On May 12, 2004, original and supplemental Stipulations in Case Nos. P AC-03- and P AC-04-2 were submitted by PacifiCorp, Commission Staff, Idaho Irrigation Pumpers Association and the City of Firth, all of the active parties in the proceedings. Reference IDAP A 31.01.01.272-274. The Stipulations present a comprehensive settlement of the issues and proposed rate changes presented in the two dockets. Those rate changes (for a proposed June 8 2004 effective date) include: 1. A proposed surcharge to recover tax audit assessment payments made by PacifiCorp in 2002 and 2003; 2. A proposed reduction in the BP A exchange credit; and 3. Other rate changes scheduled to occur on June 8 include the expiration of the Power Cost Surcharge (PCS), a small change in the Rate Mitigation Adjustment (RMA), and a PCS true-up increment. These changes were approved by the Commission in Case No. P AC-02-1 (Order No. 29034). The terms of the Stipulation in Case No. P AC-03-5 are as follows: 8. PacifiCorp shall be allowed to defer for regulatory purposes, and recover through a surcharge as described below, $4 198 000 for the income tax audit payments made in 2002 and 2003 for the audit years 1994-1998. 9. PacifiCorp shall be allowed to implement a surcharge (the "Surcharge designed to recover approximately $4 379 018 ($4 198 000 related to audit payments discussed above plus $181 018 from undercollection of the excess power costs allowed by the Commission in Case No. PAC-02-1) over the period beginning June 8, 2004 and ending September 15, 2005. The Surcharge will be implemented as a line item charge on customers ' bills through Electric Service Schedule No. 93, attached hereto as Attachment A. The amount to be collected through the Surcharge includes the true-up provided for under Order No. 29034 in Case No. PAC-02-1. The Parties agree that the revenue obligations of the various customer classes shall be spread among the classes in the manner described in Attachment B. 10. PacifiCorp shall not file any application with the Commission that may result in an increase in or surcharge on Pacifi Corp s rates to Idaho retail customers that would become effective prior to September 16, 2005. Except as provided in paragraph 12 below this provision shall not preclude the DECISION MEMORANDUM Company from requesting deferral of costs incurred after the date of this stipulation and prior to September 16, 2005 for consideration by the Commission in an appropriate regulatory proceeding for collection from customers beginning on or after September 16 , 2005. 11. PacifiCorp shall file as part of its next general rate case in Idaho a proposed method of recovering payments required as a result of income tax audits, other than through surcharges. 12. If, prior to September 16, 2005 , PacifiCorp makes any payments of federal or state income tax assessments, or both, as a result of IRS audits PacifiCorp shall not seek recovery of such payments in Idaho except through a general rate case. 13. The Parties agree that this Stipulation represents a compromise of the positions of the Parties in this case. Other than the above referenced positions and any testimony filed in support of the approval of this Stipulation, and except to the extent necessary for a Party to explain before the Commission its own statements and positions with respect to the Stipulation all negotiations relating to this Stipulation shall be treated as confidential. The relevant language and terms of the Supplemental Stipulation in consolidated Case Nos. PAC-03-5 and PAC-04-2 are as follows: 3. PacifiCorp asserts that as of September 2003 , the Idaho balancing account showed a BPA exchange credit deficit of $5.million. Following discussions with the Staff, the IIP A irrigation customers and Firth PacifiCorp proposes to reduce the BP A exchange credit by 1/3 of the $5. million, on an annual basis, thereby recovering the negative balance over a three-year period. In addition, PacifiCorp s Application proposes to reduce the BP A exchange credit to match the level of the annual credit received from the BP A with the annual credit passed on to Idaho residential and small farm customers. This reduces the credit by an addition $597 000 per year. The annual reduction in the BP credit would therefore total $2,496 000 ($1 899 000 + 597 000) under PacifiCorp s proposal. 7. With Commission approval, PacifiCorp should implement the proposed BP A exchange credit reduction on June 8 , 2004 as this date coincides with other rate changes viz.the expiration of Pacifi Corp s power cost surcharge authorized in Case No. PAC-02-1 and the proposed initiation of a surcharge for tax audit assessments addressed in Case No. P AC-03- DECISION MEMORANDUM Comments in Support of Original and Supplemental Stipulation Commission Staff was the only party to file comments. Staff recommends that the Commission approve the Stipulation (and Supplemental Stipulation) as filed. As reflected in Staff Comments: The comprehensive settlement submitted to the Commission by PacifiCorp and supported by all parties including the Commission Staff, actually consists of a Stipulation and a Supplemental Stipulation. The Stipulation addresses the following issues associated with the P AC-03-5 Case: a) The $4.2 million tax audit payment deferrals and surcharge recovery over a 16-month period. b) An approximate $200 000 Power Cost surcharge true-up recovery over a 16-month period. c) A commitment by the Company to forego a general rate increase until after September 16, 2005. The Supplemental Stipulation includes the following issues addressed in the PAC-04-2 Case: a) Implementation of a $597 000 reduction in annual BP Residential Exchange Credits b) Recovery over a three-year period of a $ 5.7 million negative residential exchange credit deferral balance created by over- crediting customers in 2003/2004. The terms of the proposed Stipulation and the Supplemental Stipulation referred to from this point forward collectively as the Stipulation, results in no rate increase for most of PacifiCorp s Idaho customers when combined with rate changes already scheduled to take effect on June 8, 2004. While 230 customers served under tariff Schedule 6a and Schedule 8 will receive a slight rate increase (3.6% and 2.95%, respectively) due to reduced BP A exchange credits, many more customers will see a net decrease in rates over those currently in effect. Tax Audit Payments As indicated in prior Staff Comments (Case No. P AC-03-5J, the primary issue subject to resolution in the consolidated case is the amount and timing of additional tax payments incurred in 2002 and 2003 that are subject to deferral and recovery. These additional tax payments result from IRS audit of Company tax returns filed for tax years 1994 through 1998. All other rate DECISION MEMORANDUM changes are either previously scheduled with Commission approval or result from changes in BP A residential exchange credits that are beyond the control of PacifiCorp. PacifiCorp s 03-5 Application for a deferral accounting Order filed in March of 2003 requested deferral of both extraordinary power purchases made in 2001 and federal and state income tax audit payments made in 2002. Upon review of the filing, Staff informally expressed concerns to the Company regarding deferral of additional power purchase costs given the passage of time since the purchases were made and the fact that a surcharge had just been put in place to recover similar extraordinary costs. At the same time Staff requested more information regarding the annual tax expense paid by customers through rates each year and what additional audit payments, if any, might reasonably be subj ect to recovery from customers. As a result of further discussions with the Company and Staff s request for additional information, PacifiCorp filed an amended Application on December 23 , 2003 in the P AC-03-5 case eliminating its request for deferral of extraordinary power supply costs and requesting deferral and recovery of tax audit payments incurred in both 2002 and 2003 for 1994- 1998 tax years. The underlying rationale put forth by the Company and generally accepted by Staff for the purpose of this Stipulation is that aggressively filed income taxes can decrease tax expense included in base rates but can also increase periodic tax payments resulting from IRS audit. Staff agrees with the general proposition that allowing recovery of prudently incurred tax audit payments provides an incentive for utilities to file income taxes aggressively thereby decreasing overall tax expense passed on to customers through rates. Staff also takes note of past Commission Order No. 20523 that recognizes tax audit expense as a potentially legitimate expense possibly subject to recovery through amortization. Staff has verified that additional taxes for the tax periods in question have been paid to the IRS as a result of income tax audit and have not been collected from ratepayers through other means such as tax reserve accounts. Staff notes that the Company s request to recover its additional tax audit payment was made contemporaneous with the IRS tax obligation determination. Consequently, for the purposes of this Stipulation Staff accepts the $4.2 million tax audit payments as legitimate expenses subject to recovery through the proposed 16-month surcharge. At the request of Staff, any future audit payments will not be recovered by surcharge. Instead, PacifiCorp will file in the next Idaho rate case a proposed method of recovering future income tax audit payments, other than through surcharge. DECISION MEMORANDUM BP A Residential Exchange Credits The next most significant issue subj ect to negotiation and settlement in the Stipulation is the recovery of the deferred BP A exchange credit overpayment of $5.7 million. The over payment accrued when BP A reduced credits paid to PacifiCorp beginning in February 2003 but PacifiCorp has not reduced credits paid to its Idaho customers. The reduction in BP A credits is beyond the control of PacifiCorp and constitutes a direct pass through to customers. Staff has verified the overpayment amount and supports the proposed reduction in future BP credits over an approximate 28-month period to eliminate the deferral balance. In addition to recovery of the BP A credit overpayment accrued during 2003 the Stipulation provides for pass through of a further reduction in BP credits of $597 000 per year to reflect the level of BP A credits currently received by PacifiCorp. This reduction is also beyond the control of PacifiCorp and constitutes a direct pass through to customers. Staff has verified the additional reduction in BP A credits going forward and supports the treatment proposed in the Stipulation. The overall net change in exchange credits of $2.496 million per year will be reflected in the tariff Schedule 34. Staff understands that the Company s goal is to achieve a zero balance in the exchange credit overpayment account by September 16, 2006 and believes the target date to be reasonable. Additional adjustment in the Schedule 34 rate may be required depending upon actual credits received from BPA and the annual energy consumption of PacifiCorp s Idaho customers. Scheduled Rate Changes One of the more important events allowing the Stipulation to be implemented with minimal rate increase is the general reduction in rates that is already scheduled to take place on June 8, 2004. The changes include elimination of all but a small portion of the Power Supply Cost (PSC) surcharge put in place by Commission Order No. 29034 issued in 2002. The second year of the surcharge, currently collected at an annual rate of approximately $7.24 million per year, will essentially expire with only a $200 000 true up remaining to be recovered over a 16-month period. While the Commission approved the true-up provision in Order No. 29034, the recovery period is part of the proposed Stipulation in this case. In addition to the scheduled reduction in the PSC surcharge, scheduled rate adjustments will also occur on June 8, 2004 as a result of changes in the Rate Mitigation Adjustment (RMA) previously approved by the Commission in Order No. 29034. The RMA was designed to modify rates and revenue generated from the various customer classes to more closely match revenues with class cost of service. During the PSC surcharge period, the RMA was DECISION MEMORANDUM also utilized to mitigate the surcharge impact on individual customer classes. The third year of the previously approved RMA established a class revenue shift that remains in place until reset in a general rate case. These scheduled adjustments are unchanged by the proposed Stipulation. Rate Impact Summary When all of the rate changes, both previously scheduled and those proposed in the Stipulation are combined on June 8, 2004, only two rate classes experience any rate increase over rates in place the prior year. This increase for some 230 customers in Schedule 6A and Schedule 8 is the result of previously approved and scheduled rate changes. Recovery of the tax audit payments and elimination of the BP A credit over payment balance were applied to each customer class in such a way as to assure that rates decreased stayed the same or increased no more than they otherwise would have absent the Stipulation. Table A attached to the Stipulation shows that irrigation customers will see a decrease of 0.3 %, residential customers will see an overall decrease of 1. and general service customers will see a decrease of 10.8%. Absent continuation of the Schedule 93 surcharge to recover the tax audit expense irrigation customers would experience a 5.9% rate reduction, residential customers would experience a 6.07% reduction and general service customers would see a 16.8% reduction in rates. This assumes that the BPA credit over-payment balance is eliminated over 28 months (or 3 irrigation seasons) without carrying charges as proposed in the Stipulation. The General Rate Moratorium A crucial aspect of the Stipulation for Staff was the Company s commitment to forgo filing a general rate increase that would become effective prior to expiration of the 16-month Schedule 93 tax audit surcharge on September 16 2005. While the Stipulation does not prohibit the Company from filing a general rate case with the Commission prior to that date, general rate changes cannot become effective until that date. From a practical standpoint, this gives Idaho ratepayers a minimum of about 4 to 5 extra months before rates from a general rate case could be put in place. For irrigators, this translates to an extra irrigation season. The assessment of minimum rate commitment benefit is based on the amount of time it would likely take the Company to file a general rate case, have the case processed through the Commission and have new rates implemented absent approval of the Stipulation. Obviously, any rate increase that might result from a general rate case is not known at this time. However, the Company has had general rate cases in all five of its other state jurisdictions within the last two years requesting increases ranging from $125 million in DECISION MEMORANDUM Utah to $16 million in California. Approved rate increases have been in the to 10% range. Consequently, Staff believes the general rate commitment has benefit given what appears to be the Company s ability and incentive to file an Idaho general rate case in a relatively short time frame absent approval of the Stipulation. Conclusions and Recommendations All parties to the consolidated case including the City of Firth, the Idaho Irrigation Pumpers ' Association, PacifiCorp and the Commission Staff support the proposed Stipulation. It allows the Company reasonable recovery of tax audit payments; it allows amortization without carrying charges of BP A credit overpayments; and it includes a general rate moratorium commitment from the Company, all without a significant increase in customer rates. While it is possible that rates could be lower for a short period absent approval of this Stipulation, Staff believes the agreement strikes a reasonable balance of cost recovery for the Company and rate stability for the customers. Therefore Staff recommends that the Commission approve the Stipulation (and Supplemental Stipulation) as filed. Commission Decision: Submitted for the Commission s consideration in consolidated Case Nos. P AC-03- 5 and P AC-04-2 are a Stipulation and Supplemental Stipulation. (Rule 248.) The Stipulation signed by all active parties to the cases are offered as a proposed settlement of the rate issues presented. (Rule 274.Parties contend that the settlement is reasonable and in the public interest. The procedure followed included public workshops, settlement discussions and comment periods. The rate change proposed for June 8 , 2004 includes the following elements: 1. $4 198 000 income tax audit payments 2002-2003 for audit years 1994- 1998 (l6-month surcharge) 2. $181 018 PCA surcharge true-up (16-month surcharge) 3. $597 000 reduction in annual BPA residential exchange credits 4. $5.7 million negative BP exchange credit deferral balance true-up (2003-2004) - (to be recovered $1 899 000/year - 3 years) Also taking effect on June 8 are other scheduled rate changes. The resultant rates are reflected in the attached schedule. Most customer classes will experience a slight decrease in rates. Two DECISION MEMORANDUM hundred and thirty customers served under Schedule 6A and Schedule 8 will receive a slight rate increase (3.6% and 2.95%, respectively). As part of the proposed settlement and discussions leading up to settlement PacifiCorp withdrew its requested recovery of $2.5 million in Idaho for excess forward purchase costs incurred in the summer of 2002. The Company also committed to forego a general rate case increase for 16 months. Staff notes that the Company has had general rate cases in all five of its other state jurisdictions within the last two years. Does the Commission find the proposed settlement as set forth in Stipulations to be reasonable and in the public interest? Ifnot, how does the Commission wish to proceed? Scott Woodbury bls/M:P ACEO305 P ACEO402 sw DECISION MEMORANDUM BlahHI..I Attachment A C. No. 28 First Revised Sheet No. Canceling Original Sheet No. 93 UT AH POWER & LIGHT COMPANY ELECTRIC SERVICE SCHEDULE NO. STATE OF IDAHO POWER COST / TAX SURCHARGE (C) AVAILABILITY: At any point on the Company s interconnected system. APPLICATION: This Schedule shall be applicable to all retail tariff Customers taking service under the terms contained in this Tariff. MONTHLY BILL: In addition to the Monthly Charges contained in the Customer s applicable schedule, all monthly bills shall have applied an amount equal to the product of all metered kilowatt-hours multiplied by the following cents per kilowatt-hour.(D) (D) Schedule 1 Schedule 6 Schedule 6A Schedule 7 Schedule 7 A Schedule 8 Schedule 9 Schedule 10 Schedule 11 Schedule 12 - Street Lighting Schedule 12 - Traffic Signal Schedule 19 Schedule 23 Schedule 23A Schedule 35 Schedule 36 3823 ~ 1196 ~ 0000 ~ 5853 ~ 6468 ~ 0000 ~ 0899 ~ 1696 ~ 1.7652 ~ 7738 ~ 6015 ~ 0.4345 ~ 5298 ~ 5453 ~ 1004 ~ 0814 ~ (N) (N) Submitted Under Docket No. P AC-03- ISStnED:Decernber 23 2003 EFFECTIVE: June 8, 2004 Ta b l e A At t a c h m e n t UT A H P O W E R ES T I M A T E D E F F E C T O F P R O P O S E D P R I C E S ON R E V E N U E S F R O M E L E C T R I C S A L E S T O U L T I M A T E C O N S U M E R S DI S T R I B U T E D B Y R A T E S C H E D U L E S I N I D A H O NO R M A L I Z E D 1 2 M O N T H S E N D E D M A R C H 2 0 0 3 Pr e s e n t R e v e n u e ( $ 0 0 0 ) Pr o p o s e d Ex c l u s i v e o f 8 c h , 3 4 In c l u s i v e o f 8 c h . 3 4 Av g . Lin e Ac c t Sc h . No . o f Ba s e RM A PC S Sc h . Ne t RM A Sc h 9 3 J , Sc b . Pr o p o s e d Cb a n ~ e Pr o p o s e d Ch a n ~ e No . De s c r i p t i o n No . Cu s t MW h Re v . Cr e d i t Re v . ($ 0 0 0 ) Cr e d i t Ne t R e v . ($ 0 0 0 ) Ne t R e v . ($ 0 0 0 ) (I ) (2 ) (3 ) (4 ) (5 ) (6 ) (7 ) (8 ) (9 ) (1 0 ) (I I ) (1 2 ) (1 3 ) (1 4 ) (1 5 ) (1 6 ) (1 7 ) (1 8 ) (1 9 ) (2 0 ) 44 0 Re s i d e n t i a l S a l e s Re s i d e n t i a l S e r v i c e 30 , 15 2 28 3 , 33 0 $2 4 , 29 5 ($ 1 14 2 ) 19 0 ($ 7 , 08 5 ) $1 7 , 25 8 ($ 1 , 97 5 ) $1 , 08 3 68 % ($ 6 , 60 9 ) $2 3 40 3 ($ 9 4 0 ) $1 6 , 79 4 ($ 4 6 4 ) Re s i d e n t i a l O p t i o n a l T O D 15 , 98 7 28 7 , 3 8 3 $1 9 , 67 2 ($ 1 15 5 ) 20 7 ($ 7 , 18 6 ) $1 2 53 8 ($ 6 9 3 ) $2 3 4 1. 2 6 % ($ 6 , 70 4 ) $1 9 , 21 3 ($ 5 1 1 ) $1 2 50 9 ($ 2 9 ) -0 . AG A - Re v e n u e 00 % To t a l R e s i d e n t i a l 46 , 13 8 57 0 71 3 54 3 , 97 0 ($ 2 . 29 7 ) 52 , 3 9 7 ($ 1 4 27 1 ) $2 9 , 79 9 ($ 2 , 66 8 ) 31 7 3.1 6 % ($ \ 3 , 31 3 ) $4 2 62 0 ($ 1 , 45 1 ) $2 9 , 30 7 (5 4 9 2 ) 1.7 % 44 2 Co m m e r c i a l & I n d u s t r i a l Ge n e r a l S e r v i c e - L a r g e P o w e r 96 8 30 1 , 53 5 $1 6 , 55 2 ($ 8 7 5 ) 51 , 26 0 $1 6 , 93 7 $3 6 1 30 % $1 6 91 3 ($ 2 4 ) 51 6 , 91 3 ($ 2 4 ) Ge n e r a l S v c . - L g . P o w e r ( R & F ) 22 6 28 . 99 8 83 4 ($ 1 \ 3 ) S1 2 2 (5 7 2 5 ) $1 , 11 8 00 % ($ 6 7 6 ) $1 , 83 4 ($ 9 ) $1 , 15 8 $4 0 Ge n e r a l S e r v i c e - M e d . V o l t a g e 99 0 51 7 0 . ( 5 1 0 ) $1 2 $1 7 2 00 % $1 7 7 $1 7 7 Ge n e r a l S e r v i c e . H i g h V o l t a g e 86 7 04 8 ($ 2 9 0 ) 53 8 2 $4 , 14 0 58 6 29 % 13 4 ($ 6 ) -0 . 13 4 ($ 6 ) Ir r i g a t i o n 23 6 60 6 , 46 0 $3 2 47 1 94 0 54 7 ($ 2 0 , 48 6 ) $1 8 , 4 7 3 $3 , 94 0 02 9 83 % ($ 1 9 , 02 4 ) $3 7 44 0 ($ 1 51 8 ) $1 8 , 41 6 ($ 5 6 ) Co m m . & I n d . S p a c e H e a t i n g 33 5 11 , 64 6 $8 3 4 ($ 3 1 ) $4 9 $8 5 2 ($ 7 5 ) $5 1 30 % $8 1 0 ($ 4 2 ) $8 1 0 ($ 4 2 ) Ge n e r a l S e r v i c e 95 0 57 2 $7 , 99 5 ($ 2 0 9 ) $3 8 9 $8 , 17 5 ($ 1 19 1 ) $4 9 0 6.3 0 % $7 , 29 4 ($ 8 8 1 ) 10 . 29 4 ($ 8 8 1 ) 10 . Ge n e r a l S e r v i c e ( R & F ) 23 A 30 4 40 7 $\ , 3 9 4 ($ 6 0 ) $6 5 ($ 3 8 5 ) $1 , 01 3 ($ 1 6 3 ) $8 4 30 % ($ 3 5 9 ) $1 , 31 5 ($ 8 4 ) $9 5 6 ($ 5 8 ) Ge n e r a l S e r v i c e O p t i o n a l T O D 88 7 $1 0 6 ($ 6 ) $1 0 8 \. 9 0 % $1 0 8 ($ 0 ) 0.1 % $1 0 8 ($ 0 ) -0 . Sp e c i a l C o n t r a c t s 48 1 15 9 $4 5 , 31 1 $4 5 , 31 1 00 % $4 5 31 I $4 5 , 31 1 AG A - Re v e n u e $2 3 4 $2 3 4 00 % $2 3 4 $2 3 4 To t a l C o m m e r c i a l & I n d u s t r i a l 10 , 03 8 63 8 , 52 3 $1 1 0 94 9 $2 , 34 6 83 4 (5 2 1 59 6 ) $9 6 , 53 3 51 8 10 3 \. 8 6 % ($ 2 0 , 05 9 ) $1 1 5 , 57 0 ($ 2 55 9 ) 59 5 , 51 1 ($ 1 02 2 ) 1.1 % 44 4 Pu b l i c S t r e e t L i j ! h t i n j ! Se c u r i t y A r e a L i g h t i n g 24 1 30 4 57 6 $7 7 ($ 2 0 ) 30 % $6 1 ($ 1 6 ) 20 . $6 1 ($ 1 6 ) 20 . Se c u r i t y A r e a L i g h t i n g ( R & F ) 16 3 12 9 $3 5 ($ 1 ) ($ 3 ) $3 1 ($ 8 ) 30 % ($ 3 ) $2 9 ($ 6 ) 17 . $2 6 ($ 6 ) 18 . Str e e t L i g h t i n g - C o m p a n y 12 8 $3 7 ($ 1 ) 53 7 ($ 1 0 ) 30 % $2 9 ($ 8 ) 21 . $2 9 ($ 8 ) 21 . Str e e t L i g h t i n g - C u s t o m e r 20 4 80 8 - 5 2 2 8 ($ 6 ) $2 3 0 ($ 6 3 ) $1 4 30 % $1 7 9 ($ 5 1 ) 22 . $1 7 9 ($ 5 I ) 22 . Tr a f f i c S i g n a l S y s t e m s 25 3 $2 5 ($ 1 ) $2 5 ($ 7 ) 30 % $2 0 ($ 5 ) 21 . $2 0 ($ 5 ) 21 . AG A - Re v e n u e 00 % To t a l P u b l i c S t r e e t L i g h t i n g 66 0 62 1 $4 0 3 ($ 9 ) $1 2 ($ 3 ) $4 0 3 ($ 1 0 8 ) $2 5 27 % ($ 3 ) $3 2 0 ($ 8 6 ) 21 . $3 1 7 ($ 8 6 ) 21 . To t a l S a l e s t o U l t i m a t e C u s t o m e r s 56 , 83 6 3, 2 1 1 , 85 7 $1 5 5 , 32 3 $4 0 $7 , 24 3 ($ 3 5 , 87 1 ) $1 2 6 73 5 ($ 2 5 8 ) $3 , 4 4 5 2. 2 2 % ($ 3 3 , 37 5 ) $1 5 8 , 50 9 ($ 4 09 6 ) $1 2 5 , 13 4 ($ 1 60 1 ) 1.3 % To t a l S a l e s t o U l t i m a t e C u s t o m e r s ( w / o S p e c i a l C o n t r a c t s ) 56 , 83 4 73 0 , 69 8 $1 1 0 , 01 1 $4 0 24 3 ($ 3 5 , 87 1 ) 58 1 42 4 ($ 2 5 8 ) $3 , 44 5 3. 1 3 % ($ 3 3 , 37 5 ) 51 1 3 19 8 ($ 4 09 6 ) $7 9 , 82 3 ($ 1 60 I ) No t e s : I : P r e s e n t R e v e n u e i s b a s e d o n c u r r e n t R M A a n d P C S r a t e s w h i c h b e c a m e e f f e c t i v e o n J u n e 8 , 2 0 0 3 a n d w i l l e x p i r e o n J u n e 7 , 2 0 0 4 . Th e c w r e n t B P A r a t e b e c a m e e f f e c t i v e o n F e b n w y 1 20 0 3 , 2: P r o p o s e d R M A i s b a s e d o n Y e a r 3 r a t e s w h i c h w i l l b e c o m e e f f e c t i v e o n J u n e 8 , 2 0 0 4 . 3: P r o p o s e d S c h . 9 3 P o w e r C o s t / T a x S u r c h a r g e i s d e s i g n e d t o r e c o v e r a t o t a l o f $ 4 , 37 9 , OI8 b e t w e e n J u n e 8 , 2 0 0 4 a n d S e p t e m b e r 1 5 , 20 0 5 . T h i s a m o u n t i n c l u d e s $ 4 19 8 , 00 0 o f i n c o m e t a x a u d i t p a y m e n t s pl u s $ 1 8 1 , 0 1 8 o f t h e p r o j e c t e d u n r e c o v e r e d p o r t i o n o f c o m b i n e d b a l a n c e o f e x i s t i n g S c h e d u l e 9 3 - Po w e r C o s t S u r c h a r g e a n d S c h e d u l e 9 4 - RM A . T h e p r o j e c t i o n i s b a s e d o n a c t u a l c o l l e c t i o n s b e t w e e n Ju n e 8 , 2 0 0 2 - Fe b r u a r y 2 9 , 20 0 4 a n d t h e f o r e c a s t e d c o l l e c t i o n s b e t w e e n M a r c h I , 2 0 O 3 - Ju n e 7 , 2 0 0 4 4: P r o p o s e d a B P A B a l a n c e a d j u s t m e n t o f - $1 . 9 m i l l i o n . 5: P r o p o s e d S c h 9 3 r a t e d e s i g n i s b a s e d o n t w o r u l e s : R u l e I : O v e r a l l i m p a c t f o r e a c h s c h e d u l e i s c a p p e d a t 0 % o r i t i s r e d u c e d u n t i l s c h e d u l e 93 r e v e n u e i s s e t a t z e r o . R u l e 2 : M a x % S c h 9 3 i s c a p p e d a t 6 . 3 % . Fo n n u l a s : F I = ( 6 ) + ( 7 ) + ( 8 ) + ( 9 ) ; F 2 = ( 1 2 ) / f ( 6 ) + ( 7 ) ) ; F 3 = ( 6 ) + ( I I ) + ( l 2 ) ; F4 = ( l 5 ) - ( 6 ) - ( 7 ) - ( 8 ) ; F 5 - ( l 6 ) / f ( 6 ) + ( 7 ) + ( 8 ) ) ; F 6 = ( 6 ) + ( I I ) + ( 1 2 ) + ( 1 4 ) ; F7 = ( 1 8 ) - ( 1 O ) ; F 8 = ( 1 9 ) / ( 1 0 ) .