Exhibit 99.2

 

 

 

 

 

 

 

BEFORE THE PUBLIC UTILITY COMMISSION
OF OREGON

UE 213

 

In the Matter of: Idaho Power Company’s Request for a General Rate Increase in the Company's Oregon Annual Revenues

 

 

 

 

 

 

 

 

 

STAFF-IDAHO POWER-CUB-OICIP-EP MINERALS

 

JOINT TESTIMONY IN SUPPORT OF
 STIPULATION

 

WITNESSES: 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 16, 2009

 

 

 

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Q.        Who is sponsoring this testimony?

A.         This testimony is jointly sponsored by Idaho Power Company (“Idaho Power” or the “Company”), Staff of the Public Utility Commission of Oregon (“Staff”), the Citizens’ Utility Board of Oregon (“CUB”), Oregon Industrial Customers of Idaho Power. (“OICIP”), and EP Minerals, referred to collectively as the “Parties.”

Q.        Please state your names.

A.         Judy Johnson, Dustin Ball, Gordon Feighner, Dr. Don Reading, and Greg Said.  Ms. Johnson’s qualifications are set forth in Joint Parties/101; Mr. Ball’s qualifications are set forth in Joint Parties/102; Mr. Feighner’s qualifications are set forth in Joint Parties/103; Dr. Reading’s qualifications are set forth in Joint Parties/104, and Mr. Said’s qualifications are set forth in Idaho Power/100. 

Q.        What is the purpose of your testimony?

A.         This testimony describes and supports the Stipulation dated and filed in this case on December 16, 2009, among the Parties (the “Stipulation”).  Our testimony supports all provisions of the Stipulation with two exceptions—CUB does not support the agreement of the other parties as to Residential Rate Design and OICIP believes that the Commission should address certain Schedule 19 service quality issues, as will be discussed in more detail below. 

Q.        How did the Parties arrive at the Stipulation?

A.         Administrative Law Judge Hardie’s Prehearing Conference Memorandum scheduled a settlement conference in this docket on November 4-5, 2009.  The Parties discussed the issues at the settlement conference (EP Minerals did not attend individually, but did through its membership in OICIP), and continued their discussions on a teleconference held on November 20^th.The Parties’ discussions and agreements resulted in the Stipulation. 

 

 

 

 

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Q.        Have all parties in this docket joined in the Stipulation? 

A.         No.  Portland General Electric Company (“PGE”), which has not been an active participant in this docket, is not a party to this Stipulation.  PGE, however, does not object to the Stipulation.

 Background

Q.        Please describe Idaho Power’s original revenue requirement increase request.

A.         On July 31, Idaho Power filed revised tariff sheets for Oregon that would result in a price increase of approximately $7.3 million or 22.6 percent.  Idaho Power based its filing on a 2009  test year.

Q.        Did Staff and other parties conduct a thorough examination of the Company’s filing?

A.         Yes.  The parties conducted extensive discovery on Idaho Power’s filing.  Over the course of this proceeding, the Company provided responses to more than 300 data requests, the vast majority of which were from Staff.  In addition, in late October, Staff members travelled to Idaho Power’s Boise offices to review the underlying accounting data that was the basis for the Company’s filed revenue requirement.  Staff members travelled again to Idaho Power’s Boise offices on November 12, 2009, to review the Company’s method for calculating revenues

Revenue Requirement Increase

Q.        What is the revenue requirement increase to which the Parties agree?

 

 

 

 

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A.         The Parties agree to a base rate revenue requirement increase of $5.0 million, which in conjunction with the other terms in the Stipulation, represents a settlement of all revenue requirement issues in this case.  Attachment A to the Stipulation includes an agreed-upon calculation of the $5.0 million increase in base rates based on the resolution of adjustments proposed by the Parties, as described in further detail later in this Joint Testimony. 

Q.        What is the overall percentage increase to rates resulting from the Stipulation?

A.         The stipulated increase in test period revenue requirement of $ 5.0 million is an approximate 15.4 percent increase to Oregon rates.   

Q.        When will the rates to recover the stipulated revenue requirement increase and new tariff riders go into effect?

A.         The Parties cannot say with certainty when the Commission will order the rates it adopts into effect.  However, the Parties agree to support a schedule that will allow rates to go into effect on March 1, 2010—provided that such a schedule allows CUB an adequate opportunity to litigate the Residential Rate Design issue and OICIP an adequate opportunity to litigate its Schedule 19 service quality issues.

Rate of Return

Q.        Please describe the Stipulation’s terms related to cost of capital.

A.         The Parties agree that the Company’s overall rate of return (“ROR”) should be set at 8.061 percent and that return on equity should be set at 10.175 percent.  The specific rate of return components agreed upon by the Parties are specified in Table 1 below:

Table 1

 

Q.        How did the Parties arrive at their agreement regarding rate of return?

 

 

 

 

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A.         In its filing, Idaho Power proposed that ROE be set at 11.25 percent, and that overall ROR be set at 8.680 percent.  Staff initially proposed that ROE and ROR be set at values lower than those ultimately agreed upon.  However, based upon Settlement discussions[1] the values shown above represent what the Parties believe to be a reasonable compromise, and not outside of the general range of ROE and ROR adopted by the Commission for other Oregon electric utilities.[2]

Calculation of Stipulated Revenue Requirement

Q.        How did the Parties calculate the agreed-upon revenue requirement increase?

A.         For purposes of supporting this Stipulation, the Parties agree to incorporate specific adjustments to the Company’s proposed revenue requirement.  These adjustments are shown on Attachment A to the Stipulation, and reflect adjustments to rate base and to expenses.  These adjustments were based on proposals initiated by Staff prior to the settlement conference.  Subsequent to Settlement discussions, compromises were reached regarding all proposed adjustments to the Company’s filing. However, the Parties expressly agree that their acceptance of the adjustments for the purpose of settlement is not binding in future proceedings and does not imply agreement on the merits of the adjustments.

Q.        What is the adjustment agreed upon by the Parties flowing from the ROR stipulation?

A.         The stipulated revenue requirement includes the 8.061 percent ROR described earlier in the testimony.  This reduces the Company’s requested revenue requirement by approximately $1.1 million.

 

 

 

 

 

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Q.        Please explain the Parties’ agreed-upon adjustment with respect to transmission plant?

A.         In its originally-filed case, Idaho Power had proposed that approximately $762.6 million related to transmission plant-in-service be included in rate base on a total Company basis, an increase of $56.2 million over the Company’s actual year-end 2008 transmission plant-in-service balance. Staff disagreed with the Company’s Test Year forecasting methodology related to “step up stations” and proposed an adjustment to the Company’s filed plant-in-service of approximately $1 million on a total jurisdiction basis, or $6 thousand on an Oregon jurisdictional revenue requirement basis.  After reviewing actual transmission plant investment for 2009 the Company concluded that Staff’s proposal was reasonable for the purposes of settlement.

Q.        Please explain the Parties’ agreed-upon adjustment with respect to distribution plant?

A.         In its original filing, Idaho Power had proposed that approximately $1.292 billion related to distribution plant-in-service be included in rate base on a total Company basis.  This number represented an increase of $83.4 million over the Company’s actual year-end 2008 distribution plant-in-service balance.  At settlement, Staff disagreed with the Company’s Test Year forecasting methodology related to “underground reconstruction of distribution plant” and proposed that Company’s filed plant-in-service be adjusted to remove approximately $5.6 million on a system-basis.  After reviewing actual distribution investment year-to-date for 2009, the Company agreed.  The adjustment to revenue requirement on an Oregon jurisdictional basis is approximately $7,000.

 

 

 

 

 

 

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Q.        Please explain the Parties’ agreement with respect to the General Plant Adjustment.

A.         The Company’s filed case included approximately $256.7 million related to General Plant in rate base on a total Company basis, an increase of $17.4 million over the Company’s actual year-end 2008 general plant-in-service balance. Staff disagreed with the Company’s Test Year forecasting methodology used for a number of General Plant categories including meters, furniture and remodeling and as a compromise the Parties agreed that the Company’s filed revenue requirement be adjusted to remove approximately $97 thousand on an Oregon jurisdictional basis.

  Q.      Did the Parties’ agree to any other adjustments with respect to General Plant?

A.         Yes. Idaho Power had included in its filed revenue requirement $33 thousand on an Oregon jurisdictional basis for the purchase of communication equipment necessary to implement the Company’s advanced metering infrastructure (“AMI”) system.  However, that system has not yet been implemented in Oregon and for that reason the Parties agreed that the costs should be removed from the case. The Parties explicitly acknowledge that it may be appropriate for the Company to recover prudently incurred costs to implement its AMI system once the system has been implemented.

Q.        The Stipulation notes that Idaho Power may be receiving a grant from the federal government under the American Recovery and Reinvestment Act (“ARRA”) to be used to subsidize its “Smart Grid” technology.  Did the Parties come to an agreement as to how such monies should be treated for ratemaking purposes if they are received by Idaho Power.

A          Yes.  The Parties agreed that if Idaho Power receives a government subsidy toward future investments, those amounts received will be included as an offset to rate base in future rate cases.      

 

 

 

 

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Q.        Please explain the Parties’ agreement with respect to Plant Held for Future Use.

A.         Idaho Power had included in its original filing approximately $211 thousand on an Oregon jurisdiction basis for Plant Held for Future Use, related to real property purchased by the Company to be used at some future date.  The Parties acknowledged that Oregon law does not allow the recovery of expenses or a return on investment related to property that is not used and useful and therefore the Parties agreed to remove the $211 thousand related to Plant Held for Future Use, which resulted in a $25 thousand reduction in the Oregon jurisdictional revenue requirement.

Q.        Please describe the Parties agreed-upon adjustment to Wage and Salary.

A.         The Company’s filed request included 2009 Wage and Salary levels based on projections about market wages as applied to Idaho Power’s workforce.  Staff originally proposed that instead the Company’s Wage and Salary be calculated by applying three-year wage and salary formula that had been used by the Commission in other rate cases.  As used by Staff in the past, this method applies the three-year wage model to all non-union employees, but passes through wages and salaries for union employees at contracted levels.  However, in settlement discussions Idaho Power pointed out that the Company does not have union employees but still must compete with other utilities for employees who work in those jobs generally filled with union employees.  If applied as Staff originally proposed, Idaho Power could recover less for those employees’ wages than would a utility with a union work force, thus making it impossible for the Company to compete for skilled labor. In the end, the parties agreed to apply half of the Staff’s initially-proposed adjustment resulting in a $117 thousand revenue requirement reduction on an Oregon jurisdiction basis.

 

 

 

 

 

 

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Q.        What is the Parties’ agreement with respect to Incentives expense?

            In its initial filing, Idaho Power sought to recover approximately $296 thousand on an Oregon jurisdictional basis in expenses related to the Company’s Employee Incentive Plan (“EIP”) for the 2009 Test Year.  This number did not include expenses related to officer incentives or the profit sharing element of the EIP.  Staff had initially taken the position that only 50% of the included EIP expenses should be recoverable, in accordance with Commission precedent allowing only 50% of incentive payments.  However, Idaho Power pointed out that its proposal did not include 100% of incentive payments.  Idaho Power’s filing included only two-thirds of the Test Year incentive payment, the portion of the incentive that is considered by Company to be directly tied to providing a customer-benefit   Accordingly, the Parties agreed to an adjustment to the Incentives category allowing the Company to recover 50% of its total EIP expense.  The Stipulated agreement regarding EIP reduces the Company’s requested revenue requirement by $75,000 on an Oregon jurisdiction basis.

Q.        What is the Parties’ agreed-upon adjustment with respect to meter depreciation.

A.         Idaho Power had included in its case $628,000 on an Oregon jurisdictional basis for meter depreciation associated with the accelerated depreciation of its meters scheduled to be replaced through the AMI program.  It was pointed out by Staff that the Company was recovering this amount through a rider, and so its inclusion in the case would result in a double recovery.  The Company confirmed that Staff was correct and agreed to remove the costs from the case.

Q.        Please explain the Parties’ agreed-upon A&G and O&M adjustments.

 

 

 

 

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A.         Staff disagreed with the Company’s Test Year forecasting methodology used to determine a number of A&G and O&M expense categories including “Outside Services”, medical expense, insurance expense, and various other A&G and O&M expense, and based on Staff’s concerns the Parties agreed to specific reductions to this category of expenses.  However, at the same time, as described in more detail below, the Parties agreed to include certain pension expenses that had been omitted from the Company’s filing.  The net effect of these agreements is an increase to revenue requirement of $150,000. 

Q.        Please explain the Parties’ agreement with respect to Pension expenses.

A.         Prior to the Company filing this case, the Idaho Public Utility Commission (“IPUC”) requested a change in the Company’s treatment of pension expenses. Specifically, the IPUC requested that the Company begin to account for pension expenses on a cash basis instead of accrual basis. As a result, the Company determined that it would be best if the Oregon Commission addressed pension expense in a separate proceeding.  Accordingly the Company did not include pension expense in its filing, and instead, on October 20, 2009, the Company filed an application with the Commission requesting permission to account for pension expenses on a cash basis with the plan to recover such expenses at some point in the future. 

            During settlement discussions, Staff requested and the Company agreed, that the Company should continue to account for pension expense on an accrual basis, consistent with SFAS 87, for the Oregon jurisdiction.

Q.        How will the Company account for the resulting differences in capitalized labor charges between jurisdictions?

 

 

 

 

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A.         The Parties acknowledge that it will not be practicable for Idaho Power to account for differences in capitalized labor charges between jurisdictions within a fixed asset system.  However, the Company has historically capitalized a portion of its labor costs, including SFAS 87 expense.  In order to simulate the historic accounting, without creating an undue burden on the Company, the Parties agree that the Company should be allowed to record the capital portion of its SFAS 87 expense as a regulatory asset, which will be amortized in a manner consistent with the depreciation of electric plant in service.  Further, the parties agree that the revenue requirement adopted by the Commission in this rate case should allow the Company to recover the SFAS 87 pension expense.  Going forward, the Parties agree that the Commission should recognize both a regulatory asset associated with the capital portion of pension expense and the non-capital pension expense component when determining the Company’s revenue requirement.

Q.        Did the Company make any commitments with respect to Pension Expense as part of the Stipulation?

A.         Yes. Should the Commission approve the stipulated provisions related to Pension Expense, the Company has committed to withdraw its request for authority to move to cash-basis accounting for pension expense.

Q         Please explain the Parties’ agreed-upon adjustment with respect to Net Power Supply Expense (“NPSE”).

 

 

 

 

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A.         Idaho Power included in its case approximately $164.6 million on total Company basis related to NPSE. The Company’s filed NPSE was based upon the level of NPSE that is currently reflected in base rates plus the October portion of the Annual Power Cost Update (“APCU”) rate that became effective June 1, 2009 (Order No. 09-186, Docket No. UE 203). Also included in the Company’s filed NPSE was approximately $797.5 thousand of purchased power expense to offset transmission line losses. Staff pointed out that the expense related to these additional power purchases to offset transmission losses are properly recovered through the Company’s APCU, and the Parties agreed that the costs should therefore be removed. Further, the Parties recognized that the NPSE approved by Order No. 09-186 was calculated according to an April 2009 through March 2010 test period and therefore agreed to adjust the level of NPSE in this case to align with the 2009 test year.

The Stipulated NPSE amount is $160.4 million on total Company basis. This amount was calculated by multiplying the 2009 Test Year system-level energy sales by the allowed per-unit base NPSE recovery approved in Order No. 09-186 (14,660,001[3] MWh  x  $10.94 per MWh = $160.4 million). The resulting impact of the Stipulated adjustments to NPSE is a decrease to Oregon jurisdictional NPSE expense of approximately $193 thousand resulting in a total Oregon jurisdictional NPSE expense of $7.4 million. However, because this change in expense also impacts the level of working cash allowance included in rate base, the total adjustment to the Oregon jurisdictional revenue requirement is a decrease of $203 thousand.

Q.        What is the Parties’ agreement with respect to the marginal cost methodology?

A.         The Parties agree that the Company’s marginal cost approach to allocating costs is appropriate and should be adopted with one exception.  The Parties agree that at this time transmission related revenue requirement should be classified as 75% demand-related and 25% energy-related, for the purpose of allocation to the customer classes.

Q.        What is the Parties’ agreement with respect to functionalization of production costs?

A.         Idaho Power has historically separated its functionalized, embedded production costs into energy and demand components, prior to their allocation.  After settlement discussions, the Parties have agreed that it is reasonable for the Company to allocate functionalized production revenue requirement directly and on the basis of each schedule’s combined shares of marginal demand and energy costs.

 

 

 

 

 

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Q.        Please describe the Parties agreement as to Revenue Spread.

A.         All Parties agreed to the Company’s revenue spread as described in the Company’s direct testimony, but with certain exceptions.  Those exceptions are described in the Testimony of George Compton.

Q.        Please describe the Parties’ agreement as to Rate Design.

A.         All Parties—except CUB—came to agreement on Rate Design.  Specifically, the Parties agreed to a rate design that is very close to that proposed by the Company—with certain modifications that were proposed by Staff.  Those modifications are discussed in the Testimony of George Compton.

Q.        What is CUB’s position as to the Rate Design agreed upon by the other parties to this Stipulation?

A.        CUB objects to the Residential Rate Design agreed upon by the other Parties and will file testimony explaining its position on January 19, 2010 pursuant to the schedule adopted by the ALJ on December 9, 2009.

Non-Financial Commitments

Q.        Did the Company make any commitments with respect to terms and conditions of service?

A.         Yes.  At the request of Staff, the Company agreed to withdraw its proposal to implement the Service Establishment Charge, and the Continuous Service Reversion Charge.  The Company also agreed that it would file revisions to Rule H, New Service Attachments and Distribution Line Installments or Alterations, during the first quarter of 2010. 

Q.        Did the Company make any commitments to address concerns of the industrial customers?

A.         Yes.  The Company made two commitments to address concerns voiced by OICIP. 

 

 

 

 

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           The first commitment concerns the EnerNoc demand response program that the Company is offering to its Idaho customers.  The Company plans in 2010 to evaluate the first year operational results of that program, in order to determine whether it will (a) continue the program; and (b) expand the program to its Oregon customers.  Idaho Power commits to sharing the results of this evaluation (subject to confidentiality concerns) with Schedule 19 customers.  The Company agrees also to file a third-party-operated, incentive–based, peak demand reduction program (such as the EnerNoc contract), which will be available to Schedule 19 customers in Oregon during the 2010 peaking season.

Q.        What is the second commitment?

A.         The Company commits to include in its 2009 Integrated Resource Plan 1) a determination of the cost and viability of an incentive-based standby generation program targeted toward Large Power Service (Schedule 19) customers and 2) a description of the Company’s intent to develop such a program through a collaborative approach involving Schedule 19 customers.  The Company commits to making this program available to its Schedule 19 customers provided that it finds that the program will be cost-effective and in the best interests of its customers.

Q.        Does the Stipulation address OICIP’s concerns regarding Schedule 19 service quality standards?

A.         No.  During settlement OICIP expressed concerns regarding the Company’s Schedule 19 service quality.  As a result, OICIP will file testimony on January 19, 2010 pursuant to the schedule adopted by the ALJ on December 9, 2009, requesting that the Commission resolve this issue.

 

 

 

 

 

 

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Other Terms of Stipulation

Q.        Do the terms of the Stipulation apply to other cases?

A.         No, the Stipulation represents a compromise in the positions of the Parties made for this case only.  By entering into the Stipulation, none of the Parties are deemed to have approved, admitted, or consented to the facts, principles, methods, or theories employed in arriving at the terms of the Stipulation, other than those specifically identified in the body of the Stipulation.  No Party has agreed that any provision of the Stipulation is appropriate for resolving issues in any other proceeding, except as specified in the Stipulation.

Q.        If the Commission rejects any part of the Stipulation, are the Parties entitled to reconsider their participation in the Stipulation?

A.         Yes.  The Stipulation provides that if the Commission rejects all or any material portions of the Stipulation, any Party that is disadvantaged by such action shall have the rights provided by OAR 860-014-0085 and shall be entitled to seek reconsideration or appeal of the Commission’s Order.

Reasonableness of the Stipulation

Q.        Have the Parties evaluated the overall fairness of the Stipulation?

A.         Yes.  Each Party has reviewed the revenue requirement adjustments and other terms contained in the Stipulation, as well as the revenue requirement level resulting from its application.  The Parties with the exceptions of CUB and OICIP agree that this Stipulation resolves all issues and results in fair, just, and reasonable rates and should be adopted. CUB disputes the Residential Rate Design portion of the settlement and OICIP has concerns over the Schedule 19 service quality standards.  Both CUB and OICIP will file testimony setting forth their positions on January 19, 2010 pursuant to the schedule adopted by the ALJ on December 9, 2009.

 

 

 

 

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Q.        Please explain why Staff believes that the Commission should approve the Stipulation.

A.         Staff carefully analyzed the Company’s case and responses to data requests and proposed certain adjustments at the time of settlement.  With future Consumer Price Index, investment returns, and expense levels unknown, reasonable minds can disagree on methodologies and escalations in the forecasting of specific items for a future period.  Based upon its review, Staff concludes that the stipulated revenue requirement increase of $5 million represents a compromise of differing positions, results in just, fair, and reasonable rates, and is a reasonable resolution to all unresolved issues regarding revenue requirement.

Q.        Did Staff conclude that the stipulated revenue requirement increase of $5 million was reasonable?

A.         Yes.  Staff considered the stipulated ROR of 8.061 percent, which is a reduction to the currently authorized rate of return of 8.16 percent, to be reasonable. 

Q.        Does Staff support the stipulated adjustment to miscellaneous rate base?

A.         Yes. Staff supports the total revenue requirement adjustments of $ 2,329,000 reflected in the Stipulation. Staff performed a thorough review of the jurisdictional allocation methodology described by Ms. Bowman on pages 17 and 18 of her direct testimony. Further, Staff reviewed the Company’s responses to approximately thirty data requests detailing the plant-in-service included in the rate base proposed by the Company in its filed case. Based upon the results of this review, Staff believes that with the stipulated adjustment the result reasonably reflects Idaho Power’s rate base for the test period.

 

 

 

 

 

 

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Q.        As part of its review of the Company’s proposed rate base, did the Staff evaluate the Company’s proposed plant-in-service to determine that it was consistent with past IRP’s acknowledged by the Commission?

A.         Yes. Following its investigation, the Staff concluded that the plant-in-service included in the Company’s rate base is consistent with past IRP’s acknowledged by the Commission.     

Q.        Please explain why CUB believes that the Commission should approve the Stipulation.    

A.         With the exception of the resolution of Residential Rate Design, CUB believes the settlement is reasonable.  While CUB would always prefer that rates do not increase, that outcome is not supportable in this case.  This case reflects significant capital investment in new generating resources that will provide benefits to customers. CUB believes that this settlement will produce rates that are fair and are representative of the Company’s cost of providing service to customers.  CUB will be providing separate testimony on the Residential Rate Design in response to the terms of the Stipulation on this issue and the supporting testimony.

Q.        Please explain why OICIP and EP Minerals believes that the Commission should approve the Stipulation.

A.         OICIP and EP Minerals believe the Stipulation, with the exception of the service quality issues, achieves a result that properly balances the interests of Idaho Power and customers.  OICIP and EP Minerals believe that the Stipulation, taken in combination with the rate spread and rate design settlement agreement, produces rates that are just and reasonable.  OICIP will be providing separate testimony on the Schedule 19 service quality issues because the Stipulation failed to resolve its concerns.

 

 

 

 

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Q.        Please explain why Idaho Power believes that the Commission should approve the Stipulation.

A.         The Company believes that its proposed revenue increase in this case is well supported and reasonable.  Nevertheless, the Company recognizes that settlement can replace the cost and risk of litigation with efficiency and certainty.  The Company also values the intangible aspects of settled outcomes, including good will from other parties.  For these reasons, the Company was willing to accept a revenue increase that was lower than it requested, along with other concessions from its case position, in return for a Stipulation supporting a 15.4 percent overall net rate increase, effective March 1, 2010. 

Q.        What do the Parties recommend?

A.         The Parties recommend that the Commission adopt the Stipulation and include the terms and conditions in its order in this case (subject to CUB’s additional testimony on Residential Rate Design and the Commission’s ruling thereon).

Q.        Does this conclude your testimony in support of the Stipulation?

A.         Yes.

 

 

 

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