Exhibit 99.1

BEFORE THE PUBLIC UTILITY COMMISSION
OF OREGON

UE 213

            This Stipulation is entered into for the purposes of resolving the issues among the parties to this docket.  This Stipulation fully resolves all issues in the docket except the issues of Residential Rate Design and service quality.  All Parties except Citizens’ Utility Board of Oregon (“CUB”) agree upon Residential Rate Design.  In addition, Oregon Industrial Customers of Idaho Power (“OICIP”) has concerns about the Company’s Schedule 19 service quality that are not addressed by the Stipulation.  CUB objects only to the Residential Rate Design portions of this Stipulation and will file, on January 19, 2010,  testimony only in opposition to the Residential Rate Design portion of the Stipulation. OICIP likewise will file, on January 19, 2010, testimony only regarding Schedule 19 service quality.

PARTIES

The parties to this Stipulation are Idaho Power Company (“Idaho Power” or “Company”), Staff of the Public Utility Commission of Oregon (“Staff”), OICIP, EP Minerals, and CUB (the “Parties”).    The Parties constitute all parties to the docket, with the exception of Portland General Electric (“PGE”) who did not actively participate in the docket.

BACKGROUND

1.            On July 31, 2009, Idaho Power filed revised tariff sheets with the Public Utility Commission of Oregon (“Commission”) that would result in a base price increase of approximately $7.3 million or 22.6 percent on an Oregon jurisdictional basis.  The tariff sheets were to be effective on August 31, 2009.  Idaho Power’s filing was based on a 2009 calendar year test period.

2.            At the public meeting on August 25, 2009 the Commission suspended the Company’s revised tariff sheets for a period of nine months.  Pursuant to Administrative Law Judge Lisa Hardie’s Prehearing Conference Memorandum of August 25, 2009, the Parties convened a settlement conference on November 4-5, 2009.  The settlement conference was noticed and all parties attended. 1

3.            As a result of the settlement conference, the Parties have reached a settlement in this case resolving all issues in the case, except for the issues of Residential Rate Design and service quality.  CUB does not agree to the Parties’ resolution of the Residential Rate Design issue and OICIP has unresolved concerns about Schedule 19 service quality.

4.            The net effect of the Stipulation is to reduce Idaho Power’s proposed increase in test period revenue requirement to approximately $5 million, which will result in an overall increase of approximately 15.4 percent.  The parties agree to request a schedule for the remaining procedures in the docket consistent with a rate effective date of March 1, 2010, provided that such a schedule will allow CUB and OICIP adequate time to prepare their respective testimony on Residential Rate Design and service quality.

1 EP Minerals did not attend as a separate entity but rather in its capacity as a member of OICIP.

AGREEMENT

5.            Just and Reasonable Rates: The Parties agree, with the exception of the issue of Residential Rate Design which is being disputed by CUB and service quality which is being disputed by OICIP, to submit this Stipulation to the Commission and request that the Commission approve the Stipulation as presented subject to resolution of CUB’s opposition to the Residential Rate Design issue and OICIP’s concerns regarding Schedule 19 service quality.  The Parties agree that the adjustments—and the rates resulting from their application—are fair just and reasonable subject to OICIP’s position on service quality discussed in paragraph 21 and CUB’s position on Residential Rate Design discussed in paragraph 21.

6.            Revenue Requirement: The Parties agree to a revenue requirement increase of $5 million in base rates on an Oregon jurisdictional basis, which represents an increase of 15.4 percent from the current $32.4 million Oregon revenues.  Exhibit A details the agreed-upon calculation of the 15.4 percent increase in base rates based on resolution by the Parties of adjustments to the Company’s request. The Parties agree that the acceptance of these adjustments for the purposes of settlement is not acceptance of any methodology underlying the various adjustments, is not binding on Parties in future proceedings, and does not imply agreement on the merits of the adjustments. 

7.            Rate of Return:  The Parties agree that the Company’s ROE should be set at 10.175 percent and the Company’s overall ROR should be set at 8.061 percent.  The individual components in the assumed capital structure should be set as shown in the table below:

8.            AMI Communication Equipment:  The Parties agree that it is appropriate to remove from the case capital expense associated with communication equipment acquired to implement the Company’s Advanced Metering Infrastructure (“AMI”) system, given that AMI has not yet been implemented in the Company’s Oregon jurisdiction.  However, the Parties recognize that the Company will in the future make a request to recover any prudently-incurred investment in such equipment once AMI is implemented in Oregon.  On a related topic, the Parties recognize that Idaho Power may receive federal funds under the American Reinvestment and Recovery Act (“ARRA”) that will be used to subsidize certain additional Smart Grid technologies.  In the event such funds are received, those amounts received will be utilized as an offset to investments reducing the net rate base upon which future returns will be determined.

9.            Net Power Supply Expense:  The Company’s filed case included a level of net power supply expense (“NPSE”) equivalent to that which 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). Because the NPSE approved by Order No. 09-186 was calculated according to a April 2009 through March 2010 test period, Parties agree that it is appropriate to adjust the level of NPSE in this case to align with the 2009 calendar-year test period. Further the Parties agree that, on a going forward basis, the level of net power supply expense recovery included in the Company’s base rates is $10.94 per megawatt-hour and that the $10.94 rate will become the base from which future APCU rates will be determined.    

10.         Pension Expense:  The Company’s filed case did not include any expense related to pension.  On October 20, 2009, the Company filed an application with the Commission requesting permission to account for pension expenses on a cash basis as opposed to accrual basis, with the plan to recover such expenses at some point in the future.  As a result of settlement discussions the Parties agree that the Company should continue to account for pension expense on an accrual basis, consistent with SFAS 87.  The Parties acknowledge that it is not practicable for Idaho Power to account for differences in capitalized labor charges between jurisdictions within a fixed asset system. However, Idaho Power has historically capitalized a portion of its labor costs, including SFAS 87 expense. In order to simulate the historic accounting without creating undue burden, the Parties agree that the Company should be allowed to record the capital portion of its SFAS 87 expense as a regulatory asset. The regulatory asset will be amortized in a manner consistent with the depreciation of electric plant in service and will be reviewed by the Commission for inclusion in rates in a subsequent rate proceeding. The capital portion of pension expense in the fixed-asset system will be removed from net plant to prevent any double recovery of pension expenses.  Further the Parties agree that the stipulated revenue requirement adopted by the Commission in this rate case includes an SFAS 87 pension expense.  The Parties agree that, on a going forward basis, 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. If the Commission adopts this

provision, the Company agrees to withdraw its request to move to a cash basis account for pension expense.

11.           Marginal Cost Methodology:  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 percent demand-related and 25 percent energy-related for the purpose of allocation to customer classes.

12.         Functionalization of Production Costs:  Idaho Power has historically separated its functionalized, embedded production costs into energy and demand components prior to their allocation.  Instead, the Parties agree that the functionalized production revenue requirement should be allocated directly and on the basis of each schedule’s combined shares of marginal demand and energy costs.

13.         Revenue Spread:  Except to the extent that it is inconsistent with paragraph 11 regarding allocation of the transmission-related revenue requirement to customer classes, the Parties agree to implement Staff’s proposed changes to the Company’s rate spread, as shown on Exhibit B. The agreed upon approach to revenue spread results in a reduction in the proportion of revenue requirement allocated to Residential Service, Small General Service, Large General Service-Secondary Voltage Level and Agricultural Irrigation Service.  The remainder of the Company’s customer classes receive a larger allocation of revenue requirement with the exception of Large Power Service-Transmission Voltage Level and Area Lighting Service which continue to receive no increase.

14.         Rate Design:  The Parties, with the exception of CUB, agree that Idaho Power’s proposed rate design should be adopted as modified below:

a.    The residential service charge should be increased to $8.00 a month as opposed to the $10.00 a month originally proposed by the Company;

b.    The upper end of the first residential usage block should be increased from 800 kWh to 1000 kWh, with the rate charge for the first block remaining the same throughout the year. 

c.    The Small General Service (Schedule 7) energy rate inversion point should be elevated from 300 kWh to 500 kWh.

CUB intends to file testimony in opposition to the residential portion of this  Rate Design.

15.         Rule F Modifications:  Idaho Power agrees to withdraw its proposal to implement the (a) Service Establishment Charge found in proposed Rule F, section (1); and (b) Continuous Service Reversion Charge, found in proposed Rule F, section (2).

16.         Rule H: Idaho Power agrees that by March 31, 2010, it will file revisions to Rule H, New Service Attachments and Distribution Line Installations or Alterations.

17.         Rule K: Idaho Power agrees to withdraw its proposed additional language to Rule K, paragraph 4, and address any addition of the proposed language at future workshops to be held with Schedule 19 customers and the Oregon Commission Staff. 

18.         EnerNoc Program:  In 2010 the Company plans to evaluate the first year operational results of the EnerNoc program it has conducted in its Idaho jurisdiction.  Idaho Power commits to sharing the results of this review (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.

19.  Diesel Standby:  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 in Oregon provided that it finds that the program will be cost-effective and in the best interests of its customers.

20.         CUB’s Position:  CUB agrees with and supports all aspects of this Stipulation except that CUB does not agree with the stipulated Residential Rate Design. CUB intends to challenge this aspect of the Stipulation.

21.         OICIP’s Position:  OICIP agrees with and supports all aspects of this Stipulation except that OICIP will request that the Commission in this case address Schedule 19 service quality. 

22.         This Stipulation will be offered into the record of this proceeding as evidence pursuant to OAR 860-014-0085.  With the exception of CUB’s opposition to Residential Rate Design and OICIP’s position with respect to Schedule 19 service quality standards, the Parties agree to support this Stipulation throughout this proceeding and any appeal (if necessary), provide witnesses to sponsor this Stipulation at the hearing and recommend that the Commission issue an order adopting the settlements contained herein.  The two exceptions are that the Parties acknowledge that CUB opposes the current Residential Rate Design settlement proposal and that CUB will submit testimony, on January 19, 2010, in opposition to the Residential Rate Design portion of the Stipulation.  The Parties also acknowledge that OICIP will challenge the Company’s Schedule 19 service quality and will submit testimony, on January 19, 2010, to address its concerns.

23.         The Parties have negotiated this Stipulation as an integrated document.  If the Commission rejects all or any material portion of this Stipulation or imposes

additional material conditions in approving this Stipulation, any party disadvantaged by such action shall have the rights provided in OAR 860-014-0085 and shall be entitled to seek reconsideration or appeal of the Commission’s order.

24.         By entering into this Stipulation, no Party shall be deemed to have approved, admitted, or consented to the facts, principles, methods, or theories employed by any other Party in arriving at the terms of the Stipulation, other than those specifically identified in the body of this Stipulation.  No party shall be deemed to have agreed that any provision of this Stipulation is appropriate for resolving issues in any other proceeding, except as specifically identified in this Stipulation.

25.         This Stipulation may be executed in counterparts and each signed counterpart shall constitute an original document.

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