Idacorp - 10-Q quarterly report FY

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Idaho Power Company
Condensed Consolidated Statements of Income
(unaudited)

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Idaho Power Company
Condensed Consolidated Balance Sheets
(unaudited)

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Idaho Power Company
Condensed Consolidated Balance Sheets
(unaudited)

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Idaho Power Company
Condensed Consolidated Statements of Capitalization
(unaudited)

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Idaho Power Company

Condensed Consolidated Statements of Cash Flows
(unaudited)

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Idaho Power Company
Condensed Consolidated Statements of Comprehensive Income
(unaudited)

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IDACORP, INC. AND IDAHO POWER COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

This Quarterly Report on Form 10-Q is a combined report of IDACORP, Inc. (IDACORP) and Idaho Power Company (Idaho Power).  Therefore, the Notes to the condensed consolidated financial statements apply to both IDACORP and Idaho Power.  However, Idaho Power makes no representation as to the information relating to IDACORP’s other operations.

Nature of Business

IDACORP is a holding company formed in 1998 whose principal operating subsidiary is Idaho Power.  IDACORP is subject to the provisions of the Public Utility Holding Company Act of 2005, which provides certain access to books and records to the Federal Energy Regulatory Commission (FERC) and state utility regulatory commissions and imposes certain record retention and reporting requirements on IDACORP.

Idaho Power is an electric utility with a service territory covering approximately 24,000 square miles in southern Idaho and eastern Oregon.  Idaho Power is regulated by the FERC and the state regulatory commissions of Idaho and Oregon.  Idaho Power is the parent of Idaho Energy Resources Co. (IERCo), a joint venturer in Bridger Coal Company (BCC), which supplies coal to the Jim Bridger generating plant owned in part by Idaho Power.

IDACORP’s other subsidiaries include IDACORP Financial Services, Inc. (IFS), an investor in affordable housing and other real estate investments; Ida-West Energy Company (Ida-West), an operator of small hydroelectric generation projects that satisfy the requirements of the Public Utility Regulatory Policies Act of 1978 (PURPA); and IDACORP Energy (IE), a marketer of energy commodities, which wound down operations in 2003.

Principles of Consolidation

IDACORP’s and Idaho Power’s consolidated financial statements include the accounts of each company, the subsidiaries that the companies control, and any variable interest entities (VIEs) for which the companies are the primary beneficiaries.  All significant intercompany balances have been eliminated in consolidation.  Investments in subsidiaries that the companies do not control and investments in VIEs for which the companies are not the primary beneficiaries, but have the ability to exercise significant influence over operating and financial policies, are accounted for using the equity method of accounting.

In January 2010, IDACORP and Idaho Power adopted amendments to prior consolidation guidance.  The amendments affected the overall consolidation analysis of VIEs and required IDACORP and Idaho Power to reconsider their previous conclusions relating to the consolidation of VIEs, including (1) whether an entity is a VIE, (2) whether either IDACORP or Idaho Power are the VIE’s primary beneficiary, and (3) what type of financial statement disclosures are required.  The adoption of this guidance did not change the entities that IDACORP or Idaho Power consolidate.

The entities that IDACORP and Idaho Power consolidate consist primarily of the wholly-owned subsidiaries discussed above.  In addition, IDACORP consolidates one VIE, Marysville Hydro Partners (Marysville), which is a joint venture owned 50 percent by Ida-West and 50 percent by Environmental Energy Company (EEC).  Marysville has approximately $25 million of assets, primarily a hydroelectric plant, and approximately $17 million of intercompany long-term debt, which is eliminated in consolidation.  EEC has borrowed amounts from Ida-West to fund a portion of its required capital contributions to Marysville.  The loans are payable from EEC’s share of distributions and are secured by the stock of EEC and EEC’s interest in Marysville.  Ida-West is the primary beneficiary because the ownership of the intercompany note and the EEC note result in it controlling the entity.  Creditors of Marysville have no recourse to the general credit of IDACORP and there are no other arrangements that could require IDACORP to provide financial support to Marysville or expose IDACORP to losses.

Through IERCo, Idaho Power holds a variable interest in BCC, a VIE for which it is not the primary beneficiary.  IERCo is not the primary beneficiary because the power to direct the activities that most significantly impact the economic performance of BCC is shared with the joint venture partner.  IERCo’s carrying value is $87 million and its maximum exposure to loss at BCC is the carrying value, any additional future contributions to the mine and the $63 million guarantee for reclamation costs at the mine which is discussed further in “Note 8 – Commitments.”

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Through IFS, IDACORP also holds variable interests in VIEs for which it is not the primary beneficiary.  These VIEs are historic rehabilitation and affordable housing developments in which IFS holds limited partnership interests ranging from five to 99 percent.  As a limited partner, IFS does not control these entities and they are not consolidated.  These investments were acquired between 1996 and 2010.  IFS’s maximum exposure to loss in these developments is limited to its net carrying value, which was $82 million at March 31, 2010.

Financial Statements

In the opinion of IDACORP and Idaho Power, the accompanying unaudited condensed consolidated financial statements contain all adjustments necessary to present fairly their consolidated financial positions as of March 31, 2010, and consolidated results of operations for the three months ended March 31, 2010, and 2009, and consolidated cash flows for the three months ended March 31, 2010, and 2009.  These adjustments are of a normal and recurring nature.  These financial statements do not contain the complete detail or footnote disclosure concerning accounting policies and other matters that would be included in full-year financial statements and should be read in conjunction with the audited consolidated financial statements included in IDACORP’s and Idaho Power’s Annual Report on Form 10-K for the year ended December 31, 2009.  The results of operations for the interim periods are not necessarily indicative of the results to be expected for the full year.

Use of Estimates

The preparation of condensed consolidated financial statements in accordance with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent liabilities, as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.  Actual results experienced could differ materially from those estimates.

Reclassifications

Certain prior year amounts have been reclassified to conform to the current year presentation.  The reclassifications did not impact IDACORP’s and Idaho Power’s net income or total equity, and include the following:

•        Third-party transmission expense was combined with purchased power in IDACORP and Idaho Power’s condensed consolidated statements of income as the balance of the third party transmission expense alone is immaterial;

•        Gain on sale of emission allowances was combined with other operations and maintenance in IDACORP and Idaho Power’s condensed consolidated statements of income as the balance of gain on sale of emission allowances alone is immaterial;

•        Other operations and maintenance in the operating expenses section of Idaho Power’s condensed consolidated statements of income were combined to be consistent with presentation in IDACORP’s condensed consolidated statements of income;

•        Allowance for uncollectible accounts was offset against associated accounts receivable and presented in a parenthetical notation in IDACORP and Idaho Power’s condensed consolidated balance sheets;

•        Excess tax benefit from share-based payment arrangements was combined with other non-cash adjustments to net income in the operating section and with other in the financing section of IDACORP’s condensed consolidated statements of cash flows; and

•        Amortization of affordable housing was removed from depreciation and amortization and combined with undistributed earnings of unconsolidated subsidiaries, the total of which was then separated into losses (earnings) of unconsolidated equity-method investments and distributions from unconsolidated equity method investments in the operating section of IDACORP’s condensed consolidated statements of cash flows.

2.  INCOME TAXES:

In accordance with interim reporting requirements, IDACORP and Idaho Power use an estimated annual effective tax rate for computing provisions for income taxes.  An estimate of annual income tax expense (or benefit) is made each interim period using estimates for annual pre-tax income, income tax adjustments and tax credits.  The estimated annual effective tax rates do not include discrete events such as tax law changes, examination settlements or method changes.  Discrete events are recorded in the period in which they occur.

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The estimated annual effective tax rate is applied to year-to-date pre-tax income to achieve income tax expense (or benefit) for the interim period consistent with the annual estimate.  In subsequent interim periods, income tax expense (or benefit) for the period is computed as the difference between the year-to-date amount reported for the previous interim period and the current period’s year-to-date amount.

An analysis of income tax expense for the three months ending March 31 is as follows (in thousands of dollars):

The decrease in the 2010 estimated annual effective tax rates from 2009 is primarily due to lower pre-tax earnings at IDACORP and Idaho Power and Idaho Power’s additional amortization of accumulated deferred investment tax credits (ADITC), partially offset by a charge related to the federal health care legislation enacted in the first quarter of 2010.  Regulatory flow-through tax adjustments at Idaho Power and tax credits at IFS were comparable quarter-over-quarter.  For further information regarding ADITC amortization, see “Note 3 – REGULATORY MATTERS - Idaho Settlement Agreement.”

The Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act were enacted in March 2010.  One provision of this legislation eliminates the deductibility of employer health care costs for retiree prescription drug expenses that are covered by federal subsidy payments equivalent to Medicare Part D.  While this provision is not effective until 2013, relevant income tax accounting guidance requires recognition of the future effects of new law in the period of enactment.  Due to the regulatory treatment of postretirement benefit costs, the increase in certain postretirement costs relating to the legislation is deferred as a regulatory asset.  Accordingly, Idaho Power reduced its deferred tax asset related to future deductible retiree prescription drug expenses by $2.3 million, increased regulatory assets by $2.4 million, increased deferred tax liabilities by $1 million and incurred a charge of $0.9 million for the three months ended March 31, 2010.

Status of Audit Proceedings

In May 2009, IDACORP formally entered the Internal Revenue Service (IRS) Compliance Assurance Process (CAP) program for its 2009 tax year.  The CAP program provides for IRS examination throughout the year.  The 2009 examination is expected to be completed in 2010.  In January 2010, IDACORP was accepted into CAP for its 2010 tax year.  IDACORP and Idaho Power are unable to predict the outcome of these examinations.

Specifically within the 2009 CAP examination, the IRS began its audit of Idaho Power’s current method of uniform capitalization.  In September 2009, the IRS issued Industry Director Directive #5 (IDD), which discusses the IRS’s compliance priorities and audit techniques related to the allocation of mixed service costs in the uniform capitalization methods of electric utilities.  The IRS and Idaho Power are jointly working through the impact the IDD guidance has on Idaho Power’s uniform capitalization method.  Idaho Power expects that the examination will be completed during 2010.  Resolution of this matter would result in a decrease to Idaho Power’s unrecognized tax benefits for its 2009 uniform capitalization deduction by $1.1 million, may reduce Idaho Power’s need to amortize additional ADITC in 2010 and is not expected to have an adverse effect on Idaho Power’s financial position, results of operations, or cash flows.

3.  REGULATORY MATTERS:

Idaho Settlement Agreement

On January 13, 2010, the Idaho Public Utilities Commission (IPUC) approved a settlement agreement among Idaho Power, several of Idaho Power’s customers, the IPUC Staff and others.  Significant elements of the settlement agreement include:

•        A general rate moratorium in effect until January 1, 2012.  The moratorium does not apply to other specified revenue requirement proceedings, such as the power cost adjustment (PCA), the fixed cost adjustment (FCA), pension funding, advanced metering infrastructure (AMI), energy efficiency rider, and government imposed fees.

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•        A specified distribution of the expected reduction in 2010 PCA rates that would reduce customer rates, provide some general rate relief to Idaho Power and reset base power supply costs for the PCA.  This provision anticipated a significant reduction in PCA rates for the 2010-2011 PCA year.  The PCA reduction and base rate adjustment is discussed in “2010 PCA filing” below.

•        A provision to share with Idaho customers 50 percent of any Idaho-jurisdictional earnings in excess of a 10.5 percent return on equity in any calendar year from 2009 to 2011.

•        A provision to allow additional amortization of ADITC if Idaho Power’s actual return on equity in its Idaho jurisdiction is below 9.5 percent in any calendar year from 2009 to 2011.  Idaho Power is permitted to amortize additional ADITC in an amount up to $45 million over the three-year period, but could use no more that $15 million in any one year unless there is a carryover.  Carryover amounts are added to the $15 million annual allowance up to a maximum amortization of $25 million in any one year.

Because Idaho Power’s 2009 Idaho-jurisdiction return on equity was between 9.5 and 10.5 percent, the sharing and additional amortization provisions were not triggered, and the ADITC available for additional amortization in 2010 is $25 million.  For the three months ended March 31, 2010, Idaho Power recorded additional ADITC amortization of $4.5 million as a result of including an estimated annual amount in its effective tax rate.  The actual amount of additional ADITC recorded in the full year 2010 will depend on Idaho Power’s annual return on year-end equity, and the amounts recorded in each quarter will vary and may ultimately be reversed.

The agreement also included a provision to reestablish the base level for net power supply costs effective with the June 1, 2010, PCA rate change.  On April 13, 2010, the IPUC approved an increase of up to $63.7 million for such base net power supply costs, deferring final calculation to Idaho Power’s 2010 PCA case.  The open issue relates to Idaho Power’s proposed increase of $25 million in coal supply costs for the Jim Bridger plant.  The increase in base net power supply costs is expected to bring Idaho Power’s total base net power supply costs closer to its actual net power supply costs, and therefore reduce the magnitude of Idaho Power’s future annual PCA adjustments.

2010 PCA Filing

On April 15, 2010, Idaho Power made its annual PCA filing with the IPUC, requesting approval of its 2010 PCA and an increase in base rates pursuant to the terms of the settlement agreement.  As filed, these two rate adjustments would be a $146.7 million 2010 PCA reduction and an $88.7 million increase to base rates, both to become effective June 1, 2010.  The base rate increase includes the $63.7 million increase in Idaho Power’s annual base net power supply costs, and a $25 million general increase in Idaho Power’s annual base rates.

Other Idaho 2010 Filings

Rate Filings:  In March 2010, Idaho Power made the following three rate filings with the IPUC, each with a requested effective date of June 1, 2010:

•        Fixed Cost Adjustment: Idaho Power’s FCA filing for the 2009 calendar year proposes to collect $6.3 million for one year, a $3.6 million annual increase over current rates.  The $6.3 million reflects amounts accrued in 2009 under the mechanism.

•        Pension:  Idaho Power filed a request to recover $5.4 million of pension contributions that it expects to make in 2010.  In accordance with IPUC orders, Idaho Power is deferring its Idaho-jurisdiction pension expense to a regulatory asset.  On February 17, 2010, the IPUC approved a recovery methodology that would permit Idaho Power to include in future rate cases a reasonable amortization and recovery of cash contributions.  Deferred pension costs are expected to be amortized to expense to match the revenues received when pension contributions are recovered through rates.

•        AMI: Idaho Power filed for a $2.4 million annual increase in base rates related to AMI.

Energy Efficiency Prudency Determination:  On March 15, 2010, Idaho Power filed an application with the IPUC requesting an order designating expenditures of $50.7 million incurred in 2008 and 2009 as prudently incurred expenses.

On April 14, 2010, the IPUC completed its review of energy efficiency rider expenditures that Idaho Power made during the 2002 through 2007 period and found that remaining amounts totaling $14.7 million were prudently incurred and approved for ratemaking purposes.

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Oregon 2009 General Rate Case Settlement

On February 24, 2010, the Oregon Public Utility Commission (OPUC) approved a $5 million, or 15.4 percent, increase in base rates.  The new rates were effective March 1, 2010 and are based on a return on equity of 10.175 percent and an overall rate of return of 8.061 percent.  This increase results from a joint stipulation filed by Idaho Power that settled the revenue requirement issues surrounding a general rate case filed by Idaho Power on July 31, 2009.

Oregon Power Cost Recovery Mechanisms

Idaho Power’s power cost recovery mechanism in Oregon went into effect in 2008.  It has two components: the annual power cost update (APCU) and the power cost adjustment mechanism (PCAM).  The combination of the APCU and the PCAM allows Idaho Power to recover excess net power supply costs in a more timely fashion than through the previously existing deferral process.

PCAM:  On February 26, 2010, Idaho Power filed its PCAM application for the 2009 year with the OPUC.  The filing stated that actual net power supply costs were within the deadband, which is the range of deviations within which Idaho Power absorbs cost increases or decreases, resulting in no request for a deferral.

APCU:  On April 15, 2010, Idaho Power filed a stipulation combining the March forecast and October update with the OPUC.  Approval of the stipulation would result in a $5.5 million annual increase in Oregon rates, effective June 1, 2010.  The target date for an OPUC order is May 28, 2010.

Deferred Net Power Supply Costs

Changes in deferred power supply costs during the quarter were as follows (in thousands of dollars):

4.  LONG-TERM DEBT:

As of March 31, 2010, IDACORP had approximately $574 million remaining on a shelf registration statement that can be used for the issuance of debt securities or common stock.

In April 2010, Idaho Power received approval from the IPUC, the OPUC and the Public Service Commission of Wyoming for the issuance of up to $500 million in aggregate principal amount of one or more series of first mortgage bonds and unsecured debt securities.  The order from the IPUC approved the issuance of the securities over a two-year period, beginning on April 19, 2010, subject to extension upon request to the IPUC.

5.  NOTES PAYABLE:

Credit Facilities

IDACORP has a $100 million credit facility and Idaho Power has a $300 million credit facility, both of which expire on April 25, 2012.  Commercial paper may be issued up to the amounts supported by the credit facilities.  Under these facilities the companies pay a facility fee on the commitment, quarterly in arrears, based on its rating for senior unsecured long-term debt securities without third-party credit enhancement as provided by Moody’s Investors Service and Standard & Poor’s Ratings Services.

At March 31, 2010, no loans were outstanding on either IDACORP’s facility or Idaho Power’s facility.  At March 31, 2010, Idaho Power had regulatory authority to incur up to $450 million of short-term indebtedness.

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Balances and interest rates of short-term borrowings were as follows at March 31, 2010, and December 31, 2009 (in thousands of dollars):

6.  COMMON STOCK:

The following table summarizes shares of IDACORP stock issued during the three months ended March 31, 2010:

IDACORP enters into sales agency agreements as a means of selling its common stock from time to time.  As of March 31, 2010, there were 2.1 million shares remaining available to be sold on the current sales agency agreement.

Restrictions on Dividends

A covenant under IDACORP’s credit facility and Idaho Power’s credit facility requires IDACORP and Idaho Power to maintain leverage ratios of consolidated indebtedness to consolidated total capitalization, as defined therein, of no more than 65 percent at the end of each fiscal quarter.

Idaho Power’s Revised Code of Conduct approved by the IPUC on April 21, 2008, states that Idaho Power will not pay any dividends to IDACORP that will reduce Idaho Power’s common equity capital below 35 percent of its total adjusted capital without IPUC approval.

Idaho Power’s ability to pay dividends on its common stock held by IDACORP and IDACORP’s ability to pay dividends on its common stock are limited to the extent payment of such dividends would violate the covenants in their respective credit facilities or Idaho Power’s Revised Code of Conduct.  At March 31, 2010, the leverage ratios for IDACORP and Idaho Power were 51 percent and 52 percent, respectively.  Based on these restrictions, IDACORP’s and Idaho Power’s dividends were limited to $562 million and $519 million, respectively, at March 31, 2010.  There are additional covenants, subject to exceptions, that prohibit or restrict: certain investments or acquisitions, mergers or sale or disposition of property without consent; the creation of certain liens; and any agreements restricting dividend payments to the company from any material subsidiary.  At March 31, 2010, IDACORP and Idaho Power were in compliance with all facility covenants.

Idaho Power’s articles of incorporation contain restrictions on the payment of dividends on its common stock if preferred stock dividends are in arrears.  Idaho Power has no preferred stock outstanding.

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Idaho Power must obtain approval of the OPUC before it could directly or indirectly loan funds or issue notes or give credit on its books to IDACORP.

7.  EARNINGS PER SHARE:

The following table presents the computation of IDACORP’s basic and diluted earnings per share (EPS) for the three months ended March 31, 2010 and 2009 (in thousands, except for per share amounts):

The diluted EPS computation excluded 346,000 options for the three months ended March 31, 2010, because the options’ exercise prices were greater than the average market price of the common stock during that period.  For the same period in 2009, there were 687,485 options excluded from the diluted EPS computation for the same reason.  In total, 585,662 options were outstanding at March 31, 2010, with expiration dates between 2010 and 2015.

8.  COMMITMENTS:

Purchase Obligations

The following item is the only material change to purchase obligations made outside of the ordinary course of business during the first quarter of 2010:

•        Idaho Power entered into a purchase power agreement with USG Oregon, LLC for the purchase of energy from the Neal Hot Springs Unit #1 geothermal electric generation facility.  The project will be located near Vale, Oregon and the expected output will be approximately 22 MW, with an estimated on-line date of late 2012.  Idaho Power’s purchases under the contract are expected to total $569 million from 2011-2037.  The agreement is pending approval from the IPUC.

Guarantees
Idaho Power has agreed to guarantee the performance of reclamation activities and obligations at BCC, of which IERCo owns a one-third interest.  This guarantee, which is renewed each December, was $63 million at March 31, 2010.  BCC has a reclamation trust fund set aside specifically for the purpose of paying these reclamation costs.  BCC continually assesses the adequacy of the reclamation trust fund and its estimate of future reclamation costs.  To ensure that the reclamation trust fund maintains adequate reserves, BCC has the ability to add a per-ton surcharge to coal sales.  In 2010, BCC began applying a nominal surcharge to coal sales in order to maintain adequate reserves in the reclamation trust fund.  Because of the existence of the fund and the ability to apply a per-ton surcharge, the estimated fair value of this guarantee is minimal.

9.  CONTINGENCIES:

Western Energy Proceedings at the FERC

In this report, the term “western energy situation” is used to refer to the California energy crisis that occurred during 2000 and 2001, and the energy shortages, high prices and blackouts in the western United States.  High prices for electricity in California and in western wholesale markets during 2000 and 2001 caused numerous purchasers of electricity in those markets to initiate proceedings seeking refunds or other forms of relief and FERC to initiate its own investigations.  Some of these proceedings (the western energy proceedings) remain pending before the FERC or on appeal to the United States Court of Appeals for the Ninth Circuit (Ninth Circuit).

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There are pending in the Ninth Circuit approximately 200 petitions for review of numerous FERC orders regarding the western energy situation.  Decisions in these appeals may have implications with respect to other pending cases, including those to which Idaho Power or IE are parties.  Idaho Power and IE intend to vigorously defend their positions in these proceedings, but are unable to predict the outcome of these matters.  Except as to the matters described below under “Pacific Northwest Refund,” Idaho Power and IE believe that settlement releases they have obtained that are described below under “California Refund” and “Market Manipulation” will restrict potential claims that might result from the disposition of the pending Ninth Circuit review petitions and that these matters will not have a material adverse effect on their consolidated financial positions, results of operations or cash flows.

California Refund:  This proceeding originated with an effort by agencies of the State of California and investor-owned utilities in California to obtain refunds for a portion of the spot market sales from sellers of electricity into California markets from October 2, 2000, through June 20, 2001.  The FERC has issued numerous orders establishing price mitigation plans for sales in the California wholesale electricity market, including the methodology for determining refunds.  IE and numerous other parties have petitioned the Ninth Circuit for review of the FERC’s orders on California refunds.  As additional FERC orders have been issued, further petitions for review have been filed before the Ninth Circuit, which from time to time has identified discrete cases that can proceed to briefing and decision while it stayed action on the other consolidated cases.

On May 22, 2006, the FERC approved an Offer of Settlement between and among IE and Idaho Power, the California Parties (Pacific Gas & Electric Company, San Diego Gas & Electric Company, Southern California Edison Company, the California Public Utilities Commission, the California Electricity Oversight Board, the California Department of Water Resources (CDWR) and the California Attorney General) and additional parties that elected to be bound by the settlement.  The settlement disposed of matters encompassed by the California refund proceeding, as well as market manipulation claims and investigations relating to the western energy situation among and between the parties agreeing to be bound by it.  Although many market participants agreed to be bound by the settlement, other market participants, representing a small minority of potential refund claims, initially elected not to be bound by the settlement.  From time to time, as the California Parties have reached settlements with those other market participants, they have elected to opt into the IE-Idaho Power-California Parties’ settlement.  The settlement provided for approximately $23.7 million of IE’s and Idaho Power’s estimated $36 million rights to accounts receivable from the California Independent System Operator (Cal ISO) and the California Power Exchange (CalPX) to be assigned to an escrow account for refunds and for an additional $1.5 million of accounts receivable to be retained by the CalPX until the conclusion of the litigation.  The additional $1.5 million of accounts receivable retained by the CalPX is available to fund the claims of non-settling parties if they prevail in the remaining litigation of these California market matters.  Any additional amounts owed to non-settling parties would be funded by other amounts owed to IE and Idaho Power by the Cal ISO and CalPX, or directly by IE and Idaho Power, and any excess funds remaining at the end of the case would be returned to IE and Idaho Power.  The remaining IE and Idaho Power receivables were paid to IE and Idaho Power under the settlement.

In an August 2006 decision, the Ninth Circuit ruled that all transactions that occurred within the CalPX and the Cal ISO markets were proper subjects of the refund proceeding.  In that decision the Ninth Circuit refused to expand the proceedings into the bilateral market, approved the refund effective date as October 2, 2000, required the FERC to consider claims that some market participants had violated governing tariff obligations at an earlier date than the refund effective date, and expanded the scope of the refund proceeding to include transactions within the CalPX and Cal ISO markets outside the limited 24-hour spot market and energy exchange transactions.  Parts of the decision exposed sellers to increased claims for potential refunds.  The Ninth Circuit issued its mandate on April 15, 2009, thereby officially returning the cases to the FERC for further action consistent with the court’s decision.

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On November 19, 2009, the FERC issued an order to implement the Ninth Circuit’s remand.  The remand order established a trial-type hearing in which participants will be permitted to submit information regarding (i) specified tariff violations committed by any public utility seller from January 1, 2000 - October 2, 2000 resulting in a transaction that set a market clearing price for the trading period when the violation occurred, and (ii) claims for refunds for multi-day transactions and energy exchange transactions entered into during the refund period (October 2, 2000 – June 20, 2001).  Numerous parties, including IE and Idaho Power, filed motions to clarify the FERC’s order.  Although IE and Idaho Power are unable to predict when or how FERC will rule on these motions, the effect of the remand order for IE and Idaho Power is confined to the minority of market participants that are not bound by the IE-Idaho Power-California Parties’ settlement described above.  Accordingly, IE and Idaho Power believe the remanded proceedings will not have a material adverse effect on their consolidated financial positions, results of operations or cash flows.

In 2005, the FERC established a framework for sellers wanting to demonstrate that the generally applicable FERC refund methodology interfered with the recovery of costs.  IE and Idaho Power made such a cost filing, which was rejected by the FERC.  On June 18, 2009, FERC issued an order stating that it was not ruling on IE’s and Idaho Power’s request for rehearing of the cost filing rejection because their request had been withdrawn in connection with the IE-Idaho Power-California Parties’ settlement.  On July 8, 2009, IE and Idaho Power sought further rehearing at the FERC because their withdrawal pertained only to the parties with whom IE and Idaho Power had settled.  On June 18, 2009, in a separate order, the FERC ruled that only net refund recipients were responsible for the costs associated with cost filings.  While most net refund recipients are bound by the settlement, until the Cal ISO completes its refund calculations, it is uncertain whether there are any net refund recipients who are not bound by the settlement.  If there are no such parties, then IE’s and Idaho Power’s request for rehearing will be moot.  FERC has not yet ruled on the request for rehearing.  IE and Idaho Power are unable to predict how or when the FERC might rule, but the effect of any such ruling is confined to obligations of IE and Idaho Power to the small minority of claims of market participants that are not bound by the settlement.  Accordingly, IE and Idaho Power believe this matter will not have a material adverse effect on their consolidated financial positions, results of operations or cash flows.

Market Manipulation:  On June 25, 2003, the FERC ordered approximately 50 entities that participated in the western wholesale power markets between January 1, 2000, and June 20, 2001, including Idaho Power, to show cause why certain trading practices did not constitute gaming or other forms of proscribed market behavior in concert with another party (partnership) in violation of the Cal ISO and CalPX Tariffs.  In 2004, the FERC dismissed the partnership show cause proceeding against Idaho Power.  Later in 2004, the FERC approved a settlement of the gaming proceeding without finding of wrongdoing by Idaho Power.

The orders establishing the scope of the show cause proceedings are presently the subject of review petitions in the Ninth Circuit.  On March 29, 2010, IE and Idaho Power filed a motion with the Ninth Circuit to dismiss 11 of the 12 petitions for review of FERC’s orders establishing the scope of the show cause proceedings as they relate to IE and Idaho Power.  Although IE and Idaho Power had obtained the consent to the motion from the 11 petitioners in those proceedings, the Ninth Circuit misconstrued the motion and instead granted on April 1, 2010, a motion to withdraw IE and Idaho Power interventions in the review proceedings.  On April 9, 2010, with the consent of the same 11 petitioners, IE and Idaho Power filed a motion for reconsideration with the Ninth Circuit, again requesting dismissal of the 11 petitions as they pertain to IE and Idaho Power.  Although IE and Idaho Power are unable to predict how or when the Ninth Circuit will act on the motion for reconsideration or the review petitions, in light of the settlement described above, IE and Idaho Power believe this matter will not have a material adverse effect on their consolidated financial positions, results of operations or cash flows.

On June 25, 2003, the FERC also issued an order instituting an investigation of anomalous bidding behavior and practices in the western wholesale markets for the time period May 1, 2000, through October 1, 2000, but the FERC terminated its investigations as to Idaho Power on May 12, 2004.  California government agencies and California investor-owned utilities have appealed the FERC’s termination of this investigation as to Idaho Power and more than 30 other market participants.  IE and Idaho Power are unable to predict the outcome of these petitions for review proceedings, but believe that the settlement releases govern any potential claims that might arise and that this matter will not have a material adverse effect on their consolidated financial positions, results of operations or cash flows.

Pacific Northwest Refund:  On July 25, 2001, the FERC issued an order establishing a proceeding separate from the California refund proceeding to determine whether there may have been unjust and unreasonable charges for spot market sales in the Pacific Northwest during the period December 25, 2000, through June 20, 2001, because the spot market in the Pacific Northwest was affected by the dysfunction in the California market.  In 2003, the FERC terminated the proceeding and declined to order refunds, but in 2007 the Ninth Circuit issued an opinion, in Port of Seattle, Washington v. FERC, remanding to the FERC the orders that declined to require refunds.  The Ninth Circuit’s opinion instructed the FERC to consider whether evidence of market manipulation would have altered the agency’s conclusions about refunds and directed the FERC to include sales originating in the Pacific Northwest to the CDWR in the scope of proceeding.  The Ninth Circuit officially returned the case to the FERC on April 16, 2009.  On September 4, 2009, IE and Idaho Power joined with a number of other parties in a joint petition for a writ of certiorari to the U.S. Supreme Court, which was denied on January 11, 2010.

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In separate filings, the California Parties, which no longer include the California Electricity Oversight Board, and the City of Tacoma, Washington (Tacoma) and the Port of Seattle, Washington (Port of Seattle) asked the FERC to reorganize and restructure the case to enable them to pursue claims that all spot market sales in the Cal ISO and CalPX markets and in the Pacific Northwest from January 1, 2000 through June 20, 2001 should be subject to refund and repriced, because market manipulation and tariff violations affected spot market prices.  Their requests would expand the scope of the refund period in the Pacific Northwest proceeding from the December 25, 2000 through June 20, 2001 period previously considered by the FERC.  On May 22, 2009, the California Parties filed a motion with the FERC to sever claims regarding sales originating in the Pacific Northwest to CDWR from the remainder of the Pacific Northwest proceedings and to consolidate their claims regarding these sales with ongoing proceedings in cases that IE and Idaho Power have settled, as well as with a new complaint filed on May 22, 2009 by the California Attorney General against parties with whom the California Parties have not settled (Brown Complaint).  IE and Idaho Power, along with a number of other parties, filed their opposition to the motion of the California Parties.  Many other parties also filed responses to the motion of the California Parties.  Tacoma and the Port of Seattle jointly filed a motion on August 4, 2009 with the FERC in connection with the California refund proceeding, the Lockyer remand pending before the FERC (involving claims of failure to file quarterly transaction reports with the FERC, from which IE and Idaho Power previously were dismissed), the Brown Complaint and the Pacific Northwest refund remand proceeding.  The Tacoma and the Port of Seattle motion asks the FERC to require refunds from all sellers in the Pacific Northwest spot markets for the expanded period (January 1, 2000 through June 20, 2001).  IE and Idaho Power joined with a number of other sellers in the Pacific Northwest markets during 2000 and 2001 in opposing the motion of Tacoma and the Port of Seattle.  On April 19, 2010, the California Parties filed a motion with the FERC renewing the requests contained in their May 22, 2009, motion and on May 3, 2010, IE and Idaho Power joined with a number of other parties opposing the renewal request.  FERC has not acted on the Ninth Circuit remand or the motions.  IE and Idaho Power intend to vigorously defend their positions in these proceedings, but are unable to predict the outcome of these matters or estimate the impact these matters may have on their consolidated financial positions, results of operations or cash flows.

Sierra Club Lawsuit – Bridger

In February 2007, the Sierra Club and the Wyoming Outdoor Council filed a complaint against PacifiCorp in the U.S. District Court for the District of Wyoming alleging thousands of violations by PacifiCorp of air quality opacity standards at the Jim Bridger coal-fired plant in Sweetwater County, Wyoming.  Opacity is an indication of the amount of light obscured by the flue gas of a power plant.  The complaint sought a declaration that PacifiCorp had violated opacity limits, a permanent injunction ordering PacifiCorp to comply with such limits, civil penalties of up to $32,500 per day per violation, and reimbursement of plaintiffs’ costs of litigation, including reasonable attorneys’ fees.  Idaho Power is not a party to this proceeding but has a one-third ownership interest in the plant.  PacifiCorp owns a two-thirds interest and is the operator of the plant.  On April 15, 2010, the parties jointly filed a proposed consent decree resolving the pending litigation.  The consent decree must be reviewed by the Environmental Protection Agency and approved by the court.  Idaho Power is fully reserved for the contingency and, if approved, the entry of the consent decree will not have a material adverse effect on Idaho Power’s consolidated financial position, results of operations or cash flows.

Sierra Club Lawsuit – Boardman

In September 2008, the Sierra Club and four other non-profit corporations filed a complaint against Portland General Electric Company (PGE) in the U.S. District Court for the District of Oregon alleging opacity permit limit violations at the Boardman coal-fired plant located in Morrow County, Oregon.  The complaint also alleged violations of the Clean Air Act, related federal regulations and the Oregon State Implementation Plan relating to PGE’s construction and operation of the plant.  The complaint sought a declaration that PGE had violated opacity limits, a permanent injunction ordering PGE to comply with such limits, injunctive relief requiring PGE to remediate alleged environmental damage and ongoing impacts, civil penalties of up to $32,500 per day per violation, and reimbursement of plaintiffs’ costs of litigation, including reasonable attorneys’ fees.  Idaho Power is not a party to this proceeding but has a 10 percent ownership interest in the Boardman plant.  PGE owns 65 percent and is the operator of the plant.  On December 5, 2008, PGE filed a motion to dismiss nine of the twelve claims asserted by the plaintiffs in their complaint, and on September 30, 2009, the court denied most of PGE’s motion to dismiss.  Idaho Power continues to monitor the status of this matter but is unable to predict its outcome or what effect this matter may have on its consolidated financial position, results of operations or cash flows.

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Snake River Basin Adjudication

Idaho Power is engaged in the Snake River Basin Adjudication (SRBA), a general stream adjudication commenced in 1987, to define the nature and extent of water rights in the Snake River Basin in Idaho, including the water rights of Idaho Power.
On March 25, 2009, Idaho Power and the State of Idaho (State) entered into a settlement agreement with respect to the 1984 Swan Falls Agreement and Idaho Power’s water rights under the Swan Falls Agreement, which settlement agreement is subject to certain conditions discussed below.  The settlement agreement will also resolve litigation between Idaho Power and the State relating to the Swan Falls Agreement that was filed by Idaho Power on May 10, 2007, with the Idaho District Court for the Fifth Judicial Circuit, which has jurisdiction over SRBA matters, including the Swan Falls case.

The settlement agreement resolves the pending litigation by clarifying that Idaho Power’s water rights in excess of minimum flows at its hydroelectric facilities between Milner Dam and Swan Falls Dam are subordinate to future upstream beneficial uses, including aquifer recharge.  The agreement commits the State and Idaho Power to further discussions on important water management issues concerning the Swan Falls Agreement and the management of water in the Snake River Basin.  It also recognizes that water management measures that enhance aquifer levels, springs and river flows, such as aquifer recharge projects, benefit both agricultural development and hydropower generation and deserve study to determine their economic potential, their impact on the environment and their impact on hydropower generation.  These will be a part of the Comprehensive Aquifer Management Plan (CAMP) approved by the Idaho Water Resource Board for the Eastern Snake Plain Aquifer (ESPA), which includes limits on the amount of aquifer recharge.  Idaho Power is a member of the ESPA CAMP advisory committee and implementation committee.

On April 24, 2009, the Governor of Idaho signed into law legislation approving provisions contained in the settlement agreement.  On May 6, 2009, as part of the settlement, Idaho Power, the Governor of Idaho and the Idaho Water Resource Board executed a memorandum of agreement relating to future aquifer recharge efforts and further assurances as to limitations on the amount of aquifer recharge.  Idaho Power and the State also filed a joint motion to the SRBA court to dismiss the Swan Falls case and enter the stipulated water right decrees set forth in the settlement agreement.  Parties representing groundwater users in the Eastern Snake Plain Aquifer objected to some of the language proposed by Idaho Power and the State relating to water rights in the decrees to be entered by the SRBA court as contemplated by the Settlement Agreement.  Specifically, the concerns relate to the language describing the subordination of the rights and its interplay with the original Swan Falls settlement document and implementing legislation.  On January 4, 2010, the court issued an order approving the overall settlement subject to certain modifications to the draft water right decrees proposed by the company and the state.  Idaho Power continues to work with the State and the parties to reach agreement consistent with the court’s order regarding the language of the decrees.

U.S. Bureau of Reclamation

Idaho Power filed a complaint on October 15, 2007, and an amended complaint on September 30, 2008, in the U.S. District Court of Federal Claims in Washington, D.C. against the U.S. Bureau of Reclamation.  The complaint relates to a 1923 contract right for delivery of water to Idaho Power’s hydropower projects on the Snake River, to recover damages from the U.S. for the lost generation resulting from reduced flows and for a prospective declaration of contractual rights and obligations of the parties.  Over the past several months, Idaho Power has been working with the U.S. and Idaho interests (including the State of Idaho and upstream water users) in an effort to resolve certain state water right issues pending in the SRBA that are common to both the SRBA and the pending federal case.  In an effort to promote efficiency, the parties have agreed to present certain legal issues associated with the 1923 contract to the court in the SRBA case that are expected to resolve issues in the pending federal case.  The SRBA court has scheduled the presentation of these issues to the court by the fall of 2010.  Idaho Power and the U.S. have agreed to stay further proceedings in the federal case pending the resolution of these issues in the SRBA case.  Idaho Power is unable to predict the outcome of this matter.

Oregon Trail Heights Fire

On August 25, 2008, a fire ignited beneath an Idaho Power distribution line in Boise, Idaho.  It was fanned by high winds and spread rapidly, resulting in one death, the destruction of 10 homes and damage or alleged fire-related losses to approximately 30 others.  Following the investigation, the Boise Fire Department determined that the fire was linked to a piece of line hardware on one of Idaho Power’s distribution poles and that high winds contributed to the fire and its resultant damage.  Idaho Power has received notice of claims from a number of the homeowners and their insurers and while it has continued investigation of these claims, Idaho Power has reached settlements with a number of the individuals or their insurers who have alleged damages resulting from the fire.  Idaho Power is insured up to policy limits against liability for claims in excess of its self-insured retention.  Idaho Power has accrued a reserve for any loss that is probable and reasonably estimable, including insurance deductibles, and believes this matter will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

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Other Legal Proceedings

IDACORP, Idaho Power and/or IE are parties to legal claims, actions and proceedings in addition to those discussed above.  Resolution of any of these matters will take time and the companies cannot predict the outcome of any of these proceedings.  The companies believe that their reserves are adequate for these matters and that resolution of these matters, taking into account existing reserves, will not have a material adverse effect on IDACORP’s or Idaho Power’s consolidated financial positions, results of operations or cash flows.

10.  BENEFIT PLANS:

Idaho Power has a noncontributory defined benefit pension plan covering most employees.  The benefits under the plan are based on years of service and the employee’s final average earnings.  In addition, Idaho Power has a nonqualified, deferred compensation plan for certain senior management employees and directors called the Senior Management Security Plan (SMSP).  Idaho Power also maintains a defined benefit postretirement plan (consisting of health care and death benefits) that covers all employees who were enrolled in the active group plan at the time of retirement as well as their spouses and qualifying dependents.  Idaho Power also has an Employee Savings Plan that complies with Section 401(k) of the Internal Revenue Code and covers substantially all employees.  Idaho Power matches specified percentages of employee contributions to the plan.

The following table shows the components of net periodic benefit costs for the pension, SMSP, and Postretirement Benefits Plans for the three months ended March 31 (in thousands of dollars):

IDACORP and Idaho Power’s minimum required contributions to the pension plan will be approximately $6 million in the third quarter of 2010, and $44 million, $47 million, $39 million, and $40 million in 2011, 2012, 2013, and 2014, respectively.  IDACORP and Idaho Power may elect to make contributions earlier than the required dates.

See Note 2 – “Income Taxes” for a summary of the impact of the Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act which were enacted in March 2010.

11.  INVESTMENTS IN DEBT AND EQUITY SECURITIES:

Investments in debt and equity securities classified as available-for-sale securities are reported at fair value, using either specific identification or average cost to determine the cost for computing gains or losses.  Any unrealized gains or losses on available-for-sale securities are included in other comprehensive income.

Investments classified as held-to-maturity securities are reported at amortized cost.  Held-to-maturity securities are investments in debt securities for which the companies have the positive intent and ability to hold the securities until maturity.

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The following table summarizes investments in debt and equity securities as of March 31, 2010 and December 31, 2009 (in thousands of dollars):

At the end of each reporting period, IDACORP and Idaho Power analyze securities in loss positions to determine whether they have experienced a decline in market value that is considered other-than-temporary.  At March 31, 2010 and December 31, 2009, no securities were in an unrealized loss position.

The following table summarizes sales of available-for-sale securities for the three months ended March 31, 2010 and 2009 (in thousands of dollars):

12.  DERIVATIVE FINANCIAL INSTRUMENTS:

Commodity Price Risk

Idaho Power is exposed to certain risks relating to its ongoing business operations.  The primary risk managed by using derivative instruments is commodity price risk related to Idaho Power’s ongoing utility operations providing electricity to meet the demand of its retail customers.  Physical and financial forward contracts for both electricity and fuel used to produce electricity are entered into to manage the price risk associated with meeting forecasted loads.  The objective of Idaho Power’s energy purchase and sale activity is to meet the demand of retail electric customers, maintain appropriate physical reserves to ensure reliability and make economic use of temporary surpluses that may develop.

All derivative instruments are recognized as either assets or liabilities at fair value on the balance sheet.  Idaho Power’s physical forward contracts, including green tags, qualify for the normal purchases and normal sales exception to derivative accounting requirements with the exception of forward contracts for the purchase of natural gas for use at Idaho Power’s natural gas generation facilities.  Because of Idaho Power’s power cost mechanisms, Idaho Power records the changes in fair value of derivative instruments related to power supply as regulatory assets or liabilities.

Idaho Power had the following derivative commodity forward contracts, entered into for the purpose of economically hedging forecasted purchases and sales, outstanding at March 31, 2010 and 2009:

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The following tables present the fair values of derivatives not designated as hedging instruments recorded in the balance sheet at March 31, 2010 and December 31, 2009 (in thousands of dollars):

The following table presents the effect on income of derivatives not designated as hedging instruments for the quarters ended March 31, 2010 and 2009 (in thousands of dollars):

Idaho Power records changes in fair value of its derivative contracts as either regulatory assets or regulatory liabilities.  Settlement gains and losses on electricity swap contracts are recorded on the income statement in off-system sales or purchased power depending on the forecasted position being economically hedged by the derivative contract.  Settlement gains and losses on both financial and physical contracts for natural gas are reflected in fuel expense.  Settlement gains and losses on diesel derivatives were immaterial for the quarter ended March 31, 2010.

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Credit Risk

At March 31, 2010, Idaho Power does not have material credit exposure from financial instruments, including derivatives.  Idaho Power monitors credit risk exposure through reviews of counterparty credit quality, corporate-wide counterparty credit exposure, and corporate-wide counterparty concentration levels.  Idaho Power manages these risks by establishing appropriate credit and concentration limits on transactions with counterparties and requiring contractual guarantees, cash deposits or letters of credit from counterparties or their affiliates, as deemed necessary.  The majority of Idaho Power’s contracts are under the Western Systems Power Pool agreement that provides for adequate assurances if a counterparty has debt that is downgraded to below investment grade by at least one rating agency.  Idaho Power also requires North American Energy Standards Board contracts as necessary for physical gas transactions, and International Swaps and Derivatives Association, Inc. contracts as needed for financial transactions.

Credit-Contingent Features

Certain of Idaho Power’s derivative instruments contain provisions that require Idaho Power’s unsecured debt to maintain an investment grade credit rating from each of the major credit rating agencies.  If Idaho Power’s unsecured debt were to fall below investment grade, it would be in violation of these provisions, and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions.  The aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in a liability position on March 31, 2010, was $8 million.  Idaho Power has posted $4 million of collateral related to this amount.  If the credit-risk-related contingent features underlying these agreements were triggered on March 31, 2010, Idaho Power could have been required to post $3 million of additional cash collateral to its counterparties.

13.  FAIR VALUE MEASUREMENTS:

IDACORP and Idaho Power have categorized their financial instruments, based on the priority of the inputs to the valuation technique, into a three-level fair value hierarchy.  The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3).  If the inputs used to measure the financial instruments fall within different levels of the hierarchy, the categorization is based on the lowest level input that is significant to the fair value measurement of the instrument.

Financial assets and liabilities recorded on the condensed consolidated balance sheets are categorized based on the inputs to the valuation techniques as follows:

Level 1:  Financial assets and liabilities whose values are based on unadjusted quoted prices for identical assets or liabilities in an active market that IDACORP and Idaho Power has the ability to access.

Level 2:  Financial assets and liabilities whose values are based on the following:

a)       Quoted prices for similar assets or liabilities in active markets;

b)       Quoted prices for identical or similar assets or liabilities in non-active markets;

c)       Pricing models whose inputs are observable for substantially the full term of the asset or liability; and

d)       Pricing models whose inputs are derived principally from or corroborated by observable market data through correlation or other means for substantially the full term of the asset or liability.

IDACORP and Idaho Power Level 2 inputs are based on quoted market prices adjusted for location using corroborated, observable market data.

Level 3:  Financial assets and liabilities whose values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement.  These inputs reflect management’s own assumptions about the assumptions a market participant would use in pricing the asset or liability.

Idaho Power’s derivatives are contracts entered into as part of its management of loads and resources.  Electricity swaps are valued on the Intercontinental Exchange with quoted prices in an active market.  Natural gas and diesel derivative valuations are performed using New York Mercantile Exchange (NYMEX) pricing, adjusted for basis location, which are also quoted under NYMEX.  Trading securities consists of employee-directed investments held in a Rabbi Trust and are related to an executive deferred compensation plan.  Available-for-sale securities are related to the SMSP and are held in a Rabbi Trust and are actively traded money market and equity funds with quoted prices in active markets.

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The following table presents information about IDACORP’s and Idaho Power’s assets and liabilities measured at fair value on a recurring basis as of March 31, 2010, and December 31, 2009 (in thousands of dollars).  IDACORP’s and Idaho Power’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy.

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The following table presents the carrying value and estimated fair value of financial instruments that are not reported at fair value, using available market information and appropriate valuation methodologies.  The use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts.  Cash and cash equivalents, deposits, customer and other receivables, notes payable, accounts payable, interest accrued and taxes accrued are reported at their carrying value as these are a reasonable estimate of their fair value.  The estimated fair values for notes receivable and long-term debt are based upon quoted market prices of the same or similar issues or discounted cash flow analyses as appropriate.

14.  SEGMENT INFORMATION:

IDACORP’s only reportable segment is utility operations.  The utility operations segment’s primary source of revenue is the regulated operations of Idaho Power.  Idaho Power’s regulated operations include the generation, transmission, distribution, purchase and sale of electricity.  This segment also includes income from IERCo, a wholly-owned subsidiary of Idaho Power that is also subject to regulation and is a one-third owner of BCC, an unconsolidated joint venture.

IDACORP’s other operating segments are below the quantitative thresholds for reportable segments and are included in the “All Other” category.  This category is comprised of IFS’s investments in affordable housing developments and historic rehabilitation projects, Ida-West’s joint venture investments in small hydroelectric generation projects, the remaining activities of energy marketer IE, which wound down its operations in 2003, and IDACORP’s holding company expenses.

The following table summarizes the segment information for IDACORP’s utility operations and the total of all other segments, and reconciles this information to total enterprise amounts (in thousands of dollars):

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