Earnings Per Share
The computation of diluted earnings per share (EPS) differs from basic EPS only due to the inclusion of potentially dilutive shares related to stock-based compensation awards.

The following table presents the computation of IDACORP's basic and diluted earnings per share for the three and nine months ended September 30, 2006 and 2005 (in thousands, except for per share amounts):

The diluted EPS computation excluded 463,600 and 643,600 common stock options for the three and nine months ended September 30, 2006, respectively, because the options' exercise prices were greater than the average market price of the common stock during those periods.  For the same periods in 2005, there were 824,500 and 1,014,437 options excluded from the diluted EPS computation for the same reason.  In total, 1,156,296 options were outstanding at September 30, 2006, with expiration dates between 2010 and 2015.

Reclassifications
Certain prior year amounts have been reclassified to conform to the current year presentation.  Net income and shareholders' equity were not affected by these reclassifications.

New Accounting Pronouncements
FIN 48:   In June 2006, the Financial Accounting Standards Board (FASB) issued FASB Interpretation No. 48, "Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109" (FIN 48), which clarifies the accounting for uncertainty in tax positions.  FIN 48 requires that IDACORP and IPC recognize in their financial statements the impact of a tax position if that position will more likely than not be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. The provisions of FIN 48 are effective for fiscal years beginning after December 15, 2006, with the cumulative effect of the change in accounting principle recorded as an adjustment to opening retained earnings.  IDACORP and IPC are currently evaluating the impact of adopting FIN 48 on their financial statements.

SFAS 157:   In September 2006, the FASB issued SFAS 157, "Fair Value Measurements."  SFAS 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements.  SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years.  IDACORP and IPC are currently evaluating the impact of adopting SFAS 157 on their financial statements.

16

Table of Contents

SFAS 158:   In September 2006, the FASB issued SFAS 158, "Employers' Accounting for Defined Benefit Pension Plans and Other Postretirement Plans - an amendment of FASB Statements No. 87, 88, 106, and 132(R)."  SFAS 158 requires an employer that is a business entity and sponsors one or more single-employer defined benefit plans to:

• Recognize the funded status of a benefit plan-measured as the difference between plan assets at fair value (with limited exceptions) and the benefit obligation-in its statement of financial position.  For a pension plan, the benefit obligation is the projected benefit obligation; for any other postretirement benefit plan, such as a retiree health care plan, the benefit obligation is the accumulated postretirement benefit obligation.

• Recognize as a component of other comprehensive income, net of tax, the gains or losses and prior service costs or credits that arise during the period but are not recognized as components of net periodic benefit cost pursuant to FASB Statement No. 87, "Employers' Accounting for Pensions", or No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions."  Amounts recognized in accumulated other comprehensive income, including the gains or losses, prior service costs or credits, and the transition asset or obligation remaining from the initial application of Statements 87 and 106, are adjusted as they are subsequently recognized as components of net periodic benefit cost pursuant to the recognition and amortization provisions of those Statements.

• Measure defined benefit plan assets and obligations as of the date of the employer's fiscal year-end statement of financial position (with limited exceptions).

• Disclose in the notes to financial statements additional information about certain effects on net periodic benefit cost for the next fiscal year that arise from delayed recognition of the gains or losses, prior service costs or credits, and transition asset or obligation.

IDACORP is required to initially recognize the funded status of its defined benefit postretirement plan and to provide the required disclosures in its December 31, 2006, financial statements.  The requirement to measure plan assets and benefit obligations as of the date of the employer's fiscal year-end statement of financial position is effective for fiscal years ending after December 15, 2008.  When adopted in the fourth quarter of 2006, the provisions of SFAS 158 will increase IDACORP's and IPC's liabilities and reduce each company's common equity by approximately $80 million as of January 1, 2006, which is the amount by which the plans' benefit obligations exceeded the plans' assets.  IPC's common equity balance is one factor used in the determination of retail rates.  The decrease in common equity resulting from the adoption of SFAS 158 would decrease rates, absent special ratemaking treatment.  IPC expects to pursue such treatment from the IPUC and OPUC, and if received, the adoption of SFAS 158 is not expected to have a material effect on IDACORP's or IPC's results of operations or cash flows.

SAB 108 : In September 2006, the Securities and Exchange Commission (SEC) released Staff Accounting Bulletin No. 108, "Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in Current Year Financial Statements" (SAB 108), in September 2006.  SAB 108 provides guidance on how the effects of the carryover or reversal of prior year financial statement misstatements should be considered in quantifying a current year misstatement.  Prior practice allowed the evaluation of materiality on the basis of (1) the error quantified as the amount by which the current year income statement was misstated (rollover method) or (2) the cumulative error quantified as the cumulative amount by which the current year balance sheet was misstated (iron curtain method).  Reliance on either method in prior years could have resulted in misstatement of the financial statements.  The guidance provided in SAB 108 requires both methods to be used in evaluating materiality.  Immaterial prior year errors may be corrected with the first filing of prior year financial statements after adoption.  The cumulative effect of the correction would be reflected in the opening balance sheet with appropriate disclosure of the nature and amount of each individual error corrected in the cumulative adjustment, as well as a disclosure of the cause of the error and that the error had been deemed to be immaterial in the past.  SAB 108 is effective for IDACORP's and IPC's opening balance sheet in 2007.  IDACORP and IPC are currently evaluating the impact SAB 108 might have on their financial position or results of operations.

2.  INCOME TAXES:

17

Table of Contents

Income tax rate
In accordance with interim reporting requirements, IDACORP and IPC use an estimated annual effective tax rate for computing their provisions for income taxes.  IDACORP's effective rate on continuing operations for the nine months ended September 30, 2006, was 24.1 percent, compared to 17.1 percent for the nine months ended September 30, 2005.  IPC's effective tax rate for the nine months ended September 30, 2006, was 38.5 percent, compared to 40.9 percent for the nine months ended September 30, 2005.

The differences in estimated annual effective tax rates are primarily due to the increase in pre-tax earnings at IDACORP and IPC, the loss of IPC's simplified service cost method tax deduction in 2005 and the adoption of a new uniform capitalization method in 2006, timing and amount of IPC's regulatory flow-through tax adjustments, settlement of a Bridger Coal Company partnership audit at IPC (discussed below), and slightly lower tax credits from IFS.

Status of audit proceedings
In March 2005, the Internal Revenue Service (IRS) began its examination of IDACORP's 2001-2003 tax years.  On October 13, 2006, the IRS issued its examination report and assessment for those years.  With the exception of IPC's capitalized overhead costs method, discussed below, the IRS and IDACORP were able to settle all issues.  The federal tax assessment for the settled issues will be paid in November 2006.  It is expected that associated interest charges and state income taxes will be paid during 2007.  Settlement of the agreed issues will not have a material impact on IDACORP's 2006 results of operations or cash flows.

The IRS disallowed IPC's capitalized overhead cost method for uniform capitalization (the simplified service cost method) on the basis that IPC's self-constructed assets were not produced on a "routine and repetitive" basis as defined by Rev. Rul. 2005-53.  The disallowance resulted in a federal tax assessment of $45 million.  IDACORP disagrees with this conclusion and will appeal the issue.  Accordingly, in November, 2006 IDACORP will file its formal protest, make a deposit of the disputed tax with the IRS to stop the accrual of interest, and enter the appeals process.  Management cannot predict the timing or outcome of this process, but believes that an adequate provision for income taxes and related interest charges has been made for this issue.

The simplified service cost method was also used for IPC's 2004 tax year.  While 2004 is not currently under examination, it is likely the IRS will take the same position for 2004 as it did for 2001-2003; however, it is not likely that this position will result in a federal income tax assessment primarily due to the mitigating effect of accelerated tax depreciation.

On July 7, 2006, the IRS issued its examination report for Bridger Coal Company's 2001-2003 tax years.  Bridger Coal is a partnership investment owned one-third by IPC.  The audit resulted in net favorable adjustments to Bridger Coal's tax returns for those years.  IPC's third quarter income tax expense decreased by $1.3 million as a result of the settlement.

Capitalized overhead costs
Generally, section 263A of the Internal Revenue Code of 1986, as amended, requires the capitalization of all direct costs and indirect costs, including mixed service costs, which directly benefit or are incurred by reason of the production of property by a taxpayer.  The simplified service cost method, a "safe harbor" method, is one of the methods provided by the section 263A treasury regulations for the calculation of mixed service cost capitalization.  IPC adopted the simplified service cost method for both the self-construction of utility plant and production of electricity beginning with its 2001 federal income tax return.

On August 2, 2005, the IRS and the Treasury Department issued guidance interpreting the meaning of "routine and repetitive" for purposes of the simplified service cost and simplified production methods of the Internal Revenue Code section 263A uniform capitalization rules.  The guidance was issued in the form of a revenue ruling (Rev. Rul. 2005-53) which is effective for all open tax years ending prior to August 2, 2005, and proposed and temporary regulations (the "Temporary Regulations") which are effective for tax years ending on or after August 2, 2005.  Both pieces of guidance take a more restrictive view of the definition of self-constructed assets produced by a taxpayer on a "routine and repetitive" basis than did treasury regulations in effect at the time IPC changed to the simplified service cost method.

18

Table of Contents

For IPC, the simplified service cost method produced a current tax deduction for costs capitalized to electricity production that are capitalized into fixed assets for financial accounting purposes.  Deferred income tax expense had not been provided for this deduction because the prescribed regulatory tax accounting treatment does not allow for inclusion of such deferred tax expense in current rates.  Rate regulated enterprises are required to recognize such adjustments as regulatory assets if it is probable that such amounts will be recovered from customers in future rates.
As discussed in "Status of Audit Proceedings" above, the IRS has disallowed IPC's use of the simplified service cost method for the tax years 2001-2003 on the basis of Rev. Rul. 2005-53.  As a result, the IRS has assessed a $45 million tax liability.  IDACORP will appeal the IRS's assessment.  Because of the nature of the issue, IDACORP's exposure with respect to this matter may be less than the tax assessed plus applicable interest charges.  The resolution of this matter could result in a one time charge to earnings; however, at this time IDACORP is not in a position to quantify such amount.  Additionally, after resolution IDACORP will likely amend its 2005 federal income tax return and its 2005 method change application to account for the effects that such resolution has on IPC's new uniform capitalization method (discussed below).  This amendment is not expected to have a negative impact on IDACORP's or IPC's consolidated financial position, results of operations, or cash flows.

With respect to tax year 2005 and future tax years, the Temporary Regulations, as drafted, preclude IPC from using the simplified service cost method for its self-constructed assets.  Under the Temporary Regulations, IPC is required to use another allowable section 263A method for its indirect costs, including mixed service costs.  As a result of the Temporary Regulations, IPC made changes to its overall section 263A uniform capitalization method of accounting.  In September 2006, the changes were adopted with an automatic method change request included in IDACORP's 2005 federal income tax return.  The uniform capitalization methodology adopted for 2005 and subsequent years involves the use of the specific identification, burden rate, and step-allocation methods of accounting.  The methods used are allowable under both the final and temporary section 263A regulations.

As with the simplified service cost method, the new uniform capitalization methodology produces an annual tax deduction for costs that are not required to be capitalized under section 263A as well as costs capitalized into the production of electricity.  The method, while producing a beneficial result, is not as favorable as the simplified service cost method.  Changing the uniform capitalization method will result in a net charge to IPC's 2006 income tax expense of $6.1 million, with $5.4 million being recorded in the third quarter.  The estimated 2006 tax deduction produces a $3.3 million tax benefit for the year, $2.5 million of which was recorded at IPC in the third quarter.  The change in method is not expected to have a material effect on IDACORP's or IPC's 2006 cash flows.  The accounting and regulatory treatment for the new method is the same as previously used for the simplified service cost method.

3.  COMMON STOCK:

During the nine months ended September 30, 2006, IDACORP entered into the following transactions involving its common stock:

• 61,168 original issue shares were granted to participants in the 2000 Long-Term Incentive and Compensation Plan and 91,215 shares were issued pursuant to the exercise of stock options under the same plan.
• A total of 194,938 original issue shares were issued under the Dividend Reinvestment and Stock Purchase Plan and the Employee Savings Plan.

On January 1, 2006, IDACORP adopted SFAS 123R.  SFAS 123R requires that any amounts of unearned stock-based compensation be charged against common equity.  Prior to January 1, 2006, IDACORP had aggregated its unearned compensation balances with treasury stock on its consolidated balance sheets.

19

Table of Contents

Long-Term Financing
IDACORP currently has $679 million remaining on two shelf registration statements that can be used for the issuance of unsecured debt (including medium-term notes) and preferred or common stock.  IPC currently has in place a registration statement that can be used for the issuance of an aggregate principal amount of $240 million of first mortgage bonds (including medium-term notes) and unsecured debt.

The amount of first mortgage bonds issuable by IPC is limited to a maximum of $1.1 billion and by property, earnings and other provisions of the mortgage and supplemental indentures thereto.  IPC may amend the indenture and increase this amount without consent of the holders of the first mortgage bonds.  The indenture requires that IPC's net earnings must be at least twice the annual interest requirements on all outstanding debt of equal or prior rank, including the bonds that IPC may propose to issue.  Under certain circumstances, the net earnings test does not apply, including the issuance of refunding bonds to retire outstanding bonds that mature in less than two years or that are of an equal or higher interest rate, or prior lien bonds.

20

Table of Contents

As of September 30, 2006, IPC could issue under the mortgage approximately $452 million of additional first mortgage bonds based on retired first mortgage bonds and $670 million of additional first mortgage bonds based on unfunded property additions.  As of September 30, 2006, unfunded property additions were approximately $1.1 billion.  Property additions consist of electric or gas property, or property used in connection therewith.  Property additions exclude securities, contracts or choses in action, merchandise and equipment for consumption or resale, materials and supplies, property used principally for production or gathering of natural gas and any power sites and uncompleted works under Idaho state permits.  In determining net property additions, IPC deducts all retired funded property from gross property additions except to the extent of certain credits for released funded property.

The mortgage requires IPC to spend or appropriate 15 percent of its annual gross operating revenues for maintenance, retirement or amortization of its properties.  IPC may, however, anticipate or make up these expenditures or appropriations within the five years that immediately follow or precede a particular year.

The mortgage secures all bonds issued under the indenture equally and ratably, without preference, priority or distinction.  IPC may issue additional first mortgage bonds in the future, and those first mortgage bonds will also be secured by the mortgage.  The lien of the indenture constitutes a first mortgage on all the properties of IPC, subject only to certain limited exceptions including liens for taxes and assessments that are not delinquent and minor excepted encumbrances.  Certain of the properties of IPC are subject to easements, leases, contracts, covenants, workmen's compensation awards and similar encumbrances and minor defects and clouds common to properties.  The mortgage does not create a lien on revenues or profits, or notes or accounts receivable, contracts or choses in action, except as permitted by law during a completed default, securities or cash, except when pledged, or merchandise or equipment manufactured or acquired for resale.  The mortgage creates a lien on the interest of IPC in property subsequently acquired, other than excepted property, subject to limitations in the case of consolidation, merger or sale of all or substantially all of the assets of IPC.

At September 30, 2006, IFS had $38 million of debt related to investments in affordable housing with interest rates ranging from 3.65 percent to 8.38 percent, due between 2006 and 2010.  The investments in affordable housing developments that collateralize this debt had a net book value of $62 million at September 30, 2006.  IFS' $13 million Series 2003-1 tax credit note is non-recourse to both IFS and IDACORP.  The $7 million Series 2003-2 tax credit note and other outstanding debt are recourse only to IFS.

On October 3, 2006, IPC completed a tax-exempt bond financing in which Sweetwater County, Wyoming issued and sold $116,300,000 aggregate principal amount of its Pollution Control Revenue Refunding Bonds (Idaho Power Company Project) Series 2006.  The bonds will mature on July 15, 2026.  The $116.3 million proceeds were loaned by Sweetwater County to IPC pursuant to a Loan Agreement, dated as of October 1, 2006, between Sweetwater County and IPC (the Loan Agreement)  On October 10, 2006, the proceeds of the new bonds, together with certain other moneys of IPC, were used to refund Sweetwater County's (i) Pollution Control Revenue Refunding Bonds (Idaho Power Company Project) Series 1996A that were outstanding in the aggregate principal amount of $68,100,000, (ii) Pollution Control Revenue Refunding Bonds (Idaho Power Company Project) Series 1996B that were outstanding in the aggregate principal amount of $24,200,000 and (iii) Pollution Control Revenue Refunding Bonds (Idaho Power Company Project) Series 1996C that were outstanding in the aggregate principal amount of $24,000,000.  The regularly scheduled principal and interest payments on the bonds, and principal and interest payments on the bonds upon mandatory redemption on determination of taxability, are insured by a financial guaranty insurance policy issued by AMBAC Assurance Corporation.  IPC and AMBAC have entered into an Insurance Agreement, dated as of October 3, 2006, pursuant to which IPC has agreed, among other things, to pay certain premiums to AMBAC and to reimburse AMBAC for any payments made under the policy.

In order to secure IPC's obligation to make principal and interest payments on the loan made to IPC, IPC issued and delivered to a trustee IPC's First Mortgage Bonds, Pollution Control Series C, in a principal amount equal to the principal amount of the new bonds.

Credit Facilities
IDACORP has a $150 million five-year credit facility that expires on March 31, 2010.  At September 30, 2006, no loans were outstanding on IDACORP's credit facility and $6 million of commercial paper was outstanding.

21

Table of Contents

At September 30, 2006, IPC had regulatory authority to incur up to $250 million of short-term indebtedness.  IPC has a $200 million five-year credit facility that expires on March 31, 2010.  At September 30, 2006, no loans were outstanding on IPC's credit facility and $26 million of commercial paper and $1 million of notes (outside of the credit facility) were outstanding.

5.  COMMITMENTS AND CONTINGENCIES:

Off-Balance Sheet Arrangements
The federal Surface Mining Control and Reclamation Act of 1977 and similar state statutes establish operational, reclamation and closure standards that must be met during and upon completion of mining activities.  These obligations mandate that mine property be restored consistent with specific standards and the approved reclamation plan.  The mining operations at the Bridger Coal Company are subject to these reclamation and closure requirements.  IPC has agreed to guarantee the performance of reclamation activities at Bridger Coal Company, of which Idaho Energy Resources Co., a subsidiary of IPC, owns a one-third interest.  This guarantee, which is renewed each December, was $60 million at September 30, 2006.  Bridger Coal has a reclamation trust fund set aside specifically for the purpose of paying these reclamation costs and expects that the fund will be sufficient to cover all such costs.  Because of the existence of the fund, the estimated fair value of this guarantee is minimal.

Regional Transmission Organization
Over the last several years, IPC has spent funds supporting the development of Grid West, a Northwest regional transmission organization (RTO).  As of September 30, 2006, IPC had recorded $1.1 million of loans to Grid West and $2.3 million of deferred internal costs from participating in the development effort.  These amounts were initially deferred anticipating future recovery through Grid West tariffs.  IPC ceased funding Grid West after the first quarter of 2006 and Grid West was dissolved on April 11, 2006.  IPC no longer expects reimbursement of either amount from Grid West.  IPC's accumulation of Grid West development costs in a deferred expense account is consistent with a 2004 accounting order that IPC received from the FERC.

Grid West Deferral in Oregon:   On April 4, 2006, IPC filed a request for an accounting order from the OPUC addressing the deferral of costs related to the development of Grid West.  On August 22, 2006, the OPUC granted IPC's request for the deferral of the costs of unrecoverable Grid West loans; however, the OPUC denied IPC's request to defer an immaterial amount of internal costs incurred directly in the development of Grid West.

Grid West Deferral in Idaho:   On April 4, 2006, IPC filed a request for an accounting order from the IPUC addressing the deferral of costs related to the development of Grid West.  The total deferral request was $3.4 million.  On June 29, 2006, the IPUC determined that the case would be processed by modified procedure.  IPC argued that it should be allowed deferral of the principal and interest on the RTO loan amounts, a carrying charge on the deferred balance and recovery of the incremental internal costs it identified in its application.  On October 24, 2006, the IPUC issued an order granting $1.1 million related to the principal of the RTO loans over a five-year amortization beginning January 1, 2007 and denying recovery of the remaining items.  IPC has until November 14, 2006, to petition the IPUC for reconsideration.  Following a final decision from the IPUC, IPC will make a filing with the FERC for recovery of Grid West costs.

If IPC is unsuccessful with either the IPUC or with the FERC, some or all of the remaining costs will be expensed.

LEGAL PROCEEDINGS

Reference is made to IDACORP's and IPC's Annual Report on Form 10-K for the year ended December 31, 2005, and Quarterly Reports on Form 10-Q for the quarters ended March 31, 2006, and June 30, 2006, for a discussion of all material pending legal proceedings to which IDACORP and IPC and their subsidiaries are parties.  The following discussion provides a summary of material developments that occurred in those proceedings during the period covered by this report and of any new material proceedings instituted during the period covered by this report.

22

Table of Contents

Proceedings Relating to the Western Power Markets
IDACORP, IPC and/or IE are involved in a number of proceedings which relate to the western power markets.

Public Utility District No. 1 of Grays Harbor County, Washington
On July 25, 2006, the case was dismissed with prejudice by the Honorable Robert H. Whaley, sitting by designation in the U.S. District Court for the Southern District of California, pursuant to an agreed resolution of the matter between Grays Harbor and IDACORP, IPC and IE. The settlement did not have a material adverse effect on IDACORP's consolidated financial position, results of operation or cash flows.

Port of Seattle
On March 7, 2006, the U.S. Court of Appeals for the Ninth Circuit heard argument on the Port of Seattle's appeal of the U.S. District Court for the Southern District of California's dismissal of its complaint with prejudice.  On March 30, 2006, the Ninth Circuit issued an order denying the Port of Seattle's appeal and affirming the dismissal of the entire case.  The dismissal of the case, with prejudice, became final on June 28, 2006, when the Port of Seattle elected not to file a certiorari petition to the U.S. Supreme Court.

Wah Chang
Following the October 18, 2005, consolidation of Wah Chang's appeal of the dismissal order to the U.S. Court of Appeals for the Ninth Circuit with an identical order in Wah Chang v. Duke Energy Trading and Marketing, IDACORP, IPC and IE filed an answering brief on November 30, 2005.  Wah Chang filed its reply brief on January 6, 2006.  Wah Chang's appeal to the U.S. Court of Appeals for the Ninth Circuit has now been fully briefed; however, no date has yet been set for oral argument.  IDACORP, IPC and IE intend to vigorously defend their position in this proceeding and believe this matter will not have a material adverse effect on their consolidated financial positions, results of operations or cash flows.

City of Tacoma
The City of Tacoma's March 10, 2005, appeal to the U.S. Court of Appeals for the Ninth Circuit of the dismissal of the case by Judge Whaley has been fully briefed; however, no date has yet been set for oral argument.  IDACORP, IPC and IE intend to vigorously defend their position in this proceeding and believe this matter will not have a material adverse effect on their consolidated financial positions, results of operations or cash flows.

Wholesale Electricity Antitrust Cases I & II
In April 2002, several subsidiaries of Reliant Energy, Inc. (Reliant) and Duke Energy Corporation (Duke) filed cross-complaints against IE and IPC and numerous other participants in the California energy market.  The cross-complaints sought indemnification for any liability that may arise from original complaints filed against Reliant and Duke with respect to charges of unlawful and unfair business practices in the California energy markets under California law.  On November 9, 2005, both Duke and Reliant submitted to the California Superior Court stipulations with IE and IPC to conditionally dismiss, with prejudice, the cross-complaints, subject to reinstatement if proposed settlements between Duke and Reliant and the plaintiffs of the underlying actions were not approved by the court.  Neither IE nor IPC paid any amount to Duke or to Reliant to obtain these dismissals.

On December 14, 2005, the court granted final approval of the Duke settlement with the plaintiffs.  The Court's order granting final approval of the Duke settlement became final on March 14, 2006.  On January 6, 2006, the court granted preliminary approval of the Reliant settlement.  On March 30, 2006, oppositions and objections to the Reliant settlement were filed by certain parties under the Eggers case caption, including by the States of Montana and Idaho.  Neither IPC nor IE is a party to the Eggers case, which seeks to recover damages on behalf of consumers in western states other than California.  A hearing on final approval of the Reliant settlement was held on April 28, 2006.  At the hearing, the court ruled that the California class settlement would receive final approval contingent on a satisfactory showing that the notice to those class members was adequate.  As for the Eggers case, the court set a briefing schedule to provide evidence and oral argument regarding the State of Montana's treatment by its class representative and Montana's connection to the California energy market.

23

Table of Contents

On May 30, 2006, the court signed and approved the Judgment, Final Order, and Decree Granting Final Approval to the Reliant settlement.  The court also signed and approved the Order Granting Reliant's Motion for Good Faith Settlement Determination.  The order approving the Reliant settlement became final on July 31, 2006.  On July 14, 2006, the court held a separate hearing to consider approval of the settlement of the Eggers action, and thereafter signed and approved the Judgment, Final Order and Decree Granting Final Approval to the Class Action Settlement in the Eggers case.  All appeal periods have now expired.

California Refund
On February 17, 2006, IE and IPC jointly filed with the California Parties (Pacific Gas & Electric Company, San Diego Gas & Electric Company, Southern California Edison, the California Public Utilities Commission, the California Electricity Oversight Board, the California Department of Water Resources and the California Attorney General) an Offer of Settlement at the FERC.  Other parties had until March 9, 2006, to elect to become an additional settling party.  The majority of other parties chose to opt out of the settlement.  After consideration of comments, the FERC approved the settlement on May 22, 2006.  Under the terms of the settlement, IE and IPC assigned $24.25 million of the rights to accounts receivable from the California Independent System Operator (Cal ISO) and California Power Exchange (CalPX) to the California Parties to pay into an escrow account for refunds to settling parties.  Amounts from that escrow not used for settling parties and $1.5 million of the remaining IE and IPC receivables that are to be retained by the CalPX are available to fund, at least partially, payment of the claims of any non-settling parties if they prevail in the remaining litigation of this matter.  Any excess funds remaining at the end of the case are to be returned to IDACORP.  Approximately $10.25 million of the remaining IE and IPC receivables was paid to IE and IPC under the Settlement.

On June 21, 2006, the Port of Seattle, Washington filed a request for rehearing of the FERC order approving the Settlement.  On July 10, 2006, IDACORP and the California Parties filed a response to Port of Seattle's request for rehearing.  On October 5, 2006, the FERC issued an order denying the Port of Seattle's request for rehearing.  The time for seeking review of the FERC's Order will not expire until December 4, 2006.  IDACORP is unable to predict at this time if any person will seek such review or, if such review is sought, what the eventual outcome will be.

For some time the Ninth Circuit Court of Appeals held in abeyance consolidated petitions for review (in excess of 100) of FERC orders related to the California Refund proceeding.  On September 21, 2004, the Ninth Circuit convened case management proceedings on these petitions and on October 22, 2004, severed a subset of issues for briefing related to: (1) which parties are subject to the FERC's refund jurisdiction under section 201(f) of the Federal Power Act; (2) the temporal scope of refunds under section 206 of the Federal Power Act; and (3) which categories of transaction are subject to refunds.  Oral argument was held on April 12-13, 2005.  On September 6, 2005, the Ninth Circuit issued a decision on the jurisdictional issues concluding that the FERC lacked refund authority over wholesale electric energy sales made by governmental entities and non-public utilities.  On August 2, 2006, the Ninth Circuit issued its decision on the appropriate temporal reach and the type of transactions subject to the FERC refund orders and concluded, among other things, that all transactions at issue in the case that occurred within or as a result of the CalPX and the Cal ISO were the proper subject of refund proceedings; refused to expand the refund proceedings into the bilateral markets including transactions with the California Department of Water Resources; approved the refund effective date as October 2, 2000, but also required the FERC to consider whether refunds, including possibly market-wide refunds, should be required for an earlier time due to claims that some market participants had violated governing tariff obligations (although the decision did not specify when that time would start, the California Parties generally had sought further refunds starting May 1, 2000); and effectively expanded the scope of the refund proceeding to transactions within the CalPX and Cal ISO markets outside the 24-hour spot market and energy exchange transactions.

IDACORP believes that these decisions should have no material effect on IDACORP under the terms of the IDACORP Settlement with the California Parties approved by the FERC on May 22, 2006.

California Power Exchange Chargeback
Based upon the Offer of Settlement filed with the FERC on February 17, 2006, between the California Parties and IE and IPC and discussed above in "California Refund", the California Parties supported a motion filed by IE and IPC with the FERC seeking an Order Directing Return of Chargeback Amounts currently held by the CalPX totaling $2.27 million.  In the May 22, 2006, Order approving the Settlement, the FERC granted the IE and IPC motion for return of chargeback funds held by the CalPX.  On June 1, 2006, IE received approximately $2.5 million from the CalPX representing the return of $2.27 million in chargeback funds plus interest.

24

Table of Contents

Market Manipulation
Pursuant to the Offer of Settlement filed with the FERC on February 17, 2006, between the California Parties and IE and IPC and discussed above in "California Refund", the requests for rehearing of the California Parties and other settling parties of the FERC's approval of an earlier settlement with the FERC staff regarding allegations of "gaming" are deemed to be withdrawn.  On May 22, 2006, the FERC issued an order approving the February 17, 2006, Offer of Settlement.  On October 11, 2006, the FERC issued an Order denying rehearing of its earlier approval of the "gaming" allegations, thereby effectively terminating the FERC investigations as to IPC and IE regarding bidding behavior, physical withholding of power and "gaming" without finding of wrongdoing.  The time for seeking review of the FERC's Order will not expire until December 11, 2006.  IPC and IE are unable to predict at this time if any person will seek such review or, if such review is sought, what the eventual outcome will be.

Pacific Northwest Refund
On September 24, 2001, the FERC Administrative Law Judge submitted recommendations and findings to the FERC finding that prices in the Pacific Northwest during the December 25, 2000, through June 20, 2001, time period should be governed by the Mobile-Sierra standard of public interest rather than the just and reasonable standard, that the Pacific Northwest spot markets were competitive and that no refunds should be allowed.  The FERC approved these recommendations on June 25, 2003, and multiple parties then appealed to the Ninth Circuit Court of Appeals.  IE and IPC were parties in the FERC proceeding and are participating in the appeal.  Briefing on the appeal was completed on May 25, 2005, and oral argument has been scheduled for January 8, 2007.  The Settlement approved by the FERC on May 22, 2006, resolves all claims the California Parties have against IE and IPC in the Pacific Northwest Refund proceeding.  The settlement with Grays Harbor resolves all claims Grays Harbor has against IE and IPC in this proceeding.  IE and IPC are unable to predict the outcome as to all other parties in this proceeding.

Other Litigation

Shareholder Lawsuit
On March 29, 2006, the U.S. District Court for the District of Idaho (Judge Edward J. Lodge) issued an Order in this case (Powell v. IDACORP) adopting the Report and Recommendation of Magistrate Judge Williams issued on September 14, 2005, granting the defendants' (IDACORP and certain of its officers and directors) motion to dismiss because plaintiffs failed to satisfy the pleading requirements for loss causation.  However, Judge Lodge modified the Report and Recommendation and ruled that plaintiffs had until May 1, 2006, to file an amended complaint only as to the loss causation element.  On May 1, 2006, the plaintiffs filed an amended complaint.  The defendants filed a motion to dismiss the amended complaint on June 16, 2006, asserting that the amended complaint still failed to satisfy the pleading requirements for loss causation.  Briefing on this most recent motion to dismiss was completed on August 28, 2006.  IDACORP and the other defendants intend to defend themselves vigorously against the allegations.  IDACORP cannot, however, predict the outcome of these matters.

Western Shoshone National Council
On April 10, 2006, the Western Shoshone National Council (which purports to be the governing body of the Western Shoshone Nation) and certain of its individual tribal members filed a First Amended Complaint and Demand for Jury Trial in the U.S. District Court for the District of Nevada, naming IPC and other unrelated entities as defendants.

Plaintiffs allege that IPC's ownership interest in certain land, minerals, water or other resources was converted and fraudulently conveyed from lands in which the plaintiffs had historical ownership rights and Indian title dating back to the 1860's or before.  Although it is unclear from the complaint, it appears plaintiffs' claims relate primarily to lands within the state of Nevada.  Plaintiffs seek a judgment declaring their title to land and other resources, disgorgement of profits from the sale or use of the land and resources, a decree declaring a constructive trust in favor of the plaintiffs of IPC's assets connected to the lands or resources, an accounting of money or things of value received from the sale or use of the lands or resources, monetary damages in an unspecified amount for waste and trespass and a judgment declaring that IPC has no right to possess or use the lands or resources.

25

Table of Contents

On May 1, 2006, IPC filed an Answer to plaintiffs' First Amended Complaint denying all liability to the plaintiffs and asserting certain affirmative defenses including collateral estoppel and res judicata, preemption, impossibility and impracticability, failure to join all real and necessary parties, and various defenses based on untimeliness.  On June 19, 2006, IPC filed a motion to dismiss plaintiffs' First Amended Complaint, asserting, among other things, that the Court lacks subject matter jurisdiction and that plaintiffs failed to join an indispensable party (namely, the United States government).  Briefing on the motion to dismiss was completed on September 28, 2006.  IPC intends to vigorously defend its position in this proceeding, but is unable to predict the outcome of this matter.

6.  REGULATORY MATTERS:

General Rate Cases
Oregon:  On September 21, 2004, IPC filed an application with the OPUC to increase general rates an average of 17.5 percent or approximately $4.4 million annually.  A partial settlement resolved most issues in a manner consistent with the results of the corresponding Idaho general rate case.  The most significant issue in this proceeding was the appropriate quantification of net power supply expenses for purposes of setting rates.  The OPUC staff proposed that net power supply expenses for IPC be set at a negative number - meaning that IPC should be able to sell enough surplus energy to pay for all fuel and purchased power expenses and still have revenue left over to offset other costs.  The bulk of IPC's rebuttal was directed at this position.  A hearing was conducted on May 23, 2005.  The OPUC issued its order in July 2005 authorizing an increase of $0.6 million in annual revenues for an average of 2.37 percent.  The OPUC adopted the OPUC staff's argument for the negative net power supply costs, thus reducing IPC's initial rate request of $4.4 million by $2.4 million with this one adjustment.

On September 26, 2005, IPC filed a complaint with the Circuit Court of Marion County, Oregon asking the court to reverse the portion of the OPUC's general rate case order related to the determination of net power supply costs.  Following a full review of the matter, the court denied IPC's reversal request on August 29, 2006.  IPC has until November 13, 2006, to file an appeal with the Oregon Court of Appeals.

Deferred (Accrued) Net Power Supply Costs
IPC's deferred (accrued) net power supply costs consisted of the following (in thousands of dollars):

Idaho :   IPC has a Power Cost Adjustment (PCA) mechanism that provides for annual adjustments to the rates charged to its Idaho retail customers.  These adjustments are based on forecasts of net power supply costs, which are fuel and purchased power less off-system sales, and the true-up of the prior year's forecast.  During the year, 90 percent of the difference between the actual and forecasted costs is deferred with interest.  The ending balance of this deferral, called the true-up for the current year's portion and the true-up of the true-up for the prior years' unrecovered portion, is then included in the calculation of the next year's PCA.

On May 25, 2006, the IPUC approved IPC's 2006-2007 PCA filing with an effective date of June 1, 2006.  The filing reduced the PCA component of customers' rates from the existing level, which was recovering $76.7 million above then-existing base rates, to a level that is $46.8 million below those base rates, a decrease of approximately $123.5 million.

26

Table of Contents

On April 13, 2006, IPC filed testimony requesting review of one component of the PCA referred to as the load growth adjustment rate, as agreed to in the stipulation of the parties settling the 2005 general rate case.  The load growth adjustment rate provides a reduction to power supply expenses for PCA purposes when loads grow from levels included in IPC's base rates.  IPC maintains that this reduction to expenses should be equal to the relative increase in revenues received as a result of load growth.  The IPUC Staff and other parties to the proceeding filed testimony on September 15, 2006, advocating load growth adjustment rates above both the existing rate and IPC's proposal.  A hearing was held on October 30, 2006.  The dollar impact of load growth adjustment rates is significant and increasing, based on continuing growth within IPC's territory.  Any increase in the load growth adjustment rate as a result of this proceeding would magnify the impact.  In its rebuttal testimony, IPC estimated that the IPUC Staff proposal, if implemented last year, would have resulted in $20 million of power supply expense attributable to load growth from April 1, 2005 through March 31, 2006, that would not have been recoverable by IPC when compared to IPC's proposal for full recovery of power supply expense attributable to load growth.

On June 1, 2005, IPC implemented the 2005-2006 PCA, which held the PCA component of customers' rates at the existing level, recovering $71 million above base rates.  By IPUC order, the PCA included $12 million in lost revenues and $2 million in related interest resulting from IPC's Irrigation Load Reduction Program that was in place in 2001.  The PCA deferred recovery of approximately $28 million of power supply costs, or 4.75 percent, for one year to help mitigate the impacts of other rate increases.  The $28 million was included in the 2006-2007 PCA filing, and IPC earned a two percent carrying charge on the balance.

Oregon :   On April 28, 2006, IPC filed for an accounting order with the OPUC to defer net power supply costs for the period of May 1, 2006, through April 30, 2007, in anticipation of higher than "normal" power supply expenses.  In the Oregon general rate case discussed above, "normal" power supply expenses were set at a negative number (meaning that under normal water conditions IPC should be able to sell enough surplus energy to pay for all fuel and purchased power expenses and still have revenue left over to offset other costs).  The forecasted system net power supply expenses included in this deferral filing were $64 million, which is $65.9 million higher than the normalized power supply expenses established in the Oregon general rate case.  IPC requested authorization to defer an estimated $3.3 million, the Oregon jurisdictional share of the $65.9 million.  IPC also requested that it earn its Oregon authorized rate of return on the deferred balance and recover the amount through rates in future years, as approved by the OPUC.  The parties met on September 20, 2006, and began negotiating for a PCA mechanism for IPC's Oregon jurisdiction, and agreed to suspend discussion of the deferral application while the PCA negotiations are ongoing.  The parties believe that any agreement regarding a PCA mechanism may impact resolution of IPC's deferral application. The parties are planning to meet again in early November 2006.

On March 2, 2005, IPC filed for an accounting order with the OPUC to defer net power supply costs for the period of March 2, 2005 through February 28, 2006, in anticipation of continued low water conditions.  The forecasted net power supply costs included in this filing were $169 million, of which $3 million related to the Oregon jurisdiction.  IPC proposed to use the same methodology for this deferral filing that was accepted in 2002 for Oregon's share of IPC's 2001 net power supply expenses.  On July 1, 2005, IPC, the OPUC staff, and the Citizen's Utility Board entered into a stipulation requesting that the OPUC accept IPC's proposed methodology.  Under this methodology, IPC will earn its Oregon authorized rate of return on the deferred balance and will recover the amount through rates in future years, as approved by the OPUC.  The OPUC issued Order 05-870 on July 28, 2005, approving the stipulation.  On April 19, 2006, IPC filed a request for review and acknowledgement of its deferred net power supply costs for the period of March 2, 2005, through February 28, 2006.  The deferral amount was quantified by IPC to be $2.7 million.  On June 14, 2006, a settlement conference was held; however, settlement is pending further staff review.

The timing of future recovery of Oregon power supply cost deferrals is subject to an Oregon statute that specifically limits rate amortizations of deferred costs to six percent per year.  IPC is currently amortizing through rates power supply costs associated with the western energy situation of 2001.  Full recovery of the 2001 deferral is not expected until 2009, at which time the rate amortization of the 2005-2006 deferral could begin.  A 2006-2007 deferral would have to be amortized sequentially following the full recovery of the authorized 2005-2006 deferral.

27

Table of Contents

Emission Allowances
In June 2005, IPC filed applications with the IPUC and OPUC requesting blanket authorization for the sale of excess SO ₂ emission allowances and an accounting order.  The IPUC issued Order 29852 on August 22, 2005, authorizing the sale and interim accounting treatment.  The OPUC issued Order 05-983 on September 13, 2005, stating that IPC did not need a blanket order to sell emission allowances and approved the interim accounting treatment.

As of September 30, 2006, IPC has sold 78,000 SO ₂ emission allowances for approximately $81.6 million (before income taxes and expenses) on the open market.  After subtracting transaction fees, the total amount of sales proceeds to be allocated to the Idaho jurisdiction is approximately $76.8 million ($46.8 million net of tax, assuming a tax rate of approximately 39 percent).  Through allowance year 2006, IPC has approximately 32,000 excess allowances remaining.

Pursuant to the IPUC order, the IPUC staff held several workshops and settlement discussions.  On May 12, 2006, the IPUC approved a stipulation filed in April 2006 by IPC on behalf of several parties.  The stipulation allows IPC to retain ten percent, or approximately $4.7 million after tax, of the emission allowance net proceeds as a shareholder benefit.  The remaining 90 percent of the sales proceeds ($69.1 million) plus a carrying charge will be recorded as a customer benefit and included as a line-item in the PCA true-up.  The carrying charge will be calculated on $42.1 million, the net-of-tax amount allocable to Idaho jurisdiction customers.  This customer benefit is included in IPC's PCA calculations as a credit to the PCA true-up balance and will be reflected in PCA rates during the June 1, 2007 through May 31, 2008 PCA rate year.

There is no current OPUC proceeding with respect to SO ₂ emission allowances, and IPC cannot predict the outcome of any future OPUC ratemaking proceeding relating to this issue.

7.  INDUSTRY SEGMENT INFORMATION:

IDACORP has identified two reportable segments: utility operations and IFS.  ITI and IDACOMM, which had previously been identified as reportable segments, are now reported as discontinued operations (see Note 10).

The utility operations segment's primary sources of revenue are the regulated operations of IPC.  IPC's regulated operations include the generation, transmission, distribution, purchase and sale of electricity.  This segment also includes income from Bridger Coal Company, an unconsolidated joint venture also subject to regulation.  The IFS segment represents that subsidiary's investments in affordable housing developments and historic rehabilitation projects.  Operating segments not included above are below the quantitative thresholds for reportable segments and are included in the "All Other" category.  This category is comprised of 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.

28

Table of Contents

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

29

Table of Contents

The following table shows the components of net periodic benefit costs for the nine months ended September 30 (in thousands of dollars):