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**UNITEDSTATES SECURITIES AND EXCHANGE COMMISSION****Washington, D.C. 20549****FORM10-K**

(Mark One)

| X |  | ANNUAL  REPORT PURSUANT TO SECTION 13 OR 15 (d) OF |
|---|--|----------------------------------------------------|
|   |  | THE  SECURITIES EXCHANGE ACT OF 1934               |
|   |  | For the fiscal year ended December  31, 2006       |

OR

|  |  TRANSITION REPORT PURSUANT  TO SECTION 13 OR 15(d) OF  |
|--|-------------------------------------------------------------------|
|  | THE SECURITIES EXCHANGE ACT  OF 1934                              |

For the transition periodfrom ................... to..................................................................

|                                                              |                                  | Exact name of registrants as specified in      |          |                       |
|--------------------------------------------------------------|----------------------------------|------------------------------------------------|----------|-----------------------|
| Commission                                                   |                                  | their charters, address of principal executive |          | IRS Employer          |
| File Number                                                  |                                  | offices, zip code and telephone number         |          | Identification Number |
| 1-14465                                                      |                                  | **IDACORP, Inc.**                              |          | 82-0505802            |
| 1-3198                                                       |                                  | **Idaho Power Company**                        |          | 82-0130980            |
|                                                              |                                  | 1221 W. Idaho Street                           |          |                       |
|                                                              |                                  | Boise, ID 83702-5627                           |          |                       |
|                                                              |                                  | (208) 388-2200                                 |          |                       |
| State of  incorporation:  Idaho                         |
| Websites:  www.idacorpinc.com  and www.idahopower.com   |
|                                                              |                                  | Name of exchange on                            |
| SECURITIES REGISTERED  PURSUANT TO SECTION 12(b) OF THE ACT: |                                  | which registered                               |
| IDACORP, Inc.:                                               | Common Stock, without par  value |                                                | New York |
|                                                              | Preferred Share Purchase  Rights |                                                |          |
| SECURITIES REGISTERED  PURSUANT TO SECTION 12(g) OF THE ACT: |                                  |                                                |
| Idaho Power Company:                                         | Preferred Stock                  |                                                |          |
|                                                              |                                  |                                                |          |                       |  |

Indicateby check mark whether the registrants are well-known seasoned issuers, asdefined in Rule 405 of the Securities Act.

| IDACORP, Inc. | Yes | (    ) | No | ( X ) | Idaho Power Company | Yes | (    ) | No | ( X ) |
|---------------|-----|-----------------------|----|-------|---------------------|-----|-----------------------|----|-------|

Indicateby check mark if the registrants are not required to file reports pursuant toSection 13 or Section 15(d) of the Act.

| IDACORP, Inc. | Yes | (    ) | No | ( X ) | Idaho Power Company | Yes | (    ) | No | ( X ) |
|---------------|-----|-----------------------|----|-------|---------------------|-----|-----------------------|----|-------|

Indicateby check mark whether the registrants (1) have filed all reports required to befiled by Section 13 or 15(d) of the Securities Exchange Act of 1934 during thepreceding 12 months (or for such shorter period that the registrants wererequired to file such reports), and (2) have been subject to such filingrequirements for the past 90 days.Yes  ( X  )  No  (    )

Indicate by check mark ifdisclosure of delinquent filers pursuant to Item 405 of Regulation S-K is notcontained herein, and will not be contained, to the best of registrants'knowledge, in definitive proxy or information statements incorporated byreference in Part III of this Form 10-K or any amendment to this Form 10-K.   (X )

Indicate by check markwhether the registrants are large accelerated filers, accelerated filers, ornon-accelerated filers.

| IDACORP, Inc.:       |                         |                       |                   |                       |                       |                       |
|----------------------|-------------------------|-----------------------|-------------------|-----------------------|-----------------------|-----------------------|
|                      | Large accelerated filer | ( X )                 | Accelerated filer | (    ) | Non-accelerated filer | (    ) |
| Idaho Power Company: |                         |                       |                   |                       |                       |                       |
|                      | Large accelerated filer | (    ) | Accelerated filer | (    ) | Non-accelerated filer | ( X )                 |
|                      |                         |                       |                   |                       |                       |                       |  |

Indicate by check mark whether the registrants are shellcompanies (as defined in Rule 12b-2 of the Act).

| IDACORP, Inc. | Yes | (    ) | No | ( X ) | Idaho Power Company | Yes | (    ) | No | ( X ) |
|---------------|-----|-----------------------|----|-------|---------------------|-----|-----------------------|----|-------|

Aggregate market value ofvoting and non-voting common stock held by nonaffiliates (June 30, 2006):

| IDACORP, Inc.: | $1,468,190,938 | Idaho Power Company: | None |
|----------------|----------------|----------------------|------|

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Number of shares of commonstock outstanding at January 31, 2007:

| IDACORP, Inc.:       | 43,635,183                            |
|----------------------|---------------------------------------|
| Idaho Power Company: | 39,150,812 all held by  IDACORP, Inc. |

| **Documents Incorporated by Reference:** |
|------------------------------------------|
| Part III, Items 10 - 14                  | Portions  of IDACORP, Inc.'s definitive proxy statement to be filed pursuant to  Regulation |
|                                     | 14A for  the 2007 Annual Meeting of Shareholders to be held on May 17, 2007. |

This combined Form 10-Krepresents separate filings by IDACORP, Inc. and Idaho Power Company. Information contained herein relating to an individual registrant is filed bythat registrant on its own behalf.  Idaho Power Company makes no representationas to the information relating to IDACORP, Inc.'s other operations.

Idaho Power Company meets theconditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K andis therefore filing this Form with the reduced disclosure format.

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| ** **              |
|-------------------------|
| **COMMONLY USED TERMS** |
| AFDC                    | - | Allowance for Funds Used  During Construction |
| ARO                     | - | Asset Retirement Obligation |
| Cal ISO                 | - | California Independent System Operator |
| CalPX                   | - | California Power Exchange |
| cfs                     | - | Cubic feet per second |
| CSPP                    | - | Cogeneration and Small  Power Production |
| Energy Act              | - | Energy Policy Act of 2005 |
| EPS                     | - | Earnings per share |
| ESA                     | - | Endangered Species Act |
| FASB                    | - | Financial Accounting  Standards Board |
| FERC                    | - | Federal Energy Regulatory  Commission |
| FIN                     | - | Financial Accounting  Standards Board Interpretation |
| Fitch                   | - | Fitch, Inc. |
| FPA                     | - | Federal Power Act |
| FSP                     | - | Financial Accounting  Standards Board Staff Position |
| GAAP                    | - | Generally Accepted Accounting  Principles |
| Ida-West                | - | Ida-West Energy, a  subsidiary of IDACORP, Inc. |
| IE                      | - | IDACORP Energy, a  subsidiary of IDACORP, Inc. |
| IFS                     | - | IDACORP Financial Services,  a subsidiary of IDACORP, Inc. |
| IPC                     | - | Idaho Power Company, a  subsidiary of IDACORP, Inc. |
| IPUC                    | - | Idaho Public Utilities Commission |
| IRP                     | - | Integrated Resource Plan |
| ITI                     | - | IDACORP Technologies, Inc. |
| kW                      | - | Kilowatt |
| maf                     | - | Million acre feet |
| MD&A                | - | Management's Discussion and  Analysis of Financial Condition and Results of Operations |
| Moody's                 | - | Moody's Investors Service |
| MW                      | - | Megawatt |
| MWh                     | - | Megawatt-hour |
| NEPA                    | - | National Environmental  Policy Act of 1996 |
| O&M                 | - | Operations and Maintenance |
| OPUC                    | - | Oregon Public Utility Commission |
| PCA                     | - | Power Cost Adjustment |
| PM&E                | - | Protection, Mitigation and  Enhancement |
| PURPA                   | - | Public Utility Regulatory  Policies Act of 1978 |
| RFP                     | - | Request for Proposal |
| RTO                     | - | Regional Transmission  Organization |
| S&P                 | - | Standard & Poor's  Ratings Services |
| SFAS                    | - | Statement of Financial  Accounting Standards |
| SO2                     | - | Sulfur Dioxide |
| Valmy                   | - | North Valmy Steam Electric  Generating Plant |
| VIEs                    | - | Variable Interest Entities |

 

| **TABLE OF CONTENTS** |
|-----------------------|
|                       | **Page** |
| **Part I**            |
|                       |
|                       | Item 1. | Business | 1-10 |
|                       | Item 1A. | Risk Factors | 10-12 |
|                       | Item 1B. | Unresolved Staff Comments | 12 |
|                       | Item 2. | Properties | 13-14 |
|                       | Item 3. | Legal Proceedings | 14 |
|                       | Item 4. | Submission of Matters to a  Vote of Security Holders | 14 |
|                       |
|                       | Executive Officers of the  Registrants | 15-16 |
|                       |
| **Part II**           |
| ** **            |
|                       | Item 5. | Market for Registrant's  Common Equity, Related Stockholder |  |
|                       |  |  | Matters and Issuer  Purchases of Equity Securities | 17-18 |
|                       | Item 6. | Selected Financial Data | 19 |
|                       | Item 7. | Management's Discussion and  Analysis of Financial Condition and |  |
|                       |  |  | Results of Operations | 19-61 |
|                       | Item 7A. | Quantitative and  Qualitative Disclosures about Market Risk | 61-62 |
|                       | Item 8. | Financial Statements and  Supplementary Data | 63-120 |
|                       | Item 9. | Changes in and  Disagreements with Accountants on Accounting and |  |
|                       |  |  | Financial Disclosure | 120 |
|                       | Item 9A. | Controls and Procedures | 120-125 |
|                       | Item 9B. | Other Information | 125 |
| ** **            |
| **Part III**          |
| ** **            |
|                       | Item 10. | Directors, Executive  Officers and Corporate Governance* | 125 |
|                       | Item 11. | Executive Compensation* | 125 |
|                       | Item 12. | Security Ownership of  Certain Beneficial Owners and Management and Related |  |
|                       |  |  | Stockholder Matters* | 125-126 |
|                       | Item 13. | Certain Relationships and  Related Transactions, and Director Independence* | 126 |
|                       | Item 14. | Principal Accountant Fees  and Services* | 126-127 |
|                       |
| **Part IV**           |
| ** **            |
|                       | Item 15. | Exhibits and Financial  Statement Schedules | 127-137 |
|                       |
|                       | Signatures | 138-139 |
|                       |
|                       |  |  |
|                       |
|                       | *Except as indicated in  Item 12, IDACORP, Inc. information is incorporated by reference to IDACORP,  Inc.'s |
|                       | definitive proxy statement  for the 2007 Annual Meeting of Shareholders. |

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**SAFE HARBOR STATEMENT**This Form 10-K contains "forward-lookingstatements" intended to qualify for the safe harbor from liability establishedby the Private Securities Litigation Reform Act of 1995.  Forward-lookingstatements should be read with the cautionary statements and important factorsincluded in this Form 10-K at Part II, Item 7- "Management's Discussion andAnalysis of Financial Condition and Results of Operations (MD&A) -FORWARD-LOOKING INFORMATION."  Forward-looking statements are all statementsother than statements of historical fact, including without limitation thosethat are identified by the use of the words "anticipates," "believes," "estimates,""expects," "intends," "plans," "predicts," "projects," "may result," "maycontinue," or similar expressions.

**PART I - IDACORP, Inc. andIdaho Power Company**

**ITEM1.  BUSINESS**

**OVERVIEW:**

IDACORP, Inc. (IDACORP) is aholding company formed in 1998 whose principal operating subsidiary is IdahoPower Company (IPC).  IDACORP is subject to the provisions of the PublicUtility Holding Company Act of 2005 (2005 Act), which provides certain accessto books and records to the Federal Energy Regulatory Commission (FERC) andstate utility regulatory commissions and imposes certain record retention andreporting requirements on IDACORP.

IPC is an electric utilityengaged in the generation, transmission, distribution, sale and purchase ofelectric energy and is regulated by the FERC and the state regulatorycommissions of Idaho and Oregon.  IPC is the parent of Idaho Energy ResourcesCo., a joint venturer in Bridger Coal Company, which supplies coal to the JimBridger generating plant owned in part by IPC.

IDACORP's other subsidiariesinclude:

•    IDACORP Financial Services, Inc.(IFS), an investor in affordable housing and other real estate investments;

•    Ida-West Energy Company(Ida-West), an operator of smallhydroelectric generation projects that satisfy the requirements of the PublicUtility Regulatory Policies Act of 1978 (PURPA); and

•    IDACORP Energy (IE), a marketer ofenergy commodities, which wound down operations in 2003.

IDACORP is focusing on astrategy that emphasizes IPC as IDACORP's core business.  IPC continues toexperience strong customer growth in its service area, and this corporatestrategy recognizes that IPC must make substantial investments ininfrastructure to ensure adequate electricity supply and reliable service.  IFSand Ida-West remain components of the corporate strategy.

In the second quarter of2006, IDACORP management designated the operations of IDACORP Technologies,Inc. (ITI) and IDACOMM as assets held for sale, as defined by Statement ofFinancial Accounting Standards No. 144, *"Accounting for the Impairment orDisposal of Long-Lived Assets"*.  IDACORP's consolidated financialstatements reflect the reclassification of the results of these businesses asdiscontinued operations for all periods presented.  Discontinued operations arediscussed in more detail in Note 17 to IDACORP's and IPC's ConsolidatedFinancial Statements.

On July 20, 2006, IDACORPcompleted the sale of all of the outstanding common stock of ITI to IdaTech UKLimited, a wholly-owned subsidiary of Investec Group Investments (UK) Limited.

On February 23, 2007, IDACORPcompleted the sale of all of the outstanding common stock of IDACOMM toAmerican Fiber Systems, Inc.  

At December 31, 2006, IDACORPhad 1,976 full-time employees, 1,927 of which were employed by IPC.

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IDACORP's reportable businesssegments are IPC and IFS, which contributed $94 million and $10 million,respectively, to income from continuing operations in 2006.  Financialinformation relating to IDACORP's reportable segments is presented in Note 11to IDACORP's and IPC's Consolidated Financial Statements and below in "UtilityOperations," and "IFS."IDACORP and IPC make available free of charge their Annual Report on Form 10-K,Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and all amendmentsto these reports filed or furnished pursuant to Section 13(a) or 15(d) of theSecurities Exchange Act of 1934 as soon as reasonably practicable after thereports are electronically filed with or furnished to the Securities andExchange Commission, through IDACORP's website at www.idacorpinc.com andthrough a link to the IDACORP website from the IPC website at www.idahopower.com.

**UTILITY OPERATIONS:**

IPC was incorporated underthe laws of the state of Idaho in 1989 as successor to a Maine corporationorganized in 1915.  IPC's service territory covers a 24,000 square mile area insouthern Idaho and eastern Oregon, with an estimated population of 943,000. IPC holds franchises in 71 cities in Idaho and nine cities in Oregon and holdscertificates from the respective public utility regulatory authorities to serveall or a portion of 24 counties in Idaho and three counties in Oregon.  As of December 31, 2006, IPC supplied electric energy to approximately 472,000general business customers.

IPC owns and operates 17hydroelectric generation developments, two natural gas-fired plants and onediesel-powered generator and shares ownership in three coal-fired generatingplants.  These generating plants and their capacities are listed in Item 2 - "Properties." IPC's coal-fired plants are in Wyoming, Oregon and Nevada, and use low-sulfurcoal from Wyoming and Utah.

IPC is one of the nation'sfew investor-owned utilities with a predominantly hydroelectric generatingbase.  Because of its reliance on hydroelectric generation, IPC's generationoperations can be significantly affected by weather conditions.  Theavailability of hydroelectric power depends on the amount of snow pack in themountains upstream of IPC's hydroelectric facilities, reservoir storage,springtime snow pack run-off, rainfall and other weather and stream flowmanagement considerations.  During low water years, when stream flows into IPC'shydroelectric projects are reduced, IPC's hydroelectric generation is reduced. This results in less generation from IPC's resource portfolio (hydroelectric,coal-fired and gas-fired) available for off-system sales and, most likely, anincreased use of purchased power to meet load requirements.  Both of thesesituations - a reduction in off-system sales and an increased use of moreexpensive purchased power - result in increased power supply costs.

The primary influences on electricitysales are weather, customer growth and economic conditions.  Extremetemperatures increase sales to customers who use electricity for cooling andheating, and moderate temperatures decrease sales.  Increased precipitationlevels during the agricultural growing season reduce electricity sales tocustomers who use electricity to operate irrigation pumps.

IPC's principal commercialand industrial customers are involved in food processing, electronics andgeneral manufacturing, forest product production, beet sugar refining and theskiing industry.

**Regulation**IPC is under the regulatoryjurisdiction (as to rates, service, accounting and other general matters ofutility operation) of the FERC, the Idaho Public Utilities Commission (IPUC)and the Oregon Public Utility Commission (OPUC).  IPC is also under theregulatory jurisdiction of the IPUC, the OPUC and the Public Service Commissionof Wyoming as to the issuance of debt and equity securities.  IPC is subject tothe provisions of the Federal Power Act as a "public utility" as thereindefined.  IPC's retail rates are established under the jurisdiction of thestate regulatory commissions and its wholesale and transmission rates areregulated by the FERC (see "Rates" below).  Pursuant to the requirements ofSection 210 of PURPA, the state regulatory commissions have each issued ordersand rules regulating IPC's purchase of power from cogeneration and small powerproduction (CSPP) facilities.

IPC is subject tothe provisions of the Federal Power Act as a "licensee" as therein defined.  Asa licensee under the Federal Power Act, IPC and its licensed hydroelectricprojects are subject to the provisions of Part I of the Federal Power Act.  Alllicenses are subject to conditions set forth in the Federal Power Act andrelated FERC regulations.  These conditions and regulations include provisionsrelating to condemnation of a project upon payment of just compensation,amortization of project investment from excess project earnings, possibletakeover of a project after expiration of its license upon payment of netinvestment, severance damages and other matters.

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The State of Oregon has a Hydroelectric Act providing for licensing of hydroelectric projects in thatstate.  IPC's Brownlee, Oxbow and Hells Canyon facilities are on the SnakeRiver where it forms the boundary between Idaho and Oregon and occupy lands inboth states.  With respect to project property located in Oregon, thesefacilities are subject to the Oregon Hydroelectric Act.  IPC has obtained Oregon licenses for these facilities and these licenses are not in conflict with theFederal Power Act or IPC's FERC licenses (see Part II, Item 7 - "MD&A -REGULATORY MATTERS - Relicensing of Hydroelectric Projects").

**Rates**The rates IPC charges to its generalbusiness customers are determined by the IPUC and the OPUC.  Approximately 95percent of IPC's general business revenue comes from customers in Idaho.  IPC has a Power Cost Adjustment (PCA) mechanism that provides for annualadjustments to the rates charged to its Idaho retail customers.  Theseadjustments are based on forecasts of net power supply costs, which are fueland purchased power less off-system sales, and the true-up of the prior year'sforecast.  During the year, 90 percent of the difference between the actual andforecasted costs is deferred with interest.  The ending balance of thisdeferral, called the true-up for the current year's portion and the true-up ofthe true-up for the prior years' unrecovered or over-recovered portion, is thenincluded in the calculation of the next year's PCA.  For further discussion ofsignificant rate cases and proceedings see Part II, Item 7 - "MD&A -REGULATORY MATTERS."

**Energy Efficiency**In 2006, IPC spent approximately $10million to promote energy efficiency and summer peak reduction through itsDemand Side Management (DSM) programs.  Major funding for program development,implementation and administration comes from the Idaho and Oregon tariff ridersfor DSM and from the Conservation & Renewables Discount Program of theBonneville Power Administration.

Approximately nine percent ofthe total DSM spending related to research and development, technologyevaluation and market transformation, through promotion and collaboration withmanufacturers of electricity consuming products, including air conditioningequipment, appliances, building components and control equipment.  A portion ofthis activity was accomplished in conjunction with the Northwest EnergyEfficiency Alliance.

Energy efficiency programstarget savings across the entire year for a wide range of customer segmentswith an emphasis on reducing energy during the summer peak:

•    Approximately 22 percent of the2006 expenses were devoted to achieving summer peak reduction through focusingon irrigation pumping and residential air conditioning equipment controlmeasures. 

•    The residential energy efficiencyprograms targeted new and existing homes, focusing on customer education andthe application of energy efficiency remediation, including energy efficientbuilding techniques, insulation augmentation, air duct sealing, and the use ofefficient lighting.  The segment's 2006 spending represented about 23 percentof the total. 

•    Energy Efficiency programs forexisting industrial and new commercial facilities focus on application ofenergy efficient techniques and technologies as well as operational andmanagement processes to reduce energy consumption.  These programs representedapproximately 18 percent of total expenses.

•    Approximately 24 percent of the2006 expenses were devoted to irrigation efficiency programs.  Irrigationcustomers can receive financial incentives for either improving the energyefficiency of an irrigation system or installing a new energy efficiencysystem.

**Power Supply**IPC meets its system loadrequirements using a combination of its own generation, mandated purchases fromprivate developers (see "CSPP Purchases" below) and purchases from otherutilities and power wholesalers.  IPC's generating plants and capacities arelisted in Item 2 - "Properties."

IPC's system is dual peaking,with the larger peak demand occurring in the summer.  The all-time system peakdemand is 3,084 megawatts (MW), set on July 24, 2006.  The peak winter demandfor the year was 2,318 MW on December 18.  IPC expects total system averageload to grow 2.1 percent annually over the next three years.

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The following table presentsIPC's system generation for the last three years:

|               | **MWh**                 | ** ** | **Percent of total generation** |
|---------------|-------------------------|------------|---------------------------------|
|               | **2006**                | ** ** | **2005**                        | ** ** | **2004** | ** ** | **2006** | ** ** | **2005** | ** ** | **2004** |
|               | **(thousands of MWhs)** | ** ** | ** **                      | ** ** | ** ** | ** ** | ** ** |
| Hydroelectric | 9,207                   |            | 6,199                           |  | 6,041 |  | 57% |  | 46% |  | 45% |
| Thermal       | 7,021                   |            | 7,315                           |  | 7,303 |  | 43% |  | 54% |  | 55% |
|               | Total system generation | 16,228     |                                 | 13,514 |  | 13,344 |  | 100% |  | 100% |  | 100% |
|               |                         |            |                                 |  |  |  |  |  |  |  |  |  |

The amount of electricity IPCis able to generate from its hydroelectric plants depends on a number offactors, primarily snow pack in the mountains upstream of its hydroelectricfacilities, reservoir storage and stream flow conditions.  When these factorsare favorable, IPC can generate more electricity using its hydroelectricplants.

Under normal stream flowconditions, IPC's system generation mix is approximately 55 percenthydroelectric and 45 percent thermal.

Stream flow conditions in2006 were much improved over 2005.  The observed stream flow data released bythe National Weather Service's Northwest River Forecast Center indicated thatBrownlee reservoir inflow for April through July 2006 was 8.95 millionacre-feet (maf), or 142 percent of average.  Brownlee reservoir inflow for 2006totaled 16.98 maf, or 123 percent of average.  Storage in selected federalreservoirs upstream of Brownlee as of February 11, 2007 was 122 percent ofaverage.  The stream flow forecast released on February 15, 2007 by theNational Weather Service's Northwest River Forecast Center predicts thatBrownlee reservoir inflow for April through July 2007 will be 3.80 maf; or 60percent of average.

IPC's generating facilitiesare interconnected through its integrated transmission system and are operatedon a coordinated basis to achieve maximum load-carrying capability andreliability.  IPC's transmission system is directly interconnected with thetransmission systems of the Bonneville Power Administration, AvistaCorporation, PacifiCorp, NorthWestern Energy and Sierra Pacific Power Company. Such interconnections, coupled with transmission line capacity made availableunder agreements with some of the above entities, permit the interchange,purchase and sale of power among all major electric systems in the west.  IPCis a member of the Western Electricity Coordinating Council, the WesternSystems Power Pool, the Northwest Power Pool and the North American EnergyStandards Board.  These groups have been formed to more efficiently coordinatetransmission reliability and planning throughout the western grid.  See "Competition- Wholesale" below.

**Integrated Resource Plan:**  IPC's IRP is prepared and filed every two years withthe IPUC and the OPUC.  Prior to filing, the IRP requires extensive involvementby IPC, the IPUC Staff, the OPUC Staff, and customer and environmentalrepresentatives, as well as input on the cost of various generationtechnologies.  The IRP is the starting point for demonstrating prudence in IPC'sresource decisions.  The 2006 IRP identified IPC's forecast load and resourcesituation for the next twenty years, analyzed potential supply-side anddemand-side options and identified near-term and long-term actions.  The twoprimary goals of the 2006 IRP were to (1) identify sufficient resources toreliably serve the growing demand for electric service within IPC's servicearea throughout the 20-year planning period and (2) ensure that the portfolioof resources selected balances cost, risk and environmental concerns.  Inaddition, there were four secondary goals: (1) to give equal and balancedtreatment to both supply-side resources and demand-side measures, (2) toinvolve the public in the planning process in a meaningful way, (3) to exploretransmission alternatives, and (4) to investigate and evaluate advanced coaltechnologies.  The 2006 IRP was submitted to the IPUC in September 2006 and theOPUC in October 2006.  See further discussion in Part II - Item 7 - "MD&A -REGULATORY MATTERS - Integrated Resource Plan."

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**CSPP Purchases**:  As mandated by the enactment of PURPA and theadoption of avoided cost rates by the IPUC and the OPUC, IPC has entered intocontracts for the purchase of energy from a number of private developers. Under these contracts, IPC is required to purchase all of the output from thefacilities located inside the IPC service territory.  For projects locatedoutside the IPC service territory, IPC is required to purchase the output thatIPC has the ability to receive at the facility's requested point of delivery onthe IPC system.  The IPUC jurisdictional portion of the costs associated withCSPP contracts are fully recovered through the PCA.  For IPUC jurisdictionalcontracts, projects that generate up to ten average MW of energy monthly areeligible for IPUC Published Avoided Costs for up to a 20-year contract term.  ThePublished Avoided Cost is a price established by the IPUC and OPUC to estimateIPC's cost of developing additional generation resources.  On August 4, 2005,the IPUC granted a temporary reduction in the eligible project size to 100 kWfor intermittent generation resources only and ordered IPC to study the impactsof integrating this type of resource.  IPC completed and filed with the IPUC awind generation integration study report on February 6, 2007.  The IPUC willevaluate the proposal, possibly including public workshops, and issue aruling.  For OPUC jurisdictional contracts, projects with a nameplate rating ofup to ten MW of capacity are eligible for OPUC Published Avoided Costs for upto a 20-year contract term.  The OPUC jurisdictional portion of the costsassociated with CSPP contracts is recovered through general rate case filings. The Oregon provisions are currently being reviewed in an OPUC proceeding, asdiscussed in Part II, Item 7 - "MD&A - REGULATORY MATTERS - Public UtilityRegulatory Policies Act of 1978."  If a PURPA project does not qualify forPublished Avoided Costs, then IPC is required to negotiate the terms, pricesand conditions with the developer of that project.  These negotiations reflectthe characteristics of the individual projects (i.e., operational flexibility,location and size) and the benefits to the IPC system and must be consistentwith other similar energy alternatives.

As of December 31, 2006, IPChad signed agreements to purchase energy from 92 CSPP facilities with contractsranging from one to 30 years.  Of these facilities, 74 were on-line at the endof 2006; the other 18 facilities under contract are due to come on-line in 2007and 2008.  During 2006, IPC purchased 911,132 megawatt hours (MWh) from theseprojects at a cost of $54 million, resulting in a blended price of 5.9 centsper kilowatt hour.

**Wholesale Energy MarketActivities:**  Guided by a riskmanagement policy and frequently updated operating plans, IPC participates inthe wholesale energy market by buying power to help meet load demands andselling power that is in excess of load demands.  IPC's market activities areinfluenced by its customer loads, market prices, and cost and availability ofgenerating resources.  Some of IPC's hydroelectric generation facilities areoperated to optimize the water that is available by choosing when to rungeneration units and when to store water in reservoirs.  These decisions affectthe timing and volumes of market purchases and market sales.  Even in belownormal water years, there are opportunities to vary water usage to maximizegeneration unit efficiency, capture marketplace economic benefits and meet loaddemand.  Compliance factors, such as allowable river stage elevation changesand flood control requirements, and wholesale energy market prices influencethese dispatch decisions.****

IPC has one firm wholesalepower sales contract and one wholesale contract for load following services. The sales contract is with the Raft River Electric Cooperative for up to 15 MW. This contract expires in September 2007; however, Raft River ElectricCooperative has provided notice that it intends to renew the contract, asallowed in the original agreement, through September 2010.  The load followingcontract, with NorthWestern Energy, requires IPC to increase or decrease itsgeneration by up to 30 MW to react to NorthWestern's system load changes.  Thiscontract automatically renews annually unless either party chooses toterminate.  Due to the uncertainty regarding the regulation requirements ofanticipated wind generation, IPC expects to terminate this contract effectiveDecember 2007.

IPC has one firm wholesalepurchased power contract.  This contract is with PPL Montana, LLC for 83 MW perhour to address increased demand during June, July and August.  The term ofthis contract began in June 2004 and runs through August 2009.

**Transmission Services: **IPC has a long history of providing wholesaletransmission service and provides firm and non-firm wheeling services forseveral surrounding utilities.  IPC's system lies between and is interconnectedto the winter-peaking northern and summer-peaking southern regions of thewestern interconnected power system.  This geographic position allows IPC toprovide transmission services and reach a broad power sales market.

IPC holds rights-of-way fromMidpoint substation in south-central Idaho through eastern Nevada to the Dry Lake area northeast of Las Vegas, Nevada, known as the Southwest Intertie Project (SWIP). In 2004, the Bureau of Land Management granted a five-year extension to beginconstruction of a proposed 500-kilovolt transmission line within therights-of-way to December 2009.  IPC obtained the rights-of-way to construct atransmission line along this corridor, but no longer plans to build the line. On March 31, 2005, IPC entered into an agreement with White Pine EnergyAssociates, LLC (White Pine), an affiliate of LS Power Development, LLC, whichprovides White Pine a three-year exclusive option to purchase the SWIPrights-of-way from IPC.  The option may be exercised in part or as a whole and,if fully exercised, will result in a net pre-tax gain to IPC of approximately$6 million.

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In December 1999, the FERCissued Order No. 2000 encouraging companies with transmission assets to formRegional Transmission Organizations.  See "Competition - Wholesale" below.

**Fuel**IPC, through its subsidiary IdahoEnergy Resources Co., owns a one-third interest in Bridger Coal Company, whichowns the Jim Bridger mine supplying coal to the Jim Bridger generating plant in  Wyoming.  The mine, located near the Jim Bridger plant, operates under along-term sales agreement that provides for delivery of coal over a 51-yearperiod ending in 2024.  The Jim Bridger mine has sufficient reserves to providecoal deliveries for the term of the sales agreement.  IPC also has a coalsupply contract providing for annual deliveries of coal through 2009 from theBlack Butte Coal Company's Black Butte and Leucite Hills mines located near theJim Bridger plant.  This contract supplements the Bridger Coal Companydeliveries and provides another coal supply to operate the Jim Bridger plant. The Jim Bridger plant's rail load-in facility and unit coal train allow theplant to take advantage of potentially lower-cost coal from other mines fortonnage requirements above established contract minimums.

In an effort to lower costsand access better quality coal, the Jim Bridger mine is converting from asurface operation to a primarily underground operation.  Underground mine developmentand limited coal production began in 2004, and start-up operations are expectedto begin in March 2007.  A number of factors were considered in this decisionincluding the increasing cost of the surface mine operation as well as theadditional capital required to develop the underground mine.  This conversionis expected to result in a reduction of the cost of mining coal over the lifeof the Jim Bridger Mine.

Sierra Pacific Power Company,as operator of the North Valmy Generating Plant (Valmy), has an agreement withArch Coal Sales Company, Inc. to supply coal to the plant through 2009.  IPC isobligated to purchase one-half of the coal, ranging from 515,000 tons to762,500 tons annually.  Sierra Pacific Power Company also has a coal supply contractwith Black Butte Coal Company's Black Butte Mine for deliveries through 2009. IPC is obligated to purchase one-half of the coal purchased under thisagreement, ranging from 450,000 to 600,000 tons annually.

The Boardman generating plantreceives coal from the Powder River Basin through annual contracts.  PortlandGeneral Electric, as operator of the Boardman plant, has an agreement withBuckskin Mining Company to supply all of Boardman's coal requirements through2008.  IPC is obligated to purchase 10 percent of the coal purchased under thisagreement, ranging from 230,000 to 270,000 tons annually.

IPC owns and operates theDanskin and Bennett Mountain combustion turbines, which receive gas through theWilliams Northwest Pipeline.  All gas is purchased as needs are identified forsummer peaks or to meet system requirements.  The gas is transported under along-term capacity contract with the Williams Northwest Pipeline and anarrangement with IGI Resources, Inc.  The Williams Northwest Pipeline contract,which extends through February 28, 2007, with annual extensions at IPC's solediscretion, is for 24,523 million British thermal units (MMBtu) per day fromthe Sumas, Washington metering point to the Elmore, Idaho metering point.  Inaddition to a long-term capacity contract, IPC has entered into a long-termcontract with Williams Northwest Pipeline for storage capacity at the JacksonPrairie Storage Project located in Lewis County, Washington.  As the project isdeveloped, storage capacity will be phased into service and allocated to IPCmonthly, until reaching 11,267 MMBtu per day of firm deliverability.  Storagecapacity is expected to commence in March 2007, reaching maximum deliverabilityby November 1, 2008.  The firm storage contract extends through November 1,2043, with bi-lateral termination rights at the end of the contract.  Storagegas will be purchased and stored with the intent of supplying needs asidentified for summer peaks or to meet system requirements.  See furtherdiscussion in Part II, Item 7 - "MD&A - RESULTS OF OPERATIONS - UtilityOperations - Fuel Expense." 

**Water Rights**Except as discussed below, IPC hasacquired water rights under applicable state law for all waters used in itshydroelectric generating facilities.  In addition, IPC holds water rights fordomestic, irrigation, commercial and other necessary purposes related to otherland and facility holdings within the state.  The exercise and use of all ofthese water rights are subject to prior rights, and with respect to certainhydroelectric generating facilities, IPC's water rights for power generationare subordinated to certain future upstream diversions of water for irrigationand other recognized consumptive uses.

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Over time, increasedirrigation development and other consumptive diversions have resulted in areduction in the stream flows available to fulfill IPC's water rights atcertain hydroelectric generating facilities.  In reaction to these reductions,IPC initiated and continues to pursue a course of action to determine andprotect its water rights.  As part of this process, IPC and the State of Idaho signed the Swan Falls agreement on October 25, 1984, which provided a level ofprotection for IPC's hydropower water rights at specified plants by settingminimum stream flows and establishing an administrative process governing thefuture development of water rights that may affect IPC's hydroelectricgeneration.  In 1987, Congress passed, and the President signed into law, HouseBill 519.  This legislation permitted implementation of the Swan Fallsagreement and further provided that during the remaining term of certain of IPC'sproject licenses the relationship established by the agreement would not beconsidered by the FERC as being inconsistent with the terms of IPC's projectlicenses or imprudent for the purposes of determining rates under Section 205of the Federal Power Act.  The FERC entered an order implementing thelegislation on March 25, 1988.

In addition to providing forthe protection of IPC's hydroelectric water rights, the Swan Falls agreement contemplated the initiation of a general adjudication of all water uses withinthe Snake River basin.  In 1987, the director of the Idaho Department of WaterResources filed a petition in state district court asking that the courtadjudicate all claims to water rights, whether based on state or federal law,within the Snake River basin.  The court signed a commencement order initiatingthe Snake River Basin Adjudication on November 19, 1987.  This legal proceedingwas authorized by state statute based upon a determination by the IdahoLegislature that the effective management of the waters of the Snake River basin required a comprehensive determination of the nature, extent and priorityof all water uses within the basin.  The adjudication is proceeding and isexpected to continue for at least the next several years.  IPC has filed claimsto its water rights within the basin and is actively participating in theadjudication in an effort to ensure that its water rights and the operation ofits hydroelectric facilities are not adversely impacted.

Please see Part II, Item 7 - "MD&A- LEGAL AND ENVIRONMENTAL ISSUES - Environmental Issues - Idaho WaterManagement Issues" and "MD&A - REGULATORY MATTERS - Relicensing of HydroelectricProjects."

**Environmental Regulation**IPC's activities are subject to abroad range of federal, state, regional and local laws and regulations designedto protect, restore and enhance the quality of the environment.  Environmentalregulation continues to impact IPC's operations due to the cost of installationand operation of equipment and facilities required for compliance with suchregulations, and the modification of system operations to accommodate suchregulations.  IPC's compliance costs will continue to be significant for theforeseeable future.

Based upon presentenvironmental laws and regulations, IPC estimates its 2007 capital expendituresfor environmental matters, excluding Allowance for Funds Used DuringConstruction (AFDC), will total $30 million.  Studies and measures related toenvironmental concerns at IPC's hydroelectric facilities account for $19million, and investments in environmental equipment and facilities at thethermal plants account for $11 million.  For 2008 and 2009, environmental-relatedcapital expenditures, excluding AFDC, are estimated to be $44 million. Anticipated expenses related to IPC's hydroelectric facilities account for $31million, and thermal plant expenses are expected to total $13 million.

IPC anticipates $19 millionin annual operating costs for environmental facilities during 2007. Hydroelectric facility expenses account for $12 million of this total, and $7million is related to thermal plant operating expenses.  For 2008 and 2009,total environmental related operating costs are estimated to be $50 million. Expenses related to the hydroelectric facilities are expected to be $35million, and thermal plant expenses are expected to be $15 million during thisperiod.

**Air Quality Issues**IPC owns two natural gas combustionturbine power plants and co-owns three coal-fired power plants that are subjectto air quality regulation.  The natural gas-fired plants, Danskin and Bennett Mountain, are located in Idaho.  The coal-fired plants are:  Jim Bridger (33 percentinterest) located in Wyoming; Boardman (ten percent interest) located in Oregon; and North Valmy (50 percent interest) located in Nevada.  Please see Part II, Item7 - "MD&A - LEGAL AND ENVIRONMENTAL ISSUES - Environmental Issues - AirQuality Issues" for a discussion of these matters.

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**Water:**  As required under the Federal Water PollutionControl Act Amendments of 1972, IPC has received necessary environmentalpermits and authorizations and has prepared necessary plans relating tooperations and water quality, such as effluent discharge, spill prevention andcountermeasures, and storm water pollution prevention.

In March 1976, IPC agreed tooperate its American Falls hydroelectric generating plant to meet certaindissolved oxygen standards in the Snake River downstream from the plant duringthe period from May 15 to October 15 of each year and to provide water qualitymonitoring facilities.  In order to meet the dissolved oxygen standards, IPCinstalled and operates aeration equipment at the American Falls plant. 

IPC has also installed aeration equipment, water quality monitors and dataprocessing equipment as part of its Cascade hydroelectric project to provideaccurate water quality data and increase dissolved oxygen levels as necessaryto maintain water quality standards on the Payette River.  IPC has alsoinstalled and operates water quality monitors at its Milner, Shoshone Falls, Twin Falls, Upper Salmon, Lower Salmon, Bliss and CJ Strike hydroelectric projects inorder to meet compliance standards for water quality on the Snake River.

**Endangered Species:**  In December 1992, the U.S. Fish and Wildlife Servicelisted several species of fish and five species of snails living within IPC'soperating area as threatened or endangered species under the Endangered SpeciesAct.  IPC continues to review and analyze the effect such designation has onits operations and is cooperating with governmental agencies to resolve issuesrelated to these species.

On December 21, 2006, IPC andIdaho Governor James Risch submitted a petition to the U.S. Fish and WildlifeService to de-list the threatened Bliss Rapids snail.  The petition wassupported with data collected by IPC over the past 14 years.  The snail, whichlives throughout the middle Snake River, springs, and tributaries betweenNiagara Springs and King Hill, was listed as threatened under the EndangeredSpecies Act in 1992.  The Fish and Wildlife Service has one year to decide ifde-listing is warranted.  With this filing, three of the five snail species thatare found in the middle Snake River and were originally listed as threatened orendangered species in 1992 are now being considered for removal from the list.

Pursuant to FERC License1971, IPC owns and finances the operation of anadromous fish hatcheries andrelated facilities to mitigate the effects of its hydroelectric dams on fishpopulations.  In connection with its fish facilities, IPC sponsors ongoingprograms for the control of fish disease, improvement of fish production, andevaluation of hatchery performance.  IPC's anadromous fish facilities at HellsCanyon, Oxbow, Rapid River, Pahsimeroi and Niagara Springs continue to beoperated by the Idaho Department of Fish and Game.  At December 31, 2006, theinvestment in these facilities was $15 million and the annual cost of operationwas $3 million.

**Hazardous/Toxic Wastes andSubstances:**  Under the ToxicSubstances Control Act, the EPA has adopted regulations governing the use,storage, inspection and disposal of electrical equipment that contains polychlorinatedbiphenyls (PCBs).  The regulations permit the continued use and servicing ofcertain equipment (including transformers and capacitors) that contain PCBs. IPC continues to meet all federal requirements of the Toxic Substances ControlAct for the continued use of equipment containing PCBs.  IPC continues toeliminate PCBs as part of its long-term strategy.  This program will reducecosts associated with the long-term monitoring of PCB-containing equipment,responding to spills and reporting to the EPA.  In 2006, IPC spentapproximately $0.9 million identifying and eliminating PCBs.

**Competition****Retail:**  Electric utilities have historically been recognized as naturalmonopolies and have operated in a highly regulated environment in which they havean obligation to provide electric service to their customers in return for anexclusive franchise within their service territory with an opportunity to earna regulated rate of return.

Some state regulatoryauthorities are in the process of changing utility regulations in response tofederal and state statutory changes and evolving competitive markets.  Thesestatutory changes and conforming regulations may result in increased retailcompetition.  In 1997, the Idaho Legislature appointed a committee to studyrestructuring of the electric utility industry.  The committee has notrecommended any restructuring legislation and is not expected to in theforeseeable future.  The committee's focus has since shifted from restructuringto general energy issues.  In 1999, the Oregon Legislature passed legislationrestructuring the electric utility industry, but exempted IPC's serviceterritory.

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**Wholesale: **The 1992 National Energy Policy Act and the FERC'srulemaking activities have established the regulatory framework to open thewholesale energy market to competition.  This act permits utilities to developindependent electric generating plants for sales to wholesale customers, andauthorizes the FERC to order transmission access for third parties totransmission facilities owned by another entity.  This act does not, however,permit the FERC to require transmission access to retail customers. Open-access transmission for wholesale customers provides energy suppliers withopportunities to sell and deliver electricity at market-based prices.

For more information, seePart II, Item 7 - "MD&A - REGULATORY MATTERS - Regional TransmissionOrganizations."

**Utility OperatingStatistics**The following table presents IPC'srevenues and energy use by customer type for the last three years, which isfurther discussed in Part II, Item 7 - "MD&A - RESULTS OF OPERATIONS -Utility Operations:"

|                                  | **Years Ended December 31,** |
|----------------------------------|------------------------------|
|                                  | **2006**                     | ** ** | **2005** | ** ** | **2004** |
| Revenues (thousands of  dollars) |                              |  |  |  |  |  |  |  |
|                                  | Residential                  | $ | 299,594 |  | $ | 299,488 |  | $ | 274,313 |
|                                  | Commercial                   |  | 162,391 |  |  | 173,268 |  |  | 164,053 |
|                                  | Industrial                   |  | 102,958 |  |  | 118,259 |  |  | 111,797 |
|                                  | Irrigation                   |  | 71,432 |  |  | 76,255 |  |  | 85,672 |
|                                  |                              | Total general business |  | 636,375 |  |  | 667,270 |  |  | 635,835 |
|                                  | Off-system sales             |  | 260,717 |  |  | 142,794 |  |  | 121,148 |
|                                  | Other                        |  | 23,381 |  |  | 27,619 |  |  | 62,526 |
|                                  |                              | Total | $ | 920,473 | $ |  | 837,683 |  | $ | 819,509 |
|                                  |                              |  |  |  |  |  |  |  |  |
| Energy use (thousands of  MWh)   |                              |  |  |  |  |  |  |  |
|                                  | Residential                  |  | 5,068 |  |  | 4,760 |  |  | 4,580 |
|                                  | Commercial                   |  | 3,761 |  |  | 3,639 |  |  | 3,561 |
|                                  | Industrial                   |  | 3,475 |  |  | 3,423 |  |  | 3,335 |
|                                  | Irrigation                   |  | 1,635 |  |  | 1,467 |  |  | 1,763 |
|                                  |                              | Total general business |  | 13,939 |  |  | 13,289 |  |  | 13,239 |
|                                  | Off-system sales             |  | 5,821 |  |  | 2,774 |  |  | 2,885 |
|                                  |                              | Total |  | 19,760 |  |  | 16,063 |  |  | 16,124 |
|                                  |                              |  |  |  |  |  |  |  |  |

See Note 11 to IDACORP's andIPC's Consolidated Financial Statements for more information.

**IFS:**

IFS invests primarily inaffordable housing developments, which provide a return principally by reducingfederal and state income taxes through tax credits and accelerated taxdepreciation benefits.  IFS generated tax credits of $19 million, $20 millionand $22 million in 2006, 2005 and 2004, respectively.  IFS's portfolio alsoincludes historic rehabilitation projects such as the Empire Building in Boise, Idaho.  IFS made $5 million in new investments during 2006.

IFS has focused on adiversified approach to its investment strategy in order to limit bothgeographic and operational risk.  Over 90 percent of IFS's investments havebeen made through syndicated funds.  At December 31, 2006, the gross amount ofIFS's portfolio equaled $175 million in tax credit investments.  Theseinvestments cover 49 states, Puerto Rico and the U.S. Virgin Islands.  Theunderlying investments include over 700 individual properties, of which all butthree are administered through syndicated funds.

See Note 11 to IDACORP's andIPC's Consolidated Financial Statements for more information.

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**IDA-WEST:**

Ida-West operates and has a50 percent interest in nine hydroelectric plants with a total generatingcapacity of 45 MW.  Four of the projects are located in Idaho and five are innorthern California.  All nine projects are "qualifying facilities" underPURPA.  IPC purchased all of the power generated by Ida-West's four Idaho hydroelectric projects at a cost of $8 million in 2006, and $7 million per year in2005 and 2004.

**ITEM1A.  RISK FACTORS**

Thefollowing are factors that could have a significant impact on the operationsand financial results of IDACORP, Inc. and Idaho Power Company and could causeactual results or outcomes to differ materially from those discussed in anyforward-looking statements:

- Reduced hydroelectric generation can reduce revenues and increase     costs.   Idaho Power Company has     a predominately hydroelectric generating base.  Because of Idaho Power     Company's heavy reliance on hydroelectric generation, the weather can     significantly affect its operations.  When hydroelectric generation is     reduced, Idaho Power Company must increase its use of generally more     expensive thermal generating resources and purchased power.  Through its     power cost adjustment in Idaho, Idaho Power Company can expect to recover approximately     90 percent of the increase in its Idaho jurisdictional net power supply     costs, which are fuel and purchased power less off-system sales, above the     level included in its base rates.  The power cost adjustment recovery     includes both a forecast and deferrals that are subject to the regulatory     process.  However, recovery of amounts above forecast in one power cost     adjustment year does not occur until the subsequent power cost adjustment     year.  The non-Idaho net power supply costs are subject to periodic     recovery from the Oregon and Federal Energy Regulatory Commission     jurisdictional customers.
- Continuing declines in stream flows and over-appropriation of     water in Idaho may reduce hydroelectric generation and revenues and     increase costs.   The combination     of declining Snake River base flows, over-appropriation of water and     drought conditions have led to disputes among surface water and ground     water irrigators, and the State of Idaho.  Recharging the Eastern Snake     Plain Aquifer, which contributes to Snake River flows, by diverting     surface water to porous locations and permitting it to sink into the     aquifer is one proposed solution to the dispute.  Diversions from the     Snake River for aquifer recharge may further reduce Snake River flows     available for hydroelectric generation and reduce Idaho Power Company     revenues and increase costs.
- Changes in temperature and precipitation can reduce power sales     and revenues.   Warmer than     normal winters, cooler than normal summers and increased rainfall during     the irrigation seasons will reduce retail revenues from power sales.
- If the Idaho Public Utilities Commission, the Oregon Public     Utility Commission or the Federal Energy Regulatory Commission grant less     rate relief than requested in rate case filings, Idaho Power Company's     earnings and cash flows will be reduced.   If the Idaho Public Utilities Commission, the Oregon Public     Utility Commission or the Federal Energy Regulatory Commission were to     grant less rate relief than Idaho Power Company requests in its rate case     filings, it would have a negative effect on earnings and cash flow and     could result in downgrades of IDACORP, Inc.'s and Idaho Power Company's     credit ratings.
- Conditions that may be imposed in connection with hydroelectric     license renewals may require large capital expenditures and reduce     earnings and cash flows.   Idaho     Power Company is currently involved in renewing federal licenses for     several of its hydroelectric projects.  The Federal Energy Regulatory     Commission may impose conditions with respect to environmental, operating     and other matters in connection with the renewal of Idaho Power Company's     licenses.  These conditions could have a negative effect on Idaho Power     Company's operations, require large capital expenditures and reduce     earnings and cash flows.

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- The cost of complying with environmental regulations can reduce     earnings and cash flows.       IDACORP, Inc. and Idaho Power Company are subject to extensive federal,     state and local environmental statutes, rules and regulations relating to     air quality, water quality, natural resources and health and safety.      Compliance with these environmental statutes, rules and regulations     involves significant capital and operating expenditures.  These     expenditures could become even more significant in the future if legislation     and enforcement policies change.  For instance, considerable attention has     been focused on carbon dioxide emissions from coal-fired generating plants     and their potential role in contributing to global warming.  The effects     of mercury emissions from coal-fired plants are also being discussed.  The     adoption of new laws and regulations to implement carbon dioxide, mercury     or other emission controls could increase the cost of operating coal-fired     generating plants and reduce earnings and cash flows.
- IDACORP, Inc., IDACORP Energy and Idaho Power Company are subject     to costs and other effects of legal and regulatory proceedings,     settlements, investigations and claims, including those that have arisen     out of the western energy situation.   IDACORP, Inc., IDACORP Energy and Idaho Power Company are involved     in a number of proceedings including the California refund proceeding at     the Federal Energy Regulatory Commission, which has been settled but which     has an appeal pending at the U.S. Court of Appeals for the Ninth Circuit;     a refund proceeding affecting sellers of wholesale power in the spot     market in the Pacific Northwest, in which the Federal Energy Regulatory     Commission directed that no refunds be paid, but which has an appeal pending     before the United States Court of Appeals for the Ninth Circuit; efforts     by two remaining parties (the City of Tacoma and Wah Chang) to reform or     terminate contracts for the purchase of power from IDACORP Energy or other     parties  claiming violations of state and federal antitrust acts and     dysfunctional energy markets as the result of market manipulation; show     cause proceedings at the Federal Energy Regulatory Commission, which have     been settled but are the subject of motions for rehearing or have been     appealed; claims pending before the United States Court of Appeals for the     Ninth Circuit that the Federal Energy Regulatory Commission-ordered refund     period should have been expanded to include a longer time period, and the     reversal by the United States Court of Appeals for the Ninth Circuit of     Federal Energy Regulatory Commission rulings that market-based sellers'     transactional reports satisfy the Federal Energy Regulatory Commission's     filed-rate doctrine requirements as a means of expanding refunds from all     sellers of wholesale power, which rulings remain pending before the United     States Court of Appeals for the Ninth Circuit on rehearing.  To the extent     the companies are required to make payments, earnings and cash flows will     be negatively affected.  It is possible that additional proceedings     related to the western energy situation may be filed in the future against     IDACORP, Inc., IDACORP Energy or Idaho Power Company.
- Idaho Power Company's business is subject to substantial     governmental regulation and may be adversely affected by increased costs     resulting from, or liability under, existing or future regulations or     requirements.   Idaho Power     Company is subject to extensive federal and state laws, policies, and     regulations, as well as regulatory actions and regulatory audits,     including those of the Federal Energy Regulatory Commission, the     Environmental Protection Agency, and the public utility commissions in Idaho, Oregon and Wyoming.  Some of these regulations are changing or subject to     interpretation, and failure to comply may result in penalties or other     adverse consequences.  Compliance with these requirements directly     influences Idaho Power Company's operating environment and may     significantly increase Idaho Power Company's operational costs.
- Pending shareholder litigation could be costly, time consuming     and, if adversely decided, result in substantial liabilities.   Two securities shareholder lawsuits     consolidated by order dated August 31, 2004 have been filed against     IDACORP, Inc. and four of its officers and directors.  Securities     litigation can be costly, time-consuming and disruptive to normal business     operations.  Costs below a self-insured retention are not covered by     insurance policies.  If these lawsuits are resolved against IDACORP, Inc.     or settled out of court, the damages or settlement amounts in excess of     insurance coverage could have a material adverse effect on the financial     position, results of operations or cash flows of IDACORP, Inc.
- Increased capital expenditures can significantly affect liquidity.   Increases in both the number of customers and     the demand for energy require expansion and reinforcement of transmission,     distribution and generating systems.  If Idaho Power Company does not     receive timely regulatory relief, Idaho Power Company will have to rely     more on external financing for its future utility construction     expenditures.  These large planned expenditures may weaken the     consolidated financial profile of IDACORP, Inc. and Idaho Power Company.      Additionally, a significant portion of Idaho Power Company's facilities     were constructed many years ago.  Aging equipment, even if maintained in     accordance with good engineering practices, may require significant     capital expenditures.  Failure of equipment or facilities used in Idaho     Power Company's systems could potentially increase repair and maintenance     expenses, purchased power expenses and capital expenditures.

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- As a holding company, IDACORP, Inc.  does not have its own operating income and must     rely on the upstream cash flows from its subsidiaries to pay dividends and     make debt payments.   IDACORP,     Inc. is a holding company and thus its primary assets are shares or other     ownership interests of its subsidiaries, primarily Idaho Power Company.      Consequently, IDACORP, Inc.'s ability to pay dividends and its ability to     service its debt is dependent upon dividends and other payments received     from its subsidiaries.  IDACORP, Inc.'s subsidiaries are separate and     distinct legal entities and have no obligation to pay any amounts to     IDACORP, Inc., whether through dividends, loans or other payments.  The     ability of IDACORP, Inc.'s subsidiaries to pay dividends or make     distributions to IDACORP, Inc. depends on several factors, including their     actual and projected earnings and cash flow, capital requirements and     general financial condition, and the prior rights of holders of their     existing and future first mortgage bonds and other debt securities.
- A downgrade in IDACORP, Inc.'s and Idaho Power Company's credit     ratings could negatively affect the companies' ability to access capital.   On November 29, 2004, Standard & Poor's     Ratings Services, on December 3, 2004, Moody's Investors Service, and on     January 24, 2005, Fitch, Inc. each downgraded IDACORP, Inc.'s and Idaho     Power Company's credit ratings.  On March 27, 2006, Standard & Poor's     Ratings Services revised its general corporate credit rating outlooks for     IDACORP, Inc. and Idaho Power Company to negative from stable.  These     downgrades and any future downgrades of IDACORP, Inc.'s or Idaho Power     Company's credit ratings could limit the companies' ability to access the     capital markets, including the commercial paper markets.  In addition,     IDACORP, Inc. and Idaho Power Company would likely be required to pay a     higher interest rate on existing short-term and variable rate debt and in     future financings.
- Terrorist threats and activities could result in reduced revenues     and increased costs.   IDACORP,     Inc. and Idaho Power Company are subject to direct and indirect effects of     terrorist threats and activities.  Potential targets include generation and     transmission facilities.  The effects of terrorist threats and activities     could prevent Idaho Power Company from purchasing, generating or     transmitting power and result in reduced revenues and increased costs.
- Adverse results of income tax audits could reduce earnings and     cash flows.   Outcome of ongoing     and future income tax audits could differ materially from the amounts     currently recorded, and the difference could reduce IDACORP's and Idaho     Power Company's earnings and cash flows.

**ITEM1B.  UNRESOLVED STAFF COMMENTS**

None

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**ITEM 2.  PROPERTIES**

IPC's system is comprised of17 hydroelectric generating plants located in southern Idaho and eastern Oregon, two natural gas-fired plants located in southern Idaho and interests in threecoal-fired steam electric generating plants located in Wyoming, Nevada and Oregon.  The system also includes approximately 4,629 miles of high-voltagetransmission lines, 23 step-up transmission substations located at powerplants, approximately 63,949 miles of distribution lines, 20 transmissionsubstations, eight switching stations and 222 energized distributionsubstations (excluding mobile substations and dispatch centers).

IPC holds FERC licenses forall of its hydroelectric projects that are subject to federal licensing.  Theseprojects and the other generating stations and their capacities are listedbelow:

| ** ** | **Estimated** | ** ** | ** ** |  
** **

**Non-Coincident**

**Nameplate**

** **

 
** **

**Maximum Operating**

**Capacity**

**License**

 
**Project**

**Capacity (kW)**

**(kW)**

**Expiration**

 
**Hydroelectric Developments:**

 
Properties subject to  federal licenses:

 
Lower Salmon

70,000

60,000

2034

 
Bliss

80,000

75,000

2034

 
Upper Salmon

39,000

34,500

2034

 
Shoshone Falls

12,500

12,500

2034

 
CJ Strike

89,000

82,800

2034

 
Upper Malad - Lower Malad

24,000

21,770

2035

 
Brownlee-Oxbow-Hells Canyon

1,398,000

1,166,900

2005

(a)

 
Swan Falls

25,547

25,000

2010

 
American Falls

112,420

92,340

2025

 
Cascade

14,000

12,420

2031

 
Milner

59,448

59,448

2038

 
Twin Falls

54,300

52,737

2040

 
Other Hydroelectric:

 
Clear Lakes -  Thousand Springs

10,400

11,300

 
Total Hydroelectric

1,706,715

 
**Steam and Other  Generating Plants:**

 
Jim Bridger (coal-fired) (b)

706,667

770,501

 
Valmy (coal-fired) (b)

260,650

283,500

 
Boardman (coal-fired) (b)

58,500

56,050

 
Danskin (gas-fired)(c) 

76,000

90,000

 
Salmon (diesel-internal  combustion)

5,500

5,000

 
Bennett Mountain  (gas-fired)(c) 

163,980

172,800

 
Total Steam and Other 

1,377,851

 
Total Generation

3,084,566

 
(a)  Licensed on an annual  basis while application for new multi-year license is pending.

(b) IPC's ownership  interests are 33 percent for Jim Bridger, 50 percent for Valmy and 10 percent  for Boardman.  Amounts shown represent 

IPC's share.

(c) Maximum operating capacity is based on summer  rating at 90 degrees F.

See discussion ofrelicensing in Part II, Item 7 - "MD&A - REGULATORY MATTERS - Relicensingof Hydroelectric Projects."

At December 31, 2006, thecomposite average ages of the principal parts of IPC's system, based on dollarinvestment, were:  production plant, 25 years; transmission system andsubstations, 24 years; and distribution lines and substations, 20 years.  IPCconsiders its properties to be well-maintained and in good operating condition.

IPC owns in fee all of itsprincipal plants and other important units of real property, except forportions of certain projects licensed under the Federal Power Act andreservoirs and other easements.  IPC's property is also subject to the lien ofits Mortgage and Deed of Trust and the provisions of its project licenses.  Inaddition, IPC's property is subject to minor defects common to properties ofsuch size and character that do not materially impair the value to, or the useby, IPC of such properties.

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Idaho Energy Resources Co.owns a one-third interest in the Bridger Coal Company and coal leases near theJim Bridger generating plant in Wyoming from which coal is mined and suppliedto the plant.

Ida-West holds 50 percentinterests in nine operating hydroelectric plants with a total generatingcapacity of 45 MW.  These plants are located in Idaho and California.

See Note 1 to IDACORP's andIPC's Consolidated Financial Statements for a discussion of the property ofIDACORP's consolidated Variable Interest Entities.

**ITEM3.  LEGAL PROCEEDINGS**

See Note 7 to IDACORP's andIPC's Consolidated Financial Statements.

**ITEM4.  SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS**

None

** **

** **

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** **

** **

**EXECUTIVE OFFICERS OF THEREGISTRANTS**

The names, ages and positionsof all of the executive officers of IDACORP, Inc. and Idaho Power Company arelisted below along with their business experience during the past five years. Mr. J. LaMont Keen and Mr. Steven R. Keen are brothers.  There are no otherfamily relationships among these officers, nor is there any arrangement orunderstanding between any officer and any other person pursuant to which theofficer was elected.

J.LAMONT KEEN President and Chief Executive Officer, appointed July 1, 2006.  Mr.Keen also serves as President and Chief Executive Officer of Idaho PowerCompany, appointed November 17, 2005.  Mr. Keen was Executive Vice President ofIDACORP, Inc., from March 1, 2002 to July 1, 2006, and President and ChiefOperating Officer of Idaho Power Company from March 1, 2002 to November 17,2005.  Mr. Keen was Senior Vice President - Administration and Chief FinancialOfficer of IDACORP, Inc. and Idaho Power Company from May 5, 1999 to March 1,2002.  Mr. Keen also serves on the Board of Directors of both IDACORP, Inc. andIdaho Power Company.  Age 54.

DARREL T. ANDERSON SeniorVice President - Administrative Services and Chief Financial Officer ofIDACORP, Inc. and Idaho Power Company, appointed July 1, 2004.  Mr. Andersonwas Vice President, Chief Financial Officer and Treasurer of IDACORP, Inc. andIdaho Power Company from March 1, 2002 to July 1, 2004 and Vice President -Finance and Treasurer of IDACORP, Inc. and Idaho Power Company from May 5, 1999to March 1, 2002.  Age 48.

THOMAS R. SALDIN Senior VicePresident, General Counsel and Secretary of IDACORP, Inc. and Idaho PowerCompany, appointed October 1, 2004.  Mr. Saldin was Executive Vice Presidentand General Counsel of Albertson's Inc., a supermarket chain, from January 29,1999 to his retirement on August 31, 2001.  Age 60.

DENNIS C. GRIBBLE VicePresident and Chief Information Officer of IDACORP, Inc. and Idaho PowerCompany, appointed June 1, 2006.  Mr. Gribble was Vice President and Treasurerof IDACORP, Inc. and Idaho Power Company, from July 15, 2004 to June 1, 2006and Finance Controller of Idaho Power Company from January 1, 1997 to July 15,2004.  Age 54.

LUCI K. MCDONALD VicePresident - Human Resources of IDACORP, Inc. and Idaho Power Company, appointedDecember 6, 2004.  Ms. McDonald was Corporate Staff Director of Human Resourcesof Boise Cascade Corporation, a forest products company, from September 16,1999 to November 19, 2004.  Age 49.

GREGORY W. PANTER VicePresident - Public Affairs of IDACORP, Inc. and Idaho Power Company, appointedApril 1, 2001.  Age 58.

LORI D. SMITH Vice President- Finance and Chief Risk Officer of IDACORP, Inc. and Idaho Power Company,appointed July 15, 2004.  Ms. Smith was Director of Strategic Analysis of IdahoPower Company from January 1, 2000 to July 15, 2004.  Age 46.

STEVEN R. KEEN Vice Presidentand Treasurer of IDACORP, Inc. and Idaho Power Company, appointed June 1,2006.  Mr. Keen is also President of IDACORP Financial Services, appointedSeptember 8, 1998.  Age 46.

NAOMI SHANKEL Vice President,Audit and Compliance of IDACORP, Inc. and Idaho Power Company, appointedSeptember 21, 2006.  Ms. Shankel was Director, Audit Services of IDACORP, Inc.and Idaho Power Company from July 2003 to September 21, 2006.  Ms. Shankel wasa member of the Finance Department of Idaho Power Company from April 4, 2001,to July 2003.  Age 35.

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JAMES C. MILLER Senior VicePresident - Power Supply of Idaho Power Company, appointed July 1, 2004.  Mr.Miller was Senior Vice President - Delivery of Idaho Power Company from October1, 1999 to July 1, 2004.  Age 52

DANIEL B. MINOR Senior VicePresident - Delivery of Idaho Power Company, appointed July 1, 2004.  Mr. Minorwas Vice President - Administrative Services & Human Resources of IDACORP,Inc. and Idaho Power Company from November 20, 2003 to July 1, 2004, VicePresident - Corporate Services of Idaho Power Company from May 15, 2003 toNovember 20, 2003, and Director of Audit Services of Idaho Power Company fromJuly 2001 to May 15, 2003.  Age 49

JOHN R. GALE Vice President -Regulatory Affairs of Idaho Power Company, appointed March 15, 2001.  Age 56

LISA A. GROW Vice President -Delivery Engineering and Operations of Idaho Power Company, appointed July 20,2005.  Ms. Grow was General Manager of Grid Operations and Planning of IdahoPower Company from October 23, 2004 to July 20, 2005, Operations Manager (GridOps) of Idaho Power Company from March 2, 2002 to October 23, 2004, and ControlArea Operations Leader from October 13, 2001 to March 2, 2002.  Age 41

WARREN KLINE Vice President - Customer Service and RegionalOperations of Idaho Power Company, appointed July 20, 2005.  Mr. Kline wasGeneral Manager of Regional Operations of Idaho Power Company from March 2,2002 to July 20, 2005 and General Manger of Customer Service and Metering fromJanuary 9, 1999 to March 2, 2002.  Age 51

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**PART II******

**ITEM 5.  MARKET FOR REGISTRANT'S COMMON EQUITY,RELATED STOCKHOLDER MATTERS****ANDISSUER PURCHASES OF EQUITY SECURITIES**

IDACORP's common stock,without par value, is traded on the New York Stock Exchange.  On December 31,2006, there were 15,868 holders of record and the stock price was $38.65 pershare.

The outstanding shares of IPC'scommon stock, $2.50 par value, are held by IDACORP and are not traded.  IDACORPbecame the holding company of IPC on October 1, 1998.

The amount and timing ofdividends payable on IDACORP's common stock are within the sole discretion ofIDACORP's Board of Directors.  The Board of Directors reviews the dividend ratequarterly to determine its appropriateness in light of IDACORP's current andlong-term financial position and results of operations, capital requirements,rating agency requirements, legislative and regulatory developments affectingthe electric utility industry in general and IPC in particular, competitiveconditions and any other factors the Board of Directors deems relevant.  Theability of IDACORP to pay dividends on its common stock is dependent upondividends paid to it by its subsidiaries, primarily IPC.

Acovenant under the IDACORP and IPC Credit Facilities described in "MD&A -LIQUIDITY AND CAPITAL RESOURCES - Financing Programs - Credit Facilities"requires IDACORP and IPC to maintain leverage ratios of consolidated indebtednessto consolidated total capitalization of no more than 65 percent at the end ofeach fiscal quarter.  IPC's ability to pay dividends on its common stock heldby IDACORP and IDACORP's ability to pay dividends on its common stock arelimited to the extent payment of such dividends would cause their leverageratios to exceed 65 percent.  At December 31, 2006, the leverage ratios forIDACORP and IPC were 51 and 50 percent, respectively.

IPC's articles ofincorporation contain restrictions on the payment of dividends on its commonstock if preferred stock dividends are in arrears.  IPC has no preferred stockoutstanding.  IPC paid dividends to IDACORP of $51 million, $51 million and $46million in 2006, 2005 and 2004, respectively.

The following table shows thereported high and low sales price of IDACORP's common stock and dividends paidfor 2006 and 2005 as reported in the consolidated transaction reporting system.

**2006 Quarters**

Common  Stock, without par value:

**1st**

** **

**2nd**

** **

**3rd**

** **

**4th**

High

$33.28

$35.20

$38.81

$40.17

Low

28.97

32.00

34.00

37.61

Dividends  paid per share (cents)

30.0

30.0

30.0

30.0

**2005 Quarters**

Common  Stock, without par value:

**1st**

** **

**2nd**

** **

**3rd**

** **

**4th**

High

$30.64

$30.80

$32.05

$31.09

Low

27.32

26.22

28.75

27.46

Dividends  paid per share (cents)

30.0

30.0

30.0

30.0

** **

**IssuerPurchases of Equity Securities:**

None

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**Performance Graph**

The following performancegraph shows a comparison of the five-year cumulative total shareholder returnfor IDACORP common stock, the S&P 500 Index and the Edison ElectricInstitute (EEI) Electric Utilities Index.  The data assumes that $100 wasinvested on December 31, 2001, with beginning-of-period weighting of the peergroup indices (based on market capitalization) and monthly compounding ofreturns.

Source: Bloomberg and EdisonElectric Institute

** **

** **

** **

**EEI Electric**

** **

**IDACORP**

**S & P 500**

**Utilities Index**

2001

$100.00

$100.00

$100.00

2002

65.02

77.91

85.27

2003

83.78

100.24

105.29

2004

89.15

111.14

129.33

2005

89.02

116.59

150.09

2006

121.40

134.99

181.25

The foregoing performancegraph and data shall not be deemed "filed" as part of this Form 10-K forpurposes of Section 18 of the Securities Exchange Act of 1934 or otherwisesubject to the liabilities of that section and should not be deemedincorporated by reference into any other filing of IDACORP or IPC under theSecurities Act of 1933 or the Securities Exchange Act of 1934, except to theextent IDACORP or IPC specifically incorporates it by reference into suchfiling.

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**ITEM6.  SELECTED FINANCIAL DATA**

**IDACORP, Inc.**

**SUMMARY OF OPERATIONS**

**(thousands of dollars  except per share amounts)**

**2006**

**2005**

**2004**

**2003**

**2002**

Operating revenues

$

926,291

$

842,864

$

827,856

$

823,002

$

928,800

Operating income

169,704

154,653

106,233

84,062

75,640

Income from continuing  operations

100,075

85,716

80,781

49,732

70,377

Diluted earnings per share  from

continuing operations

2.34

2.02

2.10

1.30

1.86

Dividends declared per  share

1.20

1.20

1.20

1.70

1.86

**Financial Condition:**

Total assets

$

3,445,130

$

3,364,126

$

3,234,172

$

3,106,108

$

3,387,168

Long-term debt

1,023,773

1,039,852

1,058,152

1,013,757

988,268

**Financial Statistics:**

Times interest charges  earned:

Before tax (1)

2.78   

2.65   

1.99   

1.48   

1.33   

After tax (2)

2.54   

2.37   

2.32   

1.77   

2.06   

Market-to-book ratio (3)

151%

121%

128%

132%

108%

Payout ratio (4)

48%

79%

63%

139%

114%

Return on year-end common  equity (5)

9.6%

6.2%

7.2%

5.4%

7.1%

Book value per share (6)

$

25.65   

$

24.05   

$

23.88   

$

22.61  

$

22.98  

The financial statistics  listed above are calculated in the following manner:

(1) The sum of interest on  long-term debt, other interest expense excluding the allowance for funds used  during construction credits (AFDC),

and income before income  taxes divided by the sum of interest on long-term debt and other interest  expense excluding AFDC credits.

(2) The sum of interest on  long-term debt, other interest expense excluding AFDC credits, and income  from continuing operations divided by

the sum of interest on  long-term debt and other interest expense excluding AFDC credits.

(3) The closing price of  IDACORP stock on the last day of the year divided by the book value per  share, which is described in (6) below.

(4) Dividends paid per  common share for the year divided by earnings per diluted share.

(5) Net income divided by  total shareholders' equity at the end of the year.

(6) Total shareholders'  equity at the end of the year divided by shares outstanding at the end of the  year.

In the second quarter of2006, IDACORP management designated the operations of IDACORP Technologies,Inc. and IDACOMM as assets held for sale.  IDACORP's consolidated financialstatements reflect the reclassification of the results of these businesses asdiscontinued operations for all periods presented.  Discontinued operations arediscussed in more detail in Note 17 to IDACORP's and IPC's ConsolidatedFinancial Statements and later in "MD&A - RESULTS OF OPERATIONS -Non-utility Operations - Discontinued Operations."

IDACORP Energy, a marketer ofenergy commodities, wound down operations in 2003.

**ITEM 7.  MANAGEMENT'SDISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS**

(Dollar amounts and Megawatthours (MWh) are in thousands unless otherwise indicated).

**INTRODUCTION:**

In Management's Discussionand Analysis of Financial Condition and Results of Operations (MD&A), thegeneral financial condition and results of operations for IDACORP, Inc. and itssubsidiaries (collectively, IDACORP) and Idaho Power Company and its subsidiary(collectively, IPC) are discussed.

IDACORP is a holding companyformed in 1998 whose principal operating subsidiary is IPC.  IDACORP is subjectto the provisions of the Public Utility Holding Company Act of 2005, whichprovides certain access to books and records to the Federal Energy RegulatoryCommission (FERC) and state utility regulatory commissions and imposes certainrecord retention and reporting requirements on IDACORP.

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IPC is an electric utilitywith a service territory covering approximately 24,000 square miles in southern Idaho and eastern Oregon.  IPC is regulated by the FERC and the stateregulatory commissions of Idaho and Oregon.  IPC is the parent of Idaho EnergyResources Co., a joint venturer in Bridger Coal Company, which supplies coal tothe Jim Bridger generating plant owned in part by IPC.

IDACORP's other subsidiariesinclude:

•    IDACORP Financial Services, Inc.(IFS), an investor in affordable housing and other real estate investments;

•    Ida-West Energy Company(Ida-West), an operator of smallhydroelectric generation projects that satisfy the requirements of the Public UtilityRegulatory Policies Act of 1978 (PURPA);and

•    IDACORP Energy (IE), a marketer ofenergy commodities, which wound down operations in 2003.

In the second quarter of2006, IDACORP management designated the operations of IDACORP Technologies,Inc. (ITI) and IDACOMM as assets held for sale, as defined by Statement ofFinancial Accounting Standards No. 144.  *"Accounting for the Impairment orDisposal of Long-Lived Assets"* (SFAS 144).  IDACORP's consolidatedfinancial statements reflect the reclassification of the results of thesebusinesses as discontinued operations for all periods presented.  Discontinuedoperations are discussed in more detail in Note 17 to IDACORP's and IPC'sConsolidated Financial Statements and later in the MD&A.

On July 20, 2006, IDACORPcompleted the sale of all of the outstanding common stock of ITI to IdaTech UKLimited, a wholly-owned subsidiary of Investec Group Investments (UK) Limited.

On February 23, 2007, IDACORPcompleted the sale of all of the outstanding common stock of IDACOMM toAmerican Fiber Systems, Inc.

While reading the MD&A,please refer to the Consolidated Financial Statements of IDACORP and IPC, whichpresent the financial position at December 31, 2006 and 2005, and the resultsof operations and cash flows for each company for the years ended December 31,2006, 2005 and 2004.

**FORWARD-LOOKINGINFORMATION:**

Inconnection with the safe harbor provisions of the Private Securities LitigationReform Act of 1995 (Reform Act), IDACORP and IPC are hereby filing cautionarystatements identifying important factors that could cause actual results todiffer materially from those projected in forward-looking statements (as suchterm is defined in the Reform Act) made by or on behalf of IDACORP or IPC inthis Annual Report on Form 10-K, in presentations, in response to questions orotherwise.  Any statements that express, or involve discussions as toexpectations, beliefs, plans, objectives, assumptions or future events orperformance (often, but not always, through the use of words or phrases such as"anticipates," "believes," "estimates," "expects," "intends," "plans," "predicts,""projects," "may result," "may continue" or similar expressions) are notstatements of historical facts and may be forward-looking.  Forward-lookingstatements involve estimates, assumptions and uncertainties and are qualifiedin their entirety by reference to, and are accompanied by, the followingimportant factors, which are difficult to predict, contain uncertainties, arebeyond IDACORP's or IPC's control and may cause actual results to differmaterially from those contained in forward-looking statements:
- Changes     in and compliance with governmental policies, including new     interpretations of existing policies, and regulatory actions and     regulatory audits, including those of the Federal Energy Regulatory     Commission, the Idaho Public Utilities Commission, the Oregon Public     Utility Commission, and the Internal Revenue Service with respect to     allowed rates of return, industry and rate structure, day-to-day business     operations, acquisition and disposal of assets and facilities, operation     and construction of plant facilities, provision of transmission services,     relicensing of hydroelectric projects, recovery of purchased power     expenses, recovery of other capital investments, present or prospective     wholesale and retail competition (including but not limited to retail     wheeling and transmission costs) and other refund proceedings;
- Changes arising from the     Energy Policy Act of 2005;
- Litigation and regulatory     proceedings, including those resulting from the energy situation in the     western United States, and settlements that influence business and     profitability;
- Changes in and compliance     with environmental, endangered species and safety laws and policies;
- Weather variations     affecting hydroelectric generating conditions and customer energy usage;

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- Over-appropriation of     surface and groundwater in the Snake River basin resulting in reduced     generation at hydroelectric facilities;
- Construction of power     generating, transmission and distribution facilities including inability     to obtain required governmental permits and approvals, and risks related     to contracting, construction and start-up;
- Operation     of power generating facilities including breakdown or failure of     equipment, performance below expected levels, competition, fuel supply,     including availability, transportation and prices, and transmission;
- Impacts from the potential     formation of a regional transmission organization or the development of     another transmission group and the dissolution of Grid West;
- Population growth rates and     demographic patterns;
- Market demand and prices     for energy, including structural market changes;
- Changes in operating     expenses and capital expenditures and fluctuations in sources and uses of     cash;
- Results of financing     efforts, including the ability to obtain financing on favorable terms,     which can be affected by factors such as credit ratings and general     economic conditions;
- Actions     by credit rating agencies, including changes in rating criteria and new     interpretations of existing criteria;
- Homeland security, natural     disasters, acts of war or terrorism;
- Market     conditions that could affect the operations and prospects of IDACORP's     subsidiaries or their competitors;
- Increasing health care     costs and the resulting effect on medical benefits paid for employees;
- Performance of the stock     market and the changing interest rate environment, which affect the amount     of required contributions to pension plans, as well as the reported costs     of providing pension and other postretirement benefits;
- Increasing costs of     insurance, changes in coverage terms and the ability to obtain insurance;
- Changes in tax rates or     policies, interest rates or rates of inflation;
- Adoption of or changes in     critical accounting policies or estimates; and
- New accounting or     Securities and Exchange Commission requirements, or new interpretation or     application of existing requirements.

Any forward-looking statementspeaks only as of the date on which such statement is made.  New factors emergefrom time to time and it is not possible for management to predict all suchfactors, nor can it assess the impact of any such factor on the business or theextent to which any factor, or combination of factors, may cause results todiffer materially from those contained in any forward-looking statement.

**EXECUTIVE OVERVIEW:**

**2006 Financial Results**IDACORP's earnings for the year were$107 million, up $44 million as compared to 2005.  Diluted earnings per sharewere $2.51, an increase of $1.01 per share as compared to 2005.

The key components of thechange in IDACORP's net income are:
- IPC's earnings increased to     $94 million, a $22 million or $0.50 per diluted share increase over the     prior year.  This increase is primarily attributable to:   
-      Customer growth and increased electricitysales contributed $15 million (net of tax) to earnings.  IPC continued toexperience strong customer growth, gaining 14,633 new customers in 2006, anincrease of 3.2 percent.  The increase in electricity sales was primarily aresult of record electricity demand during an unusually warm period in May,June, and July.
-       	Improved operating margins(revenues less net power supply costs) contributed $11 million (net of tax) toearnings, largely as a result of improved hydroelectric generating conditionsand a net base rate increase of 1.0 percent on June 1, 2006 (3.2 percent baserate increase effective June 1, 2006, less a one-time base rate increase of 2.2percent related to a rate case tax settlement that expired on the same date). Improved stream flow conditions increased total system generation.  IPC'shydroelectric generation contributed 57 percent of total system generation for2006, as compared to 46 percent for 2005, and was 49 percent higher thangeneration in 2005.

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-      O&M expenses reduced earningsby $9 million (net of tax) compared to the prior year.  The increase isprimarily due to higher labor-related expenses resulting from general wageadjustments and attainment of performance targets, higher thermal O&M dueto aging thermal plant and equipment and unanticipated outages at the Valmyplant, and increases in other O&M items associated with higher levels ofelectricity generation, distribution and customer service efforts.
-       Income tax expense at IPC was flatyear-over-year.  Higher earnings before tax increased tax expense by $8 millionbut was offset by a net $8 million tax benefit that resulted from thesettlement of all non-263A (Uniform Capitalization) issues from the 2001-2003IRS exam.  The effective tax rates for 2006 and 2005 were 31.9 percent and 37.9percent, respectively.  Excluding the settlement, IPC's tax rates for 2006 and2005 would have been substantially the same.
- In 2006, management     designated the operations of ITI and IDACOMM as assets held for sale and     presented the operations of these entities as discontinued operations on     IDACORP's financial statements.  Discontinued operations contributed $7     million to earnings in 2006 as compared to a loss of $22 million in the     prior year, an increase of $0.69 per diluted share.  The improvement was     primarily due to a gain on disposal of ITI of $12 million, net of tax, or     $0.27 per diluted share.  The earnings increase is also attributable to     lower operating expenses resulting from the sale of ITI in July 2006 and     the phase-out of the broadband over power line business at IDACOMM during     the first half of 2006.  A $10 million goodwill impairment recorded at     IDACOMM during 2005 also impacted the results.
- Earnings at IE decreased     from $5 million in 2005 to zero in 2006, a decrease of $0.12 per diluted     share.  Since 2003, IE has had no operations but has been working to     settle outstanding legal actions related to transactions in the California energy markets in 2000 and 2001.  The major transaction affecting results in     2005 was an adjustment to an allowance for uncollectible accounts due from     California Parties in the California refund proceedings.
- Net loss at the holding     company increased $2 million to $6 million as compared to the prior year,     or $0.02 per diluted share.  The increase in net loss is attributable to     higher legal expenses and higher labor-related and stock-based     compensation expenses.
- IFS contributed $1 million     less to earnings than in the prior year, a decrease of $0.04 per diluted     share.  The decline in earnings is attributable to higher investment     amortization expense and lower tax benefits due to continued aging of     investments.
- IDACORP's income tax     expense increased $1 million as a result of higher earnings moderated by     the offset by the benefit from the 2001-2003 IRS exam settlement.

**Business Strategy**IDACORP is focusing on a strategythat emphasizes IPC as IDACORP's core business.  IPC continues to experiencestrong customer growth in its service area, and this corporate strategyrecognizes that IPC must make substantial investments in infrastructure toensure adequate supply and reliable service.  IFS and Ida-West remaincomponents of the corporate strategy.

The strategy includes seekingtimely rate relief in both the Idaho and Oregon jurisdictions.  IPC plans tofile in Idaho and Oregon for either asset-specific or general rate reliefregularly in upcoming years

The strategy also includesIDACORP's sale of non-core businesses.  IDACORP completed the sale of ITI onJuly 20, 2006, and completed the sale of IDACOMM on February 23, 2007.

**Regulatory Matters****General rate case settlement:**On June 1, 2006, IPC implemented a 3.2 percent ($18million annual) increase to its Idaho retail base rates.  IPC had filed ageneral rate case with the IPUC in October 2005, and the IPUC approved asettlement agreement in May 2006.  Base rates primarily reflect IPC's cost ofproviding electrical service to its customers, including equipment, vehiclesand infrastructure.  IPC's overall allowed rate of return in Idaho increased from7.85 percent to 8.1 percent.

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**Power Cost Adjustment:**On June 1, 2006, IPC implemented its annual Power CostAdjustment (PCA), resulting in a $123.5 million reduction in the rates of Idaho customers.  The reduction in rates comes as a direct benefit of the above-averagesnow pack in the mountains upstream of Brownlee Reservoir andlower-than-forecasted power supply costs in the 2005-2006 PCA year.  In yearswhen water is plentiful and IPC can fully utilize its extensive hydroelectricsystem, power production costs are lower and IPC can pass those benefits to itscustomers in the form of rate reductions.  When water is in short supply, as itwas from 2000 through 2005, the higher costs of supplying power by other meansalso are shared with IPC's customers.

**Emission allowances:**In 2005 and early 2006, IPC sold 78,000 SO2emission allowances for approximately $81.6 million (before income taxes andexpenses) on the open market.  After subtracting transaction fees, the totalamount of sales proceeds to be allocated to the Idaho jurisdiction isapproximately $76.8 million ($46.8 million net of tax, assuming a tax rate ofapproximately 39 percent).  Through allowance year 2006, IPC has approximately 36,000excess allowances.

Pursuant to the IPUC order,IPC retained 10 percent or approximately $4.7 million after tax of the emissionallowance net proceeds as a shareholder benefit.  The remaining 90 percent ofthe sales proceeds ($69.1 million) is to be recorded as a customer benefit andincluded in the PCA true-up.  A carrying charge will be calculated on $42.1million, the net-of-tax amount allocable to Idaho jurisdiction customers.  Thiscustomer benefit will be reflected in PCA rates during the June 1, 2007 throughMay 31, 2008 PCA rate year.

A stipulation is currentlybefore the OPUC which would offset SO2 emission allowance proceedsagainst the 2005-2006 balance of Oregon deferred power supply cost.

**LoadGrowth Adjustment Rate:**IPC filed apetition with the IPUC in April 2006 requesting modification of one componentof its PCA referred to as the Load Growth Adjustment Rate (LGAR).  The LGARsubtracts the cost of serving new Idaho retail customers from the power supplycosts IPC is allowed to include in its PCA.  The LGAR was set at $16.84 per MWhwhen the PCA began in 1993.  This amount was established as the projectedmarginal cost of serving each new customer and is subtracted from each year'sPCA expense.  On January 9, 2007, the IPUC issued its final order in thismatter.  The IPUC maintained the marginal cost methodology and set the new LGARat $29.41 per MWh.  The new rate becomes effective on April 1, 2007 and willfirst affect customer rates on June 1, 2008.

The impact of the new LGAR onIPC will ultimately be determined by future load growth.  Assuming an average40 MW load growth, the new rate would result in approximately $10.3 millionbeing subtracted from the next PCA, a pre-tax increase of $4.4 million over thecurrent amount.  The impact of the new LGAR can be partially offset by IPCthrough more frequent general rate case filings with the IPUC or from lesscustomer growth.  In its order the IPUC stated that it expected IPC to updateits load growth adjustment in all future general rate cases.

**IRS audit proceedings**On October 13, 2006, the InternalRevenue Service issued its examination report and assessment for IDACORP's2001-2003 tax years.  The IRS and IDACORP were able to settle all issues, withthe exception of IPC's capitalized overhead cost method.  The federal taxassessment for the settled issues was paid in November 2006 and did not have amaterial impact on IDACORP's 2006 cash flows.  The settlement decreased IDACORP's2006 income tax expense by $7.5 million as the assessed deficiency was lessthan the amounts previously accrued.  The disallowance of IPC's capitalizedoverhead cost method for uniform capitalization (the simplified service costmethod) resulted in a federal tax assessment of $45 million.  IDACORP disagreeswith this conclusion and has appealed the issue.  In November 2006, IDACORPfiled its formal protest, made a refundable deposit of the disputed tax withthe IRS to stop the accrual of interest, and requested an appeals conference. Management cannot predict the timing or outcome of this process, but believesthat an adequate provision for income taxes and related interest charges hasbeen made for this issue (see "Income Taxes" for a more detailed discussion).

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**2006 high temperatures**IPC's service territory, along withmuch of the western United States, experienced above-normal temperatures duringthe months of May, June and July 2006.  New records were set for coolingdegree-days, a measure of temperature impact on customer demand.  Due to theseabove-normal conditions, a new system peak of 3,050 MW was first set on June 27,2006, and was subsequently surpassed on July 24, 2006, when a new system peakof 3,084 MW was recorded.  Since June 27, 2006, the previous system peak of2,983 MW, which was set in 2002, was met or exceeded 11 times.  IPC was able tomeet all of its load requirements during these periods of increased demandthrough its system generation and by increasing the amount of its purchasedpower.

**Integrated Resource Plan**The IRP is prepared and filed everytwo years with the IPUC and the OPUC.  Prior to filing, the IRP requiresextensive involvement by IPC, the IPUC Staff, the OPUC Staff, and customer andenvironmental representatives, as well as input on the cost of variousgeneration technologies.  The IRP is the starting point for demonstratingprudence in IPC's resource decisions.  The 2006 IRP identified IPC's forecastload and resource situation for the next twenty years, analyzed potentialsupply-side and demand-side options and identified near-term and long-termactions.  The two primary goals of the 2006 IRP were to (1) identify sufficientresources to reliably serve the growing demand for energy service within IPC'sservice area throughout the 20-year planning period and (2) ensure that theportfolio of resources selected balances cost, risk and environmentalconcerns.  In addition, there were four secondary goals: (1) to give equal andbalanced treatment to both supply-side resources and demand-side measures, (2)to involve the public in the planning process in a meaningful way, (3) exploretransmission alternatives, and (4) investigate and evaluate advanced coaltechnologies.  The 2006 IRP was submitted to the IPUC in September 2006 and theOPUC in October 2006.  A hearing has been set in Oregon for June 2007.

**Capital Requirements andCash Flows**IDACORP estimates that it will spend $877 million on construction expendituresover the next three years.  This amount reflects the need for additionalresources in order for IPC to supply power to its growing number of customers.

Forecasts indicate thatinternal cash generation after dividends will provide less than the full amountof total capital requirements for 2007 through 2009.  IDACORP and IPC expect tocontinue financing the utility construction program and other capitalrequirements with internally generated funds and continued reliance onexternally financed capital.

The amount of internal cashgeneration is dependent primarily upon IPC's cash flows from operations, whichare subject to risks and uncertainties relating to weather and water conditionsand IPC's ability to obtain rate relief to cover its operating costs andprovide a return on investment.

**IdahoWater Management Issues**Power generation at the IPChydroelectric power plants on the Snake River is dependent upon the state waterrights held by IPC and the long-term sustainability of the Snake River,tributary spring flows and the Eastern Snake Plain Aquifer that is connected tothe Snake River.  IPC continues to participate in water management issues in Idaho that may affect those water rights and resources.  This includes active participationin the Snake River Basin Adjudication, a judicial action initiated in 1987 todetermine the nature and extent of water use in the Snake River basin, judicialand administrative proceedings relating to the conjunctive management of groundand surface water rights, and management and planning processes intended toreverse declining trends in river, spring, and aquifer levels and address thelong-term water resource needs of the state.  While none of the pending watermanagement issues are expected to impact IPC's hydroelectric generation in thenear term, IPC's ongoing participation in such issues will help ensure thatwater remains available over the long-term for use at IPC's hydropower projectson the Snake River.

**CRITICAL ACCOUNTINGPOLICIES AND ESTIMATES:**

IDACORP's and IPC'sdiscussion and analysis of their financial condition and results of operationsare based upon their consolidated financial statements, which have beenprepared in accordance with generally accepted accounting principles (GAAP). The preparation of these financial statements requires IDACORP and IPC to makeestimates and judgments that affect the reported amounts of assets,liabilities, revenues and expenses and related disclosure of contingent assetsand liabilities.  On an ongoing basis, IDACORP and IPC evaluate theseestimates, including those related to rate regulation, benefit costs,contingencies, litigation, asset impairment, income taxes, unbilled revenuesand bad debt.  These estimates are based on historical experience and on otherassumptions and factors that are believed to be reasonable under thecircumstances, and are the basis for making judgments about the carrying valuesof assets and liabilities that are not readily apparent from other sources. IDACORP and IPC, based on their ongoing reviews, will make adjustments whenfacts and circumstances dictate.

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IDACORP and IPC believe thefollowing critical accounting policies are important to the portrayal of theirfinancial condition and results of operations and require management's mostdifficult, subjective or complex judgments, often as a result of the need tomake estimates about the effect of matters that are inherently uncertain.

**Accounting for RateRegulation**A regulated company must satisfy thefollowing conditions in order to apply the accounting policies and practices ofStatement of Financial Accounting Standards (SFAS) 71, *"Accounting for theEffects of Certain Types of Regulation;"*an independent regulator must setrates; the regulator must set the rates to cover specific costs of deliveringservice; and the service territory must lack competitive pressures to reducerates below the rates set by the regulator.  SFAS 71 requires companies thatmeet the above conditions to reflect the impact of regulatory decisions intheir consolidated financial statements and requires that certain costs bedeferred as regulatory assets until matching revenues can be recognized. Similarly, certain items may be deferred as regulatory liabilities andamortized to the income statement as rates to customers are reduced.

IPC follows SFAS 71, and itsfinancial statements reflect the effects of the different rate makingprinciples followed by the jurisdictions regulating IPC.  The primary effect ofthis policy is that IPC has recorded $425 million of regulatory assets and $295million of regulatory liabilities at December 31, 2006.  While IPC expects tofully recover these regulatory assets and return these regulatory liabilities,such recovery is subject to final review by the regulatory entities.

If IPC should determine inthe future that it no longer meets the criteria for continued application ofSFAS 71, it would be required to write off its regulatory assets andliabilities unless regulators specify some other means of recovery or refund. In the event of deregulation, IPC intends to seek recovery of all of itsprudent costs, including stranded costs.  Due to the current lack of definitivelegislation, IPC cannot predict whether recovery would be successful.  If IPChas to write off a material amount of the regulatory assets, it will have amaterial adverse effect on IPC's results of operations and financial position.

**Pension Expense**IPC maintains a qualified definedbenefit pension plan covering most employees and an unfunded nonqualifieddeferred compensation plan for certain senior management employees anddirectors.

The expenses IDACORP and IPCrecord for these plans depend on a number of factors, including the provisionsof the plans, changing employee demographics, actual returns on plan assets andseveral assumptions used in the actuarial valuations upon which pension expenseis based.  The key actuarial assumptions that affect expense are the expectedlong-term return on plan assets and the discount rate used in determiningfuture benefit obligations.  Management evaluates the actuarial assumptions onan annual basis, taking into account changes in market conditions, trends andfuture expectations.  Estimates of future stock market performance, changes ininterest rates and other factors are used to develop the actuarial assumptionsand are extremely uncertain, and actual results could vary significantly fromthe estimates.

The assumed discount rate isbased on reviews of market yields on high-quality corporate debt. Specifically, IDACORP and IPC utilize data published in the Citigroup PensionLiability Index and apply the rates therein against the projected cash outflowsof the plans.  The discount rate used to calculate the 2007 pension expensewill be increased to 5.85 percent from the 5.60 percent used in 2006.

Rate-of-return projectionsfor plan assets are based on historical risk/return relationships among assetclasses.  The primary measure is the historical risk premium each asset classhas delivered versus the return on 10-year U.S. Treasury Notes.  Thishistorical risk premium is then added to the current yield on 10-year U.S.Treasury Notes, and the result provides a reasonable prediction of futureinvestment performance.  Additional analysis is performed to measure theexpected range of returns, as well as worst-case and best-case scenarios. Based on the current low interest rate environment, current rate-of-returnexpectations are lower than the nominal returns generated over the past 20years when interest rates were generally much higher.

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Pension expense for theseplans totaled $12 million, $10 million, and $10 million for the three yearsended December 31, 2006, 2005 and 2004, respectively, including amounts allocatedto capitalized labor costs.  For 2007, pension expense is expected to totalapproximately $11 million, which takes into account the increase in thediscount rate noted above.  No changes were made to the other key assumptionsused in the actuarial calculation.

Had different actuarialassumptions been used, pension expense could have varied significantly.  Thefollowing table reflects the sensitivities associated with changes in certainactuarial assumptions on historical and future pension expense: 

** **

**Discount rate**

**Rate of return**

** **

**2007**

**2006**

**2007**

**2006**

** **

**(millions of dollars)**

Effect of 0.5% increase

$

(1.4)

$

(1.7)

$

(2.0)

$

(1.8)

Effect of 0.5% decrease

2.4 

3.8 

2.0 

1.8 

No cash contributions weremade to the qualified plan in 2004 through 2006, and none are expected in2007.  Under the non-qualified plan, IPC makes payments directly toparticipants in the plan.  Payments averaged approximately $2.5 million peryear from 2004 to 2006, and a similar amount is anticipated in 2007.

Please refer to Note 9 ofIDACORP's and IPC's Consolidated Financial Statements, which containsadditional information about the pension plans.

**ContingentLiabilities**There are a number of unresolvedissues related to regulatory, legal and tax matters.  Contingent liabilitiesare provided for in accordance with SFAS 5, "*Accounting for Contingencies*." According to SFAS 5, an estimated loss from a loss contingency is charged toincome if (a) it is probable that an asset had been impaired or a liability hadbeen incurred at the date of the financial statements and (b) the amount of theloss can be reasonably estimated.  Disclosure in the notes to the financialstatements is required for loss contingencies not meeting both conditions ifthere is a reasonable possibility that a loss may have been incurred.  Gaincontingencies are not recorded until realized.

The companies have madeestimates of the ultimate resolution of all such matters, based on the factsand circumstances, opinions of legal counsel and other factors.  If therecognition criteria of SFAS 5 have been met, liabilities have been recorded. Estimates of this nature are highly subjective, and the final outcome of thesematters could vary significantly from the amounts that have been included inthe financial statements.

**Impairment****of Long-Lived Assets**Long-lived assets are periodically reviewed for impairment when events orchanges in circumstances indicate that the carrying amount of an asset may notbe recoverable as prescribed under SFAS 144, *"Accounting for the Impairmentor Disposal of Long-Lived Assets."*  SFAS 144 requires that if the sum ofthe undiscounted expected future cash flows from an asset is less than thecarrying value of the asset, an impairment must be recognized in the financialstatements.  Long-lived assets that were evaluated in 2006 include thefollowing:

**Grid West DevelopmentCosts:**  In response to FERC Order No.2000 issued in 1999, several northwest utilities, including IPC, attemptedformation of a regional transmission organization called RTO West, whicheventually evolved into Grid West.  IPC had recorded $1.1 million of loans toGrid West and $2.3 million of deferred internal costs from participating in thedevelopment effort.  IPC's deferral of development costs was consistent with a2004 accounting order that IPC received from the FERC.  These amounts wereinitially deferred anticipating future recovery through Grid West tariffs. Grid West was dissolved on April 11, 2006 and IPC no longer expectsreimbursement of either amount from Grid West.  IPC filed requests with theIPUC and OPUC to recover Grid West costs.  The IPUC and OPUC denied recovery ofthe deferred internal costs, and in the fourth quarter of 2006, IPC wrote off$2 million of the deferred costs.  The remaining $0.3 million of FERC relatedcosts were reclassified to regulatory assets in anticipation of recovery fromthe FERC in future periods.

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**Southwest IntertieProject:** IPC began developing theSouthwest Intertie Project (SWIP) in 1988.  IPC's investment consistspredominantly of a federal permit for a specific transmission corridor in Nevada and Idaho and also private rights-of-way in Idaho.  The SWIP rights-of-way extendfrom Midpoint substation in south-central Idaho through eastern Nevada to the Dry Lake area northeast of Las Vegas, Nevada.  In 2004 the Bureau of LandManagement granted a five-year extension to begin construction of a proposed500kV transmission line within the rights-of-way before December 2009.  OnMarch 31, 2005 IPC entered into an agreement with White Pine Energy Associates,LLC (White Pine), an affiliate of LS Power Development, LLC, which providesWhite Pine a three-year exclusive option to purchase the SWIP rights-of-wayfrom IPC.  The option may be exercised in part or as a whole and, if fullyexercised, will result in a net pre-tax gain to IPC of approximately $6million.  Based on management expectations regarding SWIP, no impairment hasbeen identified.

**Impairment ofEquity-Method Investments:**IFS has affordable housing investmentswith a net book value of $90 million at December 31, 2006, and Ida-West hasinvestments in four joint ventures that own electric power generationfacilities.  Except for two investments now consolidated in accordance withGAAP these investments are accounted for under the equity method of accountingas described in Accounting Principles Board Opinion No. (APB) 18, "*TheEquity Method of Accounting for Investments in Common Stock*."  The standardfor determining whether impairment must be recorded under APB 18 is whether theinvestment has experienced a loss in value that is considered another-than-temporary decline in value.  Impairment analyses on theseinvestments were performed in 2006 and no impairment was noted.  Theseestimates required IDACORP to make assumptions about future stream flows,revenues, cash flows and other items that are inherently uncertain.  Actualresults could vary significantly from the assumptions used, and the impact ofsuch variations could be material.

**Unbilled Revenue******IPC's retail revenues include anestimate of electricity delivered that has not been billed at the end of theperiod.  Unbilled revenues estimates are dependent upon a number of inputs thatrequire management's judgment.  Unbilled revenue is calculated by taking dailyestimates of MWhs delivered and applying information from the meter-readingschedule to estimate the portion of MWhs delivered that have not been billed. These unbilled MWhs are then allocated to the retail customer classes based onhistorical usage by each class.  IPC then records revenue for each customerclass based on their respective rates.  Due to the seasonal fluctuations of IPC'sload, the amount of unbilled revenue increases during the summer and wintermonths and decreases during the spring and fall.

**RESULTS OF OPERATIONS:**

This section of the MD&Atakes a closer look at the significant factors that affected IDACORP's and IPC'searnings over the last three years.  In this analysis, the results of 2006 arecompared to 2005 and the results of 2005 are compared to 2004.

The following table presentsearnings for IDACORP's segments as well as for the holding company:

** **

**2006**

** **

**2005**

** **

**2004**

IPC - Utility operations

$

93,929 

$

71,839 

$

65,785 

IDACORP Financial Services

9,509 

10,911 

13,313 

IDACORP Energy

5 

4,881 

2,162 

Ida-West Energy

2,564 

2,381 

3,089 

Holding company expenses

(5,932)

(4,296)

(3,568)

Discontinued operations

7,328 

(22,055)

(7,798)

Total Earnings

$

107,403 

$

63,661 

$

72,983 

Average outstanding shares  - diluted (000s)

42,874 

42,362 

38,420 

Earnings per diluted share

$

2.51 

$

1.50 

$

1.90 

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**Utility Operations****Operating environment: **IPC is one of the nation's few investor-ownedutilities with a predominantly hydroelectric generating base.  Because of itsreliance on hydroelectric generation, IPC's generation operations can besignificantly affected by weather conditions.  The availability ofhydroelectric power depends on the amount of snow pack in the mountainsupstream of IPC's hydroelectric facilities, springtime snow pack run-off,rainfall and other weather and stream flow management considerations.  Duringlow water years, when stream flows into IPC's hydroelectric projects arereduced, IPC's hydroelectric generation is reduced.  This results in lessgeneration from IPC's resource portfolio (hydroelectric, coal-fired andgas-fired) available for off-system sales and, most likely, an increased use ofpurchased power to meet load requirements.  Both of these situations - a reductionin off-system sales and an increased use of more expensive purchased power -result in increased power supply costs.  During high water years, increasedoff-system sales and the decreased need for purchased power reduce net powersupply costs.

Operations plans aredeveloped during the year to provide guidance for generation resourceutilization and energy market activities (off-system sales and powerpurchases).  The plans incorporate forecasts for generation unit availability,reservoir storage and stream flows, gas and coal prices, customer loads, energymarket prices and other pertinent inputs.  Consideration is given to when touse IPC's available resources to meet forecast loads and when to transact inthe energy market.  The allocation of hydroelectric generation between heavyload and light load hours or calendar periods is considered in development ofthe operating plans.  This allocation is intended to utilize the flexibility ofthe hydroelectric system to shift generation to high value periods, whileoperating within the constraints imposed on the system.  IPC's energy riskmanagement policy, unit operating requirements and other obligations providethe framework for the plans.

Stream flow conditions in2006 were much improved over 2005 resulting in 9.21 million MWh from IPChydroelectric facilities in 2006, compared to 6.20 million MWh in 2005.  Theobserved stream flow data released on August 1, 2006, by the National WeatherService's Northwest River Forecast Center indicated that Brownlee reservoirinflow for April through July 2006 was 8.95 million acre-feet (maf), or 142percent of average.  Brownlee reservoir inflow for 2006 totaled 16.98 maf, or123 percent of average.  Storage in selected federal reservoirs upstream ofBrownlee as of February 11, 2007, was 122 percent of average.  The stream flowforecast released on February 15, 2007 by the National Weather Service'sNorthwest River Forecast Center predicts that Brownlee reservoir inflow forApril through July 2007 will be 3.80 maf, or 60 percent of average.

Generationfrom thermal plants during 2006 was lower than 2005 due primarily to anunanticipated outage at the Boardman plant and a planned outage at the Valmyplant, of which IPC owns a ten percent and 50 percent interest, respectively. Both units returned to service in June 2006.  Additionally, the Bennett Mountain combustion turbine suffered a mechanical failure on July 11, 2006.  IPC'sinvestigation has revealed that during construction a bolt was negligentlyinstalled by a third party.  The bolt came loose, causing extensive mechanicaldamage.  The plant was down from July 12 through September 6, 2006.  Totalrepair costs were approximately $16 million.  IPC anticipates that insuranceproceeds and/or recovery from the party or parties responsible for the failurewill result in substantial reimbursement of these costs.

IPC's system load peaks inthe summer and winter, with the larger peak demand occurring in the summer.  The new all-time system peak demand was 3,084megawatts (MW), set on July 24, 2006.  The peak winter demand for the year was2,318 MW on December 18.  IPC was able tomeet system load requirements and off-system sales requirements and hadsufficient system reserves in place.  The following table presents IPC's powersupply for the last three years:

**MWh**

** **

** **

**Total System**

**Purchased**

** **

**Hydroelectric**

**Thermal**

**Generation**

**Power**

**Total**

2006

9,207

7,021

16,228

4,964

21,192

2005

6,199

7,315

13,514

3,894

17,408

2004

6,041

7,303

13,344

4,274

17,618

IPC's median annualhydroelectric generation is 8.25 million MWh, based on median hydrologicconditions for the standardized period of record, 1928 through 2005.

**GeneralBusiness Revenue:**  The primaryinfluences on electricity sales are weather, customer growth and economicconditions.  Extreme temperatures increase sales to customers who useelectricity for cooling and heating, and moderate temperatures decrease sales. Precipitation levels during the agricultural growing season affect sales tocustomers who use electricity to operate irrigation pumps.  Increasedprecipitation reduces electricity usage by these customers.

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Table of Contents

The following table presentsIPC's general business revenues, MWh sales, average number of customers and Boise, Idaho weather conditions for the last three years:

**2006**

** **

**2005**

** **

**2004**

Revenue

Residential

$

299,594

$

299,488

$

274,313

Commercial

162,391

173,268

164,053

Industrial

102,958

118,259

111,797

Irrigation

71,432

76,255

85,672

Total

$

636,375

$

667,270

$

635,835

MWh

Residential

5,068

4,760

4,580

Commercial

3,761

3,639

3,561

Industrial

3,475

3,423

3,335

Irrigation

1,635

1,467

1,763

Total

13,939

13,289

13,239

Customers (average)

Residential

387,707

373,602

360,462

Commercial

59,050

57,146

55,577

Industrial

130

129

120

Irrigation

18,081

17,942

17,306

Total

464,968

448,819

433,465

Heating  degree-days

5,195

5,437

5,249

Cooling  degree-days

1,209

965

998

Precipitation

12.1"

13.6"

11.6"

Heating and coolingdegree-days are a common measure used in the utility industry to analyze thedemand for electricity and indicate when a customer would use electricity for heatingand air conditioning.  A degree-day measures how much the average dailytemperature varies from 65 degrees.  Each degree of temperature above 65degrees is counted as one cooling degree-day, and each degree of temperaturebelow 65 degrees is counted as one heating degree-day.  Normal heatingdegree-days and cooling degree-days are 5,727 and 807, respectively.

2006 vs. 2005:
- Rates:   Rate decreases negatively impacted general     business revenue by $66.6 million in 2006 as compared to prior year.  A     PCA reduction on June 1, 2006, decreased rates by an average of 19.3     percent but was moderated by a net base rate increase of 1.0 percent on     June 1, 2006 (3.2 percent base rate increase effective June 1, 2006, less     a one-time base rate increase of 2.2 percent related to a rate case tax     settlement which expired on the same date).  Prior year revenues also     included amounts related to a rate case tax settlement and an irrigation     load reduction rate adjustment, both of which were recovered from June     2005 to May 2006 (with a corresponding reduction to other revenues);
- Customers:   General business customer growth improved revenue     $18.6 million for the year, as IPC continues to experience customer growth     in its service territory.  The residential customer base (12-month     average) increased 3.8 percent over prior year; and
- Usage:   Weather variations positively impacted sales by     $17.1 million.  Conditions were unusually warm in May, June and July     compared to the prior year, which had an abnormally cool and wet spring.

 

2005 vs. 2004:
- Rates:   Increased average rates resulting from higher     base rates that took effect on June 1 in both 2005 and 2004 increased     revenues $31 million.  This was partially offset by a net reduction in the     power cost adjustment rates, which reduced revenue $3 million from 2004.      Approximately $16 million of the rate increase represents collection of     previously recorded revenues from the irrigation load reduction program     and rate case tax settlement.  This revenue is offset by a corresponding     reduction to other revenues for the same amount;

29
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Table of Contents
- Customers :  A 3.5 percent increase in average general     business customers increased revenue $27 million, as IPC continued to     experience strong customer growth in its service territory.  IPC added     over 16,000 general business customers during the year; and
- Usage :  Heavy spring precipitation reduced sales to     irrigation customers by $17 million.  Rainfall during the second quarter     of 2005 was double that of 2004.  Other weather and usage factors reduced     sales to other customers by $6 million.

**Off-system sales:** Off-system sales consist primarily of long-term salescontracts and opportunity sales of surplus system energy.  The following tablemeasures IPC's off-system sales for the last three years:

** **

**2006**

** **

**2005**

** **

**2004**

Revenue

$

260,717

$

142,794

$

121,148

MWh sold

5,821

2,774

2,885

Revenue per MWh

$

44.79

$

51.48

$

41.99

** **

2006 vs. 2005:  In 2006, the MWh volume sold more than doubled andrevenues grew 83 percent.  Improved stream flow conditions increased totalsystem generation and electricity available for surplus sales.  Revenue fromhigher sales volumes were moderated by lower prices caused by abundant energyin the region.  The volume increase was also impacted by early water year indicationssuggesting continued drought conditions for 2006, prompting IPC to make forwardpurchases in conformance with its risk management policy that were subsequentlysold.  Additional sales activities are the result of conforming to IPC's riskmanagement policy, managing IPC's energy portfolio to meet customer load, andIPC reacting to changes in market conditions to minimize net power supplycosts.

2005 vs. 2004:  Revenues grew 18 percent due to higher energy pricesin 2005.  Market prices were higher and more volatile because of oil and gasprice increases due to instability in the Middle East and hurricane damage onthe Gulf Coast.  For the Northwest, continuation of drought conditions in theregion compounded the impact of these global problems.  Consequently,off-system sales revenue on a per MWh basis increased 23 percent for the year. Off-system sales volumes declined four percent, due primarily to changes inoperating conditions and load and stream flow timing, which reduced marketsales opportunities.

**Other revenues**: The following table presents the components of other revenues:

** **

**2006**

** **

**2005**

** **

**2004**

Transmission services and  property rental

$

33,526 

$

39,012 

$

39,839

BPA credit

- 

- 

4,000

Rate case tax settlement

(4,745)

(2,892)

7,100

Irrigation lost revenues

(5,400)

(8,501)

11,587

Total

$

23,381 

$

27,619 

$

62,526

2006 vs. 2005:  Other revenues decreased $4 million due mainly tothe following:
- In 2006, IPC recorded a $1     million provision for rate refund associated with a revised Open Access     Transmission Tariff (OATT) filing with the FERC requesting an increase in     transmission rates.  This matter is discussed further in "REGULATORY     MATTERS;"
- In December 2006, IPC     recorded a $3 million revenue reduction related to estimated refundable     wheeling revenues and a true up of transmission use-of-facility rates from     1998 through 2005.

2005 vs. 2004:  Other revenues decreased $35 million due mainly tothe following:
- In December 2004, IPC     recorded approximately $12 million related to the recovery of lost revenue     resulting from IPC's Irrigation Load Reduction Program.  The recovery was     included as part of IPC's annual PCA beginning on June 1, 2005, and $9     million has been amortized as the amounts are billed.  This matter is discussed     further in "REGULATORY MATTERS - Deferred Power Supply Costs - Idaho;"

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- In 2004, IPC recognized     approximately $7 million of revenue due to the IPUC order approving     Settlement No. 1, which relates to the calculation of IPC's taxes for     purposes of test year income tax expense in the 2003 Idaho general rate     case.  As a result of this settlement, IPC recorded a regulatory asset of     approximately $12 million from June 1, 2004 through May 31, 2005 ($7     million in 2004 and $5 million in 2005).  IPC began collecting this amount     beginning in June 2005 with an adjustment to rates and $8 million has been     amortized as the amounts are billed; and
- In July 2004, IPC     recognized $4 million of revenue from an agreement with the Bonneville     Power Administration for the release of 100,000 acre-feet of storage water     from Brownlee Reservoir.  This amount was included in the June 1, 2005 PCA     resulting in a benefit to IPC's Idaho customers.

**Purchased power:**

** **

**2006**

** **

**2005**

** **

**2004**

Expense

$

283,440

$

222,310

$

195,642

MWh purchased

4,964

3,894

4,274

Cost per MWh purchased

$

57.10

$

57.09

$

45.77

** **

2006 vs. 2005:  Purchased power expense grew 27 percent in 2006. Record high temperatures and electricity demand, particularly in July 2006, ledto increased purchases during a period of high market prices.  The increase wasalso impacted by early water year indications suggesting continued droughtconditions for 2006, which prompted IPC to make forward purchases inconformance with its risk management policy.  Additional purchase activitieswere the result of managing IPC's energy portfolio to meet customer load andreacting to changes in market conditions to minimize net power supply costs.

2005 vs. 2004:  Purchased power expense grew 14 percent due to higherenergy prices in 2005.  Market prices were higher and more volatile for thereasons discussed above.  Purchased power expense on a per MWh basis increased25 percent for the year.  Purchased power volumes declined nine percent. Different operating conditions and system load and stream flow timing led toreduced market purchase activities.

**Fuel expense:**  The following table presents IPC's fuel expenses andgeneration at its thermal generating plants:

**2006**

** **

**2005**

** **

**2004**

Fuel expense

$

115,018

$

103,164

$

103,261

Thermal MWh generated

7,021

7,315

7,303

Cost per MWh

$

  16.38

$

14.10

$

14.14

** **

2006 vs. 2005:  The increase in fuel expense is due primarily to a$12.7 million increase in expense from higher coal and rail transportationcosts.  The increased cost of coal is due primarily to higher market demand,and the increased rail transportation costs are primarily driven by higherdiesel fuel costs, including an adjustable fuel surcharge.  Higher natural gascosts of $3 million also contributed to the increase.  Generation from the coalfired power plants was down 4 percent due to unplanned outages at Valmy andBoardman.  This decrease resulted in a $4 million decrease in fuel expense. 

2005 vs. 2004:  Fuel expenses and thermal plant volumes wereessentially unchanged in 2005 as compared with 2004.

**PCA:**  PCA expense represents the effect of IPC's PCAregulatory mechanism, which is discussed in more detail below in "REGULATORYMATTERS - Deferred Power Supply Costs - Idaho."  In 2006, higher electricitypurchase volumes, particularly in July during a period of high market prices,coupled with increased coal and natural gas prices, caused an increase in netpower supply costs (fuel and purchased power less off-system sales) over theamounts anticipated in the annual PCA forecast.  This increase in net powersupply costs was partially offset by increased hydroelectric generation in thefirst half of 2006, resulting in the deferral of costs which will be recoveredin subsequent rate years.  As the deferred costs are being recovered in rates,the deferred balances are amortized.

In 2005 and 2004 actual netpower supply costs also exceeded the amounts anticipated in the annual PCAforecast.

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The following table presentsthe components of PCA expense:

** **

**2006**

** **

**2005**

** **

**2004**

Current year net power  supply cost deferral

$

(27,094)

$

(30,786)

$

(29,306)

Amortization of prior year  authorized balances

(2,432)

27,791 

49,190 

Settlement agreement

- 

- 

19,300 

Total power cost adjustment

$

(29,526)

$

(2,995)

$

39,184 

** **

**Other Operations andMaintenance Expenses:**2006 vs. 2005:  Other operations and maintenance expenses increased$15 million due mainly to the following: 
- An increase in     labor-related expenses of $8.5 million due to higher salaries and     incentive-based compensation, partially triggered by improved steamflow     conditions and the sale of ITI;
- An increase of  $6.3     million in hydroelectric and distribution O&M expenses attributable to     better generation conditions and the growth in general business customers;     
- An increase of $3.5 million     in thermal O&M expense resulting primarily from costs due to an     extended outage in 2006 at the Valmy plant; and
- A write off of $2 million in     the fourth quarter of 2006 for deferred development costs associated with     the attempted formation of Grid West. 

These increases werepartially offset by a $7.1 million gain resulting from the sale of emissionallowances during the year and a $3 million reversal of accrued FERC fees.  IPCand several other utilities contested whether certain federal agency chargescould be passed on to utilities through FERC fees.  A judgment in favor of IPCand the other utilities was finalized in September.

2005 vs. 2004:  Other operations and maintenance expenses decreased$15 million due mainly to the 2004 write-off of $9 million related todisallowed items in the Idaho general rate case.

**Non-utility Operations**

**IFS**IFS earned $10 million, $11 million, and $13 million in 2006, 2005 and 2004,respectively, principally from the generation of federal income tax credits andaccelerated tax depreciation benefits.  The 2004 results included a $2 milliongain, net-of-tax, in other income on IDACORP's Consolidated Statements ofIncome for the sale of its investment in the El Cortez Hotel in San Diego, California.

IFS made $5 million in newinvestments during 2006 and generated tax credits of $19 million, $20 millionand $22 million during 2006, 2005 and 2004, respectively.  IFS expects tocontinue delivering tax benefits at a level commensurate with the ongoing needsof IDACORP.

**Discontinued Operations**In the second quarter of 2006,IDACORP management designated the operations of ITI and IDACOMM as assets heldfor sale.  The operations of these entities are presented as discontinuedoperations in IDACORP's financial statements.

On July 20, 2006, IDACORPcompleted the sale of all of the outstanding common stock of ITI to IdaTech UKLimited, a wholly-owned subsidiary of Investec Group Investments (UK) Limited. IDACORP recorded a gain of $11.5 million, net of tax, or $0.27 per dilutedshare from this transaction in the third quarter of 2006.

On February 23, 2007, IDACORPcompleted the sale of all of the outstanding common stock of IDACOMM toAmerican Fiber Systems, Inc. for proceeds of $10 million.  The sale of IDACOMM did not have a materialeffect on IDACORP's financial position, results of operations or cash flows.

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Income from discontinuedoperations was $7 million in 2006 and consisted of a loss from operations of $8million, gain on disposal of ITI of $14 million and an income tax benefit of $1million.  The loss from discontinued operations of $22 million and $8 millionfor 2005 and 2004 consisted of a loss from operations of $27 million and $13million, respectively, and an income tax benefit of $5 million for both years. The 2005 results also included a $10 million goodwill impairment chargerecorded at IDACOMM.

**Energy Marketing**IE recorded net income of $0 million,$5 million and $2 million in 2006, 2005 and 2004, respectively.

In2003, IE wound down its power marketing operations, closed its businesslocations and sold its forward book of electricity trading contracts to SempraEnergy Trading.  Since that time, IE has had no operations but has been workingto settle outstanding legal matters surrounding transactions in the California energy markets in 2000 and 2001.  These matters are discussed in "LEGAL ANDENVIRONMENTAL ISSUES - Legal and Other Proceedings."

Net income increased from $2million in 2004 to $5 million in 2005, due primarily to a $9.5 millionadjustment to an allowance for uncollectible accounts recorded in the fourthquarter of 2005.  This adjustment was based on management's assessment of thenegotiations to settle California refund proceedings discussed in "LEGAL ANDENVIRONMENTAL ISSUES - Legal and Other Proceedings."

The major transactionaffecting results in 2004 was $5 million of gains on settlements of legaldisputes.

**Ida-West**Ida-West recorded net income of $3million, $2 million and $3 million in 2006, 2005 and 2004, respectively. Ida-West continues to manage its independent power projects.

In 2003 a $2.6 million baddebt reserve was established on a note receivable from a partner in one of Ida-West'sjoint ventures.  No adjustments were made to this reserve in 2006 or 2004, butin 2005 the reserve was reduced by $0.7 million based on updated estimates ofcollectibility.

**Income TaxesFIN 48: **In June 2006, the FinancialAccounting Standards Board (FASB) issued FASB Interpretation No. 48, "*Accountingfor Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109*"(FIN 48), to create a single model to address accounting for uncertainty in taxpositions.  FIN 48 prescribes a minimum recognition threshold that a taxposition is required to meet before being recognized in a company's financialstatements and also provides guidance on derecognition, measurement,classification, interest and penalties, accounting in interim periods,disclosure, and transition.  FIN 48 is effective for fiscal years beginningafter December 15, 2006.

IDACORPand IPC will adopt FIN 48 in the first quarter of 2007, as required.  Thecumulative effect of adopting FIN 48 will be recorded as an adjustment to 2007opening retained earnings.  IDACORP and IPC have not yet completed theirevaluation of the effects the adoption of FIN 48 will have on their financialpositions or results of operations.

**Statusof audit proceedings: **In March 2005,the Internal Revenue Service (IRS) began its examination of IDACORP's 2001-2003tax years.  On October 13, 2006, the IRS issued its examination report andassessment for those years.  With the exception of IPC's capitalized overheadcosts method, discussed below, the IRS and IDACORP were able to settle allissues.  The $1.6 million federal tax assessment for the settled issues waspaid in November 2006.  Interest charges and state income taxes have beenaccrued and are expected to be paid during 2007.  Settlement of the agreedissues decreased 2006 income tax expense by $5.6 million at IDACORP and $6.2million at IPC as the assessed deficiency was less than amounts previouslyaccrued.

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TheIRS disallowed IPC's capitalized overhead cost method for uniformcapitalization (the simplified service cost method) on the basis that IPC'sself-constructed assets were not produced on a "routine and repetitive" basisas defined by Rev. Rul. 2005-53.  The disallowance resulted in a federal taxassessment of $45 million.  IDACORP disagreed with this conclusion and inNovember 2006 filed its formal protest and request for an appeals conference. Also in November 2006, IDACORP made a refundable deposit of the disputed taxwith the IRS to stop the accrual of interest.  In December 2006, the IRSexamination team filed its rebuttal to IDACORP's protest.  In January 2007,IDACORP was notified that its case has been assigned to the IRS AppealsOffice.  IDACORP cannot predict the timing or outcome of this process, butbelieves that an adequate provision for income taxes and related interestcharges 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 takethe same position for 2004 as it did for 2001-2003; however, it is not likelythat this position will result in a federal income tax assessment primarily dueto the mitigating effect of accelerated tax depreciation.

On July 7, 2006, the IRSissued its examination report for Bridger Coal Company's 2001-2003 tax years. Bridger Coal is a partnership investment owned one-third by IPC.  The auditresulted in net favorable adjustments to Bridger Coal's tax returns for thoseyears.  As a result of the settlement, IDACORP and IPC were able to decrease2006 income tax expense by $1.9 million.

In 2004, IDACORP completedsettlement of all issues related to the IRS's examination of its federal incometax returns for the years 1998 through 2000.  Concurrently, IPC settled federalincome tax deficiencies for the years 1999 and 2000 related to its partnershipinvestment in Bridger Coal Company.  Applicable state tax return amendmentswere completed in 2004 and settled.  Finalization of these examinationsresulted in deficiencies that were less than previously accrued, enablingIDACORP to decrease income tax expense by $1.7 million in 2004.

**Capitalized overheadcosts: **Generally, section 263A ofthe Internal Revenue Code of 1986, as amended, requires the capitalization ofall direct costs and indirect costs, including mixed service costs, whichdirectly benefit or are incurred by reason of the production of property by ataxpayer.  The simplified service cost method, a "safe harbor" method, is oneof the methods provided by the section 263A treasury regulations for thecalculation of mixed service cost capitalization.  IPC adopted the simplifiedservice cost method for both the self-construction of utility plant andproduction of electricity beginning with its 2001 federal income tax return.

On August 2, 2005, the IRSand the Treasury Department issued guidance interpreting the meaning of "routineand repetitive" for purposes of the simplified service cost and simplifiedproduction methods of the Internal Revenue Code section 263A uniformcapitalization 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 toAugust 2, 2005, and proposed and temporary regulations (the "TemporaryRegulations") which are effective for tax years ending on or after August 2,2005.  Both pieces of guidance take a more restrictive view of the definitionof 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 thesimplified service cost method.

For IPC, the simplifiedservice cost method produced a current tax deduction for costs capitalized toelectricity production that are capitalized into fixed assets for financialaccounting purposes.  Deferred income tax expense had not been provided forthis deduction because the prescribed regulatory tax accounting treatment doesnot allow for inclusion of such deferred tax expense in current rates.  Rateregulated enterprises are required to recognize such adjustments as regulatoryassets if it is probable that such amounts will be recovered from customers infuture rates. 

As discussed in "Status ofAudit Proceedings" above, the IRS has disallowed IPC's use of the simplifiedservice 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 is in the process of appealing the IRS's assessment.  Because of thenature of the issue, IDACORP's exposure with respect to this matter may be lessthan the tax assessed plus applicable interest charges.  Additionally, afterresolution IDACORP will likely amend its 2005 federal income tax return and its2005 method change application to account for the effects that such resolutionhas on IPC's new uniform capitalization method (discussed below).  Thisamendment is not expected to have a material negative impact on IDACORP's orIPC's consolidated financial position, results of operations, or cash flows.

With respect to tax year 2005and future tax years, the Temporary Regulations, as drafted, preclude IPC fromusing the simplified service cost method for its self-constructed assets. Under the Temporary Regulations, IPC is required to use another allowablesection 263A method for its indirect costs, including mixed service costs.  Asa result of the Temporary Regulations, IPC made changes to its overall section263A uniform capitalization method of accounting.  In September 2006, thechanges were adopted with an automatic method change request included inIDACORP's 2005 federal income tax return.  The uniform capitalizationmethodology adopted for 2005 and subsequent years involves the use of thespecific identification, burden rate, and step-allocation methods ofaccounting.  The methods used are allowable under both the final and temporarysection 263A regulations.

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As with the simplifiedservice cost method, the new uniform capitalization methodology produces anannual tax deduction for costs that are not required to be capitalized undersection 263A as well as costs capitalized into the production of electricity. The method, while producing a beneficial result, is not as favorable as thesimplified service cost method.  Changing the uniform capitalization methodresulted in a net charge to IPC's 2006 income tax expense of $6.1 million.  Theestimated 2006 tax deduction produced a $3.3 million tax benefit for the year. The change in method did not have a material effect on IDACORP's or IPC's 2006cash flows.  The accounting and regulatory treatment for the new method is thesame as previously used for the simplified service cost method.

**LIQUIDITY AND CAPITALRESOURCES:**

**Discontinued operations**Cash flows from discontinuedoperations are included with the cash flows from continuing operations in IDACORP'sConsolidated Statements of Cash Flows.  The cash flows of IDACORP'sdiscontinued operations have reduced net cash provided by operating activitiesand increased net cash used in investing activities, except for the cashreceived in 2006 from the sale of ITI.  The absence of cash flows from thesediscontinued operations is expected to positively impact liquidity and capitalresources in future periods.

**Operating Cash Flows**IDACORP's and IPC's operating cashflows for 2006 were $170 million and $131 million, respectively.  These amountswere an increase of $8 million and decrease of $35 million compared to 2005. The following are significant items that affected operating cash flows in 2006:
- Income tax payments     increased in 2006 due to the timing of and increases in taxable income,     including the timing effect of cash received in the fourth quarter of 2005     from the sale of approximately $70 million of excess SO 2      emission allowances.
- In 2006, IE collected $13     million of amounts receivable from the Cal ISO and CalPX, and collected     $10 million that it had deposited on margin with a counterparty in 2005.

IDACORP's and IPC's operatingcash flows for 2005 were $161 million and $166 million, respectively, decreasesof $33 million and $32 million compared to 2004.  The decreases were mainlyrelated to:
- A $19 million reduction in     distributions from the Bridger Coal joint venture, as Bridger is retaining     cash to fund increased capital expenditures for conversion to underground     mining.
- Timing of cash     disbursements made in 2005 for December 2004 payable balances, including     $9 million in employee incentive compensation paid during the first     quarter of 2005.

IDACORP's operating cashflows are driven principally by IPC.  General business revenues and the coststo supply power to general business customers have the greatest impact on IPC'soperating cash flows, and are subject to risks and uncertainties relating toweather and water conditions and IPC's ability to obtain rate relief to coverits operating costs and provide a return on investment.

**Investing Cash Flows**IPC's construction expenditures were$222 million in 2006, $186 million in 2005 and $190 million in 2004.  IPC isexperiencing a cycle of heavy infrastructure investment needed to addresscontinued customer growth, peak demand growth, and aging plant and equipment.

In 2005 and 2006, sales ofemission allowances provided investing cash of approximately $82 million beforetaxes and expenses.  Pursuant to negotiations with the IPUC, IPC will returnapproximately $69 million to Idaho ratepayers starting in June 2007.  Seefurther discussion in "REGULATORY MATTERS - Emission Allowances."

In November 2006, IDACORPmade a refundable deposit of $45 million with the IRS related to a disputedincome tax assessment.  See further discussion in "RESULTS OF OPERATIONS -Income Taxes."

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**Financing Cash Flows****Debt issuances:**  On October 3, 2006, IPC completed a tax-exempt bondfinancing in which Sweetwater County, Wyoming issued and sold $116.3 millionaggregate 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 in 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 thenew bonds, together with certain other moneys of IPC, were used to refundSweetwater County's Pollution Control Revenue Refunding Bonds (Idaho PowerCompany Project) Series 1996A, Series 1996B and Series 1996C totaling $116.3million.  The regularly scheduled principal and interest payments on the Series2006 bonds, and principal and interest payments on the bonds upon mandatoryredemption on determination of taxability, are insured by a financial guarantyinsurance policy issued by AMBAC Assurance Corporation.  IPC and AMBAC haveentered into an Insurance Agreement, dated as of October 3, 2006, pursuant towhich IPC has agreed, among other things, to pay certain premiums to AMBAC andto reimburse AMBAC for any payments made under the policy.  In order to secureits 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, PollutionControl Series C, in a principal amount equal to the principal amount of thenew bonds.

On August 26, 2005, IPCissued $60 million of 5.30% First Mortgage Bonds due 2035, Secured Medium-TermNotes, Series F.  The proceeds of the issuance were used to repay the $60million, 5.83% First Mortgage Bonds that matured on September 9, 2005.

**Equity issuances:** On December 15, 2005, IDACORP entered into a SalesAgency Agreement with BNY Capital Markets, Inc. (BNYCMI).  Under the terms ofthe Sales Agency Agreement, IDACORP may offer and sell up to 2,500,000 sharesof its common stock, from time to time in at the market offerings throughBNYCMI, as IDACORP's agent for such offer and sale.  In the fourth quarter of2006, IDACORP issued 536,518 shares under this program, for net proceeds of $21million.

In April 2005, with the goalof adding additional common equity to its capital structure, IDACORP beganusing original issue common stock in its Dividend Reinvestment and StockPurchase Plan, rather than purchasing this stock on the open market.  Beginningin August 2005, IDACORP also began using original issue common stock for its401(k) plan.  Under these plans, IDACORP issued 244,756 shares in 2006 and203,253 shares in 2005, for proceeds of $9 million and $6 million,respectively.

IDACORP issued 406,623 sharesin 2006 and 16,400 shares in 2005 in connection with the exercise of stockoptions, for proceeds of $12 million and $0.4 million, respectively.

**Capital Requirements**The following table presents IDACORP'sand IPC's expected capital requirements from 2007 through 2009:

**2007**

** **

**2008-2009**

**(millions of dollars)**

**IPC capital  expenditures:**

Hydroelectric generation:

Additions and upgrades

$

6

$

57

Environmental (including  relicensing)

19

31

Thermal generation

Additions and upgrades*

87

101

Environmental

11

13

Total generating facilities

123

202

Transmission lines and  substations

42

111

Distribution lines and  substations

81

151

General

40

78

IPC construction  expenditures

286

542

Other IPC

13

1

Total IPC 

299

543

Other

8

27

Total IDACORP

$

307

$

570

* Excludes $20 - $50  million potential impact of coal-fired resources (see discussion below)

Variations in the timing andamounts of capital expenditures will result from regulatory and environmentalfactors, load growth, other resource acquisition needs and the timing ofrelicensing expenditures.

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Table of Contents

**Utility ConstructionProgram:**  IPC is experiencing a cycleof heavy infrastructure investment needed to address continued customer growth,peak demand growth, and aging plant and equipment.  IPC's aging hydroelectricfacilities require continuing upgrades and component replacement.  In addition,costs related to relicensing hydroelectric facilities and complying with thenew licenses are substantial.  Continuing load growth also requires that IPCadd to its transmission system and distribution facilities to provide newservice and to maintain reliability.  Planned expenditures include distributionand high-voltage transmission lines for new customers and several lines.

As a result, IPC expects tospend $828 million in construction expenditures from 2007 to 2009.  The 2007 -2009 utility construction expenditure forecast includes: (1) $77 million ofconstruction costs for a 160-MW combustion turbine peaking resource expected tobe operational in mid-2008; (2) $40 million for an upgrade to the ShoshoneFalls hydroelectric facility expected to be operational in 2011; and (3) $50million for hydroelectric relicensing.

IPC's Integrated ResourcePlan identifies two 250-MW coal-fired resources utilizing pulverized coal andcoal gasification technologies needed in 2013 and 2017.  The 2007 - 2009estimates of capital expenditures exclude the potential impact related to theconstruction or acquisition of these coal-fired resources and relatedtransmission capacity.  The development of coal resources requires very longlead times with significant expenditures spread over many years making accurateestimates difficult.  At this time and subject to further evaluation andscreening, IPC estimates that $20 million to $50 million could be spent from2007 to 2009 for the development of these projects.  IPC will continue toreview and update its options and will evaluate financing strategies to fundthese capital requirements.  See further discussion in "REGULATORY MATTERS -Integrated Resource Plan" and "REGULATORY MATTERS - Relicensing ofHydroelectric Projects."

IPC has no nuclearinvolvement and its future construction plans do not include development orownership of any nuclear generation.

**Other Capital Requirements**: Most of IDACORP's non-regulated capital expendituresrelate to IFS's investments in affordable housing developments that help lowerIDACORP's income tax liability.

Internal cash generationafter dividends is expected to provide less than the full amount of totalcapital requirements for 2007 through 2009.  IDACORP's internally generatedcash after dividends is expected to provide approximately 50 percent of 2007capital requirements excluding mandatory or optional principal payments on debtobligations.  Excluding the ratepayer emission refunds, IDACORP's internallygenerated cash after dividends is expected to provide approximately 60 percentof 2007 capital requirements.  IDACORP and IPC expect to continue financingcapital requirements with internally generated funds and externally financedcapital.

**Financing Programs**IDACORP's consolidated capital structure consisted of common equity of 49percent and debt of 51 percent at December 31, 2006.

**Shelf Registrations**: IDACORP currently has $658 million remaining on twoshelf registration statements that can be used for the issuance of unsecureddebt (including medium-term notes) and preferred or common stock.  IPCcurrently has in place one shelf registration statement that can be used forthe issuance of an aggregate principal amount of $240 million of first mortgagebonds (including medium-term notes) and unsecured debt.  See Note 4 to IDACORP'sand IPC's Consolidated Financial Statements for more information regardinglong-term financing arrangements.

**Credit Facilities:** IDACORP has a $150 million five-year credit agreementthat terminates on March 31, 2010 (the IDACORP Facility).  The IDACORPFacility, which is used for general corporate purposes and commercial paperback-up, provides for the issuance of loans and standby letters of credit notto exceed the aggregate principal amount of $150 million, provided that theaggregate amount of the standby letters of credit may not exceed $75 million.

IPC has a $200 millionfive-year credit agreement that terminates on March 31, 2010 (the IPCFacility).  The IPC Facility, which is used for general corporate purposes andcommercial paper back-up, provides for the issuance of loans and standbyletters of credit not to exceed the aggregate principal amount of $200 million,provided that the aggregate amount of the standby letters of credit may notexceed $100 million.

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Both the IDACORP Facility andthe IPC Facility have similar terms and conditions.  Under the terms of thefacilities IDACORP and IPC may borrow floating rate advances and Eurodollarrate advances.  The floating rate is equal to the higher of (i) the prime rateannounced by Wachovia Bank or its parent and (ii) the sum of the federal fundseffective rate for such day plus 1/2 percent per annum, plus, in each case, anapplicable margin.  The Eurodollar rate is based upon the British Bankers'Association interest settlement rate for deposits in U.S. dollars published onthe Telerate Page 3750 (or any successor page) as adjusted by the applicablereserve requirement for Eurocurrency liabilities imposed under Regulation D ofthe Board of Governors of the Federal Reserve System, for periods of one, two,three or six months plus the applicable margin.  The margin is based theapplicable company's rating for senior unsecured long-term debt securitieswithout third-party credit enhancement as provided by Moody's and S&P.  Themargin for the floating rate advances is zero percent unless the applicablecompany's rating falls below Baa3 from Moody's or BBB- from S&P, at whichtime it would equal 0.50 percent.  The margin for Eurodollar rate advancesranges from 0.27 percent to 0.875 percent depending upon the credit rating.  Inaddition to the margin, if the outstanding aggregate credit exposure exceeds 50percent of the facility amount, IDACORP or IPC, as applicable, would pay autilization fee ranging from 0.10 percent to 0.125 percent on outstanding loansdepending on the credit rating.  At December 31, 2006, the applicable marginunder the IDACORP Facility and the IPC Facility was zero percent for floatingrate advances and 0.425 percent for Eurodollar rate advances and 0.125 percentfor a utilization fee.  A facility fee, payable quarterly, is calculated on theaverage daily aggregate commitment of the lenders under the relevant creditfacility and is also based on the applicable company's rating from Moody's orS&P as indicated above.  At December 31, 2006, the facility fee under eachfacility was 0.15 percent.

In connection with theissuance of letters of credit, IDACORP and IPC, as applicable, must pay (i) afee equal to the applicable margin for Eurodollar rate advances on the averagedaily undrawn stated amount under such letters of credit, payable quarterly inarrears, (ii) a fronting fee at a per annum rate of 0.125 percent on theaverage daily undrawn stated amount under each letter of credit, payablequarterly in arrears and (iii) documentary and processing charges in accordancewith the letter of credit issuer's standard schedule for such charges.

A ratings downgrade wouldresult in an increase in the cost of borrowing and of maintaining letters ofcredit, but would not result in any default or acceleration of the debt undereither the IDACORP Facility or the IPC Facility.

The events of default underboth the IDACORP Facility and the IPC Facility include (i) nonpayment ofprincipal when due and nonpayment of reimbursement obligations under letters ofcredit within one business day after becoming due and nonpayment of interest orother fees within five days after becoming due, (ii) materially falserepresentations or warranties made on behalf of the applicable company or anyof its subsidiaries on the date as of which made, (iii) breach of covenants,subject in some instances to grace periods, (iv) voluntary and involuntarybankruptcy of the applicable company or any material subsidiary, (v) thenon-consensual appointment of a receiver or similar official for the applicablecompany or any of its material subsidiaries or any substantial portion (asdefined in the applicable facility) of its property, (vi) condemnation of allor any substantial portion of the property of the applicable company or itssubsidiaries, (vii) default in the payment of indebtedness in excess of $25million or a default by the applicable company or any of its subsidiaries underany agreement under which such debt was created or governed which will cause orpermit the acceleration of such debt or if any of such debt is declared to bedue and payable prior to its stated maturity, (viii) the applicable company orany of its subsidiaries not paying, or admitting in writing its inability topay, its debts as they become due, (ix) the acquisition by any person or two ormore persons acting in concert of beneficial ownership (within the meaning ofRule 13d-3 of the Securities Exchange Act of 1934) of 20 percent or more of theoutstanding shares of voting stock of the applicable company, (x) the failureof IDACORP to own free and clear of all liens, all of the outstanding shares ofvoting stock of IPC, (xi) unfunded liabilities of all single employer plansunder the Employee Retirement Income Security Act of 1974 exceeding $50 millionand (xii) the applicable company or any subsidiary being subject to anyproceeding or investigation pertaining to the release of any toxic or hazardouswaste or substance into the environment or any violation of any environmentallaw (as defined in the applicable facility) which could reasonably be expectedto have a material adverse effect (as defined in the applicable facility).  Adefault or an acceleration of indebtedness of IPC in excess of $25 million,including indebtedness under the IPC Facility will result in a cross defaultunder the IDACORP Facility.

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Upon any event of defaultrelating to the voluntary or involuntary bankruptcy of IDACORP or IPC or theappointment of a receiver, the obligations of the lenders to make loans underthe facility and of the letter of credit issuer to issue letters of credit willautomatically terminate and all unpaid obligations will become due andpayable.  Upon any other event of default, the lenders holding 51 percent ofthe outstanding loans or 51 percent of the aggregate commitments (requiredlenders) or the administrative agent with the consent of the required lendersmay terminate or suspend the obligations of the lenders to make loans under thefacility and of the letter of credit issuer to issue letters of credit underthe facility or declare the obligations to be due and payable.  IDACORP and IPCwill also be required to deposit into a collateral account an amount equal tothe aggregate undrawn stated amount under all outstanding letters of credit andthe aggregate unpaid reimbursement obligations thereunder.

If there is a ratingsdowngrade below investment grade (BBB- or higher by S&P and Baa3 or higherby Moody's), then IPC's authority for continuing borrowings under itsregulatory approvals issued by the IPUC and the Oregon Public UtilityCommission (OPUC) must be extended or renewed during the occurrence of theratings downgrade.  The Oregon statutes, however, permit the issuance orrenewal of indebtedness maturing not more than one year after the date of suchissue or renewal without approval of the OPUC.  In an order issued May 6, 2005,the IPUC clarified that IPC's authority will not terminate but will continuefor a period of 364 days from any downgrade below investment grade.

At December 31, 2006, no loanswere outstanding under the IDACORP Facility or the IPC Facility.

**Debt Covenants:**  The IDACORP Facility and the IPC Facility eachcontain a covenant requiring each company to maintain a leverage ratio ofconsolidated indebtedness to consolidated total capitalization of no more than65 percent as of the end of each fiscal quarter.  At December 31, 2006, theleverage ratios for IDACORP and IPC were 51 and 52 percent, respectively.  AtDecember 31, 2006, IDACORP was in compliance with all other covenants of theIDACORP Facility and IPC was in compliance with all other covenants of the IPCFacility.  Both the IDACORP Facility and the IPC Facility contain additionalcovenants including:

(i)   prohibitions against: investmentsand acquisitions by the applicable company or any subsidiary without theconsent of the required lenders subject to exclusions for investments in cashequivalents or securities of the applicable company; investments by theapplicable company and its subsidiaries in any business trust controlled,directly or indirectly, by the applicable company to the extent such businesstrust purchases securities of the applicable company; investments andacquisitions related to the energy business or other business of the applicablecompany and its subsidiaries not exceeding $500 million in the aggregate at anyone time outstanding (provided that investments in non-energy relatedbusinesses do not exceed $150 million); and investments by the applicablecompany or a subsidiary in connection with a permitted receivablessecuritization (as defined in the facility); 

(ii)  prohibitions against theapplicable company or any material subsidiary merging or consolidating with anyother person or selling or disposing of all or substantially all of itsproperty to another person without the consent of the required lenders, subjectto exclusions for mergers into or dispositions to the applicable company or awholly owned subsidiary and dispositions in connection with a permittedreceivables securitization; 

(iii) restrictions on the creation ofcertain liens by the applicable company or any material subsidiary subject toexceptions, including the lien of IPC's first mortgage indebtedness; and 

(iv)  prohibitions on any materialsubsidiary of the applicable company entering into any agreement restrictingits ability to declare or pay dividends to the applicable company exceptpursuant to a permitted receivables securitization.

**Credit RatingsS&P**:  On March 27, 2006, S&Pannounced that it had revised its general corporate credit rating outlooks forIDACORP and IPC to negative from stable.  All other S&P credit ratings forIDACORP and IPC were reaffirmed.  S&P stated that the negative outlooksreflect the potential for weakened financial metrics as a result of severalfactors, including possible passage of the water diversion legislation anduncertainty regarding the federal and state tax treatment and allocation ofprevious refunds of about $75 million (see "INCOME TAXES - Capitalized OverheadCosts" above and Note 2 to IDACORP's and IPC's Condensed Consolidated FinancialStatements for a full discussion of capitalized overhead costs).  A lesssubstantial concern was the uncertainty regarding the relicensing of the HellsCanyon Complex.

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Access to capital markets ata reasonable cost is determined in large part by credit quality.  Thesedowngrades have increased the cost of new debt and other issued securities. The following outlines the current S&P, Moody's and Fitch ratings ofIDACORP's and IPC's securities:

** **

**S&P**

**Moody's**

**Fitch**

** **

**IPC**

**IDACORP**

**IPC**

**IDACORP**

**IPC**

**IDACORP**

Corporate Credit Rating

BBB+

BBB+

Baa  1

Baa  2

None

None

Senior Secured Debt

A-

None

A3

None

A-

None

Senior Unsecured Debt

BBB (prelim)

BBB (prelim)

Baa  1

Baa  2

BBB+

BBB

Short-Term Tax-Exempt Debt

BBB/A-2

None

Baa  1/VMIG-2

None

None

None

Commercial Paper

A-2

A-2

P-2

P-2

F-2

F-2

Credit Facility

None

None

Baa  1

Baa  2

None

None

Rating Outlook

Negative

Negative

Stable

Stable

Stable

Stable

These security ratingsreflect the views of the rating agencies.  An explanation of the significanceof these ratings may be obtained from each rating agency.  Such ratings are nota recommendation to buy, sell or hold securities.  Any rating can be revisedupward or downward or withdrawn at any time by a rating agency if it decidesthat the circumstances warrant the change.  Each rating should be evaluatedindependently of any other rating.

**Off-Balance SheetArrangements**The federal Surface Mining Controland Reclamation Act of 1977 and similar state statutes establish operational,reclamation and closure standards that must be met during and upon completionof mining activities.  These obligations mandate that mine property be restoredconsistent with specific standards and the approved reclamation plan.  Themining operations at the Bridger Coal Company are subject to these reclamationand closure requirements.  IPC has agreed to guarantee the performance ofreclamation activities at Bridger Coal Company, of which Idaho Energy ResourcesCo., a subsidiary of IPC, owns a one-third interest.  This guarantee, which isrenewed each December, was $60 million at December 31, 2006.  Bridger Coal hasa reclamation trust fund set aside specifically for the purpose of paying thesereclamation costs and expects that the fund will be sufficient to cover allsuch costs.  Because of the existence of the fund, the estimated fair value ofthis guarantee is minimal.

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**Contractual Obligations**The following table presents IDACORP'sand IPC's contractual cash obligations for the respective periods in which theyare due:

**Payment Due by Period**

Total

**2007**

**2008-2009**

**2010-2011**

**Thereafter**
   
**(millions of dollars)**
**IPC:**

Long-term debt (a)

$

987

$

81

$

82

$

122

$

702

Future interest payments (b)

771

56

98

81

536

Operating leases (c)

15

3

6

1

5

Purchase obligations:

Cogeneration  and small power production

1,422

45

153

159

1,065

Fuel supply agreements

131

54

59

7

11

Purchased power & transmission (d)

123

80

24

6

13

Other (e)

162

91

29

12

30

Total purchase obligations

1,838

270

265

184

1,119

Pension and postretirement plans (g)

72

6

13

14

39

Other long-term liabilities - IPC 

6

4

2

-

-

Total IPC

$

3,689

$

420

$

466

$

402

$

2,401

**Other:**

Long-term debt (a)(f)

40

14

16

3

7

Future interest payments (b)(f)

9

2

2

1

4

Operating leases (f)

9

2

2

1

4

Total IDACORP

$

3,747

$

438

$

486

$

407

$

2,416

(a)  

For additional information, see Note 4 to IDACORP's  and IPC's Consolidated Financial Statements.

(b)

Future interest payments are calculated based on the  assumption that all debt is outstanding until maturity.  For debt instruments  with variable rates, interest is calculated for all future periods using the  rates in effect at December 31, 2006

(c)  

Approximately $10 million of the obligations included  in the detail of operating leases have contracts that do not specify terms  related to expiration.  As these contracts are presumed to continue  indefinitely, 10 years of information, estimated based on current contract terms,  have been included in the table for presentation purposes

(d)  

Approximately $6 million of the obligations included  in the detail of purchased power and transmission have contracts that do not  specify terms related to expiration.  As these contracts are presumed to  continue indefinitely, 10 years of information, estimated based on current  contract terms, have been included in the table for presentation purposes.

(e)  

Approximately $4 million of the amounts in other  purchase obligations can be cancelled without penalty.  Additionally,  approximately $45 million of the contracts do not specify terms related to  expiration.  As these contracts are presumed to continue indefinitely, 10  years of information, estimated based  on current contract terms, have been  included in the table for presentation purposes

(f)  

Amounts include the obligations of IDACORP's  subsidiaries other than IPC, which is shown separately.

(g)

Based on current assumptions, no pension  contributions will be required during the next five years.  IPC cannot  estimate contributions beyond 2011 at this time.  Amounts include 10 years of  postretirement and non-qualified pension contributions.

** **

**Environmental RegulationCosts: **IPC anticipates $19 millionin annual operating costs for environmental facilities during 2007. Hydroelectric facility expenses account for $12 million of this total and $7million is related to thermal plant operating expenses.  From 2008 through2009, total environmental related operating costs are estimated to be $50million.  Expenses related to the hydroelectric facilities are expected to be$35 million and thermal plant expenses are expected to total $15 million duringthis period.

**LEGAL AND ENVIRONMENTALISSUES:**

**Legal and OtherProceedingsShareholder Lawsuit:** On May 26, 2004and June 22, 2004, respectively, two shareholder lawsuits were filed againstIDACORP and certain of its directors and officers.  The lawsuits, captionedPowell, et al. v. IDACORP, Inc., et al. and Shorthouse, et al. v. IDACORP,Inc., et al., raised largely similar allegations.  The lawsuits were putativeclass actions brought on behalf of purchasers of IDACORP stock between February1, 2002 and June 4, 2002, and were filed in the U.S. District Court for theDistrict of Idaho.  The named defendants in each suit, in addition to IDACORP,are Jon H. Miller, Jan B. Packwood, J. LaMont Keen and Darrel T. Anderson.

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The complaints alleged that,during the purported class period, IDACORP and/or certain of its officersand/or directors made materially false and misleading statements or omissionsabout the company's financial outlook in violation of Sections 10(b) and 20(a)of the Securities Exchange Act of 1934, as amended, and Rule 10b-5, therebycausing investors to purchase IDACORP's common stock at artificially inflatedprices.  More specifically, the complaints alleged that IDACORP failed todisclose and misrepresented the following material adverse facts which wereknown to defendants or recklessly disregarded by them: (1) IDACORP failed toappreciate the negative impact that lower volatility and reduced pricingspreads in the western wholesale energy market would have on its marketingsubsidiary, IE; (2) IDACORP would be forced to limit its origination activitiesto shorter-term transactions due to increasing regulatory uncertainty andcontinued deterioration of creditworthy counterparties; (3) IDACORP failed toaccount for the fact that IPC may not recover from the lingering effects of theprior year's regional drought and (4) as a result of the foregoing, defendantslacked a reasonable basis for their positive statements about IDACORP and theirearnings projections.  The Powell complaint also alleged that the defendants'conduct artificially inflated the price of IDACORP's common stock.  The actionsseek an unspecified amount of damages, as well as other forms of relief.  Byorder dated August 31, 2004, the court consolidated the Powell and Shorthousecases for pretrial purposes, and ordered the plaintiffs to file a consolidatedcomplaint within 60 days.  On November 1, 2004, IDACORP and the directors andofficers named above were served with a purported consolidated complaintcaptioned Powell, et al. v. IDACORP, Inc., et al., which was filed in the U.S.District Court for the District of Idaho.

The new complaint allegedthat during the class period IDACORP and/or certain of its officers and/ordirectors made materially false and misleading statements or omissions aboutits business operations, and specifically the IE financial outlook, in violationof Rule 10b-5, thereby causing investors to purchase IDACORP's common stock atartificially inflated prices.  The new complaint alleged that IDACORP failed todisclose and misrepresented the following material adverse facts which wereknown to it or recklessly disregarded by it: (1) IDACORP falsely inflated thevalue of energy contracts held by IE in order to report higher revenues andprofits; (2) IDACORP permitted IPC to inappropriately grant native loadpriority for certain energy transactions to IE; (3) IDACORP failed to file 13ancillary service agreements involving the sale of power for resale ininterstate commerce that it was required to file under Section 205 of theFederal Power Act; (4) IDACORP failed to file 1,182 contracts that IPC assignedto IE for the sale of power for resale in interstate commerce that IPC wasrequired to file under Section 203 of the Federal Power Act; (5) IDACORP failedto ensure that IE provided appropriate compensation from IE to IPC for certainaffiliated energy transactions; and (6) IDACORP permitted inappropriate sharingof certain energy pricing and transmission information between IPC and IE. These activities allegedly allowed IE to maintain a false perception ofcontinued growth that inflated its earnings.  In addition, the new complaintalleges that those earnings press releases, earnings release conference calls,analyst reports and revised earnings guidance releases issued during the classperiod were false and misleading.  The action seeks an unspecified amount ofdamages, as well as other forms of relief.  IDACORP and the other defendantsfiled a consolidated motion to dismiss on February 9, 2005, and the plaintiffsfiled their opposition to the consolidated motion to dismiss on March 28,2005.  IDACORP and the other defendants filed their response to the plaintiff'sopposition on April 29, 2005 and oral argument on the motion was held on May19, 2005.

On September 14, 2005,Magistrate Judge Mikel H. Williams of the U.S. District Court for the Districtof Idaho issued a Report and Recommendation that the defendants' motion todismiss be granted and that the case be dismissed.  The Magistrate Judgedetermined that the plaintiffs did not satisfactorily plead loss causation(i.e., a causal connection between the alleged material misrepresentation andthe loss) in conformance with the standards set forth in the recent UnitedStates Supreme Court decision of Dura Pharmaceuticals, Inc. v. Broudo, 544 U.S.336, 125 S. Ct. 1627 (2005).  The Magistrate Judge also concluded that it wouldbe futile to afford the plaintiffs an opportunity to file an amended complaintbecause it did not appear that they could cure the deficiencies in theirpleadings.  Each party filed objections to different parts of the MagistrateJudge's Report and Recommendation.

On March 29, 2006, the U.S.District Court for the District of Idaho (Judge Edward J. Lodge) issued anOrder in this case (Powell v. IDACORP) adopting the Report and Recommendationof Magistrate Judge Williams issued on September 14, 2005, granting thedefendants' (IDACORP and certain of its officers and directors) motion todismiss because plaintiffs failed to satisfy the pleading requirements for losscausation.  However, Judge Lodge modified the Report and Recommendation andruled that plaintiffs had until May 1, 2006, to file an amended complaint onlyas to the loss causation element.  On May 1, 2006, the plaintiffs filed anamended complaint.  The defendants filed a motion to dismiss the amendedcomplaint on June 16, 2006, asserting that the amended complaint still failedto satisfy the pleading requirements for loss causation.  Briefing on this mostrecent motion to dismiss was completed on August 28, 2006 and oral argument washeld on February 26, 2007.

IDACORP and the other defendantsintend to defend themselves vigorously against the allegations.  IDACORPcannot, however, predict the outcome of these matters.

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**Wah Chang:**  On May 5, 2004, Wah Chang, a division of TDYIndustries, Inc., filed two lawsuits in the U.S. District Court for theDistrict of Oregon against numerous defendants.  IDACORP, IE and IPC are namedas defendants in one of the lawsuits.  The complaints allege violations offederal antitrust laws, violations of the Racketeer Influenced and CorruptOrganizations Act, violations of Oregon antitrust laws and wrongfulinterference with contracts.  Wah Chang's complaint is based on allegationsrelating to the western energy situation.  These allegations include bidrigging, falsely creating congestion and misrepresenting the source anddestination of energy.  The plaintiff seeks compensatory damages of $30 millionand treble damages.

On September 8, 2004, thiscase was transferred and consolidated with other similar cases currentlypending before the Honorable Robert H. Whaley sitting by designation in theU.S. District Court for the Southern District of California.  The companies'filed a motion to dismiss the complaint which the court granted on February 11,2005.  Wah Chang appealed the dismissal to the U.S. Court of Appeals for theNinth Circuit on March 10, 2005.  The Ninth Circuit set a briefing schedule onthe appeal, requiring Wah Chang's opening brief to be filed by July 6, 2005. On May 18, 2005, Wah Chang filed a motion to stay the appeal or in thealternative to voluntarily dismiss the appeal without prejudice toreinstatement.  The companies opposed the motion and filed a cross-motionasking the Court to summarily affirm the district court's order of dismissal. On July 8, 2005, the Ninth Circuit denied Wah Chang's motion and also deniedthe companies' motion for summary affirmance without prejudice to renewalfollowing the filing of Wah Chang's opening brief.  Wah Chang's opening briefwas filed on September 21, 2005.  On October 11, 2005 the companies, along withthe other defendants, filed a motion to consolidate this appeal with Wah Changv. Duke Energy Trading and Marketing currently pending before the NinthCircuit.  On October 18, 2005 the Ninth Circuit granted the motion toconsolidate and established a revised briefing schedule.  The companies filedan answering brief on November 30, 2005.  Wah Chang's reply brief was filed onJanuary 6, 2006.  The appeal has been fully briefed and oral argument isscheduled for April 10, 2007.  The companies intend to vigorously defend theirposition in this proceeding and believe this matter will not have a materialadverse effect on their consolidated financial positions, results of operationsor cash flows.

**City of Tacoma:**  On June 7, 2004, the City of Tacoma, Washingtonfiled a lawsuit in the U.S. District Court for the Western District ofWashington at Tacoma against numerous defendants including IDACORP, IE andIPC.  The City of Tacoma's complaint alleges violations of the ShermanAntitrust Act.  The claimed antitrust violations are based on allegations ofenergy market manipulation, false load scheduling and bid rigging andmisrepresentation or withholding of energy supply.  The plaintiff seekscompensatory damages of not less than $175 million.

On September 8, 2004, thiscase was transferred and consolidated with other similar cases currentlypending before the Honorable Robert H. Whaley sitting by designation in theU.S. District Court for the Southern District of California.  The companiesfiled a motion to dismiss the complaint which the court granted on February 11,2005.  The City of Tacoma appealed to the U.S. Court of Appeals for the NinthCircuit on March 10, 2005.

On August 9, 2005, thecompanies moved for summary affirmance of the district court's order dismissingthe City of Tacoma's complaint.  The City of Tacoma filed a response to thecompanies' motion for summary affirmance on August 24, 2005.  The Ninth Circuitdenied the companies' motion for summary affirmance on November 3, 2005.  Theappeal has been fully briefed and oral argument is scheduled for April 10,2007.  The companies intend to vigorously defend their position in thisproceeding and believe this matter will not have a material adverse effect ontheir consolidated financial positions, results of operations or cash flows.

**Western Energy Proceedingsat the FERC:** IE and IPC are involvedin a number of FERC proceedings arising out of the western energy situation inCalifornia and claims that dysfunctions in the organized California marketscontributed to or caused unjust and unreasonable prices in Pacific Northwestspot markets, and may have been the result of manipulations of gas or electricpower markets.  They include proceedings involving:

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**(1)  California Power Exchange Chargeback:** the chargeback provisions of the California Power Exchange (CalPX)participation agreement triggered when a participant defaulted on a payment tothe CalPX.  Upon such a default, other participants were required to pay theirallocated share of the default amount to the CalPX.  This provision was firsttriggered by the Southern California Edison default and later by the PacificGas and Electric Company default.  The FERC has ordered the CalPX to hold thechargeback funds and that such funds may be used to make-up individual sellershortfalls in their CalPX account at the conclusion of the California Refundproceeding.  Based upon the Offer of Settlement filed with the FERC on February17, 2006 between the California Parties and IE and IPC discussed below in the California refund proceeding, the California Parties supported a motion filed by IE and IPCwith the FERC seeking an Order Directing Return of Chargeback Amounts then heldby the CalPX totaling $2.27 million.  In the May 22, 2006 order approving theSettlement, the FERC granted the IE and IPC motion for return of chargebackfunds held by the CalPX.  On June 1, 2006, IE received approximately $2.5million from the CalPX representing the return of $2.27 million in chargebackfunds plus interest.

**(2)****California****Refund:**  proceeding whichoriginated with an effort by the State of California to obtain refunds for aportion of the spot market sales from sellers of electricity into California from October 2, 2000 through June 20, 2001.  California is claiming that thesales prices were not just and reasonable and were not in compliance with theFederal Power Act.  The FERC issued an order on refund liability on March 26,2003 on which multiple parties, including IE, sought rehearing.  On October 16,2003, the FERC denied the requests for rehearing and required the CaliforniaIndependent System Operator (Cal ISO) to make a compliance filing regardingrefund amounts within five months, which has been delayed on a number ofoccasions and has not yet been filed with the FERC.  On May 12, 2004, the FERCissued an order clarifying its earlier refund orders and denying a request bycertain parties to present as evidence an earlier settlement between theCalifornia Public Utilities Commission and El Paso related to manipulation ofgas pipeline capacity claiming that the settlement dollars California isreceiving from El Paso ($1.69 billion) are duplicative of the FERC orderchanging the gas component of its refund methodology.  The FERC denied requestsfor rehearing on November 23, 2004.  On December 2, 2003, IE and otherspetitioned the United States Court of Appeals for the Ninth Circuit for reviewof the FERC's orders on California refunds.  As additional FERC orders havebeen issued, further petitions for review have been filed, including by IE, andhave been consolidated with the appeals already pending before the NinthCircuit.  On September 21, 2004, the Ninth Circuit convened the first of itscase management proceedings, a procedure reserved to help organize complex cases. On October 22, 2004, the Ninth Circuit severed several issues related to theFERC's refund jurisdiction, established a schedule for briefing and held oralargument on April 12 and 13, 2005.  On September 6, 2005, the Ninth Circuitissued a decision in one of the severed cases concluding that the FERC lackedrefund authority over wholesale electrical energy sales made by governmentalentities and non-public utilities.  On August 2, 2006, the Ninth Circuit issuedits decision on a second severed case ruling that all transactions thatoccurred within or as a result of the CalPX and the Cal ISO were the propersubject of the refund proceeding; refused to expand the proceedings into thebilateral market, approved the refund effective date as October 2, 2000 butrequired FERC to reconsider based upon claims that some market participants hadviolated governing tariff obligations (the California Parties are seeking arefund effective date of May 1, 2000); and effectively expanded the scope ofthe refund proceeding to transactions within the CalPX and Cal ISO marketsoutside the 24-hour spot market and energy exchange transactions.  On August 8,2005 the FERC issued an order establishing a framework for those sellerswanting to make a cost filing to demonstrate that the generally applicable FERCrefund methodology interfered with the recovery of costs.  The companies alongwith others made a cost filing on September 14, 2005, the California entitiescommented on October 11, 2005, and IPC and IE replied to those comments onOctober 17, 2005.  The California entities filed supplemental comments onOctober 24, 2005 and the companies filed supplemental reply comments on October27, 2005.

In December 2005, IE and IPC reached a tentativeagreement with the California Parties settling matters encompassed by theCalifornia Refund proceeding including IE and IPC's cost filing and refundobligation.  On January 20, 2006, the Parties filed a request with the FERCasking that the FERC defer ruling on IE and IPC's cost filing for thirty daysso the parties could complete and file the settlement agreement with the FERC. On January 26, 2006, the FERC granted the requested deferral of a ruling on thecost filing and required that the settlement be filed by February 17, 2006.  OnFebruary 17, 2006, IE and IPC jointly filed with 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 WaterResources and the California Attorney General) an Offer of Settlement at theFERC.  Other parties had until March 9, 2006 to elect to become an additionalsettling party.  Final comments on the settlement were due to be filed by March20, 2006.  A number of other parties, representing substantially less than themajority of potential refund claims, chose to opt out of the settlement.

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On March 27, 2006, the FERC issued an order rejectingthe IE/IPC cost filing and on April 26, 2006, IE and IPC sought rehearing ofthe rejection.  By order of April 27, 2006, the FERC tolled the time for whatotherwise would have been required by statute to make a decision on the requestfor rehearing.On May 12, 2006, the FERC issued an order determining the method that should beused to allocate amounts approved in cost filings, approving the methodologythat IE and IPC and others had advocated prior to the time IE and IPC enteredinto the February 17, 2006 settlement - allocating cost offsets to buyers inproportion to the net refunds they are owed through the Cal ISO and CalPXmarkets.  On June 12, 2006, the California Parties requested rehearing, urgingthe FERC to allocate the cost offsets to all purchasers from the Cal ISO andCalPX markets and not just to that limited subset of purchasers who are netrefund recipients.  On July 12, 2006, the FERC tolled the time to act on therequest for rehearing and has not issued orders on rehearing since that time. IDACORP and IPC are unable to predict how or when the FERC might rule on therequest for rehearing.

After consideration of comments, the FERC approved theFebruary 17, 2006 Offer of Settlement on May 22, 2006.  Under the terms of theSettlement, IE and IPC assigned $24.25 million of the rights to accountsreceivable from the Cal ISO and CalPX to the California Parties to pay into anescrow account for refunds to settling parties.  Amounts from that escrow notused for settling parties and $1.5 million of the remaining IE and IPC receivablesthat 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 theremaining litigation of this matter.  Any excess funds remaining at the end ofthe case are to be returned to IPC and IE.  Approximately $10.25 million of theremaining IE and IPC receivables was paid to IE and IPC under the settlement.

OnJune 21, 2006, the Port of Seattle, Washington filed a request for rehearing ofthe FERC order approving the settlement.  On July 10, 2006, IPC and IE and theCalifornia Parties filed a response to Port of Seattle's request forrehearing.  On October 5, 2006, the FERC issued an order denying the Port of Seattle's request for rehearing.  On October 24, 2006, the Port of Seattle petitioned the U.S. Court of Appeals for the Ninth Circuit for review of the FERCorders approving the settlement.  The Ninth Circuit consolidated that reviewpetition with the large number of review petitions already consolidated beforeit.  On January 23, 2007, IPC and IE filed a motion to sever the Port of Seattle's petition for review from the bulk of cases pending in the Ninth Circuitwith which it had been consolidated.  IPC and IE also filed a motion to dismissthe Port of Seattle's petition for review.  The Port of Seattle filed theiranswers in opposition to the motion to sever and the motion to dismiss onFebruary 1, 2007, and IPC and IE replied on February 12, 2007.  IDACORP and IPCare not able to predict when or how the Ninth Circuit might rule on themotions.

OnDecember 31, 2005, with respect to the CalPX chargeback and the CaliforniaRefund proceedings discussed above, the CalPX and the Cal ISO owed $14 millionand $30 million, respectively, for energy sales made to them by IPC in Novemberand December 2000.  In the fourth quarter of 2005, IE reduced by $9.5 millionto $32 million its reserve against these receivables.  This reserve wascalculated taking into account the uncertainty of collection, given the California energy situation.  Following payment of the $10.25 million to IE and IPC in June2006, IE further reduced the reserve by $24.9 million to $7.1 million.  Thisreserve was calculated taking into account several unresolved issues in the California refund proceeding.  Based on the reserve recorded as of December 31, 2006,IDACORP believes that the future collectibility of these receivables or anypotential refunds ordered by the FERC would not have a material adverse effecton its consolidated financial position, results of operations or cash flows.

**(3)****Pacific Northwest Refund:**  proceedings whereinit was argued that the spot market in the Pacific Northwest was affected by thedysfunction in the California market, warranting refunds.  The FERC rejectedthis claim on June 25, 2003, and denied rehearing on November 11, 2003 andFebruary 9, 2004.  The FERC orders were appealed to the Ninth Circuit.  Oralargument was held on January 8, 2007.  The companies intend to vigorouslydefend their position in this proceeding and believe this matter will not havea material adverse effect on their consolidated financial positions, results ofoperations or cash flows.

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**(4)****Market Manipulation:**  two FERC show causeorders which resulted from a ruling of the Ninth Circuit that the FERC permitthe California parties in the California refund proceeding to submit materialsto the FERC demonstrating market manipulation by various sellers of electricityinto California.  On June 25, 2003, the FERC ordered a large number of partiesincluding IPC to show cause why certain trading practices did not constitutegaming ("gaming") or anomalous market behavior ("partnership") in violation ofthe Cal ISO and CalPX Tariffs.  On October 16, 2003, IPC reached agreement withthe FERC Staff on the show cause orders.  The "gaming" settlement was approvedby the FERC on March 3, 2004.  The FERC approved the motion to dismiss the "partnership"proceeding on January 23, 2004.  Although the orders establishing the scope ofthe show cause proceedings are presently the subject of review petitions in theNinth Circuit, the order dismissing IPC from the "partnership" proceedings wasnot the subject of rehearing requests.  Originally, eight parties requestedrehearing of the FERC's March 3, 2004 order approving the "gaming" settlement. The settlement between the California Parties and IE and IPC discussed above inthe California refund proceeding approved by the FERC on May 22, 2006, resultsin the California Parties and other settling parties withdrawing their requestsfor rehearing of IPC's and IE's settlement with the FERC Staff regardingallegations of "gaming".  On October 11, 2006, the FERC issued an order denyingrehearing of its earlier approval of the "gaming" allegations, therebyeffectively terminating the FERC investigations as to IPC and IE regardingbidding behavior, physical withholding of power and "gaming" without finding ofwrongdoing.  On October 24, 2006, the Port of Seattle appealed the FERC orderto the U.S. Court of Appeals for the Ninth Circuit.

In additionto the two show cause orders, on June 25, 2003, the FERC also issued an orderinstituting an investigation of anomalous bidding behavior and practices in thewestern wholesale markets for the time period May 1, 2000 through October 1,2000 to review evidence of economic withholding of generation.  IPC, along withover 60 other market participants, responded to the FERC data requests and theFERC terminated its investigations as to IPC on May 12, 2004.  Numerous partieshave appealed the FERC's termination of this investigation as to IPC and over30 other market participants.

**Sierra Club Lawsuit-Bridger: **In February 2007, theSierra Club and the Wyoming Outdoor Council filed a complaint againstPacifiCorp in federal district court in Cheyenne, Wyoming for allegedviolations of the Clean Air Act's opacity standards (alleged violations of airpollution permit emission limits) at the Jim Bridger coal fired plant ("Plant")in Sweetwater County, Wyoming.  IPC has a one-third ownership interest in thePlant.  PacifiCorp owns a two-thirds interest and is the operator of thePlant.  The complaint alleges thousands of violations and seeks declaratory andinjunctive relief and civil penalties of $32,500 per day per violation as wellas costs of litigation, including reasonable attorney fees.  IPC believes thereare a number of defenses to the claims and intends to vigorously defend itsinterest in this matter, but is unable to predict its outcome and is unable toestimate the impact this may have on its consolidated financial positions,results of operations or cash flows.

These matters are alsodiscussed in Note 7 to IDACORP's and IPC's Consolidated Financial Statements.

**Other Legal Proceedings:**  IDACORP, IPC and/or IE are involved in lawsuits andlegal proceedings in addition to those discussed above and in Note 7 to IDACORP'sand IPC's Consolidated Financial Statements.  The companies believe they havemeritorious defenses to all lawsuits and legal proceedings where they have beennamed as defendants.  Resolution of any of these matters will take time, andthe companies cannot predict the outcome of any of these proceedings.  Thecompanies believe that their reserves are adequate for these matters.

**Other Matters: **The Bennett Mountain combustion turbine suffered amechanical failure on July 11, 2006.  IPC's investigation has revealed thatduring construction a bolt was negligently installed by a third party.  Thebolt came loose, causing extensive mechanical damage.  The plant was down fromJuly 12, 2006 through September 6, 2006.  Total repair costs were approximately$16 million.  IPC anticipates that insurance proceeds and/or recovery from theparty or parties responsible for the failure will result in substantialreimbursement of these costs.  Involved insurers and construction contractorshave been notified and cost recovery processes are underway.  At this time, nolegal proceedings have commenced.  IPC is vigorously pursuing its interest inthis matter.****

**Environmental IssuesIdahoWater Management Issues**Idaho experienced six consecutive years of below normal precipitation andstream flows from 2000 through 2005.  These conditions exacerbated a developingwater shortage in the state, which is manifested by a number of water issuesincluding declining Snake River base flows and declining levels in the EasternSnake Plain Aquifer, a large underground aquifer that has been estimated tohold between 200 - 300 maf of water.  These issues are of interest to IPCbecause of their potential impacts on generation at IPC's hydroelectricprojects.  With respect to base flows, observed records suggest that the baseflows in the Snake River, particularly between IPC's Twin Falls and Swan Falls projects, have been in decline for several decades.  The yearly average flowmeasured below Swan Falls declined at an average rate of 43 cubic feet persecond (cfs) per year during the period 1961-2003, and between Twin Falls and Lower Salmon  Falls, which significantly contribute to base flow, declined at a rate ofapproximately 27 cfs per year over the same period.  Low flow in the SnakeRiver near Hagerman, Idaho was observed during 2005, where several river gaugesin that area recorded the lowest January - March Snake River flows since theearly 1960's.

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As a result of these declinesin river flows, in 2003 several surface water users filed delivery calls withthe Idaho Department of Water Resources (IDWR), demanding that it manage groundwater withdrawals pursuant to the prior appropriation doctrine of "first intime is first in right" and curtail junior ground water rights that aredepleting the aquifer and affecting flows to senior surface water rights. These delivery calls have resulted in several administrative actions before theIDWR and judicial actions before the State District Court in Ada and Goodingcounties in Idaho challenging the constitutionality of state regulations usedby the IDWR to conjunctively administer ground and surface water rights.  Onesuch action, filed in January 2005, involves seven surface water irrigationentities from above Milner Dam that submitted a delivery call letter to theDirector of the IDWR requesting that the Director administer and deliver theirsenior natural flow and storage water rights pursuant to Idaho law.  Theirrigation entities contend that existing data reflects that senior surfacewater rights above Milner Dam have been reduced by approximately 600,000acre-feet, a 30 percent reduction, over the past six years, due in part tojunior groundwater pumping from the Eastern Snake Plain Aquifer, and that thesereductions have resulted in cumulative shortages in natural flow and storagewater accrual in American Falls Reservoir, a U.S. Bureau of Reclamationreservoir that supplies a portion of their senior water rights.  The Idaho GroundWater Appropriators, Inc., an Idaho non-profit corporation organized to promoteand represent the interests of groundwater users, and the U.S. Bureau ofReclamation, the owner of American Falls Reservoir, petitioned to intervene inthe delivery call action.  Both petitions were granted.

Since IPC holds water rightsthat are dependent on the Snake River, spring flows and the overall conditionof the Eastern Snake Plain Aquifer, IPC continues to participate in actions, asnecessary, to protect its water rights.  One such action relates to theconstitutionality of the Conjunctive Management Rules (CMR) that were developedby the IDWR to administer connected ground and surface water rights.  In August2005, the surface water irrigation entities that initiated the delivery callfiled an action against the IDWR in the state district court in Gooding County, Idaho for a declaratory judgment regarding the validity andconstitutionality of the CMR.  IPC intervened in the action as aplaintiff/intervenor in alignment with the surface water users.  The IdahoGround Water Appropriators intervened as a defendant.  In October 2005, theplaintiffs in the case filed a motion for summary judgment, contending that theCMR were unconstitutional and violated the doctrine of prior appropriation asapplied in Idaho.  After briefing and argument, on June 2, 2006, the districtcourt issued a memorandum decision granting summary judgment to the plaintiffsand holding that the CMR are unconstitutional because the rules failed to protectsenior water rights from injury by junior water right diversions.  On July 11,2006, the IDWR appealed the court's order to the Idaho Supreme Court andsubsequently filed a motion with the district court asking the court to staythe effect of its order until the conclusion of the appeal.  IPC isparticipating in the appeal.  On September 27, 2006, the Idaho Supreme Courtentered an order denying the stay and expediting the appeal.  Oral argument washeld on December 8, 2006 and the parties are currently waiting for the court'sdecision. 

IPC, together with otherinterested water users and state interests, also continues to explore andencourage the development of a long-term management plan that will protect theaquifer and the river from further depletion.  One management option beingexplored is aquifer recharge, or using surface water supplies to increaseground water supplies by allowing the water to percolate into the aquifer inporous locations.  Under certain circumstances aquifer recharge may impactsenior water rights, including water rights held by IPC for hydropowerpurposes, and therefore conflict with state law.  For that reason, IPCcontinues to participate in the processes that are considering solutions, suchas aquifer recharge, to the conflict between ground and surface water interestsin an effort to protect its existing hydroelectric generation water rights.

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In February 2006, at therequest of senior surface water interests, IPC entered into discussions withthe State of Idaho, through the Office of the Governor, and senior surfacewater interests to explore opportunities for engaging in some limited aquiferrecharge in 2006, provided any adverse impact to IPC's hydropower generationand its customers was adequately addressed.  These discussions led to aproposal to implement a recharge pilot program in 2006.  However, before thatproposal could be finalized, on March 17, 2006, the House of Representatives ofthe State of Idaho passed House Bill 800, which proposed to repeal certain provisionsof the Idaho Code that governed the use of natural water flow to recharge theEastern Snake Plain Aquifer and would have subordinated certain hydropowerwater rights held by IPC to aquifer recharge.  The introduction of House Bill800 effectively concluded the discussions between IPC, senior surface waterinterests and the Governor's Office to implement a pilot recharge project.IPC strongly opposed House Bill 800 because, if it had become law, IPC'shydroelectric generation could have been reduced and IPC would have had to relyon more expensive generation or purchased power to meet customers' needs.  Thiswould have resulted in higher costs to IPC's customers.  On March 30, 2006, theSenate defeated House Bill 800 by a vote of 21 to 14.

At the conclusion of thelegislative session, the Senate passed Senate Concurrent Resolution 136directing the Idaho Water Resource Board (IWRB) to develop a comprehensiveaquifer management plan for the Eastern Snake Plain Aquifer (ESPA) and toreceive public input regarding the goals, objectives, and methods of managementfor the ESPA from affected water right holders, cities, counties, the generalpublic and state and federal agencies.  The IWRB initiated a public process forthe development of an aquifer management plan in June 2006.  IPC isparticipating in that process.  The IWRB is expected to report to the IdahoLegislature in 2007 on the progress of the planning effort.

On April 11, 2006, IPC andthe State of Idaho entered into a stipulation agreement regarding two waterright permits.  The permits allow for limited aquifer recharge and are held bythe IWRB.  The two water right permits were issued in the early 1980's, priorto the 1984 Swan Falls Agreement.  IPC entered into the Swan Falls Agreementwith the Governor and Attorney General of Idaho in October 1984 to resolvelitigation relating to IPC's water rights at the Swan Falls project.  In theearly 1980's, IPC filed an action identifying approximately 7,500 waterlicenses and permits that had the potential to adversely impact IPC'shydropower water rights at the Swan Falls project.  The Swan Falls Agreementresolved that litigation.  One provision of the Swan Falls Agreement providedthat the action against the 7,500 water licenses and permits would be dismissedwith prejudice and that IPC's hydropower water rights on the middle Snake Riverwould be subordinate to those water rights dismissed.  In the stipulation, IPCand the state recognized that the two water right permits referred to abovewere named in the action brought by IPC and were subject to the Swan FallsAgreement and that IPC's water rights are therefore subordinate to these waterright permits.  IPC cannot determine the financial impact of the stipulationupon IPC and its customers until such time, if ever, that recharge programsunder the two water permits are established, but IPC believes that thepotential maximum impact in a median water year may be approximately $30million.

The stipulation also providedthat, in the event that there are disagreements between the parties to the SwanFalls Agreement as to the interpretation or application of the Agreement, theparties will attempt to resolve those disagreements through informaldiscussions and negotiations and that in the event that the parties are unableto resolve such disagreements, either party may file a declaratory action witha court of appropriate jurisdiction to have the disagreement resolved.  OnDecember 22, 2006, the State of Idaho, through the Attorney General's office,filed a notice of claim of ownership with the IDWR for a portion of the waterrights held by IPC that are subject to the Swan Falls Agreement.  Subsequently,IDWR filed a Director's Report with the Snake River Basin Adjudication (SRBA)court incorporating the State's claim of ownership and recommending that theSRBA court decree IPC's water rights in a manner consistent with the State'sclaim.  IPC disputes the State's claim of ownership and intends to file anobjection to the IDWR recommendation.  Objections must be filed with the SRBAcourt by April 2008.  IPC is currently reviewing the State's ownership claim todetermine the potential effect upon IPC's water rights and whether it mayaffect power generation.

**Air Quality Issues**IPC owns two natural gas combustionturbine power plants and co-owns three coal-fired power plants that are subjectto air quality regulation.  The natural gas-fired plants, Danskin and Bennett Mountain, are located in Idaho.  The coal-fired plants are:  Jim Bridger (33 percentinterest) located in Wyoming; Boardman (ten percent interest) located in Oregon; and North Valmy (50 percent interest) located in Nevada.

**Clean Air:**The Environmental Protection Agency (EPA) issuedsulfur dioxide (SO2) allowances, as defined in the Clean Air Act amendmentsof 1990, based on coal consumption during established baseline years.  IPCcurrently has more than a sufficient amount of SO2 allowances toprovide compliance for emissions attributable to IPC at all three of itsjointly-owned coal-fired facilities and both of its natural gas-firedfacilities.

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In July 1997, the EPAannounced the revised National Ambient Air Quality Standards (NAAQS) for ozoneand particulate matter.  The EPA has promulgated regulations designating areasof the country for attainment/non-attainment with these standards and IPC'sthermal plants are currently located in areas designated as attainment for bothstandards.  On September 21, 2006, the EPA adopted a final rule which loweredthe 24-hour PM2.5 (Particulate Matter less than 2.5 microns)standard to 35 micrograms per cubic meter.  States must make their initialrecommendations to the EPA on attainment and non-attainment designations byDecember 2007.  However, final designations need not be signed untilDecember 2009 and do not take effect until April 2010.  IPC continues tomonitor the status of efforts to implement the new PM2.5 standardand the designation of areas around its thermal plants.  Although the impactsof the NAAQS for ozone and particulate matter standards on IPC's thermaloperations are not known at this time, the future costs of compliance withthese regulations could be substantial and will be dependent on if and how theprograms are ultimately implemented.

The Clean Air Interstate Rule(CAIR) will cap emissions of SO2 and nitrogen oxides in 28 easternstates and the District of Columbia.  The CAIR does not impose any restrictionson emissions from any IPC facilities and, therefore, IPC does not foresee anyadverse effects upon its operations as a result of CAIR.

**Clean Air Mercury Rule:**The Clean Air Mercury Rule (CAMR) will limit mercuryemissions from new and existing coal-fired power plants and creates amarket-based cap-and-trade program that will permanently cap utility mercuryemissions in two phases (2010 - 2017, and 2018 and beyond).  Mercury emissionallocations have been set at the state level, but the states are currentlyworking to allocate the allowances to individual power plants.  States haduntil November 17, 2006, to submit to the EPA mercury plans establishingmercury emission standards and allowances for the power plants within theirjurisdictions.  Mercury continuous emission monitoring systems (CEMS) arerequired to be installed and operational on each coal-fired unit by January 1,2009.  IPC is actively monitoring developments on state mercury plans in Idaho, Wyoming, Nevada, and Oregon.

On October 10, 2006, theWyoming Environmental Quality Commission approved the Wyoming Department ofEnvironmental Quality's (WDEQ) recommended Wyoming regulation to implementCAMR.  This rule will allocate mercury allowances to each plant based onheat-input and hold back 10 percent of the allocated allowances for newsources.  This rule will also allow plants to participate in the nationalcap-and-trade program.  Mercury CEMS are planned to be installed at the JimBridger plant in 2007 and 2008 at an estimated cost of $0.7 million (IPCshare).  Until the mercury CEMS are installed and operational, the amount ofmercury emissions is not definitively known.  It is not possible at this timeto determine the effect of the allowance allocation rule on future operationsand costs at the plant.

On December 15, 2006, theOregon Environmental Quality Commission (OEQC) adopted the Oregon Department ofEnvironmental Quality proposed utility mercury rule.  IPC estimates thatcapital expenditures for mercury controls at Boardman will be $9.2 million (IPC'sshare) with an annual incremental operations and maintenance cost of up to $0.8million (IPC's share).  The mercury rule will provide a limited number ofmercury allowances to Boardman that may be used for trading. 

The Nevada Department ofEnvironmental Protection has adopted a state CAMR that will provide mercuryallowances to each plant based on actual emissions until 2018, at which timethe allowance allocations will be reduced to meet the federal cap.  To meet thereduced allocations in the year 2018, mercury controls are expected to beinstalled.  Mercury CEMS are planned to be installed at the North Valmy plantin 2007 and 2008 at an estimated cost of $0.4 million (IPC's share).

IPC anticipates that the CAMRwill require additional emission controls and expenses at all of itsjointly-owned coal-fired facilities, although impacts on future plantoperations, operating costs and generating capacity are not known at this time.

The Idaho Board ofEnvironmental Quality has adopted two new rules: a proposed rule to opt out ofthe federal mercury cap-and-trade program; and a proposed rule to prohibit theconstruction and operation of a coal-fired power plant in Idaho.  The ruleswill be sent to the Idaho Legislature for review and approval during its 2007session.

**Regional Haze - BestAvailable Retrofit Technology:** Inaccordance with new federal regional haze rules, the WDEQ and ODEQ areconducting an assessment of emission sources pursuant to a Regional Haze BestAvailable Retrofit Technology (RH BART) process.  Coal-fired utility boilersare subject to RH BART if they were built between 1962 and 1977 and affect anyClass I areas.  This includes all four units at the Jim Bridger and Boardmanplants.  The two units at the North Valmy plant were constructed after 1977 andare not subject to the federal regional haze rule.

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On December 5, 2006, the WDEQadopted regulations to comply with the federal RH BART standard and the JimBridger plant submitted required reports to the WDEQ on January 12, 2007.  TheWDEQ will perform a review, including a comment period, and revise the StateImplementation Plan, which is to be provided to the EPA by March 2008.  Duringthe acquisition of PacifiCorp by MidAmerican Energy Holdings Company (MEHC),MEHC committed to install additional pollution control equipment at most ofPacifiCorp's facilities.  This commitment includes SO3 injection,additional low NOx burners and scrubber upgrades at the Jim Bridger plant. Over the next three years, upgrade expenditures are currently estimated at $9million (IPC's share), with total project costs currently estimated at $15million (IPC's share).

In Oregon, a demonstrationanalysis for identified haze sources, utilizing modeling techniques, began in2006 and is currently in progress.  Those sources which are determined to causeor contribute to visibility impairment at protected areas will be subject to anRH BART determination.  In January 2006, IPC volunteered to participate in anODEQ pilot project that will analyze information about air emissions from theBoardman plant to determine the effect on visibility in the region,particularly in wilderness and scenic areas.  The pilot project is expected tobe completed by the end of the second quarter of 2007.

**Greenhouse Gases:**IPC continues to monitor and evaluate the possibleadoption of national, regional, or state greenhouse gas (GHG) requirements. Several GHG bills were introduced in the U.S. Senate and House ofRepresentatives during 2006 and 2007.  National, regional or state GHGrequirements, if enacted and applicable, could result in significant costs toIPC to comply with restrictions on carbon dioxide or other GHG emissions.

**Endangered Species**In December 1992, the U.S. Fish andWildlife Service listed several species of fish and five species of snails****living within IPC's operating area as threatened orendangered species under the Endangered Species Act.  IPC continues to reviewand analyze the effect such designation has on its operations and iscooperating with governmental agencies to resolve issues related to thesespecies.

On December 21, 2006, IPC andIdaho Governor James Risch submitted a petition to the U.S. Fish and WildlifeService to de-list the threatened Bliss Rapids snail.  The petition wassupported with data collected by IPC over the past 14 years.  The snail, whichlives throughout the middle Snake River, springs, and tributaries betweenNiagara Springs and King Hill, was listed as threatened under the EndangeredSpecies Act in 1992.  The Fish and Wildlife Service has one year to decide ifde-listing is warranted.  With this filing, three of the five snail speciesthat are found in the middle Snake River and were originally listed asthreatened or endangered species in 1992 are now being considered for removalfrom the list.

Pursuant to FERC License1971, IPC owns and finances the operation of anadromous fish hatcheries andrelated facilities to mitigate the effects of its hydroelectric dams on fishpopulations.  In connection with its fish facilities, IPC sponsors ongoingprograms for the control of fish disease, improvement of fish production, andevaluation of hatchery performance.  IPC's anadromous fish facilities at HellsCanyon, Oxbow, Rapid River, Pahsimeroi and Niagara Springs continue to beoperated by the Idaho Department of Fish and Game.  At December 31, 2006, theinvestment in these facilities was $15 million and the annual cost of operationwas $3 million.

**REGULATORY MATTERS:**

**General Rate Case  Idaho:**On May 12, 2006, the IPUCissued an order approving a settlement of IPC's general rate case filed inOctober 2005.  The order approves an average increase of 3.2 percent in baserates, or $18 million in revenues, effective June 1, 2006.

IPC's original filing hadasked for an annual increase to its Idaho retail base rates of $44 million, a7.8 percent average increase.  The rate case filing was made with six months ofactual operating expenses and six months of projected expenses.  The actualincrease in rates was lower than the requested amount due to three factors: (1) 2005 actual expenses were significantly less than those forecasted; (2) theoverall rate of return agreed to was 8.1 percent compared to the 8.42 percentIPC requested (no specific return on equity was determined); and (3) net powersupply costs were kept at levels currently existing in rates.

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IPC expects to file a newgeneral rate case with the IPUC in 2007.**Oregon****: **On September 21, 2004, IPC filed an application withthe 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 mannerconsistent with the results of the corresponding Idaho general rate case.  Themost significant issue in this proceeding was the appropriate quantification ofnet power supply expenses for purposes of setting rates.  The OPUC Staffproposed 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 allfuel and purchased power expenses and still have revenue left over to offsetother costs.  The bulk of IPC's rebuttal was directed at this position.  Ahearing was conducted on May 23, 2005.  The OPUC issued its order in July 2005authorizing an increase of $0.6 million in annual revenues for an average of2.37 percent.  The OPUC adopted the OPUC Staff's argument for the negative netpower 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, IPCfiled a complaint with the Circuit Court of Marion County, Oregon asking thecourt to reverse the portion of the OPUC's general rate case order related tothe determination of net power supply costs.  Following a full review of thematter, the court denied IPC's reversal request on August 29, 2006.  IPC didnot appeal the decision.

**Deferred Power SupplyCosts**IPC's deferred net power supply costsconsisted of the following at December 31 (in thousands of dollars):

** **

**2006**

** **

**2005**

Idaho PCA current year:

Deferral for the 2006-2007  rate year

$

-

$

3,684

Accrual for the 2007-2008  rate year*

(3,484)

-

Idaho PCA true-up awaiting  recovery:

Authorized May 2005

-

28,567

Authorized May 2006

(11,689)

-

Oregon deferral:

2001 costs

6,670

8,411

2005 costs

2,889

2,880

Total (accrual) deferral

$

(5,614)

$

43,542

*Includes $69 million of  emission allowance sales to be credited to the customers during the 2007-2008  PCA year

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

Thetrue-up of the true-up portion of the PCA provides a tracking of the collectionor the refund of true-up amounts.  Each month, the collection or the refund ofthe true-up amount is quantified based upon the true-up portion of the PCA rateand the consumption of energy by customers.  At the end of the PCA year, thetotal collection or refund is compared to the previously determined amount tobe collected or refunded.  Any difference between authorized amounts andamounts actually collected or refunded are then reflected in the following PCAyear, which becomes the true-up of the true-up.  Over time, the actualcollection or refund of authorized true-up dollars matches the amountsauthorized.

On May 25, 2006, the IPUCapproved 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 existinglevel, which was recovering $76.7 million above then-existing base rates, to alevel that is $46.8 million below those base rates, a decrease of approximately$123.5 million.

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OnJune 1, 2005, IPC implemented the 2005-2006 PCA, which held the PCA componentof customers' rates at the existing level recovering $71 million above baserates.  By IPUC order, the PCA included $12 million in lost revenues and $2million in related interest resulting from IPC's Irrigation Load ReductionProgram 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 helpmitigate the impacts of other rate increases.  The $28 million was included inthe 2006-2007 PCA filing, and IPC earned a two percent carrying charge on thebalance.**Idaho****Load Growth Adjustment Rate (LGAR):**  In April 2006 IPCfiled a petition with the IPUC requesting modification of one component of itsPCA referred to as the Load Growth Adjustment Rate.  The LGAR subtracts thecost of serving new Idaho retail customers from the power supply costs IPC isallowed to include in its PCA.

TheLGAR was set at $16.84 per megawatt-hour when the PCA began in 1993.  Thisamount was established as the projected marginal cost of serving each newcustomer and is subtracted from each year's PCA expense.  In its April 2006petition, IPC requested using the embedded cost of serving the new load ratherthan the projected marginal cost and to lower the rate to $6.81 permegawatt-hour.  The IPUC Staff recommended against changing to the embeddedcost approach; IPUC Staff also recommended increasing the rate to $40.87 permegawatt hour.

OnJanuary 9, 2007, the IPUC issued its final order in this matter.  The IPUC maintainedthe marginal cost methodology and set the new LGAR at $29.41 permegawatt-hour.  The new rate becomes effective on April 1, 2007 and will firstaffect customer rates on June 1, 2008.

Theimpact of the new LGAR on IPC will ultimately be determined by future loadgrowth.  Assuming an average 40 megawatt load growth, the new rate would resultin approximately $10.3 million subtracted from the next PCA, a pre-tax increaseof $4.4 million over the current amount.  The impact of the new LGAR can be partiallyoffset by IPC through more frequent general rate case filings with the IPUC orfrom less customer growth.  In its order the IPUC stated that it expected IPCto update its load growth adjustment in all future general rate cases.

**Oregon****:**  On April28, 2006, IPC filed for an accounting order with the OPUC to defer net powersupply costs for the period of May 1, 2006, through April 30, 2007, inanticipation of higher than "normal" power supply expenses.  In the Oregongeneral rate case discussed above, "normal" power supply expenses were set at anegative number (meaning that under normal water conditions IPC should be ableto sell enough surplus energy to pay for all fuel and purchased power expensesand still have revenue left over to offset other costs).  The forecasted systemnet power supply expenses included in this deferral filing were $64 million,which is $65.9 million higher than the normalized power supply expensesestablished in the Oregon general rate case.  IPC requested authorization to deferan estimated $3.3 million, the Oregon jurisdictional share of the $65.9million.  IPC also requested that it earn its Oregon authorized rate of returnon 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 begannegotiating for a PCA mechanism for IPC's Oregon jurisdiction, and agreed tosuspend discussion of the deferral application while the PCA negotiations areongoing.  The parties believe that any agreement regarding a PCA mechanism mayimpact resolution of IPC's deferral application.  The parties met on November27, 2006.  Further workshops are planned for 2007, but have not yet beenscheduled.

The timing of future recoveryof Oregon power supply cost deferrals is subject to an Oregon statute thatspecifically limits rate amortizations of deferred costs to six percent peryear.  IPC is currently amortizing through rates power supply costs associatedwith the western energy situation of 2001.  Full recovery of the 2001 deferralis not expected until 2009.  A 2006-2007 deferral would have to be amortizedsequentially following the full recovery of the 2001 deferral.

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On March 2, 2005, IPC filedfor an accounting order with the OPUC to defer net power supply costs for theperiod of March 2, 2005 through February 28, 2006, in anticipation of continuedlow water conditions.  The forecasted net power supply costs included in thisfiling were $169 million, of which $3 million related to the Oregonjurisdiction.  IPC proposed to use the same methodology for this deferralfiling that was accepted in 2002 for Oregon's share of IPC's 2001 net powersupply expenses.  On July 1, 2005, IPC, the OPUC Staff, and the Citizen'sUtility Board entered into a stipulation requesting that the OPUC accept IPC'sproposed methodology.  Under this methodology, IPC will earn its Oregon authorized rate of return on the deferred balance and will recover the amountthrough rates in future years, as approved by the OPUC.  The OPUC issued Order05-870 on July 28, 2005, approving the stipulation.  On April 19, 2006, IPCfiled a request for review and acknowledgement of its deferred net power supplycosts for the period of March 2, 2005, through February 28, 2006.  On June 14,2006, a settlement conference was held.  On December 14, 2006, IPC responded toadditional data requests by the OPUC.  The OPUC Staff subsequently drafted asettlement stipulation under which the parties agree that IPC appropriatelydeferred approximately $2.7 million during the 2005 deferral period.  Thestipulation also provides that, rather than amortizing the 2005 deferral intorates, IPC should offset the balance with the Oregon jurisdictional share ofproceeds from the sale of SO2 emission allowances and the benefitthat IPC will receive from income taxes already paid on the sale of thoseallowances.  When combined, these offsets exceed the 2005 deferral balance. The stipulation was filed with the OPUC on January 31, 2007.  A final order isexpected from the OPUC during the first quarter of 2007.

**Emission Allowances**In June 2005, IPC filed applicationswith the IPUC and OPUC requesting blanket authorization for the sale of excessSO2 emission allowances and an accounting order.  The IPUC issuedOrder 29852 on August 22, 2005, authorizing the sale and interim accountingtreatment.  The OPUC issued Order 05-983 on September 13, 2005, stating thatIPC did not need a blanket order to sell emission allowances and approved theinterim accounting treatment.

In 2005 and early 2006, IPCsold 78,000 SO2 emission allowances for approximately $81.6 million(before income taxes and expenses) on the open market.  After subtractingtransaction 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 taxrate of approximately 39 percent).  Through allowance year 2006, IPC hasapproximately 36,000 excess allowances.

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 ofseveral parties.  The stipulation allows IPC to retain ten percent, orapproximately $4.7 million after tax, of the emission allowance net proceeds asa shareholder benefit.  The remaining 90 percent of the sales proceeds ($69.1million) plus a carrying charge will be recorded as a customer benefit andincluded as a line-item in the PCA true-up.  The carrying charge will becalculated on $42.1 million, the net-of-tax amount allocable to Idaho jurisdiction customers.  This customer benefit is included in IPC's PCA calculationsas a credit to the PCA true-up balance and will be reflected in PCA ratesduring the June 1, 2007 through May 31, 2008 PCA rate year.

As discussed above, astipulation is currently before the OPUC which would offset SO2emission allowance proceeds against the 2005-2006 balance of Oregon deferredpower supply cost.  The stipulation allows for IPC to retain ten percent of theproceeds from emission allowance sales as a shareholder benefit.

**Fixed Cost AdjustmentMechanism (FCA)**On January 27, 2006, IPC filed with the IPUC for authority to implement a rateadjustment mechanism that would adjust rates downward or upward to recoverfixed costs independent from the volume of IPC's energy sales.  This filing isa continuation of a 2004 case that was opened to investigate the financialdisincentives to investment in energy efficiency by IPC.  This true-upmechanism would be applicable only to residential and small general servicecustomers.  The first FCA rate change under this proposal would occur on June1, 2007, coincident with IPC's PCA rate change.  The accounting for the FCAwill be separate from the PCA.  As part of the filing, IPC proposes a threepercent cap on any rate increase to be applied at the discretion of the IPUC.

On March 6, 2006, the IPUCreviewed IPC's proposal and acknowledged the intent of IPC and the IPUC Staffto initiate and engage in settlement discussions.  The IPUC Staff presented analternate view of IPC's proposal.  Three workshops were held in 2006 and the parties have agreed in concept to a three-yearpilot beginning at the first of the year and a stipulation was filed onDecember 18, 2006.  The stipulation calls for the implementation of a FCAmechanism pilot program as proposed by IPC in its original application withadditional conditions and provisions related to customer count and weathernormalization methodology, recording of the FCA deferral amount in reports tothe IPUC and detailed reporting of DSM activities.  The pilot program began onJanuary 1, 2007, and will run through 2009, with the first rate adjustment tooccur on June 1, 2008, and subsequent rate adjustments to occur on June 1 ofeach year thereafter during the term of the pilot program.  The deadline forfiling written comments with respect to the stipulation and the use of modifiedprocedure was January 31, 2007.  A final order is expected from the IPUC in thefirst quarter of 2007.

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**FERC ProceedingsOpen Access Transmission Tariff (OATT):** On March 24, 2006, IPC submitted a revised OATT filing with the FERC requestingan increase in transmission rates.  The purpose of the filing was to implementformula rates for the IPC OATT in order to more adequately reflect the coststhat IPC incurs in providing transmission service.  In the filing IPC proposedto move from a fixed rate to a formula rate, which allows for transmissionrates to be updated each year based on FERC Form 1 data.  The formula rate requestincluded a rate of return on equity of 11.25 percent.  The proposed rates wouldhave produced an annual revenue increase of approximately $13 million based on2004 test year data.  On May 31, 2006, the FERC accepted IPC's rates, effectiveJune 1, 2006, subject to adjustment to conform to FASB 109 tax accountingrequirements, which ultimately resulted in lowering the estimated annualrevenues to approximately $11 million.  IPC has complied with this directiveand on August 28, 2006, the FERC issued an order accepting IPC's compliancefiling and ordering that this new rate be used, subject to refund as discussedbelow.  As a result, IPC has made refunds with interest for June and Julyamounts billed, and started billing the new rate beginning in August.  Therates are being collected subject to refund pending the outcome of the FERChearing process scheduled for May 2007 with an initial decision expected to beissued in August 2007.

On November 6, 2006,intervenors filed a motion for partial summary disposition on the issue of howa pre-1996 contract with another utility was treated in the rate calculation. On December 5, 2006, oral argument was heard by the FERC administrative lawjudge (ALJ).  On December 15, 2006, the ALJ denied the intervenors' motion forpartial summary judgment.  IPC is currently preparing rebuttal testimony inthis case.

**FERC Order 890: **On February 16, 2007, the FERC adopted a final ruleamending the regulations governing its pro forma OATT.  According to the FERC,the purpose of the amendment is to remedy undue discrimination by providinggreater specificity in the pro forma OATT and increasing transparency in therules applicable to planning and the use of the transmission system.  The majorreforms to the pro forma OATT relate to: (i) the development of more consistentmethodologies and assumptions for calculating available transfer capability(ATC), (ii) more open, coordinated and transparent transmission planning, (iii)reform of the energy and generator imbalances penalties based on a tieredstructure, (iv) adoption of a "conditional firm" component to long-termpoint-to-point service requiring transmission providers to identify systemconditions, as well as reform of the redispatch service and (v) reform of therollover rights policy.  IPC, as a transmission service provider with an OATTon file with the FERC, will be required to comply with these requirements. Certain requirements provided under the final rule, such as the methodologyapplicable to calculating the ATC, will be determined prospectively and make itdifficult at this time to determine the effect of the final rule.  However,IDACORP and IPC believe that the final rule will not have a material adverseeffect on their consolidated financial positions, results of operations or cashflows.

**CassiaWind Farm Complaint**On September 13, 2006, Cassia GulchWind Park, LLC and Cassia Wind Farm, LLC (collectively Cassia) filed acomplaint against IPC with the IPUC requesting an IPUC declaration anddetermination that, as a matter of law and policy, the cost responsibility forspecified transmission system upgrades to meet contingency planning conditionsshould not be assigned to PURPA qualifying facilities connecting to the system,but rather should be rolled into IPC's plant-in-service rate base and recoveredthrough rates to retail and transmission customers.  The estimated costs oftransmission system upgrades included in this complaint that relate toconnecting Cassia to IPC's system are $60 million.  Cassia requested that theIPUC process its request for an order under modified procedure.  The IPUC Staffcontends that the policy issue raised by Cassia is one of generic consequenceand has, therefore, provided copies of Cassia's complaint to both PacifiCorpand Avista and recommended that those utilities also be provided theopportunity to address the issue raised by Cassia.  Initial comments were dueOctober 27, 2006 and reply comments were due November 9, 2006.  On November 17,2006 the IPUC granted Cassia's request for oral argument on the threshold issuepresented for IPUC determination by Cassia, i.e., whether a PURPA qualifyingfacility selling generation to a utility has a responsibility to pay thetransmission upgrade costs that result from, and that would not be incurred butfor, the facility's request for interconnection.  Oral arguments were heldNovember 28, 2006.

**Public Utility RegulatoryPolicies Act of 1978**As mandated by the enactment of PURPA and the adoption of avoided cost rates bythe IPUC and the OPUC, IPC has entered into contracts for the purchase ofenergy from a number of private developers.  Under these contracts, IPC isrequired to purchase all of the output from the facilities located inside theIPC service territory.  For projects located outside the IPC service territory,IPC is required to purchase the output that IPC has the ability to receive atthe facility's requested point of delivery on the IPC system.  The IPUCjurisdictional portion of the costs associated with cogeneration and small powerproduction (CSPP) contracts are fully recovered through the PCA.  For IPUCjurisdictional contracts, projects that generate up to ten average MW of energyon a monthly basis are eligible for IPUC Published Avoided Costs for up to a20-year contract term.  The Published Avoided Cost is a price established bythe IPUC and the OPUC to estimate IPC's cost of developing additionalgeneration resources.  On August 4, 2005, the IPUC granted a temporaryreduction in the eligible project size to 100 kW for intermittent generationresources only and ordered IPC to study the impacts of integrating this type ofresource.  IPC completed and filed with the IPUC a wind generation integrationstudy report on February 6, 2007.  The IPUC will evaluate the proposal, possiblyincluding public workshops, and issue a ruling.

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For OPUC jurisdictionalcontracts, projects with a nameplate rating of up to ten MW of capacity areeligible for OPUC Published Avoided Costs for up to a 20-year contract term. The OPUC jurisdictional portion of the costs associated with CSPP contracts isrecovered through general rate case filings.  The Oregon provisions arecurrently being reviewed in an OPUC proceeding.  If a PURPA project does notqualify for Published Avoided Costs, then IPC is required to negotiate theterms, prices and conditions with the developer of that project.  Thesenegotiations reflect the characteristics of the individual projects (i.e.,operational flexibility, location and size) and the benefits to the IPC systemand must be consistent with other similar energy alternatives.

Recent activities, includingthe extension of the Federal Production Tax Credit and the expansion of the taxcredit for eligibility to solar, geothermal and other forms of generation,resolution of IPUC and OPUC PURPA-related hearings and the December 1, 2004order by the IPUC increasing the Published Avoided Costs, create a favorableclimate for PURPA project development, which may require IPC to enter intoadditional PURPA agreements.  The requirement to enter into additional PURPAagreements may result in IPC acquiring energy at above wholesale market prices,thus increasing costs to its customers.  Additionally, it is highly likely thatthe requirement to enter into additional PURPA agreements will add to IPC'ssurplus during certain times of the year.  This could also increase costs toIPC's customers.  As of December 31, 2006, IPC had signed agreements topurchase energy from 92 CSPP facilities with contracts ranging from one to 30years.  Of these facilities, 74 were on-line at the end of 2006; the other 18facilities under contract are due to come on-line in 2007 and 2008.  During2006, IPC purchased 911,132 MWh from these projects at a cost of $54 million,resulting in a blended price of 5.9 cents per kilowatt hour.

**Integrated Resource Plan: **IPC filed its 2006 IRP with the IPUCin September 2006 and with the OPUC in October 2006.  A hearing is scheduled in  Oregon for June 2007.  The 2006 IRP previewed IPC's load and resourcesituation for the next twenty years, analyzed potential supply-side anddemand-side options and identified near-term and long-term actions.  The twoprimary goals of the 2006 IRP were to: (1) identify sufficient resources toreliably serve the growing demand for energy service within IPC's service areathroughout the 20-year planning period and (2) ensure that the portfolio ofresources selected balances cost, risk and environmental concerns.  Inaddition, there were four secondary goals: (1) to give equal and balancedtreatment to both supply-side resources and demand-side measures, (2) toinvolve the public in the planning process in a meaningful way, (3) exploretransmission alternatives, and (4) investigate and evaluate advanced coaltechnologies.

The IRP is filed every two yearswith both the IPUC and the OPUC.  IPC's IRP process utilizes an AdvisoryCouncil consisting of representatives from the IPUC Staff, OPUC Staff, as wellas representatives from customer, governmental, environmental and otherinterested groups and is the starting point for demonstrating prudence in IPC'sresource decisions.  The 20-year 2006 IRP includes the following supply-sideresources:

Year

Resource

MW

2008

Wind (2005 RFP)

100

2009

Geothermal (2006 RFP)

50

2010

Combined Heat & Power

50

2012

Wind

150

2012

Transmission Capacity

225

2013

Pulverized Coal

250

2017

Regional Integrated  Gasification Combined-Cycle Coal

250

2019

Transmission Capacity

60

2020

Combined Heat & Power

100

2021

Geothermal

50

2022

Geothermal

50

2023

Nuclear1

250

 

1The 250 MW of nuclear generation is anticipated to beacquired through a power purchase agreement for output from the Idaho NationalLaboratory's planned Next Generation Nuclear Project.

IPC has negotiated a PowerPurchase Agreement with the successful bidder on the 100 MW wind RFP (see "WindRFP" below).  An RFP for geothermal-powered generation was released on June 2,2006.  IPC is in the process of evaluating bids and expects to identify asuccessful bidder during the first quarter of 2007.

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Inaddition to the supply-side resources identified above, the 2006 IRP alsoincludes demand-side programs designed to reduce average energy needs by 88 MWand peak-hour needs by 187 MW.  To reach these totals, existing demand-sideprograms will be expanded and new programs will be implemented over the 20-yearplanning period.

**Coal-fired ResourceScreening and Evaluation: **In the2006 IRP, IPC identified the need for a coal-fired resource beginning in 2013. As a result of discussions with potential resource participants, IPC andSpokane, Washington-based Avista Utilities entered into an agreement to jointlyinvestigate possible future coal-fired resources.  Under the arrangement, theutilities are studying the options for base load coal-fired generation to meettheir collective IRP forecast needs.  Information submittals from interestedparties were received in October 2006 and IPC and Avista are currently in theprocess of evaluating and screening potential projects.  In addition, IPCcontinues to evaluate other coal-fired resource opportunities, includingexpansion of its jointly-owned facilities.

**Wind RFP (Elkhorn Wind Project):**  A contract with TelocasetWind Power Partners, LLC, a subsidiary of Horizon Wind Energy, for 100 MW(nameplate) of wind generation from the Elkhorn Wind Project was signed andfiled with the IPUC on December 15, 2006.  IPC requested the costs associatedwith the Elkhorn Project be included in IPC's annual PCA.  The IPUC approvedthe application on February 27, 2007.

**Peaking Resource: **On December 15, 2006, IPC received a Certificate ofConvenience and Necessity to construct a turnkey Siemens Power Generationcombustion turbine at the Evander Andrews Power Complex near Mountain Home, Idaho.  The Certificate of Convenience and Necessity included a commitment estimate of $60million and approval for IPC to include in rate base the prudent capital costsfor construction and operating fuel costs.  The turbine will provideapproximately 166 MW of capacity during summer load peaks and up to 200 MW duringthe winter.  Commercial operation is planned for spring 2008.  Relatedtransmission interconnection and line upgrades will be constructed by IPC at anestimated cost of $23 million.

**IPUC Review of New PURPAStandards**The IPUC initiated a project in June2006 to assess implementation of the Energy Policy Act of 2005.  The 2005 Actamended the Public Utility Regulatory Policies Act of 1978 and added five newfederal ratemaking standards for public utilities and requires state regulatorycommissions to determine whether they should adopt the standards for publicutilities in their jurisdictions.  The five new standards relate to netmetering; fuel source diversity; fossil fuel generation efficiency; time-basedmetering and communication; and interconnection services to customers withon-site generating facilities.  In July 2006, the IPUC requested that eachutility respond to questions about the proposed standards.  A public workshopwas held in September 2006.  After evaluating the responses, the IPUC determinedthat, with the exception of time-based metering, all of the standards hadalready been adopted.  The IPUC declined to adopt the time-based meteringstandard.

**Relicensing ofHydroelectric Projects**IPC, like other utilities thatoperate nonfederal hydroelectric projects on qualified waterways, obtainslicenses for its hydroelectric projects from the FERC.  These licenses last for30 to 50 years depending on the size, complexity, and cost of the project.  IPCis actively pursuing the relicensing of the Hells Canyon Complex and Swan Falls projects, a process that may continue for the next ten to fifteen years.  IPC'sMiddle Snake River project licenses were issued in 2004.

**Hells Canyon****Complex:** Themost significant ongoing relicensing effort is the Hells Canyon Complex (HCC),which provides approximately two-thirds of IPC's hydroelectric generatingcapacity and 40 percent of its total generating capacity.  The current licensefor the HCC expired at the end of July 2005.  Until the new multi-year license isissued, IPC will operate the project under an annual license issued by theFERC.  IPC developed the license application for the HCC through acollaborative process involving representatives of state and federal agenciesand business, environmental, tribal, customer, local government and locallandowner interests.  The license application was filed in July 2003 andaccepted by the FERC for filing in December 2003.

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OnOctober 28, 2005, the FERC issued its Notice of Ready for EnvironmentalAnalysis, which requires the federal and state agencies, Native American tribesand other participants in the relicensing process to file preliminary comments,recommendations, terms, conditions and prescriptions under the FPA, theNational Environmental Policy Act of 1969, as amended (NEPA), the Energy PolicyAct and other applicable federal laws.  NEPA requires that the FERCindependently evaluate the environmental effects of relicensing the HCC asproposed under the final license application (the proposed action) and alsoconsider reasonable alternatives to the proposed action.  Consistent with therequirements of NEPA, the FERC Staff will prepare an environmental impactstatement (EIS) for the Hells Canyon project, which the FERC will use todetermine whether, and under what conditions, to issue a new license for theproject.  The EIS will describe and evaluate the probable effects, if any, ofthe proposed action and the other alternatives considered.  Section 241 of theEnergy Policy Act modifies the existing hydroelectric relicensing process underthe FPA and requires federal resource agencies with authority to imposemandatory conditions on licenses under Sections 4(e) or 18 of the FPA(conditions that the FERC must include in the license) to provide licenseapplicants, and other parties to the licensing process, with evidentiaryhearings on disputed issues of material fact related to proposed conditions. It also requires that such agencies accept more cost effective alternativeconditions proposed by license applicants, or other parties, provided that theproposed alternative conditions will be no less protective of the resource orthe reservation than the original condition recommended by the agency.The federal and state agencies, Native American tribes and other interestedparties filed their preliminary comments, recommendations, terms, conditionsand prescriptions with the FERC on January 26, 2006.  Consistent with theprovisions of the FPA, IPC filed reply comments to these filings on April 11,2006.  Federal agencies with mandatory conditioning authority under sections4(e) and 18 of the FPA also filed their preliminary terms and conditions underthose sections with the FERC on January 26, 2006.  The Energy Policy Act, andthe interim final rules issued on November 17, 2005, to implement the Act,require IPC, within 30 days of the agency's filing of their preliminary termsand conditions with the FERC, to file requests for evidentiary hearings ondisputed issues of material fact relied upon by the federal agency for supportof any term or condition and also file any proposed alternative conditions.  OnFebruary 27, 2006, IPC filed requests for hearing on Section 4(e) conditionsfiled by the Department of the Interior through the Bureau of Land Management(BLM) and the Department of Agriculture through the U. S. Forest Service(USFS).  IPC also filed proposed alternative conditions with the agencies.  Thehearing requests related to travel and access management, law enforcement andemergency services, and recreation and land management conditions proposed bythe BLM, and sediment supply and sandbar maintenance and restoration, wildlifehabitat mitigation and management, noxious weed control, recreation resourcemanagement, and cultural resource management conditions filed by the USFS.  Eachof the agencies responded to the hearing requests and referred the requests tothe hearings division within the respective agencies for assignment to an ALJ. Hearings were subsequently set before a Department of Interior ALJ for June 12,2006, on the requests for hearing on the BLM conditions and a Department ofAgriculture ALJ for June 19, 2006, on the USFS requests for hearing.  While IPCwas preparing for the evidentiary hearings, IPC continued to engage indiscussions with the respective agencies regarding possible settlements.

Through these discussions,IPC was able to resolve the disputed issues associated with the pending hearingrequests.  On May 10, 2006, IPC and the USFS filed a stipulation with theDepartment of Agriculture ALJ, and revised preliminary terms and conditionswith the FERC, resolving all issues associated with the pending USFS hearingrequests except for the issues associated with the USFS condition relating tosediment supply and sandbar maintenance.  These issues remained subject tohearing on June 19, 2006.  On May 15, 2006, IPC and the BLM filed a stipulationwith the Department of Interior ALJ and revised preliminary terms andconditions with the FERC resolving all issues associated with the pending BLM hearingrequests.  Through subsequent settlement discussions with the USFS, IPCresolved all disputed issues associated with the hearing request on the USFScondition relating to sediment supply and sandbar maintenance.

All of these hearing requestswere resolved through stipulations between IPC and the USFS and BLM,respectively, providing for the withdrawal of IPC's requests for hearing andthe filing of revised preliminary terms and conditions with the FERC withprovisions that were acceptable to IPC.

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OnJuly 28, 2006, the FERC released the draft EIS, and comments were due November3, 2006.  The draft EIS is prepared by the FERC Staff, pursuant to NEPA andapplicable federal regulations, to inform the FERC Commissioners, the public,state and federal agencies and the tribes about the potential adverse andbeneficial environmental effects of licensing of the project as proposed by theIPC in its license application and provide a review of other reasonablealternatives or measures that might be included in a license for the project.  Basedupon the draft EIS, the subsequent comments received, the license applicationand other material in the FERC record, the FERC Commissioners will decidewhether to license the HCC and what conditions to include in the license toaddress project effects.  However, because this is a draft EIS, containing onlyFERC Staff conclusions, it cannot be relied upon to accurately predict whatmeasures will be included in the final EIS or the outcome of the relicensingprocess.****In connection with the issuance of the draft EIS, the FERC held publicmeetings in Boise, Weiser and Lewiston, Idaho and Halfway, Oregon  fromSeptember 7 through September 13, 2006, to take public comments on the draftEIS.  Transcripts of the public meetings are filed in the FERC record.  TheFERC will consider these comments, in addition to the written comments receivedby November 3, 2006, in connection with the preparation of the final EIS.On November 3, 2006, IPC filed comments with the FERC on the draft EIS.  Inlarge measure, the FERC Staff adopted the protection, mitigation andenhancement measures proposed by IPC in its final license application.  Withregard to the following issues, the FERC Staff took the following action: rejected an anadromous fish habitat restoration fund of $5-10 million per yearon the basis that it has no nexus to the project; rejected operational and ramprate restrictions below Hells Canyon Dam on the basis that sufficientinformation is available to determine that the aquatic community below theproject is not being adversely affected by operations; rejected an 8,500 cfsnavigation flow below the HCC on the basis that the alleged benefits tonavigation were not worth the substantial reduction in power benefitsassociated with the increased flows; and accepted IPC's proposal to acquire,enhance and manage approximately 22,761 acres as appropriate on-site, in-kindmitigation for the effects of project operations on upland and riparianhabitat.  While IPC concurred with many of Staff's conclusions in the draftEIS, IPC did provide comments on certain portions of the draft EIS.  Otherparties also submitted comments on the draft EIS.  IPC is now reviewing thosecomments to determine whether additional submittals to the FERC are necessaryin response to those comments.  The FERC is now in the process of reviewing thecomments to the draft EIS and has advised that its preliminary schedule for therelease of a final EIS is May 2007.

On August 1, 2006, the FERCrequested formal consultation with the National Marine Fisheries Service(NMFS), pursuant to section 7 of the Endangered Species Act (ESA), advising theNMFS that the FERC Staff, in the draft EIS, had concluded that the licensing ofthe HCC was likely to adversely affect the Snake River fall Chinook salmon(threatened species), Snake River spring/summer Chinook salmon (threatenedspecies), Snake River Sockeye salmon (endangered species) and Snake RiverSteelhead (threatened species), along with the critical habitat for thesespecies.  On September 7, 2006, NMFS sent a letter to the FERC advising thatthe draft EIS did not meet the information requirements for initiation offormal consultation under section 7 of the ESA because the draft EIS did notfully describe the action alternative that was to be subject to consultation. The NFMS advised that several processes were still underway that may affect theaction alternative, including the section 10(j) process under the Federal PowerAct, the outcome of the section 401 certification process under the Clean WaterAct that is pending before the Departments of Environmental Quality of Idahoand Oregon, and discussions with IPC intended to craft measures to address ESAissues.  For these reasons NMFS suggested that consultation should be initiatedat a later time.  NMFS suggested that NMFS, USFWS and IPC work cooperatively toaddress ESA issues as the NEPA process continues so as to assure that thelicensing process is not delayed due to ESA consultation. 

On August 1, 2006, the FERC requested formal consultation with the USFWS,pursuant to section 7 of the ESA, advising the USFWS that the FERC Staff, inthe draft EIS, had concluded that the licensing of the HCC was likely toadversely affect the bull trout (threatened species) and its critical habitatand the bald eagle (threatened species).  On August 31, 2006, the USFWS sent aletter to the FERC advising that the draft EIS did not meet the informationrequirements for initiation of formal consultation under section 7 of the ESAbecause the draft EIS did not fully describe the action alternative that was tobe subject to consultation.  The USFWS advised the FERC that elements relatingto a new license were still under development in processes involving IPC andstate and federal agencies, one such process being section 401 certificationunder the Clean Water Act, which is currently pending before the Departments ofEnvironmental Quality of Idaho and Oregon.  The USFWS further advised that itwas also still in the process of preparing comments to the draft EIS and thatthe FERC had yet to complete the processes necessary under the Federal PowerAct with regard to the federal agencies section 10(j) recommendations.  Forthese reasons, the USFWS suggested that the USFWS, the NMFS, and IPC workcooperatively to address ESA issues as the NEPA process continues so as toassure that the licensing process is not delayed due to ESA consultation.

Inearly December 2006, in connection with scheduled meetings between the FERC andthe USFWS and the NMFS on section 10(j) recommendations, the FERC, the USFWS,the NMFS and IPC met and conferred on pending ESA issues.  At the conclusion ofthat meeting, the FERC advised that it intended to schedule a conference callin early 2007 to further discuss ESA issues.  The FERC has not yet scheduledthat conference call.  IPC is cooperating with the USFWS, the NMFS and the FERCin an effort to address ESA concerns associated with the licensing of the HCC. 

At December 31, 2006, $86million of HCC relicensing costs were included in construction work inprogress.  The relicensing costs are recorded and held in construction work inprogress until a new multi-year license is issued by the FERC, at which timethe charges will be transferred to electric plant in service.  Relicensingcosts and costs related to a new license will be submitted to regulators forrecovery through the ratemaking process.

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**Swan Falls Project:**  The license for the Swan Falls hydroelectric project expires in 2010.  On March 10, 2005, IPC issued a FormalConsultation Package with agencies, Native American tribes and the publicregarding the relicensing of the Swan Falls project.  IPC is in the process ofcompiling information and performing studies in preparation for filing anapplication for a new license with the FERC.  IPC expects to file a draftlicense application in the fall of 2007, with the final application being filedin June 2008.

AtDecember 31, 2006, $2 million of Swan Falls project relicensing costs wereincluded in construction work in progress.  The relicensing costs are recordedand held in construction work in progress until a new multi-year license isissued by the FERC, at which time the charges will be transferred to electricplant in service.  Relicensing costs and costs related to a new license will besubmitted to regulators for recovery through the ratemaking process.

**MiddleSnake River Projects:**  IPC's middleSnake River projects consist of the Bliss, Upper Salmon Falls, Lower Salmon Falls, Shoshone Falls and CJ Strike projects.  On August 4, 2004, IPC received theFERC license orders for each of the middle Snake River projects.  On September2, 2004, two conservation groups, American Rivers and Idaho Rivers United,filed petitions for rehearing of the orders issuing the licenses for the middle Snake River projects.  These petitions asked the FERC to vacate the licensingorders and request a determination from the USFWS that the middle Snake River projects jeopardize the listed snail species.  On October 4, 2004, the FERCissued an Order Granting Rehearing for Further Consideration to provideadditional time to consider the matters raised by the rehearing requests.  OnMarch 4, 2005, the FERC issued an order denying the conservation groups'rehearing request.  On April 28, 2005, American Rivers and Idaho Rivers Unitedappealed this order to the U.S. Court of Appeals for the Ninth Circuit.  IPCfiled a motion to intervene in the appeal and the USFWS filed a motion to bedesignated a respondent-intervenor.  On June 15, 2005, the court granted thesemotions.  On July 12, 2006, the Ninth Circuit issued a memorandum decisiondenying the conservation groups' appeal.  American Rivers' and Idaho RiversUnited's appeal period ended on October 10, 2006, with no action by eithergroup.  The new licenses for the middle Snake River projects are in fulleffect.

**Shoshone Falls****Expansion**On August 17, 2006, IPC filed a License Amendment Application with the FERC,which would allow IPC to upgrade the Shoshone Falls project from 12.5 MW to62.5 MW.  The FERC is currently evaluating the application and on October 10,2006, requested additional information on 11 items.  IPC has provided theadditional information.  In addition, on October 3, 2006, IPC filed a WaterRight Application with the IDWR for rights to additional water for thispotential project expansion.  IPC is awaiting further action on theseapplications.

**Regional TransmissionOrganizations**Over the last several years, IPC has spent funds supporting the development ofGrid West, a regional transmission organization (RTO).  Through the fourthquarter of 2006, IPC had loaned Grid West $1.1 million and had accumulated $2.3million of costs in a deferred expense account, anticipating future recoverythrough Grid West tariffs.  The deferred expenses were direct expenses incurredin the development of Grid West that were deferred based on a 2004 accountingorder that IPC received from the FERC.  IPC ceased funding Grid West followingthe dissolution of Grid West on April 11, 2006.  IPC no longer expects reimbursementof either amount from Grid West.

In April 2006, IPC filedrequests with the IPUC and OPUC to recover through retail rates the amountsloaned to Grid West and the deferred expenses related to the development ofGrid West.  On August 22, 2006, the OPUC issued an order granting IPC'srecovery of the Grid West loans; however, they denied IPC's request to recoverthe deferred amounts.  On October 24, 2006, the IPUC issued an order allowingIPC to recover the principal portion of the Grid West loans over a five-yearamortization beginning January 1, 2007.  The IPUC disallowed the recovery ofthe deferred amounts and the interest portion of the Grid West loans.

As a result of these orders,IPC recognized an impairment of $2.1 million in the fourth quarter of 2006 forthe disallowance of the deferred amounts and a regulatory asset of $1.3 millionfor the recovery of the Grid West loan amounts.

**Northern Tier TransmissionGroup**IPC, along with four other utilitiescovering all or parts of the transmission system in six western states, has formedthe Northern Tier Transmission Group (NTTG).  The goal of the group is toimprove overall operation and expansion of the high-voltage transmissionnetwork.  NTTG held its first meeting in November 2006.  The group has begunthree initial activities: improving generation control performance; providingimproved information on available transmission capacity; and facilitating open,participatory transmission planning.  Goals of the group include compliancewith the new FERC Order 890.

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**FERC Market-Based RateAuthority**IPC has FERC-approved market-basedrate authority, which permits IPC to sell electric energy at market-based ratesrather than cost-based rates.  Every three years, the FERC requires a review ofthe conditions under which this market-based rate authority is granted toensure that the rates charged thereunder are just and reasonable.  On April 14,2004, the FERC issued an order commencing a market power analysis of allcompanies with market-based rate authority, including IPC.  In September 2004,IPC filed a revision of its market power analysis (based on 2003 data), whichit supplemented in September and October 2004.  On March 3, 2005, the FERCissued an order accepting IPC's market power analysis.  IPC is required to fileanother market power analysis on or before March 3, 2008.

On May 2, 2005 IPC filed a "Noticeof Change in Status" in accordance with FERC requirements to report theaddition of Bennett Mountain Power Plant, which IPC acquired on March 31,2005.  The purpose of the filing is to explain whether, and if so, how, theaddition of Bennett Mountain reflects a departure from the characteristics theFERC relied on when it authorized IPC to make sales at market-based rates.

The May 2005 filing includedan updated generation market power study that utilized original 2003 data aswell as pertinent 2004 data.  The results showed that, with the addition of Bennett Mountain, IPC still passed both of the FERC's market power screens in all relevantcontrol areas.

On December 9, 2005, the FERCStaff requested that IPC perform a complete generation market power study forthe IPC control area using 2004 data.  IPC filed a revised study with the FERCon February 3, 2006.

The FERC accepted IPC'snotice on June 20, 2006 confirming that IPC passed the market power analysisscreens and maintained market-based rate authority.

**OTHER MATTERS:**

**Adopted AccountingPronouncementsSFAS 123(R):** Effective January 1,2006, IDACORP and IPC adopted Statement of Financial Accounting Standards No.123 (revised 2004), *"Share-BasedPayment,"* (SFAS 123(R)) using the modified prospective application method. Prior to adopting SFAS 123(R), the companies accounted for stock-based employeecompensation under the recognition and measurement principles of AccountingPrinciples Board Opinion 25, "*Accounting for Stock Issued to Employees,"*and related interpretations.

In 2004 and 2005, totalstock-based employee compensation expense recorded was less than $1 millionannually.  IDACORP and IPC did not modify outstanding stock options prior tothe adoption of SFAS 123(R), and the fair value estimation model for optionsdid not differ significantly.

Since 2001, IDACORP and IPChave granted a mix of performance restricted stock, time-vesting restrictedstock and stock options.  In 2006, IDACORP and IPC granted cumulative earningsper share- and total shareholder return-based performance shares, andtime-vesting restricted stock and granted only a minimal amount of stockoptions.  The adoption of SFAS 123(R) did not have a material effect on IDACORP'sand IPC's financial statements, and, based on current levels of awards, is notexpected to have a material effect in the future*.*  See Note 8 to IDACORP'sand IPC's Consolidated Financial Statements for a discussion of the effects ofadopting SFAS 123(R).

**SFAS 158:**  In December 2006, IDACORP and IPC adopted 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)."*  See Note 9to IDACORP's and IPC's Consolidated Financial Statements for a discussion ofthe effects of adopting SFAS 158.

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**SAB108**: InSeptember 2006, the Securities and Exchange Commission (SEC) released StaffAccounting Bulletin No. 108, *"Considering the Effects of Prior YearMisstatements When Quantifying Misstatements in Current Year FinancialStatements"* (SAB 108).  SAB 108 provides guidance on how the effects of thecarryover or reversal of prior year financial statement misstatements should beconsidered in quantifying a current year misstatement.  Prior practice allowedthe evaluation of materiality on the basis of (1) the error quantified as theamount by which the current year income statement was misstated (rollovermethod) or (2) the cumulative error quantified as the cumulative amount bywhich the current year balance sheet was misstated (iron curtain method). Reliance on either method in prior years could have resulted in misstatement ofthe financial statements.  The guidance provided in SAB 108 requires bothmethods to be used in evaluating materiality.  Immaterial prior year errors maybe corrected with the first filing of prior year financial statements afteradoption.  The cumulative effect of the correction would be reflected in theopening balance sheet with appropriate disclosure of the nature and amount ofeach individual error corrected in the cumulative adjustment, as well as adisclosure of the cause of the error and that the error had been deemed to beimmaterial in the past.  SAB 108 is effective for fiscal years ending afterNovember 15, 2006.  The adoption of SAB 108 did not have a material impact onIDACORP's or IPC's financial statements.

**New AccountingPronouncements**See Note 1 to IDACORP's and IPC's Consolidated Financial Statements for adiscussion of recently issued accounting pronouncements.

**Inflation**IDACORP and IPC believe thatinflation has caused and will continue to cause increases in certain operatingexpenses and the replacement of assets at higher costs.  Inflation affects thecost of labor, products and services required for operations, maintenance costsand capital improvements.  While inflation has not had a significant impact onIDACORP's or IPC's operations, costs for products and services are subject toincreases.  IPC is subject to rate-of-return regulation and the impact ofinflation on the level of cost recovery under regulation.  Increases in utilitycosts and expenses due to inflation could have an adverse effect on earningsbecause of the need to obtain regulatory approval to recover such increasedcosts and expenses.

**ITEM 7A.  QUANTITATIVE ANDQUALITATIVE DISCLOSURES ABOUT MARKET RISK**

IDACORP and IPC are exposedto various market risks, including changes in interest rates, changes incommodity prices, credit risk and equity price risk.  The following discussionsummarizes these risks and the financial instruments, derivative instrumentsand derivative commodity instruments sensitive to changes in interest rates,commodity prices and equity prices that were held at December 31, 2006.

**InterestRate Risk**IDACORP and IPC manage interestexpense and short- and long-term liquidity though a combination of fixed rateand variable rate debt.  Generally, the amount of each type of debt is managedthrough market issuance, but interest rate swap and cap agreements with highly****rated financial institutions may be used to achieve the desiredcombination.

**Variable Rate Debt:**  As of December 31, 2006, IDACORP and IPC had $314million and $241 million, respectively, in floating rate debt, net of temporaryinvestments.  Assuming no change in either company's financial structure, ifvariable interest rates were to average one percentage point higher than theaverage rate on December 31, 2006, interest expense would increase and pre-taxearnings would decrease by approximately $3.1 million for IDACORP and $2.4million for IPC.

**Fixed Rate Debt:**  As of December 31, 2006, IDACORP and IPC hadoutstanding fixed rate debt of $836 million and $797 million, respectively, andthe fair market value of this debt was $828 million and $788 million,respectively.  These instruments are fixed rate, and therefore do not exposeIDACORP or IPC to a loss in earnings due to changes in market interest rates. However, the fair value of these instruments would increase by approximately$67 million for IDACORP and $65 million for IPC if interest rates were todecline by one percentage point from their December 31, 2006 levels.

**Commodity Price RiskUtility:** IPC's exposure to changesin commodity price is related to its ongoing utility operations producingelectricity to meet the demand of its retail electric customers.  The weatheris a major uncontrollable factor affecting the local and regional demand forelectricity and the availability and price of production.  The objective of IPC'senergy purchase and sale activity is to meet the demand of retail electriccustomers, maintain appropriate physical reserves to ensure reliability, andmake economic use of temporary surpluses that may develop.

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IPC's exposure to commodityprice risk is largely offset by the previously discussed PCA mechanism.  IPChas adopted a risk management program designed to reduce exposure to powersupply cost-related uncertainty, further mitigating commodity price risk.  Thisprogram has been reviewed and accepted by the IPUC.  IPC's Energy RiskManagement Policy (the Policy) describes a collaborative process with customersand regulators via a committee called the Customer Advisory Group (CAG).  TheRisk Management Committee (RMC), comprised of IPC officers and other seniorstaff, oversees the risk management program.  The RMC is responsible forcommunicating the status of risk management activities to the IDACORP Board ofDirectors, and to the CAG.

The Policy requiresmonitoring monthly volumetric electricity position and total dollar (net powersupply cost) exposure on a rolling 18-month forward view.  The Power Supplybusiness unit produces and evaluates projections of the operating plan andorders risk mitigating actions dictated by the limits stated in the Policy. The RMC evaluates the actions initiated by Power Supply for consistency andcompliance with the Policy.  IPC representatives meet with the CAG at leastannually to assess effectiveness of the limits.  Changes to the limits can beendorsed by the CAG and referred to the Board of Directors for approval.  Theprimary tools for risk mitigation are physical forward power transactions andfueling alternatives for utility-owned generation resources.

**Credit RiskUtility:**  IPC is subject to creditrisk based on its activity with market counterparties.  IPC is exposed to thisrisk to the extent that a counterparty may fail to fulfill a contractualobligation to provide energy, purchase energy or complete financial settlementfor market activities.  IPC mitigates this exposure by actively establishingcredit limits, measuring, monitoring, reporting, using appropriate contractualarrangements and transferring of credit risk through the use of financial guarantees,cash or letters of credit.  A current list of acceptable counterparties andcredit limits is maintained.

**Equity Price Risk**IDACORP and IPC are exposed to pricefluctuations in equity markets, primarily through their pension plan assets, amine reclamation trust fund owned by an equity-method investment of IPC andother equity investments at IPC.  A hypothetical ten percent decrease in equityprices would result in an approximate $2 million decrease in the fair value offinancial instruments that are classified as available-for-sale securities.

** **

** **

62
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Table of Contents

**ITEM 8.  FINANCIALSTATEMENTS AND SUPPLEMENTARY DATA**

**INDEX TO FINANCIALSTATEMENTS AND FINANCIAL STATEMENT SCHEDULES**

**PAGE**

**Consolidated Financial Statements:**

IDACORP, Inc.

Consolidated Statements of Income for the Years  Ended December 31, 2006, 2005 and 2004

64

Consolidated Balance Sheets as of December 31,  2006 and 2005 

65-66

Consolidated Statements of Cash Flows for the Years  Ended December 31, 2006, 2005 and 2004

67

Consolidated Statements of Shareholders'  Equity for the Years Ended December 31, 2006, 2005

and  2004

68

Consolidated Statements of Comprehensive Income  for the Years Ended December 31, 2006,

2005  and 2004

69

** **

Idaho Power Company

Consolidated Statements of Income for the Years  Ended December 31, 2006, 2005 and 2004

70

Consolidated Balance Sheets as of December 31,  2006 and 2005

71-72

Consolidated Statements of Capitalization as of  December 31, 2006 and 2005

73

Consolidated Statements of Cash Flows for the  Years Ended December 31, 2006, 2005 and 2004

74

Consolidated Statements of Retained Earnings for  the Years Ended December 31, 2006, 2005

and  2004

75

Consolidated Statements  of Comprehensive Income for the Years Ended December 31, 2006,

2005  and 2004

75

Notes to the Consolidated Financial Statements

76-116

Reports of Independent Registered Public Accounting  Firm

117-118

** **

**Supplemental  Financial Information and Consolidated Financial Statement Schedules**

Supplemental Financial Information (Unaudited)

119-120

Financial  Statement Schedules for the Years Ended December 31, 2006, 2005 and 2004:

Schedule I - Condensed Financial Information of  Registrant-IDACORP, Inc.

133-135

Schedule II-Consolidated Valuation and Qualifying  Accounts-IDACORP, Inc.

136

Schedule II-Consolidated Valuation and Qualifying  Accounts-Idaho Power Company

137

** **

** **

** **

** **

** **

** **

** **

** **

** **

** **

** **

** **

** **

** **

** **

** **

** **

** **

** **

** **

63

Table of Contents

**IDACORP, Inc.**

**Consolidated Statements of Income**

** **

** Year Ended December 31,**

 
** **

** 2006**

** 2005**

** 2004**

 
** **

** (thousands of dollars except for per**

** **

** share amounts)**

 
** Operating Revenues:**

** **

 
 Electric utility: 

 
 General  business 

 $

636,375  

 $

667,270  

 $

635,835  

 
 Off-system  sales 

260,717  

142,794  

121,148  

 
 Other  revenues 

23,381  

27,619  

65,954  

 
 Total  electric utility revenues 

920,473  

837,683  

822,937  

 
 Other 

5,818  

5,181  

4,919  

 
 Total  operating revenues 

926,291  

842,864  

827,856  

 
** Operating Expenses:**

 
 Electric utility: 

 
 Purchased  power 

283,440  

222,310  

195,642  

 
 Fuel  expense 

115,018  

103,164  

103,261  

 
 Power  cost adjustment 

(29,526)

(2,995)

39,184  

 
 Other  operations and maintenance 

256,553  

241,209  

255,867  

 
 Depreciation  

99,824  

101,485  

100,855  

 
 Taxes  other than income taxes 

18,661  

20,856  

19,090  

 
 Total  electric utility expenses 

743,970  

686,029  

713,899  

 
 Other expense 

12,617  

2,182  

7,724  

 
 Total  operating expenses 

756,587  

688,211  

721,623  

 
** Operating Income  (Loss):**

 
 Electric utility 

176,503  

151,654  

109,038  

 
 Other 

(6,799)

2,999  

(2,805)

 
 Total  operating income 

169,704  

154,653  

106,233  

 
** Other Income **

18,195  

17,121  

25,456  

 
** Earnings (Losses) of  Unconsolidated Equity-Method Investments**

(2,913)

(713)

1,050  

 
** Other Expense **

8,559  

8,006  

8,774  

 
** Interest Expense and  Preferred Dividends:**

 
 Interest on long-term debt  

56,402  

56,930  

54,937  

 
 Other interest 

4,573  

2,799  

3,375  

 
 Preferred dividends of  Idaho Power Company 

-  

-  

4,823  

 
 Total  interest expense and preferred dividends 

60,975  

59,729  

63,135  

 
** Income Before Income  Taxes**

115,452  

103,326  

60,830  

 
** Income Tax Expense  (Benefit)**

15,377  

17,610  

(19,951)

 
** Income from Continuing  Operations**

100,075  

85,716  

80,781  

 
** Income (Losses) from  Discontinued Operations, net of tax**

7,328  

(22,055)

(7,798)

 
** Net Income**

 $

107,403  

 $

63,661  

 $

72,983  

 
** Weighted Average Common  Shares Outstanding - Basic (000's)**

42,713  

42,279  

38,361  

 
** Weighted Average Common  Shares Outstanding - Diluted (000's)**

42,874  

42,362  

38,420  

 
** Earnings Per Share:**

 
 Earnings per share from  Continuing Operations-Basic 

 $

2.34  

 $

2.03  

 $

2.10  

 
 Earnings (loss) per share  from Discontinued Operations-Basic 

0.17  

(0.52)

(0.20)

 
 Earnings  Per Share of Common Stock-Basic 

 $

2.51  

 $

1.51  

 $

1.90  

 
 Earnings per share from  Continuing Operations-Diluted 

 $

2.34  

 $

2.02  

 $

2.10  

 
 Earnings (loss) per share  from Discontinued Operations-Diluted 

0.17  

(0.52)

(0.20)

 
 Earnings  Per Share of Common Stock-Diluted 

 $

2.51  

 $

1.50  

 $

1.90  

 
** Dividends Paid Per  Share of Common Stock**

 $

1.20  

 $

1.20  

 $

1.20  

 
 The accompanying notes are an integral part of  these statements. 

 
** **

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Table of Contents

** **

**IDACORP, Inc.**

**Consolidated Balance Sheets**

** **

** **

** December 31,**

** **

** 2006**

** 2005**

 
**(thousands of dollars)**
** Assets**

** **

** Current Assets:**

 Cash and cash equivalents 

 $

9,892  

 $

52,356  

 Receivables: 

 Customer  

62,131  

94,469  

 Allowance  for uncollectible accounts 

(7,168)

(33,078)

 Employee  notes 

2,569  

2,951  

 Other  

11,855  

21,377  

 Energy marketing assets 

12,069  

23,859  

 Accrued unbilled revenues 

31,365  

38,905  

 Materials and supplies (at  average cost) 

39,079  

30,451  

 Fuel stock (at average  cost) 

15,174  

11,739  

 Prepayments 

9,308  

17,876  

 Deferred income taxes 

28,035  

23,922  

 Regulatory assets 

1,480  

3,064  

 Refundable income tax  deposit 

44,903  

-  

 Other 

2,513  

2,956  

 Assets held for sale 

3,326  

6,673  

 Total  current assets 

266,531  

297,520  

** Investments**

202,825  

191,593  

** Property, Plant and  Equipment:**

 Utility plant in service 

3,583,694  

3,477,067  

 Accumulated provision for  depreciation 

(1,406,210)

(1,364,640)

 Utility  plant in service - net 

2,177,484  

2,112,427  

 Construction work in  progress 

210,094  

149,814  

 Utility plant held for  future use 

2,810  

2,906  

 Other property, net of  accumulated depreciation 

28,692  

29,294  

 Property,  plant and equipment - net 

2,419,080  

2,294,441  

** Other Assets:**

 American Falls and Milner  water rights 

30,543  

31,585  

 Company-owned life  insurance 

34,055  

35,401  

 Energy marketing assets -  long-term 

-  

22,189  

 Regulatory assets 

423,548  

415,177  

 Long-term receivables (net  of allowance of $1,878) 

3,802  

4,015  

 Employee notes 

2,411  

2,862  

 Other 

41,259  

43,377  

 Assets held for sale 

21,076  

25,966  

 Total  other assets 

556,694  

580,572  

 Total  

 $

3,445,130  

 $

3,364,126  

 The accompanying notes are an integral part of  these statements. 

** **

65

Table of Contents

**IDACORP, Inc.**

**Consolidated BalanceSheets**

** **

** **

** December 31,**

** **

** 2006**

** 2005**

** Liabilities and  Shareholders' Equity**

** (thousands of dollars)**

** **

** Current Liabilities:**

 Current maturities of long-term  debt 

 $

95,125  

 $

16,307  

 Notes payable 

129,000  

60,100  

 Accounts payable 

86,440  

80,324  

 Energy marketing  liabilities 

13,532  

24,093  

 Taxes accrued 

47,402  

72,652  

 Interest accrued 

12,657  

14,616  

 Other 

23,572  

19,577  

 Liabilities held for sale 

2,606  

5,916  

 Total  current liabilities 

410,334  

293,585  

** Other Liabilities:**

 Deferred income taxes 

498,512  

519,563  

 Energy marketing  liabilities - long-term 

-  

22,189  

 Regulatory liabilities 

294,844  

345,109  

 Other 

179,836  

124,833  

 Liabilities held for sale 

8,773  

10,051  

 Total  other liabilities 

981,965  

1,021,745  

** Long-Term Debt**

928,648  

1,023,545  

** **

** Commitments and  Contingencies (Note 7)**

** **

** Shareholders' Equity:**

 Common stock, no par value  (shares authorized 120,000,000; 

 43,905,458  and 42,656,393 shares issued, respectively) 

638,799  

598,706  

 Retained earnings 

493,363  

437,284  

 Accumulated other  comprehensive loss 

(5,737)

(3,425)

 Treasury stock (71,570 and  24,063 shares at cost, respectively) 

(2,242)

(998)

 Unearned compensation 

-  

(6,316)

 Total  shareholders' equity 

1,124,183  

1,025,251  

 Total  

 $

3,445,130  

 $

3,364,126  

 The accompanying notes are an integral part of  these statements. 

** **

** **

** **

** **

** **

** **

** **

** **

** **

** **

** **

** **

66

Table of Contents

**IDACORP, Inc.**

**ConsolidatedStatements of Cash Flows**

** **

**Year Ended December 31,**

**2006**

**2005**

**2004**

**Operating Activities:**

**(thousands of dollars)**

Net  income

 $

107,403  

 $

63,661  

 $

72,983  

Adjustments  to reconcile net income to net cash provided by

operating  activities:

Depreciation  and amortization

122,641  

124,124  

124,192  

Deferred  income taxes and investment tax credits

(17,332)

(31,769)

(33,912)

Changes  in regulatory assets and liabilities

(17,133)

7,275  

16,788  

Undistributed  (earnings) losses of subsidiaries

(9,553)

(16,762)

2,495  

Provision  for uncollectible accounts

106  

(10,729)

(128)

Gain  on sale of assets

(25,658)

(2,128)

(4,475)

Gain  on extinguishment of debt

-  

-  

(7,188)

Impairment  of goodwill

-  

10,270  

-  

Impairment  of long-lived asset

2,047  

-  

9,075  

Other  non-cash adjustments to net income

(3,501)

(4,344)

(3,117)

Excess  tax benefit from share-based payment arrangements

(1,411)

-  

-  

Change  in:

Accounts  receivable and prepayments

24,304  

(6,436)

(1,314)

Accounts  payable and other accrued liabilities

6,725  

1,821  

15,806  

Taxes  accrued

(24,099)

26,412  

717  

Other  current assets

(4,829)

(14,360)

(4,568)

Other  current liabilities

(3,465)

794  

(1,309)

 Other  assets

3,334  

(514)

2,058  

 Other  liabilities

10,199  

14,181  

6,593  

Net  cash provided by operating activities

169,778  

161,496  

194,696  

**Investing Activities:**

Additions  to property, plant and equipment

(225,048)

(193,314)

(199,770)

Sale of non-utility assets

146  

1,019  

5,554  

Sale of ITI

21,469  

-  

-  

Investments  in affordable housing

(5,059)

(4,992)

(7,655)

Sale of emission allowances

11,323  

70,757  

-  

Investments  in unconsolidated affiliates

(16,030)

-  

-  

Purchase  of available-for-sale securities

(17,979)

(85,334)

(295,356)

Sale of available-for-sale securities

20,778  

120,026  

266,331  

Purchase  of held-to-maturity securities

(2,730)

(2,181)

(4,927)

Maturity  of held-to-maturity securities

4,647  

2,840  

7,730  

Refundable  income tax deposit

(44,903)

-  

-  

Other  assets

346  

2,229  

-  

Other  liabilities

-  

-  

(1,547)

Net  cash used in investing activities

(253,040)

(88,950)

(229,640)

**Financing Activities:**

Issuance  of long-term debt 

116,300  

64,992  

106,442  

Retirement  of long-term debt

(132,642)

(83,067)

(79,890)

Retirement  of preferred stock of IPC

-  

-  

(52,351)

Dividends  on common stock

(51,272)

(50,690)

(45,838)

Change  in short-term borrowings

68,900  

23,830  

(58,250)

Issuance  of common stock

41,465  

6,296  

115,690  

Acquisition  of treasury stock

(213)

-  

(1,420)

Excess  tax benefit from share-based payment arrangements

1,411  

-  

-  

Other  assets

(3,058)

(4,486)

(1,145)

Other  liabilities

(93)

(468)

(50)

Net  cash provided by (used in) financing activities

40,798  

(43,593)

(16,812)

Net increase (decrease) in  cash and cash equivalents

(42,464)

28,953  

(51,756)

Cash and cash equivalents at  beginning of year

52,356  

23,403  

75,159  

Cash and cash equivalents at  end of year

 $

9,892  

 $

52,356  

 $

23,403  

**Supplemental Disclosure  of Cash Flow Information:**

Cash  paid during the year for:

Income  taxes

 $

54,522  

 $

18,937  

 $

7,742  

Interest  (net of amount capitalized)

 $

60,353  

 $

57,466  

 $

55,122  

The accompanying notes are an integral part of these  statements.

 

67

 

**IDACORP,Inc.**

**Consolidated Statements of Shareholders' Equity**

** **

** **

** **

** **

** **

**Accumulated**

** **

** **

** **

** **

**Other**

** **

** **

** **

** **

**Comprehensive**

**Common Stock**

**Retained**

**Income**

**Treasury Stock**

**Total**

**Shares**

**Amount**

**Earnings**

**(Loss)**

**Shares**

**Amount**

**Amount**

**(in thousands)**

Balance at January 1, 2004

38,341  

 $

472,902  

 $

397,167  

 $

(2,630)

111  

 $

(3,158)

 $

864,281  

Net Income

-    

-    

72,983  

-    

-    

-    

72,983  

Common stock dividends ($1.20  per share)

-    

-    

(45,838)

-    

-    

-    

(45,838)

Issued

4,033  

115,690  

-    

-    

-    

-    

115,690  

Acquired

-    

-    

-    

-    

46  

(1,420)

(1,420)

Other

-    

848  

-    

-    

-    

-    

848  

Unrealized gain on  securities (net of tax)

-    

-    

-    

862  

-    

-    

862  

Unfunded pension liability  adjustment (net of tax)

-    

-    

-    

880  

-    

-    

880  

Balance at December 31, 2004

42,374  

589,440  

424,312  

(888)

157  

(4,578)

1,008,286  

Net Income

-    

-    

63,661  

-    

-    

-    

63,661  

Common stock dividends  ($1.20 per share)

-    

-    

(50,690)

-    

-    

-    

(50,690)

Issued

282  

8,204  

-    

-    

(14)

431  

8,635  

Acquired

-    

-    

-    

-    

75  

(2,268)

(2,268)

Other

-    

1,062  

1  

-    

21  

(899)

164  

Unrealized loss on  securities (net of tax)

-    

-    

-    

(1,812)

-    

-    

(1,812)

Unfunded pension liability  adjustment (net of tax)

-    

-    

-    

(725)

-    

-    

(725)

Balance at December 31, 2005

42,656  

598,706  

437,284  

(3,425)

239  

(7,314)

1,025,251  

Net Income

-    

-    

107,403  

-    

-    

-    

107,403  

Common stock dividends  ($1.20 per share)

-    

-    

(51,323)

-    

-    

-    

(51,323)

Issued

1,188  

41,465  

-    

-    

(11)

348  

41,813  

Acquired

-    

-    

-    

-    

6  

(213)

(213)

Other

61  

(1,372)

(1)

-    

(162)

4,937  

3,564  

Unrealized loss on  securities (net of tax)

-    

-    

-    

(1,414)

-    

-    

(1,414)

Unfunded pension liability  adjustment (net of tax)

-    

-    

-    

2,118  

-    

-    

2,118  

Adjustment upon adoption of  SFAS 158 (net of tax)

-    

-    

-    

(3,016)

-    

-    

(3,016)

Balance at December 31, 2006

43,905  

 $

638,799  

 $

493,363  

 $

(5,737)

72  

 $

(2,242)

 $

1,124,183  

The accompanying notes are an integral part of these  statements.

** **

** **

** **

** **

** **

** **

** **

** **

** **

** **

** **

** **

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**IDACORP,Inc.**

**Consolidated Statements of Comprehensive Income**

** **

**Year Ended December 31,**

**2006**

**2005**

**2004**

**(thousands of dollars)**

**Net Income**

 $

107,403  

 $

63,661  

 $

72,983  

**Other Comprehensive  Income (Loss):**

Unrealized gains (losses)  on securities:

Unrealized  holding gains (losses) arising during the year,

net  of tax of $1,471, ($96) and $1,234

2,355  

(457)

2,057  

Reclassification  adjustment for losses included

in  net income, net of tax of ($2,250), ($870) and ($768)

(3,769)

(1,355)

(1,195)

Net  unrealized gains (losses)

(1,414)

(1,812)

862  

Unfunded pension liability  adjustment, net of tax

 of  $1,359, ($465) and $565

2,118  

(725)

880  

**Total Comprehensive  Income**

 $

108,107  

 $

61,124  

 $

74,725  

The accompanying notes are an integral part of these  statements.

** **

** **

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Table of Contents

**IdahoPower Company**

**Consolidated Statements of Income**

** **

** **

** Year Ended December 31,**

** **

** 2006**

** 2005**

** 2004**

** **

** (thousands of dollars)**

** Operating Revenues:**

 General business 

 $

636,375  

 $

667,270  

 $

635,835  

 Off-system sales 

260,717  

142,794  

121,148  

 Other revenues 

23,381  

27,619  

62,526  

 Total  operating revenues 

920,473  

837,683  

819,509  

** **

** Operating Expenses:**

 Operation: 

 Purchased  power 

283,440  

222,310  

195,642  

 Fuel  expense 

115,018  

103,164  

103,261  

 Power  cost adjustment 

(29,526)

(2,995)

39,184  

 Other  

191,833  

181,670  

194,073  

 Maintenance 

64,720  

59,539  

58,405  

 Depreciation 

99,824  

101,485  

100,855  

 Taxes other than income  taxes 

18,661  

20,856  

19,090  

 Total  operating expenses 

743,970  

686,029  

710,510  

** Income from Operations**

176,503  

151,654  

108,999  

** **

** Other Income (Expense):**

 Allowance for equity funds  used during construction 

6,092  

4,950  

3,904  

 Earnings of unconsolidated  equity-method investments 

9,347  

10,369  

12,313  

 Other income 

10,578  

11,476  

12,138  

 Other expense 

(8,701)

(8,610)

(9,074)

 Total  other income 

17,316  

18,185  

19,281  

** Interest Charges:**

 Interest on long-term debt  

53,744  

53,339  

50,317  

 Other interest 

6,211  

3,527  

3,980  

 Allowance for borrowed  funds used during construction 

(4,026)

(2,791)

(2,953)

 Total  interest charges 

55,929  

54,075  

51,344  

** Income Before Income  Taxes**

137,890  

115,764  

76,936  

** Income Tax Expense**

43,961  

43,925  

6,328  

** Net Income**

93,929  

71,839  

70,608  

 Dividends on preferred  stock 

-  

-  

4,823  

** Earnings on Common  Stock**

 $

93,929  

 $

71,839  

 $

65,785  

** **

 The accompanying notes are an integral part of  these statements. 

** **

** **

** **

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Table of Contents

**IdahoPower Company**

**Consolidated Balance Sheets**

** **

** Assets**

** December 31, **

** 2006**

** 2005**

** **

** Electric Plant:**

 In service (at original  cost) 

 $

3,583,694  

 $

3,477,067  

 Accumulated provision for  depreciation 

(1,406,210)

(1,364,640)

 In  service - net 

2,177,484  

2,112,427  

 Construction work in  progress 

210,094  

149,814  

 Held for future use 

2,810  

2,906  

 Electric  plant - net 

2,390,388  

2,265,147  

** Investments and Other  Property**

91,244  

68,049  

** **

** Current Assets:**

 Cash and cash equivalents 

2,404  

49,335  

 Receivables: 

 Customer  

54,218  

49,830  

 Allowance  for uncollectible accounts 

(968)

(833)

 Notes  

514  

3,273  

 Employee  notes 

2,569  

2,951  

 Related  parties 

-  

637  

 Other  

10,592  

7,399  

 Accrued unbilled revenues 

31,365  

38,905  

 Materials and supplies (at  average cost) 

39,078  

30,451  

 Fuel stock (at average  cost) 

15,174  

11,739  

 Prepayments 

8,952  

17,532  

 Regulatory assets 

1,480  

3,064  

 Total  current assets 

165,378  

214,283  

** Deferred Debits:**

 American Falls and Milner  water rights 

30,543  

31,585  

 Company-owned life  insurance 

34,055  

35,401  

 Regulatory assets 

423,548  

415,177  

 Employee notes 

2,411  

2,862  

 Other 

40,158  

42,187  

 Total  deferred debits 

530,715  

527,212  

 Total 

 $

3,177,725  

 $

3,074,691  

 The accompanying notes are an integral part of  these statements. 

** **

** **

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Table of Contents

**IdahoPower Company**

**ConsolidatedBalance Sheets**

** **

** Capitalization and  Liabilities**

** **

** December 31, **

** **

** 2006**

** 2005**

** **

** (thousands of dollars)**

** Capitalization:**

 Common stock equity: 

 Common  stock, $2.50 par value (50,000,000 shares 

 authorized;  39,150,812 shares outstanding) 

       $

97,877  

       $

97,877  

 Premium  on capital stock 

530,758  

483,707  

 Capital  stock expense 

(2,097)

(2,097)

 Retained  earnings 

404,076  

361,256  

 Accumulated  other comprehensive loss 

(5,737)

(3,425)

 Total  common stock equity 

1,024,877  

937,318  

 Long-term debt 

902,884  

983,720  

 Total  capitalization 

1,927,761  

1,921,038  

** Current Liabilities:**

 Long-term debt due within  one year 

81,064  

-  

 Notes payable 

52,200  

-  

 Accounts payable 

85,714  

79,433  

 Notes and accounts payable  to related parties 

1,111  

153  

 Taxes accrued 

41,688  

72,994  

 Interest accrued 

12,324  

14,105  

 Deferred income taxes 

17  

3,064  

 Other 

24,367  

19,182  

 Total  current liabilities 

298,485  

188,931  

** Deferred Credits:**

 Deferred income taxes 

489,234  

507,880  

 Regulatory liabilities 

294,844  

345,109  

 Other 

167,401  

111,733  

 Total  deferred credits 

951,479  

964,722  

 Commitments and  Contingencies (Note 7) 

 Total 

       $

3,177,725  

          $

3,074,691  

 The accompanying notes are an integral part of  these statements. 

** **

** **

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Table of Contents

**IdahoPower Company**

**Consolidated Statements of Capitalization**

** **

** **

**December 31,**

** **

**December 31,**

** **

**2006**

**%**

**2005**

**%**

**(thousands of dollars)**

**Common Stock Equity:**

** **

** **

** **

** **

Common  stock

 $

97,877  

 $

97,877  

Premium  on capital stock

530,758  

483,707  

Capital  stock expense

(2,097)

(2,097)

Retained  earnings

404,076  

361,256  

Accumulated  other comprehensive loss

(5,737)

(3,425)

Total  common stock equity

1,024,877  

53  

937,318  

49  

** **

**Long-Term Debt:**

First  mortgage bonds:

7.38%  Series due 2007

80,000  

80,000  

7.20%  Series due 2009

80,000  

80,000  

6.60%  Series due 2011

120,000  

120,000  

4.75%  Series due 2012

100,000  

100,000  

4.25%  Series due 2013

70,000  

70,000  

6     % Series due 2032

100,000  

100,000  

5.50%  Series due 2033

70,000  

70,000  

5.50%  Series due 2034

50,000  

50,000  

5.875%  Series due 2034

55,000  

55,000  

5.30%  Series due 2035

60,000  

60,000  

Total  first mortgage bonds

785,000  

785,000  

Amount  due within one year

(80,000)

-  

Net  first mortgage bonds

705,000  

785,000  

** **

Pollution  control revenue bonds:

Variable  Auction Rate Series 2003 due 2024

49,800  

49,800  

Variable  Auction Rate Series 2006 due 2026 

116,300  

-  

6.05%  Series 1996A due 2026

-  

68,100  

Variable  Rate Series 1996B due 2026

-  

24,200  

Variable  Rate Series 1996C due 2026

-  

24,000  

Variable  Rate Series 2000 due 2027

4,360  

4,360  

Total  pollution control revenue bonds

170,460  

170,460  

American   Falls bond guarantee

19,885  

19,885  

Milner  Dam note guarantee

11,700  

11,700  

Note  guarantee due within one year

(1,064)

-  

Unamortized  premium/discount - net

(3,097)

(3,325)

** **

Total  long-term debt

902,884  

47  

983,720  

51  

** **

**Total Capitalization**

 $

1,927,761  

100  

 $

1,921,038  

100  

** **

 The accompanying notes are an integral part of  these statements. 

** **

** **

** **

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Table of Contents

**IdahoPower Company**

**Consolidated Statements of Cash Flows**

Table of Contents

** **

** **

**Year Ended December 31,**

** **

**2006**

**2005**

**2004**

**Operating Activities:**

**(thousands of dollars)**

Net income

 $

93,929  

 $

71,839  

 $

70,608  

Adjustments to reconcile  net income to net cash provided by

   

operating  activities:

Depreciation  and amortization

105,464  

107,919  

108,551  

Deferred  income taxes and investment tax credits

(13,473)

(34,729)

(19,992)

Changes  in regulatory assets and liabilities

(17,133)

7,275  

16,788  

Undistributed  (earnings) losses of subsidiary

(9,347)

(16,669)

1,990  

Provision  for uncollectible accounts

106  

(530)

(128)

Gain  on sale of assets

(11,751)

(672)

-  

Impairment  of assets

2,047  

-  

9,075  

Other  non-cash adjustments to net income

(5,959)

(4,950)

(3,904)

Change  in:

Accounts  receivables and prepayments

3,596  

5,290  

(3,718)

Accounts  payable

6,623  

2,578  

29,112  

Taxes  accrued

(30,235)

30,766  

(13,155)

Other  current assets

(4,767)

(14,503)

(4,220)

Other  current liabilities

(2,310)

1,269  

(2,029)

Other  assets

3,332  

(698)

2,054  

Other  liabilities

10,997  

11,840  

6,753  

Net  cash provided by operating activities

131,119  

166,025  

197,785  

**Investing Activities:**

Additions to utility plant

(221,840)

(185,865)

(190,286)

Purchase of  available-for-sale securities

(17,979)

(85,334)

(295,356)

Sale of available-for-sale securities

20,778  

120,026  

266,331  

Sale of emission allowances

11,323  

70,758  

-  

Investments in  unconsolidated affiliate

(16,030)

-  

-  

Other assets

497  

1,181  

(38)

Net  cash used in investing activities

(223,251)

(79,234)

(219,349)

**Financing Activities:**

Issuance of long-term debt

116,300  

60,000  

105,000  

Retirement of long-term  debt

(116,300)

(60,000)

(51,105)

Retirement of preferred  stock

-  

-  

(52,351)

Dividends on common stock

(51,109)

(50,690)

(46,413)

Dividends on preferred  stock

-  

-  

(4,823)

Change in short term  borrowings

52,200  

-  

-  

Capital contribution from  parent

47,050  

-  

85,920  

Other assets

(3,058)

(4,445)

(1,145)

Other liabilities

118  

-  

129  

Net  cash provided by (used in) financing activities

45,201  

(55,135)

35,212  

Net increase (decrease) in  cash and cash equivalents

(46,931)

31,656  

13,648  

Cash and cash equivalents  at beginning of year

49,335  

17,679  

4,031  

Cash and cash equivalents  at end of year

 $

2,404  

 $

49,335  

 $

17,679  

**Supplemental Disclosure  of Cash Flow Information:**

Cash paid during the year  for:

Income  taxes paid to parent

 $

86,311  

 $

48,545  

 $

39,190  

Interest  (net of amount capitalized)

 $

55,501  

 $

51,290  

 $

48,113  

The accompanying notes are an integral part of these  statements.

 

74

 

**IdahoPower Company**

**Consolidated Statements of Retained Earnings**

** **

**Year Ended December 31,**

**2006**

**2005**

**2004**

**(thousands of dollars)**

**Retained Earnings,  Beginning of Year**

 $

361,256  

 $

340,107  

 $

320,735  

**Net Income**

93,929  

71,839  

70,608  

**Dividends**

Common  stock

(51,109)

(50,690)

(46,413)

Preferred  stock

-    

-    

(4,823)

**Retained Earnings, End  of Year**

 $

404,076  

 $

361,256  

 $

340,107  

The accompanying notes are an integral part of these  statements.

** **

** **

** **

** **

**IdahoPower Company**

**Consolidated Statements Comprehensive Income**

** **

**Year Ended December 31,**

**2006**

**2005**

**2004**

**(thousands of dollars)**

**Net Income**

 $

93,929  

 $

71,839  

 $

70,608  

**Other Comprehensive  Income (Loss):**

Unrealized gains (losses)  on securities:

Unrealized  holding gains (losses) arising during the year,

net  of tax of $1,471, ($96) and $1,234

2,355  

(457)

2,057  

Reclassification  adjustment for losses included

in  net income, net of tax of ($2,250), ($870) and ($768)

(3,769)

(1,355)

(1,195)

Net  unrealized gains (losses)

(1,414)

(1,812)

862  

Unfunded pension liability  adjustment, net of tax

 of  $1,359, ($465) and $565

2,118  

(725)

880  

**Total Comprehensive  Income**

 $

94,633  

 $

69,302  

 $

72,350  

The accompanying notes are an integral part of these  statements.

** **

** **

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Table of Contents

**IDACORP, INC. AND IDAHOPOWER COMPANYNOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS**

**1.  SUMMARY OF SIGNIFICANTACCOUNTING POLICIES:**

This Annual Report on Form10-K is a combined report of IDACORP, Inc. (IDACORP) and Idaho Power Company(IPC).  Therefore, the Notes to the Consolidated Financial Statements apply toboth IDACORP and IPC.  However, IPC makes no representation as to theinformation relating to IDACORP's other operations.

**Nature of Business**IDACORP is a holding company formedin 1998 whose principal operating subsidiary is IPC.  IDACORP is subject to theprovisions of the Public Utility Holding Company Act of 2005 (2005 Act), whichprovides certain access to books and records to the Federal Energy RegulatoryCommission (FERC) and state utility regulatory commissions and imposes certainrecord retention and reporting requirements on IDACORP.

IPC is an electric utilitywith a service territory covering approximately 24,000 square miles in southern Idaho and eastern Oregon.  IPC is regulated by the FERC and the stateregulatory commissions of Idaho and Oregon.  IPC is the parent of Idaho EnergyResources Co., a joint venturer in Bridger Coal Company, which supplies coal tothe Jim Bridger generating plant owned in part by IPC.

IDACORP's other subsidiariesinclude:

•    IDACORP Financial Services, Inc.(IFS), an investor in affordable housing and other real estate investments;

•    Ida-West Energy Company(Ida-West), an operator of smallhydroelectric generation projects that satisfy the requirements of the PublicUtility Regulatory Policies Act of 1978 (PURPA); and

•    IDACORP Energy (IE), a marketer ofenergy commodities, which wound down operations in 2003.

In the second quarter of2006, IDACORP management designated the operations of IDACORP Technologies,Inc. (ITI) and IDACOMM as assets held for sale, as defined by Statement ofFinancial Accounting Standards No. 144, *"Accounting for the Impairment orDisposal of Long-Lived Assets"* (SFAS 144).  IDACORP's consolidatedfinancial statements reflect the reclassification of the results of thesebusinesses as discontinued operations for all periods presented.  Discontinuedoperations are discussed in more detail in Note 17.

On July 20, 2006, IDACORPcompleted the sale of all of the outstanding common stock of ITI to IdaTech UKLimited, a wholly-owned subsidiary of Investec Group Investments (UK) Limited.

On February 23, 2007, IDACORPcompleted the sale of all of the outstanding common stock of IDACOMM toAmerican Fiber Systems, Inc.

**Principles ofConsolidation**The consolidated financial statementsof IDACORP and IPC include the accounts of each company, consolidatedsubsidiaries and those variable interest entities (VIEs) for which thecompanies are the primary beneficiaries.  All significant intercompany balanceshave been eliminated in consolidation.  Investments in business entities inwhich IDACORP and IPC are not the primary beneficiaries, but have the abilityto exercise significant influence over operating and financial policies, areaccounted for using the equity method.

The entities that IDACORP andIPC consolidate consist primarily of wholly-owned or controlled subsidiaries. In addition, IDACORP consolidates the following VIEs in accordance withFinancial Accounting Standards Board Interpretation No. 46(R), *"Consolidationof Variable Interest Entities - an interpretation of ARB No. 51:"*
- Ida-West participates in     Marysville Hydro Partners, a joint venture that owns a small hydroelectric     project.  Marysville Hydro Partners has approximately $22 million of     assets, primarily the hydroelectric plant, and approximately $18 million     of intercompany long-term debt, which is eliminated in consolidation.

•        IFS is a limited partner in EmpireDevelopment Company, LLC, an entity that earns historic tax credits through therehabilitation of the Empire Building in Boise, Idaho.  Empire DevelopmentCompany, LLC has approximately $8 million of assets, primarily real property,and $7 million of long-term debt.  This debt is non-recourse to IDACORP,personally guaranteed by the general partner and collateralized by the property.

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•     Through IFS, IDACORP also holdssignificant variable interests in VIEs for which it is not the primarybeneficiary.  These VIEs are historic rehabilitation and affordable housingdevelopments in which IFS holds limited partnership interests ranging from fiveto 99 percent.  These investments were acquired between 1996 and 2006.  IFS'smaximum exposure to loss in these developments totaled $90 million at December31, 2006.

**ManagementEstimates**Management makes estimates andassumptions when preparing financial statements in conformity with accountingprinciples generally accepted in the United States of America.  These estimatesand assumptions, including those related to rate regulation, benefit costs,contingencies, litigation, asset impairment, income taxes, unbilled revenuesand bad debt, affect the reported amounts of assets and liabilities and thedisclosure of contingent assets and liabilities at the date of the financialstatements, and the reported amounts of revenues and expenses during thereporting period.  These estimates involve judgments with respect to, amongother things, future economic factors that are difficult to predict and arebeyond management's control.  As a result, actual results could differ fromthose estimates.

**System of Accounts**The accounting records of IPC conformto the Uniform System of Accounts prescribed by the FERC and adopted by thepublic utility commissions of Idaho, Oregon and Wyoming.

**Regulation of UtilityOperations**IPC follows SFAS 71, *"Accountingfor the Effects of Certain Types of Regulation,"* and its financialstatements reflect the effects of the different rate-making principles followedby the jurisdictions regulating IPC.  The application of SFAS 71 by IPC canresult in IPC recording expenses in a period different than the period theexpense would be recorded by an unregulated enterprise.  When this occurs,costs are deferred as regulatory assets on the balance sheet and recorded asexpenses in the periods when those same amounts are reflected in rates. Additionally, regulators can impose regulatory liabilities upon a regulatedcompany for amounts previously collected from customers and for amounts thatare expected to be refunded to customers.

IPC has a Power CostAdjustment (PCA) mechanism that provides for annual adjustments to the ratescharged to its Idaho retail customers.  These adjustments are based onforecasts of net power supply costs, which are fuel and purchased power lessoff-system sales, and the true-up of the prior year's forecast.  During theyear, 90 percent of the difference between the actual and forecasted costs isdeferred with interest.  The ending balance of this deferral, called thetrue-up for the current year's portion and the true-up of the true-up for theprior years' unrecovered or over-recovered portion, is then included in thecalculation of the next year's PCA.

The effects of applying SFAS71 are discussed in more detail in Note 12 - "Regulatory Matters."

**Cash and Cash Equivalents**Cash and cash equivalents includecash on hand and highly liquid temporary investments with maturity dates atdate of acquisition of three months or less.

**Derivative FinancialInstruments**Financial instruments such ascommodity futures, forwards, options and swaps are used to manage exposure tocommodity price risk in the electricity market.  The objective of the riskmanagement program is to mitigate the risk associated with the purchase andsale of electricity and natural gas.  The accounting for derivative financialinstruments that are used to manage risk is in accordance with the conceptsestablished by SFAS 133, *"Accounting for Derivative Instruments and HedgingActivities,"* as amended.

**Property, Plant andEquipment and Depreciation**The cost of utility plant in servicerepresents the original cost of contracted services, direct labor and material,Allowance for Funds Used During Construction (AFDC) and indirect charges forengineering, supervision and similar overhead items.  Maintenance and repairsof property and replacements and renewals of items determined to be less thanunits of property are expensed to operations.  Repair and maintenance costsassociated with planned major maintenance are recorded as these costs areincurred.  For utility property replaced or renewed, the original cost plusremoval cost less salvage is charged to accumulated provision for depreciation,while the cost of related replacements and renewals is added to property, plantand equipment.

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All utility plant in serviceis depreciated using the straight-line method at rates approved by regulatoryauthorities.  Annual depreciation provisions as a percent of averagedepreciable utility plant in service approximated 2.75 percent in 2006, 2.91percent in 2005 and 2.96 percent in 2004.

Long-lived assets areperiodically reviewed for impairment when events or changes in circumstancesindicate that the carrying amount of an asset may not be recoverable asprescribed under SFAS 144.  SFAS 144 requires that if the sum of theundiscounted expected future cash flows from an asset is less than the carryingvalue of the asset, an asset impairment must be recognized in the financialstatements.

**Goodwill**IDACORP accounts for goodwill inaccordance with SFAS 142, "*Goodwill and Other Intangible Assets."*  SFAS142 requires that goodwill and certain intangible assets be tested forimpairment at least annually and also under certain circumstances.  Thedecision to exit one of IDACOMM's lines of business, broadband-over-power line,triggered a $10 million goodwill impairment charge in the fourth quarter of2005.  With the sale of ITI in July 2006, IDACORP no longer has any recordedgoodwill.

**Revenues**Operating revenues for IPC related tothe sale of energy are generally recorded when service is rendered or energy isdelivered to customers.  IPC accrues unbilledrevenues for electric services delivered to customers but not yet billed atperiod-end.  IPC collects franchise fees and similar taxes related to energyconsumption.  These amounts are recorded as liabilities until paid to thetaxing authority.  None of these collections are reported on the incomestatement as revenue or expense.

**Allowance for Funds UsedDuring Construction**AFDC represents the cost of financingconstruction projects with borrowed funds and equity funds.  While cash is notrealized currently from such allowance, it is realized under the rate-makingprocess over the service life of the related property through increasedrevenues resulting from a higher rate base and higher depreciation expense. The component of AFDC attributable to borrowed funds is included as a reductionto interest expense, while the equity component is included in other income. IPC's weighted-average monthly AFDC rates for 2006, 2005 and 2004 were 7.6percent, 7.4 percent and 6.9 percent, respectively.  IPC's reductions tointerest expense for AFDC were $4 million for 2006 and $3 million for both 2005and 2004.  Other income included $6 million, $5 million and $4 million of AFDCfor 2006, 2005 and 2004, respectively.

**IncomeTaxes**The liability method of computingdeferred taxes is used on all temporary differences between the book and taxbasis of assets and liabilities and deferred tax assets and liabilities areadjusted for enacted changes in tax laws or rates.  Consistent with orders anddirectives of the Idaho Public Utilities Commission (IPUC), the regulatoryauthority having principal jurisdiction, IPC's deferred income taxes (commonlyreferred to as normalized accounting) are provided for the difference betweenincome tax depreciation and straight-line depreciation computed using booklives on coal-fired generation facilities and properties acquired after 1980. On other facilities, deferred income taxes are provided for the differencebetween accelerated income tax depreciation and straight-line depreciationusing tax guideline lives on assets acquired prior to 1981.  Deferred incometaxes are not provided for those income tax timing differences where theprescribed regulatory accounting methods do not provide for current recovery inrates.  Regulated enterprises are required to recognize such adjustments asregulatory assets or liabilities if it is probable that such amounts will berecovered from or returned to customers in future rates.  See Note 2 for moreinformation.

The State of Idaho allows a three-percent investment tax credit on qualifying plant additions. Investment tax credits earned on regulated assets are deferred and amortized toincome over the estimated service lives of the related properties.  Creditsearned on non-regulated assets or investments are recognized in the yearearned.

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**Earnings Per Share**The following table presents thecomputation of IDACORP's basic and diluted earnings per common share (inthousands, except for per share amounts):

** **

**Year ended December 31,**

** **

**2006**

** **

**2005**

** **

**2004**

Numerator:

Income from continuing  operations

$

100,075

$

85,716

$

80,781

Denominator:

Weighted-average shares  outstanding - basic*

42,713

42,279

38,361

Effect of dilutive  securities:

Options

93

49

57

Restricted Stock

68

34

2

Weighted-average shares  outstanding - diluted

42,874

42,362

38,420

Basic earnings per share  from continuing operations

$

2.34

$

2.03

$

2.10

Diluted earnings per share  from continuing operations

$

2.34

$

2.02

$

2.10

*Weighted average shares  outstanding excludes non-vested shares issued under stock compensation plans.

The diluted EPS computationexcluded 538,950 options in 2006, 1,014,437 in 2005, and 818,600 in 2004because the options' exercise prices were greater than the average market priceof the common stock during those years.  In total, 840,888 options wereoutstanding at December 31, 2006, with expiration dates between 2010 and 2015.

**Stock-Based Compensation**Effective January 1, 2006, IDACORPand IPC adopted SFAS No. 123 (revised 2004), *"Share-Based Payment"* (SFAS123(R)) using the modified prospective application method.  SFAS 123(R) changesmeasurement, timing and disclosure rules relating to share-based payments,requiring that the fair value of all share-based payments be expensed.  Theadoption of SFAS 123(R) did not have a material impact on IDACORP's or IPC'sfinancial statements for the year ended December 31, 2006.

IDACORP's and IPC'sConsolidated Statements of Income for the years ended December 31, 2005 and2004 do not reflect any changes from the adoption of SFAS 123(R).  In thoseyears, stock based employee compensation was accounted for under therecognition and measurement principles of Accounting Principles Board (APB)Opinion 25, *"Accounting for Stock Issued to Employees,"* and relatedinterpretations.

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The following tableillustrates what net income and earnings per share would have been had the fairvalue recognition provisions of SFAS 123 been applied to stock-based employeecompensation in 2005 and 2004 (in thousands of dollars, except for per shareamounts):

**2005**

** **

**2004**

**IDACORP:**

Net income, as reported

$

63,661

$

72,983 

Add: Stock-based employee  compensation expense

included in reported net  income, net of related tax effects

359

399 

Deduct: Stock-based  employee compensation expense determined

under fair value based  method for all awards, 

net of related tax effects

1,214

1,169 

Pro forma net income

$

62,806

$

72,213 

EPS of common stock:

Basic - as reported

$

1.51 

$

1.90 

Diluted - as reported

1.50 

1.90 

Basic - pro forma

1.49 

1.88 

Diluted - pro forma

1.48 

1.88 

** **

** **

**IPC**

** **

Net income, as reported

$

71,839 

$

70,608 

Add: Stock-based employee  compensation expense included in

 reported net income, net  of related tax effects

108 

276 

Deduct:  Stock-based employee compensation expense determined

under  fair value based method for all awards,  

net  of related tax effects

568 

977 

Pro forma net income

$

71,379 

$

69,907 

For purposes of these proforma calculations, the estimated fair value of the options, restricted stockand performance shares is amortized to expense over the vesting period.  Thefair value of the restricted stock and performance shares is the market priceof the stock on the date of grant.  The fair value of an option award is estimatedat the date of grant using a binomial option-pricing model.  Expense related toforfeited options is reversed in the period in which the forfeit occurs.  

**Comprehensive Income**Comprehensive income includes netincome, unrealized holding gains and losses on marketable securities, IPC'sproportionate share of unrealized holding gains and losses on marketablesecurities held by an equity investee and amounts related to pension plans.  In2006, IDACORP adopted SFAS 158 "*Accounting for Pension and PostretirementCosts - an amendment of FAS 87, 88, 106,  and 132(R)"*which required thecompany to record additional amounts related to pension plans in othercomprehensive income.  SFAS 158 is discussed in more detail in Note 9.  Priorto December 2005, other comprehensive income included the additional minimumliability related to a deferred compensation plan for certain senior managementemployees and directors.  The following table presents IDACORP's and IPC'saccumulated other comprehensive loss balance at December 31:

**2006**

** **

**2005**

**(thousands of dollars)**

Unrealized holding gains on  securities

$

1,311 

$

2,725 

Defined benefit pension  plans

(7,048)

(6,150)

Total

$

(5,737)

$

(3,425)

**Other Accounting Policies**Debt discount, expense and premium aredeferred and being amortized over the terms of the respective debt issues.

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**Reclassifications**Certain items previously reported foryears prior to 2006 have been reclassified to conform to the current year'spresentation.  Net income and shareholders' equity were not affected by thesereclassifications.

**New AccountingPronouncementsFIN 48:**In June 2006, the FinancialAccounting Standards Board (FASB) issued FASB Interpretation No. 48, *"Accountingfor Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109*"(FIN 48), to create a single model to address accounting for uncertainty in taxpositions.  FIN 48 prescribes a minimum recognition threshold that a taxposition is required to meet before being recognized in a company's financialstatements and also provides guidance on derecognition, measurement,classification, interest and penalties, accounting in interim periods,disclosure, and transition.  FIN 48 is effective for fiscal years beginningafter December 15, 2006.

IDACORP and IPC will adoptFIN 48 in the first quarter of 2007, as required.  The cumulative effect ofadopting FIN 48 will be recorded as an adjustment to 2007 opening retainedearnings.  IDACORP and IPC have not yet completed their evaluation of theeffects the adoption of FIN 48 will have on their financial positions orresults of operations.

**SFAS157:**  In September 2006, the FASBissued SFAS 157*, "Fair Value Measurements."*  SFAS 157 defines fairvalue, establishes a framework for measuring fair value in generally acceptedaccounting principles, and expands disclosures about fair value measurements. SFAS 157 is effective for financial statements issued for fiscal yearsbeginning after November 15, 2007, and interim periods within those fiscalyears.  IDACORP and IPC are currently evaluating the impact of adopting SFAS157 on their financial statements.****

**SFAS 159:**  In February 2007, the FASB issued SFAS No. 159, *"TheFair Value Option for Financial Assets and Financial Liabilities - Including anAmendment of FASB Statement No. 115"*(SFAS 159).  This standard permits anentity to choose to measure many financial instruments and certain other itemsat fair value.  Most of the provisions in SFAS 159 are elective; however, theamendment to SFAS No. 115, *"Accounting for Certain Investments in Debt andEquity Securities,"* applies to all entities with available-for-sale andtrading securities.  The fair value option established by SFAS 159 permits allentities to choose to measure eligible items at fair value at specifiedelection dates.  A business entity will report unrealized gains and losses onitems for which the fair value option has been elected in earnings at eachsubsequent reporting date.  The fair value option: (a) may be appliedinstrument by instrument, with a few exceptions, such as investments otherwiseaccounted for by the equity method; (b) is irrevocable (unless a new electiondate occurs); and (c) is applied only to entire instruments and not to portionsof instruments.  SFAS 159 is effective as of the beginning of an entity's firstfiscal year that begins after November 15, 2007.  Early adoption is permittedas of the beginning of the previous fiscal year provided that the entity makesthat choice in the first 120 days of that fiscal year and also elects to apply theprovisions of SFAS No. 157, *"Fair Value Measurements." *IDACORP and IPCare currently evaluating the impact of SFAS 159.

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**2. INCOME TAXES:**

Areconciliation between the statutory federal income tax rate and the effectivetax rate is as follows:

** **

**IDACORP**

** **

**IPC**

** **

**2006**

** **

**2005**

** **

**2004**

** **

**2006**

** **

**2005**

** **

**2004**

** **

**(thousands of dollars)**

Federal income tax expense at 

35% statutory rate

$

40,408 

$

36,165 

$

21,291 

$

48,262 

$

 40,517 

$

26,928 

Change in taxes resulting from:

AFDC

(3,542)

(2,709)

(2,400)

(3,542)

(2,709)

(2,400)

Investment tax credits

(3,513)

(3,424)

(3,295)

(3,513)

(3,424)

(3,295)

Repair allowance

(2,450)

(1,750)

(2,450)

(2,450)

(1,750)

(2,450)

Removal costs

(1,912)

(1,490)

(1,244)

(1,912)

(1,490)

(1,244)

Pension accrual

1,902 

1,276 

1,237 

1,902 

1,276 

1,237

Capitalized overhead costs

(2,940)

-

(3,658)

(2,940)

-

(3,658)

Tax accounting method change

6,122 

-

-

6,122 

-

-

Regulatory tax liability

-

-

(16,457)
  -
-

(16,457)

Settlement of prior years' tax 

returns

(7,465)

-

(1,749)

(8,144)

-

(1,749)

State income taxes, net of 

federal benefit

5,287 

5,399 

3,461 

6,501 

6,173 

4,100 

Depreciation

5,757 

5,603 

4,350 

5,757 

5,603 

4,350 

Affordable housing and 

historic tax credits 

(19,218)

(20,205)

(21,717)

-

-

-

Preferred dividends of IPC

-

-

1,688 

-

-

-

Other, net

(3,059)

(1,255)

992 

(2,082)

(271)

966 

Total income tax expense (benefit)

$

15,377 

$

17,610 

$

(19,951)

$

43,961 

$

43,925 

$

6,328 

Effective tax rate

13.3%

17.0%

(32.8%)

31.9%

37.9%

8.2%

Theitems comprising income tax expense are as follows:

** **

**IDACORP**

** **

**IPC**

** **

**2006**

** **

**2005**

** **

**2004**

** **

**2006**

** **

**2005**

** **

**2004**

** **

**(thousands of dollars)**

Income taxes currently payable:

Federal

$

28,712

$

42,236 

$

10,621 

$

52,142 

$

69,479 

$

19,003 

State

4,254

8,097 

3,949 

5,293 

9,176 

7,317 

Total

32,966

50,333 

14,570 

57,435 

78,655 

26,320 

Income taxes deferred:

Federal

(17,379)

(29,534)

(31,147)

(14,161)

(31,599)

(15,488)

State

(537)

(5,139)

(2,421)

360

(5,081)

(3,551)

Total

(17,916)

(34,673)

(33,568)

(13,801)

(36,680)

(19,039)

Investment tax credits:

Deferred

3,840 

5,374 

2,342 

3,840  

5,374 

2,342 

Restored

(3,513)

(3,424)

(3,295)

(3,513)

(3,424)

(3,295)

Total

327 

1,950 

(953)

327 

1,950 

(953)

Total income tax expense (benefit)

$

15,377 

$

17,610 

$

(19,951)

$

43,961 

$

43,925 

$

6,328 

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Thecomponents of the net deferred tax liability are as follows:

** **

**IDACORP**

** **

**IPC**

** **

**2006**

** **

**2005**

** **

**2006**

** **

**2005**

** **

**(thousands of dollars)**

Deferred tax assets:

Regulatory liabilities

$

41,825

$

41,627

$

41,825

$

41,627

Advances  for construction

9,212

6,881

9,212

6,881

Deferred  compensation

15,295

15,115

14,381

13,276

Emission  allowances

12,175

27,380

12,175

27,380

Partnership  investments

308

-

308

-

Retirement  benefits

26,392

-

26,392

-

Tax  credits

27,807

26,715

-

-

Other

16,863

16,122

13,154

14,496

Total

149,877

133,840

117,447

103,660

Deferred  tax liabilities:

Property,  plant and equipment

230,361

240,144

230,361

240,144

Regulatory  assets

343,590

346,117

343,590

346,117

Conservation  programs

4,437

5,705

4,437

5,705

PCA

8,384

17,410

8,384

17,410

Partnership  investments

13,656

18,768

-

3,892

Retirement  benefits

18,055

-

18,055

-

Other

1,871

1,337

1,871

1,336

Total

620,354

629,481

606,698

614,604

Net  deferred tax liabilities

$

470,477

$

495,641

$

489,251

$

510,944

** **

IDACORP's tax allocation agreementprovides that each member of its consolidated group compute its income taxes ona separate company basis.  Amounts payable or refundable are settled throughIDACORP.

**Status of auditproceedings**In March 2005, the Internal RevenueService (IRS) began its examination of IDACORP's 2001-2003 tax years.  OnOctober 13, 2006, the IRS issued its examination report and assessment forthose years.  With the exception of IPC's capitalized overhead costs method,discussed below, the IRS and IDACORP were able to settle all issues.  The $1.6million federal tax assessment for the settled issues was paid in November2006.  Interest charges and state income taxes have been accrued and areexpected to be paid during 2007.  Settlement of the agreed issues decreased2006 income tax expense by $5.6 million at IDACORP and $6.2 million at IPC asthe assessed deficiency was less than amounts previously accrued.

The IRS disallowed IPC'scapitalized overhead cost method for uniform capitalization (the simplifiedservice cost method) on the basis that IPC's self-constructed assets were notproduced on a "routine and repetitive" basis as defined by Rev. Rul. 2005-53. The disallowance resulted in a federal tax assessment of $45 million.  InNovember 2006 IDACORP filed a formal protest and request for an appealsconference.  Also in November 2006, IDACORP made a refundable deposit of thedisputed tax with the IRS to stop the accrual of interest.  In December 2006,the IRS examination team filed its rebuttal to IDACORP's protest.  In January2007, IDACORP was notified that its case has been assigned to the IRS AppealsOffice.  IDACORP cannot predict the timing or outcome of this process, butbelieves that an adequate provision for income taxes and related interestcharges has been made for this issue.

The simplified service costmethod was also used for IPC's 2004 tax year.  While 2004 is not currentlyunder examination, it is likely the IRS will take the same position for 2004 asit did for 2001-2003; however, it is not likely that this position will resultin a federal income tax assessment primarily due to the mitigating effect ofaccelerated tax depreciation.

On July 7, 2006, the IRSissued its examination report for Bridger Coal Company's 2001-2003 tax years. Bridger Coal is a partnership investment owned one-third by IPC.  The auditresulted in net favorable adjustments to Bridger Coal's tax returns for thoseyears.  As a result of the settlement, IDACORP and IPC were able to decrease2006 income tax expense by $1.9 million.

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In 2004, IDACORP completedsettlement of all issues related to the IRS's examination of its federal incometax returns for the years 1998 through 2000.  Concurrently, IPC settled federalincome tax deficiencies for the years 1999 and 2000 related to its partnershipinvestment in the Bridger Coal Company.  Applicable state tax return amendmentswere completed in 2004 and settled.  Finalization of these examinationsresulted in deficiencies that were less than previously accrued, enablingIDACORP to decrease income tax expense by $1.7 million in 2004.

**Capitalized overhead costs**Generally, section 263A of theInternal Revenue Code of 1986, as amended, requires the capitalization of alldirect costs and indirect costs, including mixed service costs, which directlybenefit 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 themethods provided by the section 263A treasury regulations for the calculationof mixed service cost capitalization.  IPC adopted the simplified service costmethod for both the self-construction of utility plant and production ofelectricity beginning with its 2001 federal income tax return.

On August 2, 2005, the IRSand the Treasury Department issued guidance interpreting the meaning of "routineand repetitive" for purposes of the simplified service cost and simplifiedproduction methods of the Internal Revenue Code section 263A uniformcapitalization 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 toAugust 2, 2005, and proposed and temporary regulations (the "TemporaryRegulations") which are effective for tax years ending on or after August 2,2005.  Both pieces of guidance take a more restrictive view of the definitionof 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 thesimplified service cost method.

For IPC, the simplifiedservice cost method produced a current tax deduction for costs capitalized toelectricity production that are capitalized into fixed assets for financialaccounting purposes.  Deferred income tax expense had not been provided for thisdeduction because the prescribed regulatory tax accounting treatment does notallow for inclusion of such deferred tax expense in current rates.  Rateregulated enterprises are required to recognize such adjustments as regulatoryassets if it is probable that such amounts will be recovered from customers infuture rates.

As discussed in "Status ofAudit Proceedings" above, the IRS has disallowed IPC's use of the simplifiedservice 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 is inthe process of appealing the IRS's assessment.  Because of the nature of theissue, IDACORP's exposure with respect to this matter may be less than the taxassessed plus applicable interest charges.  Additionally, after resolutionIDACORP will likely amend its 2005 federal income tax return and its 2005method change application to account for the effects that such resolution hason IPC's new uniform capitalization method (discussed below).  This amendmentis not expected to have a material negative impact on IDACORP's or IPC'sconsolidated financial position, results of operations, or cash flows.

With respect to tax year 2005and future tax years, the Temporary Regulations, as drafted, preclude IPC fromusing the simplified service cost method for its self-constructed assets. Under the Temporary Regulations, IPC is required to use another allowablesection 263A method for its indirect costs, including mixed service costs.  Asa result of the Temporary Regulations, IPC made changes to its overall section263A uniform capitalization method of accounting.  In September 2006, thechanges were adopted with an automatic method change request included inIDACORP's 2005 federal income tax return.  The uniform capitalizationmethodology adopted for 2005 and subsequent years involves the use of thespecific identification, burden rate, and step-allocation methods ofaccounting.  The methods used are allowable under both the final and temporarysection 263A regulations.

As with the simplifiedservice cost method, the new uniform capitalization methodology produces anannual tax deduction for costs that are not required to be capitalized undersection 263A as well as costs capitalized into the production of electricity. The method, while producing a beneficial result, is not as favorable as thesimplified service cost method.  Changing the uniform capitalization methodresulted in a net charge to IPC's 2006 income tax expense of $6.1 million.  Theestimated 2006 tax deduction produced a $3.3 million tax benefit for the year. The change in method did not have a material effect on IDACORP's or IPC's 2006cash flows.  The accounting and regulatory treatment for the new method is thesame as previously used for the simplified service cost method.

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Table of Contents

**Regulatory Settlement**In 2004, IPC and the IPUC finalizedan income tax issue from IPC's 2003 Idaho general rate case.  The issueconcerned the regulatory accounting treatment for the capitalized overhead taxmethod IPC adopted in the 2001 IDACORP federal income tax return.  As a resultof the settlement, a $16 million regulatory tax liability was reversed,creating a benefit in 2004. 

**Tax Credits Carrryforwards**As of December 31, 2006, IDACORP had$21.3 million of general business credit carryforward for federal income taxpurposes and $5.9 million of Idaho investment tax credit carryforward.  Thegeneral business credit carryforward period expires from 2025 to 2026 and the Idaho investment tax credit expires from 2019 to 2020.

**3.  COMMON STOCK:**

**IDACORP**The following table summarizes****commonstock issued and reserved:

**Shares issued**

**Shares reserved at**

**2006**

**2005**

**2004**

**December 31, 2006**

Dividend reinvestment and  stock purchase plan

145,508

146,684

-

3,433,006

Employee savings plan

99,248

56,569

-

2,181,299

Restricted stock plan

-

-

-

314,114

Long-term incentive and  compensation plan

467,791

79,383

7,400

2,545,426

Continuous equity program

536,518

-

-

1,963,482

Public offering

-

-

4,025,000

-

Total

1,249,065

282,636

4,032,400

10,437,327

** **

On December 15, 2005, IDACORPentered into a Sales Agency Agreement with BNY Capital Markets, Inc. (BNYCMI). Under the terms of the Sales Agency Agreement, IDACORP may offer and sell up to2,500,000 shares of its common stock, from time to time in at the marketofferings through BNYCMI, as IDACORP's agent for such offer and sale.  In thefourth quarter of 2006, IDACORP issued 536,518 shares of common stock in at themarket offerings at an average price of $39.24 per share.

On January 1, 2006, IDACORPadopted SFAS 123(R), which requires that any amounts of unearned stock-basedcompensation be charged against common equity.  Prior to January 1, 2006,IDACORP had aggregated its unearned compensation balances with treasury stockon its consolidated balance sheets.

**Shareholder Rights Plan: **IDACORP has a Shareholder Rights Plan (Plan) designedto ensure that all shareholders receive fair and equal treatment in the eventof any proposal to acquire control of IDACORP.  Under the Plan, IDACORPdeclared a distribution of one Preferred Share Purchase Right (Right) for eachof its outstanding common shares held on October 1, 1998 or issued thereafter. The Rights are currently not exercisable and will be exercisable only if aperson or group (Acquiring Person) either acquires ownership of 20 percent ormore of IDACORP's voting stock or commences a tender offer that would result inownership of 20 percent or more of such stock.  IDACORP may redeem all, but notless than all, of the Rights at a price of $0.01 per Right or exchange theRights for cash, securities (including common shares of IDACORP) or otherassets at any time prior to the close of business on the tenth day afteracquisition by an Acquiring Person of a 20 percent or greater position.

Additionally, the IDACORPBoard of Directors created the A Series Preferred Stock, without par value, andreserved 1,200,000 shares for issuance upon exercise of the Rights.

Following the acquisition ofa 20 percent or greater position, each Right will entitle its holder topurchase, for $95, that number of shares of common stock or preferred stockhaving a market value of $190.  If after the Rights become exercisable, IDACORPis acquired in a merger or other business combination, 50 percent or more ofits consolidated assets or earnings power are sold, or the Acquiring Personengages in certain acts of self-dealing, each Right entitles the holder topurchase, for $95, shares of the acquiring company's common stock having a marketvalue of $190.  Any Rights that are or were held by an Acquiring Person becomevoid if any of these events occurs.  The Rights expire on September 30, 2008.

TheRights themselves do not give their holders any voting or other rights asshareholders.  The terms of the Rights may be amended without the approval ofany holders of the Rights until an Acquiring Person obtains a 20 percent orgreater position, and then may be amended as long as the amendment is notadverse to the interests of the holders of the Rights.

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**Dividend Restrictions:**IPC's articles of incorporation contain restrictionson the payment of dividends on its common stock if preferred stock dividendsare in arrears.  On September 20, 2004, IPC redeemed all of its outstandingpreferred stock.  Also, certain provisions of credit facilities containrestrictions on the ratio of debt to total capitalization.

IPC must obtain the approvalof the Oregon Public Utility Commission (OPUC) before it could directly orindirectly loan funds or issue notes or give credit on its books to IDACORP.

**IPC**In December 2006, IDACORP contributed$47 million of additional equity to IPC.  No additional shares of IPC commonstock were issued.

**4.  LONG-TERM DEBT**

The following tablesummarizes long-term debt at December 31:

**2006**

** **

**2005**

**(thousands of dollars)**

First  mortgage bonds:

7.38%     Series due 2007

$

80,000 

$

80,000 

7.20%     Series due 2009

80,000 

80,000 

6.60%     Series due 2011

120,000 

120,000 

4.75%     Series due 2012

100,000 

100,000 

4.25%     Series due 2013

70,000 

70,000 

6%          Series due 2032

100,000 

100,000 

5.50%     Series due 2033

70,000 

70,000 

5.50%     Series due 2034

50,000 

50,000 

5.875%   Series due 2034

55,000 

55,000 

5.30%     Series due 2035

60,000 

60,000 

Total  first mortgage bonds

785,000 

785,000 

Pollution  control revenue bonds:

Variable  Auction Rate Series 2003 due 2024 (a)

49,800 

49,800 

Variable  Auction Rate Series 2006 due 2026 (a)

116,300 

- 

6.05%     Series 1996A due 2026

- 

68,100 

Variable  Rate Series 1996B due 2026

- 

24,200 

Variable  Rate Series 1996C due 2026

- 

24,000 

Variable  Rate Series 2000 due 2027

4,360 

4,360 

Total  pollution control revenue bonds

170,460 

170,460 

American   Falls bond guarantee

19,885 

19,885 

Milner  Dam note guarantee

11,700 

11,700 

Unamortized  premium (discount) - net

(3,097)

(3,325)

Debt  related to investments in affordable housing

32,331 

48,481 

Other  subsidiary debt

7,494 

7,686 

Less:  Liabilities held for sale

- 

(35)

Total

1,023,773 

1,039,852 

Current  maturities of long-term debt

(95,125)

(16,307)

Total  long-term debt

$

928,648 

$

1,023,545 

(a)

Humboldt County and  Sweetwater County Pollution Control Revenue bonds are secured by first  mortgage bonds, bringing the total first mortgage bonds outstanding at  December 31, 2006, to $951.1 million.

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At December 31, 2006, thematurities for the aggregate amount of long-term debt outstanding were (inthousands of dollars):

** **

**2007**

**2008**

**2009**

**2010**

**2011**

**Thereafter**

IPC 

$

81,064

$

1,064

$

81,064

$

1,064

$

121,064

$

701,725

Other subsidiary debt

14,061

10,392

5,657

2,965

220

6,530

Total

$

95,125

$

11,456

$

86,721

$

4,029

$

121,284

$

708,255

At December 31, 2006 and2005, the overall effective cost of IPC's outstanding debt was 5.71 percent and5.84 percent, respectively.

On October 3, 2006, IPCcompleted a tax-exempt bond financing in which Sweetwater County, Wyomingissued and sold $116.3 million aggregate principal amount of its PollutionControl Revenue Refunding Bonds 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.  On October 10, 2006, the proceeds of the new bonds, togetherwith certain other moneys of IPC, were used to refund Sweetwater County'sPollution Control Revenue Refunding Bonds Series 1996A, Series 1996B and Series1996C totaling $116.3 million.  The regularly scheduled principal and interestpayments on the Series 2006 bonds, and principal and interest payments on thebonds upon mandatory redemption on determination of taxability, are insured bya 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 premiumsto AMBAC and to reimburse AMBAC for any payments made under the policy.  Tosecure its obligation to make principal and interest payments on the loan madeto IPC, IPC issued and delivered to a trustee IPC's First Mortgage Bonds,Pollution Control Series C, in a principal amount equal to the amount of thenew bonds.

AtDecember 31, 2006, IFS had $32 million of debt related to investments inaffordable housing.  This debt had interest rates ranging from 3.65 percent to8.38 percent and is due between 2007 and 2010.  This debt is collateralized byinvestments in affordable housing developments with a net book value of $59million at December 31, 2006.  Of this $32 million in debt, $11 million isnon-recourse to both IFS and IDACORP and the remainder is recourse only toIFS.  IFS also has $5 million of debt related to a limited partnershipinvestment.  This debt is non-recourse to IDACORP, personally guaranteed by thegeneral partner, and collateralized by property.

**Long-Term Financing**IDACORP has $658 million remaining ontwo shelf registration statements that can be used for the issuance ofunsecured debt (including medium-term notes) and preferred or common stock. IPC has in place a registration statement that can be used for the issuance ofan aggregate principal amount of $240 million of first mortgage bonds(including medium-term notes) and unsecured debt.

In January 2007, the IPCBoard of Directors approved an increase of the maximum amount of first mortgagebonds issuable by IPC to $1.5 billion.  The amount issuable is also restrictedby property, earnings and other provisions of the mortgage and supplementalindentures to the mortgage.  IPC may amend the indenture and increase thisamount without consent of the holders of the first mortgage bonds.  Theindenture requires that IPC's net earnings must be at least twice the annualinterest requirements on all outstanding debt of equal or prior rank, includingthe bonds that IPC may propose to issue.  Under certain circumstances, the netearnings test does not apply, including the issuance of refunding bonds toretire outstanding bonds that mature in less than two years or that are of anequal or higher interest rate, or prior lien bonds.

As of December 31, 2006, IPCcould issue under the mortgage approximately $559 million of additional firstmortgage bonds based on unfunded property additions and $452 million ofadditional first mortgage bonds based on retired first mortgage bonds.  AtDecember 31, 2006, unfunded property additions were approximately $1.0 billion.

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

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The mortgage secures all bonds issued under theindenture equally and ratably, without preference, priority or distinction. IPC may issue additional first mortgage bonds in the future, and those firstmortgage bonds will also be secured by the mortgage.  The lien of the indentureconstitutes a first mortgage on all the properties of IPC, subject only tocertain limited exceptions including liens for taxes and assessments that arenot delinquent and minor excepted encumbrances.  Certain of the properties ofIPC are subject to easements, leases, contracts, covenants, workmen'scompensation awards and similar encumbrances and minor defects and cloudscommon to properties.  The mortgage does not create a lien on revenues orprofits, or notes or accounts receivable, contracts or choses in action, exceptas permitted by law during a completed default, securities or cash, except whenpledged, or merchandise or equipment manufactured or acquired for resale.  Themortgage creates a lien on the interest of IPC in property subsequentlyacquired, other than excepted property, subject to limitations in the case ofconsolidation, merger or sale of all or substantially all of the assets of IPC.

**5. FAIR VALUE OF FINANCIAL INSTRUMENTS:**

Theestimated fair value of IDACORP's financial instruments has been determinedusing available market information and appropriate valuation methodologies. The use of different market assumptions and/or estimation methodologies mayhave a material effect on the estimated fair value amounts.

Cashand cash equivalents, customer and other receivables, notes payable, accountspayable, interest accrued and taxes accrued are reported at their carryingvalue as these are a reasonable estimate of their fair value.  The estimatedfair values for notes receivable, long-term debt and investments are based uponquoted market prices of the same or similar issues or discounted cash flowanalyses as appropriate.

**December 31, 2006**

**December 31, 2005**

**Carrying**

** **

**Estimated**

** **

**Carrying**

** **

**Estimated**

**Amount**

** **

Fair Value

** **

**Amount**

** **

**Fair Value**

** **

**(thousands of dollars)**

**IDACORP**

**Assets:**

Notes receivable

$

8,431

$

8,257

$

7,049

$

6,879

Investments 

39,109

39,074

34,510

34,514

**Liabilities:**

Long-term debt

$

1,026,870

$

1,018,250

$

1,043,248

$

1,059,199

**IPC**

**Assets:**

Notes receivable

$

5,853

$

5,679

$

7,047

$

6,876

Investments 

28,040

28,040

21,137

21,137

**Liabilities:**

Long-term debt

$

987,045

$

978,491

$

987,045

$

1,003,651

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**6.  NOTES PAYABLE:**

IDACORP has a $150 millioncredit facility and IPC has a $200 million credit facility that both expire onMarch 31, 2010.  Commercial paper may be issued up to the amounts supported bythe bank credit facilities.  Under these facilities the companies pay afacility fee on the commitment, quarterly in arrears, based on its rating forsenior unsecured long-term debt securities without third-party creditenhancement as provided by Moody's and S&P.  At December 31, 2006, IPC hadregulatory authority to incur up to $250 million of short-term indebtedness. Balances and interest rates of IDACORP's short-term borrowings were as followsat December 31 (in thousands of dollars):
   
**IDACORP**

**IPC**

**Total**

 
**2006**

**2005**

**2006**

**2005**

**2006**

**2005**

 

**(thousands of dollars)**

** **
**Balances:**

 
At the end of year

$ 76,800

$ 60,100

$ 52,200

$          	-

$ 129,000

$ 60,100

Average during the year

$ 43,351

$ 53,030

$ 14,211

$       123

$   57,562

$ 53,153

 
**Weighted-average  interest rate:**

 
At the end of year

5.48%

4.47%

5.50%

-

5.49%

4.47%

 
Average during the year

5.05%

3.49%

5.50%

3.83%

5.15%

3.49%

 
**7.  COMMITMENTS ANDCONTINGENCIES:**

**Purchase Obligations:**As of December 31, 2006, IPC hadagreements to purchase energy from 92 cogeneration and small power production(CSPP) facilities with contracts ranging from one to 30 years.  Under thesecontracts IPC is required to purchase all of the output from the facilitiesinside the IPC service territory.  For projects outside the IPC serviceterritory, IPC is required to purchase the output that it has the ability toreceive at the facility's requested point of delivery on the IPC system.  IPC purchased911,132 megawatt-hours (MWh) at a cost of $54 million in 2006, 715,209 MWh at acost of $46 million in 2005 and 677,868 MWh at a cost of $40 million in 2004.

At December 31, 2006, IPC hadthe following long-term commitments relating to purchases of energy, capacity,transmission rights and fuel:

** **

**2007**

2008

**2009**

**2010**

**2011**

**Thereafter**

**(thousands of dollars)**

Cogeneration and small

 power production

$

45,130

$

76,538

$

76,538

$

79,830

$

79,830

$

1,064,718

Power and transmission

rights

80,175

16,351

7,390

2,781

2,754

13,315

Fuel

54,395

30,035

28,885

2,941

3,821

11,005

In addition, IDACORP has thefollowing long-term commitments for lease guarantees, maintenance and services,and industry related fees.

**2007**

2008

**2009**

**2010**

**2011**

**Thereafter**

**(thousands of dollars)**

Operating leases

$

4,531

$

4,666

$

3,008

$

2,059

$

1,008

$

8,991

Maintenance and service

agreements

36,550

7,552

3,240

1,490

1,320

7,523

FERC and other industry

related fees

3,970

4,008

4,008

3,970

3,970

19,926

IDACORP's expense foroperating leases was approximately $4 million, $4 million and $5 million in2006, 2005 and 2004, respectively.

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** **

**Guarantees**IPC has agreed to guarantee theperformance of reclamation activities at Bridger Coal Company of which IdahoEnergy Resources Co., a subsidiary of IPC, owns a one-third interest.  Thisguarantee, which is renewed each December, was $60 million at December 31,2006.  Bridger Coal Company has a reclamation trust fund set aside specificallyfor the purpose of paying these reclamation costs.  Bridger Coal Company andIPC expect that the fund will be sufficient to cover all such costs.  Becauseof the existence of the fund, the estimated fair value of this guarantee isminimal.

**Legal Proceedings**From time to time IDACORP and IPC area party to legal claims, actions and complaints in addition to those discussedbelow.  IDACORP and IPC believe that they have meritorious defenses to all lawsuitsand legal proceedings.  Although they will vigorously defend against them, theyare unable to predict with certainty whether or not they will ultimately besuccessful.  However, based on the companies' evaluation, they believe that theresolution of these matters, taking into account existing reserves, will nothave a material adverse effect on IDACORP's or IPC's consolidated financialpositions, results of operations or cash flows.

**Wah Chang:**  On May 5, 2004, Wah Chang, a division of TDYIndustries, Inc., filed two lawsuits in the U.S. District Court for theDistrict of Oregon against numerous defendants.  IDACORP, IE and IPC are namedas defendants in one of the lawsuits.  The complaints allege violations offederal antitrust laws, violations of the Racketeer Influenced and CorruptOrganizations Act, violations of Oregon antitrust laws and wrongfulinterference with contracts.  Wah Chang's complaint is based on allegationsrelating to the western energy situation.  These allegations include bid rigging,falsely creating congestion and misrepresenting the source and destination ofenergy.  The plaintiff seeks compensatory damages of $30 million and trebledamages.

On September 8, 2004, thiscase was transferred and consolidated with other similar cases currentlypending before the Honorable Robert H. Whaley sitting by designation in theU.S. District Court for the Southern District of California.  The companies'filed a motion to dismiss the complaint which the court granted on February 11,2005.  Wah Chang appealed the dismissal to the U.S. Court of Appeals for theNinth Circuit on March 10, 2005.  The Ninth Circuit set a briefing schedule onthe appeal, requiring Wah Chang's opening brief to be filed by July 6, 2005. On May 18, 2005, Wah Chang filed a motion to stay the appeal or in thealternative to voluntarily dismiss the appeal without prejudice toreinstatement.  The companies opposed the motion and filed a cross-motionasking the Court to summarily affirm the district court's order of dismissal. On July 8, 2005, the Ninth Circuit denied Wah Chang's motion and also deniedthe companies' motion for summary affirmance without prejudice to renewalfollowing the filing of Wah Chang's opening brief.  Wah Chang's opening briefwas filed on September 21, 2005.  On October 11, 2005 the companies, along withthe other defendants, filed a motion to consolidate this appeal with Wah Changv. Duke Energy Trading and Marketing currently pending before the NinthCircuit.  On October 18, 2005, the Ninth Circuit granted the motion toconsolidate and established a revised briefing schedule.  The companies filedan answering brief on November 30, 2005.  Wah Chang's reply brief was filed onJanuary 6, 2006.  The appeal has been fully briefed and oral argument is scheduledfor April 10, 2007.  The companies intend to vigorously defend their positionin this proceeding and believe this matter will not have a material adverseeffect on their consolidated financial positions, results of operations or cashflows.

**City of Tacoma:**  On June 7, 2004, the City of Tacoma, Washingtonfiled a lawsuit in the U.S. District Court for the Western District ofWashington at Tacoma against numerous defendants including IDACORP, IE andIPC.  The City of Tacoma's complaint alleges violations of the ShermanAntitrust Act.  The claimed antitrust violations are based on allegations ofenergy market manipulation, false load scheduling and bid rigging andmisrepresentation or withholding of energy supply.  The plaintiff seekscompensatory damages of not less than $175 million.

On September 8, 2004, thiscase was transferred and consolidated with other similar cases currentlypending before the Honorable Robert H. Whaley sitting by designation in theU.S. District Court for the Southern District of California.  The companies'filed a motion to dismiss the complaint which the court granted on February 11,2005.  The City of Tacoma appealed to the U.S. Court of Appeals for the NinthCircuit on March 10, 2005.

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On August 9, 2005, thecompanies moved for summary affirmance of the district court's order dismissingthe City of Tacoma's complaint.  The City of Tacoma filed a response to thecompanies' motion for summary affirmance on August 24, 2005.  The Ninth Circuitdenied the companies' motion for summary affirmance on November 3, 2005.  Theappeal has been fully briefed and oral argument is scheduled for April 10,2007.  The companies intend to vigorously defend their position in thisproceeding and believe this matter will not have a material adverse effect ontheir consolidated financial positions, results of operations or cash flows.

**Western Energy Proceedingsat the FERC:**California Power Exchange Chargeback:As a component of IPC's non-utilityenergy trading in the State of California, IPC, in January 1999, entered into aparticipation agreement with the California Power Exchange (CalPX), a California non-profit public benefit corporation.  The CalPX, at that time, operated awholesale electricity market in California by acting as a clearinghouse throughwhich electricity was bought and sold.  Pursuant to the participationagreement, IPC could sell power to the CalPX under the terms and conditions ofthe CalPX Tariff.  Under the participation agreement, if a participant in theCalPX defaulted on a payment, the other participants were required to pay theirallocated share of the default amount to the CalPX.  The allocated shares werebased upon the level of trading activity, which included both power sales andpurchases, of each participant during the preceding three-month period.

On January 18, 2001, theCalPX sent IPC an invoice for $2 million - a "default share invoice" - as aresult of an alleged Southern California Edison payment default of $215 millionfor power purchases.  IPC made this payment.  On January 24, 2001, IPCterminated its participation agreement with the CalPX.  On February 8, 2001,the CalPX sent a further invoice for $5 million, due on February 20, 2001, as aresult of alleged payment defaults by Southern California Edison, Pacific Gasand Electric Company and others.  However, because the CalPX owed IPC $11million for power sold to the CalPX in November and December 2000, IPC did notpay the February 8 invoice.  The CalPX later reversed IPC's payment of theJanuary 18, 2001 invoice, but on June 20, 2001 invoiced IPC for an additional$2 million.  The CalPX owed IPC $14 million for power sold in November andDecember including $2 million associated with the default share invoice datedJune 20, 2001.  IPC essentially discontinued energy trading with the CalPX andthe California Independent System Operator (Cal ISO) in December 2000.

IPC believed that the defaultinvoices were not proper and that IPC owed no further amounts to the CalPX. IPC pursued all available remedies in its efforts to collect amounts owed to itby the CalPX.  On February 20, 2001, IPC filed a petition with the FERC tointervene in a proceeding that requested the FERC to suspend the use of theCalPX chargeback methodology and provide for further oversight in the CalPX'simplementation of its default mitigation procedures.

A preliminary injunction wasgranted by a federal judge in the U.S. District Court for the Central Districtof California enjoining the CalPX from declaring any CalPX participant indefault under the terms of the CalPX Tariff.  On March 9, 2001, the CalPX filedfor Chapter 11 protection with the U.S. Bankruptcy Court, Central District ofCalifornia.

In April 2001, Pacific Gasand Electric Company filed for bankruptcy.  The CalPX and the Cal ISO wereamong the creditors of Pacific Gas and Electric Company.

The FERC issued an order onApril 6, 2001 requiring the CalPX to rescind all chargeback actions related toPacific Gas and Electric Company's and Southern California Edison'sliabilities.  Shortly after the issuance of that order, the CalPX segregatedthe CalPX chargeback amounts it had collected in a separate account.  The CalPXclaimed it would await further orders from the FERC and the bankruptcy courtbefore distributing the funds that it collected under its chargeback tariffmechanism.  On October 7, 2004, the FERC issued an order determining that itwould not require the disbursement of chargeback funds until the completion ofthe California refund proceedings.  On November 8, 2004, IE, along with anumber of other parties, sought rehearing of that order.  On March 15, 2005,the FERC issued an order on rehearing confirming that the CalPX was to continueto hold the chargeback funds, but solely to offset seller-specific shortfallsin the seller's CalPX account at the conclusion of the California refundproceeding.  Balances were to be returned to the respective sellers at theconclusion of a seller's participation in the refund proceeding.

Based upon the Offer ofSettlement filed with the FERC on February 17, 2006 between the CaliforniaParties and IE and IPC discussed below in "California Refund," the CaliforniaParties supported a motion filed by IE and IPC with the FERC seeking an OrderDirecting Return of Chargeback Amounts then held by the CalPX totaling $2.27million.  In the May 22, 2006 order approving the Settlement, the FERC grantedthe IE and IPC motion for return of chargeback funds held by the CalPX.  OnJune 1, 2006, IE received approximately $2.5 million from the CalPX representingthe return of $2.27 million in chargeback funds plus interest.

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California Refund:In April 2001, the FERC issued anorder stating that it was establishing price mitigation for sales in the California wholesale electricity market.  Subsequently, in a June 19, 2001, order, the FERCexpanded that price mitigation plan to the entire western United States electrically interconnected system.  That plan included the potential for ordersdirecting electricity sellers into California since October 2, 2000, to refundportions of their spot market sales prices if the FERC determined that thoseprices were not just and reasonable, and therefore not in compliance with theFederal Power Act.  The June 19 order also required all buyers and sellers inthe Cal ISO market during the subject time frame to participate in settlementdiscussions to explore the potential for resolution of these issues withoutfurther FERC action.  The settlement discussions failed to bring resolution ofthe refund issue and as a result, the FERC's Chief Administrative Law Judgesubmitted a Report and Recommendation to the FERC recommending that the FERCadopt the methodology set forth in the report and set for evidentiary hearingan analysis of the Cal ISO's and the CalPX's spot markets to determine whatrefunds may be due upon application of that methodology.

On July 25, 2001, the FERCissued an order establishing evidentiary hearing procedures related to thescope and methodology for calculating refunds related to transactions in thespot markets operated by the Cal ISO and the CalPX during the period October 2,2000, through June 20, 2001 (Refund Period).

The Administrative Law Judgeissued a Certification of Proposed Findings on California Refund Liability onDecember 12, 2002.

The FERC issued its Order on Proposed Findings on Refund Liability on March 26,2003.  In large part, the FERC affirmed the recommendations of itsAdministrative Law Judge.  However, the FERC changed a component of the formulathe Administrative Law Judge was to apply when it adopted findings of its staffthat published California spot market prices for gas did not reliably reflectthe prices a gas market, that had not been manipulated, would have produced,despite the fact that many gas buyers paid those amounts.  The findings of theAdministrative Law Judge, as adjusted by the FERC's March 26, 2003, order, wereexpected to increase the offsets to amounts still owed by the Cal ISO and theCalPX to the companies.  Calculations remained uncertain because (1) the FERChad required the Cal ISO to correct a number of defects in its calculations,(2) it was unclear what, if any, effect the ruling of the Ninth Circuit inBonneville Power Administration v. FERC, described below, might have on the ISO'scalculations, and (3) the FERC had stated that if refunds would prevent aseller from recovering its California portfolio costs during the Refund Period,it would provide an opportunity for a cost showing by such a respondent.

IE, along with a number of otherparties, filed an application with the FERC on April 25, 2003, seekingrehearing of the March 26, 2003, order.  On October 16, 2003, the FERC issuedtwo orders denying rehearing of most contentions that had been advanced anddirecting the Cal ISO to prepare its compliance filing calculating revisedMitigated Market Clearing Prices and refund amounts within five months.

Two avenues of activity haveproceeded on largely but not entirely independent paths, converging from timeto time.  The Cal ISO continued to work on its compliance refund calculationswhile the appellate litigation and litigation before the FERC regarding, amongother things, cost filings, fuel cost allowance offsets, emissions offsets,cost-based recovery offsets, and allocation methods continued.

Originally, the Cal ISO wasto complete its calculation within five months of the FERC's October 16, 2003,order.  The Cal ISO compliance filing has since been delayed numerous times.  TheCal ISO has been required to update the FERC on its progress monthly.  In itsmost recent status report, filed February 22, 2007, the Cal ISO reported thatit has completed publishing settlement statements reflecting the basic refundcalculations, and is currently in a "financial adjustment" phase, in which itcalculates adjustments to its refund data to account for fuel cost allowanceoffsets, emissions offsets, cost-based recovery offsets, and interest onamounts unpaid and refunds.  The Cal ISO estimates that it will takeapproximately 10 additional weeks to complete the financial adjustment phase,including applicable review and comment periods.  The Cal ISO estimates that itwill have completed its calculations by May 2007, subject to such additionaltime as may be required if unanticipated delays are encountered.  The potentialexpansion of the FERC refund proceedings due to the Ninth Circuit orders andthe disposition of additional settlements which the Ninth Circuit has announcedit expects to be filed at the FERC in the near future may affect the finalityof any Cal ISO calculations.  At present, IDACORP and IPC are not able topredict when the Ninth Circuit mandates may issue, how the FERC will proceed inconnection with the possible expansion of the proceedings, the nature andcontent of as yet un-filed settlements or the extent to which the Cal ISOcalculation process may be disrupted. 

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On December 2, 2003, IDACORPpetitioned the U.S. Court of Appeals for the Ninth Circuit for review of theFERC's orders, and since that time, dozens of other petitions for review havebeen filed.  The Ninth Circuit consolidated IE's and the other parties'petitions with the petitions for review arising from earlier FERC orders inthis proceeding, bringing the total number of consolidated petitions to morethan 100.  The Ninth Circuit held the appeals in abeyance pending thedisposition of the market manipulation claims discussed below and thedevelopment of a comprehensive plan to brief this complicated case.  Certainparties also sought further rehearing and clarification before the FERC.  OnSeptember 21, 2004, the Ninth Circuit convened case management proceedings, aprocedure reserved to help organize complex cases.  On October 22, 2004, theNinth Circuit severed a subset of the stayed appeals in order that briefingcould commence regarding cases related to: (1) which parties are subject to theFERC'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 transactions are subject to refunds.  Oral argument washeld on April 12-13, 2005.  On September 6, 2005, the Ninth Circuit issued adecision on the jurisdictional issues concluding that the FERC lacked refundauthority over wholesale electric energy sales made by governmental entitiesand non-public utilities.  On August 2, 2006, the Ninth Circuit issued itsdecision on the appropriate temporal reach and the type of transactions subjectto the FERC refund orders and concluded, among other things, that alltransactions at issue in the case that occurred within or as a result of theCalPX and the Cal ISO were the proper subject of refund proceedings; refused toexpand the refund proceedings into the bilateral markets including transactionswith the California Department of Water Resources; approved the refundeffective date as October 2, 2000, but also required the FERC to considerwhether refunds, including possibly market-wide refunds, should be required foran earlier time due to claims that some market participants had violatedgoverning tariff obligations (although the decision did not specify when thattime would start, the California Parties generally had sought further refundsstarting May 1, 2000); and effectively expanded the scope of the refund proceedingto transactions within the CalPX and Cal ISO markets outside the 24-hour spotmarket and energy exchange transactions.  The IDACORP settlement with theCalifornia Parties approved by the FERC on May 22, 2006, and discussed belowanticipated the possibility of such an outcome and attempted to provide thatthe consideration exchanged among the settling parties also encompass thesettling parties' claims in the event of such expansion of the proceedings.

The Ninth Circuitsubsequently issued orders deferring the time for seeking rehearing of itsorder and holding the consolidated petitions for review in abeyance for alimited time in order to create an opportunity for unusual mediationproceedings managed jointly by the Court Mediator and FERC officials.  TheNinth Circuit has since extended the deferral for the mediation effort.

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

On May 12, 2004, the FERCissued an order clarifying portions of its earlier refund orders and, amongother things, denying a proposal made by Duke Energy North America and DukeEnergy Trading and Marketing (and supported by IE) to lodge as evidence acontested settlement in a separate complaint proceeding, California PublicUtilities Commission (CPUC) v. El Paso, et al.  The CPUC's complaint allegedthat the El Paso companies manipulated California energy markets by withholdingpipeline transportation capacity into California in order to drive up naturalgas prices immediately before and during the California energy crisis in2000-2001.  The settlement will result in the payment by El Paso ofapproximately $1.69 billion.  Duke claimed that the relief afforded by thesettlement was duplicative of the remedies imposed by the FERC in its March 26,2003, order changing the gas cost component of its refund calculationmethodology.  IE, along with other parties, has sought rehearing of the May 12,2004, order.  On November 23, 2004, the FERC denied rehearing and within thestatutory time allowed for petitions, a number of parties, including IE, filedpetitions for review of the FERC's order with the Ninth Circuit.  Thesepetitions have since been consolidated with the larger number of reviewpetitions in connection with the California refund proceeding.

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On March 20, 2002, theCalifornia Attorney General filed a complaint with the FERC against varioussellers in the wholesale power market, including IE and IPC, alleging that theFERC's market-based rate requirements violate the Federal Power Act, and, evenif the market-based rate requirements are valid, that the quarterly transactionreports filed by sellers do not contain the transaction-specific informationmandated by the Federal Power Act and the FERC.  The complaint stated thatrefunds for amounts charged between market-based rates and cost-based ratesshould be ordered.  The FERC denied the challenge to market-based rates andrefused to order refunds, but did require sellers, including IE and IPC, torefile their quarterly reports to include transaction-specific data.  TheAttorney General appealed the FERC's decision to the U.S. Court of Appeals forthe Ninth Circuit.  The Attorney General contends that thefailure of all market-based rate authority sellers of power to have rates onfile with the FERC in advance of sales is impermissible.  The Ninth Circuitissued its decision on September 9, 2004, concluding that market-based tariffsare permissible under the Federal Power Act, but remanding the matter to theFERC to consider whether the FERC should exercise remedial power (includingsome form of refunds) when a market participant failed to submit reports thatthe FERC relies on to confirm the justness and reasonableness of ratescharged.  On December 28, 2006, a number of sellers have filed a certioraripetition to the U.S. Supreme Court.  The U.S. Supreme Court has not yet actedon that petition.  On February 16, 2007, the Ninth Circuit announced that itwas continuing to withhold the mandate until April 27, 2007.

In June 2001, IPC transferredits non-utility wholesale electricity marketing operations to IE.  Effectivewith this transfer, the outstanding receivables and payables with the CalPX andthe Cal ISO were assigned from IPC to IE.  At December 31, 2005, with respectto the CalPX chargeback and the California refund proceedings discussed above,the CalPX and the Cal ISO owed $14 million and $30 million, respectively, forenergy sales made to them by IPC in November and December 2000.

On August 8, 2005, the FERCissued an Order establishing the framework for filings by sellers who electedto make a cost showing.  On September 14, 2005, IE and IPC made a joint costfiling, as did approximately thirty other sellers.  On October 11, 2005, the California entities filed comments on the IE and IPC cost filing and those made by otherparties.  IPC and IE submitted reply comments on October 17, 2005.  The California entities filed supplemental comments on October 24, 2005 and IPC and IE filedsupplemental reply comments on October 27, 2005.  

InDecember of 2005, IE and IPC reached a tentative agreement with the CaliforniaParties settling matters encompassed by the California Refund proceeding includingIE's and IPC's cost filing and refund obligation.  On January 20, 2006, theParties filed a request with the FERC asking that the FERC defer ruling on IE'sand IPC's cost filing for thirty days so the parties could complete and filethe settlement agreement with the FERC.  On January 26, 2006, the FERC grantedthe requested deferral of a ruling on the cost filing and required that thesettlement be filed by February 17, 2006.  On February 17, 2006, IE and IPCjointly filed with the California Parties (Pacific Gas & Electric Company,San Diego Gas & Electric Company, Southern California Edison, theCalifornia Public Utilities Commission, the California Electricity OversightBoard, the California Department of Water Resources and the California AttorneyGeneral) an Offer of Settlement at the FERC.  Other parties had until March 9,2006 to elect to become additional settling parties.  A number of parties,representing substantially less than the majority potential refund claims,chose to opt out of the settlement.

OnMarch 27, 2006, the FERC issued an order rejecting the IE/IPC cost filing andon April 26, 2006, IE and IPC sought rehearing of the rejection.  By order ofApril 27, 2006, the FERC tolled the time for what otherwise would have beenrequired by statute to be a decision on the request for rehearing.

OnMay 12, 2006, the FERC issued an order determining the method that should beused to allocate amounts approved in cost filings, approving the methodologythat IE and IPC and others had advocated prior to the time IE and IPC enteredinto the February 17, 2006 settlement - allocating cost offsets to buyers inproportion to the net refunds they are owed through the Cal ISO and CalPXmarkets.  On June 12, 2006, the California Parties requested rehearing, urgingthe FERC to allocate the cost offsets to all purchasers from the Cal ISO andCalPX markets and not just to that limited subset of purchasers who are netrefund recipients.  On July 12, 2006, the FERC tolled the time to act on therequest for rehearing and has not issued orders on rehearing since that time. IDACORP and IPC are unable to predict how or when the FERC might rule on therequest for rehearing.

Afterconsideration of comments, the FERC approved the February 17, 2006, Offer ofSettlement on May 22, 2006.  Under the terms of the settlement, IE and IPCassigned $24.25 million of the rights to accounts receivable from the Cal ISOand CalPX to the California Parties to pay into an escrow account for refundsto settling parties.  Amounts from that escrow not used for settling partiesand $1.5 million of the remaining IE and IPC receivables that are to beretained by the CalPX are available to fund, at least partially, payment of theclaims of any non-settling parties if they prevail in the remaining litigationof this matter.  Any excess funds remaining at the end of the case are to bereturned to IDACORP.  Approximately $10.25 million of the remaining IE and IPCreceivables was paid to IE and IPC under the settlement.

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OnJune 21, 2006, the Port of Seattle, Washington filed a request for rehearing ofthe FERC order approving the settlement.  On July 10, 2006, IPC and IE and theCalifornia Parties filed a response to Port of Seattle's request forrehearing.  On October 5, 2006, the FERC issued an order denying the Port of Seattle's request for rehearing.  On October 24, 2006, the Port of Seattle petitioned the U.S. Court of Appeals for the Ninth Circuit for review of the FERC orderdenying their request for rehearing of the FERC order approving thesettlement.  The Ninth Circuit consolidated that review petition with the largenumber of review petitions already consolidated before it.  On January 23,2007, IPC and IE filed a motion to sever the Port of Seattle's petition forreview from the bulk of cases pending in the Ninth Circuit with which it hadbeen consolidated.  IPC and IE also filed a motion to dismiss the Port of Seattle's petition for review.  The Port of Seattle filed their answers inopposition to the motion to sever and the motion to dismiss on February 1,2007, and IPC and IE replied on February 12, 2007.  IDACORP and IPC are notable to predict when or how the Ninth Circuit might rule on the motions.

Priorto December of 2005, IE had accrued a reserve of $42 million.  This reserve wascalculated taking into account the uncertainty of collection from the CalPX andCal ISO.  In the fourth quarter of 2005, following the tentative agreement withthe California Parties, IE reduced this reserve by $9.5 million to $32million.  Following payment of the $10.25 million to IE and IPC in June 2006,IE further reduced the reserve by $24.9 million to $7.1 million.  This reservewas calculated taking into account several unresolved issues in the California refund proceeding.

Market Manipulation:In a November 20, 2002 order, theFERC permitted discovery and the submission of evidence respecting marketmanipulation by various sellers during the western power crises of 2000 and2001.

On March 3, 2003, theCalifornia Parties (certain investor owned utilities, the California AttorneyGeneral, the California Electricity Oversight Board and the CPUC) filedvoluminous documentation asserting that a number of wholesale power suppliers,including IE and IPC, had engaged in a variety of forms of conduct that theCalifornia Parties contended were impermissible.  Although the contentions ofthe California Parties were contained in more than 11 compact discs of data andtestimony, approximately 12,000 pages, IE and IPC were mentioned only inlimited contexts with the overwhelming majority of the claims of the CaliforniaParties relating to the conduct of other parties.

The California Parties urgedthe FERC to apply the precepts of its earlier decision, to replace actualprices charged in every hour starting January 1, 2000 through the beginning ofthe existing refund period (October 2, 2000) with a Mitigated Market ClearingPrice, seeking approximately $8 billion in refunds to the Cal ISO and theCalPX.  On March 20, 2003, numerous parties, including IE and IPC, submittedbriefs and responsive testimony.

In its March 26, 2003 order,discussed above in "California Refund," the FERC declined to generically applyits refund determinations to sales by all market participants, although itstated that it reserved the right to provide remedies for the market againstparties shown to have engaged in proscribed conduct.

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On June 25, 2003, the FERCordered over 50 entities that participated in the western wholesale powermarkets between January 1, 2000 and June 20, 2001, including IPC, to show causewhy certain trading practices did not constitute gaming or anomalous marketbehavior in violation of the Cal ISO and the CalPX Tariffs.  The Cal ISO wasordered to provide data on each entity's trading practices within 21 days ofthe order, and each entity was to respond explaining their trading practiceswithin 45 days of receipt of the Cal ISO data.  IPC submitted its responses tothe show cause orders on September 2 and 4, 2003.  On October 16, 2003, IPCreached agreement with the FERC Staff on the two orders commonly referred to asthe "gaming" and "partnership" show cause orders.  Regarding the gaming order,the FERC Staff determined it had no basis to proceed with allegations of falseimports and paper trading and IPC agreed to pay $83,373 to settle allegationsof circular scheduling.  IPC believed that it had defenses to the circularscheduling allegation but determined that the cost of settlement was less thanthe cost of litigation.  In the settlement, IPC did not admit any wrongdoing orviolation of any law.  With respect to the "partnership" order, the FERC Staffsubmitted a motion to the FERC to dismiss the proceeding because materialssubmitted by IPC demonstrated that IPC did not use its "parking" and "lending"arrangement with Public Service Company of New Mexico to engage in "gaming" oranomalous market behavior ("partnership").  The "gaming" settlement wasapproved by the FERC on March 3, 2004.  Originally, eight parties requestedrehearing of the FERC's March 3, 2004 order.  The motion to dismiss the "partnership"proceeding was approved by the FERC in an order issued on January 23, 2004 andrehearing of that order was not sought within the time allowed by statute. Some of the California Parties and other parties have petitioned the U.S. Courtof Appeals for the Ninth Circuit and the District of Columbia Circuit forreview of the FERC's orders initiating the show cause proceedings.  Some of theparties contend that the scope of the proceedings initiated by the FERC was toonarrow.  Other parties contend that the orders initiating the show causeproceedings were impermissible.  Under the rules for multidistrict litigation,a lottery was held and although these cases were to be considered in theDistrict of Columbia Circuit by order of February 10, 2005, the District ofColumbia Circuit transferred the proceedings to the Ninth Circuit.  The FERChad moved the District of Columbia Circuit to dismiss these petitions on thegrounds of prematurity and lack of ripeness and finality.  The transfer orderwas issued before a ruling from the District of Columbia Circuit and themotions, if renewed, will be considered by the Ninth Circuit.  The NinthCircuit has consolidated this case with other matters and are holding them in abeyance. IPC is not able to predict the outcome of the judicial determination of theseissues.

The settlement between theCalifornia Parties and IE and IPC discussed above in  the California Refundproceeding approved by the FERC on May 22, 2006, results in the CaliforniaParties and other settling parties withdrawing their requests for rehearing ofIPC's and IE's settlement with the FERC Staff regarding allegations of "gaming". On October 11, 2006, the FERC issued an Order denying rehearing of its earlierapproval of the "gaming" allegations, thereby effectively terminating the FERCinvestigations as to IPC and IE regarding bidding behavior, physicalwithholding of power and "gaming" without finding of wrongdoing.  On October24, 2006, the Port of Seattle appealed the FERC order to the U.S. Court ofAppeals for the Ninth Circuit.

On June 25, 2003, the FERCalso issued an order instituting an investigation of anomalous bidding behaviorand practices in the western wholesale power markets.  In this investigation,the FERC was to review evidence of alleged economic withholding of generation. The FERC determined that all bids into the CalPX and the Cal ISO markets formore than $250 per MWh for the time period May 1, 2000, through October 1,2000, would be considered prima facie evidence of economic withholding.  TheFERC Staff issued data requests in this investigation to over 60 marketparticipants including IPC.  IPC responded to the FERC's data requests.  In aletter dated May 12, 2004, the FERC's Office of Market Oversight andInvestigations advised that it was terminating the investigation as to IPC.  InMarch 2005, the California Attorney General, the CPUC, the CaliforniaElectricity Oversight Board and Pacific Gas and Electric Company soughtjudicial review in the Ninth Circuit of the FERC's termination of thisinvestigation as to IPC and approximately 30 other market participants.  IPChas moved to intervene in these proceedings.  On April 25, 2005, Pacific Gasand Electric Company sought review in the Ninth Circuit of another FERC orderin the same docketed proceeding confirming the agency's earlier decision not toallow the participation of the California Parties in what the FERCcharacterized as its non-public investigative proceeding.

Pacific Northwest Refund:On July 25, 2001, the FERC issued anorder establishing another proceeding to explore whether there may have beenunjust and unreasonable charges for spot market sales in the Pacific Northwestduring the period December 25, 2000 through June 20, 2001.  The FERCAdministrative Law Judge submitted recommendations and findings to the FERC onSeptember 24, 2001.  The Administrative Law Judge found that prices should begoverned by the Mobile-Sierra standard of the public interest rather than the justand reasonable standard, that the Pacific Northwest spot markets werecompetitive and that no refunds should be allowed.  Procedurally, theAdministrative Law Judge's decision is a recommendation to the commissioners ofthe FERC.  Multiple parties submitted comments to the FERC with respect to theAdministrative Law Judge's recommendations.  The Administrative Law Judge'srecommended findings had been pending before the FERC, when at the request ofthe City of Tacoma and the Port of Seattle on December 19, 2002, the FERCreopened the proceedings to allow the submission of additional evidence relatedto alleged manipulation of the power market by Enron and others.  As was thecase in the California refund proceeding, at the conclusion of the discoveryperiod, parties alleging market manipulation were to submit their claims to theFERC and responses were due on March 20, 2003.  Grays Harbor intervened in thisFERC proceeding, asserting on March 3, 2003 that its six-month forwardcontract, for which performance had been completed, should be treated as a spotmarket contract for purposes of the FERC's consideration of refunds andrequested refunds from IPC of $5 million.  Grays Harbor did not suggest thatthere was any misconduct by IPC or IE.  The companies submitted responsivetestimony defending vigorously against Grays Harbor's refund claims.

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In addition, the Port ofSeattle, the City of Tacoma and the City of Seattle made filings with the FERCon March 3, 2003, claiming that because some market participants drove pricesup throughout the west through acts of manipulation, prices for contractsthroughout the Pacific Northwest market should be re-set starting in May 2000using the same factors the FERC would use for California markets.  Although themajority of these claims are generic, they named a number of power marketsuppliers, including IPC and IE, as having used parking services provided byother parties under FERC-approved tariffs and thus as being candidates forclaims of improperly having received congestion revenues from the Cal ISO.  OnJune 25, 2003, after having considered oral argument held earlier in the month,the FERC issued its Order Granting Rehearing, Denying Request to WithdrawComplaint and Terminating Proceeding, in which it terminated the proceeding anddenied claims that refunds should be paid.  The FERC denied rehearing onNovember 10, 2003, triggering the right to file for review.  The Port of Seattle, the City of Tacoma, the City of Seattle, the California Attorney General, theCPUC and Puget Sound Energy, Inc. filed petitions for review in the NinthCircuit.  These petitions have been consolidated.  Grays Harbor did not file apetition for review, although it sought to intervene in the proceedingsinitiated by the petitions of others.  On July 21, 2004, the City of Seattle submitted a motion requesting leave to offer additional evidence before the FERC inorder to try to secure another opportunity for reconsideration by the FERC ofits earlier rulings.  The evidence that the City of Seattle sought to introducebefore the FERC consisted of audio tapes of what purports to be Enron traderconversations containing inflammatory language.  Under Section 313(b) of theFederal Power Act, a court is empowered to direct the introduction of additionalevidence if it is material and could not have been introduced during theunderlying proceeding.  On September 29, 2004, the Ninth Circuit denied theCity of Seattle's motion for leave to adduce evidence, without prejudice torenewing the request for remand in the briefing in the Pacific Northwest refundcase.  Briefing was completed on May 25, 2005, and oral argument was held onJanuary 8, 2007.  The Settlement approved by the FERC on May 22, 2006, resolvesall 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 predictthe outcome as to all other parties in this proceeding.

In separate western energyproceedings, the Ninth Circuit issued two decisions on December 19, 2006reviewing the FERC's decisions not to require repricing of certain long termcontracts.  Those cases originated with individual complaints against specifiedsellers which did not include IE or IPC.  The Ninth Circuit remanded to theFERC for additional consideration the agency's use of restrictive standards ofcontract review.  In its decisions, the Ninth Circuit also questioned thevalidity of the FERC's administration of its market-based rate regime.  IDACORPand IPC are unable to predict whether parties to that case will seek a writ of certiorarior how or when the FERC might respond to these decisions. 

**Shareholder Lawsuit:** On May 26, 2004 and June 22, 2004, respectively, twoshareholder lawsuits were filed against IDACORP and certain of its directorsand officers.  The lawsuits, captioned Powell, et al. v. IDACORP, Inc., et al.and Shorthouse, et al. v. IDACORP, Inc., et al., raise largely similar allegations. The lawsuits are putative class actions brought on behalf of purchasers ofIDACORP stock between February 1, 2002, and June 4, 2002, and were filed in theU.S. District Court for the District of Idaho.  The named defendants in eachsuit, in addition to IDACORP, are Jon H. Miller, Jan B. Packwood, J. LaMontKeen and Darrel T. Anderson.

The complaints alleged that,during the purported class period, IDACORP and/or certain of its officersand/or directors made materially false and misleading statements or omissionsabout the company's financial outlook in violation of Sections 10(b) and 20(a)of the Securities Exchange Act of 1934, as amended, and Rule 10b-5, therebycausing investors to purchase IDACORP's common stock at artificially inflatedprices.  More specifically, the complaints alleged that IDACORP failed todisclose and misrepresented the following material adverse facts which wereknown to defendants or recklessly disregarded by them: (1) IDACORP failed toappreciate the negative impact that lower volatility and reduced pricingspreads in the western wholesale energy market would have on its marketingsubsidiary, IE; (2) IDACORP would be forced to limit its origination activitiesto shorter-term transactions due to increasing regulatory uncertainty andcontinued deterioration of creditworthy counterparties; (3) IDACORP failed toaccount for the fact that IPC may not recover from the lingering effects of theprior year's regional drought and (4) as a result of the foregoing, defendantslacked a reasonable basis for their positive statements about IDACORP and theirearnings projections.  The Powell complaint also alleged that the defendants'conduct artificially inflated the price of IDACORP's common stock.  The actionsseek an unspecified amount of damages, as well as other forms of relief.  Byorder dated August 31, 2004, the court consolidated the Powell and Shorthousecases for pretrial purposes, and ordered the plaintiffs to file a consolidatedcomplaint within 60 days.  On November 1, 2004, IDACORP and the directors andofficers named above were served with a purported consolidated complaintcaptioned Powell, et al. v. IDACORP, Inc., et al., which was filed in the U.S.District Court for the District of Idaho.

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The new complaint allegedthat during the class period IDACORP and/or certain of its officers and/ordirectors made materially false and misleading statements or omissions aboutits business operations, and specifically the IE financial outlook, inviolation of Rule 10b-5, thereby causing investors to purchase IDACORP's commonstock at artificially inflated prices.  The new complaint alleged that IDACORPfailed to disclose and misrepresented the following material adverse factswhich were known to it or recklessly disregarded by it: (1) IDACORP falselyinflated the value of energy contracts held by IE in order to report higherrevenues and profits; (2) IDACORP permitted IPC to inappropriately grant nativeload priority for certain energy transactions to IE; (3) IDACORP failed to file13 ancillary service agreements involving the sale of power for resale ininterstate commerce that it was required to file under Section 205 of theFederal Power Act; (4) IDACORP failed to file 1,182 contracts that IPC assignedto IE for the sale of power for resale in interstate commerce that IPC wasrequired to file under Section 203 of the Federal Power Act; (5) IDACORP failedto ensure that IE provided appropriate compensation from IE to IPC for certainaffiliated energy transactions; and (6) IDACORP permitted inappropriate sharingof certain energy pricing and transmission information between IPC and IE. These activities allegedly allowed IE to maintain a false perception ofcontinued growth that inflated its earnings.  In addition, the new complaint allegesthat those earnings press releases, earnings release conference calls, analystreports and revised earnings guidance releases issued during the class periodwere false and misleading.  The action seeks an unspecified amount of damages,as well as other forms of relief.  IDACORP and the other defendants filed aconsolidated motion to dismiss on February 9, 2005, and the plaintiffs filedtheir opposition to the consolidated motion to dismiss on March 28, 2005. IDACORP and the other defendants filed their response to the plaintiff'sopposition on April 29, 2005 and oral argument on the motion was held on May19, 2005.

On September 14, 2005,Magistrate Judge Mikel H. Williams of the U.S. District Court for the Districtof Idaho issued a Report and Recommendation that the defendants' motion todismiss be granted and that the case be dismissed.  The Magistrate Judgedetermined that the plaintiffs did not satisfactorily plead loss causation(i.e., a causal connection between the alleged material misrepresentation andthe loss) in conformance with the standards set forth in the recent UnitedStates Supreme Court decision of Dura Pharmaceuticals, Inc. v. Broudo, 544U.S.336, 125 S. Ct. 1627 (2005).  The Magistrate Judge also concluded that itwould be futile to afford the plaintiffs an opportunity to file an amendedcomplaint because it did not appear that they could cure the deficiencies intheir pleadings.  Each party filed objections to different parts of theMagistrate Judge's Report and Recommendation.

On March 29, 2006, the U.S.District Court for the District of Idaho (Judge Edward J. Lodge) issued anOrder in this case (Powell v. IDACORP) adopting the Report and Recommendationof Magistrate Judge Williams issued on September 14, 2005, granting the defendants'(IDACORP and certain of its officers and directors) motion to dismiss becauseplaintiffs failed to satisfy the pleading requirements for loss causation. However, Judge Lodge modified the Report and Recommendation and ruled thatplaintiffs had until May 1, 2006, to file an amended complaint only as to theloss causation element.  On May 1, 2006, the plaintiffs filed an amendedcomplaint.  The defendants filed a motion to dismiss the amended complaint onJune 16, 2006, asserting that the amended complaint still failed to satisfy thepleading requirements for loss causation.  Briefing on this most recent motionto dismiss was completed on August 28, 2006, and oral argument was held onFebruary 26, 2007.

IDACORP and the otherdefendants intend to defend themselves vigorously against the allegations. IDACORP cannot, however, predict the outcome of these matters.

**Western Shoshone NationalCouncil:** On April 10, 2006, theWestern Shoshone National Council (which purports to be the governing body ofthe Western Shoshone Nation) and certain of its individual tribal members fileda First Amended Complaint and Demand for Jury Trial in the U.S. District Courtfor the District of Nevada, naming IPC and other unrelated entities asdefendants.

Plaintiffs allege that IPC'sownership interest in certain land, minerals, water or other resources wasconverted and fraudulently conveyed from lands in which the plaintiffs hadhistorical ownership rights and Indian title dating back to the 1860's orbefore.  Although it is unclear from the complaint, it appears plaintiffs'claims relate primarily to lands within the state of Nevada.  Plaintiffs seek ajudgment declaring their title to land and other resources, disgorgement ofprofits from the sale or use of the land and resources, a decree declaring aconstructive trust in favor of the plaintiffs of IPC's assets connected to thelands or resources, an accounting of money or things of value received from thesale or use of the lands or resources, monetary damages in an unspecifiedamount for waste and trespass and a judgment declaring that IPC has no right topossess or use the lands or resources.

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On May 1, 2006, IPC filed anAnswer to plaintiffs' First Amended Complaint denying all liability to theplaintiffs and asserting certain affirmative defenses including collateralestoppel and res judicata, preemption, impossibility and impracticability,failure to join all real and necessary parties, and various defenses based onuntimeliness.  On June 19, 2006, IPC filed a motion to dismiss plaintiffs'First Amended Complaint, asserting, among other things, that the Court lackssubject matter jurisdiction and that plaintiffs failed to join an indispensableparty (namely, the United States government).  Briefing on the motion todismiss was completed on September 28, 2006.  Newly decided authority from theUnited States Court of Federal Claims in further support of IPC's motion todismiss was filed on January 3, 2007.  The Court has yet to act on the IPCmotion to dismiss.  IPC intends to vigorously defend its position in thisproceeding, but is unable to predict the outcome of this matter.

**Sierra Club Lawsuit -Bridger: **In February 2007, theSierra Club and the Wyoming Outdoor Council filed a complaint againstPacifiCorp in federal district court in Cheyenne, Wyoming for allegedviolations of the Clean Air Act's opacity standards (alleged violations of airpollution permit emission limits) at the Jim Bridger coal fired plant ("Plant")in Sweetwater County, Wyoming.  IPC has a one-third ownership interest in thePlant.  PacifiCorp owns a two-thirds interest and is the operator of the Plant. The complaint alleges thousands of violations and seeks declaratory andinjunctive relief and civil penalties of $32,500 per day per violation as wellas the costs of litigation, including reasonable attorney fees.  IPC believesthere are a number of defenses to the claims and intends to vigorously defendits interest in this matter, but is unable to predict its outcome and is unableto estimate the impact this may have on its consolidated financial positions,results of operations or cash flows.

**8. STOCK-BASED COMPENSATION:**

IDACORP has three share-basedcompensation plans.  IDACORP's employee plans are the 2000 Long-Term Incentiveand Compensation Plan (LTICP) and the 1994 Restricted Stock Plan (RSP).  Theseplans are intended to align employee and shareholder objectives related toIDACORP's long-term growth.  IDACORP also has one non-employee plan, theDirector Stock Plan (DSP).  The purpose of the DSP is to increase directors'stock ownership through stock-based compensation.

The LTICP for officers, keyemployees and directors permits the grant of nonqualified stock options,incentive stock options, stock appreciation rights, restricted stock, restrictedstock units, performance units, performance shares and other awards.  The RSPpermits only the grant of restricted stock or performance-based restrictedstock.  At December 31, 2006, the maximum number of shares available under theLTICP and RSP were 1,688,562 and 104,325, respectively.  The following tableshows the compensation cost recognized in income and the tax benefits resultingfrom these plans, as well as the amounts allocated to IPC for those costsassociated with IPC's employees (in thousands of dollars):

**IDACORP**

**IPC**

**2006**

**2005**

**2004**

**2006**

**2005**

**2004**

Compensation cost

$

2,692

$

589

$

656

$

1,458

$

178

$

453

Income tax benefit

$

1,053

$

230

$

257

$

570

$

70

$

177

No equity compensation costshave been capitalized.

**Stock awards: **Restricted stock awards have vesting periods of up tofour years.  Restricted stock awards entitle the recipients to dividends andvoting rights, and unvested shares are restricted to disposition and subject toforfeiture under certain circumstances.  The fair value of restricted stockawards is measured based on the market price of the underlying common stock onthe date of grant and charged to compensation expense over the vesting periodbased on the number of shares expected to vest.

Performance-based restrictedstock awards have vesting periods of three years.  Performance awards entitlethe recipients to voting rights, and unvested shares are restricted todisposition, subject to forfeiture under certain circumstances, and subject tomeeting specific performance conditions.  Based on the attainment of theperformance conditions, the ultimate award can range from zero to 150 percentof the target award.  For awards granted prior to 2006, dividends were paid torecipients at the time they were paid on the common stock.  Beginning with the2006 awards, dividends are accumulated and will be paid out only on shares thateventually vest.

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Theperformance goals for the 2006 awards are independent of each other and equallyweighted, and are based on two metrics, cumulative earnings per share (CEPS)and total shareholder return (TSR) relative to a peer group.  The fair value ofthe CEPS portion is based on the market value at the date of grant, reduced bythe loss in time-value of the estimated future dividend payments, using anexpected quarterly dividend of $0.30.  The fair value of the TSR portion isestimated using a statistical model that incorporates the probability ofmeeting performance targets based on historical returns relative to the peergroup.  Both performance goals are measured over the three-year vesting periodand are charged to compensation expense over the vesting period based on thenumber of shares expected to vest.

A summary of restricted stockand performance share activity is presented below.  IPC share amounts representthe portion of IDACORP amounts related to IPC employees:

** **

**IDACORP**

** **

**IPC**

** **

** **

** **

**Weighted-**

** **

** **

** **

**Weighted-**

** **

** **

** **

**average**

** **

** **

** **

**average**

** **

**Number of**

** **

**Grant date**

** **

**Number of**

** **

**Grant date**

** **

**Shares**

** **

**Fair value**

** **

**Shares**

** **

**Fair value**

Nonvested shares at December  31, 2003

94,363 

$

30.59

79,257 

$

31.19

Shares granted

83,366 

31.15

67,056 

31.13

Shares forfeited

(30,931)

34.80

(23,914)

35.71

Shares vested

(2,076)

30.20

(2,076)

30.20

Nonvested shares at  December 31, 2004

144,722 

$

30.02

120,323 

$

30.27

Shares granted

96,708 

29.75

87,620 

29.75

Shares forfeited

(26,328)

38.46

(24,804)

38.40

Shares vested

(251)

31.21

(251)

31.21

Nonvested shares at  December 31, 2005

214,851 

$

28.86

182,888 

$

28.92

Shares granted

124,126 

25.90

112,146 

25.91

Shares forfeited

(115,569)

26.48

(91,538)

26.14

Shares vested

(19,200)

30.39

(19,200)

30.39

Nonvested shares at  December 31, 2006

204,208 

$

28.26

184,296 

$

28.32

At December 31, 2006, IDACORPhad $1.9 million of total unrecognized compensation cost related to nonvestedshare-based compensation that was expected to vest.  IPC's share of this amountwas $1.7 million.  These costs are expected to be recognized over aweighted-average period of 1.91 years.  IDACORP uses original issue and/ortreasury shares for these awards.

**Stock options:** Stock option awards are granted with exercise pricesequal to the market value of the stock on the date of grant.  The options havea term of 10 years from the grant date and vest over a five-year period.  Uponadoption of SFAS 123(R) on January 1, 2006, the fair value of each option isamortized into compensation expense using graded-vesting.  Beginning in 2006,stock options are not a significant component of share-based compensationawards under the LTICP.

Thefair values of all stock option awards have been estimated as of the date ofthe grant by applying a binomial option pricing model.  The application of thismodel involves assumptions that are judgmental and sensitive in thedetermination of compensation expense.  The following key assumptions were usedin determining the fair value of options granted:

**2006**

**2005**

**2004**

Dividend yield, based on  current dividend and stock price on grant date

3.7%

4.1%

3.9%

Expected stock price  volatility, based on IDACORP historical volatility

18%

23%

29%

Risk-free interest rate  based on U.S. Treasury composite rate

4.92%

4.22%

3.96%

Expected term based on the  SEC "simplified" method

6.50 years

7 years

7 years

 

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IDACORP's and IPC's stockoption transactions are summarized below.  IPC share amounts represent theportion of IDACORP amounts related to IPC employees:

** **

** **

** **

**Weighted**

** **

** **

** **

**Weighted-**

**Average**

**Aggregate**

** **

**Number**

**Average**

**Remaining**

**Intrinsic**

** **

**of**

**Exercise**

**Contractual**

**Value**

** **

**Shares**

**Price**

**Term**

**(000s)**

**IDACORP**

** **

** **

** **

** **

Outstanding at December 31,  2003

1,145,400 

$

32.69

5.08

$

7,313

Granted

187,850 

31.06

Exercised

(7,400)

22.92

Forfeited

(57,300)

29.87

Expired

(14,000)

39.78

Outstanding at December 31,  2004

1,254,550 

$

32.55

5.33

$

8,100

Granted

208,314 

29.53

Exercised

(16,400)

22.92

Forfeited

(22,750)

31.12

Expired

(1,800)

36.74

Outstanding at December 31,  2005

1,421,914 

$

32.24

5.71

$

9,560

Granted

9,905 

31.86

Exercised

(406,623)

29.25

Forfeited

(162,632)

28.43

Expired

(21,676)

34.31

Outstanding at December 31,  2006

840,888 

$

34.36

5.63

$

4,062

Vested or expected to vest  at December 31, 2006

821,227 

$

34.49

5.60

$

3,873

Exercisable at December 31,  2006

579,624 

$

36.71

5.02

$

1,554

**IPC**

** **

** **

** **

** **

Outstanding at December 31,  2003

886,800 

$

32.48

5.04

$

5,897

Granted

110,500 

31.21

Exercised

(4,200)

22.92

Forfeited

(30,900)

29.90

Expired

(9,600)

39.91

Outstanding at December 31,  2004

952,600 

$

32.38

5.24

$

6,371

Granted

157,837 

29.75

Exercised

- 

- 

Forfeited

(16,300)

30.27

Expired

- 

- 

Outstanding at December 31,  2005

1,094,137 

$

32.03

5.64

$

7,634

Granted

- 

- 

Exercised

(320,821)

29.83

Forfeited

(142,625)

28.51

Expired

(11,600)

39.89

Outstanding at December 31,  2006

619,091 

$

33.84

5.71

$

3,385

Vested or expected to vest  at December 31, 2006

603,152 

$

33.97

5.67

$

3,227

Exercisable at December 31,  2006

407,826 

$

36.44

5.04

$

1,292

101

Table of Contents

The following table presentsinformation about options granted and exercised (in thousands of dollars,except for weighted-average amounts):

**IDACORP**

**IPC**

** **

**2006**

** **

**2005**

** **

**2004**

**2006**

** **

**2005**

** **

**2004**

Weighted-average grant-date  fair value

$

9.96

$

5.86

$

7.84

$

-

$

5.95

$

7.93

Fair value of options vested

2,191

1,865

1,596

1,275

1,390

1,229

Intrinsic value of options  exercised

3,771

104

44

2,883

-

22

Cash received from exercises

11,937

376

170

9,614

-

96

Tax benefits realized from  exercises

1,474

41

17

1,127

-

9

As of December 31, 2006,there was $0.3 million of total unrecognized compensation cost related to stockoptions.  These costs are expected to be recognized over a weighted averageperiod of 2.51 years.  IDACORP uses original issue and/or treasury shares tosatisfy exercised options.

**9. BENEFIT PLANS:**

**SFAS158**In December 2006 IDACORP and IPCadopted the recognition provisions of Statement of Financial AccountingStandards No. 158, "*Employers' Accounting for Defined Benefit Pension Plansand Other Postretirement Plans - an amendment of FASB Statements No. 87, 88,106, and 132(R)."*

The following table presentsthe incremental effect of applying SFAS 158 on individual line items in theConsolidated Balance Sheets of IDACORP at December 31, 2006:

**Before**

** **

** **

** **

** **

**After**

**Application of**

** **

** **

** **

** **

**Application of**

**Statement 158**

** **

**Adjustments**

** **

**Statement 158**

**(thousands of dollars)**

Prepayments

$

13,444 

$

(4,136)

$

9,308 

Noncurrent regulatory  assets

377,367 

46,181 

423,548 

Other current assets

42,979 

(1,720)

41,259 

Total assets

3,404,805 

40,325 

3,445,130 

Other current liabilities

21,197 

2,375 

23,572 

Noncurrent deferred income  taxes

504,260 

(5,748)

498,512 

Other liabilities

133,122 

46,714 

179,836 

Total other liabilities

940,999 

40,966 

981,965 

Accumulated other  comprehensive income (loss)

(2,721)

(3,016)

(5,737)

Total shareholders' equity

1,127,199 

(3,016)

1,124,183 

* *

The adjustments for IPC arethe same as those presented for IDACORP.  In accordance with regulatoryaccounting treatment under SFAS 71, amounts that otherwise would have beenrecorded in accumulated other comprehensive income have been recorded asregulatory assets for both the pension and postretirement plans.

Themeasurement provisions of SFAS 158 are not required to be adopted until 2008and require that a company measure its plan assets and benefit obligations asof its balance sheet date.  IPC already uses a December 31 measurement date forits plans, so adoption of the measurement provisions of SFAS 158 is notexpected to have a material effect on IDACORP's or IPC's results of operationsor cash flows.

102

Table of Contents

**PensionPlans**IPC has a noncontributory definedbenefit pension plan covering most employees.  The benefits under the plan arebased on years of service and the employee's final average earnings.  IPC'spolicy is to fund, with an independent corporate trustee, at least the minimumrequired under the Employee Retirement Income Security Act of 1974 (ERISA) butnot more than the maximum amount deductible for income tax purposes.  IPC wasnot required to contribute to the plan in 2006, 2005 or 2004.  Themarket-related value of assets for the plan is equal to the fair value of theassets.  Fair value is determined by utilizing publicly quoted market valuesand independent pricing services depending on the nature of the asset, asreported by the trustee/custodian of the plan.

In addition, IPC has anonqualified, deferred compensation plan for certain senior managementemployees and directors.  This plan was financed by purchasing life insurancepolicies and investments in marketable securities, all of which are held by atrustee.  The cash value of the policies and investments exceed the projectedbenefit obligation of the plan but do not qualify as plan assets in theactuarial computation of the funded status.

The following tablesummarizes the changes in benefit obligations and plan assets of these plans:

** **

**Pension Plan**

**Deferred Compensation Plan**

** **

**2006**

** **

**2005**

**2006**

** **

**2005**

**(thousands of dollars)**

**Change in benefit  obligation:**

Benefit obligation at  January 1

$

406,049 

$

374,333 

$

42,723 

$

38,645 

Service cost

14,476 

13,129 

1,473 

1,170 

Interest cost

 

22,340 

21,126 

2,327 

2,151 

Actuarial loss (gain)

 

(2,827)

11,399 

(2,857)

2,799 

Benefits paid

 

(14,439)

(13,938)

(2,352)

(2,312)

Plan amendments

 

- 

- 

552 

270 

Benefit obligation at  December 31

425,599 

406,049 

41,866 

42,723 

**Change in plan assets:**

Fair value at January 1

368,053 

356,217 

- 

- 

Actual return on plan assets

47,310 

25,774 

- 

- 

Employer contributions

- 

- 

- 

- 

Benefit payments

 

(14,439)

(13,938)

- 

- 

Fair value at December 31

400,924 

368,053 

- 

- 

Unfunded status at end of  year

(24,675)

(37,996)

(41,866)

(42,723)

Unrecognized actuarial loss 

- 

43,806 

- 

13,553 

Unrecognized prior service  cost

- 

5,118 

- 

1,414 

Net amount recognized

$

 (24,675)

$

10,928 

$

(41,866)

$

(27,756)

Amounts recognized in the  statement of

financial position consist  of:

Current liabilities

$

- 

$

- 

$

(2,375)

$

- 

Noncurrent liabilities

(24,675)

- 

(39,491)

- 

Prepaid (accrued) pension  cost

- 

10,928 

-

(39,268)

Intangible asset

- 

- 

- 

1,414 

Accumulated other  comprehensive income

- 

- 

- 

10,098 

Net amount recognized

$

 (24,675)

$

10,928 

$

(41,866)

$

(27,756)

Amounts recognized in  accumulated other

comprehensive income consist  of:

Net loss

$

24,356 

-

$

9,853 

-

Prior service cost

4,455 

-

1,720 

-

Subtotal

28,811 

-

11,573 

-

Less amount recorded as  regulatory asset

(28,811)

-

- 

-

Net amount recognized in  accumulated

-

other comprehensive income

$

- 

-

$

11,573 

-

Accumulated benefit  obligation

$

350,434 

$

340,007 

$

38,634 

$

39,268 

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Table of Contents

Thefollowing table shows the components of net periodic benefit cost for theseplans:

** **

**Pension Plan**

**Deferred Compensation Plan**

** **

**2006**

**2005**

**2004**

**2006**

**2005**

**2004**

**(thousands of dollars)**

Service cost

$

14,476 

$

13,129 

$

11,809 

$

1,473 

$

1,170 

$

1,358 

Interest cost

22,340 

21,126 

20,437 

2,327 

2,151 

2,312 

Expected return on assets

(30,817)

(29,690)

(27,935)

- 

- 

- 

Amortization of net loss

129 

- 

- 

844 

689 

878 

Amortization of prior  service cost

664 

771 

770 

245 

228 

(361)

Amortization of transition  asset

** **

- 

(126)

(263)

- 

310 

613 

Net periodic pension cost 

$

6,792 

$

5,210 

$

4,818 

$

4,889 

$

4,548 

$

4,800 

Changes in the DeferredCompensation Plan minimum liability increased other comprehensive income by $2million in 2006 (prior to the effect of adopting SFAS 158), decreased othercomprehensive income by $1 million in 2005 and increased other comprehensiveincome by $1 million in 2004.

In 2007, IDACORP and IPCexpect to recognize as components of net periodic benefit cost $1.4 millionfrom amortizing amounts recorded in accumulated other comprehensive income asof December 31, 2006, relating to the pension and deferred compensation plans. This amount consists of $0.6 million of prior service cost for the pension planand $0.6 million of net loss and $0.2 million of prior service cost for thedeferred compensation plan.

The following tablesummarizes the expected future benefit payments of these plans:

** **

** **

**2007**

** **

**2008**

** **

**2009**

** **

**2010**

** **

**2011**

** **

**2012-2016**

Pension Plan

$

15,070

$

16,127

$

17,354

$

18,858

$

20,462

$

133,740

Deferred Compensation Plan

$

2,438

$

2,546

$

2,797

$

2,997

$

3,059

$

16,963

**Plan Asset Allocations:** IPC's pension plan and postretirement benefit planweighted average asset allocations at December 31, 2006 and 2005, by assetcategory are as follows:

**Pension**

**Postretirement**

**Plan**

**Benefits**

Asset Category

**2006**

**2005**

**2006**

**2005**

Equity securities

68%

66%

-%

-%

Debt securities

24   

21   

-   

-   

Real estate

7   

10   

-   

-   

Other (a)

1   

3   

100   

100   

Total

100%

100%

100%

100%

(a)  The  postretirement benefit plan assets are primarily life insurance contracts.

**Pension Asset AllocationPolicy:** The target allocations forthe portfolio by asset class are as follows:

Large-Cap Growth Stocks

12%

International Growth Stocks

7%

Large-Cap Core Stocks

12%

International Value Stocks

7%

Large-Cap Value Stocks

12%

Intermediate-Term Bonds

13%

Small-Cap Growth Stocks

5%

Short-Term Bonds

10%

Small-Cap Value Stocks

5%

Core Real Estate

9%

Micro-Cap Stocks

3%

Private Equity

2%

Cash and Cash Equivalents

3%

Assetsare rebalanced as necessary to keep the portfolio close to target allocations.

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Theplan's principal investment objective is to maximize total return (defined asthe sum of realized interest and dividend income and realized and unrealizedgain or loss in market price) consistent with prudent parameters of risk andthe liability profile of the portfolio.  Emphasis is placed on preservation andgrowth of capital along with adequacy of cash flow sufficient to fund currentand future payments to pensioners.

There are three major goalsin IPC's asset allocation process:

•   Determine if theinvestments have the potential to earn the rate of return assumed in theactuarial liability calculations.
- Match the cash flow needs     of the plan.  IPC sets cash allocations sufficient to cover the current     year benefit payments and bond allocations sufficient to cover at least     five years of benefit payments.  IPC then utilizes growth instruments     (equities, real estate, venture capital) to fund the longer-term     liabilities of the plan.
- Maintain a prudent risk     profile consistent with ERISA fiduciary standards.

Allowableplan investments include stocks and stock funds, investment-grade bonds andbond funds, core real estate funds, private equity funds, and cash and cashequivalents.  With the exception of real estate holdings and private equity,investments must be readily marketable so that an entire holding can bedisposed of quickly with only a minor effect upon market price.  Uncoveredoptions, short sales, margin purchases, letter stock and commodities areprohibited.

Rate-of-return projections for planassets are based on historical risk/return relationships among asset classes. The primary measure is the historical risk premium each asset class hasdelivered versus the return on 10-year U.S. Treasury Notes.  This historical riskpremium is then added to the current yield on 10-year U.S. Treasury Notes, andthe result provides a reasonable prediction of future investment performance. Additional analysis is performed to measure the expected range of returns, aswell as worst-case and best-case scenarios.  Based on the current low interestrate environment, current rate-of-return expectations are lower than thenominal returns generated over the past 20 years when interest rates weregenerally much higher.

IPC's asset modeling processalso utilizes historical market returns to measure the portfolio's exposure toa "worst-case" market scenario, to determine how much performance could varyfrom the expected "average" performance over various time periods.  This "worst-case"modeling, in addition to cash flow matching and diversification by asset classand investment style, provides the basis for managing the risk associated withinvesting portfolio assets.

**PostretirementBenefits**IPC maintains a defined benefitpostretirement plan (consisting of health care and death benefits) that coversall employees who were enrolled in the active group plan at the time ofretirement as well as their spouses and qualifying dependents.  Benefits foremployees who retire after December 31, 2002, are limited to a fixed amount,which will limit the growth of IPC's future obligations under this plan.

Thenet periodic postretirement benefit cost was as follows (in thousands ofdollars):

**2006**

** **

**2005**

** **

**2004**

Service cost

$

1,463 

$

1,392 

$

1,400 

Interest cost

3,426 

3,381 

3,974 

Expected return on plan  assets

(2,523)

(2,486)

(2,294)

Amortization of  unrecognized transition obligation

2,040 

2,040 

2,040 

Amortization of prior  service cost

(535)

(535)

(523)

Amortization of net loss

812 

754 

1,489 

Net periodic postretirement  benefit cost

$

4,683 

$

4,546 

$

6,086 

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Table of Contents

Thefollowing table summarizes the changes in benefit obligation and plan assets(in thousands of dollars):

**2006**

** **

**2005**

Change  in accumulated benefit obligation:

Benefit  obligation at January 1

$

63,633 

$

71,105 

Service  cost

1,463 

1,392 

Interest  cost

3,426 

3,381 

Actuarial  (gain) loss

(2,445)

(9,186)

Benefits  paid

(3,164)

(2,934)

Plan  amendments

- 

(125)

Benefit  obligation at December 31

62,913 

63,633 

Change  in plan assets:

Fair  value of plan assets at January 1

29,893 

29,723 

Actual  return on plan assets

3,158 

1,127 

Employer  contributions

2,004 

800 

Benefits  paid

(2,428)

(1,757)

Fair  value of plan assets at December 31

32,627 

29,893 

Funded  status at end of year

(30,286)

(33,740)

Unrecognized  prior service cost

-

(3,677)

Unrecognized  actuarial loss 

-

15,978 

Unrecognized  transition obligation

-

14,280 

Accrued  benefit obligations included in noncurrent liabilities

$

(30,286)

$

(7,159)

Amounts recognized in  accumulated other comprehensive income consist of:

Net loss

$

12,086 

Prior service cost (credit)

(3,142)

Transition obligation

12,240 

Subtotal

21,184 

Less amount recognized in  regulatory assets

(17,370)

Less amount included in  deferred tax assets

(3,814)

Net amount recognized in  accumulated other comprehensive income

$

- 

In2007, IDACORP and IPC expect to recognize as components of net periodic benefitcost $2.0 million from amortizing amounts recorded in accumulated othercomprehensive income as of December 31, 2006 relating to the postretirementplan.  This amount consists of $0.5 million of net loss, ($0.5) million ofprior service cost and $2.0 million of transition obligation.

**MedicareAct: **The Medicare Prescription Drug,Improvement and Modernization Act of 2003 (Medicare Act) was signed into law inDecember 2003 and established a prescription drug benefit, as well as a federalsubsidy to sponsors of retiree health care benefit plans that provide aprescription drug benefit that is at least actuarially equivalent to Medicare'sprescription drug coverage.  The measure of net periodic benefit cost for theyear ended December 31, 2004 does not reflect any amount associated with thesubsidy.

Thefollowing table summarizes the expected future benefit payments of thepostretirement benefit plan and expected Medicare Part D subsidy receipts (inthousand of dollars):

**2007**

** **

**2008**

** **

**2009**

** **

**2010**

** **

**2011**

** **

**2012-2016**

Expected  benefit payments*

$

4,100

$

4,200

$

4,300

$

4,500

$

4,700

$

25,300

 
Expected  Medicare Part D

 
subsidy  receipts

$

600

$

600

$

700

$

800

$

800

$

3,200

 
*Expected  benefit payments are net of expected Medicare Part D subsidy receipts.

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Table of Contents

Theassumed health care cost trend rate used to measure the expected cost ofbenefits covered by the plan was 6.75 percent in 2006 and 2005.  Aone-percentage point change in the assumed health care cost trend rate wouldhave the following effect (in thousands of dollars):

**1-Percentage-Point**

**increase**

** **

**decrease**

Effect  on total of cost components

$

258

$

(195)

Effect  on accumulated postretirement benefit obligation

$

2,409

$

(1,897)

Thefollowing table sets forth the weighted-average assumptions used at the end ofeach year to determine benefit obligations for all IPC-sponsored pension andpostretirement benefits plans:

**Pension**

**Postretirement**

**Benefits**

**Benefits**

**2006**

**2005**

**2006**

**2005**

Discount rate

5.85%

5.6%

5.85%

5.6%

Expected long-term rate of  return on assets

8.5%

8.5%

8.5%

8.5%

Rate of compensation  increase

4.5%

4.5%

-   

-   

Medical trend rate

-   

-   

6.75%

6.75%

Expected working lifetime  (years)

-   

-   

11   

11   

Thefollowing table sets forth the weighted-average assumptions used to determinenet periodic benefit cost for all IPC-sponsored pension and postretirementbenefit plans:

**Pension**

**Postretirement**

**Benefits**

**Benefits**

**2006**

**2005**

**2006**

**2005**

Discount rate

5.6%

5.75%

5.6%

5.75%

Expected long-term rate of  return on assets

8.5%

8.5%

8.5%

8.5%

Rate of compensation  increase

4.5%

4.5%

-   

-   

Medical trend rate

-   

-   

6.75%

6.75%

Expected working lifetime  (years)

-   

-   

11   

11   

** **

**EmployeeSavings Plan**IPC has an Employee Savings Plan thatcomplies with Section 401(k) of the Internal Revenue Code and coverssubstantially all employees.  IPC matches specified percentages of employeecontributions to the plan.  Matching contributions amounted to $4 million inboth 2006 and 2005 and $3 million in 2004.

**Postemployment Benefits**IPC provides certain benefits toformer or inactive employees, their beneficiaries and covered dependents afteremployment but before retirement.  These benefits include salary continuation,health care and life insurance for those employees found to be disabled underIPC's disability plans and health care for surviving spouses and dependents. IPC accrues a liability for such benefits.  The post employment benefit amountsincluded in other deferred credits on IDACORP's and IPC's consolidated balancesheets at December 31 are $4.0 million and $3.8 million for 2006 and 2005,respectively.

** **

107

Table of Contents

** **

**10.  PROPERTY PLANT ANDEQUIPMENT AND JOINTLY-OWNED PROJECTS:**

The following table presentsthe major classifications of IPC's utility plant in service, annualdepreciation provisions as a percent of average depreciable balance andaccumulated provision for depreciation for the years 2006 and 2005 (inthousands of dollars):

 
**2006**

** **

**2005**

 
**Balance**

** **

**Avg Rate**

** **

**Balance**

** **

**Avg Rate**

Production

$

1,592,790 

2.55%

$

1,563,008 

2.54%

Transmission

606,947 

2.18   

580,382 

2.19   

Distribution

1,097,390 

2.60   

1,046,880 

2.62   

General and Other

286,567 

6.74   

286,797 

8.94   

Total in service

3,583,694 

2.75%

3,477,067 

2.91%

Accumulated provision for  depreciation

(1,406,210)

(1,364,640)

In service - net

$

2,177,484 

$

2,112,427 

IPC has interests in threejointly-owned generating facilities.  Under the joint operating agreements,each participating utility is responsible for financing its share ofconstruction, operating and leasing costs.  IPC's proportionate share of directoperation and maintenance expenses applicable to the projects is included inthe Consolidated Statements of Income.  These facilities, and the extent of IPC'sparticipation, were as follows at December 31, 2006 (in thousands of dollars):

** **

** **

** **

** **

**Utility**

** **

**Construction**

** **

**Accumulated**

** **

** **

** **

** **

** **

** **

** **

** **

**Plant In**

** **

**Work in**

** **

**Provision for**

** **

** **

** **

** **

**Name of Plant**

** **

**Location**

** **

**Service**

** **

**Progress**

** **

**Depreciation**

** **

**%**

** **

**MW**

Jim Bridger Units 1-4

Rock Springs, WY

$

468,032

$

7,890

$

270,302

33

707

Boardman

Boardman, OR

69,109

476

47,284

10

59

Valmy Units 1 and 2

Winnemucca, NV

316,075

10,527

203,188

50

261

IPC's wholly-ownedsubsidiary, Idaho Energy Resources Co., is a joint venturer in Bridger CoalCompany, which operates the mine supplying coal to the Jim Bridger generatingplant.  IPC's coal purchases from the joint venture were $52 million, $43million and $47 million in 2006, 2005 and 2004, respectively.

IPC has contracts to purchasethe energy from four PURPA qualified facilities that are 50 percent owned byIda-West.  IPC's power purchases from these facilities were $8 million in 2006and $7 million annually in 2005 and 2004.

See Note 1 for a discussionof the property of IDACORP's consolidated VIEs.

**11.  SEGMENT INFORMATION:**

Informationregarding segments is presented in accordance with SFAS 131, *"Disclosureabout Segments of an Enterprise and Related Information."*  Based on thecriteria outlined in SFAS 131, IDACORP has identified two reportable segmentsin 2006: utility operations and IFS.  ITI and IDACOMM, which had previouslybeen identified as reportable segments, are now reported as discontinuedoperations (see Note 17).

Theutility operations segment's primary sources of revenue are the regulatedoperations of IPC.  IPC's regulated operations include the generation,transmission, distribution, purchase and sale of electricity.  This segmentalso includes income from Bridger Coal Company, an unconsolidated joint venturealso subject to regulation.  The IFS segment represents that subsidiary'sinvestments in affordable housing developments and historic rehabilitationprojects.  Operating segments not included above are below the quantitativethresholds for reportable segments and are included in the "All Other"category.  This category is comprised of Ida-West's joint venture investmentsin small hydroelectric generation projects, the remaining activities of energymarketer IE, which wound down its operations in 2003, and IDACORP's holdingcompany expenses.

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Table of Contents

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

** **

**Utility**

** **

**All**

** **

**Consolidated**

** **

**Operations**

**IFS**

**Other**

**Eliminations**  1

**Total**

**2006**

Revenues

$

920,473 

$

1,375 

$

4,443 

$

- 

$

926,291 

Operating income (loss)

176,503 

(389)

(6,410)

- 

169,704 

Other income 

5,060 

(41)

1,217 

(490)

5,746 

Interest income

2,909 

1,295 

1,399 

(1,713)

3,890 

Equity method income (loss)

9,347 

(14,601)

2,341 

- 

(2,913)

Interest expense and  preferred dividends

55,929 

2,761 

4,489 

(2,204)

60,975 

Income (loss) before income  taxes

137,890 

(16,497)

(5,941)

- 

115,452 

Income tax expense (benefit)

43,961 

(26,005)

(2,579)

- 

15,377 

Income (loss) from  continuing operations

93,929 

9,509 

(3,363)

- 

100,075 

Total assets

3,177,725 

131,775 

141,967 

(6,337)

3,445,130

Expenditures for long- lived  assets

221,930 

5,065 

28 

- 

227,023 

**2005**

Revenues

$

837,683 

$

1,379 

$

3,802 

$

- 

$

842,864 

Operating income (loss)

151,654 

(513)

3,512 

- 

154,653 

Other income 

4,623 

368 

786 

(318)

5,459 

Interest income

3,193 

797 

1,426 

(1,760)

3,656 

Equity method income (loss)

10,369 

(12,851)

1,769 

- 

(713)

Interest expense and  preferred dividends

54,075 

3,691 

4,041 

(2,078)

59,729 

Income (loss) before income  taxes

115,764 

(15,890)

3,452 

- 

103,326 

Income tax expense (benefit)

43,925 

(26,801)

486 

- 

17,610 

Income from continuing  operations

71,839 

10,911 

2,966 

- 

85,716 

Total assets

3,074,691 

139,305 

184,039 

(33,909)

3,364,126 

Expenditures for long- lived  assets

186,079 

4,998 

- 

- 

191,077 

**2004**

Revenues

$

822,937 

$

1,392 

$

3,527 

$

- 

$

827,856 

Operating income (loss)

109,038 

(544)

(2,261)

- 

106,233 

Other income 

4,516 

4,857 

4,312 

(69)

13,616 

Interest income

2,413 

655 

893 

(895)

3,066 

Equity method income (loss)

12,313 

(12,502)

1,239 

- 

1,050 

Interest expense and  preferred dividends

56,167 

4,719 

3,213 

(964)

63,135 

Income (loss) before income  taxes

72,113 

(12,253)

970 

- 

60,830 

Income tax expense (benefit)

6,328 

(25,566)

(713)

- 

(19,951)

Income from continuing  operations

65,785 

13,313 

1,683 

- 

80,781 

Total assets

2,969,212 

145,279 

156,072 

(36,392)

3,234,171 

Expenditures for long- lived  assets

190,379 

7,670 

101 

- 

198,150 

** **

1Includes assets of ITI and IDACOMM which are  presented as assets held for sale.

** **

** **

109

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** **

**12.  REGULATORY MATTERS:**

**Regulatory Assets andLiabilities**The following is a breakdown of IPC'sregulatory assets and liabilities (in thousands of dollars):

** **

**As of December 31, 2006**

** **

 
** **

** **

** **

** **

** **

** **

**As of**

 
** **

**Remaining**

** **

**Not**

**Pending**

** **

**December**

 
** **

**Amortization**

**Earning**

**Earning**

**Regulatory**

**2006**

**31, 2005**

 
**Description**

**Period**

**a Return**

**a Return**

**Treatment**

**Total**

**Total**

 
Regulatory Assets:

Income Taxes

$

- 

$

343,590

$

-

$

343,590

$

346,117

SFAS 158 (1)

- 

46,181

-

46,181

-

Conservation

2010

11,349 

-

-

11,349

14,592

PCA Deferral

- 

-

-

-

32,251

Oregon Deferral (2)

9,559 

-

-

9,559

11,291

Asset Retirement

Obligations (3)

- 

11,206

-

11,206

8,363

Tax  Settlement Order

- 

-

-

-

4,994

Grid West Loans

56 

932

302

1,290

-

Various

Other

thru 2008 

390 

1,463

-

1,853

633

Total

$

21,354 

$

403,372

$

302

$

425,028

$

418,241

Regulatory Liabilities:

Income Taxes

$

- 

$

41,825

$

-

$

41,825

$

41,627

Conservation

2007

6,328 

-

-

6,328

6,535

PCA Accrual (4)

2007

(11,852)

27,025

-

15,173

-

Asset Retirement

Obligations (3)

- 

156,162

-

156,162

152,683

Deferred ITC

- 

69,114

-

69,114

68,786

IPUC Settlement

Order

- 

-

-

-

4,021

BPA Settlement

2,124 

-

-

2,124

1,393

Emission Allowance

- 

-

4,118

4,118

70,034

Various

Other

thru 2007

- 

-

-

-

30

Total

$

(3,400)

$

294,126

$

4,118

$

294,844

$

345,109

(1)   See Note 9

 
(2)  Capped at 10 percent  increase per year.

 
(3)  See Note 14

 
(4)  Includes $69 million of  emission allowances, of which $42.1 million earns a return and $27.0 million  does not.

 
 
In the event that recovery ofcosts through rates becomes unlikely or uncertain, SFAS 71 would no longerapply.  If IPC were to discontinue application of SFAS 71 for some or all ofits operations, then these items may represent stranded investments.  If IPC isnot allowed recovery of these investments, it would be required to write offthe applicable portion of regulatory assets and the financial effects could besignificant.

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Table of Contents

**Deferred Power SupplyCosts Idaho:**  IPC has a Power Cost Adjustment(PCA) mechanism that provides for annual adjustments to the rates charged toits Idaho retail customers.  These adjustments are based on forecasts of netpower 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 ofthe difference between the actual and forecasted costs is deferred withinterest.  The ending balance of this deferral, called the true-up for thecurrent 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'sPCA.

**Idaho****Load Growth Adjustment Rate (LGAR):**  In April 2006 IPC filed a petition with the IPUCrequesting modification of one component of its PCA referred to as the LoadGrowth Adjustment Rate.  The LGAR subtracts the cost of serving new Idaho retail customers from the power supply costs IPC is allowed to include in its PCA.

TheLGAR was set at $16.84 per megawatt-hour when the PCA began in 1993.  Thisamount was established as the projected marginal cost of serving each newcustomer and is subtracted from each year's PCA expense.  In its April 2006petition, IPC requested using the embedded cost of serving the new load ratherthan the projected marginal cost and to lower the rate to $6.81 permegawatt-hour.  The IPUC Staff recommended against changing to the embeddedcost approach; IPUC Staff also recommended increasing the rate to $40.87 permegawatt hour.

OnJanuary 9, 2007, the IPUC issued its final order in this matter.  The IPUCmaintained the marginal cost methodology and set the new LGAR at $29.41 permegawatt-hour.  The new rate becomes effective on April 1, 2007 and will firstaffect customer rates on June 1, 2008.

Theimpact of the new LGAR on IPC will ultimately be determined by future loadgrowth.  Assuming an average 40 megawatt load growth, the new rate would resultin approximately $10.3 million subtracted from the next PCA, a pre-tax increaseof $4.4 million over the current amount.  The impact of the new LGAR can bepartially offset by IPC through more frequent general rate case filings withthe IPUC or from less customer growth.  In its order the IPUC stated that itexpected IPC to update its load growth adjustment in all future general ratecases.

**Oregon****:**  Thetiming of recovery of Oregon power supply cost deferrals is subject to an Oregon statute that specifically limits rate amortizations of deferred costs to six percentper year.  IPC is currently amortizing through rates power supply costsassociated with the western energy situation of 2001.  Full recovery of the2001 deferral is not expected until 2009.  For the 2005-2006 deferral, asettlement stipulation drafted by the OPUC Staff provides that, instead ofbeing amortized into rates, the deferral should be offset with the Oregon jurisdictional share of proceeds from the sale of SO2 emission allowancesand the benefit that IPC will receive from income taxes already paid on thesale of those allowances.  An order is expected from the OPUC during the firstquarter of 2007.

**Emission Allowances: **During 2005 and 2006, IPC sold 78,000 SO2emission allowances for approximately $81.6 million (before income taxes andexpenses) on the open market.  After subtracting transaction fees, the totalamount of sales proceeds to be allocated to the Idaho jurisdiction wasapproximately $76.8 million ($46.8 million net of tax, assuming a tax rate ofapproximately 39 percent).  The IPUC allowed IPC to retain ten percent, orapproximately $4.7 million after tax, of the emission allowance net proceeds asa shareholder benefit.  The remaining 90 percent of the sales proceeds ($69.1million) plus a carrying charge will be recorded as a customer benefit.  Thiscustomer benefit will be reflected in PCA rates during the June 1, 2007,through May 31, 2008, PCA rate year.  The carrying charge will be calculated on$42.1 million, the net-of-tax amount allocable to Idaho jurisdiction customers.

As discussed above, astipulation is currently before the OPUC which would offset SO2 emissionallowance proceeds against the 2005-2006 balance of Oregon deferred powersupply costs.  The stipulation allows for IPC to retain ten percent of theproceeds from emission allowance sales as a shareholder benefit.

Through allowance year 2006, IPChas approximately 36,000 excess allowances.

**Deferred (Accrued) NetPower Supply Costs:**IPC's deferred net power supply costsconsisted of the following at December 31 (in thousands of dollars):

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Table of Contents

** **

**2006**

** **

**2005**

Idaho PCA current year:

Deferral for the 2006-2007  rate year

$

- 

$

3,684

Accrual for the 2007-2008  rate year*

(3,484)

-

Idaho PCA true-up awaiting  recovery (refund):

Authorized May 2005

- 

28,567

Authorized May 2006

(11,689)

-

Oregon deferral:

2001 costs

6,670 

8,411

2005 costs

2,889 

2,880

Total  (accrual) deferral

$

(5,614)

$

43,542

*Includes $69 million of  emission allowance sales to be credited to the customers during the 2007-2008  PCA year

**Fixed Cost AdjustmentMechanism (FCA)**On January 27, 2006, IPC filed with the IPUC for authority to implement a rateadjustment mechanism that would adjust rates downward or upward to recoverfixed costs independent from the volume of IPC's energy sales.  This filing isa continuation of a 2004 case that was opened to investigate the financialdisincentives to investment in energy efficiency by IPC.  This true-upmechanism would be applicable only to residential and small general servicecustomers.  The first FCA rate change under this proposal would occur on June1, 2007, coincident with IPC's PCA rate change.  The accounting for the FCAwill be separate from the PCA.  As part of the filing, IPC proposes a threepercent cap on any rate increase to be applied at the discretion of the IPUC.

OnMarch 6, 2006, the IPUC reviewed IPC's proposal and acknowledged the intent ofIPC and the IPUC Staff to initiate and engage in settlement discussions.  TheIPUC Staff presented an alternate view of IPC's proposal.  Three workshops wereheld in 2006 and the parties have agreedin concept to a three-year pilot beginning at the first of the year and astipulation was filed December 18, 2006.  The stipulation calls for theimplementation of a FCA mechanism pilot program as proposed by IPC in itsoriginal application with additional conditions and provisions related tocustomer count and weather normalization methodology, recording of the FCAdeferral amount in reports to the IPUC and detailed reporting of DSMactivities.  The pilot program began on January 1, 2007, and will run through2009, with the first rate adjustment to occur on June 1, 2008, and subsequentrate adjustments to occur on June 1 of each year thereafter during the term ofthe pilot program.  The deadline for filing written comments with respect tothe stipulation and the use of modified procedure was January 31, 2007.  Afinal order is expected from the IPUC in the first quarter of 2007.

**13.  INVESTMENTS:**

The following tablesummarizes IDACORP's and IPC's investments as of December 31 (in thousands ofdollars):

**2006**

** **

**2005**

IPC Investments:

Equity method investment 

$

62,223

$

38,764

Available-for-sale equity  securities 

21,548

21,137

Executive deferred  compensation

6,492

6,201

Other investments 

4

1,025

Total IPC investments 

90,267

67,127

Investments in affordable  housing 

90,266

99,972

Equity method investments 

8,969

8,764

Held-to-maturity debt  securities 

11,069

13,373

Executive deferred  compensation

4,767

5,313

Other investments

-

30

Total IDACORP investments 

$

205,338

$

194,579

**Equity Method Investments**IPC, through its subsidiary IdahoEnergy Resources Co., is a 33 percent owner of Bridger Coal Company, whichsupplies coal to the Jim Bridger generating plant owned in part by IPC. Ida-West, through separate subsidiaries, owns 50 percent of each of thefollowing electric generation projects: South Forks Joint Venture;Hazelton/Wilson Joint Venture and Snow Mountain Hydro LLC.

IFS invests in affordablehousing developments that are accounted for in accordance with APB 18, *"TheEquity Method of Accounting for Investments in Common Stock"* and EmergingIssues Task Force Issue 94-1, "*Accounting for Tax Benefits Resulting fromInvestments in Affordable Housing Projects,"* and are presented asInvestments on the Consolidated Balance Sheets.  All projects are reviewedperiodically for impairment.

The following table presentsIDACORP's and IPC's earnings (loss) of unconsolidated equity-method investments(in thousands of dollars):

**2006**

** **

**2005**

** **

**2004**

Bridger Coal Company (IPC)

$

9,347 

$

10,369 

$

12,313 

Ida-West projects

2,341 

1,769 

1,239 

IFS affordable housing  projects

(14,601)

(12,851)

(12,502)

Total 

$

(2,913)

$

(713)

$

1,050 

 

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Table of Contents

The following table presentssummarized income statement information for Bridger Coal Company (in thousandsof dollars):

**2006**

** **

**2005**

** **

**2004**

Operating revenues

$

154,910 

$

128,015 

$

138,329 

Operating expenses

126,869 

96,909 

101,390 

Net Income 

$

28,041 

$

31,106 

$

36,939 

The following table presentssummarized balance sheet information for Bridger Coal Company (in thousands ofdollars):

**2006**

** **

**2005**

**Assets**

Current assets

$

47,723

$

26,442

Noncurrent assets

325,252

262,909

Total Assets

$

372,975

$

289,351

**Liabilities**

Current liabilities

$

28,250

$

17,728

Noncurrent liabilities

158,054

155,330

Total Liabilities

186,304

173,058

Joint venture capital

186,671

116,293

Total Liabilities and Joint  Venture Capital

$

372,975

$

289,351

**Investments in Debt andEquity Securities**Investments in debt and equitysecurities are accounted for in accordance with SFAS 115, "*Accounting forCertain Investments in Debt and Equity Securities."*  Those investmentsclassified as available-for-sale securities are reported at fair value, usingeither specific identification or average cost to determine the cost forcomputing gains or losses.  Any unrealized gains or losses onavailable-for-sale securities are included in other comprehensive income.

Investments classified asheld-to-maturity securities are reported at amortized cost.  Held-to-maturitysecurities are investments in debt securities for which the company has thepositive intent and ability to hold the securities until maturity.  These debtsecurities have maturities ranging from 2007 through 2025

The following tablesummarizes investments in debt and equity securities (in thousands of dollars):

**2006**

**2005**

**Gross**

**Gross**

** **

**Gross**

**Gross**

** **

**Unrealized**

**Unrealized**

**Fair**

**Unrealized**

**Unrealized**

**Fair**

**Gain**

**Loss**

**Value**

**Gain**

**Loss**

**Value**

Available-for-sale 

securities (IPC)

$

2,474

$

322

$

21,548

$

2,925

$

497

$

21,137

Held-to-maturity debt 

securities (IFS)

5

40

11,034

354

350

13,377

The following tablesummarizes sales of available-for-sale securities (in thousands of dollars):

** **

**2006**

** **

**2005**

** **

**2004**

Proceeds from sales

$

20,778

$

120,026

$

266,331

Gross realized gains from  sales

3,774

2,850

2,044

Gross realized losses from  sales

280

643

634

 

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Table of Contents

Additionally,these investments are evaluated to determine whether they have experienced adecline in market value that is considered other-than-temporary.  IDACORP andIPC analyze securities in loss positions as of the end of each reportingperiod.  Any security with an unrealized loss of more than 20 percent isevaluated for other-than-temporary impairment.  A security will generally bewritten down to market value if it has an unrealized loss of 20 percent or morefor more than nine months.  If additional information is available thatindicates a security is other-than-temporarily impaired, it will be writtendown prior to the nine-month time period.  In the alternative, if a securityhas been impaired for more than nine months but available information indicatesthat the impairment is temporary, the security will not be written down. IDACORP and IPC have not recognized any other-than-temporary impairments in2006, 2005 or 2004.

The following tablesummarizes information regarding securities that were in an unrealized lossposition at the end of each year, but for which no other-than-temporaryimpairment was recognized (in thousands of dollars).

** **

**Less than 12 months**

**12 months or longer**

** **

**Aggregate**

** **

**Aggregate**

**Aggregate**

** **

**Aggregate**

** **

**Unrealized**

** **

**Related Fair**

**Unrealized**

** **

**Related Fair**

** **

**Loss**

** **

**Value**

**Loss**

** **

**Value**

**2006:**

Available for sale equity  securities (IPC)

$

241

$

3,879

$

81

$

621

Held to maturity debt  securities (IFS)

9

578

31

2,278

**2005:**

Available for sale equity  securities (IPC)

$

215

$

1,731

$

282

$

1,423

Held to maturity debt  securities (IFS)

17

1,817

333

4,128

The available-for-sale equitysecurities in unrealized loss positions are diversified investments in commonstock of various companies used to fund IPC's Senior Management Security Plan. The held-to-maturity debt securities in unrealized loss positions are bonds,whose market values fluctuate based on the interest rate environment.  AtDecember 31, 2006, 11 available-for-sale and six held-to-maturity securitieswere in an unrealized loss position.  None of these securities had unrealizedloss positions of greater than 20 percent.  At December 31, 2005, nineavailable-for-sale and 11 held-to-maturity securities were in an unrealizedloss position.  Two available-for-sale securities had unrealized loss positionsof greater than 20 percent.  IDACORP and IPC do not consider these investmentsto be other-than-temporarily impaired at December 31, 2006 or 2005.  BecauseIDACORP has the ability and intent to hold the debt securities until maturity,it does not consider them to be other-than-temporarily impaired at December 31,2006 or 2005.

**14.  ASSET RETIREMENTOBLIGATIONS:**

On January 1, 2003, IDACORPand IPC adopted SFAS 143, *"Accounting for Asset Retirement Obligations,"*requiring legal obligations associated with the retirement of property, plantand equipment to be recognized as a liability at fair value when incurred andwhen a reasonable estimate of the fair value of the liability can be made. Under SFAS 143, when a liability is initially recorded, the entity increasesthe carrying amount of the related long-lived asset to reflect the futureretirement cost.  Over time, the liability is accreted to its present value andpaid, and the capitalized cost is depreciated over the useful life of therelated asset.  If, at the end of the asset's life, the recorded liabilitydiffers from the actual obligations paid, a gain or loss would be recognized. As a rate-regulated entity, IPC records regulatory assets and liabilitiesinstead of accretion, depreciation and gains or losses.  This treatment wasapproved by Order No. 29414 from the IPUC.  The regulatory assets recordedunder this order do not earn a return on investment.

OnDecember 31, 2005, IDACORP and IPC adopted FIN 47, which clarifies the scopeand timing of liability recognition for conditional asset retirementobligations (AROs).  The interpretation requires that a liability be recordedfor the fair value of an ARO, if the fair value is estimable, even when theobligation is dependent on a future event.  FIN 47 further clarified thatuncertainty surrounding the timing and method of settlement of the obligationshould be factored into the measurement of the conditional ARO rather thanaffect whether a liability should be recognized.

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Table of Contents

Upon adoption of FIN 47, oneARO was identified at IDACOMM and two AROs were identified at IPC.  IDACOMM'sARO is due to a contractual obligation to remove pole attachments and conduitline.  This was recorded in December 2005.  IDACOMM recorded an ARO liabilityof $0.4 million and an ARO asset of $0.4 million.  The obligations at IPC arethe result of PCB removals at its distribution facilities and the reclamationand removal costs of one of its jointly owned coal-fired generationfacilities.  These AROs were recorded in March 2006 when they becamemeasurable.  IPC recorded an ARO liability of $2.2 million, fixed assets of$0.5 million, accumulated depreciation of $0.4 million and a regulatory assetof $2.1 million.

Other AROs previouslyidentified and recorded under FAS 143 relate to removal costs identified at twoof IPC's jointly owned coal-fired generation facilities.  IPC has AROsassociated with its transmission system and hydro facilities, however, due tothe indeterminate removal date, the fair value of the associated liabilitiescurrently cannot be estimated and no amounts are recognized in the consolidatedfinancial statements.

Theregulated operations of IPC also collect removal costs in rates for certainassets that do not have associated AROs.  The adoption of SFAS 143 required IPCto redesignate these removal costs as regulatory liabilities.  As of December31, 2006, IPC had $156 million of such costs recorded as regulatory liabilitieson its Consolidated Balance Sheet.

The following table presentsthe changes in the aggregate carrying amount of AROs (in thousands of dollars):

** **

**IDACORP**

**IPC**

** **

**2006**

** **

**2005**

**2006**

** **

**2005**

Balance at beginning of  year

$

10,519

$

9,288

$

10,079

$

9,288

Amount recorded on adoption

-

440

-

-

Accretion expense

665

531

628

531

Revisions in estimated cash  flows

-

260

-

260

Liability incurred

2,204

-

2,204

-

Balance at end of year

$

13,388

$

10,519

$

12,911

$

10,079

**15.  RELATED PARTYTRANSACTIONS (IPC):**

**IDACORP**IPC performs corporate functions suchas financial, legal and management services for IDACORP and its subsidiaries. IPC charges IDACORP for the costs of these services based on service agreementsand other specifically identified costs.  IPC billed IDACORP $4 million in2006, 2005 and 2004 for these services.

**IDACOMM**IPC provides project management andengineering services to IDACOMM.  IDACOMM also pays joint use fees to IPC. Total fees charged to IDACOMM were $0.1 million in 2006 and $0.3 million inboth 2005 and 2004.

**Ida-West**IPC purchases all of the powergenerated by four of Ida-West's hydroelectric projects.  IPC paid $8 million in2006 and $7 million per year in 2005 and 2004.

**16.  OTHER INCOME ANDEXPENSE:**

The following table presentsthe components of Other Income and Other Expense (in thousands of dollars):

115

Table of Contents

**2006**

**2005**

**2004**

**Other income:**

Allowance  for funds used during construction-equity

 $

6,092  

 $

4,950  

 $

3,904  

Investment  income, net

8,489  

6,424  

10,162  

Gain  on extinguishment of debt

-    

-    

7,188  

Other

3,614  

5,747  

4,202  

Total

 $

18,195  

 $

17,121  

 $

25,456  

**Other expense:**

Security  plan pension expense

 $

4,889  

 $

4,548  

 $

4,800  

Other

3,670  

3,458  

3,974  

Total

 $

8,559  

 $

8,006  

 $

8,774  

**17.  DISCONTINUEDOPERATIONS:**

In the second quarter of2006, IDACORP decided to seek buyers for its fuel cell technology subsidiaryITI and its telecommunications subsidiary IDACOMM.  IDACORP had been reviewingstrategic alternatives for ITI and IDACOMM in order to focus on its coreutility business.  The planned disposals of these businesses meet the criteriaestablished for reporting them as assets held for sale as defined by SFAS 144. SFAS 144 requires that a long-lived asset classified as held for sale bemeasured at the lower of its carrying amount or fair value, less costs to sell,and requires the holder to cease depreciation and amortization.  Based on ananalysis of the fair value of each subsidiary, no adjustments to the carryingvalues were required.

OnJuly 20, 2006, IDACORP completed the sale of all of the outstanding commonstock of ITI to IdaTech UK Limited, a wholly-owned subsidiary of Investec GroupInvestments (UK) Limited.  IDACORP recorded a gain of $11.5 million,net-of-tax, or $0.27 per diluted share from this transaction in during the yearended December 31, 2006.

On February 23, 2007, IDACORPcompleted the sale of all of the outstanding common stock of IDACOMM toAmerican Fiber Systems, Inc.

The operating results ofthese businesses have been separately classified and reported as discontinuedoperations on IDACORP's consolidated statements of income.  A summary ofdiscontinued operations is as follows (in thousands of dollars):

** **

** **

**2006**

** **

**2005**

** **

**2004**

Revenues

$

12,882 

$

16,624 

$

16,635 

Operating expenses

(21,369)

(43,528)

(29,617)

Other income

354 

159 

365 

Gain on disposal

14,476 

- 

- 

Pre-tax income (losses)

6,343 

(26,745)

(12,617)

Income tax benefit

985 

4,690 

4,819 

Income (losses) from  discontinued operations

$

7,328 

$

(22,055)

$

(7,798)

** **

The results of operations forthe year ended December 31, 2006, do not include depreciation expense of approximately$1.2 million that would be recorded if the related assets were classified asheld and used.

The assets and liabilities ofIDACOMM and ITI have been classified as held for sale on IDACORP's consolidatedbalance sheets at December 31, 2006 and 2005.  A summary of the components ofassets and liabilities held for sale on IDACORP's Consolidated Balance Sheetsis as follows (in thousands of dollars):

** **

**2006**

** **

**2005**

Assets

Current assets

$

3,326

$

6,673

Property and investments

20,789

19,848

Other assets

287

6,118

Total assets

$

24,402

$

32,639

Liabilities

Current liabilities

$

2,606

$

5,916

Other liabilities

8,773

10,016

Long-term debt

- 

35

Total liabilities

$

11,379

$

15,967

** **

** **

** **

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** **

** **

** **

**REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTINGFIRM**

Tothe Board of Directors and Shareholders of IDACORP, Inc.  Boise, Idaho

We have audited theaccompanying consolidated balance sheets of IDACORP, Inc. and subsidiaries (the"Company") as of December 31, 2006 and 2005, and the related consolidatedstatements of income, comprehensive income, shareholders' equity, and cashflows for each of the three years in the period ended December 31, 2006.  Ouraudits also included the consolidated financial statement schedules listed inthe Index at Item 8.  These financial statements and financial statementschedules are the responsibility of the Company's management.  Ourresponsibility is to express an opinion on the financial statements andfinancial statement schedules based on our audits.

We conducted our audits inaccordance with the standards of the Public Company Accounting Oversight Board(United States).  Those standards require that we plan and perform the audit toobtain reasonable assurance about whether the financial statements are free ofmaterial misstatement.  An audit includes examining, on a test basis, evidencesupporting the amounts and disclosures in the financial statements.  An auditalso includes assessing the accounting principles used and significantestimates made by management, as well as evaluating the overall financialstatement presentation.  We believe that our audits provide a reasonable basisfor our opinion.

Inour opinion, such consolidated financial statements present fairly, in allmaterial respects, the financial position of IDACORP, Inc. and subsidiaries atDecember 31, 2006 and 2005, and the results of their operations and their cashflows for each of the three years in the period ended December 31, 2006, inconformity with accounting principles generally accepted in the United Statesof America.  Also, in our opinion, such consolidated financial statementschedules, when considered in relation to the basic consolidated financialstatements taken as a whole, present fairly, in all material respects, theinformation set forth therein.

As discussed in Note 9 to theconsolidated financial statements, the Company adopted Statement of FinancialAccounting Standards No. 158, *Employers' Accountingfor Defined Benefit Pension and Other Postretirement Plans - an amendment ofFASB Statements No. 87, 88, 106, and 132(R),* as of December 31, 2006.

Wehave also audited, in accordance with the standards of the Public CompanyAccounting Oversight Board (United States), the effectiveness of the Company'sinternal control over financial reporting as of December 31, 2006, based on thecriteria established in *Internal Control-Integrated Framework* issued bythe Committee of Sponsoring Organizations of the Treadway Commission and ourreport dated February 28, 2007 expressed an unqualified opinion on management'sassessment of the effectiveness of the Company's internal control overfinancial reporting and an unqualified opinion on the effectiveness of theCompany's internal control over financial reporting.

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Boise, IdahoFebruary 28, 2007

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** **

** **

** **

**REPORT OF INDEPENDENTREGISTERED PUBLIC ACCOUNTING FIRM**

Tothe Board of Directors and Shareholder of Idaho Power Company  Boise, Idaho

Wehave audited the accompanying consolidated balance sheets and statements ofcapitalization of Idaho Power Company and subsidiary (the "Company") as ofDecember 31, 2006 and 2005, and the related consolidated statements of income,comprehensive income, retained earnings, and cash flows for each of the threeyears in the period ended December 31, 2006.  Our audits also included theconsolidated financial statement schedule listed in the Index at Item 8.  Thesefinancial statements and financial statement schedule are the responsibility ofthe Company's management.  Our responsibility is to express an opinion on thefinancial statements and financial statement schedule based on our audits.

We conducted our audits inaccordance with the standards of the Public Company Accounting Oversight Board(United States).  Those standards require that we plan and perform the audit toobtain reasonable assurance about whether the financial statements are free ofmaterial misstatement.  An audit includes examining, on a test basis, evidencesupporting the amounts and disclosures in the financial statements.  An auditalso includes assessing the accounting principles used and significantestimates made by management, as well as evaluating the overall financialstatement presentation.  We believe that our audits provide a reasonable basisfor our opinion.

Inour opinion, such consolidated financial statements present fairly, in allmaterial respects, the financial position of Idaho Power Company and subsidiaryat December 31, 2006 and 2005, and the results of their operations and theircash flows for each of the three years in the period ended December 31, 2006,in conformity with accounting principles generally accepted in the UnitedStates of America.  Also, in our opinion, such consolidated financial statementschedule, when considered in relation to the basic consolidated financialstatements taken as a whole, presents fairly, in all material respects, theinformation set forth therein.

As discussed in Note 9 to theconsolidated financial statements, the Company adopted Statement of FinancialAccounting Standards No. 158, *Employers' Accountingfor Defined Benefit Pension and Other Postretirement Plans - an amendment ofFASB Statements No. 87, 88, 106, and 132(R),* as of December 31, 2006.

Wehave also audited, in accordance with the standards of the Public CompanyAccounting Oversight Board (United States), the effectiveness of the Company'sinternal control over financial reporting as of December 31, 2006, based on thecriteria established in *Internal Control-Integrated Framework* issued bythe Committee of Sponsoring Organizations of the Treadway Commission and ourreport dated February 28, 2007 expressed an unqualified opinion on management'sassessment of the effectiveness of the Company's internal control overfinancial reporting and an unqualified opinion on the effectiveness of theCompany's internal control over financial reporting.

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Boise, IdahoFebruary 28, 2007

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**SUPPLEMENTALFINANCIAL INFORMATION, UNAUDITED**

**QUARTERLYFINANCIAL DATA:**

Thefollowing unaudited information is presented for each quarter of 2006 and 2005(in thousands of dollars except for per share amounts).  In the opinion of eachcompany, all adjustments necessary for a fair statement of such amounts for suchperiods have been included.  The results of operations for the interim periodsare not necessarily indicative of the results to be expected for the fullyear.  Accordingly, earnings information for any three-month period should notbe considered as a basis for estimating operating results for a full fiscalyear.  Amounts are based upon quarterly statements and the sum of the quartersmay not equal the annual amount reported.

**Quarter Ended**

**March 31**

**June 30**

**September 30**

**December 31**

**IDACORP, Inc.**

**2006**

Revenues

 $

268,340  

 $

242,635  

 $

230,532  

 $

184,784  

Operating income

46,478  

45,551  

56,656  

21,019  

Income from continuing  operations

26,955  

22,673  

32,492  

17,955  

Income (loss) from  discontinued operations, net

(1,479)

(2,817)

11,497  

127  

Net income

25,476  

19,856  

43,989  

18,082  

Basic earnings (loss) per  share

Continuing  operations

0.64  

0.53  

0.76  

0.42  

Discontinued  operations

(0.04)

(0.06)

0.27  

-    

Total

0.60  

0.47  

1.03  

0.42  

Diluted earnings (loss) per  share

Continuing  operations

0.63  

0.53  

0.76  

0.42  

Discontinued  operations

(0.04)

(0.06)

0.27  

-    

Total

0.59  

0.47  

1.03  

0.42  

**2005**

Revenues

 $

191,118  

 $

200,470  

 $

245,179  

 $

206,097  

Operating income

38,498  

28,136  

47,905  

40,114  

Income from continuing  operations

25,642  

12,593  

25,961  

21,520  

Income (loss) from  discontinued operations, net

(2,576)

(3,142)

(2,344)

(13,993)

Net income

23,066  

9,451  

23,617  

7,527  

Basic earnings (loss) per  share

Continuing  operations

0.61  

0.30  

0.61  

0.51  

Discontinued  operations

(0.06)

(0.08)

(0.05)

(0.33)

Total

0.55  

0.22  

0.56  

0.18  

Diluted earnings (loss) per  share

Continuing  operations

0.61  

0.30  

0.61  

0.51  

Discontinued  operations

(0.06)

(0.08)

(0.05)

(0.33)

Total

0.55  

0.22  

0.56  

0.18  

**Idaho Power Company**

**2006**

Revenues

 $

267,274  

 $

240,848  

 $

228,799  

 $

183,552  

Income from operations

49,229  

46,810  

58,216  

22,248  

Net income

25,021  

21,612  

30,389  

16,907  

**2005**

Revenues

 $

190,460  

 $

198,888  

 $

243,503  

 $

204,832  

Income from operations

40,897  

29,748  

49,259  

31,750  

Net income

21,509  

12,876  

20,969  

16,485  

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Incomefrom discontinued operations was affected in the third quarter of 2006 by an$11.5 million gain on the sale of ITI and in the fourth quarter of 2005 by a$10 million goodwill impairment at IDACOMM.

**ITEM 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTSON ACCOUNTING AND FINANCIAL DISCLOSURE**

None

**ITEM9A.  CONTROLS AND PROCEDURES**

Disclosure controls andprocedures:

**IDACORP:**

The Chief Executive Officerand Chief Financial Officer of IDACORP, based on their evaluation of IDACORP'sdisclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e))as of December 31, 2006, have concluded that IDACORP's disclosure controls andprocedures are effective.

**IPC:**

The Chief Executive Officerand Chief Financial Officer of IPC, based on their evaluation of IPC's disclosurecontrols and procedures (as defined in Exchange Act Rule 13a-15(e)) as ofDecember 31, 2006, have concluded that IPC's disclosure controls and proceduresare effective.

Internal control overfinancial reporting:

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** **

** **

**IDACORP:**

**Management's Annual ReportOn Internal Control Over Financial Reporting**The management of IDACORP isresponsible for establishing and maintaining adequate internal control overfinancial reporting for IDACORP.  Internal control over financial reporting isdefined in Rule 13a-15(f) promulgated under the Securities Exchange Act of 1934as a process designed by, or under the supervision of, the company's principalexecutive and principal financial officers and effected by the company's boardof directors, management and other personnel, to provide reasonable assuranceregarding the reliability of financial reporting and the preparation offinancial statements for external purposes in accordance with accountingprinciples generally accepted in the United States of America and includesthose policies and procedures that:
- Pertain to the maintenance     of records that in reasonable detail accurately and fairly reflect the     transactions and dispositions of the assets of the company;
- Provide reasonable     assurance that transactions are recorded as necessary to permit     preparation of financial statements in accordance with accounting     principles generally accepted in the United States of America, and that     receipts and expenditures of the company are being made only in accordance     with the authorizations of management and directors of the company; and
- Provide reasonable     assurance regarding prevention or timely detection of unauthorized     acquisition, use or disposition of the company's assets that could have a     material effect on the financial statements.

Because of its inherentlimitations, internal control over financial reporting may not prevent ordetect misstatements.  Projections of any evaluation of effectiveness to futureperiods are subject to the risk that controls may become inadequate because ofchanges in conditions, or that the degree of compliance with the policies orprocedures may deteriorate.

IDACORP's management assessedthe effectiveness of the company's internal control over financial reporting asof December 31, 2006.  In making this assessment, the company's management usedthe criteria set forth by the Committee of Sponsoring Organizations of theTreadway Commission in *Internal Control-Integrated Framework*.

Based on its assessment,management believes that, as of December 31, 2006 IDACORP's internal controlover financial reporting is effective based on those criteria.

IDACORP's independentregistered public accounting firm has audited the financial statements includedin this Annual Report on Form 10-K for the year ended December 31, 2006 andissued a report, which appears on the next page and expresses an unqualifiedopinion on management's assessment and on the effectiveness of IDACORP'sinternal control over financial reporting as of December 31, 2006.

February 28, 2007

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**REPORT OF INDEPENDENTREGISTERED PUBLIC ACCOUNTING FIRM**

To the Board of Directors andShareholders of IDACORP, Inc.  Boise, Idaho

We have audited management'sassessment, included in the accompanying Management's Annual Report on InternalControl over Financial Reporting, that IDACORP, Inc. and subsidiaries (the "Company")maintained effective internal control over financial reporting as of December31, 2006, based on criteria established in *Internal Control-IntegratedFramework* issued by the Committee of Sponsoring Organizations of theTreadway Commission.  The Company's management is responsible for maintainingeffective internal control over financial reporting and for its assessment ofthe effectiveness of internal control over financial reporting.  Ourresponsibility is to express an opinion on management's assessment and anopinion on the effectiveness of the Company's internal control over financialreporting based on our audit.

Weconducted our audit in accordance with the standards of the Public CompanyAccounting Oversight Board (United States).  Those standards require that weplan and perform the audit to obtain reasonable assurance about whethereffective internal control over financial reporting was maintained in allmaterial respects.  Our audit included obtaining an understanding of internalcontrol over financial reporting, evaluating management's assessment, testingand evaluating the design and operating effectiveness of internal control, andperforming such other procedures as we considered necessary in thecircumstances.  We believe that our audit provides a reasonable basis for ouropinions.

A company's internal controlover financial reporting is a process designed by, or under the supervision of,the company's principal executive and principal financial officers, or personsperforming similar functions, and effected by the company's board of directors,management, and other personnel to provide reasonable assurance regarding thereliability of financial reporting and the preparation of financial statementsfor external purposes in accordance with generally accepted accountingprinciples.  A company's internal control over financial reporting includesthose policies and procedures that (1) pertain to the maintenance of recordsthat, in reasonable detail, accurately and fairly reflect the transactions anddispositions of the assets of the company; (2) provide reasonable assurancethat transactions are recorded as necessary to permit preparation of financialstatements in accordance with generally accepted accounting principles, andthat receipts and expenditures of the company are being made only in accordancewith authorizations of management and directors of the company; and (3) providereasonable assurance regarding prevention or timely detection of unauthorizedacquisition, use, or disposition of the company's assets that could have amaterial effect on the financial statements.

Because of the inherentlimitations of internal control over financial reporting, including thepossibility of collusion or improper management override of controls, materialmisstatements due to error or fraud may not be prevented or detected on atimely basis.  Also, projections of any evaluation of the effectiveness of theinternal control over financial reporting to future periods are subject to therisk that the controls may become inadequate because of changes in conditions,or that the degree of compliance with the policies or procedures maydeteriorate.

In our opinion, management'sassessment that the Company maintained effective internal control overfinancial reporting as of December 31, 2006, is fairly stated, in all materialrespects, based on the criteria established in *Internal Control-IntegratedFramework* issued by the Committee of Sponsoring Organizations of theTreadway Commission.  Also in our opinion, the Company maintained, in allmaterial respects, effective internal control over financial reporting as ofDecember 31, 2006, based on the criteria established in *InternalControl-Integrated Framework* issued by the Committee of SponsoringOrganizations of the Treadway Commission.

We have also audited, inaccordance with the standards of the Public Company Accounting Oversight Board(United States), the consolidated financial statements and financial statementschedules as of and for the year ended December 31, 2006 of the Company and ourreport dated February 28, 2007 expressed an unqualified opinion on thosefinancial statements and financial statement schedules and included anexplanatory paragraph regarding the Company's adoption of Statement ofFinancial Accounting Standards No. 158.

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**Idaho Power Company:**

**Management's Annual Reporton Internal Control Over Financial Reporting**The management of Idaho Power Company(IPC) is responsible for establishing and maintaining adequate internal controlover financial reporting of IPC.  Internal control over financial reporting isdefined in Rule 13a-15(f) promulgated under the Securities Exchange Act of 1934as a process designed by, or under the supervision of, the company's principalexecutive and principal financial officers and effected by the company's boardof directors, management and other personnel, to provide reasonable assuranceregarding the reliability of financial reporting and the preparation offinancial statements for external purposes in accordance with accountingprinciples generally accepted in the United States of America and includesthose policies and procedures that:
- Pertain to the maintenance     of records that in reasonable detail accurately and fairly reflect the     transactions and dispositions of the assets of the company;
- Provide reasonable     assurance that transactions are recorded as necessary to permit     preparation of financial statements in accordance with accounting     principles generally accepted in the United States of America, and that     receipts and expenditures of the company are being made only in accordance     with the authorizations of management and directors of the company; and
- Provide reasonable     assurance regarding prevention or timely detection of unauthorized     acquisition, use or disposition of the company's assets that could have a     material effect on the financial statements.

Because of its inherentlimitations, internal control over financial reporting may not prevent ordetect misstatements.  Projections of any evaluation of effectiveness to futureperiods are subject to the risk that controls may become inadequate because ofchanges in conditions, or that the degree of compliance with the policies orprocedures may deteriorate.

IPC's management assessed theeffectiveness of the company's internal control over financial reporting as ofDecember 31, 2006.  In making this assessment, the company's management usedthe criteria set forth by the Committee of Sponsoring Organizations of theTreadway Commission in *Internal Control-Integrated Framework*.

Based on its assessment,management believes that, as of December 31, 2006, IPC's internal control overfinancial reporting is effective based on those criteria.

IPC's independent registeredpublic accounting firm has audited the financial statements included in thisAnnual Report on Form 10-K for the year ended December 31, 2006 and issued a report,which appears on the next page and expresses an unqualified opinion onmanagement's assessment and on the effectiveness of IPC's internal control overfinancial reporting as of December 31, 2006.

February 28, 2007

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**REPORT OF INDEPENDENTREGISTERED PUBLIC ACCOUNTING FIRM**

To the Board of Directors andShareholder of Idaho Power Company  Boise, Idaho

We have audited management'sassessment, included in the accompanying Management's Annual Report on InternalControl over Financial Reporting, that Idaho Power Company and subsidiary (the "Company")maintained effective internal control over financial reporting as of December31, 2006, based on criteria established in *Internal Control-IntegratedFramework* issued by the Committee of Sponsoring Organizations of theTreadway Commission.  The Company's management is responsible for maintainingeffective internal control over financial reporting and for its assessment ofthe effectiveness of internal control over financial reporting.  Our responsibilityis to express an opinion on management's assessment and an opinion on theeffectiveness of the Company's internal control over financial reporting basedon our audit.

We conducted our audit inaccordance with the standards of the Public Company Accounting Oversight Board(United States). Those standards require that we plan and perform the audit toobtain reasonable assurance about whether effective internal control overfinancial reporting was maintained in all material respects.  Our audit includedobtaining an understanding of internal control over financial reporting,evaluating management's assessment, testing and evaluating the design andoperating effectiveness of internal control, and performing such otherprocedures as we considered necessary in the circumstances.  We believe thatour audit provides a reasonable basis for our opinions.

A company's internal controlover financial reporting is a process designed by, or under the supervision of,the company's principal executive and principal financial officers, or personsperforming similar functions, and effected by the company's board of directors,management, and other personnel to provide reasonable assurance regarding thereliability of financial reporting and the preparation of financial statementsfor external purposes in accordance with generally accepted accountingprinciples.  A company's internal control over financial reporting includesthose policies and procedures that (1) pertain to the maintenance of recordsthat, in reasonable detail, accurately and fairly reflect the transactions anddispositions of the assets of the company; (2) provide reasonable assurancethat transactions are recorded as necessary to permit preparation of financialstatements in accordance with generally accepted accounting principles, andthat receipts and expenditures of the company are being made only in accordancewith authorizations of management and directors of the company; and (3) providereasonable assurance regarding prevention or timely detection of unauthorizedacquisition, use, or disposition of the company's assets that could have amaterial effect on the financial statements.

Because of the inherentlimitations of internal control over financial reporting, including thepossibility of collusion or improper management override of controls, materialmisstatements due to error or fraud may not be prevented or detected on atimely basis.  Also, projections of any evaluation of the effectiveness of theinternal control over financial reporting to future periods are subject to therisk that the controls may become inadequate because of changes in conditions,or that the degree of compliance with the policies or procedures maydeteriorate.

In our opinion, management'sassessment that the Company maintained effective internal control overfinancial reporting as of December 31, 2006, is fairly stated, in all materialrespects, based on the criteria established in *Internal Control-IntegratedFramework* issued by the Committee of Sponsoring Organizations of theTreadway Commission.  Also in our opinion, the Company maintained, in allmaterial respects, effective internal control over financial reporting as ofDecember 31, 2006, based on the criteria established in *InternalControl-Integrated Framework* issued by the Committee of SponsoringOrganizations of the Treadway Commission.

We have also audited, inaccordance with the standards of the Public Company Accounting Oversight Board(United States), the consolidated financial statements and financial statementschedule as of and for the year ended December 31, 2006 of the Company and ourreport dated February 28, 2007 expressed an unqualified opinion on thosefinancial statements and financial statement schedule and included anexplanatory paragraph regarding the Company's adoption of Statement ofFinancial Accounting Standards No. 158.

DELOITTE & TOUCHE LLPBoise, IdahoFebruary 28, 2007

 

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**Changes in Internal Control Over Financial Reporting**There have been no changes in IDACORP's or IPC's internal control overfinancial reporting during the quarter ended December 31, 2006, requiringdisclosure that have materially affected, or are reasonably likely tomaterially affect, IDACORP's or IPC's internal control over financialreporting.

**ITEM 9B.  OTHER INFORMATION**

None

**PARTIII**

**ITEM10.  DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE**

The portion of IDACORP'sdefinitive proxy statement appearing under the captions "Proposal No. 1:Election of Directors - Nominees for Election - Terms Expire 2010," "Nomineefor Election - Term Expires 2009," "Continuing Directors - Terms Expire 2009," "ContinuingDirectors - Terms Expire 2008," "Section 16(a) Beneficial Ownership ReportingCompliance," "Corporate Governance - Audit Committee," paragraph 1 and "CorporateGovernance - Code of Ethics," to be filed pursuant to Regulation 14A for the2007 Annual Meeting of Shareholders to be held on May 17, 2007 is herebyincorporated by reference.

**ITEM11.  EXECUTIVE COMPENSATION**

The portion of IDACORP'sdefinitive proxy statement appearing under the caption "Executive Compensation"to be filed pursuant to Regulation 14A for the 2007 Annual Meeting ofShareholders to be held on May 17, 2007 is hereby incorporated by reference.

**ITEM 12.  SECURITYOWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDERMATTERS**

The portion of IDACORP'sdefinitive proxy statement appearing under the caption "Security Ownership ofDirectors, Executive Officers and Five Percent Shareholders" to be filedpursuant to Regulation 14A for the 2007 Annual Meeting of Shareholders to beheld on May 17, 2007 is hereby incorporated by reference.

Thefollowing table includes information as of December 31, 2006 with respect toequity compensation plans where equity securities of IDACORP may be issued. These plans are the 1994 Restricted Stock Plan (RSP), the IDACORP 2000Long-Term Incentive and Compensation Plan (LTICP) and the Non-Employee DirectorStock Compensation Plan (DSP).

** **

** **

**(a)**

** **

**(b)**

** **

**(c)**

** **

** **

** **

** **

** **

** **

**Number of securities**

** **

** **

** **

** **

** **

** **

**remaining available for**

** **

** **

**Number of securities to**

** **

**Weighted-average**

** **

**future issuance under**

** **

** **

**be issued upon exercise**

** **

**exercise price of**

** **

**equity compensation**

** **

** **

**of outstanding options,**

** **

**outstanding options,**

** **

**plans (excluding securities**

**Plan Category**

** **

**warrants and rights**

** **

**warrants and rights**

** **

**reflected in column (a))**

Equity compensation

plans approved by

shareholders (1)

840,888

$

34.36

1,792,887(2)(3)

Equity compensation

plans not approved

by shareholders(4)

-

$

-

53,699    

Total

840,888

$

34.36

1,846,586    

(1)

Consists of the RSP and the  LTICP.

(2)

In addition to being  available for future issuance upon exercise of  options, 1,688,562 shares  under the LTICP may instead be issued in 

connection with stock  appreciation rights, restricted stock, restricted stock units, performance  units, performance shares or other equity-

based awards.

(3)

104,325 shares remain  available for future issuance under the RSP.

(4)

Consists of shares available  for future issuance under the DSP.

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**Equity Compensation PlansNot Approved by IDACORP Shareholders**:The DSP was adopted by the Board of Directors effective May 17, 1999.  Thepurpose of the DSP is to increase directors' stock ownership throughstock-based compensation.  The DSP provides for an annual stock grant inFebruary of each year valued at $40,000. 

**ITEM13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE**

The portion of IDACORP'sdefinitive proxy statement appearing under the caption  "Related PersonTransaction Disclosure" and "Corporate Governance - Director Independence" tobe filed pursuant to Regulation 14A for the 2007 Annual Meeting of Shareholdersto be held on May 17, 2007 is hereby incorporated by reference.

**ITEM14.  PRINCIPAL ACCOUNTANT FEES AND SERVICES**

**IDACORP:**

The portion of IDACORP'sdefinitive proxy statement appearing under the caption "Independent AccountantBillings" in the proxy statement to be filed pursuant to Regulation 14A for the2007 Annual Meeting of Shareholders to be held on May 17, 2007 is herebyincorporated by reference.

**IPC:**

The following table presentsfees billed for professional services rendered by Deloitte & Touche LLP,the member firms of Deloitte Touche Tohmatsu, and their respective affiliates(collectively, Deloitte & Touche), for the fiscal years ended December 31,2006 and 2005.  The amounts presented below reflect allocations from IDACORPfor IPC's portion of the fees, as well as amounts billed directly to IPC.

** **

**2006**

** **

**2005**

 
Audit fees

$

726,048

$

704,360

 
Audit-related fees (1)

46,000

47,250

 
Tax fees (2)

391,175

14,045

 
Total

$

1,163,223

$

765,655

 
 
(1)

Includes fees for audits of  IPC's benefit plans.

(2)

Includes fees for tax  compliance and tax consulting in connection with IRS account analysis and  uniform capitalization.

**Policyon Audit Committee Pre-Approval**IPC and the Audit Committee are committed to ensuring the independence of theindependent registered public accounting firm, both in fact and in appearance. In this regard, on February 4, 2004, the Audit Committee established apre-approval policy in accordance with applicable securities rules.  All feeswere pre-approved by the Audit Committee in 2005 and 2006.

Inaddition to the audits of IPC's consolidated financial statements, theindependent public accounting firm may be engaged to provide certainaudit-related, tax and other services.  The Audit Committee must pre-approveall services performed by the independent public accounting firm to assure thatthe provision of those services does not impair the public accounting firm'sindependence.  The services that the Audit Committee will consider includeaudit services such as attest services, changes in the scope of the audit ofthe financial statements, and the issuance of comfort letters and consents inconnection with financings; audit-related services such as internal controlreviews and assistance with internal control reporting requirements; attestservices related to financial reporting that are not required by statute orregulation, and accounting consultations and audits related to proposedtransactions and new or proposed accounting rules, standards andinterpretations; and tax compliance and planning services.  Unless a type ofservice to be provided by the independent public accounting firm has receivedgeneral pre-approval, it will require specific pre-approval by the AuditCommittee.  In addition, any proposed services exceeding pre-approved costlevels will require specific pre-approval by the Audit Committee.  Under thepre-approval policy, the Audit Committee has delegated to the Chairman of theAudit Committee pre-approval authority for proposed audit and audit-relatedservices.  The Chairman must report any pre-approval decisions to the Audit Committeeat its next scheduled meeting.

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Any request to engage theindependent public accounting firm to provide a service which has not receivedgeneral pre-approval must be submitted as a written proposal to IPC's ChiefFinancial Officer with a copy to the General Counsel.  The request must includea detailed description of the service to be provided, the proposed fee and thebusiness reasons for engaging the independent public accounting firm to providethe service.  Upon approval by the Chief Financial Officer, the General Counseland the independent public accounting firm that the proposed engagementcomplies with the terms of the pre-approval policy and the applicable rules andregulations, the request will be presented to the Audit Committee or the CommitteeChairman, as the case may be, for pre-approval.

In determining whether topre-approve the engagement of the independent public accounting firm, the AuditCommittee or the Committee Chairman, as the case may be, must consider, amongother things, the pre-approval policy, applicable rules and regulations andwhether the nature of the engagement and the related fees are consistent withthe following principles, as stated in the SEC's adopting release for the ruleson auditor independence:
- the independent public     accounting firm cannot function in the role of management of IPC;
- the independent public     accounting firm cannot audit its own work; and
- the independent public     accounting firm cannot serve in any advocacy role on behalf of IPC.    

Theappendices to the pre-approval policy describe the specific audit, auditrelated, tax and other services that have the general pre-approval of the AuditCommittee.  The term of any pre-approval is 12 months from the date ofpre-approval, unless the Audit Committee specifically provides for a differentperiod.  The Audit Committee will periodically revise the list of pre-approvedservices, based on subsequent determinations.

** **

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**PART IV**

**ITEM15.  EXHIBITS AND FINANCIAL STATEMENT SCHEDULES**

(1) and (2)  Please refer toPart II, Item 8 - "Financial Statements and Supplementary Data" for a completelisting of all consolidated financial statements and financial statementschedules.

(3)  Exhibits.

*Previously Filed andIncorporated Herein by Reference

127

Table of Contents

*2

Agreement and Plan of  Exchange between IDACORP, Inc., and IPC dated as of February 2, 1998.  File  number 333-48031, Form S-4, filed on 3/16/98, as Exhibit 2.

*3(a)

Restated Articles of  Incorporation of IPC as filed with the Secretary of State of Idaho on June  30, 1989.  File number 33-00440, Post-Effective Amendment No. 2 to Form S-3,  filed on 6/30/89, as Exhibit 4(a)(xiii).

*3(a)(i)

Statement of Resolution  Establishing Terms of Flexible Auction Series A, Serial Preferred Stock,  Without Par Value (cumulative stated value of $100,000 per share) of IPC, as  filed with the Secretary of State of Idaho on November 5, 1991.  File number  33-65720, Form S-3, filed on 7/7/93, as Exhibit 4(a)(ii).

*3(a)(ii)

Statement of Resolution  Establishing Terms of 7.07% Serial Preferred Stock, Without Par Value  (cumulative stated value of $100 per share) of IPC, as filed with the  Secretary of State of Idaho on June 30, 1993.  File number 33-65720, Form  S-3, filed on 7/7/93, as Exhibit 4(a)(iii).

*3(a)(iii)

Articles of Amendment to  Restated Articles of Incorporation of IPC, as amended, as filed with the  Secretary of State of Idaho on January 21, 2005.  File number 1-3198, Form  8-K, filed on 1/26/05, as Exhibit 3.3.

*3(b)

Amended Bylaws of IPC,  amended on January 20, 2005, and presently in effect.  File number 1-3198,  Form 8-K, filed on 1/26/05, as Exhibit 3.2.

*3(c)

Articles of Share Exchange,  as filed with the Secretary of State of Idaho on September 29, 1998.  File  number 33-56071-99, Post-Effective Amendment No. 1 to Form S-8, filed on  10/1/98, as Exhibit 3(d). 

*3(d)

Articles of Incorporation  of IDACORP, Inc.  File number 333-64737, Amendment No. 1 to Form S-3, filed  on 11/4/98, as Exhibit 3.1.

*3(d)(i)

Articles of Amendment to  Articles of Incorporation of IDACORP, Inc. as filed with the Secretary of  State of Idaho on March 9, 1998.  File number 333-64737, Amendment No. 1 to  Form S-3, filed on 11/4/98, as Exhibit 3.2.

*3(d)(ii)

Articles of Amendment to  Articles of Incorporation of IDACORP, Inc. creating A Series Preferred Stock,  without par value, as filed with the Secretary of State of Idaho on September  17, 1998.  File number 333-00139-99, Post-Effective Amendment No. 1 to Form  S-3, filed on 9/22/98, as Exhibit 3(b).

*3(e)

Amended Bylaws of IDACORP,  Inc., amended on January 20, 2005, and presently in effect.  File number  1-14456, Form 8-K, filed on 1/26/05, as Exhibit 3.1.

*4(a)(i)

Mortgage and Deed of Trust,  dated as of October 1, 1937, between IPC and Deutsche Bank Trust Company  Americas (formerly known as Bankers Trust Company) and R. G. Page, as  Trustees.  File number 2-3413, as Exhibit B-2.

*4(a)(ii)

IPC Supplemental Indentures  to Mortgage and Deed of Trust:

File number 1-MD, as  Exhibit B-2-a, First, July 1, 1939

File number 2-5395, as  Exhibit 7-a-3, Second, November 15, 1943

File number 2-7237, as  Exhibit 7-a-4, Third, February 1, 1947

File number 2-7502, as  Exhibit 7-a-5, Fourth, May 1, 1948

File number 2-8398, as  Exhibit 7-a-6, Fifth, November 1, 1949

File number 2-8973, as Exhibit  7-a-7, Sixth, October 1, 1951

File number 2-12941, as  Exhibit 2-C-8, Seventh, January 1, 1957

File number 2-13688, as  Exhibit 4-J, Eighth, July 15, 1957

File number 2-13689, as  Exhibit 4-K, Ninth, November 15, 1957

File number 2-14245, as Exhibit  4-L, Tenth, April 1, 1958

File number 2-14366, as  Exhibit 2-L, Eleventh, October 15, 1958

File number 2-14935, as  Exhibit 4-N, Twelfth, May 15, 1959

File number 2-18976, as  Exhibit 4-O, Thirteenth, November 15, 1960

File number 2-18977, as Exhibit  4-Q, Fourteenth, November 1, 1961

File number 2-22988, as  Exhibit 4-B-16, Fifteenth, September 15, 1964

File number 2-24578, as  Exhibit 4-B-17, Sixteenth, April 1, 1966

File number 2-25479, as  Exhibit 4-B-18, Seventeenth, October 1, 1966

File number 2-45260, as  Exhibit 2(c), Eighteenth, September 1, 1972

File number 2-49854, as  Exhibit 2(c), Nineteenth, January 15, 1974

File number 2-51722, as  Exhibit 2(c)(i), Twentieth, August 1, 1974

File number 2-51722, as  Exhibit 2(c)(ii), Twenty-first, October 15, 1974

File number 2-57374, as  Exhibit 2(c), Twenty-second, November 15, 1976

File number 2-62035, as  Exhibit 2(c), Twenty-third, August 15, 1978

File number 33-34222, as  Exhibit 4(d)(iii), Twenty-fourth, September 1, 1979

File number 33-34222, as  Exhibit 4(d)(iv), Twenty-fifth, November 1, 1981

File number 33-34222, as  Exhibit 4(d)(v), Twenty-sixth, May 1, 1982

File number 33-34222, as  Exhibit 4(d)(vi), Twenty-seventh, May 1, 1986

File number 33-00440, as  Exhibit 4(c)(iv), Twenty-eighth, June 30, 1989

File number 33-34222, as  Exhibit 4(d)(vii), Twenty-ninth, January 1, 1990

File number 33-65720, as  Exhibit 4(d)(iii), Thirtieth, January 1, 1991

File number 33-65720, as  Exhibit 4(d)(iv), Thirty-first, August 15, 1991

File number 33-65720, as  Exhibit 4(d)(v), Thirty-second, March 15, 1992

File number 33-65720, as  Exhibit 4(d)(vi), Thirty-third, April 1, 1993

File number 1-3198, Form  8-K, filed on 12/20/93, as Exhibit 4, Thirty-fourth, December 1, 1993

File number 1-3198, Form  8-K, filed on 11/21/00, as Exhibit 4, Thirty-fifth, November 1, 2000

File number 1-3198, Form  8-K, filed on 10/1/01, as Exhibit 4, Thirty-sixth, October 1, 2001

File number 1-3198, Form  8-K, filed on 4/16/03, as Exhibit 4, Thirty-seventh, April 1, 2003

File number 1-3198, Form  10-Q for the quarter ended 6/30/03, filed on 8/7/03, as Exhibit 4(a)(iii),  Thirty-eighth, May 15, 2003

File number 1-3198, Form  10-Q for the quarter ended 9/30/03, filed on 11/6/03, as Exhibit 4(a)(iii),  Thirty-ninth, October 1, 2003

File number 1-3198, Form  8-K filed 5/10/05, as Exhibit 4, Fortieth, May 1, 2005.

File number 1-3198, Form  8-K filed 10/10/06, as Exhibit 4, Forty-first, October 1, 2006.

*4(b)

Instruments relating to IPC  American Falls bond guarantee (see Exhibit 10(c)).  File number 1-3198, Form  10-Q for the quarter ended 6/30/00, filed on 8/4/00, as Exhibit 4(b).

*4(c)(i)

Agreement of IPC to furnish  certain debt instruments.  File number 33-65720, Form S-3, filed on 7/7/93,  as Exhibit 4(f).

*4(c)(ii)

Agreement of IDACORP, Inc.  to furnish certain debt instruments.  File number 1-14465, Form 10-Q for the  quarter ended 9/30/03, filed on 11/6/03, as Exhibit 4(c)(ii).

*4(d)

Agreement and Plan of  Merger dated March 10, 1989, between Idaho Power Company, a Maine  Corporation, and Idaho Power Migrating Corporation.  Post-Effective Amendment  No. 2 to Form S-3, File number 33-00440, filed on 6/30/89, as Exhibit  2(a)(iii).

*4(e)

Rights Agreement, dated as  of September 10, 1998, between IDACORP, Inc. and Wells Fargo Bank, N.A., as  successor to The Bank of New York, as Rights Agent.  File number 1-14465,  Form 8-K, filed on 9/15/98, as Exhibit 4.

*4(f)

Indenture for Senior Debt  Securities dated as of February 1, 2001, between IDACORP, Inc. and Deutsche  Bank Trust Company Americas (formerly known as Bankers Trust Company), as  trustee.  File number 1-14465, Form 8-K, filed on 2/28/01, as Exhibit 4.1.

*4(g)

First Supplemental  Indenture dated as of February 1, 2001 to Indenture for Senior Debt  Securities dated as of February 1, 2001 between IDACORP, Inc. and Deutsche  Bank Trust Company Americas (formerly known as Bankers Trust Company), as  trustee.  File number 1-14465, Form 8-K, filed on 2/28/01, as Exhibit 4.2.

*4(h)

Indenture for Debt  Securities dated as of August 1, 2001 between Idaho Power Company and  Deutsche Bank Trust Company Americas (formerly known as Bankers Trust  Company), as trustee.  File number 333-67748, Form S-3, filed on 8/16/01, as  Exhibit 4.13.
      
*10(a)

Agreements, dated September  22, 1969, between IPC and Pacific Power & Light Company relating to the  operation, construction and ownership of the Jim Bridger Project.  File  number 2-49584, as Exhibit 5(b).

*10(a)(i)

Amendment, dated February  1, 1974, relating to operation agreement filed as Exhibit 10(a).  File number  2-51762, as Exhibit 5(c). 

*10(b)

Agreement, dated as of  October 11, 1973, between IPC and Pacific Power & Light Company.  File  number 2-49584, as Exhibit 5(c).

*10(c)

Guaranty Agreement, dated  April 11, 2000, between IPC and Bank One Trust Company, N.A., as Trustee,  relating to $19,885,000 American Falls Replacement Dam Refinancing Bonds of  the American Falls Reservoir District, Idaho.  File number 1-3198, Form 10-Q  for the quarter ended 6/30/00, filed on 8/4/00, as Exhibit 10(c).

*10(d)

Guaranty Agreement, dated  as of August 30, 1974, between IPC and Pacific Power & Light Company.   File number 2-62034, Form S-7, filed on 6/30/78, as Exhibit 5(r).

*10(e)

Letter Agreement, dated  January 23, 1976, between IPC and Portland General Electric Company.  File  number 2-56513, as Exhibit 5(i).

*10(e)(i)

Agreement for Construction,  Ownership and Operation of the Number One Boardman Station on Carty  Reservoir, dated as of October 15, 1976, between Portland General Electric  Company and IPC.  File number 2-62034, Form S-7, filed on 6/30/78, as Exhibit  5(s).

*10(e)(ii)

Amendment, dated September  30, 1977, relating to agreement filed as Exhibit 10(e).  File number 2-62034,  Form S-7, filed on 6/30/78, as Exhibit 5(t).

*10(e)(iii)

Amendment, dated October  31, 1977, relating to agreement filed as Exhibit 10(e).  File number 2-62034,  Form S-7, filed on 6/30/78, as Exhibit 5(u).

*10(e)(iv)

Amendment, dated January  23, 1978, relating to agreement filed as Exhibit 10(e).  File number 2-62034,  as Exhibit 5(v).  File number 2-62034, Form S-7 filed on 6/30/78, as Exhibit  5(v).

*10(e)(v)

Amendment, dated February  15, 1978, relating to agreement filed as Exhibit 10(e).  File number 2-62034,  Form S-7, filed on 6/30/78, as Exhibit 5(w).

*10(e)(vi)

Amendment, dated September  1, 1979, relating to agreement filed as Exhibit 10(e).  File number 2-68574,  Form S-7, filed on 7/23/80, as Exhibit 5(x).

*10(f)

Participation Agreement,  dated September 1, 1979, relating to the sale and leaseback of coal handling  facilities at the Number One Boardman Station on Carty Reservoir.  File  number 2-68574, Form S-7, filed on 7/23/80, as Exhibit 5(z).

*10(g)

Agreements for the  Operation, Construction and Ownership of the North Valmy Power Plant Project,  dated December 12, 1978, between Sierra Pacific Power Company and IPC.  File  number 2-64910, Form S-7 filed on 6/29/79, as Exhibit 5(y).  

*10(h)(i) 1

Idaho Power Company  Security Plan for Senior Management Employees I - a non-qualified, deferred  compensation plan, amended and restated effective December 31, 2004.  File  number 1-14465, 1-3198, Form 10-Q for the quarter ended September 30, 2006,  filed on November 2, 2006 as Exhibit 10(h)(i).

*10(h)(ii)1

Idaho Power Company  Security Plan for Senior Management Employees II, a non-qualified, deferred  compensation plan, effective January 1, 2005, as amended July 20, 2006.  File  number 1-14465, 1-3198, Form 10-Q for the quarter ended September 30, 2006,  filed on November 2, 2006, as Exhibit 10(h)(xxxv).

*10(h)(iii) 1

IDACORP, Inc. Restricted  Stock Plan, as amended July 20, 2006.  File number 1-14465, 1-3198, Form 10-Q  for the quarter ended September 30, 2006, filed on November 2, 2006, as  Exhibit 10(h)(iii).

*10(h)(iv) 1

IDACORP, Inc. Restricted  Stock Plan - Form of Restricted Stock Agreement (time-vesting) (July 20,  2006).  File number 1-14465, 1-3198, Form 10-Q for the quarter ended  September 30, 2006, filed on November 2, 2006, as Exhibit 10(h)(vi).

*10(h)(v) 1

IDACORP, Inc. Restricted  Stock Plan - Form of Performance Stock Agreement (July 20, 2006).  File  number 1-14465, 1-3198, Form 10-Q for the quarter ended September 30, 2006,  filed on November 2, 2006, as Exhibit 10(h)(vii).

*10(h)(vi) 1

The Revised Security Plan  for Board of Directors - a non-qualified, deferred compensation plan, as  amended and restated effective July 20, 2006.  File number 1-14465, 1-3198,  Form 10-Q for the quarter ended September 30, 2006, filed on November 2, 2006,  as Exhibit 10(h)(viii).

*10(h)(vii) 1

IDACORP, Inc. Non-Employee  Directors Stock Compensation Plan, as amended on January 20, 2005.  File  number 1-14465, 1-3198, Form 8-K, filed on 1/26/05, as Exhibit 10.9.

*10(h)(viii)1

Form of Officer  Indemnification Agreement for Officers of IDACORP, Inc. and IPC, as amended  July 20, 2006.  File number 1-14465, 1-3198, Form 10-Q for the quarter ended  September 30, 2006, filed on November 2, 2006, as Exhibit 10(h)(xix).

*10(h)(ix)1

Form of Director  Indemnification Agreement for Directors of IDACORP, Inc., as amended July 20,  2006.  File number 1-14465, 1-3198, Form 10-Q for the quarter ended September  30, 2006, filed on November 2, 2006, as Exhibit 10(h)(xx).

*10(h)(x)1

Form of Change in Control  Agreement between IDACORP, Inc. and Officers of IDACORP and IPC (senior vice  president and higher), as amended July 20, 2006.  File number 1-14465,  1-3198, Form 10-Q for the quarter ended September 30, 2006, filed on November  2, 2006, as Exhibit 10(h)(x).

*10(h)(xi) 1

Form of Change in Control  Agreement between IDACORP, Inc. and Officers of IDACORP and IPC (below senior  vice president), as amended July 20, 2006.  File number 1-14465, 1-3198, Form  10-Q for the quarter ended September 30, 2006, filed on November 2, 2006, as  Exhibit 10(h)(xi).

*10(h)(xii) 1

IDACORP, Inc. 2000  Long-Term Incentive and Compensation Plan, as amended July 20, 2006.  File  number 1-14465, 1-3198, Form 10-Q for the quarter ended September 30, 2006,  filed on November 2, 2006, as Exhibit 10(h)(xii).

*10(h)(xiii)1

IDACORP, Inc. 2000  Long-Term Incentive and Compensation Plan - Form of Stock Option Award  Agreement (July 20, 2006).  File number 1-14465, 1-3198, Form 10-Q for the  quarter ended September 30, 2006, filed on November 2, 2006, as Exhibit  10(h)(xvi).

*10(h)(xiv)1

IDACORP, Inc. 2000  Long-Term Incentive and Compensation Plan - Form of Restricted Stock Award  Agreement (time vesting) (July 20, 2006).  File number 1-14465, 1-3198, Form  10-Q for the quarter ended September 30, 2006, filed on November 2, 2006, as  Exhibit 10(h)(xvii).

*10(h)(xv)1

IDACORP, Inc. 2000  Long-Term Incentive and Compensation Plan - Form of Restricted Stock Award  Agreement (performance vesting) (July 20, 2006).  File number 1-14465,  1-3198, Form 10-Q for the quarter ended September 30, 2006, filed on November  2, 2006, as Exhibit 10(h)(xviii).

*10(h)(xvi)1

IDACORP, Inc. 2000  Long-Term Incentive and Compensation Plan - Form of Performance Share Award  Agreement (performance with two goals) (July 20, 2006).  File number 1-14465,  1-3198, Form 10-Q for the quarter ended September 30, 2006, filed on November  2, 2006, as Exhibit 10(h)(xxxiii).

*10(h)(xvii)1

IDACORP, Inc. Executive  Incentive Plan.  File Number 14465, 1-3198, Form 8-K, filed on 2/27/07, as  Exhibit 10.1.

*10(h)(xviii)1

Idaho Power Company  Executive Deferred Compensation Plan, as amended July 20, 2006.  File number  1-14465, 1-3198, Form 10-Q for the quarter ended September 30, 2006, filed on  November 2, 2006, as Exhibit 10(h)(xxxvi).

 

Table of Contents

10(h)(xix)1

IDACORP, Inc. and IPC 2007  Compensation for Non-Employee Directors of the Board of Directors.

*10(i)

Framework Agreement, dated  October 1, 1984, between the State of Idaho and IPC relating to IPC's Swan Falls and Snake River water rights.  File number 33-65720, Form S-3, filed on 7/7/93, as  Exhibit 10(h).

*10(i)(i)

Agreement, dated October  25, 1984, between the State of Idaho and IPC relating to the agreement filed  as Exhibit 10(i).  File number 33-65720, Form S-3, filed on 7/7/93, as  Exhibit 10(h)(i).

*10(i)(ii)

Contract to Implement,  dated October 25, 1984, between the State of Idaho and IPC relating to the  agreement filed as Exhibit 10(i).  File number 33-65720, Form S-3, filed on  7/7/93, as Exhibit 10(h)(ii).

*10(j)

Agreement Regarding the  Ownership, Construction, Operation and Maintenance of the Milner  Hydroelectric Project (FERC No. 2899), dated January 22, 1990, between IPC  and the Twin Falls Canal Company and the Northside Canal Company Limited.   File number 33-65720, Form S-3, filed on 7/7/93, as Exhibit 10(m). 

*10(j)(i)

Guaranty Agreement, dated  February 10, 1992, between IPC and New York Life Insurance Company, as Note  Purchaser, relating to $11,700,000 Guaranteed Notes due 2017 of Milner Dam  Inc.  File number 33-65720, Form S-3, filed on 7/7/93, as Exhibit 10(m)(i).

*10(k)

Power Purchase Agreement  between IPC and PPL Montana, LLC, dated March 1, 2003 and Revised  Confirmation Agreement dated May 9, 2003.  File number 1-3198, Form 10-Q for  the quarter ended 6/30/03, filed on 8/7/03, as Exhibit 10(k).

*10(l)

$150 Million Five-Year  Credit Agreement, dated as of May 3, 2005, among IDACORP, Inc, various  lenders, Wachovia Bank, National Association, as joint lead arranger and  administrative agent and JP Morgan Chase Bank, NA, as joint lead arranger and  syndication agent and Wachovia Capital Markets, LLC and J.P. Morgan  Securities Inc., as joint lead arrangers and joint book runners.  File number  1-14465, 1-3198, Form 10-Q for the quarter ended 3/31/05, filed on 5/5/05, as  Exhibit 10(l).

*10(m)

$200 Million Five-Year  Credit Agreement, dated as of May 3, 2005, among Idaho Power Company, various  lenders, Wachovia Bank, National Association, as joint lead arranger and  administrative agent and JP Morgan Chase Bank, NA, as joint lead arranger and  syndication agent and Wachovia Capital Markets, LLC and J.P. Morgan  Securities Inc., as joint lead arrangers and joint book runners.  File number  1-14465, 1-3198, Form 10-Q for the quarter ended 3/31/05, filed on 5/5/05, as  Exhibit 10(m).

*10(n)

Loan Agreement, dated  October 1, 2006, between Sweetwater County, Wyoming and IPC.  File number  1-3198, Form 8-K, filed on 10/10/2006, as Exhibit 10.1.

12

Statement Re:  Computation  of Ratio of Earnings to Fixed Charges.  (IDACORP, Inc.)

12(a)

Statement Re:  Computation  of Supplemental Ratio of Earnings to Fixed Charges.  (IDACORP, Inc.)

12(b)

Statement Re:  Computation  of Ratio of Earnings to Combined Fixed Charges and Preferred Dividend  Requirements.  (IDACORP, Inc.)

12(c)

Statement Re:  Computation  of Supplemental Ratio of Earnings to Combined Fixed Charges and Preferred  Dividend Requirements.  (IDACORP, Inc.)

12(d)

Statement Re:  Computation  of Ratio of Earnings to Fixed Charges.  (IPC)

12 (e)

Statement Re:  Computation  of Supplemental Ratio of Earnings to Fixed Charges.  (IPC)

21

Subsidiaries of IDACORP,  Inc.

23

Consent of Independent  Registered Public Accounting Firm.

31(a)

IDACORP, Inc. Rule  13a-14(a) certification.

31(b)

IDACORP, Inc. Rule 13a-14(a)  certification.

31(c)

IPC Rule 13a-14(a)  certification.

31(d)

IPC Rule 13a-14(a)  certification.

32(a)

IDACORP, Inc. Section 1350  certification.

32(b)

IPC Section 1350  certification.

1 Management contract or  compensatory plan or arrangement

130-132

Table of Contents

**IDACORP,Inc.SCHEDULE I - CONDENSED FINANCIAL INFORMATION OFREGISTRANT**

**CONDENSEDSTATEMENTS OF INCOME**

**Year Ended December 31,**

**2006**

**2005**

**2004**

(thousands of dollars)

**Income:**

Equity  in income from continuing operations of subsidiaries

 $

106,006  

 $

90,001  

 $

84,280  

Other  income

854  

721  

535  

Total  income

106,860  

90,722  

84,815  

**Expenses:**

Operating  expenses

7,080  

5,189  

5,782  

Interest  expense

4,225  

3,816  

1,221  

Other  expense

120  

231  

994  

Total  expenses

11,425  

9,236  

7,997  

**Income from Continuing  Operations Before Income Taxes**

95,435  

81,486  

76,818  

** **

**Income Tax Benefit**

(4,640)

(4,230)

(3,963)

** **

**Income from Continuing  Operations**

100,075  

85,716  

80,781  

** **

**Income (loss) from  Discontinued Operations, net of tax**

7,328  

(22,055)

(7,798)

** **

**Net income**

 $

107,403  

 $

63,661  

 $

72,983  

The accompanying note is an integral part of these  statements.

133

Table of Contents

**IDACORP,Inc.SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT**

**CONDENSEDBALANCE SHEETS**

**Year Ended December 31,**

**2006**

**2005**

(thousands of dollars)

**Assets**

**Current Assets:**

Cash  and cash equivalents

 $

4,724  

 $

1,234  

Receivables

46,552  

1,304  

Taxes  receivable

-    

6,897  

Deferred  income taxes

27,807  

27,997  

Other

288  

335  

Total  current assets

79,371  

37,767  

**Investment in  subsidiaries**

	1,148,106

1,049,276  

**Other Assets**

Intercompany  notes receivable

2,800  

35,306  

Deferred  income taxes

2,373  

-    

Other

773  

883  

Total  other assets

5,946  

36,189  

Total

 $

	1,233,423

 $

1,123,232  

**Liabilities and  Shareholders' Equity**

**Current Liabilities:**

Notes  payable

 $

76,800  

 $

60,100  

Accounts  payable

3,269  

3,162  

Taxes  accrued

216  

-    

Other

25  

-    

Total  current liabilities

80,310  

63,262  

**Other Liabilities:**

Intercompany  notes payable

24,434  

33,265  

Other

4,496  

1,454  

Total  other liabilities

28,930  

34,719  

**Shareholders' Equity**

	1,124,183

1,025,251  

** **

Total

 $

	1,233,423  

 $

1,123,232  

The accompanying note is an integral part of these  statements.

** **

134

Table of Contents

**IDACORP,Inc.SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT**

**CONDENSEDSTATEMENTS OF CASH FLOWS**

**Year Ended December 31,**

**2006**

**2005**

**2004**

(thousands of dollars)

**Operating Activities:**

Net  cash provided by operating activities

 $

41,196  

 $

35,462  

 $

23,958  

**Investing Activities:**

Contributions  to subsidiaries

(64,533)

-    

(100,456)

Change  in intercompany notes receivable

4,196  

1,271  

12,407  

Sale of ITI

21,548  

-    

-    

Other

-    

-    

(53)

Net  cash provided by (used in) investing activities

(38,789)

1,271  

(88,102)

**Financing Activities:**

Issuance  of common stock

41,465  

6,296  

115,690  

Dividends  on common stock

(51,272)

(50,690)

(45,838)

Increase  (decrease) in short-term borrowings

16,700  

24,700  

(58,250)

Change  in intercompany notes payable

(6,814)

(17,971)

(4,323)

Other

1,004  

(471)

(1,419)

Net  cash provided by (used in) financing activities

1,083  

(38,136)

5,860  

Net  increase (decrease) in cash and cash equivalents

3,490  

(1,403)

(58,284)

Cash  and cash equivalents at beginning of year

1,234  

2,637  

60,921  

Cash  and cash equivalents at end of year

$     4,724  

$     1,234  

$     2,637  

The accompanying note is an integral part of these  statements.

**IDACORP,Inc.SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT**

**NOTESTO CONDENSED FINANCIAL STATEMENTS**

**1.  BASIS OF PRESENTATION**

Pursuant to rules and  regulations of the Securities and Exchange Commission, the unconsolidated  condensed financial statements of IDACORP, Inc. do not reflect all of the  information and notes normally included with financial statements prepared in  accordance with accounting principles generally accepted in the United States of America.  Therefore, these financial statements should be read in  conjunction with the consolidated financial statements and related notes  included in the 2006 Form 10-K, Part II, Item 8.

**Accounting for  subsidiaries**

IDACORP has accounted for  the earnings of its subsidiaries under the equity method in the  unconsolidated condensed financial statements.

** **

** **

** **

** **

** **

135

Table of Contents

**IDACORP,Inc.SCHEDULE II - CONSOLIDATED VALUATION ANDQUALIFYING ACCOUNTS**

**YearsEnded December 31, 2006, 2005 and 2004**

**Column A**

**Column B**

**Column C**

**Column D**

**Column E**

** **

** **

**Additions**

** **

** **

** **

** **

** **

**Charged**

** **

** **

** **

**Balance at**

**Charged**

**(Credited)**

** **

**Balance at**

** **

**Beginning**

**to**

**to Other**

**Deductions**

**End**

**Classification**

**of Period**

**Income**

**Accounts**

**(1)**

**of Period**

** **

**(thousands of dollars)**

2006:

Reserves Deducted From

Applicable  Assets:

Reserve  for uncollectible accounts 

 $

33,078  

 $

3,079  

 $

-  

 $

28,989  

 $

7,168  

Reserve  for uncollectible notes

1,879  

-  

-  

-  

1,879  

Deferred  tax assets

1,565  

-  

-  

-  

1,565  

Other Reserves:

Rate  refunds

-  

1,227  

-  

-  

1,227  

Injuries  and damages reserve

1,638  

1,914  

-  

2,886  

666  

Miscellaneous  operating reserves

36  

-  

-  

30  

6  

2005:

Reserves Deducted From

Applicable  Assets:

Reserve  for uncollectible accounts

 $

43,108  

 $

1,026  

 $

-  

 $

11,056  

 $

33,078  

Reserve  for uncollectible notes

2,578  

-  

-  

699  

1,879  

Deferred  tax assets

-  

1,565  

-  

-  

1,565  

Other Reserves:

Rate  refunds

400  

-  

-  

400  

-  

Injuries  and damages reserve

1,797  

10,064  

-  

10,223  

1,638  

Miscellaneous  operating reserves

35  

2  

-  

1  

36  

2004:

Reserves Deducted From

Applicable  Assets:

Reserve  for uncollectible accounts

 $

43,210  

 $

3,010  

 $

-  

 $

3,112  

 $

43,108  

Reserve  for uncollectible notes

2,578  

-  

-  

-  

2,578  

Other Reserves:

Rate  refunds

1,514  

-  

-  

1,114  

400  

Injuries  and damages reserve

831  

1,801  

-  

835  

1,797  

Miscellaneous  operating reserves

61  

-  

-  

26  

35  

Notes:   (1) Represents deductions from the reserves for purposes for which the  reserves were created.  In the case

of  uncollectible accounts and notes reserves, includes reversals of amounts  previously written off.

** **

** **

** **

136

Table of Contents

**IDAHO POWER COMPANYSCHEDULE II - CONSOLIDATED VALUATION ANDQUALIFYING ACCOUNTS****Years Ended December 31, 2006,2005, 2004**

**Column A**

**Column B**

**Column C**

**Column D**

**Column E**

** **

** **

**Additions**

** **

** **

** **

** **

** **

**Charged**

** **

** **

** **

**Balance at**

**Charged**

**(Credited)**

** **

**Balance at**

** **

**Beginning**

**to**

**to Other**

**Deductions**

**End**

**Classification**

**of Period**

**Income**

**Accounts**

**(1)**

**of Period**

** **

**(thousands of dollars)**

2006:

Reserves Deducted From

Applicable  Assets:

Reserve  for uncollectible accounts

 $

833  

 $

3,079  

 $

-  

 $

2,944  

 $

968  

Other reserves:

Rate  refunds

-  

1,227  

-  

-  

1,227  

Injuries  and damages reserve

1,191  

1,445  

-  

1,971  

665  

Miscellaneous  operating reserves

36  

-  

-  

30  

6  

2005:

Reserves Deducted From

Applicable  Assets:

Reserve  for uncollectible accounts

 $

1,363  

 $

1,026  

 $

-  

 $

1,556  

 $

833  

Other reserves:

Rate  refunds

400  

-  

-  

400  

-  

Injuries  and damages reserve

1,797  

6,973  

-  

7,579  

1,191  

Miscellaneous  operating reserves

35  

2  

-  

1  

36  

2004:

Reserves Deducted From

Applicable  Assets:

Reserve  for uncollectible accounts

 $

1,466  

 $

3,010  

 $

-  

 $

3,113  

 $

1,363  

Other reserves:

Rate  refunds

1,514  

-  

-  

1,114  

400  

Injuries  and damages reserve

831  

1,301  

-  

335  

1,797  

Miscellaneous  operating reserves

61  

-  

-  

26  

35  

** **

** **

** **

** **

** **

Notes:  (1)  Represents  deductions from the reserves for purposes for which the reserves were  created.  In the case of 

uncollectible accounts,  includes reversals of amounts previously written off.

137

Table of Contents

**SIGNATURES**Pursuant to the requirements ofSection 13 or 15(d) of the Securities Exchange Act of 1934, the registrant hascaused this report to be signed on its behalf by the undersigned, thereuntoduly authorized.

IDACORP,Inc.(Registrant)

March 1, 2007

By: */s/J. LaMont Keen*                                J. LaMont KeenPresident and Chief Executive Officer

Pursuant to the requirementsof the Securities Exchange Act of 1934, this report has been signed below bythe following persons on behalf of the registrant and in the capacities and onthe dates indicated.

By:

*/s/Jon H. Miller*

Chairman of the Board

March 1, 2007

Jon H. Miller

By:

*/s/J. LaMont Keen*

President and Chief  Executive

"

J. LaMont Keen

Officer and Director

(Principal Executive  Officer)

* *

By:

*/s/Darrel T. Anderson*

Senior Vice President -  Administrative

"

Darrel T. Anderson

Services and Chief  Financial Officer

(Principal Financial  Officer)

(Principal Accounting  Officer)

By:

*/s/Rotchford L. Barker*

By:

*/s/Richard G. Reiten*

"

Rotchford L. Barker

Richard G. Reiten

Director

Director

By:

*/s/Christine King*

By:

*/s/Joan H. Smith*

"

Christine King

Joan H. Smith

Director

Director

By:

*/s/Gary G. Michael*

By:

*/s/Robert A. Tinstman*

"

Gary G. Michael

Robert A. Tinstman

Director

Director

By:

*/s/Peter S. O'Neill*

By:

*/s/Thomas J. Wilford*

"

Peter S. O'Neill

Thomas J. Wilford

Director

Director

By:

*/s/Jan B. Packwood*

* *

Jan B. Packwood

Director

138

Table of Contents

**SIGNATURES**

Pursuant to the requirementsof Section 13 or 15(d) of the Securities Exchange Act of 1934, the registranthas caused this report to be signed on its behalf by the undersigned, thereuntoduly authorized.

IDAHOPOWER COMPANY(Registrant)

March 1, 2007

By:*/s/J. LaMont Keen*                                J. LaMont KeenPresident and Chief Executive Officer

Pursuant to the requirementsof the Securities Exchange Act of 1934, this report has been signed below bythe following persons on behalf of the registrant and in the capacities and onthe dates indicated.

By:

*/s/Jon H. Miller*

Chairman of the Board

March 1, 2007

Jon H. Miller

By:

*/s/J. LaMont Keen*

President and Chief  Executive

"

J. LaMont Keen

Officer and Director

(Principal Executive  Officer)

By:

*/s/Darrel T. Anderson*

Senior Vice President -  Administrative

"

Darrel T. Anderson

Services and Chief  Financial Officer

(Principal Financial  Officer)

(Principal Accounting  Officer)

By:

*/s/Rotchford L. Barker*

By:

*/s/Richard G. Reiten*

"

Rotchford L. Barker

Richard G. Reiten

Director

Director

By:

*/s/Christine King*

By:

*/s/Joan H. Smith*

"

Christine King

Joan H. Smith

Director

Director

By:

*/s/Gary G. Michael*

By:

*/s/Robert A. Tinstman*

"

Gary G. Michael

Robert A. Tinstman

Director

Director

By:

*/s/Peter S. O'Neill*

By:

*/s/Thomas J. Wilford*

"

Peter S. O'Neill

Thomas J. Wilford

Director

Director

By:

*/s/Jan B. Packwood*

* *

Jan B. Packwood

Director

139

Table of Contents

**EXHIBIT INDEX**

Exhibit Number

10(h)(xix)1

IDACORP, Inc. and IPC 2007  Compensation for Non-Employee Directors of the Board of Directors.

12

Statement Re:  Computation  of Ratio of Earnings to Fixed Charges.  (IDACORP, Inc.)

12(a)

Statement Re:  Computation  of Supplemental Ratio of Earnings to Fixed Charges.  (IDACORP, Inc.)

12(b)

Statement Re:  Computation  of Ratio of Earnings to Combined Fixed Charges and Preferred Dividend  Requirements.  (IDACORP, Inc.)

12(c)

Statement Re:  Computation  of Supplemental Ratio of Earnings to Combined Fixed Charges and Preferred  Dividend Requirements.  (IDACORP, Inc.)

12(d)

Statement Re:  Computation  of Ratio of Earnings to Fixed Charges.  (IPC)

12 (e)

Statement Re:  Computation  of Supplemental Ratio of Earnings to Fixed Charges.  (IPC)

21

Subsidiaries of IDACORP,  Inc.

23

Consent of Independent  Registered Public Accounting Firm.

31(a)

IDACORP, Inc. Rule  13a-14(a) certification.

31(b)

IDACORP, Inc. Rule  13a-14(a) certification.

31(c)

IPC Rule 13a-14(a)  certification.

31(d)

IPC Rule 13a-14(a)  certification.

32(a)

IDACORP, Inc. Section 1350  certification.

32(b)

IPC Section 1350  certification.

1 Management contract or  compensatory plan or arrangement

140 |
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--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------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