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**UNITED STATES SECURITIESAND EXCHANGE COMMISSIONWashington, D.C. 20549****FORM 10-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, 2005       |

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

 

For the transition period from ................... 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                 |                                            |     |
|                                                         |                            |                                            |
|                                                              |                                 |                                                 |          |                       |  |

Indicate by check mark whetherthe registrants are well-known seasoned issuers, as defined in Rule 405 of theSecurities Act.
| IDACORP, Inc. | Yes | (    ) | No | ( X ) | Idaho Power Company | Yes | (    ) | No | ( X ) |
|---------------|-----|-----------------------|----|-------|---------------------|-----|-----------------------|----|-------|

 

Indicate by check mark if theregistrants are not required to file reports pursuant to Section 13 or Section15(d) of the Act.
| IDACORP, Inc. | Yes | (    ) | No | ( X ) | Idaho Power Company | Yes | (    ) | No | ( X ) |
|---------------|-----|-----------------------|----|-------|---------------------|-----|-----------------------|----|-------|

 

Indicate by check mark whether the registrants (1) havefiled all reports required to be filed by Section 13 or 15(d) of the SecuritiesExchange Act of 1934 during the preceding 12 months (or for such shorter periodthat the registrants were required to file such reports), and (2) have beensubject to such filing requirements for the past 90 days.Yes  ( X )  No  (    )

Indicate by check mark if disclosure of delinquent filerspursuant to Item 405 of Regulation S-K is not contained herein, and will not becontained, to the best of registrants' knowledge, in definitive proxy orinformation statements incorporated by reference in Part III of this Form 10-Kor any amendment to this Form 10-K.   ( X)

Indicate by check mark whether the registrants are large acceleratedfilers, accelerated filers, or non-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 shell companies(as defined in Rule 12b-2 of the Act).
| IDACORP, Inc. | Yes | (    ) | No | ( X ) | Idaho Power Company | Yes | (    ) | No | ( X ) |
|---------------|-----|-----------------------|----|-------|---------------------|-----|-----------------------|----|-------|

 

 

 

 

 

 

 

 

 

Aggregate market value of voting and non-voting commonstock held by nonaffiliates (June 30, 2005):
| IDACORP, Inc.: | $1,287,317,487 | Idaho Power Company: | None |
|----------------|----------------|----------------------|------|

 

Number of shares of common stock outstanding at February28, 2006:
| IDACORP, Inc.:       | 42,491,802                           |
|----------------------|--------------------------------------|
| 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 2006 Annual Meeting of Shareholders  to be held on May 18, 2006. |

 

Thiscombined Form 10-K represents separate filings by IDACORP, Inc. and Idaho PowerCompany.  Information contained hereinrelating to an individual registrant is filed by that registrant on its ownbehalf.  Idaho Power Company makes norepresentation as to the information relating to IDACORP, Inc.'s otheroperations.

Idaho Power Company meets the conditions set forth inGeneral Instruction (I)(1)(a) and (b) of Form 10-K and is therefore filing thisForm with the reduced disclosure format.
| **COMMONLY USED TERMS** |
|-------------------------|
| AFDC                    | - | Allowance for Funds Used During Construction |
| Cal ISO                 | - | California Independent System Operator |
| CalPX                   | - | California Power Exchange |
| 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                    | - | Accounting Principles Generally Accepted in the United  States of America |
| 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 |
| 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 | 1-11 |
|                  | Item 1A. | Risk Factors | 11-13 |
|                  | Item 1B. | Unresolved Staff Comments | 13 |
|                  | Item 2. | Properties | 13-14 |
|                  | Item 3. | Legal Proceedings | 15 |
|                  | Item 4. | Submission of Matters to a Vote of Security Holders | 15 |
|                  |
|                  | Executive Officers of the Registrant | 15 |
|                  |
| **Part II**           |
| ** **            |
|                  | Item 5. | Market for Registrant's Common Equity, Related  Stockholder |   |
|                  |   |   | Matters and Issuer Purchases of Equity Securities | 16 |
|                  | Item 6. | Selected Financial Data | 17 |
|                  | Item 7. | Management's Discussion and Analysis of Financial  Condition and |   |
|                  |   |   | Results of Operations | 17-58 |
|                  | Item 7A. | Quantitative and Qualitative Disclosures about Market  Risk | 58-59 |
|                  | Item 8. | Financial Statements and Supplementary Data | 60 |
|                  | Item 9. | Changes in and Disagreements with Accountants on  Accounting and |   |
|                  |   |   | Financial Disclosure | 60-114 |
|                  | Item 9A. | Controls and Procedures | 114-119 |
|                  | Item 9B. | Other Information | 119 |
| ** **            |
| **Part III**          |
| ** **            |
|                  | Item 10. | Directors and Executive Officers of the Registrant* | 119 |
|                  | Item 11. | Executive Compensation* | 119 |
|                  | Item 12. | Security Ownership of Certain Beneficial Owners and  Management and Related |   |
|                  |   |   | Stockholder Matters* | 119-120 |
|                  | Item 13. | Certain Relationships and Related Transactions* | 120 |
|                  | Item 14. | Principal Accountant Fees and Services* | 120-121 |
|                  |
| **Part IV**           |
| ** **            |
|                  | Item 15. | Exhibits and Financial Statement Schedules | 121-126 |
|                  |
|                  | Signatures | 133-134 |
|                  |
|                  |   |   |
|                  |
|                  | *Except as indicated in Item 12, IDACORP, Inc.  information is incorporated by reference to IDACORP, Inc.'s |
|                  | definitive proxy statement for the 2006 Annual Meeting  of Shareholders. |

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**SAFE HARBOR STATEMENT**This Form 10-Kcontains "forward-looking statements" intended to qualify for the safeharbor from liability established by the Private Securities Litigation ReformAct of 1995.  Forward-looking statementsshould be read with the cautionary statements and important factors included inthis Form 10-K at Part II, Item 7- "Management's Discussion and Analysisof Financial Condition and Results of Operations (MD&A) - FORWARD-LOOKINGINFORMATION."  Forward-looking statementsare all statements other than statements of historical fact, including withoutlimitation those that are identified by the use of the words"anticipates," "believes," "estimates,""expects," "intends," "plans," "predicts,""projects," "may result," "may continue," or similarexpressions.

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

**ITEM 1.  BUSINESS**

**OVERVIEW:**

IDACORP, Inc. (IDACORP) is a holding company formed in1998 whose principal operating subsidiary is Idaho Power Company (IPC).  Due to the repeal of the Public UtilityHolding Company Act of 1935 (1935 Act), effective February 8, 2006, IDACORP isno longer subject to any provisions of the 1935 Act.  IDACORP is a holding company under the newlyenacted Public Utility Holding Company Act of 2005 (2005 Act), which providescertain access to books and records to the Federal Energy Regulatory Commission(FERC) and state utility regulatory commissions and imposes certain recordretention and reporting requirements on IDACORP.

IPC is an electric utility engaged in the generation,transmission, distribution, sale and purchase of electric energy and is regulatedby the FERC and the state regulatory commissions 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 subsidiaries include:

IDACORP Financial Services, Inc. (IFS)- holder of affordable housing and other real estate investments;

IdaTech, LLC (IdaTech) - developer ofintegrated fuel cell systems, over 90 percent owned by IDACORP's wholly-owned subsidiaryIDACORP Technologies, Inc. (ITI);

IDACOMM, Inc. (IDACOMM) - provider oftelecommunications services and commercial Internet services; 

Ida-West Energy Company (Ida-West) -operator of small hydroelectric generation projects that satisfy therequirements of the Public Utility Regulatory Policies Act of 1978 (PURPA).  In 2003, Ida-West discontinued its project developmentoperations and began managing its independent power projects with a reduced workforce;and

IDACORP Energy (IE), - a marketer ofelectricity and natural gas, which wound down its operations in 2003.

IDACORP is focusing on a back-to-basics strategy thatemphasizes IPC as IDACORP's core business. IPC continues to experience strong growth in its service area, and thiscorporate strategy recognizes that IPC must make substantial investments ininfrastructure to ensure adequate supply and reliable service.  IFS, with its affordable housing and historicrehabilitation portfolio, remains a key component of the corporate strategy.

IDACORPhas revised its business strategy for IDACOMM, its wholly-owned communicationssubsidiary.  IDACOMM now will focus onbuilding its existing competitive local exchange carrier business in Boise,Idaho and Las Vegas and Reno, Nevada, and phasing out the portion of itsbusiness exploring the potential use of power lines as the conduit for highspeed Internet service, commonly referred to as broadband-over-power line (BPL)technology.

IDACORP is reviewing strategic alternatives for IdaTech'sfuel cell business, including its possible sale or merger, in an effort to minimizethe financial impact on IDACORP.  IdaTechis transitioning from developmental projects to commercial products.

At December 31, 2005, IDACORP had 1,993 full-timeemployees.  Of these employees, 1,821were employed by IPC.

IDACORP's four reportable business segments are IPC, IFS,IDACOMM and ITI.  IPC and IFS contributed$72 million and $11 million, respectively, to consolidated net income in2005.  IDACOMM and ITI had net losses of$13 million and $9 million, respectively, in 2005.  Financial information relating to IDACORP'sreportable segments is presented in Note 12 to IDACORP's and IPC's ConsolidatedFinancial Statements and below in "Utility Operations," "IFS,""IDACOMM" and "ITI."

IDACORP and IPC make available free of charge their Annual Report on Form 10-K,Quarterly Reports on Forms 10-Q, Current Reports on Forms 8-K and allamendments to these reports filed or furnished pursuant to Section 13(a) or15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicableafter the reports are electronically filed with or furnished to the Securitiesand Exchange Commission, through IDACORP's website at www.idacorpinc.comand through a link to the IDACORP website from the IPC website at www.idahopower.com.

**UTILITY OPERATIONS:**

IPC was incorporated under the laws of the state of Idahoin 1989 as successor to a Maine corporation organized in 1915.  IPC's service territory covers a 24,000square mile area in southern Idaho and eastern Oregon, with an estimatedpopulation of 911,000.  IPC holdsfranchises 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, 2005, IPC suppliedelectric energy to approximately 457,000 general business customers.

IPC owns and operates 17 hydroelectric generationdevelopments, two natural gas-fired plants and one diesel-powered generator andshares ownership in three coal-fired generating plants.  These generating plants and their capacitiesare listed in Item 2 - "Properties." IPC's coal-fired plants are in Wyoming, Oregon and Nevada, and uselow-sulfur coal from Wyoming and Utah.

IPC is one of the nation's few investor-ownedutilities with a predominantly hydroelectric generating base.  Because of its reliance on hydroelectricgeneration, IPC's generation operations can be significantly affected byweather conditions.  The availability ofhydroelectric power depends on the amount of snow pack in the mountainsupstream of IPC's hydroelectric facilities, reservoir storage, springtime snowpack run-off, rainfall and other weather and stream flow managementconsiderations.  During low water years,when stream flows into IPC's hydroelectric projects are reduced, IPC'shydroelectric 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, an increased use of purchased power to meet loadrequirements.  Both of these situations -a reduction in profitable off-system sales and an increased use of moreexpensive purchased power - result in increased power supply costs.

The primary influences on electricity sales are weather,customer growth and economic conditions. Extreme temperatures increase sales to customers who use electricity forcooling and heating, and moderate temperatures decrease sales.  Increased precipitation levels during thegrowing season reduce electricity sales to customers who use electricity tooperate irrigation pumps.

IPC's principal commercial and industrial customers areinvolved in food processing, electronics and general manufacturing, forestproduct production, beet sugar refining and the skiing industry.

**Regulation**IPC is under theregulatory jurisdiction (as to rates, service, accounting and other generalmatters of utility operation) of the FERC, the Idaho Public UtilitiesCommission (IPUC) and the Oregon Public Utility Commission (OPUC).  IPC is also under the regulatory jurisdictionof the IPUC, the OPUC and the Public Service Commission of Wyoming as to theissuance of debt and equity securities. IPC is subject to the provisions of the Federal Power Act as a"public utility" as therein defined. IPC's retail rates are established under the jurisdiction of the stateregulatory commissions and its wholesale and transmission rates are regulated bythe FERC (see "Rates" below). Pursuant to the requirements of Section 210 of PURPA, the stateregulatory commissions have each issued orders and rules regulating IPC'spurchase of power from cogeneration and small power production (CSPP)facilities.

IPC is subject to the provisionsof the Federal Power Act as a "licensee" as therein defined.  As a licensee under the Federal Power Act,IPC and its licensed hydroelectric projects are subject to the provisions ofPart I of the Federal Power Act.  Alllicenses are subject to conditions set forth in the Federal Power Act andrelated FERC regulations.  Theseconditions and regulations include provisions relating to condemnation of aproject upon payment of just compensation, amortization of project investmentfrom excess project earnings, possible takeover of a project after expirationof its license upon payment of net investment, severance damages and othermatters.

The State of Oregon has a Hydroelectric Act providing forlicensing of hydroelectric projects in that state.  IPC's Brownlee, Oxbow and Hells Canyonfacilities are on the Snake River where it forms the boundary between Idaho andOregon and occupy land located in both states. With respect to project property located in Oregon, these facilities aresubject to the Oregon Hydroelectric Act. IPC has obtained Oregon licenses for these facilities and these licensesare not in conflict with the Federal Power Act or IPC's FERC licenses (see PartII, Item 7 - "MD&A - REGULATORY ISSUES - Relicensing of HydroelectricProjects").

**Rates**The rates IPC charges to its general business customers are determined bythe IPUC and the OPUC.  Approximately 96percent of IPC's general business revenue comes from customers in Idaho.  IPC has a Power Cost Adjustment (PCA)mechanism that provides for annual adjustments to the rates charged to itsIdaho 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 ofthe difference between the actual and forecasted costs is deferred withinterest.  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 of significant ratecases and proceedings see Part II, Item 7 - "MD&A - REGULATORY ISSUES."

**PowerSupply**IPC meets itssystem load requirements using a combination of its own generation, mandatedpurchases from private developers (see "CSPP Purchases" below) andpurchases from other utilities and power wholesalers.  IPC's generating plants and capacities arelisted in Item 2 - "Properties."

IPC's system is dual peaking, with the larger peak demandoccurring in the summer.  The all-timesystem peak demand was 2,963 megawatts (MW), on July 12, 2002.  Peak summer demand in 2005 was 2,961 MW, seton July 22 and peak winter demand for the year was 2,345 MW on December15.  IPC expects total system averageload to grow 2.2 percent annually over the next three years.  The following table presents IPC's systemgeneration for the last three years:
| ** **    | **MWh**                 | ** ** | **Percent of total generation** |
|---------------|-------------------------|------------|---------------------------------|
| ** **    | **2005**                | ** ** | **2004**                        | ** ** | **2003** | ** ** | **2005** | ** ** | **2004** | ** ** | **2003** |
|          | **(thousands of MWhs)** |       |                            |   |   |   |   |
| Hydroelectric | 6,199                   |       | 6,041                           |   | 6,149 |   | 46% |   | 45% |   | 47% |
| Thermal       | 7,315                   |       | 7,303                           |   | 6,914 |   | 54% |   | 55% |   | 53% |
|          | Total system generation | 13,514     |                            | 13,344 |   | 13,063 |   | 100% |   | 100% |   | 100% |
|               |                         |            |                                 |  |  |  |  |  |  |  |  |  |

 

The amount of electricity IPC is able to generate fromits hydroelectric plants depends on a number of factors, primarily snow pack inthe mountains upstream of its hydroelectric facilities, reservoir storage andstream flow conditions.  When thesefactors are favorable, IPC can generate more electricity using itshydroelectric plants.

Continuedbelow normal stream flow conditions in 2005 resulted in a system generation mixof 46 percent hydroelectric and 54 percent thermal.  Under normal stream flow conditions, IPC'ssystem generation mix is approximately 55 percent hydroelectric and 45 percentthermal.

Belowaverage stream flow conditions continued for a sixth consecutive year in2005.  Brownlee reservoir 2005 annualinflow was 8.9 million acre-feet (maf), 70 percent of average, and the Aprilthrough July inflow was 3.6 maf, 57 percent of average.  However, the forecast released on February 28,2006 by the Northwest River Forecast Center indicates that Brownlee inflow forApril through July 2006 is expected to total 6.7 maf, or 106 percent of average.  Snow pack accumulation for the Snake RiverBasin was 117 percent of average on February 28, 2006.  Storage in selected federal reservoirsupstream of Brownlee as of February 21, 2006 was 105 percent of average, upfrom 60 percent of average at the end of December 2004.  October 1, 2005 storage in these reservoirs,which is considered carryover storage into water year 2006, was 85 percent ofaverage, up from 45 percent of average on October 1, 2004.  With approximately one month remaining in thetypical snow accumulation period for 2006, conditions have improved from lastyear.

IPC'sgenerating facilities are interconnected through its integrated transmissionsystem and are operated on a coordinated basis to achieve maximum load-carryingcapability and reliability.  IPC'stransmission system is directly interconnected with the transmission systems ofthe Bonneville Power Administration, Avista Corporation, PacifiCorp,NorthWestern Energy and Sierra Pacific Power Company.  Such interconnections, coupled withtransmission line capacity made available under agreements with some of theabove entities, permit the interchange, purchase and sale of power among allmajor electric systems in the west.  IPC isa member of the Western Electricity Coordinating Council, the Western SystemsPower Pool, the Northwest Power Pool and the North American Energy Standards Board.  These groups have been formed to moreefficiently coordinate transmission reliability and planning throughout thewestern grid.  See "Competition -Wholesale" below.

**Integrated Resource Plan:** The IRP is prepared and filed every two yearswith both the IPUC and the OPUC.  Priorto filing, the IRP requires extensive involvement by IPC, the IPUC Staff andthe OPUC Staff, as well as customer, technological and environmentalrepresentatives and is the starting point for demonstrating prudence in IPC'sresource decisions.  The 2004 IRPidentified IPC's forecast load and resource situation for the next ten years,analyzed potential supply-side and demand-side options and identified near-termand long-term actions.  The two primarygoals of the 2004 IRP were to (1) identify sufficient resources to reliablyserve the growing demand for energy service within IPC's service areathroughout the 10-year planning period and (2) ensure that the portfolio ofresources selected balances cost, risk and environmental concerns.  In addition, there were two secondary goals:(1) to give equal and balanced treatment to both supply-side resources anddemand-side measures and (2) to involve the public in the planning process in ameaningful way.  The IPUC accepted the2004 IRP on April 22, 2005.  The OPUCacknowledged the 2004 IRP on June 17, 2005.

Preparationhas begun on the 2006 IRP, with the initial meeting of the IRP Advisory Councilheld on October 20, 2005, and meetings are continuing on a monthly basis.  The planning period will change from a 10-yearforecast to a 20-year forecast.  The 2006IRP is scheduled to be filed in June 2006.

See further discussion in Part II - Item 7 -"MD&A - REGULATORY ISSUES - Integrated Resource Plan."

**CSPP Purchases**:  As mandated bythe enactment of PURPA and the adoption of avoided cost rates by the IPUC andthe OPUC, IPC has entered into contracts for the purchase of energy from anumber of private developers.  Underthese contracts, IPC is required to purchase all of the output from thefacilities located inside the IPC service territory.  For projects located outside the IPC serviceterritory, IPC is required to purchase the output that IPC has the ability toreceive at the facility's requested point of delivery on the IPC system.  The IPUC jurisdictional portion of the costsassociated with CSPP contracts are fully recovered through the PCA.  For IPUC jurisdictional contracts, projectsthat generate up to ten average MW of energy on a monthly are eligible for IPUCPublished Avoided Costs for up to a 20-year contract term.  The Published Avoided Cost is a priceestablished by the IPUC and the OPUC to estimate IPC's cost of developingadditional generation resources.  OnAugust 4, 2005, the IPUC granted a temporary reduction in the eligible projectsize to 100 KW for intermittent generation resources only.  This temporary project size reduction willremain in place until studies are completed which will help the IPUC determineif the Published Avoided Cost should be revised for intermittent generationresources.  For OPUC jurisdictional contracts,projects that generate up to ten MW of capacity are eligible for OPUC PublishedAvoided Costs for up to a 20-year contract term.  The OPUC jurisdictional portion of the costsassociated with CSPP contracts is recovered throughgeneral rate case filings.  TheOregon provisions are currently being reviewed in an OPUC proceeding, as discussedin Part II, Item 7 - "MD&A - REGULATORY ISSUES - Public Utility RegulatoryPolicies Act of 1978." If a PURPA project does not qualify for PublishedAvoided Costs, then IPC is required to negotiate the terms, prices andconditions with the developer of that project. These negotiations reflect the characteristics of the individualprojects (i.e., operational flexibility, location and size) and the benefits tothe IPC system and must be consistent with other similar energy alternatives.

As of December 31, 2005, IPC had signed agreements topurchase energy from 87 CSPP facilities with contracts ranging from one to 30years.  Of these facilities, 69 wereon-line at the end of 2005; the other 18 facilities under contract are due tocome on-line in 2006 and 2007.  During2005, IPC purchased 715,209 megawatt hours (MWh) from these projects at a costof $43 million, resulting in a blended price of 6.1 cents per kilowatt hour.

**Wholesale Energy Market Activities:** Guided by a Risk Management Policy and frequently updated operatingplans, IPC participates in the wholesale energy market by buying power to helpmeet load demands and selling power that is in excess of load demands.  IPC's market activities are influenced by itscustomer loads, market prices, and cost and availability of generatingresources.  Some of IPC's hydroelectric generationfacilities are operated to optimize the water that is available by choosingwhen to run generation units and when to store water in reservoirs.  These decisions affect the timing and volumesof market purchases and market sales. Even in below normal water years, there are opportunities to vary waterusage to maximize generation unit efficiency, capture marketplace economicbenefits and meet load demand. Compliance factors, such as allowable river stage elevation changes,flood control requirements, and wholesale energy market prices influence thesedispatch decisions.****

IPC hastwo firm wholesale power sales contracts and one wholesale contract for loadfollowing services.  One is a fullrequirements sales contract with the City of Weiser for approximately 12 MW thatwill expire in December 2006.  The secondcontract is with the Raft River Electric Cooperative for up to 15 MW.  This contract expires in September 2006; however,it can be renewed by Raft River Electric Cooperative on a year-to-year basisfor five additional years.  When thesecontracts expire, IPC will either renew them, negotiate an extension or usethis power to meet its retail load requirements.  The load following contract, with NorthWesternEnergy, requires IPC to increase or decrease its generation by up to 30 MW toreact to NorthWestern's system load changes. This contract automatically renews annually unless either party choosesto terminate.  As long as IPC retains itsHells Canyon Complex operating flexibility, the load following contract isanticipated to be renewed into the foreseeable future.

IPC hasone firm wholesale purchased power contract. This contract is with PPL Montana, LLC for 83 MW per hour to addressincreased demand during June, July and August. The term of this contract began in June 2004 and runs through August2009.

**TransmissionServices: **IPC has a long history ofproviding wholesale transmission service and provides firm and non-firmwheeling services for several surrounding utilities.  IPC's system lies between and isinterconnected to the winter-peaking northern and summer-peaking southernregions of the western interconnected power system.  This geographic position allows IPC toprovide transmission services and reach a broad power sales market.

IPCholds rights-of-way from Midpoint substation in south-central Idaho througheastern Nevada to the Dry Lake area northeast of Las Vegas, Nevada, known asthe Southwest Intertie Project (SWIP).  In2004, 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.  IPCobtained the rights-of-way to construct a transmission line along thiscorridor, but no longer plans to build the line.  On March 31, 2005, IPC entered into anagreement with White Pine Energy Associates, LLC (White Pine), an affiliate ofLS Power Development, LLC, which provides White Pine a three-year exclusiveoption to purchase the SWIP rights-of-way from IPC.  The option may be exercised in part or as awhole and, if fully exercised, will result in a net pre-tax gain to IPC ofapproximately $6 million.

InDecember 1999, the FERC issued Order No. 2000 encouraging companies withtransmission assets to form Regional Transmission Organizations.  See "Competition - Wholesale"below.

**Fuel**IPC, through itssubsidiary Idaho Energy Resources Co., owns a one-third interest in BridgerCoal Company, which owns the Jim Bridger mine supplying coal to the Jim Bridgergenerating plant in Wyoming.  The mine,located near the Jim Bridger plant, operates under a long-term sales agreementthat provides for delivery of coal over a 51-year period ending in 2024.  The Jim Bridger mine has sufficient reservesto provide coal deliveries for the term of the sales agreement.  IPC also has a coal supply contract providingfor annual deliveries of coal through 2009 from the Black Butte Coal Company'sBlack Butte and Leucite Hills mines located near the Jim Bridger plant.  This contract supplements the Bridger CoalCompany deliveries and provides another coal supply to operate the Jim Bridgerplant.  The Jim Bridger plant's railload-in facility and unit coal train allow the plant to take advantage ofpotentially lower-cost coal from other mines for tonnage requirements aboveestablished contract minimums.

In an effort to lower costs and access better qualitycoal, the Jim Bridger mine is converting from a surface operation to aprimarily underground operation. Underground mine development and limited coal production began in 2004,and full operation is expected by 2007.  Anumber of factors were considered in this decision including the increasingcost of the surface mine operation as well as the additional capital requiredto develop the underground mine.  Thisconversion is expected to result in a reduction of the cost of mining coal overthe life of the Jim Bridger Mine.

Sierra Pacific Power Company, asoperator of the North Valmy Generating Plant (Valmy), has an agreement withArch Coal Sales Company, Inc. to supply coal to the plant through 2009.  IPC is obligated to purchase one-half of thecoal, ranging from approximately 515,000 tons to 762,500 tons annually.  Sierra Pacific Power Company also has a coalsupply contract with Black Butte Coal Company's Black Butte Mine for deliveriesfrom 2006 through 2009.  Idaho Power isobligated to purchase one-half of the coal purchased under this agreement,ranging from 450,000 to 600,000 tons annually.

The Boardman generating plant receives coal from thePowder River Basin through annual contracts. Portland General Electric, as operator of the Boardman plant, has anagreement with Buckskin Mining Company to supply all of Boardman's coal requirementsfor the years 2006 through 2008.  IPC isobligated to purchase 10 percent of the coal purchased under this agreement,ranging from 230,000 to 270,000 tons annually.

IPC owns and operates Danskin and Bennett Mountaincombustion turbines, which receive gas through the Williams NorthwestPipeline.  All gas is purchased as needsare identified for summer peaks or to meet system requirements.  The gas is transported under a long-termcapacity contract with the Williams Northwest Pipeline and an arrangement withIGI Resources, Inc.  The WilliamsNorthwest Pipeline contract, which extends through February 28, 2007, withannual extensions at IPC's sole discretion, is for 24,523 million Britishthermal units per day from the Sumas, Washington metering point to the Elmore,Idaho metering point.  See furtherdiscussion in Part II, Item 7 - "MD&A - RESULTS OF OPERATIONS -Utility Operations - Fuel Expense."

**Water Rights**Except asdiscussed below, IPC has acquired water rights under applicable state law forall waters used in its hydroelectric 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 of these water rights are subject to priorrights, and with respect to certain hydroelectric generating facilities, IPC'swater rights for power generation are subordinated to certain future upstreamdiversions of water for irrigation and other recognized consumptive uses.

Overtime, increased irrigation development and other consumptive diversions haveresulted in a reduction in the stream flows available to fulfill IPC's waterrights at certain hydroelectric generating facilities.  In reaction to these reductions, IPCinitiated and continues to pursue a course of action to determine and protectits water rights.  As part of thisprocess, IPC and the State of Idaho signed the Swan Falls agreement on October25, 1984, which provided a level of protection for IPC's hydropower waterrights at specified plants by setting minimum stream flows and establishing anadministrative process governing the future development of water rights thatmay affect IPC's hydroelectric generation. In 1987, Congress passed, and the President signed into law, House Bill519.  This legislation permittedimplementation of the Swan Falls agreement and further provided that during theremaining term of certain of IPC's project licenses the relationshipestablished by the agreement would not be considered by the FERC as beinginconsistent with the terms of IPC's project licenses or imprudent for thepurposes of determining rates under Section 205 of the Federal Power Act.  The FERC entered an order implementing thelegislation on March 25, 1988.

Inaddition to providing for the protection of IPC's hydroelectric water rights,the Swan Falls agreement contemplated the initiation of a general adjudicationof all water uses within the Snake River basin. In 1987, the director of the Idaho Department of Water Resources filed apetition in state district court asking that the court adjudicate all claims towater rights, whether based on state or federal law, within the Snake Riverbasin.  The court signed a commencementorder initiating the Snake River Basin Adjudication on November 19, 1987.  This legal proceeding was authorized by statestatute based upon a determination by the Idaho Legislature that the effectivemanagement of the waters of the Snake River basin required a comprehensivedetermination of the nature, extent and priority of all water uses within thebasin.  The adjudication is proceedingand is expected to continue for at least the next several years.  IPC has filed claims to its water rightswithin the basin and is actively participating in the adjudication in an effectto ensure that its water rights and the operation of its hydroelectricfacilities are not adversely impacted.

Please see Part II, Item 7 - "MD&A - LEGAL ANDENVIRONMENTAL ISSUES - Environmental Issues - Idaho Water ManagementIssues" and "MD&A - REGULATORY ISSUES - Relicensing ofHydroelectric Projects."

**Environmental Regulation**Idaho Power'sactivities are subject to a broad range of federal, state, regional and locallaws and regulations designed to protect, restore and enhance the quality ofthe environment.  Environmentalregulation continues to impact IPC's operations due to the cost of installationand operation of equipment and facilities required for compliance with such regulations,and the modification of system operations to accommodate such regulations.  IPC's compliance costs will continue to besignificant for the foreseeable future.

Based upon present environmental laws and regulations,IPC estimates its 2006 capital expenditures for environmental matters,excluding Allowance for Funds Used During Construction (AFDC), will total $20million.  Studies and measures related toenvironmental concerns at IPC's hydroelectric facilities account for $17million, and investments in environmental equipment and facilities at thethermal plants account for $3 million. From 2007 through 2008, environmental-related capital expenditures,excluding AFDC, are estimated to be $35 million.  Anticipated expenses related to IPC'shydroelectric facilities account for $24 million, and thermal plant expensesare expected to total $11 million.

IPCanticipates $18 million in annual operating costs for environmental facilitiesduring 2006.  Hydroelectric facilityexpenses account for $12 million of this total, and $6 million is related tothermal plant operating expenses.  From2007 through 2008, total environmental related operating costs are estimated tobe $35 million.  Expenses related to thehydroelectric facilities are expected to be $23 million, and thermal plantexpenses are expected to be $12 million during this period.

**CleanAir:** The Environmental Protection Agency (EPA) issued SO2allowances, as defined in the Clean Air Act amendments of 1990, based on coalconsumption during established baseline years. IPC currently has more than a sufficient amount of SO2allowances to provide compliance for emissions attributable to IPC at all threeof its jointly-owned coal-fired facilities and both of its natural gas-firedfacilities.  Prior to the sale of 77,000emission allowances in 2005 and early 2006 discussed in Part II, Item 7 -"MD&A - REGULATORY ISSUES - Emission Allowances," IPC believedthat it had approximately 107,000 allowances in excess of the amount needed forClean Air Act compliance.  In addition,IPC has been granted annual allotments of allowances ranging from 15,524 to28,622 through the year 2035.  Allowancesnecessary for IPC's compliance requirements are up to 14,500 annually.  Excess allowances owned by IPC may be heldfor future use, as they do not contain expiration terms.  There is an active marketplace for buying andselling allowances, so that SO2 allowances determined to be excesscan be sold to others.  For all theforegoing reasons, IPC does not foresee any adverse effects upon its operationswith regard to SO2 emissions at this time.

In March2005, the EPA issued two new rules limiting emissions from utility boilers, theClean Air Interstate Rule and the Clean Air Mercury Rule (CAMR).  The Clean Air Interstate Rule caps emissionsof SO2 and nitrogen oxides (NOx) in 28 eastern states andthe District of Columbia.  The Clean AirInterstate Rule does not impose any restrictions on emissions from any IPCfacilities.  IPC does not foresee anyadverse effects upon its operations with regard to the Clean Air InterstateRule.

The CAMRwill limit mercury emissions from new and existing coal-fired power plants andcreates a market-based cap-and-trade program that will permanently cap utilitymercury emissions in two phases.  Currently,power plants in the United States emit approximately 48 tons of mercury peryear.  The first phase cap is 38 tonsbeginning in 2010, with a second phase cap set at 15 tons beginning in2018.  Mercury emission allocations havebeen set at the state level, but the states have not allocated the allowancesto individual utilities.  IPC is activelymonitoring developments on this issue and advances in control equipmenttechnology.  The CAMR is being challengedin court by a number of environmental groups and some states.  On October 21, 2005, the EPA granted requestsfrom petitions to reconsider certain aspects of the CAMR.  It is anticipated that this rule may requireadditional emission controls and expenses at IPC's jointly-owned coal-firedfacilities, although impacts on future plant operations, operating costs andgenerating capacity are not known at this time.

Otherpending or proposed air regulations or legislation could require IPC and itspartners to reduce emissions of SO2, NOx and otherpollutants at the jointly-owned coal-fired facilities below currentlevels.  These reductions could berequired to address regional haze programs, acid rain, mercury emissionsregulation and possible re-interpretations and changes to the federal Clean AirAct.  Like many other coal-firedfacilities in the United States, the Jim Bridger plant has received informationrequests from the EPA related to the plant's compliance with the New SourceReview provisions of the Clean Air Act, which has resulted in discussions withthe EPA and state regulatory authorities. IPC may incur significant costs to comply with tighter air emissionsrequirements in the future.  Thesepotential costs are expected to consist primarily of capital expenditures.

In July1997, the EPA announced the National Ambient Air Quality Standards (NAAQS) forozone and Particulate Matter (PM) and, in July 1999, the EPA announced regionalhaze regulations for protection of visibility in national parks and wildernessareas.  On May 14, 1999, a federal courtruling blocked implementation of the NAAQS for ozone and PM.  In November 2000, the EPA appealed to theU.S. Supreme Court to reconsider that decision. The Supreme Court ruled in favor of the EPA on February 27, 2001.  The EPA has promulgated regulationsdesignating areas of the country for attainment/non-attainment with thesestandards, and IPC's thermal plants are located in areas designated asattainment for both standards.  EPA andstate efforts to implement the NAAQS are ongoing.  On January 17, 2006, the EPA proposed revisionsto the PM NAAQS that potentially could make these NAAQS more stringent, and IPCcontinues to monitor the EPA's revisions. Litigation concerning the EPA's regional haze regulations resulted intwo separate court remands of the rule back to the EPA for reconsideration.  On June 15, 2005, the EPA issued the CleanAir Visibility Rule (CAVR) to address the first court remand.  On July 20, 2005, the EPA proposed revisionsto the CAVR to address the second court remand. Although the impacts of the NAAQS for ozone and particulate matter andthe regional haze regulations on IPC's thermal operations are not known at thistime, the future costs of compliance with these regulations could besubstantial and will depend on if and how the regulations are ultimatelyimplemented.

**Global Climate Change: **Carbondioxide emissions are the subject of growing discussion and action in thecontext of global climate change, but such emissions are not currently subjectto regulation at the federal level or at the state level where IPC's thermalplants are located.  IPC continues tomonitor developments concerning global climate change to gauge potentialimpacts on future operations.

The United States is currently not a party to the KyotoProtocol to the United Nations Framework Convention on Climate Change(Protocol) that became effective for signatories on February 16, 2005.  The Protocol process generally requiresdeveloped countries to cap greenhouse gas emissions at certain levels from 2008through 2012.

Greenhouse gas emissions are the result of many naturaland man-made processes including the combustion of fossil fuels to generateelectricity.  Carbon dioxide representsthe largest quantity of greenhouse gases emitted at IPC's coal and gasgeneration units.  Under median water conditions,the majority of IPC's generation is hydro-based, which has negligiblegreenhouse gas emissions compared to fossil-based generation.

Although it has not ratified the Protocol, the UnitedStates may adopt a national, mandatory greenhouse gas program at some point inthe future.  At this time, IPC is unableto predict the potential impacts of any future mandatory governmentalgreenhouse gas legislative or regulatory requirements.

**Water:**  IPC has receivedNational Pollutant Discharge Elimination System Permits, as required under theFederal Water Pollution Control Act Amendments of 1972, for the discharge ofeffluents from its hydroelectric generating plants.

IPC agreed in March 1976 to meet certain dissolved oxygenstandards at its American Falls hydroelectric generating plant.  IPC signed amendments to the agreementsrelating to the operation of the American Falls Dam and the location of waterquality monitoring facilities.  Theamendments provide more accurate and reliable water quality measurementsnecessary to maintain water quality standards downstream from IPC's plantduring the period from May 15 to October 15 each year.

IPC has installed aeration equipment, water qualitymonitors and data processing equipment as part of its Cascade hydroelectricproject to provide accurate water quality data and increase dissolved oxygenlevels as necessary to maintain water quality standards on the PayetteRiver.  IPC has also installed andoperates water quality monitors at its Milner, Shoshone Falls, Twin Falls,Upper Salmon, Lower Salmon, Bliss and CJ Strike hydroelectric projects in orderto meet compliance standards for water quality on the Snake River.

**EndangeredSpecies:**  Several species of fish and Snake Riversnails living within IPC's operating area are listed as threatened orendangered.  IPC continues to review andanalyze the effect such designation has on its operations.  IPC is cooperating with governmental agenciesto resolve issues related to these species. See Part II, Item 7 - "MD&A - REGULATORY ISSUES - Relicensingof Hydroelectric Projects."

IPC ownsand finances the operation of anadromous fish hatcheries and related facilitiesto mitigate the effects of its hydroelectric dams on fish populations.  In connection with its fish facilities, IPCsponsors ongoing programs for the control of fish disease and improvement offish production.  IPC's anadromous fishfacilities at Hells Canyon, Oxbow, Rapid River, Pahsimeroi and Niagara Springscontinue to be operated by the Idaho Department of Fish and Game.  At December 31, 2005, the investment in thesefacilities was $11 million and the annual cost of operation pursuant to FERCLicense 1971 was $3 million.

**Hazardous/Toxic Wastes and Substances:** Under the Toxic Substances Control Act, the EPA has adopted regulationsgoverning the use, storage, inspection and disposal of electrical equipmentthat contains polychlorinated biphenyls (PCBs). The regulations permit the continued use and servicing of certain equipment(including transformers and capacitors) that contain PCBs.  IPC continues to meet all federalrequirements of the Toxic Substances Control Act for the continued use ofequipment containing PCBs.  IPC continuesto eliminate PCBs as part of its long-term strategy.  This program will reduce costs associatedwith the long-term monitoring of PCB-containing equipment, responding to spillsand reporting to the EPA.  In 2005, IPCspent approximately $1 million identifying and eliminating PCBs.

**Competition****Retail:**  Electric utilities havehistorically been recognized as natural monopolies and have operated in ahighly regulated environment in which they have an obligation to provideelectric service to their customers in return for an exclusive franchise withintheir service territory with an opportunity to earn a regulated rate of return.

Some state regulatory authorities are in the process ofchanging utility regulations in response to federal and state statutory changesand evolving competitive markets.  Thesestatutory changes and conforming regulations may result in increased retailcompetition.  In 1997, the IdahoLegislature appointed a committee to study restructuring of the electricutility industry.  The committee has notrecommended any restructuring legislation and is not expected to in theforeseeable future.  The committee'sfocus has since shifted from restructuring to general energy issues.  In 1999, the Oregon Legislature passedlegislation restructuring the electric utility industry, but exempted IPC'sservice territory.

**Wholesale:  **The 1992 National Energy PolicyAct and the FERC's rulemaking activities have established the regulatoryframework to open the wholesale 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 FERCto require transmission access to retail customers.  Open-access transmission for wholesalecustomers provides energy suppliers with opportunities to sell and deliverelectricity at market-based prices.

For more information, see Part II, Item 7 -"MD&A - REGULATORY ISSUES - Regional Transmission Organizations."

**Utility Operating Statistics**The followingtable presents IPC's revenues and energy use by customer type for the lastthree years, which is further discussed in Part II, Item 7 - "MD&A -RESULTS OF OPERATIONS - Utility Operations:"
|                            | **Years Ended December 31,** |
|---------------------------------|------------------------------|
|                            | **2005**                     | ** ** | **2004** | ** ** | **2003** |
| Revenues (thousands of dollars) |                         |   |   |   |   |   |   |   |
|                            | Residential                  | $ | 299,488 |   | $ | 274,313 |   | $ | 275,920 |
|                            | Commercial                   |   | 173,268 |   |   | 164,053 |   |   | 173,820 |
|                            | Industrial                   |   | 118,259 |   |   | 111,797 |   |   | 128,620 |
|                            | Irrigation                   |   | 76,255 |   |   | 85,672 |   |   | 92,609 |
|                            |                         | Total general business |   | 667,270 |   |   | 635,835 |   |   | 670,969 |
|                            | Off-system sales             |   | 142,794 |   |   | 121,148 |   |   | 71,573 |
|                            | Other                        |   | 27,619 |   |   | 62,526 |   |   | 37,840 |
|                            |                         | Total | $ | 837,683 | $ |   | 819,509 |   | $ | 780,382 |
|                            |                         |   |   |   |   |   |   |   |   |
| Energy use (thousands of MWh)   |                         |   |   |   |   |   |   |   |
|                            | Residential                  |   | 4,760 |   |   | 4,580 |   |   | 4,427 |
|                            | Commercial                   |   | 3,639 |   |   | 3,561 |   |   | 3,511 |
|                            | Industrial                   |   | 3,423 |   |   | 3,335 |   |   | 3,206 |
|                            | Irrigation                   |   | 1,467 |   |   | 1,763 |   |   | 1,836 |
|                            |                         | Total general business |   | 13,289 |   |   | 13,239 |   |   | 12,980 |
|                            | Off-system sales             |   | 2,774 |   |   | 2,885 |   |   | 1,830 |
|                            |                         | Total |   | 16,063 |   |   | 16,124 |   |   | 14,810 |
|                            |                         |   |   |   |   |   |   |   |   |

 

**IFS:**

IFSinvests primarily in affordable housing developments, which provide a returnprincipally by reducing federal and state income taxes through tax credits andaccelerated tax depreciation benefits. IFS generated tax credits of $20 million, $22 million and $20 million in2005, 2004 and 2003, respectively.  IFS'sportfolio also includes historic rehabilitation projects such as the EmpireBuilding in Boise, Idaho.  IFS made $5million in new investments during 2005.  Otheractivity during the year included cash receipts of $1.3 million representingreturns of capital which reduced the investment carrying value.

IFS hasfocused on a diversified approach to its investment strategy in order to limitboth geographic and operational risk. Over 90 percent of IFS's investments have been made through syndicatedtransactions.  At December 31, 2005, thegross amount of IFS's portfolio equaled $170 million in tax creditinvestments.  These investments cover 49states, Puerto Rico and the U.S. Virgin Islands.  The underlying investments include over 700individual properties, of which all but three are administered throughsyndicated funds.

**IDACOMM:**

InAugust 2000, IDACORP formed IDACOMM and acquired Velocitus, Inc. (formerlyRocky Mountain Communication, Inc.), a Boise, Idaho-based Internet serviceprovider founded in 1993.  In October2004, IDACORP transferred its ownership of Velocitus to IDACOMM, and in January2005, Velocitus was merged into IDACOMM.

InJune 2004, IDACOMM acquired Sierra Pacific Communications' Nevada metro areanetwork assets.  With this acquisition,IDACOMM provides high-speed fiber optic network service to large businessenterprises, government organizations, and telephony carrier customers inBoise, Idaho, and Reno and Las Vegas, Nevada. IDACOMM employs dark fiber private networks and lit Ethernetcommunications over SONET (Sychronous Optical Networking) fiber ring topologyto provide the services.  During 2005,IDACOMM sold eight strands of fiber inventory within its Las Vegas network toseveral large customers for $3.9 million.

IDACOMMbegan offering its Voice over Internet Protocol (VoIP) services in July 2004 tobusiness customers in Boise, Idaho, and expanded these services to Las Vegas,Nevada in February 2005.  The company iscurrently launching a VoIP offering in Reno, Nevada.  The company sells, designs, installs, andoperates an Internet Protocol voice and data service package to small andmedium business enterprises ranging from 5 to 100 phone stations.  The service packages include dial-tone,integrated voice and email messaging, and hosted telephony advanced servicessuch as complex call routing and Internet access.  These services are offered over its ownnetworks or over T-1 lines leased from the local telephone company.

During2004 and 2005, IDACOMM explored the commercial viability of BPL, stagingequipment trials in Boise, Idaho and in Houston, Texas.  In January 2006, the company announced itsintention to phase out this endeavor, seeing its economic viability as alonger-term proposition than desirable. While the company will meet all of its current contractual obligationsfrom this effort, it will cease pursuing additional commercial contracts usingthis emerging technology.  As part of theshift in strategy away from additional BPL efforts, the company took a goodwillimpairment charge of $10 million.  In2005, IDACOMM also recorded a valuation allowance of $1.6 million against taxassets acquired in 2000 with its acquisition of Velocitus.

**ITI:**

IdaTechwas founded in 1996 as Northwest Power Systems, LLC to develop and bring fuelcell technology to market.  In April1999, ITI, a wholly-owned subsidiary of IDACORP, purchased an interest in IdaTechand now owns over a 90 percent interest.

IdaTechis a developer of proton exchange membrane (PEM) fuel cell systems for criticalbackup, emergency, remote and portable power applications.

IdaTech'sproducts under development include:

ElectraGenTM - Critical backup systems ranging from 3-5 kWin output and designed to provide backup power in applications such astelecommunications sites.

iGenTM - A 250 watt fuel cell system with on-board fuelreformer providing portable and auxiliary power for remote off-grid locationsas well as military and recreational vehicles.

Modular fuel reformers - Fuel reformers convert liquidfuel to hydrogen for use in the ElectraGenTM systems.

Components - Multi-fuel fuel processors, fuel cell stacktechnology and automated fuel cell systems target longer-term commercialapplications in vehicular auxiliary power units and combined heat and powerunits.  For these longer-term marketopportunities, IdaTech has joined with German companies Volkswagen, RWE FuelCells and Bosch Buderus in product development programs.

Currently,these systems are being evaluated by European utilities and telecommunicationscompanies, Rittal Corp., The U.S. Department of Energy, the U.S. ArmyCommunication Electronics Command and other customers in North America, Europeand Asia.

During2005, IdaTech expanded its corporate headquarters and in February 2005, openedits first European office in Herten, state of North Rhine Westphalia, Germany,to provide development and technical support to existing customers andfacilitate additional growth in the European telecommunications market.  A strategic development agreement with RittalCorp. was signed in March 2005, which will integrate IdaTech's fuel cellsystems with Rittal's telecommunications and information technology systems toprovide the seamless backup power solutions. In July, the U.S. Army contracted with IdaTech to continue development ofand enhance its iGenTM system.

InSeptember 2005, IdaTech received CE Certification of the ElectraGenTM systems,allowing sales and operation of the systems in Europe.  Following the certification, IdaTechintroduced the ElectraGenTM Extended Run Module and the ElectraGenTM3 fuel cellsystem.

**IDA-WEST:**

Ida-West operates and has a 50 percent interest in ninehydroelectric plants with a total generating capacity of 45 MW.  Four of the projects are located in Idaho andfive are in northern California.  Allnine projects are "qualifying facilities" under PURPA.  IPC purchased all of the power generated byIda-West's four Idaho hydroelectric projects, at a cost of $7 million per year,in 2005, 2004 and 2003.

**RESEARCH AND DEVELOPMENT:**

**IPC:**In 2005, IPCspent approximately $6.5 million to promote energy efficiency and summer peakreduction through its Demand 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 and Renewable Discount Program of theBonneville Power Administration.

Aportion of these programs covers 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.  These programs represent approximately ninepercent of the total spending.

Energyefficiency programs target savings across the entire year for a wide range ofcustomer segments with an emphasis on reducing energy during the summer peak:

Approximately one-third of the 2005 expenses were devotedto achieving summer peak reduction through focusing on irrigation pumping andresidential air conditioning equipment control measures.

The residential programs target new and existing homes,focusing on customer education and the application of energy efficiencyremediation, including energy efficient building techniques, insulationaugmentation, air duct sealing, and the use of efficient lighting. Thesegment's 2005 spending represented about 33 percent of the total.

Energy efficiency programs for existing industrial andnew commercial facilities focus on application of energy efficient techniquesand technologies as well as operational and management processes to reduce energyconsumption.  These programs representapproximately 22 percent of total expenses.

**IdaTech:**In 2005, IdaTechspent $8.6 million for research and development of fuel cell technology.  IdaTech's research and development program isfocused on the adaptation of its fuel processor technology to operate on allcommercially important fuels, as well as the continued development of fullyintegrated fuel cell systems.

IdaTechcontinues to pursue patent protection in the Americas, Europe, and Asia.  The patents issued to IdaTech address thedesign and operation of fuel reformers, the design and materials ofconstruction used in IdaTech's two stage hydrogen purification devices based onthe HyPuriumTM membranes used to filter out impurities in the product hydrogen,fuel cell system automated control and operation; integrated heat recovery fromfuel cell systems and automated control of integrated pressure-swing absorptionfor efficient and reliable operation. Currently, 43 U.S. patents lasting 20 years and 62 foreign patents havebeen issued or allowed to IdaTech.  Thesepatents expire from 2016 to 2026. IdaTech also has approximately 200 pending domestic and foreign patentapplications addressing aspects of (1) fuel processor system design, operation,materials and integration; (2) membrane purification, materials and design; and(3) fuel cell system operation, thermal recovery, design, remote control anddiagnostics.  These patents will continueto help IdaTech bring its backup and remote fuel cell solutions to market.  The patents also provide the potential forlicensing of IdaTech's technology in the future.

**ITEM 1A.  RISKFACTORS**

The following are factors that could have a significantimpact on the operations and financial results of IDACORP, Inc. and Idaho PowerCompany and could cause actual results or outcomes to differ materially fromthose discussed in any forward-looking statements:

**Reduced hydroelectric generationcan reduce revenues and increase costs.**  Idaho PowerCompany has a predominately hydroelectric generating base.  Because of Idaho Power Company's heavyreliance on hydroelectric generation, the weather can significantly affect itsoperations.  Idaho Power Company experiencedits sixth consecutive year of below normal water conditions in 2005.  When hydroelectric generation is reduced,Idaho Power Company must increase its use of more expensive thermal generatingresources and purchased power.  Throughits power cost adjustment in Idaho, Idaho Power Company can expect to recoverapproximately 90 percent of the increase in its Idaho jurisdictional net powersupply costs, which are fuel and purchased power less off-system sales, abovethe level included in its base rates. The power cost adjustment recovery includes both a forecast anddeferrals that are subject to the regulatory process.  However, recovery of amounts above forecastin one power cost adjustment year does not occur until the subsequent power costadjustment year.  The non-Idaho net powersupply costs are subject to periodic recovery from the Oregon and FederalEnergy Regulatory Commission jurisdictional customers.

**Continuing declines in streamflows and over-appropriation of water in Idaho will reduce hydroelectricgeneration and revenues and increase costs.** Thecombination of declining Snake River base flows, over-appropriation of waterand continuing drought conditions have led to disputes among surface water andground water irrigators, and the State of Idaho.  Recharging the Eastern Snake Plain Aquifer,which contributes to Snake River flows, by diverting surface water to porouslocations and permitting it to sink into the aquifer is one proposed solutionto the dispute.  Idaho Power Companybelieves diversions from the Snake River for aquifer recharge may furtherreduce Snake River flows available for hydroelectric generation and reduceIdaho Power Company revenues and increase costs.

**Changes in temperature andprecipitation can reduce power sales and revenues.** Warmer than normal winters, cooler than normalsummers and increased rainfall during the irrigation seasons will reduce retailrevenues from power sales.

**If the Idaho Public UtilitiesCommission, the Oregon Public Utility Commission or the Federal EnergyRegulatory Commission grant less rate relief than requested in rate case filings,it will reduce Idaho Power Company's earnings and cash flows.** If the Idaho Public Utilities Commission, the Oregon Public UtilityCommission or the Federal Energy Regulatory Commission were to grant less raterelief than Idaho Power Company requests in its rate case filings, it couldhave a negative effect on earnings and cash flow and result in futuredowngrades of IDACORP, Inc.'s and Idaho Power Company's credit ratings.

**Conditions that may be imposed inconnection with hydroelectric license renewals may require large capitalexpenditures and reduce earnings and cash flows.** Idaho Power Company is currently involved in renewing federal licensesfor several of its hydroelectric projects. Conditions with respect to environmental, operating and other mattersthat the Federal Energy Regulatory Commission may impose in connection with therenewal of Idaho Power Company's licenses could have a negative effect on IdahoPower Company's operations, require large capital expenditures and reduceearnings and cash flows.

**The cost of complying withenvironmental 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, operating and other costs,and those costs could be even more significant in the future as a result ofchanges in legislation and enforcement policies.  For instance, considerable attention has beenfocused on carbon dioxide emissions from coal-fired generating plants and theirpotential role in contributing to global warming.  Mercury emissions from coal-fired plants arealso being discussed.  The adoption ofnew laws and regulations to implement carbon dioxide, mercury or other emissioncontrols could increase the cost of operating coal-fired generating plants andreduce earnings and cash flows.

**IDACORP, Inc., IDACORP Energy andIdaho Power Company are subject to costs and other effects of legal andregulatory proceedings, settlements, investigations and claims, including thosethat have arisen out of the western energy situation.** IDACORP, Inc., IDACORP Energy and Idaho Power Company are involved in anumber of proceedings including a cross-action wholesale electric antitrustcase against various sellers and generators of power in California and theCalifornia refund proceeding at the Federal Energy Regulatory Commission.  Other cases that are the direct or indirectresult of the western energy situation include a refund proceeding affectingsellers of wholesale power in the spot market in the Pacific Northwest, inwhich the Federal Energy Regulatory Commission directed that no refunds bepaid, but which is now pending on appeal before the United States Court ofAppeals for the Ninth Circuit; efforts by other parties to reform or terminatecontracts for the purchase of power from IDACORP Energy or claiming violationsof state and federal antitrust acts and dysfunctional energy markets as theresult of market manipulation; show cause proceedings at the Federal EnergyRegulatory Commission, which have been settled but are the subject of motionsfor rehearing or have been appealed; claims pending before the United StatesCourt of Appeals for the Ninth Circuit that the Federal Energy RegulatoryCommission-ordered refund period should have been expanded to include a longertime period, and the reversal by the United States Court of Appeals for theNinth Circuit of Federal Energy Regulatory Commission rulings that market-basedsellers' transactional reports satisfy the Federal Energy RegulatoryCommission's filed-rate doctrine requirements as a means of expanding refundsfrom all sellers of wholesale power, which rulings remain pending before theUnited States Court of Appeals for the Ninth Circuit on rehearing.  To the extent the companies are required tomake payments, earnings will be negatively affected.  It is possible that additional proceedingsrelated to the western energy situation may be filed in the future againstIDACORP, Inc., IDACORP Energy or Idaho Power Company.

**Pending shareholder litigationcould be costly, time consuming and, if adversely decided, result insubstantial liabilities.**  Two securities shareholderlawsuits consolidated by order dated August 31, 2004 have been filed againstIDACORP, 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 notcovered by insurance policies.  WhileIDACORP, Inc. cannot predict the outcome of these matters and these matterswill take time to resolve, damages arising from these lawsuits if resolvedagainst IDACORP, Inc. or in connection with any settlement, absent insurancecoverage or damages in excess of insurance coverage, could have a materialadverse effect on the financial position, results of operations or cash flows ofIDACORP, Inc.

**Increased capital expenditurescan significantly affect liquidity.**  Increases in boththe number of customers and the demand for energy require expansion andreinforcement of transmission, distribution and generating systems.  If Idaho Power Company does not receivetimely regulatory relief, Idaho Power Company will have to rely more onexternal financing for its planned utility construction expenditures from 2006through 2008; these large planned expenditures may weaken the consolidated financialprofile of Idaho Power Company and IDACORP, Inc.  Additionally, a significant portion of IdahoPower Company's facilities were constructed many years ago.  Aging equipment, even if maintained inaccordance with good engineering practices, may require significant capitalexpenditures.  Failure of equipment orfacilities used in Idaho Power Company's systems could potentially increaserepair and maintenance expenses, purchased power expenses and capitalexpenditures.

**If losses at the non-regulatedsubsidiaries continue and if they are unable to obtain financing, this mayreduce IDACORP, Inc.'s earnings and cash flow.** IdaTech and IDACOMM have experienced operating losses and it is notcertain that they will achieve or sustain profitability in the future.  If these non-regulated subsidiaries do notachieve profitability or are unable to obtain financing to fund theiroperations, this could increase the need for IDACORP, Inc. to provide liquidityin the form of capital contributions or loans and/or increase the need forIDACORP to pursue other strategic alternatives including possible sale, mergeror dissolution.  Any of these actionscould have a negative impact on IDACORP, Inc.'s earnings and cash flows.  In addition, if the value of thesesubsidiaries declines, IDACORP, Inc. may need to evaluate for possible assetimpairment charges.

**A downgrade in IDACORP, Inc.'sand 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 InvestorsService, and on January 24, 2005, Fitch, Inc. each downgraded IDACORP, Inc.'sand Idaho Power Company's credit ratings. These downgrades and any future downgrades of IDACORP, Inc.'s or IdahoPower Company's credit ratings could limit the companies' ability to access thecapital markets, including the commercial paper markets.  In addition, IDACORP, Inc. and Idaho PowerCompany would likely be required to pay a higher interest rate on existing short-termand variable rate debt and in future financings.

**Terrorist threats and activitiescould result in reduced revenues and increased costs. **IDACORP, Inc. and Idaho Power Company are subject todirect and indirect effects of terrorist threats and activities.  Potential targets include generation andtransmission facilities.  The effects ofterrorist threats and activities could prevent Idaho Power Company frompurchasing, generating or transmitting power and result in reduced revenues andincreased costs.

**Adverse results of income taxaudits could reduce earnings and cash flows.**  In March2005, the Internal Revenue Service began its examination of IDACORP's 2001through 2003 tax years.  On October 24,2005, the Idaho State Tax Commission also began its examination of the same taxyears.  Outcome of the audits coulddiffer materially from the amounts currently recorded, and the difference couldreduce IDACORP's and Idaho Power Company's earnings and cash flows.

**ITEM 1B. UNRESOLVED STAFF COMMENTS**

None

**ITEM 2.  PROPERTIES**

IPC's generation system includes 17 hydroelectric generationdevelopments located in Idaho and Oregon, two natural gas-fired plants and onediesel-powered generator located in Idaho, and interests in three coal-firedgenerating plants in Wyoming, Oregon and Nevada.  IPC acquired the second gas-fired plant,Bennett Mountain Power Plant, on March 31, 2005.  The system also includes approximately 4,691miles of high voltage transmission lines, 24 step-up transmission substationslocated at power plants, 20 transmission substations, nine transmissionswitching stations and 219 energized distribution substations (excluding mobilesubstations and dispatch centers).

IPC holds FERC licenses for 12 of its hydroelectricprojects.  These projects and the othergenerating stations and their capacities are listed below:

 
| ** ** | **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) 

164,000

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 of relicensing inPart II, Item 7 - "MD&A - REGULATORY ISSUES - Relicensing ofHydroelectric Projects."

At December 31, 2005, the composite average ages of the principalparts of IPC's system, based on dollar investment, were production plant, 24years; transmission system and substations, 23 years; and distribution linesand substations, 19 years.  IPC considersits properties to be well-maintained and in good operating condition.

IPC owns in fee all of its principal plants and other important unitsof real property, except for portions of certain projects licensed under theFederal Power Act and reservoirs 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.  In addition, IPC's property is subject tominor defects common to properties of such size and character that do notmaterially impair the value to, or the use by, IPC of such properties.

Idaho Energy Resources Co. owns a one-third interest in the BridgerCoal Company and coal leases near the Jim Bridger generating plant in Wyomingfrom which coal is mined and supplied to the plant.

Ida-West holds 50 percent interests in nine operating hydroelectricplants with a total generating capacity of 45 MW.  These plants are located in Idaho andCalifornia.

See Note 1 to IDACORP's and IPC's Consolidated Financial Statementsfor a discussion of the property of IDACORP's consolidated Variable InterestEntities.

**ITEM 3. LEGAL PROCEEDINGS**

See Note 8 of IDACORP's and IPC's Consolidated Financial Statements.

**ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS**

None

**EXECUTIVE OFFICERS OF THE REGISTRANT**

The names, ages and positions of all of the executive officers ofIDACORP, Inc. are listed below along with their business experience during thepast five years.  There are no familyrelationships among these officers, nor is there any arrangement orunderstanding between any officer and any other person pursuant to which theofficer was elected.

JAN B. PACKWOOD President and Chief Executive Officer of IDACORP,Inc., appointed May 30, 1999.  Mr.Packwood was Chief Executive Officer of Idaho Power Company from March 1, 2002to November 17, 2005.  Mr. Packwood wasPresident and Chief Executive Officer of Idaho Power Company from May 30, 1999to March 1, 2002.  Mr. Packwood alsoserves on the Board of Directors of both IDACORP, Inc. and Idaho Power Company.  Age 62

J. LAMONT KEEN Executive Vice President of IDACORP, Inc., appointedMarch 1, 2002.  Mr. Keen also serves asPresident and Chief Executive Officer of Idaho Power Company, appointedNovember 17, 2005.  Mr. Keen wasPresident and Chief Operating Officer of Idaho Power Company from March 1, 2002to November 17, 2005.  Mr. Keen wasSenior Vice President - Administration and Chief Financial Officer of IDACORP,Inc. and Idaho Power Company from May 5, 1999 to March 1, 2002.  Mr. Keen also serves on the Board ofDirectors of both IDACORP, Inc. and Idaho Power Company.  Age 53

DARREL T. ANDERSON Senior Vice President - Administrative Servicesand Chief Financial Officer of IDACORP, Inc. and Idaho Power Company, appointedJuly 1, 2004.  Mr. Anderson was VicePresident, Chief Financial Officer and Treasurer of IDACORP, Inc. and IdahoPower Company from March 1, 2002 to July 1, 2004 and Vice President - Financeand Treasurer of IDACORP, Inc. and Idaho Power Company from May 5, 1999 toMarch 1, 2002.  Age 47

THOMAS R. SALDIN Senior Vice President, General Counsel and Secretaryof IDACORP, Inc. and Idaho Power Company, appointed October 1, 2004.  Mr. Saldin was Executive Vice President andGeneral Counsel of Albertson's Inc., a supermarket chain, from January 29, 1999to his retirement on August 31, 2001.  Age59

DENNIS C. GRIBBLE Vice President and Treasurer of IDACORP, Inc. andIdaho Power Company, appointed July 15, 2004. Mr. Gribble was Finance Controller of Idaho Power Company from January1, 1997 to July 15, 2004.  Age 53

A. BRYAN KEARNEY Vice President and Chief Information Officer ofIDACORP, Inc. and Idaho Power Company, appointed March 15, 2001.  Mr. Kearney has been the Vice President andChief Information Officer of Idaho Power Company since November 18, 1999.  Age 43

LUCI K. MCDONALD Vice President - Human Resources of IDACORP, Inc.and Idaho Power Company, appointed December 6, 2004.  Ms. McDonald was Corporate Staff Director ofHuman Resources of Boise Cascade Corporation, a forest products company, fromSeptember 16, 1999 to November 19, 2004. Age 48

GREGORY W. PANTER Vice President - Public Affairs of IDACORP, Inc.and Idaho Power Company, appointed April 1, 2001.  Mr. Panter was self-employed with Greg PanterConsulting, a lobbying/government affairs business, from July 1, 1999 to April1, 2001.  Age 57

LORI D. SMITH Vice President - Finance and Chief Risk Officer ofIDACORP, Inc. and Idaho Power Company, appointed July 15, 2004.  Ms. Smith was Director of Strategic Analysisof Idaho Power Company from January 1, 2000 to July 15, 2004.  Age 45

**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, istraded on the New York Stock Exchange. On December 31, 2005, there were 17,016 holders of record and the stockprice was $29.30 per share.

The outstanding shares of IPC's common stock, $2.50par value, are held by IDACORP and are not traded.  IDACORP became the holding company of IPC onOctober 1, 1998.

The amount and timing of dividends payable onIDACORP's common stock are within the sole discretion of IDACORP's Board ofDirectors.  The Board of Directorsreviews the dividend rate quarterly to determine its appropriateness in lightof IDACORP's current and long-term financial position and results ofoperations, capital requirements, rating agency requirements, legislative andregulatory developments affecting the electric utility industry in general andIPC in particular, competitive conditions and any other factors the Board ofDirectors deems relevant.  In September2003, IDACORP announced a decrease in the annual dividend from $1.86 to $1.20per share.  See further discussion of thedividend reduction in Part II, Item 7 - "MD&A - LIQUIDITY AND CAPITALRESOURCES - Dividend Reduction." The ability of IDACORP to pay dividends on its common stock is dependentupon dividends paid to it by its subsidiaries, primarily IPC.

A covenant under the IDACORPand IPC Credit Facilities described in "MD&A - LIQUIDITY AND CAPITALRESOURCES - Financing Programs - Credit Facilities" requires IDACORP andIPC to maintain leverage ratios of consolidated indebtedness to consolidatedtotal capitalization of no more than 65 percent at the end of each fiscalquarter.  IPC's ability to pay dividendson its common stock held by IDACORP and IDACORP's ability to pay dividends onits common stock are limited to the extent payment of such dividends wouldcause their leverage ratios to exceed 65 percent.  At December 31, 2005, the leverage ratios forIDACORP and IPC were 51 and 52 percent, respectively.

IPC's articles of incorporation containrestrictions on the payment of dividends on its common stock if preferred stockdividends are in arrears.  IPC has nopreferred stock outstanding.  IPC paiddividends toIDACORPof $51 million, $46 million and $65 million in 2005, 2004 and 2003,respectively.

The following table shows the reported high and lowsales price of IDACORP's common stock and dividends paid for 2005 and 2004 asreported in the consolidated transaction reporting system.

 

**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

30.0

 

30.0

 

30.0

 

30.0

 

 

 

**2004 Quarters**

Common  Stock, without par value:

**1st**

** **

**2nd**

** **

**3rd**

** **

**4th**

 

High

$32.05

 

$30.66

 

$29.95

 

$32.95

 

Low

29.32

 

25.30

 

26.05

 

29.05

 

Dividends  paid per share

30.0

 

30.0

 

30.0

 

30.0

** **

**IssuerPurchases of Equity Securities:**

**IDACORP, Inc. Common Stock**

** **

** **

**(c) Total Number**

**(d) Maximum**

** **

** **

** **

**Purchased of**

**Number (or**

** **

**(a) Total**

** **

** Shares as Part of**

**Approximate Value**

** **

**Number**

**(b) Average**

**Publicly**

**of Shares that May**

** **

**of Shares**

**Price Paid**

**Announced**

**Yet Be Purchased Under**

**Period**

**Purchased**

**per Share**

**Plans or Programs**

**the Plans or Programs**

October 1 - October 31, 2005

-    

$

-

 

 

November 1 - November 30, 2005

-    

 

-

 

 

December 1 - December 31, 2005

82(1)

 

29.54

 

 

Total

82   

$

29.54

 

 

(1) These shares were withheld for taxes upon vesting of  restricted stock.

** **

**ITEM 6. SELECTED FINANCIAL DATA**

**IDACORP,  Inc.**

**SUMMARY  OF OPERATIONS**

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

 

**2005**

**2004**

**2003**

**2002**

**2001**

Operating  Revenues

$

859,488

$

844,491

$

823,002

$

928,800

$

1,275,312

Operating  income

 

127,749

 

93,251

 

84,062

 

75,640

 

242,289

Net  income

 

63,661

 

72,983

 

46,578

 

61,672

 

125,214

Earnings  per diluted share 

 

1.50

 

1.90

 

1.22

 

1.63

 

3.35

Dividends  declared per share

 

1.20

 

1.20

 

1.70

 

1.86

 

1.86

 

 

 

 

 

 

 

 

 

 

 

 

**Financial  Condition:**

 

 

 

 

 

 

 

 

 

 

Total  assets

$

3,364,126

$

3,234,172

$

3,106,108

$

3,387,168

$

3,769,992

Long-term  debt

 

1,039,887

 

1,058,152

 

1,013,757

 

988,268

 

879,048

 

 

 

 

 

 

 

 

 

 

 

**Financial  Statistics:**

 

 

 

 

 

 

 

 

 

 

Times  interest charges earned:

 

 

 

 

 

 

 

 

 

 

 

Before  tax

 

2.27   

 

1.83   

 

1.37   

 

1.16   

 

3.52   

 

After  tax

 

2.06   

 

2.25   

 

1.68   

 

1.93   

 

2.66   

Market-to-book  ratio

 

121%

 

128%

 

132%

 

108%

 

175%

Payout  ratio

 

79%

 

63%

 

139%

 

114%

 

56%

Return  on year-end common equity

 

6.2%

 

7.2%

 

5.4%

 

7.1%

 

14.4%

Book  value per share

$

24.17   

$

23.88   

$

22.61  

$

22.98  

$

23.21  

 

 

 

 

 

 

 

 

 

 

 

See Part II, Item 7 - "MD&A - RESULTS OF  OPERATIONS" for a discussion of the factors that affect comparability.

The above data should be read in conjunction with  IDACORP's and IPC's Consolidated Financial Statements including 

the Notes to the Consolidated Financial Statements.

 

**ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OFFINANCIAL CONDITION AND RESULTS OF OPERATIONS**

(Dollar amountsand Megawatt hours (MWh) are in thousands unless otherwise indicated).

**INTRODUCTION:**

InManagement's Discussion and Analysis of Financial Condition and Results ofOperations (MD&A), the general financial condition and results ofoperations for IDACORP, Inc. and its subsidiaries (collectively, IDACORP) andIdaho Power Company and its subsidiary (collectively, IPC) are discussed.

IDACORPis a holding company formed in 1998 whose principal operating subsidiary isIPC.  Due to the repeal of the PublicUtility Holding Company Act of 1935 (1935 Act), effective February 8, 2006,IDACORP is no longer subject to any provisions under the 1935 Act.  IDACORP is a holding company under the newlyenacted Public Utility Holding Company Act of 2005 (2005 Act), which providescertain access to books and records to the Federal Energy Regulatory Commission(FERC) and state utility regulatory commissions and imposes certain recordretention and reporting requirements on IDACORP.

IPC isan electric utility with a service territory covering approximately 24,000square miles in southern Idaho and eastern 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'sother subsidiaries include:

IDACORP Financial Services, Inc. (IFS) - holder ofaffordable housing and other real estate investments;

IdaTech, LLC (IdaTech) - developer of integrated fuelcell systems,over 90 percent-owned by IDACORP's wholly-owned subsidiary IDACORPTechnologies, Inc. (ITI);

IDACOMM, Inc. (IDACOMM) - provider of telecommunicationsservices and commercial Internet services;

Ida-West Energy Company (Ida-West) - operator of small hydroelectricgeneration projects that satisfy the requirements of the Public UtilityRegulatory Policies Act of 1978 (PURPA). In 2003,Ida-West discontinued its project development operations and began managing itsindependent power projects with a reduced workforce; and

IDACORP Energy (IE), - marketer of electricity andnatural gas, which wound down its operations in 2003.

Whilereading the MD&A, please refer to the Consolidated Financial Statements ofIDACORP and IPC, which present the financial position at December 31, 2005 and2004, and the results of operations and cash flows for each company for theyears ended December 31, 2005, 2004 and 2003.

**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 to expectations, beliefs, plans, objectives,assumptions or future events or performance (often, but not always, through theuse of words or phrases such as "anticipates," "believes,""estimates," "expects," "intends,""plans," "predicts," "projects," "mayresult," "may continue" or similar expressions) are notstatements of historical facts and may be forward-looking.  Forward-looking statements involve estimates,assumptions and uncertainties and are qualified in their entirety by referenceto, and are accompanied by, the following important factors, which aredifficult to predict, contain uncertainties, are beyond IDACORP's or IPC'scontrol and may cause actual results to differ materially from those containedin forward-looking statements:

Changes in governmental policies, including newinterpretations of existing policies, and regulatory actions and regulatoryaudits, including those of the Federal Energy Regulatory Commission, the IdahoPublic Utilities Commission, the Oregon Public Utility Commission, and theInternal Revenue Service with respect to allowed rates of return, industry andrate structure, day-to-day business operations, acquisition and disposal ofassets and facilities, operation and construction of plant facilities, relicensingof hydroelectric projects, recovery of purchased power expenses, recovery ofother capital investments, present or prospective wholesale and retailcompetition (including but not limited to retail wheeling and transmissioncosts) and other refund proceedings;

Changes arising from the recently enacted Energy PolicyAct of 2005;

Litigation and regulatory proceedings, including thoseresulting from the energy situation in the western United States, andsettlements that influence business and profitability;

Changes in and compliance with environmental, endangeredspecies and safety laws and policies;

Weather variations affecting hydroelectric generatingconditions and customer energy usage;

Over-appropriation of surface and groundwater in theSnake River Basin resulting in reduced generation at hydroelectric facilities;

Construction of power generating facilities includinginability to obtain required governmental permits and approvals, and risksrelated to contracting, construction and start-up;

Operation of power generating facilities includingbreakdown 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 regionaltransmission organization;

Population growth rates and demographic patterns;

Market demand and prices for energy, including structuralmarket changes;

Changes in operating expenses and capital expendituresand fluctuations in sources and uses of cash;

Results of financing efforts, including the ability toobtain financing on favorable terms, which can be affected by factors such ascredit ratings and general economic conditions;

Actions by credit rating agencies, including changes inrating criteria and new interpretations of existing criteria;

Homeland security, natural disasters, acts of war orterrorism;

Market conditions and technological developments thatcould affect the operations and prospects of IDACORP's subsidiaries or theircompetitors;

Increasing health care costs and the resulting effect onhealth insurance premiums paid for employees;

Performance of the stock market and the changing interestrate environment, which affect the amount of required contributions to pensionplans, as well as the reported costs of providing pension and otherpostretirement benefits;

Increasing costs of insurance, changes in coverage termsand the ability to obtain insurance;

Changes in tax rates or policies, interest rates or ratesof inflation;

Adoption of or changes in critical accounting policies orestimates; and

New accounting or Securities and Exchange Commissionrequirements, or new interpretation or application of existing requirements.

 

Anyforward-looking statement speaks only as of the date on which such statement ismade.  New factors emerge from time totime and it is not possible for management to predict all such factors, nor canit assess the impact of any such factor on the business or the extent to whichany factor, or combination of factors, may cause results to differ materiallyfrom those contained in any forward-looking statement.

**EXECUTIVEOVERVIEW:**

**2005Financial Results**IDACORP's netincome in 2005 was $64 million compared to $73 million in 2004.  Diluted earnings per share (EPS) for the yearof $1.50 was a $0.40 per share decrease from 2004's results of $1.90 per share.

The keycomponents of the change in annual IDACORP net income are:

IPC's earnings increased to $72 million, a $6 millionincrease over last year.  This increaseresulted primarily from improved operating margins resulting from theimplementation of general rate increases in June of both years.  IPC set a record for annual general businesscustomer growth with a gain of 16,737 customers to 457,146.  This represents a 3.8 percent increaseyear-over-year.

IDACOMM lost $13 million in 2005 compared to a $2 millionloss in 2004. In the fourth quarter of 2005, IDACOMM recorded a $10 milliongoodwill impairment, which resulted principally from a revision to thecompany's business strategy and decision to phase out thebroadband-over-powerline (BPL) portion of its business.

Net loss at ITI increased from $6 million to $9 millionas IdaTech accelerates in its product development phase. The increase resultsfrom a $3 million reduction in sales of products in development, and a $2million increase in product development costs.

Earnings at IE increased from $2 million in 2004 to $5million in 2005, due primarily to a $9.5 million reduction in the allowance foruncollectible accounts due from California parties in the California refundproceeding.  This adjustment was based onmanagement's assessment of negotiations to settle the legal actions surroundingtransactions in the California markets in 2000 and 2001.  On February 17, 2006, IE and IPC jointlyfiled with several California parties an Offer of Settlement at the FERC.  Final comments on the settlement are due tobe filed by March 20, 2006, after which the FERC will determine whether toapprove the settlement.  This matter isdiscussed in more detail in "Legal Matters."  In 2004, IE had recorded $4 million of gainson settlement of legal disputes.

In 2005, IFS contributed $2 million less to earnings thanin the prior year.  In 2004, IFS recordeda $2 million gain on the sale of its investment in the El Cortez Hotel in SanDiego, California.

Pershare amounts in 2005 were also affected by the issuance of approximately fourmillion shares of IDACORP common stock in December 2004.

**BusinessStrategy**IDACORP is focusingon a back-to-basics strategy that emphasizes IPC as IDACORP's corebusiness.  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, with its affordable housing and historic rehabilitation portfolio,remains a key component of the corporate strategy.

Thestrategy includes seeking timely rate relief in both the Idaho and Oregonjurisdictions.  IPC plans to file inIdaho and Oregon for either asset-specific or general rate relief regularly inupcoming years.  In 2005, IPC receivedapproval from the IPUC of a rate request related to costs incurred inconnection with the construction of the Bennett Mountain Power Plant.  IPC also filed an Idaho general rate case inthe fall; a proposed settlement of this case was filed for IPUC approval inFebruary 2006.

IDACORPhas revised its business strategy for IDACOMM, its wholly-owned communicationssubsidiary.  IDACOMM now will focus onbuilding its existing competitive local exchange carrier business in Boise,Idaho and Las Vegas and Reno, Nevada, and phasing out the portion of its businessexploring the potential use of BPL technology.

IDACORP is reviewing strategic alternatives for IdaTech'sfuel cell business, including its possible sale or merger in an effort to minimizethe financial impact on IDACORP.  IdaTechis transitioning from developmental projects to commercial products.

**Regulatory Matters:Idaho general rate case: **IPC filed a general rate case inOctober 2005, requesting the IPUC to approve an annual increase to its Idahoretail base rates of $44 million or 7.8 percent.  Base rates primarily reflect IPC's cost ofproviding electrical service to its customers, including equipment, vehiclesand infrastructure.

OnFebruary 27, 2006, IPC, the IPUC staff and representatives of customer groupsfiled a proposed stipulation with the IPUC that, if approved, would settle thiscase.  The stipulation calls for an $18.1million increase, or 3.2 percent in IPC's annual electric rates.  If approved by the IPUC, the changes in ratesare expected to become effective on June 1, 2006.

The ratecase filing was made with six months of actual operating expenses and sixmonths of projected expenses.  The agreedto increase in rates was lower than the requested amount primarily due to threefactors:  (1) 2005 actual numbers weresignificantly less than those forecasted; (2) the overall rate of return agreedto was 8.1 percent compared to the 8.42 percent IPC requested (no specificreturn on equity was determined); and (3) net power supply costs were kept atlevels currently existing in rates.  As aresult of the settlement, IPC's overall rate of return will increase from the7.85 percent currently authorized.

**Emissionallowances:** During the fourth quarter of 2005, IPC sold 69,500excess sulfur dioxide (SO2) emission allowances (out of a total ofapproximately 107,000 excess allowances) on the open market for approximately$71 million.  Through February 28, 2006, IPChas sold an additional 7,500 emission allowances for approximately $10 millionand plans to continue selling surplus allowances as market conditions permit.  IPC is now seeking an order from the IPUC todetermine the accounting treatment for these transactions and the allocation ofproceeds between retail customers and shareholders. Under the approved interimaccounting treatment, IPC is recording the Idaho and Oregon allocated portionsof the proceeds (net of expenses) as a regulatory liability.  At this time, IPC cannot predict how theproceeds might ultimately be allocated.

**Shareholder Lawsuits:**In connection with the shareholder lawsuits filed against IDACORP and four ofits officers and directors in 2004, on September 14, 2005, Magistrate JudgeMikel H. Williams of the U.S. District Court for the District of Idaho issued aReport and Recommendation that the defendants' motion to dismiss be granted andthat the case be dismissed.  TheMagistrate Judge determined that the plaintiffs did not satisfactorily pleadloss causation (i.e., a causal connection between the alleged materialmisrepresentation and the loss) in conformance with the standards set forth inthe recent United States Supreme Court decision of Dura Pharmaceuticals, Inc.v. Broudo, 544 U.S._____, 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.  The parties have eachfiled objections to different parts of the Magistrate Judge's Report andRecommendation, and the matter is now before the District Judge.

**Capital Requirements and Cash Flows:** IPC estimates that it will spend $720 million on constructionexpenditures over the next three years.  This amount reflects the need for additional resources inorder for IPC to supply power to its growing number of customers.

Forecastsindicate that internal cash generation after dividends will provide less thanthe full amount of total capital requirements for 2006 through 2008.  IDACORP and IPC expect to continue financingthe utility construction program and other capital requirements with internallygenerated funds and continued reliance on externally financed capital.

Thecontribution for internal cash generation is dependent primarily upon IPC'scash flows from operations, which are subject to risks and uncertaintiesrelating to weather and water conditions and IPC's ability to obtain raterelief to cover its operating costs.

**Idaho Water Management Issues: **Six years of below normal waterconditions have exacerbated a developing water shortage in the state of Idaho,which is manifested by a number of water issues including declining Snake Riverbase flows and declining levels in the Eastern Snake Plain Aquifer.  These issues are of interest to IPC becauseof their potential impacts on generation at IPC's hydroelectric projects.  As a result of declines in river flows, in2003 several surface water users filed delivery calls with the Idaho Departmentof Water Resources, demanding that it manage ground water withdrawals pursuantto the prior appropriation doctrine of "first in time is first in right"and curtail junior ground water rights that are depleting the aquifer andaffecting flows to senior surface water rights. These delivery calls have resulted in the several administrative actionsbefore the Idaho Department of Water Resources and judicial actions before theState District Court in Ada and Gooding Counties in Idaho challenging theconstitutionality of state regulations used by the Department to conjunctivelyadminister ground and surface water rights. IPC is participating in several of these actions to protect itsinterests and encourage the development of a long-term management plan thatwill protect the aquifer from further depletion.

Onemanagement option being explored is aquifer recharge, or using surface watersupplies to increase ground water supplies by allowing the water to percolateinto the aquifer in porous locations. Under certain circumstances aquifer recharge may impact senior waterrights, including water rights held by IPC for hydropower purposes, andtherefore conflict with state law.  Forthat reason, IPC continues to participate in the processes that are consideringsolutions, such as aquifer recharge, to the conflict between ground and surfacewater interests in an effort to protect its existing hydroelectric generationwater rights.  In February 2006, at therequest of senior surface water interests, IPC entered into discussions withthe State of Idaho and senior surface water interests to explore opportunitiesfor engaging in some limited aquifer recharge in 2006, provided any adverseimpact to IPC's hydropower generation and its customers is adequatelyaddressed.  These discussions continueand are expected to reach conclusion by mid-March or early April 2006.

**Relicensing:**  IPC's mostsignificant ongoing relicensing effort is the Hells Canyon Complex, whichprovides approximately two-thirds of IPC's hydroelectric generating capacityand approximately 40 percent of its total generating capacity.  Over the past year, IPC has participated innegotiations with a number of interested parties in an attempt to develop acomprehensive agreement for relicensing the Hells Canyon Complex.  To date, however, the parties have not beensuccessful in reaching an agreement. Because it was unlikely that the parties to the settlement process wouldreach an agreement on a comprehensive settlement package in the near term andwith the issuance of the Notice of Ready for Environmental Analysis (NREA) bythe FERC in October 2005, the settlement discussions were terminated to allowthe parties the opportunity to develop comments and preliminary terms andconditions for filing with the FERC.  Theparties expect to reassess opportunities for settlement in the spring of 2006after the filings with the FERC.

**EnergyPolicy Act of 2005:**  On August 8, 2005, the President signed intolaw the Energy Policy Act of 2005 (Energy Act), which is a comprehensive energybill affecting the regulation of energy companies, including IPC.  Key provisions of the Energy Act that mayaffect IPC include:

Creation of an electric reliability organization that theFERC will appoint and oversee to establish and enforce mandatory reliabilityrules regarding the interstate electric transmission system;

Requirements for the FERC to establish incentive-basedtransmission rate policies;

FERC backstop authority for transmission line siting incorridors of national interest;

Changes in authority over regional transmissionorganizations;

Amendments to PURPA, prospectively terminating mandatorypurchase and sale requirements when a qualifying facility has access to competitivemarkets and eliminating the prohibition against utility ownership of qualifyingfacilities;

Reform of the hydroelectric licensing process to providetrial-type hearings for disputed facts regarding license conditions, to createa process for licensees to propose alternatives to prescribed conditions and torequire prescribing authorities to balance competing interests;

Incentives to develop additional generation at existinghydroelectric dams;

Creation of significant tax incentives to encourage andpromote electricity reliability, renewable and clean energy investment andclean coal, and other energy efficiency and conservation; and

Repeal ofthe 1935 Act and amendments to the Federal Power Act (FPA), effective February8, 2006, giving the FERC (i) increased authority over mergers involving publicutilities and the acquisition of the securities of electric utility companiesand holding companies, (ii) authority to protect public utilities from crosssubsidization and the encumbrance of utility assets, (iii) authority to setcost allocation methods for affiliate transactions involving public utilities,and (iv) providing the FERC and state commissions increased access to the booksand records of holding company systems.

 

Implementationof the Energy Act requires the development of regulations by the FERC, theDepartment of Energy and other federal agencies as well as proceedings at thestate level.  The FERC has adoptednumerous new rules and regulations, including new rules relating to utilityacquisitions and dispositions, books and records access, electric utilityreliability and reliability organizations, and procedures for determiningconditions or proscriptions on hydropower licenses.  The FERC also has issued proposed rules thatare still undergoing review and comment.

IDACORP and IPC are currently monitoring the Energy Act'simplementation to determine its effects on the companies.

**CRITICALACCOUNTING POLICIES AND ESTIMATES:**

IDACORP'sand IPC's discussion and analysis of their financial condition and results ofoperations are based upon their consolidated financial statements, which havebeen prepared in accordance with accounting principles generally accepted inthe United States of America (GAAP).  Thepreparation 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 these estimates, including those related to rateregulation, benefit costs, contingencies, litigation, impairment of assets,income taxes, unbilled revenues and 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 othersources.  IDACORP and IPC, based on theirongoing reviews, will make adjustments when facts and circumstances dictate.

IDACORPand IPC believe the following critical accounting policies are important to theportrayal of their financial condition and results of operations and requiremanagement's most difficult, subjective or complex judgments, often as a resultof the need to make estimates about the effect of matters that are inherentlyuncertain.

**Accountingfor Rate Regulation**A regulatedcompany must satisfy the following conditions in order to apply the accountingpolicies and practices of Statement of Financial Accounting Standards (SFAS)71, "Accounting for the Effects of Certain Types of Regulation;" anindependent regulator must set rates; the regulator must set the rates to coverspecific costs of delivering service; and the service territory must lackcompetitive pressures to reduce rates below the rates set by theregulator.  SFAS 71 requires companiesthat meet 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 asregulatory liabilities and amortized to the income statement as rates tocustomers are reduced.

IPCfollows SFAS 71, and its financial statements reflect the effects of thedifferent rate making principles followed by the jurisdictions regulatingIPC.  The primary effect of this policyis that IPC has recorded $418 million of regulatory assets and $345 million ofregulatory liabilities at December 31, 2005. While IPC expects to fully recover these regulatory assets and returnthese regulatory liabilities, such recovery is subject to final review by theregulatory entities.

If IPCshould determine in the future that it no longer meets the criteria forcontinued application of SFAS 71, it would be required to write off itsregulatory assets and liabilities unless regulators specify some other means ofrecovery or refund.  IPC intends to seekrecovery of all of its prudent costs, including stranded costs, in the event ofderegulation.  However, due to thecurrent lack of definitive legislation, IPC cannot predict whether recoverywould be successful.  If IPC has to writeoff a material amount of the regulatory assets, it will have a material adverseeffect on IPC's results of operations and financial position.

**PensionExpense**IPC maintains aqualified defined benefit pension plan covering most employees and an unfundednonqualified deferred compensation plan for certain senior management employeesand directors.

IDACORP'sand IPC's recorded pension expense for these plans is dependent on a number offactors, including the provisions of the plans, changing employee demographics,actual returns on plan assets and several actuarial assumptions used in thevaluations upon which pension expense is based. The key actuarial assumptions that affect expense are the long-termreturn on plan assets and the discount rate used in determining future benefitobligations.  Management reviews theseassumptions on an annual basis, taking into account changes in marketconditions, trends and future expectations. Estimates of future stock market performance, changes in interest ratesand other factors used to develop these assumptions are extremely uncertain,and actual results could vary significantly from the estimates.

The assumed discount rate is based on reviews of marketyields on high-quality corporate debt. Specifically, IDACORP and IPC utilize data published in the CitigroupPension Liability Index and apply the rates therein against the projected cashoutflows of the plans.  The discount rateused to calculate the 2006 pension expense will be reduced to 5.60 percent fromthe 5.75 percent used in 2005.

Rate-of-return projections for plan assets are based onhistorical risk/return relationships among asset classes.  The primary measure is the historical riskpremium each asset class has delivered versus the return on 10-year US TreasuryNotes.  This historical risk premium isthen added to the current yield on 10-year US Treasury Notes, and the resultprovides a reasonable prediction of future investment performance.  Additional analysis is performed to measurethe expected range of returns, as well as worst-case and best-casescenarios.  Based on the current lowinterest rate environment, current rate-of-return expectations are lower thanthe nominal returns generated over the past 20 years when interest rates weregenerally much higher.

Pensionexpense for these plans totaled $10 million, $10 million, and $12 million forthe three years ended December 31, 2005, 2004 and 2003, respectively, includingamounts allocated to capitalized labor costs. For 2006, pension expense is expected to total approximately $12 million,which takes into account the reduction of the discount rate noted above.  No changes were made to the other keyassumptions used in the actuarial calculation.

Had different actuarial assumptions been used, pensionexpense could have varied significantly. The following table reflects the sensitivities associated with changesin certain actuarial assumptions on historical and future pension expense: 

** **

**Discount rate**

**Rate of return**

** **

**2006**

**2005**

**2006**

**2005**

** **

**(millions of dollars)**

Effect of 0.5% increase

$

(1.7)

$

(1.2)

$

(1.8)

$

(1.7)

Effect of 0.5% decrease

 

3.8 

 

2.7 

 

1.8 

 

1.7 

 

 

 

 

 

 

 

 

 

 

No cashcontributions were made to the qualified plan in 2003 through 2005, and noneare expected in 2006.  Under thenon-qualified plan, IPC makes payments directly to participants in theplan.  Payments averaged approximately $2.5million per year from 2003 to 2005, and a similar amount is anticipated in2006.

Please refer to Note 10 of IDACORP's and IPC's ConsolidatedFinancial Statements, which contains additional information about pensionexpense, including results of the actuarial valuations, actuarial assumptionsused to measure pension expense and information about plan assets.

**Contingent Liabilities**There are anumber of unresolved issues related to regulatory, legal and tax matters.  Contingent liabilities are provided for inaccordance with SFAS 5, "Accounting for Contingencies."  According to SFAS 5, an estimated loss from aloss contingency is charged to income if (a) it is probable that an asset hadbeen impaired or a liability had been incurred at the date of the financialstatements and (b) the amount of the loss 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.  Gain contingencies are not recorded untilrealized.

The companies have made estimates of the ultimateresolution of all such matters, based on the facts and circumstances, opinionsof legal counsel and other factors.  Ifthe recognition criteria of SFAS 5 have been met, liabilities have beenrecorded.  Estimates of this nature arehighly subjective, and the final outcome of these matters could varysignificantly from the amounts that have been included in the financialstatements.

**Asset Impairment**IDACORP hasseveral assets that are evaluated for impairment in accordance with generallyaccepted accounting principles.  Thoseassets that were evaluated in 2005 include the following:

**Goodwill:** At December 31, 2005, IDACORP had $3 millionof goodwill related to its investments in IdaTech.  In 2005, IDACORP recorded an impairment ofthe entire $10 million goodwill balance related to its investment in IDACOMM.

IDACORP follows the impairment testing provisions of SFAS142, "Goodwill and Other Intangible Assets."  In accordance with SFAS 142, goodwill istested for impairment at least annually, and more frequently when events occuror circumstances change that more likely than not would reduce the fair valueof a reporting unit below its carrying amount. SFAS 142 requires that if the fair value of a reporting unit is lessthan its carrying value including goodwill, the implied fair value of the reportingunit goodwill must be compared with its carrying value to determine the amountof the impairment.

IDACORP's annual impairment tests were conducted as ofJune 30, and at that time no impairment was noted.  The strategic decision made in December 2005to exit one of IDACOMM's lines of business, BPL, triggered the requirement toconduct another impairment test.  Basedon the results of that test, IDACOMM's goodwill balance was impaired.

The fair value calculations used for these tests requireIDACORP to make assumptions about items that are inherently uncertain.  Assumptions related to future market demand,market prices and product costs could vary from actual results, and the impactof such variations could be material. Factors that could affect the assumptions include changes in economic conditions,success in developing marketable products and services and competitiveconditions in the telecommunications and fuel cell industries.

**Long-lived Assets:** Long-lived assets are periodically reviewed forimpairment when events or changes in circumstances indicate that the carryingamount of an asset may not be recoverable as prescribed under SFAS 144,"Accounting for the Impairment or Disposal of Long-Lived Assets."  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.

**Southwest Intertie Project:** IPC began developing theSouthwest Intertie Project (SWIP) in 1988. IPC's investment consists predominantly of a federal permit for aspecific transmission corridor in Nevada and Idaho and also privaterights-of-way in Idaho.  The SWIPrights-of-way extend from Midpoint substation in south-central Idaho througheastern Nevada to the Dry Lake area northeast of Las Vegas, Nevada.  In 2004 the Bureau of Land Management granteda five-year extension to begin construction of a proposed 500kV transmissionline within the rights-of-way before December 2009.  On March 31, 2005 IPC entered into anagreement with White Pine Energy Associates, LLC (White Pine), an affiliate ofLS Power Development, LLC, which provides White Pine a three-year exclusiveoption to purchase the SWIP rights-of-way from IPC.  The option may be exercised in part or as awhole and, if fully exercised, will result in a net pre-tax gain to IPC ofapproximately $6 million.  Based onmanagement expectations regarding SWIP, no impairment has been identified.

**Investments:**IFS has affordablehousing and other investments with a net book value of $100 million at December31, 2005, and Ida-West has investments in four joint ventures that own electricpower generation facilities.  Except fortwo investments now consolidated under the provisions of Financial AccountingStandards Board (FASB) Interpretation (FIN) 46R, "Consolidation ofVariable Interest Entities - an interpretation of ARB No. 51," theseinvestments are accounted for under the equity method of accounting asdescribed in Accounting Principles Board Opinion No. (APB) 18, "The EquityMethod of Accounting for Investments in Common Stock."  The standard for determining whetherimpairment must be recorded under APB 18 is whether the investment hasexperienced a loss in value that is considered an other-than-temporary declinein value.

Prior to the decision todiscontinue Ida-West's project development activities, Ida-West had the intentand ability to hold the investments for a period sufficient to recover therecorded value.  Based upon the change inmanagement's intent, these investments were tested for impairment, and two ofthe investments were determined to be impaired, resulting in a write down of $2million in 2003.  The impairment amountsare based on the estimated fair value of the investments.  Impairment tests on these investments wereperformed in 2005 and no impairment was noted.

These estimates requiredIDACORP to make assumptions about future stream flows, revenues, cash flows andother items that are inherently uncertain. Actual results could vary significantly from the assumptions used, andthe impact of such variations could be material.

**Unbilled Revenue******IPC's retailrevenues include an estimate of MWhs delivered but unbilled at the end of eachperiod.  Unbilled revenues are dependentupon a number of factors that require management's judgment.  Unbilled revenue is calculated by takingdaily estimates of MWhs delivered and applying information from themeter-reading schedule to estimate the portion of MWhs delivered that have notbeen billed.  These unbilled MWhs arethen allocated to the retail customer classes based on estimated usage by eachclass.  IPC then records revenue for eachcustomer class based on their respective rates. Due to the seasonal fluctuations of IPC's actual load, the amount of unbilledrevenue increases during the summer and winter months and decreases during thespring and fall.

**RESULTS OF OPERATIONS:**

This section of the MD&Atakes a closer look at the significant factors that affected IDACORP's andIPC's earnings over the last three years. In this analysis, the results of 2005 are compared to 2004 and theresults of 2004 are compared to 2003.

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

** **

**2005**

** **

**2004**

** **

**2003**

IPC - Utility operations

$

71,839 

 

$

65,785 

 

$

55,161 

IDACORP Financial Services

 

10,911 

 

 

13,313 

 

 

10,404 

IDACOMM

 

(12,988)

 

 

(1,990)

 

 

(1,794)

ITI

 

(9,067)

 

 

(5,808)

 

 

(1,360)

IDACORP Energy

 

4,881 

 

 

2,162 

 

 

(9,563)

Ida-West Energy

 

2,381 

 

 

3,089 

 

 

(4,995)

Holding company expenses

 

(4,296)

 

 

(3,568)

 

 

(1,275)

 

Total Earnings

$

63,661 

 

$

72,983 

 

$

46,578 

 

Average outstanding shares (000s)

 

42,279 

 

 

38,361 

 

 

38,228 

Earnings per diluted share

$

1.50 

 

$

1.90 

 

$

1.22 

 

**Utility Operations****Operating environment: **IPC is oneof the nation's few investor-owned utilities with a predominantly hydroelectricgenerating base.  Because of its relianceon hydroelectric generation, IPC's generation operations can be significantlyaffected by weather conditions.  Theavailability of hydroelectric power depends on the amount of snow pack in themountains upstream of IPC's hydroelectric facilities, springtime snow packrun-off, rainfall and other weather and stream flow managementconsiderations.  During low water years,when stream flows into IPC's hydroelectric projects are reduced, IPC'shydroelectric 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, an increased use of purchased power to meet loadrequirements.  Both of these situations -a reduction in profitable off-system sales and an increased use of moreexpensive purchased power - result in increased power supply costs.

On a frequent basis, anoperations plan is developed to provide guidance for generation resourceutilization and energy market activities (off-system sales and powerpurchases).  The plan incorporatesforecasts for generation unit availability, reservoir storage and stream flows,gas and coal prices, customer loads, energy market prices and other pertinentinputs.  Consideration is given to whento use IPC's available resources to meet forecast loads and when to transact inthe energy market.  The allocation ofhydroelectric generation between heavy load and light load hours or variouscalendar periods is considered in development of the operating plan.  This allocation is intended to utilize theflexibility of the hydroelectric system to shift generation to high valueperiods, while operating within the constraints imposed on the system.  IPC's energy risk management policy, unitoperating requirements and other obligations provide the framework for theplan.

In2005, IPC experienced its sixth consecutive year of below normal hydroelectricgenerating conditions.  The NationalWeather Service Northwest River Forecast Center reports that April through Julyinflow to Brownlee Reservoir for 2005 totaled 3.6 million acre-feet (maf),which is 57 percent of average.  Theannual Brownlee inflow for 2005 was 8.9 maf, which the River Forecast Centerreports is 70 percent of average. However, the forecast released on February 28, 2006, by the NorthwestRiver Forecast Center indicates that Brownlee inflow for April through July2006 is expected to total 6.7 maf, or 106 percent of average.  Snow pack accumulation for the Snake RiverBasin was 117 percent of average on February 28, 2006.  Storage in selected federal reservoirsupstream of Brownlee as of February 21, 2006 was 105 percent of average, upfrom 60 percent of average at the end of December 2004.  October 1, 2005 storage in these reservoirs,which is considered carryover storage into water year 2006, was 85 percent ofaverage, up from 45 percent of average on October 1, 2004.  With approximately one month remaining in thetypical snow accumulation period for 2006, conditions have improved from lastyear.

IPC'ssystem load peaks in the summer and winter, with the larger peak demandoccurring in the summer.  IPC's recordsystem peak of 2,963 MW occurred on July 12, 2002.  Peak summer demand in 2005 was 2,961 MW onJuly 22, and peak winter demand for the year was 2,345 MW on December 15.  IPC was able to meet system load requirementsand off-system sales requirements and had sufficient 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**

2005

6,199

7,315

13,514

3,894

17,408

2004

6,041

7,303

13,344

4,274

17,618

2003

6,149

6,914

13,063

3,383

16,446

 

IPC'smedian annual hydroelectric generation is 8.5 million MWh, based on medianhydrologic conditions for the standardized period of record, 1928 through 2004.

**GeneralBusiness Revenue:**  The primary influences on electricity salesare weather, customer growth and economic conditions.  Extreme temperatures increase sales tocustomers who use electricity for cooling and heating, and moderatetemperatures decrease sales. Precipitation levels during the growing season affect sales to customerswho use electricity to operate irrigation pumps.  Increased precipitation reduces electricityusage by these customers.

Thefollowing table presents IPC's general business revenues, MWh sales and averagecustomers, and Boise, Idaho weather conditions for the three years:

 

 

**2005**

** **

**2004**

** **

**2003**

Revenue

 

 

 

 

 

 

 

 

 

 

Residential

 

$

299,488

 

$

274,313

 

$

275,920

 

Commercial

 

 

173,268

 

 

164,053

 

 

173,820

 

Industrial

 

 

118,259

 

 

111,797

 

 

128,620

 

Irrigation

 

 

76,255

 

 

85,672

 

 

92,609

 

 

Total

 

$

667,270

 

$

635,835

 

$

670,969

 

 

 

 

 

 

 

 

 

 

MWh

 

 

 

 

 

 

 

 

 

 

Residential

 

 

4,760

 

 

4,580

 

 

4,427

 

Commercial

 

 

3,639

 

 

3,561

 

 

3,511

 

Industrial

 

 

3,423

 

 

3,335

 

 

3,206

 

Irrigation

 

 

1,467

 

 

1,763

 

 

1,836

 

 

Total

 

 

13,289

 

 

13,239

 

 

12,980

 

 

 

 

 

 

 

 

 

 

Customers  (average)

 

 

 

 

 

 

 

 

 

 

Residential

 

 

373,602

 

 

360,462

 

 

349,219

 

Commercial

 

 

57,146

 

 

55,577

 

 

54,194

 

Industrial

 

 

129

 

 

120

 

 

115

 

Irrigation

 

 

17,942

 

 

17,306

 

 

16,911

 

 

Total

 

 

448,819

 

 

433,465

 

 

420,439

 

 

 

 

 

 

 

 

 

 

Heating degree-days

 

 

5,437

 

 

5,249

 

 

4,906

Cooling degree-days

 

 

965

 

 

998

 

 

1,305

Precipitation

 

 

13.6"

 

 

11.6"

 

 

10.1"

 

 

 

 

 

 

 

 

 

 

 

Heatingand cooling degree-days are a common measure used in the utility industry toanalyze the demand for electricity and indicate when a customer would useelectricity for heating and air conditioning. A degree-day measures how much the average daily temperature varies from65 degrees.  Each degree of temperatureabove 65 degrees is counted as one cooling degree day, and each degree oftemperature below 65 degrees is counted as one heating degree-day.  Normal heating-degree-days and cooling degreedays are 5,727 and 807, respectively.

2005 vs. 2004:

**Rates:**  Increased average rates resulting from higherbase rates that took effect on June 1 in both 2005 and 2004 increased revenues$31 million.  This was partially offsetby a net reduction in the power cost adjustment rates, which reduced revenue $3million from 2004.  Approximately $16million of the rate increase represents collection of previously recordedrevenues from the irrigation load reduction program and rate case taxsettlement.  This revenue is offset by acorresponding reduction to other revenues for the same amount.

**Customers**: A 3.5 percent increase in average general business customers increasedrevenue $27 million, as IPC continued to experience strong customer growth inits service territory.  IPC added over16,000 general business customers during the year; and

**Usage**: Heavy spring precipitation reduced sales to irrigation customers by $17million.  Rainfall during the secondquarter of 2005 was double that of 2004. Other weather and usage factors reduced sales to othercustomers by $6 million.

 

2004 vs. 2003:

**Rates:** Lower average rates, resulting from the PCA, decreased general businessrevenue $40 million.  The decrease in PCArevenues was approximately $68 million. This was partially offset by a $28 million increase due to new baserates beginning on June 1, 2004.  Therate changes were the result of several rate proceedings discussed in moredetail below in "REGULATORY ISSUES;"

**Customers**: An increase in general business customers improved revenue $19 millionduring 2004.  IPC added nearly 14,000general business customers during the year, a 3.2 percent average increase;

**Contract Expiration**: The expiration in March 2003 of a take-or-pay contract with FMC/Astariscaused a $9 million decrease in revenues for 2004.  FMC/Astaris, formerly IPC's largest volumecustomer, closed its plants late in 2001 but was required under the contract topay IPC for generation capacity regardless of delivery; and

**Usage:** Revenues decreased approximately $6 millionduring 2004 mainly due to cooler summer weather.  Cooling degree-days for 2004 were 24 percentless than 2003, which had unusually hot summer temperatures.

**Off-systemsales:**Off-system sales consist primarily of long-term sales contracts and opportunitysales of surplus system energy.

** **

**2005**

** **

**2004**

** **

**2003**

 

 

 

 

 

 

 

 

 

Revenue

$

142,794

 

$

121,148

 

$

71,573

MWh  sold

 

2,774

 

 

2,885

 

 

1,830

Revenue  per MWh

$

51.48

 

$

41.99

 

$

39.11

 

 

 

 

 

 

 

 

 

** **

2005 vs. 2004:  Revenues grew 18 percent due to higher energyprices in 2005.  Market prices werehigher and more volatile because of oil and gas price increases due toinstability in the Middle East and hurricane damage on the Gulf Coast.  For the Northwest, continuation of droughtconditions in the region compounded the impact of these global problems.  Consequently, off-system sales revenue on aper MWh basis increased 23 percent for the year.  Off-system sales volumes declined fourpercent, due primarily to changes in operating conditions and load and streamflow timing, which reduced market sales opportunities.

2004 vs. 2003:  Revenues from off-system sales in 2004 grewsignificantly over 2003 due mainly to increased volumes sold.  The increased volumes sold were largely aresult of power supply hedge activity in late spring based on temporarilyimproved hydroelectric generation. Although overall hydroelectric generating conditions were below normal,May 2004 precipitation was above normal and reservoir storage space waslimited.  Consequently, IPC generatedmore hydroelectric power than previously planned for May and June 2004.  Earlier hedge purchase activity combined withincreased hydroelectric generation resulted in surplus energy.

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

** **

**2005**

** **

**2004**

** **

**2003**

Transmission services and property rental

$

39,012 

 

$

39,839

 

$

37,840

BPA credit

 

- 

 

 

4,000

 

 

-

Rate case tax settlement

 

(2,892)

 

 

7,100

 

 

-

Irrigation lost revenues

 

(8,501)

 

 

11,587

 

 

-

 

Total

$

27,619 

 

$

62,526

 

$

37,840

 

 

 

 

 

 

 

 

 

 

2005 vs. 2004:  Other revenuesdecreased $35 million due mainly to the following:

In December 2004, IPC recordedapproximately $12 million related to the recovery of lost revenue resultingfrom IPC's Irrigation Load Reduction Program. The recovery was included as part of IPC's annual PCA beginning on June1, 2005, and $9 million has been amortized as the amounts are billed.  This matter is discussed further in"REGULATORY ISSUES - Deferred Power Supply Costs - Idaho;"

In 2004, IPC recognizedapproximately $7 million of revenue due to the IPUC order approving SettlementNo. 1, which relates to the calculation of IPC's taxes for purposes of testyear income tax expense in the 2003 Idaho general rate case.  As a result of this settlement, IPC recordeda regulatory asset of approximately $12 million from June 1, 2004 through May31, 2005 ($7 million in 2004 and $5 million in 2005).  IPC began collecting this amount beginning inJune 2005 with an adjustment to rates and $8 million has been amortized as the amountsare billed; and

In July 2004, IPC recognized $4million of revenue from an agreement with the Bonneville Power Administrationfor the release of 100,000 acre-feet of storage water from BrownleeReservoir.  This amount was included inthe June 1, 2005 PCA resulting in a benefit to IPC's Idaho customers.

 

2004 vs. 2003:  Other revenuesincreased $25 million over 2003 due mainly to the same factors discussed above.

**Purchased power:**

** **

**2005**

** **

**2004**

** **

**2003**

Purchased  power:

 

 

 

 

 

 

 

 

 

Purchases

$

222,310

 

$

195,642

 

$

147,850

 

Load  reduction costs

$

-

 

$

-

 

$

3,130

 

 

 

 

 

 

 

 

 

MWh  purchased

 

3,894

 

 

4,274

 

 

3,383

Cost  per MWh purchased

$

57.09

 

$

45.77

 

$

43.70

 

 

 

 

 

 

 

 

 

** **

2005 vs. 2004:Purchased power expense grew 14 percent due to higher energy prices in2005.  Market prices were higher and morevolatile for the reasons discussed above. Purchased power expense on a per MWh basis increased 25 percent for theyear.  Purchased power volumes declinednine percent.  Different operatingconditions and system load and stream flow timing led to reduced marketpurchase activities.

2004 vs. 2003:  The 2004 increase in purchased power expense wasmostly due to a 26 percent increase in volumes purchased.  The increased volumes purchased were a resultof power supply hedge activity based on expectations of reduced hydroelectricgeneration due to continued below normal water conditions.  Load reduction costs decreased from $3million in 2003 to zero due to the expiration in March 2003 of the FMC/AstarisVoluntary Load Reduction Program.

**Fuel expense:**  The following table presents IPC's fuelexpenses and generation at its thermal generating plants:

 

**2005**

** **

**2004**

** **

**2003**

Fuel  expense

$

103,164

 

$

103,261

 

$

99,898

Thermal  MWh generated

 

7,315

 

 

7,303

 

 

6,914

Cost  per MWh

$

14.10

 

$

14.14

 

$

14.45

 

 

 

 

 

 

 

 

 

** **

2005 vs. 2004:  Fuel expenses and thermal plantvolumes were essentially unchanged in 2005.

2004 vs. 2003:  Fuel expenses increased in 2004 mainlydue to a six percent rise in generation. The increase in generation resulted from a return to normal operationsat Valmy, which produced 23 percent more in 2004 than in 2003.  This increase was partially offset by a 17percent reduction in generation from the Boardman plant, which was offline fora longer period in 2004 in order to perform an upgrade to theturbine-generator.

**PCA:**  PCA expense represents theeffect of IPC's PCA regulatory mechanism, which is discussed in more detailbelow in "REGULATORY ISSUES - Deferred Power Supply Costs -Idaho."  In 2005, 2004 and 2003,actual net power supply costs, which are fuel and purchased power lessoff-system sales, exceeded those anticipated in the annual PCA forecast,resulting in the deferral of a portion of those costs to subsequent years whenthey are to be recovered in rates.  Asthe revenues are being recovered, the deferred balances are amortized.

The following table presents the components of PCAexpense:

** **

**2005**

** **

**2004**

** **

**2003**

Current year net power supply cost deferral

$

(30,786)

 

$

(29,306)

 

$

(44,320)

FMC/Astaris and irrigation program cost deferral

 

- 

 

 

- 

 

 

(2,245)

Amortization of prior year authorized balances

 

27,791 

 

 

49,190 

 

 

117,279 

Write-offs of disallowed costs

 

- 

 

 

- 

 

 

48 

Settlement agreement

 

- 

 

 

19,300 

 

 

- 

 

Total power cost adjustment

$

(2,995)

$

 

39,184 

 

$

70,762 

 

 

 

 

 

 

 

 

 

**Other Operations and Maintenance Expenses:**2005 vs. 2004: Other operations and maintenance expenses decreased $15 million duemainly to the 2004 write-off of $9 million related to disallowed items in theIdaho general rate case.

2004 vs. 2003:  Other operationsand maintenance expenses increased $35 million due mainly to the following:

An increase in payroll expense of$13 million for an employee incentive program, which was partially triggered bythe settlement relating to the irrigation load reduction program;

A write-off of $9 million relatedto disallowed items in the Idaho general rate case; and

Increases in transmission expenseof $4 million primarily due to the increase in purchased power.

 

**Non-utilityOperations**

**IFS**IFS earned $11 million, $13 million, and $10 million in 2005, 2004 and 2003,respectively, principally from the generation of federal income tax credits andaccelerated tax depreciation benefits. The 2004 results included a gain on the sale of its investment in the ElCortez Hotel in San Diego, California. In June 2000, IFS invested $4 million to assist in the renovation of thehistoric El Cortez into upscale apartment units.  Upon exiting the investment on April 22,2004, IFS recognized a gain on the sale of $5 million, income taxes of $3million and a net gain of $2 million. The gain is included in other income on IDACORP's ConsolidatedStatements of Income.

IFS generates federal income tax credits and acceleratedtax depreciation benefits related to its investments in affordable housing andhistoric rehabilitation developments. IFS made $5 million in new investments during 2005 and generated taxcredits of $20 million, $22 million and $20 million during 2005, 2004 and 2003,respectively.  IFS expects to continuedelivering tax benefits at a level commensurate with the ongoing needs ofIDACORP.

**ITI**ITI recorded netlosses of $9 million, $6 million and $1 million in 2005, 2004 and 2003,respectively.  The increase in losses in2005 results from a $3 million reduction in sales of products in development,and a $2 million increase in product development costs, partially offset by a$1.5 million decrease in related income tax expense.  The loss in 2004 exceeded the loss in 2003because of a $2 million decline in sales and a $6 million increase in costs,partially offset by a $3 million decrease in related income tax expenses.

**IDACOMM**IDACOMM recordednet losses of $13 million, $2 million and $2 million in 2005, 2004 and 2003,respectively.  In the fourth quarter of2005, IDACOMM recorded a $10 million goodwill impairment, which resultedprincipally from a revision to the company's business strategy and decision tophase out the portion of the business previously dedicated to exploring thepotential use of BPL technology.

**Energy Marketing**IE recorded netincome (loss) of $5 million, $2 million and ($9) million in 2005, 2004 and2003, respectively.

In 2003,IE wound down its power marketing operations, closed its business locations andsold its forward book of electricity trading contracts to Sempra EnergyTrading.  Since that time, IE has had nooperations but has been working to settle outstanding legal actions surroundingtransactions in the California energy markets in 2000 and 2001.  These matters, including a pending settlementagreement filed with the FERC for approval in February 2006, are discussed in"Legal Matters."

Netincome increased from $2 million in 2004 to $5 million in 2005, due primarilyto a $9.5 million adjustment to an allowance for uncollectible accountsrecorded in the fourth quarter of 2005. This adjustment was based on management's assessment of the negotiationsto settle the aforementioned California refund proceedings.  If the settlement agreement is approved bythe FERC, IE's required reserve may be further reduced.

The major transaction affecting results in2004 was $5 million of gains on settlements of legal disputes.

IE's 2003 results included a $17 million gain from thesale of its forward book of electricity trading contracts in August 2003.  This gain was offset by a loss on legaldisputes of $12 million, legal expenses of $6 million, acceleration of depreciationexpense of $6 million, restructuring expenses of $5 million and general andadministrative costs of $6 million.  OnDecember 29, 2003, IE received a $45 million cash payment from Overton PowerDistrict No. 5 for final settlement of a disputed receivable.  IE had a $46.1 million long-term receivable fromOverton, and this payment resulted in a $1.1 million expense to IE in December2003.  In addition, IE recorded awrite-down of $21.5 million related to this receivable in the second quarter of2003.  These write-downs are included in otheroperating expenses on IDACORP's Consolidated Statement of Income.

As part of the sale of the forward book of electricitytrading contracts, IE entered into an Indemnity Agreement with Sempra EnergyTrading guaranteeing the performance of one of the counterparties.  The maximum amount payable by IE under theIndemnity Agreement is $20 million.  In2005, under the terms of the guarantee, IE made $10 million in margindeposits.  IE expects this amount to berefunded no later than the end of the guarantee in 2009.  The Indemnity Agreement has been accountedfor in accordance with FIN 45, "Guarantor's Accounting and DisclosureRequirements for Guarantees, Including Indirect Guarantees of Indebtedness ofOthers" and did not have a material effect on IDACORP's financialstatements.

See Note 15 of IDACORP's and IPC's Consolidated FinancialStatements for information related to restructuring costs of IE.

**Ida-West**Ida-Westrecorded net income (loss) of $2 million, $3 million and ($5) million in 2005,2004 and 2003, respectively.

In 2003, Ida-West discontinued its project developmentoperations.  This decision resulted fromthe implementation of IDACORP's new corporate strategy.  This strategy does not include thedevelopment or acquisition of merchant generation, which was Ida-West'sfocus.  Ida-West continues to manage itsindependent power projects with a reduced workforce.  Impairment charges, asdiscussed below, negatively affected Ida-West's earnings in 2003.

**Garnet impairment**:  In 2001, Garnet, a wholly-owned subsidiary ofIda-West, entered into an agreement with IPC to provide energy to be producedby Garnet's proposed natural gas-fired plant. Due to changes in the electricity industry, financing of the project onacceptable terms under the agreement became impracticable, and in 2003, theagreement was mutually terminated.  Basedon the termination of the agreement and other factors including IDACORP'sdecision to discontinue Ida-West's project development operations, animpairment charge was recorded for the remaining $3.6 million investmentbalance in 2003.  This impairment ispresented on the Consolidated Statement of Income in other operating expenses.

**Joint ventures:** Basedon the change in corporate strategy, Ida-West's investments in four jointventures were evaluated for impairment in 2003. As a result, $2.4 million in impairment charges were recorded in thefourth quarter of 2003 to partially impair two of the joint ventures.  This impairment is presented on the ConsolidatedStatement of Income in other expense. There were no impairments identified for 2004 or 2005.

In addition, a $2.6 millionbad debt reserve was established in 2003 on a note receivable from a partner inone of the joint ventures.  The related expenseis presented on the Consolidated Statement of Income as other operatingexpenses.  No adjustments were made tothis reserve in 2004, but in 2005, the reserve was reduced by $0.7 millionbased on updated estimates of collectibility.

**Income TaxesStatus of Audit Proceedings: **In March 2005, the InternalRevenue Service (IRS) began its examination of IDACORP's 2001 through 2003 taxyears.  On October 24, 2005, the IdahoState Tax Commission also began its examination of the same tax years.  Management believes that an adequateprovision for income taxes and related interest charges has been made for theopen years 2001 and after.  The accruedamounts are classified as a current liability in taxes accrued.

With the exception of the capitalized overhead costmethod discussed below, management cannot predict with certainty whichfinancial accounts or tax adjustments will be chosen by the IRS forexamination.  IDACORP intends tovigorously defend its tax positions.  Itis possible that material differences in actual outcomes, costs and exposuresrelative to current estimates, or material changes in such estimates, couldhave a material adverse effect on IDACORP's and IPC's consolidated financialposition, results of operations, or cash flows.

In 2004, IDACORP completed settlement of all issuesrelated to the IRS's examination of its federal income tax returns for theyears 1998 through 2000.  Concurrently,IPC settled federal income tax deficiencies for the years 1999 and 2000 relatedto its partnership investment in the Bridger Coal Company.  Applicable state tax return amendments werecompleted in 2004 and settled. Finalization of these examinations resulted in deficiencies that wereless than previously accrued, enabling IDACORP to decrease income tax expenseby $2 million in 2004 and $9 million in 2003.

** **

**Capitalized Overhead Costs:** On August 2, 2005, the IRS and Treasury Department issued guidanceinterpreting the meaning of "routine and repetitive" for purposes ofthe simplified service cost and simplified production methods of the InternalRevenue Code section 263A uniform capitalization rules.  The guidance was issued in the form of arevenue ruling (Rev. Rul. 2005-53) and proposed and temporary regulations.  The regulations are effective for tax yearsending on or after August 2, 2005, and the revenue ruling applies for all prioropen years.  Both pieces of guidance takea more restrictive view of the definition of self-constructed assets producedby a taxpayer on a "routine and repetitive" basis than do the currenttreasury regulations.

Generally, section 263A requires the capitalization ofall direct costs and those indirect costs, known as "mixed servicecosts", which directly benefit or are incurred by reason of the productionof property by a taxpayer.  The treasuryregulations for section 263A provide several "safe-harbor" methodstaxpayers may adopt in order to comply with the statute.  The simplified service cost method is one ofthe methods available for the calculation of indirect overhead "mixedservice costs" cost capitalization. IPC changed to the simplified service cost method for both theself-construction of utility plant and production of electricity beginning withits 2001 federal income tax return.

For IPC, the simplified service cost method produces acurrent tax deduction for costs capitalized to electricity production that arecapitalized into fixed assets for financial accounting purposes.  Deferred income tax expense has not beenprovided for this deduction because the prescribed regulatory tax accountingtreatment does not allow for inclusion of such deferred tax expense in currentrates.  Rate regulated enterprises arerequired to recognize such adjustments as regulatory assets if it is probablethat such amounts will be recovered from customers in future rates.

For fiscal years 2002 through 2004, the simplifiedservice cost method decreased IPC's income tax expense by $60 million andresulted in cash refunds from federal and state tax authorities of $75million.  For years 2004 and prior opentax years, if IPC cannot satisfy the new guidance as currently drafted, IPCwould be required to use another method of uniform capitalization, which couldbe more or less favorable to IPC than the simplified service cost method.  A less favorable method could result in a onetime charge to earnings and reduced cash flow that could be partially offset bycarryover tax credits, accelerated tax depreciation, changes in tax regulationsand state regulatory recovery.

The temporary regulations are effective for IPC's 2005tax year and, as drafted, preclude IPC from using this method forself-constructed assets for 2005 and thereafter.  Accordingly, in the third quarter of 2005,IPC reversed its previously accrued 2005 tax deduction for capitalized overheadcosts for both financial reporting and estimated tax payment purposes.  IPC is evaluating alternatives for a newuniform capitalization method.

IPC is actively involved in pursuing resolution of thismatter and is working diligently with the IRS in the examination process.  At this time, IPC cannot predict the earningsor cash flow impacts that the revenue ruling, temporary regulations, oradditional action by the IRS in this matter may have on 2005 or prior taxyears.

**Regulatory Settlement**In 2004, IPC andthe IPUC finalized an income tax issue from IPC's 2003 Idaho general ratecase.  The issue concerned the regulatoryaccounting treatment for the capitalized overhead tax method IPC adopted in the2001 IDACORP federal income tax return. As a result of the settlement, a $16 million regulatory tax liabilitywas reversed, creating benefit in 2004.

**Tax Credits and Net Operating Loss Carryforwards**As of December 31, 2005, IDACORP had $21 million of generalbusiness credit carryforward for federal income tax purposes and $6 million ofIdaho investment tax credit carryforward. The general business credit carryforward period expires in 2025 and theIdaho investment tax credit expires from 2018 to 2019.  IDACOMM has a separate company net operatingloss carryforward of $4 million that expires from 2010 to 2021.  The deferred tax asset associated with thenet operating loss carryforward is fully offset by a $1.6 million valuationallowance recorded in 2005.

**Accounting for Uncertain Tax Positions**On July 14,2005, the FASB released an Exposure Draft for its proposed Interpretationclarifying accounting for uncertain tax positions in accordance with SFAS 109,"Accounting for Income Taxes." The proposed guidance addresses the recognition, measurement, classification,and disclosure issues related to the recording of financial statements benefitsfor income tax positions that have some degree of uncertainty.

InOctober the FASB announced that it has moved its projected issuance date of thefinal standard to the first quarter of 2006. The FASB met on this topic in November 2005 and January 2006.  The significant developments to come fromthose meetings were recommendations to lower the Interpretation's recognitionthreshold from "probable" to "more likely than not" and todelay the start date until the first annual period beginning after December 15,2006.  Management is unable to predictthe final action by the FASB, but is continuing to assess the provisions ofthis proposed Interpretation as well as the recent FASB deliberations.

**LIQUIDITY AND CAPITAL RESOURCES:**

**OperatingCash Flows**IDACORP's andIPC's operating cash flows for 2005 were $161 million and $166 million,respectively.  IDACORP's and IPC'soperating cash flows decreased $33 million and $32 million respectively, comparedto 2004.  The decreases were mainlyrelated to: (1) a $19 million reduction in distributions from the Bridger Coaljoint venture, as Bridger is retaining cash to fund increased capitalexpenditures for conversion to underground mining; and (2) timing of cashdisbursements made in 2005 for December 2004 payable balances, including $9million in employee incentive compensation paid during the first quarter of2005.

In 2005,net cash provided by operating activities was driven by IPC, where generalbusiness revenues and the costs to supply power to general business customershave the greatest impact on operating cash flows.  As IPC's service territory experienced belownormal water conditions, the company relied more on higher-cost thermalgeneration and wholesale power purchases to meet its energy needs.

IDACORP'sand IPC's operating cash flows for 2004 were $195 million and $198 million,respectively.  IDACORP's operating cash flows decreased $118 million in 2004 as a resultof reduced receipts from IPC's general business customers of $44 million and an$83 million decrease in net operating cash flows from IE.  In 2003, IE received $40 million from thesale of its forward book of electricity trading contracts and collected $45 millionon a note receivable from Overton Power District No. 5.  These decreases in 2004 were partially offsetby a $45 million reduction in income taxes paid.

**WorkingCapital**Changes inworking capital accounts from December 31, 2004 to December 31, 2005 include:

Other receivables at IDACORP increased $14 million dueprincipally to a $10 million margin deposit related to the sale of IE's energymarketing book to Sempra Energy Trading.

IDACORP's allowance for uncollectible accounts decreased$10 million due predominantly to an adjustment of IE's allowance related toreceivables from California entities.

IDACORP's energy marketing assets and liabilities bothincreased $15 million from changes in the mark-to-market values of IE's energymarketing contracts.

Taxes accrued increased $26 million at IDACORP and $31million at IPC, primarily due to income taxes due on the $70.8 million ofemission allowances sold in the fourth quarter of 2005.

 

Otherchanges in working capital are due predominantly to timing and normal businessactivity.

**EnvironmentalRegulation Costs: **IPC anticipates $18 million inannual operating costs for environmental facilities during 2006.  Hydroelectric facility expenses account for $12million of this total and $6 million is related to thermal plant operatingexpenses.  From 2007 through 2008, totalenvironmental related operating costs are estimated to be $35 million.  Anticipated expenses related to thehydroelectric facilities account for $23 million and thermal plant expenses areexpected to total $12 million during this period.

**PensionExpense and Contributions**Total pensionexpenses in 2005 were $10 million and pension plan contributions were $2million for the qualified and non-qualified plans.  Pension expense is expected to increase to$12 million in 2006.

**Dividend Reduction**In September2003, IDACORP's annual dividend was reduced to $1.20 per share from $1.86 pershare.  This action was taken in order tostrengthen IDACORP's financial position, and its ability to fund IPC's growingcapital expenditure needs.  The dividendreduction was also made to improve cash flows and help maintain credit ratings.

**Contractual Obligations**The following table presents IDACORP's and IPC's contractual cashobligations for the respective periods in which they are due:

 

**Payment Due by Period**

 

Total

**2006**

**2007-2008**

**2009-2010**

**Thereafter**

Long-term debt - IPC (a)

$

987,045

$

-

$

82,127

$

82,127

$

822,791

Future interest payments - IPC (b)

 

852,018

 

55,755

 

106,628

 

94,526

 

595,109

Long-term debt - Other (a)(i)

 

56,132

 

16,307

 

24,454

 

8,622

 

6,749

Future interest payments - Other (b)(i)

 

12,215

 

2,843

 

3,386

 

1,372

 

4,614

Capital lease obligations - Other (i)

 

35

 

35

 

-

 

-

 

-

Operating leases - IPC (c)

 

13,980

 

4,339

 

4,390

 

608

 

4,643

Operating leases - Other (i)

 

9,330

 

1,969

 

2,578

 

1,512

 

3,271

Purchase obligations - IPC:

 

 

 

 

 

 

 

 

 

 

 

Cogeneration and small power 

 

 

 

 

 

 

 

 

 

 

 

 

production

 

1,387,167

 

59,719

 

140,566

 

147,505

 

1,039,377

 

Fuel swap

 

660

 

660

 

-

 

-

 

-

 

Fuel supply agreements

 

151,004

 

43,370

 

67,493

 

30,023

 

10,118

 

Purchased power & transmission (d)

 

194,850

 

148,818

 

23,124

 

9,907

 

13,001

 

Maintenance & service agreements (e)

 

85,280

 

44,314

 

22,073

 

7,351

 

11,542

 

Other (f)

 

60,582

 

10,746

 

11,594

 

11,241

 

27,001

 

 

Total IPC purchase obligations

 

1,879,543

 

307,627

 

264,850

 

206,027

 

1,101,039

Purchase obligations - Other (i)

 

1,214

 

1,165

 

34

 

15

 

-

Restructuring charges - Other (g)

 

1,063

 

351

 

374

 

338

 

-

Other long-term liabilities - IPC (h)

 

4,168

 

831

 

1,285

 

1,067

 

985

Total IDACORP

$

3,816,743

$

391,222

$

490,106

$

396,214

$

2,539,201

Total IPC

$

3,736,754

$

368,552

$

459,280

$

384,355

$

2,524,567

 

 

 

 

 

 

 

 

 

 

 

(a)  

For additional information, see Note 5 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, 2005.

(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 $7 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 $24 million of the obligations included  in the detail of the maintenance and service agreements can be cancelled  without

 

 penalty.   Additionally, approximately $17 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)  

Approximately $5 million of the obligations  included in the detail of other purchase obligations can be cancelled without  penalty.  

 

Additionally, approximately $56 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.

(g)  

Restructuring charges are related to the wind  down of IE; for additional information see Note 15 to IDACORP's and IPC's  Consolidated

 

 Financial Statements.

(h)  

Other long-term liabilities include credit  facilities, the human resources information system license fee and lobbying agreements.  The 

 

human resources license fee obligation of  approximately $2 million can be cancelled without penalty.  Additionally, as the contract does not

 

 specify  terms related to contract expiration, 10 years of information, estimated  based on current contract terms, have been included in the

 

 table for  presentation purposes.

(i)  

Amounts include the obligations of various  subsidiaries with the exception of IPC, which is shown separately.

** **

**Off-Balance Sheet Arrangements**The federalSurface Mining Control and Reclamation Act of 1977 and similar state statutesestablish operational, reclamation and closure standards that must be metduring and upon completion of mining activities.  These obligations mandate that mine propertybe restored consistent with specific standards and the approved reclamationplan.  The mining operations at theBridger Coal Company are subject to these reclamation and closurerequirements.  IPC has agreed toguarantee the performance of reclamation activities at Bridger Coal Company, ofwhich Idaho Energy Resources Co., a subsidiary of IPC, owns a one-thirdinterest.  This guarantee, which isrenewed each December, was $60 million at December 31, 2005.  Bridger Coal has a reclamation trust fund setaside specifically for the purpose of paying these reclamation costs andexpects that the fund will be sufficient to cover all such costs.  Because of the existence of the fund, theestimated fair value of this guarantee is minimal.

InAugust 2003, IE sold its forward book of electricity trading contracts toSempra Energy Trading.  As part of thesale, IE entered into an Indemnity Agreement with Sempra Energy Trading,guaranteeing the performance of one of the counterparties.  The indemnification expires at the end of2009 and the maximum amount payable by IE under the Indemnity Agreement is $20million.  The impact of this guarantee onthe consolidated financial statements was minimal.

**Credit RatingsS&P**:  OnNovember 29, 2004, S&P announced that it had lowered the corporate creditratings and long-term ratings of IDACORP and IPC.  The companies' commercial paper rating was affirmedat A-2, and the rating outlooks for both companies are stable.

S&Pstated that its decision reflected weakened financial ratios that have resultedfrom a combination of (1) sustained drought conditions on the Snake River thathave depressed IPC's hydro production and increased deferred power costs; (2) adisappointing general rate case ruling by the IPUC, partly mitigated by theapproval of a settlement agreement on September 29, 2004, which granted IPC'sposition on income tax issues; and (3) more than $600 million of expectedcapital requirements by IPC.  S&Pstated that these pressures resulted in a financial profile that is weak evenfor the current BBB+ corporate credit rating. Further, S&P stated that two key issues that would determine futureratings movement were water flows in the Snake River and future rate caserulings by the IPUC.

**Moody's:**On December 3, 2004, Moody'sannounced that it had lowered the corporate credit ratings and long-termratings of IDACORP and the corporate credit ratings and long-term andshort-term ratings of IPC.  The ratingoutlooks for both companies are stable.

Moody'sstated that the downgrade of IPC's ratings reflected (1) expected weaker cashflow coverage of interest and debt; (2) the likelihood for continued negativefree cash flow over the next few years, with internally generated funds fallingshort of meeting the dividend requirements of IDACORP and significantutility-related capital spending; (3) persistent drought conditions that arelikely to result in higher supply costs, not all of which are recoverable underIPC's power cost adjustment mechanism; (4) the final resolution of IPC's 2003 ratecase, which resulted in a revenue increase of a little more than half of IPC'supdated request; and (5) the likely need for additional support from the IPUCin future rate proceedings as IPC adds new generation and transmissioninfrastructure to help meet customer and load growth and ensure reliability ofservice.

Accordingto Moody's, the downgrade of IDACORP's ratings reflected the weaker creditprofile of IPC, which is by far the largest source of cash flow in the form ofdividends to the parent company.  Moody'sstated that, with the continuing negative free cash flow trend for IPC, IDACORPmay need to depend more on dividends from its riskier non-utility subsidiariesto meet its own fixed obligations and common dividend to shareholders, eventhough management has committed to a "back-to-basics" strategy offocusing on its regulated business.

Inaddition, Moody's has assigned a Baa2 rating to IDACORP's five-year $150 millionsenior unsecured bank credit facility and a Baa1 rating to IPC's five-year $200million senior unsecured bank credit facility. Both facilities expire on March 31, 2010.

Moody's stated that the ratings assigned to the bankcredit facilities reflected the *pari passu* ranking of the facilitieswith each company's other senior unsecured obligations.  The facilities serve as part of the alternateliquidity for each company's commercial paper program and contain a maximum 65percent total debt to total capitalization ratio covenant with a materialadverse change clause as part of the representations and warranties relating toeach credit extension.  In Moody's view,the existence of the material adverse change clause detracts from the qualityof the facilities since it could preclude access to funds at the time ofgreatest need.

**Fitch:**  On January 24, 2005, Fitch announced that ithas lowered the long-term ratings of IDACORP and IPC and the short-term debtratings at IPC.  The rating outlooks forboth companies are stable.

Fitchstated that the downgrade of IPC's ratings reflected IPC's increased earningsvolatility and debt burden relative to cash flows, primarily due to the adverseeffect of ongoing drought conditions in southern Idaho and the lower thanexpected general rate case order issued by the IPUC in 2004.  According to Fitch, consolidated leverage hasalso been adversely affected by higher non-utility debt.  Fitch noted that the revised ratings alsoconsidered the moderating effect of IPC's PCA mechanism, which has enabled thecompany to maintain solid interest coverage ratios, the positive impact of amore conservative corporate business profile and ongoing efforts to reducefinancial leverage.  Fitch stated thatthe stable rating outlook assumes a return to normal stream flows andhydroelectric generation output in 2006.

Accessto capital markets at a reasonable cost is determined in large part by creditquality.  These downgrades have increasedthe cost of new debt and other issued securities.  The following outlines the current S&P, Moody's andFitch ratings of IDACORP'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

BBB

Baa 1

Baa 2

BBB+

BBB

 

(prelim)

(prelim)

 

 

 

 

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

Stable

Stable

Stable

Stable

Stable

Stable

 

Thesesecurity ratings reflect the views of the rating agencies.  An explanation of the significance of theseratings may be obtained from each rating agency.  Such ratings are not a recommendation to buy,sell or hold securities.  Any rating canbe revised upward or downward or withdrawn at any time by a rating agency if itdecides that the circumstances warrant the change.  Each rating should be evaluated independentlyof any other rating.

**CapitalRequirements**The following table presents IDACORP's and IPC's expected capital requirements from2006 through 2008:

 

**2006**

** **

**2007-2008**

 

**(millions of dollars)**

IPC  capital expenditures:

 

 

 

 

 

 

Generating  facilities:

 

 

 

 

 

 

 

Hydroelectric

$

25

 

$

68

 

 

Thermal

 

29

 

 

175

 

 

 

Total  generating facilities

 

54

 

 

243

 

Transmission  lines and substations

 

55

 

 

115

 

Distribution  lines and substations

 

66

 

 

122

 

General

 

20

 

 

45

Other  IPC

 

4

 

 

10

 

 

Total  IPC 

 

199

 

 

535

IFS  investments

 

21

 

 

47

Other

 

8

 

 

19

 

Total  IDACORP

$

228

 

$

601

 

 

 

 

 

 

 

Variationsin the timing and amounts of capital expenditures will result from regulatoryand environmental factors, load growth and other resource acquisition needs andthe timing of relicensing expenditures.

Internalcash generation after dividends is expected to provide less than the fullamount of total capital requirements for 2006 through 2008.  The contribution from 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.  IDACORP's internally generated cash afterdividends is expected to provide 34 percent of 2006 capital requirementsexcluding mandatory or optional principal payments on debt obligations.  IDACORP and IPC expect to continue financingcapital requirements with internally generated funds and externally financedcapital.  In 2005, sales of emission allowancesprovided investing cash of $71 million. On these sales, IPC is expects to pay approximately $28 million inincome taxes in the first quarter of 2006, reducing IDACORP's 2006 internallygenerated cash.  Excluding the subsequentcash impacts from the sale of emission allowances, IDACORP's internallygenerated cash after dividends is expected to provide 51 percent of 2006capital requirements.

**UtilityConstruction Program**:  IPC's construction expenditures were $185 millionin 2005, $190 million in 2004 and $148 million in 2003.  IPC is experiencing a cycle of heavyinfrastructure investment needed to address continued customer growth, peakdemand growth, and aging plant and equipment. As a result, IPC expects to spend $720 million in constructionexpenditures from 2006 to 2008.  The 2006- 2008 utility construction expenditure forecast includes: (1) $82 million ofconstruction costs for a 170-MW combustion turbine peaking resource expected tobe operational in mid-2008; and (2) $29 million for an upgrade to the ShoshoneFalls hydroelectric facility expected to be operational in 2010.

IPC'saging hydroelectric facilities require continuing upgrades and componentreplacement.  In addition, costs relatedto relicensing hydroelectric facilities are expected to increase substantially.  The three-year construction programanticipates $39 million of upgrades to existing hydroelectric facilities and$54 million of costs associated with relicensing of hydroelectric facilities.

Continuingload growth also requires that IPC add to its transmission system anddistribution facilities to provide new service and to maintainreliability.  Planned expendituresinclude distribution lines for new customers and several high-voltagetransmission lines.

Basedupon present environmental laws and regulations, IPC estimates its 2006 capitalexpenditures for environmental matters, excluding AFDC, will total $20million.  Studies and measures related toenvironmental concerns at IPC's hydroelectric facilities account for $17million and investments in environmental equipment and facilities at thethermal plants account for $3 million. From 2007 through 2008, environmental-related capital expenditures,excluding AFDC, are estimated to be $35 million.  Anticipated expenditures related to IPC'shydroelectric facilities account for $24 million and thermal plant expendituresare expected to total $11 million.

IPC hasno nuclear involvement and its future construction plans do not includedevelopment of any nuclear generation.

Seefurther discussion in "REGULATORY ISSUES - Integrated Resource Plan"and "REGULATORY ISSUES - Relicensing of Hydroelectric Projects."

**OtherCapital Requirements**:Most of IDACORP's non-regulated capital expenditures relate to IFS's investmentsin affordable housing developments that help lower IDACORP's income taxliability.

**Financing Programs**IDACORP'sconsolidated capital structure consisted of common equity of 48 percent anddebt of 52 percent at December 31, 2005.

**Credit Facilities:**  On May 3, 2005,IDACORP entered into a $150 million five-year credit agreement with variouslenders, Wachovia Bank, National Association, as joint lead arranger andadministrative agent and JP Morgan Chase Bank, NA, as joint lead arranger andsyndication agent and Wachovia Capital Markets, LLC and J.P. Morgan SecuritiesInc., as joint lead arrangers and joint book runners (IDACORP Facility).  The IDACORP Facility replaced IDACORP's $150million facility that was to expire on March 16, 2007.  The IDACORP Facility, which will be used forgeneral corporate purposes and commercial paper back-up, will terminate onMarch 31, 2010.  The IDACORP Facilityprovides for the issuance of loans and standby letters of credit not to exceedthe aggregate principal amount of $150 million, provided that the aggregateamount of the standby letters of credit may not exceed $75 million.

Under the terms of the IDACORP Facility, IDACORP mayborrow floating rate advances and eurodollar rate advances.  The floating rate is equal to the higher of(i) the prime rate announced by Wachovia Bank or its parent and (ii) the sum ofthe federal funds effective rate for such day plus 1/2 percent per annum, plus,in each case, an applicable margin.  Theeurodollar rate is based upon the British Bankers' Association interestsettlement rate for deposits in U.S. dollars published on the Telerate Page3750 (or any successor page) as adjusted by the applicable reserve requirementfor Eurocurrency liabilities imposed under Regulation D of the Board ofGovernors of the Federal Reserve System, for periods of one, two, three or sixmonths plus the applicable margin.  Theapplicable margin is based on IDACORP's rating for senior unsecured long-termdebt securities without third-party credit enhancement as provided by Moody'sInvestors Services (Moody's) and Standard & Poor's Ratings Service(S&P).  The applicable margin for thefloating rate advances is zero percent unless IDACORP's rating falls below Baa3from Moody's or BBB- from S&P, at which time it would equal 0.50percent.  The applicable margin foreurodollar rate advances ranges from 0.27 percent to 0.875 percent dependingupon the credit rating.  In addition tothe applicable margin, if the outstanding aggregate credit exposure exceeds 50percent of the facility amount, IDACORP would pay a utilization fee rangingfrom 0.10 percent to 0.125 percent on outstanding loans depending on the creditrating.  At December 31, 2005, theapplicable margin was zero percent for floating rate advances and 0.425 percentfor eurodollar rate advances and 0.125 percent for a utilization fee.  A facility fee, payable quarterly by IDACORP,is calculated on the average daily aggregate commitment of the lenders underthe IDACORP Facility and is also based on IDACORP's rating from Moody's orS&P as indicated above.  At December31, 2005, the facility fee was 0.15 percent.

In connection with the issuance of letters of credit,IDACORP must pay (i) a fee equal to the applicable margin for eurodollar rateadvances on the average daily undrawn stated amount under such letters ofcredit, payable quarterly in arrears, (ii) a fronting fee at a per annum rateof 0.125 percent on the average daily undrawn stated amount under each letterof credit, payable quarterly in arrears and (iii) documentary and processingcharges in accordance with the letter of credit issuer's standard schedule forsuch charges.

A ratings downgrade would result in an increase in thecost of borrowing and of maintaining letters of credit, but would not result inany default or acceleration of the debt under the IDACORP Facility.

The events of default under the IDACORP Facility include(i) nonpayment of principal when due and nonpayment of reimbursementobligations under letters of credit within one business day after becoming dueand nonpayment of interest or other fees within five days after becoming due,(ii) materially false representations or warranties made on behalf of IDACORPor any of its subsidiaries on the date as of which made, (iii) breach ofcovenants, subject in some instances to grace periods, (iv) voluntary andinvoluntary bankruptcy of IDACORP or any material subsidiary, (v) thenon-consensual appointment of a receiver or similar official for IDACORP or anyof its material subsidiaries or any substantial portion (as defined in theIDACORP Facility) of its property, (vi) condemnation of all or any substantialportion of the property of IDACORP or its subsidiaries, (vii) default in thepayment of indebtedness in excess of $25 million or a default by IDACORP or anyof its subsidiaries under any agreement under which such debt was created orgoverned which will cause or permit the acceleration of such debt or if any ofsuch debt is declared to be due and payable prior to its stated maturity,(viii) IDACORP or any of its subsidiaries not paying, or admitting in writingits inability to pay, its debts as they become due, (ix) the acquisition by anyperson or two or more persons acting in concert of beneficial ownership (withinthe meaning of Rule 13d-3 of the Securities Exchange Act of 1934) of 20 percentor more of the outstanding shares of voting stock of IDACORP, (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) IDACORP or any subsidiary being subject to any proceeding orinvestigation pertaining to the release of any toxic or hazardous waste orsubstance into the environment or any violation of any environmental law (asdefined in the IDACORP Facility) which could reasonably be expected to have amaterial adverse effect (as defined in the IDACORP Facility).  A default or an acceleration of indebtednessof IPC in excess of $25 million, including indebtedness under the IPC Facilitydescribed below, will result in a cross default under the IDACORP Facility.

Upon any event of default relating to the voluntary orinvoluntary bankruptcy of IDACORP or the appointment of a receiver, theobligations of the lenders to make loans under the facility and of the letterof credit issuer to issue letters of credit will automatically terminate andall unpaid obligations will become due and payable.  Upon any other event of default, the lendersholding 51 percent of the outstanding loans or 51 percent of the aggregatecommitments (required lenders) or the administrative agent with the consent ofthe required lenders may terminate or suspend the obligations of the lenders tomake loans under the facility and of the letter of credit issuer to issueletters of credit under the facility or declare the obligations to be due andpayable.  IDACORP will also be requiredto deposit into a collateral account an amount equal to the aggregate undrawnstated amount under all outstanding letters of credit and the aggregate unpaidreimbursement obligations thereunder.

On May 3, 2005, IPC entered into a $200 million five-yearcredit agreement with various lenders, Wachovia Bank, National Association, asjoint lead arranger and administrative agent and JP Morgan Chase Bank, NA, asjoint lead arranger and syndication agent and Wachovia Capital Markets, LLC andJ.P. Morgan Securities Inc., as joint lead arrangers and joint book runners(IPC Facility).  The IPC Facilityreplaced IPC's $200 million credit agreement that was to expire on March 16,2007.  The IPC Facility, which expires onMarch 31, 2010, will be used for general corporate purposes and commercialpaper back-up.  The IPC facility providesfor the issuance of loans and standby letters of credit not to exceed theaggregate principal amount of $200 million, provided that the aggregate amountof the standby letters of credit may not exceed $100 million.  Under the terms of the IPC Facility, IPC mayborrow floating rate advances and eurodollar rate advances.  The methods of calculating the floating rateand the eurodollar rate are the same as set forth above for the IDACORPFacility.  The applicable margin for theIPC Facility is also dependent upon IPC's rating for senior unsecured long-termdebt securities without third-party credit enhancement as provided by Moody'sand S&P.  At December 31, 2005, theapplicable margin for the IPC Facility was zero percent for floating rateadvances and 0.35 percent for eurodollar rate advances and 0.125 percent for autilization fee.  A facility fee, payablequarterly by IPC, is calculated on the average daily aggregate commitment ofthe lenders under the IPC Facility and is also based on IPC's rating fromMoody's or S&P as indicated above. At December 31, 2005, the facility fee was 0.125 percent.

In connection with the issuance of letters of credit, IPCmust pay (i) a fee equal to the applicable margin for eurodollar rate advanceson the average daily undrawn stated amount under such letters of credit,payable quarterly in arrears, (ii) a fronting fee at a per annum rate of 0.125percent on the average daily undrawn stated amount under each letter of credit,payable quarterly in arrears and (iii) documentary and processing charges inaccordance with the letter of credit issuer's standard schedule for suchcharges.

A ratings downgrade would result in an increase in thecost of borrowing, but would not result in any default or acceleration of thedebt under the IPC Facility.  If there isa ratings downgrade below investment grade (BBB- or higher by S&P and Baa3or higher by 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 or renewal of indebtedness maturing not more thanone year after the date of such issue or renewal without approval of theOPUC.  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, 2005, no loans were outstanding under theIDACORP Facility or the IPC Facility.  Theevents of default under the IPC Facility are the same as under the IDACORPFacility.

Upon any event of default relating to the voluntary orinvoluntary bankruptcy of IPC or the appointment of a receiver, the obligationsof the lenders to make loans under the facility will automatically terminateand all unpaid obligations of IPC will become due and payable.  Upon any other event of default, the requiredlenders (or the administrative agent with the consent of the required lenders)may terminate or suspend the obligation of the lenders to make loans under theIPC Facility or declare IPC's unpaid obligations to be due and payable.

**Debt Covenants:** The IDACORP Facility and the IPC Facility each contain a covenantrequiring each company to maintain a leverage ratio of consolidatedindebtedness to consolidated total capitalization of no more than 65 percent asof the end of each fiscal quarter.  AtDecember 31, 2005, the leverage ratios for IDACORP and IPC were 51 and 52percent, respectively.  At December 31,2005, IDACORP was in compliance with all other covenants of the IDACORPFacility and IPC was in compliance with all other covenants of the IPCFacility.

Other covenants in the IDACORP Facility include (i)prohibitions against: investments and acquisitions by IDACORP or any subsidiarywithout the consent of the required lenders subject to exclusions forinvestments in cash equivalents or securities of IDACORP; investments byIDACORP and its subsidiaries in any business trust controlled, directly orindirectly, by IDACORP to the extent such business trust purchases securitiesof IDACORP; investments and acquisitions related to the energy business orother business of IDACORP and its subsidiaries not exceeding $500 million inthe aggregate at any one time outstanding (provided that investments innon-energy related businesses do not exceed $150 million); and investments byIDACORP or a subsidiary in connection with a permitted receivablessecuritization (as defined in the IDACORP Facility); (ii) prohibitions againstIDACORP or any material subsidiary merging or consolidating with any otherperson or selling or disposing of all or substantially all of its property toanother person without the consent of the required lenders, subject toexclusions for mergers into or dispositions to IDACORP or a wholly ownedsubsidiary and dispositions in connection with a permitted receivablessecuritization; (iii) restrictions on the creation of certain liens by IDACORPor any material subsidiary subject to exceptions, including the lien of IPC'sfirst mortgage indebtedness; and (iv) prohibitions on any material subsidiaryentering into any agreement restricting its ability to declare or pay dividendsto IDACORP except pursuant to a permitted receivables securitization.

Other covenants in the IPC Facility include (i)prohibitions against: investments and acquisitions by IPC or any subsidiarywithout the consent of the required lenders, subject to exclusions forinvestments in cash equivalents or securities of IPC; investments by IPC andits subsidiaries in any business trust controlled, directly or indirectly, byIPC to the extent such business trust purchases securities of IPC; investmentsand acquisitions related to the energy business of IPC and its subsidiaries notexceeding $500 million in the aggregate at any one time outstanding; andinvestments by IPC or a subsidiary in connection with a permitted receivablessecuritization (as defined in the IPC Facility); (ii) prohibitions against IPCor any material subsidiary merging or consolidating with any other person orselling or disposing of all or substantially all of its property to anotherperson without the consent of the required lenders, subject to exclusions formergers into or dispositions to IPC or a wholly owned subsidiary anddispositions in connection with a permitted receivables securitization; (iii)restrictions on the creation of certain liens by IPC or any material subsidiarysubject to exceptions, including the lien of IPC's first mortgage indebtedness;and (iv) prohibitions on any material subsidiary entering into any agreementrestricting its ability to declare or pay dividends to IPC except pursuant to apermitted receivables securitization.

**Long-term financings:**  OnDecember 15, 2004, IDACORP issued 4,025,000 shares of its common stock at $30per share.  After expenses, IDACORPreceived approximately $116 million. These proceeds were used to make a capital contribution to IPC and topay down short-term borrowings at both companies.

On December 15, 2005, IDACORPentered into a SalesAgency Agreement with BNY Capital Markets, Inc. (BNYCMI).  Under the terms of the Sales AgencyAgreement, IDACORP may offer and sell up to 2,500,000 shares of its commonstock, from time to time in at the market offerings through BNYCMI, asIDACORP's agent for such offer and sale. No shares have been sold under this program.

IDACORP currently has $679 million remaining on two shelfregistration statements that can be used for the issuance of unsecured debt(including medium-term notes) and preferred or common stock, including the2,500,000 shares referred to in the preceding paragraph.

In April 2005, with the goal of adding additional commonequity to its capital structure, IDACORP began using original issue commonstock in its Dividend Reinvestment and Stock Purchase Plan, rather thanpurchasing this stock on the open market. Beginning in August 2005, IDACORP also began using original issue commonstock for its 401(k) plan.  Approximately203,253 shares were issued in 2005.

On August 26, 2005, IPC issued $60 million of 5.30% FirstMortgage Bonds due 2035, Secured Medium-Term Notes, Series F.  The proceeds of the issuance were used torepay the $60 million, 5.83% First Mortgage Bonds that matured on September 9,2005.  On August 30, 2005, IPC settled aforward-starting interest rate swap agreement by making a payment of $2.7million to the counterparty of the agreement. In accordance with regulatory accounting practices under SFAS 71, IPC isamortizing this amount over the life of its 5.30% First Mortgage Bonds due2035.

IPC currently has in place one shelf registrationstatement that can be used for the issuance of an aggregate principal amount of$240 million of first mortgage bonds (including medium-term notes) andunsecured debt.

See Note5 to IDACORP's and IPC's Consolidated Financial Statements for more informationregarding long-term financings.

**Subsidiary Financing**IDACORP iscurrently evaluating its strategic alternatives with respect to IdaTech.  One alternative is to raise additional fundsfrom private sources in 2006 for the ongoing funding of operations.  IDACORP cannot presently determine what levelof private funding, if any, may be raised or what equity interest in IdaTech maybe issued in connection with any such funding.

**LEGAL AND ENVIRONMENTAL ISSUES:**

**Legal and Other Proceedings********ShareholderLawsuits:** On May 26, 2004 and June 22, 2004,respectively, two shareholder lawsuits were filed against IDACORP and certainof its directors and officers.  Thelawsuits, captioned Powell, et al. v. IDACORP, Inc., et al. and Shorthouse, etal. v. IDACORP, Inc., et al., raised largely similar allegations.  The lawsuits were putative class actionsbrought on behalf of purchasers of IDACORP stock between February 1, 2002 andJune 4, 2002, and were filed in the U.S. District Court for the District ofIdaho.  The named defendants in eachsuit, in addition to IDACORP, are Jon H. Miller, Jan B. Packwood, J. LaMontKeen and Darrel T. Anderson.

Thecomplaints alleged that, during the purported class period, IDACORP and/orcertain of its officers and/or directors made materially false and misleadingstatements or omissions about the company's financial outlook in violation ofSections 10(b) and 20(a) of the Securities Exchange Act of 1934, as amended,and Rule 10b-5, thereby causing investors to purchase IDACORP's common stock atartificially inflated prices.  Morespecifically, the complaints alleged that IDACORP failed to disclose andmisrepresented the following material adverse facts which were known todefendants or recklessly disregarded by them: (1) IDACORP failed to appreciatethe negative impact that lower volatility and reduced pricing spreads in thewestern wholesale energy market would have on its marketing subsidiary, IE; (2)IDACORP would be forced to limit its origination activities to shorter-termtransactions due to increasing regulatory uncertainty and continueddeterioration of creditworthy counterparties; (3) IDACORP failed to account forthe fact that IPC may not recover from the lingering effects of the prioryear's regional drought and (4) as a result of the foregoing, defendants lackeda reasonable basis for their positive statements about IDACORP and theirearnings projections.  The Powellcomplaint also alleged that the defendants' conduct artificially inflated theprice of IDACORP's common stock.  Theactions seek an unspecified amount of damages, as well as other forms ofrelief.  By order dated August 31, 2004,the court consolidated the Powell and Shorthouse cases for pretrial purposes,and ordered the plaintiffs to file a consolidated complaint within 60days.  On November 1, 2004, IDACORP andthe directors and officers named above were served with a purportedconsolidated complaint captioned Powell, et al. v. IDACORP, Inc., et al., whichwas filed in the U.S. District Court for the District of Idaho.

The newcomplaint alleged that during the class period IDACORP and/or certain of itsofficers and/or directors made materially false and misleading statements or omissionsabout its 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 IDACORP failed to disclose andmisrepresented the following material adverse facts which were known to it orrecklessly disregarded by it: (1) IDACORP falsely inflated the value of energycontracts held by IE in order to report higher revenues and profits; (2)IDACORP permitted IPC to inappropriately grant native load priority for certainenergy transactions to IE; (3) IDACORP failed to file 13 ancillary serviceagreements involving the sale of power for resale in interstate commerce thatit was required to file under Section 205 of the Federal Power Act; (4) IDACORPfailed to file 1,182 contracts that IPC assigned to IE for the sale of powerfor resale in interstate commerce that IPC was required to file under Section203 of the Federal Power Act; (5) IDACORP failed to ensure that IE providedappropriate compensation from IE to IPC for certain affiliated energytransactions; and (6) IDACORP permitted inappropriate sharing of certain energypricing and transmission information between IPC and IE.  These activities allegedly allowed IE tomaintain a false perception of continued growth that inflated itsearnings.  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.  Theaction seeks an unspecified amount of damages, as well as other forms ofrelief.  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 defendantsfiled their response to the plaintiff's opposition on April 29, 2005 and oralargument on the motion was held on May 19, 2005.

On September 14, 2005, Magistrate Judge Mikel H. Williamsof the U.S. District Court for the District of Idaho issued a Report andRecommendation that the defendants' motion to dismiss be granted and that thecase 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._____, 125 S. Ct. 1627 (2005).  TheMagistrate Judge also concluded that it would be futile to afford theplaintiffs an opportunity to file an amended complaint because it did notappear that they could cure the deficiencies in their pleadings.  The parties have each filed objections todifferent parts of the Magistrate Judge's Report and Recommendation, and thematter is now before the District Judge.

IDACORPand the other defendants intend to defend themselves vigorously against theallegations.  IDACORP cannot, however,predict the outcome of these matters.

**Public Utility District No. 1 of Grays Harbor County,Washington:**  On October 15, 2002, Public Utility DistrictNo. 1 of Grays Harbor County, Washington (Grays Harbor) filed a lawsuit in theSuperior Court of the State of Washington, for the County of Grays Harbor,against IDACORP, IPC and IE.  On March 9,2001, Grays Harbor entered into a 20-MW purchase transaction with IPC for thepurchase of electric power from October 1, 2001 through March 31, 2002, at arate of $249 per MWh.  In June 2001, withthe consent of Grays Harbor, IPC assigned all of its rights and obligationsunder the contract to IE.  In itslawsuit, Grays Harbor alleged that the assignment was void and unenforceable,and sought restitution from IE and IDACORP, or in the alternative, Grays Harboralleged that the contract should be rescinded or reformed.  Grays Harbor sought as damages an amountequal to the difference between $249 per MWh and the "fair value" ofelectric power delivered by IE during the period October 1, 2001 through March31, 2002.

IDACORP, IPC and IE removed this action from the statecourt to the U.S. District Court for the Western District of Washington atTacoma.  On November 12, 2002, thecompanies filed a motion to dismiss Grays Harbor's complaint, asserting thatthe U.S. District Court lacked jurisdiction because the FERC has exclusivejurisdiction over wholesale power transactions and thus the matter is preemptedunder the Federal Power Act and barred by the filed-rate doctrine.  The court ruled in favor of the companies'motion to dismiss and dismissed the case with prejudice on January 28,2003.  On February 25, 2003, Grays Harborfiled a Notice of Appeal, appealing the final judgment of dismissal to the U.S.Court of Appeals for the Ninth Circuit. On August 10, 2004, the Ninth Circuit affirmed the dismissal of GraysHarbor's complaint, finding that Grays Harbor's claims were preempted by federallaw and were barred by the filed-rate doctrine. The court also remanded the case to allow Grays Harbor leave to amendits complaint to seek declaratory relief only as to contract formation, andheld that Grays Harbor could seek monetary relief, if at all, only from theFERC, and not from the courts.  IDACORP,IPC and IE sought rehearing from the Ninth Circuit arguing that the court erredin granting leave to amend the complaint as such a declaratory relief claimwould be preempted and would be barred by the filed-rate doctrine.  The Ninth Circuit denied the rehearingrequest on October 25, 2004, and the decision became final on November 12,2004.

On thatsame date, the companies took steps to have the case transferred andconsolidated with other similar cases arising out of the California energycrisis currently pending before the Honorable Robert H. Whaley, sitting bydesignation in the Southern District of California and presiding overMultidistrict Litigation Docket No. 1405, regarding California WholesaleElectricity Antitrust Litigation.  OnNovember 18, 2004, Grays Harbor filed an amended complaint alleging that thecontract was formed under circumstances of "mistake" as to an"artificial . . . power shortage." Grays Harbor asked that the contract therefore be declared"unenforceable" and found "unconscionable."  On December 23, 2004, the Judicial Panel onMultidistrict Litigation conditionally transferred the case to JudgeWhaley.  Grays Harbor sought to vacatethe transfer; however, on April 18, 2005, the Judicial Panel on MultidistrictLitigation ordered the case transferred. On May 18, 2005, IDACORP, IPC and IE filed a motion to dismiss theamended complaint.  The motion was heardon September 29, 2005.

OnDecember 16, 2005, Judge Whaley issued an Order Setting Status Conference wherein,rather than expressly ruling on the companies' motion to dismiss Grays Harbor'samended complaint, he ruled that either Grays Harbor or the companies may,within 45 days of the date of the order, petition the FERC to weigh in on thiscase in light of "the extensive hearings . . . already undertaken by FERCin the Northwest refund proceeding" which may be relevant to thiscase.  On January 27, 2006 Grays Harbor and the companies jointly filed astipulation requesting that the court stay the action and extend the time inwhich the parties may petition the FERC by sixty days to March 31, 2006,stating that the parties felt the case was appropriate for mediation prior tofurther proceedings.  On January 31, 2006the court approved the stipulation staying the case until March 31, 2006 andsetting a status conference for April 14, 2006. 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.

**Portof Seattle:**  On May 21, 2003, the Port of Seattle, aWashington municipal corporation, filed a lawsuit against 20 energy firms,including IPC and IDACORP, in the U.S. District Court for the Western Districtof Washington at Seattle.  The Port ofSeattle's complaint alleges fraud and violations of state and federal antitrustlaws and the Racketeer Influenced and Corrupt Organizations Act.  On December 4, 2003, the Judicial Panel onMultidistrict Litigation transferred the case to the Southern District ofCalifornia for inclusion with several similar multidistrict actions currentlypending before the Honorable Robert H. Whaley.

Alldefendants, including IPC and IDACORP, moved to dismiss the complaint in lieuof answering it.  The motions were basedon the ground that the complaint seeks to set alternative electrical rates,which are exclusively within the jurisdiction of the FERC and are barred by thefiled-rate doctrine.  A hearing on themotion to dismiss was heard on March 26, 2004. On May 28, 2004, the court granted IPC's and IDACORP's motion todismiss.  In June 2004, the Port ofSeattle appealed the court's decision to the U.S. Court of Appeals for theNinth Circuit.  On July 19, 2005 thecompanies filed a motion for summary affirmance of the district court's orderdismissing the Port of Seattle's complaint. The Ninth Circuit issued an order denying this motion on October 17,2005.  The appeal has been fully briefed andoral argument has been scheduled for March 7, 2006.  The companies intend to vigorously defendtheir position in this proceeding and believe this matter will not have amaterial adverse effect on their consolidated financial positions, results ofoperations or cash flows.

**WahChang:**  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 named as defendants in one of the lawsuits.  The complaints allege violations of federalantitrust laws, violations of the Racketeer Influenced and CorruptOrganizations Act, violations of Oregon antitrust laws and wrongfulinterference with contracts.  Wah Chang'scomplaint is based on allegations relating to the western energysituation.  These allegations include bidrigging, falsely creating congestion and misrepresenting the source anddestination of energy.  The plaintiffseeks compensatory damages of $30 million and treble damages.

OnSeptember 8, 2004, this case was transferred and consolidated with othersimilar cases currently pending before the Honorable Robert H. Whaley.  The companies' motion to dismiss thecomplaint was granted on February 11, 2005. Wah Chang appealed to the Ninth 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 amotion to stay the appeal or in the alternative to voluntarily dismiss theappeal without prejudice to reinstatement. The companies opposed the motion and filed a cross-motion asking theCourt to summarily affirm the district court's order of dismissal.  On July 8, 2005, the Ninth Circuit denied WahChang's motion and also denied the companies' motion for summary affirmancewithout prejudice to renewal following the filing of Wah Chang's openingbrief.  Wah Chang's opening brief wasfiled on September 21, 2005.  On October11, 2005 the companies, along with the other defendants, filed a motion toconsolidate this appeal with Wah Chang v. Duke Energy Trading and Marketingcurrently pending before the Ninth Circuit. On October 18, 2005 the Ninth Circuit granted the motion to consolidateand established a revised briefing schedule. The companies filed an answering brief on November 30, 2005.  Wah Chang's reply brief was filed on January6, 2006. The appeal has been fully briefed; however, no date has yet been setfor oral argument.  The companies intendto vigorously defend their position in this proceeding and believe this matterwill not have a material adverse effect on their consolidated financialpositions, results of operations or cash flows.

**Cityof Tacoma:**  On June 7, 2004, the City of Tacoma,Washington filed a lawsuit in the U.S. District Court for the Western Districtof Washington at Tacoma against numerous defendants including IDACORP, IE andIPC.  The City of Tacoma's complaintalleges violations of the Sherman Antitrust Act.  The claimed antitrust violations are based onallegations of energy market manipulation, false load scheduling and bidrigging and misrepresentation or withholding of energy supply.  The plaintiff seeks compensatory damages ofnot less than $175 million.

OnSeptember 8, 2004, this case was transferred and consolidated with othersimilar cases currently pending before the Honorable Robert H. Whaley.  The companies' motion to dismiss thecomplaint was granted on February 11, 2005. The City of Tacoma appealed to the Ninth Circuit on March 10, 2005.

OnAugust 9, 2005, the companies moved for summary affirmance of the districtcourt's order dismissing the City of Tacoma's complaint.  The City of Tacoma filed a response to thecompanies' motion for summary affirmance on August 24, 2005.  The Ninth Circuit denied the companies'motion for summary affirmance on November 3, 2005.  The appeal has been fully briefed; however,no date has yet been set for oral argument. 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.

**WholesaleElectricity Antitrust Cases I & II:**  Thesecross-actions against IE and IPC emerged from multiple California state courtproceedings first initiated in late 2000 against various powergenerators/marketers by various California municipalities and citizens.  Suit was filed against entities includingReliant Energy Services, Inc., Reliant Ormond Beach, L.L.C., Reliant EnergyEtiwanda, L.L.C., Reliant Energy Ellwood, L.L.C., Reliant Energy Mandalay,L.L.C. and Reliant Energy Coolwater, L.L.C. (collectively, Reliant); and DukeEnergy Trading and Marketing, L.L.C., Duke Energy Morro Bay, L.L.C., DukeEnergy Moss Landing, L.L.C., Duke Energy South Bay, L.L.C. and Duke EnergyOakland, L.L.C. (collectively, Duke). While varying in some particulars, these cases made a common claim thatReliant, Duke and certain others (not including IE or IPC) colluded to influencethe price of electricity in the California wholesale electricity market.  The plaintiffs asserted various claims thatthe defendants violated the California Antitrust Law (the Cartwright Act),Business and Professions Code Section 16720 and California's Unfair CompetitionLaw, Business and Professions Code Section 17200.  Among the acts complained of are bid rigging,information exchanges, withholding of power and other wrongful acts.  These actions were subsequently consolidated,resulting in the filing of Plaintiffs' Master Complaint in San Diego SuperiorCourt on March 8, 2002.

On April22, 2002, more than a year after the initial complaints were filed, two of theoriginal defendants, Duke and Reliant, filed separate cross-complaints againstIPC and IE, and approximately 30 other cross-defendants.  Duke and Reliant's cross-complaints soughtindemnity from IPC, IE and the other cross-defendants for an unspecified shareof any amounts they must pay in the underlying suits because, they allege,other market participants like IPC and IE engaged in the same conduct at issuein the Plaintiffs' Master Complaint. Duke and Reliant also sought declaratory relief as to the respectiveliability and conduct of each of the cross-defendants in the actions alleged inthe Plaintiffs' Master Complaint.  Reliantalso asserted a claim against IPC for alleged violations of the CaliforniaUnfair Competition Law, Business and Professions Code Section 17200.  As a buyer of electricity in California,Reliant requested the same relief from the cross-defendants, including IPC, asthat sought by plaintiffs in the Plaintiffs' Master Complaint as to any powerReliant purchased through the California markets.

Some ofthe newly added defendants (foreign citizens and federal agencies) removed thatlitigation to federal court.  IPC and IE,together with numerous other defendants added by the cross-complaints, moved todismiss these claims, and those motions were heard in September 2002, togetherwith motions to remand the case back to state court filed by the originalplaintiffs.  On December 13, 2002, theU.S. District Court granted Plaintiffs' Motion to Remand to state court, butdid not issue a ruling on IPC and IE's motion to dismiss.  The U.S. Court of Appeals for the NinthCircuit granted certain Defendants and Cross-Defendants' Motions to Stay theRemand Order while they appeal the order. The briefing on the appeal was completed in December 2003.  On December 8, 2004, the Ninth Circuit issuedits opinion in People of California v. NRG Energy, Inc., et al., which affirmedthe district court's remand of these cases to state court and dismissed certainfederal government defendants due to their sovereign immunity from suit.

On June 3, 2005, the cross-defendants, including IPC andIE, filed a demurrer in state court seeking to dismiss the cross-complaintsfiled by Duke and Reliant.  On August 8,2005, before that demurrer was to be heard, the Clerk of the Court enteredDuke's voluntary dismissal, with prejudice, of the cross-complaint against IEand IPC.  Further briefing and hearing onIE and IPC's demurrer to the Reliant cross-complaint was stayed pending theoutcome of the demurrer filed by Reliant on the Master Complaint.  On September 22, 2005, the Court tookReliant's demurrer off calendar pending approval of a proposed settlement as tothe plaintiff's Master Complaint.  OnOctober 3, 2005 the court sustained the defendants' (other than Reliant's)joint demurrer to the Master Complaint and scheduled a status conference todiscuss the status of the cross-complaints. On October 13, 2005 the court set IE and IPC's demurrer on thecross-complaint for hearing on December 23, 2005.

However,on November 14, 2005, Judge Joan M. Lewis approved a stipulation between thecross-defendants, including IE and IPC, and Reliant.  This stipulation provided for dismissal of IEand IPC by Reliant with prejudice subject to reinstatement in the event thatapproval and finalization of a settlement agreement between Reliant and theunderlying plaintiffs in these cases does not occur.  The December 23, 2005 hearing on IE and IPC'sdemurrer to the cross-complaint was taken off the calendar.  A hearing regarding approval of the Reliantsettlement was held on Friday January 6, 2006 before Judge Lewis.

Relianthas filed a request for dismissal of IE and IPC with prejudice, which wasentered by the clerk of the court on December 19, 2005.  Pursuant to IE and IPC's stipulation withReliant, the dismissal will become final once any judgment and order from theCourt approving the Reliant settlement with the plaintiffs becomes final (i.e.,once the time for any appeal on the order approving the settlements runs or, ifreview is sought, the trial court's approval order is affirmed after resolutionof all appeals).  The time for an appealfrom an order approving the settlements would range from 30 to 90 days afterentry of the Court's judgments and orders.

If theCourt does not grant final approval for the Reliant settlement, Reliant mayelect to reactivate its cross-complaint. Similarly, should the Court for any reason fail to approve the Reliantsettlement by May 31, 2006, IE and IPC may withdraw from the stipulationagreement by giving ten days advance written notice.  The companies intend to vigorously defendtheir position in this proceeding and believe this matter will not have amaterial adverse effect on their consolidated financial positions, results ofoperations or cash flows.

Thesematters are also discussed in Note 8 to IDACORP's and IPC's ConsolidatedFinancial Statements.

**WesternEnergy Proceedings at the FERC:** IE and IPC areinvolved in a number of FERC proceedings arising out of the western energysituation in California and claims that dysfunctions in the organizedCalifornia markets contributed to or caused unjust and unreasonable prices inPacific Northwest spot markets, and may have been the result of manipulationsof gas or electric power markets.  Theyinclude proceedings involving:

(1) the chargeback provisions of the California PowerExchange (CalPX) participation agreement triggered when a participant defaultedon a payment to the CalPX.  Upon such adefault, other participants were required to pay their allocated share of thedefault amount to the CalPX.  Thisprovision was first triggered by the Southern California Edison default andlater by the Pacific Gas 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 Refund proceeding.  One party has appealed this order to the D.C.Circuit Court of Appeals.  Based upon thesettlement agreement filed with the FERC on February 17, 2006 regarding theCalifornia Refund proceeding, the California Parties supported a request that theFERC authorize the CalPX to release $2.27 million to IE and IPC;

 

(2) The California refund proceeding is an efforts by theState of California to obtain refunds for a portion of the spot market salesfrom sellers of electricity into California from October 2, 2000 through June20, 2001.  California is claiming thatthe sales prices were not just and reasonable and were not in compliance withthe Federal Power Act.  The FERC issuedan order on refund liability on March 26, 2003 on which multiple parties,including IE, sought rehearing.  OnOctober 16, 2003, the FERC denied the requests for rehearing and required theCalifornia Independent System Operator (Cal ISO) to make a compliance filingregarding refund amounts within five months, which has since been delayed untilMarch 2006.  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 requests for rehearing onNovember 23, 2004.  On December 2, 2003,IE and others petitioned the United States Court of Appeals for the NinthCircuit for review of the FERC's orders on California refunds.  As additional FERC orders have been issued,further petitions for review have been filed, including by IE, and have beenconsolidated with the appeals already pending before the Ninth Circuit.  On September 21, 2004, the Ninth Circuitconvened the first of its case management proceedings, a procedure reserved tohelp organize complex cases.  On October22, 2004, the Ninth Circuit severed several issues related to the FERC's refundjurisdiction, established a schedule for briefing and held oral argument onApril 12 and 13, 2005.  On May 26, 2005,the California Parties filed a motion with the FERC to submit additionalevidence.  A number of parties areopposing this motion.  On September 6,2005, the Ninth Circuit issued a decision in one of the severed casesconcluding that the FERC lacked refund authority over wholesale electricalenergy sales made by governmental entities and non-public utilities.  On August 8, 2005 the FERC issued an orderestablishing a framework for those sellers wanting to make a cost filing todemonstrate that the generally applicable FERC refund methodology interferedwith the recovery of costs.  Thecompanies along with others made a cost filing on September 14, 2005, theCalifornia entities commented on October 11, 2005, and IPC and IE replied tothose comments on October 17, 2005.  TheCalifornia entities filed supplemental comments on October 24, 2005 and thecompanies filed supplemental reply comments on October 27, 2005.

In December 2005 IE and IPC reached a tentative agreementwith the California Parties settling matters encompassed by the CaliforniaRefund proceeding including IE and IPC's cost filing and refundobligation.  On January 20, 2006, theParties filed a request with the FERC asking that FERC defer ruling on IE andIPC's cost filing for thirty days so the parties could complete and file thesettlement agreement with the FERC.  On January 26, 2006, the FERC granted therequested deferral and required that the settlement 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 Company, 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. Final comments on the settlement are due to be filed by March 20, 2006,after which the FERC will determine whether to approve the settlement.  If the settlement is approved by the FERC, IEand IPC will assign $24.25 million of the rights to accounts receivable fromthe Cal ISO and the CalPX to the California Parties to pay into an escrowaccount for refunds to settling parties. Amounts from that escrow not used for settling parties and $1.5 millionof the remaining IE and IPC receivables which are to be retained by the CalPXare available to fund, at least partially, payment of the claims of anynon-settling parties if they prevail in the remaining litigation of thismatter.  Approximately $10.25 million of theremaining IE and IPC receivables are to be released to IE and IPC.  At December 31, 2005, with respect to theCalPX chargeback and the California Refund proceedings discussed above, theCalPX and the Cal ISO owed $14 million and $30 million, respectively, forenergy sales made to them by IPC in November and December 2000. In the fourthquarter of 2005 IE reduced by $9.5 million to $32 million its reserve againstthese receivables.  This reserve wascalculated taking into account the uncertainty of collection, given theCalifornia energy situation.  Based onthe reserve recorded as of December 31, 2005, IDACORP believes that the futurecollectibility of these receivables or any potential refunds ordered by theFERC would not have a material adverse effect on its consolidated financialposition, results of operations or cash flows;

(3) the Pacific Northwest refund proceedings wherein itwas argued that the spot market in the Pacific Northwest was affected by thedysfunction in the California market, warranting refunds.  The FERC rejected this claim on June 25,2003, and denied rehearing on November 11, 2003 and February 9, 2004.  The FERC orders were appealed to the NinthCircuit, which established a briefing schedule under which final briefs weresubmitted in May 2005.  There presentlyis no date set for oral argument.  IE andIPC are unable to predict the outcome of these matters; and

 (4) two FERC showcause orders which resulted from a ruling of the Ninth Circuit that the FERCpermit the California parties in the California refund proceeding to submitmaterials to the FERC demonstrating market manipulation by various sellers ofelectricity into California.  On June 25,2003, the FERC ordered a large number of parties including IPC to show causewhy certain trading practices did not constitute gaming ("gaming") oranomalous market behavior ("partnership") in violation of the Cal ISOand CalPX Tariffs.  On October 16, 2003,IPC reached agreement with the FERC Staff on the show cause orders.  The "gaming" settlement wasapproved by the FERC on March 3, 2004. The FERC approved the motion to dismiss the "partnership"proceeding on January 23, 2004.  Althoughthe orders establishing the scope of the show cause proceedings are presentlythe subject of review petitions in the Ninth Circuit, the order dismissing IPCfrom the "partnership" proceedings was not the subject of rehearingrequests.  Eight parties have requestedrehearing of the FERC's March 3, 2004 order approving the "gaming"settlement but the FERC has not yet acted on those requests.

Inaddition to the two show cause orders, on June 25, 2003, the FERC also issuedan order instituting an investigation of anomalous bidding behavior andpractices in the western wholesale markets for the time period May 1, 2000through October 1, 2000 to review evidence of economic withholding ofgeneration.  IPC, along with over 60other market participants, responded to FERC data requests and the FERCterminated its investigations as to IPC on May 12, 2004.  Numerous parties have appealed the FERC'stermination of this investigation as to IPC and over 30 other marketparticipants.

TheFebruary 17, 2006 settlement, if approved by the FERC, also provides a basisfor FERC disposition of the "gaming" settlement.

Thesematters are discussed in more detail in Note 8 to IDACORP's and IPC'sConsolidated Financial Statements.

**OtherLegal Proceedings:**  IDACORP, IPC and/or IE are involved inlawsuits and legal proceedings in addition to those discussed above and in Note8 to IDACORP's and IPC's Consolidated Financial Statements.  The companies believe they have meritoriousdefenses to all lawsuits and legal proceedings where they have been named asdefendants.  Resolution of any of thesematters will take time, and the companies cannot predict the outcome of any ofthese proceedings.  The companies believethat their reserves are adequate for these matters.

**Environmental IssuesIdaho Water Management Issues: **The state of Idaho hasexperienced six consecutive years of below normal precipitation and streamflows.  These conditions have exacerbateda developing water shortage in the state, which is manifested by a number ofwater issues including declining Snake River base flows and declining levels inthe Eastern Snake Plain Aquifer, a large underground aquifer that has beenestimated to hold between 200-300 maf of water. These issues are of interest to IPC because of their potential impactson generation at IPC's hydroelectric projects. With respect to base flows, observed records suggest that the base flowsin the Snake River, particularly between IPC's Twin Falls and Swan Fallsprojects, have been in decline for several decades.  The yearly average flow measured below SwanFalls declined at an average rate of 43 cubic feet per second (cfs) per yearduring 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 Snake River near Hagerman,Idaho continued to be observed during 2005, where several river gauges in thatarea recorded the lowest January - March Snake River flows since the early1960's.

As aresult of these declines in river flows, in 2003 several surface water usersfiled delivery calls with the Idaho Department of Water Resources, demandingthat it manage ground water withdrawals pursuant to the prior appropriationdoctrine of "first in time is first in right" and curtail juniorground water rights that are depleting the aquifer and affecting flows tosenior surface water rights.  Thesedelivery calls have resulted in several administrative actions before the IdahoDepartment of Water Resources and judicial actions before the State DistrictCourt in Ada and Gooding Counties in Idaho challenging the constitutionality ofstate regulations used by the Department to conjunctively administer ground andsurface water rights.  One such action,filed in January 2005, involves seven surface water irrigation entities fromabove Milner Dam that submitted a delivery call letter to the Director of theIdaho Department of Water Resources requesting that the Director administer anddeliver their senior natural flow and storage water rights pursuant to Idaholaw.  The irrigation entities contendthat existing data reflects that senior surface water rights above Milner Damhave been reduced by approximately 600,000 acre-feet, a 30 percent reduction,over the past six years due, in part, to junior groundwater pumping from theEastern Snake Plain Aquifer, and that these reductions have resulted incumulative shortages in natural flow and storage water accrual in AmericanFalls Reservoir, a U.S. Bureau of Reclamation reservoir that supplies a portionof their senior water rights.  The IdahoGround Water Appropriators, Inc., an Idaho non-profit corporation organized topromote and represent the interests of groundwater users, and the U.S. Bureauof Reclamation, the owner of American Falls Reservoir, petitioned to intervenein the delivery call action.  Bothpetitions were granted.

SinceIPC holds water rights that are dependent on the Snake River, spring flows andthe overall condition of the Eastern Snake Plain Aquifer, IPC is participatingin several of these actions to protect its interests and encourage thedevelopment of a long-term management plan that will protect the aquifer fromfurther depletion.

One management option being explored is aquifer recharge,or using surface water supplies to increase ground water supplies by allowingthe water to percolate into the aquifer in porous locations.  Under certain circumstances aquifer rechargemay impact senior water rights, including water rights held by IPC forhydropower purposes, and therefore conflict with state law.  For that reason, IPC continues to participatein the processes that are considering solutions, such as aquifer recharge, tothe conflict between ground and surface water interests in an effort to protectits existing hydroelectric generation water rights.  In February 2006, at the request of seniorsurface water interests, IPC entered into discussions with the State of Idahoand senior surface water interests to explore opportunities for engaging insome limited aquifer recharge in 2006 provided any adverse impact to IPC'shydropower generation and its customers is adequately addressed.  These discussions continue and are expectedto reach conclusion by mid-March or early April 2006.

**Clean Air:** The Environmental Protection Agency (EPA) issuedSulfur Dioxide (SO2) allowances, as defined in the Clean Air Actamendments of 1990, based on coal consumption during established baselineyears.  IPC currently has more than asufficient amount of SO2 allowances to provide compliance foremissions attributable to IPC at all three of its jointly-owned coal-firedfacilities and both of its natural gas-fired facilities.  Prior to the sale of 77,000 emissionallowance in 2005 and early 2006 discussed below in "EmissionAllowances," IPC believed that it had approximately 107,000 allowances inexcess of the amount needed for Clean Air Act compliance.  In addition, IPC has been granted annualallotments of allowances ranging from 15,524 to 28,622 through the year2035.  Allowances necessary for IPC'scompliance requirements are up to 14,500 annually.  Excess allowances owned by IPC may be heldfor future use, as they do not contain expiration terms.  There is an active marketplace for buying andselling allowances, so that SO2 allowances determined to be excesscan be sold to others.  For all theforegoing reasons, IPC does not foresee any adverse effects upon its operationswith regard to SO2 emissions at this time.  See further discussion in "REGULATORY ISSUES- Emission Allowances."

In March2005, the EPA issued two new rules limiting emissions from utility boilers, theClean Air Interstate Rule and the Clean Air Mercury Rule.  The Clean Air Interstate Rule will capemissions of SO2 and nitrogen oxides (NOx) in 28 easternstates and the District of Columbia.  TheClean Air Interstate Rule does not impose any restrictions on emissions fromany IPC facilities.  IPC does not foreseeany adverse effects upon its operations with regard to the Clean Air InterstateRule.

TheClean Air Mercury Rule (CAMR) will limit mercury emissions from new andexisting coal-fired power plants and creates a market-based cap-and-tradeprogram that will permanently cap utility mercury emissions in two phases.  Currently, power plants in the United States emitapproximately 48 tons of mercury per year. The first phase cap is 38 tons beginning in 2010, with a second phasecap set at 15 tons beginning in 2018. Mercury emission allocations have been set at the state level, but thestates have not allocated the allowances to individual utilities.  IPC is actively monitoring developments onthis issue and control equipment technology advances.  The CAMR is being challenged in court by anumber of environmental groups and some states. On October 21, 2005, the EPA granted requests from petitions toreconsider certain aspects of the CAMR. It is anticipated that this rule may require additional emissioncontrols and expenses at IPC's jointly-owned coal-fired facilities, althoughimpacts on future plant operations, operating costs and generating capacity arenot known at this time.

Other pendingor proposed air regulations or legislation could require IPC's jointly-ownedcoal-fired facilities to reduce plant emissions of SO2, NOxand other pollutants below current levels. These reductions could be required to address regional haze programs,acid rain, mercury emission regulations and possible re-interpretations andchanges to the federal Clean Air Act. Like many other coal-fired facilities in the United States, the JimBridger plant has received information requests from the EPA related to theplant's compliance with the New Source Review provisions of the Clean Air Act,which has resulted in discussions with the EPA and state regulatoryauthorities.  IPC may incur significantcosts to comply with tighter air emissions requirements in the future.  These potential costs are expected to consistprimarily of capital expenditures.

In July 1997, the EPA announced the National Ambient AirQuality Standards (NAAQS) for ozone and particulate matter (PM) and, in July1999, the EPA announced regional haze regulations for protection of visibilityin national parks and wilderness areas. On May 14, 1999, a federal court ruling blocked implementation of theNAAQS for ozone and PM.  In November2000, the EPA appealed to the U.S. Supreme Court to reconsider thatdecision.  The Supreme Court subsequentlyruled in favor of the EPA on February 27, 2001. The EPA has promulgated regulations designating areas of the country forattainment/non-attainment with these standards, and IPC's thermal plants arelocated in areas designated as attainment for both standards.  EPA and state efforts to implement the NAAQSare ongoing.  On January 17, 2006, the EPAproposed revisions to the PM NAAQS that potentially could make these NAAQS morestringent, and IPC continues to monitor the EPA's proposed revisions.  Litigation concerning the EPA's regional hazeregulations resulted in two separate court remands of the rule back to the EPAfor reconsideration.  On June 15, 2005,the EPA issued the Clean Air Visibility Rule (CAVR) to address the first courtremand.  On July 20, 2005, the EPAproposed revisions to the CAVR to address the second remand.  Although the impacts of the NAAQS for ozoneand particulate matter and the regional haze regulations 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.

**GlobalClimate Change: **The United States is currentlynot a party to the Kyoto Protocol to the United Nations Framework Convention onClimate Change (Protocol) that became effective for signatories on February 16,2005.  The Protocol process generallyrequires developed countries to cap greenhouse gas emissions at certain levelsfrom 2008 through 2012.

Greenhousegas emissions are the result of many natural and man-made processes including thecombustion of fossil fuels to generate electricity.  Carbon dioxide represents the largestquantity of greenhouse gases emitted at IPC's coal and gas generationunits.  Under median water conditions,the majority of IPC's generation is hydro-based which has negligible greenhousegas emissions compared to fossil-based generation.

Althoughit has not ratified the Protocol, the United States may adopt a national,mandatory greenhouse gas program at some point in the future.  At this time, IPC is unable to predict thepotential impacts of any future mandatory governmental greenhouse gaslegislative or regulatory requirements.

**REGULATORY ISSUES:**

**GeneralRate CaseIdaho:**  IPC filed its 2003 Idaho general rate casewith the IPUC on October 16, 2003.  TheIPUC approved an increase of $25 million in IPC's electric rates, an average of5.2 percent, in an order issued on May 25, 2004.  The rate increase became effective on June 1,2004.  Additionally, the IPUC approved areturn on equity of 10.25 percent and an overall rate of return of 7.85 percent.

On July13, 2004, after IPC petitioned the IPUC for reconsideration of certain items,the IPUC ordered rates increased by approximately $3 million, in light of theIPUC Staff's computational errors, on or before August 1, 2004.  The IPUC also agreed to reconsider an issuerelating to the determination of IPC's income tax expense.  As a result of this reconsideration, onSeptember 28, 2004, the IPUC issued separate orders approving two settlementagreements entered into on August 16, 2004, between IPC and the IPUC Staff.

In OrderNo. 29601, the IPUC approved the modification of the general rate case order toutilize IPC's statutory income tax rates to compute test year income taxexpense.  The rate case tax settlementallows IPC to continue its compliance with the normalization provisions of theInternal Revenue Code of 1986, as amended, and associated Treasury Regulations,and will allow IPC to continue to receive the benefits of accelerated taxdepreciation.  As a result, IPC computedand recorded monthly during the period June 1, 2004 through May 31, 2005 aregulatory asset (with interest accrued at a rate of one percent per annum) ofapproximately $12 million, or 2.2 percent, which is a one-year adjustment andwill expire on June 1, 2006.  The IPUCalso granted an ongoing adjustment of approximately $12 million, or 2.25percent, related to the rate case tax settlement.  The increase of 4.45 percent related to therate case tax settlement adjustments was effective June 1, 2005.

Additionally,IPUC Order No. 29600 resolved outstanding issues related to: (1) an unplannedoutage at one of the two units of Valmy in the summer of 2003, (2) a matterrelating to the expense adjustment rate for growth component of the PCA and (3)regulatory accounting issues related to a tax accounting method change in2002.  As a result, in September 2004,IPC established a regulatory liability of $19 million with a charge to PCAexpense.  A monthly credit ofapproximately $0.8 million is included in the PCA through May 2006, which willreduce this regulatory liability.  Alsoin September 2004, IPC reversed a $16 million regulatory tax liability byreducing income tax expense.  Thisregulatory tax liability was established in 2002 when IPC adopted a taxaccounting method change for capitalized overhead costs.

Thefinal result of IPC's 2003 Idaho general rate case was a $40 million increaseto the base Idaho jurisdictional revenue requirement, comprised of $25 millionin the initial order, $3 million related to computational errors and $12million in the order approving the rate case tax settlement.

IPCfiled a general rate case in October 2005, requesting the IPUC to approve anannual increase to its Idaho retail base rates of $44 million or 7.8percent.  Base rates primarily reflectIPC's cost of providing electrical service to its customers, includingequipment, vehicles and infrastructure.

OnFebruary 27, 2006, IPC, the IPUC staff and representatives of customer groupsfiled a proposed stipulation with the IPUC that, if approved, would settle thiscase.  The stipulation calls for an $18.1million increase, or 3.2 percent in IPC's annual electric rates.  If approved by the IPUC, the changes in ratesare expected to become effective on June 1, 2006.

The ratecase filing was made with six months of actual operating expenses and sixmonths of projected expenses.  The agreedto increase in rates was lower than the requested amount primarily due to threefactors:  (1) 2005 actual numbers weresignificantly less than those forecasted; (2) the overall rate of return agreedto was 8.1 percent compared to the 8.42 percent IPC requested (no specificreturn on equity was determined); and (3) net power supply costs were kept atlevels currently existing in rates.  As aresult of the settlement, IPC's overall rate of return will increase from the7.85 percent currently authorized.

**Oregon:** On September 21, 2004, IPC filedan application with the OPUC to increase general rates an average of 17.5percent or approximately $4.4 million annually.

Apartial settlement resolved most issues in a manner consistent with the final resultin the 2003 Idaho rate case.  The mostsignificant issue in this proceeding was the appropriate quantification of netpower supply expenses for purposes of setting rates.  The OPUC Staff proposed that net power supplyexpenses for IPC be set at a negative number - meaning that 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 bulk of IPC's rebuttal was directed atthis position.  A hearing was conductedon May 23, 2005.  The OPUC issued itsorder on July 29, 2005 authorizing an increase of $597,000 in annual revenuesfor an average of 2.37 percent.  The OPUCadopted the Staff argument for the negative net power supply costs, thus reducingIPC's initial rate request of $4.4 million by $2.4 million with this oneadjustment.

OnSeptember 26, 2005, IPC filed a complaint with the Circuit Court of MarionCounty, Oregon asking the court to reverse the portion of the OPUC's generalrate case order related to the determination of net power supply costs.

**Deferred Power Supply Costs**IPC's deferrednet power supply costs consisted of the following at December 31: 

** **

**2005**

** **

**2004**

Idaho PCA current year:

 

 

 

 

 

 

Deferral for the 2005-2006 rate year

$

-

 

$

22,778

 

Deferral for the 2006-2007 rate year

 

3,684

 

 

-

Irrigation Lost Revenues

 

-

 

 

13,290

Idaho PCA true-up awaiting recovery:

 

 

 

 

 

 

Authorized May 2004

 

-

 

 

11,415

 

Authorized May 2005*

 

28,567

 

 

-

Oregon deferral:

 

 

 

 

 

 

2001 costs

 

8,411

 

 

12,047

 

2005 costs

 

2,880

 

 

-

 

Total deferral

$

43,542

 

$

59,530

 

 

 

 

 

 

*$28 million will be recovered with interest during the  2006-2007 PCA rate year.

 

**Idaho:** IPC has a PCA mechanism that provides for annual adjustments to therates charged to its Idaho retail customers. These adjustments are based on forecasts of net power supply costs,which are fuel and purchased power less off-system sales, and the true-up ofthe prior year's forecast.  During theyear, 90 percent of the difference between the actual and forecasted costs isdeferred with interest.  The endingbalance of this deferral, called the true-up for the current year's portion andthe true-up of the true-up for the prior years' unrecovered portion, is thenincluded 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.  Eachmonth, the collection or the refund of the true-up amount is quantified basedupon the true-up portion of the PCA rate and the consumption of energy bycustomers.  At the end of the PCA year,the total collection or refund is compared to the previously determined amountto be collected or refunded.  Anydifference between authorized amounts and amounts actually collected orrefunded are then reflected in the following PCA year, which becomes thetrue-up of the true up.  Over time, theactual collection or refund of authorized true-up dollars matches the amountsauthorized.

On April15, 2005, IPC filed the 2005-2006 PCA with the IPUC with a proposed effectivedate of June 1, 2005.  The applicationproposed to hold the PCA component of customers' rates at the existing level,which is currently recovering $71 million above base rates.  By IPUC order, the 2005 - 2006 year's PCAincludes $12 million in lost revenues and $2 million in related interestresulting from IPC's Irrigation Load Reduction Program that was in place in2001.  IPC proposed to defer recovery of approximately$28 million of power supply costs, or 4.75 percent, for one year to helpmitigate the impacts of the $9 million, or 1.84 percent, increase for theBennett Mountain Power Plant and the $23 million, or 4.45 percent, increase dueto the rate case tax settlement adjustments. The $28 million will be recovered during the 2006-2007 PCA rate year,and IPC will earn a two percent carrying charge on this balance.  The IPUC accepted the company's PCA proposal.

**Oregon:**  On March 2, 2005,IPC filed for an accounting order to defer net power supply costs for theperiod of March 1, 2005 through February 28, 2006 in anticipation of continuedlow water conditions.  The forecasted netpower supply costs included in this filing were $169 million, of which $3million related to the Oregon jurisdiction. IPC is proposing to use the same methodology for this deferral filingthat was accepted in 2002 for Oregon's share of IPC's 2001 net power supplyexpenses.  On July 1, 2005, IPC, the OPUCstaff, and the Citizen's Utility Board entered into a stipulation requestingthat the OPUC accept IPC's proposed methodology.  Under this methodology, IPC will earn itsOregon authorized rate of return on the deferred balance and will recover theamount through rates in future years, as approved by the OPUC.

**Fixed-CostAdjustment Mechanism:**On January 27, 2006, IPC filed with the IPUC for authority to implement a rateadjustment mechanism which would adjust IPC's rates upward or downward torecover IPC's fixed costs independent from the volume of IPC's energy sales.  The filing is a continuation of an Idaho caseopened in 2004 to investigate the financial disincentives to investment inenergy efficiency by IPC.  The true-upmechanism, entitled "fixed-cost adjustment" (FCA) would be applicableonly to residential service and small general service customers.

The fixed-cost recovery portion of IPC's revenuerequirement allowed for recovery in rates would be established for these twocustomer classes at the time of a general rate case.  Thereafter, the FCA would provide a mechanismto true-up the collection of fixed costs to recover the difference between thefixed costs actually recovered through rates and the fixed costs that wereallowed to be recovered.  Accounting forthe FCA would be effective as of January 1, 2006, and the first FCA rate changewould occur on June 1, 2007.

The FCAis proposed to change rates coincidentally with IPC's Power Cost Adjustment(PCA) and IPC's seasonal rates.  Althoughthe FCA would be timed to adjust on the same schedule as the PCA, theaccounting for the FCA would be separate from the PCA.  Additionally, IPC proposes to include a threepercent cap on any FCA filing, to be applied at the discretion of the IPUC.

**Public Utility Regulatory Policies 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 is required to purchase all of the outputfrom the facilities located inside the IPC service territory.  For projects located outside the IPC serviceterritory, IPC is required to purchase the output that IPC has the ability toreceive at the facility's requested point of delivery on the IPC system.  The IPUC jurisdictional portion of the costsassociated with CSPP contracts are fully recovered through the PCA.  For IPUC jurisdictional contracts, projectsthat generate up to ten average MW of energy on a monthly basis are eligiblefor IPUC Published Avoided Costs for up to a 20-year contract term.  The Published Avoided Cost is a priceestablished by the IPUC and the OPUC to estimate IPC's cost of developingadditional generation resources.  OnAugust 4, 2005, the IPUC granted a temporary reduction in the eligible projectsize to 100 kW for intermittent generation resources only.  This temporary project size reduction willremain in place until studies are completed which will help the IPUC determineif the Published Avoided Cost should be revised for intermittent generationresources.  For OPUC jurisdictionalcontracts, projects that generate up to ten MW of capacity are eligible forOPUC Published Avoided Costs for up to a 20-year contract term.  The OPUC jurisdictional portion of the costsassociated with CSPP contracts is recovered throughgeneral rate case filings.  The Oregonprovisions are currently being reviewed in an OPUC proceeding.  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 reflect thecharacteristics 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.

Recent activities, including the extension of the FederalProduction Tax Credit and the expansion of the tax credit for eligibility tosolar, geothermal and other forms of generation, resolution of IPUC and OPUCPURPA-related hearings and the December 1, 2004 order by the IPUC increasingthe Published Avoided Costs, create a favorable climate for PURPA projectdevelopment, which may require IPC to enter into additional PURPAagreements.  The requirement to enterinto additional PURPA agreements may result in IPC acquiring energy at abovewholesale market prices, thus increasing costs to its customers.  Additionally, it is highly likely that therequirement to enter into additional PURPA agreements will add to IPC's surplusduring certain times of the year, potentially during off-peak hours.  This could also increase costs to IPC'scustomers.  As of December 31, 2005, IPChad signed agreements to purchase energy from 87 small power production (CSPP)facilities with contracts ranging from one to 30 years.  Of these facilities, 69 were on-line at theend of 2005; the other 18 facilities under contract are due to come on-line in2006 and 2007.  During 2005, IPCpurchased 715,209 MWh from these projects at a cost of $43 million, resultingin a blended price of 6.1 cents per kilowatt hour.

**EmissionAllowances**In June 2005,IPC filed applications with the IPUC and OPUC requesting blanket authorizationfor the sale of excess sulfur dioxide emission allowances and an accountingorder.  The IPUC issued Order 29852 onAugust 22, 2005, authorizing the sale and interim accounting treatment.  Pursuant to the Order, IPC is required tofile a report with the IPUC within 60 days after receipt of any saleproceeds.  The OPUC issued Order 05-983on September 13, 2005, stating that IPC did not need a blanket order to sellemission allowances and approved the interim accounting treatment.  The OPUC also ordered IPC to file a reportwithin 60 days after receipt of any sales proceeds and stated that ratemakingtreatment of the proceeds will be determined in a ratemaking proceeding.  Two reports on the sales proceeds have beenfiled with both the IPUC and the OPUC.

IPC isnow seeking approval from the IPUC for the accounting treatment of thesetransactions, which will determine the allocation of proceeds between retailcustomers and shareholders.  Order 29852stated that the IPUC Staff was to conduct workshops and make a recommendationas to the appropriate ratemaking treatment. Thus far, parties to the Idaho case have participated in two workshopsin November 2005 and one in February 2006 without reaching resolution.  Thus far, the matter is now set to be decidedby the IPUC via the submittal of comments and briefs by the parties to thecase.  A decision is anticipated by June1, 2006.

In 2005,IPC sold 69,500 allowances (out of a total of approximately 107,000 excessallowances) for approximately $71 million (before income taxes and expenses) onthe open market.  Through February 28, 2006,IPC has sold an additional 7,500 emission allowances for approximately $10million and plans to continue selling surplus allowances periodically as itdeems prudent in light of ongoing analysis of compliance requirements andmarket conditions.  Under the approvedinterim accounting treatment, IPC is recording the Idaho and Oregon allocatedportions of the proceeds (net of expenses) as a regulatory liability.  At this time, IPC cannot predict the outcomeof the IPUC process, or any future OPUC ratemaking proceeding relating to thisissue, or how the proceeds might ultimately be allocated between retailcustomers and shareholders.

**Integrated Resource Plan******IPC filed its2004 IRP with the IPUC and the OPUC in August 2004.  The 2004 IRP previewed IPC's load andresource situation for the next ten years, analyzed potential supply-side anddemand-side options and identified near-term and long-term actions.  The two primary goals of the 2004 IRP were to:(1) identify sufficient resources to reliably serve the growing demand forenergy service within IPC's service area throughout the 10-year planning periodand (2) ensure that the portfolio of resources selected balances cost, risk andenvironmental concerns.  In addition,there were two secondary goals: (1) to give equal and balanced treatment toboth supply-side resources and demand-side measures and (2) to involve thepublic in the planning process in a meaningful way.

The IRPis filed every two years with both the IPUC and the OPUC.  Prior to filing, the IRP requires extensiveinvolvement by IPC, the IPUC Staff and the OPUC Staff, as well as customer, technologicaland environmental representatives and is the starting point for demonstratingprudence in IPC's resource decisions. The IPUC accepted the 2004 IRP on April 22, 2005.  The OPUC acknowledged the 2004 IRP on June17, 2005.  The 2004 IRP includes thefollowing elements:

76-MW demand response programs; 

48-MW energy efficiency programs; 

100-MW geothermal-powered generation; 

48-MW combined heat and power at customer facilities; 

62-MW combustion turbine, distributed generation ormarket purchases;

500-MW coal-fired generation;

350-MW wind-powered generation; and

88-MW simple-cycle natural gas fired combustion turbine(peaking resource). 

The 2004IRP identified specific actions to be taken by IPC prior to the next IRP in2006.  IPC is in the process ofimplementing these actions.  DuringDecember of 2004, IPC issued two Requests for Proposal (RFPs) associated withan Air Conditioning Cycling Program. During 2005, IPC continued implementation of the 2004 IRP actionplan.  A Draft RFP for 100 MW of geothermal-poweredgeneration was released on January 18, 2006. Due to a PURPA developer's interest in constructing a large cogenerationproject in IPC's service territory, IPC has decided to suspend any further actionon the 48-MW combined heat and power RFP.

**Coal-firedResource Screening and Evaluation: **In the 2004 IRP, IPC identifiedthe need for seasonal-ownership of a coal-fired resource beginning in2011.  The 2004 IRP's Near-Term ActionPlan noted that during 2005 IPC would attempt to identify a utility partner forthis resource and that in 2006 IPC would issue an RFP for the coal-firedresource.  As a result of discussionswith potential resource participants, IPC and Spokane, Washington-based AvistaUtilities have entered into an agreement to jointly investigate possible futurecoal-fired resources.  Under thearrangement, the utilities will be studying the options for base loadcoal-fired generation to meet their collective IRP forecast needs.

**WindRFP:** An RFP for200 MW of wind-powered generation was issued on January 13, 2005.  The RFP requested deliveries of energy fromapproximately 100 MW of wind-powered generation commencing no later than theend of 2006 and deliveries of energy from all 200 MW commencing no later thanthe end of 2007.  Final bids were due onMarch 10, 2005.  The selection committeecompiled a short list of bidders then suspended further action until the IPUCcould process IPC's request for a moratorium on PURPA wind projects (see "PURPAWind Projects" below).  In lateSeptember IPC announced that it would reactivate the RFP, although IPC nowanticipates acquiring 100 MW through the process instead of the original 200MW.  Upon receipt of GenerationInterconnect Feasibility Studies for the short-listed projects, IPC will completeits evaluation of the proposals received in response to this RFP.

**PURPAWind Projects:  **As of January 2006, two windprojects, with a total nameplate capacity of 10.8 MW, are selling energy to IPCunder approved PURPA agreements.  Anadditional twelve wind projects, comprising 166.5 MW of wind generation, haveapproved PURPA agreements and are scheduled to come online during 2006 and2007.  The total nameplate capacity ofPURPA wind projects currently under contract is 177.3 MW.

As aresult of recent IPUC actions, IPC anticipates executing three additional PURPAwind agreements that will subsequently be submitted to the IPUC for approval.  These three agreements are expected toprovide an additional 50.4 MW of wind-powered generation.  If these agreements are signed and approvedby the IPUC, the total nameplate capacity of PURPA wind projects under contractwill increase to 227.7 MW.

On June17, 2005, IPC filed an application requesting the IPUC to issue an ordertemporarily suspending IPC's obligation under PURPA and various IPUC orders toenter into new contracts to purchase energy generated by wind-poweredqualifying facilities.  IPC requested thetemporary suspension remain in effect until the IPUC investigates the impact onIPC's customers arising out of the addition of substantial amounts ofwind-powered generation projects.  IPC isconcerned that the continuous absorption of additional wind resources willadversely affect IPC's overall power supply costs and system reliability.  IPC is also concerned that the apparent highprice for wind PURPA resources is impacting bid prices for the wind RFP.  On July 8, 2005, IPC submitted testimony insupport of the request.  On July 22,2005, the IPUC conducted a hearing on the matter and issued an order on August4, 2005 reducing the maximum size for projects eligible to receive publishedavoided cost rates to 100 kW from 10 MW and setting grandfathering criteria forPURPA wind projects in progress at the time of the order.  Currently, approximately 65 MW of proposedPURPA wind projects are actively seeking contracts from IPC through thegrandfathering criteria or via negotiated PURPA agreements.  The outcome of these agreement requests isunknown at this time.

**PeakingResource RFP: **On January 9, 2006, IPC selecteda Siemens-Westinghouse combustion turbine project in response to a RFP forconstruction of a natural gas-fired power plant, as identified in the 2004IRP.  IPC sought bids for theconstruction of a turnkey generating facility to expand its generationcapabilities during peak times when electricity supplies are low, electricityimport capabilities are reduced due to transmission constraints, or wholesale energycosts are high.  The plant is planned tobe on line prior to the summer of 2008. The proposal selected is for a Siemens-Westinghouse SGT6-5000Fcombustion turbine located at the Evander Andrews Power Complex near MountainHome, Idaho.  The unit will provideapproximately 166 MW of capacity to help meet summer load peaks and can providegreater capacity during cooler times of the year.  The Siemens-Westinghouse contract value isexpected to be between $48-$51 million following contract negotiations.  IPC plans to submit an application to the IPUCfor a Certificate of Public Convenience and Necessity before proceeding withthe project.

**2006 IRP:** Preparation has begun on the 2006 IRP with the initial meeting of theIRP Advisory Council held on October 20, 2005, and meetings are continuing on amonthly basis.  The planning period willchange from a ten-year forecast to a 20-year forecast.  The 2006 IRP is scheduled to be filed in June2006.

**Advanced Meter Reading**On February 21, 2003, the IPUC issued Order No. 29196, which directed IPC tosubmit a plan no later than March 20, 2003 to replace its existing meters withadvanced meters that are capable of both automated meter reading andtime-of-use pricing.  On April 15, 2003,the IPUC issued Order No. 29226, which modified and clarified Order No. 29196.  The requirement to commence installation in2003 was removed; however, IPC was expected to implement Advanced Meter Readingas soon as practicable, subject to updated analysis showing Advanced MeterReading to be cost effective for customers. As ordered by the IPUC, IPC submitted an updated analysis on May 9,2003.  A workshop with the IPUC Staff andother interested parties to discuss the analysis was held on May 19, 2003.  The IPUC issued Order No. 29291 on July 14,2003, providing interested parties the opportunity to submit comments regardingIPC's updated analysis.  On October 24,2003, the IPUC issued Order No. 29362, which directed IPC to collaborativelydevelop and submit a Phase One Advanced Meter Reading Implementation Plan toreplace current residential meters with advanced meters in selected serviceareas.  IPC complied with this order onDecember 23, 2003 by filing a Phase One Implementation Plan that targeted theEmmett, Idaho and McCall, Idaho areas for 2004 installation and 2005implementation.  Phase One is projected tocost $7 million and IPC included the 2005 costs in its Idaho General Rate Case.  Since April 2004, approximately 24,000advanced meters have been installed.  IPCsubmitted a report to the IPUC in December 2005 summarizing the Advanced MeterReading project and associated benefits and costs.  The IPUC has opened a comment periodextending to April 15, 2006 regarding the report.

**Relicensingof Hydroelectric Projects**IPC, like otherutilities that operate nonfederal hydroelectric projects on qualifiedwaterways, obtains licenses for its hydroelectric projects from the FERC.  These licenses last for 30 to 50 yearsdepending on the size, complexity, and cost of the project.  IPC recently received new licenses for fiveof its middle Snake River projects and the Malad project.  IPC's hydroelectric project license for theHells Canyon Complex expired at the end of July 2005 and the Swan Falls projectlicense will expire in 2010.  IPC isactively pursuing the relicensing of these projects, a process that maycontinue for the next ten to fifteen years.

**MiddleSnake River Projects:**  IPC's middle Snake River projects consist ofthe Bliss, Upper Salmon Falls, Lower Salmon Falls, Shoshone Falls and CJ Strikeprojects.  On August 4, 2004, IPCreceived the FERC license orders for each of the middle Snake Riverprojects.  Each license is for a 30-yearduration effective August 1, 2004.  Acentral component of each license order is a Settlement Agreement between IPC andthe U.S. Fish and Wildlife Service regarding five snail species that inhabitthe middle Snake River, which are listed as threatened or endangered speciesunder the Endangered Species Act (ESA). As a basis for the settlement, IPC and the U.S. Fish and WildlifeService agreed that additional studies and analyses are needed in order toaccurately assess the effect, if any, that the middle Snake River projects mayhave on one or more of the listed snail species.  The Settlement Agreement provides anoperational regime for the five projects that will permit six years of studiesand analyses of various project operations on the listed snail species, whileproviding interim protection of the listed species.  The study began in 2004.  After the studies are complete, IPC, inconsultation with the U.S. Fish and Wildlife Service, will develop a plan thataddresses project operation and the protection of listed snails for theremainder of the new license terms.

OnSeptember 2, 2004, two conservation groups, American Rivers and Idaho RiversUnited, filed petitions for rehearing of the orders issuing the licenses forthe middle Snake River projects.  Thesepetitions ask the FERC to vacate the licensing orders and request adetermination from the U.S. Fish and Wildlife Service that the middle SnakeRiver projects jeopardize the listed snail species.  On October 4, 2004, the FERC issued an OrderGranting Rehearing for Further Consideration to provide additional time toconsider the matters raised by the rehearing requests.  On March 4, 2005, the FERC issued an orderdenying the conservation groups' rehearing request.  On April 28, 2005, American Rivers and IdahoRivers United appealed this order to the U.S. Court of Appeals for the NinthCircuit.  IPC filed a motion to intervenein the appeal and the U.S. Fish and Wildlife Service filed a motion to bedesignated a respondent-intervenor.  OnJune 15, 2005, the court granted these motions. By order dated October 4, 2005, the court extended the briefing schedulein the appeal.  Pursuant to the extendedschedule, American Rivers and Idaho Rivers United filed their briefs with thecourt on October 14, 2005 and the FERC filed its brief on December 16,2005.  IPC's and Fish and Wildlife'sbriefs were filed on January 27, 2006. American Rivers and Idaho Rivers United filed a reply brief andsupplemental record on February 28, 2006.

Severalof the new license articles for the middle Snake River projects required IPC tofile additional information with the FERC either upon license issuance orwithin 30, 45 or 60 days following license issuance.  IPC has made these required filings.

Many ofthe new license articles require IPC to develop comprehensive plans forProtection, Mitigation and Enhancement (PM&E) measures and submit them tothe FERC for approval.  The plans were duewithin six months to one year following license issuance and were required tohave detailed costs, schedules and methods for implementing the PM&Emeasures.  IPC has submitted these plansto the FERC.

Plansfor each license include White Sturgeon Conservation, Recreation Management,Middle Snake River and CJ Strike Wildlife Management Area land management,Minimum and Aesthetic Water Flows, Water Quality Monitoring, HistoricProperties Management, Spring Habitat Protection, Fish Stocking and OperationalCompliance Monitoring.

Costestimates for the plans to implement required PM&E measures are $10 millionin capital and $2 million in additional annual operation and maintenanceexpense.  Most of the capitalexpenditures will occur within the first five years of the licenses.  Since the plans have not yet been accepted bythe FERC, the cost estimates are preliminary. Additionally, cost estimates do not include any PM&E measures thatmay be required as a result of the Settlement Agreement snail studies andanalysis described above.

At December31, 2005, $9 million of middle Snake River project relicensing and compliancecosts were in electric plant in service. The majority of these costs, which were incurred prior to the completionof IPC's 2003 Idaho general rate case, were approved for recovery inrates.  Costs incurred since the 2003general rate case are included in the 2005 general rate case filing.  Future costs related to the new license willbe submitted to regulators for recovery through the ratemaking process.

**MaladProject: **On March 25, 2005, IPC received anew 30-year operating license for the Malad project.  The new license was effective March 1, 2005and includes license article requirements to address project operations,minimum flow to benefit aquatic species, ESA snail protection and monitoring,habitat enhancements, fish passage, recreation enhancements and historicproperties.  IPC has developed projectplans, schedules and cost estimates for each article, the last of which will befiled with the FERC by March 2006.

Cost estimatesfor the plans to implement required PM&E measures are $2 million in capitaland $1 million in additional annual operation and maintenance expense.  Most of the capital expenditures will occurwithin the first five years of the license. A fish passage plan, to be filed by March 25, 2006, includes a lowerdiversion fish ladder.  If the plan isapproved, construction will commence in 2008. If the proposed fish ladder is successful in addressing intendedenvironmental issues, then a second fish passage structure will be built.  A second structure will result in additionalcapital expenditure of approximately $2 million sometime during the 2010-2015timeframe.  Because the plans have notyet been accepted by the FERC, the cost estimates are preliminary.

AtDecember 31, 2005, $3 million of Malad project relicensing costs were includedin electric plant in service and are included in the 2005 Idaho general ratecase filing.  Future costs related to thenew license will be submitted to regulators for recovery through the ratemakingprocess.

**HellsCanyon Complex:** The most significant ongoing relicensingeffort is the Hells Canyon Complex, which provides approximately two-thirds ofIPC's hydroelectric generating capacity and 40 percent of its total generatingcapacity.  The current license for theHells Canyon Complex expired at the end of July 2005.  IPC now operates the project under an annuallicense issued by the FERC until the new multi-year license is issued.  IPC developed the license application for theHells Canyon Complex through a collaborative process involving representativesof state and federal agencies and business, environmental, tribal, customer,local government and local landowner interests. The license application was filed in July 2003 and accepted by the FERCfor filing in December 2003.

Thelicense application includes the continuation of existing, as well as proposednew measures intended to protect, mitigate and enhance fish and wildlife,protect recreational opportunities and preserve other aspects of environmentalquality.  The estimated costs of thesePM&E measures are approximately $106 million in the first five years of alicense and $218 million over the following 25 years, for a total estimatedcost of $324 million over a 30-year license. These cost estimates do not include estimated costs of proposed waterquality measures included in the license application.  These measures are the subject of ongoingstate processes under Section 401 of the Clean Water Act.  IPC estimates that costs associated withthese water quality measures may result in an additional cost of $62 million,for a total estimated cost of $386 million. These estimated costs could increase as a result of the licensing processas the FPA requires that the FERC consider, and include in the license,conditions to ensure that the project is consistent with the comprehensive development of the water resource forthe improvement and utilization of hydropower development, and for the adequateprotection, mitigation and enhancement of fish and wildlife resources and otherbeneficial public uses.  The conditions included in the final licensemay include mandatory conditions and prescriptions proposed by federalagencies.  Under the FPA, some federalagencies have mandatory conditioning authority. Section 18 of the FPA provides the Departments of Commerce and the Interiorwith authority to require fishways, or passage facilities, to allow fish tomigrate below and above a project. Section 4(e) allows federal agencies with jurisdiction over a federalreservation, such as a national forest or park that is occupied by a licensedproject, to require the FERC to include in the license such conditions andprescriptions that the federal agency considers necessary for the adequateprotection and utilization of that reservation. The FERC must include in the license those conditions and prescriptionsproposed by these agencies, which fall within that agency's conditioningauthority, under the FPA.  Theseconditions and prescriptions, however, must be supported by substantialevidence and otherwise be in compliance with the provisions of the EnergyAct.  If they are not, a federal appealscourt may set the conditions and prescriptions aside.  In other words, the agencies have the authorityto require actions to be included in a license to protect resources or addressissues under their jurisdiction.  Assuch, the actual costs of the PM&E measures associated with the relicensingof the Hells Canyon Complex will not be known until after the new license isissued by the FERC.

In response to the filing of the license application inJuly 2003, federal and state agencies, Native American Indian Tribes and otherparticipants in the Hells Canyon Complex relicensing process filed initial commentsto the license application, some of which contained additional proposedPM&E measures.  IPC's initialestimate of the potential cost of the measures proposed in these initialcomments, assuming all of the proposed measures were included as conditions ina final license, which IPC believes is unlikely, totaled more than $2 billionover a period up to 50 years.  IPC'spreliminary estimate is that this would result in an approximate 25 to 30percent increase to existing base rates. These cost estimates, however, are preliminary as federal, state, tribaland private parties participating in the relicensing proceeding are notrequired to file their final comments, recommendations, terms, conditions andprescriptions with the FERC until later in the relicensing process.  The FERC has recently issued its Notice ofReady for Environmental Analysis (NREA), which requires the agencies, 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 of 2005 and other applicable federal laws. These preliminary recommendations, conditions, and prescriptions will beprocessed as part of the licensing and NEPA process outlined below, and whenfiled with the FERC, will provide IPC with a better indicator of the type andnature of PM&E measures that may be included in final license.  When the comments, recommendations, terms,conditions and prescriptions become final, the FERC will consider them andinclude those conditions in the final license that the FERC determines arenecessary and required to protect, mitigate and enhance those resourcesaffected by the operation and management of the project, including anymandatory conditions or prescriptions proposed under Sections 4(e) or 18 of theFPA.

AtDecember 31, 2005, $76 million of Hells Canyon Complex relicensing costs were includedin construction work in progress.  Therelicensing costs are recorded and held in construction work in progress untila new multi-year license is issued by the FERC, at which time the charges aretransferred to electric plant in service. Relicensing costs and costs related to a new license, as discussedabove, will be submitted to regulators for recovery through the ratemakingprocess.

NEPAProcess:  NEPA requires that the FERC independentlyevaluate the environmental effects of relicensing the Hells Canyon Complex asproposed under the final license application (the proposed action) and alsoconsider reasonable alternatives to the proposed action.  Consistent with the requirements of NEPA, theFERC Staff will prepare an environmental impact statement for the Hells Canyonproject, which the FERC will use to determine whether, and under whatconditions, to issue a new license for the project.  The environmental impact statement willdescribe and evaluate the probable effects, if any, of the proposed action andthe other alternatives considered.  Aspart of the NEPA process, the FERC initiated a scoping process to supportpreparation of the environmental impact statement and help ensure that allpertinent issues are identified and analyzed.

On October 20, 2003, the FERC issued Scoping Document 1to provide interested parties with information on the relicensing of theproject and solicit comments and suggestions for a preliminary list of issuesand alternatives that might be addressed in the environmental impactstatement.  The FERC also held fourscoping meetings in the fall and winter of 2003 to offer parties theopportunity for input on the scope of the environmental impact statement.  Based upon comments and information receivedin response to Scoping Document 1, on November 24, 2004, the FERC Staff issuedScoping Document 2, which provides for a tentative schedule for theenvironmental impact statement preparation including the filing of additionalinformation.  Subsequent to the issuanceof Scoping Document 2, IPC and a number of other parties participating in theFERC licensing process requested that the FERC revise the tentative schedule toenable the parties to pursue comprehensive settlement discussions in an effortto reach agreement for the relicensing of the Hells Canyon Complex. (see"Consultation/Settlement Process" discussion below)  To facilitate settlement efforts, the FERCextended the NEPA schedule, delaying the issuance of the NREA until the fall of2005.  The FERC issued the NREA onOctober 28, 2005.  Federal and stateagencies, Native American Indian Tribes and other participants in therelicensing process filed preliminary comments, recommendations, terms,conditions and prescriptions with the FERC in January 2006.  Reply comments by IPC, or other participantsin the process, are to be filed by April 11, 2006.  The FERC will consider these filings asrequired by the FPA and NEPA and under its current schedule will issue a draftenvironmental impact statement in July 2006 and a final environmental impactstatement in January 2007.

Consultation/SettlementProcess:  In an effort to resolve issues associatedwith the relicensing of the Hells Canyon Complex, IPC has been engaged indiscussions with the FERC and relevant federal and state agencies on theeffects, if any, of the relicensing of the project on species listed asthreatened or endangered under the ESA. The National Marine Fisheries Service listed Snake River sockeye asendangered in 1991, Snake River spring, summer and fall chinook as threatenedin 1992 and Snake River steelhead as threatened in 1997.  In June 1998, the U.S. Fish and WildlifeService also listed bull trout in the Columbia and Klamath River basins asthreatened.  From 1997 to 2004,discussions with the National Marine Fisheries Service and other federal, stateand tribal interests on issues associated with the effect of the Hells CanyonComplex operations on ESA-listed species and aquatic resources below the HellsCanyon Complex were in the context of the Snake River Basin Adjudicationmediation process.

In July2004, the FERC requested formal consultation with the National Marine FisheriesService regarding the effects of interim Hells Canyon Complex operations onESA-listed species and issued a notice to all interested parties of an ESAconsultation meeting on September 9, 2004 to discuss how to proceed withconsultation, including how to integrate the ongoing Hells Canyon Complexrelicensing settlement discussion into the consultation process.

OnSeptember 7, 2004, IPC submitted a letter to the FERC regarding the September9, 2004 consultation meeting, advising that IPC, the National Marine FisheriesService and the U.S. Fish and Wildlife Service had explored opportunities toaddress ESA issues associated with the interim operations and the relicensingof the Hells Canyon Complex through a negotiated settlement process.

At theSeptember 9, 2004 meeting, IPC, the National Marine Fisheries Service and theU.S. Fish and Wildlife Service discussed a proposed settlement process with theFERC Staff and other interested parties in attendance.  At the conclusion of that meeting, theparties, with the concurrence of the FERC Staff, expressed an interest inengaging in additional discussions intended to reach agreement on anorganizational structure for implementing the Hells Canyon ESA Consultation/SettlementProcess.

In lateSeptember 2004, IPC, the National Marine Fisheries Service, the U.S. Fish andWildlife Service and other parties, including the states of Idaho and Oregon,the U.S. Forest Service, several Native American Indian Tribes, AmericanRivers, Idaho Rivers United, and Idaho irrigation and industrial entitiesinterested in the relicensing of the Hells Canyon Complex met to continuediscussions relative to the initiation of the Hells Canyon ESAConsultation/Settlement Process.  As aresult of that meeting, the parties established a Hells Canyon Complexsettlement process in the fall of 2004, which included a Settlement WorkingGroup, a facilitator and separated FERC Staff. The initial objective of the Settlement Working Group was to addressinterim operations and issues related to aquatic species listed under theESA.  The primary objective of theSettlement Working Group, however, was to explore opportunities to negotiateand develop a comprehensive settlement agreement to support the relicensing ofthe project.  The goal of the parties wasto achieve an agreement in principle relative to this primary objective bySeptember 2005.  Parties participating inthe Settlement Working Group included IPC, the National Marine Fisheries Service,the U.S. Fish and Wildlife Service, the U.S. Bureau of Land Management, theU.S. Bureau of Reclamation, the U.S. Department of Agriculture - ForestService, the State of Oregon, the State of Idaho, the Nez Perce Tribe, theShoshone-Paiute Tribes, the Shoshone-Bannock Tribes, the Burns-Paiute Tribe,American Rivers, Idaho Rivers United, the Idaho Water Users Association, thePayette River Water Users Association, the Pioneer, Settlers and Nampa andMeridian irrigation districts, the Committee of Nine, the Idaho Farm Bureau,the Columbia River Inter-Tribal Fish Commission, the Idaho Council on Industryand the Environment, the J. R. Simplot Company and other industrial customersof IPC.

Followingexpedited negotiations, on January 7, 2005, IPC filed an agreement on interimoperations (Interim Agreement) with the FERC. The Interim Agreement was executed by IPC, American Rivers, Idaho RiversUnited, the National Marine Fisheries Service, the U.S. Fish and Wildlife Service,the U.S. Department of Agriculture - Forest Service, the U.S. Bureau of LandManagement, the Oregon Departments of Fish and Wildlife and EnvironmentalQuality, the Nez Perce Tribe, the Shoshone-Bannock Tribes and theShoshone-Paiute Tribes.  The InterimAgreement addresses issues relating to operations of the Hells Canyon Complexand ESA-listed species in advance of the issuance of a new license while theparties to the settlement process participated in negotiations for acomprehensive settlement agreement.  Inaccordance with the provisions of the Interim Agreement, IPC agreed toimplement certain measures until a new license is issued for the Hells CanyonComplex including monitoring flows above the Hells Canyon Complex to protectexisting rights, the leasing and passing of certain U.S. Bureau of Reclamationflow augmentation water, continuing its fall chinook plan, identifying andmonitoring potential stranding sites from March 1 through May 31 of each yearand continuing to fund its hatchery program. IPC has also agreed to implement certain additional measures on anannual basis, provided that the parties remain engaged in settlementdiscussions intended to resolve long-term relicensing issues including, subjectto certain variables, flow augmentation to aid anadromous fish migration, theshaping of U.S. Bureau of Reclamation storage water, establishing procedures tocollect the data and information necessary in the relicensing settlementdiscussions, identifying, developing and reviewing potential structuralmodifications to address dissolved oxygen, total dissolved gas and seasonalwater temperatures, providing water quality information to supportconsultations under Section 401 of the Clean Water Act and sharing informationregarding native resident and anadromous fish passage through the Hells CanyonComplex.  The signatories agree that themeasures in the Interim Agreement are intended to provide reasonable protectionfor ESA-listed species during the term of the Interim Agreement and also establisha basis for comprehensive settlement discussions to continue.  Although the settlement discussions haveconcluded (see below), IPC has agreed to implement the measures of the InterimAgreement through 2006. 

Afterthe filing of the Interim Agreement with the FERC, the Settlement Working Group,with the continuing assistance of the facilitator and separated FERC Staff,commenced negotiations on the long-term settlement agreement.  These negotiations continued through the fallof 2005, but due to the number and complexity of the issues, the parties werenot successful in reaching an agreement in principle for the licensing of theHells Canyon Complex.  Because it wasunlikely that the parties to the settlement process would reach agreement on acomprehensive settlement package in advance of the issuance of the NREA by theFERC in October 2005, the settlement discussions were terminated to allow theparties the opportunity to develop comments and preliminary terms andconditions for filing with the FERC.  Theparties expect to reassess opportunities for settlement in the spring of 2006after the filings with the FERC and the proceedings provided for by the EnergyAct have concluded.

The Energy Policy Act of 2005: The Energy Act was signed intolaw on August 8, 2005.  Section 241 ofthe Energy Act modifies the existing hydroelectric relicensing process underthe FPA.  The Energy Act requires federalresource agencies with authority to impose mandatory conditions on licensesunder Sections 4(e) or 18 of the FPA (conditions that the FERC must include inthe license, see discussion above) to provide license applicants, and otherparties to the licensing process, with evidentiary hearings on disputed issuesof material fact related to proposed conditions.  It also requires that such agencies accept morecost effective alternative conditions proposed by license applicants, or otherparties, provided that the proposed alternative conditions will be no lessprotective of the resource or the reservation than the original conditionrecommended by the agency.  Pursuant tothe provisions of the Energy Act, the Departments of the Interior, Commerce andAgriculture promulgated interim final rules on November 17, 2005 providing forspecific procedures and time frames for implementing the evidentiary hearingprovisions of the Energy Act and for proposing alternative conditions to theagencies.  Pursuant to these rules, IPCand other parties to the licensing process must file requests for evidentiaryhearings on disputed issues of material fact and proposed alternativeconditions within 30 days of the agency's filing of their preliminary terms andconditions.  IPC filed requests forhearing on February 27, 2006.  Within 45days thereafter, the agencies must respond to the hearing requests and theevidentiary hearings are to be held within 90 days thereafter.  IPC is now preparing for the proceedingscontemplated by the Energy Act. 

**Swan Falls Project:**  Thelicense for the Swan Falls hydroelectric project expires in 2010.  On March 10, 2005, IPC initiated formal consultationwith agencies, Native American tribes and the public regarding the relicensingof the Swan Falls project.  This was doneby providing interested stakeholders with detailed information on the SwanFalls project.  In addition, a site tourand meeting for interested stakeholders was held on May 2, 2005.  IPC is in the process of compilinginformation and performing studies in preparation for filing an application fora new license with the FERC in 2008.

AtDecember 31, 2005, $2 million of Swan Falls project relicensing costs wereincluded in construction work in progress. 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 are transferred to electric plant in service.  Relicensing costs and costs related to a newlicense will be submitted to regulators for recovery through the ratemakingprocess.

**Regional TransmissionOrganizations**In December 1999, the FERC, in OrderNo. 2000, encouraged all companies with transmission assets to form regionaltransmission organizations (RTOs).  Byencouraging the formation of RTOs, the FERC sought to further facilitate theformation of efficient, competitive wholesale electricity markets.  In response, several northwest utilities,including IPC, attempted formation of an RTO called RTO West, which eventuallyevolved into Grid West, a transmission management entity that would notnecessarily become an RTO.  In July 2005,the FERC acknowledged that Grid West would not need to satisfy their RTOrequirements, but did acknowledge that the Grid West governance wassufficiently independent to satisfy the independence requirements of an RTO.

By September 2005, the GridWest technical design was complete and the process was begun to commit thenecessary funding to transfer corporate control to a new independent governingboard and provide for continued development. Since then, two major funding entities, the Bonneville PowerAdministration and the British Columbia Transmission Corporation, have declaredthey are unable to commit to this developmental funding.  Recently, Grid West has developed a plan toaccelerate development and provide limited near-term services at a potentiallymuch lower cost than the original proposal. The remaining utilities are now in the process of deciding whether tofund the next stages of development on the basis of this new plan.

IPC has spent funds supporting the development ofGrid West, and expects to continue funding as long as Grid West remains viableand IPC remains a participating utility. Funding of this effort has taken two forms.  First, funds have been loaned to Grid Westfor the purpose of meeting its developmental expenses.  The total accumulated loan through the fourthquarter of 2005 was approximately $1.0 million. IPC expects this loan to be repaid by Grid West when it commencesoperation.  Second, IPC has incurredincremental internal costs from participating in the developmental effort,which are mostly related to incremental travel and legal consultation.  Prior to 2005, IPC had accumulated thesecosts in a deferred expense account.  Thetotal accumulated internal expense through the fourth quarter of 2004 wasapproximately $2.3 million.  Inrecognition of Grid West's decision at the end of 2004 to take a significantfirst step toward operation, IPC decided that, beginning in 2005, alladditional incremental costs related to Grid West development activities wouldbe expensed rather than deferred.  Atthis time, IPC expects to pursue recovery of the accumulated internal coststhrough rates.

**FERCMarket-Based Rate Authority**IPC hasFERC-approved market-based rate authority, which permits IPC to sell electricenergy at market-based rates rather than cost-based rates.  Every three years, the FERC requires a reviewof the 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 ordercommencing a market power analysis of all companies with market-based rateauthority, including IPC.  In September2004, IPC filed a revision of its market power analysis (based on 2003 data),which it supplemented in September and October 2004.  On March 3, 2005, the FERC issued an order acceptingIPC's market power analysis.  IPC isrequired to file another market power analysis on or before March 3, 2008.

On May2, 2005 IPC filed a "Notice of Change in Status" in accordance withFERC requirements to report the addition of Bennett Mountain Power Plant, whichIPC acquired on March 31, 2005.  Thepurpose of the filing is to explain whether, and if so, how, the addition ofBennett Mountain reflects a departure from the characteristics the FERC reliedon when it authorized IPC to make sales at market-based rates.

The May2005 filing included an updated generation market power study that utilizedoriginal 2003 data as well as pertinent 2004 data.  The results showed that, with the addition ofBennett Mountain, IPC still passed both of the FERC's market power screens inall relevant control areas.

OnDecember 9, 2005, the FERC staff requested that IPC perform a completegeneration market power study for the IPC control area using 2004 data.  IPC has completed the study and is awaiting aresponse from the FERC.

**OTHERMATTERS:******

**AdoptedAccounting PronouncementsFIN 46(R): **In January 2004, IDACORP and IPC adopted FIN 46(R),which addresses consolidation by business enterprises of variable interest entities,which have one or more of the following characteristics:
- The equity investment at risk is not sufficient     to permit the entity to finance its activities without additional     subordinated financial support provided by any parties, including the     equity holders;
- The equity investors     lack one or more of the following essential characteristics of a     controlling financial interest:
The direct or indirect ability to make      decisions about the entity's activities through voting rights or similar      rights;
The obligation to absorb the expected losses      of the entity;
The right to receive the expected residual      returns of the entity; and

- The equity investors have voting rights that     are not proportionate to their economic interests and the activities of     the entity involve or are conducted on behalf of an investor with a     disproportionately small voting interest.  

IDACORP and IPC evaluatedtheir investments, contracts and other potential variable interests that wouldbe subject to the provisions of FIN 46(R), and IDACORP determined that it mustconsolidate two entities under those provisions.  At adoption, total assets and liabilitieseach increased by $29 million and consisted primarily of property and long-termdebt.  Cash flows of the newly consolidatedentities are included on IDACORP's Consolidated Statement of Cash Flows fromthe date of adoption.  Net income was notaffected by the adoption of the interpretation.

**FIN 47: **In 2005, IDACORP and IPC adoptedFIN 47.  This Interpretation clarifiesthat the term "conditional asset retirement obligation"(ARO) as usedin FASB Statement No. 143, refers to a legal obligation to perform an assetretirement activity in which the timing and/or method of settlement areconditional on a future event that may or may not be within the control of theentity.  The obligation to perform theasset retirement activity is unconditional even though uncertainty exists aboutthe timing and/or method of settlement. Thus, the timing and/or method of settlement may be conditional on afuture event.  Accordingly, an entity isrequired to recognize a liability for the fair value of a conditional ARO ifthe fair value of the liability can be reasonably estimated.  The fair value of a liability for theconditional ARO should be recognized when incurred - generally uponacquisition, construction, or development and/or through the normal operationof the asset.  Uncertainty about thetiming and/or method of settlement of a conditional ARO should be factored intothe measurement of the liability when sufficient information exists.  FAS 143 acknowledges that, in some cases,sufficient information may not be available to reasonably estimate the fairvalue of an ARO.  The Interpretation alsoclarifies when an entity would have sufficient information to reasonably estimatethe fair value of an ARO.

 FIN 47 became effective December 31,2005.  After reviewing the provisions ofFIN 47, no additional ARO's were identified at IPC.  One ARO was identified at IDACOMM.  Upon adoption, IDACOMM recorded an AROliability of $0.4 million and a related asset of $0.4 million.

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

**Inflation**IDACORP and IPCbelieve that inflation has caused and will continue to cause increases incertain operating expenses and the replacement of assets at higher costs.  Inflation affects the cost of labor, productsand services required for operations, maintenance costs and capitalimprovements.  While inflation has nothad a significant impact on IDACORP's or IPC's operations, costs for productsand services are subject to increases. IPC is subject to rate-of-return regulation and the impact of inflationon the level of cost recovery under regulation. Increases in utility costs and expenses due to inflation could have anadverse effect on earnings because of the need to obtain regulatory approval torecover such increased costs and expenses.

**ITEM7A.  QUANTITATIVE AND QUALITATIVEDISCLOSURES ABOUT MARKET RISK**

IDACORP and IPC are exposed to various marketrisks, including changes in interest rates, changes in commodity prices, creditrisk and equity price risk.  Thefollowing discussion summarizes these risks and the financial instruments,derivative instruments and derivative commodity instruments sensitive tochanges in interest rates, commodity prices and equity prices that were held atDecember 31, 2005.

**Interest Rate Risk**IDACORP and IPCmanage interest expense and short- and long-term liquidity though a combinationof fixed rate and variable rate debt. Generally, the amount of each type of debt is managed through marketissuance, but interest rate swap and cap agreements with highlyratedfinancial institutions may be used to achieve the desired combination.

**VariableRate Debt:** As of December 31, 2005, IDACORP and IPC had$133 million and $74 million, respectively, in floating rate debt, net oftemporary investments.  Assuming nochange in either company's financial structure, if variable interest rates wereto average one percentage point higher than the average rate on December 31,2005, interest expense would increase and pre-tax earnings would decrease byapproximately $1 million for both IDACORP and IPC.

**FixedRate Debt:**  As of December 31, 2005, IDACORP and IPC hadoutstanding fixed rate debt of $920 million and $865 million,respectively.  The fair market value ofthis debt was $937 million and $881 million, respectively.  These instruments are fixed rate, andtherefore do not expose IDACORP or IPC to a loss in earnings due to changes inmarket interest rates.  However, the fairvalue of these instruments would increase by approximately $84 million forIDACORP and $83 million for IPC if interest rates were to decline by onepercentage point from their December 31, 2005 levels.

**Commodity Price Risk****Utility:** IPC's exposure to changes in commodity priceis related to its ongoing utility operations producing electricity to meet thedemand of its retail electric customers. The weather is a major uncontrollable factor affecting the local andregional demand for electricity and the availability and price ofproduction.  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.

IPC'sexposure to commodity price risk is largely offset by thepreviously discussed PCA mechanism.  IPChas adopted a risk management program designed to reduce exposure to power supplycost-related uncertainty, further mitigating commodity price risk.  This program has been reviewed and acceptedby 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).  The Risk Management Committee (RMC),comprised of IPC officers and other senior staff, oversees the risk managementprogram.  The RMC is responsible forcommunicating the status of risk management activities to the IDACORP Board ofDirectors, and to the CAG.

ThePolicy requires monitoring monthly volumetric electricity position and totaldollar (net power supply cost) exposure on a rolling 18-month forwardview.  The Power Supply business unitproduces and evaluates projections of the operating plan and orders riskmitigating actions dictated by the limits stated in the Policy.  The RMC evaluates the actions initiated byPower Supply for consistency and compliance with the Policy.  IPC representatives meet with the CAG atleast annually to assess effectiveness of the limits.  Changes to the limits can be endorsed by theCAG and referred to the Board of Directors for approval.  The primary tools for risk mitigation arephysical forward power transactions and fueling alternatives for utility-ownedgeneration resources.

**Credit RiskUtility:**  IPC issubject to credit risk based on its activity with market counterparties.  IPC is exposed to this risk to the extentthat a counterparty may fail to fulfill a contractual obligation to provideenergy, purchase energy or complete financial settlement for marketactivities.  IPC mitigates this exposureby actively establishing credit limits, measuring, monitoring, reporting, usingappropriate contractual arrangements and transferring of credit risk throughthe use of financial guarantees, cash or letters of credit.  A current list of acceptable counterpartiesand credit limits is maintained.

**Energy:** As part of the 2003 sale of IE's forward book of electricity tradingcontracts, IE entered into an Indemnity Agreement with Sempra Energy Tradingguaranteeing the performance of one of the counterparties.  The maximum amount payable by IE under theIndemnity Agreement is $20 million.  In2005, under the terms of the guarantee, IE made $10 million in margindeposits.  IE expects this amount to berefunded no later than the end of the guarantee in 2009.  The Indemnity Agreement has been accountedfor in accordance with FIN 45 and did not have a significant effect onIDACORP's financial statements.

**Equity Price Risk**IDACORP and IPC are exposed to price fluctuations in equity markets,primarily through their pension plan assets, a mine reclamation trust fundowned by an equity-method investment of IPC and other 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.

**ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA**

**INDEX TO FINANCIAL STATEMENTS AND FINANCIALSTATEMENT SCHEDULES**

 

**PAGE**

**Consolidated Financial  Statements:**

 

IDACORP,  Inc.

 

Consolidated  Statements of Income for the Years Ended December 31, 2005, 2004 and 2003

61

Consolidated  Balance Sheets as of December 31, 2005 and 2004 

62-63

Consolidated  Statements of Cash Flows for the Years Ended December 31, 2005, 2004 and 2003

64

Consolidated  Statements of Shareholders' Equity for the Years Ended December 31, 2005,  2004

 

 

and  2003

65

Consolidated  Statements of Comprehensive Income for the Years Ended December 31, 2005,

 

 

2004  and 2003

66

** **

 

Idaho  Power Company

 

Consolidated  Statements of Income for the Years Ended December 31, 2005, 2004 and 2003

67

Consolidated  Balance Sheets as of December 31, 2005 and 2004

68-69

Consolidated  Statements of Capitalization as of December 31, 2005 and 2004

70

Consolidated  Statements of Cash Flows for the Years Ended December 31, 2005, 2004 and 2003

71

Consolidated  Statements of Retained Earnings for the Years Ended December 31, 2005, 2004

 

 

and  2003

72

Consolidated  Statements of Comprehensive Income for the Years Ended December 31, 2005,

 

 

2004  and 2003

72

 

 

Notes  to the Consolidated Financial Statements

73-110

Reports  of Independent Registered Public Accounting Firm

111-112

** **

 

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

 

Supplemental  Financial Information (Unaudited)

113

 

 

Financial  Statement Schedules for the Years Ended December 31, 2005, 2004 and 2003:

 

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

127-130

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

131

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

132

 

 

** **

**IDACORP, Inc.Consolidated Statements of Income**

** **

**Year Ended December 31,**

** **

**2005**

** **

**2004**

** **

**2003**

** **

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

**Operating Revenues:**

 

 

 

 

 

 

 

 

 

Electric utility:

 

 

 

 

 

 

 

 

 

 

General business

$

667,270  

 

$

635,835 

 

$

670,969 

 

 

Off-system sales

 

142,794 

 

 

121,148 

 

 

71,573 

 

 

Other revenues

 

27,619 

 

 

65,954 

 

 

40,178 

 

 

 

Total electric utility revenues

 

837,683 

 

 

822,937 

 

 

782,720 

 

Other

 

21,805 

 

 

21,554 

 

 

40,282 

 

 

Total operating revenues

 

859,488 

 

 

844,491 

 

 

823,002 

** **

 

 

 

 

 

 

 

 

**Operating Expenses:**

 

 

 

 

 

 

 

 

 

Electric utility:

 

 

 

 

 

 

 

 

 

 

Purchased power

 

222,310 

 

 

195,642 

 

 

150,980 

 

 

Fuel expense

 

103,164 

 

 

103,261 

 

 

99,898 

 

 

Power cost adjustment

 

(2,995)

 

 

39,184 

 

 

70,762 

 

 

Other operations and  maintenance

 

241,209 

 

 

255,867 

 

 

220,983 

 

 

Depreciation

 

101,485 

 

 

100,855 

 

 

97,650 

 

 

Taxes other than income taxes

 

20,856 

 

 

19,090 

 

 

20,753 

 

 

 

Total electric utility expenses

 

686,029 

 

 

713,899 

 

 

661,026 

 

Other expense

 

35,440 

 

 

37,341 

 

 

77,914 

 

Goodwill impairment

 

10,270 

 

 

- 

 

 

- 

 

 

 

Total operating expenses

 

731,739 

 

 

751,240 

 

 

738,940 

 

 

 

 

 

 

 

 

 

**Operating Income (Loss):**

 

 

 

 

 

 

 

 

 

Electric utility

 

151,654 

 

 

109,038 

 

 

121,694 

 

Other

 

(23,905)

 

 

(15,787)

 

 

(37,632)

 

 

Total operating income

 

127,749 

 

 

93,251 

 

 

84,062 

 

 

 

 

 

 

 

 

 

**Other Income**

 

17,722 

 

 

25,777 

 

 

11,544 

** **

 

 

 

 

 

 

 

 

**Earnings (Losses) of  Unconsolidated Equity-method**

 

 

 

 

 

 

 

 

** **

**Investments**

 

(713)

 

 

1,050 

 

 

2,407 

** **

 

 

 

 

 

 

 

 

**Other Expense**

 

8,006 

 

 

8,726 

 

 

7,622 

 

 

 

 

 

 

 

 

 

**Interest Expense and Preferred  Dividends:**

 

 

 

 

 

 

 

 

 

Interest on long-term debt

 

56,930 

 

 

54,937 

 

 

58,670 

 

Other interest

 

3,241 

 

 

3,379 

 

 

2,832 

 

Preferred dividends of Idaho  Power Company

 

- 

 

 

4,823 

 

 

3,430 

 

 

Total interest expense and  preferred dividends

 

60,171 

 

 

63,139 

 

 

64,932 

 

 

 

 

 

 

 

 

 

**Income Before Income Taxes**

 

76,581 

 

 

48,213 

 

 

25,459 

 

 

 

 

 

 

 

 

 

**Income Tax Expense (Benefit)**

 

12,920 

 

 

(24,770)

 

 

(21,119)

 

 

 

 

 

 

 

 

 

**Net Income**

$

63,661 

 

$

72,983 

 

$

46,578 

 

 

 

 

 

 

 

 

 

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

 

42,279 

 

 

38,361 

 

 

38,228 

**Earnings Per Share of Common  Stock (basic)**

$

1.51 

 

$

1.90 

 

$

1.22 

**Earnings Per Share of Common  Stock (diluted)**

$

1.50 

 

$

1.90 

 

$

1.22 

**Dividends Paid Per Share of  Common Stock**

$

1.20 

 

$

1.20 

 

$

1.70 

** **

** **

 

 

 

 

 

 

 

 

The accompanying notes are an integral part of these statements.

** **

**IDACORP, Inc.Consolidated Balance Sheets**

** **

**December 31,**

** **

**2005**

** **

**2004**

**Assets**

**(thousands of dollars)**

 

 

 

 

**Current Assets:**

 

 

 

 

 

 

Cash and cash equivalents

$

52,356 

 

$

23,403 

 

Receivables:

 

 

 

 

 

 

 

Customer

 

97,476 

 

 

92,258 

 

 

Allowance for uncollectible  accounts

 

(33,078)

 

 

(43,108)

 

 

Employee notes

 

2,951 

 

 

3,523 

 

 

Other

 

22,631 

 

 

8,806 

 

Energy marketing assets

 

23,859 

 

 

9,203 

 

Accrued unbilled revenues

 

38,905 

 

 

33,832 

 

Materials and supplies (at  average cost)

 

32,289 

 

 

28,008 

 

Fuel stock (at average cost)

 

11,739 

 

 

6,539 

 

Prepayments

 

18,450 

 

 

30,035 

 

Deferred income taxes

 

23,922 

 

 

23,407 

 

Regulatory assets

 

3,064 

 

 

5,510 

 

Other

 

2,956 

 

 

- 

 

 

Total current assets

 

297,520 

 

 

221,416 

 

 

 

 

 

 

**Investments**

 

191,623 

 

 

223,061 

 

 

 

 

 

 

**Property, Plant and Equipment:**

 

 

 

 

 

 

Utility plant in service

 

3,477,067 

 

 

3,324,816 

 

Accumulated provision for  depreciation

 

(1,364,640)

 

 

(1,316,125)

 

 

Utility plant in service - net

 

2,112,427 

 

 

2,008,691 

 

Construction work in progress

 

153,124 

 

 

152,427 

 

Utility plant held for future  use

 

2,906 

 

 

2,636 

 

Other property, net of  accumulated depreciation

 

45,802 

 

 

45,708 

 

 

Property, plant and equipment -  net

 

2,314,259 

 

 

2,209,462 

 

 

 

 

 

 

**Other Assets:**

 

 

 

 

 

 

American Falls and Milner water  rights

 

31,585 

 

 

31,585 

 

Company-owned life insurance

 

35,401 

 

 

35,765 

 

Energy marketing assets -  long-term

 

22,189 

 

 

16,635 

 

Regulatory assets

 

415,177 

 

 

433,271 

 

Long-term receivables (net of  allowance of $1,878 and $2,578)

 

4,015 

 

 

2,895 

 

Employee notes

 

2,862 

 

 

3,746 

 

Goodwill

 

3,428 

 

 

13,659 

 

Other

 

46,067 

 

 

42,677 

 

 

Total other assets

 

560,724 

 

 

580,233 

 

 

 

 

 

 

 

 

**Total**

$

3,364,126 

 

$

3,234,172 

 

 

 

 

 

 

The accompanying notes are an integral part of these statements.

 

**IDACORP, Inc.Consolidated Balance Sheets**

** **

**December 31,**

** **

**2005**

** **

**2004**

**Liabilities and Shareholders'  Equity**

**(thousands of dollars)**

** **

 

 

 

**Current Liabilities:**

 

 

 

 

 

 

Current maturities of long-term  debt

$

16,307 

 

$

78,603 

 

Notes payable

 

60,100 

 

 

36,270 

 

Accounts payable

 

83,744 

 

 

79,156 

 

Energy marketing liabilities

 

24,093 

 

 

9,420 

 

Taxes accrued

 

72,652 

 

 

46,318 

 

Interest accrued

 

14,616 

 

 

14,426 

 

Other

 

22,073 

 

 

21,265 

 

 

Total current liabilities

 

293,585 

 

 

285,458 

 

 

 

 

 

 

**Other Liabilities:**

 

 

 

 

 

 

Deferred income taxes

 

521,855 

 

 

555,774 

 

Energy marketing liabilities -  long-term

 

22,189 

 

 

16,635 

 

Regulatory liabilities

 

345,109 

 

 

275,854 

 

Other

 

132,557 

 

 

112,616 

 

 

Total other liabilities

 

1,021,710 

 

 

960,879 

 

 

 

 

 

 

**Long-Term Debt**

 

1,023,580 

 

 

979,549 

** **

 

 

 

 

 

**Commitments and Contingencies  (Note 8)**

 

 

 

 

 

** **

 

 

 

 

 

**Shareholders' Equity:**

 

 

 

 

 

 

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

 

 

 

 

 

 

 

42,656,393 and 42,373,758  shares issued, respectively)

 

598,706 

 

 

589,440 

 

Retained earnings

 

437,284 

 

 

424,312 

 

Accumulated other comprehensive  loss

 

(3,425)

 

 

(888)

 

Treasury stock (238,914 and  156,741 shares at cost, respectively)

 

(7,314)

 

 

(4,578)

 

 

Total shareholders' equity

 

1,025,251 

 

 

1,008,286 

 

 

 

 

 

 

 

 

 

**Total**

$

3,364,126 

 

$

3,234,172 

 

 

 

 

 

 

The accompanying notes are an integral part of these statements.

 

**IDACORP,Inc.Consolidated Statements of Cash Flows**

** **

** **

**Year Ended December 31,**

** **

** **

**2005**

** **

**2004**

** **

**2003**

**Operating Activities:**

**(thousands of dollars)**

 

Net income

$

63,661 

 

$

72,983 

 

$

46,578 

 

Adjustments to reconcile net  income to net cash provided by

 

 

 

 

 

 

 

 

 

 

(used in) operating activities:

 

 

 

 

 

 

 

 

 

 

Net non-cash loss on legal  disputes

 

- 

 

 

- 

 

 

12,072 

 

 

Impairment of long-lived asset

 

- 

 

 

9,075 

 

 

3,498 

 

 

Impairment of goodwill

 

10,270 

 

 

- 

 

 

- 

 

 

Unrealized losses from energy  marketing activities

 

17 

 

 

131 

 

 

42,517 

 

 

Provision for uncollectible  accounts

 

(10,729)

 

 

(128)

 

 

2,538 

 

 

Depreciation and amortization

 

124,124 

 

 

124,192 

 

 

129,070 

 

 

Deferred income taxes and  investment tax credits

 

(31,769)

 

 

(33,912)

 

 

(56,174)

 

 

Change in regulatory assets and  liabilities

 

7,275 

 

 

16,788 

 

 

68,358 

 

 

Undistributed (earnings) losses  of subsidiaries

 

(16,762)

 

 

2,495 

 

 

(3,456)

 

 

Gain on sales of assets

 

(2,128)

 

 

(4,475)

 

 

- 

 

 

Gain on extinguishment of debt

 

- 

 

 

(7,188)

 

 

- 

 

 

Other non-cash adjustments to  net income

 

(4,361)

 

 

(3,248)

 

 

(3,510)

 

 

Change in:

 

 

 

 

 

 

 

 

 

 

 

Accounts receivables and  prepayments

 

(6,436)

 

 

(1,314)

 

 

91,991 

 

 

 

Accounts payable and other  accrued liabilities

 

1,821 

 

 

15,806 

 

 

(70,342)

 

 

 

Taxes accrued

 

26,412 

 

 

717 

 

 

(16,797)

 

 

 

Other current assets

 

(14,360)

 

 

(4,568)

 

 

7,020 

 

 

 

Other current liabilities

 

794 

 

 

(1,309)

 

 

(6,412)

 

 

 

Long-term receivable

 

- 

 

 

- 

 

 

51,394 

 

 

Other assets

 

(514)

 

 

2,058 

 

 

2,439 

 

 

Other liabilities

 

14,181 

 

 

6,593 

 

 

12,065 

 

 

Net cash provided by operating  activities

 

161,496 

 

 

194,696 

 

 

312,849 

**Investing Activities:**

 

 

 

 

 

 

 

 

 

Additions to property, plant and  equipment

 

(193,314)

 

 

(199,770)

 

 

(149,643)

 

Sale of non-utility assets

 

1,019 

 

 

5,554 

 

 

494 

 

Sale of emission allowances

 

70,757 

 

 

- 

 

 

- 

 

Investments in affordable  housing projects

 

(4,992)

 

 

(7,655)

 

 

76 

 

Purchase of available-for-sale  securities

 

(85,334)

 

 

(295,356)

 

 

(13,689)

 

Sale of available-for-sale  securities

 

120,026 

 

 

266,331 

 

 

14,040 

 

Purchase of held-to-maturity securities

 

(2,181)

 

 

(4,927)

 

 

(10,547)

 

Maturity of held-to-maturity  securities

 

2,840 

 

 

7,730 

 

 

7,571 

 

Other assets

 

2,229 

 

 

- 

 

 

(127)

 

Other liabilities

 

- 

 

 

(1,547)

 

 

(98)

 

 

Net cash used in investing  activities

 

(88,950)

 

 

(229,640)

 

 

(151,923)

**Financing Activities:**

 

 

 

 

 

 

 

 

 

Issuance of long-term debt

 

64,992 

 

 

106,442 

 

 

255,292 

 

Retirement of long-term debt

 

(83,067)

 

 

(79,890)

 

 

(230,003)

 

Retirement of preferred stock of  Idaho Power Company

 

- 

 

 

(52,351)

 

 

(860)

 

Dividends on common stock

 

(50,690)

 

 

(45,838)

 

 

(64,726)

 

Increase (decrease) in  short-term borrowings, net

 

23,830 

 

 

(58,250)

 

 

(82,550)

 

Issuance of common stock 

 

6,296 

 

 

115,690 

 

 

4,123 

 

Acquisition of treasury shares

 

- 

 

 

(1,420)

 

 

(799)

 

Other assets

 

(4,486)

 

 

(1,145)

 

 

(8,404)

 

Other liabilities

 

(468)

 

 

(50)

 

 

(576)

 

 

Net cash used in financing  activities

 

(43,593)

 

 

(16,812)

 

 

(128,503)

Net increase (decrease) in cash  and cash equivalents

 

28,953 

 

 

(51,756)

 

 

32,423 

Cash and cash equivalents at  beginning of year

 

23,403 

 

 

75,159 

 

 

42,736 

Cash and cash equivalents at end  of year

$

52,356 

 

$

23,403 

 

$

75,159 

** **

**Supplemental Disclosure of Cash  Flow Information:**

 

Cash paid during the year for:

 

 

 

 

 

 

 

 

 

 

Income taxes

$

18,937 

 

$

7,742 

 

$

52,882 

 

 

Interest (net of amount  capitalized)

$

57,466 

 

$

55,122 

 

$

58,931 

 

Theaccompanying notes are an integral part of these statements.

 

**IDACORP, Inc.Consolidated Statements of Shareholders' Equity**

 

** **

** **

**Accumulated**

** **

** **

 

** **

** **

**Other**

** **

** **

 

** **

** **

**Compre-**

** **

** **

 

** **

** **

**hensive**

** **

** **

 

**Common Stock**

**Retained**

**Income**

**Treasury Stock**

**Total**

 

**Shares**

**Amount**

**Earnings**

**(Loss)**

**Shares**

**Amount**

**Amount**

**(thousands)**

Balance at January 1,

 

 

 

 

 

 

 

 

 

 

 

 

 

2003

38,152 

$

468,241 

$

415,315 

$

(7,109)

84 

$

(1,620)

$

874,827 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income

- 

 

- 

 

46,578 

 

- 

- 

 

- 

 

46,578 

Common stock dividends

 

 

 

 

 

 

 

 

 

 

 

 

 

($1.70 per share)

- 

 

- 

 

(64,726)

 

- 

- 

 

- 

 

(64,726)

Issued

189 

 

4,123 

 

- 

 

- 

- 

 

- 

 

4,123 

Acquired

- 

 

- 

 

- 

 

- 

9 

 

(799)

 

(799)

Other

- 

 

538 

 

- 

 

- 

18 

 

(739)

 

(201)

Unrealized gain on

 

 

 

 

 

 

 

 

 

 

 

 

 

securities (net of tax)

- 

 

- 

 

- 

 

4,809 

- 

 

- 

 

4,809 

Minimum pension

 

 

 

 

 

 

 

 

 

 

 

 

 

liability adjustment

 

 

 

 

 

 

 

 

 

 

 

 

 

(net of tax)

- 

 

- 

 

- 

 

(330)

- 

 

- 

 

(330)

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance at December 31,

 

 

 

 

 

 

 

 

 

 

 

 

 

2003

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 

Minimum 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)

Minimum 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 

 

 

 

 

 

 

 

 

 

 

 

 

 

The accompanying notes are anintegral part of these statements.

** **

**IDACORP, Inc.Consolidated Statements of Comprehensive Income**

** **

**Year Ended December 31,**

 

**2005**

** **

**2004**

** **

**2003**

 

**(thousands of dollars)**

 

 

 

 

 

 

 

 

 

**Net  Income**

$

63,661 

 

$

72,983 

 

$

46,578 

 

 

 

 

 

 

 

 

 

**Other  Comprehensive Income (Loss):**

 

 

 

 

 

 

 

 

 

Unrealized  (losses) gains on securities:

 

 

 

 

 

 

 

 

 

 

Unrealized  holding (losses) gains arising during the year,

 

 

 

 

 

 

 

 

 

 

 

net of  tax of  ($96), $1,234 and $2,963

 

(457)

 

 

2,057 

 

 

4,982 

 

 

Reclassification  adjustment for (losses) gains included

 

 

 

 

 

 

 

 

 

 

 

in net  income, net of tax of  ($870), ($768)  and ($111)

 

(1,355)

 

 

(1,195)

 

 

(173)

 

 

 

Net  unrealized (losses) gains

 

(1,812)

 

 

862 

 

 

4,809 

 

Minimum  pension liability adjustment, net of tax of   ($465), 

 

 

 

 

 

 

 

 

 

 

$565  and ($191)

 

(725)

 

 

880 

 

 

(330)

 

 

 

 

 

 

 

 

 

**Total  Comprehensive Income**

$

61,124 

 

$

74,725 

 

$

51,057 

 

 

 

 

 

 

 

 

 

The accompanying notes are anintegral part of these statements.

 

**IdahoPower CompanyConsolidated Statements of Income**

** **

**Year Ended December 31,**

** **

**2005**

** **

**2004**

** **

**2003**

** **

**(thousands of dollars)**

**Operating  Revenues:**

 

 

 

 

 

 

 

 

 

General  business

$

667,270 

 

$

635,835 

 

$

670,969 

 

Off-system  sales

 

142,794 

 

 

121,148 

 

 

71,573 

 

Other  revenues

 

27,619 

 

 

62,526 

 

 

37,840 

 

 

Total  operating revenues

 

837,683 

 

 

819,509 

 

 

780,382 

** **

 

 

 

 

 

 

 

 

**Operating  Expenses:**

 

 

 

 

 

 

 

 

 

Operation:

 

 

 

 

 

 

 

 

 

 

Purchased  power

 

222,310 

 

 

195,642 

 

 

150,980 

 

 

Fuel  expense

 

103,164 

 

 

103,261 

 

 

99,898 

 

 

Power  cost adjustment

 

(2,995)

 

 

39,184 

 

 

70,762 

 

 

Other

 

181,670 

 

 

194,073 

 

 

156,030 

 

Maintenance

 

59,539 

 

 

58,405 

 

 

62,799 

 

Depreciation

 

101,485 

 

 

100,855 

 

 

97,650 

 

Taxes  other than income taxes

 

20,856 

 

 

19,090 

 

 

20,753 

 

 

Total  operating expenses

 

686,029 

 

 

710,510 

 

 

658,872 

 

 

 

 

 

 

 

 

 

**Income  from Operations**

 

151,654 

 

 

108,999 

 

 

121,510 

** **

 

 

 

 

 

 

 

 

**Other  Income (Expense):**

 

 

 

 

 

 

 

 

 

Allowance  for equity funds used during construction

 

4,950 

 

 

3,904 

 

 

3,385 

 

Earnings  of unconsolidated equity-method investments

 

10,369 

 

 

12,313 

 

 

11,336 

 

Other  income

 

11,476 

 

 

12,138 

 

 

8,467 

 

Other  expense

 

(8,610)

 

 

(9,074)

 

 

(8,326)

 

 

Total  other income

 

18,185 

 

 

19,281 

 

 

14,862 

 

 

 

 

 

 

 

 

 

**Interest  Charges:**

 

 

 

 

 

 

 

 

 

Interest  on long-term debt

 

53,339 

 

 

50,317 

 

 

54,645 

 

Other  interest

 

3,527 

 

 

3,980 

 

 

4,718 

 

Allowance  for borrowed funds used during

 

 

 

 

 

 

 

 

 

 

construction

 

(2,791)

 

 

(2,953)

 

 

(3,310)

 

 

Total  interest charges

 

54,075 

 

 

51,344 

 

 

56,053 

 

 

 

 

 

 

 

 

 

**Income  Before Income Taxes**

 

115,764 

 

 

76,936 

 

 

80,319 

 

 

 

 

 

 

 

 

 

**Income  Tax Expense**

 

43,925 

 

 

6,328 

 

 

21,728 

 

 

 

 

 

 

 

 

 

**Net  Income**

 

71,839 

 

 

70,608 

 

 

58,591 

 

 

 

 

 

 

 

 

 

 

Dividends  on preferred stock

 

- 

 

 

4,823 

 

 

3,430 

 

 

 

 

 

 

 

 

 

**Earnings  on Common Stock**

$

71,839 

 

$

65,785 

 

$

55,161 

** **

 

 

 

 

 

 

 

 

 

The accompanying notes are anintegral part of these statements.

 

**IdahoPower CompanyConsolidated Balance Sheets**

**Assets**

 

** **

**December 31,**

 

** **

**2005**

** **

**2004**

 

** **

**(thousands of dollars)**

 

** **

** **

**Electric Plant:**

 

 

 

 

 

 

 

In  service (at original cost)

 

$

3,477,067 

 

$

3,324,816 

 

 

Accumulated  provision for depreciation

 

 

(1,364,640)

 

 

(1,316,125)

 

 

In  service - net

 

 

2,112,427 

 

 

2,008,691 

 

Construction  work in progress

 

 

149,814 

 

 

151,652 

 
 

Held  for future use

 

 

2,906 

 

 

2,636 

 
 

 

 

Electric  plant - net

 

 

2,265,147 

 

 

2,162,979 

 

 

 

 

 

 

 

 
**Investments and Other Property**

 

 

68,049 

 

 

86,086 

 
** **

 

 

 

 

 

 

**Current Assets:**

 

 

 

 

 

 

 

Cash  and cash equivalents

 

 

49,335 

 

 

17,679 

 

Receivables:

 

 

 

 

 

 

 

 

Customer

 

 

49,830 

 

 

45,441 

 

 

Allowance  for uncollectible accounts

 

 

(833)

 

 

(1,363)

 

 

Notes

 

 

3,273 

 

 

3,129 

 

 

Employee  notes

 

 

2,951 

 

 

3,523 

 

 

Related  parties

 

 

637 

 

 

1,298 

 

 

Other

 

 

7,399 

 

 

5,253 

 

Accrued  unbilled revenues

 

 

38,905 

 

 

33,832 

 
 

Materials  and supplies (at average cost)

 

 

30,451 

 

 

26,065 

 
 

Fuel  stock (at average cost)

 

 

11,739 

 

 

6,539 

 
 

Prepayments

 

 

17,532 

 

 

28,449 

 
 

Regulatory  assets

 

 

3,064 

 

 

5,510 

 
 

 

 

Total  current assets

 

 

214,283 

 

 

175,355 

 

 

 

 

 

 

 

 

**Deferred Debits:**

 

 

 

 

 

 

 

American  Falls and Milner water rights

 

 

31,585 

 

 

31,585 

 

Company-owned  life insurance

 

 

35,401 

 

 

35,765 

 

Regulatory  assets

 

 

415,177 

 

 

433,271 

 

Employee  notes

 

 

2,862 

 

 

3,746 

 

Other

 

 

42,187 

 

 

40,425 

 

 

 

Total  deferred debits

 

 

527,212 

 

 

544,792 

 

 

 

 

 

 

 

 

 

**Total**

 

$

3,074,691 

 

$

2,969,212 

 

 

 

 

 

 

 

The accompanying notes are anintegral part of these statements.

 

**Idaho Power CompanyConsolidated Balance Sheets**

**Capitalization and Liabilities**

** **

** **

**December 31,**

** **

** **

**2005**

** **

**2004**

** **

** **

 

**(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

 

 

483,707 

 

 

483,707 

 

 

Capital  stock expense

 

 

(2,097)

 

 

(2,097)

 

 

Retained  earnings

 

 

361,256 

 

 

340,107 

 

 

Accumulated  other comprehensive loss

 

 

(3,425)

 

 

(888)

 

 

 

Total  common stock equity

 

 

937,318 

 

 

918,706 

 

 

 

 

 

 

 

 

Long-term  debt

 

 

983,720 

 

 

923,910 

 

 

 

Total  capitalization

 

 

1,921,038 

 

 

1,842,616 

 

 

 

 

 

 

 

**Current Liabilities:**

 

 

 

 

 

 

 

Long-term  debt due within one year

 

 

- 

 

 

60,000 

 

Accounts  payable

 

 

79,433 

 

 

74,642 

 

Notes  and accounts payable to related parties

 

 

153 

 

 

278 

 

Taxes  accrued

 

 

72,994 

 

 

42,228 

 

Interest  accrued

 

 

14,105 

 

 

13,743 

 

Deferred  income taxes

 

 

3,064 

 

 

5,510 

 

Other

 

 

19,182 

 

 

18,103 

 

 

 

Total  current liabilities

 

 

188,931 

 

 

214,504 

 

 

 

 

 

 

 

**Deferred Credits:**

 

 

 

 

 

 

 

Deferred  income taxes

 

 

507,880 

 

 

542,829 

 

Regulatory  liabilities

 

 

345,109 

 

 

275,854 

 

Other

 

 

111,733 

 

 

93,409 

 

 

 

Total  deferred credits

 

 

964,722 

 

 

912,092 

 

 

 

 

 

 

 

**Commitments and Contingencies  (Note 8)**

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

**Total**

 

$

3,074,691 

 

$

2,969,212 

 

 

 

 

 

 

 

The accompanying notes are anintegral part of these statements.

 

**Idaho Power CompanyConsolidated Statements of Capitalization**

 

 

**December 31,**

** **

 

**2005**

** **

**%**

** **

**2004**

** **

**%**

 

 

**(thousands of dollars)**

**Common Stock Equity:**

 

 

 

Common  stock

 

$

97,877 

 

 

 

$

97,877 

 

 

 

Premium  on capital stock

 

 

483,707 

 

 

 

 

483,707 

 

 

 

Capital  stock expense

 

 

(2,097)

 

 

 

 

(2,097)

 

 

 

Retained  earnings

 

 

361,256 

 

 

 

 

340,107 

 

 

 

Accumulated  other comprehensive loss

 

 

(3,425)

 

 

 

 

(888)

 

 

 

 

Total  common stock equity

 

 

937,318 

 

49

 

 

918,706 

 

50

** **

 

 

 

 

 

 

 

 

 

 

**Long-Term Debt:**

 

 

 

 

 

 

 

 

 

 

 

First  mortgage bonds:

 

 

 

 

 

 

 

 

 

 

 

 

5.83%     Series due 2005

 

 

- 

 

 

 

 

60,000 

 

 

 

 

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 

 

 

 

 

- 

 

 

 

 

 

Total  first mortgage bonds

 

 

785,000 

 

 

 

 

785,000 

 

 

 

 

Amount  due within one year

 

 

- 

 

 

 

 

(60,000)

 

 

 

 

 

Net  first mortgage bonds

 

 

785,000 

 

 

 

 

725,000 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Pollution  control revenue bonds:

 

 

 

 

 

 

 

 

 

 

 

 

6.05%  Series 1996A due 2026

 

 

68,100 

 

 

 

 

68,100 

 

 

 

 

Variable  Rate Series 1996B due 2026

 

 

24,200 

 

 

 

 

24,200 

 

 

 

 

Variable  Rate Series 1996C due 2026

 

 

24,000 

 

 

 

 

24,000 

 

 

 

 

Variable  Rate Series 2000 due 2027

 

 

4,360 

 

 

 

 

4,360 

 

 

 

 

Variable  Auction Rate Series 2003 due 2024

 

 

49,800 

 

 

 

 

49,800 

 

 

 

 

 

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

 

 

(3,325)

 

 

 

 

(3,135)

 

 

 

 

 

Total  long-term debt

 

 

983,720 

 

51

 

 

923,910 

 

50

 

 

 

 

 

 

 

 

 

 

 

**Total Capitalization**

 

$

1,921,038 

 

100

 

$

1,842,616 

 

100

 

 

 

 

 

 

 

 

 

 

 

The accompanying notes are anintegral part of these statements.

 

**Idaho Power CompanyConsolidated Statements of Cash Flows**

** **

**Year Ended December 31,**

** **

**2005**

** **

**2004**

** **

**2003**

** **

**(thousands of dollars)**

**Operating Activities:**

 

 

 

 

 

 

 

 

 

Net  income

$

71,839 

 

$

70,608 

 

$

58,591 

 

Adjustments  to reconcile net income to net cash provided by

 

 

 

 

 

 

 

 

 

operating  activities:

 

 

 

 

 

 

 

 

 

 

Impairment  of assets

 

- 

 

 

9,075 

 

 

- 

 

 

Depreciation  and amortization

 

107,919 

 

 

108,551 

 

 

110,228 

 

 

Deferred  income taxes and investment tax credits

 

(34,729)

 

 

(19,992)

 

 

(44,221)

 

 

Change  in regulatory assets and liabilities

 

7,275 

 

 

16,788 

 

 

68,358 

 

 

Undistributed  (earnings) losses of subsidiary

 

(16,669)

 

 

1,990 

 

 

(2,136)

 

 

Provision  for uncollectible accounts

 

(530)

 

 

(128)

 

 

(40)

 

 

Gain on  sale of assets

 

(672)

 

 

- 

 

 

- 

 

 

Other  non-cash adjustments to net income

 

(4,950)

 

 

(3,904)

 

 

(3,385)

 

 

Change  in:

 

 

 

 

 

 

 

 

 

 

 

Accounts  receivable and prepayments

 

5,290 

 

 

(3,718)

 

 

24,487 

 

 

 

Accounts  payable

 

2,578 

 

 

29,112 

 

 

(7,147)

 

 

 

Taxes  accrued

 

30,766 

 

 

(13,155)

 

 

(33,707)

 

 

 

Other  current assets

 

(14,503)

 

 

(4,220)

 

 

7,263 

 

 

 

Other  current liabilities

 

1,269 

 

 

(2,029)

 

 

(1,427)

 

 

Other  assets

 

(698)

 

 

2,054 

 

 

(255)

 

 

Other  liabilities

 

11,840 

 

 

6,753 

 

 

10,119 

 

 

Net  cash provided by operating activities

 

166,025 

 

 

197,785 

 

 

186,728 

 

 

 

 

 

 

 

 

 

**Investing Activities:**

 

 

 

 

 

 

 

 

 

Additions  to utility plant

 

(185,865)

 

 

(190,286)

 

 

(148,246)

 

Note  receivable payment from parent

 

- 

 

 

- 

 

 

19,282 

 

Sale of  emission allowances

 

70,758 

 

 

- 

 

 

- 

 

Purchase  of available-for-sale securities

 

(85,334)

 

 

(295,356)

 

 

(13,689)

 

Sale of  available-for-sale securities

 

120,026 

 

 

266,331 

 

 

14,040 

 

Other  assets

 

1,181 

 

 

(38)

 

 

685 

 

 

Net  cash used in investing activities

 

(79,234)

 

 

(219,349)

 

 

(127,928)

 

 

 

 

 

 

 

 

 

**Financing Activities:**

 

 

 

 

 

 

 

 

 

Issuance  of long-term debt

 

60,000 

 

 

105,000 

 

 

189,800 

 

Retirement  of long-term debt

 

(60,000)

 

 

(51,105)

 

 

(209,880)

 

Retirement  of preferred stock

 

- 

 

 

(52,351)

 

 

(860)

 

Common  stock issued to parent

 

- 

 

 

- 

 

 

39,987 

 

Dividends  on common stock

 

(50,690)

 

 

(46,413)

 

 

(64,726)

 

Dividends  on preferred stock

 

- 

 

 

(4,823)

 

 

(3,430)

 

Decrease  in short-term borrowings

 

- 

 

 

- 

 

 

(10,500)

 

Capital  contribution from parent

 

- 

 

 

85,920 

 

 

- 

 

Other  assets

 

(4,445)

 

 

(1,145)

 

 

(7,450)

 

Other  liabilities

 

- 

 

 

129 

 

 

(409)

 

 

Net  cash provided by (used in) financing activities

 

(55,135)

 

 

35,212 

 

 

(67,468)

 

 

 

 

 

 

 

 

 

Net  increase (decrease) in cash and cash equivalents

 

31,656 

 

 

13,648 

 

 

(8,668)

Cash  and cash equivalents at beginning of year

 

17,679 

 

 

4,031 

 

 

12,699 

 

 

 

 

 

 

 

 

 

Cash  and cash equivalents at end of year

$

49,335 

 

$

17,679 

 

$

4,031 

 

 

 

 

 

 

 

 

 

**Supplemental Disclosure of Cash Flow Information:**

 

Cash  paid during the year for:

 

 

 

 

 

 

 

 

 

 

Income  taxes paid to parent

$

48,545 

 

$

39,190 

 

$

99,879 

 

 

Interest  (net of amount capitalized)

 

51,290 

 

 

48,113 

 

 

54,911 

 

The accompanying notes are anintegral part of these statements.

 

**Idaho Power CompanyConsolidated Statements of Retained Earnings**

** **

**Year Ended December 31,**

** **

**2005**

** **

**2004**

** **

**2003**

** **

**(thousands of dollars)**

 

 

 

 

 

 

 

 

 

**Retained  Earnings, Beginning of Year**

$

340,107 

 

$

320,735 

 

$

330,300 

 

 

 

 

 

 

 

 

 

**Net  Income**

 

71,839 

 

 

70,608 

 

 

58,591 

 

 

 

 

 

 

 

 

 

**Dividends:**

 

 

 

 

 

 

 

 

 

Common  stock

 

(50,690)

 

 

(46,413)

 

 

(64,726)

 

Preferred  stock

 

-

 

 

(4,823)

 

 

(3,430)

 

 

 

 

 

 

 

 

 

**Retained  Earnings, End of Year**

$

361,256 

 

$

340,107 

 

$

320,735 

 

 

 

 

 

 

 

 

 

The accompanying notes are anintegral part of these statements.

 

**Idaho Power CompanyConsolidated Statements of Comprehensive Income**

** **

**Year Ended December 31,**

** **

**2005**

** **

**2004**

** **

**2003**

** **

**(thousands of dollars)**

 

 

 

 

 

 

 

 

 

**Net Income**

$

71,839 

 

$

70,608 

 

$

58,591 

 

 

 

 

 

 

 

 

 

**Other Comprehensive Income  (Loss):**

 

 

 

 

 

 

 

 

 

Unrealized  (losses) gains on securities:

 

 

 

 

 

 

 

 

 

 

Unrealized  holding (losses) gains arising during the year,

 

 

 

 

 

 

 

 

 

 

 

net of  tax of  ($96),  $1,234 and   $2,963

 

(457)

 

 

2,057 

 

 

4,982 

 

 

Reclassification  adjustment for (losses) gains included

 

 

 

 

 

 

 

 

 

 

 

in net  income, net of tax of ($870), ($768) and ($111)

 

(1,355)

 

 

(1,195)

 

 

(173)

 

 

 

Net  unrealized (losses) gains

 

(1,812)

 

 

862 

 

 

4,809 

 

Minimum  pension liability adjustment, net of tax of ($465), 

 

 

 

 

 

 

 

 

 

 

$565 and  ($191)

 

(725)

 

 

880 

 

 

(330)

 

 

 

 

 

 

 

 

 

**Total Comprehensive Income**

$

69,302 

 

$

72,350 

 

$

63,070 

** **

 

 

 

 

 

 

 

 

The accompanying notes are anintegral part of these statements.

 

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

**1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:**

ThisAnnual Report on Form 10-K is a combined report of IDACORP, Inc. (IDACORP) andIdaho Power Company (IPC).  Therefore,the Notes to the Consolidated Financial Statements apply to both IDACORP andIPC.  However, IPC makes norepresentation as to the information relating to IDACORP's other operations.

**Nature of Business**IDACORP is aholding company formed in 1998 whose principal operating subsidiary is IPC.  Due to the repeal of the Public UtilityHolding Company Act of 1935 (1935 Act), effective February 8, 2006, IDACORP isno longer subject to any provisions under the 1935 Act.  IDACORP is a holding company under the newlyenacted Public Utility Holding Company Act of 2005 (2005 Act), which providescertain access to books and records to the Federal Energy Regulatory Commission(FERC) and state utility regulatory commissions and imposes certain recordretention and reporting requirements on IDACORP.

IPC is an electric utility with a service territorycovering approximately 24,000 square miles in southern Idaho and easternOregon.  IPC is regulated by the FERC andthe State regulatory commissions 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 subsidiaries include:

IDACORP Financial Services, Inc.(IFS) - holder of affordable housing and other real estate investments;

IdaTech, LLC (IdaTech) -developer of integrated fuel cell systems, over 90 percent owned by IDACORP's wholly-owned subsidiaryIDACORP Technologies, Inc. (ITI);

IDACOMM, Inc. (IDACOMM) -provider of telecommunications services and commercial Internet services; 

Ida-West Energy (Ida-West) - operator of small hydroelectricgeneration projects that satisfy the requirements of the Public UtilityRegulatory Policies Act of 1978 (PURPA). In 2003,Ida-West discontinued its project development operations and began managing itsindependent power projects with a reduced workforce; and

IDACORP Energy (IE), a marketerof electricity and natural gas, which wound down its operations during 2003.

**Principles of Consolidation**The consolidatedfinancial statements of IDACORP and IPC include the accounts of each companyand those variable interest entities (VIEs) for which the companies are the primarybeneficiaries.  All significantintercompany balances have been eliminated in consolidation.  Investments in business entities in whichIDACORP and IPC are not the primary beneficiaries, but have the ability toexercise significant influence over operating and financial policies, areaccounted for using the equity method.

The entities that IDACORP and IPC consolidate consistprimarily of wholly-owned or controlled subsidiaries.  In addition, IDACORP consolidates thefollowing VIEs in accordance with Financial Accounting Standards BoardInterpretation No. 46(R), "Consolidation of Variable Interest Entities -an interpretation of ARB No. 51:"

Ida-West participates in MarysvilleHydro 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 $18million 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 Development Company, LLC hasapproximately $8 million of assets, primarily real property, and $8 million oflong-term debt.  This debt isnon-recourse to IDACORP, personally guaranteed by the general partner andcollateralized by the property.

Through IFS, IDACORP also holds significant variableinterests in VIEs for which it is not the primary beneficiary.  These VIEs are historic rehabilitation andaffordable housing developments in which IFS holds limited partnershipinterests ranging from five to 99 percent. These investments were acquired between 1996 and 2005.  IFS's maximum exposure to loss in thesedevelopments totaled $100 million at December 31, 2005.

**Management Estimates**Management makesestimates and assumptions when preparing financial statements in conformitywith accounting principles generally accepted in the United States ofAmerica.  These estimates and assumptionsaffect the reported amounts of assets and liabilities and the disclosure ofcontingent assets and liabilities at the date of the financial statements, andthe reported amounts of revenues and expenses during the reporting period.  These estimates involve judgments withrespect to, among other things, future economic factors that are difficult topredict and are beyond management's control. As a result, actual results could differ from those estimates.

**System of Accounts**The accountingrecords of IPC conform to the Uniform System of Accounts prescribed by the FERCand adopted by the public utility commissions of Idaho, Oregon and Wyoming.

**Property, Plant and Equipment and Depreciation**The cost ofutility plant in service represents the original cost of contracted services,direct labor and material, Allowance for Funds Used During Construction (AFDC)and indirect charges for engineering, supervision and similar overheaditems.  Maintenance and repairs ofproperty and replacements and renewals of items determined to be less thanunits of property are expensed to operations. Repair and maintenance costs associated with planned major maintenanceare recorded as these costs are incurred. For utility property replaced or renewed, the original cost plus removalcost less salvage is charged to accumulated provision for depreciation, whilethe cost of related replacements and renewals is added to property, plant andequipment.

All utility plant in service is depreciated using thestraight-line method at rates approved by regulatory authorities.  Annual depreciation provisions as a percentof average depreciable utility plant in service approximated 2.91 percent in2005, 2.96 percent in 2004 and 2.99 percent in 2003.

Long-lived assets are periodically reviewed for impairmentwhen events or changes in circumstances indicate that the carrying amount of anasset may not be recoverable as prescribed under Statement of FinancialAccounting Standards (SFAS) 144, "Accounting for the Impairment orDisposal of Long-Lived Assets." SFAS 144 requires that if the sum of the undiscounted expected futurecash flows from an asset is less than the carrying value of the asset, an assetimpairment must be recognized in the financial statements.

**Allowance for Funds Used During Construction**AFDC representsthe cost of financing construction projects with borrowed funds and equityfunds.  While cash is not realizedcurrently from such allowance, it is realized under the rate-making processover the service life of the related property through increased revenuesresulting from a higher rate base and higher depreciation expense.  The component of AFDC attributable toborrowed funds is included as a reduction to interest expense, while the equitycomponent is included in other income. IPC's weighted-average monthly AFDC rates for 2005, 2004 and 2003 were7.4 percent, 6.9 percent and 8.3 percent, respectively.  IPC's reductions to interest expense for AFDCwere $3 million annually from 2003 to 2005. Other income included $5 million, $4 million and $3 million for 2005,2004 and 2003, respectively.

**Revenues**IPC accruesunbilled revenues for electric services delivered to customers but not yetbilled at month-end.  IPC collectsfranchise fees and similar taxes related to energy consumption.  These amounts are recorded as liabilitiesuntil paid to the taxing authority.  Noneof these collections are reported on the income statement as revenue orexpense.

**Regulation of Utility Operations**IPC follows SFAS71, "Accounting for the Effects of Certain Types of Regulation," andits financial statements reflect the effects of the different rate-makingprinciples followed by the jurisdictions regulating IPC.  The application of SFAS 71 by IPC can resultin IPC recording expenses in a period different than the period the expense wouldbe recorded by an unregulated enterprise. When this occurs, costs are deferred as regulatory assets on the balancesheet and recorded as expenses in the periods when those same amounts arereflected in rates.  Additionally, regulatorscan impose regulatory liabilities upon a regulated company for amountspreviously collected from customers and for amounts that are expected to berefunded to customers.

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

**Income Taxes**The liabilitymethod of computing deferred taxes is used on all temporary differences betweenthe book and tax basis of assets and liabilities and deferred tax assets andliabilities are adjusted for enacted changes in tax laws or rates.  Consistent with orders and directives of theIdaho Public Utilities Commission (IPUC), the regulatory authority having principaljurisdiction, IPC's deferred income taxes (commonly referred to as normalizedaccounting) are provided for the difference between income tax depreciation andstraight-line depreciation computed using book lives on coal-fired generationfacilities and properties acquired after 1980. On other facilities, deferred income taxes are provided for thedifference between accelerated income tax depreciation and straight-linedepreciation using tax guideline lives on assets acquired prior to 1981.  Deferred income taxes are not provided forthose income tax timing differences where the prescribed regulatory accountingmethods do not provide for current recovery in rates.  Regulated enterprises are required torecognize such adjustments as regulatory assets or liabilities if it isprobable that such amounts will be recovered from or returned to customers infuture rates.  See Note 2 for moreinformation.

The State of Idaho allows a three-percent investment taxcredit on qualifying plant additions. Investment tax credits earned on regulated assets are deferred andamortized to income over the estimated service lives of the relatedproperties.  Credits earned onnon-regulated assets or investments are recognized in the year earned.

**Earnings Per Share**The computationof diluted earnings per share (EPS) differs from basic EPS only due to theinclusion of potentially dilutive shares related to stock-based compensationawards.

The diluted EPS computation excluded 1,014,437 commonstock options in 2005, 818,600 in 2004 and 721,800 in 2003, because the options'exercise prices were greater than the average market price of the common stockduring those years.  In total, 1,421,914options were outstanding at December 31, 2005, with expiration dates between2010 and 2015.

**Stock-Based Compensation**Stock-based employeecompensation is accounted for under the recognition and measurement principlesof Accounting Principles Board (APB) Opinion 25, "Accounting for StockIssued to Employees," and related interpretations.  Grants of performance shares are reflected innet income based on the market value at the award date, or the period-end pricefor shares not yet vested.  Grants ofrestricted stock are reflected in net income based on the market value on thegrant date.  No stock-based employeecompensation cost is reflected in net income for stock options, as all optionsgranted had an exercise price equal to the market value of the underlyingcommon stock on the date of grant. IDACORP and IPC have adopted the disclosure only provision of SFAS 123,"Accounting for Stock-Based Compensation."

The following table illustrates the effect on net incomeand EPS if the fair value recognition provisions of SFAS 123 had been appliedto stock-based employee compensation:

 

**2005**

** **

**2004**

** **

**2003**

 

**(thousands of dollars except  for**

** **

**per share amounts)**

**IDACORP**

 

 

 

 

 

 

 

 

Net income, as reported

$

63,661 

 

$

72,983 

 

$

46,578 

Add: Stock-based employee compensation expense

 

 

 

 

 

 

 

 

 

included in reported net income, net of related

 

 

 

 

 

 

 

 

 

tax effects

 

359 

 

 

399 

 

 

(76)

Deduct: Stock-based employee compensation

 

 

 

 

 

 

 

 

 

expense determined under fair value based 

 

 

 

 

 

 

 

 

 

method for all awards, net of related tax effects

 

1,214 

 

 

1,169 

 

 

1,169 

 

 

Pro forma net income

$

62,806 

 

$

72,213 

 

$

45,333 

EPS of common stock:

 

 

 

 

 

 

 

 

 

Basic - as reported

$

1.51 

 

$

1.90 

 

$

1.22 

 

Diluted - as reported

 

1.50 

 

 

1.90 

 

 

1.22 

 

Basic - pro forma

 

1.49 

 

 

1.88 

 

 

1.19 

 

Diluted - pro forma

 

1.48 

 

 

1.88 

 

 

1.19 

** **

** **

** **

** **

** **

** **

** **

** **

** **

** **

** **

** **

 

**2005**

** **

**2004**

** **

**2003**

 

**(thousands of dollars except  for**

** **

**per share amounts)**

**IPC**

** **

Net income, as reported

$

71,839 

 

$

70,608 

 

$

58,591 

Add: Stock-based employee compensation expense included  in

 

 

 

 

 

 

 

 

 

 reported net  income, net of related tax effects

 

108 

 

 

276 

 

 

(56)

Deduct: Stock-based employee  compensation expense 

 

 

 

 

 

 

 

 

 

determined under fair value  based method for all awards, net 

 

108 

 

 

276 

 

 

(56)

 

of related tax effects

 

568 

 

 

977 

 

 

1,073 

 

 

Pro forma net income

$

71,379 

 

 

69,907 

 

$

57,462 

 

 

 

 

 

 

 

 

 

 

 

 

For purposes of these pro forma calculations, theestimated fair value of the options, restricted stock and performance shares isamortized to expense over the vesting period. The fair value of the restricted stock and performance shares is themarket price of the stock on the date of grant. The fair value of an option award is estimated at the date of grantusing a binomial option-pricing model. Expense related to forfeited options is reversed in the period in whichthe forfeit occurs.  For more informationsee Note 9.

**Cash and Cash Equivalents**Cash and cashequivalents include cash on hand and highly liquid temporary investments withmaturity dates at date of acquisition of three months or less.

**Derivative FinancialInstruments**Financialinstruments such as commodity futures, forwards, options and swaps are used tomanage exposure to commodity price risk in the electricity market.  The objective of the risk management programis to mitigate the risk associated with the purchase and sale of electricity andnatural gas.  The accounting for derivativefinancial instruments that are used to manage risk is in accordance with theconcepts established by SFAS 133, "Accounting for Derivative Instrumentsand Hedging Activities," as amended.

**Comprehensive Income**Comprehensiveincome includes net income, unrealized holding gains and losses on marketablesecurities, IPC's proportionate share of unrealized holding gains and losses onmarketable securities held by an equity investee and the changes in additionalminimum liability under a deferred compensation plan for certain seniormanagement employees and directors.  Thefollowing table presents IDACORP's and IPC's accumulated other comprehensiveloss balance at December 31:

 

**2005**

** **

**2004**

 

**(thousands of dollars)**

Unrealized holding gains on securities

$

2,725 

 

$

4,538 

Minimum pension liability adjustment

 

(6,150)

 

 

(5,426)

 

Total

$

(3,425)

 

$

(888)

 

 

 

 

 

 

 

**Goodwill**On January 1,2002, SFAS 142, "Goodwill and Other Intangible Assets," wasadopted.  SFAS 142 requires that goodwilland certain intangible assets no longer be amortized, but instead be tested forimpairment at least annually.

The annual impairment tests were performed on IDACORP'sgoodwill balances, which are related to acquisitions made by ITI and IDACOMM.  IDACORP's annual impairment tests wereconducted as of June 30, and at that time no impairment was noted.  The strategic decision to exit one ofIDACOMM's lines of business, broadband-over-power line, triggered therequirement to conduct another impairment test. Based on the results of that test, IDACOMM's goodwill balance wasconsidered impaired and a $10 million impairment charge was recorded in thefourth quarter of 2005.  Impairment testson the remaining ITI goodwill balance will continue to be performed at least annually,and more frequently if circumstances indicate a possible impairment.

**New Accounting PronouncementsSFAS 123(R):** InDecember 2004, the FASB issued SFAS 123 (revised 2004), "Share-BasedPayments," which revises SFAS 123 and supersedes APB 25 and its relatedinterpretive guidance.  SFAS 123(R)establishes standards for the accounting for transactions in which an entityexchanges its equity instruments for goods or services.  It also addresses transactions in which anentity incurs liabilities in exchange for goods or services that are based onthe fair value of the entity's equity instruments or that may be settled by theissuance of those equity instruments. SFAS 123(R) focuses primarily on accounting for transactions in which anentity obtains employee services in share-based payment transactions.

Under the provisions of SFAS 123(R), the fair value ofall stock options must be reported as an expense on the financialstatements.  IDACORP and IPC currentlyapply the measurement provisions of APB 25 and the disclosure-only provisionsof SFAS 123.  SFAS 123(R) also changesother measurement, timing and disclosure rules relating to share-basedpayments.

In March 2005, the staff of the Securities and ExchangeCommission issued Staff Accounting Bulletin (SAB) 107 to provide additionalguidance regarding the application of SFAS 123(R).  SAB 107 permits registrants to choose anappropriate valuation technique or model to estimate the fair value of shareoptions, assuming consistent application, and provides guidance for the developmentof assumptions used in the valuation process. Additionally, SAB 107 discusses disclosures to be made under"Management's Discussion and Analysis of Financial Condition and Resultsof Operations" in the registrants' periodic reports.

Based upon Securities and Exchange Commission rulesissued in April 2005, SFAS 123(R) is effective for fiscal years that beginafter June 15, 2005 and will be adopted by IDACORP and IPC in the first quarterof 2006.  Adoption is not expected tohave a material effect on IDACORP's or IPC's financial statements.

**SFAS 153:** In December 2004, the FASB issued SFAS 153,"Exchanges of Nonmonetary Assets," which amends existing guidance onaccounting for nonmonetary transactions. SFAS 153 is effective for exchanges occurring in fiscal periodsbeginning after June 15, 2005, and is not expected to have a material effect onIDACORP's or IPC's financial statements.

**SFAS 154:**In May 2005 the FASB issued SFAS 154, "AccountingChanges and Error Corrections - a replacement of APB Opinion No. 20 and FASBStatement No. 3."  SFAS 154 changesthe requirements for the accounting for and reporting of a change in accountingprinciple.  It applies to all voluntarychanges in accounting principle and to changes required by an accounting pronouncementthat does not include specific transition provisions.  When a pronouncement includes specifictransition provisions, those provisions should be followed. SFAS 154 requiresretrospective application to prior periods' financial statements of changes inaccounting principle, unless it is impracticable to determine either theperiod-specific effects or the cumulative effect of the change.  When it is impracticable to determine theperiod-specific effects of an accounting change on one or more individual priorperiods presented, SFAS 154 requires that the new accounting principle beapplied to the balances of assets and liabilities as of the beginning of theearliest period for which retrospective application is practicable and that acorresponding adjustment be made to the opening balance of retained earningsfor that period rather than being reported in an income statement.  When it is impracticable to determine thecumulative effect of applying a change in accounting principle to all priorperiods, SFAS 154 requires that the new accounting principle be applied as ifit were adopted prospectively from the earliest date practicable.  SFAS 154 is effective for accounting changesand corrections of errors made in fiscal years beginning after December 15, 2005.

**Other Accounting Policies**Debt discount,expense and premium are being amortized over the terms of the respective debtissues.

**Reclassifications**Certain itemspreviously reported for years prior to 2005 have been reclassified to conformto the current year's presentation.  Netincome and shareholders' equity were not affected by these reclassifications.

**2.  INCOMETAXES:**A reconciliation between the statutory federal income tax rate and theeffective tax rate is as follows:

 

** **

**IDACORP**

** **

**IPC**

 

** **

**2005**

** **

**2004**

** **

**2003**

** **

**2005**

** **

**2004**

** **

**2003**

 

** **

**(thousands of dollars)**

Federal income tax expense at 

 

 

 

 

 

 

 

 

 

 

 

 

 

35% statutory rate

$

26,804 

$

16,875 

$

8,911 

$

40,517 

$

26,928 

$

28,112 

Change in taxes resulting from:

 

 

 

 

 

 

 

 

 

 

 

 

 

AFDC

 

(2,709)

 

(2,400)

 

(2,343)

 

(2,709)

 

(2,400)

 

(2,343)

 

Investment tax credits

 

(3,424)

 

(3,295)

 

(3,397)

 

(3,424)

 

(3,295)

 

(3,397)

 

Repair allowance

 

(1,750)

 

(2,450)

 

(2,450)

 

(1,750)

 

(2,450)

 

(2,450)

 

Removal costs

 

(1,490)

 

(1,244)

 

(1,101)

 

(1,490)

 

(1,244)

 

(1,101)

 

Pension accrual

 

1,276 

 

1,237 

 

2,456 

 

1,276 

 

1,237 

 

2,456 

 

Capitalized overhead costs

 

- 

 

(3,658)

 

(3,658)

 

- 

 

(3,658)

 

(3,658)

 

Goodwill impairment

 

3,489 

 

- 

 

- 

 

- 

 

- 

 

- 

 

Regulatory tax liability

 

- 

 

(16,457)

 

- 

 

- 

 

(16,457)

 

- 

 

Settlement of prior years tax 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

returns

 

(943)

 

(1,876)

 

(8,911)

 

(934)

 

(1,398)

 

(8,908)

 

State income taxes, net of 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

federal benefit

 

4,828 

 

2,923 

 

1,357 

 

6,173 

 

4,100 

 

3,973 

 

Depreciation

 

5,603 

 

4,350 

 

10,237 

 

5,603 

 

4,350 

 

10,237 

 

Affordable housing and 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

historic tax credits 

 

(20,205)

 

(21,717)

 

(20,345)

 

- 

 

- 

 

- 

 

Preferred dividends of IPC

 

- 

 

1,688 

 

1,200 

 

- 

 

- 

 

- 

 

Valuation allowance

 

1,564 

 

- 

 

- 

 

- 

 

- 

 

- 

 

Other, net

 

(123)

 

1,254 

 

(3,075)

 

663 

 

615 

 

(1,193)

Total income tax expense (benefit)

$

12,920 

$

(24,770)

$

(21,119)

$

43,925 

$

6,328 

$

21,728 

 

Effective tax rate

 

16.9%

 

(51.4%)

 

(83.0%)

 

37.9%

 

8.2%

 

27.1%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Theitems comprising income tax expense are as follows:

 

** **

**IDACORP**

** **

**IPC**

 

** **

**2005**

** **

**2004**

** **

**2003**

** **

**2005**

** **

**2004**

** **

**2003**

 

** **

**(thousands of dollars)**

Income taxes currently payable:

 

 

 

 

 

 

 

 

 

 

 

 

 

Federal

$

37,667 

$

6,087 

$

26,356 

$

69,479 

$

19,003 

$

55,034 

 

State

 

7,022 

 

3,055 

 

8,699 

 

9,176 

 

7,317 

 

10,915 

 

 

Total

 

44,689 

 

9,142 

 

35,055 

 

78,655 

 

26,320 

 

65,949 

Income taxes deferred:

 

 

 

 

 

 

 

 

 

 

 

 

 

Federal

 

(28,716)

 

(30,646)

 

(44,938)

 

(31,599)

 

(15,488)

 

(35,166)

 

State

 

(5,003)

 

(2,313)

 

(11,465)

 

(5,081)

 

(3,551)

 

(9,284)

 

 

Total

 

(33,719)

 

(32,959)

 

(56,403)

 

(36,680)

 

(19,039)

 

(44,450)

Investment tax credits:

 

 

 

 

 

 

 

 

 

 

 

 

 

Deferred

 

5,374 

 

2,342 

 

3,627 

 

5,374 

 

2,700 

 

3,627 

 

Restored

 

(3,424)

 

(3,295)

 

(3,398)

 

(3,424)

 

(3,653)

 

(3,398)

 

 

Total

 

1,950 

 

(953)

 

229 

 

1,950 

 

(953)

 

229 

Total income tax expense (benefit) 

$

12,920 

$

(24,770)

$

(21,119)

$

43,925 

$

6,328 

$

21,728 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Thecomponents of the net deferred tax liability are as follows:

** **

**IDACORP**

** **

**IPC**

** **

**2005**

** **

**2004**

** **

**2005**

** **

**2004**

** **

**(thousands of dollars)**

Deferred tax  assets:

 

 

 

 

 

 

 

 

 

 

 

 

Regulatory  liabilities

$

41,627

 

$

40,447

 

$

41,627

 

$

40,447

 

Advances  for construction

 

6,881

 

 

5,357

 

 

6,881

 

 

5,357

 

Deferred  compensation

 

14,581

 

 

14,001

 

 

13,276

 

 

12,324

 

Emission  allowances

 

27,380

 

 

-

 

 

27,380

 

 

-

 

Tax  credits

 

26,715

 

 

28,211

 

 

-

 

 

-

 

Other

 

16,078

 

 

15,737

 

 

14,496

 

 

14,584

 

 

Total

 

133,262

 

 

103,753

 

 

103,660

 

 

72,712

Deferred  tax liabilities:

 

 

 

 

 

 

 

 

 

 

 

 

Property,  plant and equipment

 

240,144

 

 

241,324

 

 

240,144

 

 

241,324

 

Regulatory  assets

 

346,117

 

 

344,220

 

 

346,117

 

 

344,220

 

Conservation  programs

 

5,705

 

 

6,972

 

 

5,705

 

 

6,972

 

PCA

 

17,410

 

 

20,516

 

 

17,410

 

 

20,516

 

Partnership  investments

 

18,770

 

 

19,975

 

 

3,892

 

 

5,600

 

Other

 

3,049

 

 

3,113

 

 

1,336

 

 

2,419

 

 

Total

 

631,195

 

 

636,120

 

 

614,604

 

 

621,051

Net  deferred tax liabilities

$

497,933

 

$

532,367

 

$

510,944

 

$

548,339

 

 

 

 

 

 

 

 

 

 

 

 

** **

Amountsaccrued by IPC for income taxes are payable to IDACORP, as IPC joins in thefiling of IDACORP's federal and state consolidated income tax returns.

**Status of Audit Proceedings**In March 2005,the Internal Revenue Service (IRS) began its examination of IDACORP's 2001through 2003 tax years.  On October 24,2005, the Idaho State Tax Commission also began its examination of the same taxyears.  Management believes that anadequate provision for income taxes and related interest charges has been madefor the open years 2001 and after.  Theaccrued amounts are classified as a current liability in taxes accrued.

With the exception of the capitalized overhead costmethod discussed below, management cannot predict with certainty whichfinancial accounts or tax adjustments will be chosen by the IRS forexamination.  IDACORP intends tovigorously defend its tax positions.  Itis possible that material differences in actual outcomes, costs and exposuresrelative to current estimates, or material changes in such estimates, couldhave a material adverse effect on IDACORP's and IPC's consolidated financialposition, results of operations, or cash flows.

In 2004, IDACORP completed settlement of all issuesrelated to the IRS's examination of its federal income tax returns for theyears 1998 through 2000.  Concurrently,IPC settled federal income tax deficiencies for the years 1999 and 2000 relatedto its partnership investment in the Bridger Coal Company.  Applicable state tax return amendments werecompleted in 2004 and settled. Finalization of these examinations resulted in deficiencies that wereless than previously accrued, enabling IDACORP to decrease income tax expenseby $2 million in 2004 and $9 million in 2003.

**Capitalized Overhead Costs:** On August 2, 2005, the IRS and Treasury Department issued guidanceinterpreting the meaning of "routine and repetitive" for purposes ofthe simplified service cost and simplified production methods of the InternalRevenue Code section 263A uniform capitalization rules.  The guidance was issued in the form of arevenue ruling (Rev. Rul. 2005-53) and proposed and temporary regulations.  The regulations are effective for tax yearsending on or after August 2, 2005, and the revenue ruling applies for all prioropen years.  Both pieces of guidance takea more restrictive view of the definition of self-constructed assets producedby a taxpayer on a "routine and repetitive" basis than do the currenttreasury regulations.

Generally, section 263A requires the capitalization ofall direct costs and those indirect costs, known as "mixed servicecosts", which directly benefit or are incurred by reason of the productionof property by a taxpayer.  The treasuryregulations for section 263A provide several "safe-harbor" methodstaxpayers may adopt in order to comply with the statute.  The simplified service cost method is one ofthe methods available for the calculation of indirect overhead ("mixedservice costs") cost capitalization. IPC changed to the simplified service cost method for both theself-construction of utility plant and production of electricity beginning withits 2001 federal income tax return.

For IPC, the simplified service cost method produces acurrent tax deduction for costs capitalized to electricity production that arecapitalized into fixed assets for financial accounting purposes.  Deferred income tax expense has not beenprovided for this deduction because the prescribed regulatory tax accountingtreatment does not allow for inclusion of such deferred tax expense in currentrates.  Rate regulated enterprises arerequired to recognize such adjustments as regulatory assets if it is probablethat such amounts will be recovered from customers in future rates.

For fiscal years 2002 through 2004, the simplifiedservice cost method decreased IPC's income tax expense by $60 million andresulted in cash refunds from federal and state tax authorities of $75 million.  For years 2004 and prior open tax years, ifIPC cannot satisfy the new guidance as currently drafted, IPC would be requiredto use another method of uniform capitalization, which could be more or lessfavorable to IPC than the simplified service cost method.  A less favorable method could result in a onetime charge to earnings and reduced cash flow that could be partially offset bycarryover tax credits, accelerated tax depreciation, changes in tax regulationsand state regulatory recovery.

The temporary regulations are effective for IPC's 2005tax year and, as drafted, preclude IPC from using this method forself-constructed assets for 2005 and thereafter.  Accordingly, in the third quarter of 2005,IPC reversed its previously accrued 2005 tax deduction for capitalized overheadcosts for both financial reporting and estimated tax payment purposes.  IPC is evaluating alternatives for a newuniform capitalization method.

IPC is actively involved in pursuing resolution of thismatter and is working diligently with the IRS in the examination process.  At this time, IPC cannot predict the earningsor cash flow impacts that the revenue ruling, temporary regulations, oradditional action by the IRS in this matter may have on 2005 or prior taxyears.

**Regulatory Settlement**In 2004, IPC andthe IPUC finalized an income tax issue from IPC's 2003 Idaho general ratecase.  The issue concerned the regulatoryaccounting treatment for the capitalized overhead tax method IPC adopted in the2001 IDACORP federal income tax return. As a result of the settlement, a $16 million regulatory tax liabilitywas reversed, creating benefit in 2004.

**Tax Credits and Net Operating Loss Carryforwards**As of December 31, 2005, IDACORP had $21 million of generalbusiness credit carryforward for federal income tax purposes and $6 million ofIdaho investment tax credit carryforward. The general business credit carryforward period expires in 2025 and theIdaho investment tax credit expires from 2018 to 2019.  IDACOMM has a separate company net operatingloss carryforward of $4 million that expires from 2010 to 2021.  The deferred tax asset associated with thenet operating loss carryforward is fully offset by a $1.6 million valuationallowance recorded in 2005.

**3.  COMMON STOCK:**

**IDACORP**Shares of commonstock were reserved for the following purposes at December 31:

 

**2005**

** **

**2004**

Dividend reinvestment and stock purchase plan and  employee savings plan

5,859,061

 

6,062,314

Restricted stock plan

314,114

 

314,114

Long-term incentive and compensation plan

3,013,217

 

2,042,600

Continuous equity program

2,500,000

 

-

 

Total shares reserved

11,686,392

 

8,419,028

 

 

 

 

 

 

IDACORPissues shares of common stock for its Dividend Reinvestment and Stock PurchasePlan (DRIP) and Employee Savings Plan.  Although no shares were issued in 2004, in2005 and 2003, IDACORP issued 146,684 and 122,990 shares, respectively, for theDRIP and 56,569 and 65,932 shares, respectively, for the Employee Savings Plan.

In 2005,IDACORP issued 62,983 shares in connection with stock compensation awards andissued 16,400 shares pursuant to exercises of stock options granted toparticipants in the 2000 Long-Term Incentive and Compensation Plan (LTICP).

OnDecember 15, 2005, IDACORP entered into a Sales Agency Agreement with BNYCapital Markets, Inc. (BNYCMI).  Underterms of the Sales Agency Agreement, IDACORP may offer and sell up to 2,500,000shares of its common stock, from time to time in at the market offeringsthrough BNYCMI, as IDACORP's agent for such offer and sale.

**Shareholder Rights Plan**IDACORP has aShareholder Rights Plan (Plan) designed to ensure that all shareholders receivefair and equal treatment in the event of any proposal to acquire control ofIDACORP.  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 issuedthereafter.  The Rights are currently notexercisable and will be exercisable only if a person or group (AcquiringPerson) either acquires ownership of 20 percent or more of IDACORP's votingstock or commences a tender offer that would result in ownership of 20 percentor more of such stock.  IDACORP mayredeem all, but not less than all, of the Rights at a price of $0.01 per Rightor exchange the Rights for cash, securities (including common shares ofIDACORP) or other assets at any time prior to the close of business on thetenth day after acquisition by an Acquiring Person of a 20 percent or greaterposition.

Additionally, the IDACORP Board of Directors created theA Series Preferred Stock, without par value, and reserved 1,200,000 shares forissuance upon exercise of the Rights.

Following the acquisition of a 20 percent or greaterposition, each Right will entitle its holder to purchase, for $95, that numberof shares of common stock or preferred stock having a market value of $190.

If after the Rights become exercisable, IDACORP isacquired in a merger or other business combination, 50 percent or more of itsconsolidated assets or earnings power are sold, or the Acquiring Person engagesin certain acts of self-dealing, each Right entitles the holder to purchase,for $95, shares of the acquiring company's common stock having a market valueof $190.

Any Rights that are or were held by an Acquiring Personbecome void if any of these events occurs. The Rights expire on September 30, 2008.

The Rights themselves do not give their holders anyvoting or other rights as shareholders. The terms of the Rights may be amended without the approval of anyholders of the Rights until an Acquiring Person obtains a 20 percent or greaterposition, and then may be amended as long as the amendment is not adverse tothe interests of the holders of the Rights.

**DividendRestrictions**IPC's articlesof incorporation contain restrictions on the payment of dividends on its commonstock if preferred stock dividends are in arrears.  On September 20, 2004, IPC redeemed all ofits outstanding preferred stock.  Also,certain provisions of credit facilities contain restrictions on the ratio ofdebt to total capitalization.

IPC mustobtain the approval of the Oregon Public Utility Commission (OPUC) before itcould directly or indirectly loan funds or issue notes or give credit on itsbooks to IDACORP.

**IPC**In December2004, IDACORP contributed $86 million of additional equity to IPC.  No additional shares of IPC common stock wereissued.

InDecember 2003, IPC issued 1,538,461 shares of $2.50 par value common stock toIDACORP for $40 million.  Each share ofIPC's common stock is entitled to one vote.

**4.  PREFERREDSTOCK OF IDAHO POWER COMPANY:**

OnSeptember 20, 2004, IPC redeemed all of its outstanding preferred stock for $54million using proceeds from the issuance of first mortgage bonds.  This amount includes $2 million of premiumthat was recorded as preferred dividends on the Consolidated Statements ofIncome.  The redemption price was $104per share for the 122,989 shares of 4% preferred stock, $102.97 per share forthe 150,000 shares of 7.68% preferred stock and $103.18 per share for the250,000 shares of 7.07% preferred stock, plus accumulated and unpaid dividends.

During2003 IPC reacquired and retired 10,263 shares of 4% preferred stock.

**5.  LONG-TERMDEBT:**

The following tablesummarizes long-term debt at December 31:

** **

** **

** **

** **

**2005**

** **

**2004**

** **

** **

** **

** **

**(thousands of dollars)**

First  mortgage bonds:

 

 

 

 

 

 

5.83 

%

 Series due 2005

$

- 

 

$

60,000 

 

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 

 

 

- 

 

 

Total first mortgage bonds

 

785,000 

 

 

785,000 

Pollution control revenue bonds:

 

 

 

 

 

 

Variable Auction Rate Series 2003 due 2024 (a)

 

49,800 

 

 

49,800 

 

6.05  

%

 Series 1996A due  2026

 

68,100 

 

 

68,100 

 

Variable Rate Series 1996B due 2026

 

24,200 

 

 

24,200 

 

Variable Rate Series 1996C due 2026

 

24,000 

 

 

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

 

(3,325)

 

 

(3,135)

Debt related to investments in affordable housing

 

48,481 

 

 

66,310 

Other subsidiary debt

 

7,686 

 

 

7,932 

 

Total

 

1,039,887 

 

 

1,058,152 

Current maturities of long-term debt

 

(16,307)

 

 

(78,603)

 

 

Total long-term debt

$

1,023,580 

 

$

979,549 

(a)  Humboldt  County Pollution Control Revenue bonds are secured by first mortgage bonds,  bringing the total of first mortgage 

 bonds outstanding  at December 31, 2005 to $834.8 million.

 

 

 

 

 

 

 

 

 

 

AtDecember 31, 2005, the maturities for the aggregate amount of long-term debtoutstanding were (in thousands of dollars):

** **

**2006**

**2007**

**2008**

**2009**

**2010**

**Thereafter**

 

 

 

 

 

 

 

 

 

 

 

 

 

IPC 

$

-

$

81,064

$

1,064

$

81,064

$

1,064

$

822,789

Other  subsidiary debt

 

16,307

 

14,096

 

10,392

 

5,657

 

2,965

 

6,750

Total

$

16,307

$

95,160

$

11,456

$

86,721

$

4,029

$

829,539

 

 

 

 

 

 

 

 

 

 

 

 

 

 

IDACORPcurrently has two shelf registration statements totaling $679 million that canbe used for the issuance of unsecured debt (including medium-term notes) andpreferred or common stock.

OnOctober 22, 2003, Humboldt County, Nevada issued, for the benefit of IPC, $49.8million Pollution Control Revenue Refunding Bonds (Idaho Power Company Project)Series 2003 due December 1, 2024.  IPCborrowed the proceeds from the issuance pursuant to a Loan Agreement withHumboldt County and is responsible for payment of principal, premium, if any,and interest on the bonds.  The bonds aresecured, as to principal and interest, by IPC first mortgage bonds and as toprincipal and interest when due, by an insurance policy issued by AmbacAssurance Corporation.  The bonds wereissued in an auction rate mode under which the interest rate is reset every 35days.  The initial auction rate was setat 0.95 percent.  At December 31, 2005,the auction rate was 3.15 percent. Proceeds from this issuance together with other funds provided by IPCwere used to redeem the outstanding $49.8 million Pollution Control RevenueBonds (Idaho Power Company Project) 8.3% Series 1984 due 2014, on December 1,2003, at 103 percent.

On March14, 2003, IPC filed a $300 million shelf registration statement that could beused for first mortgage bonds (including medium-term notes), unsecured debt andpreferred stock.  On May 8, 2003, IPCissued $140 million of secured medium-term notes in two series: $70 millionFirst Mortgage Bonds 4.25% Series due 2013 and $70 million First Mortgage Bonds5.50% Series due 2033.  Proceeds wereused to pay down IPC short-term borrowings incurred from the payment atmaturity of $80 million First Mortgage Bonds 6.40% Series due 2003 and theearly redemption of $80 million First Mortgage Bonds 7.50% Series due 2023, onMay 1, 2003.  On March 26, 2004, IPCissued $50 million First Mortgage Bonds 5.50% Series due 2034.  Proceeds were used to reduce short-termborrowings and replace short-term investments, which were used on March 15,2004 to pay at maturity the $50 million First Mortgage Bonds 8% Series due2004.  On August 16, 2004, IPC issued $55million First Mortgage Bonds 5.875% Series due 2034.  On September 20, 2004, the proceeds of thisissuance were used to redeem all of IPC's outstanding preferred stock.

OnJanuary 19, 2005, IPC filed a $245 million shelf registration statement thatcould be used for first mortgage bonds (including medium-term notes) and debtsecurities, and when combined with the $55 million remaining from the March 14,2003 shelf registration, provided for $300 million available in shelfregistration form.  On August 26, 2005IPC issued $60 million First Mortgage Bonds 5.30% Series due 2035.  Proceeds were invested in short-terminvestments, which were used on September 9, 2005 to pay at maturity the $60million First Mortgage Bonds 5.83% Series due 2005.  At December 31, 2005, $240 million remainedavailable to be issued on this shelf registration statement

OnAugust 17, 2004, IPC redeemed all $1 million of its Rural Electrification Administrationnotes.

OnAugust 30, 2005, IPC settled a forward-starting interest rate swap agreement bymaking a payment of $2.7 million to the counterparty of the agreement.  In accordance with regulatory accountingpractices under SFAS 71, IPC is amortizing this amount over the life of its 5.30%First Mortgage Bonds due 2035.

AtDecember 31, 2005 and 2004, the overall effective cost of IPC's outstandingdebt was 5.84 percent and 5.69 percent, respectively.

The amount of first mortgage bonds issuable by IPC islimited to a maximum of $1.1 billion and by property, earnings and otherprovisions of the mortgage and supplemental indentures thereto.  IPC may amend the indenture and increase thisamount without consent of the holders of the first mortgage bonds.  Substantially all of the electric utilityplant is subject to the lien of the mortgage. As of December 31, 2005, IPCcould issue under the mortgage approximately $560 million of additional firstmortgage bonds based on unfunded property additions and $452 million ofadditional first mortgage bonds based on retired first mortgage bonds.  At December 31, 2005, unfunded propertyadditions, which consist of electric property, were approximately $933 million.

At December 31, 2005, IFS had $48 million of debt relatedto investments in affordable housing with interest rates ranging from 3.65percent to 8.59 percent due between 2006 and 2010.  The investments in affordable housingdevelopments that collateralize this debt had a net book value of $81 millionat December 31, 2005.  IFS's $14 millionSeries 2003-1 tax credit note is non-recourse to both IFS and IDACORP.  The $8 million Series 2003-2 tax credit noteand other outstanding debt are recourse only to IFS.

In June 2004, Ida-West purchased from a third party $18million of debt issued by Marysville Hydro Partners, a 50-percent-owned,consolidated joint venture, for $11 million. This debt, previously consolidated under the provisions of FIN 46(R), isnow eliminated in consolidation. Ida-West borrowed $6 million from IDACORP for this transaction.

As a result of IDACORP's adoption of FIN 46R in January2004, other subsidiary debt increased $8 million from December 31, 2003.  This debt is non-recourse to IDACORP,personally guaranteed by the general partner and collateralized by property.

**6.  FAIRVALUE OF FINANCIAL INSTRUMENTS:**

The estimated fair value of IDACORP's financialinstruments has been determined using available market information andappropriate valuation methodologies.  Theuse of different market assumptions and/or estimation methodologies may have amaterial effect on the estimated fair value amounts.

Cash and cash equivalents, customer and otherreceivables, notes payable, accounts payable, interest accrued and taxesaccrued are reported at their carrying value as these are a reasonable estimateof their fair value.  The estimated fairvalues 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, 2005**

 

**December 31, 2004**

 

**Carrying**

** **

**Estimated**

** **

**Carrying**

** **

**Estimated**

 

**Amount**

** **

Fair Value

** **

**Amount**

** **

**Fair Value**

** **

**(thousands of dollars)**

**IDACORP**

 

 

 

 

 

 

 

 

 

 

 

**Assets:**

 

 

 

 

 

 

 

 

 

 

 

Notes receivable

$

7,049

 

$

6,879

 

$

10,376

 

$

10,245

Investments 

 

34,510

 

 

34,514

 

 

67,319

 

 

67,479

 

 

 

 

 

 

 

 

 

 

 

 

**Liabilities:**

 

 

 

 

 

 

 

 

 

 

 

Long-term debt

$

1,043,248

 

$

1,059,199

 

$

1,061,287

 

$

1,084,090

 

 

 

 

 

 

 

 

 

 

 

 

**IPC**

 

 

 

 

 

 

 

 

 

 

 

**Assets:**

 

 

 

 

 

 

 

 

 

 

 

Notes receivable

$

7,047

 

$

6,876

 

$

8,946

 

$

8,877

Investments 

 

21,137

 

 

21,137

 

 

53,155

 

 

53,155

 

 

 

 

 

 

 

 

 

 

 

 

**Liabilities:**

 

 

 

 

 

 

 

 

 

 

 

Long-term debt

$

987,045

 

$

1,003,651

 

$

987,045

 

$

1,008,369

 

 

 

 

 

 

 

 

 

 

 

 

 

**7.  NOTES PAYABLE:**

IDACORP has a $150 million credit facility that expireson March 31, 2010.  Under this facilityIDACORP pays a facility fee on the commitment, quarterly in arrears, based onits rating for senior unsecured long-term debt securities without third-partycredit enhancement as provided by Moody's Investors Service (Moody's) andStandard & Poor's Ratings Services (S&P).  Commercial paper may be issued up to theamounts supported by the bank credit facilities.

At December 31, 2005, IPC had regulatory authority toincur up to $250 million of short-term indebtedness.  IPC has a $200 million credit facility thatexpires on March 31, 2010.  Under thisfacility IPC pays a facility fee on the commitment, quarterly in arrears, basedon its rating for senior unsecured long-term debt securities withoutthird-party credit enhancement as provided by Moody's and S&P.  IPC's commercial paper may be issued up tothe amounts supported by the bank credit facilities.  There was no commercial paper outstanding atDecember 31, 2005 or 2004.

Balances and interest rates of IDACORP's short-termborrowings were as follows at December 31 (in thousands of dollars):

** **

**2005**

** **

**2004**

** **

** **

** **

**Effective**

** **

** **

** **

**Effective**

** **

**Amount**

** **

**Interest Rate**

** **

**Amount**

** **

**Interest Rate**

Commercial Paper

$

60,100

 

 

4.47%

 

$

35,400

 

 

2.52%

Notes Payable

 

-

 

 

-   

 

 

870

 

 

3.24%

Balance

$

60,100

 

 

 

 

$

36,270

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

**8.  COMMITMENTS AND CONTINGENCIES:**

As of December 31, 2005, IPC had agreements to purchaseenergy from 87 cogeneration and small power production (CSPP) facilities withcontracts ranging from one to 30 years. Under these contracts IPC is required to purchase all of the output fromthe facilities inside 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 purchased 715,209 megawatt-hours (MWh) ata cost of $43 million in 2005, 677,868 MWh at a cost of $40 million in 2004 and654,131 MWh at a cost of $38 million in 2003.

At December 31, 2005, IPC had the following long-termcommitments relating to purchases of energy, capacity, transmission rights andfuel:

** **

**2006**

2007

**2008**

**2009**

**2010**

**Thereafter**

 

 

 

 

 

 

 

 

 

 

 

 

 

Cogeneration and small

 

 

 

 

 

 

 

 

 

 

 

 

 

 power  production

 

$ 59,719

 

$70,283

 

$70,283

 

$73,753

 

$73,753

 

$1,039,377

Power and transmission

 

 

 

 

 

 

 

 

 

 

 

 

 

rights

 

148,818

 

14,362

 

8,762

 

6,193

 

3,714

 

13,001

Fuel

 

43,370

 

40,496

 

26,997

 

18,013

 

12,010

 

10,118

 

 

 

 

 

 

 

 

 

 

 

 

 

 

In addition, IDACORP has the following long-termcommitments for lease guarantees, maintenance and services, and industryrelated fees.

** **

**2006**

2007

**2008**

**2009**

**2010**

**Thereafter**

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating leases

 

$  3,994

 

$3,994

 

$2,700

 

$   771

 

$   771

 

$3,716

Maintenance and service

 

 

 

 

 

 

 

 

 

 

 

 

 

agreements

 

37,436

 

7,513

 

7,421

 

2,798

 

540

 

114

FERC and other  industry

 

 

 

 

 

 

 

 

 

 

 

 

 

related fees

 

10,219

 

5,278

 

5,262

 

5,094

 

5,094

 

24,367

 

 

 

 

 

 

 

 

 

 

 

 

 

 

IDACORP's expense for operating leases was approximately$4 million, $5 million and $4 million in 2005, 2004 and 2003, respectively.

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 is renewed eachDecember, was $60 million at December 31, 2005. Bridger Coal Company has a reclamation trust fund set aside specificallyfor the purpose of paying these reclamation costs.  Bridger Coal Company and IPC expect that thefund will be sufficient to cover all such costs.  Because of the existence of the fund, theestimated fair value of this guarantee is minimal.

In August 2003, IE sold its forward book of electricitytrading contracts to Sempra Energy Trading. As part of the sale, IE entered into an Indemnity Agreement with SempraEnergy Trading guaranteeing the performance of one of the counterpartiesthrough 2009.  The maximum amount payableby IE under the Indemnity Agreement is $20 million.  The indemnity agreement has been accountedfor in accordance with FIN 45, "Guarantor's Accounting and DisclosureRequirements for Guarantees, Including Indirect Guarantees of Indebtedness ofOthers," and did not have a significant effect on IDACORP's financialstatements.

Fromtime to time IDACORP and IPC are a party to legal claims, actions andcomplaints in addition to those discussed below.  IDACORP and IPC believe that they havemeritorious defenses to all lawsuits and legal proceedings.  Although they will vigorously defend againstthem, they are unable to predict with certainty whether or not they willultimately be successful.  However, basedon the companies' evaluation, they believe that the resolution of these matters,taking into account existing reserves, will not have a material adverse effecton IDACORP's or IPC's consolidated financial positions, results of operationsor cash flows.

**Legal Proceedings****PublicUtility District No. 1 of Grays Harbor County, Washington:** On October 15, 2002, Public Utility District No. 1 of Grays HarborCounty, Washington (Grays Harbor) filed a lawsuit in the Superior Court of theState of Washington, for the County of Grays Harbor, against IDACORP, IPC andIE.  On March 9, 2001, Grays Harborentered into a 20-megawatt (MW) purchase transaction with IPC for the purchaseof electric power from October 1, 2001 through March 31, 2002, at a rate of$249 per MWh.  In June 2001, with theconsent of Grays Harbor, IPC assigned all of its rights and obligations underthe contract to IE.  In its lawsuit,Grays Harbor alleged that the assignment was void and unenforceable, and soughtrestitution from IE and IDACORP, or in the alternative, Grays Harbor allegedthat the contract should be rescinded or reformed.  Grays Harbor sought as damages an amountequal to the difference between $249 per MWh and the "fair value" ofelectric power delivered by IE during the period October 1, 2001 through March31, 2002.

IDACORP, IPC and IE removed this action from the statecourt to the U.S. District Court for the Western District of Washington atTacoma.  On November 12, 2002, thecompanies filed a motion to dismiss Grays Harbor's complaint, asserting thatthe U.S. District Court lacked jurisdiction because the FERC has exclusivejurisdiction over wholesale power transactions and thus the matter is preemptedunder the Federal Power Act and barred by the filed-rate doctrine.  The court ruled in favor of the companies'motion to dismiss and dismissed the case with prejudice on January 28,2003.  On February 25, 2003, Grays Harborfiled a Notice of Appeal, appealing the final judgment of dismissal to the U.S.Court of Appeals for the Ninth Circuit. On August 10, 2004, the Ninth Circuit affirmed the dismissal of GraysHarbor's complaint, finding that Grays Harbor's claims were preempted byfederal law and were barred by the filed-rate doctrine.  The court also remanded the case to allowGrays Harbor leave to amend its complaint to seek declaratory relief only as tocontract formation, and held that Grays Harbor could seek monetary relief, ifat all, only from the FERC, and not from the courts.  IDACORP, IPC and IE sought rehearing from theNinth Circuit arguing that the court erred in granting leave to amend thecomplaint as such a declaratory relief claim would be preempted and would bebarred by the filed-rate doctrine.  TheNinth Circuit denied the rehearing request on October 25, 2004, and thedecision became final on November 12, 2004.

On that same date, the companies took steps to have thecase transferred and consolidated with other similar cases arising out of theCalifornia energy crisis currently pending before the Honorable Robert H.Whaley, sitting by designation in the Southern District of California andpresiding over Multidistrict Litigation Docket No. 1405, regarding CaliforniaWholesale Electricity Antitrust Litigation. On November 18, 2004, Grays Harbor filed an amended complaint allegingthat the contract was formed under circumstances of "mistake" as toan "artificial . . . power shortage." Grays Harbor asked that the contract therefore be declared"unenforceable" and found "unconscionable."  On December 23, 2004, the Judicial Panel onMultidistrict Litigation conditionally transferred the case to JudgeWhaley.  Grays Harbor sought to vacatethe transfer; however, on April 18, 2005, the Judicial Panel on MultidistrictLitigation ordered the case transferred. On May 18, 2005, IDACORP, IPC and IE filed a motion to dismiss theamended complaint.  The motion was heardon September 29, 2005.

On December 16, 2005, Judge Whaley issued an OrderSetting Status Conference wherein, rather than expressly ruling on thecompanies' motion to dismiss Grays Harbor's amended complaint, he ruled thateither Grays Harbor or the companies may, within 45 days of the date of theorder, petition the FERC to weigh in on this case in light of "the extensivehearings . . . already undertaken by FERC in the Northwest refundproceeding" which may be relevant to this case.  OnJanuary 27, 2006 Grays Harbor and the companies jointly filed astipulation requesting that the court stay the action and extend the time inwhich the parties may petition the FERC by sixty days to March 31, 2006 statingthat the parties felt the case was appropriate for mediation prior to furtherproceedings.  On January 31, 2006 thecourt approved the stipulation staying the case until March 31, 2006 andsetting a status conference for April 14, 2006. 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.

**Port of Seattle:**  On May 21, 2003,the Port of Seattle, a Washington municipal corporation, filed a lawsuitagainst 20 energy firms, including IPC and IDACORP, in the U.S. District Courtfor the Western District of Washington at Seattle.  The Port of Seattle's complaint alleges fraudand violations of state and federal antitrust laws and the Racketeer Influencedand Corrupt Organizations Act.  On December4, 2003, the Judicial Panel on Multidistrict Litigation transferred the case tothe Southern District of California for inclusion with several similarmultidistrict actions currently pending before the Honorable Robert H. Whaley.

All defendants, including IPC and IDACORP, moved todismiss the complaint in lieu of answering it. The motions were based on the ground that the complaint seeks to setalternative electrical rates, which are exclusively within the jurisdiction ofthe FERC and are barred by the filed-rate doctrine.  A hearing on the motion to dismiss was heardon March 26, 2004.  On May 28, 2004, thecourt granted IPC's and IDACORP's motion to dismiss.  In June 2004, the Port of Seattle appealedthe court's decision to the U.S. Court of Appeals for the Ninth Circuit.  On July 19, 2005 the companies filed a motionfor summary affirmance of the district court's order dismissing the Port ofSeattle's complaint.  The Ninth Circuitissued an order denying this motion on October 17, 2005.  The appeal has been fully briefed; and oralargument has been scheduled for March 7, 2006. 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.

**Wah Chang:**  On May 5, 2004,Wah Chang, a division of TDY Industries, Inc., filed two lawsuits in the U.S.District Court for the District of Oregon against numerous defendants.  IDACORP, IE and IPC are named as defendantsin one of the lawsuits.  The complaintsallege violations of federal antitrust laws, violations of the RacketeerInfluenced and Corrupt Organizations Act, violations of Oregon antitrust lawsand wrongful interference with contracts. Wah Chang's complaint is based on allegations relating to the westernenergy situation.  These allegationsinclude bid rigging, falsely creating congestion and misrepresenting the sourceand destination of energy.  The plaintiffseeks compensatory damages of $30 million and treble damages.

On September 8, 2004, this case was transferred andconsolidated with other similar cases currently pending before the HonorableRobert H. Whaley.  The companies' motionto dismiss the complaint was granted on February 11, 2005.  Wah Chang appealed to the Ninth Circuit onMarch 10, 2005.  The Ninth Circuit set abriefing schedule on the appeal, requiring Wah Chang's opening brief to befiled by July 6, 2005.  On May 18, 2005,Wah Chang filed a motion to stay the appeal or in the alternative tovoluntarily dismiss the appeal without prejudice to reinstatement.  The companies opposed the motion and filed across-motion asking the Court to summarily affirm the district court's order ofdismissal.  On July 8, 2005, the NinthCircuit denied Wah Chang's motion and also denied the companies' motion forsummary affirmance without prejudice to renewal following the filing of WahChang's opening brief.  Wah Chang'sopening brief was filed on September 21, 2005. On October 11, 2005 the companies, along with the other defendants,filed a motion to consolidate this appeal with Wah Chang v. Duke Energy Tradingand Marketing currently pending before the Ninth Circuit.  On October 18, 2005 the Ninth Circuit grantedthe motion to consolidate and established a revised briefing schedule.  The companies filed an answering brief onNovember 30, 2005.  Wah Chang's replybrief was filed on January 6, 2006.  Theappeal has been fully briefed; however, no date has yet been set for oralargument.  The companies intend tovigorously defend their position in this proceeding and believe this matterwill not have a material adverse effect on their consolidated financialpositions, results of operations or cash flows.

**City of Tacoma:**  On June 7, 2004,the City of Tacoma, Washington filed a lawsuit in the U.S. District Court forthe Western District of Washington at Tacoma against numerous defendantsincluding IDACORP, IE and IPC.  The Cityof Tacoma's complaint alleges violations of the Sherman Antitrust Act.  The claimed antitrust violations are based onallegations of energy market manipulation, false load scheduling and bidrigging and misrepresentation or withholding of energy supply.  The plaintiff seeks compensatory damages ofnot less than $175 million.

On September 8, 2004, this case was transferred andconsolidated with other similar cases currently pending before the HonorableRobert H. Whaley.  The companies' motionto dismiss the complaint was granted on February 11, 2005.  The City of Tacoma appealed to the NinthCircuit on March 10, 2005.

On August 9, 2005, the companies moved for summaryaffirmance of the district court's order dismissing the City of Tacoma'scomplaint.  The City of Tacoma filed aresponse to the companies' motion for summary affirmance on August 24, 2005.  The Ninth Circuit denied the companies'motion for summary affirmance on November 3, 2005.  The appeal has been fully briefed; however,no date has yet been set for oral argument. 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.

**Wholesale Electricity Antitrust Cases I & II:** These cross-actions against IE and IPC emerged from multiple Californiastate court proceedings first initiated in late 2000 against various powergenerators/marketers by various California municipalities and citizens.  Suit was filed against entities includingReliant Energy Services, Inc., Reliant Ormond Beach, L.L.C., Reliant EnergyEtiwanda, L.L.C., Reliant Energy Ellwood, L.L.C., Reliant Energy Mandalay,L.L.C. and Reliant Energy Coolwater, L.L.C. (collectively, Reliant); and DukeEnergy Trading and Marketing, L.L.C., Duke Energy Morro Bay, L.L.C., DukeEnergy Moss Landing, L.L.C., Duke Energy South Bay, L.L.C. and Duke EnergyOakland, L.L.C. (collectively, Duke). While varying in some particulars, these cases made a common claim thatReliant, Duke and certain others (not including IE or IPC) colluded toinfluence the price of electricity in the California wholesale electricitymarket.  The plaintiffs asserted variousclaims that the defendants violated the California Antitrust Law (theCartwright Act), Business and Professions Code Section 16720 and California'sUnfair Competition Law, Business and Professions Code Section 17200.  Among the acts complained of are bid rigging,information exchanges, withholding of power and other wrongful acts.  These actions were subsequently consolidated,resulting in the filing of Plaintiffs' Master Complaint in San Diego Superior Courton March 8, 2002.

On April 22, 2002, more than a year after the initialcomplaints were filed, two of the original defendants, Duke and Reliant, filedseparate cross-complaints against IPC and IE, and approximately 30 othercross-defendants.  Duke and Reliant'scross-complaints sought indemnity from IPC, IE and the other cross-defendantsfor an unspecified share of any amounts they must pay in the underlying suitsbecause, they allege, other market participants like IPC and IE engaged in thesame conduct at issue in the Plaintiffs' Master Complaint.  Duke and Reliant also sought declaratoryrelief as to the respective liability and conduct of each of thecross-defendants in the actions alleged in the Plaintiffs' MasterComplaint.  Reliant also asserted a claimagainst IPC for alleged violations of the California Unfair Competition Law,Business and Professions Code Section 17200. As a buyer of electricity in California, Reliant requested the samerelief from the cross-defendants, including IPC, as that sought by plaintiffsin the Plaintiffs' Master Complaint as to any power Reliant purchased throughthe California markets.

Some of the newly added defendants (foreign citizens andfederal agencies) removed that litigation to federal court.  IPC and IE, together with numerous otherdefendants added by the cross-complaints, moved to dismiss these claims, andthose motions were heard in September 2002, together with motions to remand thecase back to state court filed by the original plaintiffs.  On December 13, 2002, the U.S. District Courtgranted Plaintiffs' Motion to Remand to state court, but did not issue a rulingon IPC and IE's motion to dismiss.  TheU.S. Court of Appeals for the Ninth Circuit granted certain Defendants andCross-Defendants' Motions to Stay the Remand Order while they appeal theorder.  The briefing on the appeal wascompleted in December 2003.  On December8, 2004, the Ninth Circuit issued its opinion in People of California v. NRGEnergy, Inc., et al., which affirmed the district court's remand of these casesto state court and dismissed certain federal government defendants due to theirsovereign immunity from suit.

On June 3, 2005, the cross-defendants, including IPC andIE, filed a demurrer in state court seeking to dismiss the cross-complaintsfiled by Duke and Reliant.  On August 8,2005, before that demurrer was to be heard, the Clerk of the Court enteredDuke's voluntary dismissal, with prejudice, of the cross-complaint against IEand IPC.  Further briefing and hearing onIE and IPC's demurrer to the Reliant cross-complaint was stayed pending theoutcome of the demurrer filed by Reliant on the Master Complaint.  On September 22, 2005, the Court tookReliant's demurrer off calendar pending approval of a proposed settlement as tothe plaintiff's Master Complaint.  OnOctober 3, 2005 the court sustained the defendants' (other than Reliant's)joint demurrer to the Master Complaint and scheduled a status conference todiscuss the status of the cross-complaints. On October 13, 2005 the court set IE and IPC's demurrer on thecross-complaint for hearing on December 23, 2005.

However, on November 14, 2005, Judge Joan M. Lewisapproved a stipulation between the cross-defendants, including IE and IPC, andReliant.  This stipulation provided fordismissal of IE and IPC by Reliant with prejudice subject to reinstatement inthe event that approval and finalization of a settlement agreement betweenReliant and the underlying plaintiffs in these cases does not occur.  The December 23, 2005 hearing on IE and IPC'sdemurrer to the cross-complaint was taken off the calendar.  A hearing regarding approval of the Reliantsettlement was held on Friday January 6, 2006 before Judge Lewis.

Reliant has filed a request for dismissal of IE and IPCwith prejudice, which was entered by the clerk of the court on December 19,2005.  Pursuant to IE and IPC'sstipulation with Reliant, the dismissal will become final once any judgment andorder from the Court approving the Reliant settlement with the plaintiffs becomesfinal (i.e., once the time for any appeal on the order approving thesettlements runs or, if review is sought, the trial court's approval order isaffirmed after resolution of all appeals). The time for an appeal from an order approving the settlements wouldrange from 30 to 90 days after entry of the Court's judgments and orders.

If the Court does not grant final approval for theReliant settlement, Reliant may elect to reactivate its cross-complaint.  Similarly, should the Court for any reason failto approve the Reliant settlement by May 31, 2006, IE and IPC may withdraw fromthe stipulation agreement by giving ten days' advance written notice.  The companies intend to vigorously defendtheir position in this proceeding and believe this matter will not have amaterial adverse effect on their consolidated financial positions, results ofoperations or cash flows.

**Western Energy Proceedings at the FERC:**CaliforniaPower Exchange Chargeback:As a componentof IPC's non-utility energy trading in the State of California, IPC, in January1999, entered into a participation agreement with the California Power Exchange(CalPX), a California non-profit public benefit corporation.  The CalPX, at that time, operated a wholesaleelectricity market in California by acting as a clearinghouse through whichelectricity was bought and sold. Pursuant to the participation agreement, IPC could sell power to theCalPX under the terms and conditions of the CalPX Tariff.  Under the participation agreement, if aparticipant in the CalPX defaulted on a payment, the other participants wererequired to pay their allocated share of the default amount to the CalPX.  The allocated shares were based upon thelevel of trading activity, which included both power sales and purchases, ofeach participant during the preceding three-month period.

On January 18, 2001, the CalPX sent IPC an invoice for $2million - a "default share invoice" - as a result of an allegedSouthern California Edison payment default of $215 million for power purchases.  IPC made this payment.  On January 24, 2001, IPC terminated itsparticipation agreement with the CalPX. On February 8, 2001, the CalPX sent a further invoice for $5 million,due on February 20, 2001, as a result of alleged payment defaults by SouthernCalifornia Edison, Pacific Gas and 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 CalPXlater reversed IPC's payment of the January 18, 2001 invoice, but on June 20,2001 invoiced IPC for an additional $2 million which the CalPX has notreversed.  The CalPX owes IPC $14 millionfor power sold in November and December including $2 million associated withthe default share invoice dated June 20, 2001. IPC essentially discontinued energy trading with the CalPX and theCalifornia Independent System Operator (Cal ISO) in December 2000.

IPC believes that the default invoices were not properand that IPC owes no further amounts to the CalPX.  IPC has pursued all available remedies in itsefforts to collect amounts owed to it by the CalPX.  On February 20, 2001, IPC filed a petitionwith the FERC to intervene in a proceeding that requested the FERC to suspendthe use of the CalPX chargeback methodology and provide for further oversightin the CalPX's implementation of its default mitigation procedures.

A preliminary injunction was granted by a federal judgein the U.S. District Court for the Central District of California enjoining theCalPX from declaring any CalPX participant in default under the terms of theCalPX Tariff.  On March 9, 2001, theCalPX filed for Chapter 11 protection with the U.S. Bankruptcy Court, CentralDistrict of California.

In April 2001, Pacific Gas and Electric Company filed forbankruptcy.  The CalPX and the Cal ISOwere among the creditors of Pacific Gas and Electric Company.  To the extent that Pacific Gas and ElectricCompany's bankruptcy filing affects the collectibility of the receivables fromthe CalPX and the Cal ISO, the receivables from these entities are at greaterrisk.

The FERC issued an order on April 6, 2001 requiring theCalPX to rescind all chargeback actions related to Pacific Gas and ElectricCompany's and Southern California Edison's liabilities.  Shortly after the issuance of that order, theCalPX segregated the CalPX chargeback amounts it had collected in a separateaccount.  The CalPX claimed it was awaitingfurther orders from the FERC and the bankruptcy court before distributing thefunds that it collected under its chargeback tariff mechanism.  On October 7, 2004, the FERC issued an orderdetermining that it would not require the disbursement of chargeback fundsuntil the completion of the California refund proceedings.  On November 8, 2004, IE, along with a numberof other parties, sought rehearing of that order.  On March 15, 2005, the FERC issued an orderon rehearing confirming that the CalPX is to continue to hold the chargebackfunds, but solely to offset seller-specific shortfalls in the seller's CalPXaccount at the conclusion of the California refund proceeding.  Balances are to be returned to the respectivesellers at the conclusion of a seller's participation in the refund proceeding.  Powerex Corp. filed a petition for review ofthe Commission's order on March 24, 2005 in the D.C. Circuit.  Neither a briefing schedule nor a date fororal argument has been set.

Based upon the settlement agreement filed with the FERCon February 17, 2006 between the California Parties and IE and IPC discussedbelow in "California Refund," the California Parties have agreed tosupport a request that the FERC authorize the CalPX to release $2.27 millionrelated to the chargeback proceeding to IE and IPC.

California Refund:In April 2001, theFERC issued an order stating that it was establishing price mitigation forsales in the California wholesale electricity market.  Subsequently, in a June 19, 2001 order, theFERC expanded that price mitigation plan to the entire western United States electricallyinterconnected system.  That planincluded the potential for orders directing electricity sellers into Californiasince October 2, 2000 to refund portions of their spot market sales prices ifthe FERC determined that those prices were not just and reasonable, andtherefore not in compliance with the Federal Power Act.  The June 19 order also required all buyersand sellers in the Cal ISO market during the subject time frame to participatein settlement discussions to explore the potential for resolution of theseissues without further FERC action.  Thesettlement discussions failed to bring resolution of the refund issue and as aresult, the FERC's Chief Administrative Law Judge submitted a Report and Recommendationto the FERC recommending that the FERC adopt the methodology set forth in thereport and set for evidentiary hearing an analysis of the Cal ISO's and theCalPX's spot markets to determine what refunds may be due upon application ofthat methodology.

On July 25, 2001, the FERC issued an order establishingevidentiary hearing procedures related to the scope and methodology forcalculating refunds related to transactions in the spot markets operated by theCal ISO and the CalPX during the period October 2, 2000 through June 20, 2001(Refund Period).

The Administrative Law Judge issued a Certification ofProposed Findings on California Refund Liability on December 12, 2002.

The FERCissued its Order on Proposed Findings on RefundLiability on March 26, 2003.  In largepart, the FERC affirmed the recommendations of its Administrative LawJudge.  However, the FERC changed acomponent of the formula the Administrative Law Judge was to apply when itadopted findings of its staff that published California spot market prices forgas did not reliably reflect the prices a gas market, that had not beenmanipulated, would have produced, despite the fact that many gas buyers paidthose amounts.  The findings of theAdministrative Law Judge, as adjusted by the FERC's March 26, 2003 order, areexpected to increase the offsets to amounts still owed by the Cal ISO and theCalPX to the companies.  Calculationsremain uncertain because (1) the FERC has required the Cal ISO to correct anumber of defects in its calculations, (2) it is unclear what, if any, effectthe ruling of the Ninth Circuit in Bonneville Power Administration v. FERC,described below, might have on the ISO's calculations, and (3) the FERC hasstated that if refunds will prevent a seller from recovering its California portfoliocosts during the Refund Period, it will provide an opportunity for a costshowing by such a respondent.  On August8, 2005, the FERC issued an Order establishing the framework for filings bysellers who elected to make such a cost showing.  On September 14, 2005 IE and IPC made a jointcost filing, as did approximately thirty other sellers.  On October 11, 2005, the California entitiesfiled comments on the companies' cost filing and those made by other parties.  IPC and IE submitted reply comments onOctober 19, 2005.  The Californiaentities filed supplemental comments on October 24, 2005 and IPC and IE filedsupplemental reply comments on October 27, 2005.  IPC and IE are unsure of the impact theFERC's rulings will have on the refunds due from California.  However, as to potential refunds, if any, IPCand IE believe their exposure is likely to be offset by amounts due fromCalifornia entities.

InDecember of 2005, IE and IPC reached a tentative agreement with the CaliforniaParties settling matters encompassed by the California Refund proceedingincluding IE and IPC's cost filing and refund obligation.  On January 20, 2006, the Parties filed arequest with the FERC asking that the FERC defer ruling on IE and IPC's costfiling for thirty days so the parties could complete and file the settlementagreement with the FERC.  On January 26,2006, the FERC granted the requested deferral and required that the settlementbe 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, the California Public Utilities Commission, theCalifornia Electricity Oversight Board, the California Department of WaterResources and the California Attorney General) an Offer of Settlement at theFERC.  Final comments on the settlementare due to be filed by March 20, 2006, after which the FERC will determinewhether to approve the settlement.  Ifthe settlement is approved by the FERC, IE and IPC will assign $24.25 millionof the rights to accounts receivable from the Cal ISO and CalPX to theCalifornia Parties to pay into an escrow account for refunds to settlingparties.  Amounts from that escrow not usedfor settling parties and $1.5 million of the remaining IE and IPC receivableswhich are to be retained by the CalPX are available to fund, at leastpartially, payment of the claims of any non-settling parties if they prevail inthe remaining litigation of this matter. Approximately $10.25 million of the remaining IE and IPC receivables areto be released to IE and IPC.  In thefourth quarter of 2005 IE reduced by $9.5 million to $32 million its reserveagainst these receivables.

IE, along with a number of other parties, filed anapplication with the FERC on April 25, 2003 seeking rehearing of the March 26,2003 order.  On October 16, 2003, theFERC issued two orders denying rehearing of most contentions that had beenadvanced and directing the Cal ISO to prepare its compliance filing calculatingrevised Mitigated Market Clearing Prices and refund amounts within fivemonths.  The Cal ISO has since, on anumber of occasions, requested additional time to complete its compliancefilings.  This Cal ISO compliance filinghas been delayed until at least March 2006. The Cal ISO is required to update the FERC on its progress monthly.

On December 2, 2003, IE petitioned the U.S. Court ofAppeals for the Ninth Circuit for review of the FERC's orders, and since thattime, dozens of other petitions for review have been filed.  The Ninth Circuit consolidated IE's and theother parties' petitions with the petitions for review arising from earlierFERC orders in this proceeding, bringing the total number of consolidatedpetitions to more than 100.  The NinthCircuit held the appeals in abeyance pending the disposition of the marketmanipulation claims discussed below and the development of a comprehensive planto brief this complicated case.  Certainparties also sought further rehearing and clarification before the FERC.  On September 21, 2004, the Ninth Circuitconvened case management proceedings, a procedure reserved to help organizecomplex 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 was held on April 12-13,2005.  On September 6, 2005 the NinthCircuit issued its decision in one of the severed cases, Bonneville PowerAdministration v. FERC.  In thatdecision, the Ninth Circuit concluded that the FERC lacked refund authorityover wholesale electric energy sales made by governmental entities andnon-public utilities.  The time forrequests for rehearing was to expire on October 21, 2005, but has been extendeduntil 45 days after the Ninth Circuit issues its decision in the other severedcases.  The companies cannot predictwhether rehearing will be sought and, if sought, whether it will be granted orwhat action the FERC might take if the matter is remanded.

On May 12, 2004, the FERC issued an order clarifyingportions of its earlier refund orders and, among other things, denying aproposal made by Duke Energy North America and Duke Energy Trading andMarketing (and supported by IE) to lodge as evidence a contested settlement ina separate complaint proceeding, California Public Utilities Commission (CPUC)v. El Paso, et al.  The CPUC's complaintalleged that the El Paso companies manipulated California energy markets bywithholding pipeline transportation capacity into California in order to driveup natural gas prices immediately before and during the California energycrisis in 2000-2001.  The settlement willresult in the payment by El Paso of approximately $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 otherparties, has sought rehearing of the May 12, 2004 order.  On November 23, 2004, the FERC deniedrehearing and within the statutory time allowed for petitions, a number ofparties, including IE, filed petitions for review of the FERC's order with theNinth Circuit.  These petitions havesince been consolidated with the larger number of review petitions inconnection with the California refund proceeding.

In June 2001, IPC transferred its non-utility wholesaleelectricity marketing operations to IE. Effective with this transfer, the outstanding receivables and payableswith the CalPX and the Cal ISO were assigned from IPC to IE.  At December 31, 2005, with respect to theCalPX chargeback and the California refund proceedings discussed above, theCalPX and the Cal ISO owed $14 million and $30 million, respectively, forenergy sales made to them by IPC in November and December 2000.  IE has accrued a reserve of $32 millionagainst these receivables.  This reservewas calculated taking into account the uncertainty of collection given theCalifornia energy situation.  Based onthe reserve recorded as of December 31, 2005, IDACORP believes that the futurecollectibility of these receivables or any potential refunds ordered by theFERC would not have a material adverse effect on its consolidated financialposition, results of operations or cash flows.

On March 20, 2002, the CaliforniaAttorney General filed a complaint with the FERC against various sellers in thewholesale power market, including IE and IPC, alleging that the FERC'smarket-based rate requirements violate the Federal Power Act, and, even if themarket-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 that refunds for amounts charged betweenmarket-based rates and cost-based rates should be ordered.  The FERC denied the challenge to market-basedrates and refused to order refunds, but did require sellers, including IE andIPC, to refile their quarterly reports to include transaction-specificdata.  The Attorney General appealed theFERC's decision to the U.S. Court of Appeals for the 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 Circuit issued its decision onSeptember 9, 2004, concluding that market-based tariffs are permissible underthe Federal Power Act, but remanded the matter to the FERC to consider whetherthe FERC should exercise remedial power (including some form of refunds) when amarket participant failed to submit reports that the FERC relies on to confirmthe justness and reasonableness of rates charged.  Certain parties to the litigation have soughtrehearing.  The companies cannot predictwhether rehearing will be granted or what action the FERC might take if thematter is remanded.

On May26, 2005 the California Parties filed a motion to lodge additional evidence,primarily audiotapes produced by Enron employees, in the California RefundProceedings in Docket No. EL00-95.  Anumber of parties, including IDACORP, answered in opposition to that motion.

Market Manipulation:In a November20, 2002 order, the FERC permitted discovery and the submission of evidencerespecting market manipulation by various sellers during the western powercrises of 2000 and 2001.

On March 3, 2003, the California Parties (certaininvestor owned utilities, the California Attorney General, the CaliforniaElectricity Oversight Board and the CPUC) filed voluminous documentationasserting that a number of wholesale power suppliers, including IE and IPC, hadengaged in a variety of forms of conduct that the California Parties contendedwere impermissible.  Although thecontentions of the California Parties were contained in more than 11 compactdiscs of data and testimony, approximately 12,000 pages, IE and IPC werementioned only in limited contexts with the overwhelming majority of the claimsof the California Parties relating to the conduct of other parties.

The California Parties urged the FERC to apply theprecepts of its earlier decision, to replace actual prices charged in everyhour starting May 1, 2000 through the beginning of the existing Refund Periodwith a Mitigated Market Clearing Price, seeking approximately $8 billion inrefunds to the Cal ISO and the CalPX.  OnMarch 20, 2003, numerous parties, including IE and IPC, submitted briefs andresponsive testimony.

In its March 26, 2003 order, discussed above in"California Refund," the FERC declined to generically apply itsrefund determinations to sales by all market participants, although it statedthat it reserved the right to provide remedies for the market against partiesshown to have engaged in proscribed conduct.

On June 25, 2003, the FERC ordered over 50 entities thatparticipated in the western wholesale power markets between January 1, 2000 andJune 20, 2001, including IPC, to show cause why certain trading practices didnot constitute gaming or anomalous market behavior in violation of the Cal ISOand 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 practices within45 days of receipt of the Cal ISO data. IPC submitted its responses to the show cause orders on September 2 and4, 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 Staffdetermined it had no basis to proceed with allegations of false imports andpaper trading and IPC agreed to pay $83,373 to settle allegations of circularscheduling.  IPC believed that it haddefenses to the circular scheduling allegation but determined that the cost ofsettlement was less than the cost of litigation.  In the settlement, IPC did not admit anywrongdoing or violation of any law.  Withrespect to the "partnership" order, the FERC Staff submitted a motionto the FERC to dismiss the proceeding because materials submitted by IPCdemonstrated that IPC did not use its "parking" and"lending" arrangement with Public Service Company of New Mexico toengage in "gaming" or anomalous market behavior("partnership").  The"gaming" settlement was approved by the FERC on March 3, 2004.  Eight parties have requested rehearing of theFERC's March 3, 2004 order, but the FERC has not yet acted on those requests.  The motion to dismiss the"partnership" proceeding was approved by the FERC in an order issuedon January 23, 2004 and rehearing of that order was not sought within the timeallowed by statute.  Some of theCalifornia Parties and other parties have petitioned the U.S. Court of Appealsfor the Ninth Circuit and the District of Columbia Circuit for review of theFERC's orders initiating the show cause proceedings.  Some of the parties contend that the scope ofthe proceedings initiated by the FERC was too narrow.  Other parties contend that the ordersinitiating the show cause proceedings 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 FERC had moved the District of ColumbiaCircuit to dismiss these petitions on the grounds of prematurity and lack ofripeness and finality.  The transferorder was issued before a ruling from the District of Columbia Circuit and themotions, if renewed, will be considered by the Ninth Circuit.  IPC is not able to predict the outcome of thejudicial determination of these issues.

On June 25, 2003, the FERC also issued an orderinstituting an investigation of anomalous bidding behavior and practices in thewestern wholesale power markets.  In thisinvestigation, the FERC was to review evidence of alleged economic withholdingof generation.  The FERC determined thatall bids into the CalPX and the Cal ISO markets for more than $250 per MWh forthe time period May 1, 2000 through October 1, 2000 would be considered primafacie evidence of economic withholding. The FERC Staff issued data requests in this investigation to over 60market participants including IPC.  IPCresponded to the FERC's data requests. In a letter dated May 12, 2004, the FERC's Office of Market Oversightand Investigations advised that it was terminating the investigation as to IPC.  In March 2005, the California AttorneyGeneral, the CPUC, the California Electricity Oversight Board and Pacific Gasand Electric Company sought judicial review in the Ninth Circuit of the FERC'stermination of this investigation as to IPC and approximately 30 other marketparticipants.  IPC has moved to intervenein these proceedings.  On April 25, 2005,Pacific Gas and Electric Company sought review in the Ninth Circuit of anotherFERC order in the same docketed proceeding confirming the agency's earlierdecision not to allow the participation of the California Parties in what theFERC characterized as its non-public investigative proceeding.

The February 17, 2006 Offer of Settlement, if approved bythe FERC, would terminate the investigations the FERC initiated without findingof wrongdoing by IE or IPC, and would provide for the disposition of the"gaming" settlement.

Pacific Northwest Refund:On July 25,2001, the FERC issued an order establishing another proceeding to explorewhether there may have been unjust and unreasonable charges for spot marketsales in the Pacific Northwest during the period December 25, 2000 through June20, 2001.  The FERC Administrative LawJudge submitted recommendations and findings to the FERC on September 24, 2001.  The Administrative Law Judge found thatprices should be governed by the Mobile-Sierra standard of the public interestrather than the just and reasonable standard, that the Pacific Northwest spotmarkets were competitive and that no refunds should be allowed.  Procedurally, the Administrative Law Judge'sdecision is a recommendation to the commissioners of the FERC.  Multiple parties submitted comments to theFERC with respect to the Administrative Law Judge's recommendations.  The Administrative Law Judge's recommendedfindings had been pending before the FERC, when at the request of the City ofTacoma and the Port of Seattle on December 19, 2002, the FERC reopened theproceedings to allow the submission of additional evidence related to allegedmanipulation of the power market by Enron and others.  As was the case in the California refundproceeding, at the conclusion of the discovery period, parties alleging marketmanipulation were to submit their claims to the FERC and responses were due onMarch 20, 2003.  Grays Harbor, whose civillitigation claims were dismissed, as noted above, intervened in this FERCproceeding, asserting on March 3, 2003 that its six-month forward contract, forwhich performance had been completed, should be treated as a spot marketcontract for purposes of the FERC's consideration of refunds and is requestingrefunds from IPC of $5 million.  GraysHarbor did not suggest that there was any misconduct by IPC or IE.  The companies submitted responsive testimonydefending vigorously against Grays Harbor's refund claims.

In addition, the Port of Seattle, the City of Tacoma andthe City of Seattle made filings with the FERC on March 3, 2003 claiming thatbecause some market participants drove prices up throughout the west throughacts of manipulation, prices for contracts throughout the Pacific Northwestmarket should be re-set starting in May 2000 using the same factors the FERCwould use for California markets. Although the majority of these claims are generic, they named a numberof power market suppliers, including IPC and IE, as having used parkingservices provided by other parties under FERC-approved tariffs and thus asbeing candidates for claims of improperly having received congestion revenuesfrom the Cal ISO.  On June 25, 2003,after having considered oral argument held earlier in the month, the FERCissued its Order Granting Rehearing, Denying Request to Withdraw Complaint andTerminating Proceeding, in which it terminated the proceeding and denied claimsthat refunds should be paid.  The FERCdenied rehearing on November 10, 2003, triggering the right to file forreview.  The Port of Seattle, the City ofTacoma, the City of Seattle, the California Attorney General, the CPUC andPuget Sound Energy, Inc. filed petitions for review in the Ninth Circuit.  These petitions have been consolidated.  Grays Harbor did not file a petition forreview, although it has sought to intervene in the proceedings initiated by thepetitions of others.  On July 21, 2004,the City of Seattle submitted to the Ninth Circuit in the Pacific Northwestrefund petition for review a motion requesting leave to offer additionalevidence before the FERC in order to try to secure another opportunity forreconsideration by the FERC of its earlier rulings.  The evidence that the City of Seattle seeksto introduce before the FERC consisted of audio tapes of what purports to beEnron trader conversations containing inflammatory language that have been thesubject of coverage in the press.  UnderSection 313(b) of the Federal Power Act, a court is empowered to direct theintroduction of additional evidence if it is material and could not have beenintroduced during the underlying proceeding. On September 29, 2004, the Ninth Circuit denied the City of Seattle'smotion for leave to adduce evidence, without prejudice to renewing the requestfor remand in the briefing in the Pacific Northwest refund case.  Briefing was completed on May 25, 2005;however, no date has been set for oral argument.

The companies are unable to predict the outcome of thesematters.

**Shareholder Lawsuits:** On May 26,2004 and June 22, 2004, respectively, two shareholder lawsuits were filedagainst IDACORP and certain of its directors and officers.  The lawsuits, captioned Powell, et al. v.IDACORP, Inc., et al. and Shorthouse, et al. v. IDACORP, Inc., et al., raiselargely similar allegations.  Thelawsuits are putative class actions brought on behalf of purchasers of IDACORPstock between February 1, 2002 and June 4, 2002, and were filed in the U.S.District Court for the District 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.

The complaints alleged that, during the purported classperiod, IDACORP and/or certain of its officers and/or directors made materiallyfalse and misleading statements or omissions about the company's financialoutlook in violation of Sections 10(b) and 20(a) of the Securities Exchange Actof 1934, as amended, and Rule 10b-5, thereby causing investors to purchaseIDACORP's common stock at artificially inflated prices.  More specifically, the complaints allegedthat IDACORP failed to disclose and misrepresented the following materialadverse facts which were known to defendants or recklessly disregarded by them:(1) IDACORP failed to appreciate the negative impact that lower volatility andreduced pricing spreads in the western wholesale energy market would have onits marketing subsidiary, IE; (2) IDACORP would be forced to limit itsorigination activities to shorter-term transactions due to increasingregulatory uncertainty and continued deterioration of creditworthycounterparties; (3) IDACORP failed to account for the fact that IPC may notrecover from the lingering effects of the prior year's regional drought and (4)as a result of the foregoing, defendants lacked a reasonable basis for theirpositive statements about IDACORP and their earnings projections.  The Powell complaint also alleged that thedefendants' conduct artificially inflated the price of IDACORP's commonstock.  The actions seek an unspecifiedamount of damages, as well as other forms of relief.  By order dated August 31, 2004, the courtconsolidated the Powell and Shorthouse cases for pretrial purposes, and orderedthe plaintiffs to file a consolidated complaint within 60 days.  On November 1, 2004, IDACORP and the directorsand officers 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 alleged that during the class periodIDACORP and/or certain of its officers and/or directors made materially falseand misleading statements or omissions about its business operations, andspecifically the IE financial outlook, in violation of Rule 10b-5, therebycausing investors to purchase IDACORP's common stock at artificially inflatedprices.  The new complaint alleged thatIDACORP failed to disclose and misrepresented the following material adversefacts which were known to it or recklessly disregarded by it: (1) IDACORPfalsely inflated the value of energy contracts held by IE in order to reporthigher revenues and profits; (2) IDACORP permitted IPC to inappropriately grantnative load priority for certain energy transactions to IE; (3) IDACORP failedto file 13 ancillary service agreements involving the sale of power for resalein interstate 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 tomaintain a false perception of continued growth that inflated itsearnings.  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 actionseeks 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 theirresponse to the plaintiff's opposition on April 29, 2005 and oral argument onthe motion was held on May 19, 2005.

On September 14, 2005, Magistrate Judge Mikel H. Williamsof the U.S. District Court for the District of Idaho issued a Report andRecommendation that the defendants' motion to dismiss be granted and that thecase 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._____, 125 S. Ct. 1627 (2005).  TheMagistrate Judge also concluded that it would be futile to afford theplaintiffs an opportunity to file an amended complaint because it did notappear that they could cure the deficiencies in their pleadings.  The parties have each filed objections to differentparts of the Magistrate Judge's Report and Recommendation, and the matter isnow before the District Judge.

IDACORP and the other defendants intend to defendthemselves vigorously against the allegations. IDACORP cannot, however, predict the outcome of these matters.

**Powerex:** On August 31, 2004, Powerex Corp., thewholly-owned power marketing subsidiary of BC Hydro, a Crown Corporation of theprovince of British Columbia, Canada, filed a lawsuit against IE and IDACORP inthe U.S. District Court for the District of Idaho.  Powerex Corp. alleges that IE breached anoral and written contract regarding the assignment of transmission capacity forelectric power by IE to Powerex Corp. for a 14 month period and for intentionalinterference with Powerex Corp.'s alleged contract with IE.  Powerex Corp. seeks damages in the amount of$14,254,811.  On November 29, 2004, thecompanies filed an answer to Powerex Corp.'s complaint, denying all liabilityto the plaintiffs, and asserting certain affirmative defenses.  The parties have completed factual(non-expert) discovery, and the companies filed a motion for summary judgmenton February 28, 2006.  The parties willparticipate in a court ordered mediation scheduled for March 23, 2006.  If necessary, a trial date for the matter hasbeen set for May 16,  2006.  The companies intend to vigorously defendtheir position in this proceeding but cannot predict the outcome of thismatter.

**9. STOCK-BASED COMPENSATION:**

IDACORP has two employeestock-based compensation plans, the 2000 Long-Term Incentive and CompensationPlan (LTICP) and the 1994 Restricted Stock Plan (RSP).  These plans are intended to align employeeand shareholder objectives related to its long-term growth.  IDACORP also has one non-employee stock-basedcompensation plan, the Director Stock Plan (DSP).  The purpose of the DSPis to increase directors' stock ownership through stock-baseddirector compensation.

The LTICP for officers, key employees and directors,permits the grant of nonqualified stock options, incentive stock options, stockappreciation rights, restricted stock, restricted stock units, performanceunits, performance shares and other awards. The RSP permits only the grant of restricted stock or performance-basedrestricted stock. At December 31, 2005, the maximum number of shares availableunder the LTICP and RSP were 1,552,802 and 74,839, respectively.

All options granted have an exercise price equal to themarket price of IDACORP's stock on the date of grant.  In accordance with APB 25, no compensationcosts have been recognized for the option awards.

IDACORP's stock option transactions are summarized asfollows:

 

 

**2005**

**2004**

**2003**

 

 

** **

**Weighted**

** **

**Weighted**

** **

**Weighted**

 

 

**Number**

**average**

**Number**

**average**

**Number**

**average**

 

 

**of**

**exercise**

**of**

**exercise**

**of**

**exercise**

 

 

**shares**

**price**

**shares**

**price**

**shares**

**price**

Outstanding, beginning of year

1,254,550 

$

32.55

1,145,400 

$

32.69

846,000 

$

38.50

 

Granted

208,314 

 

29.53

187,850 

 

31.06

429,000 

 

23.01

 

Exercised

(16,400)

 

22.92

(7,400)

 

22.92

- 

 

-

 

Forfeited

(24,550)

 

31.53

(71,300)

 

31.81

(129,600)

 

38.57

Outstanding, end of year

1,421,914 

$

32.24

1,254,550 

$

32.55

1,145,400 

$

32.69

 

 

 

 

 

 

 

 

 

 

 

Exercisable

698,920 

$

34.80

472,600 

$

35.57

266,000 

$

37.91

 

 

 

 

 

 

 

 

 

 

 

 

IDACORP stock option transactions for shares granted toIPC employees are summarized as follows (these amounts are included in thetable above):

 

 

**2005**

**2004**

**2003**

 

 

** **

**Weighted**

** **

**Weighted**

** **

**Weighted**

 

 

**Number**

**average**

**Number**

**average**

**Number**

**average**

 

 

**of**

**exercise**

**of**

**exercise**

**of**

**exercise**

 

 

**shares**

**price**

**shares**

**price**

**shares**

**price**

Outstanding, beginning of year

952,600 

$

32.38

886,800 

$

32.48

591,000 

$

38.33

 

Granted

157,837 

 

29.75

110,500 

 

31.21

343,000 

 

22.95

 

Exercised

- 

 

-

(4,200)

 

22.92

- 

 

-

 

Forfeited

(16,300)

 

30.27

(40,500)

 

32.27

(47,200)

 

36.42

Outstanding, end of year

1,094,137 

$

32.03

952,600 

$

32.38

886,800 

$

32.48

 

 

 

 

 

 

 

 

 

 

 

Exercisable

559,140 

$

34.41

373,600 

$

35.42

211,000 

$

37.83

 

 

 

 

 

 

 

 

 

 

 

 

The following table summarizes information about stockoptions outstanding at December 31, 2005:

 

 

**Outstanding**

** **

** **

** **

**Exercisable**

 

 

** **

** **

** **

**Weighted**

** **

** **

** **

 

 

** **

**Weighted**

** **

**average**

** **

** **

**Weighted**

 

 

**Number**

**average**

** **

**remaining**

** **

**Number**

**average**

 

 

**of**

**exercise**

** **

**contractual**

** **

**of**

**exercise**

**Exercise Price Ranges**

**shares**

**price**

** **

**life**

** **

**shares**

**price**

$22.92 - $31.21

746,514

$

26.65

 

7.93 years

 

172,320

$

24.60

$35.81 - $40.31

675,400

 

38.41

 

5.37 years

 

526,600

 

38.13

**IPC Employees**

 

 

 

 

 

 

 

 

 

$22.92 - $31.21

575,537

$

26.27

 

7.87 years

 

147,340

$

24.09

$35.81 - $40.31

518,600

$

38.43

 

5.28 years

 

411,800

$

38.10

 

 

 

 

 

 

 

 

 

 

 

The fair value of each option granted was estimated atthe date of grant using a binomial option-pricing model with the followingassumptions:

** **

** **

**2005**

**2004**

**2003**

Dividend yield

 

4.07%

3.87%

8.09%

Expected stock price volatility

 

23%

29%

28%

Risk-free interest rate

 

4.22%

3.96%

3.94%

Expected option lives

 

7 years

7 years

7 years

Weighted average fair value of options granted

 

$5.86

$7.84

$3.90

 

 

 

 

 

 

Restricted stock grants have vesting periods up to fouryears.  Performance share grants have athree-year vesting period with the final award amount dependent on theattainment of cumulative EPS performance goals.

Restricted stock and performance share awards arecompensatory awards and IDACORP and IPC accrue compensation expense, which ischarged to operations, based upon the market value of the granted shares.  For 2005, 2004 and 2003, total compensationaccrued under the plans was less than $1 million annually.

IDACORP's restricted stock and performance share activityis summarized as follows:

**IDACORP**

**2005**

** **

**2004**

** **

**2003**

Shares outstanding - beginning of year

144,722 

 

94,363 

 

87,669 

Shares granted

96,708 

 

83,366 

 

52,517 

Shares forfeited

(26,328)

 

(30,931)

 

(6,679)

Shares issued

(251)

 

(2,076)

 

(39,144)

Shares outstanding - end of year

214,851 

 

144,722 

 

94,363 

Weighted average fair value of current year stock  grants on grant date

$

29.71 

 

$

31.16 

 

$

23.01 

 

 

 

 

 

 

 

 

 

 

IDACORP restricted stock and performance shares grantedto IPC employees are summarized as follows: (These amounts are included in the table above.)

**IPC**

**2005**

** **

**2004**

** **

**2003**

Shares outstanding - beginning of year

121,420 

 

80,454 

 

77,192 

Shares granted

87,620 

 

67,056 

 

41,945 

Shares forfeited

(25,220)

 

(24,014)

 

(1,889)

Shares issued

(251)

 

(2,076)

 

(36,794)

Shares outstanding - end of year

183,569 

 

121,420 

 

80,454 

Weighted average fair value of current year stock  grants on grant date

$

29.75 

 

$

31.15 

 

$

22.95 

 

 

 

 

 

 

 

 

 

 

**10.  BENEFITPLANS:**

**Pension Plans**IPC has a noncontributory defined benefit pension plan covering most employees.  The benefits under the plan are based onyears of service and the employee's final average earnings.  IPC's policy is to fund, with an independentcorporate trustee, at least the minimum required under the Employee RetirementIncome Security Act of 1974 (ERISA) but not more than the maximum amountdeductible for income tax purposes.  IPCwas not required to contribute to the plan in 2005, 2004 or 2003, and does notexpect to make a contribution in 2006. The market-related value of assets for the plan is equal to marketvalue.

In addition, IPC has a nonqualified, deferredcompensation plan for certain senior management employees and directors.  This plan was financed by purchasing lifeinsurance policies and investments in marketable securities, all of which areheld by a trustee.  The cash value of thepolicies and investments exceed the projected benefit obligation of the planbut do not qualify as plan assets in the actuarial computation of the fundedstatus.

IPC uses a December 31 measurement date for itsplans.

The following table summarizes the changes inbenefit obligations and plan assets of these plans:

** **

**Pension Plan**

**Deferred Compensation Plan**

** **

**2005**

** **

**2004**

**2005**

** **

**2004**

 

**(thousands of dollars)**

**Change  in benefit obligation:**

 

 

 

 

 

 

 

 

 

 

 

Benefit obligation at January 1

$

374,333 

 

$

339,121 

$

38,645 

 

$

38,870 

 

Service cost

 

13,129 

 

 

11,809 

 

1,170 

 

 

1,358 

 

Interest cost

 

21,126 

 

 

20,437 

 

2,151 

 

 

2,312 

 

Actuarial loss (gain)

 

11,399 

 

 

16,626 

 

2,799 

 

 

(1,225)

 

Benefits paid

 

(13,938)

 

 

(13,660)

 

(2,312)

 

 

(2,670)

 

Plan amendments

 

- 

 

 

- 

 

270 

 

 

- 

 

Benefit obligation at December 31

 

406,049 

 

 

374,333 

 

42,723 

 

 

38,645 

**Change  in plan assets:**

 

 

 

 

 

 

 

 

 

 

 

Fair value at January 1

 

356,217 

 

 

335,229 

 

- 

 

 

- 

 

Actual return on plan assets

 

25,774 

 

 

34,648 

 

- 

 

 

- 

 

Employer contributions

 

- 

 

 

- 

 

- 

 

 

- 

 

Benefit payments

 

(13,938)

 

 

(13,660)

 

- 

 

 

- 

 

Fair value at December 31

 

368,053 

 

 

356,217 

 

- 

 

 

- 

 

 

 

 

 

 

 

 

 

 

 

Funded status

 

(37,996)

 

 

(18,116)

 

(42,723)

 

 

(38,645)

Unrecognized actuarial loss 

 

43,806 

 

 

28,491 

 

13,553 

 

 

11,443 

Unrecognized prior service cost

 

5,118 

 

 

5,889 

 

1,414 

 

 

1,372 

Unrecognized net transition liability

 

- 

 

 

(126)

 

- 

 

 

310 

Net amount recognized

$

10,928 

 

$

16,138 

$

(27,756)

 

$

(25,520)

Amounts recognized in the statement of

 

 

 

 

 

 

 

 

 

 

 

financial position consist of:

 

 

 

 

 

 

 

 

 

 

Prepaid (accrued) pension cost

$

10,928 

 

$

16,138 

$

(39,268)

 

$

(36,110)

Intangible asset

 

- 

 

 

- 

 

1,414 

 

 

1,682 

Accumulated other comprehensive income

 

- 

 

 

- 

 

10,098 

 

 

8,908 

Net amount recognized

$

10,928 

 

$

16,138 

$

(27,756)

 

$

(25,520)

Accumulated benefit obligation

$

340,007 

 

$

316,498 

$

39,268 

 

$

36,110 

 

 

 

 

 

 

 

 

 

 

 

 

The following table shows the components of netperiodic benefit cost for these plans:

** **

**Pension Plan**

**Deferred Compensation Plan**

** **

**2005**

**2004**

**2003**

**2005**

**2004**

**2003**

 

**(thousands of dollars)**

 

 

 

 

 

 

 

 

 

 

 

 

 

Service cost

$

13,129 

$

11,809 

$

10,173 

$

1,170 

$

1,358 

$

1,212 

Interest cost

 

21,126 

 

20,437 

 

19,463 

 

2,151 

 

2,312 

 

2,414 

Expected return on assets

 

(29,690)

 

(27,935)

 

(23,445)

 

- 

 

- 

 

- 

Recognized net actuarial loss

 

- 

 

- 

 

361 

 

689 

 

878 

 

744 

Amortization of prior service cost

 

771 

 

770 

 

729 

 

228 

 

(361)

 

(345)

Amortization of transition asset

** **

(126)

 

(263)

 

(263)

 

310 

 

613 

 

613 

Net periodic pension cost 

$

5,210 

$

4,818 

$

7,018 

$

4,548 

$

4,800 

$

4,638 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Changesin the Deferred Compensation Plan minimum liability decreased othercomprehensive income by $1 million in 2005, increased other comprehensiveincome by $1 million in 2004 and decreased other comprehensive income by $1million in 2003.

Thefollowing table summarizes the expected future benefit payments of these plans:

** **

** **

**2006**

** **

**2007**

** **

**2008**

** **

**2009**

** **

**2010**

** **

**2011-2015**

Pension  Plan

$

14,277

$

14,885

$

15,988

$

17,233

$

18,701

$

120,589

Deferred  Compensation Plan

$

2,165

$

2,233

$

2,629

$

2,911

$

3,092

$

16,653

 

 

 

 

 

 

 

 

 

 

 

 

 

 

**PlanAsset Allocations:** IPC's pension plan and postretirement benefitplan weighted average asset allocations at December 31, 2005 and 2004, by assetcategory are as follows:

 

 

**Pension**

**Postretirement**

 

 

**Plan**

**Benefits**

Asset  Category

 

**2005**

**2004**

**2005**

**2004**

Equity  securities

 

66%

69%

-%

-%

Debt  securities

 

21   

21   

-   

3   

Real  estate

 

10   

9   

-   

-   

Other (a)

 

3   

1   

100   

97   

 

Total

 

100%

100%

100%

100%

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

 

**PensionAsset Allocation Policy:** The target allocations for theportfolio 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

7%

Short-Term  Bonds

10%

Small-Cap  Value Stocks

7%

Core  Real Estate

9%

Cash  and Cash Equivalents

3%

Venture  Capital

1%

 

Assets are rebalanced as necessary to keep the portfolioclose to target allocations.

The plan's principal investment objective is to maximizetotal return (defined as the sum of realized interest and dividend income andrealized and unrealized gain or loss in market price) consistent with prudentparameters of risk and the liability profile of the portfolio.  Emphasis is placed on preservation and growthof capital along with adequacy of cash flow sufficient to fund current andfuture payments to pensioners.

Thereare three major goals in IPC's asset allocation process:

Determine if the investments have the potential to earn the rate ofreturn assumed in the actuarial liability calculations.

Match the cash flow needs of the plan.  IPC sets cash allocations sufficient to coverthe current year benefit payments and bond allocations sufficient to cover atleast five years of benefit payments. IPC then utilizes growth instruments (equities, real estate, venturecapital) to fund the longer-term liabilities of the plan.

Maintain a prudent risk profile consistent with ERISAfiduciary standards.

 

Allowable plan investments include stocks and stockfunds, investment-grade bonds and bond funds, core real estate funds, privateequity funds, and cash and cash equivalents. 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.  Uncovered options, short sales, marginpurchases, letter stock and commodities are prohibited.

Rate-of-return projections for plan assets arebased on historical risk/return relationships among asset classes.  The primary measure is the historical riskpremium each asset class has delivered versus the return on 10-year US TreasuryNotes.  This historical risk premium isthen added to the current yield on 10-year US Treasury Notes, and the resultprovides a reasonable prediction of future investment performance.  Additional analysis is performed to measurethe expected range of returns, as well as worst-case and best-casescenarios.  Based on the current lowinterest rate environment, current rate-of-return expectations are lower thanthe nominal returns generated over the past 20 years when interest rates weregenerally much higher.

IPC'sasset modeling process also utilizes historical market returns to measure theportfolio's exposure to a "worst-case" market scenario, to determinehow much performance could vary from the expected "average"performance over various time periods. This "worst-case" modeling, in addition to cash flow matchingand diversification by asset class and investment style, provides the basis formanaging the risk associated with investing portfolio assets.

**Postretirement Benefits**IPC maintains a defined benefit postretirement plan (consisting ofhealth care and death benefits) that covers all employees who were enrolled inthe active group plan at the time of retirement as well as their spouses andqualifying dependents.  Effective January1, 2003, IPC amended its postretirement benefit plan.  The amendment affects all employees whoretire after December 31, 2002, limiting their postretirement benefit to afixed amount.  This amendment will limitthe growth of IPC's future obligations under this plan.

The net periodic postretirement benefit cost was asfollows (in thousands of dollars):

 

**2005**

** **

**2004**

** **

**2003**

Service cost

$

1,392 

 

$

1,400 

 

$

1,207 

Interest cost

 

3,381 

 

 

3,974 

 

 

4,017 

Expected return on plan assets

 

(2,486)

 

 

(2,294)

 

 

(1,930)

Amortization of unrecognized transition obligation

 

2,040 

 

 

2,040 

 

 

2,040 

Amortization of prior service cost

 

(535)

 

 

(523)

 

 

(563)

Recognized actuarial loss

 

754 

 

 

1,489 

 

 

1,402 

Net periodic postretirement benefit cost

$

4,546 

 

$

6,086 

 

$

6,173 

 

 

 

 

 

 

 

 

 

 

 

The following table summarizes the changes inbenefit obligation and plan assets (in thousands of dollars):

 

**2005**

** **

**2004**

**Change  in accumulated benefit obligation:**

 

 

 

 

 

 

Benefit obligation at January 1

$

71,105 

 

$

67,090 

 

Service cost

 

1,392 

 

 

1,400 

 

Interest cost

 

3,381 

 

 

3,974 

 

Actuarial (gain) loss

 

(9,186)

 

 

2,201 

 

Benefits paid

 

(2,934)

 

 

(3,997)

 

Plan Amendments

 

(125)

 

 

437 

 

Benefit obligation at December 31

 

63,633 

 

 

71,105 

** **

 

 

 

 

 

**Change  in plan assets:**

 

 

 

 

 

 

Fair value of plan assets at January 1

 

29,723 

 

 

26,603 

 

Actual return on plan assets

 

1,127 

 

 

2,301 

 

Employer contributions

 

800 

 

 

4,577 

 

Benefits paid

 

(1,757)

 

 

(3,758)

 

Fair value of plan assets at December 31

 

29,893 

 

 

29,723 

 

 

 

 

 

 

Funded status

 

(33,740)

 

 

(41,382)

Unrecognized prior service cost

 

(3,677)

 

 

(4,087)

Unrecognized actuarial loss 

 

15,978 

 

 

24,559 

Unrecognized transition obligation

 

14,280 

 

 

16,320 

Accrued benefit obligations included with other  deferred credits

$

(7,159)

 

$

(4,590)

 

 

 

 

 

 

 

**Medicare Act: **The Medicare Prescription Drug, Improvement andModernization Act of 2003 (Medicare Act) was signed into law in December 2003and established a prescription drug benefit, as well as a federal subsidy tosponsors of retiree health care benefit plans that provide a prescription drugbenefit that is at least actuarially equivalent to Medicare's prescription drugcoverage.

The measures of accumulatedpostretirement benefit obligation at December 31, 2004 and net periodic benefitcost for the years ended December 31, 2004 and 2003, do not reflect any amountassociated with the subsidy, because IDACORP and IPC initially determined thatthe effect of the Medicare Act would not be material.  Regulations published on January 28, 2005provided more flexibility in determining actuarial equivalence to Medicare ofthe benefits provided by the plan than was initially estimated by IDACORP's andIPC's actuaries.  Based on these newregulations, the effect of the Medicare Act is a reduction for IDACORP and IPCof $6 million to the accumulated postretirement benefit obligation at December31, 2005 and $1 million to the 2005 periodic postretirement benefit cost.

The following table summarizesthe expected future benefit payments of the postretirement benefit plan andexpected Medicare Part D subsidy receipts (in thousand of dollars):

 

2006

 

2007

 

2008

 

2009

 

2010

 

2001-2015

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Expected  benefit payments*

$

4,000

 

$

4,200

 

$

4,300

 

$

4,400

 

$

4,600

 

$

25,100

 
Expected  Medicare Part D

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
 

subsidy  receipts

$

480

 

$

488

 

$

503

 

$

518

 

$

530

 

$

2,936

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

 

The assumed health care cost trend rate used tomeasure the expected cost of benefits covered by the plan was 6.75 percent in2005 and 2004.  A one-percentage pointchange in the assumed health care cost trend rate would have the following effect(in thousands of dollars):

 

**1-Percentage-Point**

 

**increase**

** **

**decrease**

 

 

 

 

 

 

Effect on total of cost components

$

242

 

$

(184)

Effect on accumulated postretirement benefit obligation

$

2,397

 

$

(1,900)

 

The following table sets forth the weighted-averageassumptions used at the end of each year to determine benefit obligations forall IPC-sponsored pension and postretirement benefits plans:

 

 

**Pension**

**Postretirement**

 

 

**Benefits**

**Benefits**

 

 

**2005**

**2004**

**2005**

**2004**

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   

 

The following table sets forth the weighted-averageassumptions used for the end of each year to determine net periodic benefitcost for all IPC-sponsored pension and postretirement benefit plans:

 

 

**Pension**

**Postretirement**

 

 

**Benefits**

**Benefits**

 

 

**2005**

**2004**

**2005**

**2004**

Discount  rate

 

5.75%

6.15%

5.75%

6.15%

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   

** **

**Employee Savings Plan**IPC has an Employee Savings Plan that complies with Section 401(k) ofthe Internal Revenue Code and covers substantially all employees.  IPC matches specified percentages of employeecontributions to the plan.  Matchingcontributions amounted to $4 million in 2005 and $3 million in both 2004 and2003.

**Postemployment Benefits**IPC provides certain benefits to former or inactive employees, theirbeneficiaries and covered dependents after employment but beforeretirement.  These benefits includesalary continuation, health care and life insurance for those employees foundto be disabled under IPC's disability plans and health care for survivingspouses and dependents.  IPC accrues aliability for such benefits.  Inaccordance with an IPUC order, the portion of the liability attributable toregulated activities in Idaho as of December 31, 1993, was deferred as aregulatory asset, and amortized over a ten-year period, which ended in January2005.

The following table summarizes postemploymentbenefit amounts included in IDACORP and IPC's consolidated balance sheets atDecember 31 (in thousands of dollars):

 

**2005**

**2004**

Included  with regulatory assets

$

-

$

31

Included  with other deferred credits

$

3,845

$

3,924

 

**11.  PROPERTY PLANT AND EQUIPMENT ANDJOINTLY-OWNED PROJECTS:**

The following table presents the major classifications ofIPC's utility plant in service, annual depreciation provisions as a percent ofaverage depreciable balance and accumulated provision for depreciation for theyears 2005 and 2004 (in thousands of dollars):

 
 

**2005**

** **

**2004**

 
 

**Balance**

** **

**Avg Rate**

** **

**Balance**

** **

**Avg Rate**

Production

$

1,563,008 

 

2.54%

 

$

1,482,517 

 

2.51%

Transmission

 

580,382 

 

2.19   

 

 

560,303 

 

2.18   

Distribution

 

1,046,880 

 

2.62   

 

 

992,248 

 

2.59   

General and Other

 

286,797 

 

8.94   

 

 

289,748 

 

10.02   

 

Total in service

 

3,477,067 

 

2.91%

 

 

3,324,816 

 

2.96%

Accumulated provision for depreciation

 

(1,364,640)

 

 

 

 

(1,316,125)

 

 

 

In service - net

$

2,112,427 

 

 

 

$

2,008,691 

 

 

 

 

 

 

 

 

 

 

 

 

 

IPC has interests in three jointly-owned generatingfacilities.  Under the joint operatingagreements, each participating utility is responsible for financing its shareof construction, operating and leasing costs. IPC's proportionate share of direct operation and maintenance expensesapplicable to the projects is included in the Consolidated Statements ofIncome.  These facilities, and the extentof IPC's participation, were as follows at December 31, 2005 (in thousands ofdollars):

** **

** **

** **

** **

**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

 

$

462,240

 

$

5,148

 

$

265,641

 

33

 

707

Boardman

 

Boardman, OR

 

 

69,385

 

 

454

 

 

46,160

 

10

 

59

Valmy Units 1 and 2

 

Winnemucca, NV

 

 

311,993

 

 

4,042

 

 

193,920

 

50

 

261

 

IPC's wholly-owned subsidiary, Idaho Energy ResourcesCo., is a joint venturer in Bridger Coal Company, which operates the minesupplying coal to the Jim Bridger generating plant.  Coal purchased by IPC from the joint ventureamounted to $43 million, $47 million and $44 million in 2005, 2004 and 2003,respectively.

IPC has contracts to purchase the energy from four PURPAQualified Facilities that are 50 percent owned by Ida-West.  Power purchased from these facilitiesamounted to $7 million annually in 2005, 2004 and 2003.  See Note 1 for a discussion of the propertyof IDACORP's consolidated VIEs.

**12.  SEGMENT INFORMATION:**

Information regarding segments is presented inaccordance with SFAS 131, "Disclosure about Segments of an Enterprise andRelated Information."  Based on thecriteria outlined in SFAS 131, IDACORP has identified four reportable segmentsin 2005: utility operations, IFS, ITI and IDACOMM.  The utility operations segment has two primarysources of revenue: the regulated operations of IPC and income from BridgerCoal Company, an unconsolidated joint venture also subject to regulation.  IPC's regulated operations include thegeneration, transmission, distribution, purchase and sale of electricity.  IFS represents that subsidiary's investmentsin affordable housing developments and historic preservation projects.  ITI is the parent company of IdaTech, adeveloper of fuel cell technology. IdaTech's research and development expenses were $9 million, $5 millionand $5 million in 2005, 2004 and 2003, respectively.  IDACOMM provides telecommunications andcommercial Internet services.

The following table summarizes the segmentinformation for IDACORP's utility operations, IFS, ITI, IDACOMM and the totalof all other segments, and reconciles this information to total enterpriseamounts.

** **

** **

** **

** **

** **

** **

** **

**Consolidated**

** **

**Utility**

**IFS**

**ITI**

**IDACOMM**

**Other**

**Elimination**

**Total**

** **

**(thousands of  dollars)**

**2005**

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues

$

837,683 

$

1,379 

$

4,309 

$

12,315 

$

3,802 

$

- 

$

859,488 

Operating income 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(loss)

 

151,654 

 

(513)

 

(14,819)

 

(12,085)

 

3,512 

 

- 

 

127,749 

Other income 

 

4,623 

 

368 

 

- 

 

- 

 

786 

 

(318)

 

5,459 

Interest income

 

3,193 

 

797 

 

468 

 

133 

 

1,426 

 

(1,760)

 

4,257 

Equity method income 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(loss)

 

10,369 

 

(12,851)

 

- 

 

- 

 

1,769 

 

- 

 

(713)

Interest expense and 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

preferred dividends

 

54,075 

 

3,691 

 

24 

 

419 

 

4,040 

 

(2,078)

 

60,171 

Income (loss) before 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

income taxes

 

115,764 

 

(15,890)

 

(14,375)

 

(12,371)

 

3,453 

 

- 

 

76,581 

Income tax expense 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(benefit)

 

43,925 

 

(26,801)

 

(5,308)

 

617 

 

487 

 

- 

 

12,920 

Earnings (loss)

 

71,839 

 

10,911 

 

(9,067)

 

(12,988)

 

2,966 

 

- 

 

63,661 

Total assets

 

3,074,691 

 

139,306 

 

12,968 

 

24,525 

 

184,038 

 

(71,402)

 

3,364,126 

Expenditures for long-

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

lived assets

 

186,079 

 

4,998 

 

510 

 

6,732 

 

- 

 

- 

 

198,319 

**2004**

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues

$

822,937 

$

1,392 

$

7,036 

$

9,599 

$

3,527 

$

- 

$

844,491 

Operating income 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(loss)

 

109,038 

 

(544)

 

(9,789)

 

(3,194)

 

(2,260)

 

- 

 

93,251 

Other income 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(expense)

 

4,516 

 

4,857 

 

(23)

 

49 

 

4,298 

 

(69)

 

13,628 

Interest income

 

2,413 

 

655 

 

163 

 

193 

 

894 

 

(895)

 

3,423 

Equity method income 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(loss)

 

12,313 

 

(12,502)

 

- 

 

- 

 

1,239 

 

- 

 

1,050 

Interest expense and 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

preferred dividends

 

56,167 

 

4,719 

 

- 

 

16 

 

3,201 

 

(964)

 

63,139 

Income (loss) before 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

income taxes

 

72,113 

 

(12,253)

 

(9,649)

 

(2,968)

 

970 

 

- 

 

48,213 

Income tax expense 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(benefit)

 

6,328 

 

(25,566)

 

(3,841)

 

(978)

 

(713)

 

- 

 

(24,770)

Earnings (loss)

 

65,785 

 

13,313 

 

(5,808)

 

(1,990)

 

1,683 

 

- 

 

72,983 

Total assets

 

2,969,212 

 

145,279 

 

23,155 

 

31,893 

 

156,072 

 

(91,439)

 

3,234,172 

Expenditures for long-

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

lived assets

 

190,379 

 

7,670 

 

482 

 

8,886 

 

101 

 

- 

 

207,518 

**2003**

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues

$

782,720 

$

- 

$

9,278 

$

9,826 

$

21,178 

$

- 

$

823,002 

Operating income 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(loss)

 

121,694 

 

(796)

 

(1,552)

 

(4,363)

 

(30,921)

 

- 

 

84,062 

Other income 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(expense)

 

105 

 

71 

 

- 

 

451 

 

(959)

 

(221)

 

(553)

Interest income

 

3,237 

 

460 

 

82 

 

232 

 

3,802 

 

(3,338)

 

4,475 

Equity method income 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(loss)

 

11,336 

 

(10,461)

 

- 

 

- 

 

1,532 

 

- 

 

2,407 

Interest expense and 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

preferred dividends

 

59,483 

 

5,821 

 

448 

 

6 

 

2,733 

 

(3,559)

 

64,932 

Income (loss) before 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

income taxes

 

76,889 

 

(16,547)

 

(1,918)

 

(3,686)

 

(29,279)

 

- 

 

25,459 

Income tax expense 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(benefit)

 

21,728 

 

(26,951)

 

(558)

 

(1,892)

 

(13,446)

 

- 

 

(21,119)

Earnings (loss)

 

55,161 

 

10,404 

 

(1,360)

 

(1,794)

 

(15,833)

 

- 

 

46,578 

Total assets

 

2,820,711 

 

141,286 

 

16,466 

 

31,728 

 

165,537 

 

(69,620)

 

3,106,108 

Expenditures for long-

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

lived assets

 

148,494 

 

3 

 

234 

 

1,154 

 

5 

 

- 

 

149,890 

** **

 

 

 

 

 

 

 

 

 

 

 

 

 

 

** **

**13. REGULATORY MATTERS:**

**IdahoGeneral Rate Case**IPC filed ageneral rate case in October 2005, requesting the IPUC to approve an annualincrease to its Idaho retail base rates of $44 million or 7.8 percent.  Base rates primarily reflect IPC's cost ofproviding electrical service to its customers, including equipment, vehiclesand infrastructure.

OnFebruary 27, 2006, IPC, the IPUC staff and representatives of customer groupsfiled a proposed stipulation with the IPUC that, if approved, would settle thiscase.  The stipulation calls for an $18.1million increase, or 3.2 percent in IPC's annual electric rates.  If approved by the IPUC, the changes in ratesare expected to become effective on June 1, 2006.

The ratecase filing was made with six months of actual operating expenses and sixmonths of projected expenses.  The agreedto increase in rates was lower than the requested amount primarily due to threefactors:  (1) 2005 actual numbers weresignificantly less than those forecasted; (2) the overall rate of return agreed to was 8.1 percent compared to the8.42 percent IPC requested (no specific return on equity was determined); and(3) net power supply costs were kept at levels currently existing inrates.  As a result of the settlement,IPC's overall rate of return will increase from the 7.85 percent currentlyauthorized.

**OregonRate Case**On September 21,2004, IPC filed an application with the Oregon Public Utility Commission (OPUC)to increase general rates an average of 17.5 percent or approximately $4.4million annually.

The OPUCissued its order on July 29, 2005 authorizing an increase of $0.6 million inannual revenues, an average of 2.37 percent. The significant decrease from IPC's requested amount was primarilyrelated to differences in net power supply costs, which reduced IPC's initialrate request of $4.4 million by $2.4 million.

OnSeptember 26, 2005, IPC filed a complaint with the Circuit Court of MarionCounty, Oregon asking the court to reverse the portion of the OPUC's generalrate case order related to the determination of net power supply costs.

**Deferred Power Supply Costs******IPC's deferrednet power supply costs consisted of the following at December 31 (in thousandsof dollars):

** **

**2005**

** **

**2004**

Idaho PCA current year:

 

 

 

 

 

 

Deferral for the 2005-2006 rate year

$

-

 

$

22,778

 

Deferral for the 2006-2007 rate year

 

3,684

 

 

-

Irrigation Lost Revenues

 

-

 

 

13,290

Idaho PCA true-up awaiting recovery:

 

 

 

 

 

 

Authorized May 2004

 

-

 

 

11,415

 

Authorized May 2005*

 

28,567

 

 

-

Oregon deferral:

 

 

 

 

 

 

2001 costs

 

8,411

 

 

12,047

 

2005 costs

 

2,880

 

 

-

 

Total deferral

$

43,542

 

$

59,530

 

 

 

 

 

 

*$28 million will be recovered with interest during the  2006-2007 PCA rate year.

 

**Idaho:**IPC has a PCA mechanism that provides for annualadjustments to the rates charged to its Idaho retail customers.  These adjustments are based on forecasts ofnet power supply costs, which are fuel and purchased power less off-systemsales, and the true-up of the prior year's forecast.  During the year, 90 percent of the differencebetween the actual and forecasted costs is deferred with interest.  The ending balance of this deferral, calledthe true-up for the current year's portion and the true-up of the true-up forthe prior years' unrecovered portions, is then included in the calculation ofthe next year's PCA.

On April 15, 2005, IPC filed the 2005-2006 PCA with theIPUC with a proposed effective date of June 1, 2005.  The application proposed to hold the PCAcomponent of customers' rates at the existing level, which is currentlyrecovering $71 million above base rates. By IPUC order, the 2005 - 2006 PCA includes $12 million in lost revenuesand $2 million in related interest resulting from IPC's Irrigation LoadReduction Program that was in place in 2001. IPC proposed to defer recovery of approximately $28 million of powersupply costs, or 4.75 percent, for one year to help mitigate the impacts of theincreases for the Bennett Mountain Power Plant and the rate case tax settlementadjustments, since all three were proposed to be effective June 1, 2005.  The $28 million will be recovered during the2006-2007 PCA rate year, and IPC will earn a two percent carrying charge onthis balance.  The IPUC accepted thecompany's PCA proposal.

On April15, 2004, IPC filed its 2004-2005 PCA with the IPUC requesting recovery of $71million above base rates and a proposed effective date of June 1, 2004.  On May 25, 2004, the IPUC issued Order No.29506 approving IPC's filing.

On May15, 2003, the IPUC issued Order No. 29243 approving IPC's 2003-2004 PCA filing,with a small adjustment to the original filing. As approved, IPC's rates were adjusted to collect $81 million above 1993base rates.

On April15, 2002, the IPUC issued Order No. 28992 disallowing recovery of $12 millionof lost revenues resulting from the Irrigation Load Reduction Program that wasin place in 2001.  IPC believed that thisIPUC order was inconsistent with Order No. 28699, dated May 25, 2001, thatallowed recovery of such costs, and IPC filed a Petition for Reconsideration onMay 2, 2002.  On August 29, 2002, theIPUC issued Order No. 29103 denying the Petition for Reconsideration.  As a result of this order, approximately $12million was expensed in September 2002. IPC believed it was entitled to recover this amount and argued itsposition before the Idaho Supreme Court on December 5, 2003.  On March 30, 2004, the Idaho Supreme Courtset aside the IPUC denial of the recovery of lost revenues and remanded thematter to the IPUC to determine the amount of lost revenues to be recovered.  On December 29, 2004, the IPUC issued OrderNo. 29669 allowing IPC to recover $12 million in lost revenues and $2 millionin interest.  The recovery was includedas part of IPC's annual PCA beginning June 1, 2005.

**Oregon:**** **On March 2, 2005 IPC filed for anaccounting order to defer net power supply costs for the period of March 1,2005 through February 28, 2006 in anticipation of continued low waterconditions.  The forecasted net systempower supply costs included in this filing was $169 million, of which $3million related to the Oregon jurisdiction. IPC is proposing to use the same methodology for this deferral filingthat was accepted in 2002 for Oregon's share of IPC's 2001 net power supplyexpenses.  On July 1, 2005, IPC, the OPUCstaff and the Citizen's Utility Board entered into a stipulation requestingthat the OPUC accept IPC's proposed methodology.  Under this methodology, IPC will earn itsOregon authorized rate of return on the deferred balance and will recover theamount through rates in future years, as approved by the OPUC.

IPC is also recovering calendaryear 2001 excess power supply costs applicable to the Oregon jurisdiction.  In two separate 2001 orders, the OPUCapproved rate increases totaling six percent, which was the maximum annual rateof recovery allowed under Oregon state law at that time.  These increases were recovering approximately$2 million annually.  During the 2003Oregon legislative session, the maximum annual rate of recovery was raised toten percent under certain circumstances. IPC requested and received authority to increase the surcharge to tenpercent.  As a result of the increasedrecovery rate, which became effective on April 9, 2004, IPC is recoveringapproximately $3 million annually.

**Fixed-CostAdjustment Mechanism:**On January 27, 2006, IPC filed with the IPUC for authority to implement a rateadjustment mechanism which would adjust IPC's rates upward or downward torecover IPC's fixed costs independent from the volume of IPC's energy sales.  The filing is a continuation of an Idaho caseopened in 2004 to investigate the financial disincentives to investment inenergy efficiency by IPC.  The true-upmechanism, entitled "fixed-cost adjustment" (FCA) would be applicableonly to residential service and small general service customers.

The fixed-cost recovery portion of IPC's revenuerequirement allowed for recovery in rates would be established for these twocustomer classes at the time of a general rate case.  Thereafter, the FCA would provide a mechanismto true-up the collection of fixed costs to recover the difference between thefixed costs actually recovered through rates and the fixed costs that wereallowed to be recovered.  Accounting forthe FCA would be effective as of January 1, 2006, and the first FCA rate changewould occur on June 1, 2007.

The FCA is proposed to change rates coincidentally withIPC's Power Cost Adjustment (PCA) and IPC's seasonal rates.  Although the FCA would be timed to adjust onthe same schedule as the PCA, the accounting for the FCA would be separate fromthe PCA.  Additionally, IPC proposes toinclude a three percent cap on any FCA filing, to be applied at the discretionof the IPUC.

**Regulatory Assets andLiabilities**The following isa breakdown of IPC's regulatory assets and liabilities (in thousands ofdollars):

** **

**As of December 31, 2005**

** **

** **

** **

** **

** **

** **

** **

** **

** **

** **

** **

**As of**

** **

**Remaining**

** **

** **

**Not**

** **

**Pending**

** **

** **

** **

**December**

** **

**Amortization**

**Earning**

** **

**Earning**

** **

**Regulatory**

** **

**2005**

** **

**31, 2004**

**Description**

**Period**

**a Return**

** **

**a Return**

** **

**Treatment**

** **

**Total**

** **

**Total**

**Regulatory  Assets:**

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Income Taxes

 

$

-

 

$

346,117

 

$

-

 

$

346,117

 

$

344,220

 

Conservation

2010

 

14,592

 

 

-

 

 

-

 

 

14,592

 

 

17,836

 

PCA Deferral

2007

 

32,251

 

 

-

 

 

-

 

 

32,251

 

 

34,193

 

Oregon Deferral(1)

 

 

11,291

 

 

-

 

 

-

 

 

11,291

 

 

12,047

 

Asset Retirement

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Obligations

 

 

-

 

 

8,363

 

 

-

 

 

8,363

 

 

8,372

 

Tax Settlement

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Order

2006

 

4,994

 

 

-

 

 

-

 

 

4,994

 

 

7,119

 

Irrigation Lost

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues (2)

2007

 

-

 

 

-

 

 

-

 

 

-

 

 

13,290

 

Incremental 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Security Costs

2008

 

575

 

 

-

 

 

-

 

 

575

 

 

813

 

Other

Various

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

thru 2007

 

41

 

 

17

 

 

-

 

 

58

 

 

891

 

 

Total

 

$

63,744

 

$

354,497

 

$

-

 

$

418,241

 

$

438,781

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

**Regulatory  Liabilities:**

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Income Taxes

 

$

-

 

$

41,627

 

$

-

 

$

41,627

 

$

40,447

 

Conservation

2007

 

6,535

 

 

-

 

 

-

 

 

6,535

 

 

5,205

 

Asset Retirement

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Obligations

 

 

-

 

 

152,683

 

 

-

 

 

152,683

 

 

147,700

 

Deferred ITC

 

 

-

 

 

68,786

 

 

-

 

 

68,786

 

 

66,836

 

IPUC Settlement

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Order

2006

 

4,021

 

 

-

 

 

-

 

 

4,021

 

 

13,671

 

BPA Settlement

2006

 

1,393

 

 

-

 

 

-

 

 

1,393

 

 

1,833

 

OPUC Settlement

 

 

-

 

 

-

 

 

-

 

 

-

 

 

100

 

Emission 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Allowance

 

 

-

 

 

-

 

 

70,034

 

 

70,034

 

 

-

 

Other

Various

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

thru 2007

 

30

 

 

-

 

 

-

 

 

30

 

 

62

 

 

Total

 

$

11,979

 

$

263,096

 

$

70,034

 

$

345,109

 

$

275,854

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(1)  Capped at 10 percent increase per year.

(2)  Included in PCA amortization balance.

 

 

For further information on the asset retirementobligations amounts, see Note 17.

In the event that recovery of costs through rates becomesunlikely or uncertain, SFAS 71 would no longer apply.  If IPC were to discontinue application ofSFAS 71 for some or all of its operations, then these items may representstranded investments.  If IPC is notallowed recovery of these investments, it would be required to write off theapplicable portion of regulatory assets and the financial effects could besignificant.

**14. DERIVATIVE FINANCIALINSTRUMENTS:**

**Energy Trading Contracts**The commodity transactions entered into by IE were classified as energytrading contracts or derivatives in accordance with SFAS 133, "Accountingfor Derivative Instruments and Hedging Activities" and Emerging IssuesTask Force Issue 02-3, "Issues Involved in Accounting for Derivative ContractsHeld for Trading Purposes and Contracts Involved in Energy Trading and RiskManagement Activities."  Under SFAS133 as amended, these contracts are recorded on the balance sheet at fairmarket value.  This accounting treatmentis also referred to as mark-to-market accounting.  Mark-to-market accounting treatment cancreate a disconnect between recorded earnings and realized cash flow.  Marking a contract to market consists ofreevaluating the market value of the entire term of the contract at eachreporting period and reflecting the resulting gain or loss in earnings for theperiod.  This change in value representsthe difference between the contract price and the current market value of thecontract.  The change in market value ofthe contract could result in large gains or losses recorded in earnings at eachsubsequent reporting period unless there are offsetting changes in value ofoffsetting contracts.  The gain or lossgenerated from the change in market value of the energy trading contracts is anon-cash event.  If these contracts areheld-to-maturity, the cash flow from the contracts, and their offsettingcontracts, are realized over the life of the contract.

When determining the fair value of marketing andtrading contracts, IE used actively quoted prices for contracts with similarterms as the quoted price, including specific delivery points andmaturities.  To determine fair value ofcontracts with terms that were not consistent with actively quoted prices IEused, when available, prices provided by other external sources.  When prices from external sources were notavailable, IE determined prices by using internal pricing models thatincorporated available current and historical pricing information.  Finally, the fair market value of contractswas adjusted for the impact of market depth and liquidity, potential modelerror and expected credit losses at the counterparty level.

The following table details the gross margin forthe energy marketing operations (in thousands of dollars):

 

 

**2005**

** **

**2004**

** **

**2003**

Gross  Margin:

 

 

 

 

 

 

 

 

 

 

Realized  or otherwise settled

 

$

12 

 

$

82 

 

$

61,183 

 

Unrealized

 

 

(17)

 

 

(131)

 

 

(42,517)

 

 

Total

 

$

(5)

 

$

(49)

 

$

18,666 

 

 

 

 

 

 

 

 

 

 

 

 

**15.  RESTRUCTURING COSTS:**

IDACORP announced on June 21, 2002 that IE would winddown its power marketing operations due to changing liquidity requirementsbrought on by rating agencies, continued uncertainty in the regulatory andpolitical environment and the reduction of creditworthy counterparties.  On November 5, 2002, IDACORP announced thatit was terminating further evaluation of growth opportunities in the mid-streamnatural gas markets, and stated that IE would close its Denver office byyear-end 2002, would shut down its natural gas trading operation in Houston byMarch 2003 and would further reduce its workforce in its Boise operationsthrough mid-2003.  IE completed the majormilestones of winding down the business, including the sale of IE's forwardbook of electricity trading contracts to Sempra Energy Trading in August 2003,closing of the Denver, Houston and Boise offices and the final workforceterminations in November 2003.

IE incurred involuntary termination benefit expenses,lease termination costs and other exit-related costs in connection with thewind down.  Termination benefit expensesrelate to the termination of 98 employees (primarily energy traders andadministrative support positions).  Ofthe 98 employees laid off, 19 were hired by other IDACORP subsidiaries, andthus received no severance benefits. Restructuring expenses are presented as other operating expenses on theConsolidated Statements of Income and restructuring accruals are presented asother liabilities on the Consolidated Balance Sheets.

The following table summarizes restructuring costs duringthe periods (in thousands of dollars):

 

**Severance**

** **

**Lease**

** **

** **

** **

** **

 

**and Other**

** **

**Termination**

** **

** **

** **

** **

 

**Benefits**

** **

**Costs**

** **

**Other**

** **

**Total**

Balance at December 31, 2002

$

4,171 

 

$

2,485 

 

$

195 

 

$

6,851 

 

Amounts accrued

 

4,379 

 

 

182 

 

 

- 

 

 

4,561 

 

Amounts paid

 

(6,594)

 

 

(645)

 

 

(162)

 

 

(7,401)

 

Amounts reversed

 

(149)

 

 

- 

 

 

- 

 

 

(149)

Balance at December 31, 2003

 

1,807 

 

 

2,022 

 

 

33 

 

 

3,862 

 

Amounts accrued

 

- 

 

 

28 

 

 

- 

 

 

28 

 

Amounts paid

 

(1,807)

 

 

(657)

 

 

- 

 

 

(2,464)

 

Amounts reversed

 

- 

 

 

- 

 

 

(33)

 

 

(33)

Balance at December 31, 2004

 

- 

 

 

1,393 

 

 

- 

 

 

1,393 

 

Amounts accrued

 

- 

 

 

165 

 

 

- 

 

 

165 

 

Amounts paid

 

- 

 

 

(495)

 

 

- 

 

 

(495)

 

Amounts reversed

 

- 

 

 

- 

 

 

- 

 

 

- 

Balance at December 31, 2005

$

- 

 

$

1,063 

 

$

- 

 

$

1,063 

 

 

 

 

 

 

 

 

 

 

 

 

 

**16.  INVESTMENTS:**

Thefollowing table summarizes IDACORP's and IPC's investments as of December 31(in thousands of dollars):

 

**2005**

** **

**2004**

IPC Investments:

 

 

 

 

 

 

Auction rate securities  (available-for-sale)

$

-

 

$

31,650

 

Equity method investment 

 

38,764

 

 

25,028

 

Available-for-sale equity  securities 

 

21,137

 

 

21,505

 

Executive deferred  compensation

 

6,201

 

 

6,002

 

Other investments 

 

1,025

 

 

808

 

 

Total IPC investments 

 

67,127

 

 

84,993

Investments in affordable  housing 

 

99,972

 

 

108,974

Equity method investments 

 

8,764

 

 

8,670

Held-to-maturity debt  securities 

 

13,373

 

 

14,164

Executive deferred  compensation

 

5,313

 

 

5,928

Other investments

 

30

 

 

332

 

 

Total IDACORP investments 

$

194,579

 

$

223,061

 

 

 

 

 

 

 

**EquityMethod Investments**IPC, through itssubsidiary Idaho Energy Resources Co., is a 33 percent owner of Bridger CoalCompany, which supplies coal to the Jim Bridger generating plant owned in partby IPC.  Ida-West, through separatesubsidiaries, owns 50 percent of each of the following electric generationprojects: South Forks Joint Venture; Hazelton/Wilson Joint Venture and SnowMountain Hydro LLC.

IFSinvests in affordable housing developments that are accounted for in accordancewith APB 18, "The Equity Method of Accounting for Investments in CommonStock" and Emerging Issues Task Force Issue 94-1, "Accounting for TaxBenefits Resulting from Investments in Affordable Housing Projects," andare presented as Investments on the Consolidated Balance Sheets. All projectsare reviewed periodically for impairment.

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

 

**2005**

** **

**2004**

** **

**2003**

Bridger Coal Company (IPC)

$

10,369 

 

$

12,313 

 

$

11,336 

Ida-West projects

 

1,769 

 

 

1,239 

 

 

1,532 

IFS affordable housing projects

 

(12,851)

 

 

(12,502)

 

 

(10,461)

 

Total 

$

(713)

 

$

1,050 

 

$

2,407 

 

 

 

 

 

 

 

 

 

** **

**Investmentsin Debt and Equity Securities**Investments indebt and equity securities are accounted for in accordance with SFAS 115,"Accounting for Certain Investments in Debt and EquitySecurities."  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.  Anyunrealized gains or losses on available-for-sale securities are included inother comprehensive income.

IPC held$32 million of auction rate securities at December 31, 2004.  Auction rate securities are long-terminstruments whose interest rates or dividends are reset at specificfrequencies.  The typical reset periodsare either 28 or 35 days.  The rates ordividends are reset via a Dutch auction. The original maturities of these securities at the time of issuanceranged from 2007 to 2042.  IDACORP andIPC did not hold any auction rate securities at December 31, 2005.

Investmentsclassified as held-to-maturity securities are reported at amortized cost.  Held-to-maturity securities are investmentsin debt securities for which the company has the positive intent and ability tohold the securities until maturity. These debt securities have maturities ranging from 2006 through 2025

Thefollowing table summarizes investments in debt and equity securities (inthousands of dollars):

 

**2005**

**2004**

 

**Gross**

**Gross**

** **

**Gross**

**Gross**

** **

 

**Unrealized**

**Unrealized**

**Fair**

**Unrealized**

**Unrealized**

**Fair**

 

**Gain**

**Loss**

**Value**

**Gain**

**Loss**

**Value**

 

 

 

 

 

 

 

 

 

 

 

 

 

Available-for-sale  

 

 

 

 

 

 

 

 

 

 

 

 

 

securities  (IPC)

$

2,925

$

497

$

21,137

$

2,530

$

256

$

53,155

Held-to-maturity  debt 

 

 

 

 

 

 

 

 

 

 

 

 

 

securities  (IFS)

 

354

 

350

 

13,377

 

332

 

172

 

14,324

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Thefollowing table summarizes sales of available-for-sale securities (in thousandsof dollars):

** **

**2005**

** **

**2004**

** **

**2003**

 

 

 

 

 

 

 

 

 

Proceeds  from sales

$

120,026

 

$

266,331

 

$

14,040

Gross  realized gains from sales

 

2,850

 

 

2,044

 

 

1,046

Gross  realized losses from sales

 

643

 

 

634

 

 

1,169

 

 

 

 

 

 

 

 

 

 

Additionally,these investments are evaluated to determine whether they have experienced adecline in market value that is considered other-than-temporary.  IDACORP and IPC analyze securities in losspositions as of the end of each reporting period.  Any security with an unrealized loss of morethan 20 percent is evaluated for other-than-temporary impairment.  A security will generally be written down tomarket value if it has an unrealized loss of 20 percent or more for more thannine months.  If additional informationis available that indicates a security is other-than-temporarily impaired, itwill be written down prior to the nine-month time period.  In the alternative, if a security has beenimpaired for more than nine months but available information indicates that theimpairment is temporary, the security will not be written down.  IDACORP and IPC recognized an other-than-temporaryimpairment of $0.6 million in 2003.  Thisdecline is included in other income in the Consolidated Statements ofIncome.  In 2005 and 2004, there were noother-than-temporary declines in market value recorded.

Thefollowing table summarizes information regarding securities that were in anunrealized loss position at the end of each year, but for which noother-than-temporary impairment was recognized (in thousands of dollars).

** **

**Aggregate**

** **

**Aggregate**

**Aggregate**

** **

**Aggregate**

** **

**Unrealized**

** **

**Related  Fair**

**Unrealized**

** **

**Related  Fair**

** **

**Loss**

** **

**Value**

**Loss**

** **

**Value**

** **

**Less  than 12 months**

**12  months or longer**

**2005:**

 

 

 

 

 

 

 

 

 

 

Available for sale equity securities (IPC)

$

215

 

$

1,731

$

282

 

$

1,423

Held to maturity debt securities (IFS)

 

18

 

 

1,817

 

333

 

 

4,128

 

 

 

 

 

 

 

 

 

 

 

**2004:**

 

 

 

 

 

 

 

 

 

 

Available for sale equity securities (IPC)

$

181

 

$

2,934

$

75

 

$

362

Held to maturity debt securities (IFS)

 

97

 

 

4,071

 

75

 

 

1,794

 

 

 

 

 

 

 

 

 

 

 

 

Theavailable-for-sale equity securities in unrealized loss positions arediversified investments in common stock of various companies used to fund IPC'sSenior Management Security Plan.  Theheld-to-maturity debt securities in unrealized loss positions are bonds, whosemarket values fluctuate based on the interest rate environment.  At December 31, 2005, nine available-for-saleand 11 held-to-maturity securities were in an unrealized loss position.  At December 31, 2004, ten available-for-saleand 14 held-to-maturity securities were in an unrealized loss position.  At December 31, 2005 two available-for-sale securitieshad unrealized loss positions of greater than 20 percent.  Both securities exceeded 20 percent for fewerthan nine months.  IDACORP and IPC do notconsider these investments to be other-than-temporarily impaired at December 31,2005 or 2004.  Because IDACORP has theability and intent to hold the debt securities until maturity, it does notconsider them to be other-than-temporarily impaired at December 31, 2005 or 2004.

**17.ASSET RETIREMENT OBLIGATIONS:**

OnJanuary 1, 2003, IDACORP and IPC adopted SFAS 143, "Accounting for AssetRetirement Obligations."  Thisstatement addresses financial accounting and reporting for obligationsassociated with the retirement of tangible long-lived assets and the associatedasset retirement costs.  An obligationmay result from the acquisition, construction, development or the normaloperation of a long-lived asset.  SFAS143 requires an entity to record the fair value of a liability for an assetretirement obligation (ARO) in the period in which it is incurred.  When the liability is initially recorded, theentity increases the carrying amount of the related long-lived asset to reflectthe future retirement cost.  Over time,the liability is accreted to its present value and paid, and the capitalizedcost is depreciated over the useful life of the related asset.  If, at the end of the asset's life, therecorded liability differs from the actual obligations paid, a gain or losswould be recognized at that time.  As arate-regulated entity, IPC records regulatory assets and liabilities instead ofaccretion, depreciation and gains or losses. This treatment was approved by Order No. 29414 from the IPUC.  The regulatory assets recorded under thisorder do not earn a return on investment.

In 2005,IDACORP and IPC adopted FIN 47.  ThisInterpretation clarifies that the term "conditional asset retirementobligation," as used in FASB Statement No. 143, refers to a legalobligation to perform an asset retirement activity in which the timing and/ormethod of settlement are conditional on a future event that may or may not bewithin the control of the entity.  Theobligation to perform the asset retirement activity is unconditional eventhough uncertainty exists about the timing and/or method of settlement.  Thus, the timing and/or method of settlementmay be conditional on a future event. Accordingly, an entity is required to recognize a liability for the fairvalue of a conditional ARO if the fair value of the liability can be reasonablyestimated.  The fair value of a liabilityfor the conditional ARO should be recognized when incurred-generally uponacquisition, construction, or development and/or through the normal operationof the asset.  Uncertainty about thetiming and/or method of settlement of a conditional ARO should be factored intothe measurement of the liability when sufficient information exists.  FAS 143 acknowledges that, in some cases,sufficient information may not be available to reasonably estimate the fairvalue of an ARO.  The Interpretation alsoclarifies when an entity would have sufficient information to reasonablyestimate the fair value of an ARO.

 FIN 47 became effective December 31,2005.  After reviewing the provisions ofFIN 47, no significant additional AROs were identified at IPC.  One ARO was identified at IDACOMM.  Upon adoption, IDACOMM recorded an AROliability of $0.4 million and an ARO asset of $0.4 million.

Theregulated operations of IPC also collect removal costs in rates for certainassets that do not have associated AROs. The adoption of SFAS 143 required IPC to redesignate these removal costsas regulatory liabilities.  As ofDecember 31, 2005, IPC had $153 million of such costs recorded as regulatoryliabilities on its Consolidated Balance Sheet.

Thefollowing table presents the changes in the aggregate carrying amount of AROs(in thousands of dollars):

** **

**IDACORP**

**IPC**

** **

**2005**

** **

**2004**

**2005**

** **

**2004**

Balance  at beginning of year

$

9,288

 

$

7,140

$

9,288

 

$

7,140

Amount  recorded on adoption

 

440

 

 

-

 

 

 

 

-

Accretion  expense

 

531

 

 

421

 

531

 

 

421

Revisions  in estimated cash flows

 

260

 

 

1,727

 

260

 

 

1,727

Balance  at end of year

$

10,519

 

$

9,288

$

10,079

 

$

9,288

 

 

 

 

 

 

 

 

 

 

 

** **

**18. RELATED PARTY TRANSACTIONS (IPC):**

**IDACORP**In exchange forthe transfer of Energy Marketing to IE in June 2001, IPC received a partnershipinterest in IE, which was then transferred to IDACORP in exchange for notesreceivable from IDACORP totaling approximately $76 million.  The notes receivable were due over periods ofone to ten years, bore interest at IDACORP's overall variable short-termborrowing rate and were paid in full in 2003.

IPC performs corporate functions such as financial, legaland management services for IDACORP and its subsidiaries.  IPC charges IDACORP for the costs of these servicesbased on service agreements and other specifically identified costs.  IPC billed IDACORP $4 million, $4 million and$3 million in 2005, 2004 and 2003, respectively, for these services.

**IDACORP Energy**In 2003, IPC'ssales to IE totaled $2.2 million.  Therewere no purchases or sales between the entities in 2004 or 2005.

**IDACOMM**IPC provides project management and engineering services toIDACOMM.  IDACOMM also pays joint usefees to IPC.  Total fees charged to IDACOMMwere $0.3 million per year in 2005, 2004 and 2003.

**Ida-West**IPC purchases all of the power generated by four of Ida-West'shydroelectric projects.  IPC paid $7million per year in 2005, 2004 and 2003.

**REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTINGFIRM**

 

To the Board of Directors and Shareholders ofIDACORP, Inc.Boise, Idaho

We have audited the accompanying consolidatedbalance sheets of IDACORP, Inc. and subsidiaries (the "Company") asof December 31, 2005 and 2004, and the related consolidated statements ofincome, comprehensive income, shareholders' equity and cash flows for each ofthe three years in the period ended December 31, 2005.  Our audits also included the consolidatedfinancial statement schedules listed in the Index at Item 8.  These financial statements and financialstatement schedules are the responsibility of the Company's management.  Our responsibility is to express an opinionon the financial statements and financial statement schedules based on ouraudits.

We conducted our audits in accordance with thestandards of the Public Company Accounting Oversight Board (UnitedStates).  Those standards require that weplan and perform the audit to obtain reasonable assurance about whether thefinancial statements are free of material misstatement.  An audit includes examining, on a test basis,evidence supporting the amounts and disclosures in the financialstatements.  An audit also includesassessing the accounting principles used and significant estimates made bymanagement, as well as evaluating the overall financial statementpresentation.  We believe that our auditsprovide a reasonable basis for our opinion.

In our opinion, such consolidated financialstatements present fairly, in all material respects, the financial position ofIDACORP, Inc. and subsidiaries at December 31, 2005 and 2004, and the resultsof their operations and their cash flows for each of the three years in theperiod ended December 31, 2005, in conformity with accounting principlesgenerally accepted in the United States of America.  Also, in our opinion, such consolidatedfinancial statement schedules, when considered in relation to the basicconsolidated financial statements taken as a whole, present fairly, in allmaterial respects, the information set forth therein.

As described in Note 1 to the consolidatedfinancial statements, during 2004 the Company was required to consolidate twovariable interest entities related to the adoption of Financial AccountingStandards Board Interpretation No. 46(R).

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, 2005, based on thecriteria established in *Internal Control-Integrated Framework* issued bythe Committee of Sponsoring Organizations of the Treadway Commission and ourreport dated March 6, 2006 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.

DELOITTE & TOUCHE LLP

Boise, IdahoMarch 6, 2006

**REPORT OF INDEPENDENTREGISTERED PUBLIC ACCOUNTING FIRM**

To the Board of Directors and Shareholder of IdahoPower CompanyBoise, Idaho

We have audited the accompanying consolidatedbalance sheets and statements of capitalization of Idaho Power Company andsubsidiary (the "Company") as of December 31, 2005 and 2004, and therelated consolidated statements of income, comprehensive income, retainedearnings and cash flows for each of the three years in the period endedDecember 31, 2005.  Our audits alsoincluded the consolidated financial statement schedule listed in the Index atItem 8.  These financial statements andfinancial statement schedule are the responsibility of the Company'smanagement.  Our responsibility is toexpress an opinion on the financial statements and financial statement schedulebased on our audits.

We conducted our audits in accordance with thestandards of the Public Company Accounting Oversight Board (UnitedStates).  Those standards require that weplan and perform the audit to obtain reasonable assurance about whether thefinancial statements are free of material misstatement.  An audit includes examining, on a test basis,evidence supporting the amounts and disclosures in the financialstatements.  An audit also includesassessing the accounting principles used and significant estimates made bymanagement, as well as evaluating the overall financial statementpresentation.  We believe that our auditsprovide a reasonable basis for our opinion.

In our opinion, such consolidated financialstatements present fairly, in all material respects, the financial position ofIdaho Power Company and subsidiary at December 31, 2005 and 2004, and theresults of their operations and their cash flows for each of the three years inthe period ended December 31, 2005, in conformity with accounting principlesgenerally accepted in the United States of America.  Also, in our opinion, such consolidatedfinancial statement schedule, when considered in relation to the basicconsolidated financial statements taken as a whole, presents fairly, in allmaterial respects, the information set forth therein.

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, 2005, based on thecriteria established in *Internal Control-Integrated Framework* issued bythe Committee of Sponsoring Organizations of the Treadway Commission and ourreport dated March 6, 2006 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.

DELOITTE & TOUCHE LLP

Boise, IdahoMarch 6, 2006

**SUPPLEMENTAL FINANCIAL INFORMATION, UNAUDITED**

**QUARTERLY FINANCIAL DATA:**

The following unaudited information is presentedfor each quarter of 2005 and 2004 (in thousands of dollars except for per shareamounts).  In the opinion of eachcompany, all adjustments necessary for a fair statement of such amounts forsuch periods have been included.  Theresults of operations for the interim periods are not necessarily indicative ofthe results to be expected for the full year. 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 quarterlystatements and the sum of the quarters may not equal the annual amountreported.

**IDACORP, Inc.:**

** **
Quarter Ended
** **

**March 31**

**June 30**

**September 30**

**December 31**

 

 

 

 

 

 

 

 

 

2005

 

 

 

 

 

 

 

 

Revenues

$

195,774 

$

204,651 

$

248,414 

$

210,649 

Income from operations

 

34,926 

 

23,811 

 

43,117 

 

25,895 

Income tax expense

 

1,134 

 

498 

 

7,545 

 

3,744 

Net income

 

23,066 

 

9,451 

 

23,617 

 

7,527 

Earnings per share of common stock

 

0.55 

 

0.22 

 

0.56 

 

0.18 

 

 

 

 

 

 

 

 

 

2004

 

 

 

 

 

 

 

 

Revenues

$

188,189 

$

211,872 

$

246,677 

$

197,752 

Income from operations

 

36,194 

 

15,407 

 

18,933 

 

22,717 

Income tax expense (benefit)

 

4,685 

 

(3,379)

 

(20,886)

 

(5,191)

Net income

 

19,659 

 

12,992 

 

26,067 

 

14,266 

Earnings per share of common stock

 

0.51 

 

0.34 

 

0.68 

 

0.37 

 

 

 

 

 

 

 

 

 

 

**Idaho Power Company:**

** **

**Quarter Ended**

** **

**March 31**

**June 30**

**September 30**

**December 31**

 

 

 

 

 

 

 

 

 

2005

 

 

 

 

 

 

 

 

Revenues

$

190,460 

$

198,888 

$

243,503 

$

204,832 

Income from operations

 

40,897 

 

29,748 

 

49,259 

 

31,750 

Income tax expense

 

12,472 

 

6,362 

 

19,529 

 

5,562 

Net income

 

21,509 

 

12,876 

 

20,969 

 

16,485 

Dividends on preferred stock

 

- 

 

- 

 

- 

 

- 

Earnings on common stock

 

21,509 

 

12,876 

 

20,969 

 

16,485 

 

 

 

 

 

 

 

 

 

2004

 

 

 

 

 

 

 

 

Revenues

$

183,326 

$

205,693 

$

240,219 

$

190,271 

Income from operations

 

40,854 

 

18,411 

 

20,396 

 

29,338 

Income tax expense (benefit)

 

13,169 

 

273 

 

(13,981)

 

6,867 

Net income

 

20,263 

 

8,790 

 

26,995 

 

14,560 

Dividends on preferred stock

 

854 

 

853 

 

3,116 

 

- 

Earnings on common stock

 

19,409 

 

7,937 

 

23,879 

 

14,560 

 

 

 

 

 

 

 

 

 

 

**ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING ANDFINANCIAL DISCLOSURE**

None

**ITEM 9A.  CONTROLS AND PROCEDURES**

Disclosure controls and procedures:

**IDACORP:**

The Chief Executive Officer and Chief Financial Officerof IDACORP, based on their evaluation of IDACORP's disclosure controls andprocedures (as defined in Exchange Act Rule 13a-15(e)) as of December 31, 2005,have concluded that IDACORP's disclosure controls and procedures are effective.

**IPC:**

The Chief Executive Officer and Chief Financial Officerof IPC, based on their evaluation of IPC's disclosure controls and procedures (asdefined in Exchange Act Rule 13a-15(e)) as of December 31, 2005, have concludedthat IPC's disclosure controls and procedures are effective.

Internal control over financial reporting:

**IDACORP:**

**Management's Annual Report On Internal Control Over FinancialReporting**The managementof IDACORP is responsible for establishing and maintaining adequate internalcontrol over financial reporting for IDACORP. Internal control over financial reporting is defined in Rule 13a-15(f)promulgated under the Securities Exchange Act of 1934 as a process designed by,or under the supervision of, the company's principal executive and principalfinancial officers and effected by the company's board of directors, managementand other personnel, to provide reasonable assurance regarding the reliabilityof financial reporting and the preparation of financial statements for externalpurposes in accordance with accounting principles generally accepted in theUnited States of America and includes those policies and procedures that:

Pertain to the maintenance ofrecords that in reasonable detail accurately and fairly reflect thetransactions and dispositions of the assets of the company;

Provide reasonable assurance thattransactions are recorded as necessary to permit preparation of financialstatements in accordance with accounting principles generally accepted in theUnited States of America, and that receipts and expenditures of the company arebeing made only in accordance with the authorizations of management anddirectors of the company; and

Provide reasonable assuranceregarding prevention or timely detection of unauthorized acquisition, use ordisposition of the company's assets that could have a material effect on thefinancial statements.

 

Because of its inherent limitations, internal controlover financial reporting may not prevent or detect misstatements.  Projections of any evaluation ofeffectiveness to future periods are subject to the risk that controls maybecome inadequate because of changes in conditions, or that the degree ofcompliance with the policies or procedures may deteriorate.

IDACORP's management assessed the effectiveness of thecompany's internal control over financial reporting as of December 31,2005.  In making this assessment, thecompany's management used the criteria set forth by the Committee of SponsoringOrganizations of the Treadway Commission in *Internal Control-IntegratedFramework*.

Based on its assessment, management believes that, as ofDecember 31, 2005, IDACORP's internal control over financial reporting iseffective based on those criteria.

IDACORP's independent registered public accounting firmhas audited the financial statements included in this Annual Report on Form10-K for the year ended December 31, 2005 and issued a report, which appears onthe next page and expresses an unqualified opinion on management's assessmentand on the effectiveness of IDACORP's internal control over financial reportingas of December 31, 2005.

March 6, 2006

**REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM**

To the Board of Directors and Shareholders of IDACORP,Inc.Boise, Idaho

We have audited management's assessment, included in theaccompanying Management's Annual Report on Internal Control over FinancialReporting, that IDACORP, Inc. and subsidiaries (the "Company")maintained effective internal control over financial reporting as of December31, 2005, based on criteria established in *Internal Control-IntegratedFramework* issued by the Committee of Sponsoring Organizations of theTreadway Commission.  The Company'smanagement is responsible for maintaining effective internal control overfinancial reporting and for its assessment of the effectiveness of internalcontrol 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.

We conducted our audit in accordance with the standardsof the Public Company Accounting Oversight Board (United States).  Those standards require that we plan andperform the audit to obtain reasonable assurance about whether effectiveinternal control over financial reporting was maintained in all materialrespects.  Our audit included obtainingan understanding of internal control over financial reporting, evaluatingmanagement's assessment, testing and evaluating the design and operatingeffectiveness of internal control, and performing such other procedures as weconsidered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company's internal control over financial reporting isa process designed by, or under the supervision of, the company's principalexecutive and principal financial officers, or persons performing similarfunctions, and effected by the company's board of directors, management, andother personnel to provide reasonable assurance regarding the reliability offinancial reporting and the preparation of financial statements for externalpurposes in accordance with generally accepted accounting principles.  A company's internal control over financialreporting includes those policies and procedures that (1) pertain to themaintenance of records that, in reasonable detail, accurately and fairly reflectthe transactions and dispositions of the assets of the company; (2) providereasonable assurance that transactions are recorded as necessary to permitpreparation of financial statements in accordance with generally acceptedaccounting principles, and that receipts and expenditures of the company arebeing made only in accordance with authorizations of management and directorsof the company; and (3) provide reasonable assurance regarding prevention ortimely detection of unauthorized acquisition, use, or disposition of thecompany's assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal controlover financial reporting, including the possibility of collusion or impropermanagement override of controls, material misstatements due to error or fraudmay not be prevented or detected on a timely basis.  Also, projections of any evaluation of theeffectiveness of the internal control over financial reporting to futureperiods are subject to the risk that the controls may become inadequate becauseof changes in conditions, or that the degree of compliance with the policies orprocedures may deteriorate.

In our opinion, management's assessment that the Companymaintained effective internal control over financial reporting as of December31, 2005, is fairly stated, in all material respects, based on the criteriaestablished in *Internal Control-Integrated Framework* issued by theCommittee of Sponsoring Organizations of the Treadway Commission.  Also in our opinion, the Company maintained,in all material respects, effective internal control over financial reportingas of December 31, 2005, based on the criteria established in *InternalControl-Integrated Framework* issued by the Committee of Sponsoring Organizationsof the Treadway Commission.

We have also audited, in accordance with the standards ofthe Public Company Accounting Oversight Board (United States), the consolidatedfinancial statements and financial statement schedules as of and for the yearended December 31, 2005 of the Company and our report dated March 6, 2006expressed an unqualified opinion on those financial statements and financialstatement schedules and included an explanatory paragraph regarding theCompany's adoption of Financial Accounting Standards Board Interpretation No.46(R).

DELOITTE & TOUCHE LLP

Boise, IdahoMarch 6, 2006

**Idaho Power Company:**

**Management's Annual Report on Internal Control OverFinancial Reporting**The managementof Idaho Power Company (IPC) is responsible for establishing and maintainingadequate internal control over 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 ofrecords that in reasonable detail accurately and fairly reflect thetransactions and dispositions of the assets of the company;

Provide reasonable assurance thattransactions are recorded as necessary to permit preparation of financialstatements in accordance with accounting principles generally accepted in theUnited States of America, and that receipts and expenditures of the company arebeing made only in accordance with the authorizations of management anddirectors of the company; and

Provide reasonable assuranceregarding prevention or timely detection of unauthorized acquisition, use ordisposition of the company's assets that could have a material effect on thefinancial statements.

 

Because of its inherent limitations, internal controlover financial reporting may not prevent or detect misstatements.  Projections of any evaluation ofeffectiveness to future periods are subject to the risk that controls maybecome inadequate because of changes in conditions, or that the degree of compliancewith the policies or procedures may deteriorate.

IPC's management assessed the effectiveness of thecompany's internal control over financial reporting as of December 31,2005.  In making this assessment, thecompany's management used the criteria set forth by the Committee of SponsoringOrganizations of the Treadway Commission in *Internal Control-IntegratedFramework*.

Based on its assessment, management believes that, as ofDecember 31, 2005, IPC's internal control over financial reporting is effectivebased on those criteria.

IPC's independent registered public accounting firm hasaudited the financial statements included in this Annual Report on Form 10-Kfor the year ended December 31, 2005 and issued a report, which appears on thenext page and expresses an unqualified opinion on management's assessment andon the effectiveness of IPC's internal control over financial reporting as ofDecember 31, 2005.

March 6, 2006

**REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM**

To the Board of Directors and Shareholder of Idaho PowerCompanyBoise, Idaho

We have audited management's assessment, included in theaccompanying Management's Annual Report on Internal Control over FinancialReporting, that Idaho Power Company and subsidiary (the "Company")maintained effective internal control over financial reporting as of December31, 2005, based on criteria established in *Internal Control-IntegratedFramework* issued by the Committee of Sponsoring Organizations of theTreadway Commission.  The Company'smanagement is responsible for maintaining effective internal control overfinancial reporting and for its assessment of the effectiveness of internalcontrol 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.

We conducted our audit in accordance with the standardsof the Public Company Accounting Oversight Board (United States).  Those standards require that we plan andperform the audit to obtain reasonable assurance about whether effectiveinternal control over financial reporting was maintained in all materialrespects.  Our audit included obtainingan understanding of internal control over financial reporting, evaluatingmanagement's assessment, testing and evaluating the design and operatingeffectiveness of internal control, and performing such other procedures as weconsidered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company's internal control over financial reporting isa process designed by, or under the supervision of, the company's principalexecutive and principal financial officers, or persons performing similarfunctions, and effected by the company's board of directors, management, andother personnel to provide reasonable assurance regarding the reliability offinancial reporting and the preparation of financial statements for externalpurposes in accordance with generally accepted accounting principles.  A company's internal control over financialreporting includes those policies and procedures that (1) pertain to themaintenance of records that, in reasonable detail, accurately and fairlyreflect the transactions and dispositions of the assets of the company; (2)provide reasonable assurance that transactions are recorded as necessary topermit preparation of financial statements in accordance with generallyaccepted accounting principles, and that receipts and expenditures of thecompany are being made only in accordance with authorizations of management anddirectors of the company; and (3) provide reasonable assurance regardingprevention or timely detection of unauthorized acquisition, use, or dispositionof the company's assets that could have a material effect on the financialstatements.

Because of the inherent limitations of internal controlover financial reporting, including the possibility of collusion or impropermanagement override of controls, material misstatements due to error or fraudmay not be prevented or detected on a timely basis.  Also, projections of any evaluation of theeffectiveness of the internal control over financial reporting to futureperiods are subject to the risk that the controls may become inadequate becauseof changes in conditions, or that the degree of compliance with the policies orprocedures may deteriorate.

In our opinion, management's assessment that the Companymaintained effective internal control over financial reporting as of December31, 2005, is fairly stated, in all material respects, based on the criteriaestablished in *Internal Control-Integrated Framework* issued by theCommittee of Sponsoring Organizations of the Treadway Commission.  Also in our opinion, the Company maintained,in all material respects, effective internal control over financial reportingas of December 31, 2005, based on the criteria established in *InternalControl-Integrated Framework* issued by the Committee of SponsoringOrganizations of the Treadway Commission.

We have also audited, in accordance with the standards ofthe Public Company Accounting Oversight Board (United States), the consolidatedfinancial statements and financial statement schedule as of and for the yearended December 31, 2005 of the Company and our report dated March 6, 2006expressed an unqualified opinion on those financial statements and financialstatement schedule.

DELOITTE & TOUCHE LLP

Boise, IdahoMarch 6, 2006

**Changes in Internal Control Over Financial Reporting**There have been nochanges in IDACORP's or IPC's internal control over financial reporting duringthe quarter ended December 31, 2005 requiring dislosure that have materiallyaffected, or are reasonably likely to materially affect, IDACORP's or IPC'sinternal control over financial reporting.

**ITEM9B.  OTHER INFORMATION**

None

**PART III**

**ITEM 10.  DIRECTORSAND EXECUTIVE OFFICERS OF THE REGISTRANT**

The portion of IDACORP's definitive proxy statementappearing under the captions "Election of Directors - Nominees ForElection - Terms Expire 2009," "Election of Directors - ContinuingDirectors - Terms Expire 2008," "Election of Directors -ContinuingDirectors - Terms Expire 2007," "The Board of Directors andCommittees - Committees - Audit Committee," "Section 16(a) BeneficialOwnership Reporting Compliance" and "Corporate Governance - Code ofEthics," to be filed pursuant to Regulation 14A for the 2006 AnnualMeeting of Shareholders to be held on May 18, 2006 is hereby incorporated byreference.

**ITEM 11.  EXECUTIVECOMPENSATION**

The portion of IDACORP's definitive proxy statementappearing under the caption "Compensation of Directors and ExecutiveOfficers"  (except the Report of theCompensation Committee and the Performance Graph) to be filed pursuant to Regulation14A for the 2006 Annual Meeting of Shareholders to be held on May 18, 2006 ishereby incorporated by reference.

**ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIALOWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS**

The portion of IDACORP's definitive proxy statementappearing under the caption "Security Ownership of Directors and ExecutiveOfficers" to be filed pursuant to Regulation 14A for the 2006 AnnualMeeting of Shareholders to be held on May 18, 2006 is hereby incorporated byreference.

The following table includesinformation as of December 31, 2005 with respect to equity compensation planswhere equity securities of IDACORP may be issued.  These plans are the 1994 Restricted StockPlan (RSP), the IDACORP 2000 Long-Term Incentive and Compensation Plan (LTICP)and the Non-Employee Director Stock 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 security**

**Plan Category**

** **

**warrants and rights**

** **

**warrants and rights**

** **

**reflected in column (a))**

Equity compensation

 

 

 

 

 

 

 

 

plans approved by

 

 

 

 

 

 

 

 

shareholders(1)

 

1,421,914

 

$

32.24

 

1,627,641(2)(3)

Equity compensation

 

 

 

 

 

 

 

 

plans not approved

 

 

 

 

 

 

 

 

by shareholders(4)

 

-

 

$

-

 

53,699    

 

 

Total

 

1,421,914

 

$

32.24

 

1,681,340    

 

(1)

Consists of the RSP and the  LTICP.

(2)

In addition to being  available for future issuance upon exercise of  options, 1,552,802 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)

74,839 shares remain  available for future issuance under the RSP.

(4)

Consists of shares available  for future issuance under the DSP.

 

**Equity CompensationPlans Not Approved by IDACORP Shareholders**:The DSP was adopted by the Board of Directors effective May 17, 1999.  The purpose of the DSP is to increase directors'stock ownership through stock-based compensation.  The DSP initially provided for an annualstock grant in June of each year valued at $6,000 with a maximum number ofshares available under the plan of 10,500. Effective January 1, 2000, the DSP was amended to increase the annual grantto stock valued at $8,000.  EffectiveApril 1, 2002, the number of shares available under the plan was increased to100,000 and the annual grant was increased to $16,000 in part to offset thetermination of the director's non-qualified deferred compensation plan.  On January 20, 2005, the annual grant wasincreased to stock valued at $40,000 and the grant date changed to February ofeach year.  The plan provides for a totalof 100,000 shares that may be granted from treasury stock or stock purchased onthe open market.

**ITEM 13.  CERTAINRELATIONSHIPS AND RELATED TRANSACTIONS**

None

**ITEM 14.  PRINCIPALACCOUNTANT FEES AND SERVICES**

**IDACORP:**

The portion of IDACORP's definitive proxy statementappearing under the caption "Independent Accountant Billings" in theproxy statement to be filed pursuant to Regulation 14A for the 2006 AnnualMeeting of Shareholders to be held on May 18, 2006 is hereby incorporated byreference.

**IPC:**

The following table presents fees billed for professionalservices rendered by Deloitte & Touche LLP, the member firms of DeloitteTouche Tohmatsu, and their respective affiliates (collectively, Deloitte &Touche), for the fiscal years ended December 31, 2005 and 2004.  The amounts presented below reflectallocations from IDACORP for IPC's portion of the fees, as well as amountsbilled directly to IPC.

** **

**2005**

** **

**2004**

 
Audit fees

$

704,360

 

$

760,496

 
Audit-related fees (1)

 

47,250

 

 

74,243

 
Tax fees (2)

 

14,045

 

 

140,472

 
All other fees

 

-

 

 

-

 
Total

$

765,655

 

$

975,211

 
 

 

 

 

 

 

 
(1)

Includes fees for audits of IPC's benefit plans,  officer certification assistance, Sarbanes-Oxley section 404 readiness  assistance in 2004 and work

 

 

in connection with regulatory inquiries.

(2)

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

 

**Policy on AuditCommittee Pre-Approval**IPC and the Audit Committee are committed to ensuring the independence of theindependent registered public accounting firm, both in fact and inappearance.  In this regard, on February4, 2004, the Audit Committee established a pre-approval policy in accordancewith applicable securities rules.  Allfees were pre-approved by the Audit Committee in 2005.

In additionto the audits of IPC's consolidated financial statements, the independentpublic accounting firm may be engaged to provide certain audit-related, tax andother services.  The Audit Committee mustpre-approve all services performed by the independent public accounting firm toassure that the provision of those services does not impair the publicaccounting firm's independence.  Theservices that the Audit Committee will consider include audit services such asattest services, changes in the scope of the audit of the financial statements,and the issuance of comfort letters and consents in connection with financings;audit-related services such as internal control reviews and assistance withinternal control reporting requirements; attest services related to financialreporting that are not required by statute or regulation, and accountingconsultations and audits related to proposed transactions and new or proposedaccounting rules, standards and interpretations; and tax compliance andplanning 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 proposedservices exceeding pre-approved cost levels will require specific pre-approvalby 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 anypre-approval decisions to the Audit Committee at its next scheduled meeting.

Anyrequest to engage the independent public accounting firm to provide a servicewhich has not received general pre-approval must be submitted as a writtenproposal to IPC's Chief Financial Officer with a copy to the GeneralCounsel.  The request must include adetailed 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 ChiefFinancial Officer, the General Counsel and the independent public accountingfirm that the proposed engagement complies with the terms of the pre-approvalpolicy and the applicable rules and regulations, the request will be presentedto the Audit Committee or the Committee Chairman, as the case may be, forpre-approval.

Indetermining whether to pre-approve the engagement of the independent publicaccounting firm, the Audit Committee or the Committee Chairman, as the case maybe, must consider, among other things, the pre-approval policy, applicablerules and regulations and whether the nature of the engagement and the relatedfees are consistent with the following principles, as stated in the SEC'sadopting release for the rules on auditor independence:

the independent public accounting firm cannot function inthe role of management of IPC;

the independent public accounting firm cannot audit itsown work; and

the independent public accounting firm cannot serve inany 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-approvalis 12 months from the date of pre-approval, unless the Audit Committeespecifically provides for a different period. The Audit Committee will periodically revise the list of pre-approvedservices, based on subsequent determinations.

**PART IV**

**ITEM 15.  EXHIBITSAND FINANCIAL STATEMENT SCHEDULES**

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

(3)  Exhibits.

*Previously Filed and Incorporated Herein by Reference

*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.

 

 

*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

The Revised Security Plan for Senior Management  Employees - a non-qualified, deferred compensation plan, amended and restated  effective November 20, 2003.  File  number 1-14465, 1-3198, Form 10-Q for the quarter ended 3/31/04, filed on  5/6/04, as Exhibit 10(h)(i).

 

 

*10(h)(ii) 1

2005 IDACORP, Inc. Executive Incentive Plan.  File number 1-14465, 1-3198, Form 8-K,  filed on 1/26/05, as Exhibit 10.2.

 

 

*10(h)(iii) 1

The 1994 Restricted Stock Plan for officers and key  executives of IDACORP, Inc. and IPC effective July 1, 1994.  File number 1-3198, Form 10-K for the year  ended 12/31/94, filed on 3/10/95, as Exhibit 10(n)(iii).

 

 

*10(h)(iv) 1

Form of Restricted Stock Award Agreement.  File number 1-14465, 1-3198, Form 10-Q for  the quarter ended 9/30/04, filed on 11/4/04, as Exhibit 10(h)(iv).

 

 

*10(h)(v) 1

Form of Performance Share Award Agreement.  File number 1-14465, 1-3198, Form 10-Q for  the quarter ended 9/30/04, filed on 11/4/04, as Exhibit 10(h)(v).

 

 

*10(h)(vi) 1

The Revised Security Plan for Board of Directors - a  non-qualified, deferred compensation plan effective August 1, 1996, revised  March 8, 1999, as amended.  File number  1-14465, 1-3198, Form 10-K for the year ended 12/31/98, filed on 3/19/99, as  Exhibit 10(h)(iv).

 

 

*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 Change in Control Agreement between IDACORP,  Inc. and all Officers of IDACORP and IPC.   File number 1-14465, Form 10-Q for the quarter ended 9/30/99, filed on  11/5/99, as Exhibit 10(h).

 

 

*10(h)(ix) 1

IDACORP, Inc. 2000 Long-Term Incentive and Compensation  Plan, as amended as of March 17, 2005.   File number 1-14465, 1-3198, Form 10-Q for the quarter ended 3/31/05,  filed on 5/5/05, as Exhibit 10(h)(ix).

 

 

*10(h)(x) 1

IDACORP, Inc. 2000 Long-Term Incentive and Compensation  Plan - Form of Stock Option Award Agreement.   File number 1-14465, 1-3198, Form 10-Q for the quarter ended 9/30/04,  filed on 11/4/04, as Exhibit 10(h)(x).

 

 

*10(h)(xi)1

IDACORP, Inc. 2000 Long-Term Incentive and Compensation  Plan-Form of Restricted Stock Award Agreement (time vesting).  File number 1-14465, 1-3198, Form 8-K,  filed on 1/26/05, as Exhibit 10.4.

 

 

*10(h)(xii)1

IDACORP, Inc. 2000 Long-Term Incentive and Compensation  Plan-Form of Restricted Stock Award Agreement (performance vesting).  File number 1-14465, 1-3198, Form 8-K,  filed on 1/26/05, as Exhibit 10.5.

 

 

*10(h)(xiii)1

Form of Officer Indemnification Agreement as signed by  all Officers of IDACORP, Inc. and IPC.   File number 1-14465, 1-3198, Form 10-Q for the quarter ended 6/30/04,  filed on 8/5/04, as Exhibit 10(h)(viii).

 

 

*10(h)(xiv)1

Form of Director Indemnification Agreement as signed by  all Directors of IDACORP, Inc.  File  number 1-14465, 1-3198, Form 10-Q for the quarter ended 6/30/04, filed on  8/5/04, as Exhibit 10(h)(ix).

 

 

*10(h)(xv)1

IDACORP, Inc. and Idaho Power Company NEO 2005 Base  Compensation Table.  File number  1-14465, 1-3198, Form 8-K, filed on 1/26/05, as Exhibit 10.1.

 

 

*10(h)(xvii)1

2005 IDACORP, Inc. Executive Incentive Plan NEO Award  Opportunity Chart.  File number  1-14465, 1-3198, Form 8-K, filed on 1/26/05, as Exhibit 10.3.

 

 

*10(h)(xviix) 1

IDACORP, Inc. 2000 Long-Term Incentive and Compensation  Plan - 2005 Restricted Stock Awards (time vesting) to NEOs Chart.  File number 1-14465, 1-3198, Form 8-K,  filed on 1/26/05, as Exhibit 10.6.

 

 

*10(h)(xviii) 1

IDACORP, Inc. 2000 Long-Term Incentive and Compensation  Plan - 2005 Restricted Stock Awards (performance vesting) to NEOs Chart.  File number 1-14465, 1-3198, Form 8-K,  filed on 1/26/05, as Exhibit 10.7.

 

 

*10(h)(xix) 1

IDACORP, Inc. and IPC 2005 Compensation for  Non-Employee Directors of the Board of Directors.  File number 1-14465, 1-3198, Form 8-K,  filed on 1/26/05, as Exhibit 10.8.

 

 

*10(h)(xx) 1

Jan B. Packwood 2005 Restricted Stock Award  Agreement.  File number 1-14465,  1-3198, Form 8-K, filed on 1/26/05, as Exhibit 10.10.

 

 

*10(h)(xxi)1

Offer of employment letter dated July 9, 2004, to  Thomas R. Saldin from IDACORP, Inc.   File number 1-14465, 1-3198, Form 10-K for the year ended 12/31/04,  filed on 3/9/05, as Exhibit 10(h)(xxiv).

 

 

*10(h)(xxii)1

IDACORP, Inc. and IPC 2006 NEO Base Compensation  Table.  File Number 1-14465, 1-3198,  Form 8-K, filed on 1/25/06, as Exhibit 10.1.

 

 

*10(h)(xxiii) 1

IDACORP, Inc. 2006 Revised Executive Incentive  Plan.  File number 1-14465, 1-3198,  Form 8-K, filed on 2/9/06, as Exhibit 10.1.

 

 

*10(h)(xxiv)1

IDACORP, Inc. 2006 Revised Executive Incentive Plan NEO  Award Opportunity Chart.  File number  1-14465, 1-3198, Form 8-K, filed on 2/9/06, as Exhibit 10.2

 

 

*10(h)(xxv)1

IPC 1994 Restricted Stock Plan - Form of Restricted  Stock Agreement (time-vesting).  File  number 1-14465, 1-3198, Form 8-K, filed on 2/9/06 as Exhibit 10.3.

 

 

*10(h)(xxvi)1

IPC 1994 Restricted Stock Plan - Restricted Stock Awards  (time-vesting) to NEOs Chart.  File  number 1-14465, 1-3198, Form 8-K, filed on 2/9/06 as Exhibit 10.4.

 

 

*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).

 

 

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., File number 1-14465,  1-3198, Form 10-K for the year ended 12/31/04, filed on 3/9/05, as Exhibit  21.

 

 

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

 

 

**IDACORP, Inc.SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT**

**CONDENSED STATEMENTS OF INCOME**

 

**Year Ended December 31,**

 

**2005**

** **

**2004**

** **

**2003**

 

(thousands of dollars)

**Income:**

 

 

 

 

 

 

 

 

 

Equity in income of subsidiaries

$

67,946 

 

$

76,482 

 

$

48,163 

 

Other income

 

721 

 

 

535 

 

 

2,309 

 

 

Total income

 

68,667 

 

 

77,017 

 

 

50,472 

 

 

 

 

 

 

 

 

 

 

**Expenses:**

 

 

 

 

 

 

 

 

 

Operating expenses

 

5,189 

 

 

5,782 

 

 

5,340 

 

Interest expense

 

3,816 

 

 

1,221 

 

 

1,088 

 

Other expense

 

231

 

 

994 

 

 

1,570 

 

 

Total expenses

 

9,236 

 

 

7,997 

 

 

7,998 

 

 

 

 

 

 

 

 

 

**Income Before Income Taxes**

 

59,431 

 

 

69,020 

 

 

42,474 

 

 

 

 

 

 

 

 

 

**Income Tax Benefit**

 

(4,230)

 

 

(3,963)

 

 

(4,104)

 

 

 

 

 

 

 

 

 

**Net Income**

$

63,661 

 

 

72,983 

 

$

46,578 

 

 

 

 

 

 

 

 

 

 

 

The accompanying note is an integral part of thesestatements.

 

**IDACORP, Inc.SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT**

**CONDENSED BALANCE SHEETS**

 

**December 31,**

 

**2005**

** **

**2004**

 

(thousands of dollars)

**Assets**

 

 

 

 

 

** **

 

 

 

 

 

**Current Assets:**

 

 

 

 

 

 

Cash and cash equivalents

$

1,234

 

$

2,637

 

Receivables

 

1,304

 

 

1,467

 

Taxes receivable

 

6,897

 

 

-

 

Deferred income taxes

 

27,997

 

 

28,211

 

Other

 

335

 

 

692

 

 

Total current assets

 

37,767

 

 

33,007

 

 

 

 

 

 

 

**Investment in subsidiaries**

** **

1,049,276

 

 

1,033,141

 

 

 

 

 

 

 

**Other Assets**

** **

 

 

 

 

 

Intercompany notes receivable

 

35,306

 

 

35,753

 

Other

 

883

 

 

1,396

 

 

Total other assets

 

36,189

 

 

37,149

 

 

 

 

 

 

 

 

** **

** **

** **

**Total**

$

1,123,232

 

$

1,103,297

** **

 

 

 

 

 

** **

 

 

 

 

 

** **

 

 

 

 

 

**Liabilities and Shareholders' Equity**

 

 

 

 

 

** **

 

 

 

 

 

**Current Liabilities:**

 

 

 

 

 

 

Notes payable

$

60,100

 

$

35,400

 

Accounts payable

 

3,162

 

 

3,127

 

Taxes accrued

 

-

 

 

4,242

 

Other

 

-

 

 

1

 

 

Total current liabilities

 

63,262

 

 

42,770

 

 

 

 

 

 

 

**Other Liabilities:**

 

 

 

 

 

 

Intercompany notes payable

 

33,265

 

 

51,537

 

Other

 

1,454

 

 

704

 

 

Total other liabilities

 

34,719

 

 

52,241

** **

 

 

 

 

 

**Shareholders' Equity**

 

1,025,251

 

 

1,008,286

 

 

 

 

 

 

 

 

 

**Total**

$

1,123,232

 

$

1,103,297

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

The accompanying note is an integral part of thesestatements.

 

**IDACORP, Inc.SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT**

**CONDENSED STATEMENTS OF CASH FLOWS**

 

**Year Ended December 31,**

 

**2005**

** **

**2004**

** **

**2003**

 

(thousands of dollars)

 

 

 

 

 

 

 

 

 

**Operating Activities:**

 

 

 

 

 

 

 

 

 

Net cash provided by operating activities

$

35,462 

 

$

23,958 

 

$

131,533 

 

 

 

 

 

 

 

 

 

 

 

**Investing Activities:**

 

 

 

 

 

 

 

 

 

Contributions to subsidiaries

 

- 

 

 

(100,456)

 

 

(40,237)

 

Distributions from subsidiaries

 

- 

 

 

- 

 

 

77,792 

 

Change in intercompany notes receivable

 

1,271 

 

 

12,407 

 

 

66,286 

 

Other

 

- 

 

 

(53)

 

 

158 

 

 

Net cash provided by (used in) investing activities

 

1,271 

 

 

(88,102)

 

 

103,999 

 

 

 

 

 

 

 

 

 

**Financing Activities:**

 

 

 

 

 

 

 

 

 

Issuance of common stock

 

6,296 

 

 

115,690 

 

 

4,123 

 

Dividends on common stock

 

(50,690)

 

 

(45,838)

 

 

(64,726)

 

Increase (decrease) in short-term borrowings

 

24,700 

 

 

(58,250)

 

 

(72,050)

 

Change in intercompany notes payable

 

(17,971)

 

 

(4,323)

 

 

(41,025)

 

Other

 

(471)

 

 

(1,419)

 

 

(1,227)

 

 

Net cash provided by (used in) financing activities

 

(38,136)

 

 

5,860 

 

 

(174,905)

 

 

 

 

 

 

 

 

 

Net increase (decrease) in cash and cash equivalents

 

(1,403)

 

 

(58,284)

 

 

60,627 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents at beginning of year

 

2,637 

 

 

60,921 

 

 

294 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents at end of year

$

1,234 

 

$

2,637 

 

$

60,921 

 

 

 

 

 

 

 

 

 

 

 

The accompanying note is an integral part of thesestatements.

 

**IDACORP, Inc.SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT**

**NOTES TO CONDENSED FINANCIAL STATEMENTS**

**1.  BASIS OFPRESENTATION**

Pursuantto rules and regulations of the Securities and Exchange Commission, theunconsolidated condensed financial statements of IDACORP, Inc. do not reflectall of the information and notes normally included with financial statementsprepared in accordance with accounting principles generally accepted in theUnited States of America.  Therefore,these financial statements should be read in conjunction with the consolidatedfinancial statements and related notes included in the 2005 Form 10-K, Part II,Item 8.

**Accountingfor subsidiaries**IDACORP hasaccounted for the earnings of its subsidiaries under the equity method in theunconsolidated condensed financial statements.

**IDACORP, Inc.SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS**

YearsEnded December 31, 2005, 2004 and 2003

**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)**

 

** **

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

 

 

 

 

 

 

 

 

 

 

 

2003:

 

 

 

 

 

 

 

 

 

 

Reserves  Deducted From

 

 

 

 

 

 

 

 

 

 

 

Applicable  Assets:

 

 

 

 

 

 

 

 

 

 

 

 

Reserve  for uncollectible accounts

$

43,311

$

3,958 

$

- 

$

4,059

$

43,210

 

 

Reserve  for uncollectible notes

 

-

 

2,578 

 

- 

 

-

 

2,578

Other  Reserves:

 

 

 

 

 

 

 

 

 

 

 

Rate  refunds

 

-

 

1,514 

 

- 

 

-

 

1,514

 

Injuries  and damages reserve

 

1,936

 

111 

 

- 

 

1,216

 

831

 

Miscellaneous  operating reserves

 

-

 

61 

 

- 

 

-

 

61

 

 

 

 

 

 

 

 

 

 

 

Notes:

(1)  Represents deductions from the reserves for  purposes for which the reserves were created.

 

**IDAHO POWER COMPANYSCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS**

YearsEnded December 31, 2005, 2004 and 2003

**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)**

 
** **

 
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

 

1,801 

 

- 

 

835

 

1,797

 
 

Miscellaneous  operating reserves

 

61

 

- 

 

- 

 

26

 

35

 
 

 

 

 

 

 

 

 

 

 

 

 
2003:

 

 

 

 

 

 

 

 

 

 

 
Reserves  Deducted From

 

 

 

 

 

 

 

 

 

 

 
 

Applicable  Assets:

 

 

 

 

 

 

 

 

 

 

 
 

 

Reserve  for uncollectible accounts

$

1,566

$

3,958 

$

- 

$

4,058

$

1,466

 
Other  Reserves:

 

 

 

 

 

 

 

 

 

 

 
 

Rate  refunds

 

-

 

1,514 

 

- 

 

-

 

1,514

 
 

Injuries  and damages reserve

 

1,936

 

111 

 

- 

 

1,216

 

831

 
 

Miscellaneous  operating reserves

 

-

 

61 

 

- 

 

-

 

61

 
 

 

 

 

 

 

 

 

 

 

 

 
Notes:

(1)  Represents deductions from the reserves for  purposes for which the reserves were created.

 

** **

** **

** **

**SIGNATURES**Pursuant to the requirements of Section 13 or 15(d) of the SecuritiesExchange Act of 1934, the registrant has caused this report to be signed on itsbehalf by the undersigned, thereunto duly authorized.

IDACORP,Inc.(Registrant)

March7, 2006

By:*/s/Jan B. Packwood*                   Jan B. PackwoodPresident and Chief Executive Officer

Pursuantto the requirements of the Securities Exchange Act of 1934, this report hasbeen signed below by the following persons on behalf of the registrant and inthe capacities and on the dates indicated.

By:

 

*/s/Jon H. Miller*

 

 

Chairman of the Board

March 7, 2006

 

 

Jon H. Miller

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

By:

 

*/s/Jan B. Packwood*

 

 

President and Chief Executive

"

 

 

Jan B. Packwood

 

 

Officer and Director

 

 

 

 

 

 

(Principal Executive Officer)

 

By:

* *

*/s/J. LaMont Keen*

 

 

 

 

 

 

J. LaMont Keen

 

 

Executive Vice President

"

 

 

 

 

 

and Director

 

 

 

 

 

 

 

 

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:

 

* *

By:

 

*/s/Joan H. Smith*

"

 

 

Jack K. Lemley

 

 

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

 

 

 

 

 

 

 

 

 

 

* *

 

 

 

 

 

 

 

 

 

* *

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

**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.

IDAHOPOWER COMPANY(Registrant)

 

March 7, 2006

By:*/s/J. LaMont Keen   *                                J. LaMont KeenPresident and Chief Executive Officer

Pursuant to the requirements ofthe Securities Exchange Act of 1934, this report has been signed below by thefollowing persons on behalf of the registrant and in the capacities and on thedates indicated.

 

 

By:

 

*/s/Jon H. Miller*

 

 

Chairman of the Board

March  7, 2006

 

 

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:

 

* *

By:

 

*/s/Joan H. Smith*

"

 

 

Jack K. Lemley

 

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

**EXHIBIT INDEX**

Exhibit Number

 

 

 

 

 

12

 

Statements Re:  Computation of Ratio of Earnings to Fixed Charges.  (IDACORP, Inc.)

 

 

 

12(a)

 

Statements Re:  Computation of Supplemental Ratio of Earnings to Fixed Charges.

 

 

(IDACORP, Inc.)

 

 

 

12(b)

 

Statements Re:  Computation of Ratio of Earnings to Combined Fixed Charges and 

 

 

Preferred  Dividend Requirements.  (IDACORP, Inc.)

 

 

 

12(c)

 

Statements Re:  Computation of Supplemental Ratio of Earnings to Combined Fixed 

 

 

Charges and  Preferred Dividend Requirements.   (IDACORP, Inc.)

 

 

 

12(d)

 

Statements Re:  Computation of Ratio of Earnings to Fixed Charges.  (IPC)

 

 

 

12(e)

 

Statements Re:  Computation of Supplemental Ratio of Earnings to Fixed Charges.  (IPC)

 

 

 

23

 

Consent of  Independent Registered Public Accounting Firm.

 

 

 

31(a)

 

Rule 13a-14(a)  certification.

 

 

 

31(b)

 

Rule 13a-14(a)  certification.

 

 

 

31(c)

 

Rule 13a-14(a)  certification.

 

 

 

31(d)

 

Rule 13a-14(a)  certification.

 

 

 

32(a)

 

Section 1350  certification.

 

 

 

32(b)

 

Section 1350  certification.

 

 

 

  |
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------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------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