UNITED STATES SECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549FORM 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, 2002                                           |

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

 

Forthe transition period from ................... to..................................................................
|                                                        |                             | Exact name of registrants as specified in      |                 |                  |
|-------------------------------------------------------------|----------------------------------|------------------------------------------------|----------------------|-----------------------|
| Commission                                                  |                             | their charters, address of principal executive |                 | IRS Employer          |
| File Number                                                 |                             | offices 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 or other  jurisdiction of incorporation:  Idaho  |
|                                                        |                             | 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 and Pacific |
|                                                        | Preferred  Stock Purchase Rights |                                           |                 |
|                                                        |                             |                                           |
| SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: |                             |                                           |
| Idaho Power Company:                                        | Preferred  Stock                 |                                           |                 |
|                                                        |                             |                                           |
|                                                             |                                  |                                                |                      |                       |  |  |  |

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

Indicateby check mark if disclosure of delinquent filers pursuant to Item 405 ofRegulation S-K is not contained herein, and will not be contained, to the bestof registrants' knowledge, in definitive proxy or information statementsincorporated by reference in Part III of this Form 10-K or any amendment tothis Form 10-K.   (X )

Indicate by check markwhether the registrants are accelerated filers (as defined in Rule 12b-2 of theAct).
| IDACORP,  Inc.       | Yes    | ( X )                 |  No | (    ) |
|----------------------|--------|-----------------------|----------|-----------------------|
| Idaho  Power Company |   | (    ) |     | ( X )                 |

 

Aggregate market value of voting and non-voting commonstock held by nonaffiliates (June 30, 2002):
| IDACORP,  Inc.:       | $1,038,521,475 |
|-----------------------|----------------|
| Idaho  Power Company: | None           |

 

Number of shares of common stock outstanding atFebruary 28, 2003:
| IDACORP,  Inc.:       | 38,201,873                            |
|-----------------------|---------------------------------------|
| Idaho  Power Company: | 37,612,351  all held by IDACORP, Inc. |

 
| Documents  Incorporated by Reference: |
|---------------------------------------|
| Part III, Item 10 - 13                | Portions  of the joint definitive proxy statement of IDACORP, Inc. and Idaho Power  Company to be |
|                                  | filed  pursuant to Regulation 14A for the 2003 Annual Meeting of Shareholders to be  held on May |
|                                  | 15, 2003. |

 

This Combined Form 10-Krepresents separate filings by IDACORP, Inc. and Idaho Power Company.  Information contained herein relating to anindividual registrant is filed by that registrant on its own behalf.  Idaho Power Company makes no representationas to the information relating to IDACORP, Inc.'s other operations.
| **COMMONLY USED TERMS** |
|-------------------------|
|                    |
| AFDC                    | - | Allowance  for Funds Used During Construction |
| APB                     | - | Accounting  Principles Board |
| BPA                     | - | Bonneville  Power Administration |
| Cal  ISO                | - | California  Independent System Operator |
| CalPX                   | - | California  Power Exchange |
| CSPP                    | - | Cogeneration  and Small Power Production |
| DSM                     | - | Demand-Side  Management |
| EITF                    | - | Emerging  Issues Task Force |
| EPA                     | - | Environmental  Protection Agency |
| EPS                     | - | Earning  per share |
| FASB                    | - | Financial  Accounting Standards Board |
| FERC                    | - | Federal  Energy Regulatory Commission |
| FPA                     | - | Federal  Power Act |
| Garnet                  | - | Garnet  Energy LLC, a subsidiary of Ida-West |
| 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 |
| kW                      | - | kilowatt |
| kWh                     | - | kilowatt-hour |
| LTICP                   | - | Long-Term  Incentive and Compensation Plan |
| MD&A                | - | Management's  Discussion and Analysis |
| MMbtu                   | - | Million  British Thermal Units |
| MW                      | - | Megawatt |
| MWh                     | - | Megawatt-hour |
| OPUC                    | - | Oregon  Public Utility Commission |
| Overton                 | - | Overton  Power District No. 5 |
| PCA                     | - | Power  Cost Adjustment |
| PG&E                | - | Pacific  Gas and Electric Company |
| PURPA                   | - | Public  Utilities Regulatory Policy Act |
| REA                     | - | Rural  Electrification Administration |
| RMC                     | - | Risk  Management Committee |
| RTOs                    | - | Regional  Transmission Organizations |
| SCE                     | - | Southern  California Edison |
| SFAS                    | - | Statement  of Financial Accounting Standards |
| SPPCo                   | - | Sierra  Pacific Power Company |
| Valmy                   | - | North  Valmy Steam Electric Generating Plant |
|                    |   |   |

 

 

 

 

 
| **TABLE OF CONTENTS** |
|-----------------------|
|                  | **Page** |
| **Part  I**           |
|                  |
|                  | Item  1. | Business | 1-12 |
|                  | Item  2. | Properties | 13-15 |
|                  | Item  3. | Legal  Proceedings | 15 |
|                  | Item  4. | Submission  of Matters to a Vote of Security Holders | 15 |
|                  |
|                  | Executive  Officers of the Registrants | 16-17 |
|                  |
| **Part  II**          |
|                  |
|                  | Item  5. | Market  for the Registrant's Common Stock and Related Stockholder |   |
|                  |   |   | Matters | 18 |
|                  | Item  6. | Selected  Financial Data | 19 |
|                  | Item  7. | Management's  Discussion and Analysis of Financial Condition and |   |
|                  |   |   | Results  of Operations | 20-47 |
|                  | Item  7A. | Quantitative  and Qualitative Disclosures about Market Risk | 48-50 |
|                  | Item  8. | Financial  Statements and Supplementary Data | 51-102 |
|                  | Item  9. | Changes  in and Disagreements with Accountants on Accounting and |   |
|                  |   |   | Financial  Disclosure | 102 |
| **Part  III**         |
|                  |
|                  | Item  10. | Directors  and Executive Officers of the Registrants* |   |
|                  | Item  11. | Executive  Compensation* |   |
|                  | Item  12. | Security  Ownership of Certain Beneficial Owners and Management |   |
|                  |   |   | and  Related Stockholder Matters* | 103 |
|                  | Item  13. | Certain  Relationships and Related Transactions* |   |
|                  | Item  14. | Controls  and Procedures | 104 |
|                  |
| **Part  IV**          |
|                  |
|                  | Item  15. | Exhibits,  Financial Statement Schedules and Reports on Form 8-K | 104-111 |
|                  |
|                  | Signatures | 112-113 |
|                  |
|                  | Certifications | 114-117 |
|                  |
|                  | Exhibit  Index | 118 |
|                  |
|                  | *Incorporated  by reference, except for the Equity Compensation Plan information in Item 12. |
|                  |   |

 

 

 

 

 

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**SAFE HARBOR STATEMENT**This Form 10-K contains "forward-looking statements"intended to qualify for safe harbor from liability established by the PrivateSecurities Litigation Reform Act of 1995. Forward-looking statements should be read with the cautionary statementsand important factors included in this Form 10-K at Part II, Item 7-"Management's Discussion and Analysis of Financial Condition and Resultsof Operations (MD&A) - Forward-Looking Information."  Forward-looking statements are allstatements other than statements of historical fact, including withoutlimitation those that are identified by the use of the words"anticipates," "estimates," "expects,""intends," "plans," "predicts," and similarexpressions.

**PART I - IDACORP, Inc. and Idaho Power Company**

**ITEM 1. BUSINESS**

**OVERVIEW:**

IDACORP, Inc. (IDACORP) is a holding companywhose principal operating subsidiaries are Idaho Power Company (IPC) andIDACORP Energy (IE).  IPC is regulatedby the Federal Energy Regulatory Commission (FERC) and the state regulatorycommissions of Idaho and Oregon and is engaged in the generation, transmission,distribution, sale and purchase of electric energy.  IPC is the parent of Idaho Energy Resources Co., a joint venturerin Bridger Coal Company, which supplies coal to the Jim Bridger generatingplant owned in part by IPC.

IDACORP announced in 2002 that IE, amarketer of electricity and natural gas, would wind down its operations.

IDACORP's other subsidiaries include:

Ida-WestEnergy (Ida-West) - developer and manager of independent power projects;

IdaTech- developer of integrated fuel cell systems;

IDACORPFinancial Services, Inc. (IFS) - affordable housing and other real estateinvestments;

Velocitus- commercial and residential Internet service provider; and

IDACOMM- provider of telecommunications services.

 

AtDecember 31, 2002, IDACORP had 1,942 full-time employees.  Of these employees, 1,700 are employed byIPC.

IDACORPhas identified two reportable business segments, the regulated utilityoperations of IPC and the energy marketing activities of IE.  IPC and IE contributed 94 percent and fivepercent to consolidated operating revenues, respectively, during the year endedDecember 31, 2002.  Financialinformation relating to amounts of sales, revenue, net income and total assetsof IDACORP's operating segments is presented in Note 12 to the ConsolidatedFinancial Statements and below in "Utility Operations" and"Energy Marketing."

IDACORPand IPC make available free of charge their Annual Report on Form 10-K,Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and all amendmentsto these reports filed or furnished pursuant to Section 13(a) or 15(d) of theSecurities Exchange Act of 1934 as soon as reasonably practicable after thereports are electronically filed with or furnished to the Securities andExchange Commission, through their website at www.idacorpinc.com.

**UTILITYOPERATIONS:**

IPC was incorporated under the laws of thestate of Idaho in 1989 as successor to a Maine corporation organized in 1915.IPC is involved in the generation, purchase, transmission, distribution andsale of electric energy in a 20,000 square mile area in southern Idaho andeastern Oregon, with an estimated population of 855,000.  IPC holds franchises in 70 cities in Idahoand nine cities in Oregon and holds certificates from the respective publicutility regulatory authorities to serve all or a portion of 25 counties inIdaho and three counties in Oregon.  Asof December 31, 2002, IPC supplied electric energy to over 412,000 generalbusiness customers.

IPC owns and operates 17 hydroelectric powerplants and one natural gas-fired plant and shares ownership in three coal-firedgenerating plants.  These generatingplants and their capacities are listed in Item 2 - "Properties."  IPC's coal-fired plants are in Wyoming,Oregon and Nevada, and use low-sulfur coal from Wyoming and Utah.

IPC relies heavily on hydroelectric power forits generating needs and is one of the nation's few investor-owned utilitieswith a predominantly hydroelectric generating base.  Because of its reliance on hydro generation, IPC'sgeneration operations can be significantly affected by the weather.  The availability of inexpensivehydroelectric power depends on snowpack in the mountains above IPC's hydrofacilities, precipitation and other weather and streamflow managementconsiderations. When hydroelectric generation decreases and/or customer demandincreases, IPC increases its use of more expensive thermal generation andpurchased power.

Theprimary influences on electricity sales are weather and economicconditions.  Generally, extremetemperatures increase sales to customers, who use electricity for cooling andheating, and moderate temperatures decrease sales.  Precipitation levels during the growing season affect sales tocustomers who use electricity to operate irrigation pumps.  Increased precipitation reduces electricityusage by these customers.

IPC'sprincipal commercial and industrial customers are involved in food processing,electronics and general manufacturing, lumber, beet sugar refining and theskiing industry.  FMC/Astaris,previously IPC's largest volume customer, closed its Pocatello manufacturingplant late in 2001.  IPC entered into aload reduction agreement with FMC/Astaris in 2001.  See further discussion of FMC/Astaris in Part II, Item 7 -"MD&A - REGULATORY ISSUES - FMC/Astaris Settlement Agreement."

**Regulation**IPC is under the regulatory jurisdiction (as to rates, service,accounting and other general matters of utility operation) of the FERC, theIdaho Public Utilities Commission (IPUC) and the Oregon Public UtilityCommission (OPUC).  IPC is also underthe regulatory jurisdiction of the IPUC, OPUC and the Public Service Commissionof Wyoming as to the issuance of securities. IPC is subject to the provisions of the Federal Power Act  (FPA) as a "licensee" and"public utility" as therein defined. IPC's retail rates are established under the jurisdiction of the stateregulatory agencies and its wholesale and transmission rates are regulated bythe FERC (see "Rates" below). Pursuant to the requirements of Section 210 of the Public UtilitiesRegulatory Policy Act of 1978 (PURPA), the state regulatory agencies have eachissued orders and rules regulating IPC's purchase of power from cogenerationand small power production (CSPP) facilities.

Asa licensee under the FPA, IPC and its licensed hydroelectric projects aresubject to the provisions of Part I of the FPA.  All licenses are subject to conditions set forth in the FPA 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.

Thestate of Oregon has a Hydroelectric Act providing for licensing ofhydroelectric projects in that state. IPC's Brownlee, Oxbow and Hells Canyon facilities are on the Snake Riverwhere it forms the boundary between Idaho and Oregon and occupy land located inboth states.  With respect to projectproperty located in Oregon, these facilities are subject to the OregonHydroelectric Act.  IPC has obtainedOregon licenses for these facilities and these licenses are not in conflictwith the FPA or IPC's FERC license (see Item 2 - "Properties.")

**Rates**The rates IPC charges to its general business customers are determinedby the various regulatory authorities. Approximately 97 percent of IPC's general business revenue comes fromcustomers in Idaho.  The rates chargedto these customers are adjusted annually by a Power Cost Adjustment (PCA)mechanism.  The PCA adjusts rates toreflect the changes in costs incurred by IPC to supply power.  Throughout the year, IPC compares its actualpower supply costs to the amounts it is recovering in rates.  Most, but not all, of this difference isdeferred and included in the calculation of rates for future years. Seefurther discussion of rates in Part II, Item 7 - "MD&A - REGULATORYISSUES - Deferred Power Supply Costs," and Note 13 to the ConsolidatedFinancial Statements.

**PowerSupply**IPC meets its system load requirements using a combination of its ownsystem generation, mandated purchases from private developers (see "CSPPPurchases" below), and purchases from other utilities and powerwholesalers. IPC's generating stations and capacities are listed in Item 2 -"Properties."

IPC's system is dual peaking, with thelarger peak demand generally occurring in the summer.  The system peak demand for 2002 was 2,963 megawatts (MW), set onJuly 12, 2002.  Peak demands in 2001 and2000 were 2,570 MW and 2,919 MW, respectively. IPC expects total system energy requirements to grow 3.4 percentannually over the next three years.

The following table presents IPC's systemgeneration for the last three years:
|          | **MWh**                 |   | **Percent of total generation** |
|---------------|-------------------------|--------|---------------------------------|
|          | **2002**                |   | **2001**                        |   | **2000** |   | **2002** |   | **2001** |   | **2000** |
|          |                    |   |                            |   |   |   |   |   |   |   |   |
| Hydroelectric | 6,069                   |   | 5,638                           |   | 8,500 |   | 45% |   | 43% |   | 52% |
| Thermal       | 7,286                   |   | 7,622                           |   | 7,701 |   | 55    |   | 57    |   | 48    |
|          | Total system generation | 13,355 |                            | 13,260 |   | 16,201 |   | 100% |   | 100% |   | 100% |
|          |                    |   |                            |   |   |   |   |   |   |   |   |
|               |                         |        |                                 |  |  |  |  |  |  |  |  |  |

 

The amounts ofelectricity IPC is able to generate from its hydro plants depend on a number offactors, primarily snowpack in the mountains above its hydro facilities,reservoir storage and streamflow conditions. When these factors are favorable, IPC can generate more electricityusing its hydroelectric plants.  Whenthese factors are unfavorable, IPC must increase its reliance on more expensivethermal plants and purchased power.

Below normal streamflowconditions in 2002 yielded a system generation mix of 45 percent hydro and 55percent thermal.  Under normalstreamflow conditions, IPC's system generation mix is approximately 57 percenthydro and 43 percent thermal.

Current Snake River basin snowpack numberssuggest that streamflow conditions for 2003 will remain below normal.  IPC's March 2003 accumulations were 78percent of normal, compared to 85 percent at the same time a year earlier.  With snowpack and upstream reservoir storagebelow normal, IPC is expecting its fourth consecutive year of below normalwater conditions.

Seasonalexchanges of winter-for-summer power are included among the contractedresources to maximize the firm load carrying capability.  An exchange arrangement is currently inplace with NorthWestern Energy under a contract that expires in December 2003.

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 (BPA), Avista Corporation, PacifiCorp,NorthWestern Energy and Sierra Pacific Power Company (SPPCo).  Such interconnections, coupled withtransmission line capacity made available under agreements with certain of theabove utilities, permit the interchange, purchase and sale of power among allmajor electric systems in the west.  IPCis a member of the Western Electricity Coordinating Council, the WesternSystems Power Pool, the Northwest Power Pool and the Northwest Regional TransmissionAssociation.  These groups have beenformed to more efficiently coordinate transmission reliability and planningthroughout the western grid.  See"Competition - Wholesale" below.

**Garnet Power Purchase Agreement:**  IPC and Garnet Energy LLC (Garnet), awholly-owned subsidiary of Ida-West, entered into a power purchase agreement(PPA) on December 14, 2001 for IPC to purchase energy produced by Garnet'sproposed natural gas generation facility. IPC filed an application with the IPUC for an order approving the PPAand an accounting order authorizing the inclusion in the PCA of power supplyexpenses associated with the purchase of capacity and energy from Garnet.  Prior to the actual hearing date, Garnetinformed IPC that there was a substantial likelihood that it would be unable toobtain the financing at acceptable terms necessary to construct the facility.

OnJuly 24, 2002, the IPUC closed the proceeding involving IPC's petition to enterinto a PPA with Garnet and directed IPC to return in 90 days with a report onthe status of Garnet's progress in obtaining financing for the project and howIPC proposed to meet future power requirements if the Garnet facility is notbuilt.  On October 30, 2002, IPCsubmitted its compliance report to the IPUC, which included (1) Ida-West'snotification that due to dramatic changes in the electricity industry,financing the project on acceptable terms under the PPA was impracticable, (2)Ida-West's offering of three alternatives to allow the project to go forwardand (3) IPC's revised plan for meeting future load requirements absent the PPAassociated with the Garnet project, including wholesale power purchases, energyexchanges, obtaining certain transmission rights or constructing or acquiringgeneration resources located in IPC's service territory.  Following the IPUC's acceptance of the 2002Integrated Resource Plan (IRP) (see below), IPC continues to work onidentifying and securing resources necessary to meet future powerrequirements.  The original Garnet PPAwas mutually terminated on March 5, 2003, however, the site remains viable as afuture generation development.

Ida-Westhad capitalized $11 million related to the Garnet project as of third quarter2002.  During fourth quarter 2002,Ida-West recorded an $8 million partial write-down of its investment inequipment for this project.  Thispartial write-down reflects the drop in prices for and increased availabilityof generating equipment due to the collapse of the merchant power plantdevelopment business.

**Integrated Resource Plan:**  Every two years, IPC is required to filewith the IPUC and OPUC an IRP, a comprehensive look at IPC's present and futuredemands for electricity and plans for meeting that demand.  The 2002 IRP identified the need foradditional resources to address potential electricity shortfalls within IPC'sutility service territory by mid-2005. The new resources expected to be in place at that time were thepreviously identified 250 MW power purchase from the Garnet project, anadditional 100 MW generation resource to be determined and a 100 MWtransmission upgrade to increase import capability.  These resources would be used to satisfy energy demand duringIPC's peak periods.  Prior to 2005, IPCwill continue to use purchases from the energy markets as necessary to meetshort-term energy needs.

TheIPUC Staff and several other interested parties filed comments responding toIPC's proposed 2002 IRP.  The commentsurge the IPUC not to acknowledge the IRP until (1) the Garnet issue isresolved, and (2) IPC provides additional detail on potential conservationmeasures that could be implemented.  IPCfiled reply comments on October 30, 2002 addressing those issues.  The above mentioned Garnet compliancereport, submitted to the IPUC on October 30, 2002, was included in those replycomments by reference.  On February 11,2003, the IPUC issued Order No. 29189, which accepted and acknowledged IPC's2002 IRP as modified and directed IPC to implement certain changes in its 2004IRP related to both the public process and the evaluation of demand-sideoptions.  The accepted IRP indicated thepurchase of 100 MW from the wholesale market for IPC's retail customers duringJune, July, November and December.  OnFebruary 24, 2003, IPC issued a formal Request for Proposals seeking bids forthe construction of up to 200 MW of additional generation to support thegrowing seasonal demand for electricity in IPC's service area.  Notice of an intent to bid must be submittedto IPC by March 14, 2003.

**CSPP Purchases:**  As a result of the enactment of the PURPA andthe adoption of avoided cost standards by the IPUC and OPUC, IPC has enteredinto contracts for the purchase of energy from private developers.  Because IPC's service territory encompassessubstantial irrigation canal development, forest product production facilities,mountain streams and food processing facilities, considerable amounts of energyare available from these sources.  Suchenergy comes from hydropower producers who own and operate small plants and fromcogenerators converting waste heat or steam from industrial processes intoelectricity.  IPC is currently purchasing energy from 67on-line CSPP facilities with contracts ranging from one to 30 years.  Under these contracts IPC is required topurchase all of the output from these facilities.  During 2002, IPC purchased 692,414 Megawatt hours (MWh)from these projects at a cost of $44 million, resulting in a blended price of6.3 cents per kilowatt hour.

In 2002, the IPUC issued various ordersimpacting the terms and conditions available for new CSPP projects.  Currently, new projects up to ten MW areeligible for Published Avoided Costs for up to a 20-year contract term.  IPC is required to negotiate PPAs with allqualifying CSPP projects greater than ten MW.

**Wholesale Power Sales:**  IPC has four firm wholesale power salescontracts and one wholesale contract for load following services.  These contracts are for various amounts ofenergy, up to 36 average MW, and are of various lengths expiring between 2003and 2005.  As these contracts expire, IPCwill use this power to meet its system requirements.

**Transmission Services:**IPC has along history of providing wholesale transmission service and provides various firmand non-firm wheeling services for several surrounding utilities.  IPC's system liesbetween and is interconnectedto the winter-peaking northern and summer-peakingsouthern regions of the western interconnected power system. Thisposition allows IPCto provide transmission services and reach abroad power sales market.

In December 1999, the FERC issued Order No.2000 encouraging companies with transmission assets to form RegionalTransmission Organizations (RTOs).  See"Competition - Wholesale" below.

**Fuel**IPC, through its subsidiary Idaho Energy Resources Co., owns aone-third interest in the Bridger Coal Company, which owns the Jim Bridger minesupplying coal to the Jim Bridger generating plant in Wyoming.  The mine, located near the Jim Bridgerplant, operates under a long-term sales agreement that provides for delivery ofcoal over a 51-year period ending in 2025. The Jim Bridger mine has sufficient reserves to provide coal deliveriesfor the term of the sales agreement. IPC also has a coal supply contract providing for annual deliveries ofcoal through 2009 from the Black Butte Coal Company's Black Butte and LeuciteHills mines located near the Jim Bridger plant.  This contract supplements the Bridger Coal Company deliveries andprovides another coal supply to operate the Jim Bridger plant.  The Jim Bridger plant's rail load-in facilityand unit coal train allows the plant to take advantage of potentiallylower-cost coal from outside mines for tonnage requirements above establishedcontract minimums.

SPPCo,with whom IPC is a joint (50/50) participant in the ownership and operation ofthe North Valmy Steam Electric Generating Plant (Valmy), has a long-term coalcontract with Southern Utah Fuel Company, a subsidiary of Canyon Fuel Co.,LLC.  This contract, which expires onJune 30, 2003, calls for the delivery of up to 17.5 million tons of low-sulfurcoal from a mine near Salina, Utah, for Valmy Unit No. 1.

SSPCo has signed an agreement with Arch CoalSales Company, Inc. to supply coal to the Valmy plant from 2002 through2006.  This agreement will provide fuelto the plant following the expiration of the above contract with Southern UtahFuel Company.  IPC is obligated topurchase one-half of the coal, ranging from approximately 515,000 tons to762,500 tons annually, under the Arch Coal Sales Company agreement.

**Water Rights**Except as discussed below, IPC has acquired valid water rights underapplicable state law for all waters used in its hydroelectric generatingfacilities.  In addition, IPC holdswater rights for domestic, irrigation, commercial and other necessary purposesrelated to other land and facility holdings within the state.  The exercise and use of all of these waterrights are subject to prior rights and, with respect to certain hydroelectricfacilities, IPC's water rights for power generation are subordinated to futureupstream diversions of water for irrigation and other recognized consumptiveuses.

Overtime, increased irrigation development and other consumptive diversions haveresulted in some 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 water rightsat 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 that 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 FPA.  The FERC entered an order implementing thelegislation on March 25, 1988.

Inaddition to providing for the protection of IPC's hydropower water rights, theSwan Falls agreement contemplated the initiation of a general adjudication ofall 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.  A commencement order initiatingthe Snake River Basin Adjudication was signed by the court on November 19,1987.  This legal proceeding wasauthorized by state statute based upon a determination by the Idaho Legislaturethat the effective management of the waters of the Snake River basin required acomprehensive determination of the nature, extent and priority of all wateruses within the basin.  The adjudicationis proceeding and is expected to continue for at least the next ten years.  IPC has filed claims to its water rightswithin the basin and is actively participating in the adjudication to ensurethat its water rights and the operation of its hydroelectric facilities are notadversely impacted.  IPC does not anticipateany modification of its water rights as a result of the adjudication process.

Seealso Item 2 - "Properties," and Part II, Item 7 - "MD&A -REGULATORY ISSUES - Relicensing of Hydroelectric Projects."

**EnvironmentalRegulation**Environmental regulation at the federal, state, regional and locallevels is having a continuing impact on IPC's operations due to the cost ofinstallation and operation of equipment and facilities required for compliancewith such regulations and the modification of system operations to accommodatesuch regulation.

Basedupon present environmental laws and regulations, IPC estimates its 2003 capitalexpenditures for environmental matters, excluding Allowance for Funds UsedDuring Construction (AFDC), will total $27 million.  Studies and measures related to environmental concerns at IPC'shydro facilities account for $23 million and investments in environmentalequipment and facilities at the thermal plants account for $4 million.  From 2004 through 2005,environmental-related capital expenditures, excluding AFDC, are estimated to be$32 million.  Anticipated expensesrelated to IPC's hydro facilities account for $25 million and thermal plantexpenses are expected to total $7 million.

IPC anticipates $12 million in annualoperating costs for environmental facilities during 2003.  Hydro facility expenses account for $8million of this total and $4 million is related to thermal plant operatingexpenses.  From 2004 through 2005, totalenvironmental related operating costs are estimated to be $25 million.  Anticipated expenses related to the hydrofacilities account for $17 million and thermal plant expenses are expected tototal $8 million during this period.

**Clean Air:**  IPC has analyzed the Clean Air Act legislation and its effectsupon IPC and its customers.  IPC'scoal-fired plants in Oregon and Nevada already meet the federal emission ratestandards for sulfur dioxide (SO2) and IPC's coal-fired plant inWyoming meets that state's even more stringent SO2 regulations.  IPC has sufficient SO2 allowancesto provide compliance for all three coal-fired facilities and its Danskinnatural gas-fired facility.  At the endof 2002, IPC had 59,000 allowances in excess of the amount needed for Clean AirAct compliance.  Currently, IPC has beengranted an annual allotment of allowances ranging from 15,524 to 72,713 through2032.  These amounts are in excess ofIPC's annual compliance requirements of 13,600.  Any excess allowances owned by IPC may be held for future use asthey do not expire.  Accordingly, IPCdoes not foresee any material adverse effects upon its operations with regardto SO2 emissions.

In July 1997, the Environmental ProtectionAgency (EPA) announced the National Ambient Air Quality Standards for ozone andParticulate Matter (PM) and in July 1999, announced regional haze regulationsfor protection of visibility in national parks and wilderness areas.  On May 14, 1999, a federal court rulingblocked implementation of these standards. In November 2000, the EPA appealed to the U.S. Supreme Court toreconsider that decision.  The SupremeCourt has ruled in favor of the EPA. The EPA has not yet implemented tighter regulations on PM, regional hazeor ozone.  It is anticipated that newregulations will be in place by 2005. The impacts of tighter ozone, PM and regional haze regulations on IPC'sthermal operations are not known at this time.

Valmy,Boardman and Jim Bridger Unit 4 elected to meet Phase I nitrogen oxide (NOx)limits beginning in 1998.  As a resultof this voluntary "early election" and pending current proposed legislation,these units will not be required to meet the more restrictive Phase II NOxlimits until 2008.  Had the units notvoluntarily "early elected," they would have been required to meetthe Phase II limits in 2000.  JimBridger Units 1, 2 and 3 were accepted as substitution units in 1995 and aresubject to NOx limits of Phase I instead of the more restrictivelimits of Phase II.  Jim Bridger hasinstalled low NOx equipment to reduce NOx levels evenlower than currently required.

The Danskin gas turbine plant in MountainHome, Idaho is operating in compliance with a "permit to construct"issued by the Idaho Department of Environmental Quality (DEQ).  IPC has applied for a Title V OperatingPermit from the Idaho DEQ expected during mid to late 2003.  The units are fitted with dry-low-NOxburners and a continuous emissions monitoring system.  This should ensure that the facility will operate within thepermitted federal and state NOx and carbon monoxide limits.

**Water:**  IPC has received National Pollutant Discharge Elimination SystemPermits, as required under the Federal Water Pollution Control Act Amendmentsof 1972, for the discharge of effluents from its hydroelectric generatingplants.

IPCagreed, in March 1976, to meet certain dissolved oxygen standards at itsAmerican Falls hydroelectric generating plant. IPC signed amendments to the agreements relating to the operation of theAmerican Falls Dam and the location of water quality monitoring facilities.  The amendments provide more accurate andreliable water quality measurements necessary to maintain water qualitystandards downstream from IPC's plant during the period from May 15 to October15 each year.

IPChas installed aeration equipment, water quality monitors and data processingequipment as part of the Cascade hydroelectric project to provide accuratewater quality data and increase dissolved oxygen levels as necessary tomaintain water quality standards on the Payette River.  IPC has also installed and operates waterquality monitors at the Milner, Shoshone Falls, Twin Falls, Upper Salmon, LowerSalmon and Bliss hydroelectric projects, in order to meet compliance standardsfor water quality.

IPC owns and financesthe operation of anadromous fish hatcheries and related facilities to mitigatethe 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, 2002, the investment inthese facilities was $10 million and the annual cost of operation pursuant toFERC License 1971 was $3 million.

**EndangeredSpecies: **Several species of fishand Snake River snails living within IPC's operating area are listed asthreatened or endangered.  IPC continuesto review and analyze the effect such designation has on its operations.  IPC is cooperating with various governmentalagencies to resolve issues related to these species.  See Part II, Item 7 - "MD&A - LEGAL AND ENVIRONMENTALISSUES - Environmental Issues."

**Hazardous/ToxicWastes and Substances: **Under theToxic Substances Control Act (TSCA), the EPA has adopted regulations governingthe use, storage, inspection and disposal of electrical equipment that containpolychlorinated biphenyls (PCBs).  Theregulations permit the continued use and servicing of certain electricalequipment (including transformers and capacitors) that contain PCBs.  IPC continues to meet all federalrequirements of the TSCA for the continued use of equipment containingPCBs.  IPC continues to eliminate PCBsas part of its long-term strategy.  Thisprogram will save costs associated with the long-term monitoring and testing ofequipment and grounds for PCB contamination as well as being good for theenvironment.  Total costs for theidentification and disposal of PCBs from IPC's system were less than $1 millionannually from 2000 to 2002.  IPCbelieves that all generation facilities are presently PCB-free.

**Competition****Retail:**  Electricutilities have historically been recognized as natural monopolies and haveoperated in a highly regulated environment in which they have an obligation toprovide electric service to their customers in return for an exclusivefranchise within their service territory with an opportunity to earn aregulated rate of return.

Somestate regulatory authorities are in the process of changing utility regulationsin response to federal and state statutory changes and evolving competitivemarkets.  These statutory changes andconforming regulations may result in increased retail competition.  In 1997, the Idaho Legislature appointed acommittee to study restructuring of the electric utility industry.  The committee has not recommended anyrestructuring legislation and is not expected to in the foreseeablefuture.  In 1999, the Oregon legislaturepassed legislation restructuring the electric utility industry, but exemptedIPC's service territory.

**Wholesale: **The 1992 National Energy Policy Act(Energy Act) and the FERC's rulemaking activities have established theregulatory framework to open the wholesale energy market to competition.  The Energy 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.  The Energy Act does not, however, permit the FERC to requiretransmission access to retail customers. Open-access transmission for wholesale customers provides energysuppliers with opportunities to sell and deliver electricity at market-basedprices.

In December 1999, the FERC,in its landmark Order No. 2000, said that all companies with transmission assets mustfile to form RTOs or explainwhy they cannot.  Order No.2000 is a follow up to Order Nos.888 and 889 issued in 1996,which required transmission owners to provide non-discriminatory transmissionservice to third parties.  Byencouraging the formation of RTOs, the FERC seeks to furtherfacilitate the formation of efficient,competitive wholesale electricity markets.

In October 2000 and March 2002, in responseto FERC Order No. 2000, IPC and other regional transmission owners filed Stage One and Stage Two plansto form RTO West, an entity thatwill operate the transmission grid in seven western states.  RTO West will have itsown independent governing board.  Theparticipating transmission owners will retain ownership of the lines, but willnot have a role in operating the grid.

These FERC filings represent a portion of the filings necessaryto form RTO West. However, substantialadditional filings will be necessary to include the tariff and integrationagreements associated with the new entity. State approvals also need to be obtained.  In September 2002, the FERC issued an order granting in part, RTOWest's Stage Two request for a declaratory order, approving with modification,the majority of the proposed plan for development of a RTO by ten utilities inthe northwest and Canada and the BPA. IPC is one of the filing utilities. With further development of detail and some modification, the FERCstated that the proposal "will satisfy not only the Order No. 2000requirements, but can also provide a basic framework for standard market designfor the west".  Further developmentof the RTO West proposal by the filing utilities continues.

In July 2002, the FERC issued a Notice ofProposed Rulemaking (NOPR) on Standard Market Design for regulatedutilities.  If implemented as proposed,the NOPR will substantially change how wholesale markets operate throughout theUnited States.  The proposed rulemakingexpands the FERC's intent to unbundle transmission operations from integratedutilities and ensure robust competition in wholesale markets.  The proposed rule contemplates that allwholesale and retail customers will be on a single network transmission servicetariff.  The proposed rule alsocontemplates the implementation of a bid-based system for buying and sellingenergy in wholesale markets to manage congestion.  The market would be administered by RTOs, or IndependentTransmission Providers.  RTOs would alsobe responsible for putting together regional plans that identify opportunitiesto construct new transmission, generation or demand-side programs to reducetransmission constraints and meet regional energy requirements.  Finally, the proposed rule envisions thedevelopment of regional market monitors responsible for ensuring thatindividual participants do not exercise unlawful market power.  Comments to the proposed rules were dueduring the last months of 2002 and additional comments are due the first partof 2003.  The FERC currently anticipatesthat the final rules will be in place in mid-2003 and the contemplated marketchanges will take place in 2003 and 2004.

**Utility Operating Statistics**The following table presents IPC's revenues and energy use for thelast three years:
|                             | **Years Ended December 31,** |
|----------------------------------|------------------------------|
|                             | **2002**                     |   | **2001** |   | **2000** |
|                             |
| Revenues (thousands of  dollars) |                         |   |   |   |   |   |   |   |
|                             | Residential                  | $ | 305,827 |   | $ | 260,251 |   | $ | 225,336 |
|                             | Commercial                   |   | 196,454 |   |   | 164,019 |   |   | 132,023 |
|                             | Industrial                   |   | 176,648 |   |   | 154,318 |   |   | 133,171 |
|                             | Irrigation                   |   | 93,106 |   |   | 72,020 |   |   | 74,827 |
|                             |                         | Total general business |   | 772,035 |   |   | 650,608 |   |   | 565,357 |
|                             | Off system sales             |   | 55,031 |   |   | 219,966 |   |   | 229,986 |
|                             | Other                        |   | 39,981 |   |   | 41,738 |   |   | 40,319 |
|                             |                         | Total | $ | 867,047 |   | $ | 912,312 |   | $ | 835,662 |
|                             |                         |   |   |   |   |   |   |   |   |
| Energy use (thousands of MWh)    |                         |   |   |   |   |   |   |   |
|                             | Residential                  |   | 4,387 |   |   | 4,307 |   |   | 4,393 |
|                             | Commercial                   |   | 3,460 |   |   | 3,380 |   |   | 3,404 |
|                             | Industrial                   |   | 3,226 |   |   | 3,925 |   |   | 4,808 |
|                             | Irrigation                   |   | 1,821 |   |   | 1,419 |   |   | 1,993 |
|                             |                         | Total general business |   | 12,894 |   |   | 13,031 |   |   | 14,598 |
|                             | Off system sales             |   | 2,069 |   |   | 2,387 |   |   | 4,529 |
|                             |                         | Total |   | 14,963 |   |   | 15,418 |   |   | 19,127 |
|                             |                         |   |   |   |   |   |   |   |   |

 

**ENERGY MARKETING:**

In January 1997, IPC began implementing astrategy to become a competitive energy provider throughout the westernmarkets.  In order to compete as anenergy provider of choice, IPC built a trading operation to participate in theelectricity, natural gas and other related markets.  In 1997, IPC developed natural gas trading operations that weretransferred to IE in 1999.  In June2001, IPC transferred its non-utility wholesale electricity marketingoperations to IE.  Over the last sixyears IDACORP, through IPC then through IE, marketed electricity and naturalgas, and offered risk management and asset optimization services to wholesalecustomers in 31 states and two Canadian provinces.

**Wind Down of Energy Marketing**IDACORP announced on June 21, 2002 that IE would wind down its powermarketing operations, stating that IE would not seek new electric customers;would limit its maximum value at risk to less than $3 million; would target areduction of working capital requirements to less than $100 million by the endof 2003; and would reduce its workforce at its Boise operations byapproximately 50 percent.  On November5, 2002, IDACORP announced that it was terminating further evaluation of growthopportunities in the mid-stream natural gas markets, and stated that IE wouldclose its Denver office by year-end 2002, and because of its link to thenatural gas platform, would shut down its natural gas trading operation inHouston by March 2003.  The announcementconcluded that IE's continued wind down of its energy marketing operationswould result in additional workforce reductions at IE's Boise operationsthrough mid-2003.  Since the June 21,2002 announcement, IE has reduced its workforce by over 60 percent and willcontinue to reduce its workforce as contractual obligations terminate.

See further discussion of energy marketingwind down in Part II, Item 7 - "MD&A - RESULTS OF OPERATIONS - EnergyMarketing" and Note 13 to the Consolidated Financial Statements and Note16 to the Consolidated Financial Statements of IPC.

**Risk Management**When buying and selling energy, the volatility of energy prices canhave a significant negative impact on profitability if not appropriatelymanaged.  Also, counterpartycreditworthiness is key to ensuring that transactions entered into canwithstand potentially dramatic market fluctuations.  To manage the risks inherent in the energy commodity industry,IE's Risk Management Committee (RMC), comprised of IDACORP and IE officers,oversees IE's risk management program as defined in the risk managementpolicy.  The program is intended tomanage the impact to earnings caused by the volatility of energy prices bymitigating commodity price risk, credit risk and other risks related to theenergy commodity business.

To manage the risks inherent in itsportfolio, IE has established risk limits. Market and credit risk is measured and reported daily to the members ofthe RMC.   Other tools used to managecredit risk are the holding of collateral in the form of cash or letters ofcredit and the use of margining agreements with counterparties when credit riskexceeds certain pre-determined thresholds. Because of the volatile nature of energy market prices, marginingagreements can require the posting of large amounts of cash betweencounterparties to hold as collateral against the value of the energycontracts.  This practice mitigatescredit risk but increases the need for cash or other liquid securities toensure the ability to meet all margin requirements when the markets are mostvolatile.

At year-end 2002, 63 percent of the creditexposure related to IE's unrealized positions was with investment gradecounterparties, two percent was with non-investment grade counterparties andthe remaining 35 percent was with non-rated counterparties.  The majority of the non-rated entities aremunicipalities, public utility districts and electric cooperatives.

See further discussion in Part II, Item 7A -"QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK."

**Supply**IE's supply of electricity and natural gas is purchased directly fromproducers, including IPC until August 2002, and other energy marketers. Salesof energy are made to other marketers, investor owned utilities, municipalitiesand cooperatives as well as large commercial and industrial customers inregions that allow retail customer choice. Approximately 72 percent of IE'smarketing and trading business in 2002 was with other marketing companies. Thisis an increase from 55 percent in 2001 due to the elimination of deal originationactivity as part of the wind down of the business.

**EnergyMarketing Operating Statistics**The following table presents IE's revenues and volumes (includingintersegment transactions) for the last three years:
|                                 | **Years Ended December 31,** |
|--------------------------------------|------------------------------|
|                                 |                         |   | **2002** |   | **2001** |   | **2000** |
|                                 |
| Net Revenues (thousands of  dollars) |                         |   |   |   |   |   |   |   |
|                                 | Electricity                  | $ | 42,304 |   | $ | 330,793 |   | $ | 182,326 |
|                                 | Gas                          |   | 4,106 |   |   | 17,870 |   |   | 7,790 |
|                                 |                         | Total | $ | 46,410 |   | $ | 348,663 |   | $ | 190,116 |
| Operating Volumes (settled)          |                         |   |   |   |   |   |   |   |
|                                 | Electricity (MWh)            |   | 39,526,630 |   |   | 34,936,951 |   |   | 23,518,484 |
|                                 | Gas (MMbtu)                  |   | 35,895,039 |   |   | 97,327,432 |   |   | 80,728,530 |
|                                 |                         |   |   |   |   |   |   |   |   |

 

**IDA-WEST:**

Ida-West develops, acquires, constructs,finances, owns and operates electric power generation facilities.  Ida-West has a 50 percent interest in nineoperating hydroelectric plants with a total generating capacity of 45 MW.

Ida-West had planned to develop the 273MWGarnet energy facility.  See discussionabove in "Power Supply - Garnet Power Purchase Agreement."

In 2001, the Friant Power Authority redeemedearly, bonds that represented Ida-West's investment in the Friant PowerProject, a 27.4 MW project located in California.  The Friant bonds were originally acquired in 1996.  Ida-West recorded a pre-tax gain of $5million on this transaction in 2001.

In 2000, Ida-West sold its interest in theHermiston Power project, a 536 MW gas-fired project near Hermiston,Oregon.  Ida-West was responsible formanaging all permitting and development activities relating to the projectsince its inception in 1993.  Ida-Westrecorded a pre-tax gain of $14 million on this transaction in 2000.

IPC has purchased all of the power generatedby Ida-West's four Idaho hydroelectric projects at a cost of $7 million in 2002and $6 million in 2001.

**IDATECH:**

IdaTech was originally founded in 1996 asNorthwest Power Systems, LLC to develop and bring fuel cell technology tomarket.  In April 1999, IDACORPpurchased a majority interest in IdaTech.

IdaTech is focused on the commercializationof fuel processor technology and integrated proton exchange membrane (PEM) fuelcell solutions.  IdaTech's productsunder development include fuel processors, integrated fuel cell systems andintegration and maintenance services.  IdaTech'sfuel processors are capable of operating on liquid and gaseous hydrocarbonfuels including natural gas, propane, liquified petroleum gas, diesel, methanoland kerosene.

IdaTech has integrated its multi-fuel fuelprocessors with a number of PEM fuel cell stacks into one to ten kilowatt (kW)fuel cell systems for stationary and portable electric power generation and hasdeveloped fully integrated systems with outputs ranging from one to five kW.

Currently, these systems are beingfield-tested and evaluated with various European utilities, the Japanesetrading company Tokyo Boeki, Ltd., the Propane Education and Research Counciland the U.S. Army Communications Electronics Command.

**IDACOMM AND VELOCITUS:**

InAugust 2000, IDACORP formed IDACOMM, Inc. and acquired Velocitus, Inc., aBoise, Idaho-based Internet service provider founded in 1992.  IDACOMM and Velocitus provide a wide rangeof integrated communication services to business and residential customers in28 markets across eight western states, Virginia and New York.

IDACOMM,a facility-based integrated communication provider, delivers high-speedconnectivity, using fiber optic network technology.  IDACOMM's technologies enable high-speed voice, Internet and datacommunications, including video conferencing, voice-over Internet protocol,off-site training and gigabit Ethernet service.  IDACOMM's customers include companies in industries suchas manufacturing, health care, food processing and retail as well as government entities and schooldistricts.  IDACOMM's metropolitan areanetwork in Idaho's Treasure Valley serves Boise, Meridian, Nampa and Caldwell.

Velocitusoperates as a Managed Service Provider by offering high-speed Internet access,Internet system support and other related services such as virtual privatenetworks, firewalls and web hosting to more than 25,000 customers.  Velocitus Internet serves the traditionalresidential and general consumer segment. Velocitus Broadband targets small tomedium size business clients with high-speed connectivity and securitysolutions, including fixed wireless technology.

**IDACORP FINANCIAL SERVICES, INC.:**

IFS invests primarily in affordable housingprojects, which provide a return principally by reducing federal and stateincome taxes through tax credits and tax depreciation benefits.  IFS's portfolio also includes historic rehabilitationprojects such as the El Cortez Hotel in San Diego, California and the EmpireBuilding in Boise.

IFS has focused on a diversified approach toits investment strategy in order to limit both geographic and operationalrisk.  Over 90 percent of IFS'sinvestments have been made through syndicated transactions.  At December 31, 2002, IFS's total portfolioexceeded $160 million in tax credit investments.  These investments cover 49 states, Puerto Rico and the U.S.Virgin Islands.  The underlying investmentsinclude over 700 individual properties, of which all but four are administeredthrough syndicated funds.

**RESEARCH AND DEVELOPMENT:**

In 2002, IdaTech spent approximately $7million for research and development of fuel cell technology.  IdaTech's research and development programis focused on the adaptation of its methanol fuel processor to operate on allcommercially important fuels, as well as the development of fully integratedfuel cell systems.  Highest priority isgiven to natural gas, liquified petroleum gas, propane, kerosene and dieselfuels.

IdaTech continues to pursue patentprotection of its technology in North America, Europe, South America, Asia andAustralia.  The patents issued toIdaTech address the design and operation of fuel reformers and two stagehydrogen purification devices based on a hydrogen selective metalmembrane.  Cost reduction throughimproved designs and reduced use of expensive materials are useful objectivesof these patents.  Additionally, onepatent issued to IdaTech in 2001 protects an optimized method for purginghydrogen from the anode compartment of a Proton Exchange Membrane Fuel Cell(PEMFC) stack so as to minimize the loss of hydrogen fuel without adverselyaffecting the electrical power output from the PEMFC stack.  IdaTech also received notice in 2002 fromthe U.S. Patent and Trademark Office (PTO) that the PTO has allowed all claimsof an IdaTech patent application for a metal alloy composition that yields adurable and economical membrane for hydrogen purification.  The broad patent will be issued in early2003.  Currently, 16 20-year U.S.patents have been issued to IdaTech. IdaTech also has more than 100 pending domestic and foreign patentapplications addressing various aspects of fuel processor and system design,operation, materials and integration with fuel cell stacks.  These patents will help IdaTech to bring itstechnology to commercialization.  Thepatents also provide the potential for licensing of IdaTech's technology in thefuture.

In 2002, IPC spent nearly $2 million topromote energy efficiency. Roughly two-thirds of these expenditures went tofund the Northwest Energy Efficiency Alliance, which strives to transform theregional marketplace through demonstration of innovative technologies, collaborationwith firms that market energy-saving products and services and training andinformation services. IPC's other energy-efficiency programs include compactfluorescent lighting, manufactured home performance testing and duct sealingand low-income weatherization assistance. Much of the funding for theseprograms came from the new Idaho tariff rider for demand-side managementprograms and from the conservation and renewables discount provided by the BPA.

**ITEM 2. PROPERTIES**

IPC's system includes 17 hydroelectricgenerating plants located in southern Idaho and eastern Oregon, one naturalgas-fired plant located in southern Idaho and interests in three coal-firedsteam electric generating plants.  Thesystem also includes approximately 4,657 miles of high voltage transmissionlines; 22 step-up transmission substations located at power plants; 18transmission substations; seven transmission switching stations; and 208energized distribution substations (excluding mobile substations and dispatchcenters).

IPCholds FERC licenses for its 13 hydroelectric projects.  These and the other generating stations andtheir capacities are listed below:

|  
 

**Estimated**

 

 

 

 

 
 

**Non-Coincident**

 

 

 

 

 
 

**Maximum**

 

**Nameplate**

 

 

 
 

**Operating**

 

**Capacity**

 

**License**

 
**Project**

**Capacity (kW)**

 

**(kW)**

 

**Expiration**

**Hydroelectric:**

 

 

 

 

 

 

 

Properties Subject to Federal Licenses:

 

 

 

 

 

 

 

Lower Salmon

70,000

 

60,000

 

1997

(a)

 

Bliss

80,000

 

75,000

 

1998

(a)

 

Upper Salmon

39,000

 

34,500

 

1999

(a)

 

Shoshone Falls

12,500

 

12,500

 

1999

(a)

 

CJ Strike

89,000

 

82,800

 

2000

(a)

 

Upper Malad

9,000

 

8,270

 

2004

 

 

Lower Malad

15,000

 

13,500

 

2004

 

 

Brownlee-Oxbow-Hells Canyon

1,398,000

 

1,166,900

 

2005

 

 

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

10,400

 

11,300

 

 

 

**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)

55,200

 

56,050

 

 

 

 

Danskin (gas-fired)

100,000

 

90,000

 

 

 

 

Salmon (diesel-internal combustion)

5,500

 

5,000

 

 

 

 

 

 

 

 

 

 

 

 

(a)  Renewed on a year-to-yearbasis; application for relicense is pending.(b)  IPC's ownership interests are 33percent for Jim Bridger, 50 percent for Valmy and 10 percent for Boardman.  Amounts shown represent IPC's share only.

At December 31, 2002, the composite averageages of the principal parts of IPC's system, based on dollar investment, were:production plant, 22 years; transmission system and substations, 20 years; anddistribution lines and substations, 16 years. IPC considers its properties to be well maintained and in good operatingcondition.

IPC owns in fee all of its principal plantsand other important units of real property, except for portions of certainprojects licensed under the FPA and reservoirs and other easements.  IPC's property is also subject to the lienof its Mortgage and Deed of Trust and the provisions of its projectlicenses.  In addition, IPC's propertyis subject to minor defects common to properties of such size and characterthat do not materially impair the value to, or the use by, IPC of suchproperties.

Idaho Energy Resources Co. owns a one-thirdinterest in certain coal leases near the Jim Bridger generating plant inWyoming from which coal is mined and supplied to the plant.

Ida-West holds investments in nine operatinghydroelectric plants with a total generating capacity of 45 MW.  These plants are located in Idaho and California.

**RELICENSING OF HYDROELECTRIC PROJECTS:**

IPC, like other utilities that operatenonfederal hydroelectric projects, obtains licenses for its hydroelectricprojects from the FERC.  These licensesgenerally last for 30 to 50 years depending on the size and complexity of theproject.  Currently, the licenses forfive hydro projects have expired.  Theseprojects continue to operate under annual licenses until the FERC issues a newpermanent license.  Three more hydroproject licenses will expire by 2010.

IPC is actively pursuing the relicensing ofthese projects, a process that may continue for the next ten to 15 years. IPChas filed applications seeking renewal of licenses for the Bliss, Upper SalmonFalls, Lower Salmon Falls, CJ Strike, Shoshone Falls and Upper and Lower MaladHydroelectric projects. The licenses for the Hells Canyon Complex (Brownlee,Oxbow and Hells Canyon) and the Swan Falls project expire in 2005 and 2010,respectively. IPC is currently engaged in procedures necessary to file timelylicense applications for these projects. Although various federal and staterequirements and issues must be resolved through the license renewal process,IPC anticipates that it will relicense each of the eight projects.

Final Environmental Impact Statements (EIS)have been issued for the Bliss, Upper Salmon Falls, Lower Salmon Falls andShoshone Falls projects.  New FERClicenses are anticipated in 2003.  Whilethe actual environmental costs of protection, mitigation and enhancement(PM&E) measures and other costs associated with the relicensing of theprojects will not be known until the new licenses are issued by the FERC, costsassociated with these licenses (assuming 30-year licenses) are expected tototal approximately $8 million during the first five years of the licenses and$28 million over the following 25 years.

A final EIS has been issued in October 2002for the CJ Strike project and a new FERC license is expected in 2003.  While the actual costs of PM&E measuresand other costs associated with the relicensing of the project will not beknown until the new license is issued by the FERC, costs associated with thelicense (assuming a 30-year license) are expected to total approximately $9million during the first five years of the license and $38 million over thefollowing 25 years.

The four Mid-Snake River projects, Bliss,Upper Salmon Falls, Lower Salmon Falls and Shoshone Falls, and the CJ Strikeprojects, may affect five species of snails listed under the Endangered SpeciesAct.  See discussion in the Part II,Item 7 - "MD&A - LEGAL AND ENVIRONMENTAL ISSUES - Environmental Issues- Threatened and Endangered Snails."

The Upper and Lower Malad project licenseexpires in July 2004 and the new license application was filed in July2002.  The application is proceedingthrough the normal FERC licensing process. The application includes proposed PM&E measures estimated to total(assuming a 30-year license) approximately $1 million during the first five yearsof the license and $3 million over the following 25 years.  However, the actual costs of PM&Emeasures and other costs associated with the relicensing of the project willnot be known until the new license is issued by the FERC.

The most significant relicensing effort isthe Hells Canyon Complex, which provides 68 percent of IPC's hydro generationcapacity and 40 percent of its total generating capacity.  IPC developed its draft license applicationwith the assistance of a collaborative team made up of individuals representingstate and federal agencies, businesses, environmental, tribal, customer, localgovernment and local landowner interests. The draft license application was issued in September 2002 and the finalapplication will be filed in July 2003. The draft application includes proposed PM&E measures estimated tototal approximately (assuming a 30-year license) $78 million during the firstfive years of the license and $100 million during the following 25 years.  However, the actual costs of PM&Emeasures and other costs associated with the relicensing of the project willnot be known until the new license is issued by the FERC.

At December 31, 2002, $50 million ofpre-relicensing costs were included in Construction Work in Progress (CWIP) and$6 million of pre-relicensing costs were included in Electric Plant inService.  The pre-relicensing costs arerecorded and held in CWIP until a new permanent license or annual license isissued by the FERC, at which time the charges are transferred to Electric Plantin Service.  Pre-relicensing costs aswell as costs related to the new licenses, as referenced above, will besubmitted to regulators for recovery through the rate-making process.

**ITEM 3.  LEGALPROCEEDINGS**

Reference is made to Note 8 to theConsolidated Financial Statements.

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

None

 

 

 

**EXECUTIVE OFFICERS OF THE REGISTRANTS**

Thenames, ages and positions of all of the executive officers of IDACORP, Inc. andIdaho Power Company are listed below along with their business experienceduring the past five years.  There areno family relationships among these officers, nor any arrangement orunderstanding between any officer and any other person pursuant to which theofficer was elected.

**IDACORP,Inc.**

**Name, Age and Position**

**Business Experience During Past Five  Years**

Jan  B. Packwood, 59  President and Chief Executive Officer

Appointed  May 30, 1999.  Mr. Packwood was  President and Chief Operating Officer from February 2, 1998 to May 30, 1999.

 

 

J.  LaMont Keen, 50  Executive Vice President

Appointed  March 1, 2002.  Mr. Keen was Senior  Vice President, Administration and Chief Financial Officer from May 5, 1999  to March 1, 2002, Senior Vice President-Administration, Chief Financial  Officer and Treasurer from March 15, 1999 to May 5, 1999 and Vice President,  Chief Financial Officer and Treasurer from February 2, 1998 to March 15,  1999.

 

 

**Richard  Riazzi, 48  Executive Vice President

Appointed  March 1, 2002.  Mr. Riazzi was Senior  Vice President, Generation and Marketing from March 15, 1999 to March 1,  2002, Vice President - Marketing and Sales from January 14, 1999 to March 15,  1999 and Vice President - Marketing and Sales for Idaho Power Company from  January 9, 1997 to March 15, 1999.

 

 

*Darrel  T. Anderson, 44  Vice President, Chief Financial Officer and Treasurer

Appointed  March 1, 2002.  Mr. Anderson was Vice  President, Finance and Treasurer from May 5, 1999 to March 1, 2002.

 

 

*Bryan  A. B. Kearney, 40  Vice President and Chief Information Officer

Appointed  March 15, 2001.

 

 

*Gregory  W. Panter, 54  Vice President - Public Affairs

Appointed  April 1, 2001.

 

 

*Robert  W. Stahman, 58  Vice President, General Counsel and Secretary

Appointed  February 2, 1998.

 

 

*Marlene  K. Williams, 50  Vice President - Human Resources

Appointed  March 1, 2002.

 

 

*TheseIDACORP, Inc. executive officers serve in the same capacities at Idaho PowerCompany.  For these officers' businessexperience during the past five years, please refer to the next table.

**Mr.Riazzi has resigned from IDACORP, Inc. effective March 31, 2003 as part of thecontinued wind down of IDACORP Energy.

**Idaho Power Company**

**Name,  Age and Position**

**Business  Experience During Past Five Years**

 

 

Jan B. Packwood, 59  Chief Executive Officer

Appointed March 1, 2002.  Mr. Packwood was President and Chief  Executive Officer from May 30, 1999 to March 1, 2002 and President and Chief  Operating Officer from September 1, 1997 to May 30, 1999.

 

 

J. LaMont Keen, 50  President and Chief Operating Officer

Appointed March 1, 2002.  Mr. Keen was Senior Vice  President-Administration and Chief Financial Officer from May 5, 1999 to  March 1, 2002, Senior Vice President-Administration, Chief Financial Officer  and Treasurer from March 15, 1999 to May 5, 1999 and Vice President, Chief  Financial Officer and Treasurer from March 14, 1996 to March 15, 1999.

 

 

James C. Miller, 48  Senior Vice President - Delivery

Appointed November 18, 1999.  Mr. Miller was Vice President - Generation  from July 10, 1997 to November 18, 1999.

 

 

Darrel T. Anderson, 44  Vice President, Chief Financial Officer and Treasurer

Appointed March 1, 2002.  Mr. Anderson was Vice President-Finance  and Treasurer from May 5, 1999 to March 1, 2002, Corporate Controller from  January 25, 1999 to May 5, 1999, Executive Vice President of Finance and  Operations at Applied Power Corp. from June 5, 1998 to January 25, 1999, and  Corporate Controller from February 26, 1996 to June 5, 1998.

 

 

John R. Gale, 52  Vice President, Regulatory Affairs

Appointed March 15, 2001.  Mr. Gale was General Manager of Pricing  & Regulatory Services from 1997 to 2001.

 

 

Bryan A.B. Kearney, 40  Vice President and Chief Information Officer

Appointed November 18, 1999.  Mr. Kearney was Vice President and Chief  Technology Officer at Bear Creek Corp from 1998 to1999 and Chief Information  Officer for Shasta County, California from 1996 to 1998.

 

 

Gregory W. Panter, 54  Vice President - Public Affairs

Appointed April 1, 2001.  Mr. Panter was self-employed with Panter  & Associates from 1989 to 2001.

 

 

John P. Prescott, 46  Vice President - Power Supply

Appointed November 18, 1999.  Mr. Prescott was Vice President of  Business Development for IDACORP Technologies, Inc. from August 1999 to  November 18, 1999, and President and Treasurer of Stellar Dynamics from  October 5, 1995 to August 1999.

 

 

Robert W. Stahman, 58  Vice President, General Counsel and Secretary

Appointed July 13, 1989.

 

 

Marlene K. Williams, 50  Vice President - Human Resources

Appointed May 5, 1999.  Ms. Williams was Director of Human  Resources at Arizona Public Service prior to May 5, 1999.

 

**PART II******

**ITEM 5.  MARKET FORTHE REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS******

IDACORP, Inc.'s(IDACORP) common stock (without par value) is traded on the New York StockExchange and the Pacific Exchange.  AtDecember 31, 2002, there were 20,088 holders of record and the year-end stockprice was $24.83 per share.

The outstandingshares of Idaho Power Company (IPC) common stock ($2.50 par value) are held byIDACORP and are not traded.  IDACORPbecame the holding company of IPC on October 1, 1998.

The followingtable shows the reported high and low sales price of IDACORP's common stock anddividends paid for the years 2002 and 2001 as reported in the consolidatedtransaction reporting system.

 

**2002 Quarters**

Common  Stock, without par value:

**1st**

 

**2nd**

 

**3rd**

 

**4th**

 

High

$40.86

 

$40.99

 

$28.60

 

$26.60

 

Low

37.26

 

25.71

 

21.58

 

20.87

 

Dividends  paid per share (cents)

46.5

 

46.5

 

46.5

 

46.5

 

 

 

 

 

 

 

 

 

 

**2001 Quarters**

Common  Stock, without par value:

**1st**

 

**2nd**

 

**3rd**

 

**4th**

 

High

$49.38

 

$41.10

 

$39.94

 

$41.14

 

Low

33.80

 

34.88

 

33.55

 

35.33

 

Dividends  paid per share (cents)

46.5

 

46.5

 

46.5

 

46.5

 

 

 

 

 

 

 

 

 

 

The amount and timing of dividends payable on IDACORP'scommon 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 financial position and results of operations, legislative andregulatory developments affecting the electric utility industry in general andIPC in particular, competitive conditions and any other factors the Board ofDirectors deems relevant.  The abilityof IDACORP to pay dividends on its common stock is dependent upon dividendspaid to it by its subsidiaries, primarily IPC.

IPC's articles of incorporation contain restrictions onthe payment of dividends on its common stock if preferred stock dividends arein arrears.  IPC paid dividends toIDACORP of $70 million annually in 2002, 2001 and 2000.

**ITEM 6.  SELECTEDFINANCIAL DATA**

**SUMMARY  OF OPERATIONS (thousands of dollars except for per share amounts)**

**IDACORP,  Inc.**

 

 

 

 

 

 

 

 

 

**For  the Years Ended December 31,**

**2002**

 

**2001**

 

**2000**

 

**1999**

 

**1998**

 

Operating  revenues

$

928,800

 

$

1,275,312

 

$

1,049,785

 

$

729,742

 

$

784,882

Operating  income

 

86,095

 

 

242,289

 

 

247,310

 

 

186,682

 

 

181,264

Net  income *

 

61,672

 

 

125,214

 

 

139,883

 

 

91,349

 

 

89,176

Earnings  per average share outstanding

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(basic  and diluted)

 

1.63

 

 

3.35

 

 

3.72

 

 

2.43

 

 

2.37

Dividends  declared per share

 

1.86

 

 

1.86

 

 

1.86

 

 

1.86

 

 

1.86

 

**At  December 31,**

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total  long-term debt**

 

898,676

 

 

842,481

 

 

864,114

 

 

821,558

 

 

815,937

Total  assets

 

3,252,638

 

 

3,642,314

 

 

4,039,706

 

 

2,640,371

 

 

2,456,819

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

*  See "Wind Down of Energy Marketing" in Note 13 to the Consolidated  Financial Statements.

**Excludes  amount due within one year.

 

 

The above datashould be read in conjunction with IDACORP's Consolidated Financial Statementsand Notes to Consolidated Financial Statements included in this Annual Reporton Form 10-K.

**SUMMARY  OF OPERATIONS (thousands of dollars)**

**IDAHO  POWER COMPANY**

 

 

 

 

 

 

 

 

 

**For  the Years Ended December 31,**

**2002**

 

**2001**

 

**2000**

 

**1999**

 

**1998**

 

Operating  revenues

$

867,047

 

$

912,312

 

$

835,662

 

$

658,336

 

$

756,410

Income  from operations

 

132,540

 

 

90,020

 

 

169,636

 

 

172,458

 

 

180,584

Income  from continuing

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

operations

 

88,920

 

 

28,295

 

 

79,968

 

 

83,465

 

 

90,743

Earnings  on common stock

 

84,333

 

 

72,838

 

 

131,559

 

 

91,956

 

 

90,261

 

**At  December 31,**

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total  long-term debt**

 

870,741

 

 

802,201

 

 

808,977

 

 

821,558

 

 

815,937

Total  assets **

 

2,738,493

 

 

2,859,704

 

 

2,617,092

 

 

2,559,374

 

 

2,421,790

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

**Utility  Customer Data:**

 

 

 

 

 

 

 

 

 

 

 

 

 

 

General  business customers

 

412,308

 

 

401,739

 

 

393,831

 

 

384,421

 

 

373,730

Average  kWh per customer

 

31,273

 

 

30,846

 

 

37,068

 

 

36,379

 

 

36,368

Average  rate per kWh (cents)

 

5.99

 

 

5.25

 

 

3.87

 

 

3.75

 

 

3.85

 

*Excludes  amount due within one year.

**1998-1999  include assets of discontinued operations.   See also Note 16 to the Consolidated Financial Statements of Idaho  Power 

 

Company.

 

The above data should be read inconjunction with Idaho Power Company's Consolidated Financial Statements andNotes to Consolidated Financial Statements included in this Annual Report onForm 10-K.

**ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OFFINANCIAL CONDITION AND RESULTS OF OPERATIONS**(Dollars in thousandsunless otherwise indicated.  Megawatthours (MWh) in thousands).

**INTRODUCTION:**

In Management's Discussion andAnalysis of Financial Condition and Results of Operations (MD&A), thegeneral financial condition and results of operations for IDACORP, Inc. andsubsidiaries (IDACORP) and Idaho Power Company and its subsidiary (IPC) arediscussed.  IDACORP is a holding companyformed in 1998 as the parent of IPC, IDACORP Energy (IE) and several otherentities.

IPC is an electric utility witha service territory covering over 20,000 square miles, primarily in southernIdaho and eastern Oregon.  IPC is the parentof Idaho Energy Resources Co., a joint venturer in Bridger Coal Company, whichsupplies coal to the Jim Bridger generating plant owned in part by IPC.

IDACORP announced in 2002 thatIE, a marketer of electricity and natural gas, would wind down its operations.

IDACORP's other significantoperating subsidiaries are:

Ida-West Energy(Ida-West) - developer and manager of independent power projects;

IdaTech -developer of integrated fuel cell systems;

IDACORPFinancial Services, Inc. (IFS) - affordable housing and other real estateinvestments;

Velocitus -commercial and residential Internet service provider; and

IDACOMM -provider of telecommunications services.

 

As you read the MD&A, it maybe helpful to refer to the Consolidated Financial Statements of IDACORP and IPCwhich present the financial position at December 31, 2002 and 2001, and theresults of operations and cash flows for each company for the years endedDecember 31, 2002, 2001 and 2000.

**FORWARD-LOOKING INFORMATION:**

In connectionwith the safe harbor provisions of the Private Securities Litigation Reform Actof 1995 (Reform Act), IDACORP and IPC are hereby filing cautionary statementsidentifying important factors that could cause actual results to differmaterially from those projected in forward-looking statements (as such term isdefined in the Reform Act) made by or on behalf of IDACORP or IPC in thisAnnual Report on Form 10-K, any Quarterly Report on Form 10-Q, inpresentations, in response to questions or otherwise.  Any statements that express, or involve discussions as toexpectations, beliefs, plans, objectives, assumptions or future events orperformance (often, but not always, through the use of words or phrases such as"anticipates," "believes," "estimates,""expects," "intends," "plans,""predicts," "projects," "will likely result,""will continue," or similar expressions) are not statements ofhistorical facts and may be forward-looking. Forward-looking statements involve estimates, assumptions, anduncertainties and are qualified in their entirety by reference to, and areaccompanied by, the following important factors, which are difficult topredict, contain uncertainties, are beyond our control and may cause actualresults to differ materially from those contained in forward-lookingstatements:

changes ingovernmental policies and regulatory actions, including those of the FederalEnergy Regulatory Commission (FERC), the Idaho Public Utilities Commission(IPUC) and the Oregon Public Utility Commission (OPUC), with respect to allowedrates of return, industry and rate structure, acquisition and disposal ofassets and facilities, operation and construction of plant facilities, recoveryof purchased power and other capital investments, and present or prospectivewholesale and retail competition (including but not limited to retail wheelingand transmission costs) and other refund proceedings;

litigationresulting from the energy situation in the western United States;

economic,geographic and political factors and risks;

changes inand compliance with environmental and safety laws and policies;

weathervariations affecting customer energy usage;

operatingperformance of plants and other facilities;

changes inenvironmental conditions and requirements;

systemconditions and operating costs;

populationgrowth rates and demographic patterns;

pricing andtransportation of commodities;

marketdemand and prices for energy, including structural market changes;

changes incapacity and fuel availability and prices;

changes intax rates or policies, interest rates or rates of inflation;

changes inactuarial assumptions;

adoption orchanges in critical accounting policies or estimates;

exposure tooperational, market and credit risk in energy trading and marketing operations;

changes inoperating expenses and capital expenditures;

capitalmarket conditions;

rating actionsby Moody's, Standard & Poor's (S&P) and Fitch;

competitionfor new energy development opportunities;

results offinancing efforts, including the ability to obtain financing on favorableterms, which can be affected by various factors, including credit ratings andgeneral economic conditions;

naturaldisasters, acts of war or terrorism;

legal andadministrative proceedings (whether civil or criminal) and settlements thatinfluence business and profitability; and

new accountingor Securities and Exchange Commission requirements, or new interpretation orapplication of existing requirements.

 

Any forward-looking statementspeaks only as of the date on which such statement is made.  New factors emerge from time to time and itis not possible for management to predict all such factors, nor can it assessthe impact of any such factor on the business or the extent to which anyfactor, or combination of factors, may cause results to differ materially fromthose contained in any forward-looking statement.

**RISK FACTORS:**

The following are some importantfactors that could have a significant impact on the operations and financialresults of IDACORP and IPC and could cause actual results or outcomes to differmaterially from those discussed in any forward-looking statements:

**IPC has a predominately hydroelectricgenerating base.** Because of itsheavy reliance on inexpensive hydroelectric generation, IPC's operations can besignificantly affected by the weather. IPC is currently forecasting that the year 2003 will be its fourthconsecutive year of below normal water conditions.  When hydroelectric generation is reduced because of below normalwater conditions, IPC must increase its use of more expensive thermalgeneration and purchased power. Although IPC generally recovers certain increased power costs throughits Power Cost Adjustment (PCA), the recovery is on a deferred basis and issubject to the regulatory process.

**IPC is currently involved in renewingfederal licenses for certain of its hydroelectric projects.**  IPC currently expects new licenses for fivemiddle Snake River region hydroelectric plants to be issued in 2003.  In addition, IPC expects to file the licenseapplication in July 2003 for the Hells Canyon Complex, which provides 40percent of IPC's total generating capacity. IPC cannot predict what conditions, if any, with respect toenvironmental, operating and other matters the FERC may impose in connectionwith the renewal of these licenses and the effect of any such conditions onIPC's operations.

**IDACORP and IPC are subject to extensivefederal, state and local environmental statutes, rules and regulations relatingto air quality, water quality, natural resources and health and safety.**  There are significant capital, operating andother costs associated with compliance with these environmental statutes, rulesand regulations, and those costs could be even more significant in the futureas a result of, among other factors, changes in legislation and enforcementpolicies and additional requirements imposed in connection with the relicensingof IPC's hydroelectric projects.

**IPC currently anticipates filing a generalrate case with the IPUC by the end of the year 2003.** The rate case is being filed as a result ofcapital expenditures made and increased operating costs experienced by IPCsince 1993, the last rate case test year except for those capital costsassociated with construction of the Milner and expansion of the Twin Fallshydroelectric projects which were included in rates in 1995.  IPC cannot predict the outcome of this caseor the effect on its operations if the requested rate relief is not granted.

**IDACORP and IPC are subject to direct andindirect effects of terrorist threats and activities.** Generation andtransmission facilities, in general, have been identified as potential targets.The effects of terrorist threats and activities include, among other things,actions or responses to such actions or threats, the inability to generate,purchase or transmit power, and the increased cost and adequacy of security andinsurance.

**IPC and its affiliate, IE, may be subjectto potential liabilities as a result of energy marketing operations.**  Although IE is currently winding down itsenergy marketing operations, certain matters have been identified that requireresolution with the FERC and the IPUC. Should the FERC conclude that itsregulations or rate schedules were not complied with, it has significantdiscretion as to the appropriate remedies, if any.  The FERC's remedial authority includes the authority to requirerefunds, to order equitable relief, to suspend the authorization to sellwholesale power at market-based rates, and, in some instances, to imposemonetary penalties. In an IPUC proceeding that has been underway since May2001, IPC and the IPUC staff have been working to determine the appropriatecompensation IE should provide to IPC as a result of transactions between theaffiliates since February 2001.  IPC andIE do not believe that resolution of these transactions will have any adverseimpact on retail customers or a material adverse effect on their ongoingoperations.  However, because it cannotbe predicted at this point what regulatory actions might be taken or when, itcannot be determined what effect there may be on the companies' financialstatements and whether it will be material.

**IDACORP, IE and IPC are subject to costsand other effects of legal and administrative proceedings, settlements,investigations and claims, including those that may arise out of the Californiaenergy situation.**  Regarding the California energy situation,IDACORP, IE and IPC are involved in a number of proceedings including acomplaint filed against sellers of power in California, based on California'sunfair competition law, a cross-action wholesale electric antitrust caseagainst various sellers and generators of power in California and theCalifornia refund proceeding at the FERC. Other cases which are the direct or indirect result of the energy crisisin California include efforts by certain public parties to reform or terminatecontracts for the purchase of power from IE and the Northwest refund case atthe FERC.  It is possible that additionalproceedings may be filed against or by IDACORP, IE or IPC related to theCalifornia energy crisis in the future.

**IDACORP and IPC rely on access to capitalmarkets as a significant source of liquidity for capital requirements notsatisfied by operating cash flows. **Accessto capital markets at a reasonable cost is determined in large part by creditquality.  An inability to raise capitalon favorable terms, particularly during times of uncertainty in the capitalmarkets, could impact the liquidity of IDACORP and IPC and would likely increasetheir interest costs.  It could alsoaffect the companies' ability to implement their business plans.

The issues and associated risksand uncertainties described above are not the only ones IDACORP and IPC mayface. Additional issues may arise or become material. The risks anduncertainties associated with these additional issues could impair IDACORP'sand IPC's businesses in the future.

**SUMMARY OF 2002 RESULTS AND 2003OUTLOOK:**

**Overall Results**IDACORP's overall results show earnings per share (EPS) of $1.63, adecrease of $1.72 from 2001.  IPC's EPSincreased from $0.60 in 2001 to $2.24 in 2002 despite the operational impactsof continued below normal streamflow conditions on IPC's hydro system andreduced general business sales.  At IE,EPS decreased significantly from $2.87 in 2001 to a current year loss of$0.39.  IE's results have beensignificantly impacted by deteriorating credit, substantially reduced pricingspreads, and low volatility in the Western wholesale energy markets as well asthe decision to wind down energy marketing operations.  IDACORP's results also reflect an $8 millionpartial write-down of Ida-West's investment in equipment related to theproposed Garnet energy project.

Since the announcement to winddown its energy marketing operations, IE has recorded $9 million in severanceexpenses, non-cancelable lease liabilities and asset impairments, among othermatters.  IE has reduced its workforcefrom a peak last year of 125 to fewer than 60 employees as of December 31,2002.  Further reductions in theworkforce to approximately 20 employees are expected by July 2003.

Utility operations benefited from a tax accounting methodchange that allowed IPC to record a $35 million tax benefit.  $31 million of this benefit is attributableto 2001 and prior years.

This benefit was partially offset by expensing $12 millionin lost irrigation revenues disallowed by the IPUC.  IPC disagrees with the IPUC's decision to disallow recovery ofthe $12 million in lost irrigation revenues and has filed an appeal with theIdaho Supreme Court seeking to overturn the IPUC's decision.  IPC filed its brief on January 31,2003.  It is anticipated that this casewill not be decided by the Idaho Supreme Court until late 2003 or early2004.  If successful, IPC would recordany amount recovered as revenue.

**HydroelectricGeneration and Below Normal Water Conditions**The following table presents IPC's system generation for the lastthree years:

 

**MWh**

 

**Percent of total generation**

 

**2002**

 

**2001**

 

**2000**

 

**2002**

 

**2001**

 

**2000**

 

 

 

 

 

 

 

 

 

 

 

 

Hydroelectric

6,069

 

5,638

 

8,500

 

45%

 

43%

 

52%

Thermal

7,286

 

7,622

 

7,701

 

55   

 

57   

 

48   

 

Total  system generation

13,355

 

13,260

 

16,201

 

100%

 

100%

 

100%

 

 

 

 

 

 

 

 

 

 

 

 

 

IPC relies on low-costhydroelectric plants for a significant portion of its power supply.  IPC's hydroelectric generation has decreasedsince 2000 as IPC has experienced three years of below normal waterconditions.  Under normal streamflowconditions, IPC's generation mix is 57 percent hydro and 43 percentthermal.  The amount of electricity IPCis able to generate from its hydro plants depends primarily on the snowpack inthe mountains above its hydro facilities, reservoir storage and streamflowconditions.

Current Snake River basin snowpack numbers suggest that streamflowconditions for 2003 will remain below normal. IPC's March 2003 accumulations were 78 percent of normal, compared to 85percent at the same time a year earlier.

The U.S. Weather Service's River Forecast Center at thistime is predicting April-through-July inflow into Brownlee Reservoir will be3.7 million acre-feet (maf).  The normal30-year average for inflow during that time is 6.3 maf.  Based on the above snowpack and forecastedinflows, IPC is expecting its fourth year of below normal water conditions.  IPC currently plans to use wholesalepurchases from the energy markets when necessary to meet its energy needsduring 2003.

**Integrated Resource Plan**On February 11, 2003, theIPUC issued Order No. 28189 that accepted and acknowledged IPC's 2002 IntegratedResource Plan (IRP), which identified IPC's options to meet potentialelectricity shortfalls expected by mid-2005. The accepted IRP indicated the purchase of 100 MW from the wholesalemarket for IPC's retail customers during June, July, November and December -the months when it is difficult for IPC to generate enough electricity to meetits customer needs.  Other optionsidentified by IPC include:

Seasonal energy exchanges withother utilities;

Obtaining firm transmission rights;

Construction of new generatingresources; and

Purchasing capacity from newgenerating resources.

 

On February 24, 2003, IPC issued a formal Request forProposals (RFP) seeking bids for the construction of up to 200 MW of additionalgeneration to support the growing seasonal demand for electricity in IPC'sservice area.  Notice of an intent tobid must be submitted to IPC by March 14, 2003.

**Power Cost Adjustment and GeneralRate Relief**At December 31, 2002, the PCA deferral balance has decreased by $164million from December 31, 2001.  Thisdecrease is attributable to a 75 percent decline in the price of wholesaleelectricity purchased power costs.  Whenthe new PCA year starts in May 2003, IPC expects that retail rates for mostcustomer categories in Idaho will decrease.

The amount of PCA costs not recovered through the PCAmechanism was approximately $25 million in 2002 compared to approximately $76million in 2001. With more normal market prices and water conditions, IPC wouldabsorb lesser or no amounts.

While the PCA has been a valuable tool for IPC during theenergy crisis and increased power supply costs in 2000 and 2001, it has notprovided revenue recovery related to IPC's other costs of serving its customerssuch as increased operating expenses and substantial demands for infrastructureimprovements.  Additionally, IPC isexpecting increased capital costs for the protection, mitigation andenhancement requirements of new licenses for some of its hydroelectricprojects, its need for new sources of power supply and the need to continue theexpansion of its transmission and distribution network.

As a result of the items mentioned above, IPC anticipatesfiling a general rate case with the IPUC before year-end 2003.  This will be IPC's first general rate casefiling since 1994.  IPC anticipates therequest for an increase will be substantially less than the expectedPCA-related rate decrease expected in May 2003.

**Legal Issues and RegulatoryMatters**IDACORP, IPC and IE have been named as defendants in various legalcases during 2002.  These cases continueto be reviewed on an ongoing basis.  Atthis time, the companies believe they have meritorious defenses to all lawsuitsand legal proceedings and are making a continuous effort for resolution of alloutstanding matters.  At the time ofthis filing, the companies have settled legal proceedings with Truckee-DonnerPublic Utility District (Truckee) without material adverse effect on theirconsolidated financial positions, results of operations or cash flows.  The case filed by the Public UtilityDistrict No. 1 of Grays Harbor County, Washington (Grays Harbor) was dismissedwith prejudice on January 28, 2003.

IE and IPC voluntarily contactedthe FERC in September 2002 to discuss certain matters that needed to beresolved in connection with the wind down of energy marketing at IE, and thecompanies have provided certain documents and information to the FERC at itsrequest.  On February 26, 2003, the FERCresolved one of the matters, approving the assignment of certain wholesalepower and transmission services agreements from IPC to IE.

**Liquidity**IDACORP and IPC's operating cash flows in 2002 were $348 million and$366 million, respectively, driven by collections of outstanding PCA amounts,reduced power supply costs and the receipt of tax refunds.  The increased cash flows were used to paydown short-term debt and redeem IPC's auction rate preferred stock.

Operating cash flow for 2003 will be supported by ongoingcollections of past PCA deferrals and continued cash collections during thewind down of the energy marketing business. IDACORP has budgeted approximately $162 million for capital expendituresin 2003 of which $150 million will be for capital expenditures at IPC.  Approximately 60 percent of the budgetedamounts at IPC are dedicated to its delivery system, 30 percent is for supportof its power supply and relicensing efforts and 10 percent is for general plantand administrative expenditures.

Pension expense is expected to increase from approximately$0 in 2002 to approximately $7 million in 2003.  Of this amount, approximately 70-75 percent will impact IPC'soperation and maintenance expense.  Atthe end of 2002, the projected benefit obligation exceeded pension assets byapproximately $12 million.  Based oncurrent estimates, cash contributions in 2003 are not expected.

IDACORP has committed to continue to reduce its reliance onshort-term borrowings during 2003. IDACORP is reviewing options that may include refinancing debt at IFSand IPC.

IDACORP and IPC have credit facilities that expire in March2003.  Accordingly, both companiesexpect to have renewed these facilities by the end of first quarter 2003.

The amount and timing of dividends payable on IDACORP'scommon 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 financial position and results of operations, legislative andregulatory developments affecting the electric utility industry in general andIPC in particular, competitive conditions and any other factors the Board ofDirectors deems relevant.  The abilityof IDACORP to pay dividends on its common stock is dependent upon dividendspaid to it by its subsidiaries, primarily IPC.

IPC's articles of incorporationcontain restrictions on the payment of dividends on its common stock ifpreferred stock dividends are in arrears. IPC paid dividends to IDACORP of $70 million annually in 2002, 2001 and2000.

**Financing Activities**During the fourth quarter of 2002, IPC issued $200 million of FirstMortgage Bonds in two series.  Theproceeds were used to pay down short-term debt at IPC.

IPC is in the process of establishing a $300 million shelfregistration to facilitate future financing needs.

At this time IDACORP does notanticipate issuing equity securities during the balance of 2003 other thanthrough the normal course of its various stock plans.

**CRITICAL ACCOUNTING POLICIES:**

IDACORP and IPC's discussion andanalysis of their financial condition and results of operations are based upontheir consolidated financial statements, which have been prepared in accordancewith accounting principles generally accepted in the United States ofAmerica.  The preparation of thesefinancial statements requires IDACORP and IPC to make estimates and judgmentsthat affect the reported amounts of assets, liabilities, revenues and expenses,and related disclosure of contingent assets and liabilities.  On an ongoing basis, IDACORP and IPCevaluate these estimates, including those related to rate regulation,mark-to-market accounting on energy trading contracts, contingencies,litigation, income taxes, restructuring costs, benefit costs and baddebts.  These estimates are based onhistorical experience and on various other assumptions and factors that arebelieved to be reasonable under the circumstances, and are the basis for makingjudgments about the carrying values of assets and liabilities that are notreadily apparent from other sources. IDACORP and IPC, based on their ongoing reviews, will make adjustmentswhen facts and circumstances dictate.

IDACORP and IPC believe the following critical accountingpolicies are important to the portrayal of their financial condition andresults of operations and require management's most difficult, subjective orcomplex judgments, often as a result of the need to make estimates about theeffect of matters that are inherently uncertain.

**Accounting for Rate Regulation******A regulated company must satisfy the following conditions in orderto apply the accounting policies and practices of Statement of FinancialAccounting Standards (SFAS) 71, "Accounting for the Effects of CertainTypes of Regulation," an independent regulator must set rates; theregulator must set the rates to cover specific costs of delivering service; andthe service territory must lack competitive pressures to reduce rates below therates set by the regulator. SFAS 71 requires companies that meet the aboveconditions to reflect the impact of regulatory decisions in its consolidatedfinancial statements and requires that certain costs be deferred as regulatoryassets until matching revenues can be recognized. Similarly, certain items maybe deferred as regulatory liabilities and amortized to the income statement asrates to customers are reduced.

IPC follows SFAS 71, and its financial statements reflectthe effects of the different rate making principles followed by the variousjurisdictions regulating IPC.  Theprimary result of this policy is that IPC has deferred $499 million ofregulatory assets and $114 million of regulatory liabilities at December 31,2002.  While IPC expects to fullyrecover these regulatory assets or return these regulatory liabilities, suchrecovery is subject to final review by the regulatory entities.

If IPC should determine in the future that it no longermeets the criteria for continued application of SFAS 71, it could be requiredto write off its regulatory assets and liabilities unless regulators specifysome other means of recovery or refund. IPC intends to seek recovery of all ofits prudent costs, including stranded costs, in the event of deregulation.However, due to the current lack of definitive legislation, IPC cannot predictwhether it will be successful.

**Mark-to-Market Accounting for Energy Marketing Contracts******IE values its energy trading contracts using mark-to-marketaccounting under SFAS 133, "Accounting for Derivative Instruments andHedging Activities," and Emerging Issues Task Force (EITF) Issue No. 98-10,"Accounting for Contracts Involved in Energy Trading and Risk ManagementActivities."  This accountingrequires IE to consider several factors, including current relevant marketprices, market depth and liquidity, potential model error, and expected creditlosses at the counterparty level.  Dueto the volatility of energy markets and certain model assumptions, changes inmarket conditions could substantially change the amounts of gains or lossesultimately realized in settlement of the contracts.

Marking acontract to market consists of reevaluating the market value of the entire termof the contract at each reporting period and reflecting the resulting gain orloss of value in earnings for the period. This change in value represents thedifference between the contract price and the current market value of thecontract. The change in market value of the contract could result in largegains or losses recorded in earnings at each subsequent reporting period unlessthere are off-setting changes in value of off-setting contracts. The gain orloss in income generated from the change in market value of the energy tradingcontracts is a non-cash event.   Ifthese contracts are held to maturity, the cash flow from the contracts, andtheir off-setting contracts, is realized over the life of the contract.

When determiningthe fair value of marketing and trading contracts, IE uses actively quotedprices for contracts with similar terms as the quoted price, including specificdelivery points and maturities. To determine fair value of contracts with termsthat are not consistent with actively quoted prices, IE uses (when available)prices provided by other external sources. When prices from external sourcesare not available, IE determines prices by using internal pricing models thatincorporate available current and historical pricing information. Finally, thefair market value of contracts is adjusted for the impact of market depth andliquidity, potential model error, and expected credit losses at thecounterparty level.The following table details the gross margin booked from marketing operationsover the last three years:

 

**2002**

 

**2001**

 

**2000**

Gross Margin:

 

 

 

 

 

 

 

 

 

Realized or otherwise  settled

$

70,262 

 

$

149,956

 

$

180,196 

 

Unrealized

 

(65,965)

 

 

92,803

 

 

(34,865)

 

 

Total gross margin

$

4,297 

 

$

242,759

 

$

145,331 

 

 

 

 

 

 

 

 

 

 

At year-end 2002, 63 percent ofthe credit exposure related to IE's unrealized positions was with investmentgrade counterparties, two percent was with non-investment grade counterparties andthe remaining 35 percent was with non-rated counterparties.  The majority of the non-rated entities aremunicipalities, public utility districts and electric cooperatives.

The change in netfair value (energy marketing assets less energy marketing liabilities) betweenyear-end 2001 and year-end 2002 is explained as follows:

Net fair value of contracts  outstanding as of 12/31/2001

$

136,430 

Contracts realized or  otherwise settled during the period

 

(70,262)

Changes in net fair values  attributable to changes in valuation techniques and assumptions

 

2,068 

Changes in net fair value  attributable to market prices and other market changes

 

(30,043)

 

Net fair value of contracts  outstanding as of 12/31/2002

$

38,193 

 

 

 

 

The fair value of energy marketingand trading contracts is an accounting estimate based on reasonable assumptionsrelated to interest rates, energy prices and price volatility.  Different assumptions regarding thesevariables could result in a change to the net fair value of energy marketingand trading contracts.  The followingtable shows the estimated adverse change to the reported fair value of energymarketing and trading contracts for defined adverse moves associated with thekey assumptions incorporated into this estimate:

 

**Adverse  move**

 

**in  fair value**

**Change in assumption used  in fair value calculation**

 

 

 

 

1% change in interest rates

$

1,349

$1/MWh change in  electricity prices

$

681

$0.50/MMBtu change in gas  prices

$

1

1% change in volatility

$

208

 

 

 

 

The followingtable presents the net fair value of contracts outstanding at December 31,2002, disaggregated by source of fair value and maturity of contracts:

 

**Maturity**

 

 

 

 

 

**Maturity**

 

 

 

**less  than**

 

**Maturity**

 

**Maturity**

 

**in  excess of**

 

 

**Source of Fair Value**

**1  year**

 

**1-3  years**

 

**4-5  years**

 

**5  years**

 

**Total**

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Prices actively quoted

$

13,755 

 

$

18,138

 

$

(624)

 

$

-

 

$

31,269

Prices provided by other

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

external sources

 

7,157 

 

 

7,930

 

 

(10,816)

 

 

1,830 

 

 

6,101

Prices based on models

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

and other valuation

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

methods

 

(1,293)

 

 

1,263

 

 

853 

 

 

- 

 

 

823

 

 

Total

$

19,619 

 

$

27,331

 

$

(10,587)

 

$

1,830 

 

$

38,193

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Prices activelyquoted are quoted daily by brokers and trading exchanges such as NYMEX, TFS,Intercontinental and Bloomberg. The time horizon is January 2003 throughDecember 2007. Products include physical, financial, swap, interest rate, indexand basis for both natural gas and heavy load power.

Prices providedby other external sources are quoted periodically by brokers and tradingexchanges such as TFS, APB, Prebon, Intercontinental and Bloomberg. The timehorizon is January 2003 through December 2010. Products include physical, financial, swap, index and basis for bothnatural gas and heavy and light load power.

Prices derivedfrom models and other valuation methods incorporate available current andhistorical pricing information. The time horizon is January 2003 throughDecember 2007.  Products includetransmission, options, and ancillary services related to heavy and light loadpower.

**Pension Expense******IPC maintains a qualified defined benefit pension plan (QualifiedPlan) covering most employees and an unfunded nonqualified deferredcompensation plan for certain senior management employees and directors.  Pension income (expense) for these planstotaled ($4 million), $4 million and $7 million for the three years endedDecember 31, 2002, 2001 and 2000, respectively, including amounts allocated tocapitalized labor costs.

Pension expense is dependent onseveral assumptions used in the actuarial valuation of the plan.  The primary assumptions are the long-termreturn on plan assets and the discount rate. Annually, these assumptions are reviewed in light of changes in marketconditions, trends, and future expectations. These assumptions and the results of actuarial valuations are discussedin Note 10 to the Consolidated Financial Statements.

If these assumptions had beendifferent, the net amounts of pension expense recorded could have varied significantly.  Lowering theexpected long-term rate of return on the Qualified Plan assets by 0.5 percent(from 9.0 percent to 8.5 percent) would have increased pension expense for 2002by approximately $1.6 million. Lowering the discount rate by 0.5 percent wouldhave increased pension expense for 2002 by approximately $1.5 million.

Thevalue of the Qualified Plan assets has decreased from $326 million at December31, 2001 to $283 million at December 31, 2002. The investment performancereturns and declining discount rates have changed the funded status of theQualified Plan, net of benefit obligations, from being overfunded by $53million at December 31, 2001 to being underfunded by $12 million at December31, 2002. Despite the recent reductions in the funded status of the QualifiedPlan, IPC believes that, based on current actuarial assumptions, it will not berequired to make any cash contributions to the Qualified Plan in 2003.

**Contingent Liabilities******A number of unresolved issues related to regulatory, legal and taxmatters are discussed throughout the MD&A. Contingent liabilities are provided for in accordance with SFAS 5,"Accounting for Contingencies." According to SFAS 5, an estimatedloss from a loss contingency shall be charged to income if (a) it is probablethat an asset had been impaired or a liability had been incurred at the date ofthe financial statements and (b) the amount of the loss can be reasonablyestimated. Disclosure in the notes to the financial statements is required forloss contingencies not meeting both those conditions if there is a reasonablepossibility that a loss may have been incurred. Gain contingencies are notrecorded until earned.

For all such significant matters, best estimates of theultimate resolution have been made, and, if the recognition criteria of SFAS 5have been met, reserves have been recorded. The final outcome of these matters could vary significantly from theamounts that have been included in the current financial statements.

**RESULTS OF OPERATIONS:**

In this sectionIDACORP's earnings and the factors that affected them are discussed, beginningwith a general overview followed by a more detailed discussion of the electricutility and energy marketing activities for the years ended December 31, 2002,2001 and 2000.

**Earnings  per share of common stock**

 

 

 

 

 

 

 

 

 

**2002**

 

**2001**

 

**2000**

Utility  operations

$

2.24 

 

$

0.60   

 

$

1.97   

Energy  marketing

 

(0.39)

 

 

2.87   

 

 

1.58   

Other  operations

 

(0.22)

 

 

(0.12)  

 

 

0.17   

 

Total  earnings per share

$

1.63 

 

$

3.35   

 

$

3.72   

 

**Return  on year end common equity**

 

7.0%

 

 

14.4%

 

 

17.0%

 

 

 

 

 

 

 

 

 

 

EPS from utility operationsincreased for the year ended December 31, 2002.  Major changes occurring at the utility caused the followingfluctuations in EPS:

Net power supplycosts absorbed by the utility decreased $51 million, increasing EPS $0.82.

A change to theutility's tax accounting method for capitalized overhead costs created a taxbenefit of $35 million or a $0.92 increase to EPS.

Lost revenue of$12 million was expensed during third quarter 2002, after the utility wasdenied its request to recover lost revenue from the 2001 Irrigation LoadReduction Program.  This amount comparesto $10 million in disallowed PCA costs expensed during 2001. 

High wholesaleenergy prices and below normal water conditions had a negative effect onutility operations from 2000 to 2001. Of the $1.37 decrease from 2000, $0.70per share is attributable to increases in power supply expenses absorbed by IPCand $0.18 per share is due to the write-off of amounts disallowed in IPC's 2001PCA.  Additional increases in operatingexpenses for maintenance, depreciation, interest and customer expensesdecreased earnings by approximately $0.34 per share.

EPS from energy marketingdecreased $3.26 per share in 2002 after increasing $1.29 per share in2001.  In spite of a 13 percent increasein settled electricity volume during 2002, earnings decreased driven by a sharpdecline in regional prices, price spreads and volatility, combined with thedecreasing number of creditworthy counterparties.  In addition, the decision to wind down energy marketing andtrading at IE has resulted in significantly reduced earnings from thissegment.  Compounding this decline inearnings is $9 million of restructuring and other costs associated with thewind down of energy marketing. The strong performance in 2001 was drivenprimarily by increased price volatility and regional price spreads and a 49percent increase in settled electricity sales volume.

Combined EPS fromIDACORP's other subsidiaries decreased in both 2002 and 2001, primarily due totransactions at Ida-West.  In 2002,Ida-West recorded an $8 million impairment of its Garnet fixed asset, reducingEPS by $0.13.  In 2000, Ida-Westrecorded a $14 million gain on the sale of the Hermiston Power Project, whichcontributed approximately $0.22 per share.

**Utility Operations**This section discussesIPC's utility operations, which are subject to regulation by, among others, thestate public utility commissions of Idaho and Oregon and by the FERC.

**GeneralBusiness Revenue:**  The following table presents IPC's generalbusiness revenues and MWh sales for the last three years:

 

**Revenues**

 

**MWh**

 

**2002**

 

**2001**

 

**2000**

 

**2002**

 

**2001**

 

**2000**

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Residential

$

305,827

 

$

260,251

 

$

225,336

 

4,387

 

4,307

 

4,393

Commercial

 

196,454

 

 

164,019

 

 

132,023

 

3,460

 

3,380

 

3,404

Industrial

 

176,648

 

 

154,318

 

 

133,171

 

3,226

 

3,925

 

4,808

Irrigation

 

93,106

 

 

72,020

 

 

74,827

 

1,821

 

1,419

 

1,993

 

Total

$

772,035

 

$

650,608

 

$

565,357

 

12,894

 

13,031

 

14,598

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

As mentioned above,our general business revenue is dependent on many factors, including the numberof customers we serve, the rates we charge, and weather conditions.

2002 vs. 2001: The following factors influenced the 19 percent increase in generalbusiness revenue:

Rateincreases due to the annual PCA resulted in increased revenues of approximately$94 million.  The PCA is discussed inmore detail below in "REGULATORY ISSUES - Deferred Power SupplyCosts."

Customergrowth in IPC's service territory increased approximately two percent,resulting in a $10 million increase in revenues.

In 2001 manyirrigation customers participated in a program to decrease their usage.  This program was not in effect during 2002,resulting in increased sales to irrigation customers of $20 million.

FMC/Astaris,previously IPC's largest volume customer, closed its Pocatello manufacturingplant late in 2001.  However, based on atake or pay contract with FMC/Astaris which requires payment for powerregardless of delivery, IPC will continue to receive payments from FMC/Astaristhrough March 2003.  Because of this,revenues from FMC/Astaris changed minimally, despite the significantdecrease in MWh sold.

2001 vs. 2000: The following factors influenced the 15 percent increase in generalbusiness revenue:

Increasedaverage rates, resulting from the PCA, increased revenue $137 million. The PCAis discussed in more detail below in "REGULATORY ISSUES - Deferred PowerSupply Costs."

A 2.5 percentincrease in general business customers increased revenue $16 million.

Conservationprograms, including irrigation and large customer buybacks, and other usagefactors, decreased energy consumption, reducing revenues $67 million.

**Off-system sales**:  Off-system sales consist primarily of long-term sales contractsand opportunity sales of surplus system energy.

 

**2002**

 

**2001**

 

**2000**

 

 

 

 

 

 

 

 

 

Off-system sales

$

55,031

 

$

219,966

 

$

229,986

MWh sold

 

2,069

 

 

2,387

 

 

4,529

Revenue per MWh

$

26.60

 

$

92.14

 

$

50.78

 

 

 

 

 

 

 

 

 

 

2002 vs. 2001:  In2002, off-system sales decreased due to a 13 percent decrease in volumes soldand a 71 percent decrease in wholesale electricity prices.

2001 vs. 2000: Off-system sales decreased due principally to a 47 percent decrease involume sold, a result of poor hydro generating conditions.  The volume decrease was partially offset byan 81 percent increase in price per MWh.

**Purchasedpower:**

 

**2002**

 

**2001**

 

**2000**

 

 

 

 

 

 

 

 

 

Purchased power:

 

 

 

 

 

 

 

 

 

Purchases

$

91,312

 

$

430,451

 

$

398,649

 

Load reduction costs

 

50,790

 

 

153,758

 

 

-

 

 

 

 

 

 

 

 

 

MWh purchased

 

2,918

 

 

3,457

 

 

4,311

Purchases per MWh

$

31.29

 

$

124.53

 

$

92.47

 

 

 

 

 

 

 

 

 

 

2002 vs. 2001:  During 2002, purchased power costs decreasedprimarily due to a 75 percent reduction in average wholesale electricityprices.  Load reduction payments alsoincluded in purchased power have decreased $103 million due to expiration ofthe Irrigation Load Reduction Program and changes to the FMC/Astaris VoluntaryLoad Reduction Agreement.  See"REGULATORY ISSUES - FMC/Astaris Settlement Agreement."

2001 vs. 2000: Purchased power expenses increased in 2001.  Contributing to these results are a number of factors, includingwholesale market conditions, and $154 million of irrigation and FMC/Astarisload reduction program costs.

**Fuel expense:**  Thefollowing table presents IPC's fuel expenses and generation at its thermalgenerating plants:

 

**2002**

 

**2001**

 

**2000**

 

 

 

 

 

 

 

 

 

Fuel expense

$

102,871

 

$

98,318

 

$

94,215

Thermal MWh generated

 

7,286

 

 

7,622

 

 

7,701

Cost per MWh

$

14.12

 

$

12.90

 

$

12.23

** **

2002 vs. 2001:  Fuel expenses during 2002 increased due to anine percent increase in average coal prices partially offset by a four percentdecrease in thermal generation.

2001 vs. 2000:  Fuelexpenses increased in 2001, despite decreased generation.  Average coal prices increased, and theDanskin 90-MW gas-fired plant went on-line in September 2001.

**PCA:**  The PCAexpense component is related to IPC's PCA regulatory mechanism.  In 2002, actual power supply costs haveexceeded those anticipated in the forecast. Below normal water conditions are still impacting power supply costseven though power supply prices are significantly lower than 2001.  In 2001, actual power supply costs weresignificantly greater than forecasted, resulting in a large PCA credit, whichis now being recovered in rates (as revenues) and the deferred balance is beingamortized as PCA expense.  FMC/Astarisand Irrigation Load Reduction Program cost deferrals also affect the PCA.  The PCA is discussed in more detail below in"REGULATORY ISSUES - Deferred Power Supply Costs."

The followingtable presents the components of PCA expense: 

 

 

**December 31,**

 

 

**2002**

 

**2001**

 

**2000**

 

 

 

 

 

 

 

 

 

 

Current  year power supply cost deferral

 

$

(4,178)

 

$

(145,801)

 

$

(112,210)

FMC/Astaris  and irrigation program costs (deferral)

 

 

(39,854)

 

 

(136,028)

 

 

- 

Amortization  of prior year authorized balances

 

 

200,941 

 

 

94,358 

 

 

(8,478)

Write-off  of disallowed costs

 

 

13,580 

 

 

11,546 

 

 

- 

 

Total  power cost adjustment

 

$

170,489 

 

$

(175,925)

 

$

(120,688)

 

 

 

 

 

 

 

 

 

 

 

**Energy Marketing**IDACORP announced on June 21, 2002 that IE would wind down its powermarketing operations, stating that IE would not seek new electric customers;would limit its maximum value at risk to less than $3 million; would target areduction of working capital requirements to less than $100 million by the endof 2003; and would reduce its workforce at its Boise operations byapproximately 50 percent.  On November5, 2002, IDACORP announced that it was terminating further evaluation of growthopportunities in the mid-stream natural gas markets, and stated that IE wouldclose its Denver office by year-end 2002, and because of its link to thenatural gas platform, would shut down its natural gas trading operation inHouston by March 2003.  The announcementconcluded that IE's continued wind down of its energy marketing operationswould result in additional workforce reductions at IE's Boise operationsthrough mid-2003.  Since the June 21,2002 announcement, IE has reduced its workforce by over 60 percent and willcontinue to reduce its workforce as contractual obligations terminate.

IE recorded a restructuringcharge in the fourth quarter of 2002 of $7 million and additional chargesrelated to exiting the business of $1 million for a total of $8 million.  For the year, the charges were $9 millionand relate to, among other matters, severance charges, non-cancelable leaseliabilities and asset impairments.

In connection with the wind down of energy marketing,matters have been identified that require resolution with the FERC or theIPUC.  One matter that requiredresolution with the FERC included the assignment of IPC's power marketing contractsto IE without obtaining the required prior approval of the FERC.  On February 26, 2003, the FERC issued anorder approving the assignment of certain wholesale power and transmissionservices agreements from IPC to IE.  TheIPUC matters include a proceeding that has been 

underway since May 2001 where IPC and the IPUC staff havebeen working to determine the appropriate compensation IE should provide to IPCas a result of transactions between the affiliates.

These matters are discussed inmore detail in Note 13 to the Consolidated Financial Statements.

IE reported a $24 millionoperating loss in 2002 compared to $177 million of operating income in 2001.Gross margin for 2002 was $4 million, which included $66 million in unrealizedlosses related to the settlement, during 2002, of outstanding positions at yearend 2001 and the change in value of IE's forward positions at year end2002.  On a cumulative basis, IEanticipates that approximately 40 percent of these unrealized forward positionsrecorded at year end 2002 will be settled by the end of 2003, 58 percentsettled by the end of 2004 and 71 percent settled by the end of 2005.  All forward positions at December 31, 2002should be settled within eight years.  Changesin market conditions in future periods could substantially change the amountsof gain or loss ultimately realized upon settlement of the contracts.

**Revenues:**  IDACORP elected in third quarter 2002 tochange its presentation of energy trading activities from gross to netpresentation, as discussed in Note 1 to the Consolidated FinancialStatements.  Prior periods have beenreclassified to conform to current presentation. Operating revenues includerevenues from the sale of electricity and gas netted against the cost ofpurchased power and natural gas.  Allfinancial transactions and unrealized income are presented on a net basis asoperating revenue.  Operating expensesinclude general and administrative expenses, bad debt reserves, transmissionexpenses and broker fees.  IDACORP's netfinancial position and results of operations were not affected by this changein presentation.

The following table presents IE's energy marketing revenues and volumesfor the last three years:

 

 

 

 

 

 

 

 

**2001-2002**

 

 

 

 

**2000-2001**

 

 

 

 

 

 

 

 

**Increase**

 

 

 

 

**Increase**

 

 

**2002**

 

**2001**

 

**(Decrease)**

 

**2000**

 

**(Decrease)**

Net operating revenues:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Electricity

 

$

42,304

 

$

330,793

 

$

(288,489)

 

$

182,326

 

$

148,467

 

Gas

 

 

4,106

 

 

17,870

 

 

(13,764)

 

 

7,790

 

 

10,080

 

 

Total operating revenues

 

$

46,410

 

$

348,663

 

$

(302,253)

 

$

190,116

 

$

158,547

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating volumes  (settled):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Electricity (MWh)

 

 

39,526,630

 

 

34,936,951

 

 

4,589,679 

 

 

23,518,484

 

 

11,418,467

 

Gas (MMbtu)

 

 

35,895,039

 

 

97,327,432

 

 

(61,432,393)

 

 

80,728,530

 

 

16,598,902

 

The decline in revenues between2001 and 2002 was driven by a sharp decline in regional prices, price spreadsand volatility, combined with the decreasing number of creditworthycounterparties.  In addition, thedecision to wind down energy marketing at IE has resulted in significantly reducedrevenue from this segment.  IE's growthin revenue between 2000 and 2001 was due to an increase in wholesaleelectricity prices, electricity price volatility and growth in settled physicalelectricity volumes. IE anticipates revenues in 2003 to continue to decline asIE continues to complete its obligations under existing contracts and wind downits business.

**Selling, General and Administrative Expenses:** Total selling, general and administrative(SG&A) expenses decreased $38 million in 2002 due primarily to decreasedallowance for bad debt and compensation expense. Allowance for bad debtdecreased in 2002 due to unusually high bad debt expense in 2001 associatedwith reserves related to trading activities conducted with California entitiesin 2000.  Compensation expense hasdeclined due to a reduction in profit related incentives and a reduction inworkforce related to the wind down of operations.

SG&A expense in 2001increased $15 million.  This wasattributed to a rise in allowance for bad debt associated with reserves relatedto trading activities conducted with California entities in 2000 and anincrease in compensation driven by an increase in the workforce and profitrelated incentives.

**Other Income and Expenses**IDACORP's other income (loss) decreased $30 million as compared to2001.  The primary reasons for thisdecrease are an $8 million partial write down on equipment related to theGarnet project in fourth quarter 2002 at Ida-West and a $5 million decreaseattributed to early redemption of outstanding bonds held by Ida-West recognizedas a gain in 2001.  The early redemptionof these outstanding bonds contributed to a $2 million decrease in Ida-West's2002 interest income. IE recognized a $2 million loss on property impairmentrelated to the wind down of IE's energy marketing activities.  A $3 million loss was recorded in 2002 byIPC related to its available-for-sale securities.  IPC's interest income decreased $3 million due to the decreasedPCA balance as compared to 2001.

Other incomedecreased $7 million in 2001 as compared to 2000, due primarily to the sale in2000 of Ida-West's interest in the Hermiston Power Project, a 536 MW, gas-firedcogeneration project to be located near Hermiston, Oregon.  Ida-West was responsible for managing all permittingand development activities relating to the project since its inception in1993.  A pre-tax gain of $14 million wasrecorded on this transaction in 2000. This decrease was partially offset by a $5 million gain recognized in2001 related to the early redemption by the Friant Power Authority ofoutstanding bonds held by Ida-West.

**InterestExpense and Other:**  Interest expense and other expense decreased$7 million in 2002 and increased $9 million in 2001.  The decrease in 2002 is due primarily to reductions in variableinterest rates and average outstanding debt. The increase in 2001 is predominantly the result of higher short-termdebt balances to finance power purchased for IPC's system, partially offset bysignificant decreases in borrowing rates. IDACORP's average short-term debt in 2002 was $173 million, compared to$232 million in 2001.

**Tax Accounting Method Change**During the third quarter of2002, IDACORP filed its 2001 federal income tax return and adopted a change toIPC's tax accounting method for capitalized overhead costs.  The former method allocated such costsprimarily to construction of plant, while the new method allocates such coststo both construction of plant and the production of electricity.

The effect of the tax accounting method changehas been recorded as a decrease to income tax expense for the year endedDecember 31, 2002 of $35 million, of which $31 million is attributable to 2001and prior tax years, and $4 million is attributable to the 2002 tax year.  The decrease to tax expense is a result ofdeductions on the applicable tax returns of costs that were capitalized intofixed assets for financial reporting purposes. Deferred income tax expense has not been provided because the prescribedregulatory accounting method does not allow for inclusion of such deferred taxexpense in current rates.  Regulatedenterprises are required to recognize such adjustments as regulatory assets ifit is probable that such amounts will be recovered from customers in futurerates.

**Status of Audit Proceedings**IPC settled income taxdeficiencies related to its partnership investment in the Bridger Coal Company,covering the years 1991 through 1998. The settlement resulted in deficiencies that were less than previouslyaccrued, enabling IPC to decrease income tax expense by approximately $3million.

Federal income tax returns for years through 1997 havebeen examined by the Internal Revenue Service and substantially all issues havebeen settled.  Management believes thatadequate provision for income taxes has been made for the open years 1998 andafter and for any unsettled issues prior to 1998.

**LIQUIDITY AND CAPITAL RESOURCES:**

**Operating Cash Flow**IDACORP's and IPC's operating cash flows in 2002 were $348 millionand $366 million, respectively, driven by collections of outstanding PCAamounts, reduced power supply costs and the receipt of tax refunds.  The increased cash flows were used to paydown short-term debt and redeem IPC's auction rate preferred stock.

The tax refunds relate to net operating loss carrybacksassociated with IPC's 2001 power supply costs and the tax accounting methodchange for capitalized overhead costs. Estimated tax payments offset these refunds.

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

 

**2003**

 

**2004**

 

**2005**

 

**2006**

 

**2007**

 

**Thereafter**

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

IPC long-term  debt

$

80,084

 

$

50,077

 

$

60,079

 

$

82

 

$

81,228

 

$

679,275

Other long-term debt

 

9,508

 

 

8,445

 

 

7,196

 

 

5,649

 

 

3,705

 

 

2,940

IPC fuel supply contracts

 

35,230

 

 

30,970

 

 

27,466

 

 

27,300

 

 

9,266

 

 

22,856

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

**Credit Ratings**On September 10, 2002, Moody's changed its rating outlook for IPC tonegative from stable.  Moody's statedthat the negative rating outlook reflects uncertainties relating to potentialeffects from the FERC-related matters associated with the wind down of theenergy marketing business at IE, certain affiliated transactions and thesplitting of IE into a separate subsidiary.

Access to capital markets at a reasonable cost is determinedin large part by credit quality.  Thefollowing outlines the current S&P, Moody's and Fitch ratings of IDACORP'sand IPC's securities:

 

 

Standard and Poor's

 

Moody's

 

Fitch 

 

 

IPC

 

IDACORP

 

IPC

 

IDACORP

 

IPC

 

IDACORP

Corporate  Credit Rating

 

A-

 

A-

 

A3

 

Baa  1

 

None

 

None

Senior  Secured Debt

 

A

 

None

 

A2

 

None

 

A

 

None

Senior  Unsecured Debt

 

BBB+

 

BBB+

 

A3

 

Baa  1

 

A-

 

BBB+

Preferred  Stock

 

BBB

 

BBB

 

Baa  2

 

None

 

BBB+

 

None

Trust  Preferred Stock

 

None

 

BBB

 

None

 

Baa  2

 

None

 

BBB

Commercial  Paper

 

A-2

 

A-2

 

P-1

 

P-2

 

F-1

 

F-2

Rating  Outlook

 

Positive

 

Positive

 

Negative

 

Negative

 

Stable

 

Stable

 

These security ratings reflect the views of the ratingagencies.  An explanation of thesignificance of these ratings may be obtained from each rating agency.  Such ratings are not a recommendation tobuy, sell or hold securities.  Anyrating can be revised upward or downward or withdrawn at any time by a ratingagency if it decides that the circumstances warrant the change.  Each rating should be evaluatedindependently of any other rating.

Some collateral agreements in place between IE and itscounterparties include provisions requiring additional margining in the eventof a credit rating downgrade.  Ingeneral, credit rating changes within the investment grade category should notmaterially impact the liquidity or financial condition of IDACORP.  A credit downgrade below an investment graderating could result in additional margin calls that could have a materialnegative impact on the liquidity of IDACORP. IDACORP believes its existing credit facilities are adequate to fundthese potential liquidity requirements.

**Working Capital**The significant changes in working capital that are not attributedto normal business activity and timing are discussed below.

Due to the wind down of theenergy marketing business, IE's customer receivables have decreased $25million, accounts payable have decreased $95 million and other liabilities havedecreased $29 million.

The changes in "regulatory assets - current" and"derivative liabilities - current" are due to adoption of FinancialAccounting Standards Board (FASB) Derivative Implementation GroupImplementation Issue C-15, "Normal Purchases and Normal Sales Exceptionfor Option-Type Contracts and Forward Contracts in Electricity."  This Implementation Issue allows contractssubject to book-outs at electric utilities to qualify for the normal purchaseand sales exception in SFAS 133.  IPCcompleted an evaluation of its booked-out contracts and determined thatcontracts previously classified as derivatives were exempt.

The increase in taxes accrued is primarily due to estimatedtaxes payable at year-end 2002, plus the receipt of $90 million in cash refundsrelated to net operating loss carrybacks associated with IPC's 2001 powersupply costs and IPC's tax accounting method change for capitalized overheadcosts.

Energy marketing assets and liabilities reflect the fair value of energymarketing contracts as of the reporting date. The fair value of these contracts is unrealized and therefore does notnecessarily indicate a current source or use of funds.  The decreases in the net energymarketing assets and liabilities from 2001 to 2002 are primarily a reflectionof the wind down of the energy marketing business, significantly reducing thenumber of forward deals that remain part of the portfolio.  Also contributing to the reduction are lowermarket prices at December 31, 2002 than in the prior year.

Cash received from energy trading counterparties serves ascollateral against open positions on energy related contracts and is reportedin cash and cash equivalents.  Theresultant liability is recorded as a reduction to the energy marketing assetgenerated by the open position.  Regarding the use of postedcollateral, the margining agreements provide "...the right to: (i) sell,pledge, rehypothecate, assign, invest, use, commingle or otherwise dispose of,or otherwise use in its business any Posted collateral it holds..." aslong as IDACORP maintains a credit rating of at least BBB- (S&P) or Baa3(Moody's).  IDACORP has continued tomaintain a credit rating above this minimum and has no restrictions on the useof collateral funds.

**Capital Requirements**IDACORP capital expenditures are expected to total $908 million from2003 through 2005.  This amount includes$565 million for IPC construction expenditures, excluding Allowance for FundsUsed During Construction (AFDC), $190 million for IPC long-term debt maturitiesand $34 million for other IPC capital expenditures.  Over the next three years internally generated cash and debtissuances are expected to provide the majority of the funds needed to meetIDACORP's capital requirements. Internally generated cash is expected to provide 97 percent in 2003 andan average of 76 percent in 2004 and 2005.

 

**2003**

 

**2004-2005**

 

**(millions of dollars)**

 

 

 

 

 

 

IPC Utility capital expenditures:

 

 

 

 

 

 

Construction Expenditures (excluding AFDC):

 

 

 

 

 

 

 

Generating facilities:

 

 

 

 

 

 

 

 

Hydro

$

27

 

$

42

 

 

 

Thermal

 

19

 

 

95

 

 

 

 

Total generating facilities

 

46

 

 

137

 

 

Transmission lines and substations

 

36

 

 

86

 

 

Distribution lines and substations

 

50

 

 

145

 

 

General

 

18

 

 

47

 

 

 

Total construction expenditures (excluding AFDC)

 

150

 

 

415

 

Long-term debt maturities

 

80

 

 

110

 

Other

 

5

 

 

29

 

 

Total IPC Utility

 

235

 

 

554

 

 

 

 

 

 

IFS Capital Expenditures

 

-

 

 

40

IFS long-term debt maturities

 

17

 

 

35

Other

 

7

 

 

20

 

Total IDACORP

$

259

 

$

649

 

 

 

 

 

 

 

IPC has nonuclear involvement and its future construction plans do not includedevelopment of any nuclear generation. IPC's capital expenditures are primarily for maintaining currentinfrastructures and meeting anticipated electricity demands.

IFS's capitalexpenditures are primarily for additional investments in affordable housingprojects.The above table does not include IDACORP's future investment relating toresearch and development at its fuel cell subsidiary, IdaTech.

Based uponpresent environmental laws and regulations, IPC estimates its 2003 capitalexpenditures for environmental matters, excluding AFDC, will total $27million.  Studies and measures relatedto environmental concerns at IPC's hydro facilities account for $23 million andinvestments in environmental equipment and facilities at the thermal plantsaccount for $4 million.  From 2004through 2005, environmental-related capital expenditures, excluding AFDC, areestimated to be $32 million. Anticipated expenses related to IPC's hydro facilities account for $25million and thermal plant expenses are expected to total $7 million.

Various options that may beavailable to meet the future energy requirements of its customers includeefficiency improvements on IPC's generation, transmission and distributionsystems, purchased power and exchange agreements with other utilities or otherpower suppliers.  IPC will pursue theprojects that best meet its future energy needs.

The above estimates are subjectto constant revision in light of changing economic, regulatory andenvironmental factors and patterns of conservation.

**Financing Programs**IDACORP's consolidated capital structure fluctuated slightly duringthe three-year period, with common equity ending at 46 percent, preferred stockof IPC at three percent, and long-term debt at 51 percent at December 31, 2002.

**Creditfacilities:**  IPC has a $200 million facility that expiresMarch 25, 2003.  Under this facility IPCpays a facility fee on the commitment, quarterly in arrears, based on IPC'scorporate credit rating.  IPC'scommercial paper may be issued up to the amount supported by the bank creditfacilities.  At December 31, 2002, IPChad regulatory authority to incur up to $350 million of short-termindebtedness.

IDACORP has a$350 million facility that expires on March 25, 2003 and a $140 millionfacility that expires on March 26, 2005. Under these facilities IDACORP pays a facility fee on the commitment,quarterly in arrears, based on its corporate credit rating.  Commercial paper may be issued up to theamounts supported by the bank credit facilities.

IDACORP and IPC plan to renew their credit facilities thatexpire in March 2003.  IDACORP plans toreplace its current $350 million facility with a 364-day facility, but at areduced amount resulting from lower liquidity requirements at IE.  IPC plans to replace its current $200million facility with a similar sized facility.

**Short-termfinancings:**  At December 31, 2002, IPC'sshort-term borrowing consisted of $11 million of commercial paper, compared to$282 million at December 31, 2001, consisting of $100 million of floating ratenotes and $182 million of commercial paper. The increase in 2001 was primarily a result of unrecovered power supplyexpenditures.  IPC repaid $100 millionof floating rate notes in September 2002 using short-term borrowings fromIDACORP.  This $100 millioninter-company debt was subsequently repaid with IPC first mortgage bonds issuedin November 2002.  At December 31, 2002, IDACORP's short-termborrowing totaled $166 million, compared to $81 million at December 31, 2001.

**Long-term financings:**  IDACORP currently has two shelf registrationstatements totaling $800 million that can be used for the issuance of unsecureddebt (including medium-term notes) and preferred or common stock.  At December 31, 2002, none had been issued.

On March 23,2000, IPC filed a $200 million shelf registration statement that could be usedfor first mortgage bonds (including medium-term notes), unsecured debt orpreferred stock.  On December 1, 2000,IPC issued $80 million of Secured Medium-Term Notes, Series C, 7.38% Series due2007.  Proceeds were used in January2001 for the early redemption of $75 million of First Mortgage Bonds 9.50%Series due 2021.  On March 2, 2001, IPCissued $120 million of Secured Medium-Term Notes, Series C, 6.60% Series due2011 with the proceeds used to reduce short-term borrowing incurred in supportof ongoing long-term construction requirements.  No amounts remain to be issued on this shelf registrationstatement.

On August 16, 2001, IPC filed a $200 million shelfregistration statement that could be used for first mortgage bonds (includingmedium-term notes), unsecured debt or preferred stock.   On November 15, 2002, IPC issued $200 millionof secured medium-term notes.  This issuanceof medium-term notes was divided into two series.  The first was $100 million First Mortgage Bonds 4.75% Series due2012 and the second was $100 million First Mortgage Bonds 6.00% Series due2032.   Proceeds were used to pay downIPC short-term borrowings.  IPC plans tofile a new shelf registration statement for first mortgage bonds (includingmedium-term notes), unsecured debt and preferred stock in the first quarter of2003.

In August 2001, $25million of First Mortgage Bonds 9.52% Series due 2031 were redeemed early.  Also, in March 2002, $50 million FirstMortgage Bonds 8.75% Series due 2027 were redeemed early using short-termborrowings.

IPC redeemed its auction rate preferred stock in August 2002for $50 million using short-term borrowings.

IPC has $80million First Mortgage Bonds 6.40% Series due April 28, 2003 and has theability to redeem another $80 million first mortgage bonds.  Also in 2003, IPC is considering refundingearly $50 million Humboldt County, Nevada, Pollution Control Revenue Bonds8.30% due 2014.

Under theterms of the Indenture relating to IPC's First Mortgage Bonds, net earningsmust be at least two times the annual interest on all bonds and other equal orsenior debt.  For the twelve monthsended December 31, 2002, net earnings were 4.16 times.

In 2002, IDACORP considered the issuance of common stock orequity linked securities.  In light ofthe decision to wind down IE's wholesale energy marketing function andreviewing options to balance its capital structure, IDACORP does not anticipateissuing new common equity or equity linked securities during 2003 except forcommon stock issued for the Dividend Reinvestment Plan, the Employee SavingsPlan, the Restricted Stock Plan and the IDACORP Long-Term Incentive and CompensationPlan.

**LEGAL AND ENVIRONMENTAL ISSUES:**

**Legal and Other ProceedingsCalifornia Energy Situation: **OnJuly 25, 2001, the FERC issued an order establishing evidentiary hearingprocedures related to the scope and methodology for calculating refunds relatedto transactions in the spot markets operated by the California IndependentSystem Operator (Cal ISO) and the California Power Exchange (CalPX) during theperiod October 2, 2000 through June 20, 2001. As to potential refunds, if any,IE believes its exposure is likely to be offset by amounts due from Californiaentities. Multiple parties have filed requests for rehearing and petitions forreview.  The latter--more than 60--havebeen consolidated by the United States Court of Appeals for the Ninth Circuit andheld in abeyance while the FERC continues its deliberations.  The Ninth Circuit also directed the FERC topermit the parties to adduce additional evidence respecting market manipulationand although the California Parties (the California Attorney General, otherstate agencies and the California Investor Owned Utilities) have requestedspecific procedures to implement that requirement, the FERC has not yet actedon that request.

On November 20, 2002, the FERC issued an order allowingthe parties to the California refund proceeding to conduct discovery for onehundred days into market manipulation by various sellers during the Westernpower crises of 2000 and 2001.  At theconclusion of the discovery period parties alleging market manipulation are tosubmit their claims to the FERC and parties have until March 20, 2003 to submitevidence or comments in response, including assertions that cross-examinationis warranted.  On March 3, 2003, a groupof California parties, including the California Attorney General, theCalifornia Public Utilities Commission, the California Electricity OversightBoard, SCE and PG&E, filed materials with the FERC claiming that wholesalepower suppliers manipulated the California market during 2000-2001.  They seek approximately $8 billion inrefunds for the state's ratepayers.  Anumber of wholesale power suppliers were named in the filings, includingIDACORP and IPC.  IDACORP and IPC intendto vigorously defend in this matter, but they are unable to predict the outcomeof this proceeding.  See Note 8 to theConsolidated Financial Statements.

**Overton Power District No. 5:**  IE filed a lawsuit on November 30, 2001 inIdaho State District Court in and for the County of Ada against Overton PowerDistrict No. 5 (Overton), a Nevada electric improvement district, based onOverton's breach of its power contracts with IE.  The July contract provided for Overton to purchase 40 MW ofelectrical energy per hour from IE at $88.50 per MWh, from July 1, 2001 throughJune 30, 2011.  In the contract, Overtonagreed to raise its rates to its customers to the extent necessary to make itspayment obligations to IE under the contract.

IE has asked the Idaho DistrictCourt for damages pursuant to the contract, for a declaration that Overton isnot entitled to renegotiate or terminate the contract and for injunctive reliefrequiring Overton to raise rates as stipulated in the contract.  Overton filed an Answer and Counterclaimclaiming, among other things, that IE breached the agreement by failing toperform in accordance with its contractual obligation and asking for damages inthe amount to be proved at trial. Overton also asserts that the contract is unenforceable or subject torescission.  IE believes Overton'sassertions are without merit.  IE andOverton filed cross motions for summary judgment that have been denied by theCourt.  The parties continue withdiscovery in the lawsuit.  Trial isscheduled to commence on May 5, 2003.

IE believes that Overton'sactions constitute a breach of the contract and intends to vigorously prosecutethis lawsuit.  While the outcome oflitigation is never certain and IE has not yet completed discovery, IEcontinues to believe that it should prevail on the merits.  At December 31, 2002, IE had a $74 millionlong-term asset related to the Overton claim. IE will review the recoverability of the asset on an ongoing basis.  The recoverability of the asset is subjectto Overton's willingness and ability to raise its rates as provided for in thecontract.

**Other Legal Proceedings: **IDACORP, IPC and/or IE are involved invarious lawsuits and legal proceedings, discussed above and in detail in Note 8to the Consolidated Financial Statements. The companies believe they have meritorious defenses to all lawsuits andlegal proceedings where they have been named as defendants.  Resolution of any of these matters will taketime, and the companies cannot predict the outcome of any of theseproceedings.  The companies believe thattheir reserves are adequate for these matters. Litigation with Truckee was settled on January 3, 2003 and the casefiled by Grays Harbor was dismissed with prejudice on January 28, 2003.  See Note 8 to the Consolidated FinancialStatements.

**FERC Investigations RegardingTrading Practices:**  In a series ofrequests for information ending on May 8, 2002 the FERC issued a data requestto all sellers of Wholesale Electricity and/or Ancillary Services to the CalISO and/or the CalPX during the years 2000-2001.  The request required IPC and IE to respond in the form of anaffidavit to inquiries respecting various trading practices that the FERCidentified in its fact-finding investigation of Potential Manipulation ofElectric and Natural Gas Prices in Docket No. PA02-2-000.  IPC and IE filed the various responses soughtby the FERC.  The May 2002 responseindicated that although they did export energy from the CalPX outside ofCalifornia during the period 2000-2001, they did not engage in anyimpermissible trading practice described in the Enron memoranda and identifiedby the FERC.  The energy purchasedwithin and exported out of California was resold to supply preexisting loadobligations, to supply preexisting term transactions or to supply acontemporaneous sales transaction.  Thecompanies denied engaging in the other ten practices identified by theFERC.  IPC and IE filed additionalresponses with the FERC on May 31 and June 5, 2002.  In the May 31 response, the companies denied engaging in thepractice referred to as "wash," "round trip" or"sell/buyback" trading involving the sale of an electricity productto another company together with a simultaneous purchase of the same product atthe same price.  In the June 5 response,where the data request was directed to all sellers of natural gas in theWestern Systems Coordinating Council and/or Texas during the years 2000-2001,the companies denied engaging in the practice referred to as "wash,""round trip" or "sell/buyback" trading involving the saleof natural gas together with a simultaneous purchase of the same product at thesame price.

**U.S. Commodity FuturesTrading Commission Investigations Regarding Trading Practices: **On October 2, 2002, the U.S. CommodityFutures Trading Commission (CFTC) issued a subpoena to IPC requesting, amongother things, all records related to all natural gas and electricity trades byIPC involving "round trip trades", also known as "washtrades" or "sell/buyback trades" including, but not limited tothose made outside the Western Systems Coordinating Council region.  The subpoena applies to both IE andIPC.  As discussed above, on May 22,2002, both IE and IPC responded to a similar request from the FERC stating thatthey did not engage in "round trip" or "wash" trades.  By letter from the CFTC dated October 7,2002, the Division of Enforcement agreed to hold in abeyance until a later dateall items requested in the subpoena with the exception of one paragraph whichrelated to three trades on a certain date with a specific party.  The companies provided the requestedinformation.

On January 14, 2003, IPC received a request from the CFTC,pursuant to the October 2002 subpoena, for documents related to "roundtrip" or "wash trades" and information supplied to energyindustry publications.  The requestapplies to both IPC and IE.  The companiesstated in their response to the CFTC that they did not engage in any"round trip" or "wash trade" transactions and that theybelieve the only information provided to energy industry publications wasactual transaction data.  The companieshave provided the requested information.

**Environmental Issues****Salmon Recovery Plan:**  IPCis continuing to monitor regional efforts to develop a comprehensive andscientifically credible plan to ensure the long-term survival of anadromousfish runs on the Columbia and lower Snake Rivers.

In November of1991, the National Marine Fisheries Service (NMFS) listed the Snake RiverSockeye Salmon as endangered under the Endangered Species Act (ESA).  Subsequently, in April 1992, NMFS listed theSnake River Fall Chinook and the Snake River Spring/Summer Chinook asthreatened under the ESA.  Only theSnake River Fall Chinook inhabit the Snake River in the vicinity of IPC'sthree-dam Hells Canyon Complex (HCC). These listings have not had any major effects on IPC's operations.  In 1991, IPC voluntarily initiated a FallChinook Interim Recovery Plan and Study intended to address concerns relativeto Fall Chinook spawning immediately below Hells Canyon Dam.  Since the inception of that plan, IPC hasbeen managing releases from the HCC during the Fall Chinook spawning season toprovide stable conditions for spawning Fall Chinook below Hells CanyonDam.  These conditions are maintainedthrough fry emergence in the spring.  Inconnection with the relicensing of the HCC, IPC is engaged in ongoingdiscussions with the FERC and NMFS relative to ESA issues associated with theHCC.

In December 2000,NMFS issued a final Biological Opinion (BiOp) on the operation of the FederalColumbia River Power System (FCRPS). This BiOp resulted from ESA Section 7 consultation on the operations ofthe federal projects operated by the U.S. Army Corps of Engineers and U.S.Bureau of Reclamation (BOR) on the lower Snake and Columbia Rivers.  It did not relate to the operations of IPC'sHCC and did not call for any changes in the operations of the HCC.

In May of 2001,NMFS issued a final BiOp on the operations of the BOR projects in the SnakeRiver basin above the HCC.  This BiOpwas interim in nature, expiring in March 2002. NMFS and the BOR are currently negotiating an extension of this BiOp forsubsequent years' operations.

Portions of the2000 FCRPS BiOp and the 2001 BOR BiOp provide for the acquisition of water fromIdaho by the BOR in order to provide augmentation flows to assist with thedownstream migration of ESA listed anadromous fish through the lower SnakeRiver FCRPS projects.  For the pastseveral years, the BOR has been leasing water from willing lessors in Idaho inan effort to provide the augmentation flows. In connection with these flow augmentation efforts, IPC has beencooperating with the federal agencies by moving and shaping water acquired bythe BOR through the HCC.  In the past,IPC has been reimbursed for any energy losses incurred as a result of thiscooperation through an agreement with the Bonneville Power Administration(BPA).  While this agreement expired inApril of 2001, IPC has advised federal interests of its willingness to continueto assist with the movement and shaping of federal flow augmentation waterprovided any adverse impact to its customers is satisfactorily addressed.

The federal interests determined not to reimburse IPC andIPC did not assist with the movement and shaping of federal flow augmentationwater during 2001 or 2002.

**Threatened and EndangeredSnails:** In December 1992, theU.S. Fish and Wildlife Service (USFWS) listed five species of snails thatinhabit the middle Snake River as threatened or endangered species under theESA.  In1995, in preparation for the FERC relicensing of certain of IPC's hydropowerprojects, IPC obtained a permit from the USFWS to study the listed snails.Since that date, IPC has been collecting field data and conducting studies inan effort to determine the status of the listed snails and how they may beaffected by a variety of factors, including hydropower production, waterquality and irrigation practices.

IPC is currently involved in renewing five federal licensesfor hydroelectric projects in the middle Snake River region. Those projectsinclude the Upper Salmon Falls, Lower Salmon Falls, Bliss, Shoshone Falls(collectively called the Mid-Snake projects) and the C. J. Strike projects. Thepotential impact of the operation of these projects on the five ESA listedsnails has raised some issues in the relicensing processes before theFERC.  Section7 of the ESA requires that the FERC consult with the USFWS on any proposedfederal action, such as the relicensing of IPC's projects, that may affect aspecies listed as threatened or endangered under the ESA.  On January 16, 2002, the FERC requested thatthe USFWS engage in Section 7 consultation on the proposed relicensing of theMid-Snake projects with regard to the ESA listed snails. If the FERC determinesthat operation of IPC's Mid-Snake projects adversely affects a listed snail, theymay impose operating constraints that could result in loss of peaking capacityat the projects. The cost of replacing this peaking capacity will varydepending upon market conditions and the replacement option selected.

Based upon the studies initiated by IPC in 1995, in July andOctober of 2002 IPC, in cooperation with the State of Idaho, filed petitionswith the USFWS to remove the Bliss Rapids snail and Idaho springsnail from thefederal list of threatened and endangered wildlife. Because of the pendingrelicensing proceedings at the FERC and the ESA consultation between the FERCand USFWS on the potential effect of project operations on ESA listed snails,IPC submitted the petitions, and the studies upon which they were based, to theFERC for inclusion in the Mid-Snake and C J Strike relicensing proceedings.

On December 13, 2002, because of inconsistencies discoveredin field data collected by IPC since 1995, the macro invertebrate database intowhich the field data was entered and the use of that database in thepreparation of the studies used to support the pending petitions, IPC notifiedthe USFWS and the FERC that it was withdrawing the petitions. IPC has retainedan independent scientist to review the procedures used to collect the fielddata, the creation of the database, the database itself and its use inpreparing the snail studies. IPC has advised the FERC that it expects thisindependent review will be completed by March 30, 2003 and has asked that theFERC withhold any action on the pending ESA Section 7 consultation until theindependent review is complete. The USFWS has also requested that theconsultation be extended until the completion of the independent reviewprocess.

**Environmental Regulation Costs: **IPC anticipates $12 million in annual operating costs forenvironmental facilities during 2003. Hydro facility expenses account for $8 million of this total and $4million is related to thermal plant operating expenses.  From 2004 through 2005, total environmentalrelated operating costs are estimated to be $25 million.  Anticipated expenses related to the hydrofacilities account for $17 million and thermal plant expenses are expected tototal $8 million during this period.

**REGULATORY ISSUES:**

**Deferred Power Supply Costs**IPC's deferred power supply costs consist of the following atDecember 31, 2002 and 2001: 

 

**2002**

 

**2001**

 

 

 

 

 

 

Oregon deferral

$

14,172

 

$

14,866

 

 

 

 

 

 

Idaho PCA current year power supply cost  deferrals:

 

 

 

 

 

 

Deferral for 2001-2002 rate year

 

-

 

 

78,395

 

Deferral for 2002-2003 rate year

 

8,910

 

 

-

 

Irrigation load reduction program

 

-

 

 

69,586

 

Astaris load reduction agreement

 

27,160

 

 

62,247

 

 

 

 

 

 

 

Idaho PCA true-up awaiting recovery:

 

 

 

 

 

 

Irrigation and small general service deferral for  recovery in 

 

 

 

 

 

 

 

the 2003-2004 rate year

 

12,049

 

 

-

 

Industrial customer deferral for recovery in the  2003-2004 rate year

 

3,744

 

 

-

 

Remaining true-up authorized October 2001

 

-

 

 

36,500

 

Remaining true-up authorized May 2001

 

-

 

 

42,895

 

Remaining true-up authorized May 2002

 

74,253

 

 

-

 

 

 

 

 

 

 

Total deferral

$

140,288

 

$

304,489

 

 

 

 

 

 

 

**Idaho:**  IPC has a PCA mechanism that provides forannual adjustments to the rates charged to its Idaho retail customers.  These adjustments, which take effect in May,are based on forecasts of net power supply expenses and the true-up of theprior year's forecast.  During the year,90 percent of the difference between the actual and forecasted costs isdeferred with interest.  The endingbalance of this deferral, called a true-up, is then included in the calculationof the next year's PCA adjustment.

So far in the 2002-2003 PCA rateyear, actual power supply costs have exceeded those anticipated in theforecast.  Below normal water conditionsare still impacting power supply costs even though power supply prices aresignificantly lower. In addition, an Irrigation Load Reduction Program wascompleted in the 2001-2002 PCA rate year and the FMC/Astaris Voluntary LoadReduction costs have decreased, both reducing the PCA regulatory accountbalance from $290 million as of December 31, 2001 to $126 million as ofDecember 31, 2002.

On May 13, 2002, the IPUC issuedOrder No. 29026 related to the 2002-2003 PCA rate filing.  The order granted recovery of $255 millionof excess power supply costs, consisting of:

$209 million ofvoluntary load reduction and power supply costs incurred between March 1, 2001and March 31, 2002.

$28 million ofexcess power supply costs forecasted for the period April 2002 through March2003.

$18 million ofunamortized costs previously approved for recovery beginning October 1,2001.  The amount authorized in October2001 totaled $49 million.  This orderspreads the remaining October 2001 rate increase, which would have ended inSeptember 2002, through May 2003.

The order also:

Denied recoveryof $12 million of lost revenues resulting from the Irrigation Load ReductionProgram, and $2 million of other costs IPC sought to recover.

Deferredrecovery of $12 million of costs related to irrigation and small general servicecustomers.  In June 2002, the IPUCissued Order No. 29065 deferring an additional $4 million applicable to certainindustrial customers.  The $16 millionwill be recovered during the 2003-2004 PCA rate year, and IPC will earn a sixpercent carrying charge on the balance.

Denied IPC'srequest to issue $172 million in Energy Cost Recovery Bonds, which would havespread the recovery of that amount over three years.

Discontinuedthe IPUC-required three-tiered rate structure for residential customers.

Authorized aseparate surcharge to collect approximately $3 million annually to fund futureconservation programs.

The IPUC had previously issuedOrder No. 28992 on April 15, 2002 disallowing the lost revenue portion of theIrrigation Load Reduction Program.  IPCbelieves that the IPUC's order is inconsistent with Order No. 28699, dated May25, 2001, that allowed recovery of such costs, and IPC filed a Petition forReconsideration on May 2, 2002.  OnAugust 29, 2002, the IPUC issued Order No. 29103 denying the Petition forReconsideration.  As a result of thisorder, approximately $12 million was expensed in September 2002.  IPC still believes it should be entitled toreceive recovery of this amount and has asked the Idaho Supreme Court to reviewthe IPUC's decision.  If successful, IPCwould record any amount recovered as revenue.

In the May 2001 PCA filing, IPCrequested recovery of $227 million of power supply costs.  The IPUC subsequently issued Order No. 28772authorizing recovery of $168 million, but deferring recovery of $59 millionpending further review.  The approvedamount resulted in an average rate increase of 31.6 percent.  After conducting hearings on the remaining$59 million, the IPUC in Order No. 28552 authorized recovery of $48 millionplus $1 million of accrued interest, beginning in October 2001.  The remaining $11 million not recovered inrates from the PCA filing was written off in September 2001.

In October 2001, IPC filed anapplication with the IPUC for an order approving inclusion in the 2002-2003 PCAof costs incurred for the Irrigation Load Reduction Program and the FMC/AstarisLoad Reduction Agreement.  These twoprograms were implemented in 2001 to reduce demand and were approved by theIPUC and the OPUC.  The costs incurredin 2001 for these two programs were $70 million for the Irrigation LoadReduction Program and $62 million for the FMC/Astaris Load ReductionAgreement.  The IPUC subsequently issuedOrder No. 28992 authorizing IPC to include direct costs it has accrued in theprograms, subject to later adjustments in the 2002-2003 PCA year.  As mentioned earlier, the IPUC also deniedIPC's request to recover lost revenues experienced from the Irrigation LoadReduction Program.

The May 2000 PCA rate adjustmentincreased Idaho general business customer rates by 9.5 percent, and resultedfrom forecasted below-average hydroelectric generating conditions.  Overall, the PCA adjustment increasedgeneral business revenue by approximately $38 million during the 2000-2001 rateperiod.

**Oregon: **IPC also filed applications with the OPUC torecover calendar year 2001 extraordinary power supply costs applicable to theOregon jurisdiction.  In two separate2001 orders, the OPUC approved rate increases totaling six percent, which isthe maximum annual rate of recovery allowed under Oregon state law.  These increases are recovering approximately$2 million annually.  The Oregondeferred balance is $14 million as of December 31, 2002.

**FMC/Astaris Settlement Agreement**On January 8, 2002, the IPUC initiated an investigation to examinethe load-reduction rates contained in the Voluntary Load Reduction (VLR)Agreement between IPC and FMC/Astaris. This VLR Agreement amended the Electric Service Agreement (ESA) thatgoverned the delivery of electric service to FMC/Astaris' Pocatello plant,which ceased operations late in 2001. On June 6, 2002, IPC and FMC/Astaris signed and filed a proposedStipulation and Settlement Agreement (Agreement) with the IPUC and on June 10,2002, the IPUC approved the Agreement in Order No. 29050 which included thefollowing provisions:

The VLRpayments that IPC would have made to FMC/Astaris through May 2003 weredecreased $5 million, reducing IPC's overall payments to $37 million.  Approximately 90 percent of this reduction willflow through the PCA mechanism as a reduction in costs to Idaho retailcustomers.

FMC/Astarisdismissed, with prejudice, a declaratory judgment action concerning theFMC/Astaris contract that it had previously filed against IPC in the FourthJudicial District for the State of Idaho.

FMC/Astariswill pay IPC approximately $31 million through March 2003 to settle the ESA.

IPC's need to purchase powerfrom the wholesale markets decreased during 2002 due to the ceased operation ofFMC/Astaris' Pocatello plant and settlement of the above mentioned ESA.

**Garnet Power Purchase Agreement**IPC and Garnet Energy LLC (Garnet), a wholly-owned subsidiary ofIda-West, entered into a power purchase agreement (PPA) on December 14, 2001for IPC to purchase energy produced by Garnet's proposed natural gas generationfacility.  IPC filed an application withthe IPUC for an order approving the PPA and an accounting order authorizing theinclusion in the PCA of power supply expenses associated with the purchase ofcapacity and energy from Garnet.  Priorto the actual hearing date, Garnet informed IPC that there was a substantiallikelihood that it would be unable to obtain the financing at acceptable termsnecessary to construct the facility.  

On July 24, 2002, the IPUC closedthe proceeding involving IPC's petition to enter into a PPA with Garnet anddirected IPC to return in 90 days with a report on the status of Garnet'sprogress in obtaining financing for the project and how IPC proposed to meetfuture power requirements if the Garnet facility is not built.  On October 30, 2002, IPC submitted itscompliance report to the IPUC, which included (1) Ida-West's notification thatdue to dramatic changes in the electricity industry, financing the project onacceptable terms under the PPA was impracticable, (2) Ida-West's offering ofthree alternatives to allow the project to go forward and (3) IPC's revisedplan for meeting future load requirements absent the PPA associated with theGarnet project, including wholesale power purchases, energy exchanges,obtaining certain transmission rights, or constructing or acquiring generationresources located in IPC's service territory. Following the IPUC's acceptanceof the 2002 IRP (see below), IPC continues to work on identifying and securingresources necessary to meet future power requirements.  The original Garnet PPA was mutuallyterminated on March 5, 2003; however, the site remains viable as a futuregeneration development.

Ida-West had capitalized $11million related to the Garnet project as of third quarter 2002.  During fourth quarter 2002, Ida-Westrecorded an $8 million partial write-down of its investment in equipment forthis project.  This partial write-downreflects the drop in prices for and increased availability of generatingequipment due to the collapse of the merchant power plant development business.

**Integrated Resource Plan**Every two years, IPC is required to file with the IPUC and OPUC anIRP, a comprehensive look at IPC's present and future demands for electricity andplans for meeting that demand.  The 2002IRP identified the need for additional resources to address potentialelectricity shortfalls within IPC's utility service territory by mid-2005.  The new resources expected to be in place atthat time were the previously identified 250 MW power purchase from the Garnetproject, an additional 100 MW generation resource to be determined and a 100 MWtransmission upgrade to increase import capability.  These resources would be used to satisfy energy demand during IPC'speak periods.  Prior to 2005, IPC willcontinue to use purchases from the energy markets as necessary to meetshort-term energy needs.

The IPUC Staff andseveral other interested parties filed comments responding to IPC's proposed2002 IRP.  The comments urge the IPUCnot to acknowledge the IRP until (1) the Garnet issue is resolved, and (2) IPCprovides additional detail on potential conservation measures that could beimplemented.  IPC filed replycomments on October 30, 2002 addressing those issues.  The above mentioned Garnet compliance report, submitted to theIPUC on October 30, 2002, was included in those reply comments byreference.  On February 11, 2003, theIPUC issued Order No. 29189, which accepted and acknowledged IPC's 2002 IRP asmodified and directed IPC to implement certain changes in its 2004 IRP relatedto both the public process and the evaluation of demand-side options.  The accepted IRP indicated the purchase of100 MW from the wholesale market for IPC's retail customers during June, July,November and December.  On February 24,2003, IPC issued a formal RFP seeking bids for the construction of up to 200 MWof additional generation to support the growing seasonal demand for electricityin IPC's service area.  Notice of anintent to bid must be submitted to IPC by March 14, 2003.

**Automatic Meter Reading**On February 21, 2003, the IPUC issued Order No. 29196 which directedIPC to submit a plan no later than March 20, 2003 to replace its existingmeters with advanced meters that are capable of both automated meter reading(AMR) and time-of-use pricing.  In itsorder, the IPUC indicated that implementation of AMR meters should begin in2003 and be completed in 2004.  IPC hasestimated it would cost approximately $76 million to install advanced meterswith AMR capability.  IPC intends tofile a Petition for Reconsideration of the IPUC's order and to request a stayof the requirement to file the March 20, 2003 plan.

**Nevada Jurisdiction**In 2001, the IPUC and the Public Utilities Commission of Nevadaapproved IPC's sale of its Nevada service territory to Raft River ElectricCo-Op (Raft River).  This saletransferred the distribution facilities and rights-of-way that serve about1,250 customers in northern Nevada and about 90 customers in southernIdaho.  The FERC approved a power supplyagreement between IPC and Raft River.

**Relicensing of HydroelectricProjects**IPC, like other utilities that operate nonfederal hydroelectricprojects, obtains licenses for its hydroelectric projects from the FERC. Theselicenses generally last for 30 to 50 years depending on the size and complexityof the project.  Currently, the licensesfor five hydro projects have expired. These projects continue to operate under annual licenses until the FERCissues a new permanent license.  Threemore hydro project licenses will expire by 2010.

IPC is actively pursuing therelicensing of these projects, a process that may continue for the next 10 to15 years. IPC has filed applications seeking renewal of licenses for the Bliss,Upper Salmon Falls, Lower Salmon Falls, CJ Strike, Shoshone Falls and Upper andLower Malad Hydroelectric projects. The licenses for the Hells Canyon Complex(Brownlee, Oxbow and Hells Canyon) and the Swan Falls Project expire in 2005and 2010, respectively. IPC is currently engaged in procedures necessary tofile timely license applications for these projects. Although various federaland state requirements and issues must be resolved through the license renewalprocess, IPC anticipates that it will relicense each of the eight projects.

Final Environmental ImpactStatements (EIS) have been issued for the Bliss, Upper Salmon Falls, LowerSalmon Falls and Shoshone Falls Projects. New FERC licenses are anticipated in 2003.  While the actual costs of protection, mitigation and enhancement(PM&E) measures and other costs associated with the relicensing of theprojects will not be known until the new license is issued by the FERC, costsassociated with these licenses (assuming 30-year licenses) are expected tototal approximately $8 million during the first five years of the licenses and$28 million over the following 25 years.

A final EIS has been issued forthe CJ Strike project and a new FERC license is expected in 2003.  While the actual costs of PM&E measuresand other costs associated with the relicensing of the project will not beknown until the new license is issued by the FERC, costs associated with thelicense (assuming a 30-year license) are expected to total approximately $9million during the first five years of the license and $38 million over thefollowing 25 years.

The four Mid-Snake Riverprojects, Bliss, Upper Salmon Falls, Lower Salmon Falls and Shoshone Falls, andthe CJ Strike projects, may affect five species of snails listed under the EndangeredSpecies Act.  See previous discussion in"LEGAL AND ENVIRONMENTAL ISSUES - Environmental Issues - Threatened andEndangered Snails."

The Upper and Lower Maladproject license expires in July 2004 and the new license application was filedin July 2002.  The application isproceeding through the normal FERC licensing process.  The application includes proposed PM&E measures estimated tototal (assuming a 30-year license) approximately $1 million during the firstfive years of the license and $3 million over the following 25 years.  However, the actual costs of PM&Emeasures and other costs associated with the relicensing of the project willnot be known until the new license is issued by the FERC.

The most significant relicensingeffort is the Hells Canyon Complex, which provides 68 percent of IPC's hydrogeneration capacity and 40 percent of its total generating capacity.  IPC developed its draft license applicationwith the assistance of a collaborative team made up of individuals representingstate and federal agencies, businesses, environmental, tribal, customer, localgovernment and local landowner interests. The draft license application was issued in September 2002 and the finalapplication will be filed in July 2003. The draft application includes proposed PM&E measures estimated tototal approximately (assuming a 30-year license) $78 million during the firstfive years of the license and $100 million during the following 25 years.  However, the actual costs of PM&Emeasures and other costs associated with the relicensing of the project willnot be known until the new license is issued by the FERC.

At December 31, 2002, $50million of pre-relicensing costs were included in Construction Work in Progress(CWIP) and $6 million of pre-relicensing costs were included in Electric Plantin Service.  The pre-relicensing costsare recorded and held in CWIP until a new permanent license or annual licenseis issued by the FERC, at which time the charges are transferred to ElectricPlant in Service.  Pre-relicensing costsas well as costs related to the new licenses, as referenced above, will besubmitted to regulators for recovery through the rate-making process.

**Regional TransmissionOrganizations**In December 1999, the FERC, in its landmark Order No. 2000, saidthat all companies with transmission assets must file to form RegionalTransmission Organizations (RTOs) or explain why they cannot.  Order No. 2000 is a follow up to Order Nos.888 and 889 issued in 1996, which required transmission owners to providenon-discriminatory transmission service to third parties.  By encouraging the formation of RTOs, theFERC seeks to further facilitate the formation of efficient, competitivewholesale electricity markets.

In October 2000 and March 2002,in response to FERC Order No. 2000, IPC and other regional transmission ownersfiled Stage One and Stage Two plans to form RTO West, an entity that willoperate the transmission grid in seven western states.  RTO West will have its own independentgoverning board.  The participatingtransmission owners will retain ownership of the lines, but will not have arole in operating the grid.

These FERC filings represent aportion of the filing necessary to form RTO West.  However, substantial additional filings will be necessary toinclude the tariff and integration agreements associated with the newentity.  State approvals also need to beobtained.  In September 2002, the FERCissued an order granting in part RTO West's Stage Two request for a declaratoryorder, approving with modification the majority of the proposed plan fordevelopment of a RTO by ten utilities in the northwest and Canada and theBPA.  IPC is one of the filingutilities.  With further development ofdetail and some modification, the FERC stated that the proposal "willsatisfy not only the Order No. 2000 requirements, but can also provide a basicframework for standard market design for the west".  Further development of the RTO West proposalby the filing utilities continues.

In July 2002, the FERC issued aNotice of Proposed Rulemaking (NOPR) on Standard Market Design for regulatedutilities.  If implemented as proposed,the NOPR will substantially change how wholesale markets operate throughout theUnited States.  The proposed rulemakingexpands the FERC's intent to unbundle transmission operations from integratedutilities and ensure robust competition in wholesale markets.  The proposed rule contemplates that allwholesale and retail customers will be on a single network transmission servicetariff.  The proposed rule alsocontemplates the implementation of a bid-based system for buying and sellingenergy in wholesale markets to manage congestion.  The market would be administered by RTOs, or Independent TransmissionProviders.  RTOs would also be responsiblefor putting together regional plans that identify opportunities to constructnew transmission, generation or demand-side programs to reduce transmissionconstraints and meet regional energy requirements.  Finally, the proposed rule envisions the development of regionalmarket monitors responsible for ensuring that individual participants do notexercise unlawful market power. Comments to the proposed rules were due during the last months of 2002and additional comments are due the first part of 2003.  The FERC currently anticipates that thefinal rules will be in place in mid-2003 and the contemplated market changeswill take place in 2003 and 2004.

**OTHER MATTERS:**

**New Accounting Pronouncements**In June 2001, the FASBissued SFAS 143, "Accounting for Asset Retirement Obligations," whichaddresses financial accounting and reporting for obligations associated withthe retirement of tangible long-lived assets and the associated assetretirement costs.  An obligation mayresult from the acquisition, construction, development and the normal operationof a long-lived asset.  SFAS 143requires 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,the entity increases the carrying amount of the related long-lived asset toreflect the future retirement cost. Over time, the liability is accreted to its present value and paid, andthe capitalized cost is depreciated over the useful life of the relatedasset.  If at the end of the asset'slife the recorded liability differs from the actual obligations paid, a gain orloss would be recognized at that time. As a rate-regulated entity, IPC expects to record regulatory assets andliabilities instead of accretion, depreciation and gains or losses, if thecriteria for such treatment are met. SFAS 143 is effective beginning in 2003.

A detailed assessment of the applicability and implications of SFAS 143has been performed.  AROs related toIPC's three jointly owned coal-fired generation facilities, its transmissionand distribution facilities and the Bridger Coal mine, which is owned by anequity-method investee have been identified. When adopted in 2003, IPC expects to record ARO liabilities of $12 millionand fixed assets of $6 million, with the offset to regulatory assets.  These amounts do not include an amount forthe transmission and distribution facilities, because, based on theindeterminate life of these assets, an ARO calculation cannot be made.

In June 2002, the FASB issued SFAS 146, "Accounting for CostsAssociated with Exit or Disposal Activities."  The standard requires companies to recognize costs associatedwith exit or disposal activities when they are incurred, rather than at thedate of a commitment to an exit or disposal plan.  Examples of costs covered by the standard include leasetermination costs and certain employee severance costs that are associated witha restructuring, discontinued operation, plant closing or other exit or disposalactivity.  This standard supersedes EITFIssue No. 94-3, "Liability Recognition for Certain Employee TerminationBenefits and Other Costs to Exit an Activity (including Certain Costs Incurredin a Restructuring)."  SFAS 146 isto be applied prospectively to exit or disposal activities initiated afterDecember 31, 2002.  The adoption of SFAS146 is not expected to have a material effect on IDACORP or IPC's financialstatements.

EITF Issue No. 02-3, "Issues Involved in Accounting for DerivativeContracts Held for Trading Purposes and Contracts Involved in Energy Tradingand Risk Management Activities," reached a consensus to rescindEITF 98-10, the impact of which is to preclude mark-to-market accounting forall energy trading contracts not within the scope of SFAS 133.  The consensus regarding the rescission ofEITF 98-10 is applicable for fiscal periods beginning after December 15,2002.  Energy trading contracts notwithin the scope of SFAS 133 that are purchased after October 25, 2002, butprior to the implementation of the consensus, are not permitted to applymark-to-market accounting.  In addition,effective on January 1, 2003, all energy trading contracts previously accountedfor at fair value under EITF 98-10 must be adjusted to historical cost unlessthose contracts meet the definition of a derivative under SFAS 133.  This adjustment will be recorded as acumulative effect of adoption of a new accounting principle.  The rescission of EITF 98-10 will not have amaterial effect on IDACORP or IPC's financial statements, as substantially allof their energy trading contracts meet the definition of a derivative underSFAS 133.

EITF 02-3 also reached aconsensus that gains and losses on derivative instruments within the scope ofSFAS 133 should be shown net in the income statement if the derivativeinstruments are held for trading purposes. In anticipation of this requirement, IDACORP has elected to change itspresentation of energy trading activities from gross to net presentation, inaccordance with the option allowed under EITF 98-10.  Prior periods have been reclassified to conform to currentpresentation.   Therefore operatingrevenues for the energy marketing segment include revenues from the sale ofelectricity and gas netted against the cost of purchased power and naturalgas.  Additionally, all financialtransactions and unrealized income are presented on a net basis as operatingrevenue.  Operating expenses include generaland administrative expenses, bad debt reserves, transmission expenses andbroker fees.  The net financial positionand results of operations of IDACORP were not affected by this change inpresentation.

In November 2002 the FASB issuedInterpretation No. 45, "Guarantor's Accounting and Disclosure Requirementsfor Guarantees, Including Indirect Guarantees of Indebtedness ofOthers."  This Interpretationelaborates on the disclosures to be made by a guarantor in its interim andannual financial statements about its obligations under certain guarantees thatit has issued. It also clarifies that a guarantor is required to recognize, atthe inception of a guarantee, a liability for the fair value of the obligationundertaken in issuing the guarantee. The initial recognition and initial measurement provisions of thisInterpretation are applicable on a prospective basis to guarantees issued ormodified after December 31, 2002, irrespective of the guarantor's fiscalyear-end. The disclosure requirements in this Interpretation are effective forfinancial statements of interim or annual periods ending after December 15,2002.  The adoption of thisInterpretation is not expected to have a material effect on IDACORP and IPC'sfinancial statements.

In January 2003,the FASB issued Interpretation No. 46, "Consolidation of Variable InterestEntities."  This Interpretationclarifies the application of Accounting Research Bulletin No. 51,"Consolidated Financial Statements," to certain entities in whichequity investors do not have the characteristics of a controlling financialinterest or in which equity investors do not bear the residual economicrisks.  The Interpretation applies tovariable interest entities in which an enterprise obtains an interest afterthat date.  It applies in the fiscalyear or interim period beginning after June 15, 2003 to variable interestentities in which an enterprise holds a variable interest that was acquiredbefore February 1, 2003.  IDACORP andIPC have determined that it is not reasonably possible that they will be requiredto consolidate or disclose information about a variable interest entity uponthe effective date of this Interpretation.

**ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK**

IDACORP and IPCare exposed to various market risks, including changes in interest rates,changes in certain commodity prices, credit risk and equity price risk.  The following discussion summarizes theserisks and the financial instruments, derivative instruments and derivativecommodity instruments sensitive to changes in interest rates, commodity pricesand equity prices that were held at December 31, 2002.

**Interest Rate Risk**IDACORP and IPC are exposed to changes in interest rates through theissuance of fixed-rate and variable-rate debt. The following table summarizes the carrying amount and interest rates byexpected maturity date of debt obligations at December 31, 2002 (in thousandsof dollars):

 

 

**Fair value**

 

 

**at**

 

 

**December**

 

**2003**

**2004**

**2005**

**2006**

**2007**

**Thereafter**

**Total**

**31, 2002**

**IDACORP,  Inc.**

 

 

 

 

 

 

 

 

**Short-term  debt:**

 

 

 

 

 

 

 

 

Fixed  rate debt

$176,200

-

-

-

-

-

$176,200

$176,200

Average  interest rate

1.8%

-

-

-

-

-

1.8%

 

**Long-term  debt:**

 

 

 

 

 

 

 

 

Variable  rate debt

-

-

-

-

-

$ 72,445

$ 72,445

$   72,445

Average  interest rate

-

-

-

-

-

2.2%

2.2%

 

Fixed  rate debt

$ 89,592

$ 58,522

$ 67,275

$ 5,731

$ 84,933

$609,770

$915,823

$981,733

Average  interest rate

6.4%

7.9%

6.0%

7.2%

7.4%

6.5%

6.6%

 

 

 

 

 

 

 

 

 

 

**Idaho Power Company**

 

 

 

 

 

 

 

 

**Short-term debt:**

 

 

 

 

 

 

 

 

Fixed rate debt

$ 10,500

-

-

-

-

-

$ 10,500

$  10,500

Average interest rate

1.7%

-

-

-

-

-

1.7%

 

**Long-term debt:**

 

 

 

 

 

 

 

 

Variable rate debt

-

-

-

-

-

$  72,445

$ 72,445

$  72,445

Average interest rate

-

-

-

-

-

2.2%

2.2%

 

Fixed rate debt

$  80,084

$  50,077

$  60,079

$      82

$ 81,228

$606,830

$878,380

$942,167

Average interest rate

6.4%

8.0%

5.8%

2.5%

7.4%

6.5%

6.6%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

The majority of debt is held infixed rate securities with embedded call options.  By nature, the market value of variable rate debt is notsensitive to changes in interest rates, and short-term borrowings do not giverise to significant interest rate risk because they generally have maturitiesof less than three months.

**Commodity Price Risk****Utility:**  IPCis exposed to changes in commodity prices related to the purchases and sales ofelectricity as part of its ongoing utility operations.  IPC is exposed to this risk to the extentthat a portion of the electric energy it is required to sell to its customersat fixed rates may be purchased at wholesale electric market prices, which canbe higher than the fixed sales rate received. IPC's exposure to this risk is offset to some extent by the previouslydiscussed PCA mechanism in place in Idaho. The objective of IPC's market price risk management program is tomitigate the risk associated with the purchase and sale of electricity, whilebalancing this risk against system reliability and cost considerations.

IPC has adopted arisk management policy to address commodity price risk.  The Risk Management Committee (RMC),comprised of IPC officers and other senior staff, oversees the risk managementprogram.  On a regular basis, the RMCreviews multiple system resource and load projections and evaluates thepotential impacts of changes in four key variables, wholesale prices, systemloads, system resources and streamflow conditions.  The RMC controls the risk by assessing the impact of changes inthe variables on power supply cost and projected volumetric surplus and deficitdata, and by reviewing forward price curves for electricity and gas. The RMCthen orders an appropriate risk mitigating action.  Actions may be undertaken only with creditworthy counterparties.

On August 1,2002, due to the wind down of energy marketing, all utility-related wholesaleenergy and gas transaction processes were returned to IPC.  These activities are focused on meetingsystem requirements and capitalizing on system-related opportunities that canbe risk managed.

**EnergyTrading:**  IE buys and sells financial and physicalnatural gas and electricity commodity contracts as part of its business, exposingIE to electricity and natural gas commodity price risk as well as interest raterisk.  IE has a risk management policydefining the limits within which it contains its commodity price risk.  IE trades commodity futures, forwards,options and swaps as a method of managing the commodity price risk andoptimizing the profitability of its electricity and natural gas trading.  IE also transacts in interest rate futuresand swaps to manage the interest rate risk embedded in its commodity portfolio.

When buying andselling energy, the volatility of energy prices can have a significant negativeimpact on profitability if not appropriately managed.  Also, counterparty creditworthiness is key to ensuring thattransactions entered into can withstand potentially dramatic marketfluctuations.  To manage the risksinherent in the energy commodity industry, IE's RMC, comprised of IDACORP andIE officers, oversees IE's risk management program as defined in the riskmanagement policy.  The objective ofIE's risk management program is to manage the risk associated with the purchaseand sale of natural gas and electricity - within levels established by theRMC.  IE's policy also allows the use ofthese commodity derivative instruments for trading purposes in support of itsoperations.

The value-at-risk(VAR) measure is a tool used by IE's RMC to understand on a daily basis thepotential impact on earnings arising from changes in market prices.

The December 31,2002, VAR for energy marketing operations is approximately $1 million at both a95 and 99 percent confidence level and for a holding period of one businessday.  The average VAR for 2002 at a 95percent confidence level and one-day holding period was $1 million.  The VAR was calculated using an analytic VARmethodology. This methodology computes VAR based upon positions and forwardmarket prices as of December 31, 2002, and historical forward price volatilityand correlation. The VAR is understood to be a forecast and is not guaranteedto occur. The 95 percent confidence level and one-day holding period imply thatthere is a five percent chance that the daily loss will exceed approximately $1million.  The 99 percent confidencelevel implies a one percent chance that daily loss will exceed $1 million.  The VAR calculation is principally affectedby market prices and volatility of prices. The RMC actively manages the risk to keep IE's trading activities withintrading limits.

**Credit Risk****Utility:**  IPCis subject 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, using appropriate contractual arrangements and transferring ofcredit risk through the use of financial guarantees, cash or letters of credit. A current list of acceptable counterpartiesand credit limits is maintained.

**EnergyTrading:**  IE is exposed to counterparty credit risk aspart of its energy trading business. This risk is defined as exposure todecreases in expected earnings or cash flow when a counterparty to an energycommodity contract cannot or will not pay or deliver. To manage counterpartycredit risk within acceptable levels, the RMC has established credit risklimits for each counterparty. Credit risk exposure is measured and reporteddaily to members of the RMC. In order to provide further protection from acounterparty's deteriorating creditworthiness, IE utilizes industry standardagreements containing various protective creditworthiness provisions. Othertools used to manage credit risk are the holding of collateral in the form of cashor letters of credit and the use of margining agreements with counterpartieswhen credit risk exceeds certain pre-determined thresholds.  Because of the volatile nature of energymarket prices, margining agreements can require the posting of large amounts ofcash between counterparties to hold as collateral against the value of theenergy contracts.  This practicemitigates credit risk but increases the need for cash or other liquidsecurities to ensure the ability to meet all margin requirements when themarkets are most volatile.

At year-end 2002,63 percent of the credit exposure related to IE's unrealized positions was withinvestment grade counterparties. Two percent was with non-investment gradecounterparties and the remaining 35 percent was with non-ratedcounterparties.  The majority of thenon-rated entities are municipalities, public utility districts and electriccooperatives. Nearly 50 percent of IE's total credit exposure is to oneinvestment grade counterparty under a contract with less than two yearsremaining.  The following table presentsthe maturity of credit risk exposure for energy marketing at December 31 2002:

 

**Less than**

 

**2-5**

 

**More than**

 

 

 

**2 Years**

 

**Years**

 

**5 Years**

 

**Total**

Investment  Grade

$

116,880

 

$

0

 

$

0

 

$

116,880

Non-Investment  Grade

 

871

 

 

3,603

 

 

0

 

 

4,474

No  External Ratings

 

57,003

 

 

7,476

 

 

1,110

 

 

65,589

 

Total

$

174,754

 

$

11,079

 

$

1,110

 

$

186,943

 

 

 

 

 

 

 

 

 

 

 

 

 

 

**Equity Price Risk**IDACORP and IPC are exposedto price fluctuations in equity markets, primarily through their pension planassets, a mine reclamation trust fund owned by an equity-method investment ofIPC, and other equity investments at IPC. A hypothetical ten percent decrease in equity prices would result in anapproximate $2 million decrease in the fair value of financial instruments thatare classified as available-for-sale securities.

**ITEM 8.  FINANCIALSTATEMENTS AND SUPPLEMENTARY DATA**

**INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENTSCHEDULES**

 

**PAGE**

**Consolidated  Financial Statements:**

 

IDACORP, Inc.

 

Consolidated Statements of Income for the Years Ended  December 31, 2002, 2001 and 2000

53

Consolidated Balance Sheets as of December 31, 2002 and  2001

54-55

Consolidated Statements of Cash Flows for the Years  Ended December 31, 2002, 2001 and 2000

56

Consolidated Statement of Shareholders' Equity for the  Years Ended December 31, 2002, 2001

 

 

and 2000

57

Consolidated Statements of Comprehensive Income for the  Years Ended December 31, 2002,

 

 

2001 and 2000

58

Notes to the Consolidated Financial Statements

59-88

Independent Auditors' Report

89

 

 

Idaho Power Company

 

Consolidated Statements of Income for the Years Ended  December 31, 2002, 2001 and 2000

91

Consolidated Balance Sheets as of December 31, 2002 and  2001

92-93

Consolidated Statements of Capitalization as of December  31, 2002 and 2001

94

Consolidated Statements of Cash Flows for the Years  Ended December 31, 2002, 2001 and 2000

95

Consolidated Statement of Retained Earnings for the  Years Ended December 31, 2002, 2001

 

 

and 2000

96

Consolidated Statements of Comprehensive Income for  the Years Ended December 31, 2002,

 

 

2001 and 2000

96

Notes to the Consolidated Financial Statements

97-100

Independent Auditors' Report

101

 

 

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

 

Supplemental Financial Information (Unaudited)

102

 

 

Financial Statement Schedules for the Years Ended  December 31, 2002, 2001 and 2000:

 

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

110

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

111

 

 

 

 

 

**(Thispage intentionally left blank.)**

 

 

 

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

 

**Year Ended December 31,**

 

**2002**

 

**2001**

 

**2000**

 

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

**OPERATING REVENUES:**

 

 

 

 

 

 

 

 

 

Electric utility:

 

 

 

 

 

 

 

 

 

 

General business

$

772,035 

 

$

650,608 

 

$

565,357 

 

 

Off-system sales

 

55,031 

 

 

219,966 

 

 

229,986 

 

 

Other revenues

 

41,974 

 

 

43,627 

 

 

41,663 

 

 

 

Total electric utility revenues

 

869,040 

 

 

914,201 

 

 

837,006 

 

Energy marketing 

 

46,410 

 

 

348,663 

 

 

190,116 

 

Other

 

13,350 

 

 

12,448 

 

 

22,663 

 

 

Total operating revenues

 

928,800 

 

 

1,275,312 

 

 

1,049,785 

 

 

 

 

 

 

 

 

 

**OPERATING EXPENSES:**

 

 

 

 

 

 

 

 

 

Electric utility:

 

 

 

 

 

 

 

 

 

 

Purchased power

 

142,102 

 

 

584,209 

 

 

398,649 

 

 

Fuel expense

 

102,871 

 

 

98,318 

 

 

94,215 

 

 

Power cost adjustment

 

170,489 

 

 

(175,925)

 

 

(120,688)

 

 

Other operations and maintenance

 

207,355 

 

 

210,763 

 

 

194,870 

 

 

Depreciation

 

93,609 

 

 

87,041 

 

 

80,287 

 

 

Taxes other than income taxes

 

19,953 

 

 

19,693 

 

 

20,166 

 

 

 

Total electric utility expenses

 

736,379 

 

 

824,099 

 

 

667,499 

 

Energy marketing:

 

 

 

 

 

 

 

 

 

 

Cost of revenues

 

42,113 

 

 

105,904 

 

 

44,785 

 

 

Selling, general and administrative

 

28,036 

 

 

66,047 

 

 

50,811 

 

Other

 

36,177 

 

 

36,973 

 

 

39,380 

 

 

 

Total operating expenses

 

842,705 

 

 

1,033,023 

 

 

802,475 

 

 

 

 

 

 

 

 

 

**OPERATING INCOME (LOSS):**

 

 

 

 

 

 

 

 

 

Electric utility

 

132,661 

 

 

90,102 

 

 

169,507 

 

Energy marketing

 

(23,739)

 

 

176,712 

 

 

94,520 

 

Other

 

(22,827)

 

 

(24,525)

 

 

(16,717)

 

 

Total operating income

 

86,095 

 

 

242,289 

 

 

247,310 

 

 

 

 

 

 

 

 

 

**OTHER INCOME (EXPENSE)**

 

(6,991)

 

 

23,294 

 

 

30,317 

 

 

 

 

 

 

 

 

 

**INTEREST EXPENSE AND OTHER:**

 

 

 

 

 

 

 

 

 

Interest on long-term debt

 

54,147 

 

 

55,783 

 

 

53,356 

 

Other interest

 

9,845 

 

 

14,540 

 

 

7,641 

 

Preferred dividends of Idaho Power Company

 

4,587 

 

 

5,400 

 

 

5,929 

 

 

Total interest expense and other

 

68,579 

 

 

75,723 

 

 

66,926 

 

 

 

 

 

 

 

 

 

**INCOME BEFORE INCOME TAXES**

 

10,525 

 

 

189,860 

 

 

210,701 

 

 

 

 

 

 

 

 

 

**INCOME TAX EXPENSE (BENEFIT)**

 

(51,147)

 

 

64,646 

 

 

70,818 

 

 

 

 

 

 

 

 

 

**NET INCOME**

$

61,672 

 

$

125,214 

 

$

139,883 

 

 

 

 

 

 

 

 

 

**AVERAGE COMMON SHARES**

 

 

 

 

 

 

 

 

 

**OUTSTANDING (000's)**

 

37,729 

 

 

37,387 

 

 

37,556 

 

 

 

 

 

 

 

 

 

**EARNINGS PER SHARE OF COMMON**

 

 

 

 

 

 

 

 

 

**STOCK (basic and diluted)**

$

1.63 

 

$

3.35 

 

$

3.72 

 

 

 

 

 

 

 

 

 

Theaccompanying notes are an integral part of these statements.

 

 

 

 

 

 

 

**IDACORP, Inc.Consolidated Balance Sheets**

 

**December 31,**

 

**2002**

 

**2001**

**ASSETS**

**(thousands of dollars)**

 

 

 

 

**CURRENT ASSETS:**

 

 

 

 

 

 

Cash and cash equivalents

$

42,736 

 

$

66,688 

 

Receivables:

 

 

 

 

 

 

 

Customer

 

176,846 

 

 

207,223 

 

 

Allowance for uncollectible accounts

 

(43,311)

 

 

(42,529)

 

 

Employee notes

 

7,646 

 

 

6,274 

 

 

Other

 

15,025 

 

 

11,074 

 

Energy marketing assets

 

85,138 

 

 

193,615 

 

Taxes receivable

 

- 

 

 

51,190 

 

Accrued unbilled revenues

 

35,714 

 

 

37,400 

 

Materials and supplies (at average cost)

 

22,812 

 

 

26,309 

 

Fuel stock (at average cost)

 

6,943 

 

 

8,726 

 

Prepayments

 

34,329 

 

 

32,064 

 

Regulatory assets

 

17,147 

 

 

55,107 

 

 

Total current assets

 

401,025 

 

 

653,141 

 

 

 

 

 

 

**INVESTMENTS**

 

206,348 

 

 

158,863 

 

 

 

 

 

 

**PROPERTY, PLANT AND EQUIPMENT:**

 

 

 

 

 

 

Utility plant in service

 

3,086,965 

 

 

2,989,630 

 

Accumulated provision for depreciation

 

(1,294,961)

 

 

(1,220,002)

 

 

Utility plant in service - net

 

1,792,004 

 

 

1,769,628 

 

Construction work in progress

 

96,209 

 

 

95,788 

 

Utility plant held for future use

 

2,335 

 

 

2,232 

 

Other property, net of accumulated depreciation

 

15,950 

 

 

18,661 

 

 

Property, plant and equipment - net

 

1,906,498 

 

 

1,886,309 

 

 

 

 

 

 

**OTHER ASSETS:**

 

 

 

 

 

 

American Falls and Milner water rights

 

31,585 

 

 

31,585 

 

Company-owned life insurance

 

35,299 

 

 

39,602 

 

Energy marketing assets - long-term

 

64,733 

 

 

203,532 

 

Regulatory assets

 

482,159 

 

 

544,135 

 

Long-term receivables

 

73,941 

 

 

73,941 

 

Other

 

51,050 

 

 

51,206 

 

 

Total other assets

 

738,767 

 

 

944,001 

 

 

 

 

 

 

 

 

**TOTAL**

$

3,252,638 

 

$

3,642,314 

 

 

 

 

 

 

The accompanying notes are an integral partof these statements.

** **

** **

** **

** **

** **

**IDACORP, Inc.Consolidated Balance Sheets**

 

**December 31,**

 

**2002**

 

**2001**

**LIABILITIES AND SHAREHOLDERS' EQUITY**

**(thousands of dollars)**

 

 

 

 

**CURRENT LIABILITIES:**

 

 

 

 

 

 

Current maturities of long-term debt

$

89,592 

 

$

36,567 

 

Notes payable

 

176,200 

 

 

362,500 

 

Accounts payable

 

130,930 

 

 

248,231 

 

Energy marketing liabilities

 

59,917 

 

 

125,317 

 

Derivative liabilities

 

- 

 

 

40,528 

 

Taxes accrued

 

49,709 

 

 

- 

 

Interest accrued

 

13,639 

 

 

14,805 

 

Deferred income taxes

 

21,527 

 

 

23,761 

 

Other

 

35,119 

 

 

55,445 

 

 

Total current liabilities

 

576,633 

 

 

907,154 

 

 

 

 

 

 

**OTHER LIABILITIES:**

 

 

 

 

 

 

Deferred income taxes

 

595,496 

 

 

589,873 

 

Energy marketing liabilities - long-term

 

51,761 

 

 

135,399 

 

Regulatory liabilities

 

114,247 

 

 

113,956 

 

Derivative liabilities - long-term

 

- 

 

 

7,253 

 

Other

 

87,605 

 

 

69,810 

 

 

Total other liabilities

 

849,109 

 

 

916,291 

 

 

 

 

 

 

**LONG-TERM DEBT**

 

898,676 

 

 

842,481 

 

 

 

 

 

 

**COMMITMENTS AND CONTINGENT LIABILITIES**

 

 

 

 

 

 

 

 

 

 

 

**PREFERRED STOCK OF IDAHO  POWER COMPANY**

 

53,393 

 

 

104,387 

 

 

 

 

 

 

**SHAREHOLDERS' EQUITY:**

 

 

 

 

 

 

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

 

 

 

 

 

 

 

38,152,436 and 37,628,919 shares issued, respectively)

 

470,361 

 

 

454,197 

 

Retained earnings

 

415,315 

 

 

424,349 

 

Accumulated other comprehensive income (loss)

 

(7,109)

 

 

(3,719)

 

Treasury stock (134,667 and 66,188 shares at cost, respectively)

 

(3,740)

 

 

(2,826)

 

 

Total shareholders' equity

 

874,827 

 

 

872,001 

 

 

 

 

 

 

 

 

 

**TOTAL**

$

3,252,638 

 

$

3,642,314 

 

 

 

 

 

 

The accompanying notes are an integral partof these statements.

 

 

 

 

 

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

 

 

**Year Ended December 31,**

 

 

**2002**

 

**2001**

 

**2000**

 

 

**(thousands of dollars)**

**OPERATING ACTIVITIES:**

 

 

Net income

$

61,672 

 

$

125,214 

 

$

139,883 

 

Adjustments to reconcile  net income to net cash provided by

 

 

 

 

 

 

 

 

 

(used in) operating  activities:

 

 

 

 

 

 

 

 

 

 

Other than temporary  decline in market value of investments

 

980 

 

 

- 

 

 

- 

 

 

Impairment of long-lived  asset

 

8,064 

 

 

- 

 

 

- 

 

 

Allowance for uncollectible  accounts

 

782 

 

 

19,450 

 

 

21,682 

 

 

Unrealized (gains) losses  from energy marketing activities

 

65,965 

 

 

(92,803)

 

 

34,865 

 

 

Gain on sales of assets

 

- 

 

 

(1,605)

 

 

(14,000)

 

 

Depreciation and  amortization

 

122,831 

 

 

109,976 

 

 

103,971 

 

 

Deferred taxes and  investment tax credits

 

(110,666)

 

 

152,938 

 

 

46,718 

 

 

Accrued PCA costs

 

164,201 

 

 

(184,584)

 

 

(122,353)

 

 

Change in:

 

 

 

 

 

 

 

 

 

 

 

Receivables and prepayments

 

27,130 

 

 

32,077 

 

 

(178,864)

 

 

 

Accrued unbilled revenues

 

1,687 

 

 

7,425 

 

 

(12,831)

 

 

 

Materials and supplies and  fuel stock

 

3,645 

 

 

- 

 

 

4,104 

 

 

 

Accounts payable and other  accrued liabilities

 

(145,868)

 

 

3,914 

 

 

125,704 

 

 

 

Taxes receivable/accrued

 

98,970 

 

 

(66,821)

 

 

(5,682)

 

 

 

Other current assets and  liabilities

 

40,614 

 

 

(49,073)

 

 

(1,417)

 

 

 

Long-term receivable

 

- 

 

 

(73,706)

 

 

- 

 

 

Other - net

 

7,581 

 

 

9,615 

 

 

(8,145)

 

 

Net cash provided by (used  in) operating activities

 

347,588 

 

 

(7,983)

 

 

133,635 

 

 

 

 

 

 

 

 

 

**INVESTING ACTIVITIES:**

 

 

 

 

 

 

 

 

 

Additions to property,  plant and equipment

 

(134,223)

 

 

(179,056)

 

 

(140,302)

 

Investments in affordable  housing projects

 

(43,939)

 

 

- 

 

 

(29,166)

 

Proceeds from sales of  assets

 

- 

 

 

11,261 

 

 

17,500 

 

Other - net

 

(8,338)

 

 

(3,030)

 

 

(642)

 

 

Net cash used in investing  activities

 

(186,500)

 

 

(170,825)

 

 

(152,610)

 

 

 

 

 

 

 

 

 

**FINANCING ACTIVITIES:**

 

 

 

 

 

 

 

 

 

Proceeds from issuance of  first mortgage bonds

 

200,000 

 

 

120,000 

 

 

80,000 

 

Proceeds from issuance of  other long-term debt

 

- 

 

 

- 

 

 

14,381 

 

Retirement of first  mortgage bonds

 

(77,000)

 

 

(130,000)

 

 

(80,000)

 

Retirement of other  long-term debt

 

(12,403)

 

 

(14,454)

 

 

(22,427)

 

Retirement of preferred  stock of Idaho Power Company

 

(50,994)

 

 

(679)

 

 

- 

 

Dividends on common stock

 

(70,178)

 

 

(69,782)

 

 

(69,850)

 

Increase (decrease) in  short-term borrowings

 

(186,300)

 

 

241,900 

 

 

100,843 

 

Common stock issued

 

15,770 

 

 

618 

 

 

- 

 

Acquisition of treasury  shares

 

(998)

 

 

(7,968)

 

 

(8,014)

 

Distributions of treasury  shares

 

- 

 

 

2,575 

 

 

- 

 

Other - net

 

(2,937)

 

 

(3,509)

 

 

(501)

 

 

Net cash provided by (used  in) financing activities

 

(185,040)

 

 

138,701 

 

 

14,432 

 

 

 

 

 

 

 

 

 

Net increase (decrease) in  cash and cash equivalents

 

(23,952)

 

 

(40,107)

 

 

(4,543)

 

 

 

 

 

 

 

 

 

Cash and cash equivalents  beginning of period

 

66,688 

 

 

106,795 

 

 

111,338 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents  at end of period

$

42,736 

 

$

66,688 

 

$

106,795 

 

 

 

 

 

 

 

 

 

**SUPPLEMENTAL DISCLOSURE OF  CASH FLOW  INFORMATION:**

 

Cash paid (received) during  the period for:

 

 

 

 

 

 

 

 

 

 

Income taxes

$

(39,678)

 

$

(17,766)

 

$

29,830 

 

 

Interest (net of amount  capitalized)

$

62,665 

 

$

70,052 

 

$

61,825 

 

Distribution of treasury  shares for acquisition

$

- 

 

$

7,532 

 

$

1,630 

 

 

 

 

 

 

 

 

 

 

The accompanying notes are an integral partof these statements.

 

 

 

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

 

 

 

 

 

 

 

 

 

**Accumulated**

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

**Other**

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

**Compre-**

 

 

 

 

 

 

 

 

 

**Common  Stock**

 

**Retained**

 

**hensive**

 

**Treasury  Stock**

 

**Total**

 

**Shares**

 

**Amount**

 

**Earnings**

 

**Income**

 

**Shares**

 

**Amount**

 

**Amount**

 

 

 

 

 

 

 

**(Loss)**

 

 

 

 

 

 

 

**(thousands)**

Balance at January 1,

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2000

37,612

 

$

451,343 

 

$

300,093 

 

$

1,533 

 

- 

 

$

- 

 

$

752,969 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income

-

 

 

- 

 

 

139,883 

 

 

- 

 

- 

 

 

- 

 

 

139,883 

Common stock dividends

-

 

 

- 

 

 

(69,850)

 

 

- 

 

- 

 

 

- 

 

 

(69,850)

Issued

-

 

 

- 

 

 

- 

 

 

- 

 

(155)

 

 

6,518 

 

 

6,518 

Acquired

-

 

 

- 

 

 

- 

 

 

- 

 

199 

 

 

(8,014)

 

 

(8,014)

Other

-

 

 

1,759 

 

 

- 

 

 

- 

 

- 

 

 

- 

 

 

1,759 

Unrealized loss on

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

securities (net of tax)

-

 

 

- 

 

 

- 

 

 

(2,335)

 

- 

 

 

- 

 

 

(2,335)

Minimum pension 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

liability adjustment

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(net of tax)

-

 

 

- 

 

 

- 

 

 

(119)

 

- 

 

 

- 

 

 

(119)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance at December 31,

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2000

37,612

 

 

453,102 

 

 

370,126 

 

 

(921)

 

44 

 

 

(1,496)

 

 

820,811 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income

-

 

 

- 

 

 

125,214 

 

 

- 

 

- 

 

 

- 

 

 

125,214 

Common stock dividends

-

 

 

- 

 

 

(69,782)

 

 

- 

 

- 

 

 

- 

 

 

(69,782)

Issued

17

 

 

618 

 

 

- 

 

 

- 

 

(292)

 

 

11,527 

 

 

12,145 

Acquired

-

 

 

- 

 

 

- 

 

 

- 

 

314 

 

 

(12,857)

 

 

(12,857)

Other

-

 

 

477 

 

 

(1,209)

 

 

- 

 

- 

 

 

- 

 

 

(732)

Unrealized loss on

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

securities (net of tax)

-

 

 

- 

 

 

- 

 

 

(1,770)

 

- 

 

 

- 

 

 

(1,770)

Minimum pension

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

liability adjustment

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(net of tax)

-

 

 

- 

 

 

- 

 

 

(1,028)

 

- 

 

 

- 

 

 

(1,028)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance at December 31,

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2001

37,629

 

 

454,197 

 

 

424,349 

 

 

(3,719)

 

66 

 

 

(2,826)

 

 

872,001 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income

-

 

 

- 

 

 

61,672 

 

 

- 

 

- 

 

 

- 

 

 

61,672 

Common stock dividends

-

 

 

- 

 

 

(70,178)

 

 

- 

 

- 

 

 

- 

 

 

(70,178)

Issued

523

 

 

15,770 

 

 

- 

 

 

- 

 

(6)

 

 

338 

 

 

16,108 

Acquired

-

 

 

- 

 

 

- 

 

 

- 

 

75 

 

 

(1,252)

 

 

(1,252)

Other

-

 

 

394 

 

 

(528)

 

 

- 

 

- 

 

 

- 

 

 

(134)

Unrealized loss on

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

securities (net of tax)

-

 

 

- 

 

 

- 

 

 

(1,431)

 

- 

 

 

- 

 

 

(1,431)

Minimum pension

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

liability adjustment

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(net of tax)

-

 

 

- 

 

 

- 

 

 

(1,959)

 

- 

 

 

- 

 

 

(1,959)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance at December 31,

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2002

38,152

 

$

470,361 

 

$

415,315 

 

$

(7,109)

 

135 

 

$

(3,740)

 

$

874,827 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

The accompanying notes are an integral part of thesestatements.

 

 

 

 

 

 

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

 

**Year Ended December 31,**

 

**2002**

 

**2001**

 

**2000**

 

**(thousands of dollars)**

 

 

 

 

 

 

 

 

 

**NET  INCOME**

$

61,672 

 

$

125,214 

 

$

139,883 

 

 

 

 

 

 

 

 

 

**OTHER  COMPREHENSIVE INCOME (LOSS):**

 

 

 

 

 

 

 

 

 

Unrealized  gains on securities:

 

 

 

 

 

 

 

 

 

 

Unrealized  holding gains (losses) arising during the period, 

 

 

 

 

 

 

 

 

 

 

 

net  of tax of ($1,840), ($992) and ($1,674)

 

(2,991)

 

 

(1,690)

 

 

(2,275)

 

 

Less:  reclassification adjustment for (gains)  losses included

 

 

 

 

 

 

 

 

 

 

 

in  net income, net of tax of $1,007, ($52) and ($39)

 

1,560 

 

 

(80)

 

 

(60)

 

 

 

Net  unrealized gains

 

(1,431)

 

 

(1,770)

 

 

(2,335)

 

Minimum  pension liability adjustment (net of tax of ($1,265),

 

 

 

 

 

 

 

 

 

 

($649)  and ($78))

 

(1,959)

 

 

(1,028)

 

 

(119)

 

 

 

 

 

 

 

 

 

**TOTAL  COMPREHENSIVE INCOME**

$

58,282 

 

$

122,416 

 

$

137,429 

 

 

 

 

 

 

 

 

 

 

Theaccompanying notes are an integral part of these statements

 

 

 

 

**IDACORP, Inc.NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS**

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

**Nature of Business**IDACORP, Inc. (IDACORP) is a holding company whose principaloperating subsidiaries are Idaho Power Company (IPC) and IDACORP Energy(IE).  IPC is regulated by the FederalEnergy Regulatory Commission (FERC) and the state regulatory commissions ofIdaho and Oregon and is engaged in the generation, transmission, distribution,sale and purchase of electric energy. IPC is the parent of Idaho Energy Resources Co., a joint venturer inBridger Coal Company, which supplies coal to the Jim Bridger generating plantowned in part by IPC.

IDACORP announced in 2002 thatIE, a marketer of electricity and natural gas, would wind down its operations.

IDACORP's other subsidiariesinclude:

Ida-West Energy(Ida-West) - developer and manager of independent power projects;

IdaTech -developer of integrated fuel cell systems;

IDACORPFinancial Services, Inc. (IFS) - affordable housing and other real estateinvestments;

Velocitus -commercial and residential Internet service provider; and

IDACOMM -provider of telecommunications services. 

 

**Principles of Consolidation**The consolidated financial statements include the accounts ofIDACORP and wholly-owned or controlled subsidiaries.  All significant intercompany balances have been eliminated inconsolidation.  Investments in businessentities in which IDACORP and its subsidiaries do not have control, but havethe ability to exercise significant influence over operating and financialpolicies, are accounted for using the equity method.

**Management Estimates**Management makes estimates and assumptions when preparing financialstatements in conformity with accounting principles generally accepted in theUnited States of America.  Theseestimates and assumptions affect the reported amounts of assets and liabilitiesand the disclosure of contingent assets and liabilities at the date of thefinancial statements, and the reported amounts of revenues and expenses duringthe reporting period.  These estimatesinvolve judgments with respect to, among other things, future economic factorsthat are difficult to predict and are beyond management's control.  As a result, actual results could differfrom those estimates.

**System of Accounts**The accounting records of IPC conform to the Uniform System ofAccounts prescribed by the FERC and adopted by the public utility commissionsof Idaho, Oregon and Wyoming.

**Property, Plant and Equipment andDepreciation**The cost of utility plant in service represents the original cost ofcontracted services, direct labor and material, allowance for funds used duringconstruction and indirect charges for engineering, supervision and similaroverhead items.  Maintenance and repairsof property and replacements and renewals of items determined to be less thanunits of property are expensed to operations. Repair and maintenance 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 isdepreciated using the straight-line method at rates approved by regulatoryauthorities.  Annual depreciationprovisions as a percent of average depreciable utility plant in serviceapproximated 3.00 percent in 2002, 2.98 percent in 2001 and 2.94 percent in2000.

**Allowance for Funds Used DuringConstruction**Allowance for Funds Used During Construction (AFDC) represents thecost of financing construction projects with borrowed funds and equityfunds.  While cash is not realizedcurrently from such allowance, it is realized under the rate making process overthe service life of the related property through increased revenues resultingfrom 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 2002, 2001 and 2000 were4.3 percent, 5.4 percent, and 8.3 percent, respectively.  IPC's reductions to interest expense forAFDC were $2 million, $4 million and $2 million, and other income included $0.3million, $1 million and $3 million for 2002, 2001 and 2000, respectively.

**Revenues**In order to match revenues with associated expenses, IPC accruesunbilled revenues for electric services delivered to customers but not yetbilled at month-end.

IE reports marketing and tradingrevenues and expenses on a net basis, using the mark-to-market method ofaccounting.  Revenues and expenses forprior years have been reclassified to conform to the current presentation.  Energy marketing revenues include sales ofelectricity and gas netted against purchases, whether physically settled or netsettled.  Additionally, all financialtransactions and unrealized income are presented on a net basis in operatingrevenues.  Other cost of revenues itemssuch as transmission and broker fees are reported as operating expenses.

**Power Cost Adjustment**IPC has a Power Cost Adjustment (PCA) mechanism that provides forannual adjustments to the rates charged to its Idaho retail electriccustomers.  These adjustments, whichtake effect annually in May, are based on forecasts of net power supplyexpenses and the true-up of the prior year's forecast.  During the year, 90 percent of thedifference between the actual and forecasted costs is deferred with interest.  The ending balance of this deferral, calleda true-up, is then included in the calculation of the next year's PCAadjustment.

**Income Taxes**The liability method of computing deferred taxes is used on alltemporary differences between the book and tax basis of assets and liabilitiesand deferred tax assets and liabilities are adjusted for enacted changes in taxlaws or rates.  Consistent with ordersand directives of the Idaho Public Utilities Commission (IPUC), the regulatoryauthority having principal jurisdiction, IPC's deferred income taxes (commonlyreferred to as normalized accounting) are provided for the difference betweenincome tax depreciation and straight-line depreciation computed using booklives on coal-fired generation facilities and properties acquired after 1980.  On other facilities, deferred income taxesare provided for the difference between accelerated income tax depreciation andstraight-line depreciation using tax guideline lives on assets acquired priorto 1981. Deferred income taxes are not provided for those income tax timingdifferences where the prescribed regulatory accounting methods do not providefor current recovery in rates. Regulated enterprises are required to recognize such adjustments asregulatory assets or liabilities if it is probable that such amounts will berecovered from or returned to customers in future rates (see Note 2).

The State of Idaho allows athree-percent investment tax credit (ITC) upon certain qualifying plantadditions.  ITC's earned on regulatedassets are deferred and amortized to income over the estimated service lives ofthe related properties.  Credits earnedon non-regulated assets or investments are recognized in the year earned.

**Earnings Per Share**The computation of diluted earnings per share (EPS) differs frombasic EPS only due to including potentially dilutive shares related tostock-based compensation awards.  Thediluted EPS calculation includes immaterial amounts of potentially dilutiveshares for the periods presented.

The diluted EPS computation for2002 and 2001 excluded 849,000 and 274,000 common stock options, respectively,because the options' exercise prices were greater than the average market priceof the common stock during the years. These options expire from 2010 to 2012, and were still outstanding atthe end of 2002.  There were no suchoptions excluded from the diluted EPS calculation in 2000.

**Stock-Based Compensation**At December 31, 2002, two stock-based employee compensation plansexisted, which are described more fully in Note 9.  These plans are accounted for under the recognition andmeasurement principles of Accounting Principles Board (APB) Opinion 25,"Accounting for Stock Issued to Employees," and relatedinterpretations.  Grants of restrictedstock are reflected in net income based on the market value at the award date,or the year-end price for shares not yet vested.  No stock-based employee compensation cost is reflected in netincome for stock options, as all options granted under these plans had an exerciseprice equal to the market value of the underlying common stock on the date ofgrant.  The following table illustratesthe effect on net income and EPS if the fair value recognition provisions ofStatement of Financial Accounting Standards (SFAS) 123, "Accounting forStock-Based Compensation," had been applied to stock-based employeecompensation:

 

**2002**

 

**2001**

 

**2000**

 

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

 

 

 

 

 

 

 

 

 

Net income, as reported

$

61,672 

 

$

125,214

 

$

139,883

Add: Stock-based employee compensation expense  included in 

 

 

 

 

 

 

 

 

 

reported net income, net of related tax effects

 

(9)

 

 

442

 

 

902

Deduct: Total stock-based employee compensation  expense 

 

 

 

 

 

 

 

 

 

determined under fair value based method for all  awards, net 

 

 

 

 

 

 

 

 

 

of related tax effects

 

1,958 

 

 

1,579

 

 

1,037

 

 

Pro forma net income

$

59,705 

 

$

124,077

 

$

139,748

**Earnings per share:**

 

 

 

 

 

 

 

 

 

Basic and diluted - as reported

$

1.63 

 

$

3.35

 

$

3.72

 

Basic and diluted - pro forma

 

1.58 

 

 

3.32

 

 

3.72

 

**Cash and Cash Equivalents**Cash and cash equivalents include cash on hand and highly liquidtemporary investments with maturity dates at date of acquisition of threemonths or less.

**Investments**Investments in marketable securities are accounted for in accordancewith SFAS 115, "Accounting for Certain Investments in Debt and EquitySecurities."  These investments areclassified as available-for-sale securities, and are reported at fair value,using either specific identification or average cost to determine the cost forcomputing gains or losses.  Any unrealizedgains or losses on available-for-sale securities are included in othercomprehensive income.  Additionally,these investments are evaluated to determine whether they have experienced adecline in market value that is considered other than temporary.  Other than temporary declines in marketvalue are included in other income in the Consolidated Statements of Income.

IFS invests in affordablehousing projects that are accounted for in accordance with Emerging Issues TaskForce (EITF) Issue No. 94-1, "Accounting for Tax Benefits Resulting fromInvestments in Affordable Housing Projects," and shown in the caption"Investments" on the balance sheet. IFS accounts for these investments using the equity method.  All projects are reviewed periodically forimpairment.  At December 31, 2002 and2001 the net affordable housing projects included in investments were $126million and $95 million.

**Derivative Financial Instruments**Financial instruments such as commodity futures, forwards, optionsand swaps are used to manage exposure to commodity price risk in theelectricity and natural gas markets. The objective of the risk management program is to mitigate the riskassociated with the purchase and sale of electricity and natural gas as well asto optimize its energy marketing portfolio. The accounting for derivative financial instruments that are used tomanage risk is in accordance with the concepts established by SFAS 133,"Accounting for Derivative Instruments and Hedging Activities," asamended, and EITF Issue No. 98-10, "Accounting for Contracts Involved inEnergy Trading Activities."

**Regulation of Utility Operations**IPC follows SFAS 71, "Accounting for the Effects of CertainTypes of Regulation," and its financial statements reflect the effects ofthe different rate making principles followed by the various jurisdictionsregulating IPC.  The economic effects ofregulation can result in regulated companies recording costs that have been orare expected to be allowed in the ratemaking process in a period different fromthe period in which the costs would be charged to expense by an unregulatedenterprise.  When this occurs, costs aredeferred as regulatory assets in the balance sheet and recorded as expenses inthe periods when those same amounts are reflected in rates.  Additionally, regulators can imposeliabilities upon a regulated company for amounts previously collected fromcustomers and for amounts that are expected to be refunded to customers(regulatory liabilities).

**Comprehensive Income**Comprehensive income includes net income, unrealized holding gains(losses) on marketable securities, IPC's proportionate share of unrealizedholding gains (losses) on marketable securities held by an equity investee, andthe changes in additional minimum liability under a deferred compensation planfor certain senior management employees and directors.

**Adopted Accounting Standards**On January 1, 2002, SFAS 142, "Goodwill and Other IntangibleAssets," was adopted.  SFAS 142requires that goodwill and certain intangible assets no longer be amortized,but instead be tested for impairment at least annually.

As required by the statement,transitional and annual impairment tests have been completed on the goodwillbalance of $13 million, related to the acquisitions of IdaTech andVelocitus.  There was no impairment ofgoodwill based on these tests.  Goodwillimpairment tests will be performed at least annually, and more frequently ifcircumstances indicate a possible impairment.

The following table presentsIDACORP's net income and earnings per share, adjusted to exclude goodwillamortization expense, for the three years ended December 31:

 

**2002**

 

**2001**

 

**2000**

 

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

 

 

 

 

 

 

 

 

 

Reported net income

$

61,672

 

$

125,214

 

$

139,883

Add back goodwill amortization

 

-

 

 

2,049

 

 

907

Adjusted net income

$

61,672

 

$

127,263

 

$

140,790

 

 

 

 

 

 

 

 

 

**Basic and diluted earnings per share:**

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Reported earnings per share

$

1.63

 

$

3.35

 

$

3.72

Add back goodwill amortization

 

-

 

 

0.05

 

 

0.03

Adjusted earnings per share

$

1.63

 

$

3.40

 

$

3.75

 

 

 

 

 

 

 

 

 

 

SFAS 142 also includesprovisions related to reclassification of intangible assets and reassessment ofuseful lives of intangible assets. There were no intangible assets affected by these provisions.

In January 2002, SFAS 144,"Accounting for the Impairment or Disposal of Long-Lived Assets," wasadopted.  SFAS 144 addresses financialaccounting and reporting for the impairment or disposal of long-lived assets,superseding SFAS 121, "Accounting for the Impairment of Long-Lived Assetsand Long-Lived Assets to be Disposed of." The adoption of SFAS 144 did not have a significant effect on IDACORP orIPC's financial statements.

In June 2001, the DerivativeImplementation Group of the Financial Accounting Standards Board (FASB) issuedImplementation Issue C-15, "Normal Purchases and Normal Sales Exception for Option-TypeContracts and Forward Contracts in Electricity," concluding that contractssubject to book-outs were not eligible for the normal purchase and salesexception in SFAS 133.  Therefore,certain contracts were recorded as derivatives in prior periods.  However, this Implementation Issuewas revised in October 2001 and December 2001, and now allows these contractsto qualify for the exception.  Thisrevision applies only to electric utilities, due to the unique nature of theindustry.  IPC completed an evaluationof the effect of this revised Implementation Issue on its treatment ofbooked-out contracts and determined that contracts previously classified asderivatives were exempt.  This changedid not have a material effect on IDACORP or IPC's financial statements.

**New Accounting Pronouncements**In June 2001, the FASBissued SFAS 143, "Accounting for Asset Retirement Obligations," whichaddresses financial accounting and reporting for obligations associated withthe retirement of tangible long-lived assets and the associated assetretirement costs.  An obligation mayresult from the acquisition, construction, development and the normal operationof a long-lived asset.  SFAS 143requires 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,the entity increases the carrying amount of the related long-lived asset toreflect the future retirement cost. Over time, the liability is accreted to its present value and paid, andthe capitalized cost is depreciated over the useful life of the relatedasset.  If at the end of the asset'slife the recorded liability differs from the actual obligations paid, a gain orloss would be recognized at that time. As a rate-regulated entity, IPC expects to record regulatory assets andliabilities instead of accretion, depreciation and gains or losses, if thecriteria for such treatment are met. SFAS 143 is effective beginning in 2003.

A detailed assessment of the applicability and implications of SFAS 143has been performed.  AROs related toIPC's three jointly owned coal-fired generation facilities, its transmissionand distribution facilities and the Bridger Coal mine, which is owned by anequity-method investee, have been identified. When adopted in 2003, IPC expects to record ARO liabilities of $12million and fixed assets of $6 million, with the offset to regulatoryassets.  These amounts do not include anamount for the transmission and distribution facilities, because, based on theindeterminate life of these assets, an ARO calculation cannot be made.

In June 2002, the FASB issued SFAS 146, "Accounting for CostsAssociated with Exit or Disposal Activities."  The standard requires companies to recognize costs associatedwith exit or disposal activities when they are incurred, rather than at thedate of a commitment to an exit or disposal plan.  Examples of costs covered by the standard include leasetermination costs and certain employee severance costs that are associated witha restructuring, discontinued operation, plant closing or other exit ordisposal activity.  This standard supersedesEITF Issue No. 94-3, "Liability Recognition for Certain EmployeeTermination Benefits and Other Costs to Exit an Activity (including CertainCosts Incurred in a Restructuring)." SFAS 146 is to be applied prospectively to exit or disposal activitiesinitiated after December 31, 2002.  Theadoption of SFAS 146 is not expected to have a material effect on IDACORP orIPC's financial statements.

EITF Issue No. 02-3, "Issues Involved in Accounting forDerivative Contracts Held for Trading Purposes and Contracts Involved in EnergyTrading and Risk Management Activities," reached a consensus to rescindEITF 98-10, the impact of which is to preclude mark-to-market accounting forall energy trading contracts not within the scope of SFAS 133.  The consensus regarding the rescission ofEITF 98-10 is applicable for fiscal periods beginning after December 15,2002.  Energy trading contracts notwithin the scope of SFAS 133 that are purchased after October 25, 2002, but priorto the implementation of the consensus are not permitted to applymark-to-market accounting.  In addition,effective on January 1, 2003, all energy trading contracts previously accountedfor at fair value under EITF 98-10 must be adjusted to historical cost unlessthose contracts meet the definition of a derivative under SFAS 133.  This adjustment will be recorded as acumulative effect of adoption of a new accounting principle.  The rescission of EITF 98-10 will not have amaterial effect on IDACORP or IPC's financial statements, as substantially allof their energy trading contracts meet the definition of a derivative underSFAS 133.

EITF 02-3 also reached aconsensus that gains and losses on derivative instruments within the scope ofSFAS 133 should be shown net in the income statement if the derivativeinstruments are held for trading purposes. In anticipation of this requirement, IDACORP has elected to change itspresentation of energy trading activities from gross to net presentation, inaccordance with the option allowed under EITF 98-10.  Prior periods have been reclassified to conform to currentpresentation.   Therefore operatingrevenues for the energy marketing segment include revenues from the sale ofelectricity and gas netted against the cost of purchased power and natural gas.  Additionally, all financial transactions andunrealized income are presented on a net basis as operating revenue.  Operating expenses include general andadministrative expenses, bad debt reserves, transmission expenses and brokerfees.  The net financial position andresults of operations of IDACORP were not affected by this change inpresentation.

In November 2002, the FASBissued Interpretation No. 45, "Guarantor's Accounting and DisclosureRequirements for Guarantees, Including Indirect Guarantees of Indebtedness ofOthers."  This Interpretationelaborates on the disclosures to be made by a guarantor in its interim andannual financial statements about its obligations under certain guarantees thatit has issued. It also clarifies that a guarantor is required to recognize, atthe inception of a guarantee, a liability for the fair value of the obligationundertaken in issuing the guarantee. The initial recognition and measurement provisions of thisInterpretation are applicable on a prospective basis to guarantees issued ormodified after December 31, 2002, irrespective of the guarantor's fiscalyear-end. The disclosure requirements in this Interpretation are effective forfinancial statements of interim or annual periods ending after December 15,2002.  The adoption of thisInterpretation is not expected to have a material effect on IDACORP or IPC'sfinancial statements.

In January 2003, the FASB issued Interpretation No. 46,"Consolidation of Variable Interest Entities."  This Interpretation clarifies theapplication of Accounting Research Bulletin No. 51, "ConsolidatedFinancial Statements," to certain entities in which equity investors donot have the characteristics of a controlling financial interest or in whichequity investors do not bear the residual economic risks.  The Interpretation applies to variableinterest entities in which an enterprise obtains an interest after thatdate.  It applies in the fiscal year orinterim period beginning after June 15, 2003 to variable interest entities inwhich an enterprise holds a variable interest that was acquired before February1, 2003.  IDACORP and IPC havedetermined that it is not reasonably possible that they will be required toconsolidate or disclose information about a variable interest entity upon theeffective date of this Interpretation.

**Concentration of Credit Risk**Although IE transacts with anumber of energy trading counterparties, it has one significantinvestment-grade counterparty that exposes it to credit risk.  At December 31, 2002, nearly 50 percent ofIE's total credit exposure of $187 million was with this investment-gradecounterparty, under a contract with less than two years remaining.  In order to provide protection from creditrisk, IE uses tools such as standard agreements containing various protectivecreditworthiness provisions, collateral requirements in the form of cash orletters of credit and margining agreements when credit risk exceeds certainpredetermined thresholds.

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

**Reclassifications**Certain items previously reported for years prior to 2002 have beenreclassified to conform to the current year's presentation.  Net income and shareholders' equity were notaffected by these reclassifications.

**2.  INCOME TAXES:**

IDACORP'seffective tax rate for the year ended December 31, 2002 decreased from 34.2percent in 2001 to a benefit of 486 percent in 2002.  Tax benefit items occurring in 2002 include a tax accountingmethod change and the settlement of a partnership audit.

A reconciliationbetween the statutory federal income tax rate and the effective rate is asfollows:

 

 

**2002**

 

**2001**

 

**2000**

 

 

**(thousands of dollars)**

 

 

 

Computed  income taxes based on statutory federal income tax rate

$

3,684    

 

$

66,451   

 

$

73,746   

Change  in taxes resulting from:

 

 

 

 

 

 

 

 

 

AFDC

 

(948)   

 

 

(1,571)  

 

 

(1,719)  

 

Investment  tax credits

 

(3,179)   

 

 

(3,169)  

 

 

(3,083)  

 

Repair  allowance

 

(2,450)   

 

 

(2,800)  

 

 

(4,550)  

 

Capitalized  overhead costs

 

(3,500)   

 

 

-   

 

 

-   

 

Tax  accounting method change

 

(31,162)   

 

 

-   

 

 

-   

 

Settlement  of prior years tax returns

 

(2,971)   

 

 

(1,530)  

 

 

161   

 

State  income taxes (net of federal reduction)

 

514    

 

 

8,506   

 

 

9,793   

 

Depreciation

 

8,940    

 

 

9,790   

 

 

8,243   

 

Affordable  housing and historic tax credits (net of related 

 

 

 

 

 

 

 

 

 

 

deferred  taxes)

 

(20,863)   

 

 

(13,080)  

 

 

(12,962)  

 

Preferred  dividends of IPC

 

1,606    

 

 

1,890   

 

 

2,075   

 

Other

 

(818)   

 

 

159   

 

 

(886)  

Total  provision (benefit) for federal and state income taxes

$

(51,147)   

 

$

64,646   

 

$

70,818   

 

Effective  tax rate

 

(486.0%)

 

 

34.2%

 

 

33.6%

 

 

 

 

 

 

 

 

 

 

 

The provision forincome taxes consists of the following:

 

 

**2002**

 

**2001**

 

**2000**

 

 

**(thousands of dollars)**

Income  taxes currently (receivable) payable:

 

 

 

 

 

 

 

 

 

Federal

$

51,915 

 

$

(66,942)

 

$

18,984 

 

State

 

9,268 

 

 

(18,318)

 

 

5,169 

 

 

Total

 

61,183 

 

 

(85,260)

 

 

24,153 

Income  taxes deferred - net of amortization:

 

 

 

 

 

 

 

 

 

Federal

 

(100,559)

 

 

122,334 

 

 

40,641 

 

State

 

(11,315)

 

 

25,606 

 

 

7,407 

 

 

Total

 

(111,874)

 

 

147,940 

 

 

48,048 

Investment  tax credits:

 

 

 

 

 

 

 

 

 

Deferred

 

2,722 

 

 

5,135 

 

 

1,700 

 

Restored

 

(3,178)

 

 

(3,169)

 

 

(3,083)

 

 

Total

 

(456)

 

 

1,966 

 

 

(1,383)

Total  provision (benefit) for income taxes

$

(51,147)

 

$

64,646 

 

$

70,818 

 

 

 

 

 

 

 

 

 

 

The tax effectsof significant items comprising IDACORP's net deferred tax liabilities are asfollows:

 

 

**2002**

 

**2001**

 

 

**(thousands of dollars)**

Deferred  tax assets:

 

 

 

 

 

 

Regulatory  liabilities

$

41,013

 

$

41,290

 

Advances  for construction

 

3,759

 

 

3,941

 

Other

 

21,524

 

 

16,777

 

 

Total

 

66,296

 

 

62,008

Deferred  tax liabilities:

 

 

 

 

 

 

Utility  plant

 

230,935

 

 

250,180

 

Regulatory  assets

 

327,933

 

 

209,832

 

Conservation  programs

 

10,426

 

 

11,138

 

PCA

 

53,324

 

 

119,436

 

Net  energy trading assets

 

45,711

 

 

71,629

 

Other

 

14,990

 

 

13,427

 

 

Total

 

683,319

 

 

675,642

 

 

 

 

 

 

Net  deferred tax liabilities

$

617,023

 

$

613,634

 

 

 

 

 

 

 

**Tax Accounting Method Change**During the third quarter of2002, IDACORP filed its 2001 federal income tax return and adopted a change toIPC's tax accounting method for capitalized overhead costs.  The former method allocated such costsprimarily to construction of plant, while the new method allocates such coststo both construction of plant and the production of electricity.

The effect of the tax accountingmethod change has been recorded as a decrease to income tax expense for theyear ended December 31, 2002 of $35 million, of which $31 million isattributable to 2001 and prior tax years, and $4 million is attributable to the2002 tax year.  The decrease to taxexpense is a result of deductions on the applicable tax returns of costs thatwere capitalized into fixed assets for financial reporting purposes.  Deferred income tax expense has not beenprovided because the prescribed regulatory accounting method does not allow forinclusion of such deferred tax expense in current rates. Regulated enterprisesare required to recognize such adjustments as regulatory assets if it isprobable that such amounts will be recovered from customers in future rates.

**Status of Audit Proceedings**IPC settled income taxdeficiencies related to its partnership investment in the Bridger Coal Company,covering the years 1991 through 1998. The settlement resulted in deficiencies that were less than previouslyaccrued, enabling IPC to decrease income tax expense by approximately $3million.

Federal income tax returns for years through 1997 havebeen examined by the Internal Revenue Service and substantially all issues havebeen settled.  Management believes thatadequate provision for income taxes has been made for the open years 1998 andafter and for any unsettled issues prior to 1998.

**3.  COMMON STOCK:**

At December 31, 2002 and 2001,common stock was reserved for the following reasons:

 

**2002**

 

**2001**

Contingently issuable in connection with business  combinations

50,732

 

65,416

Dividend reinvestment and stock purchase plan and  employee savings plan

3,751,236

 

4,274,753

Restricted stock plan

314,114

 

314,114

Long-term incentive and compensation plan

2,050,000

 

2,050,000

 

Total

6,166,082

 

6,704,283

 

In 2001, IDACORP acquired198,200 shares of outstanding common stock, at a cost of $8 million, forpotential distribution to shareholders of an acquired entity as partial paymentfor the acquisition.  In 2000, IDACORPacquired 156,300 shares at a cost of $7 million for the same purpose.  IDACORP has issued 233,329 shares to theshareholders of the acquired entity.  Ofthe remaining acquired shares, 61,871 have been issued, primarily in connectionwith our dividend reinvestment program.

IDACORP issues shares of commonstock for its Dividend Reinvestment Plan (DRIP) and Employee Savings Plan (ESP)(see Note 10).  In 2002, IDACORP issued321,236 shares for the DRIP and 202,281 shares for the ESP.  In 2001, IDACORP issued 16,568 shares forthe ESP.

**Shareholder Rights Plan**IDACORP has a Shareholder Rights Plan (Plan) designed to ensure thatall shareholders receive fair and equal treatment in the event of any proposalto acquire control of IDACORP.  Underthe Plan, IDACORP declared a distribution of one Preferred Share Purchase Right(Right) for each of its outstanding Common Shares held on October 1, 1998 orissued thereafter.  The Rights arecurrently not exercisable and will be exercisable only if a person or group(Acquiring Person) either acquires ownership of 20 percent or more of IDACORP'sVoting Stock or commences a tender offer that would result in ownership of 20percent or more of such stock.  IDACORPmay redeem all but not less than all of the Rights at a price of $0.01 perRight or exchange the Rights for cash, securities (including Common Shares ofIDACORP) or other assets at any time prior to the close of business on the 10thday after acquisition by an Acquiring Person of a 20 percent or greaterposition.

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

Following the acquisition of a20 percent or greater position, each Right will entitle its holder to purchasefor $95 that number of shares of Common Stock or Preferred Stock having amarket value of $190.

If after the Rights becomeexercisable, IDACORP is acquired in a merger or other business combination, 50percent or more of its consolidated assets or earnings power are sold, or theAcquiring Person engages in certain acts of self-dealing, each Right entitlesthe holder to purchase for $95, shares of the acquiring company's common stockhaving a market value of $190.

Any Rights that are or were heldby an Acquiring Person become void if any of these events occurs.  The Rights expire on September 30, 2008.

The Rights themselves do notgive any voting or other rights as shareholders to their holders.  The terms of the Rights may be amendedwithout the approval of any holders of the Rights until an Acquiring Personobtains a 20 percent or greater position, and then may be amended as long asthe amendment is not adverse to the interests of the holders of the Rights.

**4.  PREFERRED STOCKOF IDAHO POWER COMPANY:**

The number ofshares of IPC preferred stock outstanding at December 31, 2002 and 2001 were asfollows:

 

**Shares Outstanding at**

 

 

 

**December 31,**

 

**Call Price**

 

**2002**

 

**2001**

 

**Per Share**

Preferred  stock:

 

 

 

 

 

 

Cumulative,  $100 par value:

 

 

 

 

 

 

 

4%  preferred stock (authorized 215,000 shares)

133,927

 

143,872

 

$104.00

 

 

Serial  preferred stock, 7.68% Series (authorized

 

 

 

 

 

 

 

 

150,000  shares

150,000

 

150,000

 

$102.97

 

Serial  preferred stock, cumulative, without par value,

 

 

 

 

 

 

 

total  of 3,000,000 shares authorized:

 

 

 

 

 

 

 

7.07%  Series, $100 stated value (authorized

 

 

 

 

 

 

 

 

250,000  shares) (a)

250,000

 

250,000

 

$100.354 - $103.535

 

 

Auction  rate preferred stock, $100,000 stated value

 

 

 

 

 

 

 

 

(authorized  500 shares) 

-

 

500

 

 

 

 

 

 

 

 

 

 

 

Total

533,927

 

544,372

 

 

 

 

 

 

 

 

 

(a)

The preferred stock is not redeemable prior to  July 1, 2003.

 

IPC redeemed its auction rate preferred stock in August 2002for $50 million using short-term borrowings.

During 2002 and2001 IPC reacquired and retired 9,945 and 6,784 shares of 4% preferredstock.  As of December 31, 2002, theoverall effective cost of all outstanding preferred stock was 7.03 percent.

**5.  LONG-TERM DEBT:**

The followingtable summarizes long-term debt at December 31:

 

**2002**

 

**2001**

 

**(thousands of dollars)**

First  mortgage bonds:

 

 

 

 

 

 

6.85%    Series due 2002

$

- 

 

$

27,000 

 

6.40%    Series due 2003

 

80,000 

 

 

80,000 

 

8     %     Series due 2004

 

50,000 

 

 

50,000 

 

5.83%    Series due 2005

 

60,000 

 

 

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 

 

 

- 

 

Maturing  2023 through 2032 with rates ranging from

 

 

 

 

 

 

 

6.00%  to 8.75%

 

180,000 

 

 

130,000 

 

 

Total  first mortgage bonds

 

750,000 

 

 

627,000 

Pollution  control revenue bonds:

 

 

 

 

 

 

8.30%    Series 1984 due 2014

 

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 

REA  notes

 

1,185 

 

 

1,263 

American  Falls bond guarantee

 

19,885 

 

 

19,885 

Milner  Dam note guarantee

 

11,700 

 

 

11,700 

Unamortized  premium/discount - net

 

(2,405)

 

 

(1,029)

Debt  related to investments in affordable housing

 

37,428 

 

 

49,609 

Other  subsidiary debt

 

15 

 

 

160 

 

Total

 

988,268 

 

 

879,048 

Current  maturities of long-term debt

 

(89,592)

 

 

(36,567)

 

 

 

 

 

 

 

 

Total  long-term debt

$

898,676 

 

$

842,481 

 

At December 31,2002, the maturities for the aggregate amount of long-term debt outstandingwere (in thousands of dollars):

 

 

 

**Other**

 

 

 

**subsidiary**

 

**IPC**

 

**debt**

 

 

 

 

 

 

2003

$

80,084

 

$

9,508

2004

 

50,077

 

 

8,445

2005

 

60,079

 

 

7,196

2006

 

82

 

 

5,649

2007

 

81,228

 

 

3,705

Thereafter

 

679,275

 

 

2,940

 

 

 

 

 

 

 

Total

$

950,825

 

$

37,443

 

 

 

 

 

 

 

IDACORP currentlyhas two shelf registration statements totaling $800 million that can be usedfor the issuance of unsecured debt (including medium-term notes) and preferredor common stock.  At December 31, 2002,none had been issued.

On March 23,2000, IPC filed a $200 million shelf registration statement that could be usedfor first mortgage bonds (including medium-term notes), unsecured debt orpreferred stock.  On December 1, 2000,IPC issued $80 million of Secured Medium-Term Notes, Series C, 7.38% Series due2007.  Proceeds were used in January2001 for the early redemption of $75 million First Mortgage Bonds 9.50% Seriesdue 2021.  On March 2, 2001, IPC issued$120 million of Secured Medium-Term Notes, Series C, 6.60% Series due 2011 withthe proceeds used to reduce short-term borrowing incurred in support of ongoinglong-term construction requirements.  No amounts remain to be issued on this shelf registration statement.

On August 16, 2001,IPC filed a $200 million shelf registration statement that could be used forfirst mortgage bonds (including medium-term notes), unsecured debt or preferredstock.  On November 15, 2002, IPCissued $200 million of secured medium-term notes.  This issuance of medium-term notes was divided into twoseries.  The first was $100 millionFirst Mortgage Bonds 4.75% Series due 2012 and the second was $100 millionFirst Mortgage Bonds 6.00% Series due 2032.  Proceeds were used to pay down IPC short-term borrowings.

In August 2001, $25million First Mortgage Bonds 9.52% Series due 2031 were redeemed early.  Also, in March 2002, $50 million FirstMortgage Bonds 8.75% Series due 2027 were redeemed early using short-termborrowings.

The amount offirst mortgage bonds issuable by IPC is limited to a maximum of $900 millionand by property, earnings and other provisions of the mortgage and supplementalindentures thereto.  IPC may amend theindenture and increase this amount without consent of the holders of the firstmortgage bonds.  Substantially all ofthe electric utility plant is subject to the lien of the indenture.

Pollution ControlRevenue Bonds, Series 1984, due December 1, 2014, are secured by First MortgageBonds, Pollution Control Series A, which were issued by IPC and are held by aTrustee for the benefit of the bondholders.

On April 26,2000, at the request of IPC, the American Falls Reservoir District issued itsAmerican Falls Refunding Replacement Dam Bonds, Series 2000, in the aggregateprincipal amount of $20 million for the purpose of refunding on April 26, 2000a like amount of its bonds dated May 1, 1990. IPC has guaranteed repayment of these bonds.

On May 17, 2000,tax exempt Pollution Control Revenue Refunding Bonds Series 2000, in theaggregate principal amount of $4 million, were issued by Port of Morrow, Oregonfor the purpose of refunding on August 1, 2000, a like amount of its PollutionControl Revenue Bonds, Series 1978.

At December 31,2002 and 2001, the overall effective cost of all outstanding first mortgagebonds and pollution control revenue bonds was 6.51 percent and 6.97 percent,respectively.

At December 31,2002, IFS had $37 million of debt with interest rates ranging from 6.03 percentto 8.59 percent due 2003 to 2011.  Thisdebt is collateralized by investments in affordable housing projects with a netbook value of $126 million at December 31, 2002.

**6.  FAIR VALUE OFFINANCIAL INSTRUMENTS:**

The estimatedfair value of IDACORP's financialinstruments has been determined using available market information andappropriate valuation methodologies. The use of different market assumptions and/or estimation methodologiesmay have a material effect on the estimated fair value amounts.

Cash and cashequivalents, customer and other receivables, notes payable, accounts payable,interest accrued and taxes accrued are reported at their carrying value asthese are a reasonable estimate of their fair value. The estimated fair valuesfor notes receivable, fixed rate long-term debt and investments and otherproperty are based upon quoted market prices of the same or similar issues ordiscounted cash flow analyses as appropriate.

 

**December 31, 2002**

 

**December 31, 2001**

 

**Carrying**

 

**Estimated**

 

**Carrying**

 

**Estimated**

 

**Amount**

 

**Fair Value**

 

**Amount**

 

**Fair Value**

**Assets:**

 

 

 

 

 

 

 

 

 

 

 

Notes  receivable

$

13,654

 

$

11,863

 

$

16,017

 

$

16,534

Investment  and other property

 

28,302

 

 

28,700

 

 

26,763

 

 

27,003

 

 

 

 

 

 

 

 

 

 

 

 

**Liabilities:**

 

 

 

 

 

 

 

 

 

 

 

Fixed  rate long-term debt

 

989,658

 

 

1,054,178

 

 

880,116

 

 

920,005

 

 

 

 

 

 

 

 

 

 

 

 

 

**7.  NOTES PAYABLE:**

At December 31,2002, IDACORP had a $350 million credit facility that expires March 25, 2003,and a $140 million credit facility that expires March 26, 2005.  Under these facilities IDACORP pays afacility fee on the commitment, quarterly in arrears, based on its corporatecredit rating.  Commercial paper may beissued up to the amounts supported by the bank credit facilities.

At December 31,2002, IPC had regulatory authority to incur up to $350 million of short-termindebtedness.  IPC has a $200 millioncredit facility that expires March 25, 2003. Under this facility IPC pays a facility fee on the commitment, quarterlyin arrears, based on IPC's corporate credit rating.  IPC's commercial paper may be issued up to the amounts supportedby the bank credit facilities.

Balances andinterest rates of short-term borrowings were as follows at December 31 (inthousands of dollars):

 

**IDACORP**

 

**IPC**

 

**2002**

 

**2001**

 

**2002**

 

**2001**

 

 

 

 

 

 

 

 

 

 

Balance 

$

176,200   

 

$

362,500   

 

$

10,500   

 

$

282,000   

Effective interest rate 

 

1.83%

 

 

2.18%

 

 

1.65%

 

 

2.10%

 

 

 

 

 

 

 

 

 

 

 

 

 

**8.  COMMITMENTS ANDCONTINGENT LIABILITIES:**

IPC is currently purchasing energy from 67 on-linecogeneration and small power production facilities with contracts ranging fromone to 30 years.  Under these contractsIPC is required to purchase all of the output from these facilities.  During the year ended December 31, 2002, IPCpurchased 692,414 MWh at a cost of $44 million.

IPC has agreed to guarantee the performance of reclamationactivities at Bridger Coal Company of which Idaho Energy Resources Company, asubsidiary of IPC, owns a one-third interest. This guarantee, which is renewed each December, was $60 million atDecember 31, 2002.

From time to time IDACORP and IPC are a party to variousother legal claims, actions and complaints not discussed below.  IDACROP and IPC believe that they havemeritorious defenses to all lawsuits and legal proceedings in which they aredefendants and will vigorously defend against them although they are unable topredict with certainty whether or not they will ultimately be successful.  However, based on the companies evaluation,they believe that the resolution of these matters will not have a material adverseeffect on IDACORP or IPC's consolidated financial positions, results ofoperations or cash flows.

**Legal ProceedingsOverton Power District No. 5:** IE filed a lawsuit on November 30, 2001 in Idaho State District Court inand for the County of Ada against Overton Power District No. 5 (Overton), aNevada electric improvement district, based on Overton's breach of its powercontracts with IE.  The July contractprovided for Overton to purchase 40 MW of electrical energy per hour from IE at$88.50 per MWh, from July 1, 2001 through June 30, 2011.  In the contract, Overton agreed to raise itsrates to its customers to the extent necessary to make its payment obligationsto IE under the contract.

IE has asked the Idaho DistrictCourt for damages pursuant to the contract, for a declaration that Overton isnot entitled to renegotiate or terminate the contract and for injunctive reliefrequiring Overton to raise rates as stipulated in the contract.  Overton filed an Answer and Counterclaimclaiming, among other things, that IE breached the agreement by failing toperform in accordance with its contractual obligation and asking for damages inthe amount to be proved at trial. Overton also asserts that the contract is unenforceable or subject torescission.  IE believes Overton'sassertions are without merit.  IE andOverton filed cross motions for summary judgment that have been denied by theCourt.  The parties continue withdiscovery in the lawsuit.  Trial isscheduled to commence on May 5, 2003.

IE believes that Overton'sactions constitute a breach of the contract and intends to vigorously prosecutethis lawsuit.  While the outcome oflitigation is never certain and IE has not yet completed discovery, IEcontinues to believe that it should prevail on the merits.  At December 31, 2002, IE had a $74 millionlong-term asset related to the Overton claim. IE will review the recoverability of the asset on an ongoing basis.  The recoverability of the asset is subjectto Overton's willingness and ability to raise its rates as provided for in thecontract.

**Truckee-Donner Public UtilityDistrict:**  In 2002, IE receivednotice from the Truckee-Donner Public Utility District (Truckee), located inCalifornia, asserting that IE was in purported breach of, and that Truckee hasthe right to renegotiate certain terms of, the Agreement for the Sale andPurchase of Firm Capacity and Energy in place between the two entities.  Generally, the terms of the contract providefor IE to sell to Truckee 10 MW light load energy and 20 MW heavy load energyfor the term January 1, 2002 through December 31, 2002 at $72 per MWh and 25 MWflat energy for the term January 1, 2003 through December 31, 2009 at $72 perMWh.

On May 30, 2002, IE filed alawsuit against Truckee in the Idaho State District Court in and for the Countyof Ada.  This lawsuit was later removedto the United States District Court for the District of Idaho. 

On July 23, 2002, Truckee fileda complaint against IPC, IE and IDACORP with the FERC seeking relief under itslong-term power contract for the purchase of wholesale electric power from IPCand IE.

On January 3, 2003, thecompanies and Truckee reached a settlement of all proceedings pending betweenthe parties.  Pursuant to thesettlement, Truckee has agreed to pay the companies $26 million on or beforeApril 4, 2003.  Incident to thesettlement, IE also entered into an Interim Power Sales Agreement with Truckeethrough March 31, 2003 that replaces the original long-term powercontract.  The settlement of thisdispute is not anticipated to have a material effect on the companies'consolidated financial positions, results of operations or cash flows.

**United Systems, Inc., f/k/aCommercial Building Services, Inc.:** On March 18, 2002, United Systems, Inc. (United Systems) filed acomplaint in Idaho State District Court in and for the County of Ada againstIDACORP Services Co., a subsidiary of IDACORP, dba IDACORP Solutions.  United Systems is a heating, ventilation,refrigeration and plumbing contracting company that entered into a contractwith IDACORP Services in December 2000.

Under the terms of the contract,IDACORP Services authorized United Systems to do business as "IDACORPSolutions."  The contract was to beeffective from January 2001 through December 2005.

In November 2001, IDACORPServices notified United Systems that IDACORP Services was terminating thecontract for convenience.  The contractallowed for such termination but required the terminating party to compensatethe other party for all costs incurred in preparation for, and in performanceof the contract, and for reasonable net profit for the remaining term of thecontract.  United Systems claims $7million in net profits lost and costs incurred.

IDACORP Services asserts thattermination related compensation owed to United Systems, if any, is substantiallyless than the amount claimed by United Systems.

On August 8, 2002, UnitedSystems filed an amended complaint adding IDACORP, IE, and IPC as additionaldefendants claiming they should be held jointly and severally liable for anyjudgment entered against IDACORP Services. The parties in this matter agreed to delay the jury trial set for June13, 2003 and reset it to begin on November 10, 2003.

On October 4, 2002, UnitedSystems, Inc. filed a Motion for Partial Summary Judgment as to their damages.  United Systems has estimated their damagesto be approximately $7 million as stated above.  Oral argument on the motion was heard on November 21, 2002.  No decision has been entered on the Motionfor Partial Summary Judgment as of this date.

The companies intend tovigorously defend their position in this proceeding and believe these matterswill not have a material adverse effect on their consolidated financialpositions, results of operations or cash flows.

**Public Utility District No. 1of 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-MW purchase transaction with IPC for the purchase of electricpower from October 1, 2001 through March 31, 2002, at a rate of $249 perMWh.  In June 2001, with the consent ofGrays Harbor, IPC assigned all of its rights and obligations under the contractto IE.  In its lawsuit, Grays Harboralleges that the assignment was void and unenforceable, and seeks restitutionfrom IE and IDACORP, or in the alternative, Grays Harbor alleges that thecontract should be rescinded or reformed. Grays Harbor seeks as damages an amount equal to the difference between$249 per MWh and the "fair value" of electric power delivered by IEduring the period October 1, 2001 through March 31, 2002.

IDACORP, IPC and IE had thisaction removed from the state court to the United States District Court for theWestern District of Washington at Tacoma. On November 12, 2002, the companies filed a motion to dismiss GraysHarbor's complaint, asserting that the Federal District Court lacked jurisdictionas the matter is preempted under the FPA by the FERC.  The court ruled in favor of the companies' motion to dismiss anddismissed the case with prejudice on January 28, 2003.

**State of California AttorneyGeneral:**  The California AttorneyGeneral (AG) filed the complaint in this case in the California Superior Courtin San Francisco on May 30, 2002.  Thisis one of thirteen virtually identical cases brought by the AG against varioussellers of power in the California market, seeking civil penalties pursuant toCalifornia's unfair competition law - California Business and Professions CodeSection 17200.  Section 17200 definesunfair competition as any "unlawful, unfair or fraudulent business act orpractice . . . ."  The AG allegesthat IPC engaged in unlawful conduct by violating the Federal Power Act (FPA)in two respects:  (1) by failing to fileits rates with the FERC as required by the FPA; and (2) charging unjust andunreasonable rates in violation of the FPA. The AG alleges that there were "thousands of . . . sales orpurchases" for which IPC failed to file its rates, and that IPC chargedunjust and unreasonable rates on "thousands of occasions."  Pursuant to Business and Professions CodeSection 17206, the AG seeks civil penalties of up to $2,500 for each allegedviolation.  On June 25, 2002, IPCremoved the action to federal court, and on July 25, 2002, the AG filed amotion to remand back to state court.  Thecourt previously denied the AG's prior motions to remand back to state court inthe companion cases.  The court heardIPC's Motion to Dismiss on September 26, 2002. The court has not yet ruled on the Motion to Dismiss.  IPC intends to vigorously defend itsposition in this proceeding and believes this matter will not have a material adverseeffect on its consolidated financial position, results of operations or cashflows.

**Wholesale ElectricityAntitrust Cases I & II:**  Thesecross-actions against IE and IPC emerge from multiple California state courtproceedings first initiated in late 2000 against various powergenerators/marketers by various California municipalities and citizens,including California Lieutenant Governor Cruz Bustamante and Californialegislator Barbara Matthews in their personal capacities.  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., 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.  Plaintiffs asserted variousclaims that the defendants violated California Antitrust Law (the CartwrightAct), Business & Professions Code Section 16720, *et seq*., and California's Unfair Competition Law, Business &Professions Code Section 17200, *et seq.*  Among the acts complained of are bidrigging, information exchanges, withholding of power, and various otherwrongful acts.  These actions weresubsequently consolidated, resulting in the filing of Plaintiffs' MasterComplaint (PMC) in San Diego Superior Court on March 8, 2002.

On April 22, 2002, more than ayear after the initial complaints had been filed, two of the originaldefendants, Duke and Reliant, filed separate cross-complaints against IPC andIE, and approximately 30 other cross-defendants.  Duke andReliant's cross-complaints seek indemnity from IPC, IE and the othercross-defendants for an unspecified share of any amounts they must pay in theunderlying suits because, they allege, other market participants like IPC andIE engaged in the same conduct at issue in the PMC.  Duke and Reliant also seek declaratory relief as to therespective liability and conduct of each of the cross-defendants in the actionsalleged in the PMC.  Reliant has alsoasserted a claim against IPC for alleged violations of the California UnfairCompetition Law, Business and Professions Code Section 17200, *et seq.* As a buyer of electricity in California, Reliant seeks the same relieffrom the cross-defendants, including IPC, as that sought by plaintiffs in thePMC as to any power Reliant purchased through the 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, have moved to dismiss these claims,and those motions were heard in September 2002, together with motions to remandthe case back to state court filed by the original plaintiffs.  On December 13, 2002, the Federal DistrictCourt granted Plaintiffs' Motion to Remand to State Court, and Defendants'Motion to Stay the Remand Order while they appeal the Order.  As a result of the various motions, no trialdate is set at this time.  The companiescannot predict the outcome of this proceeding, nor can they evaluate the meritsof any of the claims at this time but they intend to vigorously defend thislawsuit.

**Idaho Rivers United:**  On December 10, 2002, Idaho Rivers Unitedfiled a complaint against IPC in U.S. District Court for the District of Idaho.The complaint alleges that IPC violated the Clean Water Act by discharging anamount of dredged and fill material into the navigable waters of the SnakeRiver in excess of that allowed by a Section 404 permit issued by the U.S. ArmyCorps of Engineers. The action relates to work completed by IPC, pursuant to aSection 404 permit issued by the Corps on September 3, 1999, in the area of thetailrace downstream of IPC's Bliss hydroelectric project on the Snake River inIdaho. Idaho Rivers United asks the court to impose civil penalties on IPCunder sections 309(d) and 505(a) of the Clean Water Act [33 U.S.C. Sections1319(d) and 1365(a)], require IPC to pay for any remedial or restoration worknecessary to amend any environmental harm caused by the alleged violation, andpay reasonable attorney fees. IPC received an extension of time in which torespond to the complaint and is having settlement discussions with Idaho RiversUnited.

IPC cannot predict the outcome of this proceeding, norcan it evaluate the merits of any of the claims at this time but it intends tovigorously defend this lawsuit.

**California Energy Situation:** As a component of IPC's non-utility energytrading in the state of California, IPC, in January 1999, entered into aparticipation agreement with the California Power Exchange (CalPX), aCalifornia non-profit public benefit corporation.  The CalPX, at that time, operated a wholesale electricity marketin California by acting as a clearinghouse through which electricity was boughtand sold.  Pursuant to the participationagreement, IPC could sell power to the CalPX under the terms and conditions ofthe CalPX Tariff.  Under theparticipation agreement, if a participant in the CalPX exchange defaulted on apayment to the exchange, the other participants were required to pay theirallocated share of the default amount to the exchange.  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 CalPXsent IPC an invoice for $2 million - a "default share invoice" - as aresult of an alleged Southern California Edison (SCE) payment default of $215million for power purchases.  IPC madethis payment.  On January 24, 2001, IPCterminated the participation agreement. On February 8, 2001, the CalPX sent a further invoice for $5 million,due February 20, 2001, as a result of alleged payment defaults by SCE, PacificGas and Electric Company (PG&E) and others.  However, because the CalPX owed IPC $11 million for power sold tothe CalPX in November and December 2000, IPC did not pay the February 8thinvoice.  IPC essentially discontinuedenergy trading with CalPX and the California Independent System Operator (CalISO) in December 2000.

IPC believes that the defaultinvoices were not proper and that IPC owes no further amounts to the CalPX.  IPC has pursued all available remedies inits efforts to collect amounts owed to it by the CalPX.  On February 20, 2001, IPC filed a petitionwith FERC to intervene in a proceeding that requested the FERC to suspend theuse of the CalPX charge back methodology and provides for further oversight inthe CalPX's implementation of its default mitigation procedures.

A preliminary injunction wasgranted by a Federal Judge in the Federal District Court for the CentralDistrict of California enjoining the CalPX from declaring any CalPX participantin default under the terms of the CalPX Tariff.  On March 9, 2001, the CalPX filed for Chapter 11 protection withthe U.S. Bankruptcy Court, Central District of California.

In April 2001, PG&E filedfor bankruptcy.  The CalPX and Cal ISOwere among the creditors of PG&E. To the extent that PG&E's bankruptcy filing affects thecollectibility of the receivables from the CalPX and Cal ISO, the receivablesfrom these entities are at greater risk.

The FERC issued an order on April 6, 2001 requiring the CalPX to rescindall chargeback actions related to PG&E's and SCE's liabilities.  Shortly after that time, the CalPXsegregated the CalPX chargeback amounts it had collected in a separateaccount.  The CalPX claims it isawaiting further orders of the FERC and the bankruptcy court beforedistributing the funds that it collected under its chargeback tariffmechanism.  Although certain parties tothe California refund proceeding urged the FERC's Presiding Administrative LawJudge to consider the chargeback amounts in his determination of who owes whatto whom, in his Certification of Proposed Findings on California RefundLiability, he concluded that the matter already was pending before the FERC fordisposition.

Also in April 2001, the FERCissued an order stating that it was establishing price mitigation for sales inthe California wholesale electricity market. Subsequently, in its June 19, 2001order, the FERC expanded that price mitigation plan to the entire western UnitedStates electrically interconnected system. That plan included the potential fororders directing electricity sellers into California since October 2, 2000 torefund portions of their spot market sales prices if the FERC determined thatthose prices were not just and reasonable, and therefore not in compliance withthe Federal Power Act. The June 19 order also required all buyers and sellersin the Cal ISO market during the subject time-frame to participate insettlement discussions to explore the potential for resolution of these issueswithout further FERC action. The settlement discussions failed to bringresolution of the refund issue and as a result, the FERC's Chief AdministrativeLaw Judge submitted a Report and Recommendation to the FERC recommending thatthe FERC adopt the methodology set forth in the report and set for evidentiaryhearing an analysis of the Cal ISO's and the CalPX's spot markets to determinewhat refunds may be due upon application of that methodology.

On July 25, 2001, the FERC issuedan order establishing evidentiary hearing procedures related to the scope andmethodology for calculating refunds related to transactions in the spot marketsoperated by the Cal ISO and the CalPX during the period October 2, 2000 throughJune 20, 2001. As to potential refunds, if any, IE believes its exposure islikely to be offset by amounts due from California entities. Multiple partieshave filed requests for rehearing and petitions for review.  The latter--more than 60--have beenconsolidated by the United States Court of Appeals for the Ninth Circuit andheld in abeyance while the FERC continues its deliberations.  The Ninth Circuit also directed the FERC topermit the parties to adduce additional evidence respecting market manipulationand although the California Parties (the California Attorney General, otherstate agencies and the California Investor Owned Utilities) have requestedspecific procedures to implement that requirement, the FERC has not yet actedon that request.

On November 20, 2002, the FERCissued an order allowing the parties to the California refund proceeding toconduct discovery for one hundred days into market manipulation by varioussellers during the Western power crises of 2000 and 2001.  At the conclusion of the discovery periodparties alleging market manipulation are to submit their claims to the FERC andparties have until March 20, 2003 to submit evidence or comments in response,including assertions that cross-examination is warranted.

This case had been further complicatedby an August 13, 2002 FERC staff (Staff) Report which included therecommendation to replace the published California indices for gas prices thatthe FERC previously established as just and reasonable for calculating aMitigated Market Clearing Price (MMCP) to calculate refunds with otherpublished indices for producing basin prices plus a transportation allowance.Staff's recommendation is grounded on speculation that some sellers had anincentive to report exaggerated prices to publishers of the indices, resultingin overstated published index prices. Staff bases its speculation in large part on a statistical correlationanalysis of Henry Hub and California prices. If FERC accepts the Staff recommendation, the total amount of refundscould roughly double over earlier estimates. IE, in conjunction with others,submitted comments on the Staff recommendation - asserting that Staff'sconclusions were incorrect in part on the basis of the fact that the Staff'scorrelation study ignored evidence of normal market forces and scarcity whichcreated the pricing variations which Staff observed, rather than impropermanipulation of reported prices.  Beyondsoliciting comments on the Staff recommendation, the FERC has not decidedwhether or how to proceed with consideration of a change in the gas pricingmethodology which it previously approved.

Based upon that order andsubject to possible modification based upon revision of the gas indices to beused, the Cal ISO would then be directed by the FERC to calculate revisedrefund amounts due from sellers of spot market power into the CalPX and Cal ISOduring the refund period.

The Administrative Law Judgeissued a Certification of Proposed Findings on California Refund Liability onDecember 12, 2002.  The FERC hasindicated the intention to largely conclude work on the California refundmatters, including Judge Birchman's decision, the gas pricing component of itsMMCP methodology and claims of market manipulation, before the end of the firstquarter of 2003.

On March 3, 2003, a group ofCalifornia parties, including the California Attorney General, the CaliforniaPublic Utilities Commission, the California Electricity Oversight Board, SCEand PG&E, filed materials with the FERC claiming that wholesale power suppliersmanipulated the California market during 2000-2001.  They seek approximately $8 billion in refunds for the state'sratepayers.  A number of wholesale powersuppliers were named in the filings, including IDACORP and IPC.  IDACORP and IPC intend to vigorously defendin this matter, but they are unable to predict the outcome of this proceeding.

In addition, the July 25, 2001FERC order established another proceeding to explore whether there may havebeen unjust and unreasonable charges for spot market sales in the PacificNorthwest during the period December 25, 2000 through June 20, 2001. The FERCAdministrative Law Judge (ALJ) submitted recommendations and findings to theFERC on September 24, 2001. The ALJ found that prices should be governed by theMobile-Sierra standard of the public interest rather than the just andreasonable standard, that the Pacific Northwest spot markets were competitiveand that no refunds should be allowed. Procedurally, the ALJ's decision is arecommendation to the commissioners of the FERC. Multiple parties havesubmitted comments to the FERC respecting the ALJ's recommendations.  The ALJ's recommended findings are pendingat the FERC.  The City of Tacoma and thePort of Seattle requested that the docket be reopened to allow the submissionof additional evidence related to alleged manipulation of the power market byEnron and others.  IE opposed thatrequest.   By order issued December 19,2002, the FERC reopened the docket to allow interested parties to takeadditional discovery and present additional evidence related to alleged marketmanipulation and its intent on spot market sales in the Pacific Northwest.  As is the case in the California refundproceeding, at the conclusion of the discovery period, parties alleging marketmanipulation are to submit their claims to the FERC and parties have untilMarch 20, 2003 to submit evidence or comments in response, including assertionsthat cross-examination is warranted. Grays Harbor, whose civil litigation claims were dismissed, as notedabove, has injected itself into the FERC proceedings asserting in discoveryrequests that its six month forward contract, for which performance has beencompleted, should be treated as a spot market contract for purposes of theFERC's consideration of refunds.  GraysHarbor filed testimony on March 3, 2003 requesting refunds from IPC of $5million.  The company intends to defendvigorously.

In addition, the Port ofSeattle, the City of Tacoma and Seattle City Light made filings with the FERCon March 3, 2003 claiming that because some market participants drove prices upthroughout the west through acts of manipulation, prices for contractsthroughout the Pacific Northwest Market should be re-set starting in May 2000using the same factors the FERC would use for California markets.  These parties did not suggest any misconductby IE or IPC.  IE and IPC expect todefend against these generic claims, but are unable to predict the outcome ofthis matter.

IPC transferred its non-utilitywholesale electricity marketing operations to IE in June 2001 effective June 1,2001.  Effective with this transfer, theoutstanding receivables and payables with the CalPX and Cal ISO were assignedfrom IPC to IE.  At December 31, 2002,the CalPX and 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 $42 millionagainst these receivables.

These reserves were calculatedtaking into account the uncertainty of collection, given the current Californiaenergy situation.  Based on the reservesrecorded as of December 31, 2002, IDACORP believes that the futurecollectibility of these receivables or any potential refunds ordered by theFERC would not have a significant impact on its consolidated financialposition, results of operations or cash flows.

**Nevada Power Company:**  In February and April of 2001 IE enteredinto several transactions under the Western Systems Power Pool (WSPP) Agreementwhereby IE agreed to deliver to Nevada Power Company (NPC) 25 MW's during thethird quarter of 2002.  NPC agreed topay IE $250 per MWh for heavy load deliveries and $155 per MWh for light loaddeliveries.  Based upon the uncertainfinancial condition of NPC, IE asked for further assurances of NPC's ability topay for the power if IE made the deliveries. NPC failed to provide appropriate credit assurances; therefore, inaccordance with the WSPP Agreement procedures, IE terminated the transactionseffective July 8, 2002.

Pursuant to the WSPP Agreement IE notified NPC of theliquidated damages amount and NPC responded with a letter which describes theirview of rights under the WSPP Agreement and suggests a negotiatedresolution.  IE will continue to pursueits rights under the WSPP Agreement.  AtDecember 31, 2002, IE had a $4 million receivable related to the NPCclaim.  IE will review therecoverability of the asset on an ongoing basis.

**Washington Retail ConsumerClass Action Complaint:**  Thecomplaint in this case was filed on December 20, 2002 in the United StatesDistrict Court for the Western District of Washington at Seattle, againstvarious entities, including IPC.  Thecomplaint was served on IPC on February 3, 2003.  This action seeks class action status on behalf of all personsand businesses residing in Washington who were purchasers of electrical and/ornatural gas energy from any period beginning in January 2000 to thepresent.  The complaint alleges claimsunder the Washington Consumer Protection Act, RCW 19.86, as well as common lawclaims of fraud by concealment, negligence and for an accounting.  The complaint asserts that the defendants,including IPC, engaged in, among other things, unfair and deceptive acts, inviolation of the Federal Power Act, by (a) withholding the supply of energy;(b) misrepresenting the amount of its energy supplies; (c) exercising impropercontrol over the energy markets; and (d) manipulating the price of energymarkets resulting in energy rates being unjust, unreasonable and unlawful.  The plaintiff seeks certification of a classaction, equitable and injunctive relief, an accounting, treble damages,attorneys' fees and costs.  On February3, 2003, another defendant, Reliant, moved to transfer the case to the Judgewho is presiding over MDL No. 1405.  IPC'sresponse to the complaint is due within 30 days from the date of service.  IPC intends to vigorously defend againstthis lawsuit and believes this matter will not have a material adverse effecton its consolidated financial position, results of operations or cash flows.

**Oregon Retail Consumer Class Action Complaint:**  Thecomplaint in this case was filed on December 16, 2002 in the Circuit Court ofthe State of Oregon for the County of Multnomah, against various entities,including IPC.  The complaint was servedon IPC on February 7, 2003.  The casewas removed by another defendant, Reliant, to the United States District Court,District of Oregon on February 4, 2003. The complaint seeks class action status on behalf of all persons andbusinesses residing in Oregon who were purchasers of electrical and/or naturalgas energy from any period beginning in January 2000 to the present.  The complaint alleges claims under theOregon Unfair Trade Practices Act, ORS 646.605 *et seq.* in addition to claims of fraud by concealment, negligenceand for an accounting.  The complaintasserts that the defendants, including IPC, engaged in, among other things,unfair and deceptive acts, in violation of the Federal Power Act, by (a) withholdingthe supply of energy; (b) misrepresenting the amount of its energy supplies;(c) exercising improper control over the energy markets; and (d) manipulatingthe price of energy markets resulting in energy rates being charged to Oregonenergy consumers that were unjust, unreasonable and unlawful.  The plaintiff seeks certification of a classaction, equitable and injunctive relief, an accounting, attorneys' fees andcosts.  The action was recently removedto federal court, and IPC intends to seek an extension of time to respond.  IPC intends to vigorously defend againstthis lawsuit and believes this matter will not have a material adverse effecton its consolidated financial position, results of operations or cash flows.

**Enron Bankruptcy Case: **IE and IPC exercised their rights toterminate all contracts with Enron Power Marketing Inc. (EPMI) and Enron NorthAmerica Corp. (ENA) on or about December 3, 2001, immediately after the filingof the bankruptcy case by Enron and numerous of its subsidiaries andaffiliates.

IE timely submitted claimsduring October, 2002 in the Enron bankruptcy proceeding for net pre-petitionobligations of EPMI and ENA and Enron Corp. (as Guarantor) to IE of over $17million, primarily for power and energy delivered prior to the Enronbankruptcy, together with contingent claims based on fraud, claims arising fromgovernmental investigations and other claims against Enron.  IE and IPC have acknowledged that there arealso monetary values associated with forward contracts that were terminated,which, when analyzed separately, may result in a substantial net liability toEnron after setoff of such pre-petition obligations.

For several months, IE and IPChave been trying to reach agreement with Enron, under a non-disclosure andconfidentiality agreement, on amounts for both the pre-petition and futureobligations in order to calculate a net termination payment value and amutually agreed settlement value. However, the parties have not yet been ableto agree on these numbers.  A proposedsettlement agreement was being actively negotiated.

However, on February 27, 2003,IE received a complaint filed by EPMI in the U.S Bankruptcy Court, SouthernDistrict of New York. The complaint asserts that EPMI is entitled to aTermination Payment of $39 million, plus interest from the termination date.The complaint asks for declaratory relief, damages and makes objections to IE'sProof of Claim. The answer to the complaint is due 30 days from the date of theSummons, dated February 26, 2003. A pretrial conference has been scheduled in theNew York Bankruptcy Court on April 10, 2003.

On February 28, 2003, IEreceived a Notice of Presentment of Enron's proposed Order Governing Mediationof Trading Cases. Enron intends to present its proposed order, which wouldrefer 25 listed pending adversary proceedings involving trading agreements toanother bankruptcy judge for mediation, to the Bankruptcy Court on March 4,2003. Although the adversary proceeding against IE is not among the listedproceedings, the proposed order would also refer "any future adversaryproceedings" to the mediation judge. Certain parties filed objections tothe proposed order on March 3, 2003, which will be considered at the March 4hearing.

Enron's counsel has agreed thatsince the proceeding against IE was not among the 25 listed in the proposedorder, it was not necessary for IE to file objections or to meet certain otherdeadlines set forth in the proposed order. However, Enron will likely seek torefer the IE proceeding to the mediation judge.

While IE and IPC intend tocontinue to pursue settlement, if the matter is not resolved by settlement, IEand IPC intend to dispute the amounts claimed by EPMI and will vigorouslydefend against the complaint and aggressively prosecute any counterclaims itmay have against Enron.

The companies believe that theliabilities accrued at December 31, 2002 are sufficient to cover the paymentsconsidered probable under this litigation or potential settlement.

**9. STOCK-BASED COMPENSATION:**

IDACORP has twostock-based compensation plans that are intended to align employee andshareholder objectives related to its long-term growth.

IDACORP adoptedthe 2000 Long-Term Incentive Compensation Plan (LTICP) for officers, keyemployees and directors.  The LTICPpermits the grant of nonqualified stock options, incentive stock options, stockappreciation rights, restricted stock, restricted stock units, performanceunits, performance shares and other awards.

The maximumnumber of shares available under the LTICP is 2,050,000.  In 2002 and 2001, IDACORP issued 355,000 and274,000 stock options with an exercise price equal to the market price ofIDACORP's stock on the date of grant. The maximum term of the options is ten years, and they vest ratably overa five-year period.  In accordance withAPB 25, no compensation costs have been recognized for the option awards.

Stock optiontransactions are summarized as follows:

 

 

**2002**

 

**2001**

 

**2000**

 

 

 

 

**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

494,000

 

$

37.79

 

220,000

 

$

35.81

 

-

 

$

-

 

Granted

355,000

 

 

39.50

 

274,000

 

 

39.37

 

220,000

 

 

35.81

 

Exercised

-

 

 

-

 

-

 

 

-

 

-

 

 

-

 

Cancelled

-

 

 

-

 

-

 

 

-

 

-

 

 

-

Outstanding, end of year

849,000

 

$

38.50

 

494,000

 

$

37.79

 

220,000

 

$

35.81

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Exercisable

142,800

 

$

37.10

 

44,000

 

$

35.81

 

-

 

$

-

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

The outstandingoptions have a range of exercise prices from $35.81 to $40.31.  As of December 31, 2002, the weightedaverage remaining contractual life is 8.4 years.

IDACORP also hasa restricted stock plan for certain key employees.  Each grant made under this plan has a three-year restrictedperiod, and the final award amounts depend on the attainment of cumulativeearnings per share performance goals. At December 31, 2002, there were 201,539 remaining shares availableunder this plan.

Restricted stockawards are compensatory awards and IDACORP accrues compensation expense (whichis charged to operations) based upon the market value of the grantedshares.  For the years 2002, 2001 and2000, total compensation accrued under the plan was less than $1 millionannually.

The followingtable summarizes restricted stock activity for the years 2002, 2001 and 2000:

 

**2002**

 

**2001**

 

**2000**

Shares outstanding -  beginning of year

63,550 

 

60,195 

 

51,850 

Shares granted

45,246 

 

23,747 

 

33,054 

Shares forfeited

(417)

 

(474)

 

- 

Shares issued

(20,581)

 

(19,918)

 

(24,709)

Shares outstanding - end of  year

87,798 

 

63,550 

 

60,195 

Weighted average fair value  of current year

 

 

 

 

 

 

stock grants on grant date

$

38.58 

 

$

38.16 

 

$

35.00 

 

 

 

 

 

 

 

For purposes of the pro forma calculations in Note 1, theestimated fair value of the options and restricted stock are amortized toexpense over the vesting period.  Thefair value of the restricted stock is the market price of the stock on the dateof grant.  The fair value of each optiongranted was estimated at the date of grant using the Binomial option-pricingmodel with the following assumptions:

 

**2002**

 

**2001**

 

**2000**

 

 

 

 

 

 

Stock dividend yield

4.71%

 

4.72%

 

5.19%

Expected stock price  volatility

32%

 

29%

 

27%

Risk-free interest rate

4.92%

 

5.18%

 

6.15%

Expected option lives

7 years

 

7 years

 

7 years

Weighted average fair value  of options

 

 

 

 

 

 

granted

$10.54

 

$ 9.86

 

$ 8.42

 

 

 

 

 

 

 

**10.  BENEFIT PLANS:**

**Pension Plans**IPC has a noncontributorydefined benefit pension plan covering most employees.  The benefits under the plan are based on years of service and theemployee's final average earnings. IPC's policy is to fund with an independent corporate trustee at leastthe minimum required under the Employee Retirement Income Security Act of 1974but not more than the maximum amount deductible for income tax purposes.  IPC was not required to contribute to theplan in 2002, 2001 and 2000.  Thetrustee invests the plan assets primarily in listed stocks (both U.S. andforeign), fixed income securities and investment grade real estate.

IPC has anonqualified, deferred compensation plan for certain senior managementemployees and directors.  This plan wasfinanced by purchasing life insurance policies and investments in marketablesecurities, all of which are held by a trustee.  The cash value of the policies and investments exceed theprojected benefit obligation of the plan but do not qualify as plan assets inthe actuarial computation of the funded status.

The followingtable shows the components of net periodic benefit cost for these plans:

 

**Pension Plan**

 

**Deferred Compensation Plan**

 

**2002**

 

**2001**

 

**2000**

 

**2002**

 

**2001**

 

**2000**

 

**(in thousands of dollars)**

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Service cost

$

9,548 

 

$

7,978 

 

$

7,442 

 

$

944 

 

$

624 

 

$

574 

Interest cost

 

18,684 

 

 

17,634 

 

 

16,718 

 

 

2,108 

 

 

2,039 

 

 

1,965 

Expected return  on assets

 

(28,797)

 

 

(30,117)

 

 

(30,095)

 

 

- 

 

 

- 

 

 

- 

Recognized net  actuarial (gain) loss

 

- 

 

 

(3,179)

 

 

(4,503)

 

 

498 

 

 

281 

 

 

242 

Amortization of  prior service cost

 

729 

 

 

708 

 

 

708 

 

 

(353)

 

 

(345)

 

 

(353)

Amortization of  transition asset

 

(263)

 

 

(263)

 

 

(263)

 

 

613 

 

 

613 

 

 

613 

Net periodic  pension (benefit) cost

$

(99)

 

$

(7,239)

 

$

(9,993)

 

$

3,810 

 

$

3,212 

 

$

3,041 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

The followingtable summarizes the changes in benefit obligation and plan assets of theseplans:

 

**Pension Plan**

 

**Deferred Compensation Plan**

 

**2002**

 

**2001**

 

**2002**

 

**2001**

 

**(in  thousands of dollars)**

 

 

 

 

 

 

 

 

 

 

 

 

**Change in projected benefit obligation:**

 

 

 

 

 

 

 

 

 

 

 

 

Benefit  obligation at January 1

$

273,208 

 

$

241,281 

 

$

30,405 

 

$

27,876 

 

Service cost

 

9,548 

 

 

7,978 

 

 

944 

 

 

624 

 

Interest cost

 

18,684 

 

 

17,634 

 

 

2,108 

 

 

2,039 

 

Actuarial loss  (gain)

 

6,823 

 

 

18,560 

 

 

4,490 

 

 

2,352 

 

Benefits paid

 

(13,382)

 

 

(12,586)

 

 

(2,507)

 

 

(2,420)

 

Plan amendments

 

- 

 

 

341 

 

 

352 

 

 

(66)

 

Benefit  obligation at December 31

 

294,881 

 

 

273,208 

 

 

35,792 

 

 

30,405 

**Change in plan assets:**

 

 

 

 

 

 

 

 

 

 

 

 

Fair value at  January 1

 

326,266 

 

 

340,789 

 

 

- 

 

 

- 

 

Actual return  on plan assets

 

(30,353)

 

 

(1,936)

 

 

- 

 

 

- 

 

Employer  contributions

 

- 

 

 

- 

 

 

- 

 

 

- 

 

Benefit  payments

 

(13,382)

 

 

(12,586)

 

 

- 

 

 

- 

 

Fair value at  December 31

 

282,531 

 

 

326,267 

 

 

- 

 

 

- 

 

 

 

 

 

 

 

 

 

 

 

 

Funded status

 

(12,350)

 

 

53,059 

 

 

(35,792)

 

 

(30,405)

Unrecognized  actuarial loss (gain)

 

34,116 

 

 

(31,857)

 

 

12,505 

 

 

8,513 

Unrecognized  prior service cost

 

6,860 

 

 

7,589 

 

 

630 

 

 

(75)

Unrecognized  net transition liability

 

(652)

 

 

(916)

 

 

1,536 

 

 

2,149 

Net amount  recognized

$

27,974 

 

$

27,875 

 

$

(21,121)

 

$

(19,818)

Amounts  recognized in the statement of

 

 

 

 

 

 

 

 

 

 

 

 

financial  position consist of:

 

 

 

 

 

 

 

 

 

 

 

Prepaid  (accrued) pension cost

$

27,974 

 

$

27,875 

 

$

(33,120)

 

$

(28,500)

Intangible  asset

 

- 

 

 

- 

 

 

2,166 

 

 

2,074 

Accumulated  other comprehensive income

 

- 

 

 

- 

 

 

9,833 

 

 

6,608 

Net amount  recognized

$

27,974 

 

$

27,875 

 

$

(21,121)

 

$

(19,818)

 

 

 

 

 

 

 

 

 

 

 

 

 

The followingtable sets forth the assumptions used at the end of each year for allIPC-sponsored pension and postretirement benefit plans:

 

**Pension  Benefits**

 

**Postretirement  Benefits**

 

**2002**

 

**2001**

 

**2002**

 

**2001**

 

 

 

 

 

 

 

 

Discount rate

6.75%

 

7.0%

 

6.75%

 

7.0%

Expected long-term rate of return on assets

8.5   

 

9.0   

 

8.5   

 

9.0   

Annual salary increases

4.5   

 

4.5   

 

-   

 

-   

 

 

 

 

 

 

 

 

 

**Employee Savings Plan**IPC has an Employee SavingsPlan which complies with Section 401(k) of the Internal Revenue Code and coverssubstantially all employees.  IPCmatches specified percentages of employee contributions to the plan.  Matching contributions amounted to $4million in each of 2002 and 2001 and $3 million in 2000.

**Postretirement Benefits**IPC maintains a definedbenefit postretirement plan (consisting of health care and death benefits) thatcovers all employees who were enrolled in the active group plan at the time ofretirement, their spouses and qualifying dependents.

The net periodicpostretirement benefit cost was as follows (in thousands of dollars):

 

**2002**

 

**2001**

 

**2000**

 

 

 

 

 

 

 

 

 

Service cost

$

927 

 

$

831 

 

$

851 

Interest cost

 

3,648 

 

 

3,589 

 

 

3,374 

Expected return on plan  assets

 

(2,320)

 

 

(2,343)

 

 

(2,522)

Amortization of  unrecognized transition obligation

 

2,040 

 

 

2,040 

 

 

2,040 

Amortization of prior  service cost

 

(563)

 

 

(563)

 

 

(691)

Recognized actuarial  (gain)/loss

 

487 

 

 

- 

 

 

- 

Net periodic  post-retirement benefit cost

$

4,219 

 

$

3,554 

 

$

3,052 

 

 

 

 

 

 

 

 

 

 

The followingtable summarizes the changes in benefit obligation and plan assets (inthousands of dollars):

 

**2002**

 

**2001**

 

 

 

 

 

 

**Change in accumulated benefit obligation:**

 

 

 

 

 

 

Benefit  obligation at January 1

$

53,650 

 

$

48,806 

 

Service cost

 

927 

 

 

831 

 

Interest cost

 

3,648 

 

 

3,589 

 

Plan amendments

 

- 

 

 

600 

 

Actuarial loss

 

2,029 

 

 

3,296 

 

Benefits paid

 

(2,987)

 

 

(3,472)

 

Benefit  obligation at December 31

 

57,267 

 

 

53,650 

**Change in plan assets:**

 

 

 

 

 

 

Fair value of  plan assets at January 1

 

25,184 

 

 

26,071 

 

Actual (loss)  return on plan assets

 

(3,837)

 

 

(2,004)

 

Employer  contributions

 

4,262 

 

 

4,413 

 

Benefits paid

 

(3,087)

 

 

(3,296)

 

Fair value of  plan assets at December 31

 

22,522 

 

 

25,184 

 

 

 

 

 

 

Funded status

 

(34,745)

 

 

(28,466)

Unrecognized prior service  cost

 

(5,610)

 

 

(6,173)

Unrecognized actuarial loss  (gain)

 

18,627 

 

 

10,828 

Unrecognized transition  obligation

 

20,400 

 

 

22,440 

Accrued benefit obligations  included with other deferred credits

$

(1,328)

 

$

(1,371)

 

 

 

 

 

 

 

The assumedhealth care cost trend rate used to measure the expected cost of benefitscovered by the plan is 6.75%.  Aone-percentage point change in the assumed health care cost trend rate wouldhave the following effect (in thousands of dollars):

 

**1-Percentage-Point**

 

**1-Percentage-Point**

 

**increase**

 

**decrease**

 

 

 

 

 

 

Effect on total of service and interest cost components

$

261

 

$

(204)

Effect on accumulated postretirement benefit obligation

$

2,477

 

$

(2,008)

 

 

 

 

 

 

 

**Postemployment Benefits**IPC provides certainbenefits to former or inactive employees, their beneficiaries and covereddependents after employment but before retirement.  These benefits include salary continuation, health care and lifeinsurance for those employees found to be disabled under IPC's disability plansand health care for surviving spouses and dependents.  IPC accrues a liability for such benefits.  In accordance with an IPUC order, theportion of the liability attributable to regulated activities in Idaho as ofDecember 31, 1993, was deferred as a regulatory asset, and is being amortizedover ten years.

The followingtable summarizes postemployment benefit amounts included in IDACORP and IPC's consolidatedbalance sheets at December 31 (in thousands of dollars):

 

**2002**

 

**2001**

 

 

 

 

 

 

Included with regulatory assets

$

774 

 

$

1,146  

Included with other deferred credits

$

(3,686)

 

$

(3,010)

 

 

 

 

 

 

 

**11.  PROPERTY PLANTAND EQUIPMENT AND JOINTLY-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 2002 and 2001 (in thousands of dollars):

 
 

**2002**

 

**2001**

 
 

**Balance**

 

**Avg Rate**

 

**Balance**

 

**Avg Rate**

 

 

 

 

 

 

 

 

 

 

Production

$

1,433,627 

 

2.63%

 

$

1,424,777 

 

2.58%

Transmission

 

485,349 

 

2.30   

 

 

460,149 

 

2.30   

Distribution

 

902,985 

 

3.31   

 

 

854,445 

 

3.34   

General and Other

 

265,004 

 

6.16   

 

 

250,259 

 

6.12   

    

Total in service

 

3,086,965 

 

3.00%

 

 

2,989,630 

 

2.98%

Accumulated provision for depreciation

 

(1,294,961)

 

 

 

 

(1,220,002)

 

 

            

In service - net

$

1,792,004 

 

 

 

$

1,769,628 

 

 

 

 

 

 

 

 

 

 

 

 

 

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 theextent of IPC's participation, are as follows at December 31, 2002:

 

 

 

 

**Company Ownership**

 

 

 

 

**Utility**

 

**Construction**

 

**Accumulated**

 

 

 

 

 

 

 

 

**Plant In**

 

**Work in**

 

**Provision for**

 

 

 

 

**Name of Plant**

 

**Location**

 

**Service**

 

**Progress**

 

**Depreciation**

 

**%**

 

**MW**

 

 

 

 

**(thousands of dollars)**

 

 

 

 

Jim  Bridger Units 1-4

 

Rock  Springs, WY

 

$

410,694

 

$

306

 

$

233,367

 

33

 

707

Boardman

 

Boardman,  OR

 

 

64,613

 

 

4,865

 

 

40,274

 

10

 

55

Valmy  Units 1 and 2

 

Winnemucca,  NV

 

 

303,157

 

 

3,283

 

 

164,995

 

50

 

261

 

IPC's wholly owned subsidiary, Idaho Energy ResourcesCompany, is a joint venturer in Bridger Coal Company, which operates the minesupplying coal for the Jim Bridger steam generation plant.  Coal purchased by IPC from the joint ventureamounted to $44 million in 2002, $43 million in 2001, and $44 million in 2000.

IPC has contracts to purchase the energy from four PublicUtilities Regulatory Policy Act Qualified Facilities that are 50 percent ownedby Ida-West.  Power purchased from thesefacilities amounted to $7 million in 2002, $6 million in 2001 and $8 million in2000.

**Ida-West**During fourth quarter 2002, Ida-West recorded an $8 million partialwrite-down of its investment in equipment for the Garnet project.  This partial write-down reflects the drop inprices for and increased availability of generating equipment due to thecollapse of the merchant power plant development business.

**12.  INDUSTRY SEGMENTINFORMATION:**

IDACORP hasidentified two reportable operating segments, utility operations and energymarketing.

The utilityoperations segment has two primary sources of revenue: the regulated operationsof IPC and income from Bridger Coal Company, an unconsolidated joint venturealso subject to regulation.  IPC'sregulated operations include the generation, transmission, distribution,purchase and sale of electricity.

The energymarketing segment reflects the results of IE's electricity and natural gasmarketing operations.  See Note 13 -Regulatory Matters, for discussion on the wind down of energy marketing.

The followingtable summarizes the segment information for IDACORP's utility operations,energy marketing operations and the total of all other segments, and reconcilesthis information to total enterprise amounts.

 

**Utility**

 

**Energy**

 

 

 

 

 

**Consolidated**

 

**Operations**

 

**Marketing**

 

**Other**

 

**Eliminations**

 

**Total**

 

**(thousands of  dollars)**

**2002**

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues 

$

869,040 

 

$

46,410 

 

$

13,350 

 

$

- 

 

$

928,800 

Operating  income (loss)

 

132,661 

 

 

(23,739)

 

 

(22,827)

 

 

- 

 

 

86,095 

Other income  (expense)

 

14,371 

 

 

(1,199)

 

 

(13,176)

 

 

(6,987)

 

 

(6,991)

Interest  expense (income) and other

 

62,529 

 

 

(345)

 

 

13,382 

 

 

(6,987)

 

 

68,579 

Income (loss)  before income taxes

 

81,739 

 

 

(24,593)

 

 

(46,621)

 

 

- 

 

 

10,525 

Income tax  expense (benefit)

 

(2,594)

 

 

(9,710)

 

 

(38,843)

 

 

- 

 

 

(51,147)

Net income  (loss)

 

84,333 

 

 

(14,883)

 

 

(7,778)

 

 

- 

 

 

61,672 

Total assets

 

2,738,493 

 

 

381,690 

 

 

358,471 

 

 

(226,016)

 

 

3,252,638 

Expenditures  for long-lived assets

 

129,132 

 

 

2,713 

 

 

50,591 

 

 

- 

 

 

182,436 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

**2001**

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues 

$

914,201 

 

$

348,663 

 

$

12,448 

 

$

- 

 

$

1,275,312 

Operating  income (loss)

 

90,102 

 

 

176,712 

 

 

(24,525)

 

 

- 

 

 

242,289 

Other income  (expense)

 

19,443 

 

 

1,795 

 

 

8,744 

 

 

(6,688)

 

 

23,294 

Interest  expense (income) and other

 

67,773 

 

 

220 

 

 

14,418 

 

 

(6,688)

 

 

75,723 

Income (loss)  before income taxes

 

42,850 

 

 

178,287 

 

 

(31,277)

 

 

- 

 

 

189,860 

Income tax  expense (benefit)

 

19,955 

 

 

71,068 

 

 

(26,377)

 

 

- 

 

 

64,646 

Net income  (loss)

 

22,895 

 

 

107,219 

 

 

(4,900)

 

 

- 

 

 

125,214 

Total assets

 

2,859,704 

 

 

717,659 

 

 

205,660 

 

 

(140,709)

 

 

3,642,314 

Expenditures  for long-lived assets

 

163,045 

 

 

6,749 

 

 

8,962 

 

 

- 

 

 

178,756 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

**2000**

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues 

$

837,006 

 

$

190,116 

 

$

22,663 

 

$

- 

 

$

1,049,785 

Operating  income (loss)

 

169,507 

 

 

94,520 

 

 

(16,717)

 

 

- 

 

 

247,310 

Other income  (expense)

 

16,350 

 

 

3,483 

 

 

15,879 

 

 

(5,395)

 

 

30,317 

Interest  expense (income) and other

 

63,660 

 

 

165 

 

 

8,496 

 

 

(5,395)

 

 

66,926 

Income (loss)  before income taxes

 

122,210 

 

 

97,863 

 

 

(9,372)

 

 

- 

 

 

210,701 

Income tax  expense (benefit)

 

48,171 

 

 

38,335 

 

 

(15,688)

 

 

- 

 

 

70,818 

Net income  (loss)

 

74,039 

 

 

59,508 

 

 

6,336 

 

 

- 

 

 

139,883 

Total assets

 

2,530,312 

 

 

1,312,045 

 

 

197,349 

 

 

- 

 

 

4,039,706 

Expenditures  for long-lived assets

 

125,746 

 

 

7,556 

 

 

37,961 

 

 

- 

 

 

171,263 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

**13.  REGULATORY MATTERS:**

**Wind Down of Energy Marketing**IDACORP announced on June 21, 2002 that IE would wind down its powermarketing operations.  In connectionwith the wind down, certain matters were identified that require resolutionwith the FERC or the IPUC.  Matters thatneed to be resolved with the FERC include:

A utility suchas IPC is entitled to transmission priority for its retail customers, whiletransmission for trading transactions must be purchased under the utility'sopen access tariff on the same basis as third parties.  It appears that in some transactions thisdistinction was not observed;

Certaintransactions between a utility and an affiliate are required to have prior FERCapproval.  Such prior approval was notsought for some electricity transactions between IE and IPC, such as spinningreserves and load following services, which are common industry services; and

Although IPCinformed the FERC before IE was split off from IPC that it intended to move theutility's power marketing business to IE, IPC's power marketing contracts wereassigned without formally obtaining the requisite prior approval of the FERC.

IE and IPC voluntarily contactedthe FERC in September 2002 to discuss these matters.  Since September, the FERC has made several requests for certaindocuments and other information all of which, except for those requests whichhave been deferred, IE and IPC have supplied. IE and IPC made additional filings with the FERC in November 2002, whichincluded requests for approval of certain electricity transactions, theassignment of certain contracts between IPC and IE and termination of theElectricity Supply Management Services Agreement entered into between IPC andIE in June 2001.

On February 26, 2003, the FERCapproved the assignment of certain wholesale power and transmission servicesagreements from IPC to IE.  The FERCalso found that IPC violated Section 203 of the Federal Power Act (FPA) byassigning the agreements in June 2001 without seeking prior approval from theFERC.  The FERC noted that noncompliancewith Section 203 of the FPA may prompt the FERC in certain instances to imposeremedies as a condition of its approval; however, no such remedies were imposedin the FERC order.

Should the FERC conclude thatits regulations or rate schedules were not complied with, it has significantdiscretion as to the appropriate remedies, if any.  The FERC's remedial authority includes the authority to requirerefunds, to order equitable relief, to suspend the authorization to sellwholesale power at market-based rates, and, in some instances, to imposemonetary penalties.

In an IPUC proceeding that hasbeen underway since May 2001, IPC and the IPUC staff have been working todetermine the appropriate compensation IE should provide to IPC as a result oftransactions between the affiliates. Similar state regulatory issues relating to the period prior to February2001 were determined by the IPUC in Order No. 28852 issued on September 28,2001. The IPUC ruled on these transactions again in Order No. 29026 for thetime period from March 2001 through March 2002.  The IPUC also approved IPC's ongoing hedging and risk managementstrategies in Order No. 29102 issued August 28, 2002.  This formalized IPC's agreement to implement a number of changesto its existing practices for managing risk and initiating hedging purchasesand sales.  In the same order, the IPUCdirected IPC to present a resolution or a status report to the IPUC no laterthan December 20, 2002 on additional compensation due to the utility for theuse of its transmission system and other capital assets by IE and any remainingtransfer pricing issues.  On December20, 2002, a status report was filed with the IPUC reporting no significantdevelopments.  IPC committed toproviding another status report to the IPUC on March 20, 2003.

IDACORP does not believe thatresolution of these transactions will have any adverse impact on its ongoingoperations.  However, because it cannotbe predicted at this point what regulatory actions might be taken or when, itcannot be determined what effect there may be on earnings and whether it willbe material.

As previously disclosed, theFERC filing made on May 14, 2001, with respect to the pricing of real-timeenergy transactions between IPC and IE, is still under review by the FERC.  For the period June 2001 through March 2002,IE paid IPC approximately $6 million, which was calculated based upon thepricing methodology for the period that was most favorable to IPC.  This amount was credited to Idaho retailcustomers through the PCA.  Anadditional $1 million has been paid to IPC for the period April 2002 throughJuly 2002 based upon the same pricing methodology.  However, until the FERC takes final action on this filing, ratesfor real-time transactions between IE and IPC are subject to adjustment.

**Deferred Power Supply Costs**IPC's deferred power supply costs consist of the following atDecember 31, 2002 and 2001 (in thousands of dollars):

 

**2002**

 

**2001**

 

 

 

 

 

 

Oregon deferral

$

14,172

 

$

14,866

 

 

 

 

 

 

Idaho PCA current year power supply cost  deferrals:

 

 

 

 

 

 

Deferral for 2001-2002 rate year

 

-

 

 

78,395

 

Deferral for 2002-2003 rate year

 

8,910

 

 

-

 

Irrigation load reduction program

 

-

 

 

69,586

 

Astaris load reduction agreement

 

27,160

 

 

62,247

 

 

 

 

 

 

 

Idaho PCA true-up awaiting recovery:

 

 

 

 

 

 

Irrigation and small general service deferral for  recovery in 

 

 

 

 

 

 

 

the 2003-2004 rate year

 

12,049

 

 

-

 

Industrial customer deferral for recovery in the  2003-2004 rate year

 

3,744

 

 

-

 

Remaining true-up authorized October 2001

 

-

 

 

36,500

 

Remaining true-up authorized May 2001

 

-

 

 

42,895

 

Remaining true-up authorized May 2002

 

74,253

 

 

-

 

 

 

 

 

 

 

Total deferral

$

140,288

 

$

304,489

 

 

 

 

 

 

 

**Idaho:**  IPC has a PCA mechanism that provides forannual adjustments to the rates charged to its Idaho retail customers.  These adjustments, which take effect in May,are based on forecasts of net power supply expenses and the true-up of theprior year's forecast. During the year, 90 percent of the difference betweenthe actual and forecasted costs is deferred with interest.  The ending balance of this deferral, calleda true-up, is then included in the calculation of the next year's PCAadjustment.

So far in the 2002-2003 PCA rateyear actual power supply costs have exceeded those anticipated in theforecast.  Below normal water conditionsare still impacting power supply costs even though power supply prices aresignificantly lower. In addition an Irrigation Load Reduction Program was completedin the 2001-2002 PCA rate year and the Astaris Voluntary Load Reduction costshave decreased, both reducing the PCA regulatory account balance from $290million as of December 31, 2001 to $126 million as of December 31, 2002.

On May 13, 2002, the IPUC issuedOrder No. 29026 related to the 2002-2003 PCA rate filing.  The order granted recovery of $255 millionof excess power supply costs, consisting of:

$209 million ofvoluntary load reduction and power supply costs incurred between March 1, 2001and March 31, 2002.

$28 million ofexcess power supply costs forecasted for the period April 2002 through March2003.

$18 million ofunamortized costs previously approved for recovery beginning October 1,2001.  The amount authorized in October2001 totaled $49 million.  This orderspreads the remaining October 2001 rate increase, which would have ended inSeptember 2002, through May 2003.

The order also:

Denied recoveryof $12 million of lost revenues resulting from the Irrigation Load ReductionProgram, and $2 million of other costs IPC sought to recover.

Deferredrecovery  of $12 million of costsrelated to irrigation and small general service customers.  In June 2002, the IPUC issued Order No.29065 deferring an additional $4 million applicable to certain industrialcustomers.  The $16 million will berecovered during the 2003-2004 PCA rate year, and IPC will earn a six percentcarrying charge on the balance.

Denied IPC'srequest to issue $172 million in Energy Cost Recovery Bonds, which would havespread the recovery of that amount over three years.

Discontinuedthe IPUC-required three-tiered rate structure for residential customers.

Authorized aseparate surcharge to collect approximately $3 million annually to fund futureconservation programs.

The IPUC had previously issuedOrder No. 28992 on April 15, 2002 disallowing the lost revenue portion of theIrrigation Load Reduction Program.  IPCbelieves that the IPUC's order is inconsistent with Order No. 28699, dated May25, 2001, that allowed recovery of such costs, and IPC filed a Petition forReconsideration on May 2, 2002.  OnAugust 29, 2002, the IPUC issued Order No. 29103 denying the Petition forReconsideration.  As a result of thisorder, approximately $12 million was expensed in September 2002.  IPC still believes it should be entitled toreceive recovery of this amount and has asked the Idaho Supreme Court to reviewthe IPUC's decision.  If successful, IPCwould record any amount recovered as revenue.

In the May 2001 PCA filing, IPCrequested recovery of $227 million of power supply costs.  The IPUC subsequently issued Order No. 28772authorizing recovery of $168 million, but deferring recovery of $59 millionpending further review.  The approvedamount resulted in an average rate increase of 31.6 percent.  After conducting hearings on the remaining$59 million, the IPUC in Order No. 28552 authorized recovery of $48 millionplus $1 million of accrued interest, beginning in October 2001.  The remaining $11 million not recovered inrates from the PCA filing was written off in September 2001.

In October 2001, IPC filed anapplication with the IPUC for an order approving inclusion in the 2002-2003 PCAof costs incurred for the Irrigation Load Reduction Program and the FMC/AstarisLoad Reduction Agreement.  These twoprograms were implemented in 2001 to reduce demand and were approved by theIPUC and the OPUC.  The costs incurredin 2001 for these two programs were $70 million for the Irrigation LoadReduction Program and $62 million for the FMC/Astaris Load ReductionAgreement.  The IPUC subsequently issuedOrder No. 28992 authorizing IPC to include direct costs it has accrued in theprograms, subject to later adjustments in the 2002-2003 PCA year.  As mentioned earlier, the IPUC also deniedIPC's request to recover lost revenues experienced from the Irrigation LoadReduction Program.

The May 2000 PCA rate adjustmentincreased Idaho general business customer rates by 9.5 percent, and resultedfrom forecasted below-average hydroelectric generating conditions.  Overall, the PCA adjustment increasedgeneral business revenue by approximately $38 million during the 2000-2001 rateperiod.

**Oregon: **IPC has also filed applications with the OPUCto recover calendar year 2001 extraordinary power supply costs applicable tothe Oregon jurisdiction.  In twoseparate 2001 orders, the OPUC has approved rate increases totaling sixpercent, which is the maximum annual rate of recovery allowed under Oregonstate law.  These increases arerecovering approximately $2 million annually. The Oregon deferred balance is $14 million as of December 31, 2002.

**Regulatory Assets and Liabilities**The following is a breakdown of IPC's regulatory assets andliabilities for the years 2002 and 2001:

 

**2002**

 

**2001**

 

**Assets**

 

**Liabilities**

 

**Assets**

 

**Liabilities**

 

**(thousands of dollars)**

 

 

Income taxes

$

327,934

 

$

41,013

 

$

209,832

 

$

41,290

Conservation

 

24,450

 

 

4,402

 

 

28,324

 

 

3,524

Employee benefits

 

1,909

 

 

-

 

 

2,825

 

 

-

PCA deferral and  amortization

 

126,116

 

 

-

 

 

289,623

 

 

-

Oregon deferral and  amortization

 

14,172

 

 

-

 

 

14,866

 

 

-

Derivatives

 

91

 

 

-

 

 

47,781

 

 

-

Other

 

4,634

 

 

1,272

 

 

5,991

 

 

1,126

Deferred investment tax  credits

 

-

 

 

67,560

 

 

-

 

 

68,016

 

Total

$

499,306

 

$

114,247

 

$

599,242

 

$

113,956

 

 

 

 

 

 

 

 

 

 

 

 

 

At December 31, 2002, IPC had $3million of regulatory assets, primarily SFAS 112, "Employers Accountingfor Postemployment Benefits" benefits and reorganization costs, that werenot earning a return on investment (excluding the $328 million that relates toincome taxes). The amortization period is three to four years.In the event that recovery of costs through rates becomes unlikely oruncertain, SFAS 71 would no longer apply. If IPC were to discontinue application of SFAS 71 for some or all of itsoperations, then these items may represent stranded investments.  If IPC is not allowed recovery of theseinvestments, it would be required to write off the applicable portion ofregulatory assets and the financial effects could be significant.

**14. DERIVATIVE FINANCIALINSTRUMENTS:**

**Energy Trading Contracts**The commodity transactionsentered into by IE are classified as energy trading contracts, orderivatives.  Under SFAS 133 and EITF98-10, these contracts are recorded on the balance sheet at fair market value.  This accounting treatment is also referredto as mark-to-market accounting. Mark-to-market accounting treatment can create a disconnect betweenrecorded earnings and realized cash flow. Marking a contract to market consists of reevaluating the market valueof the entire term of the contract at each reporting period and reflecting theresulting gain or loss in earnings for the period.  This change in value represents the difference between thecontract price and the current market value of the contract.  The change in market value of the contractcould result in large gains or losses recorded in earnings at each subsequentreporting period unless there are off-setting changes in value of off-settingcontracts. The gain or loss generated from the change in market value of theenergy trading contracts is a non-cash event. If these contracts are held to maturity, the cash flow from thecontracts, and their off-setting contracts, are realized over the life of thecontract.

When determiningthe fair value of marketing and trading contracts, IE uses actively quotedprices for contracts with similar terms as the quoted price, including specificdelivery points and maturities. To determine fair value of contracts with termsthat are not consistent with actively quoted prices IE uses, when available,prices provided by other external sources. When prices from external sourcesare not available, IE determines prices by using internal pricing models thatincorporate available current and historical pricing information. Finally, thefair market value of contracts is adjusted for the impact of market depth andliquidity, potential model error, and expected credit losses at thecounterparty level.

The followingtable details the gross margin for the energy marketing operations (inthousands of dollars):

 

 

**2002**

 

**2001**

 

**2000**

Gross Margin:

 

 

 

 

 

 

 

 

 

 

Realized or otherwise  settled

 

$

70,262 

 

$

149,956

 

$

180,196 

 

Unrealized

 

 

(65,965)

 

 

92,803

 

 

(34,865)

 

 

Total

 

$

4,297 

 

$

242,759

 

$

145,331 

 

 

 

 

 

 

 

 

 

 

 

**RiskManagement:**  When buying and selling energy, the volatilityof energy prices can have significant negative impact on profitability if notappropriately managed.  Also,counterparty creditworthiness is key to ensuring that transactions entered intocan withstand potentially dramatic market fluctuations.  To manage the risks inherent in the energycommodity industry IE's Risk Management Committee (RMC), comprised of IDACORPand IE officers, oversees IE's risk management program as defined in the riskmanagement policy.  The program isintended to manage the impact to earnings caused by the volatility of energyprices by mitigating commodity price risk, credit risk, and other risks relatedto the energy commodity business.

To manage therisks inherent in its portfolio, IE has established risk limits.  Market and credit risk is measured andreported daily to the members of the RMC.  Other tools used to manage credit risk are the holding of collateral inthe form of cash or letters of credit and the use of margining agreements withcounterparties when credit risk exceeds certain pre-determined thresholds.  Because of the volatile nature of energymarket prices, margining agreements can require the posting of large amounts ofcash between counterparties to hold as collateral against the value of theenergy contracts.  This practicemitigates credit risk but increases the need for cash or other liquidsecurities to ensure the ability to meet all margin requirements when themarkets are most volatile.

**15.  RESTRUCTURING COSTS:**

In 2002, IDACORP announced two separate plans to wind downIE's energy marketing operations. The initial announcement, in June 2002,specified that IE would not seek new electric customers; would limit itsmaximum value at risk to less than $3 million; would target a reduction ofworking capital requirements to less than $100 million by the end of 2003; andwould reduce its workforce at its Boise operations by approximately 50percent.  The second announcement, inNovember 2002, indicated that IE would close its Denver office by year-end2002, would shut down its natural gas trading operation in Houston by March2003, and would result in additional workforce reductions in Boise operationsthrough mid-2003.  Since the initialannouncement in June 2002, IE has reduced its workforce by over 60 percent andwill continue to reduce its workforce as contractual obligations terminate.

In 2002, IE accrued $5 million of involuntary terminationbenefit expenses and approximately $4 million of lease termination and otherexit-related costs.  These costs are classifiedas "energy marketing - selling, general and administrative" on theconsolidated statements of income.  Ofthese amounts, $1 million of involuntary termination benefits have been paid asof December 31, 2002.  The terminationbenefit expense relates to the termination of 98 employees (primarily energytraders and administrative support positions), 51 of whom had been laid off byDecember 31, 2002.  Nineteen of the 51employees laid off by IE in 2002 were hired by other IDACORP subsidiaries, andthus received no severance benefits.

 

 

 

**INDEPENDENT AUDITORS' REPORT**

 

To the Board ofDirectors and Shareholders of IDACORP, Inc.Boise, Idaho

We have auditedthe accompanying consolidated balance sheets of IDACORP, Inc. and itssubsidiaries as of December 31, 2002 and 2001, and the related consolidatedstatements of income, comprehensive income, shareholders' equity and cash flowsfor each of the three years in the period ended December 31, 2002.  Our audits also included the consolidatedfinancial statement schedule listed in the Index at Item 8.  These financial statements and financialstatement schedule are the responsibility of the Company's management.  Our responsibility is to express an opinionon the financial statements and financial statement schedule based on ouraudits.

We conducted ouraudits in accordance with auditing standards generally accepted in the UnitedStates of America.  Those standardsrequire that we plan and perform the audit to obtain reasonable assurance aboutwhether the financial statements are free of material misstatement.  An audit includes examining, on a testbasis, 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 ouraudits provide a reasonable basis for our opinion.

In our opinion,such consolidated financial statements present fairly, in all material respects,the financial position of IDACORP, Inc. and subsidiaries at December 31, 2002and 2001, and the results of their operations and their cash flows for each ofthe three years in the period ended December 31, 2002 in conformity withaccounting principles generally 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.

As discussed in Note 1 to the consolidated financialstatements, in 2002 the Company changed its method of accounting for goodwillto conform to Statement of Financial Accounting Standards No. 142.  Also as discussed in Note 1, the Companychanged its presentation of energy trading activities in accordance withEmerging Issues Task Force Issue Nos. 98-10 and 02-3.

 

 

 

DELOITTE &TOUCHE LLP

Boise, IdahoFebruary 6, 2003

 

 

 

 

 

**(Thispage intentionally left blank.)**

 

 

 

 

 

 

**IdahoPower CompanyConsolidated Statements of Income**

 

**Year Ended December 31,**

 

**2002**

 

**2001**

 

**2000**

 

**(thousands of dollars)**

**OPERATING REVENUES:**

 

 

 

 

 

 

 

 

 

General business

$

772,035 

 

$

650,608 

 

$

565,357 

 

Off-system sales

 

55,031 

 

 

219,966 

 

 

229,986 

 

Other revenues

 

39,981 

 

 

41,738 

 

 

40,319 

 

 

Total operating revenues

 

867,047 

 

 

912,312 

 

 

835,662 

**OPERATING EXPENSES:**

 

 

 

 

 

 

 

 

 

Operation:

 

 

 

 

 

 

 

 

 

 

Purchased power

 

142,102 

 

 

584,209 

 

 

398,649 

 

 

Fuel expense

 

102,871 

 

 

98,318 

 

 

94,215 

 

 

Power cost adjustment

 

170,489 

 

 

(175,925)

 

 

(120,688)

 

 

Other

 

150,884 

 

 

153,079 

 

 

146,424 

 

Maintenance

 

54,599 

 

 

55,877 

 

 

46,973 

 

Depreciation

 

93,609 

 

 

87,041 

 

 

80,287 

 

Taxes other than income taxes

 

19,953 

 

 

19,693 

 

 

20,166 

 

 

Total operating expenses

 

734,507 

 

 

822,292 

 

 

666,026 

 

 

 

 

 

 

 

 

 

**INCOME FROM OPERATIONS**

 

132,540 

 

 

90,020 

 

 

169,636 

 

 

 

 

 

 

 

 

 

**OTHER INCOME:**

 

 

 

 

 

 

 

 

 

Allowance for equity funds used during  construction

 

333 

 

 

752 

 

 

2,565 

 

Other  - net

 

11,395 

 

 

19,847 

 

 

11,389 

 

 

Total other income

 

11,728 

 

 

20,599 

 

 

13,954 

 

 

 

 

 

 

 

 

 

**INTEREST CHARGES:**

 

 

 

 

 

 

 

 

 

Interest on long-term debt

 

51,127 

 

 

55,704 

 

 

53,253 

 

Other interest

 

9,190 

 

 

10,402 

 

 

4,544 

 

Allowance for borrowed funds used during

 

 

 

 

 

 

 

 

 

 

construction

 

(2,375)

 

 

(3,737)

 

 

(2,346)

 

 

Total interest charges

 

57,942 

 

 

62,369 

 

 

55,451 

 

 

 

 

 

 

 

 

 

**INCOME BEFORE INCOME TAXES**

 

86,326 

 

 

48,250 

 

 

128,139 

 

 

 

 

 

 

 

 

 

**INCOME TAX EXPENSE (BENEFIT)**

 

(2,594)

 

 

19,955 

 

 

48,171 

 

 

 

 

 

 

 

 

 

**INCOME FROM CONTINUING OPERATIONS**

 

88,920 

 

 

28,295 

 

 

79,968 

 

 

 

 

 

 

 

 

 

**DISCONTINUED OPERATIONS**

 

 

 

 

 

 

 

 

 

Income from operations of energy marketing

 

 

 

 

 

 

 

 

 

 

transferred to parent (net of tax of $33,574

 

 

 

 

 

 

 

 

 

 

and $37,397)

 

- 

 

 

49,943 

 

 

57,520 

 

 

 

 

 

 

 

 

 

**NET INCOME**

 

88,920 

 

 

78,238 

 

 

137,488 

 

 

 

 

 

 

 

 

 

 

Dividends on preferred stock

 

4,587 

 

 

5,400 

 

 

5,929 

 

 

 

 

 

 

 

 

 

**EARNINGS ON COMMON STOCK**

$

84,333 

 

$

72,838 

 

$

131,559 

 

 

 

 

 

 

 

 

 

** **

 

The accompanyingnotes are an integral part of these statements.

 

 

 

 

 

 

 

 

**IdahoPower CompanyConsolidated Balance Sheets**

**Assets**

 

 

**December 31,**

 

 

**2002**

 

**2001**

 

 

**(thousands of dollars)**

 

 

 

**ELECTRIC PLANT:**

 

 

 

 

 

 

 

In  service (at original cost)

 

$

3,086,965 

 

$

2,989,630 

 

Accumulated  provision for depreciation

 

 

(1,294,961)

 

 

(1,220,002)

 

 

In  service - Net

 

 

1,792,004 

 

 

1,769,628 

 

Construction  work in progress

 

 

92,481 

 

 

86,010 

 

Held  for future use

 

 

2,335 

 

 

2,232 

 

 

 

 

 

 

 

 

 

 

Electric  plant - Net

 

 

1,886,820 

 

 

1,857,870 

 

 

 

 

 

 

 

**INVESTMENTS AND OTHER  PROPERTY**

 

 

42,272 

 

 

37,432 

 

 

 

 

 

 

 

**CURRENT ASSETS:**

 

 

 

 

 

 

 

Cash  and cash equivalents

 

 

12,699 

 

 

43,040 

 

Receivables:

 

 

 

 

 

 

 

 

Customer

 

 

56,947 

 

 

58,702 

 

 

Allowance  for uncollectible accounts

 

 

(1,566)

 

 

(1,500)

 

 

Notes

 

 

4,992 

 

 

3,488 

 

 

Employee  notes

 

 

7,646 

 

 

6,274 

 

 

Related  parties

 

 

27,905 

 

 

37,517 

 

 

Other

 

 

2,702 

 

 

2,280 

 

Taxes  receivable

 

 

- 

 

 

8,244 

 

Accrued  unbilled revenues

 

 

35,714 

 

 

37,400 

 

Materials  and supplies (at average cost)

 

 

21,458 

 

 

23,280 

 

Fuel  stock (at average cost)

 

 

6,943 

 

 

8,726 

 

Prepayments

 

 

32,818 

 

 

31,897 

 

Regulatory  assets

 

 

17,147 

 

 

55,107 

 

 

 

 

 

 

 

 

 

 

Total  current assets

 

 

225,405 

 

 

314,455 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

**DEFERRED DEBITS:**

 

 

 

 

 

 

 

American  Falls and Milner water rights

 

 

31,585 

 

 

31,585 

 

Company-owned  life insurance

 

 

35,299 

 

 

39,602 

 

Regulatory  assets

 

 

482,159 

 

 

544,135 

 

Other

 

 

34,953 

 

 

34,625 

 

 

 

 

 

 

 

 

 

 

Total  deferred debits

 

 

583,996 

 

 

649,947 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

**TOTAL**

 

$

2,738,493 

 

$

2,859,704 

 

 

 

 

 

 

 

 

The accompanyingnotes are an integral part of these statements.

 

 

 

 

 

 

 

 

 

**Idaho Power CompanyConsolidated Balance Sheets**

**Capitalization and Liabilities**

 

 

**December 31,**

 

 

**2002**

 

**2001**

 

 

 

**(thousands of dollars)**

**CAPITALIZATION:**

 

 

 

 

 

 

 

Common  stock equity:

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

authorized;  37,612,351 shares outstanding)

 

$

94,031 

 

$

94,031 

 

 

Premium  on capital stock

 

 

361,948 

 

 

362,602 

 

 

Capital  stock expense

 

 

(2,710)

 

 

(4,144)

 

 

Retained  earnings

 

 

330,300 

 

 

316,856 

 

 

Accumulated  other comprehensive income (loss)

 

 

(7,109)

 

 

(3,719)

 

 

 

 

 

 

 

 

 

 

Total  common stock equity

 

 

776,460 

 

 

765,626 

 

 

 

 

 

 

 

 

Preferred  stock

 

 

53,393 

 

 

104,387 

 

 

 

 

 

 

 

 

Long-term  debt

 

 

870,741 

 

 

802,201 

 

 

 

 

 

 

 

 

 

 

Total  capitalization

 

 

1,700,594 

 

 

1,672,214 

 

 

 

 

 

 

 

**CURRENT LIABILITIES:**

 

 

 

 

 

 

 

Long-term  debt due within one year

 

 

80,084 

 

 

27,078 

 

Notes  payable

 

 

10,500 

 

 

282,000 

 

Accounts  payable

 

 

52,676 

 

 

68,806 

 

Notes  and accounts payable to related parties

 

 

52 

 

 

6,931 

 

Taxes  accrued

 

 

89,090 

 

 

- 

 

Derivative  liabilities

 

 

- 

 

 

40,528 

 

Interest  accrued

 

 

12,399 

 

 

13,115 

 

Deferred  income taxes

 

 

17,056 

 

 

14,578 

 

Other

 

 

22,906 

 

 

16,118 

 

 

 

 

 

 

 

 

 

 

Total  current liabilities

 

 

284,763 

 

 

469,154 

 

 

 

 

 

 

 

**DEFERRED CREDITS:**

 

 

 

 

 

 

 

Deferred  income taxes

 

 

574,233 

 

 

541,482 

 

Derivative  liabilities - long-term

 

 

- 

 

 

7,253 

 

Regulatory  liabilities

 

 

114,247 

 

 

113,956 

 

Other

 

 

64,656 

 

 

55,645 

 

 

 

 

 

 

 

 

 

 

Total  deferred credits

 

 

753,136 

 

 

718,336 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

**COMMITMENTS AND CONTINGENT  LIABILITIES**

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

**TOTAL**

 

$

2,738,493 

 

$

2,859,704 

 

 

 

 

 

 

 

 

The accompanyingnotes are an integral part of these statements.

 

 

 

 

 

 

 

 

 

 

**Idaho Power CompanyConsolidated Statements of Capitalization**

 

 

**December 31,**

 

 

**2002**

 

**%**

 

**2001**

 

**%**

 

 

**(thousands of dollars)**

**COMMON STOCK EQUITY:**

 

 

 

Common  stock

 

$

94,031 

 

 

 

$

94,031 

 

 

 

Premium  on capital stock

 

 

361,948 

 

 

 

 

362,602 

 

 

 

Capital  stock expense

 

 

(2,710)

 

 

 

 

(4,144)

 

 

 

Retained  earnings

 

 

330,300 

 

 

 

 

316,856 

 

 

 

Accumulated  other comprehensive income (loss)

 

 

(7,109)

 

 

 

 

(3,719)

 

 

 

 

Total  common stock equity

 

 

776,460 

 

46

 

 

765,626 

 

46

 

 

 

 

 

 

 

 

 

 

 

**PREFERRED STOCK:**

 

 

 

 

 

 

 

 

 

 

 

4%  preferred stock

 

 

13,393 

 

 

 

 

14,387 

 

 

 

7.68%  Series, serial preferred stock

 

 

15,000 

 

 

 

 

15,000 

 

 

 

7.07%  Series, serial preferred stock

 

 

25,000 

 

 

 

 

25,000 

 

 

 

Auction  rate preferred stock

 

 

- 

 

 

 

 

50,000 

 

 

 

 

Total  preferred stock

 

 

53,393 

 

3

 

 

104,387 

 

6

 

 

 

 

 

 

 

 

 

 

 

**LONG-TERM DEBT:**

 

 

 

 

 

 

 

 

 

 

 

First  mortgage bonds:

 

 

 

 

 

 

 

 

 

 

 

 

6.85%  Series due 2002

 

 

- 

 

 

 

 

27,000 

 

 

 

 

6.40%  Series due 2003

 

 

80,000 

 

 

 

 

80,000 

 

 

 

 

8     %   Series due 2004

 

 

50,000 

 

 

 

 

50,000 

 

 

 

 

5.83%  Series due 2005

 

 

60,000 

 

 

 

 

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 

 

 

 

 

- 

 

 

 

 

7.50%  Series due 2023

 

 

80,000 

 

 

 

 

80,000 

 

 

 

 

8.75%  Series due 2027

 

 

- 

 

 

 

 

50,000 

 

 

 

 

6     %  Series due 2032

 

 

100,000 

 

 

 

 

- 

 

 

 

 

 

Total  first mortgage bonds

 

 

750,000 

 

 

 

 

627,000 

 

 

 

 

Amount  due within one year

 

 

(80,000)

 

 

 

 

(27,000)

 

 

 

 

 

Net  first mortgage bonds

 

 

670,000 

 

 

 

 

600,000 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Pollution  control revenue bonds:

 

 

 

 

 

 

 

 

 

 

 

 

8.30%  Series 1984 due 2014

 

 

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 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

REA  notes

 

 

1,185 

 

 

 

 

1,263 

 

 

 

 

Amount  due within one year

 

 

(84)

 

 

 

 

(78)

 

 

 

 

 

Net  REA notes

 

 

1,101 

 

 

 

 

1,185 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

American  Falls bond guarantee

 

 

19,885 

 

 

 

 

19,885 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Milner  Dam note guarantee

 

 

11,700 

 

 

 

 

11,700 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Unamortized  premium/discount - Net

 

 

(2,405)

 

 

 

 

(1,029)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total  long-term debt

 

 

870,741 

 

51

 

 

802,201 

 

48

 

 

 

 

 

 

 

 

 

 

 

**TOTAL CAPITALIZATION**

 

$

1,700,594 

 

100

 

$

1,672,214 

 

100

 

 

 

 

 

 

 

 

 

 

 

 

Theaccompanying notes are an integral part of these statements.

 

 

 

 

 

 

**Idaho Power CompanyConsolidated Statements of Cash Flows**

 

**Year Ended December 31,**

 

**2002**

 

**2001**

 

**2000**

 

**(thousands of dollars)**

**OPERATING ACTIVITIES:**

 

 

 

 

 

 

 

 

 

Net  income

$

88,920 

 

$

78,238 

 

$

137,488 

 

Adjustments  to reconcile net income to net cash provided by

 

 

 

 

 

 

 

 

 

(used  in) operating activities:

 

 

 

 

 

 

 

 

 

 

Other  than temporary decline in market value of investments

 

980 

 

 

- 

 

 

- 

 

 

Allowance  for uncollectible accounts

 

66 

 

 

20,277 

 

 

21,682 

 

 

Unrealized  gains from energy marketing activities

 

- 

 

 

(100,653)

 

 

21,847 

 

 

Depreciation  and amortization

 

104,948 

 

 

99,565 

 

 

92,677 

 

 

Deferred  taxes and investment tax credits

 

(81,511)

 

 

103,425 

 

 

44,911 

 

 

Accrued  PCA costs

 

164,201 

 

 

(184,584)

 

 

(122,353)

 

 

Change  in:

 

 

 

 

 

 

 

 

 

 

 

Accounts  receivable and prepayments

 

(3,205)

 

 

(20,837)

 

 

(165,759)

 

 

 

Accrued  unbilled revenue

 

1,687 

 

 

7,425 

 

 

(12,831)

 

 

 

Materials  and supplies and fuel stock

 

3,605 

 

 

(2,216)

 

 

5,544 

 

 

 

Accounts  payable

 

(23,009)

 

 

(26,142)

 

 

156,932 

 

 

 

Taxes  receivable/accrued

 

97,335 

 

 

(21,227)

 

 

(8,326)

 

 

 

Other  current assets and liabilities

 

5,980 

 

 

(2,081)

 

 

(3,572)

 

 

Other  - net

 

5,921 

 

 

(10,788)

 

 

(6,843)

 

 

Net  cash provided by (used in) operating activities

 

365,918 

 

 

(59,598)

 

 

161,397 

 

 

 

 

 

 

 

 

 

**INVESTING ACTIVITIES:**

 

 

 

 

 

 

 

 

 

Additions  to utility plant

 

(128,318)

 

 

(156,787)

 

 

(131,711)

 

Note  receivable payment from parent

 

11,859 

 

 

42,743 

 

 

- 

 

Net  cash of affiliates transferred to parent

 

- 

 

 

- 

 

 

(4,737)

 

Other  - net

 

(3,437)

 

 

149 

 

 

838 

 

 

Net  cash used in investing activities

 

(119,896)

 

 

(113,895)

 

 

(135,610)

 

 

 

 

 

 

 

 

 

**FINANCING ACTIVITIES:**

 

 

 

 

 

 

 

 

 

Issuance  of first mortgage bonds

 

200,000 

 

 

120,000 

 

 

80,000 

 

Issuance  of pollution control revenue bonds

 

- 

 

 

- 

 

 

4,360 

 

Retirement  of first mortgage bonds

 

(77,000)

 

 

(130,000)

 

 

(80,000)

 

Retirement  of pollution control revenue bonds

 

- 

 

 

- 

 

 

(4,360)

 

Retirement  of preferred stock

 

(50,994)

 

 

- 

 

 

- 

 

Dividends  on common stock

 

(70,178)

 

 

(69,782)

 

 

(69,850)

 

Dividends  on preferred stock

 

(4,587)

 

 

(5,400)

 

 

(5,929)

 

Increase  (decrease) in short-term borrowings

 

(271,500)

 

 

222,300 

 

 

39,943 

 

Other  - net

 

(2,104)

 

 

(4,079)

 

 

(1,495)

 

 

Net  cash provided by (used in) financing activities

 

(276,363)

 

 

133,039 

 

 

(37,331)

 

 

 

 

 

 

 

 

 

Net  increase (decrease) in cash and cash equivalents

 

(30,341)

 

 

(40,454)

 

 

(11,544)

 

 

 

 

 

 

 

 

 

Cash  and cash equivalents at beginning of period

 

43,040 

 

 

83,494 

 

 

95,038 

 

 

 

 

 

 

 

 

 

Cash  and cash equivalents at end of period

$

12,699 

 

$

43,040 

 

$

83,494 

 

 

 

 

 

 

 

 

 

**SUPPLEMENTAL  DISCLOSURE OF CASH FLOW INFORMATION:**

 

Cash  paid (received) during the period for:

 

 

 

 

 

 

 

 

 

 

Income  taxes

$

(17,974)

 

$

(28,510)

 

$

47,732 

 

 

Interest  (net of amount capitalized)

 

56,167 

 

 

61,600 

 

 

58,090 

 

Net  non-cash assets of affiliates transferred to parent

 

- 

 

 

- 

 

 

17,353 

 

Net  assets transferred to parent for notes receivable

 

- 

 

 

76,250 

 

 

- 

 

 

 

 

 

 

 

 

 

 

The accompanyingnotes are an integral part of these statements.

 

 

 

 

 

 

**Idaho Power CompanyConsolidated Statements of Retained Earnings**

 

**Year Ended December 31,**

 

**2002**

 

**2001**

 

**2000**

 

**(thousands of dollars)**

 

 

 

 

 

 

 

 

 

**RETAINED  EARNINGS, BEGINNING OF YEAR**

$

316,856 

 

$

313,800 

 

$

274,181 

 

 

 

 

 

 

 

 

 

**NET  INCOME**

 

88,920 

 

 

78,238 

 

 

137,488 

 

 

 

 

 

 

 

 

 

**DIVIDENDS:**

 

 

 

 

 

 

 

 

 

Common  stock 

 

(70,178)

 

 

(69,782)

 

 

(69,850)

 

Preferred  stock

 

(4,587)

 

 

(5,400)

 

 

(5,929)

 

 

 

 

 

 

 

 

 

**PREFERRED  STOCK REDEMPTION**

 

(711)

 

 

- 

 

 

- 

 

 

 

 

 

 

 

 

 

**TRANSFER  TO IDACORP, INC.**

 

- 

 

 

- 

 

 

(22,090)

 

 

 

 

 

 

 

 

 

**RETAINED  EARNINGS, END OF YEAR**

$

330,300 

 

$

316,856 

 

$

313,800 

 

The accompanyingnotes are an integral part of these statements.

 

 

 

 

 

 

**Idaho Power CompanyConsolidated Statements of Comprehensive Income**

 

**Year Ended December 31,**

 

**2002**

 

**2001**

 

**2000**

 

**(thousands of dollars)**

 

 

 

 

 

 

 

 

 

**NET INCOME**

$

88,920 

 

$

78,238 

 

$

137,488 

 

 

 

 

 

 

 

 

 

**OTHER COMPREHENSIVE INCOME  (LOSS):**

 

 

 

 

 

 

 

 

 

Unrealized  gains on securities:

 

 

 

 

 

 

 

 

 

 

Unrealized  holding gains (losses) arising during the period, 

 

 

 

 

 

 

 

 

 

 

 

net  of tax of ($1,840), ($992) and ($1,674)

 

(2,991)

 

 

(1,690)

 

 

(2,275)

 

 

Less:  reclassification adjustment for (gains)  losses included

 

 

 

 

 

 

 

 

 

 

 

in  net income, net of tax of $1,007, ($52) and ($39)

 

1,560 

 

 

(80)

 

 

(60)

 

 

 

Net  unrealized gains

 

(1,431)

 

 

(1,770)

 

 

(2,335)

 

Minimum  pension liability adjustment (net of tax of ($1,265),

 

 

 

 

 

 

 

 

 

 

($649)  and ($78))

 

(1,959)

 

 

(1,028)

 

 

(119)

 

 

 

 

 

 

 

 

 

**TOTAL COMPREHENSIVE INCOME**

$

85,530 

 

$

75,440 

 

$

135,034 

 

 

 

 

 

 

 

 

 

 

The accompanyingnotes are an integral part of these statements.

 

 

 

 

 

 

 

 

 

 

**IDAHOPOWER COMPANYNOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS**

The outstanding shares of IPC'scommon stock were exchanged on a share-for-share basis into common stock ofIDACORP on October 1, 1998 and are no longer actively traded.  IPC's preferred stock and debt securities wereunaffected.

Except as modified below, theNotes to the Consolidated Financial Statements of IDACORP included in this 2002Annual Report on Form 10-K are incorporated herein by reference insofar as theyrelate to IPC.

Note 1 -Summary of Significant Accounting PoliciesNote 2 - Income TaxesNote 4 - Preferred Stock of Idaho Power CompanyNote 5 - Long-Term DebtNote 7 - Notes PayableNote 8 - Commitments and ContingentLiabilitiesNote 10 - Benefit PlansNote 11 - Property, Plant and Equipment and Jointly-Owned ProjectsNote 13 - Regulatory Matters

1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

**Stock-Based Compensation**At December 31, 2002, two stock-based employee compensation plansexisted, which are described more fully in Note 9.  These plans are accounted for under the recognition and measurementprinciples of Accounting Principles Board Opinion 25, "Accounting forStock Issued to Employees," and related interpretations.  Grants of restricted stock are reflected innet income based on the market value at the award date, or the year-end pricefor shares not yet vested.  Nostock-based employee compensation cost is reflected in net income for stockoptions, as all options granted under these plans had an exercise price equalto the market value of the underlying common stock on the date of grant.  The following table illustrates the effecton net income if the fair value recognition provisions of SFAS 123,"Accounting for Stock-Based Compensation," had been applied tostock-based employee compensation:

 

**2002**

 

**2001**

 

**2000**

 

**(thousands of dollars)**

 

 

 

 

 

 

 

 

 

Net income, as reported

$

88,920 

 

$

78,238

 

$

137,488

Add: Stock-based employee compensation expense  included 

 

 

 

 

 

 

 

 

 

in reported net income, net of related tax effects

 

(10)

 

 

403

 

 

852

Deduct: Total stock-based employee compensation  expense 

 

 

 

 

 

 

 

 

 

determined under fair value based method for all  awards, 

 

 

 

 

 

 

 

 

 

net of related tax effects

 

1,837 

 

 

1,603

 

 

976

 

 

Pro forma net income

$

87,073 

 

$

77,038

 

$

137,364

 

 

 

 

 

 

 

 

 

 

 

**2.  INCOME TAXES:**

IPC's effective tax rate for the year ended December 31, 2002 decreasedfrom 40.6 percent in 2001 to a benefit of three percent in 2002.  Tax benefit items occurring in 2002 includea tax accounting method change and the settlement of a partnership audit, whichresulted in a decrease to tax expense.

A reconciliationbetween the statutory federal income tax rate and the effective rate is asfollows:

 

 

**2002**

 

**2001**

 

**2000**

 

 

**(thousands of dollars)**

 

 

 

Computed  income taxes based on statutory federal income tax rate

$

30,214    

 

$

46,118   

 

$

78,070   

Change  in taxes resulting from:

 

 

 

 

 

 

 

 

 

AFDC

 

(948)   

 

 

(1,571)  

 

 

(1,719)  

 

Investment  tax credits

 

(3,179)   

 

 

(3,169)  

 

 

(3,083)  

 

Repair  allowance

 

(2,450)   

 

 

(2,800)  

 

 

(4,550)  

 

Capitalized  overhead costs

 

(3,500)   

 

 

-   

 

 

-   

 

Tax  accounting method change

 

(31,162)   

 

 

-   

 

 

-   

 

Settlement  of prior years tax returns

 

(2,600)   

 

 

-   

 

 

2   

 

State  income taxes (net of federal reduction)

 

3,946    

 

 

4,313   

 

 

9,465   

 

Depreciation

 

8,940    

 

 

9,790   

 

 

8,243   

 

Other

 

(1,855)   

 

 

848   

 

 

(860)  

Total  provision (benefit) for federal and state income taxes

$

(2,594)   

 

$

53,529   

 

$

85,568   

 

Effective  tax rate

 

(3.0)%

 

 

40.6%

 

 

38.4%

 

 

 

 

 

 

 

 

 

 

 

The provision forincome taxes consists of the following:

 

 

**2002**

 

**2001**

 

**2000**

 

 

**(thousands of dollars)**

Income  taxes currently (receivable) payable:

 

 

 

 

 

 

 

 

 

Federal

$

70,318 

 

$

(37,352)

 

$

35,259 

 

State

 

8,599 

 

 

(12,544)

 

 

5,398 

 

 

Total

 

78,917 

 

 

(49,896)

 

 

40,657 

Income  taxes deferred - net of amortization:

 

 

 

 

 

 

 

 

 

Federal

 

(75,600)

 

 

84,372 

 

 

38,887 

 

State

 

(5,455)

 

 

17,087 

 

 

7,407 

 

 

Total

 

(81,055)

 

 

101,459 

 

 

46,294 

Investment  tax credits:

 

 

 

 

 

 

 

 

 

Deferred

 

2,722 

 

 

5,135 

 

 

1,700 

 

Restored

 

(3,178)

 

 

(3,169)

 

 

(3,083)

 

 

Total

 

(456)

 

 

1,966 

 

 

(1,383)

Total  provision (benefit) for income taxes

$

(2,594)

 

$

53,529 

 

$

85,568 

 

 

 

 

 

 

 

 

 

 

The tax effectsof significant items comprising IPC's net deferred tax liabilities are asfollows:

 

 

**2002**

 

**2001**

 

 

**(thousands of dollars)**

Deferred  tax assets:

 

 

 

 

 

 

Regulatory  liabilities

$

41,013

 

$

41,290

 

Advances  for construction

 

3,759

 

 

3,941

 

Other

 

19,800

 

 

16,825

 

 

Total

 

64,572

 

 

62,056

Deferred  tax liabilities:

 

 

 

 

 

 

Utility  plant

 

230,935

 

 

250,180

 

Regulatory  assets

 

327,933

 

 

209,832

 

Conservation  programs

 

10,426

 

 

11,138

 

PCA

 

53,324

 

 

119,436

 

Other

 

33,243

 

 

27,530

 

 

Total

 

655,861

 

 

618,116

 

 

 

 

 

 

Net  deferred tax liabilities

$

591,289

 

$

556,060

 

 

 

 

 

 

 

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

The estimated fair value ofIPC's financial instruments has been determined using available marketinformation and appropriate valuation methodologies.  The use of different market assumptions and/or estimationmethodologies may have a material effect on the estimated fair value amounts.

Cash and cash equivalents, customer and other receivables,notes payable, accounts payable, interest accrued, and taxes accrued arereported at their carrying value as these are a reasonable estimate of theirfair value. The estimated fair values for notes receivable, fixed ratelong-term debt and investments and other property are based upon quoted marketprices of the same or similar issues or discounted cash flow analyses asappropriate.

 

**December 31, 2002**

 

**December 31, 2001**

 

**Carrying**

 

**Estimated**

 

**Carrying**

 

**Estimated**

 

**Amount**

 

**Fair Value**

 

**Amount**

 

**Fair Value**

 

**(thousands of  dollars)**

**Assets:**

 

 

 

 

 

 

 

 

 

 

 

Notes  receivable

$

9,646

 

$

10,063

 

$

12,009

 

$

11,207

Investments  and other property

 

20,401

 

 

20,401

 

 

16,729

 

 

16,729

 

 

 

 

 

 

 

 

 

 

 

 

**Liabilities:**

 

 

 

 

 

 

 

 

 

 

 

Fixed  rate long-term debt

 

953,230

 

 

1,015,612

 

 

830,508

 

 

867,808

 

 

 

 

 

 

 

 

 

 

 

 

 

**9.  STOCK-BASEDCOMPENSATION:**

IDACORP adoptedthe 2000 LTICP for officers, key employees and directors including those ofIPC.  The LTICP permits the grant ofnonqualified stock options, incentive stock options, stock appreciation rights,restricted stock, restricted stock units, performance units, performance sharesand other awards.

Stock optiontransactions are summarized as follows:

 

 

**2002**

 

**2001**

 

**2000**

 

 

 

 

**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

477,000

 

$

37.79

 

220,000

 

$

35.81

 

-

 

$

-

 

Granted

244,950

 

 

39.50

 

257,000

 

 

39.48

 

220,000

 

 

35.81

 

Exercised

-

 

 

-

 

-

 

 

-

 

-

 

 

-

 

Cancelled

-

 

 

-

 

-

 

 

-

 

-

 

 

-

Outstanding end of year

721,950

 

$

38.37

 

477,000

 

$

37.79

 

220,000

 

$

35.81

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Exercisable

139,400

 

$

37.16

 

44,000

 

$

35.81

 

-

 

$

-

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

The outstandingoptions have a range of exercise prices from $35.81 to $40.31.  As of December 31, 2002, the weightedaverage remaining contractual life is 8.3 years.

IDACORP also hasa restricted stock plan for certain key employees including those of IPC.  Each grant made under this plan has athree-year restricted period, and the final award amounts depend on theattainment of cumulative EPS performance goals.  At December 31, 2002 there were 201,539 IDACORP shares remainingavailable under this plan.

Restricted stockawards are compensatory awards and IPC accrues compensation expense (which ischarged to operations) based upon the market value of the granted shares.  For the years 2002, 2001 and 2000, totalcompensation accrued under the plan was less than $1 million annually.

The followingtable summarizes restricted stock activity for the years 2002, 2001 and 2000:

 

**2002**

 

**2001**

 

**2000**

Shares outstanding -  beginning of year

53,878 

 

52,719 

 

49,815 

Shares granted

37,197 

 

20,311 

 

27,462 

Shares forfeited

(179)

 

(474)

 

- 

Shares issued

(18,767)

 

(18,678)

 

(24,558)

Shares outstanding - end of  year

72,129

 

53,878 

 

52,719 

Weighted average fair value  of current year

 

 

 

 

 

 

stock grants on grant date

$

38.64 

 

$

38.02 

 

$

35.06 

 

 

 

 

 

 

 

**16.  DISCONTINUEDOPERATIONS:**

Effective June 11, 2001, IPC transferred its non-utilitywholesale electricity marketing operations ("Energy Marketing") toIE.

Energy Marketing net assets transferred consist primarily ofenergy trading contracts and trading accounts receivable and accountspayable.  The results of operations ofEnergy Marketing were previously reported on IPC's Statements of Income as"Energy marketing activities - net." For 2001 and 2000, Energy Marketing is reported as a discontinuedoperation.

**17. RELATED PARTY TRANSACTIONS:**

In exchange for the transfer of Energy Marketing to IE inJune 2001, IPC received a partnership interest in IE, which was thentransferred to IDACORP in exchange for notes receivable from IDACORP totalingapproximately $76 million.  This amountrepresents the historical book value of the transferred Energy Marketing netassets on May 31, 2001 of $21 million and retained intercompany tax liabilitiesof $55 million.  The notes receivableare due over periods of one to ten years and bear interest at IDACORP's overallvariable short-term borrowing rate, which was 1.8 percent at December 31, 2002.  The balance of this note at December 31,2002 is approximately $22 million, including accrued interest.

In September 2002, IPC borrowed$100 million from IDACORP in order to repay a like amount of floating ratenotes.  This amount was repaid, withinterest, on November 15, 2002.

In 2002 and 2001, IPC paid IEapproximately $2 million annually under the Electricity Supply ManagementServices Agreement.  IPC and IErequested termination of this agreement in a November 2002 FERC filing.

The following table presentsIPC's sales to and purchases from IE for the years ended December 31:

 

**2002**

 

**2001**

 

**2000**

 

**(thousands of dollars)**

 

 

 

 

 

 

 

 

 

Sales to IE

$

27,182

 

$

21,288

 

$

-

Purchases from IE

 

13,665

 

 

34,843

 

 

-

 

 

 

 

 

 

 

 

 

 

 

 

 

 

**INDEPENDENT AUDITORS' REPORT**

 

To the Board ofDirectors and Shareholder of Idaho Power CompanyBoise, Idaho

We have auditedthe accompanying consolidated balance sheets and statements of capitalizationof Idaho Power Company and its subsidiary as of December 31, 2002 and 2001, andthe related consolidated statements of income, comprehensive income, retainedearnings and cash flows for each of the three years in the period endedDecember 31, 2002.  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 ouraudits in accordance with auditing standards generally accepted in the UnitedStates of America.  Those standardsrequire that we plan and perform the audit to obtain reasonable assurance aboutwhether the financial statements are free of material misstatement.  An audit includes examining, on a testbasis, 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 ouraudits provide a reasonable basis for our opinion.

In our opinion,such consolidated financial statements present fairly, in all materialrespects, the financial position of Idaho Power Company and its subsidiary atDecember 31, 2002 and 2001, and the results of their operations and their cashflows for each of the three years in the period ended December 31, 2002 inconformity with accounting principles generally accepted in the United Statesof America.  Also, in our opinion, suchconsolidated financial statement schedule, when considered in relation to thebasic consolidated financial statements taken as a whole, presents fairly inall material respects the information set forth therein.

 

 

DELOITTE &TOUCHE LLP

Boise, IdahoFebruary 6, 2003

 

 

 

 

 

**SUPPLEMENTAL FINANCIAL INFORMATION, UNAUDITED**

**QUARTERLYFINANCIAL DATA:******

The followingunaudited information is presented for each quarter of 2002 and 2001 (inthousands of dollars except for per share amounts).  In the opinion of each company, all adjustments necessary for afair statement of such amounts for such periods have been included.  The results of operations for the interimperiods are not necessarily indicative of the results to be expected for thefull year.  Accordingly, earningsinformation for any three-month period should not be considered as a basis forestimating operating results for a full fiscal year.  Amounts are based upon quarterly statements and the sum of thequarters may not equal the annual amount reported.

**IDACORP, Inc.:**

 

**Quarter Ended**

 

**March  31**

 

**June  30**

 

**September 30**

 

**December 31**

 

 

 

 

 

 

 

 

 

 

 

 

2002

 

 

 

 

 

 

 

 

 

 

 

 

Revenues*

$

239,593

 

$

209,832 

 

$

259,577 

 

$

219,798 

 

Income from operations

 

47,257

 

 

7,743 

 

 

16,620 

 

 

14,476 

 

Income tax expense  (benefit)

 

9,329

 

 

(9,329)

 

 

(38,527)

 

 

(12,620)

 

Net income  (loss)

 

24,696

 

 

3,077 

 

 

36,908 

 

 

(3,008)

 

Earnings (loss)  per share of common stock

 

0.66

 

 

0.08 

 

 

0.98 

 

 

(0.08)

 

 

 

 

 

 

 

 

 

 

 

 

2001

 

 

 

 

 

 

 

 

 

 

 

 

Revenues*

$

310,026

 

$

326,873 

 

$

394,811 

 

$

243,602 

 

Income from operations

 

65,172

 

 

73,442 

 

 

65,690 

 

 

37,986 

 

Income tax expense  (benefit)

 

17,282

 

 

21,861 

 

 

17,055 

 

 

8,449 

 

Net income

 

34,770

 

 

36,088 

 

 

33,923 

 

 

20,432 

 

Earnings (loss)  per share of common stock

 

0.93

 

 

0.96 

 

 

0.91 

 

 

0.55 

 

 

 

 

 

 

 

 

 

 

 

 

*  Prior to third quarter 2002, IE reported marketing and trading  revenues and expenses on a gross basis.   Revenues are

reported above on a net  basis, and prior periods have been reclassified to conform to the current  period presentation.

 

**Idaho Power Company:**

 

**Quarter Ended**

 

**March 31**

 

**June 30**

 

**September 30**

 

**December 31**

 

 

 

 

 

 

 

 

 

 

 

 

2002

 

 

 

 

 

 

 

 

 

 

 

 

Revenues

$

214,586

 

$

209,068

 

$

237,251 

 

$

206,143

 

Income from operations

 

45,186

 

 

32,687

 

 

22,036 

 

 

32,631

 

Income tax expense (benefit)*

 

13,805

 

 

9,149

 

 

(31,129)

 

 

5,580

 

Net income

 

22,886

 

 

13,834

 

 

39,355 

 

 

12,846

 

Dividends on preferred stock

 

1,362

 

 

1,298

 

 

919 

 

 

1,008

 

Earnings on common stock

 

21,524

 

 

12,536

 

 

38,436 

 

 

11,838

 

 

 

 

 

 

 

 

 

 

 

 

2001

 

 

 

 

 

 

 

 

 

 

 

 

Revenues

$

200,316

 

$

227,930

 

$

286,292 

 

$

197,774

 

Income from operations

 

32,694

 

 

27,780

 

 

12,470 

 

 

17,075

 

Income taxes*

 

23,132

 

 

25,033

 

 

958 

 

 

4,406

 

Net income

 

38,225

 

 

34,785

 

 

1,274 

 

 

3,952

 

Dividends on preferred stock

 

1,461

 

 

1,292

 

 

1,347 

 

 

1,272

 

Earnings (loss) on common stock

 

36,764

 

 

33,493

 

 

(100)

 

 

2,680

 

 

 

 

 

 

 

 

 

 

 

 

*The income taxes presented for 2001 do  not include the effect of discontinued operations (see Note 16 to the  Consolidated

Financial Statements of IPC).

 

 

**ITEM 9.  CHANGES INAND DISAGREEMENTS WITH ACCOUNTANTS ONACCOUNTING AND FINANCIAL DISCLOSURE******

None

**PART III**

Items 10 and 11,portions of Item 12 and Item 13 of Part III have been omitted because theregistrants will file a definitive proxy statement pursuant to Regulation 14A,which involves the election of Directors, with the Securities and ExchangeCommission within 120 days after the close of the fiscal year, portions ofwhich are hereby incorporated by reference (except for information with respectto executive officers which is set forth in Part I hereof).

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

**EQUITYCOMPENSATION PLAN INFORMATION:**

Thefollowing table includes information as of December 31, 2002 (March 3, 2003 asto the IDACORP, Inc. (IDACORP) Non-Employee Directors Stock Compensation Plan(DCP)) with respect to equity compensation plans where equity securities ofIDACORP may be issued.  There are no planswhere equity securities of Idaho Power Company (IPC) may be issued.  These plans are the 1994 Restricted StockPlan (RSP), the IDACORP 2000 Long-Term Incentive and Compensation Plan (LTICP)and the DCP.

 

(a)

(b)

(c)

 

 

 

Number  of securities

 

 

 

remaining  available for

 

Number  of securities to 

Weighted-average  

future  issuance under 

 

be  issued upon exercise

exercise  price of 

equity  compensation 

 

of  outstanding options,

outstanding  options,

plans  (excluding securities

Plan  Category

warrants  and rights

warrants  and rights

reflected  in column (a)) 

Equity  compensation 

 

 

 

plans  approved by 

 

 

 

shareholders  (1)

849,000

$38.50

1,402,539(2)(3)

Equity  compensation

 

 

 

plans  not approved by

 

 

 

shareholders  (4)

-

-

88,042

Total

849,000

$38.50

1,490,581

 

(1)

Consists of the RSP and the  LTICP.

(2)

In addition to being  available for future issuance upon exercise of options, 1,201,000 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)

201,539 shares remain  available for future issuance under the RSP.

(4)

Consists of the DCP.

 

**EquityCompensation Plan Not Approved by IDACORP Shareholders**

TheDCP was adopted by the IDACORP Board of Directors effective May 17, 1999, andprovided for an annual stock grant in June of each year valued at $6,000.  The purpose of the DCP is to increasedirector's stock ownership through stock based director compensation.  The DCP was amended on November 18, 1999 toincrease the annual grant to stock valued at $8,000 and was amended againeffective April 1, 2002.  The April 1,2002 amendment increased the annual grant to stock valued at $16,000.  This increase offset the termination of thedirector's non-qualified deferred compensation plan.  Because the IDACORP and IPC Boards of Directors are comprised ofthe same members, IPC non-employee directors do not receive an additionalgrant.  The plan provides for a total of100,000 shares that may be issued from treasury stock or purchased on the openmarket.

**ITEM14.  CONTROLS AND PROCEDURES**

(a)  Evaluation of disclosure controls andprocedures:

The Chief Executive Officer and ChiefFinancial Officer of IDACORP, Inc., based on their evaluation of IDACORP,Inc.'s disclosure controls and procedures (as defined in Exchange Act Rule13a-14(c)) as of a date within 90 days of the filing date of this report, haveconcluded that IDACORP, Inc.'s disclosure controls and procedures areeffective.

The Chief Executive Officer and ChiefFinancial Officer of Idaho Power Company, based on their evaluation of IdahoPower Company's disclosure controls and procedures (as defined in Exchange ActRule 13a-14(c)) as of a date within 90 days of the filing date of this report,have concluded that Idaho Power Company's disclosure controls and proceduresare effective.

(b)  Changes in internal controls:

There have been no significant changes(including corrective actions with regard to significant deficiencies ormaterial weaknesses) in IDACORP, Inc.'s or Idaho Power's internal controls orin other factors that could significantly affect these controls subsequent tothe date of the evaluation referred to in paragraph (a) above.

**PART IV******

**ITEM 15.  EXHIBITS,FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K******

(a)    Please refer to Part II, Item 8 -"Financial Statements and Supplementary Data" for a complete listingof all consolidated financial statements and financial statement schedules.

(b)    Reports on SEC Form 8-K.  The following Reports on Form 8-K were filedfor the three months ended December 31, 2002

Items Reported

 
Date of Report Filed by
Item 7 - Financial Statements and Exhibits

 

November 12, 2002

 

Idaho Power Company

Item 7 - Financial Statements and Exhibits

 

November 12, 2002

 

IDACORP, Inc.

Item 5 -  Other Events and Regulation FD Disclosure

 

December 13,  2002

 

IDACORP, Inc.  and 

 

 

 

 

Idaho Power  Company

 

(c)  Exhibits.

*Previously Filed and Incorporated Herein by Reference

**Exhibit**

**File Number**

**As Exhibit**

 

 

 

 

 

*2

333-48031

2

Agreement and Plan of Exchange between  IDACORP, Inc., and IPC dated as of February 2, 1998.

 

 

 

 

*3(a)

33-00440

4(a)(xiii)

Restated  Articles of Incorporation of IPC as filed with the Secretary of State of  Idaho on June 30, 1989.

 

 

 

 

*3(a)(i)

33-65720

4(a)(ii)

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.

 

 

 

 

*3(a)(ii)

33-65720

4(a)(iii)

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.

 

 

 

 

*3(a)(iii)

1-3198  Form 10-Q  for 6/30/00

3(a)(iii)

Articles  of Amendment to Restated Articles of Incorporation of IPC as filed with the  Secretary of State of Idaho on June 15, 2000.

 

 

 

 

*3(b)

1-3198  Form 10-Q  for 9/30/99

3(c)

By-laws  of IPC amended on September 9, 1999, and presently in effect.

 

 

 

 

*3(c)

33-56071

3(d)

Articles  of Share Exchange, as filed with the Secretary of State of Idaho on September  29, 1998.

 

 

 

 

*3(d)

333-64737

3.1

Articles  of Incorporation of IDACORP, Inc.

 

 

 

 

*3(d)(i)

333-64737

3.2

Articles  of Amendment to Articles of Incorporation of IDACORP, Inc. as filed with the  Secretary of State of Idaho on March 9, 1998.

 

 

 

 

*3(d)(ii)

333-00139

3(b)

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.

 

 

 

 

*3(e)

1-4465  Form 10-Q  for 6/30/99

3(h)

Amended  Bylaws of IDACORP, Inc. as of July 8, 1999.

 

 

 

 

*4(a)(i)

2-3413

B-2

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.

 

 

 

 

*4(a)(ii)

 

 

IPC  Supplemental Indentures to Mortgage and Deed of Trust:

 

 

 

 

 

 

 

Number

**Dated**

 

1-MD

B-2-a

First

July  1, 1939

 

2-5395

7-a-3

Second

November  15, 1943

 

2-7237

7-a-4

Third

February  1, 1947

 

2-7502

7-a-5

Fourth

May  1, 1948

 

2-8398

7-a-6

Fifth

November  1, 1949

 

2-8973

7-a-7

Sixth

October  1, 1951

 

2-12941

2-C-8

Seventh

January  1, 1957

 

2-13688

4-J

Eighth

July  15, 1957

 

2-13689

4-K

Ninth

November  15, 1957

 

2-14245

4-L

Tenth

April  1, 1958

 

2-14366

2-L

Eleventh

October  15, 1958

 

2-14935

4-N

Twelfth

May  15, 1959

 

2-18976

4-O

Thirteenth

November  15, 1960

 

2-18977

4-Q

Fourteenth

November  1, 1961

 

2-22988

4-B-16

Fifteenth

September  15, 1964

 

2-24578

4-B-17

Sixteenth

April  1, 1966

 

2-25479

4-B-18

Seventeenth

October  1, 1966

 

2-45260

2(c)

Eighteenth

September  1, 1972

 

2-49854

2(c)

Nineteenth

January  15, 1974

 

2-51722

2(c)(i)

Twentieth

August  1, 1974

 

2-51722

2(c)(ii)

Twenty-first

October  15, 1974

 

2-57374

2(c)

Twenty-second

November  15, 1976

 

2-62035

2(c)

Twenty-third

August  15, 1978

 

33-34222

4(d)(iii)

Twenty-fourth

September  1, 1979

 

33-34222

4(d)(iv)

Twenty-fifth

November  1, 1981

 

33-34222

4(d)(v)

Twenty-sixth

May  1, 1982

 

33-34222

4(d)(vi)

Twenty-seventh

May  1, 1986

 

33-00440

4(c)(iv)

Twenty-eighth

June  30, 1989

 

33-34222

4(d)(vii)

Twenty-ninth

January  1, 1990

 

33-65720

4(d)(iii)

Thirtieth

January  1, 1991

 

33-65720

4(d)(iv)

Thirty-first

August  15, 1991

 

33-65720

4(d)(v)

Thirty-second

March  15, 1992

 

33-65720

4(d)(vi)

Thirty-third

April  1, 1993

 

1-3198  Form 8-K  Dated 12/17/93

4

Thirty-fourth

December  1, 1993

 

1-3198  Form 8-K  Dated 11/21/00

4

Thirty-fifth

November  1, 2000

 

1-3198  Form 8-K  Dated 9/27/01

4

Thirty-sixth

October  1, 2001

 

 

 

 

*4(b)

1-3198  Form 10-Q  for 6/30/00

4(b)

Instruments  relating to IPC American Falls bond guarantee (see Exhibit 10(c)).

 

 

 

 

*4(c)

33-65720

4(f)

Agreement  of IPC to furnish certain debt instruments.

 

 

 

 

*4(d)

33-00440

2(a)(iii)

Agreement  and Plan of Merger dated March 10, 1989, between Idaho Power Company, a Maine  Corporation, and Idaho Power Migrating Corporation.

 

 

 

 

*4(e)

1-14465  Form 8-K  dated September 15,  1998

4

Rights  Agreement, dated as of September 10, 1998, between IDACORP, Inc. and Wells  Fargo Bank Minnesota, N.A., as successor to The Bank of New York, as Rights  Agent.

 

 

 

 

*4(f)

1-14465  Form 8-K  dated February 28,  2001

4.1

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.

 

 

 

 

*4(g)

1-14465  Form 8-K  dated February 28,  2001

4.2

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.

 

 

 

 

*4(h)

1-3198  Form 10-Q  for 6/30/02

4(b)

Indenture  for Debt Securities dated as of August 1, 2001 between Idaho Power Company  and Bank One Trust Company N.A., as trustee.

 

 

 

 

*4(i)

1-3198  Form 10-Q  for 6/30/02

4(c)

First  Supplemental Indenture dated as of September 1, 2001 to Indenture for Debt  Securities dated as of August 1, 2001 between Idaho Power Company and Bank  One Trust Company N.A., as trustee.

 

 

 

 

*10(a)

2-49584

5(b)

Agreements,  dated September 22, 1969, between IPC and Pacific Power & Light Company  relating to the operation, construction and ownership of the Jim Bridger  Project. 

 

 

 

 

*10(a)(i)

2-51762

5(c)

Amendment,  dated February 1, 1974, relating to operation agreement filed as Exhibit  10(a).

 

 

 

 

*10(b)

2-49584

5(c)

Agreement,  dated as of October 11, 1973, between IPC and Pacific Power & Light  Company.

 

 

 

 

*10(c)

1-3198  Form 10-Q  for 6/30/00

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.

 

 

 

 

*10(d)

2-62034

5(r)

Guaranty  Agreement, dated as of August 30, 1974, between IPC and Pacific Power &  Light Company.

 

 

 

 

*10(e)

2-56513

5(i)

Letter  Agreement, dated January 23, 1976, between IPC and Portland General Electric  Company.

 

 

 

 

*10(e)(i)

2-62034

5(s)

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.

 

 

 

 

*10(e)(ii)

2-62034

5(t)

Amendment,  dated September 30, 1977, relating to agreement filed as Exhibit 10(e).

 

 

 

 

*10(e)(iii)

2-62034

5(u)

Amendment,  dated October 31, 1977, relating to agreement filed as Exhibit 10(e).

 

 

 

 

*10(e)(iv)

2-62034

5(v)

Amendment,  dated January 23, 1978, relating to agreement filed as Exhibit 10(e).

 

 

 

 

*10(e)(v)

2-62034

5(w)

Amendment,  dated February 15, 1978, relating to agreement filed as Exhibit 10(e).

 

 

 

 

*10(e)(vi)

2-68574

5(x)

Amendment,  dated September 1, 1979, relating to agreement filed as Exhibit 10(e).

 

 

 

 

 

*10(f)

2-68574

5(z)

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.

 

 

 

 

*10(g)

2-64910

5(y)

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.

 

 

 

 

*10(h)(i)  1

1-3198  Form 10-K  for 1996

10(n)(iv)

The  Revised Security Plan for Senior Management Employees - a non-qualified, deferred  compensation plan effective August 1, 1996.

 

 

 

 

*10(h)(ii)  1

1-14465  1-3198  Form 10-K  for 2001

10(n)(ii)

The  Executive Annual Incentive Plan for senior management employees of IPC  effective January 1, 2001.

 

 

 

 

*10(h)(iii) 1

1-3198  Form 10-K  for 1994

10(n)(iii)

The  1994 Restricted Stock Plan for officers and key executives of IDACORP, Inc.  and IPC effective July 1, 1994.

 

 

 

 

*10(h)(iv)  1

1-14465  1-3198  Form 10-K  for 1998

10(h)(iv)

The  Revised Security Plan for Board of Directors - a non-qualified, deferred  compensation plan effective August 1, 1996, revised March 8, 1999, as  amended.

 

 

 

 

10(h)(v) 1

 

 

IDACORP,  Inc. Non-Employee Directors Stock Compensation Plan as of May 17, 1999, as  amended.

 

 

 

 

 

 

 

 

1Compensatory plan

 

 

 

*10(h)(vi)

1-3198  Form 10-K  for 1997

10(y)

Executive  Employment Agreement dated November 20, 1996 between IPC and Richard Riazzi.

 

 

 

 

*10(h)(vii)

1-3198  Form 10-Q  for 6/30/99

10(g)

Executive  Employment Agreement dated April 12, 1999 between IPC and Marlene Williams.

 

 

 

 

*10(h)(viii)

1-14465  Form 10-Q  for 9/30/99

10(h)

Agreement  between IDACORP, Inc. and Jan B. Packwood, J. LaMont Keen, James C. Miller,  Richard Riazzi, Darrel T. Anderson, Bryan Kearney, Cliff N. Olson, Robert W.  Stahman and Marlene K. Williams.

 

 

 

 

*10(h)(ix) 1

1-14465  1-3198  Form 10-Q  for 3/31/02

10(i)  10(h)(ix)

IDACORP,  Inc. 2000 Long-Term Incentive and Compensation Plan, as amended.

 

 

 

 

10(h)(x) 1

 

 

IDACORP  Energy, L.P. 2002 Incentive Plan. 

 

 

 

 

10(h)(xi) 1

 

 

IDACORP,  Inc. 2002 Executive Incentive Plan.

 

 

 

 

*10(i)

33-65720

10(h)

Framework  Agreement, dated October 1, 1984, between the State of Idaho and IPC relating  to IPC's Swan Falls and Snake River water rights.

 

 

 

 

*10(i)(i)

33-65720

10(h)(i)

Agreement,  dated October 25, 1984, between the State of Idaho and IPC relating to the  agreement filed as Exhibit 10(i).

 

 

 

 

*10(i)(ii)

33-65720

10(h)(ii)

Contract  to Implement, dated October 25, 1984, between the State of Idaho and IPC  relating to the agreement filed as Exhibit 10(i).

 

 

 

 

*10(j)

33-65720

10(m)

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.

 

 

 

 

*10(j)(i)

33-65720

10(m)(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.

 

 

 

 

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)

 

 

 

 

 

 

 

 

1Compensatory plan

 

 

 

12(f)

 

 

Statement  Re:  Computation of Ratio of Earnings  to Combined Fixed Charges and Preferred Dividend Requirements.  (IPC)

 

 

 

 

12(g)

 

 

Statement  Re:  Computation of Supplemental Ratio  of Earnings to Combined Fixed Charges and Preferred Dividend  Requirements.  (IPC)

 

 

 

 

21

 

 

Subsidiaries  of IDACORP, Inc. and IPC.

 

 

 

 

23

 

 

Independent  Auditors' Consent.

 

 

 

 

99(a)

 

 

Certification  of Chief Executive Officer of IDACORP, Inc. pursuant to Section 906 of the  Sarbanes-Oxley Act of 2002.

 

 

 

 

99(b)

 

 

Certification  of Chief Financial Officer of IDACORP, Inc. pursuant to Section 906 of the  Sarbanes-Oxley Act of 2002.

 

 

 

 

99(c)

 

 

Certification  of Chief Executive Officer of Idaho Power Company pursuant to Section 906 of  the Sarbanes-Oxley Act of 2002.

 

 

 

 

99(d)

 

 

Certification  of Chief Financial Officer of Idaho Power Company pursuant to Section 906 of  the Sarbanes-Oxley Act of 2002.

 

 

 

**IDACORP,Inc.SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS******

Years Ended December 31, 2002, 2001 and 2000

**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)**

 

2002:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Reserves  Deducted From

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Applicable  Assets:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Reserve  for uncollectible

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

accounts

 

$

42,529

 

$

5,415

 

$

- 

 

$

4,633

 

$

43,311

 

 

Other  Reserves:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Rate  refunds

 

$

-

 

$

-

 

$

- 

 

$

-

 

$

-

 

 

 

Injuries  and damages

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

reserve

 

$

1,500

 

$

(255)

 

$

719 

 

$

28

 

$

1,936

 

 

 

Miscellaneous  operating

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

reserves

 

$

3,551

 

$

418

 

$

(442)

 

$

1,036

 

$

2,491

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2001:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Reserves  Deducted From

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Applicable  Assets:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Reserve  for uncollectible

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

accounts

 

$

23,079

 

$

27,469

 

$

- 

 

$

8,019

 

$

42,529

 

 

Other  Reserves:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Rate  refunds

 

$

-

 

$

-

 

$

- 

 

$

-

 

$

-

 

 

 

Injuries  and damages

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

reserve

 

$

1,500

 

$

-

 

$

- 

 

$

-

 

$

1,500

 

 

 

Miscellaneous  operating

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

reserves

 

$

4,656

 

$

107

 

$

(11)

 

$

1,201

 

$

3,551

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2000:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Reserves  Deducted From

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Applicable  Assets:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Reserve  for uncollectible

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

accounts

 

$

1,397

 

$

23,340

 

$

- 

 

$

1,658

 

$

23,079

 

 

Other  Reserves:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Rate  refunds

 

$

8,893

 

$

3,505

 

$

- 

 

$

12,398

 

$

-

 

 

 

Injuries  and damages

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

reserve

 

$

1,500

 

$

-

 

$

- 

 

$

-

 

$

1,500

 

 

 

Miscellaneous  operating

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

reserves

 

$

8,473

 

$

306

 

$

- 

 

$

4,123

 

$

4,656

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Notes:

(1)  Represents deductions from the reserves  for purposes for which the reserves were created.

 

 

**IDAHOPOWER COMPANYSCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS**

YearsEnded December 31, 2002, 2001 and 2000

**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)**

 

2002:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Reserves Deducted From

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Applicable Assets:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Reserve for uncollectible

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

accounts

 

$

1,500

 

$

4,699 

 

$

- 

 

$

4,633

 

$

1,566

 

 

Other Reserves:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Rate refunds

 

$

-

 

$

- 

 

$

- 

 

$

-

 

$

-

 

 

 

Injuries and damages

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

reserve

 

$

1,500

 

$

(255)

 

$

719 

 

$

28

 

$

1,936

 

 

 

Miscellaneous operating

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

reserves

 

$

3,551

 

$

418 

 

$

(442)

 

$

1,036

 

$

2,491

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2001:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Reserves Deducted From

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Applicable Assets:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Reserve for uncollectible

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

accounts

 

$

23,079

 

$

3,607 

 

$

(21,682)

 

$

3,504

 

$

1,500

 

 

Other Reserves:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Rate refunds

 

$

-

 

$

- 

 

$

- 

 

$

-

 

$

-

 

 

 

Injuries and damages

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

reserve

 

$

1,500

 

$

- 

 

$

- 

 

$

-

 

$

1,500

 

 

 

Miscellaneous operating

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

reserves

 

$

4,656

 

$

107 

 

$

(11)

 

$

1,201

 

$

3,551

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2000:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Reserves Deducted From

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Applicable Assets:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Reserve for uncollectible

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

accounts

 

$

1,397

 

$

23,340 

 

$

- 

 

$

1,658

 

$

23,079

 

 

Other Reserves:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Rate refunds

 

$

8,893

 

$

3,505 

 

$

- 

 

$

12,398

 

$

-

 

 

 

Injuries and damages

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

reserve

 

$

1,500

 

$

- 

 

$

- 

 

$

-

 

$

1,500

 

 

 

Miscellaneous operating

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

reserves

 

$

8,473

 

$

306 

 

$

- 

 

$

4,123

 

$

4,656

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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 theSecurities Exchange Act of 1934, the registrant has caused this report to besigned on its behalf by the undersigned, thereunto duly authorized.

IDACORP, Inc.(Registrant)

March 7, 2003

By: /s/*Jan B. Packwood*Jan B. PackwoodPresident and Chief Executive Officer 

Pursuant to the requirements of theSecurities 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*

 

/s/

Chairman of the Board

March 7, 2003

 

 

Jon H. Miller

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

By:

/s/

*Jan B. Packwood*

 

/s/

President and Chief Executive

"

 

 

Jan B. Packwood

 

 

Officer and Director

 

 

 

 

 

 

 

 

By:

/s/

*Darrel T. Anderson*

 

/s/

Vice President, Chief Financial

"

 

 

Darrel T. Anderson

 

 

Officer and Treasurer

 

 

 

 

 

 

(Principal Financial Officer)

 

 

 

 

 

 

(Principal Accounting Officer)

 

 

 

 

 

 

 

 

By:

/s/

*Rotchford L. Barker*

By:

/s/

*Evelyn Loveless*

"

 

 

Rotchford L. Barker

 

 

Evelyn Loveless

 

 

 

Director

 

 

Director

 

 

 

 

 

 

 

 

By:

/s/

*John B. Carley*

By:

/s/

*Gary G. Michael*

"

 

 

John B. Carley

 

 

Gary G. Michael

 

 

 

Director

 

 

Director

 

 

 

 

 

 

 

 

By:

/s/

*Christopher L. Culp*

By:

 

 

"

 

 

Christopher L. Culp

 

 

Peter S. O'Neill

 

 

 

Director

 

 

Director

 

 

 

 

 

 

 

 

By:

/s/

*Jack K. Lemley*

By:

/s/

*Robert A. Tinstman*

"

 

 

Jack K. Lemley

 

 

Robert A. Tinstman

 

 

 

Director

 

 

Director

 

 

 

 

 

 

 

 

 

 

 

** **

**SIGNATURES**

Pursuant tothe requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934,the registrant has caused this report to be signed on its behalf by theundersigned, thereunto duly authorized.

IDAHO POWER COMPANY(Registrant)

March 7,2003

By:/s/*J.LaMont Keen*J. LaMont KeenPresident and Chief Operating Officer

Pursuant tothe requirements of the Securities Exchange Act of 1934, this report has beensigned below by the following persons on behalf of the registrant and in thecapacities and on the dates indicated.

 

 

By:

/s/

*Jon H. Miller*

 

/s/

Chairman of the Board

March  7, 2003

 

 

Jon H. Miller

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

By:

/s/

*Jan B. Packwood*

 

/s/

Chief Executive Officer

"

 

 

Jan B. Packwood

 

 

and Director

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

By:

/s/

*J. LaMont Keen*

 

/s/

President and Chief Operating

"

 

J. LaMont Keen

 

Officer

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

By:

/s/

*Darrel T. Anderson*

 

/s/

Vice President, Chief  Financial

"

 

 

Darrel T. Anderson

 

 

Officer and Treasurer

 

 

 

 

 

 

(Principal Financial Officer)

 

 

 

 

 

 

(Principal Accounting Officer)

 

 

 

 

 

 

 

 

By:

/s/

*Rotchford L. Barker*

By:

/s/

*Evelyn Loveless*

"

 

 

Rotchford L. Barker

 

 

Evelyn Loveless

 

 

 

Director

 

 

Director

 

 

 

 

 

 

 

 

By:

/s/

*John B. Carley*

By:

/s/

*Gary G. Michael*

"

 

 

John B. Carley

 

 

Gary G. Michael

 

 

 

Director

 

 

Director

 

 

 

 

 

 

 

 

By:

/s/

*Christopher L. Culp*

By:

 

 

"

 

 

Christopher L. Culp

 

 

Peter S. O'Neill

 

 

 

Director

 

 

Director

 

 

 

 

 

 

 

 

By:

/s/

*Jack K. Lemley*

By:

/s/

*Robert A. Tinstman*

"

 

 

Jack K. Lemley

 

 

Robert A. Tinstman

 

 

 

Director

 

 

Director

 

 

 

 

 

 

 

 

 

 

 

 

 

**CERTIFICATIONS**

I, Jan B. Packwood, Presidentand Chief Executive Officer, certify that:

1. I have reviewed this annualreport on Form 10-K of IDACORP, Inc.;

2. Based on my knowledge, this annual report does not contain any untruestatement of a material fact or omit to state a material fact necessary to makethe statements made, in light of the circumstances under which such statementswere made, not misleading with respect to the period covered by this annualreport;

3. Based on my knowledge, the financial statements, and other financialinformation included in this annual report, fairly present in all materialrespects the financial condition, results of operations and cash flows of theregistrant as of, and for, the periods presented in this annual report;

4. The registrant's other certifying officers and I are responsible forestablishing and maintaining disclosure controls and procedures (as defined inExchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

a)      designedsuch disclosure controls and procedures to ensure that material informationrelating to the registrant, including its consolidated subsidiaries, is madeknown to us by others within those entities, particularly during the period inwhich this annual report is being prepared;

b)      evaluatedthe effectiveness of the registrant's disclosure controls and procedures as ofa date within 90 days prior to the filing date of this annual report (the"Evaluation Date"); and

c)      presentedin this annual report our conclusions about the effectiveness of the disclosurecontrols and procedures based on our evaluation as of the Evaluation Date;

5. The registrant's other certifying officers and I have disclosed, basedon our most recent evaluation, to the registrant's auditors and the auditcommittee of registrant's board of directors (or persons performing theequivalent functions):

a)     all significant deficiencies in the design or operation ofinternal controls which could adversely affect the registrant's ability torecord, process, summarize and report financial data and have identified forthe registrant's auditors any material weaknesses in internal controls; and

b)     any fraud, whether or not material, that involves managementor other employees who have a significant role in the registrant's internalcontrols; and

6. The registrant's other certifying officers and I have indicated inthis annual report whether there were significant changes in internal controlsor in other factors that could significantly affect internal controlssubsequent to the date of our most recent evaluation, including any correctiveactions with regard to significant deficiencies and material weaknesses.

 

Date

March 7, 2003

By:

/s/

*Jan B. Packwood*

 

Jan B. Packwood

 

President and Chief Executive  Officer

 

 

 

I, Darrel T. Anderson, VicePresident, Chief Financial Officer and Treasurer, certify that:

1.  I have reviewed this annualreport on Form 10-K of IDACORP, Inc.;

2. Based on my knowledge, this annual report does not contain any untruestatement of a material fact or omit to state a material fact necessary to makethe statements made, in light of the circumstances under which such statementswere made, not misleading with respect to the period covered by this annualreport;

3. Based on my knowledge, the financial statements, and other financialinformation included in this annual report, fairly present in all materialrespects the financial condition, results of operations and cash flows of the registrantas of, and for, the periods presented in this annual report;

4. The registrant's other certifying officers and I are responsible forestablishing and maintaining disclosure controls and procedures (as defined inExchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

a)     designed such disclosure controls and procedures to ensurethat material information relating to the registrant, including itsconsolidated subsidiaries, is made known to us by others within those entities,particularly during the period in which this annual report is being prepared;

b)     evaluated the effectiveness of the registrant's disclosurecontrols and procedures as of a date within 90 days prior to the filing date ofthis annual report (the "Evaluation Date"); and

c)     presented in this annual report our conclusions about theeffectiveness of the disclosure controls and procedures based on our evaluationas of the Evaluation Date;

5. The registrant's other certifying officers and I have disclosed, basedon our most recent evaluation, to the registrant's auditors and the auditcommittee of registrant's board of directors (or persons performing theequivalent functions):

a)      allsignificant deficiencies in the design or operation of internal controls whichcould adversely affect the registrant's ability to record, process, summarizeand report financial data and have identified for the registrant's auditors anymaterial weaknesses in internal controls; and

b)      anyfraud, whether or not material, that involves management or other employees whohave a significant role in the registrant's internal controls; and

6. The registrant's other certifying officers and I have indicated inthis annual report whether there were significant changes in internal controlsor in other factors that could significantly affect internal controlssubsequent to the date of our most recent evaluation, including any correctiveactions with regard to significant deficiencies and material weaknesses.

 

Date

March 7, 2003

By:

/s/

*Darrel T. Anderson*

 

Darrel T. Anderson

 

Vice President, Chief  Financial

 

Officer and Treasurer

 

 

 

I, Jan B. Packwood, ChiefExecutive Officer, certify that:
- I have reviewed this annual report on Form 10-K of     Idaho Power Company;  
- Based on my knowledge, this annual report does not contain     any untrue statement of a material fact or omit to state a material fact     necessary to make the statements made, in light of the circumstances under     which such statements were made, not misleading with respect to the period     covered by this annual report;  
- Based on my knowledge, the financial statements, and     other financial information included in this annual report, fairly present     in all material respects the financial condition, results of operations     and cash flows of the registrant as of, and for, the periods presented in     this annual report;  
- The registrant's other certifying officers and I are     responsible for establishing and maintaining disclosure controls and     procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the     registrant and we have:  

a)     designed such disclosure controls and procedures to ensurethat material information relating to the registrant, including itsconsolidated subsidiaries, is made known to us by others within those entities,particularly during the period in which this annual report is being prepared;

b)     evaluated the effectiveness of the registrant's disclosurecontrols and procedures as of a date within 90 days prior to the filing date ofthis annual report (the "Evaluation Date"); and

c)     presented in this annual report our conclusions about theeffectiveness of the disclosure controls and procedures based on our evaluationas of the Evaluation Date;
- The registrant's other certifying officers and I have     disclosed, based on our most recent evaluation, to the registrant's     auditors and the audit committee of registrant's board of directors (or     persons performing the equivalent functions):  

a)     all significant deficiencies in the design or operation ofinternal controls which could adversely affect the registrant's ability to record,process, summarize and report financial data and have identified for theregistrant's auditors any material weaknesses in internal controls; and

b)     any fraud, whether or not material, that involves managementor other employees who have a significant role in the registrant's internalcontrols; and
- The registrant's other certifying officers and I have     indicated in this annual report whether there were significant changes in     internal controls or in other factors that could significantly affect     internal controls subsequent to the date of our most recent evaluation,     including any corrective actions with regard to significant deficiencies     and material weaknesses.  

Date:

March 7, 2003

 

By:

/s/*Jan B.  Packwood*

 

 

 

 

Jan B.  Packwood

 

 

 

 

Chief  Executive Officer

 

 

 

I, Darrel T. Anderson, Vice President, Chief Financial Officer andTreasurer, certify that:
- I have reviewed this annual report on Form 10-K of     Idaho Power Company;  
- Based on my knowledge, this annual report does not     contain any untrue statement of a material fact or omit to state a     material fact necessary to make the statements made, in light of the     circumstances under which such statements were made, not misleading with     respect to the period covered by this annual report;  
- Based on my knowledge, the financial statements, and     other financial information included in this annual report, fairly present     in all material respects the financial condition, results of operations     and cash flows of the registrant as of, and for, the periods presented in     this annual report;  
- The registrant's other certifying officers and I are     responsible for establishing and maintaining disclosure controls and     procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the     registrant and we have:  
designed such disclosure controls and procedures to      ensure that material information relating to the registrant, including      its consolidated subsidiaries, is made known to us by others within those      entities, particularly during the period in which this annual report is      being prepared;
evaluated the effectiveness of the registrant's      disclosure controls and procedures as of a date within 90 days prior to      the filing date of this annual report (the "Evaluation Date");      and
presented in this annual report our conclusions      about the effectiveness of the disclosure controls and procedures based      on our evaluation as of the Evaluation Date;

- The registrant's other certifying officers and I have     disclosed, based on our most recent evaluation, to the registrant's     auditors and the audit committee of registrant's board of directors (or     persons performing the equivalent functions):  
all significant deficiencies in the design or      operation of internal controls which could adversely affect the      registrant's ability to record, process, summarize and report financial      data and have identified for the registrant's auditors any material      weaknesses in internal controls; and
any fraud, whether or not material, that involves      management or other employees who have a significant role in the      registrant's internal controls; and

- The registrant's other certifying officers and I have     indicated in this annual report whether there were significant changes in     internal controls or in other factors that could significantly affect     internal controls subsequent to the date of our most recent evaluation,     including any corrective actions with regard to significant deficiencies     and material weaknesses.  

Date:

March 7, 2003

 

By:

/s/*Darrel  T. Anderson*

 

 

 

 

Darrel T. Anderson

 

 

 

 

Vice President, Chief  Financial

 

 

 

 

Officer and Treasurer

 

 

 

**EXHIBIT INDEX**

** **

 

 

 

Exhibit Number

 

 

 

 

 

10(h)(v)

 

IDACORP, Inc. Non-Employee Directors Stock  Compensation Plan as of May 17, 1999, as amended.

 

 

 

10(h)(x)

 

IDACORP Energy, L.P. 2002 Incentive Plan.

 

 

 

10(h)(xi)

 

IDACORP, Inc. 2002 Executive Incentive Plan.

 

 

 

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)

 

 

 

12(f)

 

Statements  Re: Computation of Ratio of Earnings to Combined Fixed Charges and Preferred  Dividend Requirements.  (IPC)

 

 

 

12(g)

 

Statements  Re: Computation of Supplemental Ratio of Earnings to Combined Fixed Charges  and Preferred Dividend Requirements.   (IPC)

 

 

 

21

 

Subsidiaries  of IDACORP, Inc. and IPC

 

 

 

23

 

Independent  Auditors' Consent.

 

 

 

99(a)

 

Certification of Chief  Executive Officer of IDACORP, Inc. pursuant to Section 906 of the  Sarbanes-Oxley Act of 2002.

 

 

 

99(b)

 

Certification of Chief  Finanical Officer of IDACORP, Inc. pursuant to Section 906 of the  Sarbanes-Oxley Act of 2002.

 

 

 

99(c)

 

Certification of Chief  Executive Officer of Idaho Power Company pursuant to Section 906 of the  Sarbanes-Oxley Act of 2002.

 

 

 

99(d)

 

Certification of Chief  Finanical Officer of Idaho Power Company pursuant to Section 906 of the  Sarbanes-Oxley Act of 2002.

 

 

 

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