**UNITED STATES SECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549****FORM 10-K**

(Mark One)
| X      |   | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d)  OF THE SECURITIES EXCHANGE ACT OF 1934 |
|--------|--------|----------------------------------------------------------------------------------------|
|   |   | For the fiscal year ended December 31, 2003                                            |

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

 

For the transition period from ...................to .................................................................
|                                                         |                             | Exact  name of registrants as specified in      |                  |                  |
|--------------------------------------------------------------|----------------------------------|-------------------------------------------------|-----------------------|-----------------------|
| Commission                                                   |                             | their  charters, address of principal executive |                  | IRS  Employer         |
| File  Number                                                 |                             | offices 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                 |                                            |                  |
|                                                         |                             |                                            |
|                                                              |                                  |                                                 |                       |                       |  |  |  |

Indicate by check mark whether the registrants (1)have filed all reports required to be filed by Section 13 or 15(d) of theSecurities Exchange Act of 1934 during the preceding 12 months (or for suchshorter period that the registrants were required to file such reports), and(2) have been subject to such filing requirements for the past 90 days.  Yes ( X  )  No  (    )

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

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

 

Aggregatemarket value of voting and non-voting common stock held by nonaffiliates (June30, 2003):
| IDACORP,  Inc.: | $999,034,371 | Idaho  Power Company: | None |
|-----------------|--------------|-----------------------|------|

 

Numberof shares of common stock outstanding at February 27, 2004:
| IDACORP,  Inc.:       | 38,160,633                            |
|-----------------------|---------------------------------------|
| Idaho  Power Company: | 39,150,812  all held by IDACORP, Inc. |

 
| **Documents Incorporated by  Reference:** |
|-------------------------------------------|
|                                      |
| Part  III, Items 10 - 14                  | Portions of the joint definitive proxy statement  of IDACORP, Inc. and Idaho Power Company to be |
|                                      | filed pursuant to Regulation 14A for the 2004  Annual Meeting of Shareholders to be held on May 20, |
|                                      | 2004. |

 

This Combined Form 10-K represents separatefilings by IDACORP, Inc. and Idaho Power Company.  Information contained herein relating to an individual registrantis filed by that registrant on its own behalf. Idaho Power Company makes no representation as to the informationrelating to IDACORP, Inc.'s other operations.

 

 
| **COMMONLY USED TERMS** |
|-------------------------|
|                    |
| AFDC                    | - | Allowance  for Funds Used During Construction |
| ALJ                     | - | Administrative  Law Judge |
| APB                     | - | Accounting  Principles Board |
| ARO                     | - | Asset  Retirement Obligation |
| BMPP                    | - | Bennett  Mountain Power Plant |
| BPA                     | - | Bonneville  Power Administration |
| Cal  ISO                | - | California  Independent System Operator |
| CalPX                   | - | California  Power Exchange |
| CSPP                    | - | Cogeneration  and Small Power Production |
| CWIP                    | - | Construction  Work in Progress |
| 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 |
| FIN                     | - | FASB  Interpretation |
| FPA                     | - | Federal  Power Act |
| HCC                     | - | Hells  Canyon Complex |
| 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 of Financial Condition and Results of |
|                    |   |   | Operations |
| MMbtu                   | - | Million  British Thermal Units |
| MMCP                    | - | Mitigated  Market Clearing Price |
| MW                      | - | Megawatt |
| MWh                     | - | Megawatt-hour |
| NPC                     | - | Nevada  Power Company |
| OPUC                    | - | Oregon  Public Utility Commission |
| PCA                     | - | Power  Cost Adjustment |
| PM&E                | - | Protection,  Mitigation and Enhancement |
| PMC                     | - | Plaintiff's  Master Complaint |
| PPA                     | - | Power  Purchase Agreement |
| PPLM                    | - | PPL  Montana, LLC |
| PURPA                   | - | Public  Utilities Regulatory Policy Act of 1978 |
| REA                     | - | Rural  Electrification Administration |
| RFP                     | - | Request  for Proposal |
| RMC                     | - | Risk  Management Committee |
| RTOs                    | - | Regional  Transmission Organizations |
| SET                     | - | Sempra  Energy Trading |
| SFAS                    | - | Statement  of Financial Accounting Standards |
| SPPCo                   | - | Sierra  Pacific Power Company |
| Valmy                   | - | North  Valmy Steam Electric Generating Plant |
| WSPP                    | - | Western  Systems Power Pool |
|                    |   |   |

 

 

 

 

 

 

 

 
| **TABLE OF CONTENTS** |
|-----------------------|
|                  | **Page** |
| **Part  I**           |
|                  |
|                  | Item  1. | Business | 1-11 |
|                  | Item  2. | Properties | 12-14 |
|                  | Item  3. | Legal  Proceedings | 14 |
|                  | Item  4. | Submission  of Matters to a Vote of Security Holders | 14 |
|                  |
|                  | Executive  Officers of the Registrants | 15-16 |
|                  |
| **Part  II**          |
|                  |
|                  | Item  5. | Market  for the Registrant's Common Equity and Related Stockholder |   |
|                  |   |   | Matters | 17 |
|                  | Item  6. | Selected  Financial Data | 18-19 |
|                  | Item  7. | Management's  Discussion and Analysis of Financial Condition and |   |
|                  |   |   | Results  of Operations | 20-46 |
|                  | Item  7A. | Quantitative  and Qualitative Disclosures about Market Risk | 47-48 |
|                  | Item  8. | Financial  Statements and Supplementary Data | 49-100 |
|                  | Item  9. | Changes  in and Disagreements with Accountants on Accounting and |   |
|                  |   |   | Financial  Disclosure | 101 |
|                  | Item  9A. | Controls  and Procedures | 101 |
|                  |
| **Part  III**         |
|                  |
|                  | Item  10. | Directors  and Executive Officers of the Registrants* | 102 |
|                  | Item  11. | Executive  Compensation* | 102 |
|                  | Item  12. | Security  Ownership of Certain Beneficial Owners and Management |   |
|                  |   |   | and  Related Stockholder Matters* | 103 |
|                  | Item  13. | Certain  Relationships and Related Transactions* | 103 |
|                  | Item  14. | Principal  Accounting Fees and Services* | 103 |
|                  |
| **Part  IV**          |
|                  |
|                  | Item  15. | Exhibits,  Financial Statement Schedules and Reports on Form 8-K | 104-111 |
|                  |
|                  | Signatures | 112-113 |
|                  |
|                  | Exhibit  Index | 114 |
|                  |
|                  | *Incorporated  by reference to the joint definitive proxy statement of IDACORP, Inc. and  Idaho Power Company |
|                  | for  the 2004 Annual Meeting of Shareholders, except for the Code of Ethics  information in Item 10 and the |
|                  | Equity  Compensation Plan information in Item 12. |

 

 

 

 

 

** **

**SAFE HARBOR STATEMENT**This Form 10-K contains"forward-looking statements" intended to qualify for safe harbor fromliability established by the Private Securities Litigation Reform Act of1995.  Forward-looking statements shouldbe read with the cautionary statements and important factors included in thisForm 10-K at Part II, Item 7- "Management's Discussion and Analysis ofFinancial Condition and Results of Operations (MD&A) - FORWARD-LOOKINGINFORMATION."  Forward-lookingstatements are all statements other than statements of historical fact,including without limitation those that are identified by the use of the words"anticipates," "estimates," "expects," "intends,""plans," "predicts" and similar expressions.

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

**ITEM 1.  BUSINESS**

**OVERVIEW:**

IDACORP, Inc. (IDACORP) is a holding companyformed in 1998 whose principal operating subsidiary is Idaho Power Company (IPC).  IPC is regulated by the Federal EnergyRegulatory Commission (FERC) and the state regulatory commissions of Idaho andOregon and is engaged in the generation, transmission, distribution, sale andpurchase of electric energy.  IPC is theparent of Idaho Energy Resources Co., a joint venturer in Bridger Coal Company,which supplies coal to the Jim Bridger generating plant owned in part by IPC.

IDACORP's other operating subsidiaries include:

IdaTech- developer of integrated fuel cell systems;

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

Velocitus- commercial and residential Internet service provider;

IDACOMM- provider of telecommunications services;

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

IDACORPEnergy (IE) - marketer of electricity and natural gas.

 

IE is in the late stages of winding down itsoperations.  In 2003, IDACORP decidedthat Ida-West would also wind down its operations, as discussed in Part II, Item7 - "MD&A - RESULTS OF OPERATIONS - Ida-West."

During2003, IDACORP refocused on a strategy called "Electricity Plus," aback-to-basics strategy that emphasizes IPC as IDACORP's core business.  IPC continues to experience strong growth inits service area, and this revised corporate strategy recognizes that IPC mustmake substantial investments in infrastructure to ensure adequate supply andreliable service.   The "Plus"recognizes that through modest investments in IdaTech and IDACOMM, IDACORP canpreserve the potential for additional growth in shareowner value.  IFS, with its federal income tax credits,remains a key component of the revised corporate strategy.

AtDecember 31, 2003, IDACORP had 1,861 full-time employees.  Of these employees, 1,713 were employed byIPC.

IDACORPhas identified three reportable business segments: the regulated utilityoperations of IPC, the energy marketing activities of IE and IFS.  IPC, IE and IFS contributed $55 million,($10) million and $10 million to consolidated net income, respectively, in2003.  IE's 2003 results includeearnings from the August sale of its forward book of electricity tradingcontracts, which was the last major step in the wind down of energy marketingthat began in 2002.  Financialinformation relating to amounts of sales, revenue, net income and total assetsof IDACORP's operating segments is presented in Note 12 to IDACORP'sConsolidated Financial Statements and below in "Utility Operations,""Energy Marketing" and "IFS."

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.

**UTILITY OPERATIONS:**

IPC wasincorporated under the laws of the state of Idaho in 1989 as successor to aMaine corporation organized in 1915. IPC is involved in the generation,purchase, transmission, distribution and sale of electric energy in a 20,000square mile area in southern Idaho and eastern Oregon, with an estimated populationof 883,000.  IPC holds franchises in 71cities in Idaho and nine cities in Oregon and holds certificates from therespective public utility regulatory authorities to serve all or a portion of25 counties in Idaho and three counties in Oregon.  As of December 31, 2003, IPC supplied electric energy toapproximately 427,000 general business customers.

IPCowns and operates 17 hydroelectric power plants and one natural gas-fired plantand shares ownership in three coal-fired generating plants.  These generating plants and their capacitiesare listed in Item 2 - "Properties." IPC's coal-fired plants are in Wyoming, Oregon and Nevada, and uselow-sulfur coal from Wyoming and Utah.

IPCrelies heavily on hydroelectric power for its generating needs and is one ofthe nation's few investor-owned utilities with a predominantly hydroelectricgenerating base.  Because of itsreliance on hydroelectric generation, IPC's generation operations can besignificantly affected by the weather. The availability of hydroelectric power depends on snowpack in themountains upstream of IPC's hydroelectric facilities, precipitation and otherweather and streamflow management considerations. When hydroelectric generationdecreases below load requirements and/or customer demand increases beyondhydroelectric capacity, IPC increases its use of more expensive thermalgeneration and purchased power.

Theprimary influences on electricity sales are weather and economicconditions.  Extreme temperaturesincrease sales to customers, who use electricity for cooling and heating, andmoderate temperatures decrease sales. Precipitation levels during the growing season affect sales to customerswho use electricity to operate irrigation pumps.  Increased precipitation reduces electricity usage by thesecustomers.

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, Idahomanufacturing plant in late 2001.  IPCentered into a load reduction agreement with FMC/Astaris in 2001.  See further discussion of FMC/Astaris inPart II, Item 7 - "MD&A - REGULATORY ISSUES - FMC/Astaris SettlementAgreement."

**Regulation**IPC is under theregulatory jurisdiction (as to rates, service, accounting and other generalmatters of utility operation) of the FERC, the Idaho Public UtilitiesCommission (IPUC) and the Oregon Public Utility Commission (OPUC).  IPC is also under the regulatoryjurisdiction of the IPUC, OPUC and the Public Service Commission of Wyoming asto the issuance of securities.  IPC issubject 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 thestate regulatory commissions and its wholesale and transmission rates areregulated by the FERC (see "Rates" below).  Pursuant to the requirements of Section 210 of the PublicUtilities Regulatory Policy Act of 1978 (PURPA), the state regulatorycommissions have each issued orders and rules regulating IPC's purchase ofpower from cogeneration and small power production (CSPP) facilities.

As alicensee under the FPA, IPC and its licensed hydroelectric projects are subjectto the provisions of Part I of the FPA. All licenses are subject to conditions set forth in the FPA and relatedFERC regulations.  These conditions andregulations include provisions relating to condemnation of a project upon paymentof just compensation, amortization of project investment from excess projectearnings, possible takeover of a project after expiration of its license uponpayment of net investment, severance damages and other matters.

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 toits general business customers are determined by the IPUC and OPUC.  Approximately 96 percent of IPC's generalbusiness revenue comes from customers in Idaho.  The rates charged to these customers are adjusted annually by aPower Cost Adjustment (PCA), a mechanism that provides for annual adjustment tothe rates charged to IPC's Idaho retail customers.  These adjustments, which take effect in May, are based onforecasts of net power supply costs (fuel and purchased power less sales forresale) and the true-up of the prior year's forecast.  The PCA adjusts rates to reflect the changes in costs incurred byIPC to supply power.  Throughout the year,IPC compares its actual power supply costs to the amounts it is recovering inrates.  Most, but not all, of thisdifference is deferred and included in the calculation of rates for futureyears. See further discussion of the PCA in Part II, Item 7 - "MD&A -REGULATORY ISSUES - Deferred Power Supply Costs," and Note 13 to IDACORP'sConsolidated Financial Statements.

**General Rate Case Filing:** IPC is proceeding through its Idaho generalrate case that was originally filed with the IPUC on October 16, 2003.  IPC requested approximately $86 millionannually in additional revenue, or an average 17.7 percent increase to baserates.  On February 20, 2004, the IPUCStaff and seven other intervenors filed their testimony with the IPUC.  The testimony covered revenue requirementand rate design issues.  The IPUCStaff's proposal of $15 million, a three-percent overall increase to baserates, was the lowest recommendation of any of the parties.  Copies of the parties' testimony andexhibits can be viewed at the IPUC web site. IPC has until March 19, 2004 to prepare its rebuttal to these recommendations.  Formal hearings are scheduled to begin onMarch 29, 2004, and a final order is expected from the IPUC on May 28, 2004,with a June 1, 2004 effective date.

IPC has not had an overall base rate increasesince 1995.  Since that time, IPC hasinvested more than $850 million in its electrical system, experienced anincrease in normal operating costs due to inflation and added nearly 100,000customers.

IPC's application also includes proposals toincrease customers' monthly service charges and introduce summer and non-summerrates.  IPC cannot predict what level ofrate adjustment the IPUC will grant. See further discussion of the general rate case in Part II, Item 7 - "MD&A- REGULATORY ISSUES - General Rate Case."

**Power Supply**IPC meets its systemload requirements using a combination of its own system generation, mandatedpurchases from private developers (see "CSPP Purchases" below) andpurchases from other utilities and power wholesalers. IPC's generating stationsand capacities are listed in Item 2 - "Properties."

IPC's system is dual peaking, with the larger peakdemand generally occurring in the summer. The all-time system peak demand was 2,963 megawatts (MW), set on July12, 2002.  Peak demand in 2003 was 2,944MW, set on July 22, 2003.  IPC expectstotal system energy requirements to grow 2.3 percent annually over the nextthree years.

The following table presents IPC's systemgeneration for the last three years:
|          | **MWh**                  |   | **Percent  of total generation** |
|---------------|--------------------------|--------|----------------------------------|
|          | **2003**                 |   | **2002**                         |   | **2001** |   | **2003** |   | **2002** |   | **2001** |
|          | **(thousands  of MWhs)** |   |                             |   |   |   |   |
| Hydroelectric | 6,149                    |   | 6,069                            |   | 5,638 |   | 47% |   | 45% |   | 43% |
| Thermal       | 6,914                    |   | 7,286                            |   | 7,622 |   | 53% |   | 55% |   | 57% |
|          | Total system generation  | 13,063 |                             | 13,355 |   | 13,260 |   | 100% |   | 100% |   | 100% |
|          |                     |   |                             |   |   |   |   |   |   |   |   |
|               |                          |        |                                  |  |  |  |  |  |  |  |  |  |

 

The amount of electricity IPC is able to generatefrom its hydroelectric plants depends on a number of factors, primarilysnowpack in the mountains upstream of its hydroelectric facilities, reservoirstorage and streamflow conditions.  Whenthese factors are favorable, IPC can generate more electricity using itshydroelectric plants.  When thesefactors are unfavorable, IPC must increase its reliance on more expensivethermal plants and purchased power.

Continued below normal streamflow conditions in2003 yielded a system generation mix of 47 percent hydroelectric and 53 percentthermal.  Under normal streamflowconditions, IPC's system generation mix is approximately 56 percenthydroelectric and 44 percent thermal.

Current Snake River basin snowpack numbers suggestthat streamflow conditions for 2004 will remain below normal.  IPC's February 17, 2004 snowpackaccumulations were 99 percent of normal, compared to 79 percent at the sametime a year earlier.  As of February 17,2004, storage for selected reservoirs upstream of Brownlee was 63 percent ofnormal, compared to 68 percent of normal a year earlier.  IPC is currently expecting its fifthconsecutive year of below normal water conditions.

Seasonal exchanges of winter-for-summer power areincluded among the resources under contract to maximize the firm load carryingcapability. 

IPC's generating facilities are interconnectedthrough its integrated transmission system and are operated on a coordinatedbasis to achieve maximum load-carrying capability and reliability.  IPC's transmission system is directly interconnectedwith the transmission systems of the Bonneville Power Administration (BPA),Avista Corporation, PacifiCorp, NorthWestern Energy and Sierra Pacific PowerCompany (SPPCo).  Such interconnections,coupled with transmission line capacity made available under agreements withsome of the above utilities, permit the interchange, purchase and sale of poweramong all major electric systems in the west. IPC is a member of the Western Electricity Coordinating Council, theWestern Systems Power Pool (WSPP), the Northwest Power Pool and the NorthwestRegional Transmission Association. These groups have been formed to more efficiently coordinatetransmission reliability and planning throughout the western grid.  See "Competition - Wholesale"below.

**Integrated Resource Plan:**  Every two years, IPC is required to file anIntegrated Resource Plan (IRP) with both the IPUC and the OPUC.  An IRP is a comprehensive analysis of IPC'spresent and future demands for electricity and the plan for meeting thatdemand.  IPC last filed an IRP in June2002.

The 2002 IRP identified the need for additionalpeaking resources in 2005.  IPC issued aRequest for Proposal (RFP) for up to 200 MW from a generating resource locatedin the IPC service area, which would provide electrical capacity during June,July, August, November and December. The RFP generated a strong response and IPC selected TR2 (formerly known as Mountain View Power) ofBoise, Idaho to construct and deliver a 162-MW natural gas fired plant to bebuilt in Mountain Home, Idaho, at an estimated project cost of $61million.  These estimated costs are notincluded in the current rate case request. The IPUC reviewed the selection process and IPC was issued a Certificateof Convenience and Necessity in January 2004 through IPUC Order No. 29410 andOrder No. 29422.  IPC has issued aformal notice to proceed with plant construction and the plant is scheduled tobe on-line, commissioned and operational by June 2005.  See further discussion in Part II, Item 7 -"MD&A - REGULATORY ISSUES - Bennett Mountain Power Plant."

Presently, work is underway to file another IRPwith the utility commissions in June 2004. To provide additional input on the 2004 IRP, IPC has formed an IRPadvisory council.  The advisory councilconsists of public representatives from state government, industrial customers,environmental advocates and utility commission staff members.  The IRP advisory council meets with IPCperiodically to discuss the 2004 IRP.

The draft 2004 IRP should be available in thespring of 2004 and the final IRP will be published and filed with the IPUC andthe OPUC in June 2004.  The IPC serviceterritory population continues to increase and it is expected that the 2004 IRPwill identify the need for additional capacity.

**CSPP Purchases**:  As mandated by the enactment of PURPA andthe adoption of avoided costs standards by the IPUC and the OPUC, IPC hasentered into contracts for the purchase of energy from a number of privatedevelopers.  Because IPC's serviceterritory encompasses substantial irrigation canal development, forest productproduction facilities, mountain streams and food processing facilities, aconsiderable amount of CSPP facility development potential exists.  As of December 31, 2003, IPC had signedagreements to purchase energy from 69 CSPP facilities with contracts rangingfrom one to 30 years.  Of thesefacilities, 68 were on-line at the end of 2003; the other facility undercontract is due to come on-line in May 2004. Under these contracts, IPC is required to purchase all of the outputfrom the facilities located inside the IPC service territory.  For projects located outside the IPC serviceterritory, IPC is required to purchase the output that IPC has the ability to receiveat the facility's requested point of delivery on the IPC system.  During 2003, IPC purchased 654,131 megawatthours (MWh) from these projects at a cost of $38 million, resulting in ablended price of 5.8 cents per kilowatt hour (kWh).

For IPUC jurisdictional projects, new projects upto ten MW are eligible for IPUC Published Avoided Costs (PAC) for up to a20-year contract term.  The PAC is aprice established by the IPUC and the OPUC to estimate IPC's cost of developingadditional generation resources.  Forall other PURPA projects, IPC is required to negotiate the terms, conditionsand pricing.  For OPUC jurisdictionalprojects, new projects up to one MW are eligible for OPUC PAC for up to afive-year contract term (automatically renewable at the end of fiveyears).  For all other PURPA projects,IPC is required to negotiate the terms, conditions and pricing. If a PURPAproject does not qualify for the PAC, then IPC is required to negotiate theterms, prices and conditions with that project.  These negotiations reflect the characteristics of the individualprojects (i.e., operational flexibility, location and size) and the benefits tothe IPC electrical system and must be consistent with other similar energyalternatives.

**Wholesale Power Sales:** IPChas three firm wholesale power sales contracts and one wholesale contract forload following services.  Load followingservices allow a plant to react as the system load changes by increasing ordecreasing output according to the system needs, while the output is fixed in afirm contract.  These contracts are forenergy up to 12 average MW and expire between 2004 and 2006.  Two contracts will expire at the end of2004.  As these contracts expire, IPCwill either renew, negotiate an extension or use this power to meet its ownsystem requirements.  

**Wholesale Power Purchases:** IPChas one firm wholesale power purchase contract.  This contract is with PPL Montana, LLC (PPLM) for 83 MW per hourto address increased demand during June, July and August.  The term of this contract begins in June2004 and runs through August 2009.  Seefurther discussion in Part II, Item 7 - "MD&A - REGULATORY ISSUES -PPL Montana Power Purchase Agreement."

**Transmission Services:** IPChas a long history of providing wholesale transmission service and providesfirm and non-firm wheeling services for several surrounding utilities.  IPC's system lies between and isinterconnected to the winter-peaking northern and summer-peaking southernregions of the western interconnected power system. This position allows IPC toprovide transmission services and reach a broad power sales market.

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

**Fuel**IPC, through itssubsidiary Idaho Energy Resources Co., owns a one-third interest in BridgerCoal Company, which owns the Jim Bridger mine supplying coal to the Jim Bridgergenerating plant in Wyoming.  The mine,located near the Jim Bridger plant, operates under a long-term sales agreementthat provides for delivery of coal over a 51-year period ending in 2025.  The Jim Bridger mine has sufficient reservesto provide coal deliveries for the term of the sales agreement.  IPC also has a coal supply contract providingfor annual deliveries of coal through 2009 from the Black Butte Coal Company'sBlack Butte and Leucite Hills mines located near the Jim Bridger plant.  This contract supplements the Bridger CoalCompany deliveries and provides another coal supply to operate the Jim Bridgerplant.  The Jim Bridger plant's railload-in facility, the coal car unloading point, and unit coal train allow theplant to take advantage of potentially lower-cost coal from outside mines for tonnagerequirements above established contract minimums.

SPPCo has signed an agreement with Arch Coal SalesCompany, Inc. to supply coal to the North Valmy Steam Electric Generating Plant(Valmy) from 2002 through 2006.  IPC isobligated to purchase one-half of the coal, ranging from approximately 515,000tons to 762,500 tons annually, under the Arch Coal Sales Company agreement.

IPC owns 10 percent of the Boardman Plant.  Boardman receives coal from the Powder RiverBasin through annual contracts. Portland General Electric, as operator of the Boardman Plant, has signedan agreement with Triton Coal Company to supply all of Boardman's 2004 coalrequirements.

The Danskin combustion turbines receive gasthrough the Williams Northwest Pipeline. All gas is purchased on an as needed basis.  Danskin's gas is transported under a long-term capacity contractwith Northwest Pipeline.  This contract,which extends through February 28, 2007 with annual extensions at IPC's solediscretion, is for 24,523 million British thermal units (MMbtu) per day from Sumas,Washington to Elmore, Idaho.

**Water Rights**Except as discussedbelow, IPC has acquired water rights under applicable state law for all watersused in its hydroelectric generating facilities.  In addition, IPC holds water rights for domestic, irrigation,commercial and other necessary purposes related to other land and facilityholdings within the state.  The exerciseand use of all of these water rights are subject to prior rights and, withrespect to certain hydroelectric generating facilities,

IPC's water rights for power generation aresubordinated to future upstream diversions of water for irrigation and otherrecognized consumptive uses.

Overtime, increased irrigation development and other consumptive diversions haveresulted in some reduction in the streamflows 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 streamflows 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 severalyears.  IPC has filed claims to itswater rights within the basin and is actively participating in the adjudicationto ensure that its water rights and the operation of its hydroelectricfacilities are not adversely impacted. IPC does not anticipate any modification of its water rights as a resultof the adjudication process.

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

**Environmental Regulation**Environmental regulationat the federal, state, regional and local levels continues to impact IPC'soperations due to the cost of installation and operation of equipment andfacilities required for compliance with such regulations and the modificationof system operations to accommodate such regulations.

Basedupon present environmental laws and regulations, IPC estimates its 2004 capitalexpenditures for environmental matters, excluding Allowance for Funds UsedDuring Construction (AFDC), will total $21 million.  Studies and measures related to environmental concerns at IPC'shydroelectric facilities account for $18 million and investments inenvironmental equipment and facilities at the thermal plants account for $3million.  From 2005 through 2006,environmental-related capital expenditures, excluding AFDC, are estimated to be$47 million.  Anticipated expensesrelated to IPC's hydroelectric facilities account for $36 million and thermalplant expenses are expected to total $11 million.

IPC anticipates $14 million in annual operatingcosts for environmental facilities during 2004.  Hydroelectric facility expenses account for $9 million of thistotal and $5 million is related to thermal plant operating expenses.  From 2005 through 2006, total environmental-relatedoperating costs are estimated to be $28 million.  Anticipated expenses related to the hydroelectric facilitiesaccount for $18 million and thermal plant expenses are expected to total $10million during this period.

**Clean Air:**  IPC has analyzed the Clean Air Actlegislation and its effects upon IPC and its customers.  IPC's coal-fired plants in Oregon and Nevadaalready meet the federal emission rate standards for sulfur dioxide (SO2)and IPC's coal-fired plant in Wyoming meets that state's even more stringent SO2regulations.  IPC has sufficient SO2allowances to provide compliance for all three coal-fired facilities and itsDanskin natural gas-fired facility.  Atthe end of 2003, IPC had 61,425 allowances in excess of the amount needed forClean Air Act compliance.  Currently,IPC has been granted an annual allotment of allowances ranging from 15,524 to28,628 through 2032.  These amounts arein excess of IPC's annual compliance requirements of up to 14,500.  Any excess allowances owned by IPC may beheld for future use as they do not expire. Allowances determined to be excess can be sold to other companies.  Accordingly, IPC does not foresee anymaterial adverse effects upon its operations with regard to SO2emissions.

In July 1997, the Environmental Protection Agency(EPA) announced the National Ambient Air Quality Standards for Ozone andParticulate Matter (PM) and in July 1999, the EPA announced regional hazeregulations for 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.  The impacts of PM, regionalhaze and ozone regulations on IPC's thermal operations are not known at thistime.  The future costs of compliancewith these regulations could be substantial and will depend if and how they areultimately implemented.

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 proposedlegislation, these units will not be required to meet the more restrictivePhase II NOx limits until 2008. Had the units not voluntarily "early elected," they would havebeen required to meet the Phase II limits in 2000.  Jim Bridger Units 1, 2 and 3 were accepted as substitution unitsin 1995 and are subject to NOx limits of Phase I instead of the morerestrictive limits of Phase II.  JimBridger has installed low NOx equipment to reduce NOxlevels even lower than currently required.

The Danskin gas turbine plant in Mountain Home,Idaho is operating in compliance with a "permit to construct" issuedby the Idaho Department of Environmental Quality (DEQ).  IPC has applied for a Title V OperatingPermit from the Idaho DEQ, which is expected during 2004.  The units are fitted with dry-low-NOxburners and a continuous emissions monitoring system.  This equipment should ensure that the facility will operatewithin the permitted federal and state NOx and carbon monoxidelimits.

**Water:**  IPC has received National PollutantDischarge Elimination System Permits, as required under the Federal WaterPollution Control Act Amendments of 1972, for the discharge of effluents fromits hydroelectric generating plants.

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.

IPC hasinstalled 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.

IPCowns and finances the operation of anadromous fish hatcheries and relatedfacilities to mitigate the effects of its hydroelectric dams on fishpopulations.  In connection with itsfish facilities, IPC sponsors ongoing programs for the control of fish diseaseand improvement of fish production. IPC's anadromous fish facilities at Hells Canyon, Oxbow, Rapid River,Pahsimeroi and Niagara Springs continue to be operated by the Idaho Departmentof Fish and Game.  At December 31, 2003,the investment in these facilities was $10 million and the annual cost ofoperation pursuant to FERC License 1971 was $3 million.

**EndangeredSpecies:**  Several species of fish and Snake Riversnails living within IPC's operating area are listed as threatened orendangered.  IPC continues to review andanalyze the effect such designation has on its operations.  IPC is cooperating with governmentalagencies to resolve issues related to these species.  See Part II, Item 7 - "MD&A - LEGAL AND ENVIRONMENTALISSUES - Environmental Issues - Threatened and Endangered Snails."

**Hazardous/ToxicWastes and Substances:**  Under the Toxic Substances Control Act(TSCA), the EPA has adopted regulations governing the use, storage, inspectionand disposal of electrical equipment that contains polychlorinated biphenyls(PCBs).  The regulations permit thecontinued use and servicing of certain equipment (including transformers andcapacitors) that contain PCBs.  IPCcontinues to meet all federal requirements of the TSCA for the continued use ofequipment containing PCBs.  IPC continuesto eliminate PCBs as part of its long-term strategy.  This program will reduce costs associated with the long-termmonitoring of PCB-containing equipment, responding to spills and reporting tothe EPA.  Total costs for theidentification and disposal of PCBs from IPC's system were less than $1 millionannually from 2000 to 2002.  In 2003,IPC spent approximately $1.4 million identifying and eliminating PCBs.

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

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.  The committee's focus has sinceshifted from restructuring to general energy issues.  In 1999, the Oregon Legislature passed legislation restructuringthe electric utility industry, but exempted IPC's service territory.

**Wholesale: **The1992 National Energy Policy Act (Energy Act) and the FERC's rulemakingactivities have established the regulatory framework to open the wholesaleenergy market to competition.  TheEnergy Act permits utilities to develop independent electric generating plantsfor sales to wholesale customers, and authorizes the FERC to order transmissionaccess for third parties to transmission facilities owned by anotherentity.  The Energy Act does not,however, permit the FERC to require transmission access to retailcustomers.  Open-access transmission forwholesale customers provides energy suppliers with opportunities to sell and deliverelectricity at market-based prices.

In December 1999, the FERC, in its landmark OrderNo. 2000, said that all companies with transmission assets must file to formRTOs or explain why they cannot do so. 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 further facilitate theformation of efficient, competitive wholesale electricity markets.

In October 2000 and March 2002, in response toFERC Order No. 2000, IPC and other regional transmission owners filed Stage Oneand Stage Two plans to form RTO West, an entity that would operate thetransmission grid in seven western states. RTO West will have its own independent governing board.  The participating transmission owners willretain ownership of the lines, but will not have a role in operating thegrid.  IPC has been an activeparticipant in the development of RTO West. See Part II, Item 7 - "MD&A - REGULATORY ISSUES - RegionalTransmission Organizations."  

**Utility OperatingStatistics**The following tablepresents IPC's revenues and energy use by customer type for the last threeyears, which is further discussed in Part II, Item 7 - "MD&A - RESULTSOF OPERATIONS - Utility Operations":
|                             | **Years Ended December 31,** |
|----------------------------------|------------------------------|
|                             | **2003**                     |   | **2002** |   | **2001** |
|                             |
| Revenues  (thousands of dollars) |                         |   |   |   |   |   |   |   |
|                             | Residential                  | $ | 275,920 |   | $ | 305,827 |   | $ | 260,251 |
|                             | Commercial                   |   | 173,820 |   |   | 196,454 |   |   | 164,019 |
|                             | Industrial                   |   | 128,620 |   |   | 176,648 |   |   | 154,318 |
|                             | Irrigation                   |   | 92,609 |   |   | 93,106 |   |   | 72,020 |
|                             |                         | Total  general business |   | 670,969 |   |   | 772,035 |   |   | 650,608 |
|                             | Off-system  sales            |   | 71,573 |   |   | 55,031 |   |   | 219,966 |
|                             | Other                        |   | 37,840 |   |   | 39,981 |   |   | 41,738 |
|                             |                         | Total | $ | 780,382 |   | $ | 867,047 |   | $ | 912,312 |
|                             |                         |   |   |   |   |   |   |   |   |
| Energy  use (thousands of MWh)   |                         |   |   |   |   |   |   |   |
|                             | Residential                  |   | 4,427 |   |   | 4,387 |   |   | 4,307 |
|                             | Commercial                   |   | 3,511 |   |   | 3,460 |   |   | 3,380 |
|                             | Industrial                   |   | 3,206 |   |   | 3,226 |   |   | 3,925 |
|                             | Irrigation                   |   | 1,836 |   |   | 1,821 |   |   | 1,419 |
|                             |                         | Total  general business |   | 12,980 |   |   | 12,894 |   |   | 13,031 |
|                             | Off-system  sales            |   | 1,830 |   |   | 2,069 |   |   | 2,387 |
|                             |                         | Total |   | 14,810 |   |   | 14,963 |   |   | 15,418 |
|                             |                         |   |   |   |   |   |   |   |   |

 

**ENERGY MARKETING:**IDACORP announced onJune 21, 2002 that IE would wind down its power marketing operations due tochanging liquidity requirements brought on by rating agencies, continueduncertainty in the regulatory and political environment and the reduction ofcreditworthy counterparties.  Nearingthe conclusion of the wind down process, IE sold its forward book ofelectricity trading contracts in August 2003 to Sempra Energy Trading (SET).

See further discussion of the energy marketingwind down in Part II, Item 7 - "MD&A - RESULTS OF OPERATIONS - EnergyMarketing", Note 13 to IDACORP's Consolidated Financial Statements andNote 17 to IPC's Consolidated Financial Statements.

**Energy MarketingOperating Statistics**The following tablepresents IE's revenues and volumes (including intersegment transactions) forthe last three years ended December 31:
|                                 |               |       | **2003** |       | **2002** |       | **2001** |
|--------------------------------------|--------------------|------------|----------|------------|----------|------------|----------|
|                                 |
| Net  Revenues (thousands of dollars) |               |       |     |       |     |       |     |   |
|                                 | Electricity        | $          | 19,267   |       | $        | 42,304     |     | $ | 330,793 |
|                                 | Gas                |       | 649      |       |     | 4,106      |     |   | 17,870 |
|                                 |               | Total      | $        | 19,916     |     | $          | 46,410   |   | $ | 348,663 |
|                                 |               |       |     |       |     |
| Operating  Volumes (settled)         |               |       |     |       |     |
|                                 | Electricity  (MWh) | 13,045,863 |     | 39,526,630 |     | 34,936,951 |
|                                 | Gas  (MMbtu)       | 2,255,881  |     | 35,895,039 |     | 97,327,432 |
|                                 |               |       |     |       |     |       |
|                                      |                    |            |          |            |          |            |          |  |  |  |  |

 

**IDACORP FINANCIALSERVICES, INC.:**

IFS invests primarily in affordable housingdevelopments, 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, Idaho.  IFS made nonew investments in 2003.

IFS hasfocused on a diversified approach to its investment strategy in order to limitboth geographic and operational risk. Over 90 percent of IFS's investments have been made through syndicatedtransactions.  At December 31, 2003,IFS's total portfolio exceeded $160 million in tax credit investments.  These investments cover 49 states, PuertoRico and the U.S. Virgin Islands.  Theunderlying investments include over 700 individual properties, of which all butfour are administered through syndicated funds.

IFS generates federal income tax credits andaccelerated tax depreciation benefits related to its investments in affordablehousing and historic rehabilitation developments.  Net reductions in consolidated income taxes related to IFS taxcredits were $20 million, $21 million and $13 million for the years 2003, 2002and 2001, respectively.

**IDA-WEST:**

In 2003, IDACORP began winding down Ida-West'soperations.  The wind down is discussedfurther in Part II, Item 7 - "MD&A - RESULTS OF OPERATIONS -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.

IPC has purchased all of the power generated byIda-West's four Idaho hydroelectric projects at a cost of $7 million in both2003 and 2002 and $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 a global fuel cell provider focused onthe commercialization of fuel processor technology and integrated protonexchange membrane (PEM) fuel cell systems. IdaTech's products under developmentinclude components such as multi-fuel fuel processors, fuel cell stack technology,automated fuel cell systems and integration and maintenance services. IdaTech'sfuel processors are capable of operating on alcohols and liquid and gaseoushydrocarbon fuels including natural gas, liquefied petroleum gas, diesel andkerosene.

IdaTech has integrated its multi-fuel fuelprocessors with a number of PEM fuel cell stacks into one to ten kW fuel cellsystems for stationary and portable electric power generation. 

Currently, these systems are being field-testedand evaluated with European utilities, the Propane Education and ResearchCouncil, the U.S. Army Communications Electronics Command and a number of othercustomers in North America, Europe and Asia.

On September 18, 2003, IdaTech was awarded adevelopment program of $9.6 million by the United States Department of Energyfor the development of a 50 kilowatt (kW) PEM fuel cell system suitable forenergy supplied independent of the electrical grid for large facilities.  This is a three-year, cost-sharedcooperative agreement between IdaTech and other technology, utility and hotelcompanies.

In October 2003, IdaTech received ISO 9001:2000certification, an international certification for quality managementrequirements in business-to-business dealings.

In February 2004, IdaTech and RWE Fuel Cells, autility based in Germany, announced that they will install the first two 5-kW,combined heat and power fuel cell systems operating on natural gas at therepresentative office of the State of North Rhine-Westphalia in Berlin.  The fuel cells will augment the supply ofelectricity and heat used in the building.

**IDACOMM AND VELOCITUS:**

In August 2000, IDACORPformed IDACOMM, Inc. and acquired Velocitus, Inc., a Boise, Idaho-basedInternet service provider founded in 1992. IDACOMM and Velocitus provide a wide range of integrated communicationservices to business and residential customers in 22 markets across eightwestern states, Virginia and New York.

IDACOMM, afacility-based integrated communication provider, delivers high-speed network connectivityusing 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 is conducting a broadband-over-powerline (BPL) technicaltrial in Boise and will be testing the commercial marketability of the productin 2004.  BPL will provide broadbandInternet access to power outlets in homes and businesses by transporting dataover medium-voltage and low-voltage power lines directly to the end-user'scomputer.  IDACOMM's customers includecompanies inindustries such as 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.

Velocitus operates as amanaged service provider by offering high-speed Internet access, Internetsystem support and other related services such as virtual private networks,firewalls and web hosting to 20,000 customers. Velocitus Internet serves the traditional residential and generalconsumer segment. Velocitus Broadband targets small to medium size businessclients with high-speed connectivity and security solutions, including fixedwireless technology.

**RESEARCH ANDDEVELOPMENT:**

In 2003, IdaTech spent approximately $5 millionfor research and development of fuel cell technology.  IdaTech's research and development program is focused on theadaptation of its methanol fuel processor to operate on all commerciallyimportant fuels, as well as the development of fully integrated fuel cellsystems.  Highest priority is given tonatural gas, liquefied petroleum gas, kerosene and diesel fuels.

IdaTech continues to pursue patent protection ofits 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 membranes used to filter out impuritiesin the hydrogen fuel.  Cost reductionthrough improved designs and reduced use of expensive materials are usefulobjectives of these patents.  IdaTech alsoreceived approval in early 2003 from the U.S. Patent and Trademark Office of itspatent application for a metal alloy composition that yields a durable andeconomical membrane for hydrogen purification. Currently, 26 twenty-year U.S. patents have been issued to IdaTech.  These permits expire from 2016 to 2024.  IdaTech also has approximately 150 pendingdomestic and foreign patent applications addressing various aspects of (a) fuelprocessor system design, operation, materials and integration; (b) membranepurification, materials and design; and (c) fuel cell system operation, thermalrecovery, design, remote control and diagnostics.  These patents will help IdaTech to bring its technology tocommercialization.  The patents alsoprovide the potential for licensing of IdaTech's technology in the future.

In 2003, IPC spent nearly $3 million to promoteenergy efficiency and summer peak reduction. Just over $1 million of those expenditures went to fund the NorthwestEnergy Efficiency Alliance, which strives to transform the regional marketplacethrough demonstration of innovative technologies, collaboration with firms thatmarket energy-saving products and services and training and informationservices. IPC's other energy efficiency programs target efficiencies in theareas of residential lighting and air conditioning, manufactured homes and ductsealing.  Low-income weatherization assistance and Oregonresidential weatherization efforts were also funded in 2003. In addition toIPC's on-going programs, funding was also allocated to the research anddevelopment of new energy efficiency and summer peak reduction options in thecommercial and residential sectors. Most of the funding for these programs and program development comesfrom the Idaho tariff rider for demand-side management (DSM) programs and fromthe Conservation and Renewable Discount Program of the BPA.

**ITEM 2. PROPERTIES**

IPC's system includes 17 hydroelectric generatingplants located in southern Idaho and eastern Oregon, one natural gas-firedplant located in southern Idaho and interests in three coal-fired steamelectric generating plants.  The systemalso includes approximately 4,655 miles of high voltage transmission lines; 22step-up transmission substations located at power plants; 18 transmissionsubstations; seven transmission switching stations; and 208 energized distributionsubstations (excluding mobile substations and dispatch centers).

IPC holds FERC licenses for its 13 hydroelectricprojects.  These projects and the othergenerating stations and their 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)   Licensed on a year-to-year basis while application for new multi-year  license is pending.                                  |
| (b)   IPC's ownership interests are 33 percent for Jim Bridger, 50 percent  for Valmy and 10 percent for Boardman.   Amounts |
|                                                                                                                                   | shown  represent IPC's share only.      |
|                                                                                                                                        |                                         |               |                |  |  |  |  |  |  |  |

 

At December 31, 2003, the composite average agesof the principal parts of IPC's system, based on dollar investment, were:production plant, 23 years; transmission system and substations, 21 years; anddistribution lines and substations, 17 years. IPC considers its properties to be well maintained and in good operatingcondition.

IPC owns in fee all of its principal plants andother important units of real property, except for portions of certain projectslicensed 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 andCalifornia.

**RELICENSING OFHYDROELECTRIC PROJECTS:**

IPC, like other utilities that operate nonfederalhydroelectric projects, obtains licenses for its hydroelectric projects fromthe FERC.  These licenses last for 30 to50 years, depending on the size and complexity of the project.  Currently, the licenses for fivehydroelectric projects have expired. These projects continue to operate under annual licenses until the FERCissues a new multi-year license.  Threemore hydroelectric project licenses will expire by 2010.

IPC is actively pursuing the relicensing of theseprojects, a process that may continue for the next ten to 15 years. IPC hasfiled applications with the FERC seeking new licenses for the Bliss, UpperSalmon Falls, Lower Salmon Falls, CJ Strike, Shoshone Falls, Upper and LowerMalad, and the Hells Canyon Complex (Brownlee, Oxbow, and Hells Canyon)hydroelectric projects. The licenses for all but the Upper and Lower Malad andthe Hells Canyon Complex (HCC) have expired and the projects are operating onannual licenses until new multi-year licenses are issued. The licenses for theMalad and HCC projects expire in July 2004 and July 2005, respectively.  The license for the Swan Falls Project expiresin 2010. IPC is currently engaged in procedures necessary to file a timelylicense application for the Swan Falls Project. Although various federal andstate requirements and issues must be resolved through the license renewalprocess, IPC anticipates that it will relicense all of the projects for whichapplications have been filed.

Final Environmental Impact Statements (EIS) havebeen issued for the Bliss, Upper Salmon Falls, Lower Salmon Falls and ShoshoneFalls projects.  New FERC licenses forthese projects are anticipated in 2004. While the actual environmental costs of protection, mitigation andenhancement (PM&E) measures and other costs associated with the relicensingof the projects will not be known until the new licenses are issued by the FERC,costs associated with these licenses (assuming 30-year licenses) are expectedto total approximately $8 million during the first five years of the licensesand $28 million over the following 25 years.

A final EIS was issued in October 2002 for the CJ Strikeproject and a new FERC license is also expected in 2004.  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, UpperSalmon Falls, Lower Salmon Falls and Shoshone Falls) and the CJ Strike project,may affect five species of snails listed under the Endangered Species Act.  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 license expiresin July 2004 and the new license application was filed in July 2002.  The application is proceeding through thenormal FERC licensing process.  Theapplication includes proposed PM&E measures estimated to total (assuming a30-year license) approximately $1 million during the first five years of thelicense and $3 million over the following 25 years.  However, the actual costs of PM&E measures and other costsassociated with the relicensing of the project will not be known until the newlicense is issued by the FERC.

The most significant relicensing effort is theHCC, which provides 68 percent of IPC's hydroelectric generation capacity and40 percent of its total generating capacity. IPC developed its license application with the assistance of acollaborative team made up of individuals representing state and federalagencies, businesses, environmental, tribal, customer, local government andlocal landowner interests.  Theapplication was filed with the FERC in July 2003.  The FERC is reviewing the application and has given notice of itsintent to prepare an EIS under the National Environmental Policy Act (NEPA). OnOctober 20, 2003, the FERC issued Scoping Document 1 to provide interestedparties with information on the project and to solicit written and verbalcomments and suggestions on the preliminary list of issues and alternativesthat the FERC should address in the EIS. This NEPA process is continuing.  By letter dated December 1, 2003, the FERCadvised IPC that the license application had been accepted for filing andconformed to applicable FERC regulations. On December 2, 2003 the FERCpublished notice of the acceptance of the application for filing and solicitedmotions to intervene and protests to the application.  The intervention and protest period closed on February 2, 2004and 18 separate parties either intervened or protested the IPC licenseapplication.  IPC has responded toselected interventions and the FERC is now preparing a second Scoping Documentas part of the NEPA process leading up to preparation of an EIS.

The HCC application includes proposed PM&Emeasures estimated to total (assuming a 30-year license) approximately $67million during the first five years of the license and $79 million during thefollowing 25 years.  However, the actualcosts of PM&E measures and other costs associated with the relicensing ofthe project will not be known until the new license is issued by the FERC.

At December 31, 2003, $61 million of relicensingcosts were included in Construction Work in Progress (CWIP) and $8 million ofrelicensing costs were included in Electric Plant in Service.  The relicensing costs are recorded and heldin CWIP until a new multi-year license or annual license is issued by the FERC,at which time the charges are transferred to Electric Plant in Service.  Relicensing costs and costs related to thenew licenses, as discussed above, will be submitted to regulators for recoverythrough the rate-making process. The current Idaho general rate case filingincludes $10 million of relicensing costs. 

**ITEM 3.  LEGAL PROCEEDINGS**

Please refer to Note 8 of IDACORP's ConsolidatedFinancial Statements.

**ITEM 4.  SUBMISSION OF MATTERS TO A VOTE OF SECURITYHOLDERS**

None

 

 

 

 

 

 

 

**EXECUTIVE OFFICERS OFTHE REGISTRANTS**

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

**IDACORP, Inc.**
| **Name, Age and Position**                                                           | **Business Experience During Past Five Years**                                                                                                                                                                                                                                                                                                                          |
|--------------------------------------------------------------------------------------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| Jan B. Packwood, 60  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, 51  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. |
|                                                                                 |                                                                                                                                                                                                                                                                                                                                                                    |
| *Darrel  T. Anderson, 45  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, 41  Vice President and Chief Information Officer              | Appointed March 15, 2001.                                                                                                                                                                                                                                                                                                                                               |
|                                                                                 |                                                                                                                                                                                                                                                                                                                                                                    |
| *Gregory  W. Panter, 55  Vice President - Public Affairs                             | Appointed April 1, 2001.                                                                                                                                                                                                                                                                                                                                                |
|                                                                                 |                                                                                                                                                                                                                                                                                                                                                                    |
| *Robert  W. Stahman, 59  Vice President, General Counsel and Secretary               | Appointed February 2, 1998.                                                                                                                                                                                                                                                                                                                                             |
|                                                                                 |                                                                                                                                                                                                                                                                                                                                                                    |
| *Daniel  B. Minor, 46  Vice President - Administrative Services and  Human Resources | Appointed November 20, 2003.                                                                                                                                                                                                                                                                                                                                            |

 
|   |
|--------|

*These IDACORP, Inc.executive officers serve in the same capacities at Idaho Power Company.  For these officers' business experienceduring the past five years, please refer to the following page.

 

**IdahoPower Company**
| **Name,  Age and Position**                                                          | **Business  Experience During Past Five Years**                                                                                                                                                                                                                                                                                                                          |
|--------------------------------------------------------------------------------------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|                                                                                 |                                                                                                                                                                                                                                                                                                                                                                     |
| Jan B. Packwood, 60  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, 51  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, 49  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, 45  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, 53  Vice President, Regulatory Affairs                                | Appointed  March 15, 2001.  Mr. Gale was General  Manager of Pricing & Regulatory Services from November 28, 1998 to March  15, 2001.                                                                                                                                                                                                                           |
|                                                                                 |                                                                                                                                                                                                                                                                                                                                                                     |
| Bryan  A.B. Kearney, 41  Vice President and Chief Information Officer                | Appointed  November 18, 1999.  Mr. Kearney was  Vice President and Chief Technology Officer at Bear Creek Corp, a direct  marketing, manufacturing and retail corporation, from October 1, 1998 to  November 18, 1999.                                                                                                                                              |
|                                                                                 |                                                                                                                                                                                                                                                                                                                                                                     |
| Gregory  W. Panter, 55  Vice President - Public Affairs                              | Appointed  April 1, 2001.  Mr. Panter was  self-employed with Greg Panter Consulting, a lobby/government affairs  business, from July 1, 1999 to April 1, 2001 and Westberg/Panter and  Associates, a lobby/government affairs business, from November 1, 1989 to  July 19, 1999.                                                                                   |
|                                                                                 |                                                                                                                                                                                                                                                                                                                                                                     |
| John  P. Prescott, 47  Vice President - Power Supply                                 | Appointed  November 18, 1999.  Mr. Prescott was  Vice President of Business Development for IDACORP Technologies, Inc. from  August 19, 1999 to November 18, 1999, and President and Treasurer of Stellar  Dynamics from October 5, 1995 to August 19, 1999.                                                                                                        |
|                                                                                 |                                                                                                                                                                                                                                                                                                                                                                     |
| Robert  W. Stahman, 59  Vice President, General Counsel and Secretary                | Appointed  July 13, 1989.                                                                                                                                                                                                                                                                                                                                                |
|                                                                                 |                                                                                                                                                                                                                                                                                                                                                                     |
| Daniel  B. Minor, 46  Vice President - Administrative Services and   Human Resources | Appointed  November 20, 2003.  Mr. Minor was Vice  President - Corporate Services from May 15, 2003 to November 20, 2003 and  Director of Audit Services from July 19, 2001 to May 15, 2003.  Mr. Minor was Executive Vice President and  COO of Right Systems, Inc., a technology management services company, from  September 8, 1998 to July 19, 2001.      |

** **

** **

**PART II******

**ITEM 5.  MARKET FOR THE REGISTRANT'S COMMON EQUITYAND RELATED STOCKHOLDER MATTERS******

IDACORP, Inc.'s (IDACORP)common stock (without par value) is traded on the New York Stock Exchange andthe Pacific Exchange.  At December 31,2003, there were 20,634 holders of record and the year-end stock price was$29.92 per share.

The outstanding shares ofIdaho Power Company (IPC) common stock ($2.50 par value) are held by IDACORPand are not traded.  IDACORP became theholding company of IPC on October 1, 1998.

The amount and timing ofdividends payable on IDACORP's common stock are within the sole discretion ofIDACORP's Board of Directors.  The Boardof Directors reviews the dividend rate quarterly to determine itsappropriateness in light of IDACORP's current and long-term financial positionand results of operations, capital requirements, rating agency requirements,legislative and regulatory developments affecting the electric utility industryin general and IPC in particular, competitive conditions and any other factorsthe Board of Directors deems relevant. In September 2003, IDACORP announced a decrease in the annual dividendfrom $1.86 to $1.20 per share.  Thisdecreased rate is equivalent to a quarterly dividend of $0.30 per share.  See further discussion of the dividendreduction in Part II, Item 7 - "MD&A - LIQUIDITY AND CAPTIAL RESOURCES- Dividend Reduction."  The abilityof IDACORP to pay dividends on its common stock is dependent upon dividendspaid to it by its subsidiaries, primarily IPC.

IPC's articles ofincorporation contain restrictions on the payment of dividends on its commonstock if preferred stock dividends are in arrears.  IPC paid dividends toIDACORP of $65 million in 2003 and $70 million in 2002 and 2001.

The following table shows the reported high and lowsales price of IDACORP's common stock and dividends paid for the years 2003 and2002 as reported in the consolidated transaction reporting system.
|                             | **2003 Quarters**                |
|----------------------------------|----------------------------------|
| Common Stock, without par value: | **1st**                          |   | **2nd** |   | **3rd** |   | **4th** |
|                             | High                             | $26.35 |   | $27.92 |   | $27.25 |   | $30.19 |
|                             | Low                              | 20.60 |   | 22.65 |   | 23.15 |   | 25.42 |
|                             | Dividends paid per share (cents) | 46.5 |   | 46.5 |   | 46.5 |   | 30.0 |
|                             |                             |
|                             | **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 |
|                             |                             |   |   |   |   |   |   |   |

 

 

**ITEM 6.  SELECTED FINANCIAL DATA**
| **IDACORP, Inc.**                                                                                                        |
|--------------------------------------------------------------------------------------------------------------------------|
| **SUMMARY OF OPERATIONS**                                                                                                |
| **(thousands of dollars except per share amounts)**                                                                      |
|                                                                                                                     | **2003** | **2002** | **2001** | **2000** | **1999** |
| **OPERATING REVENUES:**                                                                                                  |   |   |   |   |   |   |   |   |   |   |
| Electric utility:                                                                                                        |   |   |   |   |   |   |   |   |   |   |
|                                                                                                                     | General business | $ | 670,969  | $ | 772,035  | $ | 650,608  | $ | 565,357  | $ | 516,148  |
|                                                                                                                     | Off-system sales |   | 71,573  |   | 55,031  |   | 219,966  |   | 229,986  |   | 119,785  |
|                                                                                                                     | Other revenues |   | 40,178  |   | 41,974  |   | 43,627  |   | 41,663  |   | 24,226  |
|                                                                                                                     |   | Total electric utility  revenues |   | 782,720  |   | 869,040  |   | 914,201  |   | 837,006  |   | 660,159  |
| Energy marketing                                                                                                         |   | 19,916  |   | 46,410  |   | 348,663  |   | 190,116  |   | 40,157  |
| Other                                                                                                                    |   | 20,366  |   | 13,350  |   | 12,448  |   | 22,663  |   | 29,426  |
|                                                                                                                     | Total operating revenues |   | 823,002  |   | 928,800  |   | 1,275,312  |   | 1,049,785  |   | 729,742  |
|                                                                                                                     |   |   |   |   |   |   |   |   |   |   |
| **OPERATING EXPENSES:**                                                                                                  |   |   |   |   |   |   |   |   |   |   |
| Electric utility:                                                                                                        |   |   |   |   |   |   |   |   |   |   |
|                                                                                                                     | Purchased power |   | 150,980  |   | 142,102  |   | 584,209  |   | 398,649  |   | 106,344  |
|                                                                                                                     | Fuel expense |   | 99,898  |   | 102,871  |   | 98,318  |   | 94,215  |   | 86,617  |
|                                                                                                                     | Power cost adjustment |   | 70,762  |   | 170,489  |   | (175,925) |   | (120,688) |   | (502) |
|                                                                                                                     | Other operations and |   |   |   |   |   |   |   |   |   |   |
|                                                                                                                     |   |   | maintenance |   | 220,983  |   | 207,355  |   | 210,763  |   | 194,870  |   | 196,036  |
|                                                                                                                     | Depreciation |   | 97,650  |   | 93,609  |   | 87,041  |   | 80,287  |   | 77,833  |
|                                                                                                                     | Taxes other than income taxes |   | 20,753  |   | 19,953  |   | 19,693  |   | 20,166  |   | 21,719  |
|                                                                                                                     |   | Total electric utility expenses |   | 661,026  |   | 736,379  |   | 824,099  |   | 667,499  |   | 488,047  |
| Energy marketing:                                                                                                        |   |   |   |   |   |   |   |   |   |   |
|                                                                                                                     | Cost of revenues |   | 1,250  |   | 42,113  |   | 105,904  |   | 44,785  |   | 5,049  |
|                                                                                                                     | Selling, administrative and |   |   |   |   |   |   |   |   |   |   |
|                                                                                                                     |   | general |   | 24,349  |   | 30,427  |   | 66,047  |   | 50,811  |   | 13,424  |
|                                                                                                                     | Net loss on legal disputes |   | 12,072  |   | -  |   | -  |   | -  |   | -  |
| Other                                                                                                                    |   | 40,243  |   | 44,241  |   | 36,973  |   | 39,380  |   | 36,540  |
|                                                                                                                     | Total operating expenses |   | 738,940  |   | 853,160  |   | 1,033,023  |   | 802,475  |   | 543,060  |
| Operating income                                                                                                         |   | 84,062  |   | 75,640  |   | 242,289  |   | 247,310  |   | 186,682  |
| Other Income                                                                                                             |   | 24,412  |   | 19,218  |   | 33,600  |   | 42,265  |   | 22,819  |
| Other Expense                                                                                                            |   | 18,083  |   | 15,388  |   | 10,306  |   | 11,948  |   | 5,325  |
| Interest expense and other                                                                                               |   | 64,932  |   | 68,945  |   | 75,723  |   | 66,926  |   | 67,155  |
| Income tax (benefit) expense                                                                                             |   | (21,119) |   | (51,147) |   | 64,646  |   | 70,818  |   | 45,672  |
| Net income*                                                                                                              | $ | 46,578  | $ | 61,672  | $ | 125,214  | $ | 139,883  | $ | 91,349  |
| Dividends on common stock                                                                                                | $ | 64,726  | $ | 70,178  | $ | 69,782  | $ | 69,850  | $ | 69,863  |
|                                                                                                                     |   |   |   |   |   |   |   |   |   |   |   |
| **FINANCIAL CONDITION:**                                                                                                 |   |   |   |   |   |   |   |   |   |   |
| Total assets                                                                                                             | $ | 3,101,726  | $ | 3,387,168  | $ | 3,769,992  | $ | 4,159,177  | $ | 2,752,726  |
| Capitalization ratios:                                                                                                   |   |   |   |   |   |   |   |   |   |   |
|                                                                                                                     | Long-term debt |   | 51% |   | 49% |   | 46% |   | 48% |   | 49% |
|                                                                                                                     | Preferred stock |   | 3% |   | 3% |   | 6% |   | 6% |   | 6% |
|                                                                                                                     | Common stock equity |   | 46% |   | 48% |   | 48% |   | 46% |   | 45% |
| Short-term borrowings  outstanding                                                                                       | $ | 93,650  | $ | 176,200  | $ | 362,500  | $ | 120,600  | $ | 19,757  |
|                                                                                                                     |   |   |   |   |   |   |   |   |   |   |
| **FINANCIAL STATISTICS:**                                                                                                |   |   |   |   |   |   |   |   |   |   |
| Times interest charges  earned:                                                                                          |   |   |   |   |   |   |   |   |   |   |
|                                                                                                                     | Before tax |   | 1.37  |   | 1.16  |   | 3.52  |   | 4.33  |   | 3.18  |
|                                                                                                                     | After tax |   | 1.68  |   | 1.93  |   | 2.66  |   | 3.21  |   | 2.45  |
| Market-to-book ratio                                                                                                     |   | 132% |   | 108% |   | 175% |   | 225% |   | 134% |
| Payout ratio                                                                                                             |   | 139% |   | 114% |   | 56% |   | 50% |   | 77% |
| Return on year-end common  equity                                                                                        |   | 5.4% |   | 7.1% |   | 14.4% |   | 17.0% |   | 12.1% |
|                                                                                                                     |   |   |   |   |   |   |   |   |   |   |
| **COMMON STOCK DATA:**                                                                                                   |   |   |   |   |   |   |   |   |   |   |
| Earnings per average share                                                                                               |   |   |   |   |   |   |   |   |   |   |
|                                                                                                                     | outstanding | $ | 1.22  | $ | 1.63  | $ | 3.35  | $ | 3.72  | $ | 2.43  |
| Dividends declared per share                                                                                             | $ | 1.70  | $ | 1.86  | $ | 1.86  | $ | 1.86  | $ | 1.86  |
| Book value per share                                                                                                     | $ | 22.62  | $ | 23.01  | $ | 23.21  | $ | 21.85  | $ | 20.02  |
| Average shares outstanding                                                                                               |   |   |   |   |   |   |   |   |   |   |
|                                                                                                                     | (000 omitted) |   | 38,186  |   | 37,729  |   | 37,387  |   | 37,556  |   | 37,612  |
| Common shareowners                                                                                                       |   | 20,634  |   | 20,088  |   | 22,512  |   | 21,886  |   | 23,758  |
|                                                                                                                     |   |   |   |   |   |   |   |   |   |   |
| * See "Wind Down of  Energy Marketing" in Note 13 to IDACORP's Consolidated Financial  Statements, "Legal |
| Proceedings - Overton Power  District No. 5" in Note 8 to IDACORP's Consolidated Financial Statements  and          |
| "Tax Accounting Method  Change" in Note 2 to IDACORP's Consolidated Financial Statements.                      |
|                                                                                                                     |
| The  above data should be read in conjunction with IDACORP's Consolidated  Financial Statements and Notes to the         |
| Consolidated  Financial Statements.                                                                                      |
|                                                                                                                          |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

 
| **IDAHO POWER COMPANY**                                                                                      |
|--------------------------------------------------------------------------------------------------------------|
| **SUMMARY OF OPERATIONS**                                                                                    |
| **(thousands of dollars)**                                                                                   |
|                                                                                                         | **2003** | **2002** | **2001** | **2000** | **1999** |
| Operating revenues                                                                                           | $ | 780,382  | $ | 867,047  | $ | 912,312  | $ | 835,662  | $ | 658,336  |
| Income from operations                                                                                       |   | 121,510  |   | 132,540  |   | 90,020  |   | 169,636  |   | 172,458  |
| Income from continuing  operations                                                                           |   | 58,591  |   | 88,920  |   | 28,295  |   | 79,968  |   | 83,465  |
| Earnings on common stock                                                                                     | $ | 55,161  | $ | 84,333  | $ | 72,838  | $ | 131,559  | $ | 91,956  |
|                                                                                                         |   |   |   |   |   |   |   |   |   |   |
| **At December 31,**                                                                                          |   |   |   |   |   |   |   |   |   |   |
|                                                                                                         | Total long-term debt |   | 880,868  |   | 870,741  |   | 802,201  |   | 808,977  |   | 821,558  |
|                                                                                                         | Total assets |   | 2,820,711  |   | 2,876,167  |   | 2,987,382  |   | 2,736,563  |   | 2,671,729  |
|                                                                                                         |   |   |   |   |   |   |   |   |   |   |   |
| **UTILITY CUSTOMER DATA:**                                                                                   |   |   |   |   |   |   |   |   |   |   |
| General business data:                                                                                       |   |   |   |   |   |   |   |   |   |   |
|                                                                                                         | Energy sales - MWh |   | 12,980  |   | 12,894  |   | 13,031  |   | 14,598  |   | 13,766  |
|                                                                                                         | Number of customers at |   |   |   |   |   |   |   |   |   |   |
|                                                                                                         |   | December 31 |   | 426,600  |   | 414,944  |   | 401,739  |   | 392,128  |   | 384,421  |
| Residential customer data:                                                                                   |   |   |   |   |   |   |   |   |   |   |
|                                                                                                         | Number of customers at |   |   |   |   |   |   |   |   |   |   |
|                                                                                                         |   | December 31 |   | 354,704  |   | 344,447  |   | 335,285  |   | 327,983  |   | 319,956  |
|                                                                                                         | Average kWh use per customer |   | 12,481  |   | 12,911  |   | 13,001  |   | 13,580  |   | 13,379  |
|                                                                                                         | Average rate per kWh (cents) |   | 6.23  |   | 6.97  |   | 6.04  |   | 5.13  |   | 5.08  |
|                                                                                                         |   |   |   |   |   |   |   |   |   |   |   |
| The  above data should be read in conjunction with IPC's Consolidated Financial  Statements and Notes to the |
| Consolidated  Financial Statements.                                                                          |
|                                                                                                              |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTSOF OPERATIONS

(Dollar amounts are in thousands unless otherwiseindicated.  Megawatt hours (MWh) are inthousands.)

**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. and itssubsidiaries (collectively, IDACORP) and Idaho Power Company and its subsidiary(collectively, IPC) are discussed. IDACORP is a holding company formed in 1998 as the parent of IPC andseveral other entities.

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

IDACORP's other operatingsubsidiaries include:

 
    - IdaTech - developer of integrated fuel cell     systems;
    - IDACORP Financial Services, Inc. (IFS) -     affordable housing and other real estate investments;
    - Velocitus - commercial and residential     Internet service provider;
    - IDACOMM - provider of telecommunications     services;
    - Ida-West Energy (Ida-West) - developer and     manager of independent power projects; and
    - IDACORP Energy (IE) - marketer of electricity     and natural gas.

 

IE is in the late stages ofwinding down its operations.  In 2003,IDACORP began winding down Ida-West's operations, as discussed in "RESULTSOF OPERATIONS - Ida-West" later in the MD&A.

While reading the MD&A,please refer to the Consolidated Financial Statements of IDACORP and IPC, whichpresent the financial position at December 31, 2003 and 2002, and the resultsof operations and cash flows for each company for the years ended December 31,2003, 2002 and 2001.

**FORWARD-LOOKING INFORMATION:**

In connection with the safeharbor provisions of the Private Securities Litigation Reform Act of 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, in presentations,in response to questions or otherwise. Any statements that express, or involve discussions as to expectations,beliefs, plans, objectives, assumptions or future events or performance (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 in governmentalpolicies and regulatory actions, including those of the Federal EnergyRegulatory Commission (FERC), the Idaho Public Utilities Commission (IPUC) andthe Oregon Public Utility Commission (OPUC), with respect to allowed rates ofreturn, industry and rate structure, acquisition and disposal of assets andfacilities, operation and construction of plant facilities, relicensing ofhydroelectric projects, recovery of purchased power, recovery of other capitalinvestments, present or prospective wholesale and retail competition (includingbut not limited to retail wheeling and transmission costs) and other refundproceedings;

Litigation resultingfrom the energy situation in the western United States;

Economic, geographicand political factors and risks;

Changes in andcompliance with environmental and safety laws and policies;

Weather variationsaffecting customer energy usage;

Operating performanceof plants and other facilities;

System conditions andoperating costs;

Population growth ratesand demographic patterns;

Pricing andtransportation of commodities;

Market demand andprices for energy, including structural market changes;

Changes in capacity,fuel availability and prices;

Changes in tax rates orpolicies, interest rates or rates of inflation;

Changes in actuarialassumptions;

Adoption or changes incritical accounting policies or estimates;

Exposure tooperational, market and credit risk;

Changes in operatingexpenses and capital expenditures;

Capital marketconditions;

Rating actions byMoody's, Standard & Poor's and Fitch;

Competition for newenergy development opportunities;

Results of financingefforts, including the ability to obtain financing on favorable terms, whichcan be affected by various factors, including credit ratings and generaleconomic conditions;

Natural disasters, actsof war or terrorism;

Increasing health carecosts and the resulting effect on health insurance premiums paid for employeesand on the obligation to provide postretirement health care benefits;

Increasing costs ofinsurance, changes in coverage terms and the ability to obtain insurance;

Legal andadministrative proceedings, whether civil or criminal, and settlements thatinfluence business and profitability; and

New accounting orSecurities and Exchange Commission requirements, or new interpretation orapplication of existing requirements.

 

Any forward-looking statement speaks only as of the dateon which such statement is made.  Newfactors emerge from time to time and it is not possible for management topredict all such factors, nor can it assess the impact of any such factor onthe business or the extent to which any factor, or combination of factors, maycause results to differ materially from those contained in any forward-lookingstatement.

**RISK FACTORS:**

The following are importantfactors that could have a significant impact on the operations and financialresults of IDACORP, Inc. and Idaho Power Company and could cause actual resultsor outcomes to differ materially from those discussed in any forward-lookingstatements:

**Reducedhydroelectric generation can significantly affect operating results.**  Idaho Power Company has a predominatelyhydroelectric generating base.  Becauseof Idaho Power Company's heavy reliance on hydroelectric generation, theweather can significantly affect Idaho Power Company's operations.  Idaho Power Company experienced its fourthconsecutive year of below normal water conditions in the 2002-2003 water yearand while the 2003-2004 snowpack is near normal, streamflows are currentlyexpected to remain below normal.  Whenhydroelectric generation is reduced, Idaho Power Company must increase its use ofmore expensive thermal generating resources and purchased power.  Through its Power Cost Adjustment in Idaho,Idaho Power Company can expect to recover approximately 90 percent of theincrease in its Idaho jurisdictional net power supply costs (fuel and purchasedpower less sales for resale) above the level included in its base rates.  The Power Cost Adjustment recovery is onboth a forecasted and deferred basis and is subject to the regulatoryprocess.  The balance of its fuel andpurchased power expense is subject to periodic recovery from its Oregon andFederal Energy Regulatory Commission jurisdictional customers.

**Changesin temperature can reduce power sales and affect operating results.**  Idaho Power Company experienced warmer thanusual temperatures in its service territory in the winter months of 2003, whichreduced sales.  Warmer than normalwinters or cooler than normal summers will reduce retail revenues from powersales.

**Conditionsthat may be imposed in connection with hydroelectric license renewals maynegatively affect earnings.**  IdahoPower Company is currently involved in renewing federal licenses for most ofits hydroelectric projects.  Idaho PowerCompany currently expects new licenses for five middle Snake River regionhydroelectric plants to be issued in 2004. In addition, Idaho Power Company filed its license application on July18, 2003 for the Hells Canyon Complex, which provides 40 percent of Idaho PowerCompany's total generating capacity. Conditions with respect to environmental, operating and other mattersthat may be imposed by the Federal Energy Regulatory Commission in connectionwith the renewal of these licenses could have a negative effect on Idaho PowerCompany's operations.

**Thecost of complying with environmental regulations can significantly affectoperating results.**  IDACORP,Inc. and Idaho Power Company are subject to extensive federal, state and localenvironmental statutes, rules and regulations relating to air quality, waterquality, natural resources and health and safety.  Compliance with these environmental statutes, rules andregulations involves significant capital, operating and other costs, and thosecosts could be even more significant in the future as a result of changes inlegislation and enforcement policies and additional requirements imposed inconnection with the relicensing of Idaho Power Company's hydroelectricprojects.

**If theIdaho Public Utilities Commission does not grant requested rate relief,****IdahoPower Company's earnings and cash flow will be negatively affected.**  Idaho Power Company is proceeding throughits Idaho general rate case filed with the Idaho Public Utilities Commission onOctober 16, 2003, requesting $86 million in additional annual revenue, or anaverage 17.7 percent increase to base rates. Idaho Power Company has not had an overall base rate increase since1995.  Since that time, Idaho PowerCompany has invested more than $850 million in its electrical system,experienced an increase in normal operating costs due to inflation and addednearly 100,000 customers.  If the IdahoPublic Utilities Commission does not grant the requested rate relief, IdahoPower Company's earnings and cash flow will be negatively impacted and itscredit ratings may be downgraded.

**Terroristthreats and activities can significantly affect operating results.**  IDACORP, Inc. and Idaho Power Company aresubject to direct and indirect effects of terrorist threats andactivities.  Potential targets includegeneration and transmission facilities. The effects of terrorist threats and activities could prevent IdahoPower Company from purchasing, generating or transmitting power and result inlost revenues and increased costs.

**IdahoPower Company and its affiliate, IDACORP Energy, are subject to potentialliabilities as a result of energy marketing operations.**  As IDACORP Energy wound down its energymarketing operations, certain matters were identified that required resolutionwith the Federal Energy Regulatory Commission and the Idaho Public UtilitiesCommission.  The Federal EnergyRegulatory Commission matters have been resolved; however, certain compensationissues remain to be resolved with the Idaho Public Utilities Commission.  In an Idaho Public Utilities Commissionproceeding that has been underway since May 2001, Idaho Power Company, theIdaho Public Utilities Commission staff and several interested customer groupshave been working to determine the appropriate compensation IDACORP Energyshould provide to Idaho Power Company for certain transactions between theaffiliates. The parties to the proceeding have executed a settlement agreementproviding that an additional $5.5 million will be flowed through the Power CostAdjustment mechanism to the Idaho retail customers from April 2003 throughDecember 2005.  This agreement was filedwith the Idaho Public Utilities Commission on February 17, 2004 and is subjectto its approval.  This settlement shouldresolve all remaining compensation issues. It is possible that other proceedings may be commenced against IdahoPower Company or IDACORP Energy in connection with energy marketing.

**IDACORP,Inc., IDACORP Energy and Idaho Power Company are subject to costs and othereffects of legal and administrative proceedings, settlements, investigationsand claims, including those that may arise out of the California energysituation.**  IDACORP, Inc.,IDACORP Energy and Idaho Power Company are involved in a number of proceedingsincluding a complaint filed against sellers of power in California, based onCalifornia's unfair competition law, a cross-action wholesale electricantitrust case against various sellers and generators of power in Californiaand the California refund proceeding at the Federal Energy RegulatoryCommission.  Other cases that are thedirect or indirect result of the energy crisis in California include efforts bycertain public parties to reform or terminate contracts for the purchase ofpower from IDACORP Energy and show cause proceedings at the Federal EnergyRegulatory Commission that consider whether certain trading practicesconstituted gaming or acting in concert in furtherance of a gamingstrategy.  To the extent the companiesare required to make payments, earnings will be negatively affected.  It is possible that additional proceedingsrelated to the California energy crisis may be filed in the future againstIDACORP, Inc., IDACORP Energy or Idaho Power Company.

**Increasedcapital expenditures can significantly affect liquidity.**  Increases in both the number of customersand the demand for energy require expansion and reinforcement of transmission,distribution and generating systems. Additionally, a significant portion of Idaho Power Company's facilitieswas constructed many years ago.  Agingequipment, even if maintained in accordance with good engineering practices,may require significant capital expenditures. Failure of equipment or facilities used in Idaho Power Company's systemscould potentially increase repair and maintenance expenses, purchased powerexpenses and capital expenditures.

**A SUMMARY OF 2003 AND OUTLOOK FOR 2004:**

This section presents an overview of the most criticalissues that IDACORP and IPC are facing, and the significant items that affectedIDACORP's and IPC's 2003 operating results.

**Financial Results**IDACORP's earnings per share (EPS) of $1.22 was a $0.41 decrease from2002's $1.63 per share.  Several keyfactors impacted 2003's results:

**IPC**earned $1.44 per share in 2003. Below normalstreamflow conditions continue to affect IPC's hydroelectric generationcapability.  Lower than normalhydroelectric generation, combined with unplanned outages at thermal plants,resulted in a greater reliance on market purchases of electricity to meet theneeds of its service territory.  Thesethermal outages, along with pension expense increases, were primary factors ina $13 million increase to utility operation and maintenance expenses.  Additionally, IPC reached tax settlementswith the IRS for the years 1998-2000, resulting in a $9 million decrease toincome tax expense.

**IDACORPEnergy:** Wind down activity continued at IE, which posted a net loss of$0.25 per share.  Losses on thesettlement of legal matters and other wind down costs were partially offset bya gain on the sale of the forward book of energy trading contracts.

**IFS**contributed $0.27 per share, principally from the generation of federal incometax credits and tax depreciation benefits.

**IdaTech** contributed $(0.04) per share,which is an improvement of  $0.18 pershare, due primarily to the successful resolution of existing contracts,including a $4 million settlement of a contract related to the design,production and delivery of fuel cell systems. 

**Ida-West**wrote down its remaining investment in the Garnet project and two jointventures and recorded a reserve on a note receivable, reducing EPS by $0.13.

**General Rate Case Filing**IPC is proceeding through its Idaho general rate case that wasoriginally filed with the IPUC on October 16, 2003.  IPC requested approximately $86 million annually in additionalrevenue, or an average 17.7 percent increase to base rates.  On February 20, 2004, the IPUC Staff andseven other intervenors filed their testimony with the IPUC.  The testimony covered revenue requirementand rate design issues.  The IPUCStaff's proposal of $15 million, a three-percent overall increase to base rates,was the lowest recommendation of any of the parties.  Copies of the parties' testimony and exhibits can be viewed atthe IPUC web site.  IPC has until March19, 2004 to prepare its rebuttal to these recommendations.  Formal hearings are scheduled to begin onMarch 29, 2004, and a final order is expected from the IPUC on May 28, 2004,with a June 1, 2004 effective date.

IPC hasnot had an overall base rate increase since 1995.  Since that time, IPC has invested more than $850 million in itselectrical system, experienced an increase in normal operating costs due toinflation and added nearly 100,000 customers.

IPC cannot predict what level of rate adjustment the IPUCwill grant.  Should the IPUC grant lessthan IPC's request, IPC might need to implement alternative strategies.  These strategies could result in thedeferral or elimination of certain capital expenditures, greater reliance onpurchased power to meet customer needs, other cost containment measures and thefiling of another rate request with the IPUC.

**Hydroelectric Generation and Power Supply Costs**IPC relies on low-cost hydroelectric plants for a significant portionof its power supply.  In 2003, IPCexperienced its fourth consecutive year of below normal hydroelectricgenerating conditions, which necessitated increased reliance on higher-costthermal generation and purchased power. Unplanned outages at thermal plants further increased the need topurchase power.

Increased reliance on purchased power and higher marketprices for this power resulted in IPC absorbing approximately $25 million ofpower supply costs that were not recovered through its Power Cost Adjustment(PCA) mechanism.  IPC absorbedapproximately $25 million in 2002 and $76 million in 2001.  With more normal generating conditions IPCwould absorb lesser amounts of power supply costs.

There are early indications of some relief from depressedhydroelectric generating conditions. The most recent hydrological surveyprojects that conditions in 2004 will be improved over 2003, but remain belownormal.

**Strategy**During 2003, IDACORP refocused on a strategy called "ElectricityPlus," a back-to-basics strategy that emphasizes IPC as IDACORP's corebusiness.  IPC continues to experiencestrong growth in its service area and this revised corporate strategyrecognizes that IPC must make substantial investments in infrastructure toensure adequate supply and reliable service.  The "Plus" recognizes that through modest investments in IdaTechand IDACOMM, IDACORP can preserve the potential for additional growth inshareowner value.  IFS, with its federalincome tax credits, remains a key component of the revised corporate strategy.

**Wind Down of Non-Utility Businesses**The wind down of IE neared completion asmajor milestones were reached in 2003:

Severalmajor legal issues were resolved during the year;

Theforward book of energy trading contracts was sold in August;

IE'sworkforce, once as high as 125, has been eliminated; and

$45million of a note receivable from Overton Power District No. 5 was collected inDecember.

 

At December 31, there werestill a number of legal matters outstanding, as discussed in "Legal andEnvironmental Issues" later in the MD&A.

The wind down of Ida-West began in the fourth quarter of2003, after a review of the prospects for that business.  IDACORP's revised strategic direction didnot include the development or acquisition of merchant related generation,which had been Ida-West's focus.  Thefourth quarter of 2003 includes $8.6 million in impairment charges related toremaining site costs of the Garnet energy facility, investments in jointventures and notes receivable.

**Dividend Reduction**In September 2003, IDACORP's annualdividend was reduced to $1.20 per share from $1.86 per share.  This action was taken in order to strengthenIDACORP's financial position and its ability to fund IPC's growing capitalexpenditure needs.  The change tookeffect with the quarterly dividend paid on December 1, 2003.

**Relicensing**On July 18, 2003, IPC filed itsapplication with the FERC to relicense the company's three-dam Hells CanyonComplex (HCC).  The current license forHCC will expire in 2005; however, the FERC requires applicants to file twoyears in advance of a license's expiration date.  HCC is the largest in IPC's system of 17 hydroelectric generatingplants and collectively, the HCC provides approximately two-thirds of IPC'stotal hydroelectric generation capacity.

**Legal Issues and RegulatoryMatters**IDACORP, IPC and IE have been named as defendants in a number of legalcases.  Major developments include:

Contract disputes withTruckee-Donner Public Utility District were settled, with no material impact onthe companies;

A contract-related lawsuitfiled by the Public Utility District No. 1 of Grays Harbor County, Washingtonwas dismissed with prejudice on January 28, 2003.  This matter has been appealed to the U.S. Court of Appeals forthe Ninth Circuit;

A contract dispute with OvertonPower District No. 5 was settled, resulting in a $21.5 million loss in thesecond quarter of 2003.  In December2003, IE received $45 million in final settlement of the contract;

In February 2003, the FERC resolved a matterrelated to the wind down of energy marketing, approving the assignment ofcertain wholesale power and transmission services agreements from IPC to IE;

In May 2003, the U.S. Bankruptcy Court approved asettlement agreement between the companies and Enron in connection with claimsIE had submitted in the Enron bankruptcy proceeding for net pre-petitionobligations owed by Enron to IE, primarily for power and energy delivered priorto the Enron bankruptcy; and

In February 2004, Vierstra Dairy was awardedapproximately $17 million in damages for the alleged effect of electricalcurrent on the health of Vierstra's dairy cows.  IPC intends to appeal the jury decision.

**CRITICAL ACCOUNTING POLICIES:**

IDACORP and IPC's discussion and analysis of theirfinancial condition and results of operations are based upon their consolidatedfinancial statements, which have been prepared in accordance with accountingprinciples generally accepted in the United States of America.  The preparation of these financialstatements requires IDACORP and IPC to make estimates and judgments that affectthe reported amounts of assets, liabilities, revenues and expenses, and relateddisclosure of contingent assets and liabilities.  On an ongoing basis, IDACORP and IPC evaluate these estimates,including those related to rate regulation, benefit costs, contingencies,litigation, impairment of assets, income taxes, restructuring costs and baddebt.  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 order toapply 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 71requires companies that meet the above conditions to reflect the impact ofregulatory decisions in their consolidated financial statements and requiresthat certain costs be deferred as regulatory assets until matching revenues canbe recognized.  Similarly, certain itemsmay be deferred as regulatory liabilities and amortized to the income statementas rates 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 effect of this policy is that IPC has recorded $434 million ofregulatory assets and $259 million of regulatory liabilities at December 31,2003.  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 would 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.  If IPChas to write off a material amount of the regulatory assets, this will have amaterial adverse effect on IPC's operating results.

**Pension Expense**IPC maintains a qualified defined benefit pension plan covering mostemployees and an unfunded nonqualified deferred compensation plan for certainsenior management employees and directors.

IDACORP's and IPC's recorded pension expense for theseplans is dependent on a number of factors, including the provisions of theplans, changing employee demographics, actual returns on plan assets andseveral actuarial assumptions used in the valuations upon which pension expenseis based.  The key actuarial assumptionsthat affect expense are the long-term return on plan assets and the discountrate used in determining future benefit obligations.  Management reviews these assumptions on an annual basis, takinginto account changes in market conditions, trends and future expectations.  Estimates about future stock marketperformance, changes in interest rates and other factors used to develop theseassumptions are extremely uncertain, and actual results could varysignificantly from those used to develop the assumptions.

The assumed discount rate is based on reviews of marketyields on high-quality corporate debt. Based on recent market trends, the discount rate used for 2004 pensionexpense will be reduced to 6.15 percent from the 6.75 percent used in 2003.

Rate-of-return projections for plan assets are based onhistorical real returns (after inflation) for each asset class, based on arecognized index established for the asset class being measured (S&P 500Index for large-cap core stocks, Russell 1000 Growth for large-cap growthstocks, etc.).  Historical real returnsare then adjusted to include an inflation premium based on the currentinflation environment.  Currently a twopercent inflation assumption is used in the asset modeling process.

Pension expense (income) for these plans totaled $12million, $4 million and ($4 million) for the three years ended December 31,2003, 2002 and 2001, respectively, including amounts allocated to capitalizedlabor costs.  For 2004, pension expenseis expected to total approximately $10 million, which takes into account thereduction of the discount rate noted above and returns on plan assets in 2003that exceeded actuarial estimates.  Nochanges were made to the other key assumptions used in the actuarialcalculation. 

Had different actuarial assumptions been used, pensionexpense could have varied significantly. The following table reflects the sensitivities associated with changesin certain actuarial assumptions on historical and future pension expense: 
|                    | **Discount  rate**            | **Rate  of return** |
|-------------------------|-------------------------------|---------------------|
|                    | **2004**                      | **2003**            | **2004** | **2003** |
|                    | **(in  millions of dollars)** |
| Effect of 0.5% increase | $                             | (1.6)               | $ | (1.6) | $ | (1.6) | $ | (1.4) |
| Effect of 0.5% decrease |                          | 1.7            |   | 2.9  |   | 1.6  |   | 1.4  |
|                    |                          |                |   |   |   |   |   |   |

 

No cash contributions were made to the qualified plan in2001 through 2003, and none are expected in 2004.  Under the non-qualified plan, IPC makes payments directly toparticipants in the plan.  Payments wereapproximately $2.5 million per year in 2001 though 2003, and a similar amountis anticipated in 2004.

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

**Contingent Liabilities**There are a number of unresolved issues related to regulatory, legaland tax matters.  Contingent liabilitiesare provided for in accordance with SFAS 5, "Accounting forContingencies." According to SFAS 5, an estimated loss from a loss contingencyshall be charged to income if (a) it is probable that an asset had beenimpaired or a liability had been incurred at the date of the financialstatements and (b) the amount of the loss can be reasonably estimated.Disclosure in the notes to the financial statements is required for losscontingencies not meeting both those conditions if there is a reasonablepossibility that a loss may have been incurred. Gain contingencies are notrecorded until realized.

The companies have made estimates of the ultimateresolution of all such matters, based on the facts and circumstances, opinionsof legal counsel and other factors.  Ifthe recognition criteria of SFAS 5 have been met, reserves have been recorded.  Estimates of this nature are highlysubjective, and the final outcome of these matters could vary significantlyfrom the amounts that have been included in the current financial statements.

**Asset Impairment**IDACORP has several assets that are tested for impairment inaccordance with various accounting pronouncements.  Those assets that were tested in 2003 include the following:

**Goodwill:** IDACORP has $13 million of goodwill related to its investments inVelocitus, IDACOMM and IdaTech.  IDACORPconducts its impairment tests under the provisions of SFAS 142, "Goodwilland Other Intangible Assets." According to SFAS 142, goodwill is tested for impairment at leastannually, and more frequently when events occur or circumstances change thatmore likely than not would reduce the fair value of a reporting unit below itscarrying amount.  SFAS 142 requires thatif the fair value of a reporting unit is less than its carrying value includinggoodwill, the implied fair value of the reporting unit goodwill must becompared with its carrying value to determine the amount of the impairment.

IDACORP's recorded goodwill amounts were tested forimpairment as required, and no impairment was noted.  The fair value calculations used for these tests require IDACORPto make assumptions about items that are inherently uncertain.  Assumptions related to future market demand,market prices and product costs could vary from actual results, and the impactof such variations could be material. Factors that could affect the assumptions include changes in economicconditions, success in developing marketable products and services andcompetitive conditions in the telecommunications and fuel cell industries.

**Long-lived Assets:** Long-lived assets areperiodically reviewed for impairment when events or changes in circumstancesindicate that the carrying amount of an asset may not be recoverable asprescribed under SFAS 144, "Accounting for the Impairment or Disposal ofLong-lived Assets."  SFAS 144requires that if the sum of the undiscounted expected future cash flows from anasset is less than the carrying value of the asset, an asset impairment must berecognized in the financial statements. 

SWIP: IPC began developing the Southwest IntertieProject (SWIP) in 1988.  This projectcovers the construction and operation of a 500-mile 500-kilovolt transmissionline that would connect IPC's system with California and the Southwest.  IPC's investment consists predominantly ofrights-of-way over public lands in Idaho and Nevada. While no definitive actionhas taken place with SWIP in several years, discussions occur from time-to-timewith parties interested in acquiring or joining with IPC in furtherdevelopment.  Based on these discussionsand management expectations about the ultimate development of SWIP, noimpairment has been identified.  These expectationsare based on assumptions that are inherently uncertain.  Actual results could vary significantly fromthe assumptions used, and the impact of such variations could be material.

Garnet: During 2003, Ida-West wrotedown its remaining investment in the Garnet energy facility, which was to bedeveloped as a 273-MW gas-fired generation station.  Originally, the Garnet facility had been selected by IPC to meetfuture energy needs based on IPC's 2000 Integrated Resource Plan (IRP) and IPCentered into a Power Purchase Agreement (PPA) to purchase the Garnet facility'soutput.  Due to dramatic changes in theelectric industry, financing the project on acceptable terms under the PPAbecame impractical and Ida-West wrote down its $8 million investment in equipmentfor the project in 2002.  Approximately$3.6 million of costs related to the development of the Garnet site remained,as the site continued to be viable for future generation development. 

In 2003, the PPA for Garnet was terminated and IPC issueda request for proposal (RFP) for development of additional generationcapability in IPC's service territory. The RFP specifically prohibited affiliates of IPC, including Ida-West,from bidding.  Accordingly, anotherproject proposed by a party unaffiliated with IPC was selected, leading tomanagement's determination that further development of the Garnet project wasimprobable.  Based on this conclusion,the remaining $3.6 million investment in Garnet was written off in 2003.

**Investments:**IFS hasaffordable housing and other investmentstotaling $116 million at December 31, 2003, and Ida-West has investments infour joint ventures that own electric power generation facilities.  These investments are accounted for underthe equity method of accounting as described in Accounting Principles BoardOpinion No. (APB) 18, "The Equity Method of Accounting for Investments inCommon Stock".  The standard fordetermining whether impairment must be recorded under APB 18 is whether theinvestment has experienced a loss in value that is considered an "otherthan temporary" decline in value. 

Prior to the decision to winddown Ida-West's activities, Ida-West had the intent and ability to hold theinvestments for a time period sufficient to recover the recorded value.  Based upon the change in management'sintent, these investments were tested for impairment, and two of theinvestments were determined to be impaired, resulting in a write down of $2.4million in 2003. The impairment amounts are based on the estimated fair valueof the investments.

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

**RESULTS OF OPERATIONS:**

This section of the MD&A takes a closer look at thesignificant factors that affected IDACORP's and IPC's earnings over the lastthree years.  In this analysis, theresults of 2003 are compared to 2002 and the results of 2002 are compared to2001.  The analysis is organized byoperating segment, concentrating on the Utility Operations and Energy Marketingsegments.  Additional noteworthyinformation about the results of other segments is also included.  The following table presents EPS broken downby operating segment:
| **EPS of common stock**          |     |       |     |   |       |
|----------------------------------|----------|------------|----------|--------|------------|
|                             | **2003** |       | **2002** |   | **2001**   |
| Utility operations               | $        | 1.44  |     | $      | 2.24  |   | $ | 0.60  |
| Energy marketing                 |     | (0.25)     |     |   | (0.39)     |   |   | 2.87  |
| IFS                              |     | 0.27  |     |   | 0.23  |   |   | 0.14  |
| Ida-West                         |     | (0.13)     |     |   | (0.14)     |   |   | 0.13  |
| IdaTech                          |     | (0.04)     |     |   | (0.22)     |   |   | (0.22) |
| Other                            |     | (0.07)     |     |   | (0.09)     |   |   | (0.17) |
| Total EPS                        | $        | 1.22  |     | $      | 1.63  |   | $ | 3.35  |
|                             |
| Return on year end common equity |     | 5.4%       |     |   | 7.1%       |   |   | 14.4% |

 

**Utility Operations**This section discusses IPC's utility operations, which are subject toregulation by, among others, the state public utility commissions of Idaho andOregon and by the FERC.

The decrease in EPS from utility operations in 2003 wasprimarily the result of the following factors:

EPSdecreased $0.82 due to a change to the utility's tax accounting method forcapitalized overhead costs.  This changewas adopted in 2002, and increased income $35 million that year and $4 millionin 2003. 

EPSdecreased $0.21 per share in 2003 because operating and maintenance expensesincreased $14 million in 2003, due mainly to a $5 million increase in pensionexpenses, a $4 million increase in thermal plant maintenance costs and a $3million increase in transmission line maintenance.

EPSincreased  $0.18 per share in 2003because in 2002 IPC wrote off  $12million of regulatory assets related to the 2001 Irrigation Load ReductionProgram.  The IPUC denied recovery ofthis amount in 2002.

 

The increase in EPS from utility operations in 2002was primarily the result of the following factors:

EPSincreased $0.92 due to a change adopted in 2002 to the utility's tax accountingmethod for capitalized overhead costs. This change increased net income $35 million in 2002.  Of that amount, $31 million relates to theeffect of adoption of the tax method on prior tax years.

EPSincreased $0.82 because net power supply costs (fuel and purchased power lesssales for resale) absorbed by the utility decreased $51 million.

 

**Generation:**IPCrelies on its hydroelectric plants for a significant portion of its powersupply.  The availability ofhydroelectric generation can significantly affect the amount of net powersupply costs (fuel and purchased power less sales for resale) that IPC incurs.  Most, but not all, of the power supply costsare recovered through the rates charged to customers.  Generally, lower hydroelectric generation increases power supplycosts, thereby increasing the amount of these costs that IPC absorbs.

In 2003, IPC experienced its fourth consecutive year ofbelow normal hydroelectric generating conditions, which increased reliance onhigher-cost thermal generation and purchased power. Unplanned outages atthermal plants further increased the need to purchase power.  The following table presents IPC's systemgeneration for the last three years:
|                                                                                                                          | **MWh**           | **% of  total generation** |
|-------------------------------------------------------------------------------------------------------------------------------|-------------------|----------------------------|
|                                                                                                                          |              |                       | **Total** |   |   | **Total** |
|                                                                                                                          |              |                       | **system** |   |   | **system** |
|                                                                                                                          | **Hydroelectric** | **Thermal**                | **generation** | **Hydroelectric** | **Thermal** | **generation** |
| 2003                                                                                                                          | 6,149             | 6,914                      | 13,063 | 47% | 53% | 100% |
| 2002                                                                                                                          | 6,069             | 7,286                      | 13,355 | 45% | 55% | 100% |
| 2001                                                                                                                          | 5,638             | 7,622                      | 13,260 | 43% | 57% | 100% |
| Normal(a)                                                                                                                     | 9,251             | 7,358                      | 16,609 | 56% | 44% | 100% |
|                                                                                                                          |              |                       |   |   |   |   |
| (a)Normal hydroelectric  generation represents the annual average based on median conditions, using  1928 - 2002 streamflows, |
| adjusted to the 1992 level of depletion.  Normal thermal represents average  generations for the past five years.        |

 

Current Snake River basin snowpack numbers suggest thatstreamflow conditions for 2004 will remain below normal.  IPC's February 17, 2004 snowpackaccumulations were 99 percent of normal, compared to 79 percent at the sametime a year earlier.  As of February 17,2004, storage for selected reservoirs upstream of Brownlee was 63 percent ofnormal, compared to 68 percent of normal a year earlier.

The U.S. National Weather Service's Northwest RiverForecast Center is predicting April-through-July 2004 inflow into BrownleeReservoir will be 4.3 million acre-feet (maf). The normal 30-year average for inflow during that time is 6.3 maf.  Based on the above snowpack, reservoirstorage and forecasted inflows, IPC is expecting its fifth year of below normalwater conditions.  IPC currently plansto use wholesale purchases from the energy markets when necessary to meet itsenergy needs during 2004, which, as noted above, will result in increasedexpenses.

**General Business Revenue:**  Thefollowing table presents IPC's general business revenues and MWh sales for thelast three years:
|        | **Revenue** |    | **MWh**  |
|-------------|-------------|---------|----------|
|        | **2003**    |    | **2002** |   | **2001** |   | **2003** |   | **2002** |   | **2001** |
| Residential | $           | 275,920 |     | $ | 305,827 |   | $ | 260,251 |   | 4,427 |   | 4,387 |   | 4,307 |
| Commercial  |        | 173,820 |     |   | 196,454 |   |   | 164,019 |   | 3,511 |   | 3,460 |   | 3,380 |
| Industrial  |        | 128,620 |     |   | 176,648 |   |   | 154,318 |   | 3,206 |   | 3,226 |   | 3,925 |
| Irrigation  |        | 92,609  |     |   | 93,106 |   |   | 72,020 |   | 1,836 |   | 1,821 |   | 1,419 |
|        | Total       | $       | 670,969  |   | $ | 772,035 |   | $ | 650,608 |   | 12,980 |   | 12,894 |   | 13,031 |
|        |        |    |     |   |   |   |   |   |   |   |   |   |   |   |
|             |             |         |          |  |  |  |  |  |  |  |  |  |  |  |  |

 

The following factorsinfluenced the change in general business revenue:

2003 vs. 2002:

Decreasedaverage rates, resulting from the PCA, reduced revenue $79 million. The PCA isdiscussed in more detail below in "REGULATORY ISSUES - Deferred PowerSupply Costs;"

A$28 million decrease in revenues due to the expiration in March 2003 of atake-or-pay contract with FMC/Astaris. FMC/Astaris, formerly IPC's largest volume customer, closed its plantslate in 2001 but was required under the contract to pay IPC for generationcapacity regardless of delivery;

A2.7 percent increase in general business customers increased revenue $16million; and

Milderweather and other usage factors reduced revenues by approximately $10 million.

 

2002 vs. 2001:

Rateincreases due to the annual PCA increased revenues approximately $94million.  The PCA is discussed in moredetail below in "REGULATORY ISSUES - Deferred Power Supply Costs;"

Customergrowth in IPC's service territory increased approximately 2.5 percent,resulting in a $13 million increase in revenues;

In2001 many irrigation customers participated in a program to decrease theirusage.  This program was not in effectduring 2002, resulting in increased sales to irrigation customers of $19million; and

FMC/Astaris,previously IPC's largest volume customer, closed its Pocatello, Idahomanufacturing plant late in 2001. However, based on a take-or-pay contract with FMC/Astaris that requirespayment for power regardless of delivery, IPC continued to receive paymentsfrom FMC/Astaris through March 2003. Because of this, revenues from FMC/Astaris changed minimally, despitethe significant decrease in MWh sold.

 

**Off-system sales:**  Off-system sales consist primarily of long-term sales contractsand opportunity sales of surplus system energy.
|            | **2003** |   | **2002** |   | **2001** |
|-----------------|----------|--------|----------|--------|----------|
|            |     |   |     |   |     |   |   |   |
| Revenue         | $        | 71,573 |     | $      | 55,031   |   | $ | 219,966 |
| MWh sold        |     | 1,830  |     |   | 2,069    |   |   | 2,387 |
| Revenue per MWh | $        | 39.11  |     | $      | 26.60    |   | $ | 92.14 |
|            |     |   |     |   |     |   |   |   |

 

2003 vs. 2002:  Revenuesfrom off-system sales increased due principally to higher average prices in thewholesale electricity markets.

2002 vs. 2001:  In 2002,revenues from off-system sales decreased due to a 13 percent decrease involumes sold and a 71 percent decrease in wholesale electricity prices,reflecting the return to a more normal wholesale energy market from whatexisted in 2001.

**Purchased power:**
|                   | **2003**             |   | **2002** |   | **2001** |
|------------------------|----------------------|--------|----------|--------|----------|
| Purchased power:       |                 |   |     |   |     |   |   |   |
|                   | Purchases            | $      | 147,850  |   | $        | 91,312 |   | $ | 430,451 |
|                   | Load reduction costs |   | 3,130    |   |     | 50,790 |   |   | 153,758 |
|                   |                 |   |     |   |     |   |   |   |
| MWh purchased          |                 | 3,383  |     |   | 2,918    |   |   | 3,457 |
| Cost per MWh purchased | $                    | 43.70  |     | $      | 31.29    |   | $ | 124.53 |
|                   |                 |   |     |   |     |   |   |   |

 

2003 vs. 2002:  Volumespurchased increased due principally to two factors: unplanned outages at IPC'sthermal plants and increased sales to general business customers.  Load reduction costs decreased $48 million dueto the expiration in March 2003 of the FMC/Astaris Voluntary Load ReductionProgram, which is discussed further in "REGULATORY ISSUES - FMC/AstarisSettlement Agreement."

2002 vs. 2001:  Purchased power costs decreased primarily due to a 75 percent declinein average wholesale electricity prices, reflecting the return to a more normalwholesale energy market from what existed in 2001.  Volumes purchased declined principally because of a similardecrease in sales volumes.  Loadreduction payments decreased $103 million due to expiration of the IrrigationLoad Reduction Program and changes to the FMC/Astaris Voluntary Load ReductionAgreement. 

**Fuel expense:**  Thefollowing table presents IPC's fuel expenses and generation at its thermalgenerating plants:
|                  | **2003** |   | **2002** |   | **2001** |
|-----------------------|----------|--------|----------|--------|----------|
| Fuel expense          | $        | 99,898 |     | $      | 102,871  |   | $ | 98,318 |
| Thermal MWh generated |     | 6,914  |     |   | 7,286    |   |   | 7,622 |
| Cost per MWh          | $        | 14.45  |     | $      | 14.12    |   | $ | 12.90 |
|                  |     |   |     |   |     |   |   |   |

 

2003 vs. 2002:  Fuel expense decreased in 2003 due primarily to increasedunplanned outages.  The most significantoutage involved one of the two units of the North Valmy Steam ElectricGenerating Plant (Valmy). As the unit was being returned to service after anunplanned outage, a breakdown occurred, unrelated to the completed maintenance,forcing the unit out of service from late June to early September in 2003.  The unit has been repaired and modernizedcontrols and protection systems are in place. Additional maintenance was completed during the outage which shouldminimize the 2004 planned maintenance outage period for the unit.  IPC owns 50 percent of Valmy and is not theplant operator.  

2002 vs. 2001:  Fuel expenses increased due to a nine percent increase in averagecoal prices, partially offset by a four percent decrease in thermal generation.

**PCA:**  PCAexpense represents the effect of IPC's PCA regulatory mechanism, which isdiscussed in more detail below in "REGULATORY ISSUES - Deferred PowerSupply Costs."   In 2003, 2002, and2001, actual power supply costs (fuel and purchased power less sales forresale) exceeded those anticipated in the annual PCA forecast, resulting in thedeferral of a portion of those costs to subsequent years when they are to berecovered in rates.  As the revenues arebeing recovered, the deferred balances are amortized.

Thefollowing table presents the components of PCA expense: 
|                                                |                        | **2003** |          | **2002**     |   | **2001**      |
|-----------------------------------------------------|-----------------------------|----------|---------------|--------------|--------|---------------|
| Current year power supply cost deferral             |                        | $        | (44,320)      |         | $      | (4,178)       |   | $ | (145,801) |
| FMC/Astaris and irrigation program costs (deferral) |                        |     | (2,245)       |         |   | (39,854)      |   |   | (136,028) |
| Amortization of prior year authorized balances      |                        |     | 117,279  |         |   | 200,941  |   |   | 94,358  |
| Write-offs of disallowed costs                      |                        |     | 48       |         |   | 13,580   |   |   | 11,546  |
|                                                | Total power cost adjustment |     | $             | 70,762  |   | $             | 170,489  |   | $ | (175,925) |
|                                                |                        |     |          |         |   |          |   |   |   |
|                                                     |                             |          |               |              |        |               |  |  |  |  |

 

**Other Operations and Maintenance Expenses:**2003 vs. 2002: Other operations andmaintenance expenses increased $14 million due principally to thefollowing:

Qualified pension plan expensesincreased $5 million;

Maintenance of thermal plantsrose $4 million due to increased unplanned outages, primarily at the Valmyplant; and

Transmissionmaintenance increased $3 million, predominantly from increased tree-trimmingand pole maintenance costs of $1 million, and because of insurance proceedsreceived in 2002 related to a 2001 outage of $1 million.

 

2002 vs. 2001:  Other operation and maintenance expensesdecreased $3 million, due principally to the following:

IPCpaid $5 million in 2001 to lease portable generation equipment to protectagainst electricity supply shortages. These costs were not incurred in 2002;

Costsat thermal plants decreased $4 million due to reduced unplanned outages; and

Qualifiedpension plan income decreased $5 million.

 

**EnergyMarketing**IDACORP announced on June 21, 2002 that IE would wind down its powermarketing operations due to changing liquidity requirements brought on byrating agencies, continued uncertainty in the regulatory and politicalenvironment and reduction of creditworthy counterparties.  On November 5, 2002, IDACORP announced thatit was terminating further evaluation of growth opportunities in the mid-streamnatural gas markets, and stated that IE would close its Denver office byyear-end 2002, would shut down its natural gas trading operation in Houston byMarch 2003 and would further reduce its workforce in its Boise operationsthrough mid-2003.  Since theseannouncements in 2002, IE has completed the major milestones outlined in thewind down of the business.  Thesemilestones include the sale of IE's forward book of electricity tradingcontracts to Sempra Energy Trading (SET) in August 2003, closing of the Denver,Houston and Boise operations and the final workforce termination in November2003.

The sale of IE's forward bookof electricity trading contracts to SET was approved by the FERC on September26, 2003.  To date, all but one of IE'scounterparties have consented to the assignment of its contracts to SET.  For that counterparty, IE still retains thecredit risk.  SET entered intotransactions with IE that mirror the transactions of the counterparty that hasnot consented to the assignment.  SETalso agreed to service these remaining contracts for IE.  The result of this agreement with SET isthat IE was able to close down its day-to-day operations in November 2003.

As part of the sale of theforward book of electricity trading contracts, IE entered into an IndemnityAgreement with SET, guaranteeing the performance of one of thecounterparties.  The maximum amountpayable by IE under the Indemnity Agreement is $20 million.  The Indemnity Agreement has been accountedfor in accordance with FASB Interpretation (FIN) 45, "Guarantor'sAccounting and Disclosure Requirements for Guarantees, Including IndirectGuarantees of Indebtedness of Others" and did not have a significanteffect on the financial statements. 

In 2002, IE incurred $5 million of involuntarytermination benefit expenses and approximately $4 million of lease terminationcosts and other exit-related costs.  Asof December 31, 2002, IE paid $2 million of these costs with a remainingoutstanding accrual of $7 million.  In2003, IE incurred an additional $4 million of involuntary termination benefitexpenses and $1 million of lease termination costs and other exit relatedcosts.  During 2003, IE paid $8 millionof these costs with a remaining outstanding accrual of approximately $5million.  The remaining terminationbenefit accrual will be paid out in 2004 and the remaining lease terminationaccrual will be paid out through 2008. Termination benefit expenses relate to the termination of 98 employees(primarily energy traders and administrative support positions).  Of the 98 employees laid off, 19 were hiredby other IDACORP subsidiaries, and thus received no severance benefits.  Restructuring expenses are presented asSelling, general and administrative expenses on the Consolidated Statements ofIncome and restructuring accruals are presented as Other Liabilities on theConsolidated Balance Sheets.

In connection with the winddown of energy marketing, certain matters were identified that required resolutionwith the FERC and the IPUC.  The FERCmatters have been resolved by the issuance of two FERC orders and the partiesto the IPUC proceeding have executed a settlement agreement.  This agreement was filed with the IPUC onFebruary 17, 2004 and is subject to its approval.  These matters are discussed in more detail in Note 13 toIDACORP's Consolidated Financial Statements.

IE reported an $18 millionoperating loss in 2003 compared to a $26 million of operating loss in 2002. IErealized a $17 million gain from the sale of its forward book of electricitytrading contracts in August 2003.  Thisgain was offset by a loss on legal disputes of $12 million, legal expenses of$6 million, acceleration of depreciation expense of $6 million, restructuringexpenses of $5 million and general and administrative costs of $6 million.

On December 29, 2003, IEreceived a $45 million cash payment from Overton Power District No. 5 for finalsettlement.  Overton had a $46.1 millionlong-term receivable with IE, and this payment resulted in a $1.1 millionexpense to IE in December 2003.  Inaddition, IE recorded a write-down of $21.5 million related to this receivablein the second quarter of 2003.  Thesewrite-downs are presented as a Net loss on legal disputes on the ConsolidatedStatement of Income.

The following tablepresents IE's energy marketing revenues and volumes for the last three years:
|                          |              |     |           |     | **2002-2003**  |   |         | **2001-2002** |
|-------------------------------|-------------------|----------|----------------|----------|----------------|--------|--------------|---------------|
|                          |              |     |           |     | **Increase**   |   |         | **Increase**  |
|                          | **2003**          | **2002** | **(Decrease)** | **2001** | **(Decrease)** |
| Net operating revenues:       |              |     |           |     |           |   |         |          |   |   |
|                          | Electricity       | $        | 19,267         | $        | 42,304         | $      | (23,037)     | $             | 330,793 | $ | (288,489) |
|                          | Gas               |     | 649            |     | 4,106          |   | (3,457)      |          | 17,870 |   | (13,764) |
|                          |              | Total    | $              | 19,916   | $              | 46,410 | $            | (26,494)      | $ | 348,663 | $ | (302,253) |
|                          |              |     |           |     |           |   |         |          |   |   |
| Operating  volumes (settled): |              |     |           |     |           |   |         |          |   |   |
|                          | Electricity (MWh) |     | 13,045,863     |     | 39,526,630     |   | (26,480,767) |          | 34,936,951 |   | 4,589,679  |
|                          | Gas (MMbtu)       |     | 2,255,881      |     | 35,895,039     |   | (33,639,158) |          | 97,327,432 |   | (61,432,393) |
|                          |              |     |           |     |           |   |         |          |   |   |   |
|                               |                   |          |                |          |                |        |              |               |  |  |  |  |

 

The decline in revenues andvolumes between 2002 and 2003 was a result of the decision to wind down IE'spower and gas marketing operations and the sale of its forward book ofelectricity trading contracts to SET in August 2003.  The decision to wind down IE also affected the decline inrevenues and volumes between 2001 and 2002, along with a sharp decline inregional prices, volatility and the decreasing number of creditworthycounterparties in 2002.

**Selling, General andAdministrative Expenses: **Totalselling, general and administrative (SG&A) expenses decreased $6 million in2003 as a result of the wind down of operations.  SG&A expenses decreased $36 million in 2002 due primarily todecreased allowance for bad debt and compensation expense compared to2001.  Allowance for bad debt expensedecreased in 2002 due to unusually high bad debt expense in 2001 associated withreserves related to trading activities conducted with California entities in2000.  Compensation expense declined dueto a reduction in profit-related incentives and a reduction in workforcerelated to the wind down of operations.

**Ida-West**In 2003, IDACORP made the decision to wind down Ida-West'soperations.  This decision resulted fromthe development of IDACORP's new corporate strategy.  The new strategy does not include the development or acquisitionof merchant generation, which had been Ida-West's focus.  IDACORP will either sell Ida-West or retainits remaining properties and manage them with a smaller staff.

Impairmentcharges, as discussed below, negatively affected Ida-West's earnings in both2003 and 2002.  In 2001, Ida-Westreported a $5 million gain on the early redemption by the Friant PowerAuthority of bonds held by Ida-West.

**Garnetimpairment**:  In 2001, Garnet, a wholly owned subsidiary of Ida-West, enteredinto a PPA with IPC to provide energy to be produced by Garnet's proposed naturalgas-fired plant.  Due to dramaticchanges in the electricity industry, financing of the project on acceptableterms under the PPA became impracticable. In 2002, Ida-West wrote down $8.6 million of its investment in equipmentrelated to Garnet.  At that time, thesite remained viable for future generation development.  In 2003, the original PPA was mutuallyterminated.  Also in 2003, IPC issued aformal RFP seeking bids for the construction of up to 200-MW of additionalgeneration.  The RFP specifically prohibitedaffiliates of IPC, including Ida-West, from bidding.  While one bid proposed acquisition and use of the Garnet site, adifferent bid was selected.  Based onthe termination of the PPA, the results of the RFP process and the decision towind down operations, Ida-West determined that its remaining $3.6 millioninvestment in the Garnet site development costs was uncertain of recovery andan impairment charge for the entire amount was recorded.  Each of these impairments is presented onthe Consolidated Statement of Income as Other Operating expenses.

**Jointventures:** Based on management's newcorporate strategy, Ida-West's investments in four joint ventures wereevaluated for impairment. As a result, a total of $2.4 million in impairmentcharges were recorded in the fourth quarter of 2003 to partially impair two ofthe joint ventures.  This impairment ispresented on the Consolidated Statement of Income as Other expenses. 

In addition, a $2.6 millionbad debt reserve was established on a note receivable from a partner in one ofthe joint ventures.  This reserve ispresented on the Consolidated Statement of Income as Other Operating expenses.

**Income TaxesAudit Settlements:**  In 2003, IDACORP settled substantially allissues related to the Internal Revenue Service's examination of its federalincome tax returns for the years 1998 through 2000.  The settlement resulted in a benefit of $9 million, as thedeficiencies assessed were less than previously accrued. Management believesthat adequate provision for income taxes has been made for the open years 2001and after and for any unsettled issues prior to 2001.  Of this settlement benefit amount, $6 million was recorded in thefourth quarter.

In 2002, IPC settled incometax deficiencies related to its partnership investment in the Bridger CoalCompany, 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.

**Tax Accounting Method Change:** In 2002, IDACORP filed its 2001 federal income taxreturn and adopted a change to IPC's tax accounting method for capitalizedoverhead costs.  The former methodallocated such costs primarily to construction of plant, while the new methodallocates such costs to both construction of plant and the production ofelectricity.

Thetax accounting method change decreased 2002 income tax expense by $35 million,of which $31 million was attributable to 2001 and prior tax years, and $4million was attributable to the 2002 tax year. The decrease to tax expense was a result of deductions on the applicabletax returns of costs that were capitalized into fixed assets for financialreporting purposes.  Deferred income taxexpense was not provided because the prescribed regulatory accounting methoddoes not allow for inclusion of such deferred tax expense in currentrates.  Regulated enterprises arerequired to recognize such adjustments as regulatory assets if it is probablethat such amounts will be recovered from customers in future rates.

**TaxCredits:**  IFS generates federal income tax credits and accelerated taxdepreciation benefits related to its investments in affordable housing andhistoric rehabilitation developments. Net reductions in consolidated income taxes related to IFS tax creditswere $20 million, $21 million and $13 million for the years 2003, 2002 and2001, respectively.

**LIQUIDITYAND CAPITAL RESOURCES:**

**Operating Cash Flows**IDACORP's andIPC's operating cash flows in 2003 were $311 million and $185 million,respectively.****

IPC's operating cash flowshave decreased $182 million from 2002's level, which had been bolstered by taxrefunds and the collection from electricity customers of power supplyexpenditures that had been incurred during prior years.  Net income tax-related cash inflows of $18million in 2002 changed to outflows of $100 million in 2003 and cash receivedfrom electric customers was approximately $65 million less in 2003 than in2002.  The tax refundsreceived in 2002 totaled approximately $90 million and related to the change intax accounting method for capitalized overhead costs and net operating losscarrybacks associated with IPC's 2001 power supply costs.

IDACORP's consolidated cashflows from operations decreased $37 million in 2003, resulting from the IPCitems mentioned above, offset by cash generated during the winddown of the energy marketing.  Netoperating cash flows from IE were $92 million in 2003, an improvement of $122million over 2002, with the largest contributions being $40 million from thesale of the book of forward energy trading contracts and $45 million collectedon notes receivable from Overton Power District No. 5.  IE's future cash flows are expected to be limited.  Its only significant remaining asset is $48million in receivables, including $44 million from California entities, thecollection of which is uncertain and for which reserves of $42 million havebeen established.  The resolution of theother legal and regulatory matters discussed later in MD&A could alsoimpact IE's future cash flows.

**Working Capital**The wind down of energy marketing has beenthe primary influence on changes in IDACORP's working capital items during theyear.

Energy marketing assets andliabilities reflect the fair value of energy marketing contracts as of thereporting date.  The fair value of thesecontracts is unrealized and therefore does not necessarily indicate a currentsource or use of funds.  Thedecreases in the net energy marketing assets and liabilities from 2002 to 2003are a reflection of the wind down of the energy marketing business and sale ofIE's book of forward electricity trading contracts.

Pension expense (income) totaled $12 million, $4 millionand ($4 million) for the three years ended December 31, 2003, 2002 and 2001,respectively, including amounts allocated to capitalized labor costs.  For 2004, pension expense is expected tototal approximately $10 million, which takes into account a reduction of the discountrate from the 6.75 percent used in 2003 to 6.15 percent and returns on planassets in 2003 that exceeded actuarial estimates.  No changes were made to the other key assumptions used in theactuarial calculation. 

**Insurance Expenses**IPC's medical expenses for current and retired employees increasedapproximately $3 million from 2002 to 2003. This increase reflects the overall trends in health care costs andresulting health insurance premiums.  Inaddition, IPC's property and liability insurance expense increasedapproximately $2 million from 2002 to 2003, reflecting higher premiums toinsure power plants and other utility property.  IPC forecasts that its 2004 insurance costs will continue toincrease, but more moderately than in 2003.

**Dividend Reduction**In September 2003, IDACORP's annual dividend was reduced to $1.20 pershare from $1.86 per share.  This actionwas taken in order to strengthen IDACORP's financial position, and its abilityto fund IPC's growing capital expenditure needs.  IPC's capital expenditures from 2004 to 2006 are expected tototal $643 million, significantly more than the $433 million expended in 2001through 2003.  IPC's constructionprogram is discussed in more detail later in "Capital Requirements."  The dividend reduction was also made tostrengthen financial position, improve cash flows and help maintain creditratings.

**Contractual Obligations**The following table presents IDACORP's andIPC's contractual cash obligations for the respective periods in which they aredue:
|                                                                                                                                                      | **Payment Due by Period**                                                                                                                                   |
|-----------------------------------------------------------------------------------------------------------------------------------------------------------|-------------------------------------------------------------------------------------------------------------------------------------------------------------|
|                                                                                                                                                      | Total                                                                                                                                                       | **2004** | **2005-2006** | **2007-2008** | **Thereafter** |
| Long-term debt - IPC (a)                                                                                                                                  | $930,945                                                                                                                                                    | $50,077 | $60,161 | $82,344 | $738,363 |
| Long-term debt -  Other (a)                                                                                                                               | 82,715                                                                                                                                                      | 17,846 | 32,708 | 23,936 | 8,225 |
| Capital lease  obligations - Other (f)                                                                                                                    | 97                                                                                                                                                          | - | 97 | - | - |
| Operating leases -  IPC                                                                                                                                   | 4,316                                                                                                                                                       | 1,465 | 2,692 | 86 | 73 |
| Operating leases -  Other (f)                                                                                                                             | 1,776                                                                                                                                                       | 616 | 987 | 173 | - |
| Purchase obligations  - IPC:                                                                                                                              |                                                                                                                                                        |   |   |   |   |
|                                                                                                                                                      | Cogeneration and  small power production                                                                                                                    | 634,910 | 39,360 | 78,551 | 78,391 | 438,608 |
|                                                                                                                                                      | Fuel swap                                                                                                                                                   | 2,053 | 1,657 | 396 | - | - |
|                                                                                                                                                      | Fuel supply  agreements                                                                                                                                     | 128,134 | 34,810 | 56,294 | 19,807 | 17,223 |
|                                                                                                                                                      | Purchased power &  transmission                                                                                                                         | 39,705 | 15,958 | 9,978 | 9,160 | 4,609 |
|                                                                                                                                                      | Maintenance &  service agreements (b)                                                                                                                   | 48,960 | 20,745 | 12,314 | 5,823 | 10,078 |
|                                                                                                                                                      | Other (c)                                                                                                                                                   | 110,168 | 48,663 | 21,717 | 10,478 | 29,310 |
|                                                                                                                                                      |                                                                                                                                                        | Total IPC purchase  obligations | 963,930 | 161,193 | 179,250 | 123,659 | 499,828 |
| Purchase obligations  - Other (f)                                                                                                                         | 1,584                                                                                                                                                       | 1,235 | 304 | 30 | 15 |
| Restructuring charges  - Other (d)                                                                                                                        | 4,595                                                                                                                                                       | 2,746 | 1,137 | 712 | - |
| Other long-term  liabilities - IPC (e)                                                                                                                    | 2,327                                                                                                                                                       | 658 | 549 | 320 | 800 |
| Total IDACORP                                                                                                                                             | $1,992,285                                                                                                                                                  | $235,836 | $277,885 | $231,260 | $1,247,304 |
| Total IPC                                                                                                                                                 | $1,901,518                                                                                                                                                  | $213,393 | $242,652 | $206,409 | $1,239,064 |
|                                                                                                                                                      |                                                                                                                                                        |   |   |   |   |   |
| (a)  For additional information, please see  Note 5 to IDACORP's Consolidated Financial Statements.                                                  |
| (b)  Approximately $27 million of the  obligations included in the detail of the IPC maintenance and service  agreements can be cancelled without    |
|                                                                                                                                                      | penalty.  Additionally, approximately $21 million of  the contracts do not specify terms related to expiration.  As these contracts will continue |
|                                                                                                                                                      | indefinitely, 10 years of  information, estimated based on the current contract terms, has been included  in the table for presentation purposes.           |
| (c)  Approximately $37 million of the contracts  for the obligations included in the detail of IPC other purchase obligations  do not specify terms  |
|                                                                                                                                                      | related to expiration.  As these contracts will continue  indefinitely, 10 years of information, estimated based on the current  contract terms,       |
|                                                                                                                                                      | has been included in the  table for presentation purposes.                                                                                                  |
| (d)  Restructuring charges relate to the wind  down of IE.  For additional  information, please see Note 15 to IDACORP's Consolidated Financial |
|                                                                                                                                                      | Statements.                                                                                                                                                 |
| (e)  Other Long-term liabilities reflected on  the balance sheet under GAAP include Credit Facilities, Human Resources  Information                  |
|                                                                                                                                                      | System (HRIS) license fee  and lobbying agreements.  The HRIS  obligation of approximately $2 million can be cancelled without penalty.           |
|                                                                                                                                                      | Additionally, as the  contract does not specify terms related to the contract expiration, 10 years  of information, estimated based on current              |
|                                                                                                                                                      | contract terms, has been  included in the table for presentation purposes.                                                                                  |
| (f)  Includes the obligation of the  subsidiaries of IDACORP with the exception of IPC, which is shown separately.                                   |
|                                                                                                                                                           |                                                                                                                                                             |  |  |  |  |  |  |  |

 

**Off-Balance Sheet Arrangements**IPC has guaranteed the performance of reclamation activities of itsBridger Coal Company joint venture. This guarantee, which is renewed each December, was $60 million atDecember 31, 2003.  Bridger Coal has areclamation trust fund set aside specifically for the purpose of paying thesereclamation costs and expects that the fund will be sufficient to cover allsuch costs.  Because of the existence ofthe fund, the estimated fair value as well as the impact on the consolidatedfinancial statements of this guarantee was minimal.

In August 2003, IE sold its forward book of electricitytrading contracts to SET.  As part ofthe sale of the forward book of electricity contracts IE entered into anIndemnity Agreement with SET, guaranteeing the performance of one of thecounterparties.  The maximum amount payableby IE under the Indemnity Agreement is $20 million.  The impact of this guarantee on the consolidated financialstatements was minimal.

**Credit Ratings**On October 3, 2003, S&P changed its rating outlook for IDACORPand IPC to stable from positive.  S&Pstated that the stable rating outlook reflected the belief that overallfinancial ratios will only meet expectations for an A-rating over the next twoto three years.  S&P also changedthe IDACORP business risk profile to a 4 from a 5 on a 10-point scale, where a1 is the least risky.  IPC's businessrisk profile remains a 4.

Accessto capital markets at a reasonable cost is determined in large part by creditquality.  The following outlines thecurrent S&P, Moody's and Fitch ratings of IDACORP's and 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                  | None    | Baa 2    | None | BBB+ | None |
| Trust Preferred Stock   | None                 | None    | None     | Baa 2 | None | BBB |
| Commercial Paper        | A-2                  | A-2     | P-1      | P-2 | F-1 | F-2 |
| Rating Outlook          | Stable               | Stable  | 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.

**Capital Requirements**The following table presents IDACORP'sand IPC's expected capital requirements from 2004 through 2006:
|                              | **2004**                                    |                               | **2005-2006**                                    |
|-----------------------------------|---------------------------------------------|------------------------------------|--------------------------------------------------|
|                              | **(millions  of dollars)**                  |
| IPC Utility capital expenditures: |                                        |                               |                                             |   |   |
|                              | Construction Expenditures (excluding AFDC): |                               |                                             |   |   |   |
|                              |                                        | Generating facilities:             |                                             |   |   |   |   |
|                              |                                        |                               | Hydro                                            | $ | 21 |   | $ | 88 |
|                              |                                        |                               | Thermal                                          |   | 66 |   |   | 72 |
|                              |                                        |                               |                                             | Total generating facilities |   | 87 |   |   | 160 |
|                              |                                        | Transmission lines and substations |                                             | 34 |   |   | 95 |
|                              |                                        | Distribution lines and substations |                                             | 56 |   |   | 130 |
|                              |                                        | General                            |                                             | 30 |   |   | 51 |
|                              |                                        |                               | Total construction expenditures (excluding AFDC) |   | 207 |   |   | 436 |
|                              | Long-term debt maturities                   |                               | 50                                               |   |   | 60 |
|                              | Other                                       |                               | 6                                                |   |   | 9 |
|                              |                                        | Total IPC Utility                  |                                             | 263 |   |   | 505 |
|                              |                                        |                               |                                             |   |   |
| IFS capital expenditures          |                                        | 20                                 |                                             |   | 51 |
| IFS long-term debt maturities     |                                        | 18                                 |                                             |   | 38 |
| Other                             |                                        | 7                                  |                                             |   | 12 |
|                              | Total IDACORP                               | $                                  | 308                                              |   | $ | 606 |
|                                   |                                             |                                    |                                                  |  |  |  |  |  |  |

 

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

IDACORP forecasts indicate thatinternal cash generation after dividends is expected to provide less than thefull amount of total capital requirements for 2004 through 2006.  The contribution for internal cashgeneration is dependent primarily upon IPC's cash flows from operations, whichare subject to risks and uncertainties relating to weather and water conditionsand IPC's ability to obtain rate relief to cover its operating costs. IDACORPand IPC expect to continue financing the utility construction program and othercapital requirements with internally generated funds and externally financedcapital.

**Utility Construction Program**:Construction expenditures were $148 million in 2003, $128 million in 2002 and$157 million in 2001.  However, agingfacilities, relicensing costs and projected load growth are expected toincrease construction expenditures over the next three years. IPC's coal-firedplants are approaching their fourth decade of service and plant utilization hasincreased due to both load growth and reduced hydroelectric generationresulting from below normal water conditions. These factors result in increased upgrade and replacement requirementsand plant additions such as the Bennett Mountain Power Plant (BMPP), which iscurrently estimated to cost $61 million. BMPP is discussed in more detail later in the MD&A in"Regulatory Issues". 

IPC's aging hydroelectricfacilities require continuing upgrade and component replacement.  In addition, costs related to relicensinghydroelectric facilities are expected to increase substantially.  The three-year construction programanticipates $41 million of upgrades to existing hydroelectric facilities and$56 million of costs associated with relicensing of hydroelectric facilities.

Continuing load growth alsorequires that IPC add to its transmission and distribution facilities system toprovide new service and to maintain reliability.  Planned expenditures include distribution lines for new customersand several high-voltage transmission lines.

IPC has no nuclear involvementand its future construction plans do not include development of any nucleargeneration.

Based upon presentenvironmental laws and regulations, IPC estimates its 2004 capital expendituresfor environmental matters, excluding Allowance for Funds Used DuringConstruction (AFDC), will total $21 million. Studies and measures related to environmental concerns at IPC'shydroelectric facilities account for $18 million and investments inenvironmental equipment and facilities at the thermal plants account for $3million.  From 2005 through 2006,environmental-related capital expenditures, excluding AFDC, are estimated to be$47 million.  Anticipated expensesrelated to IPC's hydroelectric facilities account for $36 million and thermalplant expenses are expected to total $11 million.

**Other Capital Requirements**: Mostof IDACORP's non-regulated capital expenditures relate to IFS's investment inaffordable housing developments that help lower IDACORP's tax liability.

**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, 2003.

**Credit facilities:**  IDACORPhas a $175 million facility that expires on March 17, 2004 and a $140 millionfacility that expires on March 25, 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.

IPC has a $200 millionfacility that expires March 17, 2004. 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 amount supportedby the bank credit facilities.  AtDecember 31, 2003, IPC had regulatory authority to incur up to $250 million of short-termindebtedness.

IDACORP and IPC plan to renewtheir credit facilities that expire in March 2004.  IDACORP plans to replace its current $175 million 364-dayfacility, and its $140 million 3-year facility, with a reduced $150 million3-year facility resulting from lower liquidity requirements at IDACORP.  IPC plans to replace its current $200million 364-day facility with a similar sized $200 million 3-year facility.

**Short-term financings:**  AtDecember 31, 2003, IPC had no short-term borrowings compared to $11 million atDecember 31, 2002.  At December 31,2003, IDACORP's short-term borrowing totaled $94 million, compared to $166million at December 31, 2002.  IDACORP'sshort-term borrowings decreased in 2003 due to lower liquidity requirements asa result of the 2002 decision to exit the power and natural gas trading andmarketing business.

**Long-term financings:**  IDACORPcurrently has two shelf registration statements totaling $800 million that canbe used for the issuance of unsecured debt (including medium-term notes) andpreferred or common stock.  At December31, 2003, none had been issued.

On October 22, 2003, Humboldt County, Nevada issued, forthe benefit of IPC, $49.8 million Pollution Control Revenue Refunding Bonds(Idaho Power Company Project) Series 2003 due December 1, 2024.  IPC borrowed the proceeds from the issuancepursuant to a Loan Agreement with Humboldt County and is responsible forpayment of principal, premium, if any, and interest on the bonds.  The bonds are secured, as to principal andinterest, by IPC first mortgage bonds and as to principal and interest whendue, by an insurance policy issued by Ambac Assurance Corporation.  The bonds were issued in an auction ratemode under which the interest rate is reset every 35 days.  The initial auction rate was set at 0.95percent. At December 31, 2003, the auction rate was 1.15 percent.  Proceeds from this issuance together withother funds provided by IPC were used to redeem the outstanding $49.8 millionPollution Control Revenue Bonds (Idaho Power Company Project) 8.3% Series 1984due 2014, on December 1, 2003, at 103%. 

On November 15, 2002, IPC issued $200 million of securedmedium-term notes in two series; $100 million First Mortgage Bonds 4.75% Seriesdue 2012 and $100 million First Mortgage Bonds 6.00% Series due 2032.  Proceeds were used to pay down IPCshort-term borrowings.

On March 14, 2003, IPC filed a $300 million shelfregistration statement that could be used for first mortgage bonds (includingmedium-term notes), unsecured debt and preferred stock.  On May 8, 2003, IPC issued $140 million ofsecured medium-term notes in two series: $70 million First Mortgage Bonds 4.25%Series due 2013 and $70 million First Mortgage Bonds 5.50% Series due 2033.Proceeds were used to pay down IPC short-term borrowings incurred from thematurity and payment of $80 million First Mortgage Bonds 6.40% Series due 2003and the early redemption of $80 million First Mortgage Bonds 7.50% Series due2023, on May 1, 2003.  At December 31,2003, $160 million remained available to be issued on this shelf registrationstatement.

The amount of first mortgagebonds issuable by IPC is limited to a maximum of $1.1 billion and by property,earnings and other provisions of the mortgage and supplemental indenturesthereto.  IPC may amend the indentureand increase this amount without consent of the holders of the first mortgagebonds.  Substantially all of theelectric utility plant is subject to the lien of the mortgage.  As of December 31, 2003, IPC could issueunder the mortgage approximately $945 million of additional first mortgagebonds based on unfunded property additions and $342 million of additional firstmortgage bonds based on retired first mortgage bonds.  At December 31, 2003, unfunded property additions, which consistof electric property, were approximately $1 billion.

In August 2001, $25 million ofFirst Mortgage Bonds 9.52% Series due 2031 were redeemed early using short-termborrowings.  Also, in March2002, $50 million First Mortgage Bonds 8.75% Series due 2027 were redeemedearly using short-term borrowings.

IPC redeemed its auction rate preferred stock in August2002 for $50 million using short-term borrowings.

IPC plans to refund its $50 million First Mortgage Bonds8.00% Series due March 15, 2004 with additional first mortgage bonds.

The following tax credit notes were issued by IFS during2003:
|                             |   | **Issue  Date**     |
|----------------------------------|--------|---------------------|
|                             |   | **March  12, 2003** |   | **July  15, 2003** |
| Series                           |   |                | 2003-1 |   |   | 2003-2 |
| Principal Amount                 |   | $                   | 25,475 |   | $ | 15,000 |
| Interest Rate                    |   |                | 5.00% |   |   | 3.98% |
| Maturity                         |   |                | 2003-2010 |   |   | 2003-2009 |
| Outstanding at December 31, 2003 |   | $                   | 20,305 |   | $ | 13,550 |
|                             |   |                |   |   |   |   |

 

Additionally, IFS borrowed $25 million from a corporatelender on July 25, 2003 at an interest rate of 3.65 percent.  This debt matures from 2003-2008.  At December 31, 2003, the amount outstandingwas $23 million.

Proceeds from the issuance of these debt instruments wereprimarily used by IFS to pay intercompany notes to IDACORP, which then usedthese proceeds to reduce short-term borrowings.  The debt for Series 2003-1 is non-recourse to both IFS andIDACORP.  The debt for the remaining twoissuances is recourse only to IFS.

**Debt Covenants**:  IDACORP and IPC are subject to several debtcovenants and restrictions.  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.  At December 31, 2003, netearnings were 5.43 times.

Additionally, the creditfacilities require IDACORP and IPC to maintain a ratio of debt to totalcapitalization (leverage ratio) of no more than 65 percent.  At December 31, 2003, IDACORP's and IPC'sleverage ratios were 55 percent and 52 percent, respectively.  IDACORP is also required to maintain aninterest coverage ratio of at least 2.75 to one.  At December 31, 2003, IDACORP was in compliance with thisrequirement.

**LEGALAND ENVIRONMENTAL ISSUES:**

**Legal and Other Proceedings****Vierstra Dairy v. Idaho Power Company: **On August 11, 2000, Mike andSusan Vierstra, dairy operators from Twin Falls, Idaho, brought suit againstIPC in Idaho State District Court, Fifth Judicial District, Twin FallsCounty.  The plaintiffs sought monetarydamages in the amount of approximately $8 million for negligence and nuisance(allegedly allowing electrical current to flow in the earth and adverselyaffect the health of plaintiffs' dairy cows) and punitive damages in the amountof approximately $40 million.

On February 10, 2004, a jury verdict in favor of theplaintiffs was entered, awarding approximately $7 million in compensatorydamages and $10 million in punitive damages. IPC intends to appeal this decision.

IPC is unable to predict theoutcome of this matter; however, based upon the information provided to date,IPC's insurance carrier has confirmed coverage.  IPC has previously expensed the full amount of its self-insuredretention.  With coverage, this matterwill not have a material adverse effect on IPC's consolidated financialposition, results of operations or cash flows.

**California Energy Proceedings at the FERC:**IE and IPC are involved in a number of FERC proceedings arising out of theCalifornia energy situation.  Theyinclude proceedings involving (1) the chargeback provisions of the CaliforniaPower Exchange (CalPX) participation agreement, which was triggered when aparticipant defaulted on a payment to the CalPX.  Upon such a default, other participants were required to paytheir allocated share of the default amount to the CalPX.  This provision was first triggered by the SouthernCalifornia Edison (SCE) default and later by the Pacific Gas & ElectricCompany (PG&E) default.  FERC hasordered the CalPX to rescind all chargeback actions related to the SCE andPG&E liabilities.  The CalPX isawaiting further orders from the FERC and bankruptcy court before distributingthe funds it collected under the chargeback mechanism; (2) efforts by the Stateof California to obtain refunds for a portion of the spot market sales pricesfrom sellers of electricity into California from October 2, 2000 through June20, 2001.  California is claiming thatthe prices were not just and reasonable and were not in compliance with theFederal Power Act (FPA).  The FERC issuedan order on refund liability on March 26, 2003 which multiple parties, includingIE, sought rehearing on.  On October 16,2003, FERC denied the requests for rehearing and required the CaliforniaIndependent System Operator (Cal ISO) to make a compliance filing regardingrefund amounts by August 2004.  AtDecember 31, 2003, with respect to the CalPX chargeback and the CaliforniaRefund proceedings discussed above, the CalPX and the Cal ISO owed $14 millionand $30 million, respectively, for energy sales made to them by IPC in Novemberand December 2000.  IE has accrued areserve of $42 million against these receivables.  This reserve was calculated taking into account the uncertaintyof collection, given the California energy situation.  Based on the reserve recorded as of December 31, 2003, IDACORPbelieves that the future collectibility of these receivables or any potentialrefunds ordered by the FERC would not have a material adverse effect on itsconsolidated financial position, results of operation or cash flows; (3) in thePacific Northwest refund proceedings it was argued that the spot market in thePacific Northwest was affected by the dysfunction in the California market,warranting refunds.  The FERC rejectedthis claim on June 25, 2003 and denied rehearing on November 11, 2003 and February9, 2004.  The FERC orders have beenappealed to the Court of Appeals for the Ninth Circuit.  The Company is unable to predict the outcomeof this matter; and (4) two cases which result from a ruling of the UnitedStates Court of Appeals for the Ninth Circuit that the FERC permit the Californiaparties in the California refund proceeding to submit materials to the FERCdemonstrating market manipulation by various sellers of electricity intoCalifornia.  On June 25, 2003, the FERCordered a large number of parties including IPC to show cause why certaintrading practices did not constitute gaming ("gaming") or anomalousmarket behavior ("partnership") in violation of the Cal ISO and CalPXTariffs.  On October 16, 2003, IPCreached agreement with the FERC Staff (Staff) on the show cause orders.  The "gaming" settlement wasapproved by the FERC on March 3, 2004.  The FERC approved the motion to dismiss the "partnership"proceeding on January 23, 2004. Although the orders establishing the scope of the show cause proceedingsare presently the subject of review petitions in the Ninth Circuit, the orderdismissing IPC from the "partnership" proceedings was not the subjectof rehearing requests.  The orderapproving the "gaming" settlement is subject to rehearing requestsfor 30 days.  The FERC also issued anorder instituting an investigation of anomalous bidding behavior and practicesin the western wholesale power markets. The Company has submitted all data and information requested by the FERCand is awaiting FERC action, and IDACORP and IPC believe that any potentialpenalties imposed by the FERC would not have a material adverse effect on theirconsolidated financial positions, results of operations or cash flows.

These matters are discussed in detail in Note 8 toIDACORP's Consolidated Financial Statements.

**Other Legal Proceedings:**  IDACORP, IPC and/or IE are involved invarious lawsuits and legal proceedings, discussed above and in detail in Note 8to IDACORP's Consolidated Financial Statements.  The companies believe they have meritorious defenses to alllawsuits and legal 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 these proceedings.  The companies believe that their reservesare adequate for these matters.

**Other Legal IssuesU.S. Commodity Futures Trading Commission Investigations Regarding TradingPractices**:  On October 2,2002, the U.S. Commodity Futures Trading Commission (CFTC) issued a subpoena toIPC requesting, among other things, all records related to all natural gas andelectricity trades by IPC involving "round trip trades," also knownas "wash trades" or "sell/buyback trades" including, butnot limited to those made outside the Western Systems Coordinating Councilregion.  The subpoena applies to both IEand IPC.  By letter from the CFTC datedOctober 7, 2002, the Division of Enforcement agreed to hold in abeyance until alater date all items requested in the subpoena with the exception of oneparagraph which related to three trades on a certain date with a specificparty.  The companies provided therequested information.

On January 14, 2003, IPCreceived a request from the CFTC, pursuant to the October 2002 subpoena, fordocuments related to "round trip" or "wash trades" andinformation supplied to energy industry publications.  The request applies to both IPC and IE.  The companies stated in their response to the CFTC that they didnot engage in any "round trip" or "wash trade" transactionsand that they believe the only information provided to energy industrypublications was actual transaction data. The companies have provided the requested information and have heardnothing further from the CFTC.

**Idaho Power Company Transmission Line Rights-of-WayAcross Fort Hall Indian Reservation:**  IPC has multiple transmission lines that cross theShoshone-Bannock Tribes' Fort Hall Indian Reservation near the city ofPocatello in southeastern Idaho.  IPChas been working since 1996 to renew five of the right-of-way permits for thetransmission lines, which have stated permit expiration dates between 1996 and2003.  IPC has filed applications withthe United States Department of the Interior, Bureau of Indian Affairs, torenew the five rights-of-way for 25 years, including payment of theindependently appraised value of the rights-of-way to the Tribes (and theTribal allottees who own portions of the rights-of-way).  The Tribes have not agreed to renew therights-of-way and have demanded a substantially greater payment of $19 million,including an up-front payment of $4 million with the remainder to be paid overthe 25 year term of the permits, or in the alternative $11 million including anup-front payment of $4 million with the remainder paid over the first threeyears of the permits. This is based on an "opportunity cost"methodology, which calculates the value of the rights-of-way as a percentage ofthe cost to IPC of relocating the transmission lines off the Reservation.  Both parties have discussed potential legalaction regarding renewal of the rights-of-way, but no such action has beentaken to date.  The probable cost ofrenewing the rights-of-way is difficult to ascertain due to the lack ofdefinitive legal guidelines for the renewals. IPC believes that the amount payable for 25-year rights-of-way shouldnot exceed $11 million, which represents the approximate present value of theoffers communicated to date by the Tribe. IPC plans to obtain IPUC approval for the recovery of any renewalpayment in its utility rates as a prerequisite to any settlement of theright-of-way renewals with the Tribe.

**Environmental IssuesThreatened and Endangered Snails:**  In December 1992, the United States Fish and Wildlife Service(USFWS) listed five species of snails that inhabit the middle Snake River asthreatened or endangered species under the Endangered Species Act (ESA).  In 1995, in preparation for the FERCrelicensing of certain of IPC's hydroelectric projects, IPC obtained a permitfrom the USFWS to study the listed snails. Since that date, IPC has been collecting field data and conductingstudies in an effort to determine the status of the listed snails and how theymay be affected by a variety of factors, including hydroelectric production,water quality and irrigation practices.

Based upon the studies initiated by IPC in 1995, in Julyand October of 2002, IPC, in cooperation with the State of Idaho, filedpetitions with the USFWS to remove the Bliss Rapids snail and Idaho springsnailfrom the federal list of threatened and endangered wildlife.  Due to the pending relicensing proceedingsat the FERC and the ESA consultation between the FERC and the USFWS on thepotential effect of project operations on ESA listed snails, IPC submitted thepetitions, and the studies upon which they were based, to the FERC forinclusion in the Mid-Snake and CJ Strike relicensing proceedings.

On December 13, 2002, because of inconsistenciesdiscovered between the field data collected by IPC since 1995, the macroinvertebrate database into which the field data were entered and the use ofthat database in the preparation of the studies used to support the pendingpetitions, IPC notified the USFWS and the FERC that it was withdrawing thepetitions.  IPC then retained anindependent scientist to review the snail studies.  This review was completed in April 2003 and IPC submitted thereport to the FERC on April 30, 2003.

Thereport identified discrepancies in the annual snail survey reports (1995-2001)that were used to support the petitions to delist the Bliss Rapids snail andIdaho springsnail.  These discrepanciesincluded: errors in summarization of field data and the entry of the data intothe macro invertebrate database; errors in compiling data for analysis;calculation or extrapolation errors; and the lack of a standard measure forexpressing snail relative abundance data. While the report concluded that annual snail surveys were unreliablebecause of these discrepancies, it also concluded that the primary orunderlying data that were used to prepare the annual survey reports appeared tobe complete and, as a consequence, could be used to correct any errors in theannual reports.

Due tothe importance of these snail data to issues pending in the relicensing ofIPC's hydroelectric projects and the pending ESA consultation between the FERCand the USFWS, IPC retained the independent scientist that conducted the reviewto analyze the primary data used to prepare the 1995-2001 snail survey reportsand to prepare new and corrected annual reports.  In October and November 2003, IPC provided the FERC and the USFWSwith revised annual reports for 1995-2001. 

Byletters dated August 5, 2003, IPC and the USFWS advised the FERC that theyinitiated efforts to reach a cooperative resolution of outstanding fish andwildlife issues associated with the relicensing of the Mid-Snake and CJ Strikeprojects, including issues relating to threatened and endangered snails andadvised the FERC that they hoped to complete these efforts within 90 days ofAugust 5, 2003.  On August 14, 2003, theFERC responded to IPC advising it would not take action on the licenses priorto the expiration of the 90-day period. In subsequent progress reports to the FERC on IPC and the USFWS efforts,IPC and the USFWS requested an additional 90days to complete theirdiscussions.  On December 3, 2003, FERCadvised IPC and the USFWS that it would take no action on the pendingapplications prior to the expiration of the 90-day period. On February 12,2004, IPC, on behalf of itself and the USFWS, presented an Offer of Settlement,including a signed Settlement Agreement and attached Appendices, to the FERCaddressing issues associated with the ESA listed threatened and endangeredsnails and the relicensing of the Mid-Snake and CJ Strike projects.  Pursuant to FERC regulations, participantsin the licensing proceeding and other interested persons have until March 3,2004 to comment on the proposed settlement. If the proposed settlement is approved by the FERC, it is expected thatthe FERC and the USFWS will complete ESA consultation on the projects and theFERC will thereafter issue new licenses for the projects. 

**Environmental RegulationCosts: **IPC anticipates $14 millionin annual operating costs for environmental facilities during 2004.  Hydroelectric facility expenses account for$9 million of this total and $5 million is related to thermal plant operatingexpenses.  From 2005 through 2006, totalenvironmental related operating costs are estimated to be $28 million.  Anticipated expenses related to thehydroelectric facilities account for $18 million and thermal plant expenses areexpected to total $10 million during this period.

**REGULATORY ISSUES:**

**General Rate Case**IPC filed an application with the IPUC on October 16, 2003 to increase itsgeneral rates an average of 17.7 percent. If approved, IPC's revenues would increase $86 million annually based onthe proposed 11.2 percent return on equity. An additional component of the filing was a request for interim raterelief of $20 million.  The IPUC turneddown IPC's request for interim rate relief in Order No. 29403 on December 22,2003 noting that the denial of interim rate relief was not an indication of theultimate merits of the case. 

In addition, IPC has proposed extensive rate designchanges including seasonal rates for most customers, increased fixed chargesfor smaller customer classes and time of day rates for industrialcustomers.  If approved, the price IPCcharges its customers from June to August would reflect IPC's seasonably highercosts of producing or purchasing power. The change would result in summer and non-summer base rates.  In connection with the seasonal pricingproposal, IPC recommended the annual PCA rate changes be implemented June 1each year instead of May 16.  If approved,this change would eliminate the need for back-to-back rate changes and the PCArecovery period would be June 1 through May 31.

On February 20, 2004, the IPUC Staff and seven otherintervenors filed their testimony with the IPUC.  The testimony covered revenue requirement and rate designissues.  The IPUC Staff's proposalof  $15 million, a three-percent overallincrease to base rates, was the lowest recommendation of any of theparties.  Copies of

the parties' increase in base rates testimony and exhibitscan be viewed at the IPUC web site.  IPChas until March 19, 2004 to prepare its rebuttal to these recommendations.

IPC's proposal requests revenue recovery for certaincosts of serving its customers, such as increased operating expenses andsubstantial demands for infrastructure improvements, increased capital costsfor the PM&E requirements of new licenses at most of its hydroelectricprojects, for the cost of new sources of power and continued expansion of itstransmission and distribution network. Because the Idaho jurisdiction does not allow assets that have not beenplaced in service to be included in the rate base, BMPP and relicensing costsincluded in Construction Work in Process (CWIP) are not included in thisfiling.  IPC is requesting an 11.2percent return on equity and an overall rate of return of 8.4 percent.  The success of this rate case is dependenton the IPUC review and approval, which could take up to seven months from thefiling date.  IPC is unable to predictwhat rate relief the IPUC will grant.

**DeferredPower Supply Costs**IPC's deferred power supply costs consist of the following atDecember 31, 2003 and 2002: 
|                                                 | **2003**                                                              |                     | **2002** |
|------------------------------------------------------|-----------------------------------------------------------------------|--------------------------|----------|
| Oregon  deferral                                     | $                                                                     | 13,620                   |     | $ | 14,172 |
| Idaho  PCA current year power supply cost deferrals: |                                                                  |                     |     |   |   |
|                                                 | Deferral  for 2003-2004 rate year                                     |                     | 44,664   |   |   | - |
|                                                 | Deferral  for 2002-2003 rate year                                     |                     | -        |   |   | 8,910 |
|                                                 | Astaris  load reduction agreement                                     |                     | -        |   |   | 27,160 |
| 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 May 2002                                |                     | -        |   |   | 74,253 |
|                                                 | Remaining  true-up authorized May 2003                                |                     | 13,646   |   |   | - |
|                                                 | Total  deferral                                                       | $                        | 71,930   |   | $ | 140,288 |
|                                                 |                                                                  |                     |     |   |   |
|                                                      |                                                                       |                          |          |  |  |  |  |

 

**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 costs (fuel and purchased power lesssales for resale) 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 withinterest.  The ending balance of thisdeferral, called a true-up, is then included in the calculation of the nextyear's PCA adjustment.

On April 15, 2003, IPC filedits 2003-2004 PCA with the IPUC, and, with a small adjustment to the filing,the rates were approved by the IPUC and became effective on May 16, 2003.  As approved, IPC's rates have been adjustedto collect $81 million above 1993 base rates, a $114 million reduction from the2002-2003 PCA.

So far in the 2003-2004 PCA rate year, actual power supply costs haveexceeded those anticipated in the forecast, due principally to greater relianceon, and higher market prices for, purchased power.  Below normal water conditions also continue to negatively impactforecasted and actual power supply costs.

On May 13, 2002, the IPUC issued Order No. 29026related to the 2002-2003 PCA rate filing. The order granted recovery of $255 million of excess power supply costs,while it denied recovery of $12 million of lost revenues resulting from theIrrigation Load Reduction Program, and $2 million of other costs IPC sought torecover.

The IPUC had previously issuedOrder No. 28992 on April 15, 2002 disallowing the lost revenue portion of theIrrigation Load Reduction Program.  IPCbelieves that this IPUC 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 this order,approximately $12 million was expensed in September 2002.  IPC still believes it should be entitled toreceive recovery of this amount and argued its position before the IdahoSupreme Court on December 5, 2003.  Ifsuccessful, IPC would 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 an application with theIPUC for an order approving inclusion in the 2002-2003 PCA of costs incurredfor the Irrigation Load Reduction Program and the FMC/Astaris Load ReductionAgreement.  These two programs wereimplemented in 2001 to reduce demand and were approved by the IPUC and theOPUC.  The costs incurred in 2001 forthese two programs were $70 million for the Irrigation Load Reduction Program and$62 million for the FMC/Astaris Load Reduction Agreement.  The IPUC subsequently issued Order No. 28992authorizing IPC to include direct costs it has accrued in the programs, subjectto later adjustments in the 2002-2003 PCA year.  As mentioned earlier, the IPUC also denied IPC's request to recoverlost revenues experienced from the Irrigation Load Reduction Program.

**Oregon: **IPC also filed applicationswith the OPUC to recover calendar year 2001 extraordinary power supply costsapplicable to the Oregon jurisdiction. In two separate 2001 orders, the OPUC approved rate increases totalingsix percent, which is the maximum annual rate of recovery allowed under Oregonstate law.  These increases arerecovering approximately $2 million annually. The Oregon deferred balance was $14 million as of December 31,2003.  During the 2003 Oregonlegislative session, the maximum annual rate of recovery was raised to tenpercent under certain circumstances. IPC expects to request the higher recovery percentage in the spring of2004.

**FMC/AstarisSettlement 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, Idahoplant, 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 $5 millionreduction flowed through the PCA mechanism as a reduction in costs to Idahoretail customers.

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/Astarispaid 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, Idaho plant and settlement of the above mentioned ESA.

**Integrated Resource Plan**Every two years, IPC is required to file with both the IPUC and OPUC an IRP, acomprehensive analysis of IPC's present and future demands for electricity andthe plan for meeting that demand.  The2002 IRP identified the need for additional resources to address potentialelectricity shortfalls within IPC's utility service territory by mid-2005.  Originally, the Garnet plant was selected asthe resource to meet future needs. However, the Garnet plant did not prove to be financially viable and the2002 IRP action plan was modified, as explained below.

On February 11, 2003, the IPUCissued 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.

The draft 2004 IRP should beavailable in the spring of 2004 and the final IRP will be published and filedwith the IPUC and the OPUC in June 2004. The IPC service territory population continues to increase and it isexpected that the 2004 IRP will identify the need for additional capacity. 

**PPL Montana Power PurchaseAgreement:**  During May 2003,IPC and PPL Montana, LLC (PPLM) entered into a firm wholesale PPA under whichIPC will purchase energy from PPLM to address increased demand during June,July and August from 2004 through 2009. With the exception of the month of August 2004, in which the quantity ofenergy to be purchased is 26 MW per hour, during each month of the PPA IPC willpurchase 83 MW per hour from PPLM at a price of $44.50 per MWh.  After deducting transmission losses, IPCwill receive approximately 80 MW per hour. The IPUC approved this PPA on July 8, 2003.

**Bennett Mountain Power Plant:**  On February 24, 2003, IPC issued a formalRFP seeking bids for the construction of up to 200-MW of additional generationto support the growing seasonal demand for electricity in IPC's servicearea.  As a result of this process, IPCselected TR2 as the successful bidderfor the construction of the BMPP, a 160-MW gas-fired generating plant nearMountain Home, Idaho.  TR2 has contracted with Siemens WestinghousePower Corporation to furnish all of the labor, equipment and materials and toperform all of the engineering and construction of the plant.  The estimated project cost, including plantconstruction and associated transmission system upgrades, is $61 million.  IPC will take ownership of the plant once itis fully tested and operational.

IPC filed an application withthe IPUC on September 26, 2003 for a Certificate of Public Convenience andNecessity for the BMPP.  On October 30,2003, the IPUC issued Order No. 29370 placing the case on ModifiedProcedure.  The IPUC approved thecertificate to BMPP through Order No. 29410 and Order No. 29422.

**Advanced Meter Reading**On February 21, 2003, the IPUC issued Order No. 29196 which directed IPC tosubmit a plan no later than March 20, 2003 to replace its existing meters withadvanced meters that are capable of both automated meter reading andtime-of-use pricing.  On April 15, 2003,the IPUC issued Order No. 29226, which modified and clarified Order No.29196.  The requirement to commenceinstallation in 2003 was removed; however, IPC was expected to implementAdvanced Meter Reading (AMR) as soon as practicable, subject to updatedanalysis showing AMR to be cost effective for customers.  As ordered by the IPUC, IPC submitted anupdated analysis on May 9, 2003.  Aworkshop with IPUC staff and other interested parties to discuss the analysis washeld on May 19, 2003.  The IPUC issuedOrder No. 29291 on July 14, 2003, providing interested parties the opportunityto submit comments regarding IPC's updated analysis.  On October 24, 2003, the IPUC issued Order No. 29362 whichdirected IPC to collaboratively develop and submit a Phase One AMRImplementation Plan to replace current residential meters with advanced metersin selected service areas.  IPC compliedwith this order on December 23, 2003 by filing a Phase One Implementation Planthat targeted the Emmett, Idaho and McCall, Idaho areas for 2004 installationand 2005 implementation.  Phase One isestimated to cost $6 million.  IPC willinclude these costs in future rate filings.

**Relicensing of HydroelectricProjects**IPC, like other utilities that operate nonfederal hydroelectric projects,obtains licenses for its hydroelectric projects from the FERC.  These licenses last for 30 to 50 yearsdepending on the size and complexity of the project.  Currently, the licenses for five hydroelectric projects haveexpired.  These projects continue tooperate under annual licenses until the FERC issues a new multi-yearlicense.  Three more of IPC'shydroelectric project licenses will expire by 2010.

IPC is actively pursuing therelicensing of these projects, a process that may continue for the next ten to15 years.  The current status of IPC'srelicensing efforts is summarized in the table below:
| Projects                                 | Current status                                                              |
|------------------------------------------|-----------------------------------------------------------------------------|
| Bliss, Upper Salmon Falls,  Lower Salmon | Annual licenses issued under terms and conditions  of the expired           |
| Falls, Shoshone Falls and CJ  Strike     | multi-year license.  Final Environmental Impact Statements have        |
|                                     | been issued.   FERC licenses anticipated in 2004.                      |
|                                     |                                                                        |
| Upper Malad and Lower Malad              | License expires in 2004.  New license application filed in July  2002. |
|                                     |                                                                        |
| Brownlee-Oxbow-Hells Canyon  (HCC)       | License expires in 2005.  New license application filed in July  2003. |
|                                     |                                                                        |

 

The most significantrelicensing effort is the HCC, which provides approximately two-thirds of IPC'shydroelectric generation capacity and 40 percent of its total generatingcapacity.  IPC developed the licenseapplication for the HCC through a collaborative process involvingrepresentatives of state and federal agencies, businesses, environmental,tribal, customer, local government and local landowner interests.  The license application for the HCC wasfiled in July 2003. The application includes existing and proposed PM&Emeasures estimated to total (assuming a 30-year license) approximately $106million in the first five years of the license and $218 million over thefollowing 25 years.  However, the actualcosts of the PM&E measures and other costs associated with the relicensingof the project will not be known until the new license is issued by the FERC.The current license for the project expires in July 2005.  IPC will thereafter operate the projectunder annual licenses issued by the FERC until the new multi-year license isissued.

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 theESA.  See previous discussion in"LEGAL AND ENVIRONMENTAL ISSUES - Environmental Issues - Threatened andEndangered Snails."

At December 31, 2003, $61million of relicensing costs were included in CWIP and $8 million ofrelicensing costs were included in Electric Plant in Service.  The relicensing costs are recorded and heldin CWIP until a new multi-year license or annual license is issued by the FERC,at which time the charges are transferred to Electric Plant in Service.  Relicensing costs and costs related to thenew licenses, as discussed above, will be submitted to regulators for recoverythrough the rate-making process.  Thecurrent Idaho general rate case filing includes $10 million of relicensingcosts. 

**American Rivers Petition:**  On May 1, 2003, American Rivers and IdahoRivers United petitioned the United States Court of Appeals for the District ofColumbia Circuit requesting that the court issue a Writ of Mandamus compellingthe FERC to respond to a petition American Rivers filed with the FERC in 1997requesting that the FERC initiate formal consultation pursuant to Section7(a)(2) of the ESA with the National Marine Fisheries Service (NMFS) on theeffects of the ongoing operations of IPC's HCC on four species of Snake Riversalmon and steelhead trout that are listed as threatened or endangered underthe ESA.  American Rivers contends thatconsultation is necessary because the operations of the HCC have a current,adverse impact on the listed anadromous fish.

IPC contested the 1997 petitionbefore the FERC on several bases: first, that there is no evidence to supportthe American Rivers contention that the operations of the HCC have an adverseimpact on ESA listed species; and second, that neither the ESA nor the FPAgrant the FERC the type of discretionary federal control that constitutes theconsultation-triggering federal action required under Section 7(a)(2) of theESA.  Since 1997, the FERC has taken noaction on the pending petition, but has been engaged in informal discussionswith IPC and the NMFS on issues associated with the effect of HCC operations onfishery resources below the HCC.  Someof these discussions have occurred in the context of the Snake River BasinAdjudication mediation, which is subject to a court imposed confidentialityorder.

On June 30, 2003, the FERCfiled a response to the Petition for Mandamus. The FERC opposed the petition, first, because there was no federalaction before the FERC to trigger a consultation responsibility under ESASection 7(a)(2); second, because there was no evidence to substantiate theallegations of the petitioners that the ESA listed species have continued todecline since the filing of the original petition with the FERC in 1997; andlastly, because there were no grounds to support the allegations ofunreasonable delay given the ongoing interaction between the FERC, IPC andother interested parties with regard to issues associated with the ESA listedspecies and the HCC.  IPC filed a briefin support of the FERC's position on July 3, 2003.  The petitioners filed a reply in support of the Petition forMandamus with the court on July 8, 2003. The court granted IPC intervention and set the matter for oral argumenton March 16, 2004.

**Regional TransmissionOrganizations**In December 1999, the FERC, in its landmark Order No. 2000, said that allcompanies with transmission assets must file to form Regional TransmissionOrganizations (RTOs) or explain why they cannot do so.  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 wouldoperate 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 filings necessary to form RTO West.  Additional filings will be necessary to include the tariff andintegration agreements associated with the new entity.  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, includingthe Bonneville Power Administration (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 mid-2003, the RTO West Regional Representatives Group(RRG) began a new phase of discussions related to the development of anindependent entity to manage the regional transmission system and improverelated wholesale markets.  Thesediscussions began with wide-ranging consideration of current transmissionproblems and opportunities within the region.

In late summer and fall 2003,task groups from the RRG focused on developing different option packages toaddress the region's transmission problems and opportunities.  As this effort proceeded, however, manyregional parties felt it would be preferable to work toward a single proposalthat could gain broad regional support. To further this goal, the RRG formed a small task team to take intoaccount all of the various perspectives, priorities and concerns that regionalparties had identified during the course of discussions since June 2003, and,working on behalf of the RRG as a whole, to develop the best proposal it couldin view of these considerations.

In April 2003, the FERC issued its "WhitePaper:  Wholesale Market Platform,"and "Appendix A:  Comparison of theProposed Wholesale Market Platform with the RTO Requirements of Order No.2000."  The Wholesale MarketPlatform (WMP) White Paper set forth the FERC's then-current thinking on issuesunder consideration in the Standard Market Design (SMD) proceeding.  It focused in particular on the elementsthat must be in place for well-functioning wholesale markets.  Appendix A provided a comparison of OrderNo. 2000's existing requirements for RTOs with the proposed requirements of theWMP that would apply to RTOs and independent system operators (ISOs).  The Commission committed to consider allcomments on the White Paper, as well as pending legislation, prior to theissuance of a Final Rule.  To date, theFERC has not issued a Final Rule in its SMD proceeding.  Among other things, the White Paper:

Setforth the FERC's assessment of how best to move forward in the electricindustry and how the FERC intended to change its proposed rulemaking on the SMDissued in 2002 based on concerns that were raised with respect to the proposedrule;

Statedthe FERC's intent to eliminate the proposed requirement that public utilitiescreate or join an Independent Transmission Provider and, instead, to requirepublic utilities to join an RTO or an ISO;

Calledfor phase-in implementation and sequencing tailored to each region allowing formodifications to benefit customers within each region;

Indicatedthat the FERC would not require implementation of a feature of the marketplatform if the costs outweighed its benefits for a particular RTO or ISO;

Calledfor the inclusion of market power mitigation measures but not divestiture ofvertically integrated utilities; and

Launchedthe commencement of technical conferences in the various regions.

The FERC's existing timetablefor finalization requires that jurisdictional utilities must file open-accesstransmission tariffs with any remaining revisions and be operating under theSMD by September 30, 2004.

**OTHER MATTERS:******

**NewAccounting Pronouncement****FIN 46**: In January 2003, the Financial Accounting Standards Board (FASB)issued Interpretation (FIN) 46, "Consolidation of Variable InterestEntities."  In December 2003, theFASB issued a revised version of FIN 46 (FIN 46R).  FIN 46R provides guidance related to identifying variableinterest entities (VIEs, previously known as special purpose entities or SPEs)and determining whether such entities should be consolidated.  Certain disclosures are required if it isreasonably possible that a company will consolidate or disclose information abouta VIE when it initially applies FIN 46R. FIN 46 was required to be applied immediately to VIEs created orobtained after January 31, 2003.  During2003, IDACORP and IPC did not participate in the creation of, or obtain a newvariable interest in, any VIE.  Forthose VIEs created or obtained on or before January 31, 2003, IDACORP and IPCmust apply the provisions of FIN 46R in the first quarter of 2004.

IDACORP and IPC are in the final stages of their analysisof FIN 46R and the majority of their investments, principally IFS' affordablehousing investments are not expected to meet the criteria for consolidationincluded in FIN 46R.  IDACORP and IPC donot expect the adoption of this standard to have a material effect on theirfinancial statements.

 

**ITEM 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURESABOUT MARKET RISK**

IDACORP and IPC are exposed tovarious market risks, including changes in interest rates, changes in commodityprices, credit risk and equity price risk. The following discussion summarizes these risks and the financialinstruments, derivative instruments and derivative commodity instrumentssensitive to changes in interest rates, commodity prices and equity prices thatwere held at December 31, 2003.

**Interest Rate Risk**IDACORP and IPC manage interest expense and short and long-termliquidity though a combination of fixed rate and variable rate debt.  Generally, the amount of each type of debtis managed through market issuance, but interest rate swap and cap agreementswith highlyrated financial institutions may be used to achieve thedesired combination. 

**Variable Rate Debt:**  As of December 31, 2003, IDACORP and IPC had$151.6 million and $118.7 million, respectively, in variable rate debt net oftemporary investments.  Assuming nochange in either company's financial structure, if variable interest rates wereto average one percentage point higher than the average rate on December 31,2003, interest rate expense would increase and pre-tax earnings would decreaseby approximately $1.5 million for IDACORP and $1.2 million for IPC.

**Fixed Rate Debt:**  As of December 31, 2003, IDACORP and IPC had outstanding fixedrate debt of $893.6 million and $810.9 million, respectively.  The fair market value of this debt was$920.8 million and $835.2 million, respectively.  These instruments are fixed rate, and therefore do not exposeIDACORP or IPC to a loss in earnings due to changes in market interestrates.  However, the fair value of theseinstruments would increase by approximately $65.9 million for IDACORP and $63.9million for IPC if interest rates were to decline by one percentage point fromtheir December 31, 2003 levels.

**Commodity Price RiskUtility:**  IPC is exposed to changes in commodity prices related to thepurchases and sales of electricity 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 a riskmanagement policy to address commodity price risk.  The Risk Management Committee (RMC), comprised of IPC officersand other senior staff, oversees the risk management program.  On a regular basis, the RMC reviews multiplesystem resource and load projections and evaluates the potential impacts ofchanges in four key variables: wholesale prices, system loads, system resourcesand streamflow conditions.  The RMC controlsthe risk by assessing the impact of changes in the variables on power supplycost and projected volumetric surplus and deficit data, and by reviewingforward price curves for electricity and gas. The RMC then orders anappropriate risk mitigating action. Actions may be undertaken only with creditworthy counterparties.

On August 1, 2002, due to thewind down of energy marketing, all utility-related wholesale energy and gastransaction processes were returned to IPC. These activities are focused on meeting system requirements andcapitalizing on system-related opportunities that can be risk managed.

**Energy Trading:**  The saleof IE's forward book of electricity trading contracts to SET and the settlementof all gas trading contracts has eliminated the energy commodity price risk.

**Credit RiskUtility:**  IPC is subject to credit risk based on its activity with marketcounterparties.  IPC is exposed to thisrisk to the extent that a counterparty may fail to fulfill a contractualobligation to provide energy, purchase energy, or complete financial settlementfor market activities.  IPC mitigatesthis exposure by 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 counterparties and credit limits is maintained.

**Energy:**  As part of the sale of the forward book of electricity tradingcontracts, IE entered into an Indemnity Agreement with SET, guaranteeing theperformance of one of the counterparties. The maximum amount payable by IE under the Indemnity Agreement is $20million.  The Indemnity Agreement hasbeen accounted for in accordance with FIN 45, "Guarantor's Accounting andDisclosure Requirements for Guarantees, Including Indirect Guarantees ofIndebtedness of Others" and did not have a significant effect on thefinancial statements.

**Equity Price Risk**IDACORP and IPC are exposed to pricefluctuations in equity markets, primarily through their pension plan assets, amine reclamation trust fund owned by an equity-method investment of IPC, andother equity investments at IPC.  Ahypothetical 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.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA**

**INDEX TO FINANCIAL STATEMENTSAND FINANCIAL STATEMENT SCHEDULES**
|                                                                                        | **PAGE**      |
|---------------------------------------------------------------------------------------------|---------------|
| **Consolidated  Financial Statements:**                                                     |          |
| IDACORP, Inc.                                                                               |          |
| Consolidated Statements of Income for the Years Ended  December 31, 2003, 2002 and 2001     | 50            |
| Consolidated Balance Sheets as of December 31, 2003 and  2002                               | 51-52         |
| Consolidated Statements of Cash Flows for the Years  Ended December 31, 2003, 2002 and 2001 | 53            |
| Consolidated Statement of Shareholders' Equity for the  Years Ended December 31, 2003, 2002 |          |
|                                                                                        | and 2001      | 54 |
| Consolidated Statements of Comprehensive Income for the  Years Ended December 31, 2003,     |          |
|                                                                                        | 2002 and 2001 | 55 |
| Notes to the Consolidated Financial Statements                                              | 56-86         |
| Independent Auditors' Report                                                                | 87            |
|                                                                                        |          |
| Idaho Power Company                                                                         |          |
| Consolidated Statements of Income for the Years Ended  December 31, 2003, 2002 and 2001     | 88            |
| Consolidated Balance Sheets as of December 31, 2003 and  2002                               | 89-90         |
| Consolidated Statements of Capitalization as of  December 31, 2003 and 2002                 | 91            |
| Consolidated Statements of Cash Flows for the Years  Ended December 31, 2003, 2002 and 2001 | 92            |
| Consolidated Statement of Retained Earnings for the  Years Ended December 31, 2003, 2002    |          |
|                                                                                        | and 2001      | 93 |
| Consolidated  Statements of Comprehensive Income for the Years Ended December 31, 2003,     |          |
|                                                                                        | 2002 and 2001 | 93 |
| Notes to the Consolidated Financial Statements                                              | 94-98         |
| Independent Auditors' Report                                                                | 99            |
|                                                                                        |          |
| **Supplemental Financial  Information and Consolidated Financial Statement Schedules**      |          |
| Supplemental Financial Information (Unaudited)                                              | 100           |
|                                                                                        |          |
| Financial Statement Schedules for the Years Ended  December 31, 2003, 2002 and 2001:        |          |
| Schedule II-Consolidated Valuation and Qualifying  Accounts-IDACORP, Inc.                   | 110           |
| Schedule II-Consolidated Valuation and Qualifying  Accounts-Idaho Power Company             | 111           |
|                                                                                        |          |

 

**IDACORP, Inc.Consolidated Statements of Income**
|                             | **Year Ended December 31,**                              |
|----------------------------------|----------------------------------------------------------|
|                             | **2003**                                                 |   | **2002** |   | **2001** |
|                             | **(thousands of dollars except  for per share amounts)** |
| **OPERATING REVENUES:**          |                                                     |   |   |   |   |   |   |   |
|                             | Electric utility:                                        |   |   |   |   |   |   |   |   |
|                             |                                                     | General business | $ | 670,969  |   | $ | 772,035  |   | $ | 650,608  |
|                             |                                                     | Off-system sales |   | 71,573  |   |   | 55,031  |   |   | 219,966  |
|                             |                                                     | Other revenues |   | 40,178  |   |   | 41,974  |   |   | 43,627  |
|                             |                                                     |   | Total electric utility revenues |   | 782,720  |   |   | 869,040  |   |   | 914,201  |
|                             | Energy marketing                                         |   | 19,916  |   |   | 46,410  |   |   | 348,663  |
|                             | Other                                                    |   | 20,366  |   |   | 13,350  |   |   | 12,448  |
|                             |                                                     | Total operating revenues |   | 823,002  |   |   | 928,800  |   |   | 1,275,312  |
|                             |                                                     |   |   |   |   |   |   |   |
| **OPERATING EXPENSES:**          |                                                     |   |   |   |   |   |   |   |
|                             | Electric utility:                                        |   |   |   |   |   |   |   |   |
|                             |                                                     | Purchased power |   | 150,980  |   |   | 142,102  |   |   | 584,209  |
|                             |                                                     | Fuel expense |   | 99,898  |   |   | 102,871  |   |   | 98,318  |
|                             |                                                     | Power cost adjustment |   | 70,762  |   |   | 170,489  |   |   | (175,925) |
|                             |                                                     | Other operations and maintenance |   | 220,983  |   |   | 207,355  |   |   | 210,763  |
|                             |                                                     | Depreciation |   | 97,650  |   |   | 93,609  |   |   | 87,041  |
|                             |                                                     | Taxes other than income taxes |   | 20,753  |   |   | 19,953  |   |   | 19,693  |
|                             |                                                     |   | Total electric utility expenses |   | 661,026  |   |   | 736,379  |   |   | 824,099  |
|                             | Energy marketing:                                        |   |   |   |   |   |   |   |   |
|                             |                                                     | Cost of revenues |   | 1,250  |   |   | 42,113  |   |   | 105,904  |
|                             |                                                     | Selling, general and administrative |   | 24,349  |   |   | 30,427  |   |   | 66,047  |
|                             |                                                     | Net loss on legal disputes |   | 12,072  |   |   | -  |   |   | -  |
|                             | Other                                                    |   | 40,243  |   |   | 44,241  |   |   | 36,973  |
|                             |                                                     |   | Total operating expenses |   | 738,940  |   |   | 853,160  |   |   | 1,033,023  |
|                             |                                                     |   |   |   |   |   |   |   |
| **OPERATING INCOME (LOSS):**     |                                                     |   |   |   |   |   |   |   |
|                             | Electric utility                                         |   | 121,694  |   |   | 132,661  |   |   | 90,102  |
|                             | Energy  marketing                                        |   | (17,755) |   |   | (26,130) |   |   | 176,712  |
|                             | Other                                                    |   | (19,877) |   |   | (30,891) |   |   | (24,525) |
|                             |                                                     | Total operating income |   | 84,062  |   |   | 75,640  |   |   | 242,289  |
|                             |                                                     |   |   |   |   |   |   |   |
| **OTHER INCOME**                 |                                                     | 24,412  |   |   | 19,218  |   |   | 33,600  |
|                             |                                                     |   |   |   |   |   |   |   |
| **OTHER EXPENSE**                |                                                     | 18,083  |   |   | 15,388  |   |   | 10,306  |
|                             |                                                     |   |   |   |   |   |   |   |
| **INTEREST EXPENSE AND OTHER:**  |                                                     |   |   |   |   |   |   |   |
|                             | Interest on long-term debt                               |   | 58,670  |   |   | 54,147  |   |   | 55,783  |
|                             | Other interest                                           |   | 2,832  |   |   | 10,211  |   |   | 14,540  |
|                             | Preferred dividends of Idaho Power Company               |   | 3,430  |   |   | 4,587  |   |   | 5,400  |
|                             |                                                     | Total interest expense and other |   | 64,932  |   |   | 68,945  |   |   | 75,723  |
|                             |                                                     |   |   |   |   |   |   |   |
| **INCOME BEFORE INCOME TAXES**   |                                                     | 25,459  |   |   | 10,525  |   |   | 189,860  |
|                             |                                                     |   |   |   |   |   |   |   |
| **INCOME TAX (BENEFIT) EXPENSE** |                                                     | (21,119) |   |   | (51,147) |   |   | 64,646  |
|                             |                                                     |   |   |   |   |   |   |   |
| **NET INCOME**                   | $                                                        | 46,578  |   | $ | 61,672  |   | $ | 125,214  |
|                             |                                                     |   |   |   |   |   |   |   |
| **AVERAGE COMMON SHARES**        |                                                     |   |   |   |   |   |   |   |
|                             | **OUTSTANDING (000's)**                                  |   | 38,186  |   |   | 37,729  |   |   | 37,387  |
|                             |                                                     |   |   |   |   |   |   |   |
| **EARNINGS PER SHARE OF COMMON** |                                                     |   |   |   |   |   |   |   |
|                             | **STOCK (basic and diluted)**                            | $ | 1.22  |   | $ | 1.63  |   | $ | 3.35  |

Theaccompanying notes are an integral part of these statements.

** **

**IDACORP, Inc.Consolidated Balance Sheets**
|                                | **December 31,**                                |
|-------------------------------------|-------------------------------------------------|
|                                | **2003**                                        |   | **2002** |
| **ASSETS**                          | **(thousands of dollars)**                      |
|                                |                                            |   |   |
| **CURRENT ASSETS:**                 |                                            |   |   |   |   |
|                                | Cash and cash equivalents                       | $ | 75,159  |   | $ | 42,736  |
|                                | Receivables:                                    |   |   |   |   |   |
|                                |                                            | Customer |   | 93,599  |   |   | 176,846  |
|                                |                                            | Allowance for uncollectible accounts |   | (43,210) |   |   | (43,311) |
|                                |                                            | Employee notes |   | 3,347  |   |   | 3,240  |
|                                |                                            | Other |   | 8,209  |   |   | 5,691  |
|                                | Energy marketing assets                         |   | 4,176  |   |   | 85,138  |
|                                | Accrued unbilled revenues                       |   | 30,869  |   |   | 35,714  |
|                                | Materials and supplies (at average cost)        |   | 21,351  |   |   | 22,812  |
|                                | Fuel stock (at average cost)                    |   | 6,228  |   |   | 6,943  |
|                                | Prepayments                                     |   | 27,779  |   |   | 34,872  |
|                                | Regulatory assets                               |   | 6,269  |   |   | 17,147  |
|                                |                                            | Total current assets |   | 233,776  |   |   | 387,828  |
|                                |                                            |   |   |   |   |
| **INVESTMENTS**                     |                                            | 204,474  |   |   | 206,348  |
|                                |                                            |   |   |   |   |
| **PROPERTY, PLANT AND  EQUIPMENT:** |                                            |   |   |   |   |
|                                | Utility plant in service                        |   | 3,220,228  |   |   | 3,086,965  |
|                                | Accumulated provision for depreciation          |   | (1,239,604) |   |   | (1,157,287) |
|                                |                                            | Utility plant in service - net |   | 1,980,624  |   |   | 1,929,678  |
|                                | Construction work in progress                   |   | 96,091  |   |   | 96,209  |
|                                | Utility plant held for future use               |   | 2,438  |   |   | 2,335  |
|                                | Other property, net of accumulated depreciation |   | 9,166  |   |   | 15,950  |
|                                |                                            | Property, plant and equipment - net |   | 2,088,319  |   |   | 2,044,172  |
|                                |                                            |   |   |   |   |
| **OTHER ASSETS:**                   |                                            |   |   |   |   |
|                                | American Falls and Milner water rights          |   | 31,585  |   |   | 31,585  |
|                                | Company-owned life insurance                    |   | 35,624  |   |   | 35,299  |
|                                | Energy marketing assets - long-term             |   | 14,358  |   |   | 64,733  |
|                                | Regulatory assets                               |   | 427,760  |   |   | 482,159  |
|                                | Long-term receivables                           |   | 3,106  |   |   | 75,915  |
|                                | Employee notes                                  |   | 4,775  |   |   | 4,615  |
|                                | Other                                           |   | 57,949  |   |   | 54,514  |
|                                |                                            | Total other assets |   | 575,157  |   |   | 748,820  |
|                                |                                            |   |   |   |   |
|                                |                                            | **TOTAL** | $ | 3,101,726  |   | $ | 3,387,168  |
|                                |                                            |   |   |   |   |

The accompanying notes are an integral part ofthese statements.

 

 

 

**IDACORP, Inc.Consolidated Balance Sheets**
|                                        | **December 31,**                                                   |
|---------------------------------------------|--------------------------------------------------------------------|
|                                        | **2003**                                                           |   | **2002** |
| **LIABILITIES AND SHAREHOLDERS'  EQUITY**   | **(thousands of dollars)**                                         |
|                                        |                                                               |   |   |
| **CURRENT LIABILITIES:**                    |                                                               |   |   |   |   |
|                                        | Current maturities of long-term debt                               | $ | 67,923  |   | $ | 89,592  |
|                                        | Notes payable                                                      |   | 93,650  |   |   | 176,200  |
|                                        | Accounts payable                                                   |   | 60,916  |   |   | 130,930  |
|                                        | Energy marketing liabilities                                       |   | 4,317  |   |   | 59,917  |
|                                        | Taxes accrued                                                      |   | 35,580  |   |   | 46,566  |
|                                        | Interest accrued                                                   |   | 13,741  |   |   | 13,639  |
|                                        | Deferred income taxes                                              |   | 5,639  |   |   | 21,203  |
|                                        | Other                                                              |   | 25,557  |   |   | 35,118  |
|                                        |                                                               | Total current liabilities |   | 307,323  |   |   | 573,165  |
|                                        |                                                               |   |   |   |   |
| **OTHER LIABILITIES:**                      |                                                               |   |   |   |   |
|                                        | Deferred income taxes                                              |   | 554,715  |   |   | 595,820  |
|                                        | Energy marketing liabilities - long-term                           |   | 14,393  |   |   | 51,761  |
|                                        | Regulatory liabilities                                             |   | 258,524  |   |   | 251,921  |
|                                        | Other                                                              |   | 104,290  |   |   | 87,605  |
|                                        |                                                               | Total other liabilities |   | 931,922  |   |   | 987,107  |
|                                        |                                                               |   |   |   |   |
| **LONG-TERM DEBT**                          |                                                               | 945,834  |   |   | 898,676  |
|                                        |                                                               |   |   |   |   |
| **COMMITMENTS AND CONTINGENT  LIABILITIES** |                                                               |   |   |   |   |
|                                        |                                                               |   |   |   |   |
| **PREFERRED  STOCK OF IDAHO POWER COMPANY** |                                                               | 52,366  |   |   | 53,393  |
|                                        |                                                               |   |   |   |   |
| **SHAREHOLDERS' EQUITY:**                   |                                                               |   |   |   |   |
|                                        | Common stock, no par value (shares authorized  120,000,000;        |   |   |   |   |   |
|                                        |                                                               | 38,341,358 and 38,152,436 shares issued,  respectively) |   | 473,904  |   |   | 470,361  |
|                                        | Retained earnings                                                  |   | 397,167  |   |   | 415,315  |
|                                        | Accumulated other comprehensive income (loss)                      |   | (2,630) |   |   | (7,109) |
|                                        | Treasury stock (134,737 and 134,667 shares at  cost, respectively) |   | (4,160) |   |   | (3,740) |
|                                        |                                                               | Total shareholders' equity |   | 864,281  |   |   | 874,827  |
|                                        |                                                               |   |   |   |   |
|                                        |                                                               |   | **TOTAL** | $ | 3,101,726  |   | $ | 3,387,168  |
|                                        |                                                               |   |   |   |   |
|                                             |                                                                    |  |  |  |  |  |  |  |

The accompanying notes are an integral part ofthese statements.

 

 

**IDACORP, Inc.Consolidated Statements of Cash Flows**
|                                                  |                                                         | **Year Ended December 31,**                                  |
|-------------------------------------------------------|--------------------------------------------------------------|--------------------------------------------------------------|
|                                                  |                                                         | **2003**                                                     |   | **2002** |   | **2001** |
|                                                  |                                                         | **(thousands of dollars)**                                   |
| **OPERATING  ACTIVITIES:**                            |                                                         |
|                                                  | Net  income                                                  | $                                                            | 46,578  |   | $ | 61,672  |   | $ | 125,214  |
|                                                  | Adjustments  to reconcile net income to net cash provided by |                                                         |   |   |   |   |   |   |   |
|                                                  |                                                         | (used  in) operating activities:                             |   |   |   |   |   |   |   |   |
|                                                  |                                                         | Other  than temporary decline in market value of investments |   | 1,948  |   |   | 980  |   |   | -  |
|                                                  |                                                         | Net  loss on legal disputes                                  |   | 12,072  |   |   | -  |   |   | -  |
|                                                  |                                                         | Impairment  of long-lived asset                              |   | 3,498  |   |   | 8,064  |   |   | -  |
|                                                  |                                                         | Allowance  for uncollectible accounts                        |   | 2,538  |   |   | 782  |   |   | 19,450  |
|                                                  |                                                         | Unrealized  (gains) losses from energy marketing activities  |   | 42,517  |   |   | 65,965  |   |   | (92,803) |
|                                                  |                                                         | Gain  on sales of assets                                     |   | -  |   |   | -  |   |   | (1,605) |
|                                                  |                                                         | Depreciation  and amortization                               |   | 129,070  |   |   | 122,831  |   |   | 109,976  |
|                                                  |                                                         | Deferred  taxes and investment tax credits                   |   | (61,985) |   |   | (110,666) |   |   | 152,938  |
|                                                  |                                                         | Accrued  PCA costs                                           |   | 68,358  |   |   | 164,201  |   |   | (184,584) |
|                                                  |                                                         | Change  in:                                                  |   |   |   |   |   |   |   |   |
|                                                  |                                                         |                                                         | Receivables  and prepayments |   | 91,991  |   |   | 27,749  |   |   | 31,470  |
|                                                  |                                                         |                                                         | Accrued  unbilled revenues |   | 4,845  |   |   | 1,687  |   |   | 7,425  |
|                                                  |                                                         |                                                         | Materials  and supplies and fuel stock |   | 2,175  |   |   | 3,645  |   |   | -  |
|                                                  |                                                         |                                                         | Accounts  payable and other accrued liabilities |   | (70,342) |   |   | (145,868) |   |   | 3,914  |
|                                                  |                                                         |                                                         | Taxes  receivable/accrued |   | (10,986) |   |   | 98,970  |   |   | (66,821) |
|                                                  |                                                         |                                                         | Other  current assets |   | -  |   |   | -  |   |   | (46,893) |
|                                                  |                                                         |                                                         | Other  current liabilities |   | (6,412) |   |   | 40,614  |   |   | (2,180) |
|                                                  |                                                         |                                                         | Long-term  receivable |   | 51,394  |   |   | -  |   |   | (73,706) |
|                                                  |                                                         |                                                         | Other  assets |   | (8,080) |   |   | 869  |   |   | 6,300  |
|                                                  |                                                         |                                                         | Other  liabilities |   | 12,065  |   |   | 6,921  |   |   | 3,315  |
|                                                  |                                                         | Net  cash provided by (used in) operating activities         |   | 311,244  |   |   | 348,416  |   |   | (8,590) |
| **INVESTING ACTIVITIES:**                             |                                                         |                                                         |   |   |   |   |   |   |
|                                                  | Additions  to property, plant and equipment                  |                                                         | (149,149) |   |   | (134,223) |   |   | (179,056) |
|                                                  | Investments  in affordable housing projects                  |                                                         | -  |   |   | (43,939) |   |   | -  |
|                                                  | Proceeds  from sales of assets                               |                                                         | -  |   |   | -  |   |   | 11,261  |
|                                                  | Other  assets                                                |                                                         | (1,358) |   |   | (5,332) |   |   | 1,046  |
|                                                  | Other  liabilities                                           |                                                         | (3,074) |   |   | (3,834) |   |   | (3,469) |
|                                                  |                                                         | Net  cash used in investing activities                       |   | (153,581) |   |   | (187,328) |   |   | (170,218) |
| **FINANCING ACTIVITIES:**                             |                                                         |                                                         |   |   |   |   |   |   |
|                                                  | Proceeds  from issuance of first mortgage bonds              |                                                         | 140,000  |   |   | 200,000  |   |   | 120,000  |
|                                                  | Proceeds  from issuance of other long-term debt              |                                                         | 65,492  |   |   | -  |   |   | -  |
|                                                  | Proceeds  from issuance of pollution control bonds           |                                                         | 49,800  |   |   | -  |   |   | -  |
|                                                  | Retirement  of first mortgage bonds                          |                                                         | (160,000) |   |   | (77,000) |   |   | (130,000) |
|                                                  | Retirement  of pollution control bonds                       |                                                         | (49,800) |   |   | -  |   |   | -  |
|                                                  | Retirement  of other long-term debt                          |                                                         | (20,203) |   |   | (12,403) |   |   | (14,454) |
|                                                  | Retirement  of preferred stock of Idaho Power Company        |                                                         | (860) |   |   | (50,994) |   |   | (679) |
|                                                  | Dividends  on common stock                                   |                                                         | (64,726) |   |   | (70,178) |   |   | (69,782) |
|                                                  | Increase  (decrease) in short-term borrowings                |                                                         | (82,550) |   |   | (186,300) |   |   | 241,900  |
|                                                  | Common  stock issued                                         |                                                         | 4,123  |   |   | 15,770  |   |   | 618  |
|                                                  | Acquisition  of treasury shares                              |                                                         | (799) |   |   | (998) |   |   | (7,968) |
|                                                  | Distributions  of treasury shares                            |                                                         | -  |   |   | -  |   |   | 2,575  |
|                                                  | Other  assets                                                |                                                         | (5,141) |   |   | (2,360) |   |   | (3,375) |
|                                                  | Other  liabilities                                           |                                                         | (576) |   |   | (577) |   |   | (134) |
|                                                  |                                                         | Net  cash (used in) provided by financing activities         |   | (125,240) |   |   | (185,040) |   |   | 138,701  |
| Net  increase (decrease) in cash and cash equivalents |                                                         | 32,423                                                  |   |   | (23,952) |   |   | (40,107) |
| Cash and cash  equivalents beginning of period        |                                                         | 42,736                                                  |   |   | 66,688  |   |   | 106,795  |
| Cash  and cash equivalents at end of period           | $                                                            | 75,159                                                  |   | $ | 42,736  |   | $ | 66,688  |
|                                                  |                                                         |                                                         |   |   |   |   |   |   |
|                                                       |                                                              |                                                              |  |  |  |  |  |  |  |  |  |  |

The accompanying notesare an integral part of these statements.

 

 

 

**IDACORP,Inc.Consolidated Statements of Shareholders' Equity**
|                     |                     |         | **Accumulated** |               |          |
|--------------------------|--------------------------|--------------|-----------------|--------------------|---------------|
|                     |                     |         | **Other**       |               |          |
|                     |                     |         | **Compre-**     |               |          |
|                     |                     |         | **hensive**     |               |          |
|                     | **Common Stock**         | **Retained** | **Income**      | **Treasury Stock** | **Total**     |
|                     | **Shares**               | **Amount**   | **Earnings**    | **(Loss)**         | **Shares**    | **Amount** | **Amount** |
| **(thousands)**          |
| Balance  at January 1,   |                     |         |            |               |          |   |   |   |   |   |   |   |
|                     | 2001                     | 37,612  | $               | 453,102       | $             | 370,126  | $ | (921) | 44  | $ | (1,496) | $ | 820,811  |
|                     |                     |         |            |               |          |   |   |   |   |   |   |   |
| Net  income              | -                   |         | -          |               | 125,214  |   | -  | -  |   | -  |   | 125,214  |
| Common  stock dividends  |                     |         |            |               |          |   |   |   |   |   |   |   |
|                     | ($1.86  per share)       | -       |            | -             |          | (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  |                     |         |            |               |          |   |   |   |   |   |   |   |
|                     | ($1.86  per share)       | -       |            | -             |          | (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  |
|                     |                     |         |            |               |          |   |   |   |   |   |   |   |
| Net  income              | -                   |         | -          |               | 46,578   |   | -  | -  |   | -  |   | 46,578  |
| Common  stock dividends  |                     |         |            |               |          |   |   |   |   |   |   |   |
|                     | ($1.70  per share)       | -       |            | -             |          | (64,726) |   | -  | -  |   | -  |   | (64,726) |
| Issued                   | 189                 |         | 4,123      |               | -        |   | -  | (39) |   | 509  |   | 4,632  |
| Acquired                 | -                   |         | -          |               | -        |   | -  | 39  |   | (929) |   | (929) |
| Other                    | -                   |         | (580)           |               | -        |   | -  | -  |   | -  |   | (580) |
| Unrealized  gain on      |                     |         |            |               |          |   |   |   |   |   |   |   |
|                     | securities  (net of tax) | -       |            | -             |          | -  |   | 4,809 | -  |   | -  |   | 4,809  |
| Minimum  pension         |                     |         |            |               |          |   |   |   |   |   |   |   |
|                     | liability  adjustment    |         |            |               |          |   |   |   |   |   |   |   |   |
|                     | (net  of tax)            | -       |            | -             |          | -  |   | (330) | -  |   | -  |   | (330) |
|                     |                     |         |            |               |          |   |   |   |   |   |   |   |
| Balance  at December 31, |                     |         |            |               |          |   |   |   |   |   |   |   |
|                     | 2003                     | 38,341  | $               | 473,904       | $             | 397,167  | $ | (2,630) | 135  | $ | (4,160) | $ | 864,281  |
|                     |                     |         |            |               |          |   |   |   |   |   |   |   |
|                          |                          |              |                 |                    |               |  |  |  |  |  |  |  |  |  |  |  |  |

The accompanying notes are an integral part of thesestatements.

 

 

 

**IDACORP,Inc.Consolidated Statements of Comprehensive Income**
|                                   | **Year  Ended December 31,**                                 |
|----------------------------------------|--------------------------------------------------------------|
|                                   | **2003**                                                     |   | **2002** |   | **2001** |
|                                   | **(thousands  of dollars)**                                  |
|                                   |                                                         |   |   |   |   |   |   |   |
| **NET INCOME**                         | $                                                            | 46,578  |   | $ | 61,672  |   | $ | 125,214  |
|                                   |                                                         |   |   |   |   |   |   |   |
| **OTHER COMPREHENSIVE INCOME (LOSS):** |                                                         |   |   |   |   |   |   |   |
|                                   | Unrealized gains on securities:                              |   |   |   |   |   |   |   |   |
|                                   |                                                         | Unrealized holding gains (losses) arising during the  period, |   |   |   |   |   |   |   |   |
|                                   |                                                         |   | net of tax of $2,963, ($1,840) and ($992) |   | 4,982  |   |   | (2,991) |   |   | (1,690) |
|                                   |                                                         | Reclassification adjustment for (gains) losses included |   |   |   |   |   |   |   |   |
|                                   |                                                         |   | in net income, net of tax of ($111), $1,007 and ($52) |   | (173) |   |   | 1,560  |   |   | (80) |
|                                   |                                                         |   | Net unrealized losses (gains) |   | 4,809  |   |   | (1,431) |   |   | (1,770) |
|                                   | Minimum pension liability adjustment, net of tax of  ($191), |   |   |   |   |   |   |   |   |
|                                   |                                                         | ($1,265) and ($649) |   | (330) |   |   | (1,959) |   |   | (1,028) |
|                                   |                                                         |   |   |   |   |   |   |   |
| **TOTAL COMPREHENSIVE INCOME**         | $                                                            | 51,057  |   | $ | 58,282  |   | $ | 122,416  |
|                                   |                                                         |   |   |   |   |   |   |   |

Theaccompanying notes are an integral part of these statements

 

 

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

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

**Natureof Business**IDACORP, Inc. (IDACORP) is a holding company formed in 1998 whoseprincipal operating subsidiary is Idaho Power Company (IPC).  IPC is regulated by the Federal EnergyRegulatory Commission (FERC) and the state regulatory commissions of Idaho andOregon and is engaged in the generation, transmission, distribution, sale andpurchase of electric energy.  IPC is theparent of Idaho Energy Resources Co., a joint venturer in Bridger Coal Company,which supplies coal to the Jim Bridger generating plant owned in part by IPC.

IDACORP's other operatingsubsidiaries include:

IdaTech- developer of integrated fuel cell systems;

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

Velocitus- commercial and residential Internet service provider;

IDACOMM- provider of telecommunications services;

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

IDACORPEnergy (IE) - marketer of electricity and natural gas.

 

IE is in the late stages ofwinding down its operations.  In 2003,IDACORP decided that Ida-West would also wind down its operations.

**Principlesof Consolidation**The consolidated financial statements include the accounts of IDACORPand 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.

**ManagementEstimates**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.

**Systemof 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 and Depreciation**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 is depreciated usingthe straight-line method at rates approved by regulatory authorities.  Annual depreciation provisions as a percentof average depreciable utility plant in service approximated 3.03 percent in2003, 3.00 percent in 2002 and 2.98 percent in 2001.

Long-lived assets are periodicallyreviewed for impairment when events or changes in circumstances indicate thatthe carrying amount of an asset may not be recoverable as prescribed under SFAS144, "Accounting for the Impairment or Disposal of Long-livedAssets."  SFAS 144 requires that ifthe sum of the undiscounted expected future cash flows from an asset is lessthan the carrying value of the asset, an asset impairment must be recognized inthe financial statements.

**Allowancefor Funds Used During Construction**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 processover the service life of the related property through increased revenuesresulting from a higher rate base and higher depreciation expense.  The component of AFDC attributable toborrowed funds is included as a reduction to interest expense, while the equitycomponent is included in other income. IPC's weighted-average monthly AFDC rates for 2003, 2002 and 2001 were8.3 percent, 4.3 percent and 5.4 percent, respectively.  IPC's reductions to interest expense forAFDC were $3 million, $2 million and $4 million, and other income included $3million, $0.3 million and $1 million for 2003, 2002 and 2001, 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.  IPC collectsfranchise fees and similar taxes related to energy consumption.  These amounts are recorded as liabilitiesuntil paid to the taxing authority. None of these collections are reported on the income statement asrevenue or expense.

IE reports marketing andtrading revenues and expenses on a net basis, using the mark-to-market methodof accounting.  Energy marketingrevenues include sales of electricity and gas netted against purchases, whetherphysically settled or net settled. Additionally, all financial transactions and unrealized income arepresented on a net basis in operating revenues.  Other cost of revenue items such as transmission and broker feesare reported as operating expenses.

**PowerCost 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 supply expenses(fuel and purchased power less sales for resale) and the true-up of the prioryear's forecast.  During the year, 90percent of the difference between the actual and forecasted costs is deferredwith interest.  The ending balance ofthis deferral, called a true-up, is then included in the calculation of thenext year's PCA adjustment.

**IncomeTaxes**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 after1980.  On other facilities, deferredincome taxes are provided for the difference between accelerated income taxdepreciation and straight-line depreciation using tax guideline lives on assetsacquired prior to 1981. Deferred income taxes are not provided for those incometax timing differences where the prescribed regulatory accounting methods donot provide for 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) on qualifying plant additions.  ITCs earned on regulated assets are deferredand amortized to income over the estimated service lives of the related properties.  Credits earned on non-regulated assets orinvestments are recognized in the year earned.

**EarningsPer 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 computationexcluded 721,800 common stock options in 2003, 849,000 in 2002 and 274,000 in2001 because the options' exercise prices were greater than the average marketprice of the common stock during the years. These options expire from 2010 to 2013, and were still outstanding atthe end of 2003.

**Stock-Based Compensation**At December 31, 2003, 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 anexercise price equal to the market value of the underlying common stock on thedate of grant.

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:
|                                             | **2003**                                                 |                 | **2002**    |         | **2001**     |
|--------------------------------------------------|----------------------------------------------------------|----------------------|-------------|--------------|--------------|
|                                             | **(thousands of dollars except for per share  amounts)** |
|                                             |                                                     |                 |        |         |         |   |   |   |
| Net income, as reported                          | $                                                        | 46,578          |        | $            | 61,672  |   | $ | 125,214 |
| Add: Stock-based employee compensation expense   |                                                     |                 |        |         |         |   |   |   |
|                                             | included in reported net income, net of related          |                 |        |         |         |   |   |   |   |
|                                             | tax effects                                              |                 | (76)        |         |         | (9) |   |   | 442 |
| Deduct: Total stock-based  employee compensation |                                                     |                 |        |         |         |   |   |   |
|                                             | expense determined under fair  value based               |                 |        |         |         |   |   |   |   |
|                                             | method for all awards, net of  related tax effects       |                 | 1,169  |         |         | 1,958  |   |   | 1,579 |
|                                             |                                                     | Pro forma net income | $           | 45,333  |         | $ | 59,705  |   | $ | 124,077 |
| Earnings per share:                              |                                                     |                 |        |         |         |   |   |   |
|                                             | Basic and diluted - as  reported                         | $                    | 1.22   |         | $            | 1.63  |   | $ | 3.35 |
|                                             | Basic and diluted - pro forma                            |                 | 1.19   |         |         | 1.58  |   |   | 3.32 |
|                                             |                                                     |                 |        |         |         |   |   |   |   |
|                                                  |                                                          |                      |             |              |              |  |  |  |  |  |

 

**Cashand 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."  Those investmentsclassified as available-for-sale securities are reported at fair value, usingeither specific identification or average cost to determine the cost forcomputing gains or losses.  Anyunrealized gains or losses on available-for-sale securities are included inother comprehensive income.  Investmentsclassified as held-to-maturity securities are reported at amortized cost.  Held-to-maturity securities are investmentsin debt securities for which the company has the positive intent and ability tohold the securities until maturity. 

Additionally, these investments are evaluated todetermine whether they have experienced a decline in market value that isconsidered other than temporary.  Otherthan temporary declines in market value are included in Other Income in theConsolidated Statements of Income.

Thefollowing table summarizes investments in debt and equity securities (inthousands of dollars):
|                                       | **2003**       | **2002**       |
|--------------------------------------------|----------------|----------------|
|                                       | **Gross**      | **Gross**      |   | **Gross** | **Gross** |   |
|                                       | **Unrealized** | **Unrealized** | **Fair** | **Unrealized** | **Unrealized** | **Fair** |
|                                       | **Gain**       | **Loss**       | **Value** | **Gain** | **Loss** | **Value** |
| Available for sale equity securities (IPC) | 2,665          | 276            | 22,408 | 370 | 2,159 | 18,336 |
| Held to maturity debt  securities          | -              | -              | 17,221 | - | - | 8,299 |
|                                       |           |           |   |   |   |   |

 

IFS invests in affordable housing developments that areaccounted for in accordance with Emerging Issues Task Force (EITF) Issue No.94-1, "Accounting for Tax Benefits Resulting from Investments inAffordable Housing Projects," and are presented as Investments on theConsolidated Balance Sheets.  IFSaccounts for these investments using the equity method.  All projects are reviewed periodically forimpairment.  At December 31, 2003 and2002, the net affordable housing developments included in Investments were $116million and $126 million, respectively.

**DerivativeFinancial Instruments**Financial instruments such as commodity futures, forwards, optionsand swaps are used to manage exposure to commodity price risk in theelectricity market.  The objective ofthe risk management program is to mitigate the risk associated with thepurchase and sale of electricity and natural gas as well as to optimize energymarketing portfolios.  The accountingfor derivative financial instruments that are used to manage risk is inaccordance with the concepts established by SFAS 133, "Accounting forDerivative Instruments and Hedging Activities," as amended.

**Regulationof 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 jurisdictions regulatingIPC.  The economic effects of regulationcan result in regulated companies recording costs that have been, or areexpected 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 on 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).

**ComprehensiveIncome**Comprehensive income includes net income, unrealized holding gainsand losses on marketable securities, IPC's proportionate share of unrealizedholding gains and losses on marketable securities held by an equity investeeand the changes in additional minimum liability under a deferred compensationplan for certain senior management employees and directors.  The following table presents IDACORP's andIPC's accumulated other comprehensive income balance at December 31:
|                                            | **2003**                    |        | **2002**    |
|-------------------------------------------------|-----------------------------|-------------|-------------|
|                                            | **(thousands  of dollars)** |
| Unrealized holding (gains) losses on securities | $                           | (3,676)     |        | $ | 1,133 |
| Minimum pension liability adjustment            |                        | 6,306  |        |   | 5,976 |
|                                            | Total                       | $           | 2,630  |   | $ | 7,109 |
|                                            |                        |        |        |   |   |
|                                                 |                             |             |             |  |  |  |

 

**Goodwill**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 SFAS 142, theannual impairment tests have been completed on IDACORP's $13 million goodwillbalance, which is related to the acquisitions of IdaTech and Velocitus.  Velocitus' test was performed as of June 30,2003 and IdaTech's as of September 30, 2003. No impairment was noted in these tests. Goodwill impairment tests will continue to be performed at leastannually, and more frequently if circumstances indicate a possible impairment.

The following table presentsIDACORP's net income and EPS, adjusted to exclude goodwill amortizationexpense, for the three years ended December 31:
|                                   | **2003**                                                 |   | **2002** |   | **2001** |
|----------------------------------------|----------------------------------------------------------|--------|----------|--------|----------|
|                                   | **(thousands of dollars except for per share  amounts)** |
| Reported net income                    | $                                                        | 46,578 |     | $      | 61,672   |   | $ | 125,214 |
| Add back goodwill  amortization        |                                                     | -      |     |   | -        |   |   | 2,049 |
| Adjusted net income                    | $                                                        | 46,578 |     | $      | 61,672   |   | $ | 127,263 |
|                                   |                                                     |   |     |   |     |   |   |   |
| Basic and diluted earnings  per share: |                                                     |   |     |   |     |   |   |   |
| Reported earnings per share            | $                                                        | 1.22   |     | $      | 1.63     |   | $ | 3.35 |
| Add back goodwill  amortization        |                                                     | -      |     |   | -        |   |   | 0.05 |
| Adjusted earnings per share            | $                                                        | 1.22   |     | $      | 1.63     |   | $ | 3.40 |
|                                   |                                                     |   |     |   |     |   |   |   |

** **

**Adopted Accounting PronouncementsSFAS 143:**On January 1, 2003 IDACORP and IPC adopted SFAS 143,"Accounting for Asset Retirement Obligations."  This statement addresses financialaccounting and reporting for obligations associated with the retirement oftangible long-lived assets and the associated asset retirement costs.  An obligation may result from theacquisition, construction, development or the normal operation of a long-livedasset.  SFAS 143 requires an entity torecord the fair value of a liability for an asset retirement obligation (ARO)in the period in which it is incurred. When the liability is initially recorded, the entity increases thecarrying amount of the related long-lived asset to reflect the futureretirement cost.  Over time, theliability is accreted to its present value and paid, and the capitalized costis depreciated over the useful life of the related asset.  If, at the end of the asset's life, therecorded liability differs from the actual obligations paid, a gain or losswould be recognized at that time.  As arate-regulated entity, IPC records regulatory assets and liabilities instead ofaccretion, depreciation and gains or losses.  This treatment was approved by Order No. 29414 from the IPUC.  The regulatory assets recorded under thisorder do not earn a return on investment.

IDACORP and IPC performeddetailed assessments of the applicability and implications of SFAS 143 andidentified AROs related to two of IPC's jointly owned coal-fired generationfacilities and IPC's transmission and distribution facilities.  Upon adoption, IPC recorded an ARO of $7million, fixed assets of $2 million, accumulated depreciation of $1 million anda regulatory asset of $6 million.  Theseamounts do not include an amount for the transmission and distributionfacilities, because, based on the indeterminate life of these assets, an AROcalculation cannot be made.

The regulated operations of IPCalso collect removal costs in rates for certain assets that do not haveassociated ARO's.  The adoption of SFAS143 required IPC to redesignate these removal costs as regulatoryliabilities.   As of December 31, 2003, IPC had $143 millionof such costs recorded as regulatory liabilities on the Consolidated BalanceSheet.  Prior year amounts werereclassified to conform to current year presentation.

An ARO also exists for thereclamation of the Bridger Coal mine property, which is leased by Bridger CoalCompany, an equity-method investee of IPC. As Bridger Coal Company has a March 31 fiscal year end, it adopted SFAS143 on April 1, 2003.  Upon adoption ofSFAS 143, IPC did not record a net change in its investment in Bridger CoalCompany, as Bridger Coal Company also is applying regulatory accounting,recording regulatory assets and liabilities instead of accretion, depreciationand gains or losses.

If the requirements of SFAS 143had been applied to prior reporting periods, IDACORP's and IPC's liability forAROs would have been $7 million at December 31, 2002 and $6 million at December31, 2001.

**SFAS149**: In April 2003, the FinancialAccounting Standards Board (FASB) issued SFAS 149, "Amendment of Statement133 on Derivative Instruments and Hedging Activities," which amends andclarifies accounting for derivative instruments, including certain derivativeinstruments embedded in other contracts, and for hedging activities under SFAS133, "Accounting for Derivative Instruments and Hedging Activities."

SFAS 149 amended SFAS 133 fordecisions made:

Aspart of the Derivatives Implementation Group process that effectively requiredamendments to SFAS 133;

Inconnection with other FASB projects dealing with financial instruments; and

Regardingimplementation issues raised in relation to the application of the definitionof a derivative, particularly regarding the meaning of an"underlying" and the characteristics of a derivative that containsfinancing components.

SFAS 149 was effective forcontracts entered into or modified after June 30, 2003, except as noted below,and for hedging relationships designated after June 30, 2003.  The guidance was to be appliedprospectively.  The provisions of SFAS149 that relate to SFAS 133 Implementation Issues that were effective forfiscal quarters that began prior to June 15, 2003 continue to be applied inaccordance with their respective effective dates.  The adoption of SFAS 149 did not have a material effect onIDACORP's or IPC's financial statements.

**SFAS150:**  In May 2003, theFASB issued SFAS 150, "Accounting for Certain Financial Instruments withCharacteristics of both Liabilities and Equity."  SFAS 150 requires that an issuer classify a financial instrumentthat is within its scope as a liability (or an asset in some circumstances).  Many of those instruments were previouslyclassified as equity.  SFAS 150 iseffective for financial instruments entered into or modified after May 31,2003, and otherwise is effective at the beginning of the first interim periodbeginning after June 15, 2003.  Theadoption of SFAS 150 did not have a material effect on IDACORP's or IPC'sfinancial statements.

**FIN 45:** InNovember 2002 the FASB issued Interpretation (FIN) No. 45, "Guarantor'sAccounting and Disclosure Requirements for Guarantees, Including IndirectGuarantees of Indebtedness of Others." This Interpretation elaborates on the disclosures to be made by aguarantor in its interim and annual financial statements about its obligationsunder certain guarantees that it has issued. It also clarifies that a guarantor is required to recognize, at theinception 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 were applicable on a prospective basis to guarantees issued ormodified after December 31, 2002, irrespective of the guarantor's fiscalyear-end.  The disclosure requirementsin this Interpretation were effective for financial statements of interim orannual periods ending after December 15, 2002. The adoption of this Interpretation did not have a material effect onIDACORP's and IPC's financial statements.

**EITFIssue No. 02-3:**  IETF Issue No. 02-3, "Issues Involvedin Accounting for Derivative Contracts Held for Trading Purposes and ContractsInvolved in Energy Trading and Risk Management Activities,"reached a consensus to rescind EITF 98-10, the impact of which is to precludemark-to-market accounting for all energy trading contracts not within the scopeof SFAS 133.  In addition, effective onJanuary 1, 2003, all energy trading contracts previously accounted for at fairvalue under EITF 98-10 must be adjusted to historical cost unless thosecontracts meet the definition of a derivative under SFAS 133. The rescission ofEITF 98-10 did not have a material effect on IDACORP or IPC's financialstatements, as substantially all of their energy trading contracts meet thedefinition of a derivative under SFAS 133.

**NewAccounting Pronouncement****FIN 46**: In January 2003, the FASB issued FIN 46, "Consolidation ofVariable Interest Entities."  InDecember 2003, the FASB issued a revised version of FIN 46 (FIN 46R).  FIN 46R provides guidance related toidentifying variable interest entities (VIEs, previously known as specialpurpose entities or SPEs) and determining whether such entities should beconsolidated.  Certain disclosures arerequired if it is reasonably possible that a company will consolidate ordisclose information about a VIE when it initially applies FIN 46R.  FIN 46 was required to be applied immediatelyto VIEs created or obtained after January 31, 2003.  During 2003, IDACORP and IPC did not participate in the creationof, or obtain a new variable interest in, any VIE.  For those VIEs created or obtained on or before January 31, 2003,IDACORP and IPC must apply the provisions of FIN 46R in the first quarter of2004.

IDACORP and IPC are in thefinal stages of their analysis of FIN 46R and the majority of theirinvestments, principally IFS' affordable housing investments, are not expectedto meet the criteria for consolidation included in FIN 46R.  IDACORP and IPC do not expect the adoptionof this standard to have a material effect on their financial statements.

**OtherAccounting Policies**Debt discount, expense and premium are being amortized over the termsof the respective debt issues.

**Reclassifications**Certain items previously reported for years prior to 2003 have beenreclassified to conform to the current year's presentation.  Net income and shareholders' equity were notaffected by these reclassifications.

 

**2.  INCOME TAXES:**

A reconciliation between thestatutory federal income tax rate and the effective rate is as follows:
|                                             |                                        | **2003**                   |         | **2002** |        | **2001**    |
|--------------------------------------------------|---------------------------------------------|----------------------------|--------------|----------|-------------|-------------|
|                                             |                                        | **(thousands of dollars)** |
| Federal income tax expense at 35% statutory rate | $                                           | 8,911                 |         | $        | 3,684  |        | $ | 66,451  |
| Change in taxes resulting from:                  |                                        |                       |         |     |        |        |   |   |
|                                             | AFDC                                        |                       | (2,343)      |     |        | (948)       |   |   | (1,571) |
|                                             | Investment tax credits                      |                       | (3,397)      |     |        | (3,179)     |   |   | (3,169) |
|                                             | Repair allowance                            |                       | (2,450)      |     |        | (2,450)     |   |   | (2,800) |
|                                             | Capitalized overhead costs                  |                       | (3,658)      |     |        | (3,500)     |   |   | -  |
|                                             | Tax accounting method change                |                       | -       |     |        | (31,162)    |   |   | -  |
|                                             | Settlement of prior years tax returns       |                       | (8,911)      |     |        | (2,971)     |   |   | (1,530) |
|                                             | State income taxes, net of federal benefit  |                       | 1,357   |     |        | 514    |   |   | 8,506  |
|                                             | Depreciation                                |                       | 10,237  |     |        | 8,940  |   |   | 9,790  |
|                                             | Affordable housing and historic tax credits |                       | (20,345)     |     |        | (20,863)    |   |   | (13,080) |
|                                             | Preferred dividends of IPC                  |                       | 1,200   |     |        | 1,606  |   |   | 1,890  |
|                                             | Other, net                                  |                       | (1,720)      |     |        | (818)       |   |   | 159  |
| Total income tax (benefit) expense               | $                                           | (21,119)                   |         | $        | (51,147)    |        | $ | 64,646  |
|                                             | Effective tax rate                          |                       | (83.0%)      |     |        | (486.0%)    |   |   | 34.2% |
|                                             |                                        |                       |         |     |        |        |   |   |   |

 

The items comprising incometax expense are as follows:
|                                         |     | **2003**                   |         | **2002**     |     | **2001**     |
|----------------------------------------------|----------|----------------------------|--------------|--------------|----------|--------------|
|                                         |     | **(thousands of dollars)** |
| Income taxes currently payable (receivable): |     |                       |         |         |     |         |   |   |
|                                         | Federal  | $                          | 30,666  |         | $        | 50,522  |   | $ | (69,557) |
|                                         | State    |                       | 10,200  |         |     | 8,997   |   |   | (18,735) |
|                                         |     | Total                      |         | 40,866  |     |         | 59,519  |   |   | (88,292) |
| Income taxes deferred:                       |     |                       |         |         |     |         |   |   |
|                                         | Federal  |                       | (49,248)     |         |     | (99,166)     |   |   | 124,949  |
|                                         | State    |                       | (12,966)     |         |     | (11,044)     |   |   | 26,023  |
|                                         |     | Total                      |         | (62,214)     |     |         | (110,210) |   |   | 150,972  |
| Investment tax credits:                      |     |                       |         |         |     |         |   |   |
|                                         | Deferred |                       | 3,627   |         |     | 2,722   |   |   | 5,135  |
|                                         | Restored |                       | (3,398)      |         |     | (3,178)      |   |   | (3,169) |
|                                         |     | Total                      |         | 229     |     |         | (456) |   |   | 1,966  |
| Total income tax (benefit) expense           | $        | (21,119)                   |         | $            | (51,147) |         | $ | 64,646  |
|                                         |     |                       |         |         |     |         |   |   |   |

 

The components of IDACORP'snet deferred tax liability are as follows:
|                         | **2003**                      |    | **2002** |
|------------------------------|-------------------------------|---------|----------|
|                         | **(thousands  of dollars)**   |
| Deferred tax assets:         |                          |    |     |   |   |
|                         | Regulatory liabilities        | $       | 41,024   |   | $ | 41,013 |
|                         | Advances for construction     |    | 4,162    |   |   | 3,759 |
|                         | Other                         |    | 21,638   |   |   | 21,524 |
|                         |                          | Total   |     | 66,824 |   |   | 66,296 |
| Deferred tax liabilities:    |                          |    |     |   |   |
|                         | Property, plant and equipment |    | 238,602  |   |   | 230,935 |
|                         | Other regulatory assets       |    | 330,833  |   |   | 327,933 |
|                         | Conservation programs         |    | 8,310    |   |   | 10,426 |
|                         | PCA                           |    | 27,529   |   |   | 53,324 |
|                         | Net energy trading assets     |    | -        |   |   | 45,711 |
|                         | Other                         |    | 21,904   |   |   | 14,990 |
|                         |                          | Total   |     | 627,178 |   |   | 683,319 |
| Net deferred tax liabilities | $                             | 560,354 |     | $ | 617,023 |

 

**Status of Audit Proceedings**Federal income tax returns for years through 2000 have been examined by theInternal Revenue Service and substantially all issues have been settled.Settlements resulted in deficiencies that were less than previously accrued,enabling IDACORP to decrease income tax expense by $9 million (principally inthe fourth quarter) in 2003 and $3 million in 2002.  Management believes that adequate provision for income taxes hasbeen made for the open years 2001 and after, and any unsettled issues prior to 2001.

**Tax Credits**As of December 31, 2003, IDACORP had $4 million of general businesscredit carryforward for federal income tax purposes.  Additionally, IDACORP had $6 million of Idaho ITC carryforward.  The general business credit carryforwardperiod expires in 2023 and the Idaho ITC expires from 2015 to 2017.  Management believes the utilization of thesecredits is more likely than not.

**Tax Accounting Method Change**During the third quarter of 2002, IDACORP filed its 2001 federalincome tax return and adopted a change to IPC's tax accounting method forcapitalized overhead costs.  The formermethod allocated such costs primarily to construction of plant, while the newmethod allocates such costs to both construction of plant and the production ofelectricity.

The effect of the taxaccounting method change was recorded as a decrease to income tax expense forthe year ended December 31, 2002 of $35 million, of which $31 million wasattributable to 2001 and prior tax years, and $4 million was attributable tothe 2002 tax year.  The decrease to taxexpense was a result of deductions on the applicable tax returns of costs thatwere capitalized into fixed assets for financial reporting purposes.  Deferred income tax expense was not providedbecause 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.

**3.  COMMON STOCK:**

At December 31, 2003 and 2002,common stock was reserved for the following purposes:
|                                                            | **2003**     |      | **2002**  |
|-----------------------------------------------------------------|--------------|-----------|-----------|
| Contingently issuable in  connection with business combinations | 23,989       |      | 50,732    |
| Dividend reinvestment and  stock purchase plan and employee     |         |      |      |
|                                                            | savings plan | 6,062,314 |      | 3,751,236 |
| Restricted stock plan                                           | 314,114      |      | 314,114   |
| Long-term incentive and  compensation plan                      | 2,050,000    |      | 2,050,000 |
|                                                            | Total        | 8,450,417 |      | 6,166,082 |
|                                                            |         |      |      |

 

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 242,371 shares to theshareholders of the acquired entity.  Ofthe remaining acquired shares, 71,755 have been issued, primarily in connectionwith its Dividend Reinvestment Program (DRIP).

IDACORP has issued shares ofcommon stock for its DRIP and Employee Savings Plan (ESP) (see Note 10).  In 2003, IDACORP issued 122,990 shares forthe DRIP and 65,932 shares for the ESP. In 2002, IDACORP issued 321,236 shares for the DRIP and 202,281 sharesfor the ESP.  In 2001, IDACORP issued16,568 shares for the ESP.

**ShareholderRights 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 purchase,for $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 wereheld by an Acquiring Person become void if any of these events occurs.  The Rights expire on September 30, 2008.

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

**4.  PREFERRED STOCK OF IDAHO POWER COMPANY:**

The number of shares of IPCpreferred stock outstanding at December 31, 2003 and 2002 were as follows:
|                                            | **Shares Outstanding at**                        |            |            |
|-------------------------------------------------|--------------------------------------------------|-----------------|-----------------|
|                                            | **December 31,**                                 |            | **Call  Price** |
|                                            | **2003**                                         |            | **2002**        |   | **Per  Share** |
| Preferred stock:                                |                                             |            |            |   |   |
| Cumulative, $100 par value:                     |                                             |            |            |   |   |
|                                            | 4% preferred stock (authorized 215,000 shares)   | 123,664         |            | 133,927 |   | $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) | 250,000         |   | 250,000 |   | $100.354  - $103.535 |
|                                            |                                             | Total           | 523,664         |   | 533,927 |   |   |
|                                            |                                             |            |            |   |   |

 

During 2003, 2002 and 2001,IPC reacquired and retired 10,263, 9,945 and 6,784 shares of 4% preferredstock, respectively.  As of December 31,2003, the overall effective cost of all outstanding preferred stock was 6.54percent.

The voting rights of IPC'scommon stock and preferred stock are as follows:

Each share of commonstock, $2.50 par value, is entitled to one vote;

Each share of 4%Preferred Stock, $100 par value, is entitled to 20 votes;

Each share of 7.68%Series, Serial Preferred Stock, $100 par value, is entitled to one vote; and

Holders of shares of7.07% Series, Serial Preferred Stock, without par value, are not entitled tovote.

 

 

**5.  LONG-TERM DEBT:**

The following table summarizeslong-term debt at December 31:
|                                                                                             | **2003**                                                |                                  | **2002**        |
|--------------------------------------------------------------------------------------------------|---------------------------------------------------------|---------------------------------------|-----------------|
|                                                                                             | **(thousands of dollars)**                              |
| First mortgage bonds:                                                                            |                                                    |                                  |            |   |   |
|                                                                                             | 6.40%    Series  due 2003                | $                                     | -               |   | $ | 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    |   |   | 100,000  |
|                                                                                             | 4.25%    Series  due 2013                |                                  | 70,000     |   |   | -  |
|                                                                                             | 7.50%    Series  due 2023                |                                  | -          |   |   | 80,000  |
|                                                                                             | 6     %   Series due 2032 |                                  | 100,000    |   |   | 100,000  |
|                                                                                             | 5.50 %   Series  due 2033                     |                                  | 70,000     |   |   | -  |
|                                                                                             |                                                    | Total first mortgage bonds            |            | 730,000  |   |   | 750,000  |
| Pollution control revenue bonds :                                                                |                                                    |                                  |            |   |   |
|                                                                                             | 8.30%    Series  1984 due 2014 (a)       |                                  | -          |   |   | 49,800  |
|                                                                                             | Variable Auction Rate Series 2003 due 2024 (a)          |                                  | 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                                                                                        |                                                    | 1,105                            |            |   | 1,185  |
| American Falls bond guarantee                                                                    |                                                    | 19,885                           |            |   | 19,885  |
| Milner Dam note guarantee                                                                        |                                                    | 11,700                           |            |   | 11,700  |
| Unamortized premium/discount - net                                                               |                                                    | (2,205)                               |            |   | (2,405) |
| Debt related to investments in affordable housing                                                |                                                    | 82,715                           |            |   | 37,428  |
| Other subsidiary debt                                                                            |                                                    | 97                               |            |   | 15  |
|                                                                                             | Total                                                   |                                  | 1,013,757  |   |   | 988,268  |
| Current maturities of long-term debt                                                             |                                                    | (67,923)                              |            |   | (89,592) |
|                                                                                             |                                                    | Total long-term debt                  | $               | 945,834  |   | $ | 898,676  |
| (a)   Humboldt County Pollution Control Revenue bonds are secured by first  mortgage bonds. |

 

At December 31, 2003, thematurities for the aggregate amount of long-term debt outstanding were (inthousands of dollars):
|                  | **2004** | **2005** | **2006** | **2007** | **2008** | **Thereafter** |
|-----------------------|----------|----------|----------|----------|----------|----------------|
|                  |     |     |     |     |     |           |   |   |   |   |   |   |
| IPC                   | $        | 50,077   | $        | 60,079   | $        | 82             | $ | 81,228 | $ | 1,116 | $ | 738,363 |
| Other subsidiary debt |     | 17,846   |     | 17,229   |     | 15,576         |   | 13,723 |   | 10,213 |   | 8,225 |
| Total                 | $        | 67,923   | $        | 77,308   | $        | 15,658         | $ | 94,951 | $ | 11,329 | $ | 746,588 |

 

IDACORP currently has twoshelf registration statements totaling $800 million that can be used for theissuance of unsecured debt (including medium-term notes) and preferred orcommon stock.  At December 31, 2003, nonehad been issued.

On October 22, 2003, Humboldt County, Nevada issued, forthe benefit of IPC, $49.8 million Pollution Control Revenue Refunding Bonds(Idaho Power Company Project) Series 2003 due December 1, 2024.  IPC borrowed the proceeds from the issuancepursuant to a Loan Agreement with Humboldt County and is responsible forpayment of principal, premium, if any, and interest on the bonds. The bonds aresecured, as to principal and interest, by IPC first mortgage bonds and as toprincipal and interest when due, by an insurance policy issued by AmbacAssurance Corporation. The bonds were issued in an auction rate mode underwhich the interest rate is reset every 35 days. The initial auction rate wasset at 0.95 percent. At December 31, 2003 the auction rate was 1.15 percent.  Proceeds from this issuance together withother funds provided by IPC were used to redeem the outstanding $49.8 millionPollution Control Revenue Bonds (Idaho Power Company Project) 8.3% Series 1984due 2014, on December 1, 2003, at 103%.

On November 15, 2002, IPC issued $200 million of securedmedium-term notes in two series: $100 million First Mortgage Bonds 4.75% Seriesdue 2012 and $100 million First Mortgage Bonds 6.00% Series due 2032.   Proceeds were used to pay down IPCshort-term borrowings.

On March 14, 2003, IPC filed a $300 million shelfregistration statement that could be used for first mortgage bonds (includingmedium-term notes), unsecured debt and preferred stock.  On May 8, 2003, IPC issued $140 million of securedmedium-term notes in two series: $70 million First Mortgage Bonds 4.25% Seriesdue 2013 and $70 million First Mortgage Bonds 5.50% Series due 2033. Proceedswere used to pay down IPC short-term borrowings incurred from the maturity andpayment of $80 million First Mortgage Bonds 6.40% Series due 2003 and the earlyredemption of $80 million First Mortgage Bonds 7.50% Series due 2023, on May 1,2003.  At December 31, 2003, $160million remained available to be issued on this shelf registration statement.

The amount of first mortgagebonds issuable by IPC is limited to a maximum of $1.1 billion and by property,earnings and other provisions of the mortgage and supplemental indenturesthereto.  IPC may amend the indentureand increase this amount without consent of the holders of the first mortgagebonds.  Substantially all of theelectric utility plant is subject to the lien of the mortgage.  As of December 31, 2003, IPC could issueunder the mortgage approximately $945 million of additional first mortgagebonds based on unfunded property additions and $342 million of additional firstmortgage bonds based on retired first mortgage bonds.  At December 31, 2003, unfunded property additions, which consistof electric property, were approximately $1 billion.

In August 2001, $25 millionFirst Mortgage Bonds 9.52% Series due 2031 were redeemed early using short-termborrowings.  Also, in March2002, $50 million First Mortgage Bonds 8.75% Series due 2027 were redeemedearly using short-term borrowings.

At December 31, 2003 and 2002,the overall effective cost of all outstanding first mortgage bonds andpollution control revenue bonds was 5.71 percent and 6.51 percent,respectively.

At December 31, 2003, IFS had$83 million of debt with interest rates ranging from 3.65 percent to 8.59percent due 2004 to 2010.  This debt iscollateralized by investments in affordable housing developments with a netbook value of $116 million at December 31, 2003.

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

The estimated fair value of IDACORP'sfinancial instruments has been determinedusing available market information and appropriate valuationmethodologies.  The use of differentmarket assumptions and/or estimation methodologies may have a material effecton the estimated fair value amounts.

Cash and cash equivalents,customer and other receivables, notes payable, accounts payable, interestaccrued and taxes accrued are reported at their carrying value as these are areasonable estimate of their fair value. The estimated fair values for notesreceivable, long-term debt and investments and other property are based uponquoted market prices of the same or similar issues or discounted cash flowanalyses as appropriate.
|                          | **December  31, 2003** |      | **December  31, 2002** |
|-------------------------------|------------------------|-----------|------------------------|
|                          | **Carrying**           |      | **Estimated**          |   | **Carrying** |   | **Estimated** |
|                          | **Amount**             |      | Fair Value             |   | **Amount** |   | **Fair  Value** |
| **Assets:**                   |                   |      |                   |   |   |   |   |   |   |   |   |
| Notes receivable              | $                      | 11,576    |                   | $ | 11,590 |   | $ | 13,654 |   | $ | 11,863 |
| Investment and other property |                   | 39,376    |                   |   | 39,630 |   |   | 28,302 |   |   | 28,700 |
|                          |                   |      |                   |   |   |   |   |   |   |   |   |
| **Liabilities:**              |                   |      |                   |   |   |   |   |   |   |   |   |
| Long-term debt                | $                      | 1,015,962 |                   | $ | 1,043,116 |   | $ | 989,673 |   | $ | 1,054,193 |
|                          |                   |      |                   |   |   |   |   |   |   |   |   |

 

**7.  NOTES PAYABLE:**

At December 31, 2003, IDACORPhad a $175 million credit facility that expires March 17, 2004, and a $140million credit facility that expires March 25, 2005.  Under these facilities IDACORP pays a facility fee on thecommitment, quarterly in arrears, based on its corporate credit rating.  Commercial paper may be issued up to theamounts supported by the bank credit facilities.

IPC has a $200 million creditfacility that expires March 17, 2004. 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. At December 31, 2003, IPC had regulatoryauthority to incur up to $250 million of short-term indebtedness. 

Balances and interest rates ofshort-term borrowings were as follows at December 31 (in thousands of dollars):
|                     | **IDACORP** |   | **IPC**  |
|--------------------------|-------------|--------|----------|
|                     | **2003**    |   | **2002** |   | **2003** |   | **2002** |
| Balance                  | $           | 93,650 |     | $ | 176,200 |   | $ | - |   | $ | 10,500 |
| Effective  interest rate |        | 1.21%  |     |   | 1.83% |   |   | - |   |   | 1.65% |
|                     |        |   |     |   |   |   |   |   |   |   |   |

 

**8.  COMMITMENTS AND CONTINGENT LIABILITIES:**

As of December 31, 2003, IPC had signed agreements topurchase energy from 69 cogeneration and small power production (CSPP)facilities with contracts ranging from one to 30 years.  Under these contracts IPC is required topurchase all of the output from the facilities inside the IPC serviceterritory.  For projects outside the IPCservice territory, IPC is required to purchase the output which IPC has theability to receive at the facility's requested point of delivery on the IPCsystem.  IPC purchased 654,131 MWh at acost of $38 million in 2003 and 692,414 Megawatt-hour (MWh) at a cost of $44million in 2002.

IPC has agreed to guarantee the performance ofreclamation activities at Bridger Coal Company of which Idaho Energy ResourcesCompany, a subsidiary of IPC, owns a one-third interest.  This guarantee, which is renewed eachDecember, was $60 million at December 31, 2003. Bridger Coal Company has areclamation trust fund set aside specifically for the purpose of paying thesereclamation costs and expects that the fund will be sufficient to cover allsuch costs.  Because of the existence ofthe fund, the estimated fair value of this guarantee is minimal.  

In August 2003, IE sold its forward book of electricitytrading contracts to Sempra Energy Trading (SET).  As part of the sale of the forward book of electricity contractsIE entered into an Indemnity Agreement with SET, guaranteeing the performanceof one of the counterparties.  Themaximum amount payable by IE under the Indemnity Agreement is $20 million.  The indemnity agreement has been accountedfor in accordance with FIN 45 and did not have a significant effect on thefinancial statements.

From time to time IDACORP and IPC are a party to variouslegal claims, actions and complaints in addition to those discussed below.  IDACORP and IPC believe that they havemeritorious defenses to all lawsuits and legal proceedings.  Although they will vigorously defend againstthem, they are unable to predict with certainty whether or not they willultimately be successful.  However,based on the companies' evaluation, they believe that the resolution of thesematters will not have a material adverse effect on IDACORP's or IPC'sconsolidated financial positions, results of operations or cash flows.

**Legal Proceedings****Vierstra Dairy v. Idaho Power Company: **On August 11, 2000, Mike andSusan Vierstra, dairy operators from Twin Falls, Idaho, brought suit againstIPC in Idaho State District Court, Fifth Judicial District, Twin FallsCounty.  The plaintiffs sought monetarydamages in the amount of approximately $8 million for negligence and nuisance(allegedly allowing electrical current to flow in the earth and adverselyaffect the health of plaintiffs' dairy cows) and punitive damages in the amountof approximately $40 million.

On February 10, 2004, a juryverdict in favor of the plaintiffs was entered, awarding approximately $7million in compensatory damages and $10 million in punitive damages.  IPC intends to appeal this decision.

IPC is unable to predict theoutcome of this matter; however, based upon the information provided to date,IPC's insurance carrier has confirmed coverage.  IPC has previously expensed the full amount of its self-insuredretention.  With coverage, this matterwill not have a material adverse effect on IPC's consolidated financialposition, 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., an inactive 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 thecontract, IDACORP Services authorized United Systems to do business as"IDACORP Solutions."  The contractwas to be effective from January 2001 through December 2005.

In November 2001, IDACORPServices Co. notified United Systems that IDACORP Services Co. was terminatingthe contract for convenience.  Thecontract allowed for such termination but required the terminating party tocompensate the other party for all costs incurred in preparation for, and inperformance of the contract, and for reasonable net profit for the remainingterm of the contract.  United Systemsclaimed $7 million in net profits lost and costs incurred.

IDACORP Services Co. assertedthat termination related compensation owed to United Systems, if any, wassubstantially less 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 Co. On October 4, 2002, United Systems filed a Motion for Partial SummaryJudgment as to its damages.  On July 9,2003, the Court denied Plaintiff's Motion for Partial Summary Judgment andgranted Defendants' Motion to Bifurcate. On October 29, 2003, IDACORP agreed to pay $712,500 to settle thisdispute with United Systems in return for dismissal of the proceeding withprejudice.  The settlement was finalizedon November 26, 2003.  An Order ofDismissal with Prejudice as to All Defendants was entered on December 2, 2003.

**Public Utility District No. 1of Grays Harbor County, Washington:**  On October 15, 2002, Public Utility District No. 1 of GraysHarbor County, Washington (Grays Harbor) filed a lawsuit in the Superior Courtof the State of Washington, for the County of Grays Harbor, against IDACORP,IPC and IE.  On March 9, 2001, GraysHarbor entered into a 20 Megawatt (MW) purchase transaction with IPC for thepurchase of electric power from October 1, 2001 through March 31, 2002, at arate of $249 per MWh.  In June 2001,with the consent of Grays Harbor, IPC assigned all of its rights andobligations under the contract to IE. In its lawsuit, Grays Harbor alleged that the assignment was void andunenforceable, and sought restitution from IE and IDACORP, or in thealternative, Grays Harbor alleged that the contract should be rescinded orreformed.  Grays Harbor sought asdamages an amount equal to the difference between $249 per MWh and the"fair value" of electric power delivered by IE during the periodOctober 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 lackedjurisdiction because the FERC has exclusive jurisdiction over wholesale powertransactions and thus the matter is preempted under the Federal Power Act (FPA)and barred by the filed-rate doctrine. The court ruled in favor of the companies' motion to dismiss anddismissed the case with prejudice on January 28, 2003.  On February 25, 2003, Grays Harbor filed aNotice of Appeal, appealing the final judgment of dismissal to the UnitedStates Court of Appeals for the Ninth Circuit. Briefing on the appeal was completed in August 2003, but the court hasyet to set a date for oral argument. The companies intend to vigorously defend their position on appeal andbelieve this matter will not have a material adverse effect on theirconsolidated financial positions, results of operations or cash flows.

**Port of Seattle:**  On May 21, 2003, the Port of Seattle, aWashington municipal corporation, filed a lawsuit against 20 energy firms,including IPC and IDACORP, in the United States District Court for the WesternDistrict of Washington at Seattle.  ThePort of Seattle's complaint alleges fraud and violations of state and federalantitrust law and the Racketeering Influenced and Corrupt OrganizationAct.  On December 4, 2003, the JudicialPanel on Multidistrict Litigation transferred the case to the Southern Districtof California for inclusion with several similar multidistrict actionscurrently pending before the Honorable Robert H. Whaley (the same judge whoheard the Public Utility District No. 1 of Snohomish County, Washington case).

Alldefendants, including IPC and IDACORP, have moved to dismiss the complaint inlieu of answering it.  The motions areall based on the ground that the complaint seeks to set alternative electricalrates, which are exclusively within the jurisdiction of the FERC and are barredby the filed-rate doctrine.  Briefing onthese motions was completed in early February 2004.  A hearing on the motion to dismiss is scheduled for March 26,2004.  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.

**Stateof California Attorney General:**  The California Attorney General (AG) filed the complaint in thiscase in the California Superior Court in San Francisco on May 30, 2002.  This is one of thirteen virtually identicalcases brought by the AG against various sellers of power in the Californiamarket, seeking civil penalties pursuant to California's unfair competition law- California Business and Professions Code Section 17200.  Section 17200 defines unfair competition asany "unlawful, unfair or fraudulent business act or practice. . ."  The AG alleges that IPC engaged in unlawfulconduct by violating the FPA in two respects: (1) by failing to file its rates with the FERC as required by the FPA;and (2) charging unjust and unreasonable rates in violation of the FPA.  The AG alleged that there were"thousands of . . . sales or purchases" for which IPC failed to fileits rates, and that IPC charged unjust and unreasonable rates on"thousands of occasions." Pursuant to Business and Professions Code Section 17206, the AG seekscivil penalties of up to $2,500 for each alleged violation.  On June 25, 2002, IPC removed the action tofederal court, and on July 25, 2002, the AG filed a motion to remand back tostate court.  On March 25, 2003, thecourt denied the AG's motion to remand and granted IPC's motion to dismiss thecase based upon grounds of federal preemption and the filed-rate doctrine.  On March 28, 2003, the AG filed a Notice ofAppeal, appealing the court's final judgment dismissing the action to theUnited States Court of Appeals for the Ninth Circuit.  The briefing on the appeal was completed on October 31, 2003.  The Court has yet to set a date for oralargument.  IPC intends to vigorouslydefend its position on appeal and believes this matter will not have a materialadverse effect on its consolidated financial positions, results of operationsor cash flows.

**Wholesale Electricity AntitrustCases I & II:**  Thesecross-actions against IE and IPC emerged from multiple California state courtproceedings first initiated in late 2000 against various powergenerators/marketers by various California municipalities and citizens,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 and federalagencies) removed that litigation to federal court.  IPC and IE, together with numerous other defendants added by thecross-complaints, have moved to dismiss these claims, and those motions wereheard in September 2002, together with motions to remand the case back to statecourt filed by the original plaintiffs. On December 13, 2002, the Federal District Court granted Plaintiffs'Motion to Remand to state court, but did not issue a ruling onIPC and IE's motion to dismiss.  TheNinth Circuit has granted certain Defendants and Cross-Defendants' Motions toStay the Remand Order while they appeal the Order.  The briefing on the appeal was completed in December 2003.  The court has yet to set a date for oralargument, and a decision by the Ninth Circuit is expected in mid-2004.  As a result of the various motions, no trialdate is set.  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.

**Class Action Complaints Relating to Trades on the NewYork Mercantile Exchange:**  On August18, 2003, Cornerstone Propane Partners, L.P. (Cornerstone), on behalf of itselfand others who allegedly purchased and sold natural gas futures and optionscontracts on the New York Mercantile Exchange from January 1, 2000 to December31, 2002, filed a class action complaint in the United States District Courtfor the Southern District of New York against more than 30 defendants,including IDACORP and IPC.  On November14, 2003, an individual, Dominick Viola (Viola), filed a substantively similarcomplaint in the United States District Court for the Southern District of NewYork, on behalf of himself and others allegedly similarly situated, againstmore than 30 defendants, including IDACORP and IPC.  The Cornerstone and Viola actions have been consolidated.  The complaints claim that the defendantsreported inaccurate trading information to various trade publications thatcompile and publish indices of natural gas prices and that the defendants engagedin various improper trades on the Enron Online internet-based trading platform,the alleged purpose of which was to improperly inflate the prices of naturalgas.  The plaintiffs seek class actioncertification and damages for alleged violations of the Commodity Exchange Actand for aiding and abetting such violations.

IDACORP and IPC provided the plaintiffs with informationthat refutes all of the allegations contained in the complaints.  The plaintiffs agreed to dismiss the actionsagainst IDACORP and IPC, without prejudice to resume the actions if additionalinformation is learned in the course of the actions still pending against otherdefendants.  IDACORP and IPC are nolonger named as defendants in the actions.

**California Energy Proceedings at the FERC:**California Power Exchange ChargebackAs a component of IPC's non-utility energy trading in the state ofCalifornia, IPC, in January 1999, entered into a participation agreement withthe California Power Exchange (CalPX), a California non-profit public benefitcorporation.  The CalPX, at that time,operated a wholesale electricity market in California by acting as aclearinghouse through which electricity was bought and sold.  Pursuant to the participation agreement, IPCcould sell power to the CalPX under the terms and conditions of the CalPXTariff.  Under the participationagreement, if a participant in the CalPX exchange defaulted on a payment to theexchange, the other participants were required to pay their allocated share ofthe default amount to the exchange.  Theallocated shares were based upon the level of trading activity, which includedboth power sales and purchases, of each participant during the precedingthree-month period.

On January 18, 2001, the CalPX sent IPC an invoice for $2million - a "default share invoice" - as a result of an allegedSouthern California Edison (SCE) payment default of $215 million for powerpurchases.  IPC made this payment.  On January 24, 2001, IPC terminated theparticipation 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, Pacific Gas and ElectricCompany (PG&E) and others.  However,because the CalPX owed IPC $11 million for power sold to the CalPX in Novemberand December 2000, IPC did not pay the February 8th invoice.  IPC essentially discontinued energy tradingwith the CalPX and the California Independent System Operator (Cal ISO) inDecember 2000.

IPC believes that the default invoices were not properand that IPC owes no further amounts to the CalPX.  IPC has pursued all available remedies in its efforts to collectamounts owed to it by the CalPX.  OnFebruary 20, 2001, IPC filed a petition with the FERC to intervene in aproceeding that requested the FERC to suspend the use of the CalPX charge backmethodology and provides for further oversight in the CalPX's implementation ofits default mitigation procedures.

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

In April 2001, PG&E filed for bankruptcy.  The CalPX and the Cal ISO were among thecreditors of PG&E.  To the extentthat PG&E's bankruptcy filing affects the collectibility of the receivablesfrom the CalPX and the Cal ISO, the receivables from these entities are atgreater risk.

The FERC issued an order on April 6, 2001 requiring theCalPX to rescind all chargeback actions related to PG&E's and SCE'sliabilities.  Shortly after that time,the CalPX segregated the CalPX chargeback amounts it had collected in aseparate account.  The CalPX claims itis awaiting further orders of the FERC and the bankruptcy court beforedistributing the funds that it collected under its chargeback tariff mechanism.  Although certain parties to the Californiarefund proceeding urged the FERC's Presiding Administrative Law Judge (ALJ) toconsider the chargeback amounts in his determination of who owes what to whom,in his Certification of Proposed Findings on California Refund Liability, heconcluded that the matter already was pending before the FERC for disposition.

California RefundIn April 2001, the FERC issued an order stating that it wasestablishing price mitigation for sales in the California wholesale electricitymarket.  Subsequently, in its June 19,2001 order, the FERC expanded that price mitigation plan to the entire westernUnited States electrically interconnected system.  That plan included the potential for orders directing electricitysellers into California since October 2, 2000 to refund portions of their spotmarket sales prices if the FERC determined that those prices were not just andreasonable, and therefore not in compliance with the FPA.  The June 19 order also required all buyersand sellers in the Cal ISO market during the subject time-frame to participatein settlement discussions to explore the potential for resolution of theseissues without further FERC action.  Thesettlement discussions failed to bring resolution of the refund issue and as aresult, the FERC's Chief ALJ submitted a Report and Recommendation to the FERCrecommending that the FERC adopt the methodology set forth in the report andset for evidentiary hearing an analysis of the Cal ISO's and the CalPX's spotmarkets to determine what refunds may be due upon application of thatmethodology.

On July 25, 2001, the FERC issued an order establishingevidentiary hearing procedures related to the scope and methodology forcalculating refunds related to transactions in the spot markets operated by theCal ISO and the CalPX during the period October 2, 2000 through June 20,2001.  As to potential refunds, if any,IE believes its exposure is likely to be offset by amounts due from Californiaentities.  Multiple parties have filedrequests for rehearing and petitions for review.  The latter, more than 60, have been consolidated by the UnitedStates Court of Appeals for the Ninth Circuit and held in abeyance while theFERC continues its deliberations.  TheNinth Circuit also directed the FERC to permit the parties to adduce additionalevidence respecting market manipulation. See "Market Manipulation" below.

On March 20, 2002, the AG filed a complaint with the FERCagainst various sellers in the wholesale power market, including IE and IPC,alleging that the FERC's market-based rates violate the FPA, and, even ifmarket-based rate requirements are valid, that the quarterly transactionreports filed by sellers do not contain the transaction-specific informationmandated by the FPA and the FERC.  Thecomplaint stated that refunds for amounts charged between market-based ratesand cost-based rates should be ordered. The FERC denied the challenge to market-based rates and refused to orderrefunds, but did require sellers, including IE and IPC, to refile theirquarterly reports to include transaction-specific data.  The AG appealed the FERC's decision to theUnited States Court of Appeals for the Ninth Circuit.  The AG contends that the failure of all market-based rateauthority sellers of power to have rates on file with the FERC in advance ofsales is impermissible.  The NinthCircuit heard oral arguments on October 9, 2003, but has not specified the dateon which it will issue a decision.  Thecompanies cannot predict the outcome of this matter.

This case had been further complicated by an August 13,2002 FERC Staff (Staff) Report which included the recommendation to replace thepublished California indices for gas prices that the FERC previouslyestablished as just and reasonable for calculating a Mitigated Market ClearingPrice (MMCP) to calculate refunds with other published indices for producingbasin prices plus a transportation allowance. The Staff's recommendation is grounded on speculation that some sellershad an incentive to report exaggerated prices to publishers of the indices,resulting in overstated published index prices.  Staff based its speculation in large part on a statisticalcorrelation analysis of Henry Hub and California prices.  IE, in conjunction with others, submittedcomments on the Staff recommendation - asserting that the Staff's conclusionswere incorrect because the Staff's correlation study ignored evidence of normalmarket forces and scarcity that created the pricing variations that the Staffobserved, rather than improper manipulation of reported prices.

TheALJ issued a Certification of Proposed Findings on California Refund Liabilityon December 12, 2002.

The FERC issued its Order on Proposed Findings onRefund Liability on March 26, 2003.  Inlarge part, the FERC affirmed the recommendations of its ALJ.  However, the FERC changed a component of theformula the ALJ was to apply when it adopted findings of its staff thatpublished California spot market prices for gas did not reliably reflect theprices a gas market that had not been manipulated would have produced, despitethe fact that many gas buyers paid those amounts.  The findings of the ALJ, as adjusted by the FERC's March 26, 2003order, are expected to increase the offsets to amounts still owed by the CalISO and the CalPX to the companies. Calculations remain uncertain because the FERC has required the Cal ISOto correct a number of defects in its calculations and because the FERC hasstated that if refunds will prevent a seller from recovering its Californiaportfolio costs during the refund period, it will provide an opportunity for acost showing by such a respondent.  As aresult, IE is unsure of the impact this ruling will have on the refunds duefrom California.

IE, along with a number of other parties, filed anapplication with the FERC on April 25, 2003 seeking rehearing of the March 26,2003 order.  On October 16, 2003, theFERC issued two orders denying rehearing of most contentions that had beenadvanced and directing the Cal ISO to prepare its compliance filing calculatingrevised MMCPs and refund amounts within five months.  The Cal ISO has since requested additional time to complete itscompliance filings.  By order of February3, 2004, the Commission granted additional time.  In a February 10, 2004 report to the Commission, the Cal ISOasserted its belief that it will complete re-running the data and financialclearing of amounts due by August 2004, subject to a number of events that mustoccur in the interim, including Commission disposition of a number of pendingissues.  The Cal ISO is required toupdate the Commission on its progress monthly. After that time, the FERC will consider cost-based filings from sellersto reduce their refund exposure.  OnDecember 2, 2003 IDACORP petitioned for review of the FERC's orders, and sincethat time, dozens of other petitions for review have been filed.  They have not yet been consolidated with oneanother or with the petitions for review of earlier FERC California refund ordersalready pending.  Certain parties alsosought further rehearing before the FERC. These latter applications remain pending before the FERC.  The Ninth Circuit has held the appeals inabeyance pending the disposition of the market manipulation claims discussedbelow and the development of a comprehensive plan to brief this complicatedcase.

In June 2001, IPC transferred its non-utility wholesaleelectricity marketing operations to IE. Effective with this transfer, the outstanding receivables and payableswith the CalPX and the Cal ISO were assigned from IPC to IE.  At December 31, 2003, with respect to theCalPX chargeback and the California Refund proceedings discussed above, theCalPX and the Cal ISO owed $14 million and $30 million, respectively, forenergy sales made to them by IPC in November and December 2000.  IE has accrued a reserve of $42 millionagainst these receivables.  This reservewas calculated taking into account the uncertainty of collection, given theCalifornia energy situation.  Based onthe reserve recorded as of December 31, 2003, IDACORP believes that the futurecollectibility of these receivables or any potential refunds ordered by theFERC would not have a material adverse effect on its consolidated financialpositions, results of operations or cash flows.

Market ManipulationIn a November 20, 2002 order, the FERC permitted discovery and thesubmission of evidence respecting market manipulation by various sellers duringthe western power crises of 2000 and 2001.

On March 3, 2003, the California Parties (certain investorowned utilities, the California Attorney General, the California ElectricityOversight Board and the California Public Utilities Commission) filedvoluminous documentation asserting that a number of wholesale power suppliers,including IE and IPC, had engaged in a variety of forms of conduct that theCalifornia Parties contended were impermissible.  Although the contentions of the California Parties were containedin more than 11 compact discs of data and testimony, approximately 12,000pages, IE and IPC were mentioned in limited contexts - the overwhelmingmajority of the claims of the California Parties related to claims respectingthe conduct of other parties.

The California Parties urged the FERC to apply theprecepts of its earlier decision, to replace actual prices charged in everyhour starting May 1, 2000 through the beginning of the existing refund period(October 2, 2000) with a MMCP, seeking approximately $8 billion in refunds tothe Cal ISO and the CalPX.  On March 20,2003, numerous parties, including IE and IPC, submitted briefs and responsivetestimony.

In its March 26, 2003 order, discussed previously, theFERC declined to generically apply its refund determinations across the boardto sales by all market participants, although it stated that it reserved theright to provide remedies for the market against parties shown to have engagedin proscribed conduct.

OnJune 25, 2003, the FERC ordered over 50 entities that participated in thewestern wholesale power markets between January 1, 2000 and June 20, 2001,including IPC, to show cause why certain trading practices did not constitutegaming or anomalous market behavior in violation of the Cal ISO and the CalPXTariffs.  The Cal ISO was ordered to providedata on each entity's trading practices within 21 days of the order, and eachentity was to respond explaining their trading practices within 45 days ofreceipt of the Cal ISO data.  IPCsubmitted its responses to the show cause orders on September 2 and 4,2003.  On October 16, 2003, IPC reachedagreement with the Staff on the two orders commonly referred to as the"gaming" and "partnership" show cause orders.  Regarding the gaming order, the Staffdetermined it had no basis to proceed with allegations of false imports andpaper trading and IPC agreed to pay $83,373 to settle allegations of circularscheduling.  IPC believed that it haddefenses to the circular scheduling allegation but determined that the cost ofsettlement was less than the cost of litigation.  In the settlement, IPC did not admit any wrongdoing or violationof any law.  With respect to the"partnership" order, the Staff submitted a motion to the FERC todismiss the proceeding because materials submitted by IPC demonstrated that IPCdid not use the "parking" and "lending" arrangement withPublic Service Company of New Mexico to engage in "gaming" oranomalous market behavior ("partnership").  The "gaming" settlement was approved by the FERC onMarch 3, 2004 and is subject to rehearing requests for 30 days.  The motion to dismiss the"partnership" proceeding was approved by the FERC in an order issuedJanuary 23, 2004 and rehearing of that order was not sought within the timeallowed by statute.

On June 25, 2003, the FERC also issued an orderinstituting an investigation of anomalous bidding behavior and practices in thewestern wholesale power markets.  Inthis investigation, the FERC will review evidence of alleged economicwithholding of generation.  The FERC hasdetermined that all bids into the CalPX and the Cal ISO markets for more than$250 per MWh for the time period May 1, 2000 through October 1, 2000 will beconsidered prima facie evidence of economic withholding.  The FERC has issued data requests in thisinvestigation to over 60 market participants including IPC.  If it is determined that IPC engaged inimproper bidding, the FERC has indicated that sanctions may includedisgorgement of alleged profits and other non-monetary actions, includingpossible revocation of market-based rate authority and/or additional requiredprovisions in codes of conduct.  IPCreceived some information regarding these matters from the Cal ISO and on July24, 2003, IPC responded to the FERC's data requests.  Based on the information received to date from the Cal ISO,IDACORP and IPC believe that any potential penalties imposed by the FERC wouldnot have a material adverse effect on their consolidated financial positions,results of operations or cash flows.

**Pacific Northwest Refund:**  On July 25, 2001, the FERC issued an orderestablishing another proceeding to explore whether there may have been unjustand unreasonable charges for spot market sales in the Pacific Northwest duringthe period December 25, 2000 through June 20, 2001.  The FERC ALJ submitted recommendations and findings to the FERCon September 24, 2001.  The ALJ foundthat prices should be governed by the Mobile-Sierra standard of the publicinterest rather than the just and reasonable standard, that the PacificNorthwest spot markets were competitive and that no refunds should be allowed.Procedurally, the ALJ's decision is a recommendation to the commissioners ofthe FERC. Multiple parties have submitted comments to the FERC respecting theALJ's recommendations.  The ALJ'srecommended findings had been pending before the FERC, when at the request ofthe City of Tacoma and the Port of Seattle on December 19, 2002, the FERCreopened the proceedings to allow the submission of additional evidence relatedto alleged manipulation of the power market by Enron and others.  As was the case in the California refundproceeding, at the conclusion of the discovery period, parties alleging marketmanipulation were to submit their claims to the FERC and responses were due onMarch 20, 2003.  Grays Harbor, whosecivil litigation claims were dismissed, as noted above, has intervened in thisFERC proceeding, asserting on March 3, 2003 that its six month forwardcontract, for which performance has been completed, should be treated as a spotmarket contract for purposes of the FERC's consideration of refunds and isrequesting refunds from IPC of $5 million. Grays Harbor did not suggest that there was any misconduct by thecompany.  The company submittedresponsive testimony defending vigorously against Grays Harbor's refund claims.

In addition, the Port of Seattle, the City of Tacoma andSeattle City Light made filings with the FERC on March 3, 2003 claiming thatbecause some market participants drove prices up throughout the west throughacts of manipulation, prices for contracts throughout the Pacific Northwestmarket should be re-set starting in May 2000 using the same factors the FERCwould use for California markets. Although the majority of the claims of these parties are generic, theynamed a number of power market suppliers, including IPC and IE, as having usedparking services provided by other parties under FERC-approved tariffs and thusas being candidates for claims of having received incorrectly congestionrevenues from the Cal ISO.  On June 25,2003, after having considered oral argument held earlier in the month, the FERCissued its Order Granting Rehearing, Denying Request to Withdraw Complaint andTerminating Proceeding, in which it terminated the proceeding and required thatno refunds be paid.  TheCommission denied rehearing on November 10, 2003.  The Port of Seattle, the City of Tacoma, the City of Seattle, theCalifornia Attorney General and Puget Sound Energy Inc. filed petitions forreview in the Ninth Circuit within the time permitted.  These petitions have not yet been consolidated.  Grays Harbor did not file a petition forreview, although it has sought to intervene in the proceedings initiated by thepetitions of others.  In addition, theCalifornia Parties sought further rehearing of aspects of the FERC'sorders.  The FERC's order remainssubject to rehearing by the FERC and review by appellate courts.  The companies are unable to predict theoutcome of these matters.

**Nevada Power Company:**  In February and April of 2001, IPC enteredinto two transactions under the Western Systems Power Pool (WSPP) Agreementwhereby IPC agreed to deliver to Nevada Power Company (NPC) 25 MW during thethird quarter of 2002.  NPC agreed topay IPC $250 per MWh for heavy load deliveries and $155 per MWh for light loaddeliveries.  IPC assigned the contractsto IE with NPC's consent and the assignment was subsequently approved by theFERC.  Based upon the uncertainfinancial condition of NPC, and pursuant to the terms of the WSPP Agreement, IErequested NPC to provide assurances of its ability to pay for the power if IEmade the deliveries.  NPC failed toprovide appropriate credit assurances; therefore, in accordance with the WSPPAgreement procedures, IE terminated all WSPP Agreement transactions with NPC effectiveJuly 8, 2002.  Pursuant to the WSPPAgreement, IE notified NPC of the liquidated damages amount and NPC respondedwith a letter, which described their view of rights under the WSPP Agreementand suggested a negotiated resolution. IE and NPC unsuccessfully attempted to mediate a resolution to thisdispute.

IE filed a complaint against NPC on April 25, 2003, inIdaho State District Court in and for the County of Ada.  This complaint was served on NPC on May 14,2003.  IE asked the Idaho State DistrictCourt for damages in excess of $9 million pursuant to the contracts.  On June 17, 2003, NPC filed a motion todismiss IE's complaint alleging, among other things, that:  the Idaho State District Court lacks jurisdictionover NPC; a separate complaint seeking declaratory judgment was filed in theUnited States District Court, District of Nevada on May 14, 2003 by NPC againstIPC, IE and IDACORP involving the same subject matter as the complaint filed byIE against NPC; IE does not have standing to maintain certain claims againstNPC; Idaho is not a convenient forum to adjudicate the matter; and IE filed theaction in Idaho State District Court in violation of the WSPP Agreement.  NPC's motion to dismiss was heard onDecember 2, 2003.  The parties await theCourt's ruling.  NPC has never served IEwith the complaint for declaratory judgment filed in the United States DistrictCourt in Nevada.

On September 23, 2003, NPC filed and served IE, IPC, andIDACORP with a Declaratory Action filed with the Nevada State Court in and forthe County of Clark concerning the same subject matter of the pending IdahoState District Court action filed by IE on April 25, 2003.  NPC seeks declaratory judgment on thefollowing issues:  that the assignmentof the February and April 2001 energy supply contracts from IPC to IE is voidor voidable; that IE did not comply with the WSPP Agreement when requestingreasonable assurances; and that NPC is relieved of its obligations to pay underthe contracts by reason of force majeure. IE filed a motion to dismiss NPC's Nevada State Court claims.  That motion was heard, and denied, onNovember 17, 2003.

IE intends to vigorously prosecute the action it filed inIdaho State District Court. Furthermore, IPC, IE and IDACORP intend to vigorously defend againstNPC's claims filed in the State of Nevada.

At December 31, 2003, IE had a $4 million receivablerelated to the NPC contracts.

**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 contract provided for Overton to purchase 40-MW of electricalenergy per hour from IE at $88.50 per MWh from July 1, 2001 through June 30,2011.

IE asked the Idaho District Court for damages pursuant tothe contract, for a declaration that Overton is not entitled to renegotiate orterminate the contract and for injunctive relief requiring Overton to raiserates as stipulated in the contract.

On April 10, 2003, IE and Overton reached an agreement tosettle the case.  On April 30, 2003, IEand Overton entered into a Settlement Agreement which provided that Overtonwould pay IE $52.5 million as follows: (a) $5.5 million on May 1, 2003 and (b) $47 million over ten years, inequal installments to be paid quarterly beginning October 1, 2003.  There was no prepayment penalty.  The Settlement Agreement terminated the Julycontract.  IE received the $5.5 millionon May 1, 2003 and the first quarterly installment payment of $1.6 million onOctober 1, 2003.  IE agreed to accept afinal payment of $45 million on December 29, 2003.  The settlement resulted in a loss on legal disputes of $23million which includes a $1 million loss associated with the finalpayment.  The settlement of this disputeand the subsequent payments relieved the $74 million long-term receivable onIE's books at December 31, 2002.

**Other Legal IssuesIdaho Power Company Transmission Line Rights-of-Way Across Fort Hall IndianReservation:**  IPC has multipletransmission lines that cross the Shoshone-Bannock Tribes' Fort Hall IndianReservation near the city of Pocatello in southeastern Idaho.  IPC has been working since 1996 to renewfive of the right-of-way permits for the transmission lines, which have statedpermit expiration dates between 1996 and 2003. IPC has filed applications with the United States Department of theInterior, Bureau of Indian Affairs, to renew the five rights-of-way for 25years, including payment of the independently appraised value of therights-of-way to the Tribes (and the Tribal allottees who own portions of therights-of-way).  The Tribes have notagreed to renew the rights-of-way and have demanded a substantially greaterpayment of $19 million, including an up-front payment of $4 million with theremainder to be paid over the 25-year term of the permits, or in thealternative $11 million including an up-front payment of $4 million with theremainder paid over the first three years of the permits. This is based on an"opportunity cost" methodology, which calculates the value of therights-of-way as a percentage of the cost to IPC of relocating the transmissionlines off the Reservation.  Both partieshave discussed potential legal action regarding renewal of the rights-of-way,but no such action has been taken to date. The probable cost of renewing the rights-of-way is difficult toascertain due to the lack of definitive legal guidelines for the renewals.  IPC believes that the amount payable for25-year rights-of-way should not exceed $11 million, which represents theapproximate present value of the offers communicated to date by the Tribe.  IPC plans to obtain IPUC approval for therecovery of any renewal payment in its utility rates as a prerequisite to anysettlement of the right-of-way renewals with the Tribe.

**9. STOCK-BASED COMPENSATION:**

IDACORP has two stock-basedcompensation plans that are intended to align employee and shareholderobjectives related to its long-term growth.

The 2000 Long-TermIncentive Compensation Plan (LTICP) for officers, key employees and directorspermits the grant of nonqualified stock options, incentive stock options, stockappreciation rights, restricted stock, restricted stock units, performanceunits, performance shares and other awards.

The maximum number of sharesavailable under the LTICP is 2,050,000 in 2003, 2002 and 2001, IDACORP issued429,000, 355,000 and 274,000 stock options, respectively, with an exerciseprice equal to the market price of IDACORP's stock on the date of grant.  In accordance with APB 25, no compensationcosts have been recognized for the option awards.

Stock option transactions are summarized asfollows:
|                            |            | **2003**      | **2002**     | **2001**   |
|---------------------------------|-----------------|---------------|--------------|------------|
|                            |            |          | **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 | 849,000    | $             | 38.50        | 494,000    | $ | 37.79 | 220,000 | $ | 35.81 |
|                            | Granted         | 429,000  |         | 23.01      | 355,000 |   | 39.50 | 274,000 |   | 39.37 |
|                            | Exercised       | -        |         | -          | - |   | - | - |   | - |
|                            | Forfeited       | (127,200)     |         | 38.55      | - |   | - | - |   | - |
| Outstanding, end of year        | 1,150,800  | $             | 32.72        | 849,000    | $ | 38.50 | 494,000 | $ | 37.79 |
|                            |            |          |         |       |   |   |   |   |   |   |
| Exercisable                     | 266,600    | $             | 37.91        | 120,800    | $ | 37.20 | 36,000 | $ | 35.81 |

 

The outstanding options have arange of exercise prices from $22.92 to $40.31.  As of December 31, 2003, the weighted average remainingcontractual life is 8.1 years.

IDACORP also has a restrictedstock plan for key employees.  Eachgrant made under this plan has a three-year restricted period, and the finalaward amounts depend on the attainment of cumulative EPS performancegoals.  At December 31, 2003, there were145,314 remaining shares available under this plan.

Restricted stock awards arecompensatory awards and IDACORP accrues compensation expense (which is chargedto operations) based upon the market value of the granted shares.  For the years 2003, 2002 and 2001, totalcompensation accrued under the plan was less than $1 million annually.

The following table summarizesrestricted stock activity for the years 2003, 2002 and 2001:
|                                                      | **2003**       |   | **2002**     |   | **2001**     |
|-----------------------------------------------------------|----------------|--------|--------------|--------|--------------|
| Shares  outstanding - beginning of year                   | 87,669    |   | 63,551  |   | 60,195  |
| Shares  granted                                           | 52,517    |   | 44,832  |   | 23,748  |
| Shares  forfeited                                         | (6,679)        |   | (132)        |   | (474)        |
| Shares  issued                                            | (39,144)       |   | (20,582)     |   | (19,918)     |
| Shares  outstanding - end of year                         | 94,363    |   | 87,669  |   | 63,551  |
| Weighted  average fair value of current year stock grants |           |   |         |   |         |
|                                                      | on  grant date | $      | 23.01   |   | $            | 38.58  |   | $ | 38.16  |
|                                                           |                |        |              |        |              |  |  |  |  |

 

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.  Expense related to forfeitedoptions is reversed in the period in which the forfeit occurs.

The fair value of each option granted was estimated atthe date of grant using the Binomial option-pricing model with the followingassumptions:
|                                            | **2003** |   | **2002** |   | **2001** |
|-------------------------------------------------|----------|--------|----------|--------|----------|
| Stock  dividend yield                           | 8.09%    |   | 4.71%    |   | 4.72%    |
| Expected  stock price volatility                | 28%      |   | 32%      |   | 29%      |
| Risk-free  interest rate                        | 3.94%    |   | 4.92%    |   | 5.18%    |
| Expected  option lives                          | 7 years  |   | 7 years  |   | 7 years  |
| Weighted  average fair value of options granted | $ 3.90   |   | $10.54   |   | $ 9.86   |
|                                            |     |   |     |   |     |

 

**10.  BENEFIT PLANS:**

**Pension Plans**IPC has a noncontributory defined benefitpension 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 2003, 2002 and 2001, and does not expect to make a contribution in2004.  The market-related value of assetsfor the plan is equal to market value.

In addition, IPC has anonqualified, deferred compensation plan for certain senior managementemployees and directors.  This plan wasfinanced by purchasing life insurance policies and investments in marketable securities,all of which are held by a trustee.  Thecash value of the policies and investments exceed the projected benefitobligation of the plan but do not qualify as plan assets in the actuarialcomputation of the funded status.

IPC uses a December 31 measurementdate for its plans.

The following table shows thecomponents of net periodic benefit cost for these plans:
|                                 | **Pension Plan**               | **Deferred Compensation  Plan** |
|--------------------------------------|--------------------------------|---------------------------------|
|                                 | **2003**                       | **2002**                        | **2001** | **2003** | **2002** | **2001** |
|                                 | **(in  thousands of dollars)** |
|                                 |                           |                            |   |   |   |   |   |   |   |   |   |   |
| Service cost                         | $                              | 10,173                     | $ | 9,548  | $ | 7,978  | $ | 1,212  | $ | 944  | $ | 624  |
| Interest cost                        |                           | 19,463                     |   | 18,684  |   | 17,634  |   | 2,414  |   | 2,108  |   | 2,039  |
| Expected return on assets            |                           | (23,445)                        |   | (28,797) |   | (30,117) |   | -  |   | -  |   | -  |
| Recognized net actuarial (gain) loss |                           | 361                        |   | -  |   | (3,179) |   | 744  |   | 498  |   | 281  |
| Amortization of prior service cost   |                           | 729                        |   | 729  |   | 708  |   | (345) |   | (353) |   | (345) |
| Amortization of transition asset     |                           | (263)                           |   | (263) |   | (263) |   | 613  |   | 613  |   | 613  |
| Net periodic pension cost (benefit)  | $                              | 7,018                      | $ | (99) | $ | (7,239) | $ | 4,638  | $ | 3,810  | $ | 3,212  |
|                                 |                           |                            |   |   |   |   |   |   |   |   |   |   |
|                                      |                                |                                 |  |  |  |  |  |  |  |  |  |  |  |

 

 

The following table summarizesthe changes in benefit obligations and plan assets of these plans:
|                                   | **Pension Plan**                  |          | **Deferred Compensation Plan** |
|----------------------------------------|-----------------------------------|---------------|--------------------------------|
|                                   | **2003**                          |          | **2002**                       |   | **2003** |   | **2002** |
|                                   | **(in thousands of dollars)**     |
|                                   |                              |          |                           |   |   |   |   |   |   |   |   |
| **Change in benefit obligation:**      |                              |          |                           |   |   |   |   |   |   |   |   |
|                                   | Benefit obligation at January 1   | $             | 294,881                   |   | $ | 273,208  |   | $ | 35,792  |   | $ | 30,405  |
|                                   | Service cost                      |          | 10,173                    |   |   | 9,548  |   |   | 1,212  |   |   | 944  |
|                                   | Interest cost                     |          | 19,463                    |   |   | 18,684  |   |   | 2,415  |   |   | 2,108  |
|                                   | Actuarial loss (gain)             |          | 27,420                    |   |   | 6,823  |   |   | 1,785  |   |   | 4,490  |
|                                   | Benefits paid                     |          | (13,345)                       |   |   | (13,382) |   |   | (2,369) |   |   | (2,507) |
|                                   | Plan amendments                   |          | 529                       |   |   | -  |   |   | 35  |   |   | 352  |
|                                   | Benefit obligation at December 31 | $             | 339,121                   |   | $ | 294,881  |   | $ | 38,870  |   | $ | 35,792  |
| **Change in plan assets:**             |                              |          |                           |   |   |   |   |   |   |   |   |
|                                   | Fair value at January 1           |          | 282,531                   |   |   | 326,266  |   |   | -  |   |   | -  |
|                                   | Actual return on plan assets      |          | 66,043                    |   |   | (30,353) |   |   | -  |   |   | -  |
|                                   | Employer contributions            |          | -                         |   |   | -  |   |   | -  |   |   | -  |
|                                   | Benefit payments                  |          | (13,345)                       |   |   | (13,382) |   |   | -  |   |   | -  |
|                                   | Fair value at December 31         | $             | 335,229                   |   | $ | 282,531  |   | $ | -  |   | $ | -  |
|                                   |                              |          |                           |   |   |   |   |   |   |   |   |
| Funded status                          |                              | (3,892)       |                           |   | (12,350) |   |   | (38,870) |   |   | (35,792) |
| Unrecognized actuarial loss (gain)     |                              | 18,577   |                           |   | 34,116  |   |   | 13,547  |   |   | 12,505  |
| Unrecognized prior service cost        |                              | 6,660    |                           |   | 6,860  |   |   | 1,010  |   |   | 630  |
| Unrecognized net transition liability  |                              | (389)         |                           |   | (652) |   |   | 923  |   |   | 1,536  |
| Net amount recognized                  | $                                 | 20,956   |                           | $ | 27,974  |   | $ | (23,390) |   | $ | (21,121) |
| Amounts recognized in the statement of |                              |          |                           |   |   |   |   |   |   |   |   |
|                                   | financial position consist of:    |          |                           |   |   |   |   |   |   |   |   |   |
| Prepaid (accrued) pension cost         | $                                 | 20,956   |                           | $ | 27,974  |   | $ | (35,676) |   | $ | (33,120) |
| Intangible asset                       |                              | -        |                           |   | -  |   |   | 1,933  |   |   | 2,166  |
| Accumulated other comprehensive income |                              | -        |                           |   | -  |   |   | 10,353  |   |   | 9,833  |
| Net amount recognized                  | $                                 | 20,956   |                           | $ | 27,974  |   | $ | (23,390) |   | $ | (21,121) |
| Accumulated benefit obligation         | $                                 | 284,910  |                           | $ | 248,074  |   | $ | 35,676  |   | $ | 33,120  |
|                                   |                              |          |                           |   |   |   |   |   |   |   |   |

 

Changes in the Deferred Compensation Plan minimumliability increased other comprehensive income by $0.5 million and $3.2 millionin 2003 and 2002, respectively.

The following table summarizes the expected futurebenefit payments of these plans:
|                       |   | 2004   |   | 2005   |   | 2006   |   | 2007   |   | 2008   |   | 2009-2013 |
|----------------------------|--------|--------|--------|--------|--------|--------|--------|--------|--------|--------|--------|-----------|
| Pension Plan               | $      | 13,675 | $      | 13,941 | $      | 14,347 | $      | 15,075 | $      | 16,085 | $      | 102,911   |
| Deferred Compensation Plan |   | 2,353  |   | 2,546  |   | 2,571  |   | 2,600  |   | 2,691  |   | 15,637    |
|                       |   |   |   |   |   |   |   |   |   |   |   |      |

 

**Plan Asset Allocations:** IPC's pension plan and postretirement benefitplan weighted average asset allocations at December 31, 2003 and 2002, by assetcategory are as follows:
|                                                                                      |   | **Pension**          |                 | **Postretirement** |
|-------------------------------------------------------------------------------------------|--------|----------------------|----------------------|--------------------|
|                                                                                      |   | **Plan**             |                 | **Benefits**       |
| Asset Category                                                                            |   | **2003**             | **2002**             |               | **2003** | **2002** |
| Equity securities                                                                         |   | 69%                  | 63%                  |               | 0% | 0% |
| Debt securities                                                                           |   | 21    | 25    |               | 2    | 2    |
| Real estate                                                                               |   | 9     | 11    |               | 0    | 0    |
| Other (a)                                                                                 |   | 1     | 1     |               | 98    | 98    |
|                                                                                      | Total  |                 | 100%                 | 100%               |   | 100% | 100% |
| (a)  The  postretirement benefit plan assets are primarily life insurance contracts. |
|                                                                                           |        |                      |                      |                    |  |  |  |

 

 

 

**Pension Asset Allocation Policy:** The target allocations for the portfolio byasset class are as follows:
| Large-Cap Growth Stocks   | 14.0% | International Growth Stocks |  6.0% |
|---------------------------|-------|-----------------------------|------------|
| Large-Cap Core Stocks     | 10.0% | International Value Stocks  |  6.0% |
| Large-Cap Value Stocks    | 14.0% | Intermediate-Term Bonds     | 20.0%      |
| Small-Cap Growth Stocks   | 7.5%  | Core Real Estate            | 10.0%      |
| Small-Cap Value Stocks    | 7.5%  | Venture Capital             | 1.0%       |
| Cash and Cash Equivalents | 4.0%  |                        |       |

 

Assets are rebalanced as necessaryto keep the portfolio close to target allocations.

The plan's principal investmentobjective is to maximize total return (defined as the sum of realized interestand dividend income and realized and unrealized gain or loss in market price)consistent with prudent parameters of risk and the liability profile of theportfolio.  Emphasis is placed onpreservation and growth of capital along with adequacy of cash flow sufficientto fund current and future payments to pensioners.

There are three major goals in IPC's asset allocationprocess:

Determine if the investmentshave the potential to earn the rate of return assumed in the actuarialliability calculations.

Match the cash flow needs ofthe plan.  IPC sets cash allocationssufficient to cover the current year benefit payments and bond allocationssufficient to cover at least five years of benefit payments.  IPC then utilizes growth instruments(equities, real estate, venture capital) to fund the longer-term liabilities ofthe plan.

Maintain a prudent risk profileconsistent with ERISA fiduciary standards. The baseline risk measure is a 60% S&P 500 stocks and a 40% LehmanAggregate bond portfolio.

 

Allowable plan investments includestocks and stock funds, investment-grade bonds and bond funds, core real estatefunds, private equity funds, and cash and cash equivalents.  With the exception of real estate holdingsand private equity, investments must be readily marketable so that an entireholding can be disposed of quickly with only a minor effect upon marketprice.  Uncovered options, short sales,margin purchases, letter stock and commodities are prohibited.

Rate-of-return projections for plan assets are based onhistorical real returns adjusted for inflation for each asset class, based on arecognized index established for the asset class being measured.  Historical real returns are then adjusted toinclude an inflation premium based on the current inflation environment.  IPC currently uses a 2% inflation assumptionin the asset modeling process.

IPC's asset modeling process also utilizes historicalmarket returns to measure the portfolio's exposure to a "worst-case"market scenario, to determine how much performance could vary from the expected"average" performance over various time periods.  This "worst-case" modeling, inaddition to cash flow matching and diversification by asset class andinvestment style, provides the basis for managing the risk associated withinvesting portfolio assets.

Investment managers for the plan are selected based ontheir expertise in a given asset class. Investment managers engaged by the portfolio are subjected to rigorousongoing due diligence to ensure that investment performance guidelines areadhered to and that the investment professionals and investment processesremain intact. 

**Postretirement Benefits**IPC maintains a defined benefitpostretirement plan (consisting of health care and death benefits) that coversall employees who were enrolled in the active group plan at the time ofretirement, their spouses and qualifying dependents.  Effective January 1, 2003, IPC amended its postretirement benefitplan.  The amendment affects allemployees who retire after December 31, 2002, limiting their postretirementbenefit to a fixed amount.  Thisamendment will limit the growth of IPC's future obligations under this plan.

IPC's postretirement plan includes a health care planthat provides prescription drug benefits. IPC is utilizing the one-time election prescribed in FASB Staff Position106-1 to defer accounting for the effects of the Medicare Prescription Drug,Improvement and Modernization Act of 2003 (the Act).  Therefore, the measures of the net periodic postretirementbenefit cost and accumulated benefit obligation do not reflect the effects ofthe Act on the plan.  Authoritativeguidance on the accounting for the federal subsidy is pending and thatguidance, when issued, could require IPC to change previously reportedinformation.  In addition, IPC may needto amend the postretirement plan in order to benefit from the new legislation. 

The net periodicpostretirement benefit cost was as follows (in thousands of dollars):
|                                     | **2003**   |        | **2002**    |   | **2001**    |
|------------------------------------------|------------|-------------|-------------|--------|-------------|
| Service  cost                            | $          | 1,207  |        | $      | 927    |   | $ | 831  |
| Interest  cost                           |       | 4,017  |        |   | 3,648  |   |   | 3,589  |
| Expected  return on plan assets          |       | (1,930)     |        |   | (2,320)     |   |   | (2,343) |
| Amortization  of unrecognized transition |       |        |        |   |        |   |   |
|                                     | obligation |        | 2,040  |   |        | 2,040  |   |   | 2,040  |
| Amortization  of prior service cost      |       | (563)       |        |   | (563)       |   | (563) |
| Recognized  actuarial (gain)/loss        |       | 1,402  |        |   | 487    |   | -  |
| Net  periodic postretirement benefit     | $          | 6,173  |        | $      | 4,219  |   | $ | 3,554  |
|                                     |       |        |        |   |        |   |   |   |   |

 

The following table summarizesthe changes in benefit obligation and plan assets (in thousands of dollars):
|                                                              | **2003**                                 |         | **2002**     |
|-------------------------------------------------------------------|------------------------------------------|--------------|--------------|
| **Change in accumulated benefit  obligation:**                    |                                     |         |         |   |   |
|                                                              | Benefit obligation at January 1          | $            | 57,267  |   | $ | 53,650  |
|                                                              | Service cost                             |         | 1,207   |   |   | 927  |
|                                                              | Interest cost                            |         | 4,017   |   |   | 3,648  |
|                                                              | Actuarial loss                           |         | 8,780   |   |   | 2,029  |
|                                                              | Benefits paid                            |         | (4,181)      |   |   | (2,987) |
|                                                              | Benefit obligation at December 31        | $            | 67,090  |   | $ | 57,267  |
|                                                              |                                     |         |         |   |   |
| **Change in plan assets:**                                        |                                     |         |         |   |   |
|                                                              | Fair value of plan assets at January 1   |         | 22,522  |   |   | 25,184  |
|                                                              | Actual (loss) return on plan assets      |         | 4,081   |   |   | (3,837) |
|                                                              | Employer contributions                   |         | 3,961   |   |   | 4,262  |
|                                                              | Benefits paid                            |         | (3,961)      |   |   | (3,087) |
|                                                              | Fair value of plan assets at December 31 | $            | 26,603  |   | $ | 22,522  |
|                                                              |                                     |         |         |   |   |
| Funded status                                                     |                                     | (40,487)     |         |   | (34,745) |
| Unrecognized  prior service cost                                  |                                     | (5,047)      |         |   | (5,610) |
| Unrecognized  actuarial loss (gain)                               |                                     | 23,854  |         |   | 18,627  |
| Unrecognized  transition obligation                               |                                     | 18,360  |         |   | 20,400  |
| Accrued  benefit obligations included with other deferred credits | $                                        | (3,320)      |         | $ | (1,328) |
|                                                              |                                     |         |         |   |   |   |

 

The assumed health care costtrend rate used to measure the expected cost of benefits covered by the plan is6.75% in 2003 and 2002.  Aone-percentage point change in the assumed health care cost trend rate wouldhave the following effect (in thousands of dollars):
|                                                     | **1-Percentage** |   | **1-Percentage** |
|----------------------------------------------------------|------------------|--------|------------------|
|                                                     | **-Point**       |   | **-Point**       |
|                                                     | **increase**     |   | **decrease**     |
|                                                     |             |   |             |   |   |
| Effect on total of cost components                       | $                | 187    |             | $ | (146) |
| Effect on accumulated postretirement  benefit obligation | $                | 1,883  |             | $ | (1,533) |
|                                                     |             |   |             |   |   |

 

Thefollowing table sets forth the weighted-average assumptions used at the end ofeach year to determine benefit obligations for all IPC-sponsored pension andpostretirement benefits plans:
|                                        |   | **Pension**           |                  | **Postretirement** |
|---------------------------------------------|--------|-----------------------|-----------------------|--------------------|
|                                        |   | **Benefits**          |                  | **Benefits**       |
|                                        |   | **2003**              | **2002**              |               | **2003** | **2002** |
| Discount rate                               |   | 6.15%                 | 6.75%                 |               | 6.15% | 6.75% |
| Expected long-term rate of return on assets |   | 8.5    | 8.5    |               | 8.5    | 8.5    |
| Rate of compensation increase               |   | 4.5    | 4.5    |               | -    | -    |
| Medical trend rate                          |   | -      | -      |               | 6.75    | 6.75    |
| Expected working lifetime (years)           |   | -      | -      |               | 12    | 12    |
|                                        |   |                  |                  |               |   |   |

 

The following table sets forth the weighted-averageassumptions used for the end of each year to determine net periodic benefitcost for all IPC-sponsored pension and postretirement benefit plans:
|                                        |   | **Pension**           |                  | **Postretirement** |
|---------------------------------------------|--------|-----------------------|-----------------------|--------------------|
|                                        |   | **Benefits**          |                  | **Benefits**       |
|                                        |   | **2003**              | **2002**              |               | **2003** | **2002** |
| 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    |
| Rate of compensation increase               |   | 4.5    | 4.5    |               | -    | -    |
| Medical trend rate                          |   | -      | -      |               | 6.75    | 6.75    |
| Expected working lifetime (years)           |   | -      | -      |               | 12    | 12    |
|                                        |   |                  |                  |               |   |   |

 

**Employee Savings Plan**IPC has an ESP which complies with Section401(k) of the Internal Revenue Code and covers substantially allemployees.  IPC matches specifiedpercentages of employee contributions to the plan.  Matching contributions amounted to $3 million in 2003 and $4million in each of 2002 and 2001.

**Postemployment Benefits**IPC provides certain benefits to former orinactive employees, their beneficiaries and covered dependents after employmentbut before retirement.  These benefitsinclude salary continuation, health care and life insurance for those employeesfound to be disabled under IPC's disability plans and health care for survivingspouses and dependents.  IPC accrues aliability for such benefits.  Inaccordance with an IPUC order, the portion of the liability attributable toregulated activities in Idaho as of December 31, 1993, was deferred as aregulatory asset, and is being amortized over the ten years ending February2005

The following table summarizespostemployment benefit amounts included in IDACORP and IPC's consolidatedbalance sheets at December 31 (in thousands of dollars):
|                                 | **2003** |      | **2002** |
|--------------------------------------|----------|-----------|----------|
| Included with regulatory assets      | $        | 403  |     | $ | 774  |
| Included with other deferred credits | $        | (4,079)   |     | $ | (3,686) |
|                                 |     |      |     |   |   |

 

 

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

The following table presentsthe major classifications of IPC's utility plant in service, annualdepreciation provisions as a percent of average depreciable balance andaccumulated provision for depreciation for the years 2003 and 2002 (inthousands of dollars):
|  
 

**2003**

 

**2002**

 
 

**Balance**

 

**Avg Rate**

 

**Balance**

 

**Avg Rate**

 

 

 

 

 

 

 

 

 

 

Production

$

1,456,954 

 

2.71%

 

$

1,433,627 

 

2.63%

Transmission

 

526,887 

 

2.21   

 

 

485,349 

 

2.30   

Distribution

 

952,979 

 

3.25   

 

 

902,985 

 

3.31   

General  and Other

 

283,408 

 

6.51   

 

 

265,004 

 

6.16   

 

Total  in service

 

3,220,228 

 

3.03%

 

 

3,086,965 

 

3.00%

Accumulated  provision for depreciation

 

(1,239,604)

 

 

 

 

(1,157,287)

 

 

 

In  service - net

$

1,980,624 

 

 

 

$

1,929,678 

 

 

 

 

 

 

 

 

 

 

 

 

 

IPC has interests in threejointly-owned generating facilities. Under the joint operating agreements, each participating utility isresponsible for financing its share of construction, operating and leasingcosts.  IPC's proportionate share ofdirect operation and maintenance expenses applicable to the projects isincluded in the Consolidated Statements of Income.  These facilities, and the extent of IPC's participation, are asfollows at December 31, 2003:

 

 

 

 

**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

 

$

424,482

 

$

4,906

 

$

243,622

 

33

 

707

Boardman

 

Boardman, OR

 

 

64,966

 

 

355

 

 

42,450

 

10

 

55

Valmy Units 1 and 2

 

Winnemucca, NV

 

 

308,211

 

 

2,373

 

 

174,194

 

50

 

261

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

IPC's wholly owned subsidiary,Idaho Energy Resources Company, is a joint venturer in Bridger Coal Company,which operates the mine supplying coal for the Jim Bridger steam generationplant.  Coal purchased by IPC from thejoint venture amounted to $44 million in 2003, $44 million in 2002 and $43million in 2001.

IPC has contracts to purchasethe energy from four Public Utilities Regulatory Policy Act (PURPA) QualifiedFacilities that are 50 percent owned by Ida-West.  Power purchased from these facilities amounted to $7 million bothin 2003 and 2002 and $6 million in 2001.

**Ida-West**During 2002, Ida-West recorded an $8.6 million partial write-down ofits investment in equipment for the Garnet facility project.  This partial write-down reflects thedecrease in prices for and increased availability of generating equipment dueto the collapse of the merchant power plant development business.  In the fourth quarter of 2003, Ida-Westwrote down its remaining investment of $3.6 million in the Garnet facilityproject.

**12.  INDUSTRY SEGMENT INFORMATION:**

IDACORP has identified threereportable operating segments: utility operations, energy marketing and IFS.

The utility operations segmenthas two primary sources of revenue: the regulated operations of IPC and incomefrom Bridger Coal Company, an unconsolidated joint venture also subject toregulation.  IPC's regulated operationsinclude the generation, transmission, distribution, purchase and sale of electricity.

The energy marketing segmentreflects the results of IE's electricity and natural gas marketingoperations.  See Note 13 - RegulatoryMatters, for discussion on the wind down of energy marketing.

IFS represents thatsubsidiary's investments in affordable housing developments and historicpreservation projects.

 

The following table summarizesthe segment information for IDACORP's utility operation, energy marketingoperations, IFS and the total of all other segments, and reconciles thisinformation to total enterprise amounts.

 

**Utility**

**Energy**

 

 

 

**Consolidated**

 

**Operations**

**Marketing**

**IFS**

**Other**

**Eliminations**

**Total**

 

**(thousands of dollars)**

**2003**

 

 

 

 

 

 

 

 

 

 

 

Revenues

$

782,720 

$

19,916 

$

- 

$

20,366 

$

- 

$

823,002 

Operating income (loss)

 

121,694 

 

(18,099)

 

(796)

 

(18,737)

 

- 

 

84,062 

Other income (expense)

 

14,678 

 

2,320 

 

(9,930)

 

2,820 

 

(3,559)

 

6,329 

Interest expense (income) and other

 

59,483 

 

53 

 

5,821 

 

3,134 

 

(3,559)

 

64,932 

Income (loss) before income taxes

 

76,889 

 

(15,832)

 

(16,547)

 

(19,051)

 

- 

 

25,459 

Income tax expense (benefit)

 

21,728 

 

(6,269)

 

(26,951)

 

(9,627)

 

- 

 

(21,119)

Net income (loss)

 

55,161 

 

(9,563)

 

10,404 

 

(9,424)

 

- 

 

46,578 

Total assets

 

2,820,711 

 

50,802 

 

141,286 

 

158,547 

 

(69,620)

 

3,101,726 

Expenditures for long-lived assets

 

148,494 

 

- 

 

3 

 

1,447 

 

- 

 

149,944 

 

 

 

 

 

 

 

 

 

 

 

 

 

**2002**

 

 

 

 

 

 

 

 

 

 

 

 

Revenues

$

869,040 

$

46,410 

$

- 

$

13,350 

$

- 

$

928,800 

Operating income (loss)

 

132,661 

 

(23,739)

 

(923)

 

(32,359)

 

- 

 

75,640 

Other income (expense)

 

11,607 

 

(1,199)

 

(11,778)

 

12,187 

 

(6,987)

 

3,830 

Interest expense (income) and other

 

62,529 

 

(345)

 

7,147 

 

6,601 

 

(6,987)

 

68,945 

Income (loss) before income taxes

 

81,739 

 

(24,593)

 

(19,848)

 

(26,773)

 

- 

 

10,525 

Income tax expense (benefit)

 

(2,594)

 

(9,710)

 

(28,680)

 

(10,163)

 

- 

 

(51,147)

Net income (loss)

 

84,333 

 

(14,883)

 

8,832 

 

(16,610)

 

- 

 

61,672 

Total assets

 

2,876,167 

 

381,690 

 

157,018 

 

198,309 

 

(226,016)

 

3,387,168 

Expenditures for long-lived assets

 

129,132 

 

2,713 

 

44,064 

 

6,527 

 

- 

 

182,436 

 

 

 

 

 

 

 

 

 

 

 

 

 

**2001**

 

 

 

 

 

 

 

 

 

 

 

 

Revenues

$

914,201 

$

348,663 

$

- 

$

12,448 

$

- 

$

1,275,312 

Operating income (loss)

 

90,102 

 

176,712 

 

(756)

 

(23,769)

 

- 

 

242,289 

Other income (expense)

 

20,631 

 

1,795 

 

(6,232)

 

13,788 

 

(6,688)

 

23,294 

Interest expense (income) and other

 

67,883 

 

220 

 

5,837 

 

8,471 

 

(6,688)

 

75,723 

Income (loss) before income taxes

 

42,850 

 

178,287 

 

(12,825)

 

(18,452)

 

- 

 

189,860 

Income tax expense (benefit)

 

19,955 

 

71,068 

 

(18,177)

 

(8,200)

 

- 

 

64,646 

Net income (loss)

 

22,895 

 

107,219 

 

5,352 

 

(10,252)

 

- 

 

125,214 

Total assets

 

2,987,382 

 

717,659 

 

123,723 

 

81,937 

 

(140,709)

 

3,769,992 

Expenditures for long-lived assets

 

163,045 

 

6,749 

 

10 

 

8,952 

 

- 

 

178,756 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

**13.  REGULATORY MATTERS:**

**General Rate Case**IPC filed an application with the IPUC on October 16, 2003 to increase itsgeneral rates an average of 17.7 percent. If approved, IPC's revenues would increase $86 million annually based onthe proposed 11.2 percent return on equity. An additional component of the filing was a request for interim raterelief of $20 million.  The IPUC turneddown IPC's request for interim rate relief in Order No. 29403 on December 22,2003 noting that the denial of interim rate relief was not an indication of theultimate merits of the case. 

In addition, IPC has proposed extensive rate designchanges including seasonal rates for most customers, increased fixed chargesfor smaller customer classes and time of day rates for industrialcustomers.  If approved, the price IPCcharges its customers from June to August would reflect IPC's seasonably highercosts of producing or purchasing power. The change would result in summer and non-summer base rates.  The seasonal pricing proposal necessitatedIPC to recommend the annual PCA rate changes be implemented June 1 each yearinstead of May 16.  If approved thischange would eliminate the need for back-to-back rate changes and the PCArecovery period would be June 1 through May 31.

On February 20, 2004, the IPUC Staff and seven otherintervenors filed their testimony with the IPUC.  The testimony covered revenue requirement and rate designissues.  The IPUC Staff's proposal of$15 million, a three percent overall increase to base rates, was the lowestrecommendation of any of the parties. Copies of the parties' increase in base rates testimony and exhibits canbe viewed at the IPUC web site.  IPC hasuntil March 19, 2004 to prepare its rebuttal to these recommendations.

IPC's proposal requests revenuerecovery for certain costs of serving its customers, such as increasedoperating expenses and substantial demands for infrastructure improvements,increased capital costs for the Protection, mitigation and Enhancement(PM&E) requirements of new licenses at most of its hydroelectric projects,for the cost of new sources of power and continued expansion of itstransmission and distribution network. Because the Idaho jurisdiction does not allow assets that have not beenplaced in service to be included in the rate base, Bennett Mountain Power Plant(BMPP) and relicensing costs included in Construction Work in Progress (CWIP)are not included in this filing.  IPC isrequesting an 11.2 percent return on equity and an overall rate of return of8.4 percent.  The success of this ratecase is dependent on the IPUC's review and approval, which could take up toseven months from the filing date.  IPC isunable to predict what rate relief the IPUC will grant.

**Wind Down of Energy Marketing**IDACORP announced in 2002 that IE would wind down its energymarketing operations.  In connectionwith the wind down, certain matters were identified that required resolutionwith the FERC and the IPUC.  The FERCmatters have been resolved; however, compensation issues remain to be resolvedwith the IPUC.

In an IPUC proceeding that hasbeen underway since May 2001, IPC, the IPUC staff and several interestedcustomer groups have been working to determine the appropriate compensation IEshould provide to IPC for certain transactions between the affiliates.  The IPUC has issued several orders sincethen regarding these matters.  Order No.28852 issued on September 28, 2001 covered the time period prior to February2001. Order No. 29026 covered the time period from March 2001 through March2002.  The IPUC also approved IPC'songoing hedging and risk management strategies in Order No. 29102 issued onAugust 28, 2002.  This order formalizedIPC's agreement to implement a number of changes to its existing practices formanaging risk and initiating hedging purchases and sales.  In the same order, the IPUC directed IPC topresent a resolution or a status report to the IPUC on additional compensationdue to the utility for the use of its transmission system and other capitalassets by IE and any remaining transfer pricing issues.  Status reports were filed with the IPUC onDecember 20, 2002, March 20, 2003 and May 13, 2003 and settlement discussionswere initiated.  The $5.8 million inbenefits related to the FERC settlement have been included in the PCA andcredited to Idaho retail customers in accordance with the PCA methodology.  The parties to the proceeding have executeda settlement agreement providing that an additional $5.5 million is beingflowed through the PCA mechanism to the Idaho retail customers from April 2003through December 2005.  This agreementwas filed with the IPUC on February 17, 2004 and is subject to their approval.

**Deferred Power Supply Costs******IPC's deferred power supply costs consist of the following atDecember 31, 2003 and 2002 (in thousands of dollars):

 

**2003**

 

**2002**

 
Oregon deferral

$

13,620

 

$

14,172

Idaho PCA current year power  supply cost deferrals:

 

 

 

 

 

 

Deferral for 2003-2004 rate  year

 

44,664

 

 

-

 

Deferral for 2002-2003 rate  year

 

-

 

 

8,910

 

Astaris load reduction  agreement

 

-

 

 

27,160

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  May 2002

 

-

 

 

74,253

 

Remaining true-up authorized  May 2003

 

13,646

 

 

-

 

Total deferral

$

71,930

 

$

140,288

 

 

 

 

 

 

 

**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 costs (fuel and purchased power lesssales for resale) and the true-up of the prior year's forecast. During theyear, 90 percent of the difference between the actual and forecasted costs isdeferred with interest.  The endingbalance of this deferral, called a true-up, is then included in the calculationof the next year's PCA adjustment.

On April 15, 2003, IPC filedits 2003-2004 PCA with the IPUC, and, with a small adjustment to the filing,the rates were approved by the IPUC and became effective on May 16, 2003.  As approved, IPC's rates have been adjustedto collect $81 million above 1993 base rates, a $114 million reduction from the2002-2003 PCA.

So far in the 2003-2004 PCA rate year, actual powersupply costs have exceeded those anticipated in the forecast, due principallyto greater reliance on, and higher market prices for, purchased power.  Below normal water conditions also continuesto negatively impact forecasted and actual power supply costs.

On May 13, 2002, the IPUCissued Order No. 29026 related to the 2002-2003 PCA rate filing.  The order granted recovery of $255 millionof excess power supply costs, while it denied recovery of $12 million of lostrevenues resulting from the Irrigation Load Reduction Program, and $2 millionof other costs IPC sought to recover.

The IPUC had previously issuedOrder No. 28992 on April 15, 2002 disallowing the lost revenue portion of theIrrigation Load Reduction Program.  IPCbelieves that this IPUC 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.  On August29, 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 argued its position before the IdahoSupreme Court on December 5, 2003. If successful, IPC would record any amountrecovered 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 Reduction Agreement.  The IPUC subsequently issued Order No. 28992authorizing IPC to include direct costs it has accrued in the programs, subjectto later adjustments in the 2002-2003 PCA year.  As mentioned earlier, the IPUC also denied IPC's request torecover lost revenues experienced from the Irrigation Load Reduction Program.

**Oregon: **IPC also filed applicationswith the Oregon Public Utilities Commission (OPUC) to recover calendar year2001 extraordinary power supply costs applicable to the Oregonjurisdiction.  In two separate 2001orders, the OPUC has approved rate increases totaling six percent, which is themaximum annual rate of recovery allowed under Oregon state law.  These increases are recovering approximately$2 million annually.  The Oregondeferred balance was $14 million as of December 31, 2003.  During the 2003 Oregon legislative session,the maximum annual rate of recovery was raised to ten percent under certaincircumstances.  IPC expects to requestthe higher percentage in Spring 2004.

 

**RegulatoryAssets and Liabilities**The following is a breakdown of IPC's regulatory assets andliabilities for the years 2003 and 2002 (in thousands of dollars):

 

**2003**

 

**2002**

 

**Assets**

 

**Liabilities**

 

**Assets**

 

**Liabilities**

Income  taxes

$

330,833

 

$

41,024

 

$

327,934

 

$

41,013

Conservation

 

21,108

 

 

5,288

 

 

24,450

 

 

4,402

Employee  benefits

 

993

 

 

-

 

 

1,909

 

 

-

PCA  deferral and amortization

 

58,310

 

 

-

 

 

126,116

 

 

-

Oregon  deferral and amortization

 

13,620

 

 

-

 

 

14,172

 

 

-

Derivatives

 

125

 

 

-

 

 

91

 

 

-

Asset  retirement obligations

 

6,456

 

 

-

 

 

-

 

 

-

Asset  removal costs

 

-

 

 

142,595

 

 

-

 

 

137,674

Other

 

2,584

 

 

1,828

 

 

4,634

 

 

1,272

Deferred  investment tax credits

 

-

 

 

67,789

 

 

-

 

 

67,560

 

Total

$

434,029

 

$

258,524

 

$

499,306

 

$

251,921

 

The regulatory assets relatedto income taxes, AROs and derivatives do not earn a current return oninvestment.  For further information onthe ARO amounts, please refer to Note 1. Additionally, at December 31, 2003, $2 million of other regulatory assetswere not earning a return.  These assetsconsist of reorganization costs and employee benefits related to SFAS 112,"Employer Accounting for Post-employment Benefits."  The remaining amortization periods of theseregulatory assets are one and two years, respectively.

In the event that recovery ofcosts through rates becomes unlikely or uncertain, SFAS 71 would no longerapply.  If IPC were to discontinueapplication of SFAS 71 for some or all of its operations, then these items mayrepresent stranded investments.  If IPCis not allowed recovery of these investments, it would be required to write offthe applicable portion of regulatory assets and the financial effects could besignificant.

**14.DERIVATIVE FINANCIAL INSTRUMENTS:**

**Energy Trading Contracts**The commodity transactions entered into byIE were classified as energy trading contracts or derivatives in accordancewith SFAS 133 and EITF 02-3.  Under SFAS133 as amended, these contracts are recorded on the balance sheet at fairmarket value.  This accounting treatmentis also referred to as mark-to-market accounting.  Mark-to-market accounting treatment can create a disconnectbetween recorded earnings and realized cash flow.  Marking a contract to market consists of reevaluating the marketvalue of the entire term of the contract at each reporting period andreflecting the resulting gain or loss 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 ofthe contract could result in large gains or losses recorded in earnings at eachsubsequent reporting period unless there are offsetting changes in value ofoffsetting contracts. The gain or loss generated from the change in marketvalue of the energy trading contracts is a non-cash event.  If these contracts are held to maturity, thecash flow from the contracts, and their offsetting contracts, are realized overthe life of the contract.

When determining the fairvalue of marketing and trading contracts, IE used actively quoted prices forcontracts with similar terms as the quoted price, including specific deliverypoints and maturities. To determine fair value of contracts with terms thatwere not consistent with actively quoted prices IE used, when available, pricesprovided by other external sources. When prices from external sources were notavailable, IE determined prices by using internal pricing models thatincorporated available current and historical pricing information. Finally, thefair market value of contracts was adjusted for the impact of market depth andliquidity, potential model error, and expected credit losses at thecounterparty level.

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

 

 

**2003**

 

**2002**

 

**2001**

Gross Margin:

 

 

 

 

 

 

 

 

 

 

Realized or otherwise settled

 

$

61,183 

 

$

70,262 

 

$

149,956 

 

Unrealized

 

 

(42,517)

 

 

(65,965)

 

 

92,803 

 

 

Total

 

$

18,666 

 

$

4,297 

 

$

242,759 

 

 

 

 

 

 

 

 

 

 

 

**15.  RESTRUCTURING COSTS:**

IDACORP announced on June 21, 2002 that IE would winddown its power marketing operations due to changing liquidity requirementsbrought on by rating agencies, continued uncertainty in the regulatory andpolitical environment and the reduction of creditworthy counterparties.  On November 5, 2002, IDACORP announced thatit was terminating further evaluation of growth opportunities in the mid-streamnatural gas markets, and stated that IE would close its Denver office byyear-end 2002, would shut down its natural gas trading operation in Houston byMarch 2003 and would further reduce its workforce in its Boise operationsthrough mid-2003.  Since theseannouncements in 2002, IE has completed the major milestones outlined in thewind down of the business.  Thesemilestones include the sale of IE's forward book of electricity trading contractsto SET in August 2003, closing of the Denver, Houston and Boise offices and thefinal workforce terminations in November 2003.

IE incurred involuntarytermination benefit expenses, lease termination costs and other exit-relatedcosts in connection with the wind down. Termination benefit expenses relate to the termination of 98 employees(primarily energy traders and administrative support positions).  Of the 98 employees laid off, 19 were hiredby other IDACORP subsidiaries, and thus received no severance benefits.  Restructuring expenses are presented asSelling, general and administrative expenses on the Consolidated Statements ofIncome and restructuring accruals are presented as Other liabilities on theConsolidated Balance Sheets.

The following table summarizesrestructuring charge accruals during the periods (in thousands of dollars):

 

**Severance**

 

**Lease**

 

 

 

 

 

**and  Other**

 

**Termination**

 

 

 

 

 

**Benefits**

 

**Costs**

 

**Other**

 

**Total**

Balance at January 1, 2002

$

- 

 

$

- 

 

$

- 

 

$

- 

 

Amounts accrued

 

5,009 

 

 

2,485 

 

 

1,376 

 

 

8,870 

 

Amounts paid

 

(838)

 

 

- 

 

 

(1,181)

 

 

(2,019)

Balance at December 31, 2002

 

4,171 

 

 

2,485 

 

 

195 

 

 

6,851 

 

Amounts accrued

 

4,379 

 

 

978 

 

 

- 

 

 

5,357 

 

Amounts paid

 

(6,594)

 

 

(708)

 

 

(162)

 

 

(7,464)

 

Amounts reversed

 

(149)

 

 

- 

 

 

- 

 

 

(149)

Balance at December 31, 2003

$

1,807 

 

$

2,755 

 

$

33 

 

$

4,595 

 

 

 

 

 

 

 

 

 

 

 

 

 

**16.  SUPPLEMENTAL CASH FLOW INFORMATION:**

Selected cash paymentsand non-cash activities were as follows (in thousands of dollars):

 

 

**Year  Ended December 31,**

 

 

**2003**

 

**2002**

 

**2001**

Cash paid (received) during the period for:

 

 

 

 

 

 

 

 

 

Income taxes

$

52,882 

 

$

(39,678)

 

$

(17,766)

 

Interest (net of amount capitalized)

$

58,931 

 

$

62,665 

 

$

70,052 

Distribution of treasury shares for acquisition

$

237 

 

$

- 

 

$

7,532 

 

 

 

 

 

 

 

 

 

 

 

**INDEPENDENT AUDITORS'REPORT**

 

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

We have audited theaccompanying consolidated balance sheets of IDACORP, Inc. and subsidiaries asof December 31, 2003 and 2002, and the related consolidated statements ofincome, comprehensive income, shareholders' equity and cash flows for each ofthe three years in the period ended December 31, 2003.  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 our audits inaccordance with auditing standards generally accepted in the United States ofAmerica.  Those standards require thatwe plan and perform the audit to obtain reasonable assurance about whether thefinancial 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, suchconsolidated financial statements present fairly, in all material respects, thefinancial position of IDACORP, Inc. and subsidiaries at December 31, 2003 and2002, and the results of their operations and their cash flows for each of thethree years in the period ended December 31, 2003 in conformity with accountingprinciples 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 method of accounting and presentation of asset retirementobligations in 2003 in accordance with Statement of Financial AccountingStandards No. 143.

 

 

 

DELOITTE & TOUCHE LLP

Boise, IdahoFebruary 27, 2004

 

**Idaho Power CompanyConsolidated Statements of Income**

 

**Year  Ended December 31,**

 

**2003**

 

**2002**

 

**2001**

 

**(thousands  of dollars)**

**OPERATING REVENUES:**

 

 

 

 

 

 

 

 

 

General business

$

670,969 

 

$

772,035 

 

$

650,608 

 

Off-system sales

 

71,573 

 

 

55,031 

 

 

219,966 

 

Other revenues

 

37,840 

 

 

39,981 

 

 

41,738 

 

 

Total operating revenues

 

780,382 

 

 

867,047 

 

 

912,312 

**OPERATING EXPENSES:**

 

 

 

 

 

 

 

 

 

Operation:

 

 

 

 

 

 

 

 

 

 

Purchased power

 

150,980 

 

 

142,102 

 

 

584,209 

 

 

Fuel expense

 

99,898 

 

 

102,871 

 

 

98,318 

 

 

Power cost adjustment

 

70,762 

 

 

170,489 

 

 

(175,925)

 

 

Other

 

156,030 

 

 

150,884 

 

 

153,079 

 

Maintenance

 

62,799 

 

 

54,599 

 

 

55,877 

 

Depreciation

 

97,650 

 

 

93,609 

 

 

87,041 

 

Taxes other than income taxes

 

20,753 

 

 

19,953 

 

 

19,693 

 

 

Total operating expenses

 

658,872 

 

 

734,507 

 

 

822,292 

 

 

 

 

 

 

 

 

 

**INCOME FROM OPERATIONS**

 

121,510 

 

 

132,540 

 

 

90,020 

 

 

 

 

 

 

 

 

 

**OTHER INCOME:**

 

 

 

 

 

 

 

 

 

Allowance for equity funds  used during construction

 

3,385 

 

 

333 

 

 

752 

 

Other income

 

19,803 

 

 

19,271 

 

 

25,485 

 

Other expense

 

8,326 

 

 

7,876 

 

 

5,638 

 

 

Total other income

 

14,862 

 

 

11,728 

 

 

20,599 

 

 

 

 

 

 

 

 

 

**INTEREST CHARGES:**

 

 

 

 

 

 

 

 

 

Interest on long-term debt

 

54,645 

 

 

51,127 

 

 

55,704 

 

Other interest

 

4,718 

 

 

9,190 

 

 

10,402 

 

Allowance for borrowed funds used  during

 

 

 

 

 

 

 

 

 

 

construction

 

(3,310)

 

 

(2,375)

 

 

(3,737)

 

 

Total interest charges

 

56,053 

 

 

57,942 

 

 

62,369 

 

 

 

 

 

 

 

 

 

**INCOME BEFORE INCOME  TAXES**

 

80,319 

 

 

86,326 

 

 

48,250 

 

 

 

 

 

 

 

 

 

**INCOME TAX EXPENSE  (BENEFIT)**

 

21,728 

 

 

(2,594)

 

 

19,955 

 

 

 

 

 

 

 

 

 

**INCOME FROM CONTINUING  OPERATIONS**

 

58,591 

 

 

88,920 

 

 

28,295 

 

 

 

 

 

 

 

 

 

**DISCONTINUED  OPERATIONS**

 

 

 

 

 

 

 

 

 

Income from operations of  energy marketing

 

 

 

 

 

 

 

 

 

 

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

 

- 

 

 

- 

 

 

49,943 

 

 

 

 

 

 

 

 

 

**NET INCOME**

 

58,591 

 

 

88,920 

 

 

78,238 

 

 

 

 

 

 

 

 

 

 

Dividends on preferred stock

 

3,430 

 

 

4,587 

 

 

5,400 

 

 

 

 

 

 

 

 

 

**EARNINGS ON COMMON  STOCK**

$

55,161 

 

$

84,333 

 

$

72,838 

 

 

 

 

 

 

 

 

 

Theaccompanying notes are an integral part of these statements.

 

 

 

 

**Idaho Power CompanyConsolidated Balance Sheets**

**Assets**

 

 

**December 31,**

 

 

**2003**

 

**2002**

 

 

**(thousands of dollars)**

 

 

 

**ELECTRIC  PLANT:**

 

 

 

 

 

 

 

In service (at original cost)

 

$

3,220,228 

 

$

3,086,965 

 

Accumulated provision for depreciation

 

 

(1,239,604)

 

 

(1,157,287)

 

 

In service - Net

 

 

1,980,624 

 

 

1,929,678 

 

Construction work in progress

 

 

96,086 

 

 

92,481 

 
 

Held for future use

 

 

2,438 

 

 

2,335 

 
 

 

 

 

 

 

 

 

 

 

Electric plant - Net

 

 

2,079,148 

 

 

2,024,494 

 

 

 

 

 

 

 

 
**INVESTMENTS  AND OTHER PROPERTY**

 

 

49,739 

 

 

42,272 

 
 

 

 

 

 

 

 

**CURRENT  ASSETS:**

 

 

 

 

 

 

 

Cash and cash equivalents

 

 

4,031 

 

 

12,699 

 

Receivables:

 

 

 

 

 

 

 

 

Customer

 

 

43,694 

 

 

56,947 

 

 

Allowance for uncollectible accounts

 

 

(1,466)

 

 

(1,566)

 

 

Notes

 

 

3,186 

 

 

2,809 

 

 

Employee notes

 

 

3,347 

 

 

3,240 

 

 

Related parties

 

 

1,143 

 

 

27,905 

 

 

Other

 

 

4,848 

 

 

2,702 

 

Accrued unbilled revenues

 

 

30,869 

 

 

35,714 

 

Materials and supplies (at average cost)

 

 

19,755 

 

 

21,458 

 

Fuel stock (at average cost)

 

 

6,228 

 

 

6,943 

 

Prepayments

 

 

26,835 

 

 

32,818 

 

Regulatory assets

 

 

6,269 

 

 

17,147 

 

 

 

 

 

 

 

 

 

 

Total current assets

 

 

148,739 

 

 

218,816 

 

 

 

 

 

 

 

 

**DEFERRED  DEBITS:**

 

 

 

 

 

 

 

American Falls and Milner water rights

 

 

31,585 

 

 

31,585 

 

Company-owned life insurance

 

 

35,624 

 

 

35,299 

 

Regulatory assets

 

 

427,760 

 

 

482,159 

 

Employee notes

 

 

4,775 

 

 

4,615 

 

Other

 

 

43,341 

 

 

36,927 

 

 

 

 

 

 

 

 

 

 

Total deferred debits

 

 

543,085 

 

 

590,585 

 

 

 

 

 

 

 

 

 

**TOTAL**

 

$

2,820,711 

 

$

2,876,167 

 

 

 

 

 

 

 

Theaccompanying notes are an integral part of these statements.

 

 

 

**Idaho Power CompanyConsolidated Balance Sheets**

**Capitalization and Liabilities**

 

 

**December 31,**

 

 

**2003**

 

**2002**

 

 

 

**(thousands of dollars)**

**CAPITALIZATION:**

 

 

 

 

 

 

 

Common stock equity:

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

authorized; 39,150,812 and 37,612,351 shares  outstanding,

 

 

 

 

 

 

 

 

 

respectively)

 

$

97,877 

 

$

94,031 

 

 

Premium on capital stock

 

 

398,231 

 

 

361,948 

 

 

Capital stock expense

 

 

(2,686)

 

 

(2,710)

 

 

Retained earnings

 

 

320,735 

 

 

330,300 

 

 

Accumulated other comprehensive income (loss)

 

 

(2,630)

 

 

(7,109)

 

 

 

 

 

 

 

 

 

 

Total common stock equity

 

 

811,527 

 

 

776,460 

 

 

 

 

 

 

 

 

Preferred stock

 

 

52,366 

 

 

53,393 

 

 

 

 

 

 

 

 

Long-term debt

 

 

880,868 

 

 

870,741 

 

 

 

 

 

 

 

 

 

 

Total capitalization

 

 

1,744,761 

 

 

1,700,594 

 

 

 

 

 

 

 

**CURRENT  LIABILITIES:**

 

 

 

 

 

 

 

Long-term debt due within one year

 

 

50,077 

 

 

80,084 

 

Notes payable

 

 

- 

 

 

10,500 

 

Accounts payable

 

 

45,529 

 

 

52,676 

 

Notes and accounts payable to related parties

 

 

75 

 

 

52 

 

Taxes accrued

 

 

55,383 

 

 

89,090 

 

Interest accrued

 

 

12,893 

 

 

12,399 

 

Deferred income taxes

 

 

6,179 

 

 

17,056 

 

Other

 

 

20,985 

 

 

22,906 

 

 

 

 

 

 

 

 

 

 

Total current liabilities

 

 

191,121 

 

 

284,763 

 

 

 

 

 

 

 

**DEFERRED  CREDITS:**

 

 

 

 

 

 

 

Deferred income taxes

 

 

546,205 

 

 

574,233 

 

Regulatory liabilities

 

 

258,524 

 

 

251,921 

 

Other

 

 

80,100 

 

 

64,656 

 

 

 

 

 

 

 

 

 

 

Total deferred credits

 

 

884,829 

 

 

890,810 

 

 

 

 

 

 

 

**COMMITMENTS  AND CONTINGENT LIABILITIES**

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

**TOTAL**

 

$

2,820,711 

 

$

2,876,167 

 

 

 

 

 

 

 

Theaccompanying notes are an integral part of these statements.

 

 

**Idaho Power CompanyConsolidated Statements of Capitalization**

 

 

**December 31,**

 

 

**2003**

 

**%**

 

**2002**

 

**%**

 

 

**(thousands of dollars)**

**COMMON  STOCK EQUITY:**

 

 

 

Common stock

 

$

97,877 

 

 

 

$

94,031 

 

 

 

Premium on capital stock

 

 

398,231 

 

 

 

 

361,948 

 

 

 

Capital stock expense

 

 

(2,686)

 

 

 

 

(2,710)

 

 

 

Retained earnings

 

 

320,735 

 

 

 

 

330,300 

 

 

 

Accumulated other comprehensive income (loss)

 

 

(2,630)

 

 

 

 

(7,109)

 

 

 

 

Total common stock equity

 

 

811,527 

 

47

 

 

776,460 

 

46

 

 

 

 

 

 

 

 

 

 

 

**PREFERRED  STOCK:**

 

 

 

 

 

 

 

 

 

 

 

4% preferred stock

 

 

12,366 

 

 

 

 

13,393 

 

 

 

7.68% Series, serial preferred stock

 

 

15,000 

 

 

 

 

15,000 

 

 

 

7.07% Series, serial preferred stock

 

 

25,000 

 

 

 

 

25,000 

 

 

 

 

Total preferred stock

 

 

52,366 

 

3

 

 

53,393 

 

3

 

 

 

 

 

 

 

 

 

 

 

**LONG-TERM  DEBT:**

 

 

 

 

 

 

 

 

 

 

 

First mortgage bonds:

 

 

 

 

 

 

 

 

 

 

 

 

6.40%  Series  due 2003

 

 

- 

 

 

 

 

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 

 

 

 

 

100,000 

 

 

 

 

4.25%  Series  due 2013

 

 

70,000 

 

 

 

 

- 

 

 

 

 

7.50%  Series  due 2023

 

 

- 

 

 

 

 

80,000 

 

 

 

 

6     %  Series due 2032

 

 

100,000 

 

 

 

 

100,000 

 

 

 

 

5.50%  Series  due 2033

 

 

70,000 

 

 

 

 

- 

 

 

 

 

 

Total first mortgage bonds

 

 

730,000 

 

 

 

 

750,000 

 

 

 

 

Amount due within one year

 

 

(50,000)

 

 

 

 

(80,000)

 

 

 

 

 

Net first mortgage bonds

 

 

680,000 

 

 

 

 

670,000 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Pollution control revenue bonds:

 

 

 

 

 

 

 

 

 

 

 

 

8.30% Series 1984 due 2014

 

 

- 

 

 

 

 

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 

 

 

 

 

Variable Auction Rate Series 2003 due 2024

 

 

49,800 

 

 

 

 

- 

 

 

 

 

 

Total pollution control revenue bonds

 

 

170,460 

 

 

 

 

170,460 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

REA notes

 

 

1,105 

 

 

 

 

1,185 

 

 

 

 

Amount due within one year

 

 

(77)

 

 

 

 

(84)

 

 

 

 

 

Net REA notes

 

 

1,028 

 

 

 

 

1,101 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

American Falls bond guarantee

 

 

19,885 

 

 

 

 

19,885 

 

 

 

Milner Dam note guarantee

 

 

11,700 

 

 

 

 

11,700 

 

 

 

Unamortized premium/discount - Net

 

 

(2,205)

 

 

 

 

(2,405)

 

 

 

 

 

Total long-term debt

 

 

880,868 

 

50

 

 

870,741 

 

51

 

 

 

 

 

 

 

 

 

 

 

**TOTAL  CAPITALIZATION**

 

$

1,744,761 

 

100

 

$

1,700,594 

 

100

 

 

 

 

 

 

 

 

 

 

 

Theaccompanying notes are an integral part of these statements.

 

 

 

**Idaho Power CompanyConsolidated Statements of Cash Flows**

 

**Year Ended December 31,**

 

**2003**

 

**2002**

 

**2001**

 

**(thousands of dollars)**

**OPERATING  ACTIVITIES:**

 

 

 

 

 

 

 

 

 

Net income

$

58,591 

 

$

88,920 

 

$

78,238 

 

Adjustments to reconcile net income to net cash  provided by

 

 

 

 

 

 

 

 

 

(used in) operating activities:

 

 

 

 

 

 

 

 

 

 

Other than temporary decline in market value of  investments

 

(408)

 

 

980 

 

 

- 

 

 

Allowance for uncollectible accounts

 

(40)

 

 

66 

 

 

20,277 

 

 

Unrealized gains from energy marketing activities

 

- 

 

 

- 

 

 

(100,653)

 

 

Depreciation and amortization

 

110,228 

 

 

104,948 

 

 

99,565 

 

 

Deferred taxes and investment tax credits

 

(44,221)

 

 

(81,511)

 

 

103,423 

 

 

Accrued PCA costs

 

68,358 

 

 

164,201 

 

 

(184,584)

 

 

Change in:

 

 

 

 

 

 

 

 

 

 

 

Accounts receivable and prepayments

 

24,487 

 

 

(2,587)

 

 

(19,912)

 

 

 

Accrued unbilled revenue

 

4,845 

 

 

1,687 

 

 

7,425 

 

 

 

Materials and supplies and fuel stock

 

2,418 

 

 

3,605 

 

 

(2,216)

 

 

 

Accounts payable

 

(7,147)

 

 

(23,009)

 

 

(26,142)

 

 

 

Taxes receivable/accrued

 

(33,707)

 

 

97,335 

 

 

(21,227)

 

 

 

Other current liabilities

 

(1,427)

 

 

5,980 

 

 

(2,081)

 

 

Other assets

 

(6,972)

 

 

(589)

 

 

(5,903)

 

 

Other liabilities

 

10,118 

 

 

6,720 

 

 

(4,883)

 

 

Net cash provided by (used in) operating activities

 

185,123 

 

 

366,746 

 

 

(58,673)

 

 

 

 

 

 

 

 

 

**INVESTING  ACTIVITIES:**

 

 

 

 

 

 

 

 

 

Additions to utility plant

 

(148,246)

 

 

(128,318)

 

 

(156,787)

 

Note receivable payment from parent

 

19,282 

 

 

11,859 

 

 

42,743 

 

Other assets

 

(622)

 

 

(4,265)

 

 

(776)

 

 

Net cash used in investing activities

 

(129,586)

 

 

(120,724)

 

 

(114,820)

 

 

 

 

 

 

 

 

 

**FINANCING  ACTIVITIES:**

 

 

 

 

 

 

 

 

 

Issuance of first mortgage bonds

 

140,000 

 

 

200,000 

 

 

120,000 

 

Issuance of pollution control revenue bonds

 

49,800 

 

 

- 

 

 

- 

 

Retirement of first mortgage bonds

 

(160,000)

 

 

(77,000)

 

 

(130,000)

 

Retirement of pollution control revenue bonds

 

(49,800)

 

 

- 

 

 

- 

 

Retirement of preferred stock

 

(860)

 

 

(50,994)

 

 

- 

 

Proceeds from sale of common stock to parent

 

39,987 

 

 

- 

 

 

- 

 

Dividends on common stock

 

(64,726)

 

 

(70,178)

 

 

(69,782)

 

Dividends on preferred stock

 

(3,430)

 

 

(4,587)

 

 

(5,400)

 

Increase (decrease) in short-term borrowings

 

(10,500)

 

 

(271,500)

 

 

222,300 

 

Other assets

 

(4,187)

 

 

(2,094)

 

 

(3,375)

 

Other liabilities

 

(489)

 

 

(10)

 

 

(704)

 

 

Net cash provided by (used in) financing activities

 

(64,205)

 

 

(276,363)

 

 

133,039 

 

 

 

 

 

 

 

 

 

Net decrease in cash and cash equivalents

 

(8,668)

 

 

(30,341)

 

 

(40,454)

Cash and cash equivalents at beginning of period

 

12,699 

 

 

43,040 

 

 

83,494 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents at end of period

$

4,031 

 

$

12,699 

 

$

43,040 

 

 

 

 

 

 

 

 

 

Theaccompanying notes are an integral part of these statements.

 

 

 

**Idaho Power CompanyConsolidated Statements of Retained Earnings**

 

**Year  Ended December 31,**

 

**2003**

 

**2002**

 

**2001**

 

**(thousands  of dollars)**

 

 

 

 

 

 

 

 

 

**RETAINED EARNINGS, BEGINNING OF YEAR**

$

330,300 

 

$

316,856 

 

$

313,800 

 

 

 

 

 

 

 

 

 

**NET INCOME**

 

58,591 

 

 

88,920 

 

 

78,238 

 

 

 

 

 

 

 

 

 

**DIVIDENDS:**

 

 

 

 

 

 

 

 

 

Common stock

 

(64,726)

 

 

(70,178)

 

 

(69,782)

 

Preferred stock

 

(3,430)

 

 

(4,587)

 

 

(5,400)

 

 

 

 

 

 

 

 

 

**PREFERRED STOCK REDEMPTION**

 

- 

 

 

(711)

 

 

- 

 

 

 

 

 

 

 

 

 

**RETAINED EARNINGS, END OF YEAR**

$

320,735

 

$

330,300 

 

$

316,856 

 

 

 

 

 

 

 

 

 

Theaccompanying notes are an integral part of these statements.

 

 

 

**Idaho Power CompanyConsolidated Statements of Comprehensive Income**

 

**Year Ended December 31,**

 

**2003**

 

**2002**

 

**2001**

 

**(thousands of dollars)**

 

 

 

 

 

 

 

 

 

**NET  INCOME**

$

58,591 

 

$

88,920 

 

$

78,238 

 

 

 

 

 

 

 

 

 

**OTHER  COMPREHENSIVE INCOME (LOSS):**

 

 

 

 

 

 

 

 

 

Unrealized gains on securities:

 

 

 

 

 

 

 

 

 

 

Unrealized holding gains (losses) arising during the  period,

 

 

 

 

 

 

 

 

 

 

 

net of tax of $2,963, ($1,840) and($992) 

 

4,982 

 

 

(2,991)

 

 

(1,690)

 

 

Reclassification adjustment for (gains) losses included

 

 

 

 

 

 

 

 

 

 

 

in net income, net of tax of ($111), $1,007and ($52) 

 

(173)

 

 

1,560 

 

 

(80)

 

 

 

Net unrealized losses (gains)

 

4,809 

 

 

(1,431)

 

 

(1,770)

 

Minimum pension liability adjustment, net of tax of  ($191), 

 

 

 

 

 

 

 

 

 

 

($1,265) and ($649)

 

(330)

 

 

(1,959)

 

 

(1,028)

 

 

 

 

 

 

 

 

 

**TOTAL  COMPREHENSIVE INCOME**

$

63,070 

 

$

85,530 

 

$

75,440 

 

 

 

 

 

 

 

 

 

Theaccompanying notes are an integral part of these statements.

 

 

 

**IDAHO POWER COMPANYNOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS**

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

Except as modified below, the Notes to the Consolidated FinancialStatements of IDACORP included in this 2003 Annual Report on Form 10-K areincorporated herein by reference insofar as they relate to IPC.

Note 1 - Summary of Significant Accounting Policies

Note 2 - Income Taxes

Note 4 - Preferred Stock of Idaho Power Company

Note 5 - Long-Term Debt

Note 7 - Notes Payable

Note 8 - Commitments and Contingent Liabilities

Note 10 - Benefit Plans

Note 11 - Property, Plant and Equipment and Jointly-OwnedProjects

Note 13 - Regulatory Matters

**1.  SUMMARY OFSIGNIFICANT ACCOUNTING POLICIES:**

**Stock-Based Compensation**At December 31, 2003, 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 APB Opinion 25, "Accounting for Stock Issued toEmployees," and related interpretations. Grants of restricted stock are reflected in net income based on themarket value at the award date, or the year-end price for shares not yetvested.  No stock-based employeecompensation cost is reflected in net income for stock options, as all optionsgranted under these plans had an exercise price equal to the market value ofthe underlying common stock on the date of grant.

Thefollowing table illustrates the effect on net income if the fair valuerecognition provisions of SFAS 123, "Accounting for Stock-BasedCompensation," had been applied to stock-based employee compensation:

 

**2003**

 

**2002**

 

**2001**

 

**(thousands  of dollars)**

Net income, as reported

$

58,591 

 

$

88,920 

 

$

78,238

Add: Stock-based employee  compensation expense included

 

 

 

 

 

 

 

 

 

in reported net income, net  of related tax effects

 

(56)

 

 

(10)

 

 

403

Deduct: Total stock-based  employee compensation expense

 

 

 

 

 

 

 

 

 

determined under fair value  based method for all awards,

 

 

 

 

 

 

 

 

 

net of related tax effects

 

1,073 

 

 

1,837 

 

 

1,603

 

 

Pro forma net income

$

57,462 

 

$

87,073 

 

$

77,038

 

 

 

 

 

 

 

 

 

 

 

 

**2.  INCOME TAXES:**

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

 

 

**2003**

 

**2002**

 

**2001**

 

 

**(thousands of dollars)**

Federal income tax expense at 35% statutory rate

$

28,112 

 

$

30,214 

 

$

46,118 

Change in taxes resulting from:

 

 

 

 

 

 

 

 

 

AFDC

 

(2,343)

 

 

(948)

 

 

(1,571)

 

Investment tax credits

 

(3,397)

 

 

(3,179)

 

 

(3,169)

 

Repair allowance

 

(2,450)

 

 

(2,450)

 

 

(2,800)

 

Capitalized overhead costs

 

(3,658)

 

 

(3,500)

 

 

- 

 

Tax accounting method change

 

- 

 

 

(31,162)

 

 

- 

 

Settlement of prior years tax returns

 

(8,908)

 

 

(2,600)

 

 

- 

 

State income taxes, net of federal benefit

 

3,973 

 

 

3,946 

 

 

4,313 

 

Depreciation

 

10,237 

 

 

8,940 

 

 

9,790 

 

Other, net

 

162 

 

 

(1,855)

 

 

848 

Total income tax expense (benefit)

$

21,728 

 

$

(2,594)

 

$

53,529 

 

Effective tax rate

 

27.1%

 

 

(3.0)%

 

 

40.6%

 

The items comprising incometax expense are as follows:

 

 

**2003**

 

**2002**

 

**2001**

 

 

**(thousands  of dollars)**

Income taxes currently payable (receivable):

 

 

 

 

 

 

 

 

 

Federal

$

55,034 

 

$

70,318 

 

$

(37,352)

 

State

 

10,915 

 

 

8,599 

 

 

(12,544)

 

 

Total

 

65,949 

 

 

78,917 

 

 

(49,896)

Income taxes deferred:

 

 

 

 

 

 

 

 

 

Federal

 

(35,166)

 

 

(75,600)

 

 

84,372 

 

State

 

(9,284)

 

 

(5,455)

 

 

17,087 

 

 

Total

 

(44,450)

 

 

(81,055)

 

 

101,459 

Investment tax credits:

 

 

 

 

 

 

 

 

 

Deferred

 

3,627 

 

 

2,722 

 

 

5,135 

 

Restored

 

(3,398)

 

 

(3,178)

 

 

(3,169)

 

 

Total

 

229 

 

 

(456)

 

 

1,966 

Total income tax expense (benefit) 

$

21,728 

 

$

(2,594)

 

$

53,529 

 

 

 

 

 

 

 

 

 

 

The components of IPC's netdeferred tax liability are as follows:

 

**2003**

 

**2002**

 

**(thousands  of dollars)**

Deferred tax assets:

 

 

 

 

 

 

Regulatory liabilities

$

41,024

 

$

41,013

 

Advances for construction

 

4,162

 

 

3,759

 

Other

 

16,151

 

 

19,800

 

 

Total

 

61,337

 

 

64,572

Deferred tax liabilities:

 

 

 

 

 

 

Property, plant and equipment

 

238,602

 

 

230,935

 

Regulatory assets

 

330,833

 

 

327,933

 

Conservation programs

 

8,310

 

 

10,426

 

PCA

 

27,529

 

 

53,324

 

Other

 

8,447

 

 

33,243

 

 

Total

 

613,721

 

 

655,861

 

 

 

 

 

 

Net deferred tax liabilities

$

552,384

 

$

591,289

 

 

 

 

 

 

 

 

**3.  COMMON STOCK:**

In December 2003, IPCissued 1,538,461 shares of $2.50 par value common stock to IDACORP for $40million.

**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, interestaccrued and taxes accrued are reported at their carrying value as these are areasonable estimate of their fair value. The estimated fair values for notesreceivable, long-term debt and investments and other property are based uponquoted market prices of the same or similar issues or discounted cash flowanalyses as appropriate.

 

**December  31, 2003**

 

**December  31, 2002**

 

**Carrying**

 

**Estimated**

 

**Carrying**

 

**Estimated**

 

**Amount**

 

**Fair  Value**

 

**Amount**

 

**Fair  Value**

 

**(thousands  of dollars)**

**Assets:**

 

 

 

 

 

 

 

 

 

 

 

Notes receivable

$

10,145

 

$

10,159

 

$

9,646

 

$

10,063

Investments and other property

 

22,408

 

 

22,408

 

 

20,401

 

 

20,401

 

 

 

 

 

 

 

 

 

 

 

 

**Liabilities:**

 

 

 

 

 

 

 

 

 

 

 

Long-term debt

$

933,150

 

$

957,399

 

$

953,230

 

$

1,015,612

 

 

 

 

 

 

 

 

 

 

 

 

 

**9.  STOCK-BASED COMPENSATION:**

The 2000 LTICP for officers,key employees and directors, permits the grant of nonqualified stock options,incentive stock options, stock appreciation rights, restricted stock,restricted stock units, performance units, performance shares and other awards.

The maximum number of shares availableunder the LTICP is 2,050,000 in 2003, 2002 and 2001, IDACORP issued to IPCemployees 343,000, 230,000 and 144,000 stock options, respectively, with anexercise price equal to the market price of IDACORP's stock on the date ofgrant.  In accordance with APB 25, nocompensation costs have been recognized for the option awards.

Stock option transactions are summarized asfollows:

 

 

**2003**

**2002**

**2001**

 

 

 

**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

594,000 

$

38.33

364,000

$

37.59

220,000

$

35.81

 

Granted

343,000 

 

22.95

230,000

 

39.50

144,000

 

40.31

 

Exercised

- 

 

-

-

 

-

-

 

-

 

Forfeited

(47,200)

 

36.42

-

 

-

-

 

-

Outstanding end of  year

889,800 

$

32.50

594,000

$

38.33

364,000

$

37.59

 

 

 

 

 

 

 

 

 

 

 

Exercisable

211,600 

$

37.84

100,800

$

37.10

36,000

$

35.81

 

The outstanding options have a range of exerciseprices from $22.92 to $40.31.  As ofDecember 31, 2003, the weighted average remaining contractual life is 8.0years.

IDACORP also has a restrictedstock plan for key employees including those of IPC.  Each grant made under this plan has a three-year restrictedperiod, and the final award amounts depend on the attainment of cumulative EPSperformance goals.  At December 31, 2003there were 145,314 IDACORP shares remaining available under this plan.

Restricted stock awards arecompensatory awards and IPC accrues compensation expense (which is charged tooperations) based upon the market value of the granted shares.  For the years 2003, 2002 and 2001, totalcompensation accrued under the plan was less than $1 million annually.

The following table summarizesrestricted stock activity for the years 2003, 2002 and 2001:

 

**2003**

 

**2002**

 

**2001**

Shares  outstanding - beginning of year

77,192 

 

58,024 

 

56,836 

Shares  granted

41,945 

 

38,752 

 

20,540 

Shares  forfeited

(1,889)

 

(132)

 

(474)

Shares  issued

(36,794)

 

(19,452)

 

(18, 878)

Shares  outstanding - end of year

80,454 

 

77,192 

 

58,024 

Weighted  average fair value of current year stock

 

 

 

 

 

 

grants  on grant date

$

22.95 

 

$

38.64 

 

$

38.02 

 

 

 

 

 

 

 

**16.  SUPPLEMENTAL CASH FLOW INFORMATION:**

Selected cash paymentsand non-cash activities were as follows (in thousands of dollars):

 

 

**Year  Ended December 31,**

 

 

**2003**

 

**2002**

 

**2001**

Cash paid (received) during the period for:

 

 

 

 

 

 

 

 

 

Income taxes paid to (received from) parent

$

99,879 

 

$

(17,974)

 

$

(28,510)

 

Interest (net of amount capitalized)

 

54,911 

 

 

56,167 

 

 

61,600 

Net assets transferred to parent for notes receivable

 

- 

 

 

- 

 

 

76,250 

 

 

 

 

 

 

 

 

 

 

** **

**17.  DISCONTINUED OPERATIONS:**

Effective June 11, 2001, IPCtransferred its non-utility wholesale electricity marketing operations("Energy Marketing") to IE.

Energy Marketing net assetstransferred consist primarily of energy trading contracts and trading accountsreceivable and accounts payable.  Theresults of operations of Energy Marketing were previously reported on IPC'sStatements of Income as "Energy marketing activities - net."  For 2001, Energy Marketing is reported as adiscontinued operation.

**18. RELATED PARTY TRANSACTIONS:**

**IDACORP**In exchange for the transfer of Energy Marketing to IE in June 2001,IPC received a partnership interest in IE, which was then transferred toIDACORP in exchange for notes receivable from IDACORP totaling approximately$76 million.  The notes receivable weredue over periods of one to ten years, bore interest at IDACORP's overall variableshort-term borrowing rate and were paid in full in 2003.

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.

**IDACORP Energy**In 2002 and 2001, IPC paid IE approximately $2 million annually underthe Electricity Supply Management Services Agreement.  In August 2002, IPC and IE terminated the Electricity SupplyAgreement eliminating all payments under that agreement.  The FERC has given public notice of IPC'srequest to cancel the agreement and no comments on the request were filed bythe due date.

 

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

 

**2003**

 

**2002**

 

**2001**

 

**(thousands  of dollars)**

Sales  to IE

$

2,268

 

$

27,182

 

$

21,288

Purchases  from IE

 

-

 

 

13,665

 

 

34,843

 

 

 

 

 

 

 

 

 

 

**IDACOMM**IPC provides project management andengineering services to IDACOMM. IDACOMM also pays joint use fees to IPC.  The following table presents the fees charged to IDACOMM:

 

**2003**

 

**2002**

 

**2001**

 

**(thousands  of dollars)**

Project  management

$

72

 

$

809

 

$

10

Engineering

 

141

 

 

73

 

 

-

Joint  use

 

61

 

 

176

 

 

-

Total

$

274

 

$

1,058

 

$

10

 

 

 

 

 

 

 

 

 

 

**Ida-West**IPC purchases all of the power generatedby four of Ida-West's hydroelectric projects.  IPC paid $7 million in both 2003 and 2002 and $6 million in 2001for this power.

 

 

 

 

INDEPENDENTAUDITORS' REPORT

 

To the Board of Directors andShareholder of Idaho Power CompanyBoise, Idaho

We have audited theaccompanying consolidated balance sheets and statements of capitalization ofIdaho Power Company and subsidiary as of December 31, 2003 and 2002, and therelated consolidated statements of income, comprehensive income, retainedearnings and cash flows for each of the three years in the period endedDecember 31, 2003.  Our audits alsoincluded the consolidated financial statement schedule listed in the Index atItem 8.  These financial statements andfinancial statement schedule are the responsibility of the Company'smanagement.  Our responsibility is toexpress an opinion on the financial statements and financial statement schedulebased on our audits.

We conducted our audits inaccordance with auditing standards generally accepted in the United States ofAmerica.  Those standards require that weplan and perform the audit to obtain reasonable assurance about whether thefinancial statements are free of material misstatement.  An audit includes examining, on a 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, suchconsolidated financial statements present fairly, in all material respects, thefinancial position of Idaho Power Company and subsidiary at December 31, 2003and 2002, and the results of their operations and their cash flows for each ofthe three years in the period ended December 31, 2003 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, theCompany changed its method of accounting and presentation of asset retirementobligations in 2003 in accordance with Statement of Financial AccountingStandards No. 143.

DELOITTE & TOUCHE LLP

Boise, ID February 27, 2004

 

 

**SUPPLEMENTAL FINANCIALINFORMATION, UNAUDITED**

**QUARTERLY FINANCIAL DATA:**

The following unauditedinformation is presented for each quarter of 2003 and 2002 (in thousands ofdollars except for per share amounts). In the opinion of each company, all adjustments necessary for a fairstatement 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**

 

 

 

 

 

 

 

 

 

2003

 

 

 

 

 

 

 

 

Revenues

$

211,928 

$

200,276 

$

239,228 

$

171,570 

Income  from operations

 

11,434 

 

14,000 

 

47,974 

 

10,654 

Income  tax benefit

 

- 

 

- 

 

(12,495)

 

(8,624)

Net income (loss)*

 

(3,072)

 

(879)

 

46,775 

 

3,754 

Earnings (loss) per share of common stock

 

(0.08)

 

(0.02)

 

1.22 

 

0.10 

 

 

 

 

 

 

 

 

 

2002

 

 

 

 

 

 

 

 

Revenues

$

239,593 

$

209,832 

$

259,576 

$

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)

 

 

 

 

 

 

 

 

 

*See "Wind down of Energy Marketing"  in Note 13 to IDACORP's Consolidated Financial Statements, 

"Legal Proceedings - Overton Power District  No. 5" in Note 8 to IDACORP's Consolidated Financial

Statements and "Tax Accounting Method  Change" in Note 2 to IDACORP's Consolidated Financial

Statements.

 

**Idaho Power Company:**

 

**Quarter Ended**

 

**March 31**

**June 30**

**September 30**

**December 31**

 

 

 

 

 

 

 

 

 

2003

 

 

 

 

 

 

 

 

Revenues

$

202,990

$

197,265

$

214,225 

$

165,902

Income  from operations

 

32,333

 

27,339

 

37,696 

 

24,142

Income  tax expense 

 

7,893

 

2,457

 

11,133 

 

245

Net income

 

14,581

 

12,633

 

15,955 

 

15,422

Dividends on preferred stock

 

868

 

866

 

847 

 

849

Earnings on common stock

 

13,713

 

11,767

 

15,108 

 

14,573

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

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

None

**ITEM 9A.  CONTROLS AND PROCEDURES**

(a)  Evaluation of disclosure controls and procedures:

The Chief ExecutiveOfficer and Chief Financial Officer of IDACORP, Inc., based on their evaluationof IDACORP, Inc.'s disclosure controls and procedures (as defined in ExchangeAct Rule 13a-15(e)) as of December 31, 2003, have concluded that IDACORP,Inc.'s disclosure controls and procedures are effective.

The Chief ExecutiveOfficer and Chief Financial Officer of Idaho Power Company, based on theirevaluation of Idaho Power Company's disclosure controls and procedures (asdefined in Exchange Act Rule 13a-15(e)) as of December 31, 2003, have concludedthat Idaho Power Company's disclosure controls and procedures are effective.

(b)  Changes in internal control over financial reporting:

There has been nochange in IDACORP, Inc.'s or Idaho Power Company's internal control overfinancial reporting identified in connection with the evaluation required byExchange Act Rule 13a-15(d) that occurred during IDACORP, Inc.'s or Idaho PowerCompany's most recent fiscal quarter that has materially affected, or isreasonably likely to materially affect IDACORP, Inc.'s or Idaho Power Company'sinternal control over financial reporting.

** **

 

 

**PART III**

**ITEM 10.  DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS**

The portion of our jointdefinitive proxy statement appearing under the captions "Election ofDirectors - IDACORP and Idaho Power Nominees For Election - Terms Expire2007," "IDACORP and Idaho Power Continuing Directors - Terms Expire2006," "IDACORP and Idaho Power Continuing Directors - Terms Expire2005," "The Boards of Directors and Committees - Committees - AuditCommittees" and "Corporate Governance - Process for Shareholders toRecommend Nominees for Directors," to be filed pursuant to Regulation 14Afor the 2004 Annual Meeting of Shareholders to be held on May 20, 2004 ishereby incorporated by reference.

Idaho Power has had for manyyears a Code of Business Conduct and Ethics, which applied to all directors,officers and employees of Idaho Power, including the principal executiveofficer and senior financial and accounting officers.  IDACORP adopted a new Code of Business Conduct and Ethics in July2003, which applies to all directors, officers, including the chief executiveofficer, principal financial and accounting officers, and employees of IDACORPand its subsidiaries.  The Code ofConduct may be accessed at the IDACORP website athttp://www.idacorpinc.com/CorpGov/conduct_ethics.cfm.  Printed copies may be obtained without charge by writing to theCorporate Secretary, IDACORP, 1221 West Idaho Street, Boise, Idaho 83702.

Amendments to the Code orwaivers of the Code as required by Regulation S-K, Item 406 or the New YorkStock Exchange listing standards will be posted on the IDACORP website referredto above.

**ITEM 11.  EXECUTIVE COMPENSATION**

The portion of our jointdefinitive proxy statement appearing under the caption "Compensation ofDirectors and Executive Officers" (except the Report of the Compensation Committee and the PerformanceGraph) to be filed pursuant to Regulation 14A for the 2004 Annual Meeting ofShareholders to be held on May 20, 2004 is hereby incorporated by reference.

 

** **

**ITEM 12.  SECURITY OWNERSHIPOF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS**

The portion of our jointdefinitive proxy statement appearing under the captions "PrincipalShareholders" and "Security Ownership of Directors and ExecutiveOfficers" to be filed pursuant to Regulation 14A for the 2004 AnnualMeeting of Shareholders to be held on May 20, 2004 is hereby incorporated byreference.

**Equity Compensation PlanInformation:**

The following table includes information as of December31, 2003 with respect to equity compensation plans where equity securities ofIDACORP may be issued.  There are noplans where equity securities of IPC may be issued.  These plans are the 1994 Restricted Stock Plan (RSP), the IDACORP2000 Long Term Incentive and Compensation Plan (LTICP) and the DirectorCompensation Plan (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)

1,150,800

$32.72

1,044,514(2)(3)

Equity compensation

 

 

 

plans not approved by

 

 

 

shareholders (4)

-

-

83,101

Total

1,150,800

$32.72

1,127,615

(1)

Consists of the RSP and the LTICP.

(2)

In addition to being available for future issuance upon  exercise of options, 899,200 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)

145,314 shares remain available for future issuance  under the RSP.

(4)

Consists of the DCP.

 

**Equity Compensation Plans NotApproved by IDACORP Shareholders**

The DCP was adopted by theIDACORP Board of Directors effective May 17, 1999, and provided for an annualstock grant in June of each year valued at $6,000.  The purpose of the DCP is to increase director's stock ownershipthrough stock based director compensation. The DCP was amended again effective April 1, 2002 to increase the annualgrant to stock valued at $16,000.  Thisincrease offset the termination of the directors' non-qualified deferredcompensation plan.  Because the IDACORPand IPC Boards of Directors are comprised of the same members, IPC non-employeedirectors do not receive an additional grant. The plan provides for a total of 100,000 shares that may be granted fromtreasury stock or stock purchased on the open market.

**ITEM 13.  CERTAIN RELATIONSHIPS AND RELATEDTRANSACTIONS**

N/A

**ITEM 14.  PRINCIPAL ACCOUNTING FEES AND SERVICES**

The portion of our joint definitive proxy statementappearing under the caption "Independent Accountant Billings" and"Audit Committee Policy for Pre-Approval of Independent AuditorServices" in Exhibit B to the proxy statement to be filed pursuant toRegulation 14A for the 2004 Annual Meeting of Shareholders to be held on May20, 2004 is hereby incorporated by reference.

 

 

**PART IV**

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

(a)      Please refer to Part II, Item 8 - "FinancialStatements and Supplementary Data" for a complete listing of allconsolidated financial statements and financial statement schedules.

(b)     Reports on SEC Form 8-K.  The following Reports on Form 8-K were filed for the three monthsended December 31, 2003.

Items Reported

 
Date of  Report Filed by
Item 5 - Other Events and Regulation FD  Disclosure

 

November 13, 2003

 

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 the quarter ended 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 the quarter ended 3/31/03

3(b)

By-laws of IPC amended on  March 20, 2003, 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)

333-104254

4(e)

Amended Bylaws of IDACORP,  Inc. amended on March 20, 2003, and presently in effect.

 

 

 

 

*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

 

1-3198  Form 8-K  Dated 4/15/03

4

Thirty-seventh

April 1, 2003

 

1-3198  Form 10-Q  Dated 6/30/03

4(a)(iii)

Thirty-eighth

May 15, 2003

 

 

 

 

 

 

1-3198  Form 10-Q  for the quarter ended 9/30/03

4(a)(iii)

Thirty-ninth

October 1, 2003

 

 

 

 

*4(b)

1-3198  Form 10-Q  for the quarter ended 6/30/00

4(b)

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

 

 

 

 

*4(c)(i)

33-65720

4(f)

Agreement of IPC to furnish  certain debt instruments.

 

 

 

 

*4(c)(ii)

1-11465  Form 10-Q  for the quarter ended 9/30/03

4(c)(ii)

Agreement of IDACORP, Inc. 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, 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)

333-67748

4.13

Indenture for Debt Securities  dated as of August 1, 2001 between Idaho Power Company and Deutsche Bank  Trust Company Americas (formerly known as Bankers Trust Company), as trustee.

 

 

 

 

*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 the quarter ended 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

 

 

IDACORP, Inc. 2003 Executive  Incentive Plan.

 

 

 

 

*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

1-14465  1-3198  Form 10-K  for 2002

10(h)(v)

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

 

 

 

 

*10(h)(vi)

1-14465  Form 10-Q  for the quarter ended 9/30/99

10(h)

Agreement between IDACORP,  Inc. and Jan B. Packwood, J. LaMont Keen, James C. Miller, Darrel T.  Anderson, Bryan Kearney and Robert W. Stahman.

 

 

 

 

 

 

 

 

1 Compensatory plan

 

 

 

 

 

 

*10(h)(vii) 1

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

10(i)  10(h)(ix)

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

 

 

 

 

*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.

 

 

 

 

*10(k)

1-3198  Form 10-Q  for the quarter ended 6/30/03

10(k)

Power Purchase Agreement  between IPC and PPL Montana, LLC, dated March 1, 2003 and Revised Confirmation  Agreement dated May 9, 2003.

 

 

 

 

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)

 

 

 

 

12(f)

 

 

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

 

 

 

 

 

 

 

 

1 Compensatory plan

 

 

 

 

 

 

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.

 

 

 

 

31(a)

 

 

Rule 13a-14(a) certification.

 

 

 

 

31(b)

 

 

Rule 13a-14(a) certification.

 

 

 

 

31(c)

 

 

Rule 13a-14(a) certification.

 

 

 

 

31(d)

 

 

Rule 13a-14(a) certification.

 

 

 

 

32(a)

 

 

Section 1350 certification.

 

 

 

 

32(b)

 

 

Section 1350 certification.

 

 

 

 

 

 

 

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

Years Ended December 31, 2003, 2002 and 2001

**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)**

 

 

2003:

 

 

 

 

 

 

 

 

 

 

Reserves Deducted From

 

 

 

 

 

 

 

 

 

 

 

Applicable Assets:

 

 

 

 

 

 

 

 

 

 

 

 

Reserve for uncollectible accounts

$

43,311

$

3,958 

$

- 

$

4,059

$

43,210

 

 

Reserve for uncollectible notes

 

-

 

2,578 

 

- 

 

-

 

2,578

Other Reserves:

 

 

 

 

 

 

 

 

 

 

 

Rate refunds

 

-

 

1,514 

 

- 

 

-

 

1,514

 

Injuries and damages reserve

 

1,936

 

111 

 

- 

 

1,216

 

831

 

Miscellaneous operating reserves

 

2,491

 

167 

 

(227)

 

-

 

2,431

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 

 

Notes:

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

 

 

**IDAHO POWER COMPANYSCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS**

Years Ended December 31, 2003, 2002 and 2001

**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)**

 
 

 
2003:

 

 

 

 

 

 

 

 

 

 

 
Reserves Deducted From

 

 

 

 

 

 

 

 

 

 

 
 

Applicable Assets:

 

 

 

 

 

 

 

 

 

 

 
 

 

Reserve for uncollectible accounts

$

1,566

$

3,958 

$

- 

$

4,058

$

1,466

 
Other Reserves:

 

 

 

 

 

 

 

 

 

 

 
 

Rate refunds

 

-

 

1,514 

 

- 

 

-

 

1,514

 
 

Injuries and damages reserve

 

1,936

 

111 

 

- 

 

1,216

 

831

 
 

Miscellaneous operating reserves

 

2,491

 

167 

 

(227)

 

-

 

2,431

 
 

 

 

 

 

 

 

 

 

 

 

 
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

 
 

 

 

 

 

 

 

 

 

 

 

 

 
Notes:

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

 

 

 

**SIGNATURES**Pursuant to the requirements of Section 13 or 15(d) of the SecuritiesExchange Act of 1934, the registrant has caused this report to be signed on itsbehalf by the undersigned, thereunto duly authorized.

IDACORP,Inc.(Registrant)

March4, 2004

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

Pursuantto the requirements of the Securities Exchange Act of 1934, this report hasbeen signed below by the following persons on behalf of the registrant and inthe capacities and on the dates indicated.

By:

/s/

*Jon  H. Miller*

 

/s/

Chairman  of the Board

March  4, 2004

 

 

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/
Peter S. O'Neill
"

 

 

Rotchford  L. Barker

 

 

Peter  S. O'Neill

 

 

 

Director

 

 

Director

 

 

 

 

 

 

 

 

By:

 

 

By:

/s/

*Richard  G. Reiten*

"

 

 

Christopher  L. Culp

 

 

Richard  G. Reiten

 

 

 

Director

 

 

Director

 

 

 

 

 

 

 

 

By:

/s/

*Jack  K. Lemley*

By:

/s/

*Robert  A. Tinstman*

"

 

 

Jack  K. Lemley

 

 

Robert  A. Tinstman

 

 

 

Director

 

 

Director

 

 

 

 

 

 

 

 

By:

/s/

*Gary  G. Michael*

 

 

 

 

 

 

Gary  G. Michael

 

 

 

 

 

 

Director

 

 

 

 

 

 

 

 

 

 

 

 

 

**SIGNATURES**

Pursuantto the requirements of Section 13 or 15(d) of the Securities Exchange Act of1934, the registrant has caused this report to be signed on its behalf by theundersigned, thereunto duly authorized.

IDAHOPOWER COMPANY(Registrant)

March4, 2004

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

Pursuantto the 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 4, 2004

 

 

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/
Peter S. O'Neill
"

 

 

Rotchford  L. Barker

 

 

Peter  S. O'Neill

 

 

 

Director

 

 

Director

 

 

 

 

 

 

 

 

By:

 

 

By:

/s/

*Richard  G. Reiten*

"

 

 

Christopher  L. Culp

 

 

Richard  G. Reiten

 

 

 

Director

 

 

Director

 

 

 

 

 

 

 

 

By:

/s/

*Jack  K. Lemley*

By:

/s/

*Robert  A. Tinstman*

"

 

 

Jack  K. Lemley

 

 

Robert  A. Tinstman

 

 

 

Director

 

 

Director

 

 

 

 

 

 

 

 

By:

/s/

*Gary  G. Michael*

 

 

 

 

 

 

Gary  G. Michael

 

 

 

 

 

 

Director

 

 

 

 

 

 

 

**EXHIBITINDEX**

 

 

 

Exhibit Number

 

 

 

 

 

10(h)(ii) 1

 

IDACORP, Inc. 2003 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.

 

 

 

31(a)

 

Rule  13a-14(a) certification.

 

 

 

31(b)

 

Rule  13a-14(a) certification.

 

 

 

31(c)

 

Rule  13a-14(a) certification.

 

 

 

31(d)

 

Rule  13a-14(a) certification.

 

 

 

32(a)

 

Section  1350 certification.

 

 

 

32(b)

 

Section  1350 certification.

 

 

 

 

 

1 Compensatory plan

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--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------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