**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, 2004                                            |

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

 

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

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, 2004):
| IDACORP,  Inc.: | $1,026,608,013 | Idaho  Power Company: | None |
|-----------------|----------------|-----------------------|------|

 

Numberof shares of common stock outstanding at February 28, 2005:
| IDACORP,  Inc.:       | 42,217,017                            |
|-----------------------|---------------------------------------|
| Idaho  Power Company: | 39,150,812  all held by IDACORP, Inc. |

 
| **Documents Incorporated by  Reference:** |
|-------------------------------------------|
|                                      |
| Part  III, Items 10 - 14                  | Portions of IDACORP, Inc.'s definitive proxy  statement to be filed pursuant to Regulation 14A for the |
|                                      | 2005 Annual Meeting of Shareholders to be held  on May 19, 2005. |

 

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.

Idaho Power Company meets the conditions set forthin General Instruction (I)(1)(a) and (b) of Form 10-K and is therefore filingthis Form with the reduced disclosure format.
| **COMMONLY USED TERMS** |
|-------------------------|
|                    |
| AFDC                    | - | Allowance  for Funds Used During Construction |
| Cal  ISO                | - | California  Independent System Operator |
| CalPX                   | - | California  Power Exchange |
| CSPP                    | - | Cogeneration  and Small Power Production |
| EPS                     | - | Earnings  per share |
| ESA                     | - | Endangered  Species Act |
| FASB                    | - | Financial  Accounting Standards Board |
| FERC                    | - | Federal  Energy Regulatory Commission |
| FIN                     | - | Financial  Accounting Standards Board Interpretation |
| Fitch                   | - | Fitch,  Inc. |
| FSP                     | - | Financial  Accounting Standards Board Staff Position |
| GAAP                    | - | Accounting  Principles Generally Accepted in the United States of America |
| Ida-West                | - | Ida-West  Energy, a subsidiary of IDACORP, Inc. |
| IE                      | - | IDACORP  Energy, a subsidiary of IDACORP, Inc. |
| IFS                     | - | IDACORP  Financial Services, a subsidiary of IDACORP, Inc. |
| IPC                     | - | Idaho  Power Company, a subsidiary of IDACORP, Inc. |
| IPUC                    | - | Idaho  Public Utilities Commission |
| IRP                     | - | Integrated  Resource Plan |
| MD&A                | - | Management's  Discussion and Analysis of Financial Condition and Results of Operations |
| Moody's                 | - | Moody's  Investors Service |
| MW                      | - | Megawatt |
| MWh                     | - | Megawatt-hour |
| NEPA                    | - | National  Environmental Policy Act of 1996 |
| OPUC                    | - | Oregon  Public Utility Commission |
| PCA                     | - | Power  Cost Adjustment |
| PM&E                | - | Protection,  Mitigation and Enhancement |
| PURPA                   | - | Public  Utilities Regulatory Policy Act of 1978 |
| REA                     | - | Rural  Electrification Administration |
| RFP                     | - | Request  for Proposal |
| RTO                     | - | Regional  Transmission Organization |
| S&P                 | - | Standard  & Poor's Ratings Services |
| SFAS                    | - | Statement  of Financial Accounting Standards |
| Valmy                   | - | North  Valmy Steam Electric Generating Plant |
| VIEs                    | - | Variable  Interest Entities |
|                    |   |   |

 

 

 

 

 

 

 
| **TABLE OF CONTENTS** |
|-----------------------|
|                  | **Page** |
| **Part  I**           |
|                  |
|                  | Item  1. | Business | 1-11 |
|                  | Item  2. | Properties | 11-12 |
|                  | Item  3. | Legal  Proceedings | 12 |
|                  | Item  4. | Submission  of Matters to a Vote of Security Holders | 12 |
|                  |
|                  | Executive  Officers of the Registrant | 13 |
|                  |
| **Part  II**          |
|                  |
|                  | Item  5. | Market  for Registrant's Common Equity, Related Stockholder |   |
|                  |   |   | Matters  and Issuer Purchases of Equity Securities | 14 |
|                  | Item  6. | Selected  Financial Data | 15 |
|                  | Item  7. | Management's  Discussion and Analysis of Financial Condition and |   |
|                  |   |   | Results  of Operations | 15-56 |
|                  | Item  7A. | Quantitative  and Qualitative Disclosures about Market Risk | 56-57 |
|                  | Item  8. | Financial  Statements and Supplementary Data | 58-112 |
|                  | Item  9. | Changes  in and Disagreements with Accountants on Accounting and |   |
|                  |   |   | Financial  Disclosure | 113 |
|                  | Item  9A. | Controls  and Procedures | 113-117 |
|                  | Item  9B. | Other  Information | 117 |
|                  |
| **Part  III**         |
|                  |
|                  | Item  10. | Directors  and Executive Officers of the Registrant* | 117 |
|                  | Item  11. | Executive  Compensation* | 117 |
|                  | Item  12. | Security  Ownership of Certain Beneficial Owners and Management and Related |   |
|                  |   |   | Stockholder  Matters* | 117 |
|                  | Item  13. | Certain  Relationships and Related Transactions* | 117 |
|                  | Item  14. | Principal  Accountant Fees and Services* | 118-119 |
|                  |
| **Part  IV**          |
|                  |
|                  | Item  15. | Exhibits  and Financial Statement Schedules | 119-132 |
|                  |
|                  | Signatures | 133-134 |
|                  |
|                  |   |   |
|                  |
|                  | *IDACORP,  Inc. information is incorporated by reference to IDACORP, Inc.'s definitive  proxy statement for |
|                  | the  2005 Annual Meeting of Shareholders. |

 

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**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 similarexpressions.

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

**ITEM 1. BUSINESS**

**OVERVIEW:**

IDACORP,Inc. (IDACORP) is a holding company formed in 1998 whose principal operatingsubsidiary is Idaho Power Company (IPC). IDACORP is exempt from registration as a public utility holding companypursuant to Section 3(a)(1) of the Public Utility Holding Company Act of 1935(1935 Act).  In addition, pursuant toRule 2 of the General Rules and Regulations under the 1935 Act, IDACORP is exemptfrom all the provisions of the 1935 Act and rules thereunder, except forSection 9(a)(2) of the 1935 Act, which requires IDACORP to seek priorSecurities and Exchange Commission approval to acquire securities of anotherpublic utility company.

IPCis an electric utility engaged in the generation, transmission, distribution,sale and purchase of electric energy. IPC is regulated by the Federal Energy Regulatory Commission (FERC) andthe state regulatory commissions of Idaho and Oregon.  IPC is the parent of Idaho Energy Resources Co., a joint venturerin Bridger Coal Company, which supplies coal to the Jim Bridger generatingplant owned in part by IPC.

IDACORP'sother operating subsidiaries include:

IDACORPFinancial Services, Inc. (IFS) - holder of affordable housing and other realestate investments;

IdaTech- developer of integrated fuel cell systems;

IDACOMM- provider of telecommunications services and commercial and residentialInternet services; and

Ida-WestEnergy (Ida-West) - operator of independent power projects.

 

IDACORPEnergy (IE), a marketer of electricity and natural gas, wound down itsoperations during 2003.  Also in2003, Ida-West discontinued its project development operations and is managingits independent power projects with a reduced workforce.

IDACORPcontinues to focus 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 corporate strategy recognizes that IPC must makesubstantial 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 affordable housing andhistoric rehabilitation portfolio, remains a key component of the revisedcorporate strategy.

AtDecember 31, 2004, IDACORP had 1,940 full-time employees.  Of these employees, 1,757 were employed byIPC.

IDACORP'stwo reportable business segments are IPC and IFS.  IPC and IFS contributed $66 million and $13 million,respectively, to consolidated net income in 2004.  Financial information relating to IDACORP's reportable segmentsis presented in Note 12 to IDACORP's Consolidated Financial Statements andbelow in "Utility Operations" and "IFS."

Due to its wind down in 2003-2004, IE did not haveany significant business activity in 2004. As a result, the energy marketing operations of IE are no longer areportable business segment.  See Note 15to IDACORP's Consolidated Financial Statements for further discussion of thewind down.

IDACORPand IPC make available free of charge their Annual Report on Form 10-K,Quarterly Reports on Forms 10-Q, Current Reports on Forms 8-K and allamendments to these reports filed or furnished pursuant to Section 13(a) or15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicableafter the reports are electronically filed with or furnished to the Securitiesand Exchange Commission, through their websites at www.idacorpinc.comand www.idahopower.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, distributionand sale of electric energy in a 24,000 square mile area in southern Idaho andeastern Oregon, with an estimated population of 895,000.  The measurement of IPC's service areaincreased by approximately 4,000 square miles over 2003 due to the conversionfrom a manual mapping system to global information system technology.  IPC holds franchises in 71 cities in Idahoand nine cities in Oregon and holds certificates from the respective publicutility regulatory authorities to serve all or a portion of 24 counties inIdaho and three counties in Oregon.  Asof December 31, 2004, IPC supplied electric energy to approximately 440,000general business customers.

IPCowns and operates 17 hydroelectric power plants and one natural gas-fired plantand shares ownership in three coal-fired generating plants.  A second gas-fired plant, Bennett MountainPower Plant, is currently under construction and due on-line in 2005.  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 snow pack in themountains upstream of IPC's hydroelectric facilities, precipitation and otherweather and stream flow management considerations.  When hydroelectric generation decreases below load requirementsand/or customer demand increases beyond hydroelectric capacity, IPC increasesits use of more expensive thermal generation and purchased power.

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

IPC'sprincipal commercial and industrial customers are involved in food processing,electronics and general manufacturing, forest product production, beet sugarrefining and the skiing industry.

**Regulation**IPC is under theregulatory jurisdiction (as to rates, service, accounting and other generalmatters of utility operation) of the FERC, the Idaho Public UtilitiesCommission (IPUC) and the Oregon Public Utility Commission (OPUC).  IPC is also under the regulatoryjurisdiction of the IPUC, the OPUC and the Public Service Commission of Wyomingas to the issuance of debt and equity securities.  IPC is subject to the provisions of the Federal Power Act as a"public utility" as therein defined. IPC's retail rates are established under the jurisdiction of the stateregulatory commissions and its wholesale and transmission rates are regulatedby the FERC (see "Rates" below). Pursuant to the requirements of Section 210 of the Public UtilitiesRegulatory Policy Act of 1978 (PURPA), the state regulatory commissions haveeach issued orders and rules regulating IPC's purchase of power fromcogeneration and small power production (CSPP) facilities.

IPC is subject to the provisionsof the Federal Power Act as a "licensee" as therein defined.  As alicensee under the Federal Power Act, IPC and its licensed hydroelectricprojects are subject to the provisions of Part I of the Federal Power Act.  All licenses are subject to conditions setforth in the Federal Power Act and related FERC regulations.  These conditions and regulations includeprovisions relating to condemnation of a project upon payment of justcompensation, amortization of project investment from excess project earnings,possible takeover of a project after expiration of its license upon payment ofnet 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 Federal Power Act or IPC's FERC licenses (see Part II, Item 7 -"MD&A - REGULATORY ISSUES - Relicensing of HydroelectricProjects").

**Rates**The rates IPC charges toits general business customers are determined by the IPUC and the OPUC.  Approximately 96 percent of IPC's generalbusiness revenue comes from customers in Idaho.  IPC has a Power Cost Adjustment (PCA) mechanism that provides forannual adjustments to the rates charged to its Idaho retail customers.  These adjustments are based on forecasts ofnet power supply costs, which are fuel and purchased power less off-systemsales, and the true-up of the prior year's forecast.  During the year, 90 percent of the difference between the actualand forecasted costs is deferred with interest.  The ending balance of this deferral, called the true-up for thecurrent year's portion and the true-up of the true-up for the prior years'unrecovered portion, is then included in the calculation of the next year'sPCA.

Forfurther discussion see Part II, Item 7 - "MD&A - REGULATORY ISSUES -General Rate Case," "MD&A REGULATORY ISSUES - Deferred PowerSupply Costs" and Note 13 to IDACORP's Consolidated Financial Statements.

**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 stations and 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 summer demand in 2004was 2,843 MW, set on June 24 and peak winter demand for the year was 2,196 MWon January 5.  IPC expects total systemenergy requirements to grow 2.5 percent annually over the next three years.

The following table presents IPC's systemgeneration for the last three years:
|          | **MWh**                  |   | **Percent  of total generation** |
|---------------|--------------------------|--------|----------------------------------|
|          | **2004**                 |   | **2003**                         |   | **2002** |   | **2004** |   | **2003** |   | **2002** |
|          | **(thousands  of MWhs)** |   |                             |   |   |   |   |
| Hydroelectric | 6,041                    |   | 6,149                            |   | 6,069 |   | 45% |   | 47% |   | 45% |
| Thermal       | 7,303                    |   | 6,914                            |   | 7,286 |   | 55% |   | 53% |   | 55% |
|          | Total system generation  | 13,344 |                             | 13,063 |   | 13,355 |   | 100% |   | 100% |   | 100% |
|          |                     |   |                             |   |   |   |   |   |   |   |   |
|               |                          |        |                                  |  |  |  |  |  |  |  |  |  |

 

The amount of electricity IPC is able to generatefrom its hydroelectric plants depends on a number of factors, primarily snowpack in the mountains upstream of its hydroelectric facilities, reservoirstorage and stream flow conditions. When these factors are favorable, IPC can generate more electricityusing its hydroelectric plants.  Whenthese factors are unfavorable, IPC must increase its reliance on more expensivethermal generation and purchased power.

Continued below normal stream flow conditions in2004 yielded a system generation mix of 45 percent hydroelectric and 55 percentthermal.  Under normal stream flowconditions, IPC's system generation mix is approximately 55 percenthydroelectric and 45 percent thermal.

Below average stream flow conditionsare continuing for a sixth consecutive year in 2005.  The forecast released on March 8, 2005 by the Northwest RiverForecast Center indicates Brownlee inflow for April through July 2005 isexpected to total 1.74 million acre-feet, or 28 percent of average.  Snow pack accumulation was 60 percent ofaverage on March 8, 2005.  Storage inselected federal reservoirs upstream of Brownlee at the end of December 2004was 60 percent of average.  October 1,2004 storage in these reservoirs, which is considered carryover storage intowater year 2005, was only 41 percent of average.  The flows in the Snake River at several measurement locations areat or near record lows.

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 directlyinterconnected with the transmission systems of the Bonneville PowerAdministration, Avista Corporation, PacifiCorp, NorthWestern Energy and SierraPacific Power Company.  Such interconnections,coupled with transmission line capacity made available under agreements withsome of the above entities, 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, the Northwest Power Pool and the Northwest RegionalTransmission Association.  These groupshave been formed to more efficiently coordinate transmission reliability andplanning throughout the western grid. See "Competition - Wholesale" below.

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

The IRP is filed every two years with both theIPUC and the OPUC.  Prior to filing, theIRP requires extensive involvement by IPC, the IPUC Staff and the OPUC Staff,as well as customer, technological and environmental representatives and is thestarting point for demonstrating prudence in IPC's resource decisions.

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

**CSPPPurchases**:  As mandated by the enactment of PURPA andthe adoption of avoided cost standards by the IPUC and the OPUC, IPC hasentered into contracts for the purchase of energy from a number of privatedevelopers.  Under these contracts, IPCis required to purchase all of the output from the facilities located insidethe IPC service territory.  For projectslocated outside the IPC service territory, IPC is required to purchase theoutput that IPC has the ability to receive at the facility's requested point ofdelivery on the IPC system.  The costsassociated with these Idaho jurisdictional contracts are fully recoveredthrough the PCA.  For IPUCjurisdictional projects, projects up to ten MW are eligible for IPUC PublishedAvoided Costs for up to a 20-year contract term.  The Published Avoided Cost is a price established by the IPUC andthe OPUC to estimate IPC's cost of developing additional generationresources.  For OPUC jurisdictionalprojects, projects up to one MW are eligible for OPUC Published Avoided Costsfor up to a five-year contract term (automatically renewable at the end of fiveyears).  The costs associatedwith these Oregon jurisdictional contracts are recovered through general ratecase filings.  TheOregon provisions are currently being reviewed in an OPUC proceeding, asdiscussed in Part II, Item 7 - "MD&A - REGULATORY ISSUES - PublicUtilities Regulatory Policy Act of 1978 - Oregon." If a PURPA project doesnot qualify for Published Avoided Costs, then IPC is required to negotiate theterms, prices and conditions with the developer of that project.  These negotiations reflect thecharacteristics of the individual projects (i.e., operational flexibility,location and size) and the benefits to the IPC system and must be consistentwith other similar energy alternatives.

As ofDecember 31, 2004, IPC had signed agreements to purchase energy from 72 CSPPfacilities with contracts ranging from one to 30 years.   Of these facilities, 68 were on-line at theend of 2004; the other four facilities under contract are due to come on-linein 2005 and 2006.  During 2004, IPCpurchased 677,868 megawatt hours (MWh) from these projects at a cost of $40million, resulting in a blended price of 5.9 cents per kilowatt hour.

**WholesaleEnergy Market Activities:**  Guided by a Risk Management Policy andfrequently updated operating plans, IPC participates in the wholesale energymarket by buying power to meet load demands and selling power that is in excessof load demands.  IPC's marketactivities are influenced by its generating resources and how they aredispatched.  Hydroelectric generationfacilities enable IPC to optimize the water that is available by choosing whento run generation units and when to store water in reservoirs.  These decisions may result in increasedvolumes of market purchases and market sales. Even in below normal water years, there are opportunities to vary waterusage to maximize generation unit efficiency, capture marketplace economicbenefits and meet load demand.  Compliancefactors, such as allowable river stage elevation changes and flood controlrequirements, and wholesale energy market prices influence these dispatchdecisions.****

IPC hasthree firm wholesale power sales contracts and one wholesale contract for loadfollowing services.  The three powersales contracts range between three MW and fifteen MW.  The three MW contract expires in 2005 andwill not be renewed.  When the two othercontracts expire in 2006, IPC will either renew, negotiate an extension or usethis power to meet its own system requirements.  The load following contract with NorthWestern Energy provides theability to increase or decrease IPC generation by 30 MW to react toNorthWestern's system load changes.  Solong as IPC retains its Hells Canyon Complex operating flexibility, the loadfollowing contract is anticipated to be renewed into the foreseeable future.

IPC has one firm wholesale purchased powercontract.  This contract is with PPLMontana, LLC for 83 MW per hour to address increased demand during June, Julyand August.  The term of this contractbegan in June 2004 and runs through August 2009.

**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 to provide transmission services andreach a broad power sales market.  IPCholds rights-of-way from Midpoint substation in south-central Idaho througheastern Nevada to the Crystal switchyard north of Las Vegas, Nevada, known asthe Southwest Intertie Project.  IPCobtained the rights-of-way to construct a transmission line along thiscorridor, but no longer plans to build the line.  IPC is currently in discussions regarding the sale of theserights-of-way.

In December 1999, the FERC issued Order No. 2000encouraging companies with transmission assets to form Regional TransmissionOrganizations.  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 contractproviding for annual deliveries of coal through 2009 from the Black Butte CoalCompany's Black Butte and Leucite Hills mines located near the Jim Bridgerplant.  This contract supplements theBridger Coal Company deliveries and provides another coal supply to operate theJim Bridger plant.  The Jim Bridgerplant's rail load-in facility, the coal car unloading point and unit coal trainallow the plant to take advantage of potentially lower-cost coal from outsidemines for tonnage requirements above established contract minimums.

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

SierraPacific Power Company, as operator of the North Valmy Steam Electric GeneratingPlant, has an agreement with Arch Coal Sales Company, Inc. to supply coal tothe plant from 2002 through 2006.  IPCis obligated to purchase one-half of the coal, ranging from approximately515,000 tons to 762,500 tons annually. Sierra Pacific Power Company also has a coal supply contract with BlackButte Coal Company's Black Butte Mine for deliveries in 2005.  See also Part II, Item 7 - "MD&A -RESULTS OF OPERATIONS - Utility Operations - Fuel Expense."

TheBoardman plant receives coal from the Powder River Basin through annualcontracts.  Portland General Electric,as operator of the Boardman Plant, has an agreement with Triton Coal Company tosupply all of Boardman's 2005 coal requirements.

IPC'sDanskin and Bennett Mountain (due on-line in 2005) combustion turbines receivegas through the Williams Northwest Pipeline. All gas is purchased as needs are identified for summer peaks or to meetsystem requirements.  The gas istransported under a long-term capacity contract with the Williams NorthwestPipeline and an arrangement with IGI Resources, Inc.  The Williams Northwest Pipeline contract, which extends throughFebruary 28, 2007, with annual extensions at IPC's sole discretion, is for24,523 million British thermal units per day from the Sumas, Washingtonmetering point to the Elmore, Idaho metering point.

**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 forpower generation are subordinated to future upstream diversions of water forirrigation and other recognized consumptive uses.

Over time, increased irrigation development andother consumptive diversions have resulted in a reduction in the stream flowsavailable to fulfill IPC's water rights at certain hydroelectric generatingfacilities.  In reaction to thesereductions, IPC initiated and continues to pursue a course of action todetermine and protect its water rights. As part of this process, IPC and the State of Idaho signed the SwanFalls agreement on October 25, 1984, which provided a level of protection forIPC's hydropower water rights at specified plants by setting minimum streamflows and establishing an administrative process governing the futuredevelopment of water rights that may affect IPC's hydroelectricgeneration.  In 1987, Congress passed,and the President signed into law, House Bill 519.  This legislation permitted implementation of the Swan Fallsagreement and further provided that during the remaining term of certain ofIPC's project licenses the relationship established by the agreement would notbe considered by the FERC as being inconsistent with the terms of IPC's projectlicenses or imprudent for the purposes of determining rates under Section 205of the Federal Power Act.  The FERCentered an order implementing the legislation on March 25, 1988.

In addition to providing for the protection ofIPC's hydroelectric water rights, the Swan Falls agreement contemplated theinitiation of a general adjudication of all water uses within the Snake Riverbasin.  In 1987, the director of theIdaho Department of Water Resources filed a petition in state district courtasking that the court adjudicate all claims to water rights, whether based onstate or federal law, within the Snake River basin.  The court signed a commencement order initiating the Snake RiverBasin Adjudication on November 19, 1987. This legal proceeding was authorized by state statute based upon adetermination by the Idaho Legislature that the effective management of thewaters of the Snake River basin required a comprehensive determination of thenature, extent and priority of all water uses within the basin.  The adjudication is proceeding and isexpected to continue for at least the next several years.  IPC has filed claims to its water rightswithin the basin and is actively participating in the adjudication to ensurethat its water rights and the operation of its hydroelectric facilities are notadversely impacted.  IPC does notanticipate any modification of its water rights as a result of the adjudicationprocess.

Pleasealso see Part II, Item 7 - "MD&A - LEGAL AND ENVIRONMENTAL ISSUES -Environmental Issues - Idaho Water Management Issues" and "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 2005 capitalexpenditures for environmental matters, excluding Allowance for Funds UsedDuring Construction (AFDC), will total $18 million.  Studies and measures related to environmental concerns at IPC'shydroelectric facilities account for $12 million, and investments inenvironmental equipment and facilities at the thermal plants account for $6million.  From 2006 through 2007,environmental-related capital expenditures, excluding AFDC, are estimated to be$40 million.  Anticipated expensesrelated to IPC's hydroelectric facilities account for $30 million, and thermalplant expenses are expected to total $10 million.

IPCanticipates $16 million in annual operating costs for environmental facilitiesduring 2005.  Hydroelectric facilityexpenses account for $11 million of this total, and $5 million is related tothermal plant operating expenses.  From2006 through 2007, total environmental related operating costs are estimated tobe $33 million.  Expenses related to thehydroelectric facilities are expected to be $23 million, and thermal plantexpenses are expected to be $10 million 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 meet federal andstate emission rate standards for sulfur dioxide (SO2) and nitrogenoxides (NOx).  The JimBridger plant is in the process of installing newer technology low-NOxburners that will reduce NOx emissions further than currentlyrequired.  Mercury emission is an activecoal-fired plant environmental issue with no regulation currently inforce.  None of IPC's plants havecontinuous mercury emission monitoring or control equipment installed.  IPC is actively observing developments onthis issue, such as proposed legislation and control equipment technologyadvances.

TheEnvironmental Protection Agency issued SO2 allowances, as defined inthe Clean Air Act Amendments, based on coal consumption during establishedbaseline years.  IPC has more than asufficient amount of SO2 allowances to provide compliance for allthree coal-fired facilities, its Danskin natural gas-fired facility and itsBennett Mountain gas-fired facility (due on-line in 2005).  Through 2005, IPC has 108,771 allowances inexcess of the amount needed for Clean Air Act compliance.  IPC has been granted annual allotments ofallowances ranging from 15,524 to 28,622 through 2034.  Allowances necessary for IPC's compliancerequirements are up to 14,500 annually. Excess allowances owned by IPC may be held for future use, as they donot expire.  There is an activemarketplace for buying and selling allowances, so allowances determined to beexcess can be sold to other companies. Accordingly, IPC does not foresee any adverse effects upon itsoperations with regard to SO2 emissions at this time.

In January of 2005, the Chairman of the SenateEnvironment and Public Works Committee reintroduced the Clear Skies Act.  This bill would further restrict SO2 andNOx emissions, and add mercury emission restrictions.  It may also include language addressinggreenhouse gases.  The bill, if passed,would require additional emission controls and expenses at the thermalfacilities, although impacts on future plant operations, operating costs andgenerating capacity are not known at this time.

TheDanskin gas turbine plant in Idaho is operating in compliance with a"permit to construct" issued by the Idaho Department of EnvironmentalQuality.  IPC has applied for a Title VOperating Permit from the Idaho Department of Environmental Quality, which isexpected during 2005.  The plant meetsSO2 regulations and the units are fitted with dry-low-NOxburners and a continuous emissions monitoring system.  This equipment should ensure that the facility operates withinthe permitted federal and state NOx and carbon monoxide limits.

In July1997, the Environmental Protection Agency announced the National Ambient AirQuality Standards for Ozone and Particulate Matter and in July 1999, theEnvironmental Protection Agency announced regional haze regulations forprotection of visibility in national parks and wilderness areas.  On May 14, 1999, a federal court rulingblocked implementation of these standards. In November 2000, the Environmental Protection Agency appealed to theU.S. Supreme Court to reconsider that decision.  The Supreme Court has ruled in favor of the EnvironmentalProtection Agency.  The EnvironmentalProtection Agency has not yet implemented tighter regulations on particulatematter, regional haze or ozone. Although the impacts of these regulations on IPC's thermal operationsare not known at this time, the future costs of compliance with theseregulations could be substantial and will be dependent on if and how theregulations are ultimately implemented.

**GlobalClimate Change:**  The United States is currently not a partyto the Kyoto Protocol to the United Nations Framework Convention on ClimateChange (Protocol) that became effective for signatories on February 16,2005.  The Protocol process generallyrequires developed countries to cap greenhouse gas emissions at certain levelsduring the 2008 through 2012 time period. Although it has not ratified the Protocol, the United States may adopt anational, mandatory greenhouse gas program at some point in the future.  At this time, IPC is unable to predict thepotential impacts of any future mandatory governmental greenhouse gaslegislative or regulatory requirements.

Greenhousegas emissions result from the combustion of fossil fuels to generateelectricity, with carbon dioxide representing the largest quantity ofgreenhouse gases emitted, from IPC's coal and gas generation units.  Under normal water conditions, the majorityof IPC's generation is comprised of hydroelectric assets that have negligiblegreenhouse gas emissions compared to fossil-based generation.

**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 monitoringfacilities.  The amendments provide moreaccurate and reliable water quality measurements necessary to maintain waterquality standards downstream from IPC's plant during the period from May 15 toOctober 15 each year.

IPC hasinstalled aeration equipment, water quality monitors and data processingequipment as part of its 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 its Milner, Shoshone Falls, Twin Falls, Upper Salmon, LowerSalmon, Bliss and CJ Strike hydroelectric projects in order to meet compliancestandards for 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, 2004,the investment in these facilities was $11 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 - REGULATORY ISSUES -Relicensing of Hydroelectric Projects."

 

**Hazardous/ToxicWastes and Substances:**  Under the Toxic Substances Control Act, theEnvironmental Protection Agency has adopted regulations governing the use,storage, inspection and disposal of electrical equipment that containspolychlorinated biphenyls (PCBs).  The regulationspermit the continued use and servicing of certain equipment (includingtransformers and capacitors) that contain PCBs.  IPC continues to meet all federal requirements of the ToxicSubstances Control Act for the continued use of equipment containing PCBs.  IPC continues to eliminate PCBs as part ofits long-term strategy.  This programwill reduce costs associated with the long-term monitoring of PCB-containingequipment, responding to spills and reporting to the Environmental ProtectionAgency.  In 2004, IPC spentapproximately $1 million identifying and eliminating PCBs.

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

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 anddeliver electricity at market-based prices.

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

**Utility Operating Statistics**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,** |
|----------------------------------|------------------------------|
|                             | **2004**                     |   | **2003** |   | **2002** |
| Revenues  (thousands of dollars) |                         |   |   |   |   |   |   |   |
|                             | Residential                  | $ | 274,313 |   | $ | 275,920 |   | $ | 305,827 |
|                             | Commercial                   |   | 164,053 |   |   | 173,820 |   |   | 196,454 |
|                             | Industrial                   |   | 111,797 |   |   | 128,620 |   |   | 176,648 |
|                             | Irrigation                   |   | 85,672 |   |   | 92,609 |   |   | 93,106 |
|                             |                         | Total  general business |   | 635,835 |   |   | 670,969 |   |   | 772,035 |
|                             | Off-system  sales            |   | 121,148 |   |   | 71,573 |   |   | 55,031 |
|                             | Other                        |   | 62,526 |   |   | 37,840 |   |   | 39,981 |
|                             |                         | Total | $ | 819,509 |   | $ | 780,382 |   | $ | 867,047 |
|                             |                         |   |   |   |   |   |   |   |   |
| Energy  use (thousands of MWh)   |                         |   |   |   |   |   |   |   |
|                             | Residential                  |   | 4,580 |   |   | 4,427 |   |   | 4,387 |
|                             | Commercial                   |   | 3,561 |   |   | 3,511 |   |   | 3,460 |
|                             | Industrial                   |   | 3,335 |   |   | 3,206 |   |   | 3,226 |
|                             | Irrigation                   |   | 1,763 |   |   | 1,836 |   |   | 1,821 |
|                             |                         | Total  general business |   | 13,239 |   |   | 12,980 |   |   | 12,894 |
|                             | Off-system  sales            |   | 2,885 |   |   | 1,830 |   |   | 2,069 |
|                             |                         | Total |   | 16,124 |   |   | 14,810 |   |   | 14,963 |
|                             |                         |   |   |   |   |   |   |   |   |

 

**IFS:**

IFSinvests primarily in affordable housing developments, which provide a returnprincipally by reducing federal and state income taxes through tax credits andaccelerated tax depreciation benefits.  IFS generated tax credits of $22 million, $20million and $21 million in 2004, 2003 and 2002, respectively.  IFS'sportfolio also includes historic rehabilitation projects such as the EmpireBuilding in Boise, Idaho.  IFS made $8million in new investments during 2004.

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, 2004, thegross amount of IFS's portfolio exceeded $165 million in tax creditinvestments.  These investments cover 49states, Puerto Rico and the U.S. Virgin Islands.  The underlying investments include over 700 individualproperties, of which all but three are administered through syndicated funds.

**IDA-WEST:**

Ida-Westoperates and has a 50 percent interest in nine hydroelectric plants with atotal generating capacity of 45 MW.  In2003, Ida-West discontinued its project development activities.  See further discussion in Part II, Item 7 -"MD&A - RESULTS OF OPERATIONS - Ida-West."  IPC purchased all of the power generated byIda-West's four Idaho hydroelectric projects, at a cost of $7 million per year,in 2004, 2003 and 2002.

**IDATECH:**

IdaTech was originally founded in1996 as Northwest Power Systems, LLC to develop and bring fuel cell technologyto market.  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 development include:

Complete systems such as its fivekilowatt electrical emergency back up power fuel cell unit ElectraGenTM  that is targeted to replace valve regulatedlead acid batteries in applications such as cellular telecommunications towersand portable power systems.

On-board reforming capability,which provides auxiliary power to high-end consumer applications such as marineand recreational vehicles and premium power for special military operations.

Components such as multi-fuel fuelprocessors, fuel cell stack technology and automated fuel cell systems, whichtarget longer-term commercial applications in vehicular auxiliary power unitsand Combined Heat and Power units.  Forthese longer-term market opportunities, IdaTech has joined with Volkswagen, RWEFuel Cells and Bosch Buderus in product development.  IdaTech's fuel processors are capable of operating on alcoholsand liquid and gaseous hydrocarbon fuels including natural gas, liquefiedpetroleum gas, diesel and kerosene.

 

IdaTech has integrated itsmulti-fuel fuel processors with a number of PEM fuel cell stacks into one toten kilowatt fuel cell systems for stationary and portable electric powergeneration.

Currently, these systems are beingfield-tested and evaluated with European utilities, the Propane Education andResearch Council, the U.S. Army Communications Electronics Command and a numberof other customers in North America, Europe and Asia.

In July 2004, IdaTech and BuderusHeiztechnik GmbH of the Bosch group, a heating equipment manufacturer locatedin Germany, joined RWE Fuel Cells in its program with IdaTech for thedevelopment of a five kilowatt combined heat and power fuel cell system formulti-dwelling and light commercial use. Under this partnership, IdaTech will develop and manufacture the fuelcell systems.  RWE Fuel Cells and BoschBuderus will integrate the fuel cells with heating systems to create a completeheat and power solution.  RWE Fuel Cellsand Bosch Buderus will test the fuel cell systems in the laboratory and in thefield.  Several IdaTech fuel cellsystems are in service and being tested by RWE Fuel Cells.  The first field trials with fully integratedfuel cell and heating systems are planned for installation in 2005.

In September 2004, IdaTech wasselected by automobile manufacturer Volkswagen to design and manufacture anintegrated fuel processor system operating on diesel fuel to be used in anautomotive application.  The agreementis part of a vehicle demonstration project at Volkswagen.

On November 19, 2004, IdaTech wasawarded a $1.4 million development program from the U.S. Department of Energyto conduct a three-year program of fuel cell system research targeting off-roadvehicle applications.  Under this award,IdaTech will identify and recommend fuel cell designs to overcome environmentalconditions faced by off-road vehicles such as turf and grounds maintenancevehicles and construction and farm equipment.

**IDACOMM:**In August 2000, IDACORPformed IDACOMM, Inc. and acquired Velocitus, Inc., a Boise, Idaho-basedInternet service provider founded in 1992. IDACOMM provides a wide range of integrated communication services tobusiness and residential customers in 22 markets across eight western states,Virginia and New York.  In 2004, IDACORPtransferred its ownership of Velocitus to IDACOMM.  Velocitus was merged into IDACOMM in January 2005.

IDACOMM's fiber optic networks provide high-speedconnectivity in its local market, Boise, Idaho, as well as recently addedmarket networks in Las Vegas, Nevada and Reno, Nevada, acquired in June 2004from Sierra Pacific Communications, Inc. IDACOMM's Internet services unit enables high-speed voice, Internet anddata communications, including video conferencing, voice-over Internetprotocol, off-site training, gigabit Ethernet service, virtual privatenetworks, firewalls and web hosting. The Internet unit serves residential, consumer and small to medium sizebusiness clients with high-speed connectivity and security solutions, includingfixed wireless technology, with 20,000 customers at December 31, 2004.

During 2004, IDACOMM formed a new unit for thetesting and commercial deployment of broadband-over-powerline technology,staging a multi-location equipment trial in Boise, Idaho during the year.  Broadband-over-powerline provides 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 include companies inindustries such as manufacturing, health care, food processing and retail aswell as government entities, schools and universities and nationaltelecommunication carriers.

**RESEARCH AND DEVELOPMENT:**

**IdaTech:**In 2004,IdaTech spent approximately $5 million for research and development of fuelcell technology.  IdaTech's research anddevelopment program is focused on the adaptation of its fuel processortechnology to operate on all commercially important fuels, as well as thedevelopment of fully integrated fuel cell systems.  Highest priority is given to natural gas, liquefied petroleumgas, 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; the design andmaterials of construction used in IdaTech's two stage hydrogen purificationdevices based on the HyPuriumTM membranes used to filter out impurities in theproduct hydrogen; fuel cell system automated control and operation; integratedheat recovery from fuel cell systems; and automated control of integratedpressure-swing absorption for efficient and reliable operation.  During 2004, IdaTech received its firstthree Japanese patents (related to the composition of the IdaTech HyPuriumTMmembranes as well as the design and materials used to construct membranemodules), and IdaTech received its first European patent related to theHyPuriumTM membrane composition and module design and construction.  Currently, 35 U.S. patents lasting 20 yearshave been issued or allowed to IdaTech. These patents expire from 2016 to 2025. IdaTech also has approximately 150 pending domestic and foreign patentapplications addressing various aspects of (1) fuel processor system design,operation, materials and integration; (2) membrane purification, materials anddesign; and (3) fuel cell system operation, thermal recovery, design, remotecontrol and diagnostics.  These patentswill help IdaTech bring its technology to commercialization.  The patents also provide the potential forlicensing of IdaTech's technology in the future.

**IPC:**In 2004, IPC spent over$4 million to promote energy efficiency and summer peak reduction.  Approximately $1 million of thoseexpenditures went to fund the Northwest Energy Efficiency Alliance, whichstrives to transform the regional marketplace through demonstration ofinnovative technologies, collaboration with firms that market energy-savingproducts and services and training and information services.  IPC's other energy efficiency programstarget efficiencies in the areas of new residential construction, manufacturedhomes, industrial and irrigation efficiency and duct sealing.  Low-income weatherization assistance and Oregonresidential weatherization efforts were also funded in 2004.  In addition to IPC's on going programs,funding was also allocated to the research and development of new energyefficiency and summer peak reduction options in the irrigation and residentialsectors.  Most of the funding for theseprograms and program development comes from the Idaho tariff rider fordemand-side management programs and from the Conservation and RenewableDiscount Program of the Bonneville Power Administration.

**ITEM2.  PROPERTIES**

IPC'ssystem includes 13 hydroelectric projects made up of 17 generating plantslocated in southern Idaho and eastern Oregon, one natural gas-fired plantlocated in southern Idaho and interests in three coal-fired steam electricgenerating plants.  A second gas-firedplant, Bennett Mountain Power Plant, is currently under construction and dueon-line later in 2005.  The system alsoincludes approximately 4,671 miles of high voltage transmission lines, 23step-up transmission substations located at power plants, 19 transmissionsubstations, seven transmission switching stations and 212 energized distributionsubstations (excluding mobile substations and dispatch centers).

IPCholds FERC licenses for all 13 of its hydroelectric projects.  These projects and the other generatingstations 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         | 2034 |   |
|                                                                                                                           | Bliss                                   | 80,000                | 75,000         | 2034 |   |
|                                                                                                                           | Upper Salmon                            | 39,000                | 34,500         | 2034 |   |
|                                                                                                                           | Shoshone Falls                          | 12,500                | 12,500         | 2034 |   |
|                                                                                                                           | CJ Strike                               | 89,000                | 82,800         | 2034 |   |
|                                                                                                                           | Upper Malad                             | 9,000                 | 8,270          | 2004 | (a) |
|                                                                                                                           | Lower Malad                             | 15,000                | 13,500         | 2004 | (a) |
|                                                                                                                           | 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         |   |   |
|                                                                                                                           | Total Hydroelectric                     |                  | 1,706,715      |   |   |
| **Steam and Other Generating  Plants:**                                                                                        |                                    |                  |           |   |
|                                                                                                                           | Jim Bridger (coal-fired) (b)            | 706,667               | 770,501        |   |   |
|                                                                                                                           | Valmy (coal-fired) (b)                  | 260,650               | 283,500        |   |   |
|                                                                                                                           | Boardman (coal-fired) (b)               | 55,200                | 56,050         |   |   |
|                                                                                                                           | Danskin (gas-fired)                     | 100,000               | 90,000         |   |   |
|                                                                                                                           | Salmon (diesel-internal combustion)     | 5,500                 | 5,000          |   |   |
|                                                                                                                           | Bennett Mountain (gas-fired)(c)         | 163,980               | 172,800        |   |   |
|                                                                                                                           |                                    | Total Steam and other |           | 1,377,851 |   |   |
|                                                                                                                           |                                    | Total Generation      |           | 3,084,566 |   |   |
|                                                                                                                           |                                    |                  |           |   |   |
| (a)   Licensed on an annual basis while application for new multi-year  license is pending.                               |
| (b) IPC's ownership interests are 33 percent for  Jim Bridger, 50 percent for Valmy and 10 percent for Boardman.  Amounts |
|                                                                                                                           | shown  represent IPC's share only.      |
| (c)  Due  on-line later in 2005.                                                                                          |
|                                                                                                                                |                                         |                       |                |  |  |  |  |  |  |  |  |

 

See discussion ofrelicensing in Part II, Item 7 - "MD&A - REGULATORY ISSUES -Relicensing of Hydroelectric Projects."

AtDecember 31, 2004, the composite average ages of the principal parts of IPC'ssystem, based on dollar investment, were production plant, 24 years;transmission system and substations, 22 years; and distribution lines andsubstations, 18 years.  IPC considersits properties to be well-maintained and in good operating condition.

IPCowns in fee all of its principal plants and other important units of realproperty, except for portions of certain projects licensed under the FederalPower Act and reservoirs and other easements. IPC's property is also subject to the lien of its Mortgage and Deed ofTrust and the provisions of its project licenses.  In addition, IPC's property is subject to minor defects common toproperties of such size and character that do not materially impair the valueto, or the use by, IPC of such properties.

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

Ida-Westholds investments in nine operating hydroelectric plants with a totalgenerating capacity of 45 MW.  Theseplants are located in Idaho and California.

SeeNote 1 to IDACORP's Consolidated Financial Statements for a discussion of theproperty of IDACORP's consolidated Variable Interest Entities.

**ITEM 3.  LEGAL PROCEEDINGS**

Reference is made to Note 8 of IDACORP'sConsolidated Financial Statements.

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

None

 

 

 

 

**EXECUTIVE OFFICERS OFTHE REGISTRANT**

The names, ages and positions of all of theexecutive officers of IDACORP, Inc. are listed below along with their businessexperience during the past five years. There are no family relationships among these officers, nor is there anyarrangement or understanding between any officer and any other person pursuantto which the officer was elected.

JAN B. PACKWOOD President and Chief ExecutiveOfficer, appointed May 30, 1999.  Mr.Packwood also serves as Chief Executive Officer of Idaho Power Company,appointed March 1, 2002.  Mr. Packwoodwas President and Chief Executive Officer of Idaho Power Company from May 30,1999 to March 1, 2002.  Age 61

J. LAMONT KEEN Executive Vice President, appointedMarch 1, 2002.  Mr. Keen was Senior VicePresident - Administration and Chief Financial Officer from May 5, 1999 toMarch 1, 2002.  Mr. Keen also serves asPresident and Chief Operating Officer of Idaho Power Company, appointed March1, 2002.  Mr. Keen was Senior VicePresident - Administration and Chief Financial Officer of Idaho Power Company fromMay 5, 1999 to March 1, 2002.  Age 52

DARREL T. ANDERSON Senior Vice President -Administrative Services and Chief Financial Officer, appointed July 1,2004.  Mr. Anderson was Vice President,Chief Financial Officer and Treasurer from March 1, 2002 to July 1, 2004 andVice President - Finance and Treasurer from May 5, 1999 to March 1, 2002.  Mr. Anderson serves in the same position atIdaho Power Company.  Age 46

THOMAS R. SALDIN Senior Vice President, GeneralCounsel and Secretary, appointed October 1, 2004.  Mr. Saldin was Executive Vice President and General Counsel ofAlbertson's Inc., a supermarket chain, from January 29, 1999 to his retirementon August 31, 2001.  Mr. Saldin servesin the same position at Idaho Power Company. Age 58

DENNIS C. GRIBBLE Vice President and Treasurer,appointed July 15, 2004.  Mr. Gribblewas Finance Controller of Idaho Power Company from January 1, 1997 to July 15,2004.  Mr. Gribble serves in the sameposition at Idaho Power Company.  Age 52

A. BRYAN KEARNEY Vice President and ChiefInformation Officer, appointed March 15, 2001. Mr. Kearney has been the Vice President and Chief Information Officer ofIdaho Power Company since November 18, 1999. Age 42

LUCI K. MCDONALD Vice President - Human Resources,appointed December 6, 2004.  Ms.McDonald was Corporate Staff Director of Human Resources of Boise CascadeCorporation, a forest products company, from September 16, 1999 to November 19,2004.  Ms. McDonald serves in the sameposition at Idaho Power Company.  Age 47

GREGORY W. PANTER Vice President - Public Affairs,appointed April 1, 2001.  Mr. Panter wasself-employed with Greg Panter Consulting, a lobbying/government affairsbusiness, from July 1, 1999 to April 1, 2001. Mr. Panter serves in the same position at Idaho Power Company.  Age 56

LORI D. SMITH Vice President - Finance and ChiefRisk Officer, appointed July 15, 2004. Ms. Smith was Director of Strategic Analysis of Idaho Power Company fromJanuary 1, 2000 to July 15, 2004.  Ms.Smith serves in the same position at Idaho Power Company.  Age 44

 

 

**PART II******

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

IDACORP, Inc.'s(IDACORP) common stock (without par value) is traded on the New York StockExchange and the Pacific Exchange.  OnDecember 31, 2004, there were 18,037 holders of record and the stock price was$30.57 per share.

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

The amount and timingof dividends payable on IDACORP's common stock are within the sole discretionof IDACORP's Board of Directors.  TheBoard of 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.  Seefurther discussion of the dividend reduction in Part II, Item 7 -"MD&A - LIQUIDITY AND CAPITAL RESOURCES - DividendReduction."  The ability of IDACORPto pay dividends on its common stock is dependent upon dividends paid to it byits 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 $46 million, $65 million and $70 million in 2004, 2003 and2002, respectively.  On September 20,2004, IPC redeemed all of its outstanding preferred stock for $54 million usingproceeds from the issuance of first mortgage bonds.

The following table shows the reportedhigh and low sales price of IDACORP's common stock and dividends paid for 2004and 2003 as reported in the consolidated transaction reporting system.
|                             | **2004 Quarters**               |
|----------------------------------|---------------------------------|
| Common Stock, without par value: | **1st**                         |   | **2nd** |   | **3rd** |   | **4th** |
|                             | High                            | $32.05  |   | $30.66  |   | $29.95  |   | $32.95  |
|                             | Low                             | 29.32  |   | 25.30  |   | 26.05  |   | 29.05  |
|                             | Dividends paid per share -cents | 30.0  |   | 30.0  |   | 30.0  |   | 30.0  |
|                             |                            |   |   |   |   |   |   |   |
|                             | **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  |
|                             |                            |

 

**ITEM 6.  SELECTED FINANCIAL DATA**
| **IDACORP, Inc.**                                                                                                               |
|---------------------------------------------------------------------------------------------------------------------------------|
| **SUMMARY OF OPERATIONS**                                                                                                       |
| **(thousands of dollars except per share amounts)**                                                                             |
|                                                                                                                            | **2004** | **2003** | **2002** | **2001** | **2000** |
| Operating Revenues                                                                                                              | $ | 844,491 | $ | 823,002 | $ | 928,800 | $ | 1,275,312 | $ | 1,049,785 |
| Operating income                                                                                                                |   | 93,251 |   | 84,062 |   | 75,640 |   | 242,289 |   | 247,310 |
| Net income                                                                                                                      |   | 72,983 |   | 46,578 |   | 61,672 |   | 125,214 |   | 139,883 |
| Earnings per share                                                                                                              |   | 1.90 |   | 1.22 |   | 1.63 |   | 3.35 |   | 3.72 |
| Dividends declared per share                                                                                                    |   | 1.20 |   | 1.70 |   | 1.86 |   | 1.86 |   | 1.86 |
|                                                                                                                            |   |   |   |   |   |   |   |   |   |   |   |
| **Financial Condition:**                                                                                                        |   |   |   |   |   |   |   |   |   |   |
| Total assets                                                                                                                    | $ | 3,234,172 | $ | 3,106,108 | $ | 3,387,168 | $ | 3,769,992 | $ | 4,159,177 |
| Long-term debt                                                                                                                  |   | 1,058,152 |   | 1,013,757 |   | 988,268 |   | 879,048 |   | 903,888 |
|                                                                                                                            |   |   |   |   |   |   |   |   |   |   |
| **Financial Statistics:**                                                                                                       |   |   |   |   |   |   |   |   |   |   |
| Times interest charges  earned:                                                                                                 |   |   |   |   |   |   |   |   |   |   |
|                                                                                                                            | Before tax |   | 1.83    |   | 1.37    |   | 1.16    |   | 3.52    |   | 4.33    |
|                                                                                                                            | After tax |   | 2.25    |   | 1.68    |   | 1.93    |   | 2.66    |   | 3.21    |
| Market-to-book ratio                                                                                                            |   | 128% |   | 132% |   | 108% |   | 175% |   | 225% |
| Payout ratio                                                                                                                    |   | 63% |   | 139% |   | 114% |   | 56% |   | 50% |
| Return on year-end common  equity                                                                                               |   | 7.2% |   | 5.4% |   | 7.1% |   | 14.4% |   | 17.0% |
| Book value per share                                                                                                            | $ | 23.88    | $ | 22.61   | $ | 22.98   | $ | 23.21   | $ | 21.85   |
|                                                                                                                            |   |   |   |   |   |   |   |   |   |   |
| See  Part II, Item 7 - "MD&A - RESULTS OF OPERATIONS" for a  discussion of the factors that affect comparability. |
|                                                                                                                            |
| The  above data should be read in conjunction with IDACORP's Consolidated  Financial Statements including the                   |
| Notes  to the Consolidated Financial Statements.                                                                                |

 

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

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

**INTRODUCTION:**

In Management's Discussion andAnalysis of Financial Condition and Results of Operations (MD&A), thegeneral financial condition and results of operations for IDACORP, Inc. and itssubsidiaries (collectively, IDACORP) and Idaho Power Company and its subsidiary(collectively, IPC) are discussed. IDACORP is a holding company formed in 1998 whose principal operatingsubsidiary is IPC.  IDACORP is exemptfrom registration as a public utility holding company pursuant to Section 3(a)(1)of the Public Utility Holding Company Act of 1935 (1935 Act).  In addition, pursuant to Rule 2 of theGeneral Rules and Regulations under the 1935 Act, IDACORP is exempt from allthe provisions of the 1935 Act and rules thereunder, except for Section 9(a)(2)of the 1935 Act, which requires IDACORP to seek prior Securities and ExchangeCommission approval to acquire securities of another public utility company.

IPC is an electric utility witha service territory covering approximately 24,000 square miles, primarily insouthern Idaho and eastern Oregon.  Themeasurement of IPC's service area increased by approximately 4,000 square milesover 2003 due to the conversion from a manual mapping system to global informationsystem technology.  IPC is the parent ofIdaho Energy Resources Co., a joint venturer in Bridger Coal Company, whichsupplies coal to the Jim Bridger generating plant owned in part by IPC.

IDACORP's other operatingsubsidiaries include:

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

IdaTech - developer of integrated fuel cellsystems;

IDACOMM - provider oftelecommunications services and commercial and residential Internet services;and

Ida-West Energy (Ida-West) -operator of independent power projects.

 

IDACORP Energy (IE), a marketerof electricity and natural gas, wound down its operations during 2003.  Also in 2003, Ida-West discontinued itsproject development operations and is managing its independent power projectswith a reduced workforce.  See furtherdiscussions in "RESULTS OF OPERATIONS - Energy Marketing" and"RESULTS OF OPERATIONS - Ida-West" later in the MD&A.

In2004, IDACORP transferred its ownership of RMC Holdings, Inc. and itssubsidiary Velocitus to IDACOMM.  In January2005, RMC Holdings, Inc. and Velocitus were merged into IDACOMM.

Whilereading the MD&A, please refer to the Consolidated Financial Statements ofIDACORP and IPC, which present the financial position at December 31, 2004 and2003, and the results of operations and cash flows for each company for theyears ended December 31, 2004, 2003 and 2002.

**FORWARD-LOOKINGINFORMATION:**

In connection with thesafe harbor 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, any currentReport on Form 8-K, in presentations, in response to questions orotherwise.  Any statements that express,or involve discussions as to expectations, beliefs, plans, objectives,assumptions or future events or performance (often, but not always, through theuse of words or phrases such as "anticipates," "believes,""estimates," "expects," "intends,""plans," "predicts," "projects," "willlikely result," "will continue" or similar expressions) are notstatements of historical facts and may be forward-looking.  Forward-looking statements involveestimates, assumptions and uncertainties and are qualified in their entirety byreference to, and are accompanied by, the following factors, which aredifficult to predict, contain uncertainties, are beyond our control and maycause actual results to differ materially from those contained inforward-looking statements:

Changesin governmental policies and regulatory actions, including those of the FederalEnergy Regulatory Commission (FERC), the Idaho Public Utilities Commission(IPUC) and the Oregon Public Utility Commission (OPUC), with respect to allowedrates of return, industry and rate structure, acquisition and disposal of assetsand facilities, operation and construction of plant facilities, relicensing ofhydroelectric projects, recovery of purchased power expenses, recovery of othercapital investments, present or prospective wholesale and retail competition(including but not limited to retail wheeling and transmission costs) and otherrefund proceedings;

Litigation and regulatoryproceedings, including those resulting from the energy situation in the westernUnited States, and settlements that influence business and profitability;

Changes in and compliance withenvironmental, endangered species and safety laws and policies;

Weather variations affectinghydroelectric generating conditions and customer energy usage;

Over-appropriation of surfaceand groundwater in the Snake River Basin resulting in reduced generation athydroelectric facilities;

Construction of powergenerating facilities including inability to obtain required governmentalpermits and approvals, and risks related to contracting, construction andstart-up;

Operation of power generatingfacilities including breakdown or failure of equipment, performance belowexpected levels, competition, fuel supply, including availability,transportation and prices, and transmission;

Impacts from the potentialformation of a regional transmission organization (RTO);

Population growth rates anddemographic patterns;

Market demand and prices forenergy, including structural market changes;

Changes in operating expensesand capital expenditures and fluctuations in sources and uses of cash;

Results of financing efforts,including the ability to obtain financing on favorable terms, which can beaffected by factors such as credit ratings and general economic conditions;

Homeland security, naturaldisasters, acts of war or terrorism;

Technological developmentsthat could affect the operations and prospects of IDACORP's subsidiaries ortheir competitors;

Increasing health care costsand the resulting effect on health insurance premiums paid for employees;

Performance of the stockmarket and the changing interest rate environment, which affect the amount ofrequired contributions to pension plans, as well as the reported costs ofproviding pension and other postretirement benefits;

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

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

Adoption of or changes incritical accounting policies or estimates; and

New accounting or Securitiesand Exchange Commission requirements, or new interpretation or application ofexisting requirements.

 

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

**RISK FACTORS:**

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

**Reducedhydroelectric generation can reduce revenues and increase costs.**  Idaho Power Company has a predominatelyhydroelectric generating base.  Becauseof Idaho Power Company's heavy reliance on hydroelectric generation, theweather can significantly affect its operations.  Idaho Power Company is experiencing its sixth consecutive year ofbelow normal water conditions in 2005. When hydroelectric generation is reduced, Idaho Power Company mustincrease its use of more expensive thermal generating resources and purchased power.  Through its power cost adjustment in Idaho,Idaho Power Company can expect to recover approximately 90 percent of theincrease in its Idaho jurisdictional net power supply costs, which are fuel andpurchased power less off-system sales, above the level included in its baserates.  The power cost adjustmentrecovery includes both a forecast and deferrals that are subject to theregulatory process.  The non-Idaho netpower supply costs are subject to periodic recovery from its Oregon and FederalEnergy Regulatory Commission jurisdictional customers.

**Continuingdeclines in stream flows and over-appropriation of water in Idaho will reducehydroelectric generation and revenues and increase costs. **The combination of decliningSnake River base flows, over-appropriation of water and continuing droughtconditions have led to disputes among certain surface water and ground waterirrigators, and the State of Idaho. Recharging the Eastern Snake River Aquifer, which contributes to SnakeRiver flows, by diverting surface water to porous locations and permitting itto sink into the Aquifer is one proposed solution to the dispute.  Idaho Power Company believes aquiferrecharge would further reduce Snake River base flows available forhydroelectric generation, reduce Idaho Power Company revenues and increasecosts.

**Changesin temperature can reduce power sales and revenues.**  Warmer than normal winters or cooler thannormal summers will reduce retail revenues from power sales.

**TheIdaho Public Utilities Commission's grant of less rate relief than requestedwill reduce Idaho Power Company's projected earnings and cash flows. **Because Idaho Power Company didnot receive the full amount of rate relief requested, its projected earningsand cash flows have been reduced and IDACORP, Inc.'s and Idaho Power Company'scredit ratings have been downgraded.  Ifthe Idaho Public Utilities Commission were to grant less rate relief than IdahoPower Company requests in the future, it could have a negative effect onearnings and cash flow and result in future downgrades of IDACORP, Inc.'s andIdaho Power Company's credit ratings.

**Adowngrade in IDACORP, Inc.'s and Idaho Power Company's credit ratings couldnegatively affect the companies' ability to access capital.**  On November 29, 2004, Standard & Poor'sRatings Services, on December 3, 2004, Moody's Investors Service, and onJanuary 24, 2005, Fitch, Inc. each downgraded IDACORP, Inc.'s and Idaho PowerCompany's credit ratings.  These downgradesand any future downgrades of IDACORP, Inc.'s or Idaho Power Company's creditratings could limit the companies' ability to access the capital markets,including the commercial paper markets. In addition, IDACORP, Inc. and Idaho Power Company would likely berequired to pay a higher interest rate on existing variable rate debt and infuture financings.

**Conditionsthat may be imposed in connection with hydroelectric license renewals mayrequire large capital expenditures and reduce earnings and cash flows.**  Idaho Power Company is currently involved inrenewing federal licenses for several of its hydroelectric projects.  Conditions with respect to environmental,operating and other matters that the Federal Energy Regulatory Commission mayimpose in connection with the renewal of Idaho Power Company's licenses couldhave a negative effect on Idaho Power Company's operations, require largecapital expenditures and reduce earnings and cash flows.

**Thecost of complying with environmental regulations can harm cash flows andearnings.**  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 and regulationsinvolves significant capital, operating and other costs, and those costs couldbe even more significant in the future as a result of changes in legislationand enforcement policies.  For instance,considerable attention has been focused on carbon dioxide emissions fromcoal-fired generating plants and their potential role in contributing to globalwarming and mercury emissions from coal-fired plants.  The adoption of new laws and regulations to implement carbondioxide, mercury or other emission controls could adversely affect operationsand increase the cost of operating coal-fired generating plants.

**Terroristthreats and activities could result in reduced revenues and increasedcosts.  IDACORP, Inc. and Idaho PowerCompany are subject to direct and indirect effects of terrorist threats andactivities. **Potentialtargets include generation and transmission facilities.  The effects of terrorist threats andactivities could prevent Idaho Power Company from purchasing, generating ortransmitting power and result in reduced revenues and increased costs.

**IDACORP,Inc., IDACORP Energy and Idaho Power Company are subject to costs and othereffects of legal and regulatory proceedings, settlements, investigations andclaims, including those that have arisen out of the western energy situation.**  IDACORP, Inc., IDACORP Energy and IdahoPower Company are involved in a number of proceedings including a complaintfiled against sellers of power in California, based on California's unfaircompetition law, a cross-action wholesale electric antitrust case againstvarious sellers and generators of power in California and the California refundproceeding at the Federal Energy Regulatory Commission.  Other cases that are the direct or indirectresult of the western energy situation include a refund proceeding affectingsellers of wholesale power in the spot market in the Pacific Northwest, inwhich the Federal Energy Regulatory Commission directed that no refunds bepaid, but which is now pending on appeal before the United States Court ofAppeals for the Ninth Circuit; efforts by certain parties to reform orterminate contracts for the purchase of power from IDACORP Energy or claimingviolations of state and federal antitrust acts and dysfunctional energy marketsas the result of market manipulation; show cause proceedings at the FederalEnergy Regulatory Commission, which have been settled but are the subject ofmotions for rehearing or have been appealed and the reversal by the UnitedStates Court of Appeals for the Ninth Circuit of Federal Energy RegulatoryCommission rulings that market-based sellers' transactional reports satisfy theFederal Energy Regulatory Commission's filed-rate doctrine requirements as ameans of expanding refunds from all sellers of wholesale power, which rulingsremain pending before the United States Court of Appeals for the Ninth Circuiton rehearing.  To the extent thecompanies are required to make payments, earnings will be negatively affected.  It is possible that additional proceedingsrelated to the western energy situation may be filed in the future againstIDACORP, Inc., IDACORP Energy or Idaho Power Company.

**Pendingshareholder litigation could be costly, time consuming and, if adverselydecided, result in substantial liabilities.**  Two securities shareholder lawsuitsconsolidated by order dated August 31, 2004 have been filed against IDACORP,Inc. and certain of its officers and directors.  Securities litigation can be costly, time-consuming anddisruptive to normal business operations. Certain costs below a self-insured retention are not covered byinsurance policies.  While IDACORP, Inc.cannot predict the outcome of these matters and these matters will take time toresolve, damages arising from these lawsuits if resolved against IDACORP, Inc.or in connection with any settlement, absent insurance coverage or damages inexcess of insurance coverage, could have a material adverse effect on thefinancial position, results of operations or cash flows of IDACORP, Inc.

**Litigationrelating to stray voltage, if adversely decided, could result in liabilities,reducing earnings, and encourage the commencement of additional lawsuits. **In three instances, dairyfarmers have brought actions against Idaho Power Company claiming loss of milkproduction and other damages to livestock due to stray voltage from Idaho PowerCompany's electrical system.  In thefirst proceeding, the jury ruled in Idaho Power Company's favor.  In the second proceeding, a jury verdict wasentered in favor of the plaintiffs.  Athird is in the discovery stage. Adverse court rulings in such proceedings could increase the number offuture claims.  The costs of defendingthese lawsuits could be significant, and certain costs, such as those below adeductible amount, are not covered by insurance policies.

**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.  Because Idaho Power Company did not receive the full amount ofrate relief requested, Idaho Power Company will have to rely more on externalfinancing for its planned utility construction expenditures in the 2005 through2007 period; these large planned expenditures may weaken the consolidatedfinancial profile of Idaho Power Company and IDACORP, Inc.  Additionally, a significant portion of IdahoPower Company's facilities were constructed many years ago.  Aging equipment, even if maintained inaccordance with good engineering practices, may require significant capitalexpenditures.  Failure of equipment orfacilities used in Idaho Power Company's systems could potentially increaserepair and maintenance expenses, purchased power expenses and capital expenditures.

**IfIDACORP, Inc. and Idaho Power Company are unable to complete future assessmentsas to the adequacy of their internal control over financial reporting asrequired by Section 404 of the****Sarbanes-OxleyAct of 2002, or if the companies complete the future assessments and identifyand report material weaknesses, investors could lose confidence in thereliability of the companies' financial statements, which could decrease thevalue of IDACORP, Inc.'s common stock. **As directed by Section404 of the Sarbanes-Oxley Act of 2002, the Securities and Exchange Commissionhas adopted rules requiring public companies to include a report of managementon the company's internal control over financial reporting in their annualreports on Form 10-K.  This report isrequired to contain management's assessment of the effectiveness of thecompany's internal control over financial reporting as of the end of the mostrecent fiscal year.  In addition, theindependent registered public accounting firm auditing a public company'sfinancial statements must also attest to and report on management's assessmentof the effectiveness of the company's internal control over financialreporting.  Effective internal controlsare necessary for the companies to provide reliable financial reports and toprevent and detect fraud.  If thecompanies should fail to have an effectively designed and operating system ofinternal control over financial reporting, this could result in decreasedconfidence in the reliability of the companies' financial statements, whichcould cause the market price of IDACORP, Inc.'s common stock to decline.

**BUSINESS STRATEGY, OVERVIEW OF2004 AND OUTLOOK FOR 2005:**

This section presents anoverview of what management believes are the most critical issues that IDACORPand IPC are facing and the significant items that affected IDACORP's and IPC's2004 operating results.  These itemswill be discussed in more detail within various sections of the MD&A.

**Business Strategy**IDACORP continues to focus on a strategy called "ElectricityPlus," a back-to-basics strategy that emphasizes IPC as IDACORP's corebusiness.  IPC continues to experiencestrong customer growth in its service area, and this corporate strategy recognizesthat IPC must make substantial investments in infrastructure to ensure adequatesupply and reliable service.  The"Plus" recognizes that through modest investments in IdaTech andIDACOMM, IDACORP can preserve the potential for additional growth in shareownervalue.  IFS, with its affordable housingand historic rehabilitation portfolio, remains a key component of the revisedcorporate strategy.

The Electricity Plus strategyincludes seeking timely rate relief in both the Idaho and Oregonjurisdictions.  IPC plans to file inIdaho and Oregon for either asset-specific or general rate relief regularly inupcoming years.  The first of thesefilings was on March 2, 2005 for the Bennett Mountain Power Plant.  IPC also plans to file an Idaho general ratecase in the fall of 2005.

**Water Conditions and Weather**As IPC's service territory enters the sixth consecutive year of belownormal water conditions, IPC expects to rely more on higher-cost thermalgeneration and wholesale power purchases. Historically, hydroelectric generation has provided approximately 55 percentof IPC's total system generation.  In2004, IPC produced 45 percent of its power at its hydroelectricfacilities.  IPC has already incurredhigher purchased power expenses in January 2005, compared to 2004, and expectspower supply costs to remain high as long as below normal water conditionspersist.  Generation at IPC'shydroelectric facilities is currently expected to be 5.5 million MWh in 2005compared to normal generation of 9.2 million MWh.  Also, temperatures through February 2005, as measured by heatingdegree days in Boise, Idaho, were approximately seven percent warmer thannormal and eleven percent warmer than 2004. If winter temperatures remain at or above last year's levels, IDACORP'sand IPC's earnings could be negatively impacted by reduced electric usage.

The continuing below normalwater conditions have exacerbated a developing water shortage in Idaho.  The state has been observing declining SnakeRiver base flows since the early 1960s. This water shortage has led to conflicts between ground water andsurface water irrigators.  At timesduring the year, flows into the Snake River are dependent upon spring flows fedby the Eastern Snake Plain Aquifer.  Oneproposed solution is aquifer recharge - diverting surface water to porous surfacelocations and permitting it to sink into the aquifer.  IPC believes aquifer recharge is inconsistent with state law andwould adversely impact generation at its hydroelectric plants.  Efforts have been underway since 2001 tofind a solution to this conflict.  AMarch 2004 interim agreement stayed all administrative and legal proceedings togive the parties one year to develop a solution.  In January 2005, surface irrigators not a party to the interimagreement submitted a delivery call letter and filed a petition with the IdahoDepartment of Water Resources requesting delivery of their senior natural flowand storage rights and for the designation of the Eastern Snake Plain Aquiferas a ground water management area.  IPChas sought intervention in these matters, which has been opposed by the IdahoGround Water Appropriators, Inc.

**Capital Requirements and CashFlows**IDACORP expects internal cash generation after dividends will provideless than the full amount of total capital requirements for 2005 through2007.  The contribution for internalcash generation is dependent primarily upon IPC's cash flows from operations,which are subject to risks and uncertainties relating to weather and waterconditions and IPC's ability to obtain rate relief to cover its operatingcosts.  Current forecasts indicate totalutility construction expenditures to be $672 million, excluding Allowance forFunds Used During Construction (AFDC), over the next three years.  This amountreflects the need for additional resources in order for IPC to supply power toa growing number of customers while considering the maintenance of corporatecredit ratings.  IDACORP and IPCexpect to continue financing the utility construction program and other capitalrequirements with internally generated funds and with increased reliance onexternally financed capital.  InDecember 2004, IDACORP issued approximately 4 million shares of common stockand received net proceeds of $116 million. IDACORP used $30 million of these proceeds to reduce short-termborrowings and contributed $86 million to IPC. IPC used a portion of the proceeds to pay down short-term borrowings.

**2004 Financial Results**IDACORP's basic and diluted earnings per share (EPS) for the year of$1.90 was a $0.68 per share increase over 2003's results of $1.22 pershare.  The increase is primarily due toimproved results at IPC, a gain on the sale of an investment at IFS and thenegative impacts of exiting energy trading at IE and asset impairments atIda-West in 2003.

IPC's earnings of $1.71 pershare for 2004 are a $0.27 per share increase over last year.  This increase was driven by the settlementof the irrigation lost revenue case allowing IPC to recover approximately $12million that was written-off in 2002 plus $2 million in related interest.  The $12 million is included in otheroperating revenue and the interest is included in other income.  IPC's other operating revenue also increased$7 million primarily as a result of Settlement No. 1 with the IPUC discussedlater, regarding the calculation of IPC's income taxes.  Additionally, the portion ofnet power supply costs absorbed by IPC and not recovered under the Idaho PowerCost Adjustment (PCA) and Oregon Excess Power Cost mechanisms decreased by $10million.  IPC's income taxexpense decreased $15 million largely due to the reversal of a $16 millionregulatory liability that was established in 2002 and reversed as part ofSettlement No. 2 with the IPUC discussed later.  These increases to net income were partially offset by a $35 millionrise in other operations and maintenance expense mainly due to higher payrollexpenses associated with an employee incentive program and a write-off ofapproximately $9 million of disallowed costs related to the Idaho general ratecase.

IFS contributed$0.35 per share, principally from the generation of federal income tax creditsand tax depreciation benefits.  Theseresults also include a $2 million gain on the sale of IFS's investment in theEl Cortez Hotel in San Diego, California.

Ida-West's earnings of $0.08per share are a $0.21 per share increase over last year's loss of $0.13 pershare.  During 2004, Ida-West recorded again on extinguishment of debt by purchasing $18 million of debt issued byMarysville Hydro Partners, a 50 percent owned, consolidated joint venture.  Ida-West's gain, net of minority interest,was approximately $3.5 million.  In2003, Ida-West wrote down its remaining investment in the Garnet project andtwo joint ventures and recorded a reserve on a note receivable.

IE earned $0.06 pershare for 2004 primarily from gains on settlements of legal disputes, which areincluded as offsets to energy marketing operating expenses.  In 2003, IE posted a net loss of $0.25 pershare due to losses on legal settlements and continued wind down costs,partially offset by a gain on the sale of its forward book of electricitytrading contracts.

**Regulatory MattersIrrigation Lost Revenues:**  OnDecember 29, 2004, the IPUC issued Order No. 29669 allowing IPC to recover $12million in revenues and $2 million of interest resulting from IPC's IrrigationLoad Reduction Program.  The recoverywill be included as part of IPC's annual PCA beginning June 1, 2005.

**General Rate Case:**  IPC filed its Idaho general rate case withthe IPUC on October 16, 2003.  The IPUCapproved an increase of $25 million in IPC's electric rates, an average of 5.2percent, in an order issued on May 25, 2004. The rate increase became effective on June 1, 2004.  The IPUC also approved a return on equity of10.25 percent.

The IPUC disallowed severalcosts in the order, including $12 million annually related to the determinationof IPC's income tax expense, $8 million of incentive payments capitalized inprior years and $1 million of capitalized pension expense.  On June 15, 2004, IPC filed with the IPUC apetition for reconsideration of these and other items.  On July 13, 2004, the IPUC granted thispetition in part, agreeing to reconsider the issue relating to thedetermination of IPC's income tax expense and, in light of the IPUC Staff'scomputational errors, ordering rates increased by approximately $3 million onor before August 1, 2004.  IPC recordedan impairment of assets in the second quarter of 2004 related to the disallowedincentive payments and the disallowed capitalized pension expenses.

The final result of IPC's Idahogeneral rate case was a $40 million increase to the base Idaho jurisdictionalrevenue requirement, comprised of $25 million in the initial order, $3 millionrelated to computational errors and $12 million in the order approvingSettlement No. 1 discussed below.

IPC filed an Oregon generalrate case with the OPUC on September 21, 2004 requesting an increase of $4million annually.

**Settlement Agreements:**  On September 28, 2004, the IPUC issuedseparate orders approving two Settlement Agreements entered into on August 16,2004 between IPC and the IPUC Staff. Settlement No. 1 relates to the calculation of IPC's taxes for purposesof test year income tax expense.  As aresult of Settlement No. 1, IPC will compute and record over the 12-monthperiod June 1, 2004 through May 31, 2005 a regulatory asset of approximately$12 million.  Approximately $7 millionof this amount was recognized as other operating revenue as of December 31,2004.

Settlement No. 2 resolvedoutstanding issues related to an unplanned outage at one of the two units ofthe North Valmy Steam Electric Generating Plant (Valmy) in the summer of 2003,a matter relating to the expense adjustment rate for growth component of thePCA and regulatory accounting issues related to a tax accounting method changein 2002.  As a result of Settlement No.2, IPC established a regulatory liability of $19 million with a charge to PCAexpense.  Also, IPC reversed a $16million regulatory tax liability by reducing income tax expense.

**Relicensing**For several years, IPC has been actively pursuing the relicensing ofsome of its hydroelectric projects.  Thefollowing is a summary of the status of relicensing activity:

**Middle Snake River Projects:** OnAugust 4, 2004, IPC received the FERC license orders for each of its fivemiddle Snake River projects.  IPC is nowin the process of developing protection, mitigation and enhancement (PM&E)plans to ensure compliance with the various license articles.  Two environmental organizations have filedpetitions for rehearing of the orders issuing the licenses for the middle SnakeRiver projects.  The FERC has yet toissue orders on these petitions.

**Malad Project**: IPCfiled a new license application for the Malad project in July 2002 and thelicense expired on August 1, 2004.  TheFERC has issued a Final Environmental Assessment under the NationalEnvironmental Policy Act of 1996 (NEPA) and IPC expects a new license to beissued in 2005.

**Hells Canyon Complex:**  This represents IPC's most significantrelicensing effort.  IPC filed itslicense application in July 2003 and the current license will expire in July2005.  IPC's current application,including water quality measures as part of the state's process under section401 of the Clean Water Act, identifies proposed PM&E measures totalingapproximately $386 million.  IPC'spreliminary estimate of the cost of all the proposed PM&E measuressubmitted by other parties participating in the Hells Canyon relicensingprocess is approximately $2.5 billion over up to a 50-year period.

IPC is engaged in discussionswith the FERC and relevant federal and state agencies on the effects, if any,of the relicensing of the Hells Canyon Complex on species listed as threatenedor endangered under the Endangered Species Act (ESA).  These discussions are generally referred to as the Hells CanyonESA Consultation/Settlement Process.  OnJanuary 7, 2005, IPC filed an agreement on interim operations with theFERC.  The interim agreement is intendedto address issues relating to operations of the Hells Canyon Complex andESA-listed species in advance of the issuance of a new license while theparties continue discussions in an effort to negotiate a comprehensiverelicensing settlement agreement.

Pursuant to the requirements ofNEPA, the FERC is independently evaluating the environmental effects ofrelicensing the Hells Canyon Complex. IPC and a number of participants in the settlement discussions haverequested that the FERC defer its NEPA schedule to enable the parties to pursuea comprehensive relicensing settlement in the Hells Canyon ESAConsultation/Settlement Process discussions. The FERC granted IPC's request for deferral.

The relicensing process permitsintervenors to submit additional study requests to the FERC.  The FERC received a total of 123 additionalstudy requests and the FERC has issued to IPC a total of 14 AdditionalInformation Requests.  IPC and thoseparticipating in the relicensing process have objected to the FERC's decisionand the FERC has made a number of rulings on the objections.  Meanwhile, IPC is proceeding with thestudies and analysis relevant to the 14 Additional Information Requests.

**LegalIssues**

IDACORP,IPC and IE have been named as defendants in a number of legal cases.  Major developments include:

OnSeptember 17, 2004, the Idaho Supreme Court dismissed IPC's appeal of a verdictawarding Vierstra Dairy approximately $17 million.  The dismissal was incident to a settlement of the matter amongIPC, IPC's insurance carrier and the plaintiffs.  The settlement, less a deductible, was covered by insurance anddid not have a material effect on IPC;

On May18, 2004, Herculano and Frances Alves brought an action against IPC seekingunspecified monetary damages alleging that IPC allowed electrical current toflow in the earth injuring their right to use and enjoy their property andadversely affecting their dairy herd;

OnOctober 12, 2004, the Ninth Circuit Court of Appeals unanimously affirmed aDistrict Court's dismissal of the California Attorney General's action againstIPC and twelve other defendants claiming violations of the Federal Power Act;

Threesimilar cases in U.S. District Court arising out of the western energysituation alleging anti-trust violations and market manipulation againstIDACORP, IPC and IE were dismissed.  Theaction by the Port of Seattle against IDACORP and IPC was dismissed on May 28,2004 and is on appeal to the Ninth Circuit Court of Appeals.  The actions by the City of Tacoma and WahChang against IDACORP, IPC and IE were both dismissed on February 11, 2005;

OnAugust 10, 2004, the Ninth Circuit Court of Appeals affirmed a U.S. DistrictCourt dismissal of a complaint filed by the Public Utility District No. 1 ofGrays Harbor County, Washington against IDACORP and IE claiming an electricpurchase contract was void and unenforceable and seeking restitution butpermitted Grays Harbor leave to amend its complaint to seek declaratory reliefonly as to contract formation;

Twoshareholder lawsuits against IDACORP and certain of its directors and officersalleging materially false and misleading statements or omissions aboutIDACORP's financial outlook and seeking unspecified monetary damages wereconsolidated and the defendants filed a consolidated motion to dismiss onFebruary 9, 2005, which is now pending;

PowerexCorp. filed suit against IDACORP and IE alleging breach of an oral and writtencontract and seeking unspecified general damages;

In themarket manipulation proceeding, on January 23, 2004, the FERC approved the FERCStaff's motion to dismiss the "partnership" proceeding against IPCand no rehearing was sought. On March 3, 2004, the FERC approved IPC'ssettlement in the "gaming" proceeding and eight parties soughtrehearing; and

On May12, 2004, the FERC Office of Market Oversight and Investigations issued aletter advising IPC that it was terminating its investigation of IPC in its"bidding" investigation.

 

**CRITICAL ACCOUNTING POLICIES:**

IDACORP's and IPC's discussionand analysis of their financial condition and results of operations are basedupon their consolidated financial statements, which have been prepared inaccordance with accounting principles generally accepted in the United Statesof America (GAAP).  The preparation ofthese financial statements requires IDACORP and IPC to make estimates andjudgments that affect the reported amounts of assets, liabilities, revenues andexpenses and related disclosure of contingent assets and liabilities.  On an ongoing basis, IDACORP and IPCevaluate these estimates, including those related to rate regulation, benefitcosts, contingencies, litigation, impairment of assets, income taxes,restructuring costs and bad debt.  Theseestimates are based on historical experience and on various other assumptions andfactors that are believed to be reasonable under the circumstances, and are thebasis for making judgments about the carrying values of assets and liabilitiesthat are not readily apparent from other sources.  IDACORP and IPC, based on their ongoing reviews, will makeadjustments when facts and circumstances dictate.

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

**Accountingfor 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 of regulatorydecisions in their consolidated financial statements and requires that certaincosts be deferred as regulatory assets until matching revenues can berecognized.  Similarly, certain itemsmay be deferred as regulatory liabilities and amortized to the income statementas rates to customers are reduced.

IPC follows SFAS 71, and itsfinancial statements reflect the effects of the different rate makingprinciples followed by the various jurisdictions regulating IPC.  The primary effect of this policy is thatIPC has recorded $439 million of regulatory assets and $276 million ofregulatory liabilities at December 31, 2004. While IPC expects to fully recover these regulatory assets and returnthese regulatory liabilities, such recovery is subject to final review by theregulatory entities.

If IPC should determine in thefuture that it no longer meets the criteria for continued application of SFAS71, it would be required to write off its regulatory assets and liabilitiesunless regulators specify some other means of recovery or refund.  IPC intends to seek recovery of all of itsprudent costs, including stranded costs, in the event of deregulation.  However, due to the current lack ofdefinitive legislation, IPC cannot predict whether recovery would be successful.  If IPC has to write off a material amount ofthe regulatory assets, it will have a material adverse effect on IPC's resultsof operations and financial position.

**PensionExpense**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 recordedpension expense for these plans is dependent on a number of factors, includingthe provisions of the plans, changing employee demographics, actual returns onplan assets and several actuarial assumptions used in the valuations upon whichpension expense is based.  The keyactuarial assumptions that affect expense are the long-term return on planassets and the discount rate used in determining future benefitobligations.  Management reviews theseassumptions on an annual basis, taking into account changes in marketconditions, trends and future expectations. Estimates of future stock market performance, changes in interest ratesand other factors used to develop these assumptions are extremely uncertain,and actual results could vary significantly from the estimates.

The assumed discount rate isbased on reviews of market yields on high-quality corporate debt.  Based on recent market trends, the discountrate used to calculate the 2005 pension expense will be reduced to 5.75 percentfrom the 6.15 percent used in 2004.

Rate-of-return projections forplan assets are based on historical real returns (after inflation) for eachasset class, based on a recognized index established for the asset class beingmeasured (S&P 500 Index for large-cap core stocks, Russell 1000 Growth forlarge-cap growth stocks, etc.). Historical real returns are then adjusted to include an inflationpremium based on the current inflation environment.  Currently a three percent inflation assumption is used in theasset modeling process.  The assumedrate of return on plan assets will be 8.5 percent in 2005, the same as in 2004.

Pension expense for these planstotaled $10 million, $12 million and $4 million for the three years endedDecember 31, 2004, 2003 and 2002, respectively, including amounts allocated tocapitalized labor costs.  For 2005,pension expense is expected to total approximately $10 million, which takesinto account the reduction of the discount rate noted above and returns on planassets in 2004 that exceeded actuarial estimates.  No changes were made to the other key assumptions used in theactuarial calculation.

Had different actuarialassumptions been used, pension expense could have varied significantly.  The following table reflects thesensitivities associated with changes in certain actuarial assumptions onhistorical and future pension expense: 
|                    | **Discount  rate**         | **Rate  of return** |
|-------------------------|----------------------------|---------------------|
|                    | **2005**                   | **2004**            | **2005** | **2004** |
|                    | **(millions  of dollars)** |
| Effect of 0.5% increase | $                          | (1.2)               | $ | (1.6) | $ | (1.7) | $ | (1.6) |
| Effect of 0.5% decrease |                       | 2.7            |   | 1.7  |   | 1.7  |   | 1.6  |
|                    |                       |                |   |   |   |   |   |   |

 

No cash contributions were madeto the qualified plan in 2002 through 2004, and none are expected in 2005.  Under the non-qualified plan, IPC makespayments directly to participants in the plan. Payments averaged approximately $3 million per year in 2002 through2004, and a similar amount is anticipated in 2005.

Please refer to Note 10 ofIDACORP's Consolidated Financial Statements, which contains additionalinformation about pension expense, including results of the actuarialvaluations, actuarial assumptions used to measure pension expense andinformation about plan assets.

**ContingentLiabilities**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 losscontingency shall be charged to income if (a) it is probable that an asset hadbeen impaired or a liability had been incurred at the date of the financialstatements and (b) the amount of the loss can be reasonably estimated.  Disclosure in the notes to the financialstatements is required for loss contingencies not meeting both conditions ifthere is a reasonable possibility that a loss may have been incurred.  Gain contingencies are not recorded untilrealized.

The companies have madeestimates of the ultimate resolution of all such matters, based on the factsand circumstances, opinions of legal counsel and other factors.  If the recognition criteria of SFAS 5 havebeen met, liabilities have been recorded. Estimates of this nature are highly subjective, and the final outcome ofthese matters could vary significantly from the amounts that have been includedin 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 2004 include the following:

**Goodwill:** IDACORP has $14 million of goodwill relatedto its investments in IDACOMM and IdaTech. IDACORP conducts its impairment tests under the provisions of SFAS 142,"Goodwill and 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 goodwillamounts were tested for impairment as required, and no impairment wasnoted.  The fair value calculations usedfor these tests require IDACORP to make assumptions about items that areinherently uncertain.  Assumptionsrelated to future market demand, market prices and product costs could varyfrom actual results, and the impact of such variations could be material.  Factors that could affect the assumptionsinclude changes in economic conditions, success in developing marketableproducts and services and competitive conditions in the telecommunications andfuel cell industries.

**Long-lived Assets:**Long-lived assets are periodically reviewed for impairment when events orchanges in circumstances indicate that the carrying amount of an asset may notbe recoverable as prescribed under SFAS 144, "Accounting for theImpairment or Disposal of Long-lived Assets."  SFAS 144 requires that if the sum of the undiscounted expectedfuture cash flows from an asset is less than the carrying value of the asset,an asset impairment must be recognized in the financial statements.

**Southwest Intertie Project:** IPCbegan developing the Southwest Intertie Project (SWIP) in 1988.  IPC's investment consists predominantly ofrights-of-way over public lands in Idaho and Nevada.  The SWIP rights-of-way extend from Midpoint substation insouth-central Idaho through eastern Nevada to the Crystal switchyard north ofLas Vegas, Nevada.  IPC does notcurrently anticipate constructing this transmission line itself and is indiscussions regarding the sale of the rights-of-way.  The Bureau of Land Management recently granted a five-yearextension to begin construction of a proposed 500kV transmission line withinthe rights-of-way before December 2009. Based on these discussions and management expectations regarding theultimate development of SWIP, no impairment has been identified.  These expectations are based on assumptionsthat are inherently uncertain.  Actualresults could vary significantly from the assumptions used, and the impact ofsuch variations could be material.

**Investments:**IFS hasaffordable housing and other investmentswith a net book value of  $109 millionat December 31, 2004, and Ida-West has investments in four joint ventures thatown electric power generation facilities. Except for two investments now consolidated under the provisions ofFinancial Accounting Standards Board (FASB) Interpretation (FIN) 46R,"Consolidation of Variable Interest Entities - an interpretation of ARB51," these investments are accounted for under the equity method ofaccounting as described in Accounting Principles Board Opinion No. (APB) 18,"The Equity Method of Accounting for Investments in CommonStock."  The standard fordetermining whether impairment must be recorded under APB 18 is whether theinvestment has experienced a loss in value that is considered another-than-temporary decline in value.

Priorto the decision to discontinue Ida-West's project development activities,Ida-West had the intent and ability to hold the investments for a periodsufficient to recover the recorded value. Based upon the change in management's intent, these investments weretested for impairment, and two of the investments were determined to beimpaired, resulting in a write down of $2 million in 2003.  The impairment amounts are based on theestimated fair value of the investments. Impairment tests on these investments were performed in 2004 and noimpairment was noted.

Theseestimates required IDACORP to make assumptions about future stream flows, revenues,cash flows and other items that are inherently uncertain.  Actual results could vary significantly fromthe assumptions used, and the impact of such variations could be material.

**RESULTS OF OPERATIONS:**

This section of theMD&A takes a closer look at the significant factors that affected IDACORP'sand IPC's earnings over the last three years. In this analysis, the results of 2004 are compared to 2003 and theresults of 2003 are compared to 2002. The analysis is organized by IDACORP's reportable segments, which areUtility Operations and IFS.  Thefollowing table presents EPS for both reportable segments as well as for theholding company and its other subsidiaries combined:
| **EPS of common stock** |   |   |   |   |   |  
 

**2004**

 

**2003**

 

**2002**

 
Utility operations*

$

1.71 

 

$

1.44   

 

$

2.24 

 
IFS*

 

0.35 

 

 

0.27 

 

 

0.23 

 
Other*

 

(0.16)

 

 

(0.49)

 

 

(0.84)

 
Total EPS

$

1.90 

 

$

1.22 

 

$

1.63 

 
 

 
* 

The EPS of any one segment does not represent a direct  legal interest in the assets and liabilities allocated to 

 

any one segment but rather represents a direct equity  interest in IDACORP's assets and liabilities as a whole.

 

 

 
Return on year-end common equity

 

7.2%

 

 

5.4%

 

 

7.1%

 
 

**UtilityOperations**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.

**Generation:**IPC relies on its hydroelectric plants for a significant portion ofits power supply.  The availability ofhydroelectric generation can significantly affect the amount of net powersupply costs, which are fuel and purchased power less off-system sales, thatIPC incurs.  Most, but not all, of thenet power supply costs are recovered through the rates charged to customers.  Lower hydroelectric generation increases netpower supply costs, thereby increasing the amount of these costs that IPC mustabsorb.

IPC's system is dual peaking, with thelarger peak demand usually occurring in the summer.  IPC's record system peak of 2,963 MW occurred on July 12,2002.  Peak summer demand in 2004 was2,843 MW on June 24 and peak winter demand for the year was 2,196 MW on January5.  IPC was able to meet system loadrequirements and off-system sales requirements and had sufficient systemreserves in place.  IPC's 2004 IntegratedResource Plan (IRP) reports that customers' use of electricity continues togrow especially during the summer months. IPC projects that summer peaks could grow by an average of 2.5 percentper year over the ten-year IRP planning period.

In 2004, IPC experienced its fifthconsecutive year of below normal hydroelectric generating conditions.  The National Weather Service Northwest RiverForecast Center reports April through July inflow to Brownlee Reservoir for 2004totaled 3.19 million acre-feet (maf), which is 51 percent of the 30-yearaverage.  The total annual Brownleeinflow for 2004 was 8.99 maf, which the River Forecast Center reports is 59percent of average.

Below average stream flow conditionsare continuing for a sixth consecutive year in 2005.  The River Forecast Center forecast released on March 8, 2005indicates Brownlee inflow for April through July 2005 is expected to total 1.74maf, or 28 percent of average.  Snowpack accumulation was 60 percent of average on March 8, 2005.  Storage in selected federal reservoirsupstream of Brownlee at the end of December 2004 was 60 percent ofaverage.  October 1, 2004 storage inthese reservoirs, which is considered carryover storage into water year 2005,was only 41 percent of average.  Theflows in the Snake River at several measurement locations are at or near recordlows.

The continuing below averagehydrologic conditions will reduce IPC's hydroelectric generation, and requireit to use wholesale purchases from the energy markets and higher-cost thermalgeneration when necessary to meet its energy needs in 2005.  Generation from IPC's hydroelectricfacilities is expected to be 5.5 million MWh in 2005, compared to 6.0 millionMWh in 2004 and normal generation of 9.2 million MWh.  The following table presents IPC's system generation:

 

**MWh**

**% of  total generation**

 

 

 

**Total**

 

 

**Total**

 

 

 

**system**

 

 

**system**

 

**Hydroelectric**

**Thermal**

**generation**

**Hydroelectric**

**Thermal**

**generation**

2004

6,041

7,303

13,344

45%

55%

100%

2003

6,149

6,914

13,063

47%

53%

100%

2002

6,069

7,286

13,355

45%

55%

100%

Normal(a)

9,172

7,365

16,537

55%

45%

100%

 

 

 

 

 

 

 

(a)      Normal  hydroelectric generation represents the annual average based on median  conditions, using 1928 - 2002 stream flows, adjusted to 

 

the 1992 level of depletion, and observed generation  for 2003-2004.  Normal thermal  represents average generation for the past five years.

 

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

 

**Revenue**

 

**MWh**

 

**2004**

 

**2003**

 

**2002**

 

**2004**

 

**2003**

 

**2002**

Residential

$

274,313

 

$

275,920

 

$

305,827

 

4,580

 

4,427

 

4,387

Commercial

 

164,053

 

 

173,820

 

 

196,454

 

3,561

 

3,511

 

3,460

Industrial

 

111,797

 

 

128,620

 

 

176,648

 

3,335

 

3,206

 

3,226

Irrigation

 

85,672

 

 

92,609

 

 

93,106

 

1,763

 

1,836

 

1,821

 

Total

$

635,835

 

$

670,969

 

$

772,035

 

13,239

 

12,980

 

12,894

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2004vs. 2003:

**Rates:**  Lower average rates, resulting from the PCA,decreased general business revenue $40 million.  The decrease in PCA revenues was approximately $68 million.  This was partially offset by a $28 millionincrease due to new base rates beginning on June 1,  2004.  The general ratecase and the PCA are discussed in more detail below in "REGULATORY ISSUES- General Rate Case" and "REGULATORY ISSUES - Deferred Power SupplyCosts - Idaho;"

**Customers**:  An increase in general business customersimproved revenue $19 million during 2004. IPC is experiencing strong customer growth in its service territory,adding nearly 14,000 general business customers in the last 12 months, a 3.2percent increase.  Similar growth isexpected to continue in 2005 and beyond;

**ContractExpiration**:  The expirationin March 2003 of a take-or-pay contract with FMC/Astaris caused a $9 milliondecrease in revenues for 2004. 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; and

**Usage**:  Revenues decreased approximately $6 millionduring 2004 mainly due to cooler summer weather.  Cooling degree-days for this year were 24 percent less than 2003,which had unusually hot summer temperatures. Cooling degree-days are a common measure used in the utility industry toanalyze the demand for electricity and indicate when a customer would useelectricity for air conditioning.

2003vs. 2002:

**Rates:**  Decreasedaverage rates, resulting from the PCA, reduced revenue $79 million;

**Contract Expiration**:  Revenuesdecreased $28 million due to the expiration in March 2003 of the take-or-paycontract with FMC/Astaris;

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

**Usage**:  Milderfall and winter weather and other usage factors reduced revenues byapproximately $10 million.

 

**Off-system sales:**  Off-system sales consist primarily oflong-term sales contracts and opportunity sales of surplus system energy.

 

**2004**

 

**2003**

 

**2002**

 

 

 

 

 

 

 

 

 

Revenue

$

121,148

 

$

71,573

 

$

55,031

MWh sold

 

2,885

 

 

1,830

 

 

2,069

Revenue per MWh

$

41.99

 

$

39.11

 

$

26.60

 

 

 

 

 

 

 

 

 

 

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

2003vs. 2002:  Revenues from off-system sales increased due principally tohigher average prices in the wholesale electricity markets.

**Otherrevenues**: 

2004vs. 2003:  Other revenues increased$25 million over 2003 due mainly to the following:

InDecember 2004, IPC recorded approximately $12 million related to the recoveryof lost revenue resulting from IPC's Irrigation Load Reduction Program.  The recovery will be included as part ofIPC's annual PCA beginning on June 1, 2005. This matter is discussed further in "REGULATORY ISSUES - DeferredPower Supply Costs - Idaho;"

IPCrecognized approximately $7 million of revenue due to the IPUC order approvingSettlement No. 1, which relates to the calculation of IPC's taxes for purposesof test year income tax expense in the Idaho general rate case.  As a result of this settlement, IPC isrecording a regulatory asset of approximately $12 million from June 1, 2004through May 31, 2005.  IPC will begincollecting this amount beginning in June 2005 with an adjustment to rates; and 

InJuly 2004, IPC recognized $4 million of revenue from an agreement with the BonnevillePower Administration for the release of 100,000 acre-feet of storage water fromBrownlee Reservoir.  This amount hasbeen included in the PCA and will result in a benefit to IPC's Idaho customersin the next PCA year.

 

2003vs. 2002:  Other revenues did notchange materially from 2002 to 2003.

**Purchasedpower:**

 

**2004**

 

**2003**

 

**2002**

Purchased power:

 

 

 

 

 

 

 

 

 

Purchases

$

195,642

 

$

147,850

 

$

91,312

 

Load reduction costs

$

-

 

$

3,130

 

$

50,790

 

 

 

 

 

 

 

 

 

MWh purchased

 

4,274

 

 

3,383

 

 

2,918

Cost per MWh purchased

$

45.77

 

$

43.70

 

$

31.29

 

 

 

 

 

 

 

 

 

 

2004vs. 2003:  The 2004 increase in purchased power expense is mostly due to a26 percent increase in volumes purchased. The increased volumes purchased are a result of power supply hedgeactivity based on expectations of reduced hydroelectric generation due tocontinued below normal water conditions. Load reduction costs decreased from $3 million to zero due to theexpiration in March 2003 of the FMC/Astaris Voluntary Load Reduction Program,which is discussed further in "REGULATORY ISSUES - FMC/Astaris SettlementAgreement."

2003vs. 2002:  Volumes purchased increased due principally to two factors:unplanned outages at IPC's thermal plants and increased sales to generalbusiness customers.  Load reductioncosts decreased $48 million due to the expiration of the FMC/Astaris VoluntaryLoad Reduction Program in March 2003.

**Fuelexpense:**  The following table presents IPC's fuel expenses and generationat its thermal generating plants:

 

**2004**

 

**2003**

 

**2002**

Fuel expense

$

103,261

 

$

99,898

 

$

102,871

Thermal MWh generated

 

7,303

 

 

6,914

 

 

7,286

Cost per MWh

$

14.14

 

$

14.45

 

$

14.12

 

 

 

 

 

 

 

 

 

 

2004 vs. 2003:  Fuel expenses increased in 2004 mainlydue to a six percent rise in generation. The increase in generation resulted from a return to normal operationsat Valmy, which produced 23 percent more in 2004 than in 2003.  See discussion of the outage at the Valmyplant below.  This increase waspartially offset by a 17 percent reduction in generation from the Boardmanplant, which was offline for a longer period in 2004 in order to perform anupgrade to the turbine-generator.

2003 vs. 2002:  Fuel expense decreased in 2003 due primarilyto increased unplanned outages.  Themost significant outage involved one of the two units of the Valmy plant.  As the unit was being returned to serviceafter an unplanned outage, a breakdown occurred, unrelated to the completedmaintenance, forcing the unit out of service from late June to early Septemberin 2003.  The unit was repaired andmodernized controls and protection systems are in place.  Additional maintenance was completed duringthe outage that minimized the 2004 planned maintenance outage period for theunit.  IPC owns 50 percent of the Valmyplant and is not the plant operator.

Coal Supply:  The Valmy plant has experienced problemswith its coal supply, delivery and resulting coal inventory level.  During 2004, delivery service from the coalmines to Valmy was unpredictable.  Inaddition, there have been several mine production and quality issues that havereduced coal availability.  Thesefactors have negatively impacted the plant's coal inventory level and IPC andSierra Pacific Power Company, Valmy's co-owner and operator, continue toaddress the problem.  IPC expects theseproblems to continue during 2005.

The preferred Valmy coalinventory level is 45 days at full load; the current coal inventory level is 24days at full load.  To date, generationhas not been negatively impacted by the coal inventory level.  IPC and Sierra Pacific Power Company have anagreement in place to modify plant operations if inventory drops below 10 daysat full load.

**PCA:**  PCA expense represents the effect of IPC'sPCA regulatory mechanism, which is discussed in more detail below in"REGULATORY ISSUES - Deferred Power Supply Costs - Idaho."   In 2004, 2003 and 2002, actual net powersupply costs, which are fuel and purchased power less off-system sales,exceeded those anticipated in the annual PCA forecast, resulting in the deferralof a portion of those costs to subsequent years when they are to be recoveredin rates.  As the revenues are beingrecovered, the deferred balances are amortized.

The following table presents the components of PCAexpense: 

 

 

**2004**

 

**2003**

 

**2002**

Current year net power supply cost deferral

 

$

(29,306)

 

$

(44,320)

 

$

(4,178)

FMC/Astaris and irrigation program cost deferral

 

 

- 

 

 

(2,245)

 

 

(39,854)

Amortization of prior year authorized balances

 

 

49,190 

 

 

117,279 

 

 

200,941 

Write-offs of disallowed costs

 

 

- 

 

 

48 

 

 

13,580 

Settlement agreement

 

 

19,300 

 

 

- 

 

 

- 

 

Total power cost adjustment

 

$

39,184 

 

$

70,762 

 

$

170,489 

 

 

 

 

 

 

 

 

 

 

 

**OtherOperations and Maintenance Expenses:**2004 vs. 2003:  Otheroperations and maintenance expenses increased $35 million due mainly to thefollowing:

Anincrease in payroll expense of $13 million for an employee incentive program,which was partially triggered by the settlement relating to the irrigation loadreduction program;

Awrite-off of $9 million related to disallowed items in the Idaho general ratecase; and

Increasesin transmission expense of $4 million primarily due to the increase inpurchased power.

 

2003 vs. 2002: Otheroperations and maintenance 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 an increase intree-trimming and pole maintenance costs of $1 million, and because ofinsurance proceeds of  $1 millionreceived in 2002 related to a 2001 outage.

 

**IFS**IFS contributed $0.35, $0.27 and $0.23 per share for 2004, 2003 and 2002,respectively, principally from the generation of federal income tax credits andtax depreciation benefits.  The 2004results include a gain on the sale of its investment in the El Cortez Hotel inSan Diego, California.  In June 2000,IFS invested $4 million to assist in the renovation of the historic El Cortezinto upscale apartment units.  Uponexiting the investment on April 22, 2004, IFS recognized a gain on the sale of$5 million, income taxes of $3 million and a net gain of $2 million.  The gain is included in other income onIDACORP's Consolidated Statements of Income.

IFS generates federal incometax credits and accelerated tax depreciation benefits related to itsinvestments in affordable housing and historic rehabilitationdevelopments.  IFS made $8 million innew investments during 2004 and generated tax credits of $22 million, $20million and $21 million during 2004, 2003 and 2002, respectively.  IFS is expected to continue generating taxbenefits near current levels.

**EnergyMarketing**IE wound down its power marketing operations, closed its businesslocations and sold its forward book of electricity trading contracts to SempraEnergy Trading in 2003.  As part of thesale of the forward book of electricity trading contracts, IE entered into anIndemnity Agreement with Sempra Energy Trading, guaranteeing the performance ofone of the counterparties.  The maximumamount payable by IE under the Indemnity Agreement is $20 million.  The Indemnity Agreement has been accountedfor in accordance with FIN 45, "Guarantor's Accounting and DisclosureRequirements for Guarantees, Including Indirect Guarantees of Indebtedness ofOthers" and did not have a material effect on IDACORP's financialstatements.

For 2004, IE reported $2million of operating income due to gains on the settlements of legal disputes.

IE reported an $18 millionoperating loss in 2003 compared to a $26 million operating loss in 2002.  IE realized a $17 million gain from the saleof its forward book of electricity trading contracts in August 2003.  This gain was offset by a loss on legaldisputes of $12 million, legal expenses of $6 million, acceleration ofdepreciation expense of $6 million, restructuring expenses of $5 million andgeneral and administrative costs of $6 million.  See also Note 15 of IDACORP's Consolidated Financial Statementsfor information related to restructuring costs of IE.

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 included in energy marketing operating expenses on IDACORP'sConsolidated Statement of Income.

**Ida-West**In 2003, Ida-West discontinued its project developmentoperations.  This decision resulted fromthe implementation of IDACORP's new corporate strategy.  This strategy does not include the developmentor acquisition of merchant generation, which was Ida-West's focus.  Currently, Ida-West continues to manage itsindependent power projects with a reduced workforce.

Impairment charges, as discussed below, negativelyaffected Ida-West's earnings in both 2003 and 2002.

**Garnet impairment**:  In 2001, Garnet, a whollyowned subsidiary of Ida-West, entered into a purchased power agreement with IPCto provide energy to be produced by Garnet's proposed natural gas-fired plant.  Due to changes in the electricity industry,financing of the project on acceptable terms under the purchased poweragreement became impracticable.  In2002, Ida-West wrote down $8.6 million of its investment in equipment relatedto Garnet.  At that time, the siteremained viable for future generation development.  In 2003, the original purchased power agreement was mutuallyterminated.  Also in 2003, IPC issued aformal request for proposal (RFP) seeking bids for the construction of up to200 megawatts (MW) of additional generation. The RFP specifically prohibited affiliates of IPC, including Ida-West,from bidding.  While one bid proposedacquisition and use of the Garnet site, a different bid was selected.  Based on the termination of the purchasedpower agreement, the results of the RFP process and the decision to discontinueproject development operations, Ida-West determined that recovery of itsremaining $3.6 million investment in the Garnet site development costs wasuncertain and an impairment charge for the entire amount was recorded.  Each of these impairments is presented onthe Consolidated Statement of Income as other operating expenses.

**Joint ventures:** Based on management's new corporate strategy, Ida-West's investments infour joint ventures were evaluated for impairment in 2003.  As a result, $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 expense.  There was no impairment identified for 2004.

Inaddition, a $2.6 million bad debt reserve was established in 2003 on a notereceivable from a partner in one of the joint ventures.  This reserve is presented on theConsolidated Statement of Income as other operating expenses.  No further reserve was necessary for 2004.

**Income TaxesStatus of Audit Proceedings:**  In 2004, IDACORP settled all issues related to the InternalRevenue Service's examination of its federal income tax returns for the years1998 through 2000.  Applicable state taxreturn amendments were completed in 2004 and settled.  The settlement resulted in a benefit of $2 million in 2004 and $9million in 2003, as the deficiencies assessed were less than previously accrued.

In 2004, IPC settled federalincome tax deficiencies for the years 1999 and 2000 related to its partnershipinvestment in the Bridger Coal Company. IPC had previously accrued sufficient amounts to satisfy the 1999 and2000 deficiencies.  In 2002, IPC settledthe years 1991 through 1998.  The 2002settlement resulted in deficiencies that were less than previously accrued,enabling IPC to decrease income tax expense by approximately $3 million.

During2005, the Internal Revenue Service will begin its examination of IDACORP's 2001through 2003 tax years.  Managementbelieves that an adequate provision for income taxes and related interestcharges has been made for the open years 2001 and after.  The accrued amounts are classified as acurrent liability in taxes accrued.

Management cannot predict withcertainty which financial accounts or tax adjustments will be chosen by the IRSfor examination.  IDACORP intends tovigorously defend its tax positions.  Itis possible that material differences in actual outcomes, costs and exposuresrelative to current estimates, or material changes in such estimates, couldhave a material adverse effect on IDACORP's consolidated financial positions,results of operations or cash flows.

**Regulatory Settlement:**  In 2004, IPC and the IPUC finalized anincome tax issue from IPC's 2003 Idaho general rate case.  The issue concerned the regulatoryaccounting treatment for the capitalized overhead cost tax method IPC adoptedin the 2001 IDACORP federal income tax return. As a result of the settlement, a $16 million regulatory tax liabilitywas reversed, creating a tax benefit.

**Tax Accounting Method Change:**  In 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 the construction of plant, while thenew method allocates such costs to both construction of plant and theproduction of electricity.

The tax accounting methodchange decreased 2002 income tax expense by $35 million, of which $31 millionwas attributable to 2001 and prior tax years, and $4 million was attributableto the 2002 tax year.  The decrease totax expense was a result of deductions on the applicable tax returns of coststhat were 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 enterprises are required torecognize such adjustments as regulatory assets if it is probable that suchamounts will be recovered from customers in future rates.

**Tax Credits:**  IFS generates federal income tax credits andaccelerated tax depreciation benefits related to its investments in affordablehousing and historic rehabilitation developments.  IFS generated tax credits of $22 million, $20 million and $21million for the years 2004, 2003 and 2002, respectively.

**American Jobs Creation Act of2004:**In October 2004, the president signed into law theAmerican Jobs Creation Act of 2004 (the Act), which may have tax implicationsfor IDACORP and IPC.  One provision ofthe Act with potential implications for the companies relates to manufacturingtax incentives for the production of electricity beginning in 2005.  Taxpayers will be able to deduct apercentage (three percent in 2005 and 2006, six percent in 2007 through 2009,and nine percent in 2010 and thereafter) of the lesser of their qualifiedproduction activities income or their taxable income.  Management is currently reviewing this and other aspects of theAct to determine the impact on the companies.

**LIQUIDITY AND CAPITAL RESOURCES:**

**Operating Cash Flows**IDACORP's and IPC's operating cash flows for 2004 were $195 millionand $198 million, respectively.

IDACORP'soperating cash flows decreased $118 million in 2004 as a result of reducedreceipts from IPC's general business customers of $44 million and an $83million decrease in net operating cash flows from IE.  In 2003, IE received $40 million from the sale of its forwardbook of electricity trading contracts and collected $45 million on a notereceivable from Overton Power District No. 5. These decreases in 2004 were partially offset by a $45 million reductionin income taxes paid.

IPC'soperating cash flows have increased $11 million from 2003 as a result of a $61million decrease in income taxes paid to IDACORP during the year, partiallyoffset by a decrease of $44 million in receipts from general businesscustomers.

In2005, net cash provided by operating activities will be driven by IPC, wheregeneral business revenues and the costs to supply power to general businesscustomers have the greatest impact on operating cash flows.  As IPC's service territory enters the sixthconsecutive year of below normal water conditions, the company expects to relymore on higher-cost thermal generation and wholesale power purchases to meetits energy needs in 2005.  Thus, it isexpected that IPC's 2005-2006 PCA will be higher than the 2004-2005 PCA.

**Environmental RegulationCosts: **IPC anticipates $16 millionin annual operating costs for environmental facilities during 2005.  Hydroelectric facility expenses account for$11 million of this total and $5 million is related to thermal plant operatingexpenses.  From 2006 through 2007, totalenvironmental related operating costs are estimated to be $33 million.  Anticipated expenses related to thehydroelectric facilities account for $23 million and thermal plant expenses areexpected to total $10 million during this period.

**Working Capital**The changes in working capital are dueprimarily to an increase in deferred income taxes of $19 million as a result ofchanges in temporary differences between pre-tax financial income and taxableincome, an increase of $11 million in current maturities of long-term debt dueto the differences in first mortgage bonds due in 2004 and 2005, a decrease innotes payable of $57 million due to the pay-down of commercial paper and anincrease of $18 million in accounts payable due mainly to the accrual ofpayroll expenses associated with an employee incentive plan.

**Pension Expense andContributions**Total pension expenses in 2004 were $10 million and pension plancontributions were $3 million for the qualified and non-qualified plans.  These amounts are not expected to changematerially in 2005.

**Insurance Expenses**IPC forecasts that its 2005 medical insurance costs will increase toapproximately $16 million, approximately $2 million above 2004 actualamounts.  Rising health care costs arethe principal contributor to this increase.

**DividendReduction**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.  The dividend reduction was also made to improve cash flows andhelp maintain credit ratings.

**ContractualObligations**The following table presents IDACORP's andIPC's contractual cash obligations for the respective periods in which they aredue:

 

**Payment Due by Period**

 

Total

**2005**

**2006-2007**

**2008-2009**

**Thereafter**

Long-term debt - IPC (a)

$

987,045

$

60,000

$

81,064

$

82,128

$

763,853

Future interest  payments - IPC (b)

 

774,427

 

54,102

 

102,605

 

90,406

 

527,314

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

 

74,179

 

18,603

 

29,813

 

16,048

 

9,715

Future interest  payments - Other (b)(i)

 

15,976

 

3,761

 

4,901

 

2,167

 

5,147

Capital lease  obligations - Other (i)

 

83

 

43

 

40

 

-

 

-

Operating leases -  IPC (c)

 

10,119

 

1,820

 

1,843

 

614

 

5,842

Operating leases -  Other (i)

 

2,889

 

1,245

 

1,551

 

65

 

28

Purchase obligations  - IPC:

 

 

 

 

 

 

 

 

 

 

 

Cogeneration and  small power 

 

 

 

 

 

 

 

 

 

 

 

 

production

 

797,564

 

43,235

 

95,331

 

97,373

 

561,625

 

Fuel swap

 

1,855

 

1,855

 

-

 

-

 

-

 

Fuel supply  agreements

 

111,309

 

36,622

 

40,568

 

22,053

 

12,066

 

Purchased power &  transmission (d)

 

111,029

 

79,381

 

13,230

 

11,805

 

6,613

 

Maintenance &  service agreements (e)

 

75,835

 

38,625

 

18,225

 

7,379

 

11,606

 

Other (f)

 

61,576

 

19,333

 

9,733

 

9,919

 

22,591

 

 

Total IPC purchase  obligations

 

1,159,168

 

219,051

 

177,087

 

148,529

 

614,501

Purchase obligations  - Other (i)

 

1,759

 

1,665

 

64

 

30

 

-

Restructuring charges  - Other (g)

 

1,393

 

338

 

717

 

338

 

-

Other long-term  liabilities - IPC (h)

 

3,958

 

1,572

 

1,046

 

355

 

985

Total IDACORP

$

3,030,996

$

362,200

$

400,731

$

340,680

$

1,927,385

Total IPC

$

2,934,717

$

336,545

$

363,645

$

322,032

$

1,912,495

 

 

 

 

 

 

 

 

 

 

 

(a)  

For additional information,  see Note 5 to IDACORP's Consolidated Financial Statements.

 
(b)

Future interest payments are  calculated based on the assumption that all debt is outstanding until  maturity.  For debt instruments with  variable 

 
 

rates, interest is  calculated for all future periods using the rates in effect at December 31, 2004.

 
(c)  

Approximately $8 million of  the obligations included in the detail of operating leases have contracts  that do not specify terms related to 

 
 

expiration.  As these contracts are presumed to  continue indefinitely, 10 years of information, estimated based on current  contract terms, 

 
 

have been included in the  table for presentation purposes.

 
(d)  

Approximately $13 million of  the obligations included in the detail of purchased power and transmission  have contracts that do not specify 

 
 

terms related to  expiration.  As these contracts are  presumed to continue indefinitely, 10 years of information, estimated based  on current 

 
 

contract terms, have been  included in the table for presentation purposes.

 
(e)  

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

 
 

penalty.  Additionally, approximately $40 million of  the contracts do not specify terms related to expiration.  As these contracts are presumed

 
 

 to continue indefinitely, 10 years of information, estimated  based on current contract terms, have been included in the table for  presentation 

 
 

purposes.

 
(f)  

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

 
 

Additionally, approximately  $41 million of the contracts do not specify terms related to expiration.  As these contracts are presumed to  continue

 
 

indefinitely, 10 years of  information, estimated based on current contract terms, have been included in  the table for presentation purposes.

 
(g)  

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

 
 

Statements.

 
(h)  

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

 
 

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

 
 

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

 
 

for presentation purposes.

 
(i)  

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

 
** **

**Off-BalanceSheet Arrangements**The federal Surface Mining Control and Reclamation Act of 1977 andsimilar state statutes establish operational, reclamation and closure standardsthat must be met during and upon completion of mining activities.  These obligations mandate that mine propertybe restored consistent with specific standards and the approved reclamationplan.  The mining operations at theBridger Coal Company are subject to these reclamation and closure requirements.

IPC has guaranteed theperformance of reclamation activities of its Bridger Coal Company jointventure.  This guarantee, which isrenewed each December, was $60 million at December 31, 2004.  Bridger Coal has a reclamation trust fundset aside specifically for the purpose of paying these reclamation costs andexpects that the fund will be sufficient to cover all such costs.  Because of the existence of the fund, theestimated fair value as well as the impact on the consolidated financialstatements of this guarantee was minimal.

In August 2003, IE sold itsforward book of electricity trading contracts to Sempra Energy Trading.  As part of the sale, IE entered into anIndemnity Agreement with Sempra Energy Trading, guaranteeing the performance ofone of the counterparties.  The maximumamount payable by IE under the Indemnity Agreement is $20 million.  The impact of this guarantee on theconsolidated financial statements was minimal.

**CreditRatingsS&P**:  On November 29, 2004, S&P announced that it had lowered thecorporate credit ratings and long-term ratings of IDACORP and IPC.  The companies' commercial paper rating wasaffirmed at A-2, and the rating outlooks for both companies are stable.

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

**Moody's:**On December 3, 2004, Moody's announcedthat it had lowered the corporate credit ratings and long-term ratings ofIDACORP and the corporate credit ratings and long-term and short-term ratingsof IPC.  The rating outlooks for bothcompanies are stable.

Moody's stated that the downgradeof IPC's ratings reflected (1) expected weaker cash flow coverage of interestand debt; (2) the likelihood for continued negative free cash flow over thenext few years, with internally generated funds falling short of meeting thedividend requirements of IDACORP and significant utility-related capitalspending; (3) persistent drought conditions that are likely to result in highersupply costs, not all of which are recoverable under IPC's power costadjustment mechanism; (4) the final resolution this fall of IPC's rate case,which resulted in a revenue increase of a little more than half of IPC'supdated request; and (5) the likely need for additional support from the IPUCin future rate proceedings as IPC adds new generation and transmissioninfrastructure to help meet customer and load growth and ensure reliability ofservice.

According to Moody's, thedowngrade of IDACORP's ratings reflected the weaker credit profile of IPC,which is by far the largest source of cash flow in the form of dividends to theparent company.  Moody's stated that,with the continuing negative free cash flow trend for IPC, IDACORP may need todepend more on dividends from its riskier non-utility subsidiaries to meet itsown fixed obligations and common dividend to shareholders, even thoughmanagement has committed to a "back-to-basics" strategy of focusingon its regulated business.

In addition, Moody's assigned aBaa2 rating to IDACORP's three-year $150 million senior unsecured bank creditfacility and a Baa1 rating to IPC's three-year $200 million senior unsecuredbank credit facility.  Both facilitiesexpire on March 16, 2007.

Moody'sstated that the ratings assigned to the bank credit facilities reflected the *paripassu* ranking of the facilities with each company's other senior unsecuredobligations.  The facilities serve aspart of the alternate liquidity for each company's commercial paper program andcontain a maximum 65 percent total debt to total capitalization ratio covenantwith a material adverse change clause as part of the representations andwarranties relating to each credit extension. In Moody's view, the existence of the material adverse change clausedetracts from the quality of the facilities since it could preclude access tofunds at the time of greatest need.**Fitch:**  On January 24, 2005, Fitchannounced that it has lowered the long-term ratings of IDACORP and IPC and theshort-term debt ratings at IPC.  Therating outlooks for both companies are stable.

Fitch stated that the downgradeof IPC's ratings reflected IPC's increased earnings volatility and debt burdenrelative to cash flows, primarily due to the adverse effect of ongoing droughtconditions in southern Idaho and the lower than expected general rate caseorder issued by the IPUC in 2004. According to Fitch, consolidated leverage has also been adverselyaffected by higher non-utility debt. Fitch noted that the revised ratings also considered the moderatingeffect of IPC's PCA mechanism, which has enabled the company to maintain solidinterest coverage ratios, the positive impact of a more conservative corporatebusiness profile and ongoing efforts to reduce financial leverage.  Fitch stated that the stable rating outlookassumes a return to normal stream flows and hydroelectric generation output in 2006.

Access to capital markets at areasonable cost is determined in large part by credit quality.  Thesedowngrades are expected to increase the cost of new debt and other issuedsecurities going forward.  Thefollowing outlines the current S&P, Moody's and Fitch ratings of IDACORP'sand IPC's securities:

 

**S&P**

**Moody's**

**Fitch**

 

**IPC**

**IDACORP**

**IPC**

**IDACORP**

**IPC**

**IDACORP**

Corporate Credit Rating

BBB+

BBB+

Baa 1

Baa 2

None

None

Senior Secured Debt

A-

None

A3

None

A-

None

Senior Unsecured Debt

BBB

BBB

Baa 1

Baa 2

BBB+

BBB

 

(prelim)

(prelim)

 

 

 

 

Subordinated Debt

None

BBB-

None

None

None

None

 

 

(prelim)

 

 

 

 

Preferred Stock

BBB-

None

(P)Baa 3

None

BBB

None

 

(prelim)

 

 

 

 

 

Trust Preferred Stock

None

BBB-

None

(P)Baa 3

None

None

Short-Term Tax-Exempt Debt

BBB/A-2

None

Baa 1/VMIG-2

None

None

None

Commercial Paper

A-2

A-2

P-2

P-2

F-2

F-2

Credit Facility

None

None

Baa 1

Baa 2

None

None

Rating Outlook

Stable

Stable

Stable

Stable

Stable

Stable

 

These security ratings reflectthe views of the rating agencies.  An explanationof the significance of these ratings may be obtained from each ratingagency.  Such ratings are not arecommendation to buy, sell or hold securities.  Any rating can be revised upward or downward or withdrawn at anytime by a rating agency if it decides that the circumstances warrant thechange.  Each rating should be evaluatedindependently of any other rating.

**Capital Requirements**The following table presents IDACORP'sand IPC's expected capital requirements from 2005 through 2007:

 

**2005**

 

**2006-2007**

 

**(millions  of dollars)**

IPC capital expenditures:

 

 

 

 

 

 

Construction Expenditures (excluding AFDC):

 

 

 

 

 

 

 

Generating facilities:

 

 

 

 

 

 

 

 

Hydroelectric

$

15

 

$

48

 

 

 

Thermal

 

41

 

 

138

 

 

 

 

Total generating facilities

 

56

 

 

186

 

 

Transmission lines and substations

 

55

 

 

115

 

 

Distribution lines and substations

 

64

 

 

118

 

 

General

 

27

 

 

51

 

 

 

Total construction expenditures (excluding AFDC)

 

202

 

 

470

 

Long-term debt maturities

 

60

 

 

81

 

Other

 

5

 

 

7

 

 

Total IPC 

 

267

 

 

558

 

 

 

 

 

 

IFS investments

 

31

 

 

51

IFS long-term debt maturities

 

19

 

 

30

Other

 

11

 

 

21

 

Total IDACORP

$

328

 

$

660

 

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

Internalcash generation after dividends is expected to provide less than the fullamount of total capital requirements for 2005 through 2007.  The contribution from internal cashgeneration is dependent primarily upon IPC's cash flows from operations, whichare subject to risks and uncertainties relating to weather and water conditionsand IPC's ability to obtain rate relief to cover its operating costs.  IDACORP's internally generated cash after dividendsis expected to provide 67 percent of 2005 capital requirements, where capitalrequirements are defined as utility construction expenditures, excluding AFDC,plus other regulated and non-regulated investments.  This excludes mandatory or optional principal payments on debtobligations.  IPC's constructionexpenditures represent 81 percent of these capital requirements.  IDACORP and IPC expect to continue financingthe utility construction program and other capital requirements with internallygenerated funds and with increased reliance on externally financed capital.

**UtilityConstruction Program**: IPC's construction expenditures were $190million in 2004, $148 million in 2003 and $128 million in 2002.  Aging facilities, relicensing costs andprojected load growth are expected to increase construction expenditures overthe 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, which iscurrently estimated to cost $61 million, $48 million of which had been incurredas of December 31, 2004.  This powerplant is discussed in more detail later in the MD&A in "RegulatoryIssues."

IPCfiled its 2004 IRP with the IPUC and the OPUC in August 2004.  The 2004 IRP includes several elementsrequiring significant capital expenditures in the future.  Two of these projects are included in the2005-2007 utility capital expenditure forecast: (1) $79 million of constructioncosts for a 160 MW combustion turbine peaking resource expected to beoperational in mid-2007; and (2) $2 million of planning costs for a $532million 500 MW coal-fired plant expected to be operational in 2011.

Additionalgeneration needs identified in the 2004 IRP are expected to be met viapurchased power agreements.  Theseagreements are projected to be $7 million (19 average MW) in 2006 and $23million (60 average MW) in 2007.  IPChas also issued an RFP for purchased power agreements for 200 MW ofwind-powered generation, which is not included in the capital expenditureforecast.

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

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

IPC'saging hydroelectric facilities require continuing upgrades and componentreplacement.  In addition, costs relatedto relicensing hydroelectric facilities are expected to increasesubstantially.  The three-yearconstruction program anticipates $21 million of upgrades to existinghydroelectric facilities and $42 million of costs associated with relicensingof hydroelectric facilities.

Basedupon present environmental laws and regulations, IPC estimates its 2005 capitalexpenditures for environmental matters, excluding AFDC, will total $18million.  Studies and measures relatedto environmental concerns at IPC's hydroelectric facilities account for $12million and investments in environmental equipment and facilities at thethermal plants account for $6 million. From 2006 through 2007, environmental-related capital expenditures,excluding AFDC, are estimated to be $40 million.  Anticipated expenses related to IPC's hydroelectric facilitiesaccount for $30 million and thermal plant expenses are expected to total $10million.

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

**FinancingPrograms**IDACORP's consolidated capital structure consisted of common equityof 48 percent and debt of 52 percent at December 31, 2004.

**Credit facilities:**  On March 17, 2004, IDACORP entered into a$150 million three-year credit agreement with various lenders, Bank One, NA(merged with JPMorgan Chase & Co. on July 1, 2004), as co-lead arranger andadministrative agent and Wachovia Bank, National Association, as co-leadarranger and syndication agent (IDACORP Facility).  The IDACORP Facility replaced IDACORP's two credit agreements, a$175 million facility that expired on March 17, 2004 and a $140 millionfacility that was to expire on March 25, 2005. The IDACORP Facility, which will be used for general corporate purposesand commercial paper back-up, will terminate on March 16, 2007.  The IDACORP facility provides for theissuance of loans and standby letters of credit not to exceed the aggregateprincipal amount of $150 million, provided that the aggregate amount of thestandby letters of credit may not exceed $75 million.  At December 31, 2004, no loans were outstanding and $35 millionof commercial paper was outstanding.

Under the terms of the IDACORPFacility, IDACORP may borrow floating rate advances and eurodollar rateadvances.  The floating rate is equal tothe higher of (i) the prime rate announced by Bank One or its parent and (ii)the sum of the federal funds effective rate for such day plus 1/2 percent per annum,plus, in each case, an applicable margin. The eurodollar rate is based upon the British Bankers' Associationinterest settlement rate for deposits in U.S. dollars, as adjusted by theapplicable reserve requirement for eurocurrency liabilities imposed underRegulation D of the Board of Governors of the Federal Reserve System, forperiods of one, two, three or six months plus the applicable margin.  The applicable margin is based on IDACORP'srating for senior unsecured long-term debt securities without third-partycredit enhancement as provided by Moody's and S&P.  The applicable margin for the floating rateadvances is zero percent unless IDACORP's rating falls below Baa3 from Moody'sor BBB- from S&P, at which time it would equal 0.50 percent.  The applicable margin for eurodollar rateadvances ranges from 0.54 percent to 1.65 percent depending upon the creditrating.  At December 31, 2004, theapplicable margin was zero percent for floating rate advances and 1.05 percentfor eurodollar rate advances.  Afacility fee, payable quarterly by IDACORP, is calculated on the average dailyaggregate commitment of the lenders under the IDACORP Facility and is alsobased on IDACORP's rating from Moody's or S&P as indicated above.  At December 31, 2004, the facility fee was0.20 percent.

In connection with the issuanceof letters of credit, IDACORP must pay (i) a fee equal to the applicable marginfor eurodollar rate advances on the average daily undrawn stated amount undersuch letters of credit, payable quarterly in arrears, (ii) a fronting fee in anamount agreed upon with the letter of credit issuer, payable quarterly inarrears and (iii) documentary and processing charges in accordance with theletter of credit issuer's standard schedule for such charges.

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

The events of default under theIDACORP Facility include (i) nonpayment of principal when due and nonpayment ofinterest or other fees within five days after becoming due, (ii) materiallyfalse representations or warranties made on behalf of IDACORP or any of itssubsidiaries on the date as of which made, (iii) breach of covenants, subjectin some instances to grace periods, (iv) voluntary and involuntary bankruptcyof IDACORP or any material subsidiary, (v) the non-consensual appointment of areceiver or similar official for IDACORP or any of its material subsidiaries orany substantial portion (as defined in the IDACORP Facility) of its property,(vi) condemnation of all or any substantial portion of the property of IDACORPor its subsidiaries, (vii) default in the payment of indebtedness in excess of$25 million or a default by IDACORP or any of its subsidiaries under anyagreement under which such debt was created or governed which will cause orpermit the acceleration of such debt or if any of such debt is declared to bedue and payable prior to its stated maturity, (viii) IDACORP or any of itssubsidiaries not paying, or admitting in writing its inability to pay, itsdebts as they become due, (ix) the acquisition by any person or two or morepersons acting in concert of beneficial ownership (within the meaning of Rule13d-3 of the Securities Exchange Act of 1934) of 20 percent or more of theoutstanding shares of voting stock of IDACORP, (x) the failure of IDACORP toown free and clear of all liens, at least 80 percent of the outstanding sharesof voting stock of IPC on a fully diluted basis, (xi) certain liabilities underthe Employee Retirement Income Security Act of 1974 exceeding $25 million and(xii) IDACORP or any subsidiary being subject to any proceeding orinvestigation pertaining to the release of any toxic or hazardous waste orsubstance into the environment or any violation of any environmental law (asdefined in the IDACORP Facility) which could reasonably be expected to have amaterial adverse effect (as defined in the IDACORP Facility).  A default or an acceleration of indebtednessof IPC under the IPC Facility described below will result in a cross defaultunder the IDACORP Facility, provided that such indebtedness is equal to atleast $25 million.

Upon any event of defaultrelating to the voluntary or involuntary bankruptcy of IDACORP or theappointment of a receiver, the obligations of the lenders to make loans underthe facility and of the letter of credit issuer to issue letters of credit willautomatically terminate and all unpaid obligations will become due andpayable.  Upon any other event ofdefault, the lenders holding 51 percent of the outstanding loans or 51 percentof the aggregate commitments (required lenders) or the administrative agent withthe consent of the required lenders may terminate or suspend the obligations ofthe lenders to make loans under the facility and of the letter of credit issuerto issue letters of credit under the facility or declare the obligations to bedue and payable.  IDACORP will also berequired to deposit into a collateral account an amount equal to the aggregateundrawn stated amount under all outstanding letters of credit and the aggregateunpaid reimbursement obligations thereunder.

On March 17, 2004, IPC enteredinto a $200 million three-year credit agreement with various lenders, Bank One,NA (merged with JPMorgan Chase & Co. on July 1, 2004), as co-lead arrangerand administrative agent and Wachovia Bank, National Association, as co-leadarranger and syndication agent (IPC Facility). The IPC Facility replaced IPC's $200 million credit agreement, whichexpired on March 17, 2004.  The IPCFacility, which expires on March 16, 2007, will be used for general corporatepurposes and commercial paper back-up. At December 31, 2004, no loans or commercial paper wereoutstanding.  Under the terms of the IPCFacility, IPC may borrow floating rate advances and eurodollar rateadvances.  The methods of calculatingthe floating rate and the eurodollar rate are the same as set forth above forthe IDACORP Facility.  The applicablemargin for the IPC Facility is also dependent upon IPC's rating for seniorunsecured long-term debt securities without third-party credit enhancement asprovided by Moody's and S&P.  AtDecember 31, 2004, the applicable margin for the IPC Facility was zero percentfor floating rate advances and 1.05 percent for eurodollar rate advances.  A facility fee, payable quarterly by IPC, iscalculated on the average daily aggregate commitment of the lenders under theIPC Facility and is also based on IPC's rating from Moody's or S&P asindicated above.  At December 31, 2004,the facility fee was 0.20 percent.  Aratings downgrade would result in an increase in the cost of borrowing, butwould not result in any default or acceleration of the debt under the IPCFacility.

The events of default under theIPC Facility are the same as under the IDACORP Facility.

Uponany event of default relating to the voluntary or involuntary bankruptcy of IPCor the appointment of a receiver, the obligations of the lenders to make loansunder the facility will automatically terminate and all unpaid obligations ofIPC will become due and payable.  Uponany other event of default, the required lenders (or the administrative agent withthe consent of the required lenders) may terminate or suspend the obligation ofthe lenders to make loans under the IPC Facility or declare IPC's unpaidobligations to be due and payable.

Eachcredit facility contains a material adverse change clause as part of therepresentations and warranties relating to each credit extension.

IDACORPand IPC are exploring the option of extending the life of their creditfacilities to take advantage of the current favorable bank market conditions.

**DebtCovenants:**  The IPC Facilityand the IDACORP Facility each contain a covenant requiring IPC and IDACORP,respectively, to maintain a leverage ratio of consolidated indebtedness toconsolidated total capitalization of no more than 65 percent as of the end ofeach fiscal quarter.  At December 31,2004, the leverage ratios for both IPC and IDACORP were 52 percent.

Other covenants in the IPCFacility include (i) prohibitions against investments and acquisitions by IPCor any subsidiary without the consent of the required lenders, subject toexclusions for investments in cash equivalents or securities of IPC,investments by IPC and its subsidiaries in any business trust controlled,directly or indirectly, by IPC to the extent such business trust purchasessecurities of IPC, investments and acquisitions related to the energy businessof IPC and its subsidiaries not exceeding $500 million in the aggregate at anyone time outstanding, investments by IPC or a subsidiary in connection with apermitted receivables securitization (as defined in the IPC Facility), (ii) prohibitionsagainst IPC or any material subsidiary merging or consolidating with any otherperson or selling or disposing of all or substantially all of its property toanother person without the consent of the required lenders, subject toexclusions for mergers into or dispositions to IPC or a wholly owned subsidiaryand dispositions in connection with a permitted receivables securitization,(iii) restrictions on the creation of liens by IPC or any material subsidiaryand (iv) prohibitions on any material subsidiary entering into any agreementrestricting its ability to declare or pay dividends to IPC except pursuant to apermitted receivables securitization. At December 31, 2004, IPC was in compliance with all of the covenants ofthe facility.

Other covenants in the IDACORPFacility include (i) prohibitions against investments and acquisitions byIDACORP or any subsidiary without the consent of the required lenders subjectto exclusions for investments in cash equivalents or securities of IDACORP,investments by IDACORP and its subsidiaries in any business trust controlled,directly or indirectly, by IDACORP to the extent such business trust purchasessecurities of IDACORP, investments and acquisitions related to the energybusiness or other business of IDACORP and its subsidiaries not exceeding $500million in the aggregate at any one time outstanding (provided that investmentsin non-energy related businesses not exceed $150 million), investments byIDACORP or a subsidiary in connection with a permitted receivablessecuritization (as defined in the IDACORP Facility), (ii) prohibitions againstIDACORP or any material subsidiary merging or consolidating with any otherperson or selling or disposing of all or substantially all of its property toanother person without the consent of the required lenders, subject toexclusions for mergers into or dispositions to IDACORP or a wholly ownedsubsidiary and dispositions in connection with a permitted receivablessecuritization, (iii) restrictions on the creation of liens by IDACORP or anymaterial subsidiary and (iv) prohibitions on any material subsidiary enteringinto any agreement restricting its ability to declare or pay dividends toIDACORP except pursuant to a permitted receivables securitization.

IDACORPis also required to maintain an interest coverage ratio of Credit AgreementEBITDA to consolidated interest charges equal to at least 2.75 to 1.00 as ofthe end of any fiscal quarter.  CreditAgreement EBITDA is a financial measure that is used in the IDACORP Facilityand is not a defined term under GAAP. Credit Agreement EBITDA differs from the term "EBITDA"(earnings before interest expense, income tax expense and depreciation andamortization) as it is commonly used. Credit Agreement EBITDA is defined as consolidated net income plusinterest charges, income taxes, depreciation and all non-cash items that reducesuch consolidated net income minus all non-cash items that increaseconsolidated net income.  At December 31,2004, IDACORP was in compliance with all of the covenants of the facility.

**Long-termfinancings:**  On December 15,2004, IDACORP issued 4,025,000 shares of its common stock at $30 pershare.  After expenses, IDACORP receivedapproximately $116 million.  Theseproceeds were used to make a capital contribution to IPC and to pay downshort-term borrowings at both companies. IDACORP currently has $679 million remaining on two shelf registrationstatements that can be used for the issuance of unsecured debt (includingmedium-term notes) and preferred or common stock.  IPC currently has in place two registration statements that canbe used for the issuance of an aggregate principal amount of $300 million offirst mortgage bonds (including medium-term notes) and unsecured debt.

SeeNote 5 to IDACORP's Consolidated Financial Statements for more informationregarding long-term financings.

**LEGAL AND ENVIRONMENTAL ISSUES:**

**Legal and Other Proceedings********Alves Dairy:**  On May 18, 2004, Herculano and FrancesAlves, dairy operators from Twin Falls, Idaho, brought suit against IPC inIdaho State District Court, Fifth Judicial District, Twin Falls County.  The plaintiffs seek unspecified monetarydamages for negligence and nuisance (allegedly allowing electrical current to flowin the earth, injuring the plaintiffs' right to use and enjoy their propertyand adversely affecting their dairy herd). On July 16, 2004, IPC filed an answer to Mr. and Mrs. Alves' complaint,denying all liability to the plaintiffs, and asserting certain affirmativedefenses.  The parties have begundiscovery in the case.  No trial datehas been scheduled.  On December 14,2004, IPC filed a motion with the District Court for permission to appeal thecourt's denial of IPC's Motion to Disqualify the trial judge, for cause.  By order dated January 31, 2005, theDistrict Court granted the motion for permissive appeal.  On February 16, 2005, IPC filed a motion forpermissive appeal with the Idaho Supreme Court.  If granted, the Supreme Court will determine whether the DistrictCourt properly refused to disqualify the trial judge for cause.

IPC intends to vigorouslydefend its position in this proceeding and believes this matter, with insurancecoverage, will not have a material adverse effect on its consolidated financialposition, results of operations or cash flows.

**Shareholder Lawsuits:**  On May 26, 2004 and June 22, 2004,respectively, two shareholder lawsuits were filed against IDACORP and certainof its directors and officers.  Thelawsuits, captioned Powell, et al. v. IDACORP, Inc., et al. and Shorthouse, etal. v. IDACORP, Inc., et al., raise largely similar allegations.  The lawsuits are putative class actionsbrought on behalf of purchasers of IDACORP stock between February 1, 2002 andJune 4, 2002, and were filed in the United States District Court for theDistrict of Idaho.  The named defendantsin each suit, in addition to IDACORP, are Jon H. Miller, Jan B. Packwood, J.LaMont Keen and Darrel T. Anderson.

The complaints alleged that,during the purported class period, IDACORP and/or certain of its officersand/or directors made materially false and misleading statements or omissionsabout the company's financial outlook in violation of Sections 10(b) and 20(a)of the Securities Exchange Act of 1934, as amended, and Rule 10b-5, thereby causinginvestors to purchase the company's common stock at artificially inflatedprices.  More specifically, thecomplaints alleged that IDACORP failed to disclose and misrepresented thefollowing material adverse facts which were known to defendants or recklesslydisregarded by them: (1) IDACORP failed to appreciate the negative impact thatlower volatility and reduced pricing spreads in the western wholesale energymarket would have on its marketing subsidiary, IE; (2) IDACORP would be forcedto limit its origination activities to shorter-term transactions due toincreasing regulatory uncertainty and continued deterioration of creditworthycounterparties; (3) IDACORP failed to discount for the fact that IPC may notrecover from the lingering effects of the prior year's regional drought and (4)as a result of the foregoing, defendants lacked a reasonable basis for theirpositive statements about IDACORP and their earnings projections.  The Powell complaint also alleged that thedefendants' conduct artificially inflated the price of the company's commonstock.  The actions sought anunspecified amount of damages, as well as other forms of relief.  By order dated August 31, 2004, the courtconsolidated the Powell and Shorthouse cases for pretrial purposes, and orderedthe plaintiffs to file a consolidated complaint within 60 days.  On November 1, 2004, IDACORP and thedirectors and officers named above were served with a purported consolidatedcomplaint captioned Powell et al. v. IDACORP, Inc. et al., which was filed inthe United States District Court for the District of Idaho.

The new complaint alleges thatduring the class period IDACORP and/or certain of its officers and/or directorsmade materially false and misleading statements or omissions about its businessoperations, and specifically the IDACORP Energy financial outlook, in violationof Rule 10b-5, thereby causing investors to purchase IDACORP's common stock atartificially inflated prices.  The newcomplaint alleges that IDACORP failed to disclose and misrepresented thefollowing material adverse facts which were known to it or recklesslydisregarded by it: (1) IDACORP falsely inflated the value of energy contractsheld by IDACORP Energy in order to report higher revenues and profits; (2)IDACORP permitted IPC to inappropriately grant native load priority for certainenergy transactions to IDACORP Energy; (3) IDACORP failed to file 13 ancillaryservice agreements involving the sale of power for resale in interstatecommerce that it was required to file under Section 205 of the Federal PowerAct; (4) IDACORP failed to file 1,182 contracts that IPC assigned to IDACORPEnergy for the sale of power for resale in interstate commerce that IPC wasrequired to file under Section 203 of the Federal Power Act; (5) IDACORP failedto ensure that IDACORP Energy provided appropriate compensation from IDACORPEnergy to IPC for certain affiliated energy transactions; and (6) IDACORPpermitted inappropriate sharing of certain energy pricing and transmissioninformation between IPC and IDACORP Energy. These activities allegedly allowed IDACORP Energy to maintain a falseperception of continued growth that inflated its earnings.  In addition, the new complaint alleges thatthose earnings press releases, earnings release conference calls, analystreports and revised earnings guidance releases issued during the class periodwere false and misleading.  The actionseeks an unspecified amount of damages, as well as other forms of relief.  IDACORP and the other defendants filed a consolidatedmotion to dismiss on February 9, 2005, which is now pending.

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

**PublicUtility District No. 1 of Grays Harbor County, Washington:**  On October 15, 2002, Public Utility DistrictNo. 1 of Grays Harbor County, Washington (Grays Harbor) filed a lawsuit in theSuperior Court of the State of Washington, for the County of Grays Harbor,against IDACORP, IPC and IE.  On March9, 2001, Grays Harbor entered into a 20 MW purchase transaction with IPC forthe purchase of electric power from October 1, 2001 through March 31, 2002, ata rate 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 this action removed from the state court to the U.S. DistrictCourt for the Western District of Washington at Tacoma.  On November 12, 2002, the companies filed amotion to dismiss Grays Harbor's complaint, asserting that the U.S. DistrictCourt lacked jurisdiction because the FERC has exclusive jurisdiction overwholesale power transactions and thus the matter is preempted under the FederalPower Act 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 U.S. Courtof Appeals for the Ninth Circuit.  OnAugust 10, 2004, the Ninth Circuit affirmed the dismissal of Grays Harbor'scomplaint, finding that Grays Harbor's claims were preempted by federal law andwere barred by the filed-rate doctrine. The court also remanded the case to allow Grays Harbor leave to amendits complaint to seek declaratory relief only as to contract formation, andheld that Grays Harbor could seek monetary relief, if at all, only from theFERC, and not from the courts.  IDACORP,IPC and IE sought rehearing from the Ninth Circuit arguing that the court erredin granting leave to amend the complaint as such a declaratory relief claimwould be preempted and would be barred by the filed-rate doctrine.  The Ninth Circuit denied the rehearingrequest on October 25, 2004 and the decision became final on November 12,2004.  On that same date, the companiestook steps to have the case transferred and consolidated with other similarcases arising out the California energy crisis currently pending before theHonorable Robert H. Whaley, sitting by designation in the Southern District ofCalifornia and presiding over Multidistrict Litigation Docket No. 1405,regarding California Wholesale Electricity Antitrust Litigation.  On November 18, 2004, Grays Harbor filed anamended complaint alleging that the contract was formed under circumstances of"mistake" as to an "artificial . . . power shortage."  Grays Harbor asks that the contracttherefore be declared "unenforceable" and found "unconscionable."  On December 23, 2004, the Judicial Panel onMultidistrict Litigation conditionally transferred the case to JudgeWhaley.  Grays Harbor is opposingtransfer, however, and the Judicial Panel on Multidistrict Litigation has yetto finally rule on the transfer. IDACORP, IE and IPC have not responded to the amended complaint as a responseis not yet required.  The companies planto file a motion to dismiss the complaint. The companies intend to vigorously defend their position on remand 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 U.S. DistrictCourt for the Western District of Washington at Seattle.  The Port of Seattle's complaint allegesfraud and violations of state and federal antitrust laws and the RacketeerInfluenced and Corrupt Organizations Act. On December 4, 2003, the Judicial Panel on Multidistrict Litigation transferredthe case to the Southern District of California for inclusion with severalsimilar multidistrict actions currently pending before the Honorable Robert H.Whaley.

All defendants, including IPC and IDACORP, moved to dismiss thecomplaint in lieu of answering it.  Themotions were based on the ground that the complaint seeks to set alternativeelectrical rates, which are exclusively within the jurisdiction of the FERC andare barred by the filed-rate doctrine. A hearing on the motion to dismiss was heard on March 26, 2004.  On May 28, 2004, the court granted IPC andIDACORP's motion to dismiss.  In June2004, the Port of Seattle appealed the court's decision to the U.S. Court of Appeals for the Ninth Circuit.  The appeal has beenfully briefed, however no date has been set for oral argument.  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.

**Wah Chang: **On May 5, 2004, WahChang, a division of TDY Industries, Inc., filed two lawsuits in the UnitedStates District Court for the District of Oregon against numerousdefendants.  IDACORP, IE and IPC arenamed as defendants in one of the lawsuits. The complaints allege violations of federal antitrust laws, violationsof the Racketeer Influenced and Corrupt Organizations Act, violations of Oregonantitrust laws and wrongful interference with contracts.  Wah Chang's complaint is based onallegations relating to the western energy situation.  These allegations include bid rigging, falsely creatingcongestion and misrepresenting the source and destination of energy.  The plaintiff seeks compensatory damages of$30 million and treble damages.

On September 8, 2004, this case was transferred and consolidatedwith other similar cases currently pending before the Honorable Robert H.Whaley, sitting by designation in the Southern District of California andpresiding over Multidistrict Litigation Docket No. 1405, regarding CaliforniaWholesale Electricity Antitrust Litigation. IDACORP, IE and IPC have not answered the complaint, as a response is not yet required.  The companies, along with the otherdefendants, subsequently filed a motion to dismiss the complaint, which was heard on January 20, 2005.  By order dated February 11, 2005, the court granted thecompanies' and other defendants' motion to dismiss.  The companies intend to vigorously defend their positionin this proceeding and believe these matters will not have a material adverseeffect on their consolidated financial positions, results of operations or cashflows.

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

On September 8, 2004, this case was transferred and consolidatedwith other similar cases currently pending before the Honorable Robert H.Whaley, sitting by designation in the Southern District of California andpresiding over Multidistrict Litigation Docket No. 1405, regarding CaliforniaWholesale Electricity Antitrust Litigation. IDACORP, IE and IPC have not answered the complaint, as a response isnot yet required.  Thecompanies, along with the other defendants, filed a motion to dismiss thecomplaint which was taken under submission by the court, without oralargument.  By order dated February11, 2005, the court granted the companies' and other defendants' motion todismiss.  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.

**WesternEnergy Proceedings at the FERC: **IE andIPC are involved in a number of FERC proceedings arising out of the westernenergy situation and claims that dysfunctions in the organized Californiamarkets contributed to or caused unjust and unreasonable prices in PacificNorthwest spot markets, and may have been the result of manipulations of gas orelectric power markets.  They includeproceedings involving: (1) the chargeback provisions of the California PowerExchange (CalPX) participation agreement, which was triggered when aparticipant defaulted on a payment to the CalPX.  Upon such a default, other participants were required to pay theirallocated share of the default amount to the CalPX.  This provision was first triggered by the Southern CaliforniaEdison default and later by the Pacific Gas and Electric Company default.  The FERC ordered the CalPX to rescind allchargeback actions related to the Southern California Edison and Pacific Gasand Electric Company liabilities.  TheCalPX is awaiting further orders from the FERC and bankruptcy court beforedistributing the funds it collected under the chargeback mechanism; (2) effortsby the State of California to obtain refunds for a portion of the spot marketsales prices from sellers of electricity into California from October 2, 2000through June 20, 2001.  California isclaiming that the prices were not just and reasonable and were not incompliance with the Federal Power Act.  TheFERC issued an order on refund liability on March 26, 2003 which multipleparties, including IE, sought rehearing on. On October 16, 2003, the FERC denied the requests for rehearing andrequired the California Independent System Operator (Cal ISO) to make acompliance filing regarding refund amounts within five months, which has sincebeen delayed until at least April 2005. On May 12, 2004, the FERC issued an order clarifying its earlier refundorders and denying a request by certain parties to present as evidence anearlier settlement between the California Public Utilities Commission and ElPaso related to manipulation of gas pipeline capacity claiming that thesettlement dollars California is receiving from El Paso ($1.69 billion) areduplicative of the FERC order changing the gas component of its refundmethodology.  The FERC denied requestsfor rehearing on November 23, 2004.   OnDecember 2, 2003, IE and others petitioned the United States Court of Appealsfor the Ninth Circuit for review of the FERC's orders on Californiarefunds.  As additional FERC orders havebeen issued, further petitions for review have been filed, including by IE, andhave been consolidated with the appeals already pending before the NinthCircuit.  On September 21, 2004, theNinth Circuit convened the first of its case management proceedings, aprocedure reserved to help organize complex cases.  On October 22, the Ninth Circuit severed several issues relatedto FERC's refund jurisdiction and established a schedule for briefing and oralargument.  At December 31, 2004, withrespect to the CalPX chargeback and the California Refund proceedings discussedabove, the CalPX and the Cal ISO owed $14 million and $30 million,respectively, for energy sales made to them by IPC in November and December2000.  IE has accrued a reserve of $42million against these receivables.  Thisreserve was calculated taking into account the uncertainty of collection, giventhe California energy situation.  Basedon the reserve recorded as of December 31, 2004, IDACORP believes that thefuture collectibility of these receivables or any potential refunds ordered bythe FERC would not have a material adverse effect on its consolidated financialposition, results of operations or cash flows; (3) the Pacific Northwest refundproceedings wherein it was argued that the spot market in the Pacific Northwestwas affected by the dysfunction in the California market, warrantingrefunds.  The FERC rejected this claimon June 25, 2003 and denied rehearing on November 11, 2003 and February 9,2004.  The FERC orders were appealed tothe Ninth Circuit.  On July 21, 2004,the City of Seattle petitioned the Ninth Circuit requesting the court to directthe FERC to permit additional evidence consisting of audiotapes of Enron traderconversations and a delay in the briefing schedule in the Pacific Northwestrefund.  On August 2, 2004, the NinthCircuit held the briefing schedule in abeyance pending resolution of the motionto offer additional evidence.  On August2, 2004 and August 3, 2004, respectively, the FERC and a group of parties,including IE, filed their answers in opposition to the motion to offeradditional evidence.  On September 29,2004, the Ninth Circuit denied the City of Seattle's motion without prejudiceto renew the request in briefing in the Pacific Northwest Refund case andestablished a briefing schedule with final briefs due in July of 2005.  IE and IPC are unable to predict the outcomeof these matters; and (4) two FERC show cause orders which resulted from aruling of the Ninth Circuit that the FERC permit the California parties in theCalifornia refund proceeding to submit materials to the FERC demonstratingmarket manipulation by various sellers of electricity into California.  On June 25, 2003, the FERC ordered a largenumber of parties including IPC to show cause why certain trading practices didnot constitute gaming ("gaming") or anomalous market behavior  ("partnership") in violation ofthe Cal ISO and CalPX Tariffs.  OnOctober 16, 2003, IPC reached agreement with the FERC Staff on the show causeorders.  The "gaming"settlement was approved 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 scopeof the show cause proceedings are presently the subject of review petitions inthe Ninth Circuit, the order dismissing IPC from the "partnership"proceedings was not the subject of rehearing requests.  Eight parties have requested rehearing ofthe FERC's March 3, 2004 order approving the "gaming" settlement butthe FERC has not yet acted on those requests.

On July 21, 2004, Californiansfor Renewable Energy filed a motion with the FERC in connection with theCalifornia refund, the Pacific Northwest refund and the market manipulationcases requesting the FERC to revise its approach to the 2000-2001 westernenergy situation by (1) revoking market-based rate authority and replacing itwith cost-of-service rates and requiring refunds back to the date of the ordergranting the market-based rate authority, (2) revising long-term contractsentered into during the western energy situation and (3) deferring new andrejecting existing refund settlements. On September 9, 2004, Californians for Renewable Energy filed a motionto withdraw its July 21, 2004 pleading. By operation of law, the withdrawal was effective September 24, 2004.

These matters are discussed inmore detail in Note 8 to IDACORP'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 theseproceedings.  The companies believe thattheir reserves are adequate for these matters.

**OtherLegal IssuesIdaho Power Company Transmission Line Rights-of-Way Across Fort Hall IndianReservation: **IPC hasmultiple transmission lines that cross the Shoshone-Bannock Tribes' Fort HallIndian Reservation near the city of Pocatello in southeastern Idaho.  IPC has been working since 1996 to renewfour of the right-of-way permits (for five of the transmission lines), whichhave stated permit expiration dates between 1996 and 2003.  IPC filed applications with the U.S. Departmentof the Interior, Bureau of Indian Affairs, to renew the four rights-of-way for25 years, 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).  Due to the lack ofdefinitive legal guidelines for valuation of the permit renewals, IPC is in theprocess of negotiating mutually acceptable renewal terms with the tribes andallottees.  The parties are pursuing apossible 23-year renewal of the permits (including all pre-renewal periods) fora total payment of approximately $7 million to the tribes and allottees.  IPC, the tribes and the Bureau of IndianAffairs are currently working through the process of finalizing the agreement,including obtaining the requisite consents from the allottees.  The parties hope to obtain the requiredconsents early in 2005.  On December 27,2004, IPC filed an application with the IPUC seeking an accounting orderregarding the treatment of this transaction. On February 28, 2005, the IPUC issued an order approving IPC'sapplication.

**Environmental IssuesIdaho Water Management Issues:**IPC holds water rights forgeneration purposes at each of its hydroelectric projects.  The state of Idaho is experiencing its sixthconsecutive year of below normal precipitation and stream flows.  These conditions have exacerbated adeveloping water shortage in the state, which is manifested by a number ofwater issues that are of interest to IPC because of their potential impacts ongeneration at IPC's hydroelectric projects including - declining Snake Riverbase flows and recharge to the Eastern Snake Plain Aquifer, a large undergroundaquifer that has been estimated to hold between 200-300 million acre-feet ofwater.  With respect to base flows,observed records suggest that the base flows in the Snake River, particularlybetween IPC's Twin Falls and Swan Falls projects, have been in decline forseveral decades.  The yearly averageflow measured below Swan Falls declined at an average rate of 43 cubic feet persecond (cfs) per year during the period 1961-2003, and observed stream flowgains between Twin Falls and Lower Salmon Falls, which are largely attributedto base flow contribution, declined at a rate of 27 cfs/year over the sameperiod.  Low flow in the Snake Rivernear Hagerman, Idaho continues to be observed - several river gauges in thatarea are recording the lowest Snake River flows since the early 1960s.  Regarding aquifer recharge, the Snake River,at various places throughout its reach from Rexburg, Idaho to King Hill, Idaho,is connected to the Eastern Snake Plain Aquifer.  In certain times of the year, the flows into the Snake Riverbelow Milner Dam are heavily dependent on the outflow from springs that areconnected to and fed by the Eastern Snake Plain Aquifer in the Thousand Springsreach of the Snake River.  The majorityof IPC's hydroelectric projects are below Milner Dam.

Ground water irrigators andsurface water irrigators in southern Idaho are involved in a conflict regardingshortages of irrigation water.  One solutionthat has been offered is aquifer recharge, or using surface water supplies toincrease ground water supplies by allowing the water to sink into the earth inporous locations.  IPC believes thissolution will impact its senior water rights and therefore conflicts with statelaw and will likely reduce the amount of water available for generation inIPC's hydroelectric plants.

In August 2001, the IdahoDepartment of Water Resources designated portions of the Eastern Snake PlainAquifer that are tributary to the Thousand Springs reach of the Snake River asa Ground Water Management Area due to the effect, exacerbated by several yearsof drought, of junior priority ground water withdrawals on senior surface waterrights.  Subsequently, in late 2001 andearly 2002, junior ground water interests entered into a stipulated agreementwith certain affected senior surface water users in an effort to mitigate theeffects of ground water pumping.  TheIdaho Department of Water Resources established two ground water districts tofacilitate the operation of the agreement. However, in 2003, surface water users that were not parties to thestipulated agreement filed delivery calls with the Idaho Department of WaterResources, demanding that it manage ground water withdrawals pursuant to theprior appropriation doctrine of "first in time is first in right" andcurtail junior ground water rights that are depleting the aquifer and affectingflows to senior surface water rights. These delivery calls resulted in several administrative actions beforethe Idaho Department of Water Resources and a judicial action before the StateDistrict Court in Ada County, Idaho. Because IPC holds water rights in the Thousand Springs area that aredependent on spring flows and the overall condition of the Eastern Snake PlainAquifer, IPC intervened in these actions to protect its interests and encouragethe development of a long-term management plan that will protect the aquiferfrom further depletion.

In March 2004, the State ofIdaho negotiated an interim agreement between various ground and surface waterusers in an effort to allow the state to develop short and long-term goals andobjectives for effectively managing the Eastern Snake Plain Aquifer andensuring that senior water rights are protected consistent with the priorappropriation doctrine and state law. As part of the interim agreement, the pending administrative andjudicial processes are stayed until March 15, 2005 and the Idaho Legislaturedirected the Natural Resources Interim Committee, a standing committee, to meetand evaluate ways to stabilize and properly manage the aquifer.  This Interim Committee has been meeting withinterested parties since March of 2004 in an effort to resolve the pendingcontroversies.  IPC is participating inthat process as necessary to protect its existing hydroelectric generationwater rights.

On January 14, 2005, sevensurface water irrigation entities from above Milner Dam that are not parties tothe March 2004 interim agreement submitted a delivery call letter to theDirector of the Idaho Department of Water Resources requesting that theDirector administer and deliver their senior natural flow and storage waterrights pursuant to Idaho law.  Theirrigation entities contend that existing data reflects that senior surfacewater rights above Milner Dam have been reduced by approximately 600,000acre-feet, a 30 percent reduction, over the past six years due, in part, tojunior groundwater pumping from the Eastern Snake Plain Aquifer and that thesereductions have resulted in cumulative shortages in natural flow and storagewater accrual in American Falls Reservoir, a U.S. Bureau of Reclamationreservoir that supplies a portion of their senior water rights.  These same entities also filed a petition withthe Idaho Department of Water Resources for water rights administration anddesignation of the Eastern Snake Plain Aquifer as a Ground Water ManagementArea.  On February 3, 2005, the IdahoGround Water Appropriators, Inc., an Idaho non-profit corporation organized topromote and represent the interests of groundwater users, petitioned tointervene in the delivery call action.

On February 14, 2005, theDirector of the Idaho Department of Water Resources issued an interlocutoryorder establishing a contested case under the department's procedural rules inresponse to the delivery call letter. The order granted the Idaho Ground Water Appropriators, Inc.'s petitionto intervene and requested that the surface water irrigation entities supplythe department with additional information relative to their claim for deliveryof water within 30 days of the date of the order.

Similar to the surface waterirrigation entities, IPC holds storage rights in American Falls Reservoir.  To the extent that groundwater pumping andthe reduced surface water flows have impacted American Falls storage waterrights, IPC's storage rights have also been impacted.  As such, IPC submitted a letter to the Idaho Department of WaterResources in support of the delivery call and asked the department to grant IPCintervenor status in the pending contested case.  The Idaho Ground Water Appropriators, Inc. filed a motionopposing IPC's intervention.

**REGULATORY ISSUES:**

**General Rate CaseIdaho**: IPC filed its Idaho general rate case with the IPUC onOctober 16, 2003.  IPC originallyrequested approximately $86 million annually in additional revenue, an average17.7 percent increase to base rates.  Onrebuttal, IPC lowered its overall requested increase to $70 million annually,an average of 14.5 percent.  The IPUCapproved an increase in IPC's electric rates of $25 million, an average of 5.2percent, in an order issued on May 25, 2004. The rate increase became effective on June 1, 2004.

In the order, the IPUC approveda return on equity of 10.25 percent, compared to the 11.2 percent IPCrequested, an overall rate of return of 7.9 percent, compared to the 8.3percent requested by IPC.  The IPUCreduced the $1.55 billion in rate base requested for IPC's Idaho jurisdictionto $1.52 billion.

Additionally, the IPUC approvedhigher rates for residential and small commercial customers during the summermonths to encourage conservation.  The12.6 percent higher summer rate applies to monthly usage over 300 kilowatt-hours.  The IPUC also ordered time-of-use rates tobe phased in for industrial customers, asked IPC to submit a proposal for aconservation program for industrial customers and ordered increased low-incomeweatherization funding of $1 million annually.

The IPUC also noted two otherissues to be addressed in separate proceedings and potentially handled inworkshops instead of formal hearings. These issues are: (1) investigating approaches to removing financialdisincentives to IPC for investing in cost effective energy efficiency andclean distributed generation and (2) investigating various cost of serviceissues raised in the general rate case, including those associated with loadgrowth.  During the year, initialworkshops were held on both issues.

The IPUC disallowed severalcosts in the Idaho general rate case order, including $12 million annuallyrelated to the determination of IPC's income tax expense, $8 million ofincentive payments capitalized in prior years and $1 million of capitalizedpension expense.  On June 15, 2004, IPCfiled with the IPUC a petition for reconsideration of these and otheritems.  On July 13, 2004, the IPUCgranted this petition in part, agreeing to reconsider the issue relating to thedetermination of IPC's income tax expense and, in light of the IPUC Staff'scomputational errors, ordering rates increased by approximately $3 million onor before August 1, 2004. IPC recorded an impairment of assets of $9 millionrelated to the disallowed incentive payments and the disallowed capitalizedpension expenses.

On September 28, 2004, the IPUC issued separateorders approving two Settlement Agreements entered into on August 16, 2004between IPC and the IPUC Staff.

Settlement No. 1, approved bythe IPUC in Order No. 29601, relates to the calculation of IPC's taxes forpurposes of test year income tax expense. In the Idaho general rate case order, the IPUC adopted the use of ahistoric five-year average income tax rate to calculate IPC's income taxexpense.  Settlement No. 1 approved themodification of the general rate case order to utilize IPC's statutory incometax rates to compute test year income tax expense.  As a result, IPC will compute and record monthly during theperiod June 1, 2004 through May 31, 2005 a regulatory asset (with interestaccrued at a rate of one percent per annum) of approximately $12 million.  Rates will increase on June 1, 2005 toreflect the ongoing impact of the tax expense. Approximately $7 million of this amount was recorded in 2004 as otheroperating revenue.  Settlement No. 1allows IPC to continue its compliance with the normalization provisions of theInternal Revenue Code of 1986, as amended, and associated Treasury Regulations,and will allow IPC to continue to receive the benefits of accelerateddepreciation.

Settlement No. 2, approved bythe IPUC in Order No. 29600, resolved outstanding issues related to: (1) anunplanned outage at one of the two units of the Valmy plant in the summer of2003, (2) a matter relating to the expense adjustment rate for growth componentof the PCA and (3) regulatory accounting issues related to a tax accountingmethod change in 2002.  In SettlementNo. 2, IPC and the IPUC Staff agreed that the IPUC will not examine the cost ofreplacement power and a possible PCA adjustment resulting from the Valmy plantoutage, and the expense adjustment rate for growth component of the PCA willcontinue at its existing value until IPC's next general rate case.  In September 2004, as a result of the order,IPC established a regulatory liability of $19 million with a charge to PCAexpense.  A monthly credit ofapproximately $804,000 will be included in the PCA through May 2006, which willreduce this regulatory liability.  Alsoin September 2004, IPC reversed a $16 million regulatory tax liability byreducing income tax expense.  Thisregulatory tax liability was established in 2002 when IPC changed its taxaccounting method for capitalized overhead costs.

The final result of IPC'sgeneral rate case was a $40 million increase to the base Idaho jurisdictionalrevenue requirement, comprised of $25 million in the initial order, $3 millionrelated to computational errors and $12 million in the order approvingSettlement No. 1.

IPC plans to file an Idahogeneral rate case with the IPUC in the fall of 2005, requesting rates to beimplemented on June 1, 2006.  IPC isunable to predict what rate relief, if any, the IPUC will grant.

**Oregon**: On September 21, 2004, IPCfiled an application with the OPUC to increase general rates an average of 17.5percent, approximately $4 million annually. IPC's filing includes a request to introduce summer and non-summer ratessimilar to proposals that were approved in the Idaho general rate case.  IPC has not filed for a change to itsoverall rates in Oregon since 1995.

On October 19, 2004, the OPUC suspended IPC's request fora period of time not to exceed nine months from October 20, 2004 to investigatethe propriety and reasonableness of the request.  A pre-hearing conference and public meeting was held on November18, 2004.  The hearing schedule calledfor a settlement conference, which began on February 14, 2005, and anevidentiary hearing to begin on May 23, 2005. IPC is unable to predict what rate relief, if any, the OPUC will grant.

**Deferred Power Supply Costs**IPC's deferred net power supply costs consisted of the following atDecember 31: 

 

**2004**

 

**2003**

Oregon  deferral

$

12,047

 

$

13,620

Idaho  PCA current year net power supply cost deferrals:

 

 

 

 

 

 

Deferral  for 2004-2005 rate year

 

-

 

 

44,664

 

Deferral  for 2005-2006 rate year

 

22,778

 

 

-

Irrigation  Lost Revenues

 

13,290

 

 

-

Idaho  PCA true-up awaiting recovery:

 

 

 

 

 

 

Remaining  true-up authorized May 2003

 

-

 

 

13,646

 

Remaining  true-up authorized May 2004

 

11,415

 

 

-

 

Total  deferral

$

59,530

 

$

71,930

 

 

 

 

 

 

 

**Idaho**: IPChas a PCA mechanism that provides for annual adjustments to the rates chargedto its Idaho retail customers.  Theseadjustments are based on forecasts of net power supply costs, which are fueland purchased power less off-system sales, and the true-up of the prior year'sforecast.  During the year, 90 percentof the difference between the actual and forecasted costs is deferred withinterest.  The ending balance of thisdeferral, called the true-up for the current year's portion and the true-up ofthe true-up for the prior years' unrecovered portion, is then included in thecalculation of the next year's PCA.

On April 15, 2004, IPC filedits 2004-2005 PCA with the IPUC requesting recovery of $71 million above baserates and a proposed effective date of June 1, 2004.  On May 25, 2004, the IPUC issued Order No. 29506 approving IPC'sfiling with additional instructions for IPC and the IPUC Staff to examine thecost of replacement power attributable to the unplanned outage at the Valmyplant in 2003.  Based on the order approvingSettlement No. 2, discussed above, the IPUC will not examine the costs relatedto this outage.

On May 15, 2003, the IPUCissued Order No. 29243 approving IPC's 2003-2004 PCA filing, with a smalladjustment to the original filing.  Asapproved, IPC's rates were adjusted to collect $81 million above 1993 baserates.

OnApril 15, 2002, the IPUC issued Order No. 28992 disallowing recovery of $12million of lost revenues resulting from the Irrigation Load Reduction Programthat was in place in 2001.  IPC believedthat this IPUC order was inconsistent with Order No. 28699, dated May 25, 2001,that allowed recovery of such costs, and IPC filed a Petition forReconsideration on May 2, 2002.  OnAugust 29, 2002, the IPUC issued Order No. 29103 denying the Petition forReconsideration.  As a result of thisorder, approximately $12 million was expensed in September 2002.  IPC believed it was entitled to recover thisamount and argued its position before the Idaho Supreme Court on December 5,2003.  On March 30, 2004, the IdahoSupreme Court set aside the IPUC denial of the recovery of lost revenues andremanded the matter to the IPUC to determine the amount of lost revenues to berecovered.  On December 29, 2004, the IPUCissued Order No. 29669 allowing IPC to recover $12 million in lost revenues and$2 million in interest.  The recoverywill be included as part of IPC's annual PCA beginning June 1, 2005.

**Oregon**:  On March 2, 2005 IPC file for an accountingorder to defer net power supply costs for the period of March 1, 2005 throughFebruary 28, 2006 in anticipation of the low water conditions IPC is currentlyexperiencing.  The net system powersupply costs included in this filing was $169 million. IPC is proposing to usethe same methodology for this deferral filing that was accepted in 2002 forOregon's share of IPC's 2001 net power supply expenses.

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

**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 bidder for the construction of the BennettMountain Power Plant, a 164 MW gas-fired generating plant near Mountain Home,Idaho.  TR2 contracted with SiemensWestinghouse Power Corporation to furnish all of the labor, equipment andmaterials and to perform all of the engineering and construction of theplant.  The estimated project cost,including plant construction and associated transmission system upgrades, is$61 million.  IPC will take ownership ofthe plant once it is tested and operational.

InJanuary 2004, the IPUC approved IPC's application for a Certificate of PublicConvenience and Necessity, which will allow IPC to place reasonable and prudentcapital costs of the Bennett Mountain Power Plant into its Idaho base rateswhen the plant is operational.  IPC madea rate filing with the IPUC on March 2, 2005 to include the investment ofapproximately $58 million associated with this plant in Idaho retailrates.  IPC requested that these costsbe included in Idaho retail rates effective June 1, 2005.

**Wind Down of Energy Marketing**IDACORPannounced in 2002 that IE would wind down its energy marketing operations.  In connection with the wind down, certainmatters were identified that required resolution with the FERC, the IPUC andthe OPUC.  These matters were resolvedin all three jurisdictions.

**Idaho**:  In an IPUC proceeding thatbegan in May 2001, IPC, the IPUC staff and several interested customer groupsworked to determine the appropriate compensation IE should provide to IPC forcertain transactions between IPC and IE. The IPUC has issued several orders since then regarding thesematters.  Order No. 28852 issued onSeptember 28, 2001 covered the time period prior to February 2001.  Order No. 29026 covered the time period fromMarch 2001 through March 2002.  The IPUCalso approved IPC's ongoing hedging and risk management strategies in Order No.29102 issued on August 28, 2002.  Thisorder formalized IPC's agreement to implement a number of changes to itsexisting practices for managing risk and initiating hedging purchases andsales.  The $5.8 million in benefitsrelated to the FERC settlement were included in the 2003-2004 PCA and credited toIdaho retail customers in accordance with the PCA methodology.  The parties to the proceeding executed asettlement agreement providing that an additional $5.5 million be flowedthrough the PCA mechanism to the Idaho retail customers from April 2003 throughDecember 2005.  This agreement was filedwith the IPUC on February 17, 2004 and approved on March 15, 2004.

**Oregon:**FollowingIPC's settlement with the IPUC on issues related to IPC's past relationshipwith IE, IPC approached the OPUC to settle the issue of fair compensation toOregon customers related to the terminated Electricity Supply ManagementServices Agreement between IPC and IE, as well as any other issues relating totransactions between IPC and IE.  OnOctober 4, 2004, IPC filed a petition with the OPUC requesting an accounting orderapproving a settlement stipulation and authorizing IPC to credit its existingdeferral balance of excess power supply costs. In the proposed settlement, IPC agrees to continue the $7,700 monthlycredit to customers that began in July 2001 through December 2005, and toreduce the existing excess power supply cost deferral balance by a one timecredit of $100,000 on January 1, 2005. The OPUC issued Order No. 04-683 approving this settlement on November22, 2004.

**FMC/Astaris Settlement Agreement**On January 8, 2002, the IPUC initiated an investigation to examinethe load-reduction rates contained in the Voluntary Load Reduction Agreementbetween IPC and FMC/Astaris.  Thisagreement amended the Electric Service Agreement that governed the delivery ofelectric service to FMC/Astaris' Pocatello, Idaho plant, which ceasedoperations late in 2001.  On June 6,2002, IPC and FMC/Astaris signed and filed a proposed Stipulation andSettlement Agreement with the IPUC and on June 10, 2002, the IPUC approved theStipulation and Settlement Agreement in Order No. 29050 which included thefollowing provisions:

TheVoluntary Load Reduction payments that IPC would have made to FMC/Astaristhrough May 2003 were decreased $5 million, reducing IPC's overall payments to$37 million.  Approximately 90 percentof this $5 million reduction flowed through the PCA mechanism as a reduction incosts to Idaho retail 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 ElectricService Agreement.

IPC'sneed to purchase power from the wholesale markets decreased during 2002 due tothe ceased operation of FMC/Astaris' Pocatello, Idaho plant and settlement ofthe above mentioned Electric Service Agreement.

**PublicUtilities Regulatory Policy Act of 1978**As mandated by the enactment of the Public Utilities Regulatory Policy Act of1978 (PURPA) and the adoption of avoided costs standards by the IPUC and theOPUC, IPC has entered into contracts for the purchase of energy from a numberof private developers.  Under thesecontracts, IPC is required to purchase all of the output from the facilitieslocated inside the IPC service territory. For projects located outside the IPC service territory, IPC is requiredto purchase the output that IPC has the ability to receive at the facility'srequested point of delivery on the IPC system. The costs associated with these Idaho jurisdictional contracts are fullyrecovered through the PCA.  For IPUCjurisdictional projects, projects up to ten MW are eligible for IPUC PublishedAvoided Costs for up to a 20-year contract term.  The Published Avoided Cost is a price established by the IPUC andthe OPUC to estimate IPC's cost of developing additional generationresources.  For OPUC jurisdictional projects,projects up to one MW are eligible for OPUC Published Avoided Costs for up to afive-year contract term (automatically renewable at the end of fiveyears).  The costs associated with these Oregonjurisdictional contracts are recovered through general rate case filings.  The Oregon provisions are currently beingreviewed in an OPUC proceeding, as discussed below.  If a PURPA project does not qualify for the Published AvoidedCosts, then IPC is required to negotiate the terms, prices and conditions withthe developer of that project.  Thesenegotiations reflect the characteristics of the individual projects (i.e.,operational flexibility, location and size) and the benefits to the IPC systemand must be consistent with other similar energy alternatives.

Recent activities, includingthe extension of the Federal Production Tax Credit and the expansion of the taxcredit for eligibility to solar, geothermal and other forms of generation,resolution of IPUC and OPUC PURPA-related hearings and the December 1, 2004order by the IPUC increasing the Published Avoided Costs, create a favorableclimate for PURPA project development during 2005, which may require IPC toenter into additional PURPA agreements. The requirement to enter into additional PURPA agreements may result inIPC acquiring energy at above wholesale market prices, thus increasing costs toits customers.  Additionally, it ishighly likely that the requirement to enter into additional PURPA agreementswill add to IPC's surplus during certain times of the year, potentially duringoff-peak hours.  This could alsoincrease costs to IPC's customers.

**Idaho**: OnJune 8, 2004, the IPUC ordered that two separate complaints against IPC beconsolidated.  The complaints bothrelate to the contract terms required by IPC for PURPA qualifying facilities.  The specific issues to be addressed by theIPUC were: (1) size threshold for standard rates; (2) the distinction betweenfirm and non-firm energy and the appropriateness of performance bands and (3)the ability to terminate contractual obligations should retail deregulation beimplemented in Idaho.  A public hearingwas conducted on September 2, 2004 and September 3, 2004 and post-hearingbriefs were filed on September 17, 2004. The IPUC issued Order No. 29632 on November 22, 2004, (1) clarifying thedetermination of the ten MW size threshold for standard published rates, (2)approving the implementation of performance bands and (3) denying IPC's requestfor the ability to terminate contractual obligations if retail deregulationwere implemented in Idaho.  IPCsubsequently signed a purchased power agreement with one of the complainants.

**Oregon**: InJanuary 2004, the OPUC opened a proceeding to review its policies on PURPAmatters and issue a comprehensive order to address them.  The following issues have been identifiedfor consideration in this proceeding: (1) contract length and price structure;(2) size threshold for standard rates; (3) utility tariff content; (4) avoidedcost calculation methods; (5) applicability of Oregon PURPA administrativerules and (6) dispute mediation.  Ahearing began on October 27, 2004. Briefs on the matter were due January 27, 2005 and oral arguments wereheld on February 7, 2005.  The outcomeof these issues is unknown at this time.

**Idaho Renewable Energy Legislation**Idaho's interim Legislative Committee on Energy developed a green-power taxincentive bill.  The legislation wouldprovide a sales tax exemption on alternative generation equipment used directlyin generating electricity using fuel cells, low impact hydro, wind, geothermalresources, cogeneration, sun or landfill gas as the principal source ofpower.  The alternative generationfacility would need to be in excess of five MW to be eligible for the sales taxexemption.  If enacted, the legislationwould expire in July 2011.  IPC isunable to predict whether this bill will become law or what effect it wouldhave on its operations.

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

The IRP is filed every twoyears with both the IPUC and the OPUC. Prior to filing, the IRP requires extensive involvement by IPC, the IPUCStaff and the OPUC Staff, as well as customer, technological and environmentalrepresentatives and is the starting point for demonstrating prudence in IPC'sresource decisions.  Public commentsconcerning IPC's 2004 IRP were filed with the IPUC by December 3, 2004.  On December 23, 2004, IPC filed its responseto the filed comments.  IPC expects thatthe commissions will acknowledge the plan in early 2005.  The 2004 IRP includes the followingelements, which may require significant capital expenditures in the future:

76-MW demand response programs;

48-MW energy efficiencyprograms; 

350-MW wind-powered generation;

100-MW geothermal-poweredgeneration; 

48-MW combined heat and powerat customer facilities; 

88-MW simple-cycle natural gasfired combustion turbine; 

62-MW combustion turbine,distributed generation or market purchases; and 

500-MW coal-fired generation.

The 2004 IRP identifies specific actions to betaken by IPC prior to the next IRP in 2006. IPC is in the process of implementing these actions.  During December of 2004, IPC issued two RFPsassociated with an Air Conditioning Cycling Program and on January 13, 2005,IPC issued an RFP for 200 MW of wind-powered generation.  During the remainder of 2005, IPC willdesign demand-side programs in coordination with the Energy Efficiency AdvisoryGroup and both commissions, issue an RFP for a combustion turbine peakingresource, issue an RFP for a 12-MW combined heat and power (co-generation)facility and issue an RFP for 100 MW of geothermal-powered generation.

**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 as soon as practicable, subject to updated analysisshowing Advanced Meter Reading to be cost effective for customers.  As ordered by the IPUC, IPC submitted anupdated analysis on May 9, 2003.  Aworkshop with the IPUC Staff and other interested parties to discuss theanalysis was held on May 19, 2003.  TheIPUC issued Order No. 29291 on July 14, 2003, providing interested parties theopportunity to submit comments regarding IPC's updated analysis.  On October 24, 2003, the IPUC issued OrderNo. 29362, which directed IPC to collaboratively develop and submit a Phase OneAdvanced Meter Reading Implementation Plan to replace current residentialmeters with advanced meters in selected service areas.  IPC complied with this order on December 23,2003 by filing a Phase One Implementation Plan that targeted the Emmett, Idahoand McCall, Idaho areas for 2004 installation and 2005 implementation.  Phase One is estimated to cost $6 millionand IPC will include these costs in future rate filings.  Since April 2004, approximately 24,000meters have been installed.  IPC willsubmit a report to the IPUC by December 31, 2005, summarizing the AdvancedMeter Reading project and associated benefits and costs.

**Relicensingof Hydroelectric Projects**IPC, like other utilities that operate nonfederal hydroelectricprojects on qualified waterways, obtains licenses for its hydroelectricprojects from the FERC.  These licenseslast for 30 to 50 years depending on the size, complexity, and cost of the project.  IPC recently received new licenses for fiveof its middle Snake River projects.  Thelicense for IPC's Malad hydroelectric project expired in 2004 and the projectwill continue to operate under an annual license until the FERC issues a newmulti-year license.  IPC's hydroelectricproject license for the Hells Canyon Complex will expire in 2005 and the SwanFalls project license will expire in 2010. IPC is actively pursuing the relicensing of these projects, a processthat may continue for the next ten to 15 years.

**Middle Snake River Projects:**  The middle Snake River projects consist ofthe Bliss, Upper Salmon Falls, Lower Salmon Falls, Shoshone Falls and CJ Strikeprojects.  On August 4, 2004, IPCreceived the FERC license orders for each of the middle Snake Riverprojects.  Each license is for a 30-yearduration effective August 1, 2004.  Acentral component of each license order is a Settlement Agreement between IPCand the U.S. Fish and Wildlife Service regarding five snail species thatinhabit the middle Snake River, which are listed as threatened or endangeredspecies under the ESA.  As a basis forthe settlement, IPC and the U.S. Fish and Wildlife Service agreed thatadditional studies and analyses are needed in order to accurately assess the effect,if any, that the middle Snake River projects may have on one or more of thelisted snail species.  The SettlementAgreement provides an operational regime for the five projects that will permitsix years of studies and analyses of various project operations on the listedsnail species, while providing interim protection of the listed species.  After the studies are complete, IPC and theU.S. Fish and Wildlife Service intend to jointly develop a plan that willaddress project operation and the protection of listed snails for the remainderof the new license terms.

On September 2, 2004, twoconservation groups, American Rivers and Idaho Rivers United, filed petitionsfor rehearing of the orders issuing the licenses for the middle Snake Riverprojects. These petitions ask the FERC to vacate the licensing orders andrequest a determination from the U.S. Fish and Wildlife Service that the middleSnake River projects jeopardize the listed snail species.  On October 4, 2004, the FERC issued an OrderGranting Rehearing for Further Consideration to provide additional time toconsider the matters raised by the rehearing requests.  The order further provided that the FERCanticipated issuing an order on the merits of the rehearing requests on orbefore November 1, 2004.  The FERC hasyet to issue an order.

On September 17, 2004, IdahoRivers United filed a complaint against the U.S. Fish and Wildlife Service inthe U.S. District Court for the District of Idaho seeking judicial review ofthe biological opinion issued by the U.S. Fish and Wildlife Service on May 14,2004 on the effect of the relicensing of the middle Snake River projects on thelisted snail species.  The complaintalleges that the U.S. Fish and Wildlife Service action in entering into andrelying on the Settlement Agreement as a basis for issuing a no jeopardydetermination in the biological opinion was arbitrary, capricious and contraryto law and asks the court to reverse the biological opinion and remand it tothe U.S. Fish and Wildlife Service for further consideration.  Neither the FERC nor IPC are parties to theaction.  On November 25, 2004, the U.S.Fish and Wildlife Service filed a motion to dismiss the complaint.  On February 4, 2005, the court granted thismotion.

Several of the new licensearticles for the middle Snake River projects require that IPC file additionalinformation with the FERC either upon license issuance or within 30, 45 or 60days following license issuance.  IPChas made these required filings.

Many of the new licensearticles require IPC to develop comprehensive plans for PM&E measures andsubmit them to the FERC for approval. The plans are due within six months to one year following licenseissuance and are required to have detailed costs, schedules and methods forimplementing the PM&E measures.  IPCis also required to consult with certain parties that participated in therelicensing process including state and federal resource agencies, NativeAmerican Indian Tribes and non-governmental organizations (environmentalorganizations) prior to the completion of development and the filing of some ofthe plans.  The FERC will then reviewand approve the plans, after which IPC will proceed with implementation of theplanned PM&E measures.

Plans to be developed andapproved for each license include White Sturgeon Conservation, RecreationManagement, Middle Snake River and CJ Strike Wildlife Management Area landmanagement, Minimum and Aesthetic Water Flows, Water Quality Monitoring,Historic Properties Management, Spring Habitat Protection, Fish Stocking andOperational Compliance Monitoring.

Cost estimates for the plans toimplement required PM&E measures are $10 million in capital and $2 millionin additional annual operation and maintenance expense.  Most of the capital expenditures will occurwithin the first five years of the licenses. Since the plans have not yet been accepted by the FERC, the costestimates are preliminary. Additionally, cost estimates do not include any PM&E measures thatmay be required as a result of the Settlement Agreement snail studies andanalysis described above.

At December 31, 2004, $10million of middle Snake River project relicensing and compliance costs were inelectric plant in service.  The majorityof these costs, which were incurred prior to the completion of IPC's recent Idahogeneral rate case, were approved for recovery in rates.  The remaining costs and any future costswill be submitted to regulators for recovery through the rate-making process.

**Malad Project:**  The license for the Malad project expired onAugust 1, 2004.  IPC filed a new licenseapplication in July 2002 and will operate the project on an annual licenseissued under the same terms and conditions of the expired license until theFERC issues a new multi-year license. In September 2004, the FERC issued a Final Environmental Assessmentunder NEPA for the Malad project concluding that, with appropriate PM&Emeasures, relicensing the project would not constitute a major federal actionsignificantly affecting the quality of the human environment.  The cost estimate of the PM&E measuresis less than $1 million annually.  InDecember 2004, the U.S. Fish and Wildlife Service submitted the final, nojeopardy biological opinion to the FERC. The biological opinion is the last piece of information required for theFERC's licensing decision.  IPCanticipates a new multi-year license will be issued in 2005.

At December 31, 2004, $3million of Malad project relicensing costs were included in construction workin progress.  The relicensing costs arerecorded and held in construction work in progress until a new multi-yearlicense is issued by the FERC, at which time the charges are transferred toelectric plant in service.  Relicensingcosts and costs related to new licenses will be submitted to regulators forrecovery through the rate-making process.

**Hells Canyon Complex:**  The most significant ongoing relicensingeffort is the Hells Canyon Complex, which provides approximately two-thirds ofIPC's hydroelectric generating capacity and 40 percent of its total generatingcapacity.  IPC developed the licenseapplication for the Hells Canyon Complex through a collaborative processinvolving representatives of state and federal agencies and business,environmental, tribal, customer, local government and local landownerinterests.  The license application wasfiled in July 2003 and accepted by the FERC for filing in December of2003.  The current license for the HellsCanyon Complex expires in July 2005. IPC will thereafter operate the project under an annual license issuedby the FERC until the new multi-year license is issued.  The application includes the continuation ofexisting, as well as proposed new measures intended to protect, mitigate andenhance fish and wildlife, protect recreational opportunities and preserveother aspects of environmental quality. The costs of these PM&E measures, as estimated in the licenseapplication, are approximately $106 million in the first five years of alicense and $218 million over the following 25 years, for a total estimatedcost of $324 million over a 30-year license. These cost estimates do not include estimated costs of proposed waterquality measures included in the license application.  These measures are the subject of ongoing state processes underSection 401 of the Clean Water Act.  IPCestimates that costs associated with these water quality measures may result inan additional cost of $62 million, for a total estimated cost of  $386 million.  These estimated costs could increase as a result of the HellsCanyon ESA Consultation/Settlement Process (see discussion below).  In response to the filing of the licenseapplication in July 2003, various federal and state agencies, Native AmericanIndian Tribes and other participants in the Hells Canyon Complex relicensingprocess filed initial comments to the license application, some of whichcontained additional proposed PM&E measures.  IPC's preliminary estimate of the potential cost of theseadditional proposed measures, assuming all of the proposed measures areincluded as conditions in a final license, which IPC believes is unlikely, isapproximately $2.5 billion over up to a 50-year period.  This would result in an approximate 28percent increase to existing base rates. These cost estimates are preliminary as federal, state, tribal andprivate parties participating in the relicensing proceeding are not required tofile their final comments, recommendations, terms, conditions and prescriptionswith the FERC until later in the relicensing process.  The FERC will then consider these final comments,recommendations, terms, conditions and prescriptions under the Federal PowerAct, NEPA and other applicable federal laws, and include those conditions inthe final license that the FERC determines are necessary and required toprotect, mitigate and enhance those resources affected by the operation andmanagement of the project.  As such, theactual costs of the PM&E measures associated with the relicensing of theHells Canyon Complex will not be known until the new license is issued by theFERC.

At December 31, 2004, $66million of Hells Canyon Complex relicensing costs were included in constructionwork in progress.  The relicensing costsare recorded and held in construction work in progress until a new multi-yearlicense is issued by the FERC, at which time the charges are transferred toelectric plant in service.  Relicensingcosts and costs related to a new license, as discussed above, will be submittedto regulators for recovery through the rate-making process.

NEPA Process:NEPA requires that the FERC independently evaluate the environmental effects ofrelicensing the Hells Canyon Complex as proposed under the final licenseapplication (the proposed action) and also consider reasonable alternatives tothe proposed action.  Consistent with therequirements of NEPA, the FERC Staff will prepare an environmental impactstatement for the Hells Canyon project, which the FERC will use to determinewhether, and under what conditions, to issue a new license for the project.  The environmental impact statement willdescribe and evaluate the probable effects, if any, of the proposed action andthe other alternatives considered.  Aspart of the NEPA process, the FERC initiated a scoping process to supportpreparation of the environmental impact statement and help ensure that allpertinent issues are identified and analyzed.

OnOctober 20, 2003, the FERC issued Scoping Document 1 to provide interestedparties with information on the relicensing of the project and solicit commentsand suggestions for a preliminary list of issues and alternatives that might beaddressed in the environmental impact statement.  The FERC also held four scoping meetings in the fall and winterof 2003 to offer parties the opportunity for input on the scope of theenvironmental impact statement.  Basedupon comments and information received in response to Scoping Document 1, onNovember 24, 2004, the FERC Staff issued Scoping Document 2, which provides atentative schedule for the environmental impact statement preparation includingthe filing of additional information on February 19, 2005; issuance of theReady for Environmental Analysis Notice in February 2005; and issuance of thedraft environmental impact statement in September 2005.  Scoping Document 2 notes, however, that thedates for issuance of the Ready for Environmental Analysis Notice and draftenvironmental impact statement may change as necessary to allow the FERC toconsider additional information needed to process the license application.  IPC and a number of other partiesparticipating in the Hells Canyon ESA Consultation/Settlement Process (see"Consultation/Settlement Process" discussion below) have requestedthat the FERC revise the schedule to enable the parties to pursue acomprehensive settlement agreement for the relicensing of the Hells CanyonComplex.  IPC is working with the otherparties to reach an agreement in principle on the relicensing issues bySeptember 2005, which will inform and focus the FERC in its preparation of thedraft environmental impact statement for the NEPA and relicensing process.  By order issued on February 8, 2005, theFERC granted IPC's request for a deferral and extended the due date for filingrecommendations and conditions until November 2005.  The Ready for Environmental Analysis Notice is now scheduled forMay 2005 and the draft environmental impact statement is scheduled to be issuedin April 2006.

Consultation/SettlementProcess:In an effort to resolve issues associated with the relicensing of theHells Canyon Complex, IPC has been engaged with the FERC and relevant federaland state agencies on the effects, if any, of the relicensing of the project onspecies listed as threatened or endangered under the ESA.  The National Marine Fisheries Service listedSnake River sockeye as endangered in 1991, Snake River spring, summer and fallchinook as threatened in 1992 and Snake River steelhead as threatened in1997.  In June 1998, the U.S. Fish andWildlife Service also listed bull trout in the Columbia and Klamath Riverbasins as threatened.  Since 1997 IPChas been engaged in informal discussions with the National Marine FisheriesService and other federal, state and tribal interests on issues associated withthe effect of the Hells Canyon Complex operations on ESA-listed species andaquatic resources below the Hells Canyon Complex in the context of the SnakeRiver Basin Adjudication mediation.

With respect to the informalconsultations regarding relicensing of the Hells Canyon Complex initiated inthe Snake River Basin Adjudication mediation, the FERC has designated IPC asits non-federal representative for purposes of continuing this informalconsultation with the National Marine Fisheries Service and the U.S. Fish andWildlife Service.  In July 2004, theFERC requested formal consultation with the National Marine Fisheries Serviceregarding the effects of interim Hells Canyon Complex operations on ESA-listedspecies and issued a notice to all interested parties of an ESA consultationmeeting on September 9, 2004 to discuss how to proceed with consultation,including how to integrate the ongoing Hells Canyon Complex relicensingsettlement discussion into the consultation process.

On September 7, 2004, IPCsubmitted a letter to the FERC regarding the September 9, 2004 consultation meeting,advising that IPC, the National Marine Fisheries Service and the U.S. Fish andWildlife Service had explored opportunities to address ESA issues associatedwith the interim operations and the relicensing of the Hells Canyon Complexthrough a negotiated settlement process.

At the September 9, 2004meeting, IPC, the National Marine Fisheries Service and the U.S. Fish andWildlife Service discussed the proposed settlement process with the FERC Staffand other interested parties in attendance. At the conclusion of that meeting, the parties, with the concurrence ofthe FERC Staff, expressed an interest in engaging in additional discussionsintended to reach agreement on an organizational structure for implementing theHells Canyon ESA Consultation/Settlement Process.

In late September 2004, IPC, the National MarineFisheries Service, the U.S. Fish and Wildlife Service and other parties,including the states of Idaho and Oregon, the U.S. Forest Service, severalNative American Indian Tribes, American Rivers and Idaho Rivers United,interested in the relicensing of the Hells Canyon Complex met to continuediscussions relative to the initiation of the Hells Canyon ESAConsultation/Settlement Process.  As aresult of that meeting, the parties established a Hells Canyon Complexsettlement process in the fall of 2004, which includes a Settlement WorkingGroup, a facilitator and separated FERC Staff. The initial objective of the Settlement Working Group was to addressinterim operations and anadromous fish species listed under the ESA in aneffort to provide agreed upon measures to the FERC by April 2005.  The primary objective of the SettlementWorking Group, however, is to negotiate and develop a comprehensive settlement agreementto support the relicensing of the project, with a goal of achieving anagreement in principle by September 2005. Parties participating in the Settlement Working Group include IPC, theNational Marine Fisheries Service, the U.S. Fish and Wildlife Service, the U.S.Bureau of Land Management, the U.S. Bureau of Reclamation, the U.S. Departmentof Agriculture - Forest Service, the State of Oregon, the State of Idaho, theNez Perce Tribe, the Shoshone-Paiute Tribes, the Shoshone Bannock Tribes, theBurns-Paiute Tribe, American Rivers, Idaho Rivers United, the Idaho Water UsersAssociation, the Payette River Water Users Association, the Pioneer, Settlersand Nampa Meridian irrigation districts, the Committee of Nine, the Idaho FarmBureau, the Columbia River Inter-Tribal Fish Commission, the Idaho Council onIndustry and the Environment, the J. R. Simplot Company and other industrialcustomers of IPC.

Following expeditednegotiations, on January 7, 2005, IPC filed an agreement on interim operations(Interim Agreement) with theFERC.  The Interim Agreement has beenexecuted by IPC, American Rivers, Idaho Rivers United, the National MarineFisheries Service, the U.S. Fish and Wildlife Service, the U.S. Department ofAgriculture - Forest Service, the U.S. Bureau of Land Management, the Oregon Departmentsof Fish and Wildlife and Environmental Quality, the Nez Perce Tribe, theShoshone-Bannock Tribes and the Shoshone-Paiute Tribes.  The InterimAgreement is intended to address issues relating to operations of theHells Canyon Complex and ESA-listed species in advance of the issuance of a newlicense while the parties to the settlement process negotiate a comprehensivesettlement agreement.  In accordancewith the provisions of the Interim Agreement, IPC has agreed to implementcertain measures until a new license is issued for the Hells Canyon Complexincluding monitoring flows above the Hells Canyon Complex to protect existingrights, the leasing and passing of certain U.S. Bureau of Reclamation flowaugmentation water, continuing its fall chinook plan from March 1 through May31 of each year, identifying and monitoring potential stranding sites andcontinuing to fund its hatchery program. IPC has also agreed to implement certain additional measures on an annualbasis, provided that the parties remain engaged in settlement discussionsintended to resolve long-term relicensing issues including, subject to certainvariables, flow augmentation to aid anadromous fish migration, the shaping ofU.S. Bureau of Reclamation storage water, establishing procedures to collectthe data and information necessary in the relicensing settlement discussions,identifying, developing and reviewing potential structural modificationsregarding dissolved oxygen, total dissolved gas and seasonal watertemperatures, providing water quality information to support consultationsunder Section 401 of the Clean Water Act and sharing information regardingnative resident and anadromous fish passage through the Hells CanyonComplex.  The signatories agree that themeasures in the Interim Agreementare intended to provide reasonable protection for ESA-listed species during theterm of the Interim Agreementand also establish a basis for comprehensive settlement discussions tocontinue.  The Settlement Working Group,with the continuing assistance of the facilitator and separated FERC Staffcommenced negotiations on the long-term settlement agreement in January2005.  Due to the number and complexityof the issues, it is anticipated that the parties to the settlement processwill be required to devote substantial resources and time to the settlementeffort in order to achieve the objective of reaching agreement by the fall of2005.

Additional InformationRequests:The relicensing process permits interveners to submit additionalstudy requests to the FERC.  In theHells Canyon Complex relicensing process, additional study requests weresubmitted in response to the FERC's Notice of Tendering Application issued onJuly 31, 2003.  The FERC received atotal of 123 additional study requests. On May 4, 2004, the FERC Staff responded to the additional studyrequests issuing to IPC a total of 14 Additional Information Requests.

On June 8, 2004, IPC filed aletter with the FERC objecting to certain of the Additional InformationRequests and requesting clarification, modification or extensions of time as toothers.  IPC objected to some of theAdditional Information Requests on the basis that there was no nexus betweenthe Hells Canyon Complex operations and the asserted effects on the resourcesthat were the subject of the Additional Information Requests, submitting thatunder the Federal Power Act, the FERC's authority to impose terms andconditions in a project license is limited to resources that are affected bythe development, operation and management of the project.  In the case of several of the AdditionalInformation Requests, IPC contended that the resources at issue were affectedby the development and operation of federal hydroelectric projects downstreamfrom the Hells Canyon Complex, not by the Hells Canyon Complex.

IPC objected to otherAdditional Information Requests relating to various limitations on flow,ramping rates and other operational restrictions intended to benefitrecreational navigation below the Hells Canyon Complex on the basis that theHells Canyon National Recreation Area Act (HCNRAA), enacted by Congress in1975, grandfathers the Hells Canyon Complex and prohibits flow requirements ofany kind on waters of the Snake River below the Hells Canyon Complex.

On June 29, 2004, the FERCStaff denied IPC's objections to the Additional Information Requests, advisingthat their review of the license application indicates that the Hells CanyonComplex has the potential to affect downstream resources and disagreeing thatthe HCNRAA places any restriction on requirements that can be included in thelicense for the Hells Canyon Complex. The FERC Staff also granted extensions of time and providedclarification for certain other Additional Information Requests.  On July 29, 2004, IPC filed a Petition forRehearing with the FERC contesting the FERC Staff's decision denying IPC'sobjections to the Additional Information Requests.

By letter dated July 30, 2004,IPC requested additional time to complete certain of the Additional InformationRequests because relevant studies and model runs could not be completed withinthe time allowed, and advised the FERC that although IPC had filed a requestfor rehearing regarding the FERC Staff's denial of IPC's objections, IPC wasproceeding with the studies and analysis relevant to the Additional InformationRequests pending the FERC's consideration of that request.

On September 13, 2004, IPCfiled a request with the FERC requesting that it defer taking action on thepending rehearing request because IPC and other interested parties hadcommenced the Hells Canyon ESA Consultation/ Settlement Process discussedabove.  IPC did not request, however,that the FERC defer action on the July 30, 2004 request for additionaltime.  By letter dated October 20, 2004,the FERC Staff denied some of the requests for additional time and providedlimited relief as to others.

On June 11, 2004, AmericanRivers and Idaho Rivers United filed an interlocutory appeal of the FERCStaff's denial of fish passage study requests, one of the Additional StudyRequests that the FERC Staff did not adopt in its May 4, 2004 response.  IPC filed a response to the interlocutoryappeal on June 28, 2004.  By order datedJuly 15, 2004, the FERC dismissed the interlocutory appeal filed by AmericanRivers and Idaho Rivers United.

**Swan Falls Project:**  The license for the Swan Falls hydroelectricproject expires in 2010. IPC is preparing for the first stage of formalconsultation for the new license application, which will be filed with the FERCin 2008.

At December 31, 2004, $1million of Swan Falls project relicensing costs were included in constructionwork in progress.  The relicensing costsare recorded and held in construction work in progress until a new multi-yearlicense is issued by the FERC, at which time the charges are transferred toelectric plant in service.  Relicensingcosts and costs related to a new license will be submitted to regulators forrecovery through the rate-making process.

**American Rivers Petition:**  On May 1, 2003, American Rivers and IdahoRivers United petitioned the U.S. Court of Appeals for the District of ColumbiaCircuit requesting that the court issue a Writ of Mandamus compelling the FERCto respond to a petition American Rivers filed with the FERC in 1997 requestingthat the FERC initiate formal consultation pursuant to Section 7(a)(2) of theESA with the National Marine Fisheries Service on the effects of the ongoingoperations of IPC's Hells Canyon Complex on four species of Snake River salmonand steelhead trout that are listed as threatened or endangered under theESA.  The case was argued on March 16,2004.  On June 22, 2004, the courtissued a decision in the case ordering the FERC to issue a judiciallyreviewable response to the 1997 petition within 45 days.

OnAugust 6, 2004, the FERC entered an Order on Mandamus and Granting Petitiongranting the 1997 petition.  Consistentwith this order, the FERC initiated ESA consultation, setting a meeting onSeptember 9, 2004 with the National Marine Fisheries Service, the U.S. Fish andWildlife Service and IPC to discuss the interaction of formal consultation onongoing operations with the anticipated ESA consultation regarding therelicensing of the Hells Canyon Complex, and how any potential settlementdiscussions could be integrated into the consultation process.  The filing of the Interim Agreement with theFERC on January 7, 2005 resolved the issues raised by the court's Order onMandamus and the FERC's order of August 6, 2004 while the parties to the HellsCanyon ESA Consultation/Settlement Process negotiate a long-term comprehensiveagreement for relicensing.  See previousdiscussion in "Hells Canyon Complex."

**Regional Transmission Organizations**In December 1999, the FERC, in Order No. 2000, said that all companies withtransmission assets must file with the FERC to form RTOs or explain why theycannot do so.  Order No. 2000 is afollow up to Order Nos. 888 and 889 issued in 1996, which required transmissionowners to provide non-discriminatory transmission service to thirdparties.  By encouraging the formationof RTOs, the FERC sought to further facilitate the formation of efficient,competitive wholesale electricity markets.

In July2002, the FERC issued a notice of proposed rulemaking on Standard Market Design.  In this notice, the FERC proposedsignificant wholesale electricity market design changes in an effort to advancethe kinds of markets envisioned in Order Nos. 888 and 2000 but not yetrealized.  The proposed changes wereintended to improve wholesale competition, make more efficient use oftransmission systems and generate clear pricing signals for investment intransmission, generation facilities and demand reduction.  In April 2003, the FERC issued its "WhitePaper: Wholesale Market Platform." The White Paper set forth the FERC's then current thinking on issuesunder consideration in the Standard Market Design proceeding.  The FERC committed to consider all commentson the White Paper, as well as pending legislation, prior to the issuance of aFinal Rule.  To date, the FERC has notissued a Final Rule in its Standard Market Design proceeding.

InOctober 2000 and March 2002, in response to FERC Order No. 2000, IPC and nineother regional transmission owners filed Stage One and Stage Two plans to formRTO West, an independent entity that would operate the transmission grid in thenorthwest and British Columbia.  InSeptember 2002, the FERC issued an order granting in part RTO West's Stage Tworequest for a declaratory order, approving the majority of the proposedplan.  With further development ofdetail and some modification, the FERC stated that the proposal "willsatisfy not only the Order No. 2000 requirements, but that it can also providea basic framework for standard market design for the West."

Inmid-2003, the RTO West Regional Representatives Group, in an effort to bolsterregional support, began a new phase of discussions related to the developmentof an independent entity to manage the regional transmission system and improverelated wholesale electricity markets. These discussions began with a wide-ranging consideration of currenttransmission problems and opportunities within the region.

Duringthe remainder of 2003, the Regional Representatives Group focused on exploringoptions and developing a consensus proposal to address the region'stransmission problems and opportunities. As a result of this effort, the Regional Representatives Group endorseda comprehensive Regional Proposal in February 2004.  The Regional Proposal provided a framework to better manage theregional transmission system and enhance wholesale power markets through thecreation of an independent entity to manage the region's combined transmissionservices, operate certain aspects of the combined system such as transmissionreservation and scheduling, provide monitoring of regional power markets,perform comprehensive transmission system-wide planning and facilitate otheraspects of transmission system operation.

In thespring of 2004, the Regional Representatives Group recommended that the name ofRTO West be changed to Grid West and set out a plan to guide its creation.  The plan contained the following four steps:(1) to establish governance acceptable to the region and form the initialDevelopmental Corporation under an interim board comprised of participatingentity representatives; (2) participating entities commit to two years offunding and transfer control to a newly seated board comprised of membersindependent of any market participants; (3) the independent board will developand offer transmission control agreements under which Grid West will performcertain operating functions on the transmission systems of participatingentities, and to develop tariffs for new transmission services and (4) GridWest will reorganize from the Developmental Corporation into an OperatingCorporation and will commence actual transmission operation.  The fourth step will be taken if sufficiententities sign transmission agreements.In December 2004, the filing entities of RTO West voted unanimously to adoptthe new Bylaws and Articles of Incorporation to formally reorganize into thenew entity, Grid West (Developmental Corporation).  This completed the first of the four major steps toward bringingGrid West into operation.  The participatingentities included: Avista Corporation, the Bonneville Power Administration,IPC, Nevada Power Company, NorthWestern Energy, PacifiCorp, Portland GeneralElectric Company, Puget Sound Energy, Sierra Pacific Power Company and BritishColumbia Transmission Corporation.

Thefirst step establishes the Grid West interim board, initiates a search forcandidates to be elected as independent trustees on a new five-personindependent board and opens a process for interested parties to become membersof the new organization.  The next stepwill transfer control to the new independent board.  The present schedule calls for reaching the second step in thefall of 2005.  The third step isexpected in 2006 and the fourth in 2007.

Theoperational impact of Grid West on IPC presently and for the near future shouldbe minimal.  No IPC facilities will besubject to Grid West operation until after operational authority isgranted.  IPC will have periodicopportunities to decide whether or not to continue participation.  At the final step, signing a transmissionagreement will be voluntary for IPC.

IPC hasspent funds supporting the development of RTO West and Grid West, and expectsto continue funding this development as long as it remains a participatingutility.  Funding of this effort hastaken two forms.  First, funds have beenloaned to RTO West, and subsequently Grid West, for the purpose of meeting itsdevelopmental expenses.  IPC expectsthis loan to be repaid by Grid West when it commences operation.  Second, IPC has incurred incrementalinternal costs from participating in the developmental effort, which are mostlyrelated to travel and legal consultation. IPC has accumulated these costs in deferred expense accounts.  The total accumulated expense for both typesof funding through 2004 was $3 million and is expected to be approximately $1million for 2005.  At this time IPCexpects full recovery of the total accumulated expense through rates.

**FERCMarket-Based Rate Authority**IPC has FERC-approved market-based rate authority, which permits IPCto sell electric energy at market-based rates rather than cost-basedrates.  The FERC requires periodicreviews of the conditions under which this market-based rate authority isgranted to ensure that the rates charged thereunder are just andreasonable.  On April 14, 2004, the FERCissued an order commencing a market power analysis of all companies withmarket-based rate authority; including IPC. In September 2004, IPC filed a revision of its previously approved (October9, 2003) market power analysis, which it supplemented in September andOctober.  On March 3, 2005, the FERCissued an order accepting IPC's market power analysis.  IPC is required to file another market poweranalysis on or before March 3, 2008.

**OTHER MATTERS:******

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

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

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

**New Accounting Pronouncements****SFAS 151:** In November 2004, the FASB issued SFAS 151, "InventoryCosts," which clarifies the accounting for certain inventory-relatedcosts.  SFAS 151 is effective forinventory costs incurred during fiscal years beginning after June 15, 2005, andis not expected to have a material effect on IDACORP's or IPC's financialstatements.

**SFAS 153:** InDecember 2004, the FASB issued SFAS 153, "Exchanges of NonmonetaryAssets," which amends existing guidance on accounting for nonmonetarytransactions.  SFAS 153 is effective forexchanges occurring in fiscal periods beginning after June 15, 2005, and is notexpected to have a material effect on IDACORP's or IPC's financial statements.

**SFAS 123(R):**InDecember 2004, the FASB issued SFAS 123 (revised 2004), "Share-BasedPayments." SFAS 123(R) which revises SFAS 123, "Accounting forStock-Based Compensation" and supersedes APB Opinion 25, "Accountingfor Stock Issued to Employees," and its related implementationguidance.  SFAS 123(R) establishesstandards for the accounting for transactions in which an entity exchanges itsequity instruments for goods or services. It also addresses transactions in which an entity incurs liabilities inexchange for goods or services that are based on the fair value of the entity'sequity instruments or that may be settled by the issuance of those equityinstruments.  SFAS 123(R) focusesprimarily on accounting for transactions in which an entity obtains employeeservices in share-based payment transactions.

Under the provisions of SFAS123(R), the fair value of all stock options must be reported as an expense onthe financial statements.  IDACORP andIPC currently apply the measurement provisions of APB 25 and thedisclosure-only provisions of SFAS 123. SFAS 123(R) also changes other measurement, timing and disclosure rulesrelating to share-based payments.

SFAS 123(R) is effective formost public entities as of the beginning of the first interim or annualreporting period beginning after June 15, 2005.  IDACORP and IPC expect to adopt SFAS 123(R) on July 1, 2005, andadoption is expected to decrease IDACORP's and IPC's pre-tax income by approximately$0.6 million in 2005.  Stock-based compensationarrangements are discussed in Note 9 to IDACORP's Consolidated FinancialStatements.

**FSP FAS 106-2:**  See Note 10 to IDACORP's ConsolidatedFinancial Statements for a discussion of this FSP, which relates topostretirement benefit obligations.

**TransmissionReliability Management System:**  On April 6, 2004, the U.S. Department of Energy issued its finalreport regarding the August 14, 2003 electric blackout in the eastern UnitedStates.  The Western ElectricityCoordinating Council, of which IPC is a member, has treated the recommendationsas though the outage occurred in the western interconnection.  The recommendations were assigned to variouscommittees in the Western Electricity Coordinating Council to create policiesand procedures to ensure compliance. IPC is actively participating in many of these forums on a regional andnational basis and is closely following the progress in other areas of thecountry.  Following the 1996 WesternBlackout, the Western Electricity Coordinating Council (then the WesternSystems Coordinating Council) adopted the Reliability Management System, whichcreated mandatory compliance and financial penalties for non-compliance of thereliability criteria.  The NorthAmerican Electric Reliability Council is using the Western ElectricityCoordinating Council Reliability Management System program as the model fortheir new mandatory compliance program. The FERC has also demonstrated a great interest in ensuring compliancewith the reliability standards.  In2004, the FERC required all electric utilities, including IPC, to submit areport on vegetation management practices. IPC submitted this report in June 2004. This year, the FERC is requiring electric utilities to complete a surveyon training practices.  IPC is currentlyin the process of submitting the training survey.  Implementation of the Blackout Report Recommendations and otherFERC and North American Electric Reliability Council policies could increaseoperating costs, but the extent of this effect cannot be determined at thistime.

**Stage Three Power Emergency: **On June 23, 2004, two downedtransmission lines in the Hells Canyon area caused IPC to shed 157 MW ofelectrical load and declare a Stage Three Power Emergency.  The Stage Three Power Emergency lastedapproximately 90 minutes and IPC employed all of its available generationresources during this time and purchased power from the wholesale markets.  IPC shed 100 MW for the entire 90 minutesand an additional 57 MW for 30 of the 90 minutes.  This occurrence did not have a significant impact on IPC'sfinancial results.

**Inflation**IDACORP and IPC believe that inflation has caused and will continueto cause increases in certain operating expenses and the replacement of assetsat higher costs.  Inflation affects thecost of labor, products and services required for operations, maintenance costsand capital improvements.  Whileinflation has not had a significant impact on IDACORP's or IPC's operations,costs for products and services are subject to increases.  IPC is subject to rate-of-return regulationand the impact of inflation on the level of cost recovery underregulation.  Increases in utility costsand expenses due to inflation could have an adverse effect on earnings becauseof the need to obtain regulatory approval to recover such increased costs andexpenses.

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

IDACORP and IPC areexposed to various market risks, including changes in interest rates, changesin commodity prices, credit risk and equity price risk.  The following discussion summarizes theserisks and the financial instruments, derivative instruments and derivativecommodity instruments sensitive to changes in interest rates, commodity pricesand equity prices that were held at December 31, 2004.

**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, 2004, IDACORP and IPC had$107 million and $73 million, respectively, in floating rate debt, net oftemporary investments.  Assuming nochange in either company's financial structure, if variable interest rates wereto average one percentage point higher than the average rate on December 31,2004, interest rate expense would increase and pre-tax earnings would decreaseby approximately $1 million for both IDACORP and IPC.

**Fixed Rate Debt:**  As of December 31, 2004, IDACORP and IPC hadoutstanding fixed rate debt of $939 million and $865 million,respectively.  The fair market value ofthis debt was $962 million and $886 million, respectively.  These instruments are fixed rate, andtherefore do not expose IDACORP or IPC to a loss in earnings due to changes inmarket interest rates.  However, thefair value of these instruments would increase by approximately $78 million forIDACORP and $76 million for IPC if interest rates were to decline by onepercentage point from their December 31, 2004 levels.

**CommodityPrice Risk****Utility:** IPC's exposure to changes in commodity price is related to itsongoing utility operations producing electricity to meet the demand of itsretail electric customers.  The weatheris a major uncontrollable factor affecting the local and regional demand forelectricity and the availability and price of production.  The objective of IPC's energy purchase andsale activity is to meet the demand of retail electric customers, maintainappropriate physical reserves to ensure reliability, and make economic use oftemporary surpluses which may develop.

IPC's exposure to commodityprice risk is largelyoffset by the previously discussed PCA mechanism.  IPC has adopted a risk management program designed to reduceexposure to power supply cost-related uncertainty, further mitigating commodityprice risk.  This program has been reviewedand accepted by the IPUC.  IPC's EnergyRisk Management Policy (the Policy) describes a collaborative process withcustomers and regulators via a committee called the Customer Advisory Group(CAG).  The Risk Management Committee(RMC), comprised of IPC officers and other senior staff, oversees the riskmanagement program.  The RMC isresponsible for communicating status of risk management activities to theIDACORP Board of Directors, and to the CAG.

ThePolicy requires monitoring monthly volumetric electricity position and totaldollar (net power supply cost) exposure for the current PCA-year plus thefollowing PCA-year six months in advance of its commencement.  The RMC evaluates revised projections forthe operating plan and orders risk mitigating action dictated by the limitsstated in the Policy.  IPCrepresentatives meet with the CAG at least annually to assess effectiveness ofthe limits.  Changes to the limits can beratified at this time for referral to the Board of Directors.  The primary tools for risk mitigation arephysical forward power transactions and fueling alternatives for utility-ownedgeneration.

**Energy Trading:**  The saleof IE's forward book of electricity trading contracts to Sempra Energy Tradingand the settlement of all gas trading contracts has eliminated the energycommodity 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 ofcredit.  A current list of acceptablecounterparties 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 Sempra Energy Trading,guaranteeing the performance of one of the counterparties.  The maximum amount payable by IE under theIndemnity Agreement is $20 million.  TheIndemnity Agreement has been accounted for in accordance with FIN 45 and didnot have a significant effect on IDACORP's financial 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 FINANCIALSTATEMENTS AND FINANCIAL STATEMENT SCHEDULES**

 

**PAGE**

**Consolidated  Financial Statements:**

 

IDACORP, Inc.

 

Consolidated Statements of Income for the Years Ended December 31,  2004, 2003 and 2002

59

Consolidated Balance Sheets as of December 31, 2004 and  2003

60-61

Consolidated Statements of Cash Flows for the Years  Ended December 31, 2004, 2003 and 2002

62

Consolidated Statements of Shareholders' Equity for the  Years Ended December 31, 2004, 2003

 

 

and 2002

63

Consolidated Statements of Comprehensive Income for the  Years Ended December 31, 2004,

 

 

2003 and 2002

64

Notes to the Consolidated Financial Statements

65-99

Report of Independent Registered Public Accounting Firm

100

 

 

Idaho Power Company

 

Consolidated Statements of Income for the Years Ended  December 31, 2004, 2003 and 2002

101

Consolidated Balance Sheets as of December 31, 2004 and  2003

102-103

Consolidated Statements of Capitalization as of  December 31, 2004 and 2003

104

Consolidated Statements of Cash Flows for the Years  Ended December 31, 2004, 2003 and 2002

105

Consolidated Statements of Retained Earnings for the  Years Ended December 31, 2004, 2003

 

 

and 2002

106

Consolidated  Statements of Comprehensive Income for the Years Ended December 31, 2004,

 

 

2003 and 2002

106

Notes to the Consolidated Financial Statements

107-110

Report of Independent Registered Public Accounting Firm

111

 

 

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

 

Supplemental Financial Information (Unaudited)

112

 

 

Financial Statement Schedules for the Years Ended  December 31, 2004, 2003 and 2002:

 

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

127-130

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

131

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

132

 

 

 

 

 

 

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

 

**Year Ended December 31,**

 

**2004**

 

**2003**

 

**2002**

 

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

**Operating Revenues:**

 

 

 

 

 

 

 

 

 

Electric utility:

 

 

 

 

 

 

 

 

 

 

General business

$

635,835 

 

$

670,969 

 

$

772,035 

 

 

Off-system sales

 

121,148 

 

 

71,573 

 

 

55,031 

 

 

Other revenues

 

65,954 

 

 

40,178 

 

 

41,974 

 

 

 

Total electric utility revenues

 

822,937 

 

 

782,720 

 

 

869,040 

 

Energy marketing

 

(131)

 

 

19,916 

 

 

46,410 

 

Other

 

21,685 

 

 

20,366 

 

 

13,350 

 

 

Total operating revenues

 

844,491 

 

 

823,002 

 

 

928,800 

 

 

 

 

 

 

 

 

 

**Operating Expenses:**

 

 

 

 

 

 

 

 

 

Electric utility:

 

 

 

 

 

 

 

 

 

 

Purchased power

 

195,642 

 

 

150,980 

 

 

142,102 

 

 

Fuel expense

 

103,261 

 

 

99,898 

 

 

102,871 

 

 

Power cost adjustment

 

39,184 

 

 

70,762 

 

 

170,489 

 

 

Other operations and maintenance

 

255,867 

 

 

220,983 

 

 

207,355 

 

 

Depreciation

 

100,855 

 

 

97,650 

 

 

93,609 

 

 

Taxes other than income taxes

 

19,090 

 

 

20,753 

 

 

19,953 

 

 

 

Total electric utility expenses

 

713,899 

 

 

661,026 

 

 

736,379 

 

Energy marketing

 

(2,565)

 

 

37,671 

 

 

72,540 

 

Other

 

39,906 

 

 

40,243 

 

 

44,241 

 

 

 

Total operating expenses

 

751,240 

 

 

738,940 

 

 

853,160 

 

 

 

 

 

 

 

 

 

**Operating Income (Loss):**

 

 

 

 

 

 

 

 

 

Electric utility

 

109,038 

 

 

121,694 

 

 

132,661 

 

Energy  marketing

 

2,434 

 

 

(17,755)

 

 

(26,130)

 

Other

 

(18,221)

 

 

(19,877)

 

 

(30,891)

 

 

Total operating income

 

93,251 

 

 

84,062 

 

 

75,640 

 

 

 

 

 

 

 

 

 

**Other Income**

 

25,777 

 

 

11,544 

 

 

6,160 

 

 

 

 

 

 

 

 

 

**Earnings of Unconsolidated  Equity-method Investments**

 

1,050 

 

 

2,407 

 

 

746 

 

 

 

 

 

 

 

 

 

**Other Expense**

 

8,726 

 

 

7,622 

 

 

3,076 

 

 

 

 

 

 

 

 

 

**Interest Expense and  Preferred Dividends:**

 

 

 

 

 

 

 

 

 

Interest on long-term debt

 

54,937 

 

 

58,670 

 

 

54,147 

 

Other interest

 

3,379 

 

 

2,832 

 

 

10,211 

 

Preferred dividends of Idaho Power Company

 

4,823 

 

 

3,430 

 

 

4,587 

 

 

Total interest expense and preferred dividends

 

63,139 

 

 

64,932 

 

 

68,945 

 

 

 

 

 

 

 

 

 

**Income Before Income Taxes**

 

48,213 

 

 

25,459 

 

 

10,525 

 

 

 

 

 

 

 

 

 

**Income Tax Benefit**

 

(24,770)

 

 

(21,119)

 

 

(51,147)

 

 

 

 

 

 

 

 

 

**Net Income**

$

72,983 

 

$

46,578 

 

$

61,672 

 

 

 

 

 

 

 

 

 

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

 

38,361 

 

 

38,228 

 

 

37,790 

 

 

 

 

 

 

 

 

 

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

$

1.90 

 

$

1.22 

 

$

1.63 

**Dividends Paid Per Share of  Common Stock**

$

1.20 

 

$

1.70 

 

$

1.86 

 

 

 

 

 

 

 

 

 

 

The accompanyingnotes are an integral part of these statements.

** **

** **

** **

** **

**IDACORP, Inc.Consolidated Balance Sheets**

 

**December 31,**

 

**2004**

 

**2003**

**Assets**

**(thousands of dollars)**

 

 

 

 

**Current Assets:**

 

 

 

 

 

 

Cash and cash equivalents

$

23,403 

 

$

75,159 

 

Receivables:

 

 

 

 

 

 

 

Customer

 

92,258 

 

 

93,599 

 

 

Allowance for uncollectible accounts

 

(43,108)

 

 

(43,210)

 

 

Employee notes

 

3,523 

 

 

3,347 

 

 

Other

 

8,806 

 

 

8,209 

 

Energy marketing assets

 

9,203 

 

 

4,176 

 

Accrued unbilled revenues

 

33,832 

 

 

30,869 

 

Materials and supplies (at average cost)

 

28,008 

 

 

21,351 

 

Fuel stock (at average cost)

 

6,539 

 

 

6,228 

 

Prepayments

 

30,035 

 

 

27,779 

 

Deferred income taxes

 

23,407 

 

 

4,382 

 

Regulatory assets

 

5,510 

 

 

6,269 

 

 

Total current assets

 

221,416 

 

 

238,158 

 

 

 

 

 

 

**Investments**

 

223,061 

 

 

204,474 

 

 

 

 

 

 

**Property, Plant and  Equipment:**

 

 

 

 

 

 

Utility plant in service

 

3,324,816 

 

 

3,220,228 

 

Accumulated provision for depreciation

 

(1,316,125)

 

 

(1,239,604)

 

 

Utility plant in service - net

 

2,008,691 

 

 

1,980,624 

 

Construction work in progress

 

152,427 

 

 

96,091 

 

Utility plant held for future use

 

2,636 

 

 

2,438 

 

Other property, net of accumulated depreciation

 

45,708 

 

 

9,166 

 

 

Property, plant and equipment - net

 

2,209,462 

 

 

2,088,319 

 

 

 

 

 

 

**Other Assets:**

 

 

 

 

 

 

American Falls and Milner water rights

 

31,585 

 

 

31,585 

 

Company-owned life insurance

 

35,765 

 

 

35,624 

 

Energy marketing assets - long-term

 

16,635 

 

 

14,358 

 

Regulatory assets

 

433,271 

 

 

427,760 

 

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

 

2,895 

 

 

3,106 

 

Employee notes

 

3,746 

 

 

4,775 

 

Other

 

56,336 

 

 

57,949 

 

 

Total other assets

 

580,233 

 

 

575,157 

 

 

 

 

 

 

 

 

**Total**

$

3,234,172 

 

$

3,106,108 

 

 

 

 

 

 

The accompanying notes are an integral part ofthese statements.

 

 

 

 

**IDACORP, Inc.Consolidated Balance Sheets**

 

**December 31,**

 

**2004**

 

**2003**

**Liabilities and Shareholders'  Equity**

**(thousands of dollars)**

 

 

 

 

**Current Liabilities:**

 

 

 

 

 

 

Current maturities of long-term debt

$

78,603 

 

$

67,923 

 

Notes payable

 

36,270 

 

 

93,650 

 

Accounts payable

 

79,156 

 

 

60,916 

 

Energy marketing liabilities

 

9,420 

 

 

4,317 

 

Taxes accrued

 

46,318 

 

 

45,601 

 

Interest accrued

 

14,426 

 

 

13,741 

 

Other

 

21,265 

 

 

25,557 

 

 

Total current liabilities

 

285,458 

 

 

311,705 

 

 

 

 

 

 

**Other Liabilities:**

 

 

 

 

 

 

Deferred income taxes

 

555,774 

 

 

554,715 

 

Energy marketing liabilities - long-term

 

16,635 

 

 

14,393 

 

Regulatory liabilities

 

275,854 

 

 

258,524 

 

Other

 

112,616 

 

 

104,290 

 

 

Total other liabilities

 

960,879 

 

 

931,922 

 

 

 

 

 

 

**Long-Term Debt**

 

979,549 

 

 

945,834 

 

 

 

 

 

 

**Commitments and Contingencies**

 

 

 

 

 

 

 

 

 

 

 

**Preferred  Stock of Idaho Power Company**

 

- 

 

 

52,366 

 

 

 

 

 

 

**Shareholders' Equity:**

 

 

 

 

 

 

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

 

 

 

 

 

 

 

42,373,758 and 38,341,358 shares issued,  respectively)

 

589,440 

 

 

472,902 

 

Retained earnings

 

424,312 

 

 

397,167 

 

Accumulated other comprehensive income (loss)

 

(888)

 

 

(2,630)

 

Treasury stock (156,741 and 110,748 shares at  cost, respectively)

 

(4,578)

 

 

(3,158)

 

 

Total shareholders' equity

 

1,008,286 

 

 

864,281 

 

 

 

 

 

 

 

 

 

**Total**

$

3,234,172 

 

$

3,106,108 

 

 

 

 

 

 

The accompanying notes are an integral part ofthese statements.

 

 

 

 

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

 

 

**Year Ended December 31,**

 

 

**2004**

 

**2003**

 

**2002**

 

 

**(thousands of dollars)**

**Operating  Activities:**

 

 

Net  income

$

72,983 

 

$

46,578 

 

$

61,672 

 

Adjustments  to reconcile net income to net cash provided by

 

 

 

 

 

 

 

 

 

 

(used  in) operating activities:

 

 

 

 

 

 

 

 

 

 

Net  non-cash loss on legal disputes

 

- 

 

 

12,072 

 

 

- 

 

 

Impairment  of long-lived asset

 

9,075 

 

 

3,498 

 

 

8,064 

 

 

Unrealized  losses from energy marketing activities

 

131 

 

 

42,517 

 

 

65,965 

 

 

Depreciation  and amortization

 

124,192 

 

 

129,070 

 

 

122,831 

 

 

Deferred  taxes and investment tax credits

 

(33,912)

 

 

(56,174)

 

 

(110,491)

 

 

Change  in regulatory assets and liabilities

 

16,788 

 

 

68,358 

 

 

164,201 

 

 

Gain  on sales of non-utility assets

 

(4,475)

 

 

- 

 

 

- 

 

 

Gain  on extinguishment of debt

 

(7,188)

 

 

- 

 

 

- 

 

 

Change  in:

 

 

 

 

 

 

 

 

 

 

 

Accounts  receivables and prepayments

 

(1,442)

 

 

94,529 

 

 

28,531 

 

 

 

Accounts  payable and other accrued liabilities

 

15,806 

 

 

(70,342)

 

 

(145,868)

 

 

 

Taxes  receivable/accrued

 

717 

 

 

(16,797)

 

 

98,795 

 

 

 

Other  current assets

 

(4,568)

 

 

7,020 

 

 

5,332 

 

 

 

Other  current liabilities

 

(1,309)

 

 

(6,412)

 

 

40,614 

 

 

 

Long-term  receivable

 

- 

 

 

51,394 

 

 

- 

 

 

Other  assets

 

649 

 

 

(4,527)

 

 

6,735 

 

 

Other  liabilities

 

7,249 

 

 

12,065 

 

 

6,921 

 

 

Net  cash provided by operating activities

 

194,696 

 

 

312,849 

 

 

353,302 

**Investing Activities:**

 

 

 

 

 

 

 

 

 

Additions  to property, plant and equipment

 

(199,770)

 

 

(149,643)

 

 

(137,442)

 

Sale  of non-utility assets

 

5,554 

 

 

494 

 

 

3,219 

 

Investments  in affordable housing projects

 

(7,655)

 

 

76 

 

 

(43,939)

 

Purchase  of available-for-sale securities

 

(295,356)

 

 

(13,689)

 

 

(16,530)

 

Sale  of available-for-sale securities

 

266,331 

 

 

14,040 

 

 

6,815 

 

Purchase  of held-to-maturity securities

 

(4,927)

 

 

(10,547)

 

 

(13,671)

 

Maturity  of held-to-maturity securities

 

7,730 

 

 

7,571 

 

 

9,713 

 

Other  assets

 

- 

 

 

(127)

 

 

2,009 

 

Other  liabilities

 

(1,547)

 

 

(98)

 

 

(737)

 

 

Net  cash used in investing activities

 

(229,640)

 

 

(151,923)

 

 

(190,563)

**Financing Activities:**

 

 

 

 

 

 

 

 

 

Issuance  of long-term debt

 

106,442 

 

 

255,292 

 

 

200,000 

 

Retirement  of long-term debt

 

(79,890)

 

 

(230,003)

 

 

(89,403)

 

Retirement  of preferred stock of Idaho Power Company

 

(52,351)

 

 

(860)

 

 

(50,994)

 

Dividends  on common stock

 

(45,838)

 

 

(64,726)

 

 

(70,178)

 

Decrease  in short-term borrowings

 

(58,250)

 

 

(82,550)

 

 

(186,300)

 

Issuance  of common stock 

 

115,690 

 

 

4,123 

 

 

15,770 

 

Acquisition  of treasury shares

 

(1,420)

 

 

(799)

 

 

(1,206)

 

Other  assets

 

(1,145)

 

 

(8,404)

 

 

(4,011)

 

Other  liabilities

 

(50)

 

 

(576)

 

 

(369)

 

 

Net  cash used in financing activities

 

(16,812)

 

 

(128,503)

 

 

(186,691)

Net  increase (decrease) in cash and cash equivalents

 

(51,756)

 

 

32,423 

 

 

(23,952)

Cash and cash  equivalents at beginning of year

 

75,159 

 

 

42,736 

 

 

66,688 

Cash  and cash equivalents at end of year

$

23,403 

 

$

75,159 

 

$

42,736 

 

**Supplemental  Disclosure of Cash Flow Information:**

 

Cash  paid (received) during the year for:

 

 

 

 

 

 

 

 

 

 

Income  taxes

$

7,742 

 

$

52,882 

 

$

(39,678)

 

 

Interest  (net of amount capitalized)

$

55,122 

 

$

58,931 

 

$

62,665 

 

The accompanying notes are an integral partof 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,

 

 

 

 

 

 

 

 

 

 

 

 

 

2002

37,629 

$

451,404

$

424,349 

$

(3,719)

1 

$

(33)

$

872,001 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net  income

- 

 

- 

 

61,672 

 

- 

- 

 

- 

 

61,672 

Common  stock dividends

 

 

 

 

 

 

 

 

 

 

 

 

 

($1.86  per share)

- 

 

- 

 

(70,178)

 

- 

- 

 

- 

 

(70,178)

Issued

523 

 

15,770 

 

- 

 

- 

- 

 

- 

 

15,770 

Acquired

- 

 

- 

 

- 

 

- 

31 

 

(1,206)

 

(1,206)

Other

- 

 

1,067 

 

(528)

 

- 

52 

 

(381)

 

158 

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 

 

468,241 

 

415,315 

 

(7,109)

84 

 

(1,620)

 

874,827 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net  income

- 

 

- 

 

46,578 

 

- 

- 

 

- 

 

46,578 

Common  stock dividends

 

 

 

 

 

 

 

 

 

 

 

 

 

($1.70  per share)

- 

 

- 

 

(64,726)

 

- 

- 

 

- 

 

(64,726)

Issued

189 

 

4,123 

 

- 

 

- 

- 

 

- 

 

4,123 

Acquired

- 

 

- 

 

- 

 

- 

9 

 

(799)

 

(799)

Other

- 

 

538 

 

- 

 

- 

18 

 

(739)

 

(201)

Unrealized  gain on

 

 

 

 

 

 

 

 

 

 

 

 

 

securities  (net of tax)

- 

 

- 

 

- 

 

4,809 

- 

 

- 

 

4,809 

Minimum  pension

 

 

 

 

 

 

 

 

 

 

 

 

 

liability  adjustment

 

 

 

 

 

 

 

 

 

 

 

 

 

(net  of tax)

- 

 

- 

 

- 

 

(330)

- 

 

- 

 

(330)

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance  at December 31,

 

 

 

 

 

 

 

 

 

 

 

 

 

2003

38,341 

 

472,902 

 

397,167 

 

(2,630)

111 

 

(3,158)

 

864,281 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net  income

- 

 

- 

 

72,983 

 

- 

- 

 

- 

 

72,983  

Common  stock dividends

 

 

 

 

 

 

 

 

 

 

 

 

 

($1.20  per share)

- 

 

- 

 

(45,838)

 

- 

- 

 

- 

 

(45,838)

Issued

4,033 

 

115,690 

 

- 

 

- 

- 

 

- 

 

115,690 

Acquired

- 

 

- 

 

- 

 

- 

46 

 

(1,420)

 

(1,420)

Other

- 

 

848 

 

- 

 

-  

- 

 

- 

 

848 

Unrealized  gain on

 

 

 

 

 

 

 

 

 

 

 

 

 

securities  (net of tax)

- 

 

- 

 

- 

 

862 

-  

 

- 

 

862 

Minimum  pension

 

 

 

 

 

 

 

 

 

 

 

 

 

liability  adjustment

 

 

 

 

 

 

 

 

 

 

 

 

 

(net  of tax)

- 

 

- 

 

- 

 

880 

- 

 

- 

 

880 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance  at December 31,

 

 

 

 

 

 

 

 

 

 

 

 

 

2004

42,374 

$

589,440 

$

424,312 

$

(888)

157 

$

(4,578)

$

1,008,286 

 

 

 

 

 

 

 

 

 

 

 

 

 

The accompanying notes are an integral part of thesestatements.

** **

** **

** **

** **

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

 

**Year  Ended December 31,**

 

**2004**

 

**2003**

 

**2002**

 

**(thousands  of dollars)**

 

 

 

 

 

 

 

 

 

**Net Income**

$

72,983 

 

$

46,578 

 

$

61,672 

 

 

 

 

 

 

 

 

 

**Other Comprehensive Income (Loss):**

 

 

 

 

 

 

 

 

 

Unrealized gains (losses) on securities:

 

 

 

 

 

 

 

 

 

 

Unrealized holding gains (losses) arising during the  year,

 

 

 

 

 

 

 

 

 

 

 

net of tax of $1,234,   $2,963 and ($1,840) 

 

2,057 

 

 

4,982 

 

 

(2,991)

 

 

Reclassification adjustment for (gains) losses included

 

 

 

 

 

 

 

 

 

 

 

in net income, net of tax of ($768), ($111) and $1,007 

 

(1,195)

 

 

(173)

 

 

1,560 

 

 

 

Net unrealized gains (losses)

 

862 

 

 

4,809 

 

 

(1,431)

 

Minimum pension liability adjustment, net of tax of  $565, 

 

 

 

 

 

 

 

 

 

 

($191) and ($1,265)

 

880 

 

 

(330)

 

 

(1,959)

 

 

 

 

 

 

 

 

 

**Total Comprehensive Income**

$

74,725 

 

$

51,057 

 

$

58,282 

 

 

 

 

 

 

 

 

 

Theaccompanying notes are an integral part of these statements

 

 

 

 

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

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

**Nature of Business**IDACORP,Inc. (IDACORP) is a holding company whose principal operating subsidiary isIdaho Power Company (IPC).  IDACORP isexempt from registration as a public utility holding company pursuant toSection 3(a)(1) of the Public Utility Holding Company Act of 1935 (1935Act).  In addition, pursuant to Rule 2of the General Rules and Regulations under the 1935 Act, IDACORP is exempt fromall the provisions of the 1935 Act and rules thereunder, except for Section9(a)(2) of the 1935 Act, which requires IDACORP to seek prior Securities andExchange Commission approval to acquire securities of another public utilitycompany.

IPCis an electric utility engaged in the generation, transmission, distribution,sale and purchase of electric energy. IPC is regulated by the Federal Energy Regulatory Commission (FERC) andthe state regulatory commissions of Idaho and Oregon.  IPC is the parent of Idaho Energy Resources Co., a joint venturerin Bridger Coal Company, which supplies coal to the Jim Bridger generatingplant owned in part by IPC.

IDACORP'sother operating subsidiaries include:

IDACORPFinancial Services, Inc. (IFS) - holder of affordable housing and other realestate investments;

IdaTech- developer of integrated fuel cell systems;

IDACOMM- provider of telecommunications services and commercial and residentialInternet services; and

Ida-WestEnergy (Ida-West) - operator of independent power projects.

IDACORPEnergy (IE), a marketer of electricity and natural gas, wound down itsoperations during 2003.  Also in 2003,Ida-West discontinued its project development operations and is managing itsindependent power projects with a reduced workforce.

In2004, IDACORP transferred its ownership of RMC Holdings, Inc. and itssubsidiary Velocitus to IDACOMM.  InJanuary 2005, RMC Holdings, Inc. and Velocitus were merged into IDACOMM.

**Principles of Consolidation**Theconsolidated financial statements of IDACORP and IPC include the accounts ofeach company and those variable interest entities (VIEs) for which thecompanies are the primary beneficiaries. All significant intercompany balances have been eliminated inconsolidation.  Investments in businessentities in which IDACORP and IPC are not the primary beneficiaries, but havethe ability to exercise significant influence over operating and financialpolicies, are accounted for using the equity method.

Theentities that IDACORP and IPC consolidate consist primarily of wholly-owned orcontrolled subsidiaries.  In addition,IDACORP consolidates the following VIEs:

Ida-Westparticipates in Marysville Hydro Partners, a joint venture that owns a smallhydroelectric project.  Marysville HydroPartners has approximately $22 million of assets, primarily the hydroelectricplant, and approximately $18 million of intercompany long-term debt, which iseliminated in consolidation.

IFSis a limited partner in Empire Development Company, LLC, an entity that earnshistoric tax credits through the rehabilitation of the Empire Building inBoise, Idaho.  Empire DevelopmentCompany, LLC has approximately $8 million of assets, primarily real property,and $8 million of long-term debt.  Thisdebt is non-recourse to IDACORP, personally guaranteed by the general partner andcollateralized by the property.

ThroughIFS, IDACORP also holds significant variable interests in VIEs for which it isnot the primary beneficiary.  These VIEsare historic rehabilitation and affordable housing developments in which IFSholds limited partnership interests ranging from five to 99 percent.  These investments were acquired between 1996and 2004.  IFS's maximum exposure toloss in these developments totaled $109 million at December 31, 2004.

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

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

**Property, Plant and Equipment and Depreciation**The cost of utility plant in service represents the original cost ofcontracted services, direct labor and material, Allowance for Funds Used DuringConstruction (AFDC) and indirect charges for engineering, supervision andsimilar overhead items.  Maintenance andrepairs of property and replacements and renewals of items determined to beless than units of property are expensed to operations.  Repair and maintenance costs associated withplanned major maintenance are recorded as these costs are incurred.  For utility property replaced or renewed,the original cost plus removal cost less salvage is charged to accumulatedprovision for depreciation, while the cost of related replacements and renewalsis added to property, plant and equipment.

All utility plant inservice is depreciated using the straight-line method at rates approved byregulatory authorities.  Annualdepreciation provisions as a percent of average depreciable utility plant inservice approximated 2.96 percent in 2004, 2.99 percent in 2003 and 3.00percent in 2002.

Long-livedassets are periodically reviewed for impairment when events or changes incircumstances indicate that the carrying amount of an asset may not berecoverable as prescribed under Statement of Financial Accounting Standards(SFAS) 144, "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.

**Allowance for Funds Used During Construction**AFDC represents the cost of financing construction projects withborrowed funds and equity funds.  Whilecash is not realized currently from such allowance, it is realized under therate-making process over the service life of the related property throughincreased revenues resulting from a higher rate base and higher depreciationexpense.  The component of AFDCattributable to borrowed funds is included as a reduction to interest expense,while the equity component is included in other income.  IPC's weighted-average monthly AFDC ratesfor 2004, 2003 and 2002 were 6.9 percent, 8.3 percent and  4.3 percent, respectively.  IPC's reductions to interest expense forAFDC were $3 million for both 2004 and 2003 and $2 million for 2002.  Other income included $4 million, $3 millionand $0.3 million for 2004, 2003 and 2002, 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.

IEreports marketing and trading revenues and expenses on a net basis, using themark-to-market method of accounting. Energy marketing revenues include sales of electricity and gas nettedagainst purchases, whether physically settled or net settled.  Additionally, all financial transactions andunrealized income are presented on a net basis in operating revenues.  Other cost of revenue items such astransmission and broker fees are 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 customers.  These adjustments are based on forecasts ofnet power supply costs, which are fuel and purchased power less off-systemsales, and the true-up of the prior year's forecast.  During the year, 90 percent of the difference between the actualand forecasted costs is deferred with interest.  The ending balance of this deferral, called the true-up for thecurrent year's portion and the true-up of the true-up for the prior years'unrecovered portion, is then included in the calculation of the next year'sPCA.

**Income Taxes**The liability method of computing deferred taxes is used on alltemporary differences between the book and tax basis of assets and liabilitiesand deferred tax assets and liabilities are adjusted for enacted changes in taxlaws or rates.  Consistent with ordersand directives of the Idaho Public Utilities Commission (IPUC), the regulatoryauthority having principal jurisdiction, IPC's deferred income taxes (commonlyreferred to as normalized accounting) are provided for the difference betweenincome tax depreciation and straight-line depreciation computed using booklives on coal-fired generation facilities and properties acquired 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 incometaxes are not provided for those income tax timing differences where theprescribed regulatory accounting methods do not provide for current recovery inrates.  Regulated enterprises arerequired to recognize such adjustments as regulatory assets or liabilities ifit is probable that such amounts will be recovered from or returned tocustomers in future rates.  See Note 2for more information.

TheState of Idaho allows a three-percent investment tax credit on qualifying plantadditions.  Investment tax creditsearned on regulated assets are deferred and amortized to income over theestimated service lives of the related properties.  Credits earned on non-regulated assets or investments arerecognized in the year earned.

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

Thediluted EPS computation excluded 818,600 common stock options in 2004, 721,800in 2003 and 849,000 in 2002, because the options' exercise prices were greaterthan the average market price of the common stock during those years.  In total, 1,211,800 options were outstandingat December 31, 2004, with expiration dates between 2010 and 2014.

**Stock-BasedCompensation******Stock-based employee compensation is accounted for under therecognition and measurement principles of Accounting Principles Board (APB)Opinion 25, "Accounting for Stock Issued to Employees," and relatedinterpretations.  Grants of performanceshares are reflected in net income based on the market value at the award date,or the period-end price for shares not yet vested.  Grants of restricted stock are reflected in net income based onthe market value on the grant date.  Nostock-based employee compensation cost is reflected in net income for stockoptions, as all options granted had an exercise price equal to the market valueof the underlying common stock on the date of grant.  IDACORP and IPC have adopted the disclosure only provision ofSFAS 123, "Accounting for Stock-Based Compensation."

Thefollowing table illustrates the effect on net income and EPS if the fair valuerecognition provisions of SFAS 123 had been applied to stock-based employeecompensation:

 

**2004**

 

**2003**

 

**2002**

 

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

 

 

 

 

 

 

 

 

 

Net income, as reported

$

72,983 

 

$

46,578 

 

$

61,672 

Add: Stock-based employee compensation expense

 

 

 

 

 

 

 

 

 

included in reported net income, net of related

 

 

 

 

 

 

 

 

 

tax effects

 

399 

 

 

(76)

 

 

(9)

Deduct: Total stock-based  employee compensation

 

 

 

 

 

 

 

 

 

expense determined under fair  value based 

 

 

 

 

 

 

 

 

 

method for all awards, net of  related tax effects

 

1,169 

 

 

1,169 

 

 

1,958 

 

 

Pro forma net income

$

72,213 

 

$

45,333 

 

$

59,705 

EPS of common stock:

 

 

 

 

 

 

 

 

 

Basic and diluted - as  reported

$

1.90 

 

$

1.22 

 

$

1.63 

 

Basic and diluted - pro forma

 

1.88 

 

 

1.19 

 

 

1.58 

 

For purposes of these pro formacalculations, the estimated fair value of the options, restricted stock andperformance shares are amortized to expense over the vesting period.  The fair value of the restricted stock andperformance shares is the market price of the stock on the date of grant.  The fair value of an option award isestimated at the date of grant using a binomial option-pricing model.  Expense related to forfeited options isreversed in the period in which the forfeit occurs.  For more information see Note 9.

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

**Derivative Financial 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 the purchaseand sale of electricity and natural gas as well as to optimize energy marketingportfolios.  The accounting forderivative financial instruments that are used to manage risk is in accordancewith the concepts established by SFAS 133, "Accounting for DerivativeInstruments and Hedging Activities," as amended.

**Regulation of Utility Operations**IPC follows SFAS 71, "Accounting for the Effects of CertainTypes of Regulation," and its financial statements reflect the effects ofthe different rate-making principles followed by the jurisdictions regulatingIPC.  The economic effects of regulationcan result in regulated companies recording costs that have been, or areexpected to be, allowed in the rate-making 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 imposeregulatory liabilities upon a regulated company for amounts previouslycollected from customers and for amounts that are expected to be refunded tocustomers.

**Comprehensive Income**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 loss balance at December 31:

 

**2004**

 

**2003**

 

**(thousands  of dollars)**

Unrealized holding gains on securities

$

4,538 

 

$

3,676 

Minimum pension liability adjustment

 

(5,426)

 

 

(6,306)

 

Total

$

(888)

 

$

(2,630)

 

 

 

 

 

 

 

**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.

Theannual impairment tests have been completed on IDACORP's $14 million goodwillbalance, which is related to the acquisitions of IdaTech and Velocitus.  Velocitus' test was performed as of June 30,2004 and IdaTech's as of September 30, 2004. No impairment was noted in these tests. Goodwill impairment tests will continue to be performed at least annually,and more frequently if circumstances indicate a possible impairment.  Goodwill is included in other assets onIDACORP's Consolidated Balance Sheets.

**Adopted AccountingPronouncement**In January 2004,IDACORP and IPC adopted Financial Accounting Standards Board (FASB)Interpretation (FIN) 46R, "Consolidation of Variable Interest Entities -an interpretation of ARB No. 51," which addresses consolidation bybusiness enterprises of VIEs, which have one or more of the followingcharacteristics:
- The equity     investment at risk is not sufficient to permit the entity to finance its     activities without additional subordinated financial support provided by     any parties, including the equity holders;
- The equity investors     lack one or more of the following essential characteristics of a     controlling financial interest:
The direct or      indirect ability to make decisions about the entity's activities through      voting rights or similar rights;
The obligation to      absorb the expected losses of the entity;
The right to      receive the expected residual returns of the entity; and

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

 

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

**New Accounting Pronouncements****SFAS 151:** In November 2004, the FASB issued SFAS 151, "InventoryCosts," which clarifies the accounting for certain inventory-relatedcosts.  SFAS 151 is effective forinventory costs incurred during fiscal years beginning after June 15, 2005, andis not expected to have a material effect on IDACORP's or IPC's financialstatements.

**SFAS 153:** InDecember 2004, the FASB issued SFAS 153, "Exchanges of NonmonetaryAssets," which amends existing guidance on accounting for nonmonetary transactions.  SFAS 153 is effective for exchangesoccurring in fiscal periods beginning after June 15, 2005, and is not expectedto have a material effect on IDACORP's or IPC's financial statements.

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

Under the provisions of SFAS123(R), the fair value of all stock options must be reported as an expense onthe financial statements.  IDACORP andIPC currently apply the measurement provisions of APB 25 and thedisclosure-only provisions of SFAS 123. SFAS 123(R) also changes other measurement, timing and disclosure rulesrelating to share-based payments.

SFAS 123(R) is effective formost public entities as of the beginning of the first interim or annualreporting period beginning after June 15, 2005.  IDACORP and IPC expect to adopt SFAS 123(R) on July 1, 2005, andadoption is expected to decrease IDACORP's and IPC's pre-tax income byapproximately $0.6 million in 2005. Stock-based compensation arrangements are discussed in Note 9.

**FSP FAS106-2:**  See Note 10 fora discussion of this FSP, which relates to postretirement benefit obligations.

**Other Accounting 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 2004 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 the statutoryfederal income tax rate and the effective rate is as follows:

 

 

**2004**

 

**2003**

 

**2002**

 

 

**(thousands of dollars)**

Federal income tax expense at 35% statutory rate

$

16,875 

 

$

8,911 

 

$

3,684 

Change in taxes resulting from:

 

 

 

 

 

 

 

 

 

AFDC

 

(2,400)

 

 

(2,343)

 

 

(948)

 

Investment tax credits

 

(3,295)

 

 

(3,397)

 

 

(3,179)

 

Repair allowance

 

(2,450)

 

 

(2,450)

 

 

(2,450)

 

Removal costs

 

(1,244)

 

 

(1,101)

 

 

(815)

 

Pension accrual

 

1,237 

 

 

2,456 

 

 

(26)

 

Capitalized overhead costs

 

(3,658)

 

 

(3,658)

 

 

(3,500)

 

Regulatory tax liability

 

(16,457)

 

 

- 

 

 

- 

 

Tax accounting method change

 

- 

 

 

- 

 

 

(31,162)

 

Settlement of prior years tax returns

 

(1,876)

 

 

(8,911)

 

 

(2,971)

 

State income taxes, net of federal benefit

 

2,923 

 

 

1,357 

 

 

514 

 

Depreciation

 

4,350 

 

 

10,237 

 

 

8,940 

 

Affordable housing and historic tax credits 

 

(21,717)

 

 

(20,345)

 

 

(20,863)

 

Preferred dividends of IPC

 

1,688 

 

 

1,200 

 

 

1,606 

 

Other, net

 

1,254 

 

 

(3,075)

 

 

23 

Total income tax benefit

$

(24,770)

 

$

(21,119)

 

$

(51,147)

 

Effective tax rate

 

(51.4%)

 

 

(83.0%)

 

 

(486.0%)

 

The items comprising incometax expense are as follows:

 

 

**2004**

 

**2003**

 

**2002**

 

 

**(thousands of dollars)**

Income taxes currently payable:

 

 

 

 

 

 

 

 

 

Federal

$

6,087 

 

$

26,356 

 

$

46,541 

 

State

 

3,055 

 

 

8,699 

 

 

12,803 

 

 

Total

 

9,142 

 

 

35,055 

 

 

59,344 

Income taxes deferred:

 

 

 

 

 

 

 

 

 

Federal

 

(30,646)

 

 

(44,938)

 

 

(95,185)

 

State

 

(2,313)

 

 

(11,465)

 

 

(14,850)

 

 

Total

 

(32,959)

 

 

(56,403)

 

 

(110,035)

Investment tax credits:

 

 

 

 

 

 

 

 

 

Deferred

 

2,342 

 

 

3,627 

 

 

2,722 

 

Restored

 

(3,295)

 

 

(3,398)

 

 

(3,178)

 

 

Total

 

(953)

 

 

229 

 

 

(456)

Total income tax benefit

$

(24,770)

 

$

(21,119)

 

$

(51,147)

 

Thecomponents of IDACORP's net deferred tax liability are as follows:

 

2004

 

2003

 

**(thousands  of dollars)**

Deferred tax assets:

 

 

 

 

 

 

Regulatory liabilities

$

40,447

 

$

41,024

 

Advances for construction

 

5,357

 

 

4,162

 

Deferred compensation

 

14,001

 

 

13,608

 

Tax credits

 

28,211

 

 

10,021

 

Other

 

15,737

 

 

13,829

 

 

Total

 

103,753

 

 

82,644

Deferred tax liabilities:

 

 

 

 

 

 

Property, plant and equipment

 

241,324

 

 

238,602

 

Regulatory assets

 

344,220

 

 

330,833

 

Conservation programs

 

6,972

 

 

8,310

 

PCA

 

20,516

 

 

27,529

 

Partnership investments

 

19,975

 

 

16,728

 

Other

 

3,113

 

 

10,975

 

 

Total

 

636,120

 

 

632,977

Net deferred tax liabilities

$

532,367

 

$

550,333

** **

**Status of Audit Proceedings**The Internal Revenue Service has examined federal income tax returnsfor years through 2000 and all issues have been settled.  Applicable state tax return amendments werecompleted in 2004 and settled.  Finalizationof these examinations resulted in deficiencies that were less than previouslyaccrued, enabling IDACORP to decrease income tax expense by $2 million in 2004,$9 million in 2003 and $3 million in 2002.

**Regulatory Settlement**In Settlement No. 2, as more fully discussed in Note 13, IPC and the IPUCfinalized an income tax issue from IPC's 2003 Idaho general rate case.  The issue concerned the regulatoryaccounting treatment for the capitalized overhead cost tax method IPC adoptedin the 2001 IDACORP federal income tax return. As a result of Settlement No. 2, a $16 million regulatory tax liabilitywas reversed to income tax expense in the third quarter of 2004.

**Tax Credits**As of December 31, 2004, IDACORP had $22 million of general business creditcarryforward for federal income tax purposes. Additionally, IDACORP had $6 million of Idaho investment tax creditcarryforward.  The general businesscredit carryforward period expires in 2024 and the Idaho investment tax creditexpires from 2016 to 2018.  Managementbelieves the utilization of these credits is more likely than not.

**TaxAccounting Method Change**During the third quarter of 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 the construction of plant, while the newmethod allocates such costs to both construction of plant and the production ofelectricity.

Theeffect of the tax accounting method change was recorded as a decrease to incometax expense for the year ended December 31, 2002 of $35 million, of which $31million was attributable to 2001 and prior tax years, and $4 million wasattributable to the 2002 tax year.  Thedecrease to tax expense was a result of deductions on the applicable taxreturns 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 are requiredto recognize such adjustments as regulatory assets if it is probable that suchamounts will be recovered from customers in future rates.

**American Jobs Creation Act of2004:**In October 2004, the president signed into law theAmerican Jobs Creation Act of 2004 (the Act), which may have tax implicationsfor IDACORP and IPC.  One provision ofthe Act with potential implications for the companies relates to manufacturingtax incentives for the production of electricity beginning in 2005.  Taxpayers will be able to deduct apercentage (three percent in 2005 and 2006, six percent in 2007 through 2009and nine percent in 2010 and thereafter) of the lesser of their qualifiedproduction activities income or their taxable income.  Management is currently reviewing this and other aspects of theAct to determine the impact on the companies.

**3.  COMMON STOCK:**

Sharesof common stock were reserved for the following purposes at December 31:

 

**2004**

 

**2003**

Dividend reinvestment and  stock purchase plan and employee savings plan

6,062,314

 

6,062,314

Restricted stock plan

314,114

 

314,114

Long-term incentive and  compensation plan

2,042,600

 

2,050,000

 

Total shares reserved

8,419,028

 

8,426,428

 

 

 

 

 

 

In2001, IDACORP acquired 198,200 shares of outstanding common stock, at a cost of$8 million, for potential distribution to shareholders of an acquired entity aspartial payment for the acquisition.  In2000, IDACORP acquired 156,300 shares at a cost of $7 million for the same purpose.  As of December 31, 2004, IDACORP had issued242,371 shares to the shareholders of the acquired entity including 1,167shares in 2004.  Of the remainingacquired shares, 71,755 had been issued, primarily in connection with IDACORP'sDividend Reinvestment Program (DRIP).

IDACORPhas issued shares of common stock for its DRIP and Employee Savings Plan,although no shares were issued for the DRIP or the Employee Savings Plan in2004.  In 2003, IDACORP issued 122,990shares for the DRIP and 65,932 shares for the Employee Savings Plan.  For additional information related to theEmployee Savings Plan, see Note 10.

In2004, IDACORP purchased 45,988 shares for its 1994 Restricted Stock Plan andissued 7,400 shares pursuant to the exercise of stock options granted under the2000 Long-Term Incentive and Compensation Plan.

OnDecember 15, 2004, IDACORP issued 4,025,000 shares of its common stock in apublic offering for net proceeds of $116 million.

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

Additionally,the IDACORP Board of Directors created the A Series Preferred Stock, withoutpar value, and reserved 1,200,000 shares for issuance upon exercise of theRights.

Followingthe acquisition of a 20 percent or greater position, each Right will entitleits holder to purchase, for $95, that number of shares of common stock orpreferred stock having a market value of $190.

If afterthe Rights become exercisable, IDACORP is acquired in a merger or otherbusiness combination, 50 percent or more of its consolidated assets or earningspower are sold, or the Acquiring Person engages in certain acts ofself-dealing, each Right entitles the holder to purchase, for $95, shares ofthe acquiring company's common stock having a market value of $190.

AnyRights that are or were held by an Acquiring Person become void if any of theseevents occurs.  The Rights expire onSeptember 30, 2008.

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

**Dividend Restrictions**IPC's articles of incorporation contain restrictions on the paymentof dividends on its common stock if preferred stock dividends are inarrears.  On September 20, 2004, IPCredeemed all of its outstanding preferred stock.  Also, certain provisions of credit facilities containrestrictions on the ratio of debt to total capitalization.

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

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

The number of shares ofIPC preferred stock outstanding at December 31 were as follows:

 

**Shares Outstanding at**

 

**December 31,**

 

**2004**

 

**2003**

Preferred stock:

 

 

 

Cumulative, $100 par value:

 

 

 

 

4% preferred stock (authorized 215,000 shares)

-

 

123,664

 

Serial preferred stock, 7.68% Series (authorized  150,000 shares)

-

 

150,000

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

 

 

Total

-

 

523,664

 

 

 

 

 

On September 20, 2004,IPC redeemed all of its outstanding preferred stock for $54 million usingproceeds from the issuance of first mortgage bonds.  This amount includes $2 million of premium that was recorded aspreferred dividends on the Consolidated Statements of Income.  The redemption price was $104 per share forthe 122,989 shares of 4% preferred stock, $102.97 per share for the 150,000shares of 7.68% preferred stock and $103.18 per share for the 250,000 shares of7.07% preferred stock, plus accumulated and unpaid dividends.

During 2003 IPCreacquired and retired 10,263 shares of 4% preferred stock.

**5.  LONG-TERM DEBT:**

The following tablesummarizes long-term debt at December 31:

 

**2004**

 

**2003**

 

**(thousands of dollars)**

First mortgage bonds:

 

 

 

 

 

 

8     

%

 Series  due 2004

$

- 

 

$

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 

 

 

70,000 

 

6     

%

 Series due 2032

 

100,000 

 

 

100,000 

 

5.50 

%

 Series due 2033

 

70,000 

 

 

70,000 

 

5.50 

%

 Series due 2034

 

50,000 

 

 

- 

 

5.875

%

 Series due 2034

 

55,000 

 

 

- 

 

 

Total first mortgage bonds

 

785,000 

 

 

730,000 

Pollution control revenue bonds:

 

 

 

 

 

 

Variable Auction Rate Series 2003 due 2024 (a)

 

49,800 

 

 

49,800 

 

6.05     

%

 Series 1996A due 2026

 

68,100 

 

 

68,100 

 

Variable Rate Series 1996B due 2026

 

24,200 

 

 

24,200 

 

Variable Rate Series 1996C due 2026

 

24,000 

 

 

24,000 

 

Variable Rate Series 2000 due 2027

 

4,360 

 

 

4,360 

 

 

Total pollution control revenue bonds

 

170,460 

 

 

170,460 

REA notes

 

- 

 

 

1,105 

American Falls bond guarantee

 

19,885 

 

 

19,885 

Milner Dam note guarantee

 

11,700 

 

 

11,700 

Unamortized premium/discount - net

 

(3,135)

 

 

(2,205)

Debt related to investments in affordable housing

 

66,310 

 

 

82,715 

Other subsidiary debt

 

7,932 

 

 

97 

 

Total

 

1,058,152 

 

 

1,013,757 

Current maturities of long-term debt

 

(78,603)

 

 

(67,923)

 

 

Total long-term debt

$

979,549 

 

$

945,834 

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

bonds outstanding at December 31, 2004 to $834.8  million.

 

AtDecember 31, 2004, the maturities for the aggregate amount of long-term debtoutstanding were (in thousands of dollars):

 

**2005**

**2006**

**2007**

**2008**

**2009**

**Thereafter**

 

 

 

 

 

 

 

 

 

 

 

 

 

IPC  

$

60,000

$

-

$

81,064

$

1,064

$

81,064

$

760,718

Other  subsidiary debt

 

18,603

 

15,985

 

13,891

 

10,392

 

5,656

 

9,715

Total

$

78,603

$

15,985

$

94,955

$

11,456

$

86,720

$

770,433

 

IDACORP currently has two shelf registrationstatements totaling $679 million that can be used for the issuance of unsecureddebt (including medium-term notes) and preferred or common stock.

 

OnOctober 22, 2003, Humboldt County, Nevada issued, for the benefit of IPC, $49.8million Pollution Control Revenue Refunding Bonds (Idaho Power Company Project)Series 2003 due December 1, 2024.  IPCborrowed the proceeds from the issuance pursuant to a Loan Agreement withHumboldt County and is responsible for payment of principal, premium, if any,and interest on the bonds.  The bondsare secured, as to principal and interest, by IPC first mortgage bonds and asto principal and interest when due, by an insurance policy issued by AmbacAssurance Corporation.  The bonds wereissued in an auction rate mode under which the interest rate is reset every 35days.  The initial auction rate was setat 0.95 percent.  At December 31, 2004,the auction rate was 1.85 percent. Proceeds from this issuance together with other funds provided by IPCwere used to redeem the outstanding $49.8 million Pollution Control RevenueBonds (Idaho Power Company Project) 8.3% Series 1984 due 2014, on December 1,2003, at 103 percent.

OnMarch 14, 2003, IPC filed a $300 million shelf registration statement thatcould be used for first mortgage bonds (including medium-term notes), unsecureddebt and preferred stock.  On May 8,2003, IPC issued $140 million of secured medium-term notes in two series: $70million First Mortgage Bonds 4.25% Series due 2013 and $70 million FirstMortgage Bonds 5.50% Series due 2033. Proceeds were used to pay down IPC short-term borrowings incurred fromthe payment at maturity of $80 million First Mortgage Bonds 6.40% Series due2003 and the early redemption of $80 million First Mortgage Bonds 7.50% Seriesdue 2023, on May 1, 2003.  On March 26,2004, IPC issued $50 million First Mortgage Bonds 5.50% Series due 2034.  Proceeds were used to reduce short-termborrowings and replace short-term investments, which were used on March 15,2004 to pay at maturity the $50 million First Mortgage Bonds 8% Series due2004.  On August 16, 2004, IPC issued$55 million First Mortgage Bonds 5.875% Series due 2034.  On September 20, 2004, the proceeds of thisissuance were used to redeem all of IPC's outstanding preferred stock.  At December 31, 2004, $55 million remainedavailable to be issued on this shelf registration statement.

OnJanuary 19, 2005, IPC filed a $245 million shelf registration statement thatcould be used for first mortgage bonds (including medium-term notes) and debtsecurities.

On August 17, 2004, IPCredeemed all $1 million of its Rural Electrification Administration notes.

AtDecember 31, 2004 and 2003, the overall effective cost of all of IPC'soutstanding debt was 5.69 percent and 5.71 percent, respectively.

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, 2004, IPC could issueunder the mortgage approximately $699 million of additional first mortgagebonds based on unfunded property additions and $392 million of additional firstmortgage bonds based on retired first mortgage bonds.  At December 31, 2004, unfunded property additions, which consistof electric property, were approximately $1.1 billion.

At December 31, 2004, IFS had $66 million of debtrelated to investments in affordable housing with interest rates ranging from3.65 percent to 8.59 percent due between 2005 and 2010.  The investments in affordable housingdevelopments that collateralize this debt had a net book value of $110 millionat December 31, 2004.  IFS's $17 millionSeries 2003-1 tax credit note is non-recourse to both IFS and IDACORP.  The $11 million Series 2003-2 tax creditnote and other outstanding debt are recourse only to IFS.

In June 2004, Ida-Westpurchased from a third party $18 million of debt issued by Marysville HydroPartners, a 50-percent-owned, consolidated joint venture, for $11 million.  This debt, previously consolidated under theprovisions of FIN 46R, is now eliminated in consolidation.  Ida-West borrowed $6 million from IDACORP forthis transaction.

As aresult of IDACORP's adoption of FIN 46R in January 2004, other subsidiary debtincreased $8 million from December 31, 2003. This debt is non-recourse to IDACORP, personally guaranteed by thegeneral partner and collateralized by property.

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

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

Cash and cashequivalents, customer and other receivables, notes payable, accounts payable,interest accrued and taxes accrued are reported at their carrying value asthese are a reasonable estimate of their fair value.  The estimated fair values for notes receivable, long-term debtand investments are based upon quoted market prices of the same or similarissues or discounted cash flow analyses as appropriate.

 

**December  31, 2004**

 

**December  31, 2003**

 

**Carrying**

 

**Estimated**

 

**Carrying**

 

**Estimated**

 

**Amount**

 

Fair Value

 

**Amount**

 

**Fair  Value**

 

**(thousands  of dollars)**

**Assets:**

 

 

 

 

 

 

 

 

 

 

 

Notes receivable

$

10,376

 

$

10,245

 

$

11,576

 

$

11,590

Investments 

 

67,319

 

 

67,479

 

 

39,405

 

 

39,659

 

 

 

 

 

 

 

 

 

 

 

 

**Liabilities:**

 

 

 

 

 

 

 

 

 

 

 

Long-term debt

$

1,061,287

 

$

1,084,090

 

$

1,015,962

 

$

1,043,116

 

 

 

 

 

 

 

 

 

 

 

 

 

**7.  NOTES PAYABLE:**

IDACORP has a $150 millioncredit facility that expires on March 16, 2007.  Under this facility IDACORP pays a facility fee on thecommitment, quarterly in arrears, based on its rating for senior unsecuredlong-term debt securities without third-party credit enhancement as provided byMoody's Investors Service (Moody's) and Standard & Poor's Ratings Services(S&P).  Commercial paper may beissued up to the amounts supported by the bank credit facilities.  Commercial paper outstanding was $35 millionand $94 million at December 31, 2004 and 2003, respectively.

At December 31, 2004, IPC hadregulatory authority to incur up to $250 million of short-termindebtedness.  IPC has a $200 millioncredit facility that expires on March 16, 2007.  Under this facility IPC pays a facility fee on the commitment,quarterly in arrears, based on its rating for senior unsecured long-term debtsecurities without third-party credit enhancement as provided by Moody's andS&P.  IPC's commercial paper may beissued up to the amounts supported by the bank credit facilities.  There was no commercial paper outstanding atDecember 31, 2004 or 2003.

Balances and interestrates of IDACORP's short-term borrowings were as follows at December 31 (inthousands of dollars):

 

**2004**

 

**2003**

 

 

 

**Effective**

 

 

 

**Effective**

 

**Amount**

 

**Interest Rate**

 

**Amount**

 

**Interest Rate**

Commercial  Paper

$

35,400

 

 

2.52%

 

$

93,650

 

 

1.21%

Notes  Payable

 

870

 

 

3.24%

 

 

-

 

 

-

Balance

$

36,270

 

 

 

 

$

93,650

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

**8.  COMMITMENTS AND CONTINGENCIES:**

As of December 31, 2004, IPChad agreements to purchase energy from 71 cogeneration and small powerproduction (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 677,868megawatt-hours (MWh) at a cost of $40 million in 2004 and 654,131 MWh at a costof $38 million in 2003.

IPC has agreed to guarantee theperformance of reclamation activities at Bridger Coal Company of which IdahoEnergy Resources Co., a subsidiary of IPC, owns a one-third interest.  This guarantee, which is renewed eachDecember, was $60 million at December 31, 2004.  Bridger Coal Company has a reclamation trust fund set asidespecifically for the purpose of paying these reclamation costs and expects thatthe fund will be sufficient to cover all such costs.  Because of the existence of the fund, the estimated fair value ofthis guarantee is minimal.

In August 2003, IE sold itsforward book of electricity trading contracts to Sempra Energy Trading.  As part of the sale, IE entered into anIndemnity Agreement with Sempra Energy Trading guaranteeing the performance ofone of the counterparties.  The maximumamount payable by IE under the Indemnity Agreement is $20 million.  The indemnity agreement has been accountedfor in accordance with FIN 45, "Guarantor's Accounting and DisclosureRequirements for Guarantees, Including Indirect Guarantees of Indebtedness ofOthers," and did not have a significant effect on IDACORP's financialstatements.

From time to time IDACORP andIPC are a party to various legal claims, actions and complaints in addition tothose discussed below.  IDACORP and IPCbelieve that they have meritorious defenses to all lawsuits and legalproceedings.  Although they willvigorously defend against them, they are unable to predict with certaintywhether or not they will ultimately be successful.  However, based on the companies' evaluation, they believe thatthe resolution of these matters will not have a material adverse effect onIDACORP's or IPC's consolidated financial positions, results of operations orcash flows.

**LegalProceedings****Alves Dairy:**  On May 18, 2004, Herculano and FrancesAlves, dairy operators from Twin Falls, Idaho, brought suit against IPC inIdaho State District Court, Fifth Judicial District, Twin Falls County.  The plaintiffs seek unspecified monetarydamages for negligence and nuisance (allegedly allowing electrical current toflow in the earth, injuring the plaintiffs' right to use and enjoy theirproperty and adversely affecting their dairy herd).  On July 16, 2004, IPC filed an answer to Mr. and Mrs. Alves'complaint, denying all liability to the plaintiffs, and asserting certainaffirmative defenses.  The parties havebegun discovery in the case.  No trialdate has been scheduled.  On December14, 2004, IPC filed a motion with the District Court for permission to appealthe court's denial of IPC's Motion to Disqualify the trial judge, forcause.  The District Court granted themotion for permissive appeal.  OnFebruary 16, 2005, IPC filed a motion for permissive appeal with the IdahoSupreme Court.  If granted, the SupremeCourt will determine whether the District Court properly refused to disqualifythe trial judge for cause.

IPCintends to vigorously defend its position in this proceeding and believes thismatter, with insurance coverage, will not have a material adverse effect on itsconsolidated financial position, results of operations or cash flows.

**PublicUtility District No. 1 of Grays Harbor County, Washington:**  On October 15, 2002, Public Utility DistrictNo. 1 of Grays Harbor County, Washington (Grays Harbor) filed a lawsuit in theSuperior Court of the State of Washington, for the County of Grays Harbor,against IDACORP, IPC and IE.  On March9, 2001, Grays Harbor entered into a 20 Megawatt (MW) purchase transaction withIPC for the purchase of electric power from October 1, 2001 through March 31,2002, at a rate of $249 per MWh.  InJune 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 the alternative,Grays Harbor alleged that the contract should be rescinded or reformed.  Grays Harbor sought as damages an amountequal to the difference between $249 per MWh and the "fair value" ofelectric power delivered by IE during the period October 1, 2001 through March31, 2002.

IDACORP, IPC and IE had this action removed from thestate court to the U.S. District Court for the Western District of Washingtonat Tacoma.  On November 12, 2002, thecompanies filed a motion to dismiss Grays Harbor's complaint, asserting thatthe U.S. District Court lacked jurisdiction because the FERC has exclusivejurisdiction over wholesale power transactions and thus the matter is preemptedunder the Federal Power Act and barred by the filed-rate doctrine.  The court ruled in favor of the companies'motion to dismiss and dismissed the case with prejudice on January 28,2003.  On February 25, 2003, GraysHarbor filed a Notice of Appeal, appealing the final judgment of dismissal tothe U.S. Court of Appeals for the Ninth Circuit.  On August 10, 2004, the Ninth Circuit affirmed the dismissal ofGrays Harbor's complaint, finding that Grays Harbor's claims were preempted byfederal law and were barred by the filed-rate doctrine.  The court also remanded the case to allowGrays Harbor leave to amend its complaint to seek declaratory relief only as tocontract formation, and held that Grays Harbor could seek monetary relief, ifat all, only from the FERC, and not from the courts.  IDACORP, IPC and IE sought rehearing from the Ninth Circuitarguing that the court erred in granting leave to amend the complaint as such adeclaratory relief claim would be preempted and would be barred by thefiled-rate doctrine.  The Ninth Circuitdenied the rehearing request on October 25, 2004and the decision became final on November 12, 2004.  On that same date, the companies took steps to have the casetransferred and consolidated with other similar cases arising out theCalifornia energy crisis currently pending before the Honorable Robert H.Whaley, sitting by designation in the Southern District of California andpresiding over Multidistrict Litigation Docket No. 1405, regarding CaliforniaWholesale Electricity Antitrust Litigation. On November 18, 2004, Grays Harbor filed an amended complaint alleging thatthe contract was formed under circumstances of "mistake" as to an"artificial . . . power shortage." Grays Harbor asks that the contract therefore be declared"unenforceable" and found "unconscionable."  On December 23, 2004, the Judicial Panel onMultidistrict Litigation conditionally transferred the case to JudgeWhaley.  Grays Harbor is opposingtransfer, however, and the Judicial Panel on Multidistrict Litigation has yetto finally rule on the transfer. IDACORP, IE and IPC have not responded to the amended complaint as aresponse is not yet required.  Thecompanies plan to file a motion to dismiss the complaint.  The companies intend to vigorously defendtheir position on remand and believe this matter will not have a materialadverse effect on their consolidated financial positions, results of operationsor cash flows.

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

All defendants, including IPC and IDACORP,moved to dismiss the complaint in lieu of answering it.  The motions were based on the ground thatthe complaint seeks to set alternative electrical rates, which are exclusivelywithin the jurisdiction of the FERC and are barred by the filed-ratedoctrine.  A hearing on the motion todismiss was heard on March 26, 2004.  OnMay 28, 2004, the court granted IPC and IDACORP's motion to dismiss.  In June 2004, the Port of Seattle appealedthe court's decision to the U.S. Court of Appealsfor the Ninth Circuit.  The appeal has been fully briefed, however no date has yet beenset for oral argument.  Thecompanies intend to vigorously defend their position in this proceeding andbelieve these matters will not have a material adverse effect on theirconsolidated financial positions, results of operations or cash flows.

**Wah Chang: **On May 5, 2004, WahChang, a division of TDY Industries, Inc., filed two lawsuits in the U.S. District Court for the District of Oregon against numerousdefendants.  IDACORP, IE and IPC arenamed as defendants in one of the lawsuits. The complaints allege violations of federal antitrust laws, violationsof the Racketeer Influenced and Corrupt Organizations Act, violations of Oregonantitrust laws and wrongful interference with contracts.  Wah Chang's complaint is based onallegations relating to the western energy situation.  These allegations include bid rigging, falsely creatingcongestion and misrepresenting the source and destination of energy.  The plaintiff seeks compensatory damages of$30 million and treble damages.

On September 8,2004, this case was transferred and consolidated with other similar casescurrently pending before the Honorable Robert H. Whaley, sitting by designationin the Southern District of California and presiding over MultidistrictLitigation Docket No. 1405, regarding California Wholesale ElectricityAntitrust Litigation.  IDACORP, IE andIPC have not answered the complaint, as a response is not yet required.  The companies, along with the otherdefendants, subsequently filed a motion to dismiss the complaint, which washeard on January 20, 2005.  By orderdated February 11, 2005, the court granted the companies' and other defendants'motion to dismiss.  Thecompanies intend to vigorously defend their position in this proceeding andbelieve these matters will not have a material adverse effect on theirconsolidated financial positions, results of operations or cash flows.

**City of Tacoma:** On June 7, 2004, the Cityof Tacoma, Washington filed a lawsuit in the U.S. District Court for the Western District of Washington atTacoma against numerous defendants including IDACORP, IE and IPC.  The City of Tacoma's complaint allegesviolations of the Sherman Antitrust Act. The claimed antitrust violations are based on allegations of energymarket manipulation, false load scheduling and bid rigging andmisrepresentation or withholding of energy supply.  The plaintiff seeks compensatory damages of not less than $175million.

On September 8,2004, this case was transferred and consolidated with other similar casescurrently pending before the Honorable Robert H. Whaley, sitting by designationin the Southern District of California and presiding over MultidistrictLitigation Docket No. 1405, regarding California Wholesale Electricity AntitrustLitigation.  IDACORP, IE and IPC havenot answered the complaint, as a response is not yet required.  The companies, along with the otherdefendants, filed a motion to dismiss the complaint which was taken undersubmission by the court, without oral argument.  By order dated February 11, 2005, the court granted thecompanies' and other defendants' motion to dismiss.  The companies intend to vigorously defend their positionin this proceeding and believe these matters will not have a material adverseeffect on their consolidated financial positions, results of operations or cashflows.

**State of California Attorney General:**  The California AttorneyGeneral filed the complaint in this case in the California Superior Court inSan Francisco on May 30, 2002.  This isone of thirteen virtually identical cases brought by the Attorney Generalagainst various sellers of power in the California market, seeking civilpenalties pursuant to California's Unfair Competition Law, Business andProfessions Code Section 17200.  Section17200 defines unfair competition as any "unlawful, unfair or fraudulentbusiness act or practice . . . ." The Attorney General alleges that IPC engaged in unlawful conduct byviolating the Federal Power Act in two respects:  (1) by failing to file its rates with the FERC and (2) chargingunjust and unreasonable rates.  TheAttorney General alleged that there were "thousands of . . . sales orpurchases" for which IPC failed to file its rates, and that IPC chargedunjust and unreasonable rates on "thousands of occasions."  Pursuant to Business and Professions CodeSection 17206, the Attorney General seeks civil penalties of up to $2,500 foreach alleged violation.  On June 25,2002, IPC removed the action to federal court, and on July 25, 2002, theAttorney General filed a motion to remand back to state court.  On March 25, 2003, the court denied theAttorney General'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 Attorney Generalfiled a Notice of Appeal to the U.S. Courtof Appeals for the Ninth Circuit, appealing the court's decision granting IPC'smotion to dismiss.  Briefing on theappeal was completed in October 2003.  On October 12, 2004, the Ninth Circuit unanimously affirmedthe order denying remand and dismissing all of the Attorney General's actions,including the action against IPC.  TheAttorney General did not file a petition for rehearingin the Ninth Circuit and has not sought review from the U.S. Supreme Court.  As aresult, the Ninth Circuit's October 12, 2004 decision is final.

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

On April 22, 2002, more than a year after theinitial complaints were filed, two of the original defendants, Duke andReliant, filed separate cross-complaints against IPC and IE, and approximately30 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 Plaintiffs' MasterComplaint.  Duke and Reliant also seekdeclaratory relief as to the respective liability and conduct of each of thecross-defendants in the actions alleged in the Plaintiffs' MasterComplaint.  Reliant also asserted aclaim against IPC for alleged violations of the California Unfair CompetitionLaw, Business and Professions Code Section 17200.  As a buyer of electricity in California, Reliant seeks the samerelief from the cross-defendants, including IPC, as that sought by plaintiffsin the Plaintiffs' Master Complaint as to any power Reliant purchased throughthe California markets.

Some of the newly added defendants (foreigncitizens and federal agencies) removed that litigation to federal court.  IPC and IE, together with numerous otherdefendants added by the cross-complaints, have moved to dismiss these claims,and those motions were heard in September 2002, together with motions to remandthe case back to state court filed by the original plaintiffs.  On December 13, 2002, the U.S. District Court granted Plaintiffs' Motion to Remand tostate court, but did not issue a ruling on IPC and IE's motion to dismiss.  The U.S. Courtof Appeals for the Ninth Circuit granted certainDefendants and Cross-Defendants' Motions to Stay the Remand Order while theyappeal the order.  The briefing on theappeal was completed in December 2003.  On December 8, 2004, the Ninth Circuit issued its opinionin California v. NRG Energy, Inc., et al., which affirmed the district court'sremand of these cases to state court and dismissed certain federal governmentdefendants due to their sovereign immunity from suit.  Cross-defendant, Powerex Corp., sought Rehearing En Banc at theNinth Circuit arguing that while it is a government entity, it is not immunefrom suit but should be permitted to litigate in federal rather than statecourt.  If the case is returned to statecourt, the companies, and other cross-defendants, intend to re-file theirmotions to dismiss in state court, which had been filed in federal court butnever ruled upon.  The companies believethese matters will not have a material adverse effect on their consolidatedfinancial positions, results of operations or cash flow.

**WesternEnergy Proceedings at the FERC:**California Power Exchange Chargeback:As 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 defaulted on a payment, the otherparticipants were required to pay their allocated share of the default amountto the CalPX.  The allocated shares werebased upon the level of trading activity, which included both power sales andpurchases, of each participant during the preceding three-month period.

OnJanuary 18, 2001, the CalPX sent IPC an invoice for $2 million - a"default share invoice" - as a result of an alleged SouthernCalifornia Edison payment default of $215 million for power purchases.  IPC made this payment.  On January 24, 2001, IPC terminated itsparticipation agreement with the CalPX. On February 8, 2001, the CalPX sent a further invoice for $5 million,due on February 20, 2001, as a result of alleged payment defaults by SouthernCalifornia Edison, Pacific Gas and Electric Company and others.  However, because the CalPX owed IPC $11million for power sold to the CalPX in November and December 2000, IPC did notpay the February 8 invoice.  The CalPXlater reversed IPC's payment of the January 18, 2001 invoice, but on June 20,2001 invoiced IPC for an additional $2 million which the CalPX has notreversed.  The CalPX owes IPC $14 millionfor power sold in November and December including $2 million associated withthe default share invoice dated June 20, 2001. IPC essentially discontinued energy trading with the CalPX and theCalifornia Independent System Operator (Cal ISO) in December 2000.

IPCbelieves that the default invoices were not proper and that IPC owes no furtheramounts to the CalPX.  IPC has pursuedall available remedies in its efforts to collect amounts owed to it by theCalPX.  On February 20, 2001, IPC fileda petition with the FERC to intervene in a proceeding that requested the FERCto suspend the use of the CalPX chargeback methodology and provide for furtheroversight in the CalPX's implementation of its default mitigation procedures.

Apreliminary injunction was granted by a federal judge in the U.S. DistrictCourt for the Central District of California enjoining the CalPX from declaringany CalPX participant in default under the terms of the CalPX Tariff.  On March 9, 2001, the CalPX filed forChapter 11 protection with the U.S. Bankruptcy Court, CentralDistrict of California.

InApril 2001, Pacific Gas and Electric Company filed for bankruptcy.  The CalPX and the Cal ISO were among thecreditors of Pacific Gas and Electric Company. To the extent that Pacific Gas and Electric Company's bankruptcy filingaffects the collectibility of the receivables from the CalPX and the Cal ISO,the receivables from these entities are at greater risk.

TheFERC issued an order on April 6, 2001 requiring the CalPX to rescind all chargebackactions related to Pacific Gas and Electric Company's and Southern CaliforniaEdison's liabilities.  Shortly after theissuance of that order, the CalPX segregated the CalPX chargeback amounts ithad collected in a separate account. The CalPX claims it is awaiting further orders from the FERC and thebankruptcy court before distributing the funds that it collected under itschargeback tariff mechanism.  Althoughcertain parties to the California refund proceeding urged the FERC's PresidingAdministrative Law Judge to consider the chargeback amounts in hisdetermination of who owes what to whom, in his Certification of ProposedFindings on California Refund Liability, he concluded that the matter alreadywas pending before the FERC for disposition. On October 7,2004, the FERC issued an order determining that it would not require thedisbursement of chargeback funds until the completion of the California refundproceedings.  On November 8, 2004, IE,along with a number of other parties, sought rehearing of that order.  The FERC has not yet acted on the requestsfor rehearing.

CaliforniaRefund:In April 2001, the FERC issued an order stating that it was establishing pricemitigation for sales in the California wholesale electricity market.  Subsequently, in a June 19, 2001 order, theFERC expanded that price mitigation plan to the entire western United Stateselectrically 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 Federal Power Act.  The June 19 order also required all buyersand sellers in the Cal ISO market during the subject time frame to participatein settlement discussions to explore the potential for resolution of theseissues without further FERC action.  Thesettlement discussions failed to bring resolution of the refund issue and as aresult, the FERC's Chief Administrative Law Judge submitted a Report andRecommendation to the FERC recommending that the FERC adopt the methodology setforth in the report and set for evidentiary hearing an analysis of the CalISO's and the CalPX's spot markets to determine what refunds may be due uponapplication of that methodology.

On July25, 2001, the FERC issued an order establishing evidentiary hearing proceduresrelated to the scope and methodology for calculating refunds related totransactions in the spot markets operated by the Cal ISO and the CalPX duringthe period October 2, 2000 through June 20, 2001 (Refund Period).

Thiscase had been complicated by an August 13, 2002 FERC Staff Report whichincluded the recommendation to replace the published California indices for gasprices that the FERC previously established as just and reasonable forcalculating a Mitigated Market Clearing Price to calculate refunds with otherpublished indices for producing basin prices plus a transportation allowance.  The FERC Staff's recommendation is groundedon speculation that some sellers had an incentive to report exaggerated pricesto publishers of the indices, resulting in overstated published index prices.  The FERC Staff based its speculation inlarge part on a statistical correlation analysis of Henry Hub and Californiaprices.  IE, in conjunction with others,submitted comments on the FERC Staff recommendation - asserting that thestaff's conclusions were incorrect because the staff's correlation study ignoredevidence of normal market forces and scarcity that created the pricingvariations that the staff observed, rather than improper manipulation ofreported prices.

TheAdministrative Law Judge issued a Certification of Proposed Findings onCalifornia Refund Liability on December 12, 2002.

TheFERC issued its Order on Proposed Findings onRefund Liability on March 26, 2003.  Inlarge part, the FERC affirmed the recommendations of its Administrative LawJudge.  However, the FERC changed acomponent of the formula the Administrative Law Judge was to apply when itadopted findings of its staff that published California spot market prices forgas did not reliably reflect the prices a gas market that had not beenmanipulated would have produced, despite the fact that many gas buyers paidthose amounts.  The findings of theAdministrative Law Judge, as adjusted by the FERC's March 26, 2003 order, areexpected to increase the offsets to amounts still owed by the Cal ISO and theCalPX to the companies.  Calculationsremain uncertain because the FERC has required the Cal ISO to correct a numberof defects in its calculations and because the FERC has stated that if refundswill prevent a seller from recovering its California portfolio costs during theRefund Period, it will provide an opportunity for a cost showing by such arespondent.  As a result, IE is unsureof the impact this ruling will have on the refunds due from California.  However, as to potential refunds, if any, IEbelieves its exposure is likely to be offset by amounts due from Californiaentities.

IE,along with a number of other parties, filed an application with the FERC onApril 25, 2003 seeking rehearing of the March 26, 2003 order.  On October 16, 2003, the FERC issued two ordersdenying rehearing of most contentions that had been advanced and directing theCal ISO to prepare its compliance filing calculating revised Mitigated MarketClearing Prices and refund amounts within five months.  The Cal ISO has since requested additionaltime to complete its compliance filings. By order of February 3, 2004, the FERC granted additional time.  In a February 10, 2004 report to the FERC,the Cal ISO asserted its belief that it would complete re-running the data andfinancial clearing of amounts due by August 2004, subject to a number of eventsthat must occur in the interim, including FERC disposition of a number ofpending issues.  This Cal ISO compliancefiling has since been delayed until at least April 2005.  The Cal ISO is required to update the FERCon its progress monthly.  After receiptof the compliance filing, the FERC will consider cost-based filings fromsellers to reduce their refund exposure.

OnDecember 2, 2003, IE petitioned the U.S. Courtof Appeals for the Ninth Circuit for review of the FERC's orders, and sincethat time, dozens of other petitions for review have been filed.  The Ninth Circuit consolidated IE's and theother parties' petitions with the petitions for review arising from earlierFERC orders in this proceeding, bringing the total number of consolidatedpetitions to more than 100.  The NinthCircuit held the appeals in abeyance pending the disposition of the marketmanipulation claims discussed below and the development of a comprehensive planto brief this complicated case.  Certainparties also sought further rehearing and clarification before the FERC.  On September 21, 2004, the Ninth Circuitconvened case management proceedings, a procedure reserved to help organizecomplex cases.  On October 22, 2004, theNinth Circuit severed a subset of the stayed appeals in order that briefingcould commence regarding limited issues of: (1) which parties are subject tothe FERC's refund jurisdiction under section 201(f) of the Federal Power Act;(2) the temporal scope of refunds under section 206 of the Federal Power Act;and (3) which categories of transactions are subject to refunds.  Petitioners and petitioner-intervenors,including IE, filed opening briefs regarding the latter two issues on December 23, 2004.  The FERC filed its respondent's brief on January 31, 2005, andpetitioners and petitioner-intervenors, including IE, filed their reply briefs on March 1, 2005.  Oral argument is scheduled for April 12-13,2005.

On May12, 2004, the FERC issued an order clarifying portions of its earlier refundorders and, among other things, denying a proposal made by Duke Energy NorthAmerica and Duke Energy Trading and Marketing (and supported by IE) to lodge asevidence a contested settlement in a separate complaint proceeding, CaliforniaPublic Utilities Commission (CPUC) v. El Paso et al.  The CPUC's complaint alleged that the El Paso companiesmanipulated California energy markets by withholding pipeline transportationcapacity into California in order to drive up natural gas prices immediatelybefore and during the California energy crisis in 2000-2001.  The settlement will result in the payment byEl Paso of some $1.69 billion.  Dukeclaimed that the relief afforded by the settlement was duplicative of theremedies imposed by the FERC in its March 26, 2003 order changing the gas costcomponent of its refund calculation methodology.  IE, along with other parties, has sought rehearing of the May 12,2004 order.  On November 23, 2004, theFERC denied rehearing and within the statutory time allowed for petitions, anumber of parties, including IE, filed petitions for review of the FERC'sorder.  These petitions have since beenconsolidated with the larger number of review petitions in connection with theCalifornia refund proceeding.

In June2001, IPC transferred its non-utility wholesale electricity marketingoperations to IE.  Effective with thistransfer, the outstanding receivables and payables with the CalPX and the CalISO were assigned from IPC to IE.  AtDecember 31, 2004, 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 a reserveof $42 million against these receivables. This reserve was calculated taking into account the uncertainty ofcollection given the California energy situation.  Based on the reserve recorded as of December 31, 2004, 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 operations or cash flows.

On March 20, 2002, theCalifornia Attorney General filed a complaint with the FERC against varioussellers in the wholesale power market, including IE and IPC, alleging that theFERC's market-based rate requirements violate the Federal Power Act, and, evenif the market-based rate requirements are valid, that the quarterly transactionreports filed by sellers do not contain the transaction-specific informationmandated by the Federal Power Act and the FERC.  The complaint stated that refunds for amounts charged between market-basedrates and 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 Attorney General appealed the FERC'sdecision to the U.S. Court ofAppeals for the Ninth Circuit.  TheAttorney General contends that the failure of all market-based rate authoritysellers of power to have rates on file with the FERC in advance of sales isimpermissible.  The Ninth Circuit issuedits decision on September 9, 2004, concluding that market-based tariffs arepermissible under the Federal Power Act, but remanded the matter to the FERC toconsider whether the FERC should exercise remedial power (including some formof refunds) when a market participant failed to submit reports that the FERCrelies on to confirm the justness and reasonableness of rates charged.  Certain parties to the litigation havesought rehearing.  The companies cannotpredict whether rehearing will be granted or what action the FERC might take ifthe matter is remanded.

MarketManipulation:In a November 20, 2002 order, the FERC permitted discovery and the submissionof evidence respecting market manipulation by various sellers during thewestern power crises of 2000 and 2001.

OnMarch 3, 2003, the California Parties (certain investor owned utilities, theCalifornia Attorney General, the California Electricity Oversight Board and theCPUC) filed voluminous documentation asserting that a number of wholesale powersuppliers, including IE and IPC, had engaged in a variety of forms of conductthat the California Parties contended were impermissible.  Although the contentions of the CaliforniaParties were contained in more than 11 compact discs of data and testimony,approximately 12,000 pages, IE and IPC were mentioned in limited contexts withthe overwhelming majority of the claims of the California Parties relating tothe conduct of other parties.

TheCalifornia Parties urged the FERC to apply the precepts of its earlierdecision, to replace actual prices charged in every hour starting May 1, 2000through the beginning of the existing Refund Period with a Mitigated MarketClearing Price, seeking approximately $8 billion in refunds to the Cal ISO andthe CalPX.  On March 20, 2003, numerousparties, including IE and IPC, submitted briefs and responsive testimony.

In itsMarch 26, 2003 order, discussed above in "California Refund," theFERC declined to generically apply its refund determinations to sales by allmarket participants, although it stated that it reserved the right to provideremedies for the market against parties shown to have engaged in proscribedconduct.

On June25, 2003, the FERC ordered over 50 entities that participated in the westernwholesale power markets between January 1, 2000 and June 20, 2001, includingIPC, to show cause why certain trading practices did not constitute gaming oranomalous market behavior in violation of the Cal ISO and the CalPXTariffs.  The Cal ISO was ordered toprovide data on each entity's trading practices within 21 days of the order,and each entity was to respond explaining their trading practices within 45days of receipt of the Cal ISO data. IPC submitted its responses to the show cause orders on September 2 and4, 2003.  On October 16, 2003, IPCreached agreement with the FERC Staff on the two orders commonly referred to asthe "gaming" and "partnership" show cause orders.  Regarding the gaming order, the FERC Staffdetermined it had no basis to proceed with allegations of false imports andpaper trading and IPC agreed to pay $83,373 to settle allegations of circularscheduling.  IPC believed that it haddefenses to the circular scheduling allegation but determined that the cost ofsettlement was less than the cost of litigation.  In the settlement, IPC did not admit any wrongdoing or violationof any law.  With respect to the"partnership" order, the FERC Staff submitted a motion to the FERC todismiss the proceeding because materials submitted by IPC demonstrated that IPCdid not use its "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.  Eight parties haverequested rehearing of the FERC's March 3, 2004 order, but the FERC has not yetacted on those requests.  The motion todismiss the "partnership" proceeding was approved by the FERC in anorder issued on January 23, 2004 and rehearing of that order was not soughtwithin the time allowed by statute. Some of the California Parties and other parties have petitioned the U.S. Courtof Appeals for the Ninth Circuit and the District of Columbia Circuit forreview of the FERC's orders initiating the show cause proceedings.  Some of the parties contend that the scopeof the proceedings initiated by the FERC was too narrow.  Other parties contend that the ordersinitiating the show cause proceedings were impermissible.  Under the rules for multidistrict litigation,a lottery was held and although these cases were to be considered in theDistrict of Columbia Circuit by order of February 10, 2005, the District ofColumbia Circuit transferred the proceedings to the Ninth Circuit.  The FERC had moved the District of ColumbiaCircuit to dismiss these petitions on the grounds of prematurity and lack ofripeness and finality.  The transferorder was issued before a ruling from the District of Columbia Circuit and themotions, if renewed, will be considered by the Ninth Circuit.  The company is not able to predict theoutcome of the judicial determination of these issues.

On June 25, 2003, the FERC alsoissued an order instituting an investigation of anomalous bidding behavior andpractices in the western wholesale power markets.  In this investigation, the FERC was to review evidence of allegedeconomic withholding of generation.  TheFERC determined that all bids into the CalPX and the Cal ISO markets for morethan $250 per MWh for the time period May 1, 2000 through October 1, 2000 wouldbe considered prima facie evidence of economic withholding.  The FERC Staff issued data requests in thisinvestigation to over 60 market participants including IPC.  IPC responded to the FERC's datarequests.  In a letter dated May 12, 2004,the FERC's Office of Market Oversight and Investigations advised that it wasterminating the investigation as to IPC.

PacificNorthwest Refund:On July 25, 2001, the FERC issued an order establishing another proceeding toexplore whether there may have been unjust and unreasonable charges for spotmarket sales in the Pacific Northwest during the period December 25, 2000through June 20, 2001.  The FERCAdministrative Law Judge submitted recommendations and findings to the FERC onSeptember 24, 2001.  The AdministrativeLaw Judge found that prices should be governed by the Mobile-Sierra standard ofthe public interest rather than the just and reasonable standard, that thePacific Northwest spot markets were competitive and that no refunds should beallowed.  Procedurally, theAdministrative Law Judge's decision is a recommendation to the commissioners ofthe FERC.  Multiple parties submittedcomments to the FERC with respect to the Administrative Law Judge'srecommendations.  The Administrative LawJudge's recommended findings had been pending before the FERC, when at therequest of the City of Tacoma and the Port of Seattle on December 19, 2002, theFERC reopened the proceedings to allow the submission of additional evidencerelated to 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, intervened in this FERCproceeding, asserting on March 3, 2003 that its six-month forward contract, forwhich performance has been completed, should be treated as a spot marketcontract for purposes of the FERC's consideration of refunds and is requestingrefunds from IPC of $5 million.  GraysHarbor did not suggest that there was any misconduct by IPC or IE.  The companies submitted responsive testimonydefending vigorously against Grays Harbor's refund claims.

Inaddition, the Port of Seattle, the City of Tacoma and the City of Seattle madefilings with the FERC on March 3, 2003 claiming that because some marketparticipants drove prices up throughout the west through acts of manipulation,prices for contracts throughout the Pacific Northwest market should be re-setstarting in May 2000 using the same factors the FERC would use for Californiamarkets.  Although the majority of theclaims of these parties are generic, they named a number of power marketsuppliers, including IPC and IE, as having used parking services provided byother parties under FERC-approved tariffs and thus as being candidates forclaims of improperly having received congestion revenues from the Cal ISO.  On June 25, 2003, after having consideredoral argument held earlier in the month, the FERC issued its Order GrantingRehearing, Denying Request to Withdraw Complaint and Terminating Proceeding, inwhich it terminated the proceeding and denied claims that refunds should bepaid.  The FERC denied rehearing onNovember 10, 2003, triggering the right to file for review.  The Port of Seattle, the City of Tacoma, theCity of Seattle, the California Attorney General, the CPUC and Puget SoundEnergy Inc. filed petitions for review in the Ninth Circuit.  These petitions have been consolidated.  Grays Harbor did not file a petition forreview, although it has sought to intervene in the proceedings initiated by thepetitions of others.  The FERC hascertified the record to the Ninth Circuit. On July 21, 2004, the City of Seattle submitted to the Ninth Circuit inthe Pacific Northwest refund petition for review a motion requesting leave tooffer additional evidence before the FERC in order to try to secure anotheropportunity for reconsideration by the FERC of its earlier rulings.  The evidence that the City of Seattle seeksto introduce before the FERC consists of audio tapes of what purports to beEnron trader conversations containing inflammatory language that have been thesubject of coverage in the press.  UnderSection 313(b) of the Federal Power Act, a court is empowered to direct theintroduction of additional evidence if it is material and could not have beenintroduced during the underlying proceeding. The City of Seattle also requested that the current briefing schedule,which required briefs to be filed by August 5, 2004, be delayed.  On September 29, 2004, the Ninth Circuitdenied the City of Seattle's motion for leave to adduce evidence, withoutprejudice to renewing the request for remand in the briefing in the PacificNorthwest refund case.  Petitioner'sbriefs were filed January 14, 2005, Petitioner-intervenors briefs were filed onFebruary 14, 2005 and Respondent's brief is due March 30, 2005 and Respondent-intervenor'sbriefs and the briefs of any non-aligned intevenors are due April 29,2005.  Petitioners reply briefs are due42 days after service of respondent's briefs. Petitioner-intervenors' briefs are due 56 days after service ofrespondent's briefs.  A date for oralargument has not yet been set.

Thecompanies are unable to predict the outcome of these matters.

On July21, 2004, Californians for Renewable Energy, Inc. (CARE) filed a motion withthe FERC in connection with the California Refund proceedings, the PacificNorthwest refund proceedings and the show cause proceedings, both gaming andpartnership, including those in which IPC was the respondent.  CARE has participated in many of the FERCproceedings dealing with California energy matters, having appointed itself asa representative of low-income communities and other groups that it claims areotherwise not represented.  The FERCpermitted CARE to participate in the cases as an intervenor.  In its current motion, CARE requests thatthe FERC radically restructure its approach to California and western energyproceedings involving the events of 2000 and 2001 by revoking market-based rateauthority from the date of their approvals, replacing market-based rates withcost-of-service rates by requiring refunds back to the date of the ordersgranting market-based rate authority, revising long-term energy contractsnegotiated during 2000 and 2001 (it appears that the contracts that CAREidentified do not include any to which IPC is a party), deferring furtherrefund settlements, establishing a direct pass-through refund mechanism forCalifornia consumers and having "previously executed settlement agreementsrejected."  CARE also requestedthat the FERC revoke market-based rates for thoseentities identified in the June 25, 2003 show cause orders, which would includeIPC.  IPC defended itself in response tothis motion and is unable to predict how the FERC will respond to CARE'smotion.  On September 9, 2004,CARE filed a motion to withdraw its July 21, 2004 pleading.  By operation of law, the withdrawal waseffective September 24, 2004.

**ShareholderLawsuits:**  On May 26, 2004and June 22, 2004, respectively, two shareholder lawsuits were filed againstIDACORP and certain of its directors and officers.  The lawsuits, captioned Powell, et al. v. IDACORP, Inc., et al.and Shorthouse, et al. v. IDACORP, Inc., et al., raise largely similarallegations.  The lawsuits are putativeclass actions brought on behalf of purchasers of IDACORP stock between February1, 2002 and June 4, 2002, and were filed in the U.S. DistrictCourt for the District of Idaho.  Thenamed defendants in each suit, in addition to IDACORP, are Jon H. Miller, JanB. Packwood, J. LaMont Keen and Darrel T. Anderson.

The complaints alleged that,during the purported class period, IDACORP and/or certain of its officersand/or directors made materially false and misleading statements or omissionsabout the company's financial outlook in violation of Sections 10(b) and 20(a)of the Securities Exchange Act of 1934, as amended, and Rule 10b-5, therebycausing investors to purchase the company's common stock at artificiallyinflated prices.  More specifically, thecomplaints alleged that IDACORP failed to disclose and misrepresented thefollowing material adverse facts which were known to defendants or recklesslydisregarded by them: (1) IDACORP failed to appreciate the negative impact thatlower volatility and reduced pricing spreads in the western wholesale energymarket would have on its marketing subsidiary, IE; (2) IDACORP would be forcedto limit its origination activities to shorter-term transactions due toincreasing regulatory uncertainty and continued deterioration of creditworthycounterparties; (3) IDACORP failed to discount for the fact that IPC may notrecover from the lingering effects of the prior year's regional drought and (4)as a result of the foregoing, defendants lacked a reasonable basis for theirpositive statements about IDACORP and their earnings projections.  The Powell complaint also alleged that thedefendants' conduct artificially inflated the price of the company's commonstock.  The actions seek an unspecifiedamount of damages, as well as other forms of relief.  By order dated August 31, 2004, the court consolidated the Powelland Shorthouse cases for pretrial purposes, and ordered the plaintiffs to filea consolidated complaint within 60 days. On November 1, 2004, IDACORP and the directors and officers named abovewere served with a purported consolidated complaint captioned Powell et al. v.IDACORP, Inc. et al., which was filed in the U.S. DistrictCourt for the District of Idaho.

The new complaint alleges thatduring the class period IDACORP and/or certain of its officers and/or directorsmade materially false and misleading statements or omissions about its businessoperations, and specifically the IDACORP Energy financial outlook, in violationof Rule 10b-5, thereby causing investors to purchase IDACORP's common stock atartificially inflated prices.  The newcomplaint alleges that IDACORP failed to disclose and misrepresented thefollowing material adverse facts which were known to it or recklesslydisregarded by it: (1) IDACORP falsely inflated the value of energy contractsheld by IDACORP Energy in order to report higher revenues and profits; (2)IDACORP permitted IPC to inappropriately grant native load priority for certainenergy transactions to IDACORP Energy; (3) IDACORP failed to file 13 ancillaryservice agreements involving the sale of power for resale in interstatecommerce that it was required to file under Section 205 of the Federal PowerAct; (4) IDACORP failed to file 1,182 contracts that IPC assigned to IDACORPEnergy for the sale of power for resale in interstate commerce that IPC wasrequired to file under Section 203 of the Federal Power Act; (5) IDACORP failedto ensure that IDACORP Energy provided appropriate compensation from IDACORPEnergy to IPC for certain affiliated energy transactions; and (6) IDACORPpermitted inappropriate sharing of certain energy pricing and transmissioninformation between IPC and IDACORP Energy. These activities allegedly allowed IDACORP Energy to maintain a falseperception of continued growth that inflated its earnings.  In addition, the new complaint alleges thatthose earnings press releases, earnings release conference calls, analystreports and revised earnings guidance releases issued during the class periodwere false and misleading.  The actionseeks an unspecified amount of damages, as well as other forms of relief.  IDACORP and the other defendants filed aconsolidated motion to dismiss on February 9, 2005, which is now pending.

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

**Powerex: **On August 31, 2004, PowerexCorp., the wholly owned power marketing subsidiary of BC Hydro, a CrownCorporation of the province of British Columbia, Canada, filed a lawsuitagainst IE and IDACORP in the U.S. District Court for the Districtof Idaho.  Powerex Corp. alleges that IEbreached an oral and written contract regarding the assignment of transmissioncapacity for electric power by IE to Powerex Corp. for a fourteen-month periodand for intentional interference with Powerex Corp.'s alleged contract withIE.  Powerex Corp. seeks unspecifiedgeneral and special damages.  OnNovember 29, 2004, the companies filed an answer to Powerex Corp.'s complaint,denying all liability to the plaintiffs, and asserting certain affirmativedefenses.  The companies intend tovigorously defend their position in this proceeding but cannot predict theoutcome of this matter.

**Other Legal IssuesIdaho Power Company Transmission Line Rights-of-Way Across Fort Hall Indian****Reservation:**  IPC hasmultiple transmission lines that cross the Shoshone-Bannock Tribes' Fort HallIndian Reservation near the city of Pocatello in southeastern Idaho.  IPC has been working since 1996 to renewfour of the right-of-way permits (for five of the transmission lines), whichhave stated permit expiration dates between 1996 and 2003.  IPC filed applications with the U.S. Departmentof the Interior, Bureau of Indian Affairs, to renew the four rights-of-way for25 years, 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).  Due to the lack ofdefinitive legal guidelines for valuation of the permit renewals, IPC is in theprocess of negotiating mutually acceptable renewal terms with the tribes andallottees.  The parties are pursuing apossible 23-year renewal of the permits (including all pre-renewal periods) fora total payment of approximately $7 million to the tribes and allottees. IPC,the tribes and the Bureau of Indian Affairs are currently working through theprocess of finalizing the agreement, including obtaining the requisite consentsfrom the allottees.  The parties hope toobtain the required consents early in 2005. On December 27, 2004, IPC filed an application with the IPUC seeking anaccounting order regarding the treatment of this transaction.  On February 28, 2005, the IPUC issued anorder approving IPC's application procedure.

**9. STOCK-BASEDCOMPENSATION:**

IDACORP hastwo stock-based compensation plans, the 2000 Long-Term Incentive andCompensation Plan (LTICP) and the 1994 Restricted Stock Plan (Restricted StockPlan).  These plans are intended toalign employee and shareholder objectives related to its long-term growth.

The LTICPfor officers, key employees and directors permits the grant of nonqualifiedstock options, incentive stock options, stock appreciation rights, restrictedstock, restricted stock units, performance units, performance shares and otherawards.

Themaximum number of shares available under the LTICP is 2,050,000.  In 2004, 2003 and 2002, IDACORP granted142,100, 429,000 and 355,000 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 summarizedas follows:

 

 

**2004**

**2003**

**2002**

 

 

 

**Weighted**

 

**Weighted**

 

**Weighted**

 

 

**Number**

**average**

**Number**

**average**

**Number**

**average**

 

 

**of**

**exercise**

**of**

**exercise**

**of**

**exercise**

 

 

**shares**

**price**

**shares**

**price**

**shares**

**price**

Outstanding, beginning of  year

1,148,400 

$

32.71

849,000 

$

38.50

494,000

$

37.79

 

Granted

142,100 

 

31.21

429,000 

 

23.01

355,000

 

39.50

 

Exercised

(7,400)

 

22.92

- 

 

-

-

 

-

 

Forfeited

(71,300)

 

31.81

(129,600)

 

38.57

-

 

-

Outstanding, end of year

1,211,800 

$

32.64

1,148,400 

$

32.71

849,000

$

38.50

 

 

 

 

 

 

 

 

 

 

 

Exercisable

473,800 

$

35.58

266,600 

$

37.91

120,800

$

37.20

 

The following table summarizes informationabout stock options outstanding at December 31, 2004:

 

**Outstanding**

**Exercisable**

 

 

 

**Weighted**

 

 

 

 

**Weighted**

**average**

 

**Weighted**

 

 

**average**

**remaining**

 

**average**

 

**Number**

**exercise**

**contractual**

**Number**

**exercise**

**Exercise Price Ranges**

**of shares**

**price**

**life**

**of shares**

**price**

$22.92 - $31.21

525,200

$

25.08

8.43 years

78,000

$

23.02

$35.81 - $40.31 

686,600

$

38.43

6.38 years

395,800

$

38.05

 

The fair value of each option granted wasestimated at the date of grant using a binomial option-pricing model with thefollowing assumptions:

 

**2004**

 

**2003**

 

**2002**

Dividend  yield

3.84%

 

8.09%

 

4.71%

Expected  stock price volatility

29%

 

28%

 

32%

Risk-free  interest rate

3.97%

 

3.94%

 

4.92%

Expected  option lives

7 years

 

7 years

 

7 years

Weighted  average fair value of options granted

$7.93

 

$ 3.90

 

$10.54

 

IDACORP's RestrictedStock Plan is for key employees.  Eachrestricted stock grant has a four-year restricted period.  Each performance share grant has athree-year restricted period and the final award amount depends on theattainment of cumulative EPS performance goals.  At December 31, 2004, there were 63,572 remaining sharesavailable under the Restricted Stock Plan.

Restricted stock andperformance share awards are compensatory awards and IDACORP accruescompensation expense, which is charged to operations, based upon the marketvalue of the granted shares.  For 2004,2003 and 2002, total compensation accrued under the Restricted Stock Plan wasless than $1 million annually.

The following tablesummarizes restricted stock and performance share activity:

 

**2004**

 

**2003**

 

**2002**

Shares  outstanding - beginning of year

94,363 

 

87,669 

 

63,551 

Shares  granted

78,116 

 

52,517 

 

44,832 

Shares  forfeited

(30,931)

 

(6,679)

 

(132)

Shares  issued

- 

 

(39,144)

 

(20,582)

Shares  outstanding - end of year

141,548 

 

94,363 

 

87,669 

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

$

31.21 

 

$

23.01 

 

$

38.58 

 

**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 1974(ERISA) but not more than the maximum amount deductible for income taxpurposes.  IPC was not required tocontribute to the plan in 2004, 2003 or 2002, and does not expect to make acontribution in 2005.  The market-relatedvalue of assets for the plan is equal to market value.

Inaddition, IPC has a nonqualified, deferred compensation plan for certain seniormanagement employees and directors. This plan was financed by purchasing life insurance policies andinvestments in marketable securities, all of which are held by a trustee.  The cash value of the policies andinvestments exceed the projected benefit obligation of the plan but do notqualify as plan assets in the actuarial computation of the funded status.

IPCuses a December 31 measurement date for its plans.

The following table summarizesthe changes in benefit obligations and plan assets of these plans:

 

**Pension Plan**

 

**Deferred Compensation Plan**

 

**2004**

 

**2003**

 

**2004**

 

**2003**

 

**(thousands of dollars)**

**Change in benefit obligation:**

 

 

 

 

 

 

 

 

 

 

 

 

Benefit obligation at January 1

$

339,121 

 

$

294,881 

 

$

38,870 

 

$

35,792 

 

Service cost

 

11,809 

 

 

10,173 

 

 

1,358 

 

 

1,212 

 

Interest cost

 

20,437 

 

 

19,463 

 

 

2,312 

 

 

2,414 

 

Actuarial loss (gain)

 

16,626 

 

 

27,420 

 

 

(1,225)

 

 

1,786 

 

Benefits paid

 

(13,660)

 

 

(13,345)

 

 

(2,670)

 

 

(2,369)

 

Plan amendments

 

- 

 

 

529 

 

 

- 

 

 

35 

 

Benefit obligation at December 31

 

374,333 

 

 

339,121 

 

 

38,645 

 

 

38,870 

**Change in plan assets:**

 

 

 

 

 

 

 

 

 

 

 

 

Fair value at January 1

 

335,229 

 

 

282,531 

 

 

- 

 

 

- 

 

Actual return on plan assets

 

34,648 

 

 

66,043 

 

 

- 

 

 

- 

 

Employer contributions

 

- 

 

 

- 

 

 

- 

 

 

- 

 

Benefit payments

 

(13,660)

 

 

(13,345)

 

 

- 

 

 

- 

 

Fair value at December 31

 

356,217 

 

 

335,229 

 

 

- 

 

 

- 

 

 

 

 

 

 

 

 

 

 

 

 

Funded status

 

(18,116)

 

 

(3,892)

 

 

(38,645)

 

 

(38,870)

Unrecognized actuarial loss 

 

28,491 

 

 

18,577 

 

 

11,443 

 

 

13,547 

Unrecognized prior service cost

 

5,889 

 

 

6,660 

 

 

1,372 

 

 

1,010 

Unrecognized net transition liability

 

(126)

 

 

(389)

 

 

310 

 

 

923 

Net amount recognized

$

16,138 

 

$

20,956 

 

$

(25,520)

 

$

(23,390)

Amounts recognized in the statement of

 

 

 

 

 

 

 

 

 

 

 

 

financial position consist of:

 

 

 

 

 

 

 

 

 

 

 

Prepaid (accrued) pension cost

$

16,138 

 

$

20,956 

 

$

(36,110)

 

$

(35,676)

Intangible asset

 

- 

 

 

- 

 

 

1,682 

 

 

1,933 

Accumulated other comprehensive income

 

- 

 

 

- 

 

 

8,908 

 

 

10,353 

Net amount recognized

$

16,138 

 

$

20,956 

 

$

(25,520)

 

$

(23,390)

Accumulated benefit obligation

$

316,498 

 

$

284,910 

 

$

36,110 

 

$

35,676 

 

The following tableshows the components of net periodic benefit cost for these plans:

 

**Pension Plan**

**Deferred Compensation  Plan**

 

**2004**

**2003**

**2002**

**2004**

**2003**

**2002**

 

**(thousands  of dollars)**

 

 

 

 

 

 

 

 

 

 

 

 

 

Service cost

$

11,809 

$

10,173 

$

9,548 

$

1,358 

$

1,212 

$

944 

Interest cost

 

20,437 

 

19,463 

 

18,684 

 

2,312 

 

2,414 

 

2,108 

Expected return on assets

 

(27,935)

 

(23,445)

 

(28,797)

 

- 

 

- 

 

- 

Recognized net actuarial loss

 

- 

 

361 

 

- 

 

878 

 

744 

 

498 

Amortization of prior service cost

 

770 

 

729 

 

729 

 

(361)

 

(345)

 

(353)

Amortization of transition asset

 

(263)

 

(263)

 

(263)

 

613 

 

613 

 

613 

Net periodic pension cost (benefit) 

$

4,818 

$

7,018 

$

(99)

$

4,800 

$

4,638 

$

3,810 

 

 

 

 

 

 

 

 

 

 

 

 

 

Changes in the Deferred Compensation Plan minimumliability increased other comprehensive income by $1 million in 2004 anddecreased other comprehensive income by $1 million and $3 million in 2003 and2002, respectively.

The following table summarizes the expected futurebenefit payments of these plans:

 

 

**2005**

 

**2006**

 

**2007**

 

**2008**

 

**2009**

 

**2010-2014**

Pension Plan

$

13,846

$

14,277

$

14,996

$

16,018

$

17,244

$

110,833

Deferred Compensation Plan

$

2,296

$

2,345

$

2,461

$

2,551

$

2,721

$

15,041

 

**Plan Asset Allocations:** IPC's pension plan and postretirement benefitplan weighted average asset allocations at December 31, 2004 and 2003, by assetcategory are as follows:

 

 

**Pension**

 

**Postretirement**

 

 

**Plan**

 

**Benefits**

Asset Category

 

**2004**

**2003**

 

**2004**

**2003**

Equity securities

 

69%

69%

 

-%

-%

Debt securities

 

21   

21   

 

3   

2   

Real estate

 

9   

9   

 

-   

-   

Other (a)

 

1   

1   

 

97   

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

12%

International Growth Stocks

7%

Large-Cap Core Stocks

12%

International Value Stocks

7%

Large-Cap Value Stocks

12%

Intermediate-Term Bonds

13%

Small-Cap Growth Stocks

7%

Short-Term Bonds

10%

Small-Cap Value Stocks

7%

Core Real Estate

9%

Cash and Cash Equivalents

3%

Venture Capital

1%

 

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

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

There are three major goals inIPC's asset allocation process:

Determine if the investments havethe potential to earn the rate of return assumed in the actuarial liabilitycalculations.

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 percent S&P 500 stocks and a 40percent Lehman Aggregate bond portfolio.

 

Allowableplan investments include stocks and stock funds, investment-grade bonds andbond funds, core real estate funds, private equity funds, and cash and cashequivalents.  With the exception of realestate holdings and private equity, investments must be readily marketable sothat an entire holding can be disposed of quickly with only a minor effect uponmarket price.  Uncovered options, shortsales, margin purchases, letter stock and commodities are prohibited.

Rate-of-return projections forplan assets are based on historical real returns adjusted for inflation foreach asset class, based on a recognized index established for the asset classbeing measured.  Historical real returnsare then adjusted to include an inflation premium based on the currentinflation environment.  IPC currentlyuses a three percent inflation assumption in the asset modeling process.

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

**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 as well as their spouses and qualifying dependents.  Effective January 1, 2003, IPC amended itspostretirement benefit plan.  Theamendment affects all employees who retire after December 31, 2002, limitingtheir postretirement benefit to a fixed amount.  This amendment will limit the growth of IPC's future obligationsunder this plan.

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

 

**2004**

 

**2003**

 

**2002**

Service  cost

$

1,400 

 

$

1,207 

 

$

927 

Interest  cost

 

3,974 

 

 

4,017 

 

 

3,648 

Expected  return on plan assets

 

(2,294)

 

 

(1,930)

 

 

(2,320)

Amortization  of unrecognized transition obligation

 

2,040 

 

 

2,040 

 

2,040 

Amortization  of prior service cost

 

(523)

 

 

(563)

 

(563)

Recognized  actuarial loss

 

1,489 

 

 

1,402 

 

487 

Net  periodic postretirement benefit cost

$

6,086 

 

$

6,173 

 

$

4,219 

 

 

 

 

 

 

 

 

 

 

 

The following table summarizesthe changes in benefit obligation and plan assets (in thousands of dollars):

 

**2004**

 

**2003**

**Change in accumulated benefit  obligation:**

 

 

 

 

 

 

Benefit obligation at January 1

$

67,090 

 

$

57,267 

 

Service cost

 

1,400 

 

 

1,207 

 

Interest cost

 

3,974 

 

 

4,017 

 

Actuarial loss

 

2,201 

 

 

8,780 

 

Benefits paid

 

(3,997)

 

 

(4,181)

 

Plan Amendments

 

437 

 

 

- 

 

Benefit obligation at December 31

 

71,105 

 

 

67,090 

 

 

 

 

 

 

**Change in plan assets:**

 

 

 

 

 

 

Fair value of plan assets at January 1

 

26,603 

 

 

22,522 

 

Actual return on plan assets

 

2,301 

 

 

4,081 

 

Employer contributions

 

4,577 

 

 

3,961 

 

Benefits paid

 

(3,758)

 

 

(3,961)

 

Fair value of plan assets at December 31

 

29,723 

 

 

26,603 

 

 

 

 

 

 

Funded status

 

(41,382)

 

 

(40,487)

Unrecognized  prior service cost

 

(4,087)

 

 

(5,047)

Unrecognized  actuarial loss 

 

24,559 

 

 

23,854 

Unrecognized  transition obligation

 

16,320 

 

 

18,360 

Accrued  benefit obligations included with other deferred credits

$

(4,590)

 

$

(3,320)

 

The assumed health carecost trend rate used to measure the expected cost of benefits covered by theplan was 6.75 percent in 2004 and 2003. A one-percentage point change in the assumed health care cost trend ratewould have the following effect (in thousands of dollars):

 

**1-Percentage-Point**

 

**increase**

 

**decrease**

 

 

 

 

 

 

Effect on total of cost components

$

220

 

$

(170)

Effect on accumulated postretirement  benefit obligation

$

1,996

 

$

(1,625)

 

The following tablesets forth the weighted-average assumptions used at the end of each year todetermine benefit obligations for all IPC-sponsored pension and postretirementbenefits plans:

 

 

**Pension**

 

**Postretirement**

 

 

**Benefits**

 

**Benefits**

 

 

**2004**

**2003**

 

**2004**

**2003**

Discount rate

 

5.75%

6.15%

 

5.75%

6.15%

Expected long-term rate of return on assets

 

8.5   

8.5   

 

8.5   

8.5   

Rate of compensation increase

 

4.5   

4.5   

 

-   

-   

Medical trend rate

 

-   

-   

 

6.75   

6.75   

Expected working lifetime (years)

 

-   

-   

 

11   

12   

 

The following tablesets forth the weighted-average assumptions used for the end of each year todetermine net periodic benefit cost for all IPC-sponsored pension andpostretirement benefit plans:

 

 

**Pension**

 

**Postretirement**

 

 

**Benefits**

 

**Benefits**

 

 

**2004**

**2003**

 

**2004**

**2003**

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)

 

-   

-   

 

11   

12   

** **

**FSP FAS 106-1 and FSP FAS 106-2**In January and May 2004, the FASB released FSP FAS 106-1 and FSP FAS106-2, "Accounting and Disclosure Requirements Related to the Medicare PrescriptionDrug, Improvement and Modernization Act of 2003."

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

FSP FAS 106-2 provides guidance on accounting for theeffects of the Medicare Act for employers that sponsor postretirement healthcare plans that provide prescription drug benefits and requires those employersto provide certain disclosures regarding the effect of the federal subsidyprovided by the Medicare Act. Under FSP FAS 106-1, IDACORP and IPC elected todefer accounting for the effects of the Medicare Act. This deferral remained ineffect until the appropriate effective date of FSP FAS 106-2.

FSP FAS 106-2 was effective for the first interim orannual period beginning after June 15, 2004. However, for entities that did not recognize a significant impact,delayed recognition of the effects of the Medicare Act until the next regularlyscheduled measurement date following the issuance of FSP FAS 106-2 wasrequired.

The measures of accumulated postretirement benefitobligation and net periodic benefit cost do not reflect any amount associatedwith the subsidy, because IDACORP and IPC initially determined that the effectof the Medicare Act would not be material. Regulations published on January 28, 2005 provide more flexibility indetermining actuarial equivalence to Medicare of the benefits provided by theplan than was initially estimated by IDACORP's and IPC's actuaries.Based onthese new regulations, IDACORP and IPC estimate that the accumulatedpostretirement benefit obligation as of January 1, 2005 will be reduced by $6million, and 2005 periodic postretirement benefit cost will decrease by $1million.

**Employee Savings Plan**IPC has an Employee Savings Plan thatcomplies with Section 401(k) of the Internal Revenue Code and coverssubstantially all employees.  IPCmatches specified percentages of employee contributions to the plan.  Matching contributions amounted to $3million in both 2004 and 2003 and $4 million in 2002.

**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 amortized over a ten-year period, which ended in January2005.

The following tablesummarizes postemployment benefit amounts included in IDACORP and IPC'sconsolidated balance sheets at December 31 (in thousands of dollars):

 

**2004**

 

**2003**

Included with regulatory assets

$

31

 

$

403

Included with other deferred credits

$

3,924

 

$

4,079

 

 

 

 

 

 

 

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

Thefollowing table presents the major classifications of IPC's utility plant inservice, annual depreciation provisions as a percent of average depreciablebalance and accumulated provision for depreciation for the years 2004 and 2003(in thousands of dollars):

 
 

**2004**

 

**2003**

 
 

**Balance**

 

**Avg Rate**

 

**Balance**

 

**Avg Rate**

Production

$

1,482,517 

 

2.51%

 

$

1,456,954 

 

2.62%

Transmission

 

560,303 

 

2.18   

 

 

526,887 

 

2.21   

Distribution

 

992,248 

 

2.59   

 

 

952,979 

 

3.25   

General and Other

 

289,748 

 

10.02   

 

 

283,408 

 

6.51   

 

Total in service

 

3,324,816 

 

2.96%

 

 

3,220,228 

 

2.99%

Accumulated provision for  depreciation

 

(1,316,125)

 

 

 

 

(1,239,604)

 

 

 

In service - net

$

2,008,691 

 

 

 

$

1,980,624 

 

 

 

IPC hasinterests in three jointly-owned generating facilities.  Under the joint operating agreements, eachparticipating utility is responsible for financing its share of construction,operating and leasing costs.  IPC'sproportionate share of direct operation and maintenance expenses applicable tothe projects is included in the Consolidated Statements of Income.  These facilities, and the extent of IPC'sparticipation, were as follows at December 31, 2004 (in thousands of dollars):

 

 

 

 

**Utility**

 

**Construction**

 

**Accumulated**

 

 

 

 

 

 

 

 

**Plant In**

 

**Work in**

 

**Provision for**

 

 

 

 

**Name of Plant**

 

**Location**

 

**Service**

 

**Progress**

 

**Depreciation**

 

**%**

 

**MW**

Jim Bridger Units 1-4

 

Rock Springs, WY

 

$

442,367

 

$

4,310

 

$

255,229

 

33

 

707

Boardman

 

Boardman, OR

 

 

66,116

 

 

1,277

 

 

44,275

 

10

 

55

Valmy Units 1 and 2

 

Winnemucca, NV

 

 

310,917

 

 

889

 

 

184,025

 

50

 

261

 

IPC'swholly owned subsidiary, Idaho Energy Resources Co., is a joint venturer inBridger Coal Company, which operates the mine supplying coal to the Jim Bridgergenerating plant.  Coal purchased by IPCfrom the joint venture amounted to $47 million in 2004 and $44 million in both2003 and 2002.

IPC hascontracts to purchase the energy from four Public Utilities Regulatory PolicyAct of 1978 (PURPA) Qualified Facilities that are 50 percent owned byIda-West.  Power purchased from thesefacilities amounted to $7 million, annually in 2004, 2003 and 2002.See Note 1 for a discussion of the property of IDACORP's consolidated VIEs.

**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.  SEGMENTINFORMATION:**

Information regardingsegments is presented in accordance with SFAS 131, "Disclosure aboutSegments of an Enterprise and Related Information."  Based on the criteria outlined in SFAS 131,IDACORP has identified two reportable segments in 2004: utility operations andIFS.

The utility operationssegment has two primary sources of revenue: the regulated operations of IPC andincome from Bridger Coal Company, an unconsolidated joint venture also subjectto regulation.  IPC's regulatedoperations include the generation, transmission, distribution, purchase andsale of electricity.

IFSrepresents that subsidiary's investments in affordable housing developments andhistoric preservation projects.

Energy marketing, which wasformerly reported as a separate operating segment, has been removed, since itno longer meets the quantitative thresholds outlined in SFAS 131, and is notconsidered to be of continuing significance. See Note 15 for a discussion of the wind down of energy marketingoperations.

Thefollowing table summarizes the segment information for IDACORP's utilityoperations, IFS and the total of all other segments, and reconciles thisinformation to total enterprise amounts.

 

**Utility**

 

 

 

**Consolidated**

 

**Operations**

**IFS**

**Other**

**Eliminations**

**Total**

 

**(thousands of dollars)**

**2004**

 

 

 

 

 

 

 

 

 

Revenues

$

822,937 

$

1,392 

$

20,162 

$

- 

$

844,491 

Operating income (loss)

 

109,038 

 

(544)

 

(15,243)

 

- 

 

93,251 

Other income (expense)

 

4,516 

 

4,857 

 

4,324 

 

(69)

 

13,628 

Interest income

 

2,413 

 

655 

 

1,250 

 

(895)

 

3,423 

Equity method income (loss)

 

12,313 

 

(12,502)

 

1,239 

 

- 

 

1,050 

Interest expense and preferred dividends

 

56,167 

 

4,719 

 

3,217 

 

(964)

 

63,139 

Income (loss) before income taxes

 

72,113 

 

(12,253)

 

(11,647)

 

- 

 

48,213 

Income tax expense (benefit)

 

6,328 

 

(25,566)

 

(5,532)

 

- 

 

(24,770)

Net income (loss)

 

65,785 

 

13,313 

 

(6,115)

 

- 

 

72,983 

Total assets

 

2,969,212 

 

145,279 

 

211,120 

 

(91,439)

 

3,234,172 

Expenditures for long-lived assets

 

190,379 

 

7,670 

 

9,469 

 

- 

 

207,518 

**2003**

 

 

 

 

 

 

 

 

 

Revenues

$

782,720 

$

- 

$

40,282 

$

- 

$

823,002 

Operating income (loss)

 

121,694 

 

(796)

 

(36,836)

 

- 

 

84,062 

Other income (expense)

 

105 

 

71 

 

(508)

 

(221)

 

(553)

Interest income

 

3,237 

 

460 

 

4,116 

 

(3,338)

 

4,475 

Equity method income (loss)

 

11,336 

 

(10,461)

 

1,532 

 

- 

 

2,407 

Interest expense and preferred dividends

 

59,483 

 

5,821 

 

3,187 

 

(3,559)

 

64,932 

Income (loss) before income taxes

 

76,889 

 

(16,547)

 

(34,883)

 

- 

 

25,459 

Income tax expense (benefit)

 

21,728 

 

(26,951)

 

(15,896)

 

- 

 

(21,119)

Net income (loss)

 

55,161 

 

10,404 

 

(18,987)

 

- 

 

46,578 

Total assets

 

2,820,711 

 

141,286 

 

213,731 

 

(69,620)

 

3,106,108 

Expenditures for long-lived assets

 

148,494 

 

3 

 

1,393 

 

- 

 

149,890 

**2002**

 

 

 

 

 

 

 

 

 

 

Revenues

$

869,040 

$

- 

$

59,760 

$

- 

$

928,800 

Operating income (loss)

 

132,661 

 

(923)

 

(56,098)

 

-  

 

75,640 

Other income (expense)

 

(3,330)

 

(21)

 

2,497 

 

(275)

 

(1,129)

Interest income

 

2,873 

 

555 

 

7,497 

 

(6,712)

 

4,213 

Equity method income (loss)

 

12,065 

 

(12,312)

 

993 

 

- 

 

746 

Interest expense and preferred dividends

 

62,529 

 

7,147 

 

6,256 

 

(6,987)

 

68,945 

Income (loss) before income taxes

 

81,739 

 

(19,848)

 

(51,366)

 

- 

 

10,525 

Income tax expense (benefit)

 

(2,594)

 

(28,680)

 

(19,873)

 

- 

 

(51,147)

Net income (loss)

 

84,333 

 

8,832 

 

(31,493)

 

- 

 

61,672 

Total assets

 

2,876,167 

 

157,018 

 

579,999 

 

(226,016)

 

3,387,168 

Expenditures for long-lived assets

 

129,132 

 

44,064 

 

8,999 

 

- 

 

182,195 

 

 

 

 

 

 

 

 

 

 

 

**13.  REGULATORY MATTERS:**

**General Rate Case****Idaho:**IPC filed its Idaho general rate case with the IPUC onOctober 16, 2003.  IPC originallyrequested approximately $86 million annually in additional revenue, an average17.7 percent increase to base rates.  Onrebuttal, IPC lowered its overall requested increase to $70 million annually,an average of 14.5 percent.  The IPUCapproved an increase of $25 million in IPC's electric rates, an average of 5.2percent, in an order issued on May 25, 2004. The rate increase became effective on June 1, 2004.

In the order, the IPUC approved a return on equity of 10.25percent, compared to the 11.2 percent IPC requested, an overall rate of returnof 7.9 percent, compared to the 8.3 percent requested by IPC.  The IPUC reduced the $1.55 billion in ratebase requested for IPC's Idaho jurisdiction to $1.52 billion.

Additionally, the IPUC approved higher rates for residential andsmall-commercial customers during the summer months to encourageconservation.  The 12.6 percent highersummer rate applies to monthly usage over 300 kilowatt-hours.  The IPUC also ordered time-of-use rates tobe phased in for industrial customers, asked IPC to submit a proposal for aconservation program for industrial customers and ordered increased low-incomeweatherization funding of $1 million annually.

The IPUC also noted two other issues to be addressed in separateproceedings and potentially handled in workshops instead of formalhearings.  These issues are: (1)investigating approaches to removing financial disincentives to IPC forinvesting in cost effective energy efficiency and clean distributed generationand (2) investigating various cost of service issues raised in the general ratecase, including those associated with load growth.  During the year, initial workshops were held on both issues.

The IPUC disallowed several costs in the Idaho general rate caseorder, including $12 million annually related to the determination of IPC'sincome tax expense, $8 million of incentive payments capitalized in prior yearsand $1 million of capitalized pension expense. On June 15, 2004, IPC filed with the IPUC a petition for reconsiderationof these and other items.  On July 13,2004, the IPUC granted this petition in part, agreeing to reconsider the issuerelating to the determination of IPC's income tax expense and, in light of theIPUC Staff's computational errors, ordering rates increased by approximately $3million on or before August 1, 2004. IPC recorded an impairment of assets of $9 million related to thedisallowed incentive payments and the disallowed capitalized pension expenses.

On September 28, 2004, the IPUC issued separate orders approvingtwo Settlement Agreements entered into on August 16, 2004 between IPC and theIPUC Staff.

Settlement No. 1,approved by the IPUC in Order No. 29601, relates to the calculation of IPC'staxes for purposes of test year income tax expense.  In the Idaho general rate case order, the IPUC adopted the use ofa historic five-year average income tax rate to calculate IPC's income taxexpense.  Settlement No. 1 approved themodification of the general rate case order to utilize IPC's statutory incometax rates to compute test year income tax expense.  As a result, IPC will compute and record monthly during theperiod June 1, 2004 through May 31, 2005 a regulatory asset (with interestaccrued at a rate of one percent per annum) of approximately $12 million.  Rates will increase on June 1, 2005 toreflect the ongoing impact of the tax expense. Approximately $7 million of this amount was recorded in 2004 as otheroperating revenue.  Settlement No. 1allows IPC to continue its compliance with the normalization provisions of theInternal Revenue Code of 1986, as amended, and associated Treasury Regulations,and will allow IPC to continue to receive the benefits of accelerateddepreciation.

Settlement No. 2,approved by the IPUC in Order No. 29600, resolved outstanding issues relatedto: (1) an unplanned outage at one of the two units of the North Valmy SteamElectric Generating Plant (Valmy) in the summer of 2003, (2) a matter relatingto the expense adjustment rate for growth component of the PCA and (3)regulatory accounting issues related to a tax accounting method change in2002.  In Settlement No. 2, IPC and theIPUC Staff agreed that the IPUC will not examine the cost of replacement powerand a possible PCA adjustment resulting from the Valmy outage, and the expenseadjustment rate for growth component of the PCA will continue at its existingvalue until IPC's next general rate case. In September 2004, as a result of the order, IPC established aregulatory liability of $19 million with a charge to PCA expense.  A monthly credit of approximately $804,000will be included in the PCA from June 2004 through May 2006, which will reducethis regulatory liability.  Also inSeptember 2004, IPC reversed a $16 million regulatory tax liability by reducingincome tax expense.  This regulatory taxliability was established in 2002 when IPC changed its tax accounting methodfor capitalized overhead costs.

The final result ofIPC's general rate case was a $40 million increase to the base Idahojurisdictional revenue requirement, comprised of $25 million in the initialorder, $3 million related to computational errors and $12 million in the orderapproving Settlement No. 1.

On March 2, 2005, IPC made arate filing with the IPUC to include the investment associated with theconstruction of the Bennett Mountain Power Plant in Idaho retail rates.

**Oregon**: OnSeptember 21, 2004, IPC filed an application with the OPUC to increase generalrates an average of 17.5 percent or approximately $4 million annually.  IPC's filing includes a request to introducesummer and non-summer rates similar to proposals that were approved in theIdaho general rate case.  IPC has notfiled for a change to its overall rates in Oregon since 1995.

On October 19, 2004, the OPUCsuspended IPC's request for a period of time not to exceed nine months fromOctober 20, 2004 to investigate the propriety and reasonableness of therequest.  A pre-hearing conference andpublic meeting was held on November 18, 2004. The hearing schedule called for a settlement conference, which began onFebruary 14, 2005 and an evidentiary hearing to begin on May 23, 2005.  IPC is unable to predict what rate reliefthe OPUC will grant.

**DeferredPower Supply Costs******IPC's deferred net power supply costs consisted of the following atDecember 31 (in thousands of dollars):

 

**2004**

 

**2003**

Oregon deferral

$

12,047

 

$

13,620

Idaho PCA current year net  power supply cost deferrals:

 

 

 

 

 

 

Deferral for 2004-2005 rate  year

 

-

 

 

44,664

 

Deferral for 2005-2006 rate  year

 

22,778

 

 

-

Irrigation Lost Revenues

 

13,290

 

 

-

Idaho PCA true-up awaiting  recovery:

 

 

 

 

 

 

Remaining true-up authorized  May 2003

 

-

 

 

13,646

 

Remaining true-up authorized  May 2004

 

11,415

 

 

-

 

Total deferral

$

59,530

 

$

71,930

 

**Idaho:**IPC hasa PCA mechanism that provides for annual adjustments to the rates charged toits Idaho retail customers.  Theseadjustments are based on forecasts of net power supply costs, which are fueland purchased power less off-system sales, and the true-up of the prior year'sforecast.  During the year, 90 percentof the difference between the actual and forecasted costs is deferred withinterest.  The ending balance of thisdeferral, called the true-up for the current year's portion and the true-up ofthe true-up for the prior years' unrecovered portions, is then included in thecalculation of the next year's PCA.

On April 15, 2004, IPC filedits 2004-2005 PCA with the IPUC requesting recovery of $71 million above baserates and a proposed effective date of June 1, 2004.  On May 25, 2004, the IPUC issued Order No. 29506 approving IPC'sfiling with additional instructions for IPC and the IPUC Staff to examine thecost of replacement power attributable to the unplanned outage at the Valmyplant in 2003.  Based on the orderapproving Settlement No. 2, discussed above, the IPUC will not examine thecosts related to this outage.

On May 15, 2003, the IPUCissued Order No. 29243 approving IPC's 2003-2004 PCA filing, with a smalladjustment to the original filing.  Asapproved, IPC's rates were adjusted to collect $81 million above 1993 baserates.

On April 15, 2002, the IPUCissued Order No. 28992 disallowing recovery of $12 million of lost revenuesresulting from the Irrigation Load Reduction Program that was in place in2001.  IPC believed that this IPUC orderwas inconsistent with Order No. 28699, dated May 25, 2001, that allowedrecovery of such costs, and IPC filed a Petition for Reconsideration on May 2,2002.  On August 29, 2002, the IPUCissued Order No. 29103 denying the Petition for Reconsideration.  As a result of this order, approximately $12million was expensed in September 2002. IPC believed it was entitled to recover this amount and argued itsposition before the Idaho Supreme Court on December 5, 2003.  On March 30, 2004, the Idaho Supreme Courtset aside the IPUC denial of the recovery of lost revenues and remanded thematter to the IPUC to determine the amount of lost revenues to berecovered.  On December 29, 2004, theIPUC issued Order No. 29669 allowing IPC to recover $12 million in lostrevenues and $2 million in interest. The recovery will be included as part of IPC's annual PCA beginning June1, 2005.

**Oregon:**** **On March 2, 2005 IPC file for an accounting order todefer net power supply costs for the period of March 1, 2005 through February28, 2006 in anticipation of the low water conditions IPC is currentlyexperiencing.  The net system powersupply costs included in this filing was $169 million. IPC is proposing to usethe same methodology for this deferral filing that was accepted in 2002 forOregon's share of IPC's 2001 net power supply expenses.

IPC is also recovering calendar year 2001 excess powersupply costs applicable to the Oregon jurisdiction.  In two separate 2001 orders, the OPUC approved rate increasestotaling six percent, which was the maximum annual rate of recovery allowedunder Oregon state law at that time. These increases were recovering approximately $2 million annually.  During the 2003 Oregon legislative session,the maximum annual rate of recovery was raised to ten percent under certaincircumstances.  IPC requested andreceived authority to increase the surcharge to ten percent.  As a result of the increased recovery rate,which became effective on April 9, 2004, IPC will recover approximately $3million annually.

**Wind Down of Energy Marketing**IDACORPannounced in 2002 that IE would wind down its energy marketing operations.  In connection with the wind down, certainmatters were identified that required resolution with the FERC, the IPUC andthe OPUC.  These matters were resolvedin all three jurisdictions.

**Idaho**:  In an IPUC proceeding thatbegan in May 2001, IPC, the IPUC staff and several interested customer groupsworked cooperatively to determine the appropriate compensation IE shouldprovide to IPC for certain transactions between the affiliates. The IPUC hasissued several orders since then regarding these matters.  Order No. 28852 issued on September 28, 2001covered the time period prior to February 2001.  Order No. 29026 covered the time period from March 2001 throughMarch 2002.  The IPUC also approvedIPC's ongoing hedging and risk management strategies in Order No. 29102 issuedon August 28, 2002.  This orderformalized IPC's agreement to implement a number of changes to its existingpractices for managing risk and initiating hedging purchases and sales.  The $5.8 million in benefits related to theFERC settlement were included in the 2003-2004 PCA and credited to Idaho retailcustomers in accordance with the PCA methodology.  The parties to the proceeding have executed a settlementagreement providing that an additional $5.5 million be flowed through the PCAmechanism to the Idaho retail customers from April 2003 through December2005.  This agreement was filed with theIPUC on February 17, 2004 and approved on March 15, 2004.

**Oregon:**FollowingIPC's settlement with the IPUC on issues related to IPC's past relationshipwith IE, IPC approached the OPUC to settle the issue of fair compensation toOregon customers related to the terminated Electricity Supply ManagementServices Agreement between IPC and IE, as well as any other issues relating totransactions between IPC and IE.  OnOctober 4, 2004, IPC filed a petition with the OPUC requesting an accountingorder approving a settlement stipulation and authorizing IPC to credit itsexisting deferral balance of excess power supply costs.  In the proposed settlement, IPC agrees tocontinue the $7,700 monthly credit to customers that began in July 2001 throughDecember 2005, and to reduce the existing excess power supply cost deferralbalance by a one time credit of $100,000 on January 1, 2005.  The OPUC issued Order No. 04-683 approvingthis settlement on November 22, 2004.

**Regulatory Assets and Liabilities**The following is a breakdown of IPC's regulatory assets andliabilities (in thousands of dollars):

 

**2004**

 

**2003**

 

**Assets**

 

**Liabilities**

 

**Assets**

 

**Liabilities**

Income  taxes

$

344,220

 

$

40,447

 

$

330,833

 

$

41,024

Conservation

 

17,836

 

 

5,205

 

 

21,108

 

 

5,288

Employee  benefits

 

76

 

 

-

 

 

993

 

 

-

PCA  deferral and amortization

 

34,193

 

 

-

 

 

58,310

 

 

-

Oregon  deferral and amortization

 

12,047

 

 

-

 

 

13,620

 

 

-

Derivatives

 

-

 

 

 

 

 

125

 

 

-

Asset  retirement obligations

 

8,372

 

 

147,700

 

 

6,456

 

 

142,595

Deferred  investment tax credits

 

-

 

 

66,836

 

 

-

 

 

67,789

IPUC  settlement order

 

7,119

 

 

13,671

 

 

-

 

 

-

Irrigation  lost revenues

 

13,290

 

 

-

 

 

-

 

 

-

BPA  settlement

 

-

 

 

1,833

 

 

-

 

 

1,735

Incremental  security costs

 

813

 

 

-

 

 

1,076

 

 

-

OPUC  settlement

 

-

 

 

100

 

 

-

 

 

-

Other

 

815

 

 

149

 

 

1,508

 

 

93

 

Total

$

438,781

 

$

275,941

 

$

434,029

 

$

258,524

 

Theregulatory assets related to income taxes and asset retirement obligations donot earn a current return on investment. For further information on the asset retirement obligations amounts, seeNote 17.

In theevent that recovery of costs through rates becomes unlikely or uncertain, SFAS71 would no longer apply.  If IPC wereto discontinue application of SFAS 71 for some or all of its operations, thenthese items may represent stranded investments.  If IPC is not allowed recovery of these investments, it would berequired to write off the applicable portion of regulatory assets and thefinancial effects could be significant.

**FERCMarket-Based Rate Authority**IPC has FERC-approved market-based rate authority, which permits IPCto sell electric energy at market-based rates rather than cost-basedrates.  The FERC requires periodicreviews of the conditions under which this market-based rate authority isgranted to ensure that the rates charged thereunder are just andreasonable.  On April 14, 2004, the FERCissued an order commencing a market power analysis of all companies withmarket-based rate authority; including IPC. In September 2004, IPC filed a revision of its previously approved(October 9, 2003) market power analysis, which it supplemented in September andOctober.  On March 3, 2005, the FERCissued an order accepting IPC's market power analysis.  IPC is required to file another market poweranalysis on or before March 3, 2008.

**14. DERIVATIVE FINANCIAL INSTRUMENTS:**

**Energy TradingContracts**The commodity transactions entered into byIE were classified as energy trading contracts or derivatives in accordancewith SFAS 133, "Accounting for Derivative Instruments and HedgingActivities" and Emerging Issues Task Force Issue 02-3, "IssuesInvolved in Accounting for Derivative Contracts Held for Trading Purposes andContracts Involved in Energy Trading and Risk Management Activities."  Under SFAS 133 as amended, these contractsare recorded on the balance sheet at fair market value.  This accounting treatment is also referredto as mark-to-market accounting. Mark-to-market accounting treatment can create a disconnect betweenrecorded earnings and realized cash flow. Marking a contract to market consists of reevaluating the market value ofthe entire term of the contract at each reporting period and reflecting theresulting gain or loss in earnings for the period.  This change in value represents the difference between thecontract price and the current market value of the contract.  The change in market value of the contractcould result in large gains or losses recorded in earnings at each subsequentreporting period unless there are offsetting changes in value of offsettingcontracts.  The gain or loss generatedfrom the change in market value of the energy trading contracts is a non-cashevent.  If these contracts areheld-to-maturity, the cash flow from the contracts, and their offsettingcontracts, are realized over the life of the contract.

When determining thefair value of marketing and trading contracts, IE used actively quoted pricesfor contracts with similar terms as the quoted price, including specificdelivery points and maturities.  Todetermine fair value of contracts with terms that were not consistent withactively quoted prices IE used, when available, prices provided by otherexternal sources.  When prices fromexternal sources were not available, IE determined prices by using internalpricing models that incorporated available current and historical pricinginformation.  Finally, the fair marketvalue of contracts was adjusted for the impact of market depth and liquidity,potential model error and expected credit losses at the counterparty level.

The following tabledetails the gross margin for the energy marketing operations (in thousands ofdollars):

 

 

**2004**

 

**2003**

 

**2002**

Gross Margin:

 

 

 

 

 

 

 

 

 

 

Realized or otherwise settled

 

$

82 

 

$

61,183 

 

$

70,262 

 

Unrealized

 

 

(131)

 

 

(42,517)

 

 

(65,965)

 

 

Total

 

$

(49)

 

$

18,666 

 

$

4,297 

 

**15. RESTRUCTURING COSTS:**

IDACORPannounced on June 21, 2002 that IE would wind down its power marketingoperations due to changing liquidity requirements brought on by ratingagencies, continued uncertainty in the regulatory and political environment andthe reduction of creditworthy counterparties. On November 5, 2002, IDACORP announced that it was terminating furtherevaluation of growth opportunities in the mid-stream natural gas markets, andstated that IE would close its Denver office by year-end 2002, would shut downits natural gas trading operation in Houston by March 2003 and would furtherreduce its workforce in its Boise operations through mid-2003.  IE has completed the major milestones ofwinding down the business, including the sale of IE's forward book ofelectricity trading contracts to Sempra Energy Trading in August 2003, closingof the Denver, Houston and Boise offices and the final workforce terminationsin November 2003.

IEincurred involuntary termination benefit expenses, lease termination costs andother exit-related costs in connection with the wind down.  Termination benefit expenses relate to thetermination of 98 employees (primarily energy traders and administrativesupport positions).  Of the 98 employeeslaid off, 19 were hired by other IDACORP subsidiaries, and thus received noseverance benefits.  Restructuringexpenses are presented as energy marketing operating expenses on theConsolidated Statements of Income and restructuring accruals are presented asother liabilities on the Consolidated Balance Sheets.

Thefollowing table summarizes restructuring costs during the periods (in thousandsof 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 

 

 

182 

 

 

- 

 

 

4,561 

 

Amounts paid

 

(6,594)

 

 

(645)

 

 

(162)

 

 

(7,401)

 

Amounts reversed

 

(149)

 

 

- 

 

 

- 

 

 

(149)

Balance at December 31, 2003

 

1,807 

 

 

2,022 

 

 

33 

 

 

3,862 

 

Amounts accrued

 

- 

 

 

28 

 

 

- 

 

 

28 

 

Amounts paid

 

(1,807)

 

 

(657)

 

 

- 

 

 

(2,464)

 

Amounts reversed

 

- 

 

 

- 

 

 

(33)

 

 

(33)

Balance at December 31, 2004

$

- 

 

$

1,393 

 

$

- 

 

$

1,393 

 

**16.  INVESTMENTS:**

The following table summarizesIDACORP's and IPC's investments as of December 31 (in thousands of dollars):

 

**2004**

 

**2003**

IPC Investments:

 

 

 

 

 

 

Auction rate securities  (available-for-sale)

$

31,650

 

$

-

 

Equity method investment 

 

25,028

 

 

25,576

 

Available-for-sale equity  securities 

 

21,505

 

 

22,438

 

Executive deferred  compensation

 

6,002

 

 

617

 

Other investments 

 

808

 

 

14

 

 

Total IPC investments 

 

84,993

 

 

48,645

 Investments in affordable housing 

 

108,974

 

 

115,776

 Equity method investments 

 

8,670

 

 

10,772

 Held-to-maturity debt securities 

 

14,164

 

 

16,967

 Executive deferred compensation

 

5,928

 

 

11,264

 Other investments

 

332

 

 

1,050

 

 

Total IDACORP investments 

$

223,061

 

$

204,474

 

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

IFS invests in affordablehousing developments that are accounted for in accordance with APB 18,"The Equity Method of Accounting for Investments in Common Stock" andEmerging Issues Task Force Issue 94-1, "Accounting for Tax BenefitsResulting from Investments in Affordable Housing Projects," and arepresented as Investments on the Consolidated Balance Sheets.  IFS currently accounts for these investmentsusing the equity method, with the exception of one investment consolidatedunder FIN 46R.  All projects arereviewed periodically for impairment.

Thefollowing table presents IDACORP's and IPC's earnings of unconsolidatedequity-method investments (in thousands of dollars):

 

**2004**

 

**2003**

 

**2002**

Bridger  Coal Company (IPC)

$

12,313 

 

$

11,336 

 

$

12,065 

Ida-West  projects

 

1,239 

 

 

1,532 

 

 

993 

IFS  affordable housing projects

 

(12,502)

 

 

(10,461)

 

 

(12,312)

 

Total  

$

1,050 

 

$

2,407  

 

$

746 

** **

**Investments in Debt and EquitySecurities**Investments in debt and equity securities are accounted for inaccordance with SFAS 115, "Accounting for Certain Investments in Debt andEquity Securities."  Thoseinvestments classified as available-for-sale securities are reported at fairvalue, using either specific identification or average cost to determine thecost for computing gains or losses.  Anyunrealized gains or losses on available-for-sale securities are included inother comprehensive income.

IPC held $32 million of auctionrate securities at December 31, 2004. Auction rate securities are long-term instruments whose interest ratesor dividends are reset at specific frequencies.  The typical reset periods are either 28 or 35 days.  The rates or dividends are reset via a Dutchauction.  The original maturities ofthese securities at the time of issuance ranged from 2007 to 2042.

Investments classified asheld-to-maturity securities are reported at amortized cost.  Held-to-maturity securities are investmentsin debt securities for which the company has the positive intent and ability tohold the securities until maturity. These debt securities have maturities ranging from 2005 through 2009.

The following table summarizes investments in debt andequity securities (in thousands of dollars):

 

**2004**

**2003**

 

**Gross**

**Gross**

 

**Gross**

**Gross**

 

 

**Unrealized**

**Unrealized**

**Fair**

**Unrealized**

**Unrealized**

**Fair**

 

**Gain**

**Loss**

**Value**

**Gain**

**Loss**

**Value**

 

 

 

 

 

 

 

 

 

 

 

 

 

Available-for-sale securities (IPC)

$

2,530

$

256

$

53,155

$

2,665

$

276

$

22,438

Held-to-maturity debt securities (IFS)

 

332

 

172

 

14,324

 

354

 

100

 

17,221

 

The following table summarizes sales ofavailable-for-sale securities (in thousands of dollars):

 

**2004**

 

**2003**

 

**2002**

 

 

 

 

 

 

 

 

 

Proceeds from sales

$

266,331

 

$

14,040

 

$

6,815

Gross realized gains from sales

 

2,044

 

 

1,046

 

 

365

Gross realized losses from sales

 

634

 

 

1,169

 

 

1,953

 

Additionally, these investmentsare evaluated to determine whether they have experienced a decline in marketvalue that is considered other-than-temporary. IDACORP and IPC analyze securities in loss positions as of the end ofeach reporting period.  Any securitywith an unrealized loss of more than 20 percent is evaluated forother-than-temporary impairment.  Asecurity will generally be written down to market value if it has an unrealizedloss of 20 percent or more for more than nine months.  If additional information is available that indicates a securityis other-than-temporarily impaired, it will be written down prior to thenine-month time period.  In thealternative, if a security has been impaired for more than nine months butavailable information indicates that the impairment is temporary, the securitywill not be written down.  IDACORP andIPC recognized other-than-temporary impairments of $0.6 million and $1 millionin 2003 and 2002, respectively.  Thesedeclines are included in other income in the Consolidated Statements of Income.  For 2004, it was determined there were noother-than-temporary declines in market value.

The following table summarizesinformation regarding securities that were in an unrealized loss position atthe end of each year, but for which no other-than-temporary impairment wasrecognized (in thousands of dollars).

 

 

 

**Aggregate**

 

**Aggregate**

 

**Aggregate**

 

**Aggregate**

 

**Unrealized**

 

**Related  Fair**

 

**Unrealized**

 

**Related  Fair**

 

**Loss**

 

**Value**

 

**Loss**

 

**Value**

 

**Less  than 12 months**

 

**12  months or longer**

**2004:**

 

 

 

 

 

 

 

 

 

 

 

Available for sale equity  securities (IPC)

$

181

 

$

2,934

 

$

75

 

$

362

Held to maturity debt securities (IFS)

 

97

 

 

4,071

 

 

75

 

 

1,794

 

 

 

 

 

 

 

 

 

 

 

 

**2003:**

 

 

 

 

 

 

 

 

 

 

 

Available for sale equity  securities (IPC)

$

200

 

$

2,577

 

$

76

 

$

359

Held to maturity debt securities (IFS)

 

88

 

 

3,862

 

 

12

 

 

429

 

The available-for-sale equity securitiesin unrealized loss positions are diversified investments in common stock ofvarious companies used to fund IPC's Senior Management Security Plan.  The held-to-maturity debt securities inunrealized loss positions are mainly yield-to-maturity bonds, whose marketvalues fluctuate based on the interest rate environment.  At December 31, 2004, ten available-for-saleand 14 held-to-maturity securities were in an unrealized loss position.  At December 31, 2003, sevenavailable-for-sale and 13 held-to-maturity securities were in an unrealizedloss position.  All unrealized losseswere less than 20 percent.  IDACORP andIPC have the ability and intent to hold the equity securities for a reasonableperiod of time sufficient for a forecasted recovery of fair value and do notconsider these investments to be other-than-temporarily impaired at December31, 2004 or 2003.  Because IDACORP hasthe ability and intent to hold the debt securities until a recovery of fairvalue, which may be maturity, it does not consider them to beother-than-temporarily impaired at December 31, 2004 or 2003.

**17. ASSET RETIREMENTOBLIGATIONS:**

On January 1, 2003, IDACORP andIPC adopted SFAS 143, "Accounting for Asset RetirementObligations."  This statementaddresses financial accounting and reporting for obligations associated withthe retirement of tangible long-lived assets and the associated assetretirement costs.  An obligation mayresult from the acquisition, construction, development or the normal operationof a long-lived asset.  SFAS 143requires an entity to record the fair value of a liability for an assetretirement obligation (ARO) in the period in which it is incurred.  When the liability is initially recorded,the entity increases the carrying amount of the related long-lived asset toreflect the future retirement cost. Over time, the liability is accreted to its present value and paid, andthe capitalized cost is depreciated over the useful life of the 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 AROs.  The adoption of SFAS143 required IPC to redesignate these removal costs as regulatoryliabilities.  As of December 31, 2004,IPC had $148 million of such costs recorded as regulatory liabilities on itsConsolidated Balance Sheet.

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 SFAS 143on April 1, 2003.  Upon adoption of SFAS143, IPC did not record a net change in its investment in Bridger Coal Company,as Bridger Coal Company also is applying regulatory accounting, recordingregulatory assets and liabilities instead of accretion, depreciation and gainsor losses.

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

 

**2004**

 

 

**2003**

Balance at beginning of year

$

7,140

 

 

$

-

Amount recorded on adoption

 

-

 

 

 

6,743

Accretion expense

 

421

 

 

 

397

Revisions in estimated cash flows

 

1,727

 

 

 

-

Balance at end of year

$

9,288

 

 

$

7,140

 

 

 

 

 

 

 

 

** **

** **

** **

**REPORT OF INDEPENDENTREGISTERED PUBLIC ACCOUNTING FIRM**

 

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

Wehave audited the accompanying consolidated balance sheets of IDACORP, Inc. andsubsidiaries (the "Company") as of December 31, 2004 and 2003, andthe related consolidated statements of income, comprehensive income,shareholders' equity and cash flows for each of the three years in the periodended December 31, 2004.  Our auditsalso included the consolidated financial statement schedules listed in theIndex at Item 8.  These financialstatements and financial statement schedules are the responsibility of the Company'smanagement.  Our responsibility is toexpress an opinion on the financial statements and financial statementschedules based on our audits.

Weconducted our audits in accordance with the standards of the Public CompanyAccounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtainreasonable assurance about whether the financial statements are free ofmaterial misstatement.  An auditincludes examining, on a test basis, evidence supporting the amounts anddisclosures in the financial statements. An audit also includes assessing the accounting principles used andsignificant estimates made by management, as well as evaluating the overallfinancial statement presentation.  Webelieve that our audits 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, 2004 and2003, and the results of their operations and their cash flows for each of thethree years in the period ended December 31, 2004 in conformity with accountingprinciples generally accepted in the United States of America.  Also, in our opinion, such consolidatedfinancial statement schedules, when considered in relation to the basicconsolidated financial statements taken as a whole, present fairly in allmaterial respects the information set forth therein.

As described in Note 1to the consolidated financial statements, during 2004 the Company was requiredto consolidate two variable interest entities related to the adoption ofFinancial Accounting Standards Board Interpretation No. 46(R).

We have also audited, in accordance with thestandards of the Public Company Accounting Oversight Board (United States), theeffectiveness of the Company's internal control over financial reporting as ofDecember 31, 2004, based on the criteria established in *Internal Control -Integrated Framework* issued by the Committee of Sponsoring Organizations ofthe Treadway Commission and our report dated March 8, 2005 expressed anunqualified opinion on management's assessment of the effectiveness of theCompany's internal control over financial reporting and an unqualified opinionon the effectiveness of the Company's internal control over financialreporting.

 

 

 

DELOITTE & TOUCHELLP

Boise, IdahoMarch 8, 2005

 

 

 

 

**Idaho Power CompanyConsolidated Statements of Income**

 

**Year  Ended December 31,**

 

**2004**

 

**2003**

 

**2002**

 

**(thousands  of dollars)**

**Operating Revenues:**

 

 

 

 

 

 

 

 

 

General business

$

635,835 

 

$

670,969 

 

$

772,035 

 

Off-system sales

 

121,148 

 

 

71,573 

 

 

55,031 

 

Other revenues

 

62,526 

 

 

37,840 

 

 

39,981 

 

 

Total operating revenues

 

819,509 

 

 

780,382 

 

 

867,047 

 

 

 

 

 

 

 

 

 

**Operating Expenses:**

 

 

 

 

 

 

 

 

 

Operation:

 

 

 

 

 

 

 

 

 

 

Purchased power

 

195,642 

 

 

150,980 

 

 

142,102 

 

 

Fuel expense

 

103,261 

 

 

99,898 

 

 

102,871 

 

 

Power cost adjustment

 

39,184 

 

 

70,762 

 

 

170,489 

 

 

Other

 

194,073 

 

 

156,030 

 

 

150,884 

 

Maintenance

 

58,405 

 

 

62,799 

 

 

54,599 

 

Depreciation

 

100,855 

 

 

97,650 

 

 

93,609 

 

Taxes other than income taxes

 

19,090 

 

 

20,753 

 

 

19,953 

 

 

Total operating expenses

 

710,510 

 

 

658,872 

 

 

734,507 

 

 

 

 

 

 

 

 

 

**Income from Operations**

 

108,999 

 

 

121,510 

 

 

132,540 

 

 

 

 

 

 

 

 

 

**Other Income  (Expense):**

 

 

 

 

 

 

 

 

 

Allowance for equity funds  used during construction

 

3,904 

 

 

3,385 

 

 

333 

 

Earnings of unconsolidated  equity-method investments

 

12,313 

 

 

11,336   

 

 

12,065 

 

Other income

 

12,138 

 

 

8,467 

 

 

7,206 

 

Other expense

 

(9,074)

 

 

(8,326)

 

 

(7,876)

 

 

Total other income

 

19,281 

 

 

14,862 

 

 

11,728 

 

 

 

 

 

 

 

 

 

**Interest Charges:**

 

 

 

 

 

 

 

 

 

Interest on long-term debt

 

50,317 

 

 

54,645 

 

 

51,127 

 

Other interest

 

3,980 

 

 

4,718 

 

 

9,190 

 

Allowance for borrowed funds  used during

 

 

 

 

 

 

 

 

 

 

construction

 

(2,953)

 

 

(3,310)

 

 

(2,375)

 

 

Total interest charges

 

51,344 

 

 

56,053 

 

 

57,942 

 

 

 

 

 

 

 

 

 

**Income Before Income  Taxes**

 

76,936 

 

 

80,319 

 

 

86,326 

 

 

 

 

 

 

 

 

 

**Income Tax Expense  (Benefit)**

 

6,328 

 

 

21,728 

 

 

(2,594)

 

 

 

 

 

 

 

 

 

**Net Income**

 

70,608 

 

 

58,591 

 

 

88,920 

 

 

 

 

 

 

 

 

 

 

Dividends on preferred stock

 

4,823 

 

 

3,430 

 

 

4,587 

 

 

 

 

 

 

 

 

 

**Earnings on Common  Stock**

$

65,785 

 

$

55,161 

 

$

84,333 

 

 

 

 

 

 

 

 

 

 

Theaccompanying notes are an integral part of these statements.

 

 

 

 

**Idaho Power CompanyConsolidated Balance Sheets**

**Assets**

 

 

**December 31,**

 

 

**2004**

 

**2003**

 

 

**(thousands of dollars)**

 

 

 

**Electric  Plant:**

 

 

 

 

 

 

 

In service (at original cost)

 

$

3,324,816 

 

$

3,220,228 

 

 

Accumulated provision for depreciation

 

 

(1,316,125)

 

 

(1,239,604)

 

 

In service - Net

 

 

2,008,691 

 

 

1,980,624 

 

Construction work in progress

 

 

151,652 

 

 

96,086 

 
 

Held for future use

 

 

2,636 

 

 

2,438 

 
 

 

 

Electric plant - Net

 

 

2,162,979 

 

 

2,079,148 

 

 

 

 

 

 

 

 
**Investments  and Other Property**

 

 

86,086 

 

 

49,739 

 
 

 

 

 

 

 

 

**Current  Assets:**

 

 

 

 

 

 

 

Cash and cash equivalents

 

 

17,679 

 

 

4,031 

 

Receivables:

 

 

 

 

 

 

 

 

Customer

 

 

45,441 

 

 

43,694 

 

 

Allowance for uncollectible accounts

 

 

(1,363)

 

 

(1,466)

 

 

Notes

 

 

3,129 

 

 

3,186 

 

 

Employee notes

 

 

3,523 

 

 

3,347 

 

 

Related parties

 

 

1,298 

 

 

1,143 

 

 

Other

 

 

5,253 

 

 

4,848 

 

Accrued unbilled revenues

 

 

33,832 

 

 

30,869 

 
 

Materials and supplies (at average cost)

 

 

26,065 

 

 

19,755 

 
 

Fuel stock (at average cost)

 

 

6,539 

 

 

6,228 

 
 

Prepayments

 

 

28,449 

 

 

26,835 

 
 

Regulatory assets

 

 

5,510 

 

 

6,269 

 
 

 

 

Total current assets

 

 

175,355 

 

 

148,739 

 

 

 

 

 

 

 

 

**Deferred  Debits:**

 

 

 

 

 

 

 

American Falls and Milner water rights

 

 

31,585 

 

 

31,585 

 

Company-owned life insurance

 

 

35,765 

 

 

35,624 

 

Regulatory assets

 

 

433,271 

 

 

427,760 

 

Employee notes

 

 

3,746 

 

 

4,775 

 

Other

 

 

40,425 

 

 

43,341 

 

 

 

Total deferred debits

 

 

544,792 

 

 

543,085 

 

 

 

 

 

 

 

 

 

**Total**

 

$

2,969,212 

 

$

2,820,711 

 

 

 

 

 

 

 

Theaccompanying notes are an integral part of these statements.

 

 

 

 

**Idaho Power CompanyConsolidated Balance Sheets**

**Capitalization and Liabilities**

 

 

**December 31,**

 
 

 

**2004**

 

**2003**

 
 

 

 

**(thousands of dollars)**

 
**Capitalization:**

 

 

 

 

 

 

 
 

Common stock equity:

 

 

 

 

 

 

 
 

 

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

 

 

 

 

 

 

 
 

 

 

authorized; 39,150,812 shares outstanding

 

$

97,877 

 

$

97,877 

 
 

 

Premium on capital stock

 

 

483,707 

 

 

398,231 

 

 

Capital stock expense

 

 

(2,097)

 

 

(2,686)

 

 

Retained earnings

 

 

340,107 

 

 

320,735 

 

 

Accumulated other comprehensive income (loss)

 

 

(888)

 

 

(2,630)

 

 

 

Total common stock equity

 

 

918,706 

 

 

811,527 

 
 

 

 

 

 

 

 

 
 

Preferred stock

 

 

- 

 

 

52,366 

 
 

 

 

 

 

 

 

 
 

Long-term debt

 

 

923,910 

 

 

880,868 

 
 

 

 

Total capitalization

 

 

1,842,616 

 

 

1,744,761 

 
 

 

 

 

 

 

 

 
**Current  Liabilities:**

 

 

 

 

 

 

 
 

Long-term debt due within one year

 

 

60,000 

 

 

50,077 

 
 

Accounts payable

 

 

74,642 

 

 

45,529 

 
 

Notes and accounts payable to related parties

 

 

278 

 

 

75 

 
 

Taxes accrued

 

 

42,228 

 

 

55,383 

 
 

Interest accrued

 

 

13,743 

 

 

12,893 

 
 

Deferred income taxes

 

 

5,510 

 

 

6,179 

 
 

Other

 

 

18,103 

 

 

20,985 

 
 

 

 

Total current liabilities

 

 

214,504 

 

 

191,121 

 
 

 

 

 

 

 

 

 
**Deferred  Credits:**

 

 

 

 

 

 

 
 

Deferred income taxes

 

 

542,829 

 

 

546,205 

 
 

Regulatory liabilities

 

 

275,854 

 

 

258,524 

 
 

Other

 

 

93,409 

 

 

80,100 

 
 

 

 

Total deferred credits

 

 

912,092 

 

 

884,829 

 
 

 

 

 

 

 

 

 
**Commitments  and Contingencies**

 

 

 

 

 

 

 
 

 

 

 

 

 

 

 
 

 

 

**Total**

 

$

2,969,212 

 

$

2,820,711 

 
 

 

 

 

 

 

 

 
Theaccompanying notes are an integral part of these statements.

 

 

 

 

**Idaho Power CompanyConsolidated Statements of Capitalization**

 

 

**December 31,**

 

 

**2004**

 

**%**

 

**2003**

 

**%**

 

 

**(thousands of dollars)**

**Common  Stock Equity:**

 

 

 

Common stock

 

$

97,877 

 

 

 

$

97,877 

 

 

 

Premium on capital stock

 

 

483,707 

 

 

 

 

398,231 

 

 

 

Capital stock expense

 

 

(2,097)

 

 

 

 

(2,686)

 

 

 

Retained earnings

 

 

340,107 

 

 

 

 

320,735 

 

 

 

Accumulated other comprehensive income (loss)

 

 

(888)

 

 

 

 

(2,630)

 

 

 

 

Total common stock equity

 

 

918,706 

 

50

 

 

811,527 

 

47

 

 

 

 

 

 

 

 

 

 

 

**Preferred  Stock:**

 

 

 

 

 

 

 

 

 

 

 

4% preferred stock

 

 

- 

 

 

 

 

12,366 

 

 

 

7.68% Series, serial preferred stock

 

 

- 

 

 

 

 

15,000 

 

 

 

7.07% Series, serial preferred stock

 

 

- 

 

 

 

 

25,000 

 

 

 

 

Total preferred stock

 

 

- 

 

-

 

 

52,366 

 

3

 

 

 

 

 

 

 

 

 

 

 

**Long-Term  Debt:**

 

 

 

 

 

 

 

 

 

 

 

First mortgage bonds:

 

 

 

 

 

 

 

 

 

 

 

 

8     %     Series due 2004

 

 

- 

 

 

 

 

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 

 

 

 

 

70,000 

 

 

 

 

6     %     Series due 2032

 

 

100,000 

 

 

 

 

100,000 

 

 

 

 

5.50%     Series due 2033

 

 

70,000 

 

 

 

 

70,000 

 

 

 

 

5.50%     Series due 2034

 

 

50,000 

 

 

 

 

- 

 

 

 

 

5.875%   Series due 2034

 

 

55,000 

 

 

 

 

- 

 

 

 

 

 

Total first mortgage bonds

 

 

785,000 

 

 

 

 

730,000 

 

 

 

 

Amount due within one year

 

 

(60,000)

 

 

 

 

(50,000)

 

 

 

 

 

Net first mortgage bonds

 

 

725,000 

 

 

 

 

680,000 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Pollution control revenue bonds:

 

 

 

 

 

 

 

 

 

 

 

 

6.05% Series 1996A due 2026

 

 

68,100 

 

 

 

 

68,100 

 

 

 

 

Variable Rate Series 1996B due 2026

 

 

24,200 

 

 

 

 

24,200 

 

 

 

 

Variable Rate Series 1996C due 2026

 

 

24,000 

 

 

 

 

24,000 

 

 

 

 

Variable Rate Series 2000 due 2027

 

 

4,360 

 

 

 

 

4,360 

 

 

 

 

Variable Auction Rate Series 2003 due 2024

 

 

49,800 

 

 

 

 

49,800 

 

 

 

 

 

Total pollution control revenue bonds

 

 

170,460 

 

 

 

 

170,460 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

REA notes

 

 

- 

 

 

 

 

1,105 

 

 

 

 

Amount due within one year

 

 

- 

 

 

 

 

(77)

 

 

 

 

 

Net REA notes

 

 

- 

 

 

 

 

1,028 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

American Falls bond guarantee

 

 

19,885 

 

 

 

 

19,885 

 

 

 

Milner Dam note guarantee

 

 

11,700 

 

 

 

 

11,700 

 

 

 

Unamortized premium/discount - Net

 

 

(3,135)

 

 

 

 

(2,205)

 

 

 

 

 

Total long-term debt

 

 

923,910 

 

50

 

 

880,868 

 

50

 

 

 

 

 

 

 

 

 

 

 

**Total  Capitalization**

 

$

1,842,616 

 

100

 

$

1,744,761 

 

100

 

 

 

 

 

 

 

 

 

 

 

Theaccompanying notes are an integral part of these statements.

 

 

 

**Idaho Power CompanyConsolidated Statements of Cash Flows**

 

**Year Ended December 31,**

 

**2004**

 

**2003**

 

**2002**

 

**(thousands of dollars)**

**Operating  Activities:**

 

 

 

 

 

 

 

 

 

Net income

$

70,608 

 

$

58,591 

 

$

88,920 

 

Adjustments to reconcile net income to net cash  provided by

 

 

 

 

 

 

 

 

 

(used in) operating activities:

 

 

 

 

 

 

 

 

 

 

Impairment of assets

 

9,075 

 

 

- 

 

 

- 

 

 

Depreciation and amortization

 

108,551 

 

 

110,228 

 

 

104,948 

 

 

Deferred taxes and investment tax credits

 

(19,992)

 

 

(44,221)

 

 

(81,511)

 

 

Change in regulatory assets and liabilities

 

16,788 

 

 

68,358 

 

 

164,201 

 

 

Change in:

 

 

 

 

 

 

 

 

 

 

 

Accounts receivable and prepayments

 

(3,846)

 

 

24,447 

 

 

(2,521)

 

 

 

Accounts payable

 

29,112 

 

 

(7,147)

 

 

(23,009)

 

 

 

Taxes receivable/accrued

 

(13,155)

 

 

(33,707)

 

 

97,335 

 

 

 

Other current assets

 

(4,220)

 

 

7,263 

 

 

5,291 

 

 

 

Other current liabilities

 

(2,029)

 

 

(1,427)

 

 

5,980 

 

 

Other assets

 

140 

 

 

(5,776)

 

 

5,276 

 

 

Other liabilities

 

6,753 

 

 

10,119 

 

 

6,720 

 

 

Net cash provided by operating activities

 

197,785 

 

 

186,728 

 

 

371,630 

 

 

 

 

 

 

 

 

 

**Investing  Activities:**

 

 

 

 

 

 

 

 

 

Additions to utility plant

 

(190,286)

 

 

(148,246)

 

 

(128,318)

 

Note receivable payment from parent

 

- 

 

 

19,282 

 

 

11,859 

 

Purchase of available-for-sale securities

 

(295,356)

 

 

(13,689)

 

 

(16,530)

 

Sale of available-for-sale securities

 

266,331 

 

 

14,040 

 

 

6,815 

 

Other assets

 

(38)

 

 

685 

 

 

2,217 

 

 

Net cash used in investing activities

 

(219,349)

 

 

(127,928)

 

 

(123,957)

 

 

 

 

 

 

 

 

 

**Financing  Activities:**

 

 

 

 

 

 

 

 

 

Issuance of long-term debt

 

105,000 

 

 

189,800 

 

 

200,000 

 

Retirement of long-term debt

 

(51,105)

 

 

(209,880)

 

 

(77,078)

 

Retirement of preferred stock

 

(52,351)

 

 

(860)

 

 

(50,994)

 

Sale of common stock to parent

 

- 

 

 

39,987 

 

 

- 

 

Dividends on common stock

 

(46,413)

 

 

(64,726)

 

 

(70,178)

 

Dividends on preferred stock

 

(4,823)

 

 

(3,430)

 

 

(4,587)

 

Decrease in short-term borrowings

 

- 

 

 

(10,500)

 

 

(271,500)

 

Capital contribution from parent

 

85,920 

 

 

- 

 

 

- 

 

Other assets

 

(1,145)

 

 

(7,450)

 

 

(3,745)

 

Other liabilities

 

129 

 

 

(409)

 

 

68 

 

 

Net cash provided by (used in) financing activities

 

35,212 

 

 

(67,468)

 

 

(278,014)

 

 

 

 

 

 

 

 

 

Net increase (decrease) in cash and cash equivalents

 

13,648 

 

 

(8,668)

 

 

(30,341)

Cash and cash equivalents at beginning of year

 

4,031 

 

 

12,699 

 

 

43,040 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents at end of year

$

17,679 

 

$

4,031 

 

$

12,699 

 

 

 

 

 

 

 

 

 

**Supplemental Disclosure of  Cash Flow Information:**

 

Cash paid (received) during the year for:

 

 

 

 

 

 

 

 

 

 

Income taxes paid to (received from) parent

$

39,190 

 

$

99,879 

 

$

(17,974)

 

 

Interest (net of amount capitalized)

 

48,113 

 

 

54,911 

 

 

56,167 

 

 

 

 

 

 

 

 

 

Theaccompanying notes are an integral part of these statements.

** **

** **

** **

** **

**Idaho Power CompanyConsolidated Statements of Retained Earnings**

 

**Year  Ended December 31,**

 

**2004**

 

**2003**

 

**2002**

 

**(thousands  of dollars)**

 

 

 

 

 

 

 

 

 

**Retained Earnings, Beginning of Year**

$

320,735 

 

$

330,300 

 

$

316,856 

 

 

 

 

 

 

 

 

 

**Net Income**

 

70,608 

 

 

58,591 

 

 

88,920 

 

 

 

 

 

 

 

 

 

**Dividends:**

 

 

 

 

 

 

 

 

 

Common stock

 

(46,413)

 

 

(64,726)

 

 

(70,178)

 

Preferred stock

 

(4,823)

 

 

(3,430)

 

 

(4,587)

 

 

 

 

 

 

 

 

 

**Preferred Stock Redemption**

 

- 

 

 

- 

 

 

(711)

 

 

 

 

 

 

 

 

 

**Retained Earnings, End of Year**

$

340,107 

 

$

320,735 

 

$

330,300 

 

 

 

 

 

 

 

 

 

Theaccompanying notes are an integral part of these statements.

 

**Idaho Power CompanyConsolidated Statements of Comprehensive Income**

 

**Year Ended December 31,**

 

**2004**

 

**2003**

 

**2002**

 

**(thousands of dollars)**

 

 

 

 

 

 

 

 

 

**Net  Income**

$

70,608 

 

$

58,591 

 

$

88,920 

 

 

 

 

 

 

 

 

 

**Other  Comprehensive Income (Loss):**

 

 

 

 

 

 

 

 

 

Unrealized gains (losses) on securities:

 

 

 

 

 

 

 

 

 

 

Unrealized holding gains (losses) arising during the  year,

 

 

 

 

 

 

 

 

 

 

 

net of tax of $1,234,   $2,963 and ($1,840) 

 

2,057 

 

 

4,982 

 

 

(2,991)

 

 

Reclassification adjustment for (gains) losses included

 

 

 

 

 

 

 

 

 

 

 

in net income, net of tax of ($768), ($111) and $1,007 

 

(1,195)

 

 

(173)

 

 

1,560 

 

 

 

Net unrealized gains (losses)

 

862 

 

 

4,809 

 

 

(1,431)

 

Minimum pension liability adjustment, net of tax of  $565, ($191) 

 

 

 

 

 

 

 

 

 

 

and ($1,265)

 

880 

 

 

(330)

 

 

(1,959)

 

 

 

 

 

 

 

 

 

**Total  Comprehensive Income**

$

72,350 

 

$

63,070 

 

$

85,530 

 

 

 

 

 

 

 

 

 

Theaccompanying notes are an integral part of these statements.

 

 

 

**IDAHOPOWER COMPANYNOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS**

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

Exceptas modified below, the Notes to the Consolidated Financial Statements ofIDACORP included in this 2004 Annual Report on Form 10-K are incorporatedherein by reference insofar as they relate to IPC.

Note 1   - Summary of Significant AccountingPolicies

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 Contingencies

Note 10 - Benefit Plans

Note 11 - Property, Plant andEquipment and Jointly-Owned Projects

Note 13 - Regulatory Matters

Note 16 - Investments

Note 17 - Asset RetirementObligations

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

**Stock-Based Compensation**The following table illustrates the effect on net income if the fairvalue recognition provisions of SFAS 123 had been applied to stock-basedemployee compensation:

 

**2004**

 

**2003**

 

**2002**

 

**(thousands  of dollars)**

Net income, as reported

$

70,608

 

$

58,591 

 

$

88,920 

Add: Stock-based employee  compensation expense included in

 

 

 

 

 

 

 

 

 

 reported net income, net of related tax effects

 

276

 

 

(56)

 

 

(10)

Deduct:  Total stock-based employee compensation expense determined 

 

 

 

 

 

 

 

 

 

under  fair value based method for all awards ,net of related tax effects

 

977

 

 

1,073 

 

 

1,837 

 

 

Pro forma net income

$

69,907

 

$

57,462 

 

$

87,073 

 

**2.  INCOME TAXES:**

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

 

 

**2004**

 

**2003**

 

**2002**

 

 

**(thousands of dollars)**

Federal income tax expense at 35% statutory rate

$

26,928 

 

$

28,112 

 

$

30,214 

Change in taxes resulting from:

 

 

 

 

 

 

 

 

 

AFDC

 

(2,400)

 

 

(2,343)

 

 

(948)

 

Investment tax credits

 

(3,295)

 

 

(3,397)

 

 

(3,179)

 

Repair allowance

 

(2,450)

 

 

(2,450)

 

 

(2,450)

 

Removal cost

 

(1,244)

 

 

(1,101)

 

 

(815)

 

Pension accrual

 

1,237 

 

 

2,456 

 

 

(26)

 

Capitalized overhead costs

 

(3,658)

 

 

(3,658)

 

 

(3,500)

 

Regulatory tax liability

 

(16,457)

 

 

- 

 

 

- 

 

Tax accounting method change

 

- 

 

 

- 

 

 

(31,162)

 

Settlement of prior years tax returns

 

(1,398)

 

 

(8,908)

 

 

(2,600)

 

State income taxes, net of federal benefit

 

4,100 

 

 

3,973 

 

 

3,946 

 

Depreciation

 

4,350 

 

 

10,237 

 

 

8,940 

 

Other, net

 

615 

 

 

(1,193)

 

 

(1,014)

Total income tax expense (benefit)

$

6,328 

 

$

21,728 

 

$

(2,594)

 

Effective tax rate

 

8.2%

 

 

27.1%

 

 

(3.0)%

 

The items comprising incometax expense are as follows:

 

 

**2004**

 

**2003**

 

**2002**

 

 

**(thousands  of dollars)**

Income taxes currently payable:

 

 

 

 

 

 

 

 

 

Federal

$

19,003 

 

$

55,034 

 

$

70,318 

 

State

 

7,317 

 

 

10,915 

 

 

8,599 

 

 

Total

 

26,320 

 

 

65,949 

 

 

78,917 

Income taxes deferred:

 

 

 

 

 

 

 

 

 

Federal

 

(15,488)

 

 

(35,166)

 

 

(75,600)

 

State

 

(3,551)

 

 

(9,284)

 

 

(5,455)

 

 

Total

 

(19,039)

 

 

(44,450)

 

 

(81,055)

Investment tax credits:

 

 

 

 

 

 

 

 

 

Deferred

 

2,700 

 

 

3,627 

 

 

2,722 

 

Restored

 

(3,653)

 

 

(3,398)

 

 

(3,178)

 

 

Total

 

(953)

 

 

229 

 

 

(456)

Total income tax expense (benefit) 

$

6,328 

 

$

21,728 

 

$

(2,594)

 

 

 

 

 

 

 

 

 

 

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

 

**2004**

 

**2003**

 

**(thousands  of dollars)**

Deferred tax assets:

 

 

 

 

 

 

Regulatory liabilities

$

40,447

 

$

41,024

 

Advances for construction

 

5,357

 

 

4,162

 

Deferred compensation

 

12,324

 

 

9,385

 

Other

 

14,584

 

 

12,329

 

 

Total

 

72,712

 

 

66,900

Deferred tax liabilities:

 

 

 

 

 

 

Property, plant and equipment

 

241,324

 

 

238,602

 

Regulatory assets

 

344,220

 

 

330,833

 

Conservation programs

 

6,972

 

 

8,310

 

PCA

 

20,516

 

 

27,529

 

Partnership investments

 

5,600

 

 

3,770

 

Other

 

2,419

 

 

10,240

 

 

Total

 

621,051

 

 

619,284

 

 

 

 

 

 

Net deferred tax liabilities

$

548,339

 

$

552,384

 

 

 

 

 

 

Amounts accrued for incometaxes are payable to IPC's parent company, IDACORP, as IPC joins in the filingof IDACORP's federal and state consolidated income tax returns.

**3.  COMMON STOCK:**

In December 2004, IDACORPcontributed $86 million of additional equity to IPC.  No additional shares of IPC common stock were issued in thistransaction.

In December 2003, IPC issued1,538,461 shares of $2.50 par value common stock to IDACORP for $40million.  Each share of IPC's commonstock is entitled to one vote.

**5.  LONG-TERM DEBT:**

IPC's $49.8 million HumboldtCounty Pollution Control Revenue bonds are secured by first mortgage bonds,bringing the total first mortgage bonds outstanding at December 31, 2004 to$834.8 million.

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

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

Cashand cash equivalents, customer and other receivables, notes payable, accountspayable, interest accrued and taxes accrued are reported at their carryingvalue as these are a reasonable estimate of their fair value.  The estimated fair values for notesreceivable, long-term debt and investments is based upon quoted market pricesof the same or similar issues or discounted cash flow analyses as appropriate.

 

**December  31, 2004**

 

**December  31, 2003**

 

**Carrying**

 

**Estimated**

 

**Carrying**

 

**Estimated**

 

**Amount**

 

**Fair  Value**

 

**Amount**

 

**Fair  Value**

 

**(thousands  of dollars)**

**Assets:**

 

 

 

 

 

 

 

 

 

 

 

Notes receivable

$

8,946

 

$

8,877

 

$

10,145

 

$

10,159

Investments

 

53,155

 

 

53,155

 

 

22,438

 

 

22,438

 

 

 

 

 

 

 

 

 

 

 

 

**Liabilities:**

 

 

 

 

 

 

 

 

 

 

 

Long-term debt

$

987,045

 

$

1,008,369

 

$

933,150

 

$

957,399

 

**9.  STOCK-BASED COMPENSATION:**

Themaximum number of shares available under the LTICP is 2,050,000.  In 2004, 2003 and 2002, IDACORP granted toIPC employees 110,500, 343,000 and 230,000 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 summarizedas follows:

 

 

**2004**

**2003**

**2002**

 

 

 

**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

889,800 

$

32.50

594,000 

$

38.33

364,000

$

37.59

 

Granted

110,500 

 

31.21

343,000 

 

22.95

230,000

 

39.50

 

Exercised

(4,200)

 

22.92

- 

 

-

-

 

-

 

Forfeited

(40,500)

 

32.27

(47,200)

 

36.42

-

 

-

Outstanding end of  year

955,600 

$

32.41

889,800 

$

32.50

594,000

$

38.33

 

 

 

 

 

 

 

 

 

 

 

Exercisable

374,800 

$

35.43

211,600 

$

37.84

100,800

$

37.10

 

The following table summarizes information aboutstock options outstanding at December 31, 2004:

 

**Outstanding**

**Exercisable**

 

 

 

**Weighted**

 

 

 

 

**Weighted**

**average**

 

**Weighted**

 

 

**average**

**remaining**

 

**average**

 

**Number**

**exercise**

**contractual**

**Number**

**exercise**

**Exercise Price Ranges**

**of shares**

**price**

**life**

**of shares**

**price**

$22.92 - $31.21

428,800

$

24.98

8.80 years

64,000

$

22.95

$35.81 - $40.31 

526,800

$

38.45

6.29 years

310,800

$

38.00

 

Restrictedstock and performance share awards are compensatory awards and IPC accruescompensation expense, which is charged to operations, based upon the marketvalue of the granted shares.  For 2004,2003 and 2002, total compensation accrued under the Restricted Stock Plan wasless than $1 million annually.

The following tablesummarizes restricted stock activity:

 

**2004**

 

**2003**

 

**2002**

Shares  outstanding - beginning of year

80,454 

 

77,192 

 

58,024 

Shares  granted

61,806 

 

41,945 

 

38,752 

Shares  forfeited

(24,014)

 

(1,889)

 

(132)

Shares  issued

- 

 

(36,794)

 

(19,452)

Shares  outstanding - end of year

118,246 

 

80,454 

 

77,192 

Weighted  average fair value of current year stock

 

 

 

 

 

 

grants  on grant date

$

31.21

$

 

22.95 

 

$

38.64 

 

 

 

 

 

 

 

**18. RELATEDPARTY 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 $76million.  The notes receivable were dueover periods of one to ten years, bore interest at IDACORP's overall variableshort-term borrowing rate and were paid in full in 2003.

IPCperforms corporate functions such as financial, legal and management servicesfor IDACORP and its subsidiaries.  IPCcharges IDACORP for the costs of these services based on service agreements andother specifically identified costs. IPC billed IDACORP $4 million, $3 million and $1 million in 2004, 2003and 2002, respectively, for these services.

**IDACORPEnergy**In 2002, IPC paid IE approximately $2 million under the ElectricitySupply Management Services Agreement. In August 2002, IPC and IE terminated the agreement eliminating allfuture payments.  The FERC gave publicnotice of IPC's request to cancel the agreement and no comments on the requestwere filed by the due date.

Thefollowing table presents IPC's sales to and purchases from IE for the yearsended December 31:

 

**2004**

 

**2003**

 

**2002**

 

**(thousands  of dollars)**

Sales  to IE

$

-

 

$

2,268

 

$

27,182

Purchases  from IE

 

-

 

 

-

 

 

13,665

 

 

 

 

 

 

 

 

 

 

**IDACOMM**IPC provides project management andengineering services to IDACOMM. IDACOMM also pays joint use fees to IPC.  Total fees charged to IDACOMM were $0.3 million, $0.3million and $1.1 million in 2004, 2003 and 2002, respectively.

**Ida-West**IPC purchases all of the power generatedby four of Ida-West's hydroelectric projects. IPC paid $7 million per year in 2004, 2003 and 2002.

 

 

**REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTINGFIRM**

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

We have audited theaccompanying consolidated balance sheets and statements of capitalization ofIdaho Power Company and subsidiary (the "Company") as of December 31,2004 and 2003, and the related consolidated statements of income, comprehensiveincome, retained earnings and cash flows for each of the three years in theperiod ended December 31, 2004.  Ouraudits also included the consolidated financial statement schedule listed inthe Index at Item 8.  These financialstatements and financial statement schedule are the responsibility of theCompany's management.  Ourresponsibility is to express an opinion on the financial statements andfinancial statement schedule based on our audits.

Weconducted our audits in accordance with the standards of the Public CompanyAccounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtainreasonable assurance about whether the financial statements are free ofmaterial misstatement.  An auditincludes examining, on a test basis, evidence supporting the amounts anddisclosures in the financial statements. An audit also includes assessing the accounting principles used andsignificant estimates made by management, as well as evaluating the overallfinancial statement presentation.  Webelieve that our audits 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, 2004and 2003, and the results of their operations and their cash flows for each ofthe three years in the period ended December 31, 2004, 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.

We have also audited, in accordance with thestandards of the Public Company Accounting Oversight Board (United States), theeffectiveness of the Company's internal control over financial reporting as ofDecember 31, 2004, based on the criteria established in *Internal Control -Integrated Framework* issued by the Committee of Sponsoring Organizations ofthe Treadway Commission and our report dated March 8, 2005 expressed anunqualified opinion on management's assessment of the effectiveness of theCompany's internal control over financial reporting and an unqualified opinionon the effectiveness of the Company's internal control over financialreporting.

DELOITTE& TOUCHE LLP

Boise,IdahoMarch 8, 2005

 

 

 

**SUPPLEMENTAL FINANCIALINFORMATION, UNAUDITED**

**QUARTERLY FINANCIALDATA:**

The following unauditedinformation is presented for each quarter of 2004 and 2003 (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**

 

 

 

 

 

 

 

 

 

2004

 

 

 

 

 

 

 

 

Revenues

$

188,189 

$

211,872 

$

246,677 

$

197,752 

Income  from operations

 

36,194 

 

15,407 

 

18,933 

 

22,717 

Income  tax expense (benefit)

 

4,685 

 

(3,379)

 

(20,886)

 

(5,191)

Net income

 

19,659 

 

12,992 

 

26,067 

 

14,266 

Earnings per share of common stock

 

0.51 

 

0.34 

 

0.68 

 

0.37 

 

 

 

 

 

 

 

 

 

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 

 

 

 

 

 

 

 

 

 

 

**Idaho Power Company:**

 

**Quarter Ended**

 

**March 31**

**June 30**

**September 30**

**December 31**

 

 

 

 

 

 

 

 

 

2004

 

 

 

 

 

 

 

 

Revenues

$

183,326

$

205,693

$

240,219 

$

190,271

Income  from operations

 

40,854

 

18,411

 

20,396 

 

29,338

Income  tax expense (benefit)

 

13,169

 

273

 

(13,981)

 

6,867

Net income

 

20,263

 

8,790

 

26,995 

 

14,560

Dividends on preferred stock

 

854

 

853

 

3,116 

 

-

Earnings on common stock

 

19,409

 

7,937

 

23,879 

 

14,560

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

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

None

**ITEM 9A. CONTROLS AND PROCEDURES**

(a)Disclosure controls and procedures:

**IDACORP:**

TheChief Executive Officer and Chief Financial Officer of IDACORP, based on theirevaluation of IDACORP's disclosure controls and procedures (as defined inExchange Act Rule 13a-15(e)) as of December 31, 2004, have concluded thatIDACORP's disclosure controls and procedures are effective.

**IPC:**

TheChief Executive Officer and Chief Financial Officer of IPC, based on theirevaluation of IPC's disclosure controls and procedures (as defined in ExchangeAct Rule 13a-15(e)) as of December 31, 2004, have concluded that IPC'sdisclosure controls and procedures are effective.

(b)Internal control over financial reporting:

**IDACORP:**

**Management'sAnnual Report On Internal Control Over Financial Reporting**The management of IDACORP is responsible for establishing and maintaining adequateinternal control over financial reporting for IDACORP.  Internal control over financial reporting isdefined in Rule 13a-15(f) promulgated under the Securities Exchange Act of 1934as a process designed by, or under the supervision of, the company's principalexecutive and principal financial officers and effected by the company's boardof directors, management and other personnel, to provide reasonable assuranceregarding the reliability of financial reporting and the preparation offinancial statements for external purposes in accordance with accountingprinciples generally accepted in the United States of America and includesthose policies and procedures that:

Pertainto the maintenance of records that in reasonable detail accurately and fairlyreflect the transactions and dispositions of the assets of the company;

Providereasonable assurance that transactions are recorded as necessary to permitpreparation of financial statements in accordance with accounting principlesgenerally accepted in the United States of America, and that receipts andexpenditures of the company are being made only in accordance with the authorizationsof management and directors of the company; and

Providereasonable assurance regarding prevention or timely detection of unauthorizedacquisition, use or disposition of the company's assets that could have amaterial effect on the financial statements.

 

Becauseof its inherent limitations, internal control over financial reporting may notprevent or detect misstatements. Projections of any evaluation of effectiveness to future periods aresubject to the risk that controls may become inadequate because of changes inconditions, or that the degree of compliance with the policies or proceduresmay deteriorate.

IDACORP's managementassessed the effectiveness of the company's internal control over financialreporting as of December 31, 2004.  Inmaking this assessment, the company's management used the criteria set forth bythe Committee of Sponsoring Organizations of the Treadway Commission in *InternalControl-Integrated Framework*.

Basedon its assessment, management believes that, as of December 31, 2004, IDACORP's internalcontrol over financial reporting is effective based on those criteria.

IDACORP'sindependent registered public accounting firm has audited the financialstatements included in this Annual Report on Form 10-K for the year ended December31, 2004 and issued a report, which appears on the next page and expresses anunqualified opinion on management's assessment and on the effectiveness ofIDACORP's internal control over financial reporting as of December 31, 2004.

March8, 2005

 

 

**REPORTOF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM**

To theBoard of Directors and Shareholders of IDACORP, Inc.Boise, Idaho

We haveaudited management's assessment, included in the accompanying Management'sAnnual Report on Internal Control over Financial Reporting, that IDACORP, Inc.and subsidiaries (the "Company") maintained effective internalcontrol over financial reporting as of December 31, 2004, based on criteriaestablished in *Internal Control-Integrated Framework* issued by theCommittee of Sponsoring Organizations of the Treadway Commission.  The Company's management is responsible formaintaining effective internal control over financial reporting and for itsassessment of the effectiveness of internal control over financialreporting.  Our responsibility is toexpress an opinion on management's assessment and an opinion on theeffectiveness of the Company's internal control over financial reporting basedon our audit.

Weconducted our audit in accordance with the standards of the Public CompanyAccounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtainreasonable assurance about whether effective internal control over financialreporting was maintained in all material respects.  Our audit included obtaining an understanding of internal controlover financial reporting, evaluating management's assessment, testing andevaluating the design and operating effectiveness of internal control, andperforming such other procedures as we considered necessary in thecircumstances.  We believe that ouraudit provides a reasonable basis for our opinions.

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

Becauseof the inherent limitations of internal control over financial reporting,including the possibility of collusion or improper management override ofcontrols, material misstatements due to error or fraud may not be prevented ordetected on a timely basis.  Also,projections of any evaluation of the effectiveness of the internal control overfinancial reporting to future periods are subject to the risk that the controlsmay become inadequate because of changes in conditions, or that the degree ofcompliance with the policies or procedures may deteriorate.

In ouropinion, management's assessment that the Company maintained effective internalcontrol over financial reporting as of December 31, 2004, is fairly stated, inall material respects, based on the criteria established in *InternalControl-Integrated Framework* issued by the Committee of Sponsoring Organizationsof the Treadway Commission.  Also in ouropinion, the Company maintained, in all material respects, effective internalcontrol over financial reporting as of December 31, 2004, based on the criteriaestablished in *Internal Control-Integrated Framework* issued by theCommittee of Sponsoring Organizations of the Treadway Commission.

We havealso audited, in accordance with the standards of the Public Company AccountingOversight Board (United States), the consolidated financial statements andfinancial statement schedules as of and for the year ended December 31, 2004 ofthe Company and our report dated March 8, 2005 expressed an unqualified opinionon those financial statements and financial statement schedules and included anexplanatory paragraph regarding the Company's adoption of Financial AccountingStandards Board Interpretation No. 46(R).

DELOITTE& TOUCHE LLP

Boise,IdahoMarch 8, 2005

 

**IPC:**

**Management'sAnnual Report on Internal Control Over Financial Reporting**The management of IPC is responsible for establishing and maintaining adequateinternal control over financial reporting of IPC.  Internal control over financial reporting is defined in Rule13a-15(f) promulgated under the Securities Exchange Act of 1934 as a processdesigned by, or under the supervision of, the company's principal executive andprincipal financial officers and effected by the company's board of directors,management and other personnel, to provide reasonable assurance regarding thereliability of financial reporting and the preparation of financial statementsfor external purposes in accordance with accounting principles generallyaccepted in the United States of America and includes those policies andprocedures that:

Pertainto the maintenance of records that in reasonable detail accurately and fairlyreflect the transactions and dispositions of the assets of the company;

Providereasonable assurance that transactions are recorded as necessary to permitpreparation of financial statements in accordance with accounting principlesgenerally accepted in the United States of America, and that receipts andexpenditures of the company are being made only in accordance with theauthorizations of management and directors of the company; and

Providereasonable assurance regarding prevention or timely detection of unauthorizedacquisition, use or disposition of the company's assets that could have amaterial effect on the financial statements.

 

Becauseof its inherent limitations, internal control over financial reporting may notprevent or detect misstatements. Projections of any evaluation of effectiveness to future periods aresubject to the risk that controls may become inadequate because of changes inconditions, or that the degree of compliance with the policies or proceduresmay deteriorate.

IPC's managementassessed the effectiveness of the company's internal control over financialreporting as of December 31, 2004.  Inmaking this assessment, the company's management used the criteria set forth bythe Committee of Sponsoring Organizations of the Treadway Commission in *InternalControl-Integrated Framework*.

Basedon its assessment, management believes that, as of December 31, 2004, IPC's internalcontrol over financial reporting is effective based on those criteria.

IPC'sindependent registered public accounting firm has audited the financialstatements included in this Annual Report on Form 10-K for the year endedDecember 31, 2004 and issued a report, which appears on the next page andexpresses an unqualified opinion on management's assessment and on theeffectiveness of IPC's internal control over financial reporting as of December31, 2004.

March8, 2005

 

 

 

**REPORTOF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM**

To theBoard of Directors and Shareholder of Idaho Power CompanyBoise, Idaho

We haveaudited management's assessment, included in the accompanying Management'sAnnual Report on Internal Control over Financial Reporting, that Idaho PowerCompany and subsidiary (the "Company") maintained effective internalcontrol over financial reporting as of December 31, 2004, based on criteriaestablished in *Internal Control-Integrated Framework* issued by theCommittee of Sponsoring Organizations of the Treadway Commission.  The Company's management is responsible formaintaining effective internal control over financial reporting and for itsassessment of the effectiveness of internal control over financialreporting.  Our responsibility is toexpress an opinion on management's assessment and an opinion on the effectivenessof the Company's internal control over financial reporting based on our audit.

Weconducted our audit in accordance with the standards of the Public CompanyAccounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtainreasonable assurance about whether effective internal control over financialreporting was maintained in all material respects.  Our audit included obtaining an understanding of internal controlover financial reporting, evaluating management's assessment, testing andevaluating the design and operating effectiveness of internal control, andperforming such other procedures as we considered necessary in thecircumstances.  We believe that ouraudit provides a reasonable basis for our opinions.

Acompany's internal control over financial reporting is a process designed by,or under the supervision of, the company's principal executive and principalfinancial officers, or persons performing similar functions, and effected bythe company's board of directors, management, and other personnel to providereasonable assurance regarding the reliability of financial reporting and thepreparation of financial statements for external purposes in accordance withgenerally accepted accounting principles. A company's internal control over financial reporting includes thosepolicies and procedures that (1) pertain to the maintenance of records that, inreasonable detail, accurately and fairly reflect the transactions anddispositions of the assets of the company; (2) provide reasonable assurancethat transactions are recorded as necessary to permit preparation of financialstatements in accordance with generally accepted accounting principles, andthat receipts and expenditures of the company are being made only in accordancewith authorizations of management and directors of the company; and (3) providereasonable assurance regarding prevention or timely detection of unauthorizedacquisition, use, or disposition of the company's assets that could have a materialeffect on the financial statements.

Becauseof the inherent limitations of internal control over financial reporting,including the possibility of collusion or improper management override ofcontrols, material misstatements due to error or fraud may not be prevented ordetected on a timely basis.  Also,projections of any evaluation of the effectiveness of the internal control overfinancial reporting to future periods are subject to the risk that the controlsmay become inadequate because of changes in conditions, or that the degree ofcompliance with the policies or procedures may deteriorate.

In ouropinion, management's assessment that the Company maintained effective internalcontrol over financial reporting as of December 31, 2004, is fairly stated, inall material respects, based on the criteria established in *InternalControl-Integrated Framework* issued by the Committee of SponsoringOrganizations of the Treadway Commission. Also in our opinion, the Company maintained, in all material respects,effective internal control over financial reporting as of December 31, 2004,based on the criteria established in *Internal Control-Integrated Framework*issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We havealso audited, in accordance with the standards of the Public Company AccountingOversight Board (United States), the consolidated financial statements andfinancial statement schedule as of and for the year ended December 31, 2004 ofthe Company and our report dated March 8, 2005 expressed an unqualified opinionon those financial statements and financial statement schedule.

DELOITTE& TOUCHE LLP

Boise,IdahoMarch 8, 2005

 

 

**Changesin Internal Control Over Financial Reporting**Section 404 of the Sarbanes-Oxley Act of 2002 (SOX) and the rulesissued thereunder require that as of December 31, 2004, IDACORP's and IPC'sChief Executive Officer and Chief Financial Officer assess the effectiveness ofIDACORP's and IPC's internal control over financial reporting.  This internal control report must include:(i) a statement of management's responsibility for establishing and maintainingadequate internal control over financial reporting, (ii) a statementidentifying the framework used by management to conduct the required evaluationof the effectiveness of the company's internal control over financialreporting, (iii) management's assessment of the effectiveness of the company'sinternal control over financial reporting as of December 31, 2004, including astatement as to whether or not internal control over financial reporting iseffective and (iv) a statement that the company's independent registered publicaccounting firm has issued an attestation report on management's assessment ofinternal control over financial reporting. To satisfy this requirement, IDACORP and IPC developed and implemented aSOX 404 process, which includes steps to (i) identify significant accounts anddisclosures and related financial statement assertions, (ii) document theexisting control activities for each significant account, and disclosure andrelated assertions, (iii) test each of those control activities, (iv) identifycontrol deficiencies, if any, (v) remediate the identified control deficienciesand (vi) test the remediated control activity to ensure that the identifiedcontrol deficiencies have been properly remediated.

IDACORP and IPC have completed their SOX 404process for 2004.  Set forth above iseach company's Management's Annual Report on Internal Control Over FinancialReporting, stating that as of December 31, 2004 each company's internal controlover financial reporting is effective, and each company's independent publicaccounting firm's report, which expresses an unqualified opinion onmanagement's assessment and on the effectiveness of internal control overfinancial reporting as of December 31, 2004.

**ITEM 9B. OTHER INFORMATION**

None

**PART III**

**ITEM10.  DIRECTORS AND EXECUTIVE OFFICERS OFTHE REGISTRANT**

Theportion of IDACORP's definitive proxy statement appearing under the captions"Election of Directors - Nominees For Election - Terms Expire 2008,""Continuing Directors - Terms Expire 2007," "ContinuingDirectors - Terms Expire 2006," "The Board of Directors andCommittees - Committees - Audit Committee," "Section 16(a) BeneficialOwnership Reporting Compliance" and "Corporate Governance - Code ofEthics," to be filed pursuant to Regulation 14A for the 2005 AnnualMeeting of Shareholders to be held on May 19, 2005 is hereby incorporated byreference.

**ITEM11.  EXECUTIVE COMPENSATION**

Theportion of IDACORP's definitive proxy statement appearing under the caption"Compensation of Directors and Executive Officers"  (except the Report of the CompensationCommittee and the Performance Graph) to be filed pursuant to Regulation 14A forthe 2005 Annual Meeting of Shareholders to be held on May 19, 2005 is herebyincorporated by reference.

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

** **

Theportion of IDACORP's definitive proxy statement appearing under the caption"Security Ownership of Directors and Executive Officers" and theRegulation S-K, Item 201(d) information appearing under the caption"Amendment of the IDACORP Long-Term Incentive and Compensation Plan toIncrease Number of Shares Subject to the Plan" to be filed pursuant toRegulation 14A for the 2005 Annual Meeting of Shareholders to be held on May19, 2005 is hereby incorporated by reference.

**ITEM13.  CERTAIN RELATIONSHIPS AND RELATEDTRANSACTIONS**

None

**ITEM14.  PRINCIPAL ACCOUNTANT FEES ANDSERVICES**

**IDACORP:**

Theportion of IDACORP's definitive proxy statement appearing under the caption"Independent Accountant Billings" in the proxy statement to be filedpursuant to Regulation 14A for the 2005 Annual Meeting of Shareholders to beheld on May 19, 2005 is hereby incorporated by reference.

**IPC:**

Thefollowing table presents fees billed for professional services rendered byDeloitte & Touche LLP, the member firms of Deloitte Touche Tohmatsu, andtheir respective affiliates (collectively, Deloitte & Touche), for thefiscal years ended December 31, 2004 and 2003. The amounts presented below reflect allocations from IDACORP for IPC'sportion of the fees, as well as amounts billed directly to IPC.

 

**2004**

 

**2003**

 
Audit  fees

$

760,496

 

$

306,485

 
Audit-related  fees (1)

 

74,243

 

 

120,455

 
Tax  fees (2)

 

140,472

 

 

91,170

 
All  other fees

 

-

 

 

-

 
Total

$

975,211

 

$

518,110

 
 

 

 

 

 

 

 
(1)

Includes  fees for audits of IPC's benefit plans and Sarbanes-Oxley Section 404  readiness assistance.

(2)

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

 

**Policy on Audit Committee Pre-Approval**IPC and the Audit Committee are committed to ensuring the independence of theindependent registered public accounting firm, both in fact and inappearance.  In this regard, the AuditCommittee has established a pre-approval policy in accordance with applicablesecurities rules.  All fees werepre-approved by the Audit Committee in 2004.

OnFebruary 4, 2004, the IPC Audit Committee adopted a policy for pre-approval ofservices to be performed by the company's independent public accounting firm.

Inaddition to the audits of IPC's consolidated financial statements, theindependent public accounting firm may be engaged to provide certainaudit-related, tax and other services. The Audit Committee must pre-approve all services performed by theindependent public accounting firm to assure that the provision of thoseservices does not impair the public accounting firm's independence.  The services that the Audit Committee willconsider include audit services such as attest services, changes in the scopeof the audit of the financial statements, and the issuance of comfort lettersand consents in connection with financings; audit-related services such asinternal control reviews and assistance with internal control reportingrequirements; attest services related to financial reporting that are notrequired by statute or regulation, and accounting consultations and auditsrelated to proposed transactions and new or proposed accounting rules,standards and interpretations; and tax compliance and planning services.  Unless a type of service to be provided bythe independent public accounting firm has received general pre-approval, itwill require specific pre-approval by the Audit Committee.  In addition, any proposed services exceedingpre-approved cost levels will require specific pre-approval by the AuditCommittee.  Under the pre-approvalpolicy, the Audit Committee has delegated to the Chairman of the AuditCommittee pre-approval authority for proposed audit and audit-relatedservices.  The Chairman must report anypre-approval decisions to the Audit Committee at its next scheduled meeting.

Anyrequest to engage the independent public accounting firm to provide a servicewhich has not received general pre-approval must be submitted as a writtenproposal to IPC's Chief Financial Officer with a copy to the GeneralCounsel.  The request must include adetailed description of the service to be provided, the proposed fee and thebusiness reasons for engaging the independent public accounting firm to providethe service.  Upon approval by the ChiefFinancial Officer, the General Counsel and the independent public accountingfirm that the proposed engagement complies with the terms of the pre-approvalpolicy and the applicable rules and regulations, the request will be presentedto the Audit Committee or the Committee Chairman, as the case may be, forpre-approval.

Indetermining whether to pre-approve the engagement of the independent publicaccounting firm, the Audit Committee or the Committee Chairman, as the case maybe, must consider, among other things, the pre-approval policy, applicablerules and regulations and whether the nature of the engagement and the relatedfees are consistent with the following principles, as stated in the SEC'sadopting release for the rules on auditor independence:

theindependent public accounting firm cannot function in the role of management ofIPC;

theindependent public accounting firm cannot audit its own work; and

theindependent public accounting firm cannot serve in any advocacy role on behalfof IPC.

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

**PART IV**

ITEM 15.  EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

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

(3) Exhibits.

*Previously Filed and Incorporated Herein byReference

**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 8-K  dated January 20, 2005 

3.3

Articles of Amendment to  Restated Articles of Incorporation of IPC, as amended, as filed with the  Secretary of State of Idaho on January 21, 2005.

 

 

 

 

*3(b)

1-3198  Form 8-K  dated January 20, 2005

3.2

Amended Bylaws of IPC,  amended on January 20, 2005 and presently in effect.

 

 

 

 

*3(c)

33-56071

3(d)

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

 

 

 

 

*3(d)

333-64737

3.1

Articles of Incorporation of  IDACORP, Inc.

 

 

 

 

 

 

 

 

 

 

 

 

*3(d)(i)

333-64737

3.2

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

 

 

 

 

*3(d)(ii)

333-00139

3(b)

Articles of Amendment to  Articles of Incorporation of IDACORP, Inc. creating A Series Preferred Stock,  without par value, as filed with the Secretary of State of Idaho on September  17, 1998.

 

 

 

 

*3(e)

1-14456  Form 8-K  dated January 20, 2005

3.1

Amended Bylaws of IDACORP,  Inc., amended on January 20, 2005 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)

1-14465  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

1-14465  1-3198  Form 10-Q  for the quarter  ended 3/31/04

10(h)(i)

The Revised Security Plan for  Senior Management Employees - a non-qualified, deferred compensation plan,  amended and restated effective November 20, 2003.

 

 

 

 

 

 

 

 

1 Compensatory plan

 

 

 

 

 

 

 

 

 

 

 

 

 

 

*10(h)(ii) 1

1-14465  1-3198  Form 8-K  dated January 20, 2005

10.2

2005 IDACORP, Inc. 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-Q  for the quarter  ended 9/30/04

10(h)(iv)

Form  of Restricted Stock Award Agreement.

 

 

 

 

*10(h)(v) 1

1-14465  1-3198  Form 10-Q  for the quarter   ended 9/30/04

10(h)(v)

Form  of Performance Share Award Agreement.

 

 

 

 

*10(h)(vi) 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)(vii) 1

1-14465  1-3198  Form 8-K  dated 1/20/05

10.9

IDACORP, Inc. Non-Employee  Directors Stock Compensation Plan as amended on January 20, 2005.

 

 

 

 

*10(h)(viii)

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

10(h)

Form of Change in Control  Agreement between IDACORP, Inc. and Jan B. Packwood, J. LaMont Keen, James C.  Miller, Darrel T. Anderson, Thomas R.   Saldin and A. Bryan Kearney.

 

 

 

 

*10(h)(ix) 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(h)(x) 1

1-14465  1-3198  Form 10-Q  for the quarter  ended 9/30/04

10(h)(x)

Form of Stock Option Award  Agreement.

 

 

 

 

*10(h)(xi) 1

1-14465  1-3198  Form 10-Q  for the quarter   ended 6/30/04

10(h)(viii)

Form of Officer  Indemnification Agreement as signed by all Officers of IDACORP, Inc. and IPC.

 

 

 

 

 

 

 

 

 

 

 

 

1 Compensatory plan

 

 

 

 

 

 

 

 

 

 

*10(h)(xii) 1

1-14465  1-3198  Form 10-Q  for the quarter  ended 6/30/04

10(h)(ix)

Form of Director  Indemnification Agreement as signed by all Directors of IDACORP, Inc.

 

 

 

 

*10(h)(xiii) 1

1-14465  1-3198  Form 8-K  dated November 24, 2004

10

Employment Agreement, dated  November 24, 2004, by and between IDACORP, Inc. and Luci K. McDonald.

 

 

 

 

*10(h)(xiv) 1

1-14465  1-3198  Form 8-K  dated December 29, 2004

10

Consulting agreement, dated  as of January 3, 2005, by and between Robert W. Stahman and IPC, including  its parent IDACORP, Inc. and all subsidiaries and affiliates.

 

 

 

 

*10(h)(xv)

1-14465  1-3198  Form 8-K  dated January 20, 2005

10.1

IDACORP, Inc. and Idaho Power  Company NEO 2005 Base Compensation Table.

 

 

 

 

*10(h)(xvi)

1-14465  1-3198  Form 8-K  dated January 20, 2005

10.3

2005 IDACORP, Inc. Executive  Incentive Plan NEO Award Opportunity Chart.

 

 

 

 

*10(h)(xvii)

1-14465  1-3198  Form 8-K  dated January 20, 2005

10.4

IDACORP, Inc. 2000 Long-Term  Incentive and Compensation Plan-Form of Restricted Stock Award Agreement  (time vesting).

 

 

 

 

*10(h)(xviii)

1-14465  1-3198  Form 8-K  dated January 20, 2005

10.5

IDACORP, Inc. 2000 Long-Term  Incentive and Compensation Plan-Form of Restricted Stock Award Agreement  (performance vesting).

 

 

 

 

*10(h)(xix) 1

1-14465  1-3198  Form 8-K  dated January 20, 2005

10.6

IDACORP, Inc. 2000 Long-Term  Incentive and Compensation Plan Restricted Stock Awards (time vesting) to  NEOs Chart.

 

 

 

 

*10(h)(xx) 1

1-14465  1-3198  Form 8-K  dated January 20, 2005

10.7

IDACORP, Inc. 2000 Long-Term  Incentive and Compensation Plan Restricted Stock Awards (performance vesting)  to NEOs Chart.

 

 

 

 

*10(h)(xxi) 1

1-14465  1-3198  Form 8-K  dated January 20, 2005

10.8

IDACORP, Inc. and Idaho Power  Company 2005 Compensation for Non-Employee Directors of the Board of  Directors.

 

 

 

 

*10(h)(xxii) 1

1-14465  1-3198  Form 8-K  dated January 20, 2005

10.9

IDACORP, Inc. Non-Employee  Directors Stock Compensation Plan, as amended on January 20, 2005.

 

 

 

 

 

 

 

 

1 Compensatory plan

 

 

*10(h)(xxiii) 1

1-14465  1-3198  Form 8-K  dated January 20, 2005

10.10

Jan B. Packwood 2005  Restricted Stock Award Agreement.

 

 

 

 

10(h)(xxiv)

 

 

Offer of employment letter  dated July 9, 2004, to Thomas R. Saldin from IDACORP, Inc.

 

 

 

 

*10(h)(xxv) 1

1-14465  1-3198  Form 8-K  dated February 17, 2005

10.1

IDACORP, Inc. 2004 Executive  Incentive Plan.

 

 

 

 

*10(h)(xxvi)

1-14465  1-3198  Form 8-K  dated February 17, 2005

10.2

IDACORP, Inc. 2004 Executive  Incentive Plan NEO Incentive Chart.

 

 

 

 

*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.)

 

 

 

 

 

 

 

 

1 Compensatory plan

 

 

 

 

 

 

12(c)

 

 

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

 

 

 

 

12(d)

 

 

Statement Re:  Computation of Ratio of Earnings to Fixed  Charges.  (IPC)

 

 

 

 

12 (e)

 

 

Statement Re:  Computation of Supplemental Ratio of Earnings  to Fixed Charges.  (IPC)

 

 

 

 

21

 

 

Subsidiaries of IDACORP,  Inc..

 

 

 

 

23

 

 

Consent of Independent  Registered Public 

 

 

 

 

Accounting Firm.

 

 

 

 

31(a)

 

 

IDACORP, Inc. Rule 13a-14(a)  certification.

 

 

 

 

31(b)

 

 

IDACORP, Inc. Rule 13a-14(a)  certification.

 

 

 

 

31(c)

 

 

IPC Rule 13a-14(a)  certification.

 

 

 

 

31(d)

 

 

IPC Rule 13a-14(a)  certification.

 

 

 

 

32(a)

 

 

IDACORP, Inc. Section 1350  certification.

 

 

 

 

32(b)

 

 

IPC Section 1350  certification.

 

 

 

 

 

 

 

**IDACORP, Inc.SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT**

**CONDENSED STATEMENTS OF INCOME**

 

**Year Ended December 31,**

 

**2004**

 

**2003**

 

**2002**

 

(thousands of dollars)

**Income:**

 

 

 

 

 

 

 

 

 

Equity  in income of subsidiaries

$

76,482 

 

$

48,163 

 

$

63,417 

 

Other  income

 

535 

 

 

2,309 

 

 

4,981 

 

 

Total  income

 

77,017 

 

 

50,472 

 

 

68,398 

 

 

 

 

 

 

 

 

 

 

**Expenses:**

 

 

 

 

 

 

 

 

 

Operating  expenses

 

5,782 

 

 

5,340 

 

 

4,564 

 

Interest  expense

 

1,221 

 

 

1,088 

 

 

3,550 

 

Other  expense

 

994 

 

 

1,570 

 

 

2,221 

 

 

Total  expenses

 

7,997 

 

 

7,998 

 

 

10,335 

 

 

 

 

 

 

 

 

 

**Income  Before Income Taxes**

 

69,020 

 

 

42,474 

 

 

58,063 

 

 

 

 

 

 

 

 

 

**Income  Tax Benefit**

 

(3,963)

 

 

(4,104)

 

 

(3,609)

 

 

 

 

 

 

 

 

 

**Net  Income**

$

72,983 

 

$

46,578 

 

$

61,672 

 

 

 

 

 

 

 

 

 

 

 

The accompanying notes are an integral part of thesestatements.

 

 

**IDACORP, Inc.SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT**

**CONDENSED BALANCE SHEETS**

 

**December 31,**

 

**2004**

 

**2003**

 

(thousands  of dollars)

**Assets**

 

 

 

 

 

 

 

 

 

 

 

**Current  Assets:**

 

 

 

 

 

 

Cash  and cash equivalents

$

2,637

 

$

60,921

 

Receivables

 

1,467

 

 

1,642

 

Taxes  receivable

 

-

 

 

5,106

 

Deferred  income taxes

 

28,211

 

 

10,021

 

Other

 

692

 

 

678

 

 

Total  current assets

 

33,007

 

 

78,368

 

 

 

 

 

 

 

**Investment  in subsidiaries**

 

1,033,141

 

 

900,682

 

 

 

 

 

 

 

**Other  Assets**

 

 

 

 

 

 

Intercompany  notes receivable

 

35,753

 

 

48,160

 

Other

 

1,396

 

 

570

 

 

Total  other assets

 

37,149

 

 

48,730

 

 

 

 

 

 

 

 

 

 

 

**Total**

**$**

1,103,297

$

 

1,027,780

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

**Liabilities  and Shareholders' Equity**

 

 

 

 

 

 

 

 

 

 

 

**Current  Liabilities:**

 

 

 

 

 

 

Notes  payable

$

35,400

 

$

93,650

 

Accounts  payable

 

3,127

 

 

13,757

 

Taxes  accrued

 

4,242

 

 

-

 

Other

 

1

 

 

17

 

 

Total  current liabilities

 

42,770

 

 

107,424

 

 

 

 

 

 

 

**Other  Liabilities:**

 

 

 

 

 

 

Intercompany  notes payable

 

51,537

 

 

55,860

 

Other

 

704

 

 

215

 

 

Total  other liabilities

 

52,241

 

 

56,075

 

 

 

 

 

 

**Shareholders'  Equity**

 

1,008,286

 

 

864,281

 

 

 

 

 

 

 

 

 

**Total**

$

1,103,297

$

 

1,02,780

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

The accompanying notes are an integral part of thesestatements.

 

 

**IDACORP, Inc.SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT**

**CONDENSED STATEMENTS OF CASHFLOWS**

 

**Year Ended December 31,**

 

**2004**

 

**2003**

 

**2002**

 

(thousands of dollars)

 

 

 

 

 

 

 

 

 

**Operating Activities:**

 

 

 

 

 

 

 

 

 

Net cash provided by (used in)  operating activities

$

23,958 

 

$

131,533 

 

$

64,888 

 

 

 

 

 

 

 

 

 

 

 

**Investing Activities:**

 

 

 

 

 

 

 

 

 

Contributions to subsidiaries

 

(100,456)

 

 

(40,237)

 

 

(566)

 

Distributions from  subsidiaries

 

- 

 

 

77,792 

 

 

- 

 

Change in intercompany notes  receivable

 

12,407 

 

 

66,286 

 

 

(45,575)

 

Other

 

(53)

 

 

158 

 

 

191 

 

 

Net cash provided by (used in)  investing activities

 

(88,102)

 

 

103,999 

 

 

(45,950)

 

 

 

 

 

 

 

 

 

**Financing Activities:**

 

 

 

 

 

 

 

 

 

Issuance of common stock

 

115,690 

 

 

4,123 

 

 

15,770 

 

Dividends on common stock

 

(45,837)

 

 

(64,726)

 

 

(70,178)

 

Increase (decrease) in  short-term borrowings

 

(58,250)

 

 

(72,050)

 

 

85,200 

 

Change in intercompany notes  payable

 

(4,323)

 

 

(41,025)

 

 

(49,730)

 

Other

 

(1,420)

 

 

(1,227)

 

 

(1,247)

 

 

Net cash provided by (used in)  financing activities

 

5,860 

 

 

(174,905)

 

 

(20,185)

 

 

 

 

 

 

 

 

 

Net increase (decrease) in  cash and cash equivalents

 

(58,284)

 

 

60,627 

 

 

(1,247)

 

 

 

 

 

 

 

 

 

Cash and cash equivalents at  beginning of year

 

60,921 

 

 

294 

 

 

1,541 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents at  end of year

$

2,637 

 

$

60,921 

 

$

294 

 

 

 

 

 

 

 

 

 

 

 

The accompanying notes are an integral part of thesestatements.

 

 

 

**IDACORP, Inc.SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT**

**NOTES TO CONDENSED FINANCIALSTATEMENTS**

**1.  BASIS OF PRESENTATION**

Pursuantto rules and regulations of the Securities and Exchange Commission, theunconsolidated condensed financial statements of IDACORP, Inc. do not reflectall of the information and notes normally included with financial statementsprepared in accordance with accounting principles generally accepted in theUnited States of America.  Therefore,these financial statements should be read in conjunction with the consolidatedfinancial statements and related notes included in the 2004 Form 10-K, Part II,Item 8.

**Accountingfor subsidiaries**IDACORP hasaccounted for the earnings of its subsidiaries under the equity method in theunconsolidated condensed financial statements.

 

 

 

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

Years Ended December 31, 2004, 2003 and 2002

**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)**

 

 

2004:

 

 

 

 

 

 

 

 

 

 

Reserves Deducted From

 

 

 

 

 

 

 

 

 

 

 

Applicable Assets:

 

 

 

 

 

 

 

 

 

 

 

 

Reserve for uncollectible accounts

$

43,210

$

3,010 

$

- 

$

3,112

$

43,108

 

 

Reserve for uncollectible notes

 

2,578

 

- 

 

- 

 

-

 

2,578

Other Reserves:

 

 

 

 

 

 

 

 

 

 

 

Rate refunds

 

1,514

 

- 

 

- 

 

1,114

 

400

 

Injuries and damages reserve

 

831

 

1,801 

 

- 

 

835

 

1,797

 

Miscellaneous operating reserves

 

61

 

- 

 

- 

 

26

 

35

 

 

 

 

 

 

 

 

 

 

 

2003:

 

 

 

 

 

 

 

 

 

 

Reserves Deducted From

 

 

 

 

 

 

 

 

 

 

 

Applicable Assets:

 

 

 

 

 

 

 

 

 

 

 

 

Reserve for uncollectible accounts

$

43,311

$

3,958 

$

- 

$

4,059

$

43,210

 

 

Reserve for uncollectible notes

 

-

 

2,578 

 

- 

 

-

 

2,578

Other Reserves:

 

 

 

 

 

 

 

 

 

 

 

Rate refunds

 

-

 

1,514 

 

- 

 

-

 

1,514

 

Injuries and damages reserve

 

1,936

 

111 

 

- 

 

1,216

 

831

 

Miscellaneous operating reserves

 

-

 

61

 

- 

 

-

 

61

 

 

 

 

 

 

 

 

 

 

 

2002:

 

 

 

 

 

 

 

 

 

 

Reserves Deducted From

 

 

 

 

 

 

 

 

 

 

 

Applicable Assets:

 

 

 

 

 

 

 

 

 

 

 

 

Reserve for uncollectible accounts

$

42,529

$

5,415 

$

- 

$

4,633

$

43,311

Other Reserves:

 

 

 

 

 

 

 

 

 

 

 

Injuries and damages reserve

 

1,500

 

(255)

 

719 

 

28

 

1,936

 

Miscellaneous operating reserves

 

1,286

 

- 

 

(250)

 

1,036

 

-

 

 

 

 

 

 

 

 

 

 

 

 

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, 2004, 2003 and 2002

**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)**

 
 

 
2004:

 

 

 

 

 

 

 

 

 

 

 
Reserves Deducted From

 

 

 

 

 

 

 

 

 

 

 
 

Applicable Assets:

 

 

 

 

 

 

 

 

 

 

 
 

 

Reserve for uncollectible accounts

$

1,466

$

3,010 

$

- 

$

3,113

$

1,363

 
Other Reserves:

 

 

 

 

 

 

 

 

 

 

 
 

Rate refunds

 

1,514

 

- 

 

- 

 

1,114

 

400

 
 

Injuries and damages reserve

 

831

 

1,801 

 

- 

 

835

 

1,797

 
 

Miscellaneous operating reserves

 

61

 

- 

 

- 

 

26

 

35

 
 

 

 

 

 

 

 

 

 

 

 

 
2003:

 

 

 

 

 

 

 

 

 

 

 
Reserves Deducted From

 

 

 

 

 

 

 

 

 

 

 
 

Applicable Assets:

 

 

 

 

 

 

 

 

 

 

 
 

 

Reserve for uncollectible accounts

$

1,566

$

3,958 

$

- 

$

4,058

$

1,466

 
Other Reserves:

 

 

 

 

 

 

 

 

 

 

 
 

Rate refunds

 

-

 

1,514 

 

- 

 

-

 

1,514

 
 

Injuries and damages reserve

 

1,936

 

111 

 

- 

 

1,216

 

831

 
 

Miscellaneous operating reserves

 

-

 

61 

 

- 

 

-

 

61

 
 

 

 

 

 

 

 

 

 

 

 

 
2002:

 

 

 

 

 

 

 

 

 

 

 
Reserves Deducted From

 

 

 

 

 

 

 

 

 

 

 
 

Applicable Assets:

 

 

 

 

 

 

 

 

 

 

 
 

 

Reserve for uncollectible accounts

$

1,500

$

4,699 

$

- 

$

4,633

$

1,566

 
Other Reserves:

 

 

 

 

 

 

 

 

 

 

 
 

Injuries and damages reserve

 

1,500

 

(255)

 

719 

 

28

 

1,936

 
 

Miscellaneous operating reserves

 

1,286

 

- 

 

(250)

 

1,036

 

-

 
 

 

 

 

 

 

 

 

 

 

 

 

 
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)

March9, 2005

By:    */s/JanB. 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  9, 2005

 

 

Jon  H. Miller

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

By:

 

*/s/Jan  B. Packwood*

 

/s/

President  and Chief Executive

"

 

 

Jan  B. Packwood

 

 

Officer  and Director

 

 

 

 

 

 

 

 

By:

 

*/s/J.  LaMont Keen*

 

 

 

 

 

 

J.  LaMont Keen

 

 

Executive  Vice President

"

 

 

 

 

 

and  Director

 

 

 

 

 

 

 

 

By:

 

*/s/Darrel  T. Anderson*

 

/s/

Senior  Vice President - Administrative

"

 

 

Darrel  T. Anderson

 

 

Services  and Chief Financial Officer

 

 

 

 

 

 

(Principal  Financial Officer)

 

 

 

 

 

 

(Principal  Accounting Officer)

 

 

 

 

 

 

 

 

By:

 

*/s/Rotchford  L. Barker*

By:

 

*/s/Joan  H. Smith*

"

 

 

Rotchford  L. Barker

 

 

Joan  H. Smith

 

 

 

Director

 

 

Director

 

 

 

 

 

 

 

 

By:

 

*/s/Gary  G. Michael*

By:

 

*/s/Robert  A. Tinstman*

"

 

 

Gary  G. Michael

 

 

Robert  A. Tinstman

 

 

 

Director

 

 

Director

 

 

 

 

 

 

 

 

By:

 

*/s/Peter  S. O'Neill*

By:

 

*/s/Thomas  J. Wilford*

"

 

 

Peter  S. O'Neill

 

 

Thomas  J. Wilford

 

 

 

Director

 

 

Director

 

 

 

 

 

 

 

 

By:

 

*/s/Richard  G. Reiten*

By:

 

 

"

 

 

Richard  G. Reiten

 

 

Jack  K. Lemley

 

 

 

Director

 

 

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)

March9, 2005

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

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

 

 

By:

 

*/s/Jon  H. Miller*

 

 

Chairman  of the Board

March 9, 2005

 
 

 

Jon  H. Miller

 

 

 

 

 
 

 

 

 

 

 

 

 
 

 

 

 

 

 

 

 
By:

 

*/s/Jan  B. Packwood*

 

 

Chief  Executive Officer

"

 
 

 

Jan  B. Packwood

 

 

and  Director

 

 
 

 

 

 

 

 

 

 
 

 

 

 

 

 

 

 
By:

 

*/s/J.  LaMont Keen*

 

 

President  and Chief Operating

"

 
 

J.  LaMont Keen

 

Officer  and Director

 

 
 

 

 

 

 

 

 

 
 

 

 

 

 

 

 

 
By:

 

*/s/Darrel  T. Anderson*

 

/s/

Senior  Vice President - Administrative

"

 
 

 

Darrel  T. Anderson

 

 

Services  and Chief Financial Officer

 

 
 

 

 

 

 

(Principal  Financial Officer)

 

 
 

 

 

 

 

(Principal  Accounting Officer)

 

 
 

 

 

 

 

 

 

 
By:

 

*/s/Rotchord  L. Barker*

By:

 

*/s/Joan  H. Smith*

"

 

 

Rotchford  L. Barker

 

 

Joan  H. Smith

 

 

 

Director

 

 

Director

 

 

 

 

 

 

 

 

By:

 

*/s/Gary  G. Michael*

By:

 

*/s/Robert  A. Tinstman*

"

 

 

Gary  G. Michael

 

 

Robert  A. Tinstman

 

 

 

Director

 

 

Director

 

 

 

 

 

 

 

 

By:

 

*/s/Peter  S. O'Neill*

By:

 

*/s/Thomas  J. Wilford*

"

 

 

Peter  S. O'Neill

 

 

Thomas  J. Wilford

 

 

 

Director

 

 

Director

 

 

 

 

 

 

 

 

By:

 

*/s/Richard  G. Reiten*

By:

 

 

"

 

 

Richard  G. Reiten

 

 

Jack  K. Lemley

 

 

 

Director

 

 

Director

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

**EXHIBITINDEX**

 

 

 

Exhibit Number

 

 

 

 

 

 

 

 

10(h)(xxiv)

 

Offer of employment letter dated July 9, 2004,  to Thomas R. Saldin from IDACORP, Inc.

 

 

 

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)

 

 

 

21

 

Subsidiaries  of IDACORP, Inc.

 

 

 

23

 

Consent  of Independent Registered Public Accounting Firm.

 

 

 

31(a)

 

Rule  13a-14(a) certification.

 

 

 

31(b)

 

Rule  13a-14(a) certification.

 

 

 

31(c)

 

Rule  13a-14(a) certification.

 

 

 

31(d)

 

Rule  13a-14(a) certification.

 

 

 

32(a)

 

Section  1350 certification.

 

 

 

32(b)

 

Section  1350 certification.

 

 

 

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