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**UNITEDSTATES SECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549FORM10-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, 2007      |

OR

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

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

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

Indicate by check markwhether the registrants are well-known seasoned issuers, as defined in Rule 405of the Securities Act.

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

Indicate by check mark if theregistrants are not required to file reports pursuant to Section 13 or Section15(d) of the Act.

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

Indicate by check markwhether the registrants (1) have filed all reports required to be filed bySection 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding12 months (or for such shorter period that the registrants were required tofile such reports), and (2) have been subject to such filing requirements forthe past 90 days.

Yes  ( X  )  No  (    )

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

Indicate by check mark whether the registrants are largeaccelerated filers, accelerated filers, non-accelerated filers, or smallerreporting companies.

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

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

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

Aggregate market value ofvoting and non-voting common stock held by nonaffiliates (June 30, 2007):

| IDACORP, Inc.: | $1,410,558,106 | Idaho Power Company: | None |
|----------------|----------------|----------------------|------|

Number of shares of commonstock outstanding at January 31, 2008:

| IDACORP, Inc.:       | 45,069,259                            |
|----------------------|---------------------------------------|
| 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 2008 Annual Meeting of Shareholders to be held on |
|                                     |  | May 15,  2008. |

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

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

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| **COMMONLY USED TERMS** |
|-------------------------|
| ** **              |
| AFDC                    | - | Allowance for Funds Used  During Construction |
| CAMP                    | - | Comprehensive Aquifer  Management Plan |
| CEP                     | - | Continuous Equity Program |
| cfs                     | - | Cubic feet per second |
| EIS                     | - | Environmental impact  statement |
| Energy Act              | - | Energy Policy Act of 2005 |
| EPS                     | - | Earnings per share |
| ESA                     | - | Endangered Species Act |
| ESPA                    | - | Eastern Snake Plain Aquifer |
| FASB                    | - | Financial Accounting  Standards Board |
| FERC                    | - | Federal Energy Regulatory  Commission |
| FIN                     | - | Financial Accounting  Standards Board Interpretation |
| Fitch                   | - | Fitch, Inc. |
| FPA                     | - | Federal Power Act |
| GAAP                    | - | Generally Accepted Accounting  Principles |
| Ida-West                | - | Ida-West Energy, a  subsidiary of IDACORP, Inc. |
| IDEQ                    | - | Idaho Department of  Environmental Quality |
| IDWR                    | - | Idaho Department of Water  Resources |
| IE                      | - | IDACORP Energy, a  subsidiary of IDACORP, Inc. |
| IERCO                   | - | Idaho Energy Resources Co.,  a subsidiary of Idaho Power Company |
| IFS                     | - | IDACORP Financial Services,  a subsidiary of IDACORP, Inc. |
| IPC                     | - | Idaho Power Company, a  subsidiary of IDACORP, Inc. |
| IPUC                    | - | Idaho Public Utilities Commission |
| IRP                     | - | Integrated Resource Plan |
| ITI                     | - | IDACORP Technologies, Inc. |
| IWRB                    | - | Idaho Water Resource Board |
| kW                      | - | Kilowatt |
| maf                     | - | Million acre feet |
| MD&A                | - | Management's Discussion and  Analysis of Financial Condition and Results of Operations |
| Moody's                 | - | Moody's Investors Service |
| MW                      | - | Megawatt |
| MWh                     | - | Megawatt-hour |
| NEPA                    | - | National Environmental  Policy Act of 1996 |
| O&M                 | - | Operations and Maintenance |
| OPUC                    | - | Oregon Public Utility Commission |
| PCA                     | - | Power Cost Adjustment |
| PCAM                    | - | Power Cost Adjustment  Mechanism |
| PURPA                   | - | Public Utility Regulatory  Policies Act of 1978 |
| RFC                     | - | River Forecast Center |
| RFP                     | - | Request for Proposal |
| S&P                 | - | Standard & Poor's  Ratings Services |
| SFAS                    | - | Statement of Financial  Accounting Standards |
| SO2                     | - | Sulfur Dioxide |
| SRBA                    | - | Snake River Basin  Adjudication |
| Valmy                   | - | North Valmy Steam Electric  Generating Plant |
| VIEs                    | - | Variable Interest Entities |

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| **TABLE OF CONTENTS** |
|-----------------------|
|                       | **Page** |
| **Part I**            |
|                       |
|                       | Item 1. | Business | 1-10 |
|                       | Item 1A. | Risk Factors | 10-13 |
|                       | Item 1B. | Unresolved Staff Comments | 13 |
|                       | Item 2. | Properties | 14-15 |
|                       | Item 3. | Legal Proceedings | 15 |
|                       | Item 4. | Submission of Matters to a  Vote of Security Holders | 15 |
|                       |
|                       | Executive Officers of the  Registrants | 16-17 |
|                       |
| **Part II**           |
| ** **            |
|                       | Item 5. | Market for Registrant's  Common Equity, Related Stockholder |  |
|                       |  |  | Matters and Issuer  Purchases of Equity Securities | 18-19 |
|                       | Item 6. | Selected Financial Data | 20 |
|                       | Item 7. | Management's Discussion and  Analysis of Financial Condition and |  |
|                       |  |  | Results of Operations | 21-64 |
|                       | Item 7A. | Quantitative and  Qualitative Disclosures about Market Risk | 64-65 |
|                       | Item 8. | Financial Statements and  Supplementary Data | 66-119 |
|                       | Item 9. | Changes in and  Disagreements with Accountants on Accounting and |  |
|                       |  |  | Financial Disclosure | 119 |
|                       | Item 9A. | Controls and Procedures | 120-125 |
|                       | Item 9B. | Other Information | 125 |
| ** **            |
| **Part III**          |
| ** **            |
|                       | Item 10. | Directors, Executive  Officers and Corporate Governance* | 125 |
|                       | Item 11. | Executive Compensation* | 125 |
|                       | Item 12. | Security Ownership of  Certain Beneficial Owners and Management and Related |  |
|                       |  |  | Stockholder Matters* | 125-126 |
|                       | Item 13. | Certain Relationships and  Related Transactions, and Director Independence* | 126 |
|                       | Item 14. | Principal Accountant Fees  and Services* | 126-127 |
|                       |
| ** **            |
| ** **            |
|                       | Item 15. | Exhibits and Financial  Statement Schedules | 128-139 |
|                       |
|                       | Signatures | 140-141 |
|                       |
|                       |  |  |
|                       |
|                       | *Except as indicated in  Item 12, IDACORP, Inc. information is incorporated by reference to IDACORP, |
|                       |  | Inc.'s definitive proxy  statement for the 2008 Annual Meeting of Shareholders. |
|                       |  |  |  |  |  |

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

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

**ITEM1.  BUSINESS**

**OVERVIEW:**

IDACORP, Inc. (IDACORP) is aholding company formed in 1998 whose principal operating subsidiary is IdahoPower Company (IPC).  IDACORP is subject to the provisions of the PublicUtility Holding Company Act of 2005, which provides certain access to books andrecords to the Federal Energy Regulatory Commission (FERC) and state utilityregulatory commissions and imposes certain record retention and reportingrequirements on IDACORP.

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

IDACORP's other subsidiariesinclude:

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

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

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

IDACORP's strategy emphasizesIPC as IDACORP's core business.  IPC is experiencing moderate customer growthin its service area, and this corporate strategy recognizes that IPC must makesubstantial investments in infrastructure to ensure adequate electricity supplyand reliable service.  IPC's regulatory plans for 2008 include finalizing the2007 general rate case as well as additional initiatives designed to speedrecovery of the financial and operating costs of new facilities and system improvements. IFS and Ida-West remain components of the corporate strategy.

On July 20, 2006, IDACORPcompleted the sale of all of the outstanding common stock of IDACORPTechnologies, Inc. to IdaTech UK Limited, a wholly-owned subsidiary of InvestecGroup Investments (UK) Limited, and on February 23, 2007, IDACORP completed thesale of all of the outstanding common stock of IDACOMM, Inc. to American FiberSystems, Inc.  IDACORP's consolidated financial statements reflect thereclassification of the results of these businesses as discontinued operationsfor all periods presented.  Discontinued operations are discussed in moredetail in Note 16 to IDACORP's and IPC's Consolidated Financial Statements.

At December 31, 2007, IDACORPhad 2,044 full-time employees, 2,028 of which were employed by IPC.

IDACORP's only reportable businesssegment is IPC, which contributed $77 million to income from continuingoperations in 2007.

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IDACORP and IPC makeavailable free of charge their Annual Report on Form 10-K, Quarterly Reports onForm 10-Q, Current Reports on Form 8-K and all amendments to these reportsfiled or furnished pursuant to Section 13(a) or 15(d) of the SecuritiesExchange Act of 1934 as soon as reasonably practicable after the reports areelectronically filed with or furnished to the Securities and ExchangeCommission, through IDACORP's website at www.idahocorpinc.com and through alink to the IDACORP website from the IPC website at www.idahopower.com.

**UTILITY OPERATIONS:**

IPC was incorporated underthe laws of the state of Idaho in 1989 as successor to a Maine corporationorganized in 1915.  IPC's service territory covers a 24,000 square mile area insouthern Idaho and eastern Oregon, with an estimated population of 982,000. IPC holds franchises in 71 cities in Idaho and nine cities in Oregon and holdscertificates from the respective public utility regulatory authorities to serveall or a portion of 25 counties in Idaho and three counties in Oregon.  As ofDecember 31, 2007, IPC supplied electric energy to approximately 482,000general business customers.

IPC is one of the nation'sfew investor-owned utilities with a predominantly hydroelectric generatingbase.  IPC owns and operates 17 hydroelectric generation developments, twonatural gas-fired plants and one diesel-powered generator and shares ownershipin three coal-fired generating plants.  These generating plants and theircapacities are listed in Item 2 - "Properties."  IPC's coal-fired plants are inWyoming, Oregon and Nevada, and use low-sulfur coal from Wyoming and Utah.

The primary influences onelectricity sales are weather, customer growth and economic conditions. Extreme temperatures increase sales to customers who use electricity forcooling and heating, and moderate temperatures decrease sales.  Increasedprecipitation levels during the agricultural growing season reduce electricitysales to customers who use electricity to operate irrigation pumps.

IPC's principal commercialand industrial customers are involved in food processing, electronics andgeneral manufacturing, forest products, beet sugar refining and winterrecreation.

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

IPC is subject tothe provisions of the FPA as a "licensee" as therein defined.  As a licenseeunder the FPA, IPC and its licensed hydroelectric projects are subject to theprovisions of Part I of the FPA.  All licenses are subject to conditions setforth in the FPA and related FERC regulations.  These conditions andregulations include provisions relating to condemnation of a project uponpayment of just compensation, amortization of project investment from excessproject earnings, possible takeover of a project after expiration of itslicense upon payment of net investment, severance damages and other matters.

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

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**Rates**The rates IPC charges to its generalbusiness customers are determined by the IPUC and the OPUC.  Significant ratecases and proceedings are discussed in more detail in Part II, Item 7 - "MD&A- REGULATORY MATTERS."  Approximately 95 percent of IPC's general businessrevenue comes from customers in Idaho.  IPC has a Power Cost Adjustment (PCA)mechanism that provides for annual adjustments to the rates charged to itsIdaho retail customers.  These adjustments are based on forecasts of net powersupply costs, which are fuel and purchased power less off-system sales, and thetrue-up of the prior year's forecast.  During the year, approximately 90percent of the difference between the actual and forecasted costs is deferredwith 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 or over-recovered portion, is then included in the calculation ofthe next year's PCA.  IPC has also applied to the OPUC to implement a PCAmechanism in Oregon similar to the one in Idaho.

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

IPC's system is dual peaking,with the larger peak demand occurring in the summer.  The all-time system peakdemand is 3,193 megawatts (MW), set on July 13, 2007.  The previous hourlysystem peak of 3,084 MW was set in 2006.  The all-time winter peak demand is2,464 MW set on January 24, 2008.  The previous hourly system winter peak of2,459 MW was set in 1998.  IPC expects total system average load to grow 2.1percent annually over the next three years.

Because of its reliance onhydroelectric generation, IPC's generation operations can be significantlyaffected by weather conditions.  The availability of hydroelectric powerdepends on the amount of snow pack in the mountains upstream of IPC's hydroelectricfacilities, reservoir storage, springtime snow pack run-off, river base flows,spring flows, rainfall and other weather and stream flow managementconsiderations.  During low water years, when stream flows into IPC'shydroelectric projects are reduced, IPC's hydroelectric generation is reduced. This results in less generation from IPC's resource portfolio (hydroelectric,coal-fired and gas-fired) available for off-system sales and, most likely, anincreased use of purchased power to meet load requirements.  Both of thesesituations - a reduction in off-system sales and an increased use of moreexpensive purchased power - result in increased power supply costs.

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

|               | **MWh**                 | ** ** | **Percent of total generation** |
|---------------|-------------------------|------------|---------------------------------|
|               | **2007**                | ** ** | **2006**                        | ** ** | **2005** | ** ** | **2007** | ** ** | **2006** | ** ** | **2005** |
|               | **(thousands of MWhs)** | ** ** | ** **                      | ** ** | ** ** | ** ** | ** ** |
| Hydroelectric | 6,181                   |            | 9,207                           |  | 6,199 |  | 46% |  | 57% |  | 46% |
| Thermal       | 7,367                   |            | 7,021                           |  | 7,315 |  | 54% |  | 43% |  | 54% |
|               | Total system generation | 13,548     |                                 | 16,228 |  | 13,514 |  | 100% |  | 100% |  | 100% |
|               |                         |            |                                 |  |  |  |  |  |  |  |  |  |

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

The generation from IPC'shydroelectric facilities in 2007 was reduced due to poor stream flow conditions. The observed stream flow data released on August 1, 2007, by the NationalWeather Service's Northwest River Forecast Center (RFC) indicated that Brownleereservoir inflow for April through July 2007 was 2.8 million acre-feet (maf),or 44 percent of the RFC average.  Brownlee reservoir inflow for 2007 totaled8.5 maf, or 56 percent of the RFC average.

Streamflow projections for2008 are somewhat improved.  Storage in selected federal reservoirs upstream ofBrownlee as of February 10, 2008 was 76 percent of average.  The stream flowforecast released on February 14, 2008, by the RFC predicts that Brownleereservoir inflow for April through July 2008 will be 5.7 maf, or 90 percent ofthe RFC average.

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IPC's generating facilitiesare interconnected through its integrated transmission system and are operatedon a coordinated basis to achieve maximum load-carrying capability andreliability.  IPC's transmission system is directly interconnected with thetransmission systems of the Bonneville Power Administration, AvistaCorporation, PacifiCorp, NorthWestern Energy and Sierra Pacific Power Company. Such interconnections, coupled with transmission line capacity made availableunder agreements with some of the above entities, permit the interchange,purchase and sale of power among all major electric systems in the west.  IPCis a member of the Western Electricity Coordinating Council, the WesternSystems Power Pool, the Northwest Power Pool, the Northern Tier TransmissionGroup, and the North American Energy Standards Board.  These groups have beenformed to more efficiently coordinate transmission reliability and planningthroughout the western grid.  See "Competition - Wholesale" below.**Fuel: **IPC, through its subsidiary IERCO, owns a one-thirdinterest in Bridger Coal, which owns the Jim Bridger mine that supplies coal tothe Jim Bridger generating plant (one-third owned by IPC) in Wyoming.  Themine, located near the Jim Bridger plant, operates under a long-term salesagreement that provides for delivery of coal over a 51-year period ending in2024 from surface, high-wall, and underground sources.  The Jim Bridger minehas sufficient reserves to provide coal deliveries for the term of the salesagreement.  IPC also has a coal supply contract providing for annual deliveriesof coal through 2009 from the Black Butte Coal Company's Black Butte andLeucite Hills mines located near the Jim Bridger plant.  This contractsupplements the Bridger Coal deliveries and provides another coal supply tooperate the Jim Bridger plant.  The Jim Bridger plant's rail load-in facilityand unit coal train allow the plant to take advantage of potentially lower-costcoal from other mines for tonnage requirements above established contractminimums.

The Bridger Coal mine experienceddifficulties in meeting its production volume and operating cost goals duringearly 2008.  The problems stemmed from soft floor and roof stability issuesthat began in late December 2007 in the underground longwall mining operation(longwall).  The impact on December 2007 production was relatively minor;however the problems persisted and January 2008 production volume wasapproximately 20 percent of forecast.  As of late February 2008, the longwallwas operating at normal production.  IPC believes Bridger Coal's overall 2008production and cost objectives are achievable by modifying the surface mineoperation plan to offset the underground mining difficulties.  Using coal fromboth mine and plant stockpiles, planned deliveries to the Jim Bridger powerplant continue and generation is not expected to be negatively impacted.

Sierra Pacific Power Company,as operator of the North Valmy generating plant, has an agreement with ArchCoal Sales Company, Inc. to supply coal to the plant through 2011.  IPC, 50percent owner of the plant, is obligated to purchase one-half of the coal,ranging from 515,000 tons to 762,500 tons annually.  Sierra Pacific PowerCompany also has a coal supply contract with Black Butte Coal Company's BlackButte Mine for deliveries through 2009.  IPC is obligated to purchase one-halfof the coal purchased under this agreement, ranging from 450,000 to 600,000tons annually.

The Boardman generating plantreceives coal from the Powder River Basin through annual contracts.  PortlandGeneral Electric, as operator of the Boardman plant, has an agreement withBuckskin Mining Company to supply all of Boardman's coal requirements through2008.  As 10 percent owner of the plant, IPC is obligated to purchase tenpercent of the coal purchased under this agreement, ranging from 230,000 to270,000 tons annually.  A Request for Proposal to secure coal for the period2009-2013 is in process.

IPC owns and operates theDanskin and Bennett Mountain combustion turbines, which are supplied gasthrough the Northwest Pipeline GP's pipeline.  Gas is purchased as needs areidentified for summer peaks or to meet system requirements.  The gas istransported under a long-term agreement with Northwest Pipeline GP for 24,523million British thermal units (MMBtu) per day.  This agreement runs throughFebruary 28, 2022, with annual extensions at IPC's sole discretion.  IPC alsohas the ability to flow a total of 73,569 MMBtu as alternate firm basis withoutincurring a reservation charge on the additional amount.  In addition to this agreement,IPC has entered into a long-term agreement with Northwest Pipeline GP for 131,453MMBtu of total storage capacity at the Jackson Prairie Storage Project locatedin Lewis County, Washington.  As the project is developed, storage capacitywill be phased into service and allocated to IPC on a monthly basis.  IPC'scurrent storage allotment is approximately 18 percent of its total, and itsfull allotment is expected to be reached by January 2011.  The firm storagecontract extends through November 1, 2043, with bilateral termination rights atthe end of the contract.  Storage gas will be purchased and stored with theintent of fulfilling needs as identified for summer peaks or to meet systemrequirements.

**Water Rights: **Except as discussed below, IPC has acquired waterrights under applicable state law for all waters used in its hydroelectricgenerating facilities.  In addition, IPC holds water rights for domestic,irrigation, commercial and other necessary purposes related to other land andfacility holdings within the state.  The exercise and use of all of these waterrights are subject to prior rights, and with respect to certain hydroelectricgenerating facilities, IPC's water rights for power generation are subordinatedto certain future upstream diversions of water for irrigation and otherrecognized consumptive uses.

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

In addition to providing forthe protection of IPC's hydroelectric water rights, the Swan Falls agreementcontemplated the initiation of a general adjudication of all water uses withinthe Snake River basin.  In 1987, the director of the Idaho Department of WaterResources filed a petition in state district court asking that the courtadjudicate all claims to water rights, whether based on state or federal law,within the Snake River basin.  The court signed a commencement order initiatingthe Snake River Basin Adjudication on November 19, 1987.  This legal proceedingwas authorized by state statute based upon a determination by the IdahoLegislature that the effective management of the waters of the Snake Riverbasin required a comprehensive determination of the nature, extent and priorityof all water uses within the basin.  The adjudication is proceeding and isexpected to continue for at least the next several years.  IPC has filed claimsto its water rights within the basin and is actively participating in theadjudication in an effort to ensure that its water rights and the operation ofits hydroelectric facilities are not adversely impacted.  In certain instances,the adjudication of water rights in the Snake River Basin Adjudication (SRBA)results in the initiation of litigation, called subcases, to determine thescope and nature of a particular water right.  IPC is involved in subcasesinvolving not only its water rights but also the water rights of otherclaimants.  One such subcase involves IPC's water rights at the Swan Fallsproject on the Snake River and several other upstream hydroelectric projectsthat are the subject of the Swan Falls Agreement.  IPC also has initiated legalaction against the U.S. Bureau of Reclamation (USBR) over the interpretationand effect of a 1923 contract with the USBR on the operation of the AmericanFalls Reservoir and the release of water from that reservoir to be used at IPC'sdownstream hydroelectric projects.

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

**Integrated Resource Plan(IRP):**  The IRP is IPC's businessplan for resource acquisition and is the starting point for demonstratingprudence in IPC's resource decisions.  IPC filed its 2006 IRP with the IPUC inSeptember 2006 and with the OPUC in October 2006.  Prior to filing, the IRPrequires extensive involvement by IPC, the IPUC Staff, the OPUC Staff, andcustomer and environmental representatives, as well as input on the cost ofgeneration technologies.  The 2006 IRP identified IPC's forecast load andresource situation for the next twenty years, analyzed potential supply-sideand demand-side options and identified near-term and long-term actions.  Thetwo primary goals of the 2006 IRP were to (1) identify sufficient resources toreliably serve the growing demand for electric service within IPC's servicearea throughout the 20-year planning period and (2) ensure that the portfolioof resources selected balances cost, risk and environmental concerns.

The IPUC accepted the 2006IRP in March 2007.  The OPUC acknowledged the 2006 IRP in September 2007 withthe stipulation that IPC not commit to the construction of a 250-MW pulverizedcoal resource, identified to come on-line in 2013, until IPC presents an updateof the 2006 IRP to the OPUC no later than June 2008.  With its acceptance ofthe 2006 IRP, the IPUC requested that IPC align the submittal of its next IRPwith those submitted by other utilities.  To comply with this request IPCintends to provide an update on the status of the 2006 IRP to both the IPUC andOPUC no later than June 2008 and file a new IRP in June 2009.

In a departure from the 2006IRP, IPC plans to construct a natural gas-fired combined cycle combustionturbine located close to its load center in southern Idaho.  IPC determinedthat coal-fired generation was not the best technology to meet its resourceneeds by 2013 due to escalating construction costs, potential permittingissues, and continued uncertainty surrounding future greenhouse gas laws andregulations.    See further discussion in Part II - Item 7 - "MD&A -REGULATORY MATTERS - Integrated Resource Plan."

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**CSPP Purchases****:**  Asmandated by the enactment of PURPA and the adoption of avoided cost rates bythe IPUC and the OPUC, IPC has entered into contracts for the purchase ofenergy from a number of private developers.  Under these contracts, IPC isrequired to purchase all of the output from the facilities located inside theIPC service territory.  For projects located outside the IPC service territory,IPC is required to purchase the output that IPC has the ability to receive atthe facility's requested point of delivery on the IPC system.  The IPUCjurisdictional portion of the costs associated with CSPP contracts are fullyrecovered through base rates and the PCA.  For IPUC jurisdictional contracts,projects that generate up to ten average MW of energy monthly are eligible forIPUC Published Avoided Costs for up to a 20-year contract term.  The OPUCjurisdictional portion of the costs associated with CSPP contracts is recoveredthrough general rate case filings.  For OPUC jurisdictional contracts, projectswith a nameplate rating of up to ten MW of capacity are eligible for OPUCPublished Avoided Costs for up to a 20-year contract term.  The PublishedAvoided Cost is a price established by the IPUC and OPUC to estimate IPC's costof developing additional generation resources.  If a PURPA project does notqualify for Published Avoided Costs, then IPC is required to negotiate theterms, prices and conditions with the developer of that project.  Thesenegotiations reflect the characteristics of the individual projects (i.e.,operational flexibility, location and size) and the benefits to the IPC systemand must be consistent with other similar energy alternatives.  During 2007 theIPUC issued orders increasing the Published Avoided Cost and requiringdifferentiation between heavy load and light load hour energy prices.  See PartII - Item 7 - "MD&A - REGULATORY MATTERS - Wind Integration Costs and PURPAAvoided Cost Rate Computation."

On August 4, 2005, the IPUCgranted a temporary reduction in the eligible CSPP project size to 100 kW forintermittent generation resources (such as wind) only and ordered IPC to studythe impacts of integrating this type of resource.  IPC completed and filed withthe IPUC a wind generation integration study report on February 6, 2007. Public workshops were conducted, comments were filed with the IPUC, andinformation request responses were submitted to the IPUC.  A proposedsettlement of this issue has been presented to the IPUC for its consideration.

In 2007, as required by theOPUC, IPC filed new avoided costs for the state of Oregon and new standardcontracts.  The OPUC has approved the new rates and standard contracts.

As of December 31, 2007, IPChad signed agreements to purchase energy from 94 CSPP facilities with contractsranging from one to 30 years.  Seventy-six of these facilities, with a combinednameplate capacity of 231 MW, were on-line at the end of 2007; the other 18facilities under contract, with a combined nameplate capacity of 267 MW, areprojected to come on-line between 2008 and 2010.  The majority of the newfacilities will be wind resources which will generate on an intermittentbasis.  During 2007, IPC purchased 777,147 megawatt-hours (MWh) from theseprojects at a cost of $45 million, resulting in a blended price of 5.9 centsper kilowatt hour.

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

Due to the uncertaintyregarding the regulation requirements of anticipated wind generation, IPCterminated the wholesale contract for load following services provided toNorthWestern Energy, effective December 31, 2007.  The load following contractrequired IPC to increase or decrease its generation by up to 30 MW to react toNorthWestern's system load changes.

IPC has one firm wholesalepower sales contract.  The sales contract is with the Raft River ElectricCooperative for up to 15 MW.  This contract expires in September 2008; however,Raft River Electric Cooperative has provided notice that it intends to renewthe contract, as allowed in the original agreement, through September 2010.

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IPC has one wholesale reservesales contract.  The reserve contract is with United Materials of Great Falls,Inc. (United Materials).  This agreement requires IPC to carry up to 0.45 MW ofreserves associated with an energy sales agreement dated January 2004 betweenIPC and United Materials from the Horseshoe Bend Wind Farm.  The term of thisagreement began in January 2008, and runs seasonally through May 2013.IPC has one firm wholesale purchased power contract.  This contract is with PPLMontana, LLC for 83 MW per hour during heavy load hours, to address increaseddemand during June, July and August.  The term of this contract began in June2004 and runs through August 2009.

**Transmission Services**IPC provides wholesale transmissionservice and provides firm and non-firm wheeling services for eligible transmissioncustomers.  IPC's system lies between and is interconnected with the winter-peakingnorthern and summer-peaking southern regions of the western power system.  Thisgeographic position allows IPC to provide transmission services and to reach a broadpower market.

IPC holds rights-of-way fromMidpoint substation in south-central Idaho through eastern Nevada to the DryLake area northeast of Las Vegas, Nevada, known as the Southwest IntertieProject (SWIP).  In 2004, the Bureau of Land Management granted a five-yearextension to begin construction of a proposed 500-kilovolt transmission linewithin the rights-of-way to December 2009.  IPC obtained the rights-of-way toconstruct a transmission line along this corridor, but no longer plans to buildthe line.  On March 31, 2005, IPC entered into an agreement with White PineEnergy Associates, LLC (White Pine), an affiliate of LS Power Development, LLC,which provides White Pine a three-year exclusive option to purchase the SWIPrights-of-way from IPC.  The option may be exercised in part or as a whole and,if fully exercised, will result in a net pre-tax gain to IPC of approximately$6 million.

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

Based upon presentenvironmental laws and regulations, IPC estimates its 2008 capital expendituresfor environmental matters, excluding Allowance for Funds Used DuringConstruction (AFDC), will total $26 million.  Studies and measures related toenvironmental concerns at IPC's hydroelectric facilities account for $15million, and investments in environmental equipment and facilities at thethermal plants account for $11 million.  For 2009 and 2010, environmental-relatedcapital expenditures, excluding AFDC, are estimated to be $65 million. Anticipated expenses related to IPC's hydroelectric facilities account for $29million, and thermal plant expenses are expected to total $36 million.

IPC anticipates approximately$20 million in annual operating costs for environmental facilities during2008.  Hydroelectric facility expenses and thermal plant expenses account forthe majority of the costs at approximately $13 million and $7 million,respectively.  For 2009 and 2010, total environmental related operating costsare estimated to be approximately $54 million.  Expenses related to thehydroelectric facilities are expected to be $39 million, and thermal plantexpenses are expected to be $15 million during this period.

**Air Quality Issues:**IPC owns two natural gas combustion turbine powerplants and co-owns three coal-fired power plants that are subject to airquality regulation.  The natural gas-fired plants, Danskin and BennettMountain, are located in Idaho.  The coal-fired plants are:  Jim Bridgerlocated in Wyoming; Boardman located in Oregon; and North Valmy located inNevada.  Please see Part II, Item 7 - "MD&A - LEGAL AND ENVIRONMENTALISSUES - Environmental Issues - Air Quality Issues" for a discussion of thesematters.

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

The FERC licenses issued forIPC's American Falls and Cascade hydroelectric generating plants requireaeration of turbine water to meet dissolved oxygen standards in the tail watersdownstream from the plants.  In order to comply with the licenses, IPCinstalled and operates aeration equipment at both plants and submits compliancereports to the appropriate regulatory agencies.

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The FERC licenses issued forIPC's Milner, Shoshone Falls, Twin Falls, Upper Salmon, Lower Salmon, Bliss andCJ Strike hydroelectric projects require dissolved oxygen and temperaturemonitoring and reporting.  IPC submits compliance reports to the appropriateregulatory agencies.

The FERC license for the CJStrike project also requires monitoring of total dissolved gas during spillperiods.  IPC installs monitors during periods of spill that record gas levelsin spilled water and reports the results to the appropriate regulatoryagencies.

**Hazardous/Toxic Wastes andSubstances:**  Under the ToxicSubstances Control Act, the EPA has adopted regulations governing the use,storage, inspection and disposal of electrical equipment that containspolychlorinated biphenyls (PCBs).  The regulations permit the continued use andservicing of certain equipment (including transformers and capacitors) thatcontain PCBs.  IPC continues to meet federal requirements of the ToxicSubstances Control Act for the continued use of equipment containing PCBs.  IPCcontinues to eliminate PCBs as part of its long-term strategy.  This programwill reduce costs associated with the long-term monitoring of PCB-containingequipment, responding to spills and reporting to the EPA.  In 2007, IPC spentapproximately $0.8 million identifying and eliminating PCBs.

For a discussion of otherenvironmental issues, including air quality, endangered species, and climatechange, please see Part II, Item 7 - "MD&A - Legal and Environmental Issues- Environmental Issues."****

**Energy Efficiency**In 2007, IPC spent approximately $15.6million to promote energy efficiency and summer peak reduction through itsDemand Side Management (DSM) programs.  Major funding for program development,implementation and administration comes from the Idaho and Oregon tariff ridersfor DSM.  From 2001 to March 2007, when funding was discontinued due to thesuspension of investor-owned utilities' participation in the ResidentialExchange Program of the Bonneville Power Administration (BPA), IPC alsoreceived funding from the Conservation and Renewables Discount Program of the BPA.

Approximately $1.8 million wasspent on research, analysis and development, technology evaluation, markettransformation, and general overhead expenses.  A portion of this activity wasaccomplished in conjunction with the Northwest Energy Efficiency Alliance (NEEA). IPC contributed $0.9 million to the NEEA.

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

•        Approximately $4.0 million wasdevoted to achieving summer peak reduction through focusing on irrigationpumping and residential air conditioning equipment control measures.

•        The residential energy efficiencyprograms targeted new and existing homes, focusing on customer education andthe application of energy efficiency remediation, including energy efficientbuilding techniques, insulation augmentation, air duct sealing, and the use ofefficient lighting.  This segment's 2007 spending was approximately $3.3million.

•        Programs for new or existingindustrial and commercial facilities focus on application of energy efficienttechniques and technologies as well as operational and management processes toreduce energy consumption.  Approximately $4.5 million was spent on theseprograms.

•        Approximately $2.0 million was devotedto irrigation efficiency programs.  Irrigation customers can receive financialincentives for either improving the energy efficiency of an irrigation systemor installing a new energy efficiency system.

** **

In 2007, IPC's energyefficiency programs reduced energy usage by approximately 91,000 MWh and the targeteddemand reduction programs resulted in a summer peak reduction of about 48 MW.

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

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Some state regulatoryauthorities are in the process of changing utility regulations in response tofederal and state statutory changes and evolving competitive markets.  Thesestatutory changes and conforming regulations may result in increased retailcompetition.  However, restructuring of the electric industry has stalled atboth the national level and in the Pacific Northwest.

**Wholesale: **The 1992 National Energy Policy Act and the FERC'srulemaking activities have established the regulatory framework to open thewholesale energy market to competition.  This act permits entities to developindependent electric generating plants for sales to wholesale customers, andauthorizes the FERC to order transmission access for third parties totransmission facilities owned by another entity.  This act does not, however,permit the FERC to require transmission access to retail customers.  Open-accesstransmission for wholesale customers provides energy suppliers withopportunities to sell and deliver electricity at market-based prices.  IPCactively monitors and participates, as appropriate, in energy industrydevelopments, to maintain and enhance its ability to effectively participate inwholesale energy markets in a manner consistent with its business goals.

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

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

|                                  | **Years Ended December 31,** |
|----------------------------------|------------------------------|
|                                  | **2007**                     | ** ** | **2006** | ** ** | **2005** |
| Revenues (thousands of  dollars) |                              |  |  |  |  |  |  |  |
|                                  | Residential                  | $ | 308,208 |  | $ | 299,594 |  | $ | 299,488 |
|                                  | Commercial                   |  | 170,001 |  |  | 162,391 |  |  | 173,268 |
|                                  | Industrial                   |  | 101,409 |  |  | 102,958 |  |  | 118,259 |
|                                  | Irrigation                   |  | 88,685 |  |  | 71,432 |  |  | 76,255 |
|                                  |                              | Total general business |  | 668,303 |  |  | 636,375 |  |  | 667,270 |
|                                  | Off-system sales             |  | 154,948 |  |  | 260,717 |  |  | 142,794 |
|                                  | Other                        |  | 52,150 |  |  | 23,381 |  |  | 27,619 |
|                                  |                              | Total | $ | 875,401 |  | $ | 920,473 |  | $ | 837,683 |
|                                  |                              |  |  |  |  |  |  |  |  |
| Energy use (thousands of MWh)    |                              |  |  |  |  |  |  |  |
|                                  | Residential                  |  | 5,227 |  |  | 5,068 |  |  | 4,760 |
|                                  | Commercial                   |  | 3,937 |  |  | 3,761 |  |  | 3,639 |
|                                  | Industrial                   |  | 3,454 |  |  | 3,475 |  |  | 3,423 |
|                                  | Irrigation                   |  | 1,924 |  |  | 1,635 |  |  | 1,467 |
|                                  |                              | Total general business |  | 14,542 |  |  | 13,939 |  |  | 13,289 |
|                                  | Off-system sales             |  | 2,744 |  |  | 5,821 |  |  | 2,774 |
|                                  |                              | Total |  | 17,286 |  |  | 19,760 |  |  | 16,063 |
|                                  |                              |  |  |  |  |  |  |  |  |

**IFS:**

IFS invests primarily inaffordable housing developments, which provide a return principally by reducingfederal and state income taxes through tax credits and accelerated taxdepreciation benefits.  IFS generated tax credits of $15 million, $19 millionand $20 million in 2007, 2006 and 2005, respectively.  IFS's portfolio alsoincludes historic rehabilitation projects such as, the Empire Building inBoise, Idaho.  IFS did not make any new investments during 2007.

IFS has focused on adiversified approach to its investment strategy in order to limit bothgeographic and operational risk.  Over 90 percent of IFS's investments havebeen made through syndicated funds.  At December 31, 2007, the gross amount ofIFS's portfolio equaled $175 million in tax credit investments.  Theseinvestments cover 49 states, Puerto Rico and the U.S. Virgin Islands.  Theunderlying investments include over 700 individual properties, of which all butthree are administered through syndicated funds.

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** **

**IDA-WEST:**

Ida-West operates and has a50 percent interest in nine hydroelectric plants with a total generatingcapacity of 45 MW.  Four of the projects are located in Idaho and five are innorthern California.  All nine projects are "qualifying facilities" underPURPA.  IPC purchased all of the power generated by Ida-West's four Idahohydroelectric projects at a cost of $8 million in both 2007 and 2006, and $7million in 2005.

**ITEM 1A.  RISK FACTORS**

The following are factorsthat could have a significant impact on the operations and financial results ofIDACORP, Inc. and Idaho Power Company and could cause actual results oroutcomes to differ materially from those discussed in any forward-lookingstatements:

•        **Reduced hydroelectric generationcan reduce revenues and increase costs.** Idaho Power Company has a predominately hydroelectric generating base.  Becauseof Idaho Power Company's heavy reliance on hydroelectric generation, theweather can significantly affect its operations.  When hydroelectric generationis reduced, Idaho Power Company must increase its use of generally moreexpensive thermal generating resources and purchased power.  Through its powercost adjustment in Idaho, Idaho Power Company can expect to recover approximately90 percent of the increase in its Idaho jurisdictional net power supply costs,which are fuel and purchased power less off-system sales, above the levelincluded in its base rates.  The power cost adjustment recovery includes both aforecast and deferrals that are subject to the regulatory process.  However,recovery of amounts above forecast in one power cost adjustment year does notoccur until the subsequent power cost adjustment year.  The non-Idaho net powersupply costs are subject to periodic recovery from the Oregon and FederalEnergy Regulatory Commission jurisdictional customers.

•        **Continuing declines in streamflows and over-appropriation of water in Idaho may reduce hydroelectricgeneration and revenues and increase costs.** The combination of declining Snake River base flows, over-appropriationof water and drought conditions have led to disputes among surface water andground water irrigators, and the state of Idaho.  Recharging the Eastern SnakePlain Aquifer, which contributes to Snake River flows, by diverting surfacewater to porous locations and permitting it to sink into the aquifer is oneproposed solution to the dispute.  Diversions from the Snake River for aquiferrecharge may further reduce Snake River flows available for hydroelectric generationand reduce Idaho Power Company's revenues and increase costs.  Idaho Power Companyis also involved in legal actions involving the water rights it holds forhydroelectric purposes.  One such action, initiated in the Snake River BasinAdjudication, involves Idaho Power Company's water rights at the Swan Fallsproject on the Snake River and several other upstream hydroelectric projectsthat are the subject of a 1984 agreement with the state of Idaho known as theSwan Falls Agreement.  Idaho Power Company also has initiated legal actionagainst the U.S. Bureau of Reclamation over the interpretation and effect of a1923 contract with the U.S. Bureau of Reclamation on the operation of theAmerican Falls Reservoir and the release of water from that reservoir to beused at Idaho Power Company's downstream hydroelectric projects.  Theresolution of these legal actions may affect Snake River flows available forhydroelectric generation and thereby reduce Idaho Power Company revenues and increasecosts.

•        **Load growth in Idaho PowerCompany's service territory exposes it to greater market and operational riskand could increase costs and reduce earnings and cash flows.**  Increases in both the number of customers and thedemand for energy have resulted and may continue to result in increasedreliance on purchased power to meet customer load requirements.

o       Through its annual power costadjustment in Idaho, Idaho Power Company can expect to recover approximately 90percent of the increase in its Idaho jurisdictional net power supply costs,which are fuel and purchased power less off-system sales, above the levelincluded in its base rates.  The remaining ten percent is absorbed by IdahoPower Company.

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o       Idaho Power Company's load growth adjustment rate adjusts the netpower supply costs Idaho Power Company includes in its annual power costadjustment for differences between actual load and the load used in calculatingbase rates.  In periods of growing load, the marginal energy costs of servingnew Idaho retail customers are subtracted from the power cost adjustmentleaving Idaho Power Company with no opportunity between general rate casefilings to recover these costs.  If the Idaho Public Utilities Commissionincreases the rate or modifies the methodused to calculate the load growth adjustment rate, or if customer load ishigher than the load used to calculate base rates, Idaho Power Company'searnings and cash flows could be reduced.

o       Since the Federal EnergyRegulatory Commission implemented market-based wholesale power rates in 1997,the price volatility of electricity has substantially increased from what itwas at the inception of the power cost adjustment.  As Idaho Power Company'sreliance on purchased power continues to increase, the risks associated withthe remaining ten percent not recovered through the power cost adjustment couldincrease costs and reduce earnings and cash flows.

o       Increased load growth can resultin the need for additional investments in Idaho Power Company's infrastructureto serve the new load.  If Idaho Power Company were unable to secure timelyrate relief from the Idaho Public Utilities Commission, the Oregon PublicUtility Commission or the Federal Energy Regulatory Commission to recover thecosts of these additional investments, the resulting regulatory lag would havea negative effect on earnings and cash flow.

o       Increased and unexpected loadgrowth can create planning and operating difficulties for Idaho Power Companythat can impact its ability to reliably serve customers.

•        **Idaho Power Company's relianceon coal and natural gas to fuel its power generation facilities exposes it torisk of increased costs and reduced earnings. **In addition to hydroelectric generation, Idaho PowerCompany relies on coal and natural gas to fuel its generation facilities.  Marketprice increases in coal and natural gas can result in reduced earnings. Increases in demand for natural gas, including increases in demand due togreater industry reliance on natural gas for power generation, may result inmarket price increases and/or supply availability issues.  In addition,delivery of coal and natural gas depends upon gas pipelines, rail lines, railcars and roadways.  Any disruption in Idaho Power Company's fuel supply mayrequire the company to find alternative fuel sources at higher costs, toproduce power from higher cost generation facilities or to purchase power fromother sources.

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

•        **Climate change could affectcustomer demand and hydroelectric generation and lead to restrictions ongeneration resources.**  Long-termclimate change could significantly affect Idaho Power Company's businessbecause changes in temperature, precipitation and snow pack conditions couldaffect customer demand and the amount and timing of hydroelectric generation. In addition, legislative and/or regulatory developments related to climatechange could place restrictions on construction of new generation resources,the expansion of existing resources, or operation of generation resources.

•        **If the Idaho Public UtilitiesCommission, the Oregon Public Utility Commission or the Federal EnergyRegulatory Commission grant less rate recovery in rate case filings than IdahoPower Company needs to cover increased costs of providing services, earningsand cash flows may be reduced and economic expansion may be limited.**  If the Idaho Public Utilities Commission, the OregonPublic Utility Commission or the Federal Energy Regulatory Commission were togrant less rate recovery in rate case filings than Idaho Power Company needs tocover increased costs of providing services, it may have a negative effect onearnings and cash flow and could result in downgrades of IDACORP, Inc.'s andIdaho Power Company's credit ratings.  Failure to obtain regular and timelyrate relief may limit Idaho Power Company's possibilities for economic expansion.

•        **Conditions that may be imposedin connection with hydroelectric license renewals may require large capitalexpenditures and reduce earnings and cash flows.**  Idaho Power Company is currently involved inrenewing federal licenses for several of its hydroelectric projects.  TheFederal Energy Regulatory Commission may impose conditions with respect toenvironmental, operating and other matters in connection with the renewal ofIdaho Power Company's licenses.  These conditions could have a negative effect onIdaho Power Company's operations, require large capital expenditures and reduceearnings and cash flows.

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•        **The cost of complying withenvironmental regulations can increase capital expenditures and operating costsand reduce earnings and cash flows.** IDACORP, Inc. and Idaho Power Company are subject to extensive federal, stateand local environmental statutes, rules and regulations relating to airquality, water quality, natural resources and health and safety.  Compliancewith these environmental statutes, rules and regulations involves significantcapital and operating expenditures.  These expenditures could become even moresignificant in the future if legislation and enforcement policies change.  Forinstance, considerable attention has been focused on emissions from coal-firedgenerating plants, including carbon dioxide, and their potential role incontributing to global warming.  The effects of mercury and other pollutant emissionsfrom coal-fired plants are also being discussed.  Governmental and non-governmentalentities closely scrutinize these plants and bring enforcement actions toensure compliance.  The adoption of new statutes, rules and regulations toimplement carbon dioxide, mercury or other emission controls could result inincreased capital expenditures and could increase the cost of operating coal-firedgenerating plants, and reduce earnings and cash flows.

•        **IDACORP, Inc., IDACORP Energyand Idaho Power Company are subject to costs and other effects of legal andregulatory proceedings, settlements, investigations and claims, including thosethat have arisen out of the western energy situation. **IDACORP, Inc., IDACORP Energy and Idaho Power Companyare involved in a number of proceedings including the California refundproceeding at the Federal Energy Regulatory Commission, which has been settled withthe largest portion of the market participants but which has appeals pending atthe United States Court of Appeals for the Ninth Circuit; a refund proceedingaffecting sellers of wholesale power in the spot market in the PacificNorthwest, in which the Federal Energy Regulatory Commission directed that norefunds be paid, but in connection with which the United States Court ofAppeals for the Ninth Circuit issued a decision remanding the matter to theFederal Energy Regulatory Commission and which is presently the subject ofrehearing applications pending before the United States Court of Appeals forthe Ninth Circuit; show cause proceedings at the Federal Energy RegulatoryCommission, which have been settled but have been appealed; claims pendingbefore the United States Court of Appeals for the Ninth Circuit that theFederal Energy Regulatory Commission ordered refund period should have beenexpanded to include a longer time period; and the reversal by the United StatesCourt of Appeals for the Ninth Circuit of Federal Energy Regulatory Commissionrulings that market-based sellers' transactional reports satisfy the FederalEnergy Regulatory Commission's filed-rate doctrine requirements as a means ofexpanding refunds from all sellers of wholesale power, which rulings have beenremanded to the Federal Energy Regulatory Commission.  To the extent thecompanies are required to make payments, earnings and cash flows will benegatively affected.  It is possible that additional proceedings related to thewestern energy situation may be filed in the future against IDACORP, Inc.,IDACORP Energy or Idaho Power Company.

•        **Idaho Power Company's businessis subject to substantial governmental regulation and may be adversely affectedby increased costs resulting from, or liability under, existing or futureregulations or requirements.** IdahoPower Company is subject to extensive federal and state laws, policies, andregulations, as well as regulatory actions and regulatory audits, includingthose of the Federal Energy Regulatory Commission, the Environmental ProtectionAgency, the North American Electric Reliability Corporation, the WesternElectricity Coordinating Council and the public utility commissions in Idaho, Oregonand Wyoming.  Some of these regulations are changing or subject tointerpretation, and failure to comply may result in penalties or other adverseconsequences.  Compliance with these requirements directly influences IdahoPower Company's operating environment and may significantly increase IdahoPower Company's operating costs.

•        **Increased capital expenditurescan significantly affect liquidity.** Increases in both the number of customers and the demand for energy requireexpansion and reinforcement of transmission and, distribution systems andgenerating facilities.  If Idaho Power Company does not receive timelyregulatory recovery, Idaho Power Company will have to rely more on externalfinancing for its future utility construction expenditures.  These largeplanned expenditures may weaken the consolidated financial profile of IDACORP,Inc. and Idaho Power Company.  Additionally, a significant portion of IdahoPower Company's facilities were constructed many years ago.  Aging equipment,even if maintained in accordance with industry practices, may requiresignificant capital expenditures.  Failure of equipment or facilities used inIdaho Power Company's system could potentially increase repair and maintenanceexpenses, purchased power expenses and capital expenditures.

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•        **As a holding company, IDACORP,Inc.****does not have its ownoperating income and must rely on the upstream cash flows from its subsidiariesto pay dividends and make debt payments.** IDACORP, Inc. is a holding company and thus its primary assets are shares orother ownership interests of its subsidiaries, primarily Idaho Power Company. Consequently, IDACORP, Inc.'s ability to pay dividends and its ability toservice its debt is dependent upon dividends and other payments received fromits subsidiaries.  IDACORP, Inc.'s subsidiaries are separate and distinct legalentities and have no obligation to pay any amounts to IDACORP, Inc., whetherthrough dividends, loans or other payments.  The ability of IDACORP, Inc.'ssubsidiaries to pay dividends or make distributions to IDACORP, Inc. depends onseveral factors, including their actual and projected earnings and cash flow,capital requirements and general financial condition, and the prior rights ofholders of their existing and future first mortgage bonds and other debtsecurities.

•        **A downgrade in IDACORP, Inc.'sand Idaho Power Company's credit ratings could negatively affect the companies'ability to access capital and increase their cost of borrowing.**  On January 31, 2008, Standard & Poor's RatingsServices lowered the corporate credit rating and long-term ratings of IDACORP,Inc. and Idaho Power Company.  In addition, two series of pollution controlbonds issued for Idaho Power Company's benefit are supported by financialguaranty insurance policies.  The interest rates on these bonds have increasedsignificantly because of the ratings downgrades of the bond insurer.  IDACORP,Inc. and Idaho Power Company also have borrowing arrangements that rely on the abilityof the banks to fund loans or support commercial paper.  Current or futuredowngrades of IDACORP, Inc.'s or Idaho Power Company's credit ratings, or thoseaffecting bond insurers or relationship banks, could limit the companies'ability to access capital, including the commercial paper markets, and require IDACORP,Inc. and Idaho Power Company to pay a higher interest rate on their debt.

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

•        **Adverse results of income taxaudits could reduce earnings and cash flows.**  The outcome of ongoing and future income tax audits could differmaterially from the amounts currently recorded, and the difference could reduceIDACORP's and Idaho Power Company's earnings and cash flows.

•        **Employee workforce factorscould increase costs and reduce earnings. **Idaho Power Company is subject to workforce factors, including loss orretirement of key personnel, availability of qualified personnel, and an agingworkforce.  Demographic factors in the workplace present challenges toemployers nationwide and are of particular concern to the electric utilityindustry.  Approximately one-half of the industry's workforce is age 45 or older,making the median age of utility workers higher than the national average. Idaho Power Company is confronted with the challenge of retaining its skilledworkforce while recruiting new talent to offset critical losses due toretirements.  The costs of attracting and retaining appropriately qualifiedemployees to replace an aging workforce could reduce earnings and cash flows.

**ITEM1B.  UNRESOLVED STAFF COMMENTS**

None

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**ITEM 2.  PROPERTIES**

IPC's system is comprised of17 hydroelectric generating plants located in southern Idaho and easternOregon, two natural gas-fired plants located in southern Idaho and interests inthree coal-fired steam electric generating plants located in Wyoming, Nevadaand Oregon.  The system also includes approximately 4,747 miles of high-voltagetransmission lines, 23 step-up transmission substations located at powerplants, 20 transmission substations, eight switching stations, 222 energizeddistribution substations (excluding mobile substations and dispatch centers)andapproximately 64,672 miles of distribution lines.

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

| ** **                                                                                                                      | ** **                               | **Nameplate**         | ** **     |
|---------------------------------------------------------------------------------------------------------------------------------|------------------------------------------|-----------------------|----------------|
| ** **                                                                                                                      | ** **                               | **Capacity (4)**      | **License**    |
| **Project**                                                                                                                     | ** **                               | **(kW)**              | **Expiration** |
| **Hydroelectric  Developments:**                                                                                                |                                          |                       |                |  |
|                                                                                                                                 | Properties subject to  federal licenses: |                       |                |  |  |
|                                                                                                                                 | Lower Salmon                             |                       | 60,000         | 2034 |  |
|                                                                                                                                 | Bliss                                    |                       | 75,000         | 2034 |  |
|                                                                                                                                 | Upper Salmon                             |                       | 34,500         | 2034 |  |
|                                                                                                                                 | Shoshone Falls                           |                       | 12,500         | 2034 |  |
|                                                                                                                                 | CJ Strike                                |                       | 82,800         | 2034 |  |
|                                                                                                                                 | Upper Malad - Lower Malad                |                       | 21,770         | 2035 |  |
|                                                                                                                                 | Brownlee-Oxbow-Hells Canyon              |                       | 1,166,900      | 2005 | (1) |
|                                                                                                                                 | Swan Falls                               |                       | 27,170         | 2010 |  |
|                                                                                                                                 | American Falls                           |                       | 92,340         | 2025 |  |
|                                                                                                                                 | Cascade                                  |                       | 12,420         | 2031 |  |
|                                                                                                                                 | Milner                                   |                       | 59,448         | 2038 |  |
|                                                                                                                                 | Twin Falls                               |                       | 52,897         | 2040 |  |
|                                                                                                                                 | Other Hydroelectric:                     |                       |                |  |  |
|                                                                                                                                 | Clear Lakes - Thousand  Springs          |                       | 11,300         |  |  |
|                                                                                                                                 | Total Hydroelectric                      |                       | 1,709,045      |  |  |
| **Steam and Other  Generating Plants:**                                                                                         |                                          |                       |                |  |
|                                                                                                                                 | Jim Bridger (coal-fired) (2)             |                       | 770,501        |  |  |
|                                                                                                                                 | Valmy (coal-fired) (2)                   |                       | 283,500        |  |  |
|                                                                                                                                 | Boardman (coal-fired) (2)                |                       | 64,200         |  |  |
|                                                                                                                                 | Danskin (gas-fired)(3)                   |                       | 261,800        |  |  |
|                                                                                                                                 | Salmon (diesel-internal  combustion)     |                       | 5,000          |  |  |
|                                                                                                                                 | Bennett Mountain (gas-fired)             |                       | 172,800        |  |  |
|                                                                                                                                 |                                          | Total Steam and Other |                | 1,557,801 |  |  |
|                                                                                                                                 |                                          | Total Generation      |                | 3,266,846 |  |  |
|                                                                                                                                 |
| (1) Licensed on an annual  basis while application for new multi-year license is pending.                                       |
| (2) 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.             |
| (3) Includes unit under  construction (estimated at 170,000 kW and commercial acceptance on April 1,  2008).                    |
| (4) Nameplate capacity has  been updated as part of the NERC reliability standards FAC-008 and 009 review  process.             |
|                                                                                                                                 |                                          |                       |                |  |  |  |  |  |  |

See discussion of relicensingin Part II, Item 7 - "MD&A - REGULATORY MATTERS - Relicensing ofHydroelectric Projects."

At December 31, 2007, thecomposite average ages of the principal parts of IPC's system, based on dollarinvestment, were:  production plant, 25 years; transmission lines andsubstations, 23 years; and distribution lines and substations, 20 years.  IPCconsiders its properties to be well-maintained and in good operating condition.

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IPC owns in fee all of itsprincipal plants and other important units of real property, except forportions of certain projects licensed under the FPA and reservoirs and othereasements.  IPC's property is also subject to the lien of its Mortgage and Deedof Trust and the provisions of its project licenses.  In addition, IPC'sproperty is subject to minor defects common to properties of such size andcharacter that do not materially impair the value to, or the use by, IPC ofsuch properties.

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

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

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

**ITEM3.  LEGAL PROCEEDINGS**

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

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

None

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**EXECUTIVE OFFICERS OF THEREGISTRANTS**

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

J. LAMONT KEEN President andChief Executive Officer, appointed July 1, 2006.  Mr. Keen also serves asPresident and Chief Executive Officer of Idaho Power Company, appointedNovember 17, 2005.  Mr. Keen was Executive Vice President of IDACORP, Inc.,from March 1, 2002, to July 1, 2006, and President and Chief Operating Officerof Idaho Power Company from March 1, 2002, to November 17, 2005.  Mr. Keen wasSenior Vice President - Administration and Chief Financial Officer of IDACORP,Inc. and Idaho Power Company from May 5, 1999, to March 1, 2002.  Mr. Keen alsoserves on the Board of Directors of both IDACORP, Inc. and Idaho PowerCompany.  Age 55.

DARREL T. ANDERSON SeniorVice President - Administrative Services and Chief Financial Officer ofIDACORP, Inc. and Idaho Power Company, appointed July 1, 2004.  Mr. Andersonwas Vice President, Chief Financial Officer and Treasurer of IDACORP, Inc. andIdaho Power Company from March 1, 2002, to July 1, 2004, and Vice President -Finance and Treasurer of IDACORP, Inc. and Idaho Power Company from May 5,1999, to March 1, 2002.  Age 49.

THOMAS R. SALDIN Senior VicePresident and General Counsel of IDACORP, Inc. and Idaho Power Company,appointed October 1, 2004.  Mr. Saldin was Executive Vice President and GeneralCounsel of Albertson's Inc., a supermarket chain, from January 29, 1999, to hisretirement on August 31, 2001.  Age 61.

JAMES C. MILLER Senior VicePresident - Power Supply of Idaho Power Company, appointed July 1, 2004.  Mr.Miller was Senior Vice President - Delivery of Idaho Power Company from October1, 1999, to July 1, 2004.  Age 53.

DANIEL B. MINOR Senior VicePresident - Delivery of Idaho Power Company, appointed July 1, 2004.  Mr. Minorwas Vice President - Administrative Services & Human Resources of IDACORP,Inc. and Idaho Power Company from November 20, 2003, to July 1, 2004, VicePresident - Corporate Services of Idaho Power Company from May 15, 2003, toNovember 20, 2003, and Director of Audit Services of Idaho Power Company fromJuly 2001, to May 15, 2003.  Age 50.

STEVEN R. KEEN Vice Presidentand Treasurer of IDACORP, Inc. and Idaho Power Company, appointed June 1,2006.  Mr. Keen was President of IDACORP Financial Services from September 8,1998 to May 31, 2007.  Age 47.

PATRICK A. HARRINGTONCorporate Secretary of IDACORP, Inc. and Idaho Power Company, appointed March15, 2007.  Mr. Harrington was Senior Attorney from June 7, 2003, to March 15,2007, and Attorney III from 1996 to June 7, 2003.  Age 47.

DENNIS C. GRIBBLE VicePresident and Chief Information Officer of IDACORP, Inc. and Idaho PowerCompany, appointed June 1, 2006.  Mr. Gribble was Vice President and Treasurerof IDACORP, Inc. and Idaho Power Company, from July 15, 2004, to June 1, 2006and Finance Controller of Idaho Power Company from January 1, 1997, to July 15,2004.  Age 55.

LORI D. SMITH Vice President- Corporate Planning and Chief Risk Officer of IDACORP, Inc. and Idaho PowerCompany, appointed January 1, 2008.  Ms. Smith was Vice President - Finance andChief Risk Officer of IDACORP, Inc. and Idaho Power Company from July 15, 2004,to January 1, 2008, and Director of Strategic Analysis of Idaho Power Companyfrom January 1, 2000 to July 15, 2004.  Age 47.

LUCI K. MCDONALD VicePresident - Human Resources of IDACORP, Inc. and Idaho Power Company, appointedDecember 6, 2004.  Ms. McDonald was Corporate Staff Director of Human Resourcesof Boise Cascade Corporation, a forest products company, from September 16,1999, to November 19, 2004.  Age 50.

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GREGORY W. PANTER VicePresident - Public Affairs of IDACORP, Inc. and Idaho Power Company, appointedApril 1, 2001.  Age 59.

NAOMI SHANKEL Vice President,Audit and Compliance of IDACORP, Inc. and Idaho Power Company, appointedSeptember 21, 2006.  Ms. Shankel was Director, Audit Services of IDACORP, Inc.and Idaho Power Company from July 2003, to September 21, 2006.  Ms. Shankel wasa member of the Finance Department of Idaho Power Company from April 4, 2001,to July 2003.  Age 36.

JOHN R. GALE Vice President -Regulatory Affairs of Idaho Power Company, appointed March 15, 2001.  Age 57.

LISA A. GROW Vice President -Delivery Engineering and Operations of Idaho Power Company, appointed July 20,2005.  Ms. Grow was General Manager of Grid Operations and Planning of IdahoPower Company from October 23, 2004, to July 20, 2005, Operations Manager (GridOps) of Idaho Power Company from March 2, 2002, to October 23, 2004, andControl Area Operations Leader from October 13, 2001, to March 2, 2002.  Age42.

WARREN KLINE Vice President - Customer Service and RegionalOperations of Idaho Power Company, appointed July 20, 2005.  Mr. Kline wasGeneral Manager of Regional Operations of Idaho Power Company from March 2,2002, to July 20, 2005 and General Manger of Customer Service and Metering fromJanuary 9, 1999, to March 2, 2002.  Age 52.

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**PART II**

**ITEM5.  MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS ANDISSUER PURCHASES OF EQUITY SECURITIES**

IDACORP's common stock,without par value, is traded on the New York Stock Exchange.  On February 22,2008, there were 14,839 holders of record and the stock price was $30.80 pershare.

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

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

A covenant under the IDACORPand IPC Credit Facilities described in "MD&A - LIQUIDITY AND CAPITALRESOURCES - Financing Programs - Debt Covenants" requires IDACORP and IPC tomaintain leverage ratios of consolidated indebtedness to consolidated totalcapitalization of no more than 65 percent at the end of each fiscal quarter. IPC's ability to pay dividends on its common stock held by IDACORP and IDACORP'sability to pay dividends on its common stock are limited to the extent paymentof such dividends would cause their leverage ratios to exceed 65 percent.  AtDecember 31, 2007, the leverage ratios for IDACORP and IPC were both 53percent.

IPC's articles ofincorporation contain restrictions on the payment of dividends on its commonstock if preferred stock dividends are in arrears.  IPC has no preferred stockoutstanding.  IPC paid dividends to IDACORP of $53 million, $51 million and $51million in 2007, 2006 and 2005, respectively.

The following table shows thereported high and low sales price of IDACORP's common stock and dividends paidfor 2007 and 2006 as reported in the consolidated transaction reporting system.

|                                   | **2007 Quarters**         |
|-----------------------------------|---------------------------|
| Common  Stock, without par value: | **1st**                   | ** ** | **2nd** | ** ** | **3rd** | ** ** | **4th** |
|                                   | High                      | $39.19 |  | $35.18 |  | $36.57 |  | $36.72 |
|                                   | Low                       | 32.00 |  | 31.22 |  | 30.07 |  | 32.36 |
|                                   | Dividends  paid per share | 0.30 |  | 0.30 |  | 0.30 |  | 0.30 |
|                                   | ** **                |
|                                   | **2006 Quarters**         |
| Common  Stock, without par value: | **1st**                   | ** ** | **2nd** | ** ** | **3rd** | ** ** | **4th** |
|                                   | High                      | $33.28 |  | $35.20 |  | $38.81 |  | $40.17 |
|                                   | Low                       | 28.97 |  | 32.00 |  | 34.00 |  | 37.61 |
|                                   | Dividends  paid per share | 0.30 |  | 0.30 |  | 0.30 |  | 0.30 |
|                                   |                           |

** **

**IssuerPurchases of Equity Securities:**

None

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**Performance Graph**

The following performancegraph shows a comparison of the five-year cumulative total shareholder returnfor IDACORP common stock, the S&P 500 Index and the Edison Electric Institute(EEI) Electric Utilities Index.  The data assumes that $100 was invested onDecember 31, 2002, with beginning-of-period weighting of the peer group indices(based on market capitalization) and monthly compounding of returns.

Source: Bloomberg and EdisonElectric Institute

| ** ** | ** **  | ** **        | ** **          | ** ** | ** ** | **EEI Electric** |
|------------|-------------|-------------------|---------------------|------------|------------|------------------|
| ** ** | **IDACORP** | **S & P 500** | **Utilities Index** |
| 2002       | $           | 100.00            | $                   | 100.00     | $          | 100.00           |
| 2003       |             | 128.86            |                     | 128.67     |            | 123.48           |
| 2004       |             | 137.11            |                     | 142.65     |            | 151.68           |
| 2005       |             | 136.92            |                     | 149.66     |            | 176.02           |
| 2006       |             | 186.71            |                     | 173.27     |            | 212.56           |
| 2007       |             | 176.26            |                     | 182.78     |            | 247.76           |

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

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** **

**ITEM6. ****SELECTED FINANCIAL DATA**

| **IDACORP, Inc.**                                                                                                                         |
|-------------------------------------------------------------------------------------------------------------------------------------------|
| **SUMMARY OF OPERATIONS**                                                                                                                 |
| **(thousands of dollars  except per share amounts)**                                                                                      |
|                                                                                                                                           | **2007** | **2006** | **2005** | **2004** | **2003** |
| Operating revenues                                                                                                                        | $ | 879,394 | $ | 926,291 | $ | 842,864 | $ | 827,856 | $ | 823,002 |
| Operating income                                                                                                                          |  | 152,078 |  | 169,704 |  | 154,653 |  | 106,233 |  | 84,062 |
| Income from continuing  operations                                                                                                        |  | 82,272 |  | 100,075 |  | 85,716 |  | 80,781 |  | 49,732 |
| Diluted earnings per share  from                                                                                                          |  |  |  |  |  |  |  |  |  |  |
|                                                                                                                                           | continuing operations |  | 1.86 |  | 2.34 |  | 2.02 |  | 2.10 |  | 1.30 |
| Dividends declared per  share                                                                                                             |  | 1.20 |  | 1.20 |  | 1.20 |  | 1.20 |  | 1.70 |
|                                                                                                                                           |  |  |  |  |  |  |  |  |  |  |  |
| **Financial Condition:**                                                                                                                  |  |  |  |  |  |  |  |  |  |  |
| Total assets                                                                                                                              | $ | 3,653,308 | $ | 3,445,130 | $ | 3,364,126 | $ | 3,234,172 | $ | 3,106,108 |
| Long-term debt                                                                                                                            |  | 1,168,336 |  | 1,023,773 |  | 1,039,852 |  | 1,058,152 |  | 1,013,757 |
|                                                                                                                                           |  |  |  |  |  |  |  |  |  |  |
| **Financial Statistics:**                                                                                                                 |  |  |  |  |  |  |  |  |  |  |
| Times interest charges earned:                                                                                                            |  |  |  |  |  |  |  |  |  |  |
|                                                                                                                                           | Before tax (1) |  | 2.35    |  | 2.78    |  | 2.65    |  | 1.99    |  | 1.48    |
|                                                                                                                                           | After tax (2) |  | 2.16    |  | 2.54    |  | 2.37    |  | 2.32    |  | 1.77    |
| Market-to-book ratio (3)                                                                                                                  |  | 131% |  | 151% |  | 121% |  | 128% |  | 132% |
| Payout ratio (4)                                                                                                                          |  | 65% |  | 48% |  | 79% |  | 63% |  | 139% |
| Return on year-end common  equity (5)                                                                                                     | 6.8% |  | 9.6% |  | 6.2% |  | 7.2% |  | 5.4% |
| Book value per share (6)                                                                                                                  | $ | 26.79    | $ | 25.65    | $ | 24.05    | $ | 23.88    | $ | 22.62    |
|                                                                                                                                           |  |  |  |  |  |  |  |  |  |  |
| The financial statistics  listed above are calculated in the following manner:                                                            |
| (1) The sum of interest on  long-term debt, other interest expense excluding the allowance for funds used  during construction credits    |
|                                                                                                                                           | (AFDC), and income before  income taxes divided by the sum of interest on long-term debt and other  interest expense excluding |
| AFDC credits.                                                                                                                             |
| (2) The sum of interest on  long-term debt, other interest expense excluding AFDC credits, and income  from continuing operations divided |
|                                                                                                                                           | by the sum of interest on  long-term debt and other interest expense excluding AFDC credits. |
| (3) The closing price of  IDACORP stock on the last day of the year divided by the book value per  share, which is described in (6) below |
| (4) Dividends paid per  common share for the year divided by earnings per diluted share.                                                  |
| (5) Net income divided by  total shareholders' equity at the end of the year.                                                             |
| (6) Total shareholders'  equity at the end of the year divided by shares outstanding at the end of the  year.                             |
|                                                                                                                                           |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

In the second quarter of2006, IDACORP management designated the operations of IDACORP Technologies,Inc. and IDACOMM as assets held for sale.  IDACORP's consolidated financialstatements reflect the reclassification of the results of these businesses asdiscontinued operations for all periods presented.  Discontinued operations arediscussed in more detail in Note 16 to IDACORP's and IPC's ConsolidatedFinancial Statements and in Part II, Item 7 - "MD&A - RESULTS OF OPERATIONS- Non-utility Operations - Discontinued Operations."

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

 

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**ITEM 7.  MANAGEMENT'SDISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS**(Dollar amounts and Megawatt-hours(MWh) are in thousands unless otherwise indicated).

**INTRODUCTION:**

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

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

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

IDACORP's other subsidiariesinclude:

- IDACORP Financial Services,     Inc. (IFS), an investor in affordable housing and other real estate     investments;
- Ida-West Energy Company     (Ida-West), an operator of small     hydroelectric generation projects that satisfy the requirements of PURPA; and
- IDACORP Energy (IE), a     marketer of energy commodities, which wound down operations in 2003.

In the second quarter of2006, IDACORP management designated the operations of IDACORP Technologies,Inc. (ITI) and IDACOMM, Inc. (IDACOMM) as assets held for sale, as defined byStatement of Financial Accounting Standards No. 144.  IDACORP's consolidatedfinancial statements reflect the reclassification of the results of thesebusinesses as discontinued operations for all periods presented.  Discontinuedoperations are discussed in more detail later in the MD&A and in Note 16 toIDACORP's and IPC's Consolidated Financial Statements.

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

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

While reading the MD&A,please refer to the accompanying Consolidated Financial Statements of IDACORPand IPC, which present the financial position at December 31, 2007 and 2006,and the results of operations and cash flows for each company for the yearsended December 31, 2007, 2006 and 2005.

**FORWARD-LOOKINGINFORMATION:**

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In connection with the safeharbor provisions of the Private Securities Litigation Reform Act of 1995,IDACORP and IPC are hereby filing cautionary statements identifying importantfactors that could cause actual results to differ materially from thoseprojected in forward-looking statements, as such term is defined in the ReformAct, made by or on behalf of IDACORP or IPC in this Annual Report on Form 10-K,in presentations, in response to questions or otherwise.  Any statements thatexpress, 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," "may result," "may continue" orsimilar expressions, are not statements of historical facts and may be forward-looking. Forward-looking statements involve estimates, assumptions and uncertainties andare qualified in their entirety by reference to, and are accompanied by, thefollowing important factors, which are difficult to predict, containuncertainties, are beyond IDACORP's or IPC's control and may cause actualresults to differ materially from those contained in forward-lookingstatements:

- Changes in and compliance     with governmental policies, including new interpretations of existing     policies, and regulatory actions and regulatory audits, including those of     the Federal Energy Regulatory Commission, the North American Electric     Reliability Corporation, the Western Electricity Coordinating Council, the     Idaho Public Utilities Commission, the Oregon Public Utility Commission,     and the Internal Revenue Service with respect to allowed rates of return,     industry and rate structure, day-to-day business operations, acquisition     and disposal of assets and facilities, operation and construction of plant     facilities, provision of transmission services, relicensing of     hydroelectric projects, recovery of purchased power expenses, recovery of     other capital investments, present or prospective wholesale and retail     competition, including but not limited to retail wheeling and transmission     costs, and other refund proceedings;
- Changes arising from the     Energy Policy Act of 2005;
- Litigation and regulatory     proceedings, including those resulting from the energy situation in the     western United States, and penalties and settlements that influence     business and profitability;
- Changes in and compliance     with environmental, endangered species and safety laws and policies;
- Climate change affecting     customer demand, hydroelectric generation and new legislative policies and     enactments, and/or regulatory obligations;
- Weather variations     affecting hydroelectric generating conditions and customer energy usage;
- Over-appropriation of     surface and groundwater in the Snake River Basin resulting in reduced     generation at hydroelectric facilities;
- Construction of power     generating, transmission and distribution facilities including an     inability to obtain required governmental permits and approvals,     rights-of-way and siting, and risks related to contracting, construction     and start-up;
- Operation of power     generating facilities including breakdown or failure of equipment,     performance below expected levels, competition, fuel supply, including     availability, transportation and prices, and availability of transmission;
- Blackouts or other     disruptions of Idaho Power Company's or the western interconnected     transmission systems;
- Impacts from the formation     of a regional transmission organization or the development of another     transmission group;
- Population growth rates and     other demographic patterns;
- Market demand and prices     for energy, including structural market changes;
- Changes in operating     expenses and capital expenditures, including costs and availability of     materials, fuel, and commodities, and fluctuations in sources and uses of     cash;
- Results of financing     efforts, including the ability to obtain financing on favorable terms,     which can be affected by factors such as credit ratings and general     economic conditions;
- Actions by credit rating     agencies, including changes in rating criteria and new interpretations of     existing criteria;
- Homeland security, natural     disasters and other natural risks, such as earthquake, flood, drought,     lightning, wind and fire, acts of war or terrorism;
- Market conditions that     could affect the operations and prospects of IDACORP's subsidiaries or     their competitors;
- Increasing health care     costs and the resulting effect on medical benefits paid for employees;
- Performance of the stock     market and the changing interest rate environment, which affect the amount     of required contributions to pension plans, as well as the reported costs     of providing pension and other postretirement benefits;
- Increasing costs of     insurance, changes in coverage terms and the ability to obtain insurance;
- Changes in tax rates or     policies, interest rates or rates of inflation;
- Adoption of or changes in     critical accounting policies or estimates; and
- New accounting or     Securities and Exchange Commission requirements, or new interpretation or     application of existing requirements.

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

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**EXECUTIVE OVERVIEW:**

**2007 Financial Results**A summary of IDACORP's net income andearnings per diluted share for the lastthree years is as follows:

|                                              |  | **2007** | ** ** | **2006** | ** ** | **2005** |
|----------------------------------------------|--|----------|------------|----------|------------|----------|
| Net income                                   |  | $        | 82,339     |          | $          | 107,403  |  | $ | 63,661 |
| Average outstanding shares -  diluted (000s) |  |          | 44,291     |          |            | 42,874   |  |  | 42,362 |
| Earnings per diluted share                   |  | $        | 1.86       |          | $          | 2.51     |  | $ | 1.50 |
|                                              |  |          |            |          |            |          |  |  |  |

The key factors affecting thechange in IDACORP's net income for 2007 include (amounts shown are net ofincome taxes):

- Discontinued operations     contributed $0.1 million to earnings in 2007 as compared to $7 million in     2006, a decrease of $0.17 per diluted share.  On July 20, 2006, IDACORP     completed the sale of all of the outstanding common stock of ITI to     IdaTech UK Limited, a wholly-owned subsidiary of Investec Group     Investments (UK) Limited.  On February 23, 2007, IDACORP completed the     sale of all of the outstanding common stock of IDACOMM to American Fiber     Systems, Inc.
- Net loss at the holding     company was $3.5 million, a decrease of $2.5 million, or $0.05 per diluted     share, from the prior year.  The decrease in net loss is attributable to a     decrease in administration expenses resulting from the sale of ITI and     IDACOMM.
- IFS contributed $2.4     million less to earnings than in the prior year, a decrease of $0.06 per     diluted share.  The decline in earnings is attributable to higher     investment amortization expense and lower tax benefits due to a reduction     in the amount of new investments combined with the continued aging of existing     investments.
- IPC's net income for the last three years is as follows:    

|            |  | **2007** | ** ** | **2006** | ** ** | **2005** |
|------------|--|----------|------------|----------|------------|----------|
| Net income |  | $        | 76,579     |          | $          | 93,929   |  | $ | 71,839 |
|            |  |          |            |          |            |          |  |  |  |

The key factors affecting IPC'snet income for 2007 include (amounts shown are net of income taxes):

- Increased retail sales     contributed $12.9 million to earnings in 2007.  Warmer and drier     conditions in 2007 led to higher residential, commercial and industrial     usage, as well as higher irrigation loads as compared to the prior year.      IPC continued to experience moderate customer growth, with the average     number of general business customers increasing 12,125 over 2006, an     increase of 2.6 percent.
- Increased costs to supply     power, net of rate adjustments, reduced earnings by $13.0 million in     2007.  Poor hydroelectric generating conditions in 2007 increased IPC's     reliance on typically more expensive thermal generation and purchased     power, and reduced wholesale sales.  IPC's hydroelectric generation     contributed only 46 percent of total system generation in 2007 as compared     to 57 percent in 2006.
- Increases in Other O&M     expenses reduced earnings by $12.7 million in 2007 compared to 2006.  The     increase is primarily the result of increases in third-party transmission     costs, regulatory commission expenses, maintenance expenses for IPC's coal-fired     generation facilities, hydroelectric license and inspection costs, and the     Fixed Cost Adjustment accrual which began in 2007.
- Gain on sales of excess SO 2      emission allowances was $1.7 million in 2007 compared to $5.0 million in     2006.

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**Non-GAAP FinancialMeasures**The following discussion includesfinancial information prepared in accordance with generally accepted accountingprinciples (GAAP), as well as one additional financial measure, electricutility margin, that is considered a "non-GAAP financial measure" under SECrules.  Generally, a non-GAAP financial measure is a numerical measure of acompany's financial performance, financial position or cash flows that excludes(or includes) amounts that are included in (or excluded from) the most directlycomparable measure calculated in accordance with GAAP.  The most directlycomparable GAAP financial measure to electric utility margin is operatingincome.

The presentation of electricutility margin is intended to supplement the information available to investorsfor evaluating IPC's operating performance.  When viewed in conjunction withIPC's operating income, electric utility margin provides a more completeunderstanding of the factors and trends affecting IPC's business, and users canassess which information best suits their needs.  However, this measure is notintended to replace operating income, or any other measure calculated inaccordance with GAAP, as an indicator of operating performance.

IPC's management useselectric utility margin, in addition to GAAP measures, to determine whether IPCis collecting the appropriate amount of energy costs from its customers toallow recovery of operating costs.  Electric utility margin also provides bothmanagement and investors with a better understanding of the effects ofregulatory mechanisms on IPC's operating income.  The primary limitationassociated with this measure is that IPC's electric utility margin may not becomparable to other companies' electric utility margins.  However, managementuses electric utility margin as an internal tool for evaluating and conductingthe business, and is therefore unburdened by this limitation.

The calculations of IPC'selectric utility margin for the last three years are as follows:

| ** **                                        | ** **                                  | **2007**      | ** **    | **2006**      | ** **    | **2005**      |
|---------------------------------------------------|---------------------------------------------|---------------|---------------|---------------|---------------|---------------|
| General business revenue                          | $                                           | 668,303  | $             | 636,375  | $             | 667,270  |
| PCA amortization                                  |                                             | 287      |               | 2,432    |               | (27,791)      |
| Other revenues amortization                       |                                             |               |               |               |               |               |
|                                                   | Irrigation load reduction                   |               | -        |               | (5,400)       |               | (8,501) |
|                                                   | Rate case tax settlement                    |               | -        |               | (4,745)       |               | (2,892) |
|                                                   |                                             | Total         |               | 668,590  |               | 628,662  |  | 628,086  |
| Power supply costs:                               |                                             |               |               |               |               |               |
|                                                   | Off-system sales                            |               | 154,948  |               | 260,717  |               | 142,794  |
|                                                   | Purchased power                             |               | (289,484)     |               | (283,440)     |               | (222,310) |
|                                                   | Fuel                                        |               | (134,322)     |               | (115,018)     |               | (103,164) |
|                                                   | PCA deferral                                |               | 120,844  |               | 27,094   |               | 30,786  |
|                                                   |                                             | Total         |               | (148,014)     |               | (110,647)     |  | (151,894) |
| Third party transmission  expense                 |                                             | (10,470)      |               | (7,639)       |               | (6,292)       |
| Other revenues (excluding  DSM)                   |                                             | 38,663   |               | 33,526   |               | 39,012   |
|                                                   | Electric utility margin                     | $             | 548,769  | $             | 543,902  | $             | 508,912  |
| Electric utility margin as  a percentage of total |                                             |               |               |               |               |               |
|                                                   | general business revenue,  PCA amortization |               |               |               |               |               |  |
|                                                   | and other revenues  amortization            |               | 82%           |               | 87%           |               | 81% |
|                                                   |                                             |               |               |               |               |               |  |

The decline in electricutility margin as a percentage of total general business revenue, PCAamortization and other revenues amortization is a result of an increase in theten percent sharing component of the PCA due to below normal hydroelectricproduction and the negative impact of the Load Growth Adjustment Rate (LGAR)mechanism.

System load in 2007 was 1.0million MWh greater than the base loads established in the 2005 general ratecase.  This represents an increase of 274,000 MWh over 2006 total systemloads.  The MWh increases, when combined with an increase in the LGAR in April2007 from $16.84 per MWh to $29.41 per MWh, result in a decline in a componentof the PCA deferral as compared to 2006.  This decline reduced electric utilitymargin by $13.0 million.

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The following table reconcileselectric utility margin to electric utility operating income (GAAP) for thelast three years:

| ** **                           | ** **                                    | **2007**      | ** **    | **2006**      | ** **    | **2005**      |
|--------------------------------------|-----------------------------------------------|---------------|---------------|---------------|---------------|---------------|
| Electric utility margin              | $                                             | 548,769  | $             | 543,902  | $             | 508,912  |
| Other operations and  maintenance    |                                               |               |               |               |               |               |
|                                      | (excluding third party  transmission expense) |               | (276,040)     |               | (257,171)     |               | (236,089) |
| Gain on sale of emission  allowances |                                               | 2,754    |               | 8,257    |               | 1,172    |
| Depreciation                         |                                               | (103,072)     |               | (99,824)      |               | (101,485)     |
| Taxes other than income  taxes       |                                               | (17,634)      |               | (18,661)      |               | (20,856)      |
|                                      | Operating income - electric  utility (GAAP)   | $             | 154,777  | $             | 176,503  | $             | 151,654  |
|                                      |                                               |               |               |               |               |               |

**Business Strategy**IDACORP is focusing on a strategythat emphasizes IPC as IDACORP's core business.  IPC continues to experience moderatecustomer growth in its service area, and this corporate strategy recognizesthat IPC must make substantial investments in infrastructure to ensure adequatesupply and reliable service.  IPC's regulatory plans in 2008 include finalizingthe 2007 general rate case as well as additional initiatives designed to speedrecovery of the financial and operating costs of new facilities and systemimprovements.

The strategy includes seekingtimely rate recovery in both the Idaho and Oregon jurisdictions.  The 2008regulatory strategy includes filing for recovery of the investment andoperating costs of IPC's new 170- MW natural gas-fired peaking plant expectedto go on line in April 2008; pursuing a power cost adjustment mechanism inOregon; and potential general rate case filings in both Idaho and Oregon.

IFS and Ida-West remain components of the corporate strategy.  This strategy alsoincluded the sale of non-core businesses.  IDACORP completed the sales of ITIon July 20, 2006, and IDACOMM on February 23, 2007.

**Regulatory Matters****General rate case settlement:  **On June 8, 2007, IPC filed an application with theIPUC requesting an average rate increase of approximately 10.35 percent, or$63.9 million annually, for its Idaho customers in order to begin recovery ofits capital investments and higher operating costs.  IPC also requested a$29.16 per MWh LGAR, which adjusts the power supply costs IPC includes in thePCA for differences between actual load and the load used in calculating baserates.  The existing LGAR is $29.41 per MWh.  The impact of the new LGAR on IPCwill ultimately be determined by future load changes.

The parties to the proceedingreached a settlement that includes an average annual increase of 5.2 percent(approximately $32.1 million annually).  The parties also agreed in the settlementto make a good faith effort to develop a mechanism to adjust or replace thecurrent LGAR.  As an interim solution, the parties have agreed to use the LGARof $62.79 per MWh recommended by the IPUC Staff in its testimony filed December10, 2007, but to apply it to only fifty percent of the load growth occurringduring each month within the April 2008 - March 2009 PCA year.

The parties also agreed inthe settlement to participate in a good faith discussion regarding a forecasttest year methodology that balances the auditing concerns of the IPUC Staff andintervenors with IPC's need for timely rate relief.  The parties agreed thatsuch a methodology would begin with auditable numbers from which projectionswould be made for the test year.

IPC filed a settlementstipulation with the IPUC on January 23, 2008.  The settlement is subject toapproval by the IPUC.  The parties have requested in the stipulation that thenew rates become effective no later than March 1, 2008, but IPC is unable topredict what relief the IPUC will grant or when the IPUC will issue its finalorder.

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**Power Cost Adjustment: **On June 1, 2007, IPC implemented its annual Power CostAdjustment (PCA), which resulted in a $77.5 million, or 14.5 percent onaverage, increase in the rates of Idaho customers.  The increase in rates is adirect result of significantly below normal winter precipitation anddeteriorated stream flow conditions during the first half of 2007.  In yearswhere water is plentiful and IPC can fully utilize its extensive hydroelectricsystem, power production costs are lower and IPC can pass those benefits to itscustomers in the form of rate reductions.  In years when water is in shortsupply, as it was this past winter, the higher costs of supplying power byother means are shared with IPC's customers.

**Emission allowances:  **In 2005 and early 2006, IPC sold 78,000 SO2emission allowances for a total of $81.6 million, after subtracting transactionfees.  The sales proceeds allocated to the Idaho jurisdiction wereapproximately $76.8 million ($46.8 million net of tax, assuming a tax rate ofapproximately 39 percent).  On May 12, 2006, the IPUC approved a stipulationthat allowed IPC to retain ten percent as a shareholder benefit with theremaining 90 percent plus a carrying charge recorded as a customer benefit. This customer benefit is included in IPC's PCA calculations as a credit to thePCA true-up balance and is currently reflected in PCA rates during the June 1,2007, through May 31, 2008, PCA rate year.

During 2007, IPC sold 35,000SO2 emission allowances for a total of $19.6 million, aftersubtracting transaction fees.  The sales proceeds to be allocated to the Idahojurisdiction are approximately $18.5 million ($11.3 million net of tax,assuming a tax rate of approximately 39 percent).  On January 15, 2008, aworkshop was held to discuss whether the customer share of the Idahojurisdictional portion of the 2007 sales proceeds should once again be includedas a PCA credit or used to reduce investment costs in wind development, greentags, or other options that would provide longer term customer benefits.  Becausethe workshop participants were unable to reach a consensus regarding the use ofthe SO2 emission allowance proceeds, the IPUC determined that thecase would proceed under modified procedure.  Written comments were dueFebruary 25, 2008.

The bulk of IPC's accumulatedexcess emission allowances were sold during the 2005-2007 period.  IPCcurrently has approximately 15,000 excess emission allowances and anticipatesaccumulating a similar amount of excess allowances annually for the nearfuture.  Tighter emission restrictions are expected in the long term, which maycause IPC to use more emission allowances for its own requirements and reducethe annual amount of excess allowances.

**Record system peaks**IPC's service territory experiencedrecord-setting high temperatures during July 2007.  Due to these weatherconditions and continued customer growth, IPC set three new all-time systempeaks between July 5 and July 13, 2007, with the highest, 3,193 MW, being seton July 13, 2007.  The previous hourly system peak of 3,084 MW was set in2006.  Although IPC was able to meet all of its load requirements during theseperiods of increased demand, all available resources of IPC's system were fullycommitted during several heavy load periods during the summer.  The record-settingtemperatures also contributed to numerous wildfires throughout IPC's servicearea.  Although the wildfires damaged or destroyed several distribution andtransmission structures, the wildfires did not have a material impact toearnings in 2007.  The all-time winter peak demand is 2,464 MW set on January 24,2008.  Theprevious hourly system winter peak of 2,459 MW was set in 1998.

**Integrated Resource Plan**IPC filed its 2006 IRP with the IPUCin September 2006 and with the OPUC in October 2006.  The 2006 IRP previewedIPC's load and resource situation for the next twenty years, analyzed potentialsupply-side and demand-side options and identified near-term and long-termactions.

The IPUC accepted the 2006IRP in March 2007.  The OPUC acknowledged the 2006 IRP in September 2007 withthe stipulation that IPC not commit to the construction of a 250-MW pulverizedcoal resource, identified to come on-line in 2013, until IPC presents an updateof the 2006 IRP to the OPUC no later than June 2008.  With its acceptance ofthe 2006 IRP, the IPUC requested that IPC align the submittal of its next IRPwith those submitted by other utilities.  To comply with this request, IPCintends to provide an update on the status of the 2006 IRP to both the IPUC andOPUC no later than June 2008 and file a new IRP in June 2009.

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The near-term action plan inthe 2006 IRP indicated initial commitments to the construction of a coal-firedbase load resource would be necessary before the end of 2007 in order for aproject to be on-line in 2013.  In order to meet this schedule, IPC screenedand evaluated coal-fired resources in 2006 and 2007.  The results of thisevaluation indicated construction costs had escalated substantially sinceresource cost estimates were prepared for the 2006 IRP.  Due to such escalatingconstruction costs, potential permitting issues, and continued uncertaintysurrounding future greenhouse gas laws and regulations, IPC determined thatcoal-fired generation was not the best technology to meet its resource needs in2013.  IPC plans to construct a natural gas-fired combined cycle combustionturbine located closer to its load center in southern Idaho.  IPC continues toevaluate coal-fired resource opportunities, including expansion of its jointly-ownedfacilities, clean coal technologies and potential power purchase agreements forfuture energy needs.

**Transmission Projects**IPC and PacifiCorp are jointlyexploring a project, called the Gateway West Project, to build two 500-kV linesbetween the Jim Bridger plant in Wyoming and Boise.  The lines would bedesigned to increase electrical transmission capacity across southern Idaho inresponse to increasing customer demand and growth.  If built, it is expectedthat the majority of the project would be completed between 2012 and 2014,depending on the timing of acquisition of rights-of-way, siting and permitting,and construction sequencing.  IPC estimates that its share of project costswould be between $800 million and $1.2 billion.

IPC is also exploringalternatives for the construction of a 500-kV line between southwestern Idahoand the Northwest, named the Hemingway-Boardman Line (formerly referred to asthe Idaho-Northwest Line).  If built, the line could run from the proposedHemingway Station southwest of Boise to a proposed transmission station nearBoardman, Oregon and be in service as early as 2012.  IPC has received inquiriesfrom other parties about participating in this project.

The proposed Gateway West andHemingway-Boardman transmission projects will be used both by wholesaletransmission customers and to serve IPC's native load consistent with IPC's OpenAccess Transmission Tariff (OATT).  Therefore these facilities will be subjectto both the FERC and state public utility commission regulation and rate makingpolicies.

**Capital Requirements andCash Flows**IDACORP estimates that it will spend approximately $900 million onconstruction expenditures over the next three years, excluding any estimatedexpenditures for a Nominal 250-MW combined cycle combustion turbine expected tobe operational in mid-2012 and the transmission projects discussed above.  Thisamount reflects the need for additional resources in order for IPC to supplypower to its growing number of customers.

Forecasts indicate thatinternal cash generation after dividends will provide less than the full amountof total capital requirements for 2008 through 2010.  IDACORP and IPC expect tocontinue financing the utility construction program and other capitalrequirements with internally generated funds and continued reliance onexternally financed capital.

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

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**IdahoWater Management Issues**Power generation at the IPChydroelectric power plants on the Snake River is dependent upon the state waterrights held by IPC and the long-term sustainability of the Snake River,tributary spring flows and the Eastern Snake Plain Aquifer that is connected tothe Snake River.  IPC continues to participate in water management issues inIdaho that may affect those water rights and resources.  This includes activeparticipation in the Snake River Basin Adjudication, a judicial action initiatedin 1987 to determine the nature and extent of water use in the Snake Riverbasin, judicial and administrative proceedings relating to the conjunctivemanagement of ground and surface water rights, and management and planningprocesses intended to reverse declining trends in river, spring, and aquiferlevels and address the long-term water resource needs of the state.  Onoccasion, resolution of these water management issues involves litigation.  IPCis involved in legal actions regarding not only its water rights but also thewater rights of others.  One such action, initiated in the Snake River BasinAdjudication, involves IPC's water rights at the Swan Falls project on theSnake River and several other upstream hydroelectric projects that are thesubject of a 1984 agreement with the state of Idaho known as the Swan FallsAgreement.  IPC also has initiated legal action against the U.S. Bureau ofReclamation (USBR) over the interpretation and effect of a 1923 contract withthe USBR on the operation of the American Falls Reservoir and the release ofwater from that reservoir to be used at IPC's downstream hydroelectricprojects.  Although IPC intends to continue vigorously defending its waterrights and although none of the pending water management issues are expected toimpact IPC's hydroelectric generation in the near term, IPC cannot predict theultimate outcome of these matters or what effect they may have on itsconsolidated financial positions, results of operations or cash flows.  IPC'songoing participation in such issues will help ensure that water remainsavailable over the long-term for use at IPC's hydroelectric projects on theSnake River.

**CRITICAL ACCOUNTINGPOLICIES AND ESTIMATES:**

The preparation of financialstatements in accordance with GAAP requires management to apply accountingpolicies and make estimates and judgments that affect the reported amounts ofassets, liabilities, revenues and expenses and related disclosure of contingentassets and liabilities.  These estimates involve judgment with respect tonumerous factors that are difficult to predict and are beyond management'scontrol.  Management adjusts these estimates based on historical experience andon other assumptions and factors that are believed to be reasonable under thecircumstances Actual amounts could materially differ from the estimates.

Management believes thefollowing accounting policies and estimates are the most critical to theportrayal of their financial condition and results of operations and requiremanagement's most difficult, subjective or complex judgments, often as a resultof the need to make estimates about the effect of matters that are inherentlyuncertain and may change in subsequent periods.

**Accounting for RateRegulation**In order to apply the accounting policiesand practices of Statement of Financial Accounting Standards (SFAS) 71, *"Accountingfor the Effects of Certain Types of Regulation,"*a regulated company mustsatisfy the following conditions: (1) an independent regulator must set rates;(2) the regulator must set the rates to cover specific costs of deliveringservice; and (3) the service territory must lack competitive pressures toreduce rates below the rates set by the regulator.  SFAS 71 requires companiesthat meet the above conditions to reflect the impact of regulatory decisions intheir consolidated financial statements and requires that certain costs bedeferred as regulatory assets until matching revenues can be recognized. Similarly, certain items may be deferred as regulatory liabilities andamortized to the income statement as rates to customers are reduced.

IPC follows SFAS 71, and itsfinancial statements reflect the effects of the different rate makingprinciples followed by the jurisdictions regulating IPC.  The primary effect ofthis policy is that IPC has recorded $450 million of regulatory assets and $274million of regulatory liabilities at December 31, 2007.  While IPC expects tofully recover these regulatory assets from customers through rates and refundthese regulatory liabilities to customers through rates, such recovery orrefund is subject to final review by the regulatory entities.  If futurerecovery or refund of these amounts ceases to be probable, or if IPC determinesthat it no longer meets the criteria for applying SFAS 71, IPC would berequired to eliminate those regulatory assets or liabilities, unless regulatorsspecify some other means of recovery or refund.  Either circumstance could havea material effect on IPC's results of operations and financial position.

**Pension and OtherPostretirement Benefits**IPC maintains a qualified definedbenefit pension plan covering most employees, an unfunded nonqualified deferredcompensation plan for certain senior management employees and directors, and apostretirement medical benefit plan.

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

The assumed discount rate isbased on reviews of market yields on high-quality corporate debt. Specifically, IDACORP and IPC utilize data published in the Citigroup PensionLiability Index and apply the rates therein against the projected cash outflowsof the plans.  The discount rate used to calculate the 2008 pension expensewill be increased to 6.4 percent from the 5.85 percent used in 2007.

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

Gross pension and otherpostretirement benefit expense for these plans totaled $15 million, $16million, and $14 million for the three years ended December 31, 2007, 2006 and2005, respectively, including amounts allocated to capitalized labor andamounts deferred as regulatory assets.  For 2008, gross pension expense isexpected to total approximately $16 million, which takes into account theincrease in the discount rate noted above.  No changes were made to the otherkey assumptions used in the actuarial calculation.

Had different actuarialassumptions been used, pension expense could have varied significantly.  Thefollowing table reflects the sensitivities associated with changes in thediscount rate and rate of return on plan assets actuarial assumptions onhistorical and future pension and postretirement expense:

| ** **              | **Discount rate**         | **Rate of return** |
|-------------------------|---------------------------|--------------------|
| ** **              | **2008**                  | **2007**           | **2008** | **2007** |
| ** **              | **(millions of dollars)** |
| Effect of 0.5% increase | $                         | (1.4)              | $ | (1.7) | $ | (2.2) | $ | (2.2) |
| Effect of 0.5% decrease |                           | 1.7           |  | 2.7  |  | 2.2  |  | 2.2  |
|                         |                           |                    |  |  |  |  |  |  |

No cash contributions weremade to the qualified plan from 2005 through 2007, and none are expected in2008.  Under the non-qualified plan, IPC makes payments directly toparticipants in the plan.  Payments are expected to be approximately $2.7million in 2008 and averaged approximately $2.5 million per year from 2005 to2007.  Gross postretirement plan contributions are expected to be approximately$4.1 million in 2008, and averaged $4.3 million from 2005 to 2007.

Please refer to Note 8 andNote 6 of IDACORP's and IPC's Consolidated Financial Statements, which containsadditional information about the pension and postretirement plans and theregulatory treatment of pension expense, respectively.

**Contingent Liabilities**Contingent liabilities are accounted for in accordance with SFAS 5, "*Accountingfor Contingencies*."  According to SFAS 5, an estimated loss from a losscontingency is charged to income if (a) it is probable that an asset had beenimpaired or a liability had been incurred at the date of the financialstatements and (b) the amount of the loss can be reasonably estimated.  If aprobable loss cannot be reasonably estimated no accrual is recorded butdisclosure of the contingency in the notes to the financial statements isrequired.  Gain contingencies are not recorded until realized.

IDACORP and IPC have a numberof unresolved issues related to regulatory and legal matters.  If therecognition criteria of SFAS 5 have been met, liabilities have been recorded. Estimates of this nature are highly subjective and the final outcome of thesematters could vary significantly from the amounts that have been included inthe financial statements.

**Impairment****of Long-Lived Assets**Long-lived assets are periodically reviewed for impairment when events orchanges in circumstances indicate that the carrying amount of an asset may notbe recoverable as prescribed under SFAS 144, *"Accounting for the Impairmentor Disposal of Long-Lived Assets."*  SFAS 144 requires that if the sum ofthe undiscounted expected future cash flows from an asset is less than thecarrying value of the asset impairment must be recognized in the financialstatements.  Long-lived assets that were evaluated in 2007 include thefollowing:

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

**Impairment of Equity-MethodInvestments**IFS has affordable housinginvestments with a net book value of $78 million at December 31, 2007, and Ida-Westhas investments in four joint ventures that own electric power generationfacilities.  Except for two investments now consolidated in accordance withGAAP these investments are accounted for under the equity method of accountingas described in Accounting Principles Board Opinion No. (APB) 18, "*TheEquity Method of Accounting for Investments in Common Stock*."  The standardfor determining whether impairment must be recorded under APB 18 is whether theinvestment has experienced a loss in value that is considered an other-than-temporarydecline in value.  Impairment analyses on these investments were performed in2007 and no impairment was noted.  These estimates required IDACORP to makeassumptions about future stream flows, revenues, cash flows and other itemsthat are inherently uncertain.  Actual results could vary significantly fromthe assumptions used, and the impact of such variations could be material.

**Unbilled Revenue******IPC's general business revenuesinclude an estimate of electricity delivered to general business customers thathas not been billed at the end of the period.  Unbilled revenues estimates aredependent upon a number of inputs that require management's judgment.  Unbilledrevenue is calculated by taking daily estimates of MWhs delivered and applyinginformation from the meter-reading schedule to estimate the portion of MWhsdelivered that have not been billed.  These unbilled MWhs are allocated to thegeneral business customer classes based on historical data.  IPC thencalculates unbilled revenue based on the respective rates of each customerclass.  Due to the seasonal fluctuations of IPC's load, the amount of unbilledrevenue increases during the summer and winter months and decreases during thespring and fall.

**Income Taxes**IDACORP and IPC account for incometaxes in accordance with SFAS No. 109, "*Accounting for Income Taxes*" andFIN 48 "*Accounting for Uncertainty in Income Taxes*."  Judgment andestimation are used in developing the provision for income taxes and thereporting of tax-related assets and liabilities.  The interpretation of taxlaws can involve uncertainty, since tax authorities may interpret such lawsdifferently.  Actual income taxes could vary from estimated amounts and mayresult in favorable or unfavorable impacts to net income, cash flows, and tax-relatedassets and liabilities.

**RESULTS OF OPERATIONS:**

This section of the MD&Atakes a closer look at the significant factors that affected IDACORP's and IPC'searnings over the last three years.  In this analysis, the results of 2007 arecompared to 2006 and the results of 2006 are compared to 2005.

The following table presentsearnings (losses) for IDACORP and its subsidiaries:

| ** **                                   | **2007**       | ** **   | **2006**     | ** ** | **2005**     |
|----------------------------------------------|----------------|--------------|--------------|------------|--------------|
| IPC - Utility operations                     | $              | 76,579  |              | $          | 93,929  |  | $ | 71,839  |
| IDACORP Financial Services                   |                | 7,112   |              |            | 9,509   |  |  | 10,911  |
| IDACORP Energy                               |                | (171)        |              |            | 5       |  |  | 4,881  |
| Ida-West Energy                              |                | 2,223   |              |            | 2,564   |  |  | 2,381  |
| Holding company expenses                     |                | (3,471)      |              |            | (5,932)      |  |  | (4,296) |
| Discontinued operations                      |                | 67      |              |            | 7,328   |  |  | (22,055) |
|                                              | Total earnings | $            | 82,339  |            | $            | 107,403  |  | $ | 63,661  |
| Average outstanding shares -  diluted (000s) |                | 44,291  |              |            | 42,874  |  |  | 42,362  |
| Earnings per diluted share                   | $              | 1.86    |              | $          | 2.51    |  | $ | 1.50  |
|                                              |                |              |              |            |              |  |  |  |  |

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**Utility Operations****Operating environment: **IPC is one of the nation's few investor-ownedutilities with a predominantly hydroelectric generating base.  Because of itsreliance on hydroelectric generation, IPC's generation operations can besignificantly affected by weather conditions.  The availability ofhydroelectric power depends on the amount of snow pack in the mountainsupstream of IPC's hydroelectric facilities, springtime snow pack run-off, riverbase flows, spring flows, rainfall and other weather and stream flow managementconsiderations.  During low water years, when stream flows into IPC'shydroelectric projects are reduced, IPC's hydroelectric generation is reduced. This results in less generation from IPC's resource portfolio (hydroelectric,coal-fired and gas-fired) available for off-system sales and, most likely, anincreased use of purchased power to meet load requirements.  Both of thesesituations - a reduction in off-system sales and an increased use of moreexpensive purchased power - result in increased power supply costs.  Duringhigh water years, increased off-system sales and the decreased need forpurchased power reduce net power supply costs.

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

Stream flow conditions weremuch lower in 2007 than 2006 resulting in 6.2 million MWh generated from IPC'shydroelectric facilities, compared to 9.2 million MWh in 2006.  The observedstream flow data released on August 1, 2007, by the National Weather Service'sNorthwest River Forecast Center (RFC) indicated that Brownlee reservoir inflowfor April through July 2007 was 2.8 million acre-feet (maf), or 44 percent ofthe RFC average.  Brownlee reservoir inflow for 2007 totaled 8.5 maf, or 56percent of the RFC average.  Storage in selected federal reservoirs upstream ofBrownlee as of February 10, 2008 was 76 percent of average.  The stream flowforecast released on February 14, 2008 by the RFC predicts that Brownleereservoir inflow for April through July 2008 will be 5.7 maf, or 90 percent ofthe RFC average.

Generationfrom thermal plants during 2007 was higher than 2006 due primarily to increasedgeneration to meet increased load requirements.  In addition, the thermalplants were under-utilized in 2006 due to an unanticipated outage at theBoardman plant and a planned outage at the Valmy plant, of which IPC owns a tenpercent and 50 percent interest, respectively.  Both units returned to servicein June 2006.  Additionally, the Bennett Mountain combustion turbine suffered amechanical failure on July 11, 2006.  IPC's investigation revealed that duringconstruction a bolt was negligently installed by a third party.  The bolt cameloose, causing extensive mechanical damage.  The plant was down from July 12through September 6, 2006.  Total repair costs were approximately $16 million. In 2007, IPC received reimbursement for the bulk of the total repair costs fromits insurance carrier.  With regards to the remaining repair costs, IPC hasreached an agreement in principle with the third party, which essentially makesIPC whole.

IPC'ssystem is dual peaking, with the larger peak demand occurring in the summer. The all-time system peak demand is 3,193 MW, set on July 13, 2007.  Theprevious hourly system peak of 3,084 MW was set in 2006.  Although IPC was ableto meet all of its load requirements during these periods of increased demand,all available resources of IPC's system were fully committed during severalheavy load periods in the summer.  The all-time winter peak demand is 2,464 MW set onJanuary 24, 2008.  The previous hourly system winter peak of 2,459 MW wasset in 1998.  The following tablepresents IPC's power supply for the last three years:

|      | **MWh**           |
|------|-------------------|
|      | **Hydroelectric** | **Thermal** | **Total System** | **Purchased** | ** ** |
|      | **Generation**    | **Generation** | **Generation** | **Power** | **Total** |
| 2007 | 6,181             | 7,367 | 13,548 | 5,196 | 18,744 |
| 2006 | 9,207             | 7,021 | 16,228 | 4,964 | 21,192 |
| 2005 | 6,199             | 7,315 | 13,514 | 3,894 | 17,408 |

IPC's modeled median annualhydroelectric generation is 8.5 million MWh, based on hydrologic conditions forthe period 1928 through 2006 and adjusted to reflect the current level of waterresource development.

**General Business Revenue:**  The primary influences on electricity sales are weather,customer growth and economic conditions.  Extreme temperatures increase salesto customers who use electricity for cooling and heating, and moderatetemperatures decrease sales.  Precipitation levels during the agriculturalgrowing season affect sales to customers who use electricity to operateirrigation pumps.  Increased precipitation reduces electricity usage by thesecustomers.

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

|                         |             | **2007** | ** ** | **2006** | ** ** | **2005** |
|-------------------------|-------------|----------|------------|----------|------------|----------|
| Revenue                 |             |          |            |          |            |          |  |  |  |
|                         | Residential |          | $          | 308,208  |            | $        | 299,594 |  | $ | 299,488 |
|                         | Commercial  |          |            | 170,001  |            |          | 162,391 |  |  | 173,268 |
|                         | Industrial  |          |            | 101,409  |            |          | 102,958 |  |  | 118,259 |
|                         | Irrigation  |          |            | 88,685   |            |          | 71,432 |  |  | 76,255 |
|                         |             | Total    |            | $        | 668,303    |          | $ | 636,375 |  | $ | 667,270 |
| MWh                     |             |          |            |          |            |          |  |  |  |
|                         | Residential |          |            | 5,227    |            |          | 5,068 |  |  | 4,760 |
|                         | Commercial  |          |            | 3,937    |            |          | 3,761 |  |  | 3,639 |
|                         | Industrial  |          |            | 3,454    |            |          | 3,475 |  |  | 3,423 |
|                         | Irrigation  |          |            | 1,924    |            |          | 1,635 |  |  | 1,467 |
|                         |             | Total    |            |          | 14,542     |          |  | 13,939 |  |  | 13,289 |
| Customers (average)     |             |          |            |          |            |          |  |  |  |
|                         | Residential |          |            | 397,285  |            |          | 387,707 |  |  | 373,602 |
|                         | Commercial  |          |            | 61,640   |            |          | 59,050 |  |  | 57,146 |
|                         | Industrial  |          |            | 126      |            |          | 130 |  |  | 129 |
|                         | Irrigation  |          |            | 18,043   |            |          | 18,081 |  |  | 17,942 |
|                         |             | Total    |            |          | 477,094    |          |  | 464,968 |  |  | 448,819 |
| Heating  degree-days    |             |          | 5,128      |          |            | 5,195    |  |  | 5,437 |
| Cooling  degree-days    |             |          | 1,290      |          |            | 1,209    |  |  | 965 |
| Precipitation  (inches) |             |          | 8.1        |          |            | 12.1     |  |  | 13.6 |

Heating and cooling degree-daysare common measures used in the utility industry to analyze the demand forelectricity and indicate when a customer would use electricity for heating andair conditioning.  A degree-day measures how much the average daily temperaturevaries from 65 degrees.  Each degree of temperature above 65 degrees is countedas one cooling degree-day, and each degree of temperature below 65 degrees iscounted as one heating degree-day.  Normal heating degree-days and coolingdegree-days are 5,727 and 807, respectively.

2007 vs. 2006:

- Rates:   Rate increases positively impacted general     business revenue by $3.0 million in 2007 as compared to prior year.  A PCA     increase on June 1, 2007, increased rates by an average of 14.5 percent,     but was moderated by the prior year net effect of the 19.3 percent PCA     reduction which was partially offset by a one percent net base rate     increase;
- Customers:   General business customer growth improved general     business revenue $11.7 million for the year, as IPC continues to     experience moderate customer growth in its service territory.  The general     business customer base (12-month average) increased 2.6 percent over prior     year; and
- Usage:   Weather variations positively impacted general     business revenue by $17.2 million.  Irrigation usage is higher due to     drier than normal conditions in the summer of 2007 as compared to 2006.      Residential, industrial and commercial usage was positively impacted by     warmer weather conditions during the summer months.

 

2006 vs. 2005:

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

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- Usage:   Weather variations positively impacted sales by     $17.1 million.  Conditions were unusually warm in May, June and July     compared to the prior year, which had an abnormally cool and wet spring.

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

| ** **      | **2007**   | ** ** | **2006** | ** ** | **2005** |
|-----------------|------------|------------|----------|------------|----------|
| Revenue         | **$**      | 154,948    |          | **$**      | 260,717  |  | **$** | 142,794 |
| MWh sold        | ** ** | 2,744      |          | ** ** | 5,821    |  | ** ** | 2,774 |
| Revenue per MWh | **$**      | 56.47      |          | **$**      | 44.79    |  | **$** | 51.48 |
|                 | ** ** |            |          | ** ** |          |  | ** ** |  |

** **

2007 vs. 2006:  In 2007, the MWh volume sold decreased 53 percentand revenues decreased 41 percent.  Deteriorated stream flow conditionsthroughout Southern Idaho decreased total system generation and electricityavailable for surplus sales.  Revenue decreases from lower sales volumes weremoderated by higher prices.  Prior year prices were lower due to the abundanceof energy in the region.

2006 vs. 2005:  In 2006, the MWh volume sold more than doubled and revenuesgrew 83 percent.  Improved stream flow conditions increased total systemgeneration and electricity available for surplus sales.  Revenue increases fromhigher sales volumes were moderated by lower prices caused by abundant energyin the region.  The volume increase was also impacted by early water yearindications suggesting continued drought conditions for 2006, prompting IPC tomake forward purchases in conformance with its risk management policy that weresubsequently sold.  Additional sales activities are the result of conforming toIPC's risk management policy, managing IPC's energy portfolio to meet customerload, and IPC reacting to changes in market conditions to minimize net powersupply costs.

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

| ** **                                 | **2007** | ** **   | **2006**     | ** ** | **2005**     |
|--------------------------------------------|----------|--------------|--------------|------------|--------------|
| Transmission services and  property rental | $        | 39,739  |              | $          | 34,737  |  | $ | 39,012  |
| Provision for rate refund                  |          | (1,076)      |              |            | (1,211)      |  |  | -  |
| DSM                                        |          | 13,487  |              |            | -       |  |  | -  |
| Rate case tax settlement                   |          | -       |              |            | (4,745)      |  |  | (2,892) |
| Irrigation lost revenues                   |          | -       |              |            | (5,400)      |  |  | (8,501) |
|                                            | Total    | $            | 52,150  |            | $            | 23,381  |  | $ | 27,619  |
|                                            |          |              |              |            |              |  |  |  |
|                                            |          |              |              |            |              |  |  |  |  |

 

2007 vs. 2006:  Other revenues increased $28.8 million due mainlyto the following:

- Beginning in January 2007,     a new IPUC accounting order became effective for the treatment of IPC's     DSM expenses.  The $13.5 million of DSM costs are recorded in Other     operations and maintenance expenses and are offset by the same amount     recorded in Other revenues resulting in no net effect on earnings.  See "Other     operations and maintenance expenses."
- Other revenues     increased $10.1 million from the completed amortization of tax settlement     and irrigation lost revenue accruals.  From June 2005 to May 2006 IPC was     collecting and recording in general business revenues, with a corresponding     reduction to Other revenues, amounts related to a 2003 Idaho general rate     case tax settlement and amounts related to an irrigation load reduction     program.  Revenues for the rate case tax settlement were accrued from     September 2004 to May 2005.
- Transmission revenues     increased $4.1 million primarily due to an increase in rates that began in     June 2006.

 

2006 vs. 2005:  Other revenues decreased $4 million due mainly tothe following:

- In 2006, IPC recorded a $1     million provision for rate refund associated with a revised OATT filing     with the FERC requesting an increase in transmission rates.  This matter     is discussed further in "REGULATORY MATTERS;"
- In December 2006, IPC     recorded a $3 million revenue reduction related to estimated refundable transmission     revenues and a true up of transmission use-of-facility rates from 1998     through 2005.

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**Purchased power:**The following table presents IPC's purchased powerexpenses and volumes:

| ** **             | **2007** | ** ** | **2006** | ** ** | **2005** |
|------------------------|----------|------------|----------|------------|----------|
| Expense                | $        | 289,484    |          | $          | 283,440  |  | $ | 222,310 |
| MWh purchased          |          | 5,196      |          |            | 4,964    |  |  | 3,894 |
| Cost per MWh purchased | $        | 55.71      |          | $          | 57.10    |  | $ | 57.09 |
|                        |          |            |          |            |          |  |  |  |

2007 vs. 2006:  Purchased power expense grew two percent in 2007. Deteriorated system generation, due to poor hydrologic conditions, combinedwith the second year in a row of record high temperatures and demand duringJuly and August, led to increased purchases.  This increase in purchases waspartially offset by a lower overall cost per MWh in 2007.  During 2006, IPC madeforward purchases in conformance with its risk management policy in response toearly water year indications that suggested continued drought conditions. Hydrologic conditions for 2006 turned out to be more favorable than forecastedand actual market prices ended up being lower than the prices of the forward purchases. These higher priced forward purchases inflated the cost per MWh that IPCrealized for 2006.  IPC began utilizing financial hedge instruments in 2007 inaddition to physical forward power transactions for the purpose of mitigatingprice risk related to conforming to IPC's energy risk management policy,managing IPC's energy portfolio to meet customer load, and reacting to changesin market conditions to minimize net power supply costs.

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

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

|                       | **2007** | ** ** | **2006** | ** ** | **2005** |
|-----------------------|----------|------------|----------|------------|----------|
| Fuel expense          | $        | 134,322    |          | $          | 115,018  |  | $ | 103,164 |
| Thermal MWh generated |          | 7,367      |          |            | 7,021    |  |  | 7,315 |
| Cost per MWh          | $        | 18.23      |          | $          | 16.38    |  | $ | 14.10 |
|                       |          |            |          |            |          |  |  |  |

2007 vs. 2006:  Fuel expense increased $19.3 million in 2007, ascompared to 2006.  The increase is largely due to an 11 percent rise in averageprices accompanied by a five percent increase in MWh volume.  Coal fuel expensewas up $7.3 million compared to 2006.  The increase in coal prices was due tohigher market demand and higher rail transportation costs.  Generation from thecoal fired power plants was up three percent in 2007.  The increase in generationis attributed to fewer planned and unplanned outages at Valmy and Boardman thanthe previous year.  Additional generation from combustion turbine plantscontributed $12 million to the overall increase in fuel expense in 2007.  Thecombustion turbine plants were readily available for dispatch in 2007 to meetpeak loads and as market conditions warranted.  The Bennett Mountain plant wasnot available during the summer of 2006 due to a turbine failure.

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

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**PCA:**  PCA expense represents the effects of the Idaho PCA andOregon deferrals of net power supply costs, which are discussed in more detailbelow in "REGULATORY MATTERS - Deferred (Accrued) Net Power Supply Costs."  In2007, net power supply costs (fuel and purchased power less off-system sales) werehigher than the amounts reflected in the annual PCA forecast.  This resulted inthe deferral of costs which will be recovered in subsequent rate years.  As thedeferred costs are being recovered in rates, the deferred balances areamortized.  In 2006 and 2005 actual net power supply costs also exceeded theamounts anticipated in the annual PCA forecast.

The following table presentsthe components of PCA expense:

| ** **                                      | **2007**                    | ** ** | **2006**  | ** ** | **2005** |
|-------------------------------------------------|-----------------------------|------------|-----------|------------|----------|
| Current year net power  supply cost deferral    | $                           | (120,844)  |           | $          | (27,094) |  | $ | (30,786) |
| Amortization of prior year  authorized balances |                             | (287)      |           |            | (2,432)  |  |  | 27,791  |
|                                                 | Total power cost adjustment | $          | (121,131) |            | $        | (29,526) |  | $ | (2,995) |
|                                                 |                             |            |           |            |          |  |  |  |
|                                                 |                             |            |           |            |          |  |  |  |  |

**Other operations andmaintenance expenses:**2007 vs. 2006:  Other operations and maintenance expenses increased$22 million due mainly to the following:

- Regulatory commission     expenses increased $5.1 million primarily due to the September 2006     reversal of FERC fee accruals of $3.3 million and an increase in legal     fees of $1.6 million related to the OATT filing and the FERC     investigation;
- Transmission O&M     expenses increased $3.1 million due to higher third-party transmission     costs;
- Outside services increased     $3.1 million primarily due to an increase in intercompany allocations as     well as legal fees;
- Distribution O&M     expense increased $2.6 million due to an increase in overhead line     maintenance;
- Thermal O&M expenses     increased $2.5 million.  While much of this increase was due to a planned     increase in maintenance activity, the increase also occurred due to     unanticipated overhaul costs during the annual outages in the first half     of the year;
- Hydroelectric O&M     expenses increased $1.7 million due to the resumption of American Falls     bond principal amortization, additional FERC hydroelectric license     compliance costs, FERC required inspection costs, and general labor cost     increases; and 
- Expense for the fixed cost     adjustment mechanism, which began in 2007, was $2.6 million.

2006vs. 2005:  Other operations andmaintenance expenses increased $22 million due mainly to the following:

- An increase in labor-related     expenses of $8.5 million due to higher salaries and incentive-based     compensation, partially triggered by improved streamflow conditions and     the sale of ITI;
- An increase of  $6.3     million in hydroelectric and distribution O&M expenses attributable to     better generation conditions and the growth in general business customers;     
- An increase of $3.5 million     in thermal O&M expense resulting primarily from costs due to an extended     outage in 2006 at the Valmy plant; and
- A write off of $2 million     in the fourth quarter of 2006 for deferred development costs associated     with the attempted formation of Grid West.
- These increases were partially     offset by a $3 million reversal of accrued FERC fees.  IPC and several     other utilities contested whether certain federal agency charges could be     passed on to utilities through FERC fees.  A judgment in favor of IPC and     the other utilities was finalized in September 2006.    

**Demand-side management(DSM):**  Beginning in January 2007, anew IPUC accounting order became effective for the treatment of IPC's DSMexpenses.  DSM costs were recorded in Other operations and maintenance expensesand were offset by the same amount recorded in Other revenues, resulting in nonet effect on earnings.

IPC's DSM programs provideopportunities for all customer classes to balance their energy needs with best-practiceenergy usage to minimize consumption while realizing the benefits of reliableelectrical service.  IPC's 2006 IRP laid the groundwork for the planning andimplementation of future programs, including the addition of three new DSMprograms.  In addition to the DSM programs identified in the 2006 IRP, IPC hasalso continued to pursue other customer-focused DSM initiatives, includingconservation programs and educational opportunities.

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**Gain on the sale ofemission allowances:**  Gain on sale ofemission allowances in 2007 decreased $5.5 million as compared to 2006 due torecording the gain on the sale of 35,000 SO2 emission allowances in2007 as compared to 78,000 in 2006.  Gains in 2006 increased $7.1 million over2005, which had minimal emission allowance sale activity.

**Non-utility Operations**

**IFS:**IFS contributed $7 million, $10 million, and $11million to net income in 2007, 2006 and 2005, respectively, principally fromthe generation of federal income tax credits and accelerated tax depreciationbenefits related to its investments in affordable housing and historicrehabilitation developments.

IFS did not make any newinvestments during 2007 and generated tax credits of $15 million, $19 millionand $20 million during 2007, 2006 and 2005, respectively.  IFS expects to makefuture investments in line with the ongoing needs of IDACORP.

**Ida-West:**Ida-West recorded net income of $2 million, $3 millionand $2 million in 2007, 2006 and 2005, respectively.  Ida-West continues tomanage its independent power projects.

In 2003 a $2.6 million baddebt reserve was established on a note receivable from a partner in one of Ida-West'sjoint ventures.  No adjustments were made to this reserve in 2007 or 2006, butin 2005 the reserve was reduced by $0.7 million based on updated estimates ofcollectability.

**Energy Marketing:**IE recorded net income of $0 million in 2007 and 2006and $5 million in 2005.  In 2003, IE wound down its power marketing operations,closed its business locations and sold its forward book of electricity tradingcontracts to Sempra Energy Trading.  In 2007, all trading contracts expired. Currently, IE has no operations but has been working to settle outstandinglegal matters surrounding transactions in the California energy markets in 2000and 2001.  These matters are discussed in "LEGAL AND ENVIRONMENTAL ISSUES -Legal and Other Proceedings."

**Discontinued Operations:  **In the second quarter of 2006, IDACORP managementdesignated the operations of ITI and IDACOMM as assets held for sale.  Theoperations of these entities are presented as discontinued operations inIDACORP's financial statements.

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

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

Income from discontinuedoperations was not material in 2007.  A loss on disposal of IDACOMM of $3million was offset by an income tax benefit of $3 million.  Income fromdiscontinued operations was $7 million in 2006 and consisted of a loss fromoperations of $8 million, gain on disposal of ITI of $14 million and an incometax benefit of $1 million.  The loss from discontinued operations of $22million for 2005 consisted of a loss from operations of $27 million and anincome tax benefit of $5 million.  The 2005 results also included a $10 milliongoodwill impairment charge recorded at IDACOMM.

**Income TaxesFIN 48: **In June 2006, the FinancialAccounting Standards Board (FASB) issued FASB Interpretation No. 48, "*Accountingfor Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109*"(FIN 48), to create a single model to address accounting for uncertainty in taxpositions.  FIN 48 prescribes a minimum recognition threshold that a taxposition is required to meet before being recognized in a company's financialstatements and also provides guidance on derecognition, measurement,classification, interest and penalties, accounting in interim periods,disclosure, and transition.  IDACORP and IPC adopted FIN 48 on January 1, 2007,as required.  IPC recorded an increase of $15.1 million to opening retainedearnings for the cumulative effect of adopting FIN 48.

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**Statusof audit proceedings: **IPC isdisputing the Internal Revenue Service's(IRS) disallowance of IPC's use of the simplified service cost method (SSCM) ofuniform capitalization for tax years 2001-2003.  The dispute is under reviewwith the IRS Appeals Office.  In December 2007, the Appeals Office informedIDACORP that the IRS had completed their review of IPC's SSCM settlementcomputations.  After evaluating the IRS review findings, IPC adjusted itsmeasurement for the SSCM uncertain tax position which resulted in a $4.4million reduction of the accrued liability for this item.  IDACORP expects thatthe appeals process and the U.S. Congress Joint Committee on Taxation reviewprocess will be completed during 2008.

InNovember 2007 the IRS began its examination of IDACORP's and IPC's 2004-2006tax years.  IDACORP and IPC are unable to predict the outcome of thisexamination.

**LIQUIDITY AND CAPITALRESOURCES:**

**Operating Cash Flows**

IDACORP's and IPC's operatingcash flows for 2007 were both $81 million.  These amounts were a decrease of$89 million and $50 million, respectively, compared to 2006.  The following aresignificant items that affected operating cash flows in 2007:

- Power supply costs deferred     for future recovery under IPC's PCA mechanism and other changes in     regulatory assets and liabilities decreased operating cash flows by $128     million.
- Income tax payments decreased     $52 million and $83 million for IDACORP and IPC, respectively, due to the     timing of and decreases in taxable income.    

IDACORP's and IPC's operatingcash flows for 2006 were $170 million and $131 million, respectively.  Theseamounts were an increase of $8 million and a decrease of $35 million comparedto 2005.  The following are significant items that affected operating cashflows in 2006:

- Income tax payments     increased in 2006 due to the timing of and increases in taxable income,     including the timing effect of cash received in the fourth quarter of 2005     from the sale of approximately $70 million of excess SO 2      emission allowances.
- In 2006, IE collected $13     million of amounts receivable from the Cal ISO and CalPX, and collected     $10 million that it had deposited on margin with a counterparty in 2005.    

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

**Investing Cash Flows**IPC's construction expenditures were$287 million in 2007, $222 million in 2006 and $186 million in 2005.  IPC isexperiencing a cycle of heavy infrastructure investment needed to addresscontinued customer growth, peak demand growth, and aging plant and equipment.

Net proceeds from the salesof emission allowances provided investing cash of approximately $20 million,$11 million and $71 million in 2007, 2006 and 2005, respectively.  The changeswere primarily caused by changes in the number of allowances sold each year aswell as changes in market prices.  See further discussion in "REGULATORYMATTERS - Emission Allowances."

In November 2006, IDACORPmade a refundable deposit of $45 million with the IRS related to a disputedincome tax assessment.  In August 2007, IPC reimbursed IDACORP for therefundable tax deposit IDACORP made on IPC's behalf.  See Note 2 to IDACORP'sand IPC's Consolidated Financial Statements for more information about the incometax assessment.

**Financing Cash Flows****Debt issuances:**  On June 22, 2007, IPC issued $140 million of its6.30% First Mortgage Bonds, Secured Medium-Term Notes, Series F, due June 15,2037.  IPC used the net proceeds to pay down outstanding commercial paper,which had increased to $164 million in June 2007 because of increased capitalexpenditures.

On October 18, 2007, IPCissued $100 million of its 6.25% First Mortgage Bonds, Secured Medium-TermNotes, Series G, due October 15, 2037.  IPC used the net proceeds to retire $80million of 7.38% First Mortgage Bonds due December 1, 2007, and paid downoutstanding commercial paper.

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**Equity issuances:** On December 15, 2005, IDACORP entered into a SalesAgency Agreement with BNY Capital Markets, Inc. (BNYCMI).  Under the terms ofthe Sales Agency Agreement, IDACORP may offer and sell up to 2,500,000 sharesof its common stock, from time to time in at-the-market offerings throughBNYCMI, as IDACORP's agent for such offer and sale.  Under this program IDACORPreceived $28 million from the issuance of 881,337 shares in 2007 and $21million from the issuance of 536,518 shares in 2006.  The average prices of theshares issued in 2007 and 2006 were $32.32 and $39.24, respectively.  As ofDecember 31, 2007, there were 1,082,145 shares available to be issued throughthis program.

In April 2005, with the goalof adding additional common equity to its capital structure, IDACORP beganusing original issue common stock in its Dividend Reinvestment and StockPurchase Plan, rather than purchasing this stock on the open market.  Beginningin August 2005, IDACORP also began using original issue common stock for its401(k) plan.  Under these plans, IDACORP issued 250,020 shares in 2007 and244,756 shares in 2006, for proceeds of $8.4 million and $8.7 million,respectively.

IDACORP issued 10,070 sharesin 2007 and 406,623 shares in 2006 in connection with the exercise of stockoptions, for proceeds of $0.3 million and $12 million, respectively.

IDACORP made capitalcontributions of $51 million and $47 million to IPC in 2007 and 2006,respectively.

**Discontinued operations**Cash flows from discontinuedoperations are included with the cash flows from continuing operations inIDACORP's Consolidated Statements of Cash Flows.  The cash flows of IDACORP'sdiscontinued operations have reduced net cash provided by operating activitiesand increased net cash used in investing activities, except for the cashreceived from the sales of ITI and IDACOMM.  The absence of cash flows fromthese discontinued operations is expected to positively impact liquidity andcapital resources in future periods.

**Financing Programs**IDACORP's consolidated capital structure consisted of common equity of 47percent and debt of 53 percent at December 31, 2007.

**Shelf Registrations**: IDACORP currently has $629 million remaining on twoshelf registration statements that can be used for the issuance of unsecureddebt (including medium-term notes) and preferred or common stock.  IPCcurrently has in place one shelf registration statement that can be used forthe issuance of an aggregate principal amount of $350 million of first mortgagebonds (including medium-term notes) and unsecured debt.  See Note 4 to IDACORP'sand IPC's Consolidated Financial Statements for more information regarding long-termfinancing arrangements.

**Credit Facilities:**  The following table outlines available liquidity asof December 31, 2007 and 2006.

| ** ** | **IDACORP** | **IPC** |  
** **

**2007**

**2006**

**2007**

**2006**

 
** **

** **

 
Revolving credit facility

$

100,000 

$

150,000 

$

300,000 

$

200,000 

Commercial paper  outstanding

(49,860)

(76,800)

(136,585)

(52,200)

Identified for other use (a)

- 

- 

(24,245)

(24,245)

Net balance available

$

50,140 

$

73,200 

$

139,170 

$

123,555 

(a)  Port of Morrow and  American Falls bonds that holders may put to IPC.

 
On April 25, 2007, IDACORPentered into an Amended and Restated Credit Agreement (IDACORP Facility) withWachovia Bank, National Association, as administrative agent, swingline lenderand LC issuer, JPMorgan Chase Bank, N.A., as syndication agent, KeybankNational Association, Wells Fargo Bank, N.A. and Bank of America, N.A., asdocumentation agents, Wachovia Capital Markets, LLC and J.P. Morgan SecuritiesInc., as joint lead arrangers and joint book runners, and the other financialinstitutions party thereto, as lenders.  The IDACORP Facility amended andrestated a $150 million five-year facility that would have expired on March 31,2010.

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The Amended and Restated IDACORPFacility is a $100 million five-year credit agreement that terminates on April25, 2012.  The IDACORP Facility, which is used for general corporate purposesand commercial paper back-up, provides for the issuance of loans and standbyletters of credit not to exceed the aggregate principal amount of $100 million,including swingline loans in an aggregate principal amount at any timeoutstanding not to exceed $10 million.  IDACORP has the right to request anincrease in the aggregate principal amount of the IDACORP Facility to $150million and to request one-year extensions of the then existing terminationdate.  At December 31, 2007, no loans were outstanding on IDACORP's Facilityand $49.9 million of commercial paper was outstanding.  At February 27, 2008, $55million of commercial paper was outstanding.

On April 25, 2007, IPCentered into an Amended and Restated Credit Agreement (IPC Facility) withWachovia Bank, National Association, as administrative agent, swingline lenderand LC issuer, JPMorgan Chase Bank, N.A., as syndication agent, KeybankNational Association, US Bank National Association and Bank of America, N.A.,as documentation agents, Wachovia Capital Markets, LLC and J.P. MorganSecurities Inc., as joint lead arrangers and joint book runners, and the otherfinancial institutions party thereto, as lenders.  The IPC Facility amended andrestated a $200 million five-year facility that would have expired on March 31,2010.

The Amended and Restated IPC Facilityis a $300 million five-year credit agreement that terminates on April 25,2012.  The IPC Facility, which will be used for general corporate purposes andcommercial paper back-up, provides for the issuance of loans and standbyletters of credit not to exceed the aggregate principal amount of $300 million,including swingline loans in an aggregate principal amount at any timeoutstanding not to exceed $30 million.  IPC has the right to request anincrease in the aggregate principal amount of the IPC Facility to $450 millionand to request one-year extensions of the then existing termination date.  AtDecember 31, 2007, no loans were outstanding on IPC's Facility and $137 millionof commercial paper was outstanding.  At February 27, 2008, $164 million ofcommercial paper was outstanding.

Both the IDACORP Facility andthe IPC Facility have similar terms and conditions.  Under the terms of thefacilities IDACORP and IPC may borrow floating rate advances and Eurodollarrate advances.  The floating rate is equal to the higher of (i) the prime rateannounced by Wachovia Bank or its parent and (ii) the sum of the federal fundseffective rate for such day plus 1/2 percent per annum, plus, in each case, anapplicable margin.  The Eurodollar rate is based upon the British Bankers'Association interest settlement rate for deposits in U.S. dollars published onthe REUTERS 01 (Telerate Page 3750 successor) as adjusted by the applicablereserve requirement for Eurocurrency liabilities imposed under Regulation D ofthe Board of Governors of the Federal Reserve System, for periods of one, two,three or six months plus the applicable margin.  The margin is based on theapplicable company's rating for senior unsecured long-term debt securitieswithout third-party credit enhancement as provided by Moody's and S&P,based on the higher of the two ratings.  If the ratings are split betweenMoody's and S&P and the differential is two levels or more, theintermediate rating at the midpoint will apply.  If there is no midpoint, thehigher of the two intermediate ratings will apply.  The margin for the floatingrate advances is zero percent unless the applicable company's rating fallsbelow Baa3 from Moody's or BBB- from S&P, at which time it would equal 0.50percent.  The margin for Eurodollar rate advances ranges from 0.15 percent to0.575 percent depending upon the credit rating.  In addition to the margin, ifthe outstanding aggregate credit exposure exceeds 50 percent of the facilityamount, IDACORP or IPC, as applicable, would pay a utilization fee ranging from0.05 percent to 0.10 percent on outstanding loans depending on the creditrating.  At December 31, 2007, the applicable margin under the IDACORP Facilityand the IPC Facility was zero percent for floating rate advances and 0.28percent for IPC and 0.36 percent for IDACORP for Eurodollar rate advances.  Theutilization fee was 0.05 percent for both companies.  A facility fee, payablequarterly, is calculated on the average daily aggregate commitment of thelenders under the relevant credit facility and is also based on the applicablecompany's rating from Moody's or S&P as indicated above.  At December 31,2007, the facility fee under the IDACORP and IPC Facilities was 0.09 percentand 0.07 percent, respectively.

As a result of the S&Pratings downgrade discussed below, as of January 31, 2008, the credit facilityfees changed for IPC.  The margin for Eurodollar rate advances increased from0.28 percent to 0.36 percent, and the facility fee increased from 0.07 percentto 0.09 percent.  All of the other fees discussed above stayed the same forIPC.  IDACORP's fees remain unchanged.

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

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

The events of default underboth the IDACORP Facility and the IPC Facility include (i) nonpayment ofprincipal when due and nonpayment of reimbursement obligations under letters ofcredit within one business day after becoming due and nonpayment of interest orother fees within five days after becoming due, (ii) materially falserepresentations or warranties made on behalf of the applicable company or anyof its subsidiaries on the date as of which made, (iii) breach of covenants,subject in some instances to grace periods, (iv) voluntary and involuntarybankruptcy of the applicable company or any material subsidiary, (v) the non-consensualappointment of a receiver or similar official for the applicable company or anyof its material subsidiaries or any substantial portion (as defined in theapplicable facility) of its property, (vi) condemnation of all or anysubstantial portion of the property of the applicable company and itssubsidiaries, (vii) default in the payment of indebtedness in excess of $25million or a default by the applicable company or any of its subsidiaries underany agreement under which such debt was created or governed which will cause orpermit the acceleration of such debt or if any of such debt is declared to bedue and payable prior to its stated maturity, (viii) the applicable company orany of its subsidiaries not paying, or admitting in writing its inability topay, its debts as they become due, (ix) the applicable company or any of itssubsidiaries failing to pay certain judgments, (x) the acquisition by anyperson or two or more persons acting in concert of beneficial ownership (withinthe meaning of Rule 13d-3 of the Securities Exchange Act of 1934) of 20 percentor more of the outstanding shares of voting stock of the applicable company, (xi)the failure of IDACORP to own free and clear of all liens, all of theoutstanding shares of voting stock of IPC, (xii) unfunded liabilities of allsingle employer plans under the Employee Retirement Income Security Act of 1974exceeding $75 million and (xiii) the applicable company or any subsidiary beingsubject to any proceeding or investigation pertaining to the release of anytoxic or hazardous waste or substance into the environment or any violation ofany environmental law (as defined in the applicable facility) which couldreasonably be expected to have a material adverse effect (as defined in theapplicable facility).  A default or an acceleration of indebtedness of IDACORPor IPC in excess of $25 million, including indebtedness under the applicable facilitywill result in a cross default under the other Facility.

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

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

**Debt Covenants:**  The IDACORP Facility and the IPC Facility eachcontain a covenant requiring the company to maintain a leverage ratio ofconsolidated indebtedness to consolidated total capitalization of no more than65 percent as of the end of each fiscal quarter.  At December 31, 2007, theleverage ratio for both IDACORP and IPC was 53 percent.  At December 31, 2007,IDACORP was in compliance with all other covenants of the IDACORP Facility andIPC was in compliance with all other covenants of the IPC Facility.  Both theIDACORP Facility and the IPC Facility contain additional covenants including:

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(i)                  prohibitions against: investmentsand acquisitions by the applicable company or any subsidiary without theconsent of the required lenders subject to exclusions for investments in cashequivalents or securities of the applicable company; investments by theapplicable company and its subsidiaries in any business trust controlled,directly or indirectly, by the applicable company to the extent such businesstrust purchases securities of the applicable company; investments andacquisitions related to the energy business or other business of the applicablecompany and its subsidiaries not exceeding $750 million in the aggregate at anyone time outstanding (provided that investments in non-energy relatedbusinesses do not exceed $150 million); and investments by the applicablecompany or a subsidiary in connection with a permitted receivablessecuritization (as defined in the facility);

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

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

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

**Credit Ratings**On January 31, 2008, Standard & Poor'sRating Services lowered its corporate credit rating on IDACORP and IPC to 'BBB'from 'BBB+'.  The outlook for both companies changed to stable from negative. S&P stated that its decision reflected a gradual deterioration of cash flowcoverage as well as a failure to sufficiently address long-term ratemakingissues in the proposed Idaho general rate case settlement.  Specifically,S&P indicated that the proposed settlement fails to resolve issues such asthe use of a forecasted test year or the appropriate level of load growthadjustment credit.

Access to capital markets ata reasonable cost is determined in large part by credit quality.  Thesedowngrades are expected to increase the cost of new debt issuances andoutstanding variable rate debt issuances within the downgraded ratingscategories.  The following table outlines the current S&P, Moody's andFitch ratings of IDACORP's and IPC's securities:

** **

**S&P**

**Moody's**

**Fitch**

** **

**IPC**

**IDACORP**

**IPC**

**IDACORP**

**IPC**

**IDACORP**

Corporate Credit Rating

BBB

BBB

Baa 1

Baa 2

None

None

Senior Secured Debt

A-

None

A3

None

A-

None

Senior Unsecured Debt

BBB-

BBB-

Baa 1

Baa 2

BBB+

BBB

(prelim)

(prelim)

Short-Term Tax-Exempt Debt

BBB-/A-2

None

Baa 

None

None

None

1/VMIG-2

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 andthe ratings discussed below reflect the views of the rating agencies.  Anexplanation of the significance of these ratings may be obtained from eachrating agency.  Such ratings are not a recommendation to buy, sell or holdsecurities.  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 evaluated independently of any other rating.

**Pollution Control RevenueRefunding Bonds: **Two series of bondshave been issued for the benefit of IPC and are each supported by a financialguaranty insurance policy issued by Ambac Assurance Corporation (Ambac).  Thetwo series are the $116.3 million aggregate principal amount of PollutionControl Revenue Refunding Bonds (Idaho Power Company Project) Series 2006issued by Sweetwater County, Wyoming due 2026 (Sweetwater bonds), and the $49.8million aggregate principal amount of Pollution Control Revenue Refunding Bonds(Idaho Power Company Project) Series 2003 issued by Humboldt County, Nevada due2024 (Humboldt bonds).  The pollution control bonds currently bear interest atan auction interest rate reset every 35 days for the Humboldt bonds and everyseven days for Sweetwater bonds.

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The Humboldt bonds andSweetwater bonds are each rated "AAA" by S&P and "Aaa" by Moody's,respectively.  Fitch also rated each series of bonds.

On January 18, 2008, Fitchannounced that it had downgraded Ambac's insurer financial strength rating to"AA" from "AAA" and was keeping the rating on negative watch.  Fitch alsodowngraded the Humboldt bonds and the Sweetwater bonds to "AA" from "AAA." S&P's and Moody's ratings for the bonds remain unchanged.  However, Moody'splaced Ambac's insurance financial strength rating on review for possibledowngrade on January 16, 2008, and, as a result of this review, Moody's-ratedsecurities that are guaranteed by Ambac were also placed under review forpossible downgrade, except those with higher public underlying ratings. S&P also placed Ambac's financial strength, financial enhancement andissuer credit ratings on CreditWatch with negative implications on January 18,2008.  On February 25, 2008, S&P affirmed Ambac's "AAA" financial strengthand financial enhancement ratings, but retained the negative watch.

The downgrade of Ambac andthe pollution control bonds has resulted in higher interest rates on the pollutioncontrol bonds.  Such downgrades could also result in a "failed auction", wherethere are no purchasers for the bonds.  A "failed auction" would result in theexisting holders having to hold the pollution control bonds at the maximuminterest rate of 14 percent for the Sweetwater bonds and at a specified ratecapped at 12 percent for the Humboldt bonds.  If a "failed auction" occurs, newauctions will continue to be every 35 days for the Humboldt bonds and everyseven days for the Sweetwater bonds.  On February 27, 2008, auctions were heldfor both series of pollution control bonds.  The Sweetwater bonds had asuccessful auction establishing a new interest rate of 7.95 percent.  TheHumboldt bonds experienced a "failed auction" which resulted in a new interestrate of 5.464 percent (currently based on LIBOR multiplied by 1.75) and theHumboldt bonds continuing to be held by the current holders.  IPC may exercisecertain options available with respect to these bonds to lessen interest ratecosts and volatility going forward.  IPC may redeem the bonds at par plusaccrued and unpaid interest or convert them from the auction rate mode toanother interest rate mode.

**Capital RequirementsUtility Construction Program:** IPC's construction program and related expenditures are subject to on-goingreview and are revised to include changes in load growth, construction costs,location of generation sources, transmission capacity, adequacy of rate recoveryand environmental concerns.  Variations in the timing and amounts of capitalexpenditures will result from regulatory and environmental factors, loadgrowth, other resource acquisition needs and the timing of relicensing expenditures.

IPC is experiencing a cycleof heavy infrastructure investment needed to address continued customer growth,peak demand growth, and aging plant and equipment.  IPC's aging hydroelectricand thermal facilities require continuing upgrades and component replacement. In addition, costs related to relicensing hydroelectric facilities andcomplying with the new licenses are substantial.  Continuing load growth alsorequires that IPC add to its transmission system and distribution facilities toprovide new service and to maintain reliability.  As a result, IPC expects tospend approximately $900 million in construction expenditures from 2008 to 2010,which excludes any estimated expenditures for a Nominal 250-MW combined cyclecombustion turbine expected to be operational in mid-2012, the Gateway WestProject expected to be in service between 2012 and 2014, and the proposedHemingway-Boardman Line that could be in service as early as 2012.  IPC expects2008 capital expenditures to be between $280 and $300 million.

IPC and PacifiCorp arejointly exploring a project, called the Gateway West Project, to build two 500-kVlines between the Jim Bridger plant and Boise.  If built, it is expected thatthe majority of the project would be completed between 2012 and 2014, dependingon the timing of rights-of-way acquisition, siting and permitting, andconstruction sequencing.  IPC estimates that its share of project costs wouldbe between $800 million and $1.2 billion.  IPC is exploring the construction ofa 500-kV line referred to as the Hemingway-Boardman Line.  IPC and a number ofother utilities with proposed regional transmission projects in the Northwesthave begun to coordinate technical studies.  See further discussion in "REGULATORYMATTERS - Gateway West Project and Hemingway-Boardman Line."

**Other Capital Requirements**:  IDACORP's non-regulated capital expenditures areexpected to be $25 million in 2008 and an aggregate of $25 million for 2009-2010. These expenditures primarily relate to IFS's tax advantaged investments.

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Internal cash generationafter dividends is expected to provide less than the full amount of totalcapital requirements for 2008 through 2010.  IDACORP and IPC expect to continuefinancing capital requirements with internally generated funds and externallyfinanced capital.

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

**Payment Due by Period**

 
Total

**2008**

**2009-2010**

**2011-2012**

**Thereafter**

 
** **

**(millions of dollars)**

 
**IPC:**

 
Long-term  debt (a)

$

1,146

$

1

$

82

$

222

$

841

 
Future  interest payments (b)

1,173

64

124

104

881

 
Operating  leases (c)

19

3

7

3

6

 
Uncertain  tax positions (d)

6

2

4

-

-

 
Purchase  obligations:

 
Cogeneration and small  power 

 
production

1,993

76

199

207

1,511

 
Fuel  supply agreements

210

54

69

32

55

 
Purchased  power & transmission (e)

65

38

10

5

12

 
Other (f)

113

63

17

10

23

 
Total  purchase obligations

4,725

301

512

583

3,329

 
Pension  and postretirement plans (h)

64

6

14

15

29

 
Other  long-term liabilities - IPC 

6

4

2

-

-

 
Total  IPC

$

4,795

$

311

$

528

$

598

$

3,358

 
**Other:**

 
Long-term  debt (a)(g)

26

10

9

1

6

 
Future  interest payments (b)(g)

7

1

1

1

4

 
Operating  leases (g)

2

1

-

-

1

 
Total  IDACORP

$

4,830

$

323

$

538

$

600

$

3,369

 
(a)   

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

 
(b)

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

 
with  variable rates, interest is calculated for all future periods using the rates  in effect at December 31, 2007.

 
(c)   

Approximately  $8 million of the obligations included in 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)

In  addition to the amounts listed, approximately $17 million of federal income  tax is estimated to be due in 2008, but would be

 
fully  offset by the $45 million tax deposit IDACORP made in 2006.

 
(e)   

Approximately  $11 million of the obligations included in 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.

 
(f)   

Approximately  $40 million of the amounts in other purchase obligations are 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.

 
(g)   

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

 
(h)

Based  on current assumptions, no pension contributions will be required during the  next five years.  IPC cannot estimate 

 
contributions  beyond 2012 at this time.  Amounts include 10 years of postretirement and  non-qualified pension contributions.

** **

**Environmental RegulationCosts: **IPC anticipates approximately$20 million in annual operating costs for environmental facilities during2008.  Hydroelectric facility expenses and thermal plant expenses account for themajority of the costs at approximately $13 million and $7 million,respectively.  From 2009 through 2010, total environmental related operatingcosts are estimated to be approximately $54 million.  Expenses related to thehydroelectric facilities are expected to be $39 million and thermal plantexpenses are expected to total $15 million during this period.

These amounts do not includecosts related to possible changes in the environmental legislation andenforcement policies that may be enacted in response to issues such as globalwarming and mercury and other pollutant emissions from coal-fired generationplants.

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** **

**Off-Balance SheetArrangements**The federal Surface Mining Controland Reclamation Act of 1977 and similar state statutes establish operational,reclamation and closure standards that must be met during and upon completionof mining activities.  These obligations mandate that mine property be restoredconsistent with specific standards and the approved reclamation plan.  Themining operations at the Bridger Coal Company are subject to these reclamationand closure requirements.  IPC has agreed to guarantee the performance ofreclamation activities at Bridger Coal Company, of which Idaho Energy ResourcesCo., a subsidiary of IPC, owns a one-third interest.  This guarantee, which isrenewed each December, was $60 million at December 31, 2007.  Bridger Coal hasa reclamation trust fund set aside specifically for the purpose of paying thesereclamation costs and expects that the fund will be sufficient to cover allsuch costs.  Because of the existence of the fund, the estimated fair value ofthis guarantee is minimal.

**LEGAL AND ENVIRONMENTALISSUES:**

**Legal and OtherProceedings**

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

On September 8, 2004, thiscase was transferred and consolidated with other similar cases currently pendingbefore the Honorable Robert H. Whaley sitting by designation in the U.S.District Court for the Southern District of California.  The companies filed amotion to dismiss the complaint, which the court granted on February 11, 2005. Wah Chang appealed the dismissal to the U.S. Court of Appeals for the NinthCircuit on March 10, 2005.  On November 20, 2007, the Ninth Circuit affirmedthe dismissal.  On December 10, 2007, Wah Chang filed Petitions for Rehearingand Rehearing En Banc with the Ninth Circuit, which were denied on January 15,2008.  If Wah Chang decides to seek Supreme Court review, time for filing itspetition for certiorari will expire on April 14, 2008.  The companies cannotpredict whether Wah Chang will seek certiorari or whether the Supreme Courtwill grant it.  The companies intend to vigorously defend their position inthis proceeding and believe this matter will not have a material adverse effecton their consolidated financial positions, results of operations, or cashflows.

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

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**(1) California Refund:**  This proceeding originated with an effort by the stateof California to obtain refunds for a portion of the spot market sales fromsellers of electricity into California from October 2, 2000, through June 20,2001.  California is claiming that the sales prices were not just andreasonable and were not in compliance with the FPA.  The FERC issued an orderon refund liability on March 26, 2003 on which multiple parties, including IE,sought rehearing.  On October 16, 2003, the FERC denied the requests forrehearing and required the California Independent System Operator (Cal ISO) tomake a compliance filing regarding refund amounts within five months, which hasbeen delayed on a number of occasions and has not yet been filed with theFERC.  On May 12, 2004, the FERC issued an order clarifying its earlier refundorders.  The FERC denied requests for 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 California refunds. As additional FERC orders have been issued, further petitions for review havebeen filed, including by IE, and have been consolidated with the appealsalready pending before the Ninth Circuit.  On September 21, 2004, the NinthCircuit convened the first of its case management proceedings, a procedurereserved to help organize complex cases, staying action on all of theconsolidated cases.  On October 22, 2004, the Ninth Circuit severed severalissues related to the FERC's refund jurisdiction, established a schedule forbriefing and held oral argument on April 12 and 13, 2005.  On September 6,2005, the Ninth Circuit issued a decision in one of the severed casesconcluding that the FERC lacked refund authority over wholesale electricalenergy sales made by governmental entities and non-public utilities.  On August2, 2006, the Ninth Circuit issued its decision on a second severed case rulingthat all transactions that occurred within or as a result of the CalPX and theCal ISO were the proper subject of the refund proceeding; refused to expand theproceedings into the bilateral market, approved the refund effective date asOctober 2, 2000 but required FERC to reconsider based upon claims that somemarket participants had violated governing tariff obligations (the CaliforniaParties are seeking a refund effective date of May 1, 2000); and effectivelyexpanded the scope of the refund proceeding to transactions within the CalPXand Cal ISO markets outside the 24-hour spot market and energy exchangetransactions.  On August 8, 2005 the FERC issued an order establishing aframework for those sellers wanting to make a cost filing to demonstrate thatthe generally applicable FERC refund methodology interfered with the recoveryof costs.  IE and IPC along with others made a cost filing on September 14, 2005. During the next two months, the California entities on the one hand and IE andIPC on the other submitted filings that argued the merits of the cost filings. On March 27, 2006, the FERC rejected the IE/IPC cost filing and on April 26,2006, IE and IPC sought rehearing of the rejection.  That request remainspending before the FERC.  IE and IPC are unable to predict how or when the FERCmight rule on the request for rehearing.

Beforethe rejection of the cost filing, on February 17, 2006, IE and IPC jointlyfiled with the California Parties (Pacific Gas & Electric Company, SanDiego Gas & Electric Company, Southern California Edison Company, theCalifornia Public Utilities Commission, the California Electricity OversightBoard, the California Department of Water Resources and the California AttorneyGeneral) an Offer of Settlement at the FERC settlingmatters encompassed by the California Refund proceeding including IE's and IPC'scost filing and refund obligation.  A number of other parties, representingsubstantially less than the majority of potential refund claims, chose to optout of the settlement.

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

TheFERC approved the February 17, 2006 Offer of Settlement on May 22, 2006.  Underthe terms of the settlement, IE and IPC assigned $24.25 million of the rightsto accounts receivable from the Cal ISO and CalPX to the California Parties topay into an escrow account for refunds to settling parties.  Amounts from thatescrow not used for settling parties and $1.5 million of the remaining IE andIPC receivables that are to be retained by the CalPX are available to fund, atleast partially, payment of the claims of any non-settling parties if they prevailin the remaining litigation of this matter.  Any excess funds remaining at theend of the case are to be returned to IPC and IE.  Approximately $10.25 millionof the remaining IE and IPC receivables was paid to IE and IPC under thesettlement.

On June 21, 2006, the Port ofSeattle, Washington filed a request for rehearing of the FERC order approvingthe settlement.  On July 10, 2006, IPC and IE and the California Parties fileda response to Port of Seattle's request for rehearing.  On October 5, 2006, theFERC issued an order denying the Port of Seattle's request for rehearing.  OnOctober 24, 2006, the Port of Seattle petitioned the U.S. Court of Appeals forthe Ninth Circuit for review of the FERC orders approving the settlement.  TheNinth Circuit consolidated that review petition with the large number of reviewpetitions already consolidated before it.  On October 25, 2007, the NinthCircuit severed the appeal of the FERC's orders approving the settlement withthe California Parties (along with appeals of two other similar cases) from theremainder of the consolidated cases.  The Ninth Circuit established a briefingschedule for the three cases which currently concludes in late June 2008.  Adate for argument has not yet been scheduled.  IPC and IE are unable to predictwhen or how the Ninth Circuit might rule on Port of Seattle's petition forreview.

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A provision of the CalPXparticipation agreement referred to as the chargeback provision was triggeredwhen a participant defaulted on a payment to the CalPX requiring other marketparticipants to pay their allocated share of the default amount to the CalPX. This provision was triggered initially by the Southern California Edison andPacific Gas and Electric Company defaults.  The FERC ordered the CalPX to holdthe chargeback funds until the conclusion of the California Refund proceeding. Based upon the settlement between the California Parties and IE and IPCdiscussed above, the FERC directed the return of IE's chargeback amounts,totaling $2.27 million.  On June 1, 2006, IE received approximately $2.5million from the CalPX representing the return of $2.27 million in chargebackfunds plus interest.

On December 31, 2005, 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.  In the fourth quarter of 2005, IE reduced by $9.5 million to $32 millionits reserve against these receivables.  This reserve was calculated taking intoaccount the uncertainty of collection, given the California energy situation. Following payment of the $10.25 million to IE and IPC in June 2006, IE furtherreduced the reserve by $24.9 million to $7.1 million.  This reserve wascalculated taking into account several unresolved issues in the Californiarefund proceeding.  Based on the reserve recorded as of December 31, 2007,IDACORP believes that the future collectability of these receivables or anypotential refunds ordered by the FERC would not have a material adverse effecton its consolidated financial position, results of operations or cash flows.

**(2)****Pacific Northwest Refund:**  These proceedings involvedarguments that the spot market in the Pacific Northwest was affected by thedysfunction in the California market, warranting refunds.  The FERC rejectedthis claim on June 25, 2003, and denied rehearing on November 11, 2003 andFebruary 9, 2004.  The FERC orders were appealed to the Ninth Circuit.  Oralargument was held on January 8, 2007.  On August 24, 2007, the court filed anopinion in the appeal, remanding to the FERC the orders that declined torequire refunds.  The court's opinion instructed the FERC to consider whetherevidence of market manipulation submitted by the petitioners for the periodJanuary 1, 2000 to June 21, 2001 would have altered the agency's conclusionsabout refunds and directed the FERC to include sales to the CaliforniaDepartment of Water Resources in the proceeding.  On September 18, 2007, thecourt extended until November 16, 2007 the time for filing petitions forrehearing to allow the parties' time to assess settlement prospects anddirected Senior Judge Edward Leavey of the Ninth Circuit to initiate mediationefforts.  The Ninth Circuit did not renew the extension of time and a number ofparties have sought rehearing of the Ninth Circuit's decision.  IE and IPC areunable to predict when the Ninth Circuit will rule on the requests forrehearing or the outcome of these matters.  The settlement in the CaliforniaRefund proceeding resolves all claims the California Parties have against IEand IPC in the Pacific Northwest proceeding.

**(3)****Market Manipulation:**  These proceedingsinclude two FERC show cause orders which resulted from a ruling of the NinthCircuit that the FERC permit the California parties in the California refundproceeding to submit materials to the FERC demonstrating market manipulation byvarious sellers of electricity into California.  On June 25, 2003, the FERCordered a large number of parties including IPC to show cause why certaintrading practices did not constitute gaming ("gaming") or anomalous marketbehavior ("partnership") in violation of the 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 January23, 2004.  Although the orders establishing the scope of the show causeproceedings are presently the subject of review petitions in the Ninth Circuit,the order dismissing IPC from the "partnership" proceedings was not the subjectof rehearing requests.  Originally, eight parties requested rehearing of theFERC's March 3, 2004 order approving the "gaming" settlement.  The settlementbetween the California Parties and IE and IPC discussed above in the Californiarefund proceeding approved by the FERC on May 22, 2006, results in theCalifornia Parties and other settling parties withdrawing their requests forrehearing of the settlement with the FERC Staff regarding allegations of "gaming." On October 11, 2006, the FERC issued an order denying rehearing of its earlierapproval of the "gaming" allegations, thereby effectively terminating the FERCinvestigations as to IPC and IE regarding bidding behavior, physicalwithholding of power and "gaming" without finding of wrongdoing.  On October24, 2006, the Port of Seattle appealed the FERC order to the U.S. Court ofAppeals for the Ninth Circuit.  That appeal was consolidated with the othercases currently before the Ninth Circuit respecting Western energy matters.  IEand IPC are unable to predict when or how the Ninth Circuit will rule on thepetitions for review.

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In addition to the two showcause orders, on June 25, 2003, the FERC also issued an order instituting aninvestigation of anomalous bidding behavior and practices in the westernwholesale markets for the time period May 1, 2000 through October 1, 2000 toreview evidence of economic withholding of generation.  IPC, along with over 60other market participants, responded to the FERC data requests and the FERCterminated its investigations as to IPC on May 12, 2004.  Numerous parties haveappealed the FERC's termination of this investigation as to IPC and over 30other market participants.  IE and IPC are unable to predict when the NinthCircuit will rule on the requests for rehearing or the outcome of thesematters.

**Sierra Club Lawsuit-Bridger: **In February 2007, the Sierra Club andthe Wyoming Outdoor Council filed a complaint against PacifiCorp in federaldistrict court in Cheyenne, Wyoming alleging violations of air quality opacitystandards at the Jim Bridger coal fired plant (Plant) in Sweetwater County,Wyoming.  Opacity is an indication of the amount of light obscured in the fluegas of a power plant.  A formal answer to the complaint was filed by PacifiCorpon April 2, 2007, in which PacifiCorp denied almost all of the allegations andasserted a number of affirmative defenses.  IPC is not a party to thisproceeding but has a one-third ownership interest in the Plant.  PacifiCorpowns a two-thirds interest and is the operator of the Plant.  The complaintalleges thousands of opacity permit limit violations by PacifiCorp and seeks adeclaration that PacifiCorp has violated opacity limits, a permanent injunctionordering PacifiCorp to comply with such limits, civil penalties of up to $32,500per day per violation, and reimbursement of the plaintiff's costs oflitigation, including reasonable attorney fees.

The U.S. District Court hasset this matter for trial commencing in April 2008.  Discovery in the matterwas completed on October 15, 2007.  Also in October 2007, the plaintiffs anddefendant filed cross-motions for summary judgment on the alleged opacitypermit violations.  The Court has not yet ruled on those motions.  IPCcontinues to monitor the status of this matter but is unable to predict itsoutcome or what effect this matter may have on its consolidated financialposition, results of operations or cash flows.

**Sierra Club Notice ofIntent to File Suit - Boardman: **OnJanuary 15, 2008, the Oregon Chapter of the Sierra Club, the NorthwestEnvironmental Defense Center, Friends of the Columbia Gorge, ColumbiaRiverkeeper, and Hells Canyon Preservation Council (collectively, Sierra Club)provided a 60-day notice to Portland General Electric Company (PGE) of intentto file suit.  Sierra Club alleges violations of opacity standards at theBoardman coal-fired power plant located in Morrow County, Oregon of which IPCowns ten percent.  PGE owns 65 percent and is the operator of the plant.  Opacityis an indication of the amount of light obscured in the flue gas of a powerplant.  Sierra further alleges violations of the Clean Air Act, related federalregulations and the Oregon State Implementation Plan relating to PGE'sconstruction and operation of the plant.  Sierra Club has not yet commencedlitigation.  Sierra Club alleges thousands of opacity permit limit violationsby PGE from and before 2003, and claims that it will seek a declaration thatPGE has violated opacity limits, a permanent injunction ordering PGE to complywith such limits, and civil penalties of up to $32,500 per day per violation.  IPCintends to monitor the status of this matter but is unable to predict itsoutcome or what effect this matter may have on its consolidated financialposition, results of operations or cash flows.

**Other Legal Proceedings:**  IDACORP and IPC are involved in lawsuits and legalproceedings in addition to those discussed above and in Note 7 to IDACORP's andIPC's Consolidated Financial Statements.  Resolution of any of these matterswill take time, and the companies cannot predict the outcome of any of theseproceedings.  The companies believe that their reserves are adequate for thesematters.

**Environmental Issues**

**Idaho Water ManagementIssues: **From 2000 through 2005, andthroughout 2007, below normal precipitation and stream flows have exacerbated adeveloping water shortage in Idaho, manifested by a number of water issuesincluding declining Snake River base flows and declining levels in the EasternSnake Plain Aquifer (ESPA), a large underground aquifer that has been estimatedto hold between 200 - 300 maf of water.  These issues are of interest to IPCbecause of their potential impacts on generation at IPC's hydroelectricprojects.

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As a result of declines inriver flows, in 2003 several surface water users filed delivery calls with theIdaho Department of Water Resources (IDWR), demanding that it manage groundwater withdrawals pursuant to the prior appropriation doctrine of "first intime is first in right" and curtail junior ground water rights that aredepleting the aquifer and affecting flows to senior surface water rights. These delivery calls have resulted in several administrative actions before theIDWR to enforce senior water rights as well as judicial actions before thestate court challenging the constitutionality of state regulations used by the IDWRto conjunctively administer ground and surface water rights.  Because IPC holdswater rights that are dependent on the Snake River, spring flows and theoverall condition of the ESPA, IPC continues to participate in these actions,as necessary, to protect its water rights.

IPC, together with other interested water users and state interests, alsocontinues to explore and encourage the development of a long-term managementplan that will protect the ESPA and the Snake River from further depletion.  OnFebruary 14, 2007, the Idaho Water Resource Board (IWRB) presented theframework for an ESPA management plan to the Idaho Legislature recommending thedevelopment of a Comprehensive Aquifer Management Plan (CAMP).  The proposedgoal of the CAMP is to sustain the economic viability and social andenvironmental health of the ESPA by adaptively managing a balance between wateruse and supplies.  The IWRB estimates that the development of the CAMP willtake 16 months.  Through House Concurrent Resolution 28 and House Bill 320, the2007 Idaho Legislature appropriated funds and directed the IWRB to proceed withthe development of the CAMP.  Pursuant to the IWRB recommendation in the CAMPFramework, an advisory committee has been established to make recommendationsto the IWRB on the development of the CAMP.  IPC sits on the CAMP advisorycommittee and will be working with the IWRB on the development of the CAMP.

IPC is also engaged in theSnake River Basin Adjudication (SRBA), a general stream adjudication, commencedin 1987, to define the nature and extent of water rights in the Snake Riverbasin in Idaho, including the water rights of IPC.  The initiation of the SRBAresulted from the Swan Falls Agreement, an agreement entered into by IPC andthe Governor and Attorney General of Idaho in October 1984 to resolvelitigation relating to IPC's water rights at its Swan Falls project.  IPC hasfiled claims to its water rights for hydropower and other uses in the SRBA. Other water users in the basin have also filed claims to water rights.  Partiesto the SRBA may file objections to water right claims that adversely affect orinjure their claimed water rights and the court then adjudicates the claims andobjections and enters a decree defining a party's water right.  IPC has filedclaims for all of its hydropower water rights in the SRBA, is activelyprotecting those water rights, and is objecting to claims that may potentiallyinjure or affect those water rights.  One such claim involves a notice of claimof ownership filed on December 22, 2006, by the state of Idaho, for a portionof the water rights held by IPC that are subject to the Swan Falls Agreement.

On May 10, 2007, in order toprotect its claims and the availability of water for power purposes at itsfacilities, and in response to the claim of ownership filed by the State, IPCfiled a complaint and petition for declaratory and injunctive relief regardingthe status and nature of IPC's water rights and the respective rights andresponsibilities of the parties under the Swan Falls Agreement.  The complaintwas filed in the Idaho District Court for the Fifth Judicial District, thecourt with jurisdiction over the SRBA, against the state of Idaho, theGovernor, the Attorney General, the IDWR and the Director of the IDWR.

In conjunction with thefiling of the complaint and petition, IPC filed motions with the court to stayall pending proceedings involving the water rights of IPC and to consolidatethose proceedings into a single action where all issues relating to the SwanFalls Agreement can be determined.

IPC alleged in the complaint,among other things, that contrary to the parties' belief at the time the SwanFalls Agreement was entered into in 1984, the Snake River basin above SwanFalls was over-appropriated and as a consequence there was not in 1984, andthere currently is not, water available for new upstream uses over and abovethe minimum flows established by the Swan Falls Agreement; that because of thismutual mistake of fact relating to the over-appropriation of the basin, theSwan Falls Agreement should be reformed; that the State's December 22, 2006,claim of ownership to IPC's water rights should be denied; and that the SwanFalls Agreement did not subordinate IPC's water rights to aquifer recharge.

On May 30, 2007, the Statefiled motions to dismiss IPC's complaint and petition.  These motions werebriefed and, together with IPC's motions to stay and consolidate theproceedings, were argued before the court on June 25, 2007.

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OnJuly 23, 2007, the court issued an Order granting in part and denying in partthe State's motion to dismiss, consolidating the issues into a consolidatedsubcase before the court, providing for discovery during the objection periodand setting a scheduling conference for December 18, 2007.  In its Order, thecourt denied the majority of the State's motion to dismiss, refusing to dismissthe complaint and finding that the court has jurisdiction to hear and determinevirtually all the issues raised by IPC's complaint that relate to IPC's waterrights and the effect of the Swan Falls Agreement upon those water rights. This includes the issues of ownership, whether IPC's water rights aresubordinated to recharge and how those water rights are to be administeredrelative to other water rights on the same or connected resources.  The courtdid find that by virtue of a state statute the IDWR, and its director, couldnot be parties to the SRBA and therefore stayed IPC's claims against the IDWRand its director pending resolution of the issues to be litigated in the SRBA,or until further order of the court.

Consistentwith IPC's motion to consolidate and stay proceedings, the court consolidatedall of the issues associated with IPC's water rights before the court andstayed that proceeding to allow other parties that may be affected by thelitigation to file responses or intervene in the consolidated proceedings byDecember 5, 2007.  On December 18, 2007, the court held a status and schedulingconference in the consolidated proceedings.  Subsequently, the court issued ascheduling order on December 20, 2007, with a trial scheduled to begin onFebruary 2, 2009.  IPC is unable to predict the outcome of the consolidatedproceedings.

IPC has also recently filed twoactions in federal court against the United States Bureau of Reclamation toenforce a contract right for delivery of water to its hydropower projects onthe Snake River.  In 1923, IPC and the United States entered into a contractthat facilitated the development of the American Falls Reservoir by the U.S. onthe Snake River in southeast Idaho.  This 1923 contract entitles IPC to 45,000acre-feet of primary storage capacity in the reservoir and 255,000 acre-feet ofsecondary storage that was to be available to IPC between October 1 of any yearand June 10 of the following year as necessary to maintain specified flows atIPC's Twin Falls power plant below Milner Dam.  IPC believes that the U.S. hasfailed to deliver this secondary storage, at the specified flows, since 2001. As a result, on October 15, 2007, IPC filed an action in the U.S. DistrictCourt of Federal Claims in Washington, D.C. to recover damages from the U.S.for the lost generation resulting from the reduced flows.  On October 15, 2007,IPC filed a second action in the United States District Court for the Districtof Idaho in Boise, Idaho, to compel the U.S. to manage American Falls Reservoirand the Snake River federal reservoir system to ensure that IPC's contractright to secondary storage is fulfilled in the future.  The U.S. Bureau ofReclamation filed an answer in the case filed with the U.S. District Court forthe District of Idaho on February 15, 2008.  No answer has been filed in thecase filed in the U.S. Court of Claims.  IPC is unable to predict the outcomeof this litigation.

**Air Quality Issues**IPC owns two natural gas combustionturbine power plants and co-owns three coal-fired power plants that are subjectto air quality regulation.  The natural gas-fired plants, Danskin and BennettMountain, are located in Idaho.  The coal-fired plants are:  Jim Bridger (33percent interest) located in Wyoming; Boardman (ten percent interest) locatedin Oregon; and North Valmy (50 percent interest) located in Nevada.  The CleanAir Act establishes controls on the emissions from stationary sources likethose owned by IPC.  The Environmental Protection Agency (EPA) adopts many ofthe standards and regulations under the Clean Air Act, while states have theprimary responsibility for implementation and administration of these air qualityprograms.  IPC continues to actively monitor, evaluate and work on air qualityissues pertaining to the Clean Air Mercury Rule (CAMR), possible legislativeamendment of the Clean Air Act, emerging greenhouse gas programs at thefederal, regional and state levels, New Source Review permitting, NationalAmbient Air Quality Standards (NAAQS), and Regional Haze - Best AvailableRetrofit Technology (RH BART).  Low nitrogen oxide (NOx) burnertechnology and mercury continuous emission monitoring systems (mercury CEMS) installationsare progressing at all three coal-fired power plants.

**National Ambient AirQuality Standards**: EPA-adopted NAAQSfor fine particulate matter became effective in December 2006.  This newstandard has been challenged by a number of groups in the U.S. Court of Appealsfor the District of Columbia Circuit.  All of the counties in Idaho, Nevada,Oregon, and Wyoming where IPC's power plants operate are currently designatedas meeting attainment with federal air quality standards, including the newparticulate matter standard.  Nevertheless, under the new fine particulatestandards, three years of data are being collected to determine the attainmentstatus of all U.S. counties.  In July 2007, the EPAproposed to revise the NAAQS for 8-hour ozone.  For the primary (health-based)standard, EPA is proposing that the standard be lowered from 0.08 parts permillion (ppm) to between 0.070 and 0.075 ppm.  The EPA received public commentfor 90 days and held 4 public hearings.  The impact of these newstandards will not be known until these data are collected, analyzed, andreleased to the public and the associated regulatory programs are promulgatedand implemented.

**Clean Air Mercury Rule:** The CAMR, issued by the EPA on March 15, 2005, limitsmercury emissions from new and existing coal-fired power plants and creates amarket-based cap-and-trade program that will permanently cap utility mercuryemissions.  On February 8, 2008, the U.S. Court of Appeals for the D.C. Circuitvacated the CAMR and remanded it back to the EPA for reconsideration consistentwith the court's interpretation of the Clean Air Act.  The EPA could appealthis decision but, in the absence of an appeal, the impact of this decisionwill not be known until such time as the EPA develops a new report in responseto the court's decision.

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In response to the CAMR, theIdaho Department of Environmental Quality (IDEQ) proposed two new rules to theIdaho Environmental Quality Commission:  a rule to opt out of the federalmercury cap-and-trade program, and a rule to prohibit the construction andoperation of a coal-fired power plant in Idaho.  In April 2006, the governor ofIdaho signed House Bill 791, which placed a two-year moratorium on applying foror issuance of permits, licenses or construction of certain coal-fired powerplants in Idaho.  The moratorium expires on April 7, 2008.  During the 2007Idaho state legislative session, the state did not reject the proposal to optout of the cap-and-trade program, therefore accepting the opt-out rule.  InJanuary 2008, Senate Bill 1314 was introduced which, if enacted, would extendthe current moratorium for an additional two years.  IPC has no current plansimpacted by the moratorium or opting out of the CAMR cap-and-trade program.

On October 10, 2006, theWyoming Environmental Quality Council (WEQC) approved the Wyoming Department ofEnvironmental Quality's (WDEQ) recommended Wyoming regulation to implementCAMR.  This rule will allocate mercury allowances to each plant based on heat-inputand hold back ten percent of the allocated allowances for new sources.  Thisrule will also allow plants to participate in the national cap-and-tradeprogram.  Mercury CEMS are planned to be installed at the Jim Bridger plant in2008 at an estimated cost of $0.2 million (IPC share).  Until the mercury CEMSare installed and operational, the amount of mercury emissions is notdefinitively known.  It is not possible at this time to determine the effect ofthe allowance allocation rule on future operations and costs at the plant.

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

The Nevada Department ofEnvironmental Protection has adopted a state CAMR that will provide mercuryallowances to each plant based on actual emissions until 2018, at which timethe allowance allocations will be reduced to meet the federal cap.  To meet thereduced allocations in the year 2018, mercury controls are expected to beinstalled.  Mercury CEMS are planned to be installed at the North Valmy plantin 2008 at an estimated cost of $0.1 million (IPC share).

Atthis time, it is uncertain how state mercury rules or requirements might beimpacted by the vacated CAMR and any resulting impacts to IPC.

**Regional Haze - BestAvailable Retrofit Technology:** Inaccordance with federal regional haze rules, the WDEQ and ODEQ are conductingan assessment of emission sources pursuant to a RH BART process.  Coal-firedutility boilers are subject to RH BART if they were built between 1962 and 1977and affect any Class I areas.  This includes all four units at the Jim Bridgerand Boardman plants.  The two units at the North Valmy plant were constructedafter 1977 and are not subject to the federal regional haze rule.

PacifiCorp submitted the RHBART application for the Jim Bridger plant in January 2007.  The WDEQ is stillevaluating the application and will go out for public comment.  If there are noappeals to the application, the WDEQ will prepare a State Implementation Planto present to the WEQC for approval and submittal to the EPA.  The plant isalready in the process of installing low NOx burners and scrubberupgrades that are proposed in the application.  Over the next four years, theseupgrade expenditures are currently estimated at $27.7 million (IPC share), witha total upgrade expenditures estimated at $34.3 million (IPC share).

PGE completed the RH BARTanalysis for the Boardman plant and submitted it to the ODEQ on November 15,2007.  This analysis includes proposed emission control upgrades for theBoardman plant to comply with RH BART requirements.  Capital upgrade costsrequired to meet RH BART standards could vary significantly depending on thetechnology utilized.  Because of the combined benefit of emission equipmentthat reduces multiple pollutants simultaneously, upgrade plans underconsideration will also meet CAMR standards.  Upgrade cost estimates to meetboth standards range from $30 million to $62 million (IPC share).  Depending onwhat pollution control equipment is required to meet the standards, an extendedmaintenance outage may be necessary.  No commitments are in place at this timeand the cost estimates are preliminary and subject to change.  More detailedinformation will be available after completion of the analysis for the Boardmanplant and approval of the RH BART proposals by state and federal environmentalregulators.

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**GreenhouseGases:**IPC continues to monitorand evaluate the possible adoption of national, regional, or state greenhousegas (GHG) regulations and judicial decisions that would affect electricutilities.  At the national level, numerous GHG bills have been introduced inthe U.S. Senate and House of Representatives during 2006 and 2007.  Debatecontinues in Congress on the direction and scope of U.S. policy on regulationof GHGs.  IPC anticipates new developments to occur in 2008.

The states of Arizona,California, New Mexico, Oregon, Utah and Washington, along with the provincesof British Columbia and Manitoba, Canada, have formed the Western RegionalClimate Action Initiative (WCI).  On August 22, 2007, the WCI partners releasedtheir regional goal to collectively reduce GHGs 15 percent below 2005 levels by2020.  The WCI partners have agreed to design a regional market-based multi-sectormechanism, such as a load-based or deliverer-based cap and trade program, tohelp achieve the goal.  The states of Idaho, Nevada and Wyoming have not joinedthe WCI.  It is possible that these and other states in which IPC operates orsells electricity into could join the WCI in the future.

California's governor signed an executive order in 2005 to reduceGHGs in that state to designated historical levels.  On September 27, 2006,California's governor signed into law the Global Warming Solutions Act of 2006,which established GHG reduction goals and a framework for achieving thesegoals.  On January 25, 2007, California enacted a GHG emission performance standardapplicable to all electricity generated within the state or delivered fromoutside the state.  Oregon passed the Global Warming Integration Act in June2007, which, among other things, established the Oregon Global WarmingCommission and state-wide GHG emission reduction goals.  IPC will continue to monitor developments with respectto the implementation of this legislation; however, until the Oregon GlobalWarming Commission makes its recommendations and the associated regulatoryprograms are promulgated and implemented, it is not possible to determine theeffect of this legislation on IPC's operations, particularly the Boardmanfacility.  The Washington legislature passed a billin April 2007 that sets climate pollution reduction and clean energy goals. Emission performance standards affecting electric utility contracts and powerplant projects are included.  Other regional and state GHG initiatives appearlikely, although the states of Idaho, Nevada and Wyoming have notadopted GHG legislation.  National, regional or stateGHG requirements, if enacted and applicable, could result in significant coststo IPC to comply with restrictions on carbon dioxide or other GHG emissions.

Information about IDACORP's carbon dioxide emissions is includedin the report *Benchmarking Air Emissions of the 100 Largest Electric Power**Producers in the United States - 2004*.  This report was released by theCeres Investor Coalition, the Natural Resources Defense Council and the PublicService Enterprise Group Inc. in April 2006.  The report lists IDACORP's 2004carbon dioxide emissions at 1,222.0 lbs/MWh, as compared to the reportedaverage for the 100 largest power producers of 1,341.8 lbs/MWh.  IPC's carbondioxide emissions on a lbs/MWh basis fluctuate with the amount of hydroelectricgeneration.  Even during a low water year like 2004, IPC's emissions fromelectricity generation were below the average of the 100 largest powerproducers.  During 2007, IPC's carbon dioxide emissions were approximately 1,153lbs/MWh.

As part of IPC's resource planning protocol, the IRP processconsiders potential GHG emissions regulation and other environmental factorswhen evaluating potential portfolios.  The2006 IRP included a risk analysis of the costs associated with the regulationof carbon dioxide emissions by analyzing low, expected and high cases of $0,$14 and $50 respectively, per ton of carbon dioxide emitted.  Environmental impacts have been and will continue to beintegral components of IPC's resource decisions.

Due to escalatingconstruction costs, potential permitting issues, and continued uncertaintysurrounding future GHG laws and regulations, IPC has determined that coal-firedgeneration is not the best technology to meet its resource needs in 2013.  IPChas shifted its focus to the development of a combined-cycle natural gas-firedresource located closer to its load center in southern Idaho.  Also, IPC added101 MW of contracted wind generation in December 2007 bringing IPC's total to121 MW.  Another 69 MW of contracted wind generation is under construction. IPC is in the process of adding 45.5 MW of geothermal generation by 2011. Additional wind and geothermal generation is anticipated through CSPP andRFP-driven contracts.

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InApril 2007, the U.S. Supreme Court issued its decision in *Massachusetts v.Environmental Protection Agency*, a case involving the EPA's authority toregulate carbon dioxide emissions from motor vehicles under the Clean Air Act. The Court held that, with respect to mobile sources, the EPA has authorityunder the Clean Air Act to regulate carbon dioxide as a pollutant and that theEPA has a duty to determine whether carbon dioxide emissions contribute toclimate change or provide some reasonable explanation why it will not exerciseits authority.  The decision, combined with stimulus from state, regional andfederal legislative and regulatory initiatives, judicial decisions and otherfactors may lead to a determination by the EPA to regulate carbon dioxideemissions from stationary sources, including electricity generators.  IPC willcontinue to monitor developments with respect to the possible regulation of GHGemissions from stationary sources under the Clean Air Act.

**New Source Review:**  EPA Region 8 began reviewing PacifiCorp operations,including the Jim Bridger plant (of which IPC is a one-third owner) forcompliance with New Source Review (NSR) and New Source Performance Standards(NSPS) through a Clean Air Act Section 114 information request sent in May2003.  PacifiCorp completed its phased response to the Section 114 request inFebruary 2004 with the submission of a large volume of documents to EPArelating to historical activities at Bridger and other PacifiCorp powerplants.  A number of utilities that have also been the subject of EPA NSR informationrequests have engaged in settlement negotiations with the EPA to resolveallegations of NSR and NSPS noncompliance.  Prior settlements reached between theEPA and utility companies around the country to resolve these issues haveresulted in commitments by the utility companies to install additionalpollution control equipment and to pay civil penalties.  IPC cannot predict theoutcome of this matter.

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

On September 5, 2007, thespecies of snail that had been listed as the "Idaho Springsnail" was delistedby the USFWS.  The delisting decision was based on recent studies thatindicated the species was synonymous with another common species.  On December21, 2006, IPC and the Governor of Idaho submitted a petition to the USFWS to de-listthe threatened Bliss Rapids snail.  The petition was supported with datacollected by IPC over the past 14 years.  The snail, which lives throughout themiddle Snake River, springs, and tributaries between Niagara Springs and KingHill, was listed as threatened under the Endangered Species Act in 1992.  As ofDecember 31, 2007, no decision on the delisting petition had been issued by theUSFWS.

Pursuantto FERC License 1971, IPC owns and finances the operation of anadromous fishhatcheries and related facilities to mitigate the effects of its hydroelectricdams on fish populations.  In connection with its fish facilities, IPC sponsorsongoing programs for the control of fish disease, improvement of fishproduction, and evaluation of hatchery performance.  IPC's anadromous fishfacilities at Hells Canyon, Oxbow, Rapid River, Pahsimeroi and Niagara Springscontinue to be operated by the Idaho Department of Fish and Game.  At December31, 2007, the investment in these facilities was $24 million and the annualcost of operation was $3 million.

**Climate Change:**  IPC's substantial hydroelectric generation resourcesneither burn nor consume fossil fuels to produce electric energy to meet theneeds of its customers.  Given the debate concerning climate change, consensusis growing that broad steps should be taken in all sectors of the nation'seconomy to carefully consider ways of limiting and/or reducing greenhouse gasemissions and mitigating climate change impacts while still providing necessaryservices in a cost-effective manner.  IPC intends to continue to add renewableresources to its resource portfolio and will continue to monitor the climatechange debate, current climate change research, and recently enacted as well asproposed legislation to identify the potential impacts of global climate changeon all aspects of its business.  Long-term climate change could significantlyaffect IPC's business in a variety of ways, including but not limited to, thefollowing: (a) changes in temperature, precipitation and snow pack conditionscould affect customer demand and the amount and timing of hydroelectricgeneration; and (b) legislative and/or regulatory developments related toclimate change could affect plans and operations in various ways includingplacing restrictions on the construction of new generation resources, theexpansion of existing resources, or the operation of generation resources ingeneral.  IPC cannot, however, quantify the potential impact of global climatechange on its business at this time.

**Renewable PortfolioStandards: **Legislation to adopt anational renewable portfolio standard (RPS) has been introduced into but notyet adopted by Congress.  IPC expects debate to continue on a national RPS andanticipates new developments in 2008.

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Anumber of states in which IPC operates or sells power into have enacted RPSlegislation.  For example, Oregon law requires the state's largest utilities tomeet 25 percent of their electric load with renewable energy by 2025.  Becauseof its relatively small presence in the state, IPC is not currently subject tothe Oregon RPS.  It is possible that Idaho and other states in which IPCoperates or sells power into could adopt similar RPS initiatives.

IPCwill continue to monitor RPS developments but cannot, at this time, predict theimpacts of state and federal RPS legislation on its business.

**REGULATORY MATTERS:**

**General Rate Case****Idaho:**  On June 8, 2007, IPC filed an application with theIPUC requesting an average rate increase of approximately 10.35 percent for itsIdaho customers in order to begin recovery of its capital investments andhigher operating costs.  IPC's proposal would increase its revenues $63.9million annually.  The application included a requested return on equity of11.5 percent and an overall rate of return of 8.561 percent.  IPC filed itscase based upon a 2007 forecast test year, a first for IPC in the Idahojurisdiction.  Since IPC's last general rate case filing in 2005, IPC projectedthat it will have placed in service an additional $300 million of investment inits electrical system during 2006 and 2007.  IPC also requested a $29.16 perMWh LGAR, which adjusts the power supply costs IPC includes in the PCA fordifferences between actual load and the load used in calculating base rates. The existing LGAR is $29.41 per MWh.  The impact of the new LGAR on IPC willultimately be determined by future load changes.

IPUC Staff and intervenortestimony was filed December 10, 2007.  The parties to the proceeding reached asettlement that includes an average annual increase of 5.2 percent(approximately $32.1 million annually).  Neither an overall rate of return nora return on equity is specified in the settlement.  The currently authorizedrate of return would remain at 8.1 percent.

The parties to the proceedingalso agreed in the settlement to make a good faith effort to develop amechanism to adjust or replace the current LGAR.  As an interim solution, theparties have agreed to use the LGAR of $62.79 per MWh recommended by the IPUCStaff on December 10, 2007, but to apply it to only 50 percent of the loadgrowth occurring during each month within the April 2008 - March 2009 PCA year.

The parties also agreed toparticipate in a good faith discussion regarding a forecast test yearmethodology that balances the auditing concerns of the IPUC Staff andintervenors with IPC's need for timely rate relief.  The parties agreed thatsuch a methodology would begin with auditable numbers from which projectionswould be made for the test year.

IPC filed a settlementstipulation with the IPUC on January 23, 2008.  The settlement is subject toapproval by the IPUC.  The parties have requested in the settlement stipulationthat the new rates become effective no later than March 1, 2008, but IPC isunable to predict what relief the IPUC will grant or when the IPUC will issueits final order.

**Deferred (Accrued) Net PowerSupply Costs**IPC's deferred (accrued) net powersupply costs consisted of the following at December 31 (in thousands ofdollars):

** **

**2007**

** **

**2006**

Idaho PCA current year:

Accrual for the 2007-2008  rate year (1)

$

- 

$

(3,484)

Deferral for the 2008-2009  rate year (2)

85,732 

- 

Idaho PCA true-up awaiting  recovery (refund):

Authorized May 2006

- 

(11,689)

Authorized May 2007

6,591 

- 

Oregon deferral:

2001 costs

2,993 

6,670 

2005 costs

- 

2,889 

2006 costs

2,107 

- 

Total deferral (accrual) 

$

97,423 

$

(5,614)

(1)The 2007-2008  PCAreflected $69 million of emission allowance sales to be  credited to customers. 

(2)The 2008-2009 PCA deferral balance reflects $17 million of emission allowance sales in  2007.

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

The true-up of the true-upportion of the PCA provides a tracking of the collection or the refund of true-upamounts.  Each month, the collection or the refund of the true-up amount isquantified based upon the true-up portion of the PCA rate and the consumptionof energy by customers.  At the end of the PCA year, the total collection orrefund is compared to the previously determined amount to be collected orrefunded.  Any difference between authorized amounts and amounts actuallycollected or refunded are then reflected in the following PCA year, whichbecomes the true-up of the true-up.  Over time, the actual collection or refundof authorized true-up dollars matches the amounts authorized.

OnMay 31, 2007, the IPUC approved IPC's 2007-2008 PCA filing.  The filingincreased the PCA component of customers' rates from the then-existing level,which was $46.8 million below base rates, to a level that is $30.7 millionabove those base rates.  This $77.5 million increase is net of $69.1 million ofproceeds from sales of excess SO2 emission allowances.  The newrates became effective June 1, 2007.

OnJune 1, 2006, IPC implemented the 2006-2007 PCA, which reduced the PCAcomponent of customers' rates from the then-existing level, which wasrecovering $76.7 million above then-existing base rates, to a level that was$46.8 million below those base rates, a decrease of approximately $123.5million.

**IdahoLoad Growth Adjustment Rate (LGAR):** On January 9, 2007, the IPUC issued an order resetting IPC's LGAR to $29.41 perMWh, effective April 1, 2007.  The LGAR subtracts the cost of servingadditional Idaho retail load from the net power supply costs IPC is allowed toinclude in its PCA.  The order revised the LGAR from the original rate of$16.84 per MWh set when the PCA began in 1993.  This amount was established asthe projected additional variable energy costs attributable to load growth andwas subtracted from each year's PCA expense.  In its petition, IPC hadrequested the use of the embedded cost of serving new load and a rate of $6.81per MWh, but the IPUC in its order determined to use the projected marginalcost, which resulted in the higher LGAR.

Asdiscussed above in "General Rate Case - Idaho", a settlement stipulation beforethe IPUC in that rate case would reset the LGAR to $62.79 per MWh, but wouldapply that rate to only 50 percent of the load growth occurring each month withinthe April 2008 - March 2009 PCA year.  In the current 2007 general rate, IPCfiled normalized firm base load of 15.6 million MWh as compared with 14.8million MWh in the 2005 general rate case.  Because the LGAR is reset ingeneral rate cases, IPC expects to update its filed base load on a morefrequent basis during periods of high load growth.

**Emission Allowances:**During 2007, IPC sold 35,000 SO2 emissionallowances for a total of $19.6 million, after subtracting transaction fees. The sales proceeds to be allocated to the Idaho jurisdiction are approximately$18.5 million ($11.3 million net of tax, assuming a tax rate of approximately39 percent).  On January 15, 2008, a workshop was held to discuss whether thecustomer share of the Idaho jurisdictional portion of the 2007 sales proceedsshould once again be included as a PCA credit or used to reduce investmentcosts in wind development, green tags, or other options that would providelonger term customer benefits.  Because the workshop participants were unableto reach a consensus regarding the use of the SO2 emission allowanceproceeds, the IPUC determined that the case would proceed under modifiedprocedure.  Written comments were due February 25, 2008.

In 2005 and early 2006, IPCsold 78,000 SO2 emission allowances for a total of $81.6 million,after subtracting transaction fees.  The sales proceeds allocated to the Idahojurisdiction were approximately $76.8 million ($46.8 million net of tax,assuming a tax rate of approximately 39 percent).  On May 12, 2006, the IPUCapproved a stipulation that allowed IPC to retain ten percent as a shareholderbenefit with the remaining 90 percent plus a carrying charge recorded as a customerbenefit.  This customer benefit is included in IPC's PCA calculations as acredit to the PCA true-up balance and is currently reflected in PCA ratesduring the June 1, 2007, through May 31, 2008, PCA rate year.

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The bulk of IPC's accumulatedexcess emission allowances were sold during the 2005-2007 period.  IPC hasapproximately 15,000 excess emission allowances currently and anticipatesrealizing a similar amount annually into the near future.  Tighter emissionrestrictions are expected in the long term which may cause IPC to use moreemission allowances for its own requirements and reduce the annual amount ofexcess emission allowances.

**Oregon:**  On April 30, 2007, IPC filed for an accounting orderwith the OPUC to defer net power supply costs for the period from May 1, 2007,through April 30, 2008, in anticipation of higher than "normal" power supplyexpenses.  In the Oregon general rate case, "normal" power supply expenses wereset at a negative number (meaning that under normal water conditions IPC shouldbe able to sell enough surplus energy to pay for all fuel and purchased powerexpenses and still have revenue left over to offset other costs).  IPCrequested authorization to defer an estimated $5.7 million, which is Oregon'sjurisdictional share of the excess power supply costs.  IPC also requested thatit earn its Oregon authorized rate of return on the deferred balance andrecover the amount through rates in future years, as approved by the OPUC.  IPCis awaiting an order from the OPUC.

On April 28, 2006, IPC filedfor an accounting order with the OPUC to defer net power supply costs for theperiod of May 1, 2006, through April 30, 2007.  IPC requested authorization todefer an estimated $3.3 million, which is Oregon's jurisdictional share of theexcess power supply costs.  IPC also requested that it earn its Oregon authorizedrate of return on the deferred balance and recover the amount through rates infuture years, as approved by the OPUC.  On April 25, 2007, a tentativesettlement agreement was reached on the deferral application with the OPUCStaff and the Citizens' Utility Board in the amount of $2 million.  The partiesalso agreed that IPC would file an application for an Oregon PCA mechanism. The settlement stipulation was approved by the OPUC on December 13, 2007.

The timing of future recoveryof Oregon power supply cost deferrals is subject to an Oregon statute thatspecifically limits rate amortizations of deferred costs to six percent peryear.  IPC is currently recovering through rates power supply costs associatedwith the western energy situation of 2001.  Full recovery of the 2001 deferralis not expected until 2009.  The 2006-2007 and the 2007-2008 deferrals will beamortized sequentially following the full recovery of the 2001 deferral.

**Oregon Power CostAdjustment Mechanism (PCAM)**On August 17, 2007, IPC filed an application with the OPUC requesting theapproval of a power cost adjustment mechanism similar to the Idaho PCA.  If theapplication is approved, it will allow IPC to recover excess net power supplycosts or distribute benefits to customers in a more timely fashion than throughthe existing deferral process.  The proposed mechanism differs from the IdahoPCA in that is reestablishes the base net power supply costs annually.  InIdaho, the base net power supply costs are set by a general rate case.  Settlementconferences were held and the interested parties reached a verbal agreement.  Astipulation has been drafted by IPC and is being reviewed by the parties to thesettlement.

In connection with thisproceeding, on October 29, 2007, IPC made a filing with the OPUC requestingthat revenues associated with IPC's base net power supply costs be increased by$4.6 million for Oregon.  In isolation, this would be an average 15 percentincrease in rates; however, a yet to be filed forecast of net power supplycosts would also be a component of future PCAM rates.  If the OPUC approves thePCAM, any changes in rates are not expected to be effective until June 2008.

**Fixed Cost AdjustmentMechanism (FCA)**On January 27, 2006, IPC filed with the IPUC for authority to implement a rateadjustment mechanism that would adjust rates downward or upward to recoverfixed costs independent of the volume of IPC's energy sales.  This filing was acontinuation of a 2004 case that was opened to investigate the financial disincentivesto investment in energy efficiency by IPC.  This true-up mechanism would beapplicable only to residential and small general service customers.  Theaccounting for the FCA will be separate from the PCA.  IPC proposed a threepercent cap on any rate increase to be applied at the discretion of the IPUC.

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IPC and the IPUC Staff agreed in concept to a three-year pilot program beginningJanuary 1, 2007, and a stipulation was filed on December 18, 2006.  Thestipulation called for the implementation of a FCA mechanism pilot program asproposed by IPC in its original application with additional conditions andprovisions related to customer count and weather normalization methodology,recording of the FCA deferral amount in reports to the IPUC and detailedreporting of DSM activities.  The IPUC approved the stipulation on March 12,2007.  The pilot program began retroactively on January 1, 2007, and will runthrough 2009, with the first rate adjustment to occur on June 1, 2008, andsubsequent rate adjustments to occur on June 1 of each year thereafter duringthe term of the pilot program.  IPC accrued $2.1 million of FCA expense in2007.****

**Pension Expense**In the 2003 Idaho general rate case,the IPUC disallowed recovery of pension expense because there were no currentcontributions being made to the plan.  On March 20, 2007, IPC filed a requestwith the IPUC to clarify that IPC can consider future contributions made to thepension plan a recoverable cost of service.  On June 1, 2007, the IPUC issued its order authorizing IPC to accountfor its defined benefit pension expense on a cash basis, and to defer andaccount for accrued pension expense under SFAS 87, *"Employers' Accountingfor Pensions,"*as a regulatoryasset.  The IPUC acknowledged that it is appropriate for IPC to seek recoveryin its revenue requirement of reasonable and prudently incurred pension expensebased on actual cash contributions.  The order did not determine the method ofrecovery.  IPC began deferring pension expense to a regulatory asset account tobe matched with revenue when future pension contributions are recovered throughrates.  The deferral of pension expense did not begin until $4.1 million ofpast contributions still recorded on the balance sheet at December 31, 2006,were expensed.  For 2007, approximately $2.8 million was deferred to aregulatory asset beginning in the third quarter.  IPC did not request acarrying charge to be applied to the deferral of the accrued SFAS 87 expense.

**AMI Report**IPC filed its Advanced MeteringInfrastructure (AMI) Status Report with the IPUC on May 1, 2007, in compliancewith an IPUC order.  The report details IPC's resolution of the AMI-relatedissues identified in the December 2005 AMI Status Report.  On August 31, 2007,IPC filed a supplemental report detailing its assessment of how it will proceedwith AMI deployment.  In the report IPC provided a summary of the financialanalysis, a three-year AMI implementation plan beginning in late 2008, adiscussion of cost recovery and identification of remaining issues.

**Federal Regulatory MattersThe Bonneville Power Administration Residential Exchange Program: **The Pacific Northwest Electric Power Planning andConservation Act of 1980, through the Residential Exchange Program, providesaccess to the benefits of low-cost federal hydroelectric power to residentialand small farm customers of the region's investor-owned utilities (IOUs).  Theprogram is administered by the Bonneville Power Administration (BPA).  IPCentered into settlement agreements with the BPA that settled IPC's rights underthe Residential Exchange Program (REP) for the fiscal year 2002-2006 rateperiod and for the fiscal year 2007-2011 rate period.  Pursuant to theseagreements between the BPA and IPC, benefits from the BPA were passed throughto IPC's Idaho and Oregon residential and small-farm customers in the form ofelectricity bill credits.

On May 3, 2007, the U.S.Court of Appeals for the Ninth Circuit ruled that the settlement agreementsentered into between the BPA and the IOUs (including IPC) are inconsistent withthe Northwest Power Act.  On May 21, 2007, the BPA notified IPC and six other IOUsthat it was immediately suspending the REP payments that the utilities passthrough to their residential and small-farm customers in the form ofelectricity bill credits.  IPC took action with both the IPUC and the OPUC toreduce the level of credit on its customers' bill to zero, effective June 1,2007.  From October 1, 2001 to June 1, 2007, IPC had passed through to its REPcustomers approximately $90 million in benefits pursuant to the settlementagreements.

Since that time IPC has beenworking with the other northwest IOUs, northwest state public utilitycommissions, and the BPA to craft an agreement so that residential and smallfarm customers of IPC can resume sharing in the benefits of the federalColumbia River power system.  However, the matter has yet to be resolved.  TheBPA has initiated several public processes, which ultimately will determinewhether benefits will be restored to IPC customers.  The most significant ofthese processes is the WP-07 supplemental rate case.  IPC will fullyparticipate in this proceeding, which is expected to be completed prior toOctober 1, 2008.  At issue is the REP calculation and allocation of benefits toIOUs, and IPC specifically, and resolution of claims of overpayment in pastperiods.

Since these REP benefits werepassed through to IPC's customers, the outcome of this matter is not expectedto have a significant effect on IPC's financial condition or results ofoperations.

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**FERC Investigation: **On March 28, 2007, the FERC advised IPC that the FERCwas commencing a preliminary, non-public investigation into the pricing andavailability of transmission capacity into and out of IPC's IPCO point ofdelivery and transactions related to that transmission capacity during theperiod January 1, 2003, to present.  Subsequently, the FERC made two datarequests in connection with this investigation.  IPC responded to those datarequests between June and August 2007.  At IPC's request, IPC representativesmet with FERC personnel on October 18, 2007, to discuss several data responsesthat IPC had previously provided.  In follow-up to that meeting, IPC hadfurther discussions with and submitted additional materials to the FERC staff. IPC is unable to predict the outcome of this investigation.

**FERC Proceedings:**Open Access Transmission Tariff(OATT):  On March 24, 2006, IPCsubmitted a revised OATT filing with the FERC requesting an increase intransmission rates.  In the filing IPC proposed to move from a fixed rate to aformula rate, which allows for transmission rates to be updated each year basedon FERC Form 1 data.  The formula rate request included a rate of return onequity of 11.25 percent.  The proposed rates would have produced an annualrevenue increase for the FERC jurisdiction of approximately $13 million basedon 2004 test year data.  The FERC accepted IPC's rates, effective June 1, 2006,subject to adjustment to conform to SFAS 109 tax accounting requirements, whichlowered the estimated annual increase in revenues to approximately $11 million.

On August 8, 2007, the FERCapproved a settlement agreement filed in June 2007 by the parties on all issuesexcept the treatment of contracts for transmission service that contain theirown terms, conditions and rates and that were in existence before theimplementation of OATT in 1996 (Legacy Agreements).  The effect of thissettlement was to reduce the estimated FERC jurisdictional annual revenue increasefrom $11 million to approximately $8.2 million based on 2004 test year data. The settlement agreement required that amounts collected in excess of the newrates for the June 1, 2006, through July 31, 2007, period be refunded withinterest to customers.  These refunds totaled approximately $1.7 million andwere paid in August 2007.

Hearings were held before theFERC in June 2007 regarding the treatment of the Legacy Agreements.  IPC'sposition was that the revenue IPC receives under the Legacy Agreements shouldbe credited against the total transmission revenue requirement attributed toOATT customers and that the contract demands of the Legacy Agreements shouldnot be included in the load divisor of the rate formula.  The intervenors inthe proceeding took the position that such contract demands should be includedin the load divisor, rather than being revenue credited.

On August 31, 2007, the FERCPresiding Administrative Law Judge (ALJ) issued an initial decision (InitialDecision) with respect to the treatment of the Legacy Agreements, which is onfile and publicly available at FERC Docket No. ER06-787.  In the InitialDecision, the ALJ concluded that (i) the Legacy Agreements should be includedin the load divisor of the rate formula and (ii) the revenue IPC receives underthe Legacy Agreements should not be credited against the total transmissionrevenue requirement attributed to OATT customers.  If the Initial Decision isimplemented, IPC estimates that this ruling will reduce the estimated FERC jurisdictionalannual revenue increase (based on 2004 test year data) to $6.8 million.

IPC has appealed the InitialDecision to the FERC.  However, if the Initial Decision is implemented, IPCwould make additional refunds, including interest, of approximately $2.4million for the June 1, 2006, through December 31, 2007, period.  IPC hasreserved this entire amount.  IPC expects to pursue recovery of amounts notreceived pursuant to a final order in this proceeding through additionalproceedings at the FERC or through the state ratemaking process.  IPC isawaiting a final FERC order.

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FERCOrder 890:  In February 2007, theFERC issued Order No. 890 adopting a final rule designed to strengthen the proforma OATT by providing greater consistency and increasing transparency.  TheFERC had stated in its Notice of Proposed Rulemaking leading to the final rulethat "as a general matter, the purpose of this rulemaking is to strengthen thepro forma OATT to ensure that it achieves its original purpose - remedying unduediscrimination - not to create new market structures."  The most significantrevisions to the pro forma OATT relate to the development of more consistentmethodologies for calculating available transfer capability, changes to thetransmission planning process, changes to the pricing of certain generator andenergy imbalances to encourage efficient scheduling behavior and to exemptintermittent generators, and changes regarding long-term point-to-pointtransmission service, including the addition of conditional firm long-termpoint-to-point transmission service, and generation re-dispatch.

Asa transmission provider with an OATT on file with the FERC, IPC is required tocomply with the requirements of the new rule.  A major requirement of the newrule was to file a revised *pro forma* OATT on July 13, 2007.  IPC alsowas required to file a revised Attachment C specifying the methodology toassess available transfer capability on September 11, 2007, and an Attachment Kwhich sets forth its coordinated, open and transparent planning process onDecember 7, 2007.  IPC made the required FERC filings and is currentlyoperating under the new tariff.

OnDecember 28, 2007, the FERC issued Order No. 890-A, an order on Rehearing andClarification of Order 890.  Order No. 890-A primarily affirms and clarifies OrderNo. 890.  Order No. 890-A will become effective 60 days after its publicationin the Federal Register.

Certain details related tothe rule remain to be determined prospectively, and thus it is difficult to makea precise determination of the overall effect of this new rule on IPC'stransmission operations or wholesale marketing function.  However, at least ona preliminary basis, the rule is not anticipated to have a significant impacton IPC's financial results.  Nonetheless, the final rule includes a wide rangeof provisions addressing the provision of transmission services, and as the newtariff is implemented there is likely to be an impact on IPC's transmissionoperations, planning and wholesale marketing functions.

FERC Order 693:  Pursuant to section 215 of the FPA, on March 16,2007, the FERC issued Order No. 693 in which it approved 83 of the 107reliability standards proposed by the North American Electric ReliabilityCorporation (NERC).  Previously, the FERC certified the NERC as the electricreliability organization responsible for developing and enforcing mandatoryreliability standards.  Collectively, the reliability standards define overallacceptable performance with regard to operation, planning and design of theNorth American bulk power system.  As the FERC recognized in Order No. 693,most of these reliability standards were already being adhered to on avoluntary basis.  Compliance with these standards became mandatory and subjectto the FERC's penalty authority in June 2007.  Since then, additionalreliability standards have been submitted, and will continue to be submitted,by the NERC to the FERC for approval.  IPC reviewed all requirements,procedures and documentation to ensure compliance with these standards andsubmitted all necessary information by the effective date of June 18, 2007. IPC certified its compliance with a subset of these standards (the WECCActively Monitored Standards) prior to the January 10, 2008 deadline.  IPC is subjectto compliance spot-checks beginning in 2008.  Order No. 693 substantiallyimpacts documentation requirements, but is not expected to have a materialimpact on operations.

**NorthernTier Transmission Group**IPC, along with four othertransmission-owning entities covering all or parts of the transmission systemin six western states, has formed the Northern Tier Transmission Group (NTTG). The goal of the group is to improve overall operation and expansion of the high-voltagetransmission network.  The group continues to make progress on four majorinitiatives: improving generation control performance (the first generationcontrol became operational in March 2007); compliance with FERC Order 890through cooperative efforts in developing process and information exchange;providing improved information on available transmission capacity; andconducting open, participatory transmission planning processes which willresult in identifying specific transmission projects.  Several projects havebeen identified for the "fast-track" planning process and work has begun onengineering analysis.  One of these projects is IPC's joint project withPacifiCorp (MidAmerican) to evaluate building two high voltage transmissionlines as discussed below (Gateway West Project).  FERC Order No. 890 requiredjurisdictional utilities to establish planning procedures, to which IPCresponded by submitting its Attachment K filing with the FERC on December 7,2007.  To date, the FERC has yet to accept or issue orders regarding anyAttachment K filings, including IPC's.  In addition to other activities, theNTTG fulfills a significant portion of the sub-regional and regional planningrequirements specified in Order 890, including the commencement of the NTTGbiennial planning process with a public stakeholder meeting held in January2008.

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**GatewayWest Project**IPC and PacifiCorp are jointlyexploring the Gateway West Project to build two 500-kV lines between the JimBridger plant in Wyoming and Boise.  The lines would be designed to increaseelectrical transmission capacity across southern Idaho in response toincreasing customer demand and growth.  This project has been submitted to theWestern Electricity Coordinating Council (WECC) for the first phases of theratings process.  A review team has been established from members of the WECCto analyze the impact of the project on the existing system.  When the study iscomplete, necessary modifications will be made to the engineering design andthe final rating will be obtained prior to the beginning of construction.  Planningand project management personnel for both companies have begun the initialphases of this project.  IPC and PacifiCorp have a cost sharing agreement forexpenses associated with the analysis work of the initial phases.  It isexpected that the majority of the project would be completed between 2012 and2014 depending on the timing of rights-of-way acquisition, siting andpermitting, and construction sequencing.  If the project is constructed, IPCestimates that its share of project costs would be between $800 million and$1.2 billion.

**Hemingway-BoardmanLine**Consistent with the 2006 IRP andrequirements of other transmission customer requirements, IPC is exploringalternatives for the construction of a 500-kV line between southwestern Idahoand the Northwest.  If built, this line could be in service as early as 2012. Several electric utilities, including IPC, have proposed development of atransmission station near Boardman, Oregon which would serve as the northwestterminal of the project.  The Idaho terminal would be the proposed HemingwayStation located in the vicinity of Melba and Murphy on the south side of theSnake River near Boise.  IPC and a number of other utilities with proposedregional transmission projects in the Northwest have signed a letter agreeingto coordinate technical studies, which have begun.  Other planning and projectmanagement activities are underway.  IPC has received inquiries aboutparticipating in this project from other parties.

Theproposed Gateway West and Hemingway-Boardman transmission projects will be usedboth by wholesale transmission customers and to serve IPC's native loadconsistent with our OATT.  Therefore these facilities will be subject to boththe FERC and state public utility commission regulation and rate-makingpolicies.

**Public Utility RegulatoryPolicies Act of 1978**As mandated by the enactment of PURPA and the adoption of avoided cost rates bythe IPUC and the OPUC, IPC has entered into contracts for the purchase ofenergy from a number of private developers.  Under these contracts, IPC isrequired to purchase all of the output from the facilities located inside theIPC service territory.  For projects located outside the IPC service territory,IPC is required to purchase the output that IPC has the ability to receive atthe facility's requested point of delivery on the IPC system.  The IPUCjurisdictional portion of the costs associated with CSPP contracts are fullyrecovered through base rates and the PCA.  For IPUC jurisdictional contracts,projects that generate up to ten average MW of energy on a monthly basis areeligible for IPUC Published Avoided Costs for up to a 20-year contract term. The Published Avoided Cost is a price established by the IPUC and the OPUC toestimate IPC's cost of developing additional generation resources.  Asdiscussed more fully in "Wind Integration Costs" below, on August 4, 2005, theIPUC granted a temporary reduction in the eligible project size to 100 kW forintermittent generation resources only and ordered IPC to study the impacts ofintegrating this type of resource.

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

Recent activities, includingthe extension of the Federal Production Tax Credit and the expansion of the taxcredit eligibility to solar, geothermal and other forms of generation,resolution of IPUC and OPUC PURPA-related hearings and a December 1, 2004,order by the IPUC increasing the Published Avoided Costs, create a favorableclimate for PURPA project development, which may require IPC to enter intoadditional PURPA agreements.  The requirement to enter into additional PURPAagreements may result in IPC acquiring energy at above wholesale market prices,thus increasing costs to its customers.  It is highly likely that therequirement to enter into additional PURPA agreements will add to IPC's surplusduring certain times of the year, which could also increase costs to IPC'scustomers.  As of December 31, 2007, IPC had signed agreements to purchaseenergy from 94 CSPP facilities with contracts ranging from one to 30 years.  Ofthese facilities, 76 were on-line at the end of 2007; the other 18 facilitiesunder contract are due to come on-line in 2008 and 2009.  During 2007, IPCpurchased 777,147 MWh from these projects at a cost of $45 million, resultingin a blended price of 5.9 cents per kilowatt hour.

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**Wind Integration Costs:**  Under PURPA, IPC is required to offer independentdevelopers a power purchase contract based on a standard avoided cost rate fora qualifying facility with an output of ten average megawatts (aMW) or less. Because a large number of wind project developers came to IPC requesting PURPAcontracts in early 2005, IPC requested and the IPUC granted temporary relieffrom PURPA requirements until the impact of wind integration could be morefully studied.  The IPUC granted this relief by temporarily reducing the PURPAcap of 10 aMW to 100 kW for PURPA wind projects.

On February 6, 2007, IPCfiled with the IPUC a wind integration study report along with a petitionrequesting removal of the temporary restriction on the size of PURPA windprojects and adjustment of avoided cost rates to compensate for the increase insystem costs due to wind variability.  On March 15, 2007, and June 20, 2007, publicworkshops were held to present the results of the study, which were contestedby wind developers and advocates of wind generation resources.

In an attempt to settle thecase, IPC entered into a settlement stipulation with Renewable NorthwestProject and the NW Energy Coalition on October 2, 2007.  The settlement stipulationprescribed, among other things, a methodology for calculating a windintegration charge that will be applied to PURPA wind projects.  Theintegration charge will be calculated as a percentage of the current 20-year,levelized, avoided cost rate, subject to a cap of $6.50/MWh.  On February 20, 2008, the IPUC issued an orderapproving the settlement stipulation and increasing the PURPA cap back to tenaMW.

**Cassia Wind Farm Complaint:**  On September 13, 2006, Cassia Gulch Wind Park, LLCand Cassia Wind Farm, LLC (collectively Cassia) filed a complaint against IPCwith the IPUC requesting the IPUC to determine that the cost responsibility forspecified transmission system upgrades to meet contingency planning conditionsshould not be assigned to PURPA qualifying facilities connecting to the system,but rather should be rolled into IPC's plant-in-service rate base and recoveredthrough rates to retail and transmission customers.  The estimated costs oftransmission system upgrades included in this complaint that relate toconnecting Cassia to IPC's system were $60 million.  Comments were filed inOctober and November 2006, and oral arguments were held in November 2006.  OnJune 13, 2007, IPC and Cassia filed a Joint Motion to Dismiss the underlyingcomplaint and to approve a related settlement stipulation.  The IPUC approvedthe Joint Motion on August 29, 2007.

The key component of thestipulation is the concept of "redispatch."  IPC's estimated cost ofapproximately $60 million to complete necessary transmission network upgradeswas based on the assumption that the requesting projects in the transmissionqueue would not be dispatchable.  Under the stipulation, Cassia agrees toinstall, at its expense, equipment and communication facilities necessary to reduceits energy output to a predetermined set-point within ten minutes of when IPCrequests the reduction.  Based on these provisions, the original estimate of$60 million decreased to approximately $11 million.  Under the stipulation, IPCwould fund 25 percent of any upgrade investment, which would be recoverablethrough rates, while the developer would fund 25 percent that is non-recoverableand 50 percent that is recoverable over time.  The stipulation also addressesresponsibility for network upgrade costs, sharing of network upgrade costs,refunds and interests on refunds and security for payment.

On October 15, 2007, the IPUCapproved the application of this same cost allocation methodology to two PURPAqualifying projects that were not parties to the Cassia dispute and are in adifferent geographic region than the one impacted by the Cassia transmissionupgrades.  Although the IPUC did not in the Cassia proceeding approve broadapplication of the settlement to other projects, it did, in this case, determinethat the circumstances were similar enough to warrant using the same costallocation methodology.

**PURPA Avoided Cost RateComputation:**  On September 10, 2007,IPC filed an application with the IPUC requesting modification to the method ofcomputing avoided cost rates.  These rates are used to set the price IPC paysto new PURPA projects over the lives of the purchase agreements.  Specifically,IPC requested that the fuel cost component of the computation be revised from athree-year average natural gas price with a prescribed escalation factor to anaverage of the 20-year forecast of median natural gas prices as published bythe Northwest Power and Conservation Council (NWPCC) for 2007.  IPC believes thatfailing to recognize the non-linear shape of the NWPCC's 2007 forecast wouldcause the published rates to be much higher than they otherwise would be.  IPC didnot propose to adjust any of the non-fuel assumptions in the avoided cost ratecomputation.

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AvistaCorporation, Rocky Mountain Power, and the IPUC Staff filed comments supportingIPC's position but recommending that the fuel cost component be tied to eachyear in the NWPCC forecast rather than using an average of the twenty years.  The IPUC approved the application including the IPUCStaff's recommended modification on December 28, 2007.****

**Integrated Resource Plan**IPC filed its 2006 IRP with the IPUCin September 2006 and with the OPUC in October 2006.  The 2006 IRP previewedIPC's load and resource situation for the next 20 years, analyzed potentialsupply-side and demand-side options and identified near-term and long-termactions.

The IPUC accepted the 2006IRP in March 2007.  The OPUC acknowledged the 2006 IRP in September 2007 withthe stipulation that IPC not commit to the construction of a 250-MW pulverizedcoal resource, identified to come on-line in 2013, until IPC presents an updateof the 2006 IRP to the OPUC no later than June 2008.  With its acceptance ofthe 2006 IRP, the IPUC requested that IPC align the submittal of its next IRP withthose submitted by other utilities.  To comply with this request IPC intends toprovide an update on the status of the 2006 IRP to both the IPUC and OPUC nolater than June 2008 and file a new IRP in June 2009.

During the time betweenresource plan filings, the public and regulatory oversight of the activitiesidentified in the IRP allows for discussion and adjustment of the IRP aswarranted.  IPC continues to analyze and evaluate the resource plan and makeperiodic adjustments and corrections to reflect changes in technology, economicconditions, anticipated resource development and regulatory requirements.  Eachof the sections below provides an update of items identified in the 2006 IRP.

**Peaking Resource: **Construction of a new simple cycle combustion turbineresource at the Danskin plant near Mountain Home, Idaho is expected to becomplete in the first quarter of 2008.  The combustion turbine will provide approximately 166 MW of capacity duringsummer load peaks and up to 200 MW during winter.  IPC received a Certificateof Public Convenience and Necessity for this project on December 15, 2006, thatincluded a construction cost commitment estimate of $60 million and approval toinclude in rate base the prudent capital costs for construction and operatingfuel.  The project is ahead of schedule and under the commitment estimate. Related transmission interconnection and line requirements are being completedby IPC at an estimated cost of $24 million.

**Wind Agreement:**  In February 2007, the IPUC approved a power purchaseagreement with Telocaset Wind Power Partners, LLC, a subsidiary of Horizon WindEnergy, for 101 MW (nameplate) of wind generation from the Elkhorn Valley WindProject located in eastern Oregon.  The project was constructed during 2007 andbecame commercially operational on December 28, 2007.

**Geothermal Agreement:**  An RFP for geothermal-powered generation wasreleased on June 2, 2006.  IPC identified U.S. Geothermal, Inc. as thesuccessful bidder in March 2007 based on a proposal to supply 45.5 MW ofgeothermal energy.  On January 9, 2008, the IPUC approved a power purchase agreementfor 13 MW (nameplate generation) from the Raft River Geothermal Power PlantUnit #1 located in southern Idaho.  This project began operating in October2007.  Contract negotiations for the remaining 32.5 MW will take place over thenext several months and will include an additional unit at the Raft River site(on-line 2009) and two units at the Neal Hot Springs site located in easternOregon (on-line 2010 and 2011).

**Coal-fired Resource (Shiftto Natural Gas-fired Resource):**  Thenear-term action plan in the 2006 IRP indicated initial commitments to theconstruction of a coal-fired resource would be necessary before the end of 2007in order for a project to be on-line in 2013.  In order to meet this schedule,IPC screened and evaluated coal-fired resources in 2006 and 2007.  Thisevaluation concluded in August 2007 and the results indicated constructioncosts had escalated substantially since resource cost estimates were preparedfor the 2006 IRP.  Due to escalating construction costs and continueduncertainty surrounding future GHG laws and regulations, IPC decided not topursue the development of a coal-based resource at this time.  However, IPCcontinues to evaluate other coal-fired resource opportunities, includingexpansion of its jointly-owned facilities, clean coal technologies andpotential power purchase agreements.  In order to meet baseload deficienciesidentified in 2013, IPC has shifted its focus to the development of a combinedcycle natural gas-fired resource located closer to its load center in southernIdaho.

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**Additional RFPs:**  On January 22, 2008, IPC released an RFP for 50 to100 MW of geothermal energy.  While additional geothermal resources were notincluded in the 2006 IRP for this time frame, the development of PURPA wind andcombined heat and power projects has been slower than anticipated.  Ifcompetitively priced geothermal resources are available, they may help to meetfuture resource needs.  IPC also anticipates releasing an RFP in 2008 for 50 MWfrom one or more combined heat and power projects.

**Relicensing ofHydroelectric Projects**IPC, like other utilities thatoperate nonfederal hydroelectric projects on qualified waterways, obtains licensesfor its hydroelectric projects from the FERC.  These licenses last for 30 to 50years depending on the size, complexity, and cost of the project.  IPC isactively pursuing the relicensing of the Hells Canyon Complex and Swan Fallsprojects.

**Hells Canyon Complex:** The most significant ongoing relicensing effort isthe Hells Canyon Complex (HCC), which provides approximately two-thirds of IPC'shydroelectric generating capacity and 40 percent of its total generatingcapacity.  The current license for the HCC expired at the end of July 2005. Until the new multi-year license is issued, IPC operates the project under anannual license issued by the FERC.  The license application was filed in July2003 and accepted by the FERC for filing in December 2003.  The FERC is nowprocessing the application consistent with the requirements of the FPA, theNational Environmental Policy Act of 1969, as amended (NEPA), the Energy PolicyAct and other applicable federal laws.

Consistent with therequirements of NEPA, the FERC Staff prepared and issued on August 31, 2007, afinal environmental impact statement (EIS) for the HCC, which the FERC will useto determine whether, and under what conditions, to issue a new license for theproject.  The purpose of the final EIS isto inform the FERC, the federal and state agencies, Native American tribes andthe public about the environmental effects of IPC's proposed operation of theHCC.  The final EIS also considers reasonable alternatives to that proposedoperation.  In this latter context, the FERC Staff reviewed the comments andalternative proposals submitted by the agencies, tribes and the privateinterests and evaluated those alternatives as compared to measures proposed byIPC.  The final EIS also contains a "Staff Alternative," reflecting thoseinstances where some modification to IPC's proposal is deemed advisable by theStaff to address environmental impacts or concerns.  The FERC will consider thefindings and proposals contained in the final EIS, together with the otherinformation and material filed in the relicensing proceeding, in thedevelopment of a license order for the HCC.  IPC's initial review of the finalEIS indicates that, in large measure, the findings and recommendations (theStaff Alternative) in the final EIS are consistent with the draft EIS issued bythe FERC in July 2006 and that the final EIS generally accepts the science,analysis and the proposed measures contained in IPC's license application andsupporting documents.  IPC is continuing to review the final EIS and expects tofile comments on the final EIS with the FERC in the first quarter of 2008.

In conjunction with theissuance of the final EIS, on September 13, 2007, the FERC requested formalconsultation with the National Marine Fisheries Service (NMFS) and the U.S.Fish and Wildlife Service (USFWS) pursuant to section 7 of the EndangeredSpecies Act (ESA) with regard to the effect of relicensing the HCC on severalaquatic and terrestrial species listed as threatened under the ESA.  In subsequentcorrespondence these entities, the USFWS and the NMFS advised the FERC thatoutstanding issues remain with regard to the licensing of the HCC and they didnot have sufficient information to complete formal ESA consultation on theproject.  The agencies further advised that they were working with IPC andother state and federal agencies to address these outstanding issues.  IPCcontinues to cooperate with the USFWS, the NMFS, and the FERC in an effort toaddress ESA concerns associated with the relicensing of the HCC.  The FERC isnot expected to issue a license order for the HCC until ESA consultation iscompleted.

On January 31, 2007, IPCfiled Water Quality Certification Applications, under section 401 of the CleanWater Act (CWA), with the States of Oregon and Idaho.  Because the HCC islocated on the Snake River where it forms the border between Idaho and Oregon,section 401 of the CWA requires as a prerequisite to the licensing of theproject by the FERC that each state certify that any discharge from the projectcomplies with applicable state water quality standards.  IPC worked with theODEQ and the IDEQ through 2007 on proposed water quality measures that wouldaddress water quality issues at the project.  However, because the CWA requiresthat a state agency act on a pending application within one year of its filingdate, IPC found it necessary to withdraw its pending section 401 applicationson November 2, 2007 and re-file new applications on that same date.  IPC filedsupplemental information to the applications on February 1, 2008.  IPCcontinues to work with the ODEQ and the IDEQ to ensure that state water qualitystandards will be met at the HCC so that the project can be appropriatelycertified.

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At December 31, 2007, $96million of HCC relicensing costs were included in construction work inprogress.  The relicensing costs are recorded and will be held in constructionwork in progress until a new multi-year license is issued by the FERC, at whichtime the charges will be transferred to electric plant in service.  Relicensingcosts and costs related to a new license will be submitted to regulators forrecovery through the ratemaking process.

**Swan Falls Project:**  The license for the Swan Falls hydroelectric projectexpires in June 2010.  On March 10, 2005, IPC issued a Formal ConsultationPackage (FCP) to natural resource agencies, Native American tribes and thepublic relating to environmental studies designed to determine project effectsfor the relicensing of the Swan Falls project.  Based upon the results of thosestudies and the consultation with the agencies, tribes and the public, onSeptember 21, 2007, IPC submitted its draft license application to FERC forpublic review and comment.  The draft contains project-specific information andthe results of the studies developed in the FCP.  Comments were received fromthe agencies and one tribe and on February 19, 2008 a joint meeting was held toaddress the comments and attempt to resolve areas of disagreement over studyresults and proposed mitigation measures.  IPC will file a final licenseapplication with the FERC in June 2008.

At December 31, 2007, $3million of Swan Falls project relicensing costs were included in constructionwork in progress.  The relicensing costs are recorded and will be held inconstruction work in progress until a new multi-year license is issued by theFERC, at which time the charges will be transferred to electric plant inservice.  Relicensing costs and costs related to a new license will besubmitted to regulators for recovery through the ratemaking process.

**Shoshone Falls Expansion:**  On August 17, 2006, IPC filed a license amendmentapplication with the FERC, which would allow IPC to upgrade the Shoshone Fallsproject from 12.5 MW to 62.5 MW.  In March 2007, IPC received from the FERC adraft Environmental Assessment (EA) and Notice of Ready for EnvironmentalAnalysis, which provided for a 60-day comment period for interested entities. The FERC issued a supplemental EA on December 4, 2007.  The license amendmentcould be issued in the first quarter 2008.

In conjunction with thelicense amendment application, IPC has filed a water rights application whichis currently being reviewed by the IDWR.

**FERC Market-Based RateAuthority**IPC has FERC-approved market-basedrate authority, which permits IPC to sell electric energy at market-based ratesrather than being limited to cost-based rates.  Every three years, the FERCrequires a review of the conditions under which this market-based rateauthority is granted to ensure that the rates charged thereunder are just andreasonable.  On April 14, 2004, the FERC issued an order indicating that is wasreconsidering the rules, procedures and methodologies associated with such"triennial filings."  In September 2004, IPC filed a revision to its marketpower analysis (based on 2003 historical data), which it supplemented inSeptember and October 2004.  On March 3, 2005, the FERC issued an orderaccepting IPC's market power analysis.  On June 21, 2007, the FERC issued afinal rule, Order No. 697, revamping its market-based rate program.  UnderOrder No. 697, IPC's next triennial filing is not due until June 30, 2010.

On December 9, 2005, the FERCStaff requested that IPC perform a complete generation market power study forthe IPC control area using 2004 historical data.  IPC filed a revised studywith the FERC on February 3, 2006.  The FERC accepted IPC's notice on June 20,2006, confirming that IPC passed the market power analysis screens andmaintained market-based rate authority.

BecauseIPC's new generating unit at its Danskin plant, which has a capacity greaterthan 100 MW, will soon be operational, IPC anticipates filing a "Notice ofChange in Status" with the FERC during the first quarter of 2008.

**OTHER MATTERS:**

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**Adopted AccountingPronouncementsFIN 48:**In 2007, IDACORP and IPCadopted FASB Interpretation No. 48, *"Accounting for Uncertainty in IncomeTaxes - an interpretation of FASB Statement No. 109*" (FIN 48), whichcreates a single model to address accounting for uncertainty in tax positions. FIN 48 prescribes a minimum recognition threshold that a tax position isrequired to meet before being recognized in a company's financial statementsand also provides guidance on derecognition, measurement, classification, interestand penalties, accounting in interim periods, disclosure, and transition.

The cumulative effect ofadopting FIN 48 was recorded as a $15.1 million increase in the 2007 openingbalance in retained earnings.

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

**Inflation**IDACORP and IPC believe thatinflation has caused and will continue to cause increases in certain operatingexpenses and the replacement of assets at higher costs.  Inflation affects thecost of labor, products and services required for operations and maintenanceand capital expenditures.  While inflation has not had a significant impact onIDACORP's or IPC's operations, increases in utility expenses due to inflationcould have an adverse effect on earnings because of the need to obtainregulatory approval to recover such increased expenses.

**ITEM7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK**

IDACORP and IPC are exposedto market risks, including changes in interest rates, changes in commodityprices, credit risk and equity price risk.  The following discussion summarizesthese risks and the financial instruments, derivative instruments andderivative commodity instruments sensitive to changes in interest rates,commodity prices and equity prices that were held at December 31, 2007.

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

**Variable Rate Debt:**  As of December 31, 2007, IDACORP and IPC had $325million and $374 million, respectively, in net floating rate debt.  Assuming nochange in financial structure for either company, if variable interest rateswere one percentage point higher than the rates in effect on December 31, 2007,interest rate expense would increase and pre-tax earnings would decrease byapproximately $3.2 million for IDACORP and $3.7 million for IPC.

**Fixed Rate Debt:**  As of December 31, 2007, IDACORP and IPC hadoutstanding fixed rate debt of $981 million and $956 million, respectively, andthe fair market value of this debt was $972 million and $946 million,respectively.  These instruments are fixed rate and, therefore, do not exposethe companies to a loss in earnings due to changes in market interest rates. However, the fair value of these instruments would increase by approximately$96 million for IDACORP and $95 million for IPC if interest rates were todecline by one percentage point from their December 31, 2007 levels.

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

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

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

**Credit RiskUtility:**  IPC is subject to creditrisk based on its activity with market counterparties.  IPC is exposed to thisrisk to the extent that a counterparty may fail to fulfill a contractual obligationto provide energy, purchase energy or complete financial settlement for marketactivities.  IPC mitigates this exposure by actively establishing creditlimits, measuring, monitoring, reporting, using appropriate contractualarrangements and transferring of credit risk through the use of financialguarantees, cash or letters of credit.  A current list of acceptablecounterparties and credit limits is maintained.

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

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** **

**ITEM 8.  FINANCIALSTATEMENTS AND SUPPLEMENTARY DATA**

**INDEX TO FINANCIALSTATEMENTS AND FINANCIAL STATEMENT SCHEDULES**

**PAGE**

**Consolidated Financial Statements:**

IDACORP, Inc.

Consolidated Statements of Income for the Years  Ended December 31, 2007, 2006 and 2005

67

Consolidated Balance Sheets as of December 31, 2007  and 2006 

68-69

Consolidated Statements of Cash Flows for the Years  Ended December 31, 2007, 2006 and 2005

70

Consolidated Statements of Shareholders'  Equity for the Years Ended December 31, 2007, 2006

and  2005

71

Consolidated Statements of Comprehensive Income  for the Years Ended December 31, 2007,

2006  and 2005

72

** **

Idaho Power Company

Consolidated Statements of Income for the Years  Ended December 31, 2007, 2006 and 2005

73

Consolidated Balance Sheets as of December 31, 2007  and 2006

74-75

Consolidated Statements of Capitalization as of  December 31, 2007 and 2006

76

Consolidated Statements of Cash Flows for the  Years Ended December 31, 2007, 2006 and 2005

77

Consolidated Statements of Retained Earnings for  the Years Ended December 31, 2007, 2006

and  2005

78

Consolidated Statements  of Comprehensive Income for the Years Ended December 31, 2007,

2006  and 2005

78

Notes to the Consolidated Financial Statements

79-116

Reports of Independent Registered Public Accounting  Firm

117-118

** **

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

Supplemental Financial Information (Unaudited)

119

Financial  Statement Schedules for the Years Ended December 31, 2007, 2006 and 2005:

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

136-137

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

138

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

139

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**IDACORP, Inc.**

**ConsolidatedStatements of Income**

** **

** Year Ended December 31,**

** **

** 2007**

** 2006**

** 2005**

** (thousands of dollars except for per**

**Operating Revenues:**

** share amounts)**

Electric utility:

General  business

 $

668,303  

 $

636,375  

 $

667,270  

Off-system  sales

154,948  

260,717  

142,794  

Other  revenues

52,150  

23,381  

27,619  

Total  electric utility revenues

875,401  

920,473  

837,683  

Other

3,993  

5,818  

5,181  

Total  operating revenues

879,394  

926,291  

842,864  

**Operating Expenses:**

Electric utility:

Purchased  power

289,484  

283,440  

222,310  

Fuel  expense

134,322  

115,018  

103,164  

Power  cost adjustment

(121,131)

(29,526)

(2,995)

Other  operations and maintenance

286,510  

264,810  

242,381  

Demand-side  management

13,487  

-  

-  

Gain  on sale of emission allowances

(2,754)

(8,257)

(1,172)

Depreciation

103,072  

99,824  

101,485  

Taxes  other than income taxes

17,634  

18,661  

20,856  

Total  electric utility expenses

720,624  

743,970  

686,029  

Other expense

6,692  

12,617  

2,182  

Total  operating expenses

727,316  

756,587  

688,211  

**Operating Income (Loss):**

Electric utility

154,777  

176,503  

151,654  

Other

(2,699)

(6,799)

2,999  

Total  operating income

152,078  

169,704  

154,653  

**Other Income**

20,524  

18,195  

17,121  

**Losses of Unconsolidated  Equity-Method Investments**

(4,824)

(2,913)

(713)

**Other Expense**

8,434  

8,559  

8,006  

**Interest Expense:**

Interest on long-term debt

59,961  

56,402  

56,930  

Other interest

3,380  

4,573  

2,799  

Total  interest expense

63,341  

60,975  

59,729  

**Income Before Income  Taxes**

96,003  

115,452  

103,326  

**Income Tax Expense**

13,731  

15,377  

17,610  

**Income from Continuing  Operations**

82,272  

100,075  

85,716  

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

67  

7,328  

(22,055)

**Net Income**

 $

82,339  

 $

107,403  

 $

63,661  

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

44,151  

42,713  

42,279  

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

44,291  

42,874  

42,362  

**Earnings Per Share of  Common Stock:**

Earnings per share from  Continuing Operations-Basic

 $

1.86  

 $

2.34  

 $

2.03  

Earnings (loss) per share  from Discontinued Operations-Basic

-    

0.17  

(0.52)

Earnings  Per Share of Common Stock-Basic

 $

1.86  

 $

2.51  

 $

1.51  

Earnings per share from  Continuing Operations-Diluted

 $

1.86  

 $

2.34  

 $

2.02  

Earnings (loss) per share  from Discontinued Operations-Diluted

-    

0.17  

(0.52)

Earnings  Per Share of Common Stock-Diluted

 $

1.86  

 $

2.51  

 $

1.50  

**Dividends Paid Per Share  of Common Stock**

 $

1.20  

 $

1.20  

 $

1.20  

 The accompanying notes are an integral part of  these statements. 

** **

** **

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**IDACORP, Inc.**

**Consolidated Balance Sheets**

** **

** December 31,**

** **

** 2007**

** 2006**

**Assets**

** (thousands of dollars)**

**Current Assets:**

Cash and cash equivalents

 $

7,966  

 $

9,892  

Receivables:

Customer

69,160  

62,131  

Allowance  for uncollectible accounts

(7,505)

(7,168)

Employee  notes

2,128  

2,569  

Other

10,957  

11,855  

Energy marketing assets

-  

12,069  

Accrued unbilled revenues

36,314  

31,365  

Materials and supplies (at  average cost)

43,270  

39,079  

Fuel stock (at average  cost)

17,268  

15,174  

Prepayments

9,371  

9,308  

Deferred income taxes

25,672  

28,035  

Refundable income tax  deposit

46,083  

44,903  

Other

6,023  

3,993  

Assets held for sale

-  

3,326  

Total  current assets

266,707  

266,531  

**Investments**

201,085  

202,825  

**Property, Plant and  Equipment:**

Utility plant in service

3,796,339  

3,583,694  

Accumulated provision for  depreciation

(1,468,832)

(1,406,210)

Utility  plant in service - net

2,327,507  

2,177,484  

Construction work in  progress

257,590  

210,094  

Utility plant held for  future use

3,366  

2,810  

Other property, net of  accumulated depreciation

28,089  

28,692  

Property,  plant and equipment - net

2,616,552  

2,419,080  

**Other Assets:**

American Falls and Milner  water rights

29,501  

30,543  

Company-owned life  insurance

30,842  

34,055  

Regulatory assets

449,668  

423,548  

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

3,583  

3,802  

Employee notes

2,325  

2,411  

Other

53,045  

41,259  

Assets held for sale

-  

21,076  

Total  other assets

568,964  

556,694  

**Total**

 $

3,653,308  

 $

3,445,130  

 The accompanying notes are an integral part of  these statements. 

** **

** **

** **

** **

** **

** **

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**IDACORP, Inc.**

**Consolidated BalanceSheets**

** **

** December 31,**

** **

** 2007**

** 2006**

**Liabilities and  Shareholders' Equity**

** (thousands of dollars)**

** **

**Current Liabilities:**

Current maturities of  long-term debt

 $

11,456  

 $

95,125  

Notes payable

186,445  

129,000  

Accounts payable

85,116  

86,440  

Energy marketing  liabilities

-  

13,532  

Taxes accrued

8,492  

47,402  

Interest accrued

18,913  

12,657  

Uncertain tax positions

26,764  

-  

Other

38,129  

23,572  

Liabilities held for sale

-  

2,606  

Total  current liabilities

375,315  

410,334  

**Other Liabilities:**

Deferred income taxes

466,182  

498,512  

Regulatory liabilities

274,204  

294,844  

Other

173,412  

179,836  

Liabilities held for sale

-  

8,773  

Total  other liabilities

913,798  

981,965  

**Long-Term Debt**

1,156,880  

928,648  

** **

**Commitments and  Contingencies (Note 7)**

** **

**Shareholders' Equity:**

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

45,063,107  and 43,905,458 shares issued, respectively)

675,774  

638,799  

Retained earnings

537,699  

493,363  

Accumulated other  comprehensive loss

(6,156)

(5,737)

Treasury stock (380 and  71,570 shares at cost, respectively)

(2)

(2,242)

Total  shareholders' equity

1,207,315  

1,124,183  

**Total**

 $

3,653,308  

 $

3,445,130  

 The accompanying notes are an integral part of  these statements. 

** **

** **

** **

** **

** **

** **

** **

** **

** **

** **

** **

** **

** **

** **

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Table ofContents

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

** **

**Year Ended December 31,**

**2007**

**2006**

**2005**

**Operating Activities:**

**(thousands of dollars)**

Net income

$

82,339  

$

107,403  

$

63,661  

    Adjustments to reconcile  net income to net cash provided by                           

operating  activities:

Depreciation  and amortization

120,368  

122,641  

124,124  

Deferred  income taxes and investment tax credits

11,026  

(17,332)

(31,769)

Changes  in regulatory assets and liabilities

(128,089)

(17,133)

7,275  

Non-cash  pension expense

6,868  

-  

-  

Undistributed  earnings of subsidiaries

(6,273)

(9,553)

(16,762)

    Gain on sale of assets

(4,758)

(25,658)

(2,128)

    Impairment of goodwill

-  

-  

10,270  

    Impairment of long-lived  asset

-  

2,047  

-  

    Other non-cash  adjustments to net income

(2,915)

(3,395)

(15,073)

    Excess tax benefit from  share-based payment arrangements

(68)

(1,411)

-  

Change  in:

Accounts  receivable and prepayments

(10,284)

24,304  

(6,436)

Accounts  payable and other accrued liabilities

2,206  

6,725  

1,821  

Taxes  accrued

(9,466)

(24,099)

26,412  

Other  current assets

(11,159)

(4,829)

(14,360)

Other  current liabilities

15,551  

(3,465)

794  

 Other  assets

2,157  

3,334  

(514)

 Other  liabilities

13,098  

10,199  

14,181  

Net  cash provided by operating activities

80,601  

169,778  

161,496  

**Investing Activities:**

Additions to property, plant  and equipment

(287,751)

(225,048)

(193,314)

Proceeds from the sale of  ITI

-  

21,469  

-  

Proceeds from the sale of  IDACOMM

7,283  

-  

-  

Investments in affordable  housing

348  

(5,059)

(4,992)

Proceeds from the sale of  emission allowances

19,846  

11,323  

70,757  

Investments in  unconsolidated affiliates

(8,535)

(16,030)

-  

Purchase of  available-for-sale securities

(24,349)

(17,979)

(85,334)

Proceeds from the sale of  available-for-sale securities

26,110  

20,778  

120,026  

Purchase of held-to-maturity  securities

(3,116)

(2,730)

(2,181)

Maturity of held-to-maturity  securities

3,317  

4,647  

2,840  

Refundable deposit for tax  related liabilities

-  

(44,903)

-  

Other assets

(263)

492  

3,248  

Net  cash used in investing activities

(267,110)

(253,040)

(88,950)

**Financing Activities:**

Issuance of long-term debt 

240,000  

116,300  

64,992  

Retirement of long-term debt

(95,033)

(132,642)

(83,067)

Dividends on common stock

(53,012)

(51,272)

(50,690)

Net change in short-term  borrowings

57,445  

68,900  

23,830  

Issuance of common stock

37,181  

41,465  

6,296  

Acquisition of treasury  stock

(346)

(213)

-  

Excess tax benefit from  share-based payment arrangements

68  

1,411  

-  

Other assets

(337)

(3,058)

(4,486)

Other

(1,383)

(93)

(468)

Net  cash provided by (used in) financing activities

184,583  

40,798  

(43,593)

Net increase (decrease) in  cash and cash equivalents

(1,926)

(42,464)

28,953  

Cash and cash equivalents at  beginning of year

9,892  

52,356  

23,403  

Cash and cash equivalents at  end of year

$

7,966  

$

9,892  

$

52,356  

**Supplemental Disclosure  of Cash Flow Information:**

Cash paid during the year  for:

Income  taxes

$

3,021  

$

54,522  

$

18,937  

Interest  (net of amount capitalized)

$

62,031  

$

60,353  

$

57,466  

Non-cash investing  activities

Additions  to property, plant and equipment in accounts payable

$

13,210  

$

8,299  

$

8,634  

The accompanying notes are an integral part of these  statements.

** **

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** **

**IDACORP,Inc.**

**Consolidated Statements of Shareholders' Equity**

** **

** **

** **

** **

**Accumulated**

 
** **

** **

** **

** **

**Other**

 
** **

** **

** **

**Comprehensive**

 
**Common Stock**

**Retained**

**Income**

**Treasury Stock**

**Total**

 
**Shares**

**Amount**

**Earnings**

**(Loss)**

**Shares**

**Amount**

**Amount**

 
**(thousands)**

 
 
Balance at January 1, 2005

42,374  

 $

589,440  

 $

424,312  

 $

(888)

157  

 $

(4,578)

 $

1,008,286  

 
 
Net Income

-  

-  

63,661  

-  

-  

-  

63,661  

 
Common stock dividends  ($1.20 per share)

-  

-  

(50,690)

-  

-  

-  

(50,690)

 
Issued

282  

8,204  

-  

-  

(14)

431  

8,635  

 
Acquired

-  

-  

-  

-  

75  

(2,268)

(2,268)

 
Other

-  

1,062  

1  

-  

21  

(899)

164  

 
Unrealized loss on  securities (net of tax)

-  

-  

-  

(1,812)

-  

-  

(1,812)

 
Minimum pension liability  adjustment (net of tax)

-  

-  

-  

(725)

-  

-  

(725)

 
 
Balance at December 31, 2005

42,656  

598,706  

437,284  

(3,425)

239  

(7,314)

1,025,251  

 
 
Net Income

-  

-  

107,403  

-  

-  

-  

107,403  

 
Common stock dividends  ($1.20 per share)

-  

-  

(51,323)

-  

-  

-  

(51,323)

 
Issued

1,188  

41,465  

-  

-  

(11)

348  

41,813  

 
Acquired

-  

-  

-  

-  

6  

(213)

(213)

 
Other

61  

(1,372)

(1)

-  

(162)

4,937  

3,564  

 
Unrealized loss on  securities (net of tax)

-  

-  

-  

(1,414)

-  

-  

(1,414)

 
Minimum pension liability  adjustment (net of tax)

-  

-  

-  

2,118  

-  

-  

2,118  

 
Adjustment upon adoption of  SFAS 158 (net of tax)

-  

-  

-  

(3,016)

-  

-  

(3,016)

 
 
Balance at December 31, 2006

43,905  

638,799  

493,363  

(5,737)

72  

(2,242)

1,124,183  

 
 
Net Income

-  

-  

82,339  

-  

-  

-  

82,339  

 
Common stock dividends  ($1.20 per share)

-  

-  

(53,138)

-  

-  

-  

(53,138)

 
Issued

1,142  

37,181  

-  

-  

(12)

330  

37,511  

 
Acquired

-  

-  

-  

-  

10  

(346)

(346)

 
Other

16  

(206)

(1)

-  

(70)

2,256  

2,049  

 
Unrealized loss on  securities (net of tax)

-  

-  

-  

(743)

-  

-  

(743)

 
Unfunded pension liability  adjustment (net of tax)

-  

-  

-  

324  

-  

-  

324  

 
Adjustment upon adoption of  FIN 48

-  

-  

15,136  

-  

-  

-  

15,136  

 
 
Balance at December 31, 2007

45,063  

 $

675,774  

 $

537,699  

 $

(6,156)

-  

 $

(2)

 $

1,207,315  

 
 
The accompanying notes are an integral part of these  statements.

** **

** **

** **

** **

** **

** **

** **

** **

** **

** **

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Table ofContents

** **

**IDACORP,Inc.**

**Consolidated Statements of Comprehensive Income**

**Year Ended December 31,**

**2007**

**2006**

**2005**

**(thousands of dollars)**

**Net Income**

 $

82,339  

 $

107,403  

 $

63,661  

**Other Comprehensive  Income (Loss):**

Unrealized gains (losses)  on securities:

Unrealized  holding gains (losses) arising during the year,

net  of tax of $114, $1,471 and ($96)

179  

2,355  

(457)

Reclassification  adjustment for gains included

in  net income, net of tax of ($592), ($2,250) and ($870)

(922)

(3,769)

(1,355)

Net  unrealized losses

(743)

(1,414)

(1,812)

Unfunded pension liability  adjustment, net of tax

 of  $208, $1,359 and ($465)

324  

2,118  

(725)

**Total Comprehensive  Income**

 $

81,920  

 $

108,107  

 $

61,124  

The accompanying notes are an integral part of these  statements.

** **

72

Table ofContents

** **

**IdahoPower Company**

**Consolidated Statements of Income**

** **

** Year Ended December 31,**

** **

** 2007**

** 2006**

** 2005**

** **

** (thousands of dollars)**

**Operating Revenues:**

General business

 $

668,303  

 $

636,375  

 $

667,270  

Off-system sales

154,948  

260,717  

142,794  

Other revenues

52,150  

23,381  

27,619  

Total  operating revenues

875,401  

920,473  

837,683  

** **

**Operating Expenses:**

Operation:

Purchased  power

289,484  

283,440  

222,310  

Fuel  expense

134,322  

115,018  

103,164  

Power  cost adjustment

(121,131)

(29,526)

(2,995)

Other

218,347  

200,090  

182,842  

Demand-side  management

13,487  

-  

-  

Gain  on sale of emission allowances

(2,754)

(8,257)

(1,172)

Maintenance

68,163  

64,720  

59,539  

Depreciation

103,072  

99,824  

101,485  

Taxes other than income  taxes

17,634  

18,661  

20,856  

Total  operating expenses

720,624  

743,970  

686,029  

**Income from Operations**

154,777  

176,503  

151,654  

** **

**Other Income (Expense):**

Allowance for equity funds  used during construction

5,995  

6,092  

4,950  

Earnings of unconsolidated  equity-method investments

5,553  

9,347  

10,369  

Other income

12,636  

10,578  

11,476  

Other expense

(8,215)

(8,701)

(8,610)

Total  other income

15,969  

17,316  

18,185  

**Interest Charges:**

Interest on long-term debt

58,097  

53,744  

53,339  

Other interest

8,281  

6,211  

3,527  

Allowance for borrowed  funds used during construction

(7,597)

(4,026)

(2,791)

Total  interest charges

58,781  

55,929  

54,075  

**Income Before Income  Taxes**

111,965  

137,890  

115,764  

**Income Tax Expense**

35,386  

43,961  

43,925  

**Net Income**

 $

76,579  

 $

93,929  

 $

71,839  

** **

 The accompanying notes are an integral part of these  statements. 

** **

** **

** **

** **

** **

** **

73

Table ofContents

** **

**IdahoPower CompanyConsolidated Balance Sheets**

** **

**Assets**

** December 31, **

** 2007**

** 2006**

** (thousands of dollars)**

**Electric Plant:**

In service (at original  cost)

 $

3,796,339  

 $

3,583,694  

Accumulated provision for  depreciation

(1,468,832)

(1,406,210)

In  service - net

2,327,507  

2,177,484  

Construction work in  progress

257,590  

210,094  

Held for future use

3,366  

2,810  

Electric  plant - net

2,588,463  

2,390,388  

**Investments and Other  Property**

105,074  

91,244  

** **

**Current Assets:**

Cash and cash equivalents

5,347  

2,404  

Receivables:

Customer

62,122  

54,218  

Allowance  for uncollectible accounts

(1,305)

(968)

Notes

517  

514  

Employee  notes

2,128  

2,569  

Other

7,605  

10,592  

Accrued unbilled revenues

36,314  

31,365  

Materials and supplies (at  average cost)

43,270  

39,078  

Fuel stock (at average  cost)

17,268  

15,174  

Prepayments

9,120  

8,952  

Deferred income taxes

4,074  

-  

Refundable income tax  deposit

44,316  

-  

Other

1,067  

1,480  

Total  current assets

231,843  

165,378  

**Deferred Debits:**

American Falls and Milner  water rights

29,501  

30,543  

Company-owned life  insurance

30,842  

34,055  

Regulatory assets

449,668  

423,548  

Employee notes

2,325  

2,411  

Other

51,800  

40,158  

Total  deferred debits

564,136  

530,715  

**Total**

 $

3,489,516  

 $

3,177,725  

 The accompanying notes are an integral part of  these statements. 

** **

** **

** **

** **

** **

** **

** **

** **

** **

74

Table ofContents

** **

**IdahoPower Company**

**ConsolidatedBalance Sheets**

** **

**Capitalization and  Liabilities**

** December 31, **

** **

** 2007**

** 2006**

** **

** (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

581,758  

530,758  

Capital  stock expense

(2,097)

(2,097)

Retained  earnings

442,300  

404,076  

Accumulated  other comprehensive loss

(6,156)

(5,737)

Total  common stock equity

1,113,682  

1,024,877  

Long-term debt

1,141,508  

902,884  

Total  capitalization

2,255,190  

1,927,761  

**Current Liabilities:**

Long-term debt due within  one year

1,064  

81,064  

Notes payable

136,585  

52,200  

Accounts payable

84,457  

85,714  

Notes and accounts payable  to related parties

724  

1,111  

Taxes accrued

2,403  

41,688  

Interest accrued

18,761  

12,324  

Uncertain tax positions

26,764  

-  

Other

36,907  

24,384  

Total  current liabilities

307,665  

298,485  

**Deferred Credits:**

Deferred income taxes

488,768  

489,234  

Regulatory liabilities

274,204  

294,844  

Other

163,689  

167,401  

Total  deferred credits

926,661  

951,479  

**Commitments and  Contingencies (Note 7)**

**Total**

 $

3,489,516  

 $

3,177,725  

 The accompanying notes are an integral part of these  statements. 

** **

** **

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** **

**IdahoPower Company**

**Consolidated Statements of Capitalization**

** **

**December 31,**

** **

**December 31,**

** **

**2007**

**%**

**2006**

**%**

**(thousands of dollars)**

**Common Stock Equity:**

** **

** **

** **

** **

Common  stock

 $

97,877  

 $

97,877  

Premium  on capital stock

581,758  

530,758  

Capital  stock expense

(2,097)

(2,097)

Retained  earnings

442,300  

404,076  

Accumulated  other comprehensive loss

(6,156)

(5,737)

Total  common stock equity

1,113,682  

49  

1,024,877  

53  

** **

**Long-Term Debt:**

First  mortgage bonds:

7.38%  Series due 2007

-  

80,000  

7.20%  Series due 2009

80,000  

80,000  

6.60%  Series due 2011

120,000  

120,000  

4.75%  Series due 2012

100,000  

100,000  

4.25%  Series due 2013

70,000  

70,000  

6     % Series due 2032

100,000  

100,000  

5.50%  Series due 2033

70,000  

70,000  

5.50%  Series due 2034

50,000  

50,000  

5.875%  Series due 2034

55,000  

55,000  

5.30%  Series due 2035

60,000  

60,000  

6.30%  Series due 2037

140,000  

-  

6.25%  Series due 2037

100,000  

-  

Total  first mortgage bonds

945,000  

785,000  

Amount  due within one year

-  

(80,000)

Net  first mortgage bonds

945,000  

705,000  

** **

Pollution  control revenue bonds:

Variable  Auction Rate Series 2003 due 2024

49,800  

49,800  

Variable  Auction Rate Series 2006 due 2026 

116,300  

116,300  

Variable  Rate Series 2000 due 2027

4,360  

4,360  

Total  pollution control revenue bonds

170,460  

170,460  

American  Falls bond guarantee

19,885  

19,885  

Milner  Dam note guarantee

10,636  

11,700  

Note  guarantee due within one year

(1,064)

(1,064)

Unamortized  premium/discount - net

(3,409)

(3,097)

** **

Total  long-term debt

1,141,508  

51  

902,884  

47  

** **

**Total  Capitalization**

 $

2,255,190  

100  

 $

1,927,761  

100  

** **

 The accompanying notes are an integral part of  these statements. 

** **

** **

** **

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** **

**IdahoPower Company**

**Consolidated Statements of Cash Flows**

** **

**Year Ended December 31,**

** **

**2007**

**2006**

**2005**

** **

**(thousands of dollars)**

**Operating Activities:**

** **

** **

Net income

 $

76,579  

 $

93,929  

 $

71,839  

Adjustments to reconcile  net income to net cash provided by

   

operating  activities:

Depreciation  and amortization

107,500  

105,464  

107,919  

Deferred  income taxes and investment tax credits

36,258  

(13,473)

(34,729)

Changes  in regulatory assets and liabilities

(128,089)

(17,133)

7,275  

Non-cash  pension expense

6,868  

-  

-  

Undistributed  earnings of subsidiary

(5,553)

(9,347)

(16,669)

Gain  on sale of assets

(4,589)

(11,751)

(672)

Impairment  of assets

-  

2,047  

-  

Other  non-cash adjustments to net income

(5,660)

(5,853)

(5,480)

Change  in:

Accounts  receivables and prepayments

(13,298)

3,596  

5,290  

Accounts  payable

3,654  

6,623  

2,578  

Taxes  accrued

(12,862)

(30,235)

30,766  

Other  current assets

(11,234)

(4,767)

(14,503)

Other  current liabilities

15,751  

(2,310)

1,269  

Other  assets

2,147  

3,332  

(698)

Other  liabilities

14,000  

10,997  

11,840  

Net  cash provided by operating activities

81,472  

131,119  

166,025  

**Investing Activities:**

Additions to utility plant

(287,219)

(221,840)

(185,865)

Purchase of  available-for-sale securities

(24,349)

(17,979)

(85,334)

Proceeds from the sale of  available-for-sale securities

26,110  

20,778  

120,026  

Proceeds from the sale of  emission allowances

19,846  

11,323  

70,758  

Investments in  unconsolidated affiliate

(8,675)

(16,030)

-  

Refundable income tax  deposits

(43,927)

-  

-  

Other assets

(263)

497  

1,181  

Net  cash used in investing activities

(318,477)

(223,251)

(79,234)

**Financing Activities:**

Issuance of long-term debt

240,000  

116,300  

60,000  

Retirement of long-term  debt

(81,064)

(116,300)

(60,000)

Dividends on common stock

(53,491)

(51,109)

(50,690)

Net change in short term  borrowings

84,385  

52,200  

-  

Capital contribution from  parent

51,000  

47,050  

-  

Other assets

(336)

(3,058)

(4,445)

Other

(546)

118  

-  

Net  cash provided by (used in) financing activities

239,948  

45,201  

(55,135)

Net increase (decrease) in  cash and cash equivalents

2,943  

(46,931)

31,656  

Cash and cash equivalents  at beginning of year

2,404  

49,335  

17,679  

Cash and cash equivalents  at end of year

 $

5,347  

 $

2,404  

 $

49,335  

**Supplemental Disclosure  of Cash Flow Information:**

Cash paid during the year  for:

Income  taxes paid to parent

 $

2,877  

 $

86,311  

 $

48,545  

Interest  (net of amount capitalized)

 $

57,355  

 $

55,501  

 $

51,290  

Non-cash investing  activities:

Additions  to utility plant in accounts payable

 $

13,210  

 $

8,299  

 $

8,634  

The accompanying notes are an integral part of these  statements.

** **

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** **

**IdahoPower Company**

**Consolidated Statements of Retained Earnings**

**Year Ended December 31,**

**2007**

**2006**

**2005**

**(thousands of dollars)**

**Retained Earnings,  Beginning of Year**

 $

404,076  

 $

361,256  

 $

340,107  

**Net Income**

76,579  

93,929  

71,839  

** **

**Cumulative effect of  accounting change (adoption of FIN 48)**

15,136  

-  

-  

**Dividends on common  stock**

(53,491)

(51,109)

(50,690)

**Retained Earnings, End  of Year**

 $

442,300  

 $

404,076  

 $

361,256  

The accompanying notes are an integral part of these  statements.

** **

**IdahoPower Company**

**Consolidated Statements Comprehensive Income**

**Year Ended December 31,**

**2007**

**2006**

**2005**

**(thousands of dollars)**

**Net Income**

 $

76,579  

 $

93,929  

 $

71,839  

**Other Comprehensive  Income (Loss):**

Unrealized gains (losses)  on securities:

Unrealized  holding gains (losses) arising during the year,

net  of tax of $114, $1,471 and ($96)

179  

2,355  

(457)

Reclassification  adjustment for gains included

in  net income, net of tax of ($592) ,($2,250) and ($870)

(922)

(3,769)

(1,355)

Net  unrealized losses

(743)

(1,414)

(1,812)

Unfunded pension liability  adjustment, net of tax

 of  $208, $1,359 and ($465)

324  

2,118  

(725)

**Total Comprehensive  Income**

 $

76,160  

 $

94,633  

 $

69,302  

The accompanying notes are an integral part of these  statements.

** **

** **

** **

** **

** **

** **

** **

** **

** **

** **

** **

** **

** **

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** **

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

**1.  SUMMARY OF SIGNIFICANTACCOUNTING POLICIES:**

This Annual Report on Form 10-Kis a combined report of IDACORP, Inc. (IDACORP) and Idaho Power Company (IPC). Therefore, the Notes to the Consolidated Financial Statements apply to bothIDACORP and IPC.  However, IPC makes no representation as to the informationrelating to IDACORP's other operations.

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

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

IDACORP's other subsidiariesinclude:
- IDACORP Financial Services,     Inc. (IFS), an investor in affordable housing and other real estate     investments;
- Ida-West Energy Company     (Ida-West), an operator of small     hydroelectric generation projects that satisfy the requirements of the     Public Utility Regulatory Policies Act of 1978 (PURPA); and
- IDACORP Energy (IE), a     marketer of energy commodities, which wound down operations in 2003.

In the second quarter of2006, IDACORP management designated the operations of IDACORP Technologies,Inc. (ITI) and IDACOMM as assets held for sale, as defined by Statement ofFinancial Accounting Standards No. 144, *"Accounting for the Impairment orDisposal of Long-Lived Assets"* (SFAS 144).  IDACORP's consolidatedfinancial statements reflect the reclassification of the results of thesebusinesses as discontinued operations for all periods presented.  Discontinuedoperations are discussed in more detail in Note 16.  On July 20, 2006, IDACORPcompleted the sale of all of the outstanding common stock of ITI to IdaTech UKLimited, a wholly-owned subsidiary of Investec Group Investments (UK) Limited. On February 23, 2007, IDACORP completed the sale of all of the outstandingcommon stock of IDACOMM to American Fiber Systems, Inc.

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

The entities that IDACORP andIPC consolidate consist primarily of wholly-owned or controlled subsidiaries. In addition, IDACORP consolidates the following VIEs in accordance withFinancial Accounting Standards Board Interpretation No. 46(R), *"Consolidationof Variable Interest Entities - an interpretation of ARB No. 51:"*
- Ida-West participates in     Marysville Hydro Partners, a joint venture that owns a small hydroelectric     project.  Marysville Hydro Partners has approximately $21 million of     assets, primarily the hydroelectric plant, and approximately $17 million     of intercompany long-term debt, which is eliminated in consolidation.

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

Through IFS, IDACORP alsoholds significant variable interests in VIEs for which it is not the primarybeneficiary.  These VIEs are historic rehabilitation and affordable housingdevelopments in which IFS holds limited partnership interests ranging from fiveto 99 percent.  These investments were acquired between 1996 and 2006.  IFS'smaximum exposure to loss in these developments totaled $78 million at December31, 2007.

**Management Estimates**Management makes estimates andassumptions when preparing financial statements in conformity with accountingprinciples generally accepted in the United States of America.  These estimatesand assumptions include those related to rate regulation, benefit costs,contingencies, litigation, asset impairment, income taxes, unbilled revenuesand bad debt.  These estimates and assumptions affect the reported amounts ofassets and liabilities and the disclosure of contingent assets and liabilitiesat the date of the financial statements, and the reported amounts of revenuesand expenses during the reporting period.  These estimates involve judgmentswith respect to, among other things, future economic factors that are difficultto predict and are beyond management's control.  As a result, actual resultscould differ from those estimates.

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

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

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

The effects of applying SFAS71 are discussed in more detail in Note 6 - "Regulatory Matters."

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

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

** **

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

All utility plant in serviceis depreciated using the straight-line method at rates approved by regulatoryauthorities.  Annual depreciation provisions as a percent of averagedepreciable utility plant in service approximated 2.95 percent in 2007, 2.75percent in 2006 and 2.91 percent in 2005.

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

**Allowance for Funds UsedDuring Construction**AFDC represents the cost of financingconstruction projects with borrowed funds and equity funds.  While cash is notrealized currently from such allowance, it is realized under the rate-makingprocess over the service life of the related property through increasedrevenues resulting from a higher rate base and higher depreciation expense. The component of AFDC attributable to borrowed funds is included as a reductionto interest expense, while the equity component is included in other income. IPC's weighted-average monthly AFDC rates for 2007, 2006 and 2005 were 6.8percent, 7.6 percent and 7.4 percent, respectively.  IPC's reductions tointerest expense for AFDC were $8 million for 2007, $4 million for 2006 and $3million for 2005.  Other income included $6 million, $6 million and $5 millionof AFDC for 2007, 2006 and 2005, respectively.

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

**Revenues**Operating revenues for IPC related tothe sale of energy are generally recorded when service is rendered or energy isdelivered to customers.  IPC accruesunbilled revenues for electric services delivered to customers but not yetbilled at period-end.  IPC collects franchise fees and similar taxes related toenergy consumption.  These amounts are recorded as liabilities until paid tothe taxing authority.  None of these collections are reported on the incomestatement as revenue or expense.

**Income Taxes**IDACORP and IPC account for incometaxes under the asset and liability method, which requires the recognition ofdeferred tax assets and liabilities for the expected future tax consequences ofevents that have been included in the financial statements.  Under this method,deferred tax assets and liabilities are determined based on the differencesbetween the financial statements and tax basis of assets and liabilities usingenacted tax rates in effect for the year in which the differences are expectedto reverse.  The effect of a change in tax rates on deferred tax assets andliabilities is recognized in income in the period that includes the enactmentdate.

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

The state of Idaho allows athree-percent investment tax credit on qualifying plant additions.  Investmenttax credits earned on regulated assets are deferred and amortized to incomeover the estimated service lives of the related properties.  Credits earned onnon-regulated assets or investments are recognized in the year earned.

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

** **

**Year ended December 31,**

** **

**2007**

** **

**2006**

** **

**2005**

Numerator:

Income from continuing  operations

$

82,272

$

100,075

$

85,716

Denominator:

Weighted-average shares  outstanding - basic*

44,151

42,713

42,279

Effect of dilutive  securities:

Options

45

93

49

Restricted Stock

95

68

34

Weighted-average shares  outstanding - diluted

44,291

42,874

42,362

Basic earnings per share  from continuing operations

$

1.86

$

2.34

$

2.03

Diluted earnings per share  from continuing operations

$

1.86

$

2.34

$

2.02

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

The diluted EPS computationexcluded 487,100 options in 2007, 538,950 options in 2006, and 1,014,437 in2005, because the options' exercise prices were greater than the average marketprice of the common stock during those years.  In total, 818,232 options wereoutstanding at December 31, 2007, with expiration dates between 2010 and 2015.

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

IDACORP's and IPC'sConsolidated Statements of Income for the year ended December 31, 2005, do notreflect any changes from the adoption of SFAS 123(R).  In those years, stockbased employee compensation was accounted for under the recognition andmeasurement principles of Accounting Principles Board (APB) Opinion 25, *"Accountingfor Stock Issued to Employees,"* and related interpretations.

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

**IDACORP**

** **

**IPC**

** **

Net income, as reported

$

63,661

$

71,839

Add: Stock-based employee  compensation expense

included in reported net  income, net of related tax effects

359

108

Deduct: Stock-based  employee compensation expense determined

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

1,214

568

Pro forma net income

$

62,806

$

71,379

EPS of common stock:

Basic - as reported

$

1.51

Diluted - as reported

$

1.50

Basic - pro forma

$

1.49

Diluted - pro forma

$

1.48

** **

** **

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

**Comprehensive Income**Comprehensive income includes netincome, unrealized holding gains and losses on available-for-sale marketablesecurities and amounts related to a deferred compensation plan for certainsenior management employees and directors.  The following table presentsIDACORP's and IPC's accumulated other comprehensive loss balance at December 31(net of tax):

**2007**

** **

**2006**

**(thousands of dollars)**

Unrealized holding gains on  available-for-sale securities

$

568 

$

1,311 

Deferred compensation plan

(6,724)

(7,048)

Total

$

(6,156)

$

(5,737)

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

**Reclassifications**Certain items previously reported foryears prior to 2007 have been reclassified to conform to the current year'spresentation.  Net income and shareholders' equity were not affected by these reclassifications.

**New AccountingPronouncements****SFAS 157:**  In September 2006, the FASB issued SFAS 157*, "Fair ValueMeasurements."*  SFAS 157 defines fair value, establishes a framework formeasuring fair value in generally accepted accounting principles, and expandsdisclosures about fair value measurements.  SFAS 157 is effective for financialstatements issued for fiscal years beginning after November 15, 2007, andinterim periods within those fiscal years.  IDACORP and IPC adopted SFAS 157 onJanuary 1, 2008, and IDACORP and IPC do not expect SFAS 157 to have a materialimpact on IDACORP's or IPC's financial statements.****

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**SFAS 159:**  In February 2007, the FASB issued SFAS No. 159, *"TheFair Value Option for Financial Assets and Financial Liabilities - Including anAmendment of FASB Statement No. 115"*(SFAS 159).  This standard permits anentity to choose to measure many financial instruments and certain other itemsat fair value.  Most of the provisions in SFAS 159 are elective; however, theamendment to SFAS No. 115, *"Accounting for Certain Investments in Debt andEquity Securities,"* applies to all entities with available-for-sale andtrading securities.  The fair value option established by SFAS 159 permits allentities to choose to measure eligible items at fair value at specifiedelection dates.  A business entity will report unrealized gains and losses onitems for which the fair value option has been elected in earnings at eachsubsequent reporting date.  The fair value option: (a) may be applied instrumentby instrument, with a few exceptions, such as investments otherwise accountedfor by the equity method; (b) is irrevocable (unless a new election dateoccurs); and (c) is applied only to entire instruments and not to portions ofinstruments.  SFAS 159 is effective as of the beginning of an entity's firstfiscal year that begins after November 15, 2007.  IDACORP and IPC adopted SFAS159 on January 1, 2008 and did not elect the fair value option for any existingeligible items.  However, IDACORP and IPC will continue to evaluate items on acase-by-case basis for consideration of the fair value option.

**SFAS 141(R):**In December 2007 the FASB issued SFAS 141(R), "*BusinessCombinations (Revised December 2007)." *SFAS 141(R) establishes principlesand requirements for how an acquirer in a business combination: 1) recognizesand measures in its financial statements the identifiable assets acquired, theliabilities assumed, and any noncontrolling interest in the acquiree; 2)recognizes and measures the goodwill acquired in the business combination or again from a bargain purchase; and 3) determines what information to disclose toenable users of the financial statements to evaluate the nature and financialeffects of the business combination.  SFAS 141(R) applies prospectively tobusiness combinations for which the acquisition date is on or after thebeginning of the first annual reporting period beginning on or after December15, 2008.  An entity may not apply it before that date.  IDACORP and IPC arecurrently evaluating the impact of SFAS 141(R).

**SFAS 160:** In December 2007 the FASB issued SFAS 160, *"NoncontrollingInterests in Consolidated Financial Statements*."  Among other things, SFAS160 establishes a standard for the way noncontrolling interests (also calledminority interests) are presented in consolidated financial statements andstandards for accounting for changes in ownership interests.  SFAS 160 iseffective for fiscal years beginning on or after December 15, 2008.  An entitymay not apply it before that date.  IDACORP and IPC are currently evaluatingthe impact of SFAS 160.

**FSP FIN 39-1:** In April 2007 the FASB issued FASB Staff Position No.FIN 39-1 (FSP FIN 39-1), "*Amendment of FASB Interpretation No. 39"* (FIN39).  FSP FIN 39-1 modifies FIN 39, "*Offsetting of Amounts Related toCertain Contracts*," and permits reporting entities to offset receivables orpayables recognized upon payment or receipt of cash collateral against fairvalue amounts recognized for derivative instruments that have been offset undera master netting arrangement.  FSP FIN 39-1 requires disclosure of a reportingentity's accounting policy (to offset or not offset) as well as amountsrecognized for the right to reclaim cash collateral, or the obligation toreturn cash collateral, that have been offset against net derivativepositions.  FSP FIN 39-1 is effective for fiscal years beginning after November15, 2007.  IDACORP and IPC adopted FSP FIN 39-1 on January 1, 2008 and itsadoption did not have a material impact on IDACORP's or IPC's financialstatements.

**EITF Issue No. 06-11:**  In June 2007, the FASB ratified Emerging Issues TaskForce Issue No. 06-11, *"Accounting for Income Tax Benefits of Dividends onShare-Based Payment Awards*" (EITF 06-11), which requires income tax benefitsfrom dividends or dividend equivalents that are charged to retained earningsand are paid to employees for equity classified awards and outstanding equityshare options to be recognized as an increase in additional paid-in capital andto be included in the pool of excess tax benefits available to absorb potentialfuture tax deficiencies on share-based payment awards.  EITF 06-11 becameeffective on January 1, 2008.  The adoption of EITF 06-11 is not expected tohave a material impact on IDACORP's or IPC's financial statements.

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**2. INCOME TAXES:**

Thecomponents of the net deferred tax liability are as follows:

** **

**IDACORP**

** **

**IPC**

** **

**2007**

** **

**2006**

** **

**2007**

** **

**2006**

** **

**(thousands of dollars)**

Deferred tax assets:

Regulatory liabilities

$

42,968

$

41,825

$

42,968

$

41,825

Advances  for construction

10,172

9,212

10,172

9,212

Deferred  compensation

17,800

15,295

16,423

14,381

Emission  allowances

6,921

12,175

6,921

12,175

Partnership  investments

572

308

572

308

Tax  credits

53,770

27,807

-

-

Retirement  benefits

20,753

26,392

20,753

26,392

Other

10,853

16,863

8,810

13,154

Total

163,809

149,877

106,619

117,447

Deferred  tax liabilities:

Property,  plant and equipment

227,337

230,361

227,337

230,361

Regulatory  assets

308,290

343,590

308,290

343,590

Conservation  programs

3,169

4,437

3,169

4,437

PCA

45,008

8,384

45,008

8,384

Partnership  investments

13,006

13,656

-

-

Retirement  benefits

6,945

18,055

6,945

18,055

Other

564

1,871

564

1,871

Total

604,319

620,354

591,313

606,698

Net  deferred tax liabilities

$

440,510

$

470,477

$

484,694

$

489,251

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

** **

**IDACORP**

** **

**IPC**

** **

**2007**

** **

**2006**

** **

**2005**

** **

**2007**

** **

**2006**

** **

**2005**

** **

**(thousands of dollars)**

Federal income tax expense  at 

35% statutory rate

$

33,601 

$

40,408 

$

36,165 

$

39,188 

$

48,262 

$

40,517 

Change in taxes resulting  from:

AFDC

(4,757)

(3,542)

(2,709)

(4,757)

(3,542)

(2,709)

Capitalized interest

2,289 

1,394 

929 

2,289 

1,394 

929 

Investment tax credits

(3,578)

(3,513)

(3,424)

(3,578)

(3,513)

(3,424)

Repair allowance

(2,450)

(2,450)

(1,750)

(2,450)

(2,450)

(1,750)

Removal costs

(3,787)

(1,912)

(1,490)

(3,787)

(1,912)

(1,490)

Pension accrual

1,022 

1,902 

1,276 

1,022 

1,902 

1,276 

Capitalized overhead costs

(4,200)

(2,940)

- 

(4,200)

(2,940)

- 

Tax accounting method change

- 

6,122 

- 

6,122 

- 

Uncertain tax positions

(3,586)

- 

- 

(3,586)

- 

- 

Settlement of prior years'  tax 

returns

- 

(7,465)

- 

- 

(8,144)

- 

State income taxes, net of 

federal benefit

5,810 

6,606 

7,147 

6,618 

7,820 

7,921 

Depreciation

7,576 

5,757 

5,603 

7,576 

5,757 

5,603 

Affordable housing and 

historic tax credits 

(14,541)

(19,218)

(20,205)

- 

- 

- 

Other, net

332 

(5,772)

(3,932)

1,051 

(4,795)

(2,948)

Total income tax expense 

$

13,731 

$

15,377 

$

17,610 

$

35,386 

$

43,961 

$

43,925 

Effective tax rate

14.3%

13.3%

17.0%

31.6%

31.9%

37.9%

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Table ofContents

Theitems comprising income tax expense are as follows:

** **

**IDACORP**

** **

**IPC**

** **

**2007**

** **

**2006**

** **

**2005**

** **

**2007**

** **

**2006**

** **

**2005**

** **

**(thousands of dollars)**

Income  taxes currently payable:

Federal

$

9,573 

$

28,712 

$

42,236 

$

8,916 

$

52,142 

$

69,479 

State

(3,105)

4,254 

8,097 

(6,202)

5,293 

9,176 

Total

6,468 

32,966 

50,333 

2,714 

57,435 

78,655 

Income  taxes deferred:

Federal

8,035 

(17,379)

(29,534)

28,148 

(14,161)

(31,599)

State

926 

(537)

(5,139)

6,223 

360 

(5,081)

Total

8,961 

(17,916)

(34,673)

34,371 

(13,801)

(36,680)

Uncertain  tax positions:

Federal

(3,345)

- 

- 

(3,345)

- 

- 

State

(241)

- 

- 

(241)

- 

- 

Total

(3,586)

- 

- 

(3,586)

- 

- 

Investment  tax credits:

Deferred

5,466 

3,840 

5,374 

5,465 

3,840  

5,374 

Restored

(3,578)

(3,513)

(3,424)

(3,578)

(3,513)

(3,424)

Total

1,888 

327 

1,950 

1,887 

327 

1,950 

Total  income tax expense 

$

13,731 

$

15,377 

$

17,610 

$

35,386 

$

43,961 

$

43,925 

IDACORP's tax allocationagreement provides that each member of its consolidated group compute itsincome taxes on a separate company basis.  Amounts payable or refundable aresettled through IDACORP.

**Tax Credits Carryforwards**As of December 31, 2007, IDACORP had$38.9 million of general business credit carryforward and $2.9 million ofalternative minimum tax credit carryforward for federal income tax purposes,and $11.9 million of Idaho investment tax credit carryforward.  The generalbusiness credit carryforward period expires from 2025 to 2027, the alternativeminimum tax credit carryforward has no expiration period, and the Idahoinvestment tax credit expires from 2019 to 2021.

**FIN 48**IDACORP AND IPC adopted FASBInterpretation No. 48, "*Accounting for Uncertainty in Income Taxes - aninterpretation of FASB Statement No. 109*" (FIN 48) on January 1, 2007, asrequired.  IPC recorded an increase of $15.1 million to opening retainedearnings for the cumulative effect of adopting FIN 48.  A reconciliation of thebeginning and ending amount of unrecognized tax benefits is as follows (inthousands of dollars):

Balance  at January 1, 2007

$

21,180 

Additions  for tax positions of prior years

848 

Reductions  for tax positions of prior years

(4,434)

Balance  at December 31, 2007

$

17,594 

Ifrecognized, the $17.6 million balance of unrecognized tax benefits would affectIPC's effective tax rate.

IPCis disputing the Internal Revenue Service's(IRS) disallowance of IPC's use of the simplified service cost method (SSCM) ofuniform capitalization for tax years 2001-2003.  The dispute is under reviewwith the IRS Appeals Office.  In December 2007, the Appeals Office informedIDACORP that the IRS had completed their review of IPC's SSCM settlementcomputations.  After evaluating the IRS review findings, IPC adjusted itsmeasurement for the SSCM uncertain tax position which resulted in a $4.4million reduction of the accrued liability for this item.  IDACORP expects thatthe appeals process and the U.S. Congress Joint Committee on Taxation reviewprocess will be completed during 2008.  The expected resolution would result ina decrease to IPC's unrecognized tax benefits of $13.6 million.  

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IDACORPand IPC recognize interest accrued related to unrecognized tax benefits asinterest expense and penalties as other expense.  FIN 48 allows companies tochange their accounting policy election for interest and penalties uponadoption of the standard.  IDACORP and IPC had classified interest as incometaxes prior to the adoption of FIN 48.  IPC's 2007 interest expense includes a$1 million net reduction for interest related to unrecognized tax benefits. The reduction was due primarily to the decrease in IPC's interest accrual forthe SSCM uncertain tax position.  As of December 31, 2007, IPC had accruedinterest of $5.5 million.  No penalties are accrued.

IDACORP and IPC are subjectto examination by their major tax jurisdictions - U.S. federal and state ofIdaho - for tax years 2004 through 2006.  The IRS began its examination ofthese years in November 2007.  IDACORP and IPC are unable to predict theoutcome of this examination.

**3.  COMMON STOCK AND STOCK-BASEDCOMPENSATION:**

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

**Shares issued**

**Shares reserved at**

**2007**

**2006**

**2005**

**December 31, 2007**

Dividend reinvestment and  stock purchase plan

150,458

145,508

146,684

3,282,548

Employee savings plan

99,562

99,248

56,569

2,081,737

Restricted stock plan

-

-

-

314,114

Long-term incentive and  compensation plan

26,292

467,791

79,383

2,519,134

Continuous equity program

881,337

536,518

-

1,082,145

Total

1,157,649

1,249,065

282,636

9,279,678

** **

On December 15, 2005, IDACORPentered into a Sales Agency Agreement with BNY Capital Markets, Inc. (BNYCMI). Under the terms of the Sales Agency Agreement, IDACORP may offer and sell up to2,500,000 shares of its common stock, from time to time in at-the-marketofferings through BNYCMI, as IDACORP's agent for such offer and sale.  In 2007,IDACORP issued 881,337 shares of common stock in at-the-market offerings at anaverage price of $32.32.  In 2006, IDACORP issued 536,518 shares of commonstock in at-the-market offerings at an average price of $39.24 per share.

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

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

Following the acquisition ofa 20 percent or greater position, each Right will entitle its holder topurchase, for $95, that number of shares of common stock or preferred stockhaving a market value of $190.  If after the Rights become exercisable, IDACORPis acquired in a merger or other business combination, 50 percent or more ofits consolidated assets or earnings power are sold, or the Acquiring Personengages in certain acts of self-dealing, each Right entitles the holder topurchase, for $95, shares of the acquiring company's common stock having amarket value of $190.  Any Rights that are or were held by an Acquiring Personbecome void if any of these events occurs.  The Rights expire on September 10,2008.

The Rights themselves do notgive their holders any voting or other rights as shareholders.  The terms ofthe Rights may be amended without the approval of any holders of the Rightsuntil an Acquiring Person obtains a 20 percent or greater position, and thenmay be amended as long as the amendment is not adverse to the interests of theholders of the Rights.

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Table ofContents

**Dividend Restrictions:**IPC's articles of incorporation contain restrictionson the payment of dividends on its common stock if preferred stock dividendsare in arrears.  IPC has no outstanding preferred stock.  Also, certainprovisions of credit facilities contain restrictions on the ratio of debt tototal capitalization.

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

**IPC Common Stock**In 2007 and 2006, IDACORP contributed$51 million and $47 million, respectively, of additional equity to IPC.  Noadditional shares of IPC common stock were issued.

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

The LTICP for officers, keyemployees and directors permits the grant of nonqualified stock options,incentive stock options, stock appreciation rights, restricted stock,restricted stock units, performance units, performance shares and otherawards.  The RSP permits only the grant of restricted stock or performance-basedrestricted stock.  At December 31, 2007, the maximum number of shares availableunder the LTICP and RSP were 1,611,355 and 108,595, respectively.

The following table shows thecompensation cost recognized in income and the tax benefits resulting fromthese plans, as well as the amounts allocated to IPC for those costs associatedwith IPC's employees (in thousands of dollars):

**IDACORP**

**IPC**

**2007**

**2006**

**2005**

**2007**

**2006**

**2005**

Compensation cost

$

2,745

$

2,692

$

589

$

2,473

$

1,458

$

178

Income tax benefit

$

1,073

$

1,053

$

230

$

967

$

570

$

70

No equity compensation costshave been capitalized.

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

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

The performance goals for the2007 awards are independent of each other and equally weighted, and are basedon two metrics, cumulative earnings per share (CEPS) and total shareholderreturn (TSR) relative to a peer group.  The fair value of the CEPS portion isbased on the market value at the date of grant, reduced by the loss in time-valueof the estimated future dividend payments, using an expected quarterly dividendof $0.30.  The fair value of the TSR portion is estimated using a statisticalmodel that incorporates the probability of meeting performance targets based onhistorical returns relative to the peer group.  Both performance goals aremeasured over the three-year vesting period and are charged to compensationexpense over the vesting period based on the number of shares expected to vest.

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Table ofContents

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

** **

**IDACORP**

** **

**IPC**

** **

** **

** **

**Weighted-**

** **

** **

** **

**Weighted-**

** **

** **

** **

**average**

** **

** **

** **

**Average**

** **

**Number of**

** **

**Grant Date**

**Number of**

** **

**Grant Date**

** **

**Shares**

** **

**Fair Value**

** **

**Shares**

** **

**Fair Value**

Nonvested shares at  December 31, 2006

204,208 

$

28.26

184,296 

$

28.32

Shares granted

91,453 

28.94

88,519 

28.94

Shares forfeited

(5,930)

30.24

(4,764)

31.09

Shares vested

(26,089)

31.16

(24,555)

31.16

Nonvested shares at  December 31, 2007

263,642 

$

28.17

243,496 

$

28.20

The total fair value ofshares vested during the years ended December 31, 2007, 2006, and 2005 was $0.9million, $0.6 million and $0.1 million, respectively.  At December 31, 2007, IDACORPhad $2.4 million of total unrecognized compensation cost related to nonvestedshare-based compensation that was expected to vest.  IPC's share of this amountwas $2.3 million.  These costs are expected to be recognized over a weighted-averageperiod of 1.64 years.  IDACORP uses original issue and/or treasury shares forthese awards.

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

The fair values of all stockoption awards have been estimated as of the date of the grant by applying abinomial option pricing model.  The application of this model involvesassumptions that are judgmental and sensitive in the determination ofcompensation expense.  The following key assumptions were used in determiningthe fair value of options granted:

**2007**

**2006**

**2005**

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

-

3.7%

4.1%

Expected stock price  volatility, based on IDACORP historical volatility

-

18%

23%

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

-

4.92%

4.22%

Expected term based on the  SEC "simplified" method

-

6.50 years

7 years

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

**IDACORP**

**IPC**

** **

**2007**

** **

**2006**

** **

**2005**

**2007**

** **

**2006**

** **

**2005**

Weighted-average grant-date  fair value

$

-

$

9.96

$

5.86

$

-

$

-

$

5.95

Fair value of options vested

737

2,191

1,865

579

1,275

1,390

Intrinsic value of options  exercised

79

3,771

104

11

2,883

-

Cash received from exercises

281

11,937

376

40

9,614

-

Tax benefits realized from  exercises

31

1,474

41

4

1,127

-

As of December 31, 2007,there was $0.1 million of total unrecognized compensation cost related to stockoptions.  These costs are expected to be recognized over a weighted averageperiod of 0.8 years.  IDACORP uses original issue and/or treasury shares tosatisfy exercised options.

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Table ofContents

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

** **

** **

** **

**Weighted**

** **

** **

** **

**Weighted-**

**Average**

**Aggregate**

** **

**Number**

**Average**

**Remaining**

**Intrinsic**

** **

**of**

**Exercise**

**Contractual**

**Value**

** **

**Shares**

**Price**

**Term**

**(000s)**

**IDACORP**

** **

** **

** **

** **

Outstanding at December 31,  2006

840,888 

$

34.36

5.63

$

4,062

Exercised

(10,070)

27.89

Forfeited

(6,586)

31.12

Expired

(6,000)

39.82

Outstanding at December 31,  2007

818,232 

$

34.37

4.61

$

2,690

Vested or expected to vest  at December 31, 2007

805,240 

$

34.47

4.58

$

2,498

Exercisable at December 31,  2007

673,045 

$

35.67

4.24

$

1,591

**IPC**

** **

** **

** **

** **

Outstanding at December 31,  2006

619,091 

$

33.84

5.71

$

3,385

Exercised

(1,412)

28.37

Forfeited

(1,636)

28.44

Expired

(4,800)

39.91

Outstanding at December 31,  2007

611,243 

$

33.75

4.71

$

2,310

Vested or expected to vest  at December 31, 2007

600,362 

$

33.85

4.68

$

2,234

Exercisable at December 31,  2007

490,139 

$

35.12

4.31

$

1,459

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Table ofContents

** **

**4. LONG-TERM DEBT**

The following tablesummarizes long-term debt at December 31:

**2007**

** **

**2006**

**(thousands of dollars)**

First  mortgage bonds:

7.38%     Series due 2007

$

- 

$

80,000 

7.20%     Series due 2009

80,000 

80,000 

6.60%     Series due 2011

120,000 

120,000 

4.75%     Series due 2012

100,000 

100,000 

4.25%     Series due 2013

70,000 

70,000 

6%          Series due 2032

100,000 

100,000 

5.50%     Series due 2033

70,000 

70,000 

5.50%     Series due 2034

50,000 

50,000 

5.875%   Series due 2034

55,000 

55,000 

5.30%     Series due 2035

60,000 

60,000 

6.30%     Series due 2037

140,000 

- 

6.25%     Series due 2037

100,000 

- 

Total  first mortgage bonds

945,000 

785,000 

Pollution  control revenue bonds:

Variable  Auction Rate Series 2003 due 2024 (a)

49,800 

49,800 

Variable  Auction Rate Series 2006 due 2026 (a)

116,300 

116,300 

Variable  Rate Series 2000 due 2027

4,360 

4,360 

Total  pollution control revenue bonds

170,460 

170,460 

American  Falls bond guarantee

19,885 

19,885 

Milner  Dam note guarantee

10,636 

11,700 

Unamortized  premium (discount) - net

(3,409)

(3,097)

Debt  related to investments in affordable housing

18,438 

32,331 

Other  subsidiary debt

7,326 

7,494 

Total

1,168,336 

1,023,773 

Current  maturities of long-term debt

(11,456)

(95,125)

Total  long-term debt

$

1,156,880 

$

928,648 

(a)

Humboldt  County and Sweetwater County Pollution Control Revenue bonds are secured by  first mortgage bonds, bringing the 

total  first mortgage bonds outstanding at December 31, 2007, to $1.111 billion.

At December 31, 2007, thematurities for the aggregate amount of long-term debt outstanding were (inthousands of dollars):

** **

**2008**

**2009**

**2010**

**2011**

**2012**

**Thereafter**

IPC 

$

1,064

$

81,064

$

1,064

$

121,064

$

101,064

$

840,661

Other subsidiary debt

10,392

5,657

2,965

220

235

6,295

Total

$

11,456

$

86,721

$

4,029

$

121,284

$

101,299

$

846,956

At December 31, 2007 and2006, the overall effective cost of IPC's outstanding debt was 5.72 percent and5.71 percent, respectively.

On June 22, 2007, IPC issued$140 million of its 6.30% First Mortgage Bonds, Secured Medium-Term Notes,Series F, due June 15, 2037.  IPC used the net proceeds to pay down outstandingcommercial paper, which had increased to $164 million in June 2007 because of increasedcapital expenditures.

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On October 18, 2007, IPCissued $100 million of its 6.25% First Mortgage Bonds, Secured Medium-TermNotes, Series G, due October 15, 2037.  IPC used the net proceeds to retire $80million of 7.38% First Mortgage Bonds due December 1, 2007, and paid downoutstanding commercial paper.

On October 3, 2006, IPCcompleted a tax-exempt bond financing in which Sweetwater County, Wyomingissued and sold $116.3 million aggregate principal amount of its PollutionControl Revenue Refunding Bonds Series 2006.  The bonds will mature on July 15,2026.  The $116.3 million proceeds were loaned by Sweetwater County to IPCpursuant to a loan agreement, dated as of October 1, 2006, between SweetwaterCounty and IPC.  On October 10, 2006, the proceeds of the new bonds, togetherwith certain other moneys of IPC, were used to refund Sweetwater County'sPollution Control Revenue Refunding Bonds Series 1996A, Series 1996B and Series1996C totaling $116.3 million.  The regularly scheduled principal and interestpayments on the Series 2006 bonds, and principal and interest payments on thebonds upon mandatory redemption on determination of taxability, are insured bya financial guaranty insurance policy issued by Ambac Assurance Corporation. IPC and Ambac entered into an Insurance Agreement, dated as of October 3, 2006,pursuant to which IPC has agreed, among other things, to pay certain premiumsto Ambac and to reimburse Ambac for any payments made under the policy.  Tosecure its obligation to make principal and interest payments on the loan madeto IPC, IPC issued and delivered to a trustee IPC's First Mortgage Bonds,Pollution Control Series C, in a principal amount equal to the amount of thenew bonds.  The Humboldt County series 2003 $49.8 million bonds have a similarfinancial guaranty insurance policy from Ambac.

On January 18, 2008, FitchRatings, Inc. announced that it had downgraded Ambac's insurer financialstrength rating to "AA" from "AAA" and was keeping the rating on negativewatch.  Fitch also downgraded the Humboldt bonds and Sweetwater bonds to "AA"from "AAA."  S&P and Moody's ratings for the bonds remain unchanged. However, Moody's placed Ambac's insurance financial strength rating on reviewfor possible downgrade on January 16, 2008 and, as a result of this review,Moody's-rated securities that are guaranteed by Ambac were also placed underreview for possible downgrade, except those with higher public underlyingratings.  S&P also placed Ambac's financial strength, financial enhancementand issuer credit ratings on CreditWatch with negative implications on January18, 2008.  On February 25, 2008, S&P affirmed Ambac's "AAA" financialstrength and financial enhancement ratings, but retained the negative watch.

The maximum interest rate is14 percent for the Sweetwater bonds and at specified rates capped at 12 percentfor the Humboldt bonds.  On February 27, 2008, auctions were held for bothseries of pollution control bonds.  The Sweetwater bonds had a successfulauction establishing a new interest rate of 7.95 percent.  The Humboldt bondsexperienced a "failed auction" which resulted in a new interest rate of 5.464percent (currently based on LIBOR multiplied by 1.75) and the Humboldt bonds continuingto be held by the current holders.

AtDecember 31, 2007, IFS had $18 million of debt related to investments inaffordable housing.  This debt had interest rates ranging from 3.65 percent to8.17 percent and is due between 2008 and 2010.  This debt is collateralized byinvestments in affordable housing developments with a net book value of $49million at December 31, 2007.  Of this $18 million in debt, $8 million is non-recourseto both IFS and IDACORP and the remainder is recourse only to IFS.  Inaddition, IFS also consolidates $7 million of debt related to a non-managinglimited partnership investment.  This debt is non-recourse to both IFS andIDACORP, is personally guaranteed by the managing member and is collateralizedby property.

**Long-Term Financing**IDACORP has $629 million remaining ontwo shelf registration statements that can be used for the issuance ofunsecured debt (including medium-term notes) and preferred or common stock. IPC has in place a registration statement that can be used for the issuance of anaggregate principal amount of $350 million of first mortgage bonds (includingmedium-term notes) and unsecured debt.

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

As of December 31, 2007, IPCcould issue under the mortgage approximately $535 million of additional firstmortgage bonds based on unfunded property additions and $532 million ofadditional first mortgage bonds based on retired first mortgage bonds.  AtDecember 31, 2007, unfunded property additions were approximately $900 million.

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

Themortgage secures all bonds issued under the indenture equally and ratably,without preference, priority or distinction.  IPC may issue additional firstmortgage bonds in the future, and those first mortgage bonds will also besecured by the mortgage.  The lien of the indenture constitutes a firstmortgage on all the properties of IPC, subject only to certain limitedexceptions including liens for taxes and assessments that are not delinquentand minor excepted encumbrances.  Certain of the properties of IPC are subjectto easements, leases, contracts, covenants, workmen's compensation awards andsimilar encumbrances and minor defects and clouds common to properties.  Themortgage does not create a lien on revenues or profits, or notes or accountsreceivable, contracts or choses in action, except as permitted by law during acompleted default, securities or cash, except when pledged, or merchandise orequipment manufactured or acquired for resale.  The mortgage creates a lien onthe interest of IPC in property subsequently acquired, other than exceptedproperty, subject to limitations in the case of consolidation, merger or saleof all or substantially all of the assets of IPC.

**5.  NOTES PAYABLE:**

IDACORP has a $100 millioncredit facility and IPC has a $300 million credit facility each of which expireson April 25, 2012.  Commercial paper may be issued up to the amounts supportedby the bank credit facilities.  Under these facilities the companies pay afacility fee on the commitment, quarterly in arrears, based on its rating forsenior unsecured long-term debt securities without third-party creditenhancement as provided by Moody's and S&P.  At December 31, 2007, IPC hadregulatory authority to incur up to $450 million of short-term indebtedness. Balances and interest rates of IDACORP's short-term borrowings were as followsat December 31 (in thousands of dollars):

**IDACORP**

**IPC**

**Total**

 
**2007**

**2006**

**2007**

**2006**

**2007**

**2006**

 
** **

**(thousands of dollars)**

 
**Balances:**

 
At the end of year

$49,860

$76,800

$136,585

$52,200

$186,445

$129,000

Average during the year

$44,773

$43,351

$96,890

$14,211

$141,663

$57,562

 
**Weighted-average  interest rate:**

 
At the end of year

5.45%

5.48%

5.56%

5.50%

5.53%

5.49%

 
Average during the year

5.44%

5.05%

5.54%

5.50%

5.51%

5.15%

 
 
** **

** **

** **

** **

** **

** **

** **

** **

** **

** **

** **

** **

** **

** **

** **

** **

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** **

**6.  REGULATORY MATTERS:**

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

** **

**As of December 31, 2007**

** **

** **

** **

** **

** **

** **

** **

**Total**

** **

**Remaining**

** **

**Not**

**Pending**

** **

**as of**

** **

**Amortization**

**Earning**

**Earning**

**Regulatory**

**2007**

**December**

**Description**

**Period**

**a Return**

**a Return**

**Treatment**

**Total**

**31, 2006**

Regulatory Assets:

Income Taxes

$

-

$

309,902

$

-

$

309,902

$

343,590

Benefit Plans (1)

-

17,765

-

17,765

46,181

Deferred Pension

Costs (1)

-

2,797

-

2,797

-

Conservation

2010

8,107

-

-

8,107

11,349

PCA Deferral

2008

92,323

-

-

92,323

-

Oregon Deferral (2)

5,100

-

-

5,100

9,559

Asset Retirement

Obligations (3)

-

12,188

-

12,188

11,206

Grid West Loans

60

746

302

1,108

1,290

Other

Through 2010

121

429

-

550

1,853

Total (4)

$

105,711

$

343,827

$

302

$

449,840

$

425,028

Regulatory Liabilities:

Income Taxes

$

-

$

44,580

$

-

$

44,580

$

41,825

Conservation

2008

1,893

-

-

1,893

6,328

PCA Accrual

-

-

-

-

15,173

FCA Deferral

-

2,145

-

2,145

-

Asset Retirement

Obligations (3)

-

155,314

-

155,314

156,162

Deferred ITC

-

71,001

-

71,001

69,114

BPA Settlement

2008

851

-

-

851

2,124

Emission Allowance

-

-

-

-

4,118

Other

-

586

-

586

-

Total (5)

$

2,744

$

273,626

$

-

$

276,370

$

294,844

(1)   See Note 8.

(2)   Capped at 10 percent  increase per year.

(3)   See Note 12.

(4)   Includes $172 reported  in other current assets on the balance sheets.

(5)   Includes $2,166  reported in other current liabilities on the balance sheets.

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

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

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**Deferred (Accrued) Net PowerSupply CostsIdaho:**  IPC has a Power CostAdjustment (PCA) mechanism that provides for annual adjustments to the ratescharged to its Idaho retail customers.  These adjustments are based onforecasts of net power supply costs, which are fuel and purchased power lessoff-system sales, and the true-up of the prior year's forecast.  During theyear, 90 percent of the difference between the actual and forecasted costs isdeferred with interest.  The ending balance of this deferral, called the true-upfor the current year's portion and the true-up of the true-up for the prioryears' unrecovered portion, is then included in the calculation of the nextyear's PCA.

On May 31, 2007, the IPUCapproved IPC's 2007-2008 PCA filing.  The filing increased the PCA component ofcustomers' rates from the then existing level, which was $46.8 million belowbase rates, to a level that is $30.7 million above those base rates.  This$77.5 million increase is net of $69.1 million of proceeds from sales of excessSO2 emission allowances.  The new rates became effective June 1,2007.

OnJune 1, 2006, IPC implemented the 2006-2007 PCA, which reduced the PCAcomponent of customers' rates from the then-existing level, which wasrecovering $76.7 million above then-existing base rates, to a level that was$46.8 million below those base rates, a decrease of approximately $123.5million.

**IdahoLoad Growth Adjustment Rate (LGAR):** On January 9, 2007, the IPUC issued an order resetting IPC's LGAR to $29.41 perMWh, effective April 1, 2007.  The LGAR subtracts the cost of servingadditional Idaho retail load from the net power supply costs IPC is allowed toinclude in its PCA.  The order revised the LGAR from the original rate of$16.84 per MWh set when the PCA began in 1993.  This amount was established asthe projected additional variable energy costs attributable to load growth andwas subtracted from each year's PCA expense.  In its petition, IPC hadrequested the use of the embedded cost of serving new load and a rate of $6.81per MWh, but the IPUC in its order determined to use the projected marginalcost, which resulted in a higher LGAR.****

**Emission Allowances: **During 2007, IPC sold 35,000 SO2 emissionallowances for a total of $19.6 million, after subtracting transaction fees. The sales proceeds to be allocated to the Idaho jurisdiction are approximately$18.5 million ($11.3 million net of tax, assuming a tax rate of approximately39 percent).  On January 15, 2008, a workshop was held to discuss whether thecustomer share of the Idaho jurisdictional portion of the 2007 sales proceedsshould once again be included as a PCA credit or used to reduce investmentcosts in wind development, green tags, or other options that would providelonger term customer benefits.  Because the workshop participants were unableto reach a consensus regarding the use of the SO2 emission allowanceproceeds, the IPUC determined that the case would proceed under modifiedprocedure.  Written comments were due February 25, 2008.

In 2005 and early 2006, IPCsold 78,000 SO2 emission allowances for a total of $81.6 million,after subtracting transaction fees.  The sales proceeds to be allocated to theIdaho jurisdiction are approximately $76.8 million ($46.8 million net of tax,assuming a tax rate of approximately 39 percent).  On May 12, 2006, the IPUCapproved a stipulation that allowed IPC to retain ten percent as a shareholderbenefit with the remaining 90 percent plus a carrying charge recorded as acustomer benefit.  This customer benefit is included in IPC's PCA calculationsas a credit to the PCA true-up balance and is currently reflected in PCA ratesduring the June 1, 2007 through May 31, 2008 PCA rate year.

**Oregon:**  On April 30, 2007, IPC filed for an accounting orderwith the OPUC to defer net power supply costs for the period of May 1, 2007,through April 30, 2008, in anticipation of higher than "normal" power supplyexpenses.  In the Oregon general rate case, "normal" power supply expenses wereset at a negative number (meaning that under normal water conditions IPC shouldbe able to sell enough surplus energy to pay for all fuel and purchased powerexpenses and still have revenue left over to offset other costs).  IPCrequested authorization to defer an estimated $5.7 million, which is Oregon'sjurisdictional share of the excess power supply costs.  IPC also requested thatit earn its Oregon authorized rate of return on the deferred balance andrecover the amount through rates in future years, as approved by the OPUC.  IPCis awaiting an order from the OPUC.

On April 28, 2006, IPC filedfor an accounting order with the OPUC to defer net power supply costs for theperiod of May 1, 2006, through April 30, 2007.  IPC requested authorization todefer an estimated $3.3 million, which is Oregon's jurisdictional share of theexcess power supply costs.  IPC also requested that it earn its Oregonauthorized rate of return on the deferred balance and recover the amountthrough rates in future years, as approved by the OPUC.  On April 25, 2007, atentative settlement agreement was reached on the deferral application with theOPUC Staff and the Citizens' Utility Board in the amount of $2 million.  Theparties also agreed that IPC would file an application for an Oregon PCAmechanism.  The settlement stipulation was approved by the OPUC on December 13,2007.

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The timing of recovery ofOregon power supply cost deferrals is subject to an Oregon statute thatspecifically limits rate amortizations of deferred costs to six percent peryear.  IPC is currently amortizing through rates power supply costs associatedwith the western energy situation of 2001.  Full recovery of the 2001 deferralis not expected until 2009.  The 2006-2007 and the 2007-2008 deferrals wouldhave to be amortized sequentially following the full recovery of the 2001deferral.

IPC's deferred (accrued) netpower supply costs consisted of the following at December 31 (in thousands ofdollars):

** **

**2007**

** **

**2006**

Idaho PCA current year:

Accrual for the 2007-2008  rate year(1)

$

-

$

(3,484)

Deferral for the 2008-2009  rate year(2)

85,732

- 

Idaho PCA true-up awaiting  recovery (refund):

Authorized May 2006

-

(11,689)

Authorized May 2007

6,591

- 

Oregon deferral:

2001 costs

2,993

6,670 

2005 costs

-

2,889 

2006 costs

2,107

- 

Total deferral (accrual)

$

97,423

$

(5,614)

(1) The 2007-2008 PCA  adjustment included $69 million of emission allowance sales to be credited to  customers.

(2) The 2008-2009 PCA  deferral balance includes $17 million of emission allowance sales in 2007.

** **

**Fixed Cost AdjustmentMechanism (FCA)**On January 27, 2006, IPC filed with the IPUC for authority to implement a rateadjustment mechanism that would adjust rates downward or upward to recoverfixed costs independent of the volume of IPC's energy sales.  This filing was acontinuation of a 2004 case that was opened to investigate the financialdisincentives to investment in energy efficiency by IPC.  This true-upmechanism would be applicable only to residential and small general servicecustomers.  The accounting for the FCA will be separate from the PCA.  IPCproposed a three percent cap on any rate increase to be applied at thediscretion of the IPUC.

IPC and the IPUC Staff agreed in concept to a three-year pilot program beginningJanuary 1, 2007, and a stipulation was filed on December 18, 2006.  Thestipulation called for the implementation of a FCA mechanism pilot program asproposed by IPC in its original application with additional conditions andprovisions related to customer count and weather normalization methodology,recording of the FCA deferral amount in reports to the IPUC and detailedreporting of demand side management (DSM) activities.  The IPUC approved thestipulation on March 12, 2007.  The pilot program began retroactively onJanuary 1, 2007, and will run through 2009, with the first rate adjustment tooccur on June 1, 2008, and subsequent rate adjustments to occur on June 1 ofeach year thereafter during the term of the pilot program.  IPC accrued $2.1million of FCA expense in 2007.****

**Open Access TransmissionTariff (OATT)**On March 24, 2006, IPC submitted arevised OATT filing with the FERC requesting an increase in transmissionrates.  In the filing IPC proposed to move from a fixed rate to a formula rate,which allows for transmission rates to be updated each year based on FERC Form1 data.  The formula rate request included a rate of return on equity of 11.25percent.  The proposed rates would have produced an annual revenue increase forthe FERC jurisdiction of approximately $13 million based on 2004 test yeardata.  The FERC accepted IPC's rates, effective June 1, 2006, subject toadjustment to conform to SFAS 109 tax accounting requirements, which loweredthe estimated annual increase in revenues to approximately $11 million.

On August 8, 2007, the FERCapproved a settlement agreement filed in June 2007 by the parties on all issuesexcept the treatment of contracts for transmission service that contain theirown terms, conditions and rates and that were in existence before theimplementation of OATT in 1996 (Legacy Agreements).  The effect of thissettlement was to reduce the estimated FERC jurisdictional annual revenueincrease from $11 million to approximately $8.2 million based on 2004 test yeardata.  The settlement agreement required that amounts collected in excess ofthe new rates for the June 1, 2006 through July 31, 2007 period be refundedwith interest to customers.  These refunds totaled approximately $1.7 millionand were paid in August 2007.

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Hearings were held before theFERC in June 2007 regarding the treatment of the Legacy Agreements.  IPC'sposition was that the revenue IPC receives under the Legacy Agreements shouldbe credited against the total transmission revenue requirement attributed toOATT customers and that the contract demands of the Legacy Agreements shouldnot be included in the load divisor of the rate formula.  The intervenors inthe proceeding took the position that such contract demands should be includedin the load divisor, rather than being revenue credited.

On August 31, 2007, the FERCPresiding Administrative Law Judge (ALJ) issued an initial decision (InitialDecision) with respect to the treatment of the Legacy Agreements, which is onfile and publicly available at FERC Docket No. ER06-787.  In the Initial Decision,the ALJ concluded that (i) the Legacy Agreements should be included in the loaddivisor of the rate formula and (ii) the revenue IPC receives under the LegacyAgreements should not be credited against the total transmission revenuerequirement attributed to OATT customers.  If the Initial Decision isimplemented, IPC estimates that this ruling will reduce the estimated FERCjurisdictional annual revenue increase (based on 2004 test year data) to $6.8million.

IPChas appealed the Initial Decision to the FERC.  However, if the InitialDecision is implemented, IPC would make additional refunds, including interest,of approximately $2.4 million for the June 1, 2006 through December 31, 2007period.  IPC has reserved this entire amount.  IPC expects to pursue recoveryof amounts not received pursuant to a final order in this proceeding throughadditional proceedings at the FERC or through the state ratemaking process. IPC is awaiting a final FERC order.

**PensionExpense**In the 2003 Idaho general rate case,the IPUC disallowed recovery of pension expense because there were no currentcontributions being made to the plan.  On March 20, 2007, IPC filed a requestwith the IPUC to clarify that IPC can consider future contributions made to thepension plan a recoverable cost of service.  An order approving thisapplication would not determine the methodology of recovery but would permitIPC to record a regulatory asset related to pension costs.  On June 1, 2007, the IPUC issued its order authorizingIPC to account for its defined benefit pension expense on a cash basis, and todefer and account for accrued pension expense under SFAS 87, *"Employers'Accounting for Pensions,"*as a regulatoryasset.  The IPUC acknowledged that it is appropriate for IPC to seek recoveryin its revenue requirement of reasonable and prudently incurred pension expensebased on actual cash contributions.  IPC will begin deferring pension expenseto a regulatory asset account to be matched with revenue when future pensioncontributions are recovered through rates.  The deferral of pension expense didnot begin until $4.1 million of past contributions still recorded on thebalance sheet at December 31, 2006, were expensed.  For 2007, approximately$2.8 million was deferred to a regulatory asset beginning in the thirdquarter.  IPC did not request a carryingcharge to be applied to the deferral of the accrued SFAS 87 expense.

**7.  COMMITMENTS ANDCONTINGENCIES:**

**Purchase Obligations:**As of December 31, 2007, IPC hadagreements to purchase energy from 94 cogeneration and small power production(CSPP) facilities with contracts ranging from one to 30 years.  Under thesecontracts IPC is required to purchase all of the output from the facilitiesinside the IPC service territory.  For projects outside the IPC serviceterritory, IPC is required to purchase the output that it has the ability toreceive at the facility's requested point of delivery on the IPC system.  IPCpurchased 777,147 megawatt-hours (MWh) at a cost of $45 million in 2007, 911,132MWh at a cost of $54 million in 2006 and 715,209 MWh at a cost of $46 millionin 2005.

At December 31, 2007, IPC hadthe following long-term commitments relating to purchases of energy, capacity,transmission rights and fuel:

** **

2008

**2009**

**2010**

**2011**

**2012**

**Thereafter**

**(thousands of dollars)**

Cogeneration  and small

power  production

$

75,813

$

99,246

$

99,246

$

103,435

$

103,435

$

1,511,405

Power  and transmission

rights

37,884

4,971

4,971

2,619

2,619

11,433

Fuel

54,290

44,465

24,478

25,214

6,636

54,466

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

2008

**2009**

**2010**

**2011**

**2012**

**Thereafter**

** **

**(thousands of dollars)**

Operating leases

$

3,080

$

3,377

$

3,377

$

1,368

$

1,368

$

7,119

Maintenance and service

agreements

50,012

4,241

4,241

1,039

1,039

3,819

FERC and other industry

related fees

4,133

3,990

3,990

3,884

3,884

19,493

IDACORP's expense foroperating leases was approximately $3 million in 2007 and $4 million in 2006and 2005.

**Guarantees**IPC has agreed to guarantee theperformance of reclamation activities at Bridger Coal Company of which IdahoEnergy Resources Co., a subsidiary of IPC, owns a one-third interest.  Thisguarantee, which is renewed each December, was $60 million at December 31,2007.  Bridger Coal Company has a reclamation trust fund set aside specificallyfor the purpose of paying these reclamation costs.  Bridger Coal Company andIPC expect that the fund will be sufficient to cover all such costs.  Becauseof the existence of the fund, the estimated fair value of this guarantee isminimal.

**Legal Proceedings**From time to time IDACORP and IPC areparties to legal claims, actions and complaints in addition to those discussedbelow.  Although they will vigorously defend against them, they are unable topredict with certainty whether or not they will ultimately be successful. However, based on the companies' evaluation, they believe that the resolutionof these matters, taking into account existing reserves, will not have amaterial adverse effect on IDACORP's or IPC's consolidated financial positions,results of operations or cash flows.

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

On September 8, 2004, thiscase was transferred and consolidated with other similar cases currentlypending before the Honorable Robert H. Whaley sitting by designation in theU.S. District Court for the Southern District of California.  The companies'filed a motion to dismiss the complaint which the court granted on February 11,2005.  Wah Chang appealed the dismissal to the U.S. Court of Appeals for theNinth Circuit on March 10, 2005.  On November 20, 2007, the Ninth Circuitaffirmed the dismissal.  On December 10, 2007, Wah Chang filed Petitions forRehearing and Rehearing En Banc with the U.S. Court of Appeals for the NinthCircuit (Ninth Circuit), which were denied on January 15, 2008.  If Wah Changdecides to seek Supreme Court review, time for filing its petition forcertiorari will expire on April 14, 2008.  The companies cannot predict whetherWah Chang will seek certiorari or whether the Supreme Court will grant it.  Thecompanies intend to vigorously defend their position in this proceeding andbelieve this matter will not have a material adverse effect on theirconsolidated financial positions, results of operations, or cash flows.

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**WesternEnergy Proceedings at the FERC:**California Power ExchangeChargeback:As a component of IPC's non-utilityenergy trading in the state of California, IPC entered into a participationagreement in January 1999 with the California Power Exchange (CalPX), aCalifornia non-profit public benefit corporation which at the time operated awholesale electricity market in California.  Under the participation agreement,if a participant in the CalPX defaulted on a payment, the other participantswere required to pay an allocated share of the default amount to the CalPX basedupon the level of trading activity of each participant during the preceding three-monthperiod.

OnJanuary 18, 2001, the CalPX sent IPC a "default share invoice" for $2 millionas a result of a Southern California Edison payment default of $215 million forpower purchases.  IPC made this payment.  On January 24, 2001, IPC terminatedits participation agreement with the CalPX.  On February 8, 2001, the CalPXsent a further invoice for $5 million as a result of alleged payment defaultsby Southern California Edison, Pacific Gas and Electric Company and others.  However,because the CalPX owed IPC more than the claimed amount for power sold to theCalPX in November and December 2000, IPC did not pay the February 8 invoice.  IPCessentially discontinued energy trading with the CalPX and the CaliforniaIndependent System Operator (Cal ISO) in December 2000.

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 March9, 2001, the CalPX filed for Chapter 11 protection with the U.S. BankruptcyCourt, Central District of California.

InApril 2001, Pacific Gas and Electric Company filed for bankruptcy.  The CalPXand the Cal ISO were among the creditors of Pacific Gas and Electric Company.

TheFERC issued an order on April 6, 2001 requiring the CalPX to rescind allchargeback actions related to Pacific Gas and Electric Company's and SouthernCalifornia Edison's liabilities but, on October 7, 2004, the FERC issued anorder determining that it would not require the disbursement of chargebackfunds until the completion of the California refund proceedings.

When the FERC approved asettlement of the California Refund matters among IE and the California Partieson May 22, 2006, the FERC also directed the CalPX to return the chargebackfunds held by the CalPX.  On June 1, 2006, IE received approximately $2.5million from the CalPX representing the return of $2.27 million in chargebackfunds plus interest.

California Refund:In April 2001, the FERC issued anorder stating that it was establishing price mitigation for sales in theCalifornia wholesale electricity market.  In a June 19, 2001 order, the FERCexpanded that price mitigation plan to the entire western United States electricallyinterconnected system.  That plan included the potential for orders directingelectricity sellers into California since October 2, 2000 to refund portions oftheir spot market sales prices if the FERC determined that those prices werenot just and reasonable.  After settlement discussions failed to bringresolution to the refund issues, the FERC established evidentiary hearings onJuly 25, 2001 to calculate refunds related to transactions in the spot marketsoperated by the Cal ISO and the CalPX during the period October 2, 2000,through June 20, 2001 (Refund Period).

On December 12, 2002, a FERCAdministrative Law Judge issued a Certification of Proposed Findings onCalifornia Refund Liability and the FERC largely affirmed the recommendationsof its Administrative Law Judge on March 26, 2003, but modified the judge'sfinding to enlarge refunds when it found that actual market prices paid for gasdid not reliably reflect the prices that should have prevailed in competitivegas markets.  The FERC also directed the Cal ISO to recalculate prices anddetermine the amount of "refunds" due to the organized California electricitymarkets.  In the context of these cases, since most sellers had not been paidby the Cal ISO or the CalPX, the term "refunds" means a reduction in the amountdue to sellers for power sold.

IE, along with a number ofother parties, sought rehearing and judicial review of the FERC's orders.

Since that time, the Cal ISOhas engaged in a detailed review of its books and records and the variousadjustments the FERC has ordered to calculate "refunds."  That process hastaken more than four years and is not yet complete.

While those calculations werebeing performed, litigation before the FERC continued regarding a variety ofmatters that would affect the level of refunds, including among other things,cost filings, fuel cost allowance offsets, emissions offsets, cost-basedrecovery offsets, and allocation methods.

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Asthe FERC issued more orders and denied rehearing, more petitions for reviewwere filed by IE and other parties.  The United States Court of Appeals for theNinth Circuit consolidated IE's and the other parties' petitions with thepetitions for review arising from earlier FERC orders in this proceeding,bringing the total number of consolidated petitions to more than two hundred. The Ninth Circuit held the appeals in abeyance pending the disposition of themarket manipulation claims discussed below and the development of acomprehensive plan to brief this complicated case.  The Ninth Circuit severed asubset of the stayed appeals so that briefing could commence regarding casesrelated to: (1) which parties are subject to the FERC's refund jurisdictionunder section 201(f) of the FPA; (2) the temporal scope of refunds under section206 of the FPA; and (3) which categories of transactions are subject torefunds.

On September 6, 2005, theNinth Circuit issued a decision on the jurisdictional issues concluding thatthe FERC lacked refund authority over wholesale electric energy sales made bygovernmental entities and non-public utilities.  On August 2, 2006, the NinthCircuit issued its decision on the appropriate temporal reach and the type oftransactions subject to the FERC refund orders and among other things (i) concludedthat all transactions at issue in the case that occurred within or as a resultof the CalPX and the Cal ISO were the proper subject of refund proceedings; (ii)refused to expand the refund proceedings into the bilateral markets includingtransactions with the California Department of Water Resources; (iii) approvedthe refund effective date as October 2, 2000, but also required the FERC toconsider whether refunds, including possibly market-wide refunds, should berequired for an earlier time due to claims that some market participants hadviolated governing tariff obligations (although the decision did not specifywhen that time would start, the California Parties generally had sought furtherrefunds starting May 1, 2000); and (iv) effectively expanded the scope of therefund proceeding to transactions within the CalPX and Cal ISO markets outsidethe 24-hour spot market and energy exchange transactions.

While the refund proceedingswere pending before the FERC, the California Attorney General filed a complaintwith the FERC against sellers in the wholesale power market, including IE andIPC, alleging that the FERC's market-based rate requirements violate the FPA,and, even if the market-based rate requirements were valid, that the quarterlytransaction reports filed by sellers did not contain the transaction-specificinformation mandated by the FPA and the FERC.  The complaint sought refunds foran expanded time when compared to the basic refund proceeding.  The FERC dismissedthe complaint but on September 9, 2004, the Ninth Circuit concluded that althoughmarket-based tariffs are permissible under the FPA, the matter should beremanded to the FERC to consider whether the FERC should exercise remedialpower (including some form of refunds) when a market participant failed tosubmit reports.  On December 28, 2006, a number of sellers filed a certioraripetition to the U.S. Supreme Court.  The Supreme Court declined to grantcertiorari and the matter has now been remanded to the FERC.

OnAugust 8, 2005, the FERC issued an order establishing the framework for filingsby sellers who elected to make a cost showing to reduce their refund exposure. On September 14, 2005, IE and IPC made a joint cost filing, as didapproximately thirty other sellers.  That filing was contested by theCalifornia Parties (Pacific Gas and Electric Company, San Diego Gas &Electric Company, Southern California Edison Company, the California PublicUtilities Commission, the California Electricity Oversight Board, theCalifornia Department of Water Resources and the California Attorney General).

Whilethe appeals of the California Attorney General's complaint were pending, andprior to the August 2, 2006 decision of the Ninth Circuit and the FERC actionon the cost filing, IPC and IE reached a settlement with the California Partiesthat was approved by the FERC on May 22, 2006.  That settlement anticipated thepossibility of the outcome of the appeals discussed above and resolved thesettling parties' claims in the event of the expansion of all of the refundproceedings as the Ninth Circuit ordered.  Under the terms of the settlement,IE and IPC assigned $24.25 million of the rights to accounts receivable fromthe Cal ISO and CalPX to the California Parties to pay into an escrow accountfor refunds to settling parties.  Amounts from that escrow not used forsettling parties and $1.5 million of the remaining IE and IPC receivables thatare to be retained by the CalPX are available to fund, at least partially,payment of the claims of any non-settling parties if they prevail in theremaining litigation of this matter.  Any excess funds remaining at the end ofthe case are to be returned to IDACORP.  Approximately $10.25 million of theremaining IE and IPC receivables was paid to IE and IPC under the settlement.

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AlthoughIPC and IE had reached a settlement with the California Parties, some partiesrepresenting a small portion of the total refund exposure did not join thesettlement.  On March 27, 2006, the FERC rejected the IE/IPC cost filing and IEand IPC sought rehearing of the rejection.  By order of April 27, 2006, theFERC tolled the time for what otherwise would have been required by statute tobe a decision on the request for rehearing.  That request remains pendingbefore the FERC.  IE and IPC are unable to predict how or when the FERC mightrule on the request for rehearing.

On June 21, 2006, the Port ofSeattle, Washington filed a request for rehearing of the FERC order approvingthe IPC and IE/California Parties settlement.  On October 5, 2006, the FERC deniedthe Port of Seattle's request for rehearing and on October 24, 2006, the Portof Seattle petitioned the U.S. Court of Appeals for the Ninth Circuit forreview of the FERC orders approving the settlement.  On October 25, 2007 theNinth Circuit lifted the stay as to the Port of Seattle's appeal along with twoother cases with which the Port of Seattle's petition remains consolidated andsevered the three cases from the remainder of the consolidated cases.  TheNinth Circuit established a briefing schedule which currently concludes in lateJune 2008 for these three cases.  A date for argument has not yet beenscheduled.  IPC and IE are unable to predict when or how the Ninth Circuitmight rule on Port of Seattle's petition for review.

Priorto December 2005, IE had accrued a reserve of $42 million for this matter. This reserve was calculated taking into account the uncertainty of collectionfrom the CalPX and Cal ISO.  In the fourth quarter of 2005, following thetentative agreement with the California Parties, IE reduced this reserve by$9.5 million to $32 million.  Following payment of the $10.25 million to IE andIPC in June 2006, IE further reduced the reserve by $24.9 million to $7.1million.  This reserve was calculated taking into account several unresolvedissues in the California refund proceeding.

Market Manipulation:On March 3, 2003, the CaliforniaParties asserted that a number of wholesale power suppliers, including IE andIPC, had engaged in a variety of forms of conduct that the California Partiescontended were impermissible.  IE and IPC were mentioned only in limitedcontexts with the overwhelming majority of the claims of the California Partiesrelating to the conduct of other parties.  On March 20, 2003, numerous parties,including IE and IPC, submitted briefs and responsive testimony.

In a March 26, 2003 order,the FERC declined to generically apply its refund determinations to sales byall market participants, although it stated that it reserved the right toprovide remedies for the market against parties shown to have engaged inproscribed conduct.

On June 25, 2003, the FERCordered over 50 entities that participated in the western wholesale powermarkets between January 1, 2000 and June 20, 2001, including IPC, to show causewhy certain trading practices did not constitute gaming or anomalous marketbehavior in violation of the Cal ISO and the CalPX Tariffs.  On October 16,2003, IPC and IE reached agreement with the FERC Staff on the two orderscommonly referred to as the "gaming" and "partnership" show cause orders.  TheFERC Staff submitted a motion to the FERC to dismiss the "partnership" proceedingbecause materials submitted by IPC demonstrated that IPC did not engage in impermissiblepartnership market behavior.  The motion to dismiss the "partnership"proceeding was approved by the FERC in an order issued on January 23, 2004 andrehearing of that order was not sought within the time allowed by statute. Regarding the gaming order, the FERC Staff determined it had no basis toproceed with most of the allegations and IPC agreed to pay $83,373 to settleallegations of circular scheduling.  IPC believed that it had defenses to thecircular scheduling allegation but determined that the cost of settlement wasless than the cost of litigation.  In the settlement, IPC did not admit anywrongdoing or violation of any law.  The "gaming" settlement was approved bythe FERC on March 3, 2004.

Some parties have soughtreview of what they claim are the excessively narrow or excessively broad scopeof the show cause orders, and the Ninth Circuit has consolidated those claimswith the other matters and are holding them in abeyance.  The Port of Seattleis the only party to appeal the orders of the FERC approving the gaming settlementand, like the dozens of other appeals pending before the Ninth Circuit, IPC isnot able to predict when that appeal will be considered or the outcome of thejudicial determination of these issues.

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On June 25, 2003, the FERCalso issued an order instituting an investigation of anomalous bidding behaviorand practices in the western wholesale power markets.  In this investigation,the FERC was to review evidence of alleged economic withholding of generation. The FERC determined that all bids into the CalPX and the Cal ISO markets formore than $250 per MWh for the time period May 1, 2000, through October 1,2000, would be considered prima facie evidence of economic withholding.  TheFERC Staff issued data requests in this investigation to over 60 marketparticipants including IPC.  IPC responded to the FERC's data requests.  In aletter dated May 12, 2004, the FERC's Office of Market Oversight andInvestigations advised that it was terminating the investigation as to IPC.  InMarch 2005, the California Attorney General, the California Public Utilities Commission,the California Electricity Oversight Board and Pacific Gas and Electric Companysought judicial review in the Ninth Circuit of the FERC's termination of thisinvestigation as to IPC and approximately 30 other market participants.  IPChas moved to intervene in these proceedings.  On April 25, 2005, Pacific Gasand Electric Company sought review in the Ninth Circuit of another FERC orderin the same docketed proceeding confirming the agency's earlier decision not toallow the participation of the California Parties in what the FERCcharacterized as its non-public investigative proceeding.  Formal ordersholding these cases in abeyance have expired and the Ninth Circuit has notestablished a briefing or decision schedule.  Neither IE nor IPC are able topredict when the Ninth Circuit will schedule briefing or decision on thesecases or how it may decide them.

Pacific Northwest Refund:On July 25, 2001, the FERC issued anorder establishing another proceeding to determine whether there may have beenunjust and unreasonable charges for spot market sales in the Pacific Northwestduring the period December 25, 2000 through June 20, 2001.  A FERCAdministrative Law Judge submitted recommendations and findings to the FERC onSeptember 24, 2001 concluding that prices should be governed by the Mobile-Sierrastandard of the public interest rather than the just and reasonable standard,that the Pacific Northwest spot markets were competitive and that refunds shouldbe allowed.  On December 19, 2002, the FERC reopened the proceedings to allowthe submission of additional evidence related to alleged manipulation of thepower market by market participants.  Parties alleging market manipulation wereto submit their claims to the FERC and responses were due on March 20, 2003.  ThePublic Utilities District No. 1 of Grays Harbor, which had executed a six-monthforward contract with IPC for which performance had been completed, intervenedin this FERC proceeding, asserting that its contract should be treated as aspot market contract for purposes of the FERC's consideration of refunds andrequested refunds from IPC of $5 million.  Grays Harbor did not suggest thatthere was any misconduct by IPC or IE.  The companies submitted responsivetestimony defending vigorously against Grays Harbor's refund claims.  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.  On June 25, 2003, after having considered oral argument held earlierin the month, the FERC terminated the proceeding and denied claims that refundsshould be paid.  The FERC denied rehearing on November 10, 2003, triggering theright to file for review.  The Port of Seattle, the City of Tacoma, the City ofSeattle, the California Attorney General, the California Public Utilities Commissionand Puget Sound Energy, Inc. filed petitions for review in the Ninth Circuit. Grays Harbor terminated its participation in the case when Grays Harbor and IPCreached a settlement.  On August 24, 2007, the Ninth Circuit issued an opinionin the appeal, remanding to the FERC the orders that declined to requirerefunds.  The Ninth Circuit's opinion instructed the FERC to consider whetherevidence of market manipulation submitted by the petitioners for the periodJanuary 1, 2000 to June 21, 2001 would have altered the agency's conclusionsabout refunds and directed the FERC to include sales to the CaliforniaDepartment of Water Resources in the proceeding.  A number of parties havesought rehearing of the Ninth Circuit's decision.  IE and IPC are unable topredict when the Ninth Circuit will rule on the requests for rehearing or theoutcome of these matters.

In separate western energyproceedings, the Ninth Circuit issued two decisions on December 19, 2006 regardingthe FERC's decisions not to require repricing of certain long term contracts. Those cases originated with individual complaints against specified sellerswhich did not include IE or IPC.  The Ninth Circuit remanded to the FERC foradditional consideration the agency's use of restrictive standards of contractreview.  In its decisions, the Ninth Circuit also questioned the validity ofthe FERC's administration of its market-based rate regime.  The United StatesSupreme Court has granted certiorari in one of the cases.  IDACORP and IPC areunable to predict how or when the Supreme Court will rule, or how the FERCmight respond to any such decision or how any such decision might affect the outcomeof the Pacific Northwest proceeding.

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**Western Shoshone NationalCouncil:** On April 10, 2006, theWestern Shoshone National Council (which purports to be the governing body ofthe Western Shoshone Nation) and certain of its individual tribal members fileda First Amended Complaint and Demand for Jury Trial in the U.S. District Courtfor the District of Nevada, naming IPC and other unrelated entities asdefendants.  Plaintiffs allege that IPC's ownership interest in certain land,minerals, water or other resources was converted and fraudulently conveyed fromlands in which the plaintiffs had historical ownership rights and Indian titledating back to the 1860's or before.

On May 1, 2006, IPC filed anAnswer to plaintiffs' First Amended Complaint denying all liability to theplaintiffs and asserting certain affirmative defenses including collateralestoppel and res judicata, preemption, impossibility and impracticability,failure to join all real and necessary parties, and various defenses based onuntimeliness.  On June 19, 2006, IPC filed a motion to dismiss plaintiffs'First Amended Complaint, asserting, among other things, that the Court lackssubject matter jurisdiction and that plaintiffs failed to join an indispensableparty (namely, the United States government).  On May 31, 2007, the U.S.District Court granted the defendants' motion to dismiss stating that theplaintiffs' claims are barred by the finality provision of the Indian ClaimsCommission Act.  On June 8, 2007, plaintiffs filed a motion forreconsideration.  On January 18, 2008, the District Court denied plaintiffs'motion for reconsideration, and on January 25, 2008 entered judgment in favorof IPC.  On January 24, 2008, plaintiffs filed a Notice of Appeal to the NinthCircuit.  IPC and plaintiffs have not yet filed briefs on appeal, althoughbriefing is currently scheduled for completion in April 2008.  Oral argument onthe appeal has not yet been scheduled.  IPC intends to vigorously defend itsposition in this proceeding, but is unable to predict the outcome of thismatter or estimate the impact it may have on IPC's consolidated financialposition, results of operations or cash flows.

**Sierra Club Lawsuit -Bridger: **In February 2007, theSierra Club and the Wyoming Outdoor Council filed a complaint againstPacifiCorp in federal district court in Cheyenne, Wyoming alleging violationsof air quality opacity standards at the Jim Bridger coal fired plant (Plant) inSweetwater County, Wyoming.  Opacity is an indication of the amount of light obscuredin the flue gas of a power plant.  A formal answer to the complaint was filedby PacifiCorp on April 2, 2007, in which PacifiCorp denied almost all of theallegations and asserted a number of affirmative defenses.  IPC is not a partyto this proceeding but has a one-third ownership interest in the Plant. PacifiCorp owns a two-thirds interest and is the operator of the Plant.  Thecomplaint alleges thousands of violations by PacifiCorp and seeks a declarationthat PacifiCorp has violated opacity limits, a permanent injunction orderingPacifiCorp to comply with such limits, civil penalties of up to $32,500 per dayper violation reimbursement of the plaintiff's costs of litigation, includingreasonable attorney fees.

The U.S. District Court hasset this matter for trial commencing in April 2008.  Discovery in the matterwas completed on October 15, 2007.  Also in October 2007, the plaintiffs anddefendant filed cross-motions for summary judgment on the alleged opacitypermit status of this matter.  The court has not yet ruled on these motions. IDACORP and IPC are unable to predict the outcome of this matter or estimatethe impact it may have on their consolidated financial positions, results ofoperations or cash flows.

**Sierra Club Notice ofIntent to File Suit - Boardman: **OnJanuary 15, 2008, the Oregon Chapter of the Sierra Club, the NorthwestEnvironmental Defense Center, Friends of the Columbia Gorge, ColumbiaRiverkeeper, and Hells Canyon Preservation Council (collectively, Sierra Club)provided a 60-day notice to Portland General Electric Company (PGE) of intentto file suit.  Sierra Club alleges violations of opacity standards at the Boardmancoal-fired power plant located in Morrow County, Oregon of which IPC owns tenpercent.  PGE owns 65 percent and is the operator of the plant.  Sierra furtheralleges various violations of the Clean Air Act, related federal regulationsand the Oregon State Implementation Plan relating to PGE's construction andoperation of the plant.  Sierra Club has not yet commenced litigation.  SierraClub alleges thousands of opacity permit limit violations by PGE from andbefore 2003, and claims that it will seek a declaration that PGE has violatedopacity limits, a permanent injunction ordering PGE to comply with such limits,and civil penalties of up to $32,500 per day per violation.

IPC intends to monitor thestatus of this matter but is unable to predict its outcome or what effect thismatter may have on its consolidated financial position, results of operationsor cash flows.

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**Renfro Dairy:**  On September 28, 2007, the principals of RenfroDairy in Canyon County, Idaho filed a lawsuit in the District Court of theThird Judicial District of the State of Idaho against IDACORP and IPC.  Theplaintiffs' complaint asserts claims for negligence, negligence *per se*,gross negligence, nuisance, and fraud.  The claims are based on allegationsthat from 1972 until at least March 2005, IPC discharged "stray voltage" fromits electrical facilities that caused physical harm and injury to theplaintiffs' dairy herd.  Plaintiffs seek compensatory damages of not less than$1 million.

Plaintiffs have not yetserved their complaint on IDACORP or IPC.  If the action is pursued by theplaintiffs, the companies intend to vigorously defend their position in thisproceeding and believe this matter will not have a material adverse effect ontheir consolidated financial positions, results of operations or cash flows.

**8. BENEFIT PLANS:**

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

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

**PensionPlans**IPC has a noncontributory definedbenefit pension plan covering most employees.  The benefits under the plan arebased on years of service and the employee's final average earnings.  IPC'spolicy is to fund, with an independent corporate trustee, at least the minimumrequired under the Employee Retirement Income Security Act of 1974 (ERISA) butnot more than the maximum amount deductible for income tax purposes.  IPC wasnot required to contribute to the plan in 2007, 2006 or 2005.  The market-relatedvalue of assets for the plan is equal to the fair value of the assets.  Fairvalue is determined by utilizing publicly quoted market values and independentpricing services depending on the nature of the asset, as reported by thetrustee/custodian of the plan.

Inaddition, IPC has a nonqualified, deferred compensation plan for certain seniormanagement employees and directors.  This plan was financed by purchasing lifeinsurance policies and investments in marketable securities, all of which areheld by a trustee.  The cash value of the policies and investments exceed theprojected benefit obligation of the plan but do not qualify as plan assets inthe actuarial computation of the funded status.

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

** **

**Pension Plan**

**Deferred Compensation Plan**

** **

**2007**

**2006**

**2005**

**2007**

**2006**

**2005**

** **

**(thousands of dollars)**

Service cost

$

15,213 

$

14,476 

$

13,129 

$

1,409

$

1,473

$

1,170

Interest cost

24,457 

22,340 

21,126 

2,372

2,327

2,151

Expected return on assets

(33,387)

(30,817)

(29,690)

-

-

-

Amortization of net loss

- 

129 

- 

566

844

689

Amortization of prior  service cost

650 

664 

771 

173

245

228

Amortization of transition  asset

- 

- 

(126)

-

-

310

Net periodic pension cost 

$

6,933 

$

6,792 

$

5,210 

$

4,520

$

4,889

$

4,548

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

** **

**Pension Plan**

**Deferred Compensation Plan**

** **

**2007**

** **

**2006**

**2007**

** **

**2006**

**(thousands of dollars)**

**Change in benefit  obligation:**

Benefit obligation at  January 1

$

425,599 

$

406,049 

$

41,866 

$

42,723 

Service cost

15,213 

14,476 

1,409 

1,473 

Interest cost

 

24,457 

22,340 

2,372 

2,327 

Actuarial loss (gain)

 

(29,585)

(2,827)

(87)

(2,857)

Benefits paid

 

(15,158)

(14,439)

(2,700)

(2,352)

Plan amendments

 

- 

- 

293 

552 

Benefit obligation at  December 31

420,526 

425,599 

43,153 

41,866 

**Change in plan assets:**

Fair value at January 1

400,924 

368,053 

- 

- 

Actual return on plan assets

22,204 

47,310 

- 

- 

Benefits paid

 

(15,158)

(14,439)

- 

- 

Fair value at December 31

407,970 

400,924 

- 

- 

Funded status at end of year

$

(12,556)

$

(24,675)

$

(43,153)

$

(41,866)

Amounts recognized in the  statement of

financial position consist  of:

Current liabilities

$

- 

$

- 

$

(2,596)

$

(2,375)

Noncurrent liabilities

(12,556)

(24,675)

(40,557)

(39,491)

Net amount recognized

$

(12,556)

$

(24,675)

$

(43,153)

$

(41,866)

Amounts recognized in  accumulated other

comprehensive income consist  of:

Net loss

$

5,954 

$

24,356 

$

9,200 

$

9,853 

Prior service cost

3,805 

4,455 

1,841 

1,720 

Subtotal

9,759 

28,811 

11,041 

11,573 

Less amount recorded as  regulatory asset

(9,759)

(28,811)

- 

- 

Net amount recognized in  accumulated

other comprehensive income

$

- 

$

- 

$

11,041 

$

11,573 

Accumulated benefit  obligation

$

346,477 

$

350,434 

$

39,851 

$

38,634 

Prior to the adoption of SFAS158, changes in the Deferred Compensation Plan minimum liability increasedother comprehensive income by $2 million in 2006, and decreased othercomprehensive income by $1 million in 2005.

In 2008, IDACORP and IPCexpect to recognize as components of net periodic benefit cost $1.3 millionfrom amortizing amounts recorded in accumulated other comprehensive income asof December 31, 2007, relating to the pension and deferred compensation plans. This amount consists of $0.6 million of prior service cost for the pension planand $0.5 million of net loss and $0.2 million of prior service cost for thedeferred compensation plan.

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

** **

** **

**2008**

** **

**2009**

** **

**2010**

** **

**2011**

** **

**2012**

** **

**2013-2017**

**(thousands of dollars)**

Pension Plan

$

16,507

$

17,610

$

18,959

$

20,512

$

22,448

$

145,577

Deferred Compensation Plan

$

2,672

$

2,859

$

3,085

$

3,142

$

3,236

$

18,435

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**Plan Asset Allocations:** IPC's pension plan and postretirement benefit planweighted average asset allocations at December 31, 2007 and 2006, by assetcategory are as follows:

**Pension**

**Postretirement**

**Plan**

**Benefits**

Asset Category

**2007**

**2006**

**2007**

**2006**

Equity securities

65%

68%

-%

-%

Debt securities

22   

24   

-   

-   

Real estate

10   

7   

-   

-   

Other (a)

3   

1   

100   

100   

Total

100%

100%

100%

100%

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

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

Large-Cap Growth Stocks

12%

International Growth Stocks

7%

Large-Cap Core Stocks

12%

International Value Stocks

7%

Large-Cap Value Stocks

12%

Intermediate-Term Bonds

13%

Small-Cap Growth Stocks

5%

Short-Term Bonds

10%

Small-Cap Value Stocks

5%

Core Real Estate

9%

Micro-Cap Stocks

3%

Private Equity

2%

Cash and Cash Equivalents

3%

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

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

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

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

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

Rate-of-return projections for planassets are based on historical risk/return relationships among asset classes. The primary measure is the historical risk premium each asset class hasdelivered versus the return on 10-year U.S. Treasury Notes.  This historicalrisk premium is then added to the current yield on 10-year U.S. Treasury Notes,and the result provides a reasonable prediction of future investmentperformance.  Additional analysis is performed to measure the expected range ofreturns, as well as worst-case and best-case scenarios.  Based on the currentlow interest rate environment, current rate-of-return expectations are lowerthan the nominal returns generated over the past 20 years when interest rateswere generally much higher.

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

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

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

**2007**

** **

**2006**

** **

**2005**

Service cost

$

1,368 

$

1,463 

$

1,392 

Interest cost

3,512 

3,426 

3,381 

Expected return on plan  assets

(2,777)

(2,523)

(2,486)

Amortization of  unrecognized transition obligation

2,040 

2,040 

2,040 

Amortization of prior  service cost

(535)

(535)

(535)

Amortization of net loss

403 

812 

754 

Net periodic postretirement  benefit cost

$

4,011 

$

4,683 

$

4,546 

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

**2007**

** **

**2006**

Change  in accumulated benefit obligation:

Benefit  obligation at January 1

$

62,913 

$

63,633 

Service  cost

1,368 

1,463 

Interest  cost

3,512 

3,426 

Actuarial  (gain) loss

(7,431)

(2,445)

Benefits  paid

(3,536)

(3,164)

Benefit  obligation at December 31

56,826 

62,913 

Change  in plan assets:

Fair  value of plan assets at January 1

32,627 

29,893 

Actual  return on plan assets

3,129 

3,158 

Employer  contributions

2,876 

2,004 

Benefits  paid

(3,536)

(2,428)

Fair  value of plan assets at December 31

35,096 

32,627 

Funded  status at end of year (included in noncurrent liabilities)

$

(21,730)

$

(30,286)

Amounts recognized in  accumulated other comprehensive income consist of:

Net loss

$

3,900 

$

12,086 

Prior service cost (credit)

(2,607)

(3,142)

Transition obligation

10,200 

12,240 

Subtotal

11,493 

21,184 

Less amount recognized in  regulatory assets

8,006 

17,370 

Less amount included in  deferred tax assets

3,487 

3,814 

Net amount recognized in  accumulated other comprehensive income

$

- 

$

- 

In2008, IDACORP and IPC expect to recognize as components of net periodic benefitcost $1.5 million from amortizing amounts recorded in accumulated othercomprehensive income as of December 31, 2007 relating to the postretirementplan.  This amount consists of ($0.5) million of prior service cost and $2.0million of transition obligation.

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**MedicareAct: **The Medicare Prescription Drug,Improvement and Modernization Act of 2003 (Medicare Act) was signed into law inDecember 2003 and established a prescription drug benefit, as well as a federalsubsidy to sponsors of retiree health care benefit plans that provide aprescription drug benefit that is at least actuarially equivalent to Medicare'sprescription drug coverage.

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

**2008**

** **

**2009**

** **

**2010**

** **

**2011**

** **

**2012**

** **

**2013-2017**

Expected  benefit payments*

$

4,100

$

4,300

$

4,400

$

4,600

$

4,800

$

25,600

 
Expected  Medicare Part D

 
subsidy  receipts

$

500

$

500

$

600

$

600

$

700

$

4,600

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

Theassumed health care cost trend rate used to measure the expected cost ofbenefits covered by the plan was 6.75 percent in 2007 and 2006.  A one-percentagepoint change in the assumed health care cost trend rate would have thefollowing effect (in thousands of dollars):

**1-Percentage-Point**

**Increase**

** **

**Decrease**

Effect  on total of cost components

$

258

$

(195)

Effect  on accumulated postretirement benefit obligation

$

2,144

$

(1,696)

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

**Pension**

**Postretirement**

**Benefits**

**Benefits**

**2007**

**2006**

**2007**

**2006**

Discount rate

6.4%

5.85%

6.4%

5.85%

Rate of compensation  increase

4.5%

4.5%

-   

-   

Medical trend rate

-   

-   

6.75%

6.75%

Measurement date

12/31/07

12/31/06

12/31/07

12/31/06

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

**Pension**

**Postretirement**

**Benefits**

**Benefits**

**2007**

**2006**

**2007**

**2006**

Discount rate

5.85%

5.6%

5.85%

5.6%

Expected long-term rate of  return on assets

8.5%

8.5%

8.5%

8.5%

Rate of compensation  increase

4.5%

4.5%

-   

-   

Medical trend rate

-   

-   

6.75%

6.75%

** **

**EmployeeSavings Plan**IPC has an Employee Savings Plan thatcomplies with Section 401(k) of the Internal Revenue Code and coverssubstantially all employees.  IPC matches specified percentages of employee contributionsto the plan.  Matching contributions amounted to $5 million in 2007 and $4million in both 2006 and 2005.

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**Postemployment Benefits**IPC provides certain benefits toformer or inactive employees, their beneficiaries and covered dependents afteremployment but before retirement.  These benefits include salary continuation,health care and life insurance for those employees found to be disabled underIPC's disability plans and health care for surviving spouses and dependents. IPC accrues a liability for such benefits.  The post employment benefit amountsincluded in other deferred credits on IDACORP's and IPC's consolidated balancesheets at December 31 are $3.5 million and $4.0 million for 2007 and 2006,respectively.

**Pension Protection Act**In 2006, the Pension Protection Actof 2006 (the Act), which affects the manner in which many companies, includingIDACORP and IPC, administer their pension plans was signed into law.  The Actmade changes to a variety of rules that apply to employee benefit plans,including those dealing with minimum funding requirements of defined benefitpension plans and plan investments of defined contribution pension plans.  TheAct also permanently extended the pension law changes made by the EconomicGrowth and Tax Relief Reconciliation Act of 2001, which had been scheduled tosunset on December 31, 2010.  This legislation became effective on January 1,2008.  Due to the funded status and funding policy of IPC's pension plan, theAct is not expected to have a material impact on the results of operations,financial condition, cash flows or liquidity of IDACORP or IPC when it wasimplemented.

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

The following table presentsthe major classifications of IPC's utility plant in service, annualdepreciation provisions as a percent of average depreciable balance andaccumulated provision for depreciation for the years 2007 and 2006 (inthousands of dollars):

**2007**

** **

**2006**

**Balance**

** **

**Avg Rate**

** **

**Balance**

** **

**Avg Rate**

Production

$

1,639,710 

2.52%

$

1,592,790 

2.55%

Transmission

684,399 

2.13   

606,947 

2.18   

Distribution

1,175,429 

2.58   

1,097,390 

2.60   

General and Other

296,801 

8.29   

286,567 

6.74   

Total in service

3,796,339 

2.95%

3,583,694 

2.75%

Accumulated provision for  depreciation

(1,468,832)

(1,406,210)

In service - net

$

2,327,507 

$

2,177,484 

IPC has interests in threejointly-owned generating facilities.  Under the joint operating agreements,each participating utility is responsible for financing its share ofconstruction, operating and leasing costs.  IPC's proportionate share of directoperation and maintenance expenses applicable to the projects is included inthe Consolidated Statements of Income.  These facilities, and the extent of IPC'sparticipation, were as follows at December 31, 2007 (in thousands of dollars):

** **

** **

** **

** **

**Utility**

** **

**Construction**

** **

**Accumulated**

** **

**Owner**

** **

** **

** **

** **

** **

** **

**Plant In**

** **

**Work in**

** **

**Provision for**

** **

**ship**

** **

** **

**Name of Plant**

** **

**Location**

** **

**Service**

** **

**Progress**

** **

**Depreciation**

** **

**%**

** **

**MW***

Jim Bridger Units 1-4

Rock Springs, WY

$

474,759

$

8,802

$

271,777

33

771

Boardman

Boardman, OR

70,294

161

49,288

10

64

Valmy Units 1 and 2

Winnemucca, NV

331,371

6,958

213,430

50

284

*IPC share of nameplate  capacity 

IPC's wholly-ownedsubsidiary, Idaho Energy Resources Co., is a joint venturer in Bridger CoalCompany, which operates the mine supplying coal to the Jim Bridger generatingplant.  IPC's coal purchases from the joint venture were $51 million, $52million and $43 million in 2007, 2006 and 2005, respectively.

IPC has contracts to purchasethe energy from four PURPA qualified facilities that are 50 percent owned byIda-West.  IPC's power purchases from these facilities were $8 million annuallyin 2007 and 2006 and $7 million in 2005.

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

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**10.  INVESTMENTS:**

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

**2007**

** **

**2006**

IPC Investments:

Equity method investment 

$

76,451

$

62,223

Available-for-sale equity  securities 

21,445

21,548

Executive deferred  compensation

6,627

6,492

Other investments 

5

4

Total IPC investments 

104,528

90,267

Investments in affordable  housing 

77,608

90,266

Equity method investments 

9,550

8,969

Held-to-maturity debt  securities 

11,248

11,069

Executive deferred  compensation

3,431

4,767

Total IDACORP investments 

$

206,365

$

205,338

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

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

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

**2007**

** **

**2006**

** **

**2005**

Bridger Coal Company (IPC)

$

5,553 

$

9,347 

$

10,369 

Ida-West projects

1,820 

2,341 

1,769 

IFS affordable housing  projects

(12,197)

(14,601)

(12,851)

Total 

$

(4,824)

$

(2,913)

$

(713)

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

**2007**

** **

**2006**

** **

**2005**

Operating revenues

$

153,126

$

154,910

$

128,015

Operating expenses

136,468

126,869

96,909

Net Income 

$

16,658

$

28,041

$

31,106

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

**2007**

** **

**2006**

**Assets**

Current assets

$

58,672

$

47,723

Noncurrent assets

330,583

325,252

Total Assets

$

389,255

$

372,975

**Liabilities**

Current liabilities

$

25,372

$

28,250

Noncurrent liabilities

134,529

158,054

Total Liabilities

159,901

186,304

Joint venture capital

229,353

186,671

Total Liabilities and Joint  Venture Capital

$

389,254

$

372,975

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

Investments classified asheld-to-maturity securities are reported at amortized cost.  Held-to-maturitysecurities are investments in debt securities for which the company has thepositive intent and ability to hold the securities until maturity.  These debtsecurities have maturities ranging from 2008 through 2025.

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

**2007**

**2006**

**Gross**

**Gross**

** **

**Gross**

**Gross**

** **

**Unrealized**

**Unrealized**

**Fair**

**Unrealized**

**Unrealized**

**Fair**

**Gain**

**Loss**

**Value**

**Gain**

**Loss**

**Value**

Available-for-sale 

securities (IPC)

$

1,059

$

128

$

21,445

$

2,474

$

322

$

21,548

Held-to-maturity debt 

securities (IFS)

15

5

11,245

5

40

11,034

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

** **

**2007**

** **

**2006**

** **

**2005**

Proceeds from sales

$

26,110

$

20,778

$

120,026

Gross realized gains from  sales

2,093

3,774

2,850

Gross realized losses from  sales

762

280

643

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Additionally, theseinvestments are evaluated to determine whether they have experienced a declinein market value that is considered other-than-temporary.  IDACORP and IPCanalyze securities in loss positions as of the end of each reporting period. Any security with an unrealized loss of more than 20 percent is evaluated forother-than-temporary impairment.  A security will generally be written down tomarket value if it has an unrealized loss of 20 percent or more for more thannine months.  If additional information is available that indicates a securityis other-than-temporarily impaired, it will be written down prior to the nine-monthtime period.  In the alternative, if a security has been impaired for more thannine months but available information indicates that the impairment istemporary, the security will not be written down.  IDACORP and IPC have notrecognized any other-than-temporary impairments in 2007, 2006 or 2005.The following table summarizes information regarding securities that were in anunrealized loss position at the end of each year, but for which no other-than-temporaryimpairment was recognized (in thousands of dollars).

** **

**Less than 12 months**

**12 months or longer**

** **

**Aggregate**

** **

**Aggregate**

**Aggregate**

** **

**Aggregate**

** **

**Unrealized**

** **

**Related Fair**

**Unrealized**

** **

**Related Fair**

** **

**Loss**

** **

**Value**

**Loss**

** **

**Value**

**2007:**

Available-for-sale equity  securities (IPC)

$

128

$

1,059

$

-

$

-

Held to maturity debt  securities (IFS)

-

-

5

642

**2006:**

Available-for-sale equity  securities IPC)

$

241

$

3,879

$

81

$

621

Held to maturity debt  securities (IFS)

9

578

31

2,278

The available-for-sale equitysecurities in unrealized loss positions are diversified investments in commonstock of various companies used to fund IPC's Senior Management Security Plan. The held-to-maturity debt securities in unrealized loss positions are bonds,whose market values fluctuate based on the interest rate environment.  AtDecember 31, 2007, one available-for-sale and two held-to-maturity securitieswere in an unrealized loss position.  None of these securities had unrealizedloss positions of greater than 20 percent.  At December 31, 2006, elevenavailable-for-sale and six held-to-maturity securities were in an unrealizedloss position.  None of these securities had unrealized loss positions ofgreater than 20 percent.  IDACORP and IPC do not consider these investments tobe other-than-temporarily impaired at December 31, 2007 or 2006.  BecauseIDACORP has the ability and intent to hold the debt securities until maturity,it does not consider them to be other-than-temporarily impaired at December 31,2007 or 2006.

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

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

Cashand cash equivalents, deposits, customer and other receivables, notes payable,accounts payable, interest accrued and taxes accrued are reported at theircarrying value as these are a reasonable estimate of their fair value.  Theestimated fair values for notes receivable, long-term debt and investments arebased upon quoted market prices of the same or similar issues or discountedcash flow analyses as appropriate.

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**December 31, 2007**

**December 31, 2006**

**Carrying**

** **

**Estimated**

** **

**Carrying**

** **

**Estimated**

**Amount**

** **

Fair Value

** **

**Amount**

** **

**Fair Value**

** **

**(thousands of dollars)**

**IDACORP**

**Assets:**

Notes receivable

$

8,073

$

8,121

$

8,431

$

8,257

Investments 

35,082

35,093

39,109

39,074

**Liabilities:**

Long-term debt

$

1,171,745

$

1,162,499

$

1,026,870

$

1,018,250

**IPC**

**Assets:**

Notes receivable

$

4,859

$

4,907

$

5,853

$

5,679

Investments 

23,848

23,848

28,040

28,040

**Liabilities:**

Long-term debt

$

1,145,981

$

1,136,042

$

987,045

$

978,491

**12.  ASSET RETIREMENTOBLIGATIONS (ARO):**

SFAS 143, *"Accounting forAsset Retirement Obligations,"* as amended and interpreted, requires thatlegal obligations associated with the retirement of property, plant andequipment be recognized as a liability at fair value when incurred and when areasonable estimate of the fair value of the liability can be made.  Under SFAS143, when a liability is initially recorded, the entity increases the carryingamount of the related long-lived asset to reflect the future retirement cost. Over time, the liability is accreted to its present value and paid, and thecapitalized cost is depreciated over the useful life of the related asset.  If,at the end of the asset's life, the recorded liability differs from the actualobligations paid, a gain or loss would be recognized.  As a rate-regulatedentity, IPC records regulatory assets or liabilities instead of accretion,depreciation and gains or losses.  This treatment was approved by Order No.29414 from the IPUC.  The regulatory assets recorded under this order do notearn a return on investment.

IPC's recorded AROs relateto: removal of PCB-contaminated equipment at its distribution facilities andthe reclamation and removal costs at its jointly owned coal-fired generationfacilities.  In 2007 changes in estimates were identified at IPC and IPC'sjointly owned coal-fired generation facilities resulting in a net increase inliability of $0.9 million.

IPC has AROs associated withits transmission system and hydroelectric facilities; however, due to theindeterminate removal date, the fair value of the associated liabilitiescurrently cannot be estimated and no amounts are recognized in the consolidatedfinancial statements.

The regulated operations ofIPC also collect removal costs in rates for certain assets that do not haveassociated AROs.  The adoption of SFAS 143 required IPC to redesignate theseremoval costs as regulatory liabilities.  Costs recorded as regulatoryliabilities on IPC's Consolidated Balance Sheet as of December 31, 2007 and2006, were $155 million and $156 million, respectively.

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

** **

**IDACORP**

**IPC**

** **

**2007**

** **

**2006**

**2007**

** **

**2006**

Balance at beginning of  year

$

13,388 

$

10,519

$

12,911 

$

10,079

Accretion expense

695 

665

692 

628

Revisions in estimated cash  flows

920 

-

920 

-

Liability incurred

- 

2,204

- 

2,204

Liability settled

(488)

-

(8)

-

Balance at end of year

$

14,515 

$

13,388

$

14,515 

$

12,911

**13.  SEGMENT INFORMATION:**

IDACORPhas identified utility operations as the only reportable segment in 2007.  IFS whichhad previously been identified as a reportable segment is now included in the "AllOther" column.  ITI and IDACOMM, which had previously been identified asreportable segments, are now reported as discontinued operations (see Note 16).

Theutility operations segment's primary sources of revenue are the regulatedoperations of IPC.  IPC's regulated operations include the generation,transmission, distribution, purchase and sale of electricity.  This segmentalso includes income from IERCO, a wholly-owned subsidiary of IPC that is alsosubject to regulation and is a one-third owner of Bridger Coal Company, anunconsolidated joint venture.  Operating segments not included above are belowthe quantitative thresholds for reportable segments and are included in the "AllOther" category.  This category is comprised of IFS's investments in affordablehousing developments and historic rehabilitation projects, Ida-West's jointventure investments in small hydroelectric generation projects, the remainingactivities of energy marketer IE, which wound down its operations in 2003, andIDACORP's holding company expenses.

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

**All**

** **

**Consolidated**
   
**Operations**

**Other**

**Eliminations**  1

**Total** 1

**2007**

Revenues

$

875,401

$

3,993 

$

- 

$

879,394 

Operating income (loss)

154,777

(2,699)

- 

152,078 

Other income 

7,436

101 

- 

7,537 

Interest income

2,980  

3,126 

(1,553)

4,553 

Equity method income (loss)

5,553

(10,377)

- 

(4,824)

Interest expense

58,781

6,113 

(1,553)

63,341 

Income (loss) before income  taxes

111,965

(15,962)

- 

96,003 

Income tax expense  (benefit)

35,386

(21,655)

- 

13,731 

Income (loss) from  continuing operations

76,579

5,693 

- 

82,272 

Total assets

3,489,516

235,636 

(71,844)

3,653,308 

Expenditures for long-  lived assets

287,219

46 

- 

287,265 

**2006**

Revenues

$

920,473

$

5,818 

$

- 

$

926,291 

Operating income (loss)

176,503

(6,799)

- 

169,704 

Other income 

5,060

1,176 

(490)

5,746 

Interest income

2,909

2,694 

(1,713)

3,890 

Equity method income (loss)

9,347

(12,260)

- 

(2,913)

Interest expense

55,929

7,250 

(2,204)

60,975 

Income (loss) before income  taxes

137,890

(22,438)

- 

115,452 

Income tax expense  (benefit)

43,961

(28,584)

- 

15,377 

Income (loss) from  continuing operations

93,929

6,146 

- 

100,075 

Total assets

3,177,725

273,742 

(6,337)

3,445,130 

Expenditures for long-  lived assets

221,930

5,093 

- 

227,023 

**2005**

Revenues

$

837,683

$

5,181 

$

- 

$

842,864 

Operating income (loss)

151,654

2,999 

- 

154,653 

Other income 

4,623

1,154 

(318)

5,459 

Interest income

3,193

2,223 

(1,760)

3,656 

Equity method income (loss)

10,369

(11,082)

- 

(713)

Interest expense

54,075

7,732 

(2,078)

59,729 

Income (loss) before income  taxes

115,764

(12,438)

- 

103,326 

Income tax expense  (benefit)

43,925

(26,315)

- 

17,610 

Income from continuing  operations

71,839

13,877 

- 

85,716 

Total assets

3,074,691

323,344 

(33,909)

3,364,126 

Expenditures for long-  lived assets

186,079

4,998 

- 

191,077 

** **

12006 includes the assets of IDACOMM, and 2005  includes the assets of both ITI and IDACOMM which are presented as 

assets held for sale.

** **

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

**IDACORP**IPC performs corporate functions suchas financial, legal and management services for IDACORP and its subsidiaries. IPC charges IDACORP for the costs of these services based on service agreementsand other specifically identified costs.  For these services IPC billed IDACORP$2 million in 2007 and $4 million in both 2006 and 2005.

**Ida-West**IPC purchases all of the powergenerated by four of Ida-West's hydroelectric projects located in Idaho.  IPCpaid $8 million in both 2007 and 2006 and $7 million in 2005.

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**15.  OTHER INCOME ANDEXPENSE:**

The following table presentsthe components of Other income and Other expense (in thousands of dollars):

**2007**

** **

**2006**

** **

**2005**

**Other income:**

Allowance for funds used  during construction-equity

$

5,995

$

6,092

$

4,950

Investment income, net

6,855

8,489

6,424

Carrying charges

3,437

1,040

2,048

Other

4,237

2,574

3,699

Total

$

20,524

$

18,195

$

17,121

**Other expense:**

Security plan pension  expense

$

4,520

$

4,889

$

4,548

Other

3,914

3,670

3,458

Total

$

8,434

$

8,559

$

8,006

**16.  DISCONTINUEDOPERATIONS:**

In the second quarter of 2006,IDACORP decided to seek buyers for its fuel cell technology subsidiary ITI andits telecommunications subsidiary IDACOMM.  IDACORP had been reviewingstrategic alternatives for ITI and IDACOMM in order to focus on its coreutility business.  The planned disposals of these businesses meet the criteriaestablished for reporting them as assets held for sale as defined by SFAS 144. SFAS 144 requires that a long-lived asset classified as held for sale bemeasured at the lower of its carrying amount or fair value, less costs to sell,and requires the holder to cease depreciation and amortization.  Based on ananalysis of the fair value of each subsidiary, no adjustments to the carryingvalues were required.

On July 20, 2006, IDACORPcompleted the sale of all of the outstanding common stock of ITI to IdaTech UKLimited, a wholly-owned subsidiary of Investec Group Investments (UK) Limited. IDACORP recorded a gain of $11.5 million, net-of-tax from this transaction in2006.

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

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

** **

** **

**2007**

** **

**2006**

** **

**2005**

Revenues

$

1,278 

$

12,882 

$

16,624 

Operating expenses

(1,309)

(21,369)

(43,528)

Other income (expense)

(25)

354 

159 

Gain (loss) on disposal

(2,877)

14,476 

- 

Pre-tax income (losses)

(2,933)

6,343 

(26,745)

Income tax benefit

3,000 

985 

4,690 

Income (losses) from  discontinued operations

$

67 

$

7,328 

$

(22,055)

** **

The results of operations forthe years ended December 31, 2007 and 2006 do not include depreciation expenseof approximately $0.3 million and $1.2 million, respectively, that would berecorded if the related assets were classified as held and used.

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The assets and liabilities ofIDACOMM were classified as held for sale on IDACORP's consolidated balancesheets at December 31, 2006.  A summary of the components of assets andliabilities held for sale on IDACORP's Consolidated Balance Sheets is asfollows (in thousands of dollars):

** **

**2006**

Assets

Current assets

$

3,326

Property and investments

20,789

Other assets

287

Total assets

$

24,402

Liabilities

Current liabilities

$

2,606

Other liabilities

8,773

Total liabilities

$

11,379

** **

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** **

**REPORTOF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM**

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

We have audited theaccompanying consolidated balance sheets of IDACORP, Inc. and subsidiaries (the"Company") as of December 31, 2007 and 2006, and the related consolidatedstatements of income, comprehensive income, shareholders' equity, and cashflows for each of the three years in the period ended December 31, 2007.  Ouraudits also included the consolidated financial statement schedules listed inthe Index at Item 8.  These financial statements and financial statementschedules are the responsibility of the Company's management.  Ourresponsibility is to express an opinion on the financial statements and financialstatement schedules based on our audits.

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

Inour opinion, such consolidated financial statements present fairly, in allmaterial respects, the financial position of IDACORP, Inc. and subsidiaries atDecember 31, 2007 and 2006, and the results of their operations and their cashflows for each of the three years in the period ended December 31, 2007, inconformity with accounting principles generally accepted in the United Statesof America.  Also, in our opinion, such consolidated financial statementschedules, when considered in relation to the basic consolidated financialstatements taken as a whole, present fairly, in all material respects, theinformation set forth therein.

Asdiscussed in Note 2 to the consolidated financial statements, the Companyadopted Financial Accounting Standards Board Interpretation No. 48, *Accountingfor Uncertainty in Income Taxes - an interpretation of FASB Statement No.*109,on January 1, 2007 and as discussed in Note 8 to the consolidated financialstatements, the Company adopted Statement of Financial Accounting Standards No.158, *Employers' Accounting for Defined Benefit Pension and OtherPostretirement Plans - an amendment of FASB Statements No. 87, 88, 106, and132(R),* as of December 31, 2006.

Wehave also audited, in accordance with the standards of the Public CompanyAccounting Oversight Board (United States), the Company's internal control overfinancial reporting as of December 31, 2007, based on the criteria establishedin *Internal Control-Integrated Framework* issued by the Committee ofSponsoring Organizations of the Treadway Commission and our report dated February27, 2008 expressed an unqualified opinion on the Company's internal controlover financial reporting.

DELOITTE& TOUCHE LLP

Boise, IdahoFebruary 27, 2008

** **

** **

** **

** **

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** **

**REPORT OF INDEPENDENTREGISTERED PUBLIC ACCOUNTING FIRM**

** **

Tothe Board of Directors and Shareholder of Idaho Power CompanyBoise, Idaho

Wehave audited the accompanying consolidated balance sheets and statements ofcapitalization of Idaho Power Company and subsidiary (the "Company") as ofDecember 31, 2007 and 2006, and the related consolidated statements of income,comprehensive income, retained earnings, and cash flows for each of the threeyears in the period ended December 31, 2007.  Our audits also included theconsolidated financial statement schedule listed in the Index at Item 8.  Thesefinancial statements and financial statement schedule are the responsibility ofthe Company's management.  Our responsibility is to express an opinion on thefinancial statements and financial statement schedule based on our audits.

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

Inour opinion, such consolidated financial statements present fairly, in allmaterial respects, the financial position of Idaho Power Company and subsidiaryat December 31, 2007 and 2006, and the results of their operations and theircash flows for each of the three years in the period ended December 31, 2007,in conformity with accounting principles generally accepted in the UnitedStates of America.  Also, in our opinion, such consolidated financial statementschedule, when considered in relation to the basic consolidated financialstatements taken as a whole, presents fairly, in all material respects, theinformation set forth therein.

Asdiscussed in Note 2 to the consolidated financial statements, the Companyadopted Financial Accounting Standards Board Interpretation No. 48, *Accountingfor Uncertainty in Income Taxes - an interpretation of FASB Statement No.*109,on January 1, 2007 and as discussed in Note 8 to the consolidated financialstatements, the Company adopted Statement of Financial Accounting Standards No.158, *Employers' Accounting for Defined Benefit Pension and OtherPostretirement Plans - an amendment of FASB Statements No. 87, 88, 106, and132(R),* as of December 31, 2006.

Wehave also audited, in accordance with the standards of the Public CompanyAccounting Oversight Board (United States), the Company's internal control overfinancial reporting as of December 31, 2007, based on the criteria establishedin *Internal Control-Integrated Framework* issued by the Committee ofSponsoring Organizations of the Treadway Commission and our report datedFebruary 27, 2008 expressed an unqualified opinion on the Company's internalcontrol over financial reporting.

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Boise, IdahoFebruary 27, 2008

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** **

**SUPPLEMENTALFINANCIAL INFORMATION, UNAUDITED**

**QUARTERLYFINANCIAL DATA:**

Thefollowing unaudited information is presented for each quarter of 2007 and 2006(in thousands of dollars except for per share amounts).  In the opinion of eachcompany, all adjustments necessary for a fair statement of such amounts forsuch periods have been included.  The results of operations for the interim periodsare not necessarily indicative of the results to be expected for the fullyear.  Accordingly, earnings information for any three-month period should notbe considered as a basis for estimating operating results for a full fiscalyear.  Amounts are based upon quarterly statements and the sum of the quartersmay not equal the annual amount reported.

**Quarter Ended**

**March 31**

**June 30**

**September 30**

**December 31**

**IDACORP, Inc.**

**2007**

Revenues

 $

206,711  

 $

213,772  

 $

261,463  

 $

197,446  

Operating income

43,779  

36,572  

47,930  

23,795  

Income from  continuing operations

24,580  

18,465  

28,931  

10,295  

Income from  discontinued operations, net

67  

-    

-    

-    

Net income

24,647  

18,465  

28,931  

10,295  

Basic and  diluted earnings per share

0.56  

0.42  

0.65  

0.23  

** **

**2006**

Revenues

 $

268,340  

 $

242,635  

 $

230,532  

 $

184,784  

Operating income

46,477  

45,551  

56,656  

21,019  

Income from  continuing operations

26,955  

22,673  

32,492  

17,955  

Income (loss)  from discontinued operations, net

(1,479)

(2,817)

11,497  

127  

Net income

25,476  

19,856  

43,989  

18,082  

Basic and  diluted earnings (loss) per share

Continuing operations

0.63  

0.53  

0.76  

0.42  

Discontinued operations

(0.03)

(0.06)

0.27  

-    

Total

0.60  

0.47  

1.03  

0.42  

**Idaho Power Company**

**2007**

Revenues

 $

205,928  

 $

212,526  

 $

260,516  

 $

196,431  

Income from operations

45,584  

35,908  

48,596  

24,689  

Net income

23,331  

16,164  

24,108  

12,976  

**2006**

Revenues

 $

267,274  

 $

240,848  

 $

228,799  

 $

183,552  

Income from operations

49,229  

46,810  

58,216  

22,248  

Net income

25,021  

21,612  

30,389  

16,907  

Incomefrom discontinued operations was affected in the third quarter of 2006 by an$11.5 million gain on the sale of ITI.

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

None

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**ITEM9A.  CONTROLS AND PROCEDURES**

Disclosure controls andprocedures:

**IDACORP:**

The Chief Executive Officerand Chief Financial Officer of IDACORP, based on their evaluation of IDACORP'sdisclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e))as of December 31, 2007, have concluded that IDACORP's disclosure controls andprocedures are effective.

**IPC:**

The Chief Executive Officerand Chief Financial Officer of IPC, based on their evaluation of IPC'sdisclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e))as of December 31, 2007, have concluded that IPC's disclosure controls andprocedures are effective.

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Internal control overfinancial reporting:

**IDACORP:**

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

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

IDACORP's management assessedthe effectiveness of the company's internal control over financial reporting asof December 31, 2007.  In making this assessment, the company's management usedthe criteria set forth by the Committee of Sponsoring Organizations of theTreadway Commission in *Internal Control-Integrated Framework*.

Based on its assessment,management believes that, as of December 31, 2007 IDACORP's internal controlover financial reporting is effective based on those criteria.

IDACORP's independentregistered public accounting firm has audited the financial statements includedin this Annual Report on Form 10-K for the year ended December 31, 2007 andissued a report, which appears on the next page and expresses an unqualifiedopinion on the effectiveness of IDACORP's internal control over financialreporting as of December 31, 2007.

February 27, 2008

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**REPORT OF INDEPENDENTREGISTERED PUBLIC ACCOUNTING FIRM**

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

We have audited the internal controlover financial reporting of IDACORP, Inc. and subsidiaries (the "Company") asof December 31, 2007, based on the criteria established in *Internal Control-IntegratedFramework* issued by the Committee of Sponsoring Organizations of theTreadway Commission.  The Company's management is responsible for maintainingeffective internal control over financial reporting and for its assessment ofthe effectiveness of internal control over financial reporting, included in theaccompanying *Management's Annual Report on Internal Control over FinancialReporting*.  Our responsibility is to express an opinion on the Company'sinternal control over financial reporting based on our audit.

We conducted our audit inaccordance with the standards of the Public Company Accounting Oversight Board(United States).  Those standards require that we plan and perform the audit toobtain reasonable assurance about whether effective internal control overfinancial reporting was maintained in all material respects.  Our auditincluded obtaining an understanding of internal control over financialreporting, assessing the risk that a material weakness exists, testing andevaluating the design and operating effectiveness of internal control based onthe assessed risk, and performing such other procedures as we considerednecessary in the circumstances.  We believe that our audit provides areasonable basis for our opinion.

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

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

In our opinion, the Companymaintained, in all material respects, effective internal control over financialreporting as of December 31, 2007, based on the criteria established in *InternalControl-Integrated Framework* issued by the Committee of SponsoringOrganizations of the Treadway Commission.

We have also audited, inaccordance with the standards of the Public Company Accounting Oversight Board(United States), the consolidated financial statements and financial statementschedules as of and for the year ended December 31, 2007 of the Company and ourreport dated February 27, 2008 expressed an unqualified opinion on thosefinancial statements and financial statement schedules and included anexplanatory paragraph regarding the Company's adoption of Statement ofFinancial Accounting Standards No. 158 and Financial Accounting Standards BoardInterpretation No. 48.

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Boise, IdahoFebruary 27, 2008

**Idaho Power Company:**

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

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

IPC's management assessed theeffectiveness of the company's internal control over financial reporting as ofDecember 31, 2007.  In making this assessment, the company's management usedthe criteria set forth by the Committee of Sponsoring Organizations of theTreadway Commission in *Internal Control-Integrated Framework*.

Based on its assessment,management believes that, as of December 31, 2007, IPC's internal control overfinancial reporting is effective based on those criteria.

IPC's independent registeredpublic accounting firm has audited the financial statements included in thisAnnual Report on Form 10-K for the year ended December 31, 2007 and issued areport, which appears on the next page and expresses an unqualified opinion onthe effectiveness of IPC's internal control over financial reporting as ofDecember 31, 2007.

February 27, 2008

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**REPORT OF INDEPENDENTREGISTERED PUBLIC ACCOUNTING FIRM**

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

We have audited the internal controlover financial reporting of Idaho Power Company and subsidiary (the "Company") asof December 31, 2007, based on the criteria established in *Internal Control-IntegratedFramework* issued by the Committee of Sponsoring Organizations of theTreadway Commission.  The Company's management is responsible for maintainingeffective internal control over financial reporting and for its assessment ofthe effectiveness of internal control over financial reporting, included in theaccompanying *Management's Annual Report on Internal Control over FinancialReporting*.  Our responsibility is to express an opinion on the Company'sinternal control over financial reporting based on our audit.

We conducted our audit inaccordance with the standards of the Public Company Accounting Oversight Board(United States).  Those standards require that we plan and perform the audit toobtain reasonable assurance about whether effective internal control overfinancial reporting was maintained in all material respects.  Our auditincluded obtaining an understanding of internal control over financialreporting, assessing the risk that a material weakness exists, testing andevaluating the design and operating effectiveness of internal control based onthe assessed risk, and performing such other procedures as we considerednecessary in the circumstances.  We believe that our audit provides a reasonablebasis for our opinion.

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

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

In our opinion, the Companymaintained, in all material respects, effective internal control over financialreporting as of December 31, 2007, based on the criteria established in *InternalControl-Integrated Framework* issued by the Committee of SponsoringOrganizations of the Treadway Commission.

We have also audited, inaccordance with the standards of the Public Company Accounting Oversight Board(United States), the consolidated financial statements and financial statementschedule as of and for the year ended December 31, 2007 of the Company and ourreport dated February 27, 2008 expressed an unqualified opinion on those financialstatements and financial statement schedule and included an explanatoryparagraph regarding the Company's adoption of Statement of Financial AccountingStandards No. 158 and Financial Accounting Standards Board Interpretation No.48.

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**Changes in InternalControl Over Financial Reporting**There have been no changes in IDACORP'sor IPC's internal control over financial reporting during the quarter endedDecember 31, 2007, requiring disclosure that have materially affected, or arereasonably likely to materially affect, IDACORP's or IPC's internal controlover financial reporting.

**ITEM 9B.  OTHER INFORMATION**

None

**PARTIII**

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

The portion of IDACORP'sdefinitive proxy statement appearing under the captions "Proposal No. 1:Election of Directors - Nominees for Election - Terms Expire 2011," "ContinuingDirectors - Terms Expire 2010," "Continuing Directors - Terms Expire 2009," "Section16(a) Beneficial Ownership Reporting Compliance," "Corporate Governance - AuditCommittee," paragraph 1 and "Corporate Governance - Code of Ethics," to befiled pursuant to Regulation 14A for the 2008 Annual Meeting of Shareholders tobe held on May 15, 2008 is hereby incorporated by reference.

**ITEM11.  EXECUTIVE COMPENSATION**

The portion of IDACORP'sdefinitive proxy statement appearing under the caption "Executive Compensation"to be filed pursuant to Regulation 14A for the 2008 Annual Meeting ofShareholders to be held on May 15, 2008 is hereby incorporated by reference.

**ITEM12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATEDSTOCKHOLDER MATTERS**

The portion of IDACORP'sdefinitive proxy statement appearing under the caption "Security Ownership ofDirectors, Executive Officers and Five Percent Shareholders" to be filedpursuant to Regulation 14A for the 2008 Annual Meeting of Shareholders to beheld on May 15, 2008 is hereby incorporated by reference.

The following table includesinformation as of December 31, 2007, with respect to equity compensation planswhere equity securities of IDACORP may be issued.  These plans are the 1994Restricted Stock Plan (RSP), the IDACORP 2000 Long-Term Incentive andCompensation Plan (LTICP) and the Non-Employee Director Stock Compensation Plan(DSP).

** **

** **

**(a)**

** **

**(b)**

** **

**(c)**

** **

** **

** **

** **

** **

** **

**Number of securities**

** **

** **

** **

** **

** **

** **

**remaining available for**

** **

** **

**Number of securities to**

** **

**Weighted-average**

** **

**future issuance under**

** **

** **

**be issued upon exercise**

** **

**exercise price of**

** **

**equity compensation**

** **

** **

**of outstanding options,**

** **

**outstanding options,**

** **

**plans (excluding securities**

**Plan Category**

** **

**warrants and rights**

** **

**warrants and rights**

** **

**reflected in column (a))**

Equity compensation

plans approved by

shareholders (1)

818,232

$

34.37

1,719,950(2)(3)

Equity compensation

plans not approved

by shareholders(4)

-

$

-

41,963      

Total

818,232

$

34.37

1,761,913      

(1)

Consists of the RSP and the  LTICP.

(2)

In addition to being  available for future issuance upon exercise of  options, 1,611,355 shares  under the LTICP may instead be issued in 

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

based awards.

(3)

108,595 shares remain  available for future issuance under the RSP.

(4)

Consists of shares available  for future issuance under the DSP.

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**Equity Compensation PlansNot Approved by IDACORP Shareholders**:The DSP was adopted by the Board of Directors effective May 17, 1999.  Thepurpose of the DSP is to increase directors' stock ownership through stock-basedcompensation.  The DSP provides for an annual stock grant valued at $40,000.  TheDSP was amended effective January 1, 2008 to increase the value of the awardgrant to $45,000.

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

The portion of IDACORP'sdefinitive proxy statement appearing under the caption  "Related PersonTransaction Disclosure" and "Corporate Governance - Director Independence" tobe filed pursuant to Regulation 14A for the 2008 Annual Meeting of Shareholdersto be held on May 15, 2008 is hereby incorporated by reference.

**ITEM14.  PRINCIPAL ACCOUNTANT FEES AND SERVICES**

**IDACORP:**

The portion of IDACORP'sdefinitive proxy statement appearing under the caption "Independent AccountantBillings" in the proxy statement to be filed pursuant to Regulation 14A for the2008 Annual Meeting of Shareholders to be held on May 15, 2008 is herebyincorporated by reference.

**IPC:**

The following table presentsfees billed for professional services rendered by Deloitte & Touche LLP,the member firms of Deloitte Touche Tohmatsu, and their respective affiliates(collectively, Deloitte & Touche), for the fiscal years ended December 31,2007 and 2006.  The amounts presented below reflect allocations from IDACORPfor IPC's portion of the fees, as well as amounts billed directly to IPC.

** **

**2007**

** **

**2006**

 
Audit fees

$

1,148,354

$

726,048

 
Audit-related fees (1)

62,520

46,000

 
Tax fees (2)

114,486

391,175

 
All other fees

-

-

 
Total

$

1,325,360

$

1,163,223

 
 
(1)

Includes fees for audits of  IPC's benefit plans and agreed upon procedures at a subsidiary.

(2)

Includes fees for tax  consulting in connection with263A settlement guidelines and uniform  capitalization    issues.

**Policy on Audit CommitteePre-Approval**IPC and the Audit Committee are committed to ensuring the independence of theindependent registered public accounting firm, both in fact and in appearance. In this regard, on February 4, 2004, the Audit Committee established a pre-approvalpolicy in accordance with applicable securities rules.  All fees were pre-approvedby the Audit Committee in 2006 and 2007.

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In addition to the audits ofIPC's consolidated financial statements, the independent public accounting firmmay be engaged to provide certain audit-related, tax and other services.  TheAudit Committee must pre-approve all services performed by the independentpublic accounting firm to assure that the provision of those services does notimpair the public accounting firm's independence.  The services that the AuditCommittee will consider include audit services such as attest services, changesin the scope of the audit of the financial statements, and the issuance ofcomfort letters and consents in connection with financings; audit-relatedservices such as internal control reviews and assistance with internal controlreporting requirements; attest services related to financial reporting that arenot required 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 by the independent public accountingfirm has received general pre-approval, it will require specific pre-approvalby the Audit Committee.  In addition, any proposed services exceeding pre-approvedcost levels will require specific pre-approval by the Audit Committee.  Underthe pre-approval policy, the Audit Committee has delegated to the Chairman ofthe Audit Committee pre-approval authority for proposed audit and audit-relatedservices.  The Chairman must report any pre-approval decisions to the AuditCommittee at its next scheduled meeting.

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

In determining whether to pre-approvethe engagement of the independent public accounting firm, the Audit Committeeor the Committee Chairman, as the case may be, must consider, among otherthings, the pre-approval policy, applicable rules and regulations and whetherthe nature of the engagement and the related fees are consistent with thefollowing principles, as stated in the SEC's adopting release for the rules onauditor independence:
- the independent public     accounting firm cannot function in the role of management of IPC;
- the independent public     accounting firm cannot audit its own work; and
- the independent public     accounting firm cannot serve in any advocacy role on behalf of IPC.    

The appendices to the pre-approvalpolicy describe the specific audit, audit related, tax and other services thathave the general pre-approval of the Audit Committee.  The term of any pre-approvalis 12 months from the date of pre-approval, unless the Audit Committee specificallyprovides for a different period.  The Audit Committee will periodically revisethe list of pre-approved services, based on subsequent determinations.

** **

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**PART IV**

**ITEM15.  EXHIBITS AND FINANCIAL STATEMENT SCHEDULES**

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

(3)  Exhibits.

*Previously Filed andIncorporated Herein by Reference

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*2

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

*3.1

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

*3.2

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

*3.3

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

*3.4

Articles of Amendment to  Restated Articles of Incorporation of IPC, as filed with the Secretary of  State of Idaho on June 15, 2000.  File number 1-3198, Form 10-Q for the  quarter ended June 30, 2000, filed on 8/4/00, as Exhibit 3(a)(iii).

*3.5

Articles of Amendment to Restated  Articles of Incorporation of Idaho Power Company as filed with the Secretary  of State of Idaho on January 21, 2005.  File number 1-3198, Form 8-K, filed  on 1/26/05, as Exhibit 4.5.

*3.6

Articles of Amendment to  Restated Articles of Incorporation of IPC, as amended, as filed with the  Secretary of State of Idaho on November 19, 2007.  File number 1-3198, Form  8-K, filed on 11/19/07, as Exhibit 3.3.

*3.7

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

*3.8

Amended Bylaws of IPC,  amended on November 15, 2007, and presently in effect.  File number 1-3198,  Form 8-K, filed on 11/19/07, as Exhibit 3.2.

*3.9

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

*3.10

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

*3.11

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

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*3.12

Amended Bylaws of IDACORP,  Inc., amended on November 15, 2007 and presently in effect.  File number  1-14456, Form 8-K, filed on 11/19/07, as Exhibit 3.1.

*4.1

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

*4.2

IPC Supplemental Indentures  to Mortgage and Deed of Trust:

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

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

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

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

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

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

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

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

File number 2-13689, as  Exhibit 4-K, Ninth, November 15, 1957

File number 2-14245, as  Exhibit 4-L, Tenth, April 1, 1958

File number 2-14366, as  Exhibit 2-L, Eleventh, October 15, 1958

File number 2-14935, as  Exhibit 4-N, Twelfth, May 15, 1959

File number 2-18976, as  Exhibit 4-O, Thirteenth, November 15, 1960

File number 2-18977, as  Exhibit 4-Q, Fourteenth, November 1, 1961

File number 2-22988, as  Exhibit 4-B-16, Fifteenth, September 15, 1964

File number 2-24578, as  Exhibit 4-B-17, Sixteenth, April 1, 1966

File number 2-25479, as  Exhibit 4-B-18, Seventeenth, October 1, 1966

File number 2-45260, as  Exhibit 2(c), Eighteenth, September 1, 1972

File number 2-49854, as  Exhibit 2(c), Nineteenth, January 15, 1974

File number 2-51722, as  Exhibit 2(c)(i), Twentieth, August 1, 1974

File number 2-51722, as  Exhibit 2(c)(ii), Twenty-first, October 15, 1974

File number 2-57374, as  Exhibit 2(c), Twenty-second, November 15, 1976

File number 2-62035, as  Exhibit 2(c), Twenty-third, August 15, 1978

File number 33-34222, as  Exhibit 4(d)(iii), Twenty-fourth, September 1, 1979

File number 33-34222, as  Exhibit 4(d)(iv), Twenty-fifth, November 1, 1981

File number 33-34222, as  Exhibit 4(d)(v), Twenty-sixth, May 1, 1982

File number 33-34222, as  Exhibit 4(d)(vi), Twenty-seventh, May 1, 1986

File number 33-00440, as  Exhibit 4(c)(iv), Twenty-eighth, June 30, 1989

File number 33-34222, as  Exhibit 4(d)(vii), Twenty-ninth, January 1, 1990

File number 33-65720, as  Exhibit 4(d)(iii), Thirtieth, January 1, 1991

File number 33-65720, as  Exhibit 4(d)(iv), Thirty-first, August 15, 1991

File number 33-65720, as  Exhibit 4(d)(v), Thirty-second, March 15, 1992

File number 33-65720, as  Exhibit 4(d)(vi), Thirty-third, April 1, 1993

File number 1-3198, Form  8-K, filed on 12/20/93, as Exhibit 4, Thirty-fourth, December 1, 1993

File number 1-3198, Form  8-K, filed on 11/21/00, as Exhibit 4, Thirty-fifth, November 1, 2000

File number 1-3198, Form  8-K, filed on 10/1/01, as Exhibit 4, Thirty-sixth, October 1, 2001

File number 1-3198, Form  8-K, filed on 4/16/03, as Exhibit 4, Thirty-seventh, April 1, 2003

File number 1-3198, Form  10-Q for the quarter ended June 30, 2003, filed on 8/7/03, as Exhibit  4(a)(iii), Thirty-eighth, May 15, 2003

File number 1-3198, Form  10-Q for the quarter ended September 30, 2003, filed on 11/6/03, as Exhibit  4(a)(iii), Thirty-ninth, October 1, 2003

File number 1-3198, Form  8-K filed 5/10/05, as Exhibit 4, Fortieth, May 1, 2005.

File number 1-3198, Form  8-K filed 10/10/06, as Exhibit 4, Forty-first, October 1, 2006.

File number 1-3198, Form  8-K filed 6/4/07, as Exhibit 4, Forty-second, May 1, 2007.

File number 1-3198, Form  8-K filed 9/26/07, as Exhibit 4, Forty-third, September 1, 2007.

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*4.3

Instruments relating to IPC  American Falls bond guarantee (see Exhibit 10.4).  File number 1-3198, Form  10-Q for the quarter ended June 30, 2000, filed on 8/4/00, as Exhibit 4(b).

*4.4

Agreement of IPC to furnish  certain debt instruments.  File number 33-65720, Form S-3, filed on 7/7/93,  as Exhibit 4(f).

*4.5

Agreement of IDACORP, Inc.  to furnish certain debt instruments.  File number 1-14465, Form 10-Q for the  quarter ended September 30, 2003, filed on 11/6/03, as Exhibit 4(c)(ii).

*4.6

Agreement and Plan of  Merger dated March 10, 1989, between Idaho Power Company, a Maine  Corporation, and Idaho Power Migrating Corporation.  File number 33-00440,  Post-Effective Amendment No. 2 to Form S-3, filed on 6/30/89, as Exhibit  2(a)(iii).

*4.7

Rights Agreement, dated as  of September 10, 1998, between IDACORP, Inc. and Wells Fargo Bank, N.A., as  successor to The Bank of New York, as Rights Agent.  File number 1-14465,  Form 8-K, filed on 9/15/98, as Exhibit 4.

*4.8

First  Amendment to Rights Agreement, dated as of May 14, 2007, between IDACORP,  Inc. and Wells Fargo Bank, N.A., as successor to The Bank of New York, as  Rights Agent.  File number 333-143404, Form S-8, filed on 5/31/07, as Exhibit  4(g).

*4.9

Indenture for Senior Debt  Securities dated as of February 1, 2001, between IDACORP, Inc. and Deutsche  Bank Trust Company Americas (formerly known as Bankers Trust Company), as  trustee.  File number 1-14465, Form 8-K, filed on 2/28/01, as Exhibit 4.1.

*4.10

First Supplemental  Indenture dated as of February 1, 2001 to Indenture for Senior Debt  Securities dated as of February 1, 2001 between IDACORP, Inc. and Deutsche  Bank Trust Company Americas (formerly known as Bankers Trust Company), as  trustee.  File number 1-14465, Form 8-K, filed on 2/28/01, as Exhibit 4.2.

*4.11

Indenture for Debt  Securities dated as of August 1, 2001 between Idaho Power Company and  Deutsche Bank Trust Company Americas (formerly known as Bankers Trust  Company), as trustee.  File number 333-67748, Form S-3, filed on 8/16/01, as  Exhibit 4.13.

*10.1

Agreements, dated September  22, 1969, between IPC and Pacific Power & Light Company relating to the  operation, construction and ownership of the Jim Bridger Project.  File  number 2-49584, as Exhibit 5(b).

*10.2

Amendment, dated February  1, 1974, relating to operation agreement filed as Exhibit 10.1.  File number  2-51762, as Exhibit 5(c). 

*10.3

Agreement, dated as of  October 11, 1973, between IPC and Pacific Power & Light Company.  File  number 2-49584, as Exhibit 5(c).

*10.4

Guaranty Agreement, dated  April 11, 2000, between IPC and Bank One Trust Company, N.A., as Trustee,  relating to $19,885,000 American Falls Replacement Dam Refinancing Bonds of  the American Falls Reservoir District, Idaho.  File number 1-3198, Form 10-Q  for the quarter ended June 30, 2000, filed on 8/4/00, as Exhibit 10(c).

*10.5

Guaranty Agreement, dated  as of August 30, 1974, between IPC and Pacific Power & Light Company.   File number 2-62034, Form S-7, filed on 6/30/78, as Exhibit 5(r).

*10.6

Letter Agreement, dated  January 23, 1976, between IPC and Portland General Electric Company.  File  number 2-56513, as Exhibit 5(i).

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*10.7

Agreement for Construction,  Ownership and Operation of the Number One Boardman Station on Carty  Reservoir, dated as of October 15, 1976, between Portland General Electric  Company and IPC.  File number 2-62034, Form S-7, filed on 6/30/78, as Exhibit  5(s).

*10.8

Amendment, dated September  30, 1977, relating to agreement filed as Exhibit 10.6.  File number 2-62034,  Form S-7, filed on 6/30/78, as Exhibit 5(t).

*10.9

Amendment, dated October  31, 1977, relating to agreement filed as Exhibit 10.6.  File number 2-62034,  Form S-7, filed on 6/30/78, as Exhibit 5(u).

*10.10

Amendment, dated January  23, 1978, relating to agreement filed as Exhibit 10.6.  File number 2-62034,  Form S-7 filed on 6/30/78, as Exhibit 5(v).

*10.11

Amendment, dated February  15, 1978, relating to agreement filed as Exhibit 10.6.  File number 2-62034,  Form S-7, filed on 6/30/78, as Exhibit 5(w).

*10.12

Amendment, dated September  1, 1979, relating to agreement filed as Exhibit 10.6.  File number 2-68574,  Form S-7, filed on 7/23/80, as Exhibit 5(x).

*10.13

Participation Agreement,  dated September 1, 1979, relating to the sale and leaseback of coal handling  facilities at the Number One Boardman Station on Carty Reservoir.  File  number 2-68574, Form S-7, filed on 7/23/80, as Exhibit 5(z).

*10.14

Agreements for the  Operation, Construction and Ownership of the North Valmy Power Plant Project,  dated December 12, 1978, between Sierra Pacific Power Company and IPC.  File  number 2-64910, Form S-7, filed on 6/29/79, as Exhibit 5(y).  

10.151

Idaho Power Company  Security Plan for Senior Management Employees I - a non-qualified, deferred  compensation plan, amended and restated effective December 31, 2004, and as  further amended March 14, 2007.  

*10.161

Idaho Power Company  Security Plan for Senior Management Employees II, a non-qualified, deferred  compensation plan, effective January 1, 2005, as amended July 20, 2006.  File  number 1-14465, 1-3198, Form 10-Q for the quarter ended September 30, 2006,  filed on 11/2/06, as Exhibit 10(h)(xxxv).

*10.17 1

IDACORP, Inc. Restricted  Stock Plan, as amended and restated September 20, 2007.  File number 1-14465,  1-3198, Form 10-Q for the quarter ended September 30, 2007, filed on  10/31/07, as Exhibit 10(h)(iii). 

*10.18 1

IDACORP, Inc. Restricted  Stock Plan - Form of Restricted Stock Agreement (time-vesting) (July 20,  2006).  File number 1-14465, 1-3198, Form 10-Q for the quarter ended  September 30, 2006, filed on 11/2/06, as Exhibit 10(h)(vi).

*10.19 1

IDACORP, Inc. Restricted  Stock Plan - Form of Performance Stock Agreement (performance vesting) (July  20, 2006).  File number 1-14465, 1-3198, Form 10-Q for the quarter ended  September 30, 2006, filed on November 2, 2006, as Exhibit 10(h)(vii).

*10.20 1

Idaho Power Company  Security Plan for Board of Directors - a non-qualified deferred compensation  plan, as amended and restated effective July 20, 2006.  File number 1-14465,  1-3198, Form 10-Q for the quarter ended September 30, 2006, filed on 11/2/06,  as Exhibit 10(h)(viii).

10.21 1

IDACORP, Inc. Non-Employee  Directors Stock Compensation Plan, as amended and restated on November 15,  2007. 

*10.221

Form of Officer  Indemnification Agreement between IDACORP, Inc. and Officers of IDACORP, Inc.  and IPC, as amended July 20, 2006.  File number 1-14465, 1-3198, Form 10-Q  for the quarter ended September 30, 2006, filed on 11/2/06, as Exhibit  10(h)(xix).

*10.231

Form of Director  Indemnification Agreement between IDACORP, Inc. and Directors of IDACORP,  Inc., as amended July 20, 2006.  File number 1-14465, 1-3198, Form 10-Q for  the quarter ended September 30, 2006, filed on 11/2/06, as Exhibit 10(h)(xx).

*10.241

Form of Change in Control  Agreement between IDACORP, Inc. and Officers of IDACORP and IPC (senior vice  president and higher), as amended July 20, 2006.  File number 1-14465,  1-3198, Form 10-Q for the quarter ended September 30, 2006, filed on 11/2/06,  as Exhibit 10(h)(x).

*10.25 1

Form of Change in Control  Agreement between IDACORP, Inc. and Officers of IDACORP and IPC (below senior  vice president), as amended July 20, 2006.  File number 1-14465, 1-3198, Form  10-Q for the quarter ended September 30, 2006, filed on 11/2/06, as Exhibit  10(h)(xi).

*10.261

IDACORP, Inc. 2000  Long-Term Incentive and Compensation Plan, as amended and restated September  20, 2007.  File number 1-14465, 1-3198, Form 10-Q for the quarter ended  September 30, 2007, filed on 10/31/07, as Exhibit 10(h)(xii). 

*10.271

IDACORP, Inc. 2000  Long-Term Incentive and Compensation Plan - Form of Stock Option Award  Agreement (July 20, 2006).  File number 1-14465, 1-3198, Form 10-Q for the  quarter ended September 30, 2006, filed on 11/2/06, as Exhibit 10(h)(xvi).

*10.281

IDACORP, Inc. 2000  Long-Term Incentive and Compensation Plan - Form of Restricted Stock Award  Agreement (time vesting) (July 20, 2006).  File number 1-14465, 1-3198, Form  10-Q for the quarter ended September 30, 2006, filed on 11/2/06, as Exhibit  10(h)(xvii).

*10.291

IDACORP, Inc. 2000  Long-Term Incentive and Compensation Plan - Form of Restricted Stock Award  Agreement (performance vesting) (July 20, 2006).  File number 1-14465,  1-3198, Form 10-Q for the quarter ended September 30, 2006, filed on 11/2/06,  as Exhibit 10(h)(xviii).

*10.301

IDACORP, Inc. 2000  Long-Term Incentive and Compensation Plan - Form of Performance Share Award  Agreement (performance with two goals) (July 20, 2006).  File number 1-14465,  1-3198, Form 10-Q for the quarter ended September 30, 2006, filed on 11/2/06,  as Exhibit 10(h)(xxxiii).

*10.311

IDACORP, Inc. Executive  Incentive Plan.  File Number 1-14465, 1-3198, Form 8-K/A, filed on 2/27/08,  as Exhibit 10.1.

*10.321

Idaho  Power Company Executive Deferred Compensation Plan, effective November 15,  2000, as amended July 20, 2006.  File number 1-14465, 1-3198, Form 10-Q for  the quarter ended September 30, 2006, filed on 11/2/06, as Exhibit  10(h)(xxxvi).

10.331

IDACORP,  Inc. and IPC 2008 Compensation for Non-Employee Directors of the Board of  Directors. 

*10.34

Framework Agreement, dated  October 1, 1984, between the State of Idaho and IPC relating to IPC's Swan  Falls and Snake River water rights.  File number 33-65720, Form S-3, filed on  7/7/93, as Exhibit 10(h).

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*10.35

Agreement, dated October  25, 1984, between the State of Idaho and IPC relating to the agreement filed  as Exhibit 10.34.  File number 33-65720, Form S-3, filed on 7/7/93, as  Exhibit 10(h)(i).

*10.36

Contract to Implement,  dated October 25, 1984, between the State of Idaho and IPC relating to the  agreement filed as Exhibit 10.34.  File number 33-65720, Form S-3, filed on  7/7/93, as Exhibit 10(h)(ii).

*10.37

Agreement Regarding the  Ownership, Construction, Operation and Maintenance of the Milner  Hydroelectric Project (FERC No. 2899), dated January 22, 1990, between IPC  and the Twin Falls Canal Company and the Northside Canal Company Limited.   File number 33-65720, Form S-3, filed on 7/7/93, as Exhibit 10(m). 

*10.38

Guaranty Agreement, dated  February 10, 1992, between IPC and New York Life Insurance Company, as Note  Purchaser, relating to $11,700,000 Guaranteed Notes due 2017 of Milner Dam  Inc.  File number 33-65720, Form S-3, filed on 7/7/93, as Exhibit 10(m)(i).

*10.39

Power Purchase Agreement  between IPC and PPL Montana, LLC, dated March 1, 2003 and Revised  Confirmation Agreement dated May 9, 2003.  File number 1-3198, Form 10-Q for  the quarter ended June 30, 2003, filed on 8/7/03, as Exhibit 10(k).

*10.40

$100 Million Five-Year  Amended and Restated Credit Agreement, dated as of April 25, 2007, among  IDACORP, Inc., various lenders, Wachovia Bank, National Association, as  administrative agent, swingline lender and LC issuer, JPMorgan Chase Bank,  N.A., as syndication agent, and KeyBank National Association, Wells Fargo  Bank, N.A. and Bank of America, N.A., as documentation agents, and Wachovia  Capital Markets, LLC and J. P. Morgan Securities Inc., as joint lead  arrangers and joint book runners.  File number 1-14465, Form 10-Q for the  quarter ended March 31, 2007, filed on 5/9/07, as Exhibit 10(l).

*10.41

$300 Million Five-Year  Amended and Restated Credit Agreement, dated as of April 25, 2007, among  Idaho Power Company, various lenders, Wachovia Bank, National Association, as  administrative agent, swingline lender and LC issuer, JPMorgan Chase Bank,  N.A., as syndication agent, and KeyBank National Association, US Bank  National Association and Bank of America, N.A., as documentation agents, and  Wachovia Capital Markets, LLC and J. P. Morgan Securities Inc., as joint lead  arrangers and joint book runners.  File number 1-3198, Form 10-Q for the  quarter ended March 31, 2007, filed on 5/9/07, as Exhibit 10(m).

*10.42

Loan Agreement, dated  October 1, 2006, between Sweetwater County, Wyoming and IPC.  File number  1-3198, Form 8-K, filed on 10/10/2006, as Exhibit 10.1.

12.1

Statement Re:  Computation  of Ratio of Earnings to Fixed Charges.  (IDACORP, Inc.)

12.2

Statement Re:  Computation  of Supplemental Ratio of Earnings to Fixed Charges.  (IDACORP, Inc.)

12.3

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

12.4

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

12.5

Statement Re:  Computation  of Ratio of Earnings to Fixed Charges.  (IPC)

12.6

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.

31.1

IDACORP, Inc. Rule 13a-14(a)  CEO certification.

31.2

IDACORP, Inc. Rule  13a-14(a) CFO certification.

31.3

IPC Rule 13a-14(a) CEO certification.

31.4

IPC Rule 13a-14(a) CFO certification.

32.1

IDACORP, Inc. Section 1350 CEO  certification.

32.2

IDACORP, Inc. Section 1350  CFO certification.

32.3

IPC Section 1350 CEO  certification.

32.4

IPC Section 1350 CFO certification.

1 Management contract or  compensatory plan or arrangement

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** **

**IDACORP,Inc.SCHEDULE I - CONDENSED FINANCIAL INFORMATION OFREGISTRANT**

**CONDENSEDSTATEMENTS OF INCOME**

**Year Ended December 31,**

**2007**

**2006**

**2005**

(thousands of dollars)

**Income:**

Equity  in income from continuing operations of subsidiaries

 $

85,742  

 $

106,006  

 $

90,001  

Other  income

1,363  

854  

721  

Total  income

87,105  

106,860  

90,722  

**Expenses:**

Operating  expenses

3,253  

7,080  

5,189  

Interest  expense

4,143  

4,225  

3,816  

Other  expense

70  

120  

231  

Total  expenses

7,466  

11,425  

9,236  

**Income from Continuing  Operations Before Income Taxes**

79,639  

95,435  

81,486  

** **

**Income Tax Benefit**

(2,633)

(4,640)

(4,230)

** **

**Income from Continuing  Operations**

82,272  

100,075  

85,716  

** **

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

67  

7,328  

(22,055)

** **

**Net income**

 $

82,339  

 $

107,403  

 $

63,661  

The accompanying note is an integral part of these  statements.

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**IDACORP,Inc.SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT**

**CONDENSEDBALANCE SHEETS**

** December 31,**

**2007**

**2006**

(thousands of dollars)

**Assets**

**Current Assets:**

Cash  and cash equivalents

 $

1,300  

$

4,724  

Receivables

2,741  

1,649  

Refundable  income tax deposit

45,695  

44,903  

Deferred  income taxes

53,770  

27,807  

Other

773  

288  

Total  current assets

104,279  

79,371  

**Investment in  subsidiaries**

1,227,981  

1,148,106  

** **

**Other Assets**

Intercompany  notes receivable

-    

2,800  

Deferred  income taxes

1,828  

2,373  

Other

2,541  

773  

Total  other assets

4,369  

5,946  

Total

 $

1,336,629  

 $

1,233,423  

**Liabilities and  Shareholders' Equity**

**Current Liabilities:**

Notes  payable

 $

49,860  

 $

76,800  

Accounts  payable

4,478  

3,269  

Taxes  accrued

47,733  

216  

Other

177  

25  

Total  current liabilities

102,248  

80,310  

**Other Liabilities:**

Intercompany  notes payable

22,652  

24,434  

Other

4,414  

4,496  

Total  other liabilities

27,066  

28,930  

**Shareholders' Equity**

1,207,315  

1,124,183  

** **

Total

 $

1,336,629  

$

1,233,423  

The accompanying note is an integral part of these  statements.

135

Table ofContents

**IDACORP,Inc.SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT**

**CONDENSEDSTATEMENTS OF CASH FLOWS**

**Year Ended December 31,**

**2007**

**2006**

**2005**

(thousands of dollars)

**Operating Activities:**

Net  cash provided by operating activities

 $

39,332  

 $

41,196  

 $

35,462  

**Investing Activities:**

Contributions  to subsidiaries

(51,000)

(64,533)

-    

Change  in intercompany notes receivable

880  

4,196  

1,271  

Sale  of ITI

-    

21,548  

-    

Sale  of IDACOMM

7,858  

-    

-    

Reimbursement  by subsidiary of refundable tax deposit

43,927  

-    

-    

Net  cash provided by (used in) investing activities

1,665  

(38,789)

1,271  

**Financing Activities:**

Issuance  of common stock

37,181  

41,465  

6,296  

Dividends  on common stock

(53,012)

(51,272)

(50,690)

Increase  (decrease) in short-term borrowings

(26,940)

16,700  

24,700  

Change  in intercompany notes payable

(626)

(6,814)

(17,971)

Other

(1,024)

1,004  

(471)

Net  cash provided by (used in) financing activities

(44,421)

1,083  

(38,136)

Net  increase (decrease) in cash and cash equivalents

(3,424)

3,490  

(1,403)

Cash  and cash equivalents at beginning of year

4,724  

1,234  

2,637  

Cash  and cash equivalents at end of year

 $

1,300  

 $

4,724  

 $

1,234  

The accompanying note is an integral part of these  statements.

**IDACORP,Inc.SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT**

**NOTESTO CONDENSED FINANCIAL STATEMENTS**

**1.  BASIS OF  PRESENTATION**

Pursuant to rules and  regulations of the Securities and Exchange Commission, the unconsolidated  condensed financial statements of IDACORP, Inc. do not reflect all of the  information and notes normally included with financial statements prepared in  accordance with accounting principles generally accepted in the United States  of America.  Therefore, these financial statements should be read in  conjunction with the consolidated financial statements and related notes  included in the 2007 Form 10-K, Part II, Item 8.

**Accounting for  subsidiaries**

IDACORP has accounted for  the earnings of its subsidiaries under the equity method in the  unconsolidated condensed financial statements.

136

Table ofContents

** **

**IDACORP,Inc.SCHEDULE II - CONSOLIDATED VALUATION ANDQUALIFYING ACCOUNTS**

**YearsEnded December 31, 2007, 2006 and 2005**

**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)**

** **

2007:

Reserves Deducted From

Applicable Assets:

Reserve for uncollectible  accounts 

$

7,168

$

2,093

$

-

$

1,756

$

7,505

Reserve for uncollectible  notes

1,879

-

-

-

1,879

Deferred tax assets

1,565

-

-

1,565

-

Other Reserves:

Rate  refunds

1,227

2,893

-

1,723

2,397

Injuries  and damages reserve

666

2,457

-

2,462

661

Miscellaneous  operating reserves

6

3

-

5

4

2006:

Reserves Deducted From

Applicable Assets:

Reserve for uncollectible  accounts 

$

33,078

$

3,079

$

-

$

28,989

$

7,168

Reserve for uncollectible  notes

1,879

-

-

-

1,879

Deferred tax assets

1,565

-

-

-

1,565

Other Reserves:

Rate  refunds

-

1,227

-

-

1,227

Injuries  and damages reserve

1,638

1,914

-

2,886

666

Miscellaneous  operating reserves

36

-

-

30

6

2005:

Reserves Deducted From

Applicable Assets:

Reserve for uncollectible  accounts 

$

43,108

$

1,026

$

-

$

11,056

$

33,078

Reserve for uncollectible  notes

2,578

-

-

699

1,879

Deferred tax assets

-

1,565

-

-

1,565

Other Reserves:

Rate  refunds

400

-

-

400

-

Injuries  and damages reserve

1,797

10,064

-

10,223

1,638

Miscellaneous  operating reserves

35

2

-

1

36

Notes:  (1) Represents  deductions from the reserves for purposes for which the reserves were  created.  In the case of

uncollectible accounts and  notes reserves, includes reversals of amounts previously written off.

137

Table ofContents

**IDAHO POWER COMPANYSCHEDULE II - CONSOLIDATED VALUATION ANDQUALIFYING ACCOUNTS****Years Ended December 31, 2007, 2006,2005**

**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)**

** **

2007:

Reserves Deducted From

Applicable Assets:

Reserve for uncollectible  accounts 

$

968

$

2,093

$

-

$

1,756

$

1,305

Other Reserves:

Rate  refunds

1,227

2,893

-

1,723

2,397

Injuries  and damages reserve

665

1,210

-

1,214

661

Miscellaneous  operating reserves

6

3

-

5

4

2006:

Reserves Deducted From

Applicable Assets:

Reserve for uncollectible  accounts 

$

833

$

3,079

$

-

$

2,944

$

968

Other Reserves:

Rate  refunds

-

1,227

-

-

1,227

Injuries  and damages reserve

1,191

1,445

-

1,971

665

Miscellaneous  operating reserves

36

-

-

30

6

2005:

Reserves Deducted From

Applicable Assets:

Reserve for uncollectible  accounts 

$

1,363

$

1,026

$

-

$

1,556

$

833

Other Reserves:

Rate  refunds

400

-

-

400

-

Injuries  and damages reserve

1,797

6,973

-

7,579

1,191

Miscellaneous  operating reserves

35

2

-

1

36

Notes:  (1) Represents  deductions from the reserves for purposes for which the reserves were  created.  In the case of

uncollectible accounts and  notes reserves, includes reversals of amounts previously written off.

138

Table ofContents

**SIGNATURES**Pursuant to the requirements ofSection 13 or 15(d) of the Securities Exchange Act of 1934, the registrant hascaused this report to be signed on its behalf by the undersigned, thereuntoduly authorized.

IDACORP,Inc.(Registrant)

February 28, 2008

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

Pursuant to the requirementsof the Securities Exchange Act of 1934, this report has been signed below bythe following persons on behalf of the registrant and in the capacities and onthe dates indicated.

By:

*/s/Jon H. Miller*

Chairman of the Board

February 28, 2008

Jon H. Miller

By:

*/s/J. LaMont Keen*

President and Chief  Executive

"

J. LaMont Keen

Officer and Director

(Principal Executive  Officer)

* *

By:

*/s/Darrel T. Anderson*

Senior Vice President -  Administrative

"

Darrel T. Anderson

Services and Chief  Financial Officer

(Principal Financial  Officer)

(Principal Accounting  Officer)

By:

*/s/Judith A. Johansen*

By:

*/s/Richard G. Reiten*

"

Judith A. Johansen

Richard G. Reiten

Director

Director

By:

*/s/Christine King*

By:

*/s/Joan H. Smith*

"

Christine King

Joan H. Smith

Director

Director

By:

*/s/Gary G. Michael*

By:

*/s/Robert A. Tinstman*

"

Gary G. Michael

Robert A. Tinstman

Director

Director

By:

*/s/Peter S. O'Neill*

By:

*/s/Thomas J. Wilford*

"

Peter S. O'Neill

Thomas J. Wilford

Director

Director

By:

*/s/Jan B. Packwood*

* *

Jan B. Packwood

Director

139

Table ofContents

**SIGNATURES**

Pursuant to the requirementsof Section 13 or 15(d) of the Securities Exchange Act of 1934, the registranthas caused this report to be signed on its behalf by the undersigned, thereuntoduly authorized.

IDAHOPOWER COMPANY(Registrant)

February 28, 2008

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

Pursuant to the requirementsof the Securities Exchange Act of 1934, this report has been signed below bythe following persons on behalf of the registrant and in the capacities and onthe dates indicated.

By:

*/s/Jon H. Miller*

Chairman of the Board

February 28, 2008

Jon H. Miller

By:

*/s/J. LaMont Keen*

President and Chief  Executive

"

J. LaMont Keen

Officer and Director

(Principal Executive  Officer)

By:

*/s/Darrel T. Anderson*

Senior Vice President -  Administrative

"

Darrel T. Anderson

Services and Chief  Financial Officer

(Principal Financial  Officer)

(Principal Accounting  Officer)

By:

*/s/Judith A. Johansen*

By:

*/s/Richard G. Reiten*

"

Judith A. Johansen

Richard G. Reiten

Director

Director

By:

*/s/Christine King*

By:

*/s/Joan H. Smith*

"

Christine King

Joan H. Smith

Director

Director

By:

*/s/Gary G. Michael*

By:

*/s/Robert A. Tinstman*

"

Gary G. Michael

Robert A. Tinstman

Director

Director

By:

*/s/Peter S. O'Neill*

By:

*/s/Thomas J. Wilford*

"

Peter S. O'Neill

Thomas J. Wilford

Director

Director

By:

*/s/Jan B. Packwood*

* *

Jan B. Packwood

Director

140

Table ofContents

**EXHIBITINDEX**

10.151

Idaho  Power Company Security Plan for Senior Management Employees I - a  non-qualified, deferred compensation plan, amended and restated effective  December 31, 2004, and as further amended March 14, 2007.

10.211

IDACORP,  Inc. Non-Employee Directors Stock Compensation Plan, as amended and restated  on November 15, 2007.

10.331

IDACORP, Inc. and IPC 2008  Compensation for Non-Employee Directors of the Board of Directors.

12.1

Statement Re:  Computation  of Ratio of Earnings to Fixed Charges.  (IDACORP, Inc.)

12.2

Statement Re:  Computation  of Supplemental Ratio of Earnings to Fixed Charges. (IDACORP, Inc.) 

12.3

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

12.4

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

12.5

Statement Re:  Computation  of Ratio of Earnings to Fixed Charges.  (IPC)

12.6

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.

31.1

IDACORP, Inc. Rule  13a-14(a) CEO certification.

31.2

IDACORP, Inc. Rule  13a-14(a) CFO certification.

31.3

IPC Rule 13a-14(a) CEO  certification.

31.4

IPC Rule 13a-14(a) CFO certification.

32.1

IDACORP, Inc. Section 1350 CEO  certification.

32.2

IDACORP, Inc. Section 1350  CFO certification.

32.3

IPC Section 1350 CEO certification.

32.4

IPC Section 1350 CFO certification.

1 Management contract or  compensatory plan or arrangement

141 |
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