UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549

FORM 8-K

CURRENT REPORT

PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

Date of Report (Date of earliest event reported):  May 24, 2010

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

[ ] Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
[ ] Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
[ ] Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
[ ] Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

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Item 8.01  Other Events.

Idaho and Oregon Rate Orders

Idaho Power Company (“IPC”) received several rate orders from the Idaho Public Utilities Commission (“IPUC”) and the Oregon Public Utility Commission (“OPUC”) between May 24, 2010 and May 28, 2010, as described below.

Power Cost Adjustment

On April 15, 2010, IPC filed an application with the IPUC to implement new Power Cost Adjustment (“PCA”) rates to be effective June 1, 2010 through May 31, 2011, and to change base rates. IPC’s application stated that the proposed PCA computations result from the stipulation approved by the IPUC in its order issued in January 2010, which provides for a sharing between customers and IPC shareholders of any PCA rate reduction that results from the 2010 PCA.  The January 2010 stipulation provides that PCA rates will be reduced by the full calculated amount and that base rates will be increased in an amount that partially offsets the PCA decrease.

On May 28, 2010, the IPUC issued its order approving a $146.9 million decrease in the PCA, along with a base rate increase of $88.7 million.  The net effect of these two rate adjustments is an overall decrease in customer rates of $58.2 million, or 6.49%, effective June 1, 2010. IPC’s PCA application was approved as filed with the exception of a $215,000 interest expense adjustment relating to base power supply costs.

The IPUC’s order identified two specific items of contention raised by certain industrial customers of IPC:  (1) the prudency of IPC’s determination of coal costs for the Jim Bridger plant, and (2) the use of the load growth adjustment rate (“LGAR”) in times of load decline.  The IPUC approved the full Jim Bridger coal costs included in the base level power supply costs and the amount included in IPC’s PCA forecast, finding that IPC had met its burden of proof to establish the reasonableness of the coal costs to be included in the base level power supply costs. With regard to the LGAR, IPC’s true-up calculation for the PCA included a negative load growth adjustment under the LGAR of $21.3 million for the Idaho jurisdiction.  The IPUC did not remove this adjustment to the PCA component, but directed the IPUC Staff to meet with IPC and other Northwest utilities to evaluate the current load growth adjustment mechanisms.

Pension Expense Recovery

On March 15, 2010, IPC filed an application with the IPUC for an order approving an increase in rates, effective June 1, 2010, to allow recovery of IPC’s 2009 cash contribution to its defined benefit pension plan, which contribution is expected to be made in September 2010.  IPC’s application sought approval of $5.42 million in pension cost recovery over a one-year amortization period to allow recovery contemporaneous with IPC’s 2009 cash contributions to the defined benefit pension plan.

On May 28, 2010, the IPUC approved IPC’s request to increase rates by 0.77%, or $5.42 million. IPC’s application requested amortization of expense recovery using calculations based on monthly forecasted revenues from June 1, 2010 through May 31, 2011.  However, the IPUC Staff recommended a straight-line amortization period of 12 months in the regulatory asset account, and the IPUC adopted this recommendation in its order.

The IPUC’s order provided that the allowance of recovery of the 2009 pension plan contribution does not imply that the IPUC will similarly approve future recovery of contributions, without evidence that IPC has evaluated alternatives to reduce the burden placed on customers.  The IPUC stated in its order that “Idaho Power is advised that, previous orders notwithstanding, approval of the Company’s pension contributions in this case does not guarantee Commission approval of future pension plan contributions.  Authority for the balancing account and regulatory account remain in place.  However, further justification is required before additional rate recovery for future contributions will be authorized.”

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Advanced Metering Infrastructure

IPC’s advanced metering infrastructure (“AMI”) project provides the means to automatically retrieve energy consumption information, eliminating manual meter reading expense.  On March 15, 2010, IPC filed an application with the IPUC requesting authority to implement a 0.41% average increase (representing a 0.33% overall increase) in rates for identified customer classes.  IPC’s AMI investment during the 2010 test year indicated a revenue deficiency of $2.36 million for the Idaho jurisdiction, which resulted from IPC’s increase in rate base from the AMI deployment, the accelerated depreciation of existing metering equipment, and the inclusion of net operating and maintenance expense related to the AMI deployment.  On May 28, 2010, the IPUC approved IPC’s application as submitted, authorizing the rate increase effective June 1, 2010.

Fixed Cost Adjustment Mechanism

In March 2007, the IPUC approved the implementation of a fixed cost adjustment mechanism (“FCA”) pilot program for IPC’s residential and small general service customers.  The FCA is a rate mechanism designed to remove IPC’s disincentive to invest in energy efficiency programs by separating (or decoupling) the recovery of fixed costs from the variable kilowatt-hour charge and linking it instead to a set amount per customer.  The FCA allows IPC to recover the difference between certain fixed costs recovered in rates and the fixed costs authorized for recovery in IPC’s most recent rate case.  The pilot program began on January 1, 2007 and ended on December 31, 2009.  On April 29, 2010, the IPUC approved a two-year extension of the FCA pilot program effective January 1, 2010.

On March 15, 2010, IPC filed an application with the IPUC requesting authorization to implement FCA rates for electric service from June 1, 2010 through May 31, 2011.  On May 28, 2010, the IPUC approved IPC’s request.  As a result, beginning June 1, 2010, IPC implemented an overall rate increase of 1.85% to residential and small general service customers.  The rate adjustment represents 0.1218 cents/kilowatt-hour for residential customers and 0.1535 cents/kilowatt-hour for small general service customers.  The rate adjustments are expected to result in collection of an additional $3.6 million over currently billed amounts and will be in place until May 31, 2011.  In its order, the IPUC reiterated a statement in its prior order that making the FCA permanent is premature, and that during the two year extension of the FCA program it expects additional data to develop, giving interested parties and customers time to evaluate the FCA and address issues of concern.

Oregon Annual Power Cost Update

Pursuant to an order of the OPUC, IPC annually updates its net power supply expense included in its Oregon rates through an automatic adjustment clause, referred to as the annual power cost update (“APCU”).  The APCU is comprised of two primary components: an October power cost update and a March power cost forecast.  The October update contains IPC’s forecasted net power supply expense reflected on a normalized and unit basis for an April through March test period.  The March forecast contains IPC’s net power supply expense based upon updated actual forecasted conditions.  The rates from the October update and March forecast are combined, and that combined rate is then included in rates effective on June 1 of each year.

On October 19, 2009, IPC filed the October update portion of its 2010 APCU with the OPUC.  On March 23, 2010, IPC filed with the OPUC the March forecast portion of its 2010 APCU.  Also on March 23, 2010, the OPUC Staff, the Citizens Utility Board of Oregon (“CUB”), and the Oregon Industrial Customers of Idaho Power entered into a partial stipulation resolving certain issues regarding the rate spread for APCU results, and on April 15, 2010, IPC, the OPUC Staff, and the CUB filed with the OPUC a revenue requirement stipulation.

On May 24, 2010, the OPUC approved the 2010 APCU, as set forth in the March 23, 2010 and April 15, 2010 stipulations, effective as of June 1, 2010 for Oregon customers.  The 2010 APCU resulted in an overall increase of 5.53% in Oregon base rates, based on increases of between 2.15% and 15.25% depending on customer class. Residential customer rates were increased by an average of 3.82%.  The rate adjustments are expected to result in collection of an additional $2.2 million over currently billed amounts over the 12-month APCU adjustment period beginning June 1, 2010.

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In the Oregon jurisdiction, IPC also uses a power cost adjustment mechanism (“PCAM”) that consists of an annual power supply expense true-up, which uses an asymmetrical dead band to calculate the net power supply deviations used in the true-up calculations.  In the April 15, 2010 stipulation, which was approved in the OPUC’s May 24, 2010 order, IPC agreed to a one-time modification to the dead band used to calculate the net power supply deviations in the 2010 PCAM.  As adjusted, the dead band is increased by $153,650 before any excess power costs are subject to collection pursuant to the terms of the PCAM, and the dead band is reduced by $153,650 before any power costs are subject to return pursuant to the terms of the PCAM.

Oregon Energy Efficiency Rider

Effective June 1, 2010, the OPUC approved IPC’s application to increase its energy efficiency rider from 1.5% of base rates to 3.0% of base rates.  Additionally, the monthly funding caps on residential and commercial customers were eliminated.  The increased rider funding percentage is expected to result in an additional $0.8 million annual demand-side management funding for a total of approximately $1.2 million per year.

FERC ITSA

On May 24, 2010, IPC filed an offer of settlement with the Federal Energy Regulatory Commission (“FERC”) in Docket No. ER09-1335.  In June 2009, IPC had filed for authority to increase rates to PacifiCorp under the Agreement for Interconnection and Transmission Services (“ITSA”) to the Open Access Transmission Tariff (“OATT”) level.  In August 2009, the FERC accepted the rates subject to refund.  The May 2010 offer of settlement agreed to with PacifiCorp affirms those rates.  Therefore, if approved, under the settlement PacifiCorp will take and pay for 250 MW of long term firm point-to-point transmission service, pursuant to the ITSA, the rates, terms, and conditions of which will be equivalent to IPC’s OATT.  The offer of settlement has been negotiated with the FERC Trial Staff, PacifiCorp, and other parties to the proceeding, and all parties either support or do not oppose the settlement.  It was requested that FERC act on the filing by June 30, 2010.

Memorandum of Understanding with PacifiCorp

On June 4, 2010, in connection with its planned filing with the FERC of the previously disclosed non-binding Memorandum of Understanding, dated March 5, 2010, between IPC and PacifiCorp ( “MOU”), IPC posted a copy of the MOU on its Open Access Same-Time Information System (“OASIS”) web site, www.oatioasis.com/ipco/index.html.  A copy of the MOU posted on the OASIS web site is included as Exhibit 99.1 to this Current Report on Form 8-K.

Forward-Looking Information

Certain statements contained in this Current Report on Form 8-K, including statements with respect to future earnings, ongoing operations, and financial conditions, are forward-looking statements within the meaning of federal securities laws.  Although IDACORP and Idaho Power Company believe that the expectations and assumptions reflected in these forward-looking statements are reasonable, these statements involve a number of risks and uncertainties, and actual results may differ materially from the results discussed in the statements.  Factors that could cause actual results to differ materially from the forward-looking statements include:  the effect of regulatory decisions by the Idaho Public Utilities Commission, the Oregon Public Utility Commission and the Federal Energy Regulatory Commission affecting our ability to recover costs and/or earn a reasonable rate of return including, but not limited to, the disallowance of costs that have been deferred; changes in and compliance with state and federal laws, policies and regulations including new interpretations by oversight bodies, which include the Federal Energy Regulatory Commission, the North American Electric Reliability Corporation, the Western Electricity Coordinating Council, the Idaho Public Utilities Commission and the Oregon Public Utility Commission, of existing policies and regulations that affect the cost of compliance, investigations and audits, penalties and costs of remediation that may or may not be recoverable through rates; changes in tax laws or related regulations or new interpretations of applicable law by the Internal Revenue Service or other taxing jurisdictions; 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 laws, regulations, and policies including changes in law and compliance with environmental, natural resources, endangered species and safety laws, regulations and policies and the adoption of laws and regulations addressing greenhouse gas emissions, global

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 climate change, and energy policies; global climate change and regional weather variations affecting customer demand and hydroelectric generation; over-appropriation of surface and groundwater in the Snake River Basin resulting in reduced generation at hydroelectric facilities; construction of power generation, 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 performance below expected levels, breakdown or failure of equipment, availability of transmission and fuel supply; changes in operating expenses and capital expenditures, including costs and availability of materials, fuel and commodities; blackouts or other disruptions of Idaho Power Company’s transmission system or the western interconnected transmission system; population growth rates and other demographic patterns; market prices and demand for energy, including structural market changes; increases in uncollectible customer receivables; fluctuations in sources and uses of cash; results of financing efforts, including the ability to obtain financing or refinance existing debt when necessary or on favorable terms, which can be affected by factors such as credit ratings, volatility in the financial markets and other economic conditions; actions by credit rating agencies, including changes in rating criteria and new interpretations of existing criteria; changes in interest rates or rates of inflation; performance of the stock market, interest rates, credit spreads and other financial market conditions, as well as changes in government regulations, which affect the amount and timing of required contributions to pension plans and the reported costs of providing pension and other postretirement benefits; increases in health care costs and the resulting effect on medical benefits paid for employees; increasing costs of insurance, changes in coverage terms and the ability to obtain insurance; homeland security, acts of war or terrorism; natural disasters and other natural risks, such as earthquake, flood, drought, lightning, wind and fire; 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 such forward-looking statements should be considered in light of such factors and others noted in the companies’ Annual Report on Form 10-K for the year ended December 31, 2009, Form 10-Q for the first quarter ended March 31, 2010 and other reports on file with the Securities and Exchange Commission.  Any forward-looking statement speaks only as of the date on which such statement is made.  New factors emerge from time to time and it is not possible for management to predict all such factors, nor can it assess the impact of any such factor on the business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement.

Item 9.01  Financial Statements and Exhibits.

(d) Exhibits.  The following exhibits are being furnished as part of this Report.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrants have duly caused this report to be signed on their behalf by the undersigned hereunto duly authorized.

Dated:  June 4, 2010

IDACORP, Inc.

By:   /s/ Darrel T. Anderson
Darrel T. Anderson
Executive Vice President -
Administrative Services
and Chief Financial Officer

IDAHO POWER COMPANY

By:   /s/ Darrel T. Anderson
Darrel T. Anderson
Executive Vice President -
Administrative Services
and Chief Financial Officer

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EXHIBIT INDEX

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