Non-Employee Director Stock Comp Plan.CURRENT.02-26-10 (00006618).DOC

IDACORP, INC. AND IDAHO POWER COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

This Quarterly Report on Form 10-Q is a combined report of IDACORP, Inc. (IDACORP) and Idaho Power Company (Idaho Power). Therefore, the Notes to the condensed consolidated financial statements apply to both IDACORP and Idaho Power. However, Idaho Power makes no representation as to the information relating to IDACORP’s other operations.

Nature of Business

IDACORP is a holding company formed in 1998 whose principal operating subsidiary is Idaho Power. IDACORP is subject to the provisions of the Public Utility Holding Company Act of 2005, which provides certain access to books and records to the Federal Energy Regulatory Commission (FERC) and state utility regulatory commissions and imposes certain record retention and reporting requirements on IDACORP.

Idaho Power is an electric utility with a service territory covering approximately 24,000 square miles in southern Idaho and eastern Oregon. Idaho Power is regulated by the FERC and the state regulatory commissions of Idaho and Oregon. Idaho Power is the parent of Idaho Energy Resources Co. (IERCo), a joint venturer in Bridger Coal Company (BCC), which supplies coal to the Jim Bridger generating plant owned in part by Idaho Power.

IDACORP’s other subsidiaries include 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.

Principles of Consolidation

IDACORP’s and Idaho Power’s consolidated financial statements include the accounts of each company, the subsidiaries that the companies control, and any variable interest entities (VIEs) for which the companies are the primary beneficiaries. All significant intercompany balances have been eliminated in consolidation. Investments in subsidiaries that the companies do not control and investments in VIEs for which the companies are not the primary beneficiaries, but have the ability to exercise significant influence over operating and financial policies, are accounted for using the equity method of accounting.

In January 2010, IDACORP and Idaho Power adopted amendments to prior consolidation guidance. The amendments affected the overall consolidation analysis of VIEs and required IDACORP and Idaho Power to reconsider their previous conclusions relating to the consolidation of VIEs, including (1) whether an entity is a VIE, (2) whether either IDACORP or Idaho Power are the VIE’s primary beneficiary, and (3) what type of financial statement disclosures are required. The adoption of this guidance did not change the entities that IDACORP or Idaho Power consolidate.

The entities that IDACORP and Idaho Power consolidate consist primarily of the wholly-owned subsidiaries discussed above. In addition, IDACORP consolidates one VIE, Marysville Hydro Partners (Marysville), which is a joint venture owned 50 percent by Ida-West and 50 percent by Environmental Energy Company (EEC). Marysville has approximately $25 million of assets, primarily a hydroelectric plant, and approximately $17 million of intercompany long-term debt, which is eliminated in consolidation. EEC has borrowed amounts from Ida-West to fund a portion of its required capital contributions to Marysville. The loans are payable from EEC’s share of distributions and are secured by the stock of EEC and EEC’s interest in Marysville. Ida-West is the primary beneficiary because the ownership of the intercompany note and the EEC note result in it controlling the entity. Creditors of Marysville have no recourse to the general credit of IDACORP and there are no other arrangements that could require IDACORP to provide financial support to Marysville or expose IDACORP to losses.

Through IERCo, Idaho Power holds a variable interest in BCC, a VIE for which it is not the primary beneficiary. IERCo is not the primary beneficiary because the power to direct the activities that most significantly impact the economic performance of BCC is shared with the joint venture partner. IERCo’s carrying value is $87 million and its maximum exposure to loss at BCC is the carrying value, any additional future contributions to the mine and the $63 million guarantee for reclamation costs at the mine which is discussed further in “Note 8 – Commitments.”

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Through IFS, IDACORP also holds variable interests in VIEs for which it is not the primary beneficiary. These VIEs are historic rehabilitation and affordable housing developments in which IFS holds limited partnership interests ranging from five to 99 percent. As a limited partner, IFS does not control these entities and they are not consolidated. These investments were acquired between 1996 and 2010. IFS’s maximum exposure to loss in these developments is limited to its net carrying value, which was $82 million at March 31, 2010.

Financial Statements

In the opinion of IDACORP and Idaho Power, the accompanying unaudited condensed consolidated financial statements contain all adjustments necessary to present fairly their consolidated financial positions as of March 31, 2010, and consolidated results of operations for the three months ended March 31, 2010, and 2009, and consolidated cash flows for the three months ended March 31, 2010, and 2009. These adjustments are of a normal and recurring nature. These financial statements do not contain the complete detail or footnote disclosure concerning accounting policies and other matters that would be included in full-year financial statements and should be read in conjunction with the audited consolidated financial statements included in IDACORP’s and Idaho Power’s Annual Report on Form 10-K for the year ended December 31, 2009. The results of operations for the interim periods are not necessarily indicative of the results to be expected for the full year.

Use of Estimates

The preparation of condensed consolidated financial statements in accordance with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent liabilities, as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results experienced could differ materially from those estimates.

Reclassifications

Certain prior year amounts have been reclassified to conform to the current year presentation. The reclassifications did not impact IDACORP’s and Idaho Power’s net income or total equity, and include the following:

• Third-party transmission expense was combined with purchased power in IDACORP and Idaho Power’s condensed consolidated statements of income as the balance of the third party transmission expense alone is immaterial;

• Gain on sale of emission allowances was combined with other operations and maintenance in IDACORP and Idaho Power’s condensed consolidated statements of income as the balance of gain on sale of emission allowances alone is immaterial;

• Other operations and maintenance in the operating expenses section of Idaho Power’s condensed consolidated statements of income were combined to be consistent with presentation in IDACORP’s condensed consolidated statements of income;

• Allowance for uncollectible accounts was offset against associated accounts receivable and presented in a parenthetical notation in IDACORP and Idaho Power’s condensed consolidated balance sheets;

• Excess tax benefit from share-based payment arrangements was combined with other non-cash adjustments to net income in the operating section and with other in the financing section of IDACORP’s condensed consolidated statements of cash flows; and

• Amortization of affordable housing was removed from depreciation and amortization and combined with undistributed earnings of unconsolidated subsidiaries, the total of which was then separated into losses (earnings) of unconsolidated equity-method investments and distributions from unconsolidated equity method investments in the operating section of IDACORP’s condensed consolidated statements of cash flows.

2. INCOME TAXES:

In accordance with interim reporting requirements, IDACORP and Idaho Power use an estimated annual effective tax rate for computing provisions for income taxes. An estimate of annual income tax expense (or benefit) is made each interim period using estimates for annual pre-tax income, income tax adjustments and tax credits. The estimated annual effective tax rates do not include discrete events such as tax law changes, examination settlements or method changes. Discrete events are recorded in the period in which they occur.

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The estimated annual effective tax rate is applied to year-to-date pre-tax income to achieve income tax expense (or benefit) for the interim period consistent with the annual estimate. In subsequent interim periods, income tax expense (or benefit) for the period is computed as the difference between the year-to-date amount reported for the previous interim period and the current period’s year-to-date amount.

An analysis of income tax expense for the three months ending March 31 is as follows (in thousands of dollars):

		IDACORP				Idaho Power
		2010		2009		2010		2009
Income tax provision		$	4,914	$	6,796	$	5,915	$	9,773
ADITC amortization			(4,512)		-		(4,512)		-
Medicare Part D subsidy			903		-		903		-
	Income tax expense	$	1,305	$	6,796	$	2,306	$	9,773

Effective tax rate			7.5%		26.5%		11.2%		33.6%

The decrease in the 2010 estimated annual effective tax rates from 2009 is primarily due to lower pre-tax earnings at IDACORP and Idaho Power and Idaho Power’s additional amortization of accumulated deferred investment tax credits (ADITC), partially offset by a charge related to the federal health care legislation enacted in the first quarter of 2010. Regulatory flow-through tax adjustments at Idaho Power and tax credits at IFS were comparable quarter-over-quarter. For further information regarding ADITC amortization, see “Note 3 – REGULATORY MATTERS - Idaho Settlement Agreement.”

The Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act were enacted in March 2010. One provision of this legislation eliminates the deductibility of employer health care costs for retiree prescription drug expenses that are covered by federal subsidy payments equivalent to Medicare Part D. While this provision is not effective until 2013, relevant income tax accounting guidance requires recognition of the future effects of new law in the period of enactment. Due to the regulatory treatment of postretirement benefit costs, the increase in certain postretirement costs relating to the legislation is deferred as a regulatory asset. Accordingly, Idaho Power reduced its deferred tax asset related to future deductible retiree prescription drug expenses by $2.3 million, increased regulatory assets by $2.4 million, increased deferred tax liabilities by $1 million and incurred a charge of $0.9 million for the three months ended March 31, 2010.

Status of Audit Proceedings

In May 2009, IDACORP formally entered the Internal Revenue Service (IRS) Compliance Assurance Process (CAP) program for its 2009 tax year. The CAP program provides for IRS examination throughout the year. The 2009 examination is expected to be completed in 2010. In January 2010, IDACORP was accepted into CAP for its 2010 tax year. IDACORP and Idaho Power are unable to predict the outcome of these examinations.

Specifically within the 2009 CAP examination, the IRS began its audit of Idaho Power’s current method of uniform capitalization. In September 2009, the IRS issued Industry Director Directive #5 (IDD), which discusses the IRS’s compliance priorities and audit techniques related to the allocation of mixed service costs in the uniform capitalization methods of electric utilities. The IRS and Idaho Power are jointly working through the impact the IDD guidance has on Idaho Power’s uniform capitalization method. Idaho Power expects that the examination will be completed during 2010. Resolution of this matter would result in a decrease to Idaho Power’s unrecognized tax benefits for its 2009 uniform capitalization deduction by $1.1 million, may reduce Idaho Power’s need to amortize additional ADITC in 2010 and is not expected to have an adverse effect on Idaho Power’s financial position, results of operations, or cash flows.

3. REGULATORY MATTERS:

Idaho Settlement Agreement

On January 13, 2010, the Idaho Public Utilities Commission (IPUC) approved a settlement agreement among Idaho Power, several of Idaho Power’s customers, the IPUC Staff and others. Significant elements of the settlement agreement include:

• A general rate moratorium in effect until January 1, 2012. The moratorium does not apply to other specified revenue requirement proceedings, such as the power cost adjustment (PCA), the fixed cost adjustment (FCA), pension funding, advanced metering infrastructure (AMI), energy efficiency rider, and government imposed fees.

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• A specified distribution of the expected reduction in 2010 PCA rates that would reduce customer rates, provide some general rate relief to Idaho Power and reset base power supply costs for the PCA. This provision anticipated a significant reduction in PCA rates for the 2010-2011 PCA year. The PCA reduction and base rate adjustment is discussed in “2010 PCA filing” below.

• A provision to share with Idaho customers 50 percent of any Idaho-jurisdictional earnings in excess of a 10.5 percent return on equity in any calendar year from 2009 to 2011.

• A provision to allow additional amortization of ADITC if Idaho Power’s actual return on equity in its Idaho jurisdiction is below 9.5 percent in any calendar year from 2009 to 2011. Idaho Power is permitted to amortize additional ADITC in an amount up to $45 million over the three-year period, but could use no more that $15 million in any one year unless there is a carryover. Carryover amounts are added to the $15 million annual allowance up to a maximum amortization of $25 million in any one year.

Because Idaho Power’s 2009 Idaho-jurisdiction return on equity was between 9.5 and 10.5 percent, the sharing and additional amortization provisions were not triggered, and the ADITC available for additional amortization in 2010 is $25 million. For the three months ended March 31, 2010, Idaho Power recorded additional ADITC amortization of $4.5 million as a result of including an estimated annual amount in its effective tax rate. The actual amount of additional ADITC recorded in the full year 2010 will depend on Idaho Power’s annual return on year-end equity, and the amounts recorded in each quarter will vary and may ultimately be reversed.

The agreement also included a provision to reestablish the base level for net power supply costs effective with the June 1, 2010, PCA rate change. On April 13, 2010, the IPUC approved an increase of up to $63.7 million for such base net power supply costs, deferring final calculation to Idaho Power’s 2010 PCA case. The open issue relates to Idaho Power’s proposed increase of $25 million in coal supply costs for the Jim Bridger plant. The increase in base net power supply costs is expected to bring Idaho Power’s total base net power supply costs closer to its actual net power supply costs, and therefore reduce the magnitude of Idaho Power’s future annual PCA adjustments.

2010 PCA Filing

On April 15, 2010, Idaho Power made its annual PCA filing with the IPUC, requesting approval of its 2010 PCA and an increase in base rates pursuant to the terms of the settlement agreement. As filed, these two rate adjustments would be a $146.7 million 2010 PCA reduction and an $88.7 million increase to base rates, both to become effective June 1, 2010. The base rate increase includes the $63.7 million increase in Idaho Power’s annual base net power supply costs, and a $25 million general increase in Idaho Power’s annual base rates.

Other Idaho 2010 Filings

Rate Filings: In March 2010, Idaho Power made the following three rate filings with the IPUC, each with a requested effective date of June 1, 2010:

• Fixed Cost Adjustment: Idaho Power’s FCA filing for the 2009 calendar year proposes to collect $6.3 million for one year, a $3.6 million annual increase over current rates. The $6.3 million reflects amounts accrued in 2009 under the mechanism.

• Pension: Idaho Power filed a request to recover $5.4 million of pension contributions that it expects to make in 2010. In accordance with IPUC orders, Idaho Power is deferring its Idaho-jurisdiction pension expense to a regulatory asset. On February 17, 2010, the IPUC approved a recovery methodology that would permit Idaho Power to include in future rate cases a reasonable amortization and recovery of cash contributions. Deferred pension costs are expected to be amortized to expense to match the revenues received when pension contributions are recovered through rates.

• AMI: Idaho Power filed for a $2.4 million annual increase in base rates related to AMI.

Energy Efficiency Prudency Determination: On March 15, 2010, Idaho Power filed an application with the IPUC requesting an order designating expenditures of $50.7 million incurred in 2008 and 2009 as prudently incurred expenses.

On April 14, 2010, the IPUC completed its review of energy efficiency rider expenditures that Idaho Power made during the 2002 through 2007 period and found that remaining amounts totaling $14.7 million were prudently incurred and approved for ratemaking purposes.

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Oregon 2009 General Rate Case Settlement

On February 24, 2010, the Oregon Public Utility Commission (OPUC) approved a $5 million, or 15.4 percent, increase in base rates. The new rates were effective March 1, 2010 and are based on a return on equity of 10.175 percent and an overall rate of return of 8.061 percent. This increase results from a joint stipulation filed by Idaho Power that settled the revenue requirement issues surrounding a general rate case filed by Idaho Power on July 31, 2009.

Oregon Power Cost Recovery Mechanisms

Idaho Power’s power cost recovery mechanism in Oregon went into effect in 2008. It has two components: the annual power cost update (APCU) and the power cost adjustment mechanism (PCAM). The combination of the APCU and the PCAM allows Idaho Power to recover excess net power supply costs in a more timely fashion than through the previously existing deferral process.

PCAM: On February 26, 2010, Idaho Power filed its PCAM application for the 2009 year with the OPUC. The filing stated that actual net power supply costs were within the deadband, which is the range of deviations within which Idaho Power absorbs cost increases or decreases, resulting in no request for a deferral.

APCU: On April 15, 2010, Idaho Power filed a stipulation combining the March forecast and October update with the OPUC. Approval of the stipulation would result in a $5.5 million annual increase in Oregon rates, effective June 1, 2010. The target date for an OPUC order is May 28, 2010.

Deferred Net Power Supply Costs

Changes in deferred power supply costs during the quarter were as follows (in thousands of dollars):

			Idaho		Oregon⁽¹⁾		Total
Balance at December 31, 2009		$	71,412	$	13,221	$	84,633
Impact of current period net power supply costs			(19,839)		(44)		(19,883)
Prior costs expensed and recovered through rates			(27,996)		(445)		(28,441)
SO₂ allowances and REC sales credited to account			(600)		(28)		(628)
Interest and other			271		220		491
	Balance at March 31, 2010	$	23,248	$	12,924	$	36,172
⁽¹⁾ Oregon power supply cost deferrals are subject to a statute that specifically limits rate amortizations of deferred costs to six percent of gross Oregon revenue per year (approximately $2 million). Deferrals are amortized sequentially.

4. LONG-TERM DEBT:

As of March 31, 2010, IDACORP had approximately $574 million remaining on a shelf registration statement that can be used for the issuance of debt securities or common stock.

In April 2010, Idaho Power received approval from the IPUC, the OPUC and the Public Service Commission of Wyoming for the issuance of up to $500 million in aggregate principal amount of one or more series of first mortgage bonds and unsecured debt securities. The order from the IPUC approved the issuance of the securities over a two-year period, beginning on April 19, 2010, subject to extension upon request to the IPUC.

5. NOTES PAYABLE:

Credit Facilities

IDACORP has a $100 million credit facility and Idaho Power has a $300 million credit facility, both of which expire on April 25, 2012. Commercial paper may be issued up to the amounts supported by the credit facilities. Under these facilities the companies pay a facility fee on the commitment, quarterly in arrears, based on its rating for senior unsecured long-term debt securities without third-party credit enhancement as provided by Moody’s Investors Service and Standard & Poor’s Ratings Services.

At March 31, 2010, no loans were outstanding on either IDACORP’s facility or Idaho Power’s facility. At March 31, 2010, Idaho Power had regulatory authority to incur up to $450 million of short-term indebtedness.

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Balances and interest rates of short-term borrowings were as follows at March 31, 2010, and December 31, 2009 (in thousands of dollars):

		March 31, 2010						December 31, 2009
				Idaho						Idaho
		IDACORP		Power		Total		IDACORP		Power		Total
Commercial paper
	outstanding	$	26,100	$	-	$	26,100	$	53,750	$	-	$	53,750

Weighted-average
	interest rate		0.35%		-		0.35%		0.41%		-		0.41%

6. COMMON STOCK:

The following table summarizes shares of IDACORP stock issued during the three months ended March 31, 2010:

		Shares issued
Balance at December 31, 2009		47,925,882
Dividend reinvestment and stock purchase plan		37,829
Employee savings plan		30,211
Long-term incentive and compensation plan (LTICP) ⁽¹⁾		90,548
Restricted stock plan		13,293
	Balance at March 31, 2010	48,097,763

⁽¹⁾ Included in the LTICP activity are 15,800 shares that were issued pursuant to the exercise of stock options on December 30, 2009, and settled on January 4, 2010.

IDACORP enters into sales agency agreements as a means of selling its common stock from time to time. As of March 31, 2010, there were 2.1 million shares remaining available to be sold on the current sales agency agreement.

Restrictions on Dividends

Idaho Power’s Revised Code of Conduct approved by the IPUC on April 21, 2008, states that Idaho Power will not pay any dividends to IDACORP that will reduce Idaho Power’s common equity capital below 35 percent of its total adjusted capital without IPUC approval.

Idaho Power’s ability to pay dividends on its common stock held by IDACORP and IDACORP’s ability to pay dividends on its common stock are limited to the extent payment of such dividends would violate the covenants in their respective credit facilities or Idaho Power’s Revised Code of Conduct. At March 31, 2010, the leverage ratios for IDACORP and Idaho Power were 51 percent and 52 percent, respectively. Based on these restrictions, IDACORP’s and Idaho Power’s dividends were limited to $562 million and $519 million, respectively, at March 31, 2010. There are additional covenants, subject to exceptions, that prohibit or restrict: certain investments or acquisitions, mergers or sale or disposition of property without consent; the creation of certain liens; and any agreements restricting dividend payments to the company from any material subsidiary. At March 31, 2010, IDACORP and Idaho Power were in compliance with all facility covenants.

Idaho Power’s articles of incorporation contain restrictions on the payment of dividends on its common stock if preferred stock dividends are in arrears. Idaho Power has no preferred stock outstanding.

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Idaho Power must obtain approval of the OPUC before it could directly or indirectly loan funds or issue notes or give credit on its books to IDACORP.

7. EARNINGS PER SHARE:

The following table presents the computation of IDACORP’s basic and diluted earnings per share (EPS) for the three months ended March 31, 2010 and 2009 (in thousands, except for per share amounts):

				Three months ended
				March 31,
				2010			2009
Numerator:
	Net income attributable to IDACORP, Inc.			$	16,063	$		18,884
Denominator:
	Weighted-average common shares outstanding - basic				47,773			46,831
	Effect of dilutive securities:
		Options			41			13
		Restricted Stock			71			32
			Weighted-average common shares outstanding – diluted		47,885			46,876
Basic and diluted earnings per share				$	0.34	$		0.40

The diluted EPS computation excluded 346,000 options for the three months ended March 31, 2010, because the options’ exercise prices were greater than the average market price of the common stock during that period. For the same period in 2009, there were 687,485 options excluded from the diluted EPS computation for the same reason. In total, 585,662 options were outstanding at March 31, 2010, with expiration dates between 2010 and 2015.

8. COMMITMENTS:

Purchase Obligations

The following item is the only material change to purchase obligations made outside of the ordinary course of business during the first quarter of 2010:

• Idaho Power entered into a purchase power agreement with USG Oregon, LLC for the purchase of energy from the Neal Hot Springs Unit #1 geothermal electric generation facility. The project will be located near Vale, Oregon and the expected output will be approximately 22 MW, with an estimated on-line date of late 2012. Idaho Power’s purchases under the contract are expected to total $569 million from 2011-2037. The agreement is pending approval from the IPUC.

Guarantees
Idaho Power has agreed to guarantee the performance of reclamation activities and obligations at BCC, of which IERCo owns a one-third interest. This guarantee, which is renewed each December, was $63 million at March 31, 2010. BCC has a reclamation trust fund set aside specifically for the purpose of paying these reclamation costs. BCC continually assesses the adequacy of the reclamation trust fund and its estimate of future reclamation costs. To ensure that the reclamation trust fund maintains adequate reserves, BCC has the ability to add a per-ton surcharge to coal sales. In 2010, BCC began applying a nominal surcharge to coal sales in order to maintain adequate reserves in the reclamation trust fund. Because of the existence of the fund and the ability to apply a per-ton surcharge, the estimated fair value of this guarantee is minimal.

9. CONTINGENCIES:

Western Energy Proceedings at the FERC

In this report, the term “western energy situation” is used to refer to the California energy crisis that occurred during 2000 and 2001, and the energy shortages, high prices and blackouts in the western United States. High prices for electricity in California and in western wholesale markets during 2000 and 2001 caused numerous purchasers of electricity in those markets to initiate proceedings seeking refunds or other forms of relief and FERC to initiate its own investigations. Some of these proceedings (the western energy proceedings) remain pending before the FERC or on appeal to the United States Court of Appeals for the Ninth Circuit (Ninth Circuit).

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There are pending in the Ninth Circuit approximately 200 petitions for review of numerous FERC orders regarding the western energy situation. Decisions in these appeals may have implications with respect to other pending cases, including those to which Idaho Power or IE are parties. Idaho Power and IE intend to vigorously defend their positions in these proceedings, but are unable to predict the outcome of these matters. Except as to the matters described below under “Pacific Northwest Refund,” Idaho Power and IE believe that settlement releases they have obtained that are described below under “California Refund” and “Market Manipulation” will restrict potential claims that might result from the disposition of the pending Ninth Circuit review petitions and that these matters will not have a material adverse effect on their consolidated financial positions, results of operations or cash flows.

California Refund: This proceeding originated with an effort by agencies of the State of California and investor-owned utilities in California to obtain refunds for a portion of the spot market sales from sellers of electricity into California markets from October 2, 2000, through June 20, 2001. The FERC has issued numerous orders establishing price mitigation plans for sales in the California wholesale electricity market, including the methodology for determining refunds. IE and numerous other parties have petitioned the Ninth Circuit for review of the FERC’s orders on California refunds. As additional FERC orders have been issued, further petitions for review have been filed before the Ninth Circuit, which from time to time has identified discrete cases that can proceed to briefing and decision while it stayed action on the other consolidated cases.

On May 22, 2006, the FERC approved an Offer of Settlement between and among IE and Idaho Power, the California Parties (Pacific Gas & Electric Company, San Diego Gas & Electric Company, Southern California Edison Company, the California Public Utilities Commission, the California Electricity Oversight Board, the California Department of Water Resources (CDWR) and the California Attorney General) and additional parties that elected to be bound by the settlement. The settlement disposed of matters encompassed by the California refund proceeding, as well as market manipulation claims and investigations relating to the western energy situation among and between the parties agreeing to be bound by it. Although many market participants agreed to be bound by the settlement, other market participants, representing a small minority of potential refund claims, initially elected not to be bound by the settlement. From time to time, as the California Parties have reached settlements with those other market participants, they have elected to opt into the IE-Idaho Power-California Parties’ settlement. The settlement provided for approximately $23.7 million of IE’s and Idaho Power’s estimated $36 million rights to accounts receivable from the California Independent System Operator (Cal ISO) and the California Power Exchange (CalPX) to be assigned to an escrow account for refunds and for an additional $1.5 million of accounts receivable to be retained by the CalPX until the conclusion of the litigation. The additional $1.5 million of accounts receivable retained by the CalPX is available to fund the claims of non-settling parties if they prevail in the remaining litigation of these California market matters. Any additional amounts owed to non-settling parties would be funded by other amounts owed to IE and Idaho Power by the Cal ISO and CalPX, or directly by IE and Idaho Power, and any excess funds remaining at the end of the case would be returned to IE and Idaho Power. The remaining IE and Idaho Power receivables were paid to IE and Idaho Power under the settlement.

In an August 2006 decision, the Ninth Circuit ruled that all transactions that occurred within the CalPX and the Cal ISO markets were proper subjects of the refund proceeding. In that decision the Ninth Circuit refused to expand the proceedings into the bilateral market, approved the refund effective date as October 2, 2000, required the FERC to consider claims that some market participants had violated governing tariff obligations at an earlier date than the refund effective date, and expanded the scope of the refund proceeding to include transactions within the CalPX and Cal ISO markets outside the limited 24-hour spot market and energy exchange transactions. Parts of the decision exposed sellers to increased claims for potential refunds. The Ninth Circuit issued its mandate on April 15, 2009, thereby officially returning the cases to the FERC for further action consistent with the court’s decision.

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On November 19, 2009, the FERC issued an order to implement the Ninth Circuit’s remand. The remand order established a trial-type hearing in which participants will be permitted to submit information regarding (i) specified tariff violations committed by any public utility seller from January 1, 2000 - October 2, 2000 resulting in a transaction that set a market clearing price for the trading period when the violation occurred, and (ii) claims for refunds for multi-day transactions and energy exchange transactions entered into during the refund period (October 2, 2000 – June 20, 2001). Numerous parties, including IE and Idaho Power, filed motions to clarify the FERC’s order. Although IE and Idaho Power are unable to predict when or how FERC will rule on these motions, the effect of the remand order for IE and Idaho Power is confined to the minority of market participants that are not bound by the IE-Idaho Power-California Parties’ settlement described above. Accordingly, IE and Idaho Power believe the remanded proceedings will not have a material adverse effect on their consolidated financial positions, results of operations or cash flows.

In 2005, the FERC established a framework for sellers wanting to demonstrate that the generally applicable FERC refund methodology interfered with the recovery of costs. IE and Idaho Power made such a cost filing, which was rejected by the FERC. On June 18, 2009, FERC issued an order stating that it was not ruling on IE’s and Idaho Power’s request for rehearing of the cost filing rejection because their request had been withdrawn in connection with the IE-Idaho Power-California Parties’ settlement. On July 8, 2009, IE and Idaho Power sought further rehearing at the FERC because their withdrawal pertained only to the parties with whom IE and Idaho Power had settled. On June 18, 2009, in a separate order, the FERC ruled that only net refund recipients were responsible for the costs associated with cost filings. While most net refund recipients are bound by the settlement, until the Cal ISO completes its refund calculations, it is uncertain whether there are any net refund recipients who are not bound by the settlement. If there are no such parties, then IE’s and Idaho Power’s request for rehearing will be moot. FERC has not yet ruled on the request for rehearing. IE and Idaho Power are unable to predict how or when the FERC might rule, but the effect of any such ruling is confined to obligations of IE and Idaho Power to the small minority of claims of market participants that are not bound by the settlement. Accordingly, IE and Idaho Power believe this matter will not have a material adverse effect on their consolidated financial positions, results of operations or cash flows.

Market Manipulation: On June 25, 2003, the FERC ordered approximately 50 entities that participated in the western wholesale power markets between January 1, 2000, and June 20, 2001, including Idaho Power, to show cause why certain trading practices did not constitute gaming or other forms of proscribed market behavior in concert with another party (partnership) in violation of the Cal ISO and CalPX Tariffs. In 2004, the FERC dismissed the partnership show cause proceeding against Idaho Power. Later in 2004, the FERC approved a settlement of the gaming proceeding without finding of wrongdoing by Idaho Power.

The orders establishing the scope of the show cause proceedings are presently the subject of review petitions in the Ninth Circuit. On March 29, 2010, IE and Idaho Power filed a motion with the Ninth Circuit to dismiss 11 of the 12 petitions for review of FERC’s orders establishing the scope of the show cause proceedings as they relate to IE and Idaho Power. Although IE and Idaho Power had obtained the consent to the motion from the 11 petitioners in those proceedings, the Ninth Circuit misconstrued the motion and instead granted on April 1, 2010, a motion to withdraw IE and Idaho Power interventions in the review proceedings. On April 9, 2010, with the consent of the same 11 petitioners, IE and Idaho Power filed a motion for reconsideration with the Ninth Circuit, again requesting dismissal of the 11 petitions as they pertain to IE and Idaho Power. Although IE and Idaho Power are unable to predict how or when the Ninth Circuit will act on the motion for reconsideration or the review petitions, in light of the settlement described above, IE and Idaho Power believe this matter will not have a material adverse effect on their consolidated financial positions, results of operations or cash flows.

On June 25, 2003, the FERC also issued an order instituting an investigation of anomalous bidding behavior and practices in the western wholesale markets for the time period May 1, 2000, through October 1, 2000, but the FERC terminated its investigations as to Idaho Power on May 12, 2004. California government agencies and California investor-owned utilities have appealed the FERC’s termination of this investigation as to Idaho Power and more than 30 other market participants. IE and Idaho Power are unable to predict the outcome of these petitions for review proceedings, but believe that the settlement releases govern any potential claims that might arise and that this matter will not have a material adverse effect on their consolidated financial positions, results of operations or cash flows.

Pacific Northwest Refund: On July 25, 2001, the FERC issued an order establishing a proceeding separate from the California refund proceeding to determine whether there may have been unjust and unreasonable charges for spot market sales in the Pacific Northwest during the period December 25, 2000, through June 20, 2001, because the spot market in the Pacific Northwest was affected by the dysfunction in the California market. In 2003, the FERC terminated the proceeding and declined to order refunds, but in 2007 the Ninth Circuit issued an opinion, in Port of Seattle, Washington v. FERC, remanding to the FERC the orders that declined to require refunds. The Ninth Circuit’s opinion instructed the FERC to consider whether evidence of market manipulation would have altered the agency’s conclusions about refunds and directed the FERC to include sales originating in the Pacific Northwest to the CDWR in the scope of proceeding. The Ninth Circuit officially returned the case to the FERC on April 16, 2009. On September 4, 2009, IE and Idaho Power joined with a number of other parties in a joint petition for a writ of certiorari to the U.S. Supreme Court, which was denied on January 11, 2010.

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In separate filings, the California Parties, which no longer include the California Electricity Oversight Board, and the City of Tacoma, Washington (Tacoma) and the Port of Seattle, Washington (Port of Seattle) asked the FERC to reorganize and restructure the case to enable them to pursue claims that all spot market sales in the Cal ISO and CalPX markets and in the Pacific Northwest from January 1, 2000 through June 20, 2001 should be subject to refund and repriced, because market manipulation and tariff violations affected spot market prices. Their requests would expand the scope of the refund period in the Pacific Northwest proceeding from the December 25, 2000 through June 20, 2001 period previously considered by the FERC. On May 22, 2009, the California Parties filed a motion with the FERC to sever claims regarding sales originating in the Pacific Northwest to CDWR from the remainder of the Pacific Northwest proceedings and to consolidate their claims regarding these sales with ongoing proceedings in cases that IE and Idaho Power have settled, as well as with a new complaint filed on May 22, 2009 by the California Attorney General against parties with whom the California Parties have not settled (Brown Complaint). IE and Idaho Power, along with a number of other parties, filed their opposition to the motion of the California Parties. Many other parties also filed responses to the motion of the California Parties. Tacoma and the Port of Seattle jointly filed a motion on August 4, 2009 with the FERC in connection with the California refund proceeding, the Lockyer remand pending before the FERC (involving claims of failure to file quarterly transaction reports with the FERC, from which IE and Idaho Power previously were dismissed), the Brown Complaint and the Pacific Northwest refund remand proceeding. The Tacoma and the Port of Seattle motion asks the FERC to require refunds from all sellers in the Pacific Northwest spot markets for the expanded period (January 1, 2000 through June 20, 2001). IE and Idaho Power joined with a number of other sellers in the Pacific Northwest markets during 2000 and 2001 in opposing the motion of Tacoma and the Port of Seattle. On April 19, 2010, the California Parties filed a motion with the FERC renewing the requests contained in their May 22, 2009, motion and on May 3, 2010, IE and Idaho Power joined with a number of other parties opposing the renewal request. FERC has not acted on the Ninth Circuit remand or the motions. IE and Idaho Power intend to vigorously defend their positions in these proceedings, but are unable to predict the outcome of these matters or estimate the impact these matters may have on their consolidated financial positions, results of operations or cash flows.

Sierra Club Lawsuit – Bridger

In February 2007, the Sierra Club and the Wyoming Outdoor Council filed a complaint against PacifiCorp in the U.S. District Court for the District of Wyoming alleging thousands of violations by PacifiCorp of air quality opacity standards at the Jim Bridger coal-fired plant in Sweetwater County, Wyoming. Opacity is an indication of the amount of light obscured by the flue gas of a power plant. The complaint sought a declaration that PacifiCorp had violated opacity limits, a permanent injunction ordering PacifiCorp to comply with such limits, civil penalties of up to $32,500 per day per violation, and reimbursement of plaintiffs’ costs of litigation, including reasonable attorneys’ fees. Idaho Power is not a party to 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. On April 15, 2010, the parties jointly filed a proposed consent decree resolving the pending litigation. The consent decree must be reviewed by the Environmental Protection Agency and approved by the court. Idaho Power is fully reserved for the contingency and, if approved, the entry of the consent decree will not have a material adverse effect on Idaho Power’s consolidated financial position, results of operations or cash flows.

Sierra Club Lawsuit – Boardman

In September 2008, the Sierra Club and four other non-profit corporations filed a complaint against Portland General Electric Company (PGE) in the U.S. District Court for the District of Oregon alleging opacity permit limit violations at the Boardman coal-fired plant located in Morrow County, Oregon. The complaint also alleged violations of the Clean Air Act, related federal regulations and the Oregon State Implementation Plan relating to PGE’s construction and operation of the plant. The complaint sought a declaration that PGE had violated opacity limits, a permanent injunction ordering PGE to comply with such limits, injunctive relief requiring PGE to remediate alleged environmental damage and ongoing impacts, civil penalties of up to $32,500 per day per violation, and reimbursement of plaintiffs’ costs of litigation, including reasonable attorneys’ fees. Idaho Power is not a party to this proceeding but has a 10 percent ownership interest in the Boardman plant. PGE owns 65 percent and is the operator of the plant. On December 5, 2008, PGE filed a motion to dismiss nine of the twelve claims asserted by the plaintiffs in their complaint, and on September 30, 2009, the court denied most of PGE’s motion to dismiss. Idaho Power continues to monitor the status of this matter but is unable to predict its outcome or what effect this matter may have on its consolidated financial position, results of operations or cash flows.

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Snake River Basin Adjudication

Idaho Power is engaged in the Snake River Basin Adjudication (SRBA), a general stream adjudication commenced in 1987, to define the nature and extent of water rights in the Snake River Basin in Idaho, including the water rights of Idaho Power.
On March 25, 2009, Idaho Power and the State of Idaho (State) entered into a settlement agreement with respect to the 1984 Swan Falls Agreement and Idaho Power’s water rights under the Swan Falls Agreement, which settlement agreement is subject to certain conditions discussed below. The settlement agreement will also resolve litigation between Idaho Power and the State relating to the Swan Falls Agreement that was filed by Idaho Power on May 10, 2007, with the Idaho District Court for the Fifth Judicial Circuit, which has jurisdiction over SRBA matters, including the Swan Falls case.

The settlement agreement resolves the pending litigation by clarifying that Idaho Power’s water rights in excess of minimum flows at its hydroelectric facilities between Milner Dam and Swan Falls Dam are subordinate to future upstream beneficial uses, including aquifer recharge. The agreement commits the State and Idaho Power to further discussions on important water management issues concerning the Swan Falls Agreement and the management of water in the Snake River Basin. It also recognizes that water management measures that enhance aquifer levels, springs and river flows, such as aquifer recharge projects, benefit both agricultural development and hydropower generation and deserve study to determine their economic potential, their impact on the environment and their impact on hydropower generation. These will be a part of the Comprehensive Aquifer Management Plan (CAMP) approved by the Idaho Water Resource Board for the Eastern Snake Plain Aquifer (ESPA), which includes limits on the amount of aquifer recharge. Idaho Power is a member of the ESPA CAMP advisory committee and implementation committee.

On April 24, 2009, the Governor of Idaho signed into law legislation approving provisions contained in the settlement agreement. On May 6, 2009, as part of the settlement, Idaho Power, the Governor of Idaho and the Idaho Water Resource Board executed a memorandum of agreement relating to future aquifer recharge efforts and further assurances as to limitations on the amount of aquifer recharge. Idaho Power and the State also filed a joint motion to the SRBA court to dismiss the Swan Falls case and enter the stipulated water right decrees set forth in the settlement agreement. Parties representing groundwater users in the Eastern Snake Plain Aquifer objected to some of the language proposed by Idaho Power and the State relating to water rights in the decrees to be entered by the SRBA court as contemplated by the Settlement Agreement. Specifically, the concerns relate to the language describing the subordination of the rights and its interplay with the original Swan Falls settlement document and implementing legislation. On January 4, 2010, the court issued an order approving the overall settlement subject to certain modifications to the draft water right decrees proposed by the company and the state. Idaho Power continues to work with the State and the parties to reach agreement consistent with the court’s order regarding the language of the decrees.

U.S. Bureau of Reclamation

Idaho Power filed a complaint on October 15, 2007, and an amended complaint on September 30, 2008, in the U.S. District Court of Federal Claims in Washington, D.C. against the U.S. Bureau of Reclamation. The complaint relates to a 1923 contract right for delivery of water to Idaho Power’s hydropower projects on the Snake River, to recover damages from the U.S. for the lost generation resulting from reduced flows and for a prospective declaration of contractual rights and obligations of the parties. Over the past several months, Idaho Power has been working with the U.S. and Idaho interests (including the State of Idaho and upstream water users) in an effort to resolve certain state water right issues pending in the SRBA that are common to both the SRBA and the pending federal case. In an effort to promote efficiency, the parties have agreed to present certain legal issues associated with the 1923 contract to the court in the SRBA case that are expected to resolve issues in the pending federal case. The SRBA court has scheduled the presentation of these issues to the court by the fall of 2010. Idaho Power and the U.S. have agreed to stay further proceedings in the federal case pending the resolution of these issues in the SRBA case. Idaho Power is unable to predict the outcome of this matter.

Oregon Trail Heights Fire

On August 25, 2008, a fire ignited beneath an Idaho Power distribution line in Boise, Idaho. It was fanned by high winds and spread rapidly, resulting in one death, the destruction of 10 homes and damage or alleged fire-related losses to approximately 30 others. Following the investigation, the Boise Fire Department determined that the fire was linked to a piece of line hardware on one of Idaho Power’s distribution poles and that high winds contributed to the fire and its resultant damage. Idaho Power has received notice of claims from a number of the homeowners and their insurers and while it has continued investigation of these claims, Idaho Power has reached settlements with a number of the individuals or their insurers who have alleged damages resulting from the fire. Idaho Power is insured up to policy limits against liability for claims in excess of its self-insured retention. Idaho Power has accrued a reserve for any loss that is probable and reasonably estimable, including insurance deductibles, and believes this matter will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

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Other Legal Proceedings

IDACORP, Idaho Power and/or IE are parties to legal claims, actions and proceedings in addition to those discussed above. Resolution of any of these matters will take time and the companies cannot predict the outcome of any of these proceedings. The companies believe that their reserves are adequate for these matters and that resolution of these matters, taking into account existing reserves, will not have a material adverse effect on IDACORP’s or Idaho Power’s consolidated financial positions, results of operations or cash flows.

10. BENEFIT PLANS:

Idaho Power has a noncontributory defined benefit pension plan covering most employees. The benefits under the plan are based on years of service and the employee’s final average earnings. In addition, Idaho Power has a nonqualified, deferred compensation plan for certain senior management employees and directors called the Senior Management Security Plan (SMSP). Idaho Power also maintains a defined benefit postretirement plan (consisting of health care and death benefits) that covers all employees who were enrolled in the active group plan at the time of retirement as well as their spouses and qualifying dependents. Idaho Power also has an Employee Savings Plan that complies with Section 401(k) of the Internal Revenue Code and covers substantially all employees. Idaho Power matches specified percentages of employee contributions to the plan.

The following table shows the components of net periodic benefit costs for the pension, SMSP, and Postretirement Benefits Plans for the three months ended March 31 (in thousands of dollars):

							Senior Management				Postretirement
			Pension Plan				Security Plan				Benefits
			2010		2009		2010		2009		2010		2009
Service cost			$	4,559	$	4,205	$	385	$	402	$	340	$	332
Interest cost				7,331		6,947		751		714		898		882
Expected return on plan assets				(6,300)		(6,088)		-		-		(640)		(528)
Amortization of transition obligation				-		-		-		-		510		510
Amortization of prior service cost				163		163		58		58		(134)		(134)
Amortization of net loss				1,925		2,120		233		165		143		190
	Net periodic benefit cost			7,678		7,347		1,427		1,339		1,117		1,252
Costs not recognized due to the
	effects of regulation ⁽¹⁾			(7,427)		(7,347)		-		-		-		-
	Net periodic benefit cost
		recognized for financial
		reporting ⁽²⁾	$	251	$	-	$	1,427	$	1,339	$	1,117	$	1,252

⁽¹⁾ Under IPUC order, income statement recognition of pension costs has been deferred until cash contributions are made and costs are recovered through rates. See Note 3 – “Regulatory Matters”, for information on Idaho Power’s 2010 pension rate filing.
⁽²⁾ Net periodic benefit costs are recognized for the Oregon jurisdiction and non-regulated subsidiaries.

IDACORP and Idaho Power’s minimum required contributions to the pension plan will be approximately $6 million in the third quarter of 2010, and $44 million, $47 million, $39 million, and $40 million in 2011, 2012, 2013, and 2014, respectively. IDACORP and Idaho Power may elect to make contributions earlier than the required dates.

See Note 2 – “Income Taxes” for a summary of the impact of the Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act which were enacted in March 2010.

11. INVESTMENTS IN DEBT AND EQUITY SECURITIES:

Investments in debt and equity securities classified as available-for-sale securities are reported at fair value, using either specific identification or average cost to determine the cost for computing gains or losses. Any unrealized gains or losses on available-for-sale securities are included in other comprehensive income.

Investments classified as held-to-maturity securities are reported at amortized cost. Held-to-maturity securities are investments in debt securities for which the companies have the positive intent and ability to hold the securities until maturity.

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The following table summarizes investments in debt and equity securities as of March 31, 2010 and December 31, 2009 (in thousands of dollars):

March 31, 2010

December 31, 2009

Gross

Unrealized

Fair

Unrealized

Fair

Gain

Loss

Value

Gain

Loss

Value

Available-for-sale

securities (Idaho Power)

3,671

19,047

2,989

18,842

At the end of each reporting period, IDACORP and Idaho Power analyze securities in loss positions to determine whether they have experienced a decline in market value that is considered other-than-temporary. At March 31, 2010 and December 31, 2009, no securities were in an unrealized loss position.

The following table summarizes sales of available-for-sale securities for the three months ended March 31, 2010 and 2009 (in thousands of dollars):

	Three months ended March 31,
	2010		2009

Proceeds from sales	$	-	$	3,817
Gross realized gains from sales		-		12
Gross realized losses from sales		-		5

12. DERIVATIVE FINANCIAL INSTRUMENTS:

Commodity Price Risk

Idaho Power is exposed to certain risks relating to its ongoing business operations. The primary risk managed by using derivative instruments is commodity price risk related to Idaho Power’s ongoing utility operations providing electricity to meet the demand of its retail customers. Physical and financial forward contracts for both electricity and fuel used to produce electricity are entered into to manage the price risk associated with meeting forecasted loads. The objective of Idaho Power’s energy purchase and sale activity is to meet the demand of retail electric customers, maintain appropriate physical reserves to ensure reliability and make economic use of temporary surpluses that may develop.

All derivative instruments are recognized as either assets or liabilities at fair value on the balance sheet. Idaho Power’s physical forward contracts, including green tags, qualify for the normal purchases and normal sales exception to derivative accounting requirements with the exception of forward contracts for the purchase of natural gas for use at Idaho Power’s natural gas generation facilities. Because of Idaho Power’s power cost mechanisms, Idaho Power records the changes in fair value of derivative instruments related to power supply as regulatory assets or liabilities.

Idaho Power had the following derivative commodity forward contracts, entered into for the purpose of economically hedging forecasted purchases and sales, outstanding at March 31, 2010 and 2009:

		March 31,
Commodity	Units	2010	2009
Electricity purchases	MWh	746,650	591,175
Electricity sales	MWh	370,825	272,400
Natural gas purchases	MMBtu	1,898,750	82,500
Diesel purchases	Gallons	645,640	615,423

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The following tables present the fair values of derivatives not designated as hedging instruments recorded in the balance sheet at March 31, 2010 and December 31, 2009 (in thousands of dollars):

March 31, 2010			Asset Derivatives			Liability Derivatives
			Balance Sheet	Fair		Balance Sheet	Fair
Commodity derivatives			Location	Value		Location	Value
Current:
	Financial swaps		Other current assets	$	16	Other current assets	$	10
	Financial swaps		Other current liabilities		2,905	Other current liabilities		5,256
	Forward contracts		Other current liabilities		-	Other current liabilities		381
Long-term:
	Financial swaps		Other assets		245	Other assets		156
	Financial swaps		Other liabilities		-	Other liabilities		2,286
		Total		$	3,166		$	8,089

December 31, 2009			Asset Derivatives			Liability Derivatives
			Balance Sheet	Fair		Balance Sheet	Fair
Commodity derivatives			Location	Value		Location	Value
Current:
	Financial swaps		Other current assets	$	2,931	Other current assets	$	2,087
	Financial swaps		Other current liabilities		9	Other current liabilities		610
	Forward contracts		Other current assets		354	Other current assets		-
Long-term:
	Financial swaps		Other assets		442	Other assets		229
		Total		$	3,736		$	2,926

The following table presents the effect on income of derivatives not designated as hedging instruments for the quarters ended March 31, 2010 and 2009 (in thousands of dollars):

		Location of Gain/(Loss)	Amount of Gain/(Loss)
		Recognized in Income on	Recognized in Income on
Commodity derivatives		Derivative	Derivative⁽¹⁾
Quarter ended March 31, 2010:
	Financial swaps	Off-system sales	$	456
	Financial swaps	Purchased power		(162)
Quarter ended March 31, 2009:
	Financial swaps	Purchased power		(756)
⁽¹⁾Excludes changes in fair value of derivatives, which are recorded on the balance sheet as regulatory assets or regulatory liabilities.

Idaho Power records changes in fair value of its derivative contracts as either regulatory assets or regulatory liabilities. Settlement gains and losses on electricity swap contracts are recorded on the income statement in off-system sales or purchased power depending on the forecasted position being economically hedged by the derivative contract. Settlement gains and losses on both financial and physical contracts for natural gas are reflected in fuel expense. Settlement gains and losses on diesel derivatives were immaterial for the quarter ended March 31, 2010.

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Credit Risk

At March 31, 2010, Idaho Power does not have material credit exposure from financial instruments, including derivatives. Idaho Power monitors credit risk exposure through reviews of counterparty credit quality, corporate-wide counterparty credit exposure, and corporate-wide counterparty concentration levels. Idaho Power manages these risks by establishing appropriate credit and concentration limits on transactions with counterparties and requiring contractual guarantees, cash deposits or letters of credit from counterparties or their affiliates, as deemed necessary. The majority of Idaho Power’s contracts are under the Western Systems Power Pool agreement that provides for adequate assurances if a counterparty has debt that is downgraded to below investment grade by at least one rating agency. Idaho Power also requires North American Energy Standards Board contracts as necessary for physical gas transactions, and International Swaps and Derivatives Association, Inc. contracts as needed for financial transactions.

Credit-Contingent Features

Certain of Idaho Power’s derivative instruments contain provisions that require Idaho Power’s unsecured debt to maintain an investment grade credit rating from each of the major credit rating agencies. If Idaho Power’s unsecured debt were to fall below investment grade, it would be in violation of these provisions, and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions. The aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in a liability position on March 31, 2010, was $8 million. Idaho Power has posted $4 million of collateral related to this amount. If the credit-risk-related contingent features underlying these agreements were triggered on March 31, 2010, Idaho Power could have been required to post $3 million of additional cash collateral to its counterparties.

13. FAIR VALUE MEASUREMENTS:

IDACORP and Idaho Power have categorized their financial instruments, based on the priority of the inputs to the valuation technique, into a three-level fair value hierarchy. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). If the inputs used to measure the financial instruments fall within different levels of the hierarchy, the categorization is based on the lowest level input that is significant to the fair value measurement of the instrument.

Financial assets and liabilities recorded on the condensed consolidated balance sheets are categorized based on the inputs to the valuation techniques as follows:

Level 1: Financial assets and liabilities whose values are based on unadjusted quoted prices for identical assets or liabilities in an active market that IDACORP and Idaho Power has the ability to access.

Level 2: Financial assets and liabilities whose values are based on the following:

a) Quoted prices for similar assets or liabilities in active markets;

b) Quoted prices for identical or similar assets or liabilities in non-active markets;

c) Pricing models whose inputs are observable for substantially the full term of the asset or liability; and

d) Pricing models whose inputs are derived principally from or corroborated by observable market data through correlation or other means for substantially the full term of the asset or liability.

IDACORP and Idaho Power Level 2 inputs are based on quoted market prices adjusted for location using corroborated, observable market data.

Level 3: Financial assets and liabilities whose values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. These inputs reflect management’s own assumptions about the assumptions a market participant would use in pricing the asset or liability.

Idaho Power’s derivatives are contracts entered into as part of its management of loads and resources. Electricity swaps are valued on the Intercontinental Exchange with quoted prices in an active market. Natural gas and diesel derivative valuations are performed using New York Mercantile Exchange (NYMEX) pricing, adjusted for basis location, which are also quoted under NYMEX. Trading securities consists of employee-directed investments held in a Rabbi Trust and are related to an executive deferred compensation plan. Available-for-sale securities are related to the SMSP and are held in a Rabbi Trust and are actively traded money market and equity funds with quoted prices in active markets.

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The following table presents information about IDACORP’s and Idaho Power’s assets and liabilities measured at fair value on a recurring basis as of March 31, 2010, and December 31, 2009 (in thousands of dollars). IDACORP’s and Idaho Power’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy.

		Quoted Prices in		Significant		Significant
		Active Markets		Other		Unobservable
		for Identical		Observable		Inputs
		Assets (Level 1)		Inputs (Level 2)		(Level 3)		Total
March 31, 2010
IDACORP
Assets:
	Derivatives	$	95	$	-	$	-	$	95
	Money market funds		19,126		-		-		19,126
	Trading securities: Equity securities		4,890		-		-		4,890
	Available-for-sale securities: Equity securities		19,047		-		-		19,047
Liabilities:
	Derivatives	$	(2,487)	$	(381)	$	-	$	(2,868)
Idaho Power
Assets:
	Derivatives	$	95	$	-	$	-	$	95
	Money market funds		19,000		-		-		19,000
	Trading securities: Equity securities		4,332		-		-		4,332
	Available-for-sale securities: Equity securities		19,047		-		-		19,047
Liabilities:
	Derivatives	$	(2,487)	$	(381)	$	-	$	(2,868)

December 31, 2009
IDACORP
Assets:
	Derivatives	$	1,056	$	354	$	-	$	1,410
	Money market funds		38,221		-		-		38,221
	Trading securities: Equity securities		6,286		-		-		6,286
	Available-for-sale securities: Equity securities		18,842		-		-		18,842
Liabilities:
	Derivatives	$	(601)	$	-	$	-	$	(601)
Idaho Power
Assets:
	Derivatives	$	1,056	$	354	$	-	$	1,410
	Money market funds		19,364		-		-		19,364
	Trading securities: Equity securities		5,217		-		-		5,217
	Available-for-sale securities: Equity securities		18,842		-		-		18,842
Liabilities:
	Derivatives	$	(601)	$	-	$	-	$	(601)

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The following table presents the carrying value and estimated fair value of financial instruments that are not reported at fair value, using available market information and appropriate valuation methodologies. The use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts. Cash and cash equivalents, deposits, customer and other receivables, notes payable, accounts payable, interest accrued and taxes accrued are reported at their carrying value as these are a reasonable estimate of their fair value. The estimated fair values for notes receivable and long-term debt are based upon quoted market prices of the same or similar issues or discounted cash flow analyses as appropriate.

		March 31, 2010				December 31, 2009
		Carrying		Estimated		Carrying		Estimated
		Amount		Fair Value		Amount		Fair Value
		(thousands of dollars)
IDACORP
Assets:
	Notes receivable	$	2,946	$	2,946	$	2,946	$	2,946
Liabilities:
	Long-term debt		1,425,186		1,412,045		1,422,130		1,406,815
IDAHO POWER
Liabilities:
	Long-term debt	$	1,412,790	$	1,399,807	$	1,413,854	$	1,398,681

14. SEGMENT INFORMATION:

IDACORP’s only reportable segment is utility operations. The utility operations segment’s primary source of revenue is the regulated operations of Idaho Power. Idaho Power’s regulated operations include the generation, transmission, distribution, purchase and sale of electricity. This segment also includes income from IERCo, a wholly-owned subsidiary of Idaho Power that is also subject to regulation and is a one-third owner of BCC, an unconsolidated joint venture.

IDACORP’s other operating segments are below the quantitative thresholds for reportable segments and are included in the “All Other” category. This category is comprised of IFS’s investments in affordable housing developments and historic rehabilitation projects, Ida-West’s joint venture investments in small hydroelectric generation projects, the remaining activities of energy marketer IE, which wound down its operations in 2003, and IDACORP’s holding company expenses.

The following table summarizes the segment information for IDACORP’s utility operations and the total of all other segments, and reconciles this information to total enterprise amounts (in thousands of dollars):

		Utility		All				Consolidated
		Operations		Other		Eliminations		Total

Three months ended March 31, 2010:
	Revenues	$	252,460	$	503	$	-	$	252,963
	Income (loss) attributable to IDACORP, Inc.		18,221		(2,158)		-		16,063

Total assets at March 31, 2010		$	4,078,494	$	166,653	$	(22,715)	$	4,222,432

Three months ended March 31, 2009:
	Revenues	$	228,029	$	545	$	-	$	228,574
	Income (loss) attributable to IDACORP, Inc.		19,284		(400)		-		18,884

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have reviewed the accompanying condensed consolidated balance sheet of IDACORP, Inc. and subsidiaries (the “Company”) as of March 31, 2010, and the related condensed consolidated statements of income, comprehensive income, equity, and cash flows for the three-month periods ended March 31, 2010 and 2009. These interim financial statements are the responsibility of the Company’s management.

We conducted our reviews in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our reviews, we are not aware of any material modifications that should be made to such condensed consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of IDACORP, Inc. and subsidiaries as of December 31, 2009, and the related consolidated statements of income, comprehensive income, equity, and cash flows for the year then ended (not presented herein); and in our report dated February 23, 2010, we expressed an unqualified opinion on those consolidated financial statements, which included an explanatory paragraph related to the adoption of accounting guidance for noncontrolling interests in consolidated financial statements and guidance for accounting for uncertainty in income taxes. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2009 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

/s/DELOITTE & TOUCHE LLP

Boise, Idaho
May 6, 2010

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of Idaho Power Company
Boise, Idaho

We have reviewed the accompanying condensed consolidated balance sheet and statement of capitalization of Idaho Power Company and subsidiary (the “Company”) as of March 31, 2010, and the related condensed consolidated statements of income, comprehensive income, and cash flows for the three-month periods ended March 31, 2010 and 2009. These interim financial statements are the responsibility of the Company’s management.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet and statement of capitalization of Idaho Power Company and subsidiary as of December 31, 2009, and the related consolidated statements of income, comprehensive income, retained earnings, and cash flows for the year then ended (not presented herein); and in our report dated February 23, 2010, we expressed an unqualified opinion on those consolidated financial statements, which included an explanatory paragraph related to the adoption of guidance for accounting for uncertainty in income taxes. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet and statement of capitalization as of December 31, 2009 is fairly stated, in all material respects, in relation to the consolidated balance sheet and statement of capitalization from which it has been derived.

/s/DELOITTE & TOUCHE LLP

Boise, Idaho
May 6, 2010

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

(Tabular dollar amounts, other than earnings per share, and megawatt-hours (MWh), are in thousands unless otherwise indicated)

INTRODUCTION

In Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A), the general financial condition and results of operations for IDACORP, Inc. and its subsidiaries (collectively, IDACORP) and Idaho Power Company and its subsidiary (collectively, Idaho Power) are discussed.

Idaho Power is an electric utility with a service territory covering approximately 24,000 square miles in southern Idaho and eastern Oregon. Idaho Power is regulated by the FERC and the state regulatory commissions of Idaho and Oregon. Idaho Power is the parent of Idaho Energy Resources Co., (IERCo) a joint venturer in Bridger Coal Company (BCC), which supplies coal to the Jim Bridger generating plant owned in part by Idaho Power.

IDACORP’s other subsidiaries include 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 (PURPA); and IDACORP Energy (IE), a marketer of energy commodities, which wound down operations in 2003.

While reading the MD&A, please refer to the accompanying condensed consolidated financial statements of IDACORP and Idaho Power. This discussion updates the MD&A included in the Annual Report on Form 10-K for the year ended December 31, 2009, and should be read in conjunction with the discussions in that report.

FORWARD-LOOKING INFORMATION

In addition to the historical information contained in this report, this report includes forward-looking statements. In connection with the safe harbor provisions of the Private Securities Litigation Reform Act of 1995, IDACORP and Idaho Power are hereby filing cautionary statements identifying important factors that could cause actual results to differ materially from those projected in forward-looking statements, made by or on behalf of IDACORP or Idaho Power in this Quarterly Report on Form 10-Q, in presentations, in response to questions or otherwise. Any statements that express, or involve discussions as to expectations, beliefs, plans, objectives, assumptions or future events or performance, often, but not always, through the use of words or phrases such as “anticipates,” “believes,” “estimates,” “expects,” “intends,” “plans,” “predicts,” “projects,” “may result,” “may continue” or similar expressions, are not statements of historical facts and may be forward-looking. Forward-looking statements involve estimates, assumptions and uncertainties and are qualified in their entirety by reference to, and are accompanied by, the following important factors, which are difficult to predict, contain uncertainties, are beyond IDACORP’s or Idaho Power’s control and may cause actual results to differ materially from those contained in forward-looking statements:

• 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;

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• 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, and endangered species laws, regulations and policies and the adoption of laws and regulations addressing greenhouse gas emissions, global 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 electrical transmission capacity and the availability of water, natural gas, coal, diesel and their associated delivery infrastructures;

• Changes in operating expenses and capital expenditures, including costs and availability of materials, fuel and commodities;

• Blackouts or other disruptions of Idaho Power’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, or New York Stock Exchange, requirements, or new interpretation or application of existing requirements.

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.

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EXECUTIVE OVERVIEW

First Quarter 2010 Financial Results

A summary of net income attributable to IDACORP, Inc. and earnings per diluted share for the three months ended March 31, 2010 and 2009 is as follows:

	Three months ended
	March 31,
	2010		2009
Net income attributable to IDACORP, Inc.	$	16,063	$	18,884
Average outstanding shares – diluted (000s)		47,885		46,876
Earnings per diluted share	$	0.34	$	0.40

The following table presents a reconciliation of net income attributable to IDACORP, Inc. for the three months ended March 31, 2009 to March 31, 2010 (items are in millions and are before tax unless otherwise noted):



Net income attributable to IDACORP, Inc. for the three months ended March 31, 2009				$	18.9
Change in Idaho Power net income before taxes:
	Rate and other regulatory changes, including PCA and FCA mechanisms	$	8.9
	Reduced sales volumes		(6.7)
	Payroll related increases		(1.8)
	Increase in depreciation expense related to advanced metering		(2.6)
	Decrease in life insurance gains		(3.3)
	Decrease in earnings at Bridger Coal Company		(3.0)
	Other		(0.1)
Accumulated deferred investment tax credit (ADITC) amortization			4.5
Decrease in income tax expense, net of ADITC			3.0
Total decrease in Idaho Power net income					(1.1)
Other net decreases, net of tax					(1.7)

Net income attributable to IDACORP, Inc. for the three months ended March 31, 2010				$	16.1

Idaho Power’s operating income decreased $1.3 million compared to the first quarter of 2009. The combination of reduced sales volumes and increased operating expenses more than offset the benefits of rate increases implemented during the year. Sales volumes were down five percent due to mild weather, which reduces electricity needs for heating, economic factors, and energy conservation. Economic conditions in Idaho Power’s service area remained weak during the first quarter of 2010, and Idaho Power attributes a portion of reduced sales volumes to these current weak economic conditions. Volume decreases are partially offset by the fixed cost adjustment (FCA) mechanism and lower power supply costs. Operating expenses increased due to increased wages and benefits and increased depreciation expense. While converting to Advanced Metering Infrastructure (AMI), Idaho Power has accelerated depreciation expense for non-AMI meters and is collecting an offsetting amount in revenues.

In accordance with a provision in its 2009 settlement agreement with the IPUC, Idaho Power recorded an amortization of $4.5 million of ADITC in the first quarter of 2010. The agreement allows an additional annual maximum amortization up to $25 million of ADITC in either 2010 or 2011 if Idaho Power’s actual rate of return on year-end equity in its Idaho jurisdiction is below 9.5 percent. The total additional ADITC amortization for both 2010 and 2011 cannot exceed $45 million.

Several other items negatively impacted earnings compared to the first quarter of 2009. Life insurance gains decreased $3.3 million as gains that were recorded in 2009 did not occur in 2010. Also, earnings from BCC decreased $3.0 million due to higher operational costs. Earnings from BCC are expected to approximate 2009 levels by year end.

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Earnings at IDACORP’s non-regulated subsidiaries and the holding company declined $1.7 million for the period due to the effects of intra-period tax allocations. IDACORP estimates its consolidated group annual effective income tax rate at the holding company in accordance with interim reporting requirements. The estimated annual rate was used in determining income tax expense for the quarter and resulted in an intra-period allocation of expense.

Regulatory Matters

Idaho Power has a number of pending or recently completed regulatory filings, including the following:

Idaho 2009 Settlement Agreement: In January 2010, the Idaho Public Utilities Commission (IPUC) approved a settlement agreement among Idaho Power, several of Idaho Power’s customers, the IPUC Staff and others with respect to rates for 2009 through 2011. The agreement contains four important elements: (1) a general rate freeze until January 1, 2012, with some exceptions; (2) a specified distribution of the expected 2010 power cost adjustment (PCA) decrease to directly reduce customer rates, providing some general rate relief to Idaho Power and resetting base level power supply costs for the PCA going forward; (3) use of investment tax credits to get to a 9.5 percent return on equity in the Idaho jurisdiction; and (4) an equal sharing of any Idaho earnings exceeding the authorized return on equity of 10.5 percent.

Idaho 2010 PCA Filing: On April 15, 2010, Idaho Power made its annual PCA filing with the IPUC, requesting approval of its 2010 PCA and an increase in base rates pursuant to the terms of the settlement agreement described above. As filed, these two rate adjustments would be a $146.7 million 2010 PCA reduction and an $88.7 million increase to base rates, both to become effective June 1, 2010. The base rate increase includes a $63.7 million increase in Idaho Power’s annual base net power supply costs, and a $25 million general increase in Idaho Power’s annual base rates. An open issue relates to Idaho Power’s proposed increase of $25 million in coal supply costs for the Jim Bridger plant. The $63.7 million amount is a maximum increase to annual base net power supply costs; the final amount will be determined in the context of the 2010 PCA case.

Other Idaho 2010 Filings: In March 2010, Idaho Power made the following rate filings with the IPUC, each with a requested effective date of June 1, 2010:

• Fixed Cost Adjustment: Idaho Power’s 2010 FCA filing for 2009 proposes to collect $6.3 million for one year, a $3.6 million annual increase over current rates.

• Pension: Idaho Power filed a request to recover $5.4 million of pension contributions that it expects to make in 2010. In accordance with IPUC orders, Idaho Power currently defers its Idaho-jurisdiction pension expense for recovery when cash contributions are made by the company.

• Advanced Metering Infrastructure: Idaho Power filed for a $2.4 million annual increase in base rates to recover additional capital expenditures related to AMI.

Oregon 2009 General Rate Case: On February 24, 2010, the Oregon Public Utility Commission (OPUC) approved a $5 million, or 15.4 percent, increase in base rates. The new rates were effective March 1, 2010 and are based on a return on equity of 10.175 percent and an overall rate of return of 8.061 percent. This increase results from a joint stipulation filed by Idaho Power that settled the revenue requirement issues surrounding the general rate case filed on July 31, 2009.

Oregon Power Cost Recovery Mechanisms: On March 23, 2010, Idaho Power filed its March forecast for the 2010 annual power cost update (APCU) rate adjustment with the OPUC. A stipulation combining the March forecast and October update filed in 2009 was filed with the OPUC on April 15, 2010. Approval of the stipulation would result in a $5.5 million annual increase in Oregon rates, effective June 1, 2010. The target date for an OPUC order is May 28, 2010.

For a more complete discussion of regulatory proceedings, refer to Note 3 to the condensed consolidated financial statements included in this report and “Regulatory Matters” below.

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Liquidity

IDACORP and Idaho Power expect to continue financing capital requirements with a combination of internally generated funds and externally financed capital. On April 19, 2010, Idaho Power received approval from the IPUC for the issuance of up to $500 million of additional first mortgage bonds or unsecured debt securities. Idaho Power would issue the securities pursuant to a shelf registration statement to be filed with the Securities and Exchange Commission (SEC).
Capital Requirements: Idaho Power has several major projects in development. The most significant projects are summarized here and are discussed further in “LIQUIDITY AND CAPITAL RESOURCES – Capital Requirements.”

• Langley Gulch Power Plant: Langley Gulch will be a natural gas-fired combined cycle combustion turbine (CCCT) generating plant with a summer nameplate capacity of approximately 300 megawatts (MWs) and a winter capacity of approximately 330 MWs. The plant will be constructed near New Plymouth, Idaho commencing in summer 2010, and is contracted to achieve commercial operation by November 1, 2012. Incentives are anticipated to advance the commercial operation date to July 1, 2012. The total cost estimate for the project including allowance for funds used during construction (AFUDC) is $427 million, $77 million of which Idaho Power has incurred through March 31, 2010. Idaho Power received ratemaking assurances for $397 million from the IPUC for this project, and will request that the IPUC include the full cost of construction in Idaho Power’s rate base after the facility is placed in operation.

• Transmission Projects: Idaho Power and PacifiCorp are jointly exploring the Boardman-Hemingway Line, a proposed 500-kiloVolt (kV) line between a substation near Boardman, Oregon and the Hemingway substation. Idaho Power estimates total construction costs of $600 million and expects its share of the project to be between 30 and 50 percent. Idaho Power estimates the project will be completed in 2015, subject to siting, permitting and regulatory approvals. Idaho Power and PacifiCorp are jointly exploring Gateway West, a project to build transmission lines between Windstar, a substation located near Douglas, Wyoming, and the Hemingway substation. The current estimated cost for Idaho Power’s share of the project is between $300 million and $500 million. Initial phases of the project could be completed by 2014. Idaho Power’s share may change and the timing of the projects segments may be deferred and constructed as demand requires.

• Transmission Equipment Purchase and Sale and Joint Ownership and Operating Agreements: On April 30, 2010, Idaho Power entered into a Joint Purchase and Sale Agreement with PacifiCorp, pursuant to which (1) Idaho Power agreed to sell to PacifiCorp an ownership interest in certain transmission-related and interconnection equipment and easement rights located at Idaho Power’s Hemingway substation; and (2) PacifiCorp agreed to sell to Idaho Power an ownership interest in certain transmission-related and interconnection equipment and easement rights located at PacifiCorp’s Populus substation. The Purchase and Sale Agreement provides that Idaho Power and PacifiCorp will initially be the 41 percent and 59 percent owner of the 500-kV portion of the transmission facilities at the Hemingway substation, respectively, and Idaho Power and PacifiCorp will initially be the 20.8 percent owner and 79.2 percent owner of the 345-kV portion of the transmission facilities at the Populus substation, respectively. On May 3, 2010, Idaho Power and PacifiCorp also entered into two Joint Ownership and Operating Agreements for the Hemingway and Populus substations, which set forth terms pertaining to the construction, joint ownership, and operation of transmission and interconnection facilities at the Hemingway and Populus substations.

Other Issues

Water Management Issues: Power generation at the Idaho Power hydroelectric power plants on the Snake River depends on the state water rights held by Idaho Power and the long-term sustainability of the Snake River, tributary spring flows and the Eastern Snake Plain Aquifer (ESPA). Idaho Power continues to participate in water management issues in Idaho that may affect those water rights and resources. For a further discussion of water management issues see “RESULTS OF OPERATIONS – Utility Operations” and “LEGAL MATTERS – Snake River Basin Water Rights.”

Environmental Matters: Long-term climate change could significantly affect Idaho Power’s business, and climate change regulations are expected to have major implications for Idaho Power and the energy industry. Idaho Power has established guidelines with goals to reduce the carbon dioxide (CO₂) emission intensity of its utility operations, intended to further prepare Idaho Power for potential legislative and/or regulatory restrictions on greenhouse gas (GHG) emissions while minimizing the costs of complying with such restrictions on Idaho Power’s customers. Idaho Power’s thermal facilities are subject to federal and/or state-promulgated (1) ambient air quality standards, including those for ozone and fine particulate matter, (2) laws and regulations limiting mercury emissions, (3) regional haze – best available retrofit technology requirements, and (4) new source review and performance standards. Idaho Power’s environmental compliance costs will continue to be significant for the foreseeable future, particularly in light of possible additional regulation at the federal and state levels. These issues are discussed in more detail in “ENVIRONMENTAL ISSUES” below.

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Boardman Coal Plant: On April 2, 2010, Portland General Electric (PGE) submitted a petition asking the Oregon Environmental Quality Commission for rule revisions to allow the utility to meet new environmental standards by closing the Boardman power plant in 2020. Included in the petition is a plan to install new controls and make operational changes during the remaining years the plant is in service. Idaho Power is a ten percent owner of the plant, representing 64 MW of nameplate capacity. Idaho Power is evaluating the proposal and discussing with PGE the advisability of closing the Boardman plant in 2020. At March 31, 2010, Idaho Power’s net book value in the Boardman plant was approximately $20 million with annual depreciation of approximately $1.2 million.

American Recovery and Reinvestment Act of 2009 (ARRA): Under the ARRA, Idaho Power was awarded a grant of $47 million from the Department of Energy (DOE). This grant will match a $47 million investment by Idaho Power in Smart Grid AMI technology as well as other incremental projects. The contract was signed with the DOE on April 2, 2010. Billings on this reimbursement contract will begin in May 2010 and occur monthly thereafter over the estimated three year term of the contract.

Health Care Acts: The Patient Protection and Affordable Care Act and the related Health Care and Education Reconciliation Act were enacted in March 2010. The enactment of the legislation required Idaho Power to record a $0.9 million adjustment to deferred income tax expense in the first quarter of 2010. The companies are continuing to evaluate the acts to determine other possible future impacts on its costs. For a more complete discussion of the legislation, refer to Note 2 to the condensed consolidated financial statements included in this report.

Key Operating and Financial Metrics

	2010 Estimates
	Current	Previous
Idaho Power Operation & Maintenance Expense (millions)	No change	$295-$305
Idaho Power Capital Expenditures (millions)	No change	$355-$365
Idaho Power Hydroelectric Generation (million MWh)⁽¹⁾	No change	6.5-8.5
Non-regulated subsidiary earnings and holding company expenses (millions)⁽²⁾	No change	$0-$3.0

⁽¹⁾The range for capital expenditures includes amounts for the Langley Gulch power plant, the Hemingway-Bowmont transmission line, the Hemingway substation and expenditures for the siting and permitting of major transmission expansions for the Boardman to Hemingway and Gateway West transmission projects.
⁽²⁾For the first quarter of 2010, non-regulated earnings and holding company expenses resulted in a net loss of $2.2 million, primarily due to the impact of intra-period tax allocation at the holding company. It is expected that combined earnings and holding company expenses will be in the range of breakeven to a positive $3.0 million by year end.

In a change from past practice, IDACORP and Idaho Power are not providing estimates of their respective effective income tax rates for 2010. These rates will be affected to the extent Idaho Power uses additional ADITC pursuant to the Idaho settlement agreement and/or changes its tax accounting method for repair-related expenditures, both of which are discussed later in the MD&A. IDACORP and Idaho Power are also withdrawing the estimates of their respective effective income tax rates for 2010 that were provided previously.

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RESULTS OF OPERATIONS

This section of the MD&A takes a closer look at the significant factors that affected IDACORP’s and Idaho Power’s earnings during the three months ended March 31, 2010. In this analysis, the results for 2010 are compared to the same period in 2009.

The following table presents net income (losses) for IDACORP and its subsidiaries for the three months ended March 31, 2010 and 2009:

		Three months ended
		March 31,
		2010		2009
Idaho Power – Utility operations		$	18,221	$	19,284
IDACORP Financial Services			(39)		141
Ida-West Energy			177		188
IDACORP Energy			197		(19)
Holding company			(2,493)		(710)
	Net income attributable to IDACORP, Inc.	$	16,063	$	18,884
Average common shares outstanding (diluted, in 000s)			47,885		46,876
Earnings per diluted share		$	0.34	$	0.40

Utility Operations

The table below presents Idaho Power’s energy sales and supply (in MWhs) for the three months ended March 31, 2010 and 2009:

		2010	2009
General business sales		3,109	3,279
Off-system sales		766	577
	Total energy sales	3,875	3,856
Hydroelectric generation		1,902	1,586
Coal generation		1,874	1,958
Natural gas and other generation		2	8
	Total system generation	3,778	3,552
Purchased power		395	661
Line losses		(298)	(357)
	Total energy supply	3,875	3,856

Because of its reliance on hydroelectric generation, Idaho Power’s generation operations can be significantly affected by water conditions. The availability of hydroelectric power depends on the amount of snow pack in the mountains upstream of Idaho Power’s hydroelectric facilities, reservoir storage, springtime snow pack run-off, river base flows, spring flows, rainfall, amount and timing of water leases, and other weather and stream flow management considerations. During low water years, when stream flows into Idaho Power’s hydroelectric projects are reduced and reservoir storage is low, Idaho Power’s hydroelectric generation is generally reduced. This results in less generation from Idaho Power’s resource portfolio available for off-system sales and, generally, an increased use of purchased power to meet load requirements. Both of these situations – a reduction in off-system sales and an increased use of more expensive purchased power – result in increased power supply costs. While the cost of purchased power is typically higher than the cost of hydroelectric generation, the incremental cost is included in the PCA mechanism where Idaho Power recovers 95 percent of such costs through rates.

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For the three months ended March 31, 2010, hydroelectric generation comprised 50 percent of Idaho Power’s total system generation and 49 percent of its total energy supply. For the three months ended March 31, 2010, Idaho Power hydroelectric generation increased 20 percent over the same period last year due to higher carryover reservoir storage in the Snake River Basin and associated flood control releases through the winter 2010. Based on Idaho Power’s current measurements of snowpack, which is significantly below average, reservoir levels, current and forecasted stream flow, and other conditions relevant to its estimate of hydroelectric generation capacity, Idaho Power expects to generate between 6.5 and 8.5 million MWh from its hydroelectric facilities in 2010, compared to 8.1 million MWh in 2009. Idaho Power’s modeled median annual hydroelectric generation is 8.6 million MWh, based on hydrologic conditions for the period 1928 through 2009 and adjusted to reflect the current level of water resource development.

Idaho Power’s system is dual peaking, with the larger peak demand occurring in the summer. The highest summer peak demand of 3,214 MW was set on June 30, 2008, and the highest winter peak demand of 2,527 MW was set on December 10, 2009. During these and other similar heavy load periods Idaho Power’s system is fully committed to serve loads and meet required operating reserves.

General business revenue: The following tables present Idaho Power’s general business revenues, MWh sales, number of customers and Boise, Idaho weather conditions for the three months ended March 31, 2010 and 2009:

			Three months ended
			March 31,
			2010		2009
Revenue
	Residential		$	111,595	$	106,447
	Commercial			57,931		51,542
	Industrial			36,118		31,044
	Irrigation			676		571
	Deferred revenue related to Hells
		Canyon relicensing AFUDC		(2,575)		(1,677)
		Total	$	203,745	$	187,927
MWh
	Residential			1,399		1,534
	Commercial			931		957
	Industrial			771		781
	Irrigation			8		7
		Total		3,109		3,279
Customers (average)
	Residential			406,748		404,408
	Commercial			64,275		64,080
	Industrial			128		124
	Irrigation			18,601		18,533
		Total		489,752		487,145
Customers (period end)
	Residential			406,771		404,384
	Commercial			64,262		64,016
	Industrial			128		123
	Irrigation			18,561		18,548
		Total		489,722		487,071
Heating degree-days⁽¹⁾				2,156		2,532
Precipitation (inches)⁽²⁾				3.93		2.33
⁽¹⁾Heating and cooling degree-days are common measures used in the utility industry to analyze the demand for electricity. They indicate when a customer would likely use electricity for heating and air conditioning. A degree-day measures how much the average of the daily high and low temperature varies from 65 degrees. Each degree of temperature above 65 degrees is counted as one cooling degree-day, and each degree of temperature below 65 degrees is counted as one heating degree-day. There were no cooling degree days during the period. Normal heating degree-days for the period are 2,574 degree days.
⁽²⁾Normal precipitation for the period is 3.94 inches.

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As part of its February 1, 2009, general rate case order, the IPUC allowed Idaho Power to recover AFUDC for the Hells Canyon Complex relicensing asset even though the relicensing process is not yet complete and the relicensing asset has not been placed in service. Idaho Power expects to collect approximately $10.6 million annually, but will defer revenue recognition of the amounts collected until the license is issued and the asset is placed in service. This deferral offset revenues by approximately $2.6 million for the first quarter of 2010.

General business revenue increased $16 million for the first quarter of 2010 as compared to the same period in 2009. This increase is primarily attributable to the effects of rate changes and was partially offset by a decrease in customer usage:

• Rates: Rate changes positively impacted general business revenue by $27 million for the quarter compared to the first quarter of 2009. This reflects PCA rate increases of $18 million and increases of $9 million in retail base rates. The following table presents significant rate increases that affected the period:

				Annualized $
	Effective	Percentage		impact
Description	Date	Rate Increase		(millions)
2008 Idaho general rate case	2/01/2009	3.1%	$	21
2008 Idaho general rate case	3/19/2009	0.9%		6
2009 Idaho PCA	6/01/2009	10.2%		84
Idaho AMI	6/01/2009	1.8%		11

• Customers: An increase in customer count in Idaho Power’s service territory increased general business revenue $1 million for the quarter.

• Usage: Lower usage decreased general business revenue $12 million for the quarter due to mild temperatures, energy conservation and a continued weak economy. Economic conditions in Idaho Power’s service area remained weak during the first quarter of 2010, including a continued high unemployment rate in the area. Continued weak economic conditions or further economic deterioration in Idaho Power’s service area may reduce the amount of energy that Idaho Power’s customers consume, reduce the number of new customers moving into Idaho Power’s service area, or result in a loss of customers, and may result in an increase in late payments and uncollectible accounts. For the first quarter of 2010, Idaho Power’s customer base remained relatively flat, and total sales by MWh declined by 170 MWh, or 5.5 percent, relative to the same period in 2009. Idaho Power believes the decline in total sales by MWh is due in part to the continued weakness of the economy in its service area. A slow economic recovery could result in continued low demand.

Off-system sales: Off-system sales consist primarily of long-term sales contracts and opportunity sales of surplus system energy. The following table presents Idaho Power’s off-system sales for the three months ended March 31, 2010 and 2009:

	Three months ended
	March 31,
	2010		2009
Revenue	$	34,406	$	28,530
MWh sold		766		577
Revenue per MWh	$	44.92	$	49.45

Off-system sales revenue increased $6 million or 21 percent, for the first quarter of 2010 compared to the first quarter of 2009 due to lower system load and more favorable generating conditions, which increased the amount of electricity Idaho Power had available for sale.

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Other revenues: The table below presents the components of other revenues for the three months ended March 31, 2010 and 2009:

		Three months ended
		March 31,
		2010		2009
Transmission services and property rental		$	9,275	$	7,515
Energy efficiency			5,034		4,057
	Total	$	14,309	$	11,572

The increase in transmission services and property rental reflects new rates implemented in October 2009.

Energy efficiency activities are funded through a rider mechanism on customer bills. Energy efficiency program expenditures are reported as an operating expense with an equal amount of revenues recorded in other revenues, resulting in no net impact on earnings. The cumulative variance between expenditures and amounts collected through the rider is recorded as a regulatory asset or liability pending future collection from or obligation to customers. A liability balance indicates that Idaho Power has collected more than it has spent and an asset balance indicates that Idaho Power has spent more than it has collected. For the first quarter of 2010, Idaho Power has increased its energy efficiency program expenses and matching revenues $1 million, and on March 31, 2010, Idaho Power’s rider balance was a regulatory asset of $7 million.

Purchased power: The following table presents Idaho Power’s purchased power expenses and volumes for the three months ended March 31, 2010 and 2009:

	Three months ended
	March 31,
	2010		2009
Purchased power expense	$	21,174	$	33,701
MWh purchased		395		661
Cost per MWh purchased	$	53.61	$	50.98

Purchased power expense decreased $13 million, or 38 percent, due to lower system loads and more favorable hydroelectric generating conditions during the first quarter of 2010 compared to the same period in 2009.

Fuel expense: The following table presents Idaho Power’s fuel expenses and generation at its thermal generating plants for the three months ended March 31, 2010 and 2009:

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			Three months ended
			March 31,
			2010		2009
Expense
	Coal		$	36,065	$	37,795
	Natural gas and other			1,122		1,338
		Total fuel expense	$	37,187	$	39,133
MWh generated
	Coal			1,874		1,958
	Natural gas and other			2		8
		Total MWh generated		1,876		1,966
Cost per MWh
	Coal		$	19.24	$	19.30
	Natural gas and other			561.00		167.25
	Weighted average, all sources			19.82		19.90

Fuel expense decreased $2 million, or six percent, for the quarter. The Valmy plant had lower production, and thus lower demand for fuel, due to a planned major maintenance outage that began in March. The cost per MWh for natural gas and other is significantly higher than the same period last year due to fixed costs that occur regardless of plant usage and lower generation from natural gas in the first quarter of 2010.

PCA: PCA expense represents the effects of the Idaho and Oregon power supply cost adjustment mechanisms. The following table presents the components of the PCA for the three months ended March 31, 2010 and 2009:

		Three months ended
		March 31,
		2010		2009
Idaho power supply cost accrued (deferred)		$	19,839	$	(10,407)
Oregon power supply cost accrued			44		-
Amortization of prior year authorized balances			28,441		26,266
	Total power cost adjustment	$	48,324	$	15,859

In the first quarter of 2010, power supply costs were below the amounts estimated in the annual PCA forecast, resulting in a charge to expense (accrual). In the first quarter of 2009, power supply costs were above the PCA forecast, resulting in a credit to expense (deferral). In addition, amortization of previously deferred power supply costs increased to match increased revenues.

Other operations and maintenance expenses: Other operations and maintenance expense increased $3 million for the quarter, primarily due to an increase in labor-related expenses.

Income Taxes

The estimated annual effective tax rate is applied to year-to-date pre-tax income to achieve income tax expense (or benefit) for the interim period consistent with the annual estimate. In subsequent interim periods, income tax expense (or benefit) is computed as the difference between the year-to-date amount reported for the previous interim period and the current period’s year-to-date amount.

An analysis of income tax expense for the three months ending March 31, 2010 and 2009 is as follows:

		IDACORP				Idaho Power
		2010		2009		2010		2009
Income tax provision		$	4,914	$	6,796	$	5,915	$	9,773
ADITC amortization			(4,512)		-		(4,512)		-
Medicare Part D subsidy			903		-		903		-
	Income tax expense	$	1,305	$	6,796	$	2,306	$	9,773

Effective tax rate			7.5%		26.5%		11.2%		33.6%

The decrease in the 2010 estimated annual effective tax rates from 2009 is primarily due to lower pre-tax earnings at IDACORP and Idaho Power and Idaho Power’s additional amortization of ADITC, partially offset by a charge related to the federal health care legislation enacted in the first quarter of 2010. Regulatory flow-through tax adjustments at Idaho Power and tax credits at IFS were comparable quarter-over-quarter. For further information regarding ADITC amortization, see “Idaho Settlement Agreement” in Note 3 to the condensed consolidated financial statements.

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The Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act were enacted in March 2010. One provision of this legislation eliminates the deductibility of employer health care costs for retiree prescription drug expenses that are covered by federal subsidy payments equivalent to Medicare Part D. While this provision is not effective until 2013, relevant income tax accounting guidance requires recognition of the future effects of new law in the period of enactment. Accordingly, Idaho Power reduced its deferred tax asset related to future deductible retiree prescription drug expenses, incurring a charge of $0.9 million for the three months ended March 31, 2010. See Note 2 to the condensed consolidated financial statements for further discussion on impacts of the enactment of this legislation.

Idaho Power is currently evaluating a tax accounting method change that would allow a current income tax deduction for repair-related expenditures on its utility assets that are currently capitalized for book and tax purposes. The deduction would be computed for tax years 1999 and forward. Idaho Power has the ability to apply for this method change following automatic consent procedures and could make such application with the filing of IDACORP’s 2009 consolidated federal income tax return in September 2010. Idaho Power’s prescribed regulatory accounting treatment requires immediate income recognition for temporary tax differences of this type. A regulatory asset is established to reflect Idaho Power’s ability to recover increased income tax expense when such temporary differences reverse. Adoption of this method may reduce Idaho Power’s need to amortize additional ADITC in 2010, possibly resulting in reversal of credits recognized in previous quarters.

Status of Audit Proceedings: In May 2009, IDACORP formally entered the Internal Revenue Service (IRS) Compliance Assurance Process (CAP) program for its 2009 tax year. The CAP program provides for IRS examination throughout the year. The 2009 examination is expected to be completed in 2010. In January 2010, IDACORP was accepted into CAP for its 2010 tax year. IDACORP and Idaho Power are unable to predict the outcome of these examinations.

Specifically within the 2009 CAP examination, the IRS began its audit of Idaho Power’s current method of uniform capitalization. In September 2009, the IRS issued Industry Director Directive #5 (IDD), which discusses the IRS’s compliance priorities and audit techniques related to the allocation of mixed service costs in the uniform capitalization methods of electric utilities. The IRS and Idaho Power are jointly working through the impact the IDD guidance has on Idaho Power’s uniform capitalization method. Idaho Power expects that the examination will be completed during 2010. Resolution of this matter would result in a decrease to Idaho Power’s unrecognized tax benefits for its 2009 uniform capitalization deduction by $1.1 million, may reduce Idaho Power’s need to amortize additional ADITC in 2010, and is not expected to have a material adverse effect on Idaho Power’s financial position, results of operations or cash flows.

LIQUIDITY AND CAPITAL RESOURCES:

Operating Cash Flows

IDACORP’s and Idaho Power’s operating cash inflows for the three months ended March 31, 2010, were $100 million and $101 million, respectively. These amounts were increases of $56 million and $46 million, respectively, compared to the three months ended March 31, 2009. The following are significant items that affected operating cash flows in the first quarter of 2010:

• An increase of $32 million from reductions in the PCA and the Oregon power cost adjustment mechanism (PCAM) regulatory assets, as Idaho Power deferred $30 million less of excess net power supply costs and collected an additional $2 million of previously deferred costs as compared with the first quarter of 2009.

• An increase of $13 million and $11 million at IDACORP and Idaho Power, respectively, from the collection of a higher 2009 year end accounts receivable balance, primarily as a result of colder temperatures increasing sales in December 2009 as compared with the prior year.

• An increase of $13 million related to accounts payable primarily due to a $15 million decrease during the first quarter of 2009 in accounts payable for purchased power as a result of 2008 purchases.

• An increase due to a refund in the first quarter of 2009 of $13 million made to Idaho Power’s transmission customers upon a final order from the FERC on Idaho Power’s Open Access Transmission Tariff.

• A partially offsetting decrease in cash flows from income tax refunds, which decreased by $12 million and $22 million at IDACORP and Idaho Power, respectively, due to the settlement in the first quarter of 2009 of the 2005 IRS examination.

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IDACORP’s operating cash flows are driven principally by Idaho Power. General business revenues and the costs to supply power to general business customers have the greatest impact on Idaho Power’s operating cash flows, and are subject to risks and uncertainties relating to weather and water conditions, fuel costs and purchased power prices, and Idaho Power’s ability to obtain rate relief to cover its operating costs and provide a return on investment.

Investing Cash Flows

IDACORP’s and Idaho Power’s investing cash outflows were $71 million and $69 million, respectively, for the three months ended March 31, 2010. These amounts were an increase in outflows of $30 million and $20 million, respectively, compared to the three months ended March 31, 2009. Investing cash outflows for 2010 were primarily for construction of utility infrastructure needed to address Idaho Power’s customer growth, peak demand growth and aging plant and equipment.

Financing Cash Flows

IDACORP’s and Idaho Power’s financing cash outflows for the three months ended March 31, 2010, were $41 million and $16 million, respectively. These amounts were an increase in outflows of $118 million and $89 million, respectively, compared to the three months ended March 31, 2009. The financing cash outflows for 2010 were primarily for dividends paid by IDACORP and Idaho Power of $14 million and for the net repayment by IDACORP of $28 million of commercial paper.

Shelf Registrations: IDACORP has approximately $574 million remaining on its shelf registration statement that can be used for the issuance of debt securities and common stock. IDACORP has a sales agency agreement with BNY Mellon Capital Markets, LLC pursuant to which it may sell common stock from time to time in at-the-market offerings. As of March 31, 2010, there were 2.1 million shares remaining available to be sold under the sales agency agreement.

Credit Facilities: IDACORP and Idaho Power each have a five-year credit agreement that terminates on April 25, 2012, subject to one year extensions, to be used for general corporate purposes and commercial paper back-up, and that provides for the issuance of loans and standby letters of credit. Each facility contains a covenant requiring a leverage ratio of consolidated indebtedness to consolidated total capitalization of no more than 65 percent as of the end of each fiscal quarter. At March 31, 2010, the leverage ratios for IDACORP and Idaho Power were 51 percent and 52 percent, respectively. IDACORP’s and Idaho Power’s ability to utilize the credit facilities is subject to continued compliance with the leverage ratio covenants included in the credit facilities, which could limit the ability of the companies to issue first mortgage bonds and debt securities pursuant to current and future shelf registration statements. At March 31, 2010, IDACORP and Idaho Power were in compliance with all facility covenants. The following table outlines available liquidity as of the dates specified:

		March 31, 2010				December 31, 2009
				Idaho				Idaho
		IDACORP⁽²⁾		Power		IDACORP⁽²⁾		Power

Revolving credit facility		$	100,000	$	300,000	$	100,000	$	300,000
Commercial paper outstanding			(26,100)		-		(53,750)		-
Identified for other use ⁽¹⁾			-		(24,245)		-		(24,245)
	Net balance available	$	73,900	$	275,755	$	46,250	$	275,755
⁽¹⁾ Port of Morrow and American Falls bonds that holders may put to Idaho Power.
⁽²⁾ Holding company only.

At April 30, 2010, IDACORP had no loans under its credit facility and $12 million of commercial paper outstanding, and Idaho Power had no loans under its credit facility and no commercial paper outstanding.

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Credit Ratings

Moody’s: On March 30, 2010, Moody’s Investors Service (Moody’s) announced that it had revised its rating outlook to stable from negative for IDACORP and Idaho Power. Additionally, Moody’s upgraded the senior secured debt rating of Idaho Power to A2 from A3 and the rating of Idaho Power’s shelf registration for senior secured debt to (P)A2 from (P)A3. All other ratings of IDACORP and Idaho Power were affirmed by Moody’s.

The upgrade of senior secured debt at Idaho Power follows Moody’s August 2009 upgrade of the senior secured debt ratings of the majority of its investment grade regulated utilities by one notch. Issuers with negative outlooks were excluded from the August 2009 upgrade.

Moody’s stated that the change to a stable rating outlook for Idaho Power reflects the company’s strengthened financial and operating profile resulting from a series of regulatory decisions during 2009 and 2010, which it said evidence strong support for credit quality. Moody’s stated that improved cost recovery for Idaho Power through general rate relief and various cost tracking mechanisms provided in regulatory orders bolstered utility cash flow and is expected to reduce past volatility and sustain Idaho Power’s key financial metrics more in line with its rating level. Moody’s added that the execution risks associated with Idaho Power’s capital spending projects and related external financing needs are tempered by assurances of future rate treatment for the ongoing construction of the Langley Gulch combined cycle natural gas plant and anticipated conservative Idaho Power funding strategies.

Fitch: On April 22, 2010, Fitch Ratings (Fitch) announced that it has revised its rating outlook to stable from negative for IDACORP and Idaho Power. Fitch also affirmed its current ratings for the two companies.

Fitch stated that the change to a stable rating outlook for Idaho Power primarily reflects a more balanced regulatory environment in Idaho, as evidenced by several constructive regulatory actions in the last 15 months that, according to Fitch, have lowered Idaho Power’s operating risk and improved Idaho Power’s financial performance. The Idaho regulatory actions noted by Fitch include (1) the IPUC’s January 2009 order in Idaho Power’s 2008 general rate case, involving a modest general rate increase and increase in annual base net power supply costs and changes to the PCA sharing mechanism to 95 percent customers, 5 percent shareholders, and (2) the IPUC’s January 2010 order approving a general rate settlement that authorizes Idaho Power and its customers to share the benefits of the 2010 PCA reduction. Fitch noted that Idaho Power’s April 2010 PCA filing with the IPUC calculates a $146.7 million 2010 PCA reduction, which if approved by the IPUC would include a $25 million increase in Idaho Power’s base rates and a $63.7 million increase in Idaho Power’s annual base net power supply costs. Fitch stated that the latest base rate increase and current PCA mechanism should help mitigate the downside risk for Idaho Power’s financial performance, which is important given the volatility of hydroelectric generating conditions and its impact on earnings and cash flows.

Fitch also cited improvements in Idaho Power’s financial performance as reflected in Idaho Power’s reported 2009 cash flows and interest coverage and debt ratios. Fitch further referenced the benefits of Idaho Power’s other cost recovery mechanisms in Idaho and the prior approval from the IPUC of Idaho Power’s Langley Gulch project.

S&P: On February 24, 2010, Standard & Poor’s (S&P) reaffirmed its current ratings, maintaining a stable outlook for both IDACORP and Idaho Power.

Access to capital markets at a reasonable cost is determined in large part by credit quality. The following table outlines the current S&P, Moody’s and Fitch ratings of IDACORP’s and Idaho Power’s securities:

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	S&P		Moody’s		Fitch
	Idaho		Idaho		Idaho
	Power	IDACORP	Power	IDACORP	Power	IDACORP
Corporate Credit Rating ⁽¹⁾	BBB	BBB	Baa 1	Baa 2	BBB	BBB
Senior Secured Debt	A-	None	A2	None	A-	None
Senior Unsecured Debt	BBB	None	Baa 1	Baa 2	BBB+	None
Short-Term Tax-Exempt Debt	BBB/A-2	None	Baa 1/ VMIG-2	None	None	None
Commercial Paper	A-2	A-2	P-2	P-2	F2	F2
Credit Facility	None	None	Baa 1	Baa 2	None	None
Rating Outlook	Stable	Stable	Stable	Stable	Stable	Stable
⁽¹⁾ Fitch refers to its comparable rating as the “Long-term Issuer Default Rating.”

These security ratings reflect the views of the rating agencies. An explanation of the significance of these ratings may be obtained from each rating agency. Such ratings are not a recommendation to buy, sell or hold securities. Any rating can be revised upward or downward or withdrawn at any time by a rating agency if it decides that the circumstances warrant the change. Each rating should be evaluated independently of any other rating.

Capital Requirements

Idaho Power expects that total capital expenditures will be at or slightly above $1 billion from 2010 through 2012. Internal cash generation after dividends is expected to provide less than the full amount of total capital requirements for 2010 through 2012. IDACORP and Idaho Power expect minimal need for external financing in 2010, except for issuances under the dividend reinvestment and employee-related plans, and potential pre-funding of 2011 debt maturities. IDACORP and Idaho Power expect to continue financing capital requirements with a combination of internally generated funds and externally financed capital.

The following table presents Idaho Power’s estimated cash requirements for construction, excluding AFUDC, for 2010 through 2012 (in millions of dollars):

		2010		2011-2012
Ongoing capital expenditures		$	155-160	$	352-380
Advanced Metering Infrastructure (AMI)			23-25		23-25
Langley Gulch Power Plant (detailed below)			138-140		175-180
Other major projects			39-40		90-95
	Total	$	355-365	$	640-680

AMI: The AMI project provides the means to automatically retrieve energy consumption information, eliminating manual meter reading expense. Idaho Power intends to install this technology for approximately 99 percent of its customers and is on pace to complete the installations by the end of 2011. As of April 30, 2010, Idaho Power had installed approximately 250,000 AMI meters. On March 15, 2010, Idaho Power requested approval from the IPUC to include the 2010 AMI investment in its rate base. The requested increase to rates is approximately $2.4 million, and if approved the new rates are scheduled to go into effect June 1, 2010. The total cost estimates for the project are approximately $74 million. The 2010 and 2011 costs are included in the table above.

Langley Gulch Power Plant: The Langley Gulch Power Plant will be a natural gas-fired CCCT generating plant with a summer nameplate capacity of approximately 300 MWs and a winter capacity of approximately 330 MWs. The plant will be constructed near New Plymouth, Idaho, commencing in summer 2010, and is contracted to achieve commercial operation by November 1, 2012. Incentives are anticipated to advance the commercial operation date to July 1, 2012. The total cost estimate for the project including AFUDC is $427 million, $77 million of which Idaho Power has incurred through March 31, 2010. The remaining costs, excluding AFUDC for the remainder of 2010 through 2012, are included in the table above. The plant will connect to Idaho Power’s existing grid. During the first quarter of 2010, project permitting activities continued and contractor milestones were met. The water treatment and disposal plan was modified to an evaporative pond design. The plan change is not expected to increase the total project cost because it is expected to be offset by reductions in other costs. On February 24, 2010, Idaho Power closed on the land purchase of the Langley site.

Other Major Projects:

Hydroelectric Projects: In the table above, Idaho Power has included costs relating to the relicensing of hydroelectric facilities and complying with the renewed licenses. These costs total approximately $25 million for the three-year period. An additional $12 million relating to future hydroelectric projects is also included in the table.

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Hemingway Station: Construction is underway for the new 500-kV Hemingway station, located near Boise, Idaho. This station will relieve capacity and operating constraints to enhance reliable service to Idaho Power’s network and native load customers. The station is expected to be in service by summer 2010 at a total cost of approximately $57 million. The 2010 cost estimate for the project, including substation interconnections, is $20 million and is included in the above table. Under the Joint Purchase and Sale Agreement and the Joint Ownership and Operating Agreements with PacifiCorp described below, we received an initial $3.7 million net payment to Idaho Power by PacifiCorp on the closing date of May 3, 2010; during further construction of the facilities the parties will make construction cost true-up payments, and Idaho Power expects that, as a result, it may ultimately pay to PacifiCorp a net amount similar to the initial payment made by PacifiCorp to Idaho Power on the closing date.

Hemingway-Bowmont Transmission Line: The Hemingway-Bowmont transmission line consists of 12 miles of new 230-kV double circuit transmission line that will provide power to the Treasure Valley in southwest Idaho. The project is scheduled to be in service by summer 2010 at a total cost of approximately $16 million. The 2010 cost estimate for the project is $6.5 million and is included in the above table.

Boardman-Hemingway Line: The Boardman-Hemingway Line is a proposed 299-mile, 500-kV transmission project between a substation near Boardman, Oregon and the Hemingway station. This line will provide transmission service to meet needs identified in the 2009 Integrated Resources Plan (IRP) and other requests pursuant to Idaho Power’s Open Access Transmission Tariff (OATT). On April 19, 2010, Idaho Power submitted the eastern line route alternative as its proposed route in its revised right-of-way application to the U.S. Bureau of Land Management (BLM). This will restart the National Environmental Policy Act process. The cost of the initial phase of the project is estimated at $50 million and the 2010 to 2012 cost estimate is included in the table above. Total cost estimates for the project are approximately $600 million. Idaho Power expects its share of the project to be between 30 and 50 percent. Construction costs beyond the initial phase are not included in the table above. This project is expected to be completed in 2015, subject to siting, permitting and regulatory approvals.

Gateway West Project: Idaho Power and PacifiCorp are jointly exploring the Gateway West project to build transmission lines between Windstar, a substation located near Douglas, Wyoming, and the Hemingway station. Idaho Power and PacifiCorp have a cost sharing agreement for expenses incurred for analysis work of the initial phases. Idaho Power’s share of the initial phase, consisting of engineering, environmental review, permitting and rights-of-way, is approximately $40 million, and cost estimates for the 2010 to 2012 timeframe are included in the above table. Initial phases of the project could be completed by 2014; however, timing of the project’s segments may be deferred and constructed as demand requires. Idaho Power’s share will vary by segment across the project and the current estimated cost for its share is between $300 million and $500 million. Construction costs are not included in table above. The BLM has indicated that a draft environmental impact statement is expected to be issued during the summer of 2010.

For a discussion of environmental considerations relating to the above projects, see “ENVIRONMENTAL ISSUES – Endangered Species.”

Memorandum of Understanding with PacifiCorp:

On March 5, 2010, Idaho Power and PacifiCorp entered into a Memorandum of Understanding (MOU). As part of the MOU, Idaho Power and PacifiCorp agreed to negotiate in good faith to attempt to reach an arrangement pertaining to (a) an arrangement pursuant to which Idaho Power will sell to PacifiCorp an undivided ownership interest in certain of its transmission facilities, and PacifiCorp will sell to Idaho Power an undivided ownership interest in certain of its transmission facilities; and (b) joint development and construction of three transmission projects, which include (1) the 500-kV Boardman to Hemingway transmission line, and two projects that are part of the Gateway West Project; (2) a 500-kV transmission line from Populus to Cedar Hill to Hemingway, including a new Cedar Hill 500-kV station; and (3) a 500-kV transmission line from Midpoint to Cedar Hill. Under the MOU, the parties will also negotiate in good faith arrangements pertaining to interconnection of their respective systems; joint ownership, operation, and maintenance of the systems; cost-sharing; capital improvements; and each party’s rights to a specified transmission capacity on each of the lines. The MOU terminates September 1, 2010, subject to extension, and may be terminated by either party at any time.

Idaho Power and PacifiCorp are parties to existing transmission capacity rights agreements, including the Restated Transmission Services Agreement and the Agreement for Interconnection and Transmission Services discussed in the Annual Report on Form 10-K for the year ended December 31, 2009, which grant to PacifiCorp certain transmission capacity rights over portions of Idaho Power’s existing transmission system. The agreements also include a memorandum of understanding and a permitting cost sharing agreement for the Gateway West transmission line National Environmental Policy Act process. The MOU provides that Idaho Power and PacifiCorp will negotiate in good faith to attempt to reach an agreement to terminate those agreements and replace the transmission arrangements with new agreements, including the Joint Purchase and Sale Agreement and Joint Ownership and Operating Agreements discussed below.

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Joint Purchase and Sale Agreement and Joint Ownership and Operating Agreements with PacifiCorp: In connection with the MOU, on April 30, 2010, Idaho Power entered into a Joint Purchase and Sale Agreement with PacifiCorp ( Purchase and Sale Agreement), pursuant to which (1) Idaho Power agreed to sell to PacifiCorp a tenant in common ownership interest in certain high-voltage transmission-related and interconnection equipment and easement rights located at the Hemingway substation south of Boise, Idaho, currently owned by Idaho Power; and (2) PacifiCorp agreed to sell to Idaho Power a tenant in common ownership interest in certain high-voltage transmission-related and interconnection equipment and easement rights located at PacifiCorp’s Populus substation in southeast Idaho, currently owned by PacifiCorp. Under the Purchase and Sale Agreement Idaho Power and PacifiCorp are initially the 41.0 percent and 59.0 percent owner of the 500-kV portion of the specified transmission facilities at the Hemingway substation, respectively, and Idaho Power and PacifiCorp are initially the 20.8 percent owner and 79.2 percent owner of the 345-kV portion of the specified transmission facilities at the Populus substation, respectively. Each party is entitled to a pro rata share, based on its ownership interest, of the bi-directional transmission capacity of the specified transmission facilities. Other than the specified high-voltage transmission-related and interconnection equipment set forth in the Purchase and Sale Agreement, each party retains a full ownership interest in its respective substation. Closing of the acquisitions was effected on May 3, 2010.

The purchase price for Idaho Power’s acquisition of the interests in the specified transmission facilities at the Populus substation was equal to the product of (1) Idaho Power’s 20.8 percent ownership interest in the specified transmission facilities at the Populus substation and (2) the costs incurred by PacifiCorp as of the date of closing of the transaction for construction of the specified transmission facilities at the Populus substation. Similarly, the purchase price for PacifiCorp’s acquisition of the interests in the specified transmission facilities at the Hemingway substation was equal to the product of (1) PacifiCorp’s 59.0 percent ownership interest in the specified transmission facilities at the Hemingway substation and (2) the costs incurred by Idaho Power as of the date of closing of the transaction for construction of the specified transmission facilities at the Hemingway substation. Following the closing, the parties will net their respective purchase prices based on these formulas, and the party whose construction costs as of the closing date were higher will be entitled to receive from the other a payment equal to the difference between those costs. The purchase price paid on the closing date by Idaho Power was $9.0 million, and the purchase price paid on the closing date by PacifiCorp was $12.7 million. The purchase price is subject to a true-up payment for actual construction costs incurred through the closing date. Following the closing, the terms of the Operating Agreements described below provide for the making of additional payments between the parties based on a true-up of subsequent development and construction costs incurred after the closing date.

The parties have agreed to customary representations, warranties, and covenants in the Purchase and Sale Agreement. The parties have each agreed, subject to certain limitations, to indemnify the other in respect of breaches of its representations, warranties and covenants, as well as certain liabilities arising prior to the closing, including pre-closing environmental liabilities.

The Purchase and Sale Agreement provides that the Hemingway substation will be owned and operated in accordance with a Joint Ownership and Operating Agreement (the Hemingway Operating Agreement), and that the Populus substation will be owned and operated in accordance with a separate Joint Ownership and Operating Agreement (the Populus Operating Agreement, and together with the Hemingway Operating Agreement, the Operating Agreements).

The Operating Agreements, each dated May 3, 2010, set forth the terms of ownership and operation of transmission facilities at the Hemingway and Populus substations. The agreements memorialize the terms under which the parties will: (i) construct and commission additional transmission and interconnection equipment and facilities at the Hemingway and Populus substations; (ii) operate and maintain the transmission facilities at the Hemingway and Populus substations; (iii) effect the interconnection and energizing of the Idaho Power transmission system and the PacifiCorp transmission system at the Hemingway substation, as well as the interconnection and energizing of Idaho Power’s transmission system to the PacifiCorp transmission system at the Populus substation; and (iv) establish the obligations of the parties as operators of their respective substations.

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Idaho Power is designated as the operator of the Hemingway substation under the terms of the Hemingway Operating Agreement and is responsible for performing all activities necessary to construct, operate, maintain, and develop jointly-owned transmission facilities at that substation, as well as compliance with all applicable regulatory requirements. PacifiCorp is designated as the operator of the Populus substation under the terms of the Populus Operating Agreement and is responsible for performing all activities necessary to construct, operate, maintain, and develop jointly-owned transmission facilities at that substation, as well as compliance with all applicable regulatory requirements.

Under the Operating Agreements, Idaho Power and PacifiCorp are responsible for their pro rata shares (based on ownership interest) of the costs associated with construction of jointly-owned transmission facilities at the Hemingway and Populus substations from and after the closing date of the acquisition. The non-operating owner is required to pay the operator a monthly common facilities charge and operation and maintenance expense charge based on a formula that takes into account, among other items, the final installed cost of the transmission facilities at the operator’s respective substation and the non-operating party’s respective ownership interest in the transmission facilities at that substation. Each party is also responsible for a pro rata share (based on ownership interest) of any costs incurred for necessary capital upgrades or improvements. Approval of the other party is required for capital upgrades or improvements estimated to exceed $250 thousand. Either party may pursue elective capital upgrades or improvements to the transmission facilities, provided that any such upgrade or improvement will not have a material adverse affect on the transmission facilities, and provided that the other party is entitled to participate in the upgrade or improvement. Any such upgrades or improvements may result in a change in the parties’ respective ownership interests in the facilities.

The parties have agreed to customary representations, warranties, and covenants in the Operating Agreements. The parties have also each agreed, subject to certain limitations, to indemnify one another for damages, including governmental fines, resulting from their respective actions arising from the Operating Agreements and the performance of their obligations under the Operating Agreements. The Operating Agreements terminate in the event the transmission facilities are destroyed and the parties determine not to repair or rebuild the facilities, if the transmission facilities are retired and decommissioned, if all ownership interests in the transmission facilities become owned by one party, by mutual agreement of the owners, or upon the occurrence of certain uncured events of default described in the Operating Agreement. The Operating Agreements must be filed with the FERC and are subject to acceptance by the FERC.

Environmental Regulation Costs

Idaho Power’s activities are subject to a broad range of federal, state, regional and local laws and regulations designed to protect, restore and enhance the quality of the environment including air, water, and solid waste. Idaho Power estimates its environmental capital expenditures excluding AFUDC, based upon present environmental laws and regulations will be approximately $18 million during 2010 and $62 million from 2011 through 2012. These amounts are included in the table above as “Ongoing Capital Expenditures” and “Other Major Projects.” The estimated expenditures do not include costs related to possible changes in the environmental laws or regulations and enforcement policies that may be enacted in response to issues such as climate change and other pollutant emissions from coal-fired generation plants.

Other Capital Requirements

IDACORP’s non-regulated capital expenditures primarily relate to IFS’s tax-structured investments. IDACORP invested $7 million in tax-structured investments in the first quarter of 2010. Currently there are no additional expenditures anticipated for 2010, $10 million is anticipated in 2011, and none are anticipated in 2012.

American Recovery and Reinvestment Act of 2009

Under the ARRA, Idaho Power was awarded a grant of $47 million from the DOE. This grant matches a $47 million investment by Idaho Power in Smart Grid AMI technology as well as other incremental projects. The contract was signed by the DOE April 2, 2010.

Contractual Obligations

The following item is the only material change to contractual obligations made outside of the ordinary course of business during the first quarter of 2010:

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REGULATORY MATTERS:

Overview

As a regulated utility, Idaho Power is under the retail jurisdiction (as to rates, service, accounting and other general matters of utility operation) of the IPUC and the OPUC, which determine the rates that Idaho Power charges to its general business customers. Idaho Power is also under the retail regulatory jurisdiction of the IPUC, the OPUC and the Public Service Commission of Wyoming as to the issuance of debt and equity securities. Idaho Power uses general rate cases, PCA mechanisms, an FCA mechanism, and subject-specific filings to recover its costs of providing service and to earn a return on investment. The disallowance by the IPUC or the OPUC of Idaho Power’s recovery of its costs would adversely impact Idaho Power’s ability to earn its authorized rate of return on equity. Also, as a public utility under the Federal Power Act, Idaho Power has authority to charge market-based rates for wholesale energy sales under its FERC tariff and to provide transmission services under its OATT.

Idaho Power monitors legislative and regulatory developments at all levels of government, particularly those with the potential to alter the operation and productivity of its generating plants and other assets. Rate changes and regulatory decisions have a significant impact on results of operations and cash flows. During the first quarter of 2010, Idaho Power has continued to focus on timely recovery of its costs through filings with the IPUC and OPUC. Discussed below are filings and important regulatory determinations that have been made since December 31, 2009. Regulatory matters and the financial impact of rate decisions are also discussed in Note 3 to the condensed consolidated financial statements included in this report.

Idaho Regulatory Matters in 2010

Idaho Settlement Agreement:

On January 13, 2010, the IPUC approved a settlement agreement among Idaho Power, several of Idaho Power’s customers, the IPUC Staff and others. Significant elements of the settlement agreement include:

• A general rate moratorium in effect until January 1, 2012. The moratorium does not apply to other specified revenue requirement proceedings, such as the PCA, the FCA, pension funding, AMI, energy efficiency rider, and government imposed fees.

o The first $40 million will be allocated equally between customers and Idaho Power. Idaho Power’s share would be applied to increase permanent base rates on a uniform percentage basis to all customer classes and contract customers. The customers’ share would be a direct PCA rate reduction.

o All of the next $20 million will be allocated to customers as a direct PCA rate reduction.

o PCA reductions in excess of $60 million will be applied to absorb any increase in the base level of net power supply expenses.

o If the PCA reduction exceeds $60 million plus the increase in base net power supply expenses, the next $10 million will be allocated equally between Idaho Power and customers.

o Any remainder will go entirely to customers.

• A provision to share with Idaho customers 50 percent of any Idaho-jurisdictional earnings in excess of a 10.5 percent return on equity in any calendar year from 2009 to 2011.

Because Idaho Power’s 2009 Idaho-jurisdiction return on equity was between 9.5 and 10.5 percent, the sharing and additional amortization provisions were not triggered in 2009, and the ADITC available for accelerated additional amortization in 2010 is $25 million. For the three months ended March 31, 2010, Idaho Power recorded additional ADITC amortization of $4.5 million as a result of including estimated annual amounts in its effective tax rate.

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The settlement agreement included a provision to reestablish the base level for net power supply costs effective with the June 1, 2010, PCA rate change. On January 19, 2010, Idaho Power filed with the IPUC a request to reestablish base net power supply costs with an increase of $74.8 million in the Idaho jurisdiction. On April 13, 2010, the IPUC found that adjustments for PURPA contracts ($7.1 million) and Hoku ($4.0 million) as proposed by the IPUC Staff were reasonable reductions to Idaho Power’s proposed base net power supply expenses. The remaining amount of $63.7 million was approved as a working number for Idaho Power’s 2010 PCA filing, but the IPUC deferred final calculation of authorized base net power supply expenses to the 2010 PCA case. Remaining at issue is a $24.9 million increase in coal costs at the Bridger plant. A proposed increase in base net power supply costs for coal costs at the Bridger plant was raised as an area for review by the OPUC Staff, which review has concluded. OPUC approval of a stipulation of Idaho Power, the OPUC Staff, and Citizen Utilities Board is pending. The IPUC found Idaho Power’s arguments for inclusion of increased coal costs persuasive, but has provided the parties with an opportunity for further investigation as part of Idaho Power’s 2010 PCA filing.

2010 PCA Filing:

On April 15, 2010, Idaho Power made its annual PCA filing with the IPUC, requesting approval of its 2010 PCA and an increase in base rates pursuant to the terms of the settlement agreement. As filed, these two rate adjustments would be a $146.7 million 2010 PCA reduction and an $88.7 million increase to base rates, both to become effective June 1, 2010. The base rate increase includes the $63.7 million increase in Idaho Power’s annual base net power supply costs and a $25 million general increase in Idaho Power’s annual base rates.

The impact of the settlement agreement sharing on Idaho Power’s customers is a $58 million net reduction in rates for the June 1, 2010, through May 31, 2011, PCA year.

Other 2010 IPUC Filings:

In March 2010, Idaho Power made three rate filings with the IPUC, each with a requested effective date of June 1, 2010:

• Fixed Cost Adjustment: Idaho Power’s FCA filing for the 2009 calendar year proposes to collect $6.3 million for one year, a $3.6 million annual increase over current rates. The $6.3 million reflects amounts accrued in 2009 under the mechanism. The FCA mechanism began as a pilot program for Idaho Power’s Idaho residential and small general service customers, running from 2007 through 2009. On April 29, 2010, the IPUC approved a two-year extension of the pilot program commencing January 1, 2010. The FCA is a rate mechanism designed to remove Idaho Power’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. Since January 1, 2010, Idaho Power has accrued revenues of $1.8 million under the FCA.

• Pension: As Idaho Power’s pension plan was below the minimum required funding levels at January 1, 2010, future minimum contributions are required. In March 2010, Idaho Power filed a request to recover $5.4 million of pension contributions that it is required to make in 2010 with respect to 2009. Previously, on February 17, 2010, the IPUC issued an order approving a recovery methodology that would permit Idaho Power to include in future rate cases a reasonable amortization and recovery of cash contributions. The IPUC also approved a carrying charge on the difference between actual contributions and the recovery of these amounts in rates. The amortization of deferred pension costs is expected to match the revenues received as future pension contributions are recovered through rates. Idaho Power is scheduled to make the 2010 cash contribution on September 15, 2010, the extended filing date for its 2009 federal income tax return. Idaho Power’s application requests authority to recover the $5.4 million cash contribution over a one-year amortization period of June 1, 2010 through May 31, 2011, with rate adjustments becoming effective on June 1, 2010. Estimated future minimum required pension contributions will be approximately $44 million in 2011, $47 million in 2012, $39 million in 2013, and $40 million in 2014.

• Advanced Metering Infrastructure: Idaho Power filed for a $2.4 million annual increase in base rates related to AMI. Idaho Power’s request reflects a change in investment and accelerated amortization costs related to the removal of current metering equipment, as well as reductions in operating expenses that accompany the changes in plant investment, through reduced meter reading costs. Idaho Power has requested recovery through a uniform percentage rate increase of 0.33 percent for Idaho Power’s affected customer classes, effective June 1, 2010.

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Energy Efficiency Programs:

Idaho Power’s energy efficiency rider is the chief funding mechanism for Idaho Power’s investment in energy efficiency, conservation, and demand response programs. On April 14, 2010, the IPUC completed its review of energy efficiency rider expenditures that Idaho Power made during the 2002 through 2007 period and found that remaining amounts totaling $14.7 million were prudently incurred and approved for ratemaking purposes.

On March 15, 2010, Idaho Power filed an application with the IPUC requesting an order designating expenditures of $50.7 million incurred in 2008 and 2009 as prudently incurred expenses.

On February 26, 2010, Idaho Power filed an application with the IPUC requesting authorization to continue its participation in the Northwest Energy Efficiency Alliance (NEEA) for the period 2010-2014, and requested that its participation be funded by the energy efficiency rider. Idaho Power first began participating in NEEA in 1997 and the IPUC has allowed it to recover its costs in its rates. Idaho Power’s share is 8.62 percent of NEEA’s $191.7 million 2010-2014 budget. Idaho Power’s commitment to continued participation in the NEEA program is contingent upon authorization by the IPUC of recovery of Idaho Power’s costs incurred in connection with the program. If Idaho Power’s application is approved, NEEA will bill Idaho Power for first quarter 2010 expenses payable within 30 days of receipt of an order from the IPUC authorizing Idaho Power’s participation in NEEA.

Oregon Regulatory Matters in 2010

Oregon 2009 General Rate Case Settlement:

On February 24, 2010, the OPUC approved a $5 million, or 15.4 percent, increase in base rates. The new rates were effective March 1, 2010, and are based on a return on equity of 10.175 percent and an overall rate of return of 8.061 percent. Idaho Power’s previously authorized rate of return in Oregon was 7.83 percent, and its requested rate of return in its general rate case filing was 8.68 percent.

Oregon Power Cost Recovery Mechanisms:

Idaho Power’s power cost recovery mechanism in Oregon went into effect in 2008. It has two components: the APCU and the PCAM. The combination of the APCU and the PCAM allows Idaho Power to recover excess net power supply costs in a more timely fashion than through the previously existing deferral process.

APCU: On March 23, 2010, Idaho Power filed its March forecast for the 2010 APCU rate adjustment with the OPUC. A stipulation combining the March forecast and October update in 2009 was filed with the OPUC on April 15, 2010. Approval of the stipulation would result in a $5.5 million annual increase in Oregon rates, effective June 1, 2010. The target date for an OPUC order is May 28, 2010.

Oregon and Idaho Deferred Net Power Supply Costs

Idaho Power’s power supply costs can vary significantly from year to year, primarily because of weather, loads and commodity markets. Idaho Power’s power cost adjustment mechanisms allow it to recover from or refund to customers a majority of the fluctuations in power supply costs. Because of these mechanisms, the primary financial impact of power supply cost variations is that cash is paid out but recovery from customers does not occur until a future period, resulting in fluctuations in operating cash flows from year to year. A summary of the changes in deferred power supply costs during the first quarter of 2010 is set forth in Note 3 to the condensed consolidated financial statements.

The net decrease of $48.5 million in Idaho Power’s balance of deferred power supply costs from December 31, 2009, to March 31, 2010, is primarily a result of power supply costs that were $19.9 million less than the forecast amount during that period and the recovery of $28.4 million through rates.

FERC Compliance Program

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As part of its compliance program Idaho Power periodically reviews its operations for compliance with FERC rules, orders and standards and self-reports compliance issues to the FERC and the WECC. To date, reports to the FERC have focused on Standards of Conduct and Idaho Power’s OATT. Matters relating to Critical Infrastructure Protection (CIP) and other reliability standards have been self-reported to the WECC. First quarter 2010 activity included Idaho Power reports to both the FERC and the WECC, the notification that the FERC intends to take no further action regarding several issues previously reported by Idaho Power, and the receipt by Idaho Power of notices of alleged violations from the WECC relating to reliability and CIP matters. The WECC’s alleged violations, as well as certain matters reported to the FERC, remain unresolved and Idaho Power is unable to predict what action if any the WECC or the FERC will take, but Idaho Power does not expect any material adverse effect on its financial position, results of operations, or cash flows. Idaho Power plans to continue its policy of reducing potential violations through its compliance program and self-reporting compliance issues to the FERC and the WECC.

Relicensing of Hydroelectric Projects:

Idaho Power, like other utilities that operate nonfederal hydroelectric projects on qualified waterways, obtains licenses for its hydroelectric projects from the FERC, and these licenses last for 30 to 50 years. Idaho Power is actively pursuing relicensing of the Hells Canyon Complex (HCC) and Swan Falls hydroelectric projects. In addition, Idaho Power is seeking a license amendment to expand the Shoshone Falls hydroelectric project.

The most significant relicensing effort is the HCC, which provides approximately 68 percent of Idaho Power’s hydroelectric generating nameplate capacity and 36 percent of its total generating nameplate capacity. In 2007, the FERC Staff issued a final environmental impact statement (EIS) for the HCC, which the FERC will use to determine whether, and under what conditions, to issue a new license for the project. Idaho Power has reviewed the final EIS and is developing comments for filing with the FERC. However, certain portions of the final EIS involve issues that may be influenced by the water quality certifications for the project under section 401 of the Clean Water Act and formal consultations under the Endangered Species Act (ESA), which remain unresolved. Idaho Power anticipates filing comments to the final EIS as the section 401 and ESA processes progress and the manner in which they may affect pending issues becomes more certain. In that regard, Idaho Power continues to cooperate with the U.S. Fish and Wildlife Service the National Marine Fisheries Service and the FERC in an effort to address ESA concerns and to work with Idaho and Oregon to take measures to ensure that any discharges from the HCC will comply with the temperature and other applicable necessary state water quality standards so that appropriate water quality certifications can be issued for the project. The FERC is expected to issue a license order for the HCC once the endangered species consultation and the state water quality certification processes are completed. Idaho Power is currently operating under an annual license issued by the FERC and expects to continue operating under annual licenses until a new multi-year license is issued.

The license for Swan Falls hydroelectric project expires in June 2010. The FERC is expected to complete an environmental impact statement in 2010. Idaho Power expects that the FERC will issue annual licenses for the Swan Falls facility until a new multi-year license is issued.

The Shoshone Falls license amendment to expand the project from 12.5 MW to 62.5 MW is expected to be issued by the FERC in 2010.

Relicensing costs are recorded in construction work in progress until new multi-year licenses are issued by the FERC, at which time the charges will be transferred to electric plant in service. Relicensing costs and costs related to new licenses will be submitted to regulators for recovery through the ratemaking process. Relicensing costs of $120 million and $5 million for HCC and Swan Falls, respectively, were included in construction work in progress at March 31, 2010. The IPUC authorizes Idaho Power to include in rates approximately $6.8 million annually ($10.6 million grossed up for income taxes) of AFUDC relating to the HCC relicensing project, and collecting these amounts will reduce the relicensing amount submitted to regulators for recovery through the ratemaking process.

LEGAL MATTERS:

Western Energy Proceedings at the FERC: Idaho Power and IE are parties to proceedings at the FERC arising from the “western energy situation” – the California energy crisis and the energy shortages, high prices and blackouts in the western United States during 2000 and 2001 that caused numerous purchasers of electricity in those markets to initiate proceedings seeking refunds or other forms of relief and FERC to initiate its own investigations. The three major sets of cases arising out of the western energy situation relate to (1) pricing of sales in the California Independent System Operator (Cal ISO) and California Power Exchange (CalPX) markets (the California refund proceeding); (2) claims of market manipulation and tariff violations in those markets, some of which have been the subject of FERC show cause orders (the market manipulation cases); and (3) pricing of sales in the spot power markets in the Pacific Northwest (the Pacific Northwest refund proceeding).

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Proceedings in all three sets of cases remain pending before the FERC. In addition, there are pending in the Ninth Circuit approximately 200 petitions for review of numerous FERC orders regarding the western energy situation, including the California refund proceeding and the market manipulation cases. Decisions in these appeals may have implications with respect to other pending cases, including those to which Idaho Power and IE are parties.

Idaho Power and IE have reached settlements with the principal parties to the California refund proceeding and the market manipulation cases, but there remain claims by parties that have not settled that represent a small minority of potential refunds in those proceedings. Idaho Power and IE are unable to predict the outcome of these matters, but believe that the settlement releases they have obtained will restrict potential claims that might result from the disposition of these two sets of proceedings and that these matters will not have a material adverse effect on their consolidated financial positions, results of operations or cash flows.

In the Pacific Northwest refund proceeding, after reviewing the FERC’s 2003 decision declining to order refunds, the Ninth Circuit remanded the case to the FERC, officially returning the case to the FERC on April 16, 2009, to consider whether evidence of market manipulation would have altered the agency’s conclusions about refunds and to include sales originating in the Pacific Northwest to the California Department of Water Resources (CDWR) in the proceedings. In separate filings the California Parties (Pacific Gas & Electric Company, San Diego Gas & Electric Company, Southern California Edison Company, the California Public Utilities Commission, the California Department of Water Resources and the California Attorney General), City of Tacoma (Tacoma), and the Port of Seattle, Washington (Port of Seattle) asked the FERC to reorganize and restructure the Pacific Northwest case to enable them to pursue claims that all spot market sales in the Cal ISO and CalPX markets and in the Pacific Northwest from January 1, 2000 through June 20, 2001 should be subject to refund and repriced because market manipulation and tariff violations affected spot market prices. Their requests would expand the scope of the refund period in the Pacific Northwest proceeding from the December 25, 2000 through June 20, 2001 period previously considered by the FERC. In May 2009, the California Parties requested that the FERC sever sales to CDWR from the Pacific Northwest proceeding and consolidate their claims regarding these sales with ongoing proceedings in cases that Idaho Power and IE have settled, as well as with a new complaint filed on May 22, 2009 by the California Attorney General against some sellers, but not Idaho Power and IE. Idaho Power and IE, along with a number of other parties, filed their opposition to the requests of the California Parties. In April 2010, the California Parties filed a motion with the FERC renewing their May 2009 requests. In August 2009, Tacoma and Port of Seattle jointly requested the FERC to require refunds from sellers in the Pacific Northwest spot markets for the expanded period (January 1, 2000-June 20, 2001). Idaho Power and IE joined with a number of other sellers in the Pacific Northwest markets during 2000 and 2001 in opposing the motion of Tacoma and Port of Seattle. The FERC has not yet acted on the remand from the Ninth Circuit or on these filings and requests from the California Parties, Tacoma and Port of Seattle. Idaho Power and IE are unable to predict the outcome of these matters or estimate the impact they may have on their consolidated financial positions, results of operations or cash flows.

Sierra Club Lawsuits at the Bridger and Boardman Coal-Fired Plants in Which Idaho Power has Ownership Interests: In February 2007, the Sierra Club and the Wyoming Outdoor Council filed a complaint against PacifiCorp in the U.S. District Court in Cheyenne, Wyoming, alleging that PacifiCorp had violated air quality opacity standards at the Jim Bridger coal-fired plant in Sweetwater County, Wyoming. On April 15, 2010, the parties jointly filed a proposed consent decree resolving the pending litigation. The consent decree must be reviewed by the Environmental Protection Agency and approved by the court. Idaho Power is fully reserved for the contingency and, if approved, the entry of the consent decree will not have a material adverse effect on Idaho Power’s consolidated financial position, results of operations or cash flows.

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In September 2008, the Sierra Club and four other non-profit corporations filed a complaint against PGE in the U.S. District Court for the District of Oregon alleging opacity permit limit violations at the Boardman coal-fired plant located in Morrow County, Oregon. The complaint also alleged violations of the Clean Air Act, related federal regulations and the Oregon State Implementation Plan relating to PGE’s construction and operation of the plant. The complaint sought a declaration that PGE had violated opacity limits, a permanent injunction ordering PGE to comply with such limits, injunctive relief requiring PGE to remediate alleged environmental damage and ongoing impacts, civil penalties of up to $32,500 per day per violation, and reimbursement of plaintiffs’ costs of litigation, including reasonable attorneys’ fees. Idaho Power is not a party to this proceeding but has a 10 percent ownership interest in the Boardman plant. PGE owns 65 percent and is the operator of the plant. PGE has stated that it cannot determine with certainty the total amount of monetary penalties and damages asserted, but based solely on the complaint, the estimated amount is $60 million. Idaho Power is unable to predict the outcome of this matter or estimate the impact it may have on its consolidated financial position, results of operations or cash flows.

Snake River Basin Water Rights: Idaho Power is engaged in the Snake River Basin Adjudication (SRBA), which commenced in 1987, to define the nature and extent of water rights in the Snake River Basin in Idaho, including the water rights of Idaho Power. On March 25, 2009, Idaho Power and the State of Idaho (State) entered into a settlement agreement with respect to the 1984 Swan Falls Agreement and Idaho Power’s water rights under the Swan Falls Agreement, which settlement agreement is subject to certain conditions discussed below. The settlement agreement will also resolve litigation between Idaho Power and the State relating to the Swan Falls Agreement that was filed by Idaho Power on May 10, 2007, with the Idaho District Court for the Fifth Judicial Circuit, which has jurisdiction over SRBA matters, including the Swan Falls case.

The settlement agreement resolves the pending litigation by clarifying that Idaho Power’s water rights in excess of minimum flows at its hydroelectric facilities between Milner Dam and Swan Falls Dam are subordinate to future upstream beneficial uses, including aquifer recharge. The agreement commits the State and Idaho Power to further discussions on important water management issues concerning the Swan Falls Agreement and the management of water in the Snake River Basin. It also recognizes that water management measures that enhance aquifer levels, springs and river flows, such as aquifer recharge projects, benefit both agricultural development and hydropower generation and deserve study to determine their economic potential, their impact on the environment and their impact on hydropower generation. These will be a part of the Comprehensive Aquifer Management Plan (CAMP), approved by the Idaho Water Resource Board (IWRB) for the Eastern Snake Plain Aquifer (ESPA), which includes limits on the amount of aquifer recharge. Idaho Power is a member of the ESPA CAMP advisory committee and implementation committee.

On April 24, 2009, the Governor of Idaho signed into law legislation approving provisions contained in the settlement agreement. On May 6, 2009, as part of the settlement, Idaho Power, the Governor of Idaho and the IWRB executed a memorandum of agreement relating to future aquifer recharge efforts and further assurances as to limitations on the amount of aquifer recharge. Idaho Power and the State also filed a joint motion to the SRBA court to dismiss the Swan Falls case and enter the stipulated water right decrees set forth in the settlement agreement. Parties representing groundwater users in the ESPA objected to some of the language proposed by Idaho Power and the State relating to water rights in the decrees to be entered by the SRBA court as contemplated by the settlement agreement. Specifically, the concerns relate to the language describing the subordination of the rights and its interplay with the original Swan Falls settlement document and implementing legislation. On January 4, 2010, the court issued an order approving the overall settlement subject to certain modifications to the draft water right decrees proposed by Idaho Power and the State. Idaho Power is working with the State and the parties to reach agreement consistent with the court’s order regarding the language of the decrees.

Idaho Power also filed an action in the U.S. District Court of Federal Claims in Washington, D.C. in October 2007, and an amended complaint on September 30, 2008, against the U.S. Bureau of Reclamation relating to a 1923 contract right for delivery of water to its hydropower projects on the Snake River. The action seeks to recover damages from the U.S. Bureau of Reclamation for the lost generation resulting from reduced flows and a prospective declaration of contractual rights and obligations of the parties. Over the past several months, Idaho Power has been working with the U.S. and Idaho interests (including the State and upstream water users) in an effort to resolve certain state water right issues pending in the SRBA that are common to both the SRBA and the pending federal case. In an effort to promote efficiency, the parties have agreed to present certain legal issues associated with the 1923 contract to the court in the SRBA case that are expected to resolve issues in the pending federal case. The SRBA court has scheduled the presentation of these issues to the court by the fall of 2010. Idaho Power and the U.S. have agreed to stay further proceedings in the federal case pending the resolution of these issues in the SRBA case.

Idaho Power is unable to predict the outcomes of these matters or estimate the impact they may have on its consolidated financial position, results of operations or cash flows.

For further information regarding legal proceedings, see Note 9 to the condensed consolidated financial statements.

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ENVIRONMENTAL ISSUES:

Global Climate Change: Long-term climate change could significantly affect Idaho Power’s business in a variety of ways, including the following: (i) changes in temperature and precipitation could affect customer demand, (ii) extreme weather events could increase service interruptions, outages, and maintenance costs; (iii) changes in the amount and timing of snowpack and stream flows could adversely affect hydroelectric generation; (iv) legislative and/or regulatory developments related to climate change could affect plans and operations, including placing restrictions on the construction of new generation resources, the expansion of existing resources, or the operation of generation resources in general; and (v) consumer preference for, and resource planning decisions requiring, renewable or low greenhouse gas-emitting sources of energy could impact demand from existing sources and require significant investment in new generation and transmission resources.

Greenhouse Gas Emission Reduction Goals: In September 2009, IDACORP’s and Idaho Power’s Board of Directors approved guidelines that established a goal to reduce the carbon dioxide (CO₂) emission intensity of Idaho Power’s utility operations. Idaho Power’s goal is to reduce its resource portfolio’s average CO₂ emission intensity for the 2010 through 2013 time period to a level of 10 to 15 percent below Idaho Power’s 2005 CO₂ emission intensity of 1,194 lbs CO₂/MWh.

Since Idaho Power’s CO₂ emission intensity fluctuates with stream flows and production levels of anticipated renewable resource additions, Idaho Power believes an average intensity reduction goal to be achieved over several years is appropriate. Generation from Idaho Power-owned and any renewable resources under contract for which Idaho Power has long-term rights to the Renewable Energy Credits (RECs) will be included in the denominator of this calculation. The guidelines are intended to reduce Idaho Power’s average CO₂emission intensity in a manner that minimizes the costs of those reductions to Idaho Power’s customers.

In 2006, Idaho Power and Ida-West ranked as one of the 30 lowest emitters of CO₂/MWh produced among the nation’s 100 largest electricity producers, according to a collaborative report from CERES, the Natural Resources Defense Council, Public Service Enterprise Group and PG&E Corporation using publicly reported 2006 generation and emissions data.

In May 2009, Idaho Power submitted information to the Carbon Disclosure Project (CDP), an independent, not-for-profit organization that claims the largest database of corporate climate change information in the world. Idaho Power’s estimated CO₂ emission intensity (Lbs/MWh) from its generation facilities as submitted to the CDP was 1,150 and 1,097 for 2007 and 2008, respectively. Idaho Power estimates that its CO₂ emission intensity from Idaho Power-owned generation facilities for 2009 was 1,003 Lbs CO₂/MWh.

Regulation of Greenhouse Gas Emissions: The American Clean Energy and Security Act of 2009, H.R. 2454, regarding GHG emissions, renewable energy, energy efficiency, carbon capture and sequestration, and other matters, passed the U.S. House of Representatives on June 26, 2009. Senate Environment and Public Works Chairman Barbara Boxer (D-CA) and Senator John Kerry (D-MA) also introduced a climate change bill on the Senate floor on September 30, 2009, and similar legislation from Senator Kerry and others is anticipated in 2010. The timeline for action on the Senate floor remains unclear and debate continues on the direction, scope and timing of federal legislation to reduce GHG emissions. There are also state and regional initiatives (including the Western Regional Climate Action Initiative) considering regional market-based mechanisms to reduce GHG emissions.

In support of international efforts to reduce GHG emissions, in January 2010, President Obama pledged to cut GHG emissions in the United States from 2005 levels by 17 percent by 2020 and 80 percent by 2050. Any international treaty creating mandatory GHG emission reduction requirements in the United States would need to be ratified by the U.S. Senate and implemented through legislation adopted by the U.S. Congress.

In September 2009, the EPA issued a final rule that requires monitoring and reporting of GHG emissions by a number of entities beginning on January 1, 2010. Most facilities will be required to report annually. Electric generation facilities (including Idaho Power’s facilities) already reporting CO₂emissions under the Clean Air Act (CAA) Acid Rain Program must report CO₂, nitrous oxide (NO_x) and methane emissions to the EPA on a quarterly basis. In March 2010, the EPA proposed to expand the monitoring and reporting requirements to include emissions of fluorinated GHGs such as sulphur hexafluoride from electrical power transmission and distribution systems.

In December 2009, the EPA issued an “endangerment finding” for GHG emissions from motor vehicles. The “endangerment finding” is required for the EPA and the Department of Transportation National Highway Traffic Safety Administration to finalize their September 2009 proposal to adopt national GHG emission (i.e. tailpipe) standards for motor vehicles. On April 1, 2010, the EPA and the Department of Transportation issued a final rule establishing motor vehicle GHG emission standards. The “endangerment finding” and the GHG emission standards for motor vehicles have been appealed to the U.S. Court of Appeals for the District of Columbia Circuit.

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On September 30, 2009, the EPA acknowledged that the CAA will require it to regulate GHG emissions from stationary sources (including Idaho Power’s thermal facilities) through both its preconstruction and operating permit programs when the national GHG emission standards for motor vehicles go into effect. Under a final determination issued by the EPA in March 2010, stationary source GHG emissions could be subject to CAA permitting requirements as early as January 2011. Under its September 30, 2009 proposed rule, the EPA sought to establish an applicability threshold of 25,000 tons of GHGs per year (CO₂equivalent) for the preconstruction and operating permit programs. In February 2010, the EPA announced that it was considering an initial applicability threshold for 2011 and 2012 of at least 75,000 tons of GHGs per year.

In August 2007, Oregon enacted legislation establishing goals for the reduction of GHG emissions, which seek to (i) by 2010, cease the growth of Oregon GHG emission; (ii) by 2020, reduce GHG levels to 10 percent below 1990 levels; and (iii) by 2050, reduce GHG levels to at least 75 percent below 1990 levels. The legislation also calls for state government-developed policy recommendations in the future to assist in the monitoring and achievement of these goals. The impact of the enacted legislation on Idaho Power cannot be determined at this time.

Idaho Power will continue to monitor and evaluate any proposed international, federal, state or regional GHG legislation or initiatives as well as any judicial decisions that could affect its generating facilities. The majority of current initiatives regarding GHG emissions contemplate market-based compliance programs. The regulation of GHG emissions under the CAA could result in GHG emission limits on stationary sources that do not provide market-based compliance options such as cap-and-trade programs or emission offsets. Such a program could raise uncertainty about the future viability of fossil fuels, specifically coal, as an economical energy source for new and existing electric generation facilities because new technologies for reducing CO₂ emissions from coal, including carbon capture storage, are still in the development stage and are not yet proven. At this time, Idaho Power is unable to estimate the costs of compliance with any such legislation or initiatives because they are in the early stages of development and final legislation, if adopted, could vary from current proposals. In the 2009 IRP, Idaho Power did not include any new conventional coal resources in the resource portfolio due to the uncertainty regarding future carbon regulations.

Renewable Portfolio Standards (RPS): The American Clean Energy and Security Act of 2009, in the form passed in the U.S. House of Representatives on June 26, 2009, would require utilities to obtain 20 percent of their electricity from renewable sources by 2020, and reduce demand an additional five percent through conservation and increased energy efficiency. The Senate version, if enacted, would require electric utilities to meet 15 percent of their electricity sales through renewable sources of energy or energy efficiency by 2021. Resources eligible to meet these standards include wind, solar, geothermal, biomass, landfill gas, ocean, and incremental hydropower (efficiency improvements or new capacity). Both bills recognize the benefits of existing hydroelectric generation by allowing utilities to subtract generation from existing hydroelectric projects from their total sales base prior to calculating the percentage requirement. Idaho Power will be required to comply with a ten percent RPS in Oregon beginning in 2025. Idaho Power expects to meet these requirements with the REC’s from the Elkhorn Valley wind project. No RPS requirement currently exists in Idaho. Idaho Power continues to monitor proposed federal RPS legislation, which if passed could increase Idaho Power’s capital expenditures and operating costs and reduce earnings and cash flows.

Idaho Power has contracts to purchase energy from seven wind projects that have already achieved commercial operations: the combined nameplate rating of these projects is 192 MW. In addition, one 17 MW wind project recently demonstrated significant progress towards achieving commercial operations. Idaho Power also has an additional 264 MW of wind generation with signed and IPUC approved contracts that have not yet been constructed. Idaho Power is currently negotiating a power purchase agreement for additional wind generation with a capacity of 160 MW. Idaho Power does not receive the “green tags” or RECs associated with PURPA projects and is selling its near-term RECs and returning to customers their share of those proceeds through the PCA in accordance with a May 2009 IPUC order. Idaho Power filed with the IPUC in December 2009 a plan to address its treatment of future RECs. Under Idaho Power’s proposed plan, Idaho Power would sell near-term RECs, while continuing to acquire and hold long-term contractual rights to own RECs for use in meeting a future federal renewable electricity standard (RES). RECs that are sold rather than retired would not count in meeting RES requirements. Idaho Power continues to pursue additional geothermal, wind, and combined heat and power (CHP) generation resource development opportunities. Other renewable generation resources anticipated from future cogeneration and small power production contracts include solar, biomass, and additional wind projects.

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Air Quality: Idaho Power co-owns three coal-fired power plants and owns two natural gas combustion turbine power plants that are subject to air quality regulation. The coal-fired plants are: Jim Bridger (33 percent interest) located in Wyoming; Boardman (10 percent interest) located in Oregon; and Valmy (50 percent interest) located in Nevada. The natural gas-fired plants, Danskin and Bennett Mountain, are located in Idaho. The CAA establishes controls on the emissions from stationary sources like those owned by Idaho Power. The EPA adopts many of the standards and regulations under the CAA, while states have the primary responsibility for implementation and administration of these air quality programs. In February 2010, a bill was introduced in the Senate to impose limits on SO₂ and NO_x emissions from power plants starting in 2012 and to require at least a 90 percent reduction in mercury emissions from coal-fired generation. Idaho Power continues to actively monitor, evaluate and work on air quality issues pertaining to federal and state mercury emission rules, possible legislative amendment of the CAA as discussed above, National Ambient Air Quality Standards (NAAQS), and Regional Haze – Best Available Retrofit Technology (RH BART) and New Source Review (NSR) permitting.

Mercury Emissions: Mercury continuous emission monitoring systems have been installed on all of the coal-fired units at the Jim Bridger, Boardman, and Valmy plants and tests to confirm the accuracy of the data being collected are currently underway. The EPA has announced that it is developing maximum achievable control technology (MACT) standards to reduce mercury emissions from coal-fired power plants. Early indications are that these MACT standards will apply uniformly to all coal-fired power plants, unlike the cap-and-trade mercury standards of the Clean Air Mercury Rule. In 2008, the State of Oregon adopted a mercury rule requiring Boardman to reduce mercury emissions by 90 percent or meet an emission rate of 0.6 lbs/trillion BTU by July 2012. PGE has requested and the State of Oregon is now considering allowing up to a two year extension. Idaho Power continues to monitor Wyoming and Nevada actions related to mercury emissions. Idaho Power is unable to predict at this time what actions the EPA or the other states may take to reduce mercury emissions from its coal-fired power plants. In April 2010, the U.S. District Court for the District of Columbia approved, by consent decree, a timetable that would require the EPA to propose a standard to control mercury emissions from coal-fired power plants by May 16, 2011, and to finalize it by November of 2011.

National Ambient Air Quality Standards: In July 1997, the EPA adopted new NAAQS for ozone (8-hour ozone standard) and fine particulate matter of less than 2.5 micrometers in diameter (PM2.5 standard). Regulations promulgated by the EPA to implement these NAAQS have been challenged and portions have been remanded back to the EPA for reconsideration. The EPA and state efforts to implement the NAAQS adopted in 1997 are ongoing. All of the counties in Idaho, Oregon, Nevada and Wyoming where Idaho Power’s power plants operate currently are designated as meeting attainment with the 8-hour ozone and PM2.5 standards adopted by the EPA in 1997.

In December 2006, the EPA revised the NAAQS for PM2.5. This new standard was challenged by a number of groups in the U.S. Court of Appeals for the District of Columbia Circuit and the court remanded the standard back to the EPA in February 2009. All of the counties in Idaho, Nevada, Oregon and Wyoming where Idaho Power’s power plants operate currently were designated as meeting attainment with the revised PM2.5 NAAQS. The impact of the new standard will not be known until the judicial appeals are completed and the associated regulatory programs are promulgated and implemented.

In March 2008, the EPA promulgated a final regulation which revised the 8-hour ozone NAAQS, and on January 19, 2010, the EPA proposed to adopt a more stringent 8-hour ozone NAAQS. Idaho Power is unable to predict what impact the adoption of this standard may have on its operations.

On January 22, 2010, the EPA adopted a new NAAQS for NO₂ at a level of 100 parts per billion averaged over a 1-hour period. The EPA has not yet designated areas as attaining or not attaining the new NAAQS. In addition, on November 16, 2009, the EPA proposed a more stringent NAAQS for SO₂ to a level between 50 and 100 parts per billion averaged over a 1-hour period. Idaho Power is unable to predict what impact the adoption and implementation of these standards may have on its operations.

Regional Haze – Best Available Retrofit Technology: In accordance with federal regional haze rules, coal-fired utility boilers are subject to RH BART if they were built between 1962 and 1977 and affect any Class I areas. This includes all four units at the Jim Bridger plant and the Boardman plant. The two units at the Valmy plant were constructed after 1977 and are not subject to the federal regional haze rule. The Wyoming Department of Environmental Quality (WDEQ) and the Oregon Department of Environmental Quality (ODEQ) have conducted assessments of the Boardman and Bridger plants pursuant to an RH BART process. These states have also evaluated the need for additional controls at Boardman and Bridger to achieve reasonable progress toward a long term strategy beyond RH BART to reduce regional haze in Class I areas to natural conditions by the year 2064.

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On December 31, 2009 WDEQ issued a RH BART permit to PacifiCorp for the Jim Bridger plant. WDEQ determined that low NO_x burners with over-fire air is RH BART for NO_x for all four Bridger units and that RH BART is not required for SO₂ for the Bridger plant. As part of WDEQ’s long term strategy for regional haze, the permit requires that PacifiCorp install selective catalytic reduction (SCR) for NO_x control at Bridger Units 3 and 4 by December 31, 2015 and December 31, 2016, respectively, and submit an application by January 15, 2015 to install add-on NO_x controls at Bridger Units 1 and 2 by December 31, 2023. PacifiCorp is already in the process of installing low NO_x burners and SO₂ scrubber upgrades at the Bridger plant. The SO₂ scrubber upgrade project has been completed on Bridger Units 2 and 4 and is expected to be completed on the other two units by the end of 2011. Idaho Power expects to spend approximately $22 million between 2009 and 2012 to complete these projects. Idaho Power’s estimated share of the cost to install SCR on Bridger Units 3 and 4 is $120 million. Installation of SCR also could require extended maintenance outages. Design and cost estimates for add-on NO_x controls at Bridger Units 1 and 2 are not yet available. On February 26, 2010, PacifiCorp filed an administrative appeal of the Bridger RH BART permit with the Wyoming Environmental Quality Council. PacifiCorp contends that WDEQ lacked the legal and technical basis to require the SCR and add-on NOx controls required by the permit. Idaho Power will continue to monitor this process. It is not possible for Idaho Power to predict the outcome of the administrative appeals process at this time.

On June 19, 2009 the Oregon Environmental Quality Commission adopted a rule that would require the installation of controls at Boardman in two phases. The first phase, which ODEQ determined is RH BART, would require the installation of low NOx burners and over-fire air by July 1, 2011, and the installation of semi-dry flue gas desulfurization and a bag house by July 1, 2014. The second phase, which is part of ODEQ’s long term strategy, would require the installation of SCR by July 1, 2017. Idaho Power’s estimated share of the cost of the pollution control requirements for RH BART and the long term strategy is between approximately $52 million and $56 million. Approximately three-quarters of the costs will be incurred by 2014 with the remainder incurred by 2017. Installation of this pollution control equipment also could require extended maintenance outages. On April 2, 2010 PGE submitted a petition requesting that the Oregon Environmental Quality Commission amend the RH BART and long term strategy requirements for the Boardman plant to be the installation of low NO_x burners and over-fire air by July 1, 2011, the phased transition to reduced sulfur coal by December 31, 2011 and July 1, 2014, and the closure of Boardman plant coal-fired boiler by December 31, 2020. Idaho Power’s estimated share of the cost of the revised RH BART and the long term strategy requirements is approximately $4 million. It is not possible for Idaho Power to predict the outcome of this proceeding at this time.

While not required under RH BART, installation of low NO_x burners and over-fired upgrades has been completed at the Valmy plant.

New Source Review: Since 1999, the EPA and the U.S. Department of Justice have been pursuing a national enforcement initiative focused on the compliance status of coal-fired power plants with the New Source Review (NSR) permitting requirements and New Source Performance Standards (NSPS) of the CAA. This initiative has resulted in both enforcement litigation and significant settlements with a large number of public utilities and other owners of coal-fired power plants across the country. The current administration has indicated an intention to continue this NSR enforcement initiative. The EPA sent information requests under section 114 of the CAA, requesting information relevant to NSR and NSPS compliance to the Jim Bridger plant in 2003, the Valmy plant in 2009 and the Boardman plant in 2008 with a follow up request for information in 2009. Idaho Power is a co-owner of these plants, but does not operate the plants. A number of utilities that have received section 114 information requests have engaged in negotiations with the EPA to address any allegations of non-compliance with NSR and NSPS requirements. In some cases, such negotiations have resulted in settlements requiring the payment of civil penalties, installation of additional pollution controls, the surrender of emission allowances, and the completion of supplemental environmental projects. Idaho Power cannot predict the outcome of these investigatory and enforcement matters at this time.

Coal Ash: In December 2008, the breach of a dike at the Tennessee Valley Authority’s Kingston Station resulted in a spill of several million cubic yards of ash into a nearby river and onto private properties. In May 2010, the EPA announced proposed regulations pursuant to the Resource Conservation and Recovery Act governing the management of coal combustion products. If this or other new legislation or regulations increase the cost of managing and disposing of coal combustion products or create additional liability with respect to historic disposal practices, they could have an adverse impact on Idaho Power’s consolidated financial position, results of operations or cash flows. However, the financial and operational consequences cannot be determined until final legislation is passed or regulations enacted.

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Endangered Species:

Slickspot Peppergrass: This southwestern Idaho plant species was listed as threatened by the U.S. Fish and Wildlife Service (USFWS) effective December 2009. While critical habitat for the plant was not designated at the time of listing, approximately 98% of the plant species is located on federal land owned by the BLM and the Department of Defense. Parts of the Gateway West and Boardman to Hemingway 500 kV transmission lines and the Langley Gulch transmission and water lines will cross BLM land. This listing will add an additional requirement and species for consideration in the Endangered Species Act (ESA) section 7 consultation. A section 7 consultation is a process used to determine a proposed action’s effects on any ESA-listed species that may be within the project area. This listing may increase the expense and delay the timing of permitting for these projects.

Sage Grouse: On March 5, 2010, the USFWS announced that listing of the greater sage grouse as threatened or endangered under the ESA is warranted, but precluded by higher priority listing actions. The sage grouse is now considered a “candidate species” under the ESA, which allows land management agencies to implement additional conservation measures in an effort to prevent a formal ESA listing. Any required additional conservation measures may increase the costs of existing operations and impact the cost and timing of siting and permitting of the Gateway West and Boardman to Hemingway 500-kV transmission lines and the Langley Gulch transmission projects. Listing of the greater sage grouse as threatened or endangered under the ESA would add an additional requirement and species for consideration in ESA section 7 consultations for those projects, and may increase the expense and adversely affect the timing of those projects.

Hells Canyon Project: In 2007, the FERC requested initiation of formal consultation under the ESA with the National Marine Fisheries Service (NMFS) and the USFWS regarding potential effects of HCC relicensing on several listed aquatic and terrestrial species. Formal consultation has not yet been initiated and NMFS and USFWS continue to gather and consider information relative to the effects of relicensing on relevant species. Idaho Power continues to cooperate with the USFWS, the NMFS and the FERC in an effort to address ESA concerns. Idaho Power may be required to modify operations pursuant to the Biological Opinion that will result from formal consultation. However, the issuance of a final Biological Opinion within the next 18 to 24 months is unlikely.

Bliss and Lower Salmon Falls Projects: Idaho Power is finalizing a Snail Protection Plan (Plan) in cooperation with the USFWS. If the Plan is approved by the FERC, Idaho Power will file applications with the FERC to amend the licenses for the Bliss and Lower Salmon Falls projects that will maintain operating flexibility at both projects for the remainder of their licenses.

OTHER MATTERS:

Critical Accounting Policies and Estimates

IDACORP’s and Idaho Power’s discussion and analysis of their financial condition and results of operations are based upon their condensed consolidated financial statements, which have been prepared in accordance with generally accepted accounting principles. The preparation of these financial statements requires IDACORP and Idaho Power to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. On an ongoing basis, IDACORP and Idaho Power evaluate these estimates including those estimates related to rate regulation, benefit costs, contingencies, litigation, impairment of assets, income taxes, unbilled revenue and bad debt. These estimates are based on historical experience and on other assumptions and factors that are believed to be reasonable under the circumstances, and are the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. IDACORP and Idaho Power, based on their ongoing reviews, make adjustments when facts and circumstances dictate.

IDACORP’s and Idaho Power’s critical accounting policies are reviewed by the Audit Committee of the Board of Directors. These policies are discussed in more detail under “Critical Accounting Policies and Estimates” in the Annual Report on Form 10-K for the year ended December 31, 2009, and have not changed materially from that discussion.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

IDACORP and Idaho Power are exposed to market risks, including changes in interest rates, changes in commodity prices, credit risk and equity price risk. The following discussion summarizes these risks and the financial instruments, derivative instruments and derivative commodity instruments sensitive to changes in interest rates, commodity prices and equity prices that were held at March 31, 2010:

Interest Rate Risk

IDACORP’s and Idaho Power’s interest rate risk has not changed materially from that reported in Item 7A of the Annual Report on Form 10-K for the year ended December 31, 2009.

Commodity Price Risk

IDACORP’s and Idaho Power’s commodity price risk has not changed materially from that reported in Item 7A of the Annual Report on Form 10-K for the year ended December 31, 2009. Information regarding Idaho Power’s use of derivative instruments to manage commodity price risk can be found in Note 12 to the condensed consolidated financial statements included in this Quarterly Report on Form 10-Q.

Credit Risk

Idaho Power is subject to credit risk based on its activity with market counterparties. Idaho Power is exposed to this risk to the extent that a counterparty may fail to fulfill a contractual obligation to provide energy, purchase energy or complete financial settlement for market activities. Idaho Power mitigates this exposure by actively establishing credit limits, measuring, monitoring, reporting, using appropriate contractual arrangements and transferring of credit risk through the use of financial guarantees, cash or letters of credit. A current list of acceptable counterparties and credit limits is maintained.

The use of performance assurance collateral in the form of cash, letters of credit, or guarantees is common industry practice. Idaho Power maintains margin agreements that allow performance assurance collateral to be requested and/or posted with certain counterparties. As of March 31, 2010, Idaho Power had posted approximately $3.7 million of assurance collateral. Should Idaho Power experience a reduction in its credit rating on Idaho Power’s unsecured debt to below investment grade, Idaho Power could be subject to additional requests by its wholesale counterparties to post additional performance assurance collateral. Counterparties to derivative instruments could request immediate payment or demand immediate ongoing full daily collateralization on derivative instruments in net liability positions. Based upon Idaho Power’s current energy and fuel portfolio and current market conditions as of March 31, 2010, the approximate amount of additional collateral that could be requested upon a downgrade is approximately $19 million. Idaho Power actively monitors the portfolio exposure and the potential exposure to additional requests for performance assurance collateral calls, through sensitivity analysis, to minimize capital requirements.

Idaho Power’s credit risk related to uncollectible accounts has not changed materially from that reported in Item 7A of the Annual report on Form 10-K for the year ended December 31, 2009.

Equity Price Risk

IDACORP’s and Idaho Power’s equity price risk has not changed materially from that reported in Item 7A of the Annual Report on Form 10-K for the year ended December 31, 2009.

ITEM 4. CONTROLS AND PROCEDURES

Disclosure controls and procedures:

IDACORP:

The Chief Executive Officer and the Chief Financial Officer of IDACORP, based on their evaluation of IDACORP’s disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of March 31, 2010, have concluded that IDACORP’s disclosure controls and procedures are effective.

Idaho Power:

The Chief Executive Officer and the Chief Financial Officer of Idaho Power, based on their evaluation of Idaho Power’s disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of March 31, 2010, have concluded that Idaho Power’s disclosure controls and procedures are effective.

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Changes in internal control over financial reporting:

There have been no changes in IDACORP’s or Idaho Power’s internal control over financial reporting during the quarter ended March 31, 2010, that have materially affected, or are reasonably likely to materially affect, IDACORP’s or Idaho Power’s internal control over financial reporting.

PART II – OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Please refer to Note 9 to the condensed consolidated financial statements in this Quarterly Report on Form 10-Q.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Restrictions on Dividends:

A covenant under IDACORP’s credit facility and Idaho Power’s credit facility requires IDACORP and Idaho Power to maintain leverage ratios of consolidated indebtedness to consolidated total capitalization, as defined therein, of no more than 65 percent at the end of each fiscal quarter. Idaho Power’s Revised Code of Conduct approved by the IPUC on April 21, 2008, states that Idaho Power will not pay any dividends to IDACORP that will reduce Idaho Power’s common equity capital below 35 percent of its total adjusted capital without IPUC approval.

Idaho Power must obtain approval of the OPUC before it could directly or indirectly loan funds or issue notes or give credit on its books to IDACORP.

Issuer Purchases of Equity Securities:

IDACORP, Inc. Common Stock
During the quarter ended March 31, 2010, IDACORP effected the following repurchases of its common stock:

						(d)
					(c)	Maximum Number
		(a)	(b)		Total Number of	(or Approximate
		Total			Shares Purchased	Dollar Value) of
		Number of	Average		as Part of Publicly	Shares that May Yet
		Shares	Price Paid		Announced Plans or	Be Purchased Under
Period		Purchased¹	per Share		Programs	the Plans or Programs

January 1 – January 31, 2010		9,717	$	32.17	-	-
February 1 – February 28, 2010		15,637		33.03	-	-
March 1 - March 31, 2010		-		-	-	-
	Total	25,354	$	32.70	-	-
¹ These shares were withheld for taxes upon vesting of restricted stock.

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ITEM 5. OTHER INFORMATION

Please refer to Part I, Item 2, “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS – LIQUIDITY AND CAPITAL RESOURCES – Joint Purchase and Sale Agreement and Joint Ownership and Operating Agreements with PacifiCorp,” for a discussion of agreements entered into by Idaho Power on April 30, 2010 and May 3, 2010.

ITEM 6. EXHIBITS

* Previously filed and incorporated herein by reference

Exhibit No.	Description

10.21¹	IDACORP, Inc. Non-Employee Directors Stock Compensation Plan, as amended February 26, 2010.
*10.61¹	Exhibit A to the IDACORP, Inc. Executive Incentive Plan, as amended February 26, 2010. File number 1-14465, 1-3198, Form 8-K, filed on 3/4/10 as Exhibit 10.1.
*10.62¹	Form of Amended and Restated Change in Control Agreement between IDACORP, Inc. and Officers of IDACORP, Inc. and Idaho Power Company, approved March 17, 2010. File number 1-14465, 1-3198, Form 8-K, filed on 3/24/10 as Exhibit 10.1.
10.66¹	IDACORP, Inc. and/or Idaho Power Executive Officers with Amended and Restated Change in Control Agreements Chart, as of March 31, 2010.
10.67¹	IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan – Form of Performance Share Award Agreement (performance with two goals) (February 26, 2010).
*10.68¹	IDACORP, Inc. Executive Incentive Plan NEO 2010 Award Opportunity Chart. File number 1-14465, 1-3198, Form 8-K, filed on 3/24/10 as Exhibit 10.2.
12.1	IDACORP, Inc. Computation of Supplemental Ratio of Earnings to Fixed Charges.
12.2	Idaho Power Company Computation of Supplemental Ratio of Earnings to Fixed Charges.
15	Letter Re: Unaudited Interim Financial Information.
31.1	IDACORP, Inc. Rule 13a-14(a) CEO certification.
31.2	IDACORP, Inc. Rule 13a-14(a) CFO certification.
31.3	Idaho Power Rule 13a-14(a) CEO certification.
31.4	Idaho Power Rule 13a-14(a) CFO certification.
32.1	IDACORP, Inc. Section 1350 CEO certification.
32.2	IDACORP, Inc. Section 1350 CFO certification.
32.3	Idaho Power Section 1350 CEO certification.
32.4	Idaho Power Section 1350 CFO certification.
99	Earnings press release for the first quarter 2010.

¹ Management contract or compensatory plan or arrangement

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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 thereunto duly authorized.

		IDACORP, Inc.
		(Registrant)



Date:	May 6, 2010	By:	/s/J. LaMont Keen
			J. LaMont Keen
			President and Chief Executive Officer

Date:	May 6, 2010	By:	/s/Darrel T. Anderson
			Darrel T. Anderson
			Executive Vice President - Administrative
			Services and Chief Financial Officer





		IDAHO POWER COMPANY
		(Registrant)



Date:	May 6, 2010	By:	/s/J. LaMont Keen
			J. LaMont Keen
			President and Chief Executive Officer

Date:	May 6, 2010	By:	/s/Darrel T. Anderson
			Darrel T. Anderson
			Executive Vice President - Administrative
			Services and Chief Financial Officer

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EXHIBIT INDEX

Exhibit No.	Description

10.21¹	IDACORP, Inc. Non-Employee Directors Stock Compensation Plan, as amended February 26, 2010.
10.66¹	IDACORP, Inc. and/or Idaho Power Executive Officers with Amended and Restated Change in Control Agreements Chart, as of March 31, 2010.
10.67¹	IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan – Form of Performance Share Award Agreement (performance with two goals) (February 26, 2010).
12.1	IDACORP, Inc. Computation of Supplemental Ratio of Earnings to Fixed Charges.
12.2	Idaho Power Company Computation of Supplemental Ratio of Earnings to Fixed Charges.
15	Letter Re: Unaudited Interim Financial Information.
31.1	IDACORP, Inc. Rule 13a-14(a) CEO certification.
31.2	IDACORP, Inc. Rule 13a-14(a) CFO certification.
31.3	Idaho Power Company Rule 13a-14(a) CEO certification.
31.4	Idaho Power Company Rule 13a-14(a) CFO certification.
32.1	IDACORP, Inc. Section 1350 CEO certification.
32.2	IDACORP, Inc. Section 1350 CFO certification.
32.3	Idaho Power Company Section 1350 CEO certification.
32.4	Idaho Power Company Section 1350 CFO certification.
99	Earnings press release for the first quarter 2010.

¹ Management contract or compensatory plan or arrangement

X	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
	EXCHANGE ACT OF 1934
	For the quarterly period ended March 31, 2010
	OR
	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
	EXCHANGE ACT OF 1934
	For the transition period from __________ to __________
		Exact name of registrants as specified	I.R.S. Employer
Commission File		in their charters, address of principal	Identification
Number		executive offices, zip code and telephone number	Number
1-14465		IDACORP, Inc.	82-0505802
1-3198		Idaho Power Company	82-0130980
		1221 W. Idaho Street
		Boise, ID 83702-5627
		(208) 388-2200
		State of Incorporation: Idaho
		Websites: www.idacorpinc.com, www.idahopower.com
		None
Former name, former address and former fiscal year, if changed since last report.

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

Number of shares of Common Stock outstanding as of March 31, 2010:
IDACORP, Inc.:	48,097,763
Idaho Power Company:	39,150,812, all held by IDACORP, Inc.

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Part I. Financial Information:
	Item 1. Financial Statements (unaudited)
		IDACORP, Inc.:
			Condensed Consolidated Statements of Income	4
			Condensed Consolidated Balance Sheets	5-6
			Condensed Consolidated Statements of Cash Flows	7
			Condensed Consolidated Statements of Comprehensive Income	8
			Condensed Consolidated Statements of Equity	9
		Idaho Power Company:
			Condensed Consolidated Statements of Income	10
			Condensed Consolidated Balance Sheets	11-12
			Condensed Consolidated Statements of Capitalization	13
			Condensed Consolidated Statements of Cash Flows	14
			Condensed Consolidated Statements of Comprehensive Income	15
		Notes to the Condensed Consolidated Financial Statements		16-32
		Reports of Independent Registered Public Accounting Firm		33-34

	Item 2. Management’s Discussion and Analysis of Financial Condition and Results of
			Operations	35-63

	Item 3. Quantitative and Qualitative Disclosures About Market Risk			64

	Item 4. Controls and Procedures			64-65

Part II. Other Information:

	Item 1. Legal Proceedings			65

	Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			65

	Item 5. Other Information			66

	Item 6. Exhibits			66

Signatures				67

Exhibit Index				68

	Three months ended
	March 31,
	2010		2009
	(thousands of dollars except
	for per share amounts)
Operating Revenues:
Electric utility:
General business	$	203,745	$	187,927
Off-system sales	34,406		28,530
Other revenues	14,309		11,572
Total electric utility revenues	252,460		228,029
Other	503		545
Total operating revenues	252,963		228,574
Operating Expenses:
Electric utility:
Purchased power	21,174		33,701
Fuel expense	37,187		39,133
Power cost adjustment	48,324		15,859
Other operations and maintenance	72,094		68,541
Energy efficiency programs	5,034		4,057
Depreciation	28,583		25,963
Taxes other than income taxes	5,680		5,062
Total electric utility expenses	218,076		192,316
Other expense	840		624
Total operating expenses	218,916		192,940
Operating Income	34,047		35,634
Other Income, Net	4,481		6,921
(Losses) Earnings of Unconsolidated Equity-Method Investments	(2,378)		402
Interest Expense:
Interest on long-term debt	19,441		16,639
Other interest expense, net of AFUDC	(453)		836
Total interest expense	18,988		17,475
Income Before Income Taxes	17,162		25,482
Income Tax Expense	1,305		6,796
Net Income	15,857		18,686
Adjustment for loss attributable to noncontrolling interests	206		198
Net Income Attributable to IDACORP, Inc.	$	16,063	$	18,884
Weighted Average Common Shares Outstanding - Basic (000’s)	47,773		46,831
Weighted Average Common Shares Outstanding - Diluted (000’s)	47,885		46,876
Earnings Per Share of Common Stock (basic and diluted):
Earnings Attributable to IDACORP, Inc.	$	0.34	$	0.40
Dividends Paid Per Share of Common Stock	$	0.30	$	0.30

The accompanying notes are an integral part of these statements.

COMMONLY USED TERMS

ADITC	-	Accumulated Deferred Investment Tax Credits
AFUDC	-	Allowance for Funds Used During Construction
APCU	-	Annual Power Cost Update
BCC	-	Bridger Coal Company, a joint venture of IERCo
Cal ISO	-	California Independent System Operator
CalPX	-	California Power Exchange
CAMP	-	Comprehensive Aquifer Management Plan
CO₂	-	Carbon Dioxide
EPS	-	Earnings per share
ESA	-	Endangered Species Act
ESPA	-	Eastern Snake Plain Aquifer
FCA	-	Fixed Cost Adjustment mechanism
FERC	-	Federal Energy Regulatory Commission
Fitch	-	Fitch Ratings
HCC	-	Hells Canyon Complex
Ida-West	-	Ida-West Energy, a subsidiary of IDACORP, Inc.
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.
IPUC	-	Idaho Public Utilities Commission
IRP	-	Integrated Resource Plan
IWRB	-	Idaho Water Resource Board
kW	-	Kilowatt
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
NOx	-	Nitrogen Oxide
O&M	-	Operations and Maintenance
OATT	-	Open Access Transmission Tariff
OPUC	-	Oregon Public Utility Commission
PCA	-	Power Cost Adjustment
PCAM	-	Power Cost Adjustment Mechanism
PURPA	-	Public Utility Regulatory Policies Act of 1978
REC	-	Renewable Energy Certificate
RH BART	-	Regional Haze - Best Available Retrofit Technology
S&P	-	Standard & Poor’s Ratings Services
SO₂	-	Sulfur Dioxide
SRBA	-	Snake River Basin Adjudication
Valmy	-	North Valmy Steam Electric Generating Plant
VIEs	-	Variable Interest Entities

	March 31,		December 31,
	2010		2009
Assets	(thousands of dollars)

Current Assets:
Cash and cash equivalents	$	41,436	$	52,987
Receivables:
Customer (net of allowance of $1,797 and $1,805, respectively)	71,518		74,987
Other (net of allowance of $1,400 and $1,073, respectively)	10,903		11,922
Accrued unbilled revenues	40,033		51,272
Materials and supplies (at average cost)	47,535		48,054
Fuel stock (at average cost)	25,006		25,634
Prepayments	8,810		11,111
Deferred income taxes	31,773		31,773
Other	4,413		2,666
Total current assets	281,427		310,406

Investments	200,458		195,298

Property, Plant and Equipment:
Utility plant in service	4,177,048		4,160,178
Accumulated provision for depreciation	(1,565,201)		(1,558,538)
Utility plant in service - net	2,611,847		2,601,640
Construction work in progress	323,116		289,188
Utility plant held for future use	7,149		7,151
Other property, net of accumulated depreciation	18,915		19,029
Property, plant and equipment - net	2,961,027		2,917,008

Other Assets:
American Falls and Milner water rights	22,902		24,226
Company-owned life insurance	26,866		26,654
Regulatory assets	684,540		720,401
Long-term receivables (net of allowance of $1,861 and $2,157, respectively)	4,020		4,217
Other	41,192		40,517
Total other assets	779,520		816,015

Total	$	4,222,432	$	4,238,727

The accompanying notes are an integral part of these statements.

Name	Title	Date of Agreement
J. LaMont Keen	President and Chief Executive Officer, IDACORP and Idaho Power	12/29/08
Darrel T. Anderson	Executive Vice President – Administrative Services and Chief Financial Officer, IDACORP and Idaho Power	12/23/08
Daniel B. Minor	Executive Vice President – Operations, Idaho Power	12/30/08
Rex Blackburn	Senior Vice President and General Counsel, IDACORP and Idaho Power	4/1/09
Lisa A. Grow	Senior Vice President – Power Supply, Idaho Power	12/12/08
Steven R. Keen	Vice President and Treasurer, IDACORP and Idaho Power	12/30/08
Dennis C. Gribble	Vice President and Chief Information Officer, IDACORP and Idaho Power	12/11/08
Lori D. Smith	Vice President – Corporate Planning and Chief Risk Officer, IDACORP and Idaho Power	12/31/08
Luci K. McDonald	Vice President – Human Resources, IDACORP and Idaho Power	12/20/08
Naomi Shankel	Vice President – Audit and Compliance, IDACORP and Idaho Power	12/9/08
Jeffrey L. Malmen	Vice President – Public Affairs, IDACORP and Idaho Power	12/10/08
John R. Gale	Vice President – Regulatory Affairs, Idaho Power	12/12/08
Warren Kline	Vice President – Customer Operations, Idaho Power	12/15/08
Patrick A. Harrington	Corporate Secretary, IDACORP and Idaho Power	12/9/08
N. Vern Porter*	Vice President – Delivery Engineering and Operations, Idaho Power	03/18/10

Date of Grant:
Number of Performance Shares (the “Target Award”):
Maximum Number of Additional Performance Shares:
Performance Period:
Performance Goal:	(i) Cumulative earnings per share (“CEPS”) for the Performance Period, as reported on the Company’s audited financial statements, weighted 50% and (ii) IDACORP total shareholder return (“TSR”) relative to the Peer Group defined in Annex A for the Performance Period, weighted 50%
Vesting Date:	Vesting of the Performance Shares subject to the Target Award (if at all) shall occur as soon as administratively practicable in the calendar year following the Performance Period to the extent the Performance Goals are met Vesting of any additional Performance Shares (if at all) shall occur as soon as administratively practicable, but no later than March 15 of the calendar year following the Performance Period to the extent performance exceeds target levels
Dividends:	Dividends are accrued throughout the Performance Period and paid as soon as administratively practicable, but no later than March 15 of the calendar year following the Performance Period with respect to Performance Shares subject to the Target Award that vest and any additional Performance Shares that are earned and distributed

CEPS for Performance Period	Payout Percentage (% of Target Award)
$___ (“maximum”) or higher	150%
$___ (“target”)	100%
$___ (“threshold”)	50%
Less than $___	0%

Percentile Rank	Payout Percentage (% of Target Award)
75^th (“maximum”) or higher	150%
55^th (“target”)	100%
35th	50%
Less than 35th	0%

Exhibit 12.1
IDACORP, Inc.
Consolidated Financial Information
Ratio of Earnings to Fixed Charges and Supplemental Ratio of Earnings to Fixed Charges
(Thousands of Dollars)
	Three Months
	Ended		Twelve Months Ended
	March 31,		December 31,
	2010		2009		2008		2007			2006		2005
RATIO OF EARNINGS TO FIXED CHARGES
Earnings, as defined:
Income from continuing operations before income taxes	$	17,162	$	146,737	$	117,614	$		96,003	$	115,452	$	103,327
Adjust for distributed income of equity investees	2,378		13,724		5,176		6,064			(9,347)		(10,370)
Supplemental fixed charges, as below	21,444		79,461		81,172		72,879			65,745		64,379
Total earnings, as defined	$	40,984	$	239,922	$	203,962	$	174,946		$	171,850	$	157,336
Fixed charges, as defined:
Interest charges¹	$	21,180	$	78,457	$	80,282	$	71,946		$	64,720	$	62,962
Rental interest factor	264		1,004		890		933			1,025		1,417
Total fixed charges, as defined	$	21,444	$	79,461	$	81,172	$	72,879		$	65,745	$	64,379
Ratio of earnings to fixed charges	1.91 x		3.02 x		2.51 x		2.40 x			2.61 x		2.44 x
SUPPLEMENTAL RATIO OF EARNINGS TO FIXED CHARGES
Earnings, as defined:
Income from continuing operations before income taxes	$	17,162	$	146,737	$	117,614	$	96,003		$	115,452	$	103,327
Adjust for distributed income of equity investees	2,378		13,724		5,176		6,064			(9,347)		(10,370)
Supplemental fixed charges, as below	21,771		80,946		82,962		74,631			67,521		65,991
Total earnings, as defined	$	41,311	$	241,407	$	205,752	$	176,698		$	173,626	$	158,948
Supplemental fixed charges, as defined:
Interest charges¹	$	21,180	$	78,457	$	80,282	$	71,946		$	64,720	$	62,962
Rental interest factor	264		1,004		890		933			1,025		1,417
Supplemental increment to fixed charges²	327		1,485		1,790		1,752			1,776		1,612
Total fixed charges, as defined	$	21,771	$	80,946	$	82,962	$	74,631		$	67,521	$	65,991
Supplemental ratio of earnings to fixed charges	1.90 x		2.98 x		2.48 x		2.37 x			2.57 x		2.41 x
¹FIN 48 interest is not included in interest charges.
² Explanation of increment - Interest on the guaranty of American Falls Reservoir District bonds and Milner Dam, Inc. notes which are already included in operation expenses.

Exhibit 12.2
Idaho Power Company
Consolidated Financial Information
Ratio of Earnings to Fixed Charges and Supplemental Ratio of Earnings to Fixed Charges
(Thousands of Dollars)
	Three Months
	Ended		Twelve Months Ended
	March 31,		December 31,
	2010		2009		2008		2007		2006		2005
RATIO OF EARNINGS TO FIXED CHARGES
Earnings, as defined:
Income from continuing operations before income taxes	$	20,527	$	158,080	$	131,715	$	111,965	$	137,890	$	115,764
Adjust for distributed income of equity investees	(348)		2,464		(6,772)		(5,553)		(9,347)		(10,370)
Supplemental fixed charges, as below	20,550		78,543		77,568		68,272		60,687		57,739
Total earnings, as defined	$	40,729	$	239,087	$	202,511	$	174,684	$	189,230	$	163,133
Fixed charges, as defined:
Interest charges¹	$	20,295	$	77,580	$	76,711	$	67,386	$	59,955	$	56,866
Rental interest factor	255		963		857		886		732		873
Total fixed charges, as defined	$	20,550	$	78,543	$	77,568	$	68,272	$	60,687	$	57,739
Ratio of earnings to fixed charges	1.98 x		3.04 x		2.61 x		2.56 x		3.12 x		2.83 x
SUPPLEMENTAL RATIO OF EARNINGS TO FIXED CHARGES
Earnings, as defined:
Income from continuing operations before income taxes	$	20,527	$	158,080	$	131,715	$	111,965	$	137,890	$	115,764
Adjust for distributed income of equity investees	(348)		2,464		(6,772)		(5,553)		(9,347)		(10,370)
Supplemental fixed charges, as below	20,877		80,028		79,358		70,024		62,463		59,351
Total earnings, as defined	$	41,056	$	240,572	$	204,301	$	176,436	$	191,006	$	164,745
Supplemental fixed charges, as defined:
Interest charges¹	$	20,295	$	77,580	$	76,711	$	67,386	$	59,955	$	56,866
Rental interest factor	255		963		857		886		732		873
Supplemental increment to fixed charges²	327		1,485		1,790		1,752		1,776		1,612
Total fixed charges, as defined	$	20,877	$	80,028	$	79,358	$	70,024	$	62,463	$	59,351
Supplemental ratio of earnings to fixed charges	1.97 x		3.01 x		2.57 x		2.52 x		3.06 x		2.78 x
¹FIN 48 interest is not included in interest charges.
² Explanation of increment - Interest on the guaranty of American Falls Reservoir District bonds and Milner Dam, Inc. notes which are already included in operation expenses.

Date:	May 6, 2010	By:	/s /J. LaMont Keen
			J. LaMont Keen
			President and Chief Executive Officer

Date:	May 6, 2010	By:	/s/ J. LaMont Keen
			J. LaMont Keen
			President and Chief Executive Officer

	March 31,		December 31,
	2010		2009
	(thousands of dollars)
Common Stock Equity:
Common stock	$	97,877	$	97,877
Premium on capital stock	638,758		638,758
Capital stock expense	(2,097)		(2,097)
Retained earnings	551,539		547,695
Accumulated other comprehensive loss	(7,674)		(8,267)
Total common stock equity	1,278,403		1,273,966

Long-Term Debt:
First mortgage bonds:
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
6.025% Series due 2018	120,000		120,000
6.15% Series due 2019	100,000		100,000
4.50% Series due 2020	130,000		130,000
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		140,000
6.25% Series due 2037	100,000		100,000
Total first mortgage bonds	1,215,000		1,215,000
Amount due within one year	(120,000)		-
Net first mortgage bonds	1,095,000		1,215,000

Pollution control revenue bonds:
5.15% Series due 2024	49,800		49,800
5.25% Series 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	7,446		8,509
Note guarantee due within one year	(1,064)		(1,064)
Unamortized premium/discount - net	(2,993)		(3,060)

Investor and Analyst Contact	Media Contact
Lawrence F. Spencer	Echo Chadwick
Director of Investor Relations	Corporate Communication
Phone: (208) 388-2664	Phone: (208) 388-6654
lspencer@idacorpinc.com	echadwick@idahopower.com


Net income attributable to IDACORP, Inc. - three months ended March 31, 2009				$	18.9
Change in Idaho Power net income before taxes:
	Rate and other regulatory changes including PCA⁽¹⁾ and FCA⁽²⁾mechanisms	$	8.9
	Reduced sales volumes		(6.7)
	Payroll related increases		(1.8)
	Increase in depreciation expense related to advanced metering		(2.6)
	Decrease in life insurance gains		(3.3)
	Decrease in earnings at Bridger Coal Company		(3.0)
	Other		(0.1)
Accumulated deferred investment tax credit (ADITC) amortization			4.5
Decrease in income tax expense (net of ADITC)			3.0
Total decrease in Idaho Power net income				$	(1.1)
Other net decreases (net of tax)					(1.7)
Net income attributable to IDACORP, Inc. - three months ended March 31, 2010				$	16.1

The outlook for key operating and financial metrics is:		2010 Estimates
Key Operating & Financial Metrics		Current	Previous
Idaho Power Operation & Maintenance
	Expense (millions)	No Change	$295-$305
Idaho Power Capital
	Expenditures (millions) ⁽¹⁾	No Change	$355-$365
Idaho Power Hydroelectric
	Generation (million MWh)	No Change	6.5-8.5
Non-Regulated Subsidiary Earnings
	and Holding Company Expenses (millions) ⁽²⁾	No Change	$0.0-$3.0