Edgar Filing: IDACORP INC

Idaho Power

IDA 09.30.13 10Q

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)



X	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
	EXCHANGE ACT OF 1934
	For the quarterly period ended September 30, 2013
	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, Idaho 83702-5627
		(208) 388-2200
		State of Incorporation: Idaho
		None
Former name, former address and former fiscal year, if changed since last report.

Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.

IDACORP, Inc.: Yes X No __ Idaho Power Company: Yes X No __

Indicate by check mark whether the registrants have submitted electronically and posted on their corporate Web sites, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrants were required to submit and post such files).

IDACORP, Inc.: Yes X No ___ Idaho Power Company: Yes X No ___

Indicate by check mark whether the registrants are large accelerated filers, accelerated filers, non-accelerated filers, or smaller reporting companies. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act (check one):

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

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

IDACORP, Inc.: Yes No X Idaho Power Company: Yes No X

Number of shares of common stock outstanding as of November 1, 2013:

IDACORP, Inc.: 50,232,745

Idaho Power Company: 39,150,812, all held by IDACORP, Inc.

This combined Form 10-Q represents separate filings by IDACORP, Inc. and Idaho Power Company. Information contained herein relating to an individual registrant is filed by that registrant on its own behalf. Idaho Power Company makes no representations as to the information relating to IDACORP, Inc.’s other operations.

Idaho Power Company meets the conditions set forth in General Instruction (H)(1)(a) and (b) of Form 10-Q and is therefore filing this report on Form 10-Q with the reduced disclosure format.

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TABLE OF CONTENTS
				Page
Commonly Used Terms				3
Cautionary Note Regarding Forward-Looking Statements				4

Part I. Financial Information

	Item 1. Financial Statements (unaudited)
		IDACORP, Inc.:
			Condensed Consolidated Statements of Income	6
			Condensed Consolidated Statements of Comprehensive Income	7
			Condensed Consolidated Balance Sheets	8
			Condensed Consolidated Statements of Cash Flows	10
			Condensed Consolidated Statements of Equity	11
		Idaho Power Company:
			Condensed Consolidated Statements of Income	12
			Condensed Consolidated Statements of Comprehensive Income	13
			Condensed Consolidated Balance Sheets	14
			Condensed Consolidated Statements of Cash Flows	16
		Notes to the Condensed Consolidated Financial Statements		17
		Reports of Independent Registered Public Accounting Firm		35
	Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			37
	Item 3. Quantitative and Qualitative Disclosures About Market Risk			69
	Item 4. Controls and Procedures			70

Part II. Other Information:

	Item 1. Legal Proceedings			70
	Item 1A. Risk Factors			70
	Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			71
	Item 4. Mine Safety Disclosures			71
	Item 5. Other Information			71
	Item 6. Exhibits			71

Signatures				72

Exhibit Index				73

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COMMONLY USED TERMS

The following select abbreviations, terms, or acronyms are commonly used or found in multiple locations in this report:

ADITC	-	Accumulated Deferred Investment Tax Credits
AFUDC	-	Allowance for Funds Used During Construction
AMI	-	Advanced Metering Infrastructure
BCC	-	Bridger Coal Company, a joint venture of IERCo
BLM	-	U.S. Bureau of Land Management
CAA	-	Clean Air Act
CO₂	-	Carbon Dioxide
CSPP	-	Cogeneration and Small Power Production
CWA	-	Clean Water Act
EGUs	-	Electric Utility Steam Generating Units
EIS	-	Environmental Impact Statement
EPA	-	U.S. Environmental Protection Agency
FCA	-	Fixed Cost Adjustment
FERC	-	Federal Energy Regulatory Commission
FIP	-	Federal Implementation Plan
GHG	-	Greenhouse Gas
HAPs	-	Hazardous Air Pollutants
HCC	-	Hells Canyon Complex
IDACORP	-	IDACORP, Inc., an Idaho corporation
Idaho Power	-	Idaho Power Company, an Idaho corporation
Idaho ROE	-	Idaho-jurisdiction return on year-end equity
Ida-West	-	Ida-West Energy, a subsidiary of IDACORP, Inc.
IERCo	-	Idaho Energy Resources Co., a subsidiary of Idaho Power Company
IESCo	-	IDACORP Energy Services Co., a subsidiary of IDACORP, Inc.
IFS	-	IDACORP Financial Services, a subsidiary of IDACORP, Inc.
IPUC	-	Idaho Public Utilities Commission
IRP	-	Integrated Resource Plan
kW	-	Kilowatt
MD&A	-	Management’s Discussion and Analysis of Financial Condition and Results of Operations
MW	-	Megawatt
MWh	-	Megawatt-hour
NO_x	-	Nitrogen Oxide
O&M	-	Operations and Maintenance
OATT	-	Open Access Transmission Tariff
OPUC	-	Oregon Public Utility Commission
PCA	-	Power Cost Adjustment
PURPA	-	Public Utility Regulatory Policies Act of 1978
REC	-	Renewable Energy Certificate
SCR	-	Selective Catalytic Reduction
SEC	-	U.S. Securities and Exchange Commission
SIP	-	State Implementation Plan
SMSP	-	Senior Management Security Plan I and II
SO₂	-	Sulfur Dioxide
SRBA	-	Snake River Basin Adjudication
WPSC	-	Wyoming Public Service Commission

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

In addition to the historical information contained in this report, this report contains (and oral communications made by IDACORP, Inc. and Idaho Power Company may contain) statements that relate to future events and expectations, such as statements regarding projected or future financial performance, cash flows, capital expenditures, dividends, capital structure or ratios, strategic goals, challenges, objectives, and plans for future operations. Such statements constitute forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. 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 are not guarantees of future performance and involve estimates, assumptions, risks, and uncertainties. Actual results, performance, or outcomes may differ materially from the results discussed in the statements. In addition to any assumptions and other factors and matters referred to specifically in connection with such forward-looking statements, factors that could cause actual results or outcomes to differ materially from those contained in forward-looking statements include those factors set forth in this report, IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2012, particularly Item 1A - “Risk Factors” and Part II, Item 7 - “Management’s Discussion and Analysis of Financial Condition and Results of Operations," subsequent reports filed by IDACORP and Idaho Power with the Securities and Exchange Commission, and the following important factors:


•	Idaho Power's rate design and the effect of regulatory decisions by the Idaho and Oregon public utilities commissions, the Federal Energy Regulatory Commission, and other regulators affecting Idaho Power's ability to recover costs and earn a return;


•	changes in residential, commercial, and industrial growth and demographic patterns within Idaho Power's service area, the loss or change in the business of significant customers, and the availability and use of energy efficiency and conservation programs, and the associated impact on loads and load growth;


•	the impacts of changes in economic conditions, including the potential for changes in customer demand for electricity, revenue from sales of excess power, financial soundness of counterparties and suppliers, and collections;


•	unseasonable or severe weather conditions, wildfires, and other natural phenomena, which affect customer demand, hydroelectric generation levels, infrastructure repair costs, and the ability and cost to procure fuel for generation plants or purchased power to serve customers;


•	advancement of new technologies that reduce loads or render Idaho Power's generation facilities obsolete;


•	adoption of, changes in, and costs of compliance with, laws, regulations, and policies relating to the environment, natural resources, and endangered species, and the ability to recover those costs through rates;


•	variable hydrological conditions and over-appropriation of surface and groundwater in the Snake River basin, which can impact the amount of generation from Idaho Power's hydroelectric facilities;


•	the ability to purchase fuel and power from suppliers on favorable payment terms and prices, particularly in the event of unanticipated power demands, lack of physical availability, transportation constraints, or a credit downgrade;

•

accidents, fires, explosions, and mechanical breakdowns that may occur while operating and maintaining an electric system, which can cause unplanned outages, reduce generating output, damage the companies’ assets, operations, or reputation, subject the companies to third-party claims for property damage, personal injury, or loss of life, or result in the imposition of civil, criminal, or regulatory fines or penalties;

•

the ability to obtain debt and equity financing or refinance existing debt when necessary and on favorable terms, which can be affected by factors such as credit ratings, volatility in the financial markets (including as a result of European sovereign debt issues) and interest rate fluctuations, decisions by the Idaho or Oregon public utility commissions, and the companies' past or projected financial performance;


•	reductions in credit ratings, which could adversely impact access to capital markets and would require the posting of additional collateral to counterparties pursuant to existing power purchase and credit arrangements;

•

the ability to buy and sell power, transmission capacity, and fuel in the markets and the availability to enter into financial and physical commodity hedges with creditworthy counterparties, including the impact of federal legislation on counterparties' willingness to transact, market liquidity, and hedging costs, which may affect fuel and power availability and pricing, and the failure of any such risk management and hedging strategies to work as intended;


•	changes in or implementation of Federal Energy Regulatory Commission and other mandatory reliability, security, and other requirements for system infrastructure, which could result in penalties and increase costs;

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•	disruptions or outages of Idaho Power's generation or transmission systems or the western interconnected transmission system;


•	the costs and operational challenges of integrating an increasing volume of mandated purchased intermittent wind power or other renewable energy sources into Idaho Power's resource portfolio;


•	changes in actuarial assumptions, the interest rate environment, and the actual return on plan assets for pension and other post-retirement plans, which can affect future pension and other post-retirement plan funding obligations, costs, and liabilities;


•	the ability to continue to pay dividends under the terms of the companies' credit arrangements and regulatory limitations, and whether the companies' boards of directors will continue to declare dividends based on the boards of directors’ periodic consideration of factors affecting IDACORP's and Idaho Power's dividend policies;


•	changes in tax laws or related regulations or new interpretations of applicable laws by federal, state, or local taxing jurisdictions, the availability of tax credits, and the tax rates payable by IDACORP shareholders on common stock dividends;


•	employee workforce factors, including the operational and financial costs of unionization or the attempt to unionize all or part of the companies' workforce, the impact of an aging workforce, the cost and ability to retain skilled workers, and the ability to adjust the labor cost structure when necessary;


•	failure to comply with state and federal laws, policies, and regulations, including new interpretations and enforcement initiatives by regulatory and oversight bodies, which may result in penalties and increase the cost of compliance, the nature and extent of investigations and audits, and the cost of remediation;


•	the inability to obtain or cost of obtaining and complying with required governmental permits and approvals, licenses, rights-of-way, and siting for transmission and generation projects and hydroelectric facilities;


•	the cost and outcome of litigation, dispute resolution, regulatory proceedings, and penalties, and the ability to recover those costs or the costs of operational changes through insurance or rates, or from third parties;


•	the failure of information systems or the failure to secure information system data, failure to comply with privacy laws, security breaches, or the direct or indirect effect on the companies' business or operations resulting from cyber attacks, terrorist incidents or the threat of terrorist incidents, and acts of war;


•	adoption of or changes in accounting policies and principles, including the potential adoption of all or a portion of International Financial Reporting Standards, changes in accounting estimates, and new Securities and Exchange Commission or New York Stock Exchange requirements, or new interpretations of existing requirements; and


•	unusual or unanticipated changes in normal business operations, including unusual maintenance or repairs, or the failure to successfully implement technology solutions.

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. IDACORP and Idaho Power disclaim any obligation to update publicly any forward-looking information, whether in response to new information, future events, or otherwise, except as required by applicable law.

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PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

IDACORP, Inc.

Condensed Consolidated Statements of Income

(unaudited)



	Three months ended September 30,						Nine months ended September 30,
	2013			2012			2013			2012
	(thousands of dollars except for per share amounts)
Operating Revenues:
Electric utility:
General business	$	349,428		$	306,066		$	846,079		$	724,025
Off-system sales	11,169			4,826			31,597			43,953
Other revenues	19,707			21,865			69,853			58,810
Total electric utility revenues	380,304			332,757			947,529			826,788
Other	803			1,262			2,455			3,074
Total operating revenues	381,107			334,019			949,984			829,862
Operating Expenses:
Electric utility:
Purchased power	74,088			71,570			166,097			151,026
Fuel expense	64,858			55,978			155,901			110,014
Power cost adjustment	(6,960		)	(42,871		)	(34,969		)	(37,074		)
Other operations and maintenance	84,471			89,968			247,409			254,487
Energy efficiency programs	6,077			8,410			30,279			20,971
Depreciation	32,538			31,607			96,680			92,028
Taxes other than income taxes	7,017			7,012			23,243			22,961
Total electric utility expenses	262,089			221,674			684,640			614,413
Other	3,459			3,068			10,945			9,837
Total operating expenses	265,548			224,742			695,585			624,250
Operating Income	115,559			109,277			254,399			205,612
Allowance for Equity Funds Used During Construction	3,734			3,541			10,876			18,989
Earnings of Unconsolidated Equity-Method Investments	2,758			1,304			571			795
Other Income, Net	1,567			1,453			3,982			3,978
Interest Expense:
Interest on long-term debt	20,887			19,670			61,349			59,252
Other interest	1,812			1,717			5,296			5,060
Allowance for borrowed funds used during construction	(1,904		)	(1,986		)	(5,711		)	(10,269		)
Total interest expense, net	20,795			19,401			60,934			54,043
Income Before Income Taxes	102,823			96,174			208,894			175,331
Income Tax Expense	31,088			3,910			58,129			22,812
Net Income	71,735			92,264			150,765			152,519
Adjustment for loss (income) attributable to noncontrolling interests	15			(195		)	31			(220		)
Net Income Attributable to IDACORP, Inc.	$	71,750		$	92,069		$	150,796		$	152,299
Weighted Average Common Shares Outstanding - Basic (000’s)	50,056			49,966			50,051			49,918
Weighted Average Common Shares Outstanding - Diluted (000’s)	50,153			50,080			50,109			49,990
Earnings Per Share of Common Stock:
Earnings Attributable to IDACORP, Inc. - Basic	$	1.43		$	1.84		$	3.01		$	3.05
Earnings Attributable to IDACORP, Inc. - Diluted	$	1.43		$	1.84		$	3.01		$	3.05
Dividends Declared Per Share of Common Stock	$	0.38		$	0.33		$	1.14		$	0.99

The accompanying notes are an integral part of these statements.

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IDACORP, Inc.

Condensed Consolidated Statements of Comprehensive Income

(unaudited)



	Three months ended September 30,					Nine months ended September 30,
	2013		2012			2013		2012
	(thousands of dollars)

Net Income	$	71,735	$	92,264		$	150,765	$	152,519
Other Comprehensive Income:
Net unrealized holding gains arising during the period, net of tax of $541, $438, $1,466 and $968	843		682			2,283		1,507
Unfunded pension liability adjustment, net of tax of $298, $170, $894 and $511	464		265			1,394		796
Total Comprehensive Income	73,042		93,211			154,442		154,822
Comprehensive loss (income) attributable to noncontrolling interests	15		(195		)	31		(220		)
Comprehensive Income Attributable to IDACORP, Inc.	$	73,057	$	93,016		$	154,473	$	154,602

The accompanying notes are an integral part of these statements.

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IDACORP, Inc.

Condensed Consolidated Balance Sheets

(unaudited)



	September 30, 2013			December 31, 2012
	(thousands of dollars)
Assets

Current Assets:
Cash and cash equivalents	$	186,870		$	26,527
Receivables:
Customer (net of allowance of $2,201 and $1,551, respectively)	111,214			66,111
Other (net of allowance of $165 and $322, respectively)	12,394			23,608
Income taxes receivable	—			1,753
Accrued unbilled revenues	52,445			51,448
Materials and supplies (at average cost)	52,857			51,037
Fuel stock (at average cost)	35,412			42,388
Prepayments	14,041			12,823
Deferred income taxes	35,056			56,532
Current regulatory assets	63,445			30,078
Other	3,116			4,948
Total current assets	566,850			367,253
Investments	174,749			189,020
Property, Plant and Equipment:
Utility plant in service	5,035,762			4,915,772
Accumulated provision for depreciation	(1,759,785		)	(1,703,159		)
Utility plant in service - net	3,275,977			3,212,613
Construction work in progress	321,128			298,470
Utility plant held for future use	7,093			7,101
Other property, net of accumulated depreciation	17,342			17,847
Property, plant and equipment - net	3,621,540			3,536,031
Other Assets:
American Falls and Milner water rights	16,064			17,909
Company-owned life insurance	22,055			22,646
Regulatory assets	1,139,353			1,132,960
Long-term receivables (net of allowance of $1,260 and $1,260, respectively)	4,437			4,437
Other	46,070			49,260
Total other assets	1,227,979			1,227,212
Total	$	5,591,118		$	5,319,516

The accompanying notes are an integral part of these statements.

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IDACORP, Inc.

Condensed Consolidated Balance Sheets

(unaudited)



	September 30, 2013			December 31, 2012
	(thousands of dollars)
Liabilities and Equity

Current Liabilities:
Current maturities of long-term debt	$	71,064		$	71,064
Notes payable	53,000			69,700
Accounts payable	88,835			90,165
Income taxes accrued	13,802			1,005
Interest accrued	26,409			22,311
Accrued compensation	35,883			42,343
Current regulatory liabilities	8,474			30,277
Other	37,797			24,438
Total current liabilities	335,264			351,303
Other Liabilities:
Deferred income taxes	938,162			894,616
Regulatory liabilities	369,729			355,362
Pension and other postretirement benefits	416,272			423,409
Other	52,717			65,228
Total other liabilities	1,776,880			1,738,615
Long-Term Debt	1,615,197			1,466,632
Commitments and Contingencies
Equity:
IDACORP, Inc. shareholders’ equity:
Common stock, no par value (shares authorized 120,000,000; 50,233,463 and 50,158,486 shares issued, respectively)	838,575			834,922
Retained earnings	1,034,472			940,968
Accumulated other comprehensive loss	(13,439		)	(17,116		)
Treasury stock (1,131 and 1,817 shares at cost, respectively)	(13		)	(21		)
Total IDACORP, Inc. shareholders’ equity	1,859,595			1,758,753
Noncontrolling interests	4,182			4,213
Total equity	1,863,777			1,762,966
Total	$	5,591,118		$	5,319,516

The accompanying notes are an integral part of these statements.

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IDACORP, Inc.

Condensed Consolidated Statements of Cash Flows

(unaudited)



	Nine months ended September 30,
	2013			2012
	(thousands of dollars)
Operating Activities:
Net income	$	150,765		$	152,519
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	99,534			95,904
Deferred income taxes and investment tax credits	42,079			19,824
Changes in regulatory assets and liabilities	(20,765		)	(24,618		)
Pension and postretirement benefit plan expense	22,026			28,689
Contributions to pension and postretirement benefit plans	(32,573		)	(47,466		)
Earnings of unconsolidated equity-method investments	(571		)	(795		)
Distributions from unconsolidated equity-method investments	14,218			12,375
Allowance for equity funds used during construction	(10,876		)	(18,989		)
Other non-cash adjustments to net income, net	2,308			2,046
Change in:
Accounts receivable	(38,553		)	(14,776		)
Accounts payable and other accrued liabilities	(4,505		)	(1,440		)
Taxes accrued/receivable	24,621			11,457
Other current assets	4,749			(11,565		)
Other current liabilities	5,253			(6,501		)
Other assets	(1,253		)	(7,202		)
Other liabilities	(8,811		)	(7,980		)
Net cash provided by operating activities	247,646			181,482
Investing Activities:
Additions to property, plant and equipment	(165,550		)	(187,751		)
Proceeds from the sale of emission allowances and RECs	498			2,706
Investments in affordable housing	—			(107		)
Distributions from affordable housing investments	1,697			—
Other	3,366			(137		)
Net cash used in investing activities	(159,989		)	(185,289		)
Financing Activities:
Issuance of long-term debt	150,000			150,000
Retirement of long-term debt	(1,064		)	(101,064		)
Dividends on common stock	(57,323		)	(49,950		)
Net change in short-term borrowings	(16,700		)	(2,800		)
Issuance of common stock	255			4,839
Acquisition of treasury stock	(2,124		)	(2,062		)
Other	(358		)	(2,735		)
Net cash provided by (used in) financing activities	72,686			(3,772		)
Net increase (decrease) in cash and cash equivalents	160,343			(7,579		)
Cash and cash equivalents at beginning of the period	26,527			27,813
Cash and cash equivalents at end of the period	$	186,870		$	20,234
Supplemental Disclosure of Cash Flow Information:
Cash paid during the period for:
Income taxes	$	60		$	1,178
Interest (net of amount capitalized)	$	54,907		$	50,137
Non-cash investing activities:
Additions to property, plant and equipment in accounts payable	$	22,480		$	22,595

The accompanying notes are an integral part of these statements.

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IDACORP, Inc.

Condensed Consolidated Statements of Equity

(unaudited)



	Nine months ended September 30,
	2013			2012
	(thousands of dollars)
Common Stock
Balance at beginning of period	$	834,922		$	828,389
Issued	255			4,839
Other	3,398			2,514
Balance at end of period	838,575			835,742
Retained Earnings
Balance at beginning of period	940,968			840,916
Net income attributable to IDACORP, Inc.	150,796			152,299
Common stock dividends ($1.14 and $0.99 per share)	(57,292		)	(49,640		)
Balance at end of period	1,034,472			943,575
Accumulated Other Comprehensive (Loss) Income
Balance at beginning of period	(17,116		)	(11,622		)
Unrealized gain on securities (net of tax)	2,283			1,507
Unfunded pension liability adjustment (net of tax)	1,394			796
Balance at end of period	(13,439		)	(9,319		)
Treasury Stock
Balance at beginning of period	(21		)	(29		)
Issued	2,132			2,070
Acquired	(2,124		)	(2,062		)
Balance at end of period	(13		)	(21		)
Total IDACORP, Inc. shareholders’ equity at end of period	1,859,595			1,769,977
Noncontrolling Interests
Balance at beginning of period	4,213			4,040
Net (loss) income attributable to noncontrolling interests	(31		)	220
Balance at end of period	4,182			4,260
Total equity at end of period	$	1,863,777		$	1,774,237

The accompanying notes are an integral part of these statements.

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Idaho Power Company

Condensed Consolidated Statements of Income

(unaudited)



	Three months ended September 30,						Nine months ended September 30,
	2013			2012			2013			2012
	(thousands of dollars)
Operating Revenues:
General business	$	349,428		$	306,066		$	846,079		$	724,025
Off-system sales	11,169			4,826			31,597			43,953
Other revenues	19,707			21,865			69,853			58,810
Total operating revenues	380,304			332,757			947,529			826,788
Operating Expenses:
Operation:
Purchased power	74,088			71,570			166,097			151,026
Fuel expense	64,858			55,978			155,901			110,014
Power cost adjustment	(6,960		)	(42,871		)	(34,969		)	(37,074		)
Other operations and maintenance	84,471			89,968			247,409			254,487
Energy efficiency programs	6,077			8,410			30,279			20,971
Depreciation	32,538			31,607			96,680			92,028
Taxes other than income taxes	7,017			7,012			23,243			22,961
Total operating expenses	262,089			221,674			684,640			614,413
Income from Operations	118,215			111,083			262,889			212,375
Other Income (Expense):
Allowance for equity funds used during construction	3,734			3,541			10,876			18,989
Earnings of unconsolidated equity-method investments	5,102			2,906			7,358			6,933
Other expense, net	(1,077		)	(769		)	(4,450		)	(3,615		)
Total other income	7,759			5,678			13,784			22,307
Interest Charges:
Interest on long-term debt	20,887			19,670			61,349			59,252
Other interest	1,724			1,617			5,009			4,756
Allowance for borrowed funds used during construction	(1,904		)	(1,986		)	(5,711		)	(10,269		)
Total interest charges	20,707			19,301			60,647			53,739
Income Before Income Taxes	105,267			97,460			216,026			180,943
Income Tax Expense	34,965			7,864			66,695			30,818
Net Income	$	70,302		$	89,596		$	149,331		$	150,125

The accompanying notes are an integral part of these statements.

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Idaho Power Company

Condensed Consolidated Statements of Comprehensive Income

(unaudited)



	Three months ended September 30,				Nine months ended September 30,
	2013		2012		2013		2012
	(thousands of dollars)

Net Income	$	70,302	$	89,596	$	149,331	$	150,125
Other Comprehensive Income:
Net unrealized holding gains arising during the period, net of tax of $541, $438, $1,466 and $968	843		682		2,283		1,507
Unfunded pension liability adjustment, net of tax of $298, $170, $894 and $511	464		265		1,394		796
Total Comprehensive Income	$	71,609	$	90,543	$	153,008	$	152,428

The accompanying notes are an integral part of these statements.

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Idaho Power Company

Condensed Consolidated Balance Sheets

(unaudited)



	September 30, 2013			December 31, 2012
	(thousands of dollars)
Assets

Electric Plant:
In service (at original cost)	$	5,035,762		$	4,915,772
Accumulated provision for depreciation	(1,759,785		)	(1,703,159		)
In service - net	3,275,977			3,212,613
Construction work in progress	321,128			298,470
Held for future use	7,093			7,101
Electric plant - net	3,604,198			3,518,184
Investments and Other Property	123,075			128,145
Current Assets:
Cash and cash equivalents	178,772			17,251
Receivables:
Customer (net of allowance of $2,201 and $1,551, respectively)	111,214			66,111
Other (net of allowance of $165 and $322, respectively)	12,263			20,618
Income taxes receivable	—			2,559
Accrued unbilled revenues	52,445			51,448
Materials and supplies (at average cost)	52,857			51,037
Fuel stock (at average cost)	35,412			42,388
Prepayments	13,910			12,688
Deferred income taxes	30,699			48,774
Current regulatory assets	63,445			30,078
Other	3,116			4,950
Total current assets	554,133			347,902
Deferred Debits:
American Falls and Milner water rights	16,064			17,909
Company-owned life insurance	22,055			22,646
Regulatory assets	1,139,353			1,132,960
Other	44,940			47,965
Total deferred debits	1,222,412			1,221,480
Total	$	5,503,818		$	5,215,711

The accompanying notes are an integral part of these statements.

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Idaho Power Company

Condensed Consolidated Balance Sheets

(unaudited)



	September 30, 2013			December 31, 2012
	(thousands of dollars)
Capitalization and Liabilities

Capitalization:
Common stock equity:
Common stock, $2.50 par value (50,000,000 shares authorized; 39,150,812 shares outstanding)	$	97,877		$	97,877
Premium on capital stock	712,258			712,258
Capital stock expense	(2,097		)	(2,097		)
Retained earnings	926,749			834,732
Accumulated other comprehensive loss	(13,439		)	(17,116		)
Total common stock equity	1,721,348			1,625,654
Long-term debt	1,615,197			1,466,632
Total capitalization	3,336,545			3,092,286
Current Liabilities:
Long-term debt due within one year	71,064			71,064
Accounts payable	87,916			89,651
Accounts payable to affiliates	1,261			252
Income taxes accrued	9,768			—
Interest accrued	26,409			22,311
Accrued compensation	35,713			42,282
Current regulatory liabilities	8,474			30,277
Other	37,235			23,813
Total current liabilities	277,840			279,650
Deferred Credits:
Deferred income taxes	1,052,512			1,001,877
Regulatory liabilities	369,729			355,362
Pension and other postretirement benefits	416,272			423,409
Other	50,920			63,127
Total deferred credits	1,889,433			1,843,775

Commitments and Contingencies

Total	$	5,503,818		$	5,215,711

The accompanying notes are an integral part of these statements.

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Idaho Power Company

Condensed Consolidated Statements of Cash Flows

(unaudited)



	Nine months ended September 30,
	2013			2012
	(thousands of dollars)
Operating Activities:
Net income	$	149,331		$	150,125
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	99,035			95,451
Deferred income taxes and investment tax credits	44,772			44,410
Changes in regulatory assets and liabilities	(20,765		)	(24,618		)
Pension and postretirement benefit plan expense	21,988			28,689
Contributions to pension and postretirement benefit plans	(32,535		)	(47,466		)
Earnings of unconsolidated equity-method investments	(7,358		)	(6,933		)
Distributions from unconsolidated equity-method investments	12,543			11,750
Allowance for equity funds used during construction	(10,876		)	(18,989		)
Other non-cash adjustments to net income, net	457			(510		)
Change in:
Accounts receivable	(40,465		)	(16,018		)
Accounts payable	(4,372		)	(1,208		)
Taxes accrued/receivable	21,769			(5,170		)
Other current assets	4,744			(11,547		)
Other current liabilities	5,185			(6,502		)
Other assets	(1,253		)	(7,203		)
Other liabilities	(8,509		)	(7,836		)
Net cash provided by operating activities	233,691			176,425
Investing Activities:
Additions to utility plant	(165,550		)	(187,751		)
Proceeds from the sale of emission allowances and RECs	498			2,706
Other	3,371			(124		)
Net cash used in investing activities	(161,681		)	(185,169		)
Financing Activities:
Issuance of long-term debt	150,000			150,000
Retirement of long-term debt	(1,064		)	(101,064		)
Dividends on common stock	(57,313		)	(49,671		)
Capital contribution from parent	—			7,500
Other	(2,112		)	(3,733		)
Net cash provided by financing activities	89,511			3,032
Net increase (decrease) in cash and cash equivalents	161,521			(5,712		)
Cash and cash equivalents at beginning of the period	17,251			19,316
Cash and cash equivalents at end of the period	$	178,772		$	13,604
Supplemental Disclosure of Cash Flow Information:
Cash paid during the period for:
Income taxes	$	8,760		$	1,224
Interest (net of amount capitalized)	$	54,619		$	49,833
Non-cash investing activities:
Additions to property, plant and equipment in accounts payable	$	22,480		$	22,595

The accompanying notes are an integral part of these statements.

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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, these Notes to 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. Idaho Power is an electric utility with a service territory covering approximately 24,000 square miles in southern Idaho and eastern Oregon. Idaho Power's utility operations are regulated primarily by the Federal Energy Regulatory Commission (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 mines and supplies coal to the Jim Bridger generating plant owned in part by Idaho Power.

IDACORP’s other wholly-owned 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 Services Co. (IESCo), which is the former limited partner of, and current successor by merger to, IDACORP Energy L.P., a marketer of energy commodities that wound down operations in 2003.

Regulation of Utility Operations

IDACORP's and Idaho Power's financial statements reflect the effects of the different ratemaking principles followed by the jurisdictions regulating Idaho Power. The application of accounting principles related to regulated operations sometimes results in Idaho Power recording expenses and revenues in a different period than when an unregulated enterprise would otherwise record expenses and revenues. In these instances, the amounts are deferred as regulatory assets or regulatory liabilities on the balance sheet and recorded on the income statement when recovered or returned in rates. Additionally, regulators can impose regulatory liabilities upon a regulated company for amounts previously collected from customers and for amounts that are expected to be refunded to customers. The effects of applying these regulatory accounting principles to Idaho Power's operations are discussed in more detail in Note 3.

Financial Statements

In the opinion of management of IDACORP and Idaho Power, the accompanying unaudited condensed consolidated financial statements contain all adjustments necessary to present fairly each company's consolidated financial position as of September 30, 2013, consolidated results of operations for the three and nine months ended September 30, 2013 and 2012, and consolidated cash flows for the nine months ended September 30, 2013 and 2012. 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, 2012. The results of operations for the interim period are not necessarily indicative of the results to be expected for the full year. A change in management's estimates or assumptions could have a material impact on IDACORP's or Idaho Power's respective financial condition and results of operations during the period in which such change occurred.

Management Estimates

Management makes estimates and assumptions when preparing financial statements in conformity with generally accepted accounting principles. These estimates and assumptions include those related to rate regulation, retirement benefits, contingencies, litigation, asset impairment, income taxes, unbilled revenues, and bad debt. These estimates and assumptions affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. These estimates involve judgments with respect to, among other things, future economic factors that are difficult to predict and are beyond management's control. Actual results could differ from those estimates.

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Reclassifications

Certain prior year amounts on the IDACORP condensed consolidated statements of income have been reclassified to conform to the current year presentation. In the current year, the allowance for equity funds used during construction has been classified to a separate line item. Previously, such amounts had been classified within the line item captioned "Other Income, Net." In addition, the components of the line item "Other interest, net of AFUDC" have been expanded to present a separate line item for the portion attributable to the allowance for borrowed funds used during construction. Previously reported net income, cash flows, and shareholders' equity were not affected by these reclassifications. Also, prior year amounts related to prepayments and related to proceeds from sales of emission allowances and renewable energy certificates on the IDACORP and Idaho Power condensed consolidated statements of cash flows have been reclassified to conform to the current year presentation.

IDACORP management identified certain operating expenses, primarily consisting of Senior Management Security Plan expense, totaling $2.1 million and $6.9 million in the three and nine months ended September 30, 2012, respectively, which had been erroneously reported as a reduction to "Other Income, net" in the previously issued IDACORP condensed consolidated statements of income rather than as a reduction to "Other" operating expenses. Accordingly, such classification has been corrected in the accompanying condensed consolidated statements of income for the three and nine months ended September 30, 2012, by including these costs within "Other" operating expenses. Such items had no effect on the previously issued condensed consolidated financial statements of Idaho Power and the previously issued condensed consolidated balance sheet, statements of cash flows, comprehensive income, or equity of IDACORP.

2. INCOME TAXES

In accordance with interim reporting requirements, IDACORP and Idaho Power use an estimated annual effective tax rate for computing their 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 interim period in which they occur. The estimated annual effective tax rate is applied to year-to-date pre-tax income to determine 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.

Income Tax Expense

The following table provides a summary of income tax expense for the three and nine months ended September 30 (in thousands of dollars):



	IDACORP						Idaho Power
	2013			2012			2013			2012
Three months ended September 30,
Income tax at statutory rates (federal and state)	$	40,210		$	37,528		$	41,159		$	38,107
Accounting method change	4,583			(7,845		)	4,583			(7,845		)
Other ⁽¹⁾	(13,705		)	(25,773		)	(10,777		)	(22,398		)
Income tax expense	$	31,088		$	3,910		$	34,965		$	7,864
Nine months ended September 30,
Income tax at statutory rates (federal and state)	$	81,690		$	68,468		$	84,466		$	70,749
Accounting method change	4,583			(7,845		)	4,583			(7,845		)
Other ⁽¹⁾	(28,144		)	(37,811		)	(22,354		)	(32,086		)
Income tax expense	$	58,129		$	22,812		$	66,695		$	30,818
Effective tax rate	27.8		%	13.0		%	30.9		%	17.0		%

⁽¹⁾ "Other" is primarily comprised of Idaho Power's regulatory flow-through tax adjustments, which are listed in the rate reconciliation table of Note 2 to the consolidated financial statements included in IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2012.

The changes in year-to-date 2013 income tax expense as compared to the same period in 2012 were primarily due to greater Idaho Power pre-tax earnings in 2013, as well as the impact of recording income tax expense for an Idaho Power income tax

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accounting method change in 2013 as compared to the tax benefit for a method change in 2012 (discussed below). Net regulatory flow-through tax adjustments at Idaho Power were lower for the three and nine months ended September 30, 2013 as compared to the same periods in 2012, primarily due to greater capitalized repairs deductions in 2012.

Accounting Method Changes:

On September 13, 2013, the U.S. Treasury Department and U.S. Internal Revenue Service (IRS) issued final regulations addressing the deduction or capitalization of expenditures related to tangible property. The regulations are generally effective for taxable years beginning on or after January 1, 2014.

In connection with the issuance of the regulations, Idaho Power assessed and estimated the impact of a method change associated with the electric generation property portion of the capitalized repairs method it adopted in fiscal year 2010. The change will be made pursuant to Revenue Procedure 2013-24 to bring Idaho Power’s existing method into alignment with the Revenue Procedure’s safe harbor unit-of-property definitions for electric generation property. Given Idaho Power’s intent to make this method change for generation property, in the third quarter of 2013 it recorded $4.6 million of income tax expense related to the estimated taxable income for the cumulative method change adjustment for years prior to 2013. Following the automatic consent procedures provided for in the Revenue Procedure, Idaho Power will be permitted to adopt this method in either its 2013 or 2014 tax years with the filing of IDACORP’s consolidated federal income tax return. The method change will be subject to IRS review as part of IDACORP’s Compliance Assurance Process (CAP) examination.

In the third quarter of 2012, Idaho Power completed an income tax accounting method change for its 2011 tax year associated with the electric transmission and distribution property portion (as opposed to the generation property portion described above) of the capitalized repairs method it adopted in fiscal year 2010. As a result of the change, in 2012 Idaho Power recorded a $7.8 million tax benefit related to the filed deduction for the cumulative method change adjustment for years prior to 2011. The change was made pursuant to Revenue Procedure 2011-43 to bring Idaho Power’s existing method into alignment with the Revenue Procedure’s safe harbor unit-of-property definitions for electric transmission and distribution property. Following the automatic consent procedures provided for in the Revenue Procedure, Idaho Power adopted this method with the filing of IDACORP’s 2011 consolidated federal income tax return. The IRS approved the method change prior to the filing of the return as part of IDACORP’s 2011 CAP examination. The final tangible property regulations discussed above are not expected to materially impact this tax accounting method.

Idaho Power’s prescribed regulatory accounting treatment requires immediate income recognition for temporary tax differences of this type. A net regulatory asset is established to reflect Idaho Power’s ability to recover the net increased income tax expense when such temporary differences reverse. Idaho Power’s 2013 capitalized repairs deduction estimate incorporates the provisions of both method changes.

3. REGULATORY MATTERS

Recent and Pending Regulatory Matters

Included below is a summary of recently concluded or pending regulatory matters and proceedings, including notable proceedings that had an impact on the comparability of rates and revenues during the first nine months of 2013 compared to the first nine months of 2012, and that may continue to have an impact on future results.

Idaho and Oregon General Rate Cases and Base Rate Adjustments

On June 1, 2011, Idaho Power filed a general rate case with the Idaho Public Utilities Commission (IPUC). On December 30, 2011, the IPUC issued an order approving a settlement stipulation in the general rate case that provided for a 7.86 percent authorized rate of return on an Idaho-jurisdiction rate base of approximately $2.36 billion. The approved settlement stipulation resulted in a $34.0 million overall increase in Idaho Power's annual Idaho-jurisdictional base rate revenues, with new rates effective January 1, 2012. Neither the order nor the settlement stipulation specified an authorized rate of return on equity.

On July 29, 2011, Idaho Power filed a general rate case and proposed rate schedules with the Oregon Public Utility Commission (OPUC). Idaho Power, the OPUC Staff, and other interested parties executed and filed a partial settlement stipulation on February 1, 2012, resolving most matters in the general rate case. The settlement stipulation provided for a $1.8 million base rate increase, a return on equity of 9.9 percent, and an overall rate of return of 7.757 percent in the Oregon jurisdiction. On February 23, 2012, the OPUC issued an order adopting the settlement stipulation, with new rates effective March 1, 2012.

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On June 29, 2012, the IPUC issued an order approving a $58.1 million increase in annual Idaho-jurisdiction base rates, effective July 1, 2012, for inclusion of the investment and associated costs of the Langley Gulch natural gas-fired power plant in rates. The order also provided for a $335.9 million increase in Idaho rate base. On September 20, 2012, the OPUC issued an order approving an approximately $3.0 million increase in annual Oregon jurisdiction base rates, effective October 1, 2012, for inclusion of the investment and associated costs of the plant in Oregon rates.

Settlement Stipulation — Investment Tax Credits and Idaho Sharing Mechanism

On December 27, 2011, the IPUC issued an order, separate from the then-pending Idaho general rate case proceeding, approving a settlement stipulation that provides as follows:

•

if Idaho Power's actual Idaho-jurisdiction return on year-end equity (Idaho ROE) for 2012, 2013, or 2014 is less than 9.5 percent, then Idaho Power may amortize additional accumulated deferred investment tax credits (ADITC) to help achieve a minimum 9.5 percent Idaho ROE in the applicable year. Idaho Power would be permitted to amortize additional ADITC in an aggregate amount up to $45 million over the three-year period;

•

if Idaho Power's actual Idaho ROE for 2012, 2013, or 2014 exceeds 10.0 percent, the amount of Idaho Power's Idaho-jurisdiction earnings exceeding a 10.0 percent and up to and including a 10.5 percent Idaho ROE for the applicable year would be shared equally between Idaho Power and its Idaho customers in the form of a rate reduction to become effective at the time of the subsequent year's power cost adjustment (PCA); and


•	if Idaho Power's actual Idaho ROE for 2012, 2013, or 2014 exceeds 10.5 percent, the amount of Idaho Power's Idaho-jurisdiction earnings exceeding a 10.5 percent Idaho ROE for the applicable year would be allocated 75 percent to Idaho Power's Idaho customers as a reduction to the pension regulatory asset and 25 percent to Idaho Power.

The settlement stipulation provides that the Idaho ROE thresholds (9.5 percent, 10.0 percent, and 10.5 percent) will be automatically adjusted prospectively in the event the IPUC approves a change to Idaho Power's authorized return on equity as part of a general rate case proceeding seeking a rate change effective prior to January 1, 2015. The automatic adjustments would be as follows: (a) the 9.5 percent Idaho ROE trigger in the settlement stipulation would be replaced by the percentage equal to 95 percent of the new authorized rate of return on equity; (b) the 10.0 percent Idaho ROE trigger in the settlement stipulation would be re-established at the new authorized rate of return on equity; and (c) the 10.5 percent Idaho ROE trigger in the settlement stipulation would be replaced by the percentage equal to 105 percent of the new authorized rate of return on equity.

Revenue Sharing Under January 2010 and December 2011 Idaho Settlement Agreements

On March 2, 2012, Idaho Power filed an application with the IPUC requesting authority to share revenues with customers based on year-end 2011 financial results, in accordance with the terms of regulatory settlement agreements authorized in January 2010 and December 2011. Idaho Power's revenue-sharing arrangements had two components: (1) a PCA mechanism component, which reduced net rates by $27.1 million effective June 1, 2012 through May 31, 2013, and (2) a pension balancing account component, which resulted in a $20.3 million net reduction to Idaho Power's pension regulatory asset (reducing Idaho customers' future obligation). Idaho Power recorded the $27.1 million revenue reduction as a regulatory liability, and the $20.3 million pension regulatory asset reduction, in 2011. On May 31, 2012, the IPUC approved Idaho Power's March 2, 2012 application requesting a corresponding adjustment to Idaho-jurisdiction rates, effective for the period from June 1, 2012 to May 31, 2013.

Idaho Power's 2012 Idaho ROE exceeded 10.5 percent, triggering the sharing mechanism of the December 2011 settlement stipulation for 2012. For 2012, Idaho Power recorded a $7.2 million provision against revenues, to be refunded to Idaho customers through the Idaho PCA mechanism during the 2013-2014 PCA collection period, and an additional $14.6 million of pension expense, to benefit Idaho customers by reducing the amount of deferred pension expense that will be collected from customers in the future.

As of September 30, 2013, Idaho Power had recorded a $6.2 million provision for sharing of 2013 revenues with customers pursuant to the terms of the December 2011 settlement stipulation, based on its estimate of full-year 2013 Idaho ROE in excess of 10.0 percent.

Idaho PCA Mechanism Filings

Idaho Power has PCA mechanisms in its Idaho and Oregon jurisdictions that address the volatility of power supply costs and provide for annual adjustments to the rates charged to retail customers. The PCA tracks Idaho Power’s actual net power supply costs (primarily fuel and purchased power less off-system sales) and compares these amounts to net power supply costs

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currently being recovered in retail rates. In the Idaho jurisdiction, the annual PCA adjustments are based on (a) a forecast component, which is based on a forecast of net power supply costs in the coming year as compared to net power supply costs in base rates, and (b) a true-up component, based on the difference between the previous year’s actual net power supply costs and the previous year’s forecast. The latter component also includes a balancing mechanism so that, over time, the actual collection or refund of authorized true-up dollars matches the amounts authorized.

On May 31, 2013, the IPUC issued an order authorizing Idaho Power's April 15, 2013 application seeking a $140.4 million increase in PCA rates (net of 2012 revenue sharing), effective for the 2013-2014 PCA collection period from June 1, 2013 to May 31, 2014. Previously, in May 2012, the IPUC issued an order approving Idaho Power's April 2012 application requesting a $43.0 million increase to Idaho PCA rates, effective for the period from June 1, 2012 to May 31, 2013. That PCA rate increase was offset by $27.1 million to be shared with customers pursuant to the revenue sharing orders described above, resulting in a net PCA rate increase of $15.9 million.

On November 1, 2013, Idaho Power filed an application with the IPUC requesting approval of new normalized or "base level" power supply expense, which if approved would reflect in base rates approximately $106 million of such expenses, effective June 1, 2014. This would remove the Idaho-jurisdictional portion of those expenses from collection via the Idaho PCA mechanism and instead result in Idaho Power collecting that portion in base rates.

Annual Idaho Fixed Cost Adjustment Filing

The fixed cost adjustment (FCA) is 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. The FCA is adjusted each year to collect, or refund, the difference between the authorized fixed-cost recovery amount and the actual fixed costs recovered by Idaho Power during the previous year. On May 22, 2013, the IPUC approved Idaho Power's March 15, 2013 application requesting a decrease in FCA rates from $10.3 million to $8.9 million, effective for the period from June 1, 2013 to May 31, 2014.

Annual Idaho Demand-Side Management Prudence and Cost Recovery Filings

On April 3, 2013, Idaho Power filed an application with the IPUC requesting an order finding Idaho Power's 2012 expenditures of $25.9 million in energy efficiency rider funds, $6.0 million in custom efficiency program incentives in a regulatory asset account, and $14.5 million of demand response program incentives included in the 2013 PCA, as prudently incurred demand-side management program expenses. A determination and order from the IPUC remains pending.

Separately, on April 15, 2013, Idaho Power filed an application with the IPUC for an accounting order authorizing transfer of the regulatory asset account associated with custom efficiency program expenditures for collection through the Idaho energy efficiency rider mechanism, effective June 1, 2013, for expenditures incurred during 2011 and thereafter. On June 12, 2013, the IPUC issued an order authorizing Idaho Power to recover custom efficiency program incentive payments, including the then-current regulatory account balance of $14.3 million, as well as subsequent custom efficiency program incentive payments, through the Idaho energy efficiency rider mechanism. As a result of the order, Idaho Power recognized the balance as other revenue and energy efficiency program expenses.

Filing for Certificate of Public Convenience and Necessity for Jim Bridger Plant Upgrades

On June 28, 2013, Idaho Power filed an application with the IPUC requesting that the IPUC issue a Certificate of Public Convenience and Necessity (CPCN) related to selective catalytic reduction (SCR) investments planned for Jim Bridger coal-fired plant units 3 and 4. Idaho Power's CPCN application requests that the IPUC provide Idaho Power with authorization and a binding commitment to provide rate base treatment for Idaho Power's share of the SCR investment in the amount of approximately $130 million (including AFUDC). Filing of the CPCN is intended to allow the IPUC to review the prudence of the investment in SCR prior to Idaho Power's incurring the bulk of the associated costs. A determination and order from the IPUC is pending.

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4. LONG-TERM DEBT

On April 8, 2013, Idaho Power issued $75 million in principal amount of 2.50% first mortgage bonds, Series I, maturing on April 1, 2023, and $75 million in principal amount of 4.00% first mortgage bonds, Series I, maturing on April 1, 2043. On October 1, 2013, Idaho Power used a portion of the net proceeds of the April 2013 sale of first mortgage bonds to satisfy its obligations upon maturity of $70 million in principal amount of 4.25% first mortgage bonds. Issuance of the Series I notes in April 2013, combined with the issuance of $200 million in principal amount of Series I notes in August 2010 and $150 million in principal amount of Series I notes in April 2012, utilized in full the available amount under a registration statement Idaho Power filed with the U.S. Securities and Exchange Commission (SEC) in May 2010 and under a selling agency agreement executed with ten banks in June 2010.

In February 2013 Idaho Power filed applications with the IPUC, OPUC, and Wyoming Public Service Commission (WPSC) seeking authorization to issue and sell from time to time up to $500 million in aggregate principal amount of debt securities and first mortgage bonds. In April 2013, Idaho Power received orders from the IPUC, OPUC, and WPSC authorizing such issuance and sales, subject to conditions specified in the orders. The order from the IPUC approved the issuance of the securities through April 9, 2015, subject to extension upon request to the IPUC. The OPUC’s and WPSC’s orders do not impose a time limitation for issuances, but the OPUC order does impose a number of other conditions, including a maximum interest rate limit of 7 percent.

In anticipation of the issuances of the notes described above and the expiration of the prior registration statement, on May 22, 2013, IDACORP and Idaho Power filed a joint shelf registration statement with the SEC, which became effective upon filing, for the offer and sale of, in the case of IDACORP, an unspecified amount of shares of common stock and unspecified principal amount of debt securities, and in the case of Idaho Power, an unspecified principal amount of its first mortgage bonds and debt securities. On July 12, 2013, Idaho Power entered into a Selling Agency Agreement with eight banks named in the agreement in connection with the potential issuance and sale from time to time of up to $500 million aggregate principal amount of first mortgage bonds, secured medium term notes, Series J (Series J Notes), under Idaho Power’s Indenture of Mortgage and Deed of Trust, dated as of October 1, 1937, as amended and supplemented (Indenture). Also on July 12, 2013, Idaho Power entered into the Forty-seventh Supplemental Indenture, dated as of July 1, 2013, to the Indenture. The Forty-seventh Supplemental Indenture provides for, among other items, the issuance of up to $500 million in aggregate principal amount of Series J Notes pursuant to the Indenture. As of September 30, 2013, Idaho Power had not sold any first mortgage bonds, including Series J Notes, or debt securities under the Selling Agency Agreement.

5. NOTES PAYABLE

Credit Facilities

IDACORP and Idaho Power have in place credit facilities that may be used for general corporate purposes and commercial paper backup. IDACORP's credit facility consists of a revolving line of credit not to exceed the aggregate principal amount at any one time outstanding of $125 million, including swingline loans in an aggregate principal amount at any time outstanding not to exceed $15 million, and letters of credit in an aggregate principal amount at any time outstanding not to exceed $50 million. Idaho Power's credit facility consists of a revolving line of credit, through the issuance of loans and standby letters of credit, not to exceed the aggregate principal amount at any one time outstanding of $300 million, including swingline loans in an aggregate principal amount at any time outstanding not to exceed $30 million. IDACORP and Idaho Power have the right to request an increase in the aggregate principal amount of the facilities to $150 million and $450 million, respectively, in each case subject to certain conditions.

The IDACORP and Idaho Power credit facilities have similar terms and conditions. The interest rates for any borrowings under the facilities are based on either (1) a floating rate that is equal to the highest of the prime rate, federal funds rate plus 0.5 percent, or LIBOR rate plus 1.0 percent, or (2) the LIBOR rate, plus, in each case, an applicable margin. The margin is based on IDACORP's or Idaho Power's, as applicable, senior unsecured long-term indebtedness credit rating by Moody's Investors Service, Inc., Standard and Poor's Ratings Services, and Fitch Rating Services, Inc., as set forth on a schedule to the credit agreements. Under their respective credit facilities, the companies pay a facility fee on the commitment based on the respective company's credit rating for senior unsecured long-term debt securities. While the credit facilities provide for an original termination date of October 26, 2016, the credit agreements grant IDACORP and Idaho Power the right to request up to two one-year extensions, in each case subject to certain conditions. In October 2012, IDACORP and Idaho Power executed First Extension Agreements with each of the lenders, extending the termination dates under both credit facilities to October 26, 2017. In October 2013, IDACORP and Idaho Power executed Second Extension Agreements with each of the lenders, extending the termination dates under both credit facilities to October 26, 2018. No other terms of the credit facilities, including the amount of permitted borrowings under the credit agreements, were affected by the extensions.

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At September 30, 2013, no loans were outstanding under either IDACORP's or Idaho Power's facilities. At September 30, 2013, Idaho Power had regulatory authority to incur up to $450 million in principal amount of short-term indebtedness at any one time outstanding. Balances (in thousands of dollars) and interest rates of IDACORP’s and Idaho Power's short-term borrowings were as follows at September 30, 2013 and December 31, 2012:



	September 30, 2013									December 31, 2012
	Idaho Power			IDACORP			Total			Idaho Power			IDACORP			Total
Commercial paper outstanding	$	—		$	53,000		$	53,000		$	—		$	69,700		$	69,700
Weighted-average annual interest rate	—		%	0.35		%	0.35		%	—		%	0.50		%	0.50		%

6. COMMON STOCK

IDACORP Common Stock

During the nine months ended September 30, 2013, IDACORP issued 74,977 shares of common stock pursuant to the IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan. Effective July 1, 2012, IDACORP instructed the plan administrators of the IDACORP, Inc. Dividend Reinvestment and Stock Purchase Plan and Idaho Power Company Employee Savings Plan to use market purchases of IDACORP common stock, as opposed to original issuance of common stock from IDACORP, to acquire shares of IDACORP common stock for the plans. However, IDACORP may determine at any time to resume original issuances of common stock under those plans.

IDACORP enters into sales agency agreements as a means of selling its common stock from time to time pursuant to a continuous equity program. On July 12, 2013, IDACORP entered into its current Sales Agency Agreement with BNY Mellon Capital Markets, LLC (BNYMCM). IDACORP may offer and sell up to 3 million shares of its common stock from time to time in at-the-market offerings through BNYMCM as IDACORP's agent. IDACORP has no obligation to issue any minimum number of shares under the Sales Agency Agreement. As of the date of this report, no shares of IDACORP common stock have been issued under the Sales Agency Agreement. Accordingly, 3 million shares remain available to be sold under the Sales Agency Agreement.

Restrictions on Dividends

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. 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. At September 30, 2013, the leverage ratios for IDACORP and Idaho Power were 48 percent and 50 percent, respectively. Based on these restrictions, IDACORP’s and Idaho Power’s dividends were limited to $920 million and $810 million, respectively, at September 30, 2013. There are additional facility covenants, subject to exceptions, that prohibit or restrict the sale or disposition of property without consent and any agreements restricting dividend payments to the company from any material subsidiary. At September 30, 2013, IDACORP and Idaho Power were in compliance with those covenants.

Idaho Power’s Revised Policy and Code of Conduct relating to transactions between and among Idaho Power, IDACORP, and other affiliates, which was approved by the IPUC in April 2008, provides 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. At September 30, 2013, Idaho Power's common equity capital was 51 percent of its total adjusted capital. Further, 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.

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

In addition to contractual restrictions on the amount and payment of dividends, the Federal Power Act prohibits the payment of dividends from "capital accounts." The term "capital account" is undefined in the Federal Power Act or its regulations, but Idaho Power does not believe the restriction would limit Idaho Power's ability to pay dividends out of current year earnings or retained earnings.

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7. EARNINGS PER SHARE

The table below presents the computation of IDACORP’s basic and diluted earnings per share for the three and nine months ended September 30, 2013 and 2012 (in thousands, except for per share amounts).



	Three months ended September 30,				Nine months ended September 30,
	2013		2012		2013		2012
Numerator:
Net income attributable to IDACORP, Inc.	$	71,750	$	92,069	$	150,796	$	152,299
Denominator:
Weighted-average common shares outstanding - basic	50,056		49,966		50,051		49,918
Effect of dilutive securities:
Options	2		4		2		5
Restricted stock	95		110		56		67
Weighted-average common shares outstanding - diluted	50,153		50,080		50,109		49,990
Basic earnings per share	$	1.43	$	1.84	$	3.01	$	3.05
Diluted earnings per share	$	1.43	$	1.84	$	3.01	$	3.05

8. COMMITMENTS

Purchase Obligations

IDACORP's and Idaho Power's purchase obligations did not change materially, outside of the ordinary course of business, during the nine months ended September 30, 2013, other than the termination of four power purchase agreements due to either uncured breach by the respective counterparties or pursuant to IPUC-approved settlement arrangements between the parties. Termination of the agreements reduced Idaho Power's contractual payment obligations by approximately $322 million over the 15-year to 20-year lives of the contracts.

Guarantees

Idaho Power has agreed to guarantee a portion of the performance of reclamation activities and obligations at BCC, of which IERCo owns a one-third interest. This guarantee, which is renewed annually, was $74 million at September 30, 2013, representing IERCo's one-third share of BCC's total reclamation obligation. BCC has a reclamation trust fund set aside specifically for the purpose of paying these reclamation costs. At September 30, 2013, the value of the reclamation trust fund was $64 million. During the nine months ended September 30, 2013, the reclamation trust fund distributed approximately $24 million for reclamation activity costs associated with the BCC surface mine. BCC periodically 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, all of which are made to the Jim Bridger plant. Starting 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.

IDACORP and Idaho Power enter into financial agreements and power purchase and sale agreements that include indemnification provisions relating to various forms of claims or liabilities that may arise from the transactions contemplated by these agreements. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnification provisions cannot be reasonably estimated. IDACORP and Idaho Power periodically evaluate the likelihood of incurring costs under such indemnities based on their historical experience and the evaluation of the specific indemnities. As of September 30, 2013, management believes the likelihood is remote that IDACORP or Idaho Power would be required to perform under such indemnification provisions or otherwise incur any significant losses with respect to such indemnification obligations. Neither IDACORP nor Idaho Power has recorded any liability on their respective condensed consolidated balance sheets with respect to these indemnification obligations.

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9. CONTINGENCIES

IDACORP and Idaho Power have in the past and expect in the future to become involved in various claims, controversies, disputes, and other contingent matters, including the items described in this Note 9. Some of these claims, controversies, disputes, and other contingent matters involve litigation and regulatory or other contested proceedings. The ultimate resolution and outcome of litigation and regulatory proceedings is inherently difficult to determine, particularly where (a) the remedies or penalties sought are indeterminate, (b) the proceedings are in the early stages or the substantive issues have not been well developed, or (c) the matters involve complex or novel legal theories or a large number of parties. In accordance with applicable accounting guidance, IDACORP and Idaho Power, as applicable, establish an accrual for legal proceedings when those matters proceed to a stage where they present loss contingencies that are both probable and reasonably estimable. In such cases, there may be a possible exposure to loss in excess of any amounts accrued. IDACORP and Idaho Power monitor those matters for developments that could affect the likelihood of a loss and the accrued amount, if any, and adjust the amount as appropriate. If the loss contingency at issue is not both probable and reasonably estimable, IDACORP and Idaho Power do not establish an accrual and the matter will continue to be monitored for any developments that would make the loss contingency both probable and reasonably estimable. As of the date of this report, IDACORP's and Idaho Power's accruals for loss contingencies are not material to their financial statements as a whole; however, future accruals could be material in a given period. IDACORP's and Idaho Power's determination is based on currently available information, and estimates presented in financial statements and other financial disclosures involve significant judgment and may be subject to significant uncertainty. As available information changes, the matters for which IDACORP and Idaho Power are able to estimate the loss may change, and the estimates themselves may change. For matters that affect Idaho Power’s operations, Idaho Power intends to seek, to the extent permissible and appropriate, recovery through the ratemaking process of costs incurred.

Western Energy Proceedings

High prices for electricity, energy shortages, and blackouts 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 the FERC to initiate its own investigations. Some of these proceedings remain pending before the FERC or are on appeal to the United States Court of Appeals for the Ninth Circuit. Idaho Power and IESCo (as successor to IDACORP Energy L.P.) believe that settlement releases they have obtained will restrict potential claims that might result from the disposition of pending proceedings and predict that these matters will not have a material adverse effect on IDACORP's or Idaho Power's results of operations or financial condition. However, the settlements and associated FERC orders have not fully eliminated the potential for so-called "ripple claims," which involve potential claims for refunds from an upstream seller of power based on a finding that its downstream buyer was liable for refunds as a seller of power during the relevant period. The FERC has characterized these ripple claims as "speculative." However, the FERC has refused to dismiss Idaho Power and IESCo from the proceedings in the Pacific Northwest and refused to approve a portion of a settlement that provided for waivers of all claims in those proceedings, despite only limited objections from two market participants. Idaho Power and IESCo petitioned the D.C. Circuit for review of the FERC's decision refusing to approve the waiver provision of the settlement, on the basis that the FERC failed to apply its established precedents and rules. The petition for review was transferred to the Ninth Circuit Court of Appeals in June 2013 and remains pending before that court.

Based on its evaluation of the merits of ripple claims and the inability to estimate the potential exposure should the claims ultimately have any merit, particularly in light of Idaho Power and IESCo being both purchasers and sellers in the energy market during the relevant period, Idaho Power and IESCo have no amount accrued relating to the proceedings. To the extent the availability of any ripple claims materializes, Idaho Power and IESCo will continue to vigorously defend their positions in the proceedings.

Water Rights - Snake River Basin Adjudication

Idaho Power holds water rights, acquired under applicable state law, for its hydroelectric projects. In addition, Idaho Power holds water rights for domestic, irrigation, commercial, and other necessary purposes related to project lands and other holdings within the states of Idaho and Oregon. Idaho Power's water rights for power generation are, to varying degrees, subordinated to future upstream appropriations for irrigation and other authorized consumptive uses. Over time, increased irrigation development and other consumptive uses within the Snake River watershed led to a reduction in flows of the Snake River. In the late 1970s and early 1980s these reduced flows resulted in a conflict between the exercise of Idaho Power's water rights at certain hydroelectric projects on the Snake River and upstream consumptive diversions. The Swan Falls Agreement, signed by Idaho Power and the State of Idaho on October 25, 1984, resolved the conflict and provided a level of protection for Idaho Power's hydropower water rights at specified projects on the Snake River through the establishment of minimum stream flows and an administrative process governing future development of water rights that may affect those minimum stream flows. In 1987, Congress enacted legislation directing the FERC to issue an order approving the Swan Falls settlement together with a

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finding that the agreement was neither inconsistent with the terms and conditions of Idaho Power's project licenses nor the Federal Power Act. The FERC entered an order implementing the legislation in March 1988.

The Swan Falls Agreement provided that the resolution and recognition of Idaho Power's water rights together with the State Water Plan provided a sound comprehensive plan for management of the Snake River watershed. The Swan Falls Agreement also recognized, however, that in order to effectively manage the waters of the Snake River basin, a general adjudication to determine the nature, extent, and priority of the rights of all water uses in the basin was necessary. Consistent with that recognition, in 1987 the State of Idaho initiated the Snake River Basin Adjudication (SRBA), and pursuant to the commencement order issued by the SRBA court that same year, all claimants to water rights within the basin were required to file water rights claims in the SRBA. Idaho Power has filed claims to its water rights and has been actively participating in the SRBA since its commencement. Questions concerning the effect of the Swan Falls Agreement on Idaho Power's water rights claims, including the nature and extent of the subordination of Idaho Power's rights to upstream uses, resulted in the filing of litigation in the SRBA in 2007 between Idaho Power and the State of Idaho. This litigation was resolved by the Framework Reaffirming the Swan Falls Settlement (Framework) signed by Idaho Power and the State of Idaho on March 25, 2009. In that Framework, the parties acknowledged that the effective management of Idaho's water resources remains critical to the public interest of the State of Idaho by sustaining economic growth, maintaining reasonable electric rates, protecting and preserving existing water rights, and protecting water quality and environmental values. The Framework further provided that the State of Idaho and Idaho Power would cooperate in exploring approaches to resolve issues of mutual concern relating to the management of Idaho's water resources. Idaho Power continues to work with the State of Idaho and other interested parties on these issues.

One such issue involves the management of the Eastern Snake Plain Aquifer (ESPA), a large underground aquifer in southeastern Idaho that is hydrologically connected to the Snake River. House Concurrent Resolution No. 28, adopted by the Idaho Legislature in 2007, directed the Idaho Water Resource Board to pursue the development of a comprehensive management plan for the ESPA, to include measures that would enhance aquifer levels, springs, and river flows on the eastern Snake River plain to the benefit of both agricultural development and hydropower generation. In May of 2007, the Idaho Water Resource Board appointed an advisory committee, charged with the responsibility of developing a management plan for the ESPA. Idaho Power was a member of that committee. In January 2009, the Idaho Water Resource Board, based on the committee's recommendations, adopted a Comprehensive Aquifer Management Plan (CAMP) for the ESPA. The Idaho Legislature approved the CAMP that same year. Idaho Power is a member of the CAMP Implementation Committee and continues to work with the Idaho Water Resource Board, other stakeholders, and the Idaho Legislature in exploring opportunities for implementation of the CAMP management plan.

Idaho Power continues its participation in the SRBA in an effort to ensure that its water rights are protected and that the operation of its hydroelectric projects is not adversely impacted. While Idaho Power cannot predict the outcome, as of the date of this report Idaho Power does not anticipate any material modification of its water rights as a result of the SRBA process.

Other Proceedings

IDACORP and Idaho Power are parties to legal claims and legal and regulatory actions and proceedings in the ordinary course of business that are in addition to those discussed above and, as noted above, records an accrual for associated loss contingencies when they are probable and reasonably estimable. As of the date of this report the companies believe that resolution of those matters will not have a material adverse effect on their respective consolidated financial statements. Idaho Power is also actively monitoring various pending environmental regulations that may have a significant impact on its future operations. Given uncertainties regarding the outcome, timing, and compliance plans for these environmental matters, Idaho Power is unable to estimate the financial impact of these regulations but does believe that future capital investment for infrastructure and modifications to its electric generating facilities to comply with these regulations could be significant.

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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 nonqualified defined benefit plans for certain senior management employees called the Senior Management Security Plan I and II (SMSP). Idaho Power also maintains a defined benefit postretirement plan (consisting of health care and death benefits) that is available to 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 Employee Savings Plan.

The table below shows the components of net periodic benefit costs for the pension, SMSP, and postretirement benefits plans for the three months ended September 30, 2013 and 2012 (in thousands of dollars).



	Pension Plan						SMSP				Postretirement Benefits
	2013			2012			2013		2012		2013			2012
Service cost	$	7,839		$	6,392		$	544	$	537	$	328		$	323
Interest cost	7,958			7,872			816		805		659			784
Expected return on plan assets	(9,053		)	(7,934		)	—		—		(582		)	(559		)
Amortization of transition obligation	—			—			—		—		—			510
Amortization of prior service cost	86			87			53		53		(57		)	(105		)
Amortization of net loss	4,280			3,529			709		382		25			96
Net periodic benefit cost	11,110			9,946			2,122		1,777		373			1,049
Adjustments due to the effects of regulation ⁽¹⁾	(6,274		)	713			—		—		—			—
Net periodic benefit cost recognized for financial reporting⁽¹⁾	$	4,836		$	10,659		$	2,122	$	1,777	$	373		$	1,049

⁽¹⁾ Net periodic benefit costs for the pension plan are recognized for financial reporting based upon the authorization of each regulatory jurisdiction in which Idaho Power operates. Under IPUC order, income statement recognition of pension plan costs is deferred until costs are recovered through rates. See Note 3 for information on Idaho Power’s revenue sharing mechanism approved by the IPUC, which resulted in additional Idaho pension expense of $5.8 million for the three months ended September 30, 2012.

The table below shows the components of net periodic benefit costs for the pension, SMSP, and postretirement benefits plans for the nine months ended September 30, 2013 and 2012 (in thousands of dollars).



	Pension Plan						SMSP				Postretirement Benefits
	2013			2012			2013		2012		2013			2012
Service cost	$	23,517		$	19,178		$	1,634	$	1,613	$	986		$	969
Interest cost	23,873			23,617			2,444		2,414		1,975			2,351
Expected return on plan assets	(26,816		)	(23,801		)	—		—		(1,746		)	(1,676		)
Amortization of transition obligation	—			—			—		—		—			1,530
Amortization of prior service cost	260			260			159		160		(172		)	(316		)
Amortization of net loss	12,839			10,586			2,129		1,146		74			288
Net periodic benefit cost	33,673			29,840			6,366		5,333		1,117			3,146
Adjustments due to the effects of regulation ⁽¹⁾	(19,168		)	(9,630		)	—		—		—			—
Net periodic benefit cost recognized for financial reporting⁽¹⁾	$	14,505		$	20,210		$	6,366	$	5,333	$	1,117		$	3,146

Idaho Power's minimum required contributions to the pension plan are zero in 2013. However, during the nine months ended September 30, 2013, Idaho Power made $30 million of discretionary contributions to its defined benefit pension plan. Idaho Power may continue to elect to make further discretionary contributions above the minimum funding requirements or at times earlier than the required dates.

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11. INVESTMENTS IN EQUITY SECURITIES

Investments in 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. The table below summarizes investments in equity securities by IDACORP and Idaho Power as of September 30, 2013 and December 31, 2012 (in thousands of dollars).



	September 30, 2013						December 31, 2012
	Gross Unrealized Gain		Gross Unrealized Loss		Fair Value		Gross Unrealized Gain		Gross Unrealized Loss		Fair Value
Available-for-sale securities	$	10,541	$	—	$	33,179	$	6,792	$	—	$	31,913

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 September 30, 2013 and at December 31, 2012, no securities were in an unrealized loss position.

There were no sales of available-for-sale securities during the nine months ended September 30, 2013 or 2012.

12. DERIVATIVE FINANCIAL INSTRUMENTS

Commodity Price Risk

Idaho Power is exposed to market risk relating to electricity, natural gas, and other fuel commodity prices, all of which are heavily influenced by supply and demand. Market risk may be influenced by market participants’ nonperformance of their contractual obligations and commitments, which affects the supply of or demand for the commodity. Idaho Power uses derivative instruments, such as physical and financial forward contracts, for both electricity and fuel to manage the risks relating to these commodity price exposures. 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 commodity-related derivative instruments not meeting the normal purchases and normal sales exception to derivative accounting are recorded at fair value on the balance sheet. Because of Idaho Power's PCA mechanisms, unrealized gains and losses associated with the changes in fair value of these derivative instruments are recorded as regulatory assets or liabilities. Most of Idaho Power’s physical forward contracts for electricity qualify for the normal purchases and normal sales exception.

All of Idaho Power's derivative instruments have been entered into for the purpose of economically hedging forecasted purchases and sales, though none of these instruments have been designated as cash flow hedges under derivative accounting guidance. Idaho Power offsets fair value amounts recognized on its balance sheet and applies collateral related to derivative instruments executed with the same counterparty under the same master netting agreement. Idaho Power does not offset a counterparty's current derivative contracts with the counterparty's long-term derivative contracts, although Idaho Power's master netting arrangements would allow current and long-term positions to be offset in the event of default. Also, in the event of a default, Idaho Power's master netting arrangements would allow for the offsetting of all transactions executed under the master netting arrangement. These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, receivables and payables arising from settled positions, and other forms of non-cash collateral (such as letters of credit). These types of transactions are excluded from the offsetting presented in the derivative fair value and offsetting table below.

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Derivative Instrument Summary

The table below presents the fair values and locations of derivative instruments not designated as hedging instruments recorded on the balance sheets and reconciles the gross amounts of derivatives recognized as assets and as liabilities to the net amounts presented in the balance sheets at September 30, 2013 and December 31, 2012 (in thousands of dollars).



		Asset Derivatives								Liability Derivatives
	Balance Sheet Location	Gross Fair Value		Amounts Offset				Net Assets		Gross Fair Value		Amounts Offset			Net Liabilities
	Balance Sheet Location	Gross Fair Value		Amounts Offset				Net Assets		Gross Fair Value		Amounts Offset			Net Liabilities
September 30, 2013
Current:
Financial swaps	Other current assets	$	2,932	$	(954	)		$	1,978	$	954	$	(954	)	$	—
Financial swaps	Other current liabilities	408		(408		)		—		1,414		(408		)	1,006
Forward contracts	Other current assets	156		—				156		—		—			—
Forward contracts	Other current liabilities	—		—				—		11		—			11
Long-term:
Financial swaps	Other assets	174		—				174		—		—			—
Financial swaps	Other liabilities	—		—				—		40		—			40
Forward contracts	Other assets	126		—				126		—		—			—
Total		$	3,796	$	(1,362	)		$	2,434	$	2,419	$	(1,362	)	$	1,057
December 31, 2012
Current:
Financial swaps	Other current assets	$	5,122	$	(1,683	)	⁽¹⁾	$	3,439	$	978	$	(978	)	$	—
Financial swaps	Other current liabilities	320		(320		)		—		1,372		(319		)	1,053
Forward contracts	Other current assets	155		(4		)		151		4		(4		)	—
Forward contracts	Other current liabilities	—		—				—		2		—			2
Long-term:
Financial swaps	Other assets	96		—				96		—		—			—
Forward contracts	Other assets	189		—				189		—		—			—
Total		$	5,882	$	(2,007	)		$	3,875	$	2,356	$	(1,301	)	$	1,055

⁽¹⁾Current asset derivative amounts offset include $705 thousand of collateral payable for the period ending December 31, 2012.

The table below presents the gains and losses on derivatives not designated as hedging instruments for the three and nine months ended September 30, 2013 and 2012 (in thousands of dollars).



	Location of Realized Gain/(Loss) on Derivatives Recognized in Income	Gain/(Loss) on Derivatives Recognized in Income ⁽¹⁾
		Gain/(Loss) on Derivatives Recognized in Income ⁽¹⁾
		Three months ended September 30,						Nine months ended September 30,
		Three months ended September 30,						Nine months ended September 30,
		2013			2012			2013			2012
Financial swaps	Off-system sales	$	(98	)	$	1,793		$	224		$	11,703
Financial swaps	Purchased power	496			(2,479		)	510			(5,631		)
Financial swaps	Fuel expense	(705		)	(2,516		)	444			(6,233		)
Financial swaps	Other operations and maintenance	12			(145		)	27			(166		)
Forward contracts	Off-system sales	135			—			135			—
Forward contracts	Purchased power	(138		)	—			(138		)	—
Forward contracts	Fuel expense	52			(1,778		)	131			(1,778		)

⁽¹⁾ Excludes unrealized gains or losses on derivatives, which are recorded on the balance sheet as regulatory assets or regulatory liabilities.

Settlement gains and losses on derivative electricity 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 contracts for natural gas are reflected in fuel expense. Settlement gains and losses on diesel derivatives are

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recorded in other operations and maintenance expense. See Note 13 for additional information concerning the determination of fair value for Idaho Power’s assets and liabilities from price risk management activities.

The table below presents the volumes of derivative commodity forward contracts and swaps outstanding at September 30, 2013 and 2012 (in thousands of units).



		September 30,
Commodity	Units	2013	2012
Electricity purchases	MWh	382	340
Electricity sales	MWh	1,064	1,692
Natural gas purchases	MMBtu	11,929	16,691
Natural gas sales	MMBtu	1,153	2,911
Diesel purchases	Gallons	1,113	263

Credit Risk

At September 30, 2013, Idaho Power did not have material credit risk 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. Idaho Power’s physical power contracts are commonly under Western Systems Power Pool agreements, physical gas contracts are usually under North American Energy Standards Board contracts, and financial transactions are usually under International Swaps and Derivatives Association, Inc. contracts. These contracts contain adequate assurance clauses requiring collateralization if a counterparty has debt that is downgraded below investment grade by at least one rating agency.

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 Moody's Investors Service and Standard & Poor's Ratings Services. 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 were in a liability position at September 30, 2013, was $2.3 million. Idaho Power posted $0.5 million cash collateral related to this amount. If the credit-risk-related contingent features underlying these agreements were triggered on September 30, 2013, Idaho Power would have been required to post $6.3 million of additional cash collateral to its counterparties.

13. FAIR VALUE MEASUREMENTS

IDACORP and Idaho Power have categorized their financial instruments into a three-level fair value hierarchy, based on the priority of the inputs to the valuation technique. 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.

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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.

An item recorded at fair value is reclassified between levels when changes in the nature of valuation inputs cause the item to no longer meet the criteria for the level in which it was previously categorized.

Idaho Power’s derivatives are contracts entered into as part of its management of loads and resources. Electricity derivatives are valued on the Intercontinental Exchange (ICE) with quoted prices in an active market. Natural gas and diesel derivative valuations are performed using New York Mercantile Exchange (NYMEX) and ICE pricing, adjusted for location basis, which are also quoted under NYMEX and ICE pricing. Trading securities consist 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. Notes receivable are related to Ida-West and are valued based on unobservable inputs, including discounted cash flows, which are partially based on forecasted hydroelectric conditions. Long-term debt is not traded on an exchange and is valued using quoted rates for similar debt in active markets. There were no material changes in valuation techniques or inputs during the three and nine months ended September 30, 2013 or the year ended December 31, 2012.

The table below presents information about IDACORP’s and Idaho Power’s assets and liabilities measured at fair value on a recurring basis as of September 30, 2013 and December 31, 2012 (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. There were no material transfers between levels for the periods presented.



	September 30, 2013								December 31, 2012
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets:
Derivatives	$	2,152	$	282	$	—	$	2,434	$	2,201	$	1,674	$	—	$	3,875
Money market funds	9,986		—		—		9,986		100		—		—		100
Trading securities: Equity securities	1,132		—		—		1,132		2,478		—		—		2,478
Available-for-sale securities: Equity securities	33,179		—		—		33,179		31,913		—		—		31,913
Liabilities:
Derivatives	$	1,046	$	11	$	—	$	1,057	$	—	$	1,055	$	—	$	1,055

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The table below presents the carrying value and estimated fair value of financial instruments that are not reported at fair value, as of September 30, 2013 and December 31, 2012, 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 long-term debt are based upon quoted market prices of similar issues or the same issues in an inactive market. The estimated fair values for notes receivable are based upon discounted cash flow analysis.



	September 30, 2013				December 31, 2012
	Carrying		Estimated		Carrying		Estimated
	Amount		Fair Value		Amount		Fair Value
	(thousands of dollars)
IDACORP
Assets:
Notes receivable ⁽¹⁾	$	3,097	$	3,097	$	3,097	$	3,097
Liabilities:
Long-term debt ⁽¹⁾	1,686,261		1,735,245		1,537,696		1,819,213
Idaho Power
Liabilities:
Long-term debt ⁽¹⁾	$	1,686,261	$	1,735,245	$	1,537,696	$	1,819,213

⁽¹⁾ Notes receivable and long-term debt are categorized as Level 3 and Level 2, respectively, of the fair value hierarchy, as defined earlier in this Note 13.

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 and qualitative thresholds for reportable segments and are included in the “All Other” category in the table below. 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 IESCo, and IDACORP’s holding company expenses.

The table below 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 Operations		All Other		Eliminations			Consolidated Total
Three months ended September 30, 2013:
Revenues	$	380,304	$	803	$	—		$	381,107
Net income attributable to IDACORP, Inc.	70,302		1,448		—			71,750
Total assets as of September 30, 2013	5,503,818		99,792		(12,492		)	5,591,118
Three months ended September 30, 2012:
Revenues	$	332,757	$	1,262	$	—		$	334,019
Net income attributable to IDACORP, Inc.	89,596		2,473		—			92,069
Nine months ended September 30, 2013:
Revenues	$	947,529	$	2,455	$	—		$	949,984
Net income attributable to IDACORP, Inc.	149,331		1,465		—			150,796
Nine months ended September 30, 2012:
Revenues	$	826,788	$	3,074	$	—		$	829,862
Net income attributable to IDACORP, Inc.	150,125		2,174		—			152,299

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15. CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME

Comprehensive income includes net income, unrealized holding gains and losses on available-for-sale marketable securities, and amounts related to the SMSP. The table below presents changes in components of accumulated other comprehensive income (AOCI), net of tax, during the three and nine months ended September 30, 2013 and 2012 (in thousands of dollars). Items in parentheses indicate reductions to AOCI.



	Unrealized Gains and Losses on Available-for-Sale Securities		Defined Benefit Pension Items			Total
Three months ended September 30, 2013:
Balance at beginning of period	$	5,576	$	(20,322	)	$	(14,746	)
Other comprehensive income before reclassifications	843		—			843
Amounts reclassified out of AOCI	—		464			464
Net current-period other comprehensive income	843		464			1,307
Balance at end of period	$	6,419	$	(19,858	)	$	(13,439	)
Nine months ended September 30, 2013:
Balance at beginning of period	$	4,136	$	(21,252	)	$	(17,116	)
Other comprehensive income before reclassifications	2,283		—			2,283
Amounts reclassified out of AOCI	—		1,394			1,394
Net current-period other comprehensive income	2,283		1,394			3,677
Balance at end of period	$	6,419	$	(19,858	)	$	(13,439	)
Three months ended September 30, 2012:
Balance at beginning of period	$	3,395	$	(13,661	)	$	(10,266	)
Other comprehensive income before reclassifications	682		—			682
Amounts reclassified out of AOCI	—		265			265
Net current-period other comprehensive income	682		265			947
Balance at end of period	$	4,077	$	(13,396	)	$	(9,319	)
Nine months ended September 30, 2012:
Balance at beginning of period	$	2,569	$	(14,191	)	$	(11,622	)
Other comprehensive income before reclassifications	1,507		—			1,507
Amounts reclassified out of AOCI	—		796			796
Net current-period other comprehensive income	1,507		796			2,303
Balance at end of period	$	4,077	$	(13,396	)	$	(9,319	)

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The table below presents amounts reclassified out of components of AOCI and the income statement location of those amounts reclassified during the three and nine months ended September 30, 2013 and 2012 (in thousands of dollars). Items in parentheses indicate increases to net income.



	Amount Reclassified from AOCI
Details About AOCI	Three months ended September 30,						Nine months ended September 30,
	2013			2012			2013			2012
Amortization of defined benefit pension items ⁽¹⁾
Prior service cost	$	53		$	53		$	159		$	160
Net loss	709			382			2,129			1,146
Total before tax	762			435			2,288			1,306
Tax benefit ⁽²⁾	(298		)	(170		)	(894		)	(511		)
Net of tax	464			265			1,394			796
Total reclassification for the period	$	464		$	265		$	1,394		$	796

⁽¹⁾ Amortization of these items is included in IDACORP's condensed consolidated income statements in other operating expenses and in Idaho Power's condensed consolidated income statements in other expense, net.

⁽²⁾ The tax benefit is included in income tax expense in the condensed consolidated income statements of both IDACORP and Idaho Power.

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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 September 30, 2013, and the related condensed consolidated statements of income and comprehensive income for the three-month and nine-month periods ended September 30, 2013 and 2012, and of equity and cash flows for the nine-month periods ended September 30, 2013 and 2012. 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, 2012, 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 21, 2013, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2012 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

November 5, 2013

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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 of Idaho Power Company and subsidiary (the “Company”) as of September 30, 2013, and the related condensed consolidated statements of income and comprehensive income for the three-month and nine-month periods ended September 30, 2013 and 2012, and of cash flows for the nine-month periods ended September 30, 2013 and 2012. 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 of Idaho Power Company and subsidiary as of December 31, 2012, 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 21, 2013, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2012 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

November 5, 2013

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

AND RESULTS OF OPERATIONS

(Megawatt-hours (MWh) and dollar amounts in tables, other than earnings per share, 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. While reading the MD&A, please refer to the accompanying condensed consolidated financial statements of IDACORP and Idaho Power, and the notes thereto. This discussion updates the MD&A included in the Annual Report on Form 10-K for the year ended December 31, 2012, and should also be read in conjunction with the information in that report. The results of operations for an interim period generally will not be indicative of results for the full year, particularly in light of the seasonality of Idaho Power's sales volumes, as discussed below.

IDACORP is a holding company formed in 1998 whose principal operating subsidiary is Idaho Power. IDACORP’s common stock is listed and trades on the New York Stock Exchange under the trading symbol “IDA.” Idaho Power is an electric utility with a service territory covering approximately 24,000 square miles in southern Idaho and eastern Oregon. Idaho Power provided electric service to approximately 506,000 general business customers as of September 30, 2013. As a regulated utility, many of Idaho Power's fundamental business decisions are subject to the approval of governmental agencies. Idaho Power is under the retail jurisdiction (as to rates, service, accounting, and other general matters of utility operation) of the Idaho Public Utilities Commission (IPUC) and the Oregon Public Utility Commission (OPUC), which determine the rates that Idaho Power charges to its general business customers. 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 Federal Energy Regulatory Commission (FERC) tariff and to provide transmission services under its FERC open access transmission tariff (OATT). Idaho Power uses general rate cases, cost adjustment mechanisms, and subject-specific filings to recover its costs of providing service and the costs of its energy efficiency and demand-side resources programs, and to seek to earn a return on investment.

Idaho Power generates revenues and cash flows primarily from the sale and distribution of electricity to customers in its Idaho and Oregon service territories, as well as from the wholesale sale and transmission of electricity. Idaho Power’s revenues and income from operations are subject to fluctuations during the year due to the impacts of seasonal weather conditions on demand for electricity, availability of water for hydroelectric generation, price changes, customer usage patterns (which are affected in large part by the condition of the local economy), and the availability and price of purchased power and fuel. Idaho Power experiences its highest retail energy sales during the summer irrigation and cooling season, with a lower peak in the winter that generally results from heating demand. IDACORP’s and Idaho Power’s financial condition are also affected by regulatory decisions through which Idaho Power seeks to recover its costs on a timely basis and earn an authorized return on investment, and by the ability to obtain financing through the issuance of debt and/or equity securities.

IDACORP’s other subsidiaries include IDACORP Financial Services, Inc. (IFS), an investor in affordable housing and other real estate investments; Ida-West Energy Company, an operator of small hydroelectric generation projects that satisfy the requirements of the Public Utility Regulatory Policies Act of 1978 (PURPA); and IDACORP Energy Services Co., which is the former limited partner of, and successor by merger to, IDACORP Energy L.P., a marketer of energy commodities that wound down operations in 2003. Idaho Power is the parent of Idaho Energy Resources Co. (IERCo), a joint venturer in Bridger Coal Company (BCC), which mines and supplies coal to the Jim Bridger generating plant owned in part by Idaho Power.

EXECUTIVE OVERVIEW

Growth at IDACORP and Idaho Power

Idaho Power considers its service territory to have inherent characteristics that make it desirable for the expansion of existing businesses and for attracting new businesses and residential customers. In recent years Idaho Power has seen positive growth in its customer count and associated positive impacts on Idaho Power's revenue. As part of its planning for the future, Idaho Power actively participates in and supports state and local economic development initiatives that seek to encourage responsible and sustainable customer growth.

Another area for growth has been, and IDACORP expects will continue to be, Idaho Power's capital investments. Idaho Power's biennial Integrated Resource Plan (IRP) seeks to identify cost-effective and responsible means for Idaho Power to address customer growth. Recent infrastructure investments, such as the Langley Gulch power plant, and future anticipated

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infrastructure projects, including those identified in the 2013 IRP, are intended to help ensure Idaho Power continues to provide reliable service to existing customers while at the same time meeting expected future customer growth. Idaho Power has also invested significant capital in recent years to maintain and replace aging assets and to build for the future. Idaho Power expects to continue these significant levels of capital investment going forward. Idaho Power's substantial capital projects include upgrades to generation plants and ongoing system maintenance and upgrades, as well as continued progress on the Boardman-to-Hemingway and Gateway West transmission lines. Idaho Power estimates capital expenditures of $805 million to $845 million from 2013 (including costs incurred to-date in 2013) through 2015. These estimates include only permitting and siting costs for the transmission line projects.

In tandem with this, Idaho Power has achieved what it believes to be a constructive regulatory framework, through general rate cases, subject-specific rate filings, and cost recovery mechanisms that share risks and benefits with Idaho Power customers. To further complement these efforts, Idaho Power has also been focusing on optimizing its business operations; controlling operating, maintenance, and capital costs through process review and improvement initiatives; and by empowering employees to identify new means to reduce costs, increase efficiencies, and enhance individual and enterprise performance for the benefit of IDACORP's shareholders, Idaho Power's customers, and both companies' other stakeholders.

A final area of recent focus on growth has been IDACORP's dividend. In November 2011, the IDACORP Board of Directors adopted a target dividend payout ratio of between 50 and 60 percent of sustainable IDACORP earnings, and during 2012 IDACORP's quarterly dividend increased from $0.30 to $0.38 per IDACORP share. In September 2013, IDACORP's board of directors again voted to increase the quarterly dividend to $0.43 per share. Idaho Power's need and ability to construct infrastructure, the availability of timely regulatory recovery of costs associated with that construction, and IDACORP's earnings, among other factors discussed elsewhere in this report, all influence dividend decisions. A number of recent positive outcomes in those areas, such as the completion of the Langley Gulch power plant in June 2012 and inclusion of associated costs in rates, combined with the corresponding impact on IDACORP's financial performance, have been important elements that the IDACORP Board of Directors has considered in its recent dividend decisions. IDACORP anticipates the potential for further growth in the dividend as the company weighs factors governing dividend decisions and continues to work toward its target dividend payout ratio.

Brief Overview of Third Quarter 2013 Financial Results

IDACORP's earnings were $1.43 per diluted share for the quarter ended September 30, 2013, compared to $1.84 per diluted share for the same quarter in 2012. IDACORP's earnings in the third quarter of 2013 were lower than the third quarter of 2012 primarily due to increased income tax expense related to income tax method changes affecting both comparative periods. Based on Idaho Power's September 30, 2013 estimate of full-year 2013 return on year-end equity in the Idaho jurisdiction (Idaho ROE), in the third quarter of 2013 Idaho Power recorded an additional $3.4 million provision for sharing with customers pursuant to the terms of a December 2011 settlement stipulation with the IPUC. Combined with the provision for sharing with customers recorded in the second quarter of 2013, the aggregate provision for sharing at September 30, 2013 was $6.2 million. The December 2011 settlement stipulation requires sharing of earnings with Idaho customers if Idaho Power's 2013 Idaho ROE exceeds 10.0 percent. IDACORP's and Idaho Power's results, including a quantification of the respective impacts of the items noted above, are discussed in more detail below.

Overview of General Factors and Trends Affecting Results of Operations and Financial Condition

IDACORP's and Idaho Power's results of operations and financial condition are affected by regulatory, operational, weather-related, economic, and other factors, many of which are described below.

Timely Regulatory Cost Recovery: The price that Idaho Power is authorized to charge for its electric service is a critical factor in determining IDACORP's and Idaho Power's results of operations and financial condition. Because of the significant impact of ratemaking decisions, and in furtherance of its goal of advancing a purposeful regulatory strategy, Idaho Power has focused on timely recovery of its costs through filings with the company's regulators, and on the prudent management of expenses and investments. Effective implementation of Idaho Power's regulatory strategy is particularly important in a climate of slow economic recovery that continues to put pressure on regulators to limit rate increases or otherwise take actions to mitigate the impact of rate increases on customers. The amount of regulatory filings and activity during the period from 2010 through September 2013 exceeded historical averages and was driven by Idaho Power's regulatory strategy.

In light of the regulatory orders Idaho Power has received in recent years, Idaho Power does not plan to seek rate relief through a full general rate case filing during 2013. Instead, during 2013 Idaho Power will continue its focus on optimizing business operations and processes and will monitor the need for and timing of its next general rate cases in Idaho and Oregon. If deemed appropriate, Idaho Power could file an application for a general rate change or extensions of other mechanisms in

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Idaho as soon as 2014. Significant rate proceedings during 2012 and 2013 that have impacted revenues are listed below. Additional important regulatory matters are also discussed in IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2012 or in "Regulatory Matters" in this MD&A or Note 3 - "Regulatory Matters" to the condensed consolidated financial statements included in this report.



Proceeding	Description	Status
Langley Gulch Power Plant	Request for recovery of and return on Idaho Power's investment in the Langley Gulch power plant, including operating costs	IPUC approved a $58.1 million increase in rates, effective July 1, 2012; OPUC approved a $3.0 million increase in rates effective October 1, 2012
Idaho Jurisdiction Power Cost Adjustment (PCA) - 2012	Annual Idaho-jurisdiction PCA mechanism rate change	IPUC approved a $43.0 million increase in rates, effective for the period from June 1, 2012 to May 31, 2013 ⁽¹⁾
2011 Revenue Sharing	Rate adjustment pursuant to January 2010 and December 2011 settlement agreements ⁽²⁾	IPUC approved a $27.1 million decrease in rates, effective for the period from June 1, 2012 to May 31, 2013 ⁽²⁾
Idaho Jurisdiction PCA - 2013 (and 2012 Revenue Sharing Impact)	Annual Idaho-jurisdiction PCA mechanism rate change	IPUC approved a $140.4 million increase in rates, effective for the period from June 1, 2013 to May 31, 2014 ⁽³⁾
Depreciation for Non-AMI Meters	Application for removal from rates of accelerated depreciation expense associated with non-advanced metering infrastructure (AMI) metering equipment	IPUC approved a $10.6 million decrease in rates and associated depreciation expense, effective June 1, 2012


⁽¹⁾	The $43.0 million increase in PCA rates was offset by the $27.1 million decrease in rates pursuant to the 2011 revenue sharing order, listed below and discussed in footnote (2), resulting in a net increase in PCA rates of $15.9 million.

⁽²⁾

This revenue-sharing arrangement, which relates to financial results for 2011, had two components: (a) a PCA mechanism component, which reduced net rates by $27.1 million, and (b) a pension balancing account component, which resulted in a $20.3 million net reduction to Idaho Power's pension regulatory asset (reducing Idaho customers' future obligation). Idaho Power recorded the $27.1 million revenue reduction and $20.3 million pension regulatory asset reduction in 2011.

⁽³⁾

The 2013 Idaho PCA rates are offset by $7.2 million of Idaho revenue-sharing related to 2012 financial results pursuant to an IPUC order issued in 2012 under regulatory settlement agreements approved in January 2010 and December 2011. The $140.4 million increase in PCA rates includes the reduction in the PCA mechanism component of the revenue sharing amount from $27.1 million for the 2012-2013 PCA to $7.2 million for the 2013-2014 PCA.

In addition to the rate changes listed in the table above, in December 2011 the IPUC approved a settlement stipulation that permits Idaho Power to amortize additional accumulated deferred investment tax credits (ADITC) to help achieve a minimum 9.5 percent Idaho ROE in 2012, 2013, and 2014, subject to prescribed limits and conditions. Based on its 2012 Idaho ROE, Idaho Power did not amortize any additional ADITC in 2012. As of the date of this report, Idaho Power also does not expect to amortize any additional ADITC in 2013. The settlement stipulation also provides for the sharing between the company and customers of Idaho-jurisdictional earnings in excess of specified levels of Idaho ROE. Based on Idaho Power's estimate of full-year 2013 Idaho ROE, in the second quarter of 2013 Idaho Power recorded a $2.8 million provision for sharing with customers pursuant to the terms of the December 2011 settlement stipulation, and in the third quarter of 2013 increased the provision for sharing to $6.2 million. The specific terms of the settlement stipulation are described in "Regulatory Matters" in this MD&A and in Note 3 - "Regulatory Matters" to the condensed consolidated financial statements included in this report. While providing no assurance that Idaho Power will obtain a 9.5 percent Idaho ROE in any of the years, IDACORP and Idaho Power believe the ability to amortize additional ADITC under the settlement stipulation provides an element of earnings stability for 2013 and 2014.

Idaho Power actively assesses regulatory matters. On November 1, 2013, Idaho Power filed an application with the IPUC requesting approval of new normalized or “base level” power supply expense, which if approved would reflect in base rates approximately $106 million of such expenses, effective June 1, 2014. Approval of the application would result in no net change in the amount collected through base rates and the PCA mechanism in the aggregate. Idaho Power expects, however, that approval of the application would decrease the amount of any base rate increase requested in Idaho Power's next general rate case application filed with the IPUC.

Economic Conditions and Customer/Load Growth: Idaho Power monitors a number of economic indicators, including employment rates, growth in customer numbers, and foreclosure rates and other housing-related data on a national and state scale and within Idaho Power's service territory. Economic conditions can impact consumer demand for electricity, collectability of accounts, the volume of off-system sales, and the need to construct and improve infrastructure, purchase power, and implement programs to meet customer load demands. While portions of Idaho have had difficulties reaching pre-

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recession economic levels, Idaho Power has observed what it believes to be a number of improvements in economic conditions in its service territory during 2012 and into the first nine months of 2013. For example, after peaking at 10.0 percent in early 2011, the service area unemployment rate fell to 8.4 percent by the end of 2011 and to 6.2 percent by the end of 2012, and was estimated at 6.3 percent at the end of August 2013, according to Idaho Department of Labor data. A forecast update issued by Moody’s Analytics, Inc. in July 2013 shows 2012 gross area product in Idaho Power’s service area exceeded pre-recession levels. The update also forecasts gross area product growth at 2.4 percent and 3.1 percent in 2013 and 2014, respectively. The housing market in Idaho Power's service territory has improved when measured by foreclosure rates, market prices, and available supply of housing. New housing permits for Idaho Power’s residential sector through September have increased 20 percent in 2013 compared to 2012. Further, a number of businesses have recently constructed, or are in the process of constructing, sizable facilities in Idaho Power's service territory, including both office and industrial complexes, and new manufacturing facilities, particularly in the food processing industry.

Based on current economic data, Idaho Power predicts that customer growth within its service territory will continue to be positive. Recently, Idaho Power conducted an updated load forecast based on observations of current economic activity. The updated forecast predicts a 1.4 percent five-year compound annual growth rate in residential loads and a 2.1 percent five-year compound annual growth rate in residential customers.

For resource planning purposes, Idaho Power's 2013 IRP, filed with the IPUC and OPUC on June 28, 2013, included a forecasted long-term annual customer growth rate more closely aligned with the 1.1 percent growth rate it experienced in 2012, an improvement over the 0.8 percent average annual growth rate experienced the past 5 years, but less than the 2.6 percent average annual growth realized over the past 20 years. Studies that Idaho Power conducted in connection with Idaho Power's 2013 IRP, based in part on these growth forecasts, indicate that under a scenario that excludes demand response programs and power capacity from the proposed Boardman-to-Hemingway 500-kV transmission line, no peak-hour load deficit exists until 2016. This result suggests there is available near term capacity to accommodate growth from economic development or increases in customers.

Should the updated estimates of higher growth rates materialize, or were there to be a significant increase in loads due to new, unanticipated large-load customers, growth would exceed the projections included in the 2013 IRP and Idaho Power could be required to adjust its infrastructure development timing and plans accordingly.

Weather Conditions and Associated Impacts: Weather and agricultural growing conditions have a significant impact on energy sales and the seasonality of those sales. Relatively low and high temperatures result in greater energy use for heating and cooling, respectively. During the agricultural growing season, which in large part occurs during the second and third quarters, irrigation customers use electricity to operate irrigation pumps, and weather conditions can impact the timing and degree of use of those pumps. Idaho Power also has tiered rates and seasonal rates, which contribute to increased revenues during higher-load periods, most notably the third quarter of each year when overall customer demand is typically at its peak. As for weather-impacted results year-to-date, an abnormally cold winter in the first quarter of 2013 drove increased demand by retail customers for the operation of electric heating systems. During the second quarter of 2013, warm late-spring and summer temperatures drove higher-than-normal demand for electric power for the operation of air conditioning units and irrigation equipment. Third quarter 2013 sales volumes were comparable to third quarter 2012 sales volumes.

Idaho Power's hydroelectric facilities comprise nearly one-half of Idaho Power's nameplate generation capacity. However, the actual availability and volume of hydroelectric power generated depends on the amount of snow pack in the mountains upstream of Idaho Power's hydroelectric facilities, reservoir storage, springtime snow pack run-off, base flows in the Snake River, spring flows, rainfall, water leases and other water rights, and other weather and stream flow considerations. Idaho Power expects hydroelectric generation during 2013 to be in the range of 5.5 to 6.0 million megawatt-hours (MWh), based on reservoir storage levels and forecasted weather conditions as of the date of this report, compared to actual generation of 8.0 million MWh in 2012, 10.9 million MWh in 2011, and 7.3 million MWh in 2010. Median annual hydroelectric generation is 8.4 million MWh. When hydroelectric generation is reduced, Idaho Power must rely on more expensive generation sources and purchased power; however, most of the increase in power supply costs is collected from customers through its Idaho and Oregon PCA mechanisms. Conversely, in periods of greater hydroelectric generation most of the resulting decrease in power supply costs that typically occurs is returned to customers through the PCA mechanisms. Idaho Power's April 2013 request for a $140.4 million PCA rate increase for the 2013-2014 PCA collection period was largely the result of unfavorable hydroelectric conditions during the 2012-2013 PCA year and a forecast of below average hydroelectric generating conditions during the 2013-2014 PCA year.

When favorable hydroelectric generating conditions exist for Idaho Power, they also may exist for other Pacific Northwest hydroelectric facility operators, thus increasing the available supply of lower-cost power and lowering regional wholesale market prices, which impacts the revenue Idaho Power receives from off-system sales of its excess power. Conversely, when

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hydroelectric generating conditions are poor, wholesale market prices may be higher due to lower supply, but Idaho Power would generally have less surplus energy available for sale into the wholesale markets at those times. Again, much of the adverse or favorable impact of these costs is addressed through the PCA mechanisms.

Fuel and Purchased Power Expense: In addition to hydroelectric generation and power it purchases in the wholesale markets, Idaho Power relies significantly on coal and natural gas to fuel its generation facilities. Fuel costs are impacted by electricity sales volumes, the terms of contracts for fuel, Idaho Power's power generation capacity, the availability of hydroelectric generation resources, transmission capacity, energy market prices, and Idaho Power's hedging program for managing fuel costs. Operation of Idaho Power's Langley Gulch power plant, placed into operation in June 2012, has increased Idaho Power's use of natural gas as a generation fuel and thus its exposure to volatility in natural gas prices.

Purchased power costs are impacted by the terms of contracts for purchased power, the rate of expansion of alternative energy generation sources such as wind energy, and wholesale energy market prices. Idaho Power is obligated to purchase power from some PURPA generation projects at a specified price regardless of the then-current load demand or wholesale energy market prices. This increases the likelihood that Idaho Power will at times be required to reduce output from its lower-cost hydroelectric and fossil fuel-fired generation resources and may be required to sell in the wholesale power market the power it purchases from PURPA projects at a significant loss. Integration of intermittent, non-dispatchable resources (such as wind energy) into Idaho Power's portfolio also creates a number of complex operational risks and challenges that Idaho Power is working to address, including through evaluation of the results of a recent comprehensive wind integration study. Notably, integration of these sources of power into Idaho Power's portfolio does not eliminate Idaho Power's need to construct facilities and infrastructure that provide reliable power. For instance, at the time Idaho Power reached its all-time system peak demand of 3,407 MW on July 2, 2013, wind resources on Idaho Power's system, representing roughly 675 MW of nameplate capacity, were contributing only 57 MW of power due to lack of wind. Increases in federally mandated PURPA power purchases have contributed to increases in customer rates.

The Idaho and Oregon PCA mechanisms mitigate in large part the potential adverse impacts to Idaho Power of fluctuations in Idaho Power's power supply costs, including substantially all of the Idaho-jurisdiction PURPA power purchase costs. Idaho Power also uses physical and financial forward contracts for both electricity and fuel and other hedging strategies in order to manage the risks relating to fuel and power price exposures.

Regulatory and Environmental Compliance Costs and Expenditures: Idaho Power is subject to extensive federal and state laws, policies, and regulations, as well as regulatory actions and audits, including FERC and North American Electric Reliability Corporation reliability requirements. Compliance with these requirements directly influences Idaho Power's operating environment and may significantly increase Idaho Power's operating costs. Further, potential monetary and non-monetary penalties for a violation of applicable laws or regulations may be substantial. Accordingly, Idaho Power has in place numerous compliance policies and initiatives, and frequently evaluates and updates those policies and initiatives.

In particular, environmental laws and regulations may, among other things, increase the cost of operating power generation plants and constructing new facilities, require that Idaho Power install additional pollution control devices at existing generating plants, or require that Idaho Power cease operating certain power generation plants. For instance, the Boardman coal-fired power plant, in which Idaho Power owns a 10-percent interest, is scheduled to cease coal-fired operations by the end of 2020, the decision for which was driven in large part by the substantial cost of environmental controls. Idaho Power expects to spend a considerable amount on environmental compliance and controls in the next decade. As legislation and regulations concerning greenhouse gas emissions develop, Idaho Power assesses, to the extent determinable, the potential impact on the costs to operate its power generation facilities, as well as the willingness of joint owners of power plants to fund any required pollution control equipment upgrades. To that end, in the first quarter of 2013 Idaho Power concluded cost studies and scenario analyses to assess the potential future investments necessary for the continued operation of the Jim Bridger and Valmy coal-fired generation facilities. Idaho Power published the results of the study in February 2013, concluding that planned investments in environmental controls at both plants are appropriate.

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Other Notable Matters and Areas of Focus

Pension Plan Funding: From 2011 through September 2013 Idaho Power contributed $93 million to its defined benefit pension plan. In May 2011 the IPUC authorized Idaho Power to increase its annual recovery and amortization of deferred pension costs from $5.4 million to $17.1 million. Idaho Power has no minimum required contribution to its defined benefit pension plan in 2013; however, it has made discretionary contributions of $30 million to-date in 2013 to bring the plan to a more funded level. While the IPUC's authorization to increase the annual recovery has decreased the adverse cash flow impacts of the contributions, the magnitude of the contributions relative to the annual cost recovery can still create a lag between the timing of expenditures and their recovery.

Water Management and Relicensing of the Hells Canyon Hydroelectric Project: Because of Idaho Power's reliance on stream flow in the Snake River and its tributaries, Idaho Power participates in numerous proceedings and venues that may affect its water rights, seeking to preserve the long-term availability of its rights for use at its hydroelectric projects. Also, Idaho Power is involved in renewing its federal license for the HCC, its largest hydroelectric generation source, and recently received a 30-year license renewal from the FERC for its Swan Falls hydroelectric project. Relicensing involves numerous environmental issues and substantial costs. Idaho Power is working with the states of Idaho and Oregon, federal and state regulatory authorities, and interested parties to address concerns and take appropriate measures relating to the relicensing of the HCC. However, given the number of parties and issues involved, Idaho Power's relicensing costs have been and will continue to be substantial, and the terms of, and costs associated with, any resulting license are not currently determinable.

Transmission Projects: Idaho Power continues to focus on expansion of its transmission system in an effort to enhance system reliability and access to wholesale markets. Its most notable transmission projects in progress are the proposed Boardman-to-Hemingway and Gateway West 500-kV transmission projects. In January 2012, Idaho Power entered into cost-sharing arrangements with third parties for the permitting phases of both projects. Construction of these projects cannot commence until all federal, state, and local regulatory requirements are met. As it relates to the Boardman-to-Hemingway project, of which Idaho Power is the project manager, the environmental requirements for, and application of environmental regulations (particularly relating to sage grouse) to, the siting process have changed significantly since commencement of the project, making identification of a suitable route for the transmission line more difficult. This has resulted in project delays and increased permitting costs. In light of the delays and siting impediments that have occurred and are expected to continue, Idaho Power estimates that the in-service date for the Boardman-to-Hemingway line would be in 2020 or beyond. The Boardman-to-Hemingway line remains Idaho Power's preferred resource alternative. Given project delays, however, Idaho Power is conducting an enhanced review of other power supply resource options as it continues progress on the Boardman-to-Hemingway line.

Summary of Third Quarter and Year-to-Date 2013 Financial Results

The following is a summary of Idaho Power's net income, net income attributable to IDACORP, and IDACORP's earnings per diluted share for the three- and nine-month periods ended September 30, 2013 and 2012:



	Three months ended September 30,				Nine months ended September 30,
	2013		2012		2013		2012
Idaho Power net income	$	70,302	$	89,596	$	149,331	$	150,125
Net income attributable to IDACORP, Inc.	$	71,750	$	92,069	$	150,796	$	152,299
Average outstanding shares – diluted (000’s)	50,153		50,080		50,109		49,990
IDACORP, Inc. earnings per diluted share	$	1.43	$	1.84	$	3.01	$	3.05

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The table below provides a reconciliation of net income attributable to IDACORP for the three- and nine-month periods ended September 30, 2013 to the same periods in 2012 (items are in millions and are before tax unless otherwise noted):



	Three months ended						Nine months ended
Net income attributable to IDACORP, Inc. - September 30, 2012				$	92.1					$	152.3
Change in Idaho Power net income:
Rate changes, net of changes in power supply costs and PCA mechanisms	$	(2.6	)				$	26.5
Change in sales volumes attributable to usage per customer, net of associated power supply costs and PCA mechanism impacts	(0.8		)				12.7
Increases in sales volumes attributable to customer growth, net of associated power supply costs and PCA mechanism impacts	2.9						7.4
Other changes in operating revenues and expenses, net	(1.1		)				(2.0		)
Reduction in revenue sharing costs	8.7						5.9
Increase in Idaho Power operating income	7.1						50.5
Change in allowance for funds used during construction (AFUDC)	0.1						(12.7		)
Changes in other non-operating income and expenses	0.6						(2.7		)
Tax method changes in 2012 and 2013	(12.4		)				(12.4		)
Change in regulatory flow-through tax adjustments	(11.6		)				(9.8		)
Increase in income tax at statutory rates	(3.1		)				(13.7		)
Total decrease in Idaho Power net income				(19.3		)				(0.8		)
Other net changes (net of tax)				(1.0		)				(0.7		)
Net income attributable to IDACORP, Inc. - September 30, 2013				$	71.8					$	150.8

Third Quarter 2013 Net Income

IDACORP's net income decreased $20.3 million for the third quarter of 2013 when compared with the same period in the prior year. Idaho Power’s operating income increased by $7.1 million as less revenue sharing occurred in the third quarter of 2013 as compared to the same period in 2012. Growth in the number of customers, and associated increased sales volumes, increased operating income by $2.9 million for the quarter compared to the third quarter of 2012. While the PCA rate increase and higher rates due to inclusion of Langley Gulch in Oregon rates positively impacted revenue for the third quarter of 2013 compared to the same period in 2012, the increased revenues were more than offset by higher power supply costs and by PCA amortization expense.

The $7.1 million increase in Idaho Power's operating income was offset by higher income tax expense, primarily driven by an income tax method change that lowered income tax expense in the third quarter of 2012 compared to an income tax method change that increased income tax expense in the same period in 2013. Tax flow-through adjustments also lowered income tax expense in the third quarter of 2012, while similar flow-through adjustments increased income tax expense in 2013, resulting in a net increase to income tax expense for the third quarter of 2013 compared to the same period in 2012. Income tax expense was also higher in the third quarter of 2013 as higher Idaho Power pre-tax income resulted in additional income tax expense.

Year-to-Date Net Income

IDACORP's net income decreased $1.5 million for the nine months ended September 30, 2013, when compared with the same period in the prior year. Idaho Power's operating income increased by $50.5 million over the comparative period. Higher rates implemented during 2012, primarily related to the Langley Gulch power plant, increased operating income for the first nine months of 2013 by $26.5 million compared to the same period in 2012. The rate impact on net income was partially offset by decreased AFUDC and increased depreciation expense, both associated with the inclusion of the Langley Gulch plant in base rates. Higher sales volumes per customer, attributed to increased heating-related sales due to abnormally cold winter temperatures combined with higher irrigation and air conditioning sales due to warm late spring and summer temperatures and the timing of precipitation, increased operating income by $12.7 million. An increase in sales volumes due to growth in the number of customers added $7.4 million to operating income for the first nine months of 2013 compared to the same period in 2012. The change in operating income was also positively impacted by the sharing mechanism under the December 2011 regulatory settlement agreement, with a combined $5.9 million lower provision for revenue sharing recorded in the first nine months of 2013 compared to the same period in 2012. Offsetting these increases was higher income tax expense related to greater pre-tax earnings at Idaho Power in 2013 and income tax method changes affecting both comparative periods.

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Effect of Income Taxes and Tax Method Changes on Results

Income tax expense related to income tax accounting method changes increased $12.4 million for the quarter and the first nine months of 2013, when compared to the same periods in the prior year. In 2012, Idaho Power recorded an income tax benefit of $7.8 million for years prior to 2011 for the cumulative tax adjustment of a method change related to its capitalized repairs deduction for transmission and distribution property. Net regulatory flow-through tax adjustments at Idaho Power were $11.6 million and $9.8 million lower for the three and nine months ended September 30, 2013, as compared to the same periods in 2012, primarily due to greater capitalized repairs deductions in 2012. By contrast, during the third quarter of 2013 Idaho Power recorded incremental income tax expense of $4.6 million as a result of a method change related to its capitalized repairs deduction for generation assets due to a change in income tax law that occurred in September 2013. This method change only impacted the cumulative tax adjustment for years prior to 2013, and Idaho Power does not expect a change to net regulatory flow-through tax adjustments for 2013 or subsequent years as a result of the 2013 method change.



Effect of Sharing on Operating Income	Three months ended September 30,								Nine months ended September 30,
	2013			2012			Change		2013			2012			Change
Additional pension expense funded through sharing	$	—		$	(5.8	)	$	5.8	$	—		$	(5.8	)	$	5.8
Provision against current revenue as a result of sharing	(3.4		)	(6.3		)	2.9		(6.2		)	(6.3		)	0.1
Total	$	(3.4	)	$	(12.1	)	$	8.7	$	(6.2	)	$	(12.1	)	$	5.9

During the third quarter of 2013, Idaho Power recorded $3.4 million as a provision against current revenues to be refunded to customers through a future rate reduction. This revenue sharing is related to a December 2011 Idaho regulatory settlement agreement, which requires sharing with Idaho customers of a portion of 2013 (and 2012 and 2014) Idaho-jurisdiction earnings exceeding a 10.0 percent Idaho return on year-end equity in the Idaho jurisdiction. The settlement agreement is described further in "Regulatory Matters" in this MD&A. By comparison, in the third quarter of 2012 Idaho Power recorded a total of $12.1 million related to the December 2011 settlement agreement. In accordance with the terms of the settlement agreement, of the total recorded in the third quarter of 2012, $5.8 million was recorded as additional pension expense and $6.3 million was recorded as a provision against revenues. For the 2013 year-to-date, Idaho Power has recorded a total of $6.2 million as a provision against revenues to be refunded to customers pursuant to the December 2011 settlement agreement, with no pension expense related to sharing.

Key Operating and Financial Metric Estimates for Full-Year 2013

IDACORP’s and Idaho Power’s estimates, as of the date of this report, for 2013 full year metrics are as follows:



	2013 Estimates
	Current ⁽¹⁾	Previous ⁽²⁾
Idaho Power Operating & Maintenance Expense (millions)	No Change	$335-$345
Idaho Power Additional Amortization of ADITC (millions)	No Change	$0
Idaho Power Capital Expenditures, excluding AFUDC (millions)	No Change	$230-$240
Idaho Power Hydroelectric Generation (million MWh) ⁽³⁾	No Change	5.5-6.0

⁽¹⁾As of November 5, 2013.
⁽²⁾As of August 1, 2013, the date of filing of IDACORP's and Idaho Power's Quarterly Report on Form 10-Q for the quarter ended June 30, 2013.
⁽³⁾Based on reservoir storage levels and forecasted weather conditions as of the date of this report.

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RESULTS OF OPERATIONS

This section of MD&A takes a closer look at the significant factors that affected IDACORP’s and Idaho Power’s earnings during the three and nine months ended September 30, 2013. In this analysis, the results for the three and nine months ended September 30, 2013 are compared to the same periods in 2012. In MD&A, MWh and dollar amounts in tables, other than earnings per share, are in thousands unless otherwise indicated.

Utility Operations

The table below presents Idaho Power’s energy sales and supply (in thousands of MWh) for the three and nine months ended September 30, 2013 and 2012.



	Three months ended September 30,				Nine months ended September 30,
	2013		2012		2013		2012
General business sales	4,342		4,304		11,340		10,941
Off-system sales	306		109		1,008		1,656
Total energy sales	4,648		4,413		12,348		12,597
Hydroelectric generation	1,356		1,649		4,365		6,630
Coal generation	1,692		1,653		4,665		3,505
Natural gas and other generation	684		410		1,176		610
Total system generation	3,732		3,712		10,206		10,745
Purchased power	1,229		1,026		3,030		2,871
Line losses	(313	)	(325	)	(888	)	(1,019	)
Total energy supply	4,648		4,413		12,348		12,597

Sales Volume and Generation: In the third quarter and first nine months of 2013, general business sales volume increased by 38 thousand MWh and 399 thousand MWh, respectively, compared to the same periods in the prior year, mostly as a result of increased residential and industrial customer usage for the quarter and increased residential, irrigation, and commercial usage for the nine-month period. The comparative increase in residential customer usage is largely attributable to more extreme temperatures, which increased electricity demand for heating and cooling. The increase in industrial and commercial usage is largely attributed to increased economic activity in the region, and the increase in irrigation customer usage is due to agricultural growing conditions and the timing and amount of precipitation.

Off-system sales volume increased by 197 thousand MWh in the third quarter but decreased 648 thousand MWh in the nine months ended September 30, 2013. Off-system sales during the third quarter of 2012 were abnormally low due to decreased hydroelectric generation and increased system load during that period. Further, greater availability of thermal generation and mandated power purchases from cogeneration and small power production (CSPP) facilities pursuant to PURPA allowed increased off-system sales volumes during the third quarter of 2013 compared to the same period in 2012. For the nine months ended September 30, 2013, off-system sales volumes decreased compared to the same period in 2012 as decreases in output from hydroelectric resources and a relative increase in customer load decreased surplus power available for off-system sales.

Hydroelectric generation comprised 36 percent and 43 percent of Idaho Power's total system generation during the third quarter and first nine months of 2013, respectively. The 293 thousand MWh and 2.3 million MWh decrease in hydroelectric generation in the third quarter and first nine months of 2013, respectively, compared to the same periods in 2012 was primarily due to below normal water supply resulting in below normal hydroelectric generating conditions. The decrease in hydroelectric generation during the periods presented of 2013 led to an increased utilization of coal-fired and natural gas-fired generation, as well as purchased power. The commencement of operation of the Langley Gulch natural gas-fired power plant, which was placed into service in the summer of 2012, replaced in part the decreased hydroelectric generation.

On July 2, 2013, Idaho Power achieved a record load demand of 3,407 MW. At the time of record load, all of the wind turbines supplying power to Idaho Power’s system, representing more than 675 MW of capacity, were generating 57 MW. The previous record peak demand of 3,245 MW was set on July 12, 2012. 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. When loads exceed Idaho Power's generation capacity, Idaho Power must rely on power obtained through purchase contracts (from which power may not be available when needed if the source is intermittent power such as wind) and third-party transmission and may be required to purchase power in the wholesale energy market.

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General Business Revenues: The table below presents Idaho Power’s general business revenues and MWh sales for the three and nine months ended September 30, 2013 and 2012 and the number of customers as of September 30, 2013 and 2012.



	Three months ended September 30,						Nine months ended September 30,
	2013			2012			2013			2012
Revenue
Residential	$	137,862		$	120,786		$	374,287		$	316,964
Commercial	80,926			72,519			209,558			181,810
Industrial	48,165			41,690			123,234			108,804
Irrigation	89,307			80,780			153,636			131,057
Total	356,260			315,775			860,715			738,635
Provision for sharing	(3,400		)	(6,300		)	(6,200		)	(6,300		)
Deferred revenue related to HCC relicensing AFUDC ⁽¹⁾	(3,432		)	(3,409		)	(8,436		)	(8,310		)
Total general business revenues	$	349,428		$	306,066		$	846,079		$	724,025
Volume of Sales (MWh)
Residential	1,328			1,285			3,952			3,757
Commercial	1,049			1,044			2,984			2,911
Industrial	813			793			2,384			2,333
Irrigation	1,152			1,182			2,020			1,940
Total MWh sales	4,342			4,304			11,340			10,941
Number of customers at period end
Residential	420,240			414,640
Commercial	66,575			65,782
Industrial	116			119
Irrigation	19,397			19,071
Total customers	506,328			499,612

⁽¹⁾As part of its January 30, 2009 general rate case order, the IPUC allowed Idaho Power to recover AFUDC for the HCC relicensing asset even though the relicensing process is not yet complete and the relicensing asset has not been placed in service. Idaho Power is collecting approximately $10.7 million annually in the Idaho jurisdiction, but is deferring revenue recognition of the amounts collected until the license is issued and the asset is placed in service under the new license.

Changes in rates and changes in customer demand are the primary reasons for fluctuations in general business revenue from period to period. The table below presents the rate changes that significantly impacted revenues for the first nine months of 2013 when compared to the same period in 2012.



Description	Effective Date	Percentage Rate Increase (Decrease)			Estimated Annualized Revenue Impact (millions)
2012 Idaho PCA	6/1/2012	5.1	%	$	43
2012 Idaho non-AMI meter depreciation	6/1/2012	(1.3	)%		(11	)
2012 Idaho Langley Gulch	7/1/2012	6.8	%		58
2012 Oregon Langley Gulch	10/1/2012	6.9	%		3
2013 Idaho PCA	6/1/2013	15.3	%		140

The primary influences on customer demand for electricity are weather and economic conditions. Extreme temperatures increase sales to customers who use electricity for cooling and heating, and moderate temperatures decrease sales. Precipitation levels and the timing of precipitation during the agricultural growing season also affect sales to customers who use electricity to operate irrigation pumps. Rates are also seasonally adjusted and based on a tiered rate structure that provides for higher rates during peak load periods. The seasonal and tiered rate structures contribute to seasonal fluctuations in revenues and earnings. For purposes of illustration, Boise, Idaho weather-related information for the three and nine months ended September 30, 2013 and 2012 is presented in the following table:

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	Three months ended September 30,			Nine months ended September 30,
	2013	2012	Normal	2013	2012	Normal
Heating degree-days⁽¹⁾	91	17	121	3,565	2,865	3,320
Cooling degree-days ⁽¹⁾	1,082	1,074	751	1,320	1,273	934
⁽¹⁾ Heating and cooling degree-days are common measures used in the utility industry to analyze the demand for electricity and indicate when a customer would use electricity for heating and air conditioning. A degree-day measures how much the average daily 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. While Boise, Idaho weather conditions are not necessarily representative of weather conditions throughout Idaho Power's service territory, the greater Boise area has the majority of Idaho Power's customers.

General business revenue increased $43.4 million and $122.1 million for the three and nine months ended September 30, 2013, respectively, compared to the same periods in 2012. Specific factors affecting general business revenues during the periods are discussed below.

•

Rates. Rate changes, including those shown in the table above, combined to increase general business revenue by $38.3 million in the quarter and $99.8 million in the first nine months of 2013 compared to the same periods in 2012. The revenue impact of several of the rate changes was directly offset by associated changes in operating expenses. For example, Idaho PCA amortization expense increased $23.9 million for the quarter and $24.2 million for the first nine months of 2013 compared to the same periods in 2012 due to the change in the corresponding Idaho PCA true-up rate in the current year. The PCA mechanism and its mechanics are discussed in detail below in this MD&A.

•

Customers. Customer growth drove an increase in overall MWh sales for the third quarter and first nine months of 2013, and a $4.2 million and $10.2 million respective increase in general business revenues, when compared to the third quarter and first nine months of 2012. Total customers increased 1.3 percent during the twelve months ended September 30, 2013. The positive impact of customer growth was offset by a $1.2 million and $6.6 million decrease in revenues for the comparative quarter and first nine months, respectively, resulting from the termination during 2012 of an electric service agreement with Hoku Materials, Inc. Combined, these changes increased general business revenues by $3.0 million for the third quarter and $3.6 million for the first nine months of 2013 when compared to the same periods in 2012.

•

Usage Per Customer. Lower usage (on a per customer basis) by irrigation and commercial customers, mostly offset by higher usage per customer by residential and industrial customers, combined to decrease general business revenue for the quarter by $0.8 million when compared to the third quarter of 2012. Higher usage per customer increased general business revenue for the first nine months of 2013 by $18.5 million compared to the same period in 2012. For the third quarter, irrigation usage per customer decreased 4.3 percent, as a result of less water available for irrigation during the period (and hence lesser irrigation equipment usage) compared to the same period in the prior year. For the first nine months of 2013, irrigation usage per customer increased 2.5 percent compared to the same period in the prior year, resulting from lower comparative precipitation and the timing of that precipitation. Residential use per customer increased 2.0 percent for the third quarter and 4.0 percent for the first nine months of 2013, due largely to more extreme summer and winter temperatures.

•

Sharing. The overall increases in general business revenue for the third quarter and first nine months of 2013 were impacted by Idaho Power's revenue sharing mechanism. This mechanism, which was in place for both 2012 and 2013, is related to a December 2011 Idaho regulatory settlement agreement that requires sharing with customers of a portion of Idaho-jurisdiction earnings exceeding a 10.0 percent Idaho ROE. The impact of the mechanism is recorded as a reduction to general business revenue. For the quarter, $3.4 million was recorded in the current year and $6.3 million was recorded in the prior year, for a net increase in general business revenue of $2.9 million in the current period. For the first nine months, $6.2 million was recorded in the current year and $6.3 million was recorded in the prior year, for a net increase of $0.1 million in the current period.

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Off-System Sales: Off-system sales consist primarily of long-term sales contracts and opportunity sales of surplus system energy. The table below presents Idaho Power’s off-system sales for the three and nine months ended September 30, 2013 and 2012.



	Three months ended September 30,				Nine months ended September 30,
	2013		2012		2013		2012
Revenue	$	11,169	$	4,826	$	31,597	$	43,953
MWh sold	306		109		1,008		1,656
Revenue per MWh	$	36.50	$	44.28	$	31.35	$	26.54

For the third quarter of 2013, off-system sales revenue increased by $6.3 million, or 131 percent, compared to the same period in 2012. For the first nine months of 2013, off-system sales revenue decreased by $12.4 million, or 28 percent, compared to the same period in 2012. Off-system sales volumes increased 181 percent for the quarter as a result of an increase in thermal generation and mandatory CSPP power purchases compared to the same period in the prior year. Off-system sales volumes decreased 39 percent for the first nine months of 2013 due to decreased hydroelectric generation and increased system load. The revenue impact of the increase in volume for the third quarter was partially offset by an 18 percent decrease in average prices. The revenue impact of the decrease in volume for the first nine months was partially offset by an 18 percent increase in average prices.

Other Revenues: The table below presents the components of other revenues for the three and nine months ended September 30, 2013 and 2012.



	Three months ended September 30,				Nine months ended September 30,
	2013		2012		2013		2012
Transmission services and other	$	13,630	$	13,455	$	39,574	$	37,839
Energy efficiency	6,077		8,410		30,279		20,971
Total other revenues	$	19,707	$	21,865	$	69,853	$	58,810

Other revenue decreased $2.2 million for the third quarter and increased $11.0 million for the first nine months of 2013 compared to the same periods in 2012. For the third quarter, energy efficiency revenues decreased $2.3 million compared to the same period in the prior year due to less utilization of these programs. Energy efficiency revenues increased for the first nine months due to an order issued by the IPUC allowing Idaho Power to recover custom efficiency program incentive payments made between January 1, 2011 and June 1, 2013, through the energy efficiency rider. Based on the order, $14.3 million of other revenue as well as energy efficiency program expense was recognized in the second quarter of 2013. Transmission wheeling revenues increased for the first nine months when compared to the same period in the prior year, mostly related to the increased need for purchased power throughout the region during the period.

Most energy efficiency activities are funded through a rider mechanism on customer bills. Energy efficiency program expenditures funded through the rider 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.

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Purchased Power: The table below presents Idaho Power’s purchased power expenses and volumes for the three and nine months ended September 30, 2013 and 2012.



	Three months ended September 30,				Nine months ended September 30,
	2013		2012		2013		2012
Expense
PURPA contracts	$	36,848	$	35,483	$	100,937	$	88,842
Other purchased power (including wheeling)	33,924		22,862		60,965		47,837
Demand response incentive payments	$	3,316	$	13,225	$	4,195	$	14,347
Total purchased power expense	$	74,088	$	71,570	$	166,097	$	151,026
MWh purchased
PURPA contracts	528		497		1,680		1,489
Other purchased power	701		529		1,350		1,382
Total MWh purchased	1,229		1,026		3,030		2,871
Cost per MWh from PURPA contracts	$	69.79	$	71.39	$	60.08	$	59.67
Cost per MWh from other sources	$	48.39	$	43.22	$	45.16	$	34.61
Weighted average - all sources	$	57.59	$	56.87	$	53.43	$	47.61

The purchased power cost per MWh often exceeds the off-system sales revenue per MWh because Idaho Power generally needs to purchase more power during heavy load periods, which is higher priced energy, than during light load periods, which is lower priced energy, and conversely has less energy available for off-system sales during heavy load periods than light load periods. Also, in accordance with Idaho Power's risk management policy, Idaho Power may purchase or sell energy several months in advance of anticipated delivery. The regional energy market price is dynamic and additional energy purchase or sale transactions that Idaho Power makes at current market prices may be noticeably different than the advance purchase or sale transaction prices.

Purchased power expense increased $2.5 million, or 4 percent, in the third quarter of 2013 and $15.1 million, or 10 percent, in the first nine months of 2013 compared to the same periods in 2012. The increases were driven by higher volumes and prices, partially offset by a reduction in demand-response program expenses. In the third quarter, Idaho Power increased purchases from non-PURPA sources, primarily due to reduced hydroelectric generation available to serve loads. Prices for wholesale power were higher because of lower availability of excess power in the region. Mandated power purchases from CSPP facilities pursuant to PURPA increased 6 percent in the quarter and 13 percent in the first nine months of 2013 due to additional PURPA wind generation facilities coming on-line in the current year. Demand-response program expenses decreased because certain peak-load reduction programs that were in place in 2012 were suspended in 2013, pursuant to authority from the IPUC, pending an evaluation of the programs. The demand response program suspension is discussed in more detail in "Regulatory Matters" below.

Substantially all PURPA power purchase costs are recovered through base rates and Idaho Power's PCA mechanisms; thus, the primary impact of the increased expense associated with PURPA power purchases is a corresponding increase in customer rates.

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Fuel Expense: The table below presents Idaho Power’s fuel expenses and generation at its thermal generating plants for the three and nine months ended September 30, 2013 and 2012.



	Three months ended September 30,				Nine months ended September 30,
	2013		2012		2013		2012
Expense
Coal	$	43,765	$	41,905	$	116,281	$	90,041
Natural gas and other thermal	21,093		14,073		39,620		19,973
Total fuel expense	$	64,858	$	55,978	$	155,901	$	110,014
MWh generated
Coal	1,692		1,653		4,665		3,505
Natural gas and other thermal	684		410		1,176		610
Total MWh generated	2,376		2,063		5,841		4,115
Cost per MWh
Coal	$	25.87	$	25.35	$	24.93	$	25.69
Natural gas and other thermal	$	30.84	$	34.32	$	33.69	$	32.74
Weighted average, all sources	$	27.30	$	27.13	$	26.69	$	26.73

Fuel expense increased $8.9 million, or 16 percent, in the third quarter of 2013 and $45.9 million, or 42 percent, in the first nine months of 2013 compared to the same periods in 2012, due principally to the following factors:

•

Idaho Power's Langley Gulch natural gas-fired power plant came on line on June 29, 2012. Operation of the plant accounted for $4.2 million of the increase in fuel expense for the third quarter and $14.7 million for the first nine months of 2013. Idaho Power operated the plant primarily to serve peak load, to integrate intermittent resources, and for economic dispatch opportunities. During the third quarter and the first nine months of 2013, Idaho Power relied more on Langley Gulch and other gas plants to meet customer loads as a result of the decline in hydroelectric generation compared to the same periods in 2012.

•

generation from coal-fired facilities increased slightly for the third quarter of 2013 and increased 33 percent for the first nine months of 2013 compared to the same periods in 2012. During the quarter and first nine months, higher wholesale power prices and lower hydroelectric generation when compared with the same periods in the prior year increased Idaho Power's reliance on its coal-fired plants to meet customer loads.

PCA Mechanisms: Idaho Power's power supply costs (primarily purchased power and fuel, less off-system sales) can vary significantly from year to year. Volatility of power supply costs arises from factors such as weather conditions, wholesale market prices and volumes of power purchased and sold in the wholesale markets, Idaho Power's hydroelectric generation volume, thermal generation volumes and fuel costs, generation plant availability, and retail loads. To address the volatility of power supply costs, Idaho Power has PCA mechanisms in both the Idaho and Oregon jurisdictions. These mechanisms allow Idaho Power to recover from or refund to customers most of the fluctuations in power supply costs. In the Idaho jurisdiction, the PCA includes a cost or benefit sharing ratio that allocates the deviations in net power supply expenses between customers (95 percent) and the company (5 percent), with the exception of PURPA power purchases, which are allocated 100 percent to customers. Because of the PCA mechanisms, the primary financial impacts of power supply cost variations is that cash is paid out but recovery from customers does not occur until a future period, or cash that is collected is refunded to customers in a future period, resulting in fluctuations in operating cash flows from year to year. The table below presents the components of the Idaho and Oregon PCA mechanisms for the three and nine months ended September 30, 2013 and 2012.



	Three months ended September 30,						Nine months ended September 30,
	2013			2012			2013			2012
Idaho power supply cost deferral	$	(24,313	)	$	(36,320	)	$	(49,414	)	$	(25,709	)
Oregon power supply cost deferral	—			—			—			(1,523		)
Amortization of prior year authorized balances	17,353			(6,551		)	14,445			(9,842		)
Total power cost adjustment expense	$	(6,960	)	$	(42,871	)	$	(34,969	)	$	(37,074	)

The power supply deferrals represent the portion of the power supply cost fluctuations deferred under the PCA mechanisms. When actual power supply costs are greater than the amount forecasted in PCA rates, which was the case for the first nine

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months of 2013 and 2012, most of the excess cost is deferred. The amortization of the prior year’s balances represents the amounts being collected or refunded in the current PCA year that were deferred or accrued in the prior PCA year (the true-up component of the PCA).

Energy Efficiency Programs: Energy efficiency expenses decreased $2.3 million for the third quarter and increased $9.3 million for the first nine months of 2013 compared to the same periods in 2012. The decrease in the quarter is due to less utilization of these programs in the current year when compared to the same period in the prior year. The increase for the first nine months was related to an order issued by the IPUC approving Idaho Power's application to recover custom efficiency program incentive payments made between January 1, 2011 and June 1, 2013 through the energy efficiency rider. Based on the order, $14.3 million of energy efficiency program expense as well as other revenue were recognized in the second quarter of 2013.

Other Operations and Maintenance (O&M) Expenses: Other O&M expense decreased $5.5 million for the third quarter and $7.1 million for the first nine months of 2013 as compared to the same periods in 2012. The changes in other O&M expense were due to the following:

•

decreased sharing-related pension expense, which decreased $5.8 million for the quarter and the first nine months of 2013, as a result of additional pension expense recorded in 2012 related to a December 2011 regulatory settlement agreement, which requires sharing with Idaho customers of a portion of Idaho-jurisdiction earnings exceeding a 10.0 percent Idaho ROE. The settlement agreement is described further in "Regulatory Matters" in this MD&A. In accordance with the terms of the settlement agreement, $5.8 million was recorded as additional pension expense during the third quarter of 2012, while no such amount was recorded in the current year.


•	decreased hydro operating and maintenance costs, which decreased $1.4 million for the quarter and $2.0 million for the first nine months, resulting from water lease payments made in 2012 but not in 2013 due to unavailability of water subject to the leases in 2013.

Income Taxes

Income Tax Expense: IDACORP's and Idaho Power's income tax expense for the nine months ended September 30, 2013, compared to the same period in 2012, increased $35.3 million and $35.9 million, respectively. The increase in tax expense for the period is primarily a result of greater Idaho Power pre-tax earnings, as well as the recording of income tax expense in 2013 for an Idaho Power income tax accounting method change as compared to the recording of a tax benefit for a method change in 2012. For information relating to IDACORP's and Idaho Power's computation of income tax expense and estimated annual effective tax rate, see Note 2 - “Income Taxes” to the condensed consolidated financial statements included in this report.

Impact of New Tax Law: On September 13, 2013, the U.S. Treasury Department and IRS issued final regulations addressing the deduction or capitalization of expenditures related to tangible property. The regulations are generally effective for tax years beginning on or after January 1, 2014, and likely impact taxpayers in all industries. In connection with the issuance of the regulations, Idaho Power assessed and estimated the impact of a method change associated with the electric generation property portion of the capitalized repairs method it adopted in fiscal year 2010. Idaho Power intends to make this method change in either its 2013 or 2014 tax year and as such recorded a $4.6 million income tax expense in the third quarter of 2013 related to the cumulative method change adjustment that will be necessary to effectuate the change. As of September 30, 2013, IDACORP and Idaho Power do not expect that compliance with these regulations will have a material adverse impact on their financial positions, results of operations, or cash flows. Additionally, the companies do not expect this method change or the regulations to have a material adverse effect on Idaho Power’s on-going capitalized repairs tax deduction. However, given the complexity of the new regulations, as IDACORP and Idaho Power continue to evaluate the impact of the regulations the companies may be required to record additional tax impacts in future periods.

Additional Amortization of ADITC: Idaho Power's December 2011 settlement stipulation with the IPUC and other parties provided for the availability of additional amortization of ADITC if Idaho Power's actual Idaho ROE is below 9.5 percent in any calendar year from 2012 to 2014. For information relating to Idaho Power's 2011 settlement stipulation, see Note 3 - “Regulatory Matters” to the condensed consolidated financial statements included in this report. In accordance with the settlement stipulation, Idaho Power has a total of $45 million of additional ADITC amortization available for use in 2013 and 2014. As of the date of this report, Idaho Power does not expect to record additional ADITC amortization for 2013 based on its estimate of 2013 Idaho ROE.

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Bonus Depreciation: Bonus depreciation provides for the accelerated deduction of current capital expenditures from certain asset classes. For 2013, the deduction is equal to 50 percent of a qualifying asset's cost. Idaho Power has included an estimated bonus depreciation deduction in its current federal income tax provision.

LIQUIDITY AND CAPITAL RESOURCES

Overview and Recent Financing Activities

IDACORP's and Idaho Power's operating cash flows are driven principally by Idaho Power's sales of electricity and transmission capacity. Significant uses of cash flows from operations include the purchase of fuel and power, other operating expenses, capital expenditures, pension plan contributions, and interest. Operating cash flows can be significantly influenced by factors such as weather conditions, rates and the outcome of regulatory proceedings, and economic conditions. As fuel and purchased power are significant uses of cash, and at the same time their prices can be volatile and difficult to predict, Idaho Power has regulatory mechanisms in place that provide for the deferral and recovery of the majority of the fluctuation in those costs. However, if actual costs rise above the level allowed in retail rates, deferral balances increase (reflected as a regulatory asset), negatively affecting operating cash flows until such time as those costs, with interest, are recovered from customers. Idaho Power uses operating and capital budgets to control operating costs and optimize capital expenditures, and funds its liquidity needs for capital expenditures through cash flows from operations, debt offerings, commercial paper markets, credit facilities, and capital contributions from IDACORP. Idaho Power seeks to recover its operating costs and earn a return on its capital expenditures through rates, periodically filing for rate adjustments for recovery of operating costs and capital investments to provide the opportunity to align Idaho Power's earned returns with those allowed by regulators.

Idaho Power continues to make significant infrastructure investments. Idaho Power estimates that total capital expenditures will be between $805 million and $845 million over the period from 2013 (inclusive of amounts incurred in 2013) through 2015. A significant focus for 2013 has been to continue to control costs and to generate sufficient operating cash inflows to meet operating requirements, contribute to capital expenditure requirements, and pay dividends to shareholders. This will remain an area of focus in 2014.

As of November 1, 2013, IDACORP's and Idaho Power's access to debt, equity, and credit arrangements included:


•	their respective $125 million and $300 million revolving credit facilities, the termination dates for which have been extended to October 2018;


•	IDACORP's shelf registration statement filed with the SEC on May 22, 2013, which may be used for the issuance of debt securities and common stock, including up to 3 million shares of IDACORP common stock available for issuance under IDACORP's sales agency agreement executed in July 2013;


•	Idaho Power's shelf registration statement, filed with the SEC jointly with IDACORP on May 22, 2013, which may be used for the issuance of first mortgage bonds and debt securities; $500 million is available for issuance under a selling agency agreement executed in July 2013 and pursuant to state regulatory authority; and


•	IDACORP's and Idaho Power's issuance of commercial paper, which they may issue up to the available credit capacity under their respective credit facilities.

Following the payment at maturity of the first mortgage bonds due October 1, 2013, IDACORP and Idaho Power have no significant debt maturities until 2018. The companies believe they will be able to meet capital requirements during the remainder of 2013 and through 2014 with a combination of existing cash and operating cash flows generated by Idaho Power's utility business. IDACORP and Idaho Power would expect to meet any shortfall with existing credit facilities and address short-term liquidity through commercial paper markets. However, IDACORP and Idaho Power monitor capital markets with a view toward opportunistic debt and equity transactions where possible in light of future needs. Thus, IDACORP may make issuances of debt securities or make issuances of common stock under the existing continuous equity program, and Idaho Power may issue debt securities, during the remainder of 2013 or in 2014 if the companies believe terms available in the capital markets are favorable and that issuances would be appropriate in light of the companies' willingness to engage in opportunistic capital market transactions and the desire for prudent financial management. IDACORP and Idaho Power seek to maintain capital structures of approximately 50 percent debt and 50 percent equity, and maintaining this ratio influences IDACORP's and Idaho Power's debt and equity issuance decisions. As of September 30, 2013, IDACORP's and Idaho Power's capital structures were as follows:

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Effective July 1, 2012, IDACORP discontinued original issuances of common stock and instructed the plan administrators to use market purchases of IDACORP common stock for purposes of acquiring IDACORP common stock for the IDACORP, Inc. Dividend Reinvestment and Stock Purchase Plan and the Idaho Power Company Employee Savings Plan. However, IDACORP may determine at any time to resume original issuances of common stock under those plans. As noted above, an important component of that determination will be IDACORP's and Idaho Power's capital structure.

Idaho Power's issuance of $150 million of Series I first mortgage bonds in April 2013, combined with the issuance of $200 million in principal amount of Series I first mortgage bonds in August 2010 and $150 million in principal amount of Series I first mortgage bonds in April 2012, utilized in full the available amount under a registration statement Idaho Power filed with the SEC in May 2010 and under a selling agency agreement executed with ten banks in June 2010. During the first half of 2013 and into July 2013, Idaho Power obtained necessary state regulatory approvals, and IDACORP and Idaho Power filed a registration statement with the SEC, executed selling agency arrangements, and took other actions necessary to re-establish programs for IDACORP's potential sale of up to 3 million shares of IDACORP common stock from time to time in at-the-market offerings and Idaho Power's sale from time to time of up to $500 million in aggregate principal amount of first mortgage bonds. These arrangements are discussed in further detail below.

Operating Cash Flows

IDACORP’s and Idaho Power’s operating cash inflows for the nine months ended September 30, 2013 were $248 million and $234 million, respectively, increases of $66 million and $57 million, respectively, compared to the same period in 2012. With the exception of cash flows related to income taxes, IDACORP’s operating cash flows are principally derived from the operating cash flows of Idaho Power. Significant items that affected the comparability of the companies' operating cash flows in the first nine months of 2013 relative to the same period in 2012 were as follows:


•	income before income taxes increased $34 million and $35 million for IDACORP and Idaho Power, respectively;


•	Idaho Power made $30 million of cash contributions to its defined benefit pension plan in the first nine months of 2013, compared to $44.3 million of cash contributions during the first nine months of 2012;


•	cash outflows related to income taxes decreased by $1 million and increased by $8 million for IDACORP and Idaho Power, respectively. IDACORP had net income tax payments of $0.1 million in 2013 compared with $1 million in 2012. Idaho Power’s net payments to IDACORP for income tax were $9 million for the nine months ended September 30, 2013, compared with $1 million for the same period in 2012;


•	an $8 million reduction in non-cash earnings associated with the collection of AFUDC; and

•

changes in working capital balances due primarily to timing. Fluctuations in fuel inventories increased cash flows by $12 million as fuel on hand decreased by $7 million during the first nine months of 2013, due to increased thermal plant operation, compared with a $5 million increase in fuel inventories during the same period in 2012. Increases in receivable balances reduced cash flows by $24 million, primarily as a result of increased third quarter sales in 2013 compared to 2012. Other current liabilities increased cash flows by $12 million primarily due to customer deposits returned in 2012.

Investing Cash Flows

Investing activities consist primarily of capital expenditures related to new construction and improvements to Idaho Power’s generation, transmission, and distribution facilities. IDACORP’s and Idaho Power’s net investing cash outflows for the nine months ended September 30, 2013 were $160 million and $162 million, respectively. Investing cash outflows for 2013 and 2012 were primarily for construction of utility infrastructure needed to address Idaho Power’s aging plant and equipment and customer growth.

Financing Cash Flows

Financing activities provide supplemental cash for both day-to-day operations and capital requirements as needed. Idaho Power funds liquidity needs for capital investment, working capital, managing commodity price risk, and other financial commitments through cash flows from operations, debt offerings, commercial paper markets, credit facilities, and capital contributions from IDACORP. IDACORP funds its cash requirements, such as payment of taxes, capital contributions to Idaho Power, and non-utility expenses allocated to IDACORP, through cash flows from operations, commercial paper markets, sales of common stock, and credit facilities.

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IDACORP’s and Idaho Power's financing cash inflows for the nine months ended September 30, 2013 were $73 million and $90 million, respectively. The following are significant items that affected financing cash flows in the first nine months of 2013:

• on April 8, 2013, Idaho Power issued $75 million in principal amount of 2.50% first mortgage bonds due 2023 and $75 million in principal amount of 4.00% first mortgage bonds due 2043;


•	IDACORP and Idaho Power paid cash dividends of approximately $57 million; and


•	IDACORP had a net reduction of commercial paper borrowings of $17 million.

On October 1, 2013, Idaho Power used a portion of the net proceeds of its April 2013 sale of first mortgage bonds to satisfy its obligations upon maturity of $70 million in principal amount of 4.25% first mortgage bonds.

Financing Programs

Idaho Power First Mortgage Bonds: Idaho Power's issuance of long-term indebtedness is subject to the approval of the IPUC, OPUC, and Wyoming Public Service Commission (WPSC). Idaho Power's April 8, 2013 issuance of first mortgage bonds, together with issuances of first mortgage bonds in August 2010 and April 2012, utilized the full $500 million available under Idaho Power's registration statement filed with the SEC in May 2010 and the amount authorized for issuance by the IPUC, OPUC, and WPSC in orders issued during 2010. In light of the anticipated full use of the then-available amount, in February 2013 Idaho Power filed applications with the IPUC, OPUC, and WPSC to renew its long-term debt financing authority. In April 2013, Idaho Power received orders from the IPUC, OPUC, and WPSC authorizing Idaho Power to issue and sell from time to time up to $500 million in aggregate principal amount of debt securities and first mortgage bonds, subject to conditions specified in the orders. Authority from the IPUC is through April 9, 2015, though Idaho Power may request an extension by letter filed with the IPUC prior to that date. The OPUC's and WPSC's orders do not impose a time limitation for issuances, but the OPUC order does impose a number of other conditions, including a maximum interest rate limit of 7 percent.

On May 22, 2013, IDACORP and Idaho Power filed a joint shelf registration statement with the SEC, which became effective upon filing, for the offer and sale of, in the case of Idaho Power, an unspecified principal amount of its first mortgage bonds and debt securities. On July 12, 2013, Idaho Power entered into a Selling Agency Agreement with eight banks named in the agreement in connection with the potential issuance and sale from time to time of up to $500 million in aggregate principal amount of first mortgage bonds, Series J (Series J Notes), under Idaho Power’s Indenture of Mortgage and Deed of Trust, dated as of October 1, 1937, as amended and supplemented (Indenture). Also on July 12, 2013, Idaho Power entered into the Forty-seventh Supplemental Indenture, dated as of July 1, 2013, to the Indenture. The Forty-seventh Supplemental Indenture provides for, among other items, the issuance of up to $500 million in aggregate principal amount of Series J Notes pursuant to the Indenture. As of the date of this report, Idaho Power has not sold any first mortgage bonds or debt securities under the May 2013 shelf registration statement or Selling Agency Agreement and does not anticipate any issuances during the remainder of 2013.

The issuance of first mortgage bonds requires that Idaho Power meet interest coverage and security provisions set forth in the Indenture of Mortgage and Deed of Trust securing the bonds. Future issuances of first mortgage bonds are subject to satisfaction of covenants and security provisions set forth in the Indenture of Mortgage and Deed of Trust, market conditions, regulatory authorizations, and covenants contained in other financing agreements. The Indenture of Mortgage and Deed of Trust limits the amount of additional first mortgage bonds that Idaho Power may issue to the sum of (a) the principal amount of retired first mortgage bonds and (b) 60 percent of total unfunded property additions, as defined in the Indenture of Mortgage and Deed of Trust. As of September 30, 2013, Idaho Power could issue approximately $1.3 billion of additional first mortgage bonds based on retired first mortgage bonds and total unfunded property additions. However, the Indenture of Mortgage and Deed of Trust further limits the maximum amount of first mortgage bonds at any one time outstanding to $2.0 billion, and as a result the maximum amount of first mortgage bonds Idaho Power could issue as of September 30, 2013 was limited to approximately $339 million. Idaho Power may increase the $2.0 billion limit on the maximum amount of first mortgage bonds outstanding by filing a supplemental indenture with the trustee as provided in the Indenture of Mortgage and Deed of Trust.

IDACORP and Idaho Power Credit Facilities: IDACORP and Idaho Power have $125 million and $300 million credit facilities, respectively. Each of the credit facilities may be used for general corporate purposes and commercial paper back-up. IDACORP's facility permits borrowings under a revolving line of credit of up to $125 million at any one time outstanding, including swingline loans not to exceed $15 million at any time and letters of credit not to exceed $50 million at any time. IDACORP's facility may be increased, subject to specified conditions, to $150 million. Idaho Power's facility permits borrowings through the issuance of loans and standby letters of credit of up to $300 million at any one time outstanding, including swingline loans not to exceed $30 million at any one time. Idaho Power's facility may be increased, subject to specified conditions, to $450 million. The interest rates for any borrowings under the facilities are based on either (1) a floating

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rate that is equal to the highest of the prime rate, federal funds rate plus 0.5 percent, or LIBOR rate plus 1.0 percent, or (2) the LIBOR rate, plus, in each case, an applicable margin. The applicable margin is based on IDACORP's or Idaho Power's, as applicable, senior unsecured long-term indebtedness credit rating by Moody's Investors Service, Inc., Standard and Poor's Ratings Services, and Fitch Rating Services, Inc., as set forth on a schedule to the credit agreements. The companies also pay a facility fee based on the respective company's credit rating for senior unsecured long-term debt securities.

Each facility contains a covenant requiring each company to maintain a leverage ratio of consolidated indebtedness to consolidated total capitalization equal to or less than 65 percent as of the end of each fiscal quarter. In determining the leverage ratio, “consolidated indebtedness” broadly includes all indebtedness of the respective borrower and its subsidiaries, including, in some instances, indebtedness evidenced by certain hybrid securities (as defined in the credit agreement). “Consolidated total capitalization” is calculated as the sum of all consolidated indebtedness, consolidated stockholders' equity of the borrower and its subsidiaries, and the aggregate value of outstanding hybrid securities. At September 30, 2013, the leverage ratios for IDACORP and Idaho Power were 48 percent and 50 percent, respectively. IDACORP's and Idaho Power's ability to utilize the credit facilities is conditioned upon their 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. There are additional covenants, subject to exceptions, that prohibit certain mergers, acquisitions, and investments, restrict the creation of certain liens, and prohibit entering into any agreements restricting dividend payments from any material subsidiary. At September 30, 2013, IDACORP and Idaho Power believe they were in compliance with all facility covenants. Further, IDACORP and Idaho Power do not believe they will be in violation or breach of their respective debt covenants during the remainder of 2013, but were circumstances to arise that may alter that view management would seek to take appropriate action in an effort to mitigate any such issue.

The events of default under both facilities include, without limitation, non-payment of principal, interest, or fees; materially false representations or warranties; breach of covenants; bankruptcy or insolvency events; condemnation of property; cross-default to certain other indebtedness; failure to pay certain judgments; change of control; failure of IDACORP to own free and clear of liens the voting stock of Idaho Power; the occurrence of specified events or the incurring of specified liabilities relating to benefit plans; and the incurring of certain environmental liabilities, subject, in certain instances, to cure periods.

Upon any event of default relating to the voluntary or involuntary bankruptcy of IDACORP or Idaho Power or the appointment of a receiver, the obligations of the lenders to make loans under the applicable facility and to issue letters of credit will automatically terminate and all unpaid obligations will become due and payable. Upon any other event of default, the lenders holding greater than 50 percent of the outstanding loans or greater than 50 percent of the aggregate commitments (required lenders) or the administrative agent with the consent of the required lenders may terminate or suspend the obligations of the lenders to make loans under the facility and to issue letters of credit under the facility and/or declare the obligations to be due and payable. During an event of default under the facilities, the lenders may, at their option, increase the applicable interest rates then in effect and the letter of credit fee by 2.0 percentage points per annum. A ratings downgrade would result in an increase in the cost of borrowing, but would not result in a default or acceleration of the debt under the facilities. However, if Idaho Power's ratings are downgraded below investment grade, Idaho Power must extend or renew its authority for borrowings under its IPUC and OPUC regulatory orders.

While the credit facilities provide for an original maturity date of October 26, 2016, the credit agreements grant IDACORP and Idaho Power the right to request up to two one-year extensions, in each case subject to certain conditions. On October 12, 2012, IDACORP and Idaho Power executed First Extension Agreements with the lenders, extending the maturity date under both credit agreements to October 26, 2017. On October 8, 2013, IDACORP and Idaho Power executed Second Extension Agreements with the lenders, extending the maturity date under both credit agreements to October 26, 2018. No other terms of the credit agreements, including the amount of permitted borrowings under the credit agreements, were affected by the extensions.

Without additional approval from the IPUC, the OPUC, and the WPSC, the aggregate amount of short-term borrowings by Idaho Power at any one time outstanding may not exceed $450 million.

IDACORP Continuous Equity Program: As noted above, on May 22, 2013, IDACORP filed a shelf registration statement with the SEC, which became effective upon filing, for the offer and sale of an unspecified number of shares or dollar amount of IDACORP common stock. On July 12, 2013, IDACORP entered into a Sales Agency Agreement with BNY Mellon Capital Markets, LLC (BNYMCM), under which IDACORP may offer and sell up to 3 million shares of its common stock from time to time through BNYMCM as IDACORP's agent. The Sales Agency Agreement replaces a similar sales agency agreement, dated December 16, 2011, between IDACORP and BNYMCM, that provided for the sale of up to 3 million shares of IDACORP common stock. IDACORP did not sell any shares of its common stock under the December 2011 sales agency agreement. IDACORP has no obligation to sell any minimum number of shares under the Sales Agency Agreement. As of the

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date of this report, 3 million shares of IDACORP common stock remain available for sale under the Sales Agency Agreement with BNYMCM.

Commercial Paper: IDACORP and Idaho Power have commercial paper programs under which they issue unsecured commercial paper notes up to a maximum aggregate amount outstanding at any time not to exceed the available capacity under their respective credit facilities, described above. IDACORP's and Idaho Power's credit facilities are available to the companies to support borrowings under their commercial paper programs. The commercial paper issuances are used to provide an additional financing source for the companies' short-term liquidity needs. The maturities of the commercial paper issuances will vary, but may not exceed 270 days from the date of issue. Individual instruments carry a fixed rate during their respective terms, although the interest rates are reflective of current market conditions, subjecting the companies to fluctuations in interest rates.

Available Short-Term Liquidity: The table below outlines available short-term borrowing liquidity as of the dates specified.



	September 30, 2013						December 31, 2012
	IDACORP ⁽²⁾			Idaho Power			IDACORP ⁽²⁾			Idaho Power
Revolving credit facility	$	125,000		$	300,000		$	125,000		$	300,000
Commercial paper outstanding	(53,000		)	—			(69,700		)	—
Identified for other use ⁽¹⁾	—			(24,245		)	—			(24,245		)
Net balance available	$	72,000		$	275,755		$	55,300		$	275,755
⁽¹⁾ Port of Morrow and American Falls bonds that Idaho Power could be required to purchase prior to maturity under the optional or mandatory purchase provisions of the bonds, if the remarketing agent for the bonds is unable to sell the bonds to third parties.
⁽²⁾ Holding company only.

At November 1, 2013, IDACORP had no loans outstanding under its credit facility and $54.4 million of commercial paper outstanding, and Idaho Power had no loans outstanding under its credit facility and no commercial paper outstanding. The table below presents additional information about short-term commercial paper borrowing during the three and nine months ended September 30, 2013.



	Three months ended						Nine months ended
	September 30, 2013						September 30, 2013
	IDACORP ⁽¹⁾			Idaho Power			IDACORP ⁽¹⁾			Idaho Power
Commercial paper:
Period end:
Amount outstanding	$	53,000		$	—		$	53,000		$	—
Weighted average interest rate	0.35		%	—		%	0.35		%	—		%
Daily average amount outstanding during the period	$	59,557		$	—		$	63,758		$	2,954
Weighted average interest rate during the period	0.35		%	—		%	0.40		%	0.43		%
Maximum month-end balance	$	60,100		$	—		$	67,150		$	16,600

⁽¹⁾ Holding company only.

Impact of Credit Ratings on Liquidity and Collateral Obligations

IDACORP’s and Idaho Power’s access to capital markets, including the commercial paper market, and their respective financing costs in those markets, may depend on their respective credit ratings. There have been no changes to IDACORP's or Idaho Power's ratings or ratings outlook by Standard & Poor’s Ratings Services or Moody’s Investors Service from those included in the companies' Annual Report on Form 10-K for the year ended December 31, 2012. However, 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.

Idaho Power maintains margin agreements relating to its wholesale commodity contracts that allow performance assurance collateral to be requested of and/or posted with certain counterparties. As of September 30, 2013, Idaho Power had posted $0.5 million of performance assurance collateral. Should Idaho Power experience a reduction in its credit rating on its unsecured debt to below investment grade Idaho Power could be subject to requests by its wholesale counterparties to post additional performance assurance collateral, and counterparties to derivative instruments and other forward contracts could request immediate payment or demand immediate ongoing full daily collateralization on derivative instruments and contracts in net

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liability positions. Based upon Idaho Power’s energy and fuel portfolio and market conditions as of September 30, 2013, the amount of additional collateral that could be requested upon a downgrade to below investment grade was approximately $8.3 million. To minimize capital requirements, Idaho Power actively monitors its portfolio exposure and the potential exposure to additional requests for performance assurance collateral through sensitivity analysis.

Capital Requirements

Idaho Power's construction expenditures, excluding AFUDC, were $159.8 million during the nine months ended September 30, 2013. The table below presents Idaho Power's estimated cash requirements for construction, excluding AFUDC, for 2013 (including amounts incurred to-date during 2013) through 2015 (in millions of dollars).



	2013	2014	2015
Ongoing capital expenditures (excluding item listed below in this table)	$225-230	$230-240	$260-270
Jim Bridger plant selective catalytic reduction (SCR) equipment	5-10	45-50	40-45
Total	$230-240	$275-290	$300-315

Major Infrastructure Projects: Idaho Power is engaged in the development of a number of significant projects and has entered into arrangements with third parties concerning joint infrastructure development. The discussion below provides a summary of certain of these projects and notable developments since the discussion of these matters included in Part II, Item 7 - “MD&A - Capital Requirements” in IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2012. The discussion below should be read in conjunction with that report.

Jim Bridger Plant Environmental Controls and Related IPUC Filing: Idaho Power and the plant co-owners intend to install SCR equipment to reduce nitrogen oxide (NO_x) emissions at the Jim Bridger power plant, in order to comply with regional haze rules. The regional haze rules provide for installation and operation of SCR on unit 3 by 2015 and unit 4 by 2016. The rules provide for an equivalent technology for NO_x reductions on unit 2 by 2021 and unit 1 by 2022. Idaho Power estimates that the total cost for Idaho Power's share of the upgrades on units 3 and 4 is approximately $118 million, excluding AFUDC. While Idaho Power does not have estimates for the cost to install SCR on units 1 and 2, particularly given the technological changes that may occur prior to the installation date on those units, it is possible that the costs will be equal to, or greater than, the costs for units 3 and 4. The estimated 2013 capital expenditures for the SCR at the Jim Bridger plant units 3 and 4 of $5-10 million in the table above have decreased compared to the estimate included in IDACORP's and Idaho Power's Form 10-K for the year ended December 31, 2012, due to a delay of initiation of the project in 2013, which has resulted in reallocation to 2014 of some of the expenditures planned for 2013.

On June 28, 2013, Idaho Power filed an application with the IPUC requesting that the IPUC issue a Certificate of Public Convenience and Necessity (CPCN) related to the SCR investments planned for units 3 and 4. Idaho Power's CPCN application requests that the IPUC provide Idaho Power with authorization and a binding commitment to provide rate base treatment for Idaho Power's share of the capital investment in the SCRs in the amount of approximately $130 million (including AFUDC), with approximately $63 million authorized for cost recovery on or after January 1, 2016 and approximately $67 million authorized for cost recovery on or after January 1, 2017. Filing of the CPCN is intended to allow the IPUC to review the prudence of the investment in SCR prior to Idaho Power's incurring the bulk of the associated expenses. Idaho Power requested in its application that the IPUC issue an order by the end of November 2013. A determination from the IPUC is pending.

Boardman-to-Hemingway Line: The Boardman-to-Hemingway line, a proposed 300-mile, 500-kV transmission project between a station near Boardman, Oregon and the Hemingway station near Boise, Idaho, would provide transmission service to meet future resource needs. The Boardman-to-Hemingway line was included in the preferred resource portfolio in Idaho Power’s 2013 IRP. In January 2012, Idaho Power entered into a joint funding agreement with PacifiCorp and the Bonneville Power Administration to jointly pursue permitting of the project. The joint funding agreement provides that Idaho Power's interest in the permitting phase of the project would be approximately 21 percent, and that during future negotiations relating to construction of the transmission line Idaho Power would seek to retain that percentage interest in the completed project. Assuming both other participants fund their full share of the total cost of the permitting phase of the project, Idaho Power's estimated share of the cost of the permitting phase of the project is approximately $15 million, including AFUDC. Total cost estimates for the project are between $890 million and $940 million, including AFUDC. This cost estimate excludes the impacts of inflation and price changes of materials and labor resources that may occur following the date of the estimate. Idaho Power's share of the permitting phase of the project (excluding AFUDC) is included in the capital requirements table above. Construction costs beyond the permitting phase are not included in the table above.

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The permitting phase of the Boardman-to-Hemingway project is subject to review and approval by the U.S. Bureau of Land Management (BLM) (as the lead federal agency on behalf of other federal agencies), the U.S. Forest Service, and the Oregon Department of Energy. Idaho Power currently expects the BLM to issue a draft environmental impact statement (EIS) for the project during the first half of 2014. The environmental requirements for, and application of environmental regulations (particularly relating to sage grouse) to, the siting process have changed significantly since commencement of the project, making identification of a suitable route for the transmission line more difficult. This has resulted in project delays and increased permitting costs. The completion date of the project is subject to these siting, permitting, and regulatory approval requirements, as well as in-service date requirements of the parties electing to construct the line, the terms of any resulting joint construction agreements, and other factors. In light of the delays and siting impediments that have occurred and are expected, Idaho Power is unable to accurately determine an approximate in-service date for the line but expects the in-service date would be in 2020 or beyond.

The permitting-related delays and changing environmental requirements will result in increased project costs, with the magnitude of the increase depending largely on the length of the delay and the line route ultimately approved. The regulatory outcomes associated with the siting process can also affect the ultimate feasibility and cost effectiveness of the project.

The Boardman-to-Hemingway project continues to be Idaho Power’s preferred power supply resource project. However, as a component of prudent utility planning, Idaho Power evaluates its resource needs on a regular basis, both inside and outside of the integrated resource planning process required by regulators. This planning process includes a review of projected available power supply resources and demand response programs against projected load demand. Projecting future loads with precision is difficult, and actual loads could exceed estimates, particularly if new large-load customers are added to Idaho Power’s system or if economic growth exceeds projections. If Idaho Power believes there will be power supply deficiencies prior to the Boardman-to-Hemingway project’s in-service date that cannot be cost-effectively met in other ways (such as through purchased power and use of demand response programs), in order to reliably meet loads Idaho Power would be required to pursue other power supply options in advance of the Boardman-to-Hemingway in-service date, as a supplement to the Boardman-to-Hemingway project. As development of new power supply infrastructure involves substantial lead-time, Idaho Power is currently performing an enhanced review of other power supply resource options, potentially including an additional gas-fired generation facility in Idaho Power’s resource portfolio.

Idaho Power has expended approximately $52 million on the Boardman-to-Hemingway project through September 30, 2013. Pursuant to the terms of the joint funding arrangements, approximately $26 million of that amount must be reimbursed to Idaho Power by joint permitting participants for expenses Idaho Power incurred, $20 million of which Idaho Power had received as of September 30, 2013. An additional $14 million is subject to reimbursement at a later date from the joint permitting participants, assuming their continued participation in the project, for expenses Idaho Power incurred prior to execution of the joint funding arrangements. Idaho Power plans to seek recovery of its share of project costs through the regulatory process.

Gateway West Line: Idaho Power and PacifiCorp are pursuing the joint development of the Gateway West project, a 500-kV transmission project between a station located near Douglas, Wyoming and the Hemingway station. In January 2012, Idaho Power and PacifiCorp entered a new joint funding agreement for permitting of the project. Idaho Power's estimated cost for the permitting phase of the Gateway West project is approximately $26 million, including AFUDC. As of the date of this report, Idaho Power estimates the total cost for its share of the project (including both permitting and construction) to be between $150 million and $300 million, including AFUDC. Idaho Power's share of the permitting phase of the project (excluding AFUDC) is included in the capital requirements table above. Construction costs are not included in the table above.

The BLM released for public comment its final EIS on April 26, 2013, and its current schedule provides for a record of decision to be issued before the end of 2013. The final EIS contemplates a potential phased decision that would allow additional time for stakeholders to provide further input on some of the segments, particularly those with social or environmental issues discussed in the final EIS. A phased approach may result in the need for additional analysis before a record of decision for the phased-in segment or segments in question would be issued, which could increase project costs.

Filing of 2013 Integrated Resource Plan and Preferred Portfolio: The IPUC and OPUC require that Idaho Power biennially prepare an IRP. The IRP seeks to forecast Idaho Power's loads and resources for a 20-year period, analyzes potential supply-side and demand-side resource options, and identifies potential near-term and long-term actions. On June 28, 2013, Idaho Power filed its 2013 IRP with the IPUC and OPUC. The 2013 IRP projects a median annual average load growth rate of 1.1 percent over the next 20 years and a median annual average peak-hour load growth rate of 1.4 percent over the 20-year period. As previously disclosed, these long-term growth assumptions include several changes relative to the growth forecasts in the 2011 IRP, including (a) changes in expectations surrounding economic conditions, (b) anticipated electricity price increases incorporating impacts of carbon legislation, (c) loss of anticipated load from the Hoku Materials, Inc. special customer contract, and (d) per the directive of the OPUC, and notwithstanding the level of historic and recent service inquiries from potential new large-load customers and Idaho Power's economic development initiatives, the elimination of load from an anticipated but

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unidentified large-load customer that had been included in the 2011 IRP. There is a considerable degree of uncertainty in the growth forecast used for long-term resource planning purposes, and Idaho Power's actual supply-side resource needs could change considerably from those outlined in the 2013 IRP.

The 2013 IRP also includes a preferred resource portfolio, which identifies the Boardman-to-Hemingway transmission line as the major near-term supply-side resource addition. See "Boardman-to-Hemingway Line" above for a discussion of the delayed in-service date for the project, and the potential implications of the delay, based on events occurring following Idaho Power's filing of the 2013 IRP. The 2013 IRP also identifies a number of significant plant upgrades and environmental control technology installations.

Notwithstanding the power supply portfolios included in the 2013 IRP, depending on changes in load and project timing Idaho Power may seek to accelerate, scale back, modify, or eliminate projects, or seek alternative projects, to accommodate anticipated resource needs and to help ensure its ability to provide reliable electric service and meet load and transmission capacity obligations. Scaling back or eliminating a project due to regulatory challenges or other factors influencing the feasibility of a project may result in Idaho Power pursuing one or more separate, more costly projects. For instance, if Idaho Power were unable to secure permits or joint funding commitments to develop transmission infrastructure necessary to serve loads, it may terminate those projects and, as an alternative, develop additional generation facilities within areas where Idaho Power has available transmission capacity. Termination of a project carries with it the potential for a write-off of all or a significant portion of the costs associated with the project, largely dependent on decisions of regulators as to the prudence of project expenditures.

Coal Unit Environmental Investment Analysis: In connection with its IRP process, in February 2013 Idaho Power filed with the IPUC and OPUC the results of cost studies and scenario analyses conducted to assess the potential future investments necessary for the continued operation of the Jim Bridger and Valmy coal-fired generation facilities. The Boardman plant was not included in the study because of the existing schedule to cease coal-fired operations at that plant by the end of 2020. In the analysis, the cost of future compliance was compared to the cost of replacement generation capacity provided by combined-cycle combustion turbine technology and conversion of the units to natural gas. Because of the uncertain nature of many of the future requirements, the analysis was performed under a range of fuel pricing assumptions, carbon cost assumptions, plant upgrade and retirement costs, environmental regulation assumptions, and replacement costs. Idaho Power concluded in its study that the Jim Bridger and Valmy plants should be retained in its resource portfolio and supports planned investments in environmental controls at those plants. This is particularly true in light of the desire to maintain a diversified portfolio of generation assets and fuel diversity that can mitigate risk associated with increases in natural gas prices. However, the study also concluded that in the event significant additional operating and maintenance or capital expenditures are necessary at the Valmy plant as a result of new environmental requirements, Idaho Power will conduct a further review to determine whether such investments are economically appropriate, and whether conversion of the facility to a natural-gas fired plant would be appropriate. Most significant actions related to the plant, including conversion to natural gas as a fuel source, would in most instances require consent of the Valmy plant's co-owner.

Valmy Coal-Fired Plant Third-Party Announcement: In April 2013, a bill introduced in the Nevada legislature, together with associated third-party news releases, outlined a proposed plan by NV Energy, Inc. to accelerate the retirement or divestiture of its coal-fired generating facilities and the construction of natural gas and renewable generation facilities. The Nevada legislature ultimately adopted legislation relating to NV Energy's resource mix. Idaho Power and NV Energy are fifty-percent co-owners of the Valmy coal-fired power plant in Nevada. Communications surrounding the legislation suggested that NV Energy may seek to divest its ownership in its share of the Valmy plant by 2025, subject to a number of conditions. Idaho Power's consent is required prior to NV Energy taking certain actions related to the Valmy plant, including retirement of the plant. Idaho Power has been working with NV Energy on cost-effective long-term solutions for the Valmy plant.

Pension Plan Funding: From 2010 to 2012 Idaho Power contributed $123 million to its defined benefit pension plan. Although Idaho Power has no minimum required cash contribution for 2013, the company made discretionary contributions of $30 million in the first nine months of 2013. Idaho Power also expects to make additional significant cash contributions to the pension plan in future years.

Contractual Obligations

During the nine months ended September 30, 2013, IDACORP's and Idaho Power's contractual obligations, outside the ordinary course of business, did not change materially from the amounts disclosed in their Annual Report on Form 10-K for the year ended December 31, 2012, except for the following:

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•	the termination of four power purchase agreements due to either uncured breach by the respective counterparties or pursuant to IPUC-approved settlement arrangements between the parties. Termination of the agreements reduced Idaho Power's contractual payment obligations by approximately $322 million over the 15-year to 20-year lives of the contracts; and


•	on April 8, 2013, Idaho Power issued $75 million in principal amount of 2.50% first mortgage bonds, Series I, maturing on April 1, 2023, and $75 million in principal amount of 4.00% first mortgage bonds, Series I, maturing on April 1, 2043.

Subsequent to the end of the third quarter, on October 4, 2013, Idaho Power entered into four wind power purchase agreements with combined estimated contractual obligations of $200 million over the 20-year lives of the agreements.

Dividends

The amount and timing of dividends paid on IDACORP’s common stock are within the discretion of IDACORP’s board of directors. IDACORP's board of directors reviews the dividend rate periodically to determine its appropriateness in light of IDACORP’s current and long-term financial position and results of operations, capital requirements, rating agency considerations, contractual and regulatory restrictions, legislative and regulatory developments affecting the electric utility industry in general and Idaho Power in particular, competitive conditions, and any other factors the board of directors deems relevant. The ability of IDACORP to pay dividends on its common stock is dependent upon dividends paid to it by its subsidiaries, primarily Idaho Power. IDACORP has a dividend policy that provides for a target long-term dividend payout ratio of between 50 and 60 percent of sustainable IDACORP earnings, with the flexibility to achieve that payout ratio over time and to adjust the payout ratio or to deviate from the target payout ratio from time to time based on the various factors that drive the IDACORP board of directors' dividend decisions. Notwithstanding the dividend policy adopted by the IDACORP board of directors, the dividends IDACORP pays remain in the discretion of the board of directors who, when evaluating the dividend amount, will continue to take into account the foregoing factors, among others. For additional information relating to IDACORP and Idaho Power dividends, including additional restrictions on IDACORP’s and Idaho Power’s payment of dividends, see Note 6 – “Common Stock” to the condensed consolidated financial statements included in this report.

In January 2012, IDACORP's board of directors voted to increase the quarterly dividend from $0.30 to $0.33 per share of IDACORP common stock. In September 2012, IDACORP's board of directors voted to increase the quarterly dividend to $0.38 per share of IDACORP common stock. In September 2013, IDACORP's board of directors voted to increase the quarterly dividend to $0.43 per share of IDACORP common stock.

Contingencies and Proceedings

IDACORP and Idaho Power are involved in a number of litigation, alternative dispute resolution, and administrative proceedings, and are subject to claims and legal actions arising in the ordinary course of business, that could affect their future results of operations and financial condition. Certain legal or administrative proceedings to which IDACORP or Idaho Power are parties or are otherwise involved, and certain actual or potential legal claims pertaining to Idaho Power, are described in Note 9 - "Contingencies" to the condensed consolidated financial statements included in this report. Except where noted in Note 9, in many instances IDACORP and Idaho Power are unable to predict the outcomes of the matters or estimate the impact the proceedings may have on their financial positions, results of operations, or cash flows.

Idaho Power is also actively monitoring various environmental regulations that may have a significant impact on its future operations. Given uncertainties regarding the outcome, timing, and compliance plans for these environmental matters, Idaho Power is unable to determine the financial impact of these regulations but does believe that future capital investment for infrastructure and modifications to its electric generating facilities to comply with these regulations could be significant.

Off-Balance Sheet Arrangements

IDACORP's and Idaho Power's off-balance sheet arrangements have not changed materially from those reported in MD&A in IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2012.

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REGULATORY MATTERS

Introduction

As a regulated utility, many of Idaho Power's fundamental business decisions are subject to the approval of governmental agencies. 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 retail customers. Idaho Power is also under the regulatory jurisdiction of the IPUC, the OPUC, and the WPSC as to the issuance of debt and equity securities. 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 uses general rate cases, cost adjustment mechanisms, and subject-specific filings to recover its costs of providing service and the costs of its energy efficiency and demand-side management programs, seeking to earn a return on investment where permitted by regulators. Idaho Power remains focused on communicating with regulators the necessity of investments to better serve its customers, the prudence of the costs incurred, and the importance of a reasonable return on investment for IDACORP's shareholders.

Idaho Power filed general rate cases in Idaho and Oregon during 2011, as well as a single-issue rate case for the Langley Gulch power plant in Idaho and Oregon in 2012. These significant rate cases resulted in the resetting of base rates in both Idaho and Oregon during 2012. The outcomes of these and other significant proceedings are described in part in this report and further in IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2012. In addition to the discussion below, which includes notable recent regulatory rate adjustments and mechanisms (including developments since the discussion of these matters in IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2012), refer to Note 3 - “Regulatory Matters” to the condensed consolidated financial statements included in this report for additional information and updates relating to Idaho Power's regulatory matters and recent regulatory filings and orders, including proceedings that impact the comparability of IDACORP's and Idaho Power's financial results during the first nine months of 2013 relative to the first nine months of 2012.

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Notable Rate Filings and Orders During 2013

During 2013 to-date, Idaho Power has received orders in notable pending rate matters summarized in the table below.



Description	Status	Estimated Rate Impact ⁽¹⁾	Notes
Power Cost Adjustment Mechanism - Idaho Filing	The IPUC issued an order on May 31, 2013 authorizing Idaho Power's requested rate increase.	$140.4 million PCA rate increase for the period from June 1, 2013 to May 31, 2014	The potential earnings impact of rate increases and decreases associated with the Idaho PCA mechanism is largely offset by associated increases and decreases in actual power supply costs and amortization of deferred power supply costs under the Idaho PCA mechanism. Idaho Power's proposal to move a portion of recovery of net power supply expenses from the Idaho PCA mechanism to base rates is also discussed below.
Fixed Cost Adjustment - Idaho Filing	The IPUC issued an order on May 22, 2013 authorizing Idaho Power's requested rate decrease.	$1.4 million decrease in the FCA for the period from June 1, 2013 to May 31, 2014	The FCA is designed to remove Idaho Power’s disincentive to invest in energy efficiency programs by separating (or decoupling) the recovery of fixed costs from the volumetric kilowatt-hour charge and linking it instead to a set amount per customer. The FCA is adjusted each year to collect, or refund, the difference between the authorized fixed-cost recovery amount and the actual fixed costs recovered by Idaho Power during the year.
Custom Efficiency Program - Idaho Order	After denying Idaho Power's application to amortize and collect a portion of the asset, the IPUC separately approved an application to recover incentive payments through the energy efficiency rider mechanism.	None - the IPUC's order did not authorize a change in rates.	On October 31, 2012, Idaho Power filed an application with the IPUC requesting authorization to begin amortization and collection of the 2011 portion of the regulatory asset associated with its custom efficiency program incentive payments (a demand-side management program) over a four-year period, equal to approximately $2.9 million per year, including a carrying charge.The IPUC denied that application. On April 15, 2013, Idaho Power filed an application with the IPUC requesting an accounting order authorizing Idaho Power to transfer the custom efficiency program incentive payments from a separate regulatory asset to the energy efficiency rider regulatory asset, and begin collecting program payments through that mechanism. The IPUC approved that application on June 12, 2013.

⁽¹⁾The annual amount collected in rates is typically not recovered on a straight-line basis (i.e., 1/12th per month), and is instead recovered in proportion to general business sales volumes.

Idaho ROE Support in 2013 and 2014 from December 2011 Regulatory Settlement Stipulation

In December 2011, the IPUC issued an order, separate from the then-pending Idaho general rate case proceeding, approving a settlement stipulation that provides as follows:


•	if Idaho Power's actual Idaho ROE for 2012, 2013, or 2014 is less than 9.5 percent, then Idaho Power may amortize additional ADITC to help achieve a minimum 9.5 percent Idaho ROE in the applicable year. Idaho Power would be permitted to amortize additional ADITC in an aggregate amount up to $45 million over the three-year period;

•

if Idaho Power's actual Idaho ROE for 2012, 2013, or 2014 exceeds 10.0 percent, the amount of Idaho Power's Idaho- jurisdictional earnings exceeding a 10.0 percent and up to and including a 10.5 percent Idaho ROE for the applicable year would be shared equally between Idaho Power and its Idaho customers in the form of a rate reduction to become effective at the time of the subsequent year's PCA adjustment; and


•	if Idaho Power's actual Idaho ROE for 2012, 2013, or 2014 exceeds 10.5 percent, the amount of Idaho Power's Idaho- jurisdictional earnings exceeding a 10.5 percent Idaho ROE for the applicable year would be allocated 75 percent to Idaho Power's Idaho customers as a reduction to the pension regulatory asset and 25 percent to Idaho Power.

The December 2011 settlement stipulation provides that the Idaho ROE thresholds (9.5 percent, 10.0 percent, and 10.5 percent) will be automatically adjusted prospectively in the event the IPUC approves a change to Idaho Power's authorized return on equity as part of a general rate case proceeding seeking a rate change effective prior to January 1, 2015.

As Idaho Power's 2012 Idaho ROE exceeded 9.5 percent, Idaho Power did not amortize additional ADITC in 2012. While providing no assurance that Idaho Power will obtain a 9.5 percent Idaho ROE in any of the years, IDACORP and Idaho Power believe the ability to amortize additional ADITC under the settlement stipulation provides an element of earnings stability for 2013 and 2014.

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Idaho Power's 2012 Idaho ROE exceeded 10.5 percent, triggering both sharing components of the December 2011 settlement stipulation. For the full year 2012, Idaho Power recorded a $7.2 million provision against current revenues, to be refunded to customers through a future rate reduction, and an additional $14.6 million of pension expense, to benefit Idaho customers by reducing the amount of deferred pension expense that will be collected from customers in the future. The $7.2 million rate adjustment was included in the annual PCA filing Idaho Power made in April 2013 and is in effect for the period from June 1, 2013 to May 31, 2014.

Based on Idaho Power's September 30, 2013 estimate of full-year 2013 Idaho ROE, which Idaho Power anticipates will exceed 10.0 percent, Idaho Power has recorded a $6.2 million provision for sharing with customers pursuant to the terms of the settlement stipulation.

Change in Deferred Net Power Supply Costs and the Power Cost Adjustment Mechanism

Deferred power supply costs represent certain differences between Idaho Power's actual net power supply costs and the costs included in its retail rates, the latter being based on annual forecasts of power supply costs. Deferred power supply costs are recorded on the balance sheets for future recovery or refund through customer rates. The table below summarizes the change in deferred net power supply costs during the nine months ended September 30, 2013.



	Idaho			Oregon ⁽¹⁾			Total
Balance at December 31, 2012	$	34,571		$	8,331		$	42,902
Current period net power supply costs deferred	49,414			—			49,414
Prior amounts returned (recovered) through rates	1,238			(1,741		)	(503		)
SO₂ allowance and renewable energy certificate (REC) sales	(441		)	(12		)	(453		)
Revenue sharing liability applied to PCA true-up mechanism	(7,172		)	—			(7,172		)
Interest and other	420			387			807
Balance at September 30, 2013	$	78,030		$	6,965		$	84,995

⁽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 $3 million). Deferrals are amortized sequentially.

Idaho Power's PCA mechanisms in its Idaho and Oregon jurisdictions address the volatility of power supply costs and provide for annual adjustments to the rates charged to retail customers. The PCA mechanism and associated financial impacts are described in "Results of Operations" in this MD&A.

On April 15, 2013, Idaho Power filed an application with the IPUC requesting a $140.4 million increase in Idaho PCA rates, effective for the 2013-2014 PCA collection period from June 1, 2013 to May 31, 2014. To lessen the single-year rate impact on customers of the PCA rate increase, Idaho Power's application included a proposal to defer a portion of the PCA rate increase for inclusion in the June 1, 2014 to May 31, 2015 PCA collection period. On May 31, 2013, the IPUC issued an order authorizing a $140.4 million increase in PCA rates, effective for the 2013-2014 PCA collection period. The IPUC's order did not defer any amount to the 2014-2015 PCA collection period. The significant PCA rate increase was driven by the following:


•	lower than forecast hydroelectric generation and market energy prices for excess power that Idaho Power sold during the 2012-2013 PCA year (April 1, 2012 through March 31, 2013), and increases in power supply costs associated with lower hydroelectric generation;


•	forecast lower market energy prices for excess power that Idaho Power sells;


•	decreased revenue sharing with customers compared to revenue sharing included in the prior PCA rates; and


•	forecast below-average hydroelectric generating conditions during the 2013-2014 PCA year (April 1, 2013 through March 31, 2014).

With the exception of power supply expenses incurred under PURPA and certain demand response program costs that are passed through to customers substantially in full, the PCA allows Idaho Power to pass through to customers 95 percent of the differences in actual net power supply expenses as compared to base power supply expenses, whether positive or negative. Thus, the primary financial statement impact of power supply cost deferrals is that cash is paid out but recovery of those costs from customers does not occur until a future period, impacting operating cash flows from year to year.

Idaho Power's currently approved normalized level of net power supply expenses included in Idaho jurisdictional base rates were established in 2010. Since 2010, many of the individual cost and revenue components of these "base level" net power supply expenses have changed significantly and permanently. These ongoing and permanent costs are currently being recovered through the Idaho PCA annually. The primary factors contributing to the increase in net power supply expenses were

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increased energy purchases pursuant to PURPA, lower surplus energy sales revenue resulting from lower energy market prices, and the elimination of anticipated offsetting revenues from the Hoku Materials, Inc. special contract. On November 1, 2013, Idaho Power filed an application with the IPUC requesting approval of new normalized or “base level” power supply expense, which if approved would reflect in base rates approximately $106 million of such expenses, effective June 1, 2014. This would remove the Idaho-jurisdictional portion of those expenses from collection via the Idaho PCA mechanism and instead result in Idaho Power collecting that portion in base rates. Approval of the application would result in no net change in the amount collected through base rates and the PCA mechanism in the aggregate. Idaho Power expects, however, that approval of the application would decrease the amount of any base rate increase requested in Idaho Power's next general rate case application filed with the IPUC.

Authorization of Temporary Suspension of Two Demand Response Programs

Idaho Power has in place a number of demand response programs designed to reduce peak summer demand through the voluntary interruption of central air conditioners for residential customers, interruption of irrigation pumps, and reduction of commercial and industrial demand through a third-party demand response aggregator. In December 2012, Idaho Power filed an application with the IPUC requesting the temporary suspension during 2013 of two of the demand response programs. Included with the application was a discussion of the results of preliminary studies conducted in connection with Idaho Power's 2013 IRP, including a load and resource balance for the 2013 to 2032 period. After application of a number of assumptions, under a scenario that excludes demand response programs and power capacity from the proposed Boardman-to-Hemingway 500-kV transmission line, the peak-hour load and resource balance indicates no peak-hour load deficit until 2016. Under those assumptions the need for near-term peak-hour resources like demand response programs or new near-term supply-side resources does not exist.

On April 2, 2013, the IPUC issued an order approving a settlement stipulation providing for the temporary suspension of two of Idaho Power's three demand response programs during 2013 and scheduling workshops to evaluate those programs for use in 2014 and thereafter. Following several public workshops, on October 2, 2013, Idaho Power filed with the IPUC a settlement agreement executed by Idaho Power and several interested parties that provided for the reinstatement of the two suspended demand response programs in 2014 and beyond, and continuation of the third program. The settlement agreement includes several program changes that would decrease program costs through lower incentive payments and increase Idaho Power's operational flexibility. Idaho Power is awaiting a decision from the IPUC on the settlement agreement. The OPUC has opened a similar docket for potential modification of demand response programs in the Oregon jurisdiction.

Filing of 2012 Demand-Side Management Annual Report

On March 15, 2013, Idaho Power filed with the IPUC its demand-side management annual report for 2012. The report states that Idaho Power's total expenditures on demand-side management-related activities increased from $46.3 million in 2011 to $49.3 million in 2012. The energy savings exclusively from Idaho Power's energy efficiency programs in 2012 were over 152,486 MWh, and demand reduction available from demand response programs reached 438 MW in 2012.

Federal Open Access Transmission Tariff Rate

Idaho Power uses a formula rate for transmission service provided under its OATT, which allows transmission rates to be updated annually based on financial and operational data Idaho Power files with the FERC. On August 29, 2013, Idaho Power filed with the FERC and publicly posted its annual final informational filing reflecting a transmission rate of $22.80 per kW-year, to be effective for the period from October 1, 2013 to September 30, 2014. Idaho Power's filing was based on a net annual transmission revenue requirement of $118.2 million. The transmission rate in effect from October 1, 2012 to September 30, 2013 was $21.32 per kW-year based on a net annual transmission revenue requirement of $108.4 million.

Transmission Coordination and FERC Order 1000

The FERC has encouraged increased coordination intended to capture power transmission efficiencies that might otherwise be gained through the formation of a Regional Transmission Organization (RTO) such as an independent system operator. While it has not mandated RTO formation, the FERC has issued orders and made public statements indicating its support for the development and formation of independent organizations, including those intended to implement a number of regional transmission planning coordination requirements.

In 2011, FERC issued Order 1000, which reforms its electric transmission planning and cost allocation requirements for public utility transmission providers. This final rule requires that transmission providers develop and implement regional and interregional planning and cost allocation processes. These processes are intended to, among other things, improve

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coordination between neighboring transmission providers and regions and to determine if there are more efficient or cost effective solutions to transmission needs. Order 1000 requires development of cost allocation processes that would seek to allocate costs to beneficiaries of a transmission project in a manner that is roughly commensurate with benefits. These procedural changes will require increased time and participation on a regional and interregional level by Idaho Power. The cost allocation processes of a regional transmission facility may assign some costs to other beneficiaries and may result in a change in costs attributable to Idaho Power and its customers.

Another significant change is the removal of the federal right of first refusal (ROFR) provision contained in tariffs or agreements with respect to transmission facilities selected in a regional transmission plan for purposes of cost allocation. Incumbent public utility transmission providers no longer have a federal ROFR to build, own, and operate large-scale regional transmission projects when they seek regional cost allocation. Idaho Power has filed its tariff revisions with the FERC for the regional and interregional portions of Order 1000 requirements. On May 17, 2013, the FERC issued an order accepting, with some modifications, Idaho Power's regional filing, subject to Idaho Power submitting additional compliance filings with the FERC, which Idaho Power made in September 2013. As of the date of this report, Idaho Power is unable to determine what impacts this order may have on its future electric transmission service costs or charges.

Renewable and Other Energy Contracts, Renewable Energy Certificates, and Emission Allowances

Sale of Renewable Energy Certificates: Pursuant to an IPUC order, Idaho Power continues to sell its near-term RECs and is returning to customers their share (shared 95 percent with customers in the Idaho jurisdiction) of those proceeds through the PCA. Idaho Power's REC sales were $0.5 million for the nine months ended September 30, 2013 as compared with $3.6 million for the same period of 2012.

Renewable and Other Energy Contracts: Idaho Power purchases wind power from both CSPP and non-CSPP facilities, including its largest non-CSPP wind power project -- the Elkhorn Valley wind project with a 101 MW nameplate capacity. As of September 30, 2013, Idaho Power had contracts to purchase energy from on-line CSPP wind power projects with a combined nameplate rating of 577 MW. In addition to its power purchase arrangements with wind power generators, Idaho Power has contracts for the purchase of power from other CSPP and non-CSPP renewable generation sources, such as biomass, small hydroelectric projects, and two geothermal projects. As of September 30, 2013, Idaho Power had the number and nameplate capacity of signed CSPP-related agreements with terms ranging from one to 35 years set forth in the following table.



Status	Number of CSPP Contracts	Nameplate Capacity (MW)
On-line as of September 30, 2013	102	774
Contracted and projected to come on-line by year-end 2014	1	5

Pursuant to the requirements of Section 210 of PURPA, the IPUC and OPUC have each issued orders and rules regulating Idaho Power's purchase of power from CSPP facilities. A key component of the PURPA power purchase contracts is the energy price contained within the agreements. Regulatory-mandated execution of PURPA agreements may result in Idaho Power acquiring energy it does not need at above wholesale market prices and require additional operational integration measures, thus increasing costs to Idaho Power's customers. Substantially all PURPA power purchase costs are recovered through base rates and Idaho Power's power supply cost mechanisms, and thus the primary impact of PURPA agreements is on customer rates.

Relicensing of Hydroelectric Projects

Costs for the relicensing of Idaho Power's hydroelectric projects are recorded in construction work in progress until new multi-year licenses are issued by the FERC, at which time the charges are 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 $174.7 million for the HCC, Idaho Power's largest hydroelectric complex and a major relicensing effort, were included in construction work in progress at September 30, 2013. As of the date of this report, the IPUC authorizes Idaho Power to include in its Idaho jurisdiction rates approximately $6.5 million annually ($10.7 million grossed up for income taxes) of AFUDC relating to the HCC relicensing project. Collecting these amounts now will reduce the amount collected in the future once the HCC relicensing costs are approved for recovery in base rates. Through September 30, 2013, Idaho Power had collected $36.4 million ($55.9 million grossed up for income taxes) of AFUDC related to the HCC relicensing project through customer rates.

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ENVIRONMENTAL MATTERS

Overview

Idaho Power is subject to a broad range of federal, state, regional, and local laws and regulations designed to protect, restore, and enhance the environment, including the Clean Air Act (CAA), the Clean Water Act (CWA), the Resource Conservation and Recovery Act, the Toxic Substances Control Act, the Comprehensive Environmental Response, Compensation and Liability Act, and the Endangered Species Act, among other laws. Current and pending environmental legislation relates to, among other issues, climate change, greenhouse gas emissions and air quality, mercury and other emissions, hazardous wastes, polychlorinated biphenyls, and endangered and threatened species. These laws are administered by a number of federal, state, and local agencies. In addition to imposing continuing compliance obligations and associated costs, these laws and regulations provide authority to regulators to levy substantial penalties for noncompliance, injunctive relief, and other sanctions. Idaho Power's three coal-fired power plants and three natural gas-fired combustion turbine power plants are subject to many of these regulations. Idaho Power's 17 hydroelectric projects are also subject to a number of water discharge standards and other environmental requirements.

Compliance with current and future environmental laws and regulations may:


•	increase the operating costs of generating plants;


•	increase the construction costs and lead time for new facilities;


•	require the modification of existing generation plants, which could result in additional costs;


•	require the curtailment or shut-down of existing generating plants; or


•	reduce the output from current generating facilities.

Current and future environmental laws and regulations will increase the cost of operating coal-fired power plants and constructing new facilities, in large part through the installation of additional pollution control devices at existing generating plants (including the SCR equipment described above), and could result in Idaho Power discontinuing the operation of one or more coal-fired plants if operation becomes uneconomical. These regulations could, in turn, affect IDACORP's and Idaho Power's results of operations and financial condition if the costs associated with these environmental requirements and plant shut-downs cannot be fully recovered in rates on a timely basis. Part I - “Business - Environmental Regulation and Costs” in IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2012 includes a summary of Idaho Power's expected capital and operating expenditures for environmental matters during the period from 2013 to 2015. Given the uncertainty of future environmental regulations, Idaho Power is unable to predict its environmental-related expenditures beyond that time, though they could be substantial. As noted above in "Liquidity and Capital Resources - Capital Projects," in this MD&A, Idaho Power filed an application for a CPCN with the IPUC in June 2013 relating to an estimated $130 million of SCR equipment to be installed at the Jim Bridger plant.

Included below is a summary of notable developments in environmental and related issues impacting Idaho Power since the discussion of these and other matters included in Part II, Item 7 - “MD&A - Environmental Issues” and “MD&A - Liquidity and Capital Resources - Capital Requirements - Environmental Regulation Costs” in IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2012.

Clean Air Act Developments

Final MATS Rule Implementation: Several regulatory programs developed under the CAA impact Idaho Power. The CAA requires the EPA to develop industry-based standards to control emissions of hazardous air pollutants (HAPs). In February 2012, the EPA issued final Mercury and Air Toxics Standards (MATS) to control emissions of mercury and other HAPs from coal- and oil-fired electric utility generating units (EGUs) under the CAA. Additionally, on March 28, 2013, the EPA issued a notice by which it finalized its MATS with regard to all pending issues except for the shutdown and startup of plants, in light of a number of requests for reconsideration that were filed by the electric utility industry. The notice revised the mercury emissions standard originally proposed in the February 2012 rule to make the mercury emission standard less stringent. The final rule took effect in April 2013. The compliance deadline for the new MATS has been established as April 2015. While the new MATS only apply to EGUs constructed in the future, and Idaho Power does not expect the new standards to impact its existing generation facilities, the new MATS would impact the nature and extent of environmental controls to be installed on new EGUs, and thus would likely increase the cost of constructing new EGUs.

Regional Haze Rules - Update to Wyoming Implementation Plan: In accordance with federal regional haze rules under the CAA, coal-fired utility boilers are subject to regional haze - best available retrofit technology (RH BART) if they were built between 1962 and 1977 and affect any "Class I" (wilderness) areas. This includes all four units at the Jim Bridger coal-fired

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plant. In December 2009, the Wyoming Department of Environmental Quality (WDEQ) issued a RH BART permit to PacifiCorp as the operator of the Jim Bridger plant. As part of the WDEQ's long term strategy for regional haze, the permit requires that PacifiCorp install SCR equipment for NO_x control at Jim 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 Jim Bridger unit 1 by 2022 and unit 2 by 2021. In November 2010, PacifiCorp and the WDEQ signed a settlement agreement under which PacifiCorp agreed to the timing and nature of the controls. However, the settlement agreement is conditioned on the EPA ultimately approving those portions of the Wyoming Regional Haze State Implementation Plan (RH SIP) that are consistent with the terms of the settlement agreement.

In May 2012, the EPA proposed to partially reject Wyoming's regional haze SIP for NO_x reduction at the Jim Bridger plant, instead proposing to substitute the EPA's own RH BART determination and its own Federal Implementation Plan (FIP). The EPA's primary proposal would have resulted in an acceleration of the installation of SCR additions at Jim Bridger units 1 and 2 to within five years after the FIP, or a SIP revised to be consistent with the proposed FIP, was adopted by the WDEQ. In May 2013, the EPA re-proposed the plant-specific NO_x control provisions. In its re-proposal, the EPA proposed to approve Wyoming's RH SIP with regard to Wyoming's determination of the appropriate level of NO_x control for units 1 and 2 at Jim Bridger, with compliance dates of December 31, 2021 for unit 2 and December 31, 2022 for unit 1. The EPA did, however, seek public comment on an alternative approach that would determine that RH BART for units 1 and 2 at the Jim Bridger power plant is SCR, and would establish corresponding NO_x emissions limits for these units that would have to be achieved within five years of the EPA's final action. Separately, Idaho Power plans to install SCR equipment on Jim Bridger units 3 and 4 in 2015 and 2016.

CAA - Executive Order and Proposed Carbon Regulations: In April 2012, the EPA proposed New Source Performance Standards (NSPS) regulating CO₂ emissions from new EGUs under the CAA. On June 25, 2013, President Obama issued a Presidential Memorandum entitled "Power Sector Carbon Pollution Standards," in which he directed the EPA to (a) issue a revised proposed rule for setting carbon emission standards for new EGUs, and (b) issue proposed standards, regulations, or guidelines under the CAA to address carbon pollution from modified, reconstructed, and existing power plants, to be finalized by June 2015. As required by the Presidential Memorandum, on September 20, 2013, the EPA re-proposed its NSPS rule regulating CO₂ emissions from new gas- and coal-fired power plants under the CAA. The new proposal replaces the EPA's prior proposal from April 2012. The proposed rule establishes different standards for new natural gas-fired combustion turbines based on the size of the plant -- 1,000 pounds of CO₂/MWh for large natural gas-fired turbines and 1,100 pounds of CO₂/MWh for smaller natural gas-fired turbines. New coal-fired units would be required to meet a standard of 1,100 pounds of CO₂/MWh, or a range of 1,000 to 1,050 pounds of CO₂/MWh for a seven-year operating period. The proposed standard for coal-fired units is intended to take into consideration current technologies available for carbon capture and sequestration and efforts to implement that technology.

In its 2013 IRP, Idaho Power did not include any new coal-fired power plants in any of its resource portfolios for the 20-year planning period. It did, however, include future new natural gas-fired power plants in certain of its portfolios, and thus the EPA's proposed rule would impact the allowable CO₂ emissions from those new facilities. While Idaho Power believes its future natural gas-fired plants would be capable of complying with the EPA's re-proposed NSPS for new power plants, the cost of constructing new natural gas-fired power plants could increase as a result of the EPA's proposed rule. Separately, Idaho Power could incur additional costs for environmental controls at its existing EGUs, depending on the standards the EPA issues for modified, reconstructed, and existing power plants.

Clean Water Act Development

On June 7, 2013, the EPA issued proposed rulemaking to revise the technology-based effluent limitation guidelines and standards under the CWA for water discharged from steam electric power plants, which includes coal-fired plants. The proposed rule would establish new or additional requirements for wastewater streams from a number of processes associated with steam electric power generation. The EPA has stated that more than half of coal-fired plants in the United States would be in compliance with the proposed rules without incurring any additional cost, and stated that its cost analysis shows very small effects on the electric power market. Idaho Power is evaluating the proposed rule to determine its impact on Idaho Power's co-owned coal-fired plants, if the rule is adopted.

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

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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 boards of directors. These policies have not changed materially from the discussion of those policies included under “Critical Accounting Policies and Estimates” in IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2012.

Recently Issued Accounting Pronouncements

There have been no recently issued accounting pronouncements that have had or are expected to have a material impact on IDACORP's or Idaho Power's results of operations or financial condition.

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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 September 30, 2013.

Interest Rate Risk

IDACORP and Idaho Power manage interest expense and short- and long-term liquidity through a combination of fixed rate and variable rate debt. Generally, the amount of each type of debt is managed through market issuance, but interest rate swap and cap agreements with highly-rated financial institutions may be used to achieve the desired combination.

Variable Rate Debt: As of September 30, 2013, IDACORP and Idaho Power each had $67.2 million and $14.2 million, respectively, in net floating rate debt. The fair market value of this debt was $67.2 million and $14.2 million, respectively. Assuming no change in financial structure, if variable interest rates were to average one percentage point higher than average rate on September 30, 2013, interest rate expense would increase and pre-tax earnings would decrease by approximately $0.7 million for IDACORP and $0.1 million for Idaho Power.

Fixed Rate Debt: As of September 30, 2013, IDACORP and Idaho Power each had $1.6 billion in fixed rate debt, with a fair market value equal to $1.7 billion. These instruments are fixed rate and, therefore, do not expose the companies to a loss in earnings due to changes in market interest rates. However, the fair value of these instruments would increase by approximately $198 million for both IDACORP and Idaho Power if market interest rates were to decline by one percentage point from their September 30, 2013 levels.

Commodity Price Risk

Idaho Power's exposure to changes in commodity prices is related to its ongoing utility operations that produce electricity to meet the demand of its retail electric customers. To supplement its generation resources and balance its supply of power with the demand of its retail customers, Idaho Power participates in the wholesale marketplace. IDACORP’s and Idaho Power’s commodity price risk as of September 30, 2013 had not changed materially from that reported in Item 7A of IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2012. Information regarding Idaho Power’s use of derivative instruments to manage commodity price risk can be found in Note 12 – “Derivative Financial Instruments” to the condensed consolidated financial statements included in this report.

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, and reporting credit risk using appropriate contractual arrangements; and transferring of credit risk through the use of financial guarantees, cash, or letters of credit. Idaho Power maintains a current list of acceptable counterparties and credit limits.

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 relating to its wholesale commodity contracts that allow performance assurance collateral to be requested of and/or posted with certain counterparties. As of September 30, 2013, Idaho Power had posted $0.5 million of performance 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 requests by its wholesale counterparties to post additional performance assurance collateral. Counterparties to derivative instruments and other forward contracts could request immediate payment or demand immediate ongoing full daily collateralization on derivative instruments and contracts in net liability positions. Based upon Idaho Power's energy and fuel portfolio and market conditions as of September 30, 2013, the amount of collateral that could be requested upon a downgrade to below investment grade was approximately $8.3 million. To minimize capital requirements, Idaho Power actively monitors the portfolio exposure and the potential exposure to additional requests for performance assurance collateral calls through sensitivity analysis.

Idaho Power’s credit risk related to uncollectible accounts as of September 30, 2013 had not changed materially from that reported in Item 7A of IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2012.

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Additional information regarding Idaho Power’s management of credit risk and credit contingent features can be found in Note 12 – “Derivative Financial Instruments” to the condensed consolidated financial statements included in this report.

Equity Price Risk

IDACORP and Idaho Power are exposed to price fluctuations in equity markets, primarily through their defined benefit pension plan assets, a mine reclamation trust fund owned by an equity-method investment of Idaho Power, and other equity security investments at Idaho Power. The equity securities held by the plan and in such accounts are diversified to achieve broad market participation and reduce the impact of any single investment, sector, or geographic region. Idaho Power has established asset allocation targets for the pension plan holdings, which are described in Note 11 - "Benefit Plans" to the notes to the consolidated financial statements included in IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2012. IDACORP’s and Idaho Power’s equity price risk as of September 30, 2013 had not changed materially from that reported in Item 7A of IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2012.

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 September 30, 2013, have concluded that IDACORP’s disclosure controls and procedures are effective as of that date.

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 September 30, 2013, have concluded that Idaho Power’s disclosure controls and procedures are effective as of that date.

Changes in Internal Control Over Financial Reporting

Idaho Power completed the implementation of a new customer information system as a part of a U.S. Department of Energy Smart Grid Investment Grant, issued in 2010. IDACORP and Idaho Power evaluated the effect of this upgrade on internal control over financial reporting for the three months ended September 30, 2013 and determined that implementation of the new system resulted in a material change to internal controls over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act). The companies reviewed the new system as it was implemented and the internal controls affected by its implementation and made appropriate changes to the affected internal controls and associated documentation and procedures in conjunction with the change.

Other than described above, there have been no changes in IDACORP’s or Idaho Power’s internal control over financial reporting during the quarter ended September 30, 2013, 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

Refer to Note 9 - “Contingencies” to the condensed consolidated financial statements included in this report for information regarding certain legal and administrative proceedings in which the registrants are involved.

ITEM 1A. RISK FACTORS

The factors discussed in Part I - Item 1A - “Risk Factors” in IDACORP’s and Idaho Power’s Annual Report on Form 10-K for the year ended December 31, 2012, could materially affect IDACORP’s and Idaho Power’s business, financial condition, or future results. In addition to those risk factors, also see "Forward-Looking Statements" in this report for additional factors that could have a significant impact on IDACORP's or Idaho Power's operations, results of operations, or financial condition and could cause actual results to differ materially from those anticipated in forward-looking statements.

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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 Policy and Code of Conduct relating to transactions between and among Idaho Power, IDACORP, and other affiliates, which was 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 credit facility covenants or Idaho Power’s Revised Policy and Code of Conduct.

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. Further, 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.

See Note 6 - “Common Stock” to the condensed consolidated financial statements included in this report for a further discussion of restrictions on IDACORP’s and Idaho Power’s payment of dividends.

Issuer Purchases of Equity Securities

IDACORP did not repurchase any shares of its common stock during the quarter ended September 30, 2013.

ITEM 4. MINE SAFETY DISCLOSURES

Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.104) is included in Exhibit 95.1 of this report, which is incorporated herein by reference.

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

Exhibits for IDACORP and Idaho Power are listed in the Exhibit Index at the end of this report, which is incorporated herein by reference.

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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:	November 5, 2013	By:	/s/ J. LaMont Keen
			J. LaMont Keen
			President and Chief Executive Officer

Date:	November 5, 2013	By:	/s/ Darrel T. Anderson
			Darrel T. Anderson
			Executive Vice President - Administrative
			Services and Chief Financial Officer





		IDAHO POWER COMPANY
		(Registrant)



Date:	November 5, 2013	By:	/s/ J. LaMont Keen
			J. LaMont Keen
			Chief Executive Officer

Date:	November 5, 2013	By:	/s/ Darrel T. Anderson
			Darrel T. Anderson
			President and Chief Financial Officer

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EXHIBIT INDEX

The following exhibits are filed or furnished, as applicable, with the Quarterly Report on Form 10-Q for the quarter ended September 30, 2013:



		Incorporated by Reference
Exhibit No.	Exhibit Description	Form	File No.	Exhibit No.	Date	Included Herewith

4.1	Idaho Power Company Forty-seventh Supplemental Indenture, dated July 1, 2013, to Mortgage and Deed of Trust, dated as of October 1, 1937	8-K	1-3198; 1-14465	4.1	7/12/2013
10.62	Second Extension Agreement, dated October 8, 2013, to the Second Amended and Restated Credit Agreement, dated October 26, 2011, among IDACORP, Inc., various lenders, Wells Fargo Bank, National Association, as administrative agent, swingline lender, and LC issuer, JPMorgan Chase Bank, N.A., as syndication agent and LC issuer, KeyBank National Association and Union Bank, N.A., as documentation agents, and Wells Fargo Securities, LLC, J.P. Morgan Securities Inc., Keybanc Capital Markets, and Union Bank, N.A. as joint lead arrangers and joint book runners					X
10.63	Second Extension Agreement, dated October 8, 2013, to the Second Amended and Restated Credit Agreement, dated October 26, 2011, among Idaho Power Company, various lenders, Wells Fargo Bank, National Association, as administrative agent, swingline lender, and LC issuer, JPMorgan Chase Bank, N.A., as syndication agent and LC issuer, KeyBank National Association and Union Bank, N.A., as documentation agents, and Wells Fargo Securities, LLC, J.P. Morgan Securities Inc., Keybanc Capital Markets, and Union Bank, N.A. as joint lead arrangers and joint book runners					X
10.64	Amendment to the Idaho Power Company Employee Savings Plan, dated October 11, 2013					X
12.1	IDACORP, Inc. Computation of Ratio of Earnings to Fixed Charges and Supplemental Ratio of Earnings to Fixed Charges					X
12.2	Idaho Power Company Computation of Ratio of Earnings to Fixed Charges and Supplemental Ratio of Earnings to Fixed Charges					X
15.1	Letter Re: Unaudited Interim Financial Information					X
31.1	Certification of IDACORP, Inc. Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002					X
31.2	Certification of IDACORP, Inc. Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002					X
31.3	Certification of Idaho Power Company Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002					X
31.4	Certification of Idaho Power Company Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002					X
32.1	Certification of IDACORP, Inc. Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002					X
32.2	Certification of IDACORP, Inc. Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002					X
32.3	Certification of Idaho Power Company Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002					X

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32.4	Certification of Idaho Power Company Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	X
95.1	Mine Safety Disclosures	X
101.INS	XBRL Instance Document	X
101.SCH	XBRL Taxonomy Extension Schema Document	X
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document	X
101.LAB	XBRL Taxonomy Extension Label Linkbase Document	X
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document	X
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document	X