Edgar Filing: IDACORP INC

Idaho Power

IDA 06.30.13 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 June 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 July 26, 2013:

IDACORP, Inc.: 50,232,332

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		34
	Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			36
	Item 3. Quantitative and Qualitative Disclosures About Market Risk			64
	Item 4. Controls and Procedures			65

Part II. Other Information:

	Item 1. Legal Proceedings			65
	Item 1A. Risk Factors			65
	Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			65
	Item 4. Mine Safety Disclosures			66
	Item 5. Other Information			66
	Item 6. Exhibits			66

Signatures				67

Exhibit Index				68

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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
Valmy	-	North Valmy Steam Electric Generating Plant
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 June 30,						Six months ended June 30,
	2013			2012			2013			2012
	(thousands of dollars except for per share amounts)
Operating Revenues:
Electric utility:
General business	$	264,432		$	220,529		$	496,651		$	417,958
Off-system sales	4,527			11,418			20,428			39,126
Other revenues	33,897			21,600			50,146			36,946
Total electric utility revenues	302,856			253,547			567,225			494,030
Other	1,092			1,154			1,652			1,812
Total operating revenues	303,948			254,701			568,877			495,842
Operating Expenses:
Electric utility:
Purchased power	49,151			45,178			92,008			79,456
Fuel expense	41,878			21,285			91,044			54,036
Power cost adjustment	(13,299		)	(3,211		)	(28,009		)	5,798
Other operations and maintenance	83,154			86,005			162,939			164,517
Energy efficiency programs	19,732			8,084			24,202			12,561
Depreciation	32,232			29,879			64,142			60,421
Taxes other than income taxes	8,054			7,849			16,226			15,949
Total electric utility expenses	220,902			195,069			422,552			392,738
Other	3,640			3,158			7,485			6,770
Total operating expenses	224,542			198,227			430,037			399,508
Operating Income	79,406			56,474			138,840			96,334
Allowance for Equity Funds Used During Construction	3,528			7,832			7,143			15,449
Losses of Unconsolidated Equity-Method Investments	(2,293		)	(1,928		)	(2,187		)	(509		)
Other Income, Net	1,588			1,065			2,414			2,525
Interest Expense:
Interest on long-term debt	20,793			20,083			40,462			39,582
Other interest	1,732			1,686			3,484			3,342
Allowance for borrowed funds used during construction	(1,876		)	(4,333		)	(3,807		)	(8,282		)
Total interest expense, net	20,649			17,436			40,139			34,642
Income Before Income Taxes	61,580			46,007			106,071			79,157
Income Tax Expense	15,930			10,569			27,041			18,902
Net Income	45,650			35,438			79,030			60,255
Adjustment for (income) loss attributable to noncontrolling interests	(137		)	(137		)	16			(25		)
Net Income Attributable to IDACORP, Inc.	$	45,513		$	35,301		$	79,046		$	60,230
Weighted Average Common Shares Outstanding - Basic (000’s)	50,056			49,927			50,047			49,893
Weighted Average Common Shares Outstanding - Diluted (000’s)	50,108			49,984			50,086			49,944
Earnings Per Share of Common Stock:
Earnings Attributable to IDACORP, Inc. - Basic	$	0.91		$	0.71		$	1.58		$	1.21
Earnings Attributable to IDACORP, Inc. - Diluted	$	0.91		$	0.71		$	1.58		$	1.21
Dividends Declared Per Share of Common Stock	$	0.38		$	0.33		$	0.76		$	0.66

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 June 30,						Six months ended June 30,
	2013			2012			2013		2012
	(thousands of dollars)

Net Income	$	45,650		$	35,438		$	79,030	$	60,255
Other Comprehensive Income:
Net unrealized holding gains (losses) arising during the period, net of tax of $167, $(344), $925 and $530	259			(536		)	1,440		826
Unfunded pension liability adjustment, net of tax of $298, $170, $596 and $340	465			265			930		530
Total Comprehensive Income	46,374			35,167			81,400		61,611
Comprehensive (income) loss attributable to noncontrolling interests	(137		)	(137		)	16		(25		)
Comprehensive Income Attributable to IDACORP, Inc.	$	46,237		$	35,030		$	81,416	$	61,586

The accompanying notes are an integral part of these statements.

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IDACORP, Inc.

Condensed Consolidated Balance Sheets

(unaudited)



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

Current Assets:
Cash and cash equivalents	$	136,155		$	26,527
Receivables:
Customer (net of allowance of $1,194 and $1,551, respectively)	69,130			66,111
Other (net of allowance of $152 and $322, respectively)	14,541			23,608
Income taxes receivable	232			1,753
Accrued unbilled revenues	86,877			51,448
Materials and supplies (at average cost)	52,347			51,037
Fuel stock (at average cost)	36,131			42,388
Prepayments	13,792			12,823
Deferred income taxes	28,157			56,532
Current regulatory assets	80,441			30,078
Other	2,767			4,948
Total current assets	520,570			367,253
Investments	178,305			189,020
Property, Plant and Equipment:
Utility plant in service	5,001,736			4,915,772
Accumulated provision for depreciation	(1,737,827		)	(1,703,159		)
Utility plant in service - net	3,263,909			3,212,613
Construction work in progress	298,594			298,470
Utility plant held for future use	7,101			7,101
Other property, net of accumulated depreciation	17,628			17,847
Property, plant and equipment - net	3,587,232			3,536,031
Other Assets:
American Falls and Milner water rights	16,324			17,909
Company-owned life insurance	22,263			22,646
Regulatory assets	1,113,051			1,132,960
Long-term receivables (net of allowance of $1,260 and $1,260, respectively)	4,437			4,437
Other	46,502			49,260
Total other assets	1,202,577			1,227,212
Total	$	5,488,684		$	5,319,516

The accompanying notes are an integral part of these statements.

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IDACORP, Inc.

Condensed Consolidated Balance Sheets

(unaudited)



	June 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	61,900			69,700
Accounts payable	77,011			90,165
Income taxes accrued	9,802			1,005
Interest accrued	23,534			22,311
Accrued compensation	30,984			42,343
Current regulatory liabilities	5,838			30,277
Other	33,486			24,438
Total current liabilities	313,619			351,303
Other Liabilities:
Deferred income taxes	904,306			894,616
Regulatory liabilities	360,299			355,362
Pension and other postretirement benefits	427,946			423,409
Other	59,566			65,228
Total other liabilities	1,752,117			1,738,615
Long-Term Debt	1,615,128			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)	836,560			834,922
Retained earnings	981,822			940,968
Accumulated other comprehensive loss	(14,746		)	(17,116		)
Treasury stock (1,131 and 1,817 shares at cost, respectively)	(13		)	(21		)
Total IDACORP, Inc. shareholders’ equity	1,803,623			1,758,753
Noncontrolling interests	4,197			4,213
Total equity	1,807,820			1,762,966
Total	$	5,488,684		$	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)



	Six months ended June 30,
	2013			2012
	(thousands of dollars)
Operating Activities:
Net income	$	79,030		$	60,255
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	66,025			62,929
Deferred income taxes and investment tax credits	15,069			11,864
Changes in regulatory assets and liabilities	(24,727		)	13,805
Pension and postretirement benefit plan expense	14,672			15,204
Contributions to pension and postretirement benefit plans	(12,391		)	(36,816		)
Losses of unconsolidated equity-method investments	2,187			509
Distributions from unconsolidated equity-method investments	7,989			4,200
Allowance for equity funds used during construction	(7,143		)	(15,449		)
Other non-cash adjustments to net income, net	1,198			2,802
Change in:
Accounts receivable	1,466			2,673
Accounts payable and other accrued liabilities	(12,204		)	(6,759		)
Taxes accrued/receivable	13,646			8,789
Other current assets	(30,061		)	(29,078		)
Other current liabilities	6,552			(3,769		)
Other assets	(582		)	(2,342		)
Other liabilities	(6,517		)	(5,780		)
Net cash provided by operating activities	114,209			83,037
Investing Activities:
Additions to property, plant and equipment	(109,059		)	(123,091		)
Proceeds from the sale of emission allowances and RECs	480			1,896
Investments in affordable housing	—			(313		)
Distributions from affordable housing investments	1,642			—
Other	2,371			(1,136		)
Net cash used in investing activities	(104,566		)	(122,644		)
Financing Activities:
Issuance of long-term debt	150,000			150,000
Retirement of long-term debt	(1,064		)	(101,064		)
Dividends on common stock	(38,313		)	(33,470		)
Net change in short-term borrowings	(7,800		)	10,500
Issuance of common stock	255			4,839
Acquisition of treasury stock	(2,124		)	(2,062		)
Other	(969		)	(2,575		)
Net cash provided by financing activities	99,985			26,168
Net increase (decrease) in cash and cash equivalents	109,628			(13,439		)
Cash and cash equivalents at beginning of the period	26,527			27,813
Cash and cash equivalents at end of the period	$	136,155		$	14,374
Supplemental Disclosure of Cash Flow Information:
Cash paid during the period for:
Income taxes	$	60		$	1,171
Interest (net of amount capitalized)	$	37,610		$	33,196
Non-cash investing activities:
Additions to property, plant and equipment in accounts payable	$	12,348		$	24,957

The accompanying notes are an integral part of these statements.

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IDACORP, Inc.

Condensed Consolidated Statements of Equity

(unaudited)



	Six months ended June 30,
	2013			2012
	(thousands of dollars)
Common Stock
Balance at beginning of period	$	834,922		$	828,389
Issued	255			4,804
Other	1,383			1,354
Balance at end of period	836,560			834,547
Retained Earnings
Balance at beginning of period	940,968			840,916
Net income attributable to IDACORP, Inc.	79,046			60,230
Common stock dividends ($0.76 and $0.66 per share)	(38,192		)	(33,080		)
Balance at end of period	981,822			868,066
Accumulated Other Comprehensive (Loss) Income
Balance at beginning of period	(17,116		)	(11,622		)
Unrealized gain on securities (net of tax)	1,440			826
Unfunded pension liability adjustment (net of tax)	930			530
Balance at end of period	(14,746		)	(10,266		)
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	1,803,623			1,692,326
Noncontrolling Interests
Balance at beginning of period	4,213			4,040
Net (loss) income attributable to noncontrolling interests	(16		)	25
Balance at end of period	4,197			4,065
Total equity at end of period	$	1,807,820		$	1,696,391

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 June 30,						Six months ended June 30,
	2013			2012			2013			2012
	(thousands of dollars)
Operating Revenues:
General business	$	264,432		$	220,529		$	496,651		$	417,958
Off-system sales	4,527			11,418			20,428			39,126
Other revenues	33,897			21,600			50,146			36,946
Total operating revenues	302,856			253,547			567,225			494,030
Operating Expenses:
Operation:
Purchased power	49,151			45,178			92,008			79,456
Fuel expense	41,878			21,285			91,044			54,036
Power cost adjustment	(13,299		)	(3,211		)	(28,009		)	5,798
Other operations and maintenance	83,154			86,005			162,939			164,517
Energy efficiency programs	19,732			8,084			24,202			12,561
Depreciation	32,232			29,879			64,142			60,421
Taxes other than income taxes	8,054			7,849			16,226			15,949
Total operating expenses	220,902			195,069			422,552			392,738
Income from Operations	81,954			58,478			144,673			101,292
Other Income (Expense):
Allowance for equity funds used during construction	3,528			7,832			7,143			15,449
(Losses) earnings of unconsolidated equity-method investments	(378		)	(266		)	2,256			4,027
Other expense, net	(1,215		)	(1,367		)	(3,374		)	(2,847		)
Total other income	1,935			6,199			6,025			16,629
Interest Charges:
Interest on long-term debt	20,793			20,083			40,462			39,582
Other interest	1,637			1,579			3,284			3,138
Allowance for borrowed funds used during construction	(1,876		)	(4,333		)	(3,807		)	(8,282		)
Total interest charges	20,554			17,329			39,939			34,438
Income Before Income Taxes	63,335			47,348			110,759			83,483
Income Tax Expense	18,352			12,639			31,730			22,954
Net Income	$	44,983		$	34,709		$	79,029		$	60,529

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 June 30,					Six months ended June 30,
	2013		2012			2013		2012
	(thousands of dollars)

Net Income	$	44,983	$	34,709		$	79,029	$	60,529
Other Comprehensive Income:
Net unrealized holding gains (losses) arising during the period, net of tax of $167, $(344), $925 and $530	259		(536		)	1,440		826
Unfunded pension liability adjustment, net of tax of $298, $170, $596 and $340	465		265			930		530
Total Comprehensive Income	$	45,707	$	34,438		$	81,399	$	61,885

The accompanying notes are an integral part of these statements.

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Idaho Power Company

Condensed Consolidated Balance Sheets

(unaudited)



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

Electric Plant:
In service (at original cost)	$	5,001,736		$	4,915,772
Accumulated provision for depreciation	(1,737,827		)	(1,703,159		)
In service - net	3,263,909			3,212,613
Construction work in progress	298,594			298,470
Held for future use	7,101			7,101
Electric plant - net	3,569,604			3,518,184
Investments and Other Property	123,514			128,145
Current Assets:
Cash and cash equivalents	132,152			17,251
Receivables:
Customer (net of allowance of $1,194 and $1,551, respectively)	69,130			66,111
Other (net of allowance of $152 and $322, respectively)	14,402			20,618
Income taxes receivable	—			2,559
Accrued unbilled revenues	86,877			51,448
Materials and supplies (at average cost)	52,347			51,037
Fuel stock (at average cost)	36,131			42,388
Prepayments	13,642			12,688
Deferred income taxes	20,400			48,774
Current regulatory assets	80,441			30,078
Other	2,767			4,950
Total current assets	508,289			347,902
Deferred Debits:
American Falls and Milner water rights	16,324			17,909
Company-owned life insurance	22,263			22,646
Regulatory assets	1,113,051			1,132,960
Other	45,330			47,965
Total deferred debits	1,196,968			1,221,480
Total	$	5,398,375		$	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)



	June 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	875,548			834,732
Accumulated other comprehensive loss	(14,746		)	(17,116		)
Total common stock equity	1,668,840			1,625,654
Long-term debt	1,615,128			1,466,632
Total capitalization	3,283,968			3,092,286
Current Liabilities:
Long-term debt due within one year	71,064			71,064
Accounts payable	75,944			89,651
Accounts payable to affiliates	1,445			252
Income taxes accrued	12,373			—
Interest accrued	23,534			22,311
Accrued compensation	30,842			42,282
Current regulatory liabilities	5,838			30,277
Other	33,003			23,813
Total current liabilities	254,043			279,650
Deferred Credits:
Deferred income taxes	1,014,316			1,001,877
Regulatory liabilities	360,299			355,362
Pension and other postretirement benefits	427,946			423,409
Other	57,803			63,127
Total deferred credits	1,860,364			1,843,775

Commitments and Contingencies

Total	$	5,398,375		$	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)



	Six months ended June 30,
	2013			2012
	(thousands of dollars)
Operating Activities:
Net income	$	79,029		$	60,529
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	65,675			62,626
Deferred income taxes and investment tax credits	17,817			42,005
Changes in regulatory assets and liabilities	(24,727		)	13,805
Pension and postretirement benefit plan expense	14,657			15,204
Contributions to pension and postretirement benefit plans	(12,376		)	(36,816		)
Earnings of unconsolidated equity-method investments	(2,256		)	(4,027		)
Distributions from unconsolidated equity-method investments	7,214			4,200
Allowance for equity funds used during construction	(7,143		)	(15,449		)
Other non-cash adjustments to net income, net	(562		)	1,411
Change in:
Accounts receivable	(238		)	1,850
Accounts payable	(12,041		)	(6,516		)
Taxes accrued/receivable	17,462			(18,586		)
Other current assets	(30,045		)	(29,035		)
Other current liabilities	6,501			(3,769		)
Other assets	(582		)	(2,342		)
Other liabilities	(6,179		)	(5,598		)
Net cash provided by operating activities	112,206			79,492
Investing Activities:
Additions to utility plant	(109,059		)	(123,091		)
Proceeds from the sale of emission allowances and RECs	480			1,896
Other	2,372			(1,136		)
Net cash used in investing activities	(106,207		)	(122,331		)
Financing Activities:
Issuance of long-term debt	150,000			150,000
Retirement of long-term debt	(1,064		)	(101,064		)
Dividends on common stock	(38,213		)	(33,112		)
Net change in short term borrowings	—			10,000
Capital contribution from parent	—			7,500
Other	(1,821		)	(3,574		)
Net cash provided by financing activities	108,902			29,750
Net increase (decrease) in cash and cash equivalents	114,901			(13,089		)
Cash and cash equivalents at beginning of the period	17,251			19,316
Cash and cash equivalents at end of the period	$	132,152		$	6,227
Supplemental Disclosure of Cash Flow Information:
Cash (received) paid during the period for:
Income taxes	$	(1,840	)	$	2,456
Interest (net of amount capitalized)	$	37,410		$	32,993
Non-cash investing activities:
Additions to property, plant and equipment in accounts payable	$	12,348		$	24,957

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 June 30, 2013, consolidated results of operations for the three and six months ended June 30, 2013 and 2012, and consolidated cash flows for the six months ended June 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 $2.3 million and $4.8 million in the three and six months ended June 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 six months ended June 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.

IDACORP's effective tax rate for the six months ended June 30, 2013, was 25.5 percent, compared to 23.9 percent for the six months ended June 30, 2012. Idaho Power's effective tax rate for the six months ended June 30, 2013, was 28.6 percent, compared to 27.5 percent for the six months ended June 30, 2012. The increase in the 2013 estimated annual effective tax rates from 2012 was primarily due to additional income tax expense from greater pre-tax earnings at Idaho Power. Net regulatory flow-through tax adjustments at Idaho Power for the six months ended June 30, 2013 were comparable to the same period in 2012.

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 six months of 2013 compared to the first six 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

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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.

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.

Based on Idaho Power's June 30, 2013 estimate that full-year 2013 Idaho ROE will exceed 10.0 percent, Idaho Power recorded in the second quarter of 2013 a $2.8 million provision for sharing with customers pursuant to the terms of the December 2011 settlement stipulation.

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Annual Idaho PCA Mechanism Filing

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 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.

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 allowed 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, and thus its ratemaking treatment, prior to Idaho Power's incurring the bulk of the associated expenses. A determination and order from the IPUC is pending.

4. LONG-TERM DEBT

On April 8, 2013, Idaho Power issued $75 million in principal amount of 2.50% first mortgage bonds, medium-term notes, Series I, maturing on April 1, 2023, and $75 million in principal amount of 4.00% first mortgage bonds, medium-term notes, Series I, maturing on April 1, 2043. Idaho Power intends to use 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 due

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in October 2013. Issuance of the Series I medium-term notes in April 2013, combined with the issuance of $200 million in principal amount of medium-term notes in August 2010 and $150 million in principal amount of medium-term 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.

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 August 1, 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 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 each of the lenders, extending the maturity dates under both credit facilities to October 26, 2017. No other terms of the credit facilities, including the amount of permitted borrowings under the credit agreements, were affected by the extension.

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At June 30, 2013, no loans were outstanding under either IDACORP's or Idaho Power's facilities. At June 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 June 30, 2013 and December 31, 2012:



	June 30, 2013									December 31, 2012
	Idaho Power			IDACORP			Total			Idaho Power			IDACORP			Total
Commercial paper outstanding	$	—		$	61,900		$	61,900		$	—		$	69,700		$	69,700
Weighted-average annual interest rate	—		%	0.37		%	0.37		%	—		%	0.50		%	0.50		%

6. COMMON STOCK

IDACORP Common Stock

During the six months ended June 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 May 22, 2013, IDACORP filed with the SEC a shelf registration statement, which became effective upon filing, for the offer and sale of an unspecified amount of shares of common stock and unspecified principal amount of debt securities. 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 pursuant to the registration statement 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. 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. 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 June 30, 2013, the leverage ratios for IDACORP and Idaho Power were 49 percent and 50 percent, respectively. Based on these restrictions, IDACORP’s and Idaho Power’s dividends were limited to $859 million and $757 million, respectively, at June 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 June 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 June 30, 2013, Idaho Power's common equity capital was 50 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.

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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 accounts" is undefined in the Federal Power Act but could be interpreted to limit the payment of dividends by Idaho Power to the amount of Idaho Power's retained earnings.

7. EARNINGS PER SHARE

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



	Three months ended June 30,				Six months ended June 30,
	2013		2012		2013		2012
Numerator:
Net income attributable to IDACORP, Inc.	$	45,513	$	35,301	$	79,046	$	60,230
Denominator:
Weighted-average common shares outstanding - basic	50,056		49,927		50,047		49,893
Effect of dilutive securities:
Options	2		5		3		5
Restricted stock	50		52		36		46
Weighted-average common shares outstanding - diluted	50,108		49,984		50,086		49,944
Basic earnings per share	$	0.91	$	0.71	$	1.58	$	1.21
Diluted earnings per share	$	0.91	$	0.71	$	1.58	$	1.21

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 six months ended June 30, 2013, except for the impact of the termination of four power purchase agreements resulting from either uncured breach by the respective counterparties or pursuant to IPUC-approved settlement arrangements between the parties. Termination of the contracts 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 June 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 June 30, 2013, the value of the reclamation trust fund was $66 million. During the six months ended June 30, 2013, the reclamation trust fund distributed approximately $15 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 June 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 characterized these ripple claims as "speculative." Recently, the FERC 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.

Based on its evaluation of the merits of ripple claims and the inability to estimate any potential exposure should the claims ultimately have any merit, 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 also continues its active participation in the SRBA in seeking 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.

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.

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



	Pension Plan						SMSP				Postretirement Benefits
	2013			2012			2013		2012		2013			2012
Service cost	$	7,866		$	6,345		$	545	$	538	$	245		$	295
Interest cost	7,979			7,853			814		804		573			749
Expected return on plan assets	(9,065		)	(8,155		)	—		—		(569		)	(513		)
Amortization of transition obligation	—			—			—		—		—			510
Amortization of prior service cost	87			86			53		54		(90		)	(106		)
Amortization of net loss (gain)	4,307			3,594			710		382		(120		)	49
Net periodic benefit cost	11,174			9,723			2,122		1,778		39			984
Costs not recognized due to the effects of regulation ⁽¹⁾	(6,351		)	(4,954		)	—		—		—			—
Net periodic benefit cost recognized for financial reporting⁽¹⁾	$	4,823		$	4,769		$	2,122	$	1,778	$	39		$	984

⁽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.

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



	Pension Plan						SMSP				Postretirement Benefits
	2013			2012			2013		2012		2013			2012
Service cost	$	15,678		$	12,786		$	1,090	$	1,076	$	658		$	646
Interest cost	15,915			15,745			1,628		1,609		1,316			1,567
Expected return on plan assets	(17,763		)	(15,867		)	—		—		(1,164		)	(1,117		)
Amortization of transition obligation	—			—			—		—		—			1,020
Amortization of prior service cost	174			173			106		107		(115		)	(211		)
Amortization of net loss	8,559			7,057			1,420		764		49			192
Net periodic benefit cost	22,563			19,894			4,244		3,556		744			2,097
Costs not recognized due to the effects of regulation ⁽¹⁾	(12,894		)	(10,343		)	—		—		—			—
Net periodic benefit cost recognized for financial reporting⁽¹⁾	$	9,669		$	9,551		$	4,244	$	3,556	$	744		$	2,097

Idaho Power's minimum required contributions to the pension plan are estimated to be zero in 2013. However, during the six months ended June 30, 2013, Idaho Power made a $10 million discretionary contribution 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.

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 June 30, 2013 and December 31, 2012 (in thousands of dollars).



	June 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	$	9,158	$	—	$	33,218	$	6,792	$	—	$	31,913

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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 June 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 six months ended June 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 June 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
June 30, 2013
Current:
Financial swaps	Other current assets	$	2,361	$	(702	)		$	1,659	$	702	$	(702	)	$	—
Financial swaps	Other current liabilities	246		(246		)		—		1,256		(246		)	1,010
Forward contracts	Other current assets	148		(3		)		145		3		(3		)	—
Long-term:
Financial swaps	Other liabilities	—		—				—		139		—			139
Forward contracts	Other assets	179		—				179		—		—			—
Total		$	2,934	$	(951	)		$	1,983	$	2,100	$	(951	)	$	1,149
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 six months ended June 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 June 30,						Six months ended June 30,
		Three months ended June 30,						Six months ended June 30,
		2013			2012			2013		2012
Financial swaps	Off-system sales	$	(1,149	)	$	5,471		$	323	$	9,910
Financial swaps	Purchased power	28			(2,159		)	14		(3,152		)
Financial swaps	Fuel expense	33			(3,633		)	1,149		(3,717		)
Financial swaps	Other operations and maintenance	5			24			16		(21		)
Forward contracts	Fuel expense	11			—			79		—

⁽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 electricity swap contracts are recorded on the income statement in off-system sales or purchased power depending on the forecasted position being economically hedged by the derivative contract. Settlement gains and losses on both financial and physical contracts for natural gas are reflected in fuel expense. Settlement gains and losses on diesel derivatives are 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.

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



		June 30,
Commodity	Units	2013	2012
Electricity purchases	MWh	112	422
Electricity sales	MWh	891	1,358
Natural gas purchases	MMBtu	14,952	20,295
Natural gas sales	MMBtu	885	2,239
Diesel purchases	Gallons	418	537

Credit Risk

At June 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 June 30, 2013, was $2.1 million. Idaho Power posted no cash collateral related to this amount. If the credit-risk-related contingent features underlying these agreements were triggered on June 30, 2013, Idaho Power would have been required to post $6.5 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.

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

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• 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 swaps are valued on the Intercontinental Exchange with quoted prices in an active market. Natural gas and diesel derivative valuations are performed using New York Mercantile Exchange (NYMEX) pricing, adjusted for location basis, which are also quoted under NYMEX. 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 six months ended June 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 June 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.



	June 30, 2013								December 31, 2012
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets:
Derivatives	$	1,141	$	842	$	—	$	1,983	$	2,201	$	1,674	$	—	$	3,875
Money market funds	66,986		—		—		66,986		100		—		—		100
Trading securities: Equity securities	1,105		—		—		1,105		2,478		—		—		2,478
Available-for-sale securities: Equity securities	33,218		—		—		33,218		31,913		—		—		31,913
Liabilities:
Derivatives	$	—	$	1,149	$	—	$	1,149	$	—	$	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 June 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.



	June 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⁾	1,686,192		1,816,864		1,537,696		1,819,213
Idaho Power
Liabilities:
Long-term debt ⁽¹⁾	$	1,686,192	$	1,816,864	$	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 June 30, 2013:
Revenues	$	302,856	$	1,092		$	—		$	303,948
Net income attributable to IDACORP, Inc.	44,983		530			—			45,513
Total assets as of June 30, 2013	5,398,375		102,542			(12,233		)	5,488,684
Three months ended June 30, 2012:
Revenues	$	253,547	$	1,154		$	—		$	254,701
Net income attributable to IDACORP, Inc.	34,709		592			—			35,301
Six months ended June 30, 2013:
Revenues	$	567,225	$	1,652		$	—		$	568,877
Net income attributable to IDACORP, Inc.	79,029		17			—			79,046
Six months ended June 30, 2012:
Revenues	$	494,030	$	1,812		$	—		$	495,842
Net income (loss) attributable to IDACORP, Inc.	60,529		(299		)	—			60,230

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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 six months ended June 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 June 30, 2013:
Balance at beginning of period	$	5,317		$	(20,787	)	$	(15,470	)
Other comprehensive income before reclassifications	259			—			259
Amounts reclassified out of AOCI	—			465			465
Net current-period other comprehensive income	259			465			724
Balance at end of period	$	5,576		$	(20,322	)	$	(14,746	)
Six months ended June 30, 2013:
Balance at beginning of period	$	4,136		$	(21,252	)	$	(17,116	)
Other comprehensive income before reclassifications	1,440			—			1,440
Amounts reclassified out of AOCI	—			930			930
Net current-period other comprehensive income	1,440			930			2,370
Balance at end of period	$	5,576		$	(20,322	)	$	(14,746	)
Three months ended June 30, 2012:
Balance at beginning of period	$	3,931		$	(13,926	)	$	(9,995	)
Other comprehensive income before reclassifications	(536		)	—			(536		)
Amounts reclassified out of AOCI	—			265			265
Net current-period other comprehensive income	(536		)	265			(271		)
Balance at end of period	$	3,395		$	(13,661	)	$	(10,266	)
Six months ended June 30, 2012:
Balance at beginning of period	$	2,569		$	(14,191	)	$	(11,622	)
Other comprehensive income before reclassifications	826			—			826
Amounts reclassified out of AOCI	—			530			530
Net current-period other comprehensive income	826			530			1,356
Balance at end of period	$	3,395		$	(13,661	)	$	(10,266	)

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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 six months ended June 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 June 30,						Six months ended June 30,
	2013			2012			2013			2012
Amortization of defined benefit pension items ⁽¹⁾
Prior service cost	$	53		$	54		$	106		$	107
Net loss	710			382			1,420			764
Total before tax	763			436			1,526			871
Tax benefit ⁽²⁾	(298		)	(170		)	(596		)	(340		)
Net of tax	465			265			930			530
Total reclassification for the period	$	465		$	265		$	930		$	530

⁽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 June 30, 2013, and the related condensed consolidated statements of income and comprehensive income for the three-month and six-month periods ended June 30, 2013 and 2012, and of equity and cash flows for the six-month periods ended June 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

August 1, 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 June 30, 2013, and the related condensed consolidated statements of income and comprehensive income for the three-month and six-month periods ended June 30, 2013 and 2012, and of cash flows for the six-month periods ended June 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

August 1, 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 504,000 general business customers as of June 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 the 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 Integrated Resource Plan (IRP) seeks to identify cost-effective and responsible means for Idaho Power to plan for and 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 plan and build for the future. As noted above, Idaho Power expects an ongoing level of significant capital investment going forward to meet the needs of both current and future customers. Idaho Power's substantial capital projects include significant upgrades to generation plants and ongoing maintenance and system 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) to 2015.

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 heavily 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 the companies' other stakeholders.

A final area of recent focus has been growth in IDACORP's dividend. In November 2011, the IDACORP Board of Directors adopted a target dividend payout ratio, and during 2012 IDACORP's quarterly dividend increased from $0.30 to $0.38 per IDACORP 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 the target dividend payout ratio. To that end, as of the date of this report IDACORP's management continues to anticipate recommending to the IDACORP Board of Directors in September 2013 an additional increase to the quarterly dividend of at least ten percent.

Brief Overview of Second Quarter 2013 Financial Results

IDACORP's earnings were $0.91 per diluted share for the quarter ended June 30, 2013, compared to $0.71 per diluted share for the same quarter in 2012. IDACORP's results in the second quarter of 2013 were positively impacted by general rate increases implemented during 2012, most notably the inclusion of the Langley Gulch power plant in Idaho rates in July 2012 and in Oregon rates in October 2012, as well as increased sales volumes. Based on Idaho Power's June 30, 2013 estimate of full-year 2013 return on year-end equity in the Idaho jurisdiction (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 a December 2011 settlement stipulation with the IPUC. That 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 number of regulatory filings and activity during the period from 2010 to 2012 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 general rate case 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.

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Rate proceedings that have significantly impacted results for the first half of 2013 compared to the first half of 2012, or that are otherwise particularly notable, 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⁾
Idaho 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 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 June 30, 2013 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. 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.

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 both a national 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. Idaho Power has observed what it believes to be a number of improvements in economic conditions during 2012 and into the first half 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 6.5 percent at the end of June 2013, according to Idaho Department of Labor data. The housing market in Idaho Power's service territory has improved when measured by foreclosure rates, market prices, and available supply of housing. 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.

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Idaho Power continues to predict that customer growth within its service territory in the next few years will be positive. 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 customer numbers. However, should there be a significant increase in loads due to new large-load customers or increased general economic activity, near-term growth could exceed projections and Idaho Power may be required to adjust its infrastructure development 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. 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 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 increased demand for electric power for the operation of air conditioning units and irrigation equipment.

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 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 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,

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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 capacity, were contributing only 57 MW of power due to lack of wind. Increases in federally mandated PURPA power purchases has 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 or ability of joint owners of power plants to fund any required pollution control equipment upgrades in lieu of early plant retirements. 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.

Other Notable Matters and Areas of Focus

Pension Plan Funding: From 2010 to 2012 Idaho Power contributed $123 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 made a discretionary contribution of $10 million in the first half of 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. Based on Idaho Power's assessment of the status and future milestones for the Boardman-to-Hemingway project, of which Idaho Power is the project manager, Idaho Power continues to believe that an in-service date prior to 2018 is unlikely. Idaho Power included the Boardman-to-Hemingway project in its preferred resource portfolio in the 2013 IRP.

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

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



	Three months ended June 30,				Six months ended June 30,
	2013		2012		2013		2012
Idaho Power net income	$	44,983	$	34,709	$	79,029	$	60,529
Net income attributable to IDACORP, Inc.	$	45,513	$	35,301	$	79,046	$	60,230
Average outstanding shares – diluted (000’s)	50,108		49,984		50,086		49,944
IDACORP, Inc. earnings per diluted share	$	0.91	$	0.71	$	1.58	$	1.21

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



	Three months ended						Six months ended
Net income attributable to IDACORP, Inc. - June 30, 2012				$	35.3					$	60.2
Change in Idaho Power net income:
Rate changes, net of changes in power supply costs and PCA mechanisms	$	16.0					$	29.8
Increase in sales volumes attributable to usage per customer, net of associated power supply costs and PCA mechanism impacts	6.5						12.7
Increases in sales volumes attributable to customer growth, net of associated power supply costs and PCA mechanism impacts	2.8						4.6
Other changes in operating revenues and expenses, net	1.0						(0.9		)
Increase in Idaho Power operating income prior to sharing mechanisms	26.3						46.2
Revenue sharing recorded in second quarter 2013	(2.8		)				(2.8		)
Increase in Idaho Power operating income	23.5						43.4
Decrease in allowance for funds used during construction (AFUDC)	(6.8		)				(12.8		)
Changes in other non-operating income and expense	(0.7		)				(3.3		)
Additional amortization of ADITC in 2012	0.8						—
Increase in income tax expense	(6.5		)				(8.8		)
Total increase in Idaho Power net income				10.3						18.5
Other net changes (net of tax)				(0.1		)				0.3
Net income attributable to IDACORP, Inc. - June 30, 2013				$	45.5					$	79.0

Second Quarter 2013 Net Income

IDACORP net income increased $10.2 million for the second quarter of 2013 when compared with the same period in the prior year. Idaho Power's operating income increased by $23.5 million over the comparative period. Rate changes that took effect in 2012, primarily increased rates related to the Langley Gulch power plant, increased operating income by $16.0 million for the quarter. In addition, increased sales volumes compared to the prior year's second quarter, led by a 14.5 percent increase in sales to irrigation customers, increased operating income by $9.3 million. The rate impact of the Langley Gulch plant was tempered by associated decreases in AFUDC of $6.8 million and increased depreciation and operating expenses related to the plant.

As a result of the rate and sales volume increases described above and their anticipated impact on annual net income, Idaho Power recorded $2.8 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 settlement agreement with the IPUC, which requires sharing with Idaho customers of a portion of 2013 Idaho-jurisdiction earnings exceeding a 10.0 percent Idaho ROE. In the second quarter of 2012, Idaho Power did not record any similar provision for sharing.

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Year-to-Date Net Income

IDACORP net income increased $18.8 million for the first six months of 2013 when compared with the same period in the prior year. Idaho Power's operating income increased by $43.4 million over the comparative period. Higher rates, mostly related to the Langley Gulch power plant, improved operating income by $29.8 million, which was partially offset by a decrease in AFUDC of $12.8 million and by increased depreciation and operating expenses related to the plant. Increased sales volumes, largely resulting from greater irrigation sales and abnormally cold winter temperatures in 2013, increased operating income by $17.3 million. Operating income for the first six months of 2013 was also impacted by the sharing mechanism discussed above, with a provision against current revenues of $2.8 million recorded in the first half of 2013 but none recorded in the first half of 2012.

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)⁽³⁾	$335-$345	$340-$350
Idaho Power Additional Amortization of ADITC (millions)	No Change	$0
Idaho Power Capital Expenditures, excluding AFUDC (millions) ⁽⁴⁾	$230-$240	$245-$255
Idaho Power Hydroelectric Generation (million MWh) ⁽⁵⁾	5.5-6.0	5.0-7.0

⁽¹⁾As of August 1, 2013.
⁽²⁾As of May 2, 2013, the date of filing of IDACORP's and Idaho Power's Quarterly Report on Form 10-Q for the quarter ended March 31, 2013.
⁽³⁾The reduction in projected expenses stem from efforts supporting Idaho Power's business optimization initiative.
⁽⁴⁾The estimated 2013 capital expenditures for selective catalytic reduction equipment 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 the 2012 Form 10-K and Form 10-Q for the quarter ended March 31, 2013, due to a delay of initiation of the project in 2013, which has resulted in reallocation of a portion of the anticipated 2013 expenditures to 2014.
⁽⁵⁾Based on reservoir storage levels and forecasted weather conditions as of the date of this report.

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 six months ended June 30, 2013. In this analysis, the results for the three and six months ended June 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 six months ended June 30, 2013 and 2012.



	Three months ended June 30,				Six months ended June 30,
	2013		2012		2013		2012
General business sales	3,649		3,459		6,997		6,637
Off-system sales	200		575		701		1,548
Total energy sales	3,849		4,034		7,698		8,185
Hydroelectric generation	1,499		2,414		3,009		4,981
Coal generation	1,316		647		2,973		1,853
Natural gas and other generation	264		189		491		201
Total system generation	3,079		3,250		6,473		7,035
Purchased power	1,080		1,200		1,801		1,844
Line losses	(310	)	(416	)	(576	)	(694	)
Total energy supply	3,849		4,034		7,698		8,185

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Sales Volume and Generation: In the second quarter and first six months of 2013, general business sales volume increased by 190 thousand MWh and 360 thousand MWh, respectively, compared to the same periods in the prior year, mostly as a result of increased irrigation and residential customer usage. The comparative increase in irrigation customer usage is due to agricultural growing conditions, whereas the increase in residential customer usage is largely attributable to more extreme temperatures, which increased electricity demand for heating and cooling. Conversely, off-system sales volume decreased by 375 thousand MWh and 847 thousand MWh in the second quarter and first six months, respectively, of 2013 as decreases in output from hydroelectric resources and an increase in customer load decreased surplus power available for off-system sales.

Hydroelectric generation comprised 49 percent and 46 percent of Idaho Power's total system generation during the second quarter and first six months of 2013, respectively. The 915 thousand MWh and 2.0 million MWh decrease in hydroelectric generation in the second quarter and first six 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. 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.

Idaho Power has a ten percent ownership interest in the Boardman coal-fired plant located near Boardman, Oregon, representing approximately 64 MW of nameplate capacity. On July 1, 2013 the plant went off-line as a result of structural damage to a portion of the plant. The damage has required repairs that prevented operation of the plant until July 31. As a result of the unplanned outage, Idaho Power incurred incremental costs to replace its share of the output of the plant through Idaho Power's other energy supply resources, including power purchased in the wholesale markets. Idaho Power's PCA mechanisms address most of any increased costs resulting from the outages, and Idaho Power expects that its financial exposure for any repairs would be largely mitigated through insurance recovery for repair work.

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 currently on 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 spot 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 six months ended June 30, 2013 and 2012 and the number of customers as of June 30, 2013 and 2012.



	Three months ended June 30,						Six months ended June 30,
	2013			2012			2013			2012
Revenue
Residential	$	100,038		$	83,632		$	236,425		$	196,178
Commercial	66,757			55,841			128,632			109,278
Industrial	39,230			33,786			75,068			67,127
Irrigation	63,556			49,604			64,330			50,276
Total	269,581			222,863			504,455			422,859
Provision for sharing	(2,800		)	—			(2,800		)
Deferred revenue related to HCC relicensing AFUDC ⁽¹⁾	(2,349		)	(2,334		)	(5,004		)	(4,901		)
Total general business revenues	$	264,432		$	220,529		$	496,651		$	417,958
Volume of Sales (MWh)
Residential	1,069			1,037			2,625			2,472
Commercial	949			919			1,935			1,867
Industrial	772			753			1,570			1,540
Irrigation	859			750			867			758
Total MWh sales	3,649			3,459			6,997			6,637
Number of customers at period end
Residential	418,213			413,266
Commercial	66,334			65,578
Industrial	117			115
Irrigation	19,376			19,037
Total customers	504,040			497,996

⁽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 six months of 2013 when compared to the same period in 2012.



Description	Effective Date	Percentage Rate Increase (Decrease)		Annualized $ 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 six months ended June 30, 2013 and 2012 is presented in the table below.

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	Three months ended June 30,			Six months ended June 30,
	2013	2012	Normal	2013	2012	Normal
Heating degree-days⁽¹⁾	642	608	719	3,474	2,848	3,199
Cooling degree-days ⁽¹⁾	238	199	183	238	199	183
⁽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 substantial majority of Idaho Power's customers.

General business revenue increased $43.9 million and $78.7 million for the three and six months ended June 30, 2013, respectively, compared to the same periods in 2012. Specific factors affecting general business revenues are discussed below.

•

Rates. Rate changes, including those shown in the table above, combined to increase general business revenue by $36.6 million in the quarter and $62.3 million in the first six 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, depreciation expense related to the Langley Gulch plant increased approximately $6 million in the first six months of 2013 compared to the same period in the prior year, offsetting a portion of the associated rate increase.

•

Usage. Higher usage by all classes of customers increased general business revenue for the quarter by $9.1 million when compared to the second quarter of 2012. Higher usage per customer also increased general business revenue for the first six months of 2013 by $18.6 million compared to the same period in 2012. For the second quarter and first six months of 2013, irrigation usage per customer increased 12.9 percent and 13.0 percent, respectively, compared to the same periods in the prior year, resulting from lower comparative precipitation and the timing of that precipitation. Residential use per customer increased 1.9 percent for the second quarter and 5.0 percent for the first six months of 2013, due largely to hotter summer temperatures and abnormally cold winter temperatures.

•

Customers. Customer growth drove an increase in overall MWh sales for the second quarter and first six months of 2013 and a $3.4 million and $6.0 million respective increase in general business revenues when compared to the second quarter and first six months of 2012. Total customers increased 1.2 percent during the twelve months ending June 30, 2013. The positive impact of customer growth was offset by a $2.4 million and $5.4 million decrease in revenues for the comparative quarter and first six months, respectively, resulting from the termination of service to Hoku Materials, Inc. during 2012 under an electric service agreement. Combined, these changes increased general business revenues by $1.0 million for the second quarter and $0.6 million for the first six months of 2013 when compared to the same periods in 2012.

•

Sharing. The overall increases in revenue for the second quarter and first six months of 2013 were offset by the recording of $2.8 million as a provision against current revenues to be refunded to customers through a future rate reduction. This revenue sharing was related to a December 2011 settlement agreement with the IPUC, which required sharing with customers of a portion of 2013 Idaho-jurisdiction earnings exceeding a 10.0 percent Idaho ROE. In the second quarter of 2012, no similar provision was recorded.

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 six months ended June 30, 2013 and 2012.



	Three months ended June 30,				Six months ended June 30,
	2013		2012		2013		2012
Revenue	$	4,527	$	11,418	$	20,428	$	39,126
MWh sold	200		575		701		1,548
Revenue per MWh	$	22.64	$	19.86	$	29.14	$	25.28

For the second quarter and first six months of 2013, off-system sales revenue decreased by $6.9 million, or 60 percent, and $18.7 million, or 48 percent, respectively, as compared to the same periods in 2012. Off-system sales volumes decreased 65 percent for the quarter and 55 percent for the first six months of 2013 when compared to the same periods in 2012, as a result of decreased hydroelectric generation and increased system load. The decreases in volume were partially offset by 14 percent and 15 percent increases in average prices for the quarter and for the first six months of 2013, respectively.

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



	Three months ended June 30,				Six months ended June 30,
	2013		2012		2013		2012
Transmission services and other	$	14,165	$	13,516	$	25,944	$	24,385
Energy efficiency	19,732		8,084		24,202		12,561
Total other revenues	$	33,897	$	21,600	$	50,146	$	36,946

Other revenue increased $12.3 million and $13.2 million for the second quarter and first six months of 2013, respectively, compared to the same periods in 2012. Energy efficiency revenues increased 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.

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.

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



	Three months ended June 30,				Six months ended June 30,
	2013		2012		2013		2012
Expense
PURPA contracts	$	33,432	$	29,602	$	64,089	$	53,359
Other purchased power (including wheeling)	15,719		15,576		27,919		26,097
Total purchased power expense	$	49,151	$	45,178	$	92,008	$	79,456
MWh purchased
PURPA contracts	640		576		1,152		992
Other purchased power	440		624		649		852
Total MWh purchased	1,080		1,200		1,801		1,844
Cost per MWh from PURPA contracts	$	52.24	$	51.39	$	55.63	$	53.79
Cost per MWh from other sources	$	35.73	$	24.96	$	43.02	$	30.63
Weighted average - all sources	$	45.51	$	37.65	$	51.09	$	43.09

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 $4.0 million, or 9 percent, in the second quarter of 2013 and $12.6 million, or 16 percent, in the first six months of 2013, compared to the same periods in 2012. This increase was driven by the volume of mandated power purchases from cogeneration and small power production (CSPP) facilities pursuant to PURPA, which increased 11 percent for the quarter and 16 percent in the first six months of 2013 due to PURPA wind generation facilities providing more generation than in the prior year.

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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.

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



	Three months ended June 30,				Six months ended June 30,
	2013		2012		2013		2012
Expense
Coal	$	32,200	$	17,052	$	72,516	$	48,137
Natural gas and other thermal	9,678		4,233		18,528		5,899
Total fuel expense	$	41,878	$	21,285	$	91,044	$	54,036
MWh generated
Coal	1,316		647		2,973		1,853
Natural gas and other thermal	264		59		491		71
Total MWh generated	1,580		706		3,464		1,924
Cost per MWh
Coal	$	24.47	$	26.36	$	24.39	$	25.98
Natural gas and other thermal	$	36.66	$	71.75	$	37.74	$	83.08
Weighted average, all sources	$	26.51	$	30.15	$	26.28	$	28.09

Fuel expense increased $20.6 million, or 97 percent, in the second quarter of 2013 and $37.0 million, or 68 percent, in the first six months of 2013 compared to the same periods in 2012, due principally to the following factors:

•

Generation from coal-fired facilities doubled for the second quarter of 2013 and increased 61 percent for the first six months of 2013 compared to the same periods in 2012. During the quarter and first six months, higher wholesale power prices and lower hydroelectric generation when compared with the same periods in the prior year significantly increased Idaho Power's reliance on its coal-fired plants to meet customer loads.

•

Idaho Power's Langley Gulch natural gas-fired power plant came on line on June 29, 2012. Operation of the plant accounted for $5.8 million of the increase in fuel expense for the second quarter and $10.6 million for the first six months of 2013. Idaho Power operated the plant primarily to serve peak load, to integrate intermittent resources, and for economic dispatch opportunities. The significant decrease in cost per MWh for natural gas and other thermal facilities shown in the table above is in large part attributable to the spreading of fuel-related fixed costs of natural gas-fired plants over a greater volume of generation from those plants—most notably, operation of the Langley Gulch power plant.

Most fuel supply contracts are subject to changes in published indexes that are closely related to materials and supplies, labor, and diesel costs. In addition to commodity (variable) costs, both natural gas and coal expense include costs that are more fixed in nature for items such as capacity charges, transportation, and fuel handling. Period to period variances in fuel expense per MWh (such as the cost per MWh for natural gas and other thermal in 2013 compared to 2012) are noticeably impacted by these fixed charges when generation output is substantially different between the two periods.

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 expenses associated with 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.

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The table below presents the components of the Idaho and Oregon PCA mechanisms for the three and six months ended June 30, 2013 and 2012.



	Three months ended June 30,						Six months ended June 30,
	2013			2012			2013			2012
Idaho power supply cost (deferral) accrual	$	(15,348	)	$	985		$	(25,102	)	$	10,610
Oregon power supply cost deferral	—			(1,385		)	—			(1,523		)
Amortization of prior year authorized balances	2,049			(2,811		)	(2,907		)	(3,289		)
Total power cost adjustment expense	$	(13,299	)	$	(3,211	)	$	(28,009	)	$	5,798

The power supply deferrals or accruals represent the portion of the power supply cost fluctuations deferred or accrued 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 six months of 2013, most of the excess cost is deferred. In 2012, power supply costs were accrued because actual power supply costs were less than the amount forecasted for inclusion in PCA rates.

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 increased $11.6 million for the second quarter and the first six months of 2013 compared to the same periods in 2012. This increase was related to an order issued by the IPUC that approved the 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: Due in part to Idaho Power's efforts around cost management referred to above, other O&M expense decreased $2.9 million for the second quarter and $1.6 million for the first six months of 2013 as compared to the same periods in 2012. The changes in other O&M expense were due to the following:


•	decreased labor and administrative costs, which decreased $2.5 million for the quarter and $1.7 million for the first six months; and


•	decreased thermal plant O&M costs of $0.9 million for the quarter related to changes in the scope and timing of outage work at one of the coal plants.

Income Taxes

Income Tax Expense: IDACORP's and Idaho Power's income tax expense for the six months ended June 30, 2013, compared to the same period in 2012, increased $8.1 million and $8.8 million, respectively, primarily as a result of greater Idaho Power pre-tax earnings. 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.

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.

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.

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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 year-to-date in 2013) through 2015. A significant focus for 2013 will be to continue to control costs and to generate sufficient cash from operations to meet operating needs, contribute to capital expenditure requirements, and pay dividends to shareholders.

As of July 26, 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;


•	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.

IDACORP and Idaho Power monitor capital markets with a view toward opportunistic debt and equity transactions where possible in light of future needs. IDACORP and Idaho Power expect to continue financing capital requirements during the remainder of 2013 with a combination of existing cash and operating cash flows generated by Idaho Power's utility business. IDACORP and Idaho Power believe that these amounts, together with access to the companies' credit facilities and commercial paper markets, will be sufficient to meet short-term obligations and debt maturities in 2013.

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. IDACORP may also determine to issue common stock from time-to-time in at-the-market offerings under its continuous equity program, depending on market conditions and capital needs. An important component of that determination will be IDACORP's and Idaho Power's capital structure.

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 June 30, 2013, IDACORP's and Idaho Power's capital structures were as follows:

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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. Idaho Power currently has outstanding $70 million in principal amount of its 4.25% first mortgage bonds due in October 2013, with no first mortgage bonds due thereafter until 2018. Idaho Power intends to use a portion of the net proceeds from its April 2013 issuance of first mortgage bonds to satisfy its obligations upon maturity of the 4.25% first mortgage bonds due in October 2013.

Idaho Power's issuance of the Series I medium-term notes in April 2013, combined with the issuance of $200 million in principal amount of medium-term notes in August 2010 and $150 million in principal amount of medium-term notes 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. Consistent with Idaho Power's historical practice of maintaining long-term financing authority from state public utility commissions, and in light of the then-perceived potential to issue medium-term notes in an amount that would exhaust the then-available regulatory authority for long-term debt issuances, during the first half of 2013 and into July 2013, IDACORP and Idaho Power obtained necessary state regulatory approvals, filed a registration statement with the SEC, executed selling agency arrangements, and took other actions necessary to 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 six months ended June 30, 2013 were $114 million and $112 million, respectively, increases of $31 million and $33 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 six months of 2013 relative to the same period in 2012 were as follows:


•	net income increased by $19 million;


•	Idaho Power made a $10 million cash contribution to its defined benefit pension plan in 2013, compared to $34 million in cash contributions during the first six months of 2012;


•	changes in regulatory assets and liabilities, mostly related to the relative amounts of power supply costs deferred under the Idaho PCA mechanism, reduced operating cash inflows by $39 million; and


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

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 investing cash outflows for the six months ended June 30, 2013 were $105 million and $106 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.

IDACORP’s and Idaho Power's financing cash inflows for the six months ended June 30, 2013 were $100 million and $109 million, respectively. The following are significant items that affected financing cash flows in the first six 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; and


•	IDACORP and Idaho Power paid cash dividends of approximately $38 million.

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Idaho Power has $70 million in principal amount of 4.25% first mortgage bonds due in October 2013. Idaho Power plans to use a portion of the net proceeds from its April 8, 2013 issuance of first mortgage bonds to satisfy its obligations upon maturity of those 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, 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 August 1, 2013, Idaho Power had not sold any first mortgage bonds or debt securities under the May 2013 shelf registration statement or Selling Agency Agreement and did 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 June 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 June 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 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

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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 June 30, 2013, the leverage ratios for IDACORP and Idaho Power were 49 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 June 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 take appropriate action 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 each of the lenders, extending the maturity date under both agreements to October 26, 2017. No other terms of the credit agreements, including the amount of permitted borrowings under the credit agreements, were affected by the extension.

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 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 may 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.

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



	June 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	(61,900		)	—			(69,700		)	—
Identified for other use ⁽¹⁾	—			(24,245		)	—			(24,245		)
Net balance available	$	63,100		$	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 July 26, 2013, IDACORP had no loans outstanding under its credit facility and $61.0 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 six months ended June 30, 2013.



	Three months ended						Six months ended
	June 30, 2013						June 30, 2013
	IDACORP ⁽¹⁾			Idaho Power			IDACORP ⁽¹⁾			Idaho Power
Commercial paper:
Period end:
Amount outstanding	$	61,900		$	—		$	61,900		$	—
Weighted average interest rate	0.37		%	—		%	0.37		%	—		%
Daily average amount outstanding during the period	$	66,632		$	455		$	65,893		$	4,455
Weighted average interest rate during the period	0.38		%	0.41		%	0.42		%	0.43		%
Maximum month-end balance	$	67,100		$	—		$	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 June 30, 2013, Idaho Power had posted no 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 liability positions. Based upon Idaho Power’s current energy and fuel portfolio and market conditions as of June 30, 2013, the amount of additional collateral that could be requested upon a downgrade to below investment grade is approximately $8.6 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.

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Capital Requirements

Idaho Power's construction expenditures, excluding AFUDC, were $105 million during the six months ended June 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 and Form 10-Q for the quarter ended March 31, 2013, 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, and thus its ratemaking treatment, prior to Idaho Power's incurring the bulk of the associated expenses. A determination and order from the IPUC are 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. 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 approximately $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.

In February 2013, Idaho Power filed its preliminary application for a site certificate with the Oregon Department of Energy and is responding to additional requests for information. Issuance of a site certificate is required prior to commencement of construction of the transmission line. Additionally, federal permitting activities continue to move forward. The U.S. Bureau of Land Management (BLM) has requested additional information and that further analysis be performed prior to issuing the draft environmental impact statement (EIS) for public review and comment. This is anticipated to delay the release date of the draft EIS from mid-2013 to early 2014. The overall impact of the delay in release of the draft EIS to the project schedule is unknown; however, the completion date of the project can be impacted by new developments such as this and remains subject

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to a number of other siting, permitting, regulatory approvals, in-service date requirements of the parties electing to construct the line, the terms of any resulting joint construction agreements, and other conditions. Based on Idaho Power's assessment of those and other factors, Idaho Power continues to expect that a project in-service date prior to 2018 is unlikely.

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 Integrated Resource Plan (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 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. The 2013 IRP also identifies a number of significant plant upgrades and environmental control technology installations, involving substantial capital expenditures.

At times, 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.

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

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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, and provided for retirement or divestiture of its interests in other of NV Energy's coal-fired plants in the relative near-term. 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 in discussions with NV Energy regarding the legislation and announcement and is 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 a discretionary contribution of $10 million in the first half of 2013. Idaho Power expects to make additional significant cash contributions to the pension plan in the future.

Contractual Obligations

During the six months ended June 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:


•	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, medium-term notes, Series I, maturing on April 1, 2023, and $75 million in principal amount of 4.00% first mortgage bonds, medium-term notes, Series I, maturing on April 1, 2043.

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 requirements, 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.

On January 19, 2012, IDACORP's board of directors voted to increase the quarterly dividend, commencing with the dividend paid on February 29, 2012, to $0.33 per share of IDACORP common stock, from the prior quarterly dividend amount of $0.30 per share of IDACORP common stock. On September 20, 2012, IDACORP's board of directors voted to increase the quarterly dividend again in 2012, commencing with the dividend payable on November 30, 2012, to $0.38 per share of IDACORP common stock. As of the date of this report, IDACORP’s management continues to anticipate recommending to the board of directors an additional increase to the quarterly dividend in September 2013 of at least ten percent.

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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.

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 half of 2013 relative to the first half of 2012.

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Notable Rate Filings and Orders During 2013

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



Description	Status	Estimated Annual 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. Thus, while the PCA rate change can have a significant impact on customer rates, the impact on Idaho Power's financial condition is largely limited to the timing of cash flows. The April 15, 2013 IPUC filing and May 31, 2013 IPUC order is discussed in more detail 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 allowed fixed-cost recovery amount and the actual fixed costs recovered by Idaho Power during the year.
Custom Efficiency Program - Idaho Order	The IPUC issued an order denying Idaho Power's application to amortize and collect a portion of the asset, but subsequently 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.

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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.

Idaho Power's 2012 Idaho ROE exceeded 10.5 percent, triggering both sharing components of the December 2011 settlement stipulation. For 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 June 30, 2013 estimate that full-year 2013 Idaho ROE will exceed 10.0 percent, Idaho Power recorded in the second quarter of 2013 a $2.8 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 estimates 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 six months ended June 30, 2013.



	Idaho			Oregon ⁽¹⁾			Total
Balance at December 31, 2012	$	34,571		$	8,331		$	42,902
Current period net power supply costs deferred	25,102			—			25,102
Prior amounts returned (recovered) through rates	15,709			(1,121		)	14,588
SO₂ allowance and renewable energy certificate (REC) sales	(432		)	(11		)	(443		)
Revenue sharing liability applied to PCA true-up mechanism	(7,172		)	—			(7,172		)
Interest and other	225			239			464
Balance at June 30, 2013	$	68,003		$	7,438		$	75,441

⁽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);


•	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 cost 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.

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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 demand response programs that Idaho Power had previously implemented to reduce peak-hour loads. 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.

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 May 31, 2013, Idaho Power publicly posted its 2013 draft transmission rate. On July 12, 2013, Idaho Power posted an updated draft transmission rate of $22.80 per kW-year, to be effective for the period from October 1, 2013 to September 30, 2014. Idaho Power is required to file its final transmission rate with the FERC by September 1, 2013. Idaho Power's draft posting was based on its net annual transmission revenue requirement of $118.2 million. The OATT rate in effect from October 1, 2012 to September 30, 2013 is $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 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. 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.

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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 six months ended June 30, 2013 as compared with $2.3 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 June 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 renewable generation sources, such as biomass and small hydroelectric projects. As of June 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 table below.



Status	Number of CSPP Contracts	Nameplate Capacity (MW)
On-line as of June 30, 2013	103	784
Contracted and projected to come on-line by year-end 2013	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 $170.2 million for the HCC, Idaho Power's largest hydroelectric complex and a major relicensing effort, were included in construction work in progress at June 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 June 30, 2013, Idaho Power had collected $33.6 million ($51.9 million grossed up for income taxes) of AFUDC related to the HCC relicensing project through customer rates.

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.

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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 of 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, will necessitate the installation of additional pollution control devices at existing generating plants, or result in Idaho Power discontinuing the operation of one or more coal-fired plants where 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 on April 24, 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 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 Jim Bridger power

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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.

Executive Order on CAA Regulations: On June 25, 2013, President Obama issued a Presidential Memorandum entitled "Power Sector Carbon Pollution Standards," in which he directed the EPA to (a) re-propose and then issue final rules relating to greenhouse gases for new EGUs, and (b) issue standards, regulations, or guidelines under the CAA to address carbon pollution from modified, reconstructed, and existing power plants, to be finalized by June 2015. The Presidential Memorandum provided that the EPA shall, to the greatest extent possible, engage states and other stakeholders on issues informing the design of the program, and develop approaches that allow the use of market-based instruments, performance standards, or other regulatory flexibilities. The Presidential Memorandum further provided that the EPA is to ensure, to the greatest extent possible, that the standards are developed and implemented in a manner consistent with the continued provision of reliable and affordable electric power. Idaho Power will be monitoring the resulting EPA actions as they develop. Because the Presidential Memorandum addresses both new and existing EGUs, Idaho Power could incur additional costs for environmental controls at its existing thermal plants, and the cost of developing new EGUs could also increase. However, as the EPA has not yet proposed rules or standards arising from the Presidential Memorandum, Idaho Power is unable to predict the magnitude of the cost increases, if any.

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 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 June 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 June 30, 2013, IDACORP had $19.2 million in net floating rate debt. The fair market value of this debt was $19.2 million. Assuming no change in financial structure, if variable interest rates were to average one percentage point higher than average rate on June 30, 2013, interest rate expense would increase and pre-tax earnings would decrease by approximately $0.2 million. As of June 30, 2013, Idaho Power, after netting with short term investments, had no floating rate debt.

Fixed Rate Debt: As of June 30, 2013, IDACORP and Idaho Power each had $1.7 billion in fixed rate debt, with a fair market value equal to $1.8 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 $128.2 million for both IDACORP and Idaho Power if market interest rates were to decline by one percentage point from their June 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 June 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 June 30, 2013, Idaho Power had posted no 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 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 June 30, 2013, the approximate amount of collateral that could be requested upon a downgrade to below investment grade was approximately $8.6 million. Idaho Power actively monitors the portfolio exposure and the potential exposure to additional requests for performance assurance collateral calls, through sensitivity analysis, to minimize capital requirements.

Idaho Power’s credit risk related to uncollectible accounts as of June 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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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. IDACORP’s and Idaho Power’s equity price risk as of June 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 June 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 June 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

There have been no changes in IDACORP’s or Idaho Power’s internal control over financial reporting during the quarter ended June 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. There have been no material changes from the risk factors set forth in that section. 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.

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.

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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

During the quarter ended June 30, 2013, IDACORP effected the following repurchases of its common stock:



Period	(a) Total Number of Shares Purchased ⁽¹⁾	(b) Average Price Paid per Share		(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	(d) Maximum Number (or approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs
April 1, 2013 - April 30, 2013	—	$	—	—	—
May 1, 2013 - May 31, 2013	—	—		—	—
June 1, 2013 - June 30, 2013	52	47.76		—	—
Total	52	$	47.76	—	—

⁽¹⁾ These shares were withheld for taxes upon vesting of restricted stock.

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, Inc. and Idaho Power Company 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:	August 1, 2013	By:	/s/ J. LaMont Keen
			J. LaMont Keen
			President and Chief Executive Officer

Date:	August 1, 2013	By:	/s/ Darrel T. Anderson
			Darrel T. Anderson
			Executive Vice President - Administrative
			Services and Chief Financial Officer





		IDAHO POWER COMPANY
		(Registrant)



Date:	August 1, 2013	By:	/s/ J. LaMont Keen
			J. LaMont Keen
			Chief Executive Officer

Date:	August 1, 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 June 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
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
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