Edgar Filing: IDACORP INC

IDA 9.30.14 10Q

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)



X	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
	EXCHANGE ACT OF 1934
	For the quarterly period ended September 30, 2014
	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 October 24, 2014:

IDACORP, Inc.: 50,268,748

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		33
	Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations			35
	Item 3. Quantitative and Qualitative Disclosures About Market Risk			59
	Item 4. Controls and Procedures			61

Part II. Other Information:

	Item 1. Legal Proceedings			61
	Item 1A. Risk Factors			61
	Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			61
	Item 3. Defaults Upon Senior Securities			61
	Item 4. Mine Safety Disclosures			61
	Item 5. Other Information			62
	Item 6. Exhibits			64

Signatures				65

Exhibit Index				66

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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
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
EIS	-	Environmental Impact Statement
EPA	-	U.S. Environmental Protection Agency
FCA	-	Fixed Cost Adjustment
FERC	-	Federal Energy Regulatory Commission
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	-	Public Utility Commission of Oregon
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
SMSP	-	Security Plan for Senior Management Employees
SO₂	-	Sulfur Dioxide
SRBA	-	Snake River Basin Adjudication
WPSC	-	Wyoming Public Service Commission

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

In addition to the historical information contained in this report, this report contains (and oral communications made by IDACORP, Inc. and Idaho Power Company may contain) statements that relate to future events and expectations, such as statements regarding projected or future financial performance, cash flows, capital expenditures, dividends, capital structure or ratios, strategic goals, challenges, objectives, and plans for future operations. Such statements constitute forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Any statements that express, or involve discussions as to, expectations, beliefs, plans, objectives, assumptions, or future events or performance, often, but not always, through the use of words or phrases such as "anticipates," "believes," "estimates," "expects," "intends," "plans," "predicts," "projects," "may result," "may continue," "may allow," "continues," 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, 2013, particularly Part I, Item 1A - “Risk Factors” and Part II, Item 7 - “Management’s Discussion and Analysis of Financial Condition and Results of Operations" of that report, subsequent reports filed by IDACORP and Idaho Power with the Securities and Exchange Commission, and the following important factors:


•	the effect of decisions by the Idaho and Oregon public utilities commissions, the Federal Energy Regulatory Commission, and other regulators that impact 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 demand-side management programs, and their associated impacts 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 of receivables;


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


•	advancement of technologies that reduce loads or reduce the need for Idaho Power's generation of electric power;


•	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;


•	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, 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 credit and contractual arrangements;


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


•	the ability to purchase fuel and power 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 buy and sell power, transmission capacity, and fuel in the markets;


•	the ability to enter into financial and physical commodity hedges with creditworthy counterparties to manage price and commodity risk, and the failure of any such risk management and hedging strategies to work as intended;


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


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

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•	the increased costs and operational challenges associated with purchasing and integrating intermittent renewable energy sources into Idaho Power's resource portfolio;


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


•	the ability to continue to pay dividends based on financial performance, and in light of contractual covenants and restrictions and regulatory limitations;


•	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 and retirements, 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 fines 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, and regulatory proceedings, 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;


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


•	adoption of or changes in accounting policies and principles, changes in accounting estimates, and new Securities and Exchange Commission or New York Stock Exchange requirements, or new interpretations of existing requirements.

Any forward-looking statement speaks only as of the date on which such statement is made. New factors emerge from time to time and it is not possible for management to predict all such factors, nor can it assess the impact of any such factor on the business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement. IDACORP and Idaho Power disclaim any obligation to update publicly any forward-looking information, whether in response to new information, future events, or otherwise, except as required by applicable law.

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PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

IDACORP, Inc.

Condensed Consolidated Statements of Income

(unaudited)



	Three months ended September 30,						Nine months ended September 30,
	2014			2013			2014			2013
	(thousands of dollars, except for per share amounts)
Operating Revenues:
Electric utility:
General business	$	347,838		$	349,428		$	874,817		$	846,079
Off-system sales	15,449			11,169			56,390			31,597
Other revenues	17,424			19,707			58,479			69,853
Total electric utility revenues	380,711			380,304			989,686			947,529
Other	1,490			803			3,017			2,455
Total operating revenues	382,201			381,107			992,703			949,984
Operating Expenses:
Electric utility:
Purchased power	75,058			74,088			181,291			166,097
Fuel expense	67,088			64,858			156,859			155,901
Power cost adjustment	(668		)	(6,960		)	23,496			(34,969		)
Other operations and maintenance	84,236			84,471			252,208			247,409
Energy efficiency programs	5,537			6,077			17,881			30,279
Depreciation	33,476			32,538			99,304			96,680
Taxes other than income taxes	8,340			7,017			24,685			23,243
Total electric utility expenses	273,067			262,089			755,724			684,640
Other	3,412			3,459			10,869			10,945
Total operating expenses	276,479			265,548			766,593			695,585
Operating Income	105,722			115,559			226,110			254,399
Allowance for Equity Funds Used During Construction	4,645			3,734			13,182			10,876
Earnings of Unconsolidated Equity-Method Investments	6,414			6,261			8,908			9,402
Other Income, Net	1,193			1,567			4,733			3,982
Interest Expense:
Interest on long-term debt	20,141			20,887			60,423			61,349
Other interest	1,908			1,812			5,714			5,296
Allowance for borrowed funds used during construction	(2,178		)	(1,904		)	(6,287		)	(5,711		)
Total interest expense, net	19,871			20,795			59,850			60,934
Income Before Income Taxes	98,103			106,326			193,083			217,725
Income Tax Expense	10,869			33,222			33,968			62,941
Net Income	87,234			73,104			159,115			154,784
Adjustment for (income) loss attributable to noncontrolling interests	(345		)	15			(283		)	31
Net Income Attributable to IDACORP, Inc.	$	86,889		$	73,119		$	158,832		$	154,815
Weighted Average Common Shares Outstanding - Basic (000’s)	50,129			50,056			50,131			50,051
Weighted Average Common Shares Outstanding - Diluted (000’s)	50,220			50,153			50,184			50,109
Earnings Per Share of Common Stock:
Earnings Attributable to IDACORP, Inc. - Basic	$	1.73		$	1.46		$	3.17		$	3.09
Earnings Attributable to IDACORP, Inc. - Diluted	$	1.73		$	1.46		$	3.16		$	3.09
Dividends Declared Per Share of Common Stock	$	0.43		$	0.38		$	1.29		$	1.14

The accompanying notes are an integral part of these statements.

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IDACORP, Inc.

Condensed Consolidated Statements of Comprehensive Income

(unaudited)



	Three months ended September 30,					Nine months ended September 30,
	2014			2013		2014			2013
	(thousands of dollars)

Net Income	$	87,234		$	73,104	$	159,115		$	154,784
Other Comprehensive Income:
Net unrealized holding gains arising during the period, net of tax of $0, $541, $0 and $1,466	—			843		—			2,283
Unfunded pension liability adjustment, net of tax of $277, $298, $832 and $894	432			464		1,296			1,394
Total Comprehensive Income	87,666			74,411		160,411			158,461
Comprehensive (income) loss attributable to noncontrolling interests	(345		)	15		(283		)	31
Comprehensive Income Attributable to IDACORP, Inc.	$	87,321		$	74,426	$	160,128		$	158,492

The accompanying notes are an integral part of these statements.

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IDACORP, Inc.

Condensed Consolidated Balance Sheets

(unaudited)



	September 30, 2014			December 31, 2013
	(thousands of dollars)
Assets

Current Assets:
Cash and cash equivalents	$	111,038		$	78,162
Receivables:
Customer (net of allowance of $2,229 and $2,349, respectively)	93,272			97,873
Other (net of allowance of $158 and $153, respectively)	16,808			15,274
Taxes receivable	—			156
Accrued unbilled revenues	55,273			63,507
Materials and supplies (at average cost)	56,023			53,643
Fuel stock (at average cost)	44,733			41,546
Prepayments	12,954			15,338
Deferred income taxes	32,638			46,874
Current regulatory assets	50,995			61,837
Other	1,472			2,401
Total current assets	475,206			476,611
Investments	155,028			159,072
Property, Plant and Equipment:
Utility plant in service	5,194,535			5,080,402
Accumulated provision for depreciation	(1,823,870		)	(1,766,680		)
Utility plant in service - net	3,370,665			3,313,722
Construction work in progress	383,667			327,000
Utility plant held for future use	7,090			7,090
Other property, net of accumulated depreciation	17,332			17,229
Property, plant and equipment - net	3,778,754			3,665,041
Other Assets:
American Falls and Milner water rights	13,958			15,803
Company-owned life insurance	23,774			22,037
Regulatory assets	1,003,099			978,234
Long-term receivables (net of allowance of $885)	6,041			4,811
Other	42,417			42,954
Total other assets	1,089,289			1,063,839
Total	$	5,498,277		$	5,364,563

The accompanying notes are an integral part of these statements.

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IDACORP, Inc.

Condensed Consolidated Balance Sheets

(unaudited)



	September 30, 2014			December 31, 2013
	(thousands of dollars)
Liabilities and Equity

Current Liabilities:
Current maturities of long-term debt	$	1,064		$	1,064
Notes payable	31,800			54,750
Accounts payable	82,901			91,519
Taxes accrued	26,232			13,302
Interest accrued	24,885			22,764
Accrued compensation	40,101			38,510
Current regulatory liabilities	7,588			10,684
Other	25,132			17,779
Total current liabilities	239,703			250,372
Other Liabilities:
Deferred income taxes	1,030,076			969,593
Regulatory liabilities	385,055			375,873
Pension and other postretirement benefits	230,385			244,627
Other	45,292			54,100
Total other liabilities	1,690,808			1,644,193
Long-Term Debt	1,614,377			1,615,258
Commitments and Contingencies
Equity:
IDACORP, Inc. shareholders’ equity:
Common stock, no par value (shares authorized 120,000,000; 50,307,512 and 50,233,463 shares issued, respectively)	843,163			839,750
Retained earnings	1,121,390			1,027,461
Accumulated other comprehensive loss	(15,257		)	(16,553		)
Treasury stock (38,764 and 718 shares at cost, respectively)	(280		)	(8		)
Total IDACORP, Inc. shareholders’ equity	1,949,016			1,850,650
Noncontrolling interests	4,373			4,090
Total equity	1,953,389			1,854,740
Total	$	5,498,277		$	5,364,563

The accompanying notes are an integral part of these statements.

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IDACORP, Inc.

Condensed Consolidated Statements of Cash Flows

(unaudited)



	Nine months ended September 30,
	2014			2013
	(thousands of dollars)
Operating Activities:
Net income	$	159,115		$	154,784
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	102,366			99,534
Deferred income taxes and investment tax credits	25,355			46,891
Changes in regulatory assets and liabilities	36,595			(20,765		)
Pension and postretirement benefit plan expense	20,927			22,026
Contributions to pension and postretirement benefit plans	(32,533		)	(32,573		)
Earnings of unconsolidated equity-method investments	(8,908		)	(9,402		)
Distributions from unconsolidated equity-method investments	5,820			14,218
Allowance for equity funds used during construction	(13,182		)	(10,876		)
Other non-cash adjustments to net income, net	4,417			2,308
Change in:
Accounts receivable	4,372			(38,553		)
Accounts payable and other accrued liabilities	(3,359		)	(4,505		)
Taxes accrued/receivable	14,066			24,621
Other current assets	2,089			4,749
Other current liabilities	7,258			5,253
Other assets	(2,970		)	(1,253		)
Other liabilities	(5,601		)	(8,811		)
Net cash provided by operating activities	315,827			247,646
Investing Activities:
Additions to property, plant and equipment	(200,928		)	(165,550		)
Proceeds from the sale of emission allowances and RECs	2,923			498
Distributions from affordable housing investments	1,048			1,697
Other	4,335			3,366
Net cash used in investing activities	(192,622		)	(159,989		)
Financing Activities:
Issuance of long-term debt	—			150,000
Retirement of long-term debt	(1,064		)	(1,064		)
Dividends on common stock	(64,958		)	(57,323		)
Net change in short-term borrowings	(22,950		)	(16,700		)
Issuance of common stock	160			255
Acquisition of treasury stock	(2,737		)	(2,124		)
Other	1,220			(358		)
Net cash (used in) provided by financing activities	(90,329		)	72,686
Net increase in cash and cash equivalents	32,876			160,343
Cash and cash equivalents at beginning of the period	78,162			26,527
Cash and cash equivalents at end of the period	$	111,038		$	186,870
Supplemental Disclosure of Cash Flow Information:
Cash paid during the period for:
Income taxes	$	4,686		$	60
Interest (net of amount capitalized)	$	55,743		$	54,907
Non-cash investing activities:
Additions to property, plant and equipment in accounts payable	$	19,375		$	22,480

The accompanying notes are an integral part of these statements.

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IDACORP, Inc.

Condensed Consolidated Statements of Equity

(unaudited)



	Nine months ended September 30,
	2014			2013
	(thousands of dollars)
Common Stock
Balance at beginning of period	$	839,750		$	834,922
Issued	160			255
Other	3,253			3,398
Balance at end of period	843,163			838,575
Retained Earnings
Balance at beginning of period	1,027,461			923,981
Net income attributable to IDACORP, Inc.	158,832			154,815
Common stock dividends ($1.29 and $1.14 per share)	(64,903		)	(57,292		)
Balance at end of period	1,121,390			1,021,504
Accumulated Other Comprehensive (Loss) Income
Balance at beginning of period	(16,553		)	(17,116		)
Unrealized gain on securities (net of tax)	—			2,283
Unfunded pension liability adjustment (net of tax)	1,296			1,394
Balance at end of period	(15,257		)	(13,439		)
Treasury Stock
Balance at beginning of period	(8		)	(21		)
Issued	2,465			2,132
Acquired	(2,737		)	(2,124		)
Balance at end of period	(280		)	(13		)
Total IDACORP, Inc. shareholders’ equity at end of period	1,949,016			1,846,627
Noncontrolling Interests
Balance at beginning of period	4,090			4,213
Net loss attributable to noncontrolling interests	283			(31		)
Balance at end of period	4,373			4,182
Total equity at end of period	$	1,953,389		$	1,850,809

The accompanying notes are an integral part of these statements.

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Idaho Power Company

Condensed Consolidated Statements of Income

(unaudited)



	Three months ended September 30,						Nine months ended September 30,
	2014			2013			2014			2013
	(thousands of dollars)
Operating Revenues:
General business	$	347,838		$	349,428		$	874,817		$	846,079
Off-system sales	15,449			11,169			56,390			31,597
Other revenues	17,424			19,707			58,479			69,853
Total operating revenues	380,711			380,304			989,686			947,529
Operating Expenses:
Operation:
Purchased power	75,058			74,088			181,291			166,097
Fuel expense	67,088			64,858			156,859			155,901
Power cost adjustment	(668		)	(6,960		)	23,496			(34,969		)
Other operations and maintenance	84,236			84,471			252,208			247,409
Energy efficiency programs	5,537			6,077			17,881			30,279
Depreciation	33,476			32,538			99,304			96,680
Taxes other than income taxes	8,340			7,017			24,685			23,243
Total operating expenses	273,067			262,089			755,724			684,640
Income from Operations	107,644			118,215			233,962			262,889
Other Income (Expense):
Allowance for equity funds used during construction	4,645			3,734			13,182			10,876
Earnings of unconsolidated equity-method investments	5,180			5,102			7,148			7,358
Other expense, net	(1,538		)	(1,077		)	(3,556		)	(4,450		)
Total other income	8,287			7,759			16,774			13,784
Interest Charges:
Interest on long-term debt	20,141			20,887			60,423			61,349
Other interest	1,859			1,724			5,547			5,009
Allowance for borrowed funds used during construction	(2,178		)	(1,904		)	(6,287		)	(5,711		)
Total interest charges	19,822			20,707			59,683			60,647
Income Before Income Taxes	96,109			105,267			191,053			216,026
Income Tax Expense	11,509			34,965			35,899			66,695
Net Income	$	84,600		$	70,302		$	155,154		$	149,331

The accompanying notes are an integral part of these statements.

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Idaho Power Company

Condensed Consolidated Statements of Comprehensive Income

(unaudited)



	Three months ended September 30,				Nine months ended September 30,
	2014		2013		2014		2013
	(thousands of dollars)

Net Income	$	84,600	$	70,302	$	155,154	$	149,331
Other Comprehensive Income:
Net unrealized holding gains arising during the period, net of tax of $0, $541, $0 and $1,466	—		843		—		2,283
Unfunded pension liability adjustment, net of tax of $277, $298, $832 and $894	432		464		1,296		1,394
Total Comprehensive Income	$	85,032	$	71,609	$	156,450	$	153,008

The accompanying notes are an integral part of these statements.

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Idaho Power Company

Condensed Consolidated Balance Sheets

(unaudited)



	September 30, 2014			December 31, 2013
	(thousands of dollars)
Assets

Electric Plant:
In service (at original cost)	$	5,194,535		$	5,080,402
Accumulated provision for depreciation	(1,823,870		)	(1,766,680		)
In service - net	3,370,665			3,313,722
Construction work in progress	383,667			327,000
Held for future use	7,090			7,090
Electric plant - net	3,761,422			3,647,812
Investments and Other Property	130,437			131,520
Current Assets:
Cash and cash equivalents	102,900			66,535
Receivables:
Customer (net of allowance of $2,229 and $2,349, respectively)	93,272			97,873
Other (net of allowance of $158 and $153, respectively)	16,674			14,290
Accrued unbilled revenues	55,273			63,507
Materials and supplies (at average cost)	56,023			53,643
Fuel stock (at average cost)	44,733			41,546
Prepayments	12,840			15,204
Deferred income taxes	—			12,386
Current regulatory assets	50,995			61,837
Other	1,473			2,401
Total current assets	434,183			429,222
Deferred Debits:
American Falls and Milner water rights	13,958			15,803
Company-owned life insurance	23,774			22,037
Regulatory assets	1,003,099			978,234
Other	42,590			41,783
Total deferred debits	1,083,421			1,057,857
Total	$	5,409,463		$	5,266,411

The accompanying notes are an integral part of these statements.

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Idaho Power Company

Condensed Consolidated Balance Sheets

(unaudited)



	September 30, 2014			December 31, 2013
	(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	1,022,744			932,547
Accumulated other comprehensive loss	(15,257		)	(16,553		)
Total common stock equity	1,815,525			1,724,032
Long-term debt	1,614,377			1,615,258
Total capitalization	3,429,902			3,339,290
Current Liabilities:
Current maturities of long-term debt	1,064			1,064
Accounts payable	82,170			90,529
Accounts payable to affiliates	1,791			1,158
Taxes accrued	25,006			14,031
Interest accrued	24,885			22,764
Accrued compensation	39,926			38,297
Current regulatory liabilities	7,588			10,684
Other	25,275			17,095
Total current liabilities	207,705			195,622
Deferred Credits:
Deferred income taxes	1,112,463			1,058,734
Regulatory liabilities	385,055			375,873
Pension and other postretirement benefits	230,385			244,627
Other	43,953			52,265
Total deferred credits	1,771,856			1,731,499

Commitments and Contingencies

Total	$	5,409,463		$	5,266,411

The accompanying notes are an integral part of these statements.

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Idaho Power Company

Condensed Consolidated Statements of Cash Flows

(unaudited)



	Nine months ended September 30,
	2014			2013
	(thousands of dollars)
Operating Activities:
Net income	$	155,154		$	149,331
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	101,925			99,035
Deferred income taxes and investment tax credits	14,087			44,772
Changes in regulatory assets and liabilities	36,595			(20,765		)
Pension and postretirement benefit plan expense	20,903			21,988
Contributions to pension and postretirement benefit plans	(32,509		)	(32,535		)
Earnings of unconsolidated equity-method investments	(7,148		)	(7,358		)
Distributions from unconsolidated equity-method investments	4,970			12,543
Allowance for equity funds used during construction	(13,182		)	(10,876		)
Other non-cash adjustments to net income, net	1,188			457
Change in:
Accounts receivable	3,818			(40,465		)
Accounts payable	(3,336		)	(4,372		)
Taxes accrued/receivable	12,160			21,769
Other current assets	2,069			4,744
Other current liabilities	7,288			5,185
Other assets	(2,970		)	(1,253		)
Other liabilities	(5,106		)	(8,509		)
Net cash provided by operating activities	295,906			233,691
Investing Activities:
Additions to utility plant	(200,778		)	(165,550		)
Proceeds from the sale of emission allowances and RECs	2,923			498
Other	4,335			3,371
Net cash used in investing activities	(193,520		)	(161,681		)
Financing Activities:
Issuance of long-term debt	—			150,000
Retirement of long-term debt	(1,064		)	(1,064		)
Dividends on common stock	(64,957		)	(57,313		)
Other	—			(2,112		)
Net cash (used in) provided by financing activities	(66,021		)	89,511
Net increase in cash and cash equivalents	36,365			161,521
Cash and cash equivalents at beginning of the period	66,535			17,251
Cash and cash equivalents at end of the period	$	102,900		$	178,772
Supplemental Disclosure of Cash Flow Information:
Cash paid during the period for:
Income taxes	$	19,793		$	8,760
Interest (net of amount capitalized)	$	55,576		$	54,619
Non-cash investing activities:
Additions to property, plant and equipment in accounts payable	$	19,375		$	22,480

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 engaged in the generation, transmission, distribution, sale, and purchase of electric energy and capacity with a service area covering approximately 24,000 square miles in southern Idaho and eastern Oregon. Idaho Power is 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. (IE), 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 record such 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 through rates. Additionally, regulators can impose regulatory liabilities upon a regulated company for amounts previously collected from customers that are expected to be refunded. The effects of applying these regulatory accounting principles to Idaho Power's operations are discussed in more detail in Note 3.

Financial Statements

In the opinion of management of IDACORP and Idaho Power, the accompanying unaudited condensed consolidated financial statements contain all adjustments necessary to present fairly each company's consolidated financial position as of September 30, 2014, consolidated results of operations for the three and nine months ended September 30, 2014 and 2013, and consolidated cash flows for the nine months ended September 30, 2014 and 2013. 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, 2013. 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 (GAAP). 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. Accordingly, actual results could differ from those estimates.

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Change in Method of Accounting for Investments in Qualified Affordable Housing Projects

On January 15, 2014, the Financial Accounting Standards Board issued Accounting Standards Update (ASU) No. 2014-01, Investments-Equity Method and Joint Ventures (Topic 323): Accounting for Investments in Qualified Affordable Housing Projects. This ASU permits an accounting policy election to account for investments in qualified affordable housing projects using the proportional amortization method. For its consolidated financial statements as of and for the year ended December 31, 2013, IDACORP elected early adoption of ASU 2014-01 and changed its accounting for its equity-method investments in qualified affordable housing projects to the proportional amortization method. All prior periods were adjusted to reflect the new method. The standard also requires the recognition of the net investment performance in the financial statements as a component of income tax expense. The new method was elected because IDACORP believes the proportional amortization method more fairly represents the economics of and provides users with a better understanding of the returns from such investments than the equity method of amortization.

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, accounting method changes, or adjustments to tax expense or benefits attributable to prior years. Discrete events are recorded in the interim period in which they occur or become known. The estimated annual effective tax rate is applied to year-to-date pre-tax income to determine income tax expense (or benefit) for the interim period consistent with the annual estimate. In subsequent interim periods, income tax expense (or benefit) for the period is computed as the difference between the year-to-date amount reported for the previous interim period and the current period's year-to-date amount.

Income Tax Expense

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



	IDACORP						Idaho Power
	2014			2013			2014			2013
Nine months ended September 30,
Income tax at statutory rates (federal and state)	$	75,385		$	85,143		$	74,702		$	84,466
Capitalized repairs deduction⁽¹⁾	(19,061		)	(16,129		)	(19,061		)	(16,129		)
Accounting method changes	(11,075		)	4,583			(11,075		)	4,583
Affordable housing tax credits	(3,792		)	(4,152		)	—			—
Affordable housing investment amortization, net of statutory taxes	2,041			739			—			—
Other⁽²⁾	(9,530		)	(7,243		)	(8,667		)	(6,225		)
Income tax expense	$	33,968		$	62,941		$	35,899		$	66,695
Effective tax rate	17.6		%	28.9		%	18.8		%	30.9		%

⁽¹⁾ The "Capitalized repairs deduction" is one of Idaho Power's most significant regulatory flow-through tax adjustments.

⁽²⁾ "Other" is primarily comprised of the net tax effect of Idaho Power's remaining regulatory flow-through tax adjustments, which are each listed in the rate reconciliation table in Note 2 to the consolidated financial statements included in IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2013.

The reductions in income tax expense for the nine months ended September 30, 2014 as compared with the same period in 2013 were primarily due to lower Idaho Power pre-tax earnings in 2014, and the accounting method changes to Idaho Power’s capitalized repairs tax method that are discussed below. Net regulatory flow-through tax adjustments at Idaho Power were higher for the nine months ended September 30, 2014, primarily due to a greater capitalized repair deduction estimate for 2014.

Accounting Method Changes

In the third quarter of 2014 Idaho Power, in coordination with the U.S. Internal Revenue Service (IRS) through IDACORP’s Compliance Assurance Program (CAP) examination process, implemented aspects of the final tangible property regulations and other technical interpretations of these rules into its existing capitalized repairs tax accounting method for generation,

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transmission and distribution assets. These technical interpretations were received from the IRS in 2014. As a result of the modifications, an $11.1 million net tax benefit related to the 2013 capitalized repairs deduction was recorded in the third quarter of 2014. Idaho Power finalized these changes with the filing of IDACORP’s 2013 consolidated federal income tax return in September 2014. The IRS approved the repairs method modifications prior to the filing of the return as part of IDACORP’s 2013 CAP examination. Idaho Power’s 2014 capitalized repairs deduction estimate incorporates the modifications made to the accounting method.

In the third quarter of 2013, the U.S. Treasury Department and IRS issued final regulations addressing the deduction or capitalization of expenditures related to tangible property. In connection with the issuance of the regulations, Idaho Power assessed and estimated the impact of a method change associated with the electric generation property portion of the capitalized repairs tax method it adopted in fiscal year 2010. The change is pursuant to Revenue Procedure 2013-24 and would bring Idaho Power's existing method into alignment with the Revenue Procedure's safe harbor unit-of-property definitions for electric generation property. Based upon this assessment, Idaho Power recorded $4.6 million of income tax expense related to the cumulative method change adjustment for years prior to 2013. Continued refinement of Idaho Power's initial estimate of the method change impact could result in additional future income tax expense or benefit. Idaho Power expects the method change will be finalized with the filing of IDACORP's 2014 consolidated federal income tax return in September 2015.

The amount of the capitalized repairs annual tax deduction will vary depending on a number of factors, but most directly by the amount and type of Idaho Power's annual capital additions. The reversal of this temporary difference from prior years will offset a portion of the ongoing annual benefit. Idaho Power’s prescribed regulatory accounting treatment requires immediate income recognition for temporary tax differences of this type, commonly referred to as "flow-through." A net regulatory asset is established to reflect Idaho Power’s ability to recover the net increased income tax expense when such temporary differences reverse.

3. REGULATORY MATTERS

Included below is a summary of Idaho Power's most recent general rate changes, as well as other recent or pending notable regulatory matters and proceedings.

Idaho and Oregon General Rate Cases and Base Rate Adjustments

Effective January 1, 2012, Idaho Power implemented new Idaho base rates resulting from its receipt of an order from the Idaho Public Utilities Commission (IPUC) approving a settlement stipulation that provided for a 7.86 percent authorized rate of return on an Idaho-jurisdiction rate base of approximately $2.36 billion. The settlement stipulation resulted in a $34.0 million overall increase in Idaho Power's annual Idaho-jurisdictional base rate revenues. Neither the IPUC's order nor the settlement stipulation specified an authorized rate of return on equity.

Effective March 1, 2012, Idaho Power implemented new Oregon base rates resulting from its receipt of an order from the Public Utility Commission of Oregon (OPUC) approving a settlement stipulation that provided for a $1.8 million base rate revenue increase, a return on equity of 9.9 percent, and an overall rate of return of 7.757 percent in the Oregon jurisdiction.

Idaho and Oregon base rates were subsequently adjusted again in 2012, in connection with Idaho Power's completion of the Langley Gulch power plant. On June 29, 2012, the IPUC issued an order approving a $58.1 million increase in annual Idaho-jurisdiction base rate revenues, effective July 1, 2012, for inclusion of the investment and associated costs of the 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 a $3.0 million increase in annual Oregon jurisdiction base rate revenues, effective October 1, 2012, for inclusion of the investment and associated costs of the plant in Oregon rates.

See "Idaho Power Cost Adjustment Mechanism; Update to Base-Level Net Power Supply Expense" below in this Note 3 for a description of Idaho Power's authorization from the IPUC to move a portion of its power supply expenses into Idaho base rates, effective June 1, 2014.

Idaho Settlement Stipulation — Investment Tax Credits and 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

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achieve a minimum 9.5 percent Idaho ROE in the applicable year. Idaho Power may 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).


•	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 through a reduction to the pension regulatory asset balancing account and 25 percent to Idaho Power.

The settlement stipulation also 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.

Idaho Power's actual Idaho ROE in 2012 and 2013 triggered the sharing mechanism of the December 2011 settlement stipulation for both years. Based on its estimate of full year 2014 Idaho ROE, in the third quarter of 2014 Idaho Power recorded a $4.9 million provision against current revenue for sharing of earnings with customers for 2014.

In October 2014, the IPUC issued an order approving an extension, with modifications, of the terms of the December 2011 Idaho settlement stipulation for the period from 2015 to 2019, or until the terms are otherwise modified or terminated by order of the IPUC. The provisions of the new settlement stipulation are as follows:


•	If Idaho Power's annual Idaho ROE in any year is less than 9.5 percent, then Idaho Power may amortize up to $25 million of additional ADITC to help achieve a 9.5 percent Idaho ROE for that year, and may amortize up to a total of $45 million of additional ADITC (less any amount of additional ADITC amortized in 2014 under the December 2011 settlement stipulation).


•	If Idaho Power's annual Idaho ROE in any year exceeds 10.0 percent, the amount of earnings exceeding a 10.0 percent Idaho ROE and up to and including a 10.5 percent Idaho ROE will be allocated 75 percent to Idaho Power's Idaho customers as a rate reduction to be effective at the time of the subsequent year's power cost adjustment and 25 percent to Idaho Power.

•

If Idaho Power's annual Idaho ROE in any year exceeds 10.5 percent, the amount of earnings exceeding a 10.5 percent Idaho ROE will be allocated 50 percent to Idaho Power's Idaho customers as a rate reduction to be effective at the time of the subsequent year's power cost adjustment, 25 percent to Idaho Power's Idaho customers in the form of a reduction to the pension regulatory asset balancing account (to reduce the amount to be collected in the future from Idaho customers), and 25 percent to Idaho Power.


•	If the full $45 million of additional ADITC contemplated by the settlement stipulation has been amortized (including any additional ADITCs amortized in 2014) the sharing provisions would terminate.


•	In the event the IPUC approves a change to Idaho Power's Idaho-jurisdictional allowed return on equity as part of a general rate case proceeding seeking a rate change effective prior to January 1, 2020, the Idaho ROE thresholds (9.5 percent, 10.0 percent, and 10.5 percent) will be adjusted prospectively, under the same methodology used for the December 2011 settlement stipulation.

Idaho Power Cost Adjustment Mechanism; Update to Base-Level Net Power Supply Expense

In both its Idaho and Oregon jurisdictions, Idaho Power's PCA mechanisms address the volatility of power supply costs and provide for annual adjustments to the rates charged to its retail customers. The PCA mechanisms compare Idaho Power's actual and forecast net power supply costs (primarily fuel and purchased power less off-system sales) against net power supply costs currently being recovered in retail rates. Under the PCA mechanisms, certain differences between actual net power supply costs incurred by Idaho Power and the costs included in retail rates are recorded as a deferred charge or credit on the balance sheets for future recovery or refund through retail rates. The power supply costs deferred primarily result from changes in wholesale market prices and transaction volumes, fuel prices, changes in contracted power purchase prices and volumes (including PURPA power purchases), and the levels of Idaho Power's own hydroelectric and thermal generation.

On November 1, 2013, Idaho Power filed an application with the IPUC requesting an increase of approximately $106 million in the normalized or "base level" net power supply expense on a total-system basis to be used to update base rates and in the

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determination of the PCA rate that would become effective June 1, 2014. Idaho Power's request was intended to remove the Idaho-jurisdictional portion of those expenses from collection via the Idaho PCA mechanism and instead collect that portion through base rates. On March 21, 2014, the IPUC issued an order approving Idaho Power's application, with the change in collection methodology effective June 1, 2014.

On May 30, 2014, the IPUC issued an order approving Idaho Power's April 15, 2014 application requesting an $11.1 million net increase in Idaho PCA rates, effective for the 2014-2015 PCA collection period from June 1, 2014 to May 31, 2015. The $11.1 million PCA rate increase was net of Idaho Power's $20.0 million of surplus Idaho energy efficiency rider funds. The PCA rate increase was also net of $7.6 million of customer revenue sharing for the year 2013 under the December 2011 settlement stipulation described above. Previously, in May 2013 the IPUC issued an order authorizing 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.

Annual Idaho Fixed Cost Adjustment Filing

The fixed cost adjustment (FCA) is designed to remove Idaho Power’s financial 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 recover or refund the difference between the amount of fixed costs authorized in Idaho Power's most recent general rate case and the amount of fixed costs recovered by Idaho Power based upon weather-normalized energy sales. On May 30, 2014, the IPUC issued an order approving Idaho Power's March 14, 2014 application requesting a $6.0 million increase in the FCA recovery from $8.9 million to $14.9 million, effective for the period from June 1, 2014 to May 31, 2015. Previously, on May 22, 2013, the IPUC issued an order authorizing a decrease in FCA collection from $10.3 million to $8.9 million, effective for the period from June 1, 2013 to May 31, 2014.

IPUC Review of Annual Rate Adjustment Mechanisms

On July 1, 2014, the IPUC opened a docket pursuant to which Idaho Power, the IPUC Staff, and other interested parties would further evaluate Idaho Power's application of the true-up component of the PCA mechanism and whether a deferral balance adjustment is appropriate. The docket arose from the IPUC's May 2014 PCA order, which noted that the IPUC Staff believed that Idaho Power's application of the true-up component introduces a line-loss bias that inflated the true-up revenue it must collect by $14.2 million. The IPUC's docket was closed via an order issued by the IPUC on August 6, 2014, with no retroactive change to the PCA mechanism. Idaho Power has subsequently met with interested parties to explore approaches to increasing the accuracy of the actual cost recovery under the PCA mechanism, and discussions are ongoing.

Also on July 1, 2014, the IPUC opened a docket to allow Idaho Power, the IPUC Staff, and other interested parties to further evaluate the IPUC Staff's concerns regarding the application of the FCA mechanism (including weather-normalization, customer count methodology, rate adjustment cap, and cross-subsidization issues) and whether the FCA is effectively removing Idaho Power's disincentive to aggressively pursue energy efficiency programs. Proceedings in the FCA docket, which remains open, could result in significant changes to the FCA.

4. 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. The terms and conditions of those credit facilities have not changed compared to the descriptions included in IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2013.

At September 30, 2014, no loans were outstanding under either IDACORP's or Idaho Power's facilities. At September 30, 2014, Idaho Power had regulatory authority to incur up to $450 million in principal amount of short-term indebtedness at any one time outstanding. Balances (in thousands of dollars) and interest rates of IDACORP’s and Idaho Power's short-term borrowings were as follows at September 30, 2014 and December 31, 2013:



	September 30, 2014									December 31, 2013
	Idaho Power			IDACORP			Total			Idaho Power			IDACORP			Total
Commercial paper outstanding	$	—		$	31,800		$	31,800		$	—		$	54,750		$	54,750
Weighted-average annual interest rate	—		%	0.31		%	0.31		%	—		%	0.34		%	0.34		%

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5. COMMON STOCK

IDACORP Common Stock

During the nine months ended September 30, 2014, IDACORP issued 74,049 shares of common stock pursuant to the IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan. Effective July 1, 2012, IDACORP instructed the plan administrators of the IDACORP, Inc. Dividend Reinvestment and Stock Purchase Plan and Idaho Power Company Employee Savings Plan to use market purchases of IDACORP common stock, as opposed to original issuance of common stock from IDACORP, to acquire shares of IDACORP common stock for the plans. However, IDACORP may determine at any time to resume original issuances of common stock under those plans.

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

Restrictions on Dividends

Idaho Power’s ability to pay dividends on its common stock held by IDACORP and IDACORP’s ability to pay dividends on its common stock are limited to the extent payment of such dividends would violate the covenants in their respective credit facilities or Idaho Power’s Revised Code of Conduct. A covenant under IDACORP’s credit facility and Idaho Power’s credit facility requires IDACORP and Idaho Power to maintain leverage ratios of consolidated indebtedness to consolidated total capitalization, as defined therein, of no more than 65 percent at the end of each fiscal quarter. At September 30, 2014, the leverage ratios for IDACORP and Idaho Power were 46 percent and 47 percent, respectively. Based on these restrictions, IDACORP’s and Idaho Power’s dividends were limited to $1.1 billion and $942 million, respectively, at September 30, 2014. There are additional facility covenants, subject to exceptions, that prohibit or restrict the sale or disposition of property without consent and any agreements restricting dividend payments to the company from any material subsidiary. At September 30, 2014, IDACORP and Idaho Power were in compliance with the financial covenants.

Idaho Power’s Revised Policy and Code of Conduct relating to transactions between and among Idaho Power, IDACORP, and other affiliates, which was approved by the IPUC in April 2008, provides that Idaho Power will not pay any dividends to IDACORP that will reduce Idaho Power’s common equity capital below 35 percent of its total adjusted capital without IPUC approval. At September 30, 2014, Idaho Power's common equity capital was 53 percent of its total adjusted capital. Further, Idaho Power must obtain approval of the OPUC before it could directly or indirectly loan funds or issue notes or give credit on its books to IDACORP.

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

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

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6. EARNINGS PER SHARE

The table below presents the computation of IDACORP’s basic and diluted earnings per share for the three and nine months ended September 30, 2014 and 2013 (in thousands, except for per share amounts).



	Three months ended September 30,				Nine months ended September 30,
	2014		2013		2014		2013
Numerator:
Net income attributable to IDACORP, Inc.	$	86,889	$	73,119	$	158,832	$	154,815
Denominator:
Weighted-average common shares outstanding - basic	50,129		50,056		50,131		50,051
Effect of dilutive securities	91		97		53		58
Weighted-average common shares outstanding - diluted	50,220		50,153		50,184		50,109
Basic earnings per share	$	1.73	$	1.46	$	3.17	$	3.09
Diluted earnings per share	$	1.73	$	1.46	$	3.16	$	3.09

7. COMMITMENTS

Purchase Obligations

IDACORP's and Idaho Power's purchase obligations did not change materially, outside of the ordinary course of business, during the nine months ended September 30, 2014, other than the addition of thirteen power purchase agreements with solar, wind, and other alternative energy developers for projects with a combined nameplate capacity of approximately 176 MW. Payments pursuant to these agreements are expected to total $659 million from 2014 to 2038. Three of these power purchase agreements remain subject to IPUC approval, with a combined nameplate capacity of approximately 120 MW and expected payments of $449 million over the period from 2016 to 2037.

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 with the Wyoming Department of Environmental Quality, was $70 million at September 30, 2014, representing IERCo's one-third share of BCC's total reclamation obligation. BCC has a reclamation trust fund set aside specifically for the purpose of paying these reclamation costs. At September 30, 2014, the value of the reclamation trust fund was $66 million. During the nine months ended September 30, 2014, the reclamation trust fund distributed approximately $10 million for reclamation activity costs associated with the BCC surface mine. BCC periodically assesses the adequacy of the reclamation trust fund and its estimate of future reclamation costs. To ensure that the reclamation trust fund maintains adequate reserves, BCC has the ability to add a per-ton surcharge to coal sales, all of which are made to the Jim Bridger plant. Starting in 2010, BCC began applying a nominal surcharge to coal sales in order to maintain adequate reserves in the reclamation trust fund. Because of the existence of the fund and the ability to apply a per-ton surcharge, the estimated fair value of this guarantee is minimal.

IDACORP and Idaho Power enter into financial agreements and power purchase and sale agreements that include indemnification provisions relating to various forms of claims or liabilities that may arise from the transactions contemplated by these agreements. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnification provisions cannot be reasonably estimated. IDACORP and Idaho Power periodically evaluate the likelihood of incurring costs under such indemnities based on their historical experience and the evaluation of the specific indemnities. As of September 30, 2014, 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.

8. 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 8. Some of these claims, controversies, disputes, and other contingent matters involve litigation and regulatory or other contested proceedings. The ultimate resolution

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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. For matters that affect Idaho Power’s operations, Idaho Power intends to seek, to the extent permissible and appropriate, recovery through the ratemaking process of costs incurred.

Western Energy Proceedings

High prices for electricity, energy shortages, and blackouts in California and in western wholesale markets during 2000 and 2001 caused numerous purchasers of electricity in those markets to initiate proceedings seeking refunds or other forms of relief and the FERC to initiate its own investigations. Some of these proceedings remain pending before the FERC or are on appeal to the United States Court of Appeals for the Ninth Circuit. Idaho Power and IESCo (as successor to IDACORP Energy L.P.) believe that settlement releases they have obtained will restrict potential claims that might result from the disposition of pending proceedings and predict that these matters will not have a material adverse effect on IDACORP's or Idaho Power's results of operations or financial condition. However, the settlements and associated FERC orders have not fully eliminated the potential for so-called "ripple claims," which involve potential claims for refunds from an upstream seller of power based on a finding that its downstream buyer was liable for refunds as a seller of power during the relevant period. The FERC has characterized these ripple claims as "speculative." The FERC has refused to dismiss Idaho Power and IESCo from the proceedings in the Pacific Northwest. In orders respecting two separately filed settlements, the FERC has refused to approve a provision that provided for waivers of all claims in those proceedings, despite only limited objections from two market participants, one of whom removed its objections in the later-filed settlement. Petitions for review filed by Idaho Power and IESCo of the first of the FERC's decisions refusing to approve the waiver provision of the settlements have been briefed to the Ninth Circuit Court of Appeals and remain pending before that court. On August 5, 2014, Idaho Power and IESCo filed a petition for review of the FERC orders rejecting ripple claim waivers in the Ninth Circuit, which stayed the new proceedings until February 2015.

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

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 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.

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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 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.

Idaho Power’s claims for water rights have now been adjudicated in the SRBA and partial decrees for those water rights have been entered by the court. In July 2011, the SRBA Court entered an Order Designating Basin-Wide Issue 16, In Re: Form and Content of Final Unified Decree, and advised the parties to the SRBA of the need to file notices of intent to participate in the basin-wide issue and of the court’s intent to establish a schedule for closing the taking of water right claims in the SRBA. Idaho Power participated in Basin-Wide Issue 16 and in June 2012 the court issued a memorandum decision and order. By subsequent orders, the court closed claims taking in all of the basins in the SRBA. The court issued a final unified decree in the SRBA in August 2014, substantially concluding the SRBA.

Separately, Idaho Power continues to work with the State of Idaho and other interested stakeholders on issues relating to 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 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.

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, including the U.S. Environmental Protection Agency's recently issued proposed rule for CO₂ emission reductions from existing utility generating plants under Section 111(d) of the Clean Air Act. 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.

9. BENEFIT PLANS

Idaho Power has two defined benefit pension plans - a noncontributory defined benefit pension plan (pension plan) and nonqualified defined benefit plans for certain senior management employees called the Security Plan for Senior Management Employees I and II (SMSP). The benefits under the pension plan are based on years of service and the employee’s final average earnings. Idaho Power also maintains a defined benefit postretirement benefit plan (consisting of health care and death benefits) that covers all employees who were enrolled in the active-employee group plan at the time of retirement as well as

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their spouses and qualifying dependents. The table below shows the components of net periodic benefit costs for the pension, SMSP, and postretirement benefits plans for the three months ended September 30, 2014 and 2013 (in thousands of dollars).



	Pension Plan						SMSP				Postretirement Benefits
	2014			2013			2014		2013		2014			2013
Service cost	$	6,323		$	7,839		$	411	$	544	$	252		$	328
Interest cost	8,853			7,958			964		816		711			659
Expected return on plan assets	(10,561		)	(9,053		)	—		—		(648		)	(582		)
Amortization of prior service cost	86			86			55		53		45			(57		)
Amortization of net loss	978			4,280			654		709		—			25
Net periodic benefit cost	5,679			11,110			2,084		2,122		360			373
Adjustments due to the effects of regulation⁽¹⁾	(1,140		)	(6,274		)	—		—		—			—
Net periodic benefit cost recognized for financial reporting⁽¹⁾	$	4,539		$	4,836		$	2,084	$	2,122	$	360		$	373

⁽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 nine months ended September 30, 2014 and 2013 (in thousands of dollars).



	Pension Plan						SMSP				Postretirement Benefits
	2014			2013			2014		2013		2014			2013
Service cost	$	18,969		$	23,517		$	1,234	$	1,634	$	758		$	986
Interest cost	26,561			23,873			2,892		2,444		2,131			1,975
Expected return on plan assets	(31,717		)	(26,816		)	—		—		(1,946		)	(1,746		)
Amortization of prior service cost	260			260			165		159		137			(172		)
Amortization of net loss	2,933			12,839			1,963		2,129		—			74
Net periodic benefit cost	17,006			33,673			6,254		6,366		1,080			1,117
Adjustments due to the effects of regulation⁽¹⁾	(3,437		)	(19,168		)	—		—		—			—
Net periodic benefit cost recognized for financial reporting⁽¹⁾	$	13,569		$	14,505		$	6,254	$	6,366	$	1,080		$	1,117

During the nine months ended September 30, 2014, Idaho Power made $30.0 million of contributions to its defined benefit pension plan.

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.

10. 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 following table summarizes investments in equity securities by IDACORP and Idaho Power as of September 30, 2014 and December 31, 2013 (in thousands of dollars).



	September 30, 2014						December 31, 2013
	Gross Unrealized Gain		Gross Unrealized Loss		Fair Value		Gross Unrealized Gain		Gross Unrealized Loss		Fair Value
Available-for-sale securities	$	—	$	—	$	37,606	$	—	$	—	$	41,119

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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 September 30, 2014 and at December 31, 2013, there were no indicators of other-than-temporary impairment related to IDACORP's and Idaho Power's investments.

There were no sales of available-for-sale securities during the nine months ended September 30, 2014 or 2013.

11. 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 primary objectives of Idaho Power’s energy purchase and sale activity are 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 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. 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 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.

The table below presents the gains and losses on derivatives not designated as hedging instruments for the three and nine months ended September 30, 2014 and 2013 (in thousands of dollars).



		Gain/(Loss) on Derivatives Recognized in Income⁽¹⁾
	Location of Realized Gain/(Loss) on Derivatives Recognized in Income	Three months ended September 30,						Nine months ended September 30,
		Three months ended September 30,						Nine months ended September 30,
		2014			2013			2014			2013
Financial swaps	Off-system sales	$	517		$	(98	)	$	(6,026	)	$	224
Financial swaps	Purchased power	(2,265		)	496			(785		)	510
Financial swaps	Fuel expense	239			(705		)	3,907			444
Financial swaps	Other operations and maintenance	(34		)	12			(44		)	27
Forward contracts	Off-system sales	112			135			164			135
Forward contracts	Purchased power	(113		)	(138		)	(163		)	(138		)
Forward contracts	Fuel expense	53			52			101			131

⁽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 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 12 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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Derivative Instrument Summary

The table below presents the fair values and locations of derivative instruments not designated as hedging instruments recorded on the balance sheets and reconciles the gross amounts of derivatives recognized as assets and as liabilities to the net amounts presented in the balance sheets at September 30, 2014 and December 31, 2013 (in thousands of dollars).



		Asset Derivatives							Liability Derivatives
	Balance Sheet Location	Gross Fair Value		Amounts Offset			Net Assets		Gross Fair Value		Amounts Offset				Net Liabilities
	Balance Sheet Location	Gross Fair Value		Amounts Offset			Net Assets		Gross Fair Value		Amounts Offset				Net Liabilities
September 30, 2014
Current:
Financial swaps	Other current assets	$	1,418	$	(154	)	$	1,264	$	154	$	(154	)		$	—
Financial swaps	Other current liabilities	—		—			—		689		—				689
Forward contracts	Other current assets	176		—			176		—		—				—
Forward contracts	Other current liabilities	—		—			—		115		—				115
Long-term:
Forward contracts	Other assets	63		—			63		—		—				—
Total		$	1,657	$	(154	)	$	1,503	$	958	$	(154	)		$	804
December 31, 2013
Current:
Financial swaps	Other current assets	$	1,451	$	(175	)	$	1,276	$	175	$	(175	)		$	—
Financial swaps	Other current liabilities	373		(373		)	—		1,975		(1,429		)	⁽¹⁾	546
Forward contracts	Other current assets	109		—			109		—		—				—
Forward contracts	Other current liabilities	—		—			—		26		—				26
Long-term:
Financial swaps	Other assets	189		(28		)	161		28		(28		)		—
Forward contracts	Other assets	126		—			126		—		—				—
Total		$	2,248	$	(576	)	$	1,672	$	2,204	$	(1,632	)		$	572

⁽¹⁾Current liability derivative amounts offset include $1.1 million of collateral receivable for the period ended December 31, 2013.

The table below presents the volumes of derivative commodity forward contracts and swaps outstanding at September 30, 2014 and 2013 (in thousands of units).



		September 30,
Commodity	Units	2014	2013
Electricity purchases	MWh	227	382
Electricity sales	MWh	391	1,064
Natural gas purchases	MMBtu	5,455	11,929
Natural gas sales	MMBtu	1,137	1,153
Diesel purchases	Gallons	222	1,113

Credit Risk

At September 30, 2014, 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 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.

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Credit-Contingent Features

Certain of Idaho Power's derivative instruments contain provisions that require Idaho Power's unsecured debt to maintain an investment grade credit rating from Moody's Investors Service and Standard & Poor's Ratings Services. If Idaho Power's unsecured debt were to fall below investment grade, it would be in violation of these provisions, and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions. The aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a liability position at September 30, 2014, was $0.7 million. Idaho Power posted $0.1 million of cash collateral related to this amount. If the credit-risk-related contingent features underlying these agreements were triggered on September 30, 2014, Idaho Power would have been required to post an additional $6.2 million of cash collateral to its counterparties.

12. 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.

• 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.

IDACORP’s and Idaho Power’s assessment of a particular input's significance 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. An item recorded at fair value is reclassified among 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. There were no transfers between levels or material changes in valuation techniques or inputs during the three and nine months ended September 30, 2014 or the year ended December 31, 2013.

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The table below presents information about IDACORP’s and Idaho Power’s assets and liabilities measured at fair value on a recurring basis as of September 30, 2014 and December 31, 2013 (in thousands of dollars).



	September 30, 2014								December 31, 2013
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets:
Derivatives	$	995	$	508	$	—	$	1,503	$	1,437	$	235	$	—	$	1,672
Money market funds	100		—		—		100		100		—		—		100
Trading securities: Equity securities	139		—		—		139		1,153		—		—		1,153
Available-for-sale securities: Equity securities	37,606		—		—		37,606		41,119		—		—		41,119
Liabilities:
Derivatives	$	78	$	726	$	—	$	804	$	546	$	26	$	—	$	572

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

The table below presents the carrying value and estimated fair value of financial instruments that are not reported at fair value, as of September 30, 2014 and December 31, 2013, using available market information and appropriate valuation methodologies (in thousands of dollars).



	September 30, 2014				December 31, 2013
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
IDACORP
Assets:
Notes receivable⁽¹⁾	$	3,472	$	3,472	$	3,472	$	3,472
Liabilities:
Long-term debt⁽¹⁾	1,615,441		1,672,271		1,616,322		1,600,248
Idaho Power
Liabilities:
Long-term debt⁽¹⁾	$	1,615,441	$	1,672,271	$	1,616,322	$	1,600,248

⁽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 12.

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. Carrying values for cash and cash equivalents, deposits, customer and other receivables, notes payable, accounts payable, interest accrued, and taxes accrued approximate fair value.

13. 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 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.

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



	Utility Operations		All Other		Eliminations			Consolidated Total
Three months ended September 30, 2014:
Revenues	$	380,711	$	1,490	$	—		$	382,201
Net income attributable to IDACORP, Inc.	84,600		2,289		—			86,889
Total assets as of September 30, 2014	5,408,736		102,904		(13,363		)	5,498,277
Three months ended September 30, 2013:
Revenues	$	380,304	$	803	$	—		$	381,107
Net income attributable to IDACORP, Inc.	70,302		2,817		—			73,119
Nine months ended September 30, 2014:
Revenues	$	989,686	$	3,017	$	—		$	992,703
Net income attributable to IDACORP, Inc.	155,154		3,678		—			158,832
Nine months ended September 30, 2013:
Revenues	$	947,529	$	2,455	$	—		$	949,984
Net income attributable to IDACORP, Inc.	149,331		5,484		—			154,815

14. 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 amounts reclassified out of components of AOCI and the income statement location of those amounts reclassified during the three and nine months ended September 30, 2014 and 2013 (in thousands of dollars). Items in parentheses indicate increases to net income.



	Amount Reclassified from AOCI
Details About AOCI	Three months ended September 30,						Nine months ended September 30,
	2014			2013			2014			2013
Amortization of defined benefit pension items⁽¹⁾
Prior service cost	$	55		$	53		$	165		$	159
Net loss	654			709			1,963			2,129
Total before tax	709			762			2,128			2,288
Tax benefit⁽²⁾	(277		)	(298		)	(832		)	(894		)
Net of tax	432			464			1,296			1,394
Total reclassification for the period	$	432		$	464		$	1,296		$	1,394

⁽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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The table below presents changes in components of accumulated other comprehensive income (AOCI), net of tax, during the three and nine months ended September 30, 2014 and 2013 (in thousands of dollars). Items in parentheses indicate reductions to AOCI.



	Unrealized Gains and Losses on Available-for-Sale Securities		Defined Benefit Pension Items			Total
Three months ended September 30, 2014:
Balance at beginning of period	$	—	$	(15,689	)	$	(15,689	)
Other comprehensive income before reclassifications	—		—			—
Amounts reclassified out of AOCI	—		432			432
Net current-period other comprehensive income	—		432			432
Balance at end of period	$	—	$	(15,257	)	$	(15,257	)
Nine months ended September 30, 2014:
Balance at beginning of period	$	—	$	(16,553	)	$	(16,553	)
Other comprehensive income before reclassifications	—		—			—
Amounts reclassified out of AOCI	—		1,296			1,296
Net current-period other comprehensive income	—		1,296			1,296
Balance at end of period	$	—	$	(15,257	)	$	(15,257	)
Three months ended September 30, 2013:
Balance at beginning of period	$	5,576	$	(20,322	)	$	(14,746	)
Other comprehensive income before reclassifications	843		—			843
Amounts reclassified out of AOCI	—		464			464
Net current-period other comprehensive income	843		464			1,307
Balance at end of period	$	6,419	$	(19,858	)	$	(13,439	)
Nine months ended September 30, 2013:
Balance at beginning of period	$	4,136	$	(21,252	)	$	(17,116	)
Other comprehensive income before reclassifications	2,283		—			2,283
Amounts reclassified out of AOCI	—		1,394			1,394
Net current-period other comprehensive income	2,283		1,394			3,677
Balance at end of period	$	6,419	$	(19,858	)	$	(13,439	)

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

IDACORP, Inc.

Boise, Idaho

We have reviewed the accompanying condensed consolidated balance sheet of IDACORP, Inc. and subsidiaries (the “Company”) as of September 30, 2014, and the related condensed consolidated statements of income and comprehensive income for the three-month and nine-month periods ended September 30, 2014 and 2013, and of equity and cash flows for the nine-month periods ended September 30, 2014 and 2013. 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, 2013, 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 20, 2014, 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, 2013 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

October 30, 2014

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Idaho Power Company

Boise, Idaho

We have reviewed the accompanying condensed consolidated balance sheet of Idaho Power Company and subsidiary (the “Company”) as of September 30, 2014, and the related condensed consolidated statements of income and comprehensive income for the three-month and nine-month periods ended September 30, 2014 and 2013, and of cash flows for the nine-month periods ended September 30, 2014 and 2013. 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, 2013, 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 20, 2014, 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, 2013 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

October 30, 2014

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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, for purposes of this Item 2, IDACORP) and Idaho Power Company and its subsidiary (collectively, for purposes of this Item 2, 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, 2013, 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 514,000 general business customers as of September 30, 2014. 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 jurisdiction (as to rates, service, accounting, and other general matters of utility operation) of the Idaho Public Utilities Commission (IPUC), the Public Utility Commission of Oregon (OPUC), and the Federal Energy Regulatory Commission (FERC). The IPUC and OPUC determine the rates that Idaho Power charges to its general business customers. Idaho Power is also under the regulatory jurisdiction of the IPUC, the OPUC, and the Public Service Commission of Wyoming as to the issuance of debt and equity securities. 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 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-response 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 economy across the service area), 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 historic rehabilitation projects; 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.

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EXECUTIVE OVERVIEW

Management's Outlook and Initiatives

In the Annual Report on Form 10-K for the year ended December 31, 2013, IDACORP's and Idaho Power's management included a brief overview of their outlook and initiatives for the companies for 2014 and beyond, under the heading "Executive Overview - Management's Outlook" in the MD&A. As of the date of this report, management's outlook is consistent with the disclosure in that report. Most notably:


•	Idaho Power continues to expect positive customer growth in its service area, and continues to support economic development initiatives aimed at sustainable levels of growth. During the first nine months of 2014, Idaho Power's customer count grew by 5,114 customers. For the twelve months ended September 30, 2014, the customer growth rate was 1.4 percent.


•	Idaho Power continues to expect sizable capital investment, with capital expenditures estimated to range from $1.47 billion to $1.56 billion during the five-year period from 2014 to 2018, including amounts spent to-date in 2014.


•	Idaho Power continues to focus on optimization efforts targeting opportunities to manage operating and maintenance (O&M) expenses.

•

IDACORP remains focused on the previously established long-term target dividend payout ratio of between 50 and 60 percent of sustainable IDACORP earnings. IDACORP's board of directors approves the dividend amount quarterly and periodically assesses the potential for changes in the dividend amount. Most recently, in September 2014 IDACORP's board of directors approved a 9.3 percent increase in the regular quarterly cash dividend, to $0.47 per share.

Brief Overview of Third Quarter 2014 Financial Results

IDACORP's earnings were $1.73 per diluted share for the quarter ended September 30, 2014, compared to $1.46 per diluted share for the same quarter in 2013. IDACORP's third quarter earnings in 2014 were higher than in the third quarter of 2013 primarily due to income tax method changes, partially offset by the impact of weather which reduced sales to residential and irrigation customers. In the third quarter of 2014, temperatures were cooler and there was more rainfall than in the third quarter of 2013, reducing energy usage for air conditioning and irrigation.

Idaho Power projects that its return on year-end equity in the Idaho jurisdiction (Idaho ROE) for 2014 will exceed 10.0 percent, which would trigger the sharing mechanism in a December 2011 settlement stipulation with the IPUC. Accordingly, Idaho Power recorded in the third quarter of 2014 a $4.9 million provision for sharing, reflecting earnings to be shared with Idaho customers. IDACORP's and Idaho Power's results, including a quantification of the impacts of the significant items influencing results, 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. Certain recent and pending rate proceedings are discussed in IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2013, in "Regulatory Matters" in this MD&A, and in Note 3 - "Regulatory Matters" to the condensed consolidated financial statements included in this report.

Idaho Power believes that the December 2011 Idaho settlement stipulation referred to above, which has been in effect for 2012, 2013, and 2014, affords an element of earnings stability. Based on its 2012 and 2013 Idaho ROEs, Idaho Power did not amortize any additional ADITC for those two years. As of the date of this report, Idaho Power does not expect to amortize additional ADITC in 2014. In addition to the ADITC amortization provisions, the settlement stipulation also provides for the sharing between Idaho Power and its customers of Idaho-jurisdiction earnings in excess of specified levels of Idaho ROE, and the sharing provisions were triggered in both 2012 and 2013. The terms of the settlement stipulation are described in further detail in "Regulatory Matters" in this MD&A and in Note 3 - "Regulatory Matters" to the condensed consolidated financial

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statements included in this report. As discussed in Note 3, Idaho Power filed an application with the IPUC in May 2014 requesting an extension of the terms of the December 2011 Idaho settlement stipulation, with modifications, and in October 2014 the IPUC approved the proposed settlement stipulation. Idaho Power believes that approval of the new settlement stipulation affords the company a continued element of earnings stability, similar to that provided by the December 2011 settlement stipulation, through the earlier of year-end 2019 or until full use of the additional amortization of ADITC.

Idaho Power's need for general rate relief and the development of rate case plans take into consideration short-term and long-term needs and factors such as in-service dates of major capital investments and the timing and magnitude of changes in major revenue and expense items. Growth in customers and sales volumes, the effect of regulatory mechanisms, and prudent cost management may allow the company to earn a reasonable rate of return and achieve timely cost recovery without having to frequently request general rate relief from regulators. As such, Idaho Power continues to focus on identifying opportunities to optimize operations and support economic growth in its service area.

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


•	According to preliminary Idaho Department of Labor data for September 2014, total employment in the service area was 458,059, compared to 450,682 in September 2013. The unemployment rate for the service area was 3.8 percent. By comparison, the September 2014 U.S. unemployment rate was 5.9 percent, according to U.S. Department of Labor data.


•	Moody's Analytics forecasts, as of September 2014, 2.0 percent and 3.2 percent growth in gross area product for the service area for 2014 and 2015, respectively.


•	Residential customer growth for the twelve months ended September 30, 2014 was 1.4 percent.


•	A number of businesses have recently constructed, or are in the process of constructing, sizable facilities in Idaho Power's service area, including office and manufacturing complexes, particularly in the food processing industry.

In August 2014, Idaho Power began the preparation of its 2015 Integrated Resources Plan (IRP). The load forecast Idaho Power expects to use in the 2015 IRP reflects a slight increase in 20-year average load growth estimates compared with the estimate used in the 2013 IRP, as follows:



	2013 IRP	2015 IRP
Average annual load growth rate	1.1%	1.2%
Summer peak load growth rate	1.4%	1.5%

Weather Conditions and Associated Impacts on Revenue and Power Supply Costs: Weather and agricultural growing conditions have a significant impact on Idaho Power's energy sales and the seasonality of those sales. Relatively low and high temperatures result in greater energy use for heating and cooling, respectively. During the agricultural growing season, which in large part occurs during the second and third quarters, irrigation customers use electricity to operate irrigation pumps, and weather conditions can impact the timing and degree of use of those pumps. Idaho Power also has tiered rates and seasonal rates, which contribute to increased revenues during higher-load periods, most notably during the third quarter of each year when overall customer demand is highest. Milder winter and summer temperatures and increased summer rainfall in 2014 compared to 2013 resulted in a reduction in sales to residential and irrigation customers in 2014 when compared to 2013. While cooler than the near-record summer temperatures seen in 2013, summer temperatures during 2014 exceeded the 30-year historical norm.

Idaho Power's hydroelectric facilities comprise nearly one-half of Idaho Power's nameplate generation capacity. However, the availability and volume of hydroelectric power generated depends on several factors - the snow pack levels in the mountains upstream of Idaho Power's 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 estimates that its 2014 hydroelectric generation will be between 5.9 million and 6.4 million megawatt-hours (MWh). This estimated range compares to 2013 hydroelectric generation of 5.7 million MWh. The median annual hydroelectric generation is 8.4 million MWh.

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When hydroelectric generation is reduced, Idaho Power must rely on more expensive generation sources and purchased power - but most of the increases in power supply costs are collected from customers through the Idaho and Oregon power cost adjustment (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.

When favorable hydroelectric generating conditions exist for Idaho Power, they also may exist for other Pacific Northwest hydroelectric facility operators – increasing the available supply of lower-cost power, lowering regional wholesale market prices, and impacting 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. Much of the adverse or favorable impact of this volatility is addressed through the PCA mechanisms.

Fuel and Purchased Power Expense: In addition to hydroelectric generation, Idaho Power relies significantly on coal and natural gas to fuel its generation facilities and power purchases in the wholesale markets. 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. Fuel costs are impacted by electricity sales volumes, the terms of contracts for fuel, Idaho Power's generation capacity, the availability of hydroelectric generation resources, transmission capacity, energy and natural gas market prices, and Idaho Power's hedging program for managing fuel costs.

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 and solar 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 less reliable, intermittent, non-dispatchable resources into Idaho Power's portfolio also creates a number of complex operational challenges and risks that Idaho Power must address. Notably, integration of these sources of power into Idaho Power's portfolio does not eliminate Idaho Power's need to construct facilities and infrastructure that provide reliable power. For instance, at the time Idaho Power reached its all-time system peak demand of 3,407 MW on July 2, 2013, wind resources on Idaho Power's system, representing roughly 675 MW of nameplate capacity, were contributing only 57 MW of power due to lack of wind. Increases in federally mandated PURPA power purchases have contributed to increases in customer rates.

The Idaho and Oregon PCA mechanisms mitigate in large part the potential adverse impacts of fluctuations in power supply costs to Idaho Power, including substantially all of the Idaho-jurisdiction PURPA power purchase costs.

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 by agencies and quasi-governmental agencies, including the FERC and the North American Electric Reliability Corporation. 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 to help ensure compliance, and periodically evaluates and updates those policies and initiatives.

In particular, environmental laws and regulations may, among other things, increase the cost of operating 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 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. Additionally, the U.S. Environmental Protection Agency (EPA) recently issued a proposed rule under the Clean Air Act (CAA) intended to reduce carbon dioxide (CO₂) emissions from the power sector, which could significantly increase costs in the industry and customer rates. 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 will continue to assess, to the extent determinable, the potential impact on the costs to generate and purchase power, as well as the willingness of joint owners of power plants to fund any required pollution control equipment upgrades in lieu of plant retirement or conversion to other fuel sources.

Other Matters: Refer to this section of MD&A in IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2013, where the companies summarize certain other notable matters that could have an impact on the companies' results of operations or financial condition, including Idaho Power's significant anticipated pension plan

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contributions, hydroelectric facility relicensing efforts, and the status of large transmission projects, each of which are discussed below in this MD&A.

Summary of Financial Results

The table below summarizes Idaho Power's financial results for the three months and nine months ended September 30, 2014 and 2013. IDACORP's 2013 results reflect the retrospective adoption of a change in accounting method related to affordable housing investments, which increased IDACORP's earnings by $1.3 million for the third quarter of 2013, and by $4.0 million for the first nine months of 2013, as compared with what had been reported for those periods under the previous method of accounting. See Note 1 - "Summary of Significant Accounting Policies" to the condensed consolidated financial statements included in this report for a further description of this adoption.



	Three months ended September 30,				Nine months ended September 30,
	2014		2013		2014		2013
Idaho Power net income	$	84,600	$	70,302	$	155,154	$	149,331
Net income attributable to IDACORP, Inc.	$	86,889	$	73,119	$	158,832	$	154,815
Average outstanding shares – diluted (000’s)	50,220		50,153		50,184		50,109
IDACORP, Inc. earnings per diluted share	$	1.73	$	1.46	$	3.16	$	3.09

The table below provides a reconciliation of net income attributable to IDACORP for the three- and nine-month periods ended September 30, 2014 to the same periods in 2013 (items are in millions and are before tax unless otherwise noted).



	Three months ended					Nine months ended
Net income attributable to IDACORP, Inc. - September 30, 2013 (as previously reported)			$	71.8				$	150.8
Accounting method change for affordable housing investment amortization			1.3					4.0
Net income attributable to IDACORP, Inc. - September 30, 2013 (as reported under new method)			$	73.1				$	154.8
Change in Idaho Power net income:
Decreased sales volumes attributable to usage per customer, net of associated power supply costs and PCA mechanism impacts	(8.3	)				(29.7	)
Increased sales volumes attributable to customer growth, net of associated power supply costs and PCA mechanism impacts	3.0					7.3
Increased payroll and benefits expenses	(1.8	)				(4.1	)
Increased depreciation, property tax, and other (net)	(2.0	)				(3.7	)
(Increased) decreased revenue sharing	(1.5	)				1.3
Decrease in Idaho Power operating income	(10.6	)				(28.9	)
Changes in other non-operating income and expenses	1.4					3.9
Decreased income taxes due to tax method changes	15.7					15.7
Decreased other income tax expense	7.8					15.1
Total increase in Idaho Power net income			14.3					5.8
Other changes (net of tax)			(0.5		)			(1.8		)
Net income attributable to IDACORP, Inc. - September 30, 2014			$	86.9				$	158.8

Third Quarter 2014 Net Income

IDACORP's net income increased $13.8 million for the third quarter of 2014 when compared with the same period in the prior year. Idaho Power’s operating income decreased by $10.6 million. Lower overall usage per customer due to comparatively mild weather decreased operating income by $8.3 million. Continued customer growth, which contributed $3.0 million to operating income, partially offset these weather-related impacts. Greater revenue sharing recorded in the third quarter of 2014 reduced operating income by $1.5 million. Idaho Power's operating income was also impacted by a $3.8 million increase in depreciation, property tax, and payroll and benefits expenses when compared with the same period in 2013.

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The $10.6 million decrease in Idaho Power's operating income was more than offset by a net decrease in income tax expense of $23.5 million, primarily related to the flow-through impact of continued benefits from tax method changes, as well as lower pre-tax income when compared with the same period in 2013.

Year-to-Date Net Income

IDACORP's net income increased $4.0 million for the first nine months of 2014 when compared with the same period in the prior year. Idaho Power's operating income decreased by $28.9 million over the comparative period. Lower usage per customer due to milder weather decreased operating income by $29.7 million. These weather-related decreases were partially offset by continued growth in the number of customers and associated increased sales volumes, which increased operating income by $7.3 million for the first nine months of 2014. The number of general business customers at Idaho Power increased by 1.4 percent from the end of September 30, 2013 to September 30, 2014. Lower revenue sharing recorded in 2014 than in 2013 over the first nine months increased operating income by $1.3 million. Increases in depreciation, property tax, and payroll and benefits expenses combined to decrease operating income by $7.8 million for the first nine months of 2014 when compared with the same period in the prior year.

The $28.9 million decrease in Idaho Power's operating income was more than offset by a net decrease in income tax expense of $30.8 million, primarily related to the flow-through impact of continued benefits from tax method changes, as well as lower pre-tax income when compared with the same period in 2013.

Effect of Income Taxes and Tax Method Changes on Results

Income tax accounting method changes increased net income by $15.7 million for the first nine months of 2014 compared with the same period in the prior year. In 2013, Idaho Power recorded $4.6 million of incremental income tax expense as a result of a cumulative method change adjustment related to its capitalized repairs for generation assets for years prior to 2013. By contrast, during the third quarter of 2014, Idaho Power recorded an incremental income tax benefit of $11.1 million related to modifications to its overall capitalized repairs deduction tax method as agreed to with the Internal Revenue Service. Other income tax expense at Idaho Power was $7.8 million and $15.1 million lower for the three and nine months ended September 30, 2014, compared with the same periods in 2013, primarily due to lower pre-tax earnings in 2014.

Effect of Sharing on Results

During the third quarter and first nine months of 2014, Idaho Power recorded $4.9 million as a provision against current revenues to be refunded to customers through a future rate reduction. Idaho Power did not record any provision for sharing under the settlement stipulation prior to the third quarter. This revenue sharing arrangement is related to a December 2011 settlement stipulation with the IPUC, which requires sharing with Idaho customers of a portion of Idaho-jurisdiction earnings exceeding a 10.0 percent Idaho ROE. The settlement stipulation is described further in "Regulatory Matters" in this MD&A and in Note 3 - "Regulatory Matters" to the condensed consolidated financial statements included in this report. By comparison, during the third quarter and first nine months of 2013, Idaho Power recorded $3.4 million and $6.2 million, respectively, related to the December 2011 settlement stipulation. The impact of sharing on results is reflected in the table below (in millions).



	Three months ended September 30,									Nine months ended September 30,
	2014			2013			Change			2014			2013			Change
Provision against current revenue as a result of sharing	$	(4.9	)	$	(3.4	)	$	(1.5	)	$	(4.9	)	$	(6.2	)	$	1.3

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Key Operating and Financial Metric Estimates for Full-Year 2014

As of the date of this report, IDACORP’s and Idaho Power’s estimates for 2014 are as follows (in millions):



	2014 Estimates
	Current⁽¹⁾	Previous⁽²⁾
Idaho Power Operating & Maintenance Expense	No Change	$335-$345
Idaho Power Additional Amortization of ADITC	No Change	$0
Idaho Power Capital Expenditures, excluding AFUDC	No Change	$280-$295
Idaho Power Hydroelectric Generation (MWh)⁽³⁾	5.9-6.4	5.5-6.5

⁽¹⁾ As of October 30, 2014.

⁽²⁾ As of July 31, 2014, the date of filing IDACORP's and Idaho Power's Quarterly Report on Form 10-Q for the quarter ended June 30, 2014.

⁽³⁾ 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 nine months ended September 30, 2014. In this analysis, the results for the three and nine months ended September 30, 2014 are compared to the same periods in 2013.

Utility Operations

The table below presents Idaho Power’s energy sales and supply (in thousands of MWh) for the three and nine months ended September 30, 2014 and 2013.



	Three months ended September 30,				Nine months ended September 30,
	2014		2013		2014		2013
General business sales	4,166		4,342		10,930		11,340
Off-system sales	434		306		1,611		1,008
Total energy sales	4,600		4,648		12,541		12,348
Hydroelectric generation	1,490		1,356		4,824		4,365
Coal generation	1,750		1,692		4,380		4,665
Natural gas and other generation	579		684		1,019		1,176
Total system generation	3,819		3,732		10,223		10,206
Purchased power	1,051		1,229		3,158		3,030
Line losses	(270	)	(313	)	(840	)	(888	)
Total energy supply	4,600		4,648		12,541		12,348

Sales Volume and Generation: General business sales volume decreased by 176 thousand MWh, or 4 percent, for the quarter, and 410 thousand MWh, or 4 percent, for the first nine months of 2014, compared with the same periods in the prior year. The decreases resulted largely from a decreased volume of sales to residential and irrigation customers. The comparative decrease in residential customer usage is largely attributable to milder temperatures in 2014 than in 2013, which reduced electricity demand for air conditioning and for heating.

Off-system sales volume increased by 128 thousand MWh, or 42 percent, in the third quarter, and by 603 thousand MWh, or 60 percent, for the first nine months of 2014, when compared with the same periods in the prior year. Favorable wholesale market conditions and lower system loads allowed for greater off-system sales during 2014 than in 2013.

The lower system load demand combined with increased hydroelectric generation led to a decreased utilization of natural gas-fired generation in the third quarter and first nine months of 2014 and of coal-fired generation for the first nine months when compared with the same periods in the prior year. Hydroelectric generation was higher by 134 thousand MWh, or 10 percent, for the third quarter, and 459 thousand MWh, or 11 percent, for the first nine months of 2014. The increased hydroelectric generation resulted from more favorable hydrologic conditions in 2014.

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The financial impacts of fluctuations in off-system sales, purchased power, fuel expense, and other power supply-related expenses are addressed in Idaho Power's Idaho and Oregon PCA mechanisms, which are described below.

General Business Revenues: The table below presents Idaho Power’s general business revenues and MWh sales volumes for the three and nine months ended September 30, 2014 and 2013 and the number of customers as of September 30, 2014 and 2013.



	Three months ended September 30,						Nine months ended September 30,
	2014			2013			2014			2013
Revenue
Residential	$	134,336		$	137,862		$	370,967		$	374,287
Commercial	85,146			80,926			226,556			209,558
Industrial	50,345			48,165			137,363			123,234
Irrigation	86,343			89,307			153,196			153,636
Total	356,170			356,260			888,082			860,715
Provision for sharing	(4,900		)	(3,400		)	(4,900		)	(6,200		)
Deferred revenue related to HCC relicensing AFUDC⁽¹⁾	(3,432		)	(3,432		)	(8,365		)	(8,436		)
Total general business revenues	$	347,838		$	349,428		$	874,817		$	846,079
Volume of Sales (MWh)
Residential	1,260			1,328			3,681			3,952
Commercial	1,053			1,049			2,962			2,984
Industrial	819			813			2,402			2,384
Irrigation	1,034			1,152			1,885			2,020
Total MWh sales	4,166			4,342			10,930			11,340
Number of customers at period end
Residential	426,288			420,240
Commercial	67,319			66,575
Industrial	117			116
Irrigation	19,825			19,397
Total customers	513,549			506,328

⁽¹⁾As part of its January 30, 2009 general rate case order, the IPUC is allowing Idaho Power to recover AFUDC on construction work in progress related to the HCC relicensing process, even though the relicensing process is not yet complete and the costs have not been moved to electric plant 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 only notable rate changes impacting general business revenue for the comparative periods were the 2014 and 2013 Idaho PCA rate changes, which were effective June 1, 2014 and 2013, respectively. The estimated annualized net rate impact of the 2014 and 2013 PCA rate increase is $11.1 million and $140.4 million, respectively. The $11.1 million 2014 PCA rate increase was net of $20.0 million of surplus Idaho energy efficiency rider funds returned to customers through the PCA.

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, while moderate temperatures decrease sales. Precipitation levels and the timing of precipitation during the agricultural growing season also affect sales to customers who use electricity to operate irrigation pumps. Rates are also seasonally adjusted and based on a tiered rate structure that provides for higher rates during peak load periods. The seasonal and tiered rate structures contribute to seasonal fluctuations in revenues and earnings. For purposes of illustration, Boise, Idaho weather-related information for the three and nine months ended September 30, 2014 and 2013 is presented in the table that follows.

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	Three months ended September 30,			Nine months ended September 30,
	2014	2013	Normal	2014	2013	Normal
Heating degree-days⁽¹⁾	56	91	121	3,043	3,565	3,320
Cooling degree-days⁽¹⁾	983	1,082	751	1,119	1,320	934

⁽¹⁾ Heating and cooling degree-days are common measures used in the utility industry to analyze the demand for electricity and indicate when a customer would use electricity for heating and air conditioning. A degree-day measures how much the average daily temperature varies from 65 degrees. Each degree of temperature above 65 degrees is counted as one cooling degree-day, and each degree of temperature below 65 degrees is counted as one heating degree-day. While Boise, Idaho weather conditions are not necessarily representative of weather conditions throughout Idaho Power's service area, the greater Boise area has the majority of Idaho Power's customers.

General business revenue decreased $1.6 million for the third quarter and increased $28.7 million for the nine months ended September 30, 2014, compared with the same periods in 2013. Specific factors affecting general business revenues during the periods are discussed below.

•

Rates: Rate changes combined to increase general business revenue by $10.2 million in the third quarter and $58.2 million in the first nine months of 2014 compared with the same periods in 2013. The revenue impact of the rate changes was partially offset by associated changes in operating expenses - Idaho PCA amortization expense increased $6.0 million for the quarter and $38.3 million for the first nine months of 2014 compared with the same periods in 2013 due to the changes in the corresponding Idaho PCA true-up rate in the comparative periods.


•	Customers: Customer growth increased general business revenue by $4.1 million and $9.5 million, respectively, when compared with the third quarter and first nine months of 2013. Total customers increased 1.4 percent during the twelve months ended September 30, 2014.

•

Usage: Lower usage (on a per customer basis), primarily by residential, irrigation, and commercial customers, decreased general business revenue for the quarter and the first nine months of 2014 by a respective $14.4 million and $40.3 million when compared with the same periods in 2013. For the quarter and first nine months of 2014, residential usage per customer decreased 7 percent and 8 percent, respectively, as a result of milder temperatures during 2014 (and hence less electricity demand for heating and cooling). Heavy precipitation and related flooding in an agricultural region of Idaho Power's service territory during part of the third quarter of 2014 led to a respective 12 percent and 9 percent decline in irrigation usage per customer during the quarter and first nine months of 2014 compared with the same periods in the prior year.

•

Sharing: $1.5 million of the decrease in revenue for the quarter and $1.3 million of the increase in revenue for the first nine months of 2014 resulted from the revenue sharing mechanism in place in both years. The revenue sharing mechanism is associated with the December 2011 Idaho regulatory settlement stipulation that provides for the sharing of Idaho-jurisdiction earnings exceeding a 10 percent Idaho ROE. The impact of this mechanism is recorded as a reduction to general business revenue. For both the three and nine months ended September 30, 2014, $4.9 million of sharing was recorded, reflecting the amount to be refunded to customers. For the three and nine months ended September 30, 2013, $3.4 million and $6.2 million of sharing were recorded, respectively.

Off-System Sales: Off-system sales consist primarily of long-term sales contracts and opportunity sales of surplus system energy. The table below presents Idaho Power’s off-system sales for the three and nine months ended September 30, 2014 and 2013.



	Three months ended September 30,				Nine months ended September 30,
	2014		2013		2014		2013
Revenue	$	15,449	$	11,169	$	56,390	$	31,597
MWh sold	434		306		1,611		1,008
Revenue per MWh	$	35.60	$	36.50	$	35.00	$	31.35

For the third quarter and first nine months of 2014, off-system sales revenue increased by $4.3 million, or 38 percent, and $24.8 million, or 78 percent, respectively, compared with the same periods in 2013. Sales volumes increased 42 percent for the quarter and 60 percent for the first nine months of 2014, as a result of favorable market conditions, at times, for selling power off-system. Off-system sales volumes also benefited from greater amounts of surplus system energy resulting from slightly

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lower system loads and increased hydroelectric generation. The favorable market conditions at times drove an increase in average off-system sales prices for the first nine months of 2014 by 12 percent.

Other Revenues: The table below presents the components of other revenues for the three and nine months ended September 30, 2014 and 2013.



	Three months ended September 30,				Nine months ended September 30,
	2014		2013		2014		2013
Transmission services and other	$	11,887	$	13,630	$	40,598	$	39,574
Energy efficiency	5,537		6,077		17,881		30,279
Total other revenues	$	17,424	$	19,707	$	58,479	$	69,853

Other revenue decreased $2.3 million, or 12 percent, and $11.4 million, or 16 percent, in the third quarter and first nine months of 2014, respectively, compared with the same periods in 2013. For the quarter, the decreases primarily related to lower transmission revenue and lower utilization of energy efficiency programs when compared with the same period in the prior year. The decreases for the first nine months of 2014 resulted primarily from an order issued by the IPUC in the prior year that allowed 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 and 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 nine months ended September 30, 2014 and 2013.



	Three months ended September 30,				Nine months ended September 30,
	2014		2013		2014		2013
Expense
PURPA contracts	$	37,827	$	36,848	$	104,443	$	100,937
Other purchased power (including wheeling)	30,001		33,924		69,009		60,965
Demand response incentive payments	7,230		3,316		7,839		4,195
Total purchased power expense	$	75,058	$	74,088	$	181,291	$	166,097
MWh purchased
PURPA contracts	544		528		1,721		1,680
Other purchased power	507		701		1,437		1,350
Total MWh purchased	1,051		1,229		3,158		3,030
Cost per MWh from PURPA contracts	$	69.53	$	69.79	$	60.69	$	60.08
Cost per MWh from other sources	$	59.17	$	48.39	$	48.02	$	45.16
Weighted average - all sources	$	64.54	$	57.59	$	54.92	$	53.43

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 than during light load periods, and conversely has less energy available for off-system sales during heavy load periods than light load periods. Energy prices are typically higher during heavy load periods than during 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.

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Purchased power expense increased $1.0 million, or 1 percent, in the third quarter and $15.2 million, or 9 percent, in the first nine months of 2014, compared with the same periods in 2013. The increases for the quarter and first nine months of 2014 were driven by wholesale gas and electricity market conditions that warranted third-party power purchases to serve system load at times rather than dispatching Idaho Power-owned thermal resources. In addition, the increases in demand response incentive payments primarily relate to the temporary cessation of some of these programs during 2013.

Most of the non-PURPA purchased power and substantially all of the PURPA power purchase costs are recovered through base rates and Idaho Power's PCA mechanisms.

Fuel Expense: The table below presents Idaho Power’s fuel expenses and generation at its thermal generating plants for the three and nine months ended September 30, 2014 and 2013.



	Three months ended September 30,				Nine months ended September 30,
	2014		2013		2014		2013
Expense
Coal	$	48,215	$	43,765	$	119,461	$	116,281
Natural gas and other thermal	18,873		21,093		37,398		39,620
Total fuel expense	$	67,088	$	64,858	$	156,859	$	155,901
MWh generated
Coal	1,750		1,692		4,380		4,665
Natural gas and other thermal	579		684		1,019		1,176
Total MWh generated	2,329		2,376		5,399		5,841
Cost per MWh - Coal	$	27.55	$	25.87	$	27.27	$	24.93
Cost per MWh - Natural gas and other thermal	$	32.60	$	30.84	$	36.70	$	33.69
Weighted average, all sources	$	28.81	$	27.30	$	29.05	$	26.69

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 are noticeably impacted by these fixed charges when generation output is substantially different between the two periods.

Fuel expense increased $2.2 million, or 3 percent, in the third quarter of 2014, and $1.0 million, or 1 percent, in the first nine months of 2014, compared with the same periods in 2013. The increases were due principally to higher commodity costs when compared with the same periods in 2013. These increases were partially offset for the quarter and first nine months of 2014 by decreased output from the natural gas-fired peaker plants during the periods, which were operated less in 2014 than in the same periods in 2013 due to lower system load demands.

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 and thermal generation volumes and fuel costs, generation plant availability, and retail loads. To address the volatility of power supply costs, Idaho Power's PCA mechanisms in the Idaho and Oregon jurisdictions allow Idaho Power to recover from or refund to customers most of the fluctuations in power supply costs. In the Idaho jurisdiction, the PCA includes a cost or benefit sharing ratio that allocates the deviations in net power supply expenses between customers (95 percent) and the company (5 percent), with the exception of PURPA power purchases and demand response program incentives, which are allocated 100 percent to customers. Because of the PCA mechanisms, the primary financial impacts of power supply cost variations is that cash is paid out but recovery from customers does not occur until a future period, or cash that is collected is refunded to customers in a future period, resulting in fluctuations in operating cash flows from year to year. The following table presents the components of the Idaho and Oregon PCA mechanisms for the three and nine months ended September 30, 2014 and 2013.



	Three months ended September 30,						Nine months ended September 30,
	2014			2013			2014			2013
Idaho power supply cost deferral	$	(24,015	)	$	(24,313	)	$	(29,170	)	$	(49,414	)
Amortization of prior year authorized balances	23,347			17,353			52,666			14,445
Total power cost adjustment expense	$	(668	)	$	(6,960	)	$	23,496		$	(34,969	)

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The power supply deferrals represent the portion of the power supply cost fluctuations deferred under the PCA mechanisms. When actual power supply costs are higher than the amount forecasted in PCA rates, which was the case for the third quarter and for the first nine months of 2014, most of the difference is deferred. The amortization of the prior year’s balances represents the offset to 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). See Note 3 - "Regulatory Matters - IPUC Review of Annual Rate Adjustment Mechanisms," to the condensed consolidated financial statements included in this report for a description of the IPUC's review of the true-up component of the PCA mechanism.

Other Operations and Maintenance Expenses: Other O&M expense was flat for the quarter and increased $4.8 million, or 2 percent, for the first nine months of 2014 as compared with the same periods in 2013. The increase for the first nine months of 2014 was primarily due to normal escalations in labor and benefits costs.

Income Taxes

Income Tax Expense: IDACORP's and Idaho Power's income tax expense for the nine months ended September 30, 2014, when compared with the same period in 2013, decreased $29.0 million and $30.8 million, respectively. The decrease in tax expense for the period is primarily the result of changes to Idaho Power’s capitalized repairs tax method (discussed below) and lower Idaho Power pre-tax earnings.

Due to the flow-through impact of an income tax accounting method change, income tax expense decreased $15.7 million for the first nine months of 2014, when compared with the same period in the prior year. In 2013, Idaho Power recorded $4.6 million of incremental income tax expense as a result of a cumulative method change adjustment related to its capitalized repair deduction for generation assets for years prior to 2013. By contrast, during the third quarter of 2014, Idaho Power recorded an incremental income tax benefit of $11.1 million related to modifications to its overall capitalized repairs tax accounting method as agreed to with the Internal Revenue Service.

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.

New Tax Regulations: On August 18, 2014, the U.S. Treasury and Internal Revenue Service issued final regulations addressing the disposition of property subject to depreciation and general asset accounts. The regulations are generally effective for tax years beginning on or after January 1, 2014. IDACORP and Idaho Power are currently evaluating the potential impacts these disposition regulations may have on future tax filings. As of September 30, 2014, no income tax impacts have been recorded related to the new regulations.

LIQUIDITY AND CAPITAL RESOURCES

Overview

Idaho Power has been pursuing significant enhancements to its utility infrastructure in an effort to ensure an adequate supply of electricity, to provide service to new customers, and to maintain system reliability. Idaho Power's existing hydroelectric and thermal generation facilities also require continuing upgrades and component replacement. Idaho Power expects these substantial capital expenditures to continue, with estimated total capital expenditures in the range of $1.47 billion to $1.56 billion over the five-year period from 2014 (including expenditures to-date in 2014) through 2018.

Idaho Power 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 periodically files 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 uses operating and capital budgets to control operating costs and capital expenditures, and focuses on optimizing its business operations, which includes controlling O&M costs through process review and improvement initiatives. During 2014, Idaho Power has continued its efforts to optimize operations and control costs and generate operating cash inflows to meet operating expenditures, contribute to capital expenditure requirements, and pay dividends to shareholders.

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As of October 24, 2014, 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 U.S. Securities and Exchange Commission (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 may be issued up to an amount equal to the available credit capacity under their respective credit facilities.

IDACORP and Idaho Power have no significant long-term debt maturities until 2018. Based on planned capital expenditures and operating and maintenance expenses for 2014, and in light of the success of cost-controlling efforts to-date, the companies believe they will be able to meet capital requirements during at least the next twelve months with a combination of existing cash and operating cash flows generated by Idaho Power's utility business. IDACORP and Idaho Power expect to be able to meet any short-term cash shortfall with existing credit facilities and expect to continue to manage short-term liquidity through commercial paper markets. However, IDACORP and Idaho Power regularly monitor capital markets with a view toward opportunistic debt and equity transactions, taking into account potential future capital needs and market conditions. As a result, IDACORP may issue debt securities or may issue common stock, and Idaho Power may issue debt securities, in the next twelve months if the companies believe terms available in the capital markets are favorable and that issuances would be financially prudent.

IDACORP and Idaho Power seek to maintain capital structures of approximately 50 percent debt and 50 percent equity, and seeking to maintain that ratio influences IDACORP's and Idaho Power's debt and equity issuance decisions. As of September 30, 2014, IDACORP's and Idaho Power's capital structures were as follows:



	IDACORP	Idaho Power
Debt	46%	47%
Equity	54%	53%

Operating Cash Flows

IDACORP’s and Idaho Power’s operating cash inflows for the nine months ended September 30, 2014 were $316 million and $296 million, respectively, increases of $68 million and $62 million, respectively, compared to the same period in 2013. With the exception of cash flows related to income taxes, IDACORP’s operating cash flows are principally derived from the operating cash flows of Idaho Power. Significant items that affected the comparability of the companies' operating cash flows in the first nine months of 2014 compared to the same period in 2013 were as follows:


•	changes in regulatory assets and liabilities, mostly related to the relative amounts of power supply costs deferred and collected under the Idaho PCA mechanism, increased operating cash flows by $57 million; and


•	changes in working capital balances due primarily to timing, including fluctuations in other accounts receivable, as there was a slight decrease in accounts receivable in the first nine months of 2014 compared to the increase experienced during the first nine months of 2013.

Investing Cash Flows

Investing activities consist primarily of capital expenditures related to new construction and improvements to Idaho Power’s generation, transmission, and distribution facilities. IDACORP’s and Idaho Power’s net investing cash outflows for the nine months ended September 30, 2014 were $193 million and $194 million, respectively. Investing cash outflows for 2014 and 2013 were primarily for construction of utility infrastructure needed to address Idaho Power’s aging plant and equipment, customer growth, and environmental and regulatory compliance requirements.

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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 outflows for the nine months ended September 30, 2014 were $90 million and $66 million, respectively. The following are significant items that affected financing cash flows in the first nine months of 2014:


•	IDACORP and Idaho Power paid cash dividends of approximately $65 million; and


•	IDACORP had a net reduction of commercial paper borrowings of $23 million.

Financing Programs and Available Liquidity

IDACORP Equity Programs: 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. IDACORP has no obligation to sell any minimum number of shares under the Sales Agency Agreement. As of the date of this report, all 3 million shares of IDACORP common stock remain available for sale under the Sales Agency Agreement with BNYMCM.

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

Idaho Power 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). 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 July 12, 2013, Idaho Power entered into a Selling Agency Agreement with eight banks named in the agreement in connection with the potential issuance and sale from time to time of up to $500 million in aggregate principal amount of first mortgage bonds, Series J (Series J Notes), under Idaho Power’s Indenture of Mortgage and Deed of Trust, dated as of October 1, 1937, as amended and supplemented (Indenture). Also on July 12, 2013, Idaho Power entered into the Forty-seventh Supplemental Indenture, dated as of July 1, 2013, to the Indenture. The Forty-seventh Supplemental Indenture provides for, among other items, the issuance of up to $500 million in aggregate principal amount of Series J Notes. As of the date of this report, Idaho Power has not sold any first mortgage bonds or debt securities under the Selling Agency Agreement and does not anticipate any issuances during the remainder of 2014, except for potential transactions the company believes may be particularly opportunistic based on capital market conditions.

The issuance of first mortgage bonds requires that Idaho Power meet interest coverage and security provisions set forth in the Indenture. Future issuances of first mortgage bonds are subject to satisfaction of covenants and security provisions set forth in the Indenture, market conditions, regulatory authorizations, and covenants contained in other financing agreements. The Indenture limits the amount of additional first mortgage bonds that Idaho Power may issue to the sum of (a) the principal amount of retired first mortgage bonds and (b) 60 percent of total unfunded property additions, as defined in the Indenture of Mortgage and Deed of Trust. As of September 30, 2014, Idaho Power could issue approximately $1.5 billion of additional first mortgage bonds based on retired first mortgage bonds and total unfunded property additions. However, the Indenture of Mortgage and Deed of Trust further limits the maximum amount of first mortgage bonds at any one time outstanding to $2.0 billion, and as a result the maximum amount of first mortgage bonds Idaho Power could issue as of September 30, 2014 was limited to approximately $409 million. Idaho Power may increase the $2.0 billion limit on the maximum amount of first

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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 outstanding at any one time, 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 outstanding at any one time, 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, as set forth on a schedule to the credit agreements. The companies also pay a facility fee based on the respective company's credit rating for senior unsecured long-term debt securities.

Each facility contains a covenant requiring each company to maintain a leverage ratio of consolidated indebtedness to consolidated total capitalization equal to or less than 65 percent as of the end of each fiscal quarter. In determining the leverage ratio, “consolidated indebtedness” broadly includes all indebtedness of the respective borrower and its subsidiaries, including, in some instances, indebtedness evidenced by certain hybrid securities (as defined in the credit agreement). “Consolidated total capitalization” is calculated as the sum of all consolidated indebtedness, consolidated stockholders' equity of the borrower and its subsidiaries, and the aggregate value of outstanding hybrid securities. At September 30, 2014, the leverage ratios for IDACORP and Idaho Power were 46 percent and 47 percent, respectively. IDACORP's and Idaho Power's ability to utilize the credit facilities is conditioned upon their continued compliance with the leverage ratio covenants included in the credit facilities, which could limit the ability of the companies to issue first mortgage bonds and debt securities. There are additional covenants, subject to exceptions, that prohibit certain mergers, acquisitions, and investments, restrict the creation of certain liens, and prohibit entering into any agreements restricting dividend payments from any material subsidiary. At September 30, 2014, 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 next twelve months.

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.

In October 2012 and 2013, IDACORP and Idaho Power executed agreements with the lenders, extending the maturity date under both credit agreements to October 26, 2018. No other terms of the credit agreements, including the amount of permitted borrowings under the credit agreements, were affected by the extensions.

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

IDACORP and Idaho Power Commercial Paper: IDACORP and Idaho Power have commercial paper programs under which they issue unsecured commercial paper notes up to a maximum aggregate amount outstanding at any time not to exceed the available capacity under their respective credit facilities, described above. IDACORP's and Idaho Power's credit facilities are available to the companies to support borrowings under their commercial paper programs. The commercial paper issuances are

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used to provide an additional financing source for the companies' short-term liquidity needs. The maturities of the commercial paper issuances will vary, but may not exceed 270 days from the date of issue. Individual instruments carry a fixed rate during their respective terms, although the interest rates are reflective of current market conditions, subjecting the companies to fluctuations in interest rates.

Available Short-Term Borrowing Liquidity

The table below outlines available short-term borrowing liquidity as of the dates specified.



	September 30, 2014						December 31, 2013
	IDACORP⁽²⁾			Idaho Power			IDACORP⁽²⁾			Idaho Power
Revolving credit facility	$	125,000		$	300,000		$	125,000		$	300,000
Commercial paper outstanding	(31,800		)	—			(54,750		)	—
Identified for other use⁽¹⁾	—			(24,245		)	—			(24,245		)
Net balance available	$	93,200		$	275,755		$	70,250		$	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 October 24, 2014, IDACORP had no loans outstanding under its credit facility and $28.4 million of commercial paper outstanding, and Idaho Power had no loans outstanding under its credit facility and no commercial paper outstanding. The table below presents additional information about short-term commercial paper borrowing during the three and nine months ended September 30, 2014.



	Three months ended						Nine months ended
	September 30, 2014						September 30, 2014
	IDACORP⁽¹⁾			Idaho Power			IDACORP ⁽¹⁾			Idaho Power
Commercial paper:
Period end:
Amount outstanding	$	31,800		$	—		$	31,800		$	—
Weighted average interest rate	0.31		%	—		%	0.31		%	—		%
Daily average amount outstanding during the period	$	33,503		$	—		$	40,832		$	—
Weighted average interest rate during the period	0.31		%	—		%	0.31		%	—		%
Maximum month-end balance	$	33,900		$	—		$	47,300		$	—

⁽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, depends in part 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, 2013. However, any rating can be revised upward or downward or withdrawn at any time by a rating agency if it decides that the circumstances warrant the change.

Idaho Power maintains margin agreements relating to its wholesale commodity contracts that allow performance assurance collateral to be requested of and/or posted with certain counterparties. As of September 30, 2014, Idaho Power had posted $0.1 million of performance assurance collateral. Should Idaho Power experience a reduction in its credit rating on its unsecured debt to below investment grade, Idaho Power could be subject to requests by its wholesale counterparties to post additional performance assurance collateral, and counterparties to derivative instruments and other forward contracts could request immediate payment or demand immediate ongoing full daily collateralization on derivative instruments and contracts in net liability positions. Based upon Idaho Power’s current energy and fuel portfolio and market conditions as of September 30, 2014, the amount of additional collateral that could be requested upon a downgrade to below investment grade is approximately $6.8 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 $194.5 million during the nine months ended September 30, 2014. The table below presents Idaho Power's estimated cash requirements for construction, excluding AFUDC, for 2014 (including amounts incurred to-date) through 2018 (in millions of dollars).



	2014	2015	2016-2018
Ongoing capital expenditures (excluding item listed below in this table)	$235-245	$275-290	$855-900
Jim Bridger plant selective catalytic reduction (SCR) equipment	45-50	40-45	20-25
Total	$280-295	$315-335	$875-925

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, 2013. The discussion below should be read in conjunction with that report.

Boardman-to-Hemingway Line: The Boardman-to-Hemingway line, a proposed 300-mile, 500-kV transmission project between a station near Boardman, Oregon and the Hemingway station near Boise, Idaho, would provide transmission service to meet future resource needs. The Boardman-to-Hemingway line was included in the preferred resource portfolio in Idaho Power’s 2013 IRP. In January 2012, Idaho Power entered into a joint funding agreement with PacifiCorp and the Bonneville Power Administration (BPA) to 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 $21 million, including AFUDC. Total cost estimates for the project are between $890 million and $940 million, including AFUDC. This cost estimate excludes the impacts of inflation and price changes of materials and labor resources that may occur following the date of the estimate. Idaho Power's share of the permitting phase of the project (excluding AFUDC) is included in the capital requirements table above. Construction costs beyond the permitting phase are not included in the table above.

The permitting phase of the Boardman-to-Hemingway project is subject to review and approval by the U.S. Bureau of Land Management (BLM) (as the lead federal agency on behalf of other federal agencies), the U.S. Forest Service, and the Oregon Department of Energy. Idaho Power currently expects the BLM to issue a draft environmental impact statement (EIS) for the project in late 2014. In the separate Oregon state permitting process, Idaho Power submitted a preliminary application for a site certificate in February 2013 and intends to submit the final application in late 2015. In light of the delays and siting impediments that have occurred and are expected, Idaho Power is unable to accurately determine an approximate in-service date for the line but continues to expect the in-service date would be in 2020 or beyond.

Idaho Power has expended approximately $61 million on the Boardman-to-Hemingway project through September 30, 2014. Pursuant to the terms of the joint funding arrangements, approximately $31 million of that amount must be reimbursed to Idaho Power by joint permitting participants for expenses Idaho Power incurred, $23 million of which Idaho Power had received as of September 30, 2014. An additional $15 million is subject to reimbursement at a later date from the joint permitting participants, assuming their continued participation in the project, for expenses Idaho Power incurred prior to execution of the joint funding arrangements. Idaho Power plans to seek recovery of its share of project costs through the regulatory process.

Gateway West Line: Idaho Power and PacifiCorp are pursuing the joint development of the Gateway West project, a 500-kV transmission project between a station located near Douglas, Wyoming and the Hemingway station. In January 2012, Idaho Power and PacifiCorp entered a new joint funding agreement for permitting of the project. Idaho Power's estimated cost for the permitting phase of the Gateway West project is approximately $35 million, including AFUDC. Idaho Power has expended approximately $26 million on the permitting phase of the project through September 30, 2014. 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.

Idaho Power's interest in the Gateway West project applies to four of ten segments involved in the project, referred to as segments 6 (which Idaho Power had previously constructed and is included only for purposes of federal permitting related to the Gateway West project), 8, 9, and 10, comprised of 88, 126, 152, and 34 miles, respectively, and each of which is 500-kV.

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The BLM released its record of decision prepared under the National Environmental Policy Act in November 2013. In its record of decision, the BLM identified its final decision on the routing of the project, issued right-of-way grants on public land for segments 1 through 7 and 10, and deferred a decision on segments 8 and 9 to resolve routing concerns in those areas. Several interested parties have appealed the BLM's record of decision, and Idaho Power has intervened in the proceedings. The BLM requested and received from the Boise District Resource Advisory Council recommendations on routing, siting, and mitigation/enhancements for segments 8 and 9. Idaho Power and PacifiCorp have adopted the council's recommended routes for both segments 8 and 9. The BLM has initiated the supplemental EIS process for segments 8 and 9. As of the date of this report, the BLM's schedule provides for the issuance of a record of decision on routes 8 and 9 by late 2016.

Shoshone Falls Expansion Project Update: The Shoshone Falls plant expansion project was included in Idaho Power's 2013 IRP and consists of constructing a new powerhouse, intake structure, penstock, and substation and the installation of a new turbine to increase the nameplate generation capacity of the plant from 12.5 MW to 61.5 MW. The most recent FERC license amendment issued for the plant in 2012 required the project to be completed by 2017. However, as the project is unlikely to be completed by 2017, Idaho Power sought from the FERC an additional schedule extension. In May 2014, the FERC authorized extension of the date of commencement of construction to July 2018 and completion of construction by July 2022. Notwithstanding this schedule extension, Idaho Power still anticipates incurring the construction expenditures included in the table above through selecting and accelerating other projects that Idaho Power had previously expected to defer beyond 2018.

Pending Transmission System Transaction: To enhance the abilities of Idaho Power and PacifiCorp to serve their respective customers, on October 24, 2014, Idaho Power and PacifiCorp executed a Joint Ownership and Operating Agreement (Joint Operating Agreement) applicable to certain transmission-related equipment proposed to be exchanged by Idaho Power and PacifiCorp. The proposed exchange would be made pursuant to the terms of a Joint Purchase and Sale Agreement (Joint Purchase Agreement), also dated October 24, 2014, between Idaho Power and PacifiCorp, under which Idaho Power agreed to transfer to PacifiCorp full or joint ownership interests in specified transmission-related equipment with an estimated year-end 2014 net book value of approximately $43 million, and PacifiCorp agreed to transfer to Idaho Power full or joint ownership interests in specified transmission-related equipment with an estimated year-end 2014 net book value of approximately $43 million, subject to true-up as of the closing date. The proposed transaction also provides for the termination and amendment of a number of legacy long-term transmission service agreements between Idaho Power and PacifiCorp.

The Joint Operating Agreement is intended to provide Idaho Power and PacifiCorp with access to integrated transmission facilities that aligns more closely with current industry standards and allows the parties to more efficiently satisfy regulatory and reliability requirements. The Joint Operating Agreement allocates the directional transmission capacity of the exchanged transmission-related assets between the companies, which will be managed pursuant to each company's open access transmission tariff. The Joint Operating Agreement also provides for the operation, upgrade, repair, rebuilding, and decommissioning of the exchanged assets and certain other equipment each company owns. Closing of the proposed transaction, effectiveness of the Joint Operating Agreement, and termination and amendment of the legacy long-term transmission service agreements is subject to a number of conditions, including approval by, or notice to, the public utility commissions of California, Idaho, Oregon, Utah, Washington, and Wyoming, and approval by the FERC.

2013 Integrated Resource Plan: The IPUC and OPUC require that Idaho Power biennially prepare an IRP. The IRP forecasts 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. Decisions made in IRP proceedings do not constitute ratemaking, but the company views acceptance for filing (in Idaho) or acknowledgment (in Oregon) of an IRP as relevant to the subsequent examination of whether the company's resource investments were prudent and thus may be recoverable through rates. On June 28, 2013, Idaho Power filed its 2013 IRP with the IPUC and OPUC. The 2013 IRP 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. On February 24, 2014, the IPUC accepted the 2013 IRP for filing and requested that Idaho Power continue monitoring environmental requirements at a national level and account for their impact in resource planning, collaborate with stakeholders on how best to use energy efficiency as a resource, be actively involved in matters relating to the North Valmy coal-fired power plant, and promptly apprise the IPUC of developments that could impact the company's continued reliance on that coal-fired resource. On July 8, 2014, the OPUC acknowledged Idaho Power's short-term action items in the 2013 IRP. In its order, the OPUC did not acknowledge Idaho Power's investments in selective catalytic reduction emissions technology at the Jim Bridger plant. The OPUC stated that it would undertake a fair and thorough investigation of the prudence of the emissions technology investments at the Jim Bridger plant when Idaho Power seeks rate recovery for the investments.

In August 2014, Idaho Power began the preparation of its 2015 IRP, including initiating the public involvement process. Idaho Power expects to file the 2015 IRP in June 2015. As part of the process of preparing the 2015 IRP, Idaho Power performed an analysis of future anticipated loads. The load forecast Idaho Power used in the 2013 IRP predicted an average annual growth

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rate of 1.1 percent for average loads and 1.4 percent for summer peak loads over the 20-year planning horizon from 2013 to 2032. The load forecast Idaho Power is using for purposes of the 2015 IRP predicts an average annual growth rate of 1.2 percent for average loads and 1.5 percent for summer peak loads over the 20-year planning horizon from 2015 to 2034. The rate of load growth can impact the timing and extent of development of resources, such as new generation plants or transmission infrastructure, to serve those loads. The 2015 IRP is intended to identify the most suitable resources to meet the load demand predicted in the IRP.

Defined Benefit Pension Plan Contributions

Idaho Power contributed $30 million to the defined benefit pension plan in both 2014 and 2013. No additional contributions are anticipated for the remainder of 2014. Idaho Power's contributions are made in a continued effort to balance the regulatory collection of these expenditures with the amount and timing of contributions and to mitigate the cost of being in an underfunded position. In 2015 and beyond, Idaho Power expects significant contribution obligations under the pension plan. The primary impact of pension contributions is on the timing of cash flows, as cost recovery lags behind the timing of contributions.

Contractual Obligations

During the nine months ended September 30, 2014, 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, 2013, except for the addition of thirteen power purchase agreements with solar, wind, and other alternative energy developers for projects with a combined nameplate capacity of approximately 176 MW. Payments pursuant to these agreements are expected to total $659 million from 2014 to 2038. Three of these power purchase agreements remain subject to IPUC approval, with a combined nameplate capacity of approximately 120 MW and expected payments of $449 million over the period from 2016 to 2037.

In October 2014, Idaho Power signed eleven energy sales agreements with solar energy developers for projects with a combined nameplate capacity of approximately 280 MW. The agreements are subject to approval by the IPUC, and the payments pursuant to these agreements are expected to total $915 million from 2017 to 2038.

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, 2013.

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 jurisdiction (as to rates, service, accounting, and other general matters of utility operation) of the FERC, the IPUC, and the OPUC. The IPUC and the OPUC 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, as well as single-issue rate cases for the Langley Gulch power plant, that resulted in the resetting of Idaho and Oregon base rates in 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, 2013. 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, 2013), 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.

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Notable Orders During 2014

During 2014 to-date, Idaho Power has received orders in the notable regulatory proceedings summarized in the table below.



Description	Status	Estimated Rate Impact⁽¹⁾	Notes
Power Cost Adjustment Mechanism - Idaho Filing	Approved by the IPUC on May 30, 2014	$11.1 million net PCA rate increase for the period from June 1, 2014 to May 31, 2015	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.
Net Power Supply Expense Recovery - Idaho Filing	Approved by the IPUC on March 21, 2014	No net impact on revenues - resulted in the reallocation of costs collected via the Idaho PCA to Idaho base rates, effective June 1, 2014	Idaho Power requested an increase of approximately $106 million on a total-system basis in the normalized or “base level” power supply expense to be used to update base rates and in the determination of the PCA rate.
Fixed Cost Adjustment - Idaho Filing	Approved by the IPUC on May 30, 2014	$6.0 million increase in the FCA for the period from June 1, 2014 to May 31, 2015	The FCA is designed to remove Idaho Power’s financial disincentive to invest in energy efficiency programs by partially separating (or decoupling) the recovery of fixed costs from the volumetric kilowatt-hour charge and linking it instead to a set amount per customer. As described in Note 3 - "Regulatory Matters" to the condensed consolidated financial statements included in this report, a docket is currently open at the IPUC to review whether the FCA is effectively removing Idaho Power's disincentive to aggressively pursue energy efficiency programs.
ADITC/Revenue Sharing Settlement Stipulation Extension - Idaho Filing	Approved by the IPUC on October 9, 2014	The potential rate impact depends on Idaho Power's Idaho ROE. See the discussion below of the terms of the settlement stipulation.	The terms of the settlement stipulation approved by the IPUC are described below.

⁽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 Earnings Support from December 2011 Settlement Stipulation; Extension of Settlement Terms

Idaho Power has in place a regulatory mechanism that it believes affords an element of earnings stability for 2014. In December 2011, the IPUC issued an order, separate from the then-pending Idaho general rate case proceeding, approving a settlement stipulation that allows Idaho Power to, in certain circumstances, amortize additional ADITC if Idaho Power's actual Idaho ROE for 2012, 2013, or 2014 is less than 9.5 percent, to help achieve a 9.5 percent Idaho ROE for the applicable year. Where Idaho Power's actual Idaho ROE for any of those years exceeds 10.0 percent, Idaho Power must share a portion of its Idaho-jurisdiction earnings with Idaho customers.

As Idaho Power's 2012 and 2013 Idaho ROE exceeded 10.5 percent, Idaho Power did not amortize additional ADITC for 2012 or 2013, but instead shared earnings with customers. The amounts Idaho Power recorded for sharing for those years were as follows:



	2013		2012
Additional pension expense funded through sharing	$	16.5	$	14.6
Provision against current revenue as a result of sharing	7.6		7.2
Total	$	24.1	$	21.8

Based on Idaho Power's September 30, 2014 estimate of full-year 2014 Idaho ROE, Idaho Power does not expect to amortize any additional ADITC for 2014, and instead recorded $4.9 million in the third quarter of 2014 as a provision for sharing with customers, in accordance with the terms of the December 2011 settlement stipulation.

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of the IPUC. The terms and conditions of the December 2011 settlement stipulation and the settlement stipulation extension, as approved by the IPUC, are described in Note 3 - "Regulatory Matters - Idaho Settlement Stipulation — Investment Tax Credits and Sharing Mechanism" to the condensed consolidated financial statements included in this report. Idaho Power believes that approval of the new settlement stipulation affords Idaho Power a continued element of earnings stability, similar to that provided by the December 2011 settlement stipulation, until the earlier of 2019 or full use of the additional amortization of ADITC.

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

Deferred power supply costs represent certain differences between Idaho Power's actual net power supply costs and the costs included in its retail rates, the latter being based on annual forecasts of power supply costs. Deferred power supply costs are recorded on the balance sheets for future recovery or refund through customer rates. The table below summarizes the change in deferred net power supply costs during the nine months ended September 30, 2014.



	Idaho			Oregon⁽¹⁾			Total
Balance at December 31, 2013	$	84,843		$	6,611		$	91,454
Current period net power supply costs deferred	29,170			—			29,170
Prior amounts recovered through rates	(37,499		)	(1,654		)	(39,153		)
SO₂ allowance and renewable energy certificate (REC) sales	(2,655		)	(117		)	(2,772		)
Revenue sharing and energy efficiency rider funds	(27,624		)	—			(27,624		)
Interest and other	465			308			773
Balance at September 30, 2014	$	46,700		$	5,148		$	51,848

⁽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. The IPUC's approval of Idaho Power's April 2014 application requesting an $11.1 million net increase in PCA rates for the 2014-2015 PCA collection period from June 1, 2014 to May 31, 2015, is discussed in Note 3 - "Regulatory Matters" to the condensed consolidated financial statements included in this report. Previously, in May 2013 the IPUC issued an order authorizing a $140.4 million increase in Idaho PCA rates, effective for the 2013-2014 PCA collection period.

With the exception of power supply expenses incurred under PURPA and certain demand response program costs that are passed through to customers substantially in full, the PCA allows Idaho Power to pass through to customers 95 percent of the differences in actual net power supply expenses as compared to forecasted base net 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.

Since 2010, when Idaho Power's normalized level of net power supply expenses included in Idaho base rates last received a comprehensive review, many of the individual cost and revenue components of these "base level" net power supply expenses changed significantly and permanently. These ongoing and permanent costs were being recovered through the Idaho PCA. The primary components contributing to the increase in net power supply expenses are increased energy purchases pursuant to PURPA, lower surplus energy sales revenue resulting from lower energy market prices, and the elimination of anticipated offsetting revenues from one special contract customer. In light of these permanent increases, on November 1, 2013, Idaho Power filed an application with the IPUC requesting an increase of approximately $106 million on a total-system basis in the normalized or “base level” power supply expense to be used to update base rates and in the determination of the PCA rate that would become effective June 1, 2014. On March 21, 2014, the IPUC issued an order approving Idaho Power's application. This removed the Idaho-jurisdiction portion of those expenses from collection via the Idaho PCA mechanism and instead results in Idaho Power collecting that portion in base rates. Approval of the application results in no change in the aggregate amount collected through base rates and the PCA mechanism. However, the approved application will reduce the magnitude of any base rate increase requested by Idaho Power in its next general rate case application filed with the IPUC.

Update to Open Access Transmission Tariff

Idaho Power uses a formula rate for transmission service provided under its OATT, which allows transmission rates to be updated annually based on financial and operational data Idaho Power files with the FERC. On August 28, 2014, Idaho Power filed with the FERC and publicly posted its annual final informational filing reflecting a transmission rate of $22.71 per kW-

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year, to be effective for the period from October 1, 2014 to September 30, 2015. Idaho Power's posting was based on a net annual transmission revenue requirement of $120.8 million. By comparison, the OATT rate in effect from October 1, 2013 to September 30, 2014 was $22.80 per kW-year based on a net annual transmission revenue requirement of $118.2 million.

Bulk-System Reliability Standards

In March 2014, the FERC directed the North American Electric Reliability Corporation (NERC), pursuant to the Federal Power Act, to submit for approval reliability standards that will require electric utilities to take steps or demonstrate that they have previously taken steps to address physical security risks and vulnerabilities related to the reliable operation of the bulk-power system. The standards require utilities to identify facilities on the bulk-power system that are critical to the reliable operation of the system and develop, validate, and implement plans to protect against physical attacks that may compromise the operability or recovery of the facilities. Idaho Power has in place a number of physical security measures for its infrastructure. However, the NERC's standards may result in Idaho Power further enhancing its existing physical security measures, which would increase costs. Idaho Power would seek to recover those increased costs through the regulatory process.

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 (95 percent in the Idaho jurisdiction) of those proceeds through the PCA. Idaho Power's REC sales were $2.9 million for the nine months ended September 30, 2014 as compared with $0.5 million for the same period of 2013. The comparative increase in REC sales resulted primarily from the execution of new bundled REC purchase and sale agreements with third parties.

Renewable and Other Energy Contracts: Idaho Power purchases wind power from both cogeneration and small power production (CSPP) and non-CSPP facilities, including its largest non-CSPP wind power project -- the Elkhorn Valley wind project with a 101 MW nameplate capacity. As of September 30, 2014, Idaho Power had contracts to purchase energy from on-line CSPP wind power projects with a combined nameplate rating of 577 MW and an additional 50 MW of CSPP wind power projects not on-line and scheduled to come on-line by year-end 2016. In addition to its power purchase arrangements with wind power generators, Idaho Power has contracts for the purchase of power from other CSPP and non-CSPP renewable generation sources, such as biomass, solar, small hydroelectric projects, and two geothermal projects. Recently, Idaho Power has received numerous requests for proposed power purchase contracts from developers of a number of potential solar power projects, which if developed would substantially increase the amount of solar power purchased by Idaho Power under solar CSPP-related agreements. As of September 30, 2014, Idaho Power had the number and nameplate capacity of signed CSPP-related agreements with terms ranging from one to 35 years set forth in the following table.



Status	Number of CSPP Contracts	Nameplate Capacity (MW)
On-line as of September 30, 2014	104	781
Contracted and projected to come on-line by June 1, 2017	18	240

Pursuant to the requirements 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 can result in Idaho Power acquiring energy that it does not need to serve customer loads at above wholesale market prices and require additional operational integration measures, thus increasing costs to Idaho Power's customers. As the volume of CSPP purchases increases under PURPA, the magnitude of the costs and integration issues also increases. Substantially all PURPA power purchase costs are recovered through base rates and Idaho Power's PCA 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. Idaho Power expects to seek recovery of relicensing costs through the ratemaking process. Relicensing costs of $194 million for the HCC, Idaho Power's largest hydroelectric complex and a major relicensing effort, were included in construction work in progress at September 30, 2014. 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 when HCC relicensing costs are approved

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for recovery in base rates. As of September 30, 2014, Idaho Power's regulatory liability for collection of AFUDC relating to the HCC was $69.7 million. While Idaho Power is unable to predict with certainty the timing of issuance of a new license for the HCC, or the financial or operational requirements of a new license, Idaho Power currently projects issuance of the license near 2020.

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 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, mercury and other emissions, air quality, hazardous wastes, polychlorinated biphenyls, and threatened and endangered species. These laws are administered by a number of federal, state, and local agencies. In addition to imposing continuing compliance obligations and associated costs, these laws and regulations provide authority to regulators to levy substantial penalties for noncompliance, injunctive relief, and other sanctions. Idaho Power's three coal-fired power plants and three natural gas-fired combustion turbine power plants are subject to many of these regulations. Idaho Power's 17 hydroelectric projects are also subject to a number of water discharge standards and other environmental requirements.

Compliance with current and future environmental laws and regulations may:


•	increase the operating costs of generating plants;


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


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


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


•	reduce the output from current generating facilities.

Current and future environmental laws and regulations will increase the cost of operating coal-fired power plants and constructing new facilities, in large part through the installation of additional pollution control devices at existing generating plants, and could result in Idaho Power discontinuing the operation of one or more coal-fired plants if operation becomes uneconomical. These regulations could, in turn, affect IDACORP's and Idaho Power's results of operations and financial condition if the costs associated with these environmental requirements and plant shut-downs cannot be fully recovered in rates on a timely basis. Part I - “Business - Environmental Regulation and Costs” in IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2013 includes a summary of Idaho Power's expected capital and operating expenditures for environmental matters during the period from 2014 to 2016. 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.

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, 2013.

Clean Air Act Developments

Clean Air Act - Proposed Rule for Existing Generating Plants under Section 111(d)

On June 2, 2014, the EPA released, under Section 111(d) of the CAA, a proposed rule for addressing greenhouse gas emissions from existing fossil fuel-fired electric generating units (EGUs). According to the EPA, the rule is designed to achieve a 30 percent reduction in CO₂ emissions from the power sector. The proposal has two main elements: (1) state-specific emission rate-based CO₂ goals and (2) guidelines for the development, submission, and implementation of state plans. The EPA used 2012 as the baseline when calculating the state-specific emission rate goals. While the proposal lays out state-specific CO₂ goals that each state is required to meet, it does not prescribe how a state should meet its goal. Under the proposal, each state may seek to do so alone or may seek to collaborate with other states on multi-state plans.

Under the proposed rule, the EPA would permit states to develop plans to reduce CO₂ emissions under an approach referred to as the “best system of emission reduction.” This approach is intended to take into account both the cost and technical feasibility of achieving such reduction. States would have flexibility to implement measures that, in some cases, are already in

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progress. The EPA has grouped these measures into the following four "building blocks," which generally describe four approaches for CO₂ emission reduction:


1.	Reducing the carbon intensity of generation at individual affected EGUs through heat rate improvements.


2.	Reducing emissions from the most carbon-intensive affected EGUs in the amount that results from substituting generation at those EGUs with generation from less carbon-intensive affected EGUs.


3.	Reducing emissions from affected EGUs in the amount that results from substituting generation at those EGUs with expanded low- or zero-carbon generation.


4.	Reducing emissions from affected EGUs in the amount that results from the use of demand-side energy efficiency that reduces the amount of generation required.

The EPA's proposal requires that states meet their goal by 2030, with periodic reports to the EPA starting in 2022. The proposal also provides for states meeting interim goals from 2020 to 2029. The EPA has stated that it expects to finalize the rulemaking by June 2015. State implementation plans would be due by June 30, 2016, subject to extension for portions of the plan to June 30, 2017 for state plans or June 30, 2018 for multi-state plans, under certain circumstances.

Idaho Power is analyzing the proposal and is participating in state and regional forums that are evaluating the assumptions included in the proposal, the potential financial and operational impacts of the proposal, the means by which states may seek to achieve compliance, the potential contents of state implementation plans, and other matters. As of the date of this report, Idaho Power is unable to determine the impact of the proposed rule, should it become final, on its generating plants, financial condition, and operations.

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 was 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. On January 10, 2014, the EPA approved the portion of Wyoming's RH SIP relating to the Jim Bridger plant, with the NOx control compliance dates set forth in the settlement agreement, and approved and disapproved other portions of the RH SIP. Several interested parties have appealed the EPA's decisions on Wyoming's RH SIP on various grounds. Idaho Power has not appealed the EPA's decisions but has intervened in the proceedings to participate if and to the extent the Jim Bridger plant could be affected.

Clean Water Act Developments

Potential Expansion of CWA Scope: On April 21, 2014, the EPA and U.S. Army Corps of Engineers jointly published for public comment a proposed rule to revise the definition of "waters of the United States" for purposes of the CWA. The proposed rule would potentially expand federal jurisdiction under the CWA beyond traditional navigable waters, interstate waters, territorial seas, tributaries, and adjacent wetlands, to a number of other waters, including waters with a "significant nexus" to those traditional waters. The rule could trigger substantial additional permitting and regulatory requirements under multiple provisions of the CWA. Idaho Power is analyzing the proposed rule but as of the date of this report is unable to determine the impact of the proposed rule, should it become final, on its operations.

CWA Section 316(b) Regulation of Cooling Water Intake Structures: Section 316(b) of the CWA requires that National Pollutant Discharge Elimination System permits for facilities with cooling water intake structures ensure that the location, design, construction, and capacity of the structures employ the best technology available (BTA) to minimize harmful impacts on the environment, such as the removal of fish, fish larvae, marine mammals, and other aquatic organisms from waters of the U.S. In May 2014, the EPA issued final rules that establish requirements under Section 316(b) of the CWA for existing power generation facilities that withdraw more than 2 million gallons per day of water from waters of the U.S. and use at least 25 percent of the water they withdraw exclusively for cooling purposes. These facilities are required to reduce fish impingement under the final rules, using one of several options for meeting BTA requirements for reducing impingement. Based on the qualification criteria, Idaho Power is evaluating whether these new requirements apply to the Jim Bridger plant. Idaho Power and the plant's co-owner are performing studies at the plant to determine the applicability of the new rules and the infrastructure improvements or operational changes that may be required for the plant to comply with the new rules, if applicable. Based on

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its preliminary analysis, as of the date of this report Idaho Power does not expect that compliance with the new rules will result in a material increase in costs.

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 committees 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, 2013.

Recently Issued Accounting Pronouncements

See Note 1 - "Summary of Significant Accounting Policies" to the condensed consolidated financial statements included in this report for a summary of significant accounting policies, including the discussion under "Change in Method of Accounting for Investments in Qualified Affordable Housing Projects," relating to IDACORP's adoption in 2013, with retrospective effect, of an accounting policy election to account for investments in qualified affordable housing projects using the proportional amortization method. This method change resulted in a $1.3 million increase in IDACORP's net income in the third quarter of 2013 and a $4.0 million increase in IDACORP's net income for the first nine months of 2013 compared to the amounts recorded under the previously applied method.

In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update (ASU) 2014-09, Revenue from Contracts with Customers (Topic 606). ASU 2014-09 is intended to enable users of financial statements to better understand and consistently analyze an entity's revenue across industries, transactions, and geographies. Under the ASU, recognition of revenue occurs when a customer obtains control of promised goods or services. In addition, the ASU requires disclosure of the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The amendments in ASU 2014-09 are effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. Early adoption is not permitted. The guidance permits two implementation approaches, one requiring retrospective application of the new standard with restatement of prior years and one requiring prospective application of the new standard including a cumulative-effect adjustment with disclosure of results under old standards. As such, at IDACORP's and Idaho Power's required adoption date of January 1, 2017, amounts in 2015 and 2016 may have to be revised. IDACORP and Idaho Power are currently evaluating the impact of ASU 2014-09 on their financial statements.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

IDACORP is exposed to market risks, including changes in interest rates, changes in commodity prices, credit risk, and equity price risk. The following discussion summarizes these risks and the financial instruments, derivative instruments, and derivative commodity instruments sensitive to changes in interest rates, commodity prices, and equity prices that were held at September 30, 2014. IDACORP has not entered into any of these market-risk-sensitive instruments for trading purposes.

Interest Rate Risk

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

Variable Rate Debt: As of September 30, 2014, IDACORP had $55.9 million in net floating rate debt. The fair market value of this debt was $55.9 million. Assuming no change in financial structure, if variable interest rates were to average one percentage

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point higher than the average rate on September 30, 2014, annual interest expense would increase and pre-tax earnings would decrease by approximately $0.6 million.

Fixed Rate Debt: As of September 30, 2014, IDACORP had $1.6 billion in fixed rate debt, with a fair market value equal to $1.6 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 $196 million if market interest rates were to decline by one percentage point from their September 30, 2014 levels.

Commodity Price Risk

IDACORP's exposure to changes in commodity prices is related to Idaho Power's ongoing utility operations that produce electricity to meet the demand of its retail electric customers. These changes in commodity prices are mitigated in large part by Idaho Power's Idaho and Oregon PCA mechanisms. 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 commodity price risk as of September 30, 2014 had not changed materially from that reported in Item 7A of IDACORP's Annual Report on Form 10-K for the year ended December 31, 2013. Information regarding Idaho Power’s use of derivative instruments to manage commodity price risk can be found in Note 11 – “Derivative Financial Instruments” to the condensed consolidated financial statements included in this report.

Credit Risk

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

The use of performance assurance collateral in the form of cash, letters of credit, or guarantees is common industry practice. Idaho Power maintains margin agreements relating to its wholesale commodity contracts that allow performance assurance collateral to be requested of and/or posted with certain counterparties. As of September 30, 2014, Idaho Power had posted $0.1 million of performance assurance collateral. Should Idaho Power experience a reduction in its credit rating on Idaho Power's unsecured debt to below investment grade Idaho Power could be subject to requests by its wholesale counterparties to post additional performance assurance collateral. Counterparties to derivative instruments and other forward contracts could request immediate payment or demand immediate ongoing full daily collateralization on derivative instruments and contracts in net liability positions. Based upon Idaho Power's energy and fuel portfolio and market conditions as of September 30, 2014, the amount of collateral that could be requested upon a downgrade to below investment grade was approximately $6.8 million. To minimize capital requirements, Idaho Power actively monitors the portfolio exposure and the potential exposure to additional requests for performance assurance collateral calls through sensitivity analysis.

IDACORP's credit risk related to uncollectible accounts, net of amounts reserved, as of September 30, 2014 had not changed materially from that reported in Item 7A of IDACORP's Annual Report on Form 10-K for the year ended December 31, 2013. Additional information regarding Idaho Power’s management of credit risk and credit contingent features can be found in Note 11 – “Derivative Financial Instruments” to the condensed consolidated financial statements included in this report.

Equity Price Risk

IDACORP is exposed to price fluctuations in equity markets, primarily through Idaho Power's defined benefit pension plan assets, a mine reclamation trust fund owned by an equity-method investment of Idaho Power, and other equity security investments at Idaho Power. The equity securities held by the pension plan and in such accounts are diversified to achieve broad market participation and reduce the impact of any single investment, sector, or geographic region. Idaho Power has established asset allocation targets for the pension plan holdings, which are described in Note 10 - "Benefit Plans" to the notes to the consolidated financial statements included in IDACORP's Annual Report on Form 10-K for the year ended December 31, 2013. IDACORP’s equity price risk as of September 30, 2014 had not changed materially from that reported in Item 7A of IDACORP's Annual Report on Form 10-K for the year ended December 31, 2013.

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ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

IDACORP: The Chief Executive Officer and the Chief Financial Officer of IDACORP, based on their evaluation of IDACORP’s disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of September 30, 2014, have concluded that IDACORP’s disclosure controls and procedures are effective as of that date.

Idaho Power: The Chief Executive Officer and the Chief Financial Officer of Idaho Power, based on their evaluation of Idaho Power’s disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of September 30, 2014, 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 September 30, 2014, 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 8 - “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, 2013, could materially affect IDACORP’s and Idaho Power’s business, financial condition, or future results. In addition to those risk factors and other risks discussed in this report, 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

See Note 5 - “Common Stock” to the condensed consolidated financial statements included in this report for a description of restrictions on IDACORP’s and Idaho Power’s payment of dividends.

Issuer Purchases of Equity Securities

IDACORP did not repurchase any shares of its common stock during the quarter ended September 30, 2014.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

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.

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ITEM 5. OTHER INFORMATION

Amendment and Restatement of the IDACORP, Inc. Amended Bylaws

On October 29, 2014, the Board of Directors of IDACORP approved and adopted the Amended and Restated Bylaws of IDACORP, Inc. (Restated Bylaws), to be effective as of that date. A complete copy of the Restated Bylaws is filed as Exhibit 3.15 to this Quarterly Report on Form 10-Q. A copy of the Restated Bylaws marked to the show the amendments compared to IDACORP’s prior Amended Bylaws, as previously in effect (Prior Bylaws), is filed as Exhibit 3.16 to this Quarterly Report on Form 10-Q. The notable amendments made to the Prior Bylaws and included in the Restated Bylaws are summarized below. The description in this report of the amendments to the Prior Bylaws is qualified in its entirety by reference to the full text of the Restated Bylaws filed as Exhibit 3.15 to this report and incorporated by reference herein.

Amendment to Section 2.2 of Article II

Section 2.2 of Article II of the Prior Bylaws has been amended in the Restated Bylaws to require shareholders delivering a demand for a special meeting to provide documentary evidence that those shareholders hold the requisite percentage of shares necessary to demand a special meeting, and to clarify that those shareholders must also provide with their demand the other information, representations, and documentation required by Section 2.9 of the Restated Bylaws.

Amendments to Section 2.9 of Article II

The amendments to Section 2.9 of the Prior Bylaws revise the information, representation, and documentation requirements, as well as the time periods, applicable to the submission of nominations and proposals for business to be brought by a shareholder at an annual or special meeting of shareholders. The amendments to Section 2.9 also specify that, when a shareholder notice is required by Section 2.9, it must be personally delivered or delivered by registered or certified mail, postage prepaid. Certain of the other specific amendments are described below.

Section 2.9.1 - The amendments to Section 2.9.1 of the Prior Bylaws (a) clarify that, other than proposals brought pursuant to Rule 14a-8 under the Securities Exchange Act of 1934, as amended, and the rules thereunder (Exchange Act), the exclusive means by which shareholders may propose business to be conducted at an annual meeting is through compliance with Section 2.9 of the Restated Bylaws, and (b) revise the deadline for the submission of nominations and other business by shareholders for consideration at an annual meeting.

The Prior Bylaws provided that a shareholder’s notice, to be timely, had to be delivered to the Secretary of IDACORP not later than the 120^th day prior to the first anniversary of the date on which IDACORP first mailed its proxy materials for the preceding year’s annual meeting, except where the date of the annual meeting was more than 30 days before or after the anniversary date of the preceding year’s annual meeting, in which case notice must have been delivered by the 10^th day following the day on which IDACORP first made a public announcement of the date of the meeting. The amendments in the Restated Bylaws create a “window” period during which the shareholder notice must be provided, and allow shareholders to submit their nominations or other business closer to the annual meeting date than under the Prior Bylaws. The Restated Bylaws provide that, to be timely, the shareholder’s notice and accompanying information, representations, and documentation must be delivered to the Secretary of IDACORP not later than the 120^th day nor earlier than the 150^th day prior to the first anniversary of the prior year’s annual meeting date. Under the Restated Bylaws, where the date of the annual meeting is more than 30 days before or 60 days after the anniversary date of the prior year’s annual meeting, the notice must be delivered not earlier than the 150^th day prior to such annual meeting and not later than the 120^th day prior to such annual meeting or, if the first public announcement by IDACORP of the date of the annual meeting is less than 130 days prior to the annual meeting, the 10^th day following the public announcement.

As to nominations and proposals for the 2015 annual meeting of shareholders, the effect of the amendments to the notice period in the Restated Bylaw is included below under the heading “Note Regarding the 2015 Annual Meeting of Shareholders.”

Section 2.9.2 - The amendments to Section 2.9.2 clarify that if a special meeting is called upon demand of shareholders, the IDACORP Board of Directors may include additional items of business on the agenda for the special meeting. The amendments to Section 2.9.2 also provide that if directors will be elected at a special meeting, shareholders may nominate directors for election at that meeting in accordance with the nomination procedures set forth in Section 2.9 of the Restated Bylaws. Also, in the case of a special meeting at which directors are to be elected, the required contents of the shareholder’s nomination of a director candidate for election at such meeting, included in Section 2.9.2 of the Prior Bylaws, were moved to

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Section 2.9.3 (discussed below) in the Restated Bylaws. Similar to the amendments made with respect to the shareholder’s notice of nominations or proposals for business to be conducted at the annual meeting, the Restated Bylaws also clarify that a shareholder must deliver information, representations and documentation to IDACORP personally or by registered or certified mail, postage prepaid. The Restated Bylaws also clarify that the public announcement of the adjournment of a special meeting will not extend the time period during which shareholders are required to give notice of proposals or nominations with respect to such meetings.

Section 2.9.3 - The Restated Bylaws require that additional information, representations, and documentation accompany a notice submitted by shareholders in connection with a nomination or proposal of business for an annual or special meeting of shareholders. Under the Restated Bylaws, in addition to the information required by the Prior Bylaws, where a shareholder is proposing a nominee for a director position, a shareholder notice must also include:


•	Information on derivative and other transactions that the nominee has entered into (or that have been entered into on the nominee’s behalf) with the intent of (or which have the effect of) creating or mitigating loss, managing risk or benefit of share price changes, or increasing or decreasing the voting power of the nominee with respect to IDACORP’s securities;


•	Information on arrangements pursuant to which the nominee was nominated; and

•

A questionnaire (similar to IDACORP’s annual directors’ and officers’ questionnaire) completed and signed by the nominee and accompanied by a written representation by the nominee concerning (i) the absence of certain voting commitments, derivative securities transactions that have not been disclosed to IDACORP, and compensation or indemnification arrangements that have not been disclosed to IDACORP, and (ii) the nominee’s compliance with applicable laws, stock exchange requirements, and applicable IDACORP policies.

The Restated Bylaws also require such shareholder to update and supplement its notice, the questionnaire, and the written representations within five days of any event that makes the information contained therein no longer true, correct, and complete.

The Restated Bylaws provide that IDACORP may also require a shareholder nominee to provide other information reasonably requested by IDACORP to determine the qualifications of the nominee to serve as a director.

As to proposals for other business to be brought by a shareholder before an annual or special meeting, the Restated Bylaws require the shareholder to include the text of the proposal in the notice delivered to the Company.

In all cases, in addition to the information required by the Prior Bylaws, the Restated Bylaws also provide that the shareholder who gives notice of a nomination or proposal of other business for an annual or special meeting must also provide the following information and consent on its own behalf and on behalf of its affiliates and associates (as those terms are defined in the Restated Bylaws):


•	The name and address of the shareholder and its affiliates and its associates on whose behalf the nomination is made;


•	A description of any material interest in the business to be proposed;


•	A description of derivative and other transactions that have been entered into with the intent of (or which have the effect of) creating or mitigating loss, managing risk or benefit of share price changes, or increasing or decreasing the voting power of the shareholder or affiliates and associates with respect to IDACORP’s securities;


•	The information that would be required in a proxy statement under the Exchange Act if the business were being proposed by the IDACORP Board of Directors;


•	A statement as to whether such shareholder or affiliate or associate intends (or is part of a group that intends) to deliver a proxy statement or form of proxy to certain IDACORP shareholders; and


•	A consent to IDACORP’s public disclosure of the information furnished.

Section 2.9.4 - Section 2.9.3 of the Prior Bylaws has been renumbered as Section 2.9.4 in the Restated Bylaws, and has been amended. The amendments include provisions generally applicable to Section 2.9. The Restated Bylaws provide, in Section 2.9.4, that proposed business will not be transacted and proposed nominations will not be made at an annual or special meeting of shareholders if the shareholder (or a qualified and authorized representative) does not appear at the meeting to present the business or nomination. Section 2.9.4 of the Restated Bylaws also clarifies that compliance with the requirements included in Sections 2.2 and 2.9 of the Restated Bylaws are the exclusive means for a shareholder to make nominations or submit other business at an annual or special meeting and are not limited by references to the Exchange Act contained therein, other than proposals requested to be included in IDACORP’s proxy statement pursuant to Rule 14a-8 under the Exchange Act.

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Amendment to Section 3.2 of Article III

Effective in May 2012, IDACORP amended its Articles of Incorporation, as amended, following a shareholder vote, to provide that the company’s classified (three-year, staggered term) board structure would be phased out, such that the annual election of the entire board of directors for a one-year term would be phased in over a three-year period commencing at the 2013 annual meeting of shareholders and concluding at the 2015 annual meeting of shareholders. Accordingly, as of the date of this report all current directors have a term expiring at the 2015 annual meeting of shareholders. In light of the current term of directors, the final two sentences of Section 3.2 of the Prior Bylaws, which provided for allocating newly created or eliminated directorships among the three-year classes, have been deleted in the Restated Bylaws as they are no longer applicable.

Note Regarding Shareholder Nominations and Other Proposals for the 2015 Annual Meeting of Shareholders

As a result of the amendments to the Prior Bylaws referred to above and set forth in the Restated Bylaws, the information contained on page 64 of IDACORP’s definitive proxy statement, dated April 2, 2014, under the caption “2015 Annual Meeting of Shareholders” is changed to and superseded by the following:

“As of the date of this report, we expect our 2015 annual meeting of shareholders to be held on May 21, 2015.

Shareholders of the company may submit proposals on matters appropriate for shareholder action at meetings of the company’s shareholders in accordance with Rule 14a-8 of the Securities and Exchange Commission. To be submitted for inclusion in next year’s proxy statement, shareholder proposals must satisfy all applicable requirements of Rule 14a-8. For our 2015 annual meeting of shareholders, if you wish to submit a proposal for inclusion in the proxy materials pursuant to Rule 14a-8, you must submit your proposal to our corporate secretary on or before the close of business on December 3, 2014.

Our Amended and Restated Bylaws require that any shareholder proposal that is not submitted for inclusion in our proxy statement under Rule 14a-8, but is instead sought to be presented directly at the 2015 annual meeting of shareholders, must be received at our principal executive offices not earlier than 150 days and not later than 120 days prior to the first anniversary of the date on which we held the 2014 Annual Meeting. As a result, proposals, including director nominations, submitted pursuant to these provisions of our Amended and Restated Bylaws must be received no earlier than December 16, 2014 and no later than the close of business on January 15, 2015. The proposal must be accompanied by certain information, representations, and documentation specified in our Amended and Restated Bylaws, which you may obtain by writing to our corporate secretary. Shareholder proposals should be personally delivered or delivered by registered or certified mail, postage prepaid, to: Corporate Secretary, IDACORP, Inc., 1221 W. Idaho Street, Boise, Idaho 83702.

If a shareholder fails to meet the applicable deadlines or fails to satisfy other requirements of Rule 14a-4 and other applicable requirements of the Securities and Exchange Commission, we may exercise discretionary voting authority over proxies we receive to vote on any such proposal as we determine appropriate.”

Process for Shareholders to Recommend Candidates for Director

The Restated Bylaws do not change the process that a shareholder must follow to recommend director candidates to IDACORP’s Corporate Governance and Nominating Committee, as outlined in IDACORP’s definitive proxy statement, dated April 2, 2014, under the caption “Process for Shareholders to Recommend Candidates for Director.” However, a shareholder who wishes to nominate a candidate for election to the IDACORP Board of Directors, rather than recommend a candidate for nomination, must follow the amended procedures for making such a nomination set forth in the Restated Bylaws, as described above.

ITEM 6. EXHIBITS

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

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SIGNATURES

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



		IDACORP, INC.
		(Registrant)



Date:	October 30, 2014	By:	/s/ Darrel T. Anderson
			Darrel T. Anderson
			President and Chief Executive Officer

Date:	October 30, 2014	By:	/s/ Steven R. Keen
			Steven R. Keen
			Senior Vice President, Chief Financial
			Officer, and Treasurer





		IDAHO POWER COMPANY
		(Registrant)



Date:	October 30, 2014	By:	/s/ Darrel T. Anderson
			Darrel T. Anderson
			President and Chief Executive Officer

Date:	October 30, 2014	By:	/s/ Steven R. Keen
			Steven R. Keen
			Senior Vice President, Chief Financial
			Officer, and Treasurer

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EXHIBIT INDEX

The following exhibits are filed or furnished, as applicable, with the Quarterly Report on Form 10-Q for the quarter ended September 30, 2014:



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

3.15	Amended and Restated Bylaws of IDACORP, Inc., adopted October 29, 2014 and presently in effect					X
3.16	Amended and Restated Bylaws of IDACORP, Inc., adopted October 29, 2014, marked to show amendments effective October 29, 2014					X
10.66	Joint Ownership and Operating Agreement, dated October 24, 2014, between Idaho Power and PacifiCorp (related to certain transmission system assets)	8-K	1-14465; 1-3198	10.1	10/24/2014
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