Form 10-Q IDACORP INC For: Sep 30

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October 29, 2015 8:36 AM EDT

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Table of Contents

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, 2015
	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 23, 2015:

IDACORP, Inc.: 50,340,688

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		32
	Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations			34
	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			62

Signatures				63

Exhibit Index				64

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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
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
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," "continues," "estimates," "expects," "guidance," "intends," "plans," "predicts," "projects," "may result," 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, 2014, 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 and the loss or change in the business of significant customers, and their associated impacts on loads and load growth;


•	the impacts of 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 the collection 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 or sale of electric power;


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


•	variable hydrological conditions and over-appropriation of surface and groundwater in the Snake River Basin, which impact the amount of power generated by Idaho Power's hydroelectric facilities;


•	the ability to purchase fuel, power, and transmission capacity under reasonable terms, 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, and regulatory fines and penalties;


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


•	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;


•	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;


•	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;

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•	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,
	2015			2014			2015			2014
	(thousands of dollars, except for per share amounts)
Operating Revenues:
Electric utility:
General business	$	340,796		$	347,838		$	897,943		$	874,817
Off-system sales	6,487			15,449			23,335			56,390
Other revenues	21,234			17,424			61,334			58,479
Total electric utility revenues	368,517			380,711			982,612			989,686
Other	648			1,490			2,277			3,017
Total operating revenues	369,165			382,201			984,889			992,703
Operating Expenses:
Electric utility:
Purchased power	71,890			75,058			166,191			181,291
Fuel expense	66,385			67,088			144,262			156,859
Power cost adjustment	(11,914		)	(668		)	26,372			23,496
Other operations and maintenance	83,972			84,236			255,329			252,208
Energy efficiency programs	7,645			5,537			19,854			17,881
Depreciation	34,639			33,476			102,996			99,304
Taxes other than income taxes	8,286			8,340			24,999			24,685
Total electric utility expenses	260,903			273,067			740,003			755,724
Other	3,598			3,412			11,340			10,869
Total operating expenses	264,501			276,479			751,343			766,593
Operating Income	104,664			105,722			233,546			226,110
Allowance for Equity Funds Used During Construction	5,654			4,645			16,219			13,182
Earnings of Unconsolidated Equity-Method Investments	5,527			6,414			8,636			8,908
Other Income, Net	1,222			1,193			5,054			4,733
Interest Expense:
Interest on long-term debt	20,614			20,141			62,443			60,423
Other interest	2,256			1,908			6,484			5,714
Allowance for borrowed funds used during construction	(2,593		)	(2,178		)	(7,550		)	(6,287		)
Total interest expense, net	20,277			19,871			61,377			59,850
Income Before Income Taxes	96,790			98,103			202,078			193,083
Income Tax Expense	23,523			10,869			39,276			33,968
Net Income	73,267			87,234			162,802			159,115
Adjustment for loss (income) attributable to noncontrolling interests	69			(345		)	45			(283		)
Net Income Attributable to IDACORP, Inc.	$	73,336		$	86,889		$	162,847		$	158,832
Weighted Average Common Shares Outstanding - Basic (000’s)	50,219			50,129			50,221			50,131
Weighted Average Common Shares Outstanding - Diluted (000’s)	50,324			50,220			50,282			50,184
Earnings Per Share of Common Stock:
Earnings Attributable to IDACORP, Inc. - Basic	$	1.46		$	1.73		$	3.24		$	3.17
Earnings Attributable to IDACORP, Inc. - Diluted	$	1.46		$	1.73		$	3.24		$	3.16
Dividends Declared Per Share of Common Stock	$	0.47		$	0.43		$	1.41		$	1.29

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,
	2015		2014			2015		2014
	(thousands of dollars)

Net Income	$	73,267	$	87,234		$	162,802	$	159,115
Other Comprehensive Income:
Unfunded pension liability adjustment, net of tax of $428, $277, $1,284 and $832	667		432			2,001		1,296
Total Comprehensive Income	73,934		87,666			164,803		160,411
Comprehensive loss (income) attributable to noncontrolling interests	69		(345		)	45		(283		)
Comprehensive Income Attributable to IDACORP, Inc.	$	74,003	$	87,321		$	164,848	$	160,128

The accompanying notes are an integral part of these statements.

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IDACORP, Inc.

Condensed Consolidated Balance Sheets

(unaudited)



	September 30, 2015			December 31, 2014
	(thousands of dollars)
Assets

Current Assets:
Cash and cash equivalents	$	121,260		$	56,808
Receivables:
Customer (net of allowance of $1,079 and $1,960, respectively)	91,936			79,083
Other (net of allowance of $220 and $144, respectively)	8,981			16,018
Taxes receivable	4,825			11,867
Accrued unbilled revenues	55,317			56,270
Materials and supplies (at average cost)	56,164			55,404
Fuel stock (at average cost)	56,124			55,171
Prepayments	18,870			18,476
Deferred income taxes	42,106			42,359
Current regulatory assets	38,326			50,042
Other	410			603
Total current assets	494,319			442,101
Investments	160,127			165,424
Property, Plant and Equipment:
Utility plant in service	5,376,721			5,248,212
Accumulated provision for depreciation	(1,890,374		)	(1,841,011		)
Utility plant in service - net	3,486,347			3,407,201
Construction work in progress	468,083			401,930
Utility plant held for future use	7,090			7,090
Other property, net of accumulated depreciation	16,965			17,256
Property, plant and equipment - net	3,978,485			3,833,477
Other Assets:
American Falls and Milner water rights	11,853			13,698
Company-owned life insurance	21,257			23,893
Regulatory assets	1,194,645			1,192,345
Long-term receivables (net of allowance of $552)	20,554			6,317
Other	56,746			39,598
Total other assets	1,305,055			1,275,851
Total	$	5,937,986		$	5,716,853

The accompanying notes are an integral part of these statements.

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IDACORP, Inc.

Condensed Consolidated Balance Sheets

(unaudited)



	September 30, 2015			December 31, 2014
	(thousands of dollars)
Liabilities and Equity

Current Liabilities:
Current maturities of long-term debt	$	1,064		$	1,064
Notes payable	3,600			31,300
Accounts payable	81,047			97,271
Taxes accrued	21,567			10,367
Interest accrued	24,073			22,630
Accrued compensation	38,463			43,774
Current regulatory liabilities	5,743			11,400
Other	29,775			23,975
Total current liabilities	205,332			241,781
Other Liabilities:
Deferred income taxes	1,092,372			1,065,290
Regulatory liabilities	409,277			390,207
Pension and other postretirement benefits	385,886			403,334
Other	49,111			44,238
Total other liabilities	1,936,646			1,903,069
Long-Term Debt	1,741,875			1,614,438
Commitments and Contingencies
Equity:
IDACORP, Inc. shareholders’ equity:
Common stock, no par value (shares authorized 120,000,000; 50,352,051 and 50,308,702 shares issued, respectively)	848,003			845,402
Retained earnings	1,224,025			1,132,237
Accumulated other comprehensive loss	(22,157		)	(24,158		)
Treasury stock (11,363 and 38,764 shares at cost, respectively)	(57		)	(280		)
Total IDACORP, Inc. shareholders’ equity	2,049,814			1,953,201
Noncontrolling interests	4,319			4,364
Total equity	2,054,133			1,957,565
Total	$	5,937,986		$	5,716,853

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,
	2015			2014
	(thousands of dollars)
Operating Activities:
Net income	$	162,802		$	159,115
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	106,304			102,366
Deferred income taxes and investment tax credits	25,265			25,355
Changes in regulatory assets and liabilities	25,776			36,595
Pension and postretirement benefit plan expense	22,668			20,927
Contributions to pension and postretirement benefit plans	(41,660		)	(32,533		)
Earnings of unconsolidated equity-method investments	(8,636		)	(8,908		)
Distributions from unconsolidated equity-method investments	9,352			5,820
Allowance for equity funds used during construction	(16,219		)	(13,182		)
Other non-cash adjustments to net income, net	1,444			4,417
Change in:
Accounts receivable	(14,704		)	4,372
Accounts payable and other accrued liabilities	(12,210		)	(3,359		)
Taxes accrued/receivable	19,845			14,066
Other current assets	(178		)	2,089
Other current liabilities	7,874			7,258
Other assets	2,468			(2,970		)
Other liabilities	629			(5,601		)
Net cash provided by operating activities	290,820			315,827
Investing Activities:
Additions to property, plant and equipment	(235,890		)	(200,928		)
Proceeds from the sale of emission allowances and RECs	1,855			2,923
Distributions from affordable housing investments	240			1,048
Other	883			4,335
Net cash used in investing activities	(232,912		)	(192,622		)
Financing Activities:
Issuance of long-term debt	250,000			—
Retirement of long-term debt	(121,064		)	(1,064		)
Dividends on common stock	(71,225		)	(64,958		)
Net change in short-term borrowings	(27,700		)	(22,950		)
Issuance of common stock	—			160
Acquisition of treasury stock	(3,277		)	(2,737		)
Make-whole premium on retirement of long-term debt	(17,872		)	—
Other	(2,318		)	1,220
Net cash provided by (used in) financing activities	6,544			(90,329		)
Net increase in cash and cash equivalents	64,452			32,876
Cash and cash equivalents at beginning of the period	56,808			78,162
Cash and cash equivalents at end of the period	$	121,260		$	111,038
Supplemental Disclosure of Cash Flow Information:
Cash paid during the period for:
Income taxes	$	4,442		$	4,686
Interest (net of amount capitalized)	$	57,630		$	55,743
Non-cash investing activities:
Additions to property, plant and equipment in accounts payable	$	12,606		$	19,375

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,
	2015			2014
	(thousands of dollars)
Common Stock
Balance at beginning of period	$	845,402		$	839,750
Issued	—			160
Other	2,601			3,253
Balance at end of period	848,003			843,163
Retained Earnings
Balance at beginning of period	1,132,237			1,027,461
Net income attributable to IDACORP, Inc.	162,847			158,832
Common stock dividends ($1.41 and $1.29 per share)	(71,059		)	(64,903		)
Balance at end of period	1,224,025			1,121,390
Accumulated Other Comprehensive (Loss) Income
Balance at beginning of period	(24,158		)	(16,553		)
Unfunded pension liability adjustment (net of tax)	2,001			1,296
Balance at end of period	(22,157		)	(15,257		)
Treasury Stock
Balance at beginning of period	(280		)	(8		)
Issued	3,500			2,465
Acquired	(3,277		)	(2,737		)
Balance at end of period	(57		)	(280		)
Total IDACORP, Inc. shareholders’ equity at end of period	2,049,814			1,949,016
Noncontrolling Interests
Balance at beginning of period	4,364			4,090
Net (loss) income attributable to noncontrolling interests	(45		)	283
Balance at end of period	4,319			4,373
Total equity at end of period	$	2,054,133		$	1,953,389

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,
	2015			2014			2015			2014
	(thousands of dollars)
Operating Revenues:
General business	$	340,796		$	347,838		$	897,943		$	874,817
Off-system sales	6,487			15,449			23,335			56,390
Other revenues	21,234			17,424			61,334			58,479
Total operating revenues	368,517			380,711			982,612			989,686
Operating Expenses:
Operation:
Purchased power	71,890			75,058			166,191			181,291
Fuel expense	66,385			67,088			144,262			156,859
Power cost adjustment	(11,914		)	(668		)	26,372			23,496
Other operations and maintenance	83,972			84,236			255,329			252,208
Energy efficiency programs	7,645			5,537			19,854			17,881
Depreciation	34,639			33,476			102,996			99,304
Taxes other than income taxes	8,286			8,340			24,999			24,685
Total operating expenses	260,903			273,067			740,003			755,724
Income from Operations	107,614			107,644			242,609			233,962
Other Income (Expense):
Allowance for equity funds used during construction	5,654			4,645			16,219			13,182
Earnings of unconsolidated equity-method investments	4,334			5,180			6,992			7,148
Other expense, net	(1,755		)	(1,538		)	(4,216		)	(3,556		)
Total other income	8,233			8,287			18,995			16,774
Interest Charges:
Interest on long-term debt	20,614			20,141			62,443			60,423
Other interest	2,204			1,859			6,311			5,547
Allowance for borrowed funds used during construction	(2,593		)	(2,178		)	(7,550		)	(6,287		)
Total interest charges	20,225			19,822			61,204			59,683
Income Before Income Taxes	95,622			96,109			200,400			191,053
Income Tax Expense	23,895			11,509			40,872			35,899
Net Income	$	71,727		$	84,600		$	159,528		$	155,154

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,
	2015		2014		2015		2014
	(thousands of dollars)

Net Income	$	71,727	$	84,600	$	159,528	$	155,154
Other Comprehensive Income:
Unfunded pension liability adjustment, net of tax of $428, $277, $1,284 and $832	667		432		2,001		1,296
Total Comprehensive Income	$	72,394	$	85,032	$	161,529	$	156,450

The accompanying notes are an integral part of these statements.

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Idaho Power Company

Condensed Consolidated Balance Sheets

(unaudited)



	September 30, 2015			December 31, 2014
	(thousands of dollars)
Assets

Electric Plant:
In service (at original cost)	$	5,376,721		$	5,248,212
Accumulated provision for depreciation	(1,890,374		)	(1,841,011		)
In service - net	3,486,347			3,407,201
Construction work in progress	468,083			401,930
Held for future use	7,090			7,090
Electric plant - net	3,961,520			3,816,221
Investments and Other Property	138,853			142,825
Current Assets:
Cash and cash equivalents	110,099			46,695
Receivables:
Customer (net of allowance of $1,079 and $1,960, respectively)	91,936			79,083
Other (net of allowance of $220 and $144, respectively)	8,873			15,890
Taxes receivable	5,617			20,428
Accrued unbilled revenues	55,317			56,270
Materials and supplies (at average cost)	56,164			55,404
Fuel stock (at average cost)	56,124			55,171
Prepayments	18,760			18,356
Current regulatory assets	38,326			50,042
Other	410			603
Total current assets	441,626			397,942
Deferred Debits:
American Falls and Milner water rights	11,853			13,698
Company-owned life insurance	21,257			23,893
Regulatory assets	1,194,645			1,192,345
Other	71,252			39,753
Total deferred debits	1,299,007			1,269,689
Total	$	5,841,006		$	5,626,677

The accompanying notes are an integral part of these statements.

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Idaho Power Company

Condensed Consolidated Balance Sheets

(unaudited)



	September 30, 2015			December 31, 2014
	(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	1,121,663			1,033,350
Accumulated other comprehensive loss	(22,157		)	(24,158		)
Total common stock equity	1,907,544			1,817,230
Long-term debt	1,741,875			1,614,438
Total capitalization	3,649,419			3,431,668
Current Liabilities:
Current maturities of long-term debt	1,064			1,064
Accounts payable	80,523			96,499
Accounts payable to affiliates	1,143			2,027
Taxes accrued	21,703			10,329
Interest accrued	24,073			22,630
Accrued compensation	38,344			43,410
Current regulatory liabilities	5,743			11,400
Other	34,868			29,476
Total current liabilities	207,461			216,835
Deferred Credits:
Deferred income taxes	1,141,044			1,141,755
Regulatory liabilities	409,277			390,207
Pension and other postretirement benefits	385,886			403,334
Other	47,919			42,878
Total deferred credits	1,984,126			1,978,174

Commitments and Contingencies

Total	$	5,841,006		$	5,626,677

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,
	2015			2014
	(thousands of dollars)
Operating Activities:
Net income	$	159,528		$	155,154
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	105,848			101,925
Deferred income taxes and investment tax credits	(5,307		)	14,087
Changes in regulatory assets and liabilities	25,776			36,595
Pension and postretirement benefit plan expense	22,646			20,903
Contributions to pension and postretirement benefit plans	(41,638		)	(32,509		)
Earnings of unconsolidated equity-method investments	(6,992		)	(7,148		)
Distributions from unconsolidated equity-method investments	8,502			4,970
Allowance for equity funds used during construction	(16,219		)	(13,182		)
Other non-cash adjustments to net income, net	(969		)	1,188
Change in:
Accounts receivable	(17,363		)	3,818
Accounts payable	(11,967		)	(3,336		)
Taxes accrued/receivable	27,942			12,160
Other current assets	(189		)	2,069
Other current liabilities	7,917			7,288
Other assets	2,468			(2,970		)
Other liabilities	800			(5,106		)
Net cash provided by operating activities	260,783			295,906
Investing Activities:
Additions to utility plant	(235,841		)	(200,778		)
Proceeds from the sale of emission allowances and RECs	1,855			2,923
Other	883			4,335
Net cash used in investing activities	(233,103		)	(193,520		)
Financing Activities:
Issuance of long-term debt	250,000			—
Retirement of long-term debt	(121,064		)	(1,064		)
Dividends on common stock	(71,215		)	(64,957		)
Make-whole premium on retirement of long-term debt	(17,872		)	—
Other	(4,125		)	—
Net cash provided by (used in) financing activities	35,724			(66,021		)
Net increase in cash and cash equivalents	63,404			36,365
Cash and cash equivalents at beginning of the period	46,695			66,535
Cash and cash equivalents at end of the period	$	110,099		$	102,900
Supplemental Disclosure of Cash Flow Information:
Cash paid during the period for:
Income taxes	$	28,336		$	19,793
Interest (net of amount capitalized)	$	57,457		$	55,576
Non-cash investing activities:
Additions to property, plant and equipment in accounts payable	$	12,606		$	19,375

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 state utility regulatory commissions of Idaho and Oregon and the Federal Energy Regulatory Commission (FERC). 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, 2015, consolidated results of operations for the three and nine months ended September 30, 2015 and 2014, and consolidated cash flows for the nine months ended September 30, 2015 and 2014. 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, 2014. The results of operations for the interim period are not necessarily indicative of the results to be expected for the full year. A change in management's estimates or assumptions could have a material impact on IDACORP's or Idaho Power's respective financial condition and results of operations during the period in which such change occurred.

Management Estimates

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

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Asset Retirement Obligations

In December 2014, the U.S. Environmental Protection Agency signed a final rule relating to the disposal of coal combustion residuals, which was published in the Federal Register on April 17, 2015. The rule adds several regulations relating to the disposal and ongoing monitoring of coal combustion residuals. Idaho Power jointly owns three coal-fired power plants that are subject to the new regulations. Together with its co-owners, Idaho Power performed engineering and cost studies to determine the financial and operational impacts of the new rule. Based on these studies, which incorporated revised assumptions about the remaining lives and operations of existing coal-combustion residual facilities, Idaho Power recorded an increase of $5 million to its asset retirement obligations and an associated $7 million increase to ARO assets and $2 million decrease to regulatory assets in the second quarter of 2015.

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 pretax 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
	2015			2014			2015			2014
Income tax at statutory rates (federal and state)	$	79,030		$	75,385		$	78,356		$	74,702
First mortgage bond redemption costs	(7,210		)	—			(7,210		)	—
Accounting method change	—			(11,075		)	—			(11,075		)
Affordable housing tax credits	(2,628		)	(3,792		)	—			—
Affordable housing investment amortization, net of statutory taxes	1,025			2,041			—			—
Other⁽¹⁾	(30,941		)	(28,591		)	(30,274		)	(27,728		)
Income tax expense	$	39,276		$	33,968		$	40,872		$	35,899
Effective tax rate	19.4		%	17.6		%	20.4		%	18.8		%

⁽¹⁾ "Other" is primarily comprised of the net tax effect of Idaho Power's regulatory flow-through tax adjustments. These adjustments, which include the capitalized repairs deduction, 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, 2014.

The increase in income tax expense for the nine months ended September 30, 2015, as compared with the same period in 2014, was primarily due to greater Idaho Power pre-tax earnings in 2015 and lower flow-through income tax benefits from discrete items. In the second quarter of 2015, Idaho Power recorded a $7.2 million income tax benefit for bond redemption costs, as compared with an $11.1 million income tax benefit recorded in the third quarter of 2014 for an income tax accounting method change related to Idaho Power's capitalized repairs deduction for generation, transmission, and distribution assets. On a net basis, Idaho Power’s estimate of its annual 2015 regulatory flow-through tax adjustments is comparable to 2014.

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3. REGULATORY MATTERS

Included below is a summary of Idaho Power's most recent general rate cases and base 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.

On March 21, 2014, the IPUC issued an order approving Idaho Power's application 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 determination of the PCA rate that became effective June 1, 2014. Approval of the order removed the Idaho-jurisdictional portion of those expenses (approximately $99 million) from collection via the Idaho PCA mechanism and instead results in collecting that portion through base rates.

Idaho Settlement Stipulation — Investment Tax Credits and Sharing Mechanism

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


•	If Idaho Power's annual return on year-end equity in the Idaho jurisdiction (Idaho ROE) in any year is less than 9.5 percent, then Idaho Power may amortize up to $25 million of additional accumulated deferred investment tax credits (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 over the 2015 through 2019 period.


•	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 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.

Idaho Power recorded no additional ADITC amortization or provision for sharing with customers during the first nine months of 2015 based on its estimate of Idaho ROE for the full-year 2015. Accordingly, the full $45 million of additional ADITC remains available for future use under the terms of the settlement stipulation.

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Idaho Power Cost Adjustment Mechanism Annual Filing

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 for future recovery or refund through retail rates. The power supply costs deferred primarily result from changes in contracted power purchase prices and volumes, changes in wholesale market prices and transaction volumes, fuel prices, and the levels of Idaho Power's own generation.

On May 28, 2015, the IPUC issued an order approving an $11.6 million net decrease in Idaho PCA rates, effective for the 2015-2016 PCA collection period from June 1, 2015 to May 31, 2016. The net decrease in Idaho PCA rates included the application of (a) a customer rate credit of $8.0 million for sharing of revenues with customers for the year 2014 under the terms of the December 2011 settlement stipulation, (b) a $1.5 million customer benefit relating to a change to the PCA methodology described below, and (c) $4.0 million of surplus Idaho energy efficiency rider funds.

Previously, on May 30, 2014, the IPUC issued an order approving 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 (a) $20.0 million of surplus Idaho energy efficiency rider funds, (b) $7.6 million of customer revenue sharing for the year 2013 under the December 2011 settlement stipulation, and (c) the shifting of $99.3 million in power supply expense from collection via the PCA mechanism to collection via base rates.

Idaho Fixed Cost Adjustment Mechanism Annual 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 rate 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 energy sales. On May 19, 2015, the IPUC issued an order approving an increase of $2.0 million in the FCA from $14.9 million to $16.9 million, with new rates effective for the period from June 1, 2015 through May 31, 2016. Previously, on May 30, 2014, the IPUC issued an order approving a $6.0 million increase in the FCA from $8.9 million to $14.9 million, effective for the period from June 1, 2014 through May 31, 2015.

IPUC Review of Annual Rate Adjustment Mechanisms

PCA Mechanism -- In July 2014, the IPUC opened a docket pursuant to which Idaho Power, the IPUC Staff, and other interested parties further evaluated Idaho Power's application of the true-up component of the PCA mechanism and whether a deferral balance adjustment was appropriate. While the IPUC's docket was closed in August 2014 with no adjustment to the PCA true-up revenue amount, Idaho Power subsequently met with the IPUC Staff to explore approaches to increasing the accuracy of the actual cost recovery under the PCA mechanism. On May 28, 2015, the IPUC approved a settlement stipulation that resulted in the replacement of the existing load-based adjustment used for determining the power cost deferrals under the PCA mechanism with a similar sales-based adjustment. The sales-based adjustment functions in the same manner as the existing load-based adjustment, but measures deviations between Idaho-specific test year sales and actual Idaho sales rather than deviations between test year loads and actual loads. The approved settlement stipulation provided that implementation of the new methodology was effective as of January 1, 2015.

FCA Mechanism -- Also in July 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. On May 6, 2015, the IPUC approved a settlement stipulation that modified the FCA mechanism by replacing weather-normalized billed sales with actual billed sales in the calculation of the FCA, applicable for the entirety of calendar year 2015 and thereafter, and reflected in FCA rates effective June 1, 2016.

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4. LONG-TERM DEBT

On March 6, 2015, Idaho Power issued $250 million in principal amount of 3.65% first mortgage bonds, secured medium-term notes, Series J, maturing on March 1, 2045. On April 23, 2015, Idaho Power redeemed, prior to maturity, $120 million in principal amount of 6.025% first mortgage bonds, medium-term notes, Series H due July 2018. In accordance with the redemption provisions of the notes, the redemption included Idaho Power's payment of a make-whole premium to the holders of the redeemed notes in the aggregate amount of approximately $17.9 million. Idaho Power used a portion of the net proceeds from the March 2015 sale of first mortgage bonds, medium-term notes to effect the redemption.

As of September 30, 2015, $250 million in principal amount of long-term debt securities remained available for issuance under a selling agency agreement executed in July 2013 and pursuant to state regulatory authority. On April 1, 2015 the IPUC approved a two-year extension of Idaho Power's state regulatory authorization to issue debt securities and first mortgage bonds, through April 9, 2017.

5. NOTES PAYABLE

Credit Facilities

IDACORP and Idaho Power have in place credit facilities that may be used for general corporate purposes and commercial paper backup. The terms and conditions of those credit facilities are as described in IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2014.

At September 30, 2015, no loans were outstanding under either IDACORP's or Idaho Power's facilities. At September 30, 2015, 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, 2015 and December 31, 2014:



	September 30, 2015									December 31, 2014
	Idaho Power			IDACORP			Total			Idaho Power			IDACORP			Total
Commercial paper outstanding	$	—		$	3,600		$	3,600		$	—		$	31,300		$	31,300
Weighted-average annual interest rate	—		%	0.56		%	0.56		%	—		%	0.43		%	0.43		%

6. COMMON STOCK

IDACORP Common Stock

During the nine months ended September 30, 2015, IDACORP issued 43,349 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, 2015, the

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leverage ratios for IDACORP and Idaho Power were 46 percent and 48 percent, respectively. Based on these restrictions, IDACORP’s and Idaho Power’s dividends were limited to $1.1 billion and $965 million, respectively, at September 30, 2015. 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 applicable company from any material subsidiary. At September 30, 2015, 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, 2015, Idaho Power's common equity capital was 52 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.

7. EARNINGS PER SHARE

The table below presents the computation of IDACORP’s basic and diluted earnings per share for the three and nine months ended September 30, 2015 and 2014 (in thousands, except for per share amounts).



	Three months ended September 30,				Nine months ended September 30,
	2015		2014		2015		2014
Numerator:
Net income attributable to IDACORP, Inc.	$	73,336	$	86,889	$	162,847	$	158,832
Denominator:
Weighted-average common shares outstanding - basic	50,219		50,129		50,221		50,131
Effect of dilutive securities	105		91		61		53
Weighted-average common shares outstanding - diluted	50,324		50,220		50,282		50,184
Basic earnings per share	$	1.46	$	1.73	$	3.24	$	3.17
Diluted earnings per share	$	1.46	$	1.73	$	3.24	$	3.16

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8. COMMITMENTS

Purchase Obligations

IDACORP's and Idaho Power's purchase obligations did not change materially, outside of the ordinary course of business, during the nine months ended September 30, 2015, except as follows:


•	four power purchase agreements with a solar energy developer were terminated due to an uncured breach by the counterparty. Termination of the agreements reduced Idaho Power's contractual payment obligations by approximately $483 million over the 20-year lives of the terminated contracts;


•	the addition of seven power purchase agreements with solar and other alternative energy developers for projects with a combined nameplate capacity of approximately 45 MW. Payments pursuant to these new agreements are estimated to total $135 million from 2017 through 2036; and

•

Idaho Power entered into a long-term service agreement, conditioned upon the IPUC's approval of the agreement and acceptable accounting treatment, for maintenance services at three of Idaho Power's natural gas plants, with a total estimated obligation of $72 million over the term of the agreement. Idaho Power received IPUC approval of the agreement on October 5, 2015. However, Idaho Power reviewed and considered the implications of the IPUC's order, including the accounting treatment described in the order, and has requested reconsideration of certain aspects of the accounting treatment included in the IPUC's order. Accordingly, as of the date of this report the agreement has not become effective.

Guarantees

Through a self-bonding mechanism, Idaho Power guarantees its portion 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 $73 million at September 30, 2015, 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, 2015, the value of the reclamation trust fund was $69 million. During the nine months ended September 30, 2015, the reclamation trust fund distributed approximately $1 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, 2015, 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.

9. CONTINGENCIES

IDACORP and Idaho Power have in the past and expect in the future to become involved in various claims, controversies, disputes, and other contingent matters, including the items described in this Note 9. Some of these claims, controversies, disputes, and other contingent matters involve litigation and regulatory or other contested proceedings. The ultimate resolution and outcome of litigation and regulatory proceedings is inherently difficult to determine, particularly where (a) the remedies or penalties sought are indeterminate, (b) the proceedings are in the early stages or the substantive issues have not been well developed, or (c) the matters involve complex or novel legal theories or a large number of parties. In accordance with applicable accounting guidance, IDACORP and Idaho Power, as applicable, establish an accrual for legal proceedings when those matters proceed to a stage where they present loss contingencies that are both probable and reasonably estimable. In such cases, there may be a possible exposure to loss in excess of any amounts accrued. IDACORP and Idaho Power monitor those matters for developments that could affect the likelihood of a loss and the accrued amount, if any, and adjust the amount as appropriate. If the loss contingency at issue is not both probable and reasonably estimable, IDACORP and Idaho Power do not

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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 in the Pacific Northwest markets 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."

Despite the speculative nature of ripple claims, the FERC has refused to dismiss Idaho Power and IESCo from the proceedings in the Pacific Northwest and refused to approve portions of two settlements that provided for waivers of claims in those proceedings, notwithstanding only limited objections from two market participants to one of the two settlements and no objections to the other settlement. Idaho Power and IESCo filed petitions for review of the FERC's decisions refusing to approve the waiver provision of the settlements, on the basis that the FERC failed to apply its established precedents and rules. In September 2015, the Ninth Circuit Court of Appeals held that the FERC departed from its rules and precedent without explanation, and directed the FERC to reconsider its decision on the settlement petitions and issue a decision within sixty days of the issuance of the court's mandate.

Idaho Power and IESCo cannot predict whether the FERC will approve in full the settlements under reconsideration. If the FERC does not approve in full the settlements, Idaho Power and IESCo cannot predict whether the FERC will ultimately order that any refunds be made, which contracts would be subject to refunds, how the refund amount would be calculated, which refunds would trigger ripple claims, if any, and whether any party would seek to pursue ripple claims. Based on these uncertainties and Idaho Power's and IESCo's evaluation of the merits of ripple claims, 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 are unable to estimate the possible loss or range of loss that could result from the proceedings and have no amount accrued relating to the proceedings. To the extent the availability of any ripple claims materializes, Idaho Power and IESCo will continue to vigorously defend their positions in the proceedings.

Hoku Corporation Bankruptcy Claims

On June 26, 2015, the trustee in the Hoku Corporation chapter 7 bankruptcy case (In Re: Hoku Corporation, United States Bankruptcy Court, District of Idaho, Case No. 13-40838 JDP) filed a complaint against Idaho Power, alleging that specified payments made by Hoku Corporation to Idaho Power in the six years prior to Hoku Corporation's bankruptcy filing in July 2013 should be recoverable by the trustee as constructive fraudulent transfers. Hoku Corporation was the parent entity of Hoku Materials, Inc., with which Idaho Power had an electric service agreement approved by the IPUC in March 2009. Under the electric service agreement, Idaho Power agreed to provide electric service to a polysilicon production facility under construction by Hoku Materials in the state of Idaho. Idaho Power also had agreements with Hoku Materials pertaining to the design and construction of apparatus for the provision of electric service to the polysilicon plant. The trustee's complaint against Idaho Power includes alternative causes of action for constructive fraudulent transfer under the federal bankruptcy code, Idaho law, and federal law, with requests for recovery from Idaho Power in amounts up to approximately $36 million. The complaint alleges that the payments made by Hoku Corporation to Idaho Power are subject to recovery by the trustee on the basis that Hoku Corporation was insolvent at the time of the payments and did not have any legal or equitable title in the polysilicon plant or liability for Hoku Materials' debts, and thus did not receive reasonably equivalent value for the payments it made for or on behalf of Hoku Materials.

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As of the date of this report it is not possible to determine Idaho Power's potential liability, if any, or to reasonably estimate a possible loss or range of possible loss, if any, within the trustee's alternative prayers for relief. Idaho Power intends to vigorously defend against the claims.

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, record an accrual for associated loss contingencies when they are probable and reasonably estimable. As of the date of this report the companies believe that resolution of those matters will not have a material adverse effect on their respective consolidated financial statements. Idaho Power is also actively monitoring various pending environmental regulations that may have a significant impact on its future operations. Given uncertainties regarding the outcome, timing, and compliance plans for these environmental matters, Idaho Power is unable to estimate the financial impact of these regulations. However, Idaho Power does believe that future capital investment for infrastructure and modifications to its electric generating facilities could be significant to comply with these regulations.

10. 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 their spouses and qualifying dependents. The following table shows the components of net periodic benefit costs for the pension, SMSP, and postretirement benefits plans for the three months ended September 30, 2015 and 2014 (in thousands of dollars).



	Pension Plan						SMSP				Postretirement Benefits
	2015			2014			2015		2014		2015			2014
Service cost	$	8,291		$	6,323		$	422	$	411	$	308		$	252
Interest cost	8,792			8,853			967		964		670			711
Expected return on plan assets	(10,994		)	(10,561		)	—		—		(669		)	(648		)
Amortization of prior service cost	56			86			47		55		3			45
Amortization of net loss	3,482			978			1,048		654		—			—
Net periodic benefit cost	9,627			5,679			2,484		2,084		312			360
Adjustments due to the effects of regulation⁽¹⁾	(4,902		)	(1,140		)	—		—		—			—
Net periodic benefit cost recognized for financial reporting⁽¹⁾	$	4,725		$	4,539		$	2,484	$	2,084	$	312		$	360

⁽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, 2015 and 2014 (in thousands of dollars).



	Pension Plan						SMSP				Postretirement Benefits
	2015			2014			2015		2014		2015			2014
Service cost	$	24,873		$	18,969		$	1,267	$	1,234	$	926		$	758
Interest cost	26,378			26,561			2,901		2,892		2,009			2,131
Expected return on plan assets	(31,733		)	(31,717		)	—		—		(2,010		)	(1,946		)
Amortization of prior service cost	166			260			139		165		11			137
Amortization of net loss	10,446			2,933			3,146		1,963		—			—
Net periodic benefit cost	30,130			17,006			7,453		6,254		936			1,080
Adjustments due to the effects of regulation⁽¹⁾	(15,873		)	(3,437		)	—		—		—			—
Net periodic benefit cost recognized for financial reporting⁽¹⁾	$	14,257		$	13,569		$	7,453	$	6,254	$	936		$	1,080

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During the nine months ended September 30, 2015, Idaho Power made $39 million in contributions to its defined benefit pension plan.

In October 2014, the Society of Actuaries released a new set of mortality tables referred to as RP-2014. Mortality tables are used by defined benefit plans to estimate the life expectancy of plan participants and the expected length of benefit payments in retirement. RP-2014 generally resulted in longer life expectancy than previous mortality tables. Idaho Power's measurement of its plan benefit obligations as of December 31, 2014, and its net periodic benefit cost for the nine months ended September 30, 2015, reflect the adoption of the new tables, which was not material.

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.

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 that follows.

The table below presents the gains and losses on derivatives not designated as hedging instruments for the three and nine months ended September 30, 2015 and 2014 (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,
		2015			2014			2015			2014
Financial swaps	Off-system sales	$	472		$	517		$	2,627		$	(6,026	)
Financial swaps	Purchased power	992			(2,265		)	1,098			(785		)
Financial swaps	Fuel expense	(3,774		)	239			(4,152		)	3,907
Financial swaps	Other operations and maintenance	(15		)	(34		)	(21		)	(44		)
Forward contracts	Off-system sales	—			112			—			164
Forward contracts	Purchased power	—			(113		)	3			(163		)
Forward contracts	Fuel expense	51			53			56			101

⁽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, 2015 and December 31, 2014 (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, 2015
Current:
Financial swaps	Other current assets	$	626	$	(289	)		$	337	$	289	$	(289	)	$	—
Financial swaps	Other current liabilities	193		(193		)		—		3,693		(193		)	3,500
Forward contracts	Other current assets	64		—				64		—		—			—
Long-term:
Financial swaps	Other assets	32		(19		)		13		19		(19		)	—
Financial swaps	Other liabilities	—		—				—		178		—			178
Total		$	915	$	(501	)		$	414	$	4,179	$	(501	)	$	3,678
December 31, 2014
Current:
Financial swaps	Other current assets	$	2,509	$	(2,002	)	⁽¹⁾	$	507	$	756	$	(756	)	$	—
Financial swaps	Other current liabilities	379		(379		)		—		4,335		(379		)	3,956
Forward contracts	Other current assets	64		—				64		—		—			—
Forward contracts	Other current liabilities	—		—				—		5		—			5
Long-term:
Forward contracts	Other assets	63		—				63		—		—			—
Total		$	3,015	$	(2,381	)		$	634	$	5,096	$	(1,135	)	$	3,961

⁽¹⁾Current asset derivative amounts offset include $1.2 million of collateral payable for the period ending December 31, 2014.

The table below presents the volumes of derivative commodity forward contracts and swaps outstanding at September 30, 2015 and 2014 (in thousands of units).



		September 30,
Commodity	Units	2015	2014
Electricity purchases	MWh	350	227
Electricity sales	MWh	160	391
Natural gas purchases	MMBtu	14,570	5,455
Natural gas sales	MMBtu	944	1,137
Diesel purchases	Gallons	61	222

Credit Risk

At September 30, 2015, 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, 2015, was $4.2 million. Idaho Power posted $0.8 million cash collateral related to this amount. If the credit-risk-related contingent features underlying these agreements were triggered on September 30, 2015, Idaho Power would have been required to post an additional $8.3 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 nine months ended September 30, 2015.

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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, 2015 and December 31, 2014 (in thousands of dollars).



	September 30, 2015								December 31, 2014
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets:
Derivatives	$	350	$	64	$	—	$	414	$	506	$	128	$	—	$	634
Money market funds	15,092		—		—		15,092		100		—		—		100
Trading securities: Equity securities	102		—		—		102		141		—		—		141
Available-for-sale securities: Equity securities	42,496		—		—		42,496		44,942		—		—		44,942
Liabilities:
Derivatives	24		3,654		—		3,678		17		3,944		—		3,961

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, are held in a Rabbi Trust, and are actively traded money market and exchange traded 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, 2015 and December 31, 2014, using available market information and appropriate valuation methodologies (in thousands of dollars).



	September 30, 2015				December 31, 2014
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
IDACORP
Assets:
Notes receivable⁽¹⁾	$	3,804	$	3,804	$	3,804	$	3,804
Liabilities:
Long-term debt⁽¹⁾	1,742,939		1,837,372		1,615,502		1,788,197
Idaho Power
Liabilities:
Long-term debt⁽¹⁾	1,742,939		1,837,372		1,615,502		1,788,197

⁽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, 2015:
Revenues	$	368,517	$	648	$	—		$	369,165
Net income attributable to IDACORP, Inc.	71,727		1,609		—			73,336
Total assets as of September 30, 2015	5,835,296		125,019		(22,329		)	5,937,986
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
Nine months ended September 30, 2015:
Revenues	$	982,612	$	2,277	$	—		$	984,889
Net income attributable to IDACORP, Inc.	159,528		3,319		—			162,847
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

14. CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME

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, 2015 and 2014 (in thousands of dollars). Items in parentheses indicate charges to AOCI.



	Defined Benefit Pension Items
Three months ended September 30, 2015:
Balance at beginning of period	$	(22,824	)
Amounts reclassified out of AOCI	667
Balance at end of period	$	(22,157	)
Nine months ended September 30, 2015:
Balance at beginning of period	$	(24,158	)
Amounts reclassified out of AOCI	2,001
Balance at end of period	$	(22,157	)
Three months ended September 30, 2014:
Balance at beginning of period	$	(15,689	)
Amounts reclassified out of AOCI	432
Balance at end of period	$	(15,257	)
Nine months ended September 30, 2014:
Balance at beginning of period	$	(16,553	)
Amounts reclassified out of AOCI	1,296
Balance at end of period	$	(15,257	)

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The table below presents amounts reclassified out of components of AOCI and the income statement location of those amounts reclassified during the three and nine months ended September 30, 2015 and 2014 (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,
	2015			2014			2015			2014
Amortization of defined benefit pension items⁽¹⁾
Prior service cost	$	47		$	55		$	139		$	165
Net loss	1,048			654			3,146			1,963
Total before tax	1,095			709			3,285			2,128
Tax benefit⁽²⁾	(428		)	(277		)	(1,284		)	(832		)
Net of tax	667			432			2,001			1,296
Total reclassification for the period	$	667		$	432		$	2,001		$	1,296

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

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

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

IDACORP, Inc.

Boise, Idaho

We have reviewed the accompanying condensed consolidated balance sheet of IDACORP, Inc. and subsidiaries (the “Company”) as of September 30, 2015, and the related condensed consolidated statements of income and comprehensive income for the three-month and nine-month periods ended September 30, 2015 and 2014, and of equity and cash flows for the nine-month periods ended September 30, 2015 and 2014. 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, 2014, 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 19, 2015, 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, 2014 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 29, 2015

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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, 2015, and the related condensed consolidated statements of income and comprehensive income for the three-month and nine-month periods ended September 30, 2015 and 2014, and of cash flows for the nine-month periods ended September 30, 2015 and 2014. 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, 2014, 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 19, 2015, 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, 2014 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 29, 2015

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

AND RESULTS OF OPERATIONS

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

INTRODUCTION

In Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A), the general financial condition and results of operations for IDACORP, Inc. and its subsidiaries (collectively, IDACORP) and Idaho Power Company and its subsidiary (collectively, Idaho Power) are discussed. While reading the MD&A, please refer to the accompanying condensed consolidated financial statements of IDACORP and Idaho Power, and the notes thereto. This discussion updates the MD&A included in the Annual Report on Form 10-K for the year ended December 31, 2014, 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 area covering approximately 24,000 square miles in southern Idaho and eastern Oregon. Idaho Power provided electric service to approximately 523,000 general business customers as of September 30, 2015. 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, tariff riders, 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 areas, 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 a 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 Company Initiatives

In the Annual Report on Form 10-K for the year ended December 31, 2014, IDACORP's and Idaho Power's management included a brief overview of their outlook and initiatives for the companies for 2015 and beyond, under the headings "Executive Overview - Management's Outlook" and "2014 Accomplishments and 2015 Initiatives" in the MD&A. As of the date of this report, management's outlook remains consistent with that discussion. 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 2015, Idaho Power's customer count grew by 6,987 customers, and for the twelve months ended September 30, 2015, the customer growth rate was 1.8 percent.


•	Idaho Power expects substantial capital investments, with estimated total capital expenditures of $1.5 billion over the five-year period from 2015 (including expenditures to date in 2015) through 2019.


•	Idaho Power continues to actively manage costs, targeting opportunities to optimize business practices.

•

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 periodically assesses the potential for changes in the dividend amount. Most recently, in September 2015, IDACORP's board of directors approved an 8.5 percent increase in the quarterly dividend from $0.47 per share to $0.51 per share, commencing with the dividend payable in the fourth quarter of 2015.


•	Idaho Power continues to focus on timely recovery of costs and earning a reasonable return on investment, including working to evaluate and ensure that its rate design and regulatory mechanisms properly reflect the cost to provide electric service.

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, 2014, in "Regulatory Matters" in this MD&A, and in Note 3 - "Regulatory Matters" to the condensed consolidated financial statements included in this report.

In 2014, Idaho Power extended its December 2011 Idaho settlement stipulation, including the provisions for potential sharing of earnings with customers and for amortization of additional accumulated deferred investment tax credits (ADITC) to help achieve a minimum 9.5 percent return on year-end equity in the Idaho jurisdiction (Idaho ROE). While providing no assurance that Idaho Power will obtain a 9.5 percent Idaho ROE in any of the applicable years, IDACORP and Idaho Power believe the ability to amortize additional ADITC under the terms of the settlement stipulation provides an element of earnings stability for 2015 and potentially through as late as 2019, depending on the usage rate of additional ADITCs during the applicable years.

In May 2015, the IPUC approved settlement stipulations relating to the calculation of the Idaho power cost adjustment (PCA) and fixed cost adjustment (FCA) mechanisms. The settlement stipulations are intended to more closely align Idaho Power's cost recovery under the PCA and FCA mechanisms with what Idaho Power believes to be the intent and purpose of those mechanisms.

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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 2015, total employment in the service area was 479,412 compared with 458,024 in September 2014. The unemployment rate for the service area was 4.0 percent. By comparison, the September 2015 U.S. unemployment rate was 5.1 percent, according to U.S. Department of Labor data.


•	Moody's Analytics forecasts, as of September 2015, 4.8 percent and 6.3 percent growth in gross area product for Idaho Power's service area for 2015 and 2016, respectively.


•	Customer growth for the twelve months ended September 30, 2015, was 1.8 percent.


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

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. Dry weather in the spring of 2015 led to increased sales to irrigation customers as compared with 2014; milder first quarter and third quarter 2015 temperatures compared with 2014, partially offset by warmer temperatures in June 2015, reduced sales to residential customers .

In May 2015, the IPUC approved a settlement stipulation relating to the operation of the FCA mechanism, which replaced weather-normalized billed sales in the calculation of the FCA with actual billed sales. The revisions to the FCA will reduce the impact on revenues and net income of weather-driven fluctuations in sales to residential and small commercial customers. The change to the FCA mechanism is discussed further in "Regulatory Matters" in this MD&A.

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. As of the date of this report, Idaho Power estimates that its 2015 hydroelectric generation will be between 5.7 million and 6.2 million megawatt-hours (MWh). This estimated range compares to 2014 hydroelectric generation of 6.2 million MWh. Idaho Power's resource-adjusted median annual hydroelectric generation is 8.5 million MWh.

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 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. Most 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.

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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 more reliable, dispatchable 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: 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's (EPA) recently issued final rule under Section 111(d) of the Clean Air Act, which is intended to reduce carbon dioxide emissions from the power sector, 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.

Summary of Financial Results



	Three months ended September 30,				Nine months ended September 30,
	2015		2014		2015		2014
Idaho Power net income	$	71,727	$	84,600	$	159,528	$	155,154
Net income attributable to IDACORP, Inc.	$	73,336	$	86,889	$	162,847	$	158,832
Average outstanding shares – diluted (000’s)	50,324		50,220		50,282		50,184
IDACORP, Inc. earnings per diluted share	$	1.46	$	1.73	$	3.24	$	3.16

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The table below provides a reconciliation of net income attributable to IDACORP for the three- and nine-month periods ended September 30, 2015 to the same periods in 2014 (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, 2014				$	86.9					$	158.8
Change in Idaho Power net income:
Decreased sales volumes attributable to usage per customer, net of associated power supply costs and PCA mechanism impacts	$	(9.4	)				$	(9.1	)
FCA revenues	0.2						11.0
Increased sales volumes attributable to customer growth, net of associated power supply costs and PCA mechanism impacts	3.4						8.1
Change in other operating and maintenance expenses	0.3						(3.1		)
Increase in depreciation expense	(1.2		)				(3.7		)
Other changes in operating revenues and expenses, net	1.8						0.5
Increase (decrease) in Idaho Power operating income	(4.9		)				3.7
Impact of sharing under Idaho regulatory settlement stipulation	4.9						4.9
Net change in Idaho Power operating income	—						8.6
Changes in other non-operating income and expenses	(0.5		)				0.8
Decrease in income tax related to first mortgage bond redemption costs	—						7.2
Increased income taxes due to tax method change recorded in 2014	(11.1		)				(11.1		)
Increase in other income tax expense	(1.3		)				(1.1		)
Total (decrease) increase in Idaho Power net income				(12.9		)				4.4
Other changes (net of tax)				(0.7		)				(0.4		)
Net income attributable to IDACORP, Inc. - September 30, 2015				$	73.3					$	162.8

Net Income - Third Quarter 2015

IDACORP's net income decreased $13.6 million for the third quarter of 2015 when compared with the same period in the prior year. The decrease was driven primarily by a $12.4 million increase in income tax expense at Idaho Power, which principally resulted from the recording of a flow-through income tax benefit in the third quarter of 2014 related to a tax accounting method change for Idaho Power's capitalized repairs deduction.

Moderate temperatures in third quarter 2015 compared with 2014 resulted in decreased average electricity usage by residential and irrigation customers. Cooling degree days in the third quarter of 2015 were closer to normal than in the warmer third quarter of 2014, which reduced demand for electricity for operation of air conditioning units in the third quarter of 2015 compared with the same period in 2014. A decrease in per customer sales volumes also resulted in lower average rates, as fewer customers reached usage levels that resulted in the application of higher rates under Idaho Power's tiered rate structure. These decreased sales volumes and lower average rates, combined with modestly higher net power supply costs, combined to decrease operating income by $9.4 million. Offsetting this decline was an increase in sales volumes attributable to continued customer growth, which contributed approximately $3.4 million to operating income.

Idaho Power has not recorded an accrual for revenue sharing during 2015 under its Idaho regulatory settlement stipulation. By contrast, in the third quarter of 2014 Idaho Power recorded a $4.9 million reduction to revenues for amounts to be shared with Idaho customers.

Net Income - First Nine Months of 2015

IDACORP's net income increased $4.0 million for the first nine months of 2015 when compared with the same period in the prior year. The variance in results for the first nine months includes the effect of two 2014 items mentioned above—an income tax accounting method change and an accrual for revenue sharing with customers. In addition, 2015 income tax expense reflects a $7.2 million flow-through impact of a tax deductible make-whole premium Idaho Power paid upon early redemption of long-term debt.

Idaho Power's operating income was impacted by several factors. A decrease in per customer sales and lower average rates due to tiered rates, along with modestly higher net power supply costs, combined to decrease operating income by $9.1 million for

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the first nine months of 2015 compared with the same period in 2014. The sales volume benefit of warmer temperatures in June 2015 was offset by unusually mild temperatures early in the year and in July. Recently approved changes to Idaho Power's FCA mechanism also affected results for the first nine months of 2015. The revised FCA mechanism now addresses fluctuations in residential and small commercial sales associated with actual weather conditions, as opposed to normalized weather conditions under the FCA mechanism prior to 2015. Idaho Power’s continued customer growth contributed approximately $8.1 million to operating income for the first nine months of 2015.

Key Operating and Financial Metric Estimates for Full-Year 2015

As of the date of this report, IDACORP’s and Idaho Power’s estimates for 2015 are as follows (in millions):



	2015 Estimates
	Current⁽¹⁾	Previous⁽²⁾
Idaho Power Operating & Maintenance Expense	No Change	$340-$350
Idaho Power Additional Amortization of ADITC	No Change	None
Idaho Power Capital Expenditures, excluding AFUDC	No Change	$300-$310
Idaho Power Hydroelectric Generation (MWh)⁽³⁾	5.7-6.2	6.0-7.0

⁽¹⁾ As of October 29, 2015.

⁽²⁾ As of July 30, 2015, the date of filing IDACORP's and Idaho Power's Quarterly Report on Form 10-Q for the quarter ended June 30, 2015.

⁽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, 2015. In this analysis, the results for the three and nine months ended September 30, 2015 are compared with the same periods in 2014.

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, 2015 and 2014.



	Three months ended September 30,				Nine months ended September 30,
	2015		2014		2015		2014
General business sales	4,165		4,166		11,010		10,930
Off-system sales	203		434		940		1,611
Total energy sales	4,368		4,600		11,950		12,541
Hydroelectric generation	1,383		1,490		4,618		4,824
Coal generation	1,473		1,750		3,680		4,380
Natural gas and other generation	787		579		1,579		1,019
Total system generation	3,643		3,819		9,877		10,223
Purchased power	1,013		1,051		2,792		3,158
Line losses	(288	)	(270	)	(719	)	(840	)
Total energy supply	4,368		4,600		11,950		12,541

Sales Volume and Generation: In the third quarter of 2015, total general business sales volumes were nearly unchanged compared with the third quarter of 2014. Over the first nine months of 2015, general business sales volume increased 80 thousand MWh, or 1 percent, compared with the same period in the prior year. In both the third quarter and first nine months of 2015, the positive sales volume impact of customer growth was substantially offset by reduced usage due to more moderate weather.

Off-system sales volume declined significantly in the third quarter and first nine months of 2015, respectively, as decreases in output from hydroelectric resources reduced the amount of surplus power available for off-system sales. Also, more favorable wholesale market conditions in 2014 provided more opportunities to make off-system sales during 2014 than during 2015. Idaho Power operated its generation facilities to take advantage of those 2014 wholesale market conditions.

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Generation from Idaho Power's hydroelectric plants declined in 2015 due to weaker Snake River stream flows and other hydroelectric generating conditions and wholesale market conditions. At Idaho Power's thermal plants, coal-fired generation decreased while natural gas-fired generation increased, as low regional natural gas prices made natural gas-fired plants more economical to run in 2015.

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, 2015 and 2014, and the number of customers as of September 30, 2015 and 2014.



	Three months ended September 30,						Nine months ended September 30,
	2015			2014			2015			2014
Revenue
Residential	$	129,393		$	134,336		$	376,584		$	370,967
Commercial	82,397			85,146			232,167			226,556
Industrial	48,843			50,345			138,292			137,363
Irrigation	83,595			86,343			159,265			153,196
Total	344,228			356,170			906,308			888,082
Provision for sharing	—			(4,900		)	—			(4,900		)
Deferred revenue related to HCC relicensing AFUDC⁽¹⁾	(3,432		)	(3,432		)	(8,365		)	(8,365		)
Total general business revenues	$	340,796		$	347,838		$	897,943		$	874,817
Volume of Sales (MWh)
Residential	1,239			1,260			3,623			3,681
Commercial	1,062			1,053			3,027			2,962
Industrial	821			819			2,382			2,402
Irrigation	1,043			1,034			1,978			1,885
Total MWh sales	4,165			4,166			11,010			10,930
Number of customers at period end
Residential	434,088			426,288
Commercial	68,255			67,319
Industrial	119			117
Irrigation	20,288			19,825
Total customers	522,750			513,549

⁽¹⁾As part of its January 30, 2009 general rate case order, the IPUC is allowing Idaho Power to recover the allowance for funds used during construction (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 accumulated license costs are placed in service.

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Changes in rates, changes in customer demand, and changes in FCA revenues are the primary reasons for fluctuations in general business revenue from period to period. 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, providing for higher rates during peak load periods, and residential customer rates are tiered, providing for higher rates based on higher levels of usage. 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, 2015 and 2014 is presented in the table that follows.



	Three months ended September 30,			Nine months ended September 30,
	2015	2014	Normal	2015	2014	Normal
Heating degree-days⁽¹⁾	60	56	121	2,659	3,043	3,320
Cooling degree-days⁽¹⁾	878	983	751	1,251	1,119	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 $7.0 million and increased $23.1 million for the three and nine months ended September 30, 2015, respectively, compared with the same periods in 2014. Factors affecting general business revenues during the period are discussed below.

•

Rates: Two rate changes impacted general business revenue for the comparative periods -- an Idaho PCA rate increase effective June 1, 2014, and an Idaho PCA rate decrease effective June 1, 2015, both described in Note 3 - "Regulatory Matters" to the condensed consolidated financial statements included in this report. Overall, rate changes combined to reduce general business revenue by $11.6 million in the third quarter of 2015, and increased general business revenue by $1.1 million for the first nine months of 2015, compared with the same periods in 2014. The revenue impact of the rate changes was partially offset by associated changes in operating expenses - Idaho PCA amortization expense decreased $12.8 million for the third quarter of 2015 when compared with the same period in 2014 due to the changes in the corresponding Idaho PCA true-up rate in the comparative periods.


•	Customers: Customer growth increased general business revenue by $4.7 million and $11.1 million, respectively, when compared with the third quarter and first nine months of 2014. Total customers increased 1.8 percent during the twelve months ended September 30, 2015.


•	Usage: Lower usage (on a per customer basis), primarily by residential and irrigation customers, reduced general business revenue by $5.2 million for the quarter and by $5.0 million for the first nine months of 2015 when compared with the same periods in 2014, as a result of the weather conditions described above.

•

FCA Revenue: The revenue impact of the Idaho FCA mechanism increased $0.2 million in the third quarter and $11.0 million for the first nine months of 2015 compared with the prior year comparable periods. These increases include the application of the modifications made to the FCA mechanism, which were approved by the IPUC in the second quarter of 2015, but made retroactive to the beginning of 2015. The modifications to the FCA mechanism are described in more detail in "Regulatory Matters" in this MD&A and in Note 3 - "Regulatory Matters" to the condensed consolidated financial statements included in this report.

•

Sharing: In the third quarter of 2014, Idaho Power recorded a $4.9 million decrease to revenue, reflecting estimated amounts to be shared with Idaho customers under a December 2011 Idaho regulatory settlement stipulation that provides for the sharing of Idaho-jurisdiction earnings exceeding a 10 percent Idaho ROE. No amounts have been recorded in 2015 for sharing, as Idaho Power's estimate of 2015 Idaho ROE does not exceed the Idaho ROE sharing threshold established by the regulatory settlement stipulation.

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Off-System Sales: Off-system sales consist primarily of long-term sales contracts and opportunity sales of surplus system energy. The table below presents Idaho Power’s off-system sales for the three and nine months ended September 30, 2015 and 2014.



	Three months ended September 30,				Nine months ended September 30,
	2015		2014		2015		2014
Revenue	$	6,487	$	15,449	$	23,335	$	56,390
MWh sold	203		434		940		1,611
Revenue per MWh	$	31.96	$	35.60	$	24.82	$	35.00

In the third quarter of 2015, off-system sales revenue decreased by $9.0 million, or 58 percent, compared with the same period in 2014. For the first nine months, off-system sales revenue decreased by $33.1 million, or 59 percent. Off-system sales volumes decreased 53 percent and 42 percent for the quarter and first nine months, respectively, as 2014 sales were well above normal and benefited from favorable market conditions, at times, for selling power off-system. The average price of off-system sales transactions for the first nine months of 2015 was 29 percent lower than for the first nine months of 2014. Decreases in output from hydroelectric resources and an increase in customer load also reduced the amount of surplus power available for sale off-system during the first nine months of 2015.

Other Revenues: The table below presents the components of other revenues for the three and nine months ended September 30, 2015 and 2014.



	Three months ended September 30,				Nine months ended September 30,
	2015		2014		2015		2014
Transmission services and other	$	13,589	$	11,887	$	41,480	$	40,598
Energy efficiency	7,645		5,537		19,854		17,881
Total other revenues	$	21,234	$	17,424	$	61,334	$	58,479

Other revenues increased $3.8 million, or 22 percent, in the third quarter of 2015 and $2.9 million, or 5 percent, in the first nine months of 2015, compared with the same periods in 2014. The increases in the third quarter primarily related to higher energy efficiency revenue and transmission service revenue, while the increases in the first nine months of 2015 were primarily the result of higher energy efficiency revenue.

Most energy efficiency activities are funded through a rider mechanism on customer bills. Energy efficiency program expenditures funded through the rider are reported as an operating expense with an equal amount of revenues recorded in other revenues, resulting in no net impact on earnings. The cumulative variance between expenditures and amounts collected through the rider is recorded as a regulatory asset or liability pending future collection from, or obligation to, customers. A liability balance indicates that Idaho Power has collected more than it has spent and an asset balance indicates that Idaho Power has spent more than it has collected.

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Purchased Power: The table below presents Idaho Power’s purchased power expenses and volumes for the three and nine months ended September 30, 2015 and 2014.



	Three months ended September 30,				Nine months ended September 30,
	2015		2014		2015		2014
Expense
PURPA contracts	$	37,392	$	37,827	$	95,503	$	104,443
Other purchased power (including wheeling)	34,497		37,231		70,688		76,848
Total purchased power expense	$	71,889	$	75,058	$	166,191	$	181,291
MWh purchased
PURPA contracts	494		544		1,524		1,721
Other purchased power	519		507		1,268		1,437
Total MWh purchased	1,013		1,051		2,792		3,158
Cost per MWh from PURPA contracts	$	75.69	$	69.53	$	62.67	$	60.69
Cost per MWh from other sources	$	66.47	$	73.43	$	55.75	$	53.48
Weighted average - all sources	$	70.97	$	71.42	$	59.52	$	57.41

Purchased power expense decreased $3.2 million, or 4 percent, in the third quarter and decreased $15.1 million, or 8 percent, in the first nine months of 2015, compared with the same periods in 2014, respectively. The decrease for the third quarter and first nine months of 2015 was due primarily to reduced volumes purchased, in large part due to lower output from renewable energy projects under PURPA contracts. Year-to-date volume decreases were partially offset by increases in average prices.

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. 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, 2015 and 2014.



	Three months ended September 30,				Nine months ended September 30,
	2015		2014		2015		2014
Expense
Coal ⁽¹⁾	$	43,869	$	48,215	$	101,654	$	119,461
Natural gas and other thermal	22,516		18,873		42,607		37,398
Total fuel expense	$	66,385	$	67,088	$	144,261	$	156,859
MWh generated
Coal ⁽¹⁾	1,473		1,750		3,533		4,380
Natural gas and other thermal	787		579		1,579		1,019
Total MWh generated	2,260		2,329		5,112		5,399
Cost per MWh - Coal	$	29.78	$	27.55	$	28.77	$	27.27
Cost per MWh - Natural gas and other thermal	$	28.61	$	32.60	$	26.98	$	36.70
Weighted average, all sources	$	29.37	$	28.81	$	28.22	$	29.05

⁽¹⁾The first nine months of 2015 exclude 147 MWh of generation from the Jim Bridger power plant for which costs were capitalized during feasibility testing of capital projects under contemplation.

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

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MWh are noticeably impacted by these fixed charges when generation output is substantially different between the two periods; however, natural gas commodity prices decreased significantly between September of 2014 and September of 2015.

Fuel expense decreased $0.7 million, or 1 percent, in the third quarter of 2015, and $12.6 million, or 8 percent, in the first nine months of 2015, compared with the same periods in 2014. The decrease in the third quarter and first nine months of 2015 was mostly due to lower output from the thermal plants for the periods..

PCA Mechanisms: Idaho Power's power supply costs (primarily purchased power and fuel, less off-system sales) can vary significantly from year to year. Volatility of power supply costs arises from factors such as weather conditions, wholesale market prices and volumes of power purchased and sold in the wholesale markets, Idaho Power's hydroelectric 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, 2015 and 2014.



	Three months ended September 30,						Nine months ended September 30,
	2015			2014			2015			2014
Idaho power supply cost deferral	$	(22,463	)	$	(24,015	)	$	(17,947	)	$	(29,170	)
Amortization of prior year authorized balances	10,549			23,347			44,319			52,666
Total power cost adjustment expense	$	(11,914	)	$	(668	)	$	26,372		$	23,496

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 first nine months of 2015 and 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 "Regulatory Matters" in this MD&A and Note 3 - "Regulatory Matters" 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 decreased $0.3 million, or less than one percent, and increased $3.1 million, or 1 percent, for the third quarter and first nine months of 2015, compared with the same periods in 2014. IDACORP and Idaho Power have been focused on targeting opportunities to optimize business practices to control O&M expenses, which has contributed to the relatively modest increase in O&M expense for the third quarter and first nine months of 2015.

Income Taxes

IDACORP's and Idaho Power's income tax expense for the nine months ended September 30, 2015, compared with the same period in 2014, increased $5.3 million and $5.0 million, respectively, primarily as a result of greater pre-tax earnings in 2015. Additionally, a flow-through tax benefit recorded in the second quarter of 2015 for the call premium Idaho Power paid on the early redemption of long-term debt was lower than a flow-through tax benefit Idaho Power recorded in the third quarter of 2014 for a change in tax accounting method related to its capitalized repairs deduction. 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.

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

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substantial capital expenditures to continue, with estimated total capital expenditures of $1.5 billion over the five-year period from 2015 (including expenditures to date in 2015) through 2019.

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. During 2015, Idaho Power has continued its efforts to optimize operations, control costs, and generate operating cash inflows to meet operating expenditures, contribute to capital expenditure requirements, and pay dividends to shareholders.

As of October 23, 2015, 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; $250 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 monitor capital markets with a view toward opportunistic debt and equity transactions, taking into account current and potential future long-term needs. As a result, IDACORP may issue debt securities or may issue common stock under the existing continuous equity program, and Idaho Power may issue debt securities, if the companies believe terms available in the capital markets are favorable and that issuances would be financially prudent. Idaho Power also periodically analyzes whether partial or full early redemption of one or more existing outstanding series of first mortgage bonds is desirable, and in some cases may refinance indebtedness with new indebtedness issued with more favorable terms, including interest rates lower than the series being redeemed.

On March 6, 2015, Idaho Power issued $250 million in principal amount of 3.65% first mortgage bonds, Series J, maturing on March 1, 2045. On April 23, 2015, Idaho Power redeemed, prior to maturity, its $120 million in principal amount of 6.025% first mortgage bonds, medium-term notes due July 2018. In accordance with the redemption provisions of the original terms of the notes, the redemption included payment by Idaho Power of a make-whole premium of $17.9 million. Idaho Power used a portion of the net proceeds of the March 2015 sale of first mortgage bonds, medium-term notes to effect the redemption.

Based on planned capital expenditures and operating and maintenance expenses for 2015, the companies believe they will be able to meet capital requirements and fund corporate expenses 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 believe they could meet any short-term cash shortfall with existing credit facilities and expect to continue to manage short-term liquidity through commercial paper markets.

IDACORP and Idaho Power seek to maintain capital structures of approximately 50 percent debt and 50 percent equity, and maintaining this ratio influences IDACORP's and Idaho Power's debt and equity issuance decisions. As of September 30, 2015, IDACORP's and Idaho Power's capital structures, as calculated for purposes of applicable debt covenants, were as follows:



	IDACORP	Idaho Power
Debt	46%	48%
Equity	54%	52%

IDACORP and Idaho Power generally maintain their cash and cash equivalents in highly liquid investments, such as U.S. Treasury Bills, money market funds, and bank deposits.

Operating Cash Flows

IDACORP’s and Idaho Power’s operating cash inflows for the nine months ended September 30, 2015 were $291 million and $261 million, respectively, decreases of $25 million and $35 million, respectively, compared with the same period in 2014. With the exception of cash flows related to income taxes, IDACORP’s operating cash flows are principally derived from the

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operating cash flows of Idaho Power. Significant items that affected the comparability of the companies' operating cash flows in the first nine months of 2015 with the same period in 2014 were as follows:


•	Net income increased $4 million.


•	Changes in regulatory assets and liabilities, mostly related to the relative amounts of power supply costs deferred and collected under the Idaho PCA mechanism, decreased operating cash flows by $11 million.


•	Idaho Power made $39 million of cash contributions to its defined benefit pension plan in the first nine months of 2015, compared with $30 million of cash contributions during the first nine months of 2014.


•	Changes in deferred taxes and in taxes accrued and receivable combined to increase cash flows by $6 million at IDACORP, and decreased cash flows by $4 million at Idaho Power.


•	Comparative changes in working capital balances due primarily to timing, including an increase in accounts receivable over the first nine months of 2015 compared with a decrease experienced in 2014, resulting in a $19 million and $21 million decrease to operating cash flows for IDACORP and Idaho Power, respectively.

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, 2015 were $233 million. Investing cash outflows for 2015 and 2014 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.

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 net financing cash inflows for the nine months ended September 30, 2015 were $7 million and $36 million, respectively. Significant 2015 transactions include Idaho Power's issuance on March 6, 2015, of $250 million in first mortgage bonds and the redemption on April 23, 2015, of $120 million in first mortgage bonds. The redemption, made prior to maturity, resulted in the payment of a make-whole premium in the aggregate amount of $18 million. Financing cash flows also included the payment of $71 million of dividends on common stock and a $28 million net decrease in IDACORP commercial paper borrowings.

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, 3 million shares of IDACORP common stock remain available for sale under the Sales Agency Agreement with BNYMCM. As of the date of this report, IDACORP does not expect to issue any shares of its common stock under the Sales Agency Agreement during 2015.

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 was

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through April 9, 2015. However, on April 1, 2015, the IPUC approved a two-year extension through April 9, 2017, continuing Idaho Power's authorization to issue and sell from time to time debt securities and first mortgage bonds. 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 seven 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, $250 million remained on Idaho Power's Selling Agency Agreement for the issuance of first mortgage bonds, including Series J Notes, or debt securities.

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 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, 2015 was limited to approximately $279 million. Idaho Power may increase the $2.0 billion limit on the maximum amount of first mortgage bonds outstanding by filing a supplemental indenture with the trustee as provided in the Indenture of Mortgage and Deed of Trust. Separately, the Indenture also 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. As of September 30, 2015, Idaho Power could issue approximately $1.5 billion of additional first mortgage bonds based on retired first mortgage bonds and total unfunded property additions.

IDACORP and Idaho Power Credit Facilities: IDACORP and Idaho Power have $125 million and $300 million credit facilities, respectively. Each of the credit facilities may be used for general corporate purposes and commercial paper back-up. IDACORP's facility permits borrowings under a revolving line of credit of up to $125 million at any one time outstanding, including swingline loans not to exceed $15 million at any time and letters of credit not to exceed $50 million at any time. IDACORP's facility may be increased, subject to specified conditions, to $150 million. Idaho Power's facility permits borrowings through the issuance of loans and standby letters of credit of up to $300 million at any one time outstanding, including swingline loans not to exceed $30 million at any one time. Idaho Power's facility may be increased, subject to specified conditions, to $450 million. Other terms and conditions of the credit facilities are described in IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2014, in Part II, Item 7 - "MD&A - Liquidity and Capital Resources."

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, 2015, the leverage ratios for IDACORP and Idaho Power were 46 percent and 48 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, 2015, 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.

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. Idaho Power has obtained approval of the state public utility commissions of Idaho, Oregon, and Wyoming for the issuance of short-term borrowings through November 2022.

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

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

Available Short-Term Borrowing Liquidity

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



	September 30, 2015						December 31, 2014
	IDACORP⁽²⁾			Idaho Power			IDACORP⁽²⁾			Idaho Power
Revolving credit facility	$	125,000		$	300,000		$	125,000		$	300,000
Commercial paper outstanding	(3,600		)	—			(31,300		)	—
Identified for other use⁽¹⁾	—			(24,245		)	—			(24,245		)
Net balance available	$	121,400		$	275,755		$	93,700		$	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 23, 2015, IDACORP had no loans outstanding under its credit facility and no 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, 2015.



	Three months ended						Nine months ended
	September 30, 2015						September 30, 2015
	IDACORP⁽¹⁾			Idaho Power			IDACORP ⁽¹⁾			Idaho Power
Commercial paper:
Period end:
Amount outstanding	$	3,600		$	—		$	3,600		$	—
Weighted average interest rate	0.56		%	—		%	0.56		%	—		%
Daily average amount outstanding during the period	$	22,892		$	—		$	28,663		$	—
Weighted average interest rate during the period	0.52		%	—		%	0.52		%	—		%
Maximum month-end balance	$	26,600		$	—		$	43,400		$	—

⁽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, depend 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, 2014. 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, 2015, Idaho Power had posted $0.8 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, 2015, the amount of additional collateral that could be requested upon a downgrade to below investment grade is approximately $9.9 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 allowance for funds used during construction (AFUDC), were $228 million during the nine months ended September 30, 2015. The table below presents Idaho Power's estimated cash requirements for construction, excluding AFUDC, for 2015 (including amounts incurred to-date) through 2019 (in millions of dollars).



	2015	2016	2017-2019
Ongoing capital expenditures (excluding item listed below in this table)	$255-260	$285-290	$850-905
Jim Bridger plant selective catalytic reduction equipment	45-50	15-20	20-25
Total	$300-310	$300-310	$870-930

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 developments in certain of those projects 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, 2014. The discussion below should be read in conjunction with that report.

Jim Bridger Plant Selective Catalytic Reduction Equipment and Related IPUC Filing: Idaho Power and the plant co-owners are installing selective catalytic reduction (SCR) equipment to reduce nitrogen oxide (NO_x) emissions at the Jim Bridger power plant, in order to comply with regional haze rules. The regional haze rules provide for installation and compliant operation of SCR on unit 3 by January 1, 2016 and unit 4 by January 1, 2017. The rules provide for an equivalent technology for NO_x reductions on unit 2 by 2021 and unit 1 by 2022. Idaho Power estimates that the total cost for Idaho Power's share of the upgrades on units 3 and 4 is approximately $109 million, excluding AFUDC. As of September 30, 2015, Idaho Power had expended $75 million, excluding AFUDC, on SCR installation at units 3 and 4. As of the date of this report, the overall project remains on schedule and Idaho Power expects the total project cost to be at or below the estimated amount.

Boardman-to-Hemingway Transmission 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 2015 IRP. In January 2012, Idaho Power entered into a joint funding agreement with PacifiCorp and the Bonneville Power Administration 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 $43 million, including Idaho Power's AFUDC. Total cost estimates for the project are between $1.0 billion and $1.2 billion, including AFUDC for Idaho Power's share of the project. 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.

Idaho Power has expended approximately $71 million on the Boardman-to-Hemingway project through September 30, 2015. Pursuant to the terms of the joint funding arrangements, approximately $36 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, 2015. In addition to the $36 million amount noted above, $16 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.

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. The BLM issued a draft environmental impact study (EIS) for the project on December 19, 2014, and as of the date of this report Idaho Power expects the BLM to issue a final EIS during 2016. In the separate Oregon state permitting process, Idaho Power submitted a preliminary application for a site certificate in February 2013 and intends to submit an amended preliminary application in 2016. Idaho Power is unable to determine an in-service date for the line but, given the status of ongoing permitting activities, expects the in-service date would be in 2022 or beyond.

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Gateway West Transmission 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 joint funding agreement for permitting of the project. Idaho Power's estimated cost for the permitting phase of the Gateway West project is approximately $64 million, including AFUDC, which has been extended to the project's anticipated in-service date. Idaho Power has expended approximately $29 million on the permitting phase of the project through September 30, 2015. 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 $200 million and $400 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 beyond the permitting phase are not included in the table above.

The permitting phase of the project is subject to review and approval of the BLM. The BLM released its record of decision 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 some segments, and deferred a decision on two segments (in both of which Idaho Power has an interest) 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 has initiated the supplemental EIS process for the two deferred segments. As of the date of this report, the BLM's schedule provides for the issuance of a record of decision on the two deferred segments in 2016.

Hells Canyon Complex Relicensing: The HCC, located on the Snake River where it forms the border between Idaho and Oregon, provides approximately 68 percent of Idaho Power's hydroelectric generating nameplate capacity and 32 percent of its total generating nameplate capacity. Idaho Power has been engaged in the process of obtaining from the FERC a new long-term license for the HCC. As noted in "Regulatory Matters" in this MD&A, the costs associated with obtaining a new long-term license for the HCC are significant. Idaho Power expects that the annual capital expenditures and operating and maintenance expenses associated with compliance with the terms and conditions of the long-term license could also be substantial, but the company is currently unable to estimate those costs in light of the uncertainty surrounding the ultimate terms and conditions that may be included in the license. Idaho Power intends to seek recovery of those relicensing and compliance costs in rates through the regulatory process.

Shoshone Falls Plant Expansion: The Shoshone Falls plant expansion project was included in Idaho Power's 2013 IRP and, as originally planned, was to consist of constructing a new powerhouse, intake structure, penstock, and substation and installing a new turbine to increase the nameplate generation capacity of the plant from 12.5 MW to 61.5 MW. However, following additional analysis of the costs and potential benefits of the expansion, Idaho Power's 2015 IRP (discussed below) includes in the near-term action plan a modified project that would result in a significantly smaller increase in nameplate generation capacity at the facility, in a range of 1.7 MW to 4 MW, with a potential on-line date as early as 2019. Idaho Power is performing additional engineering and cost studies to determine the most suitable project that will optimize and improve the reliability of the facility. Idaho Power intends to seek a license amendment from the FERC that would allow for construction of the modified project.

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, also dated October 24, 2014, between Idaho Power and PacifiCorp, under which each party agreed to transfer to the other 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 agreements related to the ownership and operation of jointly-owned facilities and transmission services between Idaho Power and PacifiCorp. Regulatory approval from the FERC and each of the necessary state regulatory commissions has been received, and closing of the transaction is expected to be effected during the fourth quarter of 2015. In 2014, Idaho Power collected approximately $8 million in transmission revenues under legacy long-term transmission agreements that would be terminated in connection with the proposed transaction. If the transaction is approved, Idaho Power anticipates an increase to its OATT rate, as discussed in "Regulatory Matters" in this MD&A.

2015 Integrated Resource Plan: The IPUC and OPUC require that Idaho Power prepare biennially an IRP. The IRP seeks to forecast Idaho Power's loads and resources for a 20-year period, analyzes potential supply-side, demand-side, and transmission options, and identifies potential near-term and long-term actions. Idaho Power filed its most recent IRP with the IPUC and OPUC in June 2015. The 2015 IRP assumes a forecasted annual growth in average energy demand of 1.2 percent and a forecasted annual growth in peak-hour demand of 1.5 percent over the 20-year period. The 2015 IRP identified a preferred resource portfolio, which includes the completion of the Boardman-to-Hemingway transmission line and the potential early retirement of the North Valmy power plant, both in 2025, with no other new resource needs prior to 2025. However, as noted in

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the 2015 IRP, there is considerable uncertainty surrounding the resource sufficiency estimates and project completion dates, including uncertainty around the timing and extent of third party development of renewable resources, implementation of the EPA's rules under Section 111(d) of the Clean Air Act, the actual completion date of the Boardman-to-Hemingway transmission project, and the economics and logistics of plant retirements. These uncertainties, as well as others, could result in changes to the desirability of the preferred portfolio and adjustments to the timing and nature of anticipated and actual actions.

The 2015 IRP includes as near-term action items the continued permitting and planning for the Boardman-to-Hemingway transmission line and further investigation of the early retirement of the North Valmy power plant in collaboration with the plant's co-owner. The near-term action plan also includes a decrease in the size of the planned Shoshone Falls expansion from 50 MW to a range of 1.7 MW to 4 MW with a scheduled on-line date in 2019, as well as commencement of an economic evaluation of SCR retrofits for units 1 and 2 at the Jim Bridger power plant.

Defined Benefit Pension Plan Contributions

Idaho Power contributed $39 million and $30 million to its defined benefit pension plan in 2015 and 2014, respectively. Idaho Power does not anticipate making additional contributions during the remainder of 2015. 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 2016 and beyond, Idaho Power expects continuing significant contribution obligations under the pension plan. The primary impact of pension contributions is on the timing of cash flows, as the timing of cost recovery lags behind contributions.

Contractual Obligations

During the nine months ended September 30, 2015, 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, 2014, except for the following:

•

on March 6, 2015, Idaho Power issued $250 million in principal amount of 3.65% first mortgage bonds, Series J, maturing on March 1, 2045. On April 23, 2015, Idaho Power redeemed, prior to maturity, its $120 million in principal amount of 6.025% first mortgage bonds, medium-term notes, Series H due July 2018. In accordance with the redemption provisions of the original terms of the notes, the redemption included payment by Idaho Power of a make-whole premium of approximately $17.9 million;


•	four power purchase agreements with a solar energy developer were terminated due to an uncured breach by the counterparty. Termination of the agreements reduced Idaho Power's contractual payment obligations by approximately $483 million over the 20-year lives of the terminated contracts;


•	the addition of seven power purchase agreements with solar and other alternative energy developers for projects with a combined nameplate capacity of approximately 45 MW. Payments pursuant to these new agreements are estimated to total $135 million from 2017 through 2036; and

•

Additionally, in October 2015, Idaho Power signed three energy sales agreements with solar energy developers for projects in Oregon with a combined nameplate capacity of approximately 25 MW. The payments pursuant to these agreements are expected to total $74 million from 2017 to 2036.

Dividends

On September 17, 2015, IDACORP's board of directors approved an increase in the regular quarterly cash dividend on IDACORP’s common stock from $0.47 per share to $0.51 per share. The declaration of dividend payments are at the discretion of the board of directors. In determining future dividend actions, the board of directors will continue to take into account factors such as current and projected capital requirements, IDACORP's and Idaho Power's liquidity position and earnings, the competitiveness of the dividend yield, business cycles, credit rating impacts, legal requirements, long-term sustainability, and other factors.

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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, 2014.

REGULATORY MATTERS

Introduction

Idaho Power's development of rate case plans take into consideration short-term and long-term needs for rate relief and involve several factors that can affect the timing of rate filings. Such factors include, among others, in-service dates of major capital investments, the timing of changes in major revenue and expense items, and customer growth rates. Idaho Power filed general rate cases in Idaho and Oregon during 2011, as well as a single-issue rate case for the Langley Gulch power plant in Idaho and Oregon in 2012. These significant rate cases resulted in the resetting of base rates in both Idaho and Oregon during 2012. More recently, Idaho Power reset its base-rate power supply expenses in 2014.

The outcomes of 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, 2014. In addition to the discussion below, which includes notable regulatory 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, 2014, refer to Note 3 - “Regulatory Matters” to the condensed consolidated financial statements included in this report for additional information relating to Idaho Power's regulatory matters and recent regulatory filings and orders.

Notable Rate Change Filings During 2015

During 2015 to-date, Idaho Power has received rate change approvals summarized in the table below.



Description	Status	Estimated Rate Impact⁽¹⁾	Notes
Power Cost Adjustment Mechanism - Idaho	New PCA rate became effective June 1, 2015	$11.6 million PCA decrease for the period from June 1, 2015 to May 31, 2016	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.
Fixed Cost Adjustment Mechanism - Idaho	New FCA rate became effective June 1, 2015	$2.0 million FCA increase for the period from June 1, 2015 to May 31, 2016	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.

⁽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 Idaho Settlement Stipulation

In December 2011, the IPUC issued an order, separate from the then-pending Idaho general rate case proceeding, approving a settlement stipulation that allowed Idaho Power to, in certain circumstances, amortize additional ADITC if Idaho Power's actual Idaho ROE for 2012, 2013, or 2014 was less than 9.5 percent, to help achieve a 9.5 percent Idaho ROE for the applicable year. When Idaho Power's actual Idaho ROE for any of those years exceeded 10.0 percent, Idaho Power was required to share a portion of its Idaho-jurisdiction earnings with Idaho customers. As Idaho Power's 2012, 2013, and 2014 Idaho ROE exceeded 10.0 percent, Idaho Power did not amortize additional ADITC for those years, but instead shared earnings with customers.

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 through 2019, or until the terms are otherwise modified or terminated by order of the IPUC or the full $45 million of additional ADITC contemplated by the settlement stipulation has been amortized. The more specific terms and conditions of the October 2014 Idaho settlement stipulations are described in Note 3 - "Regulatory Matters" to the condensed consolidated financial statements included in this report. IDACORP and Idaho Power believe that the terms allowing amortization of additional ADITC in the October 2014 settlement stipulation provide the companies with a greater degree of earnings stability than would be possible without the terms of the stipulation in effect.

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In accordance with the October 2014 settlement stipulation, Idaho Power has a total of $45 million of additional ADITC amortization available for use (limited to $25 million for any applicable year). Based on its estimate of 2015 Idaho ROE, Idaho Power did not record any additional ADITC amortization or provision for sharing in the first nine months of 2015.

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 following table summarizes the change in deferred net power supply costs during the nine months ended September 30, 2015.



	Idaho			Oregon⁽¹⁾			Total
Balance at December 31, 2014	$	54,512		$	4,677		$	59,189
Current period net power supply costs deferred	17,947			—			17,947
Prior amounts recovered through rates	(27,515		)	(1,727		)	(29,242		)
SO₂ allowance and renewable energy certificate sales	(1,443		)	(64		)	(1,507		)
Revenue sharing and energy efficiency rider funds	(11,999		)	—			(11,999		)
Interest and other	242			272			514
Balance at September 30, 2015	$	31,744		$	3,158		$	34,902

⁽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 and in Note 3 - "Regulatory Matters" to the condensed consolidated financial statements included in this report. 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 Idaho PCA mechanism allows Idaho Power to pass through to customers 95 percent of the differences in actual net power supply expenses as compared with 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.

Modification of Annual Rate Adjustment Mechanisms

PCA Mechanism -- In July 2014, the IPUC opened a docket pursuant to which Idaho Power, the IPUC Staff, and other interested parties evaluated Idaho Power's application of the true-up component of the PCA mechanism. 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 introduced a line-loss bias that inflated the true-up revenue it must collect. The IPUC's docket was closed via an order issued by the IPUC in August 2014, with no adjustment made to the PCA true-up revenue amount. Idaho Power subsequently met with the IPUC Staff to explore approaches to increasing the accuracy of the actual cost recovery under the PCA mechanism. On May 28, 2015, the IPUC approved a settlement stipulation that modified the calculation of the true-up component of the PCA mechanism. The settlement stipulation is described in Note 3 - "Regulatory Matters" to the condensed consolidated financial statements included in this report.

The 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. Stated generally, under the FCA Idaho Power charges residential and small commercial customers when it recovers less "actual fixed costs" than the base level of fixed costs that the IPUC authorized for recovery through rates in the last general rate case, and Idaho Power credits those customers when its "actual fixed costs" recovered exceed that base level of fixed costs. The FCA is adjusted each year to collect, or refund, the difference between the allowed fixed-cost recovery amount and the actual fixed costs recovered by Idaho Power during the year.

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On May 6, 2015, the IPUC approved a settlement stipulation that modified the FCA mechanism by replacing weather-normalized billed sales with actual billed sales in the calculation of the FCA, applicable for the entirety of calendar year 2015 and thereafter, with new rates effective June 1, 2016. The settlement stipulation also provided that a modified rate design should be considered at a later time for residential and small general service customers to address the financial disincentive caused by the existing rate design that the FCA is intended to remove. The rate design may include, but would not be limited to, reduced energy charges, increased monthly service charges, and the introduction of demand charges.

In years when actual billed sales per customer are higher than weather-normalized billed sales due to high summer or low winter temperatures, Idaho Power expects that the new FCA methodology will be less favorable to Idaho Power than the prior methodology. Conversely, Idaho Power expects that the new FCA methodology will be more favorable to Idaho Power in years when actual billed sales per customer are lower than weather normalized billed sales due to low summer or high winter temperatures. Implementation of the new methodology was retroactive to January 1, 2015, as contemplated by the settlement stipulation.

Update to Open Access Transmission Tariff

Idaho Power uses a formula rate for transmission service provided to third parties under its OATT. The transmission rates are updated annually based primarily on financial and operational data Idaho Power files with the FERC. On August 28, 2015, Idaho Power filed with the FERC and publicly posted its final informational filing for its 2015 transmission rate, reflecting a transmission rate of $23.43 per kW-year, to be effective for the period from October 1, 2015 to September 30, 2016. Idaho Power's transmission rate was based on a net annual transmission revenue requirement of $121.3 million. The existing OATT rate in effect from October 1, 2014 to September 30, 2015 was $22.71 per kW-year based on a net annual transmission revenue requirement of $120.8 million.

Leading up to the final informational filing, in a draft transmission rate posting Idaho Power made on June 1, 2015, Idaho Power included in its draft OATT rate calculations the expected changes in demand associated with the pending transmission system transaction with PacifiCorp described above, resulting in a draft rate of $33.23 per kW-year. If effected, the pending transmission system transaction will terminate certain legacy transmission agreements and provide for new long-term point-to-point transmission service for PacifiCorp. In response to concerns from transmission customers, Idaho Power subsequently shifted its procedural approach for incorporating the impacts of the pending transmission system transaction on its OATT rate. Idaho Power's 2015 transmission rate described above for the period from October 1, 2015 to September 30, 2016 does not include the impact of the pending transmission system transaction. In a July 28, 2015 filing, Idaho Power requested clarification from the FERC as to when Idaho Power may incorporate the effects of the pending transmission system transaction in the formula used to determine its OATT rate. A determination from the FERC is pending.

Long-Term Service Agreement for Natural Gas Plants

Idaho Power has executed a long-term service agreement for maintenance services at three of Idaho Power's natural gas plants, with a total estimated obligation of $72 million over the term of the agreement. Idaho Power expects that the agreement, if it becomes effective, will decrease the long-term costs of operating the natural gas plants. Effectiveness of the service agreement is conditioned upon the IPUC's approval of the agreement and acceptable accounting treatment. Idaho Power received IPUC approval of the agreement on October 5, 2015. However, Idaho Power reviewed and considered the implications of the IPUC's order, including the accounting treatment described in the order, and has requested reconsideration from the IPUC of certain aspects of the accounting treatment in the IPUC's order. Accordingly, as of the date of this report, the agreement has not become effective. Depending on the outcome of Idaho Power's request for reconsideration, the service agreement may not ultimately become effective, or Idaho Power may seek to work with the service provider to modify the service agreement.

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, 2015, 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. As of September 30, 2015, Idaho Power had contracts to purchase energy from solar projects not yet on-line for a total of 364 MW. All of these solar projects have estimated on-line dates no later than year-end 2016. The following table sets forth, as of September 30, 2015, the number

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and nameplate capacity of Idaho Power's signed CSPP-related agreements. These agreements have original contract terms ranging from one to 35 years.



Status	Number of CSPP Contracts	Nameplate Capacity (MW)
On-line as of September 30, 2015	107	782
Contracted and projected to come on-line by June 1, 2017	30	424

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.

In light of the volume of intermittent generation Idaho Power is required to purchase pursuant to existing PURPA power purchase agreements and the substantial increase in volume of proposed new solar generation facilities seeking power purchase agreements with Idaho Power, on January 30, 2015, Idaho Power filed an application with the IPUC requesting that the IPUC issue an order directing that the maximum required term for prospective PURPA power purchase agreements be reduced from 20 years to two years. In its application, Idaho Power stated that the requested modification to terms of PURPA energy purchases is necessary to prevent harm to Idaho Power's customers that may result from entering into additional long-term, fixed-rate purchase agreements when Idaho Power predicts that there is no need for new generation capacity through 2021. In February 2015, the IPUC issued an order reducing the maximum contract term of certain future PURPA power purchase agreements from 20 years to five years during the pendency of the proceedings. On August 20, 2015, the IPUC issued an order reducing the length of PURPA contracts that involve avoided-cost-based pricing to two years.

For the Oregon jurisdiction, on April 24, 2015, Idaho Power made filings with the OPUC requesting, among other things, a reduction in the term of standard PURPA power purchase agreements from 20 years to two years for projects above 100 kW, and a temporary suspension of Idaho Power's obligation to enter into new fixed-price standard PURPA agreements during the pendency of the proceedings. On June 23, 2015, the OPUC issued an order denying Idaho Power’s request for a temporary suspension but reduced the eligibility cap for standard contracts from 10 MW to 3 MW on a temporary basis during the pendency of the proceedings. Hearings are scheduled to commence in November 2015.

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 $214 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, 2015. As of the date of this report, the IPUC authorizes Idaho Power to include in its Idaho jurisdiction rates approximately $10.7 million of AFUDC annually relating to the HCC relicensing project. Collecting these amounts now will reduce the amount collected in the future when HCC relicensing costs are approved for recovery in base rates. As of September 30, 2015, Idaho Power's regulatory liability for collection of AFUDC relating to the HCC was $84 million. 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. As of the date of this report, Idaho Power estimates that the annual costs it will incur to obtain a new long-term license for the HCC, including AFUDC but excluding costs expected to be incurred for complying with the license after issuance, are likely to range from $20 million to $30 million until issuance of the license.

ENVIRONMENTAL MATTERS

Overview

Idaho Power is subject to a broad range of federal, state, regional, and local laws and regulations designed to protect, restore, and enhance the environment, including the Clean Air Act (CAA), the Clean Water Act (CWA), the Resource Conservation and Recovery Act, the Toxic Substances Control Act, the Comprehensive Environmental Response, Compensation and Liability Act, and the Endangered Species Act, among other laws. Current and pending environmental legislation relates to, among other

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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, 2014 includes a summary of Idaho Power's expected capital and operating expenditures for environmental matters during the period from 2015 to 2017. 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.

A summary of notable environmental matters impacting, or expected to potentially impact, IDACORP and Idaho Power, is 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, 2014. Included below is a summary of notable developments in environmental and related issues impacting Idaho Power since the discussion in that report.

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Developments in Regulation of Coal Combustion Residuals (CCRs)

The Resource Conservation and Recovery Act (RCRA) is a federal statute regulating the generation, treatment, storage, and disposal of solid and hazardous wastes. In June 2010, the EPA proposed regulations governing the disposal and management of CCRs, which are regulated under the RCRA. In December 2014, the EPA signed a final rule relating to the disposal of CCRs, which was published in the Federal Register on April 17, 2015. The rule establishes structural integrity design criteria and requires that owners and operators periodically conduct a number of structural integrity related assessments and install monitoring apparatus. The rule also imposes location restrictions on impoundments, requires the closure of impoundments that cannot meet the location restrictions, imposes liner design criteria and operating requirements, and imposes certain record keeping and notification requirements. Additionally, the EPA's rule imposes obligations associated with the closure of CCR impoundments. Idaho Power and its co-owners of coal-fired units performed engineering and cost studies to determine the impacts of the rule. In the second quarter of 2015, Idaho Power recorded an increase of approximately $5 million in its asset retirement obligation for the Jim Bridger coal-fired plant. The amounts recorded for asset retirement obligations for Idaho Power's other jointly-owned coal-fired plants were not impacted by the EPA's new rule.

Clean Water Act Updates

Definition of "Waters of the United States": On August 28, 2015, the EPA's and U.S. Army Corps of Engineers' final rule defining the phrase "waters of the United States" under the CWA became effective. Idaho Power believes that the final rule potentially expands 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. As a result of the potential expansion, the final rule may result in additional permitting and regulatory requirements under multiple provisions of the CWA. Idaho Power has analyzed the final rule and expects that while it may incur additional permitting and other costs associated with the rule, the aggregate amount of increased costs is unlikely to have a material adverse effect on Idaho Power's operations or financial condition, in part due to the relatively arid climate of Idaho Power's service area and the existing application of the CWA to most of Idaho Power's facilities, including its hydroelectric plants.

On October 9, 2015, the United States Court of Appeals for the Sixth Circuit issued a nationwide stay of the final waters of the United States rule from becoming effective. Accordingly, Idaho Power expects that the previous definition of waters of the United States will be used for CWA jurisdictional determinations until further judicial order.

Effluent Limitation Guidelines and Standards: In 2013, the EPA issued a proposed rule revising the technology-based effluent limitation guidelines and standards under the CWA for water discharged from steam electric power plants, which includes coal-fired plants. On September 30, 2015, the EPA issued the final rule, which established limits on the levels of specified metals in wastewater that can be discharged from steam electric power plants. The EPA stated that it estimates that approximately 12 percent of steam electric power plants will incur some costs associated with the final rule. Idaho Power previously performed an analysis of the potential impact of the proposed rule on its operations and financial condition and, based on that analysis, did not expect a material impact. Idaho Power is performing an updated analysis of the potential financial and operational impacts of the final rule. However, given the nature of its co-owned coal-fired power plants, as of the date of this report Idaho Power does not expect that the final rule will have any material adverse impact on either the operation of its existing co-owned coal-fired power plants or associated operating costs.

Clean Air Act Updates

Mercury and Air Toxics Standard: The final Mercury and Air Toxics Standards (MATS) rule under the CAA, previously referred to as the Utility MACT Rule, was issued in February 2012. The final rule established emission limits for hazardous air pollutants from new and existing coal-fired and oil-fired steam electric generating units. The MATS rule provided that sources must be in compliance with emission limits by April 16, 2015. Idaho Power and the plant co-owners have installed mercury continuous emission monitoring systems on all of the coal-fired units at the Jim Bridger, Boardman, and North Valmy coal-fired generating plants, along with control technology to reduce mercury, acid gases, and particulate matter emissions for purposes of compliance with the MATS rule. Idaho Power believes that as of the date of this report the coal-fired plants are in compliance with the MATS rule. However, on November 25, 2014, the United States Supreme Court granted a petition for review of the MATS rule based on the issue of whether the EPA unreasonably refused to consider costs in determining whether it is appropriate to regulate hazardous air pollutants from coal-fired and oil-fired steam electric generating units. On June 29, 2015, the Court issued a decision holding that the EPA must consider cost, including the cost of compliance, before deciding whether regulation is appropriate and necessary, and remanded the case to the District of Columbia Circuit Court for further proceedings consistent with the Court's decision. The MATS rule remains in effect until the District of Columbia Circuit Court acts.

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Section 111(d): In June 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 proposed rule was designed to achieve a 30 percent reduction in CO₂ emissions from the power sector. The EPA's proposal required that states meet their respective goals by 2030. On August 3, 2015, the EPA released the final rule under Section 111(d) of the CAA, referred to as the Clean Power Plan. The final rule contains several changes from the proposed rule. The final rule requires states to adopt plans to collectively reduce 2005 levels of power sector CO₂ emissions by 32% by the year 2030. The final rule provides states until September 2018 to submit implementation plans and until 2022 (rather than 2020 under the proposed rule) to begin achieving emissions reductions.

In the final rule, the EPA used a procedure to determine the "best system of emission reduction" that was different than under the proposed rule, establishing two sets of uniform emissions rates (one for coal-fired EGUs and one for natural gas-fired EGUs) and developing state limits based on the number and type of affected EGUs in each state. For the final rule, the EPA analyzed emissions reductions that affected EGUs could achieve by applying three “building blocks,” that the EPA concluded met the statutory standard “best system of emission reduction”:


•	Building Block 1: Improving heat rate at existing coal-fired steam EGUs;


•	Building Block 2: Shifting electricity generation from higher-emitting coal-fired steam EGUs to lower-emitting existing natural gas combined cycle generation; and


•	Building Block 3: Shifting generation from affected fossil fuel-fired EGUs to new zero-emitting renewable energy generation.

The EPA also changed its approach to calculating the emissions targets. In the final rule, the EPA specified nationwide “sub-category” CO₂ emission performance standards applicable to affected steam coal-fired EGUs (1,305 lbs/MWh) and stationary natural gas combustion turbines (771 lbs/MWh). There are a number of methods states may use to achieve compliance. States may simply require affected EGUs to meet these emission rate standards. As in the proposed rule, the EPA also calculated statewide target emission rates, though the method used to calculate the state targets was different in the final rule. The EPA also included equivalent mass-based limits (in short tons) for each state, with the intent of making it easier for states to adopt intrastate or interstate allowance-based emissions trading programs. Other modifications to the proposed rule include an allowance for increased use of thermal generation due to hydroelectric plant variability, and adjustments for plants like the Langley Gulch natural gas power plant that commenced commercial operations during 2012.

Idaho Power's owned and co-owned generation facilities are in the states of Idaho, Nevada, Oregon, and Wyoming. Idaho Power is evaluating the impact that the final rule will have on its operations in those states. Idaho Power is working with state representatives, neighboring utilities, and others as it analyzes the rule and prepares for compliance. However, because the rule is premised on state implementation plans, the terms of which Idaho Power does not control, as of the date of this report Idaho Power is unable to determine the financial or operational impacts of the final rule.

National Ambient Air Quality Standards - Ozone Regulations

In late 2014, the EPA issued a proposed rule that would update the ground-level ozone standard under the CAA, from 75 parts per billion over an eight-hour period to 65 to 70 parts per billion over an eight-hour period. On October 1, 2015, the EPA issued a final rule lowering the national ozone standard under the CAA to 70 parts per billion. The EPA stated that the vast majority of U.S. counties will meet the standards by 2025 with federal and state rules and programs now in place or underway. The EPA's plan provides for finalizing non-attainment designations in 2017, and it plans to propose rules and guidance over the next year to help states with potential non-attainment areas implement the revised standards. Non-attainment areas will have until 2020 to late 2037 to meet the new standard, with attainment dates varying based on the ozone level in the area. Due to high levels of background ozone, which can be caused by factors such as elevation, vegetation, wildfire, and international transport, attainment in areas within the Intermountain West may be difficult, and the formulation of state implementation plans to bring an area into compliance with the new standard may be challenging due to the existence of ozone caused by factors outside of local control. If the EPA were to make non-attainment determinations in areas where Idaho Power owns or co-owns power plants, or proposes to construct power plants, the state implementation plan for those areas could result in changes to the nature and frequency of operation of existing generation plants and make more difficult or costly the construction of new power generation plants. However, as the EPA has not yet made attainment and non-attainment designations, Idaho Power is unable to predict the potential impact of the standard on its operations. Idaho Power will seek to work with state regulators on implementation plans for any non-attainment areas, in an effort to reduce the potential adverse impact on Idaho Power's operation of its existing power generation plants and construction of future facilities.

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Endangered Species Act Update

In 2010, the U.S. Fish and Wildlife Service announced that listing of the greater sage grouse as threatened or endangered under the Endangered Species Act was warranted but precluded by higher priority listing actions. Due to the presence of sage grouse in the vicinity of the Boardman-to-Hemingway and Gateway West 500-kV transmission lines, siting of these projects has required more extensive, costly, and time consuming evaluation, permitting, and engineering. Listing of the greater sage grouse as threatened or endangered would have resulted in the need for a Section 7 consultation under the Endangered Species Act, increasing the cost and time requirements for the permitting of these transmission projects. After evaluating scientific and other information regarding the greater sage-grouse, the U.S. Fish and Wildlife Service determined in September 2015 that protection for the greater sage-grouse under the Endangered Species Act is no longer warranted and withdrew the species from the candidate species list. This determination does not reduce the scope or magnitude of the consideration of sage grouse issues in Idaho Power's separate permitting processes for the transmission lines, but does eliminate the requirement for a Section 7 consultation with the U.S. Fish and Wildlife Service under the Endangered Species Act.

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, retirement benefits, contingencies, litigation, asset impairment, 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, 2014.

Recently Issued Accounting Pronouncements

The Financial Accounting Standards Board (FASB) 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, 2017, including interim periods within that reporting period, with early adoption permitted one year earlier. 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, 2018, amounts in 2016 and 2017 may have to be revised. IDACORP and Idaho Power are 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 material changes in these risks since December 31, 2014 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, 2015. IDACORP has not entered into any of these market-risk-sensitive instruments for trading purposes.

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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, 2015, IDACORP had $12.8 million in net floating rate debt. The fair market value of this debt was $12.8 million. Assuming no change in financial structure, if variable interest rates were to average one percentage point higher than the average rate on September 30, 2015, annual interest expense would increase and pre-tax earnings would decrease by approximately $0.1 million.

Fixed Rate Debt: As of September 30, 2015, IDACORP had $1.7 billion in fixed rate debt, with a fair market value of approximately $1.8 billion. These instruments are fixed rate and, therefore, do not expose the companies to a loss in earnings due to changes in market interest rates. However, the fair value of these instruments would increase by approximately $254 million if market interest rates were to decline by one percentage point from their September 30, 2015 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, 2015 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, 2014. 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, 2015, Idaho Power had posted $0.8 million 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, 2015, the amount of collateral that could be requested upon a downgrade to below investment grade was approximately $9.9 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, 2015 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, 2014. 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

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established asset allocation targets for the pension plan holdings, which are described in Note 10 - "Benefit Plans" to the consolidated financial statements included in IDACORP's Annual Report on Form 10-K for the year ended December 31, 2014. IDACORP’s equity price risk as of September 30, 2015 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, 2014.

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, 2015, 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, 2015, 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, 2015, that have materially affected, or are reasonably likely to materially affect, IDACORP’s or Idaho Power’s internal control over financial reporting.

PART II – OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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

ITEM 1A. RISK FACTORS

The factors discussed in Part I - Item 1A - “Risk Factors” in IDACORP’s and Idaho Power’s Annual Report on Form 10-K for the year ended December 31, 2014, 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 "Cautionary Note Regarding 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 6 - “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, 2015.

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

None

ITEM 6. EXHIBITS

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

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SIGNATURES

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



		IDACORP, INC.
		(Registrant)



Date:	October 29, 2015	By:	/s/ Darrel T. Anderson
			Darrel T. Anderson
			President and Chief Executive Officer

Date:	October 29, 2015	By:	/s/ Steven R. Keen
			Steven R. Keen
			Senior Vice President, Chief Financial
			Officer, and Treasurer





		IDAHO POWER COMPANY
		(Registrant)



Date:	October 29, 2015	By:	/s/ Darrel T. Anderson
			Darrel T. Anderson
			President and Chief Executive Officer

Date:	October 29, 2015	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, 2015:



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

10.1	First Amendment to Second Amended and Restated Credit Agreement, dated July 9, 2015, among IDACORP, Inc., Wells Fargo Bank, National Association, and the lenders a party thereto, amending the Second Amended and Restated Credit Agreement, dated October 26, 2011, among IDACORP, Inc., various lenders, Wells Fargo Bank, National Association, as administrative agent, swingline lender, and LC issuer, JPMorgan Chase Bank, N.A., as syndication agent and LC issuer, KeyBank National Association and Union Bank, N.A., as documentation agents, and Wells Fargo Securities, LLC, J.P. Morgan Securities Inc., Keybanc Capital Markets, and Union Bank, N.A. as joint lead arrangers and joint book runners	8-K	1-14465; 1-3198	10.1	7/10/2015
10.2	First Amendment to Second Amended and Restated Credit Agreement, dated July 9, 2015, among Idaho Power Company, Wells Fargo Bank, National Association, and the lenders a party thereto, amending the Second Amended and Restated Credit Agreement, dated October 26, 2011, among Idaho Power Company, various lenders, Wells Fargo Bank, National Association, as administrative agent, swingline lender, and LC issuer, JPMorgan Chase Bank, N.A., as syndication agent and LC issuer, KeyBank National Association and Union Bank, N.A., as documentation agents, and Wells Fargo Securities, LLC, J.P. Morgan Securities Inc., Keybanc Capital Markets, and Union Bank, N.A. as joint lead arrangers and joint book runners	8-K	1-14465; 1-3198	10.2	7/10/2015
10.3	Fifth Amendment to the Employee Savings Plan of Idaho Power Company, dated September 14, 2015					X
12.1	IDACORP, Inc. Computation of Ratio of Earnings to Fixed Charges and Supplemental Ratio of Earnings to Fixed Charges					X
12.2	Idaho Power Company Computation of Ratio of Earnings to Fixed Charges and Supplemental Ratio of Earnings to Fixed Charges					X
15.1	Letter Re: Unaudited Interim Financial Information					X
15.2	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

Exhibit 10.3

FIFTH AMENDMENT

TO THE EMPLOYEE SAVINGS PLAN OF

IDAHO POWER COMPANY

The Employee Savings Plan of Idaho Power Company, as amended and restated effective January 1, 2010 (the "Plan") is further amended, effective January 1, 2015, as set forth below.

1. A new Section 1.35 is added for clarity, to read as follows; the remaining subsections are renumbered; and all references to such subsections within the Plan are revised accordingly:

"1.35 Roth Deferral.

"Roth Deferral" means a Deferral Contribution, as defined in Section 1.13, that a Participant must include as income at the time of deferral and which the Participant designates irrevocably in a salary reduction agreement at the time of the deferral election, as a Roth Deferral."

2. Section 3.5 is amended to read as follows:

"Rollover Contributions shall be permitted, subject to the provisions of this Section. The Administrator may direct the Trustee to accept, in accordance with procedures approved by the Administrator, all or part of an Eligible Rollover Distribution for the benefit of a Participant from (i) the Participant, (ii) another Qualified Plan, including, in a trustee-to-trustee transfer, After-Tax Contributions or Roth Deferrals to that plan, (iii) an annuity contract described in Code section 403(b), (iv) an individual retirement account (except a Roth IRA) or annuity as defined in Code sections 408(a) or 408(b) that is eligible to be rolled over and otherwise would be includible in gross income, or (v) an eligible plan under Code section 457(b) which is maintained by a state, political subdivision of a state, or any agency or instrumentality of a state or political subdivision of a state. The approved procedures shall require that the Administrator or Trustee reasonably conclude that any accepted Eligible Rollover Distribution is a valid rollover contribution in accordance with Treasury regulations and guidance."

3. Section 7.11.3 is amended to read as follows:

"Notwithstanding the foregoing, a Distributee may make an election under this Section only if the total amount of all Eligible Rollover Distributions made to such Distributee during a year is reasonably expected to exceed $200. Furthermore, if a Distributee elects to have only a portion of an Eligible Rollover Distribution paid in a Direct Rollover, the portion paid in a Direct Rollover must equal at least $500. If a Distributee's Eligible Rollover Distribution is $500 or less, he or she may make an election only to have all of such distribution paid in a Direct Rollover. Effective January 1, 2015, if a Participant's Account includes both pre-tax and after-tax (including Roth) amounts, any Eligible Rollover Distribution which is paid in whole or in part in a Direct Rollover shall be allocated between the pre-tax and after-tax amounts in accordance with Notice 2014-54."

4. Section 11.2.2 is amended to read as follows:

"The maximum principal amount of any loan is the lesser of (i) fifty percent (50%) of the balance of the Participant's Account, determined on the day of the loan, minus the balance of all other loans from all other qualified plans of the Employer, outstanding on that date, or (ii) $50,000, minus the highest outstanding principal balance of loans from the Plan, and from all other qualified plans of the Employer, to the Participant during the period of one year ending on the day preceding the origination of the loan being requested.

Amounts held in a Self-Directed Brokerage Fund, if any, and/or Roth Accounts will be included in the calculation of the maximum principal amount available for a loan but may not be used as a source for a loan. Therefore, if a Participant has amounts in a Self-Directed Brokerage Fund or a Roth Account, the maximum that the Participant may borrow is the lesser of the maximum available amount calculated according to the formula described above or the Participant's Account balance minus the portion held in the Participant's Self-Directed Brokerage Fund and/or Roth Account."

5. Article 15 is amended to read as follows:

"15.1 Right of Company to Amend Plan.

The Company reserves for itself, by and through one or more of its officers acting on behalf of the Company in its capacity as Plan Sponsor, the right to alter, amend, revoke or terminate this Plan. No amendment will (i) increase the duties or liabilities of the Trustee without its written consent; (ii) cause a reversion of Plan assets to the Employers not otherwise permitted under the Plan; (iii) have the effect of reducing the percentage of the vested and nonforfeitable interest of any Participant in his or her Accounts, (iv) amend the vesting provisions of the Plan unless each Participant with at least three Years of Service (including Years of Service disregarded pursuant to the reemployment provisions herein) is permitted to elect within 60 days after the latest of the date on which the amendment is adopted, the date on which the amendment is effective and the date on which the Participant is issued written notice of the amendment, to continue to have the prior vesting provisions apply; or (iv) be effective to the extent that it has the effect of decreasing a Participant's Account balance or eliminating an optional form of distribution as it applies to an existing Account balance, except as may be permitted by Treasury regulations.

15.2 Amendment Procedure.

Any amendment to the Plan will be evidenced in writing. Upon execution of the amendment by an officer of the Company, the Plan shall be deemed amended as of the effective date specified in the amendment. If no effective date is specified, the effective date shall be the date of execution of the amendment. The effective date may be before, on or after the date of execution and before, on or after the date of any action taken with respect to such amendment.

15.3 Effect on Employers.

Unless an amendment expressly provides otherwise, all Employers will be bound by any amendment to the Plan."

IN WITNESS WHEREOF, the Company has executed this Amendment this 14^th day of September, 2015.

IDAHO POWER COMPANY

By: /s/ Lonnie G. Krawl

Lonnie G. Krawl


Its:	Vice President of Human

Resources, Administrative Services

and Chief Information Officer

Exhibit 12.1

IDACORP, Inc.

Consolidated Financial Information

Ratio of Earnings to Fixed Charges and Supplemental Ratio of Earnings to Fixed Charges

(Thousands of Dollars)



	Nine months ended September 30,		Twelve Months Ended
			December 31,
	2015		2014			2013		2012		2011			2010
RATIO OF EARNINGS TO FIXED CHARGES

Earnings, as defined:
Income from continuing operations before income taxes	$	202,078	$	210,526		$	254,520	$	206,992	$	125,795		$	152,568
Adjust for distributed income of equity investees	716		(6,797		)	4,812		7,704		(8,993		)	(7,317		)
Fixed charges, as below	69,898		90,012			90,236		87,635		86,758			86,806
Total earnings, as defined	$	272,692	$	293,741		$	349,568	$	302,331	$	203,560		$	232,057

Fixed charges, as defined:
Interest charges ⁽¹⁾	$	68,927	$	88,265		$	88,695	$	85,799	$	85,097		$	85,840
Rental interest factor	971		1,747			1,541		1,836		1,661			966
Total fixed charges, as defined	$	69,898	$	90,012		$	90,236	$	87,635	$	86,758		$	86,806
Ratio of earnings to fixed charges	3.90x		3.26x			3.87x		3.45x		2.35x			2.67x

SUPPLEMENTAL RATIO OF EARNINGS TO FIXED CHARGES

Earnings, as defined:
Income from continuing operations before income taxes	$	202,078	$	210,526		$	254,520	$	206,992	$	125,795		$	152,568
Adjust for distributed income of equity investees	716		(6,797		)	4,812		7,704		(8,993		)	(7,317		)
Supplemental fixed charges, as below	70,084		90,356			90,741		88,266		87,544			87,870
Total earnings, as defined	$	272,878	$	294,085		$	350,073	$	302,962	$	204,346		$	233,121

Supplemental fixed charges:
Interest charges ⁽¹⁾	$	68,927	$	88,265		$	88,695	$	85,799	$	85,097		$	85,840
Rental interest factor	971		1,747			1,541		1,836		1,661			966
Supplemental increment to fixed charges ⁽²⁾	186		344			505		631		786			1,064
Total supplemental fixed charges	$	70,084	$	90,356		$	90,741	$	88,266	$	87,544		$	87,870
Supplemental ratio of earnings to fixed charges	3.89x		3.25x			3.86x		3.43x		2.33x			2.65x

⁽¹⁾FIN 48 interest is not included in interest charges.
⁽²⁾ Explanation of increment - Interest on the guaranty of American Falls Reservoir District bonds and Milner Dam, Inc. notes which are already included in operation expenses.

Exhibit 12.2

Idaho Power Company

Consolidated Financial Information

Ratio of Earnings to Fixed Charges and Supplemental Ratio of Earnings to Fixed Charges

(Thousands of Dollars)



	Nine months ended September 30,		Twelve Months Ended
			December 31,
	2015		2014			2013		2012		2011			2010
RATIO OF EARNINGS TO FIXED CHARGES

Earnings, as defined:
Income from continuing operations before income taxes	$	200,400	$	208,903		$	253,001	$	204,138	$	123,351		$	151,347
Adjust for distributed income of equity investees	1,510		(7,228		)	4,659		8,509		(9,018		)	(6,526		)
Fixed charges, as below	69,703		89,751			89,819		87,162		86,249			85,579
Total earnings, as defined	$	271,613	$	291,426		$	347,479	$	299,809	$	200,582		$	230,400

Fixed charges, as defined:
Interest charges ⁽¹⁾	$	68,754	$	88,034		$	88,309	$	85,359	$	84,626		$	84,651
Rental interest factor	949		1,717			1,510		1,803		1,623			928
Total fixed charges, as defined	$	69,703	$	89,751		$	89,819	$	87,162	$	86,249		$	85,579
Ratio of earnings to fixed charges	3.90x		3.25x			3.87x		3.44x		2.33x			2.69x

SUPPLEMENTAL RATIO OF EARNINGS TO FIXED CHARGES

Earnings, as defined:
Income from continuing operations before income taxes	$	200,400	$	208,903		$	253,001	$	204,138	$	123,351		$	151,347
Adjust for distributed income of equity investees	1,510		(7,228		)	4,659		8,509		(9,018		)	(6,526		)
Supplemental fixed charges, as below	69,889		90,095			90,324		87,793		87,035			86,643
Total earnings, as defined	$	271,799	$	291,770		$	347,984	$	300,440	$	201,368		$	231,464

Supplemental fixed charges:
Interest charges ⁽¹⁾	$	68,754	$	88,034		$	88,309	$	85,359	$	84,626		$	84,651
Rental interest factor	949		1,717			1,510		1,803		1,623			928
Supplemental increment to fixed charges ⁽²⁾	186		344			505		631		786			1,064
Total supplemental fixed charges	$	69,889	$	90,095		$	90,324	$	87,793	$	87,035		$	86,643
Supplemental ratio of earnings to fixed charges	3.89x		3.24x			3.85x		3.42x		2.31x			2.67x

⁽¹⁾FIN 48 interest is not included in interest charges.
⁽²⁾ Explanation of increment - Interest on the guaranty of American Falls Reservoir District bonds and Milner Dam, Inc. notes which are already included in operation expenses.

Exhibit 15.1

October 29, 2015

IDACORP, Inc.

Boise, Idaho

We have reviewed, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the unaudited interim financial information of IDACORP, Inc. and subsidiaries for the periods ended September 30, 2015, and 2014, as indicated in our report dated October 29, 2015; because we did not perform an audit, we expressed no opinion on that information.

We are aware that our report referred to above, which is included in your Quarterly Report on Form 10-Q for the quarter ended September 30, 2015, is incorporated by reference in Registration Statement Nos. 333-200399 and 333-188768 on Form S-3 and Registration Statement Nos. 333-65406, 333-125259, 333-143404, and 333-159855 on Form S-8.

We also are aware that the aforementioned report, pursuant to Rule 436(c) under the Securities Act of 1933, is not considered a part of the Registration Statement prepared or certified by an accountant or a report prepared or certified by an accountant within the meaning of Sections 7 and 11 of that Act.

/s/ DELOITTE & TOUCHE LLP

Boise, Idaho

Exhibit 15.2

October 29, 2015

Idaho Power Company

Boise, Idaho

We have reviewed, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the unaudited interim financial information of Idaho Power Company and subsidiary for the periods ended September 30, 2015, and 2014, as indicated in our report dated October 29, 2015; because we did not perform an audit, we expressed no opinion on that information.

We are aware that our report referred to above, which is included in your Quarterly Report on Form 10-Q for the quarter ended September 30, 2015, is incorporated by reference in Registration Statement No. 333-188768-01 on Form S-3 and Registration Statement No. 333-66496 on Form S-8.

/s/ DELOITTE & TOUCHE LLP

Boise, Idaho

Exhibit 31.1

CERTIFICATION

I, Darrel T. Anderson, certify that:


1.	I have reviewed this Quarterly Report on Form 10-Q of IDACORP, Inc.;


2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;


4.	The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:


a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


c)	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


d)	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and


5.	The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):


a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and


b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.



Date:	October 29, 2015	By:	/s/ Darrel T. Anderson
			Darrel T. Anderson
			President and Chief Executive Officer

Exhibit 31.2

CERTIFICATION

I, Steven R. Keen, certify that:


1.	I have reviewed this Quarterly Report on Form 10-Q of IDACORP, Inc.;


2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;


4.	The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:


a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


c)	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


d)	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and


5.	The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):


a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and


b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.



Date:	October 29, 2015	By:	/s/ Steven R. Keen
			Steven R. Keen
			Senior Vice President, Chief Financial Officer, and Treasurer

Exhibit 31.3

CERTIFICATION

I, Darrel T. Anderson, certify that:


1.	I have reviewed this Quarterly Report on Form 10-Q of Idaho Power Company;


2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;


4.	The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:


a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


c)	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


d)	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and


5.	The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):


a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and


b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.



Date:	October 29, 2015	By:	/s/ Darrel T. Anderson
			Darrel T. Anderson
			President and Chief Executive Officer

Exhibit 31.4

CERTIFICATION

I, Steven R. Keen, certify that:


1.	I have reviewed this Quarterly Report on Form 10-Q of Idaho Power Company;


2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;


4.	The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:


a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


c)	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


d)	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and


5.	The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):


a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and


b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.



Date:	October 29, 2015	By:	/s/ Steven R. Keen
			Steven R. Keen
			Senior Vice President, Chief Financial Officer, and Treasurer

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of IDACORP, Inc. (the "Company") on Form 10-Q for the quarter ended September 30, 2015 (the "Report"), I, Darrel T. Anderson, President and Chief Executive Officer of the Company, certify that:


(1)	The Report fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934; and


(2)	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Darrel T. Anderson

Darrel T. Anderson

President and Chief Executive Officer

October 29, 2015

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of IDACORP, Inc. (the "Company") on Form 10-Q for the quarter ended September 30, 2015 (the "Report"), I, Steven R. Keen, Senior Vice President, Chief Financial Officer, and Treasurer of the Company, certify that:


(1)	The Report fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934; and


(2)	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Steven R. Keen

Steven R. Keen

Senior Vice President, Chief Financial Officer, and Treasurer

October 29, 2015

Exhibit 32.3

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Idaho Power Company (the "Company") on Form 10-Q for the quarter ended September 30, 2015 (the "Report"), I, Darrel T. Anderson, President and Chief Executive Officer of the Company, certify that:


(1)	The Report fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934; and


(2)	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Darrel T. Anderson

Darrel T. Anderson

President and Chief Executive Officer

October 29, 2015

Exhibit 32.4

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Idaho Power Company (the "Company") on Form 10-Q for the quarter ended September 30, 2015 (the "Report"), I, Steven R. Keen, Senior Vice President, Chief Financial Officer, and Treasurer of the Company, certify that:


(1)	The Report fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934; and


(2)	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Steven R. Keen

Steven R. Keen

Senior Vice President, Chief Financial Officer, and Treasurer

October 29, 2015

Exhibit 95.1

Mine Safety Disclosures Required by the Dodd-Frank Wall Street Reform and Consumer Protection Act

Idaho Power is the parent company of Idaho Energy Resources Co. (IERCo), a joint venturer in Bridger Coal Company (BCC), which mines coal at the Bridger Coal Mine and processing facility (Mine) near Rock Springs, Wyoming. IERCo owns a one-third interest in BCC. The Mine is comprised of the Bridger surface and underground operations. Day-to-day operation and management of coal mining and processing operations at the Mine are conducted through IERCo's joint venture partner. Operation of the Mine is regulated by the Mine Safety and Health Administration (MSHA) under the Federal Mine Safety and Health Act of 1977 (Mine Safety Act). MSHA inspects the Mine on a regular basis and may issue citations, notices, orders, or any combination thereof, when it believes a violation has occurred under the Mine Safety Act. Monetary penalties are assessed by MSHA for citations. The severity and assessment of penalties may be reduced or, in some cases, dismissed through the contest and appeal process. Amounts are reported regardless of whether BCC has challenged or appealed the matter.

The table below summarizes the number of citations, notices, and orders issued, and penalties assessed, by MSHA for the Mine under the indicated provisions of the Mine Safety Act, and other data for the Mine, during the three-month period ended September 30, 2015. Legal actions pending before the Federal Mine Safety and Health Review Commission (FMSHRC) are as of September 30, 2015. Due to timing and other factors, the data may not agree with the mine data retrieval system maintained by MSHA at www.msha.gov.



			Three-month period ended September 30, 2015
			(unaudited)
			Surface Mine (MSHA ID No. 4800677)		Underground Mine (MSHA ID No. 4801646)
Mine Safety Act Citations and Orders:
	Section 104(a) Significant & Substantial Citations ⁽¹⁾		3		9
	Section 104(b) Orders ⁽²⁾		—		—
	Section 104(d) Citations & Orders ⁽³⁾		—		—
	Section 107(a) Imminent Danger Orders ⁽⁴⁾		—		—

Total Value of Proposed MSHA Assessments (in thousands)		$	213	$	40
Legal Actions Pending ⁽⁵⁾			6		2
Legal Actions Issued During Period			3		2
Legal Actions Closed During Period			—		5
Number of Fatalities			—		—
_________________
⁽¹⁾ For alleged violations of a mandatory mining safety standard or regulation where such violation contributed to a discrete safety hazard and there exists a reasonable likelihood that the hazard will result in an injury or illness and there is a reasonable likelihood that such injury will be of a reasonably serious nature.
⁽²⁾For alleged failure to totally abate the subject matter of a Mine Safety Act Section 104(a) citation within the period specified in the citation or as subsequently extended.
⁽³⁾For an alleged unwarrantable failure (i.e., aggravated conduct constituting more than ordinary negligence) to comply with a mining safety standard or regulation.
⁽⁴⁾ The existence of any condition or practice in a coal or other mine that could reasonably be expected to cause death or serious physical harm if normal mining operations were permitted to proceed in the area before such condition or practice is eliminated.
⁽⁵⁾For the surface mine, two of the pending legal actions were categorized as contests of civil citations or orders under Subpart B of the FMSHRC Procedural Rules and four of the pending legal actions were categorized as contests of proposed civil penalties for violations contained in a citation or order under Subpart C of the FMSHRC Procedural Rules. For the underground mine, both of the pending legal actions were categorized as contests of proposed civil penalties for violations contained in a citation or order under Subpart C of the FMSHRC Procedural Rules.

For the three-month period ended September 30, 2015, the Mine did not receive written notice from MSHA of (i) a flagrant violation under Section 110(b)(2) of the Mine Safety Act; (ii) a pattern of violations of mandatory health or safety standards that are of such a nature as could have significantly and substantially contributed to the cause and effect of coal or other mine health or safety hazards under Section 104(e) of the Mine Safety Act; or (iii) the potential to have such a pattern.

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