IDACORP INC - FORM 10-Q - October 27, 2016

IDACORP INC - FORM 10-Q - October 27, 2016

Attached files

Attached files

IDACORP INC Reports

file	filename
EX-31.2 - CERTIFICATION OF IDACORP, INC. CHIEF FINANCIAL OFFICER PURSUANT TO 18 U.S.C - IDACORP INC	ida93016ex312.htm
EX-95.1 - MINE SAFETY DISCLOSURES - IDACORP INC	ida93016ex951-minesafety1.htm
EX-32.4 - CERTIFICATION OF IDAHO POWER COMPANY CHIEF FINANCIAL OFFICER PURSUANT TO 18 U.S. - IDACORP INC	ida93016ex324.htm
EX-32.3 - CERTIFICATION OF IDAHO POWER COMPANY CHIEF EXECUTIVE OFFICER PURSUANT TO 18 U.S. - IDACORP INC	ida93016ex323.htm
EX-32.2 - CERTIFICATION OF IDACORP, INC. CHIEF FINANCIAL OFFICER PURSUANT TO 18 U.S.C. - IDACORP INC	ida93016ex322.htm
EX-32.1 - CERTIFICATION OF IDACORP, INC. CHIEF EXECUTIVE OFFICER PURSUANT TO 18 U.S.C. - IDACORP INC	ida93016ex321.htm
EX-31.4 - CERTIFICATION OF IDAHO POWER COMPANY CHIEF FINANCIAL OFFICER PURSUANT TO SECTION - IDACORP INC	ida93016ex314.htm
EX-31.3 - CERTIFICATION OF IDAHO POWER COMPANY CHIEF EXECUTIVE OFFICER PURSUANT TO SECTION - IDACORP INC	ida93016ex313.htm
EX-31.1 - CERTIFICATION OF IDACORP, INC. CHIEF EXECUTIVE OFFICER PURSUANT TO SECTION 302 - IDACORP INC	ida93016ex311.htm
EX-15.2 - IDAHO POWER LETTER RE: UNAUDITED INTERIM FINANCIAL INFORMATION - IDACORP INC	ida93016ex152.htm
EX-15.1 - IDACORP, INC. LETTER RE: UNAUDITED INTERIM FINANCIAL INFORMATION - IDACORP INC	ida93016ex151.htm
EX-12.2 - IDAHO POWER COMPANY COMPUTATION OF EARNINGS TO FIXED CHARGES - IDACORP INC	ida93016ex122.htm
EX-12.1 - IDACORP, INC. COMPUTATION OF EARNINGS TO FIXED CHARGES - IDACORP INC	ida93016ex121.htm

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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, 2016
	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 21, 2016:

IDACORP, Inc.: 50,401,768

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 Condensed Consolidated Financial Statements		17
		Reports of Independent Registered Public Accounting Firm		31
	Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations			33
	Item 3. Quantitative and Qualitative Disclosures About Market Risk			55
	Item 4. Controls and Procedures			56

Part II. Other Information

	Item 1. Legal Proceedings			56
	Item 1A. Risk Factors			56
	Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			56
	Item 3. Defaults Upon Senior Securities			57
	Item 4. Mine Safety Disclosures			57
	Item 5. Other Information			57
	Item 6. Exhibits			57

Signatures				58

Exhibit Index				59

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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, 2015, 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 U.S. Securities and Exchange Commission (SEC), 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;


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


•	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, and the availability of regulatory mechanisms that allow for timely cost recovery in the event of those changes;


•	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 may impact the amount of power generated by Idaho Power's hydroelectric facilities;


•	the ability to acquire 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 (either at or caused by Idaho Power's facilities), explosions, and mechanical breakdowns that may occur while operating and maintaining Idaho Power's assets, 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;


•	operational factors affecting Idaho Power's power generating facilities, including disruptions or outages of Idaho Power's generation or transmission systems or of any interconnected transmission system, which may cause Idaho Power to incur repair costs or purchase replacement power at increased costs;


•	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;

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•	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;


•	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, regulations, and orders, 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 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;


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


•	the expense and risks associated with capital expenditures for infrastructure, and the timing and availability of cost recovery for such expenditures.

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,
	2016			2015			2016			2015
	(thousands of dollars, except for per share amounts)
Operating Revenues:
Electric utility:
General business	$	341,825		$	340,796		$	885,486		$	897,943
Off-system sales	6,143			6,487			16,532			23,335
Other revenues	23,506			21,234			64,433			61,334
Total electric utility revenues	371,474			368,517			966,451			982,612
Other	571			648			1,986			2,277
Total operating revenues	372,045			369,165			968,437			984,889
Operating Expenses:
Electric utility:
Purchased power	74,448			71,890			170,675			166,191
Fuel expense	73,925			66,385			139,657			144,262
Power cost adjustment	(18,342		)	(11,914		)	11,914			26,372
Other operations and maintenance	87,090			83,972			259,813			255,329
Energy efficiency programs	9,102			7,645			24,256			19,854
Depreciation	36,036			34,639			107,447			102,996
Taxes other than income taxes	8,287			8,286			25,228			24,999
Total electric utility expenses	270,546			260,903			738,990			740,003
Other	3,571			3,598			10,748			11,340
Total operating expenses	274,117			264,501			749,738			751,343
Operating Income	97,928			104,664			218,699			233,546
Allowance for Equity Funds Used During Construction	5,931			5,654			16,153			16,219
Earnings of Unconsolidated Equity-Method Investments	12,324			5,527			13,650			8,636
Other Income, Net	2,681			1,222			7,074			5,054
Interest Expense:
Interest on long-term debt	20,296			20,614			61,659			62,443
Other interest	2,605			2,256			7,587			6,484
Allowance for borrowed funds used during construction	(2,589		)	(2,593		)	(7,226		)	(7,550		)
Total interest expense, net	20,312			20,277			62,020			61,377
Income Before Income Taxes	98,552			96,790			193,556			202,078
Income Tax Expense	15,535			23,523			28,622			39,276
Net Income	83,017			73,267			164,934			162,802
Adjustment for loss attributable to noncontrolling interests	83			69			141			45
Net Income Attributable to IDACORP, Inc.	$	83,100		$	73,336		$	165,075		$	162,847
Weighted Average Common Shares Outstanding - Basic (000’s)	50,296			50,219			50,299			50,221
Weighted Average Common Shares Outstanding - Diluted (000’s)	50,393			50,324			50,361			50,282
Earnings Per Share of Common Stock:
Earnings Attributable to IDACORP, Inc. - Basic	$	1.65		$	1.46		$	3.28		$	3.24
Earnings Attributable to IDACORP, Inc. - Diluted	$	1.65		$	1.46		$	3.28		$	3.24
Dividends Declared Per Share of Common Stock	$	0.51		$	0.47		$	1.53		$	1.41

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,
	2016		2015		2016		2015
	(thousands of dollars)

Net Income	$	83,017	$	73,267	$	164,934	$	162,802
Other Comprehensive Income:
Unfunded pension liability adjustment, net of tax of $362, $428, $1,085 and $1,284	563		667		1,690		2,001
Total Comprehensive Income	83,580		73,934		166,624		164,803
Comprehensive loss attributable to noncontrolling interests	83		69		141		45
Comprehensive Income Attributable to IDACORP, Inc.	$	83,663	$	74,003	$	166,765	$	164,848

The accompanying notes are an integral part of these statements.

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IDACORP, Inc.

Condensed Consolidated Balance Sheets

(unaudited)



	September 30, 2016			December 31, 2015
	(thousands of dollars)
Assets

Current Assets:
Cash and cash equivalents	$	100,796		$	114,802
Receivables:
Customer (net of allowance of $987 and $1,196, respectively)	86,215			73,505
Other (net of allowance of $260 and $159, respectively)	7,229			8,642
Taxes receivable	13,866			13,058
Accrued unbilled revenues	59,877			65,805
Materials and supplies (at average cost)	58,686			56,924
Fuel stock (at average cost)	60,257			61,818
Prepayments	15,600			17,979
Current regulatory assets	54,366			49,215
Other	2,997			288
Total current assets	459,889			462,036
Investments	131,225			140,743
Property, Plant and Equipment:
Utility plant in service	5,582,890			5,485,464
Accumulated provision for depreciation	(1,982,496		)	(1,913,927		)
Utility plant in service - net	3,600,394			3,571,537
Construction work in progress	471,331			396,931
Utility plant held for future use	7,457			7,090
Other property, net of accumulated depreciation	16,242			16,855
Property, plant and equipment - net	4,095,424			3,992,413
Other Assets:
American Falls and Milner water rights	9,747			11,592
Company-owned life insurance	57,508			48,566
Regulatory assets	1,298,519			1,305,210
Long-term receivables (net of allowance of $552)	23,242			22,538
Other	53,555			40,216
Total other assets	1,442,571			1,428,122
Total	$	6,129,109		$	6,023,314

The accompanying notes are an integral part of these statements.

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IDACORP, Inc.

Condensed Consolidated Balance Sheets

(unaudited)



	September 30, 2016			December 31, 2015
	(thousands of dollars)
Liabilities and Equity

Current Liabilities:
Current maturities of long-term debt	$	1,064		$	1,064
Notes payable	5,400			20,000
Accounts payable	77,895			95,526
Taxes accrued	20,260			10,762
Interest accrued	21,405			22,292
Accrued compensation	39,374			42,961
Current regulatory liabilities	3,011			2,217
Advances from customers	26,615			31,214
Other	10,267			16,270
Total current liabilities	205,291			242,306
Other Liabilities:
Deferred income taxes	1,169,918			1,137,375
Regulatory liabilities	434,464			416,282
Pension and other postretirement benefits	375,814			394,030
Other	45,412			45,867
Total other liabilities	2,025,608			1,993,554
Long-Term Debt	1,745,548			1,725,410
Commitments and Contingencies
Equity:
IDACORP, Inc. shareholders’ equity:
Common stock, no par value (shares authorized 120,000,000; 50,420,017 and 50,352,051 shares issued, respectively)	850,698			849,112
Retained earnings	1,317,732			1,230,105
Accumulated other comprehensive loss	(19,586		)	(21,276		)
Treasury stock (18,249 and 11,221 shares at cost, respectively)	(201		)	(57		)
Total IDACORP, Inc. shareholders’ equity	2,148,643			2,057,884
Noncontrolling interests	4,019			4,160
Total equity	2,152,662			2,062,044
Total	$	6,129,109		$	6,023,314

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,
	2016			2015
	(thousands of dollars)
Operating Activities:
Net income	$	164,934		$	162,802
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	110,161			106,304
Deferred income taxes and investment tax credits	30,077			25,265
Changes in regulatory assets and liabilities	13,502			25,776
Pension and postretirement benefit plan expense	22,175			22,668
Contributions to pension and postretirement benefit plans	(43,851		)	(41,660		)
Earnings of unconsolidated equity-method investments	(13,650		)	(8,636		)
Distributions from unconsolidated equity-method investments	17,114			9,352
Allowance for equity funds used during construction	(16,153		)	(16,219		)
Other non-cash adjustments to net income, net	3,876			1,444
Change in:
Accounts receivable	(12,435		)	(14,704		)
Accounts payable and other accrued liabilities	(10,033		)	(12,210		)
Taxes accrued/receivable	8,490			19,845
Other current assets	7,343			(178		)
Other current liabilities	(5,451		)	7,874
Other assets	(1,277		)	2,468
Other liabilities	595			629
Net cash provided by operating activities	275,417			290,820
Investing Activities:
Additions to property, plant and equipment	(199,966		)	(235,890		)
Payments received from transmission project joint funding partners	6,853			—
Proceeds from the sale of emission allowances and renewable energy certificates	969			1,855
Purchase of available-for-sale securities	(9,843		)	(469		)
Proceeds from the sale of available-for-sale securities	14,453			2,724
Purchase of life insurance investment	(10,000		)	—
Other	(9		)	(1,132		)
Net cash used in investing activities	(197,543		)	(232,912		)
Financing Activities:
Issuance of long-term debt	120,000			250,000
Retirement of long-term debt	(101,064		)	(121,064		)
Dividends on common stock	(77,350		)	(71,225		)
Net change in short-term borrowings	(14,600		)	(27,700		)
Acquisition of treasury stock	(3,287		)	(3,277		)
Make-whole premium on retirement of long-term debt	(13,895		)	(17,872		)
Other	(1,684		)	(2,318		)
Net cash (used in) provided by financing activities	(91,880		)	6,544
Net (decrease) increase in cash and cash equivalents	(14,006		)	64,452
Cash and cash equivalents at beginning of the period	114,802			56,808
Cash and cash equivalents at end of the period	$	100,796		$	121,260
Supplemental Disclosure of Cash Flow Information:
Cash paid during the period for:
Income taxes	$	2,187		$	4,442
Interest (net of amount capitalized)	$	60,224		$	57,630
Non-cash investing activities:
Additions to property, plant and equipment in accounts payable	$	21,583		$	12,606

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,
	2016			2015
	(thousands of dollars)
Common Stock
Balance at beginning of period	$	849,112		$	845,402
Cumulative effect of change in accounting principle	234			—
Other	1,352			2,601
Balance at end of period	850,698			848,003
Retained Earnings
Balance at beginning of period	1,230,105			1,132,237
Cumulative effect of change in accounting principle	(234		)	—
Net income attributable to IDACORP, Inc.	165,075			162,847
Common stock dividends ($1.53 and $1.41 per share)	(77,214		)	(71,059		)
Balance at end of period	1,317,732			1,224,025
Accumulated Other Comprehensive (Loss) Income
Balance at beginning of period	(21,276		)	(24,158		)
Unfunded pension liability adjustment (net of tax)	1,690			2,001
Balance at end of period	(19,586		)	(22,157		)
Treasury Stock
Balance at beginning of period	(57		)	(280		)
Issued	3,143			3,500
Acquired	(3,287		)	(3,277		)
Balance at end of period	(201		)	(57		)
Total IDACORP, Inc. shareholders’ equity at end of period	2,148,643			2,049,814
Noncontrolling Interests
Balance at beginning of period	4,160			4,364
Net loss attributable to noncontrolling interests	(141		)	(45		)
Balance at end of period	4,019			4,319
Total equity at end of period	$	2,152,662		$	2,054,133

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,
	2016			2015			2016			2015
	(thousands of dollars)
Operating Revenues:
General business	$	341,825		$	340,796		$	885,486		$	897,943
Off-system sales	6,143			6,487			16,532			23,335
Other revenues	23,506			21,234			64,433			61,334
Total operating revenues	371,474			368,517			966,451			982,612
Operating Expenses:
Operation:
Purchased power	74,448			71,890			170,675			166,191
Fuel expense	73,925			66,385			139,657			144,262
Power cost adjustment	(18,342		)	(11,914		)	11,914			26,372
Other operations and maintenance	87,090			83,972			259,813			255,329
Energy efficiency programs	9,102			7,645			24,256			19,854
Depreciation	36,036			34,639			107,447			102,996
Taxes other than income taxes	8,287			8,286			25,228			24,999
Total operating expenses	270,546			260,903			738,990			740,003
Income from Operations	100,928			107,614			227,461			242,609
Other Income (Expense):
Allowance for equity funds used during construction	5,931			5,654			16,153			16,219
Earnings of unconsolidated equity-method investments	11,121			4,334			11,528			6,992
Other expense, net	(328		)	(1,755		)	(1,845		)	(4,216		)
Total other income	16,724			8,233			25,836			18,995
Interest Charges:
Interest on long-term debt	20,296			20,614			61,659			62,443
Other interest	2,546			2,204			7,397			6,311
Allowance for borrowed funds used during construction	(2,589		)	(2,593		)	(7,226		)	(7,550		)
Total interest charges	20,253			20,225			61,830			61,204
Income Before Income Taxes	97,399			95,622			191,467			200,400
Income Tax Expense	17,370			23,895			31,097			40,872
Net Income	$	80,029		$	71,727		$	160,370		$	159,528

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,
	2016		2015		2016		2015
	(thousands of dollars)

Net Income	$	80,029	$	71,727	$	160,370	$	159,528
Other Comprehensive Income:
Unfunded pension liability adjustment, net of tax of $362, $428, $1,085 and $1,284	563		667		1,690		2,001
Total Comprehensive Income	$	80,592	$	72,394	$	162,060	$	161,529

The accompanying notes are an integral part of these statements.

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Idaho Power Company

Condensed Consolidated Balance Sheets

(unaudited)



	September 30, 2016			December 31, 2015
	(thousands of dollars)
Assets

Electric Plant:
In service (at original cost)	$	5,582,890		$	5,485,464
Accumulated provision for depreciation	(1,982,496		)	(1,913,927		)
In service - net	3,600,394			3,571,537
Construction work in progress	471,331			396,931
Held for future use	7,457			7,090
Electric plant - net	4,079,182			3,975,558
Investments and Other Property	111,994			121,267
Current Assets:
Cash and cash equivalents	88,936			110,756
Receivables:
Customer (net of allowance of $987 and $1,196, respectively)	86,215			73,505
Other (net of allowance of $260 and $159, respectively)	7,122			8,520
Taxes receivable	6,776			5,432
Accrued unbilled revenues	59,877			65,805
Materials and supplies (at average cost)	58,686			56,924
Fuel stock (at average cost)	60,257			61,818
Prepayments	15,483			17,846
Current regulatory assets	54,366			49,215
Other	2,997			288
Total current assets	440,715			450,109
Deferred Debits:
American Falls and Milner water rights	9,747			11,592
Company-owned life insurance	57,508			48,566
Regulatory assets	1,298,519			1,305,210
Other	70,693			56,533
Total deferred debits	1,436,467			1,421,901
Total	$	6,068,358		$	5,968,835

The accompanying notes are an integral part of these statements.

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Idaho Power Company

Condensed Consolidated Balance Sheets

(unaudited)



	September 30, 2016			December 31, 2015
	(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	1,210,430			1,127,426
Accumulated other comprehensive loss	(19,586		)	(21,276		)
Total common stock equity	1,998,882			1,914,188
Long-term debt	1,745,548			1,725,410
Total capitalization	3,744,430			3,639,598
Current Liabilities:
Current maturities of long-term debt	1,064			1,064
Accounts payable	77,557			94,970
Accounts payable to affiliates	1,189			1,059
Taxes accrued	20,261			10,745
Interest accrued	21,405			22,292
Accrued compensation	39,248			42,835
Current regulatory liabilities	3,011			2,217
Advances from customers	26,615			31,214
Other	9,700			15,506
Total current liabilities	200,050			221,902
Deferred Credits:
Deferred income taxes	1,269,208			1,252,371
Regulatory liabilities	434,464			416,282
Pension and other postretirement benefits	375,814			394,030
Other	44,392			44,652
Total deferred credits	2,123,878			2,107,335

Commitments and Contingencies

Total	$	6,068,358		$	5,968,835

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,
	2016			2015
	(thousands of dollars)
Operating Activities:
Net income	$	160,370		$	159,528
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	109,704			105,848
Deferred income taxes and investment tax credits	12,679			(5,307		)
Changes in regulatory assets and liabilities	13,502			25,776
Pension and postretirement benefit plan expense	22,191			22,646
Contributions to pension and postretirement benefit plans	(43,867		)	(41,638		)
Earnings of unconsolidated equity-method investments	(11,528		)	(6,992		)
Distributions from unconsolidated equity-method investments	16,264			8,502
Allowance for equity funds used during construction	(16,153		)	(16,219		)
Other non-cash adjustments to net income, net	(571		)	(969		)
Change in:
Accounts receivable	(12,319		)	(17,363		)
Accounts payable	(10,016		)	(11,967		)
Taxes accrued/receivable	8,172			27,942
Other current assets	7,326			(189		)
Other current liabilities	(5,451		)	7,917
Other assets	(1,277		)	2,468
Other liabilities	789			800
Net cash provided by operating activities	249,815			260,783
Investing Activities:
Additions to utility plant	(199,964		)	(235,841		)
Payments received from transmission project joint funding partners	6,853			—
Proceeds from the sale of emission allowances and renewable energy certificates	969			1,855
Purchase of available-for-sale securities	(9,843		)	(469		)
Proceeds from the sale of available-for-sale securities	14,453			2,724
Purchase of life insurance investment	(10,000		)	—
Other	(108		)	(1,372		)
Net cash used in investing activities	(197,640		)	(233,103		)
Financing Activities:
Issuance of long-term debt	120,000			250,000
Retirement of long-term debt	(101,064		)	(121,064		)
Dividends on common stock	(77,365		)	(71,215		)
Make-whole premium on retirement of long-term debt	(13,895		)	(17,872		)
Other	(1,671		)	(4,125		)
Net cash (used in) provided by financing activities	(73,995		)	35,724
Net (decrease) increase in cash and cash equivalents	(21,820		)	63,404
Cash and cash equivalents at beginning of the period	110,756			46,695
Cash and cash equivalents at end of the period	$	88,936		$	110,099
Supplemental Disclosure of Cash Flow Information:
Cash paid during the period for:
Income taxes	$	19,796		$	28,336
Interest (net of amount capitalized)	$	60,034		$	57,457
Non-cash investing activities:
Additions to property, plant and equipment in accounts payable	$	21,583		$	12,606

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, 2016, consolidated results of operations for the three and nine months ended September 30, 2016 and 2015, and consolidated cash flows for the nine months ended September 30, 2016 and 2015. 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, 2015. 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, 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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Reclassifications

In these consolidated financial statements, certain amounts in prior periods' consolidated financial statements have been reclassified to conform with the current period presentation.

New and Recently Adopted Accounting Pronouncements

Recently Adopted Accounting Pronouncements

In March 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standard Update (ASU) 2016-09, Compensation--Stock Compensation (Topic 718) - Improvements to Employer Share-Based Payment Accounting, simplifying several aspects of the accounting for stock compensation paid to employees. As allowed, IDACORP and Idaho Power elected to early adopt the provisions of the new standard in the first quarter of 2016 under the modified retrospective method, with the cumulative effect of adoption recorded as an adjustment to 2016 beginning retained earnings. The principal changes under the new accounting standard include the following:


•	Excess or deficit income tax benefits on share-based transactions are recorded as income tax expense rather than in additional-paid-in-capital.


•	Previously recorded forfeiture estimates of approximately $0.2 million are reported as a decrease to beginning retained earnings. IDACORP made an accounting policy election to account for share-based award forfeitures as they occur, rather than making an estimate of future forfeitures.


•	In the statement of cash flows, excess tax benefits on share-based payments are presented in operating activities in the same manner as other cash flows related to income taxes. Previously, these cash flows were presented in financing activities. Prior periods were not restated for this change.

In February 2015, the FASB issued ASU 2015-02, Consolidation (Topic 810) - Amendments to the Consolidation Analysis, which revises the consolidation model that reporting entities use when determining what entities are to be consolidated. The amendments focus on limited partnerships and similar legal entities. The adoption of ASU 2015-02 in the first quarter of 2016 did not have a material impact on IDACORP's or Idaho Power's financial statements.

Recent Accounting Pronouncements Not Yet Adopted

In May 2014, the FASB issued 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 FASB amended certain aspects of ASU 2014-09 to clarify the implementation guidance, including clarifications related to principal versus agent considerations, licensing and identifying performance obligations, narrow scope improvements, and practical expedients. The guidance in ASU 2014-09 is effective for annual reporting periods beginning after December 15, 2017, including interim periods, with early adoption permitted one year earlier. IDACORP and Idaho Power do not plan to early adopt the standard. 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. The companies are assessing the impacts of ASU 2014-09 on their financial statements as well as the transition method the companies will use to adopt the guidance. At this time, the companies do not know, and cannot reasonably estimate, the dollar impact of the adoption. Specifically, the companies are considering whether the new guidance will affect their accounting for contributions in aid of construction, sales of renewable energy credits, and other utility industry-related areas.

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), intended to improve financial reporting about leasing transactions. The ASU significantly changes the accounting model used by lessees to account for leases, requiring that all material leases be presented on the balance sheet. Under the current model, some leases are classified as capital leases and recorded on the balance sheet while other leases classified as operating leases are not recognized on the balance sheet. The new standard is effective for annual reporting periods beginning after December 15, 2018, including interim periods, with early adoption permitted. The standard must be adopted using a modified retrospective approach. IDACORP and Idaho Power are evaluating the impact of ASU 2016-02 on their financial statements. At this time, the companies do not know, and cannot reasonably estimate, the dollar impact of the adoption. Specifically, the companies are considering whether the new guidance will affect their accounting for purchase power agreements, easements and rights-of-way, utility pole attachments, and other utility industry-related areas.

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In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230), which amends ASC 230 to clarify guidance on the classification of certain cash receipts and payments in the statement of cash flows. The FASB issued the ASU with the intent of reducing diversity in practice with respect to eight types of cash flows. The companies expect the ASU to affect the classification of proceeds from the settlement of corporate-owned life insurance policies, which will be classified as investing activities under the new guidance. The guidance in ASU 2016-15 is effective for annual reporting periods beginning after December 15, 2017. The standard must be adopted retrospectively to all periods presented, unless impracticable to do so. IDACORP and Idaho Power do not believe the adoption will have a material impact on their financial statements.

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
	2016			2015			2016			2015
Income tax at statutory rates (federal and state)	$	75,736		$	79,030		$	74,864		$	78,356
Additional ADITC amortization	(1,500		)	—			(1,500		)	—
First mortgage bond redemption costs	(5,583		)	(7,210		)	(5,583		)	(7,210		)
Share-based compensation	(1,754		)	—			(1,720		)	—
Affordable housing tax credits	(2,130		)	(2,628		)	—			—
Affordable housing investment distributions, net of statutory rates	(1,561		)	—			—			—
Affordable housing investment amortization, net of statutory rates	1,019			1,025			—			—
Other⁽¹⁾	(35,605		)	(30,941		)	(34,964		)	(30,274		)
Income tax expense	$	28,622		$	39,276		$	31,097		$	40,872
Effective tax rate	14.8		%	19.4		%	16.2		%	20.4		%

⁽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, 2015.

The reductions in income tax expense for the nine months ended September 30, 2016, compared with the same period in 2015, were primarily due to lower pre-tax income, tax benefits resulting from share-based compensation related to the adoption of ASU 2016-09 discussed in Note 1, additional accumulated deferred investment tax credit (ADITC) amortization under the regulatory mechanism described in Note 3, and distributions related to fully-amortized affordable housing investments. On a net basis, Idaho Power’s estimate of its annual 2016 regulatory flow-through tax adjustments is comparable to 2015.

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

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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


•	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, prorated for intra-year rate changes.

Under the October 2014 settlement stipulation, Idaho Power recorded $1.5 million of additional ADITC amortization during the first nine months of 2016 based on its estimate of Idaho ROE for the full-year 2016, leaving $43.5 million of additional ADITCs estimated to be available under the settlement stipulation.

Idaho Power Cost Adjustment Mechanism

In both its Idaho and Oregon jurisdictions, Idaho Power's power cost adjustment (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 net power supply costs (primarily fuel and purchased power less off-system sales) against net power supply costs being recovered in Idaho Power's retail rates. Under the PCA mechanisms, certain differences between actual net power supply costs incurred by Idaho Power and costs being recovered in retail rates are recorded as a deferred charge or credit on the balance sheet for future recovery or refund. The power supply costs deferred primarily result from

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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 27, 2016, the IPUC issued an order approving a $17.3 million net increase in Idaho PCA rates, effective for the 2016-2017 PCA collection period from June 1, 2016 to May 31, 2017. The requested net increase in Idaho PCA rates included the application of (a) a customer rate credit of $3.2 million for sharing with customers for the year 2015 pursuant to the terms of the October 2014 settlement stipulation described above and (b) a $4.0 million reduction due to the transfer of Idaho energy efficiency rider funds. Previously, 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 with customers for the year 2014 pursuant to the terms of the December 2011 settlement stipulation, (b) a $1.5 million customer benefit relating to a change to the sales-based adjustment component of the PCA methodology, and (c) a $4.0 million reduction due to the transfer of Idaho energy efficiency rider funds.

Idaho Fixed Cost Adjustment Mechanism

The Idaho jurisdiction fixed cost adjustment (FCA) mechanism 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 instead linking it to a set amount per customer. The FCA mechanism is adjusted each year to collect, or refund, the difference between the authorized fixed-cost recovery amount and the actual fixed costs recovered by Idaho Power during the year. On May 27, 2016, the IPUC issued an order approving Idaho Power's application requesting an increase of $11.2 million in the FCA from $16.9 million to $28.1 million, with new rates effective for the period from June 1, 2016, through May 31, 2017. Previously, 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.

4. LONG-TERM DEBT

On March 10, 2016, Idaho Power issued $120 million in principal amount of 4.05 percent first mortgage bonds, secured medium-term notes, Series J, maturing on March 1, 2046. On April 11, 2016, Idaho Power redeemed, prior to maturity, $100 million in principal amount of 6.15 percent first mortgage bonds, medium-term notes, Series H due April 2019. 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 $14 million. Idaho Power used a portion of the net proceeds from the March 2016 issuance of first mortgage bonds, medium-term notes to effect the redemption.

In April and May 2016, Idaho Power received orders from the IPUC, OPUC, and Wyoming Public Service Commission (WPSC) authorizing the company to issue and sell from time to time up to $500 million in aggregate principal amount of debt securities and first mortgage bonds. The order from the IPUC approved the issuance of the securities through May 31, 2019, subject to extension upon request to the IPUC. The OPUC’s and WPSC’s orders do not impose a time limitation for issuances, but the OPUC order does impose a number of other conditions, including a requirement that the interest rates for the debt securities or first mortgage bonds fall within either (a) designated spreads over comparable U.S. Treasury rates or (b) a maximum all-in interest rate of 7.00 percent.

On May 20, 2016, IDACORP and Idaho Power filed a joint shelf registration statement with the SEC, which became effective upon filing, for the offer and sale of, in the case of IDACORP, an unspecified amount of shares of common stock and unspecified principal amount of debt securities, and in the case of Idaho Power, an unspecified principal amount of its first mortgage bonds and debt securities.

On September 27, 2016, Idaho Power entered into a selling agency agreement with seven banks named in the agreement in connection with the potential issuance and sale from time to time of up to $500 million aggregate principal amount of first mortgage bonds, secured medium term notes, Series K (Series K 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 September 27, 2016, Idaho Power entered into the Forty-eighth Supplemental Indenture, dated effective as of September 1, 2016, to the Indenture (Forty-eighth Supplemental Indenture). The Forty-eighth Supplemental Indenture provides for, among other items (a) the issuance of up to $500 million in aggregate principal amount of Series K Notes pursuant to the Indenture and (b) the increase of the maximum amount of obligations to be secured by the Indenture to $2.5 billion (which maximum amount may be further increased or decreased by Idaho Power without consent of the holders of first mortgage bonds). As of the date of this report, Idaho Power had not sold any first mortgage bonds, including Series K Notes, or debt securities under the selling agency agreement.

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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, 2015.

At September 30, 2016, no loans were outstanding under either IDACORP's or Idaho Power's facilities. At September 30, 2016, 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, 2016, and December 31, 2015:



	September 30, 2016									December 31, 2015
	Idaho Power			IDACORP			Total			Idaho Power			IDACORP			Total
Commercial paper outstanding	$	—		$	5,400		$	5,400		$	—		$	20,000		$	20,000
Weighted-average annual interest rate	—		%	0.86		%	0.86		%	—		%	0.88		%	0.88		%

6. COMMON STOCK

IDACORP Common Stock

During the nine months ended September 30, 2016, IDACORP issued 67,966 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.

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 Policy and 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, 2016, the leverage ratios for IDACORP and Idaho Power were 45 percent and 47 percent, respectively. Based on these restrictions, IDACORP’s and Idaho Power’s dividends were limited to $1.2 billion and $1.1 billion, respectively, at September 30, 2016. 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, 2016, 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, 2016, Idaho Power's common equity capital was 53 percent of its total adjusted capital. Further, Idaho Power must obtain approval of the OPUC before it could directly or indirectly loan funds or issue notes or give credit on its books to IDACORP.

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

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

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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, 2016 and 2015 (in thousands, except for per share amounts).



	Three months ended September 30,				Nine months ended September 30,
	2016		2015		2016		2015
Numerator:
Net income attributable to IDACORP, Inc.	$	83,100	$	73,336	$	165,075	$	162,847
Denominator:
Weighted-average common shares outstanding - basic	50,296		50,219		50,299		50,221
Effect of dilutive securities	97		105		62		61
Weighted-average common shares outstanding - diluted	50,393		50,324		50,361		50,282
Basic earnings per share	$	1.65	$	1.46	$	3.28	$	3.24
Diluted earnings per share	$	1.65	$	1.46	$	3.28	$	3.24

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, 2016, except that ten power purchase agreements with solar energy developers were terminated due to either an uncured breach or voluntary termination by the counterparties. Termination of the agreements reduced Idaho Power's contractual payment obligations by approximately $267 million over the 20-year lives of the terminated contracts.

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 $71 million at September 30, 2016, 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, 2016, the current value of the reclamation trust fund was $79 million. During the nine months ended September 30, 2016, the reclamation trust fund made distributions of $1.2 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, 2016, 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

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

Western Energy Proceedings

High prices for electricity, energy shortages, and blackouts in California and in the western wholesale markets during 2000 and 2001 caused numerous purchasers of electricity in those markets to initiate proceedings to consider requiring refunds and other forms of disgorgement from energy sellers. Some of these proceedings remain pending before the FERC or are on appeal to the United States Court of Appeals for the Ninth Circuit, and thus there remains some uncertainty about the ultimate outcome of the proceedings. Idaho Power and IESCo (as successor to IDACORP Energy L.P.) believe that the current state of the FERC's orders, if maintained, and the settlement releases they have obtained, will restrict potential claims that might result from the pending proceedings. As a result, IDACORP and Idaho Power predict that these matters will not have a material adverse effect on their respective results of operations or financial condition. However, if unanticipated orders are issued by the FERC or by the Ninth Circuit Court of Appeals or other courts, exposure to indirect claims in the proceedings could exist. These indirect claims would consist of 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. Given the speculative nature of ripple claims and in light of Idaho Power's and IESCo's participation in the market as both buyers and sellers of energy, 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 included 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 alleged 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. In September 2016, the bankruptcy court issued an oral decision substantively consolidating the Hoku Materials, Inc. and Hoku Corporation cases into a single case. As of the date of this report, Idaho Power believes that any potential liability is remote in light of the consolidation of the cases.

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

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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 the following pension plans - a noncontributory defined benefit pension plan (pension plan) and two nonqualified defined benefit plans for certain senior management employees called the Security Plan for Senior Management Employees I and Security Plan for Senior Management Employees II (collectively, SMSP). Idaho Power also has a nonqualified defined benefit pension plan for directors that was frozen in 2002. Remaining vested benefits from that plan are included with the SMSP in the disclosures below. 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, 2016 and 2015 (in thousands of dollars).



	Pension Plan						SMSP				Postretirement Benefits
	2016			2015			2016		2015		2016			2015
Service cost	$	8,004		$	8,291		$	307	$	422	$	279		$	308
Interest cost	9,453			8,792			1,069		967		692			670
Expected return on plan assets	(10,519		)	(10,994		)	—		—		(619		)	(669		)
Amortization of prior service cost	15			56			42		47		7			3
Amortization of net loss	3,332			3,482			883		1,048		—			—
Net periodic benefit cost	10,285			9,627			2,301		2,484		359			312
Adjustments due to the effects of regulation⁽¹⁾	(5,538		)	(4,902		)	—		—		—			—
Net periodic benefit cost recognized for financial reporting⁽¹⁾	$	4,747		$	4,725		$	2,301	$	2,484	$	359		$	312

⁽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, 2016 and 2015 (in thousands of dollars).



	Pension Plan						SMSP				Postretirement Benefits
	2016			2015			2016		2015		2016			2015
Service cost	$	24,014		$	24,873		$	921	$	1,267	$	837		$	926
Interest cost	28,360			26,378			3,206		2,901		2,075			2,009
Expected return on plan assets	(31,560		)	(31,733		)	—		—		(1,856		)	(2,010		)
Amortization of prior service cost	44			166			126		139		20			11
Amortization of net loss	9,998			10,446			2,649		3,146		—			—
Net periodic benefit cost	30,856			30,130			6,902		7,453		1,076			936
Adjustments due to the effects of regulation⁽¹⁾	(16,643		)	(15,873		)	—		—		—			—
Net periodic benefit cost recognized for financial reporting⁽¹⁾	$	14,213		$	14,257		$	6,902	$	7,453	$	1,076		$	936

Idaho Power has no minimum contribution requirement to its defined benefit pension plan in 2016. However, during the nine months ended September 30, 2016, Idaho Power made $40 million of discretionary contributions to its defined benefit pension plan. Idaho Power's contributions are made in a continued effort to balance regulatory collection of these expenditures with the amount and timing of contributions and to mitigate the cost of being in an underfunded position.

Idaho Power also has an Employee Savings Plan that complies with Section 401(k) of the Internal Revenue Code and covers substantially all employees. Idaho Power matches specified percentages of employee contributions to the Employee Savings Plan.

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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, 2016 and 2015 (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,
		2016			2015			2016			2015
Financial swaps	Off-system sales	$	(16	)	$	472		$	1,379		$	2,627
Financial swaps	Purchased power	710			992			861			1,098
Financial swaps	Fuel expense	(657		)	(3,774		)	(3,099		)	(4,152		)
Financial swaps	Other operations and maintenance	(16		)	(15		)	(166		)	(21		)
Forward contracts	Purchased power	24			—			24			3
Forward contracts	Fuel expense	49			51			139			56

⁽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, 2016, and December 31, 2015 (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, 2016
Current:
Financial swaps	Other current assets	$	3,256	$	(269	)	⁽¹⁾	$	2,987	$	245	$	(245	)	$	—
Total		$	3,256	$	(269	)		$	2,987	$	245	$	(245	)	$	—

December 31, 2015
Current:
Financial swaps	Other current assets	$	999	$	(785	)		$	214	$	785	$	(785	)	$	—
Financial swaps	Other current liabilities	177		(177		)		—		5,146		(177		)	4,969
Forward contracts	Other current assets	64		—				64		—		—			—
Forward contracts	Other current liabilities	—		—				—		3		—			3
Long-term:
Financial swaps	Other assets	148		(22		)		126		22		(22		)	—
Total		$	1,388	$	(984	)		$	404	$	5,956	$	(984	)	$	4,972

⁽¹⁾ Current asset derivative amount offset includes $24 thousand of collateral payable for the period ending September 30, 2016.

The table below presents the volumes of derivative commodity forward contracts and swaps outstanding at September 30, 2016 and 2015 (in thousands of units).



		September 30,
Commodity	Units	2016	2015
Electricity purchases	MWh	130	350
Electricity sales	MWh	143	160
Natural gas purchases	MMBtu	7,977	14,570
Natural gas sales	MMBtu	70	944
Diesel purchases	Gallons	267	61

Credit Risk

At September 30, 2016, 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.

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

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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, 2016, was $0.2 million. Idaho Power posted no cash collateral related to this amount. If the credit-risk-related contingent features underlying these agreements were triggered on September 30, 2016, Idaho Power would have been required to pay or post collateral to its counterparties up to an additional $3.8 million to cover the open liability positions as well as completed transactions that have not yet been paid.

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, 2016.

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, 2016, and December 31, 2015 (in thousands of dollars).



	September 30, 2016								December 31, 2015
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets:
Money market funds
IDACORP	$	—	$	—	$	—	$	—	$	1,000	$	—	$	—	$	1,000
Idaho Power	19,987		—		—		19,987		10,000		—		—		10,000
Derivatives	1,128		1,859		—		2,987		340		64		—		404
Trading securities: Equity securities	102		—		—		102		102		—		—		102
Available-for-sale securities: Equity securities	20,199		—		—		20,199		24,459		—		—		24,459
Liabilities:
Derivatives	—		—		—		—		286		4,686		—		4,972

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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 derivatives are valued 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, 2016, and December 31, 2015, using available market information and appropriate valuation methodologies (in thousands of dollars).



	September 30, 2016				December 31, 2015
	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⁾	1,746,612		1,997,132		1,726,474		1,813,243
Idaho Power
Liabilities:
Long-term debt⁽¹⁾	1,746,612		1,997,132		1,726,474		1,813,243

⁽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, 2016:
Revenues	$	371,474	$	571	$	—		$	372,045
Net income attributable to IDACORP, Inc.	80,029		3,071		—			83,100
Total assets as of September 30, 2016	6,068,358		82,872		(22,121		)	6,129,109
Three months ended September 30, 2015:
Revenues	$	368,517	$	648	$	—		$	369,165
Net income attributable to IDACORP, Inc.	71,727		1,609		—			73,336
Nine months ended September 30, 2016:
Revenues	$	966,451	$	1,986	$	—		$	968,437
Net income attributable to IDACORP, Inc.	160,370		4,705		—			165,075
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

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, 2016 and 2015 (in thousands of dollars). Items in parentheses indicate charges to AOCI.



	Defined Benefit Pension Items
	Three months ended September 30,						Nine months ended September 30,
	2016			2015			2016			2015
Balance at beginning of period	$	(20,149	)	$	(22,824	)	$	(21,276	)	$	(24,158	)
Amounts reclassified out of AOCI	563			667			1,690			2,001
Balance at end of period	$	(19,586	)	$	(22,157	)	$	(19,586	)	$	(22,157	)

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, 2016 and 2015 (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,
	2016			2015			2016			2015
Amortization of defined benefit pension items⁽¹⁾
Prior service cost	$	42		$	47		$	126		$	139
Net loss	883			1,048			2,649			3,146
Total before tax	925			1,095			2,775			3,285
Tax benefit⁽²⁾	(362		)	(428		)	(1,085		)	(1,284		)
Net of tax	563			667			1,690			2,001
Total reclassification for the period	$	563		$	667		$	1,690		$	2,001

⁽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, 2016, and the related condensed consolidated statements of income and comprehensive income for the three-month and nine-month periods ended September 30, 2016 and 2015, and of equity and cash flows for the nine-month periods ended September 30, 2016 and 2015. 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, 2015, 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 18, 2016, 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, 2015 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 27, 2016

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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, 2016, and the related condensed consolidated statements of income and comprehensive income for the three-month and nine-month periods ended September 30, 2016 and 2015, and of cash flows for the nine-month periods ended September 30, 2016 and 2015. 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, 2015, 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 18, 2016, 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, 2015 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 27, 2016

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

AND RESULTS OF OPERATIONS

In Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) in this report, 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. Also refer to "Cautionary Note Regarding Forward-Looking Statements" in this report for important information regarding forward-looking statements made in this MD&A and elsewhere in this report. This discussion updates the MD&A included in the Annual Report on Form 10-K for the year ended December 31, 2015, 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.

In the MD&A, MWh and dollar amounts in tables, other than earnings per share, are in thousands unless otherwise indicated.

INTRODUCTION

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 whose rates and other matters are regulated by the Idaho Public Utility Commission (IPUC), Public Utility Commission of Oregon (OPUC), and Federal Energy Regulatory Commission (FERC). Idaho Power generates revenues and cash flows primarily from the sale and distribution of electricity to customers in its Idaho and Oregon service territories, as well as from the wholesale sale and transmission of electricity. Idaho Power 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. Idaho Power’s rates are established through regulatory proceedings that affect its ability to recover its costs and the potential to earn a return on its investment.

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 subsidiaries include IDACORP Financial Services, Inc. (IFS), an investor in affordable housing and other real estate investments; Ida-West Energy Company, an operator of small hydroelectric generation projects that satisfy the requirements of the Public Utility Regulatory Policies Act of 1978 (PURPA); and IDACORP Energy Services Co., which is the former limited partner of, and successor by merger to, IDACORP Energy L.P., a marketer of energy commodities that wound down operations in 2003.

EXECUTIVE OVERVIEW

Management's Outlook and Company Initiatives

In the Annual Report on Form 10-K for the year ended December 31, 2015, IDACORP's and Idaho Power's management included a brief overview of their outlook and initiatives for the companies for 2016 and beyond, under the headings "Executive Overview - Management's Outlook" and "2015 Accomplishments and 2016 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 2016, Idaho Power's customer count grew by 7,328 customers, and for the twelve months ended September 30, 2016, the customer growth rate was 1.8 percent.


•	Idaho Power expects substantial capital investments, with expected total capital expenditures of approximately $1.5 billion over the five-year period from 2016 (including expenditures to date in 2016) through 2020.


•	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. In September 2016, the IDACORP Board of Directors approved an increase in the regular quarterly cash dividend on IDACORP’s common stock of 7.8 percent to $0.55 per share. At the new rate, the dividend on an annual basis is $2.20 per share.


•	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.

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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 a number of factors, and the impact of those factors is discussed in more detail later in this MD&A. To provide context for the discussion elsewhere in this report, some of the more notable factors include the following:

•

Regulation of Rates and Cost Recovery: The price that Idaho Power is authorized to charge for its electric and transmission service is a critical factor in determining IDACORP's and Idaho Power's results of operations and financial condition. Those rates are established by state regulatory commissions and the FERC, and are intended to allow Idaho Power an opportunity to recover its expenses and earn a reasonable return on investment. 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, working to put in place innovative regulatory mechanisms, and on the prudent management of expenses and investments. Idaho Power has a regulatory settlement stipulation in Idaho that remains in effect through 2019. That stipulation includes provisions for the accelerated amortization of certain tax credits to help achieve a minimum 9.5 percent return on year-end equity in the Idaho jurisdiction (Idaho ROE). Also during 2016, Idaho Power continues to assess the need to file a general rate case to reset base rates in the coming years.

•

Rate Base Growth and Infrastructure Investment: As noted above, the rates established by the IPUC and OPUC are determined so as to provide an opportunity for Idaho Power to recover authorized operating expenses and earn a reasonable return on “rate base.” Rate base is generally determined by reference to the original cost (net of accumulated depreciation) of utility plant in service, subject to various adjustments for deferred taxes and other items. Over time, rate base is increased by additions to utility plant in service and reduced by depreciation and retirement of utility plant and write-offs as authorized by the IPUC and OPUC. In recent years, Idaho Power has been pursuing significant enhancements to its utility infrastructure, including major ongoing transmission projects such as the Boardman-to-Hemingway and Gateway West projects, 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, and the company is undertaking a significant relicensing effort for the Hells Canyon Complex (HCC), its largest hydroelectric generation resource. Idaho Power expects to include completed capital projects in its next general rate case or, in circumstances where appropriate, a single-issue rate case for individual projects with a significant capital cost. Depending on the outcome of the regulatory process and factors such as the rate of return authorized by the IPUC and OPUC, this growth in rate base has the potential to increase Idaho Power's revenues and earnings.

•

Economic Conditions and Loads: Economic conditions impact consumer demand for electricity and revenues, 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. In recent years, Idaho Power has seen growth in both the number of customers in its service area—over the last 12 months customer count grew by 1.8 percent—and in employment in Idaho Power's service area, which grew by approximately 2.1 percent over the last twelve months, based on Idaho Department of Labor preliminary September 2016 data. Idaho Power expects that the number of customers will continue to increase in the foreseeable future. Idaho Power has in recent years supported State of Idaho-coordinated efforts to promote economic development with an emphasis on attracting industrial and commercial customers to its service area.

In August 2016, Idaho Power began preparing its 2017 Integrated Resource Plan (IRP). The load forecast assumptions Idaho Power expects to use in the 2017 IRP are included in the table below. For comparison purposes, the analogous average annual growth rates used in the prior two IRPs are included.



	2016-2021 Period		20-Year Forecast
	Annual Growth Rate: Retail Sales (Billed MWh)	Annual Growth Rate: Annual Peak (Peak Demand)	Annual Growth Rate: Retail Sales (Billed MWh)	Annual Growth Rate: Annual Peak (Peak Demand)
2017 IRP	1.3%	1.4%	1.0%	1.4%
2015 IRP	1.1%	1.6%	1.2%	1.5%
2013 IRP	1.2%	1.6%	1.1%	1.4%

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•

Weather Conditions: Weather and agricultural growing conditions have a significant impact on energy sales and the seasonality of those sales. Relatively low and high temperatures result in greater energy use for heating and cooling, respectively. During the agricultural growing season, which in large part occurs during the second and third quarters, irrigation customers use electricity to operate irrigation pumps, and weather conditions can impact the timing and degree of use of those pumps. Idaho Power also has tiered rates and seasonal rates, which contribute to increased revenues during higher-load periods, most notably during the third quarter of each year when overall customer demand is highest. Much of the adverse or favorable impact of weather on sales of energy to residential and small commercial customers is mitigated through the Idaho fixed cost adjustment (FCA) mechanism.

Further, as Idaho Power's hydroelectric facilities comprise nearly one-half of Idaho Power's nameplate generation capacity, precipitation levels impact the mix of Idaho Power's generation resources. When hydroelectric generation is reduced, Idaho Power must rely on more expensive generation sources and purchased power. When favorable hydroelectric generating conditions exist for Idaho Power, they also may exist for other Pacific Northwest hydroelectric facility operators, lowering regional wholesale market prices and impacting the revenue Idaho Power receives from off-system sales of its excess power. Much of the adverse or favorable impact of this volatility on Idaho Power's financial results is addressed through the Idaho and Oregon power cost adjustment (PCA) mechanisms.

While sales volumes during the first nine months of 2016 were consistent with sales volumes in the first nine months of 2015, temperatures in Idaho Power's service area were slightly above normal in both periods.

•

Mitigation of Impact of 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. 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 market prices, and Idaho Power's hedging program for managing fuel costs. Recently, low natural gas prices have made operation of Idaho Power's natural gas power plants more economical, resulting in increased operation of those plants and decreased operation of coal-fired plants. 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 or solar energy, and wholesale energy market prices. The Idaho and Oregon PCA mechanisms mitigate in large part the potential adverse impacts of fluctuations in power supply costs to Idaho Power.

•

Regulatory and Environmental Compliance Costs: 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 affects Idaho Power's operating costs. Environmental laws and regulations, in particular, may increase the cost of operating generation plants and constructing new facilities, may require that Idaho Power install additional pollution control devices at existing generating plants, or may 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, a decision driven in large part by the substantial cost of environmental controls required by existing regulations. Similarly, Idaho Power is assessing the closure of the North Valmy coal-fired power plant and in October 2016 filed an application with the IPUC requesting accelerated depreciation of the facility.

•

Water Management and Relicensing of the Hells Canyon Hydroelectric Project (HCC): Because of Idaho Power's reliance on stream flow in the Snake River and its tributaries, Idaho Power participates in numerous proceedings and venues that may affect its water rights, seeking to preserve the long-term availability of its rights for its hydroelectric projects. Also, Idaho Power is involved in renewing its long-term federal license for the HCC, its largest hydroelectric generation source. Given the number of parties and issues involved, Idaho Power's relicensing costs have been and will continue to be substantial. Idaho Power cannot currently determine the terms of, and costs associated with, any resulting long-term license.

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Summary of Financial Results



	Three months ended September 30,				Nine months ended September 30,
	2016		2015		2016		2015
Idaho Power net income	$	80,029	$	71,727	$	160,370	$	159,528
Net income attributable to IDACORP, Inc.	$	83,100	$	73,336	$	165,075	$	162,847
Average outstanding shares – diluted (000’s)	50,393		50,324		50,361		50,282
IDACORP, Inc. earnings per diluted share	$	1.65	$	1.46	$	3.28	$	3.24

The table below provides a reconciliation of net income attributable to IDACORP for the three and nine months ended September 30, 2015 and 2016 (items are in millions and are before related income tax impact unless otherwise noted).



	Three months ended				Nine months ended
Net income attributable to IDACORP, Inc. - September 30, 2015			$	73.3			$	162.8
Change in Idaho Power net income:
Sales volumes attributable to customer growth, net of associated power supply costs and PCA mechanism impacts	3.6				8.2
Sales volumes attributable to usage per customer, net of associated power supply costs and PCA mechanism impacts	(4.1	)			(12.2	)
Changes in revenues per MWh due to customer usage	(3.9	)			(2.0	)
FCA revenues	2.1				1.1
Third-party use of electric property, wheeling and other revenue	0.8				(1.3	)
Other operating and maintenance expenses	(3.1	)			(4.4	)
Depreciation expense	(1.4	)			(4.5	)
Other changes in operating revenues and expenses, net	(0.7	)			—
Decrease in Idaho Power operating income	(6.7	)			(15.1	)
Earnings of unconsolidated equity-method investments	6.8				4.5
Changes in other non-operating income and expenses	1.7				1.6
Income tax expense (excluding additional ADITC amortization)	5.5				8.3
Additional ADITC amortization	1.0				1.5
Total increase in Idaho Power net income			8.3				0.8
Other changes (net of tax)			1.5				1.5
Net income attributable to IDACORP, Inc. - September 30, 2016			$	83.1			$	165.1

Net Income - Third Quarter 2016

IDACORP's net income increased $9.8 million for the third quarter of 2016 when compared with the third quarter of 2015. The increase was driven primarily by an $8.3 million increase in Idaho Power's net income.

Sales volumes due to customer growth increased operating income by $3.6 million, as the number of Idaho Power customers grew by 1.8 percent over the prior twelve months. The increase from customer growth was more than offset by a decrease in sales volumes on a per-customer basis, which reduced operating income by $4.1 million in the third quarter of 2016 compared with the third quarter of 2015. Temperatures in the Idaho Power service area were milder than normal in the third quarter of 2016 and were below third quarter 2015 temperatures, which reduced sales volumes on a per-customer basis. Changes in revenues per MWh due to customer usage decreased operating income by $3.9 million, primarily from lower peak demand-based revenue from irrigation customers as a result of milder weather.

Other operating and maintenance expenses were $3.1 million higher in the third quarter of 2016 compared with the third quarter of 2015, primarily related to higher variable employee costs based on the expected achievement of customer satisfaction and reliability goals.

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Income from Idaho Power's unconsolidated investment in BCC increased non-operating income by $6.8 million, due primarily to an increase in coal sales prices at BCC. Idaho Power believes coal sales prices at BCC will decrease in the fourth quarter of 2016 and expects income from BCC for the full year of 2016 will be in line with 2015.

IDACORP income tax expense benefited from distributions related to fully-amortized affordable housing investments as well as adjustments related to the filing of 2015 income tax returns. Idaho Power recorded $1.0 million of additional ADITC amortization during the third quarter of 2016 under its Idaho regulatory settlement stipulation. No additional ADITC amortization was recorded during the same period in 2015.

Net Income - Year-to-date 2016

IDACORP's net income increased $2.3 million for the first nine months of 2016 compared with the same period in 2015. The increase was driven primarily by an increase of $0.8 million in Idaho Power’s net income and reduced IDACORP income tax expense due to distributions related to fully-amortized affordable housing investments.

Idaho Power’s continued customer growth contributed $8.2 million to operating income. Lower usage per customer in the first nine months of 2016 compared with the same period in 2015 reduced operating income by $12.2 million. During the first nine months of 2016, winter temperatures were colder, while summer temperatures were milder than in the first nine months of 2015, which contributed to lower sales volumes, revenues, and operating income. Other operating and maintenance expenses were $4.4 million higher during the first nine months of 2016 compared with the same period of 2015, primarily related to higher variable employee costs based on the expected achievement of customer satisfaction and reliability goals.

Income from Idaho Power's unconsolidated investment in BCC increased non-operating income by $4.5 million, due primarily to an increase in coal sales prices at BCC. Idaho Power believes coal sales prices at BCC will decrease in the fourth quarter of 2016 and expects income from BCC for the full year of 2016 will be in line with 2015.

Income tax expense was lower in the first nine months of 2016 compared with the same period in 2015 due to lower pretax income and additional share-based compensation tax benefits related to the adoption of ASU 2016-09. These decreases were partially offset by a smaller flow-through benefit of tax deductible make-whole premiums that Idaho Power paid in connection with the early redemption of long-term debt in both the second quarter of 2016 and 2015 and other regulatory flow-through income tax adjustments. Based on Idaho Power's current expectations of full-year 2016 results, Idaho Power has recorded $1.5 million of additional ADITC amortization during the first nine months of 2016 under its Idaho regulatory settlement stipulation. No additional ADITC amortization was recorded during the same period in 2015. Idaho Power estimates that it will record $2 million of additional ADITC amortization for the full year 2016.

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RESULTS OF OPERATIONS

This section of MD&A takes a closer look at the significant factors that affected IDACORP’s and Idaho Power’s earnings during the three and nine months ended September 30, 2016. In this analysis, the results for the three and nine months ended September 30, 2016, are compared with the same period in 2015.

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, 2016 and 2015.



	Three months ended September 30,				Nine months ended September 30,
	2016		2015		2016		2015
General business sales	4,156		4,165		10,933		11,010
Off-system sales	224		203		837		940
Total energy sales	4,380		4,368		11,770		11,950
Hydroelectric generation	1,331		1,383		5,191		4,618
Coal generation	1,487		1,473		2,961		3,680
Natural gas and other generation	712		787		1,557		1,579
Total system generation	3,530		3,643		9,709		9,877
Purchased power	1,164		1,013		2,951		2,792
Line losses	(314	)	(288	)	(890	)	(719	)
Total energy supply	4,380		4,368		11,770		11,950

Sales Volume and Generation: In the third quarter and first nine months of 2016, general business sales volumes decreased less than 1 percent, respectively, compared with the same periods in the prior year. Sales volumes to irrigation customers were approximately 4 percent higher during the third quarter of 2016, but 4 percent lower during the first nine months of 2016, respectively, compared with the same periods in 2015. During the first nine months of 2016, a shorter irrigation season due to a later start resulted in lower usage per irrigation customer than during the same period in 2015. Sales volumes to commercial and residential customers were approximately 3 percent and 1 percent lower, respectively, in the third quarter of 2016 compared with the third quarter of 2015. During the first nine months of 2016, sales volumes to commercial customers were approximately 1 percent lower, compared with the same period of 2015. Temperatures in the Idaho Power service area were milder than normal in the third quarter of 2016 and were below third quarter 2015 temperatures, which led to lower loads associated with cooling.

Off-system sales volumes increased by 21 thousand MWh, or 10 percent, during the third quarter of 2016 compared with the third quarter of 2015. Off-system sales volumes decreased 103 thousand MWh, or 11 percent, during the first nine months of 2016 compared with the same period in 2015. Low electricity wholesale market prices reduced economic benefits of operating Idaho Power's non-hydroelectric generation facilities for off-system sales.

Generation from Idaho Power's hydroelectric plants decreased in the third quarter of 2016 compared with the same period in 2015, due to weaker Snake River and tributary water flows and other less favorable hydroelectric generating conditions. Favorable hydroelectric generating conditions in the spring led to increased hydroelectric generation for the first nine months of 2016, while coal-fired generation decreased compared with the same period 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 later in this MD&A.

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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, 2016 and 2015, and the number of customers as of September 30, 2016 and 2015.



	Three months ended September 30,						Nine months ended September 30,
	2016			2015			2016			2015
Revenue
Residential	$	130,952		$	129,393		$	376,492		$	376,584
Commercial	81,062			82,397			227,442			232,167
Industrial	48,979			48,843			136,617			138,292
Irrigation	84,264			83,595			153,301			159,265
Total	345,257			344,228			893,852			906,308
Deferred revenue related to HCC relicensing AFUDC⁽¹⁾	(3,432		)	(3,432		)	(8,366		)	(8,365		)
Total general business revenues	$	341,825		$	340,796		$	885,486		$	897,943
Volume of Sales (MWh)
Residential	1,222			1,239			3,640			3,623
Commercial	1,034			1,062			2,984			3,027
Industrial	820			821			2,402			2,382
Irrigation	1,080			1,043			1,907			1,978
Total MWh sales	4,156			4,165			10,933			11,010
Number of customers at period end
Residential	442,284			434,088
Commercial	69,145			68,255
Industrial	123			119
Irrigation	20,641			20,288
Total customers	532,193			522,750

⁽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.

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, 2016 and 2015, is presented in the table that follows.



	Three months ended September 30,			Nine months ended September 30,
	2016	2015	Normal	2016	2015	Normal
Heating degree-days⁽¹⁾	97	60	121	2,715	2,659	3,320
Cooling degree-days⁽¹⁾	722	878	751	1,000	1,251	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.

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General business revenue increased $1.0 million and decreased $12.5 million for the three and nine months ended September 30, 2016, respectively, compared with the same periods in 2015. Factors affecting general business revenues during the period are discussed below.

•

Rates: Rate changes did not have a significant effect on the third quarter of 2016 compared with the same period in 2015, but decreased general business revenue by $7.3 million for the nine months ended September 30, 2016 compared with the same period in 2015. The customer rates include recovery of the prior-year PCA deferral, which increased revenue $1.1 million in the third quarter 2016, but decreased revenue $15.2 million for the first nine months of 2016 compared with the same periods in 2015. The recovery of the prior-year PCA deferral in rates has no effect on operating income as it is amortized into expense in the same period it is recovered through rates.


•	Customers: Customer growth increased general business revenue by $4.9 million and $11.4 million, respectively, compared with the third quarter and first nine months of 2015. Total customers increased 1.8 percent during the twelve months ended September 30, 2016.

•

Usage: Lower usage (on a per customer basis), primarily by residential and commercial customers, decreased general business revenue by $5.9 million for the third quarter of 2016 when compared with the third quarter of 2015. Lower usage (on a per customer basis), primarily by irrigation, commercial, and residential customers, decreased general business revenue by $17.5 million in the first nine months of 2016 when compared with the same period in 2015. The lower usage was partially a result of the fewer number of cooling degree-days in the third quarter and first nine months of 2016 when compared with the same periods in 2015, as noted in the table above. During the first nine months of 2016, a shorter irrigation season due to a later start resulted in lower usage per irrigation customer. Greater customer participation in energy efficiency programs also contributed to lower usage during the third quarter of 2016 compared with the third quarter of 2015.


•	FCA Revenue: Partially offsetting lower usage per customer, the Idaho FCA mechanism increased revenues by $2.1 million and $1.1 million for the three and nine months ended September 30, 2016, respectively, compared with the same periods in 2015.

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, 2016 and 2015.



	Three months ended September 30,				Nine months ended September 30,
	2016		2015		2016		2015
Revenue	$	6,143	$	6,487	$	16,532	$	23,335
MWh sold	224		203		837		940
Revenue per MWh	$	27.42	$	31.96	$	19.75	$	24.82

In the third quarter of 2016, off-system sales revenue decreased by $0.3 million, or 5 percent, compared with the same period in 2015. For the first nine months, off-system sales revenue decreased by $6.8 million, or 29 percent. Off-system sales volumes increased 10 percent but decreased 11 percent for the three and nine months ended of 2016, respectively, compared with the same periods in 2015. Low electricity wholesale market prices reduced economic benefits of operating Idaho Power's non-hydroelectric generation facilities for off-system sales. The average price of off-system sales for the third quarter and first nine months of 2016 was 14 percent and 20 percent lower, respectively, compared with the same periods in 2015.

Other Revenues: The table below presents the components of other revenues for the three and nine months ended September 30, 2016 and 2015.



	Three months ended September 30,				Nine months ended September 30,
	2016		2015		2016		2015
Transmission services and other	$	14,404	$	13,589	$	40,177	$	41,480
Energy efficiency	9,102		7,645		24,256		19,854
Total other revenues	$	23,506	$	21,234	$	64,433	$	61,334

The termination in late-2015 of long-term transmission agreements in connection with a transmission asset purchase and sale arrangement with a third party reduced transmission service revenue in the nine months ended September 30, 2016, compared

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with the same period in 2015. Greater customer participation in energy efficiency programs increased revenue and corresponding expense in both the three and nine months ended September 30, 2016, compared with the same periods in 2015.

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. At September 30, 2016, Idaho Power's energy efficiency rider balances were a $5.4 million regulatory asset in the Oregon jurisdiction and a $11.6 million regulatory liability in the Idaho jurisdiction.

Purchased Power: The table below presents Idaho Power’s purchased power expenses and volumes for the three and nine months ended September 30, 2016 and 2015.



	Three months ended September 30,				Nine months ended September 30,
	2016		2015		2016		2015
Expense
PURPA contracts	$	42,477	$	37,392	$	111,422	$	95,503
Other purchased power (including wheeling)	31,971		34,498		59,253		70,688
Total purchased power expense	$	74,448	$	71,890	$	170,675	$	166,191
MWh purchased
PURPA contracts	574		494		1,740		1,524
Other purchased power	590		519		1,221		1,268
Total MWh purchased	1,164		1,013		2,961		2,792
Cost per MWh from PURPA contracts	$	74.00	$	75.69	$	64.04	$	62.67
Cost per MWh from other sources	$	54.19	$	66.47	$	48.53	$	55.75
Weighted average - all sources	$	63.96	$	70.97	$	57.64	$	59.52

Purchased power expense increased $2.6 million, or 4 percent, in the third quarter of 2016 compared with the same period in 2015. The increase for the third quarter of 2016 was due primarily to increased volumes purchased from higher-cost energy projects under PURPA contracts. Purchases from energy projects under PURPA contracts increased $5.1 million, or 14 percent, in the third quarter of 2016 compared with the third quarter of 2015. The $4.5 million increase in total purchased power expense for the first nine months of 2016 compared with the first nine months of 2015 was also due to higher volumes from energy projects under PURPA contracts, which increased expenses by $15.9 million, or 17 percent. For both the three and nine months ended September 30, 2016, the increases in power purchased from energy projects under PURPA contracts was partially offset by lower costs per MWh of purchases from sources other than energy projects under PURPA contracts.

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 different than the advance purchase or sale transaction prices. Also, 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. 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.

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Fuel Expense: The table below presents Idaho Power’s fuel expenses and generation at its thermal generating plants for the three and nine months ended September 30, 2016 and 2015.



	Three months ended September 30,				Nine months ended September 30,
	2016		2015		2016		2015
Expense
Coal ⁽¹⁾	$	56,651	$	43,869	$	103,599	$	101,654
Natural gas and other thermal	17,274		22,516		36,058		42,608
Total fuel expense	$	73,925	$	66,385	$	139,657	$	144,262
MWh generated
Coal ⁽¹⁾	1,487		1,473		2,961		3,533
Natural gas and other thermal	712		787		1,557		1,579
Total MWh generated	2,199		2,260		4,518		5,112
Cost per MWh - Coal	$	38.10	$	29.78	$	34.99	$	28.77
Cost per MWh - Natural gas and other thermal	$	24.26	$	28.61	$	23.16	$	26.98
Weighted average, all sources	$	33.62	$	29.37	$	30.91	$	28.22

⁽¹⁾The first three 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 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 during the past year.

Fuel expense increased $7.5 million, or 11 percent, in the third quarter of 2016, but decreased $4.6 million, or 3 percent, in the first nine months of 2016 compared with the same periods in 2015. Coal costs per MWh were significantly higher in both the three and nine months ended September 30, 2016, compared with the same periods in 2015 due to higher mining costs at BCC, the main coal supplier of the Jim Bridger plant. The higher mining costs were due mostly to issues with underground mining equipment that Idaho Power does not expect to recur in future periods. Natural gas costs per MWh decreased in both periods in 2016 compared with the same periods in 2015 due to decreases in natural gas commodity prices during the past year, but there were fewer opportunities for economic dispatch of natural gas resources in the third quarter of 2016. In the year-to-date period, increased hydroelectric generation reduced the need for production from thermal generating plants.

PCA Mechanisms: Idaho Power's power supply costs (primarily purchased power and fuel expense, 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 Idaho Power (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 table that follows presents the components of the Idaho and Oregon PCA mechanisms for the three and nine months ended September 30, 2016 and 2015.



	Three months ended September 30,						Nine months ended September 30,
	2016			2015			2016			2015
Idaho power supply cost deferral	$	(30,006	)	$	(22,463	)	(17,408		)	(17,947		)
Amortization of prior year authorized balances	11,664			10,549			29,322			44,319
Total power cost adjustment expense	$	(18,342	)	$	(11,914	)	$	11,914		$	26,372

The power supply accruals (deferral) represent the portion of the power supply cost fluctuations accrued (deferred) under the PCA mechanisms. When actual power supply costs are higher than the amount forecasted in PCA rates, which was the case for

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all periods presented, 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).

Other Operations and Maintenance Expenses: Other O&M expense increased $3.1 million, or four percent, in the third quarter of 2016 compared with the third quarter of 2015. Other O&M expense increased $4.4 million, or two percent, for the first nine months of 2016, compared with the same period in 2015. These increases are primarily due to higher variable employee costs based on the expected achievement of customer satisfaction and reliability goals.

Income Taxes

IDACORP's and Idaho Power's income tax expense for the nine months ended September 30, 2016, when compared with the same period in 2015, decreased $10.7 million and $9.8 million, respectively, primarily as a result of (1) lower pre-tax income, (2) a $1.8 million tax benefit resulting from the adoption of a new accounting standard for share-based compensation, and (3) $1.5 million of additional ADITC amortization at Idaho Power. IDACORP also benefited from $1.6 million of distributions related to fully-amortized affordable housing investments. 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 substantial capital expenditures to continue, with expected total capital expenditures of approximately $1.5 billion over the five-year period from 2016 (including expenditures to date in 2016) through 2020.

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 the first nine months of 2016, Idaho Power 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 21, 2016, IDACORP's and Idaho Power's access to debt, equity, and credit arrangements included:


•	their respective $100 million and $300 million revolving credit facilities;


•	IDACORP's shelf registration statement filed with the U.S. Securities and Exchange Commission (SEC) on May 20, 2016, which may be used for the issuance of debt securities and common stock;


•	Idaho Power's shelf registration statement filed with the SEC on May 20, 2016, which may be used for the issuance of first mortgage bonds and debt securities; $500 million is available for issuance 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, and Idaho Power may issue debt securities or first mortgage bonds, if the companies believe terms available in the capital markets are favorable and that issuances would be financially prudent.

On March 10, 2016, Idaho Power issued $120 million in principal amount of 4.05 percent first mortgage bonds, Series J, maturing on March 1, 2046. On April 11, 2016, Idaho Power redeemed, prior to maturity, $100 million in principal amount of 6.15 percent first mortgage bonds, medium-term notes due April 2019. 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 $14 million. The make-whole premium resulted in a current income tax deduction, which under Idaho Power's regulatory flow-through tax

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accounting produced an income tax benefit of approximately $5.6 million recorded in the second quarter of 2016. Idaho Power also expects to receive an incremental net benefit to net income as a result of the lower interest rate of the notes issued in March 2016 compared with the interest rate associated with the redeemed notes. Idaho Power used a portion of the net proceeds of the March 2016 sale of first mortgage bonds, medium-term notes to effect the redemption.

Based on planned capital expenditures and operating and maintenance expenses, 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, 2016, IDACORP's and Idaho Power's capital structures, as calculated for purposes of applicable debt covenants, were as follows:



	IDACORP	Idaho Power
Debt	45%	47%
Equity	55%	53%

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, 2016 were $275 million and $250 million, respectively, decreases of $15 million and $11 million, respectively, compared with the same period in 2015. With the exception of cash flows related to income taxes, IDACORP’s operating cash flows are principally derived from the operating cash flows of Idaho Power. Significant items that affected the comparability of the companies' operating cash flows in the first nine months of 2016 compared with the same period in 2015 were as follows:


•	Changes in regulatory assets and liabilities, mostly related to the relative amounts of costs deferred and collected under the Idaho PCA mechanism, decreased operating cash flows by $12 million;


•	Idaho Power made contributions of $44 million to its pension and postretirement benefit plans during the first nine months of 2016, while it made $42 million of cash contributions during the first nine months of 2015;


•	Idaho Power received a $16 million distribution from its investment in BCC for the first nine months of 2016, as compared to a $8 million distribution for the first nine months of 2015. The change in distributions from year to year is the result of increased net income at BCC and the impact of timing differences associated with BCC;


•	A $5 million and $18 million increase from changes in deferred taxes and investment tax credits was more than offset by an $11 million and $20 million decrease in taxes accrued and receivable, combining to decrease operating cash flows by $6 million and $2 million for IDACORP and Idaho Power, respectively;


•	Changes in working capital balances due primarily to timing resulted in a $1 million decrease to operating cash flows for IDACORP and a $1 million increase for Idaho Power.

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, 2016, were $198 million. Investing cash outflows for 2016 and 2015 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. Idaho Power received $7 million during the first nine months of 2016 from Boardman-to-Hemingway project joint permitting participants relating to a portion of these construction expenditures. Idaho Power has a rabbi trust designated to provide funding for obligations of its nonqualified defined benefit plans. In the first nine months of 2016, related to activity in the rabbi trust, Idaho Power purchased $10 million of available-for-sale securities and received $14 million of proceeds from the sales of of available-for-sale securities. Idaho Power used $10 million of these proceeds to acquire company-owned life insurance held in the rabbi trust.

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Financing Cash Flows

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

Net financing cash outflows for IDACORP and Idaho Power for the nine months ended September 30, 2016, were $92 million and $74 million, respectively. As previously noted, on March 10, 2016, Idaho Power issued $120 million of 4.05 percent first mortgage bonds. On April 11, 2016, Idaho Power redeemed, prior to maturity, $100 million in principal amount of 6.15 percent first mortgage bonds, medium-term notes due April 2019. 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 $14 million. Financing cash flows also included the payment of $77 million of dividends on common stock and a $15 million net decrease in IDACORP commercial paper borrowings.

Financing Programs and Available Liquidity

IDACORP Equity Programs: In recent years, IDACORP has entered into sales agency agreements under which IDACORP could offer and sell shares of its common stock from time to time through BNY Mellon Capital Markets, LLC as IDACORP's agent. The most recent sales agency agreement terminated in May 2016. On May 20, 2016, IDACORP filed a shelf registration statement with the SEC, which became effective upon filing, for the potential offer and sale of an unspecified amount of shares of common stock. As of the date of this report, IDACORP is assessing whether to execute a new sales agency agreement for the issuance and sale of common stock, as the company does not anticipate issuing any shares of its common stock outside of its equity compensation plans during the remainder of 2016.

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 and May 2016, Idaho Power received orders from the IPUC, OPUC, and WPSC authorizing the company to issue and sell from time to time up to $500 million in aggregate principal amount of debt securities and first mortgage bonds. The order from the IPUC approved the issuance of the securities through May 31, 2019, subject to extension upon request to the IPUC. The OPUC’s and WPSC’s orders do not impose a time limitation for issuances, but the OPUC order does impose a number of other conditions, including a requirement that the interest rates for the debt securities or first mortgage bonds fall within either (a) designated spreads over comparable U.S. Treasury rates or (b) a maximum all-in interest rate of 7 percent.

On May 20, 2016, Idaho Power filed a shelf registration statement with the SEC, which became effective upon filing, for the offer and sale of an unspecified principal amount of its first mortgage bonds. Idaho Power’s Indenture of Mortgage and Deed of Trust, dated as of October 1, 1937, as amended and supplemented (Indenture) limits the amount of first mortgage bonds at any one time outstanding to $2.5 billion, and as a result the maximum amount of additional first mortgage bonds Idaho Power could issue as of September 30, 2016 was limited to approximately $759 million. 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, 2016, Idaho Power could issue approximately $1.6 billion of additional first mortgage bonds based on retired first mortgage bonds and total unfunded property additions.

For a description of the selling agency agreement entered into by Idaho Power related to the potential issuance of the first mortgage bonds refer to Note 4 - "Long-Term Debt" to the condensed consolidated financial statements included in this report. As of the date of this report, Idaho Power has not sold any first mortgage bonds or debt securities under the May 2016 shelf registration statement or selling agency agreement and does not anticipate any issuances during the remainder of 2016.

IDACORP and Idaho Power Credit Facilities: In November 2015, IDACORP and Idaho Power entered into Credit Agreements for $100 million and $300 million credit facilities, respectively. These facilities replaced IDACORP's and Idaho Power's existing Second Amended and Restated Credit Agreements, dated October 26, 2011, as amended. 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 $100 million at any one time outstanding, including swingline loans not to exceed $10 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

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one time and letters of credit not to exceed $100 million at any one time outstanding. 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, 2015, 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, 2016, the leverage ratios for IDACORP and Idaho Power were 45 percent and 47 percent, respectively. IDACORP's and Idaho Power's ability to utilize the credit facilities is conditioned upon their continued compliance with the leverage ratio covenants included in the credit facilities. 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, 2016, 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 2016.

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 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, 2016						December 31, 2015
	IDACORP⁽²⁾			Idaho Power			IDACORP⁽²⁾			Idaho Power
Revolving credit facility	$	100,000		$	300,000		$	100,000		$	300,000
Commercial paper outstanding	(5,400		)	—			(20,000		)	—
Identified for other use⁽¹⁾	—			(24,245		)	—			(24,245		)
Net balance available	$	94,600		$	275,755		$	80,000		$	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 21, 2016, IDACORP and Idaho Power had no loans outstanding under their credit facilities and no commercial paper outstanding.

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The table below presents additional information about short-term commercial paper borrowing during the three and nine months ended September 30, 2016.



	Three months ended						Nine months ended
	September 30, 2016						September 30, 2016
	IDACORP⁽¹⁾			Idaho Power			IDACORP ⁽¹⁾			Idaho Power
Commercial paper:
Period end:
Amount outstanding	$	5,400		$	—		$	5,400		$	—
Weighted average interest rate	0.86		%	—		%	0.86		%	—		%
Daily average amount outstanding during the period	$	20,124		$	—		$	20,892		$	—
Weighted average interest rate during the period	0.83		%	—		%	0.82		%	—		%
Maximum month-end balance	$	22,100		$	—		$	23,900		$	—

⁽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, 2015. 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, 2016, Idaho Power had posted no performance assurance collateral related to these contracts. 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, 2016, the amount of additional collateral that could be requested upon a downgrade to below investment grade is approximately $5.2 million. To minimize capital requirements, Idaho Power actively monitors its portfolio exposure and the potential exposure to additional requests for performance assurance collateral through sensitivity analysis.

Capital Requirements

Idaho Power's construction expenditures, excluding allowance for funds used during construction (AFUDC), were $193 million during the nine months ended September 30, 2016. The table below presents Idaho Power's expected cash requirements for construction, excluding AFUDC, for 2016 (including amounts incurred to-date) through 2020 (in millions of dollars).

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, 2015. The discussion below should be read in conjunction with that report.

Jim Bridger Plant Selective Catalytic Reduction Equipment: 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 of SCR on unit 3 and unit 4. 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 $102 million, excluding AFUDC. As of September 30, 2016, Idaho Power had expended $96 million, excluding AFUDC, on SCR installation at units 3 and 4. The unit 3 SCR was operating as of November 2015, and as of the date of this report the unit 4 SCR remains on schedule and within the total project cost estimate. In light of the uncertainty resulting from pending environmental regulation and the substantial

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estimated cost of the SCR installation, Idaho Power is assessing whether to move forward with the installation of SCR on units 1 and 2 at the Jim Bridger power plant. The expected capital expenditures (excluding AFUDC) in the table above include an estimated range of $40-$50 million in the years 2018-2020 relating to the installation of SCR on units 1 and 2.

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 $44 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 $84 million on the Boardman-to-Hemingway project through September 30, 2016. Pursuant to the terms of the joint funding arrangements, approximately $41 million of that amount has been received by Idaho Power as reimbursement from the project participants as of September 30, 2016. Idaho Power has accrued in receivables approximately $15 million more that will be billed by Idaho Power in the future to the project participants for expenses Idaho Power has incurred, for a total amount reimbursable by joint permitting participants of $56 million. In addition to the $56 million amount, $6 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. Joint permitting participants are obligated to reimburse Idaho Power for their share of any future project permitting expenditures incurred by Idaho Power. 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 federal review and approval by the U.S. Bureau of Land Management (BLM), the U.S. Forest Service, the Department of the Navy, the Army Corps of Engineers, and certain other federal agencies. The BLM, as the lead federal agency on the National Environmental Policy Act review, issued a draft environmental impact statement (EIS) for the project in December 2014 and, as of the date of this report, the BLM's schedule provides for the issuance of a final EIS in late 2016 and a record of decision in 2017. In the separate Oregon state permitting process, Idaho Power submitted a final draft amended preliminary application for a site certificate to the Oregon Department of Energy in June 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 2023 or beyond.

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 $60 million, including AFUDC. Idaho Power has expended approximately $31 million on the permitting phase of the project through September 30, 2016. 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 in November 2013. In its record of decision, the BLM authorized the routing for all segments except Segments 8 and 9 (Idaho Power has an interest in both segments) deferring its decision on those segments to resolve routing concerns in those areas. In September 2016, the Interior Board of Land Appeals affirmed the BLM's record of decision, which was challenged by certain third-parties. With respect to the two deferred segments, the BLM has initiated a supplemental EIS process. The final supplemental EIS for the two deferred segments was released on October 7, 2016. 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 late 2016.

Western Energy Imbalance Market: Utilities in the western United States outside the California Independent System Operator (California ISO) have traditionally relied upon a combination of automated and manual dispatch within the hour to balance

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generation and load to maintain reliable supply. These utilities have limited capability to transact within the hour outside their balancing area. In contrast, energy imbalance markets use automated intra-hour economic dispatch of generation from committed resources to serve loads. The California ISO and PacifiCorp implemented a new energy imbalance market in 2014 (Western EIM) under which the parties enabled their systems to interact for dispatch purposes. The Western EIM is intended to reduce the power supply costs to serve customers through more efficient dispatch of a larger and more diverse pool of resources, to integrate intermittent power from renewable generation sources more effectively, and to enhance reliability. Participation in the Western EIM is voluntary and available to all balancing authorities in the western United States. Following an evaluation of the potential power supply cost savings and other advantages, system upgrade requirements, and estimated capital and ongoing operating costs, in April 2016, Idaho Power executed an agreement under which it intends to, subject to regulatory approval and other conditions, participate in the Western EIM. Idaho Power anticipates that its participation in the Western EIM would commence in the spring of 2018. On August 19, 2016, Idaho Power filed an application with the IPUC requesting specified accounting treatment associated with its participation in the Western EIM.

Defined Benefit Pension Plan Contributions

While it has no minimum contribution requirement to its defined benefit pension plan in 2016, Idaho Power has contributed $40 million to the plan during 2016. No additional contributions during 2016 are expected. Idaho Power contributed $39 million and $30 million to its defined benefit pension plan in 2015 and 2014, respectively. 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. 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, 2016, 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, 2015, except for the following:


•	on March 10, 2016, Idaho Power issued $120 million in principal amount of 4.05 percent first mortgage bonds, Series J, maturing on March 1, 2046;


•	on April 11, 2016, Idaho Power redeemed, prior to maturity, $100 million in principal amount of 6.15 percent first mortgage bonds, medium-term notes, Series H due April 2019. 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 $14 million; and

•

ten power purchase agreements with solar energy developers were terminated due to either an uncured breach or voluntary termination by the counterparties. Termination of the agreements reduced Idaho Power's contractual payment obligations by approximately $267 million over the 20-year lives of the terminated contracts, which represents approximately 6 percent of the cogeneration and small power production purchase obligations reported in the Annual Report on Form 10-K for the year ended December 31, 2015.

Dividends

In September 13, 2016, IDACORP's board of directors approved an increase in the regular quarterly cash dividend on IDACORP's common stock from $0.51 to $0.55. 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.

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, 2015.

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REGULATORY MATTERS

Introduction

Idaho Power's development of rate case plans takes into consideration short-term and long-term needs for rate relief and involves several factors that can affect the timing of rate filings. These 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's most recent general rate cases in Idaho and Oregon were filed during 2011, and Idaho Power filed a large 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. Idaho Power also reset its base-rate power supply expenses in the Idaho jurisdiction for purposes of updating the collection of costs through retail rates in 2014, but without a resulting net increase in rates. Between general rate cases, Idaho Power relies upon customer growth, power cost adjustment mechanisms, tariff riders, and other mechanisms to reduce the impact of regulatory lag, which refers to the period of time between making an investment or incurring an expense and recovering that investment or expense and earning a return. Management's regulatory focus in recent years has been largely on regulatory settlement stipulations and the design of rate mechanisms. Idaho Power continues to assess the need and timing of filing a general rate case in its two retail jurisdictions, based on its consideration of factors such as those described above.

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, 2015. 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, 2015, 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 Retail Rate Changes During 2016

During 2016 to-date, Idaho Power has received orders authorizing the rate changes summarized in the table below.



Description	Status	Estimated Rate Impact⁽¹⁾	Notes
Power Cost Adjustment Mechanism - Idaho	New PCA rate became effective June 1, 2016	$17.3 million PCA increase for the period from June 1, 2016 to May 31, 2017	The potential revenue 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, 2016	$11.2 million FCA increase for the period from June 1, 2016 to May 31, 2017	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 instead linking it 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 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 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 stipulation 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.

Idaho Power recorded $1.5 million of additional ADITC amortization during the first nine months of 2016 based on its estimate of Idaho ROE for the full-year 2016. Idaho Power estimates that it will record $2 million of additional ADITC amortization for the full year 2016.

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

Deferred power supply costs represent certain differences between Idaho Power's actual net power supply costs and the costs included in its retail rates, the latter being based on annual forecasts of power supply costs. Deferred power supply costs are recorded on the balance sheets for future recovery or refund through customer rates.

The table that follows summarizes the change in deferred net power supply costs during the nine months ended September 30, 2016.



	Idaho			Oregon⁽¹⁾			Total
Balance at December 31, 2015	$	44,556		$	2,664		$	47,220
Current period net power supply costs deferred	17,408			—			17,408
Prior amounts recovered through rates	(20,341		)	(1,868		)	(22,209		)
SO₂ allowance and renewable energy certificate sales	(876		)	(42		)	(918		)
Revenue sharing and energy efficiency rider funds	(7,141		)	—			(7,141		)
Interest and other	269			241			510
Balance at September 30, 2016	$	33,875		$	995		$	34,870

⁽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.

Open Access Transmission Tariff Filing

Idaho Power uses a formula rate for transmission service provided under its OATT, which allows transmission rates to be updated annually based primarily on financial and operational data Idaho Power files with the FERC. On August 29, 2016, Idaho Power filed its 2016 final transmission rate with the FERC, reflecting a transmission rate of $25.52 per kW-year, to be effective for the period from October 1, 2016 to September 30, 2017. Idaho Power's final rate was based on a net annual transmission revenue requirement of $127.4 million. The existing OATT rate in effect from October 1, 2015 to September 30, 2016, was $23.43 per kW-year based on a net annual transmission revenue requirement of $121.3 million.

Transmission Revenues Associated with Asset Exchange Transaction

Effective in October 2015, Idaho Power and PacifiCorp each transferred to the other certain interests in transmission-related equipment. In connection with that transaction, the companies terminated or amended a number of long-term agreements between Idaho Power and PacifiCorp related to the ownership and operation of transmission-related equipment and transmission services. In 2014, Idaho Power collected approximately $8 million in transmission revenues under long-term transmission agreements that were terminated in connection with the asset exchange transaction. As a result of the transaction and termination of those long-term transmission agreements, Idaho Power's OATT rate will increase; however, in accordance with a FERC order, the current formula rate methodology will phase in the increase over a two-year period from August 1, 2016 through September 30, 2018.

In compliance with the IPUC's order approving the asset exchange transaction, Idaho Power submitted to the IPUC a request for verification that its regulatory accounting method reflecting a symmetrical tracking of changes in transmission revenues resulting specifically from the asset exchange with PacifiCorp complies with the IPUC’s order. As an alternative proposed by Idaho Power to its symmetrical tracking, on August 3, 2016, the IPUC ordered that any changes in transmission revenues resulting from the asset exchange will be addressed, prospectively, in Idaho Power's next general rate case.

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Depreciation Rate Request

On October 21, 2016, Idaho Power filed an application with the IPUC requesting authorization to (a) accelerate depreciation for the North Valmy coal-fired power plant, to allow the plant to be fully depreciated by December 31, 2025, (b) establish a balancing account to track the incremental costs and benefits associated with the accelerated depreciation date, and (c) adjust customer rates to recover the associated incremental annual levelized revenue requirement of $28.5 million. On the same date, Idaho Power also filed an application with the IPUC requesting approval to institute revised depreciation rates for Idaho Power's electric plant-in-service and adjust Idaho jurisdictional base rates by $6.7 million to reflect the revised depreciation rates.

Renewable and Other Energy Contracts

Idaho Power has contracts for the purchase of power from cogeneration and small power production (CSPP) and non-CSPP renewable generation sources, such as biomass, solar, small hydroelectric projects, and two geothermal projects. Idaho Power purchases wind power from both CSPP and non-CSPP facilities, including its largest non-CSPP wind power project -- the Elkhorn Valley wind project with a 101 MW nameplate capacity. As of September 30, 2016, Idaho Power had contracts to purchase energy from 110 on-line CSPP projects and 20 additional projects expected to come on-line by June 1, 2017. The following table sets forth, as of September 30, 2016, the resource type and nameplate capacity of Idaho Power's signed CSPP-related agreements. These agreements have original contract terms ranging from one to 35 years.



Resource Type	On-line (MW)	Under Contract but not yet On-line (MW)	Total CSPP Projects under Contract (MW)
Wind	577	50	627
Solar	40	249	289
Hydroelectric	147	9	156
Other	60	—	60
Total	824	308	1,132

All but one of the projects not yet on-line have scheduled on-line dates no later than year-end 2016 (one hydroelectric project is scheduled to be on-line in June 2017), though with the extension of federal investment tax credit availability, it is likely the on-line date for some of the solar projects may extend into 2017.

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, in January 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 August 2015, the IPUC issued an order reducing the length of PURPA contracts that are over the standard rate threshold to two years and determining that the sufficiency period for new generation capacity is through 2024.

For the Oregon jurisdiction, in April 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 March 29, 2016, the OPUC issued an order permanently reducing the eligibility cap for solar project standard contracts to 3 MW, with all other resource types retaining an eligibility cap of 10 MW. In its order, the OPUC retained the requirement for up to 20 year contract lengths for Oregon jurisdictional projects, comprised of 15 years of fixed prices and 5 years of market index prices.

In June 2016, the FERC held a technical conference on implementation issues under PURPA, including the mandatory power purchase obligation and the methods for determining avoided costs for those purchases. The conference also involved a discussion of PURPA project siting issues and minimum contract term lengths. On September 6, 2016, the FERC filed a notice inviting post-technical conference comments on (1) the use of the "one-mile rule" to determine the size of an entity seeking certification as a small power production qualifying facility and (2) minimum standards for PURPA-purchase contracts. Idaho Power is unable to predict what policy or rulemaking actions or proceedings, if any, on PURPA-related issues will result from the technical conference.

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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 $240 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, 2016. 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, 2016, Idaho Power's regulatory liability for collection of AFUDC relating to the HCC was $99.6 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, the Clean Water Act, the Resource Conservation and Recovery Act, the Toxic Substances Control Act, the Comprehensive Environmental Response, Compensation and Liability Act, and the Endangered Species Act, among other laws. Current and pending environmental legislation relates to, among other issues, climate change, greenhouse gas, mercury and other emissions, air quality, hazardous wastes, polychlorinated biphenyls, and threatened and endangered species. These laws are administered by a number of federal, state, and local agencies. In addition to imposing continuing compliance obligations and associated costs, these laws and regulations provide authority to regulators to levy substantial penalties for noncompliance, injunctive relief, and other sanctions. Idaho Power's three coal-fired power plants and three natural gas-fired combustion turbine power plants are subject to many of these regulations. Idaho Power's 17 hydroelectric projects are also subject to a number of water discharge standards and other environmental requirements.

Compliance with current and future environmental laws and regulations may:


•	increase the operating costs of generating plants;


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


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


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


•	reduce the output from current generating facilities.

Current and future environmental laws and regulations will increase the cost of operating fossil fuel-fired generation plants and constructing new generation and transmission facilities, in large part through the substantial cost of permitting activities and the required installation of additional pollution control devices. In many parts of the United States, some higher-cost, high-emission coal-fired plants have ceased operation or the plant owners have announced a near-term cessation of operation, as the cost of compliance makes the plants uneconomical to operate. The decision to agree to cease operation of the Boardman coal-fired plant, in which Idaho Power owns a 10 percent interest, by the end of 2020, was based in part on the significant future cost of compliance with environmental laws and regulations. Additionally, in light of the uncertainty resulting from pending environmental regulation and the substantial estimated cost of the SCR installation, Idaho Power is assessing whether to move forward with the installation of SCR on units 1 and 2 at the Jim Bridger power plant. Beyond increasing costs generally, these environmental laws and regulations could affect IDACORP's and Idaho Power's results of operations and financial condition if the costs associated with these environmental requirements and early plant retirements 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, 2015, includes a summary of Idaho Power's expected capital and operating expenditures for environmental matters during the period from 2016 to 2018. 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

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ended December 31, 2015. Included below is a summary of notable developments in environmental and related issues impacting Idaho Power since the discussion in that report.

Developments in Regulation of Sage Grouse Habitat

In February 2016, a lawsuit was filed in the U.S. District Court in Idaho challenging the BLM's sage grouse resource management and land use plan revisions that became effective in 2015 under the Federal Land Policy and Management Act. The lawsuit challenges the plans and associated environmental impact statements across the sage grouse range and alleges that the plans fail to ensure that sage grouse populations and habitats will be protected and restored in accordance with the best available science and legal mandates. Further, the complaint challenges certain exemptions provided for the Boardman-to-Hemingway and Gateway West transmission line projects. Idaho Power has intervened in the proceedings in an effort to support the exemptions provided for in the BLM's plans.

In May 2016, a separate lawsuit was filed in the U.S. District Court of North Dakota, challenging the BLM's sage grouse resource management and land use plan revisions, including the exemptions provided for the Boardman-to-Hemingway and Gateway West transmission line projects. Idaho Power has also intervened in these proceedings to support the exemptions.

Endangered Species Act and National Environmental Policy Act Developments

In May 2016, the United States District Court for the District of Oregon issued an opinion finding that in the context of hydroelectric facilities owned and operated by the U.S. Army Corps of Engineers and located on the lower Snake River, National Oceanic and Atmospheric Administration's National Marine Fisheries Service (NOAA Fisheries) violated the Endangered Species Act (ESA) by using improper standards, failing to consider adequately the impact of climate change on habitat conditions, and placing undue reliance on unproven, future federal habitat conservation measures, particularly to the degree that the success of the measures could be undermined by climate change. The court also found that other federal agencies violated the National Environmental Policy Act (NEPA) by failing to prepare a comprehensive environmental impact statement on implementation of the conservation measures ordered by NOAA Fisheries, including analysis of the measures directed by NOAA Fisheries and other reasonable alternatives. The court’s opinion and its emphasis on a climate change-driven analysis element, if generalized to other situations, could require ESA-driven avoidance, minimization, and compensatory mitigation efforts to incorporate surplus measures to ensure species’ protection, which could result in considerable increases in cost beyond the cost of additional analysis in the NEPA process. In September 2016, federal agencies initiated an environmental impact statement process to examine hydroelectric dams on the lower Snake River, which the companies expect will take place over a five-year period.

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, 2015.

Recently Issued Accounting Pronouncements

For a listing of new and recently adopted accounting standards, see Note 1 - "Summary of Significant Accounting Policies" to the notes to the condensed consolidated financial statements included in this report.

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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, 2015 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, 2016. IDACORP has not entered into any of these market-risk-sensitive instruments for trading purposes.

Interest Rate Risk

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

Variable Rate Debt: As of September 30, 2016, IDACORP had $9.7 million of net floating rate debt. The fair market value of this debt approximates the net carrying amount as the cost of borrowing is variable and approximates current market rates. Assuming no change in financial structure, if variable interest rates were to average one percentage point higher than the average rate on September 30, 2016, annual interest expense would increase and pre-tax earnings would decrease by an insignificant amount for IDACORP.

Fixed Rate Debt: As of September 30, 2016, IDACORP had $1.7 billion in fixed rate debt, with a fair market value of approximately $2.0 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 $297.4 million if market interest rates were to decline by one percentage point from their September 30, 2016 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, 2016, 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, 2015. 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, 2016, Idaho Power had posted no performance assurance collateral related to these contracts. 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, 2016, the amount of collateral that could be requested upon a downgrade to below investment grade was approximately $5.2 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, 2016, 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, 2015.

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Additional information regarding Idaho Power’s management of credit risk and credit contingent features can be found in Note 11 – “Derivative Financial Instruments” to the condensed consolidated financial statements included in this report.

Equity Price Risk

IDACORP is exposed to price fluctuations in equity markets, primarily through Idaho Power's defined benefit pension plan assets, a mine reclamation trust fund owned by an equity-method investment of Idaho Power, and other equity security investments at Idaho Power. The equity securities held by the pension plan and in such accounts are diversified to achieve broad market participation and reduce the impact of any single investment, sector, or geographic region. Idaho Power has established asset allocation targets for the pension plan holdings, which are described in Note 10 - "Benefit Plans" to the consolidated financial statements included in IDACORP's Annual Report on Form 10-K for the year ended December 31, 2015. IDACORP’s equity price risk as of September 30, 2016, 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, 2015.

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 (pursuant to Rule 13a-15(b) of the Securities Exchange Act of 1934 (Exchange Act)) as of September 30, 2016, have concluded that IDACORP’s disclosure controls and procedures (as defined in Rule 13a-15(e) of the Exchange Act) 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 (pursuant to Rule 13a-15(b) of the Exchange Act) as of September 30, 2016, have concluded that Idaho Power’s disclosure controls and procedures (as defined in Rule 13a-15(e) of the Exchange Act) 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, 2016, 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, 2015, as supplemented in Part II - Item 1A - "Risk Factors" in IDACORP's and Idaho Power's Quarterly Report on Form 10-Q for the quarter ended June 30, 2016, 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.

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Issuer Purchases of Equity Securities

During the quarter ended September 30, 2016, IDACORP effected the following repurchases of its common stock:



Period	(a) Total Number of Shares Purchased⁽¹⁾	(b) Average Price Paid per Share		(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	(d) Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs
July 1, 2016 - July 31, 2016	—	$	—	—	—
August 1, 2016 - August 31, 2016	105	76.07		—	—
September 1, 2016 - September 30, 2016	51	78.28		—	—
Total	156	$	76.79	—	—

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

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.

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 27, 2016	By:	/s/ Darrel T. Anderson
			Darrel T. Anderson
			President and Chief Executive Officer

Date:	October 27, 2016	By:	/s/ Steven R. Keen
			Steven R. Keen
			Senior Vice President, Chief Financial
			Officer, and Treasurer





		IDAHO POWER COMPANY
		(Registrant)



Date:	October 27, 2016	By:	/s/ Darrel T. Anderson
			Darrel T. Anderson
			President and Chief Executive Officer

Date:	October 27, 2016	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, 2016:



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

4.1	Idaho Power Company Forty-eighth Supplemental Indenture, dated effective as of September 1, 2016 to Mortgage and Deed of Trust, dated as of October 1, 1937	8-K	1-3198	4.1	9/28/2016
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

Expected capital expenditures (excluding AFUDC)