10-Q

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, 2017
	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, smaller reporting companies, or emerging growth companies.  See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act (check one):

IDACORP, Inc.:                                

Large accelerated filer X Accelerated filer __ Non-accelerated  filer __ (Do not check if a smaller reporting company)

Smaller reporting company __

Emerging growth company __

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange

Act. __

Idaho Power Company:                                

Large accelerated filer __ Accelerated filer __ Non-accelerated  filer __ (Do not check if a smaller reporting company)

Smaller reporting company X

Emerging growth company __

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange

Act. __

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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 27, 2017:     

IDACORP, Inc.:        50,393,038

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				4
Cautionary Note Regarding Forward-Looking Statements				5
Part I. Financial Information
	Item 1. Financial Statements (unaudited)
		IDACORP, Inc.:
			Condensed Consolidated Statements of Income	7
			Condensed Consolidated Statements of Comprehensive Income	8
			Condensed Consolidated Balance Sheets	9
			Condensed Consolidated Statements of Cash Flows	11
			Condensed Consolidated Statements of Equity	12
		Idaho Power Company:
			Condensed Consolidated Statements of Income	13
			Condensed Consolidated Statements of Comprehensive Income	14
			Condensed Consolidated Balance Sheets	15
			Condensed Consolidated Statements of Cash Flows	17
		Notes to Condensed Consolidated Financial Statements		18
		Reports of Independent Registered Public Accounting Firm		32
	Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations			34
	Item 3. Quantitative and Qualitative Disclosures About Market Risk			57
	Item 4. Controls and Procedures			59
Part II. Other Information
	Item 1. Legal Proceedings			60
	Item 1A. Risk Factors			60
	Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			60
	Item 3. Defaults Upon Senior Securities			60
	Item 4. Mine Safety Disclosures			60
	Item 5. Other Information			60
	Item 6. Exhibits			61
Signatures				62

3

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
AOCI	-	Accumulated Other Comprehensive Income
ASU	-	Accounting Standards Update
BCC	-	Bridger Coal Company, a joint venture of IERCo
BLM	-	U.S. Bureau of Land Management
CPP	-	Clean Power Plan
CWA		Clean Water Act
EIS	-	Environmental Impact Statement
EPA	-	U.S. Environmental Protection Agency
ESA	-	Endangered Species Act
FASB	-	Financial Accounting Standards Board
FCA	-	Fixed Cost Adjustment
FERC	-	Federal Energy Regulatory Commission
FIP	-	Federal Implementation Plan
GHG NSPS	-	Greenhouse Gas New Source Performance Standards
HCC	-	Hells Canyon Complex
IDACORP	-	IDACORP, Inc., an Idaho corporation
IBLA	-	U.S. Department of Interior Board of Land Appeals
ICE	-	Intercontinental Exchange
Idaho Power	-	Idaho Power Company, an Idaho corporation
Idaho Rider	-	Idaho Energy Efficiency Rider
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
IFS	-	IDACORP Financial Services, a subsidiary of IDACORP, Inc.
IPUC	-	Idaho Public Utilities Commission
IRP	-	Integrated Resource Plan
MD&A	-	Management’s Discussion and Analysis of Financial Condition and Results of Operations
MW	-	Megawatt
MWh	-	Megawatt-hour
NYMEX	-	New York Mercantile Exchange
O&M	-	Operations and Maintenance
OATT	-	Open Access Transmission Tariff
OPUC	-	Public Utility Commission of Oregon
PCA	-	Idaho Power Cost Adjustment
PURPA	-	Public Utility Regulatory Policies Act of 1978
SCR	-	Selective Catalytic Reduction
SEC	-	U.S. Securities and Exchange Commission
SMSP	-	Security Plan for Senior Management Employees
WPSC	-	Wyoming Public Service Commission

4

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. (IDACORP) and Idaho Power Company (Idaho Power) 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," "potential," "plans," "predicts," "projects," "may result," "may continue," or similar expressions, are not statements of historical facts and may be forward-looking. Forward-looking statements are not guarantees of future performance and involve estimates, assumptions, risks, and uncertainties. Actual results, performance, or outcomes may differ materially from the results discussed in the statements. In addition to any assumptions and other factors and matters referred to specifically in connection with such forward-looking statements, factors that could cause actual results or outcomes to differ materially from those contained in forward-looking statements include those factors set forth in this report, IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2016, 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, 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, including the impact of settlement stipulations;

• the expense and risks associated with capital expenditures for infrastructure, and the timing and availability of cost recovery for such expenditures through customer rates;

• 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 through customer rates in the event of those changes;

• the impacts of economic conditions, including inflation, 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 self-generation or energy efficiency technologies that reduce Idaho Power's 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 resulting 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 power purchased costs and operational challenges associated with purchasing and integrating intermittent renewable energy sources into Idaho Power's resource portfolio;

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

5

decisions by the Idaho or Oregon public utility commissions, and the companies' past or projected financial performance;

• reductions in credit ratings, which could adversely impact access to capital markets, increase costs of borrowing, 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; and

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

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

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PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

IDACORP, Inc.

Condensed Consolidated Statements of Income

(unaudited)

	Three months ended September 30,						Nine months ended September 30,
	2017			2016			2017			2016
	(in thousands, except per share amounts)
Operating Revenues:
Electric utility:
General business	$	373,569		$	341,825		$	938,802		$	885,486
Off-system sales	6,710			6,143			25,609			16,532
Other revenues	26,376			23,506			75,976			64,433
Total electric utility revenues	406,655			371,474			1,040,387			966,451
Other	1,669			571			3,487			1,986
Total operating revenues	408,324			372,045			1,043,874			968,437
Operating Expenses:
Electric utility:
Purchased power	75,653			74,448			186,275			170,675
Fuel expense	54,529			73,925			111,197			139,657
Power cost adjustment	10,979			(18,342		)	51,208			11,914
Other operations and maintenance	84,197			87,090			259,445			259,813
Energy efficiency programs	9,883			9,102			26,726			24,256
Depreciation	40,259			36,036			122,262			107,447
Taxes other than income taxes	8,614			8,287			26,134			25,228
Total electric utility expenses	284,114			270,546			783,247			738,990
Other	3,296			3,571			9,789			10,748
Total operating expenses	287,410			274,117			793,036			749,738
Operating Income	120,914			97,928			250,838			218,699
Allowance for Equity Funds Used During Construction	5,712			5,931			16,555			16,153
Earnings of Unconsolidated Equity-Method Investments	5,232			12,324			7,269			13,650
Other Income, Net	2,256			2,681			7,024			7,074
Interest Expense:
Interest on long-term debt	20,300			20,296			60,897			61,659
Other interest	2,827			2,605			8,298			7,587
Allowance for borrowed funds used during construction	(2,385		)	(2,589		)	(7,106		)	(7,226		)
Total interest expense, net	20,742			20,312			62,089			62,020
Income Before Income Taxes	113,372			98,552			219,597			193,556
Income Tax Expense	22,296			15,535			45,420			28,622
Net Income	91,076			83,017			174,177			164,934
Adjustment for (income) loss attributable to noncontrolling interests	(442		)	83			(610		)	141
Net Income Attributable to IDACORP, Inc.	$	90,634		$	83,100		$	173,567		$	165,075
Weighted Average Common Shares Outstanding - Basic	50,362			50,296			50,361			50,299
Weighted Average Common Shares Outstanding - Diluted	50,421			50,393			50,408			50,361
Earnings Per Share of Common Stock:
Earnings Attributable to IDACORP, Inc. - Basic	$	1.80		$	1.65		$	3.45		$	3.28
Earnings Attributable to IDACORP, Inc. - Diluted	$	1.80		$	1.65		$	3.44		$	3.28
Dividends Declared Per Share of Common Stock	$	0.55		$	0.51		$	1.65		$	1.53

The accompanying notes are an integral part of these statements.

7

IDACORP, Inc.

Condensed Consolidated Statements of Comprehensive Income

(unaudited)

	Three months ended September 30,					Nine months ended September 30,
	2017			2016		2017			2016
	(in thousands)
Net Income	$	91,076		$	83,017	$	174,177		$	164,934
Other Comprehensive Income:
Unfunded pension liability adjustment, net of tax   of $302, $362, $906 and $1,085	471			563		1,412			1,690
Total Comprehensive Income	91,547			83,580		175,589			166,624
Comprehensive (income) loss attributable to noncontrolling interests	(442		)	83		(610		)	141
Comprehensive Income Attributable to IDACORP, Inc.	$	91,105		$	83,663	$	174,979		$	166,765

The accompanying notes are an integral part of these statements.

8

IDACORP, Inc.

Condensed Consolidated Balance Sheets

(unaudited)

	September 30, 2017			December 31, 2016
	(in thousands)
Assets
Current Assets:
Cash and cash equivalents	$	104,411		$	61,480
Receivables:
Customer (net of allowance of $1,195 and $968, respectively)	101,703			71,557
Other (net of allowance of $146 and $164, respectively)	5,399			15,280
Taxes receivable	4,648			12,781
Accrued unbilled revenues	59,697			80,738
Materials and supplies (at average cost)	58,472			57,858
Fuel stock (at average cost)	54,093			53,698
Prepayments	16,477			18,389
Current regulatory assets	52,927			62,570
Other	101			5,961
Total current assets	457,928			440,312
Investments	111,952			125,164
Property, Plant and Equipment:
Utility plant in service	5,840,848			5,732,044
Accumulated provision for depreciation	(2,086,119		)	(1,988,477		)
Utility plant in service - net	3,754,729			3,743,567
Construction work in progress	463,106			405,069
Utility plant held for future use	7,511			7,441
Other property, net of accumulated depreciation	15,597			15,922
Property, plant and equipment - net	4,240,943			4,171,999
Other Assets:
American Falls and Milner water rights	7,641			9,487
Company-owned life insurance	58,973			57,553
Regulatory assets	1,412,086			1,409,329
Long-term receivables (net of allowance of $402)	26,367			23,482
Other	51,293			52,571
Total other assets	1,556,360			1,552,422
Total	$	6,367,183		$	6,289,897

The accompanying notes are an integral part of these statements.

9

IDACORP, Inc.

Condensed Consolidated Balance Sheets

(unaudited)

	September 30, 2017			December 31, 2016
	(in thousands)
Liabilities and Equity
Current Liabilities:
Current maturities of long-term debt	$	—		$	1,064
Notes payable	2,425			21,800
Accounts payable	72,153			106,194
Taxes accrued	57,902			11,348
Interest accrued	21,406			22,377
Accrued compensation	39,903			45,787
Current regulatory liabilities	2,296			9,944
Advances from customers	20,607			21,438
Other	9,100			9,763
Total current liabilities	225,792			249,715
Other Liabilities:
Deferred income taxes	1,241,091			1,244,250
Regulatory liabilities	466,162			436,845
Pension and other postretirement benefits	391,579			411,523
Other	44,651			45,084
Total other liabilities	2,143,483			2,137,702
Long-Term Debt	1,745,746			1,744,614
Commitments and Contingencies
Equity:
IDACORP, Inc. shareholders’ equity:
Common stock, no par value (120,000,000 shares authorized; 50,420,017 shares issued)	855,043			851,833
Retained earnings	1,413,387			1,323,198
Accumulated other comprehensive loss	(19,470		)	(20,882		)
Treasury stock (26,979 and 23,244 shares at cost, respectively)	(1,368		)	(243		)
Total IDACORP, Inc. shareholders’ equity	2,247,592			2,153,906
Noncontrolling interests	4,570			3,960
Total equity	2,252,162			2,157,866
Total	$	6,367,183		$	6,289,897
The accompanying notes are an integral part of these statements.

10

IDACORP, Inc.

Condensed Consolidated Statements of Cash Flows

(unaudited)

	Nine months ended September 30,
	2017			2016
	(in thousands)
Operating Activities:
Net income	$	174,177		$	164,934
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	125,051			110,161
Deferred income taxes and investment tax credits	(195		)	30,077
Changes in regulatory assets and liabilities	61,968			13,502
Pension and postretirement benefit plan expense	21,687			22,175
Contributions to pension and postretirement benefit plans	(45,158		)	(43,851		)
Earnings of unconsolidated equity-method investments	(7,269		)	(13,650		)
Distributions from unconsolidated equity-method investments	18,350			17,114
Allowance for equity funds used during construction	(16,555		)	(16,153		)
Other non-cash adjustments to net income, net	5,220			3,876
Change in:
Accounts receivable	(20,520		)	(12,435		)
Accounts payable and other accrued liabilities	(32,494		)	(10,033		)
Taxes accrued/receivable	54,687			8,490
Other current assets	18,736			7,343
Other current liabilities	(3,010		)	(5,451		)
Other assets	(5,357		)	(1,277		)
Other liabilities	(494		)	595
Net cash provided by operating activities	348,824			275,417
Investing Activities:
Additions to property, plant and equipment	(207,340		)	(199,966		)
Payments received from transmission project joint funding partners	5,934			6,853
Proceeds from the sale of emission allowances and renewable energy certificates	1,892			969
Purchase of available-for-sale securities	(3,248		)	(9,843		)
Proceeds from the sale of available-for-sale securities	3,755			14,453
Purchase of life insurance investment	—			(10,000		)
Other	183			(9		)
Net cash used in investing activities	(198,824		)	(197,543		)
Financing Activities:
Issuance of long-term debt	—			120,000
Retirement of long-term debt	(1,064		)	(101,064		)
Dividends on common stock	(83,441		)	(77,350		)
Net change in short-term borrowings	(19,375		)	(14,600		)
Acquisition of treasury stock	(3,189		)	(3,287		)
Make-whole premium on retirement of long-term debt	—			(13,895		)
Other	—			(1,684		)
Net cash used in financing activities	(107,069		)	(91,880		)
Net increase (decrease) in cash and cash equivalents	42,931			(14,006		)
Cash and cash equivalents at beginning of the period	61,480			114,802
Cash and cash equivalents at end of the period	$	104,411		$	100,796
Supplemental Disclosure of Cash Flow Information:
Cash paid during the period for:
Income taxes	$	1,702		$	2,187
Interest (net of amount capitalized)	$	60,257		$	60,224
Non-cash investing activities:
Additions to property, plant and equipment in accounts payable	$	23,502		$	21,583

The accompanying notes are an integral part of these statements.

11

IDACORP, Inc.

Condensed Consolidated Statements of Equity

(unaudited)

	Nine months ended September 30,
	2017			2016
	(in thousands)
Common Stock
Balance at beginning of period	$	851,833		$	849,112
Cumulative effect of change in accounting principle	—			234
Other	3,210			1,352
Balance at end of period	855,043			850,698
Retained Earnings
Balance at beginning of period	1,323,198			1,230,105
Cumulative effect of change in accounting principle	—			(234		)
Net income attributable to IDACORP, Inc.	173,567			165,075
Common stock dividends ($1.65 and $1.53 per share)	(83,378		)	(77,214		)
Balance at end of period	1,413,387			1,317,732
Accumulated Other Comprehensive (Loss) Income
Balance at beginning of period	(20,882		)	(21,276		)
Unfunded pension liability adjustment (net of tax)	1,412			1,690
Balance at end of period	(19,470		)	(19,586		)
Treasury Stock
Balance at beginning of period	(243		)	(57		)
Issued	2,063			3,143
Acquired	(3,188		)	(3,287		)
Balance at end of period	(1,368		)	(201		)
Total IDACORP, Inc. shareholders’ equity at end of period	2,247,592			2,148,643
Noncontrolling Interests
Balance at beginning of period	3,960			4,160
Net income (loss) attributable to noncontrolling interests	610			(141		)
Balance at end of period	4,570			4,019
Total equity at end of period	$	2,252,162		$	2,152,662

The accompanying notes are an integral part of these statements.

12

Idaho Power Company

Condensed Consolidated Statements of Income

(unaudited)

	Three months ended September 30,						Nine months ended September 30,
	2017			2016			2017			2016
	(in thousands)
Operating Revenues:
General business	$	373,569		$	341,825		$	938,802		$	885,486
Off-system sales	6,710			6,143			25,609			16,532
Other revenues	26,376			23,506			75,976			64,433
Total operating revenues	406,655			371,474			1,040,387			966,451
Operating Expenses:
Operation:
Purchased power	75,653			74,448			186,275			170,675
Fuel expense	54,529			73,925			111,197			139,657
Power cost adjustment	10,979			(18,342		)	51,208			11,914
Other operations and maintenance	84,197			87,090			259,445			259,813
Energy efficiency programs	9,883			9,102			26,726			24,256
Depreciation	40,259			36,036			122,262			107,447
Taxes other than income taxes	8,614			8,287			26,134			25,228
Total operating expenses	284,114			270,546			783,247			738,990
Income from Operations	122,541			100,928			257,140			227,461
Other Income (Expense):
Allowance for equity funds used during construction	5,712			5,931			16,555			16,153
Earnings of unconsolidated equity-method investments	4,151			11,121			5,068			11,528
Other expense, net	(408		)	(328		)	(1,178		)	(1,845		)
Total other income	9,455			16,724			20,445			25,836
Interest Charges:
Interest on long-term debt	20,300			20,296			60,897			61,659
Other interest	2,811			2,546			8,249			7,397
Allowance for borrowed funds used during construction	(2,385		)	(2,589		)	(7,106		)	(7,226		)
Total interest charges	20,726			20,253			62,040			61,830
Income Before Income Taxes	111,270			97,399			215,545			191,467
Income Tax Expense	22,941			17,370			46,353			31,097
Net Income	$	88,329		$	80,029		$	169,192		$	160,370

The accompanying notes are an integral part of these statements.

13

Idaho Power Company

Condensed Consolidated Statements of Comprehensive Income

(unaudited)

	Three months ended September 30,				Nine months ended September 30,
	2017		2016		2017		2016
	(in thousands)
Net Income	$	88,329	$	80,029	$	169,192	$	160,370
Other Comprehensive Income:
Unfunded pension liability adjustment, net of tax   of $302, $362, $906 and $1,085	471		563		1,412		1,690
Total Comprehensive Income	$	88,800	$	80,592	$	170,604	$	162,060

The accompanying notes are an integral part of these statements.

14

Idaho Power Company

Condensed Consolidated Balance Sheets

(unaudited)

	September 30, 2017			December 31, 2016
	(in thousands)
Assets
Electric Plant:
In service (at original cost)	$	5,840,848		$	5,732,044
Accumulated provision for depreciation	(2,086,119		)	(1,988,477		)
In service - net	3,754,729			3,743,567
Construction work in progress	463,106			405,069
Held for future use	7,511			7,441
Electric plant - net	4,225,346			4,156,077
Investments and Other Property	94,497			107,379
Current Assets:
Cash and cash equivalents	101,766			44,140
Receivables:
Customer (net of allowance of $1,195 and $968, respectively)	101,703			71,557
Other (net of allowance of $146 and $164, respectively)	5,294			7,555
Taxes receivable	—			23,334
Accrued unbilled revenues	59,697			80,738
Materials and supplies (at average cost)	58,472			57,858
Fuel stock (at average cost)	54,093			53,698
Prepayments	16,362			18,270
Current regulatory assets	52,927			62,570
Other	101			5,962
Total current assets	450,415			425,682
Deferred Debits:
American Falls and Milner water rights	7,641			9,487
Company-owned life insurance	58,973			57,553
Regulatory assets	1,412,086			1,409,329
Other	72,959			71,237
Total deferred debits	1,551,659			1,547,606
Total	$	6,321,917		$	6,236,744

The accompanying notes are an integral part of these statements.

15

Idaho Power Company

Condensed Consolidated Balance Sheets

(unaudited)

	September 30, 2017			December 31, 2016
	(in thousands)
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	1,297,262			1,211,547
Accumulated other comprehensive loss	(19,470		)	(20,882		)
Total common stock equity	2,085,830			1,998,703
Long-term debt	1,745,746			1,744,614
Total capitalization	3,831,576			3,743,317
Current Liabilities:
Current maturities of long-term debt	—			1,064
Notes payable	—			21,800
Accounts payable	71,951			105,846
Accounts payable to affiliates	48,329			1,056
Taxes accrued	23,981			11,348
Interest accrued	21,406			22,377
Accrued compensation	39,744			45,622
Current regulatory liabilities	2,296			9,944
Advances from customers	20,607			21,438
Other	8,568			9,103
Total current liabilities	236,882			249,598
Deferred Credits:
Deferred income taxes	1,351,966			1,351,415
Regulatory liabilities	466,162			436,845
Pension and other postretirement benefits	391,579			411,523
Other	43,752			44,046
Total deferred credits	2,253,459			2,243,829
Commitments and Contingencies
Total	$	6,321,917		$	6,236,744
The accompanying notes are an integral part of these statements.

16

Idaho Power Company

Condensed Consolidated Statements of Cash Flows

(unaudited)

	Nine months ended September 30,
	2017			2016
	(in thousands)
Operating Activities:
Net income	$	169,192		$	160,370
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	124,599			109,704
Deferred income taxes and investment tax credits	1,972			12,679
Changes in regulatory assets and liabilities	61,965			13,502
Pension and postretirement benefit plan expense	21,704			22,191
Contributions to pension and postretirement benefit plans	(45,174		)	(43,867		)
Earnings of unconsolidated equity-method investments	(5,068		)	(11,528		)
Distributions from unconsolidated equity-method investments	17,500			16,264
Allowance for equity funds used during construction	(16,555		)	(16,153		)
Other non-cash adjustments to net income, net	12			(571		)
Change in:
Accounts receivable	(27,369		)	(12,319		)
Accounts payable	14,155			(10,016		)
Taxes accrued/receivable	35,967			8,172
Other current assets	18,732			7,326
Other current liabilities	(3,004		)	(5,451		)
Other assets	(5,358		)	(1,277		)
Other liabilities	(354		)	789
Net cash provided by operating activities	362,916			249,815
Investing Activities:
Additions to utility plant	(207,327		)	(199,964		)
Payments received from transmission project joint funding partners	5,934			6,853
Proceeds from the sale of emission allowances and renewable energy certificates	1,892			969
Purchase of available-for-sale securities	(3,248		)	(9,843		)
Proceeds from the sale of available-for-sale securities	3,755			14,453
Purchase of life insurance investment	—			(10,000		)
Other	46			(108		)
Net cash used in investing activities	(198,948		)	(197,640		)
Financing Activities:
Issuance of long-term debt	—			120,000
Retirement of long-term debt	(1,064		)	(101,064		)
Dividends on common stock	(83,478		)	(77,365		)
Net change in short term borrowings	(21,800		)	—
Make-whole premium on retirement of long-term debt	—			(13,895		)
Other	—			(1,671		)
Net cash used in financing activities	(106,342		)	(73,995		)
Net increase (decrease) in cash and cash equivalents	57,626			(21,820		)
Cash and cash equivalents at beginning of the period	44,140			110,756
Cash and cash equivalents at end of the period	$	101,766		$	88,936
Supplemental Disclosure of Cash Flow Information:
Cash (received from) paid to IDACORP related to income taxes	$	(27,556	)	$	19,796
Cash paid for interest (net of amount capitalized)	$	60,208		$	60,034
Non-cash investing activities:
Additions to property, plant and equipment in accounts payable	$	23,502		$	21,583

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 significant other wholly-owned subsidiaries include IDACORP Financial Services, Inc. (IFS), an investor in affordable housing and other real estate investments, and 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).

Regulation of Utility Operations

As a regulated utility, many of Idaho Power's fundamental business decisions are subject to the approval of governmental agencies, including the prices that Idaho Power is authorized to charge for its electric service. These approvals are a critical factor in determining IDACORP's and Idaho Power's results of operations and financial condition.

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 or accrued 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, 2017, consolidated results of operations for the three and nine months endedSeptember 30, 2017 and 2016, and consolidated cash flows for the nine months endedSeptember 30, 2017 and 2016. 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, 2016. The results of operations for the interim period are not necessarily indicative of the results to be expected for the full year. A change in management's estimates or assumptions could have a material impact on IDACORP's or Idaho Power's respective financial condition and results of operations during the period in which such change occurred.

Management Estimates

Management makes estimates and assumptions when preparing financial statements in conformity with generally accepted accounting principles. These estimates and assumptions include those related to rate regulation, retirement benefits, contingencies, litigation, asset impairment, income taxes, unbilled revenues, and bad debt. These estimates and assumptions affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. These estimates involve

18

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.

Reclassifications

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

New and Recently Adopted Accounting Pronouncements

Recent Accounting Pronouncements Not Yet Adopted

In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2014-09, Revenue from Contracts with Customers (Topic 606). ASU 2014-09 is intended to enable users of financial statements to better understand and consistently analyze an entity's revenue across industries, transactions, and geographies. Under the ASU, recognition of revenue occurs when a customer obtains control of promised goods or services. In addition, the ASU requires disclosure of the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The 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 companies have assessed the impacts of ASU 2014-09 on their financial statements and do not expect the new guidance to affect the timing and amount of revenue recognized. However, the presentation and disclosure requirements of the standard will result in a change in the presentation of revenue on the companies' consolidated statements of income as well as expanded disclosures around the disaggregation of revenue. The guidance in ASU 2014-09 is effective for interim and annual reporting periods beginning after December 15, 2017. The guidance permits two implementation approaches, one requiring retrospective application of the new standard with restatement of prior years (full retrospective approach) and the other requiring prospective application of the new standard including a cumulative-effect adjustment with disclosure of results under previous standards (modified-retrospective approach). IDACORP and Idaho Power plan to adopt ASU 2014-09 on January 1, 2018, using the modified-retrospective approach.

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), intended to improve financial reporting on 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 are classified as operating leases and are not recognized on the balance sheet. The new standard is effective for interim and annual reporting periods beginning after December 15, 2018, 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. 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 arrangements. At this time, the companies do not know, and cannot reasonably estimate, the dollar impact of the adoption.

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 and related costs, which will be classified as investing activities under the new guidance. The companies already present debt prepayment and extinguishment costs, proceeds from the settlement of insurance claims (other than corporate-owned life insurance), and distributions received from equity-method investments in accordance with the new guidance. ASU 2016-15 is effective for interim and annual reporting periods beginning after December 15, 2017. The standard must be adopted retrospectively to all periods presented, unless impracticable to do so. At this time, IDACORP and Idaho Power do not believe the adoption will have a material impact on their financial statements.

19

In March 2017, the FASB issued ASU 2017-07, Compensation -- Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, which requires employers to disaggregate the service cost component from other components of net periodic benefit costs and to disclose the amounts of net periodic benefit costs that are included in each income statement line item. The standard requires employers to present the service cost component in the same line item as other compensation costs and to present the other components of net periodic benefit costs (which include interest costs, expected return on plan assets, amortization of prior service cost or credits and actuarial gains and losses) separately and outside a subtotal of operating income. In addition, only the service cost component is eligible for capitalization. Idaho Power currently capitalizes amounts of pension or postretirement costs that are insignificant to the consolidated financial statements. The amendments in ASU 2017-07 are effective for interim and annual reporting periods beginning after December 15, 2017. Entities must use (1) a retrospective transition method to adopt the requirement for separate presentation in the income statement of service costs and other components and (2) a prospective transition method to adopt the requirement to limit the capitalization of benefit costs to the service cost component. IDACORP and Idaho Power are evaluating the impact of ASU 2017-07 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 pre-tax income to determine income tax expense (or benefit) for the interim period consistent with the annual estimate. In subsequent interim periods, income tax expense (or benefit) for the period is computed as the difference between the year-to-date amount reported for the previous interim period and the current period's year-to-date amount.

Income Tax Expense

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

	IDACORP						Idaho Power
	2017			2016			2017			2016
Income tax at statutory rates (federal and state)	$	85,624		$	75,736		$	84,278		$	74,864
Additional accumulated deferred investment tax credits (ADITC) amortization	—			(1,500		)	—			(1,500		)
First mortgage bond redemption costs	—			(5,583		)	—			(5,583		)
Share-based compensation	(1,587		)	(1,754		)	(1,558		)	(1,720		)
Other(1)	(38,617		)	(38,277		)	(36,367		)	(34,964		)
Income tax expense	$	45,420		$	28,622		$	46,353		$	31,097
Effective tax rate	20.7		%	14.8		%	21.5		%	16.2		%

⁽¹⁾ "Other" is primarily comprised of the net tax effect of Idaho Power's regulatory flow-through tax adjustments. These adjustments 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, 2016.

The increases in income tax expense for the nine months endedSeptember 30, 2017, compared with the same period in 2016, were primarily due to greater pre-tax income, the flow-through income tax benefit related to the tax deduction for bond redemption costs incurred in the second quarter of 2016, and tax benefits from distributions from fully-amortized affordable housing investments that were recorded in the third quarter of 2016. On a net basis, Idaho Power’s estimate of its annual 2017 regulatory flow-through tax adjustments is comparable to 2016.

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.

20

Idaho and Oregon General Rate Cases and Base Rate Adjustments

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

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

Idaho and Oregon base rates were subsequently adjusted again in 2012, in connection with Idaho Power's completion of the Langley Gulch power plant. In June 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. In September 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.

In March 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 Idaho power cost adjustment (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 PCA mechanism and instead results in collecting that portion through base rates.

Idaho Settlement Stipulation — Investment Tax Credits and Sharing Mechanism

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

• If Idaho Power's annual return on year-end equity in the Idaho jurisdiction (Idaho ROE) in any year is less than 9.5 percent, then Idaho Power may record additional ADITC amortization up to $25 million to help achieve a 9.5 percent Idaho ROE for that year, and may record additional ADITC amortization up to a total of $45 million 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 PCA 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 PCA, 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 amortization contemplated by the settlement stipulation has been recorded 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 no additional ADITC amortization during the first nine months of 2017, based on Idaho Power's estimate of Idaho ROE for the full-year 2017. During the first nine months of 2016, Idaho Power recorded $1.5 million of additional ADITC amortization, which was reversed later in 2016 as actual financial results exceeded Idaho Power's early estimates.

Valmy Rate Base Adjustment Settlement Stipulations

In May 2017, the IPUC approved a settlement stipulation allowing accelerated depreciation and cost recovery for Idaho Power’s jointly-owned North Valmy coal-fired power plant (Valmy Plant). The settlement stipulation provides for an increase in

21

Idaho jurisdictional revenues of $13.3 million per year, and (1) levelized collections and associated cost recovery through December 2028, (2) accelerated depreciation on unit 1 through 2019 and unit 2 through 2025, (3) Idaho Power to use prudent and commercially reasonable efforts to end its participation in the operation of unit 1 by the end of 2019 and unit 2 by the end of 2025, and (4) a filing no later than 2020 that would include actual and planned incremental investments in unit 2, including updated financial analysis regarding the lowest costs options for unit 2. The costs intended to be recovered by the increased revenue requirement include current investments as of May 31, 2017, in both units, forecasted unit 1 investments from 2017 through 2019, and forecasted decommissioning costs for unit 1 and unit 2, offset by forecasted operation and maintenance costs savings. The settlement stipulation also provides for the regulatory deferral of the difference between actual revenue requirements and levelized collections, and provides for the regulatory deferral of the difference between actual costs incurred (including accelerated depreciation expense on unit 1 through 2019 and unit 2 through 2025) compared with costs permitted to be recovered during the cost recovery period specified in the settlement stipulation (including depreciation expense through 2028). If actual costs incurred differ from forecasted amounts included in the settlement stipulation, collection or refund of any differences would be subject to regulatory approval.

In June 2017, the OPUC also approved a settlement stipulation allowing for accelerated depreciation of units 1 and 2 through December 31, 2025, cost recovery of incremental Valmy Plant investments through May 31, 2017, and forecasted decommissioning costs. The settlement stipulation provides for an increase in the Oregon jurisdictional revenue requirement of $1.1 million, effective July 1, 2017, with yearly adjustments to the level of decommissioning cost recovery, if warranted, until decommissioning activities are concluded.

For both the three and nine month periods ended September 30, 2017, the settlement stipulations increased general business revenue collections, general business revenue accruals, net depreciation expense, and income tax expense, including plant-related flow-through tax adjustments. Idaho Power expects the ongoing annual benefit to net income from the Valmy Plant settlement stipulations to decline slightly each year through 2028, primarily due to the annual decline in Valmy Plant-related rate base, which is expected to be fully depreciated by December 31, 2028. Compared with Idaho Power’s estimate of what ongoing net income would have been without the settlement stipulations, the settlement stipulations increased after-tax net income for the first nine months of 2017 by $3.8 million, of which $1.3 million was recorded during the third quarter of 2017.

Depreciation Rate Settlement Stipulations

In May 2017, the IPUC and OPUC approved settlement stipulations related to revised depreciation rates for Idaho Power's electric plant in service other than the Valmy Plant, and adjusted base rates in Oregon to reflect the revised depreciation rates applied to electric plant-in-service based on balances from the most recent general rate case. These settlement stipulations provided for new depreciation rates to go into effect on June 1, 2017, with no significant resulting increase in revenue.

Idaho Power Cost Adjustment Mechanisms

In both its Idaho and Oregon jurisdictions, Idaho Power's power cost adjustment mechanisms address the volatility of power supply costs and provide for annual adjustments to the rates charged to its retail customers. The power cost adjustment 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 power cost adjustment 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 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 31, 2017, the IPUC issued an order approving a $10.6 million net increase in PCA rates, effective for the 2017-2018 PCA collection period from June 1, 2017, to May 31, 2018. The net increase in PCA rates was primarily due to expected higher power supply costs resulting from new PURPA power purchase agreements and higher coal-fired generation costs, combined with the effect of lower-than-expected actual hydroelectric generation for the 2016-2017 PCA year.  The net increase includes an offsetting $13.0 million refund of previously collected Idaho energy efficiency rider funds. Previously, in May 2016, the IPUC issued an order approving a $17.3 million net increase in PCA rates, effective for the 2016-2017 PCA collection period from June 1, 2016, to May 31, 2017. The net increase in 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.

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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 31, 2017, the IPUC issued an order approving Idaho Power's application requesting an increase of $6.9 million in the FCA from $28.1 million to $35.0 million, with new requested rates effective for the period from June 1, 2017, to May 31, 2018. Previously in May 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, to May 31, 2017.

4. NOTES PAYABLE

Credit Facilities

IDACORP and Idaho Power have in place credit facilities that may be used for general corporate purposes and commercial paper backup. The terms and conditions of those credit facilities are as described in IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2016. At September 30, 2017, no loans were outstanding under either IDACORP's or Idaho Power's credit facilities. At September 30, 2017, 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) and interest rates of IDACORP’s and Idaho Power's short-term borrowings were as follows at September 30, 2017, and December 31, 2016:

	September 30, 2017									December 31, 2016
	IDACORP			Idaho Power			Total			IDACORP			Idaho Power			Total
Commercial paper outstanding	$	2,425		$	—		$	2,425		$	—		$	21,800		$	21,800
Weighted-average annual interest rate	1.54		%	—		%	1.54		%	—		%	1.13		%	1.13		%

5. COMMON STOCK

IDACORP Common Stock

During the nine months endedSeptember 30, 2017, IDACORP granted 72,397 restricted stock unit awards to employees and 12,050 shares of common stock to directors but made no original issuances of shares of common stock pursuant to the IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan. As directed by IDACORP, plan administrators of the IDACORP, Inc. Dividend Reinvestment and Stock Purchase Plan and Idaho Power Company Employee Savings Plan 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 use 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, 2017, the leverage ratios for IDACORP and Idaho Power were 44 percent and 46 percent, respectively. Based on these restrictions, IDACORP’s and Idaho Power’s dividends were limited to $1.3 billion and $1.1 billion, respectively, at September 30, 2017. 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, 2017, 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

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IDACORP that will reduce Idaho Power’s common equity capital below 35 percent of its total adjusted capital without IPUC approval. At September 30, 2017, Idaho Power's common equity capital was 54 percent of its total adjusted capital. Further, Idaho Power must obtain approval of the OPUC before it can 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.

6. EARNINGS PER SHARE

The table below presents the computation of IDACORP’s basic and diluted earnings per share for the three and nine months endedSeptember 30, 2017 and 2016 (in thousands, except for per share amounts).

	Three months ended September 30,				Nine months ended September 30,
	2017		2016		2017		2016
Numerator:
Net income attributable to IDACORP, Inc.	$	90,634	$	83,100	$	173,567	$	165,075
Denominator:
Weighted-average common shares outstanding - basic	50,362		50,296		50,361		50,299
Effect of dilutive securities	59		97		47		62
Weighted-average common shares outstanding - diluted	50,421		50,393		50,408		50,361
Basic earnings per share	$	1.80	$	1.65	$	3.45	$	3.28
Diluted earnings per share	$	1.80	$	1.65	$	3.44	$	3.28

7. COMMITMENTS

Purchase Obligations

IDACORP's and Idaho Power's purchase obligations did not change materially, outside of the ordinary course of business, during the nine months endedSeptember 30, 2017, except that Idaho Power entered into agreements with solar, biomass, and hydroelectric PURPA-qualifying facilities which increased contractual payment obligations by approximately $85 million over the 20-year terms of the 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 $57 million at September 30, 2017, 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, 2017, the total value of BCC's reclamation trust fund was $97 million. During the nine months endedSeptember 30, 2017, the reclamation trust fund made no distributions 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, and does, add a per-ton surcharge to coal sales, all of which are made to the Jim Bridger plant. 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

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experience and the evaluation of the specific indemnities. As of September 30, 2017, management believes the likelihood is remote that IDACORP or Idaho Power would be required to perform under such indemnification provisions or otherwise incur any significant losses with respect to such indemnification obligations. Neither IDACORP nor Idaho Power has recorded any liability on their respective condensed consolidated balance sheets with respect to these indemnification obligations.

8. CONTINGENCIES

IDACORP and Idaho Power have in the past and expect in the future to become involved in various claims, controversies, disputes, and other contingent matters, some of which involve litigation and regulatory or other contested proceedings. The ultimate resolution and outcome of litigation and regulatory proceedings is inherently difficult to determine, particularly where (a) the remedies or penalties sought are indeterminate, (b) the proceedings are in the early stages or the substantive issues have not been well developed, or (c) the matters involve complex or novel legal theories or a large number of parties. In accordance with applicable accounting guidance, IDACORP and Idaho Power, as applicable, establish an accrual for legal proceedings when those matters proceed to a stage where they present loss contingencies that are both probable and reasonably estimable. 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.

IDACORP and Idaho Power are parties to legal claims and legal and regulatory actions and proceedings in the ordinary course of business and, as noted above, record an accrual for associated loss contingencies when they are probable and reasonably estimable. As of the date of this report, the companies believe that resolution of those matters will not have a material adverse effect on their respective consolidated financial statements. Idaho Power is also actively monitoring various pending environmental regulations and the recently issued executive orders related to environmental matters 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.

9. BENEFIT PLANS

Idaho Power has 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, 2017 and 2016 (in thousands).

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	Pension Plan						SMSP				Postretirement Benefits
	2017			2016			2017		2016		2017			2016
Service cost	$	8,436		$	8,004		$	189	$	307	$	244		$	279
Interest cost	9,739			9,453			1,079		1,069		695			692
Expected return on plan assets	(11,285		)	(10,519		)	—		—		(576		)	(619		)
Amortization of prior service cost	7			15			31		42		11			7
Amortization of net loss	3,298			3,332			742		883		—			—
Net periodic benefit cost	10,195			10,285			2,041		2,301		374			359
Regulatory deferral of net periodic benefit cost(1)	(9,708		)	(9,826		)	—		—		—			—
Previously deferred pension costs recognized(1)	4,288			4,288			—		—		—			—
Net periodic benefit cost recognized for financial reporting(1)	$	4,775		$	4,747		$	2,041	$	2,301	$	374		$	359

⁽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, the Idaho portion of net periodic benefit cost is recorded as a regulatory asset and is recognized in the income statement as those 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, 2017 and 2016 (in thousands of dollars).

	Pension Plan						SMSP				Postretirement Benefits
	2017			2016			2017		2016		2017			2016
Service cost	$	25,307		$	24,014		$	569	$	921	$	730		$	837
Interest cost	29,217			28,360			3,236		3,206		2,087			2,075
Expected return on plan assets	(33,854		)	(31,560		)	—		—		(1,730		)	(1,856		)
Amortization of prior service cost	21			44			95		126		35			20
Amortization of net loss	9,893			9,998			2,223		2,649		—			—
Net periodic benefit cost	30,584			30,856			6,123		6,902		1,122			1,076
Regulatory deferral of net periodic benefit cost(1)	(28,991		)	(29,508		)	—		—		—			—
Previously deferred pension costs recognized(1)	12,865			12,865			—		—		—			—
Net periodic benefit cost recognized for financial reporting(1)	$	14,458		$	14,213		$	6,123	$	6,902	$	1,122		$	1,076

⁽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, the Idaho portion of net periodic benefit cost is recorded as a regulatory asset and is recognized in the income statement as those costs are recovered through rates.

Idaho Power has no minimum contribution requirement to its defined benefit pension plan in 2017. However, during the nine months ended September 30, 2017, Idaho Power made $40 million of discretionary contributions to its defined benefit pension plan, 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.

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

10. 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.

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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 endedSeptember 30, 2017 and 2016 (in thousands).

		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,
		2017			2016			2017			2016
Financial swaps	Off-system sales	$	(309	)	$	(16	)	$	864		$	1,379
Financial swaps	Purchased power	904			710			169			861
Financial swaps	Fuel expense	883			(657		)	1,549			(3,099		)
Financial swaps	Other operations and maintenance	(45		)	(16		)	(126		)	(166		)
Forward contracts	Purchased power	(3		)	24			(13		)	24
Forward contracts	Fuel expense	—			49			3			139

⁽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 11 for additional information concerning the determination of fair value for Idaho Power’s assets and liabilities from price risk management activities.

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, 2017, and December 31, 2016 (in thousands).

		Asset Derivatives								Liability Derivatives
	Balance Sheet Location	Gross Fair Value		Amounts Offset				Net Assets		Gross Fair Value		Amounts Offset				Net Liabilities
September 30, 2017
Current:
Financial swaps	Other current assets	$	332	$	(234	)		$	98	$	234	$	(234	)		$	—
Financial swaps	Other current liabilities	140		(140		)		—		919		(140		)		779
Forward contracts	Other current assets	3		—				3		—		—				—
Long-term:
Financial swaps	Other assets	38		(3		)		35		3		(3		)		—
Financial swaps	Other liabilities	15		(15		)		—		127		(90		)	(1)	37
Total		$	528	$	(392	)		$	136	$	1,283	$	(467	)		$	816
December 31, 2016
Current:
Financial swaps	Other current assets	$	8,134	$	(2,183	)	(2)	$	5,951	$	302	$	(302	)		$	—
Total		$	8,134	$	(2,183	)		$	5,951	$	302	$	(302	)		$	—

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⁽¹⁾ Long-term liability derivative amount offset includes $0.1 million of collateral receivable for the period ended September 30, 2017.

⁽²⁾ Current asset derivative amount offset includes $1.9 million of collateral payable for the period ended December 31, 2016.

The table below presents the volumes of derivative commodity forward contracts and swaps outstanding at September 30, 2017 and 2016 (in thousands of units).

		September 30,
Commodity	Units	2017	2016
Electricity purchases	MWh	122	130
Electricity sales	MWh	162	143
Natural gas purchases	MMBtu	7,975	7,977
Natural gas sales	MMBtu	230	70
Diesel purchases	Gallons	304	267

Credit Risk

At September 30, 2017, 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 Idaho Power derivative instruments contain provisions that require Idaho Power's unsecured debt to maintain an investment grade credit rating from Moody's Investors Service and Standard & Poor's Ratings Services. If Idaho Power's unsecured debt were to fall below investment grade, it would be in violation of these provisions, and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions. The aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a liability position at September 30, 2017 was $1.3 million. Idaho Power posted $0.4 million cash collateral related to this amount. If the credit-risk-related contingent features underlying these agreements were triggered on September 30, 2017, Idaho Power would have been required to pay or post collateral to its counterparties up to an additional $4.7 million to cover the open liability positions as well as completed transactions that have not yet been paid.

11. 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 have the ability to access.

•   Level 2: Financial assets and liabilities whose values are based on the following:

a) quoted prices for similar assets or liabilities in active markets;

b) quoted prices for identical or similar assets or liabilities in non-active markets;

c) pricing models whose inputs are observable for substantially the full term of the asset or liability; and

d) pricing models whose inputs are derived principally from or corroborated by observable market data through correlation or other means for substantially the full term of the asset or liability.

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

•      Level 3: Financial assets and liabilities whose values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. These inputs reflect management’s own assumptions about the assumptions a market participant would use in pricing the asset or liability.

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 endedSeptember 30, 2017.

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, 2017, and December 31, 2016 (in thousands).

	September 30, 2017								December 31, 2016
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets:
Money market funds
IDACORP	$	—	$	—	$	—	$	—	$	15,000	$	—	$	—	$	15,000
Idaho Power	45,495		—		—		45,495		29,967		—		—		29,967
Derivatives	133		3		—		136		5,951		—		—		5,951
Trading securities: Equity securities	84		—		—		84		111		—		—		111
Available-for-sale securities: Equity securities	23,475		—		—		23,475		23,908		—		—		23,908
Liabilities:
Derivatives	816		—		—		816		—		—		—		—

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, 2017, and December 31, 2016, using available market information and appropriate valuation methodologies (in thousands).

	September 30, 2017				December 31, 2016
	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)	1,745,746		1,906,113		1,745,678		1,858,666
Idaho Power
Liabilities:
Long-term debt(1)	1,745,746		1,906,113		1,745,678		1,858,666

⁽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 11.

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

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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.

12. 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, and IDACORP’s holding company expenses.

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

	Utility Operations		All Other		Eliminations			Consolidated Total
Three months ended September 30, 2017:
Revenues	$	406,655	$	1,669	$	—		$	408,324
Net income attributable to IDACORP, Inc.	88,329		2,305		—			90,634
Total assets as of September 30, 2017	6,321,917		116,718		(71,452		)	6,367,183
Three months ended September 30, 2016:
Revenues	$	371,474	$	571	$	—		$	372,045
Net income attributable to IDACORP, Inc.	80,029		3,071		—			83,100
Nine months ended September 30, 2017:
Revenues	$	1,040,387	$	3,487	$	—		$	1,043,874
Net income attributable to IDACORP, Inc.	169,192		4,375		—			173,567
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

13. 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 endedSeptember 30, 2017 and 2016 (in thousands). Items in parentheses indicate charges to AOCI.

	Defined Benefit Pension Items
	Three months ended September 30,						Nine months ended September 30,
	2017			2016			2017			2016
Balance at beginning of period	$	(19,941	)	$	(20,149	)	$	(20,882	)	$	(21,276	)
Amounts reclassified out of AOCI	471			563			1,412			1,690
Balance at end of period	$	(19,470	)	$	(19,586	)	$	(19,470	)	$	(19,586	)

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The table below presents amounts reclassified out of components of AOCI and the income statement location of those amounts reclassified during the three and nine months endedSeptember 30, 2017 and 2016 (in thousands). 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,
	2017			2016			2017			2016
Amortization of defined benefit pension items(1)
Prior service cost	$	31		$	42		$	95		$	126
Net loss	742			883			2,223			2,649
Total before tax	773			925			2,318			2,775
Tax benefit(2)	(302		)	(362		)	(906		)	(1,085		)
Net of tax	471			563			1,412			1,690
Total reclassification for the period	$	471		$	563		$	1,412		$	1,690

⁽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 statements of income in other expense, net.

⁽²⁾ The tax benefit is included in income tax expense in the condensed consolidated statements of income 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, 2017, and the related condensed consolidated statements of income and comprehensive income for the three-month and nine-month periods ended September 30, 2017 and 2016, and of equity and cash flows for the nine-month periods ended September 30, 2017 and 2016. 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, 2016, 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 23, 2017, 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, 2016 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

/s/ DELOITTE & TOUCHE LLP

Boise, Idaho

November 2, 2017

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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, 2017, and the related condensed consolidated statements of income and comprehensive income for the three-month and nine-month periods ended September 30, 2017 and 2016, and of cash flows for the nine-month periods ended September 30, 2017 and 2016. 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 Idaho Power Company and subsidiary as of December 31, 2016, 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 23, 2017, 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, 2016 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

/s/ DELOITTE & TOUCHE LLP

Boise, Idaho

November 2, 2017

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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, 2016, 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.

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 significant subsidiaries include IDACORP Financial Services, Inc. (IFS), an investor in affordable housing and other real estate investments, and 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).

EXECUTIVE OVERVIEW

Management's Outlook and Company Initiatives

In the Annual Report on Form 10-K for the year ended December 31, 2016, IDACORP's and Idaho Power's management included a brief overview of their outlook and initiatives for the companies for 2017 and beyond, under the headings "Executive Overview - Management's Outlook" and "2016 Accomplishments and 2017 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 participate in and support state and local economic development initiatives aimed at responsible and sustainable growth. During the first nine months of 2017, Idaho Power's customer count grew by approximately 7,400 customers, and for the twelve months ended September 30, 2017, the customer growth rate was 1.8 percent. On July 7, 2017, Idaho Power recorded a new record system peak as total demand of 3,422 MW exceeded the previous record peak demand of 3,407 MW set on July 2, 2013.

• Idaho Power expects substantial capital investments, with expected total capital expenditures of approximately $1.5 billion over the five-year period from 2017 (including the expenditures incurred so far in 2017) through 2021.

• Idaho Power continues to execute on three core focuses for 2017 - improving Idaho Power's core business, growing revenues, and positioning the company for the future through enhancing its brand.

• 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 pursuit of its goal of advancing a purposeful regulatory strategy, Idaho Power focuses 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 includes provisions for the additional amortization of accumulated deferred investment tax credits (ADITC) to help achieve a minimum 9.5 percent return on year-end equity in the Idaho jurisdiction (Idaho ROE). Idaho Power continues to assess the need to file and the timing of a general rate case in Idaho and Oregon to change base rates.

• 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 the number of customers in its service area. Over the 12 months ended September 30, 2017, customer count grew by 1.8 percent. Idaho Power expects its number of customers to continue to increase in the foreseeable future. Employment in Idaho Power's service area grew by approximately 2.6 percent over the twelve months ended September 30, 2017, based on Idaho Department of Labor preliminary September 2017 data. 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 June 2017, Idaho Power filed its 2017 Integrated Resource Plan (IRP), Idaho Power's long-term forecast of loads and resources, as described in "Regulatory Matters" in this MD&A. The load forecast assumptions Idaho Power used 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.

	5-Year Forecast		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	1.1%	1.6%	0.9%	1.4%
2015 IRP	1.1%	1.5%	1.1%	1.4%
2013 IRP	1.2%	1.5%	1%	1.3%

Idaho Power’s 2017 IRP identifies its preferred resource portfolio and action plan. The IRP provides for the completion of the Boardman-to-Hemingway transmission line by 2026, the end of Idaho Power's participation in coal-fired operations at the North Valmy coal-fired power plant (Valmy Plant) units 1 and 2 in 2019 and 2025, respectively, and the early retirement of Jim Bridger units 1 and 2 in 2032 and 2028, respectively, with no other new resource needs prior to 2026.

• 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 the ongoing permitting of the Boardman-to-Hemingway and Gateway West transmission 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

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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.

• Weather Conditions: Weather and agricultural growing conditions have a significant impact on Idaho Power's energy sales and the seasonality of those sales. Relatively low and high temperatures result in greater energy use for heating and cooling, respectively. During the agricultural growing season, which in large part occurs during the second and third quarters, irrigation customers use electricity to operate irrigation pumps, and weather conditions can impact the timing and extent 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, which is described in Note 3 - "Regulatory Matters" to the condensed consolidated financial statements in this report. Temperatures in Idaho Power's service area during the third quarter of 2017 were warmer than normal and warmer than temperatures in the third quarter of 2016. The warmer temperatures resulted in increased sales volumes on a per-customer basis, primarily for residential customers using energy for cooling, in the third quarter of 2017 compared with the third quarter of 2016.

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 is addressed through the Idaho and Oregon power cost adjustment mechanisms. For 2017, Idaho Power expects generation from its hydroelectric resources to be in the range of 8.5 to 9.0 million MWh, compared with 20-year average annual hydroelectric generation of 7.6 million MWh. Under median water conditions, Idaho Power's hydroelectric facilities would currently provide annual generation of approximately 8.4 million MWh.

• 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. Over the past few years, 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. Idaho Power plans to end its participation in the operation of the Valmy Plant, of which Idaho Power owns a 50-percent interest, by the end of 2025, and in the second quarter of 2017 the IPUC and OPUC approved settlement stipulations providing for accelerated depreciation and cost recovery of the facility. Idaho Power also intends to cease coal-fired operations at the Boardman coal-fired plant, of which Idaho Power owns a 10-percent interest, by December 2020. 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 power cost adjustment mechanisms mitigate in large part the potential adverse impacts of fluctuations in power supply costs to Idaho Power.

• Changes in legislation, regulation, and government policy as a result of the new federal administration: The federal administration's proposed changes with respect to legislation, regulation, and government policy could significantly impact IDACORP’s and Idaho Power’s businesses and the electric utility industry. Specific legislative and regulatory proposals discussed before and after the 2016 presidential and congressional elections that could have a material impact on IDACORP and Idaho Power include, but are not limited to, reform of the federal tax code, infrastructure renewal programs, modifications to public company reporting requirements, and environmental regulation. During the first nine months of 2017, the new federal administration issued executive orders directed at changing or eliminating federal regulations that may affect Idaho Power's operations and environmental-related expenses, as described in "Environmental Matters" in this MD&A.

• Regulatory and Environmental Compliance Costs and Plant Economics: 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

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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, for economic reasons as described above in this MD&A, Idaho Power plans to end its participation in coal-fired operations at the Valmy Plant by the end of 2025.

• Water Management and Relicensing of the Hells Canyon Hydroelectric Project: Because of Idaho Power's reliance on stream flow in the Snake River and its tributaries, Idaho Power participates in numerous proceedings and venues that may affect its water rights, seeking to preserve the long-term availability of its rights for 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. As of the date of this report, Idaho Power cannot determine the ultimate terms of, and costs associated with, any resulting long-term license.

Summary of Financial Results

The following is a summary of Idaho Power's net income, net income attributable to IDACORP, and IDACORP's earnings per diluted share for the three and nine months ended September 30, 2017 and 2016 (in thousands, except earnings per share amounts):

	Three months ended September 30,				Nine months ended September 30,
	2017		2016		2017		2016
Idaho Power net income	$	88,329	$	80,029	$	169,192	$	160,370
Net income attributable to IDACORP, Inc.	$	90,634	$	83,100	$	173,567	$	165,075
Average outstanding shares – diluted	50,421		50,393		50,408		50,361
IDACORP, Inc. earnings per diluted share	$	1.80	$	1.65	$	3.44	$	3.28

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The table below provides a reconciliation of net income attributable to IDACORP for the three and nine months ended September 30, 2017, from the same periods in 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, 2016			$	83.1				$	165.1
Increase (decrease) in Idaho Power net income:
Customer growth, net of associated power supply costs and power cost adjustment mechanism impacts	2.3					7.0
Usage per customer, net of associated power supply costs and power cost adjustment mechanism impacts	12.0					12.2
FCA revenues	(7.4	)				(13.7	)
Increase in revenues per MWh, net of associated power supply costs and power cost adjustment mechanism impacts	14.3					30.3
Third-party use of electric property, wheeling, and other revenue	2.1					9.1
Other operating and maintenance (O&M) expenses	2.9					0.4
Depreciation expense	(4.2	)				(14.8	)
Other changes in operating revenues and expenses, net	(0.4	)				(0.8	)
Increase in Idaho Power operating income	21.6					29.7
Earnings of unconsolidated equity-method investments	(7.0	)				(6.5	)
Non-operating income and expenses	(0.7	)				0.9
Additional ADITC amortization	(1.0	)				(1.5	)
Income tax expense (excluding additional ADITC amortization)	(4.6	)				(13.8	)
Total increase in Idaho Power net income			8.3					8.8
Other changes (net of tax)			(0.8		)			(0.3		)
Net income attributable to IDACORP, Inc. - September 30, 2017			$	90.6				$	173.6

Net Income - Third Quarter 2017

IDACORP's net income increased $7.5 million for the third quarter of 2017 compared with the third quarter of 2016, primarily due to higher net income at Idaho Power. Continued customer growth in Idaho Power's service area, higher sales volumes resulting from warmer summer temperatures in Idaho Power's service area, lower other O&M expenses, and the net effects of the Valmy Plant settlement stipulations in the third quarter of 2017 contributed to the increase in net income.

Customer growth increased operating income by $2.3 million in the third quarter of 2017, as the number of Idaho Power customers grew by 1.8 percent over the twelve months ended September 30, 2017. Warmer summer temperatures in Idaho Power's service area in the third quarter of 2017 led to an increase in sales volumes on a per-customer basis, primarily for residential customers using energy for cooling, compared with the third quarter of 2016, while higher levels of commercial and industrial activity also led to an increase in sales volumes on a per customer basis for commercial and industrial customers. The increases in sales volumes on a per-customer basis increased operating income by $12.0 million in the third quarter of 2017 compared with the third quarter of 2016. The increase in revenues from increased sales volumes was partially offset by the FCA mechanism, which reduced revenues by $7.4 million during the third quarter of 2017 compared with the third quarter of 2016. The warmer summer temperatures also caused an increase in the proportion of residential sales in higher rate categories under Idaho Power's tiered rate structure, partially contributing to a $14.3 million increase in operating income.

In the second quarter of 2017, the IPUC and OPUC each approved settlement stipulations related to Idaho Power’s plan to end its participation in coal-fired operations at the Valmy Plant by the end of 2025. The settlement stipulations resulted in increased general business revenue collections and general business revenue accruals in the third quarter of 2017 (included in the $14.3 million "Increase in revenues per MWh, net of associated power supply costs and power cost adjustment mechanism impacts" in the table above), increased net depreciation expense (included in the $4.2 million increase in "Depreciation expense" in the table above), and increased associated income tax expenses for the quarter, including plant-related flow-through tax adjustments.

For both the third quarter and nine months ended September 30, 2017, the settlement stipulations increased general business revenue collections, general business revenue accruals, net depreciation expense, and income tax expense. The ongoing annual

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benefit to net income from the Valmy Plant settlement stipulations is expected to decline slightly each year through 2028, primarily due to the annual decline in Valmy Plant-related rate base, which is expected to be fully depreciated by December 31, 2028. Compared with Idaho Power’s estimate of what ongoing net income would have been without the settlement stipulations, the settlement stipulations increased after-tax net income for the first nine months of 2017 by $3.8 million, of which $1.3 million was recorded during the third quarter of 2017. Idaho Power estimates the Valmy Plant settlement stipulations will increase after-tax net income by approximately $1.4 million during the last three months of 2017 for a full-year 2017 increase to after-tax net income of approximately $5.2 million.

During the third quarter of 2017, Idaho Power benefited from a $2.1 million increase in third-party use of electric property, wheeling, and other revenue. This change was largely due to an increase in wheeling volumes and an increase in Idaho Power's Open Access Transmission Tariff (OATT) rates that became effective in October 2016.

Other O&M expenses were $2.9 million lower in the third quarter of 2017 compared with the third quarter in 2016, as lower generation at Idaho Power's thermal plants and the timing of an annual maintenance outage at the Jim Bridger coal-fired plant resulted in lower O&M costs.

Income from Idaho Power's unconsolidated investment in BCC decreased non-operating income by $7.0 million in the third quarter of 2017 compared with the same quarter in 2016, primarily due to a decrease in coal sales prices and volumes at BCC.

Idaho Power income tax expense increased $5.6 million in the third quarter of 2017 compared with the third quarter of 2016, due mostly to higher pre-tax income and tax benefits from distributions from fully-amortized affordable housing investments that were recorded during the third quarter of 2016. There were no significant distributions from fully-amortized affordable housing investments in the third quarter of 2017. Also, based on Idaho Power's current expectations of full-year 2017 results, Idaho Power did not record any additional ADITC amortization under its Idaho regulatory settlement stipulation during the third quarter of 2017 and does not expect additional ADITC amortization for the full-year 2017. During the third quarter of 2016, Idaho Power recorded $1.0 million of additional ADITC amortization.

Net Income - Year-to-Date 2017

IDACORP's net income increased $8.5 million, primarily from higher net income at Idaho Power, for the first nine months of 2017 compared with the same period in 2016. Customer growth added $7.0 million to Idaho Power operating income compared with the first nine months of 2016. Higher usage per customer in the first nine months of 2017 compared with the same period in 2016 contributed $12.2 million to operating income, due mostly to higher usage per customer in the third quarter of 2017 described above. Warmer summer temperatures and colder winter temperatures during the first nine months of 2017 compared with the same period in 2016 led to a greater proportion of residential sales in higher rate categories under Idaho Power's tiered rate structure. These residential sales contributed to the $30.3 million increase in operating income from the increase in revenues per MWh. The FCA mechanism reduced operating income by $13.7 million during the first nine months of 2017 compared with the first nine months of 2016. As noted above, the settlement stipulations related to the Valmy Plant approved in the second quarter of 2017 added $3.8 million to after-tax net income for the first nine months of 2017. During the first nine months of 2017, Idaho Power benefited from a $9.1 million increase in third-party use of electric property, wheeling, and other revenue. This change was largely due to an increase in wheeling volumes, an increase in Idaho Power's OATT rates that became effective in October 2016, and a new long-term wheeling agreement that became effective in July 2016.

A decrease in income from Idaho Power's unconsolidated investment in BCC decreased non-operating income by $6.5 million in the first nine months of 2017 compared with the first nine months in 2016, primarily due to a decrease in coal sales prices and higher expenses at BCC. Idaho Power anticipates that higher coal sales prices will increase income from BCC in the fourth quarter of 2017 compared with the fourth quarter of 2016. Despite the expected fourth quarter increase in income from BCC this year, Idaho Power expects income from BCC for the full year of 2017 to be slightly below the income from BCC in 2016.

Idaho Power's income tax expense was $15.3 million higher primarily due to higher pre-tax income, the $5.6 million flow-through benefit of tax deductible make-whole premiums that Idaho Power paid in connection with the early redemption of long-term debt in the first nine months of 2016, and tax benefits from distributions from fully-amortized affordable housing investments that were also recorded in 2016. There were no early redemptions of long-term debt or significant distributions from fully-amortized affordable housing investments in the first nine months of 2017. Also, based on Idaho Power's current expectations of full-year 2017 results, Idaho Power did not record any additional ADITC amortization under its Idaho regulatory settlement stipulation during the first nine months of 2017. During the first nine months of 2016, Idaho Power recorded $1.5 million of additional ADITC amortization.

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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 endedSeptember 30, 2017. In this analysis, the results for the three and nine months endedSeptember 30, 2017, are compared with the same periods in 2016.

Utility Operations

The table below presents Idaho Power’s energy sales and supply (in thousands of MWh) for the three and nine months endedSeptember 30, 2017 and 2016. 

	Three months ended September 30,				Nine months ended September 30,
	2017		2016		2017		2016
General business sales	4,438		4,156		11,309		10,933
Off-system sales	216		224		1,806		837
Total energy sales	4,654		4,380		13,115		11,770
Hydroelectric generation	1,991		1,331		7,169		5,191
Coal generation	1,236		1,487		2,578		2,961
Natural gas and other generation	665		712		1,067		1,557
Total system generation	3,892		3,530		10,814		9,709
Purchased power	1,115		1,164		3,269		2,951
Line losses	(353	)	(314	)	(968	)	(890	)
Total energy supply	4,654		4,380		13,115		11,770

Sales Volume and Generation: In the third quarter of 2017, general business sales volumes increased 282 thousand MWh, or 7 percent, compared with the third quarter of 2016. During the first nine months of 2017, general business sales volumes increased 376 thousand MWh, or 3 percent, compared with the first nine months of the prior year. Cooling degree days for the three and nine months ended September 30, 2017, were 53 percent and 34 percent higher, respectively, which increased the use of electricity for cooling purposes. Heating degree days for the first nine months of 2017 were 27 percent higher than the same period in 2016, which increased the use of electricity for heating purposes. In addition, customer growth contributed to increased sales volumes in 2017 compared with 2016, with the number of Idaho Power's customers growing by 1.8 percent over the prior twelve months. Usage per irrigation customer was approximately 11 percent lower in the first nine months of 2017 compared with the same period in 2016, as precipitation in the Idaho Power service area during the nine months ended September 30, 2017, was significantly higher than in the same periods of 2016, which reduced usage by irrigation customers, particularly in the first six months of 2017.

Off-system sales volumes in the third quarter of 2017 were relatively flat compared with the third quarter of 2016, as an increase in hydroelectric generation supported the increased general business sales, resulting in a consistent amount of energy available for off-system sales. Off-system sales volumes increased 969 thousand MWh, or 116 percent, in the first nine months of 2017 compared with the first nine months of 2016 due primarily to increased hydroelectric generation exceeding the increased general business sales, resulting in more energy available for off-system sales. For the third quarter and first nine months of 2017, hydroelectric generation comprised 51 percent and 66 percent of Idaho Power's total system generation, respectively, compared with 38 percent and 53 percent, respectively, for the third quarter and first nine months of 2016. Generation from Idaho Power's hydroelectric plants increased due to significantly greater precipitation in the first nine months of 2017. Precipitation in Boise, Idaho (measured in inches) was 131 percent higher in the first nine months of 2017 compared with the same period in 2016, and 58 percent above normal. For 2017, Idaho Power estimates annual generation from its hydroelectric facilities will be between 8.5 million MWh and 9.0 million MWh. An increase in hydroelectric generation throughout the northwest United States increased surplus power available for sale by utilities and decreased Idaho Power's wholesale power sales prices approximately 28 percent for the first nine months of 2017 compared with the first nine months of 2016.

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 power cost adjustment 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 (in thousands) and MWh sales volumes (in thousands) for the three and nine months endedSeptember 30, 2017 and 2016, and the number of customers as of September 30, 2017 and 2016.

	Three months ended September 30,						Nine months ended September 30,
	2017			2016			2017			2016
Revenue
Residential	$	145,555		$	130,952		$	410,245		$	376,492
Commercial	89,305			81,062			242,565			227,442
Industrial	52,771			48,979			147,995			136,617
Irrigation	89,370			84,264			146,363			153,301
Total	377,001			345,257			947,168			893,852
Deferred revenue related to HCC relicensing AFUDC(1)	(3,432		)	(3,432		)	(8,366		)	(8,366		)
Total general business revenues	$	373,569		$	341,825		$	938,802		$	885,486
Volume of Sales (MWh)
Residential	1,395			1,222			3,993			3,640
Commercial	1,112			1,034			3,090			2,984
Industrial	855			820			2,496			2,402
Irrigation	1,076			1,080			1,730			1,907
Total MWh sales	4,438			4,156			11,309			10,933
Number of customers at period end
Residential	450,857			442,284
Commercial	70,066			69,145
Industrial	120			123
Irrigation	20,914			20,641
Total customers	541,957			532,193

⁽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 approved for recovery 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 endedSeptember 30, 2017 and 2016, is presented in the table that follows.

	Three months ended September 30,			Nine months ended September 30,
	2017	2016	Normal	2017	2016	Normal (2)
Heating degree-days(1)	131	97	121	3,442	2,715	3,320
Cooling degree-days(1)	1,108	722	751	1,341	1,000	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.

⁽²⁾ Normal heating degree-days and cooling degree-days elements are, by convention, the arithmetic mean of the elements computed over 30 consecutive years. The normal amounts are the sum of the monthly normal amounts. These normal amounts are computed by the National Oceanic and Atmospheric Administration.

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General business revenues increased $31.7 million and $53.3 million for the three and nine months endedSeptember 30, 2017, respectively, compared with the same periods in 2016. Factors affecting general business revenues during the period are discussed below.

• Rates: Rate changes increased general business revenue by $13.3 million and $34.1 million for the three and nine months ended September 30, 2017, respectively, compared with the same periods in 2016. In the second quarter of 2017, the IPUC and OPUC each approved settlement stipulations related to Idaho Power’s plan to end its participation in coal-fired operations at the Valmy Plant by the end of 2025, which increased general business revenue collections and general business revenue accruals for the three and nine months ended September 30, 2017 compared with the same periods in 2016. Also, colder winter temperatures in early 2017 and warmer summer temperatures during the third quarter of 2017 led to a greater proportion of residential sales in higher rate categories in Idaho Power's tiered rate structure in the third quarter and first nine months of 2017 compared with the same periods in the prior year.

• Customers: Customer growth increased general business revenue by $2.8 million and $9.5 million, respectively, compared with the third quarter and first nine months of 2016. Total customers increased 1.8 percent during the twelve months ended September 30, 2017.

• Usage: Higher usage (on a per customer basis) by residential, industrial, and commercial customers increased general business revenue by $23.1 million for the third quarter of 2017 and $23.5 million for the first nine months of 2017 when compared with the same periods of 2016. Increased usage in both periods was primarily the result of warmer summer temperatures and colder winter temperatures in Idaho Power's service area, which increased usage by residential customers for cooling and heating. Cooling degree days were significantly higher in the third quarter and first nine months of 2017 compared with the same periods in 2016, and heating degree days were also significantly higher in the first nine months of 2017. These increases in usage were partially offset by an 11 percent decrease in usage per irrigation customer due to increased precipitation in Idaho Power's service area during the nine months ended September 30, 2017 compared with the same period in 2016, particularly in the first six months of 2017.

• FCA Revenue: The FCA mechanism adjusts revenue 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. Higher usage (on a per customer basis) by residential and small general service customers during the three and nine months ended September 30, 2017, compared with the same periods in 2016, decreased the amount of FCA revenue accrued by $7.4 million and $13.7 million for the third quarter and first nine months of 2017, respectively, compared with the same periods in 2016. Idaho Power did not accrue or defer FCA revenue in the third quarter of 2017, but Idaho Power accrued $7.4 million of FCA revenue in the third quarter of 2016. Idaho Power accrued $8.7 million of FCA revenue in the first nine months of 2017 compared with an accrual of $22.4 million in the same period in 2016.

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 endedSeptember 30, 2017 and 2016 (in thousands, except for per MWh amounts). 

	Three months ended September 30,				Nine months ended September 30,
	2017		2016		2017		2016
Revenue	$	6,710	$	6,143	$	25,609	$	16,532
MWh sold	216		224		1,806		837
Revenue per MWh	$	31.06	$	27.42	$	14.18	$	19.75

In the third quarter of 2017, off-system sales revenue increased by $0.6 million compared with the same period in 2016. For the first nine months of 2017, off-system sales revenue increased by $9.1 million, or 55 percent compared with the same period in 2016. Off-system sales volumes increased 116 percent in the first nine months of 2017 compared with the same period in 2016 as generation from Idaho Power's hydroelectric plants increased due to significantly greater precipitation in the first nine months of 2017 compared with the same period in the previous year. The average price of off-system sales was 28 percent lower for the nine months ended September 30, 2017 compared with the same period in 2016, as an increase in output from hydroelectric resources in the region due to increased precipitation during the period, as well as additional output from new wind and solar projects throughout the region, increased surplus power available for sale and decreased wholesale power market prices.

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Other Revenues: The table below presents the components of other revenues for the three and nine months endedSeptember 30, 2017 and 2016 (in thousands). 

	Three months ended September 30,				Nine months ended September 30,
	2017		2016		2017		2016
Transmission services and other	$	16,493	$	14,404	$	49,250	$	40,177
Energy efficiency	9,883		9,102		26,726		24,256
Total other revenues	$	26,376	$	23,506	$	75,976	$	64,433

Other revenues increased $2.9 million, or 12 percent, and $11.5 million, or 18 percent, in the third quarter and first nine months of 2017, respectively, compared with the same periods in 2016. The increase was largely due to an increase in wheeling volumes, an increase in Idaho Power's OATT rates that became effective in October 2016, and a new long-term wheeling agreement that became effective in July 2016, all of which increased revenues during the first nine months of 2017 compared with 2016.

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, 2017, Idaho Power's energy efficiency rider balances were a $4.6 million regulatory liability in the Idaho jurisdiction and a $6.0 million regulatory asset in the Oregon jurisdiction. As described in Note 3 - "Regulatory Matters" to the condensed consolidated financial statements in this report, the approved net increase in Idaho power cost adjustment (PCA) rates, effective for the 2017-2018 PCA collection period from June 1, 2017 to May 31, 2018, included a $13.0 million refund of previously collected Idaho energy efficiency rider funds.

Purchased Power: The table below presents Idaho Power’s purchased power expenses and volumes for the three and nine months endedSeptember 30, 2017 and 2016 (in thousands, except for per MWh amounts).

	Three months ended September 30,				Nine months ended September 30,
	2017		2016		2017		2016
Expense
PURPA contracts	$	50,660	$	42,477	$	127,896	$	111,422
Other purchased power (including wheeling)	18,218		25,093		51,398		52,194
Demand response incentive payments	6,775		$	6,878	6,981		7,059
Total purchased power expense	$	75,653	$	74,448	$	186,275	$	170,675
MWh purchased
PURPA contracts	763		574		2,199		1,740
Other purchased power	352		590		1,070		1,221
Total MWh purchased	1,115		1,164		3,269		2,961
Cost per MWh from PURPA contracts	$	66.40	$	74.00	$	58.16	$	64.04
Cost per MWh from other sources	$	51.76	$	42.53	$	48.04	$	42.75
Weighted average - all sources	$	61.77	$	58.05	$	54.85	$	55.26

Purchased power expense increased $1.2 million, or 2 percent, and $15.6 million, or 9 percent, in the third quarter and first nine months of 2017, respectively, compared with the same periods in 2016. The increase for the third quarter and first nine months of 2017 was primarily due to increases of 33 percent and 26 percent, respectively, in MWh purchased from generation projects under PURPA contracts, offset partially by decreases in costs per MWh.

Idaho Power is required by federal law to purchase power from some PURPA generation projects at a specified price regardless of the then-current load demand or wholesale energy market prices. The intermittent, non-dispatchable nature of most PURPA generation increases the likelihood that Idaho Power will at times be required to reduce output from its lower-cost hydroelectric and fossil fuel-fired generation resources and may be required to sell its excess power in the wholesale power market at a

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significant loss. The other 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. Market energy prices are typically higher during heavy load periods than during light load periods. Also, in accordance with Idaho Power's risk management policy, Idaho Power may purchase or sell energy several months in advance of anticipated delivery. The regional energy market price is dynamic and additional energy purchase or sale transactions that Idaho Power makes at current market prices may be noticeably different than the advance purchase or sale transaction prices. Most of the non-PURPA purchased power and substantially all of the PURPA power purchase costs are recovered through base rates and Idaho Power's power cost adjustment mechanisms.

Fuel Expense: The table below presents Idaho Power’s fuel expenses and generation at its thermal generating plants for the three and nine months endedSeptember 30, 2017 and 2016 (in thousands, except for per MWh amounts).

	Three months ended September 30,				Nine months ended September 30,
	2017		2016		2017		2016
Expense
Coal	$	40,361	$	56,651	$	84,855	$	103,599
Natural gas(1)	14,168		17,274		26,342		36,058
Total fuel expense	$	54,529	$	73,925	$	111,197	$	139,657
MWh generated
Coal	1,236		1,487		2,578		2,961
Natural gas(1)	665		712		1,067		1,557
Total MWh generated	1,901		2,199		3,645		4,518
Cost per MWh - Coal	$	32.65	$	38.10	$	32.92	$	34.99
Cost per MWh - Natural gas	$	21.31	$	24.26	$	24.69	$	23.16
Weighted average, all sources	$	28.68	$	33.62	$	30.51	$	30.91

⁽¹⁾ Includes a negligible amount of expense and generation related to the Salmon diesel-fired generation plant.

The majority of the fuel for Idaho Power’s jointly-owned coal-fired plants is purchased through long-term contracts, including purchases from BCC, a one-third owned joint venture of IERCo. The price of coal from BCC is subject to fluctuations in mine operating expenses, geologic conditions, and production levels. BCC supplies up to two-thirds of the coal used by the Jim Bridger plant.  Natural gas is mainly purchased on the regional wholesale spot market at published index prices. 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 periods.

Fuel expense decreased $19.4 million, or 26 percent, and $28.5 million, or 20 percent, in the third quarter and first nine months of 2017, respectively, compared with the same periods in 2016. The decreases in the third quarter and first nine months of 2017 were primarily due to increased output from Idaho Power's hydroelectric plants, which reduced utilization of gas and coal generation. Generation from the hydroelectric plants increased 50 percent during the third quarter of 2017 and 38 percent during the first nine months of 2017, compared with the same periods in 2016.

Power Cost Adjustment 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 power cost adjustment 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. The Idaho 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. The Idaho deferral period, or PCA year, runs from April 1 through March 31. Amounts deferred during the PCA year are primarily recovered or refunded during the subsequent June 1 through May 31 period. Because of the power cost adjustment mechanisms, the primary financial impacts of power supply cost variations is that cash is paid out but recovery from customers does not occur until a future period, or cash that is collected is refunded to customers in a future period, resulting in fluctuations in operating cash flows from year to year.

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The table that follows presents the components of the Idaho and Oregon power cost adjustment mechanisms for the three and nine months endedSeptember 30, 2017 and 2016 (in thousands). 

	Three months ended September 30,					Nine months ended September 30,
	2017		2016			2017		2016
Idaho power supply cost accrual (deferral)	$	8	$	(30,006	)	$	21,851	$	(17,408	)
Amortization of prior year authorized balances	10,971		11,664			29,357		29,322
Total power cost adjustment expense	$	10,979	$	(18,342	)	$	51,208	$	11,914

The power supply accruals (deferral) represent the portion of the power supply cost fluctuations accrued (deferred) under the power cost adjustment mechanisms. When actual power supply costs are lower than the amount forecasted in power cost adjustment rates, which was the case both periods in 2017, most of the difference is accrued.When actual power supply costs are higher than the amount forecasted in power cost adjustment rates, which was the case for both periods in 2016, 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 power cost adjustment year that were deferred or accrued in the prior power cost adjustment year (the true-up component of the power cost adjustment).

Other O&M Expenses: Other O&M expenses decreased $2.9 million, or 3 percent, in the third quarter of 2017 compared with the third quarter of 2016. Lower generation at Idaho Power's thermal plants and the timing of an annual maintenance outage at the Jim Bridger coal-fired plant resulted in lower thermal operating and maintenance costs in the third quarter of 2017 compared with the third quarter in 2016. Other O&M expenses decreased $0.4 million, or less than 1 percent, for the first nine months of 2017, compared with the same period in 2016. Compared with the first nine months of 2016, lower O&M expenses due to lower thermal generation during the first nine months of 2017, were mostly offset by weather-related increases in certain O&M expenses in early 2017.

Income Taxes

IDACORP's and Idaho Power's income tax expense for the nine months ended September 30, 2017, when compared with the same period in 2016, increased $16.8 million and $15.3 million, respectively, primarily as a result of greater pre-tax income, the $5.6 million flow-through income tax benefit related to the tax deduction for bond redemption costs incurred in the first nine months of 2016, and tax benefits from distributions from fully-amortized affordable housing investments that were also recorded in 2016. 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 2017 (including expenditures incurred to-date in 2017) through 2021.

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 2017, 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 27, 2017, IDACORP's and Idaho Power's access to debt, equity, and credit arrangements included:

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

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• 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 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.

Based on planned capital expenditures and operating and maintenance expenses, the companies believe they will be able to meet capital and debt service requirements and fund corporate expenses during at least the next twelve months with a combination of existing cash, operating cash flows generated by Idaho Power's utility business, availability under existing credit facilities, and access to commercial paper and long-term debt 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, 2017, IDACORP's and Idaho Power's capital structures, as calculated for purposes of applicable debt covenants, were as follows:

	IDACORP	Idaho Power
Debt	44%	46%
Equity	56%	54%

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 endedSeptember 30, 2017 were $349 million and $363 million, respectively, increases of $73 million and $113 million, respectively, compared with the same period in 2016. Significant items that affected the comparability of the companies' operating cash flows in the first nine months of 2017 compared with the same period in 2016 were as follows:

• Changes in regulatory assets and liabilities increased operating cash flows by $48 million. The increase is mostly related to the relative amounts of power supply and fixed costs deferred and collected under the Idaho power cost adjustment and FCA mechanisms, partially offset by revenues accrued in excess of collections from the Valmy Plant settlement stipulation, which will be collected in future periods;

• Operating cash flows increased by $16 million and $17 million for IDACORP and Idaho Power, respectively, due to a $46 million and a $28 millionincrease from changes in taxes accrued, offset partially by a $30 million and an $11 milliondecrease from changes in deferred taxes and investment tax credits, respectively; and

• Changes in working capital balances due primarily to timing, including fluctuations in accounts receivable, other current assets, and other current liabilities, as follows:

◦ timing of collections of accounts receivable balances decreased operating cash flows by $8 million for IDACORP and decreased operating cash flows by $15 million for Idaho Power. IDACORP's decrease is less than Idaho Power's decrease because IDACORP collected a $7.6 million receivable in the first quarter of 2017 from a legal settlement;

◦ the changes in other current assets increased cash flows by $11 million, which was primarily due to fluctuations in the balance in accrued unbilled revenues as energy sales near the end of the respective periods were impacted by weather;

◦ timing of accounts payable payments decreased operating cash flows by $22 million for IDACORP and increased operating cash flows by $24 million for Idaho Power (the difference relates to a $46.5 million payable from Idaho Power to IDACORP relating to estimated income tax payments); and

◦ other current liabilities, which include non-incentive accrued compensation, customer deposits, accrued interest, and other miscellaneous liabilities, increased more during the first nine months of 2017 compared

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with the first nine months of 2016, and increased cash flows by $2 million during the first nine months of 2017 compared with the first nine months of 2016.

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 endedSeptember 30, 2017, were $199 million. Investing cash outflows for 2017 and 2016 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 has a Rabbi trust designated to provide funding for obligations of its nonqualified defined benefit plans. In the first nine months of 2017, related to activity in the Rabbi trust, Idaho Power purchased $3 million of available-for-sale securities and received $4 million of proceeds from the sales of available-for-sale securities.

Financing Cash Flows

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

IDACORP's and Idaho Power's financing cash outflows for the nine months endedSeptember 30, 2017 were $107 million and $106 million, respectively. In the first nine months of 2017, IDACORP and Idaho Power paid cash dividends of $83 million and had a net reduction in commercial paper of $19 million.

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 a third-party agent. The most recent sales agency agreement terminated in May 2016. In May 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. IDACORP has no current plans to issue equity securities other than under its equity compensation plans during 2017, and as of the date of this report, the company has not pursued the execution of a new sales agency agreement.  

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, subject to conditions specified in the orders. Authority from the IPUC is effective 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 interest rate limit of seven percent.

In September 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 in 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). At the same time, Idaho Power entered into the Forty-eighth Supplemental Indenture, dated 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 the 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.

The 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, 2017 was limited to approximately $759 million. Separately, the Indenture also limits the amount of additional first mortgage bonds that Idaho

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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, 2017, Idaho Power could issue approximately $1.8 billion of additional first mortgage bonds based on retired first mortgage bonds and total unfunded property additions.

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, replacing prior credit agreements. 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 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. While the credit facilities currently provide for a maturity date of November 5, 2021, the credit agreements grant IDACORP and Idaho Power the right to request an additional one-year extension, subject to certain conditions. 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, 2016, 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, 2017, the leverage ratios for IDACORP and Idaho Power were 44 percent and 46 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, 2017, 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 2017.

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 (in thousands).

	September 30, 2017						December 31, 2016
	IDACORP(2)			Idaho Power			IDACORP(2)		Idaho Power
Revolving credit facility	$	100,000		$	300,000		$	100,000	$	300,000
Commercial paper outstanding	(2,425		)	—			—		(21,800		)
Identified for other use(1)	—			(24,245		)	—		(24,245		)
Net balance available	$	97,575		$	275,755		$	100,000	$	253,955

⁽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.

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At October 27, 2017, IDACORP hadno loans outstanding under its credit facilities and had $2.3 million of commercial paper outstanding. Idaho Power hadno loans outstanding under its credit facilities and no commercial paper outstanding. The table below presents additional information about short-term commercial paper borrowing during the three and nine months endedSeptember 30, 2017 (in thousands).

	Three months ended						Nine months ended
	September 30, 2017						September 30, 2017
	IDACORP (1)			Idaho Power			IDACORP (1)			Idaho Power
Commercial paper:
Period end:
Amount outstanding	$	2,425		$	—		$	2,425		$	—
Weighted average interest rate	1.54		%	—		%	1.54		%	—		%
Daily average amount outstanding during the period	$	115		$	—		$	241		$	1,122
Weighted average interest rate during the period	1.53		%	—		%	1.15		%	1.12		%
Maximum month-end balance	$	2,425		$	—		$	2,425		$	—

⁽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, 2016. 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, 2017, Idaho Power had posted $0.4 million 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, 2017, the amount of additional collateral that could be requested upon a downgrade to below investment grade is approximately $5.1 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 $200 million during the nine months endedSeptember 30, 2017. The table below presents Idaho Power's expected cash requirements for construction, excluding AFUDC, for 2017 (including amounts incurred to-date) through 2021 (in millions).

	2017	2018	2019-2021
Expected capital expenditures (excluding AFUDC)	$290-300	$285-295	$900-950

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, 2016. The discussion below should be read in conjunction with that report.

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. 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

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relating to construction of the transmission line Idaho Power would seek to retain that percentage interest in the completed project. Total cost estimates for the project are between $1.0 billion and $1.2 billion, including Idaho Power's AFUDC. This cost estimate is preliminary and excludes the impacts of inflation and price changes of materials and labor resources that may occur following the date of the estimate.

Approximately $92 million, including AFUDC, has been expended on the Boardman-to-Hemingway project through September 30, 2017. Pursuant to the terms of the joint funding arrangements, Idaho Power has received approximately $48 million of that amount as reimbursement from the project participants as of September 30, 2017. Idaho Power has accrued in receivables approximately $18 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 $66 million. Joint permitting participants are obligated to reimburse Idaho Power for their share of any future project permitting expenditures incurred by Idaho Power.

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 final environmental impact statement (EIS) for the project in November 2016. As of the date of this report, the BLM's schedule provides for the issuance of a record of decision in 2017.

In the separate Oregon state permitting process, in June 2017, Idaho Power submitted its amended preliminary application for site certificate and expects the Oregon Department of Energy to issue a draft proposed order on the application in 2018. 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 2024 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 located near Boise, Idaho. In January 2012, Idaho Power and PacifiCorp entered a joint funding agreement for permitting of the project. Idaho Power has expended approximately $34 million, including AFUDC, on the permitting phase of the project through September 30, 2017. 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.

The permitting phase of the Gateway West project is subject to review and approval of the BLM. The BLM released its record of decision in November 2013 for eight of the ten transmission line segments. In May 2017, President Trump signed into law a bill that issued a right-of-way for certain portions of the remaining Gateway West segments. As of the date of this report, the other portions of the remaining segments continue to be subject to the BLM's review and approval. Idaho Power expects the BLM to issue a record of decision for the outstanding portions of the remaining segments in 2018.

Defined Benefit Pension Plan Contributions

Idaho Power has no minimum contribution requirement to its defined benefit pension plan in 2017; however, Idaho Power has contributed $40 million to the plan during 2017. 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 endedSeptember 30, 2017, 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, 2016, except that Idaho Power entered into agreements with solar, biomass, and hydro PURPA-qualifying facilities that increased Idaho Power's contractual payment obligations by approximately $85 million over the 20-year terms of the contracts.

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, 2016.

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REGULATORY MATTERS

Introduction

Idaho Power's development of regulatory filings 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, 2016. 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, 2016, 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 Orders During 2017

During 2017, Idaho Power 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, 2017	$10.6 million PCA increase for the period from June 1, 2017 to May 31, 2018	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, 2017	$6.9 million FCA increase for the period from June 1, 2017 to May 31, 2018	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.
Valmy Plant Accelerated Depreciable Life - Idaho	New retail rates became effective June 1, 2017	$13.3 million increase in Idaho jurisdictional revenue requirement	The increase allows Idaho Power to recover specified costs associated with its plan to end its participation in coal-fired operations at the Valmy Plant by the end of 2025.
Depreciation Study - Idaho	New depreciation rates became effective June 1, 2017	No change in retail rates

⁽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.

Customer-Owned Generation Filing

On July 27, 2017, Idaho Power filed an application with the IPUC requesting the creation of two new classes for residential and small general service customers who choose to install on-site generation on or after January 1, 2018. If approved as proposed, Idaho Power does not, as of the date of this report, anticipate that the creation of these new rate classes would impact in the near term the current rates for the approximately 1,700 residential and small general service customers and applicants who currently take or are requesting net metering services from Idaho Power for their customer-owned generation.

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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 amortization 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 additional amortization of 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.

Under the October 2014 settlement stipulation, Idaho Power recorded no additional ADITC amortization during the first nine months of 2017, based on Idaho Power's estimate of Idaho ROE for the full-year 2017. During the first nine months of 2016, Idaho Power recorded $1.5 million of additional ADITC amortization, which was reversed later in 2016 as actual financial results exceeded Idaho Power's early estimates.

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

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 endedSeptember 30, 2017 (in thousands).

	Idaho			Oregon(1)			Total
Balance at December 31, 2016	$	53,442		$	428		$	53,870
Current period net power supply costs accrued	(21,851		)	—			(21,851		)
Prior amounts recovered through rates	(28,846		)	(511		)	(29,357		)
Revenue sharing	1,186			—			1,186
Prior energy efficiency funds refunded through rates	6,665			—			6,665
SO2 allowance and renewable energy certificate sales	(1,911		)	(56		)	(1,967		)
Energy efficiency rider funds transferred to Idaho PCA mechanism	(13,000		)	—			(13,000		)
Interest and other	218			42			260
Balance at September 30, 2017	$	(4,097	)	$	(97	)	$	(4,194	)

⁽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 power cost adjustment 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 power cost adjustment mechanisms 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.

Valmy Rate Base Adjustment Settlement Stipulations and Depreciation Rate Settlement Stipulations

In May 2017, the IPUC approved a settlement stipulation allowing accelerated depreciation and cost recovery for the Valmy Plant. The settlement stipulation provides for an increase in Idaho jurisdictional revenues of $13.3 million per year, and (1) levelized collections and associated cost recovery through December 2028, (2) accelerated depreciation on unit 1 through 2019 and unit 2 through 2025, (3) Idaho Power to use prudent and commercially reasonable efforts to end its participation in the operation of unit 1 by the end of 2019 and unit 2 by the end of 2025, and (4) a filing no later than 2020 that would include actual and planned incremental investments in unit 2, including updated financial analysis regarding the lowest costs options for unit 2. The costs intended to be recovered by the increased revenue requirement include current investments as of May 31, 2017 in both units, forecasted unit 1 investments from 2017 through 2019, and forecasted decommissioning costs for unit 1 and unit

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2, offset by forecasted operation and maintenance costs savings. The settlement stipulation also provides for the regulatory deferral of the difference between actual revenue requirements and levelized collections, and provides for the regulatory deferral of the difference between actual costs incurred (including accelerated depreciation expense on unit 1 through 2019 and unit 2 through 2025) compared with costs permitted to be recovered during the cost recovery period specified in the settlement stipulation (including depreciation expense through 2028). If actual costs incurred differ from forecasted amounts included in the settlement stipulation, collection or refund of any differences would be subject to regulatory approval.

In May 2017, the IPUC and OPUC approved settlement stipulations related to revised depreciation rates for Idaho Power's other electric plant in service, and adjusted base rates in Oregon to reflect the revised depreciation rates applied to electric plant-in-service based on balances from the most recent general rate case. These settlement stipulations provided for new depreciation rates to go into effect on June 1, 2017, with no significant resulting increase in revenue.

For more information on the settlement stipulations and their impacts on results, see Note 3 - "Regulatory Matters" to the condensed consolidated financial statements included in this report and "Executive Overview" in this MD&A.

Open Access Transmission Tariff Rate

Idaho Power uses a formula rate for transmission service provided under its OATT, which allows transmission rates to be updated annually based primarily on financial and operational data Idaho Power files with the FERC. On August 28, 2017, Idaho Power filed its 2017 final transmission rate with the FERC, reflecting a transmission rate of $34.90 per kW-year, to be effective for the period from October 1, 2017 to September 30, 2018. Idaho Power's final rate was based on a net annual transmission revenue requirement of $130.4 million. The OATT rate in effect from October 1, 2016 to September 30, 2017, was $25.52 per kW-year based on a net annual transmission revenue requirement of $127.4 million. The increase in the OATT rate was largely attributable to an asset exchange transaction with one transmission customer, and the termination of legacy long-term transmission service agreements and its impact on the transmission formula rate, which was fully incorporated in the new formula rate effective October 1, 2017.

2017 Integrated Resource Plan

The IPUC and OPUC require that Idaho Power prepare biennially an IRP. The IRP seeks to forecast Idaho Power's loads and resources for a 20-year period, analyzes potential supply-side, demand-side, and transmission options, and identifies potential near-term and long-term actions. Idaho Power filed its most recent IRP with the IPUC and OPUC in June 2017. The 2017 IRP assumes a forecasted annual growth in average energy demand of 0.9 percent and a forecasted annual growth in peak-hour demand of 1.4 percent over the 20-year period. The 2017 IRP identified a preferred resource portfolio and action plan, which includes the completion of the Boardman-to-Hemingway transmission line by 2026, the end to Idaho Power's participation in coal-fired operations at the Valmy Plant units 1 and 2 in 2019 and 2025, respectively, and the early retirement of Jim Bridger units 1 and 2 in 2032 and 2028, respectively, with no other new resource needs prior to 2026. However, as noted in the 2017 IRP, there is considerable uncertainty surrounding the resource sufficiency estimates and project completion dates, including uncertainty around the timing and extent of third party development of renewable resources, fuel commodity prices, environmental requirements, the actual completion date of the Boardman-to-Hemingway transmission project, and the economics and logistics of plant operation and retirements. These uncertainties, as well as others, could result in changes to the desirability of the preferred portfolio and adjustments to the timing and nature of anticipated and actual actions.

Idaho Energy Efficiency Rider

On an annual basis, Idaho Power applies to the IPUC for an order designating Idaho Power’s prior calendar year Idaho Energy Efficiency Rider (Idaho Rider) funded expenses as prudently incurred. In 2012 and 2013, the IPUC declined to decide the prudence of the increases in 2011 and 2012 Idaho Rider funded labor increases, while at the same time offering Idaho Power another opportunity to provide sufficient evidence at a future time.

In 2017, Idaho Power applied to the IPUC for an order determining that the 2011 - 2016 Idaho Rider funded labor increases of $1.9 million were prudently incurred and eligible for collection through the Idaho Rider. On October 16, 2017, the IPUC issued its order determining that the 2011 - 2016 incremental Idaho Rider funded labor expenses of $1.9 million were prudently incurred. In its order, the IPUC also authorized actual Idaho Rider funded wage increases after 2016, up to a 2 percent cap. The IPUC determined that this process does not require pre-determination as to prudence, no longer requires labor to be examined in Idaho Power’s annual prudence cases, and that the base wage level and annual cap will be reset in future general rate cases. Idaho Power expects that the prudency finding will result in an approximate $2.0 million increase in operating income in 2017.

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Renewable and Other Energy Contracts

Idaho Power has contracts for the purchase of electricity produced by third-party owned generation facilities, most of which produce energy with the use of renewable generation sources such as wind, solar, biomass, small hydroelectric and geothermal. The majority of these contracts are entered into as mandatory purchases under PURPA. As of September 30, 2017, Idaho Power had contracts to purchase energy from 127 on-line PURPA projects. An additional three contracts are with non-PURPA projects, including the Elkhorn Valley wind project with a 101 MW nameplate capacity. The following table sets forth, as of September 30, 2017, the resource type and nameplate capacity of Idaho Power's signed agreements for power purchases from PURPA and non-PURPA generating facilities. These agreements have original contract terms ranging from one to 35 years.

Resource Type	Total On-line (MW)	Under Contract but not yet On-line (MW)	Total Projects under Contract (MW)	Began Operating During 2017 (MW)
PURPA:
Wind	627	—	627	50
Solar	290	24	314	120
Hydroelectric	147	8	155	—
Other	50	5	55	—
Total	1,114	37	1,151	170
Non-PURPA:
Wind	101	—	101	—
Geothermal	35	—	35	—
Total	136	—	136	—

Relicensing of Hydroelectric Projects

In connection with Idaho Power's efforts to relicense the HCC, as described in more detail in IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2016, in Part II, Item 7 - "Regulatory Matters," Idaho Power has filed water quality certification applications, required under Section 401 of the Clean Water Act (CWA), with the states of Idaho and Oregon requesting that each state certify that any discharges from the project comply with applicable state water quality standards. Section 401 of the CWA requires that a state either approve or deny a Section 401 water quality certification application within one year of the filing of the application or the state may be considered to have waived its certification authority under the CWA. As a consequence, Idaho Power has been filing and withdrawing its Section 401 certification applications with Oregon and Idaho on an annual basis while it has been working with the states to identify measures that will provide reasonable assurance that discharges from the HCC will adequately address applicable water quality standards. In the 2016 Section 401 certification application process, Oregon required Idaho Power to comply with fish passage and reintroduction conditions. Idaho's water quality certification, however, provides that Idaho Power shall take no action that may result in the reintroduction or establishment of spawning populations of any fish species into Idaho's waters without consultation with and express approval of the State of Idaho. In April 2017, the governors of Oregon and Idaho jointly requested that Idaho Power withdraw and resubmit its Section 401 certification applications in both states to allow the states additional time to negotiate a potential resolution of the disputed issues. Idaho Power subsequently withdrew its Section 401 certification applications in both states. Idaho Power resubmitted its application to both states in April 2017 and since that time the states have been negotiating towards a mutually agreeable solution.

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 $269 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, 2017. 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 currently will reduce future collections when HCC relicensing costs are approved for recovery in base rates. As of September 30, 2017, Idaho Power's regulatory liability for collection of AFUDC relating to the HCC was $116 million. Idaho Power is unable to predict the timing of issuance of a new license for the HCC, or the financial or operational requirements of a new license.

In December 2016, Idaho Power filed an application with the IPUC requesting a determination that Idaho Power's expenditures of $220.8 million through year-end 2015 on relicensing of the HCC were prudently incurred, and thus eligible for future

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inclusion in retail rates. Idaho Power is currently participating in settlement proceedings related to the prudence determination. If settlement is not reached, IPUC staff and intervenor testimony is due December 15, 2017.

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 CWA, the Resource Conservation and Recovery Act, the Toxic Substances Control Act, the Comprehensive Environmental Response, Compensation and Liability Act, and the Endangered Species Act (ESA), among other laws. 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 may 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. The decision to pursue an end to participation in coal-fired operations at the Valmy Plant was also based primarily on the economics of operating the plant. Additionally, in light of the uncertainty resulting from pending environmental regulation and the substantial estimated cost of selective catalytic reduction equipment (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, 2016, includes a summary of Idaho Power's expected capital and operating expenditures for environmental matters during the period from 2017 to 2019. Given the uncertainty of future environmental regulations, Idaho Power is unable to predict its environmental-related expenditures beyond that time, though they could be substantial.

A summary of notable environmental matters impacting, or expected to potentially impact, IDACORP and Idaho Power, is included in Part II, Item 7 - "MD&A - Environmental Issues" and "MD&A - Liquidity and Capital Resources - Capital Requirements - Environmental Regulation Costs" in IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2016. Included below is a summary of notable developments in environmental and related issues impacting Idaho Power since the discussion in that report.

Executive Orders on Environmental Matters

In March 2017, President Trump issued an executive order directing the U.S. Environmental Protection Agency (EPA) to review the Clean Power Plan (CPP), the greenhouse gas new source performance standards (GHG NSPS), and the proposed Federal Implementation Plan (FIP) for CPP and, if appropriate, to propose rules suspending, revising, or rescinding the CPP, GHG NSPS, and proposed FIP within 45 to 120 days after the date of the order. The order also directs the Secretary of the Interior to lift the moratorium on federal land for coal leasing activities and revoke certain Obama Administration directives regarding the nature and extent of mitigation required for projects on federal lands. The order also addresses other climate-related issues, including rescinding the technical support documents that estimate the social cost of carbon, rescinding the National Environmental Policy Act guidance on greenhouse gases, and rescinding climate-related actions undertaken by the

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previous presidential administration, among other issues. Shortly after the orders were issued, the EPA notified each state’s governor that if any deadlines under the CPP become relevant in the future, the EPA will toll its requirement for states to comply with the regulation. On October 10, 2017, the EPA announced a proposal to repeal the CPP but did not provide specific information about its replacement. As of the date of this report and in light of these executive actions, Idaho Power believes it is unlikely that it will be required to comply with the CPP in the near term.

In August 2017, President Trump also issued an executive order to accelerate federal agencies' environmental review and permitting for major infrastructure projects. The outcome of the EPA’s and other federal agencies' review of regulations covered by the executive orders is difficult to predict. Changes to or elimination of regulations may lower Idaho Power's costs of operating and maintaining fossil fuel-fired generation plants and transmission lines, due to the reduction of potential environmental infrastructure upgrades or reduction or elimination of permitting requirements. The executive orders and resulting federal regulations could, on the other hand, be affected by Congressional action and challenged in court. Further, state and local governmental authorities could choose to replace the federal regulations or bolster environmental compliance and enforcement efforts at the local level, and therefore, Idaho Power is uncertain whether and to what extent the orders could affect its operations and environmental-related expenditures. Idaho Power plans to continue to monitor actions associated with or resulting from the executive orders.

Developments in Regulation of Sage Grouse Habitat

In February 2016, a lawsuit was filed in the U.S. District Court of 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. If the exemptions are overturned, Idaho Power may be required to reroute the projects, which could lead to substantially higher construction and permitting costs and could delay construction.

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. In October 2016, the plaintiffs amended their complaint to no longer challenge the exemptions; however, in December 2016, the North Dakota court transferred claims challenging certain Idaho land use plan amendments to the U.S. District Court for the District of Columbia. Idaho Power is participating in the proceedings in an effort to protect its interests.

In June 2017, the Secretary of the Interior issued an order directing the BLM to review the 2015 sage grouse resource management and land use plan revisions and to identify provisions that may require modification or rescission to address energy and other development of public lands. In October 2017, the Secretary of the Interior issued a notice of intent declaring the Department of the Interior’s intent to consider amending the 2015 sage grouse resource management and land use plan revisions. As of the date of this report, the above lawsuits are stayed as the parties and the courts consider the Department of the Interior’s review of the sage grouse resource management and land use plan revisions.

Clean Water Act Matters

In June 2017, the EPA and the Department of Army issued a notice of their intent to rescind and replace the definition of "waters of the United States" under the CWA as enacted in August 2015 (WOTUS), which had expanded the number of waterways subject to federal jurisdiction for environmental regulation beyond traditional navigable waters, interstate waters, territorial seas, tributaries, and adjacent wetlands, to a number of other waters, including waters with a "significant nexus" to those traditional waters. As described in Part II, Item 7 - "MD&A - Environmental Issues" in IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2016, Idaho Power did not expect the revised WOTUS to have a material adverse effect on Idaho Power's operations or financial condition. Similarly, because the CWA as previously interpreted applies to most of Idaho Power's facilities, including its hydroelectric plants, Idaho Power does not expect this proposal to have a material benefit to Idaho Power's operations or financial condition.

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Review of Federal Coal Leases

In January 2016, the Secretary of the U.S. Department of the Interior issued an order directing the BLM to prepare a Programmatic Environmental Impact Statement (PEIS) to analyze potential reforms to the federal coal lease program and placed a moratorium on new federal coal leasing, with limited exceptions, pending completion of the PEIS. In January 2017, the Secretary of the Department of the Interior ordered a cessation of all work on the PEIS and in March 2017, lifted the moratorium on new federal coal leases. As of the date of this report, Idaho Power believes that BCC has adequate reserves under existing leases to satisfy its coal delivery obligations to the Jim Bridger plant during the term of the existing coal supply contract through 2024, and that the Jim Bridger plant will otherwise have access to sufficient coal supplies for its operation for the foreseeable future. However, the lifting of the moratorium could increase the availability of coal resources and lower the cost of leases for coal resources, which could reduce the fuel cost for each of Idaho Power's co-owned coal-fired plants.

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, 2016.

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.

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, 2016, 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, 2017. 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, 2017, IDACORP had no net floating rate debt, as the carrying value of short-term investments exceeded the carrying value of outstanding variable-rate debt.

Fixed Rate Debt: As of September 30, 2017, IDACORP had $1.7 billion in fixed rate debt, with a fair market value of approximately $1.9 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 $267.5 million if market interest rates were to decline by one percentage point from their September 30, 2017 levels.

57

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 power cost adjustment 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, 2017, 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, 2016. Information regarding Idaho Power’s use of derivative instruments to manage commodity price risk can be found in Note 10 – "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, 2017, Idaho Power had posted $0.4 million 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, 2017, the amount of collateral that could be requested upon a downgrade to below investment grade was approximately $5.1 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, 2017, 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, 2016. Additional information regarding Idaho Power’s management of credit risk and credit contingent features can be found in Note 10 – "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 11 - "Benefit Plans" to the consolidated financial statements included in IDACORP's Annual Report on Form 10-K for the year ended December 31, 2016.

58

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, 2017, 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, 2017, 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, 2017, that have materially affected, or are reasonably likely to materially affect, IDACORP's or Idaho Power's internal control over financial reporting.

59

PART II – OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

None

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, 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 5 - "Common Stock" to the condensed consolidated financial statements included in this report for a description of restrictions on IDACORP's and Idaho Power's payment of dividends.

Issuer Purchases of Equity Securities

During the quarter ended September 30, 2017, 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, 2017 - July 31, 2017	44	$	86.36	—	—
August 1, 2017 - August 31, 2017	—	—		—	—
September 1, 2017 - September 30, 2017	124	87.93		—	—
Total	168	$	87.52	—	—

⁽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

60

ITEM 6. EXHIBITS

The following exhibits are filed or furnished, as applicable, with the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017:

		Incorporated by Reference
Exhibit No.	Exhibit Description	Form	File No.	Exhibit No.	Date	Included Herewith
10.1 (1)	Second Amendment to the Idaho Power Company Employee Savings Plan, executed October 29, 2017 and effective January 1, 2018					X
12.1	IDACORP, Inc. Computation of Ratio of Earnings to Fixed Charges and Supplemental Ratio of Earnings to Fixed Charges					X
12.2	Idaho Power Company Computation of Ratio of Earnings to Fixed Charges and Supplemental Ratio of Earnings to Fixed Charges					X
15.1	Letter Re: Unaudited Interim Financial Information					X
15.2	Letter Re: Unaudited Interim Financial Information					X
31.1	Certification of IDACORP, Inc. Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002					X
31.2	Certification of IDACORP, Inc. Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002					X
31.3	Certification of Idaho Power Company Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002					X
31.4	Certification of Idaho Power Company Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002					X
32.1	Certification of IDACORP, Inc. Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002					X
32.2	Certification of IDACORP, Inc. Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002					X
32.3	Certification of Idaho Power Company Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002					X
32.4	Certification of Idaho Power Company Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002					X
95.1	Mine Safety Disclosures					X
101.INS	XBRL Instance Document					X
101.SCH	XBRL Taxonomy Extension Schema Document					X
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document					X
101.LAB	XBRL Taxonomy Extension Label Linkbase Document					X
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document					X
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document					X

⁽¹⁾ Management contract or compensatory plan or arrangement.

61

SIGNATURES

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

		IDACORP, INC.
		(Registrant)
Date:	November 2, 2017	By:	/s/ Darrel T. Anderson
			Darrel T. Anderson
			President and Chief Executive Officer
Date:	November 2, 2017	By:	/s/ Steven R. Keen
			Steven R. Keen
			Senior Vice President, Chief Financial
			Officer, and Treasurer
		IDAHO POWER COMPANY
		(Registrant)
Date:	November 2, 2017	By:	/s/ Darrel T. Anderson
			Darrel T. Anderson
			President and Chief Executive Officer
Date:	November 2, 2017	By:	/s/ Steven R. Keen
			Steven R. Keen
			Senior Vice President, Chief Financial
			Officer, and Treasurer

62

EX-10.1

Exhibit 10.1

SECOND AMENDMENT

TO THE IDAHO POWER COMPANY

EMPLOYEE SAVINGS PLAN

The Idaho Power Company Employee Savings Plan, amended and restated as of January 1, 2016 (the "Plan") is amended to reduce the maximum aggregate contribution from 100% to 80% of a Participant's Compensation, as set forth below. This amendment shall be effective January 1, 2018.

1. The first sentence of Section 3.1.1 (a) is amended to read as follows:

"Upon enrollment, a Participant may direct that his or her Employer make Deferral Contributions to the Trust Fund of from 1 percent to 80 percent of his or her Compensation (in 1 percent increments) for each pay period."

2. The last sentence of Section 3.1.1 (e) is amended to read as follows:

"A Participant's Deferral Contributions, After-Tax Contributions and Roth Deferrals are limited to 80 percent of a Participant's Compensation for a Plan Year."

3. The first paragraph of Section 3.3 is amended to read as follows:

"Upon enrollment, a Participant will be entitled to contribute to the Trust Fund an amount between 1 percent and 80 percent of his or her Compensation (in 1 percent increments) for each pay period as an After-Tax or Roth Contribution which is nondeductible. Deferral Contributions, After-Tax and Roth Contributions are limited to 80 percent of a Participant's Compensation."

IN WITNESS WHEREOF, the Employer has executed this Amendment this 29^th day of October, 2017.

IDAHO POWER COMPANY

Employer

By: /s/ Lonnie G. Krawl

Lonnie G. Krawl

SVP of Administrative Services and

Chief Human Resources Officer    

EX-12.1

Exhibit 12.1

IDACORP, Inc.

Consolidated Financial Information

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

(Thousands of Dollars)

	Nine months ended September 30,		Twelve Months Ended
			December 31,
	2017		2016		2015		2014			2013		2012
RATIO OF EARNINGS TO FIXED CHARGES
Earnings, as defined:
Income from continuing operations before income taxes	$	219,597	$	234,517	$	240,235	$	210,526		$	254,520	$	206,992
Adjust for distributed income of equity investees	11,081		12,770		1,330		(6,797		)	4,812		7,704
Fixed charges, as below	70,563		93,857		93,409		90,012			90,236		87,635
Total earnings, as defined	$	301,241	$	341,144	$	334,974	$	293,741		$	349,568	$	302,331
Fixed charges, as defined:
Interest charges (1)	$	69,195	$	92,229	$	91,978	$	88,265		$	88,695	$	85,799
Rental interest factor	1,368		1,628		1,431		1,747			1,541		1,836
Total fixed charges, as defined	$	70,563	$	93,857	$	93,409	$	90,012		$	90,236	$	87,635
Ratio of earnings to fixed charges	4.27x		3.63x		3.59x		3.26x			3.87x		3.45x
SUPPLEMENTAL RATIO OF EARNINGS TO FIXED CHARGES
Earnings, as defined:
Income from continuing operations before income taxes	$	219,597	$	234,517	$	240,235	$	210,526		$	254,520	$	206,992
Adjust for distributed income of equity investees	11,081		12,770		1,330		(6,797		)	4,812		7,704
Supplemental fixed charges, as below	70,716		94,075		93,651		90,356			90,741		88,266
Total earnings, as defined	$	301,394	$	341,362	$	335,216	$	294,085		$	350,073	$	302,962
Supplemental fixed charges:
Interest charges (1)	$	69,195	$	92,229	$	91,978	$	88,265		$	88,695	$	85,799
Rental interest factor	1,368		1,628		1,431		1,747			1,541		1,836
Supplemental increment to fixed charges (2)	153		218		242		344			505		631
Total supplemental fixed charges	$	70,716	$	94,075	$	93,651	$	90,356		$	90,741	$	88,266
Supplemental ratio of earnings to fixed charges	4.26x		3.63x		3.58x		3.25x			3.86x		3.43x
(1)FIN 48 interest is not included in interest charges.
(2) Explanation of increment - Interest on the guaranty of American Falls Reservoir District bonds and Milner Dam, Inc. notes which are already included in operation expenses.

EX-12.2

Exhibit 12.2

Idaho Power Company

Consolidated Financial Information

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

(Thousands of Dollars)

	Nine months ended September 30,		Twelve Months Ended
			December 31,
	2017		2016		2015		2014			2013		2012
RATIO OF EARNINGS TO FIXED CHARGES
Earnings, as defined:
Income from continuing operations before income taxes	$	215,545	$	226,427	$	239,211	$	208,903		$	253,001	$	204,138
Adjust for distributed income of equity investees	12,432		12,861		1,060		(7,228		)	4,659		8,509
Fixed charges, as below	70,501		93,615		93,164		89,751			89,819		87,162
Total earnings, as defined	$	298,478	$	332,903	$	333,435	$	291,426		$	347,479	$	299,809
Fixed charges, as defined:
Interest charges (1)	$	69,146	$	92,006	$	91,762	$	88,034		$	88,309	$	85,359
Rental interest factor	1,355		1,609		1,402		1,717			1,510		1,803
Total fixed charges, as defined	$	70,501	$	93,615	$	93,164	$	89,751		$	89,819	$	87,162
Ratio of earnings to fixed charges	4.23x		3.56x		3.58x		3.25x			3.87x		3.44x
SUPPLEMENTAL RATIO OF EARNINGS TO FIXED CHARGES
Earnings, as defined:
Income from continuing operations before income taxes	$	215,545	$	226,427	$	239,211	$	208,903		$	253,001	$	204,138
Adjust for distributed income of equity investees	12,432		12,861		1,060		(7,228		)	4,659		8,509
Supplemental fixed charges, as below	70,654		93,833		93,406		90,095			90,324		87,793
Total earnings, as defined	$	298,631	$	333,121	$	333,677	$	291,770		$	347,984	$	300,440
Supplemental fixed charges:
Interest charges (1)	$	69,146	$	92,006	$	91,762	$	88,034		$	88,309	$	85,359
Rental interest factor	1,355		1,609		1,402		1,717			1,510		1,803
Supplemental increment to fixed charges (2)	153		218		242		344			505		631
Total supplemental fixed charges	$	70,654	$	93,833	$	93,406	$	90,095		$	90,324	$	87,793
Supplemental ratio of earnings to fixed charges	4.23x		3.55x		3.57x		3.24x			3.85x		3.42x
(1)FIN 48 interest is not included in interest charges.
(2) Explanation of increment - Interest on the guaranty of American Falls Reservoir District bonds and Milner Dam, Inc. notes which are already included in operation expenses.

EX-15.1

Exhibit 15.1

November 2, 2017

IDACORP, Inc.

Boise, Idaho

We have reviewed, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the unaudited interim financial information of IDACORP, Inc. and subsidiaries for the periods ended September 30, 2017, and 2016, as indicated in our report dated November 2, 2017; because we did not perform an audit, we expressed no opinion on that information.

We are aware that our report referred to above, which is included in your Quarterly Report on Form 10-Q for the quarter ended September 30, 2017, is incorporated by reference in Registration Statement Nos. 333-200399 and 333-211475 on Form S-3 and Registration Statement Nos. 333-65406, 333-125259, and 333-159855 on Form S-8.

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

/s/ DELOITTE & TOUCHE LLP

Boise, Idaho

EX-15.2

Exhibit 15.2

November 2, 2017

Idaho Power Company

Boise, Idaho

We have reviewed, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the unaudited interim financial information of Idaho Power Company and subsidiary for the periods ended September 30, 2017, and 2016, as indicated in our report dated November 2, 2017; because we did not perform an audit, we expressed no opinion on that information.

We are aware that our report referred to above, which is included in your Quarterly Report on Form 10-Q for the quarter ended September 30, 2017, is incorporated by reference in Registration Statement No. 333-211475-01 on Form S-3 and Registration Statement No. 333-66496 on Form S-8.

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

/s/ DELOITTE & TOUCHE LLP

Boise, Idaho

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Darrel T. Anderson, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date:	November 2, 2017	By:	/s/ Darrel T. Anderson
			Darrel T. Anderson
			President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Steven R. Keen, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date:	November 2, 2017	By:	/s/ Steven R. Keen
			Steven R. Keen
			Senior Vice President, Chief Financial Officer, and Treasurer

EX-31.3

Exhibit 31.3

CERTIFICATION

I, Darrel T. Anderson, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date:	November 2, 2017	By:	/s/ Darrel T. Anderson
			Darrel T. Anderson
			President and Chief Executive Officer

EX-31.4

Exhibit 31.4

CERTIFICATION

I, Steven R. Keen, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date:	November 2, 2017	By:	/s/ Steven R. Keen
			Steven R. Keen
			Senior Vice President, Chief Financial Officer, and Treasurer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of IDACORP, Inc. (the "Company") on Form 10-Q for the quarter ended September 30, 2017 (the "Report"), I, Darrel T. Anderson, President and Chief Executive Officer of the Company, certify that:

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

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

/s/ Darrel T. Anderson

Darrel T. Anderson

President and Chief Executive Officer

November 2, 2017

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of IDACORP, Inc. (the "Company") on Form 10-Q for the quarter ended September 30, 2017 (the "Report"), I, Steven R. Keen, Senior Vice President, Chief Financial Officer, and Treasurer of the Company, certify that:

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

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

/s/ Steven R. Keen

Steven R. Keen

Senior Vice President, Chief Financial Officer, and Treasurer

November 2, 2017

EX-32.3

Exhibit 32.3

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Idaho Power Company (the "Company") on Form 10-Q for the quarter ended September 30, 2017 (the "Report"), I, Darrel T. Anderson, President and Chief Executive Officer of the Company, certify that:

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

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

/s/ Darrel T. Anderson

Darrel T. Anderson

President and Chief Executive Officer

November 2, 2017

EX-32.4

Exhibit 32.4

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Idaho Power Company (the "Company") on Form 10-Q for the quarter ended September 30, 2017 (the "Report"), I, Steven R. Keen, Senior Vice President, Chief Financial Officer, and Treasurer of the Company, certify that:

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

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

/s/ Steven R. Keen

Steven R. Keen

Senior Vice President, Chief Financial Officer, and Treasurer

November 2, 2017

EX-95.1

Exhibit 95.1

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

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

The table below summarizes the number of citations, notices, and orders issued, and penalties assessed, by MSHA for the Mine under the indicated provisions of the Mine Safety Act, and other data for the Mine, during the three-month period ended September 30, 2017. Legal actions pending before the Federal Mine Safety and Health Review Commission (FMSHRC) are as of September 30, 2017. Due to timing and other factors, the data may not agree with the mine data retrieval system maintained by MSHA at www.msha.gov.

			Three-month period ended September 30, 2017
			(unaudited)
			Surface Mine (MSHA ID No. 4800677)		Underground Mine (MSHA ID No. 4801646)
Mine Safety Act Citations and Orders:
	Section 104(a) Significant & Substantial Citations (1)		—		5
	Section 104(b) Orders (2)		—		—
	Section 104(d) Citations & Orders (3)		—		—
	Section 107(a) Imminent Danger Orders (4)		—		—
Total Value of Proposed MSHA Assessments (in thousands)		$	1	$	4
Legal Actions Pending (5)			1		1
Legal Actions Issued During Period			—		1
Legal Actions Closed During Period			—		7
Number of Fatalities			—		1
_________________
(1) For alleged violations of a mandatory mining safety standard or regulation where such violation contributed to a discrete safety hazard and there exists a reasonable likelihood that the hazard will result in an injury or illness and there is a reasonable likelihood that such injury will be of a reasonably serious nature.
(2) For alleged failure to totally abate the subject matter of a Mine Safety Act Section 104(a) citation within the period specified in the citation or as subsequently extended.
(3) For an alleged unwarrantable failure (i.e., aggravated conduct constituting more than ordinary negligence) to comply with a mining safety standard or regulation.
(4) The existence of any condition or practice in a coal or other mine that could reasonably be expected to cause death or serious physical harm if normal mining operations were permitted to proceed in the area before such condition or practice is eliminated.
(5) For the surface mine, the one pending legal action was categorized as a contest of proposed civil penalties for violations contained in a citation or order under Subpart C of the FMSHRC Procedural Rules. For the underground mine, the one pending legal action was categorized as a contest of proposed civil penalties for violations contained in a citation or order under Subpart C of the FMSHRC Procedural Rules.

For the three-month period ended September 30, 2017, the Mine did not receive written notice from MSHA of (i) a flagrant violation under Section 110(b)(2) of the Mine Safety Act; (ii) a pattern of violations of mandatory health or safety standards that are of such a nature as could have significantly and substantially contributed to the cause and effect of coal or other mine health or safety hazards under Section 104(e) of the Mine Safety Act; or (iii) the potential to have such a pattern.

XML

Document and Entity Information Document - shares	9 Months Ended
	Sep. 30, 2017	Oct. 27, 2017
Document Information
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2017
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	Q3
Trading Symbol	IDA
Entity Registrant Name	IDACORP INC.
Entity Central Index Key	0001057877
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		50,393,038
Entity Tax Identification Number	820505802
Idaho Power Company
Document Information
Entity Registrant Name	Idaho Power Company
Entity Central Index Key	0000049648
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		39,150,812
Entity Tax Identification Number	820130980

XML

Condensed Consolidated Statements of Income Statement - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Operating Revenues:
General business	$ 373,569	$ 341,825	$ 938,802	$ 885,486
Off-system sales	6,710	6,143	25,609	16,532
Other revenues	26,376	23,506	75,976	64,433
Total electric utility revenues	406,655	371,474	1,040,387	966,451
Other	1,669	571	3,487	1,986
Total operating revenues	408,324	372,045	1,043,874	968,437
Operating Expenses:
Purchased power	75,653	74,448	186,275	170,675
Fuel expense	54,529	73,925	111,197	139,657
Power cost adjustment	10,979	(18,342)	51,208	11,914
Other operations and maintenance	84,197	87,090	259,445	259,813
Energy efficiency programs	9,883	9,102	26,726	24,256
Depreciation	40,259	36,036	122,262	107,447
Taxes other than income taxes	8,614	8,287	26,134	25,228
Total electric utility expenses	284,114	270,546	783,247	738,990
Other	3,296	3,571	9,789	10,748
Total operating expenses	287,410	274,117	793,036	749,738
Operating Income	120,914	97,928	250,838	218,699
Other Income (Expense):
Allowance for equity funds used during construction	5,712	5,931	16,555	16,153
Earnings of unconsolidated equity-method investments	5,232	12,324	7,269	13,650
Other income (expense), net	2,256	2,681	7,024	7,074
Interest Expense:
Interest on long-term debt	20,300	20,296	60,897	61,659
Other interest	2,827	2,605	8,298	7,587
Allowance for borrowed funds used during construction	(2,385)	(2,589)	(7,106)	(7,226)
Total interest expense, net	20,742	20,312	62,089	62,020
Income Before Income Taxes	113,372	98,552	219,597	193,556
Income Tax Expense	22,296	15,535	45,420	28,622
Net Income	91,076	83,017	174,177	164,934
Adjustment for (income) loss attributable to noncontrolling interests	(442)	83	(610)	141
Net Income Attributable to IDACORP, Inc.	$ 90,634	$ 83,100	$ 173,567	$ 165,075
Weighted-average common shares outstanding - basic	50,362	50,296	50,361	50,299
Weighted-average common shares outstanding - diluted	50,421	50,393	50,408	50,361
Earnings Per Share of Common Stock:
Earnings attributable to IDACORP, Inc. - basic (in dollars per share)	$ 1.80	$ 1.65	$ 3.45	$ 3.28
Earnings attributable to IDACORP, Inc. - diluted (in dollars per share)	1.80	1.65	3.44	3.28
Dividends Declared Per Share of Common Stock	$ 0.55	$ 0.51	$ 1.65	$ 1.53
Idaho Power Company
Operating Revenues:
General business	$ 373,569	$ 341,825	$ 938,802	$ 885,486
Off-system sales	6,710	6,143	25,609	16,532
Other revenues	26,376	23,506	75,976	64,433
Total electric utility revenues	406,655	371,474	1,040,387	966,451
Operating Expenses:
Purchased power	75,653	74,448	186,275	170,675
Fuel expense	54,529	73,925	111,197	139,657
Power cost adjustment	10,979	(18,342)	51,208	11,914
Other operations and maintenance	84,197	87,090	259,445	259,813
Energy efficiency programs	9,883	9,102	26,726	24,256
Depreciation	40,259	36,036	122,262	107,447
Taxes other than income taxes	8,614	8,287	26,134	25,228
Total electric utility expenses	284,114	270,546	783,247	738,990
Operating Income	122,541	100,928	257,140	227,461
Other Income (Expense):
Allowance for equity funds used during construction	5,712	5,931	16,555	16,153
Earnings of unconsolidated equity-method investments	4,151	11,121	5,068	11,528
Other income (expense), net	(408)	(328)	(1,178)	(1,845)
Total other income	9,455	16,724	20,445	25,836
Interest Expense:
Interest on long-term debt	20,300	20,296	60,897	61,659
Other interest	2,811	2,546	8,249	7,397
Allowance for borrowed funds used during construction	(2,385)	(2,589)	(7,106)	(7,226)
Total interest expense, net	20,726	20,253	62,040	61,830
Income Before Income Taxes	111,270	97,399	215,545	191,467
Income Tax Expense	22,941	17,370	46,353	31,097
Net Income	$ 88,329	$ 80,029	$ 169,192	$ 160,370

XML

Condensed Consolidated Statements of Comprehensive Income - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, Tax	$ (302)	$ (362)	$ (906)	$ (1,085)
Net Income	91,076	83,017	174,177	164,934
Other Comprehensive Income:
Unfunded pension liability adjustment, net of tax	471	563	1,412	1,690
Total Comprehensive Income	91,547	83,580	175,589	166,624
Comprehensive (income) loss attributable to noncontrolling interests	(442)	83	(610)	141
Comprehensive Income Attributable to IDACORP, Inc.	91,105	83,663	174,979	166,765
Idaho Power Company
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, Tax	(302)	(362)	(906)	(1,085)
Net Income	88,329	80,029	169,192	160,370
Other Comprehensive Income:
Unfunded pension liability adjustment, net of tax	471	563	1,412	1,690
Total Comprehensive Income	$ 88,800	$ 80,592	$ 170,604	$ 162,060

XML

Condensed Consolidated Statements of Comprehensive Income (Parenthetical) (Parentheticals) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Unfunded pension liability adjustment, tax	$ 302	$ 362	$ 906	$ 1,085
Idaho Power Company
Unfunded pension liability adjustment, tax	$ 302	$ 362	$ 906	$ 1,085

XML

Condensed Consolidated Balance Sheets Statement - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Current Assets:
Cash and cash equivalents	$ 104,411	$ 61,480
Receivables:
Customer	101,703	71,557
Other	5,399	15,280
Taxes receivable	4,648	12,781
Accrued unbilled revenues	59,697	80,738
Materials and supplies (at average cost)	58,472	57,858
Fuel stock (at average cost)	54,093	53,698
Prepayments	16,477	18,389
Current regulatory assets	52,927	62,570
Other	101	5,961
Total current assets	457,928	440,312
Investments	111,952	125,164
Property, Plant and Equipment:
Utility plant in service	5,840,848	5,732,044
Accumulated provision for depreciation	(2,086,119)	(1,988,477)
Utility plant in service - net	3,754,729	3,743,567
Construction work in progress	463,106	405,069
Utility plant held for future use	7,511	7,441
Other property, net of accumulated depreciation	15,597	15,922
Property, plant and equipment - net	4,240,943	4,171,999
Other Assets:
American Falls and Milner water rights	7,641	9,487
Company-owned life insurance	58,973	57,553
Regulatory assets	1,412,086	1,409,329
Long-term receivables	26,367	23,482
Other	51,293	52,571
Total other assets	1,556,360	1,552,422
Total	6,367,183	6,289,897
Current Liabilities:
Current maturities of long-term debt	0	1,064
Notes payable	2,425	21,800
Accounts payable	72,153	106,194
Taxes accrued	57,902	11,348
Interest accrued	21,406	22,377
Accrued compensation	39,903	45,787
Current regulatory liabilities	2,296	9,944
Advances from customers	20,607	21,438
Other	9,100	9,763
Total current liabilities	225,792	249,715
Other Liabilities:
Deferred income taxes	1,241,091	1,244,250
Regulatory liabilities	466,162	436,845
Pension and other postretirement benefits	391,579	411,523
Other	44,651	45,084
Total other liabilities	2,143,483	2,137,702
Long-Term Debt	1,745,746	1,744,614
Commitments and Contingencies
Equity:
Common stock	855,043	851,833
Retained earnings	1,413,387	1,323,198
Accumulated other comprehensive loss	(19,470)	(20,882)
Treasury stock	(1,368)	(243)
Total IDACORP, Inc. shareholders’ equity	2,247,592	2,153,906
Noncontrolling interests	4,570	3,960
Total equity	2,252,162	2,157,866
Total	6,367,183	6,289,897
Idaho Power Company
Current Assets:
Cash and cash equivalents	101,766	44,140
Receivables:
Customer	101,703	71,557
Other	5,294	7,555
Taxes receivable	0	23,334
Accrued unbilled revenues	59,697	80,738
Materials and supplies (at average cost)	58,472	57,858
Fuel stock (at average cost)	54,093	53,698
Prepayments	16,362	18,270
Current regulatory assets	52,927	62,570
Other	101	5,962
Total current assets	450,415	425,682
Investments	94,497	107,379
Property, Plant and Equipment:
Utility plant in service	5,840,848	5,732,044
Accumulated provision for depreciation	(2,086,119)	(1,988,477)
Utility plant in service - net	3,754,729	3,743,567
Construction work in progress	463,106	405,069
Utility plant held for future use	7,511	7,441
Property, plant and equipment - net	4,225,346	4,156,077
Other Assets:
American Falls and Milner water rights	7,641	9,487
Company-owned life insurance	58,973	57,553
Regulatory assets	1,412,086	1,409,329
Other	72,959	71,237
Total other assets	1,551,659	1,547,606
Total	6,321,917	6,236,744
Current Liabilities:
Current maturities of long-term debt	0	1,064
Notes payable	0	21,800
Accounts payable	71,951	105,846
Accounts payable to affiliates	48,329	1,056
Taxes accrued	23,981	11,348
Interest accrued	21,406	22,377
Accrued compensation	39,744	45,622
Current regulatory liabilities	2,296	9,944
Advances from customers	20,607	21,438
Other	8,568	9,103
Total current liabilities	236,882	249,598
Other Liabilities:
Deferred income taxes	1,351,966	1,351,415
Regulatory liabilities	466,162	436,845
Pension and other postretirement benefits	391,579	411,523
Other	43,752	44,046
Total other liabilities	2,253,459	2,243,829
Long-Term Debt	1,745,746	1,744,614
Commitments and Contingencies
Equity:
Common stock	97,877	97,877
Premium on capital stock	712,258	712,258
Capital stock expense	(2,097)	(2,097)
Retained earnings	1,297,262	1,211,547
Accumulated other comprehensive loss	(19,470)	(20,882)
Total equity	2,085,830	1,998,703
Total capitalization	3,831,576	3,743,317
Total	$ 6,321,917	$ 6,236,744

XML

Condensed Consolidated Balance Sheets (Parenthetical) (Parentheticals) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Allowance for Doubtful Accounts Receivable, Current	$ 1,195	$ 968
Allowance for Doubtful Other Receivables, Current	146	164
Allowance for Doubtful Accounts Receivable, Noncurrent	$ 402	$ 402
Common Stock, No Par Value
Common Stock, Shares Authorized	120,000,000	120,000,000
Common Stock, Shares, Issued	50,420,017	50,420,017
Treasury Stock, Shares	26,979	23,244
Idaho Power Company
Allowance for Doubtful Accounts Receivable, Current	$ 1,195	$ 968
Allowance for Doubtful Other Receivables, Current	$ 146	$ 164
Common Stock, Par or Stated Value Per Share	$ 2.50	$ 2.50
Common Stock, Shares Authorized	50,000,000	50,000,000
Common Stock, Shares, Issued	39,150,812	39,150,812

XML

Condensed Consolidated Statements of Cash Flows - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Operating Activities:
Net Income	$ 174,177	$ 164,934
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	125,051	110,161
Deferred income taxes and investment tax credits	(195)	30,077
Changes in regulatory assets and liabilities	61,968	13,502
Pension and postretirement benefit plan expense	21,687	22,175
Contributions to pension and postretirement benefit plans	(45,158)	(43,851)
Earnings of unconsolidated equity-method investments	(7,269)	(13,650)
Distributions from unconsolidated equity-method investments	18,350	17,114
Allowance for equity funds used during construction	(16,555)	(16,153)
Other non-cash adjustments to net income, net	5,220	3,876
Change in:
Accounts receivable	(20,520)	(12,435)
Accounts payable and other accrued liabilities	(32,494)	(10,033)
Taxes accrued/receivable	54,687	8,490
Other current assets	18,736	7,343
Other current liabilities	(3,010)	(5,451)
Other assets	(5,357)	(1,277)
Other liabilities	(494)	595
Net cash provided by operating activities	348,824	275,417
Investing Activities:
Additions to property, plant and equipment	(207,340)	(199,966)
Payments received from transmission project joint funding partners	5,934	6,853
Proceeds from the sale of emission allowances and renewable energy certificates	1,892	969
Purchase of available-for-sale securities	(3,248)	(9,843)
Proceeds from the sale of available-for-sale securities	3,755	14,453
Purchase of Life Insurance Investment	0	(10,000)
Other	183	(9)
Net cash used in investing activities	(198,824)	(197,543)
Financing Activities:
Issuance of long-term debt	0	120,000
Retirement of long-term debt	(1,064)	(101,064)
Dividends on common stock	(83,441)	(77,350)
Net change in short-term borrowings	(19,375)	(14,600)
Acquisition of treasury stock	(3,189)	(3,287)
Make-whole premium on retirement of long-term debt	0	(13,895)
Other	0	(1,684)
Net cash used in financing activities	(107,069)	(91,880)
Net increase (decrease) in cash and cash equivalents	42,931	(14,006)
Cash and cash equivalents at beginning of the period	61,480	114,802
Cash and cash equivalents at end of the period	104,411	100,796
Supplemental Disclosure of Cash Flow Information:
Income taxes	1,702	2,187
Interest (net of amount capitalized)	60,257	60,224
Non-cash investing activities:
Additions to property, plant and equipment in accounts payable	23,502	21,583
Idaho Power Company
Operating Activities:
Net Income	169,192	160,370
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	124,599	109,704
Deferred income taxes and investment tax credits	1,972	12,679
Changes in regulatory assets and liabilities	61,965	13,502
Pension and postretirement benefit plan expense	21,704	22,191
Contributions to pension and postretirement benefit plans	(45,174)	(43,867)
Earnings of unconsolidated equity-method investments	(5,068)	(11,528)
Distributions from unconsolidated equity-method investments	17,500	16,264
Allowance for equity funds used during construction	(16,555)	(16,153)
Other non-cash adjustments to net income, net	12	(571)
Change in:
Accounts receivable	(27,369)	(12,319)
Accounts payable and other accrued liabilities	14,155	(10,016)
Taxes accrued/receivable	35,967	8,172
Other current assets	18,732	7,326
Other current liabilities	(3,004)	(5,451)
Other assets	(5,358)	(1,277)
Other liabilities	(354)	789
Net cash provided by operating activities	362,916	249,815
Investing Activities:
Additions to property, plant and equipment	(207,327)	(199,964)
Payments received from transmission project joint funding partners	5,934	6,853
Proceeds from the sale of emission allowances and renewable energy certificates	1,892	969
Purchase of available-for-sale securities	(3,248)	(9,843)
Proceeds from the sale of available-for-sale securities	3,755	14,453
Purchase of Life Insurance Investment	0	(10,000)
Other	46	(108)
Net cash used in investing activities	(198,948)	(197,640)
Financing Activities:
Issuance of long-term debt	0	120,000
Retirement of long-term debt	(1,064)	(101,064)
Dividends on common stock	(83,478)	(77,365)
Net change in short-term borrowings	(21,800)	0
Make-whole premium on retirement of long-term debt	0	(13,895)
Other	0	(1,671)
Net cash used in financing activities	(106,342)	(73,995)
Net increase (decrease) in cash and cash equivalents	57,626	(21,820)
Cash and cash equivalents at beginning of the period	44,140	110,756
Cash and cash equivalents at end of the period	101,766	88,936
Supplemental Disclosure of Cash Flow Information:
Income taxes	(27,556)	19,796
Interest (net of amount capitalized)	60,208	60,034
Non-cash investing activities:
Additions to property, plant and equipment in accounts payable	$ 23,502	$ 21,583

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Condensed Consolidated Statements of Equity $ in Thousands	USD ($)
Balance at beginning of period at Dec. 31, 2015	$ 849,112
Common Stock
Other common stock changes	1,352
Balance at end of period at Sep. 30, 2016	850,698
Balance at beginning of period at Dec. 31, 2015	1,230,105
Retained Earnings
Net Income Attributable to IDACORP, Inc.	165,075
Common stock dividends	(77,214)
Balance at end of period at Sep. 30, 2016	1,317,732
AOCI - Beginning Balance at Dec. 31, 2015	(21,276)
Accumulated Other Comprehensive (Loss) Income
Unfunded pension liability adjustment, net of tax	1,690
AOCI - Ending Balance at Sep. 30, 2016	(19,586)
Balance at beginning of period at Dec. 31, 2015	(57)
Treasury Stock
Issued	3,143
Acquired	(3,287)
Balance at end of period at Sep. 30, 2016	(201)
Balance at beginning of period at Dec. 31, 2015	4,160
Noncontrolling Interests
Adjustment for (income) loss attributable to noncontrolling interests	(141)
Balance at end of period at Sep. 30, 2016	4,019
Balance at end of period at Sep. 30, 2016	850,698
Retained Earnings
Net Income Attributable to IDACORP, Inc.	83,100
Balance at end of period at Sep. 30, 2016	1,317,732
Accumulated Other Comprehensive (Loss) Income
Unfunded pension liability adjustment, net of tax	563
AOCI - Ending Balance at Sep. 30, 2016	(19,586)
Balance at end of period at Sep. 30, 2016	(201)
Noncontrolling Interests
Adjustment for (income) loss attributable to noncontrolling interests	(83)
Balance at end of period at Sep. 30, 2016	4,019
Common Stock
Cumulative Effect of New Accounting Principle ASU 2016-09 in Period of Adoption	234
Treasury Stock
Total IDACORP, Inc. shareholders’ equity at end of period	2,148,643
Noncontrolling Interests
Total equity at end of period	2,152,662
Total IDACORP, Inc. shareholders’ equity at end of period	2,153,906
Total equity at end of period	2,157,866
Balance at beginning of period at Dec. 31, 2016	851,833
Common Stock
Other common stock changes	3,210
Balance at end of period at Sep. 30, 2017	855,043
Balance at beginning of period at Dec. 31, 2016	1,323,198
Retained Earnings
Net Income Attributable to IDACORP, Inc.	173,567
Common stock dividends	(83,378)
Balance at end of period at Sep. 30, 2017	1,413,387
AOCI - Beginning Balance at Dec. 31, 2016	(20,882)
Accumulated Other Comprehensive (Loss) Income
Unfunded pension liability adjustment, net of tax	1,412
AOCI - Ending Balance at Sep. 30, 2017	(19,470)
Balance at beginning of period at Dec. 31, 2016	(243)
Treasury Stock
Issued	2,063
Acquired	(3,188)
Balance at end of period at Sep. 30, 2017	(1,368)
Balance at beginning of period at Dec. 31, 2016	3,960
Noncontrolling Interests
Adjustment for (income) loss attributable to noncontrolling interests	610
Balance at end of period at Sep. 30, 2017	4,570
Balance at end of period at Sep. 30, 2017	855,043
Retained Earnings
Net Income Attributable to IDACORP, Inc.	90,634
Balance at end of period at Sep. 30, 2017	1,413,387
Accumulated Other Comprehensive (Loss) Income
Unfunded pension liability adjustment, net of tax	471
AOCI - Ending Balance at Sep. 30, 2017	(19,470)
Balance at end of period at Sep. 30, 2017	(1,368)
Noncontrolling Interests
Adjustment for (income) loss attributable to noncontrolling interests	442
Balance at end of period at Sep. 30, 2017	4,570
Common Stock
Cumulative Effect of New Accounting Principle ASU 2016-09 in Period of Adoption	0
Treasury Stock
Total IDACORP, Inc. shareholders’ equity at end of period	2,247,592
Noncontrolling Interests
Total equity at end of period	$ 2,252,162

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Condensed Consolidated Statements of Equity (Parenthetical) (Parentheticals) - $ / shares	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Dividends Declared Per Share of Common Stock	$ 0.55	$ 0.51	$ 1.65	$ 1.53

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

9 Months Ended

Sep. 30, 2017

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

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 significant other wholly-owned subsidiaries include IDACORP Financial Services, Inc. (IFS), an investor in affordable housing and other real estate investments, and 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).

Regulation of Utility Operations

As a regulated utility, many of Idaho Power's fundamental business decisions are subject to the approval of governmental agencies, including the prices that Idaho Power is authorized to charge for its electric service. These approvals are a critical factor in determining IDACORP's and Idaho Power's results of operations and financial condition.

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 or accrued 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, 2017, consolidated results of operations for the three and nine months endedSeptember 30, 2017 and 2016, and consolidated cash flows for the nine months endedSeptember 30, 2017 and 2016. 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, 2016. The results of operations for the interim period are not necessarily indicative of the results to be expected for the full year. A change in management's estimates or assumptions could have a material impact on IDACORP's or Idaho Power's respective financial condition and results of operations during the period in which such change occurred.

Management Estimates

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

Reclassifications

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

New and Recently Adopted Accounting Pronouncements

Recent Accounting Pronouncements Not Yet Adopted

In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2014-09, Revenue from Contracts with Customers (Topic 606). ASU 2014-09 is intended to enable users of financial statements to better understand and consistently analyze an entity's revenue across industries, transactions, and geographies. Under the ASU, recognition of revenue occurs when a customer obtains control of promised goods or services. In addition, the ASU requires disclosure of the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The 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 companies have assessed the impacts of ASU 2014-09 on their financial statements and do not expect the new guidance to affect the timing and amount of revenue recognized. However, the presentation and disclosure requirements of the standard will result in a change in the presentation of revenue on the companies' consolidated statements of income as well as expanded disclosures around the disaggregation of revenue. The guidance in ASU 2014-09 is effective for interim and annual reporting periods beginning after December 15, 2017. The guidance permits two implementation approaches, one requiring retrospective application of the new standard with restatement of prior years (full retrospective approach) and the other requiring prospective application of the new standard including a cumulative-effect adjustment with disclosure of results under previous standards (modified-retrospective approach). IDACORP and Idaho Power plan to adopt ASU 2014-09 on January 1, 2018, using the modified-retrospective approach.

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), intended to improve financial reporting on 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 are classified as operating leases and are not recognized on the balance sheet. The new standard is effective for interim and annual reporting periods beginning after December 15, 2018, 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. 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 arrangements. At this time, the companies do not know, and cannot reasonably estimate, the dollar impact of the adoption.

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 and related costs, which will be classified as investing activities under the new guidance. The companies already present debt prepayment and extinguishment costs, proceeds from the settlement of insurance claims (other than corporate-owned life insurance), and distributions received from equity-method investments in accordance with the new guidance. ASU 2016-15 is effective for interim and annual reporting periods beginning after December 15, 2017. The standard must be adopted retrospectively to all periods presented, unless impracticable to do so. At this time, IDACORP and Idaho Power do not believe the adoption will have a material impact on their financial statements.

In March 2017, the FASB issued ASU 2017-07, Compensation -- Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, which requires employers to disaggregate the service cost component from other components of net periodic benefit costs and to disclose the amounts of net periodic benefit costs that are included in each income statement line item. The standard requires employers to present the service cost component in the same line item as other compensation costs and to present the other components of net periodic benefit costs (which include interest costs, expected return on plan assets, amortization of prior service cost or credits and actuarial gains and losses) separately and outside a subtotal of operating income. In addition, only the service cost component is eligible for capitalization. Idaho Power currently capitalizes amounts of pension or postretirement costs that are insignificant to the consolidated financial statements. The amendments in ASU 2017-07 are effective for interim and annual reporting periods beginning after December 15, 2017. Entities must use (1) a retrospective transition method to adopt the requirement for separate presentation in the income statement of service costs and other components and (2) a prospective transition method to adopt the requirement to limit the capitalization of benefit costs to the service cost component. IDACORP and Idaho Power are evaluating the impact of ASU 2017-07 on their financial statements.

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INCOME TAXES:

9 Months Ended

Sep. 30, 2017

Income Tax Disclosure [Abstract]

Income Taxes

INCOME TAXES

In accordance with interim reporting requirements, IDACORP and Idaho Power use an estimated annual effective tax rate for computing their provisions for income taxes. An estimate of annual income tax expense (or benefit) is made each interim period using estimates for annual pre-tax income, income tax adjustments, and tax credits. The estimated annual effective tax rates do not include discrete events such as tax law changes, examination settlements, accounting method changes, or adjustments to tax expense or benefits attributable to prior years. Discrete events are recorded in the interim period in which they occur or become known. The estimated annual effective tax rate is applied to year-to-date pre-tax income to determine income tax expense (or benefit) for the interim period consistent with the annual estimate. In subsequent interim periods, income tax expense (or benefit) for the period is computed as the difference between the year-to-date amount reported for the previous interim period and the current period's year-to-date amount.

Income Tax Expense

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

	IDACORP						Idaho Power
	2017			2016			2017			2016
Income tax at statutory rates (federal and state)	$	85,624		$	75,736		$	84,278		$	74,864
Additional accumulated deferred investment tax credits (ADITC) amortization	—			(1,500		)	—			(1,500		)
First mortgage bond redemption costs	—			(5,583		)	—			(5,583		)
Share-based compensation	(1,587		)	(1,754		)	(1,558		)	(1,720		)
Other(1)	(38,617		)	(38,277		)	(36,367		)	(34,964		)
Income tax expense	$	45,420		$	28,622		$	46,353		$	31,097
Effective tax rate	20.7		%	14.8		%	21.5		%	16.2		%

⁽¹⁾ "Other" is primarily comprised of the net tax effect of Idaho Power's regulatory flow-through tax adjustments. These adjustments 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, 2016.

The increases in income tax expense for the nine months endedSeptember 30, 2017, compared with the same period in 2016, were primarily due to greater pre-tax income, the flow-through income tax benefit related to the tax deduction for bond redemption costs incurred in the second quarter of 2016, and tax benefits from distributions from fully-amortized affordable housing investments that were recorded in the third quarter of 2016. On a net basis, Idaho Power’s estimate of its annual 2017 regulatory flow-through tax adjustments is comparable to 2016.

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REGULATORY MATTERS:

9 Months Ended

Sep. 30, 2017

Public Utilities, Rate Matters [Abstract]

Regulatory Matters

REGULATORY MATTERS

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

Idaho and Oregon General Rate Cases and Base Rate Adjustments

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

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

Idaho and Oregon base rates were subsequently adjusted again in 2012, in connection with Idaho Power's completion of the Langley Gulch power plant. In June 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. In September 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.

In March 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 Idaho power cost adjustment (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 PCA mechanism and instead results in collecting that portion through base rates.

Idaho Settlement Stipulation — Investment Tax Credits and Sharing Mechanism

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

• If Idaho Power's annual return on year-end equity in the Idaho jurisdiction (Idaho ROE) in any year is less than 9.5 percent, then Idaho Power may record additional ADITC amortization up to $25 million to help achieve a 9.5 percent Idaho ROE for that year, and may record additional ADITC amortization up to a total of $45 million 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 PCA 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 PCA, 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 amortization contemplated by the settlement stipulation has been recorded 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 no additional ADITC amortization during the first nine months of 2017, based on Idaho Power's estimate of Idaho ROE for the full-year 2017. During the first nine months of 2016, Idaho Power recorded $1.5 million of additional ADITC amortization, which was reversed later in 2016 as actual financial results exceeded Idaho Power's early estimates.

Valmy Rate Base Adjustment Settlement Stipulations

In May 2017, the IPUC approved a settlement stipulation allowing accelerated depreciation and cost recovery for Idaho Power’s jointly-owned North Valmy coal-fired power plant (Valmy Plant). The settlement stipulation provides for an increase in Idaho jurisdictional revenues of $13.3 million per year, and (1) levelized collections and associated cost recovery through December 2028, (2) accelerated depreciation on unit 1 through 2019 and unit 2 through 2025, (3) Idaho Power to use prudent and commercially reasonable efforts to end its participation in the operation of unit 1 by the end of 2019 and unit 2 by the end of 2025, and (4) a filing no later than 2020 that would include actual and planned incremental investments in unit 2, including updated financial analysis regarding the lowest costs options for unit 2. The costs intended to be recovered by the increased revenue requirement include current investments as of May 31, 2017, in both units, forecasted unit 1 investments from 2017 through 2019, and forecasted decommissioning costs for unit 1 and unit 2, offset by forecasted operation and maintenance costs savings. The settlement stipulation also provides for the regulatory deferral of the difference between actual revenue requirements and levelized collections, and provides for the regulatory deferral of the difference between actual costs incurred (including accelerated depreciation expense on unit 1 through 2019 and unit 2 through 2025) compared with costs permitted to be recovered during the cost recovery period specified in the settlement stipulation (including depreciation expense through 2028). If actual costs incurred differ from forecasted amounts included in the settlement stipulation, collection or refund of any differences would be subject to regulatory approval.

In June 2017, the OPUC also approved a settlement stipulation allowing for accelerated depreciation of units 1 and 2 through December 31, 2025, cost recovery of incremental Valmy Plant investments through May 31, 2017, and forecasted decommissioning costs. The settlement stipulation provides for an increase in the Oregon jurisdictional revenue requirement of $1.1 million, effective July 1, 2017, with yearly adjustments to the level of decommissioning cost recovery, if warranted, until decommissioning activities are concluded.

For both the three and nine month periods ended September 30, 2017, the settlement stipulations increased general business revenue collections, general business revenue accruals, net depreciation expense, and income tax expense, including plant-related flow-through tax adjustments. Idaho Power expects the ongoing annual benefit to net income from the Valmy Plant settlement stipulations to decline slightly each year through 2028, primarily due to the annual decline in Valmy Plant-related rate base, which is expected to be fully depreciated by December 31, 2028. Compared with Idaho Power’s estimate of what ongoing net income would have been without the settlement stipulations, the settlement stipulations increased after-tax net income for the first nine months of 2017 by $3.8 million, of which $1.3 million was recorded during the third quarter of 2017.

Depreciation Rate Settlement Stipulations

In May 2017, the IPUC and OPUC approved settlement stipulations related to revised depreciation rates for Idaho Power's electric plant in service other than the Valmy Plant, and adjusted base rates in Oregon to reflect the revised depreciation rates applied to electric plant-in-service based on balances from the most recent general rate case. These settlement stipulations provided for new depreciation rates to go into effect on June 1, 2017, with no significant resulting increase in revenue.

Idaho Power Cost Adjustment Mechanisms

In both its Idaho and Oregon jurisdictions, Idaho Power's power cost adjustment mechanisms address the volatility of power supply costs and provide for annual adjustments to the rates charged to its retail customers. The power cost adjustment 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 power cost adjustment 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 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 31, 2017, the IPUC issued an order approving a $10.6 million net increase in PCA rates, effective for the 2017-2018 PCA collection period from June 1, 2017, to May 31, 2018. The net increase in PCA rates was primarily due to expected higher power supply costs resulting from new PURPA power purchase agreements and higher coal-fired generation costs, combined with the effect of lower-than-expected actual hydroelectric generation for the 2016-2017 PCA year.  The net increase includes an offsetting $13.0 million refund of previously collected Idaho energy efficiency rider funds. Previously, in May 2016, the IPUC issued an order approving a $17.3 million net increase in PCA rates, effective for the 2016-2017 PCA collection period from June 1, 2016, to May 31, 2017. The net increase in 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.

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 31, 2017, the IPUC issued an order approving Idaho Power's application requesting an increase of $6.9 million in the FCA from $28.1 million to $35.0 million, with new requested rates effective for the period from June 1, 2017, to May 31, 2018. Previously in May 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, to May 31, 2017.

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NOTES PAYABLE:

9 Months Ended

Sep. 30, 2017

Debt Disclosure [Abstract]

Notes Payable

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, 2016. At September 30, 2017, no loans were outstanding under either IDACORP's or Idaho Power's credit facilities. At September 30, 2017, 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) and interest rates of IDACORP’s and Idaho Power's short-term borrowings were as follows at September 30, 2017, and December 31, 2016:

	September 30, 2017									December 31, 2016
	IDACORP			Idaho Power			Total			IDACORP			Idaho Power			Total
Commercial paper outstanding	$	2,425		$	—		$	2,425		$	—		$	21,800		$	21,800
Weighted-average annual interest rate	1.54		%	—		%	1.54		%	—		%	1.13		%	1.13		%

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COMMON STOCK:

9 Months Ended

Sep. 30, 2017

Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract]

Common Stock

COMMON STOCK

IDACORP Common Stock

During the nine months endedSeptember 30, 2017, IDACORP granted 72,397 restricted stock unit awards to employees and 12,050 shares of common stock to directors but made no original issuances of shares of common stock pursuant to the IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan. As directed by IDACORP, plan administrators of the IDACORP, Inc. Dividend Reinvestment and Stock Purchase Plan and Idaho Power Company Employee Savings Plan 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 use 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, 2017, the leverage ratios for IDACORP and Idaho Power were 44 percent and 46 percent, respectively. Based on these restrictions, IDACORP’s and Idaho Power’s dividends were limited to $1.3 billion and $1.1 billion, respectively, at September 30, 2017. 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, 2017, 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, 2017, Idaho Power's common equity capital was 54 percent of its total adjusted capital. Further, Idaho Power must obtain approval of the OPUC before it can 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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EARNINGS PER SHARE:

9 Months Ended

Sep. 30, 2017

Earnings Per Share [Abstract]

Earnings Per Share

EARNINGS PER SHARE

The table below presents the computation of IDACORP’s basic and diluted earnings per share for the three and nine months endedSeptember 30, 2017 and 2016 (in thousands, except for per share amounts).

	Three months ended September 30,				Nine months ended September 30,
	2017		2016		2017		2016
Numerator:
Net income attributable to IDACORP, Inc.	$	90,634	$	83,100	$	173,567	$	165,075
Denominator:
Weighted-average common shares outstanding - basic	50,362		50,296		50,361		50,299
Effect of dilutive securities	59		97		47		62
Weighted-average common shares outstanding - diluted	50,421		50,393		50,408		50,361
Basic earnings per share	$	1.80	$	1.65	$	3.45	$	3.28
Diluted earnings per share	$	1.80	$	1.65	$	3.44	$	3.28

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COMMITMENTS:

9 Months Ended

Sep. 30, 2017

Disclosure Text Block Supplement [Abstract]

Commitments

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 endedSeptember 30, 2017, except that Idaho Power entered into agreements with solar, biomass, and hydroelectric PURPA-qualifying facilities which increased contractual payment obligations by approximately $85 million over the 20-year terms of the 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 $57 million at September 30, 2017, 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, 2017, the total value of BCC's reclamation trust fund was $97 million. During the nine months endedSeptember 30, 2017, the reclamation trust fund made no distributions 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, and does, add a per-ton surcharge to coal sales, all of which are made to the Jim Bridger plant. 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, 2017, management believes the likelihood is remote that IDACORP or Idaho Power would be required to perform under such indemnification provisions or otherwise incur any significant losses with respect to such indemnification obligations. Neither IDACORP nor Idaho Power has recorded any liability on their respective condensed consolidated balance sheets with respect to these indemnification obligations.

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CONTINGENCIES:

9 Months Ended

Sep. 30, 2017

Loss Contingency [Abstract]

Contingencies

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, some of which involve litigation and regulatory or other contested proceedings. The ultimate resolution and outcome of litigation and regulatory proceedings is inherently difficult to determine, particularly where (a) the remedies or penalties sought are indeterminate, (b) the proceedings are in the early stages or the substantive issues have not been well developed, or (c) the matters involve complex or novel legal theories or a large number of parties. In accordance with applicable accounting guidance, IDACORP and Idaho Power, as applicable, establish an accrual for legal proceedings when those matters proceed to a stage where they present loss contingencies that are both probable and reasonably estimable. 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.

IDACORP and Idaho Power are parties to legal claims and legal and regulatory actions and proceedings in the ordinary course of business and, as noted above, record an accrual for associated loss contingencies when they are probable and reasonably estimable. As of the date of this report, the companies believe that resolution of those matters will not have a material adverse effect on their respective consolidated financial statements. Idaho Power is also actively monitoring various pending environmental regulations and the recently issued executive orders related to environmental matters 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.

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BENEFIT PLANS:

9 Months Ended

Sep. 30, 2017

Retirement Benefits, Description [Abstract]

Benefit Plans

BENEFIT PLANS

Idaho Power has 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, 2017 and 2016 (in thousands).

	Pension Plan						SMSP				Postretirement Benefits
	2017			2016			2017		2016		2017			2016
Service cost	$	8,436		$	8,004		$	189	$	307	$	244		$	279
Interest cost	9,739			9,453			1,079		1,069		695			692
Expected return on plan assets	(11,285		)	(10,519		)	—		—		(576		)	(619		)
Amortization of prior service cost	7			15			31		42		11			7
Amortization of net loss	3,298			3,332			742		883		—			—
Net periodic benefit cost	10,195			10,285			2,041		2,301		374			359
Regulatory deferral of net periodic benefit cost(1)	(9,708		)	(9,826		)	—		—		—			—
Previously deferred pension costs recognized(1)	4,288			4,288			—		—		—			—
Net periodic benefit cost recognized for financial reporting(1)	$	4,775		$	4,747		$	2,041	$	2,301	$	374		$	359

⁽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, the Idaho portion of net periodic benefit cost is recorded as a regulatory asset and is recognized in the income statement as those 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, 2017 and 2016 (in thousands of dollars).

	Pension Plan						SMSP				Postretirement Benefits
	2017			2016			2017		2016		2017			2016
Service cost	$	25,307		$	24,014		$	569	$	921	$	730		$	837
Interest cost	29,217			28,360			3,236		3,206		2,087			2,075
Expected return on plan assets	(33,854		)	(31,560		)	—		—		(1,730		)	(1,856		)
Amortization of prior service cost	21			44			95		126		35			20
Amortization of net loss	9,893			9,998			2,223		2,649		—			—
Net periodic benefit cost	30,584			30,856			6,123		6,902		1,122			1,076
Regulatory deferral of net periodic benefit cost(1)	(28,991		)	(29,508		)	—		—		—			—
Previously deferred pension costs recognized(1)	12,865			12,865			—		—		—			—
Net periodic benefit cost recognized for financial reporting(1)	$	14,458		$	14,213		$	6,123	$	6,902	$	1,122		$	1,076

⁽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, the Idaho portion of net periodic benefit cost is recorded as a regulatory asset and is recognized in the income statement as those costs are recovered through rates.

Idaho Power has no minimum contribution requirement to its defined benefit pension plan in 2017. However, during the nine months ended September 30, 2017, Idaho Power made $40 million of discretionary contributions to its defined benefit pension plan, 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.

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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DERIVATIVE FINANCIAL INSTRUMENTS:

9 Months Ended

Sep. 30, 2017

General Discussion of Derivative Instruments and Hedging Activities [Abstract]

Derivative Financial Instruments

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 endedSeptember 30, 2017 and 2016 (in thousands).

		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,
		2017			2016			2017			2016
Financial swaps	Off-system sales	$	(309	)	$	(16	)	$	864		$	1,379
Financial swaps	Purchased power	904			710			169			861
Financial swaps	Fuel expense	883			(657		)	1,549			(3,099		)
Financial swaps	Other operations and maintenance	(45		)	(16		)	(126		)	(166		)
Forward contracts	Purchased power	(3		)	24			(13		)	24
Forward contracts	Fuel expense	—			49			3			139

⁽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 11 for additional information concerning the determination of fair value for Idaho Power’s assets and liabilities from price risk management activities.

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, 2017, and December 31, 2016 (in thousands).

		Asset Derivatives								Liability Derivatives
	Balance Sheet Location	Gross Fair Value		Amounts Offset				Net Assets		Gross Fair Value		Amounts Offset				Net Liabilities
September 30, 2017
Current:
Financial swaps	Other current assets	$	332	$	(234	)		$	98	$	234	$	(234	)		$	—
Financial swaps	Other current liabilities	140		(140		)		—		919		(140		)		779
Forward contracts	Other current assets	3		—				3		—		—				—
Long-term:
Financial swaps	Other assets	38		(3		)		35		3		(3		)		—
Financial swaps	Other liabilities	15		(15		)		—		127		(90		)	(1)	37
Total		$	528	$	(392	)		$	136	$	1,283	$	(467	)		$	816
December 31, 2016
Current:
Financial swaps	Other current assets	$	8,134	$	(2,183	)	(2)	$	5,951	$	302	$	(302	)		$	—
Total		$	8,134	$	(2,183	)		$	5,951	$	302	$	(302	)		$	—

⁽¹⁾ Long-term liability derivative amount offset includes $0.1 million of collateral receivable for the period ended September 30, 2017.

⁽²⁾ Current asset derivative amount offset includes $1.9 million of collateral payable for the period ended December 31, 2016.

The table below presents the volumes of derivative commodity forward contracts and swaps outstanding at September 30, 2017 and 2016 (in thousands of units).

		September 30,
Commodity	Units	2017	2016
Electricity purchases	MWh	122	130
Electricity sales	MWh	162	143
Natural gas purchases	MMBtu	7,975	7,977
Natural gas sales	MMBtu	230	70
Diesel purchases	Gallons	304	267

Credit Risk

At September 30, 2017, 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 Idaho Power derivative instruments contain provisions that require Idaho Power's unsecured debt to maintain an investment grade credit rating from Moody's Investors Service and Standard & Poor's Ratings Services. If Idaho Power's unsecured debt were to fall below investment grade, it would be in violation of these provisions, and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions. The aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a liability position at September 30, 2017 was $1.3 million. Idaho Power posted $0.4 million cash collateral related to this amount. If the credit-risk-related contingent features underlying these agreements were triggered on September 30, 2017, Idaho Power would have been required to pay or post collateral to its counterparties up to an additional $4.7 million to cover the open liability positions as well as completed transactions that have not yet been paid.

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FAIR VALUE MEASUREMENTS:

9 Months Ended

Sep. 30, 2017

Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]

Fair Value Measurements

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 have 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 endedSeptember 30, 2017.

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, 2017, and December 31, 2016 (in thousands).

	September 30, 2017								December 31, 2016
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets:
Money market funds
IDACORP	$	—	$	—	$	—	$	—	$	15,000	$	—	$	—	$	15,000
Idaho Power	45,495		—		—		45,495		29,967		—		—		29,967
Derivatives	133		3		—		136		5,951		—		—		5,951
Trading securities: Equity securities	84		—		—		84		111		—		—		111
Available-for-sale securities: Equity securities	23,475		—		—		23,475		23,908		—		—		23,908
Liabilities:
Derivatives	816		—		—		816		—		—		—		—

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, 2017, and December 31, 2016, using available market information and appropriate valuation methodologies (in thousands).

	September 30, 2017				December 31, 2016
	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)	1,745,746		1,906,113		1,745,678		1,858,666
Idaho Power
Liabilities:
Long-term debt(1)	1,745,746		1,906,113		1,745,678		1,858,666

⁽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 11.

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.

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SEGMENT INFORMATION:

9 Months Ended

Sep. 30, 2017

Segment Reporting, Measurement Disclosures [Abstract]

Segment Information

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, and IDACORP’s holding company expenses.

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

	Utility Operations		All Other		Eliminations			Consolidated Total
Three months ended September 30, 2017:
Revenues	$	406,655	$	1,669	$	—		$	408,324
Net income attributable to IDACORP, Inc.	88,329		2,305		—			90,634
Total assets as of September 30, 2017	6,321,917		116,718		(71,452		)	6,367,183
Three months ended September 30, 2016:
Revenues	$	371,474	$	571	$	—		$	372,045
Net income attributable to IDACORP, Inc.	80,029		3,071		—			83,100
Nine months ended September 30, 2017:
Revenues	$	1,040,387	$	3,487	$	—		$	1,043,874
Net income attributable to IDACORP, Inc.	169,192		4,375		—			173,567
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

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CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME: CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME:

9 Months Ended

Sep. 30, 2017

Statement of Comprehensive Income [Abstract]

Changes in Accumulated Other Comprehensive Income [Text Block]

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 endedSeptember 30, 2017 and 2016 (in thousands). Items in parentheses indicate charges to AOCI.

	Defined Benefit Pension Items
	Three months ended September 30,						Nine months ended September 30,
	2017			2016			2017			2016
Balance at beginning of period	$	(19,941	)	$	(20,149	)	$	(20,882	)	$	(21,276	)
Amounts reclassified out of AOCI	471			563			1,412			1,690
Balance at end of period	$	(19,470	)	$	(19,586	)	$	(19,470	)	$	(19,586	)

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 endedSeptember 30, 2017 and 2016 (in thousands). 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,
	2017			2016			2017			2016
Amortization of defined benefit pension items(1)
Prior service cost	$	31		$	42		$	95		$	126
Net loss	742			883			2,223			2,649
Total before tax	773			925			2,318			2,775
Tax benefit(2)	(302		)	(362		)	(906		)	(1,085		)
Net of tax	471			563			1,412			1,690
Total reclassification for the period	$	471		$	563		$	1,412		$	1,690

⁽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 statements of income in other expense, net.

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

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: Organization, Consolidation, Presentation, and Significant Accounting Policies (Policies)

9 Months Ended

Sep. 30, 2017

Accounting Policies [Abstract]

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 significant other wholly-owned subsidiaries include IDACORP Financial Services, Inc. (IFS), an investor in affordable housing and other real estate investments, and 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).

Regulation of Utility Operations

As a regulated utility, many of Idaho Power's fundamental business decisions are subject to the approval of governmental agencies, including the prices that Idaho Power is authorized to charge for its electric service. These approvals are a critical factor in determining IDACORP's and Idaho Power's results of operations and financial condition.

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 or accrued 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, 2017, consolidated results of operations for the three and nine months endedSeptember 30, 2017 and 2016, and consolidated cash flows for the nine months endedSeptember 30, 2017 and 2016. 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, 2016. The results of operations for the interim period are not necessarily indicative of the results to be expected for the full year. A change in management's estimates or assumptions could have a material impact on IDACORP's or Idaho Power's respective financial condition and results of operations during the period in which such change occurred.

Management Estimates

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

Reclassification

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

Income Tax

In accordance with interim reporting requirements, IDACORP and Idaho Power use an estimated annual effective tax rate for computing their provisions for income taxes. An estimate of annual income tax expense (or benefit) is made each interim period using estimates for annual pre-tax income, income tax adjustments, and tax credits. The estimated annual effective tax rates do not include discrete events such as tax law changes, examination settlements, accounting method changes, or adjustments to tax expense or benefits attributable to prior years. Discrete events are recorded in the interim period in which they occur or become known. The estimated annual effective tax rate is applied to year-to-date pre-tax income to determine income tax expense (or benefit) for the interim period consistent with the annual estimate. In subsequent interim periods, income tax expense (or benefit) for the period is computed as the difference between the year-to-date amount reported for the previous interim period and the current period's year-to-date amount.

Fair Value of Financial Instruments

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 have 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.

New Accounting Pronouncements

Recent Accounting Pronouncements Not Yet Adopted

In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2014-09, Revenue from Contracts with Customers (Topic 606). ASU 2014-09 is intended to enable users of financial statements to better understand and consistently analyze an entity's revenue across industries, transactions, and geographies. Under the ASU, recognition of revenue occurs when a customer obtains control of promised goods or services. In addition, the ASU requires disclosure of the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The 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 companies have assessed the impacts of ASU 2014-09 on their financial statements and do not expect the new guidance to affect the timing and amount of revenue recognized. However, the presentation and disclosure requirements of the standard will result in a change in the presentation of revenue on the companies' consolidated statements of income as well as expanded disclosures around the disaggregation of revenue. The guidance in ASU 2014-09 is effective for interim and annual reporting periods beginning after December 15, 2017. The guidance permits two implementation approaches, one requiring retrospective application of the new standard with restatement of prior years (full retrospective approach) and the other requiring prospective application of the new standard including a cumulative-effect adjustment with disclosure of results under previous standards (modified-retrospective approach). IDACORP and Idaho Power plan to adopt ASU 2014-09 on January 1, 2018, using the modified-retrospective approach.

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), intended to improve financial reporting on 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 are classified as operating leases and are not recognized on the balance sheet. The new standard is effective for interim and annual reporting periods beginning after December 15, 2018, 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. 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 arrangements. At this time, the companies do not know, and cannot reasonably estimate, the dollar impact of the adoption.

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 and related costs, which will be classified as investing activities under the new guidance. The companies already present debt prepayment and extinguishment costs, proceeds from the settlement of insurance claims (other than corporate-owned life insurance), and distributions received from equity-method investments in accordance with the new guidance. ASU 2016-15 is effective for interim and annual reporting periods beginning after December 15, 2017. The standard must be adopted retrospectively to all periods presented, unless impracticable to do so. At this time, IDACORP and Idaho Power do not believe the adoption will have a material impact on their financial statements.

In March 2017, the FASB issued ASU 2017-07, Compensation -- Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, which requires employers to disaggregate the service cost component from other components of net periodic benefit costs and to disclose the amounts of net periodic benefit costs that are included in each income statement line item. The standard requires employers to present the service cost component in the same line item as other compensation costs and to present the other components of net periodic benefit costs (which include interest costs, expected return on plan assets, amortization of prior service cost or credits and actuarial gains and losses) separately and outside a subtotal of operating income. In addition, only the service cost component is eligible for capitalization. Idaho Power currently capitalizes amounts of pension or postretirement costs that are insignificant to the consolidated financial statements. The amendments in ASU 2017-07 are effective for interim and annual reporting periods beginning after December 15, 2017. Entities must use (1) a retrospective transition method to adopt the requirement for separate presentation in the income statement of service costs and other components and (2) a prospective transition method to adopt the requirement to limit the capitalization of benefit costs to the service cost component. IDACORP and Idaho Power are evaluating the impact of ASU 2017-07 on their financial statements.

Derivatives, Methods of Accounting, Derivatives Not Designated or Qualifying as Hedges [Policy Text Block]

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.

Derivatives, Reporting of Derivative Activity

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.

Segment Reporting

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, and IDACORP’s holding company expenses.

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INCOME TAXES: Level 3 (Tables)

9 Months Ended

Sep. 30, 2017

Income Tax Disclosure [Abstract]

Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]

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

	IDACORP						Idaho Power
	2017			2016			2017			2016
Income tax at statutory rates (federal and state)	$	85,624		$	75,736		$	84,278		$	74,864
Additional accumulated deferred investment tax credits (ADITC) amortization	—			(1,500		)	—			(1,500		)
First mortgage bond redemption costs	—			(5,583		)	—			(5,583		)
Share-based compensation	(1,587		)	(1,754		)	(1,558		)	(1,720		)
Other(1)	(38,617		)	(38,277		)	(36,367		)	(34,964		)
Income tax expense	$	45,420		$	28,622		$	46,353		$	31,097
Effective tax rate	20.7		%	14.8		%	21.5		%	16.2		%

⁽¹⁾ "Other" is primarily comprised of the net tax effect of Idaho Power's regulatory flow-through tax adjustments. These adjustments 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, 2016.

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NOTES PAYABLE: Level 3 (Tables)

9 Months Ended

Sep. 30, 2017

Shedule of short term debt [Abstract]

Schedule of Short-term Debt

Balances (in thousands) and interest rates of IDACORP’s and Idaho Power's short-term borrowings were as follows at September 30, 2017, and December 31, 2016:

	September 30, 2017									December 31, 2016
	IDACORP			Idaho Power			Total			IDACORP			Idaho Power			Total
Commercial paper outstanding	$	2,425		$	—		$	2,425		$	—		$	21,800		$	21,800
Weighted-average annual interest rate	1.54		%	—		%	1.54		%	—		%	1.13		%	1.13		%

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EARNINGS PER SHARE: Level 3 (Tables)

9 Months Ended

Sep. 30, 2017

Earnings Per Share, Basic and Diluted [Abstract]

Schedule of Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Table Text Block]

The table below presents the computation of IDACORP’s basic and diluted earnings per share for the three and nine months endedSeptember 30, 2017 and 2016 (in thousands, except for per share amounts).

	Three months ended September 30,				Nine months ended September 30,
	2017		2016		2017		2016
Numerator:
Net income attributable to IDACORP, Inc.	$	90,634	$	83,100	$	173,567	$	165,075
Denominator:
Weighted-average common shares outstanding - basic	50,362		50,296		50,361		50,299
Effect of dilutive securities	59		97		47		62
Weighted-average common shares outstanding - diluted	50,421		50,393		50,408		50,361
Basic earnings per share	$	1.80	$	1.65	$	3.45	$	3.28
Diluted earnings per share	$	1.80	$	1.65	$	3.44	$	3.28

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BENEFIT PLANS: Level 3 (Tables)

9 Months Ended

Sep. 30, 2017

Defined Benefit Plan [Abstract]

Schedule of Defined Benefit Plans Disclosures [Table Text Block]

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, 2017 and 2016 (in thousands).

	Pension Plan						SMSP				Postretirement Benefits
	2017			2016			2017		2016		2017			2016
Service cost	$	8,436		$	8,004		$	189	$	307	$	244		$	279
Interest cost	9,739			9,453			1,079		1,069		695			692
Expected return on plan assets	(11,285		)	(10,519		)	—		—		(576		)	(619		)
Amortization of prior service cost	7			15			31		42		11			7
Amortization of net loss	3,298			3,332			742		883		—			—
Net periodic benefit cost	10,195			10,285			2,041		2,301		374			359
Regulatory deferral of net periodic benefit cost(1)	(9,708		)	(9,826		)	—		—		—			—
Previously deferred pension costs recognized(1)	4,288			4,288			—		—		—			—
Net periodic benefit cost recognized for financial reporting(1)	$	4,775		$	4,747		$	2,041	$	2,301	$	374		$	359

⁽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, the Idaho portion of net periodic benefit cost is recorded as a regulatory asset and is recognized in the income statement as those 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, 2017 and 2016 (in thousands of dollars).

	Pension Plan						SMSP				Postretirement Benefits
	2017			2016			2017		2016		2017			2016
Service cost	$	25,307		$	24,014		$	569	$	921	$	730		$	837
Interest cost	29,217			28,360			3,236		3,206		2,087			2,075
Expected return on plan assets	(33,854		)	(31,560		)	—		—		(1,730		)	(1,856		)
Amortization of prior service cost	21			44			95		126		35			20
Amortization of net loss	9,893			9,998			2,223		2,649		—			—
Net periodic benefit cost	30,584			30,856			6,123		6,902		1,122			1,076
Regulatory deferral of net periodic benefit cost(1)	(28,991		)	(29,508		)	—		—		—			—
Previously deferred pension costs recognized(1)	12,865			12,865			—		—		—			—
Net periodic benefit cost recognized for financial reporting(1)	$	14,458		$	14,213		$	6,123	$	6,902	$	1,122		$	1,076

⁽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, the Idaho portion of net periodic benefit cost is recorded as a regulatory asset and is recognized in the income statement as those costs are recovered through rates.

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DERIVATIVE FINANCIAL INSTRUMENTS: Level 3 (Tables)

9 Months Ended

Sep. 30, 2017

Summary of Derivative Instruments [Abstract]

Schedule of Derivative Instruments, Gain (Loss) in Statement of Financial Performance

The table below presents the gains and losses on derivatives not designated as hedging instruments for the three and nine months endedSeptember 30, 2017 and 2016 (in thousands).

		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,
		2017			2016			2017			2016
Financial swaps	Off-system sales	$	(309	)	$	(16	)	$	864		$	1,379
Financial swaps	Purchased power	904			710			169			861
Financial swaps	Fuel expense	883			(657		)	1,549			(3,099		)
Financial swaps	Other operations and maintenance	(45		)	(16		)	(126		)	(166		)
Forward contracts	Purchased power	(3		)	24			(13		)	24
Forward contracts	Fuel expense	—			49			3			139

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

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value

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, 2017, and December 31, 2016 (in thousands).

		Asset Derivatives								Liability Derivatives
	Balance Sheet Location	Gross Fair Value		Amounts Offset				Net Assets		Gross Fair Value		Amounts Offset				Net Liabilities
September 30, 2017
Current:
Financial swaps	Other current assets	$	332	$	(234	)		$	98	$	234	$	(234	)		$	—
Financial swaps	Other current liabilities	140		(140		)		—		919		(140		)		779
Forward contracts	Other current assets	3		—				3		—		—				—
Long-term:
Financial swaps	Other assets	38		(3		)		35		3		(3		)		—
Financial swaps	Other liabilities	15		(15		)		—		127		(90		)	(1)	37
Total		$	528	$	(392	)		$	136	$	1,283	$	(467	)		$	816
December 31, 2016
Current:
Financial swaps	Other current assets	$	8,134	$	(2,183	)	(2)	$	5,951	$	302	$	(302	)		$	—
Total		$	8,134	$	(2,183	)		$	5,951	$	302	$	(302	)		$	—

⁽¹⁾ Long-term liability derivative amount offset includes $0.1 million of collateral receivable for the period ended September 30, 2017.

⁽²⁾ Current asset derivative amount offset includes $1.9 million of collateral payable for the period ended December 31, 2016.

Schedule of Derivative Instruments

The table below presents the volumes of derivative commodity forward contracts and swaps outstanding at September 30, 2017 and 2016 (in thousands of units).

		September 30,
Commodity	Units	2017	2016
Electricity purchases	MWh	122	130
Electricity sales	MWh	162	143
Natural gas purchases	MMBtu	7,975	7,977
Natural gas sales	MMBtu	230	70
Diesel purchases	Gallons	304	267

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FAIR VALUE MEASUREMENTS: Level 3 (Tables)

9 Months Ended

Sep. 30, 2017

Fair Value Disclosures [Abstract]

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]

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, 2017, and December 31, 2016 (in thousands).

	September 30, 2017								December 31, 2016
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets:
Money market funds
IDACORP	$	—	$	—	$	—	$	—	$	15,000	$	—	$	—	$	15,000
Idaho Power	45,495		—		—		45,495		29,967		—		—		29,967
Derivatives	133		3		—		136		5,951		—		—		5,951
Trading securities: Equity securities	84		—		—		84		111		—		—		111
Available-for-sale securities: Equity securities	23,475		—		—		23,475		23,908		—		—		23,908
Liabilities:
Derivatives	816		—		—		816		—		—		—		—

Fair Value, by Balance Sheet Grouping [Table Text Block]

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, 2017, and December 31, 2016, using available market information and appropriate valuation methodologies (in thousands).

	September 30, 2017				December 31, 2016
	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)	1,745,746		1,906,113		1,745,678		1,858,666
Idaho Power
Liabilities:
Long-term debt(1)	1,745,746		1,906,113		1,745,678		1,858,666

⁽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 11.

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SEGMENT INFORMATION: Level 3 (Tables)

9 Months Ended

Sep. 30, 2017

Segment Information [Abstract]

Schedule of Segment Reporting Information, by Segment

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). 

	Utility Operations		All Other		Eliminations			Consolidated Total
Three months ended September 30, 2017:
Revenues	$	406,655	$	1,669	$	—		$	408,324
Net income attributable to IDACORP, Inc.	88,329		2,305		—			90,634
Total assets as of September 30, 2017	6,321,917		116,718		(71,452		)	6,367,183
Three months ended September 30, 2016:
Revenues	$	371,474	$	571	$	—		$	372,045
Net income attributable to IDACORP, Inc.	80,029		3,071		—			83,100
Nine months ended September 30, 2017:
Revenues	$	1,040,387	$	3,487	$	—		$	1,043,874
Net income attributable to IDACORP, Inc.	169,192		4,375		—			173,567
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

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CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME: Level 3 (Tables)

9 Months Ended

Sep. 30, 2017

Statement of Comprehensive Income [Abstract]

Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block]

The table below presents changes in components of accumulated other comprehensive income (AOCI), net of tax, during the three and nine months endedSeptember 30, 2017 and 2016 (in thousands). Items in parentheses indicate charges to AOCI.

	Defined Benefit Pension Items
	Three months ended September 30,						Nine months ended September 30,
	2017			2016			2017			2016
Balance at beginning of period	$	(19,941	)	$	(20,149	)	$	(20,882	)	$	(21,276	)
Amounts reclassified out of AOCI	471			563			1,412			1,690
Balance at end of period	$	(19,470	)	$	(19,586	)	$	(19,470	)	$	(19,586	)

Reclassification out of Accumulated Other Comprehensive Income [Table Text Block]

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 endedSeptember 30, 2017 and 2016 (in thousands). 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,
	2017			2016			2017			2016
Amortization of defined benefit pension items(1)
Prior service cost	$	31		$	42		$	95		$	126
Net loss	742			883			2,223			2,649
Total before tax	773			925			2,318			2,775
Tax benefit(2)	(302		)	(362		)	(906		)	(1,085		)
Net of tax	471			563			1,412			1,690
Total reclassification for the period	$	471		$	563		$	1,412		$	1,690

⁽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 statements of income in other expense, net.

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

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: Accounting Adoption Pronouncement (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Sep. 30, 2016
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Cumulative Effect of New Accounting Principle in Period of Adoption	$ 0	$ (234)

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INCOME TAXES: Level 4 (Details) - USD ($) $ in Thousands		3 Months Ended		9 Months Ended
		Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Income Tax Expense [Line Items]
Income tax at statutory rates (federal and state)				$ 85,624	$ 75,736
Additional ADITC amortization				0	(1,500)
First mortgage bond redemption costs				0	(5,583)
Share-based compensation				(1,587)	(1,754)
Other	[1]			(38,617)	(38,277)
Income Tax Expense		$ 22,296	$ 15,535	$ 45,420	$ 28,622
Effective tax rate				20.70%	14.80%
Idaho Power Company
Income Tax Expense [Line Items]
Income tax at statutory rates (federal and state)				$ 84,278	$ 74,864
Additional ADITC amortization				0	(1,500)
First mortgage bond redemption costs				0	(5,583)
Share-based compensation				(1,558)	(1,720)
Other	[1]			(36,367)	(34,964)
Income Tax Expense		$ 22,941	$ 17,370	$ 46,353	$ 31,097
Effective tax rate				21.50%	16.20%

[1] "Other" is primarily comprised of the net tax effect of Idaho Power's regulatory flow-through tax adjustments. These adjustments 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, 2016.

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REGULATORY MATTERS: Level 4 (Details) - USD ($) $ in Thousands								3 Months Ended	9 Months Ended		12 Months Ended
	Jul. 01, 2017	Jun. 01, 2017	Jun. 01, 2014	Oct. 01, 2012	Jul. 01, 2012	Mar. 01, 2012	Jan. 01, 2012	Sep. 30, 2017	Sep. 30, 2017	Sep. 30, 2016	May 31, 2018	May 31, 2017	Dec. 31, 2016	Jun. 01, 2016	Jun. 01, 2015	Oct. 30, 2014
Rate Case
Additional ADITC amortization									$ 0	$ 1,500
Idaho Power Company
Rate Case
Additional ADITC amortization									0	1,500
Idaho and Oregon General Rate Cases and Base Rate Adjustments | IDAHO
Rate Case
Authorized Rate of Return in Rate Case							7.86%
Total Retail Rate Base							$ 2,360,000
Approved Rate Increase (Decrease), Amount							$ 34,000
Idaho and Oregon General Rate Cases and Base Rate Adjustments | OREGON
Rate Case
Authorized Rate of Return in Rate Case						7.757%
Approved Rate Increase (Decrease), Amount						$ 1,800
Public Utilities, Approved Return on Equity, Percentage						9.90%
Base rate adjustment request for potential Valmy closure [Member] [Member]
Rate Case
ValmySettlementStipulationRateIncreaseAfterTaxNetIncomeEffect								$ 1,300	3,800
Base rate adjustment request for potential Valmy closure [Member] [Member] | IDAHO
Rate Case
Approved Rate Increase (Decrease), Amount		$ 13,300
Base rate adjustment request for potential Valmy closure [Member] [Member] | OREGON
Rate Case
Approved Rate Increase (Decrease), Amount	$ 1,100
Cost Recovery for Langley Gulch Power Plant | IDAHO
Rate Case
Approved Rate Increase (Decrease), Amount					$ 58,100
Increase (Decrease) in Rate Base					$ 335,900
Cost Recovery for Langley Gulch Power Plant | OREGON
Rate Case
Approved Rate Increase (Decrease), Amount				$ 3,000
Idaho Settlement Stipulation - Investment Tax Credits and Sharing Mechanism
Rate Case
Authorized Return on Equity in Rate Case, Minimum																9.50%
Authorized Return on Equity in Rate Case, Mid-point																10.00%
Authorized Return on Equity in Rate Case, Maximum																10.50%
Investment Tax Credits Maximum In One Year In Rate Case																$ 25,000
Investment Tax Credits, Maximum, in Rate Case																$ 45,000
Additional ADITC amortization									$ 0	$ 1,500
Percentage to be Shared with Customers																75.00%
Percentage to be Shared with Entity																25.00%
Percent To Be Shared With Customers, Power Cost Adjustment																50.00%
Percent To Be Shared With Customers, Pension Balancing																25.00%
Regulatory Liabilities													$ 3,200
Annual Power Cost Adjustment Mechanism Filing [Member]
Rate Case
Approved Rate Increase (Decrease), Amount			$ 106,000									$ 17,300
Regulatory Liabilities		13,000											$ 4,000
Annual Power Cost Adjustment Mechanism Filing [Member] | IDAHO
Rate Case
Approved Rate Increase (Decrease), Amount			$ 99,000
Idaho Fixed Cost Adjustment Mechanism Annual Filing
Rate Case
Approved Rate Increase (Decrease), Amount												$ 11,200
Annual fixed cost adjustment mechanism deferral		$ 35,000												$ 28,100	$ 16,900
Scenario, Forecast [Member] | Idaho Fixed Cost Adjustment Mechanism Annual Filing
Rate Case
Approved Rate Increase (Decrease), Amount											$ 6,900
Subsequent Event [Member] | Annual Power Cost Adjustment Mechanism Filing [Member]
Rate Case
Approved Rate Increase (Decrease), Amount											$ 10,600

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NOTES PAYABLE: Level 4 (Details) - USD ($)	Sep. 30, 2017	Dec. 31, 2016
Short-term borrowings:
Commercial paper outstanding	$ 2,425,000	$ 21,800,000
Weighted-average annual interest rate	1.54%	1.13%
IDACORP
Short-term borrowings:
Commercial paper outstanding	$ 2,425,000	$ 0
Weighted-average annual interest rate	1.54%	0.00%
Credit facility:
Amount outstanding on credit facility	$ 0
Idaho Power Company
Short-term borrowings:
Commercial paper outstanding	$ 0	$ 21,800,000
Weighted-average annual interest rate	0.00%	1.13%
Credit facility:
Amount outstanding on credit facility	$ 0
Regulatory authority to incur short-term indebtedness	$ 450,000,000

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COMMON STOCK: Level 4 (Details) $ in Billions	9 Months Ended
	Sep. 30, 2017 USD ($) shares
Shareholders' equity
Restricted Stock Unit Awards to Employees	72,397
Restricted stock awards to directors	12,050
IDACORP
Shareholders' equity
Stock Issued During Period, Shares, New Issues	0
Maximum leverage ratio requirement	0.65
Ratio of Indebtedness to Net Capital	0.44
Dividend Distribution Restriction Amount | $	$ 1.3
Idaho Power Company
Shareholders' equity
Maximum leverage ratio requirement	0.65
Ratio of Indebtedness to Net Capital	0.46
Dividend Distribution Restriction Amount | $	$ 1.1
Dividend Distribution Restriction Threshold	0.35
Ratio of total Capital to total capital and long-term debt	0.54
Preferred Stock, Shares Outstanding	0

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EARNINGS PER SHARE: Level 4 (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Numerator:
Net Income Attributable to IDACORP, Inc.	$ 90,634	$ 83,100	$ 173,567	$ 165,075
Denominator:
Weighted-average common shares outstanding - basic	50,362	50,296	50,361	50,299
Effect of dilutive securities	59	97	47	62
Weighted-average common shares outstanding - diluted	50,421	50,393	50,408	50,361
Earnings attributable to IDACORP, Inc. - basic (in dollars per share)	$ 1.80	$ 1.65	$ 3.45	$ 3.28
Earnings attributable to IDACORP, Inc. - diluted (in dollars per share)	$ 1.80	$ 1.65	$ 3.44	$ 3.28

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COMMITMENTS: Level 4 (Details) $ in Millions	9 Months Ended
	Sep. 30, 2017 USD ($)
Idaho Power Company
Guarantor Obligations
IERCo ownership interest in BCC	33.00%
IERCo guarantee of BCC reclamation obligation	$ 57
Long-term Purchase Commitment
Increase of Long-term Purchase Obligations, Amount	$ 85
Life of Contract	20 years
Bridger Coal Company
Guarantor Obligations
Guarantor Obligations Total Reclamation Trust Fund	$ 97
Distribution from Reclamation Trust Fund	$ 0

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BENEFIT PLANS: Level 4 (Details) - USD ($)		3 Months Ended		9 Months Ended
		Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Pension Plan
Defined Benefit Plan Disclosure
Service cost		$ 8,436,000	$ 8,004,000	$ 25,307,000	$ 24,014,000
Interest cost		9,739,000	9,453,000	29,217,000	28,360,000
Expected return on plan assets		(11,285,000)	(10,519,000)	(33,854,000)	(31,560,000)
Amortization of prior service cost		7,000	15,000	21,000	44,000
Amortization of net loss		3,298,000	3,332,000	9,893,000	9,998,000
Net periodic benefit cost		10,195,000	10,285,000	30,584,000	30,856,000
Regulatory deferral of net periodic benefit cost	[1]	(9,708,000)	(9,826,000)	(28,991,000)	(29,508,000)
IPUC Authorized recovered pension cost	[1]	4,288,000	4,288,000	12,865,000	12,865,000
Net periodic benefit cost recognized for financial reporting	[1]	4,775,000	4,747,000	14,458,000	14,213,000
Contribution Requirement				0
Defined Benefit Plan, Contributions by Employer				40,000,000
Supplemental Employee Retirement Plan
Defined Benefit Plan Disclosure
Service cost		189,000	307,000	569,000	921,000
Interest cost		1,079,000	1,069,000	3,236,000	3,206,000
Expected return on plan assets		0	0	0	0
Amortization of prior service cost		31,000	42,000	95,000	126,000
Amortization of net loss		742,000	883,000	2,223,000	2,649,000
Net periodic benefit cost		2,041,000	2,301,000	6,123,000	6,902,000
Net periodic benefit cost recognized for financial reporting		2,041,000	2,301,000	6,123,000	6,902,000
Other Postretirement Benefits Plan
Defined Benefit Plan Disclosure
Service cost		244,000	279,000	730,000	837,000
Interest cost		695,000	692,000	2,087,000	2,075,000
Expected return on plan assets		(576,000)	(619,000)	(1,730,000)	(1,856,000)
Amortization of prior service cost		11,000	7,000	35,000	20,000
Amortization of net loss		0	0	0	0
Net periodic benefit cost		374,000	359,000	1,122,000	1,076,000
Net periodic benefit cost recognized for financial reporting		$ 374,000	$ 359,000	$ 1,122,000	$ 1,076,000

[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, the Idaho portion of net periodic benefit cost is recorded as a regulatory asset and is recognized in the income statement as those costs are recovered through rates.

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Derivative Instruments Fair Value and Offsets Table (Details) - USD ($) $ in Thousands		Sep. 30, 2017	Dec. 31, 2016
Derivatives, Fair Value [Line Items]
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	[1]	$ 100
Derivative Asset, Collateral, Obligation to Return Cash, Offset	[1]		$ 1,900
Derivative Asset, Fair Value, Gross Asset		528	8,134
Derivative Asset, Fair Value, Gross Liability		(392)	(2,183)
Derivative Asset, Fair Value, Amount Offset Against Collateral		136	5,951
Derivative Liability, Fair Value, Gross Liability		1,283	302
Derivative Liability, Fair Value, Gross Asset		(467)	(302)
Derivative Liability, Fair Value, Amount Offset Against Collateral		816	0
Financial Swaps | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		332	8,134
Derivative Asset, Fair Value, Gross Liability		(234)	(2,183)	[2]
Derivative Asset, Fair Value, Amount Offset Against Collateral		98	5,951
Derivative Liability, Fair Value, Gross Liability		234	302
Derivative Liability, Fair Value, Gross Asset		(234)	(302)
Derivative Liability, Fair Value, Amount Offset Against Collateral		0	$ 0
Financial Swaps | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		140
Derivative Asset, Fair Value, Gross Liability		(140)
Derivative Asset, Fair Value, Amount Offset Against Collateral		0
Derivative Liability, Fair Value, Gross Liability		919
Derivative Liability, Fair Value, Gross Asset		(140)
Derivative Liability, Fair Value, Amount Offset Against Collateral		779
Financial Swaps | Other Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		38
Derivative Asset, Fair Value, Gross Liability		(3)
Derivative Asset, Fair Value, Amount Offset Against Collateral		35
Derivative Liability, Fair Value, Gross Liability		3
Derivative Liability, Fair Value, Gross Asset		(3)
Derivative Liability, Fair Value, Amount Offset Against Collateral		0
Financial Swaps | Other Liabilities
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		15
Derivative Asset, Fair Value, Gross Liability		(15)
Derivative Asset, Fair Value, Amount Offset Against Collateral		0
Derivative Liability, Fair Value, Gross Liability		127
Derivative Liability, Fair Value, Gross Asset	[3]	(90)
Derivative Liability, Fair Value, Amount Offset Against Collateral		37
Forward contracts | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		3
Derivative Asset, Fair Value, Gross Liability		0
Derivative Asset, Fair Value, Amount Offset Against Collateral		3
Derivative Liability, Fair Value, Gross Liability		0
Derivative Liability, Fair Value, Gross Asset		0
Derivative Liability, Fair Value, Amount Offset Against Collateral		$ 0

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

[2] Current asset derivative amount offset includes $1.9 million of collateral payable for the period ended December 31, 2016.

[3] Long-term liability derivative amount offset includes $0.1 million of collateral receivable for the period ended September 30, 2017.

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Derivative Instruments Gains (Loss) on Derivatives Recognized in Income (Details) - USD ($) $ in Thousands		3 Months Ended		9 Months Ended
		Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Financial Swaps | Off-system sales
Derivative Instruments, Gain (Loss)
Derivative, Loss on Derivative	[1]	$ (309)	$ (16)
Derivative, Gain on Derivative	[1]			$ 864	$ 1,379
Financial Swaps | Purchased power
Derivative Instruments, Gain (Loss)
Derivative, Gain on Derivative	[1]	904	710	169	861
Financial Swaps | Fuel expense
Derivative Instruments, Gain (Loss)
Derivative, Loss on Derivative	[1]		(657)		(3,099)
Derivative, Gain on Derivative	[1]	883		1,549
Financial Swaps | Other operations and maintenance
Derivative Instruments, Gain (Loss)
Derivative, Loss on Derivative	[1]	(45)	(16)	(126)	(166)
Forward contracts | Purchased power
Derivative Instruments, Gain (Loss)
Derivative, Loss on Derivative	[1]	(3)		(13)
Derivative, Gain on Derivative	[1]		24		24
Forward contracts | Fuel expense
Derivative Instruments, Gain (Loss)
Derivative, Gain on Derivative	[1]	$ 0	$ 49	$ 3	$ 139

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

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Derivative Commodities and Disclosures (Details) MWh in Thousands, MMBTU in Thousands, Gallon in Thousands, $ in Millions	Sep. 30, 2017 USD ($) MMBTU Gallon MWh	Sep. 30, 2016 MMBTU Gallon MWh
Derivative
Derivatives in a net liability position	$ 1.3
Collateral Already Posted, Aggregate Fair Value	0.4
Additional Collateral, Aggregate Fair Value	$ 4.7
Electricity (MWh) | Long
Derivative
Derivative, Nonmonetary Notional Amount | MWh	122	130
Electricity (MWh) | Short
Derivative
Derivative, Nonmonetary Notional Amount | MWh	162	143
Natural Gas (MMBTU) | Long
Derivative
Derivative, Nonmonetary Notional Amount | MMBTU	7,975	7,977
Natural Gas (MMBTU) | Short
Derivative
Derivative, Nonmonetary Notional Amount | MMBTU	230	70
Diesel Fuel (Gallons) | Long
Derivative
Derivative, Nonmonetary Notional Amount | Gallon	304	267

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FAIR VALUE MEASUREMENTS: Level 4 (Details) - USD ($)	Sep. 30, 2017	Dec. 31, 2016
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Assets, Level 1 to Level 2 Transfers, Amount	$ 0	$ 0
Derivative Assets	136,000	5,951,000
Money market funds	0	15,000,000
Trading Securities	84,000	111,000
Available-for-sale Securities: Equity securities	23,475,000	23,908,000
Derivative Liabilities	816,000	0
Idaho Power Company
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Money market funds	45,495,000	29,967,000
Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets	133,000	5,951,000
Money market funds	0	15,000,000
Trading Securities	84,000	111,000
Available-for-sale Securities: Equity securities	23,475,000	23,908,000
Derivative Liabilities	816,000	0
Fair Value, Inputs, Level 1 [Member] | Idaho Power Company
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Money market funds	45,495,000	29,967,000
Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets	3,000	0
Money market funds	0	0
Trading Securities	0	0
Available-for-sale Securities: Equity securities	0	0
Derivative Liabilities	0	0
Fair Value, Inputs, Level 2 [Member] | Idaho Power Company
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Money market funds	0	0
Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets	0	0
Money market funds	0	0
Trading Securities	0	0
Available-for-sale Securities: Equity securities	0	0
Derivative Liabilities	0	0
Fair Value, Inputs, Level 3 [Member] | Idaho Power Company
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Money market funds	$ 0	$ 0

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FAIR VALUE MEASUREMENTS: Fair Value, by Balance Sheet Grouping (Details) - USD ($) $ in Thousands		Sep. 30, 2017	Dec. 31, 2016
Carrying Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Notes Receivable	[1]	$ 3,804	$ 3,804
Long-term debt	[1]	1,745,746	1,745,678
Carrying Amount | Idaho Power Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	[1]	1,745,746	1,745,678
Estimated Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Notes Receivable	[1]	3,804	3,804
Long-term debt	[1]	1,906,113	1,858,666
Estimated Fair Value | Idaho Power Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	[1]	$ 1,906,113	$ 1,858,666

[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 11.

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SEGMENT INFORMATION: Level 4 (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Segment Reporting Information
Revenues	$ 408,324	$ 372,045	$ 1,043,874	$ 968,437
Net Income Attributable to IDACORP, Inc.	91,076	83,017	174,177	164,934
Net Income Attributable to IDACORP, Inc.	90,634	83,100	173,567	165,075
Total assets	6,367,183		6,367,183		$ 6,289,897
Idaho Power Company
Segment Reporting Information
Revenues	406,655	371,474	1,040,387	966,451
Net Income Attributable to IDACORP, Inc.	88,329	80,029	169,192	160,370
Total assets	6,321,917		$ 6,321,917
IERCo's ownership percentage in Bridger Coal Company			33.00%
All Other
Segment Reporting Information
Revenues	1,669	571	$ 3,487	1,986
Net Income Attributable to IDACORP, Inc.	2,305	3,071	4,375	4,705
Total assets	116,718		116,718
Eliminations
Segment Reporting Information
Revenues	0	0	0	0
Net Income Attributable to IDACORP, Inc.	0	$ 0	0	$ 0
Total assets	$ (71,452)		$ (71,452)

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CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME: Level 4 (Details) - USD ($) $ in Thousands		3 Months Ended		9 Months Ended
		Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Reclassification out of Accumulated Other Comprehensive Income
Amortization of prior service cost	[1]	$ 31	$ 42	$ 95	$ 126
Amortization of net loss	[1]	742	883	2,223	2,649
Total reclassification, before tax - pension and postretirement benefits		773	925	2,318	2,775
Other Comprehensive Income (Loss), Tax, Portion Attributable to Parent	[2]	(302)	(362)	(906)	(1,085)
Total reclassification, net of tax - pension and postretirement benfits		471	563	1,412	1,690
Reclassifications		471	563	1,412	1,690
Increase (Decrease) in Accumulated Other Comprehensive Income [Roll Forward]
AOCI - Beginning Balance				(20,882)	(21,276)
Reclassifications		471	563	1,412	1,690
AOCI - Ending Balance		(19,470)	(19,586)	(19,470)	(19,586)
Accumulated Defined Benefit Pension Items
Reclassification out of Accumulated Other Comprehensive Income
Reclassifications		471	563	1,412	1,690
Increase (Decrease) in Accumulated Other Comprehensive Income [Roll Forward]
AOCI - Beginning Balance		(19,941)	(20,149)	(20,882)	(21,276)
Reclassifications		471	563	1,412	1,690
AOCI - Ending Balance		$ (19,470)	$ (19,586)	$ (19,470)	$ (19,586)

[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 statements of income in other expense, net.

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