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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)



X	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
	EXCHANGE ACT OF 1934
	For the quarterly period ended ~~September~~June 30, ~~2017~~2018
	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 __X (Do not check if a smaller reporting company)

Smaller reporting company X__

Emerging growth company __

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~~July 27, ~~2017:~~2018:

IDACORP, Inc.: ~~50,393,038~~50,392,903

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		3237
	Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations			3439
	Item 3. Quantitative and Qualitative Disclosures About Market Risk			5764
	Item 4. Controls and Procedures			5966

Part II. Other Information

	Item 1. Legal Proceedings			6067
	Item 1A. Risk Factors			6067
	Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			6067
	Item 3. Defaults Upon Senior Securities			6067
	Item 4. Mine Safety Disclosures			6067
	Item 5. Other Information			6067
	Item 6. Exhibits			6168

Signatures				6269

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COMMONLY USED TERMS

The following select abbreviations, terms, or acronyms are commonly used or found in multiple locations in this report:

ADITC	-	Accumulated Deferred Investment Tax Credits
AFUDC	-	Allowance for Funds Used During Construction
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~~CWA	-	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~~FPA	-	Federal ~~Implementation Plan~~
~~GHG NSPS~~	-	~~Greenhouse Gas New Source Performance Standards~~Power Act
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
Valmy Plant	-	North Valmy coal-fired power plant
Western EIM	-	Energy imbalance market implemented in the western United States
WPSC	-	Wyoming Public Service Commission

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

In addition to the historical information contained in this report, this report contains (and oral communications made by IDACORP, Inc. (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," "could," "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,~~2017, 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 and the Federal Energy Regulatory Commission, ~~and other regulators that~~which impact Idaho Power's ability to recover costs and earn a return ~~including the impact of settlement stipulations;~~on investment;

the expense and risks associated with capital expenditures for utility infrastructure, and the timing and availability of cost recovery for such expenditures through customer ~~rates;~~rates, including the potential for the write-down or write-off of assets if not deemed prudent by regulators;

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, or the addition of new 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~~interest rates, authorized regulatory returns on equity, supply costs, population growth or decline in Idaho Power's service area, 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, including conditions and events associated with climate change, which affect customer demand, hydroelectric generation levels, repair costs, liability for damage caused by utility property, 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;

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;

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~~and/or 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)~~facilities or infrastructure), 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 purchased power ~~purchased~~ costs and operational challenges associated with purchasing and integrating intermittent renewable energy sources into Idaho Power's resource portfolio;

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disruptions or outages of Idaho Power's generation or transmission systems or of any interconnected transmission system ~~may~~that 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 or disruptions in the financial markets, interest rate fluctuations,

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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 borrowing 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;

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 or regulations, security breaches, or the direct or indirect effect on the companies' business, operations or ~~operations~~reputation resulting from cyber-attacks or related litigation, 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,						Three months ended June 30,						Six months ended June 30,
	2017			2016			2017			2016			2018			2017			2018			2017
	(in thousands, except per share amounts)												(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
Electric utility revenues													$	338,699		$	331,768		$	648,160		$	633,732
Other	1,669			571			3,487			1,986			1,253			1,238			1,898			1,818
Total operating revenues	408,324			372,045			1,043,874			968,437			339,952			333,006			650,058			635,550

Operating Expenses:
Electric utility:
Purchased power	75,653			74,448			186,275			170,675			62,980			61,506			124,908			110,622
Fuel expense	54,529			73,925			111,197			139,657			21,515			20,416			49,250			56,668
Power cost adjustment	10,979			(18,342		)	51,208			11,914			19,963			16,742			45,501			40,229
Other operations and maintenance	84,197			87,090			259,445			259,813			92,314			86,729			178,512			173,720
Energy efficiency programs	9,883			9,102			26,726			24,256			8,802			10,515			16,399			16,843
Depreciation	40,259			36,036			122,262			107,447			41,348			45,240			81,416			82,002
Taxes other than income taxes	8,614			8,287			26,134			25,228			9,118			8,843			18,395			17,521
Total electric utility expenses	284,114			270,546			783,247			738,990			256,040			249,991			514,381			497,605
Other	3,296			3,571			9,789			10,748			1,077			1,108			2,253			2,411
Total operating expenses	287,410			274,117			793,036			749,738			257,117			251,099			516,634			500,016

Operating Income	120,914			97,928			250,838			218,699			82,835			81,907			133,424			135,534

Allowance for Equity Funds Used During Construction	5,712			5,931			16,555			16,153			5,985			5,611			12,018			10,843
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

Earnings of Equity-Method Investments													1,537			592			5,552			2,037

Other Income (Expense), Net													309			(426		)	(150		)	(841		)

Interest Expense:
Interest on long-term debt	20,300			20,296			60,897			61,659			21,412			20,300			42,099			40,597
Other interest	2,827			2,605			8,298			7,587			2,162			2,756			5,121			5,471
Allowance for borrowed funds used during construction	(2,385		)	(2,589		)	(7,106		)	(7,226		)	(2,606		)	(2,408		)	(5,078		)	(4,720		)
Total interest expense, net	20,742			20,312			62,089			62,020			20,968			20,648			42,142			41,348

Income Before Income Taxes	113,372			98,552			219,597			193,556			69,698			67,036			108,702			106,225

Income Tax Expense	22,296			15,535			45,420			28,622			7,105			16,940			9,998			23,124

Net Income	91,076			83,017			174,177			164,934			62,593			50,096			98,704			83,101
Adjustment for (income) loss attributable to noncontrolling interests	(442		)	83			(610		)	141
Adjustment for income attributable to noncontrolling interests													(305		)	(265		)	(274		)	(168		)
Net Income Attributable to IDACORP, Inc.	$	90,634		$	83,100		$	173,567		$	165,075		$	62,288		$	49,831		$	98,430		$	82,933
Weighted Average Common Shares Outstanding - Basic	50,362			50,296			50,361			50,299			50,435			50,363			50,430			50,361
Weighted Average Common Shares Outstanding - Diluted	50,421			50,393			50,408			50,361			50,481			50,407			50,472			50,402
Earnings Per Share of Common Stock:
Earnings Attributable to IDACORP, Inc. - Basic	$	1.80		$	1.65		$	3.45		$	3.28		$	1.24		$	0.99		$	1.95		$	1.65
Earnings Attributable to IDACORP, Inc. - Diluted	$	1.80		$	1.65		$	3.44		$	3.28		$	1.23		$	0.99		$	1.95		$	1.65
Dividends Declared Per Share of Common Stock	$	0.55		$	0.51		$	1.65		$	1.53		$	0.59		$	0.55		$	1.18		$	1.10

The accompanying notes are an integral part of these statements.

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IDACORP, Inc.

Condensed Consolidated Statements of Comprehensive Income

(unaudited)


	Three months ended September 30,					Nine months ended September 30,					Three months ended June 30,						Six months ended June 30,
	2017			2016		2017			2016		2018			2017			2018			2017
	(in thousands)										(in thousands)

Net Income	$	91,076		$	83,017	$	174,177		$	164,934	$	62,593		$	50,096		$	98,704		$	83,101
Other Comprehensive Income:
Unfunded pension liability adjustment, net of tax of $302, $362, $906 and $1,085	471			563		1,412			1,690
Unfunded pension liability adjustment, net of tax of $250, $302, $500, and $604											722			470			1,443			941
Total Comprehensive Income	91,547			83,580		175,589			166,624		63,315			50,566			100,147			84,042
Comprehensive (income) loss attributable to noncontrolling interests	(442		)	83		(610		)	141
Comprehensive income attributable to noncontrolling interests											(305		)	(265		)	(274		)	(168		)
Comprehensive Income Attributable to IDACORP, Inc.	$	91,105		$	83,663	$	174,979		$	166,765	$	63,010		$	50,301		$	99,873		$	83,874

The accompanying notes are an integral part of these statements.

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IDACORP, Inc.

Condensed Consolidated Balance Sheets

(unaudited)


	September 30, 2017			December 31, 2016			June 30, 2018			December 31, 2017
	(in thousands)						(in thousands)
Assets

Current Assets:
Cash and cash equivalents	$	104,411		$	61,480		$	183,141		$	76,649
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
Customer (net of allowance of $1,913 and $2,013, respectively)							87,975			75,249
Other (net of allowance of $205 and $180, respectively)							5,284			30,438
Taxes receivable	4,648			12,781			2,929			8,147
Accrued unbilled revenues	59,697			80,738			79,818			75,120
Materials and supplies (at average cost)	58,472			57,858			60,229			55,745
Fuel stock (at average cost)	54,093			53,698			66,389			56,638
Prepayments	16,477			18,389			14,852			16,984
Current regulatory assets	52,927			62,570			37,977			48,613
Other	101			5,961			757			18
Total current assets	457,928			440,312			539,351			443,601
Investments	111,952			125,164			106,558			115,698
Property, Plant and Equipment:
Utility plant in service	5,840,848			5,732,044			6,005,176			5,906,162
Accumulated provision for depreciation	(2,086,119		)	(1,988,477		)	(2,162,143		)	(2,098,274		)
Utility plant in service - net	3,754,729			3,743,567			3,843,033			3,807,888
Construction work in progress	463,106			405,069			465,413			452,424
Utility plant held for future use	7,511			7,441			4,727			8,075
Other property, net of accumulated depreciation	15,597			15,922			17,908			15,488
Property, plant and equipment - net	4,240,943			4,171,999			4,331,081			4,283,875
Other Assets:
American Falls and Milner water rights	7,641			9,487
Company-owned life insurance	58,973			57,553			60,537			59,323
Regulatory assets	1,412,086			1,409,329			1,106,110			1,083,483
Long-term receivables (net of allowance of $402)	26,367			23,482
Other	51,293			52,571			62,480			59,425
Total other assets	1,556,360			1,552,422			1,229,127			1,202,231
Total	$	6,367,183		$	6,289,897		$	6,206,117		$	6,045,405

The accompanying notes are an integral part of these statements.

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IDACORP, Inc.

Condensed Consolidated Balance Sheets

(unaudited)


	September 30, 2017			December 31, 2016			June 30, 2018			December 31, 2017
	(in thousands)						(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			$	74,804		$	90,277
Taxes accrued	57,902			11,348			28,807			11,075
Interest accrued	21,406			22,377			23,153			22,379
Accrued compensation	39,903			45,787			40,004			47,018
Current regulatory liabilities	2,296			9,944			30,876			1,404
Advances from customers	20,607			21,438			28,408			18,414
Other	9,100			9,763			11,952			10,182
Total current liabilities	225,792			249,715			238,004			200,749
Other Liabilities:
Deferred income taxes	1,241,091			1,244,250			642,013			660,940
Regulatory liabilities	466,162			436,845			720,574			698,044
Pension and other postretirement benefits	391,579			411,523			429,513			438,869
Other	44,651			45,084			43,751			44,566
Total other liabilities	2,143,483			2,137,702			1,835,851			1,842,419
Long-Term Debt	1,745,746			1,744,614			1,834,055			1,746,123
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
Common stock, no par value (120,000 shares authorized; 50,420 shares issued)							859,652			857,207
Retained earnings	1,413,387			1,323,198			1,465,009			1,426,528
Accumulated other comprehensive loss	(19,470		)	(20,882		)	(29,521		)	(30,964		)
Treasury stock (26,979 and 23,244 shares at cost, respectively)	(1,368		)	(243		)
Treasury stock (27 shares and 28 shares, respectively, at cost)							(1,936		)	(1,386		)
Total IDACORP, Inc. shareholders’ equity	2,247,592			2,153,906			2,293,204			2,251,385
Noncontrolling interests	4,570			3,960			5,003			4,729
Total equity	2,252,162			2,157,866			2,298,207			2,256,114
Total	$	6,367,183		$	6,289,897		$	6,206,117		$	6,045,405

The accompanying notes are an integral part of these statements.

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IDACORP, Inc.

Condensed Consolidated Statements of Cash Flows

(unaudited)


	Nine months ended September 30,						Six months ended June 30,
	2017			2016			2018			2017
	(in thousands)						(in thousands)
Operating Activities:
Net income	$	174,177		$	164,934		$	98,704		$	83,101
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	125,051			110,161			83,306			83,912
Deferred income taxes and investment tax credits	(195		)	30,077			(9,708		)	6,828
Changes in regulatory assets and liabilities	61,968			13,502			45,691			37,736
Pension and postretirement benefit plan expense	21,687			22,175			14,038			14,513
Contributions to pension and postretirement benefit plans	(45,158		)	(43,851		)	(24,516		)	(3,920		)
Earnings of unconsolidated equity-method investments	(7,269		)	(13,650		)
Distributions from unconsolidated equity-method investments	18,350			17,114
Earnings of equity-method investments							(5,552		)	(2,037		)
Distributions from equity-method investments							11,300			8,100
Allowance for equity funds used during construction	(16,555		)	(16,153		)	(12,018		)	(10,843		)
Other non-cash adjustments to net income, net	5,220			3,876			5,185			3,741
Change in:
Accounts receivable	(20,520		)	(12,435		)	(5,937		)	(5,406		)
Accounts payable and other accrued liabilities	(32,494		)	(10,033		)	(13,010		)	(30,677		)
Taxes accrued/receivable	54,687			8,490			22,950			18,073
Other current assets	18,736			7,343			(16,152		)	(16,951		)
Other current liabilities	(3,010		)	(5,451		)	9,054			6,948
Other assets	(5,357		)	(1,277		)	(5,439		)	(3,692		)
Other liabilities	(494		)	595			(1,472		)	(430		)
Net cash provided by operating activities	348,824			275,417			196,424			188,996
Investing Activities:
Additions to property, plant and equipment	(207,340		)	(199,966		)	(133,598		)	(146,341		)
Payments received from transmission project joint funding partners	5,934			6,853			20,323			5,787
Proceeds from the sale of emission allowances and renewable energy certificates	1,892			969			1,650			1,839
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		)
Purchase of equity securities							(228		)	(3,165		)
Proceeds from the sale of equity securities							2,450			2,428
Other	183			(9		)	495			2,860
Net cash used in investing activities	(198,824		)	(197,543		)	(108,908		)	(136,592		)
Financing Activities:
Issuance of long-term debt	—			120,000			220,000			—
Retirement of long-term debt	(1,064		)	(101,064		)	(130,000		)	(1,064		)
Dividends on common stock	(83,441		)	(77,350		)	(59,941		)	(55,763		)
Net change in short-term borrowings	(19,375		)	(14,600		)	—			(21,250		)
Acquisition of treasury stock	(3,189		)	(3,287		)	(3,551		)	(3,174		)
Make-whole premium on retirement of long-term debt	—			(13,895		)	(4,607		)	—
Other	—			(1,684		)	(2,925		)	(4		)
Net cash used in financing activities	(107,069		)	(91,880		)
Net cash provided by (used in) financing activities							18,976			(81,255		)
Net increase (decrease) in cash and cash equivalents	42,931			(14,006		)	106,492			(28,851		)
Cash and cash equivalents at beginning of the period	61,480			114,802			76,649			61,480
Cash and cash equivalents at end of the period	$	104,411		$	100,796		$	183,141		$	32,629
Supplemental Disclosure of Cash Flow Information:
Cash paid during the period for:
Income taxes	$	1,702		$	2,187		$	—		$	1,202
Interest (net of amount capitalized)	$	60,257		$	60,224		$	39,494		$	39,481
Non-cash investing activities:
Additions to property, plant and equipment in accounts payable	$	23,502		$	21,583		$	20,650		$	21,410

The accompanying notes are an integral part of these statements.

Table of Contents

IDACORP, Inc.

Condensed Consolidated Statements of Equity

(unaudited)


	Nine months ended September 30,						Six months ended June 30,
	2017			2016			2018			2017
	(in thousands)						(in thousands)
Common Stock
Balance at beginning of period	$	851,833		$	849,112		$	857,207		$	851,833
Cumulative effect of change in accounting principle	—			234
Other	3,210			1,352
Share-based compensation expense and other							2,445			1,771
Balance at end of period	855,043			850,698			859,652			853,604
Retained Earnings
Balance at beginning of period	1,323,198			1,230,105			1,426,528			1,323,198
Cumulative effect of change in accounting principle	—			(234		)
Net income attributable to IDACORP, Inc.	173,567			165,075			98,430			82,933
Common stock dividends ($1.65 and $1.53 per share)	(83,378		)	(77,214		)
Common stock dividends ($1.18 and $1.10 per share)							(59,949		)	(55,594		)
Balance at end of period	1,413,387			1,317,732			1,465,009			1,350,537
Accumulated Other Comprehensive (Loss) Income
Balance at beginning of period	(20,882		)	(21,276		)	(30,964		)	(20,882		)
Unfunded pension liability adjustment (net of tax)	1,412			1,690			1,443			941
Balance at end of period	(19,470		)	(19,586		)	(29,521		)	(19,941		)
Treasury Stock
Balance at beginning of period	(243		)	(57		)	(1,386		)	(243		)
Issued	2,063			3,143			3,007			2,060
Acquired	(3,188		)	(3,287		)	(3,557		)	(3,174		)
Balance at end of period	(1,368		)	(201		)	(1,936		)	(1,357		)
Total IDACORP, Inc. shareholders’ equity at end of period	2,247,592			2,148,643			2,293,204			2,182,843
Noncontrolling Interests
Balance at beginning of period	3,960			4,160			4,729			3,960
Net income (loss) attributable to noncontrolling interests	610			(141		)
Net income attributable to noncontrolling interests							274			168
Balance at end of period	4,570			4,019			5,003			4,128
Total equity at end of period	$	2,252,162		$	2,152,662		$	2,298,207		$	2,186,971

The accompanying notes are an integral part of these statements.

Table of Contents

Idaho Power Company

Condensed Consolidated Statements of Income

(unaudited)


	Three months ended September 30,						Nine months ended September 30,						Three months ended June 30,						Six months ended June 30,
	2017			2016			2017			2016			2018			2017			2018			2017
	(in thousands)												(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 Revenues													$	338,699		$	331,768		$	648,160		$	633,732

Operating Expenses:
Operation:
Purchased power	75,653			74,448			186,275			170,675			62,980			61,506			124,908			110,622
Fuel expense	54,529			73,925			111,197			139,657			21,515			20,416			49,250			56,668
Power cost adjustment	10,979			(18,342		)	51,208			11,914			19,963			16,742			45,501			40,229
Other operations and maintenance	84,197			87,090			259,445			259,813			92,314			86,729			178,512			173,720
Energy efficiency programs	9,883			9,102			26,726			24,256			8,802			10,515			16,399			16,843
Depreciation	40,259			36,036			122,262			107,447			41,348			45,240			81,416			82,002
Taxes other than income taxes	8,614			8,287			26,134			25,228			9,118			8,843			18,395			17,521
Total operating expenses	284,114			270,546			783,247			738,990			256,040			249,991			514,381			497,605

Income from Operations	122,541			100,928			257,140			227,461			82,659			81,777			133,779			136,127

Other Income (Expense):
Allowance for equity funds used during construction	5,712			5,931			16,555			16,153			5,985			5,611			12,018			10,843
Earnings of unconsolidated equity-method investments	4,151			11,121			5,068			11,528
Earnings (losses) of equity-method investments													683			(337		)	4,825			917
Other expense, net	(408		)	(328		)	(1,178		)	(1,845		)	(391		)	(1,000		)	(1,519		)	(2,297		)
Total other income	9,455			16,724			20,445			25,836			6,277			4,274			15,324			9,463
Interest Charges:

Interest Expense:
Interest on long-term debt	20,300			20,296			60,897			61,659			21,412			20,300			42,099			40,597
Other interest	2,811			2,546			8,249			7,397			2,148			2,740			5,093			5,438
Allowance for borrowed funds used during construction	(2,385		)	(2,589		)	(7,106		)	(7,226		)	(2,606		)	(2,408		)	(5,078		)	(4,720		)
Total interest charges	20,726			20,253			62,040			61,830
Total interest expense, net													20,954			20,632			42,114			41,315

Income Before Income Taxes	111,270			97,399			215,545			191,467			67,982			65,419			106,989			104,275

Income Tax Expense	22,941			17,370			46,353			31,097			7,345			17,038			10,496			23,412

Net Income	$	88,329		$	80,029		$	169,192		$	160,370		$	60,637		$	48,381		$	96,493		$	80,863

The accompanying notes are an integral part of these statements.

Table of Contents

Idaho Power Company

Condensed Consolidated Statements of Comprehensive Income

(unaudited)


	Three months ended September 30,				Nine months ended September 30,				Three months ended June 30,				Six months ended June 30,
	2017		2016		2017		2016		2018		2017		2018		2017
	(in thousands)								(in thousands)

Net Income	$	88,329	$	80,029	$	169,192	$	160,370	$	60,637	$	48,381	$	96,493	$	80,863
Other Comprehensive Income:
Unfunded pension liability adjustment, net of tax of $302, $362, $906 and $1,085	471		563		1,412		1,690
Unfunded pension liability adjustment, net of tax of $250, $302, $500, and $604									722		470		1,443		941
Total Comprehensive Income	$	88,800	$	80,592	$	170,604	$	162,060	$	61,359	$	48,851	$	97,936	$	81,804

The accompanying notes are an integral part of these statements.

Table of Contents

Idaho Power Company

Condensed Consolidated Balance Sheets

(unaudited)


	September 30, 2017			December 31, 2016			June 30, 2018			December 31, 2017
	(in thousands)						(in thousands)
Assets

Electric Plant:
In service (at original cost)	$	5,840,848		$	5,732,044		$	6,005,176		$	5,906,162
Accumulated provision for depreciation	(2,086,119		)	(1,988,477		)	(2,162,143		)	(2,098,274		)
In service - net	3,754,729			3,743,567			3,843,033			3,807,888
Construction work in progress	463,106			405,069			465,413			452,424
Held for future use	7,511			7,441			4,727			8,075
Electric plant - net	4,225,346			4,156,077			4,313,173			4,268,387
Investments and Other Property	94,497			107,379			93,710			99,904
Current Assets:
Cash and cash equivalents	101,766			44,140			149,150			44,646
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
Customer (net of allowance of $1,913 and $2,013, respectively)							87,975			75,249
Other (net of allowance of $205 and $180, respectively)							5,143			30,274
Taxes receivable	—			23,334			—			26,492
Accrued unbilled revenues	59,697			80,738			79,818			75,120
Materials and supplies (at average cost)	58,472			57,858			60,229			55,745
Fuel stock (at average cost)	54,093			53,698			66,389			56,638
Prepayments	16,362			18,270			14,729			16,866
Current regulatory assets	52,927			62,570			37,977			48,613
Other	101			5,962			757			18
Total current assets	450,415			425,682			502,167			429,661
Deferred Debits:
American Falls and Milner water rights	7,641			9,487
Company-owned life insurance	58,973			57,553			60,537			59,323
Regulatory assets	1,412,086			1,409,329			1,106,110			1,083,483
Other	72,959			71,237			57,805			54,677
Total deferred debits	1,551,659			1,547,606			1,224,452			1,197,483
Total	$	6,321,917		$	6,236,744		$	6,133,502		$	5,995,435

The accompanying notes are an integral part of these statements.

Table of Contents

Idaho Power Company

Condensed Consolidated Balance Sheets

(unaudited)


	September 30, 2017			December 31, 2016			June 30, 2018			December 31, 2017
	(in thousands)						(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
Common stock, $2.50 par value (50,000 shares authorized; 39,151 shares outstanding)							$	97,877		$	97,877
Premium on capital stock	712,258			712,258			712,258			712,258
Capital stock expense	(2,097		)	(2,097		)	(2,097		)	(2,097		)
Retained earnings	1,297,262			1,211,547			1,345,246			1,308,702
Accumulated other comprehensive loss	(19,470		)	(20,882		)	(29,521		)	(30,964		)
Total common stock equity	2,085,830			1,998,703			2,123,763			2,085,776
Long-term debt	1,745,746			1,744,614			1,834,055			1,746,123
Total capitalization	3,831,576			3,743,317			3,957,818			3,831,899
Current Liabilities:
Current maturities of long-term debt	—			1,064
Notes payable	—			21,800
Accounts payable	71,951			105,846			74,694			89,978
Accounts payable to affiliates	48,329			1,056			44,202			57,562
Taxes accrued	23,981			11,348			21,884			10,904
Interest accrued	21,406			22,377			23,153			22,379
Accrued compensation	39,744			45,622			39,863			46,832
Current regulatory liabilities	2,296			9,944			30,876			1,404
Advances from customers	20,607			21,438			28,408			18,414
Other	8,568			9,103			11,365			9,556
Total current liabilities	236,882			249,598			274,445			257,029
Deferred Credits:
Deferred income taxes	1,351,966			1,351,415			708,205			725,942
Regulatory liabilities	466,162			436,845			720,574			698,044
Pension and other postretirement benefits	391,579			411,523			429,513			438,869
Other	43,752			44,046			42,947			43,652
Total deferred credits	2,253,459			2,243,829			1,901,239			1,906,507

Commitments and Contingencies

Total	$	6,321,917		$	6,236,744		$	6,133,502		$	5,995,435

The accompanying notes are an integral part of these statements.

Table of Contents

Idaho Power Company

Condensed Consolidated Statements of Cash Flows

(unaudited)


	Nine months ended September 30,						Six months ended June 30,
	2017			2016			2018			2017
	(in thousands)						(in thousands)
Operating Activities:
Net income	$	169,192		$	160,370		$	96,493		$	80,863
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	124,599			109,704			83,007			83,611
Deferred income taxes and investment tax credits	1,972			12,679			(9,505		)	6,144
Changes in regulatory assets and liabilities	61,965			13,502			45,691			37,736
Pension and postretirement benefit plan expense	21,704			22,191			14,038			14,513
Contributions to pension and postretirement benefit plans	(45,174		)	(43,867		)	(24,516		)	(3,920		)
Earnings of unconsolidated equity-method investments	(5,068		)	(11,528		)
Distributions from unconsolidated equity-method investments	17,500			16,264
Earnings of equity-method investments							(4,825		)	(917		)
Distributions from equity-method investments							11,300			8,100
Allowance for equity funds used during construction	(16,555		)	(16,153		)	(12,018		)	(10,843		)
Other non-cash adjustments to net income, net	12			(571		)	(220		)	(47		)
Change in:
Accounts receivable	(27,369		)	(12,319		)	(4,884		)	(12,446		)
Accounts payable	14,155			(10,016		)	(27,256		)	(1,109		)
Taxes accrued/receivable	35,967			8,172			37,472			13,679
Other current assets	18,732			7,326			(16,145		)	(16,945		)
Other current liabilities	(3,004		)	(5,451		)	9,099			6,974
Other assets	(5,358		)	(1,277		)	(5,439		)	(3,693		)
Other liabilities	(354		)	789			(1,363		)	(275		)
Net cash provided by operating activities	362,916			249,815			190,929			201,425
Investing Activities:
Additions to utility plant	(207,327		)	(199,964		)	(133,584		)	(146,328		)
Payments received from transmission project joint funding partners	5,934			6,853			20,323			5,787
Proceeds from the sale of emission allowances and renewable energy certificates	1,892			969			1,650			1,839
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		)
Purchase of equity securities							(228		)	(3,165		)
Proceeds from the sale of equity securities							2,450			2,428
Other	46			(108		)	440			2,860
Net cash used in investing activities	(198,948		)	(197,640		)	(108,949		)	(136,579		)
Financing Activities:
Issuance of long-term debt	—			120,000			220,000			—
Retirement of long-term debt	(1,064		)	(101,064		)	(130,000		)	(1,064		)
Dividends on common stock	(83,478		)	(77,365		)	(59,949		)	(55,695		)
Net change in short term borrowings	(21,800		)	—			—			(21,800		)
Make-whole premium on retirement of long-term debt	—			(13,895		)	(4,607		)	—
Other	—			(1,671		)	(2,920		)	—
Net cash used in financing activities	(106,342		)	(73,995		)
Net cash provided by (used in) financing activities							22,524			(78,559		)
Net increase (decrease) in cash and cash equivalents	57,626			(21,820		)	104,504			(13,713		)
Cash and cash equivalents at beginning of the period	44,140			110,756			44,646			44,140
Cash and cash equivalents at end of the period	$	101,766		$	88,936		$	149,150		$	30,427
Supplemental Disclosure of Cash Flow Information:
Cash (received from) paid to IDACORP related to income taxes	$	(27,556	)	$	19,796
Cash paid to IDACORP related to income taxes							$	—		$	22,861
Cash paid for interest (net of amount capitalized)	$	60,208		$	60,034		$	39,467		$	39,447
Non-cash investing activities:
Additions to property, plant and equipment in accounts payable	$	23,502		$	21,583		$	20,650		$	21,410

The accompanying notes are an integral part of these statements.

Table of Contents

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.~~Power (Jim Bridger plant).

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~~sheet. Regulatory assets represent incurred costs that have been deferred because it is probable they will be recovered ~~or returned through rates. Additionally, regulators can impose regulatory liabilities upon a regulated company for amounts previously collected~~ from customers ~~that are expected~~through future rates. Regulatory liabilities represent obligations to ~~be refunded.~~make refunds to customers for previous collections, or represent amounts collected in advance of incurring an expense. The effects of applying these regulatory accounting principles to Idaho Power's operations are discussed in more detail in Note 3.3 - "Regulatory Matters."

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~~June 30, ~~2017,~~2018, consolidated results of operations for the three and ~~nine~~six months ended ~~September~~June 30, ~~2017~~2018 and ~~2016,~~2017, and consolidated cash flows for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2018 and ~~2016.~~2017. 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.~~2017. 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

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~~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~~Recently Adopted 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~~IDACORP and Idaho Power adopted ASU 2014-09 on ~~their financial statements and do~~January 1, 2018, using the modified-retrospective approach as provided for in the standard. The adoption did not ~~expect the new guidance to affect~~change the timing ~~and amount~~or amounts of revenue ~~recognized. However,~~currently recognized by the ~~presentation and disclosure requirements of the standard will result in a~~companies, so no cumulative-effect adjustment was required. The adoption did change ~~in the~~ presentation of ~~revenue~~revenues on the ~~companies'~~condensed consolidated statements of income and also added disclosures. To conform with current period presentation, electric utility revenues on IDACORP's and Idaho Power's condensed consolidated statements of income for the three and six months ended June 30, 2018 and 2017, which had previously been reported separately as ~~well as expanded disclosures around~~"General business," "Off-system sales," and "Other revenues," are no longer reported separately. See Note 4 - "Revenues" for additional information on the disaggregation of ~~revenue.~~revenue and additional disclosures.

In January 2016, the FASB issued ASU 2016-01, Financial Instruments—Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities, which revises the accounting related to the classification and measurement of investments in equity securities and the presentation of certain fair value changes for financial liabilities measured at fair value. It also amends certain disclosure requirements associated with the fair value of financial instruments. The new standard is effective for fiscal years beginning after December 15, 2017, including interim periods. IDACORP and Idaho Power adopted ASU 2016-01 on January 1, 2018. The adoption did not have a material impact on the companies' financial statements as the companies previously elected the fair value option and reported available-for-sale securities at fair value.

In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230) Classification of Certain Cash Receipts and Cash Payments, to reduce diversity in practice in how certain cash receipts and cash payments are classified in the statement of cash flows. The companies' classification of proceeds from the settlement of corporate-owned life insurance policies and related costs will be classified as investing activities under the new guidance. The new guidance did not affect the companies' presentation of 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. IDACORP and Idaho Power adopted ASU 2016-15 on January 1, 2018, using the retrospective approach as provided for in the standard. To conform with current period presentation, the companies reclassified $2.6 million of company-owned life insurance proceeds received for the six months ended June 30, 2017, to "Other" within "Investing Activities" from "Change in accounts receivable" within "Operating Activities" on the condensed consolidated statements of cash flows.

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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 capitalizes amounts of pension or postretirement costs that are insignificant to the consolidated financial statements. The amendments in ASU ~~2014-09 is~~2017-07 are effective for interim and annual reporting periods beginning after December 15, 2017. ~~The guidance permits two implementation approaches, one requiring~~Entities must use (1) a retrospective ~~application~~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 ~~new standard with restatement~~requirement to limit the capitalization of ~~prior years (full retrospective approach) and~~benefit costs to the ~~other requiring prospective application of the new standard including a cumulative-effect adjustment with disclosure of results under previous standards (modified-retrospective approach).~~service cost component. IDACORP and Idaho Power ~~plan to adopt~~adopted ASU ~~2014-09~~2017-07 on January 1, 2018, ~~using~~and accordingly, have retrospectively adjusted prior periods to reflect the ~~modified-retrospective approach.~~disaggregation of service cost from other components of net periodic benefit costs. The adoption did not have a material impact on the companies' financial statements nor did it affect net income for the three and six months ended June 30, 2018. For IDACORP, for the three and six months ended June 30, 2017, $0.8 million and $1.5 million, respectively, were reclassified out of "Other operations and maintenance" and $2.0 million and $4.1 million, respectively, were reclassified out of "Other" operating expenses for a total of $2.8 million and $5.6 million, respectively, reclassified to "Other Income (Expense), Net" to conform to current period presentation. For Idaho Power, for the three and six months ended June 30, 2017, $0.8 million and $1.5 million, respectively, were reclassified from "Other operations and maintenance" to "Other expense, net" to conform to current period presentation.

Recent Accounting Pronouncements Not Yet Adopted

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.

Reclassifications

In ~~August 2016, the FASB issued ASU 2016-15,~~ ~~Statement of Cash Flows (Topic 230), which amends ASC 230~~these condensed consolidated financial statements, certain amounts in prior periods’ consolidated financial statements have been reclassified to ~~clarify guidance on the classification of certain cash receipts and payments in the statement of cash flows. The FASB issued the ASU~~conform 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, IDACORPcurrent period presentation. On IDACORP's and Idaho ~~Power do not believe~~Power's December 31, 2017 condensed consolidated balance sheets, the ~~adoption will have a material impact on their financial statements.~~

~~Table~~"Long-term receivables" balances of ~~Contents~~

~~In March 2017, the FASB issued ASU 2017-07,~~ ~~Compensation -- Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost~~$4.3 million and ~~Net Periodic Postretirement Benefit Cost,~~$0.5 million, respectively, which ~~requires employers~~had previously been reported separately, were reclassified to ~~disaggregate the service cost component from other components of net periodic benefit costs~~"Other" within "Other Assets" 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."Deferred Debits," respectively.

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.

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Income Tax Expense

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


	IDACORP						Idaho Power						IDACORP						Idaho Power
	2017			2016			2017			2016			2018			2017			2018			2017
Income tax at statutory rates (federal and state)	$	85,624		$	75,736		$	84,278		$	74,864		$	27,909		$	41,468		$	27,539		$	40,772
Additional accumulated deferred investment tax credits (ADITC) amortization	—			(1,500		)	—			(1,500		)
First mortgage bond redemption costs	—			(5,583		)	—			(5,583		)	(1,261		)	—			(1,261		)	—
Share-based compensation	(1,587		)	(1,754		)	(1,558		)	(1,720		)	(1,053		)	(1,559		)	(1,040		)	(1,530		)
Other⁽¹⁾	(38,617		)	(38,277		)	(36,367		)	(34,964		)	(15,597		)	(16,785		)	(14,742		)	(15,830		)
Income tax expense	$	45,420		$	28,622		$	46,353		$	31,097		$	9,998		$	23,124		$	10,496		$	23,412
Effective tax rate	20.7		%	14.8		%	21.5		%	16.2		%	9.2		%	21.8		%	9.8		%	22.5		%

⁽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~~decreases in income tax expense for the ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2018, as compared ~~with~~to the same period in ~~2016,~~2017, were primarily due to ~~greater pre-tax income, the~~lower statutory tax rates and a flow-through income tax benefit related to the tax deduction for bond redemption costs incurred in the second quarter of ~~2016,~~2018. The decrease in statutory rates was due to the 2017 Tax Cuts and Jobs Act, which reduced the U.S. federal corporate income tax ~~benefits~~rate from ~~distributions~~35 percent to 21 percent, and Idaho House Bill 463 which lowered the Idaho state corporate income tax rate from ~~fully-amortized affordable housing investments that~~7.4 percent to 6.925 percent. The federal and Idaho state income tax rate changes were ~~recorded in the third quarter of 2016.~~effective January 1, 2018. On a net basis, Idaho Power’s estimate of its annual ~~2017~~2018 regulatory flow-through tax adjustments is comparable to ~~2016.~~2017.

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.

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Idaho and Oregon General Rate Cases ~~and Base Rate Adjustments~~

~~Effective January 1, 2012,~~ Idaho ~~Power implemented new Idaho~~Power's current base rates ~~resulting from its receipt~~are a result of ~~an order~~orders from the Idaho Public Utilities Commission (IPUC) ~~approving a~~and Public Utility Commission of Oregon (OPUC). The commissions approve settlement ~~stipulation~~stipulations that ~~provided~~generally provide 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 specifiedcost recovery and an authorized rate of return on ~~equity.~~

~~Effective March 1, 2012,~~their respective Idaho-jurisdiction and Oregon-jurisdiction rate bases. 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 basePower's most recent general rate ~~revenue increase, a return on equity of 9.9 percent, and an overall rate of return of 7.757 percent~~cases in ~~the Oregon jurisdiction.~~

Idaho and Oregon ~~base rates~~ were ~~subsequently adjusted again in 2012, in connection with~~filed during 2011, and Idaho ~~Power's completion of~~Power filed a large single-issue rate case for the Langley Gulch power ~~plant. In June 2012,~~plant in Idaho and Oregon in 2012. These significant rate cases resulted in the ~~IPUC issued an order approving~~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 ~~$58.1 million~~resulting net increase in ~~annual Idaho-jurisdiction base~~rates. Between general 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~~cases, 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 IdahoPower relies upon customer growth, power cost adjustment ~~(PCA)~~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. For more information on the Idaho and Oregon general rate ~~that became effective June 1, 2014. Approval of~~cases and base rate adjustments, refer to Note 3 - "Regulatory Matters" to the ~~order removed~~consolidated financial statements included in IDACORP's and Idaho Power's Annual Report on Form 10-K for 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.~~year ended December 31, 2017.

Idaho Settlement ~~Stipulation — Investment Tax Credits and Sharing Mechanism~~Stipulations

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.~~IPUC (October 2014 Idaho Earnings Support and Sharing Settlement Stipulation). The provisions of the October 2014 ~~settlement stipulation~~Idaho Earnings Support and Sharing Settlement Stipulation are ~~as follows:~~described in the table included under "Income Tax Reform - Regulatory Treatment" below.

IfUnder the October 2014 Idaho Earnings Support and Sharing Settlement Stipulation, during the second quarter of 2018 Idaho Power reversed the $0.5 million of additional accumulated deferred investment tax credits (ADITC) amortization recorded during the first quarter of 2018, based on Idaho Power's ~~annual~~current estimate of return on year-end equity in the Idaho jurisdiction (Idaho ROE) ~~in any year is less than 9.5 percent, then~~for the full-year 2018. During the second quarter of 2017, 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~~reversed $1.9 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~~quarter 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~~

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Income Tax Reform - Regulatory Treatment

In ~~May~~December 2017, the Tax Cuts and Jobs Act was signed into law, which, among other things, lowered the corporate federal income tax rate from 35 percent to 21 percent and modified or eliminated certain federal income tax deductions for corporations. In March 2018, Idaho House Bill 463 was signed into law reducing the Idaho state corporate income tax rate from 7.4 percent to 6.925 percent. In January 2018, the IPUC ~~approved~~issued an order requiring utilities within its jurisdiction, including Idaho Power, to file a report with the IPUC, identifying and quantifying the financial impact of the income tax reform changes on the utility, along with proposed tariff schedule changes that would adjust the utility's rates to reflect the utility's modified federal tax obligations under the Tax Cuts and Jobs Act. The IPUC order required Idaho Power to estimate the income tax reform changes by comparing actual 2017 federal income tax components with what those federal income tax components would have been if the Tax Cuts and Jobs Act had been effective for the full year of 2017.

In March 2018, Idaho Power made a filing with the IPUC providing the results of its pro forma analysis indicating pro forma annual income tax reform expense reductions, composed of a current income tax expense reduction and a deferred income tax expense reduction. In May 2018, the IPUC issued an order approving a settlement stipulation ~~allowing accelerated depreciation and cost recovery for~~(May 2018 Idaho ~~Power’s jointly-owned North Valmy coal-fired power plant (Valmy Plant). The~~Tax Reform Settlement Stipulation) related to income tax reform. Beginning June 1, 2018, the settlement stipulation provides an annual (a) $18.7 million reduction to Idaho customer base rates and (b) $7.4 million amortization of existing regulatory deferrals for ~~an increase~~specified items or future amortization of other existing or future unspecified regulatory deferrals that would otherwise be a future liability recoverable from Idaho customers. Additionally, a one-time benefit of a $7.8 million rate reduction is being provided to Idaho customers through the Idaho-jurisdiction power cost adjustment (PCA) mechanism for the period from June 1, 2018 through May 31, 2019, for the income tax reform benefits accrued from January 1, 2018 to May 31, 2018, and the income tax reform benefits related to Idaho Power's open access transmission tariff (OATT). The amount provided via the PCA mechanism will decrease to $2.7 million on June 1, 2019, for income tax reform benefits related to Idaho Power's OATT and will cease on June 1, 2020, to reflect the impact of a full year of reduced OATT third-party transmission revenues.

The May 2018 Idaho Tax Reform Settlement Stipulation also provides for the indefinite extension of the October 2014 Idaho Earnings Support and Sharing Settlement Stipulation beyond its termination date of December 31, 2019. The table below summarizes and compares the terms of the October 2014 Idaho Earnings Support and Sharing Settlement Stipulation with the terms in the May 2018 Idaho Tax Reform Settlement Stipulation that will be applicable commencing on January 1, 2020.

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October 2014 Idaho Earnings Support and Sharing Settlement Stipulation (Effective through December 31, 2019)		May 2018 Idaho Tax Reform Settlement Stipulation (Effective beginning January 1, 2020, with no defined end date)
If Idaho Power's actual annual 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 the $45 million of ADITC are completely amortized, the revenue sharing provisions below would no longer be applicable.		If Idaho Power's actual annual Idaho ROE in any year is less than 9.4 percent, then Idaho Power may amortize up to $25 million of additional ADITC to help achieve a 9.4 percent Idaho ROE for that year, so long as the cumulative amount of ADITC used does not exceed $45 million (Idaho Power will have available and may continue to use any unused portion of the $45 million of additional ADITC from the October 2014 Idaho Earnings Support and Sharing Settlement Stipulation); however, Idaho Power may seek approval from the IPUC to replenish the total amount of ADITC it is permitted to amortize. If there are no remaining amounts of ADITC authorized to be amortized, the revenue sharing provisions below would not be applicable until ADITC is replenished.
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 10.0 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 80 percent to Idaho Power's Idaho customers as a rate reduction to be effective at the time of the subsequent year's PCA, and 20 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 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 55 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 20 percent to Idaho Power.
In the event the IPUC approves a change to Idaho Power's allowed annual Idaho ROE as part of a general rate case proceeding before December 31, 2019, the Idaho ROE thresholds will be adjusted on a prospective basis as follows: (a) the Idaho ROE under which Idaho Power will be permitted to amortize an additional amount of ADITC will be set at 95 percent of the newly authorized Idaho ROE, (b) sharing with customers on an 75 percent basis as a customer rate reduction will begin at the newly authorized Idaho ROE, and (c) sharing with customers on a 75 percent basis but allocated 50 percent to a rate reduction, and 25 percent to a pension expense deferral regulatory asset, will begin at 105 percent of the newly authorized Idaho ROE.		In the event the IPUC approves a change to Idaho Power's allowed annual Idaho ROE as part of a general rate case proceeding effective on or after January 1, 2020, the Idaho ROE thresholds will be adjusted on a prospective basis as follows: (a) the Idaho ROE under which Idaho Power will be permitted to amortize an additional amount of ADITC will be set at 95 percent of the newly authorized Idaho ROE, (b) sharing with customers on an 80 percent basis as a customer rate reduction will begin at the newly authorized Idaho ROE, and (c) sharing with customers on an 80 percent basis but allocated 55 percent to a rate reduction, and 25 percent to a pension expense deferral regulatory asset, will begin at 105 percent of the newly authorized Idaho ROE.

Neither the October 2014 Idaho ~~jurisdictional revenues~~Earnings Support and Sharing Settlement Stipulation nor the May 2018 Idaho Tax Reform Settlement Stipulation impose a moratorium on Idaho Power filing a general rate case or other form of ~~$13.3~~rate proceeding in Idaho during their respective terms.

Also in May 2018, the OPUC issued an order approving a settlement stipulation that provides for an annual $1.5 million ~~per year, and (1) levelized collections and associated cost recovery~~reduction to Oregon customer base rates beginning June 1, 2018, through ~~December 2028, (2) accelerated depreciation on unit 1 through 2019 and unit 2 through 2025, (3)~~May 31, 2020, related to income tax reform. Unless resolved in a regulatory proceeding before, the settlement stipulation requires Idaho Power to ~~use prudent~~file a deferral request with the OPUC by December 31, 2019, to begin tracking tax reform benefits beginning January 1, 2020, at which time Idaho Power, the OPUC staff, and ~~commercially reasonable efforts~~other interested parties will discuss the methodology 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.quantify potential future tax reform benefits. The settlement stipulation also ~~provides for~~deemed prudent Idaho Power's decision to pursue the ~~regulatory deferral~~end of its participation in coal-fired operations of Unit 1 at Idaho Power's jointly-owned North Valmy coal-fired plant and approved Idaho Power's request to recover annual incremental accelerated depreciation of $2.5 million relating to Unit 1, beginning June 1, 2018, and ending December 31, 2019.

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Hells Canyon Complex Relicensing Costs Settlement Stipulation

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 ~~difference between actual revenue requirements~~Hells Canyon Complex (HCC) were prudently incurred, and ~~levelized collections,~~thus eligible for inclusion in retail rates in a future regulatory proceeding. In December 2017, Idaho Power filed with the IPUC a settlement stipulation signed by Idaho Power, the IPUC staff, and ~~provides~~a third party intervenor, recognizing that a total of $216.5 million in HCC relicensing expenditures and other related costs were reasonably incurred, and therefore should be eligible for ~~the regulatory deferral~~inclusion in customer rates at a later date. As a result 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 infiling the settlement stipulation, ~~(including depreciation expense through 2028). If actual~~Idaho Power recorded a $5.0 million pre-tax charge in the fourth quarter of 2017, which included $4.3 million for costs incurred ~~differ from forecasted amounts included~~through 2015, as well as $0.7 million related to associated costs incurred in 2016 and 2017. In April 2018, the IPUC issued an order approving 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,as filed 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~~determined the $216.5 million of associated costs to ~~revised depreciation rates for Idaho Power's electric plant in service other than the Valmy Plant,~~be reasonably 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.prudently incurred.

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~~wholesale energy 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.

OnIn June 2018, the IPUC issued an order approving a $22.6 million net decrease in PCA rates, effective for the 2018-2019 PCA collection period from June 1, 2018, to May 31, 2019. The net decrease in PCA rates is primarily due to better-than-expected actual water conditions for the 2017-2018 PCA year, which resulted in additional low-cost hydroelectric generation available to reduce net power supply costs. Previously in May 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~~renewable energy power purchase agreements under PURPA 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~~included an offsetting $13.0 million one-time 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 a portion of 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, applicable to residential and small commercial customers, is adjusted each year to ~~collect,~~accrue, or ~~refund,~~defer, the difference between the authorized fixed-cost recovery amount per customer and the actual fixed costs per customer recovered by Idaho Power during the year. OnIn May 2018, the IPUC issued an order approving a decrease of $19.4 million in the FCA from $35.0 million to $15.6 million, with new rates effective for the period from June 1, 2018, to May 31, 2019. Previously in May 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~~

Western Energy Imbalance Market Costs

Idaho Power's participation in ~~May~~the energy imbalance market implemented in the western United States (Western EIM) commenced on April 4, 2018. The Western EIM aims to reduce the power supply costs to serve customers through more efficient dispatch within the hour of a larger and more diverse pool of resources, to integrate intermittent power from renewable generation sources more effectively, and to enhance reliability.

In August 2016, Idaho Power filed an application with the IPUC requesting specified regulatory accounting treatment associated with its participation in the Western EIM. In January 2017, the IPUC issued an order authorizing deferral accounting treatment for costs associated with joining the Western EIM. Idaho Power deferred $1.0 million of incremental other operations and maintenance (O&M) costs incurred through April 1, 2018.

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In November 2017, Idaho Power filed an application with the IPUC requesting approval to establish an interim method of recovery for costs associated with participation in the Western EIM. In July 2018, the IPUC issued an order approving a settlement stipulation that provides for a recovery mechanism administered through Idaho Power's ~~application requesting an increase~~PCA mechanism. The recovery mechanism provides for monthly incremental revenue, which includes a return on and return of ~~$11.2~~Western EIM-related capital costs and recovery of ongoing Western EIM operating costs. As of April 1, 2018, Idaho Power ceased deferring incremental Western EIM participation O&M start-up costs, and began recognizing the monthly incremental revenue associated with Western EIM participation. During both the three and six months ended June 30, 2018, Idaho Power recorded $0.7 million inof revenue relating to Western EIM participation and deferred the ~~FCA from $16.9 million~~same amount to ~~$28.1 million, with new rates effective for~~ the ~~period from June 1, 2016, to May 31, 2017.~~PCA deferral account.

4. ~~NOTES PAYABLE~~REVENUES

~~Credit Facilities~~

On January 1, 2018, IDACORP and Idaho Power adopted ASU 2014-09 using the modified retrospective method. The adoption did not change the timing or amounts of revenue recognized by IDACORP or Idaho Power and, therefore, no cumulative-effect adjustment was recorded. The following table provides a summary of electric utility operating revenues for IDACORP and Idaho Power for the three and six months ended June 30, 2018 and 2017 (in thousands):



	Three months ended June 30,				Six months ended June 30,
	2018		2017		2018		2017
Electric utility operating revenues:
Revenue from contracts with customers	$	331,298	$	326,190	$	620,871	$	620,081
Alternative revenue programs and other revenues	7,401		5,578		27,289		13,651
Total electric utility operating revenues	$	338,699	$	331,768	$	648,160	$	633,732

Revenues from Contracts with Customers

Revenues from contracts with customers are primarily related to Idaho Power’s regulated tariff-based sales of energy or related services. Generally, tariff-based sales do not involve a written contract, but are classified as revenues from contracts with customers under ASU 2014-09. Idaho Power assesses revenues on a contract-by-contract basis to determine the nature, amount, timing and uncertainty, if any, of revenues being recognized. The following table presents revenues from contracts with customers disaggregated by revenue source for the three and six months ended June 30, 2018 and 2017 (in thousands):



	Three months ended June 30,						Six months ended June 30,
	2018			2017			2018			2017
Revenues from contracts with customers:
Retail revenues:
Residential (includes $5,508, $3,205, $19,052 and $8,331, respectively, related to the FCA⁽¹⁾)	$	109,155		$	112,534		$	255,838		$	264,689
Commercial(includes $291, $276, $652 and $387, respectively, related to the FCA⁽¹⁾)	76,965			78,982			151,191			153,260
Industrial	48,868			49,766			94,660			95,224
Irrigation	65,065			56,068			65,471			56,993
Deferred revenue related to HCC relicensing AFUDC⁽²⁾	(1,462		)	(2,349		)	(4,046		)	(4,933		)
Total retail revenues	298,591			295,001			563,114			565,233
Less: FCA mechanism revenues⁽¹⁾	(5,799		)	(3,481		)	(19,704		)	(8,718		)
Wholesale energy sales	10,214			6,003			24,283			13,967
Transmission services (wheeling) revenues	13,205			11,965			24,600			20,824
Energy efficiency program revenues	8,802			10,515			16,399			16,843
Other revenues from contracts with customers	6,285			6,187			12,179			11,932
Total revenues from contracts with customers	$	331,298		$	326,190		$	620,871		$	620,081

⁽¹⁾ The FCA mechanism is an alternative revenue program and does not represent revenue from contracts with customers.

⁽²⁾As part of its January 30, 2009 general rate case order, the IPUC is allowing Idaho Power to recover a portion of 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 ~~place credit facilities~~service. Idaho Power is collecting $8.8 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. Prior to the May 2018 Idaho Tax Reform Settlement Stipulation described in Note 3 - "Regulatory Matters," Idaho Power was collecting $10.7 million annually.

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Retail Revenues:Idaho Power’s retail revenues primarily relate to the sale of electricity to customers based on regulated tariff-based prices. Idaho Power recognizes retail revenues in amounts for which it has the right to invoice the customer in the period when energy is delivered or services are provided to customers. The total energy price generally has a fixed component related to having service available and a usage-based component related to the demand, delivery, and consumption of energy. The revenues recognized reflect the consideration Idaho Power expects to be entitled to in exchange for that energy or those services. Retail customers are classified as residential, commercial, industrial, or irrigation. Approximately 95 percent of Idaho Power's retail revenue originates from customers located in Idaho, with the remainder originating from customers located in Oregon. Idaho Power’s retail customer rates are based on Idaho Power’s cost of service and are determined through general rate case proceedings, settlement stipulations, and other filings with the IPUC and OPUC. Changes in rates and changes in customer demand are typically the primary causes of fluctuations in retail revenue from period to period. The primary influences on changes in customer demand for electricity are weather, economic conditions (including growth in the number of Idaho Power customers), and energy efficiency. Idaho Power's utility revenues are not earned evenly during the year.

Retail revenues are billed monthly based on meter readings taken throughout the month. Payments for amounts billed are generally due from the customer within 15 days of billing. Idaho Power accrues estimated unbilled revenues for energy or related services delivered to customers but not yet billed at period-end based on actual meter readings at period-end and estimated rates.

Credit losses recorded on receivables arising from Idaho Power’s contracts with customers were $1.5 million and $1.8 million for the three and six months ended June 30, 2018, respectively, and $2.2 million and $2.4 million for the three and six months ended June 30, 2017, respectively.

Residential Customers: Idaho Power’s energy sales to residential customers typically peak during the winter heating season and summer cooling season. Extreme temperatures increase sales to residential customers who use electricity for cooling and heating, compared with normal temperatures. Idaho Power's rate structure provides for higher rates during the summer when overall system loads are at their highest, and includes tiers such that rates increase as a customer's consumption level increases. These seasonal and tiered rate structures contribute to the seasonal fluctuations in revenues and earnings. Economic and demographic conditions can also affect residential customer demand; strong job growth and population growth in Idaho Power’s service area have led to increasing customer growth rates in recent years. Residential demand is also impacted by energy efficiency initiatives. Idaho Power’s FCA mechanism mitigates some of the fluctuations caused by weather and energy efficiency initiatives.

Commercial Customers: Most businesses are included in Idaho Power's commercial customer class, as well as small industrial companies, and public street and highway lighting accounts. Idaho Power’s commercial customers are less influenced by weather conditions than residential customers, although weather does affect commercial customer energy use. Economic conditions, including manufacturing activity levels, and energy efficiency initiatives also affect energy use of commercial customers.

Industrial Customers: Industrial customers consist of large industrial companies, including special contract customers. Energy use of industrial customers is primarily driven by economic conditions, with weather having little impact on this customer class.

Irrigation Customers: Irrigation customers use electricity to operate irrigation pumps, primarily during the agricultural growing season. The amount and timing of precipitation as well as temperature levels can affect the timing and amounts of sales to irrigation customers with increased precipitation generally resulting in decreased sales.

Wholesale Energy Sales:As a public utility under the Federal Power Act (FPA), Idaho Power has the authority to charge market-based rates for wholesale energy sales under its FERC tariff. Idaho Power’s wholesale electricity sales are primarily to utilities and power marketers and are predominantly short-term and consist of a single performance obligation satisfied as energy is transferred to the counterparty. Idaho Power's wholesale energy sales depend largely on the availability of generation resources in excess of the amount necessary to serve customer loads as well as adequate market power prices at the time when those resources are available. A reduction in either factor may lead to lower wholesale energy sales.

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Transmission Services (Wheeling) Revenues: As a public utility under the FPA, Idaho Power has the authority to provide cost-based wholesale and retail access transmission services under its OATT. Services under the OATT are offered on a nondiscriminatory basis such that all potential customers have an equal opportunity to access the transmission system. Idaho Power’s transmission revenue is primarily related to third parties reserving capacity on Idaho Power’s transmission system to transmit electricity through Idaho Power’s service area. The reservations are predominantly short-term but may be ~~used~~part of a long-term capacity contract, short-term contract, or on demand when available. Transmission services revenues consist of a single performance obligation satisfied as capacity on Idaho Power’s transmission system is provided to the third party. Transmission service revenues are affected by changes in Idaho Power’s OATT transmission rate and customer demand. Demand for ~~general corporate purposes~~transmission services can be affected by regional market factors, such as loads and ~~commercial paper backup.~~generation of utilities in Idaho Power’s region.

Energy Efficiency Program Revenues: Idaho Power collects most of its energy efficiency program costs through an energy efficiency rider on customer bills. The ~~terms~~rider collections are deferred until expenditures are incurred. Energy efficiency program expenditures funded through the rider are reported as an operating expense with an equal amount recorded in revenues, resulting in no net impact on earnings. Energy efficiency program revenues are recognized in the period when the related costs of the energy efficiency program are incurred by Idaho Power. The cumulative variance between expenditures and ~~conditions of those credit facilities are~~amounts collected through the rider is recorded as ~~described in IDACORP's~~a regulatory asset or liability. 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 June 30, 2018, Idaho Power's ~~Annual Report on Form 10-K~~energy efficiency rider balances were a $2.6 million regulatory liability in the Idaho jurisdiction and a $6.5 million regulatory asset in the Oregon jurisdiction.

Alternative Revenue Programs and Other Revenues

While revenues from contracts with customers make up most of Idaho Power’s revenues, the IPUC has authorized the use of an additional regulatory mechanism, which may increase or decrease tariff-based rates billed to customers. The Idaho FCA mechanism, applicable to residential and small commercial customers, is designed to remove a portion of Idaho Power’s financial disincentive to invest in energy efficiency programs by separating (or decoupling) the recovery of fixed costs from the variable kilowatt-hour charge and linking it instead to a set amount per customer. Under Idaho Power's current rate design, recovery of a portion of fixed costs is included in the variable kilowatt-hour charge, which may result in overcollection or undercollection of fixed costs. To return overcollection to customers or to collect undercollection from customers, the FCA mechanism allows Idaho Power to accrue, or defer, the difference between the authorized fixed-cost recovery amount per customer and the actual fixed costs per customer recovered by Idaho Power during the year. Increases in FCA recovery are capped at 3 percent of base revenue annually, with any excess deferred for collection in a subsequent year.

The FCA mechanism revenues include only the initial recognition of FCA revenues when the regulator-specified conditions for recognition have been met. Revenue from contracts with customers excludes the portion of the tariff price representing FCA revenues that had been initially recorded in prior periods when regulator-specified conditions were met. When those amounts are included in the price of utility service and billed to customers, such amounts are recorded as recovery of the associated regulatory asset or liability and not as revenues.

The table below presents the FCA mechanism revenues and other revenues for the ~~year~~three and six months ended ~~December 31, 2016. At September~~June 30, 2018 and 2017 ~~no loans were outstanding under either~~ (in thousands):



	Three months ended June 30,				Six months ended June 30,
	2018		2017		2018		2017
Alternative revenue programs and other revenues:
FCA mechanism revenues	$	5,799	3,481		$	19,704	$	8,718
Derivative revenues	1,602		2,097		7,585		4,933
Total alternative revenue programs and other revenues	$	7,401	$	5,578	$	27,289	$	13,651

IDACORP's ~~or Idaho Power's credit facilities. At September 30, 2017,~~Other Revenues

IDACORP's other revenues are primarily comprised of revenues from IDACORP’s subsidiary, Ida-West. Ida-West operates small hydroelectric generation projects that satisfy the requirements of PURPA.

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5. LONG-TERM DEBT

In March 2018, Idaho Power ~~had regulatory authority to incur up to $450~~issued $220 million in principal amount of ~~short-term indebtedness at any one time outstanding.~~4.20 percent first mortgage bonds, secured medium-term notes, Series K, maturing on March 1, 2048. In April 2018, Idaho Power redeemed, prior to maturity, $130 million in principal amount of 4.50 percent first mortgage bonds, medium-term notes, Series H due March 2020. In accordance with the redemption provisions of the notes, the redemption included Idaho Power's payment of a make-whole premium to the holders of the redeemed notes in the aggregate amount of $4.6 million. Idaho Power used a portion of the net proceeds from the March 2018 sale of first mortgage bonds, medium-term notes to effect the redemption.

~~Balances (in thousands)~~As of June 30, 2018, $280 million in principal amount of long-term debt securities remained available for issuance under a selling agency agreement executed on September 27, 2016, 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 %
pursuant to state regulatory authority.

5.6. COMMON STOCK

IDACORP Common Stock

During the ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2018, IDACORP granted ~~72,397~~75,761 restricted stock unit awards to employees and ~~12,050~~12,950 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~~June 30, ~~2017,~~2018, 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~~June 30, ~~2017.~~2018. 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~~IDACORP and Idaho Power from any material subsidiary. At ~~September~~June 30, ~~2017,~~2018, IDACORP and Idaho Power were in compliance with ~~the~~those 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~~June 30, ~~2017,~~2018, Idaho Power's common equity capital was 54 percent of its total adjusted capital. Further, Idaho Power must obtain approval offrom 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~~FPA prohibits the payment of dividends from "capital accounts." The term "capital account" is undefined in the ~~Federal Power Act~~FPA or its regulations, but Idaho Power does not believe the restriction would limit Idaho Power's ability to pay dividends out of current year earnings or retained earnings.

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7. EARNINGS PER SHARE

The table below presents the computation of IDACORP’s basic and diluted earnings per share for the three and ~~nine~~six months ended ~~September~~June 30, ~~2017~~2018 and ~~2016~~2017 (in thousands, except for per share amounts).


	Three months ended September 30,				Nine months ended September 30,				Three months ended June 30,				Six months ended June 30,
	2017		2016		2017		2016		2018		2017		2018		2017
Numerator:
Net income attributable to IDACORP, Inc.	$	90,634	$	83,100	$	173,567	$	165,075	$	62,288	$	49,831	$	98,430	$	82,933
Denominator:
Weighted-average common shares outstanding - basic	50,362		50,296		50,361		50,299		50,435		50,363		50,430		50,361
Effect of dilutive securities	59		97		47		62		46		44		42		41
Weighted-average common shares outstanding - diluted	50,421		50,393		50,408		50,361		50,481		50,407		50,472		50,402
Basic earnings per share	$	1.80	$	1.65	$	3.45	$	3.28	$	1.24	$	0.99	$	1.95	$	1.65
Diluted earnings per share	$	1.80	$	1.65	$	3.44	$	3.28	$	1.23	$	0.99	$	1.95	$	1.65

7.8. COMMITMENTS

Purchase Obligations

IDACORP's and Idaho Power's purchase obligations did not change materially, outside of the ordinary course of business, during the ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2018, except that Idaho Power entered into agreements with solar ~~biomass,~~ and ~~hydroelectric~~biomass PURPA-qualifying facilities, which increased contractual payment obligations by approximately ~~$85~~$51 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~~$58.4 million at ~~September~~June 30, ~~2017,~~2018, representing IERCo's one-third share of BCC's total reclamation ~~obligation.~~obligation of $175.2 million. BCC has a reclamation trust fund set aside specifically for the purpose of paying these reclamation costs. At ~~September~~June 30, ~~2017,~~2018, the ~~total~~ value of BCC's reclamation trust fund was ~~$97~~$108.3 million. During the ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2018, the reclamation trust fund made no distributions of $3.0 million for reclamation activity costs associated with the BCC surface mine. BCC periodically assesses the adequacy of the reclamation trust fund and its estimate of future reclamation costs. To ensure that the reclamation trust fund maintains adequate reserves, BCC has the ability to, 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~~June 30, ~~2017,~~2018, 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.

8.9. CONTINGENCIES

IDACORP and Idaho Power have in the past and expect in the future to become involved in various claims, controversies, disputes, and other contingent matters, 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

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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.

9.10. 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~~June 30, ~~2017~~2018 and ~~2016~~2017 (in thousands).

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	Pension Plan						SMSP				Postretirement Benefits						Pension Plan						SMSP					Postretirement Benefits						Total
	2017			2016			2017		2016		2017			2016			2018			2017			2018			2017		2018			2017			2018			2017
Service cost	$	8,436		$	8,004		$	189	$	307	$	244		$	279		$	9,742		$	8,245		$	(79	)	$	190	$	242		$	197		$	9,905		$	8,632
Interest cost	9,739			9,453			1,079		1,069		695			692			9,683			9,716			1,061			1,079		656			702			11,400			11,497
Expected return on plan assets	(11,285		)	(10,519		)	—		—		(576		)	(619		)	(13,056		)	(11,181		)	—			—		(605		)	(584		)	(13,661		)	(11,765		)
Amortization of prior service cost	7			15			31		42		11			7			2			7			25			32		12			17			39			56
Amortization of net loss	3,298			3,332			742		883		—			—			3,394			3,212			947			740		—			—			4,341			3,952
Net periodic benefit cost	10,195			10,285			2,041		2,301		374			359			9,765			9,999			1,954			2,041		305			332			12,024			12,372
Regulatory deferral of net periodic benefit cost⁽¹⁾	(9,708		)	(9,826		)	—		—		—			—			(9,309		)	(9,488		)	—			—		—			—			(9,309		)	(9,488		)
Previously deferred pension costs recognized⁽¹⁾	4,288			4,288			—		—		—			—			4,289			4,289			—			—		—			—			4,289			4,289
Net periodic benefit cost recognized for financial reporting⁽¹⁾⁽²⁾	$	4,775		$	4,747		$	2,041	$	2,301	$	374		$	359		$	4,745		$	4,800		$	1,954		$	2,041	$	305		$	332		$	7,004		$	7,173

⁽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.

⁽²⁾ Of total net periodic benefit cost recognized for financial reporting, $4.1 million and $4.4 million, respectively, was recognized in "Other operations and maintenance" and $2.9 million and $2.8 million, respectively, was recognized in "Other expense, net" on the condensed consolidated statements of income of the companies for the three months ended June 30, 2018 and 2017.

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The following table ~~below~~ shows the components of net periodic benefit costs for the pension, SMSP, and postretirement benefits plans for the ~~nine~~six months ended ~~September~~June 30, 2018 and 2017 ~~and 2016~~ (in ~~thousands of dollars)~~thousands).


	Pension Plan						SMSP				Postretirement Benefits						Pension Plan						SMSP					Postretirement Benefits						Total
	2017			2016			2017		2016		2017			2016			2018			2017			2018			2017		2018			2017			2018			2017
Service cost	$	25,307		$	24,014		$	569	$	921	$	730		$	837		$	19,485		$	16,871		$	(158	)	$	380	$	526		$	486		$	19,853		$	17,737
Interest cost	29,217			28,360			3,236		3,206		2,087			2,075			19,365			19,479			2,124			2,157		1,322			1,392			22,811			23,028
Expected return on plan assets	(33,854		)	(31,560		)	—		—		(1,730		)	(1,856		)	(26,111		)	(22,569		)	—			—		(1,234		)	(1,154		)	(27,345		)	(23,723		)
Amortization of prior service cost	21			44			95		126		35			20			3			14			49			64		24			24			76			102
Amortization of net loss	9,893			9,998			2,223		2,649		—			—			6,788			6,595			1,894			1,481		—			—			8,682			8,076
Net periodic benefit cost	30,584			30,856			6,123		6,902		1,122			1,076			19,530			20,390			3,909			4,082		638			748			24,077			25,220
Regulatory deferral of net periodic benefit cost⁽¹⁾	(28,991		)	(29,508		)	—		—		—			—			(18,616		)	(19,284		)	—			—		—			—			(18,616		)	(19,284		)
Previously deferred pension costs recognized⁽¹⁾	12,865			12,865			—		—		—			—			8,577			8,577			—			—		—			—			8,577			8,577
Net periodic benefit cost recognized for financial reporting⁽¹⁾⁽²⁾	$	14,458		$	14,213		$	6,123	$	6,902	$	1,122		$	1,076		$	9,491		$	9,683		$	3,909		$	4,082	$	638		$	748		$	14,038		$	14,513

⁽²⁾ Of total net periodic benefit cost recognized for financial reporting, $8.2 million and $8.9 million, respectively, was recognized in "Other operations and maintenance" and $5.8 million and $5.6 million, respectively, was recognized in "Other expense, net" on the condensed consolidated statements of income of the companies for the six months ended June 30, 2018 and 2017.

Idaho Power has no minimum contribution requirement to its defined benefit pension plan in ~~2017.~~2018. However, during the ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2018, Idaho Power made ~~$40~~$20 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.~~11. DERIVATIVE FINANCIAL INSTRUMENTS

Commodity Price Risk

Idaho Power is exposed to market risk relating to electricity, natural gas, and other fuel commodity prices, all of which are heavily influenced by supply and demand. Market risk may be influenced by market participants’ nonperformance of their contractual obligations and commitments, which affects the supply of or demand for the commodity. Idaho Power uses derivative instruments, such as physical and financial forward contracts, for both electricity and fuel to manage the risks relating to these commodity price exposures. The primary objectives of Idaho Power’s energy purchase and sale activity are to meet the demand of retail electric customers, maintain appropriate physical reserves to ensure reliability, and make economic use of temporary surpluses that may develop.

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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.

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The table below presents the gains and losses on derivatives not designated as hedging instruments for the three and ~~nine~~six months ended ~~September~~June 30, ~~2017~~2018 and ~~2016~~2017 (in thousands).


			Gain/(Loss) on Derivatives Recognized in Income⁽¹⁾																	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,							Location of Realized Gain/(Loss) on Derivatives Recognized in Income		Three months ended June 30,								Six months ended June 30,
		2017				2016				2017				2016					2018				2017				2018				2017
Financial swaps		Off-system sales		$	(309	)		$	(16	)		$	864			$	1,379		Operating revenues		$	27			$	(305	)		$	266			$	1,173
Financial swaps	Purchased power		904				710				169				861			Purchased power		13				(287		)		(189		)		(735		)
Financial swaps	Fuel expense		883				(657		)		1,549				(3,099		)	Fuel expense		(112		)		(4		)		(800		)		666
Financial swaps	Other operations and maintenance		(45		)		(16		)		(126		)		(166		)	Other operations and maintenance		31				(55		)		38				(81		)
Forward contracts	Purchased power		(3		)		24				(13		)		24			Operating revenues		—				—				2				—
Forward contracts	Fuel expense		—				49				3				139			Purchased power		(7		)		(8		)		(20		)		(10		)
Forward contracts																		Fuel expense		10				3				24				3

⁽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~~revenues from contracts with customers 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 1112 - "Fair Value Measurements" 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~~June 30, ~~2017,~~2018, and December 31, ~~2016~~2017 (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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		Asset Derivatives							Liability Derivatives
	Balance Sheet Location	Gross Fair Value		Amounts Offset			Net Assets		Gross Fair Value		Amounts Offset				Net Liabilities
	Balance Sheet Location	Gross Fair Value		Amounts Offset			Net Assets		Gross Fair Value		Amounts Offset				Net Liabilities
June 30, 2018
Current:
Financial swaps	Other current assets	$	1,545	$	(791	)	$	754	$	791	$	(791	)		$	—
Financial swaps	Other current liabilities	195		(195		)	—		1,051		(195		)		856
Forward contracts	Other current assets	3		—			3		—		—				—
Long-term:
Financial swaps	Other assets	49		(1		)	48		1		(1		)		—
Financial swaps	Other liabilities	15		(15		)	—		354		(15		)		339
Total		$	1,807	$	(1,002	)	$	805	$	2,197	$	(1,002	)		$	1,195
December 31, 2017
Current:
Financial swaps	Other current assets	$	18	$	—		$	18	$	—	$	—			$	—
Financial swaps	Other current liabilities	553		(553		)	—		1,971		(748		)	⁽¹⁾	1,223
Forward contracts	Other current liabilities	—		—			—		2		—				2
Long-term:
Financial swaps	Other assets	4		—			4		—		—				—
Total		$	575	$	(553	)	$	22	$	1,973	$	(748	)		$	1,225

⁽¹⁾ ~~Long-term~~Current liability derivative amount offset includes ~~$0.1~~$0.2 million of collateral receivable for the period ended ~~September 30,~~December 31, 2017.

⁽²⁾ ~~Current asset derivative amount offset includes $1.9 million~~

Table of ~~collateral payable for the period ended December 31, 2016.~~Contents

The table below presents the volumes of derivative commodity forward contracts and swaps outstanding at ~~September~~June 30, ~~2017~~2018 and ~~2016~~2017 (in thousands of units).


		September 30,			June 30,
Commodity	Units	2017	2016	Units	2018	2017
Electricity purchases	MWh	122	130	MWh	323	194
Electricity sales	MWh	162	143	MWh	58	38
Natural gas purchases	MMBtu	7,975	7,977	MMBtu	12,371	10,297
Natural gas sales	MMBtu	230	70	MMBtu	233	75
Diesel purchases	Gallons	304	267	Gallons	451	605

Credit Risk

At ~~September~~June 30, ~~2017,~~2018, 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~~June 30, ~~2017~~2018 was ~~$1.3~~$2.2 million. Idaho Power posted ~~$0.4~~$0.8 million cash collateral related to this amount. If the credit-risk-related contingent features underlying these agreements were triggered on ~~September~~June 30, ~~2017,~~2018, Idaho Power would have been required to pay or post collateral to its counterparties up to an additional ~~$4.7~~$3.0 million to cover the open liability positions as well as completed transactions that have not yet been paid.

~~11.~~12. FAIR VALUE MEASUREMENTS

IDACORP and Idaho Power have categorized their financial instruments into a three-level fair value hierarchy, based on the priority of the inputs to the valuation technique. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). If the inputs used to measure the financial instruments fall within different levels of the hierarchy, the categorization is based on the lowest level input that is significant to the fair value measurement of the instrument.

Financial assets and liabilities recorded on the condensed consolidated balance sheets are categorized based on the inputs to the valuation techniques as follows:

• Level 1: Financial assets and liabilities whose values are based on unadjusted quoted prices for identical assets or liabilities in an active market that IDACORP and Idaho Power 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.

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

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~~six months ended ~~September~~June 30, ~~2017.~~2018.

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~~June 30, ~~2017,~~2018, and December 31, ~~2016~~2017 (in thousands).


	September 30, 2017								December 31, 2016								June 30, 2018								December 31, 2017
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets:
Money market funds
IDACORP(1)	$	—	$	—	$	—	$	—	$	15,000	$	—	$	—	$	15,000	$	30,611	$	—	$	—	$	30,611	$	28,038	$	—	$	—	$	28,038
Idaho Power	45,495		—		—		45,495		29,967		—		—		29,967		80,593		—		—		80,593		10,260		—		—		10,260
Derivatives	133		3		—		136		5,951		—		—		5,951		802		3		—		805		22		—		—		22
Trading securities: Equity securities	84		—		—		84		111		—		—		111
Available-for-sale securities: Equity securities	23,475		—		—		23,475		23,908		—		—		23,908
Equity securities																	27,916		—		—		27,916		30,266		—		—		30,266
Liabilities:
Derivatives	816		—		—		816		—		—		—		—		1,195		—		—		1,195		1,223		2		—		1,225

⁽¹⁾ Holding company only. Does not include amounts held by Idaho Power.

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~~Intercontinental Exchange pricing, adjusted for location basis, which are also quoted under NYMEX and ICE pricing. ~~Trading~~Equity 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,~~plan and ~~are~~ actively traded money market and exchange traded funds ~~with~~related to the SMSP. The investments are measured using quoted prices in active ~~markets.~~markets and are held in a Rabbi trust.

The table below presents the carrying value and estimated fair value of financial instruments that are not reported at fair value, as of ~~September~~June 30, ~~2017,~~2018, and December 31, ~~2016,~~2017, using available market information and appropriate valuation methodologies (in thousands).


	September 30, 2017				December 31, 2016				June 30, 2018				December 31, 2017
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
IDACORP
Assets:
Notes receivable⁽¹⁾	$	3,804	$	3,804	$	3,804	$	3,804	$	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		1,834,055		1,946,794		1,746,123		1,915,459
Idaho Power
Liabilities:
Long-term debt⁽¹⁾	1,745,746		1,906,113		1,745,678		1,858,666		1,834,055		1,946,794		1,746,123		1,915,459

⁽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.~~12.

Notes receivable are related to Ida-West and are valued based on unobservable inputs, including discounted cash flows, which are partially based on forecasted hydroelectric conditions. Long-term debt is not traded on an exchange and is valued using

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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.

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~~12.~~

13. SEGMENT INFORMATION

IDACORP’s only reportable segment is utility operations. The utility operations segment’s primary source of revenue is the regulated operations of Idaho Power. Idaho Power’s regulated operations include the generation, transmission, distribution, purchase, and sale of electricity. This segment also includes income from IERCo, a wholly-owned subsidiary of Idaho Power that is also subject to regulation and is a one-third owner of BCC, an unconsolidated joint venture.

IDACORP’s other operating segments are below the quantitative and qualitative thresholds for reportable segments and are included in the "All Other" category in the table below. This category is comprised of IFS’s investments in affordable housing developments 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		Utility Operations		All Other		Eliminations			Consolidated Total
Three months ended September 30, 2017:
Three months ended June 30, 2018:
Revenues	$	406,655	$	1,669	$	—		$	408,324	$	338,699	$	1,253	$	—		$	339,952
Net income attributable to IDACORP, Inc.	88,329		2,305		—			90,634		60,637		1,651		—			62,288
Total assets as of September 30, 2017	6,321,917		116,718		(71,452		)	6,367,183
Three months ended September 30, 2016:
Total assets as of June 30, 2018										6,133,502		153,529		(80,914		)	6,206,117
Three months ended June 30, 2017:
Revenues	$	371,474	$	571	$	—		$	372,045	$	331,768	$	1,238	$	—		$	333,006
Net income attributable to IDACORP, Inc.	80,029		3,071		—			83,100		48,381		1,450		—			49,831
Nine months ended September 30, 2017:
Six months ended June 30, 2018:
Revenues	$	1,040,387	$	3,487	$	—		$	1,043,874	$	648,160	$	1,898	$	—		$	650,058
Net income attributable to IDACORP, Inc.	169,192		4,375		—			173,567		96,493		1,937		—			98,430
Nine months ended September 30, 2016:
Six months ended June 30, 2017:
Revenues	$	966,451	$	1,986	$	—		$	968,437	$	633,732	$	1,818	$	—		$	635,550
Net income attributable to IDACORP, Inc.	160,370		4,705		—			165,075		80,863		2,070		—			82,933

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~~13.~~14. CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME

The table below presents changes in components of accumulated other comprehensive income (AOCI), net of tax, during the three and ~~nine~~six months ended ~~September~~June 30, ~~2017~~2018 and ~~2016~~2017 (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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	Defined Benefit Pension Items
	Three months ended June 30,						Six months ended June 30,
	2018			2017			2018			2017
Balance at beginning of period	$	(30,243	)	$	(20,411	)	$	(30,964	)	$	(20,882	)
Amounts reclassified out of AOCI	722			470			1,443			941
Balance at end of period	$	(29,521	)	$	(19,941	)	$	(29,521	)	$	(19,941	)

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~~six months ended ~~September~~June 30, ~~2017~~2018 and ~~2016~~2017 (in thousands). Items in parentheses indicate increases to net income.


	Amount Reclassified from AOCI												Amount Reclassified from AOCI
Details About AOCI	Three months ended September 30,						Nine months ended September 30,						Three months ended June 30,						Six months ended June 30,
	2017			2016			2017			2016			2018			2017			2018			2017
Amortization of defined benefit pension items⁽¹⁾
Prior service cost	$	31		$	42		$	95		$	126		$	25		$	32		$	49		$	64
Net loss	742			883			2,223			2,649			947			740			1,894			1,481
Total before tax	773			925			2,318			2,775			972			772			1,943			1,545
Tax benefit⁽²⁾	(302		)	(362		)	(906		)	(1,085		)	(250		)	(302		)	(500		)	(604		)
Net of tax	471			563			1,412			1,690			722			470			1,443			941
Total reclassification for the period	$	471		$	563		$	1,412		$	1,690		$	722		$	470		$	1,443		$	941

⁽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 shareholders and the Board of Directors ~~and Shareholders~~ of

IDACORP, Inc.

~~Boise, Idaho~~

Results of Review of Interim Financial Information

We have reviewed the accompanying condensed consolidated balance sheet of IDACORP, Inc. and subsidiaries (the “Company”) as of ~~September~~June 30, ~~2017~~2018, and the related condensed consolidated statements of income and comprehensive income for the three-month and ~~nine-month~~six-month periods ended ~~September~~June 30, ~~2017~~2018 and ~~2016~~,2017 and of equity and cash flows for the ~~nine-month~~six-month periods ended ~~September~~June 30, ~~2017~~2018 and ~~2016~~2017, and the related notes (collectively referred to as the "interim financial information"). ~~These~~Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial ~~statements are~~information for it to be in conformity with accounting principles generally accepted in the ~~responsibility~~United States of ~~the Company’s management.~~America.

We ~~conducted our reviews~~have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States). (PCAOB), the consolidated balance sheet of the Company as of December 31, 2017, 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 22, 2018, 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, 2017, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

Basis for Review Results

This interim financial information is the responsibility of the Company’s management. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our reviews in accordance with the standards of the PCAOB. 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),~~PCAOB, 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.

/s/ DELOITTE & TOUCHE LLP

Boise, Idaho

August 2, 2018

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the shareholder and the Board of Directors of Idaho Power Company

Results of Review of Interim Financial Information

We have reviewed the accompanying condensed consolidated balance sheet of Idaho Power Company and subsidiary (the “Company”) as of June 30, 2018, the related condensed consolidated statements of income and comprehensive income for the three-month and six-month periods ended June 30, 2018 and 2017 and cash flows for the six-month periods ended June 30, 2018 and 2017, and the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of any material modifications that should be made to ~~such condensed consolidated~~the accompanying interim financial ~~statements~~information for ~~them~~it 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) (PCAOB), the consolidated balance sheet of ~~IDACORP, Inc. and subsidiaries~~the Company as of December 31, ~~2016~~,2017, and the related consolidated statements of income, comprehensive income, ~~equity,~~retained earnings and cash flows for the year then ended (not presented herein); and in our report dated February ~~23, 2017,~~22, 2018, 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~~2017, 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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Basis for Review Results

~~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. TheseThis interim financial ~~statements are~~information is the responsibility of the Company’s management. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our reviews in accordance with the standards of the ~~Public Company Accounting Oversight Board (United States).~~PCAOB. 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),~~PCAOB, 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~~August 2, ~~2017~~2018

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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,~~2017, 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.~~Power (Jim Bridger plant). 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,~~2017, IDACORP's and Idaho Power's management included a brief overview of their ~~outlook~~initiatives and ~~initiatives~~strategies for the companies for ~~2017~~2018 and beyond, under the ~~headings~~heading "Executive Overview - ~~Management's Outlook"~~2018 Initiatives and ~~"2016 Accomplishments and 2017 Initiatives"~~Strategy" in the MD&A. As of the date of this report, management's outlook ~~remains~~and strategy remain 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~~six months of ~~2017,~~2018, Idaho Power's customer count grew by approximately ~~7,400~~5,700 customers, and for the twelve months ended ~~September~~June 30, ~~2017,~~2018, the customer growth rate was ~~1.8~~2.2 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~~anticipates substantial capital investments, with expected total capital expenditures of approximately $1.5 billion over the five-year period from ~~2017~~2018 (including the expenditures incurred so far in ~~2017)~~2018) through ~~2021.~~2022.

Idaho Power continues to execute on ~~three core focuses for 2017 -~~its four strategic areas: growing to enhance financial strength, improving Idaho Power's core business, ~~growing revenues,~~enhancing Idaho Power’s brand, and ~~positioning the company for the future through enhancing its brand.~~focusing on safety and employee engagement.

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.

During the first six months of 2018, Idaho Power reached various regulatory settlements that were approved by the IPUC and OPUC. These approved settlements related to recent income tax reform, the indefinite extension, with modifications, of the current earnings support and sharing mechanism, the prudence of certain Hells Canyon Complex (HCC) relicensing costs, and the treatment of costs incurred to join the energy imbalance market implemented in the western United States (Western EIM). In May 2018, the IPUC issued an order authorizing the creation of new customer classes for customers with on-site generation, and in June 2018, the IPUC issued an order requiring further investigation to resolve eligibility issues for the new

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customer classes. Idaho Power believes that these regulatory actions are positive outcomes as they reduce future uncertainty for both shareholders and customers. Refer to "Regulatory Matters" in this MD&A for more information on the related regulatory proceedings.

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 six months ended June 30, 2018 and 2017 (in thousands, except earnings per share amounts):



	Three months ended June 30,				Six months ended June 30,
	2018		2017		2018		2017
Idaho Power net income	$	60,637	$	48,381	$	96,493	$	80,863
Net income attributable to IDACORP, Inc.	$	62,288	$	49,831	$	98,430	$	82,933
Average outstanding shares – diluted	50,481		50,407		50,472		50,402
IDACORP, Inc. earnings per diluted share	$	1.23	$	0.99	$	1.95	$	1.65

The table below provides a reconciliation of net income attributable to IDACORP for the three and six months ended June 30, 2018, from the same periods in 2017 (items are in millions and are before related income tax impact unless otherwise noted).



	Three months ended				Six months ended
Net income attributable to IDACORP, Inc. - June 30, 2017			$	49.8			$	82.9
Increase (decrease) in Idaho Power net income:
Customer growth, net of associated power supply costs and power cost adjustment mechanisms	1.8				4.2
Usage per retail customer, net of associated power supply costs and power cost adjustment mechanisms	4.7				(6.9	)
Idaho fixed cost adjustment (FCA) revenues	2.3				11.0
Retail revenues per megawatt-hour (MWh), net of associated power supply costs and power cost adjustment mechanisms	(6.8	)			(9.4	)
Transmission services (wheeling) and other revenues	1.3				4.0
Other operations and maintenance (O&M) expense	(5.6	)			(4.8	)
Depreciation expense	3.9				0.6
Other changes in operating revenues and expenses, net	(0.7	)			(1.1	)
Increase (decrease) in Idaho Power operating income	0.9				(2.4	)
Earnings of equity-method investments	1.0				3.9
Non-operating income and expenses	0.7				1.2
Additional accumulated deferred investment tax credits (ADITC) amortization	1.4				—
Tax benefit from make-whole premium for early bond redemption	1.3				1.3
Income tax expense (excluding additional ADITC amortization and tax benefit from early bond redemption)	7.0				11.6
Total increase in Idaho Power net income			12.3				15.6
Other IDACORP changes (net of tax)			0.2				(0.1		)
Net income attributable to IDACORP, Inc. - June 30, 2018			$	62.3			$	98.4

Net Income - Second Quarter 2018

IDACORP's net income increased $12.5 million for the second quarter of 2018 compared with the second quarter of 2017, primarily due to higher net income at Idaho Power.

Customer growth increased operating income by $1.8 million in the second quarter of 2018 compared with the second quarter of 2017, as the number of Idaho Power customers grew by 2.2 percent during the twelve months ended June 30, 2018. Sales volumes on a per-customer basis also increased operating income by $4.7 million in the second quarter of 2018 compared with

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the second quarter of 2017. Precipitation in Idaho Power's service area was near normal in the second quarter of 2018, but was significantly less than precipitation in the second quarter of 2017. This resulted in a 15 percent increase in usage per agricultural irrigation customer, who use electricity to operate irrigation pumps. The increase in sales volumes to irrigation customers was partially offset by a decrease in usage per residential customer as milder temperatures in the second quarter of 2018 compared with the second quarter of 2017 caused residential customers to use less electricity for cooling and heating. The decrease in residential sales volumes was partially offset by the FCA mechanism, which increased revenues by $2.3 million during the second quarter of 2018 compared with the second quarter of 2017.

The net decrease in retail revenues per MWh decreased operating income by $6.8 million in the second quarter of 2018 compared with the second quarter of 2017. The settlement stipulations approved by the IPUC and OPUC during the second quarter of 2018 relating to recent income tax reform (discussed in more detail below), reduced revenues in the second quarter of 2018. 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 Idaho Power’s jointly-owned North Valmy coal-fired power plant (Valmy Plant) by the end of 2025. The Valmy Plant settlement stipulations provided for an accrual of six months of the increase in retail revenues, depreciation expense, and associated income tax expense in the second quarter of 2017, resulting in a decrease in these items in the second quarter of 2018 compared with the same period in 2017.

Other O&M expenses were $5.6 million higher in the second quarter of 2018 compared with the second quarter of 2017. As provided by the settlement stipulation approved by the IPUC related to income tax reform, O&M expenses in the second quarter of 2018 included $1.1 million of non-cash amortization expense of regulatory deferrals that would otherwise be a future liability of Idaho customers. Also, transmission and distribution asset maintenance expense increased $0.9 million in the second quarter of 2018 compared with 2017 due to higher maintenance service costs. Labor and benefit costs increased $3.1 million, primarily related to the timing of accruals for variable employee-related costs which resulted in earlier recognition of expense in the second quarter of 2018 compared with 2017.

Depreciation expense was $3.9 million lower in the second quarter of 2018 compared with the second quarter of 2017, due mostly to the effect of recognizing six months of the accelerated depreciation during the second quarter of 2017 as provided by the 2017 Valmy Plant settlement stipulation described above. This decrease was partially offset by higher depreciation expense from an increase in electric plant in service.

Idaho Power income tax expense, excluding additional ADITC amortization and the $1.3 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 April 2018, decreased $7.0 million in the second quarter of 2018 compared with the second quarter of 2017, due primarily to the lower federal and state statutory income tax rates resulting from income tax reform discussed in further detail below. In addition, the Valmy Plant settlement stipulation described above increased income tax expense in the second quarter of 2017. Idaho Power reversed $0.5 million of previously recorded additional ADITC amortization under its Idaho regulatory settlement stipulation during the second quarter of 2018, compared with a reversal of $1.9 million during the second quarter of 2017. Based on Idaho Power's current expectations of full-year 2018 results, Idaho Power does not expect to record additional ADITC amortization in 2018.

Net Income - Year-to-Date 2018

IDACORP's net income increased $15.5 million for the first half of 2018 compared with the same period in 2017, primarily due to higher net income at Idaho Power. Customer growth added $4.2 million to Idaho Power operating income, compared with the first half of 2017. Lower usage per residential customer in the first six months of 2018 reduced operating income by $6.9 million, due primarily to milder temperatures, compared with the first six months of 2017. The lower residential customer usage was partially offset by higher usage per irrigation customer in the second quarter of 2018, due to lower precipitation, compared with the same period in 2017. However, due to the lower usage by residential customers, the FCA mechanism added $11.0 million to operating income during the first six months of 2018, compared with the first six months of 2017.

The net decrease in retail revenues per MWh decreased operating income by $9.4 million in the first six months of 2018 compared with the same period in 2017. The settlement stipulations approved by the IPUC and OPUC during the second quarter of 2018 relating to recent income tax reform (discussed in more detail below) reduced revenue in the first six months of 2018.

During the first six months of 2018, Idaho Power benefited from a $4.0 million increase in third-party use of electric property, wheeling, and other revenue, compared with the first six months of 2017. This change was largely due to an increase in Idaho Power's open access transmission tariff (OATT) rates that became effective in October 2017.

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Other O&M expenses were $4.8 million higher in the first six months of 2018 compared with the first six months of 2017. As noted above, related to recent income tax reform regulatory settlements, O&M expenses in the first six months of 2018 included $1.1 million of non-cash amortization expense of regulatory deferrals that would otherwise be a future liability of Idaho customers. Also, transmission and distribution asset maintenance expense increased $2.0 million in the second quarter of 2018 compared with the first half of 2017 due to higher maintenance service costs. Labor and benefit costs increased $1.7 million primarily related to the timing of accruals for variable employee-related costs, which resulted in earlier recognition of expense in the first six months of 2018 compared with 2017.

Idaho Power's income tax expense, excluding the $1.3 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 April 2018, was $11.6 million lower during the first six months of 2018 compared with the first six months of 2017, due mostly to the lower federal and state statutory income tax rates resulting from income tax reform discussed in further detail below.

Overview of General Factors and Trends Affecting Results of Operations and Financial Condition

IDACORP's and Idaho Power's results of operations and financial condition are affected by a number of factors, and the impact of those factors is discussed in more detail ~~later~~below in this MD&A. To provide context for the discussion elsewhere in this report, some of the more notable factors ~~include~~are summarized below:

Income Tax Reform: In December 2017, the ~~following:~~Tax Cuts and Jobs Act was signed into law, which lowered the corporate federal income tax rate from 35 percent to 21 percent and modified or eliminated certain federal income tax deductions for corporations. The majority of the changes, including the rate reduction, became effective on January 1, 2018. In March 2018, Idaho House Bill 463 was signed into law reducing the Idaho state corporate income tax rate from 7.4 percent to 6.925 percent. In May 2018, the IPUC issued an order approving a settlement stipulation (May 2018 Idaho Tax Reform Settlement Stipulation) related to income tax reform. Beginning June 1, 2018, the settlement stipulation provides an annual (a) $18.7 million reduction to Idaho customer base rates and (b) $7.4 million amortization of existing regulatory deferrals for specified items or future amortization of other existing or future unspecified regulatory deferrals that would otherwise be a future liability recoverable from Idaho customers. Additionally, a one-time benefit of a $7.8 million rate reduction is being provided to Idaho customers through the Idaho-jurisdiction power cost adjustment (PCA) mechanism during the period from June 1, 2018, through May 31, 2019, for the income tax reform benefits accrued from January 1, 2018 to May 31, 2018, and the income tax reform benefits related to Idaho Power's OATT. The amount provided via the PCA mechanism will decrease to $2.7 million on June 1, 2019, for income tax reform benefits related to Idaho Power's OATT and will cease on June 1, 2020, to reflect the impact of a full year of reduced OATT third-party transmission revenues. The May 2018 Idaho Tax Reform Settlement Stipulation was designed to return to Idaho customers their share of the estimated annual pro forma tax expense reductions resulting from income tax reform, based on the full-year 2017 as required by the IPUC. Idaho Power financial results from 2018 forward will be affected by any differences between annual income tax expense and the pro forma 2017 income tax expense used in the settlement until affected by a future rate proceeding or rate case. The May 2018 Idaho Tax Reform Settlement Stipulation also provides for the indefinite extension of the October 2014 Idaho Earnings Support and Sharing Settlement Stipulation beyond its termination date of December 31, 2019. Refer to "Regulatory Matters" in this MD&A for more information on the related regulatory proceedings.

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~~its regulators, working to put in place innovative regulatory mechanisms, and on the prudent management of expenses and investments. Idaho Power currently has a regulatory settlement stipulation in Idaho that includes provisions for the ~~additional~~accelerated amortization of ~~accumulated deferred investment~~certain tax credits ~~(ADITC)~~ to help achieve a minimum 9.5 percent ~~return on year-end equity in~~Idaho ROE. The settlement stipulation also provides for the ~~Idaho jurisdiction (Idaho ROE).~~potential sharing between Idaho Power ~~continues~~and customers of Idaho-jurisdictional earnings in excess of specified levels of Idaho ROE. In May 2018, the IPUC approved an Idaho settlement stipulation that provides for the indefinite extension of the current mechanism with the modification of certain terms, which are described in "Regulatory Matters" in this MD&A and in Note 3 - "Regulatory Matters" to the condensed consolidated financial statements included in this report. During 2018, Idaho Power will continue to assess the need to file ~~and the timing of~~ a general rate case to reset base rates, but does not anticipate filing a rate case in ~~Idaho and Oregon to change base rates.~~the next twelve months.

Economic Conditions and Loads: Economic conditions impact consumer demand for ~~electricity and~~energy, revenues, collectability of accounts, the volume of ~~off-system~~wholesale energy sales, and the need to construct and improve infrastructure, purchase

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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~~June 30, ~~2017,~~2018, Idaho Power's customer count grew by ~~1.8~~2.2 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~~3.2 percent ~~over~~during the twelve months ended ~~September~~June 30, ~~2017,~~2018, based on Idaho Department of Labor preliminary ~~September 2017~~June 2018 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.

Idaho Power’s system is dual peaking, with the larger peak demand occurring in the summer. On July 9, 2018, Idaho Power reached its highest system peak demand so far in 2018 of 3,392 MW, which was 30 MW below the all-time system peak demand. The all-time system peak demand was 3,422 MW, set on July 7, 2017.

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.~~resources. 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		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)	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%	1.1%	1.6%	0.9%	1.4%
2015 IRP	1.1%	1.5%	1.1%	1.4%	1.1%	1.5%	1.1%	1.4%
2013 IRP	1.2%	1.5%	1%	1.3%	1.2%	1.5%	1.0%	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)~~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~~wholesale energy 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,~~2018, Idaho Power expects generation from its hydroelectric resources to be in the range of ~~8.5~~8.0 to 9.0 million MWh, compared with 20-year average annual hydroelectric generation of 7.6 million MWh. ~~Under median water conditions,~~

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 and certain other assets, subject to various adjustments for deferred taxes and other items. Over time, rate base is increased by additions to utility plant in service and reduced by depreciation and retirement of utility plant and write-offs as authorized by the IPUC and OPUC. In recent years, Idaho Power has been pursuing significant enhancements to its utility infrastructure, including major ongoing transmission projects such as the Boardman-to-Hemingway and Gateway West projects, in an effort to ensure an adequate supply of electricity, to provide service to new customers, and to maintain system reliability. Idaho Power's existing hydroelectric and thermal generation facilities ~~would currently provide annual~~also require continuing upgrades and component replacement, and the company is undertaking a significant relicensing effort for the 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

Table of ~~approximately 8.4 million MWh.~~Contents

the regulatory process and items 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.

Mitigation of Impact of Fuel and Purchased Power Expense: In addition to hydroelectric generation, Idaho Power relies significantly on ~~coal~~natural gas and ~~natural gas~~coal 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,~~Recently, low natural gas prices have made operation of Idaho Power's natural gas power plants more economical, resulting in increased operation of those plants and decreased operation of coal-fired plants. 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:~~Costs: Idaho Power is subject to extensive federal and state laws, policies, and regulations, as well as regulatory actions and audits by agencies and quasi-governmental agencies, including the FERC, ~~and~~ the North American Electric Reliability ~~Corporation.~~Corporation, and the Western Electricity Coordinating Council. 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~~expects to spend a ~~10-percent interest, is scheduled to cease coal-fired operations by~~considerable amount on environmental compliance and controls in 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.next decade.

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~~are expected to continue to be substantial. ~~As of the date of this report,~~ Idaho Power cannot currently 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~~six months ended ~~September~~June 30, ~~2017.~~2018. In this analysis, the results for the three and ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2018, are compared with the same ~~periods~~period in ~~2016.~~2017.

~~Utility Operations~~

The table below presents Idaho Power’s energy sales and supply (in thousands of MWh) for the three and ~~nine~~six months ended ~~September~~June 30, ~~2017~~2018 and ~~2016.~~2017.


	Three months ended September 30,				Nine months ended September 30,				Three months ended June 30,				Six months ended June 30,
	2017		2016		2017		2016		2018		2017		2018		2017
General business sales	4,438		4,156		11,309		10,933
Off-system sales	216		224		1,806		837
Retail energy sales									3,576		3,464		6,822		6,872
Wholesale energy sales									821		751		1,681		1,439
Bundled energy sales									73		85		297		151
Total energy sales	4,654		4,380		13,115		11,770		4,470		4,300		8,800		8,462
Hydroelectric generation	1,991		1,331		7,169		5,191		2,847		2,815		5,571		5,177
Coal generation	1,236		1,487		2,578		2,961		459		505		1,067		1,342
Natural gas and other generation	665		712		1,067		1,557		124		68		228		399
Total system generation	3,892		3,530		10,814		9,709		3,430		3,388		6,866		6,918
Purchased power	1,115		1,164		3,269		2,951		1,383		1,246		2,572		2,154
Line losses	(353	)	(314	)	(968	)	(890	)	(343	)	(334	)	(638	)	(610	)
Total energy supply	4,654		4,380		13,115		11,770		4,470		4,300		8,800		8,462

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Sales Volume and Generation: In the ~~third~~second quarter of ~~2017, general business~~2018, retail 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~~112 thousand MWh, or 3 percent, compared with the second quarter of 2017. During the first ~~nine~~six months of ~~the prior year. Cooling degree days for the three and nine months ended September 30, 2017, were 53~~2018, retail sales volumes decreased 50 thousand MWh, or 1 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~~compared with the same period in ~~2016, which increased~~ the ~~use of electricity for heating purposes. In addition, customer~~prior year. Customer growth ~~contributed to~~ increased sales volumes ~~in 2017~~during the three and six months ended June 30, 2018 compared with ~~2016,~~the same periods in 2017, with the number of Idaho Power's customers growing by ~~1.8~~2.2 percent over the prior twelve months. ~~Usage~~During the second quarter of 2018, usage per irrigation customer was approximately 1115 percent ~~lower in the first nine months of 2017~~higher compared with the same period in ~~2016, as precipitation~~2017. Precipitation in the Idaho Power service area during the ~~nine~~three months ended ~~September~~June 30, ~~2017,~~2018 was significantly ~~higher~~less than in the same ~~periods~~period of ~~2016,~~2017, which ~~reduced~~increased usage by irrigation ~~customers, particularly~~customers. Usage per residential customer was approximately 4 percent and 8 percent lower in the second quarter and the first six months of 2018, respectively, compared with the second quarter and first six months of 2017. The decrease in residential usage was primarily due to more moderate weather during the first six months of 2018 compared with the first six months of 2017, which decreased the use of electricity for heating and cooling purposes. Heating degree-days were 16 percent lower during the six months ended June 30, 2018 compared with the six months ended June 30, 2017, and 13 percent below normal during the six months ended June 30, 2018.

~~Off-system~~Wholesale energy sales volumes increased 70 thousand MWh, or 9 percent, and 242 thousand MWh, or 17 percent, in the ~~third~~second quarter and first six months of ~~2017 were relatively flat~~2018, respectively, compared with the ~~third~~second quarter and first six months of ~~2016, as~~2017, due primarily to an increase in hydroelectric generation ~~supported the increased general business sales,~~and purchased power resulting in ~~a consistent amount of~~increased 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 morewholesale energy ~~available for off-system~~ sales. For the ~~third~~second quarter and first ~~nine~~six months of ~~2017,~~2018, hydroelectric generation comprised 5183 percent and 6681 percent of Idaho Power's total system generation, respectively, compared with 3883 percent and 5375 percent, respectively, for the ~~third~~second quarter and first ~~nine~~six months of ~~2016.~~2017. Generation from Idaho Power's hydroelectric plants increased due to ~~significantly greater precipitation~~strong reservoir storage attributable to above-normal snowpack from 2017 and near-normal snowpack 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 2016.2018.

The financial impacts of fluctuations in ~~off-system~~wholesale energy 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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Operating Revenues

~~General Business~~Retail Revenues: The table below presents Idaho Power’s ~~general business~~retail revenues (in thousands) and MWh sales volumes (in thousands) for the three and ~~nine~~six months ended ~~September~~June 30, ~~2017~~2018 and ~~2016,~~2017, and the number of customers as of ~~September~~June 30, ~~2017~~2018 and ~~2016.~~2017.


	Three months ended September 30,						Nine months ended September 30,						Three months ended June 30,						Six months ended June 30,
	2017			2016			2017			2016			2018			2017			2018			2017
Revenue
Retail revenues:
Residential (includes $5,508, $3,205, $19,052 and $8,331, respectively, related to the FCA⁽¹⁾)													$	109,155		$	112,534		$	255,838		$	264,689
Commercial(includes $291, $276, $652 and $387, respectively, related to the FCA⁽¹⁾)													76,965			78,982			151,191			153,260
Industrial													48,868			49,766			94,660			95,224
Irrigation													65,065			56,068			65,471			56,993
Deferred revenue related to HCC relicensing AFUDC⁽²⁾													(1,462		)	(2,349		)	(4,046		)	(4,933		)
Total retail revenues													$	298,591		$	295,001		$	563,114		$	565,233
Volume of retail sales (MWh)
Residential	$	145,555		$	130,952		$	410,245		$	376,492		1,036			1,057			2,439			2,597
Commercial	89,305			81,062			242,565			227,442			969			952			1,970			1,980
Industrial	52,771			48,979			147,995			136,617			815			811			1,648			1,641
Irrigation	89,370			84,264			146,363			153,301			756			644			765			654
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
Total retail MWh sales													3,576			3,464			6,822			6,872
Number of retail customers at period end
Residential	450,857			442,284									458,448			448,159
Commercial	70,066			69,145									71,074			69,818
Industrial	120			123									116			121
Irrigation	20,914			20,641									21,165			20,886
Total customers	541,957			532,193									550,803			538,984

⁽¹⁾ The FCA mechanism is an alternative revenue program and does not represent revenue from contracts with customers.

⁽²⁾As part of its January 30, 2009 general rate case order, the IPUC is allowing Idaho Power to recover a portion of 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~~$8.8 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. Prior to the May 2018 Idaho Tax Reform Settlement Stipulation described in Note 3 - "Regulatory Matters," Idaho Power was collecting $10.7 million annually.

Changes in rates, changes in customer demand, and changes in FCA mechanism revenues are the primary reasons for fluctuations in ~~general business revenue~~retail revenues 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~~six months ended ~~September~~June 30, ~~2017~~2018 and ~~2016,~~2017, is presented in the table that follows.

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	Three months ended September 30,			Nine months ended September 30,			Three months ended June 30,			Six months ended June 30,
	2017	2016	Normal	2017	2016	Normal ⁽²⁾	2018	2017	Normal	2018	2017	Normal ⁽²⁾
Heating degree-days⁽¹⁾	131	97	121	3,442	2,715	3,320	486	720	719	2,783	3,311	3,199
Cooling degree-days⁽¹⁾	1,108	722	751	1,341	1,000	934	192	233	183	192	233	183
Precipitation (inches)							3.1	4.2	3.3	6.9	11.2	6.9

⁽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~~Retail revenues increased ~~$31.7~~$3.6 million ~~and $53.3~~during the second quarter of 2018, but decreased $2.1 million ~~for~~during the ~~three and nine~~first six months ~~ended September 30, 2017, respectively,~~of 2018, compared with the same periods in ~~2016. Factors~~2017. The factors affecting ~~general business~~retail revenues during the period are discussed below.

Rates: Rate changes, ~~increased general business~~including the revenue accruals provided for in the 2017 Valmy Plant settlement stipulations and the revenue reductions due to the settlement stipulations related to recent income tax reform, decreased retail revenues by ~~$13.3~~$7.3 million and ~~$34.1~~$6.6 million for the three and ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2018, respectively, compared with the same periods in ~~2016.~~2017. 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~~2025. The Valmy Plant settlement stipulations provided for an accrual of six months of the increase in retail revenues, depreciation expense, and ~~general business revenue accruals for~~associated income tax expenses in the ~~three and nine months ended September 30,~~second quarter of 2017, resulting in a decrease in these items in the second quarter of 2018 compared with the same ~~periods~~period in ~~2016.~~2017. As a direct result of settlement stipulations approved by the IPUC and OPUC during the second quarter of 2018 relating to income tax reform, Idaho Power's revenues decreased in the second quarter of 2018. Also, ~~colder~~more moderate winter and spring temperatures in ~~early 2017 and warmer summer temperatures during~~ the ~~third quarter~~first half of 2018 compared with the first half of 2017 led to a ~~greater~~lower proportion of residential sales in higher rate categories inunder Idaho Power's tiered rate structure in the ~~third quarter~~first half of 2018. The customer rates include collection of amounts related to the PCA mechanism, which decreased revenue $0.8 million in the three months ended June 30, 2018, but increased revenue $2.5 million in the six months ended June 30, 2018, compared with the first three and ~~first nine~~six months of ~~2017~~2017. The collection of amounts related to the PCA mechanism in rates has no effect on operating income as a corresponding amount is recorded as expense in the same period it is collected through rates.

Customers: Continued customer growth increased retail revenues $2.2 million and $5.6 million in the first three and six months of 2018, respectively, 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), primarily by ~~residential, industrial, and commercial~~irrigation customers, increased ~~general business revenue~~retail revenues by ~~$23.1~~$6.3 million ~~for~~during the ~~third~~second quarter of ~~2017 and $23.5 million for the first nine months of 2017~~2018 when compared with the ~~same periods~~second quarter of ~~2016.~~2017. Increased usage ~~in both periods~~ was primarily the result of ~~warmer summer temperatures~~lower precipitation in the Idaho Power service area during the second quarter of 2018 compared with the second quarter of 2017, which led to increased usage by irrigation customers. For the six months ended June 30, 2018, a 15 percent increase in usage per irrigation customer was more than offset by an 8 percent decrease in usage per residential customer, compared with the same period in 2017, resulting in a decrease in retail revenues of $12.0 million. Decreased usage per residential customer was primarily the result of more moderate winter and ~~colder winter~~spring temperatures in Idaho Power's service area, which ~~increased~~led to decreased usage by residential customers for ~~cooling~~heating and ~~heating. Cooling degree days~~cooling. Heating degree-days were ~~significantly higher in~~16 percent lower during the ~~third quarter and~~ first ~~nine months~~half of ~~2017~~2018 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 monthshalf of 2017.

FCA Revenue: The FCA mechanism adjusts revenue each year to ~~collect,~~accrue, or ~~refund,~~defer, the difference between the authorized fixed-cost recovery amount per customer and the actual fixed costs per customer recovered by Idaho Power through volume-based rates during the year. ~~Higher~~Lower usage (on a per customer basis) by residential and small general service customers during the three and ~~nine~~six months ended ~~September~~June 30, ~~2017, compared with the same periods in 2016, decreased~~2018 increased the amount of FCA revenue accrued by ~~$7.4~~$2.3 million and ~~$13.7~~$11.0 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~~2017.

Table 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.Contents

~~Off-System~~Wholesale Energy Sales: ~~Off-system~~Wholesale energy sales consist primarily of long-term sales contracts, ~~and~~ opportunity sales of surplus system ~~energy.~~energy, and sales into the Western EIM, and do not include derivative transactions. The table below presents Idaho Power’s ~~off-system~~wholesale energy sales for the three and ~~nine~~six months ended ~~September~~June 30, ~~2017~~2018 and ~~2016~~2017 (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



	Three months ended June 30,				Six months ended June 30,
	2018		2017		2018		2017
Wholesale energy revenues	$	10,214	$	6,003	$	24,283	$	13,967
Wholesale MWh sold	821		751		1,681		1,439
Wholesale energy revenues per MWh	$	12.44	$	7.99	$	14.45	$	9.71

In the ~~third quarter~~first three and six months of ~~2017, off-system sales~~2018, wholesale energy revenue increased by ~~$0.6~~$4.2 million, or 70 percent, and $10.3 million, or 74 percent, respectively, compared with the same ~~period in 2016. For~~periods of 2017. The average price of wholesale energy sales was 56 percent and 49 percent higher for the ~~first nine~~three and six months ~~of 2017, off-system sales revenue increased by $9.1 million, or 55 percent~~ended June 30, 2018, respectively, compared with the same ~~period in 2016. Off-system~~periods of 2017. Wholesale energy sales volumes increased ~~116~~9 percent and 17 percent in the first ~~nine~~three and six months of ~~2017~~2018, respectively, compared with the same ~~period in 2016~~periods of 2017, as generation from Idaho Power's hydroelectric plants increased due to ~~significantly greater precipitation~~strong reservoir storage attributable to above-normal snowpack from 2017 and near-normal snowpack in 2018. The increase in hydroelectric generation resulted in additional energy available for wholesale sales in the first ~~nine~~three and six months of ~~2017~~2018 compared with the same ~~period~~periods of 2017. The increase in wholesale energy sales volumes was also due to transactions 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~~Western EIM, which commenced 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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April 2018.

~~Other~~Transmission Services (Wheeling) Revenues: ~~The table below presents~~Revenue from transmission services increased $1.2 million and $3.8 million during the ~~components of other revenues for the~~first three and ~~nine months ended September 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~~six months of ~~2017,~~2018, respectively, compared with the same periods ~~in 2016. The increase was~~of 2017, largely due to ~~an increase in wheeling volumes, an increase in~~ Idaho Power's OATT rates that ~~became effective~~increased 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.~~2017.

~~Most~~Energy Efficiency Program Revenues: In both Idaho and Oregon, energy efficiency ~~activities are funded through a rider mechanism on customer bills. Energy~~riders fund energy efficiency program ~~expenditures~~expenditures. Expenditures funded through the ~~rider~~riders 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.~~liability. 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~~June 30, ~~2017,~~2018, Idaho Power's energy efficiency rider balances were a ~~$4.6~~$2.6 million regulatory liability in the Idaho jurisdiction and a ~~$6.0~~$6.5 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

Table of ~~previously collected Idaho energy efficiency rider funds.~~Contents

Operating Expenses

Purchased Power: The table below presents Idaho Power’s purchased power expenses and volumes for the three and ~~nine~~six months ended ~~September~~June 30, ~~2017~~2018 and ~~2016~~2017 (in thousands, except for per MWh amounts).


	Three months ended September 30,				Nine months ended September 30,				Three months ended June 30,				Six months ended June 30,
	2017		2016		2017		2016		2018		2017		2018		2017
Expense
PURPA contracts	$	50,660	$	42,477	$	127,896	$	111,422	$	47,867	$	46,397	$	89,805	$	77,237
Other purchased power (including wheeling)	18,218		25,093		51,398		52,194		15,113		15,109		35,103		33,385
Demand response incentive payments	6,775		$	6,878	6,981		7,059
Total purchased power expense	$	75,653	$	74,448	$	186,275	$	170,675	$	62,980	$	61,506	$	124,908	$	110,622
MWh purchased
PURPA contracts	763		574		2,199		1,740		908		916		1,619		1,435
Other purchased power	352		590		1,070		1,221		475		330		953		719
Total MWh purchased	1,115		1,164		3,269		2,961		1,383		1,246		2,572		2,154
Cost per MWh from PURPA contracts	$	66.40	$	74.00	$	58.16	$	64.04	$	52.72	$	50.65	$	55.47	$	53.82
Cost per MWh from other sources	$	51.76	$	42.53	$	48.04	$	42.75	$	31.82	$	45.78	$	36.83	$	46.43
Weighted average - all sources	$	61.77	$	58.05	$	54.85	$	55.26	$	45.54	$	49.36	$	48.56	$	51.36

Purchased power expense increased ~~$1.2~~$1.5 million, or 2 percent, and ~~$15.6~~$14.3 million, or 913 percent, in the ~~third quarter~~first three and ~~first nine~~six months of ~~2017,~~2018, respectively, compared with the same periods ~~in 2016.~~of 2017. The increase for the ~~third quarter and~~ first ~~nine~~six months of ~~2017~~2018 was primarily due to ~~increases~~an increase of 3313 percent ~~and 26 percent, respectively,~~ in MWh purchased from generation projects under PURPA contracts, offset partially by decreases in costs per ~~MWh.~~MWh of other purchased power.

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~~wholesale energy 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~~wholesale energy 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.

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Fuel Expense: The table below presents Idaho Power’s fuel expenses and ~~generation at its~~ thermal ~~generating plants~~generation for the three and ~~nine~~six months ended ~~September~~June 30, ~~2017~~2018 and ~~2016~~2017 (in thousands, except for per MWh amounts).


	Three months ended September 30,				Nine months ended September 30,				Three months ended June 30,				Six months ended June 30,
	2017		2016		2017		2016		2018		2017		2018		2017
Expense
Coal	$	40,361	$	56,651	$	84,855	$	103,599	$	18,092	$	16,638	$	41,373	$	44,494
Natural gas⁽¹⁾	14,168		17,274		26,342		36,058		3,423		3,778		7,877		12,174
Total fuel expense	$	54,529	$	73,925	$	111,197	$	139,657	$	21,515	$	20,416	$	49,250	$	56,668
MWh generated
Coal	1,236		1,487		2,578		2,961		459		505		1,067		1,342
Natural gas⁽¹⁾	665		712		1,067		1,557		124		68		228		399
Total MWh generated	1,901		2,199		3,645		4,518		583		573		1,295		1,741
Cost per MWh - Coal	$	32.65	$	38.10	$	32.92	$	34.99	$	39.42	$	32.95	$	38.78	$	33.15
Cost per MWh - Natural gas	$	21.31	$	24.26	$	24.69	$	23.16	$	27.60	$	55.56	$	34.55	$	30.51
Weighted average, all sources	$	28.68	$	33.62	$	30.51	$	30.91	$	36.90	$	35.63	$	38.03	$	32.55

⁽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~~expenses 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~~increased $1.1 million, or ~~26 percent, and $28.5 million, or 20~~5 percent, in the ~~third~~second quarter ~~and~~of 2018, but decreased $7.4 million, or 13 percent, in the first ~~nine~~six months of ~~2017, respectively,~~2018, compared with the same periods ~~in 2016.~~of 2017. The ~~decreases~~increase in the ~~third~~second quarter ~~and first nine months~~of 2018 compared with the second quarter of 2017 was due to an increase in the prices of coal purchased from BCC. BCC shipped fewer tons to the Jim Bridger plant, which resulted in a higher price per ton as fixed costs were spread over fewer tons. The decrease in the first half of 2018 compared with 2017 was 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 501 percent ~~during the third quarter of 2017~~ and 388 percent during the first ~~nine~~three and six months of ~~2017,~~2018, respectively, compared with the same periods of 2017. Generation from Idaho Power's hydroelectric plants increased due to strong reservoir storage attributable to above-normal snowpack from 2017 and near-normal snowpack in ~~2016.~~2018.

Power Cost Adjustment Mechanisms: Idaho Power's power supply costs (primarily purchased power and fuel expense, less ~~off-system~~wholesale energy 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 customers, or refund to customers, most of the fluctuations in power supply costs. ~~The~~In the Idaho jurisdiction, the PCA includes a cost or benefit sharing ratio that allocates the deviations in net power supply expenses between customers (95 percent) and Idaho Power (5 percent), with the exception of PURPA power purchases and demand response program incentives, which are allocated 100 percent to customers. 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~~six months ended ~~September~~June 30, ~~2017~~2018 and ~~2016~~2017 (in thousands).


	Three months ended September 30,					Nine months ended September 30,					Three months ended June 30,				Six months ended June 30,
	2017		2016			2017		2016			2018		2017		2018		2017
Idaho power supply cost accrual (deferral)	$	8	$	(30,006	)	$	21,851	$	(17,408	)
Idaho power supply cost accrual											$	16,353	$	7,981	$	33,899	$	21,844
Amortization of prior year authorized balances	10,971		11,664			29,357		29,322			3,610		8,761		11,602		18,385
Total power cost adjustment expense	$	10,979	$	(18,342	)	$	51,208	$	11,914		$	19,963	$	16,742	$	45,501	$	40,229

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~~for all periods ~~in 2017,~~presented, most of the difference is ~~accrued.When~~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)~~adjustment mechanism).

Other O&M Expenses: Other O&M expenses ~~decreased $2.9~~increased $5.6 million, or 6 percent, and $4.7 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~~first three 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 ninesix months of ~~2017,~~2018, respectively, compared with the same ~~period~~periods of 2017. Transmission and distribution asset maintenance expense increased $0.9 million and $2.0 million in ~~2016. Compared~~the first three and six months of 2018, respectively, compared with the ~~first nine months of 2016, lower O&M expenses~~same periods in 2017, primarily due to ~~lower thermal generation during~~higher maintenance service costs. As provided by the ~~first nine months of 2017, were mostly offset~~settlement stipulation approved by ~~weather-related increases in certain~~the IPUC related to recent income tax reform, O&M expenses in ~~early~~the second quarter of 2018 also included $1.1 million of non-cash amortization expense of regulatory deferrals that would otherwise be a future liability of Idaho customers. Labor and benefit costs increased $3.1 million and $1.7 million in the second quarter and first six months of 2018, respectively, primarily related to the timing of accruals for variable employee-related costs which resulted in earlier recognition of expense compared with the same periods of 2017.

Income Taxes

IDACORP's and Idaho Power's income tax expense for the ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2018, when compared with the same period in ~~2016, increased $16.8~~2017, decreased $13.1 million and ~~$15.3~~$12.9 million, respectively, primarily asdue to lower statutory tax rates and a ~~result of greater pre-tax income, the $5.6~~$1.3 million flow-through income tax benefit related to the tax deduction for bond redemption costs incurred in the ~~first nine months~~second quarter of ~~2016,~~2018. The lower statutory tax rates were the result of the Tax Cuts and Jobs Act, which reduced the U.S. federal corporate income tax ~~benefits~~rate from ~~distributions~~35 percent to 21 percent, and Idaho House Bill 463, which lowered the Idaho state corporate income tax rate from ~~fully-amortized affordable housing investments that~~7.4 percent to 6.925 percent. The new tax rates were ~~also recorded in 2016.~~effective on January 1, 2018. 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~~anticipates these substantial capital expenditures to continue, with expected total capital expenditures of approximately $1.5 billion over the five-year period from ~~2017~~2018 (including expenditures incurred to-date in ~~2017)~~2018) through ~~2021.~~2022.

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~~six months of ~~2017,~~2018, 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~~July 27, ~~2017,~~2018, IDACORP's and Idaho Power's access to debt, equity, and credit arrangements included:

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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~~$280 million isremains 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.

In March 2018, Idaho Power issued $220 million in principal amount of 4.20% first mortgage bonds, Series K, maturing on March 1, 2048. In April 2018, Idaho Power redeemed, prior to maturity, its $130 million in principal amount of 4.50% first mortgage bonds, medium-term notes due March 2020. In accordance with the redemption provisions of the original terms of the notes, the redemption included payment by Idaho Power of a make-whole premium of $4.6 million. Idaho Power used a portion of the net proceeds of the March 2018 sale of first mortgage bonds, medium-term notes to effect the redemption.

Based on planned capital expenditures and ~~operating and maintenance~~O&M 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~~June 30, ~~2017,~~2018, 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~~six months ended ~~September~~June 30, ~~2017~~2018, were ~~$349~~$196 million and ~~$363~~$191 million, respectively, ~~increases~~an increase of ~~$73~~$7 million and ~~$113~~a decrease of $10 million, respectively, compared with the same period in ~~2016.~~2017. Significant items that affected the comparability of the companies' operating cash flows in the first ~~nine~~six months of ~~2017~~2018 compared with the same period in ~~2016~~2017 were as follows:

~~Changes in regulatory assets and liabilities~~net income 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 million increase from changes~~the reasons described in ~~taxes accrued, offset partially by a $30 million and an $11 million decrease from~~ "Results of Operations" above in this MD&A;

changes in deferred taxes and ~~investment tax credits,~~in taxes accrued and receivable combined to decrease cash flows by $12 million and increase by $8 million at IDACORP and Idaho Power, respectively;

Idaho Power made $25 million of benefit plan contributions during the first six months of 2018, while it made contributions of $4 million for the same period in 2017; and

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

◦

timing of collections of accounts receivable balances ~~decreased~~increased operating cash flows by $8 million for IDACORP and ~~decreased operating cash flows by $15 million for~~ Idaho Power. For IDACORP, the increase was offset by IDACORP's ~~decrease is less than Idaho Power's decrease because IDACORP collected a $7.6~~collection in 2017 of $8 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; and


◦	timing of accounts payable payments increased operating cash flows by $18 million for IDACORP and decreased operating cash flows by ~~$22 million for IDACORP and increased operating cash flows by $24~~$26 million for Idaho Power (the difference relates to a ~~$46.5~~$44 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~~six months ended ~~September~~June 30, ~~2017,~~2018, were ~~$199~~$109 million. Investing cash outflows for ~~2017~~2018 and ~~2016~~2017 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. During the six months ended June 30, 2018, Idaho Power ~~has a Rabbi trust designated~~received $20 million in payments from transmission project co-participants pursuant to ~~provide~~the terms of the joint funding arrangements for ~~obligations~~their share 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.costs.

Financing Cash Flows

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

IDACORP's and Idaho Power's net financing cash ~~outflows~~inflows for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2018 were ~~$107~~$19 million and ~~$106~~$23 million, respectively. In March 2018, Idaho Power issued $220 million in first mortgage bonds. In April 2018, Idaho Power redeemed, prior to maturity, $130 million in principal amount of 4.50% first mortgage bonds, medium-term notes due March 2020. In accordance with the redemption provisions of the original terms of the notes, the redemption included payment by Idaho Power of a make-whole premium of $4.6 million. Idaho Power also expects to receive an incremental net benefit to net income as a result of the lower interest rate of the notes issued in March 2018 compared to the interest rate associated with the redeemed notes. Financing cash flows also included the payment of $60 million of dividends on common stock during the first ~~nine~~six months of ~~2017, IDACORP and Idaho Power paid cash dividends of $83 million and had a net reduction in commercial paper of $19 million.~~2018.

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,~~2018, and as of the date of this report, ~~the company~~IDACORP 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~~has $280 million available for the issuance of first mortgage bonds, including Series K Notes, or debt securities under the selling agency agreement.

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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~~June 30, ~~2017~~2018 was limited to approximately ~~$759~~$669 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~~June 30, ~~2017,~~2018, 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~~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.~~4, 2022. 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,~~2017, 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~~June 30, ~~2017,~~2018, 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~~June 30, ~~2017,~~2018, IDACORP and Idaho Power ~~believe~~believed 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.~~2018.

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					June 30, 2018					December 31, 2017
	IDACORP⁽²⁾			Idaho Power			IDACORP⁽²⁾		Idaho Power			IDACORP⁽²⁾		Idaho Power			IDACORP⁽²⁾		Idaho Power
Revolving credit facility	$	100,000		$	300,000		$	100,000	$	300,000		$	100,000	$	300,000		$	100,000	$	300,000
Commercial paper outstanding	(2,425		)	—			—		(21,800		)	—		—			—		—
Identified for other use⁽¹⁾	—			(24,245		)	—		(24,245		)	—		(24,245		)	—		(24,245		)
Net balance available	$	97,575		$	275,755		$	100,000	$	253,955		$	100,000	$	275,755		$	100,000	$	275,755

⁽¹⁾ Port of Morrow and American Falls bonds that Idaho Power could be required to purchase prior to maturity under the optional or mandatory purchase provisions of the bonds, if the remarketing agent for the bonds is unable to sell the bonds to third parties.

⁽²⁾ Holding company only.

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At ~~October~~July 27, ~~2017,~~2018, IDACORP had no loans outstanding under its credit facilities and had ~~$2.3 million of~~no commercial paper outstanding. Idaho Power had no loans outstanding under its credit facilities and no commercial paper outstanding. ~~The table below presents additional information about~~During the three and six months ended June 30, 2018, no 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.~~was borrowed at IDACORP or Idaho Power.

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.~~2017. 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~~June 30, ~~2017,~~2018, Idaho Power had posted ~~$0.4~~$0.8 million of 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~~June 30, ~~2017,~~2018, the amount of additional collateral that could be requested upon a downgrade to below investment grade is approximately ~~$5.1~~$4.2 million. To minimize capital requirements, Idaho Power actively monitors its portfolio exposure and the potential exposure to additional requests for performance assurance collateral through sensitivity analysis.

Capital Requirements

Idaho Power's construction expenditures, excluding ~~allowance for funds used during construction (AFUDC),~~AFUDC, were ~~$200~~$129 million during the ~~nine~~six months ended ~~September~~June 30, ~~2017.~~2018. The table below presents Idaho Power's expected cash requirements for construction, excluding AFUDC, for ~~2017~~2018 (including amounts incurred to-date) through ~~2021~~2022 (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.~~2017. 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~~$97 million, including AFUDC, has been expended on the Boardman-to-Hemingway project through ~~September~~June 30, ~~2017.~~2018. Pursuant to the terms of the joint funding arrangements, Idaho Power has received approximately ~~$48~~$69 million ~~of that amount as reimbursement from the project participants~~ as of ~~September~~June 30, ~~2017. Idaho Power has accrued~~2018, including $20 million received in ~~receivables approximately $18 million more that will be billed by Idaho Power in~~2018, due from project co-participants for their share of costs. As of the ~~future to the project participants for expenses Idaho Power has incurred, for a total amount reimbursable by joint permitting participants~~date of ~~$66 million.~~this report, no material co-participant reimbursements are outstanding. 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,~~

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issued ~~a final environmental impact statement (EIS)~~its record of decision for the project in November ~~2016. As of the date of this report, the BLM's schedule provides for the issuance of a~~2017. The U.S. Forest Service released its draft record of decision in ~~2017.~~

June 2018 for the 6.8 miles across National Forest lands consistent with the preferred route in the BLM's final environmental impact statement. Idaho Power expects the Department of the Navy to issue its decision in 2018. 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~~Given the status of ongoing permitting activities and the construction period, Idaho Power expects the in-service date ~~would~~for the transmission line to be in ~~2024~~2025 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~~have a joint funding agreement for permitting of the project. Idaho Power has expended approximately ~~$34~~$37 million, including AFUDC, onfor its share of the permitting phase of the project through ~~September~~June 30, ~~2017.~~2018. 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~~$250 million and ~~$400~~$450 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~~a federal bill was 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~~In April 2018, the BLM ~~to issue a~~published its record of decision for the outstanding portions of the remaining ~~segments in 2018.~~segments. Idaho Power and PacifiCorp continue to coordinate the timing of next steps to best meet customer and system needs.

Defined Benefit Pension Plan Contributions

Idaho Power has no minimum contribution requirement to its defined benefit pension plan in ~~2017;~~2018; however, Idaho Power ~~has~~ contributed ~~$40~~$20 million to the plan during ~~2017.~~the first six months of 2018. Depending on market conditions and cash flow considerations during the remainder of 2018, Idaho Power may contribute up to an additional $20 million to the pension plan during 2018. 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~~six months ended ~~September~~June 30, ~~2017,~~2018, 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,~~2017, except that Idaho Power entered into power purchase agreements with solar ~~biomass,~~ and ~~hydro~~biomass PURPA-qualifying facilities that increased Idaho Power's contractual payment obligations by approximately ~~$85~~$51 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.~~2017.

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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, the in-service dates of major capital investments, the timing and magnitude 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~~mitigate 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.~~above, but does not anticipate filing a general rate case in the next twelve months.

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.~~2017. 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,~~2017, 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~~Changes During ~~2017~~2018

During ~~2017,~~2018, 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~~2018	$~~10.6~~22.6 million PCA ~~increase~~decrease for the period from June 1, ~~2017~~2018 to May 31, ~~2018~~2019	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~~ 2018	$~~6.9~~19.4 million FCA ~~increase~~decrease for the period from June 1, ~~2017~~2018 to May 31, ~~2018~~2019	The FCA is designed to remove a portion of 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~~Tax Cuts and Jobs Act Settlement Stipulation - Idaho	New ~~retail rates~~base rate became effective June 1, ~~2017~~2018	~~$13.3~~On an annual basis, $18.7 million ~~increase in Idaho jurisdictional revenue requirement~~reduction of customer base rates, commencing on June 1, 2018	~~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.~~See "Income Tax Reform - Impact and Regulatory Treatment" below for more information.
~~Depreciation Study~~Tax Cuts and Jobs Act Settlement Stipulation - Idaho	New ~~depreciation rates~~PCA rate became effective June 1, ~~2017~~2018	~~No change in retail~~ One-time benefit of a $7.8 million decrease to be provided through PCA mechanism rates for the period from June 1, 2018 through May 31, 2019	For the income tax benefits accrued from January 1, 2018 to May 31, 2018, and the income tax benefits related to Idaho Power's OATT. See "Income Tax Reform - Impact and Regulatory Treatment" below for more information.

⁽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~~retail sales volumes.

Customer-Owned Generation Filing

OnIn July ~~27,~~ 2017, Idaho Power filed an application with the IPUC ~~requesting~~related to customers who install their own on-site generation, seeking the creation of two new classes ~~for residential and small general service~~of customers, ~~who choose~~with no request to ~~install on-site generation on~~change pricing or ~~after January 1, 2018. If approved as proposed, Idaho Power does not, as of~~compensation. In May 2018, the ~~date of this report, anticipate that~~IPUC issued an order authorizing the creation of ~~these~~the new ~~rate classes would impact in~~customer classes. In that order, 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.IPUC also stated its intent to open

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an Idaho Power-specific docket to comprehensively study on-site generation and ordered Idaho Power to file a study with the IPUC exploring fixed-cost recovery prior to its next general rate case. In June 2018, the IPUC issued an order requiring further investigation to resolve eligibility issues for the new customer classes.

Idaho Earnings Support and Sharing from Idaho Settlement Stipulation

In October 2014, the IPUC issued an order (October 2014 Idaho Earnings Support and Sharing Settlement Stipulation) 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~~Earnings Support and Sharing 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~~Idaho Earnings Support and Sharing 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 Earnings Support and Sharing Settlement Stipulation, during the second quarter of 2018, Idaho Power ~~recorded no additional ADITC amortization during~~reversed 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~~$0.5 million of additional ADITC amortization ~~which was~~recorded during the first quarter of 2018, based on Idaho Power's then-current estimate of return on year-end equity in the Idaho jurisdiction (Idaho ROE) for the full-year 2018. During the second quarter of 2017, Idaho Power reversed ~~later in 2016~~$1.9 million of additional ADITC amortization recorded during the first quarter of 2017, as actual financial results exceeded Idaho Power's early estimates.

Income Tax Reform - Impact and Regulatory Treatment

In December 2017, the Tax Cuts and Jobs Act was signed into law, which, among other things, lowered the corporate federal income tax rate from 35 percent to 21 percent and modified or eliminated certain federal income tax deductions for corporations. In March 2018, Idaho House Bill 463 was signed into law reducing the Idaho state corporate income tax rate from 7.4 percent to 6.925 percent. In January 2018, the IPUC issued an order requiring utilities within its jurisdiction, including Idaho Power, to (1) record a regulatory liability for the estimated Idaho-jurisdictional share of financial benefits after January 1, 2018, from the changes in federal income tax law under the Tax Cuts and Jobs Act, and (2) file a report with the IPUC by March 30, 2018, identifying and quantifying the financial impact of the income tax changes on the utility, along with proposed tariff schedule changes that would adjust the utility's rates to reflect the utility's modified federal tax obligations under the Tax Cuts and Jobs Act. The IPUC order required Idaho Power to estimate the income tax reform changes by comparing actual 2017 federal income tax components with what those federal income tax components would have been if the Tax Cuts and Jobs Act had been effective for the full year of 2017.

In March 2018, Idaho Power made a filing with the IPUC providing the results of its pro forma analysis indicating pro forma annual income tax reform expense reductions, composed of a current income tax expense reduction and a deferred income tax expense reduction. In May 2018, the IPUC issued an order approving a settlement stipulation (May 2018 Idaho Tax Reform Settlement Stipulation) related to income tax reform. Beginning June 1, 2018, the settlement stipulation provides an annual (a) $18.7 million reduction to Idaho customer base rates and (b) $7.4 million amortization of existing regulatory deferrals for specified items or future amortization of other existing or future unspecified regulatory deferrals that would otherwise be a future liability recoverable from Idaho customers. Additionally, a one-time benefit of a $7.8 million rate reduction is being provided to Idaho customers through PCA mechanism rates for the period from June 1, 2018 through May 31, 2019, for the income tax reform benefits accrued from January 1, 2018 to May 31, 2018, and the income tax reform benefits related to Idaho Power's OATT. The amount provided via the PCA mechanism will decrease to $2.7 million on June 1, 2019, for income tax reform benefits related to Idaho Power's OATT and will cease on June 1, 2020, to reflect the impact of a full year of reduced OATT third-party transmission revenues.

The May 2018 Idaho Tax Reform Settlement Stipulation provides for the extension of the October 2014 Idaho Earnings Support and Sharing Settlement Stipulation described above beyond the initial termination date of December 31, 2019, with modified terms related to the ADITC and revenue sharing mechanism to become effective beginning January 1, 2020. Neither the October 2014 Idaho Earnings Support and Sharing Settlement Stipulation nor the May 2018 Idaho Tax Reform Settlement Stipulation impose a moratorium on Idaho Power filing a general rate case or other form of rate proceeding in Idaho during their respective terms.

Also in May 2018, the OPUC issued an order approving a settlement stipulation that provides for an annual $1.5 million reduction to Oregon customer base rates beginning June 1, 2018, through May 31, 2020, related to income tax reform. Unless resolved in a regulatory proceeding before, the settlement stipulation requires Idaho Power to file a deferral request with the

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OPUC by December 31, 2019, to begin tracking tax reform benefits beginning January 1, 2020, at which time Idaho Power, the OPUC staff, and other interested parties will discuss the methodology to quantify potential future tax reform benefits. The settlement stipulation also deemed prudent Idaho Power's decision to pursue the end of its participation in coal-fired operations of Unit 1 at Idaho Power's jointly-owned North Valmy coal-fired plant and approved Idaho Power's request to recover $2.5 million of annual incremental accelerated depreciation relating to Unit 1, beginning June 1, 2018 and ending December 31, 2019.

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.

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~~six months ended ~~September~~June 30, ~~2017~~2018 (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			Oregon			Total
Deferred net power supply costs at December 31, 2017	$	(2,201	)	$	(105	)	$	(2,306	)
Current period net power supply costs accrued	(33,227		)	—			(33,227		)
Prior amounts recovered through rates	(6,402		)	—			(6,402		)
Tax reform revenue accrual transferred to Idaho PCA mechanism	(4,244		)	—			(4,244		)
SO₂ allowance and renewable energy certificate sales	(2,263		)	(93		)	(2,356		)
Interest and other	(82		)	4			(78		)
Deferred net power supply costs at June 30, 2018	$	(48,419	)	$	(194	)	$	(48,613	)

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 or accruals is that the timing of when cash is paid out ~~but recovery of~~for power supply expenses differs from when those costs are recovered 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~~

Draft Posting

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,~~In June 2018, Idaho Power ~~filed~~publicly posted its ~~2017 final~~2018 draft transmission rate, ~~with the FERC,~~ reflecting a transmission rate of ~~$34.90~~$31.26 per ~~kW-year,~~"kW-year," to be effective for the period from October 1, 2018 to September 30, 2019. A "kW-year" is a unit of electrical capacity equivalent to 1 kilowatt of power used for 8,760 hours. Idaho Power's draft rate was based on a net annual transmission revenue requirement of $123.1 million. The existing OATT rate in effect from October 1, 2017 to September 30, ~~2018. Idaho Power's final rate was~~2018, is $34.90 per kW-year 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~~decrease in the OATT rate ~~was~~is largely attributable to an ~~asset exchange transaction with one~~increase in short-term firm and non-firm transmission ~~customer, and the termination of legacy long-term transmission service agreements and its impact on~~revenues in 2017, which serves as an offset to the transmission ~~formula rate, which was fully incorporated in the new formula rate effective October 1, 2017.~~revenue requirement.

~~2017 Integrated Resource Plan~~Western Energy Imbalance Market Costs

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~~Western EIM commenced on April 4, 2018. The Western EIM is intended to reduce the power supply costs to serve customers through more efficient dispatch within the hour of a larger and ~~2 in 2019~~more diverse pool of resources, to integrate intermittent power from renewable generation sources more effectively, and ~~2025, respectively, and~~to enhance reliability. In August 2016, Idaho Power filed an application with the ~~early retirement of Jim Bridger units 1 and 2 in 2032 and 2028, respectively,~~IPUC requesting specified regulatory accounting treatment associated with ~~no other new resource needs prior to 2026. However, as noted~~its participation 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.~~Western EIM. 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,January 2017, the IPUC issued ~~its~~an order ~~determining that~~authorizing deferral accounting treatment for costs associated with joining 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.Western EIM. Idaho Power ~~expects that the prudency finding will result in an approximate $2.0~~deferred $1.0 million ~~increase in operating income in 2017.~~of incremental other O&M costs incurred through

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April 1, 2018. In November 2017, Idaho Power filed an application with the IPUC requesting approval to establish an interim method of recovery for Western EIM-related costs. In July 2018, the IPUC issued an order approving a settlement stipulation that provides for a recovery mechanism administered through Idaho Power's PCA mechanism. For more information on the order and its impact on financial results, see Note 3 - "Regulatory Matters" to the condensed consolidated financial statements included in this report.

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~~June 30, ~~2017,~~2018, Idaho Power had contracts to purchase energy from ~~127~~128 on-line PURPA projects. An additional three contracts are with non-PURPA projects, including the Elkhorn Valley wind project with a ~~101 MW~~101-MW nameplate capacity. The following table sets forth, as of ~~September~~June 30, ~~2017,~~2018, 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)	Total On-line mega-watts (MW)	Under Contract but not yet On-line (MW)	Total Projects under Contract (MW)
PURPA:
Wind	627	—	627	50	627	—	627
Solar	290	24	314	120	290	27	317
Hydroelectric	147	8	155	—	147	2	149
Other	50	5	55	—	56	—	56
Total	1,114	37	1,151	170	1,120	29	1,149
Non-PURPA:
Wind	101	—	101	—	101	—	101
Geothermal	35	—	35	—	35	—	35
Total	136	—	136	—	136	—	136

Of the six projects not yet on-line, one hydroelectric project and five solar projects are scheduled to be on-line in 2019.

Relicensing of Hydroelectric Projects

In connection with Idaho Power's efforts to relicense the HCC, Idaho Power's largest hydroelectric complex and a major relicensing effort, 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,~~2017, 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 November 2016, Idaho Power filed a petition with the FERC requesting that the FERC resolve the conflict between Oregon's and Idaho's conditions and declare that the Federal Power Act pre-empts the Oregon state law. In January 2017, the FERC issued an order denying Idaho Power’s petition, stating that the petition for a declaratory order was premature, cannot realistically be considered separately from the issue of the states’ certification authority under the CWA Section 401, and raises issues that are beyond the FERC’s authority to decide. In February 2017, Idaho Power sought rehearing before the FERC on the January 2017 order, which the FERC denied. In February 2018, Idaho Power filed an appeal of the FERC's January 2017 order with the D.C. Circuit Court, which is pending.

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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. Idaho Power most recently resubmitted its application to both states in June 2018 with the intent to allow additional time for the states to continue negotiating.

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~~$282 million (including AFUDC) for the HCC ~~Idaho Power's largest hydroelectric complex and a major relicensing effort,~~ were included in construction work in progress at ~~September~~June 30, ~~2017.~~2018. As of the date of this report, the IPUC authorizes Idaho Power to include in its Idaho jurisdiction rates ~~approximately $10.7~~$8.8 million of AFUDC annually relating to the HCC relicensing project. Prior to the May 2018 Idaho Tax Reform Settlement Stipulation described in Note 3 - "Regulatory Matters," Idaho Power was collecting $10.7 million annually. Collecting these amounts currently will reduce future collections when HCC relicensing costs are approved for recovery in base rates. As of ~~September~~June 30, ~~2017,~~2018, Idaho Power's regulatory liability for collection of AFUDC relating to the HCC was ~~$116~~approximately $127 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.

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inclusion in retail ~~rates.~~rates in a future regulatory proceeding. In December 2017, Idaho Power ~~is currently participating in~~filed with the IPUC a settlement ~~proceedings related to~~stipulation signed by Idaho Power, the ~~prudence determination. If settlement is not reached,~~ IPUC staff, and a third party intervenor, ~~testimony is due December 15,~~recognizing that a total of $216.5 million in expenditures were reasonably incurred, and therefore should be eligible for inclusion in customer rates at a later date. As a result of filing the settlement stipulation, Idaho Power recorded a $5.0 million pre-tax charge in the fourth quarter of 2017, which included $4.3 million for costs incurred through 2015, as well as $0.7 million related to associated costs incurred in 2016 and 2017. In April 2018, the IPUC issued an order approving the settlement stipulation as filed with the IPUC and determined the associated costs to be reasonably and prudently incurred.

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,~~2017, includes a summary of Idaho Power's expected capital and operating expenditures for environmental matters during the period from ~~2017~~2018 to ~~2019.~~2020. 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.

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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.~~2017.

~~Executive Orders on Environmental~~Endangered Species Act Matters

Overview: The listing of a species of fish, wildlife, or plants as threatened or endangered under the ESA may have an adverse impact on Idaho Power's ability to construct generation, transmission, or distribution facilities or relicense or operate its hydroelectric facilities. When a species is added to the federal list of threatened and endangered species, it is protected from “take,” which is defined to include harming the species. The ESA directs that, concurrent with a designation of a threatened or endangered species, and where prudent and determinable, the applicable agencies also designate “any habitat of such species which is then considered to be critical habitat.” The ESA also provides that each federal agency must ensure that any action they authorize, fund, or carry out is not likely to jeopardize the continued existence of a listed species or result in the destruction or adverse modification of its critical habitat. If an action is determined to result in adverse modification of critical habitat, the federal agency must adopt changes to the proposed action to avoid the adverse modification. These changes are often quite extensive and can affect the size, scope, and even the feasibility of a project moving forward. In ~~March 2017, President Trump issued an executive order directing~~February 2016, the U.S. ~~Environmental Protection Agency (EPA)~~Fish and Wildlife Service (USFWS) and the NMFS issued a set of regulatory and policy changes relating to ~~review~~critical habitat and adverse modification determinations under the ~~Clean~~ESA (2016 ESA Rules). While the ultimate impact of implementation of those changes is yet to be determined, taken as a whole, Idaho Power ~~Plan (CPP),~~believes that the ~~greenhouse gas new source performance~~2016 ESA Rules could result in the applicable agencies having greater authority in making designations of critical habitat and could increase the likelihood of adverse modification determinations.

On July 19, 2018, the USFWS and the NMFS issued three proposals to revise ESA regulations (2018 ESA Regulations) related to the process and standards ~~(GHG NSPS)~~for listing species and designating critical habitat, the process for consultations with federal agencies under Section 7 of the ESA (including the definition of "destructive or adverse modification" of designated critical habitat), 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~~scope of ~~the order. The order also directs the Secretary~~protection 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,threatened species. Idaho Power believes ~~it is unlikely~~ that ~~it will~~if the 2018 ESA Regulations are enacted, the regulations could reduce Idaho Power’s obligations for mitigation under the ESA related to various construction and relicensing projects.

The construction of generation, transmission, or distribution facilities and the relicensing of Idaho Power's hydroelectric projects can be ~~required~~federally authorized actions that fall under the ESA. There are a number of threatened or endangered species within Idaho Power's service area and within or near proposed transmission line routes, including the slickspot peppergrass. Further, there are a number of ESA-listed fish and other aquatic species located in waterways in which Idaho Power has hydroelectric facilities, including fall Chinook salmon, bull trout, Bliss Rapids snail, and Snake River physa snail. To date, efforts to ~~comply with~~protect these and other listed species have not significantly affected generation levels or operating costs at any of Idaho Power's hydroelectric facilities. However, the ~~CPP in~~ongoing relicensing of the ~~near term.~~HCC presents endangered species and fisheries issues that may require operational adjustments and could adversely impact the amount of output from hydroelectric dams, potentially causing Idaho Power to rely on more expensive sources for power generation or market purchases.

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~~

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~~re-route 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.

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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. In May 2018, the BLM issued draft resource management plan amendments and draft environmental impact statements to modify the 2015 sage grouse plans to better align the plans with state plans, conservation measures and the Department of the Interior and BLM policy. The public comment period runs through August 2, 2018. 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,~~Definition of “Waters of the ~~EPA~~United States” Under the CWA: On August 28, 2015, the EPA's and U.S. Army Corps of Engineers' final rule defining the ~~Department of Army issued a notice of their intent to rescind and replace the definition of~~phrase "waters of the United States" under the CWA ~~as enacted in August 2015 (WOTUS), which had~~became effective (WOTUS Rule). Idaho Power believes that the final rule potentially expanded ~~the number of waterways subject to~~ federal jurisdiction ~~for environmental regulation~~under the CWA beyond traditional navigable waters, interstate waters, territorial seas, tributaries, and adjacent wetlands, to a number of other waters, including waters with a "significant nexus" to those traditional waters. ~~As described~~The WOTUS Rule was widely challenged in ~~Part II, Item 7 - "MD&A - Environmental Issues"~~both federal district and circuit courts. The State of Idaho, and several other parties, challenged the rule in ~~IDACORP's~~North Dakota federal court. That court held that it had jurisdiction and enjoined the implementation of the WOTUS Rule. In February 2017, President Trump issued an executive order directing the EPA and the U.S. Army Corps of Engineers to rescind the WOTUS Rule. In July 2017, the EPA and the U.S. Army Corps of Engineers issued a notice of their intent to rescind and replace the definition of "waters of the United States" under the CWA, which Idaho Power expects would reduce the number of waters in Idaho Power's ~~Annual Report~~service area subject to the WOTUS Rule. In November 2017, the EPA issued a notice that it will delay the effectiveness of the WOTUS Rule until 2020 while the U.S. Army Corps of Engineers considers a replacement rule. In January 2018, the U.S. Supreme Court issued a unanimous ruling that challenges to the WOTUS Rule must begin with the federal district courts, effectively negating a nationwide stay issued by the Sixth Circuit in 2016. However, because the State of Idaho remains a party to the federal court action in North Dakota, that court’s enjoinder remains in effect, meaning the WOTUS Rule currently does not apply to actions brought in Idaho. On July 12, 2018, the EPA and the U.S. Army Corps of Engineers issued a supplemental notice seeking additional comment on ~~Form 10-K for~~their 2017 proposal to repeal the ~~year ended December 31, 2016,~~ definition of the term WOTUS Rule under the CWA.

Idaho Power ~~did not expect~~has analyzed the ~~revised~~ WOTUS Rule and expects that, even if the WOTUS Rule is reinstated in Idaho, while it may cause Idaho Power to incur additional permitting, regulatory requirements, and other costs associated with the rule, the aggregate amount of increased costs is unlikely to have a material adverse effect on Idaho Power's operations or financial ~~condition.~~condition, in part due to the relatively arid climate of Idaho Power's service area. Similarly, because the CWA, as ~~previously~~ interpreted even prior to the WOTUS Rule, applies to most of Idaho Power's facilities, including its hydroelectric plants, Idaho Power does not expect ~~this proposal to~~that the repeal of the WOTUS Rule will 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,~~revenues, 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.~~2017.

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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,~~2017, 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~~June 30, ~~2017.~~2018. 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~~June 30, ~~2017,~~2018, 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~~June 30, ~~2017,~~2018, IDACORP had ~~$1.7~~$1.8 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~~$281.2 million if market interest rates were to decline by one percentage point from their ~~September~~June 30, ~~2017~~2018 levels.

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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~~June 30, ~~2017,~~2018, 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.~~2017. Information regarding Idaho Power’s use of derivative instruments to manage commodity price risk can be found in Note ~~10 –~~11 - "Derivative Financial Instruments" to the condensed consolidated financial statements included in this report.

Credit Risk

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

The use of performance assurance collateral in the form of cash, letters of credit, or guarantees is common industry practice. Idaho Power maintains margin agreements relating to its wholesale commodity contracts that allow performance assurance collateral to be requested of and/or posted with certain counterparties. As of ~~September~~June 30, ~~2017,~~2018, Idaho Power had posted ~~$0.4~~$0.8 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~~June 30, ~~2017,~~2018, the amount of collateral that could be requested upon a downgrade to below investment grade was approximately ~~$5.1~~$4.2 million. To minimize capital requirements, Idaho Power actively monitors the portfolio exposure and the potential exposure to additional requests for performance assurance collateral calls through sensitivity analysis.

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IDACORP's credit risk related to uncollectible accounts, net of amounts reserved, as of ~~September~~June 30, ~~2017,~~2018, 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.~~2017. Additional information regarding Idaho Power’s management of credit risk and credit contingent features can be found in Note ~~10 –~~11 - "Derivative Financial Instruments" to the condensed consolidated financial statements included in this report.

Equity Price Risk

IDACORP is exposed to price fluctuations in equity markets, primarily through Idaho Power's defined benefit pension plan assets, a mine reclamation trust fund owned by an equity-method investment of Idaho Power, and other equity security investments at Idaho Power. The equity securities held by the pension plan and in such accounts are diversified to achieve broad market participation and reduce the impact of any single investment, sector, or geographic region. Idaho Power has established asset allocation targets for the pension plan holdings, which are described in Note 1110 - "Benefit Plans" to the consolidated financial statements included in IDACORP's Annual Report on Form 10-K for the year ended December 31, ~~2016.~~2017.

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ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

IDACORP: The Chief Executive Officer and the Chief Financial Officer of IDACORP, based on their evaluation of IDACORP’s disclosure controls and procedures (pursuant to Rule 13a-15(b) of the Securities Exchange Act of 1934 (Exchange Act)) as of ~~September~~June 30, ~~2017,~~2018, 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~~June 30, ~~2017,~~2018, 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~~June 30, ~~2017,~~2018, that have materially affected, or are reasonably likely to materially affect, IDACORP's or Idaho Power's internal control over financial reporting.

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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~~2017, 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 56 - "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~~IDACORP did not repurchase any shares of its common stock during the quarter ended ~~September~~June 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.~~2018.

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

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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~~June 30, ~~2017:~~2018:



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


10.1 ⁽¹⁾	~~Second~~Third Amendment to the Idaho Power Company Employee Savings Plan, executed ~~October 29, 2017~~April 26, 2018 and effective January 1, 2018	10-Q	1-14465; 1-3198	10.4	5/3/2018		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.

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SIGNATURES

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



		IDACORP, INC.
		(Registrant)



Date:	~~November~~August 2, ~~2017~~2018	By:	/s/ Darrel T. Anderson
			Darrel T. Anderson
			President and Chief Executive Officer

Date:	~~November~~August 2, ~~2017~~2018	By:	/s/ Steven R. Keen
			Steven R. Keen
			Senior Vice President, Chief Financial
			Officer, and Treasurer





		IDAHO POWER COMPANY
		(Registrant)



Date:	~~November~~August 2, ~~2017~~2018	By:	/s/ Darrel T. Anderson
			Darrel T. Anderson
			President and Chief Executive Officer

Date:	~~November~~August 2, ~~2017~~2018	By:	/s/ Steven R. Keen
			Steven R. Keen
			Senior Vice President, Chief Financial
			Officer, and Treasurer

6269



	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



	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	)



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	—	—

Expected capital expenditures (excluding AFUDC)