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 June 30, ~~2014~~2015
	OR
	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
	EXCHANGE ACT OF 1934
	For the transition period from __________ to __________
		Exact name of registrants as specified	I.R.S. Employer
Commission File		in their charters, address of principal	Identification
Number		executive offices, zip code and telephone number	Number
1-14465		IDACORP, Inc.	82-0505802
1-3198		Idaho Power Company	82-0130980
		1221 W. Idaho Street
		Boise, Idaho 83702-5627
		(208) 388-2200
		State of Incorporation: Idaho
		None
Former name, former address and former fiscal year, if changed since last report.

Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.

IDACORP, Inc.: Yes X No __ Idaho Power Company: Yes X No __

Indicate by check mark whether the registrants have submitted electronically and posted on their corporate Web sites, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrants were required to submit and post such files).

IDACORP, Inc.: Yes X No ___ Idaho Power Company: Yes X No ___

Indicate by check mark whether the registrants are large accelerated filers, accelerated filers, non-accelerated filers, or smaller reporting companies. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act (check one):

IDACORP, Inc.:

Large accelerated filer X Accelerated filer Non-accelerated filer Smaller reporting company

Idaho Power Company:

Large accelerated filer Accelerated filer Non-accelerated filer X Smaller reporting company

Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Exchange Act).

IDACORP, Inc.: Yes No X Idaho Power Company: Yes No X

Number of shares of common stock outstanding as of July ~~25, 2014~~24, 2015:

IDACORP, Inc.: ~~50,268,748~~50,341,399

Idaho Power Company: 39,150,812, all held by IDACORP, Inc.

This combined Form 10-Q represents separate filings by IDACORP, Inc. and Idaho Power Company. Information contained herein relating to an individual registrant is filed by that registrant on its own behalf. Idaho Power Company makes no representations as to the information relating to IDACORP, Inc.’s other operations.

Idaho Power Company meets the conditions set forth in General Instruction (H)(1)(a) and (b) of Form 10-Q and is therefore filing this report on Form 10-Q with the reduced disclosure format.

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TABLE OF CONTENTS
				Page
Commonly Used Terms				3
Cautionary Note Regarding Forward-Looking Statements				4

Part I. Financial Information

	Item 1. Financial Statements (unaudited)
		IDACORP, Inc.:
			Condensed Consolidated Statements of Income	6
			Condensed Consolidated Statements of Comprehensive Income	7
			Condensed Consolidated Balance Sheets	8
			Condensed Consolidated Statements of Cash Flows	10
			Condensed Consolidated Statements of Equity	11
		Idaho Power Company:
			Condensed Consolidated Statements of Income	12
			Condensed Consolidated Statements of Comprehensive Income	13
			Condensed Consolidated Balance Sheets	14
			Condensed Consolidated Statements of Cash Flows	16
		Notes to the Condensed Consolidated Financial Statements		17
		Reports of Independent Registered Public Accounting Firm		3331
	Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations			3533
	Item 3. Quantitative and Qualitative Disclosures About Market Risk			5856
	Item 4. Controls and Procedures			5957

Part II. Other Information:

	Item 1. Legal Proceedings			5957
	Item 1A. Risk Factors			5958
	Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			5958
	Item 3. Defaults Upon Senior Securities			6058
	Item 4. Mine Safety Disclosures			6058
	Item 5. Other Information			6058
	Item 6. Exhibits			6058

Signatures				6159

Exhibit Index				6260

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COMMONLY USED TERMS

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

ADITC	-	Accumulated Deferred Investment Tax Credits
AFUDC	-	Allowance for Funds Used During Construction
BCC	-	Bridger Coal Company, a joint venture of IERCo
BLM	-	U.S. Bureau of Land Management
~~CAA~~	-	~~Clean Air Act~~
CO₂	-	~~Carbon Dioxide~~
CSPP	-	Cogeneration and Small Power Production
~~CWA~~	-	~~Clean Water Act~~
EIS	-	Environmental Impact Statement
EPA	-	U.S. Environmental Protection Agency
FCA	-	Fixed Cost Adjustment
FERC	-	Federal Energy Regulatory Commission
HCC	-	Hells Canyon Complex
IDACORP	-	IDACORP, Inc., an Idaho corporation
Idaho Power	-	Idaho Power Company, an Idaho corporation
Idaho ROE	-	Idaho-jurisdiction return on year-end equity
Ida-West	-	Ida-West Energy, a subsidiary of IDACORP, Inc.
IERCo	-	Idaho Energy Resources Co., a subsidiary of Idaho Power Company
IESCo	-	IDACORP Energy Services Co., a subsidiary of IDACORP, Inc.
IFS	-	IDACORP Financial Services, a subsidiary of IDACORP, Inc.
IPUC	-	Idaho Public Utilities Commission
IRP	-	Integrated Resource Plan
kW	-	Kilowatt
MD&A	-	Management’s Discussion and Analysis of Financial Condition and Results of Operations
MW	-	Megawatt
MWh	-	Megawatt-hour
NO_x	-	Nitrogen Oxide
O&M	-	Operations and Maintenance
OATT	-	Open Access Transmission Tariff
OPUC	-	Public Utility Commission of Oregon
PCA	-	Power Cost Adjustment
PURPA	-	Public Utility Regulatory Policies Act of 1978
REC	-	Renewable Energy Certificate
SCR	-	Selective Catalytic Reduction
SEC	-	U.S. Securities and Exchange Commission
SMSP	-	Security Plan for Senior Management Employees
SO₂	-	~~Sulfur Dioxide~~
~~SRBA~~	-	~~Snake River Basin Adjudication~~
WPSC	-	Wyoming Public Service Commission

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

In addition to the historical information contained in this report, this report contains (and oral communications made by IDACORP, Inc. and Idaho Power Company may contain) statements that relate to future events and expectations, such as statements regarding projected or future financial performance, cash flows, capital expenditures, dividends, capital structure or ratios, strategic goals, challenges, objectives, and plans for future operations. Such statements constitute forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Any statements that express, or involve discussions as to, expectations, beliefs, plans, objectives, assumptions, or future events or performance, often, but not always, through the use of words or phrases such as "anticipates," "believes," "continues," "estimates," "expects," "guidance," "intends," "plans," "predicts," "projects," "may result,~~" "may continue," "may allow," "continues,~~" or similar expressions, are not statements of historical facts and may be forward-looking. Forward-looking statements are not guarantees of future performance and involve estimates, assumptions, risks, and uncertainties. Actual results, performance, or outcomes may differ materially from the results discussed in the statements. In addition to any assumptions and other factors and matters referred to specifically in connection with such forward-looking statements, factors that could cause actual results or outcomes to differ materially from those contained in forward-looking statements include those factors set forth in this report, IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, ~~2013,~~2014, particularly Part I, Item 1A - “Risk Factors” and Part II, Item 7 - “Management’s Discussion and Analysis of Financial Condition and Results of Operations" of that report, subsequent reports filed by IDACORP and Idaho Power with the Securities and Exchange Commission, and the following important factors:

the effect of decisions by the Idaho and Oregon public utilities commissions, the Federal Energy Regulatory Commission, and other regulators that impact Idaho Power's ability to recover costs and earn a return;

changes in residential, commercial, and industrial growth and demographic patterns within Idaho Power's service area, the loss or change in the business of significant customers, and the availability and use of demand-side management programs, and their associated impacts on loads and load growth;

the impacts of changes in economic conditions, including the potential for changes in customer demand for electricity, revenue from sales of excess power, financial soundness of counterparties and suppliers, and collections of receivables;

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

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

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

the ability to obtain debt and equity financing or refinance existing debt when necessary and on favorable terms, which can be affected by factors such as credit ratings, volatility in the financial markets, interest rate fluctuations, decisions by the Idaho or Oregon public utility commissions, and the companies' past or projected financial performance;

reductions in credit ratings, which could adversely impact access to capital markets and would require the posting of additional collateral to counterparties pursuant to credit and contractual arrangements;

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

the ability to purchase fuel and power on favorable payment terms and prices, particularly in the event of unanticipated power demands, lack of physical availability, transportation constraints, or a credit downgrade;

accidents, fires, explosions, and mechanical breakdowns that may occur while operating and maintaining an electric system, which can cause unplanned outages, reduce generating output, damage the companies’ assets, operations, or reputation, subject the companies to third-party claims for property damage, personal injury, or loss of life, or result in the imposition of civil, criminal, or regulatory fines or penalties;

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

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

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

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

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the increased costs and operational challenges ofassociated with purchasing and integrating intermittent ~~wind power or other~~ renewable energy sources into Idaho Power's resource portfolio;

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

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

changes in tax laws or related regulations or new interpretations of applicable laws by federal, state, or local taxing jurisdictions, the availability of tax credits, and the tax rates payable by IDACORP shareholders on common stock dividends;

employee workforce factors, including the operational and financial costs of unionization or the attempt to unionize all or part of the companies' workforce, the impact of an aging workforce and retirements, the cost and ability to retain skilled workers, and the ability to adjust the labor cost structure when necessary;

failure to comply with state and federal laws, policies, and regulations, including new interpretations and enforcement initiatives by regulatory and oversight bodies, which may result in penalties and fines and increase the cost of compliance, the nature and extent of investigations and audits, and the cost of remediation;

the inability to obtain or cost of obtaining and complying with required governmental permits and approvals, licenses, rights-of-way, and siting for transmission and generation projects and hydroelectric facilities;

the cost and outcome of litigation, dispute resolution, and regulatory proceedings, and the ability to recover those costs or the costs of operational changes through insurance or rates, or from third parties;

the failure of information systems or the failure to secure information system data, failure to comply with privacy laws, security breaches, or the direct or indirect effect on the companies' business or operations resulting from cyber attacks, terrorist incidents or the threat of terrorist incidents, and acts of war;

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

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

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

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PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

IDACORP, Inc.

Condensed Consolidated Statements of Income

(unaudited)


	Three months ended June 30,						Six months ended June 30,						Three months ended June 30,						Six months ended June 30,
	2014			2013			2014			2013			2015			2014			2015			2014
	(thousands of dollars except for per share amounts)												(thousands of dollars, except for per share amounts)
Operating Revenues:
Electric utility:
General business	$	282,147		$	264,432		$	526,979		$	496,651		$	308,660		$	282,147		$	557,146		$	526,979
Off-system sales	11,731			4,527			40,941			20,428			3,829			11,731			16,848			40,941
Other revenues	22,777			33,897			41,055			50,146			22,832			22,777			40,100			41,055
Total electric utility revenues	316,655			302,856			608,975			567,225			335,321			316,655			614,094			608,975
Other	1,128			1,092			1,527			1,652			1,007			1,128			1,629			1,527
Total operating revenues	317,783			303,948			610,502			568,877			336,328			317,783			615,723			610,502
Operating Expenses:
Electric utility:
Purchased power	62,437			49,151			106,233			92,008			51,336			62,437			94,301			106,233
Fuel expense	34,443			41,878			89,771			91,044			46,401			34,443			77,877			89,771
Power cost adjustment	9,141			(13,299		)	24,164			(28,009		)	10,531			9,141			38,285			24,164
Other operations and maintenance	87,452			83,154			167,973			162,939			87,843			87,452			171,357			167,973
Energy efficiency programs	7,620			19,732			12,344			24,202			7,867			7,620			12,209			12,344
Depreciation	32,952			32,232			65,827			64,142			34,314			32,952			68,357			65,827
Taxes other than income taxes	8,241			8,054			16,345			16,226			8,193			8,241			16,713			16,345
Total electric utility expenses	242,286			220,902			482,657			422,552			246,485			242,286			479,099			482,657
Other	3,688			3,640			7,458			7,485			3,867			3,688			7,743			7,458
Total operating expenses	245,974			224,542			490,115			430,037			250,352			245,974			486,842			490,115
Operating Income	71,809			79,406			120,387			138,840			85,976			71,809			128,881			120,387
Allowance for Equity Funds Used During Construction	4,459			3,528			8,538			7,143			5,378			4,459			10,565			8,538
Earnings of Unconsolidated Equity-Method Investments	1,510			442			2,493			3,141			3,270			1,510			3,110			2,493
Other Income, Net	1,252			1,588			3,540			2,414			1,871			1,252			3,831			3,540
Interest Expense:
Interest on long-term debt	20,141			20,793			40,282			40,462			21,056			20,141			41,829			40,282
Other interest	1,946			1,732			3,805			3,484			2,199			1,946			4,228			3,805
Allowance for borrowed funds used during construction	(2,145		)	(1,876		)	(4,109		)	(3,807		)	(2,592		)	(2,145		)	(4,957		)	(4,109		)
Total interest expense, net	19,942			20,649			39,978			40,139			20,663			19,942			41,100			39,978
Income Before Income Taxes	59,088			64,315			94,980			111,399			75,832			59,088			105,287			94,980
Income Tax Expense	14,391			17,676			23,098			29,719			9,642			14,391			15,753			23,098
Net Income	44,697			46,639			71,882			81,680			66,190			44,697			89,534			71,882
Adjustment for (income) loss attributable to noncontrolling interests	(157		)	(137		)	62			16			(110		)	(157		)	(24		)	62
Net Income Attributable to IDACORP, Inc.	$	44,540		$	46,502		$	71,944		$	81,696		$	66,080		$	44,540		$	89,510		$	71,944
Weighted Average Common Shares Outstanding - Basic (000’s)	50,133			50,056			50,133			50,047			50,222			50,133			50,221			50,133
Weighted Average Common Shares Outstanding - Diluted (000’s)	50,156			50,108			50,166			50,086			50,258			50,156			50,259			50,166
Earnings Per Share of Common Stock:
Earnings Attributable to IDACORP, Inc. - Basic	$	0.89		$	0.93		$	1.44		$	1.63		$	1.32		$	0.89		$	1.78		$	1.44
Earnings Attributable to IDACORP, Inc. - Diluted	$	0.89		$	0.93		$	1.43		$	1.63		$	1.31		$	0.89		$	1.78		$	1.43
Dividends Declared Per Share of Common Stock	$	0.43		$	0.38		$	0.86		$	0.76		$	0.47		$	0.43		$	0.94		$	0.86

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 June 30,						Six months ended June 30,				Three months ended June 30,						Six months ended June 30,
	2014			2013			2014		2013		2015			2014			2015			2014
	(thousands of dollars)										(thousands of dollars)

Net Income	$	44,697		$	46,639		$	71,882	$	81,680	$	66,190		$	44,697		$	89,534		$	71,882
Other Comprehensive Income:
Net unrealized holding gains arising during the period, net of tax of $0, $167, $0 and $925	—			259			—		1,440
Unfunded pension liability adjustment, net of tax of $277, $298, $555 and $596	432			465			864		930
Unfunded pension liability adjustment, net of tax of $428, $277, $856 and $555											667			432			1,334			864
Total Comprehensive Income	45,129			47,363			72,746		84,050		66,857			45,129			90,868			72,746
Comprehensive (income) loss attributable to noncontrolling interests	(157		)	(137		)	62		16		(110		)	(157		)	(24		)	62
Comprehensive Income Attributable to IDACORP, Inc.	$	44,972		$	47,226		$	72,808	$	84,066	$	66,747		$	44,972		$	90,844		$	72,808

The accompanying notes are an integral part of these statements.

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IDACORP, Inc.

Condensed Consolidated Balance Sheets

(unaudited)


	June 30, 2014			December 31, 2013			June 30, 2015			December 31, 2014
	(thousands of dollars)						(thousands of dollars)
Assets

Current Assets:
Cash and cash equivalents	$	50,621		$	78,162		$	130,979		$	56,808
Receivables:
Customer (net of allowance of $2,017 and $2,349, respectively)	98,000			97,873
Other (net of allowance of $155 and $153, respectively)	8,663			15,274
Customer (net of allowance of $995 and $1,960, respectively)							79,215			79,083
Other (net of allowance of $193 and $144, respectively)							7,087			16,018
Taxes receivable	—			156			1,348			11,867
Accrued unbilled revenues	70,896			63,507			87,580			56,270
Materials and supplies (at average cost)	55,316			53,643			56,389			55,404
Fuel stock (at average cost)	44,029			41,546			57,477			55,171
Prepayments	17,722			15,338			14,700			18,476
Deferred income taxes	29,545			46,874			42,345			42,359
Current regulatory assets	69,953			61,837			48,811			50,042
Other	2,250			2,401			2,113			603
Total current assets	446,995			476,611			528,044			442,101
Investments	162,916			159,072			159,466			165,424
Property, Plant and Equipment:
Utility plant in service	5,149,226			5,080,402			5,332,181			5,248,212
Accumulated provision for depreciation	(1,804,567		)	(1,766,680		)	(1,876,873		)	(1,841,011		)
Utility plant in service - net	3,344,659			3,313,722			3,455,308			3,407,201
Construction work in progress	370,895			327,000			454,757			401,930
Utility plant held for future use	7,090			7,090			7,090			7,090
Other property, net of accumulated depreciation	17,423			17,229			17,058			17,256
Property, plant and equipment - net	3,740,067			3,665,041			3,934,213			3,833,477
Other Assets:
American Falls and Milner water rights	14,219			15,803			12,113			13,698
Company-owned life insurance	19,614			22,037			21,148			23,893
Regulatory assets	956,003			978,234			1,164,183			1,192,345
Long-term receivables (net of allowance of $885 and $885, respectively)	6,115			4,811
Long-term receivables (net of allowance of $552)							18,991			6,317
Other	43,940			42,954			59,218			39,598
Total other assets	1,039,891			1,063,839			1,275,653			1,275,851
Total	$	5,389,869		$	5,364,563		$	5,897,376		$	5,716,853

The accompanying notes are an integral part of these statements.

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IDACORP, Inc.

Condensed Consolidated Balance Sheets

(unaudited)


	June 30, 2014			December 31, 2013			June 30, 2015			December 31, 2014
	(thousands of dollars)						(thousands of dollars)
Liabilities and Equity

Current Liabilities:
Current maturities of long-term debt	$	1,064		$	1,064		$	1,064		$	1,064
Notes payable	37,200			54,750			27,000			31,300
Accounts payable	82,424			91,519			89,035			97,271
Taxes accrued	27,739			13,302			15,920			10,367
Interest accrued	22,693			22,764			22,160			22,630
Accrued compensation	32,989			38,510			34,694			43,774
Current regulatory liabilities	6,447			10,684			8,071			11,400
Other	25,702			17,779			35,826			23,975
Total current liabilities	236,258			250,372			233,770			241,781
Other Liabilities:
Deferred income taxes	980,139			969,593			1,064,620			1,065,290
Regulatory liabilities	376,820			375,873			399,347			390,207
Pension and other postretirement benefits	247,776			244,627			407,363			403,334
Other	48,656			54,100			47,669			44,238
Total other liabilities	1,653,391			1,644,193			1,918,999			1,903,069
Long-Term Debt	1,614,316			1,615,258			1,741,800			1,614,438
Commitments and Contingencies
Equity:
IDACORP, Inc. shareholders’ equity:
Common stock, no par value (shares authorized 120,000,000; 50,307,512 and 50,233,463 shares issued, respectively)	841,718			839,750
Common stock, no par value (shares authorized 120,000,000; 50,352,051 and 50,308,702 shares issued, respectively)							846,914			845,402
Retained earnings	1,056,133			1,027,461			1,174,366			1,132,237
Accumulated other comprehensive loss	(15,689		)	(16,553		)	(22,824		)	(24,158		)
Treasury stock (38,764 and 718 shares at cost, respectively)	(286		)	(8		)
Treasury stock (10,652 and 38,764 shares at cost, respectively)							(37		)	(280		)
Total IDACORP, Inc. shareholders’ equity	1,881,876			1,850,650			1,998,419			1,953,201
Noncontrolling interests	4,028			4,090			4,388			4,364
Total equity	1,885,904			1,854,740			2,002,807			1,957,565
Total	$	5,389,869		$	5,364,563		$	5,897,376		$	5,716,853

The accompanying notes are an integral part of these statements.

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IDACORP, Inc.

Condensed Consolidated Statements of Cash Flows

(unaudited)


	Six months ended June 30,						Six months ended June 30,
	2014			2013			2015			2014
	(thousands of dollars)						(thousands of dollars)
Operating Activities:
Net income	$	71,882		$	81,680		$	89,534		$	71,882
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	67,857			66,025			70,511			67,857
Deferred income taxes and investment tax credits	4,933			17,747			(312		)	4,933
Changes in regulatory assets and liabilities	29,513			(24,727		)	31,375			29,513
Pension and postretirement benefit plan expense	13,937			14,672			15,131			13,937
Contributions to pension and postretirement benefit plans	(8,837		)	(12,391		)	(12,395		)	(8,837		)
Earnings of unconsolidated equity-method investments	(2,493		)	(3,141		)	(3,110		)	(2,493		)
Distributions from unconsolidated equity-method investments	—			7,989			5,723			—
Allowance for equity funds used during construction	(8,538		)	(7,143		)	(10,565		)	(8,538		)
Other non-cash adjustments to net income, net	1,170			1,198			431			1,170
Change in:
Accounts receivable	6,258			1,466			(782		)	6,258
Accounts payable and other accrued liabilities	(13,663		)	(12,204		)	(12,871		)	(13,663		)
Taxes accrued/receivable	15,561			13,646			17,868			15,561
Other current assets	(16,943		)	(30,061		)	(28,607		)	(16,943		)
Other current liabilities	7,710			6,552			7,834			7,710
Other assets	1,173			(582		)	2,923			1,173
Other liabilities	(6,213		)	(6,517		)	(1,713		)	(6,213		)
Net cash provided by operating activities	163,307			114,209			170,975			163,307
Investing Activities:
Additions to property, plant and equipment	(128,326		)	(109,059		)	(152,973		)	(128,326		)
Proceeds from the sale of emission allowances and RECs	2,615			480			1,536			2,615
Distributions from affordable housing investments	848			1,642			234			848
Investments in unconsolidated affiliates	(1,639		)	—			—			(1,639		)
Other	(946		)	2,371			557			(946		)
Net cash used in investing activities	(127,448		)	(104,566		)	(150,646		)	(127,448		)
Financing Activities:
Issuance of long-term debt	—			150,000			250,000			—
Retirement of long-term debt	(1,064		)	(1,064		)	(121,064		)	(1,064		)
Dividends on common stock	(43,419		)	(38,313		)	(47,327		)	(43,419		)
Net change in short-term borrowings	(17,550		)	(7,800		)	(4,300		)	(17,550		)
Issuance of common stock	160			255			—			160
Acquisition of treasury stock	(2,737		)	(2,124		)	(3,277		)	(2,737		)
Make-whole premium on retirement of long-term debt							(17,872		)	—
Other	1,210			(969		)	(2,318		)	1,210
Net cash (used in) provided by financing activities	(63,400		)	99,985
Net (decrease) increase in cash and cash equivalents	(27,541		)	109,628
Net cash provided by (used in) financing activities							53,842			(63,400		)
Net increase (decrease) in cash and cash equivalents							74,171			(27,541		)
Cash and cash equivalents at beginning of the period	78,162			26,527			56,808			78,162
Cash and cash equivalents at end of the period	$	50,621		$	136,155		$	130,979		$	50,621
Supplemental Disclosure of Cash Flow Information:
Cash paid during the period for:
Income taxes	$	4,686		$	60		$	284		$	4,686
Interest (net of amount capitalized)	$	38,739		$	37,610		$	40,081		$	38,739
Non-cash investing activities:
Additions to property, plant and equipment in accounts payable	$	21,395		$	12,348		$	21,889		$	21,395

The accompanying notes are an integral part of these statements.

Table of ~~contents~~Contents

IDACORP, Inc.

Condensed Consolidated Statements of Equity

(unaudited)


	Six months ended June 30,						Six months ended June 30,
	2014			2013			2015			2014
	(thousands of dollars)						(thousands of dollars)
Common Stock
Balance at beginning of period	$	839,750		$	834,922		$	845,402		$	839,750
Issued	160			255			—			160
Other	1,808			1,383			1,512			1,808
Balance at end of period	841,718			836,560			846,914			841,718
Retained Earnings
Balance at beginning of period	1,027,461			923,981			1,132,237			1,027,461
Net income attributable to IDACORP, Inc.	71,944			81,696			89,510			71,944
Common stock dividends ($0.86 and $0.76 per share)	(43,272		)	(38,192		)
Common stock dividends ($0.94 and $0.86 per share)							(47,381		)	(43,272		)
Balance at end of period	1,056,133			967,485			1,174,366			1,056,133
Accumulated Other Comprehensive (Loss) Income
Balance at beginning of period	(16,553		)	(17,116		)	(24,158		)	(16,553		)
Unrealized gain on securities (net of tax)	—			1,440
Unfunded pension liability adjustment (net of tax)	864			930			1,334			864
Balance at end of period	(15,689		)	(14,746		)	(22,824		)	(15,689		)
Treasury Stock
Balance at beginning of period	(8		)	(21		)	(280		)	(8		)
Issued	2,459			2,132			3,526			2,459
Acquired	(2,737		)	(2,124		)	(3,283		)	(2,737		)
Balance at end of period	(286		)	(13		)	(37		)	(286		)
Total IDACORP, Inc. shareholders’ equity at end of period	1,881,876			1,789,286			1,998,419			1,881,876
Noncontrolling Interests
Balance at beginning of period	4,090			4,213			4,364			4,090
Net loss attributable to noncontrolling interests	(62		)	(16		)
Net income (loss) attributable to noncontrolling interests							24			(62		)
Balance at end of period	4,028			4,197			4,388			4,028
Total equity at end of period	$	1,885,904		$	1,793,483		$	2,002,807		$	1,885,904

The accompanying notes are an integral part of these statements.

Table of ~~contents~~Contents

Idaho Power Company

Condensed Consolidated Statements of Income

(unaudited)


	Three months ended June 30,						Six months ended June 30,						Three months ended June 30,						Six months ended June 30,
	2014			2013			2014			2013			2015			2014			2015			2014
	(thousands of dollars)												(thousands of dollars)
Operating Revenues:
General business	$	282,147		$	264,432		$	526,979		$	496,651		$	308,660		$	282,147		$	557,146		$	526,979
Off-system sales	11,731			4,527			40,941			20,428			3,829			11,731			16,848			40,941
Other revenues	22,777			33,897			41,055			50,146			22,832			22,777			40,100			41,055
Total operating revenues	316,655			302,856			608,975			567,225			335,321			316,655			614,094			608,975
Operating Expenses:
Operation:
Purchased power	62,437			49,151			106,233			92,008			51,336			62,437			94,301			106,233
Fuel expense	34,443			41,878			89,771			91,044			46,401			34,443			77,877			89,771
Power cost adjustment	9,141			(13,299		)	24,164			(28,009		)	10,531			9,141			38,285			24,164
Other operations and maintenance	87,452			83,154			167,973			162,939			87,843			87,452			171,357			167,973
Energy efficiency programs	7,620			19,732			12,344			24,202			7,867			7,620			12,209			12,344
Depreciation	32,952			32,232			65,827			64,142			34,314			32,952			68,357			65,827
Taxes other than income taxes	8,241			8,054			16,345			16,226			8,193			8,241			16,713			16,345
Total operating expenses	242,286			220,902			482,657			422,552			246,485			242,286			479,099			482,657
Income from Operations	74,369			81,954			126,318			144,673			88,836			74,369			134,995			126,318
Other Income (Expense):
Allowance for equity funds used during construction	4,459			3,528			8,538			7,143			5,378			4,459			10,565			8,538
Earnings (losses) of unconsolidated equity-method investments	721			(378		)	1,968			2,256
Earnings of unconsolidated equity-method investments													2,530			721			2,658			1,968
Other expense, net	(1,591		)	(1,215		)	(2,019		)	(3,374		)	(1,316		)	(1,591		)	(2,460		)	(2,019		)
Total other income	3,589			1,935			8,487			6,025			6,592			3,589			10,763			8,487
Interest Charges:
Interest on long-term debt	20,141			20,793			40,282			40,462			21,056			20,141			41,829			40,282
Other interest	1,890			1,637			3,688			3,284			2,129			1,890			4,107			3,688
Allowance for borrowed funds used during construction	(2,145		)	(1,876		)	(4,109		)	(3,807		)	(2,592		)	(2,145		)	(4,957		)	(4,109		)
Total interest charges	19,886			20,554			39,861			39,939			20,593			19,886			40,979			39,861
Income Before Income Taxes	58,072			63,335			94,944			110,759			74,835			58,072			104,779			94,944
Income Tax Expense	15,419			18,352			24,390			31,730			10,495			15,419			16,977			24,390
Net Income	$	42,653		$	44,983		$	70,554		$	79,029		$	64,340		$	42,653		$	87,802		$	70,554

The accompanying notes are an integral part of these statements.

Table of ~~contents~~Contents

Idaho Power Company

Condensed Consolidated Statements of Comprehensive Income

(unaudited)


	Three months ended June 30,				Six months ended June 30,				Three months ended June 30,				Six months ended June 30,
	2014		2013		2014		2013		2015		2014		2015		2014
	(thousands of dollars)								(thousands of dollars)

Net Income	$	42,653	$	44,983	$	70,554	$	79,029	$	64,340	$	42,653	$	87,802	$	70,554
Other Comprehensive Income:
Net unrealized holding gains arising during the period, net of tax of $0, $167, $0 and $925	—		259		—		1,440
Unfunded pension liability adjustment, net of tax of $277, $298, $555 and $596	432		465		864		930
Unfunded pension liability adjustment, net of tax of $428, $277, $856 and $555									667		432		1,334		864
Total Comprehensive Income	$	43,085	$	45,707	$	71,418	$	81,399	$	65,007	$	43,085	$	89,136	$	71,418

The accompanying notes are an integral part of these statements.

Table of ~~contents~~Contents

Idaho Power Company

Condensed Consolidated Balance Sheets

(unaudited)


	June 30, 2014			December 31, 2013			June 30, 2015			December 31, 2014
	(thousands of dollars)						(thousands of dollars)
Assets

Electric Plant:
In service (at original cost)	$	5,149,226		$	5,080,402		$	5,332,181		$	5,248,212
Accumulated provision for depreciation	(1,804,567		)	(1,766,680		)	(1,876,873		)	(1,841,011		)
In service - net	3,344,659			3,313,722			3,455,308			3,407,201
Construction work in progress	370,895			327,000			454,757			401,930
Held for future use	7,090			7,090			7,090			7,090
Electric plant - net	3,722,644			3,647,812			3,917,155			3,816,221
Investments and Other Property	137,540			131,520			137,849			142,825
Current Assets:
Cash and cash equivalents	42,848			66,535			125,206			46,695
Receivables:
Customer (net of allowance of $2,017 and $2,349, respectively)	98,000			97,873
Other (net of allowance of $155 and $153, respectively)	8,378			14,290
Customer (net of allowance of $995 and $1,960, respectively)							79,215			79,083
Other (net of allowance of $193 and $144, respectively)							6,964			15,890
Taxes receivable							1,363			20,428
Accrued unbilled revenues	70,896			63,507			87,580			56,270
Materials and supplies (at average cost)	55,316			53,643			56,389			55,404
Fuel stock (at average cost)	44,029			41,546			57,477			55,171
Prepayments	17,597			15,204			14,574			18,356
Deferred income taxes	—			12,386
Current regulatory assets	69,953			61,837			48,811			50,042
Other	2,250			2,401			2,112			603
Total current assets	409,267			429,222			479,691			397,942
Deferred Debits:
American Falls and Milner water rights	14,219			15,803			12,113			13,698
Company-owned life insurance	19,614			22,037			21,148			23,893
Regulatory assets	956,003			978,234			1,164,183			1,192,345
Other	44,147			41,783			72,125			39,753
Total deferred debits	1,033,983			1,057,857			1,269,569			1,269,689
Total	$	5,303,434		$	5,266,411		$	5,804,264		$	5,626,677

The accompanying notes are an integral part of these statements.

Table of ~~contents~~Contents

Idaho Power Company

Condensed Consolidated Balance Sheets

(unaudited)


	June 30, 2014			December 31, 2013			June 30, 2015			December 31, 2014
	(thousands of dollars)						(thousands of dollars)
Capitalization and Liabilities

Capitalization:
Common stock equity:
Common stock, $2.50 par value (50,000,000 shares authorized; 39,150,812 shares outstanding)	$	97,877		$	97,877		$	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	960,163			932,547			1,073,615			1,033,350
Accumulated other comprehensive loss	(15,689		)	(16,553		)	(22,824		)	(24,158		)
Total common stock equity	1,752,512			1,724,032			1,858,829			1,817,230
Long-term debt	1,614,316			1,615,258			1,741,800			1,614,438
Total capitalization	3,366,828			3,339,290			3,600,629			3,431,668
Current Liabilities:
Long-term debt due within one year	1,064			1,064
Current maturities of long-term debt							1,064			1,064
Accounts payable	81,696			90,529			88,299			96,499
Accounts payable to affiliates	1,603			1,158			1,397			2,027
Taxes accrued	28,165			14,031			12,849			10,329
Interest accrued	22,693			22,764			22,166			22,630
Accrued compensation	32,839			38,297			34,579			43,410
Current regulatory liabilities	6,447			10,684			8,071			11,400
Other	29,428			17,095			41,641			29,476
Total current liabilities	203,935			195,622			210,066			216,835
Deferred Credits:
Deferred income taxes	1,060,732			1,058,734			1,140,359			1,141,755
Regulatory liabilities	376,820			375,873			399,347			390,207
Pension and other postretirement benefits	247,776			244,627			407,364			403,334
Other	47,343			52,265			46,499			42,878
Total deferred credits	1,732,671			1,731,499			1,993,569			1,978,174

Commitments and Contingencies

Total	$	5,303,434		$	5,266,411		$	5,804,264		$	5,626,677

The accompanying notes are an integral part of these statements.

Table of ~~contents~~Contents

Idaho Power Company

Condensed Consolidated Statements of Cash Flows

(unaudited)


	Six months ended June 30,						Six months ended June 30,
	2014			2013			2015			2014
	(thousands of dollars)						(thousands of dollars)
Operating Activities:
Net income	$	70,554		$	79,029		$	87,802		$	70,554
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	67,566			65,675			70,206			67,566
Deferred income taxes and investment tax credits	(6,556		)	17,817			(2,252		)	(6,556		)
Changes in regulatory assets and liabilities	29,513			(24,727		)	31,376			29,513
Pension and postretirement benefit plan expense	13,920			14,657			15,125			13,920
Contributions to pension and postretirement benefit plans	(8,820		)	(12,376		)	(12,389		)	(8,820		)
Earnings of unconsolidated equity-method investments	(1,968		)	(2,256		)	(2,658		)	(1,968		)
Distributions from unconsolidated equity-method investments	—			7,214			5,723			—
Allowance for equity funds used during construction	(8,538		)	(7,143		)	(10,565		)	(8,538		)
Other non-cash adjustments to net income, net	(649		)	(562		)	(963		)	(649		)
Change in:
Accounts receivable	5,530			(238		)	(2,849		)	5,530
Accounts payable	(13,624		)	(12,041		)	(12,624		)	(13,624		)
Taxes accrued/receivable	15,695			17,462			23,329			15,695
Other current assets	(16,951		)	(30,045		)	(28,601		)	(16,951		)
Other current liabilities	7,752			6,501			7,881			7,752
Other assets	1,173			(582		)	2,923			1,173
Other liabilities	(5,690		)	(6,179		)	(1,518		)	(5,690		)
Net cash provided by operating activities	148,907			112,206			169,946			148,907
Investing Activities:
Additions to utility plant	(128,234		)	(109,059		)	(152,943		)	(128,234		)
Proceeds from the sale of emission allowances and RECs	2,615			480			1,536			2,615
Investments in unconsolidated affiliates	(1,639		)	—			—			(1,639		)
Other	(946		)	2,372			557			(946		)
Net cash used in investing activities	(128,204		)	(106,207		)	(150,850		)	(128,204		)
Financing Activities:
Issuance of long-term debt	—			150,000			250,000			—
Retirement of long-term debt	(1,064		)	(1,064		)	(121,064		)	(1,064		)
Dividends on common stock	(43,326		)	(38,213		)	(47,537		)	(43,326		)
Make-whole premium on retirement of long-term debt							(17,872		)	—
Other	—			(1,821		)	(4,112		)	—
Net cash (used in) provided by financing activities	(44,390		)	108,902
Net (decrease) increase in cash and cash equivalents	(23,687		)	114,901
Net cash provided by (used in) financing activities							59,415			(44,390		)
Net increase (decrease) in cash and cash equivalents							78,511			(23,687		)
Cash and cash equivalents at beginning of the period	66,535			17,251			46,695			66,535
Cash and cash equivalents at end of the period	$	42,848		$	132,152		$	125,206		$	42,848
Supplemental Disclosure of Cash Flow Information:
Cash paid (received) during the period for:
Income taxes paid (received)	$	17,332		$	(1,840	)
Cash (received) paid during the period for:
Income taxes							$	(2,034	)	$	17,332
Interest (net of amount capitalized)	$	38,622		$	37,410		$	39,954		$	38,622
Non-cash investing activities:
Additions to property, plant and equipment in accounts payable	$	21,395		$	12,348		$	21,889		$	21,395

The accompanying notes are an integral part of these statements.

Table of ~~contents~~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 ~~Federal Energy Regulatory Commission (FERC) and the~~ state utility regulatory commissions of Idaho and ~~Oregon.~~Oregon and the Federal Energy Regulatory Commission (FERC). Idaho Power is the parent of Idaho Energy Resources Co. (IERCo), a joint venturer in Bridger Coal Company (BCC), which mines and supplies coal to the Jim Bridger generating plant owned in part by Idaho Power.

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

Regulation of Utility Operations

IDACORP's and Idaho Power's financial statements reflect the effects of the different ratemaking principles followed by the jurisdictions regulating Idaho Power. The application of accounting principles related to regulated operations sometimes results in Idaho Power recording expenses and revenues in a different period than when an unregulated enterprise would record such expenses and revenues. In these instances, the amounts are deferred as regulatory assets or regulatory liabilities on the balance sheet and recorded on the income statement when recovered or returned through rates. Additionally, regulators can impose regulatory liabilities upon a regulated company for amounts previously collected from customers that are expected to be refunded. The effects of applying these regulatory accounting principles to Idaho Power's operations are discussed in more detail in Note 3.

Financial Statements

In the opinion of management of IDACORP and Idaho Power, the accompanying unaudited condensed consolidated financial statements contain all adjustments necessary to present fairly each company's consolidated financial position as of June 30, ~~2014~~2015, consolidated results of operations for the three and six months ended June 30, ~~2014~~2015 and ~~2013~~2014, and consolidated cash flows for the six months ended June 30, ~~2014~~2015 and ~~2013~~2014. These adjustments are of a normal and recurring nature. These financial statements do not contain the complete detail or footnote disclosure concerning accounting policies and other matters that would be included in full-year financial statements and should be read in conjunction with the audited consolidated financial statements included in IDACORP’s and Idaho Power’s Annual Report on Form 10-K for the year ended December 31, ~~2013~~2014. The results of operations for the interim period are not necessarily indicative of the results to be expected for the full year. A change in management's estimates or assumptions could have a material impact on IDACORP's or Idaho Power's respective financial condition and results of operations during the period in which such change occurred.

Management Estimates

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

Table of ~~contents~~Contents

~~Change in Method of Accounting for Investments in Qualified Affordable Housing Projects~~Asset Retirement Obligations

~~On January 15,~~In December 2014, the ~~Financial Accounting Standards Board issued Accounting Standards Update (ASU) No. 2014-01,~~ ~~Investments-Equity Method and Joint Ventures (Topic 323): Accounting for Investments in Qualified Affordable Housing Projects~~. This ASU permits an accounting policy election to account for investments in qualified affordable housing projects using the proportional amortization method. For its consolidated financial statements as of and for the year ended December 31, 2013, IDACORP elected early adoption of ASU 2014-01 and thus changed its accounting for its equity-method investments in qualified affordable housing projectsU.S. Environmental Protection Agency signed a final rule relating to the ~~proportional amortization method. All prior periods were properly adjusted~~disposal of coal combustion residuals, which was published in the Federal Register on April 17, 2015. The rule adds several regulations relating to ~~reflect~~the disposal and ongoing monitoring of coal combustion residuals. Idaho Power jointly owns three coal-fired power plants that are subject to the new ~~method. The standard also requires~~regulations. Together with its co-owners, Idaho Power performed engineering and cost studies to determine the ~~recognition~~financial and operational impacts of the ~~net investment performance~~new rule. Based on these studies, which incorporated revised assumptions about the remaining lives and operations of existing coal-combustion residual facilities, Idaho Power recorded an increase of $5 million to its asset retirement obligations and an associated $7 million increase to ARO assets and $2 million decrease to regulatory assets in the ~~financial statements as a component~~second quarter of income tax expense (benefit). The new method was elected because IDACORP believes the proportional amortization method more fairly represents the economics of and provides users with a better understanding of the returns from such investments than the equity method of amortization.2015.

2. INCOME TAXES

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

Income Tax Expense

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


	IDACORP						Idaho Power						IDACORP						Idaho Power
	2014			2013			2014			2013			2015			2014			2015			2014
Three months ended June 30,
Income tax at statutory rates (federal and state)	$	23,042		$	25,094		$	22,707		$	24,764		$	41,158		$	37,161		$	40,969		$	37,123
Additional accumulated deferred investment tax credit amortization	950			—			950			—
Affordable housing tax credits	(1,256		)	(1,384		)	—			—
Affordable housing investment amortization, net of statutory taxes	640			658			—			—
Other⁽¹⁾	(8,985		)	(6,692		)	(8,238		)	(6,412		)
Income tax expense	$	14,391		$	17,676		$	15,419		$	18,352

Six months ended June 30,
Income tax at statutory rates (federal and state)	$	37,161		$	43,563		$	37,123		$	43,307
First mortgage bond redemption costs													(7,210		)	—			(7,210		)	—
Affordable housing tax credits	(2,524		)	(2,768		)	—			—			(1,615		)	(2,524		)	—			—
Affordable housing investment amortization, net of statutory taxes	1,344			557			—			—			749			1,344			—			—
Other⁽¹⁾	(12,883		)	(11,633		)	(12,733		)	(11,577		)	(17,329		)	(12,883		)	(16,782		)	(12,733		)
Income tax expense	$	23,098		$	29,719		$	24,390		$	31,730		$	15,753		$	23,098		$	16,977		$	24,390
Effective tax rate	24.3		%	26.7		%	25.7		%	28.6		%	15.0		%	24.3		%	16.2		%	25.7		%

⁽¹⁾ "Other" is primarily comprised of the net tax effect of Idaho Power's regulatory flow-through tax adjustments. These adjustments, which include the capitalized repairs deduction, are each listed in the rate reconciliation table in Note 2 to the consolidated financial statements included in IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, ~~2013.~~2014.

InThe reductions in income tax expense for the six months ended June 30, 2015, as compared with the same period in 2014, were primarily due to the flow-through income tax benefit related to the current income tax deduction for bond redemption costs incurred in the second quarter of ~~2014,~~2015. On a net basis, Idaho ~~Power reversed the $950 thousand of additional accumulated deferred investment tax credit (ADITC) amortization recorded in the first quarter of 2014, based on its updated~~Power’s estimate of ~~year-end 2014 return on year-end equity in~~its annual 2015 regulatory flow-through tax adjustments is comparable to 2014; additionally, the ~~Idaho jurisdiction (Idaho ROE). See Note 3 for a discussion of Idaho Power's regulatory authority for use of additional ADITC amortization.~~2015 capitalized repairs deduction estimate is slightly greater than the prior year estimate.

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3. REGULATORY MATTERS

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

Idaho and Oregon General Rate Cases and Base Rate Adjustments

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

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

Idaho and Oregon base rates were subsequently adjusted again in 2012, in connection with Idaho Power's completion of the Langley Gulch power plant. On June 29, 2012, the IPUC issued an order approving a $58.1 million increase in annual Idaho-jurisdiction base rate revenues, effective July 1, 2012, for inclusion of the investment and associated costs of the plant in rates. The order also provided for a $335.9 million increase in Idaho rate base. On September 20, 2012, the OPUC issued an order approving a $3.0 million increase in annual Oregon jurisdiction base rate revenues, effective October 1, 2012, for inclusion of the investment and associated costs of the plant in Oregon rates.

~~See "Idaho Power Cost Adjustment Mechanism; Update to Base -Level Net Power Supply Expense" below in this Note 3 for a description of~~On March 21, 2014, the IPUC issued an order approving Idaho Power's ~~authorization from~~application requesting an increase of approximately $106 million in the ~~IPUC to move a portion of its~~normalized or "base level" net power supply ~~expenses into Idaho~~expense on a total-system basis to be used to update base rates and in the determination of the PCA rate that became effective June 1, 2014. Approval of the order removed the Idaho-jurisdictional portion of those expenses (approximately $99 million) from collection via the Idaho PCA mechanism and instead results in collecting that portion through base rates.

Idaho Settlement Stipulation — Investment Tax Credits and Sharing Mechanism

~~On December 27, 2011,~~In October 2014, the IPUC issued an order ~~separate from~~approving an extension, with modifications, of the ~~then-pending~~terms of a December 2011 Idaho ~~general rate case proceeding, approving a~~ settlement stipulation ~~that provides~~for the period from 2015 through 2019, or until the terms are otherwise modified or terminated by order of the IPUC. The provisions of the October 2014 settlement stipulation are as follows:

ifIf Idaho Power's ~~actual~~annual return on year-end equity in the Idaho ~~ROE for 2012, 2013, or 2014~~jurisdiction (Idaho ROE) in any year is less than 9.5 percent,, then Idaho Power may amortize up to $25 million of additional ~~ADITC~~accumulated deferred investment tax credits (ADITC) to help achieve a ~~minimum~~ 9.5 percent Idaho ROE for that year, and may amortize up to a total of $45 million of additional ADITC over the 2015 through 2019 period.

If Idaho Power's annual Idaho ROE in ~~the applicable year. Idaho Power would be permitted to amortize additional ADITC in an aggregate amount up to~~ ~~$45 million~~ ~~over the~~ ~~three-year period;~~

~~if Idaho Power's actual Idaho ROE for 2012, 2013, or 2014~~any year exceeds 10.0 percent,, the amount of ~~Idaho Power's Idaho-jurisdiction~~ earnings exceeding a 10.0 percent Idaho ROE and up to and including a 10.5 percent Idaho ROE ~~for the applicable year would~~will be ~~shared equally between~~allocated 75 percent to Idaho ~~Power and its~~Power's Idaho customers ~~in the form of~~as a rate reduction to ~~become~~be effective at the time of the subsequent year's power cost adjustment ~~(PCA);~~ and

25 percent to Idaho Power.

ifIf Idaho Power's ~~actual~~annual Idaho ROE ~~for 2012, 2013, or 2014~~in any year exceeds 10.5 percent,, the amount of ~~Idaho Power's Idaho-jurisdiction~~ earnings exceeding a 10.5 percent Idaho ROE ~~for the applicable year would~~will be allocated 7550 percent to Idaho Power's Idaho customers ~~through~~as a rate reduction to be effective at the time of the subsequent year's power cost adjustment, 25 percent to Idaho Power's Idaho customers in the form of a reduction to the pension regulatory asset balancing account (to reduce the amount to be collected in the future from Idaho customers), and 25 percent to Idaho Power.

~~The~~If the full $45 million of additional ADITC contemplated by the settlement stipulation ~~also provides that~~has been amortized the ~~Idaho ROE thresholds (9.5 percent~~, ~~10.0 percent, and~~ ~~10.5 percent) will be automatically adjusted prospectively in~~sharing provisions would terminate.

In the event the IPUC approves a change to Idaho Power's ~~authorized~~Idaho-jurisdictional allowed return on equity as part of a general rate case proceeding seeking a rate change effective prior to January 1, ~~2015.~~

~~Based on Idaho Power's~~2020, the Idaho ROE ~~in 2012~~thresholds (9.5 percent, 10.0 percent, and ~~2013, Idaho Power triggered the sharing mechanism of the December 2011 settlement stipulation for both years. The amounts Idaho Power recorded for revenue sharing were as follows (in millions):~~

2013 2012
Additional pension expense funded through sharing $ 16.5
$ 14.6
Provision against current revenue as a result of sharing 7.6
7.2
Total $ 24.1
$ 21.8
10.5 percent) will be adjusted prospectively.

In the first ~~quarter~~six months of ~~2014,~~2015, Idaho Power recorded ~~$950 thousand of~~no additional ADITC amortization or provision for ~~that period~~sharing with customers based on its ~~then-current~~ estimate of ~~the company's year-end 2014~~ Idaho ROE ~~being less than the 9.5 percent threshold (absent amortization~~

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~~of additional ADITC).~~for full-year 2015. In the second quarter of 2014, Idaho Power reversed the $950 thousand of additional ADITC amortization it had recorded in the first quarter of 2014, based on its ~~updated~~then-current estimate of Idaho ROE for full-year 2014, under the ~~company's year-end 2014 Idaho ROE.~~

~~Application to Extend Terms of Idaho Settlement Stipulation~~

~~On May 30, 2014, Idaho Power filed an application with the IPUC requesting an extension of the terms of the~~prior December 2011 settlement stipulation described above. Idaho Power's application requested that the IPUC issue an order extending the terms of the December 2011 settlement stipulation until Idaho Power has amortized a total of $45 million of additional ADITCs (including any additional ADITCs amortized in 2014) or until the terms are otherwise modified or terminated by order of the IPUC. Idaho Power requested that the IPUC issue its decision and order no later than December 31, 2014.stipulation.

Idaho Power Cost Adjustment ~~Mechanism; Update to Base Level Net Power Supply Expense~~Mechanism Annual Filing

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

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On ~~November 1, 2013, Idaho Power filed an application with the IPUC requesting an increase of approximately~~ ~~$106 million~~ in the normalized or "base level" net power supply expense on a total-system basis to be used to update base rates and in the determination of the PCA rate that would become effective June 1, 2014. Idaho Power's request was intended to remove the Idaho-jurisdictional portion of those expenses from collection via the Idaho PCA mechanism and instead collect that portion through base rates. On March 21, 2014,May 28, 2015, the IPUC issued an order approving an $11.6 million net decrease in Idaho ~~Power's application, with~~PCA rates, effective for the ~~change in~~2015-2016 PCA collection ~~methodology effective~~period from June 1, ~~2014.~~2015 to May 31, 2016. The requested net decrease in Idaho PCA rates included the application of (a) a customer rate credit of $8.0 million for sharing of revenues with customers for the year 2014 under the terms of the December 2011 settlement stipulation, (b) a $1.5 million customer benefit relating to a change to the PCA methodology described below, and (c) $4.0 million of surplus Idaho energy efficiency rider funds.

OnPreviously, on May 30, 2014, the IPUC issued an order approving Idaho Power's April 15, 2014 application requesting an $11.1 million net increase in Idaho PCA rates, effective for the 2014-2015 PCA collection period from June 1, 2014 to May 31, 2015. The $11.1 million PCA rate increase was net of ~~Idaho Power's~~(a) $20.0 million of surplus Idaho energy efficiency rider ~~funds. The PCA rate increase was also net of~~funds, (b) $7.6 million of customer revenue sharing for the year 2013 under the December 2011 settlement stipulation, ~~described above. Previously,~~and (c) the shifting of $99.3 million in ~~May 2013~~power supply expense from collection via the ~~IPUC issued an order authorizing a~~ ~~$140.4 million~~ ~~increase in~~ PCA ~~rates (net of 2012 revenue sharing), effective for the 2013-2014 PCA~~mechanism to collection ~~period from June 1, 2013 to May 31, 2014.~~via base rates.

~~Annual~~ Idaho Fixed Cost Adjustment Mechanism Annual Filing

The fixed cost adjustment (FCA) is designed to remove Idaho Power’s financial disincentive to invest in energy efficiency programs by separating (or decoupling) the recovery of fixed costs from the variable kilowatt-hour charge and linking it instead to a set amount per customer. The FCA rate is adjusted each year to recover or refund the difference between the amount of fixed costs authorized in Idaho Power's most recent general rate case and the amount of fixed costs recovered by Idaho Power based upon weather-normalized energy sales. On May 19, 2015, the IPUC issued an order approving Idaho Power's application requesting an increase of $2.0 million in the FCA from $14.9 million to $16.9 million, with new rates effective for the period from June 1, 2015 through May 31, 2016. Previously, on May 30, 2014, the IPUC issued an order approving Idaho Power's ~~March 14, 2014~~ application requesting a $6.0 million increase in the FCA ~~recovery~~ from $8.9 million to $14.9 million, effective for the period from June 1, 2014 tothrough May 31, 2015. ~~Previously, on May 22, 2013, the IPUC issued an order authorizing a decrease in FCA collection from~~ ~~$10.3 million~~ to ~~$8.9 million, effective for the period from June 1, 2013 to May 31, 2014.~~

IPUC Review of Annual Rate Adjustment Mechanisms

OnPCA Mechanism -- In July 1, 2014, the IPUC opened a docket pursuant to which Idaho Power, the IPUC Staff, and other interested parties ~~will~~ further ~~evaluate~~evaluated Idaho Power's application of the true-up component of the PCA mechanism and whether a deferral balance adjustment iswas appropriate. ~~The docket arose from~~While the IPUC's ~~May~~docket was closed in August 2014 with no adjustment to the PCA ~~order, which noted that~~true-up revenue amount, Idaho Power subsequently met with the IPUC Staff ~~believes that Idaho Power's application~~to explore approaches to increasing the accuracy of the ~~true-up component introduces~~actual cost recovery under the PCA mechanism. On May 28, 2015, the IPUC approved a ~~line-loss bias~~settlement stipulation that ~~inflated~~resulted in the ~~true-up revenue it must collect by $14.2 million.~~replacement of the existing load-based adjustment used for determining the power cost deferrals under the PCA mechanism with a similar sales-based adjustment. The sales-based adjustment functions in the same manner as the existing load-based adjustment, but measures deviations between Idaho-specific test year sales and actual Idaho sales rather than deviations between test year loads and actual loads. The approved settlement stipulation provided that implementation of the new methodology was effective as of January 1, 2015. During the second quarter of 2015, Idaho Power recorded a $1.5 million reduction to the PCA regulatory asset balance to reflect the impact of applying the new PCA mechanism methodology to the first quarter of 2015.

FCA Mechanism -- Also onin July 1, 2014, the IPUC opened a docket to allow Idaho Power, the IPUC Staff, and other interested parties to further evaluate the IPUC Staff's concerns regarding the ~~future~~ application of the FCA mechanism (including weather-normalization, customer count methodology, rate adjustment cap, and cross-subsidization issues) and whether the FCA is effectively removing Idaho Power's disincentive to aggressively pursue energy efficiency programs. AsOn May 6, 2015, the IPUC approved a settlement stipulation that modified the FCA mechanism by replacing weather-normalized billed sales with actual billed sales in the calculation of the ~~date~~FCA, applicable for the entirety of ~~this report, both dockets remain open.~~calendar year 2015 and thereafter, and reflected in FCA rates effective June 1, 2016. During the second quarter of 2015, Idaho Power recorded a $7.4 million increase to the FCA regulatory asset and FCA revenue to reflect the impact of applying the new FCA mechanism methodology to the first quarter of 2015.

4. LONG-TERM DEBT

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

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

5. NOTES PAYABLE

Credit Facilities

IDACORP and Idaho Power have in place credit facilities that may be used for general corporate purposes and commercial paper backup. The terms and conditions of those credit facilities ~~have not changed compared to the descriptions included~~are as described in IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, ~~2013.~~2014.

At June 30, ~~2014~~2015, no loans were outstanding under either IDACORP's or Idaho Power's facilities. At June 30, ~~2014~~2015, Idaho Power had regulatory authority to incur up to $450 million in principal amount of short-term indebtedness at any one time outstanding. Balances (in thousands of dollars) and interest rates of IDACORP’s and Idaho Power's short-term borrowings were as follows at June 30, ~~2014~~2015 and December 31, ~~2013~~2014:


	June 30, 2014									December 31, 2013									June 30, 2015									December 31, 2014
	Idaho Power			IDACORP			Total			Idaho Power			IDACORP			Total			Idaho Power			IDACORP			Total			Idaho Power			IDACORP			Total
Commercial paper outstanding	$	—		$	37,200		$	37,200		$	—		$	54,750		$	54,750		$	—		$	27,000		$	27,000		$	—		$	31,300		$	31,300
Weighted-average annual interest rate	—		%	0.31		%	0.31		%	—		%	0.34		%	0.34		%	—		%	0.54		%	0.54		%	—		%	0.43		%	0.43		%

5.6. COMMON STOCK

IDACORP Common Stock

During the six months ended June 30, ~~2014~~2015, IDACORP issued ~~74,049~~43,349 shares of common stock pursuant to the IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan. Effective July 1, 2012, IDACORP instructed the plan administrators of the IDACORP, Inc. Dividend Reinvestment and Stock Purchase Plan and Idaho Power Company Employee Savings Plan to use market purchases of IDACORP common stock, as opposed to original issuance of common stock from IDACORP, to acquire shares of IDACORP common stock for the plans. However, IDACORP may determine at any time to resume original issuances of common stock under those plans.

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

Restrictions on Dividends

Idaho Power’s ability to pay dividends on its common stock held by IDACORP and IDACORP’s ability to pay dividends on its common stock are limited to the extent payment of such dividends would violate the covenants in their respective credit facilities or Idaho Power’s Revised Code of Conduct. A covenant under IDACORP’s credit facility and Idaho Power’s credit facility requires IDACORP and Idaho Power to maintain leverage ratios of consolidated indebtedness to consolidated total capitalization, as defined therein, of no more than 65 percent at the end of each fiscal quarter. At June 30, ~~2014~~2015, the leverage ratios for IDACORP and Idaho Power were 47 percent and 4849 percent, respectively. Based on these restrictions, IDACORP’s and Idaho Power’s dividends were limited to $~~989 million~~1.0 billion and $~~880~~915 million, respectively, at June 30, ~~2014~~2015. There are additional facility covenants, subject to exceptions, that prohibit or restrict the sale or disposition of property without consent and any agreements restricting dividend payments to the applicable company from any material subsidiary. At June 30, ~~2014~~2015, IDACORP and Idaho Power were in compliance with the financial covenants.

Idaho Power’s Revised Policy and Code of Conduct relating to transactions between and among Idaho Power, IDACORP, and other affiliates, which was approved by the IPUC in April 2008, provides that Idaho Power will not pay any dividends to IDACORP that will reduce Idaho Power’s common equity capital below 35 percent of its total adjusted capital without IPUC

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approval. At June 30, ~~2014~~2015, Idaho Power's common equity capital was 52 percent of its total adjusted capital. Further, Idaho Power must obtain approval of the OPUC before it could directly or indirectly loan funds or issue notes or give credit on its books to IDACORP.

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

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

6.7. EARNINGS PER SHARE

The table below presents the computation of IDACORP’s basic and diluted earnings per share for the three and six months ended June 30, ~~2014~~2015 and ~~2013~~2014 (in thousands, except for per share amounts).


	Three months ended June 30,				Six months ended June 30,				Three months ended June 30,				Six months ended June 30,
	2014		2013		2014		2013		2015		2014		2015		2014
Numerator:
Net income attributable to IDACORP, Inc.	$	44,540	$	46,502	$	71,944	$	81,696	$	66,080	$	44,540	$	89,510	$	71,944
Denominator:
Weighted-average common shares outstanding - basic	50,133		50,056		50,133		50,047		50,222		50,133		50,221		50,133
Effect of dilutive securities:
Options	1		2		1		3
Restricted stock	22		50		32		36
Effect of dilutive securities									36		23		38		33
Weighted-average common shares outstanding - diluted	50,156		50,108		50,166		50,086		50,258		50,156		50,259		50,166
Basic earnings per share	$	0.89	$	0.93	$	1.44	$	1.63	$	1.32	$	0.89	$	1.78	$	1.44
Diluted earnings per share	$	0.89	$	0.93	$	1.43	$	1.63	$	1.31	$	0.89	$	1.78	$	1.43

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 six months ended June 30, ~~2014~~2015, ~~other than the addition of ten~~except as follows:

Idaho Power entered into a 25-year service agreement, subject to approval by the IPUC, for ~~projects~~maintenance services at three of Idaho Power's natural gas plants, with a ~~combined nameplate capacity~~total estimated obligation of ~~approximately 64 MW. Payments pursuant to these agreements are expected to total $252~~$72 million ~~from 2014 to 2038. Four~~over the term of ~~these power purchase agreements remain subject to IPUC approval, with a combined nameplate capacity of approximately 10 MW and expected payments of $50 million.~~the agreement.

Guarantees

Through a self-bonding mechanism, Idaho Power ~~has agreed to guarantee a~~guarantees its portion ~~of the performance~~ of reclamation activities and obligations at BCC, of which IERCo owns a one-third interest. This guarantee, which is renewed annually with the Wyoming Department of Environmental Quality, was $70 million at June 30, ~~2014~~2015, representing IERCo's one-third share of BCC's total reclamation obligation. BCC has a reclamation trust fund set aside specifically for the purpose of paying these reclamation costs. At June 30, ~~2014~~2015, the value of the reclamation trust fund was ~~$70 million~~.$72 million. During the six months endedJune 30, ~~2014~~,2015, the reclamation trust fund distributed approximately $5$1 million for reclamation activity costs associated with the BCC surface mine. BCC periodically assesses the adequacy of the reclamation trust fund and its estimate of future reclamation costs. To ensure that the reclamation trust fund maintains adequate reserves, BCC has the ability to add a per-ton surcharge to coal sales, all of which are made to the Jim Bridger plant. Starting in 2010, BCC began applying a nominal surcharge to coal sales in order to maintain adequate reserves in the reclamation trust fund. Because of the existence of the fund and the ability to apply a per-ton surcharge, the estimated fair value of this guarantee is minimal.

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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 June 30, ~~2014~~2015, management believes the likelihood is remote that IDACORP or Idaho Power would be required to perform under such indemnification provisions or otherwise incur any significant losses with respect to such indemnification obligations. Neither IDACORP nor Idaho Power has recorded any liability on their respective condensed consolidated balance sheets with respect to these indemnification obligations.

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, including the items described in this Note 8.9. Some of these claims, controversies, disputes, and other contingent matters involve litigation and regulatory or other contested proceedings. The ultimate resolution and outcome of litigation and regulatory proceedings is inherently difficult to determine, particularly where (a) the remedies or penalties sought are indeterminate, (b) the proceedings are in the early stages or the substantive issues have not been well developed, or (c) the matters involve complex or novel legal theories or a large number of parties. In accordance with applicable accounting guidance, IDACORP and Idaho Power, as applicable, establish an accrual for legal proceedings when those matters proceed to a stage where they present loss contingencies that are both probable and reasonably estimable. In such cases, there may be a possible exposure to loss in excess of any amounts accrued. IDACORP and Idaho Power monitor those matters for developments that could affect the likelihood of a loss and the accrued amount, if any, and adjust the amount as appropriate. If the loss contingency at issue is not both probable and reasonably estimable, IDACORP and Idaho Power do not establish an accrual and the matter will continue to be monitored for any developments that would make the loss contingency both probable and reasonably estimable. As of the date of this report, IDACORP's and Idaho Power's accruals for loss contingencies are not material to their financial statements as a whole; however, future accruals could be material in a given period. IDACORP's and Idaho Power's determination is based on currently available information, and estimates presented in financial statements and other financial disclosures involve significant judgment and may be subject to significant uncertainty. For matters that affect Idaho Power’s operations, Idaho Power intends to seek, to the extent permissible and appropriate, recovery through the ratemaking process of costs incurred.

Western Energy Proceedings

High prices for electricity, energy shortages, and blackouts in California and in western wholesale markets during 2000 and 2001 caused numerous purchasers of electricity in those markets to initiate proceedings seeking refunds or other forms of relief and the FERC to initiate its own investigations. Some of these proceedings remain pending before the FERC or are on appeal to the United States Court of Appeals for the Ninth Circuit. Idaho Power and IESCo (as successor to IDACORP Energy L.P.) believe that settlement releases they have obtained will restrict potential claims that might result from the disposition of pending proceedings and predict that these matters will not have a material adverse effect on IDACORP's or Idaho Power's results of operations or financial condition. However, the settlements and associated FERC orders have not fully eliminated the potential for so-called "ripple claims," which involve potential claims for refunds in the Pacific Northwest markets from an upstream seller of power based on a finding that its downstream buyer was liable for refunds as a seller of power during the relevant period. The FERC has characterized these ripple claims as "speculative." ~~The~~However, the FERC has refused to dismiss Idaho Power and IESCo from the proceedings in the Pacific ~~Northwest. In orders respecting two separately filed settlements, the FERC has~~Northwest and refused to approve ~~a provision~~portions of two settlements that provided for waivers of ~~all~~ claims in those proceedings, despite only limited objections from two market participants to one of ~~whom removed its~~the two settlements and no objections into the ~~later-filed~~other settlement. Idaho Power and IESCo ~~petitioned the D.C. Circuit~~have filed petitions for review ~~of the first~~ of the FERC's decisions refusing to approve the waiver provision of the settlements, on the basis that the FERC failed to apply its established precedents and rules. The ~~petition~~petitions for review ~~was transferred to~~are pending in the Ninth Circuit Court of ~~Appeals in June 2013~~Appeals.

Idaho Power and ~~remains pending before that court. In June 2014,~~IESCo cannot predict whether the FERC ~~rejected~~will ultimately order that any refunds be made, which contracts would be subject to refunds, how the refund amount would be calculated, which refunds would trigger ripple claims, if any, and whether any party would seek to pursue ripple claims. Based on these uncertainties and Idaho Power's ~~request for rehearing of the partial disapproval of the second settlement.~~

~~Based on its~~and IESCo's evaluation of the merits of ripple claims, ~~and the inability to estimate the potential exposure should the claims ultimately have any merit,~~ particularly in light of Idaho Power and IESCo being both purchasers and sellers in the energy market during the relevant period, Idaho Power and IESCo are unable to estimate the possible loss or range of loss that could result from the proceedings and have no amount accrued relating to the proceedings. To the extent the availability of any ripple claims materializes, Idaho Power and IESCo ~~intend to~~will continue to vigorously defend their positions in the proceedings.

~~Snake River Basin Adjudication~~

Idaho Power holds water rights, acquired under applicable state law, for its hydroelectric projects. In addition, Idaho Power holds water rights for domestic, irrigation, commercial, and other necessary purposes related to project lands and other holdings within the states of Idaho and Oregon. Idaho Power's water rights for power generation are, to varying degrees, subordinated to future upstream appropriations for irrigation and other authorized consumptive uses. Over time, increased irrigation development and other consumptive uses within the Snake River watershed led to a reduction in flows of the Snake River. In

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the late 1970s and early 1980s these reduced flows resulted in a conflict between the exercise of Idaho Power's water rights at certain hydroelectric projects on the Snake River and upstream consumptive diversions. The Swan Falls Agreement, signed by Idaho Power and the State of Idaho on October 25, 1984, resolved the conflict and provided a level of protection for Idaho Power's hydropower water rights at specified projects on the Snake River through the establishment of minimum stream flows and an administrative process governing future development of water rights that may affect those minimum stream flows. In 1987, Congress enacted legislation directing the FERC to issue an order approving the Swan Falls settlement together with a finding that the agreement was neither inconsistent with the terms and conditions of Idaho Power's project licenses nor the Federal Power Act. The FERC entered an order implementing the legislation in March 1988.

The Swan Falls Agreement provided that the resolution and recognition of Idaho Power's water rights together with the State Water Plan provided a sound comprehensive plan for management of the Snake River watershed. The Swan Falls Agreement also recognized, however, that in order to effectively manage the waters of the Snake River basin, a general adjudication to determine the nature, extent, and priority of the rights of all water uses in the basin was necessary. Consistent with that recognition, in 1987 the State of Idaho initiated the Snake River Basin Adjudication (SRBA), and pursuant to the commencement order issued by the SRBA court that same year, all claimants to water rights within the basin were required to file water rights claims in the SRBA. Idaho Power filed claims to its water rights and has been actively participating in the SRBA since its commencement. Questions concerning the effect of the Swan Falls Agreement on Idaho Power's water rights claims, including the nature and extent of the subordination of Idaho Power's rights to upstream uses, resulted in the filing of litigation in the SRBA in 2007 between Idaho Power and the State of Idaho. This litigation was resolved by the Framework Reaffirming the Swan Falls Settlement (Framework) signed by Idaho Power and the State of Idaho on March 25, 2009. In that Framework, the parties acknowledged that the effective management of Idaho's water resources remains critical to the public interest of the State of Idaho by sustaining economic growth, maintaining reasonable electric rates, protecting and preserving existing water rights, and protecting water quality and environmental values. The Framework further provided that the State of Idaho and Idaho Power would cooperate in exploring approaches to resolve issues of mutual concern relating to the management of Idaho's water resources. Idaho Power continues to work with the State of Idaho and other interested parties on these issues.

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

Separately, Idaho Power continues to work with the State of Idaho and other interested stakeholders on issues relating to the management of the Eastern Snake Plain Aquifer (ESPA), a large underground aquifer in southeastern Idaho that is hydrologically connected to the Snake River. House Concurrent Resolution No. 28, adopted by the Idaho Legislature in 2007, directed the Idaho Water Resource Board to pursue the development of a comprehensive management plan for the ESPA, to include measures that would enhance aquifer levels, springs, and river flows on the eastern Snake River plain to the benefit of both agricultural development and hydropower generation. In May 2007, the Idaho Water Resource Board appointed an advisory committee, charged with the responsibility of developing a management plan for the ESPA. Idaho Power was a member of that committee. In January 2009, the Idaho Water Resource Board, based on the committee's recommendations, adopted a Comprehensive Aquifer Management Plan (CAMP) for the ESPA. The Idaho Legislature approved the CAMP that same year. Idaho Power is a member of the CAMP Implementation Committee and continues to work with the Idaho Water Resource Board, other stakeholders, and the Idaho Legislature in exploring opportunities for implementation of the CAMP management plan.

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~~Other Proceedings~~Hoku Corporation Bankruptcy Claims

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

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

Other Proceedings

IDACORP and Idaho Power are parties to legal claims and legal and regulatory actions and proceedings in the ordinary course of business that are in addition to those discussed above and, as noted above, ~~records~~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, including the U.S. Environmental Protection Agency's proposed rule under Section 111(d) of the Clean Air Act, that may have a significant impact on its future ~~operations, including the U.S. Environmental Protection Agency's recently issued proposed regulations for CO~~₂ ~~emission reductions from existing utility generating plants under Section 111(d) of the Clean Air Act.~~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 but does believe that future capital investment for infrastructure and modifications to its electric generating facilities to comply with these regulations could be significant.

9.10. BENEFIT PLANS

Idaho Power has two defined benefit pension plans - a noncontributory defined benefit pension plan (pension plan) and nonqualified defined benefit plans for certain senior management employees called the Security Plan for Senior Management Employees I and II (SMSP). The benefits under the pension plan are based on years of service and the employee’s final average earnings. Idaho Power also maintains a defined benefit postretirement benefit plan (consisting of health care and death benefits) that covers all employees who were enrolled in the active-employee group plan at the time of retirement as well as their spouses and qualifying dependents. The table below shows the components of net periodic benefit costs for the pension, SMSP, and postretirement benefits plans for the three months ended June 30, ~~2014~~2015 and ~~2013~~2014 (in thousands of dollars).


	Pension Plan						SMSP				Postretirement Benefits						Pension Plan						SMSP				Postretirement Benefits
	2014			2013			2014		2013		2014			2013			2015			2014			2015		2014		2015			2014
Service cost	$	6,062		$	7,866		$	412	$	545	$	230		$	245		$	8,123		$	6,062		$	423	$	412	$	280		$	230
Interest cost	8,837			7,979			964		814		704			573			8,766			8,837			967		964		665			704
Expected return on plan assets	(10,835		)	(9,065		)	—		—		(642		)	(569		)	(10,520		)	(10,835		)	—		—		(668		)	(642		)
Amortization of prior service cost	87			87			55		53		46			(90		)	55			87			46		55		4			46
Amortization of net loss (gain)	947			4,307			654		710		—			(120		)
Amortization of net loss																	3,418			947			1,049		654		—			—
Net periodic benefit cost	5,098			11,174			2,085		2,122		338			39			9,842			5,098			2,485		2,085		281			338
Adjustments due to the effects of regulation⁽¹⁾	(592		)	(6,351		)	—		—		—			—			(5,095		)	(592		)	—		—		—			—
Net periodic benefit cost recognized for financial reporting⁽¹⁾	$	4,506		$	4,823		$	2,085	$	2,122	$	338		$	39		$	4,747		$	4,506		$	2,485	$	2,085	$	281		$	338

⁽¹⁾ Net periodic benefit costs for the pension plan are recognized for financial reporting based upon the authorization of each regulatory jurisdiction in which Idaho Power operates. Under IPUC order, income statement recognition of pension plan costs is deferred until costs are recovered through rates.

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The table below shows the components of net periodic benefit costs for the pension, SMSP, and postretirement benefits plans for the six months ended June 30, ~~2014~~2015 and ~~2013~~2014 (in thousands of dollars).


	Pension Plan						SMSP				Postretirement Benefits						Pension Plan						SMSP				Postretirement Benefits
	2014			2013			2014		2013		2014			2013			2015			2014			2015		2014		2015			2014
Service cost	$	12,646		$	15,678		$	823	$	1,090	$	506		$	658		$	16,582		$	12,646		$	845	$	823	$	618		$	506
Interest cost	17,708			15,915			1,928		1,628		1,420			1,316			17,586			17,708			1,934		1,928		1,339			1,420
Expected return on plan assets	(21,156		)	(17,763		)	—		—		(1,298		)	(1,164		)	(20,739		)	(21,156		)	—		—		(1,341		)	(1,298		)
Amortization of prior service cost	174			174			110		106		92			(115		)	110			174			92		110		8			92
Amortization of net loss	1,955			8,559			1,309		1,420		—			49			6,964			1,955			2,098		1,309		—			—
Net periodic benefit cost	11,327			22,563			4,170		4,244		720			744			20,503			11,327			4,969		4,170		624			720
Adjustments due to the effects of regulation⁽¹⁾	(2,297		)	(12,894		)	—		—		—			—			(10,971		)	(2,297		)	—		—		—			—
Net periodic benefit cost recognized for financial reporting⁽¹⁾	$	9,030		$	9,669		$	4,170	$	4,244	$	720		$	744		$	9,532		$	9,030		$	4,969	$	4,170	$	624		$	720

During the six months ended June 30, ~~2014~~2015, Idaho Power made $~~6.5~~10 million in contributions to its defined benefit pension plan. In July ~~2014,~~2015, Idaho Power made an additional ~~$6.5~~$10 million contribution to the pension plan. The company plans to contribute ~~approximately~~at least $30 million to the pension plan during ~~2014,~~2015, including the contributions made to-date.

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

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

~~10. INVESTMENTS IN EQUITY SECURITIES~~

Investments in securities classified as available-for-sale securities are reported at fair value, using either specific identification or average cost to determine the cost for computing gains or losses. Any unrealized gains or losses on available-for-sale securities are included in other comprehensive income. The table below summarizes investments in equity securities by IDACORP and Idaho Power as of ~~June 30, 2014~~ ~~and~~ ~~December 31, 2013~~ ~~(in thousands of dollars).~~

June 30, 2014 December 31, 2013

Gross
Unrealized
Gain

Gross
Unrealized
Loss

Fair
Value

Gross
Unrealized
Gain

Gross
Unrealized
Loss

Fair
Value
Available-for-sale securities $ —
$ —
$ 43,240
$ —
$ —
$ 41,119

At the end of each reporting period, IDACORP and Idaho Power analyze securities in loss positions to determine whether they have experienced a decline in market value that is considered other-than-temporary. At ~~June 30, 2014~~ ~~and at~~ ~~December 31, 2013, there were no indicators of other-than-temporary impairment related to IDACORP's and Idaho Power's investments.~~

~~There were~~ no ~~sales of available-for-sale securities during the~~ ~~six months endedJune 30, 2014~~ or ~~2013~~.

11. DERIVATIVE FINANCIAL INSTRUMENTS

Commodity Price Risk

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

All of Idaho Power's derivative instruments have been entered into for the purpose of economically hedging forecasted purchases and sales, though none of these instruments have been designated as cash flow hedges. Idaho Power offsets fair value amounts recognized on its balance sheet and applies collateral related to derivative instruments executed with the same counterparty under the same master netting agreement. Idaho Power does not offset a counterparty's current derivative contracts with the counterparty's long-term derivative contracts, although Idaho Power's master netting arrangements would allow current and long-term positions to be offset in the event of default. Also, in the event of default, Idaho Power's master netting arrangements would allow for the offsetting of all transactions executed under the master netting arrangement. These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, receivables and payables arising from settled positions, and other forms of non-cash collateral (such as letters of credit). These types of transactions are excluded from the offsetting presented in the derivative fair value and offsetting table ~~below.~~that follows.

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~~Derivative Instrument Summary~~

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

Asset Derivatives Liability Derivatives
Balance Sheet Location Gross Fair Value Amounts Offset Net Assets Gross Fair Value Amounts Offset Net Liabilities

June 30, 2014
Current:

Financial swaps Other current assets $ 2,161
$ (232 ) $ 1,929
$ 232
$ (232 ) $ —
Financial swaps Other current liabilities 340
(340 ) —
1,788
(1,509 )
⁽¹⁾
279
Forward contracts Other current assets 289
—
289
—
—
—
Forward contracts Other current liabilities —
—
—
226
—
226
Long-term:

Financial swaps Other assets 138
—
138
—
—
—
Financial swaps Other liabilities —
—
—
4
—
4
Forward contracts Other assets 118
—
118
—
—
—
Total $ 3,046
$ (572 ) $ 2,474
$ 2,250
$ (1,741 ) $ 509
December 31, 2013
Current:

Financial swaps Other current assets $ 1,451
$ (175 ) $ 1,276
$ 175
$ (175 ) $ —
Financial swaps Other current liabilities 373
(373 ) —
1,975
(1,429 )
⁽¹⁾
546
Forward contracts Other current assets 109
—
109
—
—
—
Forward contracts Other current liabilities —
—
—
26
—
26
Long-term:

Financial swaps Other assets 189
(28 ) 161
28
(28 ) —
Forward contracts Other assets 126
—
126
—
—
—
Total $ 2,248
$ (576 ) $ 1,672
$ 2,204
$ (1,632 ) $ 572

⁽¹⁾~~Current liability derivative amounts offset include $1.2 million and~~ ~~$1.1 million~~ ~~of collateral receivable for the periods ending June 30, 2014 and~~ ~~December 31, 2013, respectively.~~

The table below presents the gains and losses on derivatives not designated as hedging instruments for the three and six months ended June 30, ~~2014~~2015 and ~~2013~~2014 (in thousands of dollars).


			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 June 30,								Six months ended June 30,							Location of Realized Gain/(Loss) on Derivatives Recognized in Income		Three months ended June 30,								Six months ended June 30,
			Three months ended June 30,																	Three months ended June 30,								Six months ended June 30,
		2014				2013				2014				2013					2015				2014				2015				2014
Financial swaps		Off-system sales		$	251			$	(1,149	)	Six months ended June 30,			$	(6,543	)	$	323			Off-system sales		$	(841	)		$	251			$	2,155			$	(6,543	)
Financial swaps		Purchased power		464				28				1,480				14			Purchased power		741				464				106				1,480
Financial swaps	Fuel expense		51				33				3,668				1,149			Fuel expense		368				51				(378		)		3,668
Financial swaps	Other operations and maintenance		(25		)		5				(10		)		16			Other operations and maintenance		(4		)		(25		)		(6		)		(10		)
Forward contracts	Off-system sales		9								52							Off-system sales		—				9				—				52
Forward contracts	Purchased power		(9		)						(50		)					Purchased power		—				(9		)		3				(50		)
Forward contracts	Fuel expense		8				11				48				79			Fuel expense		10				8				5				48

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

Settlement gains and losses on electricity swap contracts are recorded on the income statement in off-system sales or purchased power depending on the forecasted position being economically hedged by the derivative contract. Settlement gains and losses

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on contracts for natural gas are reflected in fuel expense. Settlement gains and losses on diesel derivatives are recorded in other operations and maintenance expense. See Note 12 for additional information concerning the determination of fair value for Idaho Power’s assets and liabilities from price risk management activities.

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 June 30, 2015 and December 31, 2014 (in thousands of dollars).



		Asset Derivatives								Liability Derivatives
	Balance Sheet Location	Gross Fair Value		Amounts Offset				Net Assets		Gross Fair Value		Amounts Offset			Net Liabilities
	Balance Sheet Location	Gross Fair Value		Amounts Offset				Net Assets		Gross Fair Value		Amounts Offset			Net Liabilities
June 30, 2015
Current:
Financial swaps	Other current assets	$	4,579	$	(2,540	)	⁽¹⁾	$	2,039	$	1,249	$	(1,249	)	$	—
Financial swaps	Other current liabilities	178		(178		)		—		4,101		(178		)	3,923
Forward contracts	Other current assets	65		—				65		—		—			—
Forward contracts	Other current liabilities	—		—				—		2		—			2
Long-term:
Financial swaps	Other assets	185		—				185		—		—			—
Financial swaps	Other liabilities	42		(42		)		—		638		(42		)	596
Forward contracts	Other assets	54		—				54		—		—			—
Total		$	5,103	$	(2,760	)		$	2,343	$	5,990	$	(1,469	)	$	4,521
December 31, 2014
Current:
Financial swaps	Other current assets	$	2,509	$	(2,002	)	⁽¹⁾	$	507	$	756	$	(756	)	$	—
Financial swaps	Other current liabilities	379		(379		)		—		4,335		(379		)	3,956
Forward contracts	Other current assets	64		—				64		—		—			—
Forward contracts	Other current liabilities	—		—				—		5		—			5
Long-term:
Forward contracts	Other assets	63		—				63		—		—			—
Total		$	3,015	$	(2,381	)		$	634	$	5,096	$	(1,135	)	$	3,961

⁽¹⁾Current asset derivative amounts offset include $1.3 million and $1.2 million of collateral payable for the periods ending June 30, 2015 and December 31, 2014, respectively.

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The table below presents the volumes of derivative commodity forward contracts and swaps outstanding at June 30, ~~2014~~2015 and ~~2013~~2014 (in thousands of units).


		June 30,			June 30,
Commodity	Units	2014	2013	Units	2015	2014
Electricity purchases	MWh	357	112	MWh	403	357
Electricity sales	MWh	470	891	MWh	115	470
Natural gas purchases	MMBtu	10,516	14,952	MMBtu	18,787	10,516
Natural gas sales	MMBtu	636	885	MMBtu	1,022	636
Diesel purchases	Gallons	452	418	Gallons	122	452

Credit Risk

At June 30, ~~2014~~2015, Idaho Power did not have material credit risk exposure from financial instruments, including derivatives. Idaho Power monitors credit risk exposure through reviews of counterparty credit quality, corporate-wide counterparty credit exposure, and corporate-wide counterparty concentration levels. Idaho Power manages these risks by establishing credit and concentration limits on transactions with counterparties and requiring contractual guarantees, cash deposits, or letters of credit from counterparties or their affiliates, as deemed necessary. Idaho Power’s physical power contracts are commonly under Western Systems Power Pool agreements, physical gas contracts are usually under North American Energy Standards Board contracts, and financial transactions are usually under International Swaps and Derivatives Association, Inc. contracts. These contracts contain adequate assurance clauses requiring collateralization if a counterparty has debt that is downgraded below investment grade by at least one rating agency.

Credit-Contingent Features

Certain of Idaho Power's derivative instruments contain provisions that require Idaho Power's unsecured debt to maintain an investment grade credit rating from Moody's Investors Service and Standard & Poor's Ratings Services. If Idaho Power's unsecured debt were to fall below investment grade, it would be in violation of these provisions, and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions. The aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a liability position at June 30, ~~2014~~2015, was $~~2.0~~6.0 million. Idaho Power posted ~~$1.7~~$0.8 million cash collateral related to this amount. If the credit-risk-related contingent features underlying these agreements were triggered on ~~June��~~June 30, ~~2014~~2015, Idaho Power would have been required to post an additional $~~5.8~~10.2 million of cash collateral to its counterparties.

12. FAIR VALUE MEASUREMENTS

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

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

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

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

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

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

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

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

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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 ~~three and~~ six months endedJune 30, ~~2014~~2015 ~~or the year ended~~ ~~December 31, 2013~~.

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 June 30, ~~2014~~2015 and December 31, ~~2013~~2014 (in thousands of dollars).


	June 30, 2014								December 31, 2013								June 30, 2015								December 31, 2014
	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:
Derivatives	$	2,067	$	407	$	—	$	2,474	$	1,437	$	235	$	—	$	1,672	$	2,213	$	130	$	—	$	2,343	$	506	$	128	$	—	$	634
Money market funds	100		—		—		100		100		—		—		100		10,097		—		—		10,097		100		—		—		100
Trading securities: Equity securities	144		—		—		144		1,153		—		—		1,153		109		—		—		109		141		—		—		141
Available-for-sale securities: Equity securities	43,240		—		—		43,240		41,119		—		—		41,119		43,038		—		—		43,038		44,942		—		—		44,942
Liabilities:
Derivatives	$	283	$	226	$	—	$	509	$	546	$	26	$	—	$	572	1		4,520		—		4,521		17		3,944		—		3,961

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

The table below presents the carrying value and estimated fair value of financial instruments that are not reported at fair value, as of June 30, ~~2014~~2015 and December 31, ~~2013~~2014, using available market information and appropriate valuation ~~methodologies.~~methodologies (in thousands of dollars).


	June 30, 2014				December 31, 2013
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value		June 30, 2015				December 31, 2014
	(thousands of dollars)								Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
IDACORP
Assets:
Notes receivable⁽¹⁾	$	3,472	$	3,472	$	3,472	$	3,472	$	3,804	$	3,804	$	3,804	$	3,804
Liabilities:
Long-term debt⁽¹⁾	1,615,380		1,738,062		1,616,322		1,600,248		1,742,863		1,837,408		1,615,502		1,788,197
Idaho Power
Liabilities:
Long-term debt⁽¹⁾	$	1,615,380	$	1,738,062	$	1,616,322	$	1,600,248	1,742,863		1,837,408		1,615,502		1,788,197

⁽¹⁾ Notes receivable and long-term debt are categorized as Level 3 and Level 2, respectively, of the fair value hierarchy, as defined earlier in this Note 12.

Notes receivable are related to Ida-West and are valued based on unobservable inputs, including discounted cash flows, which are partially based on forecasted hydroelectric conditions. Long-term debt is not traded on an exchange and is valued using quoted rates for similar debt in active markets. ~~Cash~~Carrying values for cash and cash equivalents, deposits, customer and other receivables, notes

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payable, accounts payable, interest accrued, and taxes accrued ~~are reported at their carrying value as these are a reasonable estimate of their~~approximate fair value. The estimated fair values for long-term debt are based upon quoted market prices of similar issues or the same issues in an inactive market. The estimated fair values for notes receivable are based upon discounted cash flow analysis.

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13. SEGMENT INFORMATION

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

IDACORP’s other operating segments are below the quantitative and qualitative thresholds for reportable segments and are included in the “All Other” category in the table below. This category is comprised of IFS’s investments in affordable housing and historic rehabilitation projects, Ida-West’s joint venture investments in small hydroelectric generation projects, the remaining activities of IESCo, and IDACORP’s holding company expenses.

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


	Utility Operations		All Other		Eliminations			Consolidated Total		Utility Operations		All Other		Eliminations			Consolidated Total
Three months ended June 30, 2015:
Revenues										$	335,321	$	1,007	$	—		$	336,328
Net income attributable to IDACORP, Inc.										64,340		1,740		—			66,080
Total assets as of June 30, 2015										5,797,908		115,429		(15,961		)	5,897,376
Three months ended June 30, 2014:
Revenues	$	316,655	$	1,128	$	—		$	317,783	$	316,655	$	1,128	$	—		$	317,783
Net income attributable to IDACORP, Inc.	42,653		1,887		—			44,540		42,653		1,887		—			44,540
Total assets as of June 30, 2014	5,299,199		103,444		(12,774		)	5,389,869
Three months ended June 30, 2013:
Six months ended June 30, 2015:
Revenues	$	302,856	$	1,092	$	—		$	303,948	$	614,094	$	1,629	$	—		$	615,723
Net income attributable to IDACORP, Inc.	44,983		1,519		—			46,502		87,802		1,708		—			89,510
Six months ended June 30, 2014:
Revenues	$	608,975	$	1,527	$	—		$	610,502	$	608,975	$	1,527	$	—		$	610,502
Net income attributable to IDACORP, Inc.	70,554		1,390		—			71,944		70,554		1,390		—			71,944
Six months ended June 30, 2013:
Revenues	$	567,225	$	1,652	$	—		$	568,877
Net income attributable to IDACORP, Inc.	79,029		2,667		—			81,696

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14. CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME

~~Comprehensive income includes net income, unrealized holding gains and losses on available-for-sale marketable securities, and amounts related to the SMSP.~~ The table below presents changes in components of accumulated other comprehensive income (AOCI), net of tax, during the three and six months ended June 30, ~~2014~~2015 and ~~2013~~2014 (in thousands of dollars). Items in parentheses indicate ~~reductions~~charges to AOCI.


	Unrealized Gains and Losses on Available-for-Sale Securities		Defined Benefit Pension Items			Total			Defined Benefit Pension Items
Three months ended June 30, 2015:
Balance at beginning of period									$	(23,491	)
Amounts reclassified out of AOCI									667
Balance at end of period									$	(22,824	)
Six months ended June 30, 2015:
Balance at beginning of period									$	(24,158	)
Amounts reclassified out of AOCI									1,334
Balance at end of period									$	(22,824	)
Three months ended June 30, 2014:
Balance at beginning of period	$	—	$	(16,121	)	$	(16,121	)	$	(16,121	)
Other comprehensive income before reclassifications	—		—			—
Amounts reclassified out of AOCI	—		432			432			432
Net current-period other comprehensive income	—		432			432
Balance at end of period	$	—	$	(15,689	)	$	(15,689	)	$	(15,689	)
Six months ended June 30, 2014:
Balance at beginning of period	$	—	$	(16,553	)	$	(16,553	)	$	(16,553	)
Other comprehensive income before reclassifications	—		—			—
Amounts reclassified out of AOCI	—		864			864			864
Net current-period other comprehensive income	—		864			864
Balance at end of period	$	—	$	(15,689	)	$	(15,689	)	$	(15,689	)
Three months ended June 30, 2013:
Balance at beginning of period	$	5,317	$	(20,787	)	$	(15,470	)
Other comprehensive income before reclassifications	259		—			259
Amounts reclassified out of AOCI	—		465			465
Net current-period other comprehensive income	259		465			724
Balance at end of period	$	5,576	$	(20,322	)	$	(14,746	)
Six months ended June 30, 2013:
Balance at beginning of period	$	4,136	$	(21,252	)	$	(17,116	)
Other comprehensive income before reclassifications	1,440		—			1,440
Amounts reclassified out of AOCI	—		930			930
Net current-period other comprehensive income	1,440		930			2,370
Balance at end of period	$	5,576	$	(20,322	)	$	(14,746	)

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The table below presents amounts reclassified out of components of AOCI and the income statement location of those amounts reclassified during the three and six months ended June 30, ~~2014~~2015 and ~~2013~~2014 (in thousands of dollars). Items in parentheses indicate increases to net income.


	Amount Reclassified from AOCI												Amount Reclassified from AOCI
Details About AOCI	Three months ended June 30,						Six months ended June 30,						Three months ended June 30,						Six months ended June 30,
	2014			2013			2014			2013			2015			2014			2015			2014
Amortization of defined benefit pension items⁽¹⁾
Prior service cost	$	55		$	53		$	110		$	106		$	46		$	55		$	92		$	110
Net loss	654			710			1,309			1,420			1,049			654			2,098			1,309
Total before tax	709			763			1,419			1,526			1,095			709			2,190			1,419
Tax benefit⁽²⁾	(277		)	(298		)	(555		)	(596		)	(428		)	(277		)	(856		)	(555		)
Net of tax	432			465			864			930			667			432			1,334			864
Total reclassification for the period	$	432		$	465		$	864		$	930		$	667		$	432		$	1,334		$	864

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

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

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

IDACORP, Inc.

Boise, Idaho

We have reviewed the accompanying condensed consolidated balance sheet of IDACORP, Inc. and subsidiaries (the “Company”) as of June 30, ~~2014~~2015, and the related condensed consolidated statements of income and comprehensive income for the three-month and six-month periods ended June 30, ~~2014~~2015 and ~~2013~~2014, and of equity and cash flows for the six-month periods ended June 30, ~~2014~~2015 and ~~2013~~.2014. These interim financial statements are the responsibility of the Company’s management.

We conducted our reviews in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our reviews, we are not aware of any material modifications that should be made to such condensed consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of IDACORP, Inc. and subsidiaries as of December 31, ~~2013~~2014, and the related consolidated statements of income, comprehensive income, equity, and cash flows for the year then ended (not presented herein); and in our report dated February ~~20, 2014,~~19, 2015, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, ~~2013~~2014 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

/s/ DELOITTE & TOUCHE LLP

Boise, Idaho

July ~~31, 2014~~30, 2015

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Idaho Power Company

Boise, Idaho

We have reviewed the accompanying condensed consolidated balance sheet of Idaho Power Company and subsidiary (the “Company”) as of June 30, ~~2014~~2015, and the related condensed consolidated statements of income and comprehensive income for the three-month and six-month periods ended June 30, ~~2014~~2015 and ~~2013~~2014, and of cash flows for the six-month periods ended June 30, ~~2014~~2015 and ~~2013~~.2014. These interim financial statements are the responsibility of the Company’s management.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Idaho Power Company and subsidiary as of December 31, ~~2013~~2014, and the related consolidated statements of income, comprehensive income, retained earnings, and cash flows for the year then ended (not presented herein); and in our report dated February ~~20, 2014,~~19, 2015, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, ~~2013~~2014 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

/s/ DELOITTE & TOUCHE LLP

Boise, Idaho

July ~~31, 2014~~30, 2015

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

AND RESULTS OF OPERATIONS

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

INTRODUCTION

In Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A), the general financial condition and results of operations for IDACORP, Inc. and its subsidiaries (collectively, ~~for purposes of this Item 2,~~ IDACORP) and Idaho Power Company and its subsidiary (collectively, ~~for purposes of this Item 2,~~ Idaho Power) are discussed. While reading the MD&A, please refer to the accompanying condensed consolidated financial statements of IDACORP and Idaho Power, and the notes thereto. This discussion updates the MD&A included in the Annual Report on Form 10-K for the year ended December 31, ~~2013~~2014, and should also be read in conjunction with the information in that report. The results of operations for an interim period generally will not be indicative of results for the full year, particularly in light of the seasonality of Idaho Power's sales volumes, as discussed below.

IDACORP is a holding company formed in 1998 whose principal operating subsidiary is Idaho Power. IDACORP’s common stock is listed and trades on the New York Stock Exchange under the trading symbol “IDA.” Idaho Power is an electric utility with a service ~~territory~~area covering approximately 24,000 square miles in southern Idaho and eastern Oregon.

Idaho Power provided electric service to approximately ~~512,000~~520,000 general business customers as of June 30, ~~2014~~2015. As a regulated utility, many of Idaho Power's fundamental business decisions are subject to the approval of governmental agencies. Idaho Power is under the jurisdiction (as to rates, service, accounting, and other general matters of utility operation) of the Idaho Public Utilities Commission (IPUC), the Public Utility Commission of Oregon (OPUC), and the Federal Energy Regulatory Commission (FERC). The IPUC and OPUC determine the rates that Idaho Power charges to its general business customers. Idaho Power is also under the regulatory jurisdiction of the IPUC, the OPUC, and the Public Service Commission of Wyoming as to the issuance of debt and equity securities. As a public utility under the Federal Power Act, Idaho Power has authority to charge market-based rates for wholesale energy sales under its FERC tariff and to provide transmission services under its open access transmission tariff (OATT). Idaho Power uses general rate cases, cost adjustment mechanisms, tariff riders, and subject-specific filings to recover its costs of providing service and the costs of its energy efficiency and demand-response programs, and to seek to earn a return on investment.

Idaho Power generates revenues and cash flows primarily from the sale and distribution of electricity to customers in its Idaho and Oregon service ~~territories,~~areas, as well as from the wholesale sale and transmission of electricity. Idaho Power’s revenues and income from operations are subject to fluctuations during the year due to the impacts of seasonal weather conditions on demand for electricity, availability of water for hydroelectric generation, price changes, customer usage patterns (which are affected in large part by the condition of the economy across the service area), and the availability and price of purchased power and fuel. Idaho Power experiences its highest retail energy sales during the summer irrigation and cooling season, with a lower peak in the winter that generally results from heating demand. IDACORP’s and Idaho Power’s financial condition are also affected by regulatory decisions through which Idaho Power seeks to recover its costs on a timely basis and earn an authorized return on investment, and by the ability to obtain financing through the issuance of debt and/or equity securities.

IDACORP’s other subsidiaries include IDACORP Financial Services, Inc. (IFS), an investor in affordable housing and historic rehabilitation projects; Ida-West Energy Company, an operator of small hydroelectric generation projects that satisfy the requirements of the Public Utility Regulatory Policies Act of 1978 (PURPA); and IDACORP Energy Services Co., which is the former limited partner of, and successor by merger to, IDACORP Energy L.P., a marketer of energy commodities that wound down operations in 2003. Idaho Power is the parent of Idaho Energy Resources Co. (IERCo), a joint venturer in Bridger Coal Company (BCC), which mines and supplies coal to the Jim Bridger generating plant owned in part by Idaho Power.

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EXECUTIVE OVERVIEW

Management's Outlook and Company Initiatives

In the Annual Report on Form 10-K for the year ended December 31, ~~2013,~~2014, IDACORP's and Idaho Power's management included a brief overview of their outlook and initiatives for the companies for ~~2014~~2015 and beyond, under the ~~heading~~headings "Executive Overview - Management's Outlook" and "2014 Accomplishments and 2015 Initiatives" in the MD&A. As of the date of this report, management's outlook is consistent with the disclosure in that report. Most notably:

Idaho Power continues to expect positive customer growth in its service area, and continues to support economic development initiatives aimed at sustainable levels of growth. During the first six months of ~~2014,~~2015, Idaho Power's customer count grew by ~~3,090 customers.~~4,536 customers, and for the twelve months ended June 30, 2015, the customer growth rate was 1.7 percent.

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

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

~~Idaho Power continues to focus on optimization efforts~~actively manage costs, targeting opportunities to ~~manage operating and maintenance (O&M) expenses.~~optimize business practices.

IDACORP remains focused on the previously established long-term target dividend payout ratio of between 50 and 60 percent of sustainable IDACORP earnings. IDACORP's board of directors ~~approves the dividend amount quarterly and~~ periodically assesses the potential for changes in the dividend amount.

~~Brief Overview of Second Quarter 2014 Financial Results~~

~~IDACORP's earnings were~~ ~~$0.89~~ ~~per diluted share for the quarter ended~~ ~~June 30, 2014, compared to~~ ~~$0.93~~ per diluted share for the same quarter in 2013. IDACORP's second quarter earnings in 2014 were lower than in the second quarter of 2013 primarily due to the impact of milder weather on sales to residential customers, who use electricity for cooling. In the second quarter of 2014 temperatures were slightly cooler than normal, while in the second quarter of 2013 temperatures were warmer than normal.

~~A December 2011 settlement stipulation with the IPUC allows~~ Idaho Power continues to ~~amortize additional accumulated deferred investment tax credits (ADITC) if Idaho Power's~~focus on timely recovery of costs and earning a reasonable return on ~~year-end equity in the Idaho jurisdiction (Idaho ROE) is less than 9.5 percent. Based on Idaho Power's June 30, 2014 estimate of full-year 2014 Idaho ROE, Idaho Power does not expect~~investment, including working to ~~amortize additional ADITC in 2014,~~ensure that its rate design and reversed in the second quarter the $950 thousand of additional ADITC that it had recorded in the first quarter. IDACORP's and Idaho Power's results, including a quantification of the impacts of the significant items influencing results, are discussed in more detail below.regulatory mechanisms properly reflect economic realities.

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

IDACORP's and Idaho Power's results of operations and financial condition are affected by regulatory, operational, weather-related, economic, and other factors, many of which are described below.

Timely Regulatory Cost Recovery: The price that Idaho Power is authorized to charge for its electric service is a critical factor in determining IDACORP's and Idaho Power's results of operations and financial condition. Because of the significant impact of ratemaking decisions, and in furtherance of its goal of advancing a purposeful regulatory strategy, Idaho Power has focused on timely recovery of its costs through filings with the company's regulators, and on the prudent management of expenses and investments. Certain recent and pending rate proceedings are discussed in IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, ~~2013,~~2014, in "Regulatory Matters" in this MD&A, and in Note 3 - "Regulatory Matters" to the condensed consolidated financial statements included in this report.

In 2014, Idaho Power ~~believes that the~~extended its December 2011 Idaho settlement stipulation, ~~referred~~including the provisions for potential sharing of earnings with customers and for amortization of additional accumulated deferred investment tax credits (ADITC) to ~~above, which has been~~help achieve a minimum 9.5 percent return on year-end equity in ~~effect for 2012, 2013,~~the Idaho jurisdiction (Idaho ROE). While providing no assurance that Idaho Power will obtain a 9.5 percent Idaho ROE in any of the applicable years, IDACORP and ~~2014, affords~~Idaho Power believe the ability to amortize additional ADITC under the settlement stipulation provides an element of earnings ~~stability. Based~~stability for 2015 and potentially through as late as 2019, depending on ~~its 2012 and 2013 Idaho ROEs, Idaho Power did not amortize any~~the usage rate of additional ~~ADITC for those two~~ADITCs during the applicable years. As

In May 2015, the IPUC approved settlement stipulations relating to the operation of the ~~date of this report,~~ Idaho ~~Power does not expect~~power cost adjustment (PCA) and fixed cost adjustment (FCA) mechanisms. The settlement stipulations are intended to ~~amortize additional ADITC in 2014,~~more closely align Idaho Power's cost recovery under the PCA and in the second quarter of 2014 Idaho Power reversed the full amount of additional ADITC recorded in the first quarter of 2014. In addition to the ADITC amortization provisions, the settlement stipulation also provides for the sharing between the company and customers of Idaho-jurisdictional earnings in excess of specified levels of Idaho ROE, and the sharing provisions were triggered in both 2012 and 2013. The terms of the settlement stipulation are described in further detail in "Regulatory Matters" in this MD&A and in Note 3 - "Regulatory Matters" to the condensed consolidated financial statements included in this report. As discussed in Note 3, Idaho Power filed an applicationFCA mechanisms with the ~~IPUC in May~~

~~Table~~intent and purpose of ~~contents~~

~~2014 requesting an extension of the terms of the December 2011 Idaho settlement stipulation, and that application remains pending.~~those mechanisms.

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

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

~~For the second quarter of 2014, the service area's average employment of 457,656, based on~~According to preliminary Idaho Department of Labor ~~seasonally-adjusted preliminary~~ data ~~established an all-time quarterly peak. The pre-recession employment peak in the fourth quarter of 2006 of 449,710 was first eclipsed in the fourth quarter of 2013. For~~for June ~~2014,~~2015, total employment in the service area was ~~459,340~~474,434 compared ~~to 453,494~~with 459,407 in ~~March~~June 2014. The unemployment rate for the service area was ~~4.5~~3.9 percent. ~~The~~By comparison, the June ~~2014~~2015 U.S. unemployment rate ~~stood at 6.1~~was 5.3 percent, according to U.S. Department of Labor data.

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Moody's Analytics forecasts, as of ~~July 3, 2014, 3.0~~June 2015, 4.6 percent and ~~3.8~~5.4 percent growth in gross area product for ~~the~~Idaho Power's service area for ~~2014~~2015 and ~~2015,~~2016, respectively.

Residential customer growth for the 12twelve months ended June 30, ~~2014~~2015, was ~~1.5~~1.7 percent.

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

Weather Conditions and Associated ~~Impacts:~~Impacts on Revenue and Power Supply Costs: Weather and agricultural growing conditions have a significant impact on Idaho Power's energy sales and the seasonality of those sales. Relatively low and high temperatures result in greater energy use for heating and cooling, respectively. During the agricultural growing season, which in large part occurs during the second and third quarters, irrigation customers use electricity to operate irrigation pumps, and weather conditions can impact the timing and degree of use of those pumps. Idaho Power also has tiered rates and seasonal rates, which contribute to increased revenues during higher-load periods, most notably during the third quarter of each year when overall customer demand is highest. InDry weather in the spring of 2015 led to increased sales to irrigation customers as compared with 2014, and the impact of milder first quarter ~~of 2014, slightly above-normal~~2015 temperatures ~~reduced~~on sales to residential customers ~~for~~was largely offset by increased sales volumes due to hotter temperatures during the second half of June 2015.

In May 2015, the IPUC approved a settlement stipulation relating to the operation of ~~electric heating systems, while~~the FCA mechanism, which replaced weather-normalized billed sales in the ~~first quarter~~calculation of ~~2013 extremely cold temperatures increased~~the FCA with actual billed sales. InThe revisions to the ~~second quarter~~FCA will reduce the impact on revenues and net income of ~~2014, relatively mild weather decreased~~weather-driven fluctuations in sales to residential ~~customers for the operation of air conditioning~~ and ~~electric heating systems compared~~small commercial customers. The change to the ~~second quarter of 2013.~~FCA mechanism is discussed further in "Regulatory Matters" in this MD&A.

Idaho Power's hydroelectric facilities comprise nearly one-half of Idaho Power's nameplate generation capacity. However, the availability and volume of hydroelectric power generated depends on several factors --- the snow pack levels in the mountains upstream of Idaho Power's facilities, reservoir storage, springtime snow pack run-off, base flows in the Snake River, spring flows, rainfall, water leases and other water rights, and other weather and stream flow considerations. As of the date of this report, Idaho Power estimates that its ~~2014~~2015 hydroelectric generation will be between ~~5.5~~6.0 million and ~~6.5~~7.0 million megawatt-hours (MWh). This estimated range compares to ~~2013~~2014 hydroelectric generation of ~~5.7~~6.2 million MWh. ~~The~~Idaho Power's resource-adjusted median annual hydroelectric generation is ~~8.4~~8.5 million MWh.

When hydroelectric generation is reduced, Idaho Power must rely on more expensive generation sources and purchased power - but most of the increases in power supply costs are collected from customers through the Idaho and Oregon ~~power cost adjustment (PCA)~~PCA mechanisms. Conversely, in periods of greater hydroelectric generation most of the resulting decrease in power supply costs that typically occurs is returned to customers through the ~~Idaho and Oregon~~ PCA mechanisms.

When favorable hydroelectric generating conditions exist for Idaho Power, they also may exist for other Pacific Northwest hydroelectric facility operators – increasing the available supply of lower-cost power, lowering regional wholesale market prices, and impacting the revenue Idaho Power receives from off-system sales of its excess power. Conversely, when hydroelectric generating conditions are poor, wholesale market prices may be higher due to lower supply, but Idaho Power would generally have less surplus energy available for sale into the wholesale markets at those times. ~~Much~~Most of the adverse or favorable impact of this volatility is addressed through the PCA mechanisms.

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Fuel and Purchased Power Expense: In addition to hydroelectric generation, Idaho Power relies significantly on coal and natural gas to fuel its generation facilities and power purchases in the wholesale markets. Idaho Power also uses physical and financial forward contracts for both electricity and fuel and other hedging strategies in order to manage the risks relating to fuel and power price exposures. Fuel costs are impacted by electricity sales volumes, the terms of contracts for fuel, Idaho Power's generation capacity, the availability of hydroelectric generation resources, transmission capacity, energy and natural gas market prices, and Idaho Power's hedging program for managing fuel costs.

Purchased power costs are impacted by the terms of contracts for purchased power, the rate of expansion of alternative energy generation sources such as wind and solar energy, and wholesale energy market prices. Idaho Power is obligated to purchase power from some PURPA generation projects at a specified price regardless of the then-current load demand or wholesale energy market prices. This increases the likelihood that Idaho Power will at times be required to reduce output from its lower-cost hydroelectric and fossil fuel-fired generation resources and may be required to sell in the wholesale power market the power it purchases from PURPA projects at a significant loss. Integration of less reliable, intermittent, non-dispatchable resources ~~(such as wind energy)~~ into Idaho Power's portfolio also creates a number of complex operational challenges and risks that Idaho Power must address. Notably, integration of these sources of power into Idaho Power's portfolio does not eliminate Idaho Power's need to construct facilities and infrastructure that provide reliable power. For instance, at the time Idaho Power reached its all-time system peak demand of 3,407 MW on July 2, 2013, wind resources on Idaho Power's system, representing roughly 675 MW of

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nameplate capacity, were contributing only 57 MW of power due to lack of wind. Increases in federally mandated PURPA power purchases have contributed to increases in customer rates.

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

Regulatory and Environmental Compliance Costs and Expenditures: Idaho Power is subject to extensive federal and state laws, policies, and regulations, as well as regulatory actions and audits by agencies and quasi-governmental agencies, including the FERC and the North American Electric Reliability Corporation. Compliance with these requirements directly influences Idaho Power's operating environment and may significantly increase Idaho Power's operating costs. Further, potential monetary and non-monetary penalties for a violation of applicable laws or regulations may be substantial. Accordingly, Idaho Power has in place numerous compliance policies and initiatives to help ensure compliance, and periodically evaluates and updates those policies and initiatives.

In particular, environmental laws and regulations may, among other things, increase the cost of operating generation plants and constructing new facilities, require that Idaho Power install additional pollution control devices at existing generating plants, or require that Idaho Power cease operating certain generation plants. For instance, the Boardman coal-fired power plant, in which Idaho Power owns a 10-percent interest, is scheduled to cease coal-fired operations by the end of 2020, the decision for which was driven in large part by the substantial cost of environmental controls. Additionally, the U.S. Environmental Protection ~~Agency~~Agency's (EPA) ~~recently issued~~ proposed ~~rules~~rule under Section 111(d) of the Clean Air Act, ~~(CAA)~~which is intended to reduce carbon dioxide ~~(CO~~₂) emissions from the power sector, ~~which~~ could significantly increase costs in the ~~industry.~~industry and customer rates. Idaho Power expects to spend a considerable amount on environmental compliance and controls in the next decade. As legislation and regulations concerning greenhouse gas emissions develop, Idaho Power will continue to assess, to the extent determinable, the potential impact on the costs to ~~operate its generation facilities,~~generate and purchase power, as well as the willingness of joint owners of power plants to fund any required pollution control equipment upgrades in lieu of plant retirement or conversion to other fuel sources.

~~Other Matters:~~ Refer to this section of MD&A in IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2013, where the companies summarize certain other notable matters that could have an impact on the companies' results of operations or financial condition, including Idaho Power's significant anticipated pension plan contributions, hydroelectric facility relicensing efforts, and the status of large transmission projects, each of which are discussed below in this MD&A.

Summary of ~~Second Quarter and First Half of 2014~~ 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-months and six-months ended June 30, 2014 and 2013. IDACORP's 2013 results reflect the retrospective adoption of Accounting Standards Update No. 2014-01, which increased IDACORP's earnings by $1.0 million for the second quarter of 2013, and by $2.7 million for the first six months of 2013, as compared with what had been reported for those periods under the previous method of accounting. See Note 1 - "Summary of Significant Accounting Policies" to the condensed consolidated financial statements included in this report for a further description of the impact of this adoption.



	Three months ended June 30,				Six months ended June 30,
	2015		2014		2015		2014
Idaho Power net income	$	64,340	$	42,653	$	87,802	$	70,554
Net income attributable to IDACORP, Inc.	$	66,080	$	44,540	$	89,510	$	71,944
Average outstanding shares – diluted (000’s)	50,258		50,156		50,259		50,166
IDACORP, Inc. earnings per diluted share	$	1.31	$	0.89	$	1.78	$	1.43

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Three months ended
June 30, Six months ended
June 30,
2014 2013 2014 2013
Idaho Power net income $ 42,653
$ 44,983
$ 70,554
$ 79,029
Net income attributable to IDACORP, Inc. $ 44,540
$ 46,502
$ 71,944
$ 81,696
Average outstanding shares – diluted (000’s) 50,156
50,108
50,166
50,086
IDACORP, Inc. earnings per diluted share $ 0.89
$ 0.93
$ 1.43
$ 1.63

The table below provides a reconciliation of net income attributable to IDACORP for the three- and six-month periods ended June 30, ~~2014~~2015 to the same periods in ~~2013~~2014 (items are in millions and are before tax unless otherwise noted).

Three months ended Six months ended
Net income attributable to IDACORP, Inc. - June 30, 2013 (as previously reported) $ 45.5
$ 79.0
Effect of an accounting method change for IDACORP Financial Services affordable housing investment amortization 1.0
2.7
Net income attributable to IDACORP, Inc. - June 30, 2013 (as reported under new method) $ 46.5
$ 81.7
Change in Idaho Power net income:

Decreased sales volumes attributable to usage per customer, net of associated power supply costs and PCA mechanism impacts (8.6 )
(21.4 )
Increased sales volumes attributable to customer growth, net of associated power supply costs and PCA mechanism impacts 2.5
4.3

Other changes in operating revenues and expenses, net (4.3 ) (4.1 )
Revenue sharing recorded in 2013 not recorded in 2014 2.8
2.8

Decrease in Idaho Power operating income (7.6 ) (18.4 )
Changes in other non-operating income and expenses 2.4
2.6

Decrease in income tax expense 2.9
7.3

Total decrease in Idaho Power net income (2.3 ) (8.5 )
Other changes (net of tax) 0.3
(1.3 )
Net income attributable to IDACORP, Inc. - June 30, 2014 $ 44.5
$ 71.9



	Three months ended					Six months ended
Net income attributable to IDACORP, Inc. - June 30, 2014			$	44.5				$	71.9
Change in Idaho Power net income:
Increased sales volumes attributable to usage per customer, net of associated power supply costs and PCA mechanism impacts	7.8					0.2
Impact in the second quarter of 2015 of retroactively applying FCA mechanism changes to first quarter activity	7.4					7.4
Other (decreases) increases in FCA revenues	(1.7	)				3.4
Increased sales volumes attributable to customer growth, net of associated power supply costs and PCA mechanism impacts	2.9					4.7
Increase in other operating and maintenance expenses	(0.4	)				(3.4	)
Increase in depreciation expense	(1.4	)				(2.5	)
Other changes in operating revenues and expenses, net	(0.1	)				(1.1	)
Increase in Idaho Power operating income	14.5					8.7
Changes in other non-operating income and expenses	2.3					1.1
Decrease in income tax related to first mortgage bond redemption costs	7.2					7.2
Change in additional amortization of ADITC	1.0					—
(Increase) decrease in other income tax expense	(3.3	)				0.2
Total increase in Idaho Power net income			21.7					17.2
Other changes (net of tax)			(0.1		)			0.4
Net income attributable to IDACORP, Inc. - June 30, 2015			$	66.1				$	89.5

Second Quarter ~~2014~~2015 Net Income

IDACORP's net income ~~decreased $2.0~~increased $21.6 million for the second quarter of ~~2014~~2015 when compared with the same period in the prior year. The increase was driven primarily by a $14.5 million increase in Idaho Power’s operating income ~~decreased~~and by ~~$7.6 million. Lower overall usage per customer due to relatively mild~~lower income tax expense.

A June 2015 heat wave combined with dry spring weather ~~decreased~~resulted in record second quarter sales volumes, which improved Idaho Power's operating income by ~~$8.6~~$7.8 million when compared with the same period of 2014, which was a more normal weather quarter. Hot temperatures increased loads for air conditioning purposes, and dry weather increased the use of irrigation equipment. Idaho Power’s continued customer growth also contributed $2.9 million to operating income.

Recently approved changes to Idaho Power's FCA mechanism also affected second quarter 2015 results. The revisions were approved by the IPUC in May 2015, retroactive to January 1, 2015. The FCA revenue accrual associated with the first quarter of 2015 increased by $7.4 million—reflective of the extremely mild temperatures during the first quarter—as the revised mechanism now addresses fluctuations in sales associated with actual weather conditions, as opposed to normalized weather conditions under the prior mechanism. This impact was recorded in the second quarter of 2015 when the order was received from the IPUC. FCA revenues associated with the second quarter decreased $1.7 million compared with the same period in ~~2013. Relatively mild~~the prior year, which reduced some of the benefit that the hot temperatures ~~throughout~~had on residential and small commercial sales.

Income tax expense was lower in the second quarter of 2015 compared with the second quarter of 2014, ~~resulted~~reflecting the flow-through impact of a $17.9 million tax deductible make-whole premium that Idaho Power paid in ~~lower use across most customer classes during~~connection with the ~~period. Partially offsetting these decreases~~early redemption of long-term debt that was ~~growth~~due in ~~the number~~2018. The tax benefit of customers and associated increased sales volumes, which increased operating income by $2.5 million for the quarter compared to the same period in 2013. Idaho Power's operating income was also impacted by a $4.3 million increase in other operating expenses, mostly related to increased thermal maintenance expenses and normal payroll and benefits increases when compared to the same period in 2013.

~~The $7.6 million decrease in Idaho Power's operating income~~this was partially offset by ~~$2.4 million of other non-operating income, mostly attributable to an increase in AFUDC resulting from~~ increased ~~capital expenditures, and $2.9 million of lower~~ income tax expense ~~mostly related to lower pre-tax~~on higher pretax income when compared towith the ~~same period~~second quarter of 2014. The second quarter of 2014 also included a $950 thousand income tax increase from the reversal of additional ADITC amortization originally recorded in ~~2013.~~the first quarter of 2014. No additional ADITC amortization was recorded in 2015.

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~~Year-to-Date~~Year-to-date Net Income

IDACORP's net income ~~decreased $9.8~~increased $17.6 million for the first ~~six months~~half of ~~2014~~2015 when compared with the same period in the prior year. The increase was driven primarily by an increase of $8.7 million in Idaho ~~Power's~~Power’s operating income, ~~decreased~~and by ~~$18.4~~reduced income tax expense.

Idaho Power’s continued customer growth contributed $4.7 million ~~over~~to operating income. The sales volume benefit of hotter temperatures in June 2015 was offset by unusually mild temperatures in the ~~comparative period. Lower usage per customer due to relatively mild weather decreased operating income by $21.4 million when compared~~first quarter.

The FCA mechanism, including the retroactive revisions made to the ~~same period in 2013. These weather-related decreases were partially offset~~mechanism, increased revenues by ~~growth in the number of customers and associated increased sales volumes, which increased operating income by $4.3~~$10.8 million ~~for the first six months of 2014 when compared to the same period in 2013. Small increases in operating and maintenance expenses, such as normal increases in payroll and benefits~~

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~~expenses, decreased operating income by a combined $4.1 million for the first six months of 2014~~ when compared with the ~~same period in the~~ prior year.

The $18.4 million decrease in Idaho Power's operating income was partially offset by $2.6 million of other non-operating income, mostly attributable to an increase in AFUDC resulting from increased capital expenditures and $7.3 million of lowerYear-to-date income tax expense ~~mostly related to~~was lower ~~pre-tax income, when compared to~~in 2015, reflecting the ~~same period in 2013.~~

~~Also partially offsetting~~flow-through impact of the ~~decrease in operating income for the second quarter and the first six months~~$17.9 million tax deductible make-whole premium Idaho Power paid upon early redemption of ~~2014 was a $2.8 million decrease in revenue sharing~~long-term debt that was ~~recorded~~due in 2013. The revenue sharing recorded in the second quarter of 2013 related to a December 2011 settlement agreement with the IPUC, which requires sharing with Idaho customers of a portion of 2012, 2013, and 2014 Idaho-jurisdiction earnings exceeding a 10.0 percent Idaho ROE. In the second quarter of 2014, Idaho Power did not record any provision for sharing under the settlement agreement.

2018.

Key Operating and Financial Metric Estimates for Full-Year ~~2014~~2015

As of the date of this report, IDACORP’s and Idaho Power’s estimates for ~~2014~~2015 are as follows (in millions):



	~~2014~~2015 Estimates
	Current⁽¹⁾	Previous⁽²⁾
Idaho Power Operating & Maintenance Expense	No Change	$~~335-~~340-$~~345~~350
Idaho Power Additional Amortization of ADITC	$0No Change	~~Less than $5~~None
Idaho Power Capital Expenditures, excluding AFUDC	No Change	$~~280-~~300-$~~295~~310
Idaho Power Hydroelectric Generation (MWh)⁽³⁾	~~5.5-6.5~~6.0-7.0	~~5.5-7.5~~5.0-7.0

⁽¹⁾ As of July ~~31, 2014.~~30, 2015.

⁽²⁾ As of ~~May 1, 2014,~~April 30, 2015, the date of filing IDACORP's and Idaho Power's ~~Quarterly~~Annual Report on Form 10-Q for the quarter ended March 31, ~~2014.~~2015.

⁽³⁾ Based on reservoir storage levels and forecasted weather conditions as of the date of this report.

RESULTS OF OPERATIONS

This section of MD&A takes a closer look at the significant factors that affected IDACORP’s and Idaho Power’s earnings during the three and six months ended June 30, ~~2014~~2015. In this analysis, the results for the three and six months ended June 30, ~~2014~~2015 are compared towith the same periods in ~~2013~~2014.

Utility Operations

The table below presents Idaho Power’s energy sales and supply (in thousands of MWh) for the three and six months ended June 30, ~~2014~~2015 and ~~2013~~2014.


	Three months ended June 30,				Six months ended June 30,				Three months ended June 30,				Six months ended June 30,
	2014		2013		2014		2013		2015		2014		2015		2014
General business sales	3,577		3,649		6,763		6,997		3,733		3,577		6,845		6,763
Off-system sales	361		200		1,177		701		201		361		737		1,177
Total energy sales	3,938		3,849		7,940		7,698		3,934		3,938		7,582		7,940
Hydroelectric generation	1,778		1,499		3,334		3,009		1,417		1,778		3,235		3,334
Coal generation	1,068		1,316		2,630		2,973		1,198		1,068		2,208		2,630
Natural gas and other generation	44		264		439		491		583		44		792		439
Total system generation	2,890		3,079		6,403		6,473		3,198		2,890		6,235		6,403
Purchased power	1,368		1,080		2,107		1,801		1,015		1,368		1,779		2,107
Line losses	(320	)	(310	)	(570	)	(576	)	(279	)	(320	)	(432	)	(570	)
Total energy supply	3,938		3,849		7,940		7,698		3,934		3,938		7,582		7,940

Sales Volume and Generation: In the second quarter and first six months of ~~2014,~~2015, general business sales volume ~~decreased~~increased by 72156 thousand MWh, or 24 percent, ~~for the quarter,~~ and ~~234~~82 thousand MWh, or 31 percent, ~~for the first six months of 2014,~~respectively, compared towith the same periods in the prior year. The ~~decreases resulted largely from a decreased volume of~~most notable fluctuations in second quarter general business sales relate to ~~residential, commercial, and irrigation customers. The comparative decrease in residential customer usage is largely attributable to milder~~dry spring weather, which positively

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impacted sales to irrigation customers and extremely warm June temperatures that increased electricity demand for cooling. Year-to-date results also reflect mild first quarter temperatures that reduced electricity demand for heating.

Off-system sales volume decreased by 160 thousand MWh, or 44 percent, and 441 thousand MWh, or 37 percent, in the second quarter and first six months of 2015, respectively, as decreases in output from hydroelectric resources and an increase in customer load decreased surplus power available for off-system sales. Also, favorable wholesale market conditions in 2014 provided more opportunities to make off-system sales during 2014 than induring 2015. Idaho Power operated its generation facilities to take advantage of those 2014 wholesale market conditions, which did not exist to the same ~~periods of 2013, which decreased electricity demand for air conditioning and for heating.~~favorable level in 2015.

~~Off-system sales volume increased by 161~~Hydroelectric generation comprised 44 percent and 52 percent of Idaho Power's total system generation during the second quarter and first six months of 2015, respectively. The 400 thousand MWh ~~or 81 percent,~~and 100 thousand MWh decrease in hydroelectric generation in the second quarter and ~~by 476 thousand MWh, or 68 percent, for the~~ first six months of ~~2014, when~~2015, respectively, compared towith the same periods in ~~the prior year. Favorable wholesale market conditions and lower system loads allowed for greater off-system sales during~~ 2014, ~~than~~was primarily due to below normal water supply resulting in ~~2013.~~

below normal hydroelectric generating conditions. The ~~lower system load demand combined with increased~~decrease in hydroelectric generation led to ~~a decreased~~an increased utilization of coal-fired and ~~natural-gas fired~~natural gas-fired generation. Hydroelectric generation was higher by 279 thousand MWh, or 19 percent, for the second quarter, and 325 thousand MWh, or 11 percent, for the first six months of 2014, compared to the same periods in 2013. The increased hydroelectric generation resulted from more favorable hydrologic conditions when compared to the same periods in the prior year.

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

General Business Revenues: The table below presents Idaho Power’s general business revenues and MWh sales volumes for the three and six months ended June 30, ~~2014~~2015 and ~~2013~~2014, and the number of customers as of June 30, ~~2014~~2015 and ~~2013~~2014.


	Three months ended June 30,						Six months ended June 30,						Three months ended June 30,						Six months ended June 30,
	2014			2013			2014			2013			2015			2014			2015			2014
Revenue
Residential	$	102,768		$	100,038		$	236,631		$	236,425		$	116,337		$	102,768		$	247,192		$	236,631
Commercial	71,352			66,757			141,411			128,632			75,099			71,352			149,769			141,411
Industrial	44,190			39,230			87,018			75,068			45,902			44,190			89,449			87,018
Irrigation	66,186			63,556			66,853			64,330			73,671			66,186			75,670			66,853
Total	284,496			269,581			531,913			504,455			311,009			284,496			562,080			531,913
Provision for sharing	—			(2,800		)	—			(2,800		)
Deferred revenue related to HCC relicensing AFUDC⁽¹⁾	(2,349		)	(2,349		)	(4,934		)	(5,004		)	(2,349		)	(2,349		)	(4,934		)	(4,934		)
Total general business revenues	$	282,147		$	264,432		$	526,979		$	496,651		$	308,660		$	282,147		$	557,146		$	526,979
Volume of Sales (MWh)
Residential	1,015			1,069			2,421			2,625			1,080			1,015			2,384			2,421
Commercial	933			949			1,909			1,935			964			933			1,965			1,909
Industrial	786			772			1,583			1,570			778			786			1,561			1,583
Irrigation	843			859			850			867			911			843			935			850
Total MWh sales	3,577			3,649			6,763			6,997			3,733			3,577			6,845			6,763
Number of customers at period end
Residential	424,518			418,213									431,909			424,518
Commercial	67,116			66,334									68,033			67,116
Industrial	115			117									119			115
Irrigation	19,776			19,376									20,238			19,776
Total customers	511,525			504,040									520,299			511,525

⁽¹⁾As part of its January 30, 2009 general rate case order, the IPUC ~~allowed~~is allowing Idaho Power to recover ~~AFUDC~~the allowance for funds used during construction (AFUDC) on construction work in progress related to the HCC relicensing ~~asset~~process, even though the relicensing process is not yet complete and the ~~relicensing asset has~~costs have not been ~~placed~~moved to electric plant in service. Idaho Power is collecting approximately $10.7 million annually in the Idaho jurisdiction, but is deferring revenue recognition of the amounts collected until the license is issued and the ~~asset is~~accumulated license costs are placed in ~~service under the new license.~~service.

Changes in rates, ~~and~~ changes in customer demand, and changes in FCA revenues are the primary reasons for fluctuations in general business revenue from period to period. The only notable rate changes impacting general business revenue for the comparative periods were the 2014 and 2013 Idaho PCA rate changes, which were effective June 1, 2014 and 2013, respectively. The estimated annualized revenue impact of the 2014 and 2013 PCA rate increase is $11.1 million and $140.4 million, respectively.

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

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electricity to operate irrigation pumps. Rates are also seasonally adjusted, ~~and based on a tiered rate structure that provides~~providing for higher rates during peak load ~~periods.~~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

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illustration, Boise, Idaho weather-related information for the three and six months ended June 30, ~~2014~~2015 and ~~2013~~2014 is presented in the table ~~below.~~that follows.


	Three months ended June 30,			Six months ended June 30,			Three months ended June 30,			Six months ended June 30,
	2014	2013	Normal	2014	2013	Normal	2015	2014	Normal	2015	2014	Normal
Heating degree-days⁽¹⁾	617	642	719	2,987	3,474	3,199	526	617	719	2,599	2,987	3,199
Cooling degree-days⁽¹⁾	136	238	183	136	238	183	373	136	183	373	136	183

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

General business revenue increased $~~17.7~~26.5 million and ~~$30.3~~$30.2 million for the three and six months ended June 30, ~~2014~~,2015, respectively, compared towith the same periods in ~~2013. Specific factors~~2014. Factors affecting general business revenues during the ~~periods~~period are discussed below.

Rates: ~~Rate~~Two rate changes impacted general business revenue for the comparative periods -- an Idaho PCA rate increase effective June 1, 2014, and an Idaho PCA rate decrease effective June 1, 2015, both described in Note 3 - "Regulatory Matters" to the condensed consolidated financial statements included in this report. Overall, rate changes combined to increase general business revenue by ~~$21.6~~$7.0 million in the second quarter, and ~~$48.1~~increased general business revenue by $12.8 million infor the first six months of ~~2014~~2015, compared towith the same periods in ~~2013.~~2014. The revenue impact of the rate changes was ~~substantially~~partially offset by associated changes in operating ~~expenses. Of note,~~expenses - Idaho PCA amortization expense increased ~~$14.5 million for the quarter and $32.3~~$4.4 million for the first six months of ~~2014~~2015 when compared towith the same ~~periods~~period in ~~2013~~2014 due to the changes in the corresponding Idaho PCA true-up rate in the comparative periods.

Customers: Customer growth increased general business ~~revenues~~revenue by ~~$3.1~~$4.0 million and ~~$5.4~~$6.4 million, respectively, when compared towith the second quarter and first six months of ~~2013.~~2014. Total customers increased ~~1.5~~1.7 percent during the twelve months ended June 30, ~~2014.~~2015.

Usage: ~~Lower~~Higher usage (on a per customer basis), primarily by residential and irrigation customers, ~~decreased~~increased general business revenue by $9.8 million for the quarter and by $0.1 million for the first six months of ~~2014 by a respective $9.8 million and $26.0 million~~2015 when compared towith the same periods in ~~2013. For the quarter and first six months of~~ 2014, ~~residential usage per customer decreased 7 percent and 9 percent, respectively,~~ as a result of ~~more mild temperatures during~~ the ~~periods (and hence lesser electric heat~~weather conditions described above.

FCA revenue: The revenue impact of the Idaho FCA mechanism increased $5.7 million in the second quarter and ~~air conditioning usage) compared~~$10.8 million year-to-date. These increases reflect the application of the modifications made to the FCA mechanism, which were approved by the IPUC in the second quarter of 2015, but made retroactive to the beginning of 2015. In the second quarter, Idaho Power recorded $7.4 million of FCA revenue impacts associated with the first quarter sales volumes. Absent the first quarter retroactive impact, the second quarter FCA would have been a decrease of $1.7 million compared with the same ~~periods~~period in the prior ~~year.~~year, due to higher actual sales in the current quarter. The modifications to the FCA mechanism are described in more detail in "Regulatory Matters" in this MD&A and in Note 3 - "Regulatory Matters" to the condensed consolidated financial statements included in this report. The impacts of the FCA are summarized below:

~~Sharing~~: A portion of the increase in revenue for the quarter and the first six months of 2014 resulted from the revenue sharing mechanism in place in both years. The revenue sharing mechanism is associated with the Idaho regulatory agreement that provides for the sharing of Idaho-jurisdiction earnings exceeding a 10 percent Idaho ROE. The impact of this mechanism is recorded as a reduction to general business revenue. For both the quarter and six months ended June 30, 2013, $2.8 million of sharing was recorded, reflecting the amount to be refunded to customers. No such provision was recorded in the comparable periods of the current year.



	1st quarter		2nd quarter			Year-to-date
FCA revenues as reported - 2015	$	6.4	$	9.6		$	16.0
Impact attributable to first quarter activity reported in second quarter	7.4		(7.4		)	—
FCA revenue under new methodology	$	13.8	$	2.2		$	16.0
FCA revenues as reported - 2014	$	1.3	$	3.9		$	5.2
Change in FCA revenues 2015 adjusted vs 2014	$	12.5	$	(1.7	)	$	10.8

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Off-System Sales: Off-system sales consist primarily of long-term sales contracts and opportunity sales of surplus system energy. The table below presents Idaho Power’s off-system sales for the three and six months endedJune 30, ~~2014~~2015 and ~~2013~~2014.


	Three months ended June 30,				Six months ended June 30,				Three months ended June 30,				Six months ended June 30,
	2014		2013		2014		2013		2015		2014		2015		2014
Revenue	$	11,731	$	4,527	$	40,941	$	20,428	$	3,829	$	11,731	$	16,848	$	40,941
MWh sold	361		200		1,177		701		201		361		737		1,177
Revenue per MWh	$	32.50	$	22.64	$	34.78	$	29.14	$	19.05	$	32.50	$	22.86	$	34.78

For the second quarter ~~and first six months~~ of ~~2014,~~2015, off-system sales revenue ~~increased~~decreased by $~~7.2~~7.9 million, or ~~159~~67 percent, ~~and~~ ~~$20.5 million, or 100 percent, respectively,~~ compared towith the same ~~periods~~period in ~~2013. Sales~~2014. Year-to-date, off-system sales revenue decreased by $24.1 million, or 59 percent. Off-system sales volumes ~~increased~~decreased 8144 percent and 37 percent for the quarter and ~~68 percent for the~~ first six months, ofrespectively, as 2014 ~~when compared to the same periods in 2013, as a result of~~sales were well above normal and benefited from favorable market conditions, at times, for selling power off-system. ~~Off-system sales volumes also benefited~~Decreases in output from ~~greater amounts of surplus system energy resulting from slightly lower system loads~~hydroelectric resources and ~~increased hydroelectric generation. The favorable market~~

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~~conditions drove~~ an increase in ~~average~~customer load also reduced the amount of surplus power available for sale off-system ~~sales prices for the second quarter and~~during the first six months of 2015. The favorable market conditions in 2014 by 44also led to higher average prices that year; the average price of off-system sales transactions for the first six months of 2015 was 34 percent ~~and 19 percent, respectively.~~ lower than for the first six months of 2014.

Other Revenues: The table below presents the components of other revenues for the three and six months ended June 30, ~~2014~~2015 and ~~2013~~2014.


	Three months ended June 30,				Six months ended June 30,				Three months ended June 30,				Six months ended June 30,
	2014		2013		2014		2013		2015		2014		2015		2014
Transmission services and other	$	15,157	$	14,165	$	28,711	$	25,944	$	14,965	$	15,157	$	27,891	$	28,711
Energy efficiency	7,620		19,732		12,344		24,202		7,867		7,620		12,209		12,344
Total other revenues	$	22,777	$	33,897	$	41,055	$	50,146	$	22,832	$	22,777	$	40,100	$	41,055

Other ~~revenue decreased~~ ~~$11.1 million, or 33 percent, and $9.1 million, or 18 percent,~~revenues were relatively unchanged in the second quarter of 2015 and ~~first six months of 2014, respectively,~~$1.0 million lower year-to-date, compared with the same periods in ~~2013. These~~2014. The decreases ~~resulted~~ primarily ~~from an order issued by~~related to lower transmission revenue when compared with the ~~IPUC~~same periods in the prior year that allowed Idaho Power to recover custom efficiency program incentive payments made between January 1, 2011 and June 1, 2013 through the energy efficiency rider. Based on the order, $14.3 million of other revenue and energy efficiency program expense was recognized in the second quarter of 2013.year.

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

Purchased Power: The table below presents Idaho Power’s purchased power expenses and volumes for the three and six months ended June 30, ~~2014~~2015 and ~~2013~~2014.


	Three months ended June 30,				Six months ended June 30,				Three months ended June 30,				Six months ended June 30,
	2014		2013		2014		2013		2015		2014		2015		2014
Expense
PURPA contracts	$	37,919	$	33,432	$	66,616	$	64,089	$	31,709	$	37,919	$	58,110	$	66,616
Other purchased power (including wheeling)	24,518		15,719		39,617		27,919		19,627		24,518		36,191		39,617
Total purchased power expense	$	62,437	$	49,151	$	106,233	$	92,008	$	51,336	$	62,437	$	94,301	$	106,233
MWh purchased
PURPA contracts	681		640		1,178		1,152		590		681		1,030		1,178
Other purchased power	687		440		929		649		425		687		749		929
Total MWh purchased	1,368		1,080		2,107		1,801		1,015		1,368		1,779		2,107
Cost per MWh from PURPA contracts	$	55.68	$	52.24	$	56.55	$	55.63	$	53.74	$	55.68	$	56.42	$	56.55
Cost per MWh from other sources	$	35.69	$	35.73	$	42.64	$	43.02	$	46.18	$	35.69	$	48.32	$	42.64
Weighted average - all sources	$	45.64	$	45.51	$	50.42	$	51.09	$	50.58	$	45.64	$	53.01	$	50.42

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Purchased power expense decreased $11.1 million, or 18 percent, in the second quarter and decreased $11.9 million, or 11 percent, in the first six months of 2015, compared with the same periods in 2014, respectively. The decrease for the second quarter and first six months of 2015 was due primarily to reduced volumes purchased.

The purchased power cost per MWh often exceeds the off-system sales revenue per MWh because Idaho Power generally needs to purchase more power during heavy load periods than during light load periods, and conversely has less energy available for off-system sales during heavy load periods than light load periods. Energy prices are typically higher during heavy load periods than during light load periods. Also, in accordance with Idaho Power's risk management policy, Idaho Power may purchase or sell energy several months in advance of anticipated delivery. The regional energy market price is dynamic and additional energy purchase or sale transactions that Idaho Power makes at current market prices may be noticeably different than the advance purchase or sale transaction prices.

~~Purchased power expense increased $13.3 million, or~~ ~~27 percent, in the~~ ~~second~~ ~~quarter and $14.2 million, or 15 percent, in the first six months of 2014, compared to the same periods in~~ ~~2013~~. The increases for the quarter and first six months of 2014 were driven by wholesale gas and electricity market conditions that warranted third-party power purchases to serve system load at times rather than dispatching Idaho Power-owned thermal resources. Scheduled maintenance on thermal resources, which

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~~makes them temporarily unavailable for generation purposes, also caused greater reliance on third-party purchases of power to serve customer loads.~~

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

Fuel Expense: The table below presents Idaho Power’s fuel expenses and generation at its thermal generating plants for the three and six months ended June 30, ~~2014~~2015 and ~~2013~~2014.


	Three months ended June 30,				Six months ended June 30,				Three months ended June 30,				Six months ended June 30,
	2014		2013		2014		2013		2015		2014		2015		2014
Expense
Coal	$	30,211	$	32,200	$	71,247	$	72,516
Coal ⁽¹⁾									$	33,614	$	30,211	$	57,786	$	71,247
Natural gas and other thermal	4,232		9,678		18,524		18,528		12,787		4,232		20,091		18,524
Total fuel expense	$	34,443	$	41,878	$	89,771	$	91,044	$	46,401	$	34,443	$	77,877	$	89,771
MWh generated
Coal	1,068		1,316		2,630		2,973
Coal ⁽¹⁾									1,198		1,068		2,208		2,630
Natural gas and other thermal	44		264		439		491		583		44		792		439
Total MWh generated	1,112		1,580		3,069		3,464		1,781		1,112		3,000		3,069
Cost per MWh - Coal	$	28.29	$	24.47	$	27.09	$	24.39	$	28.06	$	28.29	$	26.17	$	27.09
Cost per MWh - Natural gas and other thermal	$	96.18	$	36.66	$	42.20	$	37.74	$	21.93	$	96.18	$	25.37	$	42.20
Weighted average, all sources	$	30.97	$	26.51	$	29.25	$	26.28	$	26.05	$	30.97	$	25.96	$	29.25

⁽¹⁾The first six months of 2015 exclude 118 MWh of generation from the Jim Bridger power plant for which costs were capitalized during feasibility testing of capital projects under contemplation.

Most fuel supply contracts are subject to changes in published indexes that are closely related to materials and supplies, labor, and diesel costs. In addition to commodity (variable) costs, both natural gas and coal expense include costs that are more fixed in nature for items such as capacity charges, transportation, and fuel handling. Period to period variances in fuel expense per MWh ~~(such as the cost per MWh for natural gas and other in the second quarter compared to the same period in 2013)~~ are noticeably impacted by these fixed charges when generation output is substantially different between the two ~~periods.~~periods; however, natural gas commodity prices decreased significantly between June of 2014 and June of 2015.

Fuel expense ~~decreased~~increased $~~7.4~~12.0 million, or 1835 percent, in the second quarter of ~~2014,~~2015, and ~~$1.3~~decreased $11.9 million, or 113 percent, in the first six months of ~~2014,~~2015, compared towith the same ~~periods~~period in ~~2013.~~2014. The decreases were due principally to more favorable hydrologic conditions and resulting increased hydroelectric generation, as well as lower prices for purchased power, which collectively reduced the need to rely on coal and natural gas-fired generation. Further decreasing fuel expense was the impact of scheduled outages at the Langley Gulch natural gas-fired plant that did not occurincrease in the ~~prior year. These decreases were partially offset for~~second quarter of 2015 was due to greater output from the thermal plants, as MWh generated at these plants increased 12 percent due to increased system load demands. The decrease in the first six months of ~~2014 by increased~~2015 was due to lower output from the ~~Langley Gulch natural gas-fired plant during~~thermal plants for the ~~first quarter,~~period, combined with lower regional gas prices, which ~~was operated in part to take advantage of more favorable pricing in the region for selling~~decreased power ~~off-system than during the same period in 2013.~~production costs.

PCA Mechanisms: Idaho Power's power supply costs (primarily purchased power and fuel, less off-system sales) can vary significantly from year to year. Volatility of power supply costs arises from factors such as weather conditions, wholesale market prices and volumes of power purchased and sold in the wholesale markets, Idaho Power's hydroelectric ~~generation volume,~~and thermal generation volumes and fuel costs, generation plant availability, and retail loads. To address the volatility of power supply costs, Idaho ~~Power has~~Power's PCA mechanisms in ~~both~~ the Idaho and Oregon ~~jurisdictions. These mechanisms~~jurisdictions allow Idaho Power to recover from or refund to customers most of the fluctuations in power supply costs. In the Idaho jurisdiction, the PCA includes a cost or benefit sharing ratio that allocates the deviations in net power supply expenses between customers (95 percent) and the company (5 percent), with the exception of PURPA power purchases and demand response program incentives, which are allocated 100 percent to customers. Because of the PCA mechanisms, the primary financial impacts of power supply cost variations is that cash is paid out but recovery from customers does not occur until a future period, or cash that is collected is refunded to customers in a

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future period, resulting in fluctuations in operating cash flows from year to year. The following table presents the components of the Idaho and Oregon PCA mechanisms for the three and six months ended June 30, ~~2014~~2015 and ~~2013~~2014.

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	Three months ended June 30,						Six months ended June 30,						Three months ended June 30,						Six months ended June 30,
	2014			2013			2014			2013			2015			2014			2015		2014
Idaho power supply cost deferral	$	(7,362	)	$	(15,348	)	$	(5,156	)	$	(25,102	)
Idaho power supply cost (deferral) accrual													$	(5,847	)	$	(7,362	)	$	4,515	$	(5,156	)
Amortization of prior year authorized balances	16,503			2,049			29,320			(2,907		)	16,378			16,503			33,770		29,320
Total power cost adjustment expense	$	9,141		$	(13,299	)	$	24,164		$	(28,009	)	$	10,531		$	9,141		$	38,285	$	24,164

The power supply ~~deferrals~~accruals represent the portion of the power supply cost fluctuations ~~deferred~~accrued under the PCA mechanisms. When actual power supply costs are higher than the amount forecasted in PCA rates, which was the case for the second quarter ~~and for the first six months~~ of ~~2014,~~2015, most of the difference is deferred. The amortization of the prior year’s balances represents the offset to the amounts being collected or refunded in the current PCA year that were deferred or accrued in the prior PCA year (the true-up component of the PCA). See "Regulatory ~~Matters - IPUC Review of Annual Rate Adjustment Mechanisms,"~~Matters" in this MD&A and Note 3 - "Regulatory Matters" to the condensed consolidated financial statements included in this report for a description of the IPUC's review of the true-up component of the PCA mechanism.

Other Operations and Maintenance Expenses: Other O&M expense increased ~~$4.3~~$0.4 million, or 5less than one percent, and $3.4 million, or 2 percent, for the quarter and ~~$5.0 million, or 3 percent, for the~~ first six months of ~~2014 as~~2015, compared to the same periods in 2013. The increase for the quarter related to a shift of $2.2 million in thermal maintenance expenses to the second quarter from the first quarter due to the timing of maintenance work performed in the comparative periods and to a $1.8 million increase in labor and benefits costs when compared towith the same period in 2014. IDACORP and Idaho Power have been focused on targeting opportunities to optimize business practices to control O&M expenses, which has contributed to the ~~prior year. Operating and maintenance expenses~~relatively modest increase in O&M expense for the first six months of 2014 were higher due to normal escalations in labor and materials costs of $2.2 million, higher non-labor administrative expenses of $2.4 million, and a $1.0 million increase in bad debt expense when compared to the same period in the prior year. The increase in non-labor administrative expenses primarily related to smart grid expense reimbursements received in 2013 that were not received in 2014.periods.

Income Taxes

~~Income Tax Expense:~~IDACORP's and Idaho Power's income tax expense for the six months endedJune 30, ~~2014~~,2015, compared towith the same period in ~~2013,~~2014, decreased ~~$6.6~~$7.3 million and ~~$7.3~~$7.4 million,, respectively, primarily as a result of ~~lower~~the flow-through tax impact of the call premium Idaho Power ~~pre-tax earnings.~~

paid on the early redemption of long-term debt during the second quarter of 2015. 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.

~~Additional Amortization of ADITC:~~ Idaho Power's December 2011 settlement stipulation with the IPUC and other parties provided for the availability of additional amortization of ADITC if Idaho Power's actual Idaho ROE is below 9.5 percent in any calendar year from 2012 to 2014. For information relating to Idaho Power's 2011 settlement stipulation, see Note 3 - “Regulatory Matters” to the condensed consolidated financial statements included in this report. In accordance with the settlement stipulation, Idaho Power has a total of $45 million of additional ADITC amortization available for use in 2014. Based on its~~estimate of 2014 Idaho ROE, Idaho Power did not utilize additional ADITC amortization in the second quarter of 2014 and reversed the~~ ~~$950 thousand~~ ~~that had been recorded in the first quarter of 2014.~~

LIQUIDITY AND CAPITAL RESOURCES

Overview

Idaho Power has been pursuing significant enhancements to its utility infrastructure in an effort to ensure an adequate supply of electricity, to provide service to new customers, and to maintain system reliability. Idaho Power's existing hydroelectric and thermal generation facilities also require continuing upgrades and component replacement. Idaho Power expects these substantial capital expenditures to continue, with estimated total capital expenditures ~~in the range~~ of ~~$1.47 billion to $1.56~~$1.5 billion over the five-year period from ~~2014~~2015 (including expenditures ~~to-date~~to date in ~~2014)~~2015) through ~~2018.~~ 2019.

Idaho Power funds its liquidity needs for capital expenditures through cash flows from operations, debt offerings, commercial paper markets, credit facilities, and capital contributions from IDACORP. Idaho Power periodically files for rate adjustments for recovery of operating costs and capital investments to provide the opportunity to align Idaho Power's earned returns with those allowed by regulators.

Idaho Power uses operating and capital budgets to control operating costs and capital ~~expenditures, and focuses on optimizing~~expenditures. During 2015, Idaho Power has continued its ~~business operations, which includes controlling O&M costs through process review and improvement initiatives. A~~

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~~significant focus for 2014 will be to continue~~efforts to optimize operations, ~~and~~ control costs, and to generate ~~sufficient~~ operating cash inflows to meet operating expenditures, contribute to capital expenditure requirements, and pay dividends to shareholders.

As of July ~~25, 2014~~24, 2015, IDACORP's and Idaho Power's access to debt, equity, and credit arrangements included:

their respective $125 million and $300 million revolving credit facilities;

IDACORP's shelf registration statement filed with the U.S. Securities and Exchange Commission (SEC) on May 22, 2013, which may be used for the issuance of debt securities and common stock, including up to 3 million shares of IDACORP common stock available for issuance under IDACORP's sales agency agreement executed in July 2013;

Idaho Power's shelf registration statement, filed with the SEC jointly with IDACORP on May 22, 2013, which may be used for the issuance of first mortgage bonds and debt securities; ~~$500~~$250 million is available for issuance under a selling agency agreement executed in July 2013 and pursuant to state regulatory authority; and

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IDACORP's and Idaho Power's issuance of commercial paper, which may be issued up to an amount equal to the available credit capacity under their respective credit facilities.

IDACORP and Idaho Power have no significant long-term debt maturities until 2018. Based on planned capital expenditures and operating and maintenance expenses for 2014, and in light of the success of cost-controlling efforts to-date, the companies believe they will be able to meet capital requirements during the remainder of 2014 with a combination of existing cash and operating cash flows generated by Idaho Power's utility business. IDACORP and Idaho Power would expect to meet any cash shortfall with existing credit facilities and expect to continue to manage short-term liquidity through commercial paper markets. At the same time, IDACORP and Idaho Power monitor capital markets with a view toward opportunistic debt and equity transactions, taking into account current and potential future long-term needs. As a result, IDACORP may issue debt securities or may issue common stock under the existing continuous equity program, and Idaho Power may issue debt securities, if the companies believe terms available in the capital markets are ~~particularly~~ favorable and that issuances would be financially prudent. Idaho Power also periodically analyzes whether partial or full early redemption of one or more existing outstanding series of first mortgage bonds is desirable, and in some cases may refinance indebtedness with new indebtedness issued with more favorable terms, including interest rates lower than the series being redeemed.

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

Based on planned capital expenditures and operating and maintenance expenses for 2015, the companies believe they will be able to meet capital requirements and fund corporate expenses during at least the next twelve months with a combination of existing cash and operating cash flows generated by Idaho Power's utility business. IDACORP and Idaho Power believe they could meet any short-term cash shortfall with existing credit facilities and expect to continue to manage short-term liquidity through commercial paper markets.

IDACORP and Idaho Power seek to maintain capital structures of approximately 50 percent debt and 50 percent equity, and maintaining this ratio influences IDACORP's and Idaho Power's debt and equity issuance decisions. As of June 30, ~~2014~~2015, IDACORP's and Idaho Power's capital structures, as calculated for purposes of applicable debt covenants, were as follows:


	IDACORP	Idaho Power	IDACORP	Idaho Power
Debt	47%	48%	47%	49%
Equity	53%	52%	53%	51%

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 six months endedJune 30, ~~2014~~2015 were ~~$163~~$171 million and ~~$149~~$170 million, respectively, increases of ~~$49~~$8 million and ~~$37~~$21 million, respectively, compared towith the same ~~period~~periods in ~~2013~~.2014. With the exception of cash flows related to income taxes, IDACORP’s operating cash flows are principally derived from the operating cash flows of Idaho Power. Significant items that affected the comparability of the companies' operating cash flows in the first six months of ~~2014 compared to~~2015 with the same period in ~~2013~~2014 were as follows:

net income increased $18 million.

changes in ~~regulatory assets~~deferred taxes and ~~liabilities, mostly related~~in taxes accrued and receivable combined to ~~the relative amounts of power supply costs deferred and collected under the Idaho PCA mechanism, increased operating~~decrease cash flows by ~~$54 million;~~$3 million at IDACORP, and increased cash flows by $12 million at Idaho Power.

increased coal sales for the first six months of 2015 resulted in a $6 million increase in cash distributions from BCC.

comparative changes in working capital balances due primarily to timing, ~~including fluctuations in other current assets,~~ as ~~there was a smaller increase in accrued unbilled revenue in the first six months of 2014 compared to the increase experienced during the first six months of 2013.~~follows:


◦	changes in unbilled revenues reduced operating cash flows $23 million; and


◦	changes in current and long-term prepayments increased operating cash flows $10 million.

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 six months endedJune 30, ~~2014~~2015 were ~~$127 million~~ ~~and~~ ~~$128 million, respectively.~~$151 million. Investing cash outflows for ~~2014~~2015 and ~~2013~~2014 were primarily for construction of utility infrastructure needed to address Idaho Power’s aging plant and equipment, customer growth, and environmental and regulatory compliance requirements.

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Financing Cash Flows

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

IDACORP’s and Idaho Power's financing cash ~~outflows~~inflows for the six months endedJune 30, ~~2014~~2015 were ~~$63~~$54 million and ~~$44~~$59 million,~~, respectively. The following are significant items that affected~~ respectively, primarily related to Idaho Power's issuance on March 6, 2015, of $250 million in first mortgage bonds and redemption on April 23, 2015, of $120 million in first mortgage bonds. Other financing cash flows infor the~~first~~ six months ended June 30, 2015 decreased by $20 million over the same period in 2014, primarily due to the unamortized call premium on the redemption of ~~2014:~~

~~IDACORP~~first mortgage bonds of $18 million in 2015. Financing cash flows in 2015 also included the payment of $47 million of dividends on common stock and ~~Idaho Power paid cash dividends of approximately~~ ~~$43~~a $4 million~~; and~~

~~IDACORP had a~~ net ~~reduction of~~decrease in commercial paper ~~borrowings of~~ ~~$18 million~~.

borrowings.

Financing Programs and Available Liquidity

IDACORP Equity Programs:On July 12, 2013, IDACORP entered into a Sales Agency Agreement with BNY Mellon Capital Markets, LLC (BNYMCM), under which IDACORP may offer and sell up to 3 million shares of its common stock from time to time through BNYMCM as IDACORP's agent. IDACORP has no obligation to sell any minimum number of shares under the Sales Agency Agreement. As of the date of this report, ~~all~~ 3 million shares of IDACORP common stock remain available for sale under the Sales Agency Agreement with BNYMCM. As of the date of this report, IDACORP does not expect to issue any shares of its common stock under the Sales Agency Agreement during 2015.

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

Idaho Power First Mortgage Bonds: Idaho Power's issuance of long-term indebtedness is subject to the approval of the IPUC, OPUC, and Wyoming Public Service Commission (WPSC). In April 2013, Idaho Power received orders from the IPUC, OPUC, and WPSC authorizing Idaho Power to issue and sell from time to time up to $500 million in aggregate principal amount of debt securities and first mortgage bonds, subject to conditions specified in the orders. Authority from the IPUC iswas through April 9, 2015. However, on April 1, 2015, ~~though Idaho Power may request an extension by letter filed with~~ the IPUC ~~prior~~approved a two-year extension through April 9, 2017, continuing Idaho Power's authorization to ~~that date.~~issue and sell from time to time debt securities and first mortgage bonds. The OPUC's and WPSC's orders do not impose a time limitation for issuances, but the OPUC order does impose a number of other conditions, including a maximum interest rate limit of 7seven percent.

On July 12, 2013, Idaho Power entered into a Selling Agency Agreement with eight banks named in the agreement in connection with the potential issuance and sale from time to time of up to $500 million in aggregate principal amount of first mortgage bonds, Series J (Series J Notes), under Idaho Power’s Indenture of Mortgage and Deed of Trust, dated as of October 1, 1937, as amended and supplemented (Indenture). Also on July 12, 2013, Idaho Power entered into the Forty-seventh Supplemental Indenture, dated as of July 1, 2013, to the Indenture. The Forty-seventh Supplemental Indenture provides for, among other items, the issuance of up to $500 million in aggregate principal amount of Series J Notes. As of the date of this report, $250 million remained on Idaho ~~Power has not sold any~~Power's Selling Agency Agreement for the issuance of first mortgage bonds, including Series J Notes, or debt securities under the Selling Agency Agreement and does not anticipate any issuances during the remainder of 2014, except for potential transactions the company believes may be particularly opportunistic based on capital market conditions.securities.

The issuance of first mortgage bonds requires that Idaho Power meet interest coverage and security provisions set forth in the Indenture. Future issuances of first mortgage bonds are subject to satisfaction of covenants and security provisions set forth in the Indenture, market conditions, regulatory authorizations, and covenants contained in other financing agreements.

The Indenture limits the amount of additional first mortgage bonds that Idaho Power may issue to the sum of (a) the principal amount of retired first mortgage bonds and (b) 60 percent of total unfunded property additions, as defined in the Indenture of Mortgage and Deed of Trust. As of ~~June 30, 2014~~, Idaho Power could issue approximately $1.5 billion of additional first mortgage bonds based on retired first mortgage bonds and total unfunded property additions. However, the Indenture of Mortgage and Deed of Trust further limits the maximum amount of first mortgage bonds at any one time outstanding to $2.0 billion, and as a result the maximum amount of first mortgage bonds Idaho Power could issue as of June 30, ~~2014~~2015 was limited to approximately ~~$409~~$279 million. Idaho Power may increase the $2.0 billion limit on the maximum amount of first mortgage bonds outstanding by filing a supplemental indenture with the trustee as provided in the Indenture of Mortgage and Deed of Trust. Separately, the Indenture also limits the amount of additional first mortgage bonds that Idaho Power may issue to the sum of (a) the principal

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amount of retired first mortgage bonds and (b) 60 percent of total unfunded property additions, as defined in the Indenture. As of June 30, 2015, Idaho Power could issue approximately $1.5 billion of additional first mortgage bonds based on retired first mortgage bonds and total unfunded property additions.

IDACORP and Idaho Power Credit Facilities: IDACORP and Idaho Power have $125 million and $300 million credit facilities, respectively. Each of the credit facilities may be used for general corporate purposes and commercial paper back-up. IDACORP's facility permits borrowings under a revolving line of credit of up to $125 million ~~outstanding~~ at any one time outstanding, including swingline loans not to exceed $15 million at any time and letters of credit not to exceed $50 million at any time. IDACORP's facility may be increased, subject to specified conditions, to $150 million. Idaho Power's facility permits borrowings through the issuance of loans and standby letters of credit of up to $300 million ~~outstanding~~ at any one time outstanding, including swingline loans not to exceed $30 million at any one time. Idaho Power's facility may be increased, subject to specified conditions, to $450 million. ~~The interest rates for any borrowings under~~Other terms and conditions of the credit facilities are ~~based on either (1) a floating rate that is equal to the highest of the prime rate, federal funds rate plus 0.5 percent, or LIBOR rate plus 1.0 percent, or (2) the LIBOR rate, plus,~~described in ~~each case, an applicable margin. The applicable margin is based on~~ IDACORP's orand Idaho Power's ~~as applicable, senior unsecured long-term indebtedness credit rating, as set forth~~Annual Report on ~~a schedule to~~Form 10-K for the ~~credit agreements. The companies also pay a facility fee based on the respective company's credit rating for senior unsecured long-term debt securities.~~year ended December 31, 2014, in Part II, Item 7 - "MD&A - Liquidity and Capital Resources."

Each facility contains a covenant requiring each company to maintain a leverage ratio of consolidated indebtedness to consolidated total capitalization equal to or less than 65 percent as of the end of each fiscal quarter. In determining the leverage ratio, “consolidated indebtedness” broadly includes all indebtedness of the respective borrower and its subsidiaries, including, in some instances, indebtedness evidenced by certain hybrid securities (as defined in the credit agreement). “Consolidated total capitalization” is calculated as the sum of all consolidated indebtedness, consolidated stockholders' equity of the borrower and its subsidiaries, and the aggregate value of outstanding hybrid securities. At June 30, ~~2014~~2015, the leverage ratios for IDACORP and Idaho Power were 47 percent and 4849 percent,, respectively. IDACORP's and Idaho Power's ability to utilize the credit facilities is conditioned upon their continued compliance with the leverage ratio covenants included in the credit facilities, which could limit the ability of the companies to issue first mortgage bonds and debt securities. There are additional covenants, subject to exceptions, that prohibit certain mergers, acquisitions, and investments, restrict the creation of certain liens, and prohibit entering into any agreements restricting dividend payments from any material subsidiary. At June 30, ~~2014~~2015, IDACORP and Idaho Power believe they were in compliance with all facility covenants. Further, IDACORP and Idaho Power do not believe they will be in violation or breach of their respective debt covenants during the next twelve months.

The events of default under both facilities include, without limitation, non-payment of principal, interest, or fees; materially false representations or warranties; breach of covenants; bankruptcy or insolvency events; condemnation of property; cross-default to certain other indebtedness; failure to pay certain judgments; change of control; failure of IDACORP to own free and clear of liens the voting stock of Idaho Power; the occurrence of specified events or the incurring of specified liabilities relating to benefit plans; and the incurring of certain environmental liabilities, subject, in certain instances, to cure periods.

Upon any event of default relating to the voluntary or involuntary bankruptcy of IDACORP or Idaho Power or the appointment of a receiver, the obligations of the lenders to make loans under the applicable facility and to issue letters of credit will automatically terminate and all unpaid obligations will become due and payable. Upon any other event of default, the lenders holding greater than 50 percent of the outstanding loans or greater than 50 percent of the aggregate commitments (required lenders) or the administrative agent with the consent of the required lenders may terminate or suspend the obligations of the lenders to make loans under the facility and to issue letters of credit under the facility and/or declare the obligations to be due and payable. During an event of default under the facilities, the lenders may, at their option, increase the applicable interest rates then in effect and the letter of credit fee by 2.0 percentage points per annum. A ratings downgrade would result in an increase in the cost of borrowing, but would not result in a default or acceleration of the debt under the facilities. However, if Idaho Power's ratings are downgraded below investment grade, Idaho Power must extend or renew its authority for borrowings under its IPUC and OPUC regulatory orders.

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

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

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

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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.


	June 30, 2014						December 31, 2013						June 30, 2015						December 31, 2014
	IDACORP⁽²⁾			Idaho Power			IDACORP⁽²⁾			Idaho Power			IDACORP⁽²⁾			Idaho Power			IDACORP⁽²⁾			Idaho Power
Revolving credit facility	$	125,000		$	300,000		$	125,000		$	300,000		$	125,000		$	300,000		$	125,000		$	300,000
Commercial paper outstanding	(37,200		)	—			(54,750		)	—			(27,000		)	—			(31,300		)	—
Identified for other use⁽¹⁾	—			(24,245		)	—			(24,245		)	—			(24,245		)	—			(24,245		)
Net balance available	$	87,800		$	275,755		$	70,250		$	275,755		$	98,000		$	275,755		$	93,700		$	275,755

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

⁽²⁾ Holding company only.

At July ~~25, 2014~~24, 2015, IDACORP had no loans outstanding under its credit facility and ~~$34.8~~$26.6 million of commercial paper outstanding, and Idaho Power had no loans outstanding under its credit facility and no commercial paper outstanding. The table

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below presents additional information about short-term commercial paper borrowing during the three and six months ended June 30, ~~2014~~2015.


	Three months ended						Six months ended						Three months ended						Six months ended
	June 30, 2014						June 30, 2014						June 30, 2015						June 30, 2015
	IDACORP⁽¹⁾			Idaho Power			IDACORP ⁽¹⁾			Idaho Power			IDACORP⁽¹⁾			Idaho Power			IDACORP ⁽¹⁾			Idaho Power
Commercial paper:
Period end:
Amount outstanding	$	37,200		$	—		$	37,200		$	—		$	27,000		$	—		$	27,000		$	—
Weighted average interest rate	0.31		%	—		%	0.31		%	—		%	0.54		%	—		%	0.54		%	—		%
Daily average amount outstanding during the period	$	42,363		$	—		$	44,557		$	—		$	35,991		$	—		$	31,596		$	—
Weighted average interest rate during the period	0.30		%	—		%	0.31		%	—		%	0.56		%	—		%	0.52		%	—		%
Maximum month-end balance	$	40,500		$	—		$	47,300		$	—		$	35,200		$	—		$	43,400		$	—

⁽¹⁾ Holding company only.

Impact of Credit Ratings on Liquidity and Collateral Obligations

IDACORP’s and Idaho Power’s access to capital markets, including the commercial paper market, and their respective financing costs in those markets, depends in part on their respective credit ratings. There have been no changes to IDACORP's or Idaho Power's ratings or ratings outlook by Standard & Poor’s Ratings Services or Moody’s Investors Service from those included in the companies' Annual Report on Form 10-K for the year ended December 31, ~~2013.~~2014. However, any rating can be revised upward or downward or withdrawn at any time by a rating agency if it decides that the circumstances warrant the change.

Idaho Power maintains margin agreements relating to its wholesale commodity contracts that allow performance assurance collateral to be requested of and/or posted with certain counterparties. As of June 30, ~~2014~~2015, Idaho Power had posted ~~$1.7~~$0.8 million of performance assurance collateral. Should Idaho Power experience a reduction in its credit rating on its unsecured debt to below investment grade, Idaho Power could be subject to requests by its wholesale counterparties to post additional performance assurance collateral, and counterparties to derivative instruments and other forward contracts could request immediate payment or demand immediate ongoing full daily collateralization on derivative instruments and contracts in net liability positions. Based upon Idaho Power’s current energy and fuel portfolio and market conditions as of June 30, ~~2014~~2015, the amount of additional collateral that could be requested upon a downgrade to below investment grade is approximately ~~$10.6~~$16.0 million. To minimize capital requirements, Idaho Power actively monitors its portfolio exposure and the potential exposure to additional requests for performance assurance collateral through sensitivity analysis.

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Capital Requirements

Idaho Power's construction expenditures, excluding ~~AFUDC,~~allowance for funds used during construction (AFUDC), were ~~$124.1~~$148 million during the six months ended June 30, ~~2014~~2015. The table below presents Idaho Power's estimated cash requirements for construction, excluding AFUDC, for ~~2014~~2015 (including amounts incurred ~~to-date during 2014)~~to-date) through ~~2018~~2019 (in millions of dollars).


	2014	2015	2016-2018	2015	2016	2017-2019
Ongoing capital expenditures (excluding item listed below in this table)	$235-245	$275-290	$855-900	$255-260	$285-290	$850-905
Jim Bridger plant selective catalytic reduction (SCR) equipment	45-50	40-45	20-25
Jim Bridger plant selective catalytic reduction equipment				45-50	15-20	20-25
Total	$280-295	$315-335	$875-925	$300-310	$300-310	$870-930

Major Infrastructure Projects: Idaho Power is engaged in the development of a number of significant projects and has entered into arrangements with third parties concerning joint infrastructure development. The discussion below provides a summary of developments in certain of ~~these~~those projects ~~and notable developments~~ since the discussion of these matters included in Part II, Item 7 - “MD&A - Capital Requirements” in IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, ~~2013.~~2014. The discussion below should be read in conjunction with that report.

~~Boardman-to-Hemingway Line:~~Jim Bridger Plant Selective Catalytic Reduction Equipment and Related IPUC Filing: Idaho Power and the plant co-owners are installing selective catalytic reduction (SCR) equipment to reduce nitrogen oxide (NO_x) emissions at the Jim Bridger power plant, in order to comply with regional haze rules. The regional haze rules provide for installation and operation of SCR on unit 3 by 2015 and unit 4 by 2016. The rules provide for an equivalent technology for NO_x reductions on unit 2 by 2021 and unit 1 by 2022. Idaho Power estimates that the total cost for Idaho Power's share of the upgrades on units 3 and 4 is approximately

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$109 million, excluding AFUDC. As of June 30, 2015, Idaho Power had expended $65 million, excluding AFUDC, on SCR installation at units 3 and 4. As of the date of this report, the overall project remains on schedule and Idaho Power expects the total project cost to be at or below the estimated amount.

Boardman-to-Hemingway Transmission Line:The Boardman-to-Hemingway line, a proposed 300-mile, 500-kV transmission project between a station near Boardman, Oregon and the Hemingway station near Boise, Idaho, would provide transmission service to meet future resource needs. The Boardman-to-Hemingway line was included in the preferred resource portfolio in Idaho Power’s ~~2013 Integrated Resource Plan (IRP).~~2015 IRP. In January 2012, Idaho Power entered into a joint funding agreement with PacifiCorp and the Bonneville Power Administration ~~(BPA)~~ to pursue permitting of the project. The joint funding agreement provides that Idaho Power's interest in the permitting phase of the project would be approximately 21 percent, and that during future negotiations relating to construction of the transmission line Idaho Power would seek to retain that percentage interest in the completed project. Assuming both other participants fund their full share of the total cost of the permitting phase of the project, Idaho Power's estimated share of the cost of the permitting phase of the project is approximately ~~$20~~$37 million, including AFUDC. Total cost estimates for the project are between ~~$890 million~~$1.0 billion and ~~$940 million,~~$1.2 billion, including AFUDC. This cost estimate excludes the impacts of inflation and price changes of materials and labor resources that may occur following the date of the estimate. Idaho Power's share of the permitting phase of the project (excluding AFUDC) is included in the capital requirements table above. Construction costs beyond the permitting phase are not included in the table above.

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

Idaho Power has expended approximately ~~$58~~$68 million on the Boardman-to-Hemingway project through June 30, ~~2014.~~2015. Pursuant to the terms of the joint funding arrangements, approximately ~~$29~~$35 million of that amount must be reimbursed to Idaho Power by joint permitting participants for expenses Idaho Power incurred, $23 million of which Idaho Power had received as of June 30, ~~2014. An additional $14~~2015. In addition to the $35 million amount noted above, $16 million is subject to reimbursement at a later date from the joint permitting participants, assuming their continued participation in the project, for expenses Idaho Power incurred prior to execution of the joint funding arrangements. Idaho Power plans to seek recovery of its share of project costs through the regulatory process.

The permitting phase of the Boardman-to-Hemingway project is subject to review and approval by the U.S. Bureau of Land Management (BLM) as the lead federal agency on behalf of other federal agencies, the U.S. Forest Service, and the Oregon Department of Energy. The BLM issued a draft environmental impact study (EIS) for the project on December 19, 2014, and as of the date of this report Idaho Power expects the BLM to issue a final EIS during 2016. In the separate Oregon state permitting process, Idaho Power submitted a preliminary application for a site certificate in February 2013 and intends to submit an amended preliminary application in 2016. Idaho Power is unable to determine an approximate in-service date for the line but expects the in-service date would be during 2021 or beyond.

Gateway West ~~Line:~~Transmission Line: Idaho Power and PacifiCorp are pursuing the joint development of the Gateway West project, a 500-kV transmission project between a station located near Douglas, Wyoming and the Hemingway station. In January 2012, Idaho Power and PacifiCorp entered a ~~new~~ joint funding agreement for permitting of the project. Idaho Power's estimated cost for the permitting phase of the Gateway West project is approximately ~~$29~~$64 million, including ~~AFUDC.~~AFUDC, which has been extended to the project's anticipated in-service date. Idaho Power has expended approximately ~~$25~~$28 million on the permitting phase of the project through June 30, ~~2014.~~2015. As of the date of this report, Idaho Power estimates the total cost for its share of the project (including both permitting and construction) to be between ~~$150~~$200 million and ~~$300~~$400 million, including AFUDC. Idaho Power's share of the permitting phase of the project (excluding AFUDC) is included in the capital requirements table above. Construction costs beyond the permitting phase are not included in the table above.

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

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BLM. The BLM released its record of decision ~~prepared~~ under the National Environmental Policy Act in November 2013. In its record of decision, the BLM identified its final decision on the routing of the project, issued right-of-way grants on public land for some segments, ~~1 through 7 and 10,~~ and deferred a decision on two segments ~~8 and 9~~(in both of which Idaho Power has an interest) to resolve routing concerns in those areas. Several interested parties have appealed the BLM's record of decision, and Idaho Power has intervened in the proceedings. The BLM ~~requested and received from~~has initiated the ~~Boise District Regional Advisory Council recommendations on routing, siting, and mitigation/enhancements for segments 8 and 9. The BLM has determined that a full~~ supplemental EIS ~~will be required for segments 8 and 9 but has not released a schedule~~process for the ~~preparation and~~two deferred segments. As of the date of this report, the BLM's schedule provides for the issuance of ~~the supplemental EIS. Idaho Power estimates that it could take up to two years before~~ a record of decision on the two deferred segments by mid-year 2016.

Hells Canyon Complex Relicensing: The HCC, located on the Snake River where it forms the border between Idaho and Oregon, provides approximately 68 percent of Idaho Power's hydroelectric generating nameplate capacity and 32 percent of its total generating nameplate capacity. Idaho Power has been engaged in the process of obtaining from the FERC a new long-term license for the HCC. As noted in "Regulatory Matters" in this MD&A, the costs associated with obtaining a new long-term license for the HCC are significant. Idaho Power expects that the annual capital expenditures and operating and maintenance expenses associated with compliance with the terms and conditions of the long-term license could also be substantial, but the company is ~~issued by~~currently unable to estimate those costs in light of the ~~BLM on segments 8~~uncertainty surrounding the ultimate

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terms and 9.conditions that may be included in the license. Idaho Power would seek to recover those relicensing and compliance costs in rates through the regulatory process.

Shoshone Falls Plant Expansion ~~Project Update~~: The Shoshone Falls plant expansion project was included in Idaho Power's 2013 IRP and, ~~consists~~as originally planned, was to consist of constructing a new powerhouse, intake structure, penstock, and substation and ~~the installation of~~installing a new turbine to increase the nameplate generation capacity of the plant from 12.5 MW to 61.5 MW. ~~The most recent FERC license amendment issued for~~However, following additional analysis of the ~~plant~~costs and potential benefits of the expansion, Idaho Power's 2015 IRP (discussed below) includes in ~~2012 required~~ the near-term action plan a modified project that would result in a significantly smaller increase in nameplate generation capacity at the facility, in a range of 1.7 MW to ~~be completed by 2017. However,~~4 MW, with a potential on-line date as ~~the project is unlikely to be completed by 2017,~~early as 2019. Idaho Power ~~sought~~is performing additional engineering and cost studies to determine the most suitable project that will optimize and improve the reliability of the facility. Idaho Power intends to seek a license amendment from the FERC that would allow for construction of the modified project.

Pending Transmission System Transaction: To enhance the abilities of Idaho Power and PacifiCorp to serve their respective customers, on October 24, 2014, Idaho Power and PacifiCorp executed a Joint Ownership and Operating Agreement (Joint Operating Agreement) applicable to certain transmission-related equipment proposed to be exchanged by Idaho Power and PacifiCorp. The proposed exchange would be made pursuant to the terms of a Joint Purchase and Sale Agreement, also dated October 24, 2014, between Idaho Power and PacifiCorp, under which each party agreed to transfer to the other specified transmission-related equipment with an ~~additional schedule extension. In May~~estimated year-end 2014 net book value of approximately $43 million, subject to true-up as of the ~~FERC authorized extension~~closing date. The proposed transaction also provides for the termination and amendment of a number of legacy long-term agreements related to the ownership and operation of jointly-owned facilities and transmission services between Idaho Power and PacifiCorp. Closing of the proposed transaction, effectiveness of the Joint Operating Agreement, and termination and amendment of the legacy long-term transmission service agreements is subject to a number of conditions, including regulatory approvals and notices. As of the date of ~~commencement of construction to July 2018~~this report, regulatory approval from the FERC and ~~completion of construction by July 2022. Notwithstanding this schedule extension,~~several state regulatory commissions has been obtained, but approval from some state public utility commissions remains pending. In 2014, Idaho Power ~~still anticipates incurring~~collected approximately $8 million in transmission revenues under legacy long-term transmission agreements that would be terminated in connection with the ~~construction expenditures included in~~proposed transaction. If the ~~table above through selecting and accelerating other projects that~~transaction is approved, Idaho Power ~~had previously expected~~anticipates an increase to ~~defer beyond 2018.~~its OATT rate, subject to FERC approval, as discussed in "Regulatory Matters" in this MD&A.

~~2013~~2015 Integrated Resource Plan:The IPUC and OPUC require that Idaho Power prepare biennially ~~prepare~~ an IRP. The IRP ~~forecasts~~seeks to forecast Idaho Power's loads and resources for a 20-year period, analyzes potential supply-side, demand-side, and ~~demand-side resource~~transmission options, and identifies potential near-term and long-term actions. Decisions made in IRP proceedings do not constitute ratemaking, but the company views acceptance for filing (in Idaho) or acknowledgment (in Oregon) of an IRP as relevant to the subsequent examination of whether the company's resource investments were prudent and thus may be recoverable through rates. On June 28, 2013, Idaho Power filed its ~~2013~~most recent IRP with the IPUC and ~~OPUC.~~OPUC in June 2015. The ~~2013~~2015 IRP ~~includes~~assumes a forecasted annual growth in average energy demand of 1.2 percent and a forecasted annual growth in peak-hour demand of 1.5 percent over the 20-year period. The 2015 IRP identified a preferred resource portfolio, which ~~identifies~~includes the completion of the Boardman-to-Hemingway transmission line asand the ~~major near-term supply-side resource addition. The 2013 IRP also identifies a number~~potential early retirement of significant plant upgrades and environmental control technology installations. On February 24, 2014, the IPUC accepted the 2013 IRP for filing and requested that Idaho Power continue monitoring environmental requirements at a national level and account for their impact in resource planning, collaborate with stakeholders on how best to use energy efficiency as a resource, be actively involved in matters relating to the North Valmy ~~coal-fired~~ power plant, both in 2025, with no other new resource needs prior to 2025. However, as noted in the 2015 IRP, there is considerable uncertainty surrounding the resource sufficiency estimates and ~~promptly apprise~~project completion dates, including uncertainty around the ~~IPUC~~timing and extent of ~~developments that~~third party development of renewable resources, the EPA's proposed rules under Section 111(d) of the Clean Air Act, the actual completion date of the Boardman-to-Hemingway transmission project, and the economics and logistics of plant retirements. These uncertainties, as well as others, could ~~impact~~result in changes to the ~~company's continued reliance on that coal-fired resource. On July 8, 2014,~~desirability of the ~~OPUC acknowledged Idaho Power's short-term~~preferred portfolio and adjustments to the timing and nature of anticipated and actual actions.

The 2015 IRP includes as near-term action items the continued permitting and planning for the Boardman-to-Hemingway transmission line and further investigation of the early retirement of the North Valmy power plant in collaboration with the plant's co-owner. The near-term action plan also includes a decrease in the ~~2013 IRP. In its order,~~size of the ~~OPUC did not acknowledge Idaho Power's investments~~planned Shoshone Falls expansion from 50 MW to a range of 1.7 MW to 4 MW with a scheduled on-line date in ~~selective catalytic reduction emissions technology~~2019, as well as commencement of an economic evaluation of SCR retrofits for units 1 and 2 at the Jim Bridger power plant. The OPUC stated that it would undertake a fair and thorough investigation of the prudence of the emissions technology investments at the Jim Bridger plant when Idaho Power seeks rate recovery for the investments.

Defined Benefit Pension Plan Contributions

Idaho Power contributed $30 million to the defined benefit pension plan in ~~2013, $6.5~~2014, $10 million in April ~~2014,~~2015, and ~~$6.5~~$10 million in July ~~2014.~~2015. Idaho Power currently plans to contribute ~~approximately~~at least $30 million to the pension plan during ~~2014 (including the April and July 2014 contributions)~~2015, including contributions made to-date, in a continued effort to balance the regulatory collection of these expenditures with the amount and timing of contributions and to mitigate the cost of being in an underfunded position. In ~~2015~~2016 and beyond, Idaho Power expects significant contribution obligations under the pension plan. The primary impact of pension contributions is on the timing of cash flows, as the timing of cost recovery lags behind ~~the timing of~~ contributions.

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Contractual Obligations

During the six months endedJune 30, ~~2014~~,2015, IDACORP's and Idaho Power's contractual obligations, outside the ordinary course of business, did not change materially from the amounts disclosed in their Annual Report on Form 10-K for the year ended December 31, ~~2013~~,2014, except for the ~~addition~~following:

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

four power purchase agreements with a solar ~~wind,~~energy developer were terminated due to an uncured breach by the counterparty. Termination of the agreements reduced Idaho Power's contractual payment obligations by approximately $483 million over the 20-year lives of the terminated contracts; and ~~other alternative energy developers for projects with a combined nameplate capacity of approximately 64 MW. Payments pursuant to these agreements are expected to total~~ ~~$252 million~~ ~~from 2014 to 2038. Four of these power purchase agreements remain subject to IPUC approval, with a combined nameplate capacity of approximately 10 MW and expected payments of $50 million.~~

~~In July 2014,~~ Idaho Power ~~signed two energy sales agreements with solar energy developers for projects with~~entered into a ~~combined nameplate capacity of approximately 120 MW. The agreements are~~25-year service agreement, subject to approval by the IPUC, ~~and~~for maintenance services at three of Idaho Power's natural gas plants, with a total estimated obligation of $72 million over the ~~payments pursuant to these agreements are expected to total $480 million from 2016 to 2036.~~term of the agreement.

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Off-Balance Sheet Arrangements

IDACORP's and Idaho Power's off-balance sheet arrangements have not changed materially from those reported in MD&A in IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, ~~2013~~2014.

REGULATORY MATTERS

Introduction

~~As a regulated utility, many of~~ Idaho Power's ~~fundamental business decisions are subject to~~development of rate case plans take into consideration short-term and long-term needs for rate relief, and involve several factors that can affect the ~~approval~~timing of ~~governmental agencies. Idaho Power is under~~rate filings. Such factors include, among others, in-service dates of major capital investments, the ~~jurisdiction (as to rates, service, accounting,~~timing of changes in major revenue and ~~other general matters of utility operation) of the FERC, the IPUC,~~expense items, and the OPUC. The IPUC and the OPUC determine the rates that Idaho Power charges to its retail customers. Idaho Power is also under the regulatory jurisdiction of the IPUC, the OPUC, and the WPSC as to the issuance of debt and equity securities. Also, as a public utility under the Federal Power Act, Idaho Power has authority to charge market-based rates for wholesale energy sales under its FERC tariff and to provide transmission services under its OATT. Idaho Power uses general rate cases, cost adjustment mechanisms, and subject-specific filings to recover its costs of providing service and the costs of its energy efficiency and demand-side management programs, seeking to earn a return on investment where permitted by regulators. Idaho Power remains focused on communicating with regulators the necessity of investments to better serve its customers, the prudence of the costs incurred, and the importance of a reasonable return on investment for IDACORP's shareholders.

customer growth rates. Idaho Power filed general rate cases in Idaho and Oregon during 2011, as well as a single-issue rate ~~cases~~case for the Langley Gulch power plant ~~that~~in Idaho and Oregon in 2012. These significant rate cases resulted in the resetting of base rates in both Idaho and Oregon ~~base rates~~during 2012. More recently, Idaho Power reset its base-rate power supply expenses in ~~2012.~~ 2014.

The outcomes of ~~these and other~~ significant proceedings are described in part in this report and further in IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, ~~2013.~~2014. In addition to the discussion below, which includes notable ~~recent~~ regulatory ~~rate adjustments and mechanisms (including~~ developments since the discussion of these matters in IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, ~~2013),~~2014, refer to Note 3 - “Regulatory Matters” to the condensed consolidated financial statements included in this report for additional information ~~and updates~~ relating to Idaho Power's regulatory matters and recent regulatory filings and orders.

Notable ~~Orders~~Rate Change Filings During ~~2014~~2015

During ~~2014~~2015 to-date, Idaho Power has received ~~orders in the notable regulatory proceedings~~rate change approvals summarized in the table below.



Description	Status	Estimated Rate Impact⁽¹⁾	Notes
Power Cost Adjustment Mechanism - Idaho Filing	~~Approved by the IPUC on May 30, 2014~~New PCA rate became effective June 1, 2015	$~~11.1~~11.6 million ~~net~~ PCA ~~rate increase~~decrease for the period from June 1, ~~2014~~2015 to May 31, ~~2015~~2016	The potential earnings impact of rate increases and decreases associated with the Idaho PCA mechanism is largely offset by associated increases and decreases in actual power supply costs and amortization of deferred power supply ~~costs under the Idaho PCA mechanism.~~
~~Net Power Supply Expense Recovery~~	~~Approved by the IPUC on March 21, 2014~~	~~No net impact on revenues - resulted in the reallocation of costs collected via the Idaho PCA to Idaho base rates, effective June 1, 2014~~	Idaho Power requested an increase of approximately $106 million on a total-system basis in the normalized or “base level” power supply expense to be used to update base rates and in the determination of the PCA rate.costs.
Fixed Cost Adjustment Mechanism - Idaho Filing	~~Approved by the IPUC on May 30, 2014~~New FCA rate became effective June 1, 2015	$~~6.0~~2.0 million FCA increase ~~in the FCA~~ for the period from June 1, ~~2014~~2015 to May 31, ~~2015~~2016	The FCA is designed to remove Idaho Power’s financial disincentive to invest in energy efficiency programs by partially separating (or decoupling) the recovery of fixed costs from the volumetric kilowatt-hour charge and linking it instead to a set amount per customer.

⁽¹⁾ The annual amount collected in rates is typically not recovered on a straight-line basis (i.e., 1/12th per month), and is instead recovered in proportion to general business sales volumes.

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Idaho ~~ROE~~Earnings Support from ~~December 2011~~Idaho Settlement ~~Stipulation; Request for Extension of Settlement Terms~~Stipulation

~~Idaho Power has in place a regulatory mechanism that it believes affords an element of earnings stability for 2014.~~ In December 2011, the IPUC issued an order, separate from the then-pending Idaho general rate case proceeding, approving a settlement stipulation that ~~provides as follows:~~

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allowed Idaho Power to, in certain circumstances, amortize additional ADITC if Idaho Power's actual Idaho ROE for 2012, 2013, or 2014 iswas less than 9.5 percent, ~~then Idaho Power may amortize additional ADITC~~ to help achieve a ~~minimum~~ 9.5 percent Idaho ROE infor the applicable year. ~~Idaho Power would be permitted to amortize additional ADITC in an aggregate amount up to $45 million over the three-year period;~~

ifWhen Idaho Power's actual Idaho ROE for ~~2012, 2013, or 2014 exceeds~~any of those years exceeded 10.0 percent, ~~the amount of Idaho Power's Idaho- jurisdictional earnings exceeding a 10.0 percent and up to and including a 10.5 percent Idaho ROE for the applicable year would be shared equally between~~ Idaho Power ~~and~~was required to share a portion of its Idaho-jurisdiction earnings with Idaho ~~customers in the form of a rate reduction to become effective at the time of the subsequent year's PCA adjustment; and~~

if Idaho Power's actual Idaho ROE for 2012, 2013, or 2014 exceeds 10.5 percent, the amount of Idaho Power's Idaho- jurisdictional earnings exceeding a 10.5 percent Idaho ROE for the applicable year would be allocated 75 percent to Idaho Power's Idaho customers through a reduction to the pension regulatory asset and 25 percent to Idaho Power.

customers. As Idaho Power's 2012, 2013, and ~~2013~~2014 Idaho ROE exceeded ~~10.5~~10.0 percent, Idaho Power did not amortize additional ADITC ~~in 2012 or 2013,~~for those years, but instead shared earnings with ~~customers, as~~customers.

In October 2014, the IPUC issued an order approving an extension, with modifications, of the terms of the December 2011 Idaho settlement stipulation for the period from 2015 through 2019, or until the terms are otherwise modified or terminated by order of the IPUC or the full $45 million of additional ADITC contemplated by the settlement stipulation has been amortized. The more specific terms and conditions of the October 2014 Idaho settlement stipulations are described in Note 3 - "Regulatory Matters" to the condensed consolidated financial statements included in this report. ~~Based on Idaho Power's June 30, 2014 estimate of full-year 2014 Idaho ROE,~~IDACORP and Idaho Power ~~does not expect to amortize any~~believe that the terms allowing amortization of additional ADITC ~~or share~~in the October 2014 settlement stipulation provide the companies with a greater degree of earnings ~~with customers in 2014.~~

~~On May 30, 2014, Idaho Power filed an application with the IPUC requesting an extension of~~stability than would be possible without the terms of the ~~December 2011~~stipulation in effect.

In accordance with the October 2014 settlement stipulation, described above. Idaho Power's application stated that Idaho Power expected, as of the date of the application, to amortize less than $5 million of additional ADITCs in 2014, which would leave more than $40 million of additional ADITCs unused under the December 2011 settlement stipulation. Idaho Power's application requested that the IPUC issue an order extending the terms of the December 2011 settlement stipulation until Idaho Power has ~~amortized~~ a total of $45 million of additional ~~ADITCs (including~~ADITC amortization available for use (limited to $25 million for any applicable year). Based on its estimate of 2015 Idaho ROE, Idaho Power did not record any additional ~~ADITCs amortized~~ADITC amortization or provision for sharing in ~~2014) or until~~ the ~~terms are otherwise modified or terminated by order~~first half of 2015. For the ~~IPUC.~~first quarter of 2014, Idaho Power ~~requested that~~recorded $950 thousand in additional ADITC amortization, all of which was subsequently reversed in the ~~IPUC process the application under modified procedure (which involves written submissions rather than hearings) and issue its decision and order no later than December 31, 2014. The IPUChas granted the request for modified procedure. A meeting among the IPUC Staff,~~second quarter of 2014 based on a then-current estimate of full year 2014 Idaho ~~Power, and intervening parties to conduct a workshop and engage in settlement negotiations is scheduled for August 11, 2014.~~ROE.

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

Deferred power supply costs represent certain differences between Idaho Power's actual net power supply costs and the costs included in its retail rates, the latter being based on annual forecasts of power supply costs. Deferred power supply costs are recorded on the balance sheets for future recovery or refund through customer rates. The following table ~~below~~ summarizes the change in deferred net power supply costs during the six months ended June 30, ~~2014~~2015.

Idaho
Oregon⁽¹⁾
Total
Balance at December 31, 2013 $ 84,843
$ 6,611
$ 91,454
Current period net power supply costs deferred 5,156
—
5,156
Prior amounts recovered through rates (22,869 ) (1,062 ) (23,931 )
SO₂ allowance and renewable energy certificate (REC) sales
(2,362 ) (104 ) (2,466 )
Revenue sharing and energy efficiency rider funds (27,624 ) —
(27,624 )
Interest and other 340
202
542
Balance at June 30, 2014 $ 37,484
$ 5,647
$ 43,131



	Idaho			Oregon⁽¹⁾			Total
Balance at December 31, 2014	$	54,512		$	4,677		$	59,189
Current period net power supply costs accrued	(4,515		)	—			(4,515		)
Prior amounts recovered through rates	(21,035		)	(1,103		)	(22,138		)
SO₂ allowance and renewable energy certificate sales	(1,154		)	(52		)	(1,206		)
Revenue sharing and energy efficiency rider funds	(11,999		)	—			(11,999		)
Interest and other	160			175			335
Balance at June 30, 2015	$	15,969		$	3,697		$	19,666

⁽¹⁾ Oregon power supply cost deferrals are subject to a statute that specifically limits rate amortizations of deferred costs to six percent of gross Oregon revenue per year (approximately $3 million). Deferrals are amortized sequentially.

Idaho Power's PCA mechanisms in its Idaho and Oregon jurisdictions address the volatility of power supply costs and provide for annual adjustments to the rates charged to retail customers. The PCA mechanism and associated financial impacts are described in "Results of Operations" in this MD&A. The IPUC's approval of Idaho Power's April 2014 application requesting an $11.1 million net increase in PCA rates for the 2014-2015 PCA collection period from June 1, 2014 to May 31, 2015, is discussed&A and in Note 3 - "Regulatory Matters" to the condensed consolidated financial statements included in this report. ~~Previously, in May 2013 the IPUC issued an order authorizing a~~ ~~$140.4 million~~ ~~increase in Idaho PCA rates, effective for the 2013-2014 PCA collection period. Also, see Note 3 for a description of the IPUC's currently open docket to review aspects of the PCA mechanism.~~

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

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differences in actual net power supply expenses as compared towith forecasted base net power supply expenses, whether positive or negative. Thus, the primary financial statement impact of power supply cost deferrals is that cash is paid out but recovery of those costs from customers does not occur until a future period, impacting operating cash flows from year to year.

~~Since 2010, when~~Modification of Annual Rate Adjustment Mechanisms

PCA Mechanism -- In July 2014, the IPUC opened a docket pursuant to which Idaho Power, the IPUC Staff, and other interested parties evaluated Idaho Power's ~~normalized level of net power supply expenses included in Idaho base rates last received a comprehensive review, many~~application of the ~~individual cost and~~true-up component of the PCA mechanism. The docket arose from the IPUC's May 2014 PCA order, which noted that the IPUC Staff believed that Idaho Power's application of the true-up component introduced a line-loss bias that inflated the true-up revenue ~~components of these "base level" net power supply expenses changed significantly and permanently. These ongoing and permanent costs were being recovered through~~it must collect. The IPUC's docket was closed via an order issued by the ~~Idaho PCA. The primary components contributing~~IPUC in August 2014, with no adjustment made to the ~~increase in net power supply expenses are increased energy purchases pursuant to PURPA, lower surplus energy sales~~PCA true-up revenue ~~resulting from lower energy market prices, and the elimination~~amount. Idaho Power

Table of ~~anticipated offsetting revenues from one special contract customer. In light of these permanent increases, on November 1, 2013, Idaho Power filed an application~~Contents

subsequently met with the IPUC ~~requesting an increase~~Staff to explore approaches to increasing the accuracy of ~~approximately $106 million on~~the actual cost recovery under the PCA mechanism. On May 28, 2015, the IPUC approved a ~~total-system basis in~~settlement stipulation that modified the ~~normalized or “base level” power supply expense to be used to update base rates and in~~calculation of the ~~determination~~true-up component of the PCA mechanism. The settlement stipulation is described in Note 3 - "Regulatory Matters" to the condensed consolidated financial statements included in this report. Idaho Power estimates the ongoing annual impact of the change to the PCA mechanism will be approximately $2 million of additional expense under normal weather conditions.

FCA Mechanism -- Also in July 2014, the IPUC opened a docket to allow Idaho Power, the IPUC Staff, and other interested parties to further evaluate the IPUC Staff's concerns regarding the application of the FCA. Concerns cited included the application of weather-normalization, the customer count methodology, the rate adjustment cap, cross-subsidization issues, and whether the FCA is in fact effectively removing Idaho Power's disincentive to aggressively pursue energy efficiency programs.

The FCA is designed to remove Idaho Power’s financial disincentive to invest in energy efficiency programs by separating (or decoupling) the recovery of fixed costs from the variable kilowatt-hour charge and linking it instead to a set amount per customer. Stated generally, under the FCA Idaho Power charges residential and small commercial customers when it recovers less "actual fixed costs" than the base level of fixed costs that ~~would become~~the IPUC authorized for recovery through rates in the last general rate case, and Idaho Power credits those customers when its "actual fixed costs" recovered exceed that base level of fixed costs. The FCA is adjusted each year to collect, or refund, the difference between the allowed fixed-cost recovery amount and the actual fixed costs recovered by Idaho Power during the year on a weather-normalized basis.

On May 6, 2015, the IPUC approved a settlement stipulation that modified the FCA mechanism by replacing weather-normalized billed sales with actual billed sales in the calculation of the FCA, applicable for the entirety of calendar year 2015 and thereafter, with new rates effective June 1, ~~2014. On March 21, 2014,~~2016. The settlement stipulation also provided that a modified rate design should be considered at a later time for residential and small general service customers to address the ~~IPUC issued an order approving Idaho Power's application. This removed~~financial disincentive caused by the ~~Idaho-jurisdiction portion~~existing rate design that the FCA is intended to remove. The rate design may include, but would not be limited to, reduced energy charges, increased monthly service charges, and the introduction of ~~those expenses from collection via the Idaho PCA mechanism and instead results in~~demand charges.

In years when actual billed sales per customer are higher than weather-normalized billed sales due to high summer or low winter temperatures, Idaho Power ~~collecting~~expects that ~~portion in base rates. Approval of~~ the ~~application results in no change in~~new FCA methodology will be less favorable to Idaho Power than the ~~aggregate amount collected through base rates and~~prior methodology. Conversely, Idaho Power expects that the ~~PCA mechanism. However, the approved application~~new FCA methodology will ~~reduce the magnitude of any base rate increase requested by~~be more favorable to Idaho Power in ~~its next general rate case application filed with~~years when actual billed sales per customer are lower than weather normalized billed sales due to low summer or high winter temperatures.

Implementation of the ~~IPUC.~~new methodology was retroactive to January 1, 2015, as contemplated by the settlement stipulation. In the second quarter of 2015, Idaho Power recorded additional FCA revenues of $7.4 million related to warmer than normal temperatures experienced in the first quarter of 2015, based on the new terms of the FCA. The net full year impact of the FCA will be recoverable through FCA rates beginning June 1, 2016.

Update to Open Access Transmission Tariff

Idaho Power uses a formula rate for transmission service provided under its OATT, which allows transmission rates to be updated annually based primarily on financial and operational data Idaho Power files with the FERC. On ~~May 30, 2014,~~June 1, 2015, Idaho Power publicly posted ~~its 2014~~an updated 2015 draft transmission rate, reflecting a transmission rate of ~~$22.71~~$33.23 per kW-year, to be effective for the period from October 1, ~~2014~~2015 to September 30, ~~2015. Idaho Power is required to file its final transmission rate with the FERC by September 1, 2014.~~2016. Idaho Power's draft ~~posting~~rate was based on a net annual transmission revenue requirement of ~~$120.8~~$121.3 million. The existing OATT rate in effect from October 1, ~~2013~~2014 to September 30, ~~2014~~2015 is ~~$22.80~~$22.71 per kW-year based on a net annual transmission revenue requirement of ~~$118.2~~$120.8 million.

~~Bulk-System Reliability Standards~~In its June 1, 2015 posting, Idaho Power included in its OATT rate calculations the expected changes in demand associated with the pending transmission system transaction with PacifiCorp described above. If effected, the pending transmission system transaction will terminate certain legacy transmission agreements and provide for new long-term point-to-point transmission service for PacifiCorp. In response to concerns from transmission customers, Idaho Power subsequently shifted its procedural approach for incorporating the impacts of the pending transmission system transaction on its OATT rate. On July 23, 2015, Idaho Power posted a revised draft transmission rate for the same period from October 1, 2015 to September 30, 2016, removing the impact of the pending transmission system transaction. The revised draft filing reflected an OATT rate of $23.43 per kW-year and $121.3 million net annual transmission revenue requirement. On July 28, 2015, Idaho Power made a separate filing with the FERC requesting clarification from the FERC that Idaho Power may incorporate the effects of the pending transmission system transaction in its OATT rate, effective the later of October 1, 2015 or the closing of the pending transmission system transaction. A determination from the FERC is pending.

In March 2014, the FERC directed the North American Electric Reliability Corporation (NERC), pursuant to the Federal Power Act, to submit for approval reliability standards that will require electric utilities to take steps or demonstrate that they have taken steps to address physical security risks and vulnerabilities related to the reliable operation

Table of the bulk-power system. The standards require utilities to identify facilities on the bulk-power system that are critical to the reliable operation of the system and develop, validate, and implement plans to protect against physical attacks that may compromise the operability or recovery of the facilities. Idaho Power has in place a number of physical security measures for its infrastructure. However, the NERC's standards may result in Idaho Power further enhancing its existing physical security measures, which would increase costs. Idaho Power would seek to recover those increased costs through the regulatory process.Contents

Renewable and Other Energy Contracts ~~Renewable Energy Certificates, and Emission Allowances~~

~~Sale of Renewable Energy Certificates:~~ Pursuant to an IPUC order, Idaho Power continues to sell its near-term RECs and is returning to customers their share (95 percent in the Idaho jurisdiction) of those proceeds through the PCA. Idaho Power's REC sales were $2.6 million for the six months ended ~~June 30, 2014~~ ~~as compared with $0.5 million for the same period of~~ ~~2013. The comparative increase in REC sales resulted primarily from the execution of new bundled REC purchase and sale agreements with third parties.~~

~~Renewable and Other Energy Contracts:~~ Idaho Power purchases wind power from both cogeneration and small power production (CSPP) and non-CSPP facilities, including its largest non-CSPP wind power project -- the Elkhorn Valley wind project with a 101 MW nameplate capacity. As of June 30, ~~2014,~~2015, Idaho Power had contracts to purchase energy from on-line CSPP wind power projects with a combined nameplate rating of 577 MW and an additional 50 MW of CSPP wind power projects not on-line and scheduled to come on-line by year-end 2016. In addition to its power purchase arrangements with wind power generators, Idaho Power has contracts for the purchase of power from other CSPP and non-CSPP renewable generation sources, such as biomass, solar, small hydroelectric projects, and two geothermal projects. Recently, Idaho Power has received numerous requests for proposed power purchase contracts from developers of a number of potential solar power projects. As of June 30, ~~2014,~~2015, Idaho Power had contracts to purchase energy from solar projects not yet on-line for a total of 320 MW. All of these solar projects have estimated on-line dates no later than year-end 2016. The following table sets forth, as of June 30, 2015, the number and nameplate capacity of Idaho Power's signed CSPP-related agreements. These agreements ~~with~~have original contract terms ranging from one to 35 ~~years set forth in the following table.~~years.

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Status	Number of CSPP Contracts	Nameplate Capacity (MW)	Number of CSPP Contracts	Nameplate Capacity (MW)
On-line as of June 30, 2014	104	781
On-line as of June 30, 2015			106	782
Contracted and projected to come on-line by June 1, 2017	15	120	24	380

On April 6, 2015, four power purchase agreements with a solar energy developer, for 141 MW of energy, terminated due to an uncured breach by the counterparty. Termination of the agreements reduced Idaho Power's contractual payment obligations by approximately $483 million over the 20-year lives of the terminated contracts.

Pursuant to the requirements ~~of Section 210~~ of PURPA, the IPUC and OPUC have each issued orders and rules regulating Idaho Power's purchase of power from CSPP facilities. A key component of the PURPA power purchase contracts is the energy price contained within the agreements. Regulatory-mandated execution of PURPA agreements ~~may~~can result in Idaho Power acquiring energy that it does not need to serve customer loads at above wholesale market prices and require additional operational integration measures, thus increasing costs to Idaho Power's customers. As the volume of CSPP purchases increases under PURPA, the magnitude of the costs and integration issues also increases. Substantially all PURPA power purchase costs are recovered through base rates and Idaho Power's PCA mechanisms, and thus the primary impact of PURPA agreements is on customer rates.

In light of the volume of intermittent generation Idaho Power is required to purchase pursuant to existing PURPA power purchase agreements and the substantial increase in volume of proposed new solar generation facilities seeking power purchase agreements with Idaho Power, on January 30, 2015, Idaho Power filed an application with the IPUC requesting that the IPUC issue an order directing that the maximum required term for prospective PURPA power purchase agreements be reduced from 20 years to two years. In its application, Idaho Power stated that the requested modification to terms of PURPA energy purchases is necessary to prevent harm to Idaho Power's customers that may result from entering into additional long-term, fixed-rate purchase agreements when Idaho Power predicts that there is no need for new generation capacity through 2021. On February 6, 2015, the IPUC issued an order reducing the maximum contract term of future PURPA power purchase agreements from 20 years to five years during the pendency of the proceedings. IPUC hearings occurred in June 2015. For the Oregon jurisdiction, on April 24, 2015, Idaho Power made filings with the OPUC requesting, among other things, a reduction in the term of standard PURPA power purchase agreements from 20 years to 2 years for projects above 100 kW, and a temporary suspension of Idaho Power's obligation to enter into new fixed-price standard PURPA agreements during the pendency of the proceedings. On June 23, 2015, the OPUC issued an order denying Idaho Power’s request for a temporary suspension but reduced the eligibility cap for standard contracts from 10 MW to 3 MW on a temporary basis during the pendency of the proceedings. Hearings are scheduled to commence in October 2015.

Relicensing of Hydroelectric Projects

Costs for the relicensing of Idaho Power's hydroelectric projects are recorded in construction work in progress until new multi-year licenses are issued by the FERC, at which time the charges are transferred to electric plant in service. Idaho Power expects to seek recovery of relicensing costs through the ratemaking process. Relicensing costs of ~~$189~~$209 million for the HCC, Idaho Power's largest hydroelectric complex and a major relicensing effort, were included in construction work in progress at June 30, ~~2014.~~2015. As of the date of this report, the IPUC authorizes Idaho Power to include in its Idaho jurisdiction rates approximately ~~$6.5~~$10.7 million ~~annually ($10.7 million grossed up for income taxes)~~ of AFUDC annually relating to the HCC relicensing project. Collecting these amounts now will reduce the amount collected in the future when HCC relicensing costs are approved for recovery in base rates. As of June 30, ~~2014,~~2015, Idaho

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Power's regulatory liability for collection of AFUDC relating to the HCC was ~~$65.5~~$80 million. ~~While~~ Idaho Power is unable to predict with certainty the timing of issuance of a new license for the HCC, or the financial or operational requirements of a new ~~license,~~license. As of the date of this report, Idaho Power ~~currently projects~~estimates that the annual costs it will incur to obtain a new long-term license for the HCC, including AFUDC but excluding costs expected to be incurred for complying with the license after issuance, are likely to range from $20 million to $30 million until issuance of the ~~license near 2020.~~license.

ENVIRONMENTAL MATTERS

Overview

Idaho Power is subject to a broad range of federal, state, regional, and local laws and regulations designed to protect, restore, and enhance the environment, including the ~~CAA,~~Clean Air Act, the Clean Water Act, ~~(CWA),~~ the Resource Conservation and Recovery Act, the Toxic Substances Control Act, the Comprehensive Environmental Response, Compensation and Liability Act, and the Endangered Species Act, among other laws. Current and pending environmental legislation relates to, among other issues, climate change, greenhouse gas, mercury and other emissions, air quality, hazardous wastes, polychlorinated biphenyls, and threatened and endangered species. These laws are administered by a number of federal, state, and local agencies. In addition to imposing continuing compliance obligations and associated costs, these laws and regulations provide authority to regulators to levy substantial penalties for noncompliance, injunctive relief, and other sanctions. Idaho Power's three coal-fired power plants and three natural gas-fired combustion turbine power plants are subject to many of these regulations. Idaho Power's 17 hydroelectric projects are also subject to a number of water discharge standards and other environmental requirements.

Compliance with current and future environmental laws and regulations may:

increase the operating costs of generating plants;

increase the construction costs and lead time for new facilities;

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

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

reduce the output from current generating facilities.

Current and future environmental laws and regulations will increase the cost of operating coal-fired power plants and constructing new facilities, in large part through the installation of additional pollution control devices at existing generating plants, and could result in Idaho Power discontinuing the operation of one or more coal-fired plants if operation becomes uneconomical. These regulations could, in turn, affect IDACORP's and Idaho Power's results of operations and financial condition if the costs associated with these environmental requirements and plant shut-downs cannot be fully recovered in rates on a timely basis. Part I - “Business - Environmental Regulation and Costs” in IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, ~~2013~~2014 includes a summary of Idaho Power's expected capital and operating expenditures for environmental matters during the period from ~~2014~~2015 to ~~2016.~~2017. Given the uncertainty of future environmental

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regulations, Idaho Power is unable to predict its environmental-related expenditures beyond that time, though they could be substantial.

~~Included below is a~~A summary of notable ~~developments in~~ environmental matters impacting, or expected to potentially impact, IDACORP and ~~related issues impacting~~ Idaho Power, ~~since the discussion of these and other matters~~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, ~~2013.~~2014. Included below is a summary of notable developments in environmental and related issues impacting Idaho Power since the discussion in that report.

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Developments in Regulation of Coal Combustion Residuals (CCRs)

~~Clean Air~~The Resource Conservation and Recovery Act ~~Developments~~

~~Clean Air Act - Proposed Rules for Existing Generating Plants~~(RCRA) is a federal statute regulating the generation, treatment, storage, and disposal of solid and hazardous wastes. In June 2010, the EPA proposed regulations governing the disposal and management of CCRs, which are regulated under ~~Section 111(d)~~

~~On June 2,~~the RCRA. In December 2014, the EPA ~~released, under Section 111(d) of the CAA, proposed regulations for addressing greenhouse gas emissions from existing fossil fuel-fired electric generating units (EGUs). According~~signed a final rule relating to the ~~EPA,~~disposal of CCRs, which was published in the ~~regulations are designed to achieve a 30 percent reduction in CO~~₂ ~~emissions from the power sector.~~Federal Register on April 17, 2015. The ~~proposal has two main elements: (1) state-specific emission rate-based CO~~₂ ~~goals~~rule establishes structural integrity design criteria and (2) guidelines for the development, submission, and implementation of state plans. The EPA used 2012 as the baseline when calculating the state-specific emission rate goals. While the proposal lays out state-specific CO₂ goals that each state is required to meet, it does not prescribe how a state should meet its goal. Under the proposal, each state may seek to do so alone or may seek to collaborate with other states on multi-state plans.

~~Under the proposed rule, the EPA would permit states to develop plans to reduce CO~~₂ emissions under an approach referred to as the “best system of emission reduction.” This approach is intended to take into account both the cost and technical feasibility of achieving such reduction. States would have flexibility to implement measures that, in some cases, are already in progress. The EPA has grouped these measures into the following four "building blocks," which generally describe four approaches for CO₂ ~~emission reduction:~~


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


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


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


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

~~The EPA's proposal~~ requires that ~~states~~owners and operators periodically conduct a number of structural integrity related assessments and install monitoring apparatus. The rule also imposes location restrictions on impoundments, requires the closure of impoundments that cannot meet ~~their goal by 2030,~~the location restrictions, imposes liner design criteria and operating requirements, and imposes certain record keeping and notification requirements. Additionally, the EPA's rule imposes obligations associated with ~~periodic reports to~~ the ~~EPA starting in 2022. The proposal also provides for states meeting interim goals from 2020 to 2029. State implementation plans would be due by June 30, 2016, subject to extension for portions~~closure of ~~the plan to June 30, 2017 for state plans or June 30, 2018 for multi-state plans, under certain circumstances.~~

CCR impoundments. Idaho Power ~~is analyzing the proposed rules~~ and ~~is participating in state~~its co-owners of coal-fired units performed engineering and regional forums that are evaluating the impact of the proposed rules, the means by which states may seek to achieve compliance, the potential contents of state implementation plans, and other matters. As of the date of this report, Idaho Power is unablecost studies to determine the ~~impact~~impacts of the ~~proposed rules, should they become final, on~~rule. In the second quarter of 2015, Idaho Power recorded an increase of approximately $5 million in its ~~generating plants and operations.~~

~~Regional Haze Rules - Update to Wyoming Implementation Plan~~: In accordance with federal regional haze rules under the CAA, coal-fired utility boilers are subject to regional haze - best available retrofit technology (RH BART) if they were built between 1962 and 1977 and affect any "Class I" (wilderness) areas. This includes all four units atasset retirement obligation for the Jim Bridger coal-fired plant. ~~In December 2009, the Wyoming Department of Environmental Quality (WDEQ) issued a RH BART permit to PacifiCorp as the operator of the Jim Bridger plant. As part of the WDEQ's long term strategy~~The amounts recorded for ~~regional haze, the permit requires that PacifiCorp install SCR equipment~~asset retirement obligations for NO_x ~~control at Jim Bridger Units 3 and 4~~Idaho Power's other jointly-owned coal-fired plants were not impacted by ~~December 31, 2015 and December 31, 2016, respectively, and submit an application by January 15, 2015 to install add-on NO~~_x controls at Jim Bridger unit 1 by 2022 and unit 2 by 2021. In November 2010, PacifiCorp and the WDEQ signed a settlement agreement under which PacifiCorp agreed to the timing and nature of the controls. However, the settlement agreement was conditioned on the EPA ultimately approving those portions of the Wyoming Regional Haze State Implementation Plan (RH SIP) that are consistent with the terms of the settlement agreement. On January 10, 2014, the EPA approved the portion of Wyoming's RH SIP relating to the Jim Bridger plant, with the NOx control compliance dates set forth in the settlement agreement, and approved and disapproved other portions of the RH SIP. Several interested parties have appealed the EPA's decisions on Wyoming's RH SIP on various grounds. Idaho Power has not appealed the EPA's decisions but has intervened in the proceedings to participate if and to the extent the Jim Bridger plant could be affected.new rule.

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Clean Water Act ~~Developments~~-- Definition of "Waters of the United States"

~~Potential Expansion of CWA Scope~~: On ~~April 21, 2014,~~June 29, 2015, the ~~EPA~~EPA's and U.S. Army Corps of ~~Engineers jointly published for public comment a proposed~~Engineers' final rule ~~to revise~~defining the ~~definition of~~phrase "waters of the United States" ~~for purposes of~~under the ~~CWA. The proposed~~Clean Water Act (CWA) was published in the Federal Register, and the rule ~~would~~is scheduled to become effective on August 28, 2015. Idaho Power believes that the final rule potentially ~~expand~~expands federal jurisdiction under the CWA beyond traditional navigable waters, interstate waters, territorial seas, tributaries, and adjacent wetlands, to a number of other waters, including waters with a "significant nexus" to those traditional waters. ~~The~~As a result of the potential expansion, the final rule ~~could trigger substantial~~may result in additional permitting and regulatory requirements under multiple provisions of the CWA. Idaho Power has analyzed the final rule and expects that while it may incur additional permitting and other costs associated with the rule, the aggregate amount of increased costs is ~~analyzing~~unlikely to have a material adverse effect on Idaho Power's operations or financial condition, in part due to the ~~proposed rules but~~relatively arid climate of Idaho Power's service area and the existing application of the CWA to most of Idaho Power's facilities, including its hydroelectric plants.

Clean Air Act -- Mercury and Air Toxics Standard

The final Mercury and Air Toxics Standards (MATS) rule under the Clean Air Act, previously referred to as the Utility MACT Rule, was issued in February 2012. The final rule established emission limits for hazardous air pollutants from new and existing coal-fired and oil-fired steam electric generating units. The MATS rule provided that sources must be in compliance with emission limits by April 16, 2015. Idaho Power and the plant co-owners have installed mercury continuous emission monitoring systems on all of the coal-fired units at the Jim Bridger, Boardman, and North Valmy coal-fired generating plants, along with control technology to reduce mercury, acid gases, and particulate matter emissions for purposes of compliance with the MATS rule. Idaho Power believes that as of the date of this report ~~is unable to determine~~ the ~~impact of the proposed rules, should they become final rules, on its operations.~~

~~CWA Section 316(b) Regulation of Cooling Water Intake Structures~~: Section 316(b) of the CWA requires that National Pollutant Discharge Elimination System permits for facilities with cooling water intake structures ensure that the location, design, construction, and capacity of the structures employ the best technology available (BTA) to minimize harmful impacts on the environment, such as the removal of fish, fish larvae, marine mammals, and other aquatic organisms from waters of the U.S. In May 2014, the EPA issued final rules that establish requirements under Section 316(b) of the CWA for existing power generation facilities that withdraw more than 2 million gallons per day of water from waters of the U.S. and use at least 25 percent of the water they withdraw exclusively for cooling purposes. These facilitiescoal-fired plants are required to reduce fish impingement under the final rules, using one of several options for meeting BTA requirements for reducing impingement. Based on the qualification criteria, Idaho Power expects that these new requirements apply to the Jim Bridger plant. Idaho Power and the plant's co-owner are performing studies at the plant to determine the infrastructure improvements or operational changes that may be required for the plant to comply with the new rules. Based on its preliminary analysis, as of the date of this report Idaho Power does not expect thatin compliance with the ~~new rules will result~~MATS rule. However, on November 25, 2014, the United States Supreme Court granted a petition for review of the MATS rule based on the issue of whether the EPA unreasonably refused to consider costs in determining whether it is appropriate to regulate hazardous air pollutants from coal-fired and oil-fired steam electric generating units. On June 29, 2015, the Court issued a ~~material increase~~decision holding that the EPA must consider cost, including the cost of compliance, before deciding whether regulation is appropriate and necessary, and remanded the case to the District of Columbia Circuit Court for further proceedings consistent with the Court's decision. The MATS rule remains in ~~costs.~~effect until the District of Columbia Circuit Court acts.

OTHER MATTERS

Critical Accounting Policies and Estimates

IDACORP’s and Idaho Power’s discussion and analysis of their financial condition and results of operations are based upon their condensed consolidated financial statements, which have been prepared in accordance with generally accepted accounting principles. The preparation of these financial statements requires IDACORP and Idaho Power to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues, and expenses and related disclosure of contingent assets and liabilities. On an ongoing basis, IDACORP and Idaho Power evaluate these estimates, including those estimates related to rate regulation, ~~benefit costs,~~retirement benefits, contingencies, litigation, asset impairment, ~~of assets,~~ income taxes, unbilled revenue, and bad debt. These estimates are based on historical experience and on other assumptions and factors that are believed to be reasonable under the circumstances, and are the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. IDACORP and Idaho Power, based on their ongoing reviews, make adjustments when facts and circumstances dictate.

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IDACORP’s and Idaho Power’s critical accounting policies are reviewed by the audit committees of the boards of directors. These policies have not changed materially from the discussion of those policies included under “Critical Accounting Policies and Estimates” in IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, ~~2013~~2014.

Recently Issued Accounting Pronouncements

See Note 1 - "Summary of Significant Accounting Policies" to the condensed consolidated financial statements included in this report for a summary of significant accounting policies, including the discussion under "Change in Method of Accounting for Investments in Qualified Affordable Housing Projects," relating to IDACORP's adoption in 2013, with retrospective effect, of an accounting policy election to account for investments in qualified affordable housing projects using the proportional amortization method. This method change resulted in a $1.0 million increase in IDACORP's net income in the second quarter of 2013 and a $2.7 million increase in IDACORP's net income for the first half of 2013 compared to the amounts recorded under the previously applied method.

~~In May 2014, the~~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, ~~2014-09 requires an entity to apply~~recognition of revenue occurs when a ~~five-step model to achieve the core principle of recognizing revenue to depict the transfer~~customer obtains control of promised goods or ~~services to customers in an amount that reflects~~services. In addition, the ~~consideration to which~~ASU requires disclosure of the ~~entity expects to be entitled in exchange for those goods and services. The ASU also requires certain disclosures to enable users of financial statements to understand the~~ nature,

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amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The amendments in ASU 2014-09 are effective for annual reporting periods beginning after December 15, ~~2016,~~2017, including interim periods within that reporting ~~period. Early~~period, with early adoption ~~is not permitted.~~permitted one year earlier. The guidance permits two implementation approaches, one requiring retrospective application of the new standard with restatement of prior years and one requiring prospective application of the new standard including a cumulative-effect adjustment with disclosure of results under old standards. As such, at IDACORP's and Idaho Power's required adoption date of January 1, 2018, amounts in 2016 and 2017 may have to be revised. IDACORP and Idaho Power are ~~currently~~ evaluating the impact of ASU 2014-09 on their financial statements.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

IDACORP is exposed to market risks, including changes in interest rates, changes in commodity prices, credit risk, and equity price risk. The following discussion summarizes material changes in these risks since December 31, 2014 and the financial instruments, derivative instruments, and derivative commodity instruments sensitive to changes in interest rates, commodity prices, and equity prices that were held at June 30, ~~2014~~2015. 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 June 30, ~~2014~~2015, IDACORP had ~~$61.3~~$41.1 million in net floating rate debt. The fair market value of this debt was ~~$61.3~~$41.1 million. Assuming no change in financial structure, if variable interest rates were to average one percentage point higher than the average rate on June 30, ~~2014~~,2015, annual interest expense would increase and pre-tax earnings would decrease by approximately ~~$0.6~~$0.4 million.

Fixed Rate Debt: As of June 30, ~~2014~~2015, IDACORP had ~~$1.6~~$1.7 billion in fixed rate debt, with a fair market value ~~equal to $1.7~~of approximately $1.8 billion. These instruments are fixed rate and, therefore, do not expose the companies to a loss in earnings due to changes in market interest rates. However, the fair value of these instruments would increase by approximately ~~$203~~$246 million if market interest rates were to decline by one percentage point from their June 30, ~~2014~~2015 levels.

Commodity Price Risk

IDACORP's exposure to changes in commodity prices is related to Idaho Power's ongoing utility operations that produce electricity to meet the demand of its retail electric customers. These changes in commodity prices are mitigated in large part by Idaho Power's Idaho and Oregon PCA mechanisms. To supplement its generation resources and balance its supply of power with the demand of its retail customers, Idaho Power participates in the wholesale marketplace. IDACORP’s commodity price risk as of June 30, ~~2014~~2015 had not changed materially from that reported in Item 7A of IDACORP's Annual Report on Form 10-K for the year ended December 31, ~~2013~~2014. Information regarding Idaho Power’s use of derivative instruments to manage commodity price risk can be found in Note 11 – “Derivative Financial Instruments” to the condensed consolidated financial statements included in this report.

Credit Risk

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

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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 June 30, ~~2014~~2015, Idaho Power had posted ~~$1.7~~$0.8 million of performance assurance collateral. Should Idaho Power experience a reduction in its credit rating on Idaho Power's unsecured debt to below investment grade Idaho Power could be subject to requests by its wholesale counterparties to post additional performance assurance collateral. Counterparties to derivative instruments and other forward contracts could request immediate payment or demand immediate ongoing full daily collateralization on derivative instruments and contracts in net liability positions. Based upon Idaho Power's energy and fuel portfolio and market conditions as of June 30, ~~2014~~2015, the amount of collateral that could be requested upon a downgrade to below investment grade was approximately ~~$10.6~~$16.0 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 June 30, ~~2014~~2015 had not changed materially from that reported in Item 7A of IDACORP's Annual Report on Form 10-K for the year ended December 31, ~~2013~~2014. Additional information regarding Idaho Power’s management of credit risk and credit contingent features can be found in Note 11 – “Derivative Financial Instruments” to the condensed consolidated financial statements included in this report.

Equity Price Risk

IDACORP is exposed to price fluctuations in equity markets, primarily through Idaho Power's defined benefit pension plan assets, a mine reclamation trust fund owned by an equity-method investment of Idaho Power, and other equity security investments at Idaho Power. The equity securities held by the pension plan and in such accounts are diversified to achieve broad market participation and reduce the impact of any single investment, sector, or geographic region. Idaho Power has established asset allocation targets for the pension plan holdings, which are described in Note 10 - "Benefit Plans" to the ~~notes to the~~ consolidated financial statements included in IDACORP's Annual Report on Form 10-K for the year ended December 31, ~~2013~~2014. IDACORP’s equity price risk as of June 30, ~~2014~~2015 had not changed materially from that reported in Item 7A of IDACORP's Annual Report on Form 10-K for the year ended December 31, ~~2013~~2014.

ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

IDACORP: The Chief Executive Officer and the Chief Financial Officer of IDACORP, based on their evaluation of IDACORP’s disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of June 30, ~~2014~~2015, have concluded that IDACORP’s disclosure controls and procedures are effective as of that date.

Idaho Power: The Chief Executive Officer and the Chief Financial Officer of Idaho Power, based on their evaluation of Idaho Power’s disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of June 30, ~~2014~~2015, have concluded that Idaho Power’s disclosure controls and procedures are effective as of that date.

Changes in Internal Control over Financial Reporting

There have been no changes in IDACORP’s or Idaho Power’s internal control over financial reporting during the quarter ended June 30, ~~2014~~2015, that have materially affected, or are reasonably likely to materially affect, IDACORP’s or Idaho Power’s internal control over financial reporting.

PART II – OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Refer to Note 89 - “Contingencies” to the condensed consolidated financial statements included in this report for information regarding certain legal and administrative proceedings in which the registrants are involved.

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ITEM 1A. RISK FACTORS

The factors discussed in Part I - Item 1A - “Risk Factors” in IDACORP’s and Idaho Power’s Annual Report on Form 10-K for the year ended December 31, ~~2013~~2014, could materially affect IDACORP’s and Idaho Power’s business, financial condition, or future results. In addition to those risk factors and other risks discussed in this report, see ~~"Forward-Looking~~"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.

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Issuer Purchases of Equity Securities

During the quarter ended June 30, ~~2014~~,2015, 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
April 1, 2014 - April 30, 2014 4,667
$ 56.14
—
—
May 1, 2014 - May 31, 2014 —
—
—
—
June 1, 2014 - June 30, 2014 184
57.83
—
—
Total 4,851
$ 56.20
—
—



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
April 1, 2015 - April 30, 2015	—	$	—	—	—
May 1, 2015 - May 31, 2015	501	59.47		—	—
June 1, 2015 - June 30, 2015	449	56.14		—	—
Total	950	$	57.90	—	—

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

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

~~None.~~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.~~None

ITEM 6. EXHIBITS

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

6058

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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:	July ~~31, 2014~~30, 2015	By:	/s/ Darrel T. Anderson
			Darrel T. Anderson
			President and Chief Executive Officer

Date:	July ~~31, 2014~~30, 2015	By:	/s/ Steven R. Keen
			Steven R. Keen
			Senior Vice President, Chief Financial
			Officer, and Treasurer





		IDAHO POWER COMPANY
		(Registrant)



Date:	July ~~31, 2014~~30, 2015	By:	/s/ Darrel T. Anderson
			Darrel T. Anderson
			President and Chief Executive Officer

Date:	July ~~31, 2014~~30, 2015	By:	/s/ Steven R. Keen
			Steven R. Keen
			Senior Vice President, Chief Financial
			Officer, and Treasurer

6159

Table of ~~contents~~Contents

EXHIBIT INDEX

The following exhibits are filed or furnished, as applicable, with the Quarterly Report on Form 10-Q for the quarter ended June 30, ~~2014~~:2015:



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

~~10.65~~	~~Fourth Amendment to the Employee Savings Plan of Idaho Power Company, dated June 16, 2014~~					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
~~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



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

10.1	First Amendment to Second Amended and Restated Credit Agreement, dated July 9, 2015, among IDACORP, Inc., Wells Fargo Bank, National Association, and the lenders a party thereto, amending the Second Amended and Restated Credit Agreement, dated October 26, 2011, among IDACORP, Inc., various lenders, Wells Fargo Bank, National Association, as administrative agent, swingline lender, and LC issuer, JPMorgan Chase Bank, N.A., as syndication agent and LC issuer, KeyBank National Association and Union Bank, N.A., as documentation agents, and Wells Fargo Securities, LLC, J.P. Morgan Securities Inc., Keybanc Capital Markets, and Union Bank, N.A. as joint lead arrangers and joint book runners	8-K	1-14465; 1-3198	10.1	7/10/2015
10.2	First Amendment to Second Amended and Restated Credit Agreement, dated July 9, 2015, among Idaho Power Company, Wells Fargo Bank, National Association, and the lenders a party thereto, amending the Second Amended and Restated Credit Agreement, dated October 26, 2011, among Idaho Power Company, various lenders, Wells Fargo Bank, National Association, as administrative agent, swingline lender, and LC issuer, JPMorgan Chase Bank, N.A., as syndication agent and LC issuer, KeyBank National Association and Union Bank, N.A., as documentation agents, and Wells Fargo Securities, LLC, J.P. Morgan Securities Inc., Keybanc Capital Markets, and Union Bank, N.A. as joint lead arrangers and joint book runners	8-K	1-14465; 1-3198	10.2	7/10/2015
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

6260



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



	June 30, 2014						December 31, 2013
	Gross Unrealized Gain		Gross Unrealized Loss		Fair Value		Gross Unrealized Gain		Gross Unrealized Loss		Fair Value
Available-for-sale securities	$	—	$	—	$	43,240	$	—	$	—	$	41,119