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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

☒

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES

EXCHANGE ACT OF 1934

For the quarterly period ended

June 30, ~~2021~~2022

☐

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.

Securities registered pursuant to Section 12(b) of the ~~Securities Exchange Act of 1934~~Act:


Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Stock	IDA	New York Stock Exchange

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 every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrants were required to submit such files).

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

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

IDACORP, Inc.:

Large accelerated filer X Accelerated filer __ Non-accelerated filer __

Smaller reporting company ☐

Emerging growth company ☐

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

Act. __

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Idaho Power Company:

Large accelerated filer __ Accelerated filer __ Non-accelerated Filer X

Smaller reporting company ☐

Emerging growth company ☐

Act. __

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 ~~23, 2021:~~29, 2022:

IDACORP, Inc.: ~~50,516,384~~50,560,040

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

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

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

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TABLE OF CONTENTS
				Page
Commonly Used Terms				4
Cautionary Note Regarding Forward-Looking Statements				5

Part I. Financial Information

	Item 1. Financial Statements (unaudited)
		IDACORP, Inc.:
			Condensed Consolidated Statements of Income	7
			Condensed Consolidated Statements of Comprehensive Income	8
			Condensed Consolidated Balance Sheets	9
			Condensed Consolidated Statements of Cash Flows	11
			Condensed Consolidated Statements of Equity	12
		Idaho Power Company:
			Condensed Consolidated Statements of Income	13
			Condensed Consolidated Statements of Comprehensive Income	14
			Condensed Consolidated Balance Sheets	15
			Condensed Consolidated Statements of Cash Flows	17
		Notes to Condensed Consolidated Financial Statements		18
		Reports of Independent Registered Public Accounting Firm - Deloitte & Touche LLP		3233
	Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations			3435
	Item 3. Quantitative and Qualitative Disclosures About Market Risk			5863
	Item 4. Controls and Procedures			5965

Part II. Other Information

	Item 1. Legal Proceedings			6066
	Item 1A. Risk Factors			6066
	Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			6066
	Item 3. Defaults Upon Senior Securities			6066
	Item 4. Mine Safety Disclosures			6066
	Item 5. Other Information			6066
	Item 6. Exhibits			6167

Signatures				6268

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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:

~~2020~~2021 Annual Report	-	IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, ~~2020~~2021
ADITC	-	Accumulated Deferred Investment Tax Credits
AFUDC	-	Allowance for Funds Used During Construction
AOCI	-	Accumulated Other Comprehensive Income

BCC	-	Bridger Coal Company, a joint venture of IERCo
BLM	-	U.S. Bureau of Land Management
BPA	-	Bonneville Power Administration
CEQ	-	Council on Environmental Quality
CWA	-	Clean Water Act
EPA	-	U.S. Environmental Protection Agency
ESA	-
		Endangered Species Act
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
IFS	-	IDACORP Financial Services, a subsidiary of IDACORP, Inc.
IPUC	-	Idaho Public Utilities Commission
IRP	-	Integrated Resource Plan
Jim Bridger plant	-	Jim Bridger generating plant
MD&A	-	Management’s Discussion and Analysis of Financial Condition and Results of Operations
MW	-	Megawatt
MWh	-	Megawatt-hour
NAV	-	Net asset value
NEPA	-	National Environmental Policy Act
NMFS	-	National Marine Fisheries Service
O&M	-	Operations and Maintenance
OATT	-	Open Access Transmission Tariff
OPUC	-	Public Utility Commission of Oregon
PCA	-	Idaho-Jurisdiction Power Cost Adjustment
PCAOB	-	Public Company Accounting Oversight Board (United States)
PURPA	-	Public Utility Regulatory Policies Act of 1978

SEC	-	U.S. Securities and Exchange Commission
SIP	-	State Implementation Plan
SMSP	-	Security Plan for Senior Management Employees


~~Valmy~~Term Loan Facility	-	Term Loan Credit Agreement
USACE	-	U.S. Army Corps of Engineers
USFWS	-	U.S. Fish and Wildlife Service
Valmy plant	-	Idaho Power's jointly-owned coal-fired generating plant in Valmy, Nevada
Western EIM	-	Energy imbalance market ~~implemented~~ in the western United States
WMP	-	Wildfire Mitigation Plan
WOTUS	-	Waters of the United States
WPSC	-	Wyoming Public Service Commission

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

In addition to the historical information contained in this report, this report contains (and oral communications made by IDACORP, Inc. (IDACORP) and Idaho Power Company (Idaho Power) may contain) statements that relate to future events and expectations, such as statements regarding projected or future financial performance, cash flows, capital expenditures, dividends, capital structure or ratios, strategic goals, challenges, objectives, and plans for future operations. Such statements constitute forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Any statements that express, or involve discussions as to, expectations, beliefs, plans, objectives, assumptions, or future events or performance, often, but not always, through the use of words or phrases such as "anticipates," "believes," ~~"continues,"~~ "could," "estimates," "expects," "guidance," "intends," "potential," "plans," "predicts," "projects," "may," "may result," "may continue," or similar expressions, are not statements of historical facts and may be forward-looking. Forward-looking statements are not guarantees of future performance and involve estimates, assumptions, risks, and ~~uncertainties. Actual results, performance, or outcomes~~uncertainties that may differ materially from ~~the~~actual results, ~~discussed in the statements.~~performance, or outcomes. 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, ~~2020,~~2021, particularly Part I, Item 1A - "Risk Factors" and Part II, Item 7 - "Management’s Discussion and Analysis of Financial Condition and Results of Operations" of that report, subsequent reports filed by IDACORP and Idaho Power with the U.S. Securities and Exchange Commission (SEC), and the following important factors:

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

•changes to or the elimination of Idaho Power's regulatory cost recovery mechanisms;

•~~the~~ impacts of ~~the COVID-19 pandemic,~~economic conditions, including ~~COVID-19 variants,~~an inflationary or recessionary environment and increasing interest rates, on ~~the global~~operations and ~~regional economy~~capital investments, supply costs and ondelays, supply scarcity and shortages, population growth or decline in Idaho Power's ~~employees, customers, contractors,~~service area, changes in customer demand for electricity, revenue from sales of excess power, credit quality of counterparties and suppliers, ~~including on loads~~ and ~~revenues, uncollectible accounts, transmission revenues, and other aspects~~collection of ~~the companies' business;~~receivables;

•changes in residential, commercial, and industrial growth and demographic patterns within Idaho Power's service area, and ~~their~~the associated impacts on loads and load growth, and the availability of regulatory mechanisms that allow for timely cost recovery of those changes through customer ~~rates in the event of those changes;~~rates;

•abnormal or severe weather conditions (including conditions and events associated with climate change), wildfires, droughts, earthquakes, and other natural phenomena and natural disasters, which affect customer sales, hydropower generation levels, repair costs, service interruptions, liability for damage caused by utility property, and the availability and cost of fuel for generation plants or purchased power to serve customers;

•advancement of self-generation, energy storage, energy efficiency, alternative energy sources, and other technologies that may reduce Idaho Power's sale or delivery of electric power or ~~introduction of~~introduce operational or cyber-security vulnerabilities to the power grid;

•acts or threats of terrorist incidents, acts of war, social unrest, cyber-attacks, the companies' failure to secure data or to comply with privacy laws or regulations, physical security breaches, or the disruption or damage to the companies' business, operations, or reputation resulting from such events;

•~~the~~ expense and risks associated with capital expenditures for, and the permitting and construction of, utility infrastructure that Idaho Power may be unable to complete or that may not be deemed prudent by regulators for cost ~~recovery;~~recovery or a return on investment;

•power demand exceeding supply, resulting in increased costs for purchasing energy and capacity in the market, if available, or acquiring or constructing additional generation resources and battery storage facilities;

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

•~~the~~Idaho Power's ability ~~of Idaho Power~~ to acquire fuel, power, electrical equipment, and transmission capacity on reasonable terms and prices, particularly in the event of unanticipated or abnormally high ~~power~~resource demands, price volatility, lack of physical availability, transportation constraints, ~~disruptions~~outages due to maintenance or ~~delays~~repairs to generation or transmission facilities, disruptions in the supply chain, or credit quality or a lack of ~~credit;~~credit of counterparties and suppliers;

•disruptions or outages of Idaho Power's generation or transmission systems or of any interconnected transmission systems, which can result in liability for Idaho Power, increase power supply costs and repair expenses, and reduce revenues;

•accidents, ~~terrorist acts,~~electrical contacts, fires (either affecting or caused by Idaho Power facilities or infrastructure), explosions, ~~mechanical breakdowns,~~infrastructure failures, general system damage or dysfunction, and other unplanned events that may occur while operating and maintaining assets, which can cause unplanned outages; reduce generating ~~output;~~output, damage company assets, operations, or reputation; subject Idaho Power to third-party claims for property damage, personal injury, or ~~loss of life; or result in the imposition of civil, criminal, and regulatory fines and penalties for which Idaho Power may have inadequate insurance coverage;~~

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loss of life; or result in the imposition of fines and penalties for which Idaho Power may have inadequate insurance coverage;

•acts or threats of terrorist incidents, acts of war, social unrest, cyber or physical security attacks, and other malicious acts of individuals or groups seeking to disrupt Idaho Power's operations or the electric power grid or compromise data, or the disruption or damage to the companies’ business, operations, or reputation resulting from such events;

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

•ongoing impacts of COVID-19 and its variants, and government mandates related to COVID-19 vaccines, masking, and testing, on the global and regional economy and on Idaho Power’s employees, customers, contractors, and suppliers, including on loads and revenues, uncollectible accounts, transmission revenues, supply chain availability, attrition of skilled workers, and other aspects of the economy and the companies’ business;

•Idaho Power’s concentration in one industry and one region, and the resulting exposure to regional economic conditions and regional legislation and regulation;

•employee workforce factors, including the operational and financial costs of unionization or the attempt to unionize all or part of the companies’ workforce, the cost and ability to attract and retain skilled workers and third-party contractors, the cost of living and the related impact on recruiting employees, and the ability to adjust to fluctuations in labor costs;

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

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

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

•~~the~~ inability to timely obtain orand the cost of obtaining and complying with required governmental permits and approvals, licenses, rights-of-way, and siting for transmission and generation projects and hydropower facilities;

•failure to comply with mandatory reliability and cyber and physical security requirements, which may result in penalties, reputational harm, and operational changes;

•the impacts of economic conditions, including inflation, interest rates, supply costs, population growth or decline in Idaho Power's service area, changes in customer demand for electricity, revenue from sales of excess power, credit quality of counterparties and suppliers, and the collection of receivables;

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

•~~changes in the method for determining the London Interbank Offered Rate (LIBOR) and the replacement of LIBOR and the impact on interest rates for IDACORP's and Idaho Power's credit facilities;~~

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

•changes in actuarial assumptions, changes in interest rates, increasing health care costs, and the actual and projected 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 and the companies' cash flows;

•~~the~~ assumptions underlying the coal mine reclamation obligations at Bridger Coal Company and related funding and bonding requirements, and the remediation costs associated with planned exits from participation in Idaho Power's co-owned coal plants;

•~~the~~ ability to continue to pay dividends and achieve ~~target-payout~~target dividend payout ratios based on financial performance, and in light of credit rating considerations, contractual covenants and restrictions, and regulatory limitations;

•Idaho Power's concentration in one industry and one region and the resulting lack of diversification, and the resulting exposure to regional economic conditions and regional legislation and regulation;

•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 attract and retain skilled workers and third-party vendors, and the ability to adjust the labor cost structure when necessary; and

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

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,
		2021		2020		2021		2020			2022		2021		2022		2021
		(in thousands, except per share amounts)				(in thousands, except per share amounts)					(in thousands, except per share amounts)				(in thousands, except per share amounts)
Operating Revenues:	Operating Revenues:									Operating Revenues:
Electric utility revenues	Electric utility revenues	$	359,058	$	317,666	$	674,625	$	608,154	Electric utility revenues	$	357,668	$	359,058	$	701,589	$	674,625
Other	Other	1,016		1,100		1,502		1,620		Other	1,055		1,016		1,422		1,502
Total operating revenues	Total operating revenues	360,074		318,766		676,127		609,774		Total operating revenues	358,723		360,074		703,011		676,127

Operating Expenses:	Operating Expenses:									Operating Expenses:
Electric utility:	Electric utility:									Electric utility:
Purchased power	Purchased power	96,116		61,774		164,104		122,975		Purchased power	91,727		96,116		177,151		164,104
Fuel expense	Fuel expense	31,191		31,414		64,496		61,430		Fuel expense	34,417		31,191		80,119		64,496
Power cost adjustment	Power cost adjustment	(7,934)		(1,536)		(2,263)		(4,927)		Power cost adjustment	(426)		(7,934)		(825)		(2,263)
Other operations and maintenance	Other operations and maintenance	88,490		83,144		174,148		172,951		Other operations and maintenance	100,556		88,490		192,642		174,148
Energy efficiency programs	Energy efficiency programs	6,658		11,953		15,685		21,428		Energy efficiency programs	6,609		6,658		13,198		15,685
Depreciation	Depreciation	43,627		42,914		86,942		85,440		Depreciation	34,830		43,627		79,287		86,942
Other electric utility operating expenses	Other electric utility operating expenses	9,007		9,151		18,333		18,292		Other electric utility operating expenses	8,865		9,007		17,765		18,333
Total electric utility operating expenses	Total electric utility operating expenses	267,155		238,814		521,445		477,589		Total electric utility operating expenses	276,578		267,155		559,337		521,445
Other	Other	515		512		1,170		1,176		Other	639		515		1,500		1,170
Total operating expenses	Total operating expenses	267,670		239,326		522,615		478,765		Total operating expenses	277,217		267,670		560,837		522,615

Operating Income	Operating Income	92,404		79,440		153,512		131,009		Operating Income	81,506		92,404		142,174		153,512

Nonoperating (Income) Expense:	Nonoperating (Income) Expense:									Nonoperating (Income) Expense:
Allowance for equity funds used during construction	Allowance for equity funds used during construction	(7,795)		(7,149)		(15,564)		(14,421)		Allowance for equity funds used during construction	(9,287)		(7,795)		(18,410)		(15,564)
Earnings of unconsolidated equity-method investments	Earnings of unconsolidated equity-method investments	(2,313)		(2,687)		(4,630)		(5,003)		Earnings of unconsolidated equity-method investments	(2,288)		(2,313)		(4,596)		(4,630)
Interest on long-term debt	Interest on long-term debt	21,036		22,056		42,073		41,718		Interest on long-term debt	21,374		21,036		42,443		42,073
Other interest	Other interest	3,611		3,557		7,130		7,369		Other interest	3,860		3,611		7,675		7,130
Allowance for borrowed funds used during construction	Allowance for borrowed funds used during construction	(3,019)		(2,886)		(6,025)		(5,616)		Allowance for borrowed funds used during construction	(3,481)		(3,019)		(6,865)		(6,025)
Other income, net	Other income, net	(460)		(1,043)		(702)		(1,976)		Other income, net	(1,551)		(460)		(3,163)		(702)
Total nonoperating expense, net	Total nonoperating expense, net	11,060		11,848		22,282		22,071		Total nonoperating expense, net	8,627		11,060		17,084		22,282

Income Before Income Taxes	Income Before Income Taxes	81,344		67,592		131,230		108,938		Income Before Income Taxes	72,879		81,344		125,090		131,230

Income Tax Expense	Income Tax Expense	11,070		6,933		16,156		10,821		Income Tax Expense	8,291		11,070		14,317		16,156

Net Income	Net Income	70,274		60,659		115,074		98,117		Net Income	64,588		70,274		110,773		115,074
Income attributable to noncontrolling interests	Income attributable to noncontrolling interests	(251)		(270)		(220)		(238)		Income attributable to noncontrolling interests	(301)		(251)		(225)		(220)
Net Income Attributable to IDACORP, Inc.	Net Income Attributable to IDACORP, Inc.	$	70,023	$	60,389	$	114,854	$	97,879	Net Income Attributable to IDACORP, Inc.	$	64,287	$	70,023	$	110,548	$	114,854

Weighted Average Common Shares Outstanding - Basic	Weighted Average Common Shares Outstanding - Basic	50,609		50,551		50,588		50,534		Weighted Average Common Shares Outstanding - Basic	50,668		50,609		50,650		50,588
Weighted Average Common Shares Outstanding - Diluted	Weighted Average Common Shares Outstanding - Diluted	50,622		50,567		50,601		50,547		Weighted Average Common Shares Outstanding - Diluted	50,687		50,622		50,673		50,601
Earnings Per Share of Common Stock:	Earnings Per Share of Common Stock:									Earnings Per Share of Common Stock:
Earnings Attributable to IDACORP, Inc. - Basic	Earnings Attributable to IDACORP, Inc. - Basic	$	1.38	$	1.19	$	2.27	$	1.94	Earnings Attributable to IDACORP, Inc. - Basic	$	1.27	$	1.38	$	2.18	$	2.27
Earnings Attributable to IDACORP, Inc. - Diluted	Earnings Attributable to IDACORP, Inc. - Diluted	$	1.38	$	1.19	$	2.27	$	1.94	Earnings Attributable to IDACORP, Inc. - Diluted	$	1.27	$	1.38	$	2.18	$	2.27

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,
		2021		2020		2021		2020			2022		2021		2022		2021
		(in thousands)				(in thousands)					(in thousands)				(in thousands)

Net Income	Net Income	$	70,274	$	60,659	$	115,074	$	98,117	Net Income	$	64,588	$	70,274	$	110,773	$	115,074
Other Comprehensive Income:	Other Comprehensive Income:									Other Comprehensive Income:

Unfunded pension liability adjustment, net of tax of $290, $259, $579, and $518, respectively		836		747		1,672		1,494
Unfunded pension liability adjustment, net of tax of $290, $290, $580, and $579, respectively										Unfunded pension liability adjustment, net of tax of $290, $290, $580, and $579, respectively	837		836		1,674		1,672
Total Comprehensive Income	Total Comprehensive Income	71,110		61,406		116,746		99,611		Total Comprehensive Income	65,425		71,110		112,447		116,746
Income attributable to noncontrolling interests	Income attributable to noncontrolling interests	(251)		(270)		(220)		(238)		Income attributable to noncontrolling interests	(301)		(251)		(225)		(220)
Comprehensive Income Attributable to IDACORP, Inc.	Comprehensive Income Attributable to IDACORP, Inc.	$	70,859	$	61,136	$	116,526	$	99,373	Comprehensive Income Attributable to IDACORP, Inc.	$	65,124	$	70,859	$	112,222	$	116,526

The accompanying notes are an integral part of these statements.

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IDACORP, Inc.

Condensed Consolidated Balance Sheets

(unaudited)


		June 30, 2021		December 31, 2020			June 30, 2022		December 31, 2021
		(in thousands)					(in thousands)
Assets	Assets					Assets

Current Assets:	Current Assets:					Current Assets:
Cash and cash equivalents	Cash and cash equivalents	$	259,965	$	275,116	Cash and cash equivalents	$	237,886	$	215,243
Short-term investments	Short-term investments	0		25,000		Short-term investments	25,000		—
Receivables:	Receivables:					Receivables:
Customer (net of allowance of $4,252 and $4,766, respectively)		84,542		72,826
Other (net of allowance of $581 and $497, respectively)		16,659		12,661
Customer (net of allowance of $3,921 and $4,499, respectively)						Customer (net of allowance of $3,921 and $4,499, respectively)	90,604		78,819
Other (net of allowance of $441 and $517, respectively)						Other (net of allowance of $441 and $517, respectively)	13,012		14,994
Income taxes receivable	Income taxes receivable	0		2,164		Income taxes receivable	—		14,770
Accrued unbilled revenues	Accrued unbilled revenues	108,913		72,461		Accrued unbilled revenues	94,757		74,843
Materials and supplies (at average cost)	Materials and supplies (at average cost)	70,248		64,941		Materials and supplies (at average cost)	78,715		77,552
Fuel stock (at average cost)	Fuel stock (at average cost)	37,600		31,646		Fuel stock (at average cost)	16,023		18,045
Prepayments	Prepayments	20,451		20,184		Prepayments	23,301		24,676
Current regulatory assets	Current regulatory assets	61,896		63,407		Current regulatory assets	98,550		71,223
Other	Other	12,705		1,995		Other	15,496		5,708
Total current assets	Total current assets	672,979		642,401		Total current assets	693,344		595,873
Investments	Investments	129,000		126,948		Investments	114,048		123,824
Property, Plant and Equipment:	Property, Plant and Equipment:					Property, Plant and Equipment:
Utility plant in service	Utility plant in service	6,392,964		6,283,790		Utility plant in service	6,680,494		6,509,316
Accumulated provision for depreciation	Accumulated provision for depreciation	(2,236,478)		(2,193,831)		Accumulated provision for depreciation	(2,395,644)		(2,298,951)
Utility plant in service - net	Utility plant in service - net	4,156,486		4,089,959		Utility plant in service - net	4,284,850		4,210,365
Construction work in progress	Construction work in progress	600,800		597,152		Construction work in progress	708,529		670,585
Utility plant held for future use	Utility plant held for future use	4,035		4,109		Utility plant held for future use	4,089		4,511
Other property, net of accumulated depreciation	Other property, net of accumulated depreciation	16,576		18,290		Other property, net of accumulated depreciation	16,983		16,361
Property, plant and equipment - net	Property, plant and equipment - net	4,777,897		4,709,510		Property, plant and equipment - net	5,014,451		4,901,822
Other Assets:	Other Assets:					Other Assets:
Company-owned life insurance	Company-owned life insurance	64,533		62,382		Company-owned life insurance	70,180		67,343
Regulatory assets	Regulatory assets	1,495,961		1,495,488		Regulatory assets	1,496,817		1,462,431

Other	Other	61,088		58,515		Other	63,256		59,222
Total other assets	Total other assets	1,621,582		1,616,385		Total other assets	1,630,253		1,588,996
Total	Total	$	7,201,458	$	7,095,244	Total	$	7,452,096	$	7,210,515

The accompanying notes are an integral part of these statements.

Table of Contents

IDACORP, Inc.

Condensed Consolidated Balance Sheets

(unaudited)


		June 30, 2021		December 31, 2020			June 30, 2022		December 31, 2021
		(in thousands)					(in thousands)
Liabilities and Equity	Liabilities and Equity					Liabilities and Equity

Current Liabilities:	Current Liabilities:					Current Liabilities:

Current maturities of long-term debt						Current maturities of long-term debt	$	75,000	$	—

Accounts payable	Accounts payable	$	122,834	$	120,576	Accounts payable	152,569		145,980
Taxes accrued	Taxes accrued	43,073		19,508		Taxes accrued	30,712		14,229
Interest accrued	Interest accrued	23,944		24,030		Interest accrued	23,924		23,959
Accrued compensation	Accrued compensation	43,302		52,245		Accrued compensation	49,236		55,666
Current regulatory liabilities	Current regulatory liabilities	26,899		11,104		Current regulatory liabilities	20,101		11,239
Advances from customers	Advances from customers	41,544		29,341		Advances from customers	67,400		43,472
Other	Other	29,545		30,767		Other	30,038		31,079
Total current liabilities	Total current liabilities	331,141		287,571		Total current liabilities	448,980		325,624
Other Liabilities:	Other Liabilities:					Other Liabilities:
Deferred income taxes	Deferred income taxes	789,215		800,251		Deferred income taxes	828,758		842,375
Regulatory liabilities	Regulatory liabilities	768,416		757,730		Regulatory liabilities	794,753		781,695
Pension and other postretirement benefits	Pension and other postretirement benefits	638,455		634,070		Pension and other postretirement benefits	521,963		521,462
Other	Other	60,597		48,752		Other	68,114		63,485
Total other liabilities	Total other liabilities	2,256,683		2,240,803		Total other liabilities	2,213,588		2,209,017
Long-Term Debt	Long-Term Debt	2,000,527		2,000,414		Long-Term Debt	2,075,698		2,000,640
Commitments and Contingencies	Commitments and Contingencies	0		0		Commitments and Contingencies	0		0
Equity:	Equity:					Equity:
IDACORP, Inc. shareholders’ equity:	IDACORP, Inc. shareholders’ equity:					IDACORP, Inc. shareholders’ equity:
Common stock, no par value (120,000 shares authorized; 50,516 and 50,462 shares issued, respectively)		871,111		869,235
Common stock, no par value (120,000 shares authorized; 50,560 and 50,516 shares issued, respectively)						Common stock, no par value (120,000 shares authorized; 50,560 and 50,516 shares issued, respectively)	877,362		874,896
Retained earnings	Retained earnings	1,776,986		1,734,103		Retained earnings	1,867,811		1,833,580
Accumulated other comprehensive loss	Accumulated other comprehensive loss	(41,686)		(43,358)		Accumulated other comprehensive loss	(38,366)		(40,040)

Total IDACORP, Inc. shareholders’ equity	Total IDACORP, Inc. shareholders’ equity	2,606,411		2,559,980		Total IDACORP, Inc. shareholders’ equity	2,706,807		2,668,436
Noncontrolling interests	Noncontrolling interests	6,696		6,476		Noncontrolling interests	7,023		6,798
Total equity	Total equity	2,613,107		2,566,456		Total equity	2,713,830		2,675,234
Total	Total	$	7,201,458	$	7,095,244	Total	$	7,452,096	$	7,210,515

The accompanying notes are an integral part of these statements.	The accompanying notes are an integral part of these statements.					The accompanying notes are an integral part of these statements.

Table of Contents

IDACORP, Inc.

Condensed Consolidated Statements of Cash Flows

(unaudited)


		Six months ended June 30,					Six months ended June 30,
		2021		2020			2022		2021
		(in thousands)					(in thousands)
Operating Activities:	Operating Activities:					Operating Activities:
Net income	Net income	$	115,074	$	98,117	Net income	$	110,773	$	115,074
Adjustments to reconcile net income to net cash provided by operating activities:	Adjustments to reconcile net income to net cash provided by operating activities:					Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	Depreciation and amortization	88,889		87,764		Depreciation and amortization	81,351		88,889
Deferred income taxes and investment tax credits	Deferred income taxes and investment tax credits	(6,169)		(2,121)		Deferred income taxes and investment tax credits	(16,953)		(6,169)
Changes in regulatory assets and liabilities	Changes in regulatory assets and liabilities	9,311		(11,831)		Changes in regulatory assets and liabilities	8,658		9,311
Pension and postretirement benefit plan expense	Pension and postretirement benefit plan expense	14,534		14,478		Pension and postretirement benefit plan expense	14,484		14,534
Contributions to pension and postretirement benefit plans	Contributions to pension and postretirement benefit plans	(11,957)		(13,219)		Contributions to pension and postretirement benefit plans	(12,122)		(11,957)
Earnings of equity-method investments	Earnings of equity-method investments	(4,630)		(5,003)		Earnings of equity-method investments	(4,596)		(4,630)
Distributions from equity-method investments	Distributions from equity-method investments	4,100		0		Distributions from equity-method investments	4,265		4,100
Allowance for equity funds used during construction	Allowance for equity funds used during construction	(15,564)		(14,421)		Allowance for equity funds used during construction	(18,410)		(15,564)
Other non-cash adjustments to net income, net	Other non-cash adjustments to net income, net	4,428		5,989		Other non-cash adjustments to net income, net	5,953		4,428
Change in:	Change in:					Change in:
Receivables	Receivables	(15,241)		(8,943)		Receivables	(13,045)		(15,241)
Accounts payable and other accrued liabilities	Accounts payable and other accrued liabilities	2,620		(30,008)		Accounts payable and other accrued liabilities	(23,439)		2,620
Taxes accrued/receivable	Taxes accrued/receivable	25,728		20,179		Taxes accrued/receivable	31,253		25,728
Other current assets	Other current assets	(48,206)		(23,889)		Other current assets	(17,044)		(48,206)
Other current liabilities	Other current liabilities	5,658		13,076		Other current liabilities	7,882		5,658
Other assets	Other assets	(3,285)		(1,420)		Other assets	(7,590)		(3,285)
Other liabilities	Other liabilities	1,905		(135)		Other liabilities	4,535		1,905
Net cash provided by operating activities	Net cash provided by operating activities	167,195		128,613		Net cash provided by operating activities	155,955		167,195
Investing Activities:	Investing Activities:					Investing Activities:
Additions to property, plant and equipment	Additions to property, plant and equipment	(128,265)		(145,116)		Additions to property, plant and equipment	(194,094)		(128,265)
Payments received from transmission project joint funding partners	Payments received from transmission project joint funding partners	2,253		1,728		Payments received from transmission project joint funding partners	5,531		2,253

Investments in affordable housing and other tax credits		(10,164)		(9,394)
Investments in affordable housing and other real estate tax credits projects						Investments in affordable housing and other real estate tax credits projects	(2,665)		(10,164)

Investments in unconsolidated affiliates		0		(2,300)

Distributions from equity-method investments, return of investment						Distributions from equity-method investments, return of investment	10,335		—
Purchases of equity securities	Purchases of equity securities	(392)		(3,326)		Purchases of equity securities	(27,942)		(392)
Purchases of held-to-maturity securities						Purchases of held-to-maturity securities	(29,692)		—
Proceeds from the sale of equity securities						Proceeds from the sale of equity securities	52,833		3,197
Purchases of short-term investments	Purchases of short-term investments	(25,000)		0		Purchases of short-term investments	(25,000)		(25,000)
Maturities of short-term investments	Maturities of short-term investments	50,000		0		Maturities of short-term investments	—		50,000
Proceeds from the sale of equity securities		3,197		2,630

Other	Other	1,347		4,941		Other	6,767		1,347
Net cash used in investing activities	Net cash used in investing activities	(107,024)		(150,837)		Net cash used in investing activities	(203,927)		(107,024)
Financing Activities:	Financing Activities:					Financing Activities:
Issuance of long-term debt	Issuance of long-term debt	0		310,000		Issuance of long-term debt	150,000		—
Premium on issuance of long-term debt		0		31,384

Dividends on common stock	Dividends on common stock	(72,285)		(68,160)		Dividends on common stock	(76,339)		(72,285)

Tax withholdings on net settlements of share-based awards	Tax withholdings on net settlements of share-based awards	(3,026)		(4,630)		Tax withholdings on net settlements of share-based awards	(2,958)		(3,026)

Debt issuance costs and other	Debt issuance costs and other	(11)		(3,259)		Debt issuance costs and other	(88)		(11)
Net cash (used in) provided by financing activities		(75,322)		265,335
Net (decrease) increase in cash and cash equivalents		(15,151)		243,111
Net cash provided by (used in) financing activities						Net cash provided by (used in) financing activities	70,615		(75,322)
Net increase (decrease) in cash and cash equivalents						Net increase (decrease) in cash and cash equivalents	22,643		(15,151)
Cash and cash equivalents at beginning of the period	Cash and cash equivalents at beginning of the period	275,116		217,254		Cash and cash equivalents at beginning of the period	215,243		275,116
Cash and cash equivalents at end of the period	Cash and cash equivalents at end of the period	$	259,965	$	460,365	Cash and cash equivalents at end of the period	$	237,886	$	259,965
Supplemental Disclosure of Cash Flow Information:	Supplemental Disclosure of Cash Flow Information:					Supplemental Disclosure of Cash Flow Information:
Cash paid during the period for:	Cash paid during the period for:					Cash paid during the period for:
Income taxes	Income taxes	$	2,880	$	325	Income taxes	$	6,265	$	2,880
Interest (net of amount capitalized)	Interest (net of amount capitalized)	$	41,626	$	38,303	Interest (net of amount capitalized)	$	41,657	$	41,626
Non-cash investing activities:	Non-cash investing activities:					Non-cash investing activities:
Additions to property, plant and equipment in accounts payable	Additions to property, plant and equipment in accounts payable	$	30,984	$	22,072	Additions to property, plant and equipment in accounts payable	$	70,063	$	30,984

The accompanying notes are an integral part of these statements.

Table of Contents

IDACORP, Inc.

Condensed Consolidated Statements of Equity

(unaudited)


		Three months ended June 30,				Six months ended June 30,					Three months ended June 30,				Six months ended June 30,
		2021		2020		2021		2020			2022		2021		2022		2021
		(in thousands)				(in thousands)					(in thousands)				(in thousands)
Common Stock	Common Stock									Common Stock
Balance at beginning of period	Balance at beginning of period	$	868,944	$	864,850	$	869,235	$	868,307	Balance at beginning of period	$	875,067	$	868,944	$	874,896	$	869,235
Share-based compensation expense	Share-based compensation expense	2,140		1,701		4,850		4,325		Share-based compensation expense	2,262		2,140		5,364		4,850
Tax withholdings on net settlements of share-based awards	Tax withholdings on net settlements of share-based awards	0		(447)		(3,026)		(4,630)		Tax withholdings on net settlements of share-based awards	—		—		(2,958)		(3,026)
Treasury shares issued		0		0		0		(1,920)

Other	Other	27		23		52		45		Other	33		27		60		52
Balance at end of period	Balance at end of period	871,111		866,127		871,111		866,127		Balance at end of period	877,362		871,111		877,362		871,111
Retained Earnings	Retained Earnings									Retained Earnings
Balance at beginning of period	Balance at beginning of period	1,742,994		1,638,065		1,734,103		1,634,525		Balance at beginning of period	1,841,644		1,742,994		1,833,580		1,734,103
Net income attributable to IDACORP, Inc.	Net income attributable to IDACORP, Inc.	70,023		60,389		114,854		97,879		Net income attributable to IDACORP, Inc.	64,287		70,023		110,548		114,854
Common stock dividends ($0.71, $0.67, $1.42, and $1.34 per share, respectively)		(36,031)		(33,986)		(71,971)		(67,936)
Common stock dividends ($0.75, $0.71, $1.50, and $1.42 per share, respectively)										Common stock dividends ($0.75, $0.71, $1.50, and $1.42 per share, respectively)	(38,120)		(36,031)		(76,317)		(71,971)
Balance at end of period	Balance at end of period	1,776,986		1,664,468		1,776,986		1,664,468		Balance at end of period	1,867,811		1,776,986		1,867,811		1,776,986
Accumulated Other Comprehensive (Loss) Income
Accumulated Other Comprehensive Loss										Accumulated Other Comprehensive Loss
Balance at beginning of period	Balance at beginning of period	(42,522)		(35,537)		(43,358)		(36,284)		Balance at beginning of period	(39,203)		(42,522)		(40,040)		(43,358)
Unfunded pension liability adjustment (net of tax)	Unfunded pension liability adjustment (net of tax)	836		747		1,672		1,494		Unfunded pension liability adjustment (net of tax)	837		836		1,674		1,672
Balance at end of period	Balance at end of period	(41,686)		(34,790)		(41,686)		(34,790)		Balance at end of period	(38,366)		(41,686)		(38,366)		(41,686)
Treasury Stock
Balance at beginning of period		0		0		0		(1,920)
Issued		0		0		0		1,920

Balance at end of period		0		0		0		0

Total IDACORP, Inc. shareholders’ equity at end of period	Total IDACORP, Inc. shareholders’ equity at end of period	2,606,411		2,495,805		2,606,411		2,495,805		Total IDACORP, Inc. shareholders’ equity at end of period	2,706,807		2,606,411		2,706,807		2,606,411
Noncontrolling Interests	Noncontrolling Interests									Noncontrolling Interests
Balance at beginning of period	Balance at beginning of period	6,445		5,893		6,476		5,925		Balance at beginning of period	6,722		6,445		6,798		6,476
Net income attributable to noncontrolling interests		251		270		220		238
Net loss attributable to noncontrolling interests										Net loss attributable to noncontrolling interests	301		251		225		220
Balance at end of period	Balance at end of period	6,696		6,163		6,696		6,163		Balance at end of period	7,023		6,696		7,023		6,696
Total equity at end of period	Total equity at end of period	$	2,613,107	$	2,501,968	$	2,613,107	$	2,501,968	Total equity at end of period	$	2,713,830	$	2,613,107	$	2,713,830	$	2,613,107

The accompanying notes are an integral part of these statements.

Table of Contents

Idaho Power Company

Condensed Consolidated Statements of Income

(unaudited)


		Three months ended June 30,				Six months ended June 30,					Three months ended June 30,				Six months ended June 30,
		2021		2020		2021		2020			2022		2021		2022		2021
		(in thousands)				(in thousands)					(in thousands)				(in thousands)

Operating Revenues	Operating Revenues	$	359,058	$	317,666	$	674,625	$	608,154	Operating Revenues	$	357,668	$	359,058	$	701,589	$	674,625

Operating Expenses:	Operating Expenses:									Operating Expenses:
Operation:	Operation:									Operation:
Purchased power	Purchased power	96,116		61,774		164,104		122,975		Purchased power	91,727		96,116		177,151		164,104
Fuel expense	Fuel expense	31,191		31,414		64,496		61,430		Fuel expense	34,417		31,191		80,119		64,496
Power cost adjustment	Power cost adjustment	(7,934)		(1,536)		(2,263)		(4,927)		Power cost adjustment	(426)		(7,934)		(825)		(2,263)
Other operations and maintenance	Other operations and maintenance	88,490		83,144		174,148		172,951		Other operations and maintenance	100,556		88,490		192,642		174,148
Energy efficiency programs	Energy efficiency programs	6,658		11,953		15,685		21,428		Energy efficiency programs	6,609		6,658		13,198		15,685
Depreciation	Depreciation	43,627		42,914		86,942		85,440		Depreciation	34,830		43,627		79,287		86,942
Other operating expenses	Other operating expenses	9,007		9,151		18,333		18,292		Other operating expenses	8,865		9,007		17,765		18,333
Total operating expenses	Total operating expenses	267,155		238,814		521,445		477,589		Total operating expenses	276,578		267,155		559,337		521,445

Operating Income	Operating Income	91,903		78,852		153,180		130,565		Operating Income	81,090		91,903		142,252		153,180

Nonoperating (Income) Expense:	Nonoperating (Income) Expense:									Nonoperating (Income) Expense:
Allowance for equity funds used during construction	Allowance for equity funds used during construction	(7,795)		(7,149)		(15,564)		(14,421)		Allowance for equity funds used during construction	(9,287)		(7,795)		(18,410)		(15,564)
Earnings of unconsolidated equity-method investments	Earnings of unconsolidated equity-method investments	(1,743)		(1,987)		(4,293)		(4,440)		Earnings of unconsolidated equity-method investments	(1,784)		(1,743)		(4,265)		(4,293)
Interest on long-term debt	Interest on long-term debt	21,036		22,056		42,073		41,718		Interest on long-term debt	21,374		21,036		42,443		42,073
Other interest	Other interest	3,606		3,544		7,120		7,357		Other interest	3,854		3,606		7,665		7,120
Allowance for borrowed funds used during construction	Allowance for borrowed funds used during construction	(3,019)		(2,886)		(6,025)		(5,616)		Allowance for borrowed funds used during construction	(3,481)		(3,019)		(6,865)		(6,025)
Other income, net	Other income, net	(423)		(841)		(613)		(1,311)		Other income, net	(1,337)		(423)		(2,978)		(613)
Total nonoperating expense, net	Total nonoperating expense, net	11,662		12,737		22,698		23,287		Total nonoperating expense, net	9,339		11,662		17,590		22,698

Income Before Income Taxes	Income Before Income Taxes	80,241		66,115		130,482		107,278		Income Before Income Taxes	71,751		80,241		124,662		130,482

Income Tax Expense	Income Tax Expense	11,419		7,192		17,291		11,578		Income Tax Expense	9,316		11,419		16,013		17,291

Net Income	Net Income	$	68,822	$	58,923	$	113,191	$	95,700	Net Income	$	62,435	$	68,822	$	108,649	$	113,191

The accompanying notes are an integral part of these statements.

Table of Contents

Idaho Power Company

Condensed Consolidated Statements of Comprehensive Income

(unaudited)


		Three months ended June 30,				Six months ended June 30,					Three months ended June 30,				Six months ended June 30,
		2021		2020		2021		2020			2022		2021		2022		2021
		(in thousands)				(in thousands)					(in thousands)				(in thousands)

Net Income	Net Income	$	68,822	$	58,923	$	113,191	$	95,700	Net Income	$	62,435	$	68,822	$	108,649	$	113,191
Other Comprehensive Income:	Other Comprehensive Income:									Other Comprehensive Income:

Unfunded pension liability adjustment, net of tax of $290, $259, $579, and $518, respectively		836		747		1,672		1,494
Unfunded pension liability adjustment, net of tax of $290, $290, $580, and $579, respectively										Unfunded pension liability adjustment, net of tax of $290, $290, $580, and $579, respectively	837		836		1,674		1,672
Total Comprehensive Income	Total Comprehensive Income	$	69,658	$	59,670	$	114,863	$	97,194	Total Comprehensive Income	$	63,272	$	69,658	$	110,323	$	114,863

The accompanying notes are an integral part of these statements.

Table of Contents

Idaho Power Company

Condensed Consolidated Balance Sheets

(unaudited)


		June 30, 2021		December 31, 2020			June 30, 2022		December 31, 2021
		(in thousands)					(in thousands)
Assets	Assets					Assets

Current Assets:	Current Assets:					Current Assets:
Cash and cash equivalents	Cash and cash equivalents	$	127,070	$	165,604	Cash and cash equivalents	$	103,607	$	60,075
Receivables:	Receivables:					Receivables:
Customer (net of allowance of $4,252 and $4,766, respectively)		84,542		72,826
Other (net of allowance of $581 and $497, respectively)		16,534		12,457
Customer (net of allowance of $3,921 and $4,499, respectively)						Customer (net of allowance of $3,921 and $4,499, respectively)	90,604		78,819
Other (net of allowance of $441 and $517, respectively)						Other (net of allowance of $441 and $517, respectively)	12,702		14,134
Income taxes receivable	Income taxes receivable	0		4,667		Income taxes receivable	—		15,328
Accrued unbilled revenues	Accrued unbilled revenues	108,913		72,461		Accrued unbilled revenues	94,757		74,843
Materials and supplies (at average cost)	Materials and supplies (at average cost)	70,248		64,941		Materials and supplies (at average cost)	78,715		77,552
Fuel stock (at average cost)	Fuel stock (at average cost)	37,600		31,646		Fuel stock (at average cost)	16,023		18,045
Prepayments	Prepayments	20,321		20,057		Prepayments	23,172		24,558

Current regulatory assets	Current regulatory assets	61,896		63,407		Current regulatory assets	98,550		71,223
Other	Other	12,705		1,995		Other	15,496		5,708
Total current assets	Total current assets	539,829		510,061		Total current assets	533,626		440,285
Investments	Investments	85,060		87,848		Investments	69,058		77,108
Property, Plant and Equipment:	Property, Plant and Equipment:					Property, Plant and Equipment:
Plant in service	Plant in service	6,392,964		6,283,790		Plant in service	6,680,494		6,509,316
Accumulated provision for depreciation	Accumulated provision for depreciation	(2,236,478)		(2,193,831)		Accumulated provision for depreciation	(2,395,644)		(2,298,951)
Plant in service - net	Plant in service - net	4,156,486		4,089,959		Plant in service - net	4,284,850		4,210,365
Construction work in progress	Construction work in progress	600,800		597,152		Construction work in progress	708,529		670,585
Plant held for future use	Plant held for future use	4,035		4,109		Plant held for future use	4,089		4,511
Other property	Other property	3,647		5,123		Other property	4,357		3,647
Property, plant and equipment, net	Property, plant and equipment, net	4,764,968		4,696,343		Property, plant and equipment, net	5,001,825		4,889,108
Other Assets:	Other Assets:					Other Assets:
Company-owned life insurance	Company-owned life insurance	64,533		62,382		Company-owned life insurance	70,180		67,343
Regulatory assets	Regulatory assets	1,495,961		1,495,488		Regulatory assets	1,496,817		1,462,431
Other	Other	56,640		53,988		Other	58,156		54,564
Total other assets	Total other assets	1,617,134		1,611,858		Total other assets	1,625,153		1,584,338
Total	Total	$	7,006,991	$	6,906,110	Total	$	7,229,662	$	6,990,839

The accompanying notes are an integral part of these statements.

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Idaho Power Company

Condensed Consolidated Balance Sheets

(unaudited)


		June 30, 2021		December 31, 2020			June 30, 2022		December 31, 2021
		(in thousands)					(in thousands)
Liabilities and Equity	Liabilities and Equity					Liabilities and Equity

Current Liabilities:	Current Liabilities:					Current Liabilities:

Current maturities of long-term debt						Current maturities of long-term debt	$	75,000	$	—

Accounts payable	Accounts payable	$	122,731	$	120,476	Accounts payable	152,475		145,871
Accounts payable to affiliates	Accounts payable to affiliates	2,507		1,720		Accounts payable to affiliates	2,699		2,159
Taxes accrued	Taxes accrued	33,796		19,554		Taxes accrued	29,086		14,316
Interest accrued	Interest accrued	23,944		24,030		Interest accrued	23,924		23,959

Accrued compensation	Accrued compensation	43,165		52,036		Accrued compensation	48,948		55,491
Current regulatory liabilities	Current regulatory liabilities	26,899		11,104		Current regulatory liabilities	20,101		11,239
Advances from customers	Advances from customers	41,544		29,341		Advances from customers	67,400		43,472
Other	Other	17,446		16,717		Other	20,552		19,117
Total current liabilities	Total current liabilities	312,032		274,978		Total current liabilities	440,185		315,624
Other Liabilities:	Other Liabilities:					Other Liabilities:
Deferred income taxes	Deferred income taxes	821,232		829,146		Deferred income taxes	831,492		844,871
Regulatory liabilities	Regulatory liabilities	768,416		757,730		Regulatory liabilities	794,753		781,695
Pension and other postretirement benefits	Pension and other postretirement benefits	638,455		634,070		Pension and other postretirement benefits	521,963		521,462
Other	Other	59,604		45,937		Other	67,264		62,245
Total other liabilities	Total other liabilities	2,287,707		2,266,883		Total other liabilities	2,215,472		2,210,273
Long-Term Debt	Long-Term Debt	2,000,527		2,000,414		Long-Term Debt	2,075,698		2,000,640
Commitments and Contingencies	Commitments and Contingencies	0		0		Commitments and Contingencies	0		0
Equity:	Equity:					Equity:
Common stock, $2.50 par value (50,000 shares authorized; 39,151 shares outstanding)	Common stock, $2.50 par value (50,000 shares authorized; 39,151 shares outstanding)	97,877		97,877		Common stock, $2.50 par value (50,000 shares authorized; 39,151 shares outstanding)	97,877		97,877
Premium on capital stock	Premium on capital stock	712,257		712,258		Premium on capital stock	712,258		712,258
Capital stock expense	Capital stock expense	(2,097)		(2,097)		Capital stock expense	(2,097)		(2,097)
Retained earnings	Retained earnings	1,640,374		1,599,155		Retained earnings	1,728,635		1,696,304
Accumulated other comprehensive loss	Accumulated other comprehensive loss	(41,686)		(43,358)		Accumulated other comprehensive loss	(38,366)		(40,040)
Total equity	Total equity	2,406,725		2,363,835		Total equity	2,498,307		2,464,302
Total	Total	$	7,006,991	$	6,906,110	Total	$	7,229,662	$	6,990,839

The accompanying notes are an integral part of these statements.	The accompanying notes are an integral part of these statements.					The accompanying notes are an integral part of these statements.

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Idaho Power Company

Condensed Consolidated Statements of Cash Flows

(unaudited)


		Six months ended June 30,					Six months ended June 30,
		2021		2020			2022		2021
		(in thousands)					(in thousands)
Operating Activities:	Operating Activities:					Operating Activities:
Net income	Net income	$	113,191	$	95,700	Net income	$	108,649	$	113,191
Adjustments to reconcile net income to net cash provided by operating activities:	Adjustments to reconcile net income to net cash provided by operating activities:					Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	Depreciation and amortization	88,593		87,454		Depreciation and amortization	81,053		88,593
Deferred income taxes and investment tax credits	Deferred income taxes and investment tax credits	(5,393)		(1,734)		Deferred income taxes and investment tax credits	(19,471)		(5,393)
Changes in regulatory assets and liabilities	Changes in regulatory assets and liabilities	9,311		(11,831)		Changes in regulatory assets and liabilities	8,658		9,311
Pension and postretirement benefit plan expense	Pension and postretirement benefit plan expense	14,534		14,478		Pension and postretirement benefit plan expense	14,484		14,534
Contributions to pension and postretirement benefit plans	Contributions to pension and postretirement benefit plans	(11,957)		(13,219)		Contributions to pension and postretirement benefit plans	(12,122)		(11,957)
Earnings of equity-method investments	Earnings of equity-method investments	(4,293)		(4,440)		Earnings of equity-method investments	(4,265)		(4,293)
Distributions from equity-method investments	Distributions from equity-method investments	4,100		0		Distributions from equity-method investments	4,265		4,100
Allowance for equity funds used during construction	Allowance for equity funds used during construction	(15,564)		(14,421)		Allowance for equity funds used during construction	(18,410)		(15,564)
Other non-cash adjustments to net income, net	Other non-cash adjustments to net income, net	(422)		1,664		Other non-cash adjustments to net income, net	464		(422)
Change in:	Change in:					Change in:
Receivables	Receivables	(14,535)		(10,759)		Receivables	(13,064)		(14,535)
Accounts payable	Accounts payable	2,616		(22,065)		Accounts payable	(23,425)		2,616
Taxes accrued/receivable	Taxes accrued/receivable	18,908		22,181		Taxes accrued/receivable	30,097		18,908
Other current assets	Other current assets	(48,203)		(23,877)		Other current assets	(17,033)		(48,203)
Other current liabilities	Other current liabilities	5,728		13,159		Other current liabilities	7,795		5,728
Other assets	Other assets	(3,307)		(1,442)		Other assets	(7,613)		(3,307)
Other liabilities	Other liabilities	1,999		(42)		Other liabilities	4,630		1,999
Net cash provided by operating activities	Net cash provided by operating activities	155,306		130,806		Net cash provided by operating activities	144,692		155,306
Investing Activities:	Investing Activities:					Investing Activities:
Additions to utility plant	Additions to utility plant	(128,264)		(144,865)		Additions to utility plant	(193,940)		(128,264)

Payments received from transmission project joint funding partners	Payments received from transmission project joint funding partners	2,253		1,728		Payments received from transmission project joint funding partners	5,531		2,253

Investments in unconsolidated affiliates		0		(2,300)
Distributions from equity-method investments, return of investment						Distributions from equity-method investments, return of investment	10,335		—

Purchases of equity securities	Purchases of equity securities	(392)		(3,326)		Purchases of equity securities	(27,118)		(392)
Purchases of held-to-maturity securities						Purchases of held-to-maturity securities	(29,692)		—
Proceeds from the sale of equity securities	Proceeds from the sale of equity securities	3,197		2,630		Proceeds from the sale of equity securities	52,833		3,197

Other	Other	1,347		4,911		Other	7,282		1,347
Net cash used in investing activities	Net cash used in investing activities	(121,859)		(141,222)		Net cash used in investing activities	(174,769)		(121,859)
Financing Activities:	Financing Activities:					Financing Activities:
Issuance of long-term debt	Issuance of long-term debt	0		310,000		Issuance of long-term debt	150,000		—
Premium on issuance of long-term debt		0		31,384

Dividends on common stock	Dividends on common stock	(71,972)		(67,939)		Dividends on common stock	(76,318)		(71,972)

Other		(9)		(3,232)
Net cash (used in) provided by financing activities		(71,981)		270,213
Net (decrease) increase in cash and cash equivalents		(38,534)		259,797
Debt issuance costs and other						Debt issuance costs and other	(73)		(9)
Net cash provided by (used in) financing activities						Net cash provided by (used in) financing activities	73,609		(71,981)
Net increase (decrease) in cash and cash equivalents						Net increase (decrease) in cash and cash equivalents	43,532		(38,534)
Cash and cash equivalents at beginning of the period	Cash and cash equivalents at beginning of the period	165,604		98,950		Cash and cash equivalents at beginning of the period	60,075		165,604
Cash and cash equivalents at end of the period	Cash and cash equivalents at end of the period	$	127,070	$	358,747	Cash and cash equivalents at end of the period	$	103,607	$	127,070
Supplemental Disclosure of Cash Flow Information:	Supplemental Disclosure of Cash Flow Information:					Supplemental Disclosure of Cash Flow Information:
Cash paid to (received from) IDACORP related to income taxes		$	10,046	$	(9,189)
Cash paid to IDACORP related to income taxes						Cash paid to IDACORP related to income taxes	$	10,645	$	10,046
Cash paid for interest (net of amount capitalized)	Cash paid for interest (net of amount capitalized)	41,616		38,291		Cash paid for interest (net of amount capitalized)	$	41,647	$	41,616
Non-cash investing activities:	Non-cash investing activities:					Non-cash investing activities:
Additions to property, plant and equipment in accounts payable	Additions to property, plant and equipment in accounts payable	$	30,984	$	22,072	Additions to property, plant and equipment in accounts payable	$	70,063	$	30,984

The accompanying notes are an integral part of these statements.

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IDACORP, INC. AND IDAHO POWER COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

This Quarterly Report on Form 10-Q is a combined report of IDACORP, Inc. (IDACORP) and Idaho Power Company (Idaho Power). Therefore, these Notes to Condensed Consolidated Financial Statements apply to both IDACORP and Idaho Power. However, Idaho Power makes no representation as to the information relating to IDACORP’s other operations.

Nature of Business

IDACORP is a holding company formed in 1998 whose principal operating subsidiary is Idaho Power. Idaho Power is an electric utility engaged in the generation, transmission, distribution, sale, and purchase of electric energy and capacity with a service area covering approximately 24,000 square miles in southern Idaho and eastern Oregon. Idaho Power is regulated primarily by the state utility regulatory commissions of Idaho and Oregon and the Federal Energy Regulatory ~~Commission (FERC).~~Commission. 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 (Jim Bridger plant) owned in part by Idaho Power.

IDACORP’s significant other wholly-owned subsidiaries include IDACORP Financial Services, Inc. (IFS), an investor in affordable housing and other real estate tax credit investments, and Ida-West Energy Company (Ida-West), an operator of small hydropower generation projects that satisfy the requirements of the Public Utility Regulatory Policies Act of 1978 (PURPA).

Regulation of Utility Operations

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

IDACORP's and Idaho Power's financial statements reflect the effects of the different ratemaking principles followed by the jurisdictions regulating Idaho Power. The application of accounting principles related to regulated operations sometimes results in Idaho Power recording expenses and revenues in a different period than when an unregulated enterprise would record such expenses and revenues. In these instances, the amounts are deferred or accrued as regulatory assets or regulatory liabilities on the balance sheet. Regulatory assets represent incurred costs that have been deferred because it is probable they will be recovered from customers through future rates. Regulatory liabilities represent obligations to make refunds to customers for previous collections, or represent amounts collected in advance of incurring an expense. The effects of applying these regulatory accounting principles to Idaho Power's operations are discussed in more detail in Note 3 - "Regulatory Matters."

Financial Statements

In the opinion of management of IDACORP and Idaho Power, the accompanying unaudited condensed consolidated financial statements contain all adjustments necessary to present fairly each company's condensed consolidated financial position as of June 30, ~~2021,~~2022, condensed consolidated results of operations for the three and six months ended June 30, 2022 and 2021, and ~~2020, and~~condensed consolidated cash flows for the six months ended June 30, ~~2021~~2022 and ~~2020.~~2021. These adjustments are of a normal and recurring nature. These financial statements do not contain the complete detail or note disclosures 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, ~~2020 (2020~~2021 (2021 Annual Report). 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.~~principles in the United States of America (GAAP). These estimates and assumptions include those related to rate regulation, retirement benefits, contingencies, 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

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date of the financial statements and the reported amounts of revenues and expenses during the reporting period. These estimates involve judgments

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with respect to, among other things, future economic factors that are difficult to predict and are beyond management's control. Accordingly, actual results could differ from those estimates.

~~Reclassifications~~

Idaho Power changed the presentation of its consolidated statements of income from a utility format to a traditional format. The changes revised the order of certain line items and did not result in any material changes in classification of amounts between line items.

In the condensed consolidated statements of income, certain amounts in prior periods' consolidated statements of income have been reclassified to conform with current period presentation. On IDACORP's and Idaho Power's condensed consolidated statements of income for the three months ended June 30, 2020, $0.4 million that had previously been reported as "Other" within "Operating Expenses" and "Other expense, net" within "Other Income (Expense)" respectively, were reclassified to "Other electric utility operating expenses" and "Other operating expenses" within "Operating Expenses," respectively. On IDACORP's and Idaho Power's condensed consolidated statements of income for the six months ended June 30, 2020, $0.9 million that had previously been reported as "Other" within "Operating Expenses" and "Other expense, net" within "Other Income (Expense)" respectively, were reclassified to "Other electric utility operating expenses" and "Other operating expenses" within "Operating Expenses," respectively.

New and Recently Adopted Accounting Pronouncements

There have been no recently issued accounting pronouncements that have had or are expected to have a material impact on IDACORP's or Idaho Power's condensed consolidated financial statements.

2. INCOME TAXES

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

Income Tax Expense

The following table provides a summary of income tax expense for the six months ended June 30, ~~2021~~2022 and ~~2020~~2021 (in thousands):


		IDACORP						Idaho Power							IDACORP						Idaho Power
		2021			2020			2021			2020				2022			2021			2022			2021
Income tax at statutory rates (federal and state)	Income tax at statutory rates (federal and state)	$	33,722		$	27,980		$	33,586		$	27,613		Income tax at statutory rates (federal and state)	$	32,140		$	33,722		$	32,088		$	33,586

Excess deferred income tax reversal	Excess deferred income tax reversal	(3,213)			(2,962)			(3,213)			(2,962)			Excess deferred income tax reversal	(5,703)			(3,213)			(5,703)			(3,213)

Other(1)	Other(1)	(14,353)			(14,197)			(13,082)			(13,073)			Other(1)	(12,120)			(14,353)			(10,372)			(13,082)
Income tax expense	Income tax expense	$	16,156		$	10,821		$	17,291		$	11,578		Income tax expense	$	14,317		$	16,156		$	16,013		$	17,291
Effective tax rate	Effective tax rate	12.3		%	9.9		%	13.3		%	10.8		%	Effective tax rate	11.5		%	12.3		%	12.8		%	13.3		%

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

The increase in income tax expense for the six months ended June 30, 2021, compared with the same period in 2020, was primarily due to higher pre-tax earnings. On a net basis, Idaho Power’s estimate of its annual 2021 regulatory flow-through tax adjustments is comparable to 2020.

3. REGULATORY MATTERS

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

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Idaho and Oregon General Rate Cases

Idaho Power's current base rates result from ~~orders from~~ the Idaho Public Utilities Commission (IPUC) and Public Utility Commission of Oregon (OPUC)~~, as~~ orders described in Note 3 - "Regulatory Matters" to the consolidated financial statements included in the ~~2020~~2021 Annual Report.

Idaho Settlement Stipulations

A May 2018 Idaho settlement stipulation related to tax reform (May 2018 Idaho Tax Reform Settlement Stipulation) is described in Note 3 - "Regulatory Matters" to the consolidated financial statements included in the ~~2020~~2021 Annual Report and includes provisions for the accelerated amortization of accumulated deferred investment tax credits (ADITC) to help achieve a minimum 9.4 percent Idaho-jurisdiction return on year-end equity ~~in the Idaho jurisdiction~~ (Idaho ROE). In addition, under the May 2018 Idaho Tax Reform Settlement Stipulation, ~~minimum~~the Idaho ROE at which Idaho Power would begin amortizing additional ADITC would revert back to 95 percent of the authorized return on equity in the next general rate case. The settlement stipulation also provides for the potential sharing between Idaho Power and Idaho customers of Idaho-jurisdictional earnings in excess of 10.0 percent of Idaho ROE.

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Based on its estimate of full-year ~~2021~~2022 Idaho ROE, in ~~both~~ the second quarter ~~and first six months~~ of ~~2021,~~2022, Idaho Power recorded 0no additional ADITC amortization or provision against current revenues for sharing of earnings with customers ~~for 2021~~ under the May 2018 Idaho Tax Reform Settlement Stipulation. Accordingly, at June 30, ~~2021,~~2022, the full $45 million of additional ADITC remains available for future use. Idaho Power also recorded 0no additional ADITC amortization or provision against revenues for sharing of earnings with customers during the second quarter ~~and first six months~~ of ~~2020,~~2021, based on its then-current estimate of full-year ~~2020~~2021 Idaho ROE.

~~Idaho~~ Power Cost Adjustment Mechanisms

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

In May ~~2021,~~2022, the IPUC approved a ~~$39.1~~ $94.9 million netincrease in Idaho-jurisdiction power cost adjustment (PCA) revenues, effective for the ~~2021-2022~~2022-2023 PCA collection period from June 1, ~~2021,~~2022, to May 31, ~~2022.~~2023. The net increase in PCA revenues reflects a forecasted reduction in low-cost ~~hydroelectric~~hydropower generation as well as higher costs associated with higher forecasted PURPA power purchases. The net increase in PCA revenues also reflects a smaller credit to customers through the true-up component. Also in May 2021, the IPUC ordered Idaho Power to initiate a case to review the PCA mechanism and propose any modifications it determines are appropriate so the case may be processed before the filing of the 2022 PCA application in April 2022.

Previously, in May 2020, the IPUC issued an order approving a $58.7 million net increase in PCA rates, effective for the 2020-2021 PCA collection period from June 1, 2020, to May 31, 2021. The net increase in PCA revenues reflected a return to a more normal level of power supply costs as wholesale market energy prices ~~came down from unusually high levels reflected in~~and higher natural gas prices. The filing also includes $0.6 million of 2021 earnings to be shared with customers under the prior year's PCA. The net increase in PCA revenues also reflected a forecasted reduction in low-cost hydropower generation and the removal of a $7.7 million one-time customer benefit associated with revenue sharing and income tax reform benefits, which expired in May ~~2020.~~2018 Idaho Tax Reform Settlement Stipulation described above.

Idaho Fixed Cost Adjustment Mechanism

The Idaho jurisdiction fixed cost adjustment (FCA) mechanism, applicable to Idaho residential and small general service customers, is designed to remove a portion of Idaho Power’s financial disincentive to invest in energy efficiency programs by separating (or decoupling) the recovery of fixed costs from the variable kilowatt-hour charge and linking it instead to a set amount per customer. Under Idaho Power's current rate design, Idaho Power recovers a portion of fixed costs through the variable kilowatt-hour charge, which may result in over-collection or under-collection of fixed costs. To return over-collection to customers or to collect under-collection from customers, the FCA mechanism allows Idaho Power to accrue, or defer, the difference between the authorized fixed-cost recovery amount per customer and the actual fixed costs per customer recovered

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by Idaho Power during the year. The IPUC has discretion to cap the annual increase in the FCA recovery at 3 percent of base revenue, with any excess deferred for collection in a subsequent year. In May ~~2021,~~2022, the IPUC approved ~~an increase~~a decrease of ~~$2.8~~$3.1 million in recovery from the FCA from ~~$35.5~~$38.3 million to ~~$38.3~~$35.2 million for the 2021 FCA deferral, with new rates effective for the period from June 1, ~~2021,~~2022, to May 31, 2022. Also in May 2021, the IPUC ordered Idaho Power to work with interested parties and initiate a case to review the FCA mechanism and propose any modifications it determines are appropriate so the case may be processed before the filing of the 2022 FCA application in March 2022. Previously, in June 2020, the IPUC issued an order approving an increase of $0.7 million in the FCA from $34.8 million to $35.5 million, with rates effective for the period from June 1, 2020, to May 31, 2021.2023.

~~Depreciation Rate Requests~~

In 2021, Idaho Power conducted a depreciation study of electric plant-in-service, which it conducts approximately every five years. The study provided updates to net salvage percentages and service life estimates for Idaho Power plant assets. Based on the study, in June 2021, Idaho Power filed applications with the IPUC and OPUC requesting approval to institute revised depreciation rates for Idaho Power's electric plant-in-service and adjust base rates by an aggregate of $3.9 million to reflect the revised depreciation rates applied to electric plant-in-service balances subject to the most recent general rate cases. The proposed adjustments in these applications are an overall rate increase of 0.31 percent in Idaho and 0.24 percent in Oregon. Idaho Power requested an effective date of December 1, 2021, for these adjustments.

Jim Bridger Power Plant Rate ~~Request~~Base Adjustment and Recovery

In June ~~2021,~~2022, the IPUC issued an order approving, with modifications, Idaho ~~Power filed an~~Power’s amended application ~~with the IPUC~~ requesting authorization to (a) accelerate depreciation for the Jim Bridger plant to allow the coal-related plant assets to be fully depreciated and recovered by December 31, 2030, (b) establish a balancing account to track the incremental costs, benefits, and ~~benefits~~required regulatory accounting associated with ceasing participation in coal-fired operations at the Jim Bridger plant, and (c) adjust customer rates to recover the associated incremental annual levelized revenue requirement (Bridger Order).

The Bridger Order allows for regulatory accounting entries and establishes balancing accounts (recorded as regulatory assets or liabilities on Idaho Power’s and IDACORP’s consolidated balance sheets) to track differences between amounts recovered in ~~the aggregate amount~~rates and actual incremental costs and benefits associated with Idaho Power’s cessation of ~~$30.8 million, which includes Idaho Power's share of all electric plant in service~~coal-fired operations at the Jim Bridger plant.The ~~proposed adjustment in this application is an overall~~incremental costs and benefits include the revenue requirement associated with the incremental Jim Bridger plant coal-related investments made from 2012 through the end of 2020, forecasted coal-related investments, and near-term decommissioning costs, offset by other operations and maintenance (O&M) cost savings. The Bridger Order deemed all coal-related investments at the Jim Bridger plant from 2012 through 2020 to be prudent for recovery. In the Bridger Order, the IPUC reduced Idaho Power's requested rate increase ~~of 2.53~~from 2.1 percent in ~~Idaho.~~its amended filing to 1.5 percent, a reduction from $27.1 million to $18.8 million annually. The Bridger Order provides that any uncollected amount resulting from the reduction in the rate increase will be recorded in the balancing account for future recovery with no carrying charge. Idaho Power ~~requested an effective date~~anticipates making future filings with the IPUC that may result in periodic adjustments to rates to true up variances between revenue collections and actual revenue requirement amounts.

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The Bridger Order allows Idaho Power to earn a return on and recover through 2030 the net book value of coal-related assets at the Jim Bridger plant as of December ~~1, 2021,~~31, 2020, as well as forecasted coal-related investments, which resulted in Idaho Power's deferral of certain depreciation expense during the three- and six-month periods ended June 30, 2022. The deferral and impacts of the Bridger Order resulted in an increase in net income for ~~this adjustment.~~the first half of 2022 of approximately $9 million, all of which was recorded during the second quarter of 2022.

Wildfire Mitigation Cost ~~Deferral~~Recovery

In June 2021, the IPUC authorized Idaho Power to defer for future amortization incremental ~~operations and maintenance (O&M)~~O&M and depreciation expense for certain capital investments necessary to implement Idaho Power's Wildfire Mitigation Plan (WMP). The IPUC also authorized Idaho Power to record these deferred expenses as a regulatory asset until Idaho Power can request amortization of the deferred costs in a future IPUC proceeding, at which time the IPUC will have the opportunity to review actual costs and determine the amount of prudently incurred costs that Idaho Power can recover through retail rates. In the filing, Idaho Power ~~projects~~projected spending approximately $47 million in incremental wildfire mitigation-related O&M and ~~roughly~~approximately $35 million in wildfire mitigation system-hardening capital incremental expenditures over ~~the next five years.~~a five-year period. The IPUC authorized a deferral period of five years, or until rates go into effect from Idaho Power's next general rate case, whichever is first. As of June 30, ~~2021,~~2022, Idaho ~~Power had not recorded any~~Power's deferral of Idaho-jurisdiction costs related to the WMP ~~as Idaho Power does not expect to incur significant incremental costs in connection with many of the projects identified in or associated with the WMP until the second half of 2021.~~was $14.8 million.

4. REVENUES

The following table provides a summary of electric utility operating revenues for IDACORP and Idaho Power for the three and six months ended June 30, ~~2021~~2022 and ~~2020~~2021 (in thousands):


		Three months ended June 30,				Six months ended June 30,					Three months ended June 30,				Six months ended June 30,
		2021		2020		2021		2020			2022		2021		2022		2021
Electric utility operating revenues:	Electric utility operating revenues:									Electric utility operating revenues:
Revenue from contracts with customers	Revenue from contracts with customers	$	357,461	$	310,971	$	648,787	$	581,155	Revenue from contracts with customers	$	345,483	$	357,461	$	663,665	$	648,787
Alternative revenue programs and other revenues	Alternative revenue programs and other revenues	1,597		6,695		25,838		26,999		Alternative revenue programs and other revenues	12,185		1,597		37,924		25,838
Total electric utility operating revenues	Total electric utility operating revenues	$	359,058	$	317,666	$	674,625	$	608,154	Total electric utility operating revenues	$	357,668	$	359,058	$	701,589	$	674,625

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Revenues from Contracts with Customers

The following table presents revenues from contracts with customers disaggregated by revenue source for the three and six months ended June 30, ~~2021~~2022 and ~~2020~~2021 (in thousands):


		Three months ended June 30,				Six months ended June 30,					Three months ended June 30,				Six months ended June 30,
		2021		2020		2021		2020			2022		2021		2022		2021
Revenues from contracts with customers:	Revenues from contracts with customers:									Revenues from contracts with customers:
Retail revenues:	Retail revenues:									Retail revenues:
Residential (includes ($715), $4,135, $15,107, and $19,844, respectively, related to the FCA)(1)		$	122,633	$	109,471	$	277,418	$	254,357
Commercial (includes $165, $397, $647 and $881, respectively, related to the FCA)(1)		77,609		67,214		149,878		136,728
Residential (includes $5,459, $(715), $15,551, and $15,107, respectively, related to the FCA)(1)										Residential (includes $5,459, $(715), $15,551, and $15,107, respectively, related to the FCA)(1)	$	124,593	$	122,633	$	293,888	$	277,418
Commercial (includes $304, $165, $588, and $647, respectively, related to the FCA)(1)										Commercial (includes $304, $165, $588, and $647, respectively, related to the FCA)(1)	79,260		77,609		157,826		149,878
Industrial	Industrial	48,047		43,087		93,477		85,847		Industrial	51,987		48,047		101,047		93,477
Irrigation	Irrigation	76,799		60,149		77,885		61,523		Irrigation	57,659		76,799		58,700		77,885

Deferred revenue related to HCC relicensing AFUDC(2)	Deferred revenue related to HCC relicensing AFUDC(2)	(1,927)		(1,927)		(4,046)		(4,046)		Deferred revenue related to HCC relicensing AFUDC(2)	(1,927)		(1,927)		(4,046)		(4,046)

Total retail revenues	Total retail revenues	323,161		277,994		594,612		534,409		Total retail revenues	311,572		323,161		607,415		594,612
Less: FCA mechanism revenues(1)	Less: FCA mechanism revenues(1)	550		(4,532)		(15,754)		(20,725)		Less: FCA mechanism revenues(1)	(5,763)		550		(16,139)		(15,754)
Wholesale energy sales	Wholesale energy sales	4,308		6,866		10,567		10,775		Wholesale energy sales	6,980		4,308		10,015		10,567
Transmission wheeling-related revenues	Transmission wheeling-related revenues	15,420		11,491		29,887		21,854		Transmission wheeling-related revenues	18,323		15,420		34,788		29,887
Energy efficiency program revenues	Energy efficiency program revenues	6,658		11,953		15,685		21,428		Energy efficiency program revenues	6,609		6,658		13,198		15,685
Other revenues from contracts with customers	Other revenues from contracts with customers	7,364		7,199		13,790		13,414		Other revenues from contracts with customers	7,762		7,364		14,388		13,790
Total revenues from contracts with customers	Total revenues from contracts with customers	$	357,461	$	310,971	$	648,787	$	581,155	Total revenues from contracts with customers	$	345,483	$	357,461	$	663,665	$	648,787

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

(2) The IPUC allows Idaho Power to recover a portion of the allowance for funds used during construction (AFUDC) on construction work in progress related to the Hells Canyon Complex (HCC) relicensing process, even though the relicensing process is not yet complete and the costs have not been moved to electric plant in service. Idaho Power is collecting $8.8 million annually in the Idaho jurisdiction but is deferring revenue recognition of the amounts collected until the license is issued and the accumulated license costs approved for recovery are placed in service.

Alternative Revenue Programs and Other Revenues

While revenues from contracts with customers make up most of Idaho Power’s revenues, the IPUC has authorized the use of an additional regulatory mechanism, the Idaho FCA mechanism, which may increase or decrease tariff-based customer rates. The Idaho FCA mechanism is described in Note 3 - "Regulatory Matters." The FCA mechanism revenues include only the initial recognition of FCA revenues when they meet the regulator-specified conditions for recognition. Revenue from contracts with customers excludes the portion of the tariff price representing FCA revenues that Idaho Power initially recorded in prior periods when revenues met regulator-specified conditions. When Idaho Power includes those amounts in the price of utility service billed to customers, Idaho Power records such amounts as recovery of the associated regulatory asset or liability and not as revenues.

Derivative revenues include gains from settled electricity swaps and sales of electricity under forward sales contracts that are bundled with renewable energy credits. Related to these forward sales, Idaho Power simultaneously enters into forward purchases of electricity for the same quantity at the same location, which are recorded in purchased power on the condensed consolidated statements of income. For more information on settled electricity swaps, see Note 1012 - "Derivative Financial Instruments."

The table below presents the FCA mechanism revenues and other revenues for the three and six months ended June 30, ~~2021~~2022 and ~~2020~~2021 (in thousands):


		Three months ended June 30,				Six months ended June 30,					Three months ended June 30,				Six months ended June 30,
		2021		2020		2021		2020			2022		2021		2022		2021
Alternative revenue programs and other revenues:	Alternative revenue programs and other revenues:									Alternative revenue programs and other revenues:
FCA mechanism revenues	FCA mechanism revenues	$	(550)	4,532		$	15,754	$	20,725	FCA mechanism revenues	$	5,763	(550)		$	16,139	$	15,754
Derivative revenues	Derivative revenues	2,147		2,163		10,084		6,274		Derivative revenues	6,422		2,147		21,785		10,084
Total alternative revenue programs and other revenues	Total alternative revenue programs and other revenues	$	1,597	$	6,695	$	25,838	$	26,999	Total alternative revenue programs and other revenues	$	12,185	$	1,597	$	37,924	$	25,838

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Receivables and Allowance for Uncollectible Accounts

In response to the COVID-19 ~~pandemic,~~public health crisis, Idaho Power provided certain relief to customers, including temporarily suspending disconnections for customers and temporarily waiving late fees. This relief as well as the economic conditions created by the response to the COVID-19 public health crisis have resulted in higher aged accounts receivable and an increase in the number of late payments. Compared with historical levels, Idaho Power ~~is experiencing and~~ expects ~~to continue to experience~~ higher uncollectible account write-offs as a result of the COVID-19 ~~pandemic~~public health crisis and, accordingly, ~~increased~~has maintained its higher allowance for uncollectible accounts related to customer receivables at June 30, ~~2021, as compared with pre-COVID-19 allowance levels.~~2022.

The following table provides a ~~rollforward~~roll-forward of the allowance for uncollectible accounts related to customer receivables for the ~~six~~three months ended June 30, ~~2021~~2022 and ~~2020~~2021 (in thousands):


		Six months ended June 30,							Six months ended June 30,
		2021			2020				2022			2021
Balance at beginning of period	Balance at beginning of period	$	4,766		$	1,401		Balance at beginning of period	$	4,499		$	4,766
Additions to the allowance	Additions to the allowance	369			2,786			Additions to the allowance	478			369
Write-offs, net of recoveries	Write-offs, net of recoveries	(883)			(686)			Write-offs, net of recoveries	(1,056)			(883)
Balance at end of period	Balance at end of period	$	4,252		$	3,501		Balance at end of period	$	3,921		$	4,252
Allowance for uncollectible accounts as a percentage of customer receivables	Allowance for uncollectible accounts as a percentage of customer receivables	4.8		%	4.3		%	Allowance for uncollectible accounts as a percentage of customer receivables	4.3		%	4.8		%

5. LONG-TERM DEBT

Term-Loan Credit Agreement

On March 4, 2022, Idaho Power entered into a term loan credit agreement (Term Loan Facility). The Term Loan Facility is a two-year senior unsecured delayed draw term loan facility used for general corporate purposes, including funding Idaho Power’s capital projects. It provided for the issuance of loans not to exceed the aggregate principal amount of $150 million with a maturity date of March 4, 2024. At June 30, 2022, $150 million in principal amount had been drawn and was outstanding on the Term Loan Facility.

6. COMMON STOCK

IDACORP Common Stock

During the six months ended June 30, ~~2021,~~2022, IDACORP granted ~~76,147~~73,131 restricted stock ~~unit awards~~units to employees and issued ~~54,499~~43,561 shares of common stock using original issuances of shares pursuant to the IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan, including ~~12,784~~8,674 shares of common stock issued to members of the board of directors. As directed by IDACORP, plan administrators of the IDACORP, Inc. Dividend Reinvestment and Stock Purchase Plan and Idaho Power Company Employee Savings Plan used market purchases of IDACORP common stock to acquire shares of IDACORP common stock for the plans.

Restrictions on Dividends

Idaho Power’s ability to pay dividends on its common stock held by IDACORP and IDACORP’s ability to pay dividends on its common stock are limited to the extent payment of such dividends would violate the covenants in their respective credit facilities or Idaho Power’s Revised 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, ~~2021,~~2022, the leverage ratios for IDACORP and Idaho Power were 4344 percent and 46 percent, respectively. Based on these restrictions, IDACORP’s and Idaho Power’s dividends were limited to ~~$1.5~~$1.6 billion and $1.3 billion, respectively, at June 30, ~~2021.~~2022. 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 IDACORP and Idaho Power from any material subsidiary. At June 30, ~~2021,~~2022, IDACORP and Idaho Power were in compliance with those financial covenants.

Idaho Power’s Revised Code of Conduct relating to transactions ~~between and~~ among Idaho Power, IDACORP, and other affiliates, which was approved by the IPUC in April 2008, provides that Idaho Power will not pay any dividends to IDACORP that will reduce Idaho Power’s common equity capital below 35 percent of its total adjusted capital without IPUC approval. At June 30, ~~2021,~~ 2022,

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Idaho Power's common equity capital was 5554 percent of its total adjusted capital. Further, Idaho Power must obtain approval from the OPUC before it can directly or indirectly loan funds or issue notes or give credit on its books to IDACORP.

Idaho Power’s articles of incorporation contain restrictions on the payment of dividends on its common stock if preferred stock dividends are in arrears. As of the date of this report, Idaho Power has 0no 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

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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, ~~2021~~2022 and ~~2020~~2021 (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,
		2021		2020		2021		2020			2022		2021		2022		2021
Numerator:	Numerator:									Numerator:
Net income attributable to IDACORP, Inc.	Net income attributable to IDACORP, Inc.	$	70,023	$	60,389	$	114,854	$	97,879	Net income attributable to IDACORP, Inc.	$	64,287	$	70,023	$	110,548	$	114,854
Denominator:	Denominator:									Denominator:
Weighted-average common shares outstanding - basic	Weighted-average common shares outstanding - basic	50,609		50,551		50,588		50,534		Weighted-average common shares outstanding - basic	50,668		50,609		50,650		50,588
Effect of dilutive securities	Effect of dilutive securities	13		16		13		13		Effect of dilutive securities	19		13		23		13
Weighted-average common shares outstanding - diluted	Weighted-average common shares outstanding - diluted	50,622		50,567		50,601		50,547		Weighted-average common shares outstanding - diluted	50,687		50,622		50,673		50,601
Basic earnings per share	Basic earnings per share	$	1.38	$	1.19	$	2.27	$	1.94	Basic earnings per share	$	1.27	$	1.38	$	2.18	$	2.27
Diluted earnings per share	Diluted earnings per share	$	1.38	$	1.19	$	2.27	$	1.94	Diluted earnings per share	$	1.27	$	1.38	$	2.18	$	2.27

7.8. COMMITMENTS

Purchase Obligations

During the six months ended June 30, ~~2021,~~2022, Idaho Power entered into:

•1 new non-PURPA-qualifying solar facility power purchase contract and 1 replacement PURPA-qualifying hydropower facility power purchase contract for an expiring power purchase agreement, which collectively increased Idaho Power's contractual purchase obligations by approximately $86 million over the 20-year terms of the contracts; and

•two new contracts to acquire and own battery storage assets, which collectively increased Idaho Power's contractual purchase obligations by approximately $137 million over the 1-year terms of the contracts. During the six months ended June 30, 2022, Idaho Power made payments of $35 million related to these obligations.

Aside from these changes, IDACORP's and Idaho Power's contractual obligations, outside the ordinary course of business, did not change materially from the amounts disclosed in the notes to the consolidated financial statements in the ~~2020~~2021 Annual Report, except that Idaho Power entered into two new long-term transmission purchase agreements, which increased Idaho Power's contractual purchase obligations by approximately $16 million over the 5-year terms of the contracts, and five new replacement contracts for expiring power purchase agreements with PURPA-qualifying hydropower facilities, which increased Idaho Power's contractual purchase obligations by approximately $29 million over the 20-year terms of the contracts.Report.

Guarantees

Idaho Power guarantees its portion of reclamation activities and obligations at BCC, of which IERCo owns a one-third interest. This guarantee, which is renewed annually with the Wyoming Department of Environmental Quality, was ~~$51.7~~$50.8 million at June 30, ~~2021,~~2022, representing IERCo's one-third share of BCC's total reclamation obligation of ~~$155.2~~$152.5 million. BCC has a reclamation trust fund set aside specifically for the purpose of paying these reclamation costs. At June 30, ~~2021,~~2022, the value of BCC's reclamation trust fund was ~~$198.3~~$183.9 million. During the six months ended June 30, ~~2021,~~2022, the reclamation trust fund made ~~$16.4~~$1.1 million of distributions for reclamation activity costs associated with the BCC surface mine. BCC periodically assesses the adequacy of the reclamation trust fund and its estimate of future reclamation costs. To ensure that the reclamation trust fund maintains adequate reserves, BCC has the ability to, and does, add a per-ton surcharge to coal sales, all of which are made to the

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Jim Bridger plant. Because of the existence of the fund and the ability to apply a per-ton surcharge, the estimated fair value of this guarantee is minimal.

IDACORP and Idaho Power enter into financial agreements and power purchase and sale agreements that include indemnification provisions relating to various forms of claims or liabilities that may arise from the transactions contemplated by these agreements. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnification provisions cannot be reasonably estimated. IDACORP and Idaho Power periodically evaluate the likelihood of incurring costs under such indemnities based on their historical experience and the evaluation of the specific indemnities. As of June 30, ~~2021,~~2022, the companies believe the likelihood is remote that IDACORP or Idaho Power would be required to perform under such indemnification provisions or otherwise incur any significant losses with respect to such indemnification obligations. Neither IDACORP nor Idaho Power has recorded any liability on their respective condensed consolidated balance sheets with respect to these indemnification obligations.

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8.9. CONTINGENCIES

IDACORP and Idaho Power have in the past and expect in the future to become involved in various claims, controversies, disputes, and other contingent matters, some of which involve litigation and regulatory or other contested proceedings. The ultimate resolution and outcome of litigation and regulatory proceedings is inherently difficult to determine, particularly where (a) the remedies or penalties sought are indeterminate, (b) the proceedings are in the early stages or the substantive issues have not been well developed, or (c) the matters involve complex or novel legal theories or a large number of parties. In accordance with applicable accounting guidance, IDACORP and Idaho Power, as applicable, establish an accrual for legal proceedings when those matters proceed to a stage where they present loss contingencies that are both probable and reasonably estimable. If the loss contingency at issue is not both probable and reasonably estimable, IDACORP and Idaho Power do not establish an accrual and the matter will continue to be monitored for any developments that would make the loss contingency both probable and reasonably estimable. As of the date of this report, IDACORP's and Idaho Power's accruals for loss contingencies are not material to their financial statements as a whole; however, future accruals could be material in a given period. IDACORP's and Idaho Power's determination is based on currently available information, and estimates presented in financial statements and other financial disclosures involve significant judgment and may be subject to significant uncertainty. For matters that affect Idaho Power's operations, Idaho Power intends to seek, to the extent permissible and appropriate, recovery through the rate-making process of costs incurred, although there is no assurance recovery would be granted.

IDACORP and Idaho Power are parties to legal claims and legal, tax, and regulatory actions and proceedings in the ordinary course of business and, as noted above, record an accrual for associated loss contingencies when they are probable and reasonably estimable. In connection with its utility operations, Idaho Power is subject to claims by individuals, entities, and governmental agencies for damages for alleged personal injury, property damage, ~~trespass,~~ and economic losses, relating to ~~Idaho Power’s~~the company’s provision of electric service and the operation of its generation, transmission, and distribution facilities. Some of those claims relate to ~~personal injury,~~electrical contacts, service quality, ~~and business interruption,~~ property damage, personal injury, and wildfires. In recent years, utilities in the western United States have been subject to significant liability for personal injury, loss of life, property damage, trespass, and economic losses, and in some cases, punitive damages and criminal charges, ~~and fines and penalties,~~ associated with wildfires that originated from utility property, most commonly transmission and distribution lines. ~~In recent years,~~ Idaho Power has also regularly received claims by ~~both~~ governmental agencies and private landowners for damages for fires allegedly originating from Idaho Power’s transmission and distribution system. As of the date of this report, the companies believe that resolution of existing claims will not have a material adverse effect on their respective condensed consolidated financial statements.

Idaho Power is also actively monitoring various pending environmental regulations and executive orders related to environmental matters that may have a significant impact on its future ~~operations and compliance costs.~~operations. Given uncertainties regarding the outcome, timing, and compliance plans for these environmental matters, Idaho Power is unable to estimate the financial ~~or operational~~ impact ~~of many~~ of these regulations.

9.10. BENEFIT PLANS

Idaho Power has a noncontributory defined benefit pension plan (pension plan) and two nonqualified defined benefit plans for certain senior management employees called the Security Plan for Senior Management Employees I and Security Plan for Senior Management Employees II (together, SMSP). Idaho Power also has a nonqualified defined benefit pension plan for directors that was frozen in 2002. Remaining vested benefits from that plan are included with the SMSP in the disclosures below. The benefits under the pension plan are based on years of service and the employee’s final average earnings. Idaho Power also maintains a defined benefit postretirement benefit plan (consisting of health care and death benefits) that covers all employees who were enrolled in the active-employee group plan at the time of retirement as well as their spouses and

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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, ~~2021~~2022 and ~~2020~~2021 (in thousands).


		Pension Plan				SMSP				Postretirement Benefits				Total					Pension Plan				SMSP				Postretirement Benefits				Total
		2021		2020		2021		2020		2021		2020		2021		2020			2022		2021		2022		2021		2022		2021		2022		2021
Service cost	Service cost	$	13,693	$	10,578	$	203	$	53	$	179	$	240	$	14,075	$	10,871	Service cost	$	12,849	$	13,693	$	297	$	203	$	266	$	179	$	13,412	$	14,075
Interest cost	Interest cost	9,456		9,988		889		1,087		502		633		10,847		11,708		Interest cost	9,751		9,456		975		889		530		502		11,256		10,847
Expected return on plan assets	Expected return on plan assets	(16,024)		(14,089)		0		0		(597)		(597)		(16,621)		(14,686)		Expected return on plan assets	(18,137)		(16,024)		—		—		(585)		(597)		(18,722)		(16,621)
Amortization of prior service cost	Amortization of prior service cost	1		1		74		73		12		12		87		86		Amortization of prior service cost	1		1		69		74		(2)		12		68		87
Amortization of net loss	Amortization of net loss	6,225		4,296		1,052		933		0		0		7,277		5,229		Amortization of net loss	2,589		6,225		1,058		1,052		(5)		—		3,642		7,277
Net periodic benefit cost	Net periodic benefit cost	13,351		10,774		2,218		2,146		96		288		15,665		13,208		Net periodic benefit cost	7,053		13,351		2,399		2,218		204		96		9,656		15,665
Regulatory deferral of net periodic benefit cost(1)	Regulatory deferral of net periodic benefit cost(1)	(12,787)		(10,279)		—		—		—		—		(12,787)		(10,279)		Regulatory deferral of net periodic benefit cost(1)	(6,727)		(12,787)		—		—		—		—		(6,727)		(12,787)
Previously deferred pension costs recognized(1)	Previously deferred pension costs recognized(1)	4,289		4,289		—		—		—		—		4,289		4,289		Previously deferred pension costs recognized(1)	4,289		4,289		—		—		—		—		4,289		4,289
Net periodic benefit cost recognized for financial reporting(1)(2)	Net periodic benefit cost recognized for financial reporting(1)(2)	$	4,853	$	4,784	$	2,218	$	2,146	$	96	$	288	$	7,167	$	7,218	Net periodic benefit cost recognized for financial reporting(1)(2)	$	4,615	$	4,853	$	2,399	$	2,218	$	204	$	96	$	7,218	$	7,167

(1) Net periodic benefit costs for the pension plan are recognized for financial reporting based upon the authorization of each regulatory jurisdiction in which Idaho Power operates. Under IPUC order, the Idaho portion of net periodic benefit cost is recorded as a regulatory asset and is recognized in the income statement as those costs are recovered through rates.

(2) Of total net periodic benefit cost recognized for financial reporting, ~~$4.5~~$5.0 million and ~~$4.3~~$4.5 million, respectively, were recognized in "Other operations and maintenance" and ~~$2.6~~$2.2 million and ~~$3.0~~$2.6 million, respectively, were recognized in "Other income, net" on the condensed consolidated statements of income of the companies for the three months ended June 30, ~~2021~~2022 and ~~2020.~~2021.

~~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, 2021 and 2020 (in thousands).~~


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, 2022 and 2021 (in thousands).																		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, 2022 and 2021 (in thousands).
		Pension Plan				SMSP				Postretirement Benefits				Total					Pension Plan				SMSP				Postretirement Benefits				Total
		2021		2020		2021		2020		2021		2020		2021		2020			2022		2021		2022		2021		2022		2021		2022		2021
Service cost	Service cost	$	27,101	$	21,493	$	406	$	106	$	532	$	514	$	28,039	$	22,113	Service cost	$	26,013	$	27,101	$	593	$	406	$	536	$	532	$	27,142	$	28,039
Interest cost	Interest cost	18,659		20,006		1,778		2,175		1,030		1,247		21,467		23,428		Interest cost	19,835		18,659		1,949		1,778		1,056		1,030		22,840		21,467
Expected return on plan assets	Expected return on plan assets	(32,045)		(28,119)		0		0		(1,198)		(1,202)		(33,243)		(29,321)		Expected return on plan assets	(36,174)		(32,045)		—		—		(1,176)		(1,198)		(37,350)		(33,243)
Amortization of prior service cost	Amortization of prior service cost	3		3		148		145		24		24		175		172		Amortization of prior service cost	3		3		139		148		(3)		24		139		175
Amortization of net loss	Amortization of net loss	11,898		8,663		2,103		1,867		0		0		14,001		10,530		Amortization of net loss	6,137		11,898		2,115		2,103		(16)		—		8,236		14,001
Net periodic benefit cost	Net periodic benefit cost	25,616		22,046		4,435		4,293		388		583		30,439		26,922		Net periodic benefit cost	15,814		25,616		4,796		4,435		397		388		21,007		30,439
Regulatory deferral of net periodic benefit cost(1)	Regulatory deferral of net periodic benefit cost(1)	(24,482)		(21,021)		—		—		—		—		(24,482)		(21,021)		Regulatory deferral of net periodic benefit cost(1)	(15,100)		(24,482)		—		—		—		—		(15,100)		(24,482)
Previously deferred pension costs recognized(1)	Previously deferred pension costs recognized(1)	8,577		8,577		—		—		—		—		8,577		8,577		Previously deferred pension costs recognized(1)	8,577		8,577		—		—		—		—		8,577		8,577
Net periodic benefit cost recognized for financial reporting(1)(2)	Net periodic benefit cost recognized for financial reporting(1)(2)	$	9,711	$	9,602	$	4,435	$	4,293	$	388	$	583	$	14,534	$	14,478	Net periodic benefit cost recognized for financial reporting(1)(2)	$	9,291	$	9,711	$	4,796	$	4,435	$	397	$	388	$	14,484	$	14,534

(2) Of total net periodic benefit cost recognized for financial reporting, ~~$9.3~~$9.9 million and ~~$8.5~~$9.3 million, respectively, were recognized in "Other operations and maintenance" and ~~$5.2~~$4.6 million and ~~$5.9~~$5.2 million, respectively, were recognized in "Other income, net" on the condensed consolidated statements of income of the companies for the six months ended June 30, ~~2021~~2022 and ~~2020.~~2021.

~~During~~Idaho Power has no minimum contribution requirement to its defined benefit pension plan in 2022, and during the six months ended June 30, ~~2021,~~2022, Idaho Power made a $10 million ~~contribution to its defined benefit pension plan.~~contribution. In July ~~2021,~~2022, Idaho Power made an additional $10 million contribution to the defined benefit pension plan in a continued effort to balance the regulatory collection of these expenditures with the amount and timing of contributions and to mitigate the cost of being in an underfunded position. Idaho Power ~~has no further minimum required contributions~~is considering contributing up to ~~be made~~an additional $20 million to its defined benefit pension plan during ~~2021, but depending on market conditions and cash flows, Idaho Power expects it will contribute up to a total of $40 million to the pension plan for the full year of 2021.~~2022. The primary impact of pension contributions is on the timing of cash flows, as the timing of cost recovery lags behind contributions.

In March 2021, the American Rescue Plan Act of 2021 (American Rescue Plan) was signed into law, which included changes to the funding rules for single employer pension plans. The American Rescue Plan lowered the minimum funding requirements by revising liability discount rates and by lengthening the period over which unfunded liabilities must be amortized. This did not have a material effect on Idaho Power's near-term pension contribution plans.

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

~~10.~~11. INVESTMENTS

Idaho Power has a rabbi trust designated to provide funding for obligations related to the SMSP. During the first quarter of 2022, the rabbi trust purchased $29.7 million of held-to-maturity investments in corporate fixed-income and asset-backed debt

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securities. Substantially all of these debt securities mature between 2027 and 2037. Held-to-maturity investments are carried at amortized cost, reflecting Idaho Power’s ability and intent to hold the securities to maturity. Held-to-maturity investments are adjusted for the amortization or accretion of premiums or discounts, which are amortized or accreted over the life of the related held-to-maturity security. Such amortization and accretion are included in the “Other income, net” line in the condensed consolidated statements of income. Due to increases in market interest rates in the first half of 2022, all held-to-maturity securities were in a gross unrealized holding loss position totaling $4.3 million at June 30, 2022. Based on ongoing credit evaluations of these holdings, Idaho Power does not expect payment defaults or delinquencies and has not recorded an allowance for credit losses for these securities as of June 30, 2022. Refer to Note 13 – “Fair Value Measurement” for additional information relating to the carrying amount and estimated fair value of the securities at the balance sheet date.

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

The table below presents the gains and losses on derivatives not designated as hedging instruments for the three and six months ended June 30, ~~2021~~2022 and ~~2020~~2021 (in thousands).


				Gain/(Loss) on Derivatives Recognized in Income(1)															Gain/(Loss) on Derivatives Recognized in Income(1)
		Location of Realized Gain/(Loss) on Derivatives Recognized in Income		Three months ended 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,
			2021		2020			2021			2020							2022		2021			2022			2021
Financial swaps	Financial swaps		Operating revenues		$	0		$	308		$	0		$	1,134	Financial swaps		Operating revenues		$	(1,577)		$	—		$	(995)		$	—
Financial swaps	Financial swaps	Purchased power		0			(1,125)			249			(1,315)	Financial swaps			Purchased power		(1,197)			—			(1,081)			249
Financial swaps	Financial swaps	Fuel expense		903			(69)			1,636			(2,917)	Financial swaps			Fuel expense		2,991			903			4,451			1,636

Forward contracts	Forward contracts	Operating revenues		26			41			73			120	Forward contracts			Operating revenues		32			26			211			73
Forward contracts	Forward contracts	Purchased power		(26)			(39)			(73)			(115)	Forward contracts			Purchased power		(31)			(26)			(210)			(73)
Forward contracts	Forward contracts	Fuel expense		2			(1)			1			(20)	Forward contracts			Fuel expense		(9)			2			(62)			1

(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 operating revenues or purchased power depending on the forecasted position being economically hedged by the derivative contract. Settlement gains and losses on contracts for natural gas are reflected in fuel expense. Settlement gains and losses on diesel derivatives are recorded in other ~~operations and maintenance~~O&M expense. See Note 1113 - "Fair Value Measurements" for additional information concerning the determination of fair value for Idaho Power’s assets and liabilities from price risk management activities.

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Credit Risk

At June 30, ~~2021,~~2022, 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, physical gas, and financial transactions are generally under standardized industry contracts. These contracts contain adequate assurance clauses requiring collateralization if a counterparty has debt that is downgraded below investment grade by at least one rating agency.

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Credit-Contingent Features

Certain Idaho Power derivative instruments contain provisions that require Idaho Power's unsecured debt to maintain an investment grade credit rating from Moody's Investors Service and Standard & Poor's Ratings Services. If Idaho Power's unsecured debt were to fall below investment grade, it would be in violation of these provisions, and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions. ~~The~~At June 30, 2022, the aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a liability position ~~at June 30, 2021,~~ was ~~$1.0~~$9.3 million. Idaho Power posted ~~$0.4~~$1.2 million of cash collateral related to this amount. If the credit-risk-related contingent features underlying these agreements were triggered on June 30, ~~2021,~~2022, Idaho Power would have been required to pay or post collateral to its counterparties up to ~~an additional $9.7~~$7.3 million to cover the open liability positions as well as completed transactions that have not yet been paid.

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, ~~2021,~~2022, and December 31, ~~2020~~2021 (in thousands).


			Asset Derivatives						Liability Derivatives									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, 2021
June 30, 2022																June 30, 2022
Current:	Current:															Current:
Financial swaps	Financial swaps	Other current assets	$	13,390	$	(685)	$	12,705	$	685	$	(685)		$	0	Financial swaps	Other current assets	$	15,496	$	—		$	15,496	$	—	$	—	$	—

Financial swaps																Financial swaps	Other current liabilities	9,052		(9,052)			—		9,229		(9,052)		177

Forward contracts	Forward contracts	Other current liabilities	0		0		0		104		0			104		Forward contracts	Other current liabilities	—		—			—		2,095		—		2,095
Long-term:	Long-term:															Long-term:
Financial swaps	Financial swaps	Other assets	2,547		(236)		2,311		236		(236)			0		Financial swaps	Other assets	5,854		(1,509)			4,345		1,509		(1,509)		—

Forward contracts																Forward contracts	Other liabilities	—		—			—		3,194		—		3,194
Total	Total		$	15,937	$	(921)	$	15,016	$	1,025	$	(921)		$	104	Total		$	30,402	$	(10,561)		$	19,841	$	16,027	$	(10,561)	$	5,466

December 31, 2020
December 31, 2021																December 31, 2021
Current:	Current:															Current:
Financial swaps	Financial swaps	Other current assets	$	2,028	$	(36)	$	1,992	$	36	$	(36)		$	0	Financial swaps	Other current assets	$	10,599	$	(4,893)	(1)	$	5,706	$	2,910	$	(2,910)	$	—
Financial swaps	Financial swaps	Other current liabilities	187		(187)		0		786		(652)		(1)	134		Financial swaps	Other current liabilities	—		—			—		20		—		20
Forward contracts	Forward contracts	Other current assets	5		(2)		3		2		(2)			0		Forward contracts	Other current assets	6		(4)			2		4		(4)		—
Forward contracts	Forward contracts	Other current liabilities	3		(3)		0		13		(3)			10		Forward contracts	Other current liabilities	—		—			—		1,970		—		1,970
Long-term:	Long-term:															Long-term:

Financial swaps	Financial swaps	Other liabilities	40		(40)		0		56		(56)		(1)	0		Financial swaps	Other assets	899		(9)			890		9		(9)		—

Financial swaps																Financial swaps	Other liabilities	—		—			—		14		—		14
Forward contracts																Forward contracts	Other liabilities	—		—			—		3,743		—		3,743
Total	Total		$	2,263	$	(268)	$	1,995	$	893	$	(749)		$	144	Total		$	11,504	$	(4,906)		$	6,598	$	8,670	$	(2,923)	$	5,747

(1) Current ~~and long-term liability~~asset derivative amounts offset ~~include $0.5~~includes $2.0 million ~~and $16 thousand~~ of collateral ~~receivable~~payable at December 31, ~~2020, respectively.~~2021.

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The table below presents the volume of derivative commodity forward contracts and swaps outstanding at June 30, ~~2021~~2022 and ~~2020~~2021 (in thousands of units).


			June 30,				June 30,
Commodity	Commodity	Units	2021	2020	Commodity	Units	2022	2021
Electricity purchases	Electricity purchases	MWh	254	115	Electricity purchases	MWh	541	254
Electricity sales	Electricity sales	MWh	10	40	Electricity sales	MWh	118	10
Natural gas purchases	Natural gas purchases	MMBtu	14,455	12,930	Natural gas purchases	MMBtu	21,215	14,455
Natural gas sales	Natural gas sales	MMBtu	75	388	Natural gas sales	MMBtu	—	75

~~11.~~13. 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

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markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). If the inputs used to measure the financial instruments fall within different levels of the hierarchy, the categorization is based on the lowest level input that is significant to the fair value measurement of the instrument.

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

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

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

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

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

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

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

IDACORP and Idaho Power Level 2 inputs are based on quoted market prices adjusted for location using corroborated, observable market ~~data.~~data or using quoted prices which may be in non-active markets.

• 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. There were 0no transfers between levels or material changes in valuation techniques or inputs during the six months ended June 30, ~~2021.~~2022.

Certain instruments have been valued using net asset value (NAV) as a practical expedient. These instruments are similar to mutual funds; however, their NAV is generally not published and publicly available, nor are these instruments traded on an exchange. Instruments valued using NAV as a practical expedient are included in the fair value disclosures below; however, in accordance with GAAP are not classified within the fair value hierarchy levels.

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The table below presents information about IDACORP’s and Idaho Power’s assets and liabilities measured at fair value on a recurring basis as of June 30, ~~2021,~~2022, and December 31, ~~2020~~2021 (in thousands).


		June 30, 2021								December 31, 2020									June 30, 2022								December 31, 2021
		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:	Assets:																	Assets:
Money market funds	Money market funds																	Money market funds
IDACORP(1)	IDACORP(1)	$	69,177	$	0	$	0	$	69,177	$	56,048	$	0	$	0	$	56,048	IDACORP(1)	$	76,279	$	—	$	—	$	76,279	$	80,406	$	—	$	—	$	80,406
Idaho Power	Idaho Power	11,616		0		0		11,616		40,038		0		0		40,038		Idaho Power	42,845		—		—		42,845		10,393		—		—		10,393
Derivatives	Derivatives	15,016		0		0		15,016		1,995		0		0		1,995		Derivatives	19,841		—		—		19,841		6,596		2		—		6,598
Equity securities	Equity securities	47,752		0		0		47,752		50,733		0		0		50,733		Equity securities	27,408		—		—		27,408		54,431		—		—		54,431
IDACORP assets measured at NAV (not subject to hierarchy disclosure)(1)																		IDACORP assets measured at NAV (not subject to hierarchy disclosure)(1)	—		—		—		2,063		—		—		—		1,363
Liabilities:	Liabilities:																	Liabilities:
Derivatives	Derivatives	0		104		0		104		134		10		0		144		Derivatives	177		5,289		—		5,466		34		5,713		—		5,747

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

Idaho Power’s derivatives are contracts entered into as part of its management of loads and resources. Electricity derivatives are valued on the Intercontinental Exchange (ICE) with quoted prices in an active market. Electricity forward contract derivatives are valued using a blend of two electricity exchanges, adjusted for location basis, as specified in the forward contract. Natural gas and diesel derivatives are valued using New York Mercantile Exchange (NYMEX) and ICE pricing, adjusted for location basis, which are also quoted under NYMEX and ICE pricing. Equity securities consist of employee-directed investments related to an executive deferred compensation plan and actively traded money market and exchange traded funds related to the SMSP. The investments are measured using quoted prices in active markets and are held in a ~~Rabbi~~rabbi trust.

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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, ~~2021,~~2022, and December 31, ~~2020,~~2021, using available market information and appropriate valuation methodologies (in thousands).


		June 30, 2021				December 31, 2020					June 30, 2022				December 31, 2021
		Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value			Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
IDACORP	IDACORP									IDACORP
Assets:	Assets:									Assets:
Notes receivable(1)	Notes receivable(1)	$	3,804	$	3,804	$	3,804	$	3,804	Notes receivable(1)	$	3,804	$	3,804	$	3,804	$	3,804
Held-to-maturity securities(1)										Held-to-maturity securities(1)	29,308		24,959		—		—
Liabilities:	Liabilities:									Liabilities:
Long-term debt, including current portion(1)	Long-term debt, including current portion(1)	2,000,527		2,352,122		2,000,414		2,466,967		Long-term debt, including current portion(1)	2,150,698		2,060,739		2,000,640		2,381,172
Idaho Power	Idaho Power									Idaho Power
Assets:										Assets:
Held-to-maturity securities(1)										Held-to-maturity securities(1)	29,308		24,959		—		—
Liabilities:	Liabilities:									Liabilities:
Long-term debt, including current portion(1)	Long-term debt, including current portion(1)	2,000,527		2,352,122		2,000,414		2,466,967		Long-term debt, including current portion(1)	2,150,698		2,060,739		2,000,640		2,381,172

(1) Notes receivable are categorized as Level 3 and held-to-maturity securities and long-term debt are categorized as Level ~~3 and Level~~ 2 ~~respectively,~~ of the fair value hierarchy, as defined earlier in this Note 1113 - "Fair Value Measurements."

Notes receivable are related to Ida-West and are valued based on unobservable inputs, including forecasted cash flows, which are partially based on expected hydropower conditions. Held-to-maturity securities are generally valued using quoted prices which may be in non-active markets and are held in a rabbi trust. Long-term debt is not traded on an exchange and is valued using quoted rates for similar debt in active markets. Carrying values for cash and cash equivalents, deposits, customer and other receivables, notes payable, accounts payable, interest accrued, and taxes accrued approximate fair value.

~~12.~~

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14. 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 other real estate tax credit projects, Ida-West’s joint venture investments in small hydropower generation projects, and IDACORP’s holding company expenses.

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


		Utility Operations		All Other		Eliminations		Consolidated Total			Utility Operations		All Other		Eliminations		Consolidated Total
Three months ended June 30, 2022:										Three months ended June 30, 2022:
Revenues										Revenues	$	357,668	$	1,055	$	—	$	358,723
Net income attributable to IDACORP, Inc.										Net income attributable to IDACORP, Inc.	62,435		1,852		—		64,287
Total assets as of June 30, 2022										Total assets as of June 30, 2022	7,229,662		288,328		(65,894)		7,452,096
Three months ended June 30, 2021:	Three months ended June 30, 2021:									Three months ended June 30, 2021:
Revenues	Revenues	$	359,058	1,016		$	0	$	360,074	Revenues	$	359,058	$	1,016	$	—	$	360,074
Net income attributable to IDACORP, Inc.	Net income attributable to IDACORP, Inc.	68,822		1,201		0		70,023		Net income attributable to IDACORP, Inc.	68,822		1,201		—		70,023
Total assets as of June 30, 2021		7,006,991		250,549		(56,082)		7,201,458
Three months ended June 30, 2020:
Six months ended June 30, 2022:										Six months ended June 30, 2022:
Revenues	Revenues	$	317,666	$	1,100	$	0	$	318,766	Revenues	701,589		$	1,422	$	—	$	703,011
Net income attributable to IDACORP, Inc.	Net income attributable to IDACORP, Inc.	58,923		1,466		0		60,389		Net income attributable to IDACORP, Inc.	108,649		1,899		—		110,548
Six months ended June 30, 2021:	Six months ended June 30, 2021:									Six months ended June 30, 2021:
Revenues	Revenues	$	674,625	$	1,502	$	0	$	676,127	Revenues	674,625		$	1,502	$	—	$	676,127
Net income attributable to IDACORP, Inc.	Net income attributable to IDACORP, Inc.	113,191		1,663		0		114,854		Net income attributable to IDACORP, Inc.	113,191		1,663		—		114,854
Six months ended June 30, 2020:
Revenues		$	608,154	$	1,620	$	0	$	609,774
Net income attributable to IDACORP, Inc.		95,700		2,179		0		97,879

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~~13.~~15. CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME

The table below presents changes in components of accumulated other comprehensive income (AOCI), net of tax, during the three and six months ended June 30, ~~2021~~2022 and ~~2020~~2021 (in thousands). Items in parentheses indicate charges to AOCI.


		Defined Benefit Pension Items				Defined Benefit Pension Items					Defined Benefit Pension Items				Defined Benefit Pension Items
		Three months ended June 30,				Six months ended June 30,					Three months ended June 30,				Six months ended June 30,
		2021		2020		2021		2020			2022		2021		2022		2021
Balance at beginning of period	Balance at beginning of period	$	(42,522)	$	(35,537)	$	(43,358)	$	(36,284)	Balance at beginning of period	$	(39,203)	$	(42,522)	$	(40,040)	$	(43,358)
Amounts reclassified out of AOCI	Amounts reclassified out of AOCI	836		747		1,672		1,494		Amounts reclassified out of AOCI	837		836		1,674		1,672
Balance at end of period	Balance at end of period	$	(41,686)	$	(34,790)	$	(41,686)	$	(34,790)	Balance at end of period	$	(38,366)	$	(41,686)	$	(38,366)	$	(41,686)

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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, ~~2021~~2022 and ~~2020~~2021 (in thousands). Items in parentheses indicate increases to net income.


		Amount Reclassified from AOCI									Amount Reclassified from AOCI
Details About AOCI	Details About AOCI	Three months ended June 30,				Six months ended June 30,				Details About AOCI	Three months ended June 30,				Six months ended June 30,
		2021		2020		2021		2020			2022		2021		2022		2021
Amortization of defined benefit pension items(1)	Amortization of defined benefit pension items(1)									Amortization of defined benefit pension items(1)
Prior service cost	Prior service cost	$	74	$	73	$	148	$	145	Prior service cost	$	69	$	74	$	139	$	148
Net loss	Net loss	1,052		933		2,103		1,867		Net loss	1,058		1,052		2,115		2,103
Total before tax	Total before tax	1,126		1,006		2,251		2,012		Total before tax	1,127		1,126		2,254		2,251
Tax benefit(2)	Tax benefit(2)	(290)		(259)		(579)		(518)		Tax benefit(2)	(290)		(290)		(580)		(579)

Total reclassification for the period, net of tax	Total reclassification for the period, net of tax	$	836	$	747	$	1,672	$	1,494	Total reclassification for the period, net of tax	$	837	$	836	$	1,674	$	1,672

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

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

~~14.~~16. CHANGES IN IDAHO POWER RETAINED EARNINGS

The table below presents changes in Idaho Power retained earnings during the three and six months ended June 30, ~~2021~~2022 and ~~2020~~2021 (in thousands).


		Three months ended June 30,				Six months ended June 30,					Three months ended June 30,				Six months ended June 30,
		2021		2020		2021		2020			2022		2021		2022		2021
Balance at beginning of period	Balance at beginning of period	$	1,607,583	$	1,506,629��	$	1,599,155	$	1,503,805	Balance at beginning of period	$	1,704,320	$	1,607,583	$	1,696,304	$	1,599,155
Net income	Net income	68,822		58,923		113,191		95,700		Net income	62,435		68,822		108,649		113,191
Dividends to parent	Dividends to parent	(36,031)		(33,986)		(71,972)		(67,939)		Dividends to parent	(38,120)		(36,031)		(76,318)		(71,972)
Balance at end of period	Balance at end of period	$	1,640,374	$	1,531,566	$	1,640,374	$	1,531,566	Balance at end of period	$	1,728,635	$	1,640,374	$	1,728,635	$	1,640,374

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the shareholders and the Board of Directors of IDACORP, Inc.

Results of Review of Interim Financial Information

We have reviewed the accompanying condensed consolidated balance sheet of IDACORP, Inc. and subsidiaries (the “Company”) as of June 30, ~~2021,~~2022, the related condensed consolidated statements of income, comprehensive income, and equity for the three-month and six-month periods ended June 30, ~~2021~~2022 and ~~2020,~~2021, and of cash flows for the six-month periods ended June 30, ~~2021~~2022 and ~~2020,~~2021, and the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial information for it to be in conformity with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheet of the Company as of December 31, ~~2020,~~2021, and the related consolidated statements of income, comprehensive income, equity, and cash flows for the year then ended (not presented herein); and in our report dated February ~~18, 2021,~~17, 2022, 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, ~~2020,~~2021, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

Basis for Review Results

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

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

/s/ DELOITTE & TOUCHE LLP

Boise, Idaho

~~July 29, 2021~~August 4, 2022

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

Results of Review of Interim Financial Information

We have reviewed the accompanying condensed consolidated balance sheet of Idaho Power Company and subsidiary (the “Company”) as of June 30, ~~2021,~~2022, the related condensed consolidated statements of income and comprehensive income for the three-month and six-month periods ended June 30, ~~2021~~2022 and ~~2020,~~2021, and of cash flows for the six-month periods ended June 30, ~~2021~~2022 and ~~2020,~~2021, and the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial information for it to be in conformity with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheet of the Company as of December 31, ~~2020,~~2021, and the related consolidated statements of income, comprehensive income, retained earnings, and cash flows for the year then ended (not presented herein); and in our report dated February ~~18, 2021,~~17, 2022, 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, ~~2020,~~2021, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

Basis for Review Results

/s/ DELOITTE & TOUCHE LLP

Boise, Idaho

~~July 29, 2021~~August 4, 2022

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

AND RESULTS OF OPERATIONS

In Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) in this report, the general financial condition and results of operations for IDACORP, Inc. and its subsidiaries (collectively, IDACORP) and Idaho Power Company and its subsidiary (collectively, Idaho Power) are discussed. While reading the MD&A, please refer to the accompanying condensed consolidated financial statements of IDACORP and Idaho Power. Also refer to "Cautionary Note Regarding Forward-Looking Statements" in this report for important information regarding forward-looking statements made in this MD&A and elsewhere in this report. This discussion updates the MD&A included in IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, ~~2020 (2020~~2021 (2021 Annual Report), and should also be read in conjunction with the information in that report. The results of operations for an interim period generally will not be indicative of results for the full year, particularly in light of the seasonality of Idaho Power's sales volumes, as discussed below.

INTRODUCTION

IDACORP is a holding company formed in 1998 whose principal operating subsidiary is Idaho Power. IDACORP’s common stock is listed and trades on the New York Stock Exchange under the trading symbol "IDA". Idaho Power is an electric utility whose rates and other matters are regulated by the Idaho Public Utilities Commission (IPUC), Public Utility Commission of Oregon (OPUC), and Federal Energy Regulatory Commission (FERC). Idaho Power generates revenues and cash flows primarily from the sale and distribution of electricity to customers in its Idaho and Oregon service areas, as well as from the wholesale sale and transmission of electricity. Idaho Power experiences its highest retail energy sales during the summer irrigation and cooling season, with a lower peak in the winter that generally results from heating demand.

Idaho Power 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 (Jim Bridger plant) owned in part by Idaho Power. IDACORP’s other significant subsidiaries include IDACORP Financial Services, Inc., an investor in affordable housing and other real estate tax credit investments, and Ida-West Energy Company, an operator of small hydropower generation projects that satisfy the requirements of the Public Utility Regulatory Policies Act of 1978 (PURPA).

EXECUTIVE OVERVIEW

Management's Outlook and Company Initiatives

In the ~~2020~~2021 Annual Report, IDACORP's and Idaho Power's management included a ~~brief overview~~summary of their business strategies for the companies for ~~2021~~2022 and beyond, under the heading "Executive Overview" in the MD&A. As of the date of this report, management's outlook and strategy remain consistent with that ~~discussion.~~discussion, as updated by some of the discussion in this MD&A. Most notably:

•Idaho Power continues to execute on its four strategic areas and initiatives: growing financial strength, improving Idaho Power's core business, enhancing Idaho Power's brand, and focusing on safety and employee engagement.

•Idaho Power continues to expect positive customer growth in its service area. During the first six months of ~~2021,~~2022, Idaho Power's customer count grew by over ~~8,500~~7,600 customers, and for the twelve months ended June 30, ~~2021,~~2022, the customer growth rate was ~~2.9~~2.6 percent. On June 30, 2021, a new all-time system peak demand of 3,751 MW was set, exceeding the previous high of 3,422 MW set on July 7, 2017. The previous high from July 2017 was exceeded multiple times during the heat wave in Idaho Power's service area in June and July of 2021.

•Idaho Power anticipates substantial capital investments, with expected total capital expenditures of ~~approximately $2.0~~up to $2.8 billion over the five-year period from ~~2021~~2022 (including the expenditures incurred ~~so far~~to-date in ~~2021)~~2022) through ~~2025.~~2026.

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

•Idaho Power is committed to continuing to provide reliable, affordable, safe service to its customers while furthering its environmental, social, and governance initiatives, including the "Clean Today. Cleaner Tomorrow.®" goal to provide Idaho Power's customers with ~~100-percent~~100 percent clean energy by 2045, as well as water stewardship and environmental projects, and the company’s ~~diversity, equity,~~workforce recruiting, retention, and ~~inclusion~~connection initiatives.

~~Coronavirus (COVID-19) Response and Impacts~~Notable for the second quarter, in June 2022, the IPUC issued an order approving Idaho Power’s amended application requesting authorization to recover costs associated with its plan to cease participation in coal-fired operations at the Jim Bridger plant by 2028 (Bridger Order). For more information on the Bridger Order, see "Regulatory Matters" in this MD&A.

In response to the COVID-19 pandemic, in 2020 Idaho Power implemented its emergency management, business continuity, and enterprise pandemic plans. Idaho Power's internal emergency management team responded in accordance with the plans in an effort to ensure Idaho Power continues to provide reliable service to its customers during the pandemic. Idaho Power's

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provision of electricity to customers through its power supply, transmission, and distribution operations, as of the date of this report, continues largely uninterrupted. For more information about Idaho Power's response to the COVID-19 pandemic and the effects of COVID-19 on Idaho Power, see Part II - Item 7 - "Executive Overview" in the MD&A in the 2020 Annual Report. For a discussion of certain risks to IDACORP and Idaho Power as a result of the pandemic, see Part II - Item 1A - "Risk Factors" in the 2020 Annual Report.

Summary of Financial Results

The following is a summary of Idaho Power's net income, net income attributable to IDACORP, and IDACORP's earnings per diluted share for the three and six months ended June 30, ~~2021~~2022 and ~~2020~~2021 (in thousands, except earnings per share amounts):


		Three months ended June 30,				Six months ended June 30,					Three months ended June 30,				Six months ended June 30,
		2021		2020		2021		2020			2022		2021		2022		2021
Idaho Power net income	Idaho Power net income	$	68,822	$	58,923	$	113,191	$	95,700	Idaho Power net income	$	62,435	$	68,822	$	108,649	$	113,191
Net income attributable to IDACORP, Inc.	Net income attributable to IDACORP, Inc.	$	70,023	$	60,389	$	114,854	$	97,879	Net income attributable to IDACORP, Inc.	$	64,287	$	70,023	$	110,548	$	114,854
Weighted average outstanding shares – diluted	Weighted average outstanding shares – diluted	50,622		50,567		50,601		50,547		Weighted average outstanding shares – diluted	50,687		50,622		50,673		50,601
IDACORP, Inc. earnings per diluted share	IDACORP, Inc. earnings per diluted share	$	1.38	$	1.19	$	2.27	$	1.94	IDACORP, Inc. earnings per diluted share	$	1.27	$	1.38	$	2.18	$	2.27

The table below provides a reconciliation of net income attributable to IDACORP for the three and six months ended June 30, ~~2021,~~2022, from the same ~~period~~periods in ~~2020~~2021 (items are in millions and are before related income tax impact unless otherwise noted).


		Three months ended			Six months ended				Three months ended			Six months ended
Net income attributable to IDACORP, Inc. - June 30, 2020			$	60.4		$	97.9
Net income attributable to IDACORP, Inc. - June 30, 2021								Net income attributable to IDACORP, Inc. - June 30, 2021		$	70.0		$	114.9
Increase (decrease) in Idaho Power net income:	Increase (decrease) in Idaho Power net income:							Increase (decrease) in Idaho Power net income:
Customer growth, net of associated power supply costs and power cost adjustment mechanisms	Customer growth, net of associated power supply costs and power cost adjustment mechanisms	3.9			7.6			Customer growth, net of associated power supply costs and power cost adjustment mechanisms	2.7			5.8
Usage per retail customer, net of associated power supply costs and power cost adjustment mechanisms	Usage per retail customer, net of associated power supply costs and power cost adjustment mechanisms	22.9			20.5			Usage per retail customer, net of associated power supply costs and power cost adjustment mechanisms	(25.9)			(15.8)
Idaho fixed cost adjustment (FCA) revenues	Idaho fixed cost adjustment (FCA) revenues	(5.1)			(5.0)			Idaho fixed cost adjustment (FCA) revenues	6.3			0.4
Retail revenues per megawatt-hour (MWh), net of associated power supply costs and power cost adjustment mechanisms	Retail revenues per megawatt-hour (MWh), net of associated power supply costs and power cost adjustment mechanisms	(6.8)			(6.1)			Retail revenues per megawatt-hour (MWh), net of associated power supply costs and power cost adjustment mechanisms	3.9			4.7
Transmission wheeling-related revenues	Transmission wheeling-related revenues	3.9			8.0			Transmission wheeling-related revenues	2.9			4.9

Other operations and maintenance (O&M) expenses	Other operations and maintenance (O&M) expenses	(5.3)			(1.2)			Other operations and maintenance (O&M) expenses	(12.0)			(18.5)

Depreciation expense								Depreciation expense	8.8			7.7
Other changes in operating revenues and expenses, net	Other changes in operating revenues and expenses, net	(0.4)			(1.2)			Other changes in operating revenues and expenses, net	2.5			(0.1)

Increase in Idaho Power operating income		13.1			22.6
Decrease in Idaho Power operating income								Decrease in Idaho Power operating income	(10.8)			(10.9)

Non-operating income and expenses		1.0			0.6
Non-operating expense, net								Non-operating expense, net	2.4			5.1

Income tax expense	Income tax expense	(4.2)			(5.7)			Income tax expense	2.1			1.3
Total increase in Idaho Power net income			9.9			17.5
Total decrease in Idaho Power net income								Total decrease in Idaho Power net income		(6.3)			(4.5)
Other IDACORP changes (net of tax)	Other IDACORP changes (net of tax)		(0.3)			(0.5)		Other IDACORP changes (net of tax)		0.6			0.1
Net income attributable to IDACORP, Inc. - June 30, 2021			$	70.0		$	114.9
Net income attributable to IDACORP, Inc. - June 30, 2022								Net income attributable to IDACORP, Inc. - June 30, 2022		$	64.3		$	110.5

Net Income - Second Quarter ~~2021~~2022

IDACORP's net income ~~increased $9.6~~decreased $5.7 million for the second quarter of ~~2021~~2022 compared with the second quarter of ~~2020,~~2021, due primarily ~~due~~ to ~~higher~~lower net income at Idaho Power. ~~Customer~~At Idaho Power, customer growth increased operating income by ~~$3.9~~$2.7 million in the second quarter of ~~2021~~2022 compared with the second quarter of ~~2020,~~2021, as the number of Idaho Power customers grew by ~~over 16,900,~~approximately 15,500, or ~~2.9~~2.6 percent, during the twelve months ended June 30, ~~2021. Higher~~2022. Lower sales volumes on a per-customer basis in all customer classes ~~increased~~decreased operating income by ~~$22.9 million as warmer~~$25.9 million. Milder weather and ~~drier weather caused customers to use more energy for cooling or irrigation~~greater precipitation in the second quarter of ~~2021~~2022 when compared with the second quarter of ~~2020. Increases in usage~~2021 led customers to use less energy per ~~commercial~~customer for irrigation pumping and ~~industrial customers were partially due to a return to more normal economic activity in~~air conditioning. The revenue impact of the ~~second quarter of 2021 compared with the second quarter of 2020, which was affected by negative COVID-19-related business conditions. The increase~~decrease in sales volumes per customer was partially offset by the FCA mechanism (applicable to residential and small general service customers), which ~~decreased~~increased revenues in the second quarter of ~~2021~~2022 by ~~$5.1~~$6.3 million compared with the second quarter of ~~2020.~~2021.

~~Table of Contents~~

The net ~~decrease~~increase in retail revenues per MWh, net of associated power supply costs and power cost adjustment mechanisms, ~~decreased~~increased operating income by $6.8 million during the second quarter of 2021 compared with the second quarter of 2020. In the second quarter of 2021, higher wholesale energy market prices due to a heat wave in the western United States and higher energy usage by Idaho Power customers increased Idaho Power's net power supply expenses. The increase in the amount of net power supply expenses that were not deferred through Idaho Power's power cost adjustment mechanisms was the primary cause of the negative variance in net retail revenues per MWh between the comparison periods.

~~Transmission wheeling-related revenues increased~~ $3.9 million during the second quarter of ~~2021~~2022 compared with the second quarter of ~~2020 as~~2021 due partially to the ~~warmer, drier~~rate-related impact of monthly fixed charges being allocated over fewer MWh from the lower usage per customer, particularly among irrigation customers, described above. Also, a June 1, 2022 rate increase for Idaho Power’s Idaho

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retail customers related to the Bridger Order increased retail revenues per MWh during the second quarter of 2022 compared with the second quarter of 2021. For more information on the Bridger Order, see "Regulatory Matters" in this MD&A.

Transmission wheeling-related revenues increased $2.9 million during the second quarter of 2022 compared with the second quarter of 2021. Warmer weather in the ~~western~~southwest United States and milder weather in the Pacific Northwest during the second quarter of 2022 compared with the second quarter of 2021 led to a price spread between energy market hubs. This price spread increased third-party wheeling ~~volumes.~~activity across Idaho Power's transmission system for transmission wheeling customers to access these markets in the second quarter of 2022 compared with the second quarter of 2021. Also, Idaho Power's open access transmission tariff (OATT) rates were approximately 104 percent higher in the second quarter of ~~2021~~2022 compared with the second quarter of ~~2020.~~2021.

Other O&M expenses ~~were $5.3~~increased $12.0 million ~~higher~~ in the second quarter of ~~2021~~2022 compared with the second quarter of ~~2020, primarily~~2021 due to maintenance activities at the ~~timing~~Jim Bridger coal plant, Langley Gulch natural gas plant, and American Falls hydropower project. Most of ~~performing certain~~those maintenance ~~projects at Idaho Power's jointly-owned thermal generation plants~~activities are performed as scheduled maintenance, but not annually. Also, an increase in ~~2021 instead of~~performance-based variable compensation accruals and inflationary pressures on labor-related costs, professional services, vehicle fuel, and supplies contributed to the increase in ~~2020. Also,~~ other O&M expenses ~~increased~~ in the second quarter of ~~2021~~2022 compared with the second quarter of 2021.

Depreciation expense decreased $8.8 million due primarily to the impacts of the Bridger Order from the IPUC authorizing Idaho Power to accelerate depreciation on, earn a return on, and recover through 2030 the net book value of coal-related assets at Idaho Power's jointly-owned Jim Bridger plant as of December 31, 2020, plus forecasted plant investments. The Bridger Order resulted in Idaho Power recording the deferral of certain depreciation expense in the second quarter of 2022. Idaho Power plans to cease participation in all coal-related operations at the Jim Bridger plant by 2028. Idaho Power expects the Bridger Order to increase operating revenues, net depreciation expense, and income tax expense in future periods and estimates the impacts of the Bridger Order will increase net income by approximately $10 million in 2023. Idaho Power expects the ongoing annual benefit to net income from the Bridger Order to decline each year through 2030, primarily due to the annual decline in Jim Bridger plant coal-related rate base, which Idaho Power expects to be fully depreciated by December 31, 2030. The Bridger Order is described more fully in the "Regulatory Matters" section of this MD&A.

Net non-operating expense decreased $2.4 million in the second quarter of 2022 compared with the second quarter of 2021. Allowance for funds used during construction (AFUDC) increased as the average construction work in progress balance was higher throughout the second quarter of 2022 compared with the second quarter of 2021 and, to a ~~result of an increase in labor-related costs from~~lesser extent, higher ~~performance-based variable compensation accruals.~~market interest rates led to higher interest income.

~~The increase in~~

Idaho Power income tax expense for the second quarter of ~~2021~~2022 decreased by $2.1 million compared with the second quarter of ~~2020 was~~2021, primarily due to ~~greater 2021~~lower pre-tax income.

Net Income - ~~Year-to-Date 2021~~Year-To-Date 2022

IDACORP's net income ~~increased $17.0~~decreased $4.4 million for the first half of ~~2021~~2022 compared with the first half of ~~2020,~~2021, due primarily ~~due~~ to ~~higher~~lower net income at Idaho Power. At Idaho Power, increases in sales volumes among all customer classes, except for irrigation customers, were due primarily to customer growth. Customer growth increased operating income by ~~$7.6~~$5.8 million. Lower sales volumes on a per-customer basis, almost entirely related to irrigation customers, decreased operating income by $15.8 million in the first six months of 2022 compared with the same period of 2021. Milder weather and greater precipitation in Idaho Power's service area during the late spring and early summer when compared with the same seasons in 2021 led customers to use less energy per customer for irrigation pumping and, to a lesser extent, air conditioning. Higher sales per residential customer for heating from colder winter weather during the first quarter of 2022 were offset by weather-related declines in residential usage during the second quarter of 2022.

The increase in retail revenues per MWh, net of associated power supply costs and power cost adjustment mechanisms, increased operating income by $4.7 million during the first half of 2022 compared with the first half of 2021, due partially to the rate-related impact of monthly fixed charges being allocated over fewer MWh from the lower usage per customer, particularly among irrigation customers, described above. Also, a June 1, 2022 rate increase for Idaho Power’s Idaho retail customers related to the Bridger Order increased retail revenues per MWh during the first half of 2022 compared with the first half of 2021.

Transmission wheeling-related revenues increased $4.9 million during the first half of 2022 compared with the first half of 2021. Warmer weather in the southwest United States and milder weather in the Pacific Northwest during the second quarter of 2022 compared with the second quarter of 2021 led to a price spread between energy market hubs. This price spread increased

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wheeling activity across Idaho Power's transmission system for wheeling customers to access these markets in the first half of 2022 compared with the first half of 2021. In addition, two new long-term wheeling agreements executed in April 2021 contributed to increased wheeling volumes during the first half of 2022 compared with the same period in 2021. Also, Idaho Power's OATT rates were approximately 4 percent higher in the first half of 2022 compared with the first half of 2021.

Other O&M expenses increased $18.5 million in the first half of ~~2021~~2022 compared with the first half of ~~2020. An~~2021, due largely to maintenance activities at the Jim Bridger coal plant, Langley Gulch natural gas plant, and American Falls hydropower project. Also, an increase in ~~sales volumes~~performance-based variable compensation accruals and inflationary pressures on ~~a per-customer basis increased operating income by $20.5 million due primarily~~labor-related costs, professional services, vehicle fuel, and supplies contributed to ~~warmer and drier weather that caused customers to use more energy for cooling or irrigation~~the increase in other O&M expenses in the first half of 2021 compared with 2020. To a lesser extent, a return to more normal economic conditions for commercial and industrial customers in the first half of 2021 compared with 2020, also increased sales volumes on a per-customer basis, as the first half of 2020 was affected by negative COVID-19-related business conditions. The increase in sales volumes per customer was partially offset by the FCA mechanism (applicable to residential and small general service customers), which decreased revenues by $5.0 million.

The net decrease in retail revenues per MWh in the first half of 2021 compared to the first half of 2020, decreased operating income by $6.1 million primarily due to higher power supply costs. In the second quarter of 2021, higher wholesale energy market prices due to a heat wave in the western United States and higher energy usage by Idaho Power customers increased Idaho Power's net power supply expenses. The increase in the amount of net power supply expenses that were not deferred through Idaho Power's power cost adjustment mechanisms was the primary cause of the negative variance in net retail revenues per MWh between the comparison periods.

~~During the first half of 2021, transmission wheeling-related revenues increased $8.0 million~~2022 compared with the first half of 2021.

Depreciation expense decreased $7.7 million, due primarily to the impact of the Bridger Order described above in this MD&A, which authorized Idaho Power to accelerate the depreciation on and recover through 2030 the net book value of coal-related assets at Idaho Power's jointly-owned Jim Bridger plant as of December 31, 2020, plus forecasted plant investments.

Non-operating expense, net, decreased $5.1 million in the first half of 2022 compared with the first half of 2021. AFUDC increased as the ~~warmer and drier weather~~average construction work in the western United States caused customers in the region to use more energy for cooling or irrigation, as applicable, which increased wheeling volumes. Colder winter weather in the southwest United States during the first quarter of 2021 also contributed to increased wheeling volumes inprogress balance was higher throughout the first six months of ~~2021~~2022 compared with the first six months of ~~2020. In addition,~~2021. Also, interest income increased due to higher market interest rates, and investment income increased related to life insurance claims in the rabbi trust for Idaho Power's ~~OATT rates were approximately 10 percent higher~~nonqualified defined benefit pension plans, in the first ~~six months~~half of ~~2021~~2022 compared with the first ~~six months~~half of ~~2020.~~2021.

~~The increase in~~Idaho Power income tax expense for the first half of ~~2021~~2022 decreased by $1.3 million compared with the first half of ~~2020 was~~2021, primarily due to ~~greater 2021~~lower pre-tax income.

Based on its estimate of full-year 2021 return on year-end equity in the Idaho jurisdiction (Idaho ROE), in the first half of 2021 Idaho Power recorded no additional accumulated deferred investment tax credits (ADITC) amortization or any provision against revenues for sharing of earnings with customers under the Idaho regulatory settlement stipulation approved in May 2018.

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

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

•Rate Base Growth and Infrastructure Investment: The rates established by the IPUC and OPUC are determined with the intent to provide an opportunity for Idaho Power to recover authorized operating expenses and depreciation and earn a reasonable return on “rate base.” Rate base is generally determined by reference to the original cost (net of accumulated depreciation) of utility plant in service and certain other assets, subject to various adjustments for deferred income taxes and other items. Over time, rate base is increased by additions to utility plant in service and reduced by depreciation and retirement of utility plant and write-offs as authorized by the IPUC and OPUC. Idaho Power is pursuing significant enhancements to its utility infrastructure in an effort to maintain system reliability, ensure an adequate supply of electricity, and provide service to new customers, including major ongoing transmission projects such as the Boardman-to-Hemingway and Gateway West projects. Idaho Power's existing hydropower and thermal generation facilities also require continuing upgrades and equipment replacement, and the company is undertaking a significant relicensing effort for the Hells Canyon Complex (HCC), its largest hydropower generation resource. Idaho Power intends to pursue timely inclusion of any significant completed capital projects into rate base as part of a future general rate case or other appropriate regulatory proceeding.

Growth in customers and peak demand for electricity will require Idaho Power to continue to enhance its power supply, transmission, and distribution infrastructure. While demand varies and is based on numerous factors, Idaho Power's 2021 Integrated Resource Plan (IRP) indicated Idaho Power may have a resource capacity deficit for peak energy demand of 101 megawatts (MW) in 2023, an additional 85 MW deficit in 2024, and an additional 125 MW deficit in 2025. To help meet peak demand in 2023, Idaho Power has entered into contracts to purchase, own, and operate 120 MW of battery storage assets, and also entered into a 20-year power purchase agreement signed in February 2022 for the output of a planned third-party 40-MW solar facility. In March 2022, Idaho Power filed an application with the IPUC requesting approval of a revised special contract for electric service between Idaho Power and its existing customer Micron Technology, Inc. (Micron) under which Micron would purchase from Idaho Power the energy generated by the solar facility.

To help address the capacity deficits projected for 2024 and 2025, Idaho Power has been pursuing multiple options and issued a request for proposals (RFP) in December 2021. Depending on RFP results, timing of project in-service dates, and the outcome of regulatory proceedings, Idaho Power expects it could invest over $400 million in capital expenditures from 2022 through 2025 for resource additions to help meet the projected capacity deficits noted above.

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For more information on the 2021 IRP, including the load forecast assumptions Idaho Power used in its 2021 IRP, refer to "Resource Planning" in Item 1 - "Business" in Idaho Power's 2021 Annual Report. For more information about forecasted capital expenditures and expected rate base growth, see the "Liquidity and Capital Resources" section of this MD&A.

•Regulation of Rates and Cost Recovery: The prices that Idaho Power is authorized to charge for its electric and transmission service is a critical factor in determining IDACORP's and Idaho Power's results of operations and financial condition. Those rates are established by state regulatory commissions and the FERC and are intended to allow Idaho Power an opportunity to recover its expenses and earn a reasonable return on investment. Idaho Power focuses on timely recovery of its costs through filings with its regulators, working to put in place innovative regulatory mechanisms, and ~~on the~~ prudent management of expenses and investments. Idaho Power has a regulatory settlement stipulation in Idaho that includes provisions for the accelerated amortization of ~~certain~~accumulated deferred investment tax credits (ADITC) to help achieve a minimum 9.4 percent ~~Idaho ROE.~~Idaho-jurisdiction return on year-end equity (Idaho ROE). The settlement stipulation also provides for the potential sharing between Idaho Power and its Idaho customers of Idaho-jurisdictional earnings in excess of 10.0 percent of Idaho ROE. The settlement stipulation has no expiration date but the minimum Idaho ROE would revert back to 95 percent of the allowed return on equity in the next Idaho general rate case. The specific terms of the settlement stipulation are described in Note 3 - "Regulatory Matters" to the consolidated financial statements included in the ~~2020~~2021 Annual Report. With Idaho Power’s anticipated significant infrastructure investments, including those that are intended to help meet projected near-term capacity deficits, Idaho Power ~~will continue~~believes that the appropriate time to ~~assess~~file general rate cases in both Idaho and Oregon is approaching. The expected increase in rate-base eligible assets as these projects are placed into service, along with the significant amounts of capital expenditures Idaho Power has made since its last general rate case filed in 2011, impact Idaho Power’s need to file, and the timing of, general rate cases. In Idaho, Idaho Power is required to file a notice of its intent to file a general rate case ~~to reset base rates but does not anticipate~~with the IPUC at least 60 days before filing an application for a general rate case, and Idaho Power expects the processing of a general rate case in ~~the next twelve~~Idaho would span at least seven months before new rates would be in effect. In Oregon, Idaho Power expects that processing of a general rate case would take approximately ten months.

•Economic Conditions and ~~Loads:~~Loads: Economic conditions impact consumer demand for energy, revenues, collectability of accounts, the volume of wholesale energy sales, and the need to construct and improve infrastructure, purchase power, and implement programs to meet customer load demands. In recent years, Idaho Power has seen significant growth in the number of customers in its service area. Over the twelve months ended June 30, ~~2021,~~2022, Idaho Power's customer count grew by ~~2.9~~2.6 percent. For Idaho Power, a new all-time system peak demand of 3,751 MW was set on June 30, 2021, exceeding the previous high of 3,422 MW set on July 7, 2017. The previous peak demand from July 2017 was exceeded multiple times during the heat wave in Idaho Power's service area in June and July of 2021. Idaho Power expects its number of customers to continue to increase in the foreseeable future. Idaho Power also expects that existing and sustained ~~future customer~~ growth in customers and ~~an increasing~~ peak demand for electricity will require Idaho Power to continue to enhance its ~~distribution~~capacity resources, transmission, and ~~transmission system~~distribution infrastructure, including the Boardman-to-Hemingway ~~project.~~and Gateway West transmission projects and the capacity and energy resources contemplated by the RFPs described above in this MD&A. That growth ~~and peak demand may also result~~has resulted in the need for Idaho Power to procure ~~other new~~additional sources of energy and capacity to serve growing demand and to maintain system ~~reliability.~~reliability, as noted above. Further, recent changes in the regional transmission markets have constrained the transmission system external to Idaho Power's service area and impacted Idaho Power's ability to import energy from energy markets in the western United ~~States.~~States during peak load periods. In order to meet growth in its service area, Idaho Power ~~expects~~relies on numerous vendors to ~~need approximately 80 MW of additional capacity as early as the summer of 2023. On June 30, 2021,~~provide goods and services, and economic conditions have resulted in inflationary cost increases and supply chain constraints for numerous goods and services. Idaho Power ~~issued a formal request for proposals for up to 80MW of new resources~~has taken measures to help ~~meet peak electric energy needs in 2023. Idaho Power is analyzing options for potential energy~~ensure the availability of supply chain-constrained items, such as distribution transformers and ~~capacity resource procurement, while at the same time working on its 2021 Integrated Resources Plan.~~other electrical apparatus that are needed to serve new and existing customers, as it confronts continued strong customer growth amid an uncertain national and global economic environment.

•Weather Conditions: Weather and agricultural growing conditions have a significant impact on Idaho Power's energy 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 of each year, irrigation customers use electricity to operate irrigation pumps, and weather conditions can impact the timing and extent of use of those pumps. Idaho Power also has tiered rates and seasonal rates, which contribute to increased revenues during higher-load periods, most notably during the third quarter of each year when overall customer demand is highest. Much of the adverse or favorable impact of weather on sales of energy to residential and small commercial customers is mitigated through the Idaho FCA mechanism, which is described in Note 3 - "Regulatory Matters" to the condensed consolidated financial statements included in this report.

Further, as Idaho Power's hydropower facilities comprise over one-half of Idaho Power's nameplate generation capacity, precipitation levels impact the mix of Idaho Power's generation resources. When hydropower generation

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decreases, Idaho Power must rely on more expensive generation sources and purchased power. When favorable hydropower generating conditions exist for Idaho Power, they also may exist for other Pacific Northwest hydropower facility operators, lowering regional wholesale market prices and impacting the revenue Idaho Power receives from wholesale energy sales. Much of the adverse or favorable impact of this volatility is addressed through the Idaho and Oregon power cost adjustment mechanisms. For ~~2021,~~2022, due to relatively low reservoir storage carryover combined with the year's snowpack conditions, precipitation levels, and timing of run-off, Idaho Power expects generation from its hydropower resources to be in the range of 5.0 to 6.0 million MWh, compared with 30-year average total annual hydropower generation of approximately 7.7 million ~~MWh over the last 30 years.~~

•~~Rate Base Growth and Infrastructure Investment:~~ As noted above, the rates established by the IPUC and OPUC are determined with the intent to provide an opportunity for Idaho Power to recover authorized operating expenses and depreciation and earn a reasonable return on “rate base.” Rate base is generally determined by reference to the original cost (net of accumulated depreciation) of utility plant in service and certain other assets, subject to various adjustments

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for deferred taxes and other items. Over time, rate base is increased by additions to utility plant in service and reduced by depreciation and retirement of utility plant and write-offs as authorized by the IPUC and OPUC. Idaho Power is pursuing significant enhancements to its utility infrastructure in an effort to maintain system reliability, ensure an adequate supply of electricity, and to provide service to new customers, including major ongoing transmission projects such as the Boardman-to-Hemingway and Gateway West projects. Idaho Power's existing hydropower and thermal generation facilities also require continuing upgrades and equipment replacement, and the company is undertaking a significant relicensing effort for the Hells Canyon Complex (HCC), its largest hydropower generation resource. Idaho Power intends to pursue timely inclusion of any significant completed capital projects into rate base as part of a future general rate case or other appropriate regulatory proceeding.MWh.

•Mitigation of Impact of Fuel and Purchased Power Expense: In addition to hydropower generation, Idaho Power relies significantly on natural gas and coal to fuel its generation facilities and on power purchases in the wholesale markets. Fuel costs are impacted by electricity sales volumes, the terms and conditions of contracts for fuel, Idaho Power's generation capacity, the availability of hydropower generation resources, transmission capacity, energy market prices, and Idaho Power's hedging program for managing fuel costs. Purchased power costs are impacted by the terms and conditions of contracts for purchased power, the rate of expansion of alternative energy generation sources such as wind or solar energy, hydropower generation resource maintenance outages, and wholesale energy market prices. The Idaho and Oregon power cost adjustment mechanisms mitigate in large part the potential adverse impacts to Idaho Power of fluctuations in power supply costs.

•Regulatory and Environmental Compliance Costs: Idaho Power is subject to extensive federal and state laws, policies, and regulations, as well as regulatory actions and audits by agencies and quasi-governmental agencies, including the FERC, the North American Electric Reliability Corporation, and the Western Electricity Coordinating Council. Compliance with these requirements directly influences Idaho Power's operating environment and affects Idaho Power's operating costs. ~~Recently, energy~~Energy industry regulators ~~have issued~~may issue substantial penalties for utilities alleged to have violated reliability and critical infrastructure protection requirements. Moreover, environmental laws and regulations, in particular, may increase the cost of constructing new facilities, ~~and transmission projects,~~ may increase the cost of operating generation ~~plants, including Idaho Power's jointly-owned coal-fired generating~~ plants, may require that Idaho Power install additional pollution control devices at existing generating plants, may result in penalties for non-compliance, even where inadvertent, or may require that Idaho Power curtail or cease operating certain generation plants. Idaho Power expects to spend significant amounts on environmental compliance and controls in the next decade. Due to economic factors in part associated with the costs of compliance with environmental regulation, Idaho Power accelerated the retirement date of its jointly-owned coal-fired generating plant in Valmy, Nevada ~~(Valmy)~~(Valmy plant), ceasing operations at one unit in ~~2019. In April 2021, Idaho Power filed an application with~~2019 and planning to cease operations at the ~~IPUC requesting an acknowledgment that its~~remaining unit by year-end 2025 exit date from Valmy unit 2 is appropriate based on economics and reliability needs. In June 2021, Idaho Power filed an application with the IPUC requesting, among other things, authorization to accelerate depreciation for the Jim Bridger plant by end-of-year 2030. In addition,2025. Idaho Power's jointly-owned coal plant in Boardman, Oregon, ceased operations as planned in October 2020. In June 2022, the IPUC approved Idaho Power's request to allow the coal-related assets at the Jim Bridger plant to be fully depreciated and recovered by end-of-year 2030. The IPUC's Bridger Order related to Idaho Power's plan to cease participation in coal-related operations at the Jim Bridger plant by 2028 is described more fully in the "Regulatory Matters" section of this MD&A.

•Water Management and Relicensing of Hydropower Projects: Because of Idaho Power's reliance on stream flow in the Snake River and its tributaries, Idaho Power participates in numerous proceedings and venues that may affect its water rights, seeking to preserve the long-term availability of its rights for its hydropower projects. Also, Idaho Power is involved in renewing its long-term federal licenses for the HCC, its largest hydropower generation source, and for American Falls, its second largest hydropower generation source. Given the number of parties involved, Idaho Power's relicensing costs have been and are expected to continue to be substantial. Idaho Power cannot currently determine the ultimate terms of, and costs associated with, any resulting long-term ~~licenses.~~licenses for the HCC or American Falls facilities.

•Wildfire Mitigation Efforts: In recent years, in the western United States ~~there~~ has ~~been~~experienced an increasing trend in the degree of annual destruction from wildfires. A variety of factors have contributed in varying degrees to this trend including climate change, increased wildland-urban interfaces, historical land management practices, and overall wildland and forest health. While Idaho Power has not experienced to-date the extent of catastrophic wildfires within its service area that have occurred in California ~~Oregon,~~ and elsewhere in the western United States, Idaho Power is taking a proactive approach to wildfire threat ~~relative to~~in its service ~~area.~~area and transmission corridors. Idaho Power has ~~drafted~~adopted a Wildfire Mitigation Plan (WMP) that outlines actions Idaho Power is taking or is working to implement in the future to reduce wildfire risk and to strengthen the resiliency of its transmission and distribution system to wildfires. Idaho Power's approach to achieve these objectives includes identifying areas subject to elevated risk; system hardening programs, vegetation management, and field personnel practices to mitigate wildfire risk; incorporating current and forecasted weather and field conditions into operational practices; ~~evaluating a~~ public safety power shutoff ~~approach;~~protocols adopted in 2022; and evaluating the performance and effectiveness of the strategies identified in the WMP through metrics and monitoring. In June 2021, the IPUC authorized Idaho Power to defer, for future amortization, the Idaho jurisdictional share of ~~actual incremental~~

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actual incremental O&M expenses and depreciation expense of certain capital investments necessary to implement the ~~WMP, including incremental insurance costs, among other things.~~WMP. The WMP case with the IPUC is described in more detail in ~~Note 3 -~~the "Regulatory Matters" ~~to the condensed consolidated financial statements included in~~section of this ~~report.~~MD&A.

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, ~~2021.~~2022. In this analysis, the results for the three and six months ended June 30, ~~2021,~~2022, are compared with the same period in ~~2020.~~2021.

The table below presents Idaho Power’s energy sales and supply (in thousands of MWh) for the three and six months ended June 30, ~~2021~~2022 and ~~2020.~~2021.


		Three months ended June 30,		Six months ended June 30,			Three months ended June 30,		Six months ended June 30,
		2021	2020	2021	2020		2022	2021	2022	2021
Retail energy sales	Retail energy sales	4,098	3,594	7,467	6,913	Retail energy sales	3,648	4,098	7,273	7,467
Wholesale energy sales	Wholesale energy sales	67	489	188	671	Wholesale energy sales	121	67	149	188
Bundled energy sales	Bundled energy sales	34	110	245	272	Bundled energy sales	179	34	550	245
Total energy sales	Total energy sales	4,199	4,193	7,900	7,856	Total energy sales	3,948	4,199	7,972	7,900
Hydropower generation	Hydropower generation	1,449	2,275	2,875	3,881	Hydropower generation	1,602	1,449	2,866	2,875
Coal generation	Coal generation	372	810	908	1,272	Coal generation	777	372	1,595	908
Natural gas and other generation	Natural gas and other generation	666	89	1,307	727	Natural gas and other generation	179	666	638	1,307
Total system generation	Total system generation	2,487	3,174	5,090	5,880	Total system generation	2,558	2,487	5,099	5,090
Purchased power	Purchased power	1,949	1,305	3,346	2,526	Purchased power	1,723	1,949	3,504	3,346
Line losses	Line losses	(237)	(286)	(536)	(550)	Line losses	(333)	(237)	(631)	(536)
Total energy supply	Total energy supply	4,199	4,193	7,900	7,856	Total energy supply	3,948	4,199	7,972	7,900

Weather-related information for Boise, Idaho, for the three and six months ended June 30, ~~2021~~2022 and ~~2020,~~2021, is presented in the table below. 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 and is included for illustrative purposes.


		Three months ended June 30,			Six months ended June 30,				Three months ended June 30,			Six months ended June 30,
		2021	2020	Normal (2)	2021	2020	Normal (2)		2022	2021	Normal (2)	2022	2021	Normal (2)
Heating degree-days(1)	Heating degree-days(1)	594	664	719	2,921	2,902	3,199	Heating degree-days(1)	909	594	685	3,505	2,921	3,087
Cooling degree-days(1)	Cooling degree-days(1)	383	195	183	383	195	183	Cooling degree-days(1)	157	383	188	157	383	188
Precipitation (inches)	Precipitation (inches)	2.4	6.4	2.4	7.5	11.6	6.0	Precipitation (inches)	4.6	2.5	3.4	7.3	6.3	7.2

(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 cooling. 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.

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

Sales Volume and Generation: Retail sales volumes ~~increased 14~~decreased 11 percent and 83 percent in the second quarter and first six months of ~~2021,~~2022, respectively, compared with the same periods in ~~2020,~~2021. Increases in sales volumes from customer growth partially offset a decrease in sales volumes per customer during the second quarter of 2022, compared with the second quarter of 2021, as the number of Idaho Power customers grew by 2.6 percent over the prior twelve months. Increases in sales volumes among all customer classes, except for irrigation customers, were due primarily ~~due~~ to ~~warmer~~customer growth, during the first six months of 2022, compared with the first six months of 2021. Mild temperatures and ~~drier weather that~~greater precipitation caused customers to use ~~more~~less energy for ~~cooling or irrigation. Cooling degree-days~~irrigation and, to a lesser extent, air conditioning, particularly in the second quarter of 2022 compared with the second quarter of 2021. Precipitation in Boise Idaho ~~were 96~~was 86 percent higher during the three months ended June 30, 2021, compared with the three months ended June 30, 2020, and 109 percent above normal. Also, precipitation in Idaho Power's service area decreased significantly during the three months ended June 30, 2021,2022, compared with the same period of ~~2020,~~2021, and 35 percent above normal, which ~~increased~~decreased usage by irrigation ~~customers. During~~customers by approximately 36 percent and 35 percent, respectively, during the ~~second quarter~~three and ~~first~~ six months ~~of 2021, usage per irrigation customer was approximately 25 percent and 24 percent higher, respectively,~~ended June 30, 2022, compared with the same periods in 2020. During the second quarter and first six months of 2021, usage per residential customer was approximately 10 percent and 5 percent higher, respectively, compared with the same periods in 2020. Customer growth increased sales volumes

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same periods in 2021. During the second quarter of 2022, usage per residential customer was approximately 10 percent lower and usage per commercial customer was approximately 6 percent lower than the same period of 2021, primarily due to cooler temperatures during the second quarter of 2022, which decreased the use of electricity for cooling purposes. Cooling degree-days in Boise, Idaho were 59 percent lower during the three ~~and six~~months ended June 30, 2022, compared with the three months ended June 30, 2021, and 16 percent below normal. The weather-related declines in residential usage during the second quarter were almost entirely offset by the higher sales per residential customer that Idaho Power experienced from colder winter weather during the first quarter of 2022.

Total system generation increased 3 percent in the second quarter and was flat in the first six months of 2022 compared with the same ~~period~~periods in ~~2020, with the number of Idaho Power's customers growing by 2.9~~2021. Hydropower generation increased 11 percent ~~over the prior twelve months. Increases in usage per commercial and industrial customers were partially due to a return to more normal economic activity~~ in the second quarter of ~~2021~~2022 and was slightly lower in the first six months of 2022 compared with the same periods in 2021, with the second-quarter increase due mostly to greater precipitation in the second quarter of ~~2020, which was affected by negative COVID-19-related business conditions. During~~2022, and the overall decrease for the first six months of 2022 due largely to less snowpack and carry-over reservoir storage. Natural gas generation decreased significantly in the second quarter and first six months of ~~2021, usage per commercial customer was approximately 12 percent and 5 percent higher,~~2022, respectively, compared with ~~the~~ same periods of 2021, due primarily to a planned maintenance outage at the Langley Gulch natural gas plant and, to a lesser extent, higher natural gas market prices. This decrease in ~~2020. Usage per industrial customer was approximately 8 percent and 4 percent higher~~natural gas generation during the second quarter and first six months of ~~2021 compared with~~2022 led to a significant increase in coal generation, and for the ~~same periods in 2020, respectively.~~

~~Total system generation decreased 22 percent and 13 percent in the second quarter and~~ first six months of ~~2021, respectively, compared with the second quarter and first six months of 2020, due primarily~~2022, an increase in energy purchased from wholesale markets to lower hydropower and coal-fired generation, partially offset by increased natural gas generation. Generation from hydropower during the second quarter and first six months of 2021 decreased 36 percent and 26 percent, respectively, compared with the same periods of 2020, due mostly to less snowpack and precipitation in the Snake River basin. Coal-fired generation also decreased 54 percent and 29 percent during the second quarter and first six months of 2021 compared with the same periods of 2020, respectively, due to economic-, operations-, and reliability-based decisions. During the second quarter and first six months of 2021, natural gas generation increased compared with the same periods of 2020, due to the decreases in hydropower and coal-fired generation.help meet customer demand.

Purchased power volumes increased 49 percent and 32 percent in the second quarter and first six months of 2021, respectively, mostly due to an increase in purchases from the energy imbalance market implemented in the western United States (Western EIM) and additional purchases to meet load requirements. The financial impacts of fluctuations in wholesale energy sales, purchased power, fuel expense, and other power supply-related expenses are addressed in Idaho Power's Idaho and Oregon power cost adjustment mechanisms, which are described below in ~~"Power~~"Power Cost Adjustment ~~Mechanisms.~~Mechanisms" in this MD&A.

Operating Revenues

Retail Revenues: The table below presents Idaho Power’s retail revenues (in thousands) and MWh sales volumes (in thousands) for the three and six months ended June 30, ~~2021~~2022 and ~~2020,~~2021, and the number of customers as of June 30, ~~2021~~2022 and ~~2020.~~2021.

Three months ended
June 30, Six months ended
June 30,
2021 2020 2021 2020
Retail revenues:
Residential (includes ($715), $4,135, $15,107, and $19,844, respectively, related to the FCA)(1)
$ 122,633 $ 109,471 $ 277,418 $ 254,357
Commercial (includes $165, $397, $647, and $881, respectively, related to the FCA)(1)
77,609 67,214 149,878 136,728
Industrial 48,047 43,087 93,477 85,847
Irrigation 76,799 60,149 77,885 61,523
Deferred revenue related to HCC relicensing AFUDC(2)
(1,927) (1,927) (4,046) (4,046)
Total retail revenues $ 323,161 $ 277,994 $ 594,612 $ 534,409
Volume of retail sales (MWh)
Residential 1,262 1,127 2,764 2,575
Commercial 1,013 894 2,015 1,899
Industrial 856 801 1,708 1,653
Irrigation 967 772 980 786
Total retail MWh sales 4,098 3,594 7,467 6,913
Number of retail customers at period end
Residential 498,747 483,609
Commercial 75,187 73,620
Industrial 126 127
Irrigation 21,811 21,583
Total customers 595,871 578,939

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	Three months ended June 30,				Six months ended June 30,
	2022		2021		2022		2021
Retail revenues:
Residential (includes $5,459, $(715), $15,551, and $15,107, respectively, related to the FCA)(1)	$	124,593	$	122,633	$	293,888	$	277,418
Commercial (includes $304, $165, $588, and $647, respectively, related to the FCA)(1)	79,260		77,609		157,826		149,878
Industrial	51,987		48,047		101,047		93,477
Irrigation	57,659		76,799		58,700		77,885

Deferred revenue related to HCC relicensing AFUDC(2)	(1,927)		(1,927)		(4,046)		(4,046)

Total retail revenues	$	311,572	$	323,161	$	607,415	$	594,612
Volume of retail sales (MWh)
Residential	1,173		1,262		2,838		2,764
Commercial	974		1,013		2,035		2,015
Industrial	852		856		1,737		1,708
Irrigation	649		967		663		980
Total retail MWh sales	3,648		4,098		7,273		7,467
Number of retail customers at period end
Residential	512,594		498,747
Commercial	76,573		75,187
Industrial	125		126
Irrigation	22,063		21,811
Total customers	611,355		595,871

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

(2) As part of its January 30, 2009, general rate case order, the IPUC is allowing Idaho Power to recover a portion of the allowance for funds used during construction (AFUDC) on construction work in progress related to the HCC relicensing process, even though the relicensing process is not yet complete and the costs have not been moved to electric plant in service. Idaho Power is collecting approximately $8.8 million annually in the Idaho jurisdiction but is

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deferring revenue recognition of the amounts collected until the license is issued and the accumulated license costs approved for recovery are placed in service.

Changes in rates, changes in customer usage, customer growth, and changes in FCA mechanism revenues are the primary reasons for fluctuations in retail revenues from period to period. The primary influences on customer usage ~~for~~of electricity are weather, economic conditions, and energy efficiency. Extreme temperatures increase sales to customers who use electricity for cooling and heating, while moderate temperatures decrease sales. Precipitation levels and the timing of precipitation during the agricultural growing season also affect sales to customers who use electricity to operate irrigation pumps. Rates are also seasonally adjusted, providing for higher rates during peak load periods, and residential customer rates are tiered, providing for higher rates based on higher levels of usage. The seasonal and tiered rate structures contribute to seasonal fluctuations in revenues and earnings.

Retail revenues ~~increased $45.2~~decreased $11.6 million and ~~$60.2~~increased $12.8 million during the second quarter and first six months of ~~2021,~~2022, respectively, compared with the same periods in ~~2020.~~2021. The factors affecting retail revenues during ~~the period~~these periods are discussed below.

•Customers: Customer growth of ~~2.9~~2.6 percent during the twelve months ended June 30, ~~2021,~~2022, increased retail revenues by ~~$5.1~~$4.2 million and ~~$10.2~~$8.9 million in the second quarter and first six months of ~~2021,~~2022, respectively, compared with the same periods ~~of 2020.~~in 2021.

•Usage: ~~Higher~~Lower usage (on a per customer basis) by, primarily related to irrigation ~~residential, commercial, and industrial~~ customers, ~~increased~~decreased retail revenues by ~~$37.1~~$44.8 million and ~~$36.9~~$27.7 million in the second quarter and first six months of ~~2021,~~2022, respectively, compared with the same periods of ~~2020. Increased~~2021. The decreased usage by irrigation customers was primarily the result of ~~warmer summer temperatures and drier weather~~greater precipitation in Idaho Power's service area ~~which increased usage by~~during the second quarter and first six months of 2022 compared with the same periods of 2021. Also, residential and ~~irrigation customers. To a lesser extent, a return~~commercial customers used less energy per customer for cooling in the second quarter of 2022 primarily due to ~~more normal economic conditions~~milder temperatures compared with the second quarter of 2021. Higher sales per residential customer for ~~commercial and industrial customers also increased sales volumes on a per-customer basis, as~~heating from colder winter weather during the first ~~half~~quarter of ~~2020 was negatively affected~~2022 were offset by ~~COVID-19-related business conditions.~~weather-related declines in residential usage during the second quarter of 2022.

•Idaho FCA Revenue: The FCA mechanism, applicable to Idaho residential and small commercial customers, adjusts revenue each year to accrue, or defer, the difference between the authorized fixed-cost recovery amount per customer and the actual fixed costs per customer recovered by Idaho Power through volume-based rates during the year. ~~Higher~~Lower usage (on a per customer basis) by residential and small general service customers during the second quarter and first six months of ~~2021 decreased~~2022 increased the amount of FCA revenue accrued by ~~$5.1~~$6.3 million and ~~$5.0~~$0.4 million, respectively, compared with the same periods in ~~2020.~~2021.

•Rates: Average customer rates, excluding amounts related to the power cost adjustment mechanisms, ~~decreased~~increased retail revenues by ~~$3.1~~$8.7 million and ~~$4.1~~$8.5 million, respectively, for the three and six months ended June 30, ~~2021,~~2022, compared with the same periods in ~~2020.~~2021, due partially to the rate-related impact of monthly fixed charges being allocated over fewer MWh from the lower usage per customer, particularly among irrigation customers, described above. Also, a June 1, 2022 rate increase for Idaho Power’s Idaho retail customers related to the Bridger Order increased retail revenues for the three and six months ended June 30, 2022, compared with the same periods of 2021. Customer rates also include the collection from customers of amounts related to the power cost adjustment mechanisms, which increased revenues by ~~$11.1~~$14.1 million and ~~$22.2~~$22.7 million in the second quarter and first six months of ~~2021,~~2022, respectively, compared with the same periods of ~~2020.~~2021. The amount collected from customers in rates under the power cost adjustment mechanisms has relatively little effect on operating income as a corresponding amount is recorded as expense in the same period it is collected through rates.

Wholesale Energy Sales: Wholesale energy sales consist primarily of opportunistic sales of surplus system energy, ~~and~~but also include sales into the ~~Western EIM, and do not include derivative transactions.~~energy imbalance market in the western United States (Western EIM). The table below presents Idaho Power’s wholesale energy sales for the three and six months ended June 30, ~~2021~~2022 and ~~2020~~2021 (in thousands, except for per MWh amounts).


		Three months ended June 30,				Six months ended June 30,					Three months ended June 30,				Six months ended June 30,
		2021		2020		2021		2020			2022		2021		2022		2021
Wholesale energy revenues	Wholesale energy revenues	$	4,308	$	6,866	$	10,567	$	10,775	Wholesale energy revenues	$	6,980	$	4,308	$	10,015	$	10,567
Wholesale volume in MWh sold	Wholesale volume in MWh sold	67		489		188		671		Wholesale volume in MWh sold	121		67		149		188
Average wholesale energy revenues per MWh	Average wholesale energy revenues per MWh	$	64.30	$	14.04	$	56.21	$	16.06	Average wholesale energy revenues per MWh	$	57.69	$	64.30	$	67.21	$	56.21

In the second quarter and during the first six months of 2021, wholesale energy revenues decreased $2.6 million and $0.2 million, respectively, compared with the same periods of 2020, primarily due to a heat wave in Idaho Power's service area which increased energy usage by Idaho Power customers and resulted in less energy available for opportunistic market sales. Wholesale energy sales volumes decreased 86 percent and 72 percent in the second quarter and first six months of 2021, respectively, compared with the sames periods of 2020. The decreases in wholesale energy revenues related to lower volumes sold were partially offset by increases in average wholesale energy revenues per MWh due mostly to higher wholesale energy

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~~prices in the region.~~ Wholesale energy ~~prices were higher~~revenues increased $2.7 million in the second quarter ~~and~~of 2022 compared with the second quarter of 2021, due to higher wholesale energy sales volumes. Wholesale energy revenues were relatively flat in the first six months of 2022 compared with the first six months of 2021, ~~compared with the same periods~~as lower wholesale energy sales were mostly offset by higher wholesale market prices. The financial impacts of fluctuations in ~~2020 as extreme weather resulted~~wholesale energy sales are largely mitigated by Idaho Power's Idaho and Oregon power cost adjustment mechanisms, which are described below in ~~higher demand and lower supply of energy to the wholesale markets~~"Power Cost Adjustment Mechanisms" in ~~the region.~~this MD&A.

Transmission Wheeling-Related Revenues: Transmission wheeling-related revenues increased ~~$3.9~~$2.9 million, or 3419 percent, and ~~$8.0~~$4.9 million, or 3716 percent, during the second quarter and during the first six months of 2021, respectively, compared with the same periods in 2020, as warmer, drier spring and summer weather in the western United States increased wheeling volumes. Colder winter weather in the southwest United States in early 2021 also contributed to increased wheeling volumes in the first six months of 2021 compared with the first six months of 2020. In addition, Idaho Power's open access transmission tariff (OATT) rates were approximately 10 percent higher in the second quarter and first six months of ~~2021~~2022, respectively, compared with the same periods of ~~2020.~~2021. Warmer weather in the southwest United States and milder weather in the Pacific Northwest during the second quarter of 2022 compared with the second quarter of 2021 led to a price spread between energy market hubs. This price spread increased wheeling activity across Idaho Power's transmission system for wheeling customers to access these markets. In addition, two new long-term wheeling agreements executed in April 2021 contributed to increased wheeling volumes during the first half of 2022 compared with the same period in 2021. Also, Idaho Power's OATT rates were approximately 4 percent higher in the first half of 2022 compared with the first half of 2021.

Energy Efficiency Program Revenues: In both Idaho and Oregon, energy efficiency riders fund energy efficiency program expenditures. Expenditures funded through the riders are reported as an operating expense with an equal amount recorded in 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. A liability balance indicates that Idaho Power has collected more than it has spent, and an asset balance indicates that Idaho Power has spent more than it has collected. At June 30, ~~2021,~~2022, Idaho Power's energy efficiency rider balances were regulatory assets of ~~$12.1~~$4.3 million in the Idaho jurisdiction and ~~$0.8~~$0.1 million in the Oregon jurisdiction.

Operating Expenses

Purchased Power: The table below presents Idaho Power’s purchased power expenses and volumes for the three and six months ended June 30, ~~2021~~2022 and ~~2020~~2021 (in thousands, except for per MWh amounts).


		Three months ended June 30,				Six months ended June 30,					Three months ended June 30,				Six months ended June 30,
		2021		2020		2021		2020			2022		2021		2022		2021
Expense	Expense									Expense
PURPA contracts	PURPA contracts	$	53,163	$	47,388	$	96,220	$	89,677	PURPA contracts	$	48,607	$	53,163	$	88,603	$	96,220
Other purchased power (including wheeling)	Other purchased power (including wheeling)	42,953		14,386		67,884		33,298		Other purchased power (including wheeling)	43,120		42,953		88,548		67,884
Total purchased power expense	Total purchased power expense	$	96,116	$	61,774	$	164,104	$	122,975	Total purchased power expense	$	91,727	$	96,116	$	177,151	$	164,104
MWh purchased	MWh purchased									MWh purchased
PURPA contracts	PURPA contracts	979		915		1,675		1,621		PURPA contracts	855		979		1,462		1,675
Other purchased power	Other purchased power	970		390		1,671		905		Other purchased power	868		970		2,042		1,671
Total MWh purchased	Total MWh purchased	1,949		1,305		3,346		2,526		Total MWh purchased	1,723		1,949		3,504		3,346
Average cost per MWh from PURPA contracts	Average cost per MWh from PURPA contracts	$	54.30	$	51.79	$	57.44	$	55.32	Average cost per MWh from PURPA contracts	$	56.85	$	54.30	$	60.60	$	57.44
Average cost per MWh from other sources	Average cost per MWh from other sources	$	44.28	$	36.89	$	40.62	$	36.79	Average cost per MWh from other sources	$	49.68	$	44.28	$	43.36	$	40.62
Weighted average - all sources	Weighted average - all sources	$	49.32	$	47.34	$	49.04	$	48.68	Weighted average - all sources	$	53.24	$	49.32	$	50.56	$	49.04

Purchased power expense ~~increased $34.3~~decreased $4.4 million, or 565 percent, ~~and $41.1 million, or 33 percent, during~~in the second quarter ~~and~~of 2022, but increased $13.0 million, or 8 percent, in the first six months of ~~2021~~2022 compared with the same periods of ~~2020,~~2021. The decrease in purchased power expense for the second quarter was primarily due to ~~148~~a 12 percent ~~and 84 percent increases, respectively,~~decrease in total MWh purchased compared with the second quarter of 2021. Compared with the first six months of 2021, a decrease in natural gas generation during the first six months of 2022 led to a 5 percent increase in energy purchased from ~~sources other than PURPA contracts mostly due~~wholesale markets to ~~increases in purchases from the Western EIM and additional purchases to~~help meet ~~load requirements.~~customer demand.

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Fuel Expense: The table below presents Idaho Power’s fuel expenses and thermal generation for the three and six months ended June 30, ~~2021~~2022 and ~~2020~~2021 (in thousands, except for per MWh amounts).


		Three months ended June 30,				Six months ended June 30,					Three months ended June 30,				Six months ended June 30,
		2021		2020		2021		2020			2022		2021		2022		2021
Expense	Expense									Expense
Coal	Coal	$	11,672	$	27,414	$	28,607	$	43,188	Coal	$	22,346	$	11,672	$	50,005	$	28,607
Natural gas	Natural gas	19,519		4,000		35,889		18,242		Natural gas	12,071		19,519		30,114		35,889
Total fuel expense	Total fuel expense	$	31,191	$	31,414	$	64,496	$	61,430	Total fuel expense	$	34,417	$	31,191	$	80,119	$	64,496
MWh generated	MWh generated									MWh generated
Coal	Coal	372		810		908		1,272		Coal	777		372		1,595		908
Natural gas	Natural gas	666		89		1,307		727		Natural gas	179		666		638		1,307
Total MWh generated	Total MWh generated	1,038		899		2,215		1,999		Total MWh generated	956		1,038		2,233		2,215
Average cost per MWh - Coal	Average cost per MWh - Coal	$	31.38	$	33.84	$	31.51	$	33.95	Average cost per MWh - Coal	$	28.76	$	31.38	$	31.35	$	31.51
Average cost per MWh - Natural gas	Average cost per MWh - Natural gas	$	29.31	$	44.94	$	27.46	$	25.09	Average cost per MWh - Natural gas	$	67.44	$	29.31	$	47.20	$	27.46
Weighted average, all sources	Weighted average, all sources	$	30.05	$	34.94	$	29.12	$	30.73	Weighted average, all sources	$	36.00	$	30.05	$	35.88	$	29.12

The majority of the fuel for Idaho Power’s jointly-owned coal-fired plants is purchased through long-term contracts, including purchases from BCC, a one-third owned joint venture of IERCo. The price of coal from BCC is subject to fluctuations in mine operating expenses, geologic conditions, and production levels. BCC supplies approximately two-thirds of the coal used by the Jim Bridger plant. Natural gas is mainly purchased on the regional wholesale spot market at published index prices. In addition to commodity (variable) costs, both natural gas and coal expenses include costs that are more fixed in nature for items such as capacity charges, transportation, and fuel handling. Period to period variances in fuel expense per MWh are noticeably impacted by these fixed charges when generation output is substantially different between the periods.

Fuel expense ~~decreased $0.2~~increased $3.2 million, or 110 percent, and $15.6 million, or 24 percent, in the second quarter ~~of 2021, but increased $3.1 million, or 5 percent, in the~~and first six months of ~~2021~~2022, respectively, compared with the same periods of ~~2020.~~2021. The ~~slight decrease~~increases in fuel expense ~~in the second quarter of 2021 compared with the same period in 2020 was~~were primarily due to ~~a 14 percent decrease~~higher natural gas market prices in 2022, which resulted in an increase in the average cost per MWh ~~generated~~of natural gas generation. Also, coal-fired generation increased to compensate for the significant decrease in natural gas generation primarily resulting from a planned maintenance outage at the ~~thermal plants, mostly offset by~~ ~~an increase in thermal generation to meet load requirements~~. ~~The increase in fuel expense in~~Langley Gulch natural gas plant during the first ~~six months~~half of ~~2021 compared with~~2022 and, to a lesser extent, higher natural gas market prices. Idaho Power expects natural gas market prices to be volatile and to remain elevated through the ~~same period in 2020 was due to an increase in thermal generation to meet higher load requirements,~~ ~~partially offset by a 5 percent decrease in the average cost per MWh generated at the thermal plants.~~rest of 2022.

Power Cost Adjustment Mechanisms: Idaho Power's power supply costs (primarily purchased power and fuel expense, less wholesale energy sales) can vary significantly from year to year. Volatility of power supply costs arises from factors such as weather conditions, wholesale market prices, volumes of power purchased and sold in the wholesale markets, Idaho Power's hydropower and thermal generation volumes and fuel costs, generation plant availability, and retail loads. To address the volatility of power supply costs, Idaho Power's power cost adjustment mechanisms in the Idaho and Oregon jurisdictions allow Idaho Power to recover from customers, or refund to customers, most of the fluctuations in power supply costs. ~~In the Idaho jurisdiction, the PCA~~The Idaho-jurisdiction power cost adjustment (PCA) includes a cost or benefit sharing ratio that allocates the deviations in net power supply expenses between customers (95 percent) and Idaho Power (5 percent), with the exception of PURPA power purchases and demand response program incentives, which are allocated 100 percent to customers. The Idaho deferral period, or PCA year, runs from April 1 through March 31. Amounts deferred or accrued during the PCA year are primarily recovered or refunded during the subsequent June 1 through May 31 period. ~~Because~~The primary financial impact of the power cost adjustment mechanisms ~~one~~relates to the timing of the primary financial impacts of power supply cost variations is that cash is paid out but recovery from customers does not occur until a future period, or cash that is collected is refunded to customers in a future period, resulting in fluctuations in operating cash flows, as cash may be paid out for power supply costs prior to recovery from ~~year to year.~~customers.

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The table that follows presents the components of the Idaho and Oregon power cost adjustment mechanisms for the three and six months ended June 30, ~~2021~~2022 and ~~2020~~2021 (in thousands).


		Three months ended June 30,				Six months ended June 30,					Three months ended June 30,				Six months ended June 30,
		2021		2020		2021		2020			2022		2021		2022		2021
Power supply cost accrual		$	866	$	11,991	$	16,126	$	22,948
Power supply cost (deferral) accrual										Power supply cost (deferral) accrual	$	(1,026)	$	866	$	3,457	$	16,126

Amortization of prior year authorized balances	Amortization of prior year authorized balances	(8,800)		(13,527)		(18,389)		(27,875)		Amortization of prior year authorized balances	600		(8,800)		(4,282)		(18,389)
Total power cost adjustment expense	Total power cost adjustment expense	$	(7,934)	$	(1,536)	$	(2,263)	$	(4,927)	Total power cost adjustment expense	$	(426)	$	(7,934)	$	(825)	$	(2,263)

The power supply (deferrals) accruals represent the portion of the power supply cost fluctuations (deferred) accrued under the power cost adjustment mechanisms. When actual power supply costs are lower than the amount forecasted in power cost adjustment rates, ~~which was the case for all periods presented,~~ most of the difference is accrued as an increase to a regulatory liability or decrease to a regulatory asset. When actual power supply costs are higher than the amount forecasted in power cost adjustment rates, most of the difference is deferred as an increase to a regulatory asset or decrease to a regulatory liability. The amortization of the prior year’s balances represents the offset to the amounts being collected or refunded in the current power cost adjustment year that were deferred or accrued in the prior PCA ~~year (the true-up component of the power cost adjustment mechanism).~~year.

Other O&M Expenses: Other O&M expenses increased ~~$5.3~~$12.0 million, or 614 percent, and ~~$1.2~~$18.5 million, or 111 percent, ~~for~~in the second quarter and first six months of ~~2021~~2022, compared with the first quarter of 2020, respectively, primarily due to the timing of completing certain maintenance projects at its jointly-owned thermal generation plants in 2021 instead of 2020. Also, other O&M expenses increased in the second quartersame periods of 2021, ~~compared with~~due largely to maintenance activities at the ~~second quarter~~Jim Bridger coal plant, Langley Gulch natural gas plant, and American Falls hydropower project. Most of ~~2020,~~those maintenance activities are performed as ~~a result of~~scheduled maintenance, but not annually. Also, an increase in ~~labor-related costs from higher~~ performance-based variable compensation ~~accruals.~~accruals and inflationary pressures on labor-related costs, professional services, vehicle fuel, and supplies contributed to the increase in other O&M expenses.

Income Taxes

~~IDACORP's~~Income tax expense for IDACORP and Idaho ~~Power's income tax expense increased $5.3 million and $5.7 million~~Power for the six months ended June 30, ~~2021, when~~2022, decreased by $1.8 million and $1.3 million, respectively, compared ~~with~~to the same period in ~~2020, respectively,~~2021, primarily due to ~~greater~~lower pre-tax income.For information relating to IDACORP's and Idaho Power's computation of income tax expense ~~and~~ effective income tax rates, see Note 2 - "Income Taxes" to the condensed consolidated financial statements included in this report.

LIQUIDITY AND CAPITAL RESOURCES

Overview

Idaho Power ~~has been pursuing~~continues to pursue 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 hydropower and thermal generation facilities also require continuing upgrades and component replacement. Idaho Power anticipates these substantial capital expenditures will continue, with ~~expected~~estimated total capital expenditures of ~~approximately $2.0~~up to $2.8 billion over the five-year period from ~~2021~~2022 (including expenditures incurred to-date in ~~2021)~~2022) through ~~2025.~~2026.

Idaho Power funds its liquidity needs for capital expenditures through cash flows from operations, debt offerings, commercial paper markets, credit facilities, a term loan facility, and capital contributions from IDACORP. Idaho Power periodically files for rate adjustments for recovery of operating costs and capital investments to provide the opportunity to align Idaho Power's earned returns with those allowed by regulators. Idaho Power uses operating and capital budgets to control operating costs and capital expenditures. During the first six months of 2021, Idaho Power continued its efforts to optimize operations, control costs, and generate operating cash inflows to meet operating expenditures, contribute to capital expenditure requirements, and pay dividends to shareholders.

As of July ~~23, 2021,~~29, 2022, IDACORP's and Idaho Power's access to debt, equity, and credit arrangements included:

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

•IDACORP's shelf registration statement filed with the U.S. Securities and Exchange Commission (SEC) on May ~~17, 2019,~~16, 2022, which may be used for the issuance of debt securities and common stock;

•Idaho Power's shelf registration statement filed with the SEC on May ~~17, 2019,~~16, 2022, which may be used for the issuance of first mortgage bonds and debt securities; ~~$190 million~~$1.2 billion remains available for issuance pursuant to state regulatory authority; and

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

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IDACORP and Idaho Power monitor capital markets with a view toward opportunistic debt and equity transactions, taking into account current and potential future long-term needs. As a result, IDACORP may issue debt securities or common stock, and Idaho Power may issue debt securities or first mortgage bonds, if the companies believe terms available in the capital markets are favorable and that issuances would be financially prudent. 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.

Based on planned capital expenditures and other O&M expenses, the companies believe they will be able to meet capital and debt service requirements and fund corporate expenses during at least the next twelve months with a combination of existing cash, operating cash flows generated by Idaho Power's utility business, availability under existing credit facilities, and access to commercial paper and long-term debt markets.

IDACORP and Idaho Power generally seek to maintain capital structures of approximately 50 percent debt and 50 percent ~~equity, and maintaining~~equity. Maintaining this ratio influences IDACORP's and Idaho Power's debt and equity issuance decisions. As of June 30, ~~2021,~~2022, 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	Debt	43%	46%	Debt	44%	46%
Equity	Equity	57%	54%	Equity	56%	54%

IDACORP and Idaho Power typically 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 ended June 30, ~~2021,~~2022, were ~~$167~~$156 million and ~~$155~~$145 million, respectively, ~~an increase~~a decrease of ~~$39~~$11 million for IDACORP and ~~an increase of $25 million for~~ Idaho Power, compared with the same period in ~~2020.~~2021. With the exception of cash flows related to income taxes, IDACORP's operating cash flows are principally derived from the operating cash flow of Idaho Power. Significant items that affected the comparability of the companies' operating cash flows in the first six months of ~~2021~~2022 compared with the same period in ~~2020~~2021 were as follows:

•~~increased~~decreased net income;

•changes in ~~regulatory assets~~deferred taxes and ~~liabilities, mostly related~~taxes accrued and receivable combined to ~~the relative amounts of costs deferred~~decrease IDACORP and ~~collected under the~~ Idaho ~~PCA mechanism, increased operating~~Power cash flows by ~~$21 million;~~$5 million and $3 million, respectively;

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

◦timing of ~~collections of~~ accounts ~~receivable balances~~payable and other accrued liability payments decreased operating cash flows by $6$26 million for IDACORP and ~~$4 million for Idaho Power;~~

◦~~timing of accounts payable payments increased operating cash flows by $33 million for IDACORP and $25 million for~~ Idaho Power, ~~of which $8 million of the difference between IDACORP~~ and ~~Idaho Power related to intercompany tax payments in the first six months of 2020;~~

◦the changes in other current assets ~~decreased~~increased operating cash flows by ~~$24~~$31 million for IDACORP and Idaho Power, which was primarily due to fluctuations in accrued unbilled revenues, the timing of purchases and consumption of materials and supplies, and the timing of purchases and consumption of coal at Idaho Power's jointly-owned coal-fired generating ~~plants; and~~

◦the changes in other current liabilities, which includes compensation, customer deposits, accrued interest, and other miscellaneous liabilities, decreased operating cash flows by $7 million for IDACORP and Idaho Power.plants.

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 ended June 30, ~~2021,~~2022, were ~~$107~~$204 million and ~~$122~~$175 million, respectively. Investing cash outflows for ~~2021~~2022 and ~~2020~~2021 were primarily for construction of utility infrastructure needed to address Idaho Power’s aging plant and equipment, customer growth, and environmental and regulatory compliance requirements. ~~During~~Significant items and transactions that affected investing cash flows during the first six months of 2022 and 2021 were as follows:

•IDACORP’s and Idaho Power’s investing cash outflows both included additions to utility plant of $194 million during the first half of 2022 compared with $128 million during the first half of 2021;

•IDACORP's investing cash outflows and inflows for 2022 and ~~outflows also~~2021 included ~~$50~~$25 million ~~of proceeds from maturities~~in purchases of short-term investments and ~~$25~~for 2021 included $50 million in sales of short-term investments;

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~~purchases of short-term investments, respectively. In addition,~~ •IDACORP's investing cash outflows ~~also~~for 2022 and 2021 included $3 million and $10 million, ~~and $9 million~~respectively, of tax credit investments in affordable housing and other real estate, which provide a return principally by reducing federal and state income taxes through tax credits ~~during the six months ended June 30, 2021~~ and ~~2020, respectively.~~accelerated tax depreciation benefits;

•IDACORP's and Idaho Power's investing cash inflows for 2022 included a $10 million return of investment from IERCo, a wholly-owned subsidiary of Idaho Power; and

•IDACORP's and Idaho Power's investing cash outflows and inflows for 2022 included $27 million and $30 million, respectively, in purchases of equity and held-to-maturity securities, respectively, and $53 million in sales of equity securities held in a rabbi trust, which is designated to provide funding for obligations related to Idaho Power's security plan for senior management employees.

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, a term loan facility, and capital contributions from IDACORP. IDACORP funds its cash requirements, such as payment of taxes, capital contributions to Idaho Power, and non-utility expenses allocated to IDACORP, through cash flows from operations, commercial paper markets, sales of common stock, and credit facilities.

IDACORP's and Idaho Power's net financing cash ~~outflows~~inflows for the six months ended June 30, ~~2021,~~2022, were ~~$75~~$71 million and ~~$72~~$74 million, respectively. InDuring the first six months of ~~2021,~~2022, Idaho Power drew $150 million from a delayed draw term loan facility, described below, and IDACORP and Idaho Power paid dividends of ~~approximately $72~~$76 million.

Financing Programs and Available Liquidity

Term Loan Credit Agreement:

In March 2022, Idaho Power entered into a term loan credit agreement (Term Loan Facility). The Term Loan Facility is a two-year senior unsecured delayed draw term loan facility in the aggregate principal amount of $150 million. The maturity date of the Term Loan Facility is March 4, 2024. The Term Loan Facility which will be used for general corporate purposes, including funding Idaho Power's capital projects, provided for the issuance of loans in the aggregate principal amount of $150 million.

The interest rates for the floating rate advances under the Term Loan Facility were based on the highest of (1) the prime commercial lending rate of the lender acting as administrative agent, (2) the federal funds rate, plus 0.5 percent, (3) Term SOFR (as defined in the Term Loan Facility) for a one-month tenor that is published by CME Group Benchmark Administration limited (or the successor administrator of such rate), plus 1%, and (4) zero percent. The interest rates for SOFR Advances (as defined in the Term Loan Facility) were based on the Term SOFR rate for the borrower-selected period plus the Applicable Margin. The “Applicable Margin” is based on Idaho Power's senior unsecured non-credit enhanced long-term indebtedness credit rating, as set forth on a schedule to the Term Loan Facility.

At June 30, 2022, $150 million in principal amount had been drawn and was outstanding on the Term Loan Facility.

IDACORP Equity Programs: IDACORP has no current plans to issue equity securities in 2022 other than under its equity compensation ~~plans during 2021.~~plans.

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~~May and ~~May 2019,~~June 2022, Idaho Power received orders from the IPUC, OPUC, and WPSC authorizing the company to issue and sell from time to time up to ~~$500 million~~$1.2 billion in aggregate principal amount of debt securities and first mortgage bonds, subject to conditions specified in the orders. Following the April 2020 issuance of Series K medium-term notes and the June 2020 issuance of Series L medium-term notes described in the 2020 Annual Report, in Part II, Item 7 - "MD&A - Liquidity and Capital Resources," $190 million of debt securities remains available for issuance under the orders. Authority from the IPUC and WPSC is effective through May 31, ~~2022,~~2025, subject to extension upon request to the ~~IPUC.~~IPUC and WPSC. The ~~OPUC’s and WPSC’s orders do~~OPUC's order does not impose a time limitation for issuances, but ~~the OPUC order~~ does impose a number of other conditions, including a requirement that the interest rates for the debt securities or first mortgage bonds fall within either (a) designated spreads over comparable U.S. Treasury rates or (b) a maximum ~~all-in~~ interest rate limit of ~~seven~~eight percent.

In May ~~2019,~~2022, Idaho Power filed a shelf registration statement with the SEC, which became effective upon filing, for the offer and sale of an unspecified principal amount of its first mortgage bonds. The issuance of first mortgage bonds requires that Idaho Power meet interest coverage and security provisions set forth in Idaho Power's Indenture of Mortgage and Deed of Trust, dated as of October 1, 1937, as amended and supplemented from time to time (Indenture). Future issuances of first mortgage bonds

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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.

In June ~~2020,~~2022, Idaho Power entered into a selling agency agreement with six banks named in the agreement in

connection with the potential issuance and sale from time to time of up to ~~$500 million~~$1.2 billion aggregate principal amount of first

mortgage bonds, secured medium term notes, Series LM (Series LM Notes), under Idaho Power’s Indenture of Mortgage and Deed

of Trust, dated as of October 1, 1937, as amended and supplemented (Indenture). Also in June ~~2020,~~2022, Idaho Power

entered into the ~~Forty-ninth~~Fiftieth Supplemental Indenture, dated effective as of June ~~5, 2020,~~30, 2022, to the Indenture ~~(Forty-ninth~~

(Fiftieth Supplemental Indenture). The ~~Forty-ninth~~Fiftieth Supplemental Indenture provides for, among other items the issuance of up to

~~$500 million~~ $1.2 billion in aggregate principal amount of Series LM Notes pursuant to the Indenture.

The Indenture limits the amount of first mortgage bonds at any one time outstanding to $2.5 billion, and as a result, the maximum amount of additional first mortgage bonds Idaho Power could issue as of June 30, ~~2021,~~2022, was limited to approximately $534 million. Idaho Power ~~may~~plans to increase the $2.5 billion limit ~~on the maximum amount of first mortgage bonds outstanding~~to $3.5 billion by filing a supplemental indenture with the trustee during the third quarter of 2022 as provided in the Indenture of Mortgage and Deed of Trust. Separately, the Indenture also limits the amount of additional first mortgage bonds that Idaho Power may issue to the sum of (a) the principal amount of retired first mortgage bonds and (b) 60 percent of total unfunded property additions, as defined in the Indenture. As of June 30, ~~2021,~~2022, Idaho Power could issue approximately ~~$1.8~~$2.2 billion of additional first mortgage bonds based on retired first mortgage bonds and total unfunded property additions.

IDACORP and Idaho Power Credit Facilities: ~~In December 2019,~~ IDACORP and Idaho Power ~~entered into amendments to~~have credit agreements for $100 million and $300 million credit facilities, respectively, ~~replacing prior-credit agreements. Each of the credit facilities~~which may be used for general corporate purposes and commercial paper back-up. IDACORP's facility permits

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borrowings under a revolving line of credit of up to $100 million at any one time outstanding, including swingline loans not to exceed $10 million at any one time and letters of credit not to exceed $50 million at any one time. IDACORP's facility may be increased, subject to specified conditions, to $150 million. Idaho Power's facility permits borrowings through the issuance of loans and standby letters of credit of up to $300 million at any one time outstanding, including swingline loans not to exceed $30 million at any one time and letters of credit not to exceed $50 million at any one time outstanding. Idaho Power's facility may be increased, subject to specified conditions, to $450 million. The credit facilities currently provide for a maturity date of December 6, ~~2024,~~2025, though IDACORP and Idaho Power may request up to two-one-year extensions of the credit agreements, subject to certain conditions. Other terms and conditions of the credit facilities are described in the ~~2020~~2021 Annual Report, 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, ~~2021,~~2022, the leverage ratios for IDACORP and Idaho Power were 4344 percent and 46 percent, respectively. IDACORP's and Idaho Power's ability to utilize the credit facilities is conditioned upon their continued compliance with the leverage ratio covenants included in the credit facilities. There are additional covenants, subject to exceptions, that prohibit certain mergers, acquisitions, and investments, restrict the creation of certain liens, and prohibit entering into any agreements restricting dividend payments from any material subsidiary.

At June 30, ~~2021,~~2022, IDACORP and Idaho Power believed they were in compliance with all facility covenants. Further, IDACORP and Idaho Power do not anticipate they will be in violation or breach of their respective debt covenants during ~~2021.~~2022.

Without additional approval from the IPUC, the OPUC, and the WPSC, the aggregate amount of short-term borrowings up to three years by Idaho Power at any one time outstanding may not exceed $450 million. Idaho ~~Power~~Power has obtained approval of the IPUC, the OPUC, and the WPSC for the issuance of short-term borrowings through December 2026.

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

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Available Short-Term Borrowing Liquidity

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


		June 30, 2021				December 31, 2020					June 30, 2022				December 31, 2021
		IDACORP(2)		Idaho Power		IDACORP(2)		Idaho Power			IDACORP(2)		Idaho Power		IDACORP(2)		Idaho Power
Revolving credit facility	Revolving credit facility	$	100,000	$	300,000	$	100,000	$	300,000	Revolving credit facility	$	100,000	$	300,000	$	100,000	$	300,000
Commercial paper outstanding	Commercial paper outstanding	—		—		—		—		Commercial paper outstanding	—		—		—		—
Identified for other use(1)	Identified for other use(1)	—		(24,245)		—		(24,245)		Identified for other use(1)	—		(24,245)		—		(24,245)
Net balance available	Net balance available	$	100,000	$	275,755	$	100,000	$	275,755	Net balance available	$	100,000	$	275,755	$	100,000	$	275,755

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

(2) Holding company only.

On July ~~23, 2021,~~29, 2022, IDACORP had no loans outstanding under its revolving credit facilities and had no commercial paper outstanding. Idaho Power also had no loans outstanding under its revolving credit facilities and no commercial paper outstanding at that date. During the three and six months ended June 30, ~~2021,~~2022, IDACORP and Idaho Power issued no short-term commercial paper.

Impact of Credit Ratings on Liquidity and Collateral Obligations

IDACORP’s and Idaho Power’s access to capital markets, including the commercial paper market, and their respective financing costs in those markets, depend in part on their respective credit ratings. There have been no changes to IDACORP's or

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Idaho Power's ratings by ~~Standard & Poor’s Ratings Services (S&P) or Moody’s Investors Service (Moody's)~~S&P from those included in the ~~2020~~2021 Annual Report. 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. In ~~June 2021,~~July 2022, Moody's Investors Service (Moody's) Long-Term Issuer rating for IDACORP was downgraded to Baa2 from Baa1, and Idaho Power's Long-Term Issuer rating was downgraded to Baa1 from A3. In addition, Moody's ratings for Idaho Power's First Mortgage Bonds and Senior Secured Debt were downgraded to A2 from A1. IDACORP and IPC's short-term ratings for commercial paper were affirmed at Prime-2 and the outlook for ~~IDACORP and Idaho Power~~both companies were ~~modified to negative, from stable, due to Moody's perception of~~rated as stable. Following the companies' financial profile relative to its A-rated peers. Moody's rating outlook indicated that it expects that IDACORP and Idaho Power will not take any material actions to improve their cash flows over the next 12-18 months. As disclosed in the 2020 Annual Report, Moody's credit ratings ~~of IDACORP and Idaho Power are currently higher than the similar ratings of S&P. Were IDACORP’s and Idaho Power’s credit ratings at Moody’s to decrease to a similar level as S&P,~~changes, the companies’ credit ratings ~~would nonetheless~~ remain investment grade and the companies do not believe ~~it would~~the ratings changes will have a material impact on their liquidity ornor access to debt capital. Moody’s credit ratings of Baa3 and above are considered to be investment grade, or prime, ratings.

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, ~~2021,~~2022, Idaho Power had posted ~~$0.4~~$1.2 million cash performance assurance collateral related to these contracts. Should Idaho Power experience a reduction in its credit rating on its unsecured debt to below investment grade, Idaho Power could be subject to requests by its wholesale counterparties to post additional performance assurance collateral, and counterparties to derivative instruments and other forward contracts could request immediate payment or demand immediate ongoing full daily collateralization on derivative instruments and contracts in net liability positions. Based upon Idaho Power’s current energy and fuel portfolio and market conditions as of June 30, ~~2021,~~2022, the amount of additional collateral that could be requested upon a downgrade to below investment grade is approximately ~~$27.6~~$14.5 million. To minimize capital requirements, Idaho Power actively monitors its portfolio exposure and the potential exposure to additional requests for performance assurance collateral through sensitivity analysis.

Capital Requirements

Idaho Power's construction expenditures, excluding AFUDC, were ~~$122~~$187 million during the six months ended June 30, ~~2021. The cash expenditure amount excludes net costs of removing assets from service.~~2022. The table below presents Idaho Power's estimated accrual-basis additions to electric plant for ~~2021~~2022 (including amounts incurred to-date) through ~~2025~~2026 (in millions of dollars). The amounts in the table exclude AFUDCbut include net costs of removing assets from service that Idaho Power expects would be eligible to ~~include~~be included in rate base in future rate case proceedings. However, given the uncertainty associated with the timing of infrastructure projects and associated expenditures, actual expenditures and ~~their~~the timing of such expenditures could deviate substantially from those set forth in the table. The capital expenditure table below assumes, among other projects, construction and ownership of a number of resources identified in Idaho Power's 2021 IRP in order to safely and reliably serve the company's customers. The timing and amount of actual constructed projects and capital expenditures could be affected by Idaho Power’s ability to timely obtain labor or materials at

2021 2022 2023-2025
Expected capital expenditures (excluding AFUDC) $320-$330 $340-$350 $1,250-$1,350

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reasonable costs, supply chain disruptions and delays, regulatory determinations, inflationary pressures, macroeconomic conditions, or other issues.


	2022	2023	2024-2026
Expected capital expenditures (excluding AFUDC)	$500-$520	$690-$715	$1,450-$1,550

Major Infrastructure Projects: Idaho Power is engaged in the development of a number of significant projects and has entered into arrangements with third parties concerning joint infrastructure development. The discussion below provides a summary of developments in certain of those projects since the discussion of these matters included in Part II, Item 7 - "MD&A - Capital Requirements" in the ~~2020~~2021 Annual Report. The discussion below should be read in conjunction with that report.

Resource Additions to Address Projected Energy and Capacity Deficits: As noted previously, Idaho Power believes that existing and sustained growth in customers and peak demand for electricity, along with transmission constraints, will create the need for Idaho Power to acquire significant generation and storage resources to meet energy and capacity needs over the next several years. While demand varies and is based on numerous factors, Idaho Power's 2021 IRP indicated Idaho Power could have a resource capacity deficit for peak needs of 101 MW in 2023, an additional 85 MW deficit in 2024, and an additional 125 MW deficit in 2025. To help meet peak needs in 2023, Idaho Power has entered into contracts to purchase, own, and operate 120 MW of battery storage assets, and also entered into a 20-year power purchase agreement signed in February 2022 for the output of a planned third-party 40 MW solar facility. In March 2022, Idaho Power filed an application with the IPUC requesting approval of a revised special contract for electric service between Idaho Power and its existing industrial customer Micron under which Micron would purchase from Idaho Power the energy generated by the solar facility. To help address the capacity deficits projected for 2024 and 2025, Idaho Power has been pursuing multiple options and issued a request for proposal for resources in December 2021. Depending on factors such as RFP results, the timing of project in-service dates, updated load and resource balances and customer growth, and the outcome of regulatory proceedings, Idaho Power expects it could invest over $400 million in capital expenditures from 2022 through 2025 for resource additions to help meet the projected capacity deficits noted above.

Boardman-to-Hemingway Transmission Line: The Boardman-to-Hemingway line, a proposed 300-mile, high-voltage transmission project between a substation near Boardman, Oregon, and the Hemingway substation near Boise, Idaho, would provide transmission service to meet future resource needs. In January 2012, Idaho Power entered into a joint funding agreement with PacifiCorp and the Bonneville Power Administration (BPA) to pursue permitting of the project. The joint funding agreement ~~provides~~provided that Idaho Power's interest in the permitting phase of the project would be approximately 21 percent. Total cost estimates for the project are between $1.0 billion and $1.2 billion, including Idaho Power's AFUDC. This cost estimate is preliminary and excludes the impacts of inflation and price changes of materials and labor resources that may occur following the date of the estimate.

Approximately ~~$118~~$137 million, including Idaho Power's AFUDC, has been expended on the Boardman-to-Hemingway project through June 30, ~~2021.~~2022. Pursuant to the terms of the joint funding arrangements, Idaho Power has received ~~$78~~$87 million in reimbursement as of June 30, ~~2021,~~2022, from project co-participants for their share of costs. As of the date of this report, no material co-participant reimbursements are outstanding. Joint permitting participants are obligated to reimburse Idaho Power for their share of any future project permitting expenditures or agreed upon early construction expenditures incurred by Idaho Power under the terms of the joint funding agreement.

Idaho Power's share of the remaining permitting phase of the project (excluding AFUDC) is included in the capital requirements table above, which includes approximately $160 million of Idaho Power's share of estimated costs related to

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permitting, design, material procurement, and construction. The preliminary estimates of Idaho Power’s share of construction costs, which are primarily included in the table in the period 2023-2025, could significantly change as the construction timeline nears and as the project participants further align on future activities, allocation of ownership interests, and cost estimates. In addition to the estimated costs included in the table above, costs will continue to be incurred until the transmission line is placed into service.

The permitting phase of the Boardman-to-Hemingway project is subject to federal review and approval by the U.S. Bureau of Land Management (BLM), the U.S. Forest Service, the Department of the Navy, and certain other federal agencies. The BLM issued its record of decision for the project in November 2017, approving a right-of-way grant for the project to cross approximately 86 miles of BLM-administered land. The U.S. Forest Service issued its record of decision in November 2018 authorizing the project to cross approximately seven miles of National Forest lands. In September 2019, the Department of the Navy issued its record of decision authorizing the project to cross approximately seven miles of Department of the Navy lands. In November 2019, third parties filed a lawsuit in the federal district court of Oregon challenging the BLM and U.S. Forest Service records of decision for the Boardman-to-Hemingway project on several grounds. In ~~February 2020, Idaho Power filed a motion to intervene in~~August 2021, the ~~legal proceeding,~~federal district court of Oregon dismissed the third-party lawsuits challenging the records of decision for the Boardman-to-Hemingway project and the ~~motion was granted in April 2020. The litigation remains pending as of the date of this report, and a decision is expected in the second half of 2021.~~third parties did not file to appeal that decision.

In the separate State of Oregon permitting process, the Oregon Department of Energy ~~(ODOE)~~ issued a Proposed Order in July 2020 that recommends approval of the project to the state's Energy Facility Siting Council (EFSC). On May 31, 2022, at the conclusion of the administrative hearing, the hearing officer issued a proposed contested case order proposing Idaho Power be granted a site certificate to construct and operate the project in Oregon. The ~~project permit~~matter is ~~actively undergoing~~now before the EFSC, ~~administrative process, and~~which Idaho Power ~~currently~~ expects ~~the EFSC~~ to ~~issue~~make a final ~~order and site certificate~~decision in the second half of 2022.

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As the current joint funding agreement covers primarily permitting activities, which are nearing completion, Idaho Power and its co-participants have been exploring several scenarios of ownership, asset, and service arrangements aimed at maximizing the value of the project to each of the co-participants' customers. Under the current joint funding agreement, Idaho Power has an approximate 21 percent interest, BPA has an approximate 24 percent interest, and PacifiCorp has an approximate 55 percent interest in the permitting phase. As the current joint funding agreement covers primarily permitting activities, which are nearing completion, Idaho Power and its co-participants are exploring several scenarios of ownership, asset, and service arrangements aimed at maximizing the valuephase of the ~~project to each of~~project. In January 2022, the ~~co-participants' customers. In July 2021, the co-participants entered into an agreement and acknowledged that BPA does not intend to participate in the construction of the project or to be~~participants executed a ~~co-owner, in whole or in part, of the project, and that BPA intends to sell its interest in the project to either Idaho Power or a third party. Any changes~~non-binding term sheet regarding the ownership structure that would be addressed through amended or new funding agreements for the future phases of the project. The term sheet contemplates that Idaho Power would acquire BPA's ownership interest, which would increase Idaho Power's interest to approximately 45 percent, and Idaho Power would deliver transmission service to BPA's customers across Southern Idaho.

Total cost estimates for the project are between $1.0 billion and $1.2 billion, including Idaho Power's AFUDC. The capital requirements table above includes approximately $380 million of Idaho Power's share of estimated costs (excluding AFUDC) related to the remaining permitting phase, design, material procurement, and construction phases of the project. The preliminary estimates of construction costs could significantly change as the construction timeline nears and as the project participants obtain more detailed information on construction and material costs.

In July 2021, Idaho Power awarded contracts for detailed design, geotechnical investigation, land surveying, and right-of-way option acquisition; and that work commenced in the third quarter of 2021. In April 2022, Idaho Power awarded a contract for constructability consulting services. Idaho Power's 2021 IRP included the Boardman-to-Hemingway transmission line in its resource capacity plans for 2026. Given ~~the~~the status of ongoing permitting activities and the construction period, Idaho Power expects the in-service date for the transmission line will be no earlier than 2026.

Gateway West Transmission Line: Idaho Power and PacifiCorp are pursuing the joint development of the Gateway West project, a high-voltage transmission lines project between a substation located near Douglas, Wyoming, and the Hemingway substation located near Boise, Idaho. In January 2012, Idaho Power and PacifiCorp entered a joint funding agreement for permitting of the project. Idaho Power has expended approximately ~~$46~~$50 million, including Idaho Power's AFUDC, for its share of the permitting phase of the project through June 30, ~~2021.~~2022. 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 $250 million and $450 million, including AFUDC. Idaho Power's estimated share of ongoing expenditures for the permitting phase of the project (excluding AFUDC) is included in the capital requirements table above. Idaho Power's share of potential early construction costs are excluded from the capital requirements table above because the timing of construction of Idaho Power's portion of the project is uncertain.

The permitting phase of the Gateway West project was subject to review and approval of the BLM. The BLM has published its records of decision for all segments of the transmission line. PacifiCorp recently constructed and commissioned a 140-mile segment of their portion of the project in Wyoming. Idaho Power and PacifiCorp continue to coordinate the timing of next steps to best meet customer and system needs.

Defined Benefit Pension Plan Contributions

Idaho Power ~~contributed~~has no minimum contribution requirement to its defined benefit pension plan in 2022 and during the six months ended June 30, 2022, Idaho Power made a $10 million contribution. In July 2022, Idaho Power made an additional $10 million contribution to the defined benefit pension plan in the first half of 2021. In July 2021, Idaho Power contributed an additional $10 million to the plan. Idaho Power has no further minimum required contributions to be made to its defined benefit pension plan during 2021, but depending on market conditions and cash flows, Idaho Power expects it will contribute up to a total of $40 million to the pension plan for the full year of 2021. Idaho Power's contributions are made in a continued effort to balance the regulatory collection of these expenditures with the amount and timing of contributions and to mitigate the cost of being in an underfunded position. Idaho Power is considering contributing up to an additional $20 million to its defined benefit pension plan during 2022. The primary impact of pension contributions is on the timing of cash flows, as the timing of cost recovery lags behind contributions.

In March 2021, the American Rescue Plan Act of 2021 was signed into law, which included changes to the funding rules for single employer pension plans. The minimum funding requirements have been lowered by revising liability discount rates and by lengthening the period over which unfunded liabilities must be amortized. This did not have a material effect on Idaho Power's near-term pension contribution plans.

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Contractual Obligations

~~During the six months ended~~IDACORP’s and Idaho Power’s contractual cash obligations as of June 30, ~~2021, IDACORP's~~2022, include long-term debt, interest payments, purchase obligations, pension and ~~Idaho Power's~~post-retirement benefit plans, and other long-term liabilities specific to IDACORP, most of which are discussed throughout this MD&A. Refer to Note 8 – “Commitments” to the condensed consolidated financial statements included in this report for additional information relating to contractual obligations outside the ordinary course of business, did not change materially from the amounts disclosed in the 2020 Annual Report, except that Idaho Power entered into two new long-term transmission purchase agreements, which increased Idaho Power's contractual purchase obligations by approximately $16 million over the 5-year terms of the contracts, and five new replacement contracts for expiring power purchase agreements with PURPA-qualifying hydropower facilities, which increased Idaho Power's contractual purchase obligations by approximately $29 million over the 20-year terms of the contracts.companies.

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 the ~~2020~~2021 Annual Report.

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REGULATORY MATTERS

Introduction

Idaho Power is under the jurisdiction (as to rates, service, accounting, and other general matters of utility operation) of the IPUC, the OPUC, and the FERC. The IPUC and OPUC determine the rates that Idaho Power is authorized to charge 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. 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. Additionally, the FERC has jurisdiction over Idaho Power's sales of transmission capacity and wholesale electricity, hydropower project relicensing, and system reliability, among other items.

Idaho ~~Power's development of~~Power develops its regulatory filings ~~takes~~taking into consideration short-term and long-term needs for rate relief and ~~involves~~ several other factors that can affect the structure and timing of ~~these regulatory~~those filings. These factors include ~~among others,~~ in-service dates of major capital investments, the timing and magnitude of changes in major revenue and expense items, and customer growth ~~rates.~~rates, as well as other factors. Idaho Power's most recent general rate cases in Idaho and Oregon were filed during ~~2011. In~~2011, and in 2012, large single-issue rate cases for the Langley Gulch power plant ~~in Idaho and Oregon~~ resulted in the resetting of base rates in both Idaho and Oregon. Idaho Power also reset its base-rate power supply expenses in the Idaho jurisdiction for purposes of updating the collection of costs through retail rates in 2014 but without a resulting net increase in rates. The IPUC and OPUC have also approved base rate changes in ~~single issue~~single-issue cases subsequent to 2014.

Between general rate cases, Idaho Power relies upon customer growth, a ~~fixed cost adjustment~~FCA mechanism, power cost adjustment mechanisms, tariff riders, and other mechanisms to mitigate the impact of regulatory lag, which refers to the period of time between making an investment or incurring an expense and recovering that investment or expense and earning a return. Management's regulatory focus in recent years has been largely on regulatory settlement stipulations and the design of rate mechanisms. ~~In May 2021,~~With Idaho Power’s anticipated significant infrastructure investments that are intended to help meet projected near-term capacity deficits, Idaho Power’s evaluations indicate that the ~~IPUC ordered~~appropriate time to file general rate cases in both Idaho and Oregon is approaching. The resulting expected increase in rate-base eligible assets as these projects are placed into service, along with the significant amounts of capital expenditures Idaho Power to work with interested parties and initiate separate cases to review the PCA and FCA mechanisms and to propose any modifications it determines are appropriate so those cases may be processed before the filing of the 2022 PCA application in April 2022 and the 2022 FCA application in March 2022. Reviews of the mechanisms are ongoing, and to date, discussions have been productive and aimed toward mutually agreeable solutions. Idaho Power continues to assess the need and timing of filing ahas made since its last general rate case filed in ~~its two retail jurisdictions, based on its consideration of factors such as those described above, but does not anticipate filing a~~2011, will increase and potentially accelerate Idaho Power’s need to file general rate ~~case in the next twelve months.~~cases.

The outcomes of significant proceedings are described in part in this report and further in the ~~2020~~2021 Annual Report. In addition to the discussion below, which includes notable regulatory developments since the discussion of these matters in the ~~2020~~2021 Annual Report, refer to Note 3 - "Regulatory Matters" to the condensed consolidated financial statements included in this report for additional information relating to Idaho Power's regulatory matters and recent regulatory filings and orders.

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Notable Retail Rate Changes ~~During 2021~~

During ~~2021,~~2022, Idaho Power received orders authorizing the ~~rates~~rate changes summarized in the table below.

Description

Status

Estimated Annual Rate Impact(1)

Notes

Jim Bridger plant accelerated recovery

New base rates became effective June 1, 2022

$18.8 million increase effective June 1, 2022

The IPUC approved Idaho Power’s amended application requesting authorization to recover costs associated with its plan to cease participation in coal-fired operations at the Jim Bridger plant by 2028, as described in more detail below.

Power Cost Adjustment Mechanism - Idaho

New PCA rate became effective June 1, ~~2021~~2022

$~~39.1~~94.9 million ~~PCA~~ increase for the period from June 1, ~~2021~~2022, to May 31, ~~2022~~2023

The income statement impact of revenue changes 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. The rate increase reflects a forecasted reduction in low-cost ~~hydroelectric~~hydropower generation as well as higher costs associated with ~~PURPA power purchases.~~market energy prices and natural gas prices. The ~~net increase in PCA revenues~~filing also reflects ~~a smaller credit~~$0.6 million of 2021 earnings to be shared with customers ~~through~~under the ~~true-up component.~~May 2018 Idaho Tax Reform Settlement Stipulation described below.

Fixed Cost Adjustment Mechanism - Idaho

New FCA rate became effective June 1, ~~2021~~2022

$~~2.8~~3.1 million ~~FCA increase~~decrease for the period from June 1, ~~2021~~2022, to May 31, ~~2022~~2023

The FCA is designed to remove a portion of Idaho Power’s financial disincentive to invest in energy efficiency programs by partially separating (or decoupling) the recovery of fixed costs from the volumetric kilowatt-hour charge and instead linking it to a set amount per customer.

(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 retail sales volumes.

Idaho Earnings Support and Sharing from Idaho Settlement Stipulation

Based on its estimate of full-year ~~2021~~2022 Idaho ROE, in ~~both~~ the second quarter ~~and first six months~~ of ~~2021,~~2022, Idaho Power recorded no additional ADITC amortization or provision against current revenues for sharing of earnings with customers ~~for 2021~~ under the May 2018 Idaho Tax Reform Settlement Stipulation. Accordingly, at June 30, ~~2021,~~2022, the full $45 million of additional ADITC ~~remained~~remains available for future use. Idaho Power also recorded no additional ADITC amortization or provision against revenues for sharing of earnings with customers during the second quarter ~~and first six months~~ of ~~2020,~~2021, based on its then-current estimate of full-year ~~2020~~2021 Idaho ROE.

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

Deferred (accrued) 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 (accrued) power supply costs are recorded on the balance sheets for future recovery or refund through customer rates.

Idaho Power's power cost adjustment mechanisms in its Idaho and Oregon jurisdictions address the volatility of power supply costs and provide for annual adjustments to the rates charged to retail customers. The power cost adjustment mechanisms and associated financial impacts are described in "Results of Operations" in this MD&A and in Note 3 - "Regulatory Matters" to the condensed consolidated financial statements included in this report. With the exception of power supply expenses incurred under PURPA and certain demand response program costs that are passed through to customers substantially in full, the Idaho PCA mechanism allows Idaho Power to pass through to customers 95 percent of the differences in actual net power supply expenses as compared with base net power supply expenses, whether positive or negative. Thus, the primary financial statement impact of power supply cost deferrals or accruals is that the timing of when cash is paid out for power supply expenses differs from when those costs are recovered from customers, impacting operating cash flows from year to year.

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The following table summarizes the change in ~~accrued~~deferred (accrued) net power supply costs during the six months ended June 30, ~~2021~~2022 (in millions).


		Idaho		Oregon		Total			Idaho		Oregon		Total
Accrued net power supply costs at December 31, 2020		$	(14.7)	$	(0.3)	$	(15.0)
Deferred (accrued) net power supply costs at December 31, 2021								Deferred (accrued) net power supply costs at December 31, 2021	$	33.8	$	(0.3)	$	33.5
Current period net power supply costs accrued	Current period net power supply costs accrued	(16.1)		—		(16.1)		Current period net power supply costs accrued	(3.4)		—		(3.4)

Revenue sharing								Revenue sharing	(0.6)		—		(0.6)
Prior amounts refunded through rates	Prior amounts refunded through rates	18.3		0.1		18.4		Prior amounts refunded through rates	3.4		0.1		3.5
SO2 allowance and renewable energy certificate sales	SO2 allowance and renewable energy certificate sales	(3.3)		(0.1)		(3.4)		SO2 allowance and renewable energy certificate sales	(5.2)		(0.2)		(5.4)
Interest and other	Interest and other	1.5		(0.1)		1.4		Interest and other	1.5		(0.1)		1.4
Accrued net power supply costs at June 30, 2021		$	(14.3)	$	(0.4)	$	(14.7)
Deferred (accrued) net power supply costs at June 30, 2022								Deferred (accrued) net power supply costs at June 30, 2022	$	29.5	$	(0.5)	$	29.0

Open Access Transmission Tariff Draft Posting

Idaho Power uses a formula rate for transmission service provided under its OATT, which allows transmission rates to be updated annually based primarily on financial and operational data Idaho Power files with the FERC. The existing OATT rate in effect from October 1, 2021, to September 30, 2022, is $31.19 per kW-year based on a net annual transmission revenue requirement of $127.3 million.In June ~~2021,~~2022, Idaho Power publicly posted its ~~2021~~2022 draft transmission rate, reflecting a transmission rate of ~~$31.19~~$31.42 per "kW-year," to be effective for the period from October 1, ~~2021,~~2022, to September 30, ~~2022.~~2023. A "kW-year" is a unit of electrical capacity equivalent to 1 kilowatt of power used for 8,760 hours. Idaho Power's draft rate was based on a net annual transmission revenue requirement of ~~$127.3~~$132.7 million. ~~The existing OATT rate in effect from October 1, 2020, to September 30, 2021, is $29.95 per kW-year based on a net annual transmission revenue requirement of $117.7 million.~~ The increase in the draft OATT rate is largely attributable to increased transmission plant ~~as well as decreased short-term firm and non-firm transmission revenues~~ in ~~2020, which serve as an offset to the transmission revenue requirement.~~service.

~~Integrated~~Oregon Resource ~~Plan~~Procurement Filing

The IPUC and OPUC require that Idaho Power prepare biennially an Integrated Resource Plan (IRP). The IRP seeks to forecast Idaho Power's loads and resources for a 20-year period; analyzes potential supply-side, demand-side, and transmission resource options; and identifies potential near-term and long-term actions.In December 2021, Idaho Power filed an application with the OPUC requesting a waiver of Oregon's competitive bidding rules for Idaho Power's procurement of resources to fill near-term capacity deficits. Specifically, Idaho Power requested that the OPUC issue an order waiving Idaho Power’s obligation to comply with the competitive bidding rules for its ~~most recent IRP~~proposed resource procurement in favor of a modified competitive process and authorizing Idaho Power to move forward expeditiously with resource procurement to meet identified resource needs in 2023, 2024, and 2025. In March 2022, the OPUC issued an order denying Idaho Power's request to waive the competitive bidding rules. However, as allowed by the OPUC in certain cases, Idaho Power is pursuing an exception for 2023 resource needs, and plans to pursue additional exceptions to the competitive bidding rules for certain projects to meet the identified resource needs in 2024 and 2025.

Filing for Certificate of Public Convenience and Necessity for Battery Storage Projects

In April 2022, Idaho Power filed an application with the IPUC requesting that the IPUC issue a Certificate of Public Convenience and ~~OPUC~~Necessity (CPCN) authorizing Idaho Power to install, own, and operate two battery storage facilities. The 120 MW combined capacity of the two projects is planned to help meet peak energy needs in ~~June~~the summer of 2023 and beyond. The CPCN is intended to allow the IPUC to review the need for the project prior to Idaho Power incurring the bulk of the associated expenses. As of the date of this report, the IPUC's decision in this matter is pending.

Customer-Owned Generation Filing

Customer-owned generation allows customers to install solar panels or other on-site energy-generating resources and connect them to Idaho Power’s grid. If a customer requires more energy than its system generates, it uses energy supplied by Idaho Power’s grid and infrastructure. If a customer's system generates more energy than the customer uses, the energy is transferred to the grid and Idaho Power applies a corresponding kilowatt-hour credit to the customer’s bill. In May 2018, the IPUC issued an order authorizing the creation of two new customer classes for residential and small commercial customers who install their own on-site generation, with no change to pricing or compensation. Since October 2018, Idaho Power has initiated several cases with the IPUC related to studying the costs and benefits of customer-owned generation on Idaho Power’s system, and exploring whether, and to what extent, there should be modifications to the customer-owned generation pricing structure for residential and small general service customers, and large commercial, industrial, and irrigation customers (CI&I). The IPUC issued orders in December 2019 and February 2020 directing Idaho Power to (1) complete additional studies related to the costs and benefits of customer generation before changes to the compensation structure are implemented, and (2) continue to allow residential and small commercial customers with on-site generation installed prior to December 20, 2019, to be subject to the compensation and billing structure in place on that date until December 20, 2045. In December 2020, the IPUC issued an order

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establishing a 25-year grandfathering term for CI&I customers, similar to the terms approved for the residential and small commercial customer classes.

In June 2021, Idaho Power filed an amended 2019 IRP with additional information and modeling results in January 2020, as described in Part 1, Item 1 - "Resource Planning and Renewable Energy Projects" in the 2020 Annual Report. In March 2021 and April 2021,application requesting that the IPUC initiate the multi-phase process for a comprehensive study of the costs and ~~OPUC, respectively, acknowledged the second amended 2019 IRP.~~benefits of on-site generation as directed by previous IPUC orders. In ~~May~~December 2021, the IPUC issued an order ~~approving Idaho Power's request to extend the filing deadline of the 2021 IRP to the last business day of December 2021.~~

~~Depreciation Rate Update Requests~~

~~In 2021,~~requiring Idaho Power ~~conducted a depreciation~~to complete the comprehensive study on the costs and benefits of ~~electric plant-in-service, which it performs approximately every five years. The~~on-site generation based on the IPUC’s study ~~provided updates to net salvage percentages~~framework findings and ~~service life estimates for~~conclusions, and requiring that Idaho Power ~~plant assets. Based on~~complete the study in 2022 as soon as feasible. In June ~~2021,~~2022, Idaho Power filed ~~applications~~the comprehensive study with a proposed schedule that would allow the IPUC ~~and OPUC, requesting approval~~ to ~~institute revised depreciation rates for Idaho Power's electric plant-in-service and adjust base rates by an aggregate of $3.9 million to reflect~~issue a determination regarding the revised depreciation rates applied to electric plant-in-service balances subject to the most recent general rate cases. The proposed adjustments in these applications are an overall rate increase of 0.31 percent in Idaho and 0.24 percent in Oregon. Idaho Power requested an effective date of December 1, 2021, for these adjustments, and asfuture structure of the ~~date~~service offering by the end of ~~this report, orders from the IPUC and OPUC are pending.~~2022, with implementation no earlier than June 2023.

Jim Bridger Power Plant Rate ~~Request~~Base Adjustment and Recovery

~~Also in~~In June ~~2021,~~2022, the IPUC issued an order approving, with modifications, Idaho ~~Power filed an~~Power’s amended application ~~with the IPUC~~ requesting authorization to (a) accelerate depreciation for the Jim Bridger plant, to allow the coal-related plant assets to be fully depreciated and recovered by December 31, 2030, (b) establish a balancing account to track the incremental costs, benefits, and ~~benefits~~required regulatory accounting associated with ceasing participation in coal-fired operations at the Jim Bridger plant, and (c) adjust customer rates to recover the associated incremental annual levelized revenue requirement (Bridger Order).The Bridger Order and associated accounting are described in Note 3 – “Regulatory Matters” to the condensed consolidated financial statements included in this report. As a result of the Bridger Order, Idaho Power recorded the deferral of certain depreciation expense in the ~~aggregate amount~~second quarter of ~~$30.8 million, which includes~~2022. Idaho ~~Power's share of~~Power plans to cease participation in all ~~electric plant in service~~coal-related operations at the Jim Bridger ~~plant. The proposed adjustment in this application is an overall rate increase of 2.53 percent in Idaho.~~plant by 2028. Idaho Power ~~requested an effective date of December 1, 2021, for this adjustment,~~expects the Bridger Order to increase operating revenues, net depreciation expense, and asincome tax expense in future periods, and estimates the impacts of the ~~date of this report, an~~ order will increase after-tax net income by approximately $10 million in 2023. Idaho Power expects the ongoing annual benefit to net income from the ~~IPUC is pending.~~Bridger Order to decline each year through 2030, primarily due to the annual decline in Jim Bridger plant coal-related rate base, which Idaho Power expects to be fully depreciated by December 31, 2030.

Wildfire Mitigation Cost Deferral

In June 2021, the IPUC authorized Idaho Power to defer for future amortization incremental O&M and depreciation expense of

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certain capital investments necessary to implement the company's WMP. The IPUC also authorized Idaho Power to record these deferred expenses as a regulatory asset until the company can request amortization of the deferred costs in a future IPUC proceeding, at which time the IPUC will have the opportunity to review actual costs and determine the amount of prudently incurred costs that Idaho Power can recover through retail rates. Idaho Power projects spending approximately $47 million in incremental wildfire mitigation-related O&M and roughly $35 million in wildfire mitigation system-hardening capital incremental expenditures over the next five years. The IPUC authorized a deferral period of five years, or until rates go into effect after Idaho Power's next general rate case, whichever is first. As of June 30, ~~2021,~~2022, Idaho ~~Power had not recorded any~~Power’s deferral of Idaho-jurisdiction costs related to the WMP ~~as Idaho Power does not expect to incur significant incremental costs in connection with many of the projects identified in the plan until the second half of 2021.~~was $14.8 million.

~~Valmy Plant Exit Date~~Industrial Customer Dedicated Renewable Resource

In ~~April 2021,~~March 2022, Idaho Power filed an application with the IPUC requesting approval of a revised special contract for electric service between Idaho Power and its existing industrial customer, Micron. The application included an ~~acknowledgment~~arrangement under which Micron would be the purchaser from Idaho Power of the energy generated by a to-be-constructed 40 MW solar facility pursuant to a 20-year power purchase agreement between Idaho Power and a third party. The solar facility is scheduled to begin operating as early as June 2023. Idaho Power also requested in the application revised electric service rates for Micron that include new energy rates that incorporate the solar generation and compensation for capacity value and excess renewable energy generation. The application is modeled after a separate case pending before the IPUC requesting that Idaho Power be permitted to expand customer clean energy offerings through a new "Clean Energy Your Way" program, which would provide certain large customers the opportunity to purchase the output of renewable energy facilities, as described in the 2021 Annual Report in Part II, Item 7 - "Regulatory Matters." In early August, the IPUC issued an order approving Idaho Power’s application, with modifications, which Idaho Power is evaluating as of the date of this report.

Large Customer Rate Proceedings - Speculative High-Density Load

In June 2022, the IPUC approved Idaho Power's application to create a new customer class that would be applicable to commercial and industrial cryptocurrency mining operations, or any other speculative high-density load customers of less than 20 MW. Idaho Power has received approximately 2,000 MW of potential customer interest from this industry and believes new system resources may be necessary to serve this speculative customer load, which could create a financial risk for Idaho Power

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and its ~~year-end 2025 exit date~~customers if the underlying economics of cryptocurrency mining change. Idaho Power believes that the financial and system risks of speculative high-density load could be mitigated through rate design for this customer class, which prices energy at a marginal rate, and through a requirement that speculative high-density load customers be interruptible at Idaho Power's discretion from ~~Valmy unit 2 is appropriate based on economics~~June 15 through September 15, Idaho Power's summer peak season. On July 6, 2022, a prospective cryptocurrency mining customer of Idaho Power filed a petition for late intervention and ~~reliability needs. As~~reconsideration of the IPUC's approval of the new speculative high-density load customer class. Idaho Power filed an answer requesting the IPUC deny both the request for intervention and reconsideration and, as of the date of this report, ~~comments from intervenors and an order from~~a decision on the ~~IPUC are~~petition is pending.

Renewable and Other Energy Contracts

Idaho Power has contracts for the purchase of electricity produced by third-party owned generation facilities, most of which produce energy with the use of renewable generation sources such as wind, solar, biomass, small hydropower, and geothermal. The majority of these contracts are entered into as mandatory purchases under PURPA. As of June 30, ~~2021,~~2022, Idaho Power had contracts to purchase energy from 129 online PURPA projects. An additional three contracts are with online non-PURPA projects, including the Elkhorn Valley wind project with a 101-MW nameplate capacity.

The following table sets forth, as of June 30, ~~2021,~~2022, the resource type and nameplate capacity of Idaho Power's signed agreements for power purchases from PURPA and non-PURPA generating facilities. These agreements have original contract terms ranging from one to 35 years.


Resource Type	Resource Type	On-line megawatts (MW)	Under Contract but not yet On-line (MW)	Total Projects under Contract (MW)	Resource Type	On-line (MW)	Under Contract but not yet On-line (MW)	Total Projects under Contract (MW)
PURPA:	PURPA:				PURPA:
Wind	Wind	627	—	627	Wind	627	—	627
Solar	Solar	316	3	319	Solar	316	74	390
Hydropower	Hydropower	150	1	151	Hydropower	150	1	151
Other	Other	44	—	44	Other	44	—	44
Total	Total	1,137	4	1,141	Total	1,137	75	1,212
Non-PURPA:	Non-PURPA:				Non-PURPA:
Wind	Wind	101	—	101	Wind	101	—	101
Geothermal	Geothermal	35	—	35	Geothermal	35	—	35
Solar	Solar	—	120	120	Solar	—	160	160
Total	Total	136	120	256	Total	136	160	296

The projects not yet ~~online~~on-line include one ~~PURPA~~PURPA-qualifying facility hydropower project that is scheduled to be ~~online later this year~~on-line in 2022, two PURPA-qualifying facility solar projects scheduled to be on-line in 2023, and one ~~PURPA~~PURPA-qualifying facility solar project scheduled to be on-line in ~~2022. The~~2024. One non-PURPA solar project is scheduled to be online in ~~2022.~~2022 and another in 2023.

In July 2020, the FERC issued Order No. 872, which could affect how states determine PURPA project avoided cost rates for purchases of power generated from PURPA qualifying facilities (QF), which facilities are eligible for QF status, whether and when certain QFs can enter into purchase agreements with utilities, and how parties can contest the eligibility of a generation facility seeking QF status. As of the date of this report, Idaho Power is unable to determine the impact of these potential changes on the company's future obligations for ~~new~~ PURPA power purchase contracts. Further action by the state public utility commissions is required to implement many of the changes. Substantially all PURPA power purchase costs are recovered through base rates and Idaho Power's power cost adjustment mechanisms.

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~~Customer-Owned Generation Filings~~

Customer-owned generation allows customers to install solar panels or other on-site energy-generating resources and connect them to Idaho Power’s grid. If a customer requires more energy than its system generates, it utilizes energy supplied by Idaho Power’s grid. If a customer's system generates more energy than the customer uses, the energy goes back to the grid and Idaho Power applies a corresponding kWh credit to the customer’s bill. Idaho Power has filed various cases with the IPUC related to customer generation as described in Part II, Item 7 - "Regulatory Matters" in the 2020 Annual Report. In March 2021, the IPUC issued an order approving Idaho Power's application as filed that establishes a smart inverter requirement for all new on-site energy-generating resources interconnected to the company's system, among other things. In June 2021, Idaho Power filed an application requesting that the IPUC initiate the multi-phase process for a comprehensive study of the costs and benefits of on-site generation as directed by previous IPUC orders. Idaho Power expects to complete the first phase of the proposed process involving a study design by the end of 2021.

Relicensing of Hydropower Projects

HCC Relicensing: In connection with Idaho Power's efforts to relicense the HCC, Idaho Power's largest hydropower complex and a major relicensing effort, as described in more detail in the ~~2020~~2021 Annual Report in Part II, Item 7 - "Regulatory Matters," Idaho Power filed water quality certification applications, required under Section 401 of the Clean Water Act (CWA), with the states of Idaho and Oregon requesting that each state certify that any discharges from the project comply with applicable state water quality standards. Idaho Power continues to work with the states ~~to identify~~on measures that will provide reasonable assurance that discharges from the HCC will adequately address applicable water quality standards.

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In April 2019, the states of Idaho and Oregon, along with Idaho Power, reached a settlement pertaining to the CWA Section 401 certification that requires Idaho Power, among other measures, to increase the number of Chinook salmon it releases each year through expanded hatchery production. Additionally, Idaho Power is required to fund a total of $12 million of research and water quality improvements in the HCC over a 20-year period following the issuance of the license. Idaho Power estimates that the combined cost of the mandated water quality improvements and expanded hatchery production is $20 million in aggregate over the first 20 years of the new license term. In May 2019, Oregon and Idaho issued final CWA Section 401 certifications. These certifications have been submitted to the FERC as part of the relicensing process. In July 2019, three third parties filed lawsuits against the Oregon Department of Environmental Quality in Oregon state court challenging the Oregon CWA Section 401 certification based on fish passage, water temperature, and mercury issues associated with the Snake River and the HCC. Two of the lawsuits were consolidated, and Idaho Power ~~has~~ intervened in that ~~lawsuit.~~lawsuit and the parties reached a settlement. The court dismissed the third challenge to the Oregon CWA 401 certification with prejudice. No parties challenged the Idaho CWA 401 certification. In December 2019, Idaho Power filed an Offer of Settlement with the FERC requesting specific language be included in the new HCC license based upon the settlement among Idaho, Oregon, and Idaho Power. During the first quarter of 2020, the FERC received several comments opposing the Offer of Settlement, and its decision relating to the Offer of Settlement is pending as of the date of this report.

In July 2020, Idaho Power submitted to the FERC its supplement to the final license application that incorporated the settlement agreement reached between Idaho and Oregon on the CWA Section 401 certifications and provided feedback on proposed modification of the 2007 final environmental impact statement for the HCC. The July 2020 filing also contained an updated cost analysis of the HCC and a request for the FERC to issue a 50-year license and initiate a supplemental National Environmental Policy Act (NEPA) process at the FERC. Idaho Power prepared draft biological assessments in consultation with the U.S. Fish and Wildlife Service (USFWS) and the National Marine Fisheries Service (NMFS) and filed those with the FERC in October 2020. The draft biological assessments provide information to the USFWS and the NMFS that is necessary to issue their biological opinion as required under the Endangered Species Act (ESA). In December 2020, FERC staff issued six ~~requests for~~ additional information requests (AIRs) from Idaho Power to help with the analysis and baseline for the project moving forward. Idaho Power has filed responses to all six of the ~~requests~~AIRs with the FERC. Subsequently, in September 2021 FERC asissued ten additional AIRs to clarify the cost of the date of this report. Once FERC has evaluated the additional information, Idaho Power expects it to decide what, if any, additional environmental analysis is necessary to issue a license. Idaho Power expectsproposed mitigation measures. In June 2022, the FERC issued a notice of intent to prepare a draft and final supplemental environmental impact statement (EIS) in accordance with NEPA. The FERC indicated that the supplemental EIS will address the new and revised measures proposed by the 401 certification settlement, the conditions contained in the Oregon and Idaho water quality certificates, and the information provided in the draft biological assessments. The FERC also ~~initiate formal ESA~~reinstated informal consultation with the USFWS and NMFS under section 7 of the ~~NMFS. The FERC could issue an HCC license as early as 2022, but as~~ESA. As of the date of this report, Idaho Power believes issuance ~~is more likely~~of a new HCC license by the FERC will be in ~~2023~~2024 or thereafter.

As of the date of this report, Idaho Power is unable to predict the exact timing that the FERC will issue a new license order or the ultimate capital investment and ongoing operating and maintenance costs Idaho Power will incur in complying with any new license. Idaho Power estimates that the annual costs it will incur to obtain a new long-term license for the HCC, including AFUDC, are likely to range from $30 million to $40 million until issuance of the license. Subsequent to the issuance of a new license, Idaho Power expects to incur increased annual operating and maintenance costs to comply with the requirements of any new license.

Costs for the relicensing of Idaho Power's hydropower 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 and costs related to a new long-term license through the regulatory process. Relicensing costs of ~~$372~~$406 million (including AFUDC) for the HCC were included in construction work in progress at June 30, ~~2021.~~2022. As of the date of this report, the IPUC authorizes Idaho Power to include in its Idaho jurisdiction rates $8.8 million of

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AFUDC annually relating to the HCC relicensing project. Collecting these amounts currently will reduce future collections when HCC relicensing costs are approved for recovery in base rates. As of June 30, ~~2021,~~2022, Idaho Power's regulatory liability for collection of AFUDC relating to the HCC was approximately ~~$178~~$197 million.

When the FERC issues a new long-term license, Idaho Power will begin operating under the requirements contained in the new license. Idaho Power expects those requirements to increase both O&M expenditures and capital expenditures. Because Idaho Power is uncertain when the FERC will issue a new license, it has not included the expected capital expenditure increases in the “Capital Requirements” section of “Liquidity and Capital Resources” of this MD&A. Idaho Power is unable to predict the exact timing of issuance of a new license for the HCC, or the ultimate financial or operational requirements of a new license.

American Falls Relicensing: In April 2020, the FERC formally initiated the relicensing ~~proceeding for~~of the American Falls hydropower facility, which is Idaho Power's largest hydropower facility outside of the HCC, with a generating capacity of 92.3 MW. Idaho Power owns the generation facility but not the structural dam itself, which is owned by the U.S. Bureau of Reclamation. The FERC recognized Idaho Power’s pre-application document, including a proposed process plan and schedule, and recognized Idaho Power’s intent to file an application for a license. A final license application is due to the FERC in 2023. The relicensing ~~proceeding will begin~~has begun the process of informal ESA Section 7 consultation with the USFWS and Section 106 of the National Historic Preservation Act consultation with the Idaho State Historic Preservation Office. American Falls' current license expires in 2025,

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and as of the date of this report, Idaho Power expects the FERC to issue a new license for this facility concurrent with or prior to the existing license's expiration.

ENVIRONMENTAL MATTERS

Overview

Idaho Power is subject to a broad range of federal, state, regional, and local laws and regulations designed to protect, restore, and enhance the environment, including the Clean Air Act (CAA), the CWA, the Resource Conservation and Recovery Act, the Toxic Substances Control Act, the Comprehensive Environmental Response, Compensation and Liability Act, and the ESA, among other laws. These laws are administered by various 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 two jointly-owned coal-fired power plants and three wholly-owned natural gas-fired combustion turbine power plants are subject to many of these regulations. Idaho Power's 17 hydropower projects are also subject to numerous 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, fuel-switching, or shut-down of existing generating plants;

•reduce the output from current generating facilities; or

•require the acquisition of alternative sources of energy or storage technology, increased transmission wheeling, or require construction of additional generating facilities, which could result in higher costs.

Current and future environmental laws and regulations ~~may~~could significantly increase the cost of operating fossil fuel-fired generation plants and constructing new generation and transmission facilities, in large part through the substantial cost of permitting activities and the required installation of additional pollution control devices. In many parts of the United States, some higher-cost, high-emission coal-fired plants have ceased operation or the plant owners have announced a near-term cessation of operation, as the cost of compliance makes the plants uneconomical to operate. The decision to cease operations of the Boardman power plant in 2020 was based in part on the significant cost of compliance with environmental laws and regulations. The decision to pursue an end to participation in coal-fired operations at the Valmy plant was also based primarily on the economics of operating the plant. Beyond increasing costs generally, these environmental laws and regulations could affect IDACORP's and Idaho Power's results of operations and financial condition if the costs associated with these environmental requirements and early plant retirements and new replacement resource costs cannot be fully recovered in rates on a timely basis.

Part I - "Business - Utility Operations - Environmental Regulation and ~~Costs"~~Costs" in the ~~2020~~2021 Annual Report, includes a summary of Idaho Power's expected capital and operating expenditures for environmental matters during the period from ~~2021~~2022 to ~~2023.~~2024. Given the uncertainty of future environmental regulations and technological advances, there is uncertainty around near-term estimates, and Idaho Power is also unable to predict its environmental-related expenditures and infrastructure investments beyond ~~that time,~~2024, though they could be substantial.

A summary of notable environmental matters (including conditions and events associated with climate change) impacting, or expected to potentially impact, IDACORP and Idaho Power is included in Part II, Item 7 - "MD&A - Environmental Issues" and "MD&A - Liquidity and Capital Resources - Capital Requirements - Environmental Regulation Costs" in the ~~2020~~2021 Annual Report. Developments in certain environmental matters relevant to Idaho Power are described below.

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Endangered Species Act Matters

Changes to the Endangered Species Act:The listing of a species, or changes to the critical habitat designations, of fish, wildlife, or plants as threatened or endangered under the ESA, may have an adverse impact on Idaho Power's ability to construct ~~generation,~~power supply, transmission, or distribution facilities or relicense or operate its hydropower facilities. ~~When~~In August 2019, under the previous presidential administration, the USFWS and the NMFS issued a ~~species is added~~set of regulatory changes to some of the ~~federal list of threatened~~standards under which listing, delisting, and ~~endangered species, it is protected from “take,” which is defined to include harming the species. The ESA directs that, concurrent with a designation of a threatened or endangered species,~~reclassifications and where prudent and determinable, the applicable agencies also designate “any habitat of such species which is then considered to be critical habitat.” The ESA also provides that each federal agency must ensure that any action they authorize, fund, or carry out is not likely to jeopardize the continued existence of a listed species or result in the destruction or adverse modification of its critical habitat. If an action is determined to result in adverse modification of critical habitat ~~the federal agency must adopt changes to the proposed action to avoid the adverse modification. These changes~~designations are ~~often quite extensive and can affect the size, scope, and even the feasibility of a project moving forward.~~

made (2019 ESA Rules). In ~~June~~October 2021, in response to ~~the new Presidential Administration's executive order~~January 2021 Executive Orders directing federal agencies to review certain environmental regulations, ~~(January 2021 Executive Order),~~ the USFWS and the NMFS ~~released a plan~~proposed new rules to ~~initiate rulemaking~~remove certain exclusions for designating critical habitat and to ~~revise,~~ rescind ~~or reinstate five ESA regulations finalized by~~ the prior ~~administration. The agencies announced that they intend to rescind regulations that revised the USFWS's process for considering exclusions from critical habitat designations, rescind the~~administration's regulatory definition of ~~habitat, revise regulations~~habitat. In July 2022, the U.S. District Court for ~~listing species~~the Northern District of California (Ninth Circuit) issued an order remanding and ~~designating critical habitat, revise regulations for interagency cooperation,~~vacating the 2019 ESA Rules, which order applies nationwide. While the USFWS and ~~reinstate certain protections for species listed as threatened~~the NMFS continue to work toward finalizing the new rules, Idaho Power plans to continue to operate under the ~~ESA. As described~~ESA rules in ~~Part II, Item 7 - "MD&A - Environmental Issues"~~effect prior to the 2019 ESA Rules.

Developments in Regulation of Sage Grouse Habitat: In February 2016, a lawsuit was filed in the ~~2020 Annual Report, these ESA regulations could impact~~U.S. District Court of Idaho challenging the ~~timing~~BLM's sage grouse resource management and ~~feasibility of~~land use plan revisions that became effective in 2015 under the ~~HCC relicensing project~~Federal Land Policy and Management Act. The lawsuit challenges the plans and associated EISs across the sage grouse range and alleges that the plans fail to ensure that sage grouse populations and habitats will be protected and restored in accordance with the best available science and legal mandates. Further, the complaint challenges certain exemptions provided for the Boardman-to-Hemingway and Gateway West ~~and Boardman-to-Hemingway~~ transmission line projects. Idaho Power has intervened in the proceedings in an effort to support the exemptions provided for in the BLM's plans. If the exemptions are overturned, Idaho Power may be required to re-route the projects, ~~and other infrastructure,~~ which could lead to substantially higher construction ~~permitting,~~ and ~~licensing~~permitting costs and could delay construction.

In May 2016, a separate lawsuit was filed in the U.S. District Court of North Dakota, challenging the BLM's sage grouse resource management and land use plan revisions, including the exemptions provided for the Boardman-to-Hemingway and Gateway West transmission line projects. In October 2016, the plaintiffs amended their complaint to no longer challenge the exemptions; however, in December 2016, the North Dakota court transferred claims challenging certain Idaho land use plan amendments to the U.S. District Court for the District of Columbia. Idaho Power is participating in the proceedings in an effort to protect its interests.

In June 2017, the Secretary of the Interior issued an order directing the BLM to review the 2015 sage grouse resource management and land use plan revisions and to identify provisions that may require modification or rescission to address energy and other development of public lands. In March 2019, the BLM issued a record of decision for six EISs that modified the 2015 sage grouse plans to better align the plan with state plans, conservation measures and the Department of the Interior and BLM policy. In October 2019, the U.S. District Court for Idaho placed a preliminary injunction on the implementation of the BLM's March 2019 plans. In order to address the concerns contained in the preliminary injunction, BLM initiated a supplemental EIS process that was completed in November 2020. A record of decision for the 2020 supplemental EIS was signed in January 2021. In November 2021, the BLM issued a notice of intent to address the management of sage grouse and sagebrush habitat on BLM-managed public lands in Idaho and Oregon, among other states, through a land use planning initiative. In February 2022, BLM issued a notice of intent to amend its land use plans regarding sage grouse conservation and prepare associated EISs, soliciting public comments on the planning initiative.

As of the date of this report, the above lawsuits are stayed as the parties and the courts have agreed that the processes initiated by the BLM may result in further administrative actions that could remove the need for the lawsuits.

Hells Canyon Relicensing Project: In December 2004, Idaho Power and eleven other parties, including the NMFS and the USFWS, entered into an interim agreement that addresses the effects of the ongoing operations of the HCC on ESA listed species pending the relicensing of the project. In 2007, the FERC requested initiation of formal consultation under the ESA with the NMFS and the USFWS regarding potential effects of HCC relicensing on several listed aquatic and terrestrial species. Idaho Power prepared draft biological assessments in consultation with the USFWS and the NMFS and filed those with the FERC in October 2020. The draft biological assessments are intended to provide the necessary information to the USFWS and the NMFS to issue their biological opinion as required under the ESA. In June 2022 the FERC issued a notice of intent to prepare a draft and final supplemental EIS in accordance with NEPA. The FERC indicated that the supplemental EIS will address the new and revised measures proposed by the 401 certification settlement, the conditions contained in the Oregon and Idaho water quality certificates, and the information provided in the draft biological assessments. The FERC also reinstated informal consultation with the USFWS and NMFS under section 7 of the ESA. As of the date of this report, Idaho Power believes that the issuance of a final biological opinion during 2022 is unlikely.

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Changes to NEPA: In July 2020, the previous Presidential Administration's Council on Environmental Quality (CEQ) announced its final rule to narrow federal agencies' NEPA obligations (2020 NEPA Rule), which had the potential to expedite and reduce the cost of Idaho Power's permitting and right-of-way processes. NEPA applies to Idaho Power’s transmission and distribution lines that are located on federal land, as well as other company activities involving federal actions. Under Executive Order 13990 issued in January 2021, the current Presidential Administration’s CEQ was tasked with reviewing the 2020 NEPA Rule. In October 2021, the CEQ published a notice of proposed rulemaking to reverse the more narrow 2020 NEPA Rule, with minor modifications (2021 NEPA Rule). In April 2022, the CEQ published a final rule consistent with the proposed 2021 NEPA Rule, that restores the requirement that federal agencies consider all indirect and cumulative environmental impacts of infrastructure projects in their decision-making, among other things, which could delay and increase the cost of Idaho Power’s infrastructure projects. Also in April 2022, the current Presidential Administration announced that the CEQ will propose a second phase of changes to NEPA that are aimed at further climate change related reform.

Clean Air Act Matters

Regional Haze Rules: 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 units at the Jim Bridger plant.

In December 2009, the ~~WDEQ~~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 for regional haze, the permit required that PacifiCorp install selective catalytic reduction ~~(SCR)~~ equipment for nitrogen oxide ~~(NOx)~~(NOx) control at Jim Bridger units 3 and 4 by December 31, 2015, and December 31, 2016, respectively, which has been completed, and submit an application by December 31, 2017, to install add-on ~~NOx~~NOx controls at Jim Bridger unit 2 by ~~December 31,~~ 2021 and unit 1 by ~~December 31,~~ 2022, which was submitted in December 2017. ~~In November 2010,~~ PacifiCorp ~~and~~has been negotiating with the WDEQ ~~signed a settlement agreement under which PacifiCorp agreed~~since 2009 to settle on terms of the timing and nature of controls for the ~~controls. The settlement agreement was conditioned~~Jim Bridger plant units. More information on the ~~EPA ultimately approving those portions~~history of the permitting process for the Jim Bridger plant is included in Part II, Item 7 - "MD&A - Environmental Issues" in the 2021 Annual Report.

On December 27, 2021, Wyoming ~~regional haze~~Governor Gordon issued a temporary emergency suspension of Wyoming’s existing state implementation plan (SIP) that ~~are consistent with~~allows Jim Bridger unit 2 to continue to operate through the ~~terms~~end of April 2022. On January 12, 2022, the U.S. Environmental Protection Agency (EPA) issued a proposed rule that, if adopted, would disapprove the 2019 proposed SIP revision, and the proposed rule was published in the Federal Register on January 18, 2022. Comments on the proposed disapproval were due by February 17, 2022, and as of the ~~settlement agreement. In January 2014,~~date of this report, the proposed EPA ~~approved Wyoming's regional haze SIP~~rule is pending. On February 14, 2022, the State of Wyoming filed a complaint against PacifiCorp as ~~to the Jim Bridger plant,~~well as a negotiated consent decree with ~~the NO~~x ~~control compliance dates set forth~~PacifiCorp in ~~the settlement agreement.~~

~~In February 2019, PacifiCorp submitted a SIP revision to the WDEQ as an alternative regional haze compliance plan~~Wyoming state court for the ~~Jim Bridger plant that includes a reduced plant-wide monthly limit on emissions for NO~~x ~~and SO~~2 ~~and an annual total emissions cap for NO~~x ~~and SO~~2 ~~for units 1-4. In May 2020, the WDEQ approved the alternative plan as proposed, which would eliminate the requirement to install add-on NO~~x ~~controls at~~threat of non-compliant operation of Jim Bridger units 1 and 2.2 (February Consent Decree). The consent decree requires that PacifiCorp (1) submit a revised permit application and request a SIP revision that would reflect a natural gas conversion of both units; and (2) propose an RFP for carbon capture technology at units 3 and 4. As of the date of this report, the revised permit application and RFP are pending.

On March 22, 2022, Idaho Power submitted comments to the WDEQ in support of the WDEQ's analysis that no additional requirements are necessary at the Jim Bridger plant to meet air quality standards. Idaho Power's comments included a recommendation that the WDEQ include the terms of the February Consent Decree in the SIP for the EPA's approval. In June 2022, the EPA ~~has not formally acted~~issued an administrative compliance order on consent pursuant to which PacifiCorp agreed to comply with the contents and timeline of a SIP revision that includes emission and control requirements for units 1 and 2, and the EPA agreed to allow the Jim Bridger plant to continue generation under certain operational limits that Idaho Power believes will allow it to reliably serve its customers while the SIP revision process moves forward.

On April 6, 2022, the EPA issued a proposed rule under the CAA called the Federal Implementation Plan Addressing Regional Ozone Transport for the 2015 National Ambient Air Quality Standards (CSAPR) to establish NOx emissions budgets requiring fossil fuel-fired power plants to participate in an allowance-based ozone season trading program beginning in 2023. Idaho Power submitted comments on the ~~SIP revision; however,~~CSAPR on June 21, 2022, and believes that the ~~EPA has been~~proposed rule, if finalized, could impact operations at the Jim Bridger and Valmy plants. Idaho Power believes that if the proposed CSAPR were implemented, under certain conditions the company could have reduced ability to use the full available output at the Valmy and Jim Bridger plants in ~~discussions~~order to comply with the ~~WDEQ~~CSAPR limitations. Idaho Power will be evaluating the specific impacts to both plants and, ~~PacifiCorp regarding~~for the Jim Bridger plant, how the CSAPR will interact with the SIP ~~revision.~~and February Consent Decree between Wyoming and PacifiCorp.

Clean Water Act Matters

Definition of “Waters of the United States” Under the ~~CWA:~~ CWA: In August 2015, the EPA and U.S. Army Corps of ~~Engineers'~~Engineers (USACE) final rule defining the phrase "waters of the United States" (WOTUS) under the CWA became effective (WOTUS

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Rule). Idaho Power believes that the 2015 rule potentially expanded 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 WOTUS Rule was widely challenged in both federal district and circuit courts. In January 2020, the EPA and USACE finalized the first of a two-part rule to repeal the WOTUS Rule and set new and more expansive standards for determining which waters are subject to the CWA, which substantially restored the definitions and guidance used prior to the WOTUS Rule. In April 2020, the EPA and USACE published the second

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part of the final rule to replace the WOTUS Rule with the "Navigable Waters Protection Rule" that provides a final definition of "waters of the United States," which ultimately narrows the scope of waters subject to federal regulation under the CWA. The Navigable Waters Protection Rule became effective in June 2020. In ~~June~~December 2021, in response to the January 2021 Executive ~~Order,~~Orders, the EPA and USACE ~~announced their intent~~published a proposed rule, subject to ~~initiate~~ a ~~new rulemaking process~~comment period that ended in February 2022, that restores the protections in place prior to the WOTUS Rule and ~~develop~~establishes a new ~~rule to establish a new~~expansive definition of "waters of the United States."

In January 2022, the U.S. Supreme Court agreed to review a challenge to the EPA’s assertion of jurisdiction over certain wetlands because the wetlands are WOTUS under a standard described in a prior U.S. Supreme Court decision. While it remains unclear what the court will review, it could clarify the definition of WOTUS, or focus on the narrower question of when wetlands constitute WOTUS. The EPA has not indicated whether it plans to alter the rulemaking timeline in light of the pending U.S. Supreme Court proceedings, but EPA officials indicated that they intend to continue moving forward with the regulatory process. If the court opines on relevant statutory language before the EPA finalizes a new definition of WOTUS, the EPA may need to consider the court’s interpretation in their regulations.

Idaho Power believes the repeal rule, the WOTUS Rule, the Navigable Waters Protection Rule, and the ~~potential~~proposed new rule will continue to be challenged in court, but expects that, even if the WOTUS Rule is reinstated in Idaho or ~~another~~the expansive proposed new rule is enacted ~~in Idaho~~ and should the revised definition take effect in Idaho, while it may cause Idaho Power to incur additional permitting, regulatory requirements, and other costs associated with the rule, the aggregate amount of increased costs is unlikely to have a material adverse effect on Idaho Power's operations or financial condition, in part due to the relatively arid climate of Idaho Power's service area. Similarly, because the CWA, as interpreted even prior to the WOTUS Rule, applies to most of Idaho Power's facilities, including its hydropower plants, Idaho Power does not expect reinstatement ~~or a similar rule~~ would have a material impact on Idaho Power's operations or financial condition.

Section 401 Water Quality Certification: As described more fully under “Relicensing of Hydropower Projects” in the "Regulatory Matters" section of this MD&A, ~~and in the 2020 Annual Report in Part II, Item 7 - "Regulatory Matters,"~~ Idaho Power filed water quality certification applications, required under Section 401 of the CWA, with the states of Idaho and Oregon requesting that each state certify that any discharges from the HCC comply with applicable state water quality standards. The states issued final certifications in May 2019, after reaching a settlement with Idaho Power on fisheries-related matters. The Oregon certification, however, was challenged in state court by three third parties. Two of the lawsuits were consolidated, and Idaho Power intervened in ~~one of those lawsuits~~that lawsuit and the ~~other lawsuit was~~parties reached a settlement. The court dismissed by the ~~court.~~third challenge to the Oregon CWA 401 certification with prejudice. In December 2019, Idaho Power filed an Offer of Settlement with the FERC requesting specific language be included in the new HCC license based upon the fish settlement among Idaho, Oregon, and Idaho Power. During the first quarter of 2020, the FERC received several comments opposing the Offer of Settlement and its decision relating to the Offer of Settlement is pending as of the date of this report.

In July 2020, the EPA published a rule amending regulations intended to implement the CWA Section 401 water quality certification ~~process.~~process (July 2020 Rule). The rule clarifies that a state must issue its water quality certification within a reasonable time period, up to one year from the certification request, and limits the scope of the certification to jurisdictional water quality matters. Further, the new regulations make clear that federal agencies, not the state departments of environmental quality, will enforce the certification conditions. ~~This rule~~The July 2020 Rule became effective in September ~~2020. The new~~2020 (2020 CWA Section 401 ~~regulations have been challenged~~Order). In October 2021, the Ninth Circuit Court of Appeals issued an order remanding and vacating the 2020 CWA Section 401 Order, which order applies nationwide, and requires a temporary return to the EPA's previous Section 401 of the CWA in ~~court~~effect since 1979. In April 2022, the U.S. Supreme Court stayed the vacatur imposed by the Ninth Circuit, and the EPA filed a notice of intent to repeal the July 2020 Rule. While the EPA finalizes a new certification rule, Idaho Power ~~has joined a coalition of utilities~~plans to ~~defend the EPA’s regulation in a case being tried in the Northern District of California. If these regulations are rejected by the courts, Idaho Power would~~ continue to operate under the current CWA Section 401 regulations as described above.

~~In May 2021, in response to the January 2021 Executive Order, the EPA announced its intention to reconsider and revise the CWA Section 401 regulations.~~ Idaho Power expects the EPA to expand state and tribal authority over water quality certifications; however, such expanded authority would not likely impact the timing and cost of the HCC certification unless the ~~401 certification is invalidated by either the Oregon litigation or the~~ FERC declines to adopt the Offer of Settlement,

in which case Idaho Power would file new water quality certification applications in Idaho and Oregon with revisions necessary to address changes to the regulations, which Idaho Power cannot currently ~~predict.~~predict and could delay the timing of issuance and increase the cost of obtaining a license for the HCC.

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CWA Permitting: Idaho Power's hydropower generation facilities are subject to compliance and permitting obligations under the CWA. Idaho Power has been engaged for several years with the EPA, and is now engaged with the Idaho Department of Environmental Quality (IDEQ), regarding Idaho Power's CWA permitting obligations and compliance status for those facilities. Idaho Power has in the past, and expects in the future, to incur costs and expenses associated with those permitting and compliance obligations. Idaho Power also expects to incur additional expenses associated with the relicensing of its hydropower facilities, as discussed elsewhere in this report.

On April 7, 2022, Idaho Power and the IDEQ entered into a consent judgment in the district courts for the third, fourth, fifth, and sixth judicial districts of the State of Idaho to resolve a National Pollutant Discharge Elimination System permitting issue related to 15 of Idaho Power’s hydropower projects that requires Idaho Power to pay a $1.1 million fine, implement interim measures for compliance, and ultimately submit applications for new permits at each of the dams subject to the consent judgment. Due to a misinterpretation, the EPA cancelled water discharge permits in the mid-1990’s, and Idaho Power recently determined that those permits are applicable for operation of the dams. However, Idaho Power believes that the dams would have been in compliance with the earlier permits had they remained in place.

OTHER MATTERS

Critical Accounting Policies and Estimates

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

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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 the ~~2020~~2021 Annual Report.

Recently Issued Accounting Pronouncements

There have been no recently issued accounting pronouncements that have had or are expected to have a material impact on IDACORP's or Idaho Power's condensed consolidated 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, ~~2020,~~2021, 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, ~~2021.~~2022. 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, ~~2021,~~2022, IDACORP had no$30.1 million in net ~~variable~~floating rate debt, aswhich approximated fair value. Assuming no change in financial structure, if variable interest rates were to average one percentage point higher than the ~~carrying value~~average rate on June 30, 2022, annual interest expense would increase and pre-tax earnings would decrease by approximately $0.3 million for IDACORP.

Table of ~~short-term investments exceeded the carrying value of outstanding variable rate debt.~~Contents

Fixed Rate Debt: As of June 30, ~~2021,~~2022, IDACORP had $2.0 billion in fixed rate debt, with a fair market value of approximately ~~$2.3~~$1.9 billion. These instruments are fixed rate and, therefore, do not expose the companies to a loss in earnings due to changes in market interest rates. However, the fair value of these instruments would increase by approximately ~~$234~~$222 million if market interest rates were to decline by one percentage point from their June 30, ~~2021,~~2022, 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 power cost adjustment mechanisms. To supplement its generation resources and balance its supply of power with the demand of its retail customers, Idaho Power participates in the wholesale marketplace. IDACORP's commodity price risk as of June 30, ~~2021,~~2022, had not changed materially from that reported in Item 7A of IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, ~~2020 (2020~~2021 (2021 Annual Report). Information regarding Idaho Power’s use of derivative instruments to manage commodity price risk can be found in Note 1012 - "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 credit risk through the use of financial guarantees, cash, or letters of credit. Idaho Power maintains a current list of acceptable counterparties and credit limits.

The use of performance assurance collateral in the form of cash, letters of credit, or guarantees is common industry practice. Idaho Power maintains margin agreements relating to its wholesale commodity contracts that allow performance assurance collateral to be requested of and/or posted with certain counterparties. As of June 30, ~~2021,~~2022, Idaho Power ~~had~~ posted ~~$0.4~~$1.2 million performance assurance collateral related to these contracts. Should Idaho Power experience a reduction in its credit rating on Idaho Power's unsecured debt to below investment grade Idaho Power could be subject to requests by its wholesale counterparties to post additional performance assurance collateral. Counterparties to derivative instruments and other forward contracts could request immediate payment or demand immediate ongoing full daily collateralization on derivative instruments and contracts in net liability positions. Based upon Idaho Power's energy and fuel portfolio and market conditions as of June 30,

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~~2021,~~ 2022, the amount of collateral that could be requested upon a downgrade to below investment grade was approximately ~~$27.6~~$14.5 million. To minimize capital requirements, Idaho Power actively monitors the portfolio exposure and the potential exposure to additional requests for performance assurance collateral calls through sensitivity analysis.

IDACORP's credit risk related to uncollectible accounts, net of amounts reserved, as of June 30, ~~2021,~~2022, had not changed materially from that reported in Item 7A of the ~~2020~~2021 Annual Report, except as disclosed in Note 4 - "Revenues" to the condensed consolidated financial statements included in this report. Additional information regarding Idaho Power’s management of credit risk and credit contingent features can be found in Note 1012 - "Derivative Financial Instruments" to the condensed consolidated financial statements included in this report.

Equity Price Risk

IDACORP is exposed to price fluctuations in equity markets, primarily through Idaho Power's defined benefit pension plan assets, a mine reclamation trust fund owned by an equity-method investment of Idaho Power, and other equity security investments at Idaho Power. The equity securities held by the pension plan and in such accounts are diversified to achieve broad market participation and reduce the impact of any single investment, sector, or geographic region. Idaho Power has established asset allocation targets for the pension plan holdings, which are described in Note 10 - "Benefit Plans" to the consolidated financial statements included in the ~~2020~~2021 Annual Report.

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ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

IDACORP: The Chief Executive Officer and the Chief Financial Officer of IDACORP, based on their evaluation of IDACORP’s disclosure controls and procedures (pursuant to Rule 13a-15(b) of the Securities Exchange Act of 1934 (Exchange Act)) as of June 30, ~~2021,~~2022, have concluded that IDACORP’s disclosure controls and procedures (as defined in Rule 13a-15(e) of the Exchange Act) are effective as of that date.

Idaho Power: The Chief Executive Officer and the Chief Financial Officer of Idaho Power, based on their evaluation of Idaho Power’s disclosure controls and procedures (pursuant to Rule 13a-15(b) of the Exchange Act) as of June 30, ~~2021,~~2022, have concluded that Idaho Power’s disclosure controls and procedures (as defined in Rule 13a-15(e) of the Exchange Act) are effective as of that date.

Changes in Internal Control over Financial Reporting

There have been no changes in IDACORP's or Idaho Power's internal control over financial reporting during the quarter ended June 30, ~~2021,~~2022, that have materially affected, or are reasonably likely to materially affect, IDACORP's or Idaho Power's internal control over financial reporting.

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PART II – OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

~~None~~On April 7, 2022, Idaho Power and the Idaho Department of Environmental Quality entered into a consent judgment in the District Courts for the Third, Fourth, Fifth, and Sixth Judicial Districts of the State of Idaho to resolve a National Pollutant Discharge Elimination System permitting issue related to 15 of Idaho Power’s hydropower projects. The consent judgement requires Idaho Power to pay a $1.1 million fine, implement interim measures for compliance, and ultimately submit applications for new permits at each of the dams subject to the consent judgment. Due to a misinterpretation, the U.S. Environmental Protection Agency cancelled water discharge permits in the mid-1990’s, and Idaho Power recently determined that those permits are applicable for operation of the dams and self-reported the permitting issue. However, Idaho Power believes that the dams would have been in compliance with the earlier permits had they remained in place.

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, ~~2020,~~2021, could materially affect IDACORP’s and Idaho Power's business, financial condition, or future results. In addition to those risk factors and other risks discussed in this report, see "Cautionary Note Regarding Forward-Looking Statements" in this report for additional factors that could have a significant impact on IDACORP's or Idaho Power's operations, results of operations, or financial condition and could cause actual results to differ materially from those anticipated in forward-looking statements.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Restrictions on Dividends

See Note 56 - "Common Stock" to the condensed consolidated financial statements included in this report for a description of restrictions on IDACORP's and Idaho Power's payment of dividends.

Issuer Purchases of Equity Securities

IDACORP did not repurchase any shares of its common stock during the quarter ended June 30, ~~2021.~~2022.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None

ITEM 4. MINE SAFETY DISCLOSURES

Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.104) is included in Exhibit 95.1 of this report, which is incorporated herein by reference.

ITEM 5. OTHER INFORMATION

None

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ITEM 6. EXHIBITS

The following exhibits are filed or furnished, as applicable, with the Quarterly Report on Form 10-Q for the quarter ended June 30, ~~2021:~~2022:

~~Incorporated by Reference~~

~~Exhibit No.~~

~~Exhibit Description~~

~~Form~~

~~File No.~~

~~Exhibit No.~~

~~Date~~

~~Included Herewith~~

~~15.1~~

~~Letter Re: Unaudited Interim Financial Information~~

~~15.2~~

~~Letter Re: Unaudited Interim Financial Information~~

~~31.1~~

~~Certification of IDACORP, Inc. Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002~~

~~31.2~~

~~Certification of IDACORP, Inc. Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002~~

~~31.3~~

~~Certification of Idaho Power Company Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002~~

~~31.4~~

~~Certification of Idaho Power Company Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002~~

~~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~~

~~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~~

~~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~~

~~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~~

~~95.1~~

~~Mine Safety Disclosures~~

~~101.SCH~~

~~Inline XBRL Taxonomy Extension Schema Document~~

~~101.CAL~~

~~Inline XBRL Taxonomy Extension Calculation Linkbase Document~~

~~101.LAB~~

~~Inline XBRL Taxonomy Extension Label Linkbase Document~~

~~101.PRE~~

~~Inline XBRL Taxonomy Extension Presentation Linkbase Document~~

~~101.DEF~~

~~Inline XBRL Taxonomy Extension Definition Linkbase Document~~

~~104~~

~~Cover Page Interactive Data File (formatted as inline XBRL with applicable taxonomy extension information contained in Exhibits 101.)~~

Incorporated by Reference

Exhibit No.

Exhibit Description

Form

File No.

Exhibit No.

Date

Included Herewith

4.1

Idaho Power Company Fiftieth Supplemental Indenture, d ated effective as of June 30, 2022, to Mortgage and Deed of Trust, dated as of October 1, 1937

8-K

1-3198

4.1

6/30/2022

15.1

Letter Re: Unaudited Interim Financial Information

15.2

Letter Re: Unaudited Interim Financial Information

31.1

Certification of IDACORP, Inc. Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.2

Certification of IDACORP, Inc. Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.3

Certification of Idaho Power Company Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.4

Certification of Idaho Power Company Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

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

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

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

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

95.1

Mine Safety Disclosures

101.SCH

Inline XBRL Taxonomy Extension Schema Document

101.CAL

Inline XBRL Taxonomy Extension Calculation Linkbase Document

101.LAB

Inline XBRL Taxonomy Extension Label Linkbase Document

101.PRE

Inline XBRL Taxonomy Extension Presentation Linkbase Document

101.DEF

Inline XBRL Taxonomy Extension Definition Linkbase Document

104

Cover Page Interactive Data File (formatted as inline XBRL with applicable taxonomy extension information contained in Exhibits 101.)

6167

Table of Contents

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 29, 2021~~August 4, 2022	By:	/s/ Lisa A. Grow
			Lisa A. Grow
			President and Chief Executive Officer

Date:	~~July 29, 2021~~August 4, 2022	By:	/s/ ~~Steven~~Brian R. ~~Keen~~Buckham
			~~Steven~~Brian R. ~~Keen~~Buckham
			Senior Vice President and Chief Financial Officer






		IDAHO POWER COMPANY
		(Registrant)



Date:	~~July 29, 2021~~August 4, 2022	By:	/s/ Lisa A. Grow
			Lisa A. Grow
			President and Chief Executive Officer

Date:	~~July 29, 2021~~August 4, 2022	By:	/s/ ~~Steven~~Brian R. ~~Keen~~Buckham
			~~Steven~~Brian R. ~~Keen~~Buckham
			Senior Vice President and Chief Financial Officer

6268


	2021	2022	2023-2025
Expected capital expenditures (excluding AFUDC)	$320-$330	$340-$350	$1,250-$1,350