Table of Contents                              

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 10-K

☒ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
 THE SECURITIES EXCHANGE ACT OF 1934
  
 For the fiscal year endedDecember 31, 20212023
 
OR
☐TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
 THE SECURITIES EXCHANGE ACT OF 1934
 
For the transition period from ..................._________ to .................................................................
ida-20211231_g1.jpgida-20211231_g2.jpg________________________________
idacorp-logo.jpg
Idaho Power logo (stacked).jpg
  
Commission
File Number		Exact name of registrants as specified inIRS Employer
Commission
File Number		their charters, address of principal executive
offices, zip code and telephone number		I.R.S. Employer Identification NumberNo.
1-14465IDACORP, Inc.82-0505802
1-3198Idaho Power Company82-0130980
 1221 W. Idaho Street 
 Boise,ID83702-5627 
 (208)388-2200 
State of incorporation:Idaho

Securities registered pursuant to Section 12(b) of the Securities Exchange Act of 19341934:
Title of each classTrading Symbol(s)Name of each exchange on which registered
Common Stock, without par valueIDANew York Stock Exchange

Securities registered pursuant to Section 12(g) of the Securities Exchange Act of 19341934:
Idaho Power Company:Preferred Stock

Indicate by check mark whetherif the registrants are well-known seasoned issuers, as defined in Rule 405 of the Securities Act.
IDACORP, Inc.Yes☒No☐Idaho Power CompanyYes☐No☒
Indicate by check mark if the registrants are not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
IDACORP, Inc.Yes☐No☒Idaho Power CompanyYes☐No☒
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.  Yes  (X)☒   No  (  )☐
1
Table of Contents                              

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 and post such files). 
IDACORP, Inc.Yes☒No☐Idaho Power CompanyYes☒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 Securities Exchange Act.Act of 1934.

IDACORP, Inc.:                                
Large accelerated filerX Accelerated filer __ Non-accelerated  filer __
                                     Smaller reporting company ☐
                                     Emerging growth company ☐

Accelerated filerNon-accelerated filerSmaller reporting companyEmerging growth company
IDACORP, Inc.:☒☐☐☐☐
Idaho Power Company:☐☐☒☐☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange
Act. __

Idaho Power Company:                                
Large accelerated filer __ Accelerated filer __ Non-accelerated filer X
                                     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. __

IDACORP, Inc.☐Idaho Power Company☐
Indicate by check mark whether the registrants have filed a report on and attestation to its management's assessment of the effectiveness of its internal control over financial reporting under Sections 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.

IDACORP, Inc.Yes☒No☐Idaho Power CompanyYes☒No☐

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements.
IDACORP, Inc.☐Idaho Power Company☐
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b).
IDACORP, Inc.☐Idaho Power Company☐
Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Act).
IDACORP, Inc.Yes☐No☒Idaho Power CompanyYes☐No☒
Aggregate market value of voting and non-voting common stock held by non-affiliates (June(as of June 30, 2021)2023):
IDACORP, Inc.:$4,876,126,8085,170,636,474 Idaho Power Company:None
Number of shares of common stock outstanding as of February 11, 2022:
IDACORP, Inc.:50,523,810
Idaho Power Company:39,150,812, all held by IDACORP, Inc.
Number of shares of common stock outstanding as of February 9, 2024:

IDACORP, Inc.:50,628,079Idaho Power Company:39,150,812, all held by IDACORP, Inc.
Documents Incorporated by Reference:
Part III, Items 10 - 14Portions of IDACORP, Inc.’s definitive proxy statement to be filed pursuant to Regulation 14A for the 20222024 annual meeting of shareholders.
This combined Form 10-K 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 representation as to the information relating to IDACORP, Inc.’s other operations.

Idaho Power Company meets the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K and is therefore filing this Form with the reduced disclosure format.
2
Table of Contents                              
TABLE OF CONTENTS
Page
Commonly Used Terms
4
Cautionary Note Regarding Forward-Looking Statements
5
Part I 
Item 1Business
7
Information about our Executive Officers
20
Item 1ARisk Factors
2221
Item 1BUnresolved Staff Comments
36
Item 1CCybersecurity
36
Item 2Properties
36
Item 3Legal Proceedings
3738
Item 4Mine Safety Disclosures
3738
Part II 
Item 5Market for Registrant's Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities
3839
Item 6Reserved
Item 7Management's Discussion and Analysis of Financial Condition and Results of Operations
3940
Item 7AQuantitative and Qualitative Disclosures About Market Risk
7972
Item 8Financial Statements
8174
Item 9Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
137132
Item 9AControls and Procedures
137132
Item 9BOther Information
141136
Item 9CDisclosure Regarding Foreign JurisdictionJurisdictions that Prevent Inspections
141136
Part III 
Item 10Directors, Executive Officers and Corporate Governance*
141136
Item 11Executive Compensation*
141136
Item 12Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters*
141136
Item 13Certain Relationships and Related Transactions, and Director Independence*
142137
Item 14Principal Accountant Fees and Services*
142137
 
Part IV
Item 15Exhibits and Financial Statement Schedules
143138
Item 16Form 10-K Summary
152146
Signatures
153147
 
* Except as indicated in Items 10, 12, and 14, IDACORP, Inc. information is incorporated by reference to IDACORP, Inc.'s definitive proxy statement for the 20222024 annual meeting of shareholders.

3
Table of Contents                              
COMMONLY USED TERMS
The following select abbreviations, terms, or acronyms are commonly used or found in multiple locations in this report:
2021 Annual Report2023 IRP-IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 20212023 Integrated Resource PlankWhMATS-Kilowatt-hourMercury and Air Toxics Standards
ADITC-Accumulated Deferred Investment Tax CreditsLTICP-IDACORP 2000 Long-Term Incentive and Compensation Plan
AFUDC-Allowance for Funds Used During ConstructionMATS-Mercury and Air Toxics Standards
AOCI-Accumulated Other Comprehensive IncomeMD&A-Management’s Discussion and Analysis of Financial Condition and Results of Operations
APCUAFUDC-Annual Power Cost UpdateAllowance for Funds Used During ConstructionMMBtu-Million British Thermal Units
AOCI-Accumulated Other Comprehensive IncomeMoody's-Moody’s Investors Service
BCC-Bridger Coal Company, a joint venturejointly-owned investment of IERCoMW-Megawatt
BLM-U.S. Bureau of Land ManagementMWh-Megawatt-hour
BPA-Bonneville Power AdministrationNAAQS-National Ambient Air Quality Standards
CAA-Clean Air ActNAAQSNAV-National Ambient Air Quality StandardsNet Asset Value
CO2
-Carbon DioxideNEPA-National Environmental Policy Act
CWA-Clean Water ActNMFS-National Marine Fisheries Service
EIS-Environmental Impact StatementNOAA Fisheries-National Oceanic and Atmospheric Administration's National Marine Fisheries Service
EPA-U.S. Environmental Protection Agency
NO2
-Nitrogen Dioxide
ESA-Endangered Species Act
NOx
-Nitrogen Oxide
FASBESA-Financial Accounting Standards BoardEndangered Species ActO&M-Operations and Maintenance
FCAESG-Idaho Fixed Cost AdjustmentEnvironmental, Social, and GovernanceOATT-Open Access Transmission Tariff
FERCExchange Act-Federal Energy Regulatory CommissionU.S. Securities Exchange Act of 1934, as amendedOPUC-Public Utility Commission of Oregon
FPAFCA-Federal Power ActIdaho Fixed Cost AdjustmentPCA-Idaho-jurisdiction Power Cost Adjustment
GAAPFERC-Generally Accepted Accounting PrinciplesFederal Energy Regulatory CommissionPCAMPSPS-Oregon Power Cost Adjustment MechanismPublic safety power shutoff
GHGFPA-Greenhouse GasFederal Power ActPURPA-Public Utility Regulatory Policies Act of 1978
GAAP-Generally Accepted Accounting PrinciplesREC-Renewable Energy Credit
GHG-Greenhouse GasRFP-Request for proposals
HCC-Hells Canyon Complex, composed of the Brownlee, Oxbow, and Hells Canyon facilitiesRECRPS-Renewable Energy CertificatePortfolio Standard
IDACORP-IDACORP, Inc., an Idaho CorporationRH BARTSEC-Regional haze - best available retrofit technologyU.S. Securities and Exchange Commission
Idaho Power-Idaho Power Company, an Idaho CorporationRPSSIP-Renewable Portfolio StandardState Implementation Plan
Idaho ROE-Idaho-jurisdiction return on year-end equitySECSMSP-U.S. SecuritiesSecurity Plans for Senior Management Employees I and Exchange CommissionII
Ida-West-Ida-West Energy Company, a subsidiary of IDACORP, Inc.SMSPSOFR-Security Plan for Senior Management EmployeesSecured Overnight Financing Rate administered by the Federal Reserve Bank of New York
IDEQ-Idaho Department of Environmental Quality
SO2
-Sulfur Dioxide
IERCo-Idaho Energy Resources Co., a subsidiary of Idaho Power Company
SOUSACE2
-Sulfur DioxideU.S. Army Corps of Engineers
IFS-IDACORP Financial Services, Inc., a subsidiary of IDACORP, Inc.USACE-U.S. Army Corps of Engineers
IPUC-Idaho Public Utilities CommissionUSFWS-U.S. Fish and Wildlife Service
IPUC-Idaho Public Utilities CommissionWestern EIM-Energy imbalance market implemented in the western United States
IRP-Integrated Resource PlanWestern EIM-Energy imbalance market implemented in the western United States
IRS-U.S. Internal Revenue ServiceWDEQ-Wyoming Department of Environmental Quality
Jim Bridger plant-Jim Bridger generatingpower plantWMP-Wildfire Mitigation Plan
kWh-Kilowatt-hourWOTUS-Waters of the United States
LTICP-IDACORP 2000 Long-Term Incentive and Compensation PlanWPSC-Wyoming Public Service Commission
kW-Kilowatt

4
Table of Contents                              
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, regulatory filings, dividends, capital structure or ratios, load forecasts, 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," "preliminary," "projects," "targets," "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 outcomesuncertainties, and may differ materially from theactual 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 Part I, Item 1A - “Risk Factors”"Risk Factors" and Part II, Item 7 - “Management’s Discussion and Analysis of Financial Condition and Results of Operations"MD&A of this report, as well as in 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 CommissionFERC 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;
•expenses and risks associated with capital expenditures for, and the ongoingpermitting and construction of, utility infrastructure projects that Idaho Power may be unable to complete or that may not be deemed prudent by regulators for cost recovery or return on investment;
•expenses and risks associated with supplier and contractor delays and failure to satisfy project quality and performance standards on utility infrastructure projects, and the potential impacts of COVID-19those delays and its variants, and government mandates related to COVID-19 vaccines, masking, and testing, on the global and regional economy andfailures on Idaho Power’s employees, customers, contractors,Power's ability to serve customers;
•power demand exceeding supply, and the rapid addition of new industrial and commercial customer load and the volatility of such new load demand, resulting in increased costs for purchasing energy and capacity in the market, if available, or acquiring or constructing additional generation and transmission resources and battery storage facilities;
•impacts of economic conditions, including an inflationary or recessionary environment and increasing interest rates, on items such as operations and capital investments, supply costs and delivery delays, supply scarcity and shortages, 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 including on loads and revenues, uncollectible accounts, transmission revenues, supply chain availability, attritiontheir ability to meet financial and operational commitments, and collection of skilled workers, and other aspects of the economy and the companies’ business;receivables;
•changes in residential, commercial, and industrial growth and demographic patterns within Idaho Power’sPower's service area, and theirthe associated impacts on loads and load growth,growth;
•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 and suppliers, the cost of living and the availabilityrelated impact on recruiting employees, and the ability to adjust to fluctuations in labor costs;
•changes in, failure to comply with, and costs of regulatory mechanisms that allow for timely costcompliance with laws, regulations, policies, orders, and licenses including those relating to reliability and security, the environment, climate change, natural resources, and threatened and endangered species, and associated mitigation requirements, which may result in penalties and fines, increase compliance and operational costs, and impact recovery associated with increased costs 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’sPower's sale or delivery of electric power or introduction ofintroduce operational or cyber-security vulnerabilities to the power grid;
•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 and power supply costs;
5
Table of Contents
•ability to acquire fuel, power, equipment, and transmission capacity on reasonable terms and prices, particularly in the event of unanticipated or abnormally high resource demands, price volatility, lack of physical availability, transportation constraints, outages due to maintenance or repairs to generation or transmission facilities, disruptions in the supply chain, or reduced credit quality or lack of counterparty and supplier credit;
•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, electrical contacts, fires (either affecting or caused by Idaho Power facilities or infrastructure), explosions, 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; 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 fines and penalties;
•acts or threats of terrorist incidents,terrorism, 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;
•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 may not be deemed prudent by regulators for cost recovery or a return on investment;
•demand for power during peak periods could exceed forecasted supply, resulting in increased costs for purchasing capacity in the market 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 ability of Idaho Power to acquire fuel, power, electrical equipment, and transmission capacity on reasonable terms, particularly in the event of unanticipated or abnormally high power demands, price volatility, lack of physical availability, transportation constraints, disruptions or delays in the supply chain, or a lack of credit;
•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 costs, and reduce revenues;
•accidents, terrorist acts, electrical contacts, fires (either affecting or caused by Idaho Power facilities or infrastructure), explosions, general system damage or dysfunction, intentional acts of destruction, uncontrolled release of water from hydropower dams, and other unplanned events that may occur while operating and maintaining assets, which can cause unplanned outages; reduce generating output, damage company assets, operations, or reputation; subject Idaho Power
5
Table of Contents
to third-party claims for property damage, personal injury, or loss of life; or result in the imposition of fines and penalties for which Idaho Power may have inadequate insurance coverage;
•the increased purchased power costs and operational and reliability challenges associated with purchasing and integrating intermittent renewable energy sources into Idaho Power’sPower's resource portfolio;
•Idaho Power’s concentration in one industry and one region, and the lack of diversification, and the resulting exposure to regional economic conditions and regional legislation and regulation;
•employee workforce factors, including the operationalunaligned goals and financial costspositions with co-owners of unionization or the attempt to unionize all or part of the companies’ workforce, the impact of an aging workforceIdaho Power’s generation and retirements, the cost and ability to attract and retain skilled workers and third-party vendors, the cost of living and the related impact on recruiting employees, and the ability to adjust the labor cost structure when necessary;
•failure to comply with state and federal laws, regulations, and orders, including interpretations and enforcement initiatives by regulatory and oversight bodies, which may result in penalties and fines and increase the cost of compliance and remediation;transmission assets;
•changes in tax laws or related regulations or interpretations of applicable laws or regulations 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;credits;
•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 and 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 favorablesatisfactory terms, which can be affected by factors such as credit ratings, reputational harm, volatility or disruptions in the financial markets, interest rate fluctuations, decisions by the Idaho, Oregon, or OregonWyoming public utility commissions, and the companies’companies' past or projected financial performance;
•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;intended, and the potential losses the companies may incur on those hedges, which can be affected by factors such as the volume of hedging transactions and degree of price volatility;
•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’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 incessation of coal-fired operations at Idaho Power’s co-owned coal plants;plants and conversion of the plants to natural gas;
•the ability to continue to pay dividends and achieve target-payouttarget dividend payout ratios based on financial performance and capital requirements, and in light of credit rating considerations, contractual covenants and restrictions, and regulatory limitations; and
•adoption of or changes in accounting policies and principles, changes in accounting estimates, and new Securities and Exchange CommissionSEC or New York Stock Exchange requirements or new interpretations of existing requirements.requirements; and
•changing market dynamics due to the emergence of day ahead or other energy and transmission markets in the West.
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 managementthe companies to predict all such factors, nor can itthey 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.
6
Table of Contents                              
PART I
ITEM 1. BUSINESS

OVERVIEW
 
Background

IDACORP Inc. (IDACORP) is a holding company incorporated in 1998 under the laws of the state of Idaho. Its principal operating subsidiary is Idaho Power Company (Idaho Power).Power. IDACORP is subject to the provisions of the Public Utility Holding Company Act of 2005, which provides the Federal Energy Regulatory Commission (FERC)FERC and state utility regulatory commissions with access to books and records and imposes record retention and reporting requirements on IDACORP.
 
Idaho Power was incorporated under the laws of the state of Idaho in 1989 as the successor to a Maine corporation that was organized in 1915 and began operations in 1916. Idaho Power is an electric utility engaged in the generation, transmission, distribution, sale, and purchase of electric energy and capacity and is regulated by the state regulatory commissions of Idaho and Oregon and by the FERC. Idaho Power is the parent of Idaho Energy Resources Co. (IERCo),IERCo, a joint venturer in Bridger Coal Company (BCC),joint-owner of BCC, which mines and supplies coal to the Jim Bridger generating plant (Jim Bridger plant) owned in part by Idaho Power. Idaho Power's utility operations constitute nearly all of IDACORP's current business operations.
 
IDACORP’s other notable subsidiaries include IDACORP Financial Services, Inc. (IFS),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).PURPA.

IDACORP’s and Idaho Power’s principal executive offices are located at 1221 W. Idaho Street, Boise, Idaho 83702, and the telephone number is (208) 388-2200.

Available Information

IDACORP and Idaho Power make available free of charge on their websites their Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and all amendments to these reports filed or furnished pursuant to Section 13(a) or 15(d) of the U.S. Securities Exchange Act of 1934 as soon as reasonably practicable after the reports are electronically filed with or furnished to the U.S. Securities and Exchange Commission (SEC).SEC. IDACORP's website is www.idacorpinc.com and Idaho Power's website is www.idahopower.com. The contents of these websites are not part of IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2021 (2021 Annual Report).this report.
 
UTILITY OPERATIONS

Background
 
Idaho Power provided electric utility service to approximately 604,000633,000 retail customers in southern Idaho and eastern Oregon as of December 31, 2021.2023. Approximately 506,000532,000 of these customers are residential. Idaho Power’s principal commercial and industrial customers are involved in food processing, electronics and general manufacturing, agriculture, health care, government, and education. Idaho Power also provides irrigation customers with electric utility service to operate irrigation pumps during the agricultural growing season. Idaho Power holds franchises, typically in the form of right-of-way arrangements, in 72 cities in Idaho and 7 cities in Oregon and holds certificates from the respective public utility regulatory authorities to serve all or a portion of 25 counties in Idaho and 3 counties in Oregon. Idaho Power's service area is shaded in the illustration on the following page and covers approximately 24,000 square miles with an estimated population of 1.31.4 million.

7
Table of Contents                              
serviceterritorymap2015a04.jpg
Idaho Power is under the jurisdiction (as to rates, service, accounting, and other general matters of utility operation) of the Idaho Public Utilities Commission (IPUC),IPUC, the Public Utility Commission of Oregon (OPUC),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 Wyoming Public Service Commission (WPSC)WPSC as to the issuance of debt and equity securities. As a public utility under the Federal Power Act (FPA),FPA, Idaho Power has authority to charge market-based rates for wholesale energy sales under its FERC tariff and to provide transmission services under its open access transmission tariff (OATT).OATT. Additionally, the FERC has jurisdiction over Idaho Power's sales of transmission capacity and wholesale electricity, hydropower project relicensing, and system reliability and security, among other items.

Regulatory Accounting

Idaho Power meets the requirements under accounting principles generally accepted in the United States of America (GAAP) to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation, with the impacts of rate regulation reflected in its financial statements. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant, and equipment; regulatory assets and liabilities; operating revenues; other operations and maintenance expense; depreciation expense; and income tax expense.disclosures. These principles sometimes result in Idaho Power recording expenses and revenues in a different period than when an unregulated enterprise would record such expenses and revenues. In these instances, the amounts are deferred or accrued as regulatory assets or regulatory liabilities on the balance sheet and recorded on the income statement when recovered or returned in rates or when otherwise directed to begin amortization by a regulator. Additionally, regulators can impose regulatory liabilities upon a regulated company for amounts previously collected from customers that are expected to be refunded. Idaho Power records regulatory assets or liabilities if it expects the amounts will be reflected in future prices,customer rates, based on regulatory orders or other available evidence.

Consistent with orders and directives of the IPUC, unless contrary to applicable income tax guidance, Idaho Power does not provide deferred income tax expense or benefit for certain income tax temporary differences and instead recognizes the tax impact currently (commonly referred to as flow-through accounting) for rate making and financial reporting. Therefore, Idaho Power's effective income tax rate is impacted as these differences arise and reverse. Idaho Power recognizes such adjustments as regulatory assets or liabilities if it is probable that the amounts will be recovered from or returned to customers in future rates.

8
Table of Contents                              
Business Strategy

IDACORP is committed to its focus on competitive total returns and generating long-term value for shareholders. IDACORP’s business strategy emphasizes Idaho Power as its core business, as Idaho Power's regulated utility operations are the primary driver of IDACORP's operating results. IDACORP’s strategy is focused on four areas: keeping employees safe and engaged, growing financial strength, improving Idaho Power's core business, and enhancing Idaho Power’s brand, and keeping employees safe and engaged.brand. IDACORP's board of directors has reviewed and affirmed IDACORP’s long-term strategy. In executing on these four strategic cornerstones, IDACORP seeks to balance the interests of shareowners, Idaho Power customers, employees, and other stakeholders. Idaho Power is committed to working for strong, sustainable financial results by continuing to safely provide reliable, affordable, clean energy to its customers from diversified generation resources.

Rates and Revenues

Idaho Power generates revenue primarily through the sale of electricity to retail and wholesale customers and the provision of transmission service. The prices that the IPUC, the OPUC, and the FERC authorize Idaho Power to charge for electric power and services are critical factors in determining IDACORP's and Idaho Power's results of operations and financial condition. In addition to the discussion below, for more information on Idaho Power's regulatory framework and rate regulation seecan be found in the “Regulatory Matters” section of Part II, Item 7 – “Management’s Discussion and Analysis of Financial Condition and Results of Operations” (MD&A)MD&A and Note 3 – “Regulatory Matters” to the consolidated financial statements included in this report.

Retail Rates: Idaho Power's rates for retail electric services are generally determined on a “cost of service” basis. Rates are designed to provide after recovery of allowable operating expenses including depreciation on capital investments, an opportunity for Idaho Power to earn a reasonable return on investment as authorized by regulators.regulators, after recovery of allowable operating expenses, including depreciation on capital investments. Idaho Power regularly evaluates the need to request changes toin its retail electricity price structure to cover its operating costs and to earn a fair return on its investments. Idaho Power usesthrough the use of general rate cases, power cost adjustment mechanisms in Idaho and Oregon, a fixed cost adjustment (FCA)an FCA mechanism in Idaho, balancing accounts, and also uses tariff riders, and subject-specific filings to recover its costs of providing service and to earn a return on investment. Retail prices are generally determined through formal ratemaking proceedings that are conducted under established procedures and schedules before the issuance of a final order. Participants in these proceedings include Idaho Power, the staffs of the IPUC or OPUC, and other interested parties. The IPUC and OPUC are charged with ensuring that the prices and terms of service are fair, are non-discriminatory, and provide Idaho Power an opportunity to recover its prudently incurred or allowable costs and expenditures and earn a reasonable return on investment. The ability to request rate changes does not, however, ensure that Idaho Power will recover all of its costs or earn a specified rate of return, or that its costs will be recovered in advance of or at the same time when the costs are incurred.

In addition to general rate case filings, ratemaking proceedings can involve charges or credits related to specific costs, programs, or activities, as well as the recovery or refund of amounts deferred or accrued under specific authorization from the IPUC or OPUC. Deferred amounts are generally collected from, and accrued amounts are generally refunded to, retail customers through the use of base rates or supplemental tariffs. Outside of base rates, three of the most significant mechanisms for recovery of costs are the power cost adjustment mechanisms, FCA mechanism, and energy efficiency riders. For more information on these mechanisms, see Note 3 – “Regulatory Matters” and Note 4 -– “Revenues” to the consolidated financial statements included in this reportreport.

Retail Energy Sales: Weather, seasonal customer demand, energy efficiency, customer generation, customer growth, and economic conditions all impact the amount of electricity that Idaho Power sells as well as the costs it incurs to provide that electricity. Idaho Power's utility revenues are not earned, and associated expenses are not incurred, evenly during the year. Idaho Power’s retail energy sales typically peak during the summer irrigation and cooling season, with a lower peak during the winter heating season. Extreme temperatures increase sales to customers who use electricity for cooling and heating, and mild temperatures decrease sales. Availability of water and extremevariations in temperatures and precipitation during the agricultural growing season impact electricity sales to customers who use electricity to operate irrigation pumps. Alternative methods of generation, including customer-owned solar and other forms of distributed generation, have the potential to decrease Idaho Power sales to existing customers. Also, development of new technologies and services to help energy consumers manage energy in new ways could continue to alter demand for Idaho Power's electric energy. Approximately 95 percent of Idaho Power’s retail revenue originates from customers located in Idaho, with the remainder originating from customers located in Oregon. Idaho Power’s operations, including information on energy sales, are discussed further in Part II, Item 7 - MD&A - "Results of Operations - Utility Operations.”

9
Table of Contents                              
The table that follows presents Idaho Power’s revenues and sales volumes for the last three years, classified by customer type.
Year Ended December 31, Year Ended December 31,
202120202019 202320222021
Retail revenues (thousands of dollars):Retail revenues (thousands of dollars):   Retail revenues (thousands of dollars): 
Residential (includes $34,835, $34,409, and $35,587, respectively, related to the FCA(1))
$583,061 $547,404 $526,966 
Commercial (includes $1,407, $1,543, and $1,336, respectively, related to the FCA(1))
314,745 293,057 295,203 
Residential (includes $37,233, $22,595, and $34,835, respectively, related to the FCA)
Commercial (includes $1,338, $922, and $1,407, respectively, related to the FCA)
IndustrialIndustrial195,214 181,258 181,372 
IrrigationIrrigation168,664 154,791 135,850 
Provision for sharingProvision for sharing(569)— — 
Deferred revenue related to HCC relicensing AFUDC(2)
(8,780)(8,780)(8,780)
Deferred revenue related to HCC relicensing AFUDC(1)
Total retail revenuesTotal retail revenues1,252,335 1,167,730 1,130,611 
Wholesale energy salesWholesale energy sales40,839 33,656 71,198 
Transmission wheeling-related revenuesTransmission wheeling-related revenues67,997 51,592 53,828 
Energy efficiency program revenuesEnergy efficiency program revenues29,920 42,478 40,128 
Other revenuesOther revenues64,319 51,884 47,175 
Total electric utility operating revenuesTotal electric utility operating revenues$1,455,410 $1,347,340 $1,342,940 
Energy sales (thousands of Megawatt-hour (MWh)):   
Energy sales (thousands of MWh):Energy sales (thousands of MWh): 
ResidentialResidential5,645 5,463 5,273 
CommercialCommercial4,164 4,009 4,092 
IndustrialIndustrial3,471 3,369 3,412 
IrrigationIrrigation2,126 1,987 1,760 
Total retail energy salesTotal retail energy sales15,406 14,828 14,537 
Wholesale energy salesWholesale energy sales600 1,197 2,171 
Energy sales bundled with renewable energy credits739 690 680 
Energy sales bundled with RECs
Total energy salesTotal energy sales16,745 16,715 17,388 
(1) The FCA mechanism is an alternative revenue program in the Idaho jurisdiction and does not represent revenue from contracts with customers as disclosed in Note 4 – “Revenues” to the consolidated financial statements included in this report.
(2)The IPUC allows Idaho Power to recover a portion of the allowance for funds used during construction (AFUDC)AFUDC on construction work in progress related to the Hells Canyon Complex (HCC)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.

Wholesale Markets: Idaho Power participates in the wholesale energy markets by purchasing power to help meet load demands and selling power that is in excess of load demands. Idaho Power's market activities are guided by an energy risk management policyprogram and frequently updated operating plans. These operating plans are impacted by factors such as customer demand for power, market prices, generating costs, transmission constraints, and availability of generating resources. Some of Idaho Power's 17 hydropower generation facilities are operated to optimize the water that is available by choosing when to run hydropower generation units and when to store water in reservoirs. Idaho Power at times operates these and its other generation facilities to take advantage of market opportunities. These decisions affect the timing and volumes of market purchases and market sales. Even in below-normal water years, there are opportunities to vary water usage to capture wholesale marketplace economic benefits, maximize generation unit efficiency, and meet peak loads. Compliance factors such as allowable reservoir stage elevation changes and flood control requirements also influence these generation dispatch decisions. Idaho Power's wholesale energy sales depend largely on the availability of generation resources above the amount necessary to serve customer loads as well as market power prices at the time when those resources are available. A reduction in either factor leads to lower wholesale energy sales.

Idaho Power also provides energy transmission services through its OATT. The OATT rate is revised each year based primarily on financial and operational data Idaho Power files annually with the FERC in its Form 1. The FERC oversees mandatory transmission and network reliability standards, as well as power and transmission markets, including protection against market manipulation. These mandatory transmission and reliability standards were developed by the North American Electric Reliability Corporation and the Western Electricity Coordinating Council, which have responsibility for compliance and enforcement of transmission, reliability, and reliabilitysecurity standards.
10
Table of Contents
 
Competition: Idaho Power's electric utility business has historically been recognized as a natural monopoly. Idaho Power competes with fuel distribution companies, including natural gas providers, in serving the energy needs of customers for space heating, water heating, and appliances. Alternative methods of generation, including customer-owned solar and other forms of distributed generation, and energy efficiency measures, also have the potential to decrease Idaho Power sales to existing customers.

10
Table of Contents
Idaho Power also participates in the wholesale energy markets and in the electricelectricity transmission markets. Generally, these wholesale markets are regulated by the FERC, which requires electric utilities to transmit power to or for wholesale purchasers and sellers and make available transmission capacity, on a non-discriminatory basis, transmission capacity for the purpose of providing these services.

In return for agreeing to provide service to all customers within a defined service area, electric utilities are typically provided with an exclusive right to provide service in that service area. However, certain prescribed areas within Idaho Power's service area, such as municipalities or Native American Tribal reservations, may elect not to take service from Idaho Power and instead operate as a municipal electric utility or otherwise as a separate entity. In such cases, the entity would be required to purchase or otherwise obtain rights (such as by contract) to Idaho Power's distribution infrastructure within the municipal or other designated area. Idaho Power would have no responsibility for providing electric service to the municipal or separate entity, absent Idaho Power's voluntary execution of an agreement to provide that service.

Power Supply
 
Overview: Idaho Power primarily relies on company-owned hydropower, coal-fired, and gas-fired generation facilities and long-term power purchase agreements to supply the energy needed to serve customers and forto make power sales into the wholesale markets. Market purchases and sales are used to supplement Idaho Power's generation and balance supply and demand throughout the year. Idaho Power’s generating plants and their capacities are listed in Part I, Item 2 - “Properties.”
 
Various external and internal factors impact power supply costs;costs, such as weather, load demand, economic conditions, fuel costs, and availability of generation resources. Idaho Power’s annual hydropower generation varies depending on water conditions in the Snake River Basin. Drought conditions and increased peak load demand cause a greater reliance on potentially more expensive energy sources to meet load requirements. Conversely, favorable hydropower generation conditions increase production at Idaho Power’s hydropower generating facilities and reduce the need for thermal generation and wholesale market purchased power. Weather also affects the generation of projects with which Idaho Power has contracts to purchase power. Economic conditions, weather, supply constraints, and governmental regulations can affect the market price of natural gas and coal, which impact fuel expense and market prices for purchased power. Idaho Power's power cost adjustment mechanisms mitigate in large part the financialearnings impacts to Idaho Power of volatile fuel and power costs.

Idaho Power’s system is dual peaking, with the larger peak demand occurring in the summer. Idaho Power reached its highest all-time system peak demand of 3,751 megawatts (MW)MW on June 30, 2021. Idaho Power's highest all-time winter peak demand of 2,5272,719 MW was last achievedoccurred on January 6, 2017.16, 2024. During these and other similarlysimilar heavy load periods, Idaho Power’s system is fully committed to serve load and meet required operating reserves. The table that follows shows Idaho Power’s total power supply for the last three years.
Power SupplyPercent of Total Generation Power SupplyPercent of Total Generation
202120202019202120202019 202320222021202320222021
(thousands of MWh)  (thousands of MWh) 
Hydropower plantsHydropower plants5,382 6,967 8,294 48 %54 %62 %Hydropower plants6,548 5,347 5,347 5,382 5,382 55 55 %48 %48 %
Coal-fired plantsCoal-fired plants2,981 3,719 3,012 27 %29 %22 %Coal-fired plants2,473 3,657 3,657 2,981 2,981 21 21 %32 %27 %
Natural gas-fired plantsNatural gas-fired plants2,765 2,109 2,114 25 %17 %16 %Natural gas-fired plants2,917 2,319 2,319 2,765 2,765 24 24 %20 %25 %
Total system generationTotal system generation11,128 12,795 13,420 100 %100 %100 %
      
Purchased power - cogeneration and small power production3,040 3,087 2,983    
Purchased power - other3,783 1,985 2,217    
Total purchased power6,823 5,072 5,200    
Purchased power
Purchased power
Purchased power7,027 7,178 6,823  
Total power supplyTotal power supply17,951 17,867 18,620    Total power supply18,965 18,501 18,501 17,951 17,951   
 
11
Table of Contents
Hydropower Generation: Idaho Power operates 17 hydropower projects located on the Snake River and its tributaries. Together, these hydropower facilities provide a total nameplate capacity of 1,7991,818 MW and have averaged total annual generation of approximately 7.77.6 million MWh over the last 30 years. The amount of water available for hydropower generation depends on several factors—the amount of snowpack in the mountains upstream of Idaho Power’s hydropower facilities, upstream reservoir storage, springtime precipitation and temperatures, main river and tributary base flows, the condition of the Eastern Snake Plain Aquifer and its spring flow impact, summertime irrigation withdrawals and returns, and upstream reservoir regulation. Idaho Power actively participates in collaborative work groups focused on water management issues in the Snake River Basin, with the goal of preserving the long-term availability of water for use at Idaho Power’s hydropower projects on the Snake River.

11
Table of Contents
In 2023, hydropower generation was 6.5 million MWh, an increase from the prior two years, due to above-normal snow accumulation throughout most of the Snake River basin. In 2022 and 2021, below-normal snow accumulation and drought conditions resulted in lower than average hydropower generation of 5.3 million and 5.4 million MWh. In 2020, precipitation and snowpack were unevenly distributed across the Snake River Basin, with the Upper Snake River Basin experiencing near-normal winter snowpack but other key basins near the HCC experiencing below-normal snowpack. These snowpack conditions, coupled with strong early season irrigation demands, yielded lower inflows toMWh, respectively. Idaho Power’s hydroelectric projects and resulted in 7.0 million MWhPower's 2024 estimate of hydropower generation in 2020. In 2019, above-normal reservoir storage carryover from the previous year coupled with near-normal winter snowpack resulted in 8.3 million MWh of hydropower generation. During low water years, when stream flows into Idaho Power’s hydropower projects are reduced, Idaho Power’s hydropower generation is reduced, resulting in a greater reliance on other generation resources and wholesale power purchases. For 2022, Idaho Power estimates annual generation from its hydropower facilities will beis between 5.5 million MWh and 7.5 million MWh.
 
Idaho Power obtains licenses for its hydropower projects from the FERC, similar to other utilities that operate nonfederal hydropower projects on qualified waterways. The licensing process includes an extensive public review process and involves numerous natural resource and environmental agencies. The licenses last from 30 to 50 years depending on the size, complexity, and cost of the project. Idaho Power is actively pursuing the FERC relicensing of the HCC, its largest hydropower generation source, and American Falls, its second largest hydropower resource. Idaho Power also has Oregon licenses for the HCC under the Oregon Hydroelectric Act. For further information on relicensing activities, see Part II, Item 7 – MD&A – "Regulatory Matters – Relicensing of Hydropower Projects.”

Idaho Power is subject to the provisions of the FPA as a “public utility” and as a “licensee” by virtue of its hydropower operations. As a licensee under Part I of the FPA, Idaho Power and its licensed hydropower projects are subject to conditions described in the FPA and related FERC regulations. These conditions and regulations include, among other items, provisions relating to condemnation of a project upon payment of just compensation, amortization of project investment from excess project earnings, and possible takeover of a project after expiration of its license upon payment of net investment and severance damages.
 
Coal-Fired Generation: Idaho Power co-owns the following coal-fired power plants in operation:plants:

•Jim Bridger, located in Wyoming, in which Idaho Power has a one-third interest; and
•North Valmy, located in Nevada, in which Idaho Power has a 50 percent interest.

PacifiCorp is the operator of the Jim Bridger plant. BCC supplies coal to the Jim Bridger power plant. IERCo, a wholly-owned subsidiary of Idaho Power, owns a one-third interest in BCC and PacifiCorp owns a two-third interest in BCC and is the operator of the Bridger Coal Mine. The mine operates under a long-term sales agreement that provides for delivery of coal through 2024. Idaho Power believes that BCC has sufficient reserves to provide coal deliveries for at leastthrough the current term of the salesagreement, as well as reserves available to allow for an extension of the term agreement. Idaho Power also has a coal supply contract providingan established process approved by the IPUC for annual deliveriesrecovery of coal through April 2022 from the Black Butte mine located nearnon-fuel, coal-related costs related to Idaho Power’s plan to end its participation in coal-fired operations at the Jim Bridger plant. This contract supplements the BCC deliveries and provides another coal supply to fuel the Jim Bridger plant. The Jim Bridger plant’s rail load-in facility and unit coal train, while limited, provides the opportunity to access other fuel supplies for tonnage requirements above established contract minimums.

Idaho Power's 2021 Integrated Resource Plan identified a preferred resource portfolio and action plan includes the conversion from coal to natural gas of two generating units at the Jim Bridger plant is in 2024progress and an endis expected to Idaho Power's participationbe completed in the remaining two coal-fired units at the Jim Bridger plant by the endspring of 2028. For more information on the 2021 Integrated Resource Plan, refer to "Resource Planning" in this Item 1 - "Business." In June 2021, Idaho Power filed an application with the IPUC requesting, among other things, authorization to allow the Jim Bridger plant to be fully depreciated and recovered by end-of-year 2030. The status of Idaho Power's application is described more fully in Part II, Item 7 – MD&A – "Regulatory Matters."2024.

12
Table of Contents
NV Energy is the operator of the North Valmy power plant. Idaho Power expects to meet 20222024 and future fuel requirements through existing inventory and new or existing coal supply contracts. Idaho Power has an established process approved by the IPUC and OPUC for recovery of non-fuel costs related to Idaho Power’s plan to end its participation in coal-fired operations at the North Valmy plant. Idaho Power ended its participation in coal-fired operations at unit 1 of the North Valmy plant in December 2019, as planned, and plans to end its participation in unit 2 no later than the end of 2025.planned.

In October 2020,Idaho Power's 2023 IRP identified a preferred resource portfolio and action plan that includes the conversion from coal to natural gas of two units at the Jim Bridger plant in 2024, the two units at the North Valmy plant in 2026, and the remaining two units at the Jim Bridger plant in 2030. For more information on the 2023 IRP, refer to "Resource Planning" in this Item 1 – "Business." Idaho Power expects to seek approval from the IPUC and co-owner Portland General Electric ceased coal-fired operations at their Boardman powerOPUC for any necessary adjustments to plant as planned.retirement dates to align with its current resource plan.

Natural Gas-fired Generation: Idaho Power owns and operates the Langley Gulch natural gas-fired combined-cycle combustion turbine power plant and the Danskin and Bennett Mountain natural gas-fired simple-cycle combustion turbine power plants. All three plants are located in Idaho. As noted previously, in the spring of 2024, the conversion of two units at the Jim Bridger plant from coal to natural gas-fired steam turbines is expected to be completed.

Idaho Power operates the Langley Gulch plant as a baseload unit and the Danskin and Bennett Mountain plants to serve load and meet peak supply needs. The natural-gas-fired units at the Jim Bridger plant will operate to serve load and meet peak supply needs. The plants are also used to take advantage of wholesale market opportunities. Natural gas for all facilities is purchased based on system requirements and dispatch efficiency. The natural gas is transported through the Williams-Northwest Pipeline under Idaho Power's 55,584 million British thermal units (MMBtu) per day long-term gas transportation service agreements.agreements with the Williams-Northwest Pipeline for 55,584 MMBtu per day and Williams-Mt. West Overthrust Pipeline for 89,000 MMBtu per day. These transportation agreements vary in contract length but generally contain the right for Idaho Power to extend the term. In addition to the long-term gas transportation service agreements, Idaho
12
Table of Contents
Power has entered into a long-term storage service agreementagreements with Northwest Pipeline and Spire Inc. for 131,453 MMBtu and 1 billion cubic feet, respectively, of total storage capacity at the Jackson Prairie Storage Project. Thiscapacity. The firm storage contract with Northwest Pipeline expires in 2043.2043, while the contract with Spire begins in 2025 and ends in 2035. Idaho Power purchases and stores natural gas with the intent of fulfilling needs as identified for seasonal peaks or to meet system requirements.
 
As of December 31, 2021,February 9, 2024, Idaho Power had approximately 10.624.5 million MMBtu of natural gas financially hedged for physical delivery, primarily for the operational dispatch of the Langley Gulch plant through February 2023.September 2025. Idaho Power plans to manage the procurement of additional natural gas for the peaking units primarily on the daily spot market or from storage inventory as necessary to meet system requirements and fueling strategies.
 
Purchased Power: As described below, Idaho Power purchases power in the wholesale market as well as pursuant to long-term power purchase contracts and exchange agreements. The table below presents Idaho Power’s purchased power expenses and volumes for the last three years ended December 31 (in thousands, except for per MWh amounts). Transmission costs, purchases from the Western EIM, and costs from demand response programs are included with wholesale market purchases in the table.
Year Ended December 31,
 202320222021
Expense
Wholesale market purchases$243,319 $306,263 $142,248 
Long-term agreements (including PURPA)258,212 238,082 251,443 
Total purchased power expense$501,531 $544,345 $393,691 
MWh purchased
Wholesale market purchases3,278 3,823 3,168 
Long-term agreements (including PURPA)3,749 3,355 3,655 
Total MWh purchased7,027 7,178 6,823 
Cost per MWh from wholesale market purchases$74.23 $80.11 $44.90 
Cost per MWh from long-term agreement purchases$68.87 $70.96 $68.79 
 Weighted average cost per MWh - all sources$71.37 $75.84 $57.70 

Wholesale Market Transactions: To supplement its self-generated power and long-term purchase arrangements, Idaho Power purchases power in the wholesale market based on economics, operating reserve margins, energy risk management policyprogram guidelines, and unit availability. Depending on availability of excess power or generation capacity, pricing, and opportunities in the markets, Idaho Power also sells power in the wholesale markets. During 2021 and 2020, Idaho Power purchased 3.2 million MWh and 1.4 million MWh, respectively, of power through wholesale market purchases at an average cost of $40.65 per MWh and $27.91 per MWh, respectively. During 2021 and 2020, Idaho Power sold 0.6 million MWh and 1.2 million MWh of power in wholesale market sales, respectively, with an average price of $68.07 per MWh and $28.12 per MWh, respectively.

Idaho Power has two firm multi-year wholesale purchased power contracts to address increased demand during summer months. These agreements total approximately 150 MW per hour during peak summer periods through 2024.

Long-term Power Purchase and Exchange Arrangements: In addition to its wholesale market purchases, Idaho Power has contracts for the following notable long-term power 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 and energy exchange agreements:

•Telocaset Wind Power Partners, LLC - for 101 MW (nameplate generation) from the Elkhorn Valley wind project located in eastern Oregon. The contract term ends in 2027.
•USG Oregon LLC - for 22 MW (estimated average annual output) from the Neal Hot Springs Unit #1 geothermal power plant located near Vale, Oregon. The contract term ends in 2037.
•Clatskanie People's Utility - for up to 18 MW of generation from the Arrowrock hydropower project in southern Idaho in exchange for energy from Idaho Power's system or power purchased at the Mid-Columbia trading hub. The contract term ends in 2025.
•Raft River Energy I, LLC - for up to 13 MW (estimated average annual output) from its Raft River Geothermal Power Plant Unit #1 located in southern Idaho. The contract term ends in 2033.
•Jackpot Holdings LLC - a 20-year power purchase agreement to purchase the output from a planned 120-MW solar facility, with a scheduled in-service date in late 2022.
13
Table of Contents
PURPA Qualifying Facility Energy Sales Agreements: Idaho Power purchases power from PURPA qualifying facilitiesare entered into as mandatedrequired by federal law. As of December 31, 2021, Idaho Power had contracts with on-line PURPA qualifying facilities with a total of 1,137 MW of nameplate generation capacity, with an additional 75 MW nameplate capacity of projects projected to be on-line through 2024. The energy sales agreements for these qualifying facilities have original contract terms ranging from one to 35 years. The expense and volume of purchases from PURPA qualifying facilities during the last three years is included in the following table:
Year Ended December 31,
 202120202019
PURPA contracts expense (in thousands)$199,517 $194,380 $187,344 
MWh purchased under PURPA contracts (in thousands)3,040 3,087 2,983 
Average cost per MWh from PURPA contracts$65.63 $62.97 $62.80 

Pursuant to the requirements of PURPA, the IPUC and OPUC have each issued orders and rules regulating Idaho Power’s purchase of power from qualifying facilities that meet the requirements oflaw under PURPA. A key component of the PURPA contracts is the energy price contained within the agreements. PURPA regulations specify that a utility must pay energy prices based on the utility’s avoided costs. The IPUC and OPUC have established specific rules and regulations to calculate the avoided cost that Idaho Power is required to include inFor PURPA energy sales agreements, under each state's jurisdiction. For PURPA energy sales agreements:
•Idaho Power is required to purchase all of the output delivered from the contracted qualifying facilities, subject to some exceptions such as adverse impacts on system reliability.
•facilities. The Idaho jurisdictional portion of the costs associated with PURPA contracts is fully recovered through base rates and the Idaho-jurisdiction power cost adjustment (PCA)PCA mechanism, and the Oregon jurisdictional portion is recovered through base rates and an Oregon power cost adjustment mechanism. Thus, the primary impact of high power purchase costs under PURPA contracts is on customer rates.rates and the timing of cash flows.
•
13
Table of ContentsOregon jurisdictional regulations
The following table sets forth, as of the date of this report, 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 generally provided for PURPA standard contract terms of upranging from one to 2035 years.
Resource TypeNon-PURPA Online (MW)PURPA
Online (MW)		Total Online (MW)Under Contract but not yet Online (MW)Total Projects under Contract (MW)
Wind101 625 726 — 726 
Solar160 316 476 428 904 
Hydropower— 152 152 — 152 
Other35 43 78 — 78 
Total Long-term Projects296 1,136 1,432 428 1,860 
Idaho Power has one agreement with a PURPA-qualifying facility solar project expected to be online in 2024. Idaho Power has agreements with three non-PURPA solar projects for 100 MW, 200 MW, and 125 MW, which are scheduled to be online in 2024, 2025, and 2026, respectively.

•Battery Storage:The IPUC requires Idaho Power utilizes batteries primarily to pay "published avoided cost" rates for all wind, solar,store power generated during periods of lower customer demand and energydeliver that power to serve customers during peak hours, especially early summer evenings when irrigation pumps and air conditioners drive up electrical demand. In 2023, 131 MW of company-owned battery storage projects that are smaller than 100 kilowatts (kW) and all other types of projects that are smaller than 10 average MWs. For PURPA qualifying facilities that exceed these size limitations,were installed. In April 2023, Idaho Power is requiredentered into a 20-year agreement to negotiate an applicable price using an avoided cost methodology based on IPUC regulations.
•The IPUC issued an orderutilize the storage capacity from a 150-MW battery storage facility scheduled to be online in August 2015 that revised the standard PURPA power purchase contract term for new contracts to a 2-year term from the previously required 20-year term for qualifying facilities that exceed the size limitations for published avoided costs.
•The OPUC requires thatJune 2025. Idaho Power pay published avoided costsintends for solar PURPA qualifying facilities withthis capacity to supplement a nameplate ratingtotal of 3304 MW or less and all other types of projects with a nameplate ratingcompany-owned storage that it expects to be online by the end of 10 MW or less. Idaho Power is required to negotiate an applicable price using an avoided cost methodology based on OPUC regulations.2025.

Participation in Western Energy Imbalance MarketMarkets: Idaho Power participates in an energy imbalance market in the western United States (Western EIM)Western EIM under which the participating parties enable their systems to interact for automated intra-hour economic dispatch of generation from committed resources to serve loads. The Western EIM is intended to reduce the power supply costs to serve customers through more efficient dispatch of a larger and more diverse pool of resources, to integrate intermittent power from renewable generation sources more effectively, and to enhance reliability. ParticipationIdaho Power is participating with other stakeholders in different regional forums discussing the Western EIM is voluntary and available to all balancing authoritiespotential for developing other energy markets in the western United States. U.S., including development of a potential day-ahead wholesale centralized market, which Idaho Power believes could provide additional benefits through the centralized economic dispatch of resources of participating utilities.
Transmission Services
 
Electric transmission systems deliver energy from electric generation facilities to distribution systems for final delivery to customers. Transmission systems are designed to move electricity over long distances because generation facilities can be located hundreds of miles away from customers. Idaho Power’s generating facilities are interconnected through its integrated transmission system and are operated on a coordinated basis to achieve maximum capability and reliability. Idaho Power’s transmission system is directly interconnected with the transmission systems of the Bonneville Power Administration,BPA, Avista Corporation, PacifiCorp, NorthWestern Energy, and NV Energy. These interconnections, coupled with transmission line capacity made available under agreements with some of those entities, permit the interchange, purchase, and sale of power among entities in the Western Interconnection, the transmission grid covering much of western North America. Idaho Power provides wholesale transmission service for eligible transmission customers on a non-discriminatory basis. Idaho Power is a member of the Western Electricity Coordinating Council, the NorthwestWestern Power Pool, NorthernGrid, and the North American
14
Table of Contents
Energy Standards Board. These groups have been formed to more efficiently coordinate transmission reliability and planning throughout the Western Interconnection. Demand for transmission services can be affected by regional market factors, such as loads and generation of utilities in Idaho Power’s region.

Transmission to serve Idaho Power's retail customers is subject to the jurisdiction of the IPUC and OPUC for retail rate makingrate-making purposes. Idaho Power provides cost-based wholesale and retail access transmission services under the terms of a FERC approvedFERC-approved OATT. Services under the OATT are offered on a nondiscriminatorynon-discriminatory basis such that all potential customers, including Idaho Power, have an equal opportunity to access the transmission system. As required by FERC standards of conduct, Idaho Power's transmission function is operated independently from Idaho Power's energy marketing function.

14
Table of Contents
Idaho Power is jointly working with various partners on the permittingdevelopment of two significant transmission projects. The Boardman-to-Hemingway project is a proposed 300-mile, high-voltage transmission line between a stationsubstation near Boardman, Oregon, and the Hemingway stationsubstation near Boise, Idaho. The Gateway West project is a proposed 1,000-mile, high-voltage transmission line project between a stationsubstation located near Douglas, Wyoming, and the Hemingway station.substation. Both projects are intended to meet future anticipated resource needs and are discussed in Part II, Item 7 – MD&A - "Liquidity and Capital Resources - Capital Requirements" in this report.
 
Resource Planning
 
Integrated Resource Planning: The IPUC and OPUC require that Idaho Power prepare biennially an Integrated Resource Plan (IRP).IRP. Idaho Power filed its most recent 2023 IRP with the IPUC and OPUC in 2021 (2021 IRP). TheSeptember 2023. Each 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, mid-term, and long-term actions. The four primary goals of the IRP are to: 

•identify sufficient resources to reliably serve the growing demand for energy within Idaho Power's service area throughout the 20-year planning period;
•ensure the selected resource portfolio balances cost and risk, while including environmental considerations;
•give balanced treatment to supply-side and demand-side measures; and
•involve the public in the planning process in a meaningful way.
 
During the time between IRP filings, the public and regulatory oversight of the activities identified in the IRP allows for discussion and adjustment of the IRP as warranted. Idaho Power makes periodic adjustments and corrections to the resource plan to reflect economic conditions, anticipated resource development, changes in technology, and regulatory requirements.

The load forecast assumptions Idaho Power used in its 20212023 IRP are included in the table below, together with the average annual growth rate assumptions used in the prior two IRPs. While assumptions are estimates only and subject to change based on actual customer load ramp-rates, the 2023 IRP assumptions include significant large commercial and industrial additions in the 5-year forecasted annual growth rate, including potential load from new facilities under development by Meta Platforms, Inc. and Micron Technology, Inc. The rate of load growth can impact the timing and extent of development of resources, such as new generation plants or transmission infrastructure, to serve those loads.

5-Year Forecasted Annual Growth Rate20-Year Forecasted Annual Growth Rate
Retail Sales
(Billed MWh)		Annual Peak
(Peak Demand)		Retail Sales
(Billed MWh)		Annual Peak
(Peak Demand)
5-Year Forecasted Annual Growth Rate5-Year Forecasted Annual Growth Rate20-Year Forecasted Annual Growth Rate
Retail Sales
(Billed MWh)		Retail Sales
(Billed MWh)		Annual Peak
(Peak Demand)		Retail Sales
(Billed MWh)		Annual Peak
(Peak Demand)
2023 IRP2023 IRP5.5%3.7%2.1%1.8%
2021 IRP2021 IRP2.6%2.1%1.4%2021 IRP2.6%2.1%1.4%1.4%
2019 IRP2019 IRP1.3%1.4%1.0%1.2%2019 IRP1.3%1.4%1.0%1.2%
2017 IRP1.1%1.6%0.9%1.4%

Idaho Power's 2021The 2023 IRP identified a preferred resource portfolio and action plan which includedadds 8,436 MW of resource capacity partially offset by retirements of 841 MW of coal-fired generation and 706 MW of natural gas generation over the next 20 years to meet energy and capacity needs. The additions to resource capacity include 3,325 MW of solar, 1,800 MW of wind, 1,453 MW of storage, 360 MW of additional energy efficiency, 340 MW of hydrogen, 160 MW from demand response, and 30 MW of geothermal. In addition, the preferred resource portfolio includes Idaho Power's complete exit from coal-fired generation by 2030 and the conversions of multiple jointly-owned coal-fired generation units to add 968 MW of natural gas generation capacity. Of the additional natural gas generation capacity, 706 MW are expected to be retired in 2038, resulting in a net addition of a 120-MW solar resource in late 2022, the conversion from coal to261 MW of natural gas of two units atgeneration capacity through 2043. To support these resource additions, the Jim Bridger plant in 2024, the end to Idaho Power's participation in coal-fired operations at the North Valmy plant unit 2 in 2025, the completion ofpreferred portfolio also includes the Boardman-to-Hemingway transmission line in 2026 and an end to Idaho Power's participationthree Gateway West transmission line segments phased in the remaining two coal-fired units at the Jim Bridger plant by the end of 2028. The 2021 IRP preferred resource portfolio and action plan also includes a need to acquire significant generation and storage resources to meet energy and capacity needs. Including the resources noted above, over the next 20 years the IRP plans for the addition of 1,685 MW of storage capacity, 1,405 MW of solar capacity, 700 MW of wind capacity, 500 MW of transmission capacity, and 400 MW of capacitywith in-service dates from demand response. As2028 through 2040. However, as noted in the 20212023 IRP, there is considerable uncertainty surrounding the resource sufficiency estimates and project completion dates, including uncertainty around the timing and extent of third-party development of renewable resources, fuel commodity prices, regulatory requirements,and the actual completion date and ownership allocations of the Boardman-to-Hemingway transmission project, and the economics and logistics of coal-fired plant conversions and retirements.projects. These uncertainties, as well as others, maycould result in changes to the desirability of the
15
Table of Contents
preferred portfolio and adjustments to the timing and nature of anticipated and actual actions in the 2021 IRP. As of the date of this report, proceedings relating to the 2021 IRP are pending at the IPUC and OPUC.actions.

Energy Efficiency and Demand Response Programs: Idaho Power’s energy efficiency and demand response portfolio is comprised of 2422 programs. The energy efficiency programs target energy savings across the entire year, while the demand response programs target system demand reduction in the summer at times of peak loads. The programs are offered to all
15
Table of Contents
customer segments and emphasize the wise use of energy, especially during periods of high demand. This energy and demand reduction can reduce or delay the need for new generation and transmission infrastructure. Idaho Power’s programs include:

•financial incentives for irrigation customers for either improving the energy efficiency of an irrigation system or installing new energy efficient systems;
•energy efficiency programs for new and existing homes including electric heating, ventilation and cooling equipment, as well as energy efficient building techniques, air duct sealing, and energy efficient lighting;
•incentives to industrial and commercial customers for acquiring energy efficient equipment, and using energy efficiency techniques for operational and management processes;
•demand response programs to reduce peak summer demand through the voluntary cycling of central air conditioners for residential customers, interruption of irrigation pumps, and reduction of commercial and industrial demand through actions taken by business owners and operators; and
•participation in the Northwest Energy Efficiency Alliance, which supports market transformation efforts across the region.

In 2021,2023, Idaho Power’s energy efficiency programs reduced energy usage by approximately 138,000140,000 MWh compared with 195,000141,000 MWh in 2020.2022. For 2021,2023, Idaho Power had a demand response available capacity of approximately 379312 MW. In 2021, 2020,both 2023 and 2019,2022, Idaho Power expended approximately $42 million and expended $38 million $51 million, and $49 million, respectively,in 2021 on both energy efficiency and demand response programs. Funding for these programs is provided through a combination of the Idaho and Oregon energy efficiency tariff riders, base rates, and the power cost adjustment mechanisms. Energy efficiency program expenditures funded through the riders are reported as an operating expense with an equal amount of revenues recorded in other revenues, resulting in no net impact on earnings.

Environmental, Social, and Governance Initiatives

Overview: IDACORP’s and Idaho Power’s boards of directors,corporate governance and nominating committee, with considerable focus from the corporate governance and nominating committee, areboard of directors, is primarily responsible for the oversight of the companies’ environmental, social,ESG initiatives and governance (ESG) initiatives andboth are regularly informed of the goals, measures, and results of the companies' ESG and sustainabilityprograms. Each committee of the board of directors is assigned a portion of the oversight of the companies' ESG programs. Idaho Power has established an internal ESG Steering Committee co-ledsteering committee led by two officerssenior management and composed of a cross-functional team of key employees from the legal, finance, operations, investor relations, and othermultiple departments to oversee ESG activities and inform leadership and the board of directors on ESG relatedESG-related activities and matters it identifies as material to the company's operations.operations and financial condition.

IDACORP and Idaho Power publicly release annual ESG reports and the most current report is located on Idaho Power’s website, together with other information on ESG issues relevant to Idaho Power, including short-, medium-, and long-term carbon dioxide (COCO2) emission reduction targets that Idaho Power believes are aligned with the Paris Agreement goal of reducing CO2 emissions to net zero by 2050.targets. IDACORP's and Idaho Power's 20212022 ESG Report released in April 2023 incorporated elements of the Task Force on Climate-Related Financial Disclosures(TCFD) guidelines and the Sustainability Accounting Standards Board (SASB) reporting framework, as well as the Edison Electric Institute (EEI) ESG reporting template. Additionally, in 2023 Idaho Power responded to the Climate Disclosure Project (CDP) annual questionnaire, providing emissions data and management plans to address risks associated with climate change. The ESG reports, CDP filing, and related website content are not incorporated by reference into this 2021 Annual Report.report. IDACORP’s and Idaho Power’s ESG initiatives include:

•establishing responsible management goals and long-term strategies related to the companies’ impact on the environment; such as
◦the "Clean Today,Today. Cleaner Tomorrow.®" goal to provide Idaho Power's customers with 100-percent clean energy by 2045,2045;
◦the sustainability benefits from the Boardman-to-Hemingway and Gateway West transmission projects, which include integrating renewable energy generation and deferring or eliminating the need for development of additional fossil-fueled resources,resources;
◦integrating renewable resources into Idaho Power's generation mix and identifying and investigating new generation and storage technologies; as part of this effort, Idaho Power has issued requests for proposals in June
16
Table of Contents
2021 and December 2021RFPs for additional energy resources, including renewables or natural gas resource convertible to hydrogen gas power, and to-date has procured solar power and battery storage as a result of those RFPs;
◦continuing various environmental stewardship programs along the Snake River, including fish habitat preservation, water temperature reduction, and fish and plant restoration,restoration;
◦wildfire mitigation planning and actions, andactions;
◦wildlife habitat, archaeological and cultural resource, and raptor protection stewardship;
16
Table of Contents
•operational excellence in safely providing reliable, affordable, and clean energy, including enhancing grid resiliency and reliability;
•engaging and empowering Idaho Power’s workforce (including succession planning at all levels, employee development, leadership education, retirement planning education, and providing competitive compensation and benefits, including post-retirement benefits);
•promoting a culture of safety, security, and inclusiveness for all employees; and
•building strong community partnerships for healthy, sustainable economic development in Idaho Power’s service area.area; and

•
Based on shareholder engagement feedback, in 2021publicly releasing Idaho Power also publicly released itsPower's annual EEO-1 statement to report its board and employee demographic workforce data.

Reducing Carbon Emissions Intensity: Carbon emissions intensity is a measure of the pounds of CO2 emitted per MWh of energy generated. Idaho Power tracks carbon emissions intensity to measure the impact of its efforts to reduce carbon emissions relative to growing power demand in its service area. Idaho Power has actively engaged in voluntary carbon emissions intensity reduction over the past decade with an original short-term goal to reduce emissions 10-15 percent from the baseline year of 2005 levels. Idaho Power increased the short-term goal to reduce carbon emission intensity by at least 15-20 percent for the period from 2010 to 2020,2010-2020, and exceeded this goal with an estimated average reduction of 29 percent over that period compared with 2005. In May 2020, IDACORP’s and Idaho Power’s boards of directors approved an increased short-term goal to reduce carbon emission intensity by 35 percent for the period from 2021-2025 compared with 2005. In January 2022, Idaho Power posted its emissions reduction report on its website that establishesestablished short-, medium-, and long-term targets for further CO2 reductions. This report also includes target annual power generation levels and associated CO2 emissions and emissions intensity for the 2021-2040 period. The emissions reduction report is not incorporated in this 2021 Annual Report.report. Idaho Power has significantly reduced its CO2 emissions since the 2005 baseline year, primarily by decreasing its coal generation levels, including terminating coal generation at the North Valmy Unit 1 in 2019 and at the Boardman plant in 2020, and also by upgrading its hydropower facilities, and through its energy efficiency, demand-side management, and cloud-seeding programs. Idaho Power plans to continue to reduce CO2 emissions in future years, including a medium-term goal with a targeted 7986 percent reduction in annual CO2 emissions tons by 2030, compared towith the 2005 baseline year. In 2019, Idaho Power announced its long-term goal to provide 100 percent clean energy by 2045.

Reduction in Coal-Fired Generation: Idaho Power monitors environmental requirements and assesses whether environmental control measures are or remain economically appropriate. In 2017 and 2018, the IPUC and OPUC approved settlement stipulations allowing accelerated depreciation and cost recovery for the North Valmy plant in connection with Idaho Power's plan to end its participation in the coal-fired operation of units 1 and 2. Idaho Power ended its participation in the coal-fired operation of unit 1 in December 2019, as planned, and plansregulatory orders from the IPUC and OPUC provide for Idaho Power to end its participation in coal-fired operations of unit 2 no later than the end of 2025. In October 2020, Idaho Power and co-owner Portland General Electric ceased coal-fired operations at theirthe Boardman plant, as planned.

In June 2021,2022, the IPUC approved Idaho Power filed anPower's amended application with the IPUC requesting, among other things, authorization to allow the Jim Bridger plant to be fully depreciated and recovered by end-of-year 2030. In September 2021,The details of the co-owner and operator ofIPUC's order relating to the Jim Bridger plant submitted its integrated resource plan to the IPUC that contemplates ceasing coal-fired generation in units 1 and 2 in 2023 and converting those units to natural gas generation by 2024. The status of Idaho Power's application isare described more fully in Part II, Item 7 – MD&A – "Regulatory Matters."

As ofRegulatory orders from the date of this report,IPUC and OPUC provide for Idaho Power expects to cease participation incoal-fired operations ofat all jointly-owned coal-fired generation plants by the end of 2028. However, as noted previously, Idaho Power's 2023 IRP identified a preferred resource portfolio and action plan that includes the conversion from coal to natural gas of two units at the Jim Bridger plant in 2024, the two units at the North Valmy plant in 2026, and the remaining two units at the Jim Bridger plant in 2030. For more information on the 2023 IRP, refer to "Resource Planning" in this Item 1 – "Business." Idaho Power expects to seek approval from the IPUC and OPUC for any necessary adjustments to plant retirement dates to align with its current resource plan.

Climate Change Adaptation: Idaho Power believes its practice of in-depth planning and prudent preparation helps the company adapt to and address the risks of climate change. For more than 100 years, Idaho Power has adapted to changes in temperatures, water conditions, economic impacts, and regulatory requirements. In recent years, Idaho Power has proactively addressed risks associated with climate change through preventative measures. To address the physical impacts of climate change, Idaho Power conducts cloud-seeding operations, implements a wildfire mitigation plan,WMP, enhances grid resiliency and reliability, and continues to further Snake River shading and in-stream river enhancement projects. Idaho Power also plans for the social and economic impacts of climate change by furtheringmoving forward toward its carbon emissions intensity reduction goal,goals, continuing efforts to achieve its path away from coal generation, increasing the integration of renewable energy, and enhancing outage communication efforts.
17
Table of Contents
customer and stakeholder communication. Additionally, to plan for the potential regulatory impacts of climate change, Idaho Power emphasizesconsiders climate-related impacts in planning efforts, plans and advocates for additional transmission capacity to integrate additional renewable energy onto its
17
Table of Contents
system, identifies and investigates new technologies, including battery storage, hydrogen generation, and modular nuclear reactor technology, and evaluates modifications to its pricing structure it believes will help ensure fair pricing for all customers.

Environmental Regulation and Costs

Idaho Power's activities are subject to a broad range of federal, state, regional, and local laws and regulations designed to protect, restore, and enhance the quality of the environment. Environmental regulation impacts Idaho Power’s operations due to the cost of installation and operation of equipment and facilities required for compliance with environmental regulations, the modification of system operations to accommodate environmental regulations, and the cost of acquiring and complying with permits and licenses. In addition to generally applicable regulations, Idaho Power's jointly-owned coal-fired power plants, natural gas combustion turbine power plants, and hydropower generating plants are subject to a broad range of environmental requirements, including those related to air and water quality, waste materials, and endangered species. For a more detailed discussion of these and other environmental issues, refer to Part II - Item 7 - MD&A - "Environmental Matters" in this report.

Environmental Expenditures: Idaho Power’s environmental compliance expenditures will remain significant for the foreseeable future, particularly given the volume of existing and proposed regulations at the federal level. Idaho Power estimates its environmental expenditures, based upon present environmental laws and regulations, will be as follows for the periods indicated, excluding AFUDC (in millions of dollars):
20222023-2024
202420242025-2026
Capital expenditures:Capital expenditures:
License compliance and relicensing efforts at hydropower facilities
License compliance and relicensing efforts at hydropower facilities
License compliance and relicensing efforts at hydropower facilitiesLicense compliance and relicensing efforts at hydropower facilities$21 $68 
Investments in equipment and facilities at thermal plantsInvestments in equipment and facilities at thermal plants10 11 
Total capital expendituresTotal capital expenditures$31 $79 
Operating expenses:Operating expenses:
Operating costs for environmental facilities - hydropowerOperating costs for environmental facilities - hydropower$21 $43 
Operating costs for environmental facilities - hydropower
Operating costs for environmental facilities - hydropower
Operating costs for environmental facilities - thermalOperating costs for environmental facilities - thermal10 21 
Total operations and maintenance$31 $64 
Total other O&M
 
Idaho Power anticipates that finalization, implementation, or modification of a number of federal and state rulemakings and other proceedings addressing, among other things, greenhouse gases (GHG)GHGs and endangered species, could result in substantial changes in operating and compliance costs, but Idaho Power is unable to estimate those changes in costs given the uncertainty associated with existing and potential future regulations. Idaho Power expects that it would seek to recover increases in costs through the ratemaking process. 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 potential early plant retirements cannot be fully recovered in rates on a timely basis.

Idaho Power is actively pursuing the relicensing of the HCC, its largest hydropower generation source. As of the date of this report, although Idaho Power believes issuance of a new HCC license by the FERC is likely in 2025 or thereafter, Idaho Power is unable to predict the exact timing of issuance by the FERC of any license order or the ultimate capital investment and ongoing operating and maintenance costs Idaho Power will incur in complying with any new license. However, Idaho Power estimates that the annual costs it will incur to obtain a new long- termlong-term license for the HCC, including AFUDC, are likely to range from $30$35 million to $40$45 million until issuance of the license. Subsequent to the issuance of a new license, Idaho Power expects to incur increased annual capital expenditures and operating and maintenance costs to comply with the requirements of any new license.

Human Capital

Overview: Idaho PowerPower's purpose is passionate about powering lives withby safely providing reliable, affordable, and clean energy. Idaho Power believes that it will prosper by committing to the needs, safety, and success of its customers, communities, employees, and owners. Idaho Power relies on its foundational core values to guide its plan and actions: safety first; integrity always; and respect for all.

To further its mission,objectives, Idaho Power’s human capital programs are designed to attract, retain, and develop high quality employees.employees, without regard to race, color, religion, national origin, sex (including pregnancy), age, sexual orientation, gender identity, genetic information, veteran status, physical or mental disability, or marital status. Idaho Power believes it maintains a good relationship with its employees due to a strong safety culture, a respectful and inclusive environment, opportunities for development, and competitive compensation and benefits. Idaho Power regularly
18
Table of Contents                              
development, and competitive compensation and benefits. Idaho Power regularly conducts employee engagement surveys to seek feedback from its employees on a variety of topics, including safety reporting, support for development, understanding of the company’s initiatives,objectives, communication, being treated with respect, and feeling valued. Idaho Power shares the survey results with employees, and senior management incorporates the results of the surveys in their action plans in order to respond to the feedback and improve employee relations.

As of December 31, 2021,2023, IDACORP had 1,9922,100 full-time employees, 1,9832,092 of whom were employed by Idaho Power and 98 of whom were employed by Ida-West. IDACORP had 712 part-time employees, 59 of whom were employed by Idaho Power. Of IDACORP's full-time employees, 5349 percent havehave worked at the company for over 10 years as of the date of this report. All IDACORP and Idaho Power employees work in the United States. As of the date of this report, no Idaho Power employees are represented by unions.

Board and Board Committee Oversight: IDACORP’s and Idaho Power’s boards of directors provide oversight for the companies’ human capital management. The companies’ management updates the full board of directors and its committees regularly on safety metrics, total rewardscompensation for employees, benefit and pension programs, succession planning and training programs, and diversity, equity, and inclusion initiatives, among other things. Each committee of the board of directors is delegated and takes on specific roles in this oversight. The compensation and human resources committee is responsible for overseeing employee compensation, benefit plans, and general labor issues, diversity, equity, and inclusion, and safety issues. The audit committee is responsible for overseeing risk management, including compliance with the code of business conduct, and physical security risks relating to employees.employees, and environmental compliance. The corporate governance and nominating committee is responsible for overseeing risks associated with governance, lobbying and government relations, political contributions, and social issues associated with employees as part of its ESG risk oversight function.

Safety: Idaho Power is committed to the safety of its employees, customers, and the communities it serves. Idaho Power believes that safe, engaged, and effective employees are critical to the company’s success and that the company’s record of safety helps keep its service reliable and affordable. Idaho Power consistently ranks in the top 30 percent of all United States utilities in safety performance. Reflective of Idaho Power's focus on safety, the company’s Occupational Health and Safety Administration (OSHA) recordable injury rate was below the industry average rate during the last four years, and its safety metrics in 2021 were the strongest in the company’s history. In 2021, for example, Idaho Power's severity rate for injuries, measured by the number of lost workdays per 100 employees, decreased 84 percent, and its lost-time injury rate, measured by the number of lost time injuries divided by the number of OSHA-recordable injuries, decreased 79 percent, compared to its previous five-year averages for those rates.

In recognition of Idaho Power's safety culture and the dedication of its employees, the EEI presented the inaugural Thomas F. Farrell, II Safety Leadership and Innovation Award in the Member Company Project category to Idaho Power in January 2022. Idaho Power was selected for its approach of combining psychological safety and behavioral safety with practical application of human performance principles. The award recognizes the contributions of leadership and innovation to the advancement of safety in the energy industry. Recipients of the award are selected by a panel consisting of leadership from the labor, contractor, and academic communities; regulatory agencies; and EEI senior leadership.
During the COVID-19 public health crisis, Idaho Power implemented significant changes that it determined were in the best interest of its employees, as well as the communities in which it operates, in addition to complying with government regulations. While the nature of Idaho Power’s industry necessitated that much of its field-based workforce continue to operate in the field, Idaho Power implemented numerous measures to help ensure the safety of those employees, and the public, amidst the public health crisis. Most of Idaho Power’s non-field employees worked remotely beginning in March 2020 and many remain working remotely or under a hybrid, in-office and remote schedule as of the date of this report. For more information on Idaho Power's response to the COVID-19 public health crisis, see the “Executive Overview” section of Part II, Item 7 – MD&A.

Total Rewards: Compensation: Idaho Power provides its employees with competitive pay and benefits, based in large part on salary studies and market data. Idaho Power utilizes a structured compensation schedule and regularly conducts compensation analyses that helps mitigate the potential for gender, race, or ethicity-basedethnicity-based disparities in compensation. Beyond base salaries and incentive compensation, benefits for all full-time employees include a 401k plan with company matching contributions, healthcare and insurance benefits, health savings and flexible spending accounts, paid time off, family leave, parental leave, employee assistance programs, and tuition assistance. Currently afterAfter five years of employment, a full-time employee vests in Idaho Power’s defined benefit pension plan. Idaho Power also ties annual employee incentive compensation to metrics based on the categories of earnings,financial performance, power system reliability, and customer satisfaction reflective of broad stakeholder interests and each employee's contribution.

19
Table of Contents
Idaho Power delivers a variety of training opportunities and provides rotational assignment and continuous learning and development opportunities to all employees without regard to race, color, religion, national origin, sex (including pregnancy), age, sexual orientation, gender identity, genetic information, veteran status, physical or mental disability, or marital status.employees. Idaho Power's talent development programs, overseen by a talent development team in the Human Resources department, are designed to help employees achieve their career goals, build management skills, and lead their organizations.

Idaho Power also encourages and enables its employees to support many charitable causes. This includes volunteer program engagement promoted by the company or employees. Idaho Power also has an employee-led organization called the “Employee Community Funds,” which administers charitable contributions from employees; Idaho Power matches a portion of employee donations, which supplements the company’s separate charitable contributions.

Unity - Diversity, Equity, and Inclusion: One of Idaho Power’s core values as a company is “respect for all.” IDACORP’s and Idaho Power’s Code of Business Conduct, available publicly on IDACORP’s website, states Idaho Power's position that employees deserve a workplace where they can be treated in a professional and respectful manner, and each of the company's employees has the responsibility to create and maintain such an environment. In furtherance of this core value, Idaho Power posts its "Our Commitment to Each Other" initiative on its website, which promotes an inclusive company environment as follows:

At Idaho Power, we are committed to an inclusive environment where we are all valued, respected and given equal consideration for our contributions. We believe that to be successful as a company we must be able to innovate and adapt, which only happens when we seek out and value diverse backgrounds, opinions and perspectives. Our collaborative environment thrives when we are engaged, feel we belong and are empowered to do our best work. We are a stronger company when we stand together and embrace our differences.

As of December 31, 2021,2023, 44 percent of Idaho Power’s senior management were women, 2129 percent of its officers were women, and 36 percent of its board of directors were women. IdahoIdaho Power also has programs in place to encourage STEM participation in science, technology, engineering, and mathematics education and careers, training to minimize bias and ensure a respectful and inclusive workplace, with a mindset of unity, community outreach to underservedacross the communities Idaho Power serves, and partnerships with multiple diversity-focused organizations.
19
Table of Contents

IDACORP FINANCIAL SERVICES, INC.
 
IFS invests in real estate tax credit projects, such as affordable housing developments, which provide a return principally by reducing federal and state income taxes through tax credits and accelerated tax depreciation benefits. IFS has focused on a diversified approach to its investment strategy in order to limit both geographic and operational risk with most of IFS’s investments having been made through syndicated funds. At December 31, 2021,2023, the unamortized amount of IFS’s portfolio was approximately $35$57 million ($118127 million in gross tax credit investments, net of $83$70 million of accumulated amortization). IFS generated tax credits of $6.9 million in 2023, $6.4 million in 2022, and $6.2 million in 2021, $5.3 million in 2020, and $2.9 million in 2019. In 2021 and 2019,2021. IFS received distributions related to fully-amortized real estate tax credit investments that reduced IDACORP's income tax expense by $0.5 million in 2023, $0.8 million in 2022, and $1.0 million and $3.2 million, respectively. In 2020, IFS received no distributions related to fully-amortized real estate tax credit investments.in 2021.

IDA-WEST ENERGY COMPANY
 
Ida-West operates and has a 50 percent ownership interest in nine hydropower projects that have a total nameplate capacity of 44 MW. Four of the projects are located in Idaho and five are in northern California. All nine projects are “qualifying facilities” under PURPA. Idaho Power purchased all of the power generated by Ida-West’s four Idaho hydropower projects at a cost of approximately $9 million in 2023 and $8 million in 2021both 2022 and $9 million in both 2020 and 2019.2021.

INFORMATION ABOUT OUR EXECUTIVE OFFICERS
 
The names, ages, and positions of the executive officers of IDACORP and Idaho Power are listed below (in alphabetical order), along with their business experience during at least the past five years. There are no family relationships among these officers, nor is there any arrangement or understanding between any officer and any other person pursuant to which the officer was appointed.

20
Table of Contents
RYAN N. ADELMAN, 4749
•Vice President of Power Supply of Idaho Power Company, August 2020 - present
•Vice President of Transmission & Distribution, Engineering and Construction of Idaho Power Company, October 2019 - August 2020
•Regional Manager for the Southeast Region of Idaho Power Company, January 2018 - October 2019
BRIAN R. BUCKHAM, 44
•Transmission & Distribution Projects Senior ManagerVice President, Chief Financial Officer, and Treasurer of IDACORP, Inc. and Idaho Power Company, January 20152024 - present
•Senior Vice President and Chief Financial Officer of IDACORP, Inc. and Idaho Power Company, March 2022 - December 20172023
BRIAN R. BUCKHAM, 43*
•Senior Vice President and General Counsel of IDACORP, Inc. and Idaho Power Company, February 2017 - present
•Vice President and General Counsel of IDACORP, Inc. and Idaho Power Company, April 2016 - February 2017March 2022

MITCH COLBURN, 3840
•Vice President of Planning, Engineering and Construction of Idaho Power Company, August 2020 - present
•Director of Engineering and Construction of Idaho Power Company, March 2020 - August 2020
•Director of Resource Planning and Operations of Idaho Power Company, January 2018 - March 2020
•Senior Manager, Transmission & Distribution Strategic Projects of Idaho Power Company, April 2017 - January 2018
•Engineering Leader, 500 kV and Joint Projects, Idaho Power Company, January 2015 – April 2017

SARAH E. GRIFFIN, 5254
•Vice President of Human Resources of Idaho Power Company, October 2019 - present
•Director of Human Resources of Idaho Power Company, May 2014 - October 2019
 
LISA A. GROW, 5658
•President and Chief Executive Officer of IDACORP, Inc. and Idaho Power Company, June 2020 - present
•President of Idaho Power Company, October 2019 - June 2020
•Senior Vice President and Chief Operating Officer of Idaho Power Company, April 2016 - October 2019

JAMES BO D. HANCHEY, 4648
•Vice President of Customer Operations and Chief Safety Officer of Idaho Power Company, October 2019 - present
•Customer Service Senior Manager of Idaho Power Company, February 2018 - October 2019
20
•Table of ContentsRegional Manager of Southern Region of Idaho Power Company, May 2014 - February 2018

 STEVEN R. KEEN, 61*JULIA A. HILTON, 46
•Senior Vice President and Chief Financial OfficerGeneral Counsel of IDACORP, Inc. and Idaho Power Company, March 20202023 - present
•Senior Vice President, Chief Financial OfficerDeputy General Counsel and TreasurerDirector of IDACORP, Inc. andLegal of Idaho Power Company, May 2014October 2019 - March 20202023
•Senior Counsel of Idaho Power Company, January 2016 - October 2019

JEFFREY L. MALMEN, 5456
•Senior Vice President of Public Affairs of IDACORP, Inc. and Idaho Power Company, April 2016 - present

KEN W. PETERSEN, 58
•Vice President, Chief Accounting Officer and Treasurer of IDACORP, Inc. and Idaho Power Company, March 2020 - present
•Vice President, Controller and Chief Accounting Officer of IDACORP, Inc. and Idaho Power Company, January 2014 - March 2020

ADAM J. RICHINS, 4345
•Senior Vice President and Chief Operating Officer of Idaho Power Company, October 2019 - present
•Vice President of Customer Operations and Business Development of Idaho Power Company, March 2017 - October 2019
•General Manager of Customer Operations, Engineering and Construction, January 2014 - February 2017

*As previously reported to the SEC on Form 8-K on November 19, 2021, Mr. Buckham will succeed Mr. Keen as Chief Financial OfficerAMY I. SHAW, 44
•Vice President of Finance, Compliance, and Risk of IDACORP, Inc. and Idaho Power Company, January 2024 - present
•Director of Investor Relations, Compliance, and Patrick A. Harrington will succeed Mr. Buckham as General CounselRisk of IDACORP, Inc. and Idaho Power effective March 1, 2022.Company, August 2023 - December 2023
•Director of Compliance, Risk, and Security of Idaho Power Company, May 2017 - August 2023

21
Table of Contents
ITEM 1A. RISK FACTORS
 
IDACORP and Idaho Power operate in a highly regulated industry and business environment that involves significant risks, many of which are beyond the companies' control. The circumstances and factors set forth below should not be considered a complete list of potential risks that the companies may encounter. These risk factors, as well as additional risks and uncertainties either not known as of the date of this report or that are currently believed to not be material to the business, may have a material impact on the business, financial condition, or results of operations of IDACORP and Idaho Power and could cause actual results or outcomes to differ materially from those discussed in any forward-looking statements. These risk factors, as well as other information in this report, including without limitation, in the "Cautionary Note Regarding Forward-Looking Statements" and Part II - Item 7 - "Management’s DiscussionMD&A, and Analysis of Financial Condition and Results of Operations - Matters Impacting Future Results" in this report, and information in other reports the companies file with the SEC, may be important to understanding any statement in this 2021 Annual Report or elsewhere and should be considered carefully when making any investment decisions relating to IDACORP or Idaho Power.

IDACORP's and Idaho Power's businesses regularly face risks, many of which may cause future results to be different than anticipated as of the date of this report. Below are certain important utility-specific regulatory, operational, legal and compliance, financial and investment, and general business risks.risks that may cause IDACORP's and Idaho Power's reactionsfuture business results to material future developmentsbe different than anticipated as well asof the utility industry's reactions to those developments may also impact the Companies' future results.date of this report.

Utility-Specific Regulatory Risks

Utility-specific regulatory risk includes the risks that federal, state, or local regulators may impose additional requirements and costs on Idaho Power and the utility industry, reduce authorized rates of return or otherwise adversely affect recovery of costs and the opportunity to earn a return on investments, or require Idaho Power as a utility to make adverse changes to its business models, strategies, and practices.
 
State or federal regulators may not approve customer rates that provide timely or sufficient recovery of Idaho Power's costs or allow Idaho Power to earn a reasonable rate of return, which could causeadversely affect IDACORP's and Idaho Power's financial condition and results of operations to be adversely affected. The prices that the IPUC and OPUC authorize Idaho Power to charge customers for its retail services, and the tariff rate that the FERC permits Idaho Power to charge for its transmission services, are significant factors influencing IDACORP’s and Idaho Power’s business, results of operations, liquidity, and financial condition. Idaho Power's ability to recover its costs and earn a reasonable rate of return can be affected by many regulatory factors, including the timing differencetime between when Idaho Power incurs costs and when Idaho Power recovers those costs in customers’ rates (often called "regulatory lag" in the utility industry), and differences between the costs included in rates and the amount of actual costs incurred. Idaho Power expects to incur increasing costs, which is likely to occur before the IPUC, OPUC, or FERC approve the recovery of those costs, such as construction costs for new facilities and transmission resources, costs associated with changes in the long-term cost-effectiveness or changes to the operating conditions of Idaho Power's assets that could result in early retirements of utility facilities, the costs of compliance with legislative and regulatory requirements, fuel and wholesale power costs, and increased funding levels of Idaho Power's defined benefit pension plan, and the costs of damage from fires, climate change and weather-related events, and natural disasters.plan. The IPUC, OPUC, and FERC may not allow Idaho Power to recover some or all of those costs on the basisor costs that have already been deferred as regulatory assets if they find Idaho Power did not reasonably or prudently incur those costs or for other reasons. The IPUC and OPUC may adopt different methods
21
Table of Contents
of calculating the allocation of the total utility costs in their respective jurisdictions, resulting in certain costs excluded in both states. Ratemaking has generally been premised on estimates of historic costs based on a test year, so if a given year’s actual costs are higher than historic costs, rates may not be sufficient to cover actual costs. While rate regulation is also premised on the assumption that rates established are fair, just, and reasonable, regulators have considerable discretion in applying this standard.

Economic, political, legislative, public policy, or regulatory pressures may lead stakeholders to seek rate reductions or refunds, limits on rate increases, or lower allowed rates of return on investments for Idaho Power. The ratemaking process typically involves multiple intervening parties, including governmental bodies, consumer advocacy groups, and customers, generally with the common objective of limiting rate increases or even reducing rates. While Idaho Power reached a settlement stipulation for its 2023 general rate case in Idaho that was approved by the IPUC, with the large amount of ongoing investments and the associated regulatory lag in cost recovery, Idaho Power has filed a general rate case in Oregon and on February 14, 2024, Idaho Power provided notice to the IPUC of its intent to file a general rate case or limited issue rate proceeding in Idaho on or after June 1, 2024. There can be no assurance that any rate case filed by Idaho Power will result in an outcome that is satisfactory for Idaho Power. In the past, Idaho Power has been denied recovery, or required to defer recovery pending the next general rate case, including denials or deferrals related to capital expenditures for long-term project expenses. Adverse outcomes in regulatory proceedings, or significant regulatory lag, may cause Idaho Power to incur increased or unrecovered project costs or result in cancellation of projects, or to record an impairment of its assets or otherwise adversely affect cash flows and earnings. This may also result in lower credit ratings, reduced access to capital, higher financing costs, and reductions or delays in planned capital expenditures.

For additional information relating to Idaho Power's state and federal regulatory framework and regulatory matters, see Part I - Item 1 - "Business - Utility Operations," Part II - Item 7 - "Management’s Discussion and Analysis of Financial Condition and
22
Table of Contents
Results of OperationsMD&A - Regulatory"Regulatory Matters," and Note 3 - "Regulatory Matters" to the consolidated financial statements of Part II - Item 8 in this report.
 
Idaho Power's regulatory cost recovery mechanisms may not function as intended and are subject to change or elimination, which may adversely affect IDACORP's and Idaho Power's financial condition and results of operations. Idaho Power has power cost adjustment mechanisms in its Idaho and Oregon jurisdictions and a fixed cost adjustmentFCA mechanism in Idaho. The power cost adjustment mechanisms track Idaho Power’s actual net power supply costs (primarily fuel and purchased power less wholesale energy sales) and compare these amounts to net power supply costs being recovered in retail rates. A majority of the differences between these two amounts is deferred for future recovery from, or refund to, customers through rates. Volatility in power supply costs continues to be significant, in large part due to fluctuations in hydropower generation conditions, fuel cost variability from factors including supply chain disruptions and inflationary pressures, generalinflation, supply and demand economics for fuel and power, the impact of high costs for theto purchase of renewable energy under mandatory long-term contracts, and market price variability for the purchase of power purchases from third parties based on seasonal demands and transmission system constraints. Changes in market dynamics due to the emergence of day ahead or other energy and transmission markets in the West could also increase the volatility of power supply costs. While the power cost adjustment mechanisms function to mitigate the potentially adverse impact on net income of power supply cost volatility, the mechanisms do not eliminate the cash flow impact of that volatility. When power costs rise above the level recovered in current retail rates, Idaho Power incurs the costs but recovery of those costs is deferred to a subsequent collection period, which can adversely affect Idaho Power’s operating cash flow and liquidity until those costs are recovered from customers.recovered. The fixed cost adjustmentFCA mechanism is a decoupling mechanism that allows Idaho Power to charge Idaho residential and small commercial customers when it recovers less than the base level of fixed costs per customer that the IPUC authorized for recovery in the most recent general rate case.recovery. The power cost adjustment and fixed cost adjustmentFCA mechanisms are generally subject to change at the discretion of applicable state regulators, who could decide to modify or eliminate either mechanism in a manner that adversely impacts IDACORP's and Idaho Power's financial condition, cash flows, and results of operations. In December 2021, the IPUC approved Idaho Power's proposed modifications to the fixed cost adjustment mechanism (FCA) to institute separate, and reduced, fixed cost tracking for customers added to Idaho Power's system after December 31, 2021. In January 2022, the IPUC approved Idaho Power's proposed modifications to the power cost adjustment mechanism (PCA), which would simplify the mechanism without impairing the intent or effectiveness of the PCA and have no material impact on overall cost recovery.

Operational Risks

Operational risk relates to risks arising from the systems, assets, processes, people, and external factors that affect the operation of IDACORP's or Idaho Power's businesses.

The ongoing impacts of COVID-19 could adversely affect IDACORP's and Idaho Power's business functions, financial condition, and results of operations. The COVID-19 public health crisis has had, and continues to have, widespread impacts on the global economy and on Idaho Power's employees, customers, contractors, and suppliers, and there is considerable uncertainty regarding the duration and intensity of the COVID-19 public health crisis. At the peak of the public health crisis, authorities implemented various measures to reduce the spread of the virus, such as restrictive orders and mandates (including those in effect in Idaho Power's service area in the states of Idaho and Oregon), as well as business and government shutdowns. While governmental authorities have eased restrictions and vaccines are available, it is possible that an increase in COVID-19 cases or variants or their severity could prompt a return to tighter restrictions in some or all of the states and countries in which Idaho Power and its contractors and suppliers operate. Restrictions of this nature are difficult to predict and may cause Idaho Power or its contractors to miss milestones on construction and generation resource projects and experience operational delays, delay the delivery of electrical infrastructure and other supplies that it sources from around the globe, delay the connection of electric service to new customers, prolong the time period necessary to perform maintenance of infrastructure, and reduce the use of electricity by commercial and industrial customers. For example, several suppliers and contractors have notified Idaho Power that they will be unable to timely perform services or deliver products due to supply chain and workforce disruptions associated with the public health crisis, and some have attempted to rely on force majeure provisions in their contracts with Idaho Power to permit a delay in performance. These delays could result in untimely completion of infrastructure projects, which could adversely affect Idaho Power’s operations and financial condition.

The federal government has issued, and may continue to issue, mandates related to COVID-19 vaccines, testing, and other restrictions and requirements that may be applied to Idaho Power and its workforce. Idaho Power is uncertain to what extent the requirements could disrupt the supply chain or result in Idaho Power losing skilled or specialized employees or limit Idaho Power’s ability to attract and retain skilled or specialized employees who are unwilling to abide by such restrictions, such as obtaining a vaccine or subjecting themselves to masking and weekly testing. Idaho Power, based on discussions with employees, does believe that attrition of skilled workers could result from application of a mandate for COVID-19 vaccines and masking and testing requirements to Idaho Power's workforce. If Idaho Power loses key portions of its skilled or specialized
23
Table of Contents
workforce, or significant supply chain disruptions occur, those events could adversely impact Idaho Power's ability to provide reliable service to its customers and its business and results of operations.

Further, while Idaho Power has implemented numerous COVID-19-related safety measures, Idaho Power has a limited number of highly skilled operators for some of its critical power plants and its grid operations centers. If a large portion of Idaho Power's employees in those critical facilities were to contract COVID-19 at the same time, Idaho Power would need to rely upon its business continuity plans in an effort to continue operations at those facilities. There is no certainty that such measures will be sufficient to mitigate the adverse impact to its operations.

Additionally, the uncertainty around and impacts of COVID-19 on IDACORP’s and Idaho Power’s business operations and access to capital, on their customers, and on the utility industry and economy as a whole, could adversely impact IDACORP’s financial condition, and business operations. For example, the costs related to Idaho Power's noncontributory defined benefit pension plan, as well as a defined benefit postretirement benefit plan (consisting of health care and death benefits) that covers eligible retirees, are based in part on the value of the plans’ assets and, therefore, adverse investment performance for these assets or the failure to maintain sustained growth in pension investments over time could increase its plan costs and funding requirements related to the plans. Similarly, IDACORP and Idaho Power rely on access to the capital markets to fund capital requirements. To the extent that access to the capital markets is adversely affected by COVID-19, IDACORP and Idaho Power may need to consider alternative sources of funding, such as existing or additional credit facilities, for its operations and for working capital, which may increase its cost of, as well as adversely impact its access to, capital. Increased volatility or significant disruptions in the global financial markets due to COVID-19 could impact IDACORP's and Idaho Power's ability to comply with debt covenants. These uncertain economic conditions may also result in the inability of Idaho Power's customers to pay for electric service, which could affect the collectability of its revenues and adversely affect its financial results.

The degree to which COVID-19 may continue to impact IDACORP's and Idaho Power's liquidity, financial condition, and results of operations is unknown at this time and will depend on future developments, including the continuing spread of the virus and variants, the severity of the disease, the duration of the outbreak, the effectiveness and deployment rate of vaccines, and actions that may be taken by governmental authorities.

Changes in customer growth and customer usage may negatively affect IDACORP's and Idaho Power's business, financial condition, and results of operations. Changes in the number of customers and customers' use of electricity are affected by a number of factors, such as population growth or decline in Idaho Power's service area, expansion or loss of service area, changes in customer needs and expectations, changes to customer rates, adoption rates of energy efficiency measures, customer-generated power such as from solar panels and gas-fired generators, demand-side management requirements, regulation or deregulation, and adverse economic conditions. AnContinued inflationary pressures, or an economic downturn or recession, as a result of the COVID-19 public health crisis or otherwise, could also negatively impact customer use and reduce revenues and cash flows, thus adversely affecting results of operations. Many electric utilities, including Idaho Power, have experienced a long-term decline in usage per customer, in part attributable to
22
Table of Contents
energy efficiency activities. State or federal regulations may be enacted to encourage or require mandatory energy conservation or technological advances that increase energy efficiency, which could further reduce usage per customer. Also, changing customer needs and expectations, increased customer rates as a result of the 2023 Idaho general rate case and any future rate cases, and increased competition from customer-owned generation could lead to lower customer satisfaction, reduced loyalty, difficulty in obtaining rate increases, legislation to deregulate electric service, and customers seeking alternative sources of energy and electric service. If customers choose to generate their own energy, discontinue a portion or all service from Idaho Power, or replace electric power for heating with natural gas, demand for Idaho Power's energy may decline and adversely impact the affordability of its services for remaining customers. While Idaho Power has recently experienced a net growth in usage due to an increase in the number of customers, when adjusted for the impacts of weather, the average monthly usage on a per customer basis for Idaho Power's residential customers has declined from 1,042 kilowatt-hour (kWh) in 2011 to 945 1,032 kWh in 2021.2012 to 922 kWh in 2023. There is also no guarantee that Idaho Power will continue to experience an increase in the number of customers at the current rate of growth or at all. Rate mechanisms, such as the Idaho fixed cost adjustmentFCA for residential and small commercial customers, are designed to address the financial disincentive associated with promoting energy efficiency activities, but there is no assurance that the mechanism will result in full or timely collection of Idaho Power's fixed costs, which are currently collected in large part through the company's volume-based energy rates that are based on historical sales volume. Any undercollection of fixed costs would adversely impact revenues, earnings, and cash flows. The formation of municipal utilities or similar entities for distribution systems within Idaho Power's service area could also result in a load decrease. The loss of loads resulting from some of these events may result in excess infrastructure and stranded costs and require IDACORP and Idaho Power to modify or eliminate large generation, storage, or transmission projects. This could in turn result in reduced revenues as well as write-downs or write-offs if regulators determine that the costs of the projects were incurred imprudently, which could have a material adverse impact on IDACORP's and Idaho Power's financial condition, results of operations, and cash flows.

24
Table of Contents
Conversely, if Idaho Power were to experience an unanticipated increase in the demand for energy through, for example, the rapid addition of new industrial and commercial customers or population growth in the service area, Idaho Power may be required to rely on higher-cost purchased power to meet peak system demand and may need to accelerate investment in additional generation or transmission resources. Idaho Power's 2021 IRP's2023 IRP preferred resource portfolio and action plan included a need to acquire significant generation and storage resources to meet forecasted increasing energy and capacity needs. There can be no assurance that these energy and capacity needs will not change or that the resources will be adequate to meet load demands, in which case Idaho Power issued requests for proposals in June 2021would need to rely on wholesale power purchases and December 2021 for additional energy resources, including renewables or natural gas resource convertiblewould be subject to hydrogen gas power, as described in Part 1, Item 1 - "Resource Planning and Renewable Energy Projects" in this report.the volatility of wholesale markets. If the incremental costs associated with unanticipated changes in loads exceed the incremental revenue received from the sales to the new customers, and Idaho Power is unable to secure timely and full rate relief to recover those increased costs, the resulting imbalance could have an adverse effect on IDACORP's and Idaho Power's financial condition, results of operations, and cash flows.

Changes in weather conditions, severe weather, and the impacts of climate change can adversely affect IDACORP's and Idaho Power's operating results and cause them to fluctuate seasonally. Idaho Power's electric power sales are seasonal, with demand in Idaho Power's service area peaking during the hot summer months, with a secondary peak during the cold winter months. Electric power demands by irrigation customers in Idaho Power's service area, which are impacted by temperatures and the timing and amount of precipitation, can also create significant seasonal changes in usage. Seasonality of revenues may be further impacted by Idaho Power's tiered rate structure, under which rates charged to customers are often higher during higher-load periods, such as hot summers and cold winters. Market prices for power also often increase significantly during these peak periods, at times when Idaho Power is required to purchase power in the wholesale markets to meet customer demand. While Idaho Power has regulatory mechanisms to help mitigate the impact of weather on power supply costs, there is no assurance that it will continue to receive such regulatory protection in the future. By contrast, when temperatures are relatively mild or where precipitation supplants irrigation systems, loads are often lower as customers are not using electricity for heating and air conditioning or irrigation purposes. Thus, weather conditions and the timing and extent of precipitation can cause IDACORP's and Idaho Power's results of operations and financial condition to fluctuate seasonally, quarterly, and from year to year.

Climate change could also have significant physical effects in Idaho Power’s service area, such as increased frequency and severity of storms, lightning, high winds, icing events, droughts, heat waves, fires, floods, snow loading, and other extreme weather events. These extreme weather events and their associated impacts could damage transmission, distribution, and generation facilities, causing service interruptions and extended or mass outages, increasing costs, and limiting Idaho Power's ability to meet customer energy demand. Sustained drought conditions or decreased snow pack due to reduced precipitation or higher temperatures are likely to decrease power generation from hydropower plants. Prolonged periods of unfavorable wind or solar conditions will temporarily reduce or eliminate the availability of power from wind and solar facilities, respectively. This could limit Idaho Power's ability to meet customer demand for those periods.

23
Table of Contents
The costs of repairing and replacing infrastructure or any costs related to Idaho Power liability for personal injury, loss of life, and property damage from utility equipment that fails, including as a result of significant weather and weather-related events and the increasing threat of fires, may not be covered by insurance. Costs incurred in connection with such events might also not be recovered through customer rates if the costs incurred are greater than those allowed for recovery by regulators.

Idaho Power's customers' energy needs vary with weather and to the extent weather conditions are affected by climate change, customers' energy use could increase or decrease. Increased energy use due to weather changes may require Idaho Power to invest in generating assets and transmission and distribution infrastructure, while decreased energy use due to weather changes may result in decreased revenues. Extreme weather conditions creating high energy demand may raise wholesale electricity prices for power that Idaho Power purchases to serve customers, increasing the cost of energy Idaho Power provides to its customers, and at the same time can increase the revenues Idaho Power receives for wholesale market sales of excess generation during regional extreme weather events. Variations in hydropower generation that increase Idaho Power's reliance on market purchases may lead to more costly power supply sources for its customers and reduce benefits from selling surplus hydropower in the wholesale market. The price of power in the wholesale energy markets tends to be higher during periods of high regional demand that tends to occur with weather extremes, which may cause Idaho Power to purchase power in the wholesale market during peak price periods, increasing power supply costs. Idaho Power has in place mechanisms to help mitigate the effects of energy market price volatility, but there is no assurance these mechanisms will continue to be in place or function as intended.

The costs of repairing and replacing infrastructure or liability for personal injury, loss of life, and property damage from utility equipment that fails, including as a result of significant weather and weather-related events and the increasing threat of fires, may not be covered in full by insurance. Costs incurred in connection with such events might also not be recovered through customer rates if the costs incurred are greater than those allowed for recovery by regulators.

In addition, state and federal legislation and regulations have been proposed in recent years and may be implemented in the future, intended to limit the severity and impact of climate change. Proposals have included imposing mandatory reductions in GHG emissions, which could increase Idaho Power’s power supply and compliance costs or require generation facilities to be retired early, resulting in potential stranded costs and write-downs or write-offs if Idaho Power is unable to fully recover investments in such facilities. If financial markets increasingly view climate change or GHG emissions as a financial or investment risk for electric utilities, it could negatively affect IDACORP's and Idaho Power's ability to access debt and equity
25
Table of Contents
capital markets on favorable terms. For additional information relating to legislation, regulations, and legal proceedings related to environmental matters, see Part II - Item 7 - “Management’s Discussion and Analysis of Financial Condition and Results of OperationsMD&A - Environmental"Environmental Matters” in this report.

Liability from fires could adversely impact IDACORP's and Idaho Power's business, financial condition, and results of operations, and Idaho Power's WMP and other protocols may not prevent such liability. Fires alleged to have been caused by Idaho Power's transmission, distribution, or generation infrastructure, or that allegedly result from Idaho Power’s or its contractors’ operating or maintenance practices, could expose Idaho Power to claims for fire suppression and clean-up costs, evacuation costs, fines and penalties, and liability for economic damages, personal injury, loss of life, property damage, and environmental pollution, whether based on claims of negligence, trespass, or otherwise. The risk of wildfires is exacerbated in forested areas where beetle infestations and rising tree mortality rates have caused a significant increase in the quantity of standing dead and dying timber, increasing the risk that such trees may fall from either inside or outside Idaho Power's right-of-way into a powerline igniting a fire and increasing the severity of fires. A significant number of urban-wildland interfaces in and near Idaho Power's service area, and commonly hot, dry summer conditions that may worsen as a result of climate change, increase the likelihood and magnitude of damages that may be caused by fires burning into or allegedly originating from utility equipment. Further, there has been an increasing trend in the degree of annual destruction from wildfires in the western United States, as well as utility companies facing claims for significant damages resulting from wildfires. Idaho Power maintains insurance coverage for such risks, but insurance coverage is subject to terms and limitations and may not be sufficient to cover Idaho Power’s ultimate liability. Coverage limits within wildfire insurance policies could result in material self-insured costs due to self-insured retention amounts under the terms of Idaho Power’s insurance policies. Idaho Power or its contractors and customers could also experience coverage reductions and increased wildfire insurance costs in future years. Idaho Power may be unable to recover costs in excess of insurance through customer rates or regulatory mechanisms and, even if such recovery is possible, it could take several years to collect. If the amount of insurance is insufficient or otherwise unavailable, and if Idaho Power is unable to fully recover in rates the costs of uninsured losses, IDACORP’s and Idaho Power’s business, financial condition, and results of operations could be materially affected.

Idaho Power spends significant resources on initiatives designed to mitigate wildfire risks, including through its WMP, but there is no assurance that the WMP and protocols such as the PSPS will be successful or effective in reducing wildfire-related losses. Idaho Power will face a higher likelihood of wildfires in its service area if it cannot effectively implement its WMP. There also can be no assurance that the WMP and protocols such as the PSPS will be effective. For instance, a wildfire may be ignited and spread even in conditions that do not trigger a PSPS event. Idaho Power's inspections of vegetation near its assets may not detect structural weaknesses within a tree or other issues. If Idaho Power's WMP and protocols are not effective, a wildfire could be ignited and spread. To the extent Idaho Power’s criteria for implementing a PSPS are not sufficient to mitigate the risk of wildfires, Idaho Power does not fully implement a PSPS when criteria are met, due to other overriding factors, or
24
Table of Contents
Idaho Power’s regulators mandate changes to, or restrictions on, its criteria or other operational PSPS practices, Idaho Power will face a higher likelihood of wildfires in its service area during high-risk weather conditions.

New advances in power generation, energy efficiency, alternative energy sources, or other technologies that impact the power utility industry could decrease customer energy demand and revenues, which could have implications for generation and system planning. Advances in technology and changes in customer demand and preferences in the electric utility industry have encouraged the development of new technologies for power generation, renewable energy, energy storage, customer-owned generation, and energy efficiency. In particular, in recent years the net cost of solar and wind generation and storage technology has decreased significantly, and there are federal and state regulations, laws, and other incentives in place to help further reduce the net cost of solar, wind, and windenergy storage facilities. There is potential that customer-owned solar power generation systems, could become sufficiently cost-effective and efficient that an increasing number of Idaho Power's customers choose to install such systems on their homes or businesses, which in turn could require changes in the way Idaho Power builds and manages its distribution systems and substantial grid infrastructure costs, and at the same time reduce the demand for and sale of energy. Additionally, considerable emphasis has been placed on energy efficiency, such as LED lighting and high-efficiency appliances. Energy efficiency programs, including programs sponsored by Idaho Power under a directive from state regulatory commissions, are designed to reduce energy use and demand. The introduction of new technologies could pose risks in the form of reduced sales and new business models for energy services. These changes in technology could also alter the channels through which customers buy or utilize energy, including the potential formation of community-based, cooperative ownership or municipal structures, which could reduce Idaho Power's revenues or impact Idaho Power's expenses. A reduction in load, however, would not necessarily reduce Idaho Power's need for ongoing investments in its infrastructure to reliably serve its customers. If Idaho Power is unable to adjust its rate design or maintain adequate regulatory mechanisms allowing for timely cost recovery, declining usage from customer-owned generation sources and energy efficiency could result in under-recovery of Idaho Power's costs and investment in infrastructure, and reduce revenues, which would impact IDACORP's and Idaho Power's financial condition and results of operations.
Acts or threats of terrorism, 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 could adversely impact IDACORP's and Idaho Power's business, financial condition, and results of operations. Idaho Power operates in an industry that requires the continuous use and operation of sophisticated information technology and increasingly complex operational technology systems and network infrastructure. Idaho Power's generation and transmission facilities and its grid operations are potential targets for terrorist acts and threats, acts of war, social unrest, cyber and physical security attacks, and other disruptive activities of individuals or groups, including by nation states or nation state-sponsored groups. There have been cyber and physical attacks within the energy industry on energy infrastructure such as electric substations and fuel pipelines in the past with notable reports in the media of electric industry infrastructure specifically being targeted for and impacted by physical attacks more recently, and there are likely to be additional attacks in the future. Idaho Power and its vendors have been subject to, and will likely continue to be subject to, attempts to gain unauthorized access to systems and confidential information, or to disrupt operations. As noted by the U.S. Department of Homeland Security, the utility industry is continuing to experience an increase in the frequency and sophistication of cybersecurity incidents.

Some of Idaho Power's facilities are deemed "critical infrastructure" under federal standards, in that incapacity or destruction of the facilities could have a debilitating impact on security, reliability, or operability of the bulk electric power system, national economic security, and public health and safety. The fact that infrastructure facilities, such as power generation facilities and electric transmission or distribution facilities, are direct targets of, or potential indirect casualties of, an act of terror or war or cyber or physical attack (whether originating internal to Idaho Power or externally), may affect Idaho Power's operations by limiting the ability to generate, purchase, or transmit power. Idaho Power's electric transmission systems are part of an interconnected regional grid, and therefore, it faces the risk of causing or being subject to a long-term power outage due to grid disturbances or disruptions on a neighboring interconnected grid system. Cyber and physical threats and attacks can have cascading impacts that unfold with increasing speed across networks, information systems, and other technologies. Network, information systems, and technology-related events, including those caused by IDACORP or Idaho Power through process breakdowns, human error, security architecture or design vulnerabilities, or by third parties through cyber or physical security attacks, could result in a degradation or disruption in the energy grid and the services of the companies, as well as the ability to record, process, and report customer, business, and financial information. Physical or cyber attacks against key suppliers or service providers could have a similar effect on Idaho Power.

Idaho Power's business operations require the continuous availability of information technology systems and network infrastructure, and in the normal course of business, Idaho Power or its vendors collect and store sensitive and confidential customer and employee information and proprietary information of Idaho Power. Idaho Power’s technology systems are
2625
Table of Contents                              
dependent upon connectivity to the internet and third-party vendors to host, maintain, modify, and update its systems, which may experience significant system failures or cyber attacks that could compromise the security of Idaho Power’s assets and information. During 2020 and into 2021, as just one example, a sophisticated security breach of the SolarWinds software platform used by Idaho Power and broadly across industry sectors, including the utility industry and many of the industry’s vendors, created a cyber security vulnerability for thousands of companies in the United States as well as a number of governmental entities. All information technology systems are vulnerable to disability,being disabled, unauthorized access, unintentional defects, user error, errors in system changes, and cybersecurity incidents. Idaho Power is in the process of pursuing complex business system upgrades, and these significant changes increase the risk of system interruption. Any data security breaches, such as misappropriation, misuse, leakage, falsification or accidental release or loss of information maintained in Idaho Power's information technology systems or on third-party systems, including customer or employee data, could result in violations of privacy and other laws and associated litigation and liability for damages, fines, and penalties; financial loss to Idaho Power or to its customers; customer dissatisfaction or diminished customer confidence; and damage to Idaho Power’s reputation, all of which could materially affect Idaho Power's financial condition and results of operations.

No security measures can completely shield Idaho Power's systems, infrastructure, and data from vulnerabilities to cyber attacks, human error, intrusions, or other catastrophic events that could result in their failure or reduced functionality, and ultimately the potential loss of sensitive information or the loss of Idaho Power's ability to fulfill critical business functions and provide reliable electric power to customers. Despite the steps Idaho Power may take to detect, mitigate, or eliminate threats and respond to security incidents, the techniques used by those who seek to obtain unauthorized access, and possibly disable or sabotage systems or abscond with information and data, change frequently and Idaho Power may not be able to protect against all such actions. Idaho Power actively monitors developments in the area of cybersecurity and is involved in various related government and industry groups, and the company’s board receives security updates at least quarterly. Although Idaho Power continues to make investments in its cybersecurity program, including personnel, technologies, cyber insurance and training of personnel, there can be no assurance that these systems or their expected functionality will be implemented, maintained, or expanded effectively; nor can security measures completely eliminate the possibility of a cybersecurity breach. Further, the implementation of security guidelines and measures has resulted in, and Idaho Power expects to continue to result in, increased costs. Idaho Power maintains insurance related to many forms of cyber and physical security events; however, such insurance is subject to exclusions and may be insufficient in amount to offset any losses, costs, or damage experienced, particularly given the potential significant magnitude of a security incident like those reported broadly in the media, and further, any such insurance may become unreasonably expensive or unavailable in the future.

Terrorist attacks, acts of war, social unrest, cyber and physical security attacks, and similar incidents can also have indirect impacts by creating political, economic, social, or financial market instability, and can cause damage to or interference with Idaho Power’s operating assets, customers, or suppliers. This may result in business interruption, lost revenue, higher commodity prices, disruption in fuel supplies, lower energy consumption, and unstable commodity and financial markets, particularly with respect to electricity and natural gas, any of which may materially adversely affect Idaho Power. These events, and governmental actions in response, could result in a material decrease in revenues and increase costs to protect, repair, and insure Idaho Power's assets and operate its infrastructure, systems, and business.

Changes in capital expenditures for infrastructure and the risks associated with permitting and construction of utility infrastructure can significantly affect IDACORP's and Idaho Power's financial condition and results of operations. Idaho Power’s business is capital intensive and requires significant investments in power supply, transmission, and distribution infrastructure. A significant portion of Idaho Power’s facilities were constructed many years ago, and thus require periodic upgrades and frequent maintenance. Also, short-term and long-term anticipated increases in both the number of customers and the demand for energy require expansion and reinforcement of that infrastructure as described in Idaho Power's 20212023 IRP. Idaho Power is not only in the permitting process for two high-voltage transmission line projects, but has also entered into contracts to purchase, own, and operate 304 megawatts of battery storage assets as well as issued requests for proposalsRFPs for new capacity resources, and utility-scale battery storage,resources, which areare intended to help meet increasing customer energy demands. Idaho Power expects significant investment in capital improvements and expenditures for infrastructure projects that are subject to usual permitting and construction risks that can adversely affect project costs and the completion time. These risks include, as examples:

•the ability to timely obtain labor or materials at reasonable costs;
•defaults and delays by suppliers and contractors, including delays for specialty equipment that require significant lead times;
•increases in price and limitations on availability of commodities, materials, and equipment;
•imposition of tariffs on commodities, materials, and equipment sourced by foreign providers;
•equipment, engineering, and design failures;
•credit quality of counterparties and suppliers and their ability to meet financial and operational commitments;
•unexpected environmental and geological problems;
•the effects of adverse weather conditions;
•catastrophic events, natural disasters, epidemics, pandemics and other public health or disruptive events that could result in supply chain disruptions, as well as permitting and construction delays;
•availability of financing;
27
26
Table of Contents                              
•catastrophic events, natural disasters, pandemics and other public health events;
•availability of financing;
•the ability to obtain approval from local, state, or federal regulatory and governmental bodies and to comply with permits and land use rights, and environmental constraints; and
•delays and costs associated with disputes and litigation with third parties.

The occurrence of any of these risks could cause Idaho Power to operate at reduced capacity levels, which in turn could reduce revenues and reliability, increase expenses, or cause Idaho Power to incur penalties. If Idaho Power is unable to complete the permitting or construction of a project, or incurs costs that regulators do not deem prudent, it may be unable to recover its costs in full through rates or on a timely basis. Further, if Idaho Power is unable to secure permits or joint funding commitments to develop transmission infrastructure necessary to serve loads or if other resources become more economical, it may terminate those projects and, as alternatives, seek to develop additional generation facilities within areas where Idaho Power has available transmission capacity or pursue other more costly options to serve loads. To limit the timing-related risks of these projects, Idaho Power may enter into purchase orders and construction contracts and incur engineering and design service costs in advance of receiving necessary regulatory approvals or permits. If any of the projects are canceled for any reason, including Idaho Power's failure to receive necessary regulatory approvals or permits or because the project is no longer economical, Idaho Power could incur significant cancellation penalties under purchase orders or construction contracts. Additionally, termination of a project carries with it the potential for impairment of the associated asset if regulators deny full recovery of project costs. Thus, termination of a project could negatively affect IDACORP's and Idaho Power's financial condition and results of operations.

Demand for power during peak periods could exceed forecasted supply, resulting in deliverability risks and increased costs for, or difficulty in, purchasing capacity in the market or acquiring or constructing additional generation resources and battery storage facilities. Idaho Power's 20212023 IRP identified a low-cost preferred resource portfolio and action plan for the next 20-year period that includes adding substantial renewable resources and ending participationthe conversion from coal to natural gas of two units at the Jim Bridger plant in 2024, the two units at the North Valmy plant in 2026, and the remaining coal-firedtwo units byat the end of 2028.Jim Bridger plant in 2030. As Idaho Power implements the IRP's action plan, which also advances its goal to provide 100 percent clean energy by 2045, it remains obligated to provide reliable and affordable energy to its customers, but there are certain potential deliverability and cost risks associated with this transition.implementation. These risks include, but are not limited to, (1) the failure to timely obtain or construct additional resources to meet forecast needs related to load growth, and coal exits, (2) increased renewable energy generation presenting risks of uncertainty and variability that could be further compounded as neighboring systems transition towards increasing levels of renewable resources, and (3) increased potential resource volatility due to changes in the energy market. During peak periods, power demand could exceed, and on occasion has exceeded, Idaho Power’s forecasted available generation capacity, particularly if Idaho Power’s power plants are not performing as anticipated and additional resources and battery storage are not acquiredavailable as needed to meet demand. Competitive market forces or adverse regulatory actions may require Idaho Power to purchase capacity and energy from the market, if such resources are even available for purchase, or build additional resources to meet customers’ energy needs in an expedited manner. If that occurs, Idaho Power may be unable to recover these additional costs and could experience a lag between when costs are incurred and when regulators permit recovery in customers’ rates, which could have negative impacts on operations and cash flows.

Factors contributing to lower hydropower generation can increase costs and negatively impact IDACORP's and Idaho Power's financial condition and results of operations. Idaho Power derives a significant portion of its power supply from its hydropower facilities. During 20202023 and 2021, 542022, 55 percent and 48 percent, respectively, ofof Idaho Power's electric power from Idaho Power-owned generation was from hydropower facilities. Due to Idaho Power’s heavy reliance on hydropower generation, the impacts of climate change and factors such as precipitation and snowpack, the timing of run-off, and the availability of water in the Snake River Basin can significantly affect its operations. The combination of a long-term trend of declining Snake River base flows, over-appropriation of water, and periods of drought have led to water rights disputes and proceedings among surface water and ground water irrigators and the State of Idaho. Recharging the Eastern Snake Plain Aquifer by diverting surface water to porous locations and permitting it to sink into the aquifer is one approach to the over-appropriation dispute. Diversions from the Snake River for aquifer recharge or the loss of water rights reduce Snake River flows available for hydropower generation. When hydropower generation is reduced, Idaho Power must increase its use of more expensive thermal generating resources and market power purchases; therefore, costs increase and opportunities for wholesale energy sales are reduced, reducing revenues and potentially earnings. Through its power cost adjustment mechanisms, Idaho Power expects to recover most (but not all) of the increase in net power supply costs caused by lower hydropower generation. The timing of recovery of the increased costs, however, may not occur until the subsequent power cost adjustment year, adversely affecting cash flows and liquidity.

Idaho Power’s use of coal and natural gas to fuel power generation facilities exposes it to commodity availability and price risk, which can adversely affect IDACORP's and Idaho Power's results of operations and financial condition. AsAs part of its
28
Table of Contents
normal business operations, Idaho Power purchases coal and natural gas in the open market or under short-term or long-term contracts, often with variable pricing terms. Market prices for coal and natural gas are volatile and influenced by factors
27
Table of Contents
impacting supply and demand such as weather conditions, the adequacy and type of generating capacity, fuel transportation availability, economic conditions, regulations related to GHG emissions, changes in technology, moratoriums on federally leased coal, and increases in coal lease costs. Natural gas transportation to Idaho Power's three natural gas plants is limited to one primary pipeline, presenting a heightened possibility of supply constraint and disruptions separate from the risk of counterparty default. Most of Idaho Power's current coal supply arrangements are under long-term contracts for coal originating in Wyoming, Utah, and Colorado, and thus Idaho Power is exposed to risk of disruption of coal production in, or transportation from, that region.those regions. Idaho Power may from time to time enter into new, or renegotiate, these long-term contracts but can provide no assurance that such contracts will be negotiated or renegotiated on satisfactory terms, or at all. There also can be no assurance that counterparties to the natural gas or coal supply agreements will fulfill their obligations to supply natural gas or coal, and they may experience regulatory, financial, or technical problems or unforeseeable events that inhibit their ability to deliver natural gas or coal. Disruptions in transportation of fuel and defaults by coal and natural gas suppliers may cause Idaho Power to seek alternative, and potentially more costly, sources of fuel or rely on other generation sources or wholesale market power purchases. Idaho Power's failure to provide service due to such disruptions may also result in fines, penalties, or cost disallowances through the regulatory process. Idaho Power may not be able to fully or timely recover these increased costs through rates and power cost adjustment mechanisms, which may adversely affect IDACORP's and Idaho Power's financial condition and results of operations.

Idaho Power’s power supply, transmission, and distribution facilities are subject to numerous operational risks unique to it and its industry, including circumstances causing power outages, injuries and property damage, loss of life, and fires. Operating risks associated with Idaho Power's power supply, transmission, and distribution facilities include equipment failures, volatility in fuel and transportation pricing, interruptions in fuel supplies, increased regulatory compliance costs, changes necessitated by environmental legislation or litigation, labor disputes or attrition, accidents and workforce safety matters, environmental damage, property damage, wildfires, acts of terrorism or war or sabotage (both cyber and asset-based), the loss of cost-effective disposal options for solid waste such as coal ash, operator error, and the occurrence of catastrophic events at the facilities. Idaho Power maintains business continuity and disaster recovery plans, but such plans may be inadequate or not function as anticipated, which could result in delayed recovery after any such events. Diminished availability or performance of those facilities could result in reduced customer satisfaction, reputational harm, liability to third parties (including tort liability), and regulatory inquiries and fines. Operation of Idaho Power's owned and co-owned generating stations below expected capacity levels, or unplanned outages at these stations, could cause reduced energy output and lower efficiency levels and result in lost revenues and increased expenses for alternative fuels or wholesale market power purchases. Further, during high-load periods the transmission system in Idaho Power's service area is constrained, limiting the ability to transmit electric energy within the service area and access electric energy from outside the service area. Idaho Power's transmission facilities are also interconnected with those of third parties, and thus operation of Idaho Power's and third-parties' facilities could be adversely affected by unexpected or uncontrollable events. These transmission constraints and events could result in failure to provide reliable service to customers and the inability to deliver energy from generating facilities to the power grid, and the inability to access lower cost sources of electric energy. Idaho Power also enters into agreements with third-party contractors to perform work on its power supply, transmission, and distribution facilities, and may in some circumstances retain liability for the quality and completion of those contractors’ work, potentially subjecting Idaho Power to penalties, liability for personal injury, loss of life, or property damage, reputational harm, or enforcement actions or liability if a contractor violates applicable laws, rules, regulations, or orders.

Accidents, terrorist acts of terrorism or war, electrical contacts, fires, explosions, catastrophic failures, general system damage or dysfunction, intentional acts of destruction, uncontrolled release of water from hydropower dams, and other unplanned events related to Idaho Power's infrastructure would increase repair costs and may expose Idaho Power to liability for personal injury, loss of life, and property damage. Fires alleged to have been caused by Idaho Power's transmission, distribution, or generation infrastructure, or that allegedly result from Idaho Power’s or its contractors’ operating or maintenance practices, could also expose Idaho Power to claims for fire suppression and clean-up costs, evacuation costs, fines and penalties, and liability for economic damages, personal injury, loss of life, property damage, and environmental pollution, whether based on claims of negligence, trespass, or otherwise. The risk of wildfires is exacerbated in forested areas where beetle infestations and rising tree mortality rates have caused a significant increase in the quantity of standing dead and dying timber, increasing the risk that such trees may fall from either inside or outside our right-of-way into a powerline igniting a fire and increasing the magnitude of fires. A significant number of urban-wildland interfaces in and near Idaho Power's service area, and commonly hot, dry summer conditions that may worsen as a result of climate change, increase the likelihood and magnitude of damages that may be caused by fires burning into or allegedly originating from utility equipment. Further, there has been an increasing trend in the degree of annual destruction from wildfires in the western United States. Idaho Power maintains insurance coverage for such operating and event risks, but insurance coverage is subject to the terms and limitations of the available policies and may not be sufficient in amount to cover Idaho Power’s ultimate liability. Coverage limits within wildfire insurance policies could result in material self-insured costs in the event there are fires that are deemed to be separate occurrences covered by self-insured retention
29
Table of Contents                          ��  
amounts under the terms of Idaho Power’s insurance policies. Idaho Power or its contractors and customers could also experience coverage reductions and increased wildfire insurance costs in future years. Idaho Power may be unable to fully recover costs in excess of insurance through customer rates or regulatory mechanisms and, even if such recovery is possible, it could take several years to collect. If the amount of insurance is insufficient or otherwise unavailable, and if Idaho Power is unable to fully recover in rates the costs of uninsured losses, IDACORP’s and Idaho Power’s financial condition, results of operations, or cash flows could be materially affected.

Purchases of power mandated by PURPA from renewable energy projects and integration of power generated from those projects into Idaho Power's system, may increase costs and decrease system reliability, and adversely affect Idaho Power's and IDACORP's results of operations and financial condition. An abundance of intermittent, non-dispatchable generation from renewable energy projects interconnected with Idaho Power's system has had an impact on the operation of Idaho Power's generation plants, system reliability, power supply costs, and the wholesale power markets.Under PURPA, Idaho Power is generally obligated under federal law to purchase power from certain renewable energy projects, regardless of the then-current load demand, availability of lower cost generation resources, or wholesale energy market prices. As of December 31, 2021,2023, Idaho Power had federally-mandated contracts mandated under PURPA to purchase energy from 129 on-linefrom 130 online projects with third parties. This increasesAbsent a need for this generation, these contracts increase the likelihood and frequency that Idaho Power will be required to reduce output from its lower-cost hydropower and fossil fuel-fired generation resources, which in turn increases power purchase costs and customer rates and impacts Idaho Power's ability to invest in
28
Table of Contents
additional generation and earn a reasonable return on rate base in the future. Further, balancing load and generation from Idaho Power's power generation portfolio is challenging, and Idaho Power expects that its operational and infrastructure costs will continue to increase as a result of its efforts to integrate intermittent, non-dispatchable generation from a large number of renewable energy projects. If Idaho Power is unable to timely recover those costs through its rates, power cost adjustment mechanisms, or otherwise, those increased costs may negatively affect IDACORP's and Idaho Power's results of operations, financial condition, and cash flows.

IDACORP's and Idaho Power's activities are concentrated in one industry and in one region, which exposes it to risks from lack of diversification, regional economic conditions, and regional legislation and regulation. IDACORP and Idaho Power do not have diversified operations or sources of revenue. Idaho Power comprises the bulknearly all of IDACORP's operations, and Idaho Power's business is concentrated solely in the electricityelectric power industry. Furthermore, Idaho Power's provision of electric service to retail customers is conducted exclusively in its southern Idaho and eastern Oregon service area. As a result, IDACORP's and Idaho Power's future performance, revenues, and collectability of revenues, as well as expenses, will be affected by regional economic conditions, regulatory and legislative activity, weather conditions, and other events and conditions in its service area and in the electric power industry.
 
The impacts of a retiring workforce with specialized utility-specific functions and the inability to hire qualified third-party vendors could increase costs and adversely affect IDACORP's and Idaho Power's financial condition and results of operations. Idaho Power’s operations require a skilled workforce to perform specialized utility functions. Many of these positions, such as linemen, grid operators, engineering and design personnel, and generation plant operators, require extensive, specialized training. At December 31, 2021, approximately 16 percent of Idaho Power's employees were eligible for regular or early retirement under Idaho Power's defined benefit pension plan. This will require Idaho Power to attract, train, and retain new employees to help prevent a loss of institutional knowledge and avoid a skills gap. Idaho Power does not have employment contracts with its officers or key employees and cannot guarantee that any member of its management or any key employee at the IDACORP parent or any subsidiary level will continue to serve in any capacity for any particular period of time. Employee retention and recruitment may also be negatively impacted by more flexible remote work opportunities, higher pay offered by other employers, or lower cost of living in other areas. The loss of skills and institutional knowledge of experienced employees, the failure to foster an innovative, inclusive, equitable, and diverse environment in order to hire appropriately qualified employees, the costs associated with attracting, training, and retaining such employees to replace an aging and skilled workforce or the inability to do so, and the operational and financial costs of unionization or the attempt to unionize all or part of the companies’ workforce, could have a negative effect on IDACORP's and Idaho Power's financial condition and results of operations. Idaho Power could incur increased costs due toas a result of such turnover due to a loss of knowledge, errors due to inexperienced employees, or substantial training time, loss of productivity, and increased safety and compliance issues.

Idaho Power also hires third-party vendors to assist in performing a variety of ordinary business functions, such as power plant maintenance, data warehousing and management, software development and licensing, electric transmission and distribution operations, billing and metering processes, and vegetation management, among other things. In recent years, Idaho Power has experienced increased competition and rising prices for many forms of third-party vendor services. While Idaho Power does not rely entirely on third-party vendors for many of these business functions, the unavailability of such vendors could adversely affect the quality and cost of Idaho Power's electric service and negatively impact its results of operation.

Co-owners of Idaho Power’s generation and transmission assets may have unaligned goals and positions due to the effects of legislation, regulations, capital requirements, load growth amounts, changes in our industry, or other factors, which could at times adversely impact Idaho Power’s ability to construct and operate those facilities in a manner most suitable to Idaho Power.Idaho Power owns certain of its generation and transmission assets jointly with other owners, with varying ownership interests in such facilities, and Idaho Power plans to develop and own assets jointly in the future. While there are advantages to joint ownership of resources, there are also restrictions imposed by the joint ownership and operating agreements for those facilities that provide rights, but also restrictions, on when and how the facilities are constructed and on how they are operated. Changes in the nature of Idaho Power’s industry and the economic viability of certain plants and facilities, including impacts resulting from types and availability of other resources, fuel costs, and legislation and regulation, together with timing considerations related to expiration of permits or leases or other agreements for such facilities and other factors, could result in unaligned positions among co-owners. While Idaho Power negotiates and enforces its rights and obligations thoughtfully, differences in the co-owners’ willingness or ability to continue their participation or the timing of facility construction, modification, or decommissioning could lead to restrictions and disruptions to operations, adverse financial impacts to Idaho Power, and/or uncertainty related to the resulting cost recovery of such assets.

Legal and Compliance Risks
30
Table of Contents

Legal and compliance risk relates to risks arising from government and regulatory action and from legal proceedings and compliance with applicable laws, rules, orders, regulations, policies, and procedures, including those related to financial reporting, environmental,environment, health, and safety, and potential changes in legal requirements.

Changes in legislation, regulation, and government policy may have a material adverse effect on IDACORP’s and Idaho Power’s business in the future. Specific legislative and regulatory proposals and recently enacted legislation that could have a
29
Table of Contents
material impact on IDACORP and Idaho Power include, but are not limited to, tax reform, utility regulation, carbon-reduction initiatives, infrastructure renewal programs, climate change and environmental regulation, and modifications to accounting and public company reporting requirements. Further, the proposals and new legislation could have an impact on the rate of growth of Idaho Power’s customers and their willingness to expand operations and increase electric service requirements. Under the current Presidential Administration, Idaho Power expects laws, regulations, and policies relating to environmental compliance to continue to change and require IDACORP and Idaho Power and some of their customers to modify their business strategy or restrict activities and projects, potentially subjecting them to increased compliance costs. For example, in January 2021, the United States rejoined the Paris Agreement on climate change that requires commitments related to GHG emissions, among other things, and the Presidential Administration has announced ambitious clean energy initiatives. Many states and localities may continue to pursue climate policies in addition to federal mandates. The state of Oregon, for instance, has been pursuing cap-and-trade legislation for GHG emissions. Failure to comply with environmental laws and regulations, even if such non-compliance is caused by factors outside of Idaho Power's control, may result in the assessment of civil or criminal penalties or fines, or government enforcement actions. Idaho Power could also become subject to climate change lawsuits and an adverse outcome could require substantial expenditures and could possibly require payment of damages. IDACORP and Idaho Power expect federal, state, and local governmental authorities to implement various recent and expected future executive orders from the Presidential Administration and are unable to predict whether and to what extent such actions will meaningfully change existing legislative and regulatory environments relevant to the companies, or if any such changes would have a net positive or negative impact on the companies. Idaho Power is unable to estimate the costs of complying with such legislative or regulatory changes due to the uncertainties associated with the nature and implementation of the changes, and may not be able to recover the associated costs. To the extent that such changes have a negative impact on the companies or Idaho Power’s customers, including as a result of related uncertainty, these changes may materially and adversely impact IDACORP’s and Idaho Power’s business, financial condition, results of operations, and cash flows.

Changes in income tax laws and regulations, or differing interpretation or enforcement of applicable laws by the U.S. Internal Revenue Service or other taxing jurisdictions, could have a material adverse impact on IDACORP’s or Idaho Power’s financial condition and results of operations. IDACORP and Idaho Power must make judgments and interpretations about the application of the law when determining the provision for income taxes. Amounts of income tax-related assets and liabilities involve judgments and estimates of the timing and probability of recognition of income, deductions, and tax credits, which are subject to challenge by taxing authorities. These judgments may include estimates for potential outcomes regarding tax positions that may be subject to challenge by the taxing authorities. Disputes over interpretations of tax laws may be settled with the taxing authority in examination, upon appeal, or through litigation. In recent years, state regulatory mechanisms with income tax-related provisions (such as Idaho Power's May 2018 Idaho tax reform settlement stipulation approved by the IPUC), have significantly impacted IDACORP's and Idaho Power's results of operations. Due to the current Presidential Administration, IDACORP and Idaho Power expect tax reform legislation could be enacted that may increase the companies' federal and state tax rates and reporting obligations. The outcome of potential future income tax proceedings or laws, or the state public utility commissions' treatment of those outcomes, could differ materially from the amounts IDACORP and Idaho Power record prior to conclusion of those proceedings, and the difference could negatively affect IDACORP’s and Idaho Power’s earnings and cash flows. Further, in some instances, the treatment from a ratemaking perspective of any net income tax expense (including from increased tax rates) or benefit could be different than IDACORP or Idaho Power anticipate or request from applicable state regulatory commissions, which could have a negative effect on their financial condition and results of operations. In addition, Idaho Power uses the regulatory flow-through income tax accounting method as described in Note 1 - "Summary of Significant Accounting Policies" to the consolidated financial statements included in this report, and potential changes in income tax laws or interpretations may impact IDACORP's and Idaho Power's income taxes and reporting obligations differently than most other companies.

IDACORP's and Idaho Power’s businesses are subject to an extensive set of environmental laws, rules, and regulations, which could impact their operations and costs of operations, potentially rendering some generating units uneconomical to maintain or operate, and could increase the costs and alter the timing of major projects. IDACORP's and Idaho Power's operations are subject to a number of federal, state, and local environmental statutes, rules, and regulations relating to climate change, air and water quality, natural resources, endangered species and wildlife, renewable energy, and health and safety. Many of these laws and regulations are described in Part II - Item 7 - “Management’s Discussion and Analysis of Financial
31
Table of Contents
Condition and Results of OperationsMD&A - Environmental"Environmental Matters” in this report. These laws and regulations generally require IDACORP and Idaho Power to obtain and comply with a wide variety of environmental licenses, permits, and other approvals, including through substantial investment in pollution controls, and may be enforced by both public officials and private individuals. Some of these regulations are pending, changing, or subject to interpretation, and failure to comply may result in penalties, mandatory operational changes, and other adverse consequences, including costs associated with defending against claims by governmental authorities or private parties and complying with new operating requirements. Idaho Power devotes significant resources to environmental monitoring, pollution control equipment, and mitigation projects to comply with existing and anticipated environmental regulations. However, it is possible that federal, state and local authorities could attempt to enforce more stringent standards, stricter regulation, and more expansive application of environmental regulations.

30
Table of Contents
Environmental regulations have created the need for Idaho Power to install new pollution control equipment at, and may cause Idaho Power to perform environmental remediation on, its owned and co-owned power generation facilities, often at a substantial cost. Compliance with environmental regulations can significantly increase capital spending, operating costs, and plant outages, and can negatively affect the affordability of Idaho Power's services for customers. Idaho Power cannot predict with certainty the amount and timing of all future expenditures necessary to comply with these environmental laws and regulations, although Idaho Power expects the expenditures willcould be substantial. In some cases, the costs to obtain permits and ensure facilities are in compliance may be prohibitively expensive. If the costs of compliance with new regulations renders the generating facilities uneconomical to maintain or operate, Idaho Power would need to identify alternative resources for power, potentially in the form of new generation and transmission facilities, market power purchases, demand-side management programs, or a combination of these and other methods. Furthermore, Idaho Power may not be able to obtain or maintain all environmental regulatory approvals necessary for operation of its existing infrastructure or construction of new infrastructure. 

The utility industry is also facing increasing stakeholder scrutiny related to its environmental, social, and governance (ESG) programs. Recently, Idaho Power has seen a rise in certain stakeholders, such as investors, customers, employees, and lenders placing increasing importance on the impact and social cost of their investments. Emissions of GHGs, including, most significantly CO2, could be further restricted in the future in response to additional state and federal regulatory requirements, increased scrutiny and changing stakeholder expectations with respect to environmental and climate change programs, judicial decisions and international accords. If new emissions reduction rules were to become effective, they could result in significant additional compliance costs that would affect Idaho Power's future financial position, results of operations, and cash flows if such costs are not timely recovered through regulated rates. Moreover, the possibility exists that stricter laws, regulations, or enforcement policies could significantly increase compliance costs and the cost of any remediation that may become necessary.

In addition, some environmental regulations are currently subject to litigation and not yet final. As a result of this uncertainty, approaches to comply with the regulations, including available control technologies or other allowed compliance measures, are unpredictable and Idaho Power cannot foresee the potential impacts these regulations would have on Idaho Power's operations or financial condition. In 2019, Idaho Power announced its commitmentlong-term goal to serve customers with 100 percent clean energy by 2045, and Idaho Power has short-term and medium-term targetsgoals for CO2 emission reductions, which could impact infrastructure resource decisions and costs. Idaho Power's ability to achieve these targets are subject to a number of risks and uncertainties, including the company's regulatory obligation to serve its customers, the availability and cost of new generation resources, legal and permitting requirements, system operation and energy integration, and grid balancing, among others. Additionally, Idaho Power is not guaranteed timely or full recovery through customer rates of costs associated with environmental regulations, environmental compliance, its clean energy initiatives, plant closures, or clean-up of contamination. If there is a delay in obtaining any required environmental regulatory approval or if Idaho Power fails to obtain, maintain, or comply with any such approval, construction and/or operation of Idaho Power's generation or transmission facilities could be delayed, halted, terminated, or subjected to additional costs. For further discussion of environmental matters that may affect Idaho Power, see "Environmental Matters" in Item 7 - “Management’s Discussion and Analysis of Financial Condition and Results of Operations”MD&A in this report.

Obligations imposed in connection with hydropower license renewals and permitting may require large capital expenditures, increase operating costs, reduce hydropower generation, and negatively affect IDACORP's or Idaho Power's results of operations and financial condition. For the last several years,Since 2003, Idaho Power has been engaged in an effort to renew its federal license for its largest hydropower generation source, the HCC. Relicensing and ongoing permitting requirements include an extensive public review process that involves numerous natural resource issues and environmental conditions. The existence of endangered and threatened species in the watershed may result in major operational changes to the region’s hydropower projects, which may be reflected in hydropower licenses, including for the HCC and the American Falls facility. Federal land use agencies may also impose conditions under the FPA that could impact costs and operations if FERC deems them necessary for the adequate protection and utilization of the public lands and reservations of the United States. In addition, new agency requirements and new interpretations of existing laws and regulations could be adopted or become applicable to hydropower facilities, which could further increase required expenditures for flood control, marine life recovery and endangered species protection and may reduce the amount of hydropower generation available to meet Idaho Power’s generation requirements. Idaho Power cannot predict the requirements that might be imposed during the relicensing and permitting process, the financial impact of those requirements,
32
Table of Contents
whether a new multi-year license will ultimately be issued, and whether the IPUC or OPUC will allow recovery through rates of the substantial costs incurred in connection with the licensing process and subsequent compliance. Imposition of onerous conditions in the relicensing and permitting processes could result in Idaho Power incurring significant capital expenditures, increase operating costs (including power purchase costs), and reduce hydropower generation, which could negatively affect results of operations and financial condition.

Idaho Power could be subject to penalties, reputational harm, and operational changes if it violates mandatory reliability and security requirements, which could adversely impact IDACORP's and Idaho Power's results of operations and financial condition. As an owner and operator of a bulk power transmission system, Idaho Power is subject to mandatory reliability and security standards issued by the FERC and other regulators. The standards are based on the functions that need to be performed to ensure the bulk power system operates reliably and are guided by reliability, security, and market interface principles. Compliance with reliability standards subjects Idaho Power to higher operating costs and increased capital expenditures. Idaho Power has received in recent years notices of violations from, and regularly self-reports reliability standard compliance issues to, the FERC, the North American Electric Reliability Corporation, and the Western Electricity Coordinating Council. Potential monetary and non-monetary penalties for a violation of FERC regulations may be substantial, and in some circumstances monetary penalties may exceed $1.41.5 million per day per violation. As a utility with a large customer base, Idaho Power is subject to adverse publicity focused on the reliability of its services and the speed with which it is able to respond to electric outages caused by storm damage or other unanticipated events. Adverse publicity could harm the reputations of IDACORP and
31
Table of Contents
Idaho Power; may make state legislatures, utility commissions, and other regulatory authorities less likely to view the companies in a favorable light; and may cause Idaho Power to be subject to less favorable legislative and regulatory outcomes or increased regulatory oversight. The imposition of any of the foregoing on Idaho Power for its actual or alleged failure to comply with reliability and security requirements could also have a negative effect on its and IDACORP’s results of operations and financial condition.

IDACORP and Idaho Power are subject to costs and other effects of legal and regulatory proceedings, disputes, and claims. From time to time in the normal course of business, IDACORP and Idaho Power are subject to various lawsuits, regulatory proceedings, disputes, and claims that could result in adverse judgments or settlements, fines, penalties, injunctions, or other adverse consequences. These matters are subject to a number of uncertainties, and management is often unable to predict the outcome of such matters; resulting liabilities could exceed amounts currently reserved or insured against with respect to such matter. The legal costs and final resolution of matters in which IDACORP or Idaho Power are involved could have reputational impact and a short- or long-term negative effect on their financial condition and results of operations. Addressing any adverse publicity or governmental scrutiny could be time consuming and expensive, regardless of the basis of the assertions being made, and could impact Idaho Power's relationship with employees, stakeholders, and regulators. Further, the terms of resolution could require the companies to change their operational practices and procedures, which could also have a negative effect on their financial positions and results of operations.

Changes in accounting standards or rules may impact IDACORP's and Idaho Power's financial results and disclosures. The Financial Accounting Standards Board (FASB) and the SEC have made and may continue to make changes to accounting standards that impact presentation and disclosures of financial condition and results of operations. Further, new accounting orders issued by the FERC could significantly impact IDACORP's and Idaho Power's reported financial condition. IDACORP and Idaho Power do not have any control over the impact these changes may have on their financial conditions or results of operations nor the timing of such changes. Idaho Power meets the requirements under GAAPaccounting principles generally accepted in the United States of America to reflect the impact of regulatory decisions in its financial statements and to defer certain costs as regulatory assets until those costs are collected in rates, and to defer some items as regulatory liabilities. If recovery of these amounts ceases to be probable, if Idaho Power determines that it no longer meets the criteria for applying regulatory accounting or if accounting rules change to no longer provide for regulatory assets and liabilities, Idaho Power could be required to eliminate some or all of those regulatory assets or liabilities. Any of these circumstances could result in write-offs and have a material effect on IDACORP's and Idaho Power’s financial condition and results of operations.

Financial and Investment Risks

Financial and investment risks relate to IDACORP's and Idaho Power's ability to meet financial obligations and mitigate exposure to market risks, including liquidity risks and the ability to raise capital and cost of funding, risks related to credit ratings, credit risk, liquidity, interest rates, and commodity prices.

Volatility or disruptions in the financial markets, failure of IDACORP or Idaho Power to satisfy conditions necessary for obtaining loans or issuing debt securities, and denial of regulatory authority to issue debt or equity securities, may negatively affect IDACORP’s and Idaho Power’s ability to access capital and/or increase their cost of borrowing and ability to execute
33
Table of Contents
on their strategic plans. IDACORP and Idaho Power use credit facilities, commercial paper markets, and long-term debt, and equity securities as significant sources of liquidity and funding for operating and capital requirements and debt maturities not satisfied by operating cash flow. The creditCredit facilities represent commitments by the participating banks to make loans and issue letters of credit. However, the ability and obligation of the participating banks to make those loans and issue letters of credit is subject to specified conditions and volatility or disruptions in the financial markets could affect the companies' ability to obtain debt financing or draw upon or renew existing credit facilities on favorable terms and comply with debt covenants. Idaho Power's ability to issue long-term debt is also subject to a number of conditions included in an indenture, and Idaho Power's ability to issue long-term debt, and commercial paper, and equity securities is subject to the availability of purchasers willing to purchase the securities under reasonable terms or at all. Because of these limitations, IDACORP and Idaho Power may be unable to issue commercial paper, or short-term or long-term debt, ator equity securities on reasonable interest rates and terms or at all. Higher interest rates on short-term borrowings with variable interest rates could also have an adverse effect on IDACORP's and Idaho Power's operating results. Changes in interest rates may also impact the fair value of the debt securities in Idaho Power's pension funds, as well as Idaho Power's ability to earn a return on short-term investments of excess cash. Also, while the credit facilities represent a contractual obligation to make loans, one or more of the participating banks may default on their obligations to make loans under, or may withdraw from, the credit facilities.

Idaho Power is required to obtain regulatory approval in Idaho, Oregon, and Wyoming in order to borrow money or to issue securities and is therefore dependent on the public utility commissions of those states to issue favorable orders in a timely
32
Table of Contents
manner to permit them to finance their operations, capital expenditures, and debt maturities. IDACORP's and Idaho Power's credit facilities includeconsist of revolving lines of credit not to exceed an aggregate principal amount outstanding at any one time of $100 million and $400 million, respectively (Credit Facilities). Each of the Credit Facilities includes a financial covenantscovenant that limitlimits the amount of debt that can be outstanding as a percentage of total capital, and Idaho Power's long-term debt has also been issued under an indenture that contains a number of financial covenants. The companies must also make specified representations in connection with requestrequests for loans and it is possible that they may be unable to do so at the time of such request, which would limit or eliminate the obligation of the banks to provide loans. Failure to maintain these representations and covenants could preclude IDACORP and Idaho Power from issuing commercial paper, borrowing under their credit facilities,Credit Facilities, or issuing long-term debt, and could trigger a default and repayment obligation under debt instruments, which could limit their ability to pursue certain projects, acquisitions, or improvements, to support future growth, and adversely impact IDACORP's and Idaho Power's financial condition, results of operations, and liquidity.

A downgrade in IDACORP’s and Idaho Power’s credit ratings could affect the companies’ ability to access capital, increase their cost of borrowing, and require the companies to post collateral with transaction counterparties. Credit rating agencies periodically review the corporate credit ratings and long-term ratings of IDACORP and Idaho Power. These ratings are premised on financial ratios and performance, the regulatory environment and rate mechanisms, the effectiveness of management, resource risks and power supply costs, and other factors. IDACORP and Idaho Power also have borrowing arrangements that rely on the ability of the banks to fund loans or support commercial paper, a principal source of short-term financing. In addition, IDACORP's or Idaho Power's credit ratings may change as a result of the differing methodologies or change in the methodologies used by the various rating agencies. Downgrades of IDACORP’s or Idaho Power’s credit ratings, or those affecting relationship banks, could limit the companies’ ability to access short- and long-term capital under reasonable terms or at all, reduce the pool of potential lenders, increase borrowing costs under existing credit facilities,Credit Facilities, limit access to the commercial paper market, require the companies to pay a higher interest rate on their debt, limit the ability of IDACORP to declare and make dividends, and require the companies to post additional performance assurance collateral with transaction counterparties. If access to capital were to become significantly constrained or costs of capital increased significantly due to lowered credit ratings, prevailing industry conditions, regulatory constraints, the volatility of the capital markets, or other factors, IDACORP's and Idaho Power's ability to pursue improvements or acquisitions (including generating capacity and transmission assets, which may be necessary for future growth), liquidity, financial condition, and results of operations could be adversely affected.

Stakeholder actions and increased regulatory activity related to ESG matters, particularly global climate change and reducing GHG emissions, could negatively impact IDACORP and Idaho Power. The power and gas utility industry is facing increasing stakeholder scrutiny related to ESG matters. Recently, Idaho Power has seen a rise in certain stakeholders, such as investors, customers, suppliers, employees, and lenders, placing increasing importance on the impact and social cost associated with climate change. Customers, suppliers, or other stakeholders could pursue, and in some cases have pursued, alternatives to Idaho Power's services or business as a result of their ESG-related expectations. GHG emissions, including, most significantly CO2, could be further restricted in the future in response to additional state and federal regulatory requirements, increased scrutiny, and changing stakeholder expectations with respect to environmental and climate change programs, judicial decisions, and international accords. If new emissions reduction rules were to become effective, they could result in significant additional compliance costs that could negatively impact Idaho Power's future financial position, results of operations, and cash flows if such costs are not timely recovered through regulated rates. Moreover, the possibility exists that stricter laws, regulations, or enforcement policies could significantly increase compliance costs and the cost of any remediation that may become necessary. In addition, the increasing focus on climate change and stricter regulatory and legal requirements may result in Idaho Power facing adverse reputational risks associated with certain of its operations producing GHG emissions. If Idaho Power is unable to satisfy the increasing climate-related expectations of certain stakeholders, IDACORP and Idaho Power may suffer reputational harm, which could cause IDACORP’s stock price to decrease or cause certain investors and financial institutions not to purchase the companies’ debt or equity securities or otherwise provide the companies with capital or credit on favorable terms, which may cause IDACORP’s and Idaho Power’s cost of capital to increase.

Idaho Power’s energy risk management policy and programs relating to economically hedging commodity exposures and credit risk may not always perform as intended, and as a result, IDACORP and Idaho Power may suffer economic losses. Idaho Power enters into transactions to buy and sell power, natural gas, and transmission service, enters into transactions to hedge its positions in coal, natural gas, power, and other commodities, and enters into financialeconomic hedge transactions to mitigate in part exposure to variable commodity prices. IDACORP and Idaho Power could recognize financial losses as a result of volatility in the market value of these contracts or if a counterparty fails to perform. The derivative instruments used for hedging might not offset the underlying exposure being mitigated as intended, due to pricing inefficiencies or other terms of the derivative instruments, and any such failure to mitigate exposure could result in financial losses. Certain of Idaho Power's purchase or sale, hedging, and derivative agreements may result in the receipt of, or posting of, collateral with counterparties. Fluctuations in
33
Table of Contents
commodity prices that lead to the posting of collateral with counterparties negatively impact liquidity, and downgrades in Idaho Power's credit ratings may lead to additional collateral posting requirements. In 2023, Idaho Power has additional indirect credit exposures to financial institutionsrecorded losses on economic hedges of $16.2 million, compared with $68.5 million of gains in the form of letters of credit provided as security by power suppliers under
34
Table of Contents
various purchased power contracts and by vendors for infrastructure development projects. If any of the credit ratings of the letter of credit issuers were to drop below investment grade, the vendor or supplier would need to replace the security with an acceptable substitute, which may be impracticable and may expose2022. At times, Idaho Power’s energy risk management policy results in Idaho Power to losses resulting from a vendor or supplier default. Ifentering into economic hedges in an environment where prices are high, and if prices are lower at the security were not replaced,time the party could be in default under the contract and Idaho Power's remedies for default may be inadequate to fully compensateeconomic hedge settles, Idaho Power for itswill record losses on the economic hedges. Depending on the volume of economic hedges and the degree of price volatility, those losses can be substantial, and the power cost adjustment mechanisms generally provide that Idaho Power will incur a portion of those losses. Forecasts of future fuel needs and loads and available resources to meet those loads are inherently uncertain and may cause Idaho Power to over- or under-hedge actual resource needs, exposing the company to market risk on the over- or under-hedged position. To the extent that commodity markets are illiquid, Idaho Power may not be able to execute its risk management strategies, which could result in undesired over-exposure to unhedged positions that Idaho Power may not be able to collect in customer rates. The FERC may take action to limit volatility in the energy market by imposing price limits or other market restrictions to control market-based rate sales, which could adversely affect the companies' financial results. As a result, risk management actions, or the failure or inability to manage commodity availability and price and counterparty risk, may adversely affect IDACORP’s and Idaho Power’s financial condition and results of operations. Idaho Power has additional indirect credit exposures to financial institutions in the form of letters of credit provided as security by power suppliers under various purchased power contracts and by vendors for infrastructure development projects. If any of the credit ratings of the letter of credit issuers were to drop below investment grade, the vendor or supplier would need to replace the security with an acceptable substitute, which may be impracticable and may expose Idaho Power to losses resulting from a vendor or supplier default. If the security were not replaced, the party could be in default under the contract and Idaho Power's remedies for default may be inadequate to fully compensate Idaho Power for its losses. Further, the bankruptcy or insolvency of a counterparty to commodity or other transactions could impair Idaho Power’s ability to collect amounts receivable from those counterparties, potentially including the ability to collect or retain collateral posted by a counterparty.

Idaho Power is a participant in the energy markets, including the Western EIM, and engages in direct and indirect power purchase and sale transactions in connection with that participation. The Western EIM has collateral posting requirements based on established credit criteria, but there is no assurance the collateral will be sufficient to cover obligations that counterparties may owe each other in the Western EIM and any such credit losses could be socialized to all Western EIM participants, including Idaho Power. A significant failure of a participant in the Western EIM to make payments when due on its obligations could have a ripple effect on various Idaho Power counterparties in the power, gas, and derivative markets if those counterparties experience ancillary liquidity issues, and could generally result in a decline in the ability of Idaho Power’s counterparties to perform on their obligations.

The performance of pension and postretirement benefit plan investments, increasing health care costs, and other factors impacting plan costs and funding obligations could adversely affect IDACORP's and Idaho Power's financial condition and results of operations - primarily cash flows and liquidity. Idaho Power provides a noncontributory defined benefit pension plan covering most employees, as well as a defined benefit postretirement benefit plan (consisting of health care and death benefits) that covers eligible retirees. Costs of providing these benefits are based in part on the value of the plans' assets and, therefore, adverse investment performance for these assets or the failure to maintain sustained growth in pension investments over time could increase Idaho Power’s plan costs and funding requirements related to the plans. Idaho Power's self-insured costs of health care benefits for eligible employees and retirees have increased in recent years and Idaho Power believes that future legislative changes related to the provision of health care benefits and other external market conditions and factors, could cause such costs to continue to rise. As benefit costs continue to rise, there is no assurance that the IPUC and OPUC will continue to allow recovery.

The key actuarial assumptions that affect pension funding obligations are the expected long-term return on plan assets and the discount rate used in determining future benefit obligations. Idaho Power evaluates the actuarial assumptions on an annual basis, taking into account changes in market conditions, trends, and future expectations. Estimates of future investment market performance, changes in interest rates, and other factors Idaho Power and its actuary firms use to develop the actuarial assumptions are inherently uncertain, and actual results could vary significantly from the estimates. Changes in demographics, including timing of retirements or changes in life expectancy assumptions, may also increase Idaho Power's plan costs and funding requirements. Future pension funding requirements and the timing of funding payments are also subject to the impacts of changes in legislation. Depending on the timing of contributions to the plans and Idaho Power's ability to recover costs through rates, cash contributions to the plans could reduce the cash available for the companies' businesses and payment of dividends. For additional information regarding Idaho Power's funding obligations under its benefit plans, see Note 1211 - "Benefit Plans" to the consolidated financial statements included in this report.

34
Table of Contents
If the assumptions underlying coal mine reclamation at Bridger Coal Company and related forecast trust fund growth are materially inaccurate, Idaho Power’s costs could be greater than anticipated or be incurred sooner than anticipated. Bridger Coal Company (BCC), a subsidiaryBCC, an indirect jointly-owned investment of Idaho Power located in the state of Wyoming, uses both surface and underground methodsmining to mineextract coal to be used for power generation at the Jim Bridger power plant. The federal Surface Mining Control and Reclamation Act and state laws and regulations establish operational, reclamation, bonding, and closure obligations and standards for mining of coal. BCC’s estimate of reclamation liability and bonding obligations is reviewed periodically by Idaho Power’s management committee, audit committee of the board of directors, external and internal auditors, and by government regulators. Idaho Power funds a trust and posts collateral in the form of a surety bond purchased jointly with the co-owner of BCC to cover such projected mine reclamation costs pursuant to the laws of the state of Wyoming. The trust funds are invested in debt and equity securities and poor performance of these investments would reduce the amount of funds available for their intended purpose, which could require Idaho Power to make additional cash contributions. If actual costs related to those
35
Table of Contents
obligations exceed estimates, government regulations relating to those obligations change significantly or unexpected cash funding obligations are required, IDACORP’s and Idaho Power’s results of operations and financial condition could be adversely affected.

As a holding company, IDACORP does not have its own operating income and must rely on the cash flows from its subsidiaries to pay dividends and make debt payments. IDACORP is a holding company with no significant operations of its own, and its primary assets are shares or other ownership interests of its subsidiaries, primarily Idaho Power. IDACORP’s subsidiaries are separate and distinct legal entities and have no obligation to pay any amounts to IDACORP, whether through dividends, loans, or other means. The ability of IDACORP’s subsidiaries to pay dividends or make distributions to IDACORP depends on several factors, including each subsidiary's actual and projected earnings and cash flow, capital requirements and general financial condition, regulatory restrictions, tax obligations, covenants contained in credit facilities to which they are parties, and the prior rights of holders of their existing and future first mortgage bonds and other debt or equity securities. Further, the amount and payment of dividends is at the discretion of the board of directors, which may reduce or cease payment of dividends at any time. See Note 76 - "Common Stock" to the consolidated financial statements included in this report for a further description of restrictions on IDACORP's and Idaho Power's payment of dividends.

The market price of IDACORP's common stock may be volatile. The market price of IDACORP's common stock could be subject to significant fluctuations in response to factors such as the following, some of which are beyond its control:

•variations in IDACORP and Idaho Power's quarterly operating results;
•operating results that vary from the expectations of management, securities analysts, and investors and other impacts from the risks identified in this "Risk Factors" section and elsewhere in this report;
•changes in expectations as to future financial performance, including financial estimates by securities analysts or investors;
•developments generally affecting IDACORP and Idaho Power's industry;
•announcements by IDACORP and Idaho Power of significant contracts, acquisitions, joint ventures, or capital commitments;
•announcements by third parties of significant claims or proceedings against IDACORP or Idaho Power;
•favorable or adverse regulatory or legislative developments;
•IDACORP's dividend policy;
•change in IDACORP or Idaho Power's management;
•future sales of IDACORP's equity or equity-linked securities; and
•general domestic and international economic conditions.

In addition, the stock market in general has experienced volatility that has often been unrelated to the operating performance of a particular company. These broad market fluctuations may adversely affect the market price of IDACORP's common stock.

IDACORP's charter and bylaws and Idaho law could delay or prevent a change in control that shareholders may favor. The terms of some of the provisions in IDACORP's articles of incorporation and bylaws and provisions of Idaho law could delay or prevent a change in control that shareholders may favor or may impede the ability of shareholders to change IDACORP's management. In particular, the provisions of IDACORP's articles of incorporation and bylaws authorize issuance of up to 20,000,000 shares of preferred stock without further action by shareholders; limit the shareholders’ right to remove directors, fill vacancies and change the number of directors; regulate how shareholders may present proposals or nominate directors for election at shareholders’ meetings; and require a supermajority vote of shareholders to amend certain provisions. IDACORP is also subject to the provisions of the Idaho Control Share Acquisition Act and the Idaho Business Combination Act, which provide for certain procedures and restrictions in connection with acquisitions or business combinations.

35
Table of Contents
Statutory and regulatory factors will limit another party’s ability to acquire IDACORP and could deprive shareholders of the opportunity to gain a takeover premium for their shares of common stock. Even if IDACORP's board of directors favors a sale of the company, a sale would require approval of a number of federal and state regulatory agencies, including the FERC, the IPUC, the OPUC, and the WPSC. The approval process could be lengthy and the outcome uncertain, which may deter otherwise interested parties from proposing or attempting a business combination.

ITEM 1B. UNRESOLVED STAFF COMMENTS
 
None.

ITEM 1C. CYBERSECURITY

Assessing, identifying, managing, and mitigating risks from cybersecurity threats that may affect Idaho Power's systems and service are essential to its business. IDACORP's and Idaho Power's board of directors oversees risks from cybersecurity threats through the audit committee and the executive committee. The audit committee assists the board in the oversight of Idaho Power's major cybersecurity risk exposures, including oversight of management’s information security activities. Those activities include briefing the audit committee and the board on information security matters several times a year in their regular meetings and on an ad hoc basis, conducting an annual security training program, and arranging for external security assessments. Together with the audit committee, the board's executive committee assists the board in monitoring management’s risk management framework for cybersecurity on a regular basis.

IDACORP and Idaho Power include risks from cybersecurity threats, including from use of third-party service providers, as part of the companies' enterprise risk assessment process. The companies have utilized and continue to utilize recognized third-party cybersecurity standards such as those published by the Center for Internet Security and the U.S. National Institute of Standards and Technology in developing their risk management framework for cybersecurity, their cybersecurity processes, controls, and procedures, and risk identification. The companies engage with consultants and other third parties as necessary to design, enhance, and implement appropriate cybersecurity measures in seeking to mitigate risks from cybersecurity threats. As part of the companies' strategy to manage risks from cybersecurity threats with third-party service providers, the companies seek to include appropriate security clauses in their contracts with those providers, including incident reporting requirements.

A dedicated cybersecurity team lead by a cybersecurity manager oversees the assessment and management of risks from cybersecurity threats on a day-to-day basis at IDACORP and Idaho Power. The cybersecurity manager reports to Idaho Power's corporate security senior manager. The cybersecurity team has a range of expertise including architecture, forensics, cloud, incident response, auditing/logging, and software administration, with several industry-recognized certifications among the team, including Certified Information Systems Security Professional and Certified Information Security Manager.

The cybersecurity team monitors and reviews threat intelligence feeds from various sources, including security vendors and U.S. federal and state agencies, to determine potential risks to the companies' information and control systems. Additionally, the team utilizes a defense-in-depth approach to cybersecurity that provides layers of defenses and monitoring/alerting to which the team responds. The team also monitors the companies' third-party service providers for risks related to the confidentiality, availability, and integrity of the companies' data and services hosted through those third parties.

The companies have an established cybersecurity incident response plan to provide structure and guidance when responding to cybersecurity incidents. In appropriate cases, an incident response team is activated to lead the companies' response. The team is composed of individuals from the cybersecurity team and other departments within the companies with relevant expertise, as well as third-party contractors and vendors.

As of the date of this report, IDACORP and Idaho Power believe that no risks from known cybersecurity incidents have materially affected or are reasonably likely to materially affect IDACORP or Idaho Power, including their business strategy, results of operations, and financial condition. However, the companies can provide no assurance that there will not be cybersecurity threats or incidents in the future or that they will not materially affect the companies, including their business strategy, results of operations, or financial condition. For more information regarding the risks the companies face from cybersecurity threats, see Item 1A. “Risk Factors” included in this report.

ITEM 2. PROPERTIES
 
Idaho Power's properties consist of the physical assets necessary to support its utility operations, which include generation and battery storage, transmission, and distribution facilities, as well as coal assets that support one of its coal-fired generation plants.facilities. In addition to these physical assets, Idaho Power has rights-of-way and water rights that enable it to use its facilities. Idaho Power’s system is composed of 17 hydropower generating plants located in
36
Table of Contents
southern Idaho and eastern Oregon, three natural gas-fired plants in southern Idaho, and interests in two coal-fired steam electric generating plants located in Wyoming and Nevada. In October 2020, Idaho Power and co-owner Portland General Electric ceased coal-fired operations at their Boardman power plant, as planned. As of December 31, 2021,2023, the system also includes approximately 4,843 pole-miles4,762 linear miles of high-voltage transmission lines, 23 step-up transmission substations located at power plants, 21 transmission substations, 1011 switching stations, 30 mixed-use transmission and distribution substations, 187186 energized distribution substations (excluding mobile substations and dispatch centers), and approximately 28,570 pole-miles29,714 linear miles of distribution lines.

Idaho Power holds Federal Energy Regulatory Commission (FERC) licenses for alllines, and 131 MW of its hydropower projects that are subject to federal licensing. Relicensing of Idaho Power’s hydropower projects is discussed in Part II - Item 7 - "Management’s Discussion and Analysis of Financial Condition and Results of Operations – Regulatory Matters – Relicensing of Hydropower Projects" in this report.battery storage.

IDACORP's and Idaho Power's headquarters are located in Boise, Idaho. The corporate headquarters campus consists of approximately 305,741 square feet of owned office space. Excluding Idaho Power's power generation facilities and substations, Idaho Power owns an additional 1,129,2221,218,813 square feet of office, warehouse, and industrial space to support its operations in Idaho and Oregon.

Idaho Power owns all of its interests in principal plants and other important units of real property, except for portions of certain projects licensed under the Federal Power Act (FPA)FPA and reservoirs and other easements. Substantially all of Idaho Power’s property is subject to the lien of its Mortgage and Deed of Trust and the provisions of its project licenses. Idaho Power’s property is subject to minor defects common to properties of such size and character that it believes do not materially impair the value to, or the use by, Idaho Power of such properties. Idaho Power considers its properties to be well-maintained and in good operating condition.

Through Idaho Energy Resources Co., Idaho Power owns a one-third interest in Bridger Coal Company and coal leases near the Jim Bridger generating plant in Wyoming from which coal is mined and supplied to the plant. Ida-West Energy Company holds 50-percent interests in nine hydropower plants that have a total nameplate capacity of 44 MW. These plants are located in Idaho and California.

3637
Table of Contents                              
Idaho Power's hydropower projects and other owned and co-owned generating facilities and their nameplate capacities, as of the date of this report, are included in the table below.
ProjectProject
Nameplate Capacity (kW)(1)
License ExpirationProject
Nameplate Capacity (Kilowatt (kW))(1)
License Expiration
Hydropower Projects:Hydropower Projects:   Hydropower Projects:  
Properties Subject to Federal Licenses:   
Properties Subject to Federal Licenses:(2)
Properties Subject to Federal Licenses:(2)
  
Lower SalmonLower Salmon60,000 2034 Lower Salmon60,000 20342034 
BlissBliss75,038 2034 Bliss75,038 20342034 
Upper SalmonUpper Salmon34,500 2034 Upper Salmon34,500 20342034 
Shoshone FallsShoshone Falls14,729 2040 Shoshone Falls14,729 20402040 
CJ StrikeCJ Strike82,800 2034 CJ Strike82,800 20342034 
Upper Malad - Lower MaladUpper Malad - Lower Malad21,770 2035 Upper Malad - Lower Malad21,770 20352035 
Brownlee - Oxbow - Hells Canyon (Hells Canyon Complex)1,256,501 2005(2)
HCC: Brownlee, Oxbow, and Hells CanyonHCC: Brownlee, Oxbow, and Hells Canyon1,276,076 2005(3)
Swan FallsSwan Falls27,170 2042
American Falls
American Falls
American FallsAmerican Falls92,340 2025 92,340 20252025 
CascadeCascade12,420 2031 Cascade12,420 20312031 
MilnerMilner59,448 2038 Milner59,448 20382038 
Twin FallsTwin Falls52,898 2040 Twin Falls52,898 20402040 
Other Hydropower:Other Hydropower:   Other Hydropower:  
Clear Lake - Thousand SpringsClear Lake - Thousand Springs9,300   Clear Lake - Thousand Springs9,300    
Total HydropowerTotal Hydropower1,798,914   Total Hydropower1,818,489    
Steam and Other Generating Plants:Steam and Other Generating Plants:   Steam and Other Generating Plants:   
Jim Bridger (coal-fired)(3)
775,286   
North Valmy Unit 2 (coal-fired)(3)(4)
144,900   
Jim Bridger (coal-fired)(4)(5)
Jim Bridger (coal-fired)(4)(5)
775,286   
North Valmy Unit 2 (coal-fired)(4)(6)
North Valmy Unit 2 (coal-fired)(4)(6)
144,900   
Danskin (gas-fired)Danskin (gas-fired)270,900   Danskin (gas-fired)270,900    
Langley Gulch (gas-fired)Langley Gulch (gas-fired)318,453 
Bennett Mountain (gas-fired)Bennett Mountain (gas-fired)172,800 
Bennett Mountain (gas-fired)
Bennett Mountain (gas-fired)
Salmon (diesel-internal combustion)
Salmon (diesel-internal combustion)
Salmon (diesel-internal combustion)Salmon (diesel-internal combustion)5,000   5,000    
Total Steam and OtherTotal Steam and Other1,687,339   Total Steam and Other1,687,339    
Total GenerationTotal Generation3,486,253  Total Generation3,505,828    
(1) Actual generation capacity from a facility may be greater or less than the rated nameplate generation capacity.(2) Licensed on an annual basis while the application for a new multi-year license is pending.(3) Idaho Power’s ownership interests are one-third for Jim Bridger and 50 percent for North Valmy. Amounts shown represent Idaho Power’s share.(4) Pursuant to an agreement with NV Energy, Idaho Power's participation in coal-fired operations of North Valmy ended in December 2019 at unit 1 and is planned to end no later than the end of 2025 at unit 2.
(2) Idaho Power holds FERC licenses for all of its hydropower projects that are subject to federal licensing. Relicensing of Idaho Power’s hydropower projects is discussed in Part II - Item 7 - MD&A - "Regulatory Matters – Relicensing of Hydropower Projects" in this report.(2) Idaho Power holds FERC licenses for all of its hydropower projects that are subject to federal licensing. Relicensing of Idaho Power’s hydropower projects is discussed in Part II - Item 7 - MD&A - "Regulatory Matters – Relicensing of Hydropower Projects" in this report.
(3) Licensed on an annual basis while the application for a new multi-year license is pending.(3) Licensed on an annual basis while the application for a new multi-year license is pending.
(4) Idaho Power’s ownership interests are one-third for Jim Bridger and 50 percent for North Valmy. Amounts shown represent Idaho Power’s share.(4) Idaho Power’s ownership interests are one-third for Jim Bridger and 50 percent for North Valmy. Amounts shown represent Idaho Power’s share.
(5) Idaho Power's 2023 IRP identified a preferred resource portfolio and action plan that includes the conversion from coal generation to natural gas generation of two units at the Jim Bridger plant in 2024 and the remaining two units at the Jim Bridger plant in 2030.(5) Idaho Power's 2023 IRP identified a preferred resource portfolio and action plan that includes the conversion from coal generation to natural gas generation of two units at the Jim Bridger plant in 2024 and the remaining two units at the Jim Bridger plant in 2030.
(6) Pursuant to an agreement with NV Energy, Idaho Power's participation in coal-fired operations of North Valmy ended in December 2019 at unit 1 and is planned to end no later than the end of 2025 at unit 2. Idaho Power's 2023 IRP identified a preferred resource portfolio and action plan that includes the conversion of the two units at the North Valmy plant from coal generation to natural gas generation in 2026.(6) Pursuant to an agreement with NV Energy, Idaho Power's participation in coal-fired operations of North Valmy ended in December 2019 at unit 1 and is planned to end no later than the end of 2025 at unit 2. Idaho Power's 2023 IRP identified a preferred resource portfolio and action plan that includes the conversion of the two units at the North Valmy plant from coal generation to natural gas generation in 2026.

ITEM 3. LEGAL PROCEEDINGS
 
Refer to Note 1110 – “Contingencies” to the consolidated financial statements included in this report.

SEC regulations require IDACORP and Idaho Power to disclose certain information about proceedings arising under federal, state or local environmental provisions if the companies reasonably believe that such proceedings may result in monetary sanctions above a stated threshold. Pursuant to the SEC regulations, the companies use a threshold of $1 million or more for purposes of determining whether disclosure of any such proceedings is required.

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.

report, which is incorporated herein by reference.
3738
Table of Contents                              
PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES
 
IDACORP’s common stock, without par value, is traded on the New York Stock Exchange (NYSE) under the trading symbol "IDA". On February 11, 2022,9, 2024, there were 7,7477,127 holders of record of IDACORP common stock. The outstanding shares of Idaho Power’s common stock, $2.50 par value, are held by IDACORP and are not traded. IDACORP became the holding company of Idaho Power on October 1, 1998.

For information regarding IDACORP's dividend policy, see Part II - Item 7 - "Management’s Discussion and Analysis of Financial Condition and Results of OperationsMD&A - Liquidity"Liquidity and Capital Resources - Dividends" in this report. For information relating to restrictions on dividends, see Note 76 - "Common Stock" to the consolidated financial statements included in this report.

IDACORP did not repurchase any shares of its common stock during the fourth quarter of 2021.2023.

Performance Graph

The graph below shows a comparison of the five-year cumulative total shareholder return for IDACORP common stock, the S&P 500 Index, and the Edison Electric Institute (EEI)EEI Electric Utilities Index. The data assumes that $100 was invested on December 31, 2016,2018, with beginning-of-period weighting of the peer group indices (based on market capitalization) and monthly compounding of returns.
ida-20211231_g4.jpg1362
    Source: Bloomberg and EEI
201620172018201920202021
2018201820192020202120222023
IDACORPIDACORP$100.00 $116.43 $121.74 $143.27 $132.57 $161.01 
S&P 500S&P 500100.00 121.82 116.47 153.14 181.30 233.30 
EEI Electric Utilities IndexEEI Electric Utilities Index100.00 111.72 115.82 145.69 144.00 168.65 

The foregoing performance graph and data shall not be deemed “filed” as part of this Form 10-K for purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liabilities of that section and shall not be deemed incorporated by reference into any other filing of IDACORP or Idaho Power under the Securities Act of 1933 or the Securities Exchange Act,
38
Table of Contents
of 1934, except to the extent IDACORP or Idaho Power specifically incorporates it by reference into such filing.

39
Table of Contents
ITEM 7. 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)MD&A in this report, the general financial condition and results of operations for IDACORP and its subsidiaries and Idaho Power and its subsidiary are discussed. The discussion of IDACORP's and Idaho Power's general financial condition and results of operations for 20202022 compared with 20192021 can be found in their Annual Report on Form 10-K for the year ended December 31, 2020 (2020 Annual Report).2022. See Part II - Item 7 - “Management’s Discussion and Analysis of Financial Condition and Results of Operations”MD&A in the 2020 Annual Reportthat report for further information on the companies' prior period results of operations. While reading the MD&A, please refer to the accompanying consolidated financial statements of IDACORP and Idaho Power. Also refer to "Cautionary Note Regarding Forward-Looking Statements" and Part I - Item 1A - "Risk Factors" in this report for important information regarding forward-looking statements made in this MD&A and elsewhere in this report.

INTRODUCTION

IDACORP is a holding company 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),IPUC, OPUC, and Federal Energy Regulatory Commission (FERC).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 is the parent of Idaho Energy Resources Co. (IERCo),IERCo, a joint venturer in Bridger Coal Company (BCC),joint-owner of BCC, which mines and supplies coal to the Jim Bridger generating plant owned in part by Idaho Power. IDACORP’s other notable subsidiaries include IDACORP Financial Services, Inc. (IFS), 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).PURPA.

EXECUTIVE OVERVIEW

IDACORP is committed to its focus on competitive total returns and generating long-term value for shareholders. IDACORP’s business strategy emphasizes Idaho Power as IDACORP’s core business, since Idaho Power’s regulated electric utility operations are the primary driver of IDACORP’s operating results. This strategy is described in Part I, Item 1 - "Business - Business Strategy" of this report. Examples of IDACORP's and Idaho Power's achievements, notable events, milestones, and recognitions during 20212023 include:

•IDACORP achieved net income growth for a fourteenthsixteenth consecutive year;year. Idaho Power achieved a 9.4 percent return on year-end equity in the Idaho jurisdiction without the need to amortize additional ADITCs available under its Idaho regulatory mechanism, described in Note 3 – “Regulatory Matters” to the consolidated financial statements included in this report.
•IDACORP increasedIdaho Power continues to focus on timely recovery of costs and earning a reasonable return on investment. In December 2023, the IPUC approved a settlement stipulation publicly filed by Idaho Power, the Staff of the IPUC, and intervening parties (2023 Settlement Stipulation) related to the Idaho general rate case that Idaho Power had filed in June 2023. Also, in December 2023 Idaho Power filed a general rate case with the OPUC. The general rate case filings and 2023 Settlement Stipulation are described more fully in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report and in "Regulatory Matters" in this MD&A.
•Idaho Power's customer count grew 2.4 percent in 2023 and Idaho Power's MWh sales to retail customers in 2023 were the second highest in its history, only behind 2022.
•In 2023, Idaho Power’s reliability metrics continued to be among the best in company history, as Idaho Power provided uninterrupted service to its retail customers 99.97 percent of the time.
•In September 2023, Idaho Power filed its 2023 IRP with the IPUC and OPUC. The 2023 IRP preferred resource portfolio plans for a significant increase in energy and capacity resources over the next 20 years to meet growing demand, primarily solar, wind, and battery resource additions. In addition, the preferred resource portfolio includes conversions of multiple jointly-owned coal-fired generation units to natural gas-fired generation units. To support the resource additions, the preferred portfolio also includes the Boardman-to-Hemingway transmission line with an in-service date in 2026 and three Gateway West transmission line segments phased in with in-service dates from 2028 through 2040.
•In September 2023, IDACORP's board of directors approved a 5.1 percent increase in the regular quarterly cash dividend on IDACORP’s common stock dividend to $0.75from $0.79 per share from $0.71to $0.83 per share, as a part of a 150177 percent increase in quarterly dividends approved over the last tentwelve years. The increase keeps IDACORP within its current target payout ratio of between 60 and 70 percent of sustainable IDACORP earnings, annualizing the most recently declared quarterly dividend;
•Idaho Power's customer count grew 2.8 percent in 2021. On June 30, 2021, Idaho Power set a new all-time system peak demand of 3,751 megawatts (MW), 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 continued its strong safety performance in 2021, tying its previous record for lowest number of Occupational Safety and Health Administration (OSHA) recordable incidents in Idaho Power's history. In January 2022, in recognition of Idaho Power's nontraditional approach of combining psychological safety and behavioral safety with practical application of human performance principles, the Edison Electric Institute (EEI) presented Idaho Power with the inaugural Thomas F. Farrell, II Safety Leadership and Innovation Award; and
•In December 2021,March 2023, Idaho Power issued its 2021 Integrated Resource Plan (IRP) that contemplates no new fossil fuel resources forexecuted an agreement with the BPA to transfer BPA's 24 percent interest in the Boardman-to-Hemingway transmission line project to Idaho Power, bringing Idaho Power's power supply mix and plans for substantial renewable resource additions overinterest in the next 20 years. The 2021 IRP also includes the endproject to Idaho Power's participation in coal-fired generation facilities by the end of 2028, including the conversion of two coal-fired units at the Jim Bridger plant to natural gas in 2024 which facilitates Idaho Power's transition toward its "Clean Today, Cleaner Tomorrow.®" goal to provide Idaho Power's customers with 100 percent clean energy by 2045.
3940
Table of Contents                              

Coronavirus (COVID-19) Response and Impacts

45 percent. In response to the COVID-19 public health crisis, 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 public health crisis and to protect employees, customers, the general public, and Idaho Power's electrical system. Idaho Power's provision of electricity to customers through its power supply, transmission, and distribution operations, as of the date of this report, continues largely uninterrupted.

In March 2020, in consideration of COVID-19, Idaho Power temporarily suspended disconnections and late fees for late payment or non-payment. As approved by the IPUC in July 2020, Idaho Power resumed disconnections and accruing late fees for customers in its Idaho service area beginning in early August 2020. In recognition of the economic impact of the COVID-19 public health crisis, Idaho Power continues to carry a higher allowance for uncollectible receivables compared with historical levels. Idaho Power's allowance for estimated uncollectible receivables was $4.5 million at December 31, 2021, $4.8 million at December 31, 2020, and $1.4 million at December 31, 2019.

In 2020,June 2023, both the IPUC and OPUC issued orders granting Idaho Powergranted certificates of public convenience and necessity (CPCNs) related to the authority to defer unanticipated, emergency-related expenses due to COVID-19, net of any cost savings, for possible recovery through future rates. As of December 31, 2021, Idaho Power had recorded an immaterial regulatory asset for its estimate of unanticipated, emergency-related expenses, including higher bad debt expense, net of estimated savings.

In September 2021, the Presidential Administration issued an executive order announcing new U.S. Department of Labor’s OSHA requirements that all employers with more than 100 employees ensure their workforce is fully vaccinated or require any workers who remain unvaccinated to undergo weekly testing before coming to work. In January 2022, the Presidential Administration withdrew the OSHA requirements. If the requirements are reinstated or if there are new requirements imposed that are applicable to Idaho Power's workforce, vendors, or suppliers, Idaho Power is uncertain to what extent the requirements could disrupt the supply chain or result in Idaho Power losing skilled or specialized employees or limit Idaho Power’s ability to attract and retain skilled or specialized employees who are unwilling to obtain a vaccine or subject themselves to weekly testing or other new requirements. Idaho Power, based on discussions with employees, does believe that attrition of skilled workers could result from applicationconstruction of the mandate for COVID-19 vaccines and testing or other requirements to Idaho Power's workforce. If Idaho Power loses key portions of its skilled or specialized workforce, or significant supply chain disruptions occur, those events could adversely impact Idaho Power's ability to provide reliable service to its customers and its business and results of operations.

As of the date of this report, Idaho Power is uncertain how long the COVID-19 public health crisis will last and how significantly it will ultimately impact its business operations, results of operations, cash flows, financial condition, or capital resources. For a discussion of certain risks IDACORPBoardman-to-Hemingway transmission line, and Idaho Power are confrontingplans to begin construction in 2024.
•In April 2023, Idaho Power entered into a 20-year agreement to utilize the storage capacity from a 150-MW battery storage facility scheduled to be online in June 2025. Idaho Power intends for this capacity to supplement 304 MW of company-owned storage that it expects to be online by the end of 2025. In 2023, 131 MW of company-owned battery storage were installed.
•Idaho Power issued a formal RFP in April 2023, soliciting bids for new energy and capacity resources as a resultwell as energy that can be delivered via transmission, beginning in 2026. At the time of the public health crisis, see Part II - Item 1A - "Risk Factors"RFP issuance, Idaho Power’s long-range planning process had identified a potential need in this report.2026 and 2027 of approximately 350 MW of peak capacity, which could be met by approximately 1,100 MW of variable energy resources. RFP procurement decisions will be based on the most up-to-date energy and capacity need information. The RFP provides that a portion of these resources may be transmitted via the Boardman-to-Hemingway transmission line project, which Idaho Power plans to have in-service as early as late 2026. Idaho Power anticipates completing the RFP process in the first half of 2024.

Summary of 20212023 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 years ended December 31, 2021, 2020,2023, 2022, and 20192021 (in thousands, except earnings per share amounts):
Year Ended December 31,
Year Ended December 31,Year Ended December 31,
202120202019 202320222021
Idaho Power net incomeIdaho Power net income$243,225 $233,235 $224,437 
Net income attributable to IDACORP, Inc.Net income attributable to IDACORP, Inc.$245,550 $237,417 $232,854 
Average outstanding shares – diluted (000’s)Average outstanding shares – diluted (000’s)50,645 50,572 50,537 
IDACORP, Inc. earnings per diluted shareIDACORP, Inc. earnings per diluted share$4.85 $4.69 $4.61 

40
Table of Contents
The table below provides a reconciliation of net income attributable to IDACORP for the year ended December 31, 2021,2023, from the year ended December 31, 20202022 (items are in millions and are before tax unless otherwise noted):
Net income attributable to IDACORP, Inc. - December 31, 20202022$237.4259.0 
Increase (decrease) in Idaho Power net income:
Customer growth, net of associated power supply costs and power cost adjustment mechanisms16.015.7 
Usage per retail customer, net of associated power supply costs and power cost adjustment mechanisms13.4 (31.3)
Idaho FCA revenues15.1 
Retail revenues per MWh, net of associated power supply costs and power cost adjustment mechanisms(13.4)11.0 
Transmission wheeling-related revenues16.4 (0.2)
Other operations and maintenance (O&M)O&M expenses(9.2)(0.5)
Depreciation expense(25.3)
Other changes in operating revenues and expenses, net(1.8)1.7 
Increase in Idaho Power operating income prior to sharing mechanism21.4 
Provision for sharing with customers(0.6)
IncreaseDecrease in Idaho Power operating income20.8 (13.8)
Non-operating expense, net(3.1)4.7 
Income tax expense(7.7)11.0 
Total increase in Idaho Power net income10.01.9 
Other IDACORP changes (net of tax)(1.8)0.3 
Net income attributable to IDACORP, Inc. - December 31, 20212023$245.6261.2 
 
IDACORP's net income increased $8.2$2.2 million for 20212023 compared with 2020,2022, due primarily to higher net income at Idaho Power.

Idaho Power's customer growth of 2.82.4 percent added $16.0$15.7 million to Idaho Power's operating income in 2023 compared with 2020. Higher2022. Lower sales volumes on a per-customer basis increased operating income by $13.4 million in 2021 compared with 2020, due mostly to warmeramong all customer classes, but more significantly among residential and drier weather in the spring and early summer that caused irrigation customers to use more energy for irrigation pumps and residential customers to use more energy for cooling in 2021 compared with 2020. The increase in usage per residential customer from the spring and early summer was mostly offset by lower usage per residential customer from August through December 2021 compared with those same months in 2020 due to milder temperatures. Also, a return to more normal economic conditions for commercial and industrial customers in 2021 compared with 2020 increased sales volumes on a per-customer basis, as 2020 was affected by negative COVID-19-related business conditions.

The net decrease in retail revenues per megawatt-hour (MWh) reduced operating income by $13.4 million in 2021 compared with 2020, primarily due to higher power supply costs. During the summer 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 contributed to the negative variance in net retail revenues per MWh between the comparison periods. Also, Idaho Power decreased annual Idaho customer rates an estimated $3.9 million on January 1, 2021, and decreased annual Oregon customer rates an estimated $0.3 million on November 1, 2020, to reflect full depreciation of all Boardman power plant investments after ceasing coal-fired operations at the Boardman power plant in October 2020.

During 2021, transmission wheeling-related revenues increased $16.4 million compared with 2020, as the warmer and drier weather in the western United States in the spring and early summer, along with two new long-term wheeling agreements which began in April 2021, increased wheeling volumes. Colder winter weather in the southwest United States during the first quarter of 2021 also contributed to increased wheeling volumes in 2021 compared with 2020. In addition, Idaho Power's open access transmission tariff (OATT) rates increased approximately 10 percent during the period from October 1, 2020, to September 30, 2021, as compared with the rates in effect from October 1, 2019, to September 30, 2020. The rate increased an additional four percent on October 1, 2021.

Other O&M expenses increased $9.2 million in 2021 compared with 2020, primarily due to a return to more normal levels of purchased services and maintenance activity compared with 2020, which was affected by the COVID-19 public health crisis. Also, labor-related other O&M expenses increased slightly in 2021 compared with 2020.
41
Table of Contents                              
irrigation customers, decreased operating income by $31.3 million in 2023 compared with 2022. More moderate temperatures and greater precipitation in Idaho Power's service area during 2023, compared with 2022, led residential customers to use less energy per customer for cooling and heating and agricultural irrigation customers to use less energy per customer to operate irrigation pumps. The negative revenue impact of the decrease in sales volumes per residential and small commercial customer was partially offset by the FCA mechanism, which increased revenues in 2023 by $15.1 million compared with 2022.

In 2021, Idaho Power recorded $0.6 million as a provision against currentThe net increase in retail revenues to be refunded to customers through a future rate reduction, through the Idaho-jurisdictionper MWh, net of associated power supply costs and power cost adjustment (PCA) mechanism pursuantmechanisms, increased operating income by $11.0 million in 2023 compared with 2022. The net increase in retail revenues per MWh was primarily due to the June 1, 2022, rate increase for Idaho Power’s Idaho retail customers related to an order from the IPUC that 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 (Bridger Order).

Other O&M expenses were relatively flat in 2023 compared with 2022, as inflationary pressures on labor-related costs were mostly offset by lower expenses from scheduled cyclical plant maintenance projects, as well as the timing of regulatory deferrals and payment credits received related to a settlement stipulation approved byjointly-funded infrastructure project.

Depreciation expense increased $25.3 million due partially to an increase in plant-in-service. In addition, the IPUC as describedincrease was partially due to the impacts of the Bridger Order. The Bridger Order resulted in "RegulationIdaho Power recording the deferral of Rates and Cost Recovery" below.certain depreciation expense in the second quarter of 2022, reducing depreciation expense in that year.

Non-operating expense, net, increased $3.1decreased $4.7 million in 20212023 compared with 2020, primarily2022. AFUDC increased as the average construction work in progress balance was higher throughout 2023 compared with 2022. Also, interest and investment income increased due to increased costs of an Idaho Power postretirement medical plan that are not expected to recur.higher interest rates and higher average cash and cash equivalents balances. These increases were partially offset by higher interest expense on long-term debt and other liabilities in 2023 compared with 2022.

The $7.7$11.0 million increasedecrease in Idaho Power income tax expense in 20212023 compared with 20202022 was primarily due to greater 2021 pre-tax income and other plant-related income tax return adjustments.adjustments at Idaho Power.

20222024 Initiatives and Strategy

IDACORP’s strategy is focused on four areas: keeping employees safe and engaged, growing financial strength, improving Idaho Power's core business, and enhancing Idaho Power’s brand, and keeping employees safe and engaged.brand. IDACORP's board of directors hashave reviewed and affirmed IDACORP’s long-term strategy. In executing on these four strategic cornerstones, IDACORP seeks to balance the interests of shareowners, Idaho Power customers, employees, and other stakeholders. Idaho Power is committed to working for strong, sustainable financial results by continuing to safely provide reliable, affordable, clean energy to its customers from diversified generation resources.resources, including an increasingly clean portfolio of generation as Idaho Power works toward its “Clean Today. Cleaner Tomorrow.®” goal of 100% clean energy by 2045. More specific information on IDACORP’s strategy is included in Item 1 – “Business,” in this report.

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 include the following:

•Regulation of Rates and Cost Recovery; General Rate Case Filings: The prices that Idaho Power is authorized to charge for its electric and transmission service are 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 the prudent management of expenses and investments and on the timely recovery of its costs through filings with its regulators.

In December 2023, the IPUC approved the 2023 Settlement Stipulation between Idaho Power, the Staff of the IPUC, and intervening parties related to the Idaho general rate case filed by Idaho Power in June 2023. New tariff schedules resulting from the 2023 Settlement Stipulation are designed to increase annual Idaho-jurisdictional retail revenue by $54.7 million, or 4.25 percent, and became effective January 1, 2024. The $54.7 million of additional annual revenue is net of a PCA rate decrease of $168.3 million and a reduction to annual energy efficiency rider collection of $3.5 million, each of which was transferred into base rates. The 2023 Settlement Stipulation also included a 9.6
42
Table of Contents
percent return on equity and a 7.247 percent authorized rate of return based on a non-specified cost of debt and capital structure, applied to an Idaho-jurisdictional rate base of approximately $3.8 billion, excluding coal-related assets at the Jim Bridger plant and North Valmy plant which are recovered under separate regulatory mechanisms. Idaho Power also made a general rate case filing in Oregon in December 2023 and expects the full processing of that general rate case will take approximately ten months. The general rate case filings and the 2023 Settlement Stipulation are described more fully in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report and in "Regulatory Matters" in this MD&A. Several factors impacted Idaho Power’s need to file its general rate cases including the increase in depreciation expense from plant in service, the significant amounts of capital expenditures Idaho Power made since its last general rate case filed in 2011, the financing costs for capital expenditures in a higher interest-rate environment, and, to a lesser extent, inflationary pressures on other O&M expenses. Due to the continuing impact of many of these same factors and the effect of regulatory lag, on February 14, 2024, Idaho Power provided notice to the IPUC of its intent to file a general rate case or limited issue rate proceeding in Idaho on or after June 1, 2024.

•Rate Base Growth and Infrastructure Investment: The rates established by the IPUC, OPUC, and OPUCFERC 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 companyIdaho Power is undertaking a significant relicensing effort for the Hells Canyon Complex (HCC),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.proceeding, but the company incurs the cash requirements of constructing and the costs of financing those resources before they are in rates and customer revenues.

Existing and sustained growth in customers and peak demand for electricity will require Idaho Power to continue to enhance its power supply, transmission, and distribution infrastructure. Idaho Power's 2021 IRP indicates Idaho Power will 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 plans to acquire and own 120 MW of battery storage assets, 40MW of which would be interconnected to a planned 40 MW solar facility from which Idaho Power will purchase the output through a 20-year power purchase agreement signed in February 2022. The interconnected battery storage facility is expected to qualify for investment tax credits. To help address the capacity deficits projected for 2024 and 2025, Idaho Power issued a request for proposals in December 2021. Based on current estimates, Idaho Power expects it could invest over $400 million inits capital expenditures from 2022 through 2025 for resource additionson infrastructure investments in the next five years or more will be considerable as it works to help meet theaddress projected energy and capacity deficits noted above. 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 this report.deficits. 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
42
Table of Contents
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 prudent management of expenses and investments. Idaho Power has a regulatory settlement stipulation in Idaho that includes provisions for the accelerated amortization of certain tax credits to help achieve a minimum 9.4 percent 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 general rate case. The specific terms of the settlement stipulation are described in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report. 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 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 has made since its last general rate case filed in 2011, will increase and potentially accelerate Idaho Power’s need to file general rate cases. In Idaho, Idaho Power is required to file a notice of its intent to file a general rate case 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 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: 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. In 2021,2023, Idaho Power's customer count grew by 2.82.4 percent. Idaho Power set a new all-time system peak demandWhile recessionary or volatile economic conditions could slow the rate of 3,751 MW on June 30, 2021, exceedingcustomer growth in 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. near-term, Idaho Power expects its number of customers and, to continuea greater extent its load due to anticipated commercial and industrial customer growth, to increase in the foreseeable future.

Idaho Power also expectsfiled its most recent IRP with the IPUC and OPUC in September 2023. The 2023 IRP assumes a forecasted annual growth in retail MWh sales of 5.5 percent and a forecasted annual growth in peak-hour demand of 3.7 percent over the upcoming 5-year period. For more information on the 2023 IRP, refer to "Resource Planning" in Item 1 – "Business." Customer growth has contributed to increases in peak loads experienced in recent years. For example, Idaho Power's highest all-time winter peak demand of 2,719 MW occurred on January 16, 2024.Idaho Power believes that existing and sustained growth in customers, load, and peak demand for electricity, willalong with changes in the regional transmission markets that have constrained the availability of transmission outside Idaho Power’s service area to import energy during peak load periods, require that Idaho Power to continue to enhanincrease its investment in ce its capacity resources, transmission, and distribution infrastructure, includinginfrastructure. This includes the Boardman-to-Hemingway and Gateway West transmission projects. That growth has resultedprojects, along with other capacity, energy, and transmission resources. This includes those contemplated by the resource procurements described in the need for Idaho Power to procure additional new sources of energy"Liquidity and capacity to serve growing demand and to maintain system reliability, as noted above. Further, recent changesCapital Resources" 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 during peak load periods.this MD&A.

•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
43
Table of Contents
of those pumps. Idaho Power also has tiered rates and seasonal rates, which contribute to increased revenues during higher-load periods, most notably during the third quarter of each year when overall customer demand is highest. Much of the adverse or favorable impact of weather on sales of energy to residential and small commercial customers is mitigated through the Idaho Fixed Cost Adjustment (FCA)FCA mechanism, which is described in Note 3 - "Regulatory Matters" to the 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 decreases, Idaho Power must rely on more expensive generation sourcesresources 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.mechanisms, which lessen the potential earnings benefit or detriment of volatile hydrological conditions and their impact on overall power supply costs. For 2022, due to relatively low reservoir storage carryover combined with current and forecasted snowpack conditions,2024, Idaho Power expects generation from its hydropower resources to be in the range of 5.5 million to 7.5 million MWh, compared with 6.5 million MWh in 2023 and average total annual hydropower generation of approximately 7.77.6 million MWh over the last 30 years.

43
Table of Contents
•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, long-term power purchase agreements (including PURPA agreements), 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, andgeneration resource maintenance outages, wholesale energy market prices.prices, transmission availability, and the outcome of Idaho Power’s hedging programs. The Idaho and Oregon power cost adjustment mechanisms mitigate in large part the potential adverse earnings impacts to Idaho Power of fluctuations in power supply costs. However, collection from customers or return to customers of most of the difference between actual power supply costs compared with those included in retail rates is deferred to a subsequent period, which can affect Idaho Power’s operating cash flow and liquidity until those costs are recovered from or returned to customers.

•Regulatory and Environmental Compliance Costs:Costs; Coal Plant Retirements: 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. Energy industry regulators 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, 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 infor the next decade.foreseeable future. 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 North Valmy, Nevada (Valmy)(North Valmy plant), ceasing coal-fired operations at one unit in 2019. In 2021,2019 and planning to cease its participation in coal-fired operations at the IPUC acknowledged that Idaho Power'sremaining unit by year-end 2025 exit date from Valmy unit 2 is appropriate based on economics and reliability needs.2025. Idaho Power's jointly-owned coal plant in Boardman, Oregon, ceased operations as planned in October 2020. In June 2021, Idaho Power filed an application with2022, the IPUC requesting, among other things, authorizationapproved 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 status of Idaho Power's application is described2023 IRP identified a preferred resource portfolio and action plan that includes the conversion from coal to natural gas of two units at the Jim Bridger plant in 2024, the two units at the North Valmy plant in 2026, and the remaining two units at the Jim Bridger plant in 2030. For more fullyinformation on the 2023 IRP, refer to "Resource Planning" in the "Regulatory Matters" sectionItem 1 – "Business" of this MD&A.report.

•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
44
Table of Contents
ultimate terms of, and costs associated with, any resulting long-term licenses for the HCC or American Falls Facilities.hydroelectric facilities.

•Wildfire Mitigation Efforts: In recent years, the western United States has 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-dateto date the extent of catastrophic wildfires within its service area that have occurred in California Oregon, Colorado, and elsewhere in the western United States, Idaho Power is taking a proactive approach to wildfire threat in its service area.area and transmission corridors. Idaho Power has adopted a Wildfire Mitigation Plan (WMP)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; public safety power shutoffPSPS protocols; and evaluating the performance and effectiveness of the strategies identified in the WMP through metrics and monitoring. In June 2021,Idaho Power has a regulatory mechanism which allows the IPUC authorized Idaho Powercompany to defer, for future amortization, the Idaho jurisdictional share of actual incremental O&M expenses and depreciation expense of certain capital investments necessary to implement the WMP. The WMP case with the IPUCregulatory deferral is described in more detail in Note 3 -the "Regulatory Matters" to the consolidated financial statements included insection 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. In this analysis, the results for 20212023 are compared with 2020.
44
Table of Contents
2022.
 
The table below presents Idaho Power’s energy sales and supply (in thousands of MWh) for the last two years.years ended December 31.
Year Ended December 31,
20212020 20232022
Retail energy salesRetail energy sales15,406 14,828 
Wholesale energy salesWholesale energy sales600 1,197 
Energy sales bundled with renewable energy credits739 690 
Energy sales bundled with RECs
Total energy salesTotal energy sales16,745 16,715 
Hydropower generationHydropower generation5,382 6,967 
Coal generation2,981 3,719 
Natural gas and other generation2,765 2,109 
Coal-fired generation
Natural gas-fired and other generation
Total system generationTotal system generation11,128 12,795 
Purchased powerPurchased power6,823 5,072 
Line lossesLine losses(1,206)(1,152)
Total energy supplyTotal energy supply16,745 16,715 

For purposes of illustration, Boise, Idaho weather-related information for the last two years ended December 31 is presented in the table that follows.
Year Ended December 31,
20212020
Normal(2)
202320232022
Normal(2)
Heating degree-days(1)
Heating degree-days(1)
4,856 4,999 5,516 
Cooling degree-days(1)
Cooling degree-days(1)
1,393 1,087 941 
Precipitation (inches)Precipitation (inches)12.3 14.5 11.7 
(1) Heating and cooling degree-days are common measures used in the utility industry to analyze the demand for electricity and indicate when a customer would use electricity for heating and air conditioning. A degree-day measures how much the average daily temperature varies from 65 degrees. Each degree above 65 degrees is counted as one cooling degree-day, and each degree below 65 degrees is counted as one heating degree-day. While Boise, Idaho weather conditions are not necessarily representative of weather conditions throughout Idaho Power's service area, the greater Boise area has the majority of Idaho Power's customers.
(2) Normal heating degree-days and cooling degree-days elements are, by convention, the arithmetic mean of the elements computed over 30 consecutive years. The annual normal amounts are the sum of the 12 monthly normal amounts. These normal amounts are computed by the National Oceanic and Atmospheric Administration.

Sales Volume and Generation: In 2021, retail sales volumes increased 4 percent compared with the prior year, primarily due to growth in the number of Idaho Power customers and warmer and drier spring and early summer weather that caused customers to use more energy for cooling and irrigation. The number of Idaho Power customers grew by 2.8 percent in 2021. Less precipitation in Idaho Power's service area during the spring and early summer of 2021 compared with the same time period in 2020 led agricultural irrigation customers to use 6 percent more energy per customer to operate irrigation pumps during 2021 compared with 2020. During 2021, usage per commercial and industrial customer was approximately 3 percent higher compared with the prior year, due to a return to more normal economic activity compared with 2020, which was affected by negative COVID-19-related business conditions. Usage per residential customer was approximately 1 percent higher in 2021 than 2020, which was primarily due to weather variations that caused residential customers to use more energy for cooling in the spring and early summer, but less energy from August through December. Cooling degree-days in Boise, Idaho were 28 percent higher during 2021 compared with 2020 and 48 percent above normal. Also, heating degree-days were 3 percent lower during 2021 compared with 2020 and 12 percent lower than normal.

Wholesale energy sales volumes decreased 0.6 million MWh, or 50 percent, during 2021 compared with 2020, as lower system generation and higher retail sales volumes led to less energy available for opportunistic market sales.

Total system generation decreased 13 percent in 2021 compared with the prior year, due primarily to lower hydropower generation and coal-fired generation, partially offset by increased natural gas generation. Hydropower generation decreased 23 percent during 2021 compared with 2020, due primarily to lower reservoir storage carryover and weaker snowpack in the Snake River Basin. Coal-fired generation also decreased 20 percent during 2021, due to mostly to economic displacement by power purchased from the energy imbalance market in the western United States (Western EIM) and to a lesser extent due to the
45
Table of Contents                              
October 2020 closureSales Volume and Generation: In 2023, retail sales volumes decreased 2 percent compared with the prior year, primarily due to weather variations that caused lower usage per customer. Greater precipitation and more moderate temperatures in Idaho Power's service area during 2023 led agricultural irrigation customers to use less energy per customer to operate irrigation pumps and residential and commercial customers to use less energy per customer for cooling and heating purposes compared with 2022. The decrease in usage per customer was partially offset by customer growth, as the number of Idaho Power customers grew by 2.4 percent in 2023. For more information on the coal-firedchanges in sales volume, see the "Operating Revenues" section below in this MD&A.

Total system generation plantincreased 5 percent in Boardman, Oregon. Natural2023 compared with 2022, due primarily to higher natural gas generation increased 31 percent due mostly toand hydropower generation, partially offset by decreased coal-fired generation. For more information on the decreasechanges in hydropower and coal-fired generation.sales volume, see the "Operating Expenses" section below in this MD&A.

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 Cost Adjustment Mechanisms."

Operating Revenues

Retail Revenues: The tabletables below presentspresent Idaho Power’s retail revenues (in thousands), MWh sales (in thousands), and number of retail customers for the last two years.years ended December 31.
Year Ended December 31,
 20212020
Retail revenues:  
Residential (includes $34,835 and $34,409, respectively, related to the FCA(1))
$583,061 $547,404 
Commercial (includes $1,407 and $1,543, respectively, related to the FCA(1))
314,745 293,057 
Industrial195,214 181,258 
Irrigation168,664 154,791 
Provision for sharing(569)— 
Deferred revenue related to HCC relicensing AFUDC(2)
(8,780)(8,780)
Total retail revenues$1,252,335 $1,167,730 
Volume of Sales (MWh)  
Residential5,645 5,463 
Commercial4,164 4,009 
Industrial3,471 3,369 
Irrigation2,126 1,987 
Total retail MWh sales15,406 14,828 
Number of retail customers at year-end  
Residential505,774 491,229 
Commercial76,022 74,409 
Industrial125 126 
Irrigation21,832 21,594 
Total customers603,753 587,358 
 20232022
Retail revenues:  
Residential (includes $37,233 and $22,595, respectively, related to the FCA(1))
$684,649 $645,236 
Commercial (includes $1,338 and $922, respectively, related to the FCA(1))
378,330 347,970 
Industrial244,538 217,368 
Irrigation173,929 170,964 
Deferred revenue related to HCC relicensing AFUDC(2)
(8,780)(8,780)
Total retail revenues$1,472,666 $1,372,758 
(1) The FCA mechanism is an alternative revenue program 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)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 deferring revenue recognition of the amounts collected until the license is issued and the accumulated license costs approved for recovery are placed in service.

MWh SalesRetail Customers
2023202220232022
Residential5,903 6,056 531,885 518,490 
Commercial4,269 4,306 78,586 77,306 
Industrial3,538 3,510 132 128 
Irrigation1,805 1,950 22,333 22,071 
Total15,515 15,822 632,936 617,995 
Changes in rates, changes in customer demand, and changes in FCA mechanism revenues are the primary reasons for fluctuations in retail revenues from period to period. See "Regulatory Matters" in this MD&A for a list of rate changes implemented over the last two years. The primary influences on customer demand for electricity are weather, economic conditions, and energy efficiency. Extreme temperatures increase sales to customers who use electricity for cooling and heating, while mild 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 summer 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.

46
Table of Contents                              
Retail Revenues: Retail revenues increased $84.6$99.9 million in 20212023 compared with 2020.2022. The primary factors affecting retail revenues during the period were the following:

•Rates: Customer rates, excluding collections of amounts related to the power cost adjustment mechanisms, decreasedincreased retail revenues by $6.4$11.0 million in 20212023 compared with 2020.2022, due primarily to the June 1, 2022 rate increase for Idaho Power decreased annualPower’s Idaho customer rates an estimated $3.9 million on January 1, 2021, and decreased annual Oregon customer rates an estimated $0.3 million on November 1, 2020,retail customers related to reflect full depreciation of all Boardman power plant investments after ceasing coal-fired operations at the Boardman power plant in October 2020.Bridger Order. Customer rates also include adjustmentsthe collection from customers of amounts related to the PCA mechanism,power cost adjustment mechanisms, which increased revenues by $42.0$98.5 million in 20212023 compared with 2020.2022. The adjustments related to the Idaho-jurisdiction PCA mechanism in rates do not have a significant effect on operating income as a corresponding amount is recorded in expense in the same period.period it is collected through rates.

•Customers: Customer growth of 2.82.4 percent increased retail revenues by $22.0$26.7 million in 20212023 compared with 2020.2022.

•Usage: HigherDecreased usage (on a per customer basis), in all customer classes increaseddecreased retail revenues by $27.2$51.4 million during 20212023 compared with 2020. Less2022. Milder temperatures during 2023, compared with temperatures during 2022, led retail customers to use less energy per customer for cooling and heating. More precipitation in Idaho Power's service area during the spring and earlylate summer of 20212023, compared with the same time period in 2020of 2022, led agricultural irrigation customers to use 67 percent moreless energy per customer to operate irrigation pumps during 2021. A return to more normal economic conditions in 2021 for commercial and industrial customers increased usage by both customer classes approximately 3 percent on a per-customer basis, as 2020 was affected by negative COVID-19-related business conditions. Usage per residential customer was approximately 1 percent higher than 2020, which was primarily due to weather variations that caused residential customers to use more energy at home for cooling in the spring and early summer of 2021, compared with 2020, but less energy from August through December. Cooling2023. Heating degree-days in Boise, Idaho, were 28 percent higher during 2021 compared to 2020 and 48 percent above normal. Also, heating degree-days in that area were 313 percent lower during 20212023 compared to 2020with 2022, and 125 percent lower than normal. Also, cooling degree-days in Boise, Idaho, were 4 percent lower during 2023 compared with 2022 and 28 percent above normal.

•SharingIdaho FCA Revenues:: During 2021, 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 recorded $0.6through volume-based rates during the year. Lower usage (on a per customer basis) by residential and small commercial customers during 2023 increased the amount of FCA revenue accrued by $15.1 million, as a provision against current revenues to be refunded to customers through a future rate reduction. If approved, the rate reduction would be included in PCA rates beginning in Junecompared with 2022. Idaho Power did not record any provision for sharing in 2020. This revenue sharing arrangement, which requires Idaho Power to share with Idaho customers a portion of Idaho-jurisdiction earnings exceeding a 10.0 percent Idaho ROE, is related to the May 2018 Idaho Tax Reform Settlement Stipulation. The May 2018 Idaho Tax Reform Settlement Stipulation is described further in "Regulatory Matters" in this MD&A and Note 3 -"Regulatory Matters" to the consolidated financial statements included in this report.

Wholesale Energy Sales: Wholesale energy sales consist primarily of long-term sales contracts, opportunity sales of surplus system energy, and sales into the energy imbalance market in the western United States,EIM, and do not include derivative transactions. The table below presents Idaho Power’s wholesale energy sales for the last two years ended December 31 (in thousands, except for revenue per MWh amounts). 
Year Ended December 31,
20212020 20232022
Wholesale energy revenuesWholesale energy revenues$40,839 $33,656 
Wholesale MWh soldWholesale MWh sold600 1,197 
Wholesale energy revenues per MWhWholesale energy revenues per MWh$68.07 $28.12 

In 2021,2023, wholesale energy revenue increaseddecreased by $7.2$3.1 million, or 215 percent, compared with 2020,2022, as higher average wholesale energy pricessales volumes were more than offset a decreaseby lower wholesale market prices. The increase in wholesale energy volumes sold. Wholesalesold during 2023, was partially due to energy prices were higher comparedoriginally purchased under derivative forward contracts to be bundled with 2020 as extreme summer weather resultedRECs, but the energy was ultimately sold in higher demand and lower supply of energy to the wholesale marketsmarkets. Those sales increased wholesale energy revenues by $16.7 million in 2023, and a corresponding amount was recorded in purchased power on the region. Wholesaleconsolidated statements of income. The financial impacts of fluctuations in wholesale energy sales volumes decreased 50 percent in 2021 compared with 2020, as lower system generation and higher retail sales volumes led to less energy available for opportunistic market sales.

Transmission Wheeling-Related Revenues: Revenue related to transmission wheeling increased $16.4 million in 2021 compared with 2020, as warmer, drier spring and summer weather in the western United States, along with two new long-term wheeling agreements that began in April 2021, increased wheeling volumes. In addition,are largely mitigated by Idaho Power's OATT rates increased approximately 10 percent during the period from October 1, 2020, to September 30, 2021, as compared with the ratesIdaho and Oregon power cost adjustment mechanisms, which are described below in effect from October 1, 2019, to September 30, 2020. Also, Idaho Power's OATT rate increased 4 percent in October 2021. Refer to "Regulatory Matters""Power Cost Adjustment Mechanisms" in this MD&A for more information on Idaho Power's OATT rate.
47
Table of Contents
&A.

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 variances between expenditures and amounts collected through the riders are recorded as regulatory assets or liabilities. 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 December 31, 2021,2023, Idaho Power's energy efficiency rider balances were a $6.9$0.7 million regulatory assetliability in the Idaho jurisdiction and a $0.7$0.8 million regulatory assetliability in the Oregon jurisdiction. In December 2020, the IPUC authorized Idaho Power to increase the Idaho energy efficiency rider collection percentage from 2.75 percent to 3.1 percent, effective January 1, 2021.

47
Table of Contents
Operating Expenses

Purchased Power: The table below presents Idaho Power’s purchased power expenses and volumes for the last two years ended December 31 (in thousands, except for per MWh amounts). 
Year Ended December 31,
 20212020
Expense
PURPA contracts$199,517 $194,380 
Other purchased power (including wheeling)194,174 103,037 
Total purchased power expense$393,691 $297,417 
MWh purchased
PURPA contracts3,040 3,087 
Other purchased power3,783 1,985 
Total MWh purchased6,823 5,072 
Cost per MWh from PURPA contracts$65.63 $62.97 
Cost per MWh from other sources$51.33 $51.91 
 Weighted average - all sources$57.70 $58.64 

Idaho Power is required by federal law to purchase power from some PURPA generation projects at a specified price regardless of the then-current load demand or wholesale energy market prices. The intermittent, non-dispatchable nature of most PURPA generation increases the likelihood that Idaho Power will at times be required to reduce output from its lower-cost hydropower and fossil fuel-fired generation resources and may be required to sell its excess power in the wholesale power market at a significant loss. Although it was not the case in 2021, the other purchased power cost per MWh often exceeds the wholesale energy sales revenue per MWh because Idaho Power generally needs to purchase more power during heavy load periods than during light load periods, and conversely has less energy available for wholesale energy sales during heavy load periods than light load periods. Market energy prices are typically higher during heavy load periods than during light load periods. Also, in accordance with Idaho Power's energy risk management policy, Idaho Power may purchase or sell energy several months in advance of anticipated delivery. The regional energy market price is dynamic and additional energy transactions that Idaho Power makes at current market prices may be noticeably different than the advance transaction prices. Most of the non-PURPA purchased power and substantially all of the PURPA power purchase costs are recovered through base rates and Idaho Power's power cost adjustment mechanisms.
 20232022
Purchased power expense$501,531 $544,345 
MWh purchased7,027 7,178 
Average cost per MWh$71.37 $75.84 

Purchased power expense increased $96.3decreased $42.8 million, or 328 percent, in 20212023 compared with 2020.2022. The increase wasdecrease in purchased power expense in 2023 is primarily due to a 91 percent increaselower wholesale energy market prices as milder summer and winter weather resulted in MWhlower demand and lower fuel costs (natural gas and coal) in the wholesale markets in the region. For further information on purchased from sources other than PURPA contracts as power purchased from the Western EIM economically displaced coal-fired generation at greater volumes in 2021 compared with 2020.activities, see Part I, Item 1 – Utility Operations – "Power Supply – Purchased Power."

48
Table of Contents
Fuel Expense: The table below presents Idaho Power’s fuel expenses and thermal generation for the last two years ended December 31 (in thousands, except for per MWh amounts).
Year Ended December 31,
 20212020
Expense  
Coal$95,324 $119,678 
Natural gas(1)
85,226 53,062 
Total fuel expense$180,550 $172,740 
MWh generated  
Coal2,981 3,719 
Natural gas(1)
2,765 2,109 
Total MWh generated5,746 5,828 
Cost per MWh - Coal$31.98 $32.18 
Cost per MWh - Natural gas$30.82 $25.16 
Weighted average, all sources$31.42 $29.64 

Fuel ExpenseMWh GeneratedCost per MWh
 202320222023202220232022
Coal$95,499 $105,552 2,473 3,657 $38.62 $28.86 
Natural gas(1)
179,906 124,658 2,917 2,319 $61.68 $53.76 
Total/Weighted average, all$275,405 $230,210 5,390 5,976 $51.10 $38.52 
(1) Includes a negligible amount of expense and generation related to the Salmon diesel-fired generation plant.

The majority of the fuel for Idaho Power’s jointly-owned coal-fired plants is purchased through long-term contracts, including purchases from BCC, a one-third owned joint ventureinvestment of IERCo. The price of coal from BCC is subject to fluctuations in mine operating expenses, geologic conditions, and production levels. BCC supplies up to two-thirdsthe majority of the coal used by the Jim Bridger plant.plant and BCC does not have significant sales to third parties. 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 increased $7.8$45.2 million, or 520 percent, in 20212023 compared with 2020,2022, despite lower total thermal generation. The increase in fuel expense was primarily due to a 31 percent increase inhigher coal purchase prices and higher natural gas generation and a 22 percentmarket prices in 2023, which resulted in an increase in the average cost per MWh of coal and natural gas MWh generated primarily from highergeneration. The mix of Idaho Power's thermal generation between natural gas market prices. These increases were partially offsetand coal in 2023 compared with 2022 was affected by a decreasefluctuations in coal-fired generation due to economic displacement by power purchased from the Western EIM.natural gas prices and coal supply constraints.

Included in fuel expense are losses and gains on settled financial gas hedges entered into in accordance with Idaho Power's energy risk management policy. In 2021,2023, losses on financial gas hedges of $16.2 million increased natural gas fuel expense. In 2022, gains on financial gas hedges of $12.1$68.5 million reduced natural gas fuel expense, while in 2020, losses on financial gas hedges of $4.8 million increased natural gas fuel expense. Most of these realized hedging gainslosses and lossesgains are passed on to customers through the power cost adjustment mechanisms described below.

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 includes a cost or benefit sharing ratio that allocates the deviations in net power supply expenses between customers (95 percent) and Idaho Power (5 percent), with the exception of PURPA power purchases and demand response program incentives, which are allocated 100 percent to customers. The Idaho deferral period, or PCA year, runs from April 1 through March 31. Amounts deferred during the PCA year are primarily recovered or refunded during the subsequent June 1 through May 31 period. However, the IPUC directed Idaho Power to spread recovery of the March 31, 2023, PCA deferral
48
Table of Contents
balance over a two-year period from June 1, 2023, to May 31, 2025. Because of the power cost adjustment mechanisms, the primary financial impacts of power supply cost variations is that cash is paid out but recovery from customers does not occur until a future period, or cash that is collected is refunded to customers in a future period, resulting in fluctuations in operating cash flows from year to year.

49
Table of Contents
The table below presents the components of the Idaho and Oregon power cost adjustment mechanisms for the last two years ended December 31 (in thousands). 
Year Ended December 31,
 20212020
Power supply cost (deferral) accrual$(22,036)$16,763 
Amortization of prior year authorized balances(27,808)(50,471)
Total power cost adjustment expense$(49,844)$(33,708)
 20232022
Idaho power supply cost deferral$(66,728)$(116,994)
Oregon power supply cost accrual (deferral)1,169 (1,079)
Amortization of prior year authorized balances72,444 17,414 
Total power cost adjustment (income statement)$6,885 $(100,659)

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, 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. During 2021,2023, higher fuel costs partially offset by lower purchased power costsexpense led to higher actual power supply costs compared with the forecasted amount, which resulted in a significant increase in the amountdeferral of power supply costs deferred by the mechanism.costs. The amortization of the prior year’s balances represents the offset to the amounts being collected or refunded in the current power cost adjustment year that were deferred or accrued in the prior power cost adjustment year (the true-up component of the power cost adjustment mechanism).
Other Operations and Maintenance Expenses: Other O&M expenses increased $9.2$0.5 million or 3 percent, in 20212023 compared with 2020, primarily due2022, as inflationary pressures on labor-related costs were mostly offset by lower expenses from scheduled cyclical plant maintenance projects as well as the timing of regulatory deferrals and payment credits received related to a return to more normal levels of purchased services and maintenance costs compared with 2020, which was affected by the COVID-19 public health crisis. In 2020, the response to the COVID-19 public health crisis affected the availability and performance of some of Idaho Power's service providers, contractors and vendors, which resulted in lower other O&M expenses. Also, labor-related other O&M expenses increased slightly in 2021, compared with 2020.jointly funded infrastructure project.

Income Taxes

IDACORP's and Idaho Power's 20212023 income tax expense increased $8.2decreased $10.5 million and $7.7$11.0 million, respectively, when compared with 2020.2022. The increasesdecreases were primarily due to higher pre-tax earnings and other plant-related income tax return adjustments at Idaho Power. For additional information relating to IDACORP's and Idaho Power's income taxes, see Note 2 - “Income Taxes” to the consolidated financial statements included in this report.

LIQUIDITY AND CAPITAL RESOURCES
 
Overview

Idaho Power 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. Cash capital expenditures, excluding AFUDC and excluding net costs of removing assets from service, were $288$591 million in 20212023 and $299$419 million in 2020.2022. Idaho Power expects an increase in capital expenditures over the next several years, with estimated total capital expenditures of up to $2.8$4.4 billion over the period from 20222024 through 2026.2028.

Idaho Power funds its liquidity needs for capital expenditures through cash flows from operations, debt offerings, commercial paper markets, credit facilities, and capital contributions from IDACORP.

As of February 11, 2022,9, 2024, IDACORP's and Idaho Power's access to debt, equity, and credit arrangements included:

•their respective $100 million and $300$400 million revolving credit facilities (Credit Facilities);Credit Facilities;
•IDACORP's shelf registration statement filed with the U.S. Securities and Exchange Commission (SEC)SEC on May 17, 2019,16, 2022, which may be used for the issuance of debt securities and common stock;
49
Table of Contents
•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$280 million isremains available for issuance pursuant to state regulatory authority; and
•IDACORP's and Idaho Power's issuance of commercial paper, which may be issued up to an amount equal to the available credit capacity under their respective Credit Facilities.credit facilities; and
•IDACORP's forward sale agreements (FSA), which may be physically settled with common stock in exchange for net proceeds, which as of February 9, 2024, would be approximately $291 million.

50In March 2023, Idaho Power issued the following long-term debt with the proceeds being used for general corporate purposes, including repaying outstanding commercial paper and long-term debt and funding Idaho Power's capital projects:
Table
•$60 million of Contents5.06% first mortgage bonds, secured medium-term notes, Series N, maturing in March 2043;
•$62 million of 5.20% first mortgage bonds, secured medium-term notes, Series N, maturing in March 2053; and
•$400 million of 5.50% first mortgage bonds, secured medium-term notes, Series M, maturing in March 2053.

During March through May 2023, a portion of the proceeds from the March 2023 issuances was used to repay outstanding commercial paper, $150 million in principal amount from a March 2022 term loan agreement, and $75 million in principal amount of maturing 2.50% first mortgage bonds, Series I.

In September 2023, Idaho Power issued $350 million of 5.80% first mortgage bonds, secured medium-term notes, Series M, maturing in April 2054 with the proceeds used for general corporate purposes, including funding its capital projects.

In November 2023, IDACORP entered into FSAs in connection with a completed $299 million public offering of approximately 3.2 million shares of its common stock. IDACORP may settle the agreements at any time up to the maturity date of November 7, 2024. Depending on settlement timing, if IDACORP elects to physically settle by delivering shares of common stock, cash proceeds are expected to be approximately $290 million to $295 million. The proceeds are expected to be used for general corporate purposes, including funding Idaho Power's capital projects. For more detailed information about IDACORP's FSAs, see Note 6 - "Common Stock" to the consolidated financial statements included in this report.

IDACORP and Idaho Power monitor capital markets with a view toward opportunisticfavorable 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. In January 2024, IDACORP began using original issuances of shares for its dividend reinvestment and stock purchase plan and also intends to use original issuances of IDACORP shares for share purchases within Idaho Power's employee savings plan going forward. IDACORP may discontinue using original issuances of shares for its dividend reinvestment and stock purchase plan and/or the employee savings plan at any time.

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 and thereafter for the foreseeable future with a combination of existing cash, operating cash flows generated by Idaho Power's utility business, availability under existing Credit Facilities, andcredit facilities, access to commercial paper, short-term, and long-term debt markets.markets, and equity issuances.

IDACORP and Idaho Power generally seek to maintain capital structures of approximately 50 percent debt and 50 percent equity, maintainingequity. Maintaining this ratio influences IDACORP's and Idaho Power's debt and equity issuance decisions. As of December 31, 2021,2023, IDACORP's and Idaho Power's capital structures, as calculated for purposes of applicable debt covenants, were as follows:
IDACORPIdaho Power
IDACORPIDACORPIdaho Power
DebtDebt43%45%Debt50%51%
EquityEquity57%55%Equity50%49%

IDACORP and Idaho Power generally maintain their cash and cash equivalents in highly liquid investments, such as U.S. Treasury Bills, money market funds, and bank deposits. 

50
Table of Contents
Operating Cash Flows
 
IDACORP's and Idaho Power's principal sources of cash flows from operations are Idaho Power's sales of electricity and transmission capacity. Significant uses of cash flows from operations include the purchase of fuel and power, other operating expenses, interest, income taxes, and plan contributions. Operating cash flows can be significantly influenced by factors such as weather conditions, rates and the outcome of regulatory proceedings, and economic conditions. As fuel and purchased power are significant uses of cash, Idaho Power has regulatory mechanisms in place that provide for the deferral and recovery of the majority of the fluctuation in those costs. However, if actual costs rise above the level currently allowed in retail rates, deferral balances increase (reflected as a regulatory asset), negatively affecting operating cash flows until such time as those costs, with interest, are recovered from customers.
IDACORP’s and Idaho Power’s operating cash inflows in 20212023 were $363$267 million and $323$207 million, respectively, decreasesa decrease of $25$84 million and $30$174 million for IDACORP and Idaho Power, respectively, when compared with 2020.2022. With the exception of cash flows related to income taxes, IDACORP's operating cash flows are principally derived from operating cash flows from Idaho Power. Significant items that affected the companies' operating cash flows in 2021 relative to 20202023 when compared with 2022 were as follows:

•an $8 million and a $10$2 million increase in IDACORP and Idaho Power net income, respectively;
•changes in regulatory assets and liabilities, mostly related to the relative amounts of costs deferred and collected under the Idaho PCA, FCA, and energy efficiency program cost mechanisms,wildfire mitigation, increased operating cash inflows by $3$75 million;
•changes in deferred taxes and in taxes accrued and receivable combined to decreaseincrease operating cash flows for IDACORP and Idaho Power by $32 million and $38 million, respectively;
•contributions to pension and postretirement benefits plans decreased IDACORP and Idaho Power cash flows by $28$11 million;
•changes in distributions from equity-method investments, primarily related to IERCo, a wholly-owned subsidiary of Idaho Power, decreased IDACORP and Idaho Power cash flows by $9 million and $37$10 million, respectively; and
•changes in working capital balances due primarily to timing, including fluctuations in accounts receivable and unbilled revenues, materials, supplies, and fuel stock, accounts and wages payable, and other current assets and other current liabilities, as follows:
◦the timing of collections of accounts receivable balances decreased operating cash flows by $6 million for IDACORP and $3 million for Idaho Power;
◦timing of accounts payable paymentsunbilled revenues increased operating cash flows by $18$64 million for IDACORP and $63 million for Idaho Power;
◦the changes in other current assetsmaterials, supplies, and fuel stock decreased operating cash flows by $13$42 million for IDACORP and Idaho Power, which was primarily due to an increase in material and supply inventory offset by the timing of purchases and consumption of coal at Idaho Power's jointly-owned coal-fired generating plants, offset partiallyplants;
◦the changes in accounts and wages payable decreased operating cash flows by fluctuations$194 million for IDACORP and $288 million for Idaho Power, which was primarily due to an increase in the balance in accrued unbilled revenues;power supply costs and associated timing of payments, and includes a $94 million difference between IDACORP and Idaho Power related to intercompany estimated tax payments; and
◦the changes in other currentassets and liabilities, which includes non-incentive compensation,accrued paid time off and leave, customer deposits, accrued interest, and other miscellaneous liabilities, decreased operating cash flows by $5$12 million for IDACORP and Idaho Power.

51
Table of Contents
Investing Cash Flows

Investing activities consist primarily of capital expenditures related to new construction of, and improvements to, Idaho Power’s power supply, transmission, and distribution facilities. IDACORP's and Idaho Power's capital expenditures, including AFUDC,net investing cash outflows for 2023 were $300$590 million and $311$582 million, in 2021respectively. Investing cash outflows for 2023 and 2020, respectively. These capital expenditures2022 were primarily for construction of utility infrastructure needed to address Idaho Power’s customer growth, aging plant and equipment, customer growth, and environmental and regulatory compliance requirements. As discussedSignificant items and transactions that affected investing cash flows in "Capital Requirements" below, Idaho Power received $62023 and 2022 included:

•$611 million and $3$433 million, respectively, of additions to property, plant and equipment, including $112 million spent on battery storage projects, and at December 31, 2023, $31 million was accrued in 2021accounts payable on their consolidated balance sheets related to battery payments;
•$27 million and 2020,$18 million, respectively, from Boardman-to-Hemingway project joint permitting participants relating to a portion of thesethe permitting expenditures.expenditures;

•
Idaho Power's investing cash inflows include $14$3 million and $1 million return of investment from IERCO, a wholly-owned subsidiary of Idaho Power, in 2021 and 2020, respectively.

Idaho Power has a Rabbi trust designated to provide funding for obligations of its nonqualified defined benefit plans. In the Rabbi trust, Idaho Power purchased equity securities of $16 million in 2021 and $33 million in 2020. Idaho Power received $11 million and $26 million of proceeds in the Rabbi trust from the sales of equity securities in 2021 and 2020, respectively.

During 2021, IDACORP's investing cash inflows also included $50 million of proceeds from maturities of short-term investments. During 2021 and 2020, IDACORP's investing cash outflows included $25 million of purchases of short-term investments in addition to $15 million and $14$10 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 and accelerated tax depreciation benefits.benefits at IDACORP;
51
Table of Contents
•$8 million in 2022 related to return of investment from IERCo, a wholly-owned subsidiary of Idaho Power;
•$11 million and $44 million in purchases of equity securities, respectively, $2 million and $31 million in purchases of held-to-maturity securities, respectively, and $9 million and $64 million in sales of equity securities, respectively, held in a rabbi trust, which is designated to provide funding for obligations related to Idaho Power's SMSP; and
•$25 million in 2022 of both purchases and sales of short-term investments at IDACORP.

Financing Cash Flows

Financing activities provide supplemental cash for both day-to-day operations and capital requirements as needed. IDACORP's and Idaho Power's net financing cash inflows for 2023 were $473 million and $538 million, respectively. Idaho Power funds liquidity needs for capital investment, working capital, managing commodity price risk, dividends, and other financial commitments through cash flows from operations, debt offerings, commercial paper markets, credit facilities, and capital contributions from IDACORP. IDACORP funds its cash requirements, such as payment of taxes, payment of dividends, capital contributions to Idaho Power, and non-utility operating expenses allocated to IDACORP, through cash flows from operations, commercial paper markets, sales of common stock, and credit facilities. The following are significantSignificant items and transactions that affected financing cash flows in 2021 and 2020:2023 were as follows:

•in April 2020,2023, Idaho Power issued $230$872 million in aggregate principal amount of first mortgage bonds, secured medium-term notes, as described above in this "Liquidity and Capital Resources" section;
•in 2023, Idaho Power repaid the entire $150 million in principal amount of its 4.20 percent first mortgage bonds, secured
mediuma March 2022 term notes, Series K, maturing March 1, 2048. The bonds were issued at a reoffer yield of 3.422 percent,
which resulted in a net premium of 13.0 percentloan agreement and net proceeds to Idaho Power of $260 million;
•in June 2020, Idaho Power issued $80 million in principal amount of its 1.90 percent first mortgage bonds, secured
medium term notes, Series L, maturing July 15, 2030;
•in July 2020, Idaho Power redeemed, prior to maturity, $75 million in principal amount of 2.95 percent first mortgage
bonds, medium-term notes, Series H due in April 2022. In accordance with the redemption provisions of the notes, the
redemption included Idaho Power's payment of a make-whole premium to the holders of the redeemed notes in the
aggregate amount of $3 million;
•in August 2020, Idaho Power redeemed $100 million in principal amount of 3.40 percent first mortgage bonds, duesecured medium-term notes at maturity, each as described above in this "Liquidity and Capital Resources" section; and
November 2020; and
•IDACORP and Idaho Power paid dividends of approximately $146$164 million and $138$102 million in 2021 and 2020,2023, respectively.

Financing Programs and Available Liquidity

IDACORP Equity Programs:IDACORP hasissued no current plans to issue equity securities in 2023 other than under its equity compensation plans. As described elsewhere in this MD&A, IDACORP has significant planned capital expenditures in the near-term, and the company plans to issue approximately 3.2 million shares of common stock during 2022.2024 under the FSAs. See Note 6 - "Common Stock" to the consolidated financial statements included in this report. Depending on market conditions, its financial and regulatory strategy, and other factors, IDACORP could determine to issue additional equity securities in 2024.

Term Loan Credit Agreement: In March 2022, Idaho Power entered into a term loan credit agreement (Term Loan Facility). The Term Loan Facility was a two-year senior unsecured term loan facility in the aggregate principal amount of $150 million. On March 31, 2023, Idaho Power repaid $100 million and on May 17, 2023, repaid $50 million principal amount to fully repay the Term Loan Facility.

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).WPSC. In AprilMay 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. FollowingAt December 31, 2023, $280 million remains available for debt issuance under the June 2020regulatory orders. In January 2024, Idaho Power submitted applications to the IPUC, OPUC, and WPSC requesting authorization to issue and sell from time to time up to $1.2 billion in aggregate principal amount of debt securities and first mortgage bonds, which if approved will replace the $280 million remaining on the 2022 orders. For more detailed information about Idaho Power First Mortgage Bonds, see Note 5 - "Long-term Debt" to the consolidated financial statements included in this report.

In December 2022, Idaho Power entered into a Bond Purchase Agreement with certain institutional purchasers, relating to the sale by the Idaho Power of $170 million in aggregate principal amount of first mortgage bonds, secured medium-term notes, Series N (Series N Notes). Also in December 2022, Idaho Power entered into the Fifty-second Supplemental Indenture, dated December 20, 2022, to the Indenture (Fifty-second Supplemental Indenture). The Fifty-second Supplemental Indenture provides for, among other items, the issuance of Series L medium-term notesN Notes pursuant to the Indenture. The Series N Notes consist of four tranches of bonds, due in 2032, 2042, 2043, and 2053, respectively. The first two tranches were issued on December 22, 2022, and the April 2020 issuancethird and fourth tranches were issued on March 8, 2023, each under the Indenture. Idaho Power used the proceeds of the sale of the Series N Notes for general corporate purposes, primarily related to the construction of a battery storage project. At December 31, 2023, $170 million in principal amount of Series K medium-term notes described above, $190 million of debt securities remains available for issuance underN Notes had been issued and was outstanding. For more detailed information about the orders. Authority fromSeries N Notes, see Note 5 - "Long-term Debt" to the IPUC is effective through May 31,consolidated financial statements included in this report.
52
Table of Contents                              
2022, subject to extension upon request to the IPUC. The OPUC's and WPSC's orders do not impose a time limitation for issuances, but the OPUC order does impose a number of other conditions, including a requirement that the interest rates for the debt securities or first mortgage bonds fall within either (a) designated spreads over comparable U.S. Treasury rates or (b) a maximum all-in interest rate limit of seven percent.

In May 2019, 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 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, 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 aggregate principal amount of first
mortgage bonds, secured medium term notes, Series L (Series L 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, Idaho Power
entered into the Forty-ninth Supplemental Indenture, dated effective as of June 5, 2020, to the Indenture (Forty-ninth
Supplemental Indenture). The Forty-ninth Supplemental Indenture provides for, among other items the issuance of up to
$500 million in aggregate principal amount of Series L 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 December 31, 2021, was limited to approximately $534 million. Idaho Power may increase the $2.5 billion limit on the maximum amount of first mortgage bonds outstanding by filing a supplemental indenture with the trustee as provided in the Indenture of Mortgage and Deed of Trust. Separately, the Indenture also limits the amount of additional first mortgage bonds that Idaho Power may issue to the sum of (a) the principal amount of retired first mortgage bonds and (b) 60 percent of total unfunded property additions, as defined in the Indenture. As of December 31, 2021, Idaho Power could issue approximately $2.1 billion of additional first mortgage bonds based on retired first mortgage bonds and total unfunded property additions.

IDACORP and Idaho Power Credit Facilities (Credit Facilities): In December 2023, IDACORP and Idaho Power entered into Credit Agreements for $100 million and $400 million Credit Facilities, respectively. These facilities replaced IDACORP's and Idaho Power's existing credit agreements, dated November 18, 2022, as amended. The IDACORP Credit Facility, which may be used for general corporate purposes, and commercial paper backup, consists of a revolving line of credit not to exceed the aggregate principal amount at any one time outstanding of $100 million, including swingline loans in an aggregate principal amount at any time outstanding not to exceed $10 million, and letters of credit in an aggregate principleprincipal amount at any time outstanding not to exceed $50 million. The Idaho Power Credit Facility, which may be used for general corporate purpose and commercial paper backup,purposes, consists of a revolving line of credit, through the issuance of loans and standby letters of credit, not to exceed the aggregate principleprincipal amount at any one time outstanding of $300$400 million, including swingline loans in an aggregate principal amount at any time outstanding not to exceed $30$50 million, and letters of credit in an aggregate principal amount at any time outstanding not to exceed $50 million. IDACORP and Idaho Power have the right to request an increase in the aggregate principal amount of the facilities to $150 million and $450$600 million, respectively, in each case subject to certain conditions.

The IDACORP and Idaho Power Credit Facilities have similar terms and conditions. The interest rates for any borrowings under the facilities are based on either (1) a floating rate that is equal to the highest of the prime rate, federal funds rate plus 0.5 percent, or London interbank offered rate (LIBOR) Market Index rateAdjusted Term SOFR plus 1.0 percent, or 1.0 percent, or (2) the LIBOR Market Index rate,Adjusted Term SOFR, plus, in each case an applicable margin, provided that the federal funds rate and LIBOR rateAdjusted Term SOFR will not be less than zero. The Secured Overnight Financing Rate (SOFR) plus a defined benchmark adjustment would replace the LIBOR Market Index rate during any period in which the LIBOR rate is unavailable or unascertainable.0.0 percent. If during any period both the LIBOR and SOFR rates arerate is unavailable or unascertainable, an alternate benchmark rate selected by the administrative agent and the borrower would apply. The applicable margin is based on IDACORP's or Idaho Power's, as applicable, senior unsecured long-term indebtedness credit rating by rating agencies, as set forth on a schedule to the credit agreements. Under their respective credit facilities,Credit Facilities, the companies pay a facility fee on the commitment based on the respective company's credit rating for senior unsecured long-term debt securities. In December 2021,debt. Both the IDACORP and Idaho Power amended the Credit Facilities to extendmature on December 8, 2028, and each contains the termination dates of each facility to December 6, 2025, and provided additional information on potential alternatives, successors or replacement rates for LIBOR in the event it is no longer available as of the date of borrowing, among other things. While the Credit Facilities provide for a maturity date of December 6, 2025, the credit agreements grant IDACORP and Idaho Power the rightrights to request up to two-one-yeartwo one-year extensions, subject to certain conditions.

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,
53
Table of Contents
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 December 31, 2021,2023, the leverage ratios for IDACORP and Idaho Power were 4350 percent and 4551 percent, respectively. IDACORP's and Idaho Power's ability to utilize the credit facilitiestheir respective Credit Facilities is conditioned upon their continued compliance with the leverage ratio covenants included in the credit facilities.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 December 31, 2021,2023, IDACORP and Idaho Power believe they were in compliance with all facility covenants. Further,of their respective Credit Facility covenants and, as of the date of this report, IDACORP and Idaho Power do not believe they will be in violation or breach of their respective debtsuch covenants during 2022.2024.

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

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

Without additional
53
Table of Contents
In November and December 2023, Idaho Power obtained approval from the IPUC, the OPUC, and the WPSC the aggregate amount offor unsecured short-term borrowings by Idaho Power at any one time outstanding may not to exceed $450 million. Idaho Power has obtained approval of the state public utility commissions of Idaho, Oregon, and Wyoming for the issuance of short-term borrowings$600 million through December 2026.2030, subject to certain requirements under the order.

IDACORP and Idaho Power Commercial Paper: IDACORP and Idaho Power have commercial paper programs under which they issue unsecured commercial paper notes up to a maximum aggregate amount outstanding at any time not to exceed the available capacity under their respective credit facilities,Credit Facilities, described above. IDACORP's and Idaho Power's credit facilitiesCredit Facilities are available to the companies to support borrowings under their commercial paper programs. The commercial paper issuances are used to provide an additional financing source for the companies' short-term liquidity needs. The maturities of the commercial paper issuances will vary, but may not exceed 270 days from the date of issue. Individual instruments carry a fixed rate during their respective terms, although the interest rates are reflective of current market conditions, subjecting the companies to fluctuations in interest rates.

Available Short-Term Borrowing Liquidity

The following table outlines available short-term borrowing liquidity as of the dates specified (in thousands):
December 31, 2021December 31, 2020 December 31, 2023December 31, 2022
IDACORP(2)
Idaho Power
IDACORP(2)
Idaho Power
IDACORP(2)
Idaho Power
IDACORP(2)
Idaho Power
Revolving credit facilityRevolving credit facility$100,000 $300,000 $100,000 $300,000 
Commercial paper outstandingCommercial paper outstanding— — — — 
Identified for other use(1)
Identified for other use(1)
— (24,245)— (24,245)
Net balance availableNet 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 were unable to sell the bonds to third parties.
(1) 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 were unable to sell the bonds to third parties.
(1) 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 were unable to sell the bonds to third parties.
(1) 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 were unable to sell the bonds to third parties.
(2) Holding company only.(2) Holding company only.(2) Holding company only.

At February 9, 2024, IDACORP and Idaho Power had no short term commercial paper outstanding during the years ended December 31, 2021 and 2020. At February 11, 2022, neither IDACORP nor Idaho Power had loans outstanding under their credit facilitiesrespective revolving Credit Facilities and neitherno commercial paper outstanding. The table below presents additional information about short-term commercial paper borrowing during the year ended December 31 (in thousands).
 20232022
 
IDACORP(1)
Idaho Power
IDACORP(1)
Idaho Power
Commercial Paper:
Period end:
Amount outstanding$— $— $— $— 
Weighted average interest rate— %— %— %— %
Daily average amount outstanding during the period$— $9,201 $— $— 
Weighted average interest rate during the period— %4.94 %— %— %
Maximum month-end balance$— $110,000 $— $— 
(1) Holding company only.

54
Table of Contents                              
had commercial paper outstanding.

Impact of Credit Ratings on Liquidity and Collateral Obligations
 
IDACORP’s and Idaho Power’s access to capital markets, including the commercial paper market, and their respective financing costs in those markets, depends in part on their respective credit ratings. The following table outlines the ratings of Idaho Power’s and IDACORP’s securities, and the ratings outlook, by Moody’s Investors ServiceMoody's and Standard & Poor’s Ratings Services as of the date of this report:
Moody'sStandard & Poor's
IDACORPIdaho PowerIDACORPIdaho Power
Moody's Investors Service:
Rating OutlookNegativeStableStableNegativeStableStable
Long-Term Issuer RatingRating/CorporateBaa2Baa1BBBA3BBB
First Mortgage BondsNoneA2A1
Senior Secured DebtNoneA2A1NoneA-
Commercial PaperPaper/Short-TermP-2P-2
Standard & Poor's Rating Services:
Corporate Credit RatingBBBBBB
Rating OutlookStableStable
Short-Term RatingA-2A-2
Senior Secured DebtNoneA-

These security ratings reflect the views of the ratings agencies. An explanation of the significance of these ratings may be obtained from each rating agency. Such ratings are not a recommendation to buy, sell, or hold securities. There have been no changes to IDACORP's or Idaho Power's ratings by Standard & Poor’s Ratings Services (S&P) or Moody’s Investors Service (Moody's) from those included in the 2020 Annual Report. However, anyAny 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, Moody's rating outlook for IDACORP and Idaho Power were modified to negative, from stable, due to Moody's perception of the companies' financial profile relative to its A-rated peers. Moody's rating outlook indicated that it expected that IDACORP and Idaho Power would not take any material actions to improve their cash flows over the following 12-18 months. 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, the companies’ credit ratings would nonetheless remain investment grade and the companies do not believe it would have a material impact on their liquidity nor access to debt capital. Moody’s credit ratings of Baa3 and above are considered to be investment grade, or prime, ratings. Each rating agency has its own methodology for assigning ratings and, accordingly, each rating should be evaluated independently of any other rating.

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 December 31, 2021, Idaho Power had no performance assurance collateral posted. Should Idaho Power experience a reductioncounterparties, which are discussed further 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,Part II - Item 7A "Quantitative and counterparties to derivative instruments and other forward contracts could request immediate payment or demand immediate ongoing full daily collateralization on derivative instruments and contractsQualitative Disclosures About Market Risk" included in net liability positions. Based upon Idaho Power’s current energy and fuel portfolio and market conditions as of December 31, 2021, the amount of additional collateral that could be requested upon a downgrade to below investment grade is approximately $25.7 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.this report.

Capital Requirements
 
Idaho Power's cash capital expenditures, excluding AFUDC, were $288$591 million during the year ended December 31, 2021.2023. The cash expenditure amount excludes net costs of removing assets from service. The table below presents Idaho Power's estimated accrual-basis additions to electricproperty, plant, and equipment for 20222024 through 20262028 (in millions of dollars). The amounts in the table exclude AFUDC but include net costs of removing assets from service that Idaho Power expects would be eligible to be included in rate base in future rate case proceedings. However, givenGiven the uncertainty associated with the timing of infrastructure projects and associated expenditures, actual expenditures and their timing could deviate substantially from those set forth in the table. The timing and amount of actual constructed projects and capital expenditures could be significantly affected by Idaho Power’s ability to timely obtain labor
55
Table of Contents
or materials at reasonable costs, supply chain disruptions and delays, regulatory determinations, inflationary pressures, macroeconomic conditions, or other issues. For future resources that Idaho Power is currently planning to own, if Idaho Power were to enter into power purchase arrangements instead of owningissues, including those resources it would decrease Idaho Power's expected capital expenditures.described below.

 202220232024-2026
Expected capital expenditures (excluding AFUDC)$480-500$690-715$1,450-1,550
 202420252026-2028
Expected capital expenditures (excluding AFUDC)$925-975$850-950$2,000-2,500

Infrastructure Projects: A significant portion of expected capital expenditures included in the five-year forecast above relate to a large number of relatively small projects as Idaho Power continues to add to its system to accommodate growth and maintain reliability and operational effectiveness. These projects involve significant capital expenditures.expenditures in the aggregate. Examples of anticipated system enhancements planned for 20222024 through 20262028 and estimated costs include the following:

•$40-140-$70250 million per year for construction and replacement of transmission lines and stations other than the Boardman-to-Hemingway and Gateway West projects;
•$125-130-$170175 million per year for construction and replacement of distribution lines and stations, including replacement of underground distribution cables;
•$10-$8050 million per year for ongoing improvements and replacements at thermal plants;
•$70-80-$110150 million per year for hydropower plant improvement programs, including relicensing costs; and
•$50-60-$75 million per year for general plant improvements, such as land and buildings, vehicles, information technology, and communication equipment.

Other Major Infrastructure Projects: Idaho Power has recently completed or is engaged in the development of a number of significant projects and has entered into arrangements with third parties for joint development of infrastructure projects. The most notable projects are described below.
55
Table of Contents

Resource Additions to Address Projected Energy and Capacity Deficits: As noted previously, Idaho Power's existing and sustained growth in customers, load, and peak demand for electricity, along with transmission constraints, and Idaho Power’s planned exit from coal-fired generation, will also requirehas created the need for Idaho Power to acquire significant generation, transmission, and storage resources to meet energy and capacity needs over the next several years. Idaho Power's 2021 IRP indicates 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 infrom 2023 through 2025, Idaho Power plansentered into contracts to acquirepurchase, own, and own 120operate 304 MW of battery storage assets 40MWwith expected useful lives of which would be interconnectedapproximately 20 years, entered into a 20-year agreement to a planned 40 MW solar facility from which Idaho Power will purchase the output throughstorage capacity from a 20-year power purchase agreement signed in February 2022. The interconnected150-MW battery storage facility, is expected to qualifyand also entered into three power purchase agreements for investment tax credits. To help address the capacity deficits projected for 2024combined 340 MW output of planned third-party solar facilities with 20- and 2025,25-year terms. As described in “Regulatory Matters” of this MD&A, Idaho Power issued a request for proposals in December 2021. Based on current estimates,plans to sell the output of two of these solar power purchase agreements totaling 240 MW exclusively to two large industrial customers under agreements modeled after Idaho Power expects it could invest over $400Power’s Clean Energy Your Way program. The capital requirements table above includes capital expenditures of more than $220 million in capital expenditures from 2022the years 2024 through 2025 for resource additions to help meet theaddress projected energy and capacity deficits noted above.in those years. To help address the additional capacity deficits projected for 2026 through 2027, Idaho Power has issued an RFP for additional resources. The table above does not currently include any amounts for possible company-owned resources from the RFP to address projected deficits in 2026 or 2027. Depending on factors such as RFP results, the timing of project in-service dates, estimated load and resource balances and customer growth, the nature and quantity of resources owned versus acquired under power purchase agreements or similar agreements, and the outcome of regulatory proceedings, actual expenditures and their timing could deviate substantially from Idaho Power's expected expenditures.

Boardman-to-Hemingway Transmission Line:The Boardman-to-Hemingway line, a proposedplanned 300-mile, high-voltage transmission project between a substation near Boardman, Oregon, and the Hemingway substation near Boise, Idaho, wouldis expected to provide transmission service to meet future resource needs. In January 2012,Material procurement and construction subcontract bid events are in progress. As a result of delays in issuing Notices to Proceed from state and federal agencies and obtaining right-of-way grants, Idaho Power entered intoexpects construction will begin in 2024. Given the status of ongoing activities and the construction period, Idaho Power expects the in-service date for the transmission line will be no earlier than late 2026.

Until recently, Idaho Power had a joint funding agreement with PacifiCorp and the Bonneville Power Administration (BPA)BPA to pursue permitting of the project. The joint funding agreement provided thatproject, with Idaho Power'sPower having an approximate 21 percent interest, BPA having an approximate 24 percent interest, and PacifiCorp having an approximate 55 percent interest in the permitting phase of the project. In March 2023, BPA, PacifiCorp, and Idaho Power signed various agreements to facilitate certain asset transfers and other coordination efforts among the parties as the transmission line moves toward construction. In particular, an agreement between Idaho Power and BPA transferred BPA’s total interest in the project would beto Idaho Power, increasing Idaho Power's interest to approximately 21 percent. Total cost estimates45 percent, and provided that Idaho Power will deliver long-term transmission service to BPA's customers across southern Idaho. The agreement also required BPA to make a $10 million security payment to Idaho Power. On Idaho Power's consolidated balance sheet, the agreement increased construction work in progress by $31 million for the acquired permitting interest, cash and cash equivalents by $10 million for the additional security payment, and other non-current liabilities by $41 million for Idaho Power's obligation to pay for the permitting interest and to return the security deposit to BPA. Payments to BPA for the permitting interest are expected to be made over a 15-year period beginning 10 years after energization of the transmission line project, are between $1.0 billion and $1.2 billion,while the security deposit is due to be returned to BPA upon energization.

Idaho Power has spent approximately $215 million, including Idaho Power's AFUDC.

Approximately $125 million, including AFUDC, has been expended on the Boardman-to-Hemingway project through December 31, 2021.2023. Pursuant to the terms of the joint funding arrangements, Idaho Power has received $81$124 million in reimbursement as of December 31, 2021,2023, from project co-participants for their share of costs. Ascosts (including $31 million related to BPA's share, which was transferred to Idaho Power in March 2023 as part of the date of this report, no material co-participant reimbursementsagreement described above) and continues to receive reimbursement as costs are outstanding. Joint permitting participants areincurred. PacifiCorp is obligated to reimburse Idaho Power for theirits 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. In June 2023, Idaho Power and PacifiCorp executed a construction funding agreement and filed it with the FERC. The agreement became fully effective in September 2023.

The permitting phase of the Boardman-to-Hemingway project iswas subject to federal review and approval by various federal agencies. Federal agency records of decision have been received and all lawsuits challenging the U.S. Bureaufederal rights-of-way have been resolved. In the separate State of Land Management (BLM),Oregon permitting process, the U.S. Forest Service, thestate's Energy Facility Siting Council (EFSC) approved Idaho Power's site certificate in September 2022. The Oregon Department of Energy subsequently issued a final order and site certificate. Idaho Power is pursuing multiple amendments to the Navy,site certificate to accommodate route changes 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.enhance constructability. In September 2019,2023, EFSC approved Idaho Power's first amendment request. One party filed in Union County Circuit Court contesting the DepartmentEFSC’s approval of the Navy issuedfirst amendment, which Idaho Power is seeking to remove to the appropriate venue to expedite review. Idaho Power submitted its record of decision authorizing the project to cross approximately seven miles of Department of the Navy lands.preliminary request for a second amendment in June 2023,
56
Table of Contents                              
In November 2019, third parties filed a lawsuit inwhich remains pending. During the federal district courtsecond quarter of Oregon challenging2023, the BLMIPUC, OPUC, and U.S. Forest Service recordsWPSC granted Idaho Power and PacifiCorp their respective CPCNs related to the construction of decision for the Boardman-to-Hemingway project on several grounds. In August 2021, the federal district court of Oregon dismissed the third-party lawsuits challenging the records of decision for the Boardman-to-Hemingway project and the third parties did not file to appeal that decision by the deadline in October 2021.project.

In the separate State of Oregon permitting process, the Oregon Department of Energy (ODOE) issued a Proposed Order in July 2020 that recommends approval ofTotal cost estimates for the project to the state's Energy Facility Siting Council (EFSC). The project permit is actively undergoing the EFSC administrative process,are between $1.5 billion and Idaho Power currently expects the EFSC to issue a final order in the second half of 2022.

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. In January 2022, the participants executed a 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$1.7 billion, including Idaho Power's interest to approximately 45 percent, and Idaho Power would deliver transmission service to BPA's customers across Southern Idaho.

AFUDC. The capital requirements table above includes approximately $380$550 million of Idaho Power's share of estimated costs (excluding AFUDC) related to the remaining permitting phase, of the project (excluding AFUDC), and the costs related to design, material procurement, and construction phases of the project. The preliminary estimates of Idaho Power’s share ofActual construction costs could significantly change as the construction timeline nearsdiffer from Idaho Power's estimates based upon Idaho Power’s or its contractors ability to timely obtain labor or materials at reasonable costs, supply chain disruptions and as the project participants further align on future cost estimates.

In July 2021, Idaho Power awarded contracts for detailed design, geotechnical investigation, land surveying, and right-of-way option acquisition; and work commenced in the third quarter of 2021. Given 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.delays, inflationary pressures, macroeconomic conditions, or other issues.

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 $48$60 million, including Idaho Power's AFUDC, for its share of the permitting phase of the project through December 31, 2021.2023. 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$900 million and $450 million,$1.1 billion, including AFUDC. Idaho Power's AFUDC. The estimated cost range is based on assumptions about Idaho Power participation levels in the construction of certain project segments and any changes in those assumptions or in Idaho Power's actual participation could affect future estimates and actual project costs. The capital requirements table above includes approximately $425 million of Idaho Power's share of ongoing expendituresestimated costs (excluding AFUDC) for the permitting phase of the project (excluding AFUDC) is included in the capital requirements table above. Idaho Power's share of potentialand early construction costs, are excluded from the capital requirements table above because the timing ofbased on Idaho Power's current estimate that it may commence construction of applicable segments during that time period. Actual construction costs could differ from Idaho Power's portionestimates based upon the ability of the project is uncertain.Idaho Power, PacificCorp, or their respective contractors to timely obtain labor or materials at reasonable costs, supply chain disruptions and delays, inflationary pressures, macroeconomic conditions, or other issues.

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. In late 2020, PacifiCorp recently constructedcompleted construction and commissioned a 140-mile segment of theirits portion of the project in Wyoming. In March 2023, PacifiCorp initiated the pre-construction phase of 620 miles of 500-kV transmission line from the Populus substation near Downey, Idaho, to the Hemingway substation near Boise, Idaho. Idaho Power and PacifiCorp continue to coordinate the timing of next steps to best meet customer and system needs.needs including potentially modifying the ownership structure of a few segments of the project.

Hells Canyon Complex Relicensing: The HCC, located on the Snake River where it forms the border between Idaho and Oregon, provides approximately 70 percent of Idaho Power's hydropower generating nameplate capacity and 36 percent of its total generating nameplate capacity. Idaho Power has been engaged in the process of obtaining from the FERC a new long-term license for the HCC.HCC from the FERC. The past and anticipated future costs associated with obtaining a new long-term license for the HCC are significant.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 $460 million (including AFUDC) for the HCC, Idaho Power's largest hydropower complex and a major relicensing effort, were included in construction work in progress at December 31, 2023. As of the date of this report, the IPUC has authorized Idaho Power to include in its Idaho jurisdiction rates approximately $8.8 million annually of AFUDC relating to the HCC relicensing project. Collecting these amounts currently will reduce future collections when the HCC relicensing costs are approved for recovery in base rates. As of December 31, 2023, Idaho Power's regulatory liability for collection of AFUDC relating to the HCC was $229 million.

As of the date of this report, Idaho Power believes issuance of a new HCC license by the FERC will be in 2025 or thereafter. 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 a new license. As of the date of this report, Idaho Power estimates that the annual costs it will incur to obtain a new long-term license for the HCC, including AFUDC but excluding costs expected to be incurred for complying with the license after issuance, are likely to range from $30$35 million to $40$45 million until issuance of the license. The FERC could issue the license as early as 2023, but as of the date of this report Idaho Power believes issuance is more likely in 2024 or thereafter. Upon issuance of a long-term license, Idaho Power expects that the annual capital expenditures and operating and maintenance expenses associated with compliance with the terms and conditions of the long-term license could also be substantial. Idaho Power intends to seek recovery of those relicensing and compliance costs in rates through the regulatory process. In December 2016, Idaho Power filed an application with the IPUC requesting a determination that Idaho Power's expenditures of $220.8 million through year-end 2015 on relicensing of the HCC were prudently incurred, and thus eligible for future inclusion in retail rates in a future rate proceeding. In April 2018, the IPUC issued an order approving a settlement stipulation signed by Idaho Power, the IPUC staff, and a third-party intervenor
57
Table of Contents                              
IPUC staff, and a third-party intervenor recognizing that a total of $216.5 million in expenditures were reasonably incurred, and therefore should be eligible for inclusion in customer rates at a later date.

Environmental Regulation Costs: Idaho Power anticipates that it will continue to incur significant expenditures for its compliance with environmental regulations related to the operation of its hydropower and thermal generation facilities. In addition, Idaho Power expects it will continue to incur significant expenditures for its hydropower relicensing efforts. The near-term cost estimates for environmental matters are summarized in Part I, Item 1 - "Business - Environmental Regulation and Costs" of this report. The capital portion of these amounts is included in the Capital Requirements table above but does not include costs related to possible changes in current or new environmental laws or regulations and enforcement policies that may be enacted in response to issues such as climate change and emissions from coal-fired and gas-fired generation plants.

Long-Term Resource Planning:The IPUC and OPUC require that Idaho Power prepare biennially an IRP. The IRP seeks to forecast Idaho Power's loads and resources for a 20-year period, analyzes potential supply-side, demand-side, and transmission options, and identifies potential near-term, mid-term, and long-term actions. Idaho Power filed its most recent IRP with the IPUC and OPUC in 2021. Idaho Power's 2021 IRP identified a preferred resource portfolio and action plan, which included the addition of a 120-MW solar resource in late 2022, the conversion from coal to natural gas of two units at the Jim Bridger plant in 2024, the end to Idaho Power's participation in coal-fired operations at the North Valmy plant unit 2 in 2025, the completion of the Boardman-to-Hemingway transmission line in 2026, and an end to Idaho Power's participation in the remaining two coal-fired units at the Jim Bridger plant by the end of 2028. The 2021 IRP preferred resource portfolio and action plan also includes a need to acquire significant generation and storage resources to meet energy and capacity needs. Including the resources noted above, over the next 20 years the IRP plans for the addition of 1,685 MW of storage capacity, 1,405 MW of solar capacity, 700 MW of wind capacity, 500 MW of transmission capacity, and 400 MW of capacity from demand response. As noted in the 2021 IRP, there is uncertainty surrounding the resource sufficiency estimates and project completion dates, including uncertainty around the timing and extent of third-party development of renewable resources, fuel commodity prices, the actual completion date of the Boardman-to-Hemingway transmission project, and the economics and logistics of coal-fired plant conversions and retirements. These uncertainties, as well as others, may result in changes to the desirability of the preferred portfolio and adjustments to the timing and nature of anticipated and actual actions in the 2021 IRP. As of the date of this report, proceedings relating to the 2021 IRP are pending at the IPUC and OPUC. Additional information2023. Information on Idaho Power's 20212023 IRP is included in Part I, Item 1 - "Business - Resource Planning" in this report.

Defined Benefit Pension Plan Contributions and Recovery

Idaho Power contributed $48 million in 2023 and $40 million in 2022 to its defined benefit pension plan in each of 2021 and 2020.plan. Idaho Power estimates that it has no minimum required contribution to be made during 2022.2024. Depending on market conditions and cash flow considerations, Idaho Power could contribute up to $40$30 million to the pension plan during 2022.2024. 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 to mitigate the cost of being in an underfunded position. Beyond 2022,2024, Idaho Power expects continuing significant contribution obligationscontributions under the pension plan.plan could be significant. Refer to Note 1211 – “Benefit Plans” to the consolidated financial statements included in this report for information relating to those obligations.

Idaho Power defers its Idaho-jurisdiction pension expense as a regulatory asset until recovered from Idaho customers. At December 31, 20212023 and 2020,2022, Idaho Power's deferral balance associated with the Idaho jurisdiction was $234$255 million and $201$250 million, respectively. Deferred pension costs are amortized to expense to match the revenues received when contributions are recovered through rates. Idaho Power only records a carrying charge on the unrecovered balance of cash contributions. TheIn December 2023, the IPUC has authorized Idaho Power to recoverincrease its annual recovery and amortize $17 millionamortization of deferred pension costs annually, andin 2024 from $17 million to $35 million annually. Idaho Power has applied $68 million against the deferred amount under its Idaho sharing mechanisms since 2011. The primary impact of pension contributions is on the timing of cash flows, as cost recovery lags behind the timing of contributions. Additional information on the regulatory assets related to Idaho Power's pension and postretirement programs can be found in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.

Contractual Obligations

IDACORP’s and Idaho Power’s contractual cash obligations as of December 31, 2021,2023, include long-term debt, interest payments, purchase obligations, pension and post-retirement benefit plans, and other long-term liabilities specific to IDACORP, most of which are discussed throughout this MD&A. Refer to Note 109 – “Commitments” to the consolidated financial statements included in this report for additional information relating to purchase obligations and other long-term liabilities.
58
Table of Contents

Dividends
 
The amount and timing of dividends paid on IDACORP’s common stock are within the discretion of IDACORP’s board of directors. IDACORP's board of directors reviews the dividend rate periodically to determine its appropriateness in light of IDACORP’s current and long-term financial position and results of operations, capital requirements, rating agency considerations, contractual and regulatory restrictions, legislative and regulatory developments affecting the electric utility industry in general and Idaho Power in particular, competitive conditions, and any other factors the board of directors deems relevant. The ability of IDACORP to pay dividends on its common stock is generally dependent upon dividends paid to it by its subsidiaries, primarily Idaho Power.

IDACORP has a dividend policy that provides for a target long-term dividend payout ratio of between 60 percent and 70 percent of sustainable IDACORP earnings, with the flexibility to achieve that payout ratio over time and to adjust the payout ratio or to deviate from the target payout ratio from time to time based on the various factors that drive IDACORP's board of
58
Table of Contents
directors' dividend decisions. Notwithstanding the dividend policy adopted by IDACORP's board of directors, the dividends IDACORP pays remain in the discretion of the board of directors who, when evaluating the dividend amount, will continue to take into account the factors above, among others. In September of 20212023 and 2020,2022, IDACORP's board of directors voted to increase the quarterly dividend to $0.75$0.83 per share and $0.71$0.79 per share of IDACORP common stock, respectively. IDACORP's dividends during 20212023 were 59.462.3 percent of actual 20212023 earnings.

For additional information relating to IDACORP and Idaho Power dividends, including restrictions on IDACORP’s and Idaho Power’s payment of dividends, see Note 76 – “Common Stock” to the consolidated financial statements included in this report.

Contingencies and Proceedings

IDACORP and Idaho Power are involved in a number of litigation, alternative dispute resolution, and administrative proceedings, and are subject to claims and legal actions arising in the ordinary course of business that could affect their future results of operations and financial condition. In many instances IDACORP and Idaho Power are unable to predict the outcomes of the matters or estimate the impact the proceedings may have on their financial positions, results of operations, or cash flows.

Idaho Power is also actively monitoring various environmental regulations that may have a significant impact on its future operations. Given uncertainties regarding the outcome, timing, and compliance plans for these environmental matters, Idaho Power is unable to determine the financial impact of potential new regulations but does believe that future capital investment for infrastructure and modifications to its electric generating facilities to comply with these regulations could be significant.

Off-Balance Sheet Arrangements

IDACORP’s and Idaho PowerPower’s off-balance sheet arrangements as of December 31, 2023, include guarantees itsof Idaho Power's 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 (WDEQ), was $51.6 million at December 31, 2021, representing IERCo's one-third share of BCC's total reclamation obligation of $154.7 million. BCC has a reclamation trust fund set aside and specifically for the purpose of paying these reclamation costs. At December 31, 2021, the value of the reclamation trust fund totaled $211.2 million. During 2021, the reclamation trust fund made $21.1 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 madeSee Note 9 – “Commitments” to the Jim Bridger plant. Because of the existence of the fund and the abilityconsolidated financial statements included in this report for additional information relating to apply a per-ton surcharge, the estimated fair value of this guarantee is minimal.off-balance sheet arrangements.

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 (FPA),FPA, 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,
59
Table of Contents
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 develops its regulatory filings taking into consideration short-term and long-term needs for rate relief and several other factors that can affect the structure and timing of those filings. These factors include in-service dates of major capital investments, the timing and magnitude of changes in major revenue and expense items, and customer growth rates, as well as other factors. In recognition of Idaho Power's most recentPower’s current and anticipated significant infrastructure investments, including those that are intended to help meet projected near-term capacity deficits, Idaho Power filed a general rate casescase in Idaho in June 2023. The 2023 Settlement Stipulation was filed for that rate case in October 2023, and Oregon were filed during 2011, and in 2012, large single-issue rate cases for the Langley Gulch power plant resulted inIPUC approved the resetting of base2023 Settlement Stipulation on December 28, 2023, with rates in both Idaho and Oregon.effective January 1, 2024. Idaho Power also resetfiled a general rate case in Oregon on December 15, 2023. With the large amount of ongoing investments and the associated regulatory lag in cost recovery, on February 14, 2024, Idaho Power provided notice to the IPUC of its base-rate power supply expensesintent to file a general rate case or limited issue rate proceeding 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 cases subsequent to 2014.on or after June 1, 2024.

Between general rate cases, Idaho Power relies upon customer growth, a fixed cost adjustmentFCA mechanism, power cost adjustment mechanisms, WMP cost deferrals, project-specific cases, 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. 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 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 has made since its last general rate case filed in 2011, will increase and potentially accelerate Idaho Power’s need to file general rate cases.

59
Table of Contents
Notable Retail Rate Changes in Idaho and Oregon

The table below presents notable rate changes during 20212023 and 20202022 that affected Idaho Power's results for the periods or that will likely affect future periods. Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report also provides a description of regulatory mechanisms and associated orders of the IPUC and OPUC, and should be read in conjunction with the discussion of regulatory matters in this MD&A. The table does not include the changes to rates effective January 1, 2024, resulting from the 2023 Settlement Stipulation.
DescriptionEffective Date
Estimated Annualized Rate Impact (millions)(1)
20212023 Idaho PCA6/1/20212023$39105 
20212023 Idaho FCA6/1/202120233 (10)
2022 Idaho PCA6/1/202295 
2022 Idaho FCA6/1/2022(3)
Idaho Boardman plant closureBridger rate base adjustment and recovery1/1/2021(4)
2020 Idaho PCA6/1/202020225919 
2020 Idaho FCA6/1/20201 
Oregon North Valmy plant Exit Framework Settlement Stipulation1/1/2020(3)
(1) The annual amount collected or refunded in rates is typically not recovered or refunded on a linear basis (i.e., 1/12th per month), and is instead recovered or refunded in proportion to retail sales volumes. The rate changes for the Idaho PCA and FCA are applicable only for one-year periods and represent the net change to the deferral balance from the prior year's filing.filing, as well as a forecast component for the PCA.

Idaho and Oregon General Rate Cases

Effective January 1, 2012, Idaho Power implemented new Idaho base rates resulting from the regulatory settlement of a general rate case filing Idaho Power made in 2011. In the general rate case,
As noted above, on December 28, 2023, the IPUC approved the 2023 Settlement Stipulation in connection with Idaho Power's general rate case. The 2023 Settlement Stipulation provides for revised tariff schedules designed to increase annual Idaho-jurisdictional retail revenue by $54.7 million, or 4.25 percent, effective January 1, 2024, net of an Idaho-jurisdiction PCA rate decrease of $168.3 million and a settlement stipulation that providedreduction to annual energy efficiency rider collection of $3.5 million, each of which was transferred into base rates. The 2023 Settlement Stipulation also provides for an overall 7.86a 9.6 percent return on equity and a 7.247 percent authorized rate of return based on a non-specified cost of debt and capital structure, applied to an Idaho-jurisdictionIdaho-jurisdictional rate base of approximately $2.36$3.8 billion. The settlement stipulation resultedFor more information on the Idaho general rate case and related 2023 Settlement Stipulation, see Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.

At December 31, 2023, Idaho Power estimates that it had $86 million of deferred credits for future use under the ADITC and Revenue Sharing mechanism. Under the modified ADITC and Revenue Sharing mechanism, Idaho Power may seek approval from the IPUC to replenish the total amount of additional ADITC it is permitted to amortize and if there are no remaining amounts of additional ADITC authorized to be amortized, the remainder of the revenue sharing provisions would not be applicable until additional ADITC is replenished.

In December 2023, Idaho Power filed a $34.0 million overall increase in Idaho Power's annual Idaho-jurisdictional basegeneral rate revenues. Neithercase with the IPUC's order nor the settlement stipulation specified an authorized rate of return on equity.

EffectiveOPUC. Previously, effective March 1, 2012, Idaho Power implemented new Oregon base rates resulting from its receipt of an order from the OPUC approving a settlement stipulation in its general rate case proceedings that provided for a $1.8 million base rate revenue increase, a rate of return on equity of 9.9 percent, and an overall rate of return of 7.757 percent in the Oregon jurisdiction.
Idaho and Oregon base rates were subsequently adjusted again in 2012 in connection with Idaho Power's completion of the Langley Gulch power plant. In June 2012, the IPUC issued an order approving a $58.1 million increase in annual Idaho-jurisdiction base rate revenues, effective July 1, 2012, for inclusion of the investment and associated costs of the plant in rates.
60
Table of Contents
The order also provided for a $335.9 million increase in Idaho rate base. In September 2012, the OPUC issued an order approving a $3.0 million increase in annual Oregon jurisdiction base rate revenues, effective October 1, 2012, for inclusion of the investment and associated costs of the plant in Oregon rates. Additionally, in October 2020, the OPUC approved an increase in Oregon customer rates of $0.4 million annually associated with amortization of deferred Langley Gulch power plant revenue requirement variances, effective November 1, 2020, through October 31, 2024.

Other Notable Regulatory Matters

October 2014 Idaho Earnings Support and Sharing Settlement Stipulation: In October 2014, the IPUC issued an order approving an extension, with modifications, of the terms of a December 2011 Idaho settlement stipulation that allowed Idaho Power to, in certain circumstances, amortize additional accumulated deferred investment tax credits (ADITC) if Idaho Power's actual Idaho ROE was less than 9.5 percent, to help achieve a 9.5 percent Idaho ROE for the applicable year (October 2014 Idaho Earnings Support and Sharing Settlement Stipulation). Under the October 2014 Idaho Earnings Support and Sharing Settlement Stipulation, when Idaho Power's actual calendar-year Idaho ROE exceeded 10.0 percent, Idaho Power was required to share a portion of its calendar-year Idaho-jurisdiction earnings with Idaho customers for the period from 2015 through 2019. The more specific terms and conditions of the October 2014 Idaho Earnings Support and Sharing Settlement Stipulation are described in Note 3 - "Regulatory Matters - Notable Idaho Regulatory Matters" to the consolidated financial statements included in this report. The October 2014 Idaho Earning Support and Sharing Settlement Stipulation was modified and indefinitely extended, as described in "May 2018 Idaho Tax Reform Settlement Stipulation" of this MD&A.

May 2018 Idaho Tax Reform Settlement Stipulation: In December 2017, the Tax Cuts and Jobs Act was signed into law, which, among other things, lowered the corporate federal income tax rate from 35 percent to 21 percent and modified or eliminated certain federal income tax deductions for corporations. In March 2018, Idaho House Bill 463 was signed into law reducing the Idaho state corporate income tax rate from 7.4 percent to 6.925 percent. In May 2018, the IPUC issued an order approving a settlement stipulation (May 2018 Idaho Tax Reform Settlement Stipulation) related to income tax reform. Beginning June 1, 2018, the settlement stipulation provides an annual (a) $18.7 million reduction to Idaho customer base rates and (b) $7.4 million amortization of existing regulatory deferrals for specified items or future amortization of other existing or future unspecified regulatory deferrals that would otherwise be a future regulatory asset recoverable from Idaho customers.

The May 2018 Idaho Tax Reform Settlement Stipulation provides for the extension of the October 2014 Idaho Earnings Support and Sharing Settlement Stipulation described above beyond the initial termination date of December 31, 2019, with modified terms related to the ADITC and revenue sharing mechanism that became effective beginning January 1, 2020, with no defined end date. The May 2018 Idaho Tax Reform Settlement Stipulation does not impose a moratorium on Idaho Power filing a general rate case or other form of rate proceeding in Idaho during its term and includes provisions for the accelerated amortization of ADITC to help achieve a minimum 9.4 percent (9.5 percent prior to 2020) Idaho ROE. In addition, under the May 2018 Idaho Tax Reform Settlement Stipulation, minimum Idaho ROE would revert back to 95 percent of the authorized return on equity in the next general rate case. IDACORP and Idaho Power believe that the terms allowing amortization of additional ADITC in the May 2018 Idaho Tax Reform Settlement Stipulation provide the companies with a greater degree of earnings stability than would be possible without the terms of the stipulation in effect. In 2021, Idaho Power recorded a $0.6 million provision against current revenue for sharing with customers, as its full-year Idaho ROE exceeded 10.0 percent. Idaho Power recorded no provision against current revenue for sharing with customers in 2020, as its full-year ROE was between 9.4 percent and 10.0 percent. At December 31, 2021, the full $45 million of additional ADITC remained available for future use under the terms of the May 2018 Idaho Tax Reform Settlement Stipulation.2020.

Idaho Power recordedis unable to predict the following amounts for sharing with customers underoutcome of the December 2011 andOregon general rate case, but anticipates that new rates, if approved by the OPUC, would become effective in October 2014 Idaho Settlement Stipulations and the May 2018 Idaho Tax Reform Settlement Stipulation (in millions):

YearRecorded as Refunds to CustomersRecorded as a Pre-tax Charge to Pension ExpenseTotal
2021$0.6 $— $0.6 
2020— — — 
2019— — — 
20185.0 — 5.0 
2011(1) - 2017
53.1 68.1 121.2 
Total$58.7 $68.1 $126.8 
(1) The 2011 sharing amounts were recorded pursuant to a regulatory mechanism preceding the December 2011 Idaho settlement stipulation.

61
Table of Contents
2024 or later. For more information on the settlement stipulations and their impacts on results,Oregon general rate changes, see Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.

Other Notable Regulatory Matters
Oregon
May 2018 Idaho Tax Reform MattersSettlement Stipulation: : In May 2018, the OPUCIPUC issued an order approving a settlement stipulation that provided for an annual $1.5 million reduction to Oregon customer base rates beginning June 1, 2018, through May 31, 2020,(2018 Settlement Stipulation) related to income tax reform (Mayreform. In 2023, Idaho Power recorded no amounts for sharing with customers under this stipulation. For the years 2011 through 2022, Idaho Power recorded $58.7 million as a refund to customers and $68.1 million as a pre-tax charge to pension expense cumulatively under the 2018 Oregon Income Tax Reform Settlement Stipulation). In May 2020, the OPUC issued an order approving the quantification of $1.5 million in annualized Oregon jurisdictional benefits associated with federalStipulation and state income tax changes resulting from tax reform and adjusting Idaho Power's customer rates to reflect this amount, effective June 1, 2020, until the company's next general rate case or other proceeding where the tax-related revenue requirement components are reflected in rates.its predecessors.

2021 Integrated Resource Plan and Resource Procurement Filings: Idaho Power filed its most recent IRP with the IPUC and OPUC in December 2021, as described in Part 1, Item 1 - "Resource Planning and Renewable Energy Projects" in this report. The 2021 IRP identified the need for resources to meet projected capacity deficits in the near-term.

Also in December 2021, Idaho Power filed an application with the IPUC requesting approval to procure additional capacity resources to provide adequate, reliable, and fair-priced service to customers due to recent customer growth and an increase in energy demand. In its application, Idaho Power requested the IPUC issue an order: (1) eliminating the IPUC requirement to comply with the OPUC’s resource procurement rules in favor of a competitive, but expedited process; (2) authorizing Idaho Power to move forward expeditiously with resource procurement to meet identified resource needs in 2023, 2024, and 2025; and (3) affirming support and the continuation of the state of Idaho’s system of public utility regulation under which Idaho Power believes the interests of customers are best served by a vertically integrated electric utility maintaining ownership of the power supply, transmission, and distribution utility functions, with limited exceptions. As of the date of this report, the IPUC's decision in this matter is pending.

Similarly, in December 2021, Idaho Power filed an application with the OPUC requesting a waiver of Oregon's competitive bidding rules. Specifically, Idaho Power requested the OPUC issue an order waiving Idaho Power’s obligation to comply with the competitive bidding rules for its proposed resource procurement in favor of a competitive process and authorizing Idaho Power to move forward expeditiously with resource procurement to meet identified resource needs in 2023, 2024, and 2025. As of the date of this report, the OPUC's decision in this matter is pending.

Large Customer Rate Proceedings:

Speculative High-Density Load: In November 2021, Idaho Power filed an application with the IPUC to create a new customer class that would be applicable to commercial and industrial cryptocurrency mining operations smaller than 20 MW. Idaho Power 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 and its customers if the economics of cryptocurrency mining change. Idaho Power believes that the financial and system risks of Speculative High-Density Load can 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 June 15 through September 15, Idaho Power's summer peak season. As of the date of this report, the IPUC's decision in this matter is pending.

Clean Energy Your Way Program: In December 2021, Idaho Power filed an application with the IPUC requesting to expand optional customer clean energy offerings through its new Clean Energy Your Way Program. Specifically, Idaho Power is seeking authority to: (1) rename its existing green power program; (2) maintain and expand procurement options for the renewable energy credits (RECs); (3) establish a regulatory framework for a future voluntary subscription green power service program; (4) offer a tailored renewable option for Idaho Power's largest customers; and (5) procure the associated additional resources outside of the IPUC's current competitive procurement requirements. As of the date of this report, the IPUC's decision in this matter is pending.

Brisbie, LLC (Brisbie) Data Center: In December 2021, Idaho Power filed an application with the IPUC for approval of a special contract for electric service for a new large load customer, Brisbie, LLC (Brisbie), for a new 960,000 square-foot enterprise data center expected to begin operations in 2025. Brisbie is a wholly-owned subsidiary of Meta Platforms, Inc. Idaho regulations require any utility customer with an average load exceeding 20 MW to enter into a special contract with Idaho Power. Brisbie, in addition to its large load service requirements in excess of 20 MW, has a sustainability objective to support 100 percent of its operations with new renewable resources. Under the proposed special contract, Idaho Power would procure enough renewable resources to provide Brisbie with 100 percent renewable energy on an annual basis for Brisbie’s facility. In
6260
Table of Contents                              
its application, Idaho Power requested authority to procureFor more information on the necessary resources contemplated within its agreement with Brisbie without seeking IPUC approval for each such procurement and requested assurance from the IPUC that each such resource procurement would receive the same ratemaking treatment outlined in the case, unless otherwise modified in a subsequent proceeding. Asprovisions of the date of this report,2018 Settlement Stipulations, see Note 3 - "Regulatory Matters" to the IPUC's decisionconsolidated financial statements included in this matter is pending.report.

North Valmy Base Rate Adjustment Settlement Stipulations: In May 2017,Idaho Power has settlement stipulations in place in Idaho and Oregon related to the IPUC approved a settlement stipulation, effective June 1, 2017, allowing accelerated depreciation and cost recovery for theplanned early retirement of both units of its jointly-owned North Valmy coal-fired power plant. The settlement stipulation provides for an increasestipulations are described more fully in Idaho jurisdictional revenues of $13.3 million per year, and (1) levelized collections and associated cost recovery through December 2028, (2) accelerated depreciation on unit 1 through 2019 and unit 2 through 2025, and (3) Idaho PowerNote 3 - "Regulatory Matters" to use prudent and commercially reasonable efforts to end its participation in the operation of unit 1 by the end of 2019 and unit 2 no later than the end of 2025. The settlement stipulation also provides for the regulatory accrual or deferral of the difference between actual revenue requirements and levelized collections, and provides for the regulatory accrual or deferral of the difference between actual costs incurred (including accelerated depreciation expense on unit 1 through 2019 and unit 2 through 2025) compared with costs permitted to be recovered during the cost recovery period specified in the settlement stipulation (including depreciation expense through 2028). If actual costs incurred differ from forecasted amountsconsolidated financial statements included in the settlement stipulation, collection or refund of any differences would be subject to regulatory approval. In February 2019, Idaho Power reached an agreement with NV Energy that facilitates the planned end of Idaho Power's participation in coal-fired operations at units 1 and 2 of its jointly-owned North Valmy plant in 2019 and 2025, respectively. In May 2019, the IPUC issued an order approving the North Valmy plant exit agreement and allowing Idaho Power to recover through customer rates the $1.2 million incremental annual levelized revenue requirement associated with required North Valmy plant investments and other exit costs, effective June 1, 2019, through December 31, 2028. In December 2019, as planned, Idaho Power ended its participation in coal-fired operations of North Valmy plant unit 1.

In June 2017, the OPUC also approved a settlement stipulation allowing for (1) accelerated depreciation of North Valmy plant units 1 and 2 through December 31, 2025, (2) cost recovery of incremental North Valmy plant investments through May 31, 2017, and (3) forecasted North Valmy plant decommissioning costs. The settlement stipulation provided for an increase in the Oregon jurisdictional revenue requirement of $1.1 million, with yearly adjustments, if warranted. In May 2018, the OPUC also deemed prudent Idaho Power's decision to pursue the end of its participation in coal-fired operations of unit 1 by the end of 2019 and approved Idaho Power's request to recover annual incremental accelerated depreciation relating to unit 1, ending December 31, 2019, resulting in a $2.5 million annualized revenue requirement. In October 2019, the OPUC approved the North Valmy plant exit agreement and authorized Idaho Power to adjust customer rates in Oregon, effective January 1, 2020, to reflect a decrease in the annual levelized revenue requirement of $3.2 million, which mostly relates to the decrease in depreciation expense and other costs associated with the December 2019 end of Idaho Power's participation in coal-fired operations of North Valmy plant unit 1. In September 2021, the IPUC issued an order acknowledging Idaho Power's year-end 2025 exit date from Valmy unit 2 is appropriate based on economics and reliability needs.

Boardman Power Plant Filings: In October 2020, Idaho Power and co-owner Portland General Electric ceased coal-fired operations at their Boardman power plant. In December 2020, the IPUC issued an order authorizing a determination that all actual Boardman power plant investments made through June 30, 2020, were prudently incurred and decreasing Idaho customer rates $3.9 million to reflect full depreciation of all Boardman power plant investments, effective January 1, 2021. In October 2020, the OPUC issued a similar order approving a $0.3 million decrease in Oregon customer rates, effective November 1, 2020.

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 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 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 one of the residential and small commercial cases during 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 customers with on-site generation prior to December 20, 2019, to be subject to the billing terms in place on that date until December 20, 2045. In December 2020, the IPUC issued an order establishing a 25-year grandfathering term for CI&I customers, similar to the terms approved for the residential and small commercial customer classes.
63
Table of Contents

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. In December 2021, the IPUC issued an order requiring Idaho Power to complete the study design for its comprehensive study on the costs and benefits of on-site generation based on the IPUC’s study framework findings and conclusions and requiring that Idaho Power complete the study in 2022 as soon as feasible. As of the date of this report, Idaho Power expects to complete the study in the first half of 2022.

Depreciation Rate Requests: In 2021, Idaho Power conducted a depreciation study of electric plant-in-service, which it performs approximately every five years. The study provided updates to net salvage percentages and service life estimates for Idaho Power plant assets. In November 2021, Idaho Power filed stipulations in both jurisdictions, adopting new depreciation rates, and agreeing to no increases in either the Idaho or Oregon jurisdictional revenue requirement and no changes in customer rates. The IPUC and OPUC approved the stipulations, to be effective January 1, 2022.report.

Jim Bridger Power Plant Rate Request:Base Adjustment and Recovery: In June 2021, Idaho Power filed an application with2022, the IPUC requesting authorizationissued an order (Bridger Order) approving, with modifications, Idaho Power’s amended application related to (1) accelerate depreciation foradjustment and recovery of the Jim Bridger plant,Power Plant rate base. The Bridger Order and associated accounting are described in Note 3 – “Regulatory Matters” to allow the plantconsolidated financial statements included in this report. Regulatory orders from the IPUC and OPUC provide for Idaho Power to be fully depreciated and recovered by December 31, 2030, (2) establish a balancing account to track the incremental costs and benefits associated with ceasing participation incease coal-fired operations at the Jim Bridger plant by the end of 2028. However, as noted previously, Idaho Power's 2023 IRP identified a preferred resource portfolio and (3) adjust customer rates to recoveraction plan that includes the associated incremental annual levelized revenue requirement.

In September 2021, the co-owner and operator of the Jim Bridger Plant submitted its IRP to the IPUC that contemplates ceasing coal-fired generation in units 1 and 2 in 2023 and converting those unitsconversion from coal to natural gas generation by 2024. Idaho Power's 2021 IRP includes the same plan. At a public meeting in October 2021, the IPUC approved a joint motion by Idaho Power and the IPUC Staff to suspend the procedural schedule in Idaho Power's rate request case to assess new developments that impact operationsof two units at the Jim Bridger plant citing the potential option to convert the two units to natural gas generation as well as ongoing regional haze compliance discussions. In February 2022, Idaho Power filed a request to resume the procedural schedule with an amended application to the IPUC that contemplates the conversion of units 1 and 2 to natural gas in 2024 and therefore removes from the application all investments for the portion of the plant that will be converted to support gas-fired operations, leaving just coal-related plant investments in the requested regulatory treatment. The updated filing requests authorization to adjust customer rates to recover the associated incremental annual levelized revenue requirement in the aggregate amount of $27.1 million, which included Idaho Power's share of all electric plant in service related to coal-fired operationsremaining two units at the Jim Bridger plant. The proposed adjustmentplant in this application would result in an overall rate increase of 2.12 percent in Idaho. As of the date of this report, the case remains pending at the IPUC.

Deferred Costs for COVID-19 Public Health Crisis:2030. Idaho Power has incurred, and expects to continueseek approval from the IPUC and OPUC for any necessary adjustments to incur, costs associatedplant retirement dates to align with its response to the COVID-19 public health crisis, including information technology expenditures for remote work and higher than average levels of bad debt expense related to uncollectible accounts associated in part with its temporary suspension of disconnects and late payment fees. Accordingly, in March and April 2020, Idaho Power submitted applications to the OPUC and IPUC, respectively, requesting authorization to defer incremental costs associated with its response to the COVID-19 public health crisis. Idaho Power requested authorization to establish a new regulatory asset to record the deferral of incremental costs and, in the Idaho jurisdiction, unrecovered costs associated with the COVID-19 response. Both applications requested only the authority to defer these costs and to determine ratemaking treatment at a later date. Subsequent to Idaho Power's application, the IPUC opened a general docket to address the issue. In July 2020, the IPUC issued an order authorizing Idaho Power and other utilities to account for unanticipated, emergency-related expenses incurred due to the COVID-19 public health crisis by recording the expenses as regulatory assets for possible recovery through future rates. The order also requires utilities to account for the decreases in expenses resulting from the COVID-19 public health crisis, such as reduced employee travel and training, and apply these reductions in expenses to offset the deferral account balance. Additionally, the order addressed potential reductions in revenue due to the COVID-19 public health crisis, allowing utilities to track reduced revenues from customer classes not included in an FCA-type mechanism for possible movement to the regulatory asset account at a later date. Idaho Power resumed assessing late fees and disconnections in early August 2020 in its Idaho service area. In October 2020, the OPUC issued an order authorizing Idaho Power to defer certain COVID-19-related costs for the 12-month period beginning March 24, 2020. In March 2021, Idaho Power requested that the OPUC re-authorize such deferral for an additional 12-month period. As of December 31, 2021, Idaho Power had recorded an immaterial regulatory asset for its estimate of unanticipated, emergency-related expenses, including higher bad debt expense, net of estimated savings.current resource plan.

Wildfire Mitigation Cost Recovery:Deferral: In JuneBeginning in 2021, the IPUC has authorized Idaho Power to defer for future amortization incremental O&M and depreciation expense of certain capital investmentsexpenses necessary to implement the company's WMP. The
64
Table of Contents
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. In the filing, Idaho Power projected spending approximately $47 million in incremental wildfire mitigation-related O&M and roughly $35 million in wildfire mitigation system-hardening capital incremental expenditures over a five-year period. The IPUC authorized acost deferral period of five years, or until rates go into effect after Idaho Power's next general rate case, whichever is first. As of December 31, 2021, Idaho Power’s deferral relateddescribed more fully in Note 3 - "Regulatory Matters" to the WMP was $6.1 million. Idaho Power expects that it will continue to incur additional incremental costs from its enhanced wildfire mitigation effortsconsolidated financial statements included in future periods.this report.

Fixed Cost Adjustment: The FCA mechanism, applicable to Idaho residential and small commercial customers, is designed to remove a portion of Idaho Power’s financial disincentive to invest in energy efficiency programs by separating (or decoupling) the recovery of fixed costs from the variable kilowatt-hour (kWh)kWh charge and linking it instead to a set amount per customer. In May 2021, the IPUC ordered Idaho Power to work with interested parties and initiate a case to review the FCA mechanism and propose modifications it determines are appropriate. In December 2021, the IPUC approved Idaho Power's proposed modifications to the FCA mechanism to institute separate, and reduced, fixed cost tracking for customers added to Idaho Power's system after December 31, 2021. Idaho Power does not expect the modifications to have a material impact on Idaho Power's operating revenues or consolidated financial statements. The FCA mechanism is described more fully in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report. 

Integrated Resource Plan and Resource Procurement Filings: Idaho Power filed its most recent IRP with the IPUC and OPUC in September 2023, as described in Part 1, Item 1 - "Business - Resource Planning" in this report.

The State of Oregon has competitive bidding rules regarding a public utility's procurement of resources. However, as allowed by the rules in certain cases, Idaho Power is pursuing exceptions for its identified 2024 and 2025 resource needs. In July 2023, following review by an independent evaluator appointed by the OPUC, OPUC staff, and other intervening parties, the OPUC issued an order approving issuance of Idaho Power's final RFP to procure resources for its anticipated energy and capacity needs in 2026 and 2027.

Customer-Owned Generation Filing: Customer-owned generation enables 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 kWh credit to the customer’s bill. The IPUC issued an order in February 2020 directing Idaho Power to 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 establishing a 25-year grandfathering term for large commercial, industrial, and irrigation customers, similar to the terms approved for the residential and small commercial customer classes.

In June 2022, as directed by the IPUC, Idaho Power filed a comprehensive study on the costs and benefits of on-site generation based on the IPUC’s study framework findings and conclusions, and in December 2022, the IPUC issued an order that directed Idaho Power to file a new case requesting to implement changes to the structure and design of its on-site generation program. In May 2023, Idaho Power filed a new case as directed by the IPUC, requesting to implement changes for non-grandfathered customers starting January 1, 2024, including: (1) a change from net monthly to real-time net billing, which would better measure customers’ actual reliance on the grid; (2) a change in the excess exported energy credit from a kWh credit ranging in value of 5 to 12 cents, depending on the customer class, to a time-differentiated financial bill credit ranging from approximately 5 to 20 cents per kWh that would be updated annually; and (3) a modification to the eligibility cap for large commercial, industrial, and irrigation customers. On December 29, 2023, the IPUC approved Idaho Power's filing, with certain modifications, including an adjustment to the financial bill credit rates to a range from 5 to 17 cents as well as other administrative modifications.
61
Table of Contents

Large Customer Rate Proceedings

Clean Energy Your Way Program: In August 2023, the IPUC approved Idaho Power's application to expand optional customer clean energy offerings through its new Clean Energy Your Way Program. Specifically, Idaho Power received authority to: (1) rename its existing green power program; (2) maintain and expand procurement options for the RECs; (3) establish a regulatory framework for a future voluntary subscription green power service program; (4) offer a tailored renewable option for Idaho Power's largest customers; and (5) procure the associated additional resources outside of the IPUC's current competitive procurement requirements.

Brisbie, LLC (Brisbie) Data Center: In April 2023, the IPUC approved an arrangement, modeled after the Clean Energy Your Way program under which a new large load customer, Brisbie, LLC (Brisbie), a wholly-owned subsidiary of Meta Platforms, Inc., would purchase from Idaho Power energy for a new 960,000 square-foot enterprise data center. The energy to be purchased by Brisbie is anticipated to be generated by a to-be-constructed 200-MW solar facility pursuant to a long-term power purchase agreement between Idaho Power and a third party, as well as additional renewable resource projects to be developed. The 200-MW solar facility is scheduled to begin operating as early as March 2025. In January 2024, Idaho Power filed for IPUC approval of an additional contract with a 125-MW solar project to be online in December 2026.

In May 2023, the IPUC issued an order approving, with modifications, a special contract for electric service for Brisbie for the new data center. Idaho regulations require any utility customer with an average load exceeding 20 MW to enter into a special contract with its electric provider. Brisbie, in addition to its large load service requirements in excess of 20 MW, has a sustainability objective to support 100 percent of its operations with new renewable resources. Under the special contract, Idaho Power expects to procure enough renewable resources to support 100 percent of Brisbie's operations on an annual basis with new renewable resources. The modified special contract and related rate schedule were approved by the IPUC in October 2023.

Micron Dedicated Renewable Resource: In August 2022, the IPUC issued an order approving, with modifications, Idaho Power's application for a revised special contract for electric service between Idaho Power and Micron. The application was modeled after the Clean Energy Your Way program and included an arrangement under which Micron would purchase from Idaho Power 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 began operating in May 2023.

In April 2023, the IPUC issued an order approving Idaho Power's compliance filing of 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.

Lamb Weston, Inc. Special Contract: In September 2023, the IPUC issued an order approving Idaho Power's special contract for electric service for an existing large load customer, Lamb Weston, Inc. (Lamb Weston). Idaho Power anticipates Lamb Weston's large load service requirements to exceed 20 MW in the near future.

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 believes new system resources may be necessary to serve this speculative customer load, which could create a financial risk for Idaho Power and its 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 use of a rate design for this customer class that prices energy at a marginal rate, and through a requirement that speculative high-density load customers be interruptible at Idaho Power's discretion from June 15 through September 15, Idaho Power's summer peak season. As subsequently required by the IPUC, in December 2022, Idaho Power filed an application proposing the interruption compensation for Schedule 20 customers. In August 2023, the IPUC approved interim interruption compensation rates until a rate can be designed using sufficient data from actual Schedule 20 customers.

Deferred (Accrued) Net Power Supply Costs
 
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 (refund)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
62
Table of Contents
associated financial impacts are described in "Results of Operations" in this MD&A and in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.

Factors that have influenced power cost adjustment rate changes in recent years include year-to-year volatility in hydropower generation conditions, market energy prices and the volume of wholesale energy sales, power purchase costs from renewable energy projects, income tax reform, and revenue sharing under Idaho regulatory settlement stipulations. From year to year, these factors can vary significantly, which can result in significant accruals and deferrals under the power cost adjustment mechanisms. The power cost adjustment rate changes reflected in the table under the heading "Notable Retail Rate Changes in Idaho and Oregon" in this MD&A are illustrative of the volatility of net power supply costs and the impact on power cost adjustment rates.

The following table summarizes the change in deferred (accrued) net power supply costs over last year (in millions):
 IdahoOregonTotal
Balance at December 31, 2020$(14.7)$(0.3)$(15.0)
Current period net power supply costs deferred22.0 — 22.0 
Prior amounts refunded through rates27.6 0.2 27.8 
SO2 allowance and renewable energy certificate (REC) sales
(4.2)(0.2)(4.4)
Interest and other3.1 — 3.1 
Balance at December 31, 2021$33.8 $(0.3)$33.5 
 IdahoOregonTotal
Balance at December 31, 2022$128.7 $0.6 $129.3 
Current period net power supply costs deferred/(accrued)66.7 (1.2)65.5 
Prior amounts collected through rates(72.2)(0.2)(72.4)
REC sales(13.2)(0.6)(13.8)
Interest and other5.6 0.1 5.7 
Balance at December 31, 2023$115.6 $(1.3)$114.3 

Open Access Transmission Tariff Rate Proceedings

Idaho Power uses a formula rate for transmission service provided under its OATT, which allows transmission rates to be updated annually based primarily on actual financial and operational data Idaho Power files with the FERC and allows Idaho Power to recover costs associated with its transmission system.FERC. In September 2021,October 2023, Idaho Power filed its 20212023 final transmission rate with the FERC, reflecting a transmission rate of $31.19$30.74 per kW-year, effective"kW-year," to be effective for the period from October 1, 2021,2023, to September 30, 2022.2024. A "kW-year" is a unit of electrical capacity equivalent to 1 kilowattkW of power used for 8,760 hours. Idaho Power's final rate was based on a net annual transmission revenue requirement of $127.3$135.7 million. The OATT rate in effect from October 1, 2020,2022 to September 30, 2021,2023, was $29.95$31.42 per kW-year based on a net annual transmission revenue requirement of $117.7 millio$132.7 min. The increase in the 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
65
Table of Contentsllion.
requirement. Historical OATT rate information is included in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.

Relicensing of Hydropower Projects
 
Overview: Idaho Power, like other utilities that operate non-federal hydropower projects on qualified waterways, obtains licenses for its hydropower projects from the FERC. These licenses have a term of 30 to 50 years depending on the size, complexity, and cost of the project. The expiration dates for the FERC licenses for each of the facilities are included in Part I - Item 2 - "Properties" in this report. CostsSee Note 12 - "Property, Plant and Equipment and Jointly-Owned Projects" to the consolidated financial statements included in this report for information regarding relicensing 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. In April 2018, the IPUC approved a settlement stipulation signed by Idaho Power, the IPUC Staff, and a third-party intervenor and determined that $216.5 million in expenditures incurred for relicensing through December 31, 2015, were reasonably and prudently incurred, and therefore should be eligible for inclusion in customer rates at a later date. Relicensing costs of $389 million (including AFUDC) for the HCC, Idaho Power's largest hydropower complex and a major relicensing effort, were included in construction work in progress at December 31, 2021. As of the date of this report, the IPUC authorizes Idaho Power to include in its Idaho jurisdiction rates approximately $8.8 million annually of AFUDC relating to the HCC relicensing project. Collecting these amounts currently will reduce future collections when the HCC relicensing costs are approved for recovery in base rates. As of December 31, 2021, Idaho Power's regulatory liability for collection of AFUDC relating to the HCC was $187.7 million.HCC. In addition to the discussion below, refer to“Hells Canyon Complex Relicensing” in “Liquidity and Capital Resources” in this MD&A for a discussion of the costs and expected timing of a HCC license and "Environmental Matters" in this MD&A for a discussion of environmental compliance under FERC licenses for Idaho Power's hydropower generating plants.

Hells Canyon Complex Relicensing: The HCC, located on the Snake River where it forms the border between Idaho and Oregon, provides approximately 70 percent of Idaho Power's hydropower generating nameplate capacity and 36 percent of its total generating nameplate capacity. In July 2003, Idaho Power filed an application with the FERC for a new license in anticipation of the July 2005 expiration of the then-existing license. Since the expiration of that license, Idaho Power has been operating the project under annual licenses issued by the FERC. In December 2004, Idaho Power and eleven other parties including National Marine Fisheries Service (NMFS) and U.S. Fish and Wildlife Service (USFWS), involved in the HCC relicensing process, including NMFS and USFWS, entered into an interim agreement that addresses the effects of the ongoing operations of the HCC on Endangered Species Act (ESA)-listedESA-listed species pending the relicensing of the project. In August 2007, theThe FERC Staffstaff issued a final environmental impact statement (EIS) for the HCC, which the FERC will use to determine whether, and under what conditions, to issue a new license for the project. The FERC may require a supplemental, updated EIS prior to the issuance of a new license for the HCC. The purpose of the final EIS is to inform the FERC, federal and state agencies, Native American tribes, and the public about the environmental effects of Idaho Power's operation of the HCC. Certain portions of the final EIS involve issues that may be influenced by water quality certifications for the project under Section 401 of the Clean Water Act (CWA) and formal consultations under the ESA.in August 2007.

In September 2007, in connection with the issuance of its final EIS, the FERC notified the NMFS and the USFWS of its determination that the licensing of the HCC was likely to adversely affect ESA-listed species, including the bull trout and fall Chinook salmon and steelhead, under the NMFS's and USFWS's jurisdiction and requested that the NMFS and USFWS initiate formal consultation under Section 7 of the ESA on the licensing of the HCC. Both the NMFS and USFWS responded to the FERC that the conditions relating to the licensing of the HCC were not fully described or developed in the final EIS as the measures to address the water quality effects of the project were yet to be fully defined by the Section 401 certification process. The NMFS and USFWS each therefore recommended that formal consultation under the ESA be delayed until the Section 401 certification process is completed.
In connection with its relicensing efforts, Idaho Power filed annual 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 projectHCC comply with applicable state water quality standards. Section 401 ofChallenges regarding how to meet water temperature standards below the CWA requires thatHCC dam for spawning fall Chinook salmon, and a state either approve or deny a Section 401 water quality certification application within one year of the filing of the application or the state may be considered to have waived its certification authority under the CWA. As a consequence, Idaho Power filed and withdrew its Section 401 certification applications withconflict in laws between Oregon and Idaho on an annual basis while it was working withregarding the states to identify measures that will provide reasonable assurance that discharges fromreintroduction and passage of fish above the HCC, will adequately address applicable water quality standards. Indelayed the 2016 Section 401 certification application process, Oregon required Idaho Power to comply with fish passage and reintroduction conditions. Idaho's water quality certification, however, provided that Idaho Power take no action that might result in the reintroduction or establishment of spawning populations of any fish species into Idaho's waters without consultation with and express approvalissuance of the State of Idaho.states' 401 certifications for several years. In November 2016, Idaho Power filed a petition with the FERC requesting that the FERC resolve the conflict between Oregon's and Idaho's conditions and declare that the FPA pre-empts the Oregon state law requiring reintroduction and passage, which the
6663
Table of Contents                              
Oregon state law. InFERC denied in January 2017, the FERC issued an order denying Idaho Power’s petition, stating that the petition for a declaratory order was premature, cannot realistically be considered separately from the issue of the states’ certification authority under the CWA Section 401, and raises issues that are beyond the FERC’s authority to decide. In February 2017, Idaho Power sought rehearing before the FERC on the January 2017 order, which the FERC denied.2017. In February 2018, Idaho Power filed an appeal ofappealed the FERC's January 2017 order with the D.C.United States Court of Appeals for the District of Columbia Circuit, Court, which is pending.

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 which 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 intervened in that 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 itsThe FERC's decision relating to the Offer of Settlement is pending as of the date of this report.

Idaho Power continues to work with Idaho and Oregon on measures to provide reasonable assurance that any discharges from the HCC will comply with applicable state water quality standards and associated measures identified in the final Section 401 certifications, and continues to cooperate with the USFWS, the NMFS, and the FERC in an effort to address ESA concerns. Measures identified in the final Section 401 certifications included construction of aerated runners at the Brownlee project (part of the HCC), modification of spillways at the three dams in the HCC to address total dissolved gas issues, and upstream watershed improvements to address water temperature exceedances during a small portion of the year. These and any other additional measures to satisfy relicensing requirements have added and will continue to add substantially to project costs.

In July 2020, Idaho Power submitted to the FERC its supplement to the final license application, that incorporatedincorporating the settlement agreement reached between Idaho and Oregon on the CWA Section 401 certifications and providedcertifications. The supplement included feedback on proposed modificationmodifications of the 2007 final EIS for the HCC. The July 2020 filing also containedHCC, as well as an updated cost analysis of the HCC and a request forthat the FERC to issue a 50-year license and initiate a supplemental National Environmental Policy Act (NEPA)NEPA process at the FERC. Idaho Power prepared draft biological assessmentsIn June 2022, the FERC issued a notice of intent to prepare a supplemental EIS in accordance with NEPA. The FERC also reinstated informal consultation with the USFWS and the 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 section 7 of the ESA. In December 2020, FERC staff issued six additional information requests (AIRs) from Idaho Power to help withOctober 2023, the analysis and baseline for the project moving forward. Idaho Power has filed responses to all six of the AIRs with FERC. Subsequently, in September 2021 FERC issued ten additional AIRsa notice revising the schedule for completing the supplemental EIS. Under the revised schedule, the draft supplemental EIS is targeted to clarify the cost of the proposed mitigation measures. Once FERC has evaluated the additional information, Idaho Power expects it to issue a Notice of Intent indicating what, if any, additional environmental analysis is necessary to issue a license. Idaho Power expects the FERC will also initiate formal ESA consultation with the USFWSbe published in February 2024 and the NMFS.

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 incurfinal supplemental EIS in complying with any new license. The FERC could issue an HCC license as early as 2023, but as of the date of this report Idaho Power believes issuance is more likely in 2024 or thereafter. 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.November 2024.

American Falls Relicensing: In April 2020, the FERC formally initiated the relicensing proceeding forof 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 recognizedIn February 2023, following the filing of a draft license application and public comment period, Idaho Power’s pre-application document, includingPower filed a proposed process plan and schedule, and recognized Idaho Power’s intent to file an application for a license. A final license application is duewith the FERC. In July 2023, the FERC accepted Idaho Power’s final license application for filing and solicited motions to intervene and protest. In September 2023, the FERC issued a request for comments to determine the resource issues that should be addressed in the environmental analysis and identify reasonable alternatives to the proposed action that the FERC should evaluate under the NEPA framework. In January 2024, the FERC indicated that it planned to issue a Notice of Ready for Environmental Analysis, the next major milestone in 2023.the relicensing process, in February 2024. The relicensing proceeding will beginhas 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.

In September 2023, Idaho Power filed an application for CWA Section 401 water quality certification with the IDEQ. The IDEQ informed Idaho Power that it anticipates preparing a draft certification and will seek public comment once the draft is complete. American Falls' current
67
Table of Contents
license expires in 2025, 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.

Renewable Energy Standards and Contracts

Renewable Portfolio Standards: Many states have enacted legislation that would require electric utilities to obtain a specified percentage of their electricity from renewable sources. These requirements are commonly referred to as a "renewable portfolio standard" or "RPS." However, as of the date of this report no State of Idaho RPS is in effect. Idaho Power will be required to comply with either a five- or ten-percent RPS in Oregon beginning in 2025 (depending on loads at that time), and Idaho Power expects to meet either RPS requirement with RECs obtained from the purchase of energy from the Elkhorn Valley wind project.

Pursuant to an IPUC order, Idaho Power is selling its near-term RECs and returning to customers their share (shared 95 percent with customers in the Idaho jurisdiction) of those proceeds through the PCA. For the years ended December 31, 2021, and 2020, Idaho Power's REC sales totaled $4.7 million and $5.2 million, respectively.

Were Idaho Power to be subject to additional RPS legislation, it may cease in full or in part the sale of RECs it receives, seek to obtain RECs from additional projects, generate RECs from any REC-generating facilities it owns or may be required to construct in light of an RPS, or purchase RECs in the market. Historically, Idaho Power has generally not received the RECs associated with PURPA projects. However, an order issued by the IPUC in 2012 provides that Idaho Power will own a portion of the RECs generated by some PURPA projects. The required purchase of additional RECs to meet RPS requirements would increase Idaho Power's costs, which Idaho Power expects would be wholly or largely passed on to customers through rates and the power cost adjustment mechanisms.

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 December 31, 2021, Idaho Power had contracts to purchase energy from 129 on-line PURPA projects. An additional three contracts are with on-line non-PURPA projects, including the Elkhorn Valley wind project with a 101-MW nameplate capacity.

The following table sets forth, as of December 31, 2021, 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 TypeOn-line megawatts (MW)Under Contract but not yet On-line (MW)Total Projects under Contract (MW)
PURPA:
Wind627 — 627 
Solar316 74 390 
Hydropower150 1 151 
Other44 — 44 
Total PURPA1,137 75 1,212 
Non-PURPA:
Wind101 — 101 
Geothermal35 — 35 
Solar— 120 120 
Total non-PURPA136 120 256 
The projects not yet on-line include one PURPA-qualifying facility hydropower project that is scheduled to be on-line in 2022, two PURPA-qualifying facility solar projects scheduled to be on-line in 2023, and one PURPA-qualifying facility solar project scheduled to be on-line in 2024. The non-PURPA solar project is scheduled to be on-line in late 2022.

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 qualifying facilities (QF), which facilities are eligible for QF status, whether and when
68
Table of Contents
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.
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) requirements,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 a number of federal, state, and local agencies. In addition to imposing continuing compliance obligations and associated costs, these laws and regulations provide authority to regulators to levy substantial penalties for noncompliance, injunctive relief, and other sanctions. Idaho Power's two co-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 a number of water discharge standards and other environmental requirements.

Compliance with current and future environmental laws and regulations may:

•increase the operating costs of generating plants;
•increase the construction costs and lead time for new facilities;
•require the modification of existing generating 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
64
Table of Contents
•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 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 operation of the Boardman power plant in October 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 North Valmy plant was also based primarilyin part on the economics of operatingcontinuing coal-fired generation at 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 cannot be fully recovered in rates on a timely basis.

Part I, Item 1 - “Business - Utility Operations - Environmental Regulation and Costs”Costs” in this report includes a summary of Idaho Power's expected capital and operating expenditures for environmental matters during the period from 20222024 to 2024.2026. 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 beyond 2024,2026, though they could be substantial. Furthermore, several executive orders issued since 2017 concerning environmental regulations, including executive orders issued by the current Presidential Administration in 2021, as described below, to establish new federal environmental mandates, revoke several existing executive orders, and require agencies to review environmental regulations issued by the previous Presidential Administration, could result in significant changes in, and uncertainty with respect to, legislation, regulation, and government policy regarding environmental matters. The outcome of federal agencies' review of regulations covered by executive orders and revocation of executive orders is difficult to predict. Additionally, the court system has become more active in reviewing agency actions, resulting in even less certainty as to the outcome and durability of rules that are administratively implemented. Changes to or elimination of regulations may lower Idaho Power's costs of operating and maintaining fossil fuel-fired generation plants and transmission lines, due to the reduction of potential environmental infrastructure upgrades or conversions, or reduction or elimination of permitting requirements. Executive orders resulting in moreMore strict or robust regulations, or additional regulations, on the other hand, would likely increase Idaho Power's costs of operating and maintaining its facilities.facilities, and could impact Idaho Power's plans and pre-construction activities related to its major transmission projects, which could lead to substantially higher construction and permitting costs and could delay construction. Executive orders may be affected by Congressional action and challenged in court. Further, state and local governmental authorities could choose to challenge or replace the federal regulations or bolster or undermine environmental compliance and enforcement efforts at the local level, and therefore, Idaho Power is uncertain whether and to what extent the orders could affect its operations, and environmental-related expenditures. Idaho Power plans to continue to monitor actions associated with or resulting from executive orders.
69
Table of Contentslevel. Therefore,

Executive Orders on Environmental Matters

In January 2021, the current Presidential Administration issued several executive orders to establish new federal environmental mandates, revoke several existing executive orders, and require agencies to review regulations related to environmental matters issued by the previous Presidential Administration (January 2021 Executive Order(s)). One executive order rejoined the United States to the Paris Agreement on climate change, which requires commitments to reduce greenhouse gas (GHG) emissions, among other things. In response to another executive order, the U.S. Environmental Protection Agency (EPA) requested that the U.S. Department of Justice stay all proceedings in pending litigation seeking judicial review of any EPA regulations promulgated between 2017 and January 20, 2021. Another executive order in 2021 directed the Office of the Federal Register to stop publishing rules and other documents sent to it by the previous Presidential Administration, which Idaho Power believes may apply to the regional haze rules described in this MD&A below, and paused the effective date of certain federal rules that had not yet taken effect as of January 20, 2021. During the "freeze period," the federal agencies were directed to review any such pending actions and determine whether they should move forward or be modified on a rule-by-rule basis by the relevant federal agency. New or modified environmental regulations resulting from these orders could impact Idaho Power's plans and pre-construction activities related to its major transmission projects, which could lead to substantially higher construction and permitting costs and could delay construction. As of the date of this report, and except as specifically described below in this MD&A, Idaho Power is uncertain whether and to what extent the January 2021 Executive Orders, orders, any future executive orders, and the implementation of these and any future executive orders may impact Idaho Power's could affect its business, results of operations, and financial condition. Idaho Power will continue to monitor actions associated with or resulting from executive orders.

Endangered Species Act Matters

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

In November 2018,Over the U.S. Supreme Court held that an area is eligible for designationpast few years and as a critical habitatresult of changes in Presidential Administrations, regulatory developments and executive orders have called into question the existing requirements under the ESA only if it is also "habitat" forESA. Subsequent federal court decisions have in some cases undermined the species as definedeffectiveness of those regulations and orders. The uncertainty in the statute, which generally meansregulatory landscape makes it difficult to predict the area can support the species without modification,scope, timing and as partcomplexity of the designation, the USFWS must also consider the costs comparedproject-related ESA matters to the benefits of such designation. Idaho Power believes this ruling may limit the number of areas designated as critical habit and could also reduce Idaho Power’s obligations for mitigation under the ESA. Furthermore, in August 2019, the USFWS and the NMFS issued a set of regulatory changes to some of the standards under which listings, delisting, and reclassifications and critical habitat designations are made.be addressed.

In June 2021, in response to the January 2021 Executive Orders directing federal agencies to review certain environmental regulations,May 2023, the USFWS published a revised Mitigation Policy and the NMFS released a plan to initiate rulemaking to revise, rescind, or reinstate fiverevised 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 regulatory definitionCompensatory Mitigation Policy (Revised Policies) which together establish fundamental mitigation principles and compensatory mitigation standards and application guidance through implementation of habitat, revise regulations for listing species and designating critical habitat, revise regulations for interagency cooperation, and reinstate certain protections for species listed as threatened under the ESA. In October 2021,The Revised Policies scale back the USFWSmitigation goal from the previous policies by including a nexus and NMFSproportionality principle to reinforce that government-required mitigation measures must have a clear connection with the anticipated effects of the proposed new rulesland use. As of the date of this report, Idaho Power is uncertain to remove exclusions for certain territory subject to critical habitat designationswhat extent the Revised Policies may impact its obligations in permitting infrastructure, including relicensing its hydropower facilities, and to rescind the prior administration's regulatory definition of habitat.transmission lines.

The construction
65
Table of power supply, transmission, or distribution facilities and the relicensing of Idaho Power's hydropower projects can be federally authorized actions that fall under the ESA. Contents
There are a number of threatened or endangered species within Idaho Power's service area and within or near proposed transmission line routes, including the slickspot peppergrass. In December 2020, the USFWS announced that although it will not yet list the black and orange monarch butterfly as threatened or endangered, it will continue to monitor this species for future determination in 2024, which Idaho Power believes could potentially impact right-of-way maintenance for its transmission line routes. Further, there are a number of ESA-listed fish and other aquatic species located in waterways in which Idaho Power has hydropower facilities, including fall Chinook salmon, bull
70
Table of Contents
trout, Bliss Rapids snail, and Snake River physa snail.within or near proposed transmission line routes. To date, efforts to protect these and other listed species have not significantly affected generation levels or operating costs at any of Idaho Power's hydropower facilities. However, the ongoing relicensing of the HCC presents endangered species and fisheries issues that may require operational adjustments and could adversely impact the amount of output from hydropower dams, potentially causing Idaho Power to rely on more expensive sources for power generation or market purchases. These ESA regulations could impact the timing and feasibility of the HCC relicensing project and the Gateway West and Boardman-to-Hemingway transmission projects and other infrastructure projects, which could lead to substantially higher construction, permitting, and licensing costs and could delay construction.

Developments in Regulation of Sage Grouse Habitat: In February 2016, a lawsuit wasgroup of lawsuits were filed in the U.S. District Court of Idaho challengingfederal court to challenge the BLM's sage grouse resource management and land use plan revisions that became effective in 2015 under the Federal Land Policy and Management Act. The lawsuit challengeslawsuits challenge the plans and associated EISs across the sage grouse range, including in Idaho and allegesNorth Dakota, and allege 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 challengeslawsuits challenge certain exemptions provided for the Boardman-to-Hemingway and Gateway West transmission line projects. Idaho Power has intervened in the proceedings in an effort to support the exemptions provided for in the BLM's plans. If the exemptions are overturned, Idaho Power may be required to re-route the projects, which could lead to substantially higher construction and permitting costs and could delay construction.

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

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 issuedFollowing a recordseries of decision for six EISs that modified the 2015 sage grouse plans to better align the plan with state plans, conservationinterim 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,February 2022, the BLM issued a notice of intent to address the management ofamend its land use plans regarding sage grouse conservation and sagebrush habitat on BLM-managed public lands in Idaho and Oregon, among other states, through a land use planning initiative. The BLM indicated that it will prepare an EIS to support the planning initiative, and will begin the scoping process to solicitassociated EISs, soliciting public comments on the planning initiative by February 2022.initiative. It is unclear when the BLM will issue the applicable draft land use plan amendments and associated EISs.

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.

Migratory Bird Treaty Act Matters: In October 2021, also in response to the January 2021 Executive Orders, the USFWS announced that it revoked the previous Presidential Administration's interpretation of the Migratory Bird Treaty Act (MBTA) and implemented a new rule that reinstates the USFWS long-standing interpretation of the MBTA prohibiting the incidental take of migratory birds. Concurrently, the USFWS published an advanced notice of proposed rulemaking to determine whether and under what circumstances it could authorize incidental take. Similar to the changes in the ESA regulations described above in this MD&A, these MBTA regulations could impact the timing and feasibility of the Gateway West and Boardman-to-Hemingway transmission projects and other infrastructure projects that may interfere with migratory birds in the vicinity of such projects, which could lead to substantially higher construction, permitting, and licensing costs and could delay construction.

71
Table of Contents
ESA Issues Related to Specific Projects:

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. Idaho Power expectsIn June 2022, the FERC issued a notice of intent to initiate formal ESAprepare a draft supplemental EIS and a final supplemental EIS in accordance with NEPA. The FERC also reinstated informal consultation with the USFWS and the NMFS. At the conclusion of formal consultation and with the issuance of biological opinions by the NMFS and the USFWS and an operating license by the FERC, Idaho Power may be required to implement additional measures or further modify or adjust operations to comply with Sectionunder section 7 of the ESA. The issuanceAs of the date of this report, Idaho Power anticipates that the final biological opinions will likely be issued after the FERC issues a final biological opinion during 2022supplemental EIS, which is unlikely.scheduled for November 2024 according to the FERC's revised notice of intent.

Gateway West and Boardman-to-Hemingway Transmission Projects and Other Infrastructure - Slickspot Peppergrass and Washington Ground Squirrel DesignationsDesignation: In August 2016, the USFWS re-instated the threatened species status of slickspot peppergrass under the ESA. In July 2020, the USFWS published a revised proposed rule designating critical habitat for the species, most of which are located on federal land. Idaho Power expects the listing of the slickspot peppergrass and its existence within or near the proposed route for the Gateway West transmission line project and other transmission and distribution lines to increase the cost and timing of permitting and construction of the projects, as it requires an ESA Section 7 consultation and potential mitigation. As of the date of this report, Idaho Power is uncertain whether such increases will be significant.

The Washington ground squirrel inhabits various locations throughout two of the counties within the proposed routes for Boardman-to-Hemingway. It is not listed under the federal ESA, but it is considered endangered under Oregon law and the Boardman-to-Hemingway project will need to avoid ground squirrel colonies during construction. If colonies are found within the proposed site boundary during pre-construction surveys, re-siting the transmission would require additional permitting and would likely involve increased permitting costs and could further delay the in-service date of the project.National Environmental Policy Act Matters

Lower Snake River Hydroelectric Projects: In May 2016, the United States District Court for the District of Oregon issued an opinion findingNEPA is a federal law that in the context of hydropower facilities owned and operated by the U.S. Army Corps of Engineers (USACE) and located on the lower Snake River, National Oceanic and Atmospheric Administration's National Marine Fisheries Service (NOAA Fisheries) violated the ESA by using improper standards, failingrequires federal agencies to consider adequately the impactenvironmental impacts of climate change on habitat conditions,their actions and placing undue reliance on unproven, future federal habitat conservation measures, particularly to the degree that the success of the measures could be undermined by climate change. The court also found that other federal agencies violated the NEPA by failing to prepare a comprehensive EIS on implementation of the conservation measures ordered by NOAA Fisheries, including analysis of the measures directed by NOAA Fisheries and other reasonable alternatives. The court’s opinion and its emphasis on a climate change-driven analysis element, if generalized to other situations, could require ESA-driven avoidance, minimization, and compensatory mitigation efforts to incorporate surplus measures to ensure species’ protection, which could result in considerable increases in cost beyond the cost of additional analysis in the NEPA process. In September 2016, federal agencies initiated an EIS to examine hydropower dams on the lower Snake River. In September 2020, the federal agencies signed a record of decision on the EIS that will guide the operation of those dams and may expedite projects and reduce the number of actions subject to NEPA review. None of Idaho Power’s hydropower facilities are included in the studies.

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.decisions. 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,In April 2022, the current Presidential Administration’s CEQ was tasked with reviewing the 2020 NEPA Rule. In October 2021, the CEQCouncil on Environmental Quality (CEQ) published a noticefinal rule that restores a prior NEPA requirement, eliminated under the previous Administration, that federal agencies consider all indirect and cumulative environmental impacts of proposed rulemaking to reverse the more narrow 2020 NEPA Rule, with minor modifications,infrastructure projects in their decision-making, among other things, which if promulgated as proposed could delay and increase the cost of Idaho Power’s transmissioninfrastructure projects. TheIn July 2023 the CEQ proposed rule’s focus on restoring consideration of indirect and cumulative environmental impacts of infrastructure projects could result in federal agencies giving greater consideration to climate change and environmental justice-related impacts in their decision-making. The proposed rule was subject to a comment period that expired in November 2021. As of the date of this report, the proposed rule is still pending.

7266
Table of Contents                              
second round of NEPA reform to revise regulations for implementing NEPA. Key changes in the Phase 2 rule relate to the definition of “reasonably foreseeable effects,” how the agency interprets a reasonable range of alternatives, what constitutes a major federal action, and the incorporation of environmental justice into the NEPA analysis. The CEQ is now working on finalizing the rule.

Climate Change and the Regulation of Greenhouse Gas Emissions

Overview: Long-termOngoing climate change could significantly affect Idaho Power's business in a variety of ways, including:

•changes in temperature and precipitation could affect customer demand for electric power;
•extreme weather events, wildfires, drought, and other natural phenomena and natural disasters could increase service interruptions, outages, maintenance costs, system damage, personal property damage, personal injuries and loss of life, legal liability, and the need for additional backup systems, and can affect the supply of, and demand for, electricity and natural gas, which may impact the price of those and other commodities;
•changes in the amount and timing of snowpack and other precipitation and stream flows could affect hydropower generation;
•legislative and/or regulatory developments related to climate change could affect power/generation plants and operations, including restrictions on the construction or addition of new power supply resources, the expansion of existing resources, or the operation of power supply resources; and
•consumer preference for, and resource planning decisions requiring, renewable or low GHG-emitting sources of energy could impact usage of existing generation sources and require significant investment in new generation and transmission infrastructure.

Federal and state regulations pertaining to GHG emissions under the CAA have raised uncertainty about the future viability of fossil fuels, most notably coal, as an economical energy source for new and existing electric generation facilities because many new technologies for reducing carbon dioxide (COCO2) emissions from coal, including carbon capture and storage, are still in the development stage and are not yet proven.proven. Stringent emissions standards could result in significant increases in capital expenditures and operating costs, which may accelerate the retirement of coal-fired units and create power system reliability issues. 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, particularly in light of continued low natural gas prices that decrease the cost to operate natural gas-fired power plants. As a result, Idaho Power ended its participation in coal-fired operations at the Boardman power plant in October 2020 and the North Valmy plant unit 1 in December 2019. Idaho Power's 2023 IRP identifies a preferred resource portfolio and plans to end its participation in theaction plan that anticipates (1) converting North Valmy plant unitunits 1 and 2 no later thanto natural gas by summer 2026; (2) converting units 1 and 2 at the end of 2025. Idaho Power's 2021 IRP contemplates the conversionJim Bridger plant from coal to natural gas of twoin 2024; and (3) converting units 3 and 4 at the Jim Bridger plant from coal to natural gas in 2024 and an end to Idaho Power's participation in the remaining two coal-fired units at the Jim Bridger plant by the end of 2028. As discussed above in the "Regulatory Matters" section of this MD&A, as of the date of this report, discussions among the IPUC Staff, Idaho Power, and the co-owner regarding this potential conversion and the environmental regulations related to the Jim Bridger plant are ongoing.2030.

A variety of factors contribute to the financial, regulatory, and logistical uncertainties related to GHG reductions. These include the specific GHG emissions limits imposed, the timing of implementation of these limits, the level of emissions allowances allocated and the level that must be purchased, the purchase price of emissions allowances, the development and commercial availability of technologies for renewable energy and for the reduction of emissions, the degree to which offsets may be used for compliance, provisions for cost containment (if any), the impact on coal and natural gas prices, and the timing and amount of cost recovery through rates. Accordingly, Idaho Power cannot predict the effect on its results of operations, financial condition, or cash flows of any GHG emissionemissions or other climate change requirements that may be adopted, although the costs to implement and comply with any such requirements could be substantial. A more detailed discussion of legislative and regulatory developments related to climate change follows.

National GHG Initiatives; Clean Power Plan/Affordable Clean Energy Rule: The EPA has been active in the regulation of GHGs. The EPA's endangerment finding in 2009 that GHGs threaten public health and welfare resulted in the enactment of a series of EPA regulations to address GHG emissions.

In May 2010, the EPA issued the “Tailoring Rule,” which set thresholds for GHG emissions that define when permits are required for new and existing industrial facilities. While the rule is complex, Idaho Power believes that its owned and co-owned fossil fuel-fired generation plants are, as of the date of this report, in compliance with the GHG Tailoring Rule.

In August 2015, the EPA promulgatedissued the Clean Power Plan (CPP) under Section 111(d) of the CAA, which required states to adopt plans to collectively reduce 2005 levels of power sector CO2 emissions by 32 percent by the year 2030. In June 2019, the EPA releasedrepealed the CPP and replaced it with the Affordable Clean Energy (ACE) rule to replace the CPP under Section 111(d) of the CAA for existing electric utility generating units. In January 2021, the U.S. Court of Appeals for the District of Columbia Circuit vacated the ACE rule in its entirety and directed the EPA to create a new regulatory approach. In February 2021, the EPA issued a memorandum notifying states that it will not require states to submit plans to the EPA under Section 111(d) of the CAA because the Court
7367
Table of Contents                              
vacatedelectric utility generating units. In subsequent litigation, the ACE rule was vacated without reinstating the CPP.CPP and the case is pending further legal proceedings.

In May 2023, the EPA released a proposed rule under Section 111 of the CAA to regulate GHG emissions from fossil fuel-fired power plants. The proposed rule would impose significant GHG emissions reductions on new and existing natural gas-fired generating units and coal plants expected to be operational in 2040 and beyond. The proposed rule would require states to submit plans to the EPA to implement standards for existing sources within 24 months of the effective date of the emission guidelines. In August 2023, Idaho Power submitted comments to the EPA requesting it to maintain certain jurisdictional limits published in the rule and create flexibility for state plans to account for system reliability. In November 2023, the EPA finalized a portion of the Section 111 rule related to existing fossil fuel-fired power plants, but deferred action on new sources, pending additional comments and information related to reliability. As of the date of this report, Idaho Power expectscontinues to continue withevaluate the specific impacts the rule could have on its planned retirementsoperations at its three natural gas facilities, as well as the North Valmy and other planned upgrades at generating facilities.Jim Bridger plants. Idaho Power anticipates that the GHG emissions reductions may under certain circumstances only be achievable by reducing unit runtimes.

State GHG Initiatives and Idaho Power’s Voluntary GHG Reduction Initiative: In August 2007, the Oregon legislature enacted legislation setting goals of reducing GHG levels to 10 percent below 1990 levels by 2020 and at least 75 percent below 1990 levels by 2050. Oregon imposes GHG emission reporting requirements on facilities emitting 2,500 metric tons or more of CO2 equivalent annually. The Boardman power plant located in Oregon, in which Idaho Power was a 10-percent owner, was subject to and in compliance with Oregon's GHG reporting requirements but ceased coal-fired operations in 2020.

In Oregon, legislation referred to as thealso established its Oregon Clean Electricity and Coal Transition Plan was enacted in March 2016, andwhich requires certain Oregon utilities to remove coal-fired generation from their Oregon retail rates by 2030. Oregon utilities would be permitted to sell the output of coal-fired plants into the wholesale market or reallocate such plants to other states. To the extent Idaho Power is subject to the legislation, it plans to seek recovery, through the ratemaking process, of operating and capitalized costs related to its coal-fired generation assets and removal of any of those assets from Oregon rate base.

The State of Idaho has not passed legislation specifically regulating GHGs. Wyoming and Nevada similarly have not enacted legislation to regulate GHG emissions and do not have a reporting requirement, but they are members of the Climate Registry, a national, voluntary GHG emissions reporting system.Registry. The Climate Registry is a voluntary collaboration aimed at developing and managing a common GHG emissions reporting system across states, provinces, and tribes to track GHG emissions nationally. All states for which Idaho Power has traditional fuel generating plants (i.e. Idaho, Oregon, Wyoming, and Nevada) are members of the Climate Registry. Idaho Power is engaged in voluntary GHG emissions intensity reduction efforts, which is discussed in Part I, Item 1 - “Business - Utility Operations - Environmental Regulation and Costs."

Other Clean Air Act Matters

Overview:In addition to the CAA developments related to GHG emissions described above, several other regulatory programs developed under the CAA apply to Idaho Power. These include the final Mercury and Air Toxics Standards (MATS), National Ambient Air Quality Standards (NAAQS),MATS, NAAQS, New Source Review / Prevention of Significant Deterioration Rules, and the Regional Haze Rule.

MATS Implementation:The final MATS rule under the CAA previously referred to as the Utility Maximum Achievable Control Technology Rule, was issued in February 2012. The final rule established emission limits for hazardous air pollutants from new and existing coal-fired and oil-fired steam electric generating units. The MATS rule providedprovides that sources must be in compliancecomply with emission limits by April 2015. Idaho Power and the plant co-owners of Jim Bridger and North Valmy coal-fired generating plants have installed mercury continuous emission monitoring systems on all of the coal-fired units at the Jim Bridger and North Valmy coal-fired generating plants, along with control technology to reduce mercury, acid gases, and particulate matter emissions for purposes of compliance with the MATS rule. Legal challenges relating to the MATS rule, to which Idaho Power is not a party and pursuant to which the EPA is performing a court-mandated cost analysis for the rule, are pending. In August 2018, the EPA began reconsidering the justification behind the MATS rule and reviewing the regulations emissions standards. In December 2018, the EPA determined that it is not appropriate and necessary to regulate hazardous air pollutant emissions from power plants under Section 112 of the CAA. The emissions standards and other requirements of the MATS rule, however, remain in place. Idaho Power believes that as of the date of this report, its jointly-owned coal-fired plants are in compliance with the MATS rule, which does not significantly impact Idaho Power’s operations or financial results.rule.

National Ambient Air Quality Standards: The CAA requires the EPA to set ambient air quality standards for six "criteria" pollutants considered harmful to public health and the environment. These six pollutants are carbon monoxide, lead, ozone, particulate matter, nitrogen dioxide, (NOand SO2), and sulfur dioxide (SO2). States are then required to develop emissions reduction strategies through State Implementation Plans, or SIPs, based on attainment of these ambient air quality standards. Recent developments and pending actions related to certain of those items are relevant to Idaho Power include the following:

•NO2:In 2010, the EPA adopted a new NAAQS for NO2 at a level of 100 parts per billion averaged over a one-hour period. In connection with the new NAAQS, in February 2012 the EPA issued a final rule designating all of the counties in Idaho, Nevada, and Wyoming where Idaho Power owns or has an interest in a natural gas or coal-fired power plantPower. However, as “unclassifiable/attainment” for NO2.

•SO2: In 2010, the EPA adopted a new NAAQS for SO2 at a level of 75 parts per billion averaged over a one-hour period. In 2011, the states of Idaho, Nevada, Oregon, and Wyoming sent letters to the EPA recommending that all counties in these states be classified as "unclassifiable" under the new one-hour SO2 NAAQS because of a lack of
74
Table of Contents
definitive monitoring and modeling data. In February 2013, the EPA issued letters to the states of Idaho and Oregon, finding that the most recent air quality data for those states showed no violations of the 2010 SO2 standard. Since January 2018, the EPA has finalized designations of “unclassifiable/attainment” for SO2 for all areas in which Idaho Power owns or has an interest in a natural gas or coal-fired power plant.

•Ozone: In late 2014, the EPA issued a proposed rule that would update the ozone standard under the CAA, from 75 parts per billion over an eight-hour period to 65 to 70 parts per billion over an eight-hour period. In October 2015, the EPA issued a final rule lowering the national ozone standard under the CAA to 70 parts per billion. The EPA stated that the vast majority of United States counties will meet the standards by 2025 with federal and state rules and programs now in place or underway. Since January 2018, the EPA has finalized designations for all of the counties in which Idaho Power owns or has an interest in a natural gas or coal-fired power plant and determined that they meet the standard.

As of the date of this report, and based on the EPA designations described above, Idaho Power does not expect these standardsthe recent changes in the NAAQS to significantly impact its operations or materially increase Idaho Power’s capital and operating costs.

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.plant, which are subject to regulation by both EPA and WDEQ.

In December 2009,June 2023, the WDEQ issued a RH BART permitEPA published the final rule under the CAA called the Federal "Good Neighbor Plan" for the 2015 Ozone NAAQS (Good Neighbor Plan), which took effect on August 4, 2023. The Good Neighbor Plan establishes NOx emissions budgets requiring fossil fuel-fired power plants to PacifiCorp asparticipate in an allowance-based ozone season trading program. The EPA's final rule temporarily excluded power plants located in Wyoming, while the operatorEPA reevaluated the proposed disapproval of the Jim Bridger plant. As part
68
Table of the WDEQ's long term strategy for regional haze, the permit required that PacifiCorp install selective catalytic reduction equipment for nitrogen oxide (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 NOxContents                              controls at Jim Bridger unit 2 by 2021 and unit 1 by 2022, which was submitted in December 2017.
Wyoming SIP. In November 2010, PacifiCorp and the WDEQ signed a settlement agreement under which PacifiCorp agreed to the timing and nature of the controls. The settlement agreement was conditioned onAugust 2023, the EPA ultimately approving those portionspublished a proposed approval of the Wyoming regional haze state implementation plan (SIP)SIP, finding that the EPA’s updated modeling demonstrated that Wyoming’s determination that no additional controls are consistent withrequired to address interstate transport for the terms2015 zone NAAQSs was reasonable. In December 2023, the EPA finalized the approval of the settlement agreement. In January 2014,Wyoming SIP, removing it from the EPA approved Wyoming's regional hazefederal implementation plan. The Wyoming SIP as to the Jim Bridger plant, with the NOx control compliance dates set forth in the settlement agreement.

In February 2019, PacifiCorp submitted a SIP revision to the WDEQ as an alternative regional haze compliance plandoes not have additional requirements for the Jim Bridger plant that includes a reduced plant-wide monthly limit on emissions for NOx and SO2 and an annual total emissions cap for NOx and SO2 for units 1-4. facility under the Good Neighbor Plan.
In May 2020,July 2023, the WDEQ approved the alternative plan as proposed, which would eliminate the requirement to install add-on NOx controls at Jim Bridger units 1 and 2. In September 2021, PacifiCorp submitted its IRP to the IPUC that contemplates ceasing coal-fired generation in units 1 and 2 in 2023 and converting those units to natural gas generation by 2024. In late-2021, the StateNinth Circuit Court of Wyoming and PacifiCorpAppeals issued a Noticestay halting application of Intent to sue the EPA for the EPA’s failure to actGood Neighbor Plan in Nevada pending a hearing on the 2019 proposed SIP revision. The Noticemerits of Intent was intended to allow PacifiCorp and Wyoming to bring a non-delegable duty suit againstan appeal challenging the EPA. On December 27, 2021, Wyoming Governor Gordon issued a temporary emergency suspensionEPA's disapproval of Wyoming’s existing SIP that allows Jim Bridger unit 2 to continue to operate throughNevada's SIP. In light of the end of April 2022. On January 12, 2022,court's ruling, in September 2023, the EPA issued a proposedan interim final rule that, if adopted, would disapproveindefinitely suspending the 2019 proposed SIP revision, and the proposed rule was published in the Federal Register on January 18, 2022. Comments on the proposed disapproval are due by February 17, 2022, and asimplementation of the date of this report, the proposed EPA rule is pending. On February 14, 2022, the State of Wyoming filed a complaint against PacifiCorp as well as a negotiated consent decree with PacifiCorpGood Neighbor Plan in Wyoming state court for the threat of non-compliant operation of Jim Bridger units 1 and 2. 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.Nevada. As of the date of this report, Idaho Power continues to evaluate the revised permit application and RFP are pending.specific impacts the Good Neighbor Plan could have on its operations at the North Valmy plant. If the Good Neighbor Plan is implemented in Nevada, Idaho Power anticipates that, under certain conditions, it could reduce the ability to use the full available output, or require the purchase of allowances in order to utilize the full available output, at the North Valmy plant during the EPA defined ozone season (May through September).

Clean Water Act Matters

Definition of “Waters of the United States” Under the CWA: In August 2015, the EPA and USACE final rule defining the phrase "waters of the United States" (WOTUS) under the CWA became effective (WOTUS 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 part of the final rule to replace the WOTUS Rule
75
Table of Contents
with the "Navigable Waters Protection Rule" that provides a final definition of "waters of the United States," which ultimately narrowsStates" is fundamental to the scopeapplication of waters subject to federal regulationthe CWA because only those bodies of water designated as WOTUS are protected from unlawful discharge of pollutants under the CWA. In May 2023, the U.S. Supreme Court issued a decision defining WOTUS under the CWA and providing nationwide clarity of the federal government’s jurisdiction over WOTUS. The Navigable Waters Protection Rule became effectivedecision restricts the federal government's ability to regulate wetlands that do not have a continuous surface connection with a navigable water. While not addressed in June 2020. In November 2021, in response to the January 2021 Executive Orders,opinion, ephemeral streams and other water bodies that are not relatively permanent would also not be jurisdictional under the EPA and USACE announced the availability of a pre-publication version of a proposed rule that restores the protections in place prior to the WOTUS Rule and establishes aMay 2023 decision. The new expansive definition of "waters ofWOTUS from the United States."

Idaho Power believesSupreme Court should not alter how the repeal rule, the WOTUS Rule, the Navigable Waters Protection Rule, and the proposed new rule will continue to be challenged in court, but expects that, even if the WOTUS Rule is reinstated in Idaho or the expansive proposed new rule is enacted 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,plants. As a result, Idaho Power does not expect reinstatement would have a materialthe new definition to materially 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, 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 third parties. Idaho Power intervened in one of those lawsuits and is closely monitoring the other. 2019. In December 2019,September 2023, Idaho Power filed an Offer of Settlementa water quality certification application with Idaho for the American Falls facility, that is pending 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.IDEQ.

In July 2020, the EPA published a rule amending regulations intended to implement the CWA Section 401 water quality certification process. The rule clarifies thathas been subject to various legal challenges. In September 2023, the EPA finalized 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 became effective in September 2020 (2020 CWA Section 401 Order). In October 2021, the U.S. District Court for the Northern District of California issued an order remandingWater Quality Certification Rule and vacatingrepealed 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 effect since 1979. While the EPA finalizes a new certification rule, Idaho Power plans to continue to operate under the current CWA Section 401 regulations as described above.rule.

Idaho Power expects the EPA to expandThe EPA’s new rule expands state and tribal authority over water quality certifications; however, such expanded authority wouldwill not likely impact the timing and cost of the HCC certification unlessunder the FERC declines to adopt the Offer of Settlement, in which casecurrent approval process. Idaho Power would fileis still evaluating the impact the new water quality certification applications in Idaho and Oregon with revisions necessary to address changes torule will have on the regulations, which Idaho Power cannot currently predict and could delay the timing of issuance and increase the cost of obtaining a license for the HCC.American Falls application.

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),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, but as of the date of this report, Idaho Power is unable to estimate with any reasonable certainty those costs and expenses.costs. Idaho Power also expects to incur additional expensescosts associated with the relicensing of its hydroelectrichydropower facilities, as discussed elsewhere in this report.

In June 2022, Idaho Power and the IDEQ entered into a consent judgment in the Idaho state district courts to resolve a National Pollutant Discharge Elimination System permitting issue related to 15 of Idaho Power’s hydropower projects that required 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 of law, the EPA cancelled water discharge permits in the mid-1990’s, which Idaho Power subsequently determined were applicable for operation of the dams. Idaho Power believes that the dams would have been in compliance with the earlier permits had they remained in place. As of the date of this report, Idaho Power has submitted new permit applications for twelve of the dams and anticipates completing all submissions by June 2024.

7669
Table of Contents                              
Invasive Species Management

Quagga mussels are an invasive species which have not been present in the Snake River system historically. Quagga mussel infestations can foul up irrigation, hydropower, and water delivery facilities and increase the costs to maintain such facilities. In September 2023, a larval form of quagga mussels and one adult quagga mussel were detected in the mid-Snake River near Twin Falls in Idaho Power's service area by the Idaho State Department of Agriculture (ISDA). As a result, in October 2023, ISDA treated approximately six miles of the Snake River, which includes Idaho Power's Twin Falls and Shoshone Falls hydropower facilities, using a copper-based, EPA-approved treatment called Natrix to eradicate quagga mussels. Initial ISDA sample results indicated that the treatment impacted larvae and adult quagga mussel populations. However, it is premature to conclude complete eradication at this stage. The ISDA will resume sampling in spring 2024 once water temperatures warm. The ISDA expects to implement ongoing surveying to determine the success of treatment.

If the treatment was unsuccessful, and a quagga mussel infestation occurs, it may result in increased other O&M expenses for mitigation efforts and other adverse impacts for Idaho Power's operation of its hydropower facilities in any infested areas. As of the date of this report, Idaho Power cannot predict the extent to which the Natrix treatment will be successful in eradicating quagga mussels from the Snake River, the extent of the treatment’s impact to the river and its inhabitants, or the potential increase in other O&M expenses related to quagga mussel mitigation efforts.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES
 
When preparing financial statements in accordance with the accounting principles generally accepted in the United States of America (GAAP),GAAP, IDACORP’s and Idaho Power’s management must apply accounting policies and make estimates that affect the reported amounts of assets, liabilities, revenues, and expenses and related disclosures. These estimates often involve judgment about factors that are difficult to predict and are beyond management’s control. Management adjusts these estimates based on historical experience and on other assumptions and factors that are believed to be reasonable under the circumstances. Actual amounts could materially differ from the estimates. Management believes the accounting policies and estimates discussed below are the most critical to the portrayal of their financial condition and results of operations and require management’s most difficult, subjective, or complex judgments, often as a result of the need to make estimates about the effect of matters that are inherently uncertain and may change in subsequent periods.
 
Accounting for Rate Regulation

Entities that meet specific conditions are required by GAAP to reflect the impact of regulatory decisions in their consolidated financial statements and to defer certain costs as regulatory assets until matching revenues can be recognized. Similarly, certain items must be deferred as regulatory liabilities. Idaho Power must satisfy three conditions to apply regulatory accounting: (1) an independent regulator must set rates; (2) the regulator must set the rates to cover specific costs of delivering service; and (3) the service area must lack competitive pressures to reduce rates below the rates set by the regulator.
 
Idaho Power has determined that it meets these conditions, and its financial statements reflect the effects of the different rate-making principles followed by the jurisdictions regulating Idaho Power. The primary effect of this policy is that Idaho Power had recorded approximately $1.5$1.7 billion of regulatory assets and $0.8$0.9 billion of regulatory liabilities at December 31, 2021.2023. Idaho Power expects to recover these regulatory assets from customers through rates and refund these regulatory liabilities to customers through rates, but recovery or refund is subject to final review by the regulatory bodies. If future recovery or refund of these amounts ceases to be probable, or if Idaho Power determines that it no longer meets the criteria for applying regulatory accounting, or if accounting rules change to no longer provide for regulatory assets and liabilities, Idaho Power could be required to eliminate those regulatory assets or liabilities, which could have a material effect on Idaho Power’s financial condition or results of operations.

Refer to Note 3 - “Regulatory Matters” to the consolidated financial statements included in this report for additional information relating to regulatory matters.

Income Taxes

IDACORP and Idaho Power use judgment and estimation in developing the provision for income taxes and the reporting of tax-related assets and liabilities. The interpretation of tax laws can involve uncertainty, since tax authorities may interpret such laws differently. Actual income taxes could vary from estimated amounts and may result in favorable or unfavorable impacts to net income, cash flows, and tax-related assets and liabilities.
Idaho Power records deferred income taxes related to its plant assets for the difference between income tax depreciation and book depreciation used for financial statement purposes. Deferred income taxes for other items are recorded for the temporary differences between the income tax and financial accounting treatment of such items. Unless contrary to applicable income tax guidance, deferred income taxes are not recorded for those income tax temporary differences where the prescribed regulatory accounting methods, or flow-through, direct Idaho Power to recognize the tax impacts currently for rate making and financial reporting.

Refer to Note 1 - “Summary of Significant Accounting Policies” and Note 2 - “Income Taxes” to the consolidated financial statements included in this report for additional information relating to income taxes.

70
Table of Contents
Pension and Other Postretirement Benefits

Idaho Power maintains a tax-qualified, noncontributory defined benefit pension plan covering most employees, and two unfunded nonqualified deferred compensation plans for certain senior management employees and directors called the Security Plan for Senior Management Employees I and Security Plan for Senior Management Employees II, (together, SMSP), and a postretirement benefit plan (consisting of health care and death benefits).
 
77
Table of Contents
The costs IDACORP and Idaho Power record for these plans depend on the provisions of the plans, changing employee demographics, actual returns on plan assets, and several assumptions used in the actuarial valuations from which the expense is derived. The key actuarial assumptions that affect expense are the expected long-term return on plan assets and the discount rate used in determining future benefit obligations. Management evaluates the actuarial assumptions on an annual basis, taking into account changes in market conditions, trends, and future expectations. Estimates of future capital markets performance, changes in interest rates, and other factors used to develop the actuarial assumptions are uncertain, and actual results could vary significantly from the estimates.
 
The assumed discount rate is based on reviews of market yields on high-quality corporate debt. Specifically, IDACORP and Idaho Power determined the discount rate for each plan through the construction of hypothetical portfolios of bonds selected from high-quality corporate bonds available as of December 31, 2021,2023, with maturities matching the projected cash outflows of the plans. Based on the results of this analysis, the discount rate used to calculate the 20222024 defined benefit plan pension expense will be increaseddecreased to 3.055.10 percent from the 2.805.45 percent rate used in 2021.2023.

Rate-of-return projections for plan assets are based on historical risk/return relationships among asset classes. The primary measure is the historical risk premium each asset class has delivered versus the yield on the Moody's AA Corporate Bond Index. This historical risk premium is then added to the current yield on the Moody's AA Corporate Bond Index, and Idaho Power believes the result provides a reasonable prediction of future investment performance. Additional analysis is performed to measure the expected range of returns, as well as worst-case and best-case scenarios. Based on the current interest rate environment, current rate-of-return expectations are lower than the nominal returns generated over the past 20 years when interest rates were generally much higher. The long-term rate of return used to calculate the 20222024 pension expense will be 7.4 percent, the same assumption as used in 2021.2023.

Total net periodic pension and other postretirement benefit cost for these plans totaled $65.6$28.5 million and $53.8$42.3 million for the years ended December 31, 20212023 and 2020,2022, respectively, including amounts deferred as regulatory assets (see discussion below) and amounts allocated to capitalized labor. For 2022,2024, total net periodic pension costs and other postretirement benefit costs are expected to total approximately $45.4$26.3 million, which takes into account the change in the discount rate noted above.
 
Had different actuarial assumptions been used, net periodic pension costs and other postretirement benefit costs could have varied significantly. The following table reflects the sensitivities associated with changes in the discount rate and rate-of-return on plan assets actuarial assumptions on historical and future net periodic pension costs and other postretirement benefit costs:
Discount rateRate of return Discount rateRate of return
2022202120222021 2024202320242023
(millions of dollars) (millions of dollars)
Effect of 0.5% rate increase on total net periodic pension costs and other postretirement benefit costsEffect of 0.5% rate increase on total net periodic pension costs and other postretirement benefit costs$(10.9)$(10.7)$(5.0)$(4.6)
Effect of 0.5% rate decrease on total net periodic pension costs and other postretirement benefit costsEffect of 0.5% rate decrease on total net periodic pension costs and other postretirement benefit costs12.1 12.3 5.1 4.5 
 
Additionally, a 0.5 percent increase in the plans' discount rates would have resulted in a $119.4$76.2 million decrease in the combined benefit obligations of the plans as of December 31, 2021.2023. A 0.5 percent decrease in the plans' discount rates would have resulted in an $135.9$85.4 million increase in the combined benefit obligations of the plans as of December 31, 2021.2023.

The IPUC has authorized Idaho Power to account for its defined benefit pension plan expense on a cash basis, and to defer and account for accrued pension expense as a regulatory asset. The IPUC acknowledged that it is appropriate for Idaho Power to seek recovery in its revenue requirement of reasonable and prudently incurred pension expense based on actual cash contributions. In 2007, Idaho Power began deferring pension expense to a regulatory asset account to be matched with revenue when future pension contributions are recovered through rates. At December 31, 2021,2023, a total of $234$255 million of expense was deferred as a regulatory asset. Idaho Power expects to defernet amortization of the regulatory asset of approximately $16$19 million of expense in 2022.2024. Idaho Power recorded pension expense on its consolidated statements of income related to its tax-qualified defined benefit pension plan of approximately $18 million in 2023 and $19 million in 2021 and 2020.2022.
 
71
Table of Contents
Refer to Note 1211 – “Benefit Plans” to the consolidated financial statements included in this report for additional information relating to pension and postretirement benefit plans.

78
Table of Contents
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

There have been noFor discussion of new and recently issuedadopted accounting pronouncements, that have had or are expected to have a material impact on IDACORP's or Idaho Power's results of operations or financial condition. Seesee Note 1 - “Summary"Summary of Significant Accounting Policies”Policies" to the notes to the consolidated financial statements included in this report for a summary of significant accounting policies.report.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
 
IDACORP and Idaho Power are exposed to market risks, including changes in interest rates, changes in commodity prices, credit risk, and equity price risk. The following discussion summarizes these risks 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 December 31, 2021.2023. Neither IDACORP andnor Idaho Power have not entered into any of these market-risk-sensitive instruments for tradingspeculative purposes.
 
Interest Rate Risk
 
IDACORP and Idaho Power managemanages 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 December 31, 2021,2023, IDACORP and Idaho Power had no net floatingvariable rate debt, as the carrying value of short-term investments exceeded the carrying value of outstanding variable-rate debt. As of December 31, 2021, Idaho Power had $13.9 million of net floatingvariable rate debt. The fair market value of this debt was $13.9 million. Assuming no change in financial structure, if variable interest rates were to average one percentage point higher than the average rate on December 31, 2021, annual interest expense would increase and pre-tax earnings would decrease by approximately $0.1 million for Idaho Power.
 
Fixed Rate Debt: As of December 31, 2021,2023, both IDACORP and Idaho Power had $2.0$2.8 billion in fixed rate debt, with a fair market value of approximately $2.4$2.7 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 $234.7$343 million if market interest rates were to decline by one percentage point from their December 31, 20212023 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. To supplement its power supply resources and balance its supply of power with the demand of its retail customers, Idaho Power participates in the wholesale marketplace. Purchased power arrangements allow Idaho Power to respond to fluctuations in the demand for electricity and variability in generating plant operations. Idaho Power also enters into arrangements for the purchase of fuel for natural gas and coal-fired generating plants. These contracts for the purchase of power and fuel expose Idaho Power to commodity price risk. The effects of changes in commodity prices on Idaho PowerPower's net income are mitigated in large part by Idaho Power's Idaho and Oregon power cost adjustment mechanisms. However, collection from customers or return to customers of most of the difference between actual power supply costs compared with those included in retail rates is deferred to a subsequent period, which can affect Idaho Power’s operating cash flow and liquidity until those costs are recovered from or returned to customers.
 
A number of factors associated with the structure and operation of the energy markets influence the level and volatility of prices for energy commodities and related derivative products. The weather is a major uncontrollable factor affecting the local and regional demand for electricity and the availability and cost of power generation. Other factors include the occurrence and timing of demand peaks due to seasonal, daily, and hourly power demand; power supply; power transmission capacity; changes in federal and state regulation and compliance obligations; fuel supplies; and market liquidity.
 
The primary objectives of Idaho Power’s energy purchase and sale activity are to meet the demand of retail electric customers, to maintain appropriate physical reserves to ensure reliability, and to make economic use of temporary surpluses that may develop. Idaho Power has adopted an energy risk management program, whichoverseen by the risk management committee (RMC), and described in Idaho Power’s Energy Risk Management Policy and associated standards (ERMP). The ERMP has been reviewed and accepted by the IPUC, designed to reduce exposure to power supply cost-related uncertainty, further mitigating commodity price risk. Idaho Power’s Energy Risk Management Policy and associated standards implementing the Energy Risk Management Policy describe a collaborative process with customers and regulators via a committee called the Customer Advisory Group (CAG). The Risk Management Committee (RMC),RMC, composed of Idaho Power officers and senior managers, oversees the risk management program. The RMC is responsible for communicating the status of risk management activities to Idaho Power's Boardboard of Directors and to the CAG, and Idaho Power’s Audit Committee is responsible for approving the Energy Risk Management
79
Table of Contents
Policy and associated standards. The RMC is also responsible for conducting an ongoing general assessment of the appropriateness of Idaho Power’s strategies for energy risk management activities.directors. In its energy risk management process, Idaho Power considers both demand-side and supply-side options consistent with its IRP. The primary tools for risk mitigation are physical and financial forward power transactions and fueling alternatives
72
Table of Contents
for utility-owned generation resources. Idaho Power only engages in a nominal amount of trading activity for non-retail purposes.
 
The Energy Risk Management Policy and associated standardsERMP require monitoring monthly volumetric electricity position and total monthly dollar (net power supply cost) exposure on a rolling 18-month forward view. The power supply business unit produces and evaluates projections of the operating plan based on factors such as forecasted resource availability, stream flows, and load, and orders risk mitigating actions, including resource optimization and hedging strategies, dictated by the limits stated in the Energy Risk Management Policy and associated standardsERMP to bring exposures within pre-established risk guidelines. The RMC evaluates the actions initiated by the power supply unit for consistency and compliance with the Risk Management Policy and associated standards. Idaho Power representatives meet with the CAG at least annually to assess effectiveness of the limits. Changes to the limits can be endorsed by the CAG and referred to the board of directors for approval.ERMP.

Credit Risk
 
IDACORP is subject to credit risk based on Idaho Power's activity with market counterparties. Idaho Power is exposed to this risk to the extent that a counterparty may fail to fulfill a contractual obligation to provide energy, purchase energy, or complete financial settlement for market activities. Idaho Power mitigates this exposure by actively establishing credit limits; measuring, monitoring, and reporting credit risk using appropriate contractual arrangements; and transferring of credit risk through the use of financial guarantees, cash, or letters of credit. Idaho Power maintains a current list of acceptable counterparties and credit limits.
 
The use of performance assurance collateral in the form of cash, letters of credit, or guarantees is common industry practice. Idaho Power maintains margin agreements relating to its wholesale commodity contracts that allow performance assurance collateral to be requested of and/or posted with certain counterparties. As of December 31, 2021,2023, Idaho Power had noposted $53 million of performance assurance collateral posted 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 then existing market conditions as of December 31, 2021,2023, the amount of additional collateral that could behave been requested upon a downgrade to below investment grade was approximately $25.7$23 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.
 
Idaho Power is obligated to provide service to all electric customers within its service area. Credit risk for Idaho Power’s retail customers is managed by credit and collection policies that are governed by rules issued by the IPUC or OPUC. Idaho Power records a provision for uncollectible accounts, based upon historical experience, to provide for the potential loss from nonpayment by these customers. Idaho Power continuously monitors levels of nonpayment from customers and makes any necessary adjustments to its provision for uncollectible accounts accordingly.
 
Idaho utility customer relations rules prohibit Idaho Power from terminating electric service during the months of December through February to any residential customer who declares that he or she is unable to pay in full for utility service and whose household includes children, elderly, or infirm persons. Idaho Power’s provision for uncollectible accounts could be affected by changes in future prices as well as changes in IPUC or OPUC regulations.

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 1211 - "Benefit Plans" to the consolidated financial statements included in this report.

8073
Table of Contents                              

ITEM 8. FINANCIAL STATEMENTS

Index to Financial Statements and Financial Statement Schedules

Consolidated Financial StatementsPage
IDACORP, Inc.: 
Consolidated Statements of Income
8275
Consolidated Statements of Comprehensive Income
8376
Consolidated Balance Sheets
8477
Consolidated Statements of Cash Flows
8679
Consolidated Statements of Equity
8780
Idaho Power Company: 
Consolidated Statements of Income
8881
Consolidated Statements of Comprehensive Income
8982
Consolidated Balance Sheets
9083
Consolidated Statements of Cash Flows
9285
Consolidated Statements of Retained Earnings
9386
Notes to the Consolidated Financial Statements
9487
Reports of Independent Registered Public Accounting Firm - Deloitte & Touche LLP (PCAOB ID No. 34)
133128
 
Financial Statement Schedules
IDACORP, Inc. - Schedule I - Condensed Financial Information of Registrant
150144
IDACORP, Inc. and Idaho Power Company - Schedule II - Consolidated Valuation and Qualifying Accounts
152146

All other schedules have been omitted because they are not required, not applicable, or the required information is otherwise included.
8174
Table of Contents                              


IDACORP, Inc.
Consolidated Statements of Income

Year Ended December 31,Year Ended December 31,
Year Ended December 31, 202320222021
202120202019
(thousands of dollars except for per share amounts)
(thousands of dollars except for per share amounts)(thousands of dollars except for per share amounts)
Operating Revenues:Operating Revenues:
Electric utility revenues
Electric utility revenues
Electric utility revenuesElectric utility revenues$1,455,410 $1,347,340 $1,342,940 
OtherOther2,674 3,389 3,443 
Total operating revenuesTotal operating revenues1,458,084 1,350,729 1,346,383 
Operating Expenses:Operating Expenses:
Operating Expenses:
Operating Expenses:
Electric utility:Electric utility:
Electric utility:
Electric utility:
Purchased power
Purchased power
Purchased powerPurchased power393,691 297,417 285,266 
Fuel expenseFuel expense180,550 172,740 156,872 
Power cost adjustmentPower cost adjustment(49,844)(33,708)2,047 
Other operations and maintenanceOther operations and maintenance361,297 352,071 355,770 
Energy efficiency programsEnergy efficiency programs29,920 42,478 40,128 
DepreciationDepreciation175,555 171,648 169,210 
Other electric utility operating expensesOther electric utility operating expenses34,673 35,914 35,995 
Total electric utility expensesTotal electric utility expenses1,125,842 1,038,560 1,045,288 
OtherOther2,591 2,648 2,769 
Total operating expensesTotal operating expenses1,128,433 1,041,208 1,048,057 
Operating IncomeOperating Income329,651 309,521 298,326 
Operating Income
Operating Income
Nonoperating (Income) Expense:Nonoperating (Income) Expense:
Nonoperating (Income) Expense:
Nonoperating (Income) Expense:
Allowance for equity funds used during construction
Allowance for equity funds used during construction
Allowance for equity funds used during constructionAllowance for equity funds used during construction(31,537)(29,551)(27,112)
Earnings of unconsolidated equity-method investmentsEarnings of unconsolidated equity-method investments(11,435)(11,513)(12,370)
Interest on long-term debtInterest on long-term debt84,145 84,251 82,457 
Other interestOther interest14,546 14,753 14,721 
Allowance for borrowed funds used during constructionAllowance for borrowed funds used during construction(11,993)(11,578)(10,703)
Other (income) expense, netOther (income) expense, net3,141 (3,509)(6,502)
Total nonoperating expense, netTotal nonoperating expense, net46,867 42,853 40,491 
Income Before Income TaxesIncome Before Income Taxes282,784 266,668 257,835 
Income Before Income Taxes
Income Before Income Taxes
Income Tax ExpenseIncome Tax Expense36,912 28,700 24,507 
Income Tax Expense
Income Tax Expense
Net Income
Net Income
Net IncomeNet Income245,872 237,968 233,328 
Adjustment for income attributable to noncontrolling interestsAdjustment for income attributable to noncontrolling interests(322)(551)(474)
Net Income Attributable to IDACORP, Inc.Net Income Attributable to IDACORP, Inc.$245,550 $237,417 $232,854 
Weighted Average Common Shares Outstanding - Basic (000’s)Weighted Average Common Shares Outstanding - Basic (000’s)50,599 50,538 50,502 
Weighted Average Common Shares Outstanding - Basic (000’s)
Weighted Average Common Shares Outstanding - Basic (000’s)
Weighted Average Common Shares Outstanding - Diluted (000’s)Weighted Average Common Shares Outstanding - Diluted (000’s)50,645 50,572 50,537 
Earnings Per Share of Common Stock:Earnings Per Share of Common Stock:
Earnings Attributable to IDACORP, Inc. - BasicEarnings Attributable to IDACORP, Inc. - Basic$4.85 $4.70 $4.61 
Earnings Attributable to IDACORP, Inc. - Basic
Earnings Attributable to IDACORP, Inc. - Basic
Earnings Attributable to IDACORP, Inc. - DilutedEarnings Attributable to IDACORP, Inc. - Diluted$4.85 $4.69 $4.61 

The accompanying notes are an integral part of these statements.
8275
Table of Contents                              
IDACORP, Inc.
Consolidated Statements of Comprehensive Income
 
Year Ended December 31,Year Ended December 31,
Year Ended December 31, 202320222021
(thousands of dollars)(thousands of dollars)
202120202019
(thousands of dollars)
Net Income
Net Income
Net IncomeNet Income$245,872 $237,968 $233,328 
Other Comprehensive Income:Other Comprehensive Income:
Unfunded pension liability adjustment, net of tax
of $1,150, $(2,452), and $(4,658)
3,318 (7,074)(13,440)
Unfunded pension liability adjustment, net of tax
of $(1,477), $9,399, and $1,150
Unfunded pension liability adjustment, net of tax
of $(1,477), $9,399, and $1,150
Unfunded pension liability adjustment, net of tax
of $(1,477), $9,399, and $1,150
Total Comprehensive Income
Total Comprehensive Income
Total Comprehensive IncomeTotal Comprehensive Income249,190 230,894 219,888 
Comprehensive income attributable to noncontrolling interestsComprehensive income attributable to noncontrolling interests(322)(551)(474)
Comprehensive Income Attributable to IDACORP, Inc.Comprehensive Income Attributable to IDACORP, Inc.$248,868 $230,343 $219,414 

The accompanying notes are an integral part of these statements.
 
 

8376
Table of Contents                              
IDACORP, Inc.
Consolidated Balance Sheets
 
December 31,
20212020
(in thousands)
December 31,December 31,
202320232022
(in thousands)(in thousands)
AssetsAssets
Current Assets:Current Assets:
Current Assets:
Current Assets:
Cash and cash equivalentsCash and cash equivalents$215,243 $275,116 
Short-term investments— 25,000 
Cash and cash equivalents
Cash and cash equivalents
Receivables:Receivables:
Customer (net of allowance of $4,499 and $4,766, respectively)78,819 72,826 
Other (net of allowance of $517 and $497, respectively)14,994 12,661 
Receivables:
Receivables:
Customer (net of allowance of $4,869 and $5,034, respectively)
Customer (net of allowance of $4,869 and $5,034, respectively)
Customer (net of allowance of $4,869 and $5,034, respectively)
Other (net of allowance of $716 and $512, respectively)
Income taxes receivableIncome taxes receivable14,770 2,164 
Accrued unbilled revenuesAccrued unbilled revenues74,843 72,461 
Materials and supplies (at average cost)Materials and supplies (at average cost)77,552 64,941 
Fuel stock (at average cost)Fuel stock (at average cost)18,045 31,646 
PrepaymentsPrepayments24,676 20,184 
Current regulatory assetsCurrent regulatory assets71,223 63,407 
Current regulatory assets
Current regulatory assets
OtherOther5,708 1,995 
Total current assetsTotal current assets595,873 642,401 
InvestmentsInvestments123,824 126,948 
Investments
Investments
Property, Plant and Equipment:
Property, Plant, and Equipment:
Property, Plant, and Equipment:
Property, Plant, and Equipment:
Utility plant in service
Utility plant in service
Utility plant in serviceUtility plant in service6,509,316 6,283,790 
Accumulated provision for depreciationAccumulated provision for depreciation(2,298,951)(2,193,831)
Utility plant in service - netUtility plant in service - net4,210,365 4,089,959 
Construction work in progressConstruction work in progress670,585 597,152 
Utility plant held for future useUtility plant held for future use4,511 4,109 
Other property, net of accumulated depreciationOther property, net of accumulated depreciation16,361 18,290 
Property, plant and equipment - net4,901,822 4,709,510 
Property, plant, and equipment - net
Other Assets:Other Assets:
Other Assets:
Other Assets:
Company-owned life insurance
Company-owned life insurance
Company-owned life insuranceCompany-owned life insurance67,343 62,382 
Regulatory assetsRegulatory assets1,462,431 1,495,488 
OtherOther59,222 58,515 
Total other assetsTotal other assets1,588,996 1,616,385 
TotalTotal$7,210,515 $7,095,244 
Total
Total

The accompanying notes are an integral part of these statements.
8477
Table of Contents                              
IDACORP, Inc.
Consolidated Balance Sheets

 
December 31,
20212020
(in thousands)
December 31,December 31,
202320232022
(in thousands)(in thousands)
Liabilities and EquityLiabilities and Equity
Current Liabilities:Current Liabilities:
Current Liabilities:
Current Liabilities:
Current maturities of long-term debt
Current maturities of long-term debt
Current maturities of long-term debt
Accounts payable
Accounts payable
Accounts payableAccounts payable$145,980 $120,576 
Taxes accruedTaxes accrued14,229 19,508 
Interest accruedInterest accrued23,959 24,030 
Accrued compensationAccrued compensation55,666 52,245 
Current regulatory liabilitiesCurrent regulatory liabilities11,239 11,104 
Advances from customersAdvances from customers43,472 29,341 
OtherOther31,079 30,767 
Total current liabilitiesTotal current liabilities325,624 287,571 
Other Liabilities:Other Liabilities:
Other Liabilities:
Other Liabilities:
Deferred income taxes
Deferred income taxes
Deferred income taxesDeferred income taxes842,375 800,251 
Regulatory liabilitiesRegulatory liabilities781,695 757,730 
Pension and other postretirement benefitsPension and other postretirement benefits521,462 634,070 
OtherOther63,485 48,752 
Total other liabilitiesTotal other liabilities2,209,017 2,240,803 
Long-Term DebtLong-Term Debt2,000,640 2,000,414 
Long-Term Debt
Long-Term Debt
Commitments and Contingencies
Commitments and Contingencies
Commitments and ContingenciesCommitments and Contingencies00
Equity:Equity:
Equity:
Equity:
IDACORP, Inc. shareholders’ equity:IDACORP, Inc. shareholders’ equity:
Common stock, no par value (120,000 shares authorized; shares issued 50,516 and 50,462, respectively)874,896 869,235 
IDACORP, Inc. shareholders’ equity:
IDACORP, Inc. shareholders’ equity:
Common stock, no par value (120,000 shares authorized; 50,615 and 50,562 shares issued, respectively)
Common stock, no par value (120,000 shares authorized; 50,615 and 50,562 shares issued, respectively)
Common stock, no par value (120,000 shares authorized; 50,615 and 50,562 shares issued, respectively)
Retained earningsRetained earnings1,833,580 1,734,103 
Accumulated other comprehensive lossAccumulated other comprehensive loss(40,040)(43,358)
Total IDACORP, Inc. shareholders’ equity
Total IDACORP, Inc. shareholders’ equity
Total IDACORP, Inc. shareholders’ equityTotal IDACORP, Inc. shareholders’ equity2,668,436 2,559,980 
Noncontrolling interestsNoncontrolling interests6,798 6,476 
Total equityTotal equity2,675,234 2,566,456 
TotalTotal$7,210,515 $7,095,244 
Total
Total
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.

8578
Table of Contents                              
IDACORP, Inc.
Consolidated Statements of Cash Flows

Year Ended December 31,Year Ended December 31,
Year Ended December 31, 202320222021
202120202019
(thousands of dollars)
(thousands of dollars)(thousands of dollars)
Operating Activities:Operating Activities:
Net incomeNet income$245,872 $237,968 $233,328 
Net income
Net income
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
Depreciation and amortizationDepreciation and amortization179,444 175,941 173,800 
Deferred income taxes and investment tax creditsDeferred income taxes and investment tax credits23,901 25,175 22,389 
Changes in regulatory assets and liabilitiesChanges in regulatory assets and liabilities(33,705)(36,246)(4,310)
Pension and postretirement benefit plan expensePension and postretirement benefit plan expense33,817 28,970 27,804 
Contributions to pension and postretirement benefit plansContributions to pension and postretirement benefit plans(44,220)(45,161)(48,525)
Earnings of equity-method investmentsEarnings of equity-method investments(11,435)(11,513)(12,370)
Distributions from equity-method investmentsDistributions from equity-method investments11,711 14,477 21,800 
Allowance for equity funds used during constructionAllowance for equity funds used during construction(31,537)(29,551)(27,112)
Other adjustments to net income, net8,929 10,457 8,040 
Other non-cash adjustments to net income, net
Other non-cash adjustments to net income, net
Other non-cash adjustments to net income, net
Change in:Change in:  
Accounts receivable(6,697)(374)(5,996)
Accounts payable and other accrued liabilities17,700 (356)(9,526)
Accounts receivable and unbilled revenues
Accounts receivable and unbilled revenues
Accounts receivable and unbilled revenues
Prepayments
Materials, supplies, and fuel stock
Accounts and wages payable
Taxes accrued/receivableTaxes accrued/receivable(17,885)8,950 742 
Other current assets(8,327)4,910 (8,820)
Other current liabilities3,102 7,996 (799)
Other assets(10,764)(5,546)(4,375)
Other liabilities3,358 2,034 555 
Other assets and liabilities
Net cash provided by operating activitiesNet cash provided by operating activities363,264 388,131 366,625 
Investing Activities:Investing Activities:   Investing Activities: 
Additions to property, plant and equipmentAdditions to property, plant and equipment(299,999)(310,938)(278,705)
Payments received from transmission project joint funding partnersPayments received from transmission project joint funding partners5,876 3,197 2,442 
Investments in affordable housing and other real estate tax credit projectsInvestments in affordable housing and other real estate tax credit projects(15,148)(14,338)(2,687)
Investments in affordable housing and other real estate tax credit projects
Investments in affordable housing and other real estate tax credit projects
Distributions from equity-method investments, return of investment
Distributions from equity-method investments, return of investment
Distributions from equity-method investments, return of investmentDistributions from equity-method investments, return of investment14,439 1,073 — 
Purchase of equity securitiesPurchase of equity securities(17,186)(33,382)(10,896)
Purchase of equity securities
Purchase of equity securities
Purchases of held-to-maturity securities
Proceeds from sale of equity securities
Purchases of short-term investmentsPurchases of short-term investments(25,000)(25,000)— 
Maturities of short-term investmentsMaturities of short-term investments50,000 — — 
Proceeds from sale of equity securities11,328 25,795 5,080 
Other
Other
OtherOther2,037 6,335 4,274 
Net cash used in investing activitiesNet cash used in investing activities(273,653)(347,258)(280,492)
Financing Activities:Financing Activities:   Financing Activities: 
Issuance of long-term debtIssuance of long-term debt— 310,000 166,100 
Premium on issuance of long-term debt— 31,384 — 
Discount on issuance of long-term debt
Discount on issuance of long-term debt
Discount on issuance of long-term debt
Retirement of long-term debtRetirement of long-term debt— (175,000)(166,100)
Dividends on common stockDividends on common stock(146,119)(137,813)(129,677)
Tax withholdings on net settlements of share-based awardsTax withholdings on net settlements of share-based awards(3,031)(4,641)(4,160)
Make-whole premium on retirement of long-term debt— (3,305)— 
Tax withholdings on net settlements of share-based awards
Tax withholdings on net settlements of share-based awards
Debt issuance costs and otherDebt issuance costs and other(334)(3,636)(2,534)
Net cash (used in) provided by financing activities(149,484)16,989 (136,371)
Net (decrease) increase in cash and cash equivalents(59,873)57,862 (50,238)
Debt issuance costs and other
Debt issuance costs and other
Net cash provided by (used in) financing activities
Net increase (decrease) in cash and cash equivalents
Cash and cash equivalents at beginning of the yearCash and cash equivalents at beginning of the year275,116 217,254 267,492 
Cash and cash equivalents at end of the yearCash and cash equivalents at end of the year$215,243 $275,116 $217,254 
Supplemental Disclosure of Cash Flow Information:Supplemental Disclosure of Cash Flow Information:   Supplemental Disclosure of Cash Flow Information: 
Cash paid during the year for:Cash paid during the year for:   Cash paid during the year for: 
Income taxesIncome taxes$34,330 $9,975 $14,055 
Interest (net of amount capitalized)Interest (net of amount capitalized)$83,499 $81,074 $85,260 
Non-cash investing activities:Non-cash investing activities:
Additions to property, plant and equipment in accounts payableAdditions to property, plant and equipment in accounts payable$53,690 $45,004 $38,815 
Additions to property, plant and equipment in accounts payable
Additions to property, plant and equipment in accounts payable

The accompanying notes are an integral part of these statements.
8679
Table of Contents                              
IDACORP, Inc.
Consolidated Statements of Equity
 
Year Ended December 31,Year Ended December 31,
202320222021
(thousands of dollars)
Common Stock:
Balance at beginning of year
Balance at beginning of year
Balance at beginning of year
Share-based compensation expense
Share-based compensation expense
Share-based compensation expense
Tax withholdings on net settlements of share-based awards
Other
Other
Other
Balance at end of year
Retained Earnings:
Retained Earnings:
Retained Earnings:
Balance at beginning of year
Balance at beginning of year
Balance at beginning of year
Net income attributable to IDACORP, Inc.
Net income attributable to IDACORP, Inc.
Net income attributable to IDACORP, Inc.
Common stock dividends ($3.20, $3.04, and $2.88 per share, respectively)
Balance at end of year
Accumulated Other Comprehensive (Loss) Income:
Accumulated Other Comprehensive (Loss) Income:
Accumulated Other Comprehensive (Loss) Income:
Balance at beginning of year
Balance at beginning of year
Balance at beginning of year
Unfunded pension liability adjustment (net of tax)
Unfunded pension liability adjustment (net of tax)
Unfunded pension liability adjustment (net of tax)
Balance at end of year
Year Ended December 31,
202120202019
(thousands of dollars)
Common Stock:
Balance at beginning of year$869,235 $868,307 $863,593 
Share-based compensation expense8,583 7,416 8,788 
Tax withholdings on net settlements of share-based awards(3,031)(4,641)— 
Treasury shares issued— (1,920)(4,172)
Other109 73 98 
Balance at end of year874,896 869,235 868,307 
Retained Earnings:
Balance at beginning of year1,734,103 1,634,525 1,531,543 
Total IDACORP, Inc. shareholders’ equity at end of year
Net income attributable to IDACORP, Inc.245,550 237,417 232,854 
Common stock dividends ($2.88, $2.72, and $2.56 per share, respectively)(146,073)(137,839)(129,872)
Balance at end of year1,833,580 1,734,103 1,634,525 
Accumulated Other Comprehensive (Loss) Income:
Balance at beginning of year(43,358)(36,284)(22,844)
Unfunded pension liability adjustment (net of tax)3,318 (7,074)(13,440)
Balance at end of year(40,040)(43,358)(36,284)
Treasury Stock:
Balance at beginning of year— (1,920)(1,932)
Issued— 1,920 4,172 
Acquired— — (4,160)
Balance at end of year— — (1,920)
Total IDACORP, Inc. shareholders’ equity at end of year
Total IDACORP, Inc. shareholders’ equity at end of yearTotal IDACORP, Inc. shareholders’ equity at end of year2,668,436 2,559,980 2,464,628 
Noncontrolling Interests:Noncontrolling Interests:
Noncontrolling Interests:
Noncontrolling Interests:
Balance at beginning of year
Balance at beginning of year
Balance at beginning of yearBalance at beginning of year6,476 5,925 5,451 
Net income attributable to noncontrolling interestsNet income attributable to noncontrolling interests322 551 474 
Distributions to noncontrolling interests
Balance at end of yearBalance at end of year6,798 6,476 5,925 
Total equity at end of yearTotal equity at end of year$2,675,234 $2,566,456 $2,470,553 
Total equity at end of year
Total equity at end of year

The accompanying notes are an integral part of these statements.

8780
Table of Contents                              
Idaho Power Company
Consolidated Statements of Income
 
Year Ended December 31,Year Ended December 31,
Year Ended December 31, 202320222021
(thousands of dollars)(thousands of dollars)
202120202019
(thousands of dollars)
Operating Revenues
Operating Revenues
Operating RevenuesOperating Revenues$1,455,410 $1,347,340 $1,342,940 
Operating Expenses:Operating Expenses:
Operating Expenses:
Operating Expenses:
Operation:Operation:
Operation:
Operation:
Purchased power
Purchased power
Purchased powerPurchased power393,691 297,417 285,266 
Fuel expenseFuel expense180,550 172,740 156,872 
Power cost adjustmentPower cost adjustment(49,844)(33,708)2,047 
Other operations and maintenanceOther operations and maintenance361,297 352,071 355,770 
Energy efficiency programsEnergy efficiency programs29,920 42,478 40,128 
DepreciationDepreciation175,555 171,648 169,210 
Other operating expensesOther operating expenses34,673 35,914 35,995 
Total operating expensesTotal operating expenses1,125,842 1,038,560 1,045,288 
Operating IncomeOperating Income329,568 308,780 297,652 
Operating Income
Operating Income
Nonoperating (Income) Expense:Nonoperating (Income) Expense:
Nonoperating (Income) Expense:
Nonoperating (Income) Expense:
Allowance for equity funds used during construction
Allowance for equity funds used during construction
Allowance for equity funds used during constructionAllowance for equity funds used during construction(31,537)(29,551)(27,112)
Earnings of unconsolidated equity-method investmentsEarnings of unconsolidated equity-method investments(10,211)(10,102)(10,285)
Interest on long-term debtInterest on long-term debt84,145 84,251 82,457 
Other interestOther interest14,511 14,716 14,658 
Allowance for borrowed funds used during constructionAllowance for borrowed funds used during construction(11,993)(11,578)(10,703)
Other (income) expense, netOther (income) expense, net3,171 (2,739)(4,217)
Total nonoperating expense, netTotal nonoperating expense, net48,086 44,997 44,798 
Income Before Income TaxesIncome Before Income Taxes281,482 263,783 252,854 
Income Before Income Taxes
Income Before Income Taxes
Income Tax Expense
Income Tax Expense
Income Tax ExpenseIncome Tax Expense38,257 30,548 28,417 
Net IncomeNet Income$243,225 $233,235 $224,437 
Net Income
Net Income

The accompanying notes are an integral part of these statements.
8881
Table of Contents                              
Idaho Power Company
Consolidated Statements of Comprehensive Income
 
Year Ended December 31,Year Ended December 31,
Year Ended December 31, 202320222021
(thousands of dollars)(thousands of dollars)
202120202019
(thousands of dollars)
Net Income
Net Income
Net IncomeNet Income$243,225 $233,235 $224,437 
Other Comprehensive Income:Other Comprehensive Income:
Unfunded pension liability adjustment, net of tax
of $1,150, $(2,452), and $(4,658)
3,318 (7,074)(13,440)
Unfunded pension liability adjustment, net of tax
of $(1,477), $9,399, and $1,150
Unfunded pension liability adjustment, net of tax
of $(1,477), $9,399, and $1,150
Unfunded pension liability adjustment, net of tax
of $(1,477), $9,399, and $1,150
Total Comprehensive IncomeTotal Comprehensive Income$246,543 $226,161 $210,997 
Total Comprehensive Income
Total Comprehensive Income

The accompanying notes are an integral part of these statements.
 
 

8982
Table of Contents                              
Idaho Power Company
Consolidated Balance Sheets
 
December 31,
20212020
(in thousands)
December 31,December 31,
202320232022
(in thousands)(in thousands)
AssetsAssets
Current Assets:Current Assets:
Current Assets:
Current Assets:
Cash and cash equivalents
Cash and cash equivalents
Cash and cash equivalentsCash and cash equivalents$60,075 $165,604 
Receivables:Receivables:
Customer (net of allowance of $4,499 and $4,766, respectively)78,819 72,826 
Other (net of allowance of $517 and $497, respectively)14,134 12,457 
Customer (net of allowance of $4,869 and $5,034, respectively)
Customer (net of allowance of $4,869 and $5,034, respectively)
Customer (net of allowance of $4,869 and $5,034, respectively)
Other (net of allowance of $716 and $512, respectively)
Income taxes receivableIncome taxes receivable15,328 4,667 
Accrued unbilled revenuesAccrued unbilled revenues74,843 72,461 
Materials and supplies (at average cost)Materials and supplies (at average cost)77,552 64,941 
Fuel stock (at average cost)Fuel stock (at average cost)18,045 31,646 
PrepaymentsPrepayments24,558 20,057 
Current regulatory assetsCurrent regulatory assets71,223 63,407 
Current regulatory assets
Current regulatory assets
OtherOther5,708 1,995 
Total current assetsTotal current assets440,285 510,061 
InvestmentsInvestments77,108 87,848 
Investments
Investments
Property, Plant and Equipment:
Property, Plant, and Equipment:
Property, Plant, and Equipment:
Property, Plant, and Equipment:
Plant in service
Plant in service
Plant in servicePlant in service$6,509,316 $6,283,790 
Accumulated provision for depreciationAccumulated provision for depreciation(2,298,951)(2,193,831)
Plant in service - netPlant in service - net4,210,365 4,089,959 
Construction work in progressConstruction work in progress670,585 597,152 
Plant held for future usePlant held for future use4,511 4,109 
Other propertyOther property3,647 5,123 
Property, plant and equipment, net4,889,108 4,696,343 
Property, plant, and equipment, net
Other Assets:Other Assets:
Other Assets:
Other Assets:
Company-owned life insurance
Company-owned life insurance
Company-owned life insuranceCompany-owned life insurance67,343 62,382 
Regulatory assetsRegulatory assets1,462,431 1,495,488 
OtherOther54,564 53,988 
Total other assetsTotal other assets1,584,338 1,611,858 
TotalTotal$6,990,839 $6,906,110 
Total
Total


The accompanying notes are an integral part of these statements.
9083
Table of Contents                              
Idaho Power Company
Consolidated Balance Sheets

 
December 31,
20212020
(in thousands)
December 31,December 31,
202320232022
(in thousands)(in thousands)
Liabilities and EquityLiabilities and Equity
Current Liabilities:Current Liabilities:
Current Liabilities:
Current Liabilities:
Current maturities of long-term debt
Current maturities of long-term debt
Current maturities of long-term debt
Accounts payable
Accounts payable
Accounts payableAccounts payable$145,871 $120,476 
Accounts payable to affiliatesAccounts payable to affiliates2,159 1,720 
Taxes accruedTaxes accrued14,316 19,554 
Interest accruedInterest accrued23,959 24,030 
Accrued compensationAccrued compensation55,491 52,036 
Current regulatory liabilitiesCurrent regulatory liabilities11,239 11,104 
Advances from customersAdvances from customers43,472 29,341 
OtherOther19,117 16,717 
Total current liabilitiesTotal current liabilities315,624 274,978 
Other Liabilities:Other Liabilities:
Other Liabilities:
Other Liabilities:
Deferred income taxes
Deferred income taxes
Deferred income taxesDeferred income taxes844,871 829,146 
Regulatory liabilitiesRegulatory liabilities781,695 757,730 
Pension and other postretirement benefitsPension and other postretirement benefits521,462 634,070 
OtherOther62,245 45,937 
Total other liabilitiesTotal other liabilities2,210,273 2,266,883 
Long-Term DebtLong-Term Debt2,000,640 2,000,414 
Long-Term Debt
Long-Term Debt
Commitments and Contingencies
Commitments and Contingencies
Commitments and ContingenciesCommitments and Contingencies00
Equity: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)
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 
Premium on capital stockPremium on capital stock712,258 712,258 
Capital stock expenseCapital stock expense(2,097)(2,097)
Retained earningsRetained earnings1,696,304 1,599,155 
Accumulated other comprehensive lossAccumulated other comprehensive loss(40,040)(43,358)
Total equityTotal equity2,464,302 2,363,835 
TotalTotal$6,990,839 $6,906,110 
Total
Total
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.

9184
Table of Contents                              
Idaho Power Company
Consolidated Statements of Cash Flows

Year Ended December 31,
Year Ended December 31,Year Ended December 31,
202120202019 202320222021
(thousands of dollars) (thousands of dollars)
Operating Activities:Operating Activities:  
Net incomeNet income$243,225 $233,235 $224,437 
Net income
Net income
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
Depreciation and amortizationDepreciation and amortization178,847 175,334 173,205 
Deferred income taxes and investment tax creditsDeferred income taxes and investment tax credits(7,682)1,149 14,889 
Changes in regulatory assets and liabilitiesChanges in regulatory assets and liabilities(33,705)(36,246)(4,310)
Pension and postretirement benefit plan expensePension and postretirement benefit plan expense33,804 28,955 27,788 
Contributions to pension and postretirement benefit plansContributions to pension and postretirement benefit plans(44,207)(45,146)(48,509)
Earnings of equity-method investmentsEarnings of equity-method investments(10,211)(10,102)(10,285)
Distributions from equity-method investmentsDistributions from equity-method investments10,211 12,627 19,450 
Allowance for equity funds used during constructionAllowance for equity funds used during construction(31,537)(29,551)(27,112)
Other adjustments to net income, net346 3,041 (748)
Other non-cash adjustments to net income, net
Other non-cash adjustments to net income, net
Other non-cash adjustments to net income, net
Change in:Change in:  
Accounts receivable(5,607)(2,220)(4,724)
Accounts payable17,690 (292)(9,463)
Accounts receivable and unbilled revenues
Accounts receivable and unbilled revenues
Accounts receivable and unbilled revenues
Prepayments
Materials, supplies, and fuel stock
Accounts and wages payable
Taxes accrued/receivableTaxes accrued/receivable(15,899)12,685 2,281 
Other current assets(8,336)4,919 (8,821)
Other current liabilities3,133 8,072 (870)
Other assets(10,809)(5,588)(4,280)
Other liabilities3,443 2,116 584 
Other assets and liabilities
Net cash provided by operating activitiesNet cash provided by operating activities322,706 352,988 343,512 
Investing Activities:Investing Activities:  
Additions to utility plant
Additions to utility plant
Additions to utility plantAdditions to utility plant(299,972)(310,937)(278,707)
Payments received from transmission project joint funding partnersPayments received from transmission project joint funding partners5,876 3,197 2,442 
Distributions from equity-method investments, return of investmentDistributions from equity-method investments, return of investment14,439 1,073 — 
Distributions from equity-method investments, return of investment
Distributions from equity-method investments, return of investment
Purchase of equity securitiesPurchase of equity securities(15,823)(33,382)(10,896)
Purchases of held-to-maturity securities
Proceeds from the sale of equity securitiesProceeds from the sale of equity securities11,328 25,795 5,080 
Other
Other
OtherOther2,231 6,305 4,117 
Net cash used in investing activitiesNet cash used in investing activities(281,921)(307,949)(277,964)
Financing Activities:Financing Activities:  
Issuance of long-term debtIssuance of long-term debt— 310,000 166,100 
Premium on issuance of long-term debt— 31,384 — 
Issuance of long-term debt
Issuance of long-term debt
Discount on issuance of long-term debt
Retirement of long-term debtRetirement of long-term debt— (175,000)(166,100)
Dividends on common stockDividends on common stock(146,076)(137,885)(129,877)
Dividends on common stock
Make-whole premium on retirement of long-term debt— (3,305)— 
Dividends on common stock
OtherOther(238)(3,579)(2,181)
Net cash (used in) provided by financing activities(146,314)21,615 (132,058)
Net (decrease) increase in cash and cash equivalents(105,529)66,654 (66,510)
Other
Other
Net cash provided by (used in) financing activities
Net increase (decrease) in cash and cash equivalents
Cash and cash equivalents at beginning of the yearCash and cash equivalents at beginning of the year165,604 98,950 165,460 
Cash and cash equivalents at end of the yearCash and cash equivalents at end of the year$60,075 $165,604 $98,950 
Supplemental Disclosure of Cash Flow Information:Supplemental Disclosure of Cash Flow Information:  
Cash paid to IDACORP related to income taxesCash paid to IDACORP related to income taxes$64,003 $32,118 $19,856 
Cash paid to IDACORP related to income taxes
Cash paid to IDACORP related to income taxes
Cash paid for interest (net of amount capitalized)Cash paid for interest (net of amount capitalized)$83,464 $81,037 $85,198 
Non-cash investing activities:Non-cash investing activities:
Additions to property, plant and equipment in accounts payableAdditions to property, plant and equipment in accounts payable$53,690 $45,004 $38,815 
Additions to property, plant and equipment in accounts payable
Additions to property, plant and equipment in accounts payable

The accompanying notes are an integral part of these statements.
9285
Table of Contents                              
Idaho Power Company
Consolidated Statements of Retained Earnings

Year Ended December 31,Year Ended December 31,
2023202320222021
(thousands of dollars)(thousands of dollars)
Year Ended December 31,
202120202019
(thousands of dollars)
Retained Earnings, Beginning of Year
Retained Earnings, Beginning of Year
Retained Earnings, Beginning of YearRetained Earnings, Beginning of Year$1,599,155 $1,503,805 $1,409,245 
Net IncomeNet Income243,225 233,235 224,437 
Dividends on Common StockDividends on Common Stock(146,076)(137,885)(129,877)
Retained Earnings, End of YearRetained Earnings, End of Year$1,696,304 $1,599,155 $1,503,805 
Retained Earnings, End of Year
Retained Earnings, End of Year

The accompanying notes are an integral part of these statements.
9386
Table of Contents                              

IDACORP, INC. AND IDAHO POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
 
This Annual Report on Form 10-K is a combined report of IDACORP Inc. (IDACORP) and Idaho Power Company (Idaho Power).Power. Therefore, these Notes to the 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, sales, 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).FERC. Idaho Power is the parent of Idaho Energy Resources Co. (IERCo),IERCo, a joint venturer in Bridger Coal Company (BCC),joint-owner of BCC, which mines and supplies coal to the Jim Bridger generating plant (Jim Bridger plant) owned in part by Idaho Power.
 
IDACORP’s other notable wholly-owned subsidiaries include IDACORP Financial Services, Inc. (IFS),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).PURPA.
 
Principles of Consolidation
 
IDACORP’s and Idaho Power’s consolidated financial statements include the assets, liabilities, revenues, and expenses of each company and its wholly-owned subsidiaries listed above, as well as any variable interest entity (VIE) for which the respective company is the primary beneficiary. Investments in VIEs for which the companies are not the primary beneficiaries, but have the ability to exercise significant influence over operating and financial policies, are accounted for using the equity method of accounting. 

IDACORP also consolidates one VIE, Marysville Hydro Partners (Marysville), which is a joint venture owned 50 percent by Ida-West and 50 percent by Environmental Energy Company (EEC). At December 31, 2021,2023 and 2022, Marysville had approximately $16.0$14.9 million of assets, primarily a hydropower plant and approximately $2.3 million of intercompany long-term debt, which is eliminated in consolidation.assets. EEC has borrowed amounts from Ida-West to fund a portion of its required capital contributions to Marysville. The loans are payable from EEC’s share of distributions from Marysville and are secured by the stock of EEC and EEC’s interest in Marysville. Ida-West is identified as the primary beneficiary because the combination of its ownership interest in the joint venture with the intercompany note and the EEC note result in Ida-West's ability to control the activities of the joint venture. Creditors of Marysville have no recourse to the general credit of IDACORP and there are no other arrangements that could require IDACORP to provide financial support to Marysville or expose IDACORP to losses.
 
The BCC joint ventureinvestment is also a VIE, but because the power to direct the activities that most significantly impact the economic performance of BCC is shared with the joint venture partner,joint-owner, Idaho Power is not the primary beneficiary. The carrying value of Idaho Power's investment in BCC was $22.7$24.1 million at December 31, 2021,2023, and Idaho Power's maximum exposure to loss is the carrying value, any additional future contributions to BCC, and a $51.6$47.6 million guarantee for mine reclamation costs. BCC has a reclamation trust fund set aside specifically for the purpose of paying the reclamation costs, the market value of which isexceeded the total estimated reclamation obligation at December 31, 2023. The guarantee, reclamation obligation, and reclamation trust are discussed further in Note 109 - "Commitments."
 
IFS's affordable housing limited partnership and other real estate tax credit investments are also VIEs for which IDACORP is not the primary beneficiary. IFS's limited partnership interests range from 24 to 100 percent and were acquired between 19962003 and 2021.2023. As a limited partner, IFS does not control these entities and they are not consolidated. IFS’s maximum exposure to loss in these developments is limited to its net carrying value, which was $35.0$57.3 million at December 31, 2021.2023.

Ida-West's other investments in PURPA facilities, Idaho Power's investment in BCC, and IFS's investments are accounted for under the equity method of accounting (see Note 1514 - "Investments").

Except for amounts related to sales of electricity by Ida-West's PURPA projects to Idaho Power, all intercompany transactions and balances have been eliminated in consolidation. 

94
87
Table of Contents                              

The accompanying consolidated financial statements include Idaho Power's proportionate share of utility plant and related operations resulting from its interests in jointly-owned plants (see Note 1312 - "Property, Plant and Equipment and Jointly-Owned Projects"). 

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.

Idaho Power meets the requirements under accounting principles generally accepted in the United States of America (GAAP)GAAP to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. IDACORP’s and Idaho Power’s financial statements reflect the effects of the different ratemaking principles followed by the jurisdictions regulating Idaho Power. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant, and equipment; regulatory assets and liabilities; operating revenues; operation and maintenanceO&M expense; depreciation expense; and income tax expense. 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."

Management Estimates
 
Management makes estimates and assumptions when preparing financial statements in conformity with 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 date of the financial statements and the reported amounts of revenues and expenses during the reporting period. These estimates involve judgments with respect to, among other things, future economic factors that are difficult to predict and are beyond management’s control. Accordingly, actual results could differ from those estimates.
 
System of Accounts

The accounting records of Idaho Power conform to the Uniform System of Accounts prescribed by the FERC and adopted by the public utility commissions of Idaho, Oregon, and Wyoming.
 
Cash and Cash Equivalents

Cash and cash equivalents include cash on-hand and highly liquid temporary investments that mature within 90 days of the date of acquisition.
 
Receivables and Allowance for Uncollectible Accounts

Customer receivables are recorded at the invoiced amounts and do not bear interest. A late payment fee of 1one percent per month may be assessed on account balances after 30 days. An allowance is recorded for potential uncollectible accounts. The measurement of expected credit losses on Idaho Power accounts receivable is based on historical experience, current economic conditions, and forecasted information that may affect collections on the outstanding balance. Generally, this includes adjustments based upon a combination of historical write-off experience, aging of accounts receivable, an analysis of specific customer accounts, and an evaluation of whether there are current or forecasted economic conditions that might cause variation in collection from the historical experience. Adjustments are charged to income. Customer accounts receivable balances that remain outstanding after reasonable collection efforts are written off.

In response to the COVID-19 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
9588
Table of Contents                              
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 expects higher uncollectible account write-offs as a result of the COVID-19 public health crisis and, accordingly, has maintained its higher allowance for uncollectible accounts related to customer receivables at December 31, 2021.

The following table provides a rollforward of the allowance for uncollectible accounts related to customer receivables (in thousands of dollars):
Year Ended
December 31,
Year Ended
December 31,		Year Ended
December 31,
20212020 20232022
Balance at beginning of periodBalance at beginning of period$4,766 $1,401 
Additions to the allowanceAdditions to the allowance2,017 5,222 
Write-offs, net of recoveriesWrite-offs, net of recoveries(2,284)(1,857)
Balance at end of periodBalance at end of period$4,499 $4,766 
Allowance for uncollectible accounts as a percentage of customer receivablesAllowance for uncollectible accounts as a percentage of customer receivables5.4 %6.1 %Allowance for uncollectible accounts as a percentage of customer receivables4.3 %4.2 %

Other receivables, primarily notes receivable from business transactions, are also reviewed for impairment periodically, based upon transaction-specific facts. When it is probable that IDACORP or Idaho Power will be unable to collect all amounts due according to the contractual terms of the agreement, an allowance is established for the estimated uncollectible portion of the receivable and charged to income.

There were no impaired receivables without related allowances at December 31, 20212023 and 2020.2022. Once a receivable is determined to be impaired, any further interest income recognized is fully reserved.

Derivative Financial Instruments

Financial instruments such as commodity futures, forwards, options, and swaps are used to manage exposure to commodity price risk in the electricity and natural gas markets. All derivative instruments are recognized as either assets or liabilities at fair value on the balance sheet unless they are designated as normal purchases and normal sales. With the exception of forward contracts for the purchase of natural gas for use at Idaho Power's natural gas generation facilities and a nominal number of power transactions, Idaho Power’s physical forward contracts are designated as normal purchases and normal sales. Because of Idaho Power’s regulatory accounting mechanisms, Idaho Power records the unrealized changes in fair value of derivative instruments related to power supply as regulatory assets or liabilities.
 
Revenues

Operating revenues are generally recorded when service is rendered or energy is delivered to customers. Idaho Power accrues estimated unbilled revenues for electric services delivered to customers but not yet billed at year-end. Idaho Power does not report any collections of franchise fees and similar taxes related to energy consumption on the income statement. In addition, regulatory mechanisms in place in Idaho and Oregon affect the reported amount of revenue. The effects of applying these regulatory mechanisms are discussed in more detail in Note 4 - "Revenues."
 
Property, Plant, and Equipment and Depreciation

The cost of utility plant in service represents the original cost of contracted services, direct labor and material, allowance for funds used during construction (AFUDC),AFUDC, and indirect charges for engineering, supervision, and similar overhead items. Repair and maintenance costs associated with planned major maintenance are expensed as the costs are incurred, as are maintenance and repairs of property and replacements and renewals of items determined to be less than units of property. For utility property replaced or renewed, the original cost plus removal cost less salvage is charged to accumulated provision for depreciation, while the cost of related replacements and renewals is added to property, plant, and equipment.
 
All utility plant in service is depreciated using the straight-line method at rates approved by regulatory authorities. Annual depreciation provisions as a percent of average depreciable utility plant in service approximated 2.9 percent in 2021, 2020,2023, 2.7 percent in 2022, and 2019.2.9 percent in 2021.

96
Table of Contents
During the period of construction, costs expected to be included in the final value of the constructed asset, and depreciated once the asset is complete and placed in service, are classified as construction work in progress on the consolidated balance sheets. If the project becomes probable of being abandoned, these costs are expensed in the period such determination is made. Idaho Power may seek recovery of these costs in customer rates, although there can be no guarantee such recovery would be granted.
 
89
Table of Contents
Long-lived assets are periodically reviewed for impairment when events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If the sum of the undiscounted expected future cash flows from an asset is less than the carrying value of the asset, impairment is recognized in the financial statements. There were no material impairments of long-lived assets in 2021, 2020,2023, 2022, or 2019.2021.
 
Allowance for Funds Used During Construction

AFUDC represents the cost of financing construction projects with borrowed funds and equity funds. With one exception, for the Hells Canyon Complex (HCC)HCC relicensing project, cash is not realized currently from such allowance; it is realized under the ratemaking process over the service life of the related property through increased revenues resulting from a higher rate base and higher depreciation expense. The component of AFUDC attributable to borrowed funds is included as a reduction to total interest expense.nonoperating expense, net. Idaho Power’s weighted-average monthly AFUDC rate was 7.4 percent for 2023 and 2022, and 7.5 percent for 2021 and 2020, and 7.6 percent for 2019.2021.

Income Taxes

IDACORP and Idaho Power account for income taxes under the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements. Under this method (commonly referred to as normalized accounting), deferred tax assets and liabilities are determined based on the differences between the financial statements and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. In general, deferred income tax expense or benefit for a reporting period is recognized as the change in deferred tax assets and liabilities from the beginning to the end of the period. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date unless Idaho Power's primary regulator, the Idaho Public Utilities Commission (IPUC),IPUC, orders direct deferral of the effect of the change in tax rates over a longer period of time.

Consistent with orders and directives of the IPUC, unless contrary to applicable income tax guidance, Idaho Power does not record deferred income tax expense or benefit for certain income tax temporary differences and instead recognizes the tax impact currently (commonly referred to as flow-through accounting) for rate making and financial reporting. Therefore, Idaho Power's effective income tax rate is impacted as these differences arise and reverse. Idaho Power recognizes such adjustments as regulatory assets or liabilities if it is probable that such amounts will be recovered from or returned to customers in future rates.

IDACORP and Idaho Power use judgment, estimation, and historical data in developing the provision for income taxes and the reporting of tax-related assets and liabilities, including development of current year tax depreciation, capitalized repair costs, capitalized overheads, and other items. Income taxes can be impacted by changes in tax laws and regulations, interpretations by taxing authorities, changes to accounting guidance, and actions by federal or state public utility regulators. Actual income taxes could vary from estimated amounts and may result in favorable or unfavorable impacts to net income, cash flows, and tax-related assets and liabilities.

In compliance with the federal income tax requirements for the use of accelerated tax depreciation, Idaho Power records deferred income taxes related to its plant assets for the difference between income tax depreciation and book depreciation used for financial statement purposes. Deferred income taxes are recorded for other temporary differences unless accounted for using flow-through.
 
Investment tax credits earned on regulated assets are deferred and amortized to income over the estimated service lives of the related properties.
 
Income taxes are discussed in more detail in Note 2 - "Income Taxes."

97
Table of Contents
Other Accounting Policies

Debt discount, expense, and premium are deferred and amortized over the terms of the respective debt issuances. Losses on reacquired debt and associated costs are amortized over the life of the associated replacement debt, as allowed under regulatory accounting.

90
Table of Contents
New and Recently Adopted Accounting Pronouncements

Recently Adopted Accounting Pronouncements

There have been no recently issuedadopted accounting pronouncements that have had a material impact on IDACORP's or Idaho Power's consolidated financial statements.

Recent Accounting Pronouncements Not Yet Adopted

In November 2023, the Financial Standards Accounting Board (FASB) issued Accounting Standards Update (ASU) 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures which expands annual and interim disclosure requirements for reportable segments, primarily through enhanced disclosures about significant segment expenses. This ASU is effective for annual periods beginning after December 15, 2023, and for interim periods beginning after December 15, 2024, with early adoption permitted. The amendments in this ASU will be applied retrospectively. IDACORP and Idaho Power are currently evaluating the impact that adoption of this ASU will have on their notes to the consolidated financial statements.

In December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures which expands the disclosure requirements for income taxes, specifically related to the rate reconciliation and income taxes paid. This ASU is effective for annual periods beginning after December 15, 2024, with early adoption permitted. The amendments in this ASU will be applied prospectively and may be applied retrospectively. IDACORP and Idaho Power are currently evaluating the impact that adoption of this ASU will have on their notes to the consolidated financial statements.

There have been no other recent accounting pronouncements not yet adopted that are expected to have a material impact on IDACORP's or Idaho Power's consolidated financial statements.

2. INCOME TAXES
 
A reconciliation between the statutory federal income tax rate and the effective tax rate is as follows:
IDACORPIdaho Power IDACORPIdaho Power
202120202019202120202019 202320222021202320222021
(thousands of dollars)
(thousands of dollars)(thousands of dollars)
Federal income tax expense at statutory rateFederal income tax expense at statutory rate$59,317 $55,885 $54,046 $59,111 $55,394 $53,099 
Change in taxes resulting from:Change in taxes resulting from:     Change in taxes resulting from:   
AFUDCAFUDC(9,141)(8,637)(7,941)(9,141)(8,637)(7,941)
Capitalized interestCapitalized interest1,077 1,044 976 1,077 1,044 976 
Investment tax creditsInvestment tax credits(2,866)(2,906)(6,252)(2,866)(2,906)(6,252)
Removal costsRemoval costs(3,302)(3,148)(3,139)(3,302)(3,148)(3,139)
Capitalized overhead costsCapitalized overhead costs(8,190)(7,560)(7,140)(8,190)(7,560)(7,140)
Capitalized repair costsCapitalized repair costs(17,430)(18,480)(18,480)(17,430)(18,480)(18,480)
Bond redemption costs— (726)— — (726)— 
State income taxes, net of federal benefit
State income taxes, net of federal benefit
State income taxes, net of federal benefitState income taxes, net of federal benefit11,359 8,804 8,627 11,633 9,052 8,401 
DepreciationDepreciation14,233 13,589 14,641 14,233 13,589 14,641 
Excess deferred income tax reversalExcess deferred income tax reversal(8,958)(4,885)(6,181)(8,958)(4,885)(6,181)
Income tax return adjustmentsIncome tax return adjustments3,169 (2,552)745 1,759 (2,508)993 
Income tax return adjustments
Income tax return adjustments
Real Estate-related tax creditsReal Estate-related tax credits(6,245)(5,315)(2,874)— — — 
Real Estate-related investment distributionsReal Estate-related investment distributions(1,010)(13)(3,232)— — — 
Real Estate-related investment amortizationReal Estate-related investment amortization4,095 3,754 1,825 — — — 
Other, netOther, net804 (154)(1,114)331 319 (560)
Total income tax expenseTotal income tax expense$36,912 $28,700 $24,507 $38,257 $30,548 $28,417 
Effective tax rateEffective tax rate13.1%10.8%9.5%13.6%11.6%11.2%Effective tax rate9.5%12.7%13.1%10.1%13.5%13.6%

9891
Table of Contents                              
The items comprising income tax expense are as follows:
IDACORPIdaho Power IDACORPIdaho Power
202120202019202120202019 202320222021202320222021
(thousands of dollars)
(thousands of dollars)(thousands of dollars)
Income taxes current:Income taxes current:      Income taxes current: 
FederalFederal$15,210 $7,800 $8,830 $40,525 $30,464 $25,338 
StateState6,630 3,215 4,865 12,932 6,409 (4,392)
TotalTotal21,840 11,015 13,695 53,457 36,873 20,946 
Income taxes deferred:Income taxes deferred:      Income taxes deferred: 
FederalFederal(1,787)11,543 9,486 (21,737)(4,905)(4,599)
StateState1,154 (1,414)1,159 (5,295)(4,241)10,054 
TotalTotal(633)10,129 10,645 (27,032)(9,146)5,455 
Investment tax credits:Investment tax credits:      Investment tax credits: 
DeferredDeferred14,698 5,727 8,268 14,698 5,727 8,268 
RestoredRestored(2,866)(2,906)(6,252)(2,866)(2,906)(6,252)
TotalTotal11,832 2,821 2,016 11,832 2,821 2,016 
Real estate-related investments at IFSReal estate-related investments at IFS3,873 4,735 (1,849)— — — 
Total income tax expenseTotal income tax expense$36,912 $28,700 $24,507 $38,257 $30,548 $28,417 

The components of the net deferred tax liability are as follows:
IDACORPIdaho Power IDACORPIdaho Power
2021202020212020 2023202220232022
(thousands of dollars) (thousands of dollars)
Deferred tax assets:Deferred tax assets:    Deferred tax assets: 
Regulatory liabilitiesRegulatory liabilities$96,880 $95,883 $96,880 $95,883 
Deferred compensationDeferred compensation23,333 22,576 23,333 22,576 
Deferred compensation
Deferred compensation
Deferred revenueDeferred revenue48,318 43,525 48,318 43,525 
Tax creditsTax credits41,896 61,707 35,781 30,215 
Partnership investmentsPartnership investments12,265 10,189 11,949 7,211 
Partnership investments
Partnership investments
Retirement benefits
Retirement benefits
Retirement benefitsRetirement benefits110,997 142,864 110,997 142,864 
OtherOther17,066 15,005 16,893 14,792 
TotalTotal350,755 391,749 344,151 357,066 
Deferred tax liabilities:Deferred tax liabilities:  Deferred tax liabilities: 
Property, plant and equipmentProperty, plant and equipment272,530 282,983 272,530 282,983 
Regulatory assetsRegulatory assets721,276 687,628 721,276 687,628 
Power cost adjustment
Power cost adjustment
Power cost adjustment
Partnership investments
Partnership investments
Partnership investmentsPartnership investments2,824 3,257 — — 
Retirement benefitsRetirement benefits138,154 164,399 138,154 164,399 
OtherOther58,346 53,733 57,062 51,202 
TotalTotal1,193,130 1,192,000 1,189,022 1,186,212 
Net deferred tax liabilitiesNet deferred tax liabilities$842,375 $800,251 $844,871 $829,146 

IDACORP's tax allocation agreement provides that each member of its consolidated group compute its income taxes on a separate company basis. Amounts payable or refundable are settled through IDACORP and are reported as taxes accrued or income taxes receivable, respectively, on the consolidated balance sheets of Idaho Power. See Note 1 - "Summary of Significant Accounting Policies" for further discussion of accounting policies related to income taxes.

Tax Credit Carryforwards

As of December 31, 2021,2023, IDACORP had $41.9$52.0 million of Idaho investment tax credit carryforwards,carryforward, which expire from 20262029 to 2035.  2037.

9992
Table of Contents                              
Uncertain Tax Positions

IDACORP and Idaho Power believe that they have no material income tax uncertainties for 20212023 and prior tax years. Both companies recognize interest accrued related to unrecognized tax benefits as interest expense and penalties as other expense. 
 
IDACORP and Idaho Power are subject to examination by their major tax jurisdictions - United States federal and the State of Idaho. The open tax years for examination are 2020-2021 and 2023 for federal and 2016-20212022-2023 for Idaho. The Idaho State Tax Commission began its examination of the 2016-2018 tax years in March of 2020. In May 2009, IDACORP formally entered the U.S. Internal Revenue Service (IRS) Compliance Assurance Process (CAP) program for its 2009 tax year and has remained in the CAP program for all subsequent years. The CAP program provides forIn 2023, the IRS completed its examination and issue resolution throughout the currentof IDACORP’s 2022 tax year with the objective of return filings containing no contested items. The IRS moved IDACORP from the maintenance phase of CAP to the bridge phase for both the 2020 and 2021unresolved income tax years.issues.

3. REGULATORY MATTERS

IDACORP’s and Idaho Power’s financial statements reflect the effects of the different ratemaking principles followed by the jurisdictions regulating Idaho Power. Included below is a summary of Idaho Power's regulatory assets and liabilities, as well as a discussion of notable regulatory matters.
 
Regulatory Assets and Liabilities
 
The application of accounting principles related to regulated operations sometimes results in Idaho Power recording some expenses and revenues in a different period than when an unregulated enterprise would record those expenses and revenues. 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.

10093
Table of Contents                              
The following table presents a summary of Idaho Power’s regulatory assets and liabilities (in thousands of dollars):
As of December 31, 2021
Remaining
Amortization Period
Earning a Return(1)
Not Earning a ReturnTotal as of December 31,
As of December 31, 2023
Remaining
Amortization Period
Remaining
Amortization Period
Remaining
Amortization Period
Earning a Return(1)
Not Earning a ReturnTotal as of December 31,
DescriptionDescriptionRemaining
Amortization Period
Earning a Return(1)
Not Earning a Return20212020Description20232022
Regulatory Assets:Regulatory Assets: Regulatory Assets:   
Income taxes(2)
Income taxes(2)
 $— $721,276 $721,276 $687,628 
Unfunded postretirement benefits(3)
Unfunded postretirement benefits(3)
 — 315,011 315,011 444,470 
Pension expense deferrals(4)
Pension expense deferrals(4)
197,623 36,814 234,437 200,686 
Energy efficiency program costs(5)
Energy efficiency program costs(5)
7,622 — 7,622 13,225 
Power supply costs(6)
Power supply costs(6)
2022-202342,940 (9,411)33,529 — 
Fixed cost adjustment(6)
Fixed cost adjustment(6)
2022-202335,058 19,886 54,944 55,491 
North Valmy plant settlements(6)
North Valmy plant settlements(6)
2022-202897,852 — 97,852 103,085 
Jim Bridger plant settlement(6)
Wildfire Mitigation Plan deferral(6)
Asset retirement obligations(7)
Asset retirement obligations(7)
 — 22,585 22,585 19,035 
Wildfire Mitigation Plan deferral(6)
 — 6,075 6,075 — 
Long-term service agreementLong-term service agreement2022-204314,046 9,227 23,273 24,431 
OtherOther2022-20552,846 14,204 17,050 10,844 
TotalTotal $397,987 $1,135,667 $1,533,654 $1,558,895 
Regulatory Liabilities:Regulatory Liabilities:     Regulatory Liabilities: 
Income taxes(8)
Income taxes(8)
 $— $96,880 $96,880 $95,883 
Depreciation-related excess deferred income taxes(9)
Depreciation-related excess deferred income taxes(9)
170,039 — 170,039 178,997 
Removal costs(7)
Removal costs(7)
 — 184,670 184,670 182,334 
Investment tax creditsInvestment tax credits — 109,460 109,460 97,627 
Deferred revenue-AFUDC(10)
Deferred revenue-AFUDC(10)
 141,450 46,267 187,717 169,095 
Energy efficiency program costs(5)
Power supply costs(6)
Power supply costs(6)
— — — 15,009 
Settlement agreement sharing mechanism(6)
2022-2023569 — 569 — 
Mark-to-market liabilities
Mark-to-market liabilities
Mark-to-market liabilitiesMark-to-market liabilities — 8,581 8,581 1,995 
Tax reform accrual for future amortization(11)
Tax reform accrual for future amortization(11)
— 24,522 24,522 16,893 
OtherOther4,697 5,799 10,496 11,001 
TotalTotal $316,755 $476,179 $792,934 $768,834 
(1) Earning a return includes either interest or a return on the investment as a component of rate base at the allowed rate of return. The interest rate on deferral accounts is published annually by the IPUC and OPUC. The applicable rates for 2023 were 2% and 4.5%, respectively.
(2) Represents flow-through income tax accounting differences which have a corresponding deferred tax liability disclosed in Note 2 - "Income Taxes."
(3) Represents the unfunded obligation of Idaho Power’s pension and postretirement benefit plans, which are discussed in Note 1211 - "Benefit Plans."
(4) Idaho Power records a regulatory asset for the difference between net periodic pension cost and pension cost considered for rate-making purposes relating to Idaho Power's defined benefit pension plan. In its Idaho jurisdiction, Idaho Power’s inclusion of pension costs for the establishment of retail rates is based upon contributions made to the pension plan. This regulatory asset account represents the difference between cumulative cash contributions and amounts collected in rates. Deferred costs are amortized into expense as the amounts are provided for in Idaho retail revenues.
(5)    The energy efficiency asset includes bothand liability represent the separate Idaho and Oregon jurisdiction balances at December 31, 20212022, and 2020.December 31, 2023, respectively. During 2023, the balances changed from an asset to a liability in the Idaho jurisdiction.
(6) This item is discussed in more detail in this Note 3 - "Regulatory Matters."
(7) Asset retirement obligations and removal costs are discussed in Note 1413 - "Asset Retirement Obligations (ARO)."
(8) Represents the tax gross-up related to the depreciation-related excess deferred income taxes and investment tax credits included in this table and has a corresponding deferred tax asset disclosed in Note 2 - "Income Taxes."
(9) In 2017, income tax reform reduced deferred income tax assets and liabilities. For depreciation-related temporary differences under the normalized tax accounting method, the resulting excess deferred taxes will flow back to customers ratably over the remaining regulatory lives of Idaho Power's plant assets under the alternative method provided in the statute. The average rate assumption method was used to compute this reversal for fiscal years 2018-2020.
(10) Idaho Power is collecting revenue in the Idaho jurisdiction for AFUDC on HCC relicensing costs but is deferring revenue recognition of the amounts collected until the license is issued and the asset is placed in service under the new license.
(11) Represents amount accrued under the May 2018 Idaho Tax Reform Settlement Stipulationtax reform settlement stipulation (described below) for the future amortization of existing or future unspecified regulatory deferrals that would otherwise be a future liability recoverable from Idaho customers.

94
Table of Contents
Idaho Power’s regulatory assets and liabilities are typically amortized over the period in which they are reflected in customer rates. In the event that recovery of Idaho Power’s costs through rates becomes unlikely or uncertain, regulatory accounting would no longer apply to some or all of Idaho Power’s operations and the items above may represent stranded investments. If
101
Table of Contents
not allowed full recovery of these items, Idaho Power would be required to write off the applicable portion, which could have a materially adverse financial impact.

Power Cost Adjustment Mechanisms and Deferred Power Supply Costs

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 sheets for future recovery or refund. The power supply costs deferred primarily result from changes in the levels of Idaho Power's own hydroelectric generation, changes in contracted power purchase prices and volumes, changes in wholesale market prices and transaction volumes, and changes in fuel prices.

Idaho Jurisdiction Power Cost Adjustment Mechanism: In the Idaho jurisdiction, the annual power cost adjustment (PCA)PCA consists of (a) a forecast component, based on a forecast of net power supply costs in the coming year as compared with net power supply costs included in base rates; and (b) a true-upbalancing component based onthat trues up the difference between the previous year’s actual net power supply costs and the costs collected in the previous year’s forecast.year's forecast component. The latter component also includes a balancing mechanism soensures that, over time, the actual collection or refund of authorized true-up dollarsnet power supply costs matches the amounts authorized. The PCA mechanism also 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 exceptions of expenses associated with PURPA power purchases and demand response incentive payments, which are allocated 100 percent to customers; and
•a sales-based adjustment intended to ensure that power supply expense recovery resulting solely from sales volume changes does not distort the results of the mechanism.

The Idaho deferral period or Idaho-jurisdiction PCA year runs from April 1 through March 31. Amounts deferred during the PCA year are primarily recovered or refunded during the subsequent June 1 through May 31 period. In May 2021,2023, the IPUC orderedapproved recovery of an incremental $200.2 million of Idaho-jurisdiction PCA revenues, but directed 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 filingspread recovery of the 2022 PCA application in April 2022. In January 2022, the IPUC approved Idaho Power's proposed modifications to the PCA, which simplify the mechanism without impairing the intent or effectiveness$190.2 million deferral balance component of the PCA over a two-year period from June 1, 2023 to May 31, 2025, resulting in a total PCA increase of $105.1 million, effective for the PCA collection period from June 1, 2023 to May 31, 2024. The order deferred collection of $95.1 million of deferred PCA costs to the subsequent annual PCA collection period from June 1, 2024, to May 31, 2025. The net increase in PCA revenues reflects higher market energy and have no material impact on overall cost recovery.natural gas prices, combined with lower-than-expected hydropower generation and limited coal supply in the prior April 2022 to March 2023 PCA period. The net increase also reflects an expectation of continued elevated market energy and natural gas prices in the April 2023 to March 2024 forecast period.

The table below summarizes the three most recent Idaho-jurisdiction PCA rate adjustments, which also include non-PCA-related rate adjustments as ordered by the IPUC:
Effective Date$ Change (millions)Notes
June 1, 2023$Notes105.1 The $105.1 million increase in PCA rates reflects higher market energy and natural gas prices, combined with lower-than-expected low-cost hydropower generation and limited coal supply. The increased rate also reflects an expectation of continued elevated market energy prices and natural gas prices in the forecast period.
June 1, 2022$94.9 The increase in PCA rates reflected a forecasted reduction in low-cost hydroelectric generation as well as higher costs associated with market energy prices and natural gas prices. The rate also reflected $0.6 million of 2021 earnings shared with customers under the 2018 Settlement Stipulation described below.
June 1, 2021$39.1 The net increase in PCA revenues reflectsrates reflected a forecasted reduction in low-cost hydroelectric generation as well as higher costs associated with forecasted PURPA power purchases. The net increase in PCA revenuesrates also reflectsreflected a smaller credit to customers thruthrough the true-up component.
June 1, 2020$58.7 The $58.7 million increase in PCA rates reflects a return to a more normal level of power supply costs as wholesale market energy prices came down from unusually high levels in the previous year's PCA and a forecasted reduction in low-cost hydropower generation.
June 1, 2019$(50.1)The $$50.1 million decrease in PCA rates includes a $5.0 million credit to customers for sharing of 2018 earnings under the October 2014 Idaho Earnings Support and Sharing Settlement Stipulation and a $2.7 million credit for income tax reform benefits related to Idaho Power's open access transmission tariff (OATT) rate under a May 2018 Idaho tax reform settlement stipulation as described below in this Note 3 - Regulatory Matters.
 
Oregon Jurisdiction Power Cost Adjustment Mechanism: Idaho Power’s power cost recovery mechanism in Oregon has two components: an annual power cost update (APCU) and a power cost adjustment mechanism (PCAM). The APCU allows Idaho
95
Table of Contents
Power to reestablish its Oregon base net power supply costs annually, separate from a general rate case, and to forecast net power supply costs for the upcoming water year. The PCAM is a true-up filed annually in February. The filing calculates the deviation between actual net power supply expenses incurred for the preceding calendar year and the net power supply expenses recovered through the APCU for the same period. Actual 2023 Oregon-jurisdiction power supply costs were less than the amount recovered through the APCU, resulting in a $0.9 million refund due to customers, while in 2022, Oregon jurisdiction power supply cost changes underexceeded the amount recovered through the APCU, resulting in a $1.1 million deferral of costs for future recovery. Variances during 2023 and PCAM during each of 2021, 2020, and 20192022 did not have a material impact on the companies' financial statements.
102
Table of Contents
Idaho Power's annual June 1 APCU rate changes were $7.7 million, $4.0 million, and $2.4 million in 2023, 2022, and 2021, respectively.
 
Notable Idaho Base Rate Adjustments

Idaho base rates were most recently established through a general rate case in 2023, with rate changes effective January 1, 2024. Previously, base rates were established in a general rate case in 2012 and adjusted in 2014, 2017, 2018, and 2019.

January 2012 and2023 Idaho General Rate Case: In June 2014 Idaho Base Rate Adjustments: Effective January 1, 2012,2023, Idaho Power implemented new Idaho base rates resulting from IPUC approval offiled a settlement stipulation that provided for a 7.86 percent authorized overallgeneral rate of return on an Idaho-jurisdiction rate base of approximately $2.36 billion. The settlement stipulation resulted in a 4.07 percent, or $34.0 million, overall increase in Idaho Power's annual Idaho-jurisdiction base rate revenues. Idaho base rates were subsequently adjusted again in 2012, in connectioncase with Idaho Power's completion of the Langley Gulch power plant.IPUC. In June 2012,December 2023, the IPUC issued an order approving a $58.1 million increase in annual Idaho-jurisdiction base rates, effective July 1, 2012. The order also provided for a $335.9 million increase in Idaho rate base. Neither the settlement stipulation noramong parties (2023 Settlement Stipulation) settling the IPUC orders adjusting base rates specified an authorized rate of return on equity or imposed a moratorium on Idaho Power filing a general rate case at a future date.case.

The IPUC issuedOrder and the 2023 Settlement Stipulation contains the following significant terms, among other items:

•Idaho Power will implement revised tariff schedules designed to increase annual Idaho-jurisdictional retail revenue by $54.7 million, or 4.25 percent, effective January 1, 2024. The $54.7 million of additional annual revenue is net of an Idaho-jurisdiction PCA rate decrease of $168.3 million and a March 2014 order approving Idaho Power's request forreduction to annual energy efficiency rider collection of $3.5 million, each of which was transferred into base rates;
•A 9.6 percent return on equity and a 7.247 percent authorized rate of return based on a non-specified cost of debt and capital structure, applied to an increase inIdaho-jurisdictional rate base of approximately $3.8 billion;
•Modifications to the normalized or "base level"Idaho-jurisdiction PCA including establishment of a new level of base net power supply expense of $484.9 million, which includes the transfer of $168.3 million from current PCA rates to be usedbase rates;
•Modifications to updatethe energy efficiency rider to support the transfer of $3.5 million of energy efficiency labor-related cost collection from the annual energy efficiency rider into base rates, andwarranting a decrease in the determinationenergy efficiency rider rate from 3.1 percent to 2.35 percent;
•Modifications to the Idaho-jurisdiction FCA mechanism to support Idaho Power’s rate designs and to reflect updated fixed costs;
•Continued deferral of incremental vegetation management and insurance costs, as measured from 2022 actual costs, through the earlier of Idaho Power’s next Idaho general rate case or 2025;
•An annual $18 million increase in collection of Idaho Power’s regulatory asset associated with its defined benefit pension plan contributions;
•Modifications to Idaho Power’s ADITC and revenue sharing mechanism beginning in 2024 to (1) include an additional amount of investment tax credits equal to the incremental investment tax credits generated from Idaho Power’s investment in 2023 battery storage projects; (2) remove the existing $25 million annual cap on the amount of accelerated amortization of ADITCs; (3) establish a minimum specified Idaho ROE of 9.12 percent for additional amortization of ADITCs; (4) establish a 9.6 percent Idaho ROE as the threshold for revenue sharing of Idaho-jurisdiction earnings between Idaho Power and Idaho customers; and (5) implement all revenue sharing through the PCA rather than a portion offsetting customer-funded pension obligations;
•Agreement that Idaho Power’s capital expenditures through year-end 2022 were prudently incurred;
•Deferral and amortization of annual differences between certain periodic maintenance costs at Idaho Power’s natural gas-fired power plants; and
•A residential price modernization plan and updated rate that became effective June 1, 2014.designs.

October 2014Under the modified ADITC and Revenue Sharing mechanism, if Idaho Earnings SupportPower's annual Idaho ROE in any year exceeds 9.6 percent, the amount of earnings exceeding 9.6 percent will be allocated 80.0 percent to Idaho Power's Idaho customers as a rate reduction to be effective at the time of the subsequent year's PCA, and Sharing Settlement Stipulation:20.0 percent to Idaho Power.

In October 2014,2023, Idaho Power recorded no amortization of ADITC. Accordingly, at December 31, 2023, the IPUC issued an order approving an extension, with modifications,full amount of ADITC remained available for future use under the terms of a December 2011 Idaho settlement stipulation for the period from 2015 through 2019, or until the terms are otherwise modified or terminated by order of the IPUC or the full $45 million of additional accumulated deferred investment tax credits (ADITC) contemplated by the settlement stipulation has been amortized (October 2014 Idaho Earnings Support and Sharing Settlement Stipulation). The provisions of the October 2014 Idaho Earnings Support and Sharing2023 Settlement Stipulation areand the 2018 Settlement Stipulation described in the table below.
96
Table of Contents

May 2018 Idaho Tax Reform Settlement Stipulation: In December 2017, the Tax Cuts and Jobs Act was signed into law, which, among other things, lowered the corporate federal income tax rate from 35 percent to 21 percent and modified or eliminated certain federal income tax deductions for corporations. In March 2018, Idaho House Bill 463 was signed into law reducing the Idaho state corporate income tax rate from 7.4 percent to 6.925 percent.

In May 2018, the IPUC issued an order approving a settlement stipulation (May 2018 Idaho Tax Reform(2018 Settlement Stipulation) related to income tax reform. Beginning June 1, 2018, the settlement stipulation2018 Settlement Stipulation provided an annual (a) $18.7 million reduction to Idaho customer base rates and (b) $7.4 million amortization of existing regulatory deferrals for specified items or future amortization of other existing or future unspecified regulatory deferrals that would otherwise be a future regulatory asset recoverable from Idaho customers. The May 2018 Idaho Tax Reform Settlement Stipulation also provided for the indefinite extension, with modifications, noted in the table below, of the Octobera previous 2014 Idaho Earnings Support and Sharing Settlement Stipulationsettlement stipulation beyond its termination date of December 31, 2019.

103
Table of Contents
The table below summarizes2019, with modified terms related to the ADITC and compares the terms of the October 2014 Idaho Earnings Support and Sharing Settlement Stipulation with the terms in the May 2018 Idaho Tax Reform Settlement Stipulationrevenue sharing mechanism that became applicable oneffective January 1, 2020.
October 2014 Idaho Earnings Support and Sharing Settlement Stipulation
(Effective through December 31, 2019)
May 2018 Idaho Tax Reform Settlement Stipulation
(Effective January 1, 2020, with no defined end date)
If Idaho Power's actual annual Idaho ROE in any year is less than 9.5 percent, then Idaho Power may record additional ADITC amortization up to $25 million to help achieve a 9.5 percent Idaho ROE for that year, and may record additional ADITC amortization up to a total of $45 million over the 2015 through 2019 period. If the $45 million of ADITC are completely amortized, the revenue sharing provisions below would no longer be applicable.If Idaho Power's actual annual Idaho ROE in any year is less than 9.4 percent, then Idaho Power may amortize up to $25 million of additional ADITC to help achieve a 9.4 percent Idaho ROE for that year, so long as the cumulative amount of ADITC used does not exceed $45 million (Idaho Power will have available and may continue to use any unused portion of the $45 million of additional ADITC from the October 2014 Idaho Earnings Support and Sharing Settlement Stipulation); however, Idaho Power may seek approval from the IPUC to replenish the total amount of ADITC it is permitted to amortize. If there are no remaining amounts of ADITC authorized to be amortized, the revenue sharing provisions below would not be applicable until ADITC is replenished.
If Idaho Power's annual Idaho ROE in any year exceeds 10.0 percent, the amount of earnings exceeding a 10.0 percent Idaho ROE and up to and including a 10.5 percent Idaho ROE will be allocated 75 percent to Idaho Power's Idaho customers as a rate reduction to be effective at the time of the subsequent year's PCA, and 25 percent to Idaho Power.If Idaho Power's annual Idaho ROE in any year exceeds 10.0 percent, the amount of earnings exceeding a 10.0 percent Idaho ROE and up to and including a 10.5 percent Idaho ROE will be allocated 80 percent to Idaho Power's Idaho customers as a rate reduction to be effective at the time of the subsequent year's PCA, and 20 percent to Idaho Power.
If Idaho Power's annual Idaho ROE in any year exceeds 10.5 percent, the amount of earnings exceeding a 10.5 percent Idaho ROE will be allocated 50 percent to Idaho Power's Idaho customers as a rate reduction to be effective at the time of the subsequent year's PCA, 25 percent to Idaho Power's Idaho customers in the form of a reduction to the pension regulatory asset balancing account (to reduce the amount to be collected in the future from Idaho customers), and 25 percent to Idaho Power.If Idaho Power's annual Idaho ROE in any year exceeds 10.5 percent, the amount of earnings exceeding a 10.5 percent Idaho ROE will be allocated 55 percent to Idaho Power's Idaho customers as a rate reduction to be effective at the time of the subsequent year's PCA, 25 percent to Idaho Power's Idaho customers in the form of a reduction to the pension regulatory asset balancing account (to reduce the amount to be collected in the future from Idaho customers), and 20 percent to Idaho Power.
In the event the IPUC approves a change to Idaho Power's allowed annual Idaho ROE as part of a general rate case proceeding before December 31, 2019, the Idaho ROE thresholds will be adjusted on a prospective basis as follows: (a) the Idaho ROE under which Idaho Power will be permitted to amortize an additional amount of ADITC will be set at 95 percent of the newly authorized Idaho ROE, (b) sharing with customers on an 75 percent basis as a customer rate reduction will begin at the newly authorized Idaho ROE, and (c) sharing with customers on a 75 percent basis but allocated 50 percent to a rate reduction, and 25 percent to a pension expense deferral regulatory asset, will begin at 105 percent of the newly authorized Idaho ROE.In the event the IPUC approves a change to Idaho Power's allowed annual Idaho ROE as part of a general rate case proceeding effective on or after January 1, 2020, the Idaho ROE thresholds will be adjusted on a prospective basis as follows: (a) the Idaho ROE under which Idaho Power will be permitted to amortize an additional amount of ADITC will be set at 95 percent of the newly authorized Idaho ROE, (b) sharing with customers on an 80 percent basis as a customer rate reduction will begin at the newly authorized Idaho ROE, and (c) sharing with customers on an 80 percent basis but allocated 55 percent to a rate reduction, and 25 percent to a pension expense deferral regulatory asset, will begin at 105 percent of the newly authorized Idaho ROE.

The May 2018 Idaho Tax Reform Settlement Stipulation did not impose a moratorium onprovided Idaho Power filingthe ability to earn a generalminimum Idaho ROE of 9.4 percent by amortizing up to $25 million of additional ADITC in any calendar year. If Idaho Power’s annual Idaho ROE in any year exceeded 10.0 percent, the amount of earnings exceeding 10.0 percent and up to and including 10.5 percent would be allocated 80 percent to Idaho Power’s Idaho customers as a rate case or other formreduction to be effective at the time of rate proceeding inthe subsequent year’s PCA, and 20 percent to Idaho during its respective term.Power. Idaho Power’s ADITC and revenue sharing mechanism was modified by the 2023 Settlement Stipulation.

In 2021, Idaho Power recorded a $0.6 million provision against current revenue for sharing with customers, as its full-year return on year-end equity in the Idaho jurisdiction (Idaho ROE) exceeded 10.0 percent. In 2020, Idaho Power recorded no provision against current revenue for sharing with customers, as its Idaho ROE was between 9.4 percent and 10.0 percent in 2020. Accordingly, at December 31, 2021, the full $45 million of additional ADITC remained available for future use under the terms of the May 2018 Idaho Tax Reform Settlement Stipulation.

North Valmy Base Rate Adjustment Settlement Stipulations:In May 2017, Idaho Power has settlement stipulations in place in Idaho and Oregon related to the IPUC approved a settlement stipulation allowing accelerated depreciation and cost recovery for Idaho Power’splanned end of its participation in coal-fired operations of both units of its jointly-owned North Valmy coal-fired power plant. Idaho Power ceased coal-fired operations at unit 1 in 2019, as planned, and these settlement stipulations provide for Idaho Power to cease coal-fired operations at unit 2 in 2025. The IPUC-approved settlement stipulation provides for an increase in Idaho jurisdictional revenues of $13.3 million per year, and (1) levelized collections and associated cost recovery through December 2028, (2) accelerated depreciation on unit 1 through 2019for the North Valmy plant to allow the coal-related plant assets to be fully depreciated and unit 2 through 2025, and (3)recovered by December 31, 2028, (2) Idaho Power to use prudent and commercially reasonable efforts to end its participation in coal-fired operations at North Valmy as described above, (3) a balancing account to track the operation of unit 1 byincremental costs, benefits, and required regulatory accounting associated with ceasing participation in coal-fired operations at the end of 2019North Valmy plant, and unit 2 no later than(4) increased customer rates related to the end of 2025. The costs intended to be recovered by the increased jurisdictional revenues include current investments as of May 31, 2017, in both units, forecasted unit 1 investments from 2017 through 2019, and forecasted decommissioning costs for unit 1 and unit 2, offset by forecasted operation and maintenance costs
104
Table of Contents
savings. The settlement stipulation also provides for the regulatory accrual or deferral of the difference between actualassociated incremental annual levelized revenue requirements and levelized collections, and provides for the regulatory accrual or deferral of the difference between actual costs incurred (including accelerated depreciation expense on unit 1 through 2019 and unit 2 through 2025) compared with costs permitted to be recovered during the cost recovery period specified in the settlement stipulation (including depreciation expense through 2028).requirement. If actual costs incurred differ from forecasted amounts included in the settlement stipulation, collection or refund of any differences would be subject to regulatory approval.

Jim Bridger Power Plant Rate Base Adjustment and Recovery: In February 2019, Idaho Power reached an agreement with NV Energy that facilitates the planned end of Idaho Power's participation in coal-fired operations at units 1 and 2 of its jointly-owned North Valmy coal-fired power plant in 2019 and no later than 2025, respectively. In May 2019,June 2022, the IPUC issued an order approving, with modifications, Idaho Power’s amended application requesting authorization to (1) accelerate depreciation for the North ValmyJim Bridger plant agreementto allow the coal-related plant assets to be fully depreciated and allowing Idaho Powerrecovered by December 31, 2030, (2) establish a balancing account to recover throughtrack the incremental costs, benefits, and required regulatory accounting associated with ceasing participation in coal-fired operations at the Jim Bridger plant, and (3) increase customer rates related to the $1.2 millionassociated 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 rates and actual incremental costs and benefits associated with required North Valmy plant investments and other exit costs, effective June 1, 2019, through December 31, 2028. In December 2019, as planned, Idaho Power endedPower’s plan at the time of the Bridger Order to cease its participation in coal-fired operations at the Jim Bridger plant by the end of North Valmy2028. The incremental costs and benefits include the revenue requirement associated with the incremental Jim Bridger plant unit 1. In September 2021,coal-related investments made from 2012 through the IPUC issued an order acknowledging Idaho Power's year-end 2025 exit dateend of 2020, forecasted coal-related investments, and near-term decommissioning costs, offset by other O&M cost savings. The Bridger Order deemed all coal-related investments at the Jim Bridger plant from Valmy unit 2 is appropriate based on economics and reliability needs.2012 through 2020 to be prudent for recovery.

In the Bridger Order, the IPUC reduced Idaho Power's requested rate increase from 2.1 percent in its amended filing to 1.5 percent, a reduction from a requested $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. The uncollected amounts tracked in this balancing account were included for recovery in the 2023 Settlement Stipulation. Idaho Power 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. 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 31, 2020, as well as forecasted coal-related investments.

Other Notable Idaho Regulatory Matters

Fixed Cost Adjustment: The Idaho jurisdiction fixed cost adjustment (FCA)FCA mechanism, applicable to Idaho residential and small commercial customers, is designed to remove a portion of Idaho Power’s financial disincentive to invest in energy efficiency programs by separating (or decoupling) the recovery of fixed costs from the variable kilowatt-hour (kWh)kWh charge and linking it instead to a set amount per customer. Under Idaho Power's current rate design, recovery of a portion of fixed costs is included in the variable kWh charge, which may result in
97
Table of Contents
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 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 2021,2023, the IPUC ordered Idaho Power to work with interested parties and initiateissued an order approving a case to review$10.1 million decrease in recovery from the FCA mechanismfrom $35.2 million to $25.1 million for the 2022 FCA deferral, with new rates effective for the period from June 1, 2023, to May 31, 2024. Beginning with the 2024 FCA deferral, the 2023 Settlement Stipulation updates the authorized fixed-cost recovery amount per customer and propose modifications it determines are appropriate. In December 2021, the IPUC approved Idaho Power's proposed modifications tomodifies parts of the FCA mechanism to institute separate, and reduced, fixed cost tracking for customers added tosupport Idaho Power's system after December 31, 2021.proposed rate designs, as noted above.

The following table summarizes FCA amounts approved for collection in the prior three FCA years:
FCA YearFCA YearPeriod Rates in EffectAnnual Amount
 (in millions)		FCA YearPeriod Rates in EffectAnnual Amount
 (in millions)
20222022June 1, 2023-May 31, 2024$25.1
20212021June 1, 2022-May 31, 2023$35.2
20202020June 1, 2021-May 31, 2022$38.32020June 1, 2021-May 31, 2022$38.3
2019June 1, 2020-May 31, 2021$35.5
2018June 1, 2019-May 31, 2020$34.8

Wildfire Mitigation Cost Recovery: In June 2021 and March 2023, the IPUC authorizedissued orders authorizing 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 projected spending approximately $47 million in incremental wildfire mitigation-related O&M and roughly $35 million in wildfire mitigation system-hardening capital incremental expenditures over 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.WMP. As of December 31, 2021,2023, Idaho Power'sPower’s deferral balance of Idaho-jurisdiction costs related to the WMP was $6.1$51.3 million.

Jim Bridger Power Plant Rate Request: In June 2021, As a result of the 2023 Settlement Stipulation, Idaho Power filed an application with the IPUC requesting authorization to (a) accelerate depreciation for the Jim Bridger plant, to allow the plant to be fully depreciatedwill recover and recovered by December 31, 2030, (b) establish a balancing account to track the incremental costs and benefits 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.

In September 2021, the co-owner and operatoramortize its WMP deferral balance through 2022 of the Jim Bridger Plant submitted its IRP to the IPUC that contemplates ceasing coal-fired generation in units$26.7 million, beginning January 1, and 2 in 2023 and converting those units to natural gas generation by 2024. Idaho Power's 2021 IRP includes the same plan. At a public meeting in October 2021, the IPUC approved a joint motion by Idaho Power and the IPUC Staff to suspend the procedural schedule in Idaho Power's rate request case to assess new developments that impact
105
Table of Contents
operations at the Jim Bridger plant, citing the potential option to convert the two units to natural gas generation as well as ongoing regional haze compliance discussions. In February 2022, Idaho Power filed a request to resume the procedural schedule with an amended application to the IPUC that contemplates the conversion of units 1 and 2 to natural gas in 2024 and therefore removes from the application all investments for the portion of the plant that will be converted to support gas-fired operations, leaving just coal-related plant investments in the requested regulatory treatment. The updated filing requests authorization to adjust customer rates to recover the associated incremental annual levelized revenue requirement in the aggregate amount of $27.1 million, which included Idaho Power's share of all electric plant in service related to coal-fired operations at the Jim Bridger plant. The proposed adjustment in this application would result in an overall rate increase of 2.12 percent in Idaho. As of the date of this report, the case remains pending at the IPUC.

Notable Oregon Regulatory Matters

Oregon Base Rate Changes: Oregon base rates were most recently established in a general rate case in 2012. In February 2012, the Public Utility Commission of Oregon (OPUC)OPUC issued an order approving a settlement stipulation that provided for a $1.8 million base rate increase, a return on equity of 9.9 percent, and an overall rate of return of 7.757 percent in the Oregon jurisdiction. New rates in conformity with the settlement stipulation were effective March 1, 2012. Subsequently, in September 2012, the OPUC issued an order approving an approximately $3.0 million increase in annual Oregon jurisdiction base rates, effective October 1, 2012, for inclusion of the Langley Gulch power plant in Idaho Power's Oregon rate base. Additionally, in October 2020, the OPUC approved an increase in Oregon customer rates of $0.4 million annually associated with amortization of deferred Langley Gulch power plant revenue requirement variances, effective November 1, 2020, through October 31, 2024.

In May 2018, the OPUC issued an order approving a settlement stipulation that provides for an annual $1.5 million reduction to Oregon customer base rates beginning June 1, 2018 through May 31, 2020, related to income tax reform. In May 2020, the OPUC issued an order to approve the quantification of $1.5 million in annualized Oregon jurisdictional benefits associated with federal and state income tax changes resulting from tax reform and adjusting customer rates to reflect this amount, effective June 1, 2020, until its next general rate case or other proceeding where the tax-related revenue requirement components are reflected in rates.

In June 2017,The OPUC has also approved settlement stipulations that provide for the OPUC approved a settlement stipulation allowing for (1) accelerated depreciation of North Valmy plant units 1 and 2 through December 31, 2025, (2) cost recovery of incrementaljointly-owned North Valmy plant investmentsunit 1 through May 31, 2017,2019 and (3) forecasted North Valmy plant decommissioning costs.unit 2 through 2025. The settlement stipulation provides for an increase innet rate impact of the Oregon jurisdictional revenue requirement of $1.1 million, with yearly adjustments, if warranted. In May 2018, the OPUC also deemed prudent Idaho Power's decision to pursue the end of its participation in coal-fired operations of unit 1 by the end of 2019 and approved Idaho Power's request to recover annual incremental accelerated depreciation relating to unit 1, ending December 31, 2019, resulting in a $2.5 million annualized revenue requirement. In October 2019, the OPUC approved the North Valmy plant agreement and authorized Idaho Power to adjust customer rates in Oregon, effective January 1, 2020, to reflect a decrease in the annual levelized revenue requirement of $3.2 million, which mostly relates to the decrease in depreciation expense and other costs associated with the December 2019 end of Idaho Power's participation in coal-fired operations of North Valmy plant unit 1.settlement stipulations is immaterial.

Other Notable Regulatory MattersIn December 2023, Idaho Power filed a general rate case with the OPUC. The filing was based on a 2024 test year and requested an overall annual rate increase of $10.7 million, or 19.28 percent. The filing requested, among other items, a 10.4 percent authorized rate of return on equity and an approximate $188.9 million Oregon-jurisdiction retail rate base. The $188.9 million of rate base excludes rate base associated with Idaho Power's jointly-owned North Valmy coal facilities, the costs of which are recovered under the separate rate mechanism noted above. In its application, Idaho Power proposed a capitalization structure of 49 percent long-term debt and 51 percent common stock equity. Idaho Power included an average cost of debt of 5.104 percent and an overall cost of capital of 7.807 percent. If approved by the OPUC, new rates for Oregon-jurisdiction customers would become effective in October 2024 or later.

98
Depreciation Rate Requests:Table of Contents                              In 2021, Idaho Power conducted a depreciation study of electric plant-in-service, which it performs approximately every five years. The study provided updates to net salvage percentages and service life estimates for Idaho Power plant assets. In November 2021, in each of the Idaho and Oregon jurisdictions, Idaho Power and other stakeholders filed a joint motion for approval of a settlement stipulation adopting new depreciation rates and agreeing to no increase in the jurisdictional revenue requirement and no change in customer rates. In December 2021 and January 2022, respectively, the IPUC and OPUC approved Idaho Power's requests, which were effective January 1, 2022.

Federal Regulatory Matters - Open Access Transmission Tariff Rates

Idaho Power uses a formula rate for transmission service provided under its OATT, which allows transmission rates to be updated annually based primarily on actual financial and operational data Idaho Power files with the FERC and allows Idaho
106
Table of Contents
Power to recover costs associated with its transmission system. Idaho Power's OATT rates submitted to the FERC in Idaho Power's four most recent annual OATT Final Informational Filings were as follows:
Applicable PeriodOATT Rate (per kW-year)
October 1, 2023 to September 30, 2024$30.74 
October 1, 2022 to September 30, 2023$31.42 
October 1, 2021 to September 30, 2022$31.19 
October 1, 2020 to September 30, 2021$29.95 
October 1, 2019 to September 30, 2020$27.32 
October 1, 2018 to September 30, 2019$31.25 

Idaho Power's current OATT rate is based on a net annual transmission revenue requirement of $127.3$135.7 million, which represents the OATT formulaic determination of Idaho Power's net cost of providing OATT-based transmission service.

4. REVENUES
 
The following table provides a summary of electric utility operating revenues for IDACORP and Idaho Power (in thousands):
Year Ended December 31,
Year Ended December 31,Year Ended December 31,
202120202019 202320222021
Electric utility operating revenues:Electric utility operating revenues:
Revenue from contracts with customersRevenue from contracts with customers$1,382,653 $1,286,637 $1,285,286 
Revenue from contracts with customers
Revenue from contracts with customers
Alternative revenue programs and derivative revenuesAlternative revenue programs and derivative revenues72,757 60,703 57,654 
Total electric utility operating revenuesTotal electric utility operating revenues$1,455,410 $1,347,340 $1,342,940 

Revenues from Contracts with Customers

Revenues from contracts with customers are primarily related to Idaho Power’s regulated tariff-based sales of energy or related services. Generally, tariff-based sales do not involve a written contract, but are classified as revenues from contracts with customers. Idaho Power assesses revenues on a contract-by-contract basis to determine the nature, amount, timing, and uncertainty, if any, of revenues being recognized.

99
Table of Contents
The following table presents revenues from contracts with customers disaggregated by revenue source (in thousands):

Year Ended December 31,
 202120202019
Revenues from contracts with customers:
Retail revenues:
 Residential (includes $34,835, $34,409, and $35,587, respectively, related to the FCA(1))
$583,061 $547,404 $526,966 
 Commercial (includes $1,407, $1,543, and $1,336, respectively, related to the FCA(1))
314,745 293,057 295,203 
Industrial195,214 181,258 181,372 
Irrigation168,664 154,791 135,850 
Provision for sharing(569)— — 
Deferred revenue related to HCC relicensing AFUDC(2)
(8,780)(8,780)(8,780)
Total retail revenues1,252,335 1,167,730 1,130,611 
Less: FCA mechanism revenues(1)
(36,242)(35,952)(36,923)
Wholesale energy sales40,839 33,656 71,198 
Transmission wheeling-related revenues67,997 51,592 53,828 
Energy efficiency program revenues29,920 42,478 40,128 
Other revenues from contracts with customers27,804 27,133 26,444 
Total revenues from contracts with customers$1,382,653 $1,286,637 $1,285,286 
107
Table of Contents
Year Ended December 31,
 202320222021
Revenues from contracts with customers:
Retail revenues:
 Residential (includes $37,233, $22,595, and $34,835, respectively, related to the FCA(1))
$684,649 $645,236 $583,061 
 Commercial (includes $1,338, $922, and $1,407, respectively, related to the FCA(1))
378,330 347,970 314,745 
Industrial244,538 217,368 195,214 
Irrigation173,929 170,964 168,664 
Provision for sharing— — (569)
Deferred revenue related to HCC relicensing AFUDC(2)
(8,780)(8,780)(8,780)
Total retail revenues1,472,666 1,372,758 1,252,335 
Less: FCA mechanism revenues(1)
(38,571)(23,517)(36,242)
Wholesale energy sales63,421 66,519 40,839 
Transmission wheeling-related revenues80,357 80,527 67,997 
Energy efficiency program revenues31,948 33,197 29,920 
Other revenues from contracts with customers29,791 28,490 27,804 
Total revenues from contracts with customers$1,639,612 $1,557,974 $1,382,653 
(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 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 $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.

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

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

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

100
Table of Contents
Commercial Customers: Most businesses are included in Idaho Power's commercial customer class, as are small industrial companies, and public street and highway lighting accounts. Idaho Power’s commercial customers are less influenced by weather conditions than residential customers, although weather does still affect commercial customer energy use. Economic conditions, including manufacturing activity levels, and energy efficiency initiatives also affect energy use of commercial customers. In 2021, a return to more normal economic conditions for commercial customers compared with 2020 increased sales volumes on a per customer basis, as 2020 was affected by negative COVID-19-related business conditions.

Industrial Customers: Industrial customers consist of large industrial companies, including special contract customers. Energy use of industrial customers is primarily driven by economic conditions, with weather having little impact on this customer class. In 2021, a return to more normal economic conditions for industrial customers compared with 2020 increased sales volumes on a per customer basis, as 2020 was affected by negative COVID-19-related business conditions.

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

Provision for Sharing: Idaho Power has regulatory settlement stipulations in Idaho that provide for the potential sharing between Idaho Power and its Idaho customers of Idaho-jurisdictional earnings in excess of 10.0 percent of Idaho ROE.ROE (in excess of 9.6 percent of Idaho ROE beginning in 2024). Based on full-year 20212023 Idaho ROE, Idaho Power recorded $0.6 millionno provision against current revenues for sharing of earnings with customers for 2021.2023. During 2020 and 2019,2022, no provision against current revenues forwas recorded and in 2021, $0.6 million of sharing of earnings with customers was recorded. The regulatory settlement stipulations are described further in Note 3 - "Regulatory Matters."

Wholesale Energy Sales: As a public utility under the Federal Power Act (FPA),FPA, Idaho Power has the authority to charge market-based rates for wholesale energy sales under its FERC tariff. Idaho Power’s wholesale electricity sales are primarily to utilities and power marketers and are predominantly short-term and consist of a single performance obligation satisfied as
108
Table of Contents
energy is transferred to the counterparty. Idaho Power's wholesale energy sales depend largely on the availability of generation resources in excess of the amount necessary to serve customer loads as well as adequate market power prices and demand at the time when those resources are available. A reduction in any of those factors may lead to lower wholesale energy sales.

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

Energy Efficiency Program Revenues: Idaho Power collects most of its energy efficiency program costs through an energy efficiency rider on customer bills. The rider collections are deferred until expenditures are incurred. Energy efficiency program expenditures funded through the rider are reported as an operating expense with an equal amount recognized in revenues, resulting in no net impact on earnings. Fewer energy efficiency projects were completed in 2021 due mostly to impacts of the COVID-19 public health crisis which decreased energy efficiency program revenues compared with prior years. 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 December 31, 2021,2023, Idaho Power's energy efficiency rider balances were a $6.9$0.7 million regulatory assetliability in the Idaho jurisdiction and a $0.7$0.8 million regulatory assetliability in the Oregon jurisdiction. In December 2020, the IPUC authorized Idaho Power to increase the Idaho energy efficiency rider collection percentage from 2.75 percent to 3.1 percent, effective January 1, 2021.

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 and billed to customers, Idaho Power records such amounts as recovery of the associated regulatory asset or liability and not as revenues.

101
Table of Contents
Derivative revenues include gains from settled electricity swaps and sales of electricity under forward sales contracts that are bundled with renewable energy credits.RECs. 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 consolidated statements of income. For more information on settled electricity swaps, see Note 1615 - "Derivative Financial Instruments."

The table below presents the FCA mechanism revenues and derivative revenues (in thousands):
Year Ended December 31,
Year Ended December 31,Year Ended December 31,
202120202019 202320222021
Alternative revenue programs and derivative revenues:Alternative revenue programs and derivative revenues:
FCA mechanism revenuesFCA mechanism revenues$36,242 $35,952 $36,923 
FCA mechanism revenues
FCA mechanism revenues
Derivative revenuesDerivative revenues36,515 24,751 20,731 
Total alternative revenue programs and derivative revenuesTotal alternative revenue programs and derivative revenues$72,757 $60,703 $57,654 

IDACORP's Other Operating Revenues

Other operating revenues on IDACORP's consolidated statements of income are primarily comprised of revenues from IDACORP’s subsidiary, Ida-West. Ida-West operates small hydropower generation projects that satisfy the requirements of PURPA.

109
102
Table of Contents                              

5. LONG-TERM DEBT
 

The following table summarizes IDACORP's and Idaho Power's long-term debt at December 31 (in thousands of dollars):
20212020
202320232022
First mortgage bonds:First mortgage bonds:
2.50% Series due 2023
2.50% Series due 2023
2.50% Series due 20232.50% Series due 2023$75,000 $75,000 
1.90% Series due 20301.90% Series due 203080,000 80,000 
6.00% Series due 20326.00% Series due 2032100,000 100,000 
4.99% Series due 2032
5.50% Series due 20335.50% Series due 203370,000 70,000 
5.50% Series due 20345.50% Series due 203450,000 50,000 
5.875% Series due 20345.875% Series due 203455,000 55,000 
5.30% Series due 20355.30% Series due 203560,000 60,000 
6.30% Series due 20376.30% Series due 2037140,000 140,000 
6.25% Series due 20376.25% Series due 2037100,000 100,000 
4.85% Series due 20404.85% Series due 2040100,000 100,000 
4.30% Series due 20424.30% Series due 204275,000 75,000 
5.06% Series due 2042
5.06% Series due 2043
4.00% Series due 20434.00% Series due 204375,000 75,000 
3.65% Series due 20453.65% Series due 2045250,000 250,000 
4.05% Series due 20464.05% Series due 2046120,000 120,000 
4.20% Series due 20484.20% Series due 2048450,000 450,000 
5.20% Series due 2053
5.50% Series due 2053
5.80% Series due 2054
Total first mortgage bondsTotal first mortgage bonds1,800,000 1,800,000 
Pollution control revenue bonds:Pollution control revenue bonds:
1.45% Series due 2024(1)
1.45% Series due 2024(1)
49,800 49,800 
1.45% Series due 2024(1)
1.45% Series due 2024(1)
1.70% Series due 2026(1)
1.70% Series due 2026(1)
116,300 116,300 
Variable Rate Series 2000 due 20274,360 4,360 
Total pollution control revenue bondsTotal pollution control revenue bonds170,460 170,460 
American Falls bond guarantee19,885 19,885 
Floating Rate Term Loan Facility due 2024
American Falls Variable Rate bond guarantee due 2025
Unamortized premium/discount and issuance costsUnamortized premium/discount and issuance costs10,295 10,069 
Total IDACORP and Idaho Power outstanding debt(2)
Total IDACORP and Idaho Power outstanding debt(2)
2,000,640 2,000,414 
Current maturities of long-term debtCurrent maturities of long-term debt— — 
Total long-term debtTotal long-term debt$2,000,640 $2,000,414 
(1) Humboldt County and Sweetwater County Pollution Control Revenue Bonds are secured by the first mortgage bonds, bringing the total first mortgage bonds outstanding at December 31, 2021,2023, to $1.966$2.811 billion.
(2) At both December 31, 20212023 and 2020,2022, the overall effective cost rate of Idaho Power's outstanding debt was 4.40 percent.4.98 percent and 4.60 percent, respectively.

At December 31, 2021,2023, the maturities for the aggregate amount of IDACORP and Idaho Power long-term debt outstanding were as follows (in thousands of dollars):
20222023202420252026Thereafter
$— $75,000 $49,800 $19,885 $116,300 $1,729,360 
Long-Term Debt Issuances, Maturities, and Redemptions

In April 2020, Idaho Power issued $230.0 million in principal amount of 4.20% first mortgage bonds, secured medium term notes, Series K, maturing March 1, 2048. The bonds were issued at a reoffer yield of 3.422 percent, which resulted in a net premium of 13.0 percent and net proceeds to Idaho Power of $259.9 million. After this offering the aggregate principal amount of the 4.20% first mortgage bonds is $450 million.
20242025202620272028Thereafter
$49,800 $19,885 $116,300 $— $— $2,645,000 

110103
Table of Contents                              
In June 2020,Long-Term Debt Issuances, Maturities, and Redemptions

On September 11, 2023, under the shelf registration statement with the SEC, Idaho Power issued $80.0$350 million in aggregate principal amount of 5.80% first mortgage bonds, secured medium-term notes, Series M, maturing on April 1, 2054.

On April 1, 2023, Idaho Power repaid $75 million in aggregate principal amount of maturing 2.50% first mortgage bonds due 2023,Series I.

On March 14, 2023, under the shelf registration statement with the SEC, Idaho Power issued $400 million in aggregate principal amount of 5.50% first mortgage bonds, secured medium-term notes, Series M, maturing on March 15, 2053.

On March 8, 2023, pursuant to the Bond Purchase Agreement defined below, Idaho Power issued $60 million in aggregate principal amount of 5.06% first mortgage bonds, secured medium-term notes, Series N, maturing on March 8, 2043; and $62 million in aggregate principal amount of 5.20% first mortgage bonds, secured medium-term notes, Series N, maturing on March 8, 2053.

On December 22, 2022, Idaho Power entered into a Bond Purchase Agreement (Bond Purchase Agreement) with certain institutional purchasers relating to the sale by Idaho Power of $170 million of first mortgage bonds secured medium-term-term notes, Series N (Series N Notes), as described in more detail below.

On December 1, 2022, Idaho Power redeemed at par $4.36 million in principal amount of 1.90% first mortgagevariable-rate pollution control revenue bonds secured medium term notes, Series L, maturing July 15, 2030. In July 2020,due in 2027.

On March 4, 2022, Idaho Power redeemed, prior to maturity, $75 millionentered into a floating rate term loan credit agreement (Term Loan Facility). The Term Loan Facility was a two-year senior unsecured term loan facility in the aggregate principal amount of 2.95 percent first mortgage bonds, medium-term notes, Series H due in April 2022. In accordance with$150 million. On March 31, 2023, Idaho Power repaid $100 million and on May 17, 2023, repaid $50 million principal amount to fully repay the redemption provisionsTerm Loan Facility. At December 31, 2023, there was no remaining outstanding principal balance of the notes, the redemption included Idaho Power's payment of a make-whole premium to the holders of the redeemed notes in the aggregate amount of $3.3 million.Term Loan Facility.

In August 2020, Idaho Power redeemed $100 million in principal amount of 3.40 percent first mortgage bonds due in November 2020.

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).WPSC. In AprilMay 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. Authority from the IPUC is effective through May 31, 2022,2025, subject to extensions upon request to the IPUC. The OPUC's and WPSC's orders do not impose a time limitation for issuances, but the OPUC order does impose a number of other conditions, including a requirement that the interest rates for the debt securities or first mortgage bonds fall within either (a) designated spreads over comparable U.S. Treasury rates or (b) a maximum interest rate limit of 7.08.0 percent. At December 31, 2023, $280 million remains available for debt issuance under the regulatory orders. In January 2024, Idaho Power submitted applications to the IPUC, OPUC, and WPSC requesting authorization to issue and sell from time to time up to $1.2 billion in aggregate principal amount of debt securities and first mortgage bonds, which if approved will replace the $280 million remaining under the existing regulatory orders. On February 8, 2024, Idaho Power received an order from OPUC authorizing its request. As of the date of this report, approvals from the IPUC and WPSC are still pending.

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 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).Indenture. Also in June 2020,2022, Idaho Power
entered into the Forty-ninthFiftieth Supplemental Indenture, dated effective as of June 5, 2020,30, 2022, to the Indenture (Forty-ninth
(Fiftieth Supplemental Indenture). The Forty-ninthFiftieth Supplemental Indenture provides for, among other items, the issuance of up to $1.2 billion in aggregate principal amount of Series M Notes pursuant to the Indenture. In October 2022, Idaho Power entered into the Fifty-first Supplemental Indenture to increase the limit of the amount of first mortgage bonds at any one time outstanding to $3.5 billion as provided in the Indenture. The amount issuable is also restricted by property, earnings, and other provisions of the Indenture and supplemental indentures to the Indenture. The Indenture requires that Idaho Power's net earnings be at least twice the
$500
104
Table of Contents
annual interest requirements on all outstanding debt of equal or prior rank, including the bonds that Idaho Power may propose to issue. Under certain circumstances, the net earnings test does not apply, including the issuance of refunding bonds to retire outstanding bonds that mature in less than two years or that are of an equal or higher interest rate, or prior lien bonds.

In December 2022, Idaho Power entered into the Bond Purchase Agreement with certain institutional purchasers, relating to the sale by Idaho Power of $170 million in aggregate principal amount of Series LN Notes. Also in December 2022, Idaho Power entered into the Fifty-second Supplemental Indenture, dated effective as of December 30, 2022, to the Indenture (Fifty-second Supplemental Indenture). The Fifty-second Supplemental Indenture provides for, among other items, the issuance of Series N Notes pursuant to the Indenture. The Series N Notes consist of:

•$23 million in aggregate principal amount of Idaho Power’s 4.99% first mortgage bonds due 2032, Series N Notes, Tranche 1 (Tranche 1 Bonds);
•$25 million in aggregate principal amount of Idaho Power’s 5.06% first mortgage bonds due 2042, Series N Notes, Tranche 2 (Tranche 2 Bonds);
•$60 million in aggregate principal amount of Idaho Power’s 5.06% first mortgage bonds due 2043, Series N Notes, Tranche 3 (Tranche 3 Bonds); and
•$62 million in aggregate principal amount of Idaho Power’s 5.20% first mortgage bonds due 2053, Series N Notes, Tranche 4 (Tranche 4 Bonds).

The Tranche 1 Bonds and Tranche 2 Bonds were issued on December 22, 2022, and the Tranche 3 Bonds and Tranche 4 Bonds were issued on March 8, 2023, each under the Indenture.

The mortgage of the Indenture secures all bonds issued under the Indenture equally and ratably, without preference, priority, or distinction. First mortgage bonds issued in the future will also be secured by the mortgage of the Indenture. The lien constitutes a first mortgage on all the properties of Idaho Power, subject only to certain limited exceptions including liens for taxes and assessments that are not delinquent and minor excepted encumbrances. Certain of the properties of Idaho Power are subject to easements, leases, contracts, covenants, workmen's compensation awards, and similar encumbrances and minor defects common to properties. The mortgage of the Indenture does not create a lien on revenues or profits, or notes or accounts receivable, contracts or choses in action, except as permitted by law during a completed default, securities, or cash, except when pledged, or merchandise or equipment manufactured or acquired for resale. The mortgage of the Indenture creates a lien on the interest of Idaho Power in property subsequently acquired, other than excepted property, subject to limitations in the case of consolidation, merger, or sale of all or substantially all of the assets of Idaho Power. The Indenture requires Idaho Power to spend or appropriate 15 percent of its annual gross operating revenues for maintenance, retirement, or amortization of its properties. Idaho Power may, however, anticipate or make up these expenditures or appropriations within the 5 years that immediately follow or precede a particular year.

The Forty-eighth Supplemental Indenture increasedAs of December 31, 2023, the maximum amount of additional first mortgage bonds issuable by Idaho Power undercould issue approximately $700 million, though as of the date of this report the amount is limited to the $280 million amount authorized by the IPUC, OPUC, and WPSC. Separately, the Indenture from $2.0 billion to $2.5 billion. Idaho Power may amendalso limits the Indenture and increase this amount without consent of the holders of theadditional first mortgage bonds. The amount issuable is also restricted by property, earnings, and other provisions of the Indenture and supplemental indentures to the Indenture. The Indenture requires that Idaho Power's net earnings be at least twice the annual interest requirements on all outstanding debt of equal or prior rank, including the bonds that Idaho Power may proposeissue to issue. Under certain circumstances, the net earnings test does not apply, includingsum of (a) the issuanceprincipal amount of refundingretired first mortgage bonds to retire outstanding bonds that matureand (b) 60 percent of total unfunded property additions, as defined in less than 2 years or that are of an equal or higher interest rate, or prior lien bonds.

111
Table of Contents
the Indenture. As of December 31, 2021,2023, Idaho Power could issue under its Indenture approximately $2.1$1.9 billion of additional first mortgage bonds based on retired first mortgage bonds and total unfunded property additions. These amounts are further limited by the maximum amount of first mortgage bonds set forth in the Forty-ninth Supplemental Indenture. As a result, the maximum amount of first mortgage bonds Idaho Power could issue as of December 31, 2021, was limited to approximately $534 million under the Indenture.

6. NOTES PAYABLE
Credit Facilities
The IDACORP credit facility, which may be used for general corporate purposes and commercial paper backup, consists of a revolving line of credit not to exceed the aggregate principal amount at any one time outstanding of $100 million, including swingline loans in an aggregate principal amount at any time outstanding not to exceed $10 million, and letters of credit in an aggregate principal amount at any time outstanding not to exceed $50 million. The Idaho Power credit facility, which may be used for general corporate purpose and commercial paper backup, consists of a revolving line of credit, through the issuance of loans and standby letters of credit, not to exceed the aggregate principal amount at any one time outstanding of $300 million, including swingline loans in an aggregate principal amount at any time outstanding not to exceed $30 million, and letters of credit in an aggregate principal amount at any time outstanding not to exceed $50 million. IDACORP and Idaho Power have the right to request an increase in the aggregate principal amount of the facilities to $150 million and $450 million, respectively, in each case subject to certain conditions.

The IDACORP and Idaho Power credit facilities have similar terms and conditions. The interest rates for any borrowings under the facilities are based on either (1) a floating rate that is equal to the highest of the prime rate, federal funds rate plus 0.5 percent, or London interbank offered rate (LIBOR) Market Index rate plus 1.0 percent, or (2) the LIBOR Market Index rate, plus, in each case, an applicable margin, provided that the federal funds rate and LIBOR rate will not be less than zero. The Secured Overnight Financing Rate (SOFR) plus a defined benchmark adjustment would replace the LIBOR Market Index rate during any period in which the LIBOR rate is unavailable or unascertainable. If during any period both the LIBOR and SOFR rates are unavailable or unascertainable, an alternate benchmark rate selected by the administrative agent and the borrower would apply. The applicable margin is based on IDACORP's or Idaho Power's, as applicable, senior unsecured long-term indebtedness credit rating by rating agencies, as set forth on a schedule to the credit facility agreements. Under their respective credit facilities, the companies pay a facility fee on the commitment based on the respective company's credit rating for senior unsecured long-term debt securities. In December 2021, IDACORP and Idaho Power amended their outstanding credit agreements to extend the termination dates of each facility to December 6, 2025, and provided additional information on potential alternatives, successors or replacement rates for LIBOR in the event it is no longer available as of the date of borrowing, among other things. While the credit facilities provide for an original maturity date of December 6, 2025, the credit agreements grant IDACORP and Idaho Power the right to request up to 2 one-year extensions, subject to certain conditions.
At December 31, 2021, no loans were outstanding under either IDACORP's or Idaho Power's facilities. At December 31, 2021, Idaho Power had regulatory authority to incur up to $450 million in principal amount of short-term indebtedness at any one time outstanding through December of 2026. IDACORP’s and Idaho Power's short-term borrowings were zero at both December 31, 2021 and 2020.
112105
Table of Contents                              
7.6. COMMON STOCK
 
IDACORP Common Stock

The following table summarizes IDACORP common stock transactions during the last three years and shares reserved at December 31, 2021:2023:
Shares issuedShares reserved Shares issuedShares reserved
202120202019December 31, 2021 202320222021December 31, 2023
Balance at beginning of yearBalance at beginning of year50,461,88550,420,01750,420,017 Balance at beginning of year50,561,89250,516,47950,461,885 
Forward sale agreementsForward sale agreements—3,221,982
Continuous equity program (inactive)Continuous equity program (inactive)———3,000,000Continuous equity program (inactive)—3,000,000
Dividend reinvestment and stock purchase planDividend reinvestment and stock purchase plan———2,840,117Dividend reinvestment and stock purchase plan—2,841,702
Employee savings planEmployee savings plan———3,567,954Employee savings plan—3,567,954
Long-term incentive and compensation plan(1)
Long-term incentive and compensation plan(1)
54,59441,868—1,260,267
Long-term incentive and compensation plan(1)
53,34545,41354,5941,161,509
Balance at end of yearBalance at end of year50,516,47950,461,88550,420,017 Balance at end of year50,615,23750,561,89250,516,479 
(1) During 2021, 2020,2023, 2022, and 2019,2021, IDACORP granted 76,147, 75,030,75,295, 73,131, and 70,41976,147 restricted stock unit awards, respectively, to employees and 14,025, 10,296,12,459, 12,021, and 9,59414,025 shares of common stock, respectively, to directors. During 20212023, 2022, and 2020,2021, IDACORP issued 54,59453,345, 45,413, and 41,86854,594 shares of common stock, respectively, using original issuances of shares pursuant to the IDACORP, Inc. 2000 Long-Term IncentiveLTICP, including 13,842, 8,674, and Compensation Plan, including 12,784 and 8,938 shares of common stock, respectively, issued to members of the board of directors. During 2019,

Equity Forward Sale Agreements

On November 7, 2023, IDACORP madeannounced a registered public offering of 2,801,724 shares of its common stock at a public offering price of $92.80 per share, for an issuance amount of $260.0 million. In conjunction with this offering, IDACORP granted the underwriters an option to purchase up to 420,258 additional shares, which was subsequently exercised in full on November 8, 2023, for an additional issuance amount of $39.0 million. The 3,221,982 shares were sold under FSAs which provide for settlement on a settlement date or dates to be specified at IDACORP’s discretion, but which is expected to occur on or prior to November 7, 2024.

The FSAs will be physically settled with common shares issued by IDACORP, unless IDACORP elects to settle the agreements in net cash or net shares, subject to certain conditions. On a settlement date or dates, if IDACORP decides to physically settle the FSAs, IDACORP will issue shares of common stock to the forward purchaser at the then-applicable forward sale price and receive issuance proceeds at that time. The forward sale price was initially $90.016 per share and is subject to certain adjustments in accordance with the terms of the FSAs through the date of settlement.

At December 31, 2023, IDACORP could have settled the FSAs with physical delivery of 3,221,982 shares of common stock to the counterparty in exchange for cash of $291.9 million. The FSAs could have also been settled at December 31, 2023, with delivery of approximately $23.9 million of cash or approximately 0.2 million shares of common stock to the counterparty, if IDACORP had elected to net cash or net share settle, respectively.

The FSAs have been classified as an equity transaction because they are indexed to IDACORP’s common stock and the other requirements necessary for equity classification are met. As a result of the equity classification, no original issuancesgain or loss will be recognized within earnings due to subsequent changes in the fair value of the FSAs.

Prior to settlement, the potentially issuable shares pursuant to the FSAs will be reflected in IDACORP’s diluted earnings per share calculations using the treasury stock method. Under this method, the number of shares of IDACORP’s common stock.stock used in calculating diluted earnings per share for a reporting period would be increased by the number of shares, if any, that would be issued upon physical settlement of the FSAs less the number of shares that could be purchased by IDACORP in the market with the proceeds received from issuance (based on the average market price during that reporting period). Share dilution occurs when the average market price of IDACORP’s stock during the reporting period is higher than the then-applicable forward sale price as of the end of the reporting period. As of December 31, 2023, 34,131 incremental shares were included in the calculation of diluted EPS related to the securities under the FSAs. See Note 8 - "Earnings Per Share" for additional information concerning IDACORP's diluted earnings per share.
106
Table of Contents

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 facilitiesCredit 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 December 31, 2021,2023, the leverage ratios for IDACORP and Idaho Power were 4350 percent and 4551 percent, respectively. Based on these restrictions, IDACORP’s and Idaho Power’s dividends were limited to $1.6$1.4 billion and $1.4$1.2 billion, respectively, at December 31, 2021.2023. 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 December 31, 2021,2023, IDACORP and Idaho Power were in compliance with those covenants.

Idaho Power’s Revised Policy and Code of Conduct relating to transactions between and among Idaho Power, IDACORP, and other affiliates, which was approved by the IPUC in April 2008, provides that Idaho Power will not pay any dividends to IDACORP that will reduce Idaho Power’s common equity capital below 35 percent of its total adjusted capital without IPUC approval. At December 31, 2021,2023, Idaho Power's common equity capital was 5550 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 no preferred stock outstanding.

In addition to contractual restrictions on the amount and payment of dividends, the FPA prohibits the payment of dividends from "capital accounts." The term "capital account" is undefined in the FPA or its regulations, but Idaho Power does not believe the restriction would limit Idaho Power's ability to pay dividends out of current year earnings or retained earnings.
 
8.7. SHARE-BASED COMPENSATION
 
IDACORP has one share-based compensation plan — the 2000 Long-Term Incentive and Compensation Plan (LTICP).LTICP. The LTICP (for officers, key employees, and directors) permits the grant of stock options, restricted stock and restricted stock units, (together, Restricted Stock), performance shares and performance-based units, (together, Performance-Based Shares), and several other types of share-based awards. At December 31, 2021,2023, the maximum number of shares available under the LTICP was 443,663.244,938.
 
113
Table of Contents
Restricted Stock Unit and Performance-Based SharesUnit Awards

Restricted Stockstock unit awards have three-year vesting periods, and entitle the recipients to dividends or dividend equivalents, as applicable, and voting rights, except that holders of restricted stock units do not have voting rights until the units are vested and settled in shares. Unvested awards are restricted as to disposition and subject to forfeiture under certain circumstances. The fair value of these awards is based on the closing market price of common stock on the grant date and is charged to compensation expense over the vesting period, reduced for any forfeitures during the vesting period.
 
Performance-Based SharesPerformance-based unit awards have three-year vesting periods and entitle the recipients to voting rights, except that holders of performance-based units do not have voting rights until the units are vested and settled in shares. Unvested awards are restricted as to disposition, subject to forfeiture under certain circumstances, and subject to the attainment of specific performance conditions over the three-year vesting period. The performance conditions are two equally-weighted metrics, cumulative earnings per share (CEPS) and total shareholder return (TSR) relative to a peer group. Depending on the level of attainment of the performance conditions and the year issued, the final number of shares awarded can range from zero to 200 percent of the target award. Dividends or dividendDividend equivalents as applicable, are accrued during the vesting period and paid out based on the final number of shares awarded.
 
The grant-date fair value of the CEPS portion is based on the closing market value at the date of grant, reduced by the loss in time-value of the estimated future dividend payments. The fair value of this portion of the awards is charged to compensation expense over the requisite service period based on the estimated achievement of performance targets, reduced for any forfeitures during the vesting period. The grant-date fair value of the TSR portion is estimated using the market value at the date of grant and a statistical model that incorporates the probability of meeting performance targets based on historical returns relative to the peer group. The fair value of this portion of the awards is charged to compensation expense over the requisite service period, provided the requisite service period is rendered, regardless of the level of TSR metric attained.
107
Table of Contents

A summary of Restricted Stockrestricted stock units and Performance-Based Sharesperformance-based units award activity is presented below. Idaho Power shareunit amounts represent the portion of IDACORP amounts related to Idaho Power employees:
 IDACORPIdaho Power
Number of
Shares/Units		Weighted-Average
Grant Date
Fair Value		Number of
Shares/Units		Weighted-Average
Grant Date
Fair Value
Nonvested shares/units at January 1, 2021157,035 $100.89 156,013 $100.90 
Shares/units granted96,345 87.76 95,821 87.76 
Shares/units forfeited(2,210)98.72 (2,210)98.72 
Shares/units vested(75,914)87.24 (75,415)87.24 
Nonvested shares/units at December 31, 2021175,256 $99.61 174,209 $99.61 
 IDACORPIdaho Power
Number of
Units		Weighted-Average
Grant Date
Fair Value		Number of
Units		Weighted-Average
Grant Date
Fair Value
Nonvested units at January 1, 2023188,468 $99.92 187,816 $99.91 
Units granted94,580 103.98 94,118 103.98 
Units forfeited(2,604)99.37 (2,604)99.37 
Units vested(70,344)113.07 (70,106)113.07 
Nonvested units at December 31, 2023210,100 $97.35 209,224 $97.34 
 
The total fair value of shares vested was $7.5 million in 2023, $6.9 million in 2022, and $6.7 million in 2021, $10.5 million in 2020, and $9.4 million in 2019.2021. At December 31, 2021,2023, IDACORP had $7.5$8.0 million of total unrecognized compensation cost related to nonvested share-based compensation, nearly all of which was Idaho Power's share. These costs are expected to be recognized over a weighted-average period of 1.71.6 years. IDACORP uses original issue shares for these awards.
 
In 2021,2023, a total of 14,02512,459 shares were awarded to directors at an average grant date fair value of $86.24$103.48 per share. Directors elected to defer receipt of 2,5504,640 of these shares, which are being held as deferred stock units with dividend equivalents reinvested in additional stock units.

Compensation Expense: The following table shows the compensation cost recognized in income and the tax benefits resulting from the LTICP, as well as the amounts allocated to Idaho Power for those costs associated with Idaho Power’s employees (in thousands of dollars): 
 IDACORPIdaho Power
 202120202019202120202019
Compensation cost$8,583 $7,416 $8,788 $8,497 $7,339 $8,639 
Income tax benefit2,209 1,909 2,262 2,187 1,889 2,224 
114
Table of Contents
 IDACORPIdaho Power
 202320222021202320222021
Compensation cost$9,578 $10,279 $8,583 $9,508 $10,204 $8,497 
Income tax benefit2,465 2,646 2,209 2,447 2,627 2,187 

No equity compensation costs have been capitalized. These costs are primarily reported within "Other operations and maintenance" expense on the consolidated statements of income.

9.8. EARNINGS PER SHARE
 
The following table presents the computation of IDACORP’s basic and diluted earnings per share for the years ended December 31, 2021, 2020,2023, 2022, and 20192021 (in thousands, except for per share amounts):
Year Ended December 31,
Year Ended December 31,Year Ended December 31,
202120202019 202320222021
Numerator:Numerator:   Numerator: 
Net income attributable to IDACORP, Inc.Net income attributable to IDACORP, Inc.$245,550 $237,417 $232,854 
Denominator:Denominator:  
Weighted-average common shares outstanding - basicWeighted-average common shares outstanding - basic50,599 50,538 50,502 
Effect of dilutive securities463435
Weighted-average common shares outstanding - basic
Weighted-average common shares outstanding - basic
Effect of dilutive securities(1)
Effect of dilutive securities(1)
894146
Weighted-average common shares outstanding - dilutedWeighted-average common shares outstanding - diluted50,645 50,572 50,537 
Basic earnings per shareBasic earnings per share$4.85 $4.70 $4.61 
Diluted earnings per shareDiluted earnings per share$4.85 $4.69 $4.61 

(1) The effect of dilutive securities amount includes 34,131 incremental shares related to FSAs as of December 31, 2023. See Note 6 - "Common Stock" for additional information concerning IDACORP's FSAs.
108

Table of Contents
10.9. COMMITMENTS
 
Purchase Obligations

At December 31, 2021,2023, Idaho Power had the following long-term commitments relating to purchases of energy, capacity, transmission rights, and fuel (in thousands of dollars):
20222023202420252026Thereafter 20242025202620272028Thereafter
Cogeneration and power production$298,867 $308,741 $311,968 $296,579 $293,508 $2,456,582 
Cogeneration and power production(1)
FuelFuel62,287 19,328 8,663 8,362 8,354 58,355 
(1) As of December 31, 2023, Idaho Power had a $431 million commitment related to an agreement to utilize the storage capacity of a 150 MW battery storage facility, over a 20-year term, scheduled to be online in June 2025.

As of December 31, 2021,2023, Idaho Power had 1,137 megawatt (MW)power purchase obligations with respect to 1,432 MW nameplate capacity of PURPA-relatedonline PURPA and non-PURPA projects, on-line, with an additional 75428 MW nameplate capacity of projects projectedthat are scheduled to be on-line by 2024.online through 2026. The power purchase contractsagreements for these projects have original contract terms ranging from one to 35 years. Idaho Power's expensespurchased power expense associated with PURPA-related projects werelong-term agreements (including PURPA) was approximately $200$258 million in 2021, $1942023, $238 million in 2020,2022, and $187$251 million in 2019. In February 2022, Idaho Power entered into a 20-year power purchase agreement with a planned 40 MW solar facility expected to be in service in 2023 which increased Idaho Power's contractual purchase obligations by approximately $78 million over the term of the contract.2021.

Idaho Power also has the following long-term commitments (in thousands of dollars):
20222023202420252026Thereafter 20242025202620272028Thereafter
Joint-operating agreement payments(1)
Joint-operating agreement payments(1)
$2,822 $2,822 $2,822 $2,822 $2,822 $14,110 
Easements and other payments1,925 1,965 2,006 2,049 2,092 11,136 
Maintenance and service agreements(1)
97,847 13,522 10,134 6,319 6,592 46,764 
Easements and other payments(1)
Maintenance, service, and materials agreements(1)(2)
FERC and other industry-related fees(1)
FERC and other industry-related fees(1)
16,772 14,549 14,174 14,174 14,174 70,870 
(1) Approximately $28 million, $18$1 million, $20 million, and $143$166 million of the obligationscommitments included in joint-operating agreement payments, easements and other payments, maintenance, service, and servicematerials agreements, and FERC and other industry-related fees, respectively, have contracts that do not specify terms related to expiration. As these contracts are presumed to continue indefinitely, ten years of information, estimated based on current contract terms, has been included in the table for presentation purposes.
(2) As of December 31, 2023, Idaho Power had a remaining $115 million commitment related to four contracts to acquire and own battery storage assets with in-service dates through 2025.

At IDACORP, long-term purchase commitments of $3$34.7 million are mostly comprised of other long-term liabilities at Ida-West of which approximately $2 million relate to contracts that do not specify terms related to expiration.and IFS. At December 31, 2021,2023, IDACORP had a commitment to invest an additional $8.5$5.9 million into a private market investment fund, which is expected to occur over the next few years. IDACORP’s expense for operating leases was not material for the years ended 2021, 2020,2023, 2022, and 2019.2021.

115Acquisition of Additional Interest in Boardman-to-Hemingway Transmission Project
Table
In March 2023, Idaho Power executed a purchase, sale, and security agreement with the BPA to transfer BPA's 24 percent interest in the Boardman-to-Hemingway transmission line project to Idaho Power, bringing Idaho Power's interest in the project to approximately 45 percent. Pursuant to the agreement, Idaho Power has a commitment to provide long-term transmission service to BPA. The agreement also required BPA to make a $10 million security payment to Idaho Power. On Idaho Power's consolidated balance sheet, the agreement increased construction work in progress by $31.4 million for the acquired permitting interest, cash and cash equivalents by $10.0 million for the additional security payment, and other non-current liabilities by $41.4 million for Idaho Power's obligation to pay for the permitting interest and to return the security deposit to BPA. Payments to BPA for the permitting interest are expected to be made over a 15-year period beginning 10 years after energization of Contents
the transmission line project, while the security deposit is due to be returned to BPA upon energization.
 
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 WDEQ, was $51.6$47.6 million at December 31, 2021,2023, representing IERCo's one-third share of BCC's total reclamation obligation of $154.7$142.9 million. BCC has a reclamation trust fund set aside specifically for the purpose of paying these reclamation costs. At December 31, 2021,2023, the value of the reclamation trust fund was $211.2$253.3 million. During 2021,2023, the reclamation trust fund made $21.1$6.0 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
109
Table of Contents
future reclamation costs. To ensure that the reclamation trust fund maintains adequate reserves, BCC has the ability to, and does, add a per-ton surcharge to coal sales, all of which are made to the Jim Bridger plant. Because of the existence of the fund and the ability to apply a per-ton surcharge, the estimated fair value of this guarantee is minimal.
 
IDACORP and Idaho Power enter into financial agreements and power purchase and sale agreements that include indemnification provisions relating to various forms of claims or liabilities that may arise from the transactions contemplated by these agreements. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnification provisions cannot be reasonably estimated. IDACORP and Idaho Power periodically evaluate the likelihood of incurring costs under such indemnities based on their historical experience and the evaluation of the specific indemnities. As of December 31, 2021,2023, management believes the likelihood is remote that IDACORP or Idaho Power would be required to perform under such indemnification provisions or otherwise incur any significant losses with respect to such indemnification obligations. Neither IDACORP nor Idaho Power has recorded any liability on their respective consolidated balance sheets with respect to these indemnification obligations.
 
11.10. CONTINGENCIES
 
IDACORP and Idaho Power have in the past and expect in the future to become involved in various claims, controversies, disputes, and other contingent matters, some of which involve litigation and regulatory or other contested proceedings. The ultimate resolution and outcome of litigation and regulatory proceedings is inherently difficult to determine, particularly where (a) the remedies or penalties sought are indeterminate, (b) the proceedings are in the early stages or the substantive issues have not been well developed, or (c) the matters involve complex or novel legal theories or a large number of parties. In accordance with applicable accounting guidance, IDACORP and Idaho Power, as applicable, establish an accrual for legal proceedings when those matters proceed to a stage where they present loss contingencies that are both probable and reasonably estimable. If the loss contingency at issue is not both probable and reasonably estimable, IDACORP and Idaho Power do not establish an accrual and the matter will continue to be monitored for any developments that would make the loss contingency both probable and reasonably estimable. As of the date of this report, IDACORP's and Idaho Power's accruals for loss contingencies are not material to their financial statements as a whole; however, future accruals could be material in a given period. IDACORP's and Idaho Power's determination is based on currently available information, and estimates presented in financial statements and other financial disclosures involve significant judgment and may be subject to significant uncertainty. For matters that affect Idaho Power's operations, Idaho Power intends to seek, to the extent permissible and appropriate, recovery through the ratemaking process of costs incurred, although there is no assurance that such 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, and economic losses, relating to the company’s provision of electric service and the operation of its generation,power supply, transmission, and distribution facilities. Some of those claims relate to electrical contacts, service quality, property damage, 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, associated with wildfires that originated from utility property, most commonly transmission and distribution lines. Idaho Power has also regularly received claims by 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 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. Given uncertainties regarding the outcome, timing, and compliance plans for these environmental matters, Idaho Power is unable to estimate the financial impact of these regulations.
116
Table of Contents

12.11. BENEFIT PLANS
 
Idaho Power sponsors defined benefit and other postretirement benefit plans that cover the majority of its employees. Idaho Power also sponsors a defined contribution 401(k) employee savings plan and provides certain post-employment benefits.

110
Table of Contents
Pension Plans

Idaho Power has pension plans–a noncontributory defined benefit pension plan (pension plan) and two nonqualified defined benefit pension 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).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 these plans are based on years of service and the employee's final average earnings.
 
The following table summarizes the changes in benefit obligations and plan assets of these plans (in thousands of dollars): 
Pension PlanSMSP Pension PlanSMSP
2021202020212020 2023202220232022
Change in projected benefit obligation:Change in projected benefit obligation:    
Change in projected benefit obligation:
Change in projected benefit obligation: 
Benefit obligation at January 1Benefit obligation at January 1$1,337,395 $1,134,752 $134,791 $122,443 
Service costService cost54,202 42,987 813 213 
Interest costInterest cost37,317 40,013 3,557 4,350 
Actuarial (gain) loss(35,833)163,610 33 13,420 
Actuarial loss (gain)
Plan amendmentPlan amendment— — — 130 
Benefits paidBenefits paid(46,551)(43,967)(6,182)(5,765)
Projected benefit obligation at December 31Projected benefit obligation at December 311,346,530 1,337,395 133,012 134,791 
Change in plan assets:Change in plan assets:  
Fair value at January 1
Fair value at January 1
Fair value at January 1Fair value at January 1871,603 763,119 — — 
Actual return on plan assetsActual return on plan assets119,412 112,451 — — 
Employer contributionsEmployer contributions40,000 40,000 — — 
Benefits paidBenefits paid(46,551)(43,967)— — 
Fair value at December 31Fair value at December 31984,464 871,603 — — 
Funded status at end of yearFunded status at end of year$(362,066)$(465,792)$(133,012)$(134,791)
Amounts recognized in the balance sheet consist of:Amounts recognized in the balance sheet consist of:    
Amounts recognized in the balance sheet consist of:
Amounts recognized in the balance sheet consist of: 
Other current liabilitiesOther current liabilities$— $— $(6,226)$(6,154)
Noncurrent liabilitiesNoncurrent liabilities(362,066)(465,792)(126,786)(128,637)
Net amount recognizedNet amount recognized$(362,066)$(465,792)$(133,012)$(134,791)
Amounts recognized in accumulated other comprehensive income consist of:    
Amounts recognized in AOCI consist of:
Amounts recognized in AOCI consist of:
Amounts recognized in AOCI consist of: 
Net lossNet loss$322,908 $437,859 $51,365 $55,537 
Prior service costPrior service cost43 49 2,687 2,983 
SubtotalSubtotal322,951 437,908 54,052 58,520 
Less amount recorded as regulatory asset(1)
Less amount recorded as regulatory asset(1)
(322,951)(437,908)— — 
Net amount recognized in accumulated other comprehensive income$— $— $54,052 $58,520 
Net amount recognized in AOCI
Accumulated benefit obligationAccumulated benefit obligation$1,120,036 $1,115,923 $121,591 $119,517 
(1) Changes in the funded status of the pension plan that would be recorded in accumulated other comprehensive incomeAOCI for an unregulated entity are recorded as a regulatory asset for Idaho Power as Idaho Power believes it is probable that an amount equal to the regulatory asset will be collected through the setting of future rates.
 
The actuarial losses reflected in the benefit obligations for the pension and SMSP plans in 2023 are due primarily to decreases in the assumed discount rates of both plans from December 31, 2022, to December 31, 2023. The actuarial gains reflected in the benefit obligations for the pension and SMSP plans in 20212022 are due primarily to increases in the assumed discount rates of both plans from December 31, 2020,2021, to December 31, 2021. The actuarial losses affecting the
117
Table of Contents
benefit obligations for the pension and SMSP plans in 2020 are due primarily to decreases in the assumed discount rates from December 31, 2019, to December 31, 2020.2022. For more information on discount rates, see “Plan Assumptions” below in this Note 12.11.

As a non-qualified plan, the SMSP has no plan assets. However, Idaho Power has a Rabbi trust designated to provide funding for SMSP obligations. The Rabbi trust holds investments in marketable securities and corporate-owned life insurance. The
111
Table of Contents
recorded value of these investments was approximately $117.1$146.2 million and $108.8$134.2 million at December 31, 20212023 and 2020,2022, respectively, and is reflected in Investments and in company-ownedCompany-owned life insurance on the consolidated balance sheets.

The following table shows the components of net periodic pension cost for these plans (in thousands of dollars). For purposes of calculating the expected return on plan assets, the market-related value of assets is equal to the fair value of the assets.
Pension PlanSMSP Pension PlanSMSP
202120202019202120202019 202320222021202320222021
Service costService cost$54,202 $42,987 $34,061 $813 $213 $(181)
Interest costInterest cost37,317 40,013 42,312 3,557 4,350 4,575 
Expected return on assetsExpected return on assets(64,090)(56,239)(48,623)— — — 
Amortization of net lossAmortization of net loss23,796 17,325 13,564 4,205 3,734 2,533 
Amortization of prior service costAmortization of prior service cost6 6 6 296 290 96 
Net periodic pension costNet periodic pension cost51,231 44,092 41,320 8,871 8,587 7,023 
Regulatory deferral of net periodic pension cost(1)
Regulatory deferral of net periodic pension cost(1)
(48,962)(42,042)(39,379)— — — 
Previously deferred pension cost recognized(1)
Previously deferred pension cost recognized(1)
17,154 17,154 17,154 — — — 
Net periodic pension cost recognized for financial reporting(1)(2)
Net periodic pension cost recognized for financial reporting(1)(2)
$19,423 $19,204 $19,095 $8,871 $8,587 $7,023 
(1) Net periodic pension costs for the pension plan are recognized for financial reporting based upon the authorization of each regulatory jurisdiction in which Idaho Power operates. Under an IPUC order, the Idaho portion of net periodic pension 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 pension cost recognized for financial reporting $17.8$18.2 million, $15.919.0 million, and $15.1$17.8 million respectively, was recognized in "Other operations and maintenance" and $10.5$6.5 million, $9.2 million, and $11.9 million, and $11.0$10.5 million respectively, was recognized in "Other (income) expense, net" on the consolidated statements of income of the companies for the twelve months ended December 31, 2021, 2020,2023, 2022, and 2019.2021.

The following table shows the components of other comprehensive income (loss) income for the plans (in thousands of dollars):
Pension PlanSMSP Pension PlanSMSP
202120202019202120202019 202320222021202320222021
Actuarial gain (loss) during the year$91,156 $(107,399)$(82,631)$(33)$(13,420)$(17,888)
Actuarial (loss) gain during the year
Plan amendment service costPlan amendment service cost— — — — (130)(2,839)
Reclassification adjustments for:Reclassification adjustments for:
Amortization of net loss
Amortization of net loss
Amortization of net lossAmortization of net loss23,796 17,325 13,564 4,205 3,734 2,533 
Amortization of prior service costAmortization of prior service cost6 6 6 296 290 96 
Adjustment for deferred tax effectsAdjustment for deferred tax effects(29,590)23,184 17,776 (1,150)2,452 4,658 
Adjustment due to the effects of regulationAdjustment due to the effects of regulation(85,368)66,884 51,285 — — — 
Other comprehensive income (loss) recognized related to pension benefit plansOther comprehensive income (loss) recognized related to pension benefit plans$— $— $— $3,318 $(7,074)$(13,440)

The following table summarizes the expected future benefit payments of these plans (in thousands of dollars):
202220232024202520262026-2030 202420252026202720282029-2033
Pension PlanPension Plan$45,239 $47,038 $48,890 $50,850 $52,855 $293,409 
SMSPSMSP6,226 6,439 6,619 6,638 6,738 34,700 
 
Idaho Power’s funding policy for the pension plan is to contribute at least the minimum required under the Employee Retirement Income Security Act of 1974 (ERISA) but not more than the maximum amount deductible for income tax purposes. In 2021, 2020,2023, 2022, and 2019,2021, Idaho Power elected to contribute more than the minimum required amounts in order to bring the pension plan to a more funded position, to reduce future required contributions, and to reduce Pension Benefit Guaranty Corporation premiums. As of the date of this report, IDACORP and Idaho Power have no estimated minimum required
118
Table of Contents
contributions to the pension plan for 2022.2024. Depending on market conditions and cash flow considerations in 2022,2023, Idaho Power could contribute up to $40$30 million to the pension plan during 20222024 in order to help 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.

112
Table of Contents
Postretirement Benefits

Idaho Power maintains a defined benefit postretirement benefit plan (consisting of health care and death benefits) that covers all employees who were enrolled in the active-employee group plan at the time of retirement as well as their spouses and qualifying dependents. Retirees hired on or after January 1, 1999, have access to the standard medical option at full cost, with no contribution by Idaho Power. Benefits for employees who retire after December 31, 2002, are limited to a fixed amount, which has limited the growth of Idaho Power’s future obligations under this plan.
 
The following table summarizes the changes in benefit obligation and plan assets (in thousands of dollars):
20212020 20232022
Change in accumulated benefit obligation:Change in accumulated benefit obligation:  Change in accumulated benefit obligation: 
Benefit obligation at January 1Benefit obligation at January 1$80,952 $71,029 
Service costService cost1,063 1,029 
Interest costInterest cost2,059 2,493 
Actuarial (gain) loss(5,805)9,359 
Actuarial gain
Benefits paid(1)
Benefits paid(1)
(4,194)(2,958)
Plan amendments
Benefit obligation at December 31Benefit obligation at December 3174,075 80,952 
Change in plan assets:Change in plan assets:  Change in plan assets: 
Fair value of plan assets at January 1Fair value of plan assets at January 141,311 39,625 
Actual return on plan assetsActual return on plan assets6,308 5,248 
Employer contributions(1)
Employer contributions(1)
(1,961)(604)
Benefits paid(1)
Benefits paid(1)
(4,194)(2,958)
Fair value of plan assets at December 31Fair value of plan assets at December 3141,464 41,311 
Funded status at end of year (included in noncurrent liabilities)Funded status at end of year (included in noncurrent liabilities)$(32,611)$(39,641)
(1) Contributions and benefits paid are each net of $3.0$2.6 million and $3.4$2.9 million of plan participant contributions for 20212023 and 2020,2022, respectively.

Amounts recognized in accumulated other comprehensive incomeAOCI consist of the following (in thousands of dollars):
20212020 20232022
Net (gain) loss$(8,020)$6,434 
Net gain
Prior service costPrior service cost80 127 
SubtotalSubtotal(7,940)6,561 
Subtotal
Subtotal
Less amount recognized in regulatory assetsLess amount recognized in regulatory assets7,940 (6,561)
Net amount recognized in accumulated other comprehensive income$— $— 
Net amount recognized in AOCI
Net amount recognized in AOCI
Net amount recognized in AOCI

The net periodic postretirement benefit cost was as follows (in thousands of dollars):

202120202019 202320222021
Service costService cost$1,063 $1,029 $853 
Interest costInterest cost2,059 2,493 2,989 
Expected return on plan assetsExpected return on plan assets(2,395)(2,404)(2,220)
Immediate recognition of loss from temporary deviation(1)
Immediate recognition of loss from temporary deviation(1)
4,736 — — 
Amortization of net loss
Amortization of prior service costAmortization of prior service cost47 47 48 
Net periodic postretirement benefit costNet periodic postretirement benefit cost$5,510 $1,165 $1,670 
(1) In 2021, a loss associated with a temporary deviation from the cost-sharing provisions of the substantive plan was recognized in "Other (income) expense, net" on the consolidated statements of income of the companies.

119
113
Table of Contents                              

The following table shows the components of other comprehensive income for the plan (in thousands of dollars):
202120202019 202320222021
Actuarial gain (loss) during the year$9,718 $(6,515)$(249)
Actuarial gain during the year
Prior service cost arising during the year
Reclassification adjustments for:Reclassification adjustments for:
Amortization of net loss
Amortization of net loss
Amortization of net loss
Amortization of prior service cost
Immediate recognition of loss from temporary deviation(1)
Immediate recognition of loss from temporary deviation(1)
4,736 — — 
Reclassification adjustments for amortization of prior service cost47 47 48 
Adjustment for deferred tax effectsAdjustment for deferred tax effects(2,514)1,665 52 
Adjustment due to the effects of regulationAdjustment due to the effects of regulation(11,987)4,803 149 
Other comprehensive income related to postretirement benefit plansOther comprehensive income related to postretirement benefit plans$— $— $— 
(1) In 2021, a loss associated with a temporary deviation from the cost-sharing provisions of the substantive plan was recognized in "Other (income) expense, net" on the consolidated statements of income of the companies.
 
The following table summarizes the expected future benefit payments of the postretirement benefit plan (in thousands of dollars):
 202220232024202520262026-2029
Expected benefit payments$5,447 $5,241 $4,982 $4,790 $4,557 $19,841 
 202420252026202720282028-2032
Expected benefit payments$4,909 $4,734 $4,556 $4,386 $4,277 $19,988 
 
Plan Assumptions
 
The following table sets forth the weighted-average assumptions used at the end of each year to determine benefit obligations for all Idaho Power-sponsored pension and postretirement benefits plans:
Pension PlanSMSPPostretirement
Benefits
Pension PlanPension PlanSMSPPostretirement
Benefits
202120202021202020212020 202320222023202220232022
Discount rateDiscount rate3.05 %2.80 %3.00 %2.70 %2.95 %2.70 %Discount rate5.10 %5.45 %5.20 %5.50 %5.15 %5.45 %
Rate of compensation increase(1)
Rate of compensation increase(1)
4.49 %4.43 %4.75 %4.75 %— — 
Medical trend rateMedical trend rate— — — — 6.3 %6.8 %Medical trend rate— — — — — 7.1 7.1 %6.7 %
Dental trend rateDental trend rate— — — — 3.5 %4.0 %Dental trend rate— — — — — 3.5 3.5 %3.5 %
Measurement dateMeasurement date12/31/202112/31/202012/31/202112/31/202012/31/202112/31/2020Measurement date12/31/202312/31/202212/31/202312/31/202212/31/202312/31/2022
(1) The 20212023 rate of compensation increase assumption for the pension plan includes an inflation component of 2.40% plus a 2.09%2.03% composite merit increase component that is based on employees' years of service. Merit salary increases are assumed to be 8.0%10.6% for employees in their first year of service and scale down to 0.6%3.4% for employees in their fortieth year of service and beyond.

The following table sets forth the weighted-average assumptions used to determine net periodic benefit cost for all Idaho Power-sponsored pension and postretirement benefit plans: 
Pension PlanSMSPPostretirement
Benefits
Pension PlanPension PlanSMSPPostretirement
Benefits
202120202019202120202019202120202019 202320222021202320222021202320222021
Discount rateDiscount rate2.80 %3.60 %4.55 %2.70 %3.65 %4.60 %2.70 %3.60 %4.60 %Discount rate5.45 %3.05 %2.80 %5.50 %3.00 %2.70 %5.45 %2.95 %2.70 %
Expected long-term rate of return on assetsExpected long-term rate of return on assets7.40 %7.40 %7.50 %— — — 6.00 %6.50 %6.75 %Expected long-term rate of return on assets7.40 %7.40 %7.40 %— — — — — 6.00 6.00 %6.00 %6.00 %
Rate of compensation increaseRate of compensation increase4.49 %4.43 %4.37 %4.75 %4.75 %4.75 %— — %— %Rate of compensation increase4.49 %4.49 %4.49 %4.75 %4.75 %4.75 %— — — %— %
Medical trend rateMedical trend rate— — — — — — 6.3 %6.8 %6.7 %Medical trend rate— — — — — — — — — — — 6.7 6.7 %5.8 %6.3 %
Dental trend rateDental trend rate— — — — — — 3.5 %4.0 %4.0 %Dental trend rate— — — — — — — — — — — 3.5 3.5 %3.5 %3.5 %
  
The assumed health care cost trend rate used to measure the expected cost of health benefits covered by the postretirement plan was 6.36.7 percent in 20212023 and is assumed to decreaseincrease to 5.77.1 percent in 2022, 5.1 percent in 2023 and 2024, 5.06.5 percent in 2025, decrease to 5.8 percent in 2026,
114
Table of Contents
and to gradually decrease to 3.93.8 percent by 2074. The assumed dental cost trend rate used to measure the expected cost of dental benefits covered by the plan was 3.5 percent, or equal to the medical trend rate if lower, for all years.
120
Table of Contents

Plan Assets

Pension Asset Allocation Policy: The target allocation and actual allocations at December 31, 2021,2023, for the pension asset portfolio by asset class is set forth below:
Asset ClassAsset ClassTarget
Allocation		Actual
Allocation
December 31, 2021		Asset ClassTarget
Allocation		Actual
Allocation
December 31, 2023
Debt securitiesDebt securities24 %23 %Debt securities25 %24 %
Equity securitiesEquity securities59 %61 %Equity securities56 %60 %
Real estateReal estate9 %8 %Real estate8 %8 %
Other plan assetsOther plan assets8 %8 %Other plan assets11 %8 %
TotalTotal100 %100 %Total100 %100 %
 
Assets are rebalanced as necessary to keep the portfolio close to target allocations. The plan’s principal investment objective is to maximize total return (defined as the sum of realized interest and dividend income and realized and unrealized gain or loss in market price) consistent with prudent parameters of risk and the liability profile of the portfolio. Emphasis is placed on preservation and growth of capital along with adequacy of cash flow sufficient to fund current and future payments to plan participants.
 
The three major goals in Idaho Power’s asset allocation process are to:

•determine if the investments have the potential to earn the rate of return assumed in the actuarial liability calculations;
•match the cash flow needs of the plan. Idaho Power sets bonddebt security allocations sufficient to cover approximately five years of benefit payments. Idaho Power then utilizes growth instruments (equities, real estate, venture capital) to fund the longer-term liabilities of the plan; and
•maintain a prudent risk profile consistent with ERISA fiduciary standards.
 
Allowable plan investments include stocks and stock funds, investment-grade bonds and bond funds, real estate funds, private infrastructure funds, private direct lending funds, private equity funds, and cash and cash equivalents. With the exception of real estate holdings, private infrastructure holdings, private direct lending loans, and private equity, investments must be readily marketable so that an entire holding can be disposed of quickly with only a minor effect upon market price.

Rate-of-return projections for plan assets are based on historical risk/return relationships among asset classes. The primary measure is the historical risk premium each asset class has delivered versus the yield on the Moody's AA Corporate Bond Index. This historical risk premium is then added to the current yield on the Moody's AA Corporate Bond Index. Additional analysis is performed to measure the expected range of returns, as well as worst-case and best-case scenarios. Based on the current low interest rate environment, current rate-of-return expectations are lower than the nominal returns generated over the past 30 years when interest rates were generally much higher.

Idaho Power’s asset modeling process also utilizes historical market returns to measure the portfolio’s exposure to a “worst-case” market scenario, to determine how much performance could vary from the expected “average” performance over various time periods. This “worst-case” modeling, in addition to cash flow matching and diversification by asset class and investment style, provides the basis for managing the risk associated with investing portfolio assets.

121115
Table of Contents                              
Fair Value of Plan Assets: Idaho Power classifies its pension plan and postretirement benefit plan investments using the three-level fair value hierarchy described in Note 1716 - "Fair Value Measurements." The following table presents the fair value of the plans' investments by asset category (in thousands of dollars).
Level 1Level 2Level 3Total Level 1Level 2Level 3Total
Assets at December 31, 2021    
Assets at December 31, 2023Assets at December 31, 2023 
Cash and cash equivalentsCash and cash equivalents$24,636 $— $— $24,636 
Intermediate bondsIntermediate bonds39,133 187,048 — 226,181 
Intermediate bonds
Intermediate bonds
Equity Securities: Large-Cap
Equity Securities: Large-Cap
Equity Securities: Large-CapEquity Securities: Large-Cap104,318 — — 104,318 
Equity Securities: Mid-CapEquity Securities: Mid-Cap113,621 — — 113,621 
Equity Securities: Small-CapEquity Securities: Small-Cap85,244 — — 85,244 
Equity Securities: Micro-CapEquity Securities: Micro-Cap42,915 — — 42,915 
Equity Securities: Global and InternationalEquity Securities: Global and International67,625 — — 67,625 
Equity Securities: Emerging MarketsEquity Securities: Emerging Markets7,393 — — 7,393 
Plan assets measured at NAV (not subject to hierarchy disclosure)Plan assets measured at NAV (not subject to hierarchy disclosure)
Commingled Fund: Equity Securities: Global and InternationalCommingled Fund: Equity Securities: Global and International134,752 
Commingled Fund: Equity Securities: Global and International
Commingled Fund: Equity Securities: Global and International
Commingled Fund: Equity Securities: Emerging MarketsCommingled Fund: Equity Securities: Emerging Markets47,332 
Direct Lending Fund: Fixed Income
Real estateReal estate73,958 
Private market investmentsPrivate market investments56,489 
TotalTotal$484,885 $187,048 $— $984,464 
Postretirement plan assets(1)
Postretirement plan assets(1)
$2,391 $39,073 $— $41,464 
Level 1Level 2Level 3Total Level 1Level 2Level 3Total
Assets at December 31, 2020    
Assets at December 31, 2022Assets at December 31, 2022 
Cash and cash equivalentsCash and cash equivalents$25,008 $— $— $25,008 
Intermediate bondsIntermediate bonds34,455 163,000 — 197,455 
Intermediate bonds
Intermediate bonds
Equity Securities: Large-Cap
Equity Securities: Large-Cap
Equity Securities: Large-CapEquity Securities: Large-Cap79,259 — — 79,259 
Equity Securities: Mid-CapEquity Securities: Mid-Cap104,089 — — 104,089 
Equity Securities: Small-CapEquity Securities: Small-Cap82,069 — — 82,069 
Equity Securities: Micro-CapEquity Securities: Micro-Cap44,715 — — 44,715 
Equity Securities: Global and InternationalEquity Securities: Global and International69,687 — — 69,687 
Equity Securities: Emerging MarketsEquity Securities: Emerging Markets10,574 — — 10,574 
Plan assets measured at NAV (not subject to hierarchy disclosure)Plan assets measured at NAV (not subject to hierarchy disclosure)
Commingled Fund: Equity Securities: Global and InternationalCommingled Fund: Equity Securities: Global and International116,223 
Commingled Fund: Equity Securities: Global and International
Commingled Fund: Equity Securities: Global and International
Commingled Fund: Equity Securities: Emerging MarketsCommingled Fund: Equity Securities: Emerging Markets50,019 
Real estate
Real estate
Real estateReal estate54,630 
Private market investmentsPrivate market investments37,875 
TotalTotal$449,856 $163,000 $— $871,603 
Postretirement plan assets(1)
Postretirement plan assets(1)
$1,333 $39,978 $— $41,311 
(1) The postretirement benefits assets are primarily life insurance contracts.

For the years ended December 31, 20212023 and 2020,2022, there were no material transfers into or out of Levels 1, 2, or 3.

Fair Value Measurement of Level 2 Plan assets and Plan assets measured at NAV:

Level 2 Bonds: These investments represent United States government, agency bonds, and corporate bonds. The United States government and agency bonds, as well as the corporate bonds, are not traded on an exchange and are valued utilizing market prices for similar assets or liabilities in active markets.

116
Table of Contents
Level 2 Postretirement Asset: This asset represents an investment in a life insurance contract and is recorded at fair value, which is the cash surrender value, less any unpaid expenses. The cash surrender value of this insurance contract is contractually
122
Table of Contents
equal to the insurance contract's proportionate share of the market value of an associated investment account held by the insurer. The investments held by the insurer's investment account are all instruments traded on exchanges with readily determinable market prices.

Commingled Funds: These funds, made up of global, international and emerging markets equity securities are measured at NAV, are not publicly traded, and therefore no publicly quoted market price is readily available. The values of the commingled funds are presented at estimated fair value, which is determined based on the unit value of the fund. The values of these investments are calculated by the custodian for the fund company on a monthly or more frequent basis, and are based on market prices of the assets held by each of the commingled funds divided by the number of fund shares outstanding for the respective fund. The investments in commingled funds have redemption limitations that permit monthly redemption following notice requirements of 5 to 7 days.

Direct Lending Funds: Direct lending strategies are closed-end funds that provide senior secured loans primarily to private, non-investment-grade companies. Direct lending fund investments are valued by the fund companies, or an independent external advisor based on the estimated fair value of the underlying loans divided by the fund shares outstanding. These direct lending funds also furnish annual audited financial statements that are used to further validate the information provided. These closed-end funds are formed with a stated life of 6 to 10 years, which can be further extended with the approval of the limited partners. There are generally no redemption rights associated with these funds. The limited partner must hold the fund for the life of the fund or find a third-party buyer.

Real Estate: Real estate holdings represent investments in open-end and closed-end commingled real estate funds. As the property interests held in these real estate funds are not frequently traded, establishing the market value of the property interests held by the fund, and the resulting unit value of fund shareholders, is based on unobservable inputs including property appraisals by the fund companies, property appraisals by independent appraisal firms, analysis of the replacement cost of the property, discounted cash flows generated by property rents and changes in property values, and comparisons with sale prices of similar properties in similar markets. These real estate funds also furnish annual audited financial statements that are also used to further validate the information provided. Redemptions on the open-end funds are generally available on a quarterly basis, with 10 to 35 days written notice, depending on the individual fund. If the fund has sufficient liquidity, the redemption will be processed at the fund NAV or the fund’s estimate of fair value at the end of the quarter. If the fund does not have sufficient liquidity to honor the full redemption, the remainder will be set for redemption the following quarter on a pro-rata basis with other redemption requests. This same process will repeat until the redemption request has been completed. To protect other fund holders, real estate funds have no duty to liquidate or encumber funds to meet redemption requests. The closed-end funds are formed for a stated life of 7 to 910 years. The fund can be further extended with the approval of the limited partners. There are generally no redemption rights associated with these funds. The limited partner must hold the fund for the life of the fund or find a third-party buyer.

Private Market Investments: Private market investments represent two categories: venture capital funds and fund of hedge funds and venture capital funds. These funds are valued by the fund companies based on the estimated fair values of the underlying fund holdings divided by the fund shares outstanding or multiplied by the ownership percentages of the holder. Some hedge fund strategies utilize securities with readily available market prices, while others utilize less liquid investment vehicles that are valued based on unobservable inputs including cost, operating results, recent funding activity, or comparisons with similar investment vehicles. Redemptions are available on a quarterly basis with 70 days written notice. Redemptions will be processed at the quarterly NAV or fair value within 60 days following quarter end. In the event of a full redemption, a reserve amount of 5% to 10% of the redemption amount may be held in reserve until the audited financial statements of the fund are published. This allows the fund to adjust the redemption so that other fund holders are not adversely impacted. Venture capital fund investments are valued by the fund companies based on estimated fair value of the underlying fund holdings divided by the fund shares outstanding. Some venture capital investments have progressed to the point that they have readily available exchange-based market valuations. Early stage venture investments are valued based on unobservable inputs including cost, operating results, discounted cash flows, the price of recent funding events, or pending offers from other viable entities. These private market investments furnish annual audited financial statements that are also used to further validate the information provided. These funds are formed for a stated life of 10 to 15 years. The general partner can extend the fund life for 2 or 3 one-year periods. The fund can be further extended with the approval of the limited partners. There are generally no redemption rights associated with these funds. The limited partner must hold the fund for the life of the fund or find a third-party buyer. The value of the fund of hedge funds investment is the residual value of an immaterial non-liquid position in a single fund of hedge funds.

Employee Savings Plan

Idaho Power has a defined contribution plan designed to comply with Section 401(k) of the Internal Revenue Code and that covers substantially all employees. Idaho Power matches specified percentages of employee contributions to the plan. Matching annual contributions were approximately $9.8 million, $8.8 million, and $8.2 million $7.9 million,in 2023, 2022, and $7.7 million in 2021, 2020, and 2019, respectively.
 
117
Table of Contents
Post-employment Benefits

Idaho Power provides certain benefits to former or inactive employees, their beneficiaries, and covered dependents after employment but before retirement, in addition to the health care benefits required under the Consolidated Omnibus Budget Reconciliation Act.Act (COBRA). These benefits include salary continuation, health care and life insurance for those employees found to be disabled under Idaho Power’s disability plans, and health care for surviving spouses and dependents. Idaho Power accrues a
123
Table of Contents
liability for such benefits. The post-employment benefits included in other deferred creditsliabilities on both IDACORP’s and Idaho Power’s consolidated balance sheets at December 31, 20212023 and 2020,2022, were approximately $3 million and $2 million.

13.12. PROPERTY, PLANT AND EQUIPMENT AND JOINTLY-OWNED PROJECTS
 
The following table presents the major classifications of Idaho Power’s utility plant in service, annual depreciation provisions as a percent of average depreciable balance, and accumulated provision for depreciation for the years ended December 31, 20212023 and 20202022 (in thousands of dollars):
20212020 20232022
BalanceAvg RateBalanceAvg Rate BalanceAvg RateBalanceAvg Rate
ProductionProduction$2,597,285 3.15 %$2,529,708 3.23 %Production$2,794,534 3.50 3.50 %$2,700,494 2.89 2.89 %
TransmissionTransmission1,309,143 1.89 %1,272,360 1.88 %Transmission1,392,338 1.90 1.90 %1,346,463 1.91 1.91 %
DistributionDistribution2,058,819 2.25 %1,968,752 2.26 %Distribution2,454,458 2.18 2.18 %2,192,135 2.15 2.15 %
General and OtherGeneral and Other544,069 6.17 %512,970 6.17 %General and Other650,202 5.21 5.21 %589,375 5.36 5.36 %
Total in serviceTotal in service6,509,316 2.85 %6,283,790 2.88 %Total in service7,291,532 2.89 2.89 %6,828,467 2.66 2.66 %
Accumulated provision for depreciationAccumulated provision for depreciation(2,298,951) (2,193,831) Accumulated provision for depreciation(2,557,744)  (2,465,279)  
In service - netIn service - net$4,210,365  $4,089,959  In service - net$4,733,788   $4,363,188   
 
At December 31, 2021,2023, Idaho Power's construction work in progress balance of $670.6$985.5 million included relicensing costs of $389.3$459.8 million for the HCC, Idaho Power's largest hydropower complex. In 2021, 2020,2023, 2022, and 2019,2021, Idaho Power had IPUC authorization to include in its Idaho jurisdiction rates $6.5 million annually ($8.8 million when grossed-up for the effect of income taxes) of AFUDC relating to the HCC relicensing project. Collecting these amounts will reduce the amount collected in the future once the HCC relicensing costs are approved for recovery in base rates. At December 31, 2021,2023, Idaho Power's regulatory liability for collection of AFUDC relating to the HCC was $187.7$228.7 million.

Idaho Power's ownership interest in two jointly-owned generating facilities is included in the table above. Under the joint operating agreements for these facilities, each participating utility is responsible for financing its share of construction, operating, and leasing costs. Idaho Power's proportionate share of operating expenses for each facility is included in the Consolidated Statements of Income. These jointly-owned facilities, including balance sheet amounts and the extent of Idaho Power’s participation, were as follows at December 31, 20212023 (in thousands of dollars): 
Name of PlantName of PlantLocationUtility Plant in ServiceConstruction
Work in Progress		Accumulated
Provision for Depreciation		Ownership %
MW(1)(2)
Name of PlantLocationUtility Plant in ServiceConstruction
Work in Progress		Accumulated
Provision for Depreciation		Ownership %
MW(1)(2)
Jim Bridger units 1-4Jim Bridger units 1-4Rock Springs, WY$771,034 $7,775 $401,696 33775Jim Bridger units 1-4Rock Springs, WY$770,179 $$12,891 $$500,685 3333775
North Valmy unit 2(2)
North Valmy unit 2(2)
Winnemucca, NV255,451 881 195,258 50145
North Valmy unit 2(2)
Winnemucca, NV262,544 2,237 2,237 225,147 225,147 5050145
(1) Idaho Power’s share of nameplate capacity.
(2) Pursuant to an agreement with NV Energy, Idaho Power's participation in coal-fired operations of North Valmy ended in December 2019 at unit 1 and is planned to end no later than the end of 2025 at unit 2.
 
In October 2020, Idaho Power and co-owner Portland General Electric ceased coal-fired operations at their Boardman power plant, as planned. All depreciable property, plant and equipment associated with Idaho Power's ownership in the Boardman power plant was fully depreciated as of December 31, 2020.

IERCo, Idaho Power’s wholly-owned subsidiary, is a joint venturer injoint-owner of BCC. Idaho Power’s coal purchases from the joint ventureBCC were $67.9 million in 2023, $60.4 million in 2022, and $59.7 million in 2021, $68.3 million in 2020, and $73.6 million in 2019.2021.
 
Idaho Power has contracts to purchase the energy from four PURPA qualifying facilities that are 50 percent owned by Ida-West. Idaho Power’s power purchases from these facilities were $8.2 million in 2021, $9.3 million in 2020, and $8.6 million in 2019.
IDACORP's consolidated VIE, Marysville, owns a hydropower plant with a net book value of $13.7 million and $14.2 million at December 31, 2021 and 2020, respectively.

124
Table of Contents
14.13. ASSET RETIREMENT OBLIGATIONS (ARO)
 
The guidance relating to accounting for AROs requires that legal obligations associated with the retirement of property, plant, and equipment be recognized as a liability at fair value when incurred and when a reasonable estimate of the fair value of the liability can be made. Under the guidance, when a liability is initially recorded, the entity increases the carrying amount of the related long-lived asset to reflect the future retirement cost. Over time, the liability is accreted to its estimated settlement value
118
Table of Contents
and paid, and the capitalized cost is depreciated over the useful life of the related asset. If, at the end of the asset’s life, the recorded liability differs from the actual obligations paid, a gain or loss would be recognized. As a rate-regulated entity, Idaho Power records regulatory assets or liabilities instead ofdefers accretion, depreciation, and gains or losses as regulatory assets, as approved by the IPUC.IPUC, until such ARO costs are included in customer rates for collection. The regulatory assets recorded under this order do not earn a return on investment. Accretion, depreciation, and gains or losses related to the Boardman generating facility have been exempted from such regulatory treatment as Idaho Power collected amounts related to the decommissioning of Boardman in rates. In October 2020, Idaho Power and co-owner Portland General Electric ceased coal-fired operations at their Boardman power plant. As of December 31, 2021 and 2020, Idaho Power has recorded a liability for estimated costs of decommissioning and retirement of Boardman plant assets, which is included in the amounts in the table below.
 
Idaho Power’s recorded AROs relate to the reclamation and removal costs at its jointly-owned coal-fired generation facilities. In 2021,2023, changes in estimates at the coal-fired generation facilities resulted in a net increase of $9.4$11.3 million in the recorded AROs. The increase is primarily related to revised cost estimates for the closure of a flue gas desulfurization pond placed in-service during 2023 at the Jim Bridger plant.

Idaho Power also has additional AROs associated with its transmission system and generation facilities; however, due to the indeterminate removal date, the fair value of the associated liabilities currently cannot be estimated and no amounts are recognized in the consolidated financial statements.
 
Idaho Power also collects removal costs in rates for certain assets that do not have associated AROs. Idaho Power is required to classify these removal costs as regulatory liabilities, see Note 3 - "Regulatory Matters" for the removal costs recorded as regulatory liabilities on IDACORP’s and Idaho Power’s consolidated balance sheets as of December 31, 20212023 and 2020.2022.
 
The following table presents the changes in the carrying amount of AROs (in thousands of dollars): 
20212020 20232022
Balance at beginning of yearBalance at beginning of year$27,691 $28,191 
Accretion expenseAccretion expense1,021 1,053 
Revisions in estimated cash flowsRevisions in estimated cash flows9,415 193 
Liability settledLiability settled(1,429)(1,746)
Liability settled
Liability settled
Balance at end of yearBalance at end of year$36,698 $27,691 

15.14. INVESTMENTS
 
The table below summarizes IDACORP’s and Idaho Power’s investments as of December 31 (in thousands of dollars): 
20212020 20232022
Idaho Power investments:Idaho Power investments:  Idaho Power investments: 
Bridger Coal Company (equity method investment)Bridger Coal Company (equity method investment)$22,677 $37,115 
Exchange traded short-term bond funds and cash equivalentsExchange traded short-term bond funds and cash equivalents54,078 50,531 
Held-to-Maturity securities
Executive deferred compensation plan investmentsExecutive deferred compensation plan investments353 202 
Total Idaho Power investmentsTotal Idaho Power investments77,108 87,848 
IFS investments in real estate tax credit projects, such as affordable housing developmentsIFS investments in real estate tax credit projects, such as affordable housing developments34,967 28,438 
Ida-West joint ventures (equity method investments)Ida-West joint ventures (equity method investments)10,386 10,662 
Other investmentsOther investments1,363 — 
Total IDACORP investmentsTotal IDACORP investments$123,824 $126,948 
 
125
Table of Contents
Equity Method Investments

Idaho Power, through its subsidiary IERCo, is a 33 percent owner of BCC. Ida-West, through separate subsidiaries, owns 50 percent of three electric generation projects that are accounted for using the equity method: South Forks Joint Venture, Hazelton/Wilson Joint Venture, and Snow Mountain Hydro LLC. All projects are reviewed periodically for impairment. The table below presents IDACORP’s and Idaho Power’s earnings of unconsolidated equity-method investments (in thousands of
119
Table of Contents
dollars):
202120202019 202320222021
Bridger Coal Company (Idaho Power)Bridger Coal Company (Idaho Power)$10,211 $10,102 $10,285 
Ida-West joint venturesIda-West joint ventures1,224 1,411 2,085 
TotalTotal$11,435 $11,513 $12,370 
Total
Total
 
Investments in Equity Securities

Investments in equity securities are reported at fair value. Any unrealized gains or losses on equity securities are included in income. Unrealized gains and losses on equity securities were immaterial at December 31, 20212023 and December 31, 2020.2022. The following table summarizes sales of equity securities (in thousands of dollars):
202120202019 202320222021
Proceeds from salesProceeds from sales$11,328 $25,795 $5,080 
Gross realized gains from salesGross realized gains from sales— — — 

Held-to-Maturity Securities

Idaho Power has a rabbi trust designated to provide funding for obligations related to the SMSP. During 2023 and 2022, the rabbi trust purchased $1.6 million and $31.2 million, respectively of held-to-maturity investments in corporate fixed-income and asset-backed debt 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 consolidated statements of income. Due to increases in market interest rates in 2023 and 2022, all held-to-maturity securities were in a gross unrealized holding loss position totaling $3.3 million and $5.0 million at December 31, 2023 and December 31, 2022, respectively. Based on ongoing credit evaluations of these holdings, Idaho Power does not expect material payment defaults or delinquencies and has not recorded an allowance for credit losses for these securities as of December 31, 2023 and 2022.

IDACORP Financial Services Investments

IFS invests primarily in real estate tax credit projects, such as affordable housing developments, which provide a return principally by reducing federal and state income taxes through tax credits and accelerated tax depreciation benefits. IFS has focused on a diversified approach to its investment strategy in order to limit both geographic and operational risk, with most of IFS’s investments having been made through syndicated funds. IDACORP accounts for its equity-method investments in qualified real estate projects using the proportional amortization method and recognizes the net investment performance in the consolidated statements of income as a component of income tax expense.

16.15. 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
120
Table of Contents
netting arrangements would allow current and long-term positions to be offset in the event of default. Also, in the event of default, Idaho Power's master netting arrangements would allow for the offsetting of all transactions executed under the master netting arrangement. These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, receivables and payables arising from settled positions, and other forms of non-cash collateral (such as letters of credit). These types of transactions are excluded from the offsetting presented in the derivative fair value and offsetting table below.that follows.

126
Table of Contents
The table below presents the gains and losses on derivatives not designated as hedging instruments for the years ended December 31, 2021, 2020,2023, 2022, and 20192021 (in thousands of dollars):
Location of Realized Gain/(Loss) on Derivatives Recognized in Income
Gain/(Loss) on Derivatives Recognized in Income(1)
202120202019
Location of Realized Gain/(Loss) on Derivatives Recognized in IncomeLocation of Realized Gain/(Loss) on Derivatives Recognized in Income
Gain/(Loss) on Derivatives Recognized in Income(1)
2023202320222021
Financial swapsFinancial swapsOperating revenues$1,046 $2,173 $904 
Financial swapsFinancial swapsPurchased power1,959 (3,531)(2,183)
Financial swapsFinancial swapsFuel expense12,180 (4,791)13,811 
Forward contractsForward contractsOperating revenues1,966 421 285 
Forward contractsForward contractsPurchased power(1,099)(384)(270)
Forward contractsForward contractsFuel expense(194)(36)565 
Forward contracts
Forward contracts
(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 O&M expense. See Note 1716 - "Fair Value Measurements" for additional information concerning the determination of fair value for Idaho Power’s assets and liabilities from price risk management activities.

Credit Risk
At December 31, 2023, Idaho Power did not have material credit risk exposure from financial instruments, including derivatives. Idaho Power monitors credit risk exposure through reviews of counterparty credit quality, corporate-wide counterparty credit exposure, and corporate-wide counterparty concentration levels. Idaho Power manages these risks by establishing credit and concentration limits on transactions with counterparties and requiring contractual guarantees, cash deposits, or letters of credit from counterparties or their affiliates, as deemed necessary. Idaho Power’s physical power contracts are commonly under WSPP, Inc. agreements, physical gas contracts are usually under North American Energy Standards Board contracts, and financial transactions are usually under International Swaps and Derivatives Association, Inc. contracts. These contracts typically contain adequate assurance clauses requiring collateralization if a counterparty has debt that is downgraded below investment grade by at least one rating agency.
Credit-Contingent Features
Certain of Idaho Power's derivative instruments contain provisions that require Idaho Power's unsecured debt to maintain an investment grade credit rating from Moody's and Standard & Poor's Ratings Services. If Idaho Power's unsecured debt were to fall below investment grade, it would be in violation of these provisions, and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions. The aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a liability position at December 31, 2023, was $63.9 million. Idaho Power posted $53.3 million cash collateral related to this amount. If the credit-risk-related contingent features underlying these agreements were triggered on December 31, 2023, Idaho Power would have been required to pay or post collateral to its counterparties up to an additional $14.2 million to cover open liability positions as well as completed transactions that have not yet been paid.

121
Table of Contents
Derivative Instrument SummaryCredit-Contingent Features

The table below presents the fair values and locationsCertain of Idaho Power's derivative instruments not designated as hedging instruments recorded oncontain provisions that require Idaho Power's unsecured debt to maintain an investment grade credit rating from Moody's 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 balance sheets and reconciles the gross amounts of derivatives recognized as assets and as liabilitiescounterparties to the derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on derivative instruments in net amounts presentedliability positions. The aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in the balance sheetsa liability position at December 31, 2021 and 2020 (in thousands of dollars):
Asset DerivativesLiability Derivatives
 Balance Sheet LocationGross Fair ValueAmounts OffsetNet AssetsGross Fair ValueAmounts OffsetNet Liabilities
December 31, 2021
Current:   
Financial swapsOther current assets$10,599 $(4,893)(1)$5,706 $2,910 $(2,910)$— 
Financial swapsOther current liabilities— — — 20 — 20 
Forward contractsOther current assets6 (4)2 4 (4)— 
Forward contractsOther current liabilities— — — 1,970 — 1,970 
Long-term:  
Financial swapsOther assets899 (9)890 9 (9)— 
Financial swapsOther liabilities— — — 14 — 14 
Forward contractsOther liabilities— — — 3,743 — 3,743 
Total $11,504 $(4,906)$6,598 $8,670 $(2,923)$5,747 
December 31, 2020
Current:   
Financial swapsOther current assets$2,028 $(36)$1,992 $36 $(36)$— 
Financial swapsOther current liabilities187 (187)— 786 (652)(2)134 
Forward contractsOther current assets5 (2)3 2 (2)— 
Forward contractsOther current liabilities3 (3)— 13 (3)10 
Long-term:   
Financial swapsOther liabilities40 (40)— 56 (56)(2)— 
Total $2,263 $(268)$1,995 $893 $(749)$144 
(1) Current asset derivative amounts offset include $2.02023, was $63.9 million. Idaho Power posted $53.3 millionof cash collateral payable atrelated to this amount. If the credit-risk-related contingent features underlying these agreements were triggered on December 31, 2021.
(2) Current and long-term2023, Idaho Power would have been required to pay or post collateral to its counterparties up to an additional $14.2 million to cover open liability derivative amounts offset include $0.5 million and $16 thousand of collateral receivable at December 31, 2020, respectively.positions as well as completed transactions that have not yet been paid.

127121
Table of Contents                              
The table below presents the volumes of derivative commodity forward contracts and swaps outstanding at December 31, 2021 and 2020 (in thousands of units):
December 31,
CommodityUnits20212020
Electricity purchasesMWh529 74 
Electricity salesMWh129 — 
Natural gas purchasesMMBtu11,740 7,923 
Natural gas salesMMBtu— 775 
Credit Risk
At December 31, 2021, Idaho Power did not have material credit risk exposure from financial instruments, including derivatives. Idaho Power monitors credit risk exposure through reviews of counterparty credit quality, corporate-wide counterparty credit exposure, and corporate-wide counterparty concentration levels. Idaho Power manages these risks by establishing credit and concentration limits on transactions with counterparties and requiring contractual guarantees, cash deposits, or letters of credit from counterparties or their affiliates, as deemed necessary. Idaho Power’s physical power contracts are commonly under WSPP, Inc. agreements, physical gas contracts are usually under North American Energy Standards Board contracts, and financial transactions are usually under International Swaps and Derivatives Association, Inc. contracts. These contracts typically contain adequate assurance clauses requiring collateralization if a counterparty has debt that is downgraded below investment grade by at least one rating agency.
Credit-Contingent Features
 
Certain of Idaho Power's derivative instruments contain provisions that require Idaho Power's unsecured debt to maintain an investment grade credit rating from Moody's Investors Service and Standard & Poor's Ratings Services. If Idaho Power's unsecured debt were to fall below investment grade, it would be in violation of these provisions, and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions. The aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a liability position at December 31, 2021,2023, was $3.0$63.9 million. Idaho Power did not post anyposted $53.3 million cash collateral related to this amount. If the credit-risk-related contingent features underlying these agreements were triggered on December 31, 2021,2023, Idaho Power would have been required to pay or post collateral to its counterparties up to an additional $7.6$14.2 million to cover open liability positions as well as completed transactions that have not yet been paid.

121
Table of Contents
17.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 December 31, 2023 and 2022 (in thousands of dollars):
Asset DerivativesLiability Derivatives
 Balance Sheet LocationGross Fair ValueAmounts OffsetNet AssetsGross Fair ValueAmounts OffsetNet Liabilities
December 31, 2023
Current:   
Financial swapsOther current assets$241 $(169)$72 $169 $(169)$— 
Financial swapsOther current liabilities1,476 (1,476)— 41,977 (38,045)(1)3,932 
Forward contractsOther current liabilities— — — 2,000 — 2,000 
Long-term:  
Financial swapsOther assets106 (89)17 89 (89)— 
Financial swapsOther liabilities376 (376)— 2,123 (2,123)(2)— 
Total $2,199 $(2,110)$89 $46,358 $(40,426)$5,932 
December 31, 2022
Current:   
Financial swapsOther current assets$72,548 $(32,609)(3)$39,939 $13,982 $(13,982)$— 
Financial swapsOther current liabilities132 (132)— 1,577 (132)1,445 
Forward contractsOther current assets400 — 400 — — — 
Forward contractsOther current liabilities— — — 2,071 — 2,071 
Long-term:   
Financial swapsOther assets622 (43)579 43 (43)— 
Financial swapsOther liabilities644 (644)— 2,136 (644)1,492 
Forward contractsOther liabilities— — — 1,780 — 1,780 
Total $74,346 $(33,428)$40,918 $21,589 $(14,801)$6,788 
(1) Current liability derivative amounts offset include $36.6 millionof collateral receivable at December 31, 2023.
(2) Long-term liability derivative amounts offset include $1.7 million of collateral receivable at December 31, 2023.
(3) Current asset derivative amounts offset include $18.6 millionof collateral payable at December 31, 2022.

The table below presents the volumes of derivative commodity forward contracts and swaps outstanding at December 31, 2023 and 2022 (in thousands of units):
December 31,
CommodityUnits20232022
Electricity purchasesMWh440 898 
Electricity salesMWh57 32 
Natural gas purchasesMMBtu24,593 26,773 
Natural gas salesMMBtu— 310 

16. FAIR VALUE MEASUREMENTS
 
IDACORP and Idaho Power have categorized their financial instruments into a three-level fair value hierarchy, based on the priority of the inputs to the valuation technique. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). If the inputs used to measure the financial instruments fall within different levels of the hierarchy, the categorization is based on the lowest level input that is significant to the fair value measurement of the instrument.
 
122
Table of Contents
Financial assets and liabilities recorded on the 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 for derivative instruments are based on quoted market prices adjusted for location using corroborated, observable market data.
128
Table of Contents
data or using quoted price 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 no transfers between levels or material changes in valuation techniques or inputs during the years ended December 31, 20212023 and 2020.2022.

Certain instruments have been valued using net asset value (NAV)NAV as a practical expedient. These instruments are similar to mutual funds; however, theirThe 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 the GAAP are not classified within the fair value hierarchy levels.

The following table presents information about IDACORP’s and Idaho Power’s assets and liabilities measured at fair value on a recurring basis as of December 31, 20212023 and 20202022 (in thousands of dollars): 
December 31, 2021December 31, 2020
Level 1Level 2Level 3TotalLevel 1Level 2Level 3Total
December 31, 2023December 31, 2023December 31, 2022
Level 1Level 1Level 2Level 3TotalLevel 1Level 2Level 3Total
Assets:Assets:    
Money market funds and commercial paperMoney market funds and commercial paper
Money market funds and commercial paper
Money market funds and commercial paper
IDACORP(1)
IDACORP(1)
IDACORP(1)
IDACORP(1)
$80,406 $— $— $80,406 $56,048 $— $— $56,048 
Idaho PowerIdaho Power10,393 — — 10,393 40,038 — — 40,038 
DerivativesDerivatives6,596 2 — 6,598 1,995 — — 1,995 
Equity securitiesEquity securities54,431 — — 54,431 50,733 — — 50,733 
Equity securities
Equity securities
IDACORP assets measured at NAV (not subject to hierarchy disclosure)(1)
IDACORP assets measured at NAV (not subject to hierarchy disclosure)(1)
— — — 1,363 — — — — 
Liabilities:Liabilities:
DerivativesDerivatives$34 $5,713 $— $5,747 $134 $10 $— $144 
Derivatives
Derivatives
(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 swap 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 Intercontinental ExchangeICE pricing, adjusted for location basis, which are also quoted under NYMEX and ICE pricing. Equity securities at Idaho Power 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 Rabbirabbi trust.

129123
Table of Contents                              
The table below presents the carrying value and estimated fair value of financial instruments that are not reported at fair value, as of December 31, 20212023 and 2020,2022, using available market information and appropriate valuation methodologies (in thousands)thousands of dollars).
December 31, 2021December 31, 2020 December 31, 2023December 31, 2022
Carrying AmountEstimated Fair ValueCarrying AmountEstimated Fair Value Carrying AmountEstimated Fair ValueCarrying AmountEstimated Fair Value
(thousands of dollars) (thousands of dollars)
IDACORPIDACORP    IDACORP 
Assets:Assets:    Assets: 
Notes receivable(1)
Notes receivable(1)
$3,804 $3,804 $3,804 $3,804 
Held-to-maturity securities(1)
Liabilities:Liabilities:    Liabilities: 
Long-term debt (including current portion)(1)
Long-term debt (including current portion)(1)
2,000,640 2,381,172 2,000,414 2,466,967 
Idaho PowerIdaho Power    Idaho Power 
Assets:
Held-to-maturity securities(1)
Held-to-maturity securities(1)
Held-to-maturity securities(1)
Liabilities:Liabilities:    Liabilities: 
Long-term debt (including current portion)(1)
Long-term debt (including current portion)(1)
$2,000,640 $2,381,172 $2,000,414 $2,466,967 
(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 1716 - "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 held in a rabbi trust and are generally valued using quoted prices, which may be in non-active markets. 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.

18.17. 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.investment.
 
IDACORP’s other operating segments are below the quantitative and qualitative thresholds for reportable segments and are included in the “All Other” category in the table below. This category is comprised of IFS’s investments in affordable housing developments and other real estate tax credit projects,credits, Ida-West’s joint venture investments in small hydropower generation projects, and IDACORP’s holding company expenses.

124
Table of Contents
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		EliminationsConsolidated
Total
2021    
Utility
Operations		Utility
Operations		All
Other		EliminationsConsolidated
Total
20232023 
RevenuesRevenues$1,455,410 $2,674 $— $1,458,084 
Operating incomeOperating income329,568 83 — 329,651 
Other income, netOther income, net21,243 (138)— 21,105 
Interest income7,123 216 (47)7,292 
Interest income including carrying charges on regulatory assets
Equity-method incomeEquity-method income10,211 1,224 — 11,435 
Interest expenseInterest expense86,663 82 (47)86,698 
Income before income taxesIncome before income taxes281,482 1,302 — 282,784 
Income tax expense (benefit)Income tax expense (benefit)38,257 (1,345)— 36,912 
Income attributable to IDACORP, Inc.243,225 2,325 — 245,550 
Net Income attributable to IDACORP, Inc.
Total assetsTotal assets6,990,839 281,999 (62,323)7,210,515 
Expenditures for long-lived assetsExpenditures for long-lived assets299,972 27 — 299,999 
2022    
Revenues$1,641,040 $2,941 $— $1,643,981 
Operating income327,170 8 — 327,178 
Other income, net33,876 (187)— 33,689 
Interest income including carrying charges on regulatory assets12,556 2,776 (931)14,401 
Equity-method income10,211 1,300 — 11,511 
Interest expense89,038 1,268 (931)89,375 
Income before income taxes294,775 2,629 — 297,404 
Income tax expense (benefit)39,908 (2,064)— 37,844 
Net Income attributable to IDACORP, Inc.254,867 4,115 — 258,982 
Total assets7,411,104 245,762 (113,608)7,543,258 
Expenditures for long-lived assets432,430 159 — 432,589 
2021    
Revenues$1,455,410 $2,674 $— $1,458,084 
Operating income329,568 83 — 329,651 
Other income, net21,243 (138)— 21,105 
Interest income including carrying charges on regulatory assets7,123 216 (47)7,292 
Equity-method income10,211 1,224 — 11,435 
Interest expense86,663 82 (47)86,698 
Income before income taxes281,482 1,302 — 282,784 
Income tax expense (benefit)38,257 (1,345)— 36,912 
Net Income attributable to IDACORP, Inc.243,225 2,325 — 245,550 
Total assets6,990,839 281,999 (62,323)7,210,515 
Expenditures for long-lived assets299,972 27 — 299,999 

130125
Table of Contents                              
Utility
Operations		All
Other		EliminationsConsolidated
Total
2020    
Revenues$1,347,340 $3,389 $— $1,350,729 
Operating income308,780 741 — 309,521 
Other income, net22,555 (8)— 22,547 
Interest income9,733 1,275 (496)10,512 
Equity-method income10,102 1,411 — 11,513 
Interest expense87,389 533 (496)87,426 
Income before income taxes263,783 2,885 — 266,668 
Income tax expense (benefit)30,548 (1,848)— 28,700 
Income attributable to IDACORP, Inc.233,235 4,182 — 237,417 
Total assets6,906,110 253,060 (63,926)7,095,244 
Expenditures for long-lived assets310,937 1 — 310,938 
2019    
Revenues$1,342,940 $3,443 $— $1,346,383 
Operating income297,652 674 — 298,326 
Other income, net20,362 1 — 20,363 
Interest income10,968 3,052 (769)13,251 
Equity-method income10,285 2,085 — 12,370 
Interest expense86,412 832 (769)86,475 
Income before income taxes252,854 4,981 — 257,835 
Income tax expense (benefit)28,417 (3,910)— 24,507 
Income attributable to IDACORP, Inc.224,437 8,417 — 232,854 
Total assets6,494,159 220,620 (73,578)6,641,201 
Expenditures for long-lived assets278,707 (2)— 278,705 

19.18. OTHER INCOME AND EXPENSE
 
The following table presents the components of IDACORP’s other income (expense), net and Idaho Power's other income (expense), net (in thousands of dollars):
IDACORPIDACORP202120202019IDACORP202320222021
Interest and dividend income, netInterest and dividend income, net$1,408 $3,813 $8,181 
Carrying charges on regulatory assetsCarrying charges on regulatory assets5,034 7,063 5,494 
Pension and postretirement non-service costs(1)
Pension and postretirement non-service costs(1)
(15,249)(11,865)(10,976)
Income from life insurance investmentsIncome from life insurance investments5,203 4,036 4,104 
Other income (expense)Other income (expense)463 462 (301)
Total other income (expense), netTotal other income (expense), net$(3,141)$3,509 $6,502 
Idaho PowerIdaho Power
Idaho Power
Idaho Power
Interest and dividend income, net
Interest and dividend income, net
Interest and dividend income, netInterest and dividend income, net$1,241 $3,034 $5,898 
Carrying charges on regulatory assetsCarrying charges on regulatory assets5,034 7,063 5,494 
Pension and postretirement non-service costs(1)
Pension and postretirement non-service costs(1)
Pension and postretirement non-service costs(1)
Pension and postretirement non-service costs(1)
(15,240)(11,862)(10,976)
Income from life insurance investmentsIncome from life insurance investments5,203 4,036 4,104 
Other income (expense)Other income (expense)591 468 (303)
Total other income (expense), netTotal other income (expense), net$(3,171)$2,739 $4,217 
(1) The 2021 pension and postretirement non-service costs includes $4.7 million of expense for a temporary deviation from the cost-sharing provisions of the substantive postretirement plan as described in Note 1211 - "Benefit Plans."

131
Table of Contents
20.19. CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME

Comprehensive income includes net income and amounts related to the SMSP. The table below presents changes in components of accumulated other comprehensive income (AOCI),AOCI, net of tax, during the years ended December 31, 2021, 2020,2023, 2022, and 20192021 (in thousands of dollars). Items in parentheses indicate reductions to AOCI.
Year Ended December 31,
202120202019
Year Ended December 31,Year Ended December 31,
2023202320222021
Defined benefit pension itemsDefined benefit pension items
Balance at beginning of periodBalance at beginning of period$(43,358)$(36,284)$(22,844)
Other comprehensive income before reclassifications, net of tax of $(8), $(3,488), and $(5,335)(25)(10,062)(15,392)
Amounts reclassified out of AOCI to net income, net of tax of $1,158, $1,036, and $6773,343 2,988 1,952 
Balance at beginning of period
Balance at beginning of period
Other comprehensive income before reclassifications, net of tax of $(1,680), $8,239, and $(8)
Amounts reclassified out of AOCI to net income, net of tax of $203, $1,160, and $1,158
Net current-period other comprehensive incomeNet current-period other comprehensive income3,318 (7,074)(13,440)
Balance at end of periodBalance at end of period$(40,040)$(43,358)$(36,284)

126
Table of Contents
The table below presents the effects on net income of amounts reclassified out of components of AOCI and the income statement location of those amounts reclassified during the years ended December 31, 2021, 2020,2023, 2022, and 20192021 (in thousands of dollars). Items in parentheses indicate increases to net income.
Amount Reclassified from AOCI
Year Ended December 31,
202120202019
Amount Reclassified from AOCIAmount Reclassified from AOCI
Year Ended December 31,Year Ended December 31,
2023202320222021
Amortization of defined benefit pension items(1)
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
Prior service costPrior service cost$296 $290 $96 
Net lossNet loss4,205 3,734 2,533 
Total before taxTotal before tax4,501 4,024 2,629 
Tax benefit(2)
Tax benefit(2)
(1,158)(1,036)(677)
Net of taxNet of tax3,343 2,988 1,952 
Total reclassification for the periodTotal reclassification for the period$3,343 $2,988 $1,952 
(1) Amortization of these items is included in "Other (income) expense, net" in the consolidated income statements of both IDACORP and Idaho Power.
(2) The tax benefit is included in "Income tax expense" in the consolidated income statements of both IDACORP and Idaho Power.

21.20. RELATED PARTY TRANSACTIONS
 
IDACORP: Idaho Power performs corporate functions such as financial, legal, and management services for IDACORP and its subsidiaries. Idaho Power charges IDACORP for the costs of these services based on service agreements and other specifically identified costs. For these services, Idaho Power billed IDACORP $0.8$1.1 million in 2021, $0.72023, $0.9 million in 2020,2022, and $0.8 million in 2019.2021.

At December 31, 20212023 and 2020,2022, Idaho Power had a $2.0$16.2 million and $1.5$56.2 million payable to IDACORP, respectively, which was included in its accounts payable to affiliates balance on its consolidated balance sheets.sheets, primarily related to income tax payments. At IDACORP, the receivable from Idaho Power is eliminated in consolidation.
 
Ida-West: Idaho Power purchases all of the power generated by four of Ida-West’s 50 percent owned PURPA qualifying hydropower projects located in Idaho. Idaho Power purchased $9.1 million in 2023, $7.9 million in 2022, and $8.2 million in 2021 $9.3 million in 2020, and $8.6 million in 2019 of power from Ida-West.

132127
Table of Contents                              
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
To the shareholders and the Board of Directors of IDACORP, Inc.
 
Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of IDACORP, Inc. and subsidiaries (the “Company”) as of December 31, 20212023 and 2020,2022, the related consolidated statements of income, comprehensive income, equity, and cash flows, for each of the three years in the period ended December 31, 2021,2023, and the related notes and the schedules listed in the Index at Item 8 (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 20212023 and 2020,2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021,2023, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2021,2023, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 17, 2022,15, 2024, expressed an unqualified opinion on the Company’s internal control over financial reporting.

Basis for Opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. 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 audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Regulation of Utility Operations - Refer to Notes 1 and 3 to the financial statements

Critical Audit Matter Description

Idaho Power Company (Idaho Power)("Idaho Power"), the principal operating subsidiary of the Company, is subject to rate regulation by the Federal Energy Regulatory Commission (FERC) and the Idaho and Oregon Public Utility Commissions (the “Commissions”), which have jurisdiction with respect to the rates of electric distribution companies in Idaho and Oregon. Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant, and equipment; regulatory assets and liabilities; operating revenues; operation and maintenance expense; depreciation expense; and income tax expense.

133128
Table of Contents                              
Idaho Power’s rates are subject to regulatory rate-setting processes. Regulatory decisions can have an impact on the recovery of costs, the rate of return earned on investment, and the timing and amount of assets to be recovered by rates. The Commissions’ regulation of rates is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital. Decisions to be made by the Commissions in the future will impact the accounting for regulated operations, including decisions about the amount of allowable costs and return on invested capital included in rates and any refunds that may be required. While the Company has indicated it expects Idaho Power to recover costs from customers through regulated rates, there is a risk that the Commissions will not approve:approve (1) full recovery of the costs of providing utility service, or (2) full recovery of all amounts invested in the utility business and a reasonable return on that investment.

Additionally, consistent with orders and directives of the Commissions, unless contrary to applicable income tax guidance, Idaho Power does not record deferred income tax expense or benefit for certain income tax temporary differences and instead recognizes the tax impact currently (commonly referred to as flow-through accounting) for rate making and financial reporting. Therefore, Idaho Power's effective income tax rate is impacted as these differences arise and reverse. Idaho Power recognizes such adjustments as regulatory assets or liabilities if it is probable that such amounts will be recovered from or returned to customers in future rates.

We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by managementcomplexity in applying the specialized rules to support its assertions about impacted account balances and disclosuresfor the effects of cost-based rate regulation and the degreerecording of subjectivity involved in assessing the impact of expected future regulatory orders on the financial statements. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costsassets and (2) a refund to customers for amounts collected prior to costs being incurred.liabilities. Given that management’s accounting judgments are based on assumptions aboutcomplexity, performing audit procedures to evaluate the outcomeCompany’s application of future decisions by the Commissions, auditing these judgmentsspecialized rules to account for the effects of cost-based rate regulation and the recording of regulatory assets and liabilities required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.rate-setting process.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the uncertaintyspecialized rules to account for the effects of future decisions by the Commissions andcost-based rate regulation, including the application of flow-through accounting for income taxes included the following, among others:

•We tested the effectiveness of management’s controls over the evaluationrecording of the likelihood of (1) the recovery in future rates of costs capitalized as property, plant, and equipment (2) recovery of costs deferred as regulatory assets and (3) a refund or a future reductionliabilities in rates that should be reported as regulatory liabilities.accordance with specialized rules to account for the effects of cost-based rate regulation.

•We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.

•We read relevant regulatory orders issued by the Commissions for Idaho Power and evaluated whether such orders were appropriately reflected in the Company's financial statements.

•For selected regulatory assets and liabilities, we evaluated whether management had determined such amounts in accordance with regulatory orders.orders and whether it was probable that such amounts will be recovered from or returned to customers in future rates.

•With the assistance of income tax specialists, we evaluated whether management had appropriately identified the income tax timing differences eligible for flow-through accounting and recorded such differences as adjustments to income tax expense and regulatory assets. We then assessed whether these regulatory assets were probable of being recovered through future rates by comparing methodology to current rate cases.

/s/ DELOITTE & TOUCHE LLP
 
Boise, Idaho
February 17, 202215, 2024

We have served as the Company's auditor since 1932.
134129
Table of Contents                              
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
To the shareholder and the Board of Directors of Idaho Power Company
 
Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Idaho Power Company and subsidiary (the “Company”) as of December 31, 20212023 and 2020,2022, the related consolidated statements of income, comprehensive income, retained earnings, and cash flows, for each of the three years in the period ended December 31, 2021,2023, and the related notes and the schedule listed in the Index at Item 8 (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 20212023 and 2020,2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021,2023, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2021,2023, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 17, 2022,15, 2024, expressed an unqualified opinion on the Company’s internal control over financial reporting.

Basis for Opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. 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 audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Regulation of Utility Operations - Refer to Notes 1 and 3 to the financial statements

Critical Audit Matter Description

The Company is subject to rate regulation by the Federal Energy Regulatory Commission (FERC) and the Idaho and Oregon Public Utility Commissions (the “Commissions”), which have jurisdiction with respect to the rates of electric distribution companies in Idaho and Oregon. Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant, and equipment; regulatory assets and liabilities; operating revenues; operation and maintenance expense; depreciation expense; and income tax expense.

The Company’s rates are subject to regulatory rate-setting processes. Regulatory decisions can have an impact on the recovery of costs, the rate of return earned on investment, and the timing and amount of assets to be recovered by rates. The
135130
Table of Contents                              
Commissions’ regulation of rates is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital. Decisions to be made by the Commissions in the future will impact the accounting for regulated operations, including decisions about the amount of allowable costs and return on invested capital included in rates and any refunds that may be required. While the Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that the Commissions will not approve:approve (1) full recovery of the costs of providing utility service, or (2) full recovery of all amounts invested in the utility business and a reasonable return on that investment.

Additionally, consistent with orders and directives of the Commissions, unless contrary to applicable income tax guidance, the Company does not record deferred income tax expense or benefit for certain income tax temporary differences and instead recognizes the tax impact currently (commonly referred to as flow-through accounting) for rate making and financial reporting. Therefore, the Company's effective income tax rate is impacted as these differences arise and reverse. The Company recognizes such adjustments as regulatory assets or liabilities if it is probable that such amounts will be recovered from or returned to customers in future rates.

We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by managementcomplexity in applying the specialized rules to support its assertions about impacted account balances and disclosuresfor the effects of cost-based rate regulation and the degreerecording of subjectivity involved in assessing the impact of expected future regulatory orders on the financial statements. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costsassets and (2) a refund to customers for amounts collected prior to costs being incurred.liabilities. Given that management’s accounting judgments are based on assumptions aboutcomplexity, performing audit procedures to evaluate the outcomeCompany's application of future decisions by the Commissions, auditing these judgmentsspecialized rules to account for the effects of cost-based rate regulation and the recording of regulatory assets and liabilities required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.rate-setting process.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the uncertaintyspecialized rules to account for the effects of future decisions by the Commissions andcost-based rate regulation, including the application of flow-through accounting for income taxes, included the following, among others:

•We tested the effectiveness of management’s controls over the evaluationrecording of the likelihood of (1) the recovery in future rates of costs capitalized as property, plant, and equipment (2) recovery of costs deferred as regulatory assets and (3) a refund or a future reductionliabilities in rates that should be reported as regulatory liabilities.accordance with specialized rules to account for the effects of cost-based rate regulation.

•We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.

•We read relevant regulatory orders issued by the Commissions for the Company and evaluated whether such orders were appropriately reflected in the Company's financial statements.

•For selected regulatory assets and liabilities, we evaluated whether management had determined such amounts in accordance with regulatory orders.orders and whether it was probable that such amounts will be recovered from or returned to customers in future rates.

•With the assistance of income tax specialists, we evaluated whether management had appropriately identified the income tax timing differences eligible for flow-through accounting and recorded such differences as adjustments to income tax expense and regulatory assets. We then assessed whether these regulatory assets were probable of being recovered through future rates by comparing methodology to current rate cases.
 
/s/ DELOITTE & TOUCHE LLP
 
Boise, Idaho
February 17, 202215, 2024

 We have served as the Company's auditor since 1932.
 
136131
Table of Contents                              
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
 
None.

ITEM 9A. CONTROLS AND PROCEDURES
 
Disclosure Controls and Procedures - IDACORP, Inc.

The Chief Executive Officer and Chief Financial Officer of IDACORP, Inc., based on their evaluation of IDACORP, Inc.’sIDACORP’s disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of December 31, 2021,2023, have concluded that IDACORP, Inc.’sIDACORP’s disclosure controls and procedures are effective as of that date.

Internal Control Over Financial Reporting - IDACORP, Inc.

Management’s Annual Report on Internal Control Over Financial Reporting
 
The management of IDACORP is responsible for establishing and maintaining adequate internal control over financial reporting for IDACORP. Internal control over financial reporting is defined in Rule 13a-15(f) promulgated under the Securities Exchange Act of 1934 as a process designed by, or under the supervision of, the company’s principal executive and principal financial officers and effected by the company’s board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America and includes those policies and procedures that:
 
•pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the company;
•provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States of America, and that receipts and expenditures of the company are being made only in accordance with the authorizations of management and directors of the company; and
•provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements.
 
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 
IDACORP’s management assessed the effectiveness of the company’s internal control over financial reporting as of December 31, 2021.2023. In making this assessment, the company’s management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework (2013).
 
Based on its assessment, management concluded that, as of December 31, 2021,2023, IDACORP’s internal control over financial reporting is effective based on those criteria.
 
IDACORP’s independent registered public accounting firm has audited the financial statements included in this Annual Report on Form 10-K for the year ended December 31, 20212023, and issued a report, which appears on the next page and expresses an unqualified opinion on the effectiveness of IDACORP’s internal control over financial reporting as of December 31, 2021.2023.
 
February 17, 202215, 2024

137132
Table of Contents                              
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
To the shareholders and the Board of Directors of
IDACORP, Inc.

Opinion on Internal Control over Financial Reporting

We have audited the internal control over financial reporting of IDACORP, Inc. and subsidiaries (the “Company”) as of December 31, 2021,2023, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2021,2023, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2021,2023, of the Company and our report dated February 17, 2022,15, 2024, expressed an unqualified opinion on those financial statements.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. 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 audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 
/s/ DELOITTE & TOUCHE LLP
 
Boise, Idaho
February 17, 202215, 2024

138133
Table of Contents                              
Disclosure Controls and Procedures - Idaho Power Company

The Chief Executive Officer and Chief Financial Officer of Idaho Power, Company, based on their evaluation of Idaho Power Company'sPower's disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of December 31, 2021,2023, have concluded that Idaho Power Company'sPower's disclosure controls and procedures are effective as of that date.

Internal Control Over Financial Reporting - Idaho Power Company

Management’s Annual Report on Internal Control Over Financial Reporting
 
The management of Idaho Power Company (Idaho Power) is responsible for establishing and maintaining adequate internal control over financial reporting of Idaho Power. Internal control over financial reporting is defined in Rule 13a-15(f) promulgated under the Securities Exchange Act of 1934 as a process designed by, or under the supervision of, the company’s principal executive and principal financial officers and effected by the company’s board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America and includes those policies and procedures that:
 
•pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the company;
•provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States of America, and that receipts and expenditures of the company are being made only in accordance with the authorizations of management and directors of the company; and
•provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements.
 
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 
Idaho Power’s management assessed the effectiveness of the company’s internal control over financial reporting as of December 31, 2021.2023. In making this assessment, the company’s management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework (2013).
 
Based on its assessment, management concluded that, as of December 31, 2021,2023, Idaho Power’s internal control over financial reporting is effective based on those criteria.
 
Idaho Power’s independent registered public accounting firm has audited the financial statements included in this Annual Report on Form 10-K for the year ended December 31, 2021,2023, and issued a report which appears on the next page and expresses an unqualified opinion on the effectiveness of Idaho Power’s internal control over financial reporting as of December 31, 2021.2023.
 
February 17, 202215, 2024

139134
Table of Contents                              
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
To the shareholder and the Board of Directors of
Idaho Power Company
 
Opinion on Internal Control over Financial Reporting

We have audited the internal control over financial reporting of Idaho Power Company and subsidiary (the “Company”) as of December 31, 2021,2023, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2021,2023, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2021,2023, of the Company and our report dated February 17, 2022,15, 2024, expressed an unqualified opinion on those financial statements.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. 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 audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.


/s/ DELOITTE & TOUCHE LLP
 
Boise, Idaho
February 17, 202215, 2024

140135
Table of Contents                              
Changes in Internal Control Over Financial Reporting - IDACORP, Inc. and Idaho Power Company
 
There have been no changes in IDACORP, Inc.’sIDACORP’s or Idaho Power Company’sPower’s internal control over financial reporting during the quarter ended December 31, 2021,2023, that have materially affected, or are reasonably likely to materially affect, IDACORP, Inc.’sIDACORP’s or Idaho Power Company’sPower’s internal control over financial reporting.
 

ITEM 9B. OTHER INFORMATION
 
None.During the three months ended December 31, 2023, none of IDACORP's or Idaho Power's directors or officers (as defined in
Rule 16a-1(f) of the Exchange Act) adopted, terminated, or modified a Rule 10b5-1 trading arrangement or
non-Rule 10b5-1 trading arrangement (as such terms are defined in Item 408 of Regulation S-K).

ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

Not applicable.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE
 
The portions of IDACORP’s definitive proxy statement appearing under the captions “Proposal No. 1: Election of Directors,” “Delinquent Section 16(a) Reports,” “Board of Directors - Committees of the Board of Directors - Audit Committee,” “Corporate Governance at IDACORP - Codes of Business Conduct,” and "Corporate Governance at IDACORP - Certain Relationships and Related Transactions" to be filed pursuant to Regulation 14A for the 20222024 annual meeting of shareholders are hereby incorporated by reference.
Information regarding IDACORP’s executive officers required by this item appears in Item 1 of this report under “Executive Officers of the Registrants.”

ITEM 11. EXECUTIVE COMPENSATION
 
The portion of IDACORP’s definitive proxy statement appearing under the caption “Executive Compensation” to be filed pursuant to Regulation 14A for the 20222024 annual meeting of shareholders is hereby incorporated by reference.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
 
The portion of IDACORP’s definitive proxy statement appearing under the caption “Security Ownership of Directors, Executive Officers, and Five-Percent Shareholders” to be filed pursuant to Regulation 14A for the 20222024 annual meeting of shareholders is hereby incorporated by reference. The table below includes information as of December 31, 2021,2023, with respect to the IDACORP 2000 Long-Term Incentive and Compensation Plan (LTICP)LTICP pursuant to which equity securities of IDACORP may be issued.

141136
Table of Contents                              
Plan Category(a)
Number of securities to be issued upon exercise
of outstanding options, warrants and rights		(b)
Weighted-average
exercise price of
outstanding options, warrants and rights		(c)
Number of securities remaining available for future issuance under equity compensation
plans (excluding securities reflected in column (a))
Equity compensation plans approved by shareholders250,875 (1)$— (2)244,938 (3)
Equity compensation plans not approved by shareholders— $— — 
Total250,875 $— 244,938 
(1) Represents shares subject to outstanding time-based restricted stock units, performance-based restricted stock units (at target), and deferred director stock unit awards, all under the LTICP. Such awards may be settled only for shares of common stock on a one-for-one basis.
(2) None of the outstanding awards included in column (a) have an exercise price.
(3) Shares under the LTICP may be issued in connection with stock options, stock appreciation rights, restricted stock, restricted stock units, performance units, performance shares, or other equity-based awards.
Equity Compensation Plan Information
Plan Category(a)
Number of securities to be issued upon exercise
of outstanding options, warrants and rights		(b)
Weighted-average
exercise price of
outstanding options, warrants and rights		(c)
Number of securities remaining available for future issuance under equity compensation
plans (excluding securities reflected in column (a))
Equity compensation plans approved by shareholders211,519 (1)$— (2)443,663 (3)
Equity compensation plans not approved by shareholders— $— — 
Total211,519 $— 443,663 
(1) Represents shares subject to outstanding time-based restricted stock units, performance-based restricted stock units (at target), and deferred director stock unit awards, all under the LTICP. Restricted stock unit awards and director deferred stock unit awards may be settled only for shares of common stock on a one-for-one basis.
(2) Time-based restricted stock units and performance-based restricted stock units have no exercise price.
(3) Shares under the LTICP may be issued in connection with stock options, stock appreciation rights, restricted stock, restricted stock units, performance units, performance shares, or other equity-based awards.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
 
The portions of IDACORP’s definitive proxy statement appearing under the captions “Certain Relationships and Related Transactions” and “Corporate Governance at IDACORP – Director Independence and Executive Sessions” to be filed pursuant to Regulation 14A for the 20222024 annual meeting of shareholders are hereby incorporated by reference.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
 
IDACORP: The portion of IDACORP’s definitive proxy statement appearing under the caption “Independent Accountant Billings” in the proxy statement to be filed pursuant to Regulation 14A for the 20222024 annual meeting of shareholders is hereby incorporated by reference.
 
Idaho Power: The table below presents the aggregate fees of Idaho Power's principal independent registered public accounting firm, Deloitte & Touche LLP, billed or is expected to bill to Idaho Power for the fiscal years ended December 31, 20212023 and 2020:2022:
20212020 20232022
Audit feesAudit fees$1,526,750 $1,531,235 
Audit-related fees(1)
Tax fees(1)
Tax fees(1)
19,885 16,121 
All other fees(2)
All other fees(2)
12,050 1,895 
TotalTotal$1,558,685 $1,549,251 
(1) Includes fees for consultation related to tax planning and accounting.
(1) Includes fees for consultation related to tax planning and accounting.
(1) Includes fees for consultation related to tax planning and accounting.
(2) Accounting research tool subscription and fees for finance and accounting conference attendance.(2) Accounting research tool subscription and fees for finance and accounting conference attendance.(2) Accounting research tool subscription and fees for finance and accounting conference attendance.
 
Policy on Audit Committee Pre-Approval:
 
Idaho Power and the Audit Committeeaudit committee are committed to ensuring the independence of the independent registered public accounting firm, both in fact and in appearance. In this regard, the Audit Committeeaudit committee has established and periodically reviews a pre-approval policy for audit and non-audit services. For 20212023 and 2020,2022, all audit and non-audit services and all fees paid in connection with those services were pre-approved by the Audit Committee.audit committee.
 
In addition to the audits of Idaho Power’s consolidated financial statements, the independent public accounting firm may be engaged to provide certain audit-related, tax, and other services. The Audit Committeeaudit committee must pre-approve all services performed by the independent public accounting firm to assure that the provision of those services does not impair the public accounting firm’s independence. The services that the Audit Committeeaudit committee will consider include: audit services such as attest services, changes in the scope of the audit of the financial statements, and the issuance of comfort letters and consents in connection with financings; audit-related services such as internal control reviews and assistance with internal control reporting requirements;
142137
Table of Contents                              
attest services related to financial reporting that are not required by statute or regulation, and accounting consultations and audits related to proposed transactions and new or proposed accounting rules, standards and interpretations; and tax compliance and planning services. Unless a type of service to be provided by the independent public accounting firm has received general pre-approval, it will require specific pre-approval by the Audit Committee.audit committee. In addition, any proposed services exceeding pre-approved cost levels will require specific pre-approval by the Audit Committee.audit committee. Under the pre-approval policy, the Audit Committeeaudit committee has delegated to the ChairmanChair of the Audit Committeeaudit committee pre-approval authority for proposed services; however, the ChairmanChair must report any pre-approval decisions to the Audit Committeeaudit committee at its next scheduled meeting.
 
Any request to engage the independent public accounting firm to provide a service which has not received general pre-approval must be submitted as a written proposal to Idaho Power’s Chief Financial Officer with a copy to the General Counsel. The request must include a detailed description of the service to be provided, the proposed fee, and the business reasons for engaging the independent public accounting firm to provide the service. Upon approval by the Chief Financial Officer, the General Counsel, and the independent public accounting firm that the proposed engagement complies with the terms of the pre-approval policy and the applicable rules and regulations, the request will be presented to the Audit Committeeaudit committee or the Audit Committee Chairman,audit committee Chair, as the case may be, for pre-approval.

In determining whether to pre-approve the engagement of the independent public accounting firm, the Audit Committeeaudit committee or the Committee Chairman,committee Chair, as the case may be, must consider, among other things, the pre-approval policy, applicable rules and regulations, and whether the nature of the engagement and the related fees are consistent with the following principles:
 
•       the independent public accounting firm cannot function in the role of management of Idaho Power; and
•       the independent public accounting firm cannot audit its own work.
 
The pre-approval policy and separate supplements to the pre-approval policy describe the specific audit, audit related,audit-related, tax, and other services that have the general pre-approval of the Audit Committee.audit committee. The term of any pre-approval is 12 months from the date of pre-approval, unless the Audit Committeeaudit committee specifically provides for a different period. The Audit Committeeaudit committee will periodically revise the list of pre-approved services, based on subsequent determinations.

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
 
(1) and (2) Refer to Part II, Item 8 - “Financial Statements” for a complete listing of consolidated financial statements and financial statement schedules.
 
(3) Exhibits. Note Regarding Reliance on Statements in Agreements: The agreements filed as exhibits to IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2021,2023, are filed to provide information regarding their terms and are not intended to provide any other factual or disclosure information about IDACORP, Inc., Idaho Power Company, or the other parties to the agreements. Some of the agreements contain statements, representations, and warranties by each of the parties to the applicable agreement. These representations and warranties have been made solely for the benefit of the other parties to the applicable agreement and (a) should not in all instances should not be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties to the agreement if those statements prove to be inaccurate; (b) have been qualified by disclosures that were made to the other party, which disclosures are not necessarily reflected in the agreement; (c) may apply standards of materiality in a way that is different from what may be viewed as material to investors; and (d) were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement and are subject to more recent developments. Accordingly, readers should not rely upon the statements, representations, or warranties made in the agreements.
Incorporated by Reference
Exhibit No.Exhibit DescriptionFormFile No.Exhibit No.DateIncluded Herewith
2S-4333-48031A3/16/1998
3.1Restated Articles of Incorporation of Idaho Power Company as filed with the Secretary of State of Idaho on June 30, 1989S-3 Post-Effective Amend. No. 233-00440*4(a)(xiii)6/30/1989
143
Table of Contents          ��                  
Incorporated by Reference
Exhibit No.Exhibit DescriptionFormFile No.Exhibit No.DateIncluded Herewith
3.2Statement of Resolution Establishing Terms of Flexible Auction Series A, Serial Preferred Stock, Without Par Value (cumulative stated value of $100,000 per share) of Idaho Power Company, as filed with the Secretary of State of Idaho on November 5, 1991S-333-65720*4(a)(ii)7/7/1993
3.3Statement of Resolution Establishing Terms of 7.07% Serial Preferred Stock, Without Par Value (cumulative stated value of $100 per share) of Idaho Power Company, as filed with the Secretary of State of Idaho on June 30, 1993S-333-65720*4(a)(iii)7/7/1993
3.4S-8 Post-Effective Amend. No. 133-56071-993(d)10/1/1998
3.510-Q1-31983(a)(iii)8/4/2000
3.68-K1-31983.31/26/2005
3.78-K1-31983.311/19/2007
3.88-K1-31983.145/21/2012
3.98-K1-31983.211/19/2007
3.10S-3333-647373.111/4/1998
3.11S-3 Amend. No. 1333-647373.211/4/1998
3.12S-3 Post-Effective Amend. No. 1333-00139-993(b)9/22/1998
3.138-K1-144653.135/21/2012
3.1410-Q1-144653.1510/30/2014
4.1Mortgage and Deed of Trust, dated as of October 1, 1937, between Idaho Power Company and Deutsche Bank Trust Company Americas (formerly known as Bankers Trust Company) and R. G. Page, as Trustees2-3413*B-2
4.2Idaho Power Company Supplemental Indentures to Mortgage and Deed of Trust:
File number 1-MD, as Exhibit B-2-a, First, July 1, 1939*
File number 2-5395, as Exhibit 7-a-3, Second, November 15, 1943*
File number 2-7237, as Exhibit 7-a-4, Third, February 1, 1947*
File number 2-7502, as Exhibit 7-a-5, Fourth, May 1, 1948*
File number 2-8398, as Exhibit 7-a-6, Fifth, November 1, 1949*
File number 2-8973, as Exhibit 7-a-7, Sixth, October 1, 1951*
File number 2-12941, as Exhibit 2-C-8, Seventh, January 1, 1957*
File number 2-13688, as Exhibit 4-J, Eighth, July 15, 1957*
File number 2-13689, as Exhibit 4-K, Ninth, November 15, 1957*
File number 2-14245, as Exhibit 4-L, Tenth, April 1, 1958*
File number 2-14366, as Exhibit 2-L, Eleventh, October 15, 1958*
File number 2-14935, as Exhibit 4-N, Twelfth, May 15, 1959*
File number 2-18976, as Exhibit 4-O, Thirteenth, November 15, 1960*
File number 2-18977, as Exhibit 4-Q, Fourteenth, November 1, 1961*
File number 2-22988, as Exhibit 4-B-16, Fifteenth, September 15, 1964*
144138
Table of Contents                              
Incorporated by Reference
Exhibit No.Exhibit DescriptionFormFile No.Exhibit No.DateIncluded Herewith
File number 2-24578, as Exhibit 4-B-17, Sixteenth, April 1, 1966*
File number 2-25479, as Exhibit 4-B-18, Seventeenth, October 1, 1966*
File number 2-45260, as Exhibit 2(c), Eighteenth, September 1, 1972*
File number 2-49854, as Exhibit 2(c), Nineteenth, January 15, 1974*
File number 2-51722, as Exhibit 2(c)(i), Twentieth, August 1, 1974*
File number 2-51722, as Exhibit 2(c)(ii), Twenty-first, October 15, 1974*
File number 2-57374, as Exhibit 2(c), Twenty-second, November 15, 1976*
File number 2-62035, as Exhibit 2(c), Twenty-third, August 15, 1978*
File number 33-34222, as Exhibit 4(d)(iii), Twenty-fourth, September 1, 1979*
File number 33-34222, as Exhibit 4(d)(iv), Twenty-fifth, November 1, 1981*
File number 33-34222, as Exhibit 4(d)(v), Twenty-sixth, May 1, 1982*
File number 33-34222, as Exhibit 4(d)(vi), Twenty-seventh, May 1, 1986*
File number 33-00440, as Exhibit 4(c)(iv), Twenty-eighth, June 30, 1989*
File number 33-34222, as Exhibit 4(d)(vii), Twenty-ninth, January 1, 1990*
File number 33-65720, as Exhibit 4(d)(iii), Thirtieth, January 1, 1991*
File number 33-65720, as Exhibit 4(d)(iv), Thirty-first, August 15, 1991*
File number 33-65720, as Exhibit 4(d)(v), Thirty-second, March 15, 1992*
File number 33-65720, as Exhibit 4(d)(vi), Thirty-third, April 1, 1993*
File number 1-3198, Form 8-K, filed on 12/20/93, as Exhibit 4, Thirty-fourth, December 1, 1993*
File number 1-3198, Form 8-K, filed on 11/21/00, as Exhibit 4, Thirty-fifth, November 1, 2000
File number 1-3198, Form 8-K, filed on 10/1/01, as Exhibit 4, Thirty-sixth, October 1, 2001
File number 1-3198, Form 8-K, filed on 4/16/03, as Exhibit 4, Thirty-seventh, April 1, 2003
File number 1-3198, Form 10-Q for the quarter ended June 30, 2003, filed on 8/7/03, as Exhibit 4(a)(iii), Thirty-eighth, May 15, 2003
File number 1-3198, Form 10-Q for the quarter ended September 30, 2003, filed on 11/6/03, as Exhibit 4(a)(iv), Thirty-ninth, October 1, 2003
File number 1-3198, Form 8-K filed on 5/10/05, as Exhibit 4, Fortieth, May 1, 2005
File number 1-3198, Form 8-K filed on 10/10/06, as Exhibit 4, Forty-first, October 1, 2006
File number 1-3198, Form 8-K filed on 6/4/07, as Exhibit 4, Forty-second, May 1, 2007
File number 1-3198, Form 8-K filed on 9/26/07, as Exhibit 4, Forty-third, September 1, 2007
File number 1-3198, Form 8-K filed on 4/3/08, as Exhibit 4, Forty-fourth, April 1, 2008
File number 1-3198, Form 10-K filed on 2/23/10, as Exhibit 4.10, Forty-fifth, February 1, 2010
File number 1-3198, Form 8-K filed on 6/18/10, as Exhibit 4, Forty-sixth, June 1, 2010
File number 1-3198, Form 8-K filed on 7/12/2013, as Exhibit 4.1, Forty-seventh, July 1, 2013
File number 1-3198, Form 8-K filed on 9/27/2016, as Exhibit 4.1, Forty-eighth, September 1, 2016
4.310-Q1-31984(b)8/4/2000
4.4Agreement of Idaho Power Company to furnish certain debt instrumentsS-333-65720*4(f)7/7/1993
4.5Agreement and Plan of Merger dated March 10, 1989, between Idaho Power Company, a Maine corporation, and Idaho Power Migrating CorporationS-3 Post-Effective Amend. No. 233-00440*2(a)(iii)6/30/1989
4.68-K1-144654.12/28/2001
4.78-K1-144654.22/28/2001
4.8S-3333-677484.138/16/2001
Incorporated by Reference
Exhibit No.Exhibit DescriptionFormFile No.Exhibit No.DateIncluded Herewith
3.2Statement of Resolution Establishing Terms of Flexible Auction Series A, Serial Preferred Stock, Without Par Value (cumulative stated value of $100,000 per share) of Idaho Power Company, as filed with the Secretary of State of Idaho on November 5, 1991S-333-65720*4(a)(ii)7/7/1993
3.3Statement of Resolution Establishing Terms of 7.07% Serial Preferred Stock, Without Par Value (cumulative stated value of $100 per share) of Idaho Power Company, as filed with the Secretary of State of Idaho on June 30, 1993S-333-65720*4(a)(iii)7/7/1993
3.4S-8 Post-Effective Amend. No. 133-56071-993(d)10/1/1998
3.510-Q1-31983(a)(iii)8/4/2000
3.68-K1-31983.31/26/2005
3.78-K1-31983.311/19/2007
3.88-K1-31983.145/21/2012
3.98-K1-31983.211/19/2007
3.10S-3 Amend. No. 1333-647373.111/4/1998
3.11S-3 Amend. No. 1333-647373.211/4/1998
3.12S-3 Post-Effective Amend. No. 1333-00139-993(b)9/22/1998
3.138-K1-144653.135/21/2012
3.148-K1-14465, 1-31983.111/22/2023
4.1Mortgage and Deed of Trust, dated as of October 1, 1937, between Idaho Power Company and Deutsche Bank Trust Company Americas (formerly known as Bankers Trust Company) and R. G. Page, as Trustees2-3413*B-2
4.2Idaho Power Company Supplemental Indentures to Mortgage and Deed of Trust:
File number 1-MD, as Exhibit B-2-a, First, July 1, 1939*
File number 2-5395, as Exhibit 7-a-3, Second, November 15, 1943*
File number 2-7237, as Exhibit 7-a-4, Third, February 1, 1947*
File number 2-7502, as Exhibit 7-a-5, Fourth, May 1, 1948*
File number 2-8398, as Exhibit 7-a-6, Fifth, November 1, 1949*
File number 2-8973, as Exhibit 7-a-7, Sixth, October 1, 1951*
File number 2-12941, as Exhibit 2-C-8, Seventh, January 1, 1957*
File number 2-13688, as Exhibit 4-J, Eighth, July 15, 1957*
File number 2-13689, as Exhibit 4-K, Ninth, November 15, 1957*
File number 2-14245, as Exhibit 4-L, Tenth, April 1, 1958*
File number 2-14366, as Exhibit 2-L, Eleventh, October 15, 1958*
File number 2-14935, as Exhibit 4-N, Twelfth, May 15, 1959*
File number 2-18976, as Exhibit 4-O, Thirteenth, November 15, 1960*
145139
Table of Contents                              
Incorporated by Reference
Exhibit No.Exhibit DescriptionFormFile No.Exhibit No.DateIncluded Herewith
4.910-Q1-31984.128/5/2010
4.1010-K1-14465, 1-31984.102/18/21
10.110-K1-14465, 1-319810.42/19/2015
10.210-K1-14465, 1-319810.52/19/2015
10.3Framework Agreement, dated October 1, 1984, between the State of Idaho and Idaho Power Company relating to Idaho Power Company's Swan Falls and Snake River water rightsS-333-65720*10(h)7/7/1993
10.4Agreement, dated October 25, 1984, between the State of Idaho and Idaho Power Company, relating to the agreement filed as Exhibit 10.3S-333-65720*10(h)(i)7/7/1993
10.5Contract to Implement, dated October 25, 1984, between the State of Idaho and Idaho Power Company, relating to the agreement filed as Exhibit 10.3S-333-65720*10(h)(ii)7/7/1993
10.610-Q1-14465*10.585/7/2009
10.7Agreement Regarding the Ownership, Construction, Operation and Maintenance of the Milner Hydroelectric Project (FERC No. 2899), dated January 22, 1990, between Idaho Power Company and the Twin Falls Canal Company and the Northside Canal Company LimitedS-333-65720*10(m)7/7/1993
10.88-K1-14465, 1-319810.111/9/2015
10.98-K1-14465, 1-319810.211/9/2015
10.10
First Amendment to Credit Agreement, dated December 6, 2019, among IDACORP, Inc., Wells Fargo Bank, National Association, as administrative agent, swingline lender, and LC issuer; JPMorgan Chase Bank, N.A., as syndication agent and LC issuer; KeyBank National Association and MUFG Bank, LTD., as documentation agents and LC Issuers; Wells Fargo Securities, LLC, and JPMorgan Chase Bank, N.A., as joint lead arrangers and joint book runners; and the other lenders named therein
8-K1-14465, 1-319810.112/10/2019
10.118-K1-14465, 1-319810.212/10/2019
Incorporated by Reference
Exhibit No.Exhibit DescriptionFormFile No.Exhibit No.DateIncluded Herewith
File number 2-18977, as Exhibit 4-Q, Fourteenth, November 1, 1961*
File number 2-22988, as Exhibit 4-B-16, Fifteenth, September 15, 1964*
File number 2-24578, as Exhibit 4-B-17, Sixteenth, April 1, 1966*
File number 2-25479, as Exhibit 4-B-18, Seventeenth, October 1, 1966*
File number 2-45260, as Exhibit 2(c), Eighteenth, September 1, 1972*
File number 2-49854, as Exhibit 2(c), Nineteenth, January 15, 1974*
File number 2-51722, as Exhibit 2(c)(i), Twentieth, August 1, 1974*
File number 2-51722, as Exhibit 2(c)(ii), Twenty-first, October 15, 1974*
File number 2-57374, as Exhibit 2(c), Twenty-second, November 15, 1976*
File number 2-62035, as Exhibit 2(c), Twenty-third, August 15, 1978*
File number 33-34222, as Exhibit 4(d)(iii), Twenty-fourth, September 1, 1979*
File number 33-34222, as Exhibit 4(d)(iv), Twenty-fifth, November 1, 1981*
File number 33-34222, as Exhibit 4(d)(v), Twenty-sixth, May 1, 1982*
File number 33-34222, as Exhibit 4(d)(vi), Twenty-seventh, May 1, 1986*
File number 33-00440, as Exhibit 4(c)(iv), Twenty-eighth, June 30, 1989*
File number 33-34222, as Exhibit 4(d)(vii), Twenty-ninth, January 1, 1990*
File number 33-65720, as Exhibit 4(d)(iii), Thirtieth, January 1, 1991*
File number 33-65720, as Exhibit 4(d)(iv), Thirty-first, August 15, 1991*
File number 33-65720, as Exhibit 4(d)(v), Thirty-second, March 15, 1992*
File number 33-65720, as Exhibit 4(d)(vi), Thirty-third, April 1, 1993*
File number 1-3198, Form 8-K, filed on 12/20/93, as Exhibit 4, Thirty-fourth, December 1, 1993*
File number 1-3198, Form 8-K, filed on 11/21/00, as Exhibit 4, Thirty-fifth, November 1, 2000
File number 1-3198, Form 8-K, filed on 10/1/01, as Exhibit 4, Thirty-sixth, October 1, 2001
File number 1-3198, Form 8-K, filed on 4/16/03, as Exhibit 4, Thirty-seventh, April 1, 2003
File number 1-3198, Form 10-Q for the quarter ended June 30, 2003, filed on 8/7/03, as Exhibit 4(a)(iii), Thirty-eighth, May 15, 2003
File number 1-3198, Form 10-Q for the quarter ended September 30, 2003, filed on 11/6/03, as Exhibit 4(a)(iv), Thirty-ninth, October 1, 2003
File number 1-3198, Form 8-K filed on 5/10/05, as Exhibit 4, Fortieth, May 1, 2005
File number 1-3198, Form 8-K filed on 10/10/06, as Exhibit 4, Forty-first, October 1, 2006
File number 1-3198, Form 8-K filed on 6/4/07, as Exhibit 4, Forty-second, May 1, 2007
File number 1-3198, Form 8-K filed on 9/26/07, as Exhibit 4, Forty-third, September 1, 2007
File number 1-3198, Form 8-K filed on 4/3/08, as Exhibit 4, Forty-fourth, April 1, 2008
File number 1-3198, Form 10-K filed on 2/23/10, as Exhibit 4.10, Forty-fifth, February 1, 2010
File number 1-3198, Form 8-K filed on 6/18/10, as Exhibit 4, Forty-sixth, June 1, 2010
File number 1-3198, Form 8-K filed on 7/12/2013, as Exhibit 4.1, Forty-seventh, July 1, 2013
File number 1-3198, Form 8-K filed on 9/27/2016, as Exhibit 4.1, Forty-eighth, September 1, 2016
File number 1-3198, Form 8-K filed on 12/22/2022, as Exhibit 4.1, Fifty-second, December 20, 2022
4.310-Q1-31984(b)8/4/2000
4.4Agreement of Idaho Power Company to furnish certain debt instrumentsS-333-65720*4(f)7/7/1993
4.5Agreement and Plan of Merger dated March 10, 1989, between Idaho Power Company, a Maine corporation, and Idaho Power Migrating CorporationS-3 Post-Effective Amend. No. 233-00440*2(a)(iii)6/30/1989
4.68-K1-144654.12/28/2001
146140
Table of Contents                              
Incorporated by Reference
Exhibit No.Exhibit DescriptionFormFile No.Exhibit No.DateIncluded Herewith
10.128-K1-14465, 1-319810.112/3/2021
10.138-K1-14465, 1-319810.212/3/2021
10.148-K1-319810.110/10/2006
10.1510-Q1-319810(c)8/4/2000
10.161
10-K1-14465, 1-319810.152/26/2009
10.171
10-Q1-14465, 1-319810.6211/1/2012
10.181
10-K1-14465, 1-319810.312/23/2017
10.191
10-Q1-14465, 1-319810.18/3/2017
10.201
10-Q1-14465, 1-319810(h)(viii)11/2/2006
10.211
X
10.221
10-Q1-14465, 1-319810(h)(xix)11/2/2006
10.231
10-Q1-14465, 1-319810(h)(xx)11/2/2006
10.241
10-K1-14465, 1-319810.242/26/2009
10.251
10-K1-14465, 1-319810.252/26/2009
10.261
8-K1-14465, 1-319810.13/24/2010
10.271
10-K1-14465, 1-319810.252/18/21
10.281
10-K1-14465, 1-319810.412/23/2017
10.291
10-K1-14465, 1-319810.302/21/2019
10.301
10-K1-14465, 1-319810.312/21/2019
Incorporated by Reference
Exhibit No.Exhibit DescriptionFormFile No.Exhibit No.DateIncluded Herewith
4.78-K1-144654.22/28/2001
4.8S-3333-677484.138/16/2001
4.910-Q1-31984.128/5/2010
4.10X
10.110-K1-14465, 1-319810.42/19/2015
10.210-K1-14465, 1-319810.52/19/2015
10.3Framework Agreement, dated October 1, 1984, between the State of Idaho and Idaho Power Company relating to Idaho Power Company's Swan Falls and Snake River water rightsS-333-65720*10(h)7/7/1993
10.4Agreement, dated October 25, 1984, between the State of Idaho and Idaho Power Company, relating to the agreement filed as Exhibit 10.3S-333-65720*10(h)(i)7/7/1993
10.5Contract to Implement, dated October 25, 1984, between the State of Idaho and Idaho Power Company, relating to the agreement filed as Exhibit 10.3S-333-65720*10(h)(ii)7/7/1993
10.610-Q1-1446510.585/7/2009
10.7Agreement Regarding the Ownership, Construction, Operation and Maintenance of the Milner Hydroelectric Project (FERC No. 2899), dated January 22, 1990, between Idaho Power Company and the Twin Falls Canal Company and the Northside Canal Company LimitedS-333-65720*10(m)7/7/1993
10.88-K1-14465, 1-319810.112/11/2023
10.98-K1-14465, 1-319810.212/11/2023
10.108-K1-1446510.111/9/2023
10.118-K1-1446510.211/9/2023
10.128-K1-319810.110/10/2006
10.1310-Q1-319810(c)8/4/2000
10.141
10-K1-14465, 1-319810.152/26/2009
10.151
10-Q1-14465, 1-319810.6211/1/2012
147141
Table of Contents                              
Incorporated by Reference
Exhibit No.Exhibit DescriptionFormFile No.Exhibit No.DateIncluded Herewith
10.161
10-K1-14465, 1-319810.312/23/2017
10.171
10-Q1-14465, 1-319810.18/3/2017
10.181
10-Q1-14465, 1-319810(h)(viii)11/2/2006
10.191
10-K1-14465, 1-319810.212/17/2022
10.201
10-Q1-14465, 1-319810(h)(xix)11/2/2006
10.211
10-Q1-14465, 1-319810(h)(xx)11/2/2006
10.221
10-K1-14465, 1-319810.242/26/2009
10.231
10-K1-14465, 1-319810.252/26/2009
10.241
8-K1-14465, 1-319810.13/24/2010
10.251
X
10.261
10-K1-14465, 1-319810.412/23/2017
10.271
X
10.281
X
10.291
10-K1-14465, 1-3198X10.322/21/2019
10.3210.301
10-K1-14465, 1-319810.362/21/2019
10.3310.311
10-K1-14465, 1-319810.322/26/2009
10.3410.321
10-KX1-14465, 1-319810.342/17/2022
10.3510.331
10-K1-14465, 1-319810.462/26/2009
10.3610.341
10-K1-14465, 1-319810.472/26/2009
10.3710.351
10-K1-14465, 1-319810.482/26/2009
10.3810.361
10-K1-14465, 1-319810.492/26/2009
10.3910.371
10-K1-14465, 1-319810.502/26/2009
142
Table of Contents
Incorporated by Reference
Exhibit No.Exhibit DescriptionFormFile No.Exhibit No.DateIncluded Herewith
10.4010.381
10-K1-14465, 1-319810.512/26/2009
10.4110.391
10-K1-14465, 1-319810.522/26/2009
10.4210.401
10-K1-14465, 1-319810.532/26/2009
10.4310.411
10-K1-14465, 1-319810.592/18/2016
10.4410.421
10-K1-14465, 1-319810.612/23/2017
10.4510.431
10-Q1-14465, 1-319810.111/2/2017
10.4610.441
10-Q1-14465, 1-319810.45/3/2018
10.4710.451
10-Q1-14465, 1-319810.110/31/2019
10.4810.461
10-K1-14465, 1-319810.492/18/212021
10.471
10-Q1-14465, 1-319810.15/5/2022
21.1X
23.1X
23.2X
31.1X
31.2X
31.3X
31.4X
32.1X
32.2X
32.3X
32.4X
95.1X
97.1X
101.SCHInline XBRL Taxonomy Extension Schema DocumentX
148
Table of Contents
Incorporated by Reference
Exhibit No.Exhibit DescriptionFormFile No.Exhibit No.DateIncluded Herewith
101.CALInline XBRL Taxonomy Extension Calculation Linkbase DocumentX
101.LABInline XBRL Taxonomy Extension Label Linkbase DocumentX
101.PREInline XBRL Taxonomy Extension Presentation Linkbase DocumentX
101.DEFInline XBRL Taxonomy Extension Definition Linkbase DocumentX
104Cover Page Interactive Data File (formatted as inline XBRL with applicable taxonomy extension information contained in Exhibits 101.)X
* Exhibit originally filed with the U.S. Securities and Exchange CommissionSEC in paper format and as such, a hyperlink is not available.
(1) Management contract or compensatory plan or arrangement

149143
Table of Contents                              
IDACORP, INC.
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME
Year Ended December 31, Year Ended December 31,
202120202019 202320222021
(thousands of dollars) (thousands of dollars)
Income:Income:  Income:  
Equity in income of subsidiariesEquity in income of subsidiaries$245,591 $237,233 $231,534 
Investment incomeInvestment income148 748 2,214 
Total incomeTotal income245,739 237,981 233,748 
Expenses:Expenses:   Expenses: 
Operating expensesOperating expenses679 692 816 
Interest expenseInterest expense82 534 831 
Other expensesOther expenses192 145 30 
Total expensesTotal expenses953 1,371 1,677 
Income Before Income TaxesIncome Before Income Taxes244,786 236,610 232,071 
Income Tax BenefitIncome Tax Benefit(764)(807)(783)
Net Income Attributable to IDACORP, Inc.Net Income Attributable to IDACORP, Inc.245,550 237,417 232,854 
Other comprehensive (loss) incomeOther comprehensive (loss) income3,318 (7,074)(13,440)
Comprehensive Income Attributable to IDACORP, Inc.Comprehensive Income Attributable to IDACORP, Inc.$248,868 $230,343 $219,414 
The accompanying note is an integral part of these statements.
The accompanying note is an integral part of these statements.
The accompanying note is an integral part of these statements.

IDACORP, INC.
CONDENSED STATEMENTS OF CASH FLOWS
Year Ended December 31, Year Ended December 31,
202120202019 202320222021
(thousands of dollars) (thousands of dollars)
Operating Activities:Operating Activities:   Operating Activities: 
Net cash provided by operating activitiesNet cash provided by operating activities$174,209 $168,699 $112,745 
Investing Activities:Investing Activities:   Investing Activities: 
Purchase of short-term investments(26,363)(25,000)— 
Maturities of short-term investments50,000 — — 
Net cash provided by (used in) investing activities23,637 (25,000)— 
Purchase of investments
Purchase of investments
Purchase of investments
Maturities of investments
Net cash (used in) provided by investing activities
Financing Activities:Financing Activities:   Financing Activities: 
Dividends on common stockDividends on common stock(146,119)(137,856)(129,682)
Change in intercompany notes payableChange in intercompany notes payable(2,167)(9,732)37,588 
Change in intercompany notes payable
Change in intercompany notes payable
OtherOther(3,124)(4,663)(4,410)
Net cash used in financing activitiesNet cash used in financing activities(151,410)(152,251)(96,504)
Net increase (decrease) in cash and cash equivalents46,436 (8,552)16,241 
Net (decrease) increase in cash and cash equivalents
Cash and cash equivalents at beginning of yearCash and cash equivalents at beginning of year106,589 115,141 98,900 
Cash and cash equivalents at end of yearCash and cash equivalents at end of year$153,025 $106,589 $115,141 
The accompanying note is an integral part of these statements.
The accompanying note is an integral part of these statements.
The accompanying note is an integral part of these statements.

150144
Table of Contents                              
IDACORP, INC.
CONDENSED BALANCE SHEETS
December 31, December 31,
20212020 20232022
AssetsAssets(thousands of dollars)Assets(thousands of dollars)
Current Assets:Current Assets:  Current Assets: 
Cash and cash equivalentsCash and cash equivalents$153,025 $106,589 
Short-term investments— 25,000 
ReceivablesReceivables2,050 1,604 
Receivables
Receivables
Income taxes receivable
Other
Other
OtherOther102 107 
Total current assetsTotal current assets155,177 133,300 
InvestmentsInvestments2,570,150 2,468,955 
Other Assets:Other Assets: Other Assets: 
Deferred income taxesDeferred income taxes5,004 23,859 
OtherOther299 312 
Total other assetsTotal other assets5,303 24,171 
Total assetsTotal assets$2,730,630 $2,626,426 
Liabilities and Shareholders’ EquityLiabilities and Shareholders’ Equity Liabilities and Shareholders’ Equity 
Current Liabilities: 
Taxes accrued$850 $2,745 
Other777 928 
Total current liabilities1,627 3,673 
Other Liabilities: 
Noncurrent Liabilities:
Noncurrent Liabilities:
Noncurrent Liabilities:
Intercompany notes payable
Intercompany notes payable
Intercompany notes payableIntercompany notes payable59,928 62,049 
OtherOther639 724 
Total other liabilities60,567 62,773 
Total noncurrent liabilities
IDACORP, Inc. Shareholders’ EquityIDACORP, Inc. Shareholders’ Equity2,668,436 2,559,980 
Total Liabilities and Shareholders' EquityTotal Liabilities and Shareholders' Equity$2,730,630 $2,626,426 
The accompanying note is an integral part of these statements.
The accompanying note is an integral part of these statements.
The accompanying note is an integral part of these statements.

NOTE TO CONDENSED FINANCIAL STATEMENTS

1. BASIS OF PRESENTATION
 
Pursuant to rules and regulations of the U.S. Securities and Exchange Commission,SEC, the unconsolidated condensed financial statements of IDACORP Inc. do not reflect all of the information and notes normally included with financial statements prepared in accordance with accounting principles generally accepted in the United States of America.GAAP. Therefore, these financial statements should be read in conjunction with the consolidated financial statements and related notes included in the 20212023 Form 10-K, Part II, Item 8.

Accounting for Subsidiaries: IDACORP has accounted for the earnings of its subsidiaries under the equity method of accounting in these unconsolidated condensed financial statements. Included in net cash provided by operating activities in the condensed statements of cash flows are dividends that IDACORP subsidiaries paid to IDACORP of $105 million, $117 million, and $149 million $141 million,in 2023, 2022, and $133 million in 2021, 2020, and 2019, respectively.

151145
Table of Contents                              
IDACORP, INC. AND IDAHO POWER COMPANY
SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31, 2021, 2020,2023, 2022, and 20192021
 
 Additions   Additions 
  Charged     Charged 
Balance atCharged(Credited) Balance at Balance atCharged(Credited) Balance at
Beginningtoto OtherEnd Beginningtoto OtherEnd
ClassificationClassificationof YearIncomeAccounts
Deductions(1)
of YearClassificationof YearIncomeAccounts
Deductions(1)
of Year
(thousands of dollars) (thousands of dollars)
2021:
2023:
Reserve for uncollectible accountsReserve for uncollectible accounts$5,263 $2,083 $640 $2,970 $5,016 
Injuries and damages2,484 2,032 — 736 3,780 
2020:     
Reserve for uncollectible accountsReserve for uncollectible accounts$1,744 $5,239 $438 $2,158 $5,263 
Injuries and damages1,748 1,203 — 467 2,484 
2019:     
Reserve for uncollectible accountsReserve for uncollectible accounts$1,989 $2,381 $227 $2,853 $1,744 
Injuries and damagesInjuries and damages1,877 390 — 519 1,748 
Injuries and damages
Injuries and damages
2022:2022:  
Reserve for uncollectible accounts
Reserve for uncollectible accounts
Reserve for uncollectible accounts
Injuries and damages
Injuries and damages
Injuries and damages
2021:2021: 
Reserve for uncollectible accounts
Reserve for uncollectible accounts
Reserve for uncollectible accounts
Injuries and damages
Injuries and damages
Injuries and damages
(1) Represents deductions from the reserves for purposes for which the reserves were created. In the case of uncollectible accounts, and notes reserves, includes reversals of amounts previously reserved.


ITEM 16. FORM 10-K SUMMARY
None.

152146
Table of Contents                              
SIGNATURES
 
Pursuant to the requirements of Section 13 andor 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
 
February 17, 202215, 2024 IDACORP, INC.
Date
  By:/s/ Lisa A. Grow
    Lisa A. Grow
    President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Signature TitleDate
    
/s/ Richard J. Dahl ChairmanChair of the BoardFebruary 17, 202215, 2024
Richard J. Dahl   
    
/s/ Lisa A. Grow (Principal Executive Officer)February 17, 202215, 2024
Lisa A. Grow   
President and Chief Executive Officer and Director   
/s/ StevenBrian R. KeenBuckham (Principal Financial Officer)February 17, 202215, 2024
StevenBrian R. KeenBuckham  
Senior Vice President, and Chief Financial Officer, and Treasurer   
    
/s/ Kenneth W. PetersenAmy I. Shaw (Principal Accounting Officer)February 17, 202215, 2024
Kenneth W. PetersenAmy I. Shaw  
Vice President Chief Accounting Officerof Finance, Compliance, and TreasurerRisk 
/s/ Darrel T. AndersonDirectorFebruary 17, 2022
Darrel T. Anderson
/s/ Odette C. BolanoDirectorFebruary 17, 202215, 2024
Odette C. Bolano
/s/ Thomas CarlileDirectorFebruary 17, 2022
Thomas Carlile
/s/ Annette G. ElgDirectorFebruary 17, 202215, 2024
Annette G. Elg
/s/ Ronald W. Jibson DirectorFebruary 17, 202215, 2024
Ronald W. Jibson   
/s/ Judith A. Johansen DirectorFebruary 17, 202215, 2024
Judith A. Johansen   
/s/ Dennis L. Johnson DirectorFebruary 17, 202215, 2024
Dennis L. Johnson   
/s/ Nate R. Jorgensen DirectorFebruary 15, 2024
Nate R. Jorgensen
/s/ Jeff C. KinneeveaukDirectorFebruary 15, 2024
Jeff C. Kinneeveauk   
/s/ Susan D. MorrisDirectorFebruary 15, 2024
Susan D. Morris
/s/ Richard J. Navarro DirectorFebruary 17, 202215, 2024
Richard J. Navarro   
/s/ Dr. Mark T. PetersDirectorFebruary 17, 202215, 2024
Dr. Mark T. Peters
153147
Table of Contents                              
SIGNATURES

Pursuant to the requirements of Section 13 andor 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
 
February 17, 202215, 2024 Idaho Power Company
Date  
  By:/s/ Lisa A. Grow
    Lisa A. Grow
    President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
SignatureTitleDate
/s/ Richard J. DahlChairmanChair of the BoardFebruary 17, 202215, 2024
Richard J. Dahl
/s/ Lisa A. Grow(Principal Executive Officer)February 17, 202215, 2024
Lisa A. Grow
President and Chief Executive Officer and Director
/s/ StevenBrian R. KeenBuckham(Principal Financial Officer)February 17, 202215, 2024
StevenBrian R. KeenBuckham
Senior Vice President, and Chief Financial Officer, and Treasurer
/s/ Kenneth W. PetersenAmy I. Shaw(Principal Accounting Officer)February 17, 202215, 2024
Kenneth W. PetersenAmy I. Shaw
Vice President Chief Accounting Officerof Finance, Compliance, and TreasurerRisk
/s/ Darrel T. AndersonDirectorFebruary 17, 2022
Darrel T. Anderson
/s/ Odette C. BolanoDirectorFebruary 17, 202215, 2024
Odette C. Bolano
/s/ Thomas CarlileDirectorFebruary 17, 2022
Thomas Carlile
/s/ Annette G. ElgDirectorFebruary 17, 202215, 2024
Annette G. Elg
/s/ Ronald W. JibsonDirectorFebruary 17, 202215, 2024
Ronald W. Jibson
/s/ Judith A. JohansenDirectorFebruary 17, 202215, 2024
Judith A. Johansen
/s/ Dennis L. JohnsonDirectorFebruary 17, 202215, 2024
Dennis L. Johnson
/s/ Nate R. JorgensenDirectorFebruary 15, 2024
Nate R. Jorgensen
/s/ Jeff C. KinneeveaukDirectorFebruary 15, 2024
Jeff C. Kinneeveauk
/s/ Susan D. MorrisDirectorFebruary 15, 2024
Susan D. Morris
/s/ Richard J. NavarroDirectorFebruary 17, 202215, 2024
Richard J. Navarro
/s/ Dr. Mark T. PetersDirectorFebruary 17, 202215, 2024
Dr. Mark T. Peters
154148