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


X☒ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended
December 31, 20182021
 
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
Exact name of registrants as specified inIRS Employer
Commission
File Number		their charters, address of principal executiveIRS Employer
File Number
offices, zip code and telephone number		Identification Number
1-14465IDACORP, Inc.82-0505802
1-3198Idaho Power Company82-0130980
1221 W. Idaho Street
Boise, ID 83702-5627ID83702-5627
(208) 388-2200388-2200
State of incorporation:Idaho
Securities registered pursuant to Section 12(b) of the Securities Exchange Act of 1934
Title of each classTrading Symbol(s)Name of each exchange on which registered
Name of exchange on
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:which registered
IDACORP, Inc.: Common Stock, without par valueIDANew York Stock Exchange

Securities registered pursuant to Section 12(g) of the Securities Exchange Act of 1934
Stock Exchange
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
Idaho Power Company:Preferred Stock

Indicate by check mark whether the registrants are well-known seasoned issuers, as defined in Rule 405 of the Securities Act.
IDACORP, Inc.Yes(X)☒No( )☐Idaho Power CompanyYes( )☐No(X)☒
 
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(X)☒Idaho Power CompanyYes( )☐No(X)☒
 
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  (  )
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Indicate by check mark whether the registrants have submitted electronically 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(X)☒No( )☐Idaho Power CompanyYes(X)☒No( )☐
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter)
is not contained herein, and will not be contained, to the best of registrants’ knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  (X)
 
Indicate by check mark whether the registrants are large accelerated filers, accelerated filers, non-accelerated filers, smaller reporting companies, or emerging growth companies. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.


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


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


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. __


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☐

Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Act).
IDACORP, Inc.Yes( )☐No(X)☒Idaho Power CompanyYes( )☐No(X)☒
 
Aggregate market value of voting and non-voting common stock held by non-affiliates (June 30, 2018)2021):
IDACORP, Inc.: $4,611,144,658
 Idaho Power Company: None
IDACORP, Inc.:$4,876,126,808 Idaho Power Company:None
Number of shares of common stock outstanding as of February 15, 2019:11, 2022:
IDACORP, Inc.:50,383,36650,523,810
Idaho 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 20192022 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.
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TABLE OF CONTENTS
TABLE OF CONTENTSPage
Page
Commonly Used Terms
4
Cautionary Note Regarding Forward-Looking Statements
5
Part I
Item 1Business
7
Information about our Executive Officers of the Registrants
1820
Item 1ARisk Factors
1922
Item 1BUnresolved Staff Comments
3036
Item 2Properties
3036
Item 3Legal Proceedings
3237
Item 4Mine Safety Disclosures
3237
Part II
Item 5Market for Registrant's Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities
3338
Item 6Selected Financial DataReserved
34
Item 7Management's Discussion and Analysis of Financial Condition and Results of Operations
3539
Item 7AQuantitative and Qualitative Disclosures About Market Risk
7479
Item 8Financial Statements and Supplementary Data
7681
Item 9Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
133137
Item 9AControls and Procedures
133137
Item 9BOther Information
137141
Item 9CDisclosure Regarding Foreign Jurisdiction that Prevent Inspections
141
Part III
Part III
Item 10Directors, Executive Officers and Corporate Governance*
137141
Item 11Executive Compensation*
137141
Item 12Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters*
137141
Item 13Certain Relationships and Related Transactions, and Director Independence*
138142
Item 14Principal Accountant Fees and Services*
138142
Part IV
Item 15Exhibits and Financial Statement Schedules
139143
Item 16Form 10-K Summary
150152
Signatures
150153
* 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 20192022 annual meeting of shareholders.


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COMMONLY USED TERMS
The following select abbreviations, terms, or acronyms are commonly used or found in multiple locations in this report:
ADITC2021 Annual Report-IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2021kWh-Kilowatt-hour
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
APCU-Annual Power Cost UpdateMMBtu-Million British Thermal Units
ASUBCC-Accounting Standards UpdateMW-Megawatt
BCC-Bridger Coal Company, a joint venture of IERCoMWhMW-Megawatt-hourMegawatt
BLM-U.S. Bureau of Land ManagementNAAQSMWh-Megawatt-hour
CAA-Clean Air ActNAAQS-National Ambient Air Quality Standards
CAA
CO2
-Clean Air ActCarbon DioxideNEPA-National Environmental Policy Act
CO2
CWA		-Carbon DioxideClean Water ActNMFS-National Marine Fisheries Service
CWAEIS-Clean Water ActEnvironmental Impact StatementNOAA Fisheries-National Oceanic and Atmospheric Administration's National Marine Fisheries Service
EISEPA-Environmental Impact Statement
NO2
-Nitrogen Dioxide
EPA-U.S. Environmental Protection Agency
NOx2
-Nitrogen OxideDioxide
ESA-Endangered Species ActO&M
NOx
-Operations and MaintenanceNitrogen Oxide
FASB-Financial Accounting Standards BoardOATTO&M-Operations and Maintenance
FCA-Idaho Fixed Cost AdjustmentOATT-Open Access Transmission Tariff
FCAFERC-Idaho Fixed Cost AdjustmentFederal Energy Regulatory CommissionOPUC-Public Utility Commission of Oregon
FERCFPA-Federal Energy Regulatory CommissionPower ActPCA-Idaho-jurisdiction Power Cost Adjustment
FPAGAAP-Federal Power ActGenerally Accepted Accounting PrinciplesPCAM-Oregon Power Cost Adjustment Mechanism
GAAPGHG-Generally Accepted Accounting PrinciplesPEIS-Programmatic Environmental Impact Statement
GHG-Greenhouse GasPURPA-Public Utility Regulatory Policies Act of 1978
HCC-Hells Canyon ComplexREC-Renewable Energy Certificate
IDACORP-IDACORP, Inc., an Idaho CorporationRH BART-Regional haze - best available retrofit technology
Idaho Power-Idaho Power Company, an Idaho CorporationRPS-Renewable Portfolio Standard
Idaho ROE-Idaho-jurisdiction return on year-end equitySEC-U.S. Securities and Exchange Commission
Ida-West-Ida-West Energy Company, a subsidiary of IDACORP, Inc.SCRSMSP-Selective catalytic reduction equipmentSecurity Plan for Senior Management Employees
IERCo-Idaho Energy Resources Co., a subsidiary of Idaho Power CompanySMSP
SO2
-Security Plan for Senior Management EmployeesSulfur Dioxide
IFS-IDACORP Financial Services, Inc., a subsidiary of IDACORP, Inc.
SO2
USACE		-Sulfur DioxideU.S. Army Corps of Engineers
IPUC-Idaho Public Utilities CommissionUSFWS-U.S. Fish and Wildlife Service
IRP-Integrated Resource PlanValmy Plant-North Valmy coal-fired power plant
IRS-U.S. Internal Revenue ServiceWestern EIM-
Energy imbalance market implemented in the western United States

kWIRS-KilowattU.S. Internal Revenue ServiceWPSCWDEQ-Wyoming Public Service Commission
kWh-Kilowatt-hourWDEQ-Wyoming Department of Environmental Quality
Jim Bridger plant-Jim Bridger generating plantWPSC-Wyoming Public Service Commission
kW-Kilowatt

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS


In addition to the historical information contained in this report, this report contains (and oral communications made by IDACORP, Inc. (IDACORP) and Idaho Power Company (Idaho Power) may contain) statements that relate to future events and expectations, such as statements regarding projected or future financial performance, cash flows, capital expenditures, dividends, capital structure or ratios, strategic goals, challenges, objectives, and plans for future operations. Such statements constitute forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Any statements that express, or involve discussions as to, expectations, beliefs, plans, objectives, assumptions, future events, or performance, often, but not always, through the use of words or phrases such as "anticipates," "believes," "continues," "could," "estimates," "expects," "guidance," "intends," "potential," "plans," "predicts," "projects," "may result," "may continue," or similar expressions, are not statements of historical facts and may be forward-looking. Forward-looking statements are not guarantees of future performance and involve estimates, assumptions, risks, and uncertainties. Actual results, performance, or outcomes may differ materially from the results discussed in the statements. In addition to any assumptions and other factors and matters referred to specifically in connection with such forward-looking statements, factors that could cause actual results or outcomes to differ materially from those contained in forward-looking statements include those factors set forth in Part I, Item 1A - “Risk Factors” and Part II, Item 7 - “Management’s Discussion and Analysis of Financial Condition and Results of Operations" of this report, as well as in subsequent reports filed by IDACORP and Idaho Power with the U.S. Securities and Exchange Commission, and the following important factors:
•the effect of decisions by the Idaho and Oregon public utilities commissions and the Federal Energy Regulatory Commission that impact Idaho Power's ability to recover costs and earn a return on investment;
•changes to or the expenseelimination of Idaho Power's regulatory cost recovery mechanisms;
•the ongoing impacts of COVID-19 and risks associated with capital expenditures for utility infrastructure,its variants, and government mandates related to COVID-19 vaccines, masking, and testing, on the global and regional economy and on Idaho Power’s employees, customers, contractors, and suppliers, including on loads and revenues, uncollectible accounts, transmission revenues, supply chain availability, attrition of skilled workers, and other aspects of the economy and the timing and availability of cost recovery for such expenditures through customer rates, including the potential for the write-down or write-off of expenditures if not deemed prudent by regulators;companies’ business;
•changes in residential, commercial, and industrial growth and demographic patterns within Idaho Power'sPower’s service area, the loss or change in the business of significant customers, or the addition of new customers, and their associated impacts on loads and load growth, and the availability of regulatory mechanisms that allow for timely cost recovery through customer rates in the event of those changes;
•abnormal or severe weather conditions (including conditions and events associated with climate change), wildfires, droughts, earthquakes, and other natural phenomena and natural disasters, which affect customer sales, hydropower generation levels, repair costs, service interruptions, liability for damage caused by utility property, and the availability and cost of fuel for generation plants or purchased power to serve customers;
•advancement of self-generation, energy storage, energy efficiency, alternative energy sources, and other technologies that may reduce Idaho Power’s sale or delivery of electric power or introduction of operational or cyber-security vulnerabilities to the power grid;
•acts or threats of terrorist incidents, acts of war, social unrest, cyber or physical security attacks, and other malicious acts of individuals or groups seeking to disrupt Idaho Power's operations or the electric power grid or compromise data, or the disruption or damage to the companies’ business, operations, or reputation resulting from such events;
•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
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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 challenges associated with purchasing and integrating intermittent renewable energy sources into Idaho Power’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 operational and financial costs of unionization or the attempt to unionize all or part of the companies’ workforce, the impact of an aging workforce and retirements, the cost and ability to attract and retain skilled workers and third-party vendors, 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;
•changes in tax laws or related regulations or interpretations of applicable laws by federal, state, or local taxing jurisdictions, and the availability of tax credits, and the tax rates payable by IDACORP shareholders on common stock dividends;
•adoption of, changes in, and costs of compliance with, laws, regulations, and policies relating to the environment, climate change, natural resources, and threatened and endangered species, and the ability to recover associated increased costs through rates;
•the inability to timely obtain 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, regulatory authorized returns on equity, supply costs, population growth or decline in Idaho Power'sPower’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;
unseasonable or severe weather conditions, wildfires, drought, and other natural phenomena and natural disasters, including conditions and events associated with climate change, which affect customer demand, hydroelectric generation levels, repair costs, liability for damage caused by utility property, and the availability and cost of fuel for generation plants or purchased power to serve customers;
advancement of self-generation, energy storage, and energy efficiency technologies that may affect Idaho Power's sale or delivery of electric power or introduce new cyber security risks;
changes in tax laws or related regulations or new interpretations of applicable laws by federal, state, or local taxing jurisdictions, the availability of tax credits, and the tax rates payable by IDACORP shareholders on common stock dividends;
adoption of, changes in, and costs of compliance with laws, regulations, and policies relating to the environment, natural resources, and threatened and endangered species, and the ability to recover associated increased costs through rates;
variable hydrological conditions and over-appropriation of surface and groundwater in the Snake River Basin, which may impact the amount of power generated by Idaho Power's hydroelectric facilities;
the ability to acquire fuel, power, and transmission capacity under reasonable terms, particularly in the event of unanticipated power demands, lack of physical availability, transportation constraints, or a credit downgrade;
accidents, fires (either affecting or caused by Idaho Power facilities or infrastructure), explosions, and mechanical breakdowns that may occur while operating and maintaining Idaho Power assets, which can cause unplanned outages, reduce generating output, damage the companies’ assets, operations, or reputation, subject the companies to third-party claims for property damage, personal injury, or loss of life, or result in the imposition of civil, criminal, and regulatory fines and penalties for which the companies may have inadequate insurance coverage;
the increased purchased power costs and operational challenges associated with purchasing and integrating intermittent renewable energy sources into Idaho Power's resource portfolio;
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disruptions or outages of Idaho Power's generation or transmission systems or of any interconnected transmission systems may constrain resources or cause Idaho Power to incur repair costs and purchase replacement power at increased costs;
•the ability to obtain debt and equity financing or refinance existing debt when necessary and on favorable terms, which can be affected by factors such as credit ratings, volatility or disruptions in the financial markets, interest rate fluctuations, decisions by the Idaho or Oregon public utility commissions, and the companies'companies’ past or projected financial performance;
reductions in credit ratings, which could adversely impact access to debt and equity markets, increase borrowing costs, and require the posting of additional collateral to counterparties pursuant to credit and contractual arrangements;
•the ability to enter into financial and physical commodity hedges with creditworthy counterparties to manage price and commodity risk for fuel, power, and transmission, and the failure of any such risk management and hedging strategies to work as intended;
•changes in actuarial assumptions, changes in interest rates, increasing health care costs, and the actual and projected return on plan assets for pension and other post-retirement plans, which can affect future pension and other postretirement plan funding obligations, costs, and liabilities and the companies'companies’ cash flows;
•the assumptions underlying the coal mine reclamation obligations at Bridger Coal Company and related funding and bonding requirements, and the remediation costs associated with planned exits from participation in Idaho Power’s co-owned coal plants;
•the ability to continue to pay dividends and achieve target-payout ratios based on financial performance, and in light of credit rating considerations, contractual covenants and restrictions, and regulatory limitations; and
employee workforce factors, including the operational and financial costs of unionization or the attempt to unionize all or part of the companies' workforce, the impact of an aging workforce and retirements, the cost and ability to attract and retain skilled workers, and the ability to adjust the labor cost structure when necessary;
failure to comply with state and federal laws, regulations, and orders, including new interpretations and enforcement initiatives by regulatory and oversight bodies, which may result in penalties and fines and increase the cost of compliance, the nature and extent of investigations and audits, and the cost of remediation;
the inability to obtain or cost of obtaining and complying with required governmental permits and approvals, licenses, rights-of-way, and siting for transmission and generation projects and hydroelectric facilities;
the cost and outcome of litigation, dispute resolution, and regulatory proceedings, and the ability to recover those costs or the costs of resulting operational changes through insurance or rates, or from third parties;
the companies' failure to secure data or to comply with privacy laws or regulations, security breaches, or the disruption or damage to the companies' business, operations, or reputation resulting from cyber-attacks and related litigation or penalties, terrorist incidents or the threat of terrorist incidents, or other malicious acts, and acts of war;
unusual or unanticipated changes in normal business operations, including unusual maintenance or repairs, or the failure to successfully implement new technology solutions; and
•adoption of or changes in accounting policies and principles, changes in accounting estimates, and new U.S. Securities and Exchange Commission or New York Stock Exchange requirements, or new interpretations of existing requirements.

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

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PART I
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). IDACORP is subject to the provisions of the Public Utility Holding Company Act of 2005, which provides the Federal Energy Regulatory Commission (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), a joint venturer in Bridger Coal Company (BCC), which mines and supplies coal to the Jim Bridger generating plant (Jim Bridger plant) owned in part by Idaho Power. Idaho Power's utility operations constitute nearly all of IDACORP's current business operations. As of December 31, 2018, IDACORP had 1,981 full-time employees, 1,972 of whom were employed by Idaho Power, and 9 part-time employees, 7 of whom were employed 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 (Ida-West), an operator of small hydroelectrichydropower generation projects that satisfy the requirements of the Public Utility Regulatory Policies Act of 1978 (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). 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 thisIDACORP's and Idaho Power's Annual Report on Form 10-K.10-K for the year ended December 31, 2021 (2021 Annual Report).
 
UTILITY OPERATIONS


Background
 
Idaho Power provided electric utility service to more than 558,000approximately 604,000 retail customers in southern Idaho and eastern Oregon as of December 31, 2018.2021. Approximately 465,000506,000 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 winter recreation.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 1.21.3 million.


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ida-20211231_g3.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), the Public Utility Commission of Oregon (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) as to the issuance of debt and equity securities. As a public utility under the Federal Power Act (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). Additionally, the FERC has jurisdiction over Idaho Power's sales of transmission capacity and wholesale electricity, hydroelectrichydropower project relicensing, and system reliability, among other items.


Regulatory Accounting


Idaho Power is subject tomeets 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. 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, 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 taxestax 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. Regulated enterprises are required to recognize thoseIdaho 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.


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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 IDACORP’sits 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: growing financial strength, improving Idaho Power's core business, enhancing Idaho Power’s brand, and keeping employees safe and engaged. IDACORP's board of directors regularly reviews IDACORP'shas reviewed and affirmed IDACORP’s long-term strategy, which as of the date of this report is focused on the following areas and initiatives:
Focus AreasInitiatives
Grow to Enhance Financial Strength
- Execute on Business Development Initiatives
- Find New Revenue Opportunities
- Promote and Engage in Beneficial Electrification
Improve the Core Business
- Implement/Utilize Value-Added Analytics and Machine Learning
- Upgrade Infrastructure for Growth, Technology Changes, Renewable Energy Integration, and Flexibility
- Evaluate and Control Expenditures and Continue Efficient Operations
- Use Technology to Enhance the Grid, System Reliability, and Safety
- Implement Rate Structures that are Fair and Reasonable to All Customers
- Leverage Technology and Turn Disruptive Threats into Opportunities
Enhance Idaho Power's Brand
- Enhance Idaho Power's Customers' Experience and Interactions
- Continue Environmental Stewardship and Emission Reductions
- Continue Constructive Regulatory Relationships and a Regulatory Compliance Mindset
- Communicate Idaho Power's Story
Focus on Safety & Employee Engagement
- Continue Idaho Power's Strong Focus on Safety and Reducing Injuries
- Execute on Employee Engagement and Leadership Development Initiatives
strategy. In executing the focus areas above,on these four strategic cornerstones, IDACORP seeks to balance the interests of shareholders,shareowners, Idaho Power customers, employees, and other stakeholders. Idaho Power is committed to working to continuefor strong, sustainable financial results by continuing to provide safe, fair-priced, reliable, serviceaffordable, clean energy to its customers from diversified generation resources, with a continued commitment to strong, sustainable financial results and strong credit ratings.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, see the “Regulatory Matters” section of Part II, Item 7 – “Management’s Discussion and Analysis of Financial Condition and Results of Operations” (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. Idaho Power regularly evaluates the need to request changes to its retail electricity price structure to cover its operating costs and to earn a fair return on its investments. Idaho Power uses general rate cases, power cost adjustment mechanisms in Idaho and Oregon, a fixed cost adjustment (FCA) mechanism in Idaho, balancing accounts and 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, 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 aswhen the costs are incurred.

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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 recordeddeferred or accrued under specific authorization from the IPUC or OPUC but deferred for recovery or accrued for refund.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. Idaho Power collects most of its energy efficiency program costs through energy efficiency ridersFor more information on customer bills. The Idahothese mechanisms, see Note 3 – “Regulatory Matters” and Oregon power cost adjustment mechanisms are intended to address the volatility of power supply costs and provide for annual adjustmentsNote 4 - “Revenues” to the rates charged to retail customers by allowing partial recovery or refund of the difference between net power supply costsconsolidated financial statements included in base rates and actual net power supply costs incurred by Idaho Power. 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 charge and linking it instead to a set amount per customer. Under Idaho Power's current rate design, recovery of a portion of fixed costs is included in the variable kilowatt-hour charge, which may result in overcollection or undercollection of fixed costs. To return overcollection to customers or to collect undercollection from customers, the FCA mechanism allows Idaho Power to accrue, or defer, the difference between the authorized fixed-cost recovery amount per customer and the actual fixed costs per customer recovered by Idaho Power during the year. Increases in FCA recovery are capped at 3 percent of base revenue annually, with any excess deferred for collection in a subsequent year.this report


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 a risk management policy 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 hydroelectric generation facilities are operated to optimize the water that is available by choosing when to run hydroelectric 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 river 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’s 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 and reliability standards.
Retail Energy Sales:Weather, seasonal customer demand, energy efficiency, customer generation, 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. Increased precipitation levelsAvailability of water and extreme temperatures during the agricultural growing season reduceimpact 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.”


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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,
 202120202019
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 
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 
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 revenues64,319 51,884 47,175 
Total electric utility operating revenues$1,455,410 $1,347,340 $1,342,940 
Energy sales (thousands of Megawatt-hour (MWh)):   
Residential5,645 5,463 5,273 
Commercial4,164 4,009 4,092 
Industrial3,471 3,369 3,412 
Irrigation2,126 1,987 1,760 
Total retail energy sales15,406 14,828 14,537 
Wholesale energy sales600 1,197 2,171 
Energy sales bundled with renewable energy credits739 690 680 
Total 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) on construction work in progress related to the Hells Canyon Complex (HCC) relicensing process, even though the relicensing process is not yet complete and the costs have not been moved to electric plant in service. Idaho Power is collecting $8.8 million annually in the Idaho jurisdiction but is deferring revenue recognition of the amounts collected until the license is issued and the accumulated license costs approved for recovery are placed in service.

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 policy 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 and reliability standards.
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  Year Ended December 31,
  2018 2017 2016
Retail revenues (thousands of dollars):  
  
  
Residential (includes $34,625, $17,320, and $29,170, respectively, related to the FCA(1))
 $530,527
 $552,333
 $514,954
Commercial (includes $1,299, $876, and $1,087, respectively, related to the FCA(1))
 310,299
 319,195
 302,650
Industrial 190,130
 195,124
 182,590
Irrigation 158,001
 150,030
 156,505
Provision for sharing (5,025) —
 —
Deferred revenue related to HCC relicensing AFUDC(2)
 (8,780) (10,706) (10,706)
Total retail revenues 1,175,152
 1,205,976
 1,145,993
Wholesale energy sales 52,845
 24,790
 11,900
Transmission wheeling revenues 59,094
 43,970
 32,496
Energy efficiency program revenues 35,703
 39,241
 33,754
Other revenues 43,788
 30,916
 35,210
Total electric utility operating revenues $1,366,582
 $1,344,893
 $1,259,353
Energy sales (thousands of Megawatt-hour (MWh)):  
  
  
Residential 5,135
 5,355
 5,004
Commercial 4,105
 4,099
 3,999
Industrial 3,371
 3,346
 3,243
Irrigation 1,976
 1,771
 1,950
Total retail energy sales 14,587
 14,571
 14,196
Wholesale energy sales 2,246
 1,934
 742
Bundled energy sales 617
 202
 444
Total energy 17,450
 16,707
 15,382
 
(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)
As part of its January 30, 2009, general rate case order, the IPUC is allowing Idaho Power to recover a portion of the allowance for funds used during construction (AFUDC) on construction work in progress related to the Hells Canyon Complex (HCC) relicensing process, even though the relicensing process is not yet complete and the costs have not been moved to electric plant in service. Idaho Power is collecting $8.8 million annually in the Idaho jurisdiction but is deferring revenue recognition of the amounts collected until the license is issued and the accumulated license costs approved for recovery are placed in service. Prior to the May 2018 Idaho Tax Reform Settlement Stipulation, described in Note 3 – “Regulatory Matters” to the consolidated financial statements included in this report, Idaho Power was collecting $10.7 million annually.

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.


Idaho Power also participates in the wholesale energy markets and in the electric 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, 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.

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Power Supply
 
Overview: Idaho Power primarily relies on company-owned hydroelectric,hydropower, coal-fired, and gas-fired generation facilities and long-term power purchase agreements to supply the energy needed to serve customers.customers, and for 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.”
 
Weather,Various external and internal factors impact power supply costs; such as, weather, load demand, supply constraints, economic conditions, fuel costs, and availability of generation resources impact power supply costs.resources. Idaho Power’s annual hydroelectrichydropower 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 hydroelectrichydropower generation conditions increase production at Idaho Power’s hydroelectrichydropower generating facilities and reduce the need for thermal generation and wholesale market purchased power. Economic conditions, weather, supply constraints, and governmental regulations can affect the market price of natural gas and coal, which may impact fuel expense and market prices for purchased power. Idaho Power's power cost adjustment mechanisms mitigate in large part the financial 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 3,4223,751 megawatts (MW) on July 7, 2017.June 30, 2021. Idaho Power's highest all-time winter peak demand of 2,527 MW was last achieved on January 6, 2017. During these and other similarly 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 Supply Percent of Total Generation 202120202019202120202019
 2018 2017 2016 2018 2017 2016 (thousands of MWh) 
 (thousands of MWh)   
Hydroelectric plants 8,682
 8,900
 6,408
 65% 65% 53%
Hydropower plantsHydropower plants5,382 6,967 8,294 48 %54 %62 %
Coal-fired plants 3,274
 3,284
 4,045
 24% 24% 33%Coal-fired plants2,981 3,719 3,012 27 %29 %22 %
Natural gas-fired plants 1,408
 1,504
 1,722
 11% 11% 14%Natural gas-fired plants2,765 2,109 2,114 25 %17 %16 %
Total system generation 13,364
 13,688
 12,175
 100% 100% 100%Total system generation11,128 12,795 13,420 100 %100 %100 %
  
  
  
  
  
  
      
Purchased power - cogeneration and small power production 3,045
 2,800
 2,314
  
  
  
Purchased power - cogeneration and small power production3,040 3,087 2,983    
Purchased power - other 2,386
 1,442
 2,023
  
  
  
Purchased power - other3,783 1,985 2,217    
Total purchased power 5,431
 4,242
 4,337
  
  
  
Total purchased power6,823 5,072 5,200    
Total power supply 18,795
 17,930
 16,512
  
  
  
Total power supply17,951 17,867 18,620    
 
Hydroelectric
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Hydropower Generation: Idaho Power operates 17 hydroelectrichydropower projects located on the Snake River and its tributaries. Together, these hydroelectrichydropower facilities provide a total nameplate capacity of 1,7751,799 MW and have averaged total annual generation of approximately 8.77.7 million MWh under median water conditions.over the last 30 years. The amount of water available for hydroelectric powerhydropower generation depends on several factors—the amount of snowpack in the mountains upstream of Idaho Power’s hydroelectrichydropower 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, summer timesummertime 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 hydroelectrichydropower projects on the Snake River.


In 2018,2021, below-normal snow accumulation and drought conditions resulted in lower than average hydropower generation of 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 to Idaho Power’s hydroelectric projects and resulted in 7.0 million MWh of hydropower generation in 2020. In 2019, above-normal reservoir storage carryover from the previous year coupled with near-normal winter snowpack resulted in 8.78.3 million MWh of hydroelectrichydropower generation. In 2017, above normal winter and spring precipitation resulted in 8.9 million MWh of hydroelectric generation. In 2016, low upstream reservoir carryover (primarily in the upper Snake River basin) resulted in reduced downstream flow releases. Additionally, although snowpack accumulation was near-normal on April 1, 2016, the snowpack melted earlier than usual. The combined effect was lower than median hydro production of 6.4 million MWh in 2016. During low water years, when stream flows into Idaho Power’s hydroelectrichydropower projects are reduced, Idaho Power’s hydroelectrichydropower generation is reduced, resulting in a greater reliance on other generation resources and wholesale power purchases. For 2019,2022, Idaho Power estimates annual generation from its hydroelectrichydropower facilities towill be between 6.55.5 million MWh and 8.57.5 million MWh.
 
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Idaho Power obtains licenses for its hydroelectrichydropower projects from the FERC, similar to other utilities that operate nonfederal hydroelectrichydropower 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 hydroelectrichydropower generation source.source, and American Falls, its second largest hydropower resource. Idaho Power also has three Oregon licenses for the HCC under the Oregon Hydroelectric Act, which applies to Idaho Power’s Brownlee, Oxbow, and Hells Canyon facilities.Act. For further information on relicensing activities, see Part II, Item 7 – MD&A – "Regulatory Matters – Relicensing of HydroelectricHydropower Projects.”


Idaho Power is subject to the provisions of the FPA as a “public utility” and as a “licensee” by virtue of its hydroelectrichydropower operations. As a licensee under Part I of the FPA, Idaho Power and its licensed hydroelectrichydropower 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:plants in operation:


•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; andinterest.
Boardman, located in Oregon, in which Idaho Power has a 10 percent interest.


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 from surface and underground sources.2024. Idaho Power believes that BCC has sufficient reserves to provide coal deliveries for at least the term of the sales agreement. Idaho Power also has a coal supply contract providing for annual deliveries of coal through 2021April 2022 from the Black Butte mine located near 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 units at the Jim Bridger plant 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. 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."

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NV Energy is the operator of the North Valmy power plant (Valmy Plant).plant. Idaho Power expects to meet 20192022 and future fuel requirements through existing inventory and coal contracts and expects to be able to meet future coal requirements through new or existing coal supply contracts. In 2017 and 2018, Idaho Power has an established a 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 unitsplant. Idaho Power ended its participation in unit 1 of the North Valmy plant in December 2019, as planned, and plans to end its participation in unit 2 in 2019no later than the end of 2025.

In October 2020, Idaho Power and 2025, respectively. In 2018, the Valmy Plant provided 5 percent of Idaho Power's total generation, compared with 2 percent of Idaho Power's total generation in both 2017 and 2016.

co-owner Portland General Electric Company is the operator of the Boardman power plant. Idaho Power believes that it has sufficient inventory and coal contracts to supply the Boardman plant with fuel through 2019. The Boardman plant receives coal through annual contracts with suppliers from the Powder River Basin in northeast Wyoming. Idaho Power expects to meet future coal needs through similar contracts. In December 2010, the Oregon Environmental Quality Commission approved a plan to ceaseceased coal-fired operations at thetheir Boardman power plant, no later than December 31, 2020.as planned.


Natural Gas-fired Generation: Idaho Power owns and operates the Langley Gulch natural gas-fired combined cyclecombined-cycle combustion turbine power plant and the Danskin and Bennett Mountain natural gas-fired simple cyclesimple-cycle combustion turbine power plants. All three plants are located in Idaho.


Idaho Power operates the Langley Gulch plant as a baseload unit and the Danskin and Bennett Mountain plants to 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. 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 Power has entered into a long-term storage service agreement with Northwest Pipeline for 131,453 MMBtu of total storage capacity at the Jackson Prairie Storage Project. This firm storage contract expires in 2043. Idaho Power purchases and stores natural gas with the intent of fulfilling needs as identified for seasonal peaks or to meet system requirements.
 
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As of December 31, 2018,2021, Idaho Power had approximately 6.410.6 million MMBtu of natural gas was financially hedged for physical delivery, primarily for the operational dispatch of the Langley Gulch plant through January 2020.February 2023. 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 power pursuant to long-term power purchase contracts and exchange agreements.


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 policy requirements,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 20182021 and 2017,2020, Idaho Power purchased 3.2 million MWh and 1.4 million MWh, and 0.9 million MWhrespectively, of power through wholesale market purchases at an average cost of $31.55$40.65 per MWh and $26.32$27.91 per MWh, respectively. During 20182021 and 2017,2020, Idaho Power sold 2.20.6 million MWh and 1.91.2 million MWh of power in wholesale market sales, respectively, with an average price of $23.53$68.07 per MWh and $12.82$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 the following notable long-term power purchase 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 hydroelectrichydropower 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 2020. Idaho Power has the right to renew the agreement for an additional five-year term.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.
 
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PURPA Qualifying Facility Energy Sales Agreements: Idaho Power purchases power from PURPA qualifying facilities as mandated by federal law. As of December 31, 2018,2021, Idaho Power had contracts with on-line PURPA qualifying facilities with a total of 1,1191,137 MW of nameplate generation capacity, with an additional 2975 MW nameplate capacity of projects projected to be on-line in 2019.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 
  Year Ended December 31,
  2018 2017 2016
PURPA contracts expense (in thousands) $189,722
 $169,788
 $153,665
MWh purchased under PURPA contracts (in thousands) 3,045
 2,800
 2,314
Average cost per MWh from PURPA contracts $62.31
 $60.64
 $66.41


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 of 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 in 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, located inside its service area, subject to some exceptions such as adverse impacts on system reliability.
Idaho Power is required to purchase the output of projects located outside its service area if it has the ability to receive power at the qualifying facility’s requested point of delivery on Idaho Power's system.
•The IPUCIdaho jurisdictional portion of the costs associated with PURPA contracts is fully recovered through base rates and the Idaho-jurisdiction power cost adjustment (PCA) mechanism, and the OPUCOregon jurisdictional portion is recovered through base rates and an Oregon power cost recoveryadjustment mechanism. Thus, the primary impact of high power purchase costs under PURPA contracts is on customer rates.
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OPUC•Oregon jurisdictional regulations have generally provided for PURPA standard contract terms of up to 20 years.
•The IPUC requires Idaho Power to pay "published avoided cost" rates for all wind, solar, and solarenergy 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, Idaho Power is required to negotiate an applicable price (premisedusing an avoided cost methodology based on avoided costs) based upon IPUC regulations.
•The IPUC issued an order 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 that Idaho Power pay the published avoided costs for solar PURPA qualifying facilities with a nameplate rating of 3 MW or less and all other types of projects with a nameplate rating of 10 MW or less. Idaho Power is required to negotiate an applicable price (premisedusing an avoided cost methodology based on avoided costs) for all other qualifying facilities based upon OPUC regulations.


Participation in Western Energy Imbalance Market: In 2014, the California Independent System Operator and PacifiCorp implementedIdaho Power participates in an energy imbalance market in the western United States (Western EIM) under which the participating parties enabledenable 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. Participation in the Western EIM is voluntary and available to all balancing authorities in the western United States. Idaho Power commenced participation in the Western EIM in April 2018. For information on regulatory proceedings related to costs associated with joining the Western EIM, see Part II, Item 7 – MD&A - "Regulatory Matters - Western Energy Imbalance Market Costs."
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, 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 Northwest PowerPool, the Northern Tier Transmission Group,Power Pool, NorthernGrid, and the North American
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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 making purposes. Idaho Power provides cost-based wholesale and retail access transmission services under the terms of a FERC approved OATT. Services under the OATT are offered on a nondiscriminatory 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.


Idaho Power is jointly working with various partners on the permitting of two significant transmission projects. The Boardman-to-Hemingway lineproject is a proposed 300-mile, 500-kVhigh-voltage transmission projectline between a station near Boardman, Oregon and the Hemingway station near Boise, Idaho. The Gateway West lineproject is a proposed 1,000-mile, 500-kVhigh-voltage transmission projectline between a station located near Douglas, Wyoming and the Hemingway station. 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). Idaho Power filed its most recent IRP with the IPUC and OPUC in June 2017.2021 (2021 IRP). The IRP seeks to forecast Idaho Power's loads and resources for a 20-year period, analyzes potential supply-side, demand-side, and demand-sidetransmission resource options, and identifies potential near-term, mid-term, and long-term actions. The four primary goals of the IRP are to: 


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•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, andwhile including environmental concerns;considerations;
•give equal and balanced treatment to both supply-side resources 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.


In 2018, Idaho Power began preparing its 2019 IRP. The load forecast assumptions Idaho Power expects to useused in its 20192021 IRP are included in the table below, together with the average annual growth rate assumptions used in the prior two IRPs. 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 Forecast 20-Year Forecast
  
Annual Growth Rate: Retail Sales
(Billed MWh)
Annual Growth Rate: Annual Peak
(Peak Demand)
 
Annual Growth Rate: Retail Sales
(Billed MWh)
Annual Growth Rate: Annual Peak
(Peak Demand)
2019 IRP (preliminary) 1.3%1.4% 1.0%1.2%
2017 IRP 1.1%1.6% 0.9%1.4%
2015 IRP 1.1%1.5% 1.1%1.4%


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)
2021 IRP2.6%2.1%1.4%1.4%
2019 IRP1.3%1.4%1.0%1.2%
2017 IRP1.1%1.6%0.9%1.4%

Idaho Power's 20172021 IRP identifies itsidentified a preferred resource portfolio and action plan. The IRP includesplan, which included the completionaddition of a 120-MW solar resource in late 2022, the Boardman-to-Hemingway 500-kV transmission line by 2026,conversion from coal to natural gas of two units at the Jim Bridger plant in 2024, the end ofto Idaho Power's participation in coal-fired operations at the North Valmy power plant units 1 andunit 2 in 20192025, the completion of the Boardman-to-Hemingway transmission line in 2026, and 2025, respectively, andan end to Idaho Power's participation in the early retirement ofremaining two coal-fired units at the Jim Bridger units 1plant by the end of 2028. The 2021 IRP preferred resource portfolio and 2 in 2032action plan also includes a need to acquire significant generation and 2028, respectively, with no other new resource needs priorstorage resources to 2026. However, asmeet 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 20172021 IRP, there is considerable uncertainty surrounding the resource sufficiency estimates and project completion dates, including uncertainty around the timing and extent of third partythird-party development of renewable resources, fuel commodity prices, regulatory requirements, the actual completion date of the Boardman-to-Hemingway transmission project, and the economics and logistics of coal-fired plant conversions and retirements. These and other uncertainties, couldas well as others, may result in changes to the desirability of the
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preferred portfolio and adjustments to the timing and nature of anticipated and actual actions.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.


Energy Efficiency and Demand Response Programs: Idaho Power’s energy efficiency and demand response portfolio is comprised of 2324 programs. TheseThe 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 customer segments and emphasize the wise use of energy, especially during periods of high demand. This energy and demand reduction can minimizereduce 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
membership•participation in the Northwest Energy Efficiency Alliance, which supports market transformation efforts across the region.


In 2018,2021, Idaho Power’s energy efficiency programs reduced energy usage by approximately 173,000 MWh.138,000 MWh compared with 195,000 MWh in 2020. For 2018,2021, Idaho Power had a demand response available capacity of approximately 382379 MW. In 2018, 2017,2021, 2020, and 2016,2019, Idaho Power expended approximately $44$38 million, $48$51 million, and $43$49 million, respectively, 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
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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, with considerable focus from the corporate governance and nominating committee, are responsible for the oversight of the companies’ environmental, social, and governance (ESG) initiatives and are regularly informed of the goals, measures, and results of theirthe companies' ESG and sustainability programs. Idaho Power has established an internal ESG Steering Committee co-led by two officers and composed of employees from the legal, finance, operations, investor relations, and other departments to oversee ESG activities and inform leadership and the board of directors on ESG related activities and matters it identifies as material to the company's operations.

IDACORP and Idaho Power publicly released their inaugural sustainability report in May 2012 and have issued sustainabilityrelease annual ESG reports annually thereafter. IDACORP’s and Idaho Power’s ESG initiatives include establishing responsible management goals to balance shareholder return and the companies’ impact on the environment (such as the sustainability benefits from the Boardman to Hemingway transmission project, which includes integrating renewable energy generation and deferring the need for development of additional fossil-fueled resources), operational excellence in providing reliable, fair priced, and clean energy, continuing various environmental stewardship programs along the Snake River, engaging and empowering Idaho Power’s workforce (including succession planning at all levels, retirement planning education, and providing competitive pension benefits), promoting a culture of safety and inclusiveness for all employees, and building strong community partnerships for healthy economic development in Idaho Power’s service area, among other things. The most current sustainability report is located on Idaho Power’s website, together with other information on ESG issues relevant to Idaho Power.Power, including short-, medium-, and long-term carbon dioxide (CO2) emission reduction targets that Idaho Power believes are aligned with the Paris Agreement goal of reducing CO2 emissions to net zero by 2050. IDACORP's and Idaho Power's 2021 ESG Report 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, 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 sustainabilityESG reports, CDP filing, and related website content are not incorporated by reference into this 2021 Annual ReportReport. IDACORP’s and Idaho Power’s ESG initiatives include:

•establishing responsible management goals and long-term strategies related to the companies’ impact on Form 10-K.the environment; such as

◦the "Clean Today, Cleaner Tomorrow.®" goal to provide Idaho Power's customers with 100-percent clean energy by 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,
◦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 issued requests for proposals in June
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2021 and December 2021 for additional energy resources, including renewables or natural gas resource convertible to hydrogen gas power,
◦continuing various environmental stewardship programs along the Snake River, including fish habitat preservation, water temperature reduction, and fish and plant restoration,
◦wildfire mitigation planning and actions, and
◦wildlife habitat, archaeological and cultural resource, and raptor protection stewardship;
•operational excellence in 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.

Based on shareholder engagement feedback, in 2021 Idaho Power also publicly released its EEO-1 statement to report its 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 goal to reduce emissions 10-15 percent from the baseline year of 2005 levels. Idaho Power increased the goal to reduce carbon emission intensity by at least 15-20 percent for the period from 2010 to 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 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 establishes short-, medium-, and long-term targets for further CO2 reductions. This report also includes 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. 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 targeted 79 percent reduction in annual CO2 emissions tons by 2030, compared to the 2005 baseline year.

Reduction in Coal-Fired Generation: Idaho Power monitors environmental requirements and assesses whether environmental control measures are or remain economically appropriate. Continued review of the economic appropriateness of further investments in coal-fired plants was included in an IPUC order in February 2014, in which the IPUC requested that Idaho Power continue monitoring environmental requirements at a national level and account for their impact in resource planning and promptly apprise the IPUC of developments that could impact the company's continued reliance on the Valmy Plant as a coal-fired resource. In 2017 and 2018, the IPUC and OPUC approved settlement stipulations allowing accelerated depreciation and cost recovery for the North Valmy Plantplant in connection with Idaho Power's plan to end its participation in the operation of units 1 and 2. Idaho Power ended its participation in the operation of unit 1 at the Valmy Plant byin December 2019, as planned, and plans to end its participation in unit 2 no later than the end of 20192025. In October 2020, Idaho Power and unit 2co-owner Portland General Electric ceased coal-fired operations at their Boardman, as planned.

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 2025. Theend-of-year 2030. In September 2021, the co-owner and operator of the Jim Bridger plant submitted its integrated resource plan to end Idaho Power's participationthe IPUC that contemplates ceasing coal-fired generation in operations of units 1 and 2 at the Valmy Plant was based primarily on the economicsin 2023 and converting those units to natural gas generation by 2024. The status of operating the plant. The settlement stipulations areIdaho Power's application is described more fully in Part II, Item 7 -– MD&A -– "Regulatory Matters” in this report. Additionally, in lightMatters."

As of the uncertainty resulting from pending environmental regulation and the substantial estimated costdate of selective catalytic reduction equipment (SCR) installation,this report, Idaho Power expects to cease participation in operations of all jointly-owned coal-fired generation plants by the end of 2028.

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, enhances grid resiliency and reliability, and continues to assess whether to move forward with the installation of SCR on units 1further Snake River shading and 2 at the Jim Bridger power plant. The table above does not include costs associated with a SCR installation on units 1 and 2 at the Jim Bridger power plant.

Voluntary CO2 Emissions Intensity Reduction Goal:in-stream river enhancement projects. Idaho Power is engaged in voluntary greenhouse gas emissions (GHG)also plans for the social and economic impacts of climate change by furthering its carbon emissions intensity reduction efforts. In 2013, IDACORP'sgoal, continuing efforts to achieve its path away from coal generation, increasing the integration of renewable energy, and Idaho Power's boardsenhancing outage communication efforts.
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Additionally, to reduce the company-owned resource portfolio average carbon dioxide (CO2) emissions intensity to 15-20 percent below 2005 levels of 1,194 lbs CO2/MWhplan for the 2010-2017 cumulative period.potential regulatory impacts of climate change, Idaho Power has achievedemphasizes climate-related impacts in planning efforts, plans and furthered the reduction goal several times, which now extends through 2020.advocates for additional transmission capacity to integrate additional renewable energy onto its system, identifies and investigates new technologies, including battery storage, and evaluates modifications to its pricing structure it believes will help ensure fair pricing for all customers.

Idaho Power's estimated historic CO2 emissions intensity from its generation facilities is as follows (in lbs CO2/MWh):
  2018 2017 2016 2015 2014 2013 2012 2011 2010
Cumulative Emissions Intensity 2010-2018 869 896 934 944 945 929 867 864 1,066
Annual Average Emissions Intensity 647 632 858 944 1,015 1,129 874 681 1,066


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 threejointly-owned coal-fired power plants, three natural gas combustion turbine power plants, and 17 hydroelectrichydropower generating plants are subject to a broad range of environmental
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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):
 2019 2020-202120222023-2024
Capital expenditures:    Capital expenditures:
License compliance and relicensing efforts at hydroelectric facilities $12
 $35
License compliance and relicensing efforts at hydropower facilitiesLicense compliance and relicensing efforts at hydropower facilities$21 $68 
Investments in equipment and facilities at thermal plants 4
 22
Investments in equipment and facilities at thermal plants10 11 
Total capital expenditures $16
 $57
Total capital expenditures$31 $79 
Operating expenses:    Operating expenses:
Operating costs for environmental facilities - hydroelectric $21
 $42
Operating costs for environmental facilities - hydropowerOperating costs for environmental facilities - hydropower$21 $43 
Operating costs for environmental facilities - thermal 12
 23
Operating costs for environmental facilities - thermal10 21 
Total operations and maintenance $33
 $65
Total operations and maintenance$31 $64 
 
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) 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, Idaho Power is unable to predict the 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- 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 capital expenditures and operating and maintenance costs to comply with the requirements of any new license.

Human Capital

Overview: Idaho Power is passionate about powering lives with 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, Idaho Power’s human capital programs are designed to attract, retain, and develop high quality employees. Idaho Power believes it maintains a good relationship with its employees due to a strong safety culture, respectful and inclusive environment, opportunities for development, and competitive compensation and benefits. Idaho Power regularly
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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, 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, IDACORP had 1,992 full-time employees, 1,983 of whom were employed by Idaho Power and 9 of whom were employed by Ida-West. IDACORP had 7 part-time employees, 5 of whom were employed by Idaho Power. Of IDACORP's full-time employees, 53 percent have 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 rewards 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. The audit committee is responsible for overseeing risk management, including compliance with the code of business conduct and physical security risks relating to employees. The corporate governance and nominating committee is responsible for overseeing risks associated with governance 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: 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-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 after 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, power system reliability, and customer satisfaction reflective of broad stakeholder interests and each employee's contribution.

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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. 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 "OurCommitment 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, 44 percent of Idaho Power’s senior management were women, 21 percent of its officers were women, and 36 percent of its board of directors were women. Idaho Power also has programs in place to encourage STEM participation, training to minimize bias and ensure a respectful and inclusive workplace, with a mindset of unity, community outreach to underserved communities, and partnerships with multiple diversity-focused organizations.

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. While IFS has not actively pursued new investment opportunities for some time, IFS does evaluate new investment opportunities. At December 31, 2018,2021, the unamortized amount of IFS’s portfolio was approximately $3$35 million ($146118 million in gross tax credit investments, net of $143$83 million of accumulated amortization). IFS generated tax credits of $2.6$6.2 million in each year2021, $5.3 million in 2018, 2017,2020, and 2016.$2.9 million in 2019. In 2018, 2017,2021 and 2016,2019, IFS received distributions related to fully-amortized affordable housingreal estate tax credit investments that reduced IDACORP's income tax expense by $0.3 million, $1.1$1.0 million and $1.7$3.2 million, respectively. In 2020, IFS received no distributions related to fully-amortized real estate tax credit investments.


IDA-WEST ENERGY COMPANY
 
Ida-West operates and has a 50 percent ownership interest in nine hydroelectrichydropower projects that have a total generatingnameplate 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 hydroelectrichydropower projects at a cost of approximately $10$8 million in 2021 and $9 million in both 20182020 and 2017 and $8 million in 2016.2019.


INFORMATION ABOUT OUR EXECUTIVE OFFICERS OF THE REGISTRANTS
 
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.


DARREL T. ANDERSON, 60
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RYAN N. ADELMAN, 47
•Vice President and Chief Executive Officer of IDACORP, Inc., May 2014Power Supply of Idaho Power Company, August 2020 - present
•Vice President of Transmission & Distribution, Engineering and Chief Executive OfficerConstruction of Idaho Power Company, October 2019 - August 2020
•Regional Manager for the Southeast Region of Idaho Power Company, January 20142018 - presentOctober 2019
President and Chief Financial Officer•Transmission & Distribution Projects Senior Manager of Idaho Power Company, January 20122015 - December 2013
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Executive Vice President, Administrative Services and Chief Financial Officer of IDACORP, Inc., October 2009 - April 2014
Member of the Boards of Directors of IDACORP, Inc. and Idaho Power Company since September 20132017
 
BRIAN R. BUCKHAM, 4043*
•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 2017
In-house legal counsel
MITCH COLBURN, 38
•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, 52
•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, 56
•President and Chief Executive Officer of IDACORP, Inc. and Idaho Power Company, April 2010June 2020 - March 2016present

JEFFREY S. GLENN, 51
Vice •President of Corporate Services and Chief Information Officer of Idaho Power Company, June 2018 - present
Vice President of Information Technology and Chief Information Officer of Idaho Power Company, January 2016October 2019 - June 20182020
Vice President of Technology Operations of Verizon Digital Media Services, Inc. (a digital media content delivery network company), January 2014 - January 2016
Vice President of Technology Operations of Edgecast Networks, Inc. (acquired by Verizon Digital Media Services, Inc. in 2014), January 2012 - January 2014
LISA A. GROW, 53
•Senior Vice President and Chief Operating Officer of Idaho Power Company, April 2016 - presentOctober 2019
Senior
JAMES BO D. HANCHEY, 46
•Vice President of Customer Operations of Idaho Power Company, January 2016 - March 2016
Senior Vice President - Power Supplyand Chief Safety Officer of Idaho Power Company, October 20092019 - December 2015present

•Customer Service Senior Manager of Idaho Power Company, February 2018 - October 2019
•Regional Manager of Southern Region of Idaho Power Company, May 2014 - February 2018

 STEVEN R. KEEN, 5861*
•Senior Vice President and Chief Financial Officer of IDACORP, Inc. and Idaho Power Company, March 2020 - present
•Senior Vice President, Chief Financial Officer and Treasurer of IDACORP, Inc., and Idaho Power Company, May 2014 - present
Senior Vice President - Chief Financial Officer, and Treasurer of Idaho Power Company, January 2014 - present
Senior Vice President - Finance and Treasurer of Idaho Power Company, January 2012 - December 2013
Vice President - Finance and Treasurer of IDACORP, Inc., June 2010 - April 2014March 2020
 
JEFFREY L. MALMEN, 5154
•Senior Vice President of Public Affairs of IDACORP, Inc. and Idaho Power Company, April 2016 - present

KEN W. PETERSEN, 58
•Vice President, of Public AffairsChief Accounting Officer and Treasurer of IDACORP, Inc. and Idaho Power Company, October 2008March 2020 - March 2016present

TESSIA PARK, 57
Vice President of Power Supply of Idaho Power Company, January 2016 - present
Director of Load Serving Operations of Idaho Power Company, September 2012 - December 2015

KEN W. PETERSEN, 55
•Vice President, Controller and Chief Accounting Officer of IDACORP, Inc. and Idaho Power Company, January 2014 - presentMarch 2020
Corporate Controller
ADAM J. RICHINS, 43
•Senior Vice President and Chief AccountingOperating Officer of IDACORP, Inc. and Idaho Power Company, May 2010 - December 2013
N. VERN PORTER, 59
Vice President of Transmission & Distribution Engineering and Construction and Chief Safety Officer, April 2016 - present
Vice President of Customer Operations of Idaho Power Company, January 2016October 2019 - March 2016present
Senior Vice President of Customer Operations of Idaho Power Company, April 2015 - December 2015
Vice President of Idaho Power Company, January 2014 - April 2015
Vice President of Delivery Engineering and Construction of Idaho Power Company, May 2012 - December 2013

ADAM RICHINS, 40
•Vice President of Customer Operations and Business Development of Idaho Power Company, March 2017 - presentOctober 2019
•General Manager of Customer Operations, Engineering and Construction, January 2014 - February 2017
In-house legal counsel
*As previously reported to the SEC on Form 8-K on November 19, 2021, Mr. Buckham will succeed Mr. Keen as Chief Financial Officer of IDACORP, Inc. and Idaho Power, Company, November 2010 - January 2014and Patrick A. Harrington will succeed Mr. Buckham as General Counsel of IDACORP, Inc. and Idaho Power, effective March 1, 2022.


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ITEM 1A. RISK FACTORS
 
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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 Part II - Item 7 - "Management's"Management’s Discussion 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. IDACORP's and Idaho Power's reactions to material future developments as well as the utility industry's reactions to those developments may also impact the Companies' future results.

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 cause 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 generally the most 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 difference 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 is often requiredexpects to incur increasing costs, which is likely to occur before the IPUC, OPUC, or FERC approvesapprove the recovery of those costs, such as construction costs for new facilities and transmission resources, changes in the long-term cost-effectiveness or power lines,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, increased funding levels of aIdaho Power's defined benefit pension plan, and the costs of damage from fires, climate change and weather-related events, and natural disasters. The IPUC, OPUC, and FERC may not allow Idaho Power to recover some or all of those costs on the basis that they find Idaho Power did not reasonably or prudently incur those costs or for other reasons. The IPUC and OPUC may adopt different methods 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. Decisions are subject to judicial appeal, which could lead to further uncertainty in regulatory proceedings.


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. The IPUC and OPUC may adopt different methods of calculating the allocation of the total utility costs in their respective jurisdictions, resulting in certain costs excluded in both states. 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 andearnings. This may also result in lower credit ratings, reduced access to capital, and 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
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Results of Operations - Regulatory Matters," and Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report, andof Part II - Item 7 - "Management's Discussion and Analysis of Financial Condition and Results of Operations - Regulatory Matters"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 adjustment 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 hydroelectrichydropower generation conditions, fuel cost variability from supply chain disruptions and inflationary pressures, general supply and demand economics for fuel and power, the impact of high costs for the purchase of renewable energy under mandatory long-term contracts.contracts, and market price variability for the purchase of power from third parties based on seasonal demands and transmission system constraints. 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. The fixed cost adjustment mechanism is a decoupling mechanism designed to remove a portion of Idaho Power's disincentive to invest in and support
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energy efficiency activities. This mechanismthat 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. The power cost and fixed cost adjustment 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
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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 may be negatively affected by changes in customer growth or customer usage.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, 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. 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 decline in usage per customer, in part attributable to 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 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 1,063 1,042 kilowatt-hour (kWh) in 2011 to 945 kWh in 2009 to 945 kWh in 2018.2021. Rate mechanisms, such as the Idaho fixed cost adjustment 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 modifyingto modify or eliminatingeliminate large generation 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.


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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's preferred resource portfolio and action plan included a need to acquire significant generation and storage resources to meet forecasted increasing energy and capacity needs. Idaho Power issued requests for proposals in June 2021 and December 2021 for additional energy resources, including renewables or natural gas resource convertible to hydrogen gas power, as described in Part 1, Item 1 - "Resource Planning and Renewable Energy Projects" in this report. If the incremental costs associated with the unanticipated changes in loads exceed the incremental revenue received from the salessales 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 and can be adversely affected by changes in weather conditions, severe weather, and climate change.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, and impact Idaho Power’s ability to import power on transmission lines from other geographic areas.events. These extreme weather events and their associated impacts could damage transmission, distribution, and generation facilities, causing service interruptions and
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extended or mass outages, increasing costs, and other operating and maintenance expenses, 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 hydroelectrichydropower plants.

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 hydroelectrichydropower 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 hydroelectric powerhydropower 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 repairrepairing and replacing infrastructure or liability for personal injury, loss of life, orand property damage from utility equipment that fails, including as a result of significant weather and weather-related events includingand 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, such aschange. Proposals have included imposing mandatory reductions in greenhouse gasGHG emissions, which could increase Idaho Power’s power supply and compliance costs.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
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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“Management’s Discussion and Analysis of Financial Condition and Results of Operations - Environmental Matters"Matters” in this report.


New advances in power generation, energy efficiency, alternative energy sources, or other technologies that impact the power utility industry could cause decreaseddecrease customer energy demand and decreased 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, powerrenewable 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 generation.and wind facilities. There is potential that customer-owned solar power generation systems, particularly if coupled with power storage devices, 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 wouldcould 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 attacks, data or physical security breaches,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 require significant expenditures, or result in claims against the companies, and negativelyadversely impact IDACORP's and Idaho Power's business, financial condition, and results of operations.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, as well asacts 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. Federal regulatorsThere have stated that a number of organizationsbeen cyber and physical attacks within the energy industry on energy infrastructure such as electric substations and pipelines in the past, 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 seek opportunitiesbe subject to, exploit potential vulnerabilitiesattempts 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 U.S. energy infrastructurefrequency and that those attacks have become increasingly frequent and sophisticated. sophistication of cybersecurity incidents.

Some of Idaho Power's facilities are deemed "critical infrastructure,"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 possibilityfact that infrastructure facilities, such as power generation facilities and electric transmission or distribution facilities, would beare direct targets of, or potential indirect casualties of, an act of terror or cyber attack, including by nation states or nation state-sponsored groupsphysical attack (whether originating internallyinternal 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 such asthrough process breakdowns, human error, security architecture or design vulnerabilities, or by third parties such as computer hackings,through cyber attacks, computer viruses, or other destructive or disruptive software, denial of servicephysical security attacks, social engineering or other malicious activities, or any combination of the foregoing, could result in a degradation or disruption in the energy grid and the services of the companies.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 IDACORP and Idaho Power. Political, economic, social, or financial market instability or damage to or interference with Idaho Power’s operating assets, customers, or suppliers may result in business interruptions, lost revenue, higher commodity prices, disruption in fuel supplies, lower energy consumption, and unstable markets, particularly with respect to electricity and natural gas, and increased security, repair, or other costs, any of which may materially adversely affect Idaho Power in ways that cannot be predicted as of the date of this report. Any of these risks could materially affect the companies’ consolidated financial results.
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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 business.  


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
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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, 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. AnyDespite the steps Idaho Power may take to detect, mitigate, or eliminate threats and respond to security breaches, such as misappropriation, misuse, leakage, falsificationincidents, the techniques used by those who seek to obtain unauthorized access, and possibly disable or accidental releasesabotage systems or loss ofabscond with information maintained in IDACORP'sand data, change frequently and Idaho Power's information technologyPower 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 including customer data,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 violations of privacya material decrease in revenues and other laws, financial lossincrease costs to Idaho Power or to its customers, customer dissatisfaction, damage to Idaho Power’s reputation,protect, repair, and significant litigation and penalty exposure, all of which could materially affectinsure Idaho Power's financial conditionassets and results of operations.operate its infrastructure, systems, and business.


CapitalChanges in capital expenditures for infrastructure and the risks associated with permitting and construction of thatutility infrastructure and the timing and availability of cost recovery for the expenditures, 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 energy generation,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. For instance,infrastructure as described in Idaho Power's 2021 IRP. Idaho Power is not only in the permitting process for two 500-kVhigh-voltage transmission line projects, but has issued requests for proposals for new capacity resources, and utility-scale battery storage, which areare intended to help meet futureincreasing customer energy demands. ConstructionIdaho 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;contractors, including delays for specialty equipment that require significant lead times;
•equipment, engineering, and design failures;
•unexpected environmental and geological problems;
•the effects of adverse weather conditions;
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•catastrophic events, natural disasters, pandemics and other public health events;
•availability of financing;
load forecasts;
•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 or unwilling 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 purchasing capacity in the market or acquiring or constructing additional generation resources and battery storage facilities. Idaho Power's 2021 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 participation in the remaining coal-fired units by the end of 2028. 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. 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 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 acquired 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 2020 and 2021, 54 percent and 48 percent, respectively, of 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. As part of its
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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 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 coal supply arrangements are under long-term contracts for coal originating in Wyoming, and thus Idaho Power is exposed to risk of disruption of coal production in, or transportation from, that region. 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 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. 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, 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
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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 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. 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, Idaho Power had federally-mandated contracts to purchase energy from 129 on-line projects with third parties. This increases 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 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 bulk of IDACORP's operations, and Idaho Power's business is concentrated solely in the electricity 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. 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 to such turnover due to a loss of knowledge, errors due to inexperienced employees or substantial training time, loss of productivity, and increased safety 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.

Legal and Compliance Risks
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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, 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. Changes in, and uncertainty with respect to, federal, state, and local legislation, regulation, and government policy could significantly impact IDACORP’s and Idaho Power’s businesses and the electric utility industry. Specific legislative and regulatory proposals and recently enacted legislation that could have a 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. Laws,Under the current Presidential Administration, Idaho Power expects laws, regulations, and policies relating to environmental compliance couldto continue to change and require IDACORP and Idaho Power and some of their customers to modify their business strategy or affect their returns on
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investment by restrictingrestrict activities and projects, orpotentially 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 are monitoring the implementation byexpect federal, state, and local governmental authorities ofto 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 regulatoryIdaho tax reform settlement stipulation withapproved by the IPUC), hashave 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“Management’s Discussion and Analysis of Financial
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Condition and Results of Operations - Environmental Matters"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.


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 will 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 current presidential administration has issued a number of executive ordersutility industry is also facing increasing stakeholder scrutiny related to its environmental, matters designedsocial, 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 easeadditional state and federal regulatory requirements, increased scrutiny and changing stakeholder expectations with respect to environmental regulationand 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 the federal agencieswould affect Idaho Power's future financial position, results of operations, and cash flows if such costs are still implementing. However, the outcome of the Environmental Protection Agency's and other federal agencies' review of regulations covered by the executive orders is difficult to predict.not timely recovered through regulated rates. Moreover, the executive orders and any resulting federal regulations could be affected by Congressional action and challenged in court. Further, state and local governmental authorities could choose to replace the federalpossibility exists that stricter laws, regulations, or bolsterenforcement policies could significantly increase compliance costs and the cost of any remediation that may become necessary.
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environmental compliance and enforcement efforts at the local level. Accordingly, Idaho Power may not realize any benefit from changes to federal environmental regulations, if any, resulting from the executive orders and, as of the date of this report, cannot predict whether and to what extent the orders and resulting changes to regulations could affect its operations and environmental-related expenditures.

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 commitment to serve customers with 100 percent clean energy by 2045, and Idaho Power has short-term and medium-term targets 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, grid balancing, among others. Additionally, Idaho Power is not guaranteed timely or full recovery through customer rates or insurance 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.

Factors contributing to lower hydroelectric generation can increase costs and negatively impact IDACORP's and Idaho Power's financial condition and results For further discussion of operations.environmental matters that may affect Idaho Power, derives a significant portionsee "Environmental Matters" in Item 7 - “Management’s Discussion and Analysis of its power supply from its hydroelectric facilities. During 2017Financial Condition and 2018, 65 percentResults of Idaho Power's electric power generation was from hydroelectric facilities. Due to Idaho Power’s heavy reliance on hydroelectric generation, factors such as precipitation and snowpack, the timing of run-off, and the availability of waterOperations” 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 hydroelectric generation. When hydroelectric 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 hydroelectric 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.this report.


Obligations imposed in connection with hydroelectrichydropower license renewals and permitting may require large capital expenditures, increase operating costs, reduce hydroelectrichydropower generation, and negatively affect IDACORP's or Idaho Power's results of operations and financial condition. For the last several years, Idaho Power has been engaged in an effort to renew its federal license for its largest hydroelectrichydropower generation source, the Hells Canyon Complex.HCC. Relicensing includesand 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 hydroelectrichydropower projects, which may be reflected in hydroelectrichydropower licenses, including for the Hells Canyon Complex.HCC and the American Falls facility. In addition, new interpretations of existing laws and regulations could be adopted or become applicable to hydroelectrichydropower facilities, which could further increase required expenditures for marine life recovery and endangered species protection and reduce the amount of hydroelectrichydropower generation available to meet Idaho Power’s generation requirements. One significant issue identified in connection with the Hells Canyon Complex relicensing effort involves water temperature gradients in the Snake River below the Hells Canyon dam. Certain parties in the relicensing proceedings have advocated for the installation of a water temperature management apparatus which, if required to be installed, would involve substantial costs to construct, operate, and maintain. Idaho Power may be unable to recover in full or in a timely manner the costs of such an apparatus through rates, particularly given the magnitude of any potential impact on customer rates. Another significant issue related to the relicensing effort involves a dispute between the states of Idaho and Oregon regarding whether to reintroduce or establish spawning populations of fish species into Idaho waters. In December 2018, the states of Idaho and Oregon, along with Idaho Power, reached a proposed settlement on this matter, requiring Idaho Power to reintroduce certain fish species and fund-related research. Idaho Power cannot predict the outcome of these proceedings, the requirements that might be imposed during the relicensing and permitting process, the financial impact of those requirements,
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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 processand permitting processes could result in Idaho Power incurring significant capital expenditures, increase operating costs (including power purchase costs), and reduce hydroelectrichydropower generation, which could negatively affect results of operations and financial condition.


Idaho Power’s use of coalPower could be subject to penalties, reputational harm, and natural gas to fuel power generation facilities exposesoperational changes if it to commodity availabilityviolates mandatory reliability and price risk,security requirements, which cancould adversely affectimpact IDACORP's and Idaho Power's results of operations and financial condition.condition. As partan owner and operator of its normal business operations, Idaho Power purchases coal and natural gas in the open market or under short-term or long-term
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contracts, often with variable pricing terms. Market prices for coal and natural gas are volatile and influenced by factors impacting supply and demand such as weather conditions, the adequacy and type of generating capacity, fuel transportation availability, economic conditions, and changes in technology. 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 coal supply arrangements are under long-term contracts for coal originating in Wyoming, and thusbulk power transmission system, Idaho Power is exposedsubject to risk of disruption of coal production in, or transportation from,mandatory reliability and security standards issued by the FERC and other regulators. The standards are based on the functions that region.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 mayto higher operating costs and increased capital expenditures. Idaho Power has received in recent years notices of violations 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 counterpartiesand regularly self-reports reliability standard compliance issues to, the natural gasFERC, 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 $1.4 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 coal supply agreements will fulfill their obligationsother unanticipated events. Adverse publicity could harm the reputations of IDACORP and Idaho Power; may make state legislatures, utility commissions, and other regulatory authorities less likely to supply natural gas or coal,view the companies in a favorable light; and they may experience 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,be subject to less favorable legislative and potentially more costly, sourcesregulatory outcomes or increased regulatory oversight. The imposition of fuel or relyany of the foregoing on other generation sources or wholesale market power purchases. 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 not be able to fully or timely recover these increased costs through rates, which may adversely affectimpact 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.

If Further, new accounting orders issued by the assumptions underlying coal mine reclamation at Bridger Coal CompanyFERC could significantly impact IDACORP's 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, a subsidiary ofPower's reported financial condition. IDACORP and Idaho Power uses both surface and underground methods to mine coal to be used for power generation atdo not have any control over 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. Bridger Coal Company’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 to cover such projected mine reclamation costs. The trust funds are invested in debt and equity securities and poor performance ofimpact these investments would reduce the amount of funds available forchanges may have on their intended purpose, which could require Idaho Power to make additional cash contributions. If actual costs related to those obligations exceed estimates, government regulations relating to those obligations change significantlyfinancial conditions or unexpected cash funding obligations are required, IDACORP’s and Idaho Power’s results of operations nor the timing of such changes. Idaho Power meets the requirements under GAAP to reflect the impact of regulatory decisions in its financial statements and financial conditionto 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 adversely affected.

Idaho Power’s generation, transmission, and distribution facilities are subjectrequired to numerous operational risks unique to it and its industry. Operating risks associated with Idaho Power's generation, transmission, and distribution facilities include equipment failures, volatility in fuel and transportation pricing, interruptions in fuel supplies, increased regulatory compliance costs, labor disputeseliminate some or attrition, accidents and workforce safety matters, release of hazardous or toxic substances into the air, water, or ground, wildfires, acts of terrorism or sabotage, 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. Diminished availability or performanceall of those facilitiesregulatory assets or liabilities. Any of these circumstances could result in reduced customer satisfaction, reputational harm, liability to third parties,write-offs 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, 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 during high-load periods. 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 workhave a material effect on its generation, 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, or enforcement actions or liability if a contractor violates applicable laws, rules, regulations, or orders.

Accidents, terrorist acts, electrical contacts, fires, explosions, catastrophic failures, general system damage or dysfunction, uncontrolled release of water from hydroelectric 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, and property damage, whether based on claims of negligence, trespass, or otherwise. The risk of wildfires is exacerbated in forested areas where beetle infestations 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
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commonly hot, dry summer conditions, increase the likelihood and magnitude of damages that may be caused by fires burning into or allegedly originating from utility equipment. 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 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’sIDACORP's and Idaho Power’s financial condition and results of operations, or cash flows could be materially affected.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
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on their strategic plans. IDACORP and Idaho Power use credit facilities, commercial paper markets, and long-term debt as significant sources of liquidity and funding for operating and capital requirements and debt maturities not satisfied by operating cash flow. The credit 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.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 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 at 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 manner to permit them to finance their operations, capital expenditures, and debt maturities. IDACORP's and Idaho Power's credit facilities include financial covenants that limit 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 request 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, 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, 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.


Changes in the method for determining LIBOR and the potential replacement of LIBOR may affect our credit facilities and the interest rates on such borrowings. LIBOR, the London interbank offered rate, is the basic rate of interest used in lending between banks on the London interbank market and is widely used as a reference for setting the interest rate on loans globally. The interest rates for any borrowings under IDACORP and Idaho Power’s credit facilities are based on either (1) a floating rate
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that is equal to the highest of the prime rate, federal funds rate plus 0.5 percent, or LIBOR rate plus 1.0 percent, or (2) the LIBOR rate, plus, in each case, an applicable margin, provided that the federal funds rate and LIBOR rate will not be less than zero percent. In July 2017, the United Kingdom’s Financial Conduct Authority, which regulates LIBOR, announced that it intends to phase out LIBOR by the end of 2021. It is unclear if at that time LIBOR will cease to exist or if new methods of calculating LIBOR will be established such that it continues to exist after 2021. If the method for calculation of LIBOR changes, if LIBOR is no longer available, or if lenders have increased costs due to changes in LIBOR, IDACORP and Idaho Power may suffer from potential increases in interest rates on any borrowings. Further, IDACORP and Idaho Power may need to renegotiate their credit facilities that utilize LIBOR as a factor in determining the interest rate to replace LIBOR with the new standard that is established.

Idaho Power’senergy 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 financial 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 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. Idaho Power has additional indirect credit exposures to financial institutions in the form of letters of credit provided as security by power suppliers under
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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. 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. 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. In January 2019, Pacific Gas & Electric Company and PG&E Corporation, its parent entity (collectively, PG&E), filed voluntary bankruptcy petitions under Chapter 11 of the U.S. Bankruptcy Code. Idaho Power does not have any direct power, gas, or derivative transactions with PG&E. However, both Idaho Power and PG&E are participantsis a participant in the energy markets, including the Western EIM, and engageengages 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 PG&Ecounterparties may owe each other participants in the Western EIM. Also, PG&E purchasesEIM and any such credit losses could be socialized to all Western EIM participants, including Idaho Power. A significant failure of a participant in the output of power from small hydroelectric facilities located in California, in which Ida-West is a 50% co-owner. If PG&E is unableWestern EIM to performmake payments when due on its obligations under its arrangements with Ida-West’s joint venture, IDACORP does not believe the impact would be material to its financial condition nor results of operations. However, a bankruptcy filing of the magnitude of PG&E’s filing in 2019 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.  


Idaho Power could be subject to penalties 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 million per day per violation. The imposition of penalties 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.

Federally mandated purchases of power 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
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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 in the Pacific Northwest. 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. This increases the likelihood and frequency that Idaho Power will be required to reduce output from its lower-cost hydroelectric 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 additional generation. Increases in customer rates could make self-generation more financially attractive for customers, which could result in reduced net load and shifts in customer costs. Further, balancing load and generation from Idaho Power's power generation portfolio is challenging, and Idaho Power expects that its operational 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 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.

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 state public utility commissionsIPUC 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 12 - "Benefit Plans" to the consolidated financial statements included in this report.


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 subsidiary of Idaho Power located in the state of Wyoming, uses both surface and underground methods to mine 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
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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 7 - "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.


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 bulk of IDACORP's operations, and Idaho Power's business is concentrated solely in the electricity 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 will be affected by 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 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
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design personnel, and generation plant operators, require extensive, specialized training. Idaho Power has experienced in recent years an above-average number of employee retirements and expects the increased level of retirement of its skilled workforce and persons in key positions will continue in 2019 and in the near-term. At December 31, 2018, approximately 22 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. The loss of skills and institutional knowledge of experienced employees and the failure to hire and the costs associated with attracting, training, and retaining appropriately qualified employees to replace an aging and skilled workforce could have a negative effect on IDACORP's and Idaho Power's financial condition and results of operations.
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. Similarly, 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 conditions under GAAP 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.

ITEM 1B. UNRESOLVED STAFF COMMENTS
 
None.


ITEM 2. PROPERTIES
 
Idaho Power's properties consist of the physical assets necessary to support its utility operations, which include generation, transmission, and distribution facilities, as well as coal assets that support one of its coal-fired generation plants. 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 comprisedcomposed of 17 hydroelectrichydropower generating plants located in southern Idaho and eastern Oregon, three natural gas-fired plants in southern Idaho, and interests in threetwo coal-fired steam electric generating plants located in Wyoming Nevada, and Oregon.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, 2018,2021, the system also includes approximately 4,8164,843 pole-miles of high-voltage transmission lines, 2423 step-up transmission substations located at power plants, 21 transmission substations, 910 switching stations, 3230 mixed-use transmission and distribution substations, 183187 energized distribution substations (excluding mobile substations and dispatch centers), and approximately 27,56928,570 pole-miles of distribution lines.


Idaho Power holds Federal Energy Regulatory Commission (FERC) licenses for all of its hydroelectrichydropower projects that are subject to federal licensing. Relicensing of Idaho Power’s hydroelectrichydropower projects is discussed in Part II - Item 7 - MD&A"Management’s Discussion and Analysis of Financial Condition and Results of Operations – "RegulatoryRegulatory Matters – Relicensing of Hydroelectric Projects”Hydropower Projects" in this report.

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Idaho Power's hydroelectric projects and other owned and co-owned generating facilities and their nameplate capacities are included in the table below.
Project 
Nameplate Capacity (kW)(1)
 License Expiration
Hydroelectric Projects:  
   
Properties Subject to Federal Licenses:  
   
Lower Salmon 60,000
 2034 
Bliss 75,000
 2034 
Upper Salmon 34,500
 2034 
Shoshone Falls 11,500
 2034 
CJ Strike 82,800
 2034 
Upper Malad - Lower Malad 21,770
 2035 
Brownlee - Oxbow - Hells Canyon (Hells Canyon Complex) 1,235,600
 2005
(2) 
Swan Falls 27,170
 2042 
American Falls 92,340
 2025 
Cascade 12,420
 2031 
Milner 59,448
 2038 
Twin Falls 52,897
 2040 
Other Hydroelectric:  
   
Clear Lakes - Thousand Springs 9,300
   
Total Hydroelectric 1,774,745
   
Steam and Other Generating Plants:  
   
Jim Bridger (coal-fired)(3)
 770,501
   
North Valmy (coal-fired)(3)
 283,500
   
Boardman (coal-fired)(3)(4)
 64,200
   
Danskin (gas-fired) 270,900
   
Langley Gulch (gas-fired) 318,452
   
Bennett Mountain (gas-fired) 172,800
   
Salmon (diesel-internal combustion) 5,000
   
Total Steam and Other 1,885,353
   
Total Generation 3,660,098
   
(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, 50 percent for North Valmy, and 10 percent for Boardman. Amounts shown represent Idaho Power’s share.
(4) Pursuant to an Oregon Environmental Quality Commission plan and associated rules, the Boardman power plant is scheduled for cessation of coal-fired operations by December 31, 2020.


IDACORP's and Idaho Power's headquarters are located in Boise, Idaho. The corporate headquarters campus is comprisedconsists of approximately 305,741 square feet of owned office space. Excluding Idaho Power's power generation facilities and substations, Idaho Power owns an additional 1,113,6311,129,222 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) 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 (BCC) 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 hydroelectrichydropower plants that have a total nameplate capacity of 44 MW. These plants are located in Idaho and California.


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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.
Project
Nameplate Capacity (kW)(1)
License Expiration
Hydropower Projects:   
Properties Subject to Federal Licenses:   
Lower Salmon60,000 2034 
Bliss75,038 2034 
Upper Salmon34,500 2034 
Shoshone Falls14,729 2040 
CJ Strike82,800 2034 
Upper Malad - Lower Malad21,770 2035 
Brownlee - Oxbow - Hells Canyon (Hells Canyon Complex)1,256,501 2005(2)
Swan Falls27,170 2042
American Falls92,340 2025 
Cascade12,420 2031 
Milner59,448 2038 
Twin Falls52,898 2040 
Other Hydropower:   
Clear Lake - Thousand Springs9,300   
Total Hydropower1,798,914   
Steam and Other Generating Plants:   
Jim Bridger (coal-fired)(3)
775,286   
North Valmy Unit 2 (coal-fired)(3)(4)
144,900   
Danskin (gas-fired)270,900   
Langley Gulch (gas-fired)318,453 
Bennett Mountain (gas-fired)172,800 
Salmon (diesel-internal combustion)5,000   
Total Steam and Other1,687,339   
Total Generation3,486,253   
(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.

ITEM 3. LEGAL PROCEEDINGS
 
Refer to Note 11 – “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.


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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 15, 2019,11, 2022, there were 9,0067,747 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 - MD&A"Management’s Discussion and Analysis of Financial Condition and Results of Operations - "LiquidityLiquidity and Capital Resources - Dividends" in this report. For information relating to restrictions on dividends see, Note 7 - "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 2018.2021.


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) Electric Utilities Index. The data assumes that $100 was invested on December 31, 2013,2016, with beginning-of-period weighting of the peer group indices (based on market capitalization) and monthly compounding of returns.ida123116_charta03.jpg
ida-20211231_g4.jpg
Source: Bloomberg and EEI
201620172018201920202021
IDACORP$100.00 $116.43 $121.74 $143.27 $132.57 $161.01 
S&P 500100.00 121.82 116.47 153.14 181.30 233.30 
EEI Electric Utilities Index100.00 111.72 115.82 145.69 144.00 168.65 
  2013 2014 2015 2016 2017 2018
IDACORP $100.00
 $131.78
 $139.49
 $169.92
 $197.83
 $206.86
S&P 500 100.00
 113.68
 115.25
 129.02
 157.17
 150.27
EEI Electric Utilities Index 100.00
 128.91
 123.88
 145.48
 162.53
 168.49


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
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of 1934, except to the extent IDACORP or Idaho Power specifically incorporates it by reference into such filing.
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ITEM 6. SELECTED FINANCIAL DATA
IDACORP, Inc.
SUMMARY OF OPERATIONS
(thousands of dollars, except per share amounts and statistics)
  2018 2017 2016 2015 2014
Operating revenues $1,370,752
 $1,349,486
 $1,262,020
 $1,270,289
 $1,282,524
Operating income(1)
 296,922
 315,545
 283,582
 297,048
 267,194
Net income attributable to IDACORP, Inc. 226,801
 212,419
 198,288
 194,679
 193,480
Diluted earnings per share 4.49
 4.21
 3.94
 3.87
 3.85
Dividends declared per share 2.40
 2.24
 2.08
 1.92
 1.76
           
Financial Condition:    
  
  
  
Total assets(2)
 $6,382,754
 $6,045,405
 $6,289,897
 $6,023,314
 $5,701,037
Long-term debt (including current portion)(2)
 $1,834,788
 $1,746,123
 $1,745,678
 $1,726,474
 $1,599,686
           
Financial Statistics:    
  
  
  
Times interest charges earned:    
  
  
  
Before tax(3)
 3.55
 3.82
 3.54
 3.61
 3.38
After tax(4)
 3.36
 3.30
 3.15
 3.12
 3.19
Book value per share(5)
 $47.04
 $44.68
 $42.74
 $40.88
 $38.85
Market-to-book ratio(6)
 198% 204% 188% 166% 170%
Payout ratio(7)
 53% 53% 53% 50% 46%
Return on year-end common equity(8)
 9.6% 9.4% 9.2% 9.5% 9.9%
           
(1) Operating income in 2018-2014 reflects IDACORP's 2018 adoption of Accounting Standards Update (ASU) 2017-07. IDACORP retrospectively adjusted prior periods to reflect the disaggregation of service cost from other components of net periodic benefit cost. The non-service cost components of net periodic benefit cost were reclassified from "Other operations and maintenance" and "Other" operating expenses to "Other Expense, Net" on the consolidated statements of income to conform to current period presentation.
(2) Amounts in 2014 were adjusted to reflect IDACORP's 2015 adoption of ASU 2015-03, which required debt issuance costs be reported as reductions of long-term debt rather than as long-term assets on the consolidated balance sheets.
The financial statistics listed above are calculated in the following manner:
(3) The sum of "Interest on long-term debt," "Other interest" expense, and "Income before income taxes" divided by the sum of "Interest on long-term debt" and "Other interest" expense on the consolidated statements of income.
(4) The sum of "Interest on long-term debt," "Other interest" expense, and "Net income attributable to IDACORP, Inc." divided by the sum of "Interest on long-term debt" and "Other interest" expense on the consolidated statements of income.
(5) "Total IDACORP, Inc. shareholders' equity" on the consolidated balance sheets at the end of the year divided by shares outstanding at the end of the year.
(6) The closing price of IDACORP stock on the last day of the year divided by the book value per share, which is described in footnote (5) above.
(7) Dividends paid per common share divided by diluted earnings per share.
(8) "Net income attributable to IDACORP, Inc." on the consolidated income statements divided by "Total IDACORP, Inc. shareholders' equity" on the consolidated balance sheets at the end of the year.

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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) 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 2020 compared with 2019 can be found in their Annual Report on Form 10-K for the year ended December 31, 2020 (2020 Annual Report). See Part II - Item 7 - “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the 2020 Annual 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), and Federal Energy Regulatory Commission (FERC). Idaho Power generates revenues and cash flows primarily from the sale and distribution of electricity to customers in its Idaho and Oregon service areas, as well as from the wholesale sale and transmission of electricity.


Idaho Power is the parent of Idaho Energy Resources Co. (IERCo), a joint venturer in Bridger Coal Company (BCC), which mines and supplies coal to the Jim Bridger generating plant owned in part by Idaho Power. IDACORP’s other 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 hydroelectrichydropower generation projects that satisfy the requirements of the Public Utility Regulatory Policies Act of 1978 (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 and recognitions during 20182021 include:


•IDACORP achieved net income growth for an eleventha fourteenth consecutive year;
IDACORP provided a 14 percent cumulative annual total shareholder return over the past three years, including share price appreciation and dividends paid, ranking in the 63rd percentile among peer companies in the Edison Electric Institute (EEI) Electric Utilities Index;
IDACORP received its second EEI Electric Utilities Index award in the past three years, for the best total shareholder return performance among small cap utilities (market capitalization of less than $5 billion) over the past five years, measured as of September 30, 2018;
•IDACORP increased its quarterly common stock dividend from $0.59to $0.75 per share to $0.63from $0.71 per share, as a part of a 110150 percent increase in quarterly dividends approved over the last seven years under the company's objective to pay dividends at the upper endten years. The increase keeps IDACORP within its current target payout ratio of the range of 50 percent tobetween 60 and 70 percent of sustainable earnings;IDACORP earnings, annualizing the most recently declared quarterly dividend;
•Idaho Power's customer count grew 2.32.8 percent in 2018;
2021. On June 30, 2021, Idaho Power ranked secondset 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 J.D.Idaho Power's Electric Utility Residential Customer Satisfaction Studyservice area in its West Region Midsize segment for the second year in a row;June and July of 2021;
•Idaho Power reached milestones on keycontinued 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, Idaho Power issued its 2021 Integrated Resource Plan (IRP) that contemplates no new fossil fuel resources for Idaho Power's power supply mix and plans for substantial renewable resource additions over the next 20 years. The 2021 IRP also includes the end 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.
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Coronavirus (COVID-19) Response and Impacts

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, projectsand distribution operations, as the U.S. Forest Service issued a record of decision on the siting of the Boardman-to-Hemingway 500-kV project and the U.S. Bureaudate of Land Management (BLM) issued a recordthis report, continues largely uninterrupted.

In March 2020, in consideration of decision for the remaining transmission line segments of the Gateway West 500-kV transmission project;
•
Idaho Power achieved its carbon dioxide (CO2) emissions intensity reduction goal; and
COVID-19, Idaho Power reached several constructive regulatory settlements that weretemporarily 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, the IPUC and OPUC relatedissued orders granting Idaho Power the authority to recent income tax reform,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 indefinite extension,Presidential Administration issued an executive order announcing new U.S. Department of Labor’s OSHA requirements that all employers with modifications,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 application of the current earnings supportmandate for COVID-19 vaccines and revenue sharing mechanism,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 prudencedate 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 Hells Canyon Complex (HCC) relicensing costs,risks IDACORP and Idaho Power are confronting as a result of the treatment of costs incurred to join the energy imbalance market implementedpublic health crisis, see Part II - Item 1A - "Risk Factors" in the western United States (Western EIM).this report.

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Summary of 20182021 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, 2018, 2017,2021, 2020, and 20162019 (in thousands, except earnings per share amounts):
Year Ended December 31,
 202120202019
Idaho Power net income$243,225 $233,235 $224,437 
Net income attributable to IDACORP, Inc.$245,550 $237,417 $232,854 
Average outstanding shares – diluted (000’s)50,645 50,572 50,537 
IDACORP, Inc. earnings per diluted share$4.85 $4.69 $4.61 

40
  Year Ended December 31,
  2018 2017 2016
Idaho Power net income $222,334
 $206,347
 $189,242
Net income attributable to IDACORP, Inc. $226,801
 $212,419
 $198,288
Average outstanding shares – diluted (000’s) 50,510
 50,424
 50,373
IDACORP, Inc. earnings per diluted share $4.49
 $4.21
 $3.94
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The table below provides a reconciliation of net income attributable to IDACORP for the year ended December 31, 2018,2021, from the year ended December 31, 20172020 (items are in millions and are before tax unless otherwise noted):
Net income attributable to IDACORP, Inc. - December 31, 2017   $212.4
Increase (decrease) in Idaho Power net income:    
Customer growth, net of associated power supply costs and power cost adjustment mechanisms 10.3
  
Usage per retail customer, net of associated power supply costs and power cost adjustment mechanisms (9.4)  
Idaho fixed cost adjustment (FCA) revenues 17.7
  
Retail revenues per MWh, net of associated power supply costs and power cost adjustment mechanisms (26.9)  
Transmission wheeling and other revenues 16.1
  
Non-cash amortization of regulatory deferrals (related to tax reform) (4.0)  
Other operations and maintenance (O&M) expenses (excluding non-cash amortization of regulatory deferrals) (13.8)  
Other changes in operating revenues and expenses, net (3.6)  
Decrease in Idaho Power operating income prior to sharing mechanism (13.6)  
Decrease in revenues as a result of sharing mechanism (5.0)  
Decrease in Idaho Power operating income (18.6)  
Earnings of unconsolidated equity-method investments 1.4
  
Non-operating income and expenses, net 0.3
  
Decrease in income tax expense from remeasurement of deferred taxes and make-whole premium for early bond redemption 9.0
  
Income tax expense (excluding remeasurement of deferred taxes and make-whole premium for early bond redemption) 23.9
  
Total increase in Idaho Power net income   16.0
Other IDACORP changes (net of tax)   (1.6)
Net income attributable to IDACORP, Inc. - December 31, 2018   $226.8
Net income attributable to IDACORP, Inc. - December 31, 2020$237.4
Increase (decrease) in Idaho Power net income:
Customer growth, net of associated power supply costs and power cost adjustment mechanisms16.0 
Usage per retail customer, net of associated power supply costs and power cost adjustment mechanisms13.4 
Retail revenues per MWh, net of associated power supply costs and power cost adjustment mechanisms(13.4)
Transmission wheeling-related revenues16.4 
Other operations and maintenance (O&M) expenses(9.2)
Other changes in operating revenues and expenses, net(1.8)
Increase in Idaho Power operating income prior to sharing mechanism21.4 
Provision for sharing with customers(0.6)
Increase in Idaho Power operating income20.8 
Non-operating expense, net(3.1)
Income tax expense(7.7)
Total increase in Idaho Power net income10.0 
Other IDACORP changes (net of tax)(1.8)
Net income attributable to IDACORP, Inc. - December 31, 2021$245.6
 
IDACORP's net income increased $14.4$8.2 million for 20182021 compared with 2017,2020, due primarily due to higher net income at Idaho Power. Customer

Idaho Power's customer growth of 2.8 percent added $10.3$16.0 million to Idaho Power's operating income compared with 2017. Sales2020. Higher sales volumes on a per-customer basis decreasedincreased operating income by $9.4$13.4 million in 20182021 compared with 2017. A decrease2020, due mostly to warmer and drier weather in sales volumesthe spring and early summer that caused irrigation customers to use more energy for irrigation pumps and residential customers was partially offset by anto use more energy for cooling in 2021 compared with 2020. The increase in usage per irrigation customer. Milder temperatures in 2018residential customer from the spring and early summer was mostly offset by lower usage per residential customer from August through December 2021 compared with 2017 caused residentialthose same months in 2020 due to milder temperatures. Also, a return to more normal economic conditions for commercial and industrial customers to use 6 percent less electricity per customer, mostly for cooling and heating purposes, while decreased precipitation led agricultural irrigation customers to use 9 percent more electricity per customer to operate irrigation pumps. However, due mostly to the lower usage by Idaho residential customers, the FCA mechanism added $17.7 million to operating income during 2018in 2021 compared with 2017.2020 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 MWhmegawatt-hour (MWh) reduced operating income by $26.9$13.4 million in 20182021 compared with 2017. The settlement stipulations approved by the IPUC and OPUC during the second quarter of 2018 relating to recent income tax reform reduced revenues by approximately $22 million in 2018. The timing of the revenue reductions may not align with decreases in income tax expense in any given period2020, primarily due to higher power supply costs. During the method and timingsummer of customer rate reductions provided for2021, higher wholesale energy market prices due to a heat wave in the settlement
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stipulations, the naturewestern United States and timing of income tax accruals, discrete items, and other items discussed in more detailhigher energy usage by Idaho Power customers increased Idaho Power's net power supply expenses. The increase in the "Income Tax Reform" section below. Also, a changeamount of net power supply expenses that were not deferred through Idaho Power's power cost adjustment mechanisms contributed to the negative variance in customer sales mix reduced thenet retail revenues per MWh as volumes soldbetween 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 residential customers made up a smaller portionreflect full depreciation of all Boardman power plant investments after ceasing coal-fired operations at the customer sales mix.Boardman power plant in October 2020.


During 2018, Idaho Power benefited from a $16.12021, transmission wheeling-related revenues increased $16.4 million increase in transmission wheeling and other revenues, compared with 2017. This change was largely due to a 37 percent increase2020, as the warmer and drier weather in the Open Access Transmission Tariffwestern 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) rate in October 2017, partially offset by arates increased approximately 10 percent decreaseduring the period from October 1, 2020, to September 30, 2021, as compared with the rates in the OATTeffect from October 1, 2019, to September 30, 2020. The rate inincreased an additional four percent on October 2018 and, to a lesser extent, an increase in wheeling volumes.1, 2021.


Other O&M expenses included $4.0increased $9.2 million in 2021 compared with 2020, primarily due to a return to more normal levels of non-cash amortization expense of regulatory deferrals that would otherwise be a future liability of Idaho customers, as providedpurchased services and maintenance activity compared with 2020, which was affected by the settlement stipulation approved by the IPUC related to income tax reform. Excluding the non-cash amortization of regulatory deferrals,COVID-19 public health crisis. Also, labor-related other O&M expenses were $13.8 million higherincreased slightly in 20182021 compared with 2017. 2020.
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In 2018, compared with 2017, higher maintenance service costs led to a $4.2 million increase in transmission and distribution asset maintenance expenses, and higher variable employee-related costs led to an $8.4 million increase in labor and benefit expenses.

In 2018,2021, Idaho Power recorded $5.0$0.6 million as a provision against current revenues to be refunded to customers through a future rate reduction, through the Idaho-jurisdiction power cost adjustment (PCA) mechanismmechanism pursuant to a settlement stipulation withapproved by the IPUC as described in "Regulation of Rates and Cost Recovery" below.


Idaho Power's $5.7Non-operating expense, net, increased $3.1 million remeasurementin 2021 compared with 2020, primarily due to increased costs of deferred taxes resulting from the federal and Idaho income tax rate change (discussed in further detail below) on the adjustment of temporary differences as a result of IDACORP’s 2017 consolidated income tax return filings and the $1.3 million flow-through benefit of a tax deductible make-whole premium thatan Idaho Power paidpostretirement medical plan that are not expected to recur.

The $7.7 million increase in connection with the early redemption of long-term debt in April 2018 decreased Idaho Power's income tax expense by $7.0 million in 2018. Idaho Power recorded $2.0 million of income tax expense in 2017 for the initial remeasurement of deferred taxes resulting from the federal and Idaho income tax rate change. Excluding these items, Idaho Power income tax expense was $23.9 million lower during 2018in 2021 compared with 2017,2020 was primarily due mostly to the lower federalgreater 2021 pre-tax income and state statutoryother plant-related income tax rates resulting from income tax reform.return adjustments.


20182022 Initiatives and Strategy


IDACORP’s strategy is focused on four areas: growing to enhance financial strength, improving Idaho Power's core business, enhancing Idaho Power’s brand, and focusing on safetykeeping employees safe and employee engagement.engaged. IDACORP's board of directors has reviewed and affirmed IDACORP’s long-term strategy. In executing on these four strategic focus areas,cornerstones, IDACORP seeks to balance the interests of shareowners, Idaho Power customers, employees, and other stakeholders. Idaho Power is committed to working to continuefor strong, sustainable financial results by continuing to provide safe, fair-priced, reliable, serviceaffordable, clean energy to its customers from a diversified source of generation resources, with a continued commitment to strong, sustainable financial results. For more information on the business strategy of the companies, see Part I, Item 1 – “Business - Business Strategy” in this report.resources.


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:


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

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 in capital expenditures from 2022 through 2025 for resource additions to help meet the projected 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. 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 priceprices 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
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allow Idaho Power an opportunity to recover its expenses and earn a reasonable return on investment. Idaho Power focuses on timely recovery of its costs through filings with its regulators, working to put in place innovative regulatory mechanisms, and on the prudent management of expenses and investments. Idaho Power has a regulatory settlement stipulationsstipulation in Idaho that includeincludes provisions for the accelerated amortization of certain tax credits to help achieve a minimum 9.59.4 percent (9.4 percent after 2019)Idaho-jurisdiction return on year-end equity in the Idaho jurisdiction (Idaho ROE). The settlement stipulationsstipulation also provideprovides for the potential sharing between Idaho Power and its Idaho customers of Idaho-jurisdictional earnings in excess of specified levels10.0 percent of Idaho ROE. The settlement stipulations provide for modifications of certain terms andstipulation has no expiration date but the indefinite extensionminimum Idaho ROE would revert back to 95 percent of the mechanism beyondallowed return on equity in the original termination date of December 31, 2019.next general rate case. The specific terms of thesethe settlement stipulationsstipulation are described in "Regulatory Matters" in this MD&A and in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report. During
TableWith 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 Contents

2019,capital expenditures Idaho Power has made since its last general rate case filed in 2011, will continueincrease and potentially accelerate Idaho Power’s need to assess the needfile general rate cases. In Idaho, Idaho Power is required to file a notice of its intent to file a general rate case to reset base rates, but does not anticipatewith the IPUC at least 60 days before filing an application for a general rate case, and Idaho Power expects the processing of a general rate case in the next twelveIdaho 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.


Income Tax Reform: In December 2017, the Tax Cuts and Jobs Act was signed into law, which lowered the corporate federal income tax rate from 35 percent to 21 percent and modified or eliminated certain federal income tax deductions for corporations (Tax Cuts and Jobs Act). The majority of the changes, including the rate reduction, became effective on January 1, 2018. In March 2018, Idaho House Bill 463 was signed into law reducing the Idaho state corporate income tax rate from 7.4 percent to 6.925 percent. In May 2018, the IPUC issued an order approving a settlement stipulation related to these changes in income taxes (May 2018 Idaho Tax Reform Settlement Stipulation). Beginning June 1, 2018, the settlement stipulation provided an annual (a) $18.7 million reduction to Idaho customer base rates and (b) $7.4 million for the amortization of regulatory deferrals that would otherwise be a future liability recoverable from Idaho customers. Additionally, a one-time benefit of a $7.8 million rate reduction is being provided to Idaho customers through the PCA mechanism during the period from June 2018 through May 2019, for the income tax reform benefits accrued from January 2018 to May 2018 and for amounts included in Idaho Power's transmission revenues. The May 2018 Idaho Tax Reform Settlement Stipulation was designed to return to Idaho customers their share of the estimated annual pro forma tax expense reductions resulting from income tax reform, based on the full-year 2017 as required by the IPUC. Idaho Power's financial results from 2018 forward will be affected by any differences between annual income tax expense and the pro forma 2017 income tax expense used in the settlement until incorporated into a future rate proceeding or rate case. Refer to "Regulatory Matters" in this MD&A for more information on the related regulatory proceedings.

•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 2018,2021, Idaho Power's customer count grew by 2.3 percent, and employment2.8 percent. Idaho Power set a new all-time system peak demand of 3,751 MW on June 30, 2021, exceeding the previous high of 3,422 MW set on July 7, 2017. The previous peak demand from July 2017 was exceeded multiple times during the heat wave in Idaho Power's service area grew by approximately 2.2 percent based on Idaho Departmentin June and July of Labor preliminary December 2018 data. 2021. Idaho Power expects its number of customers to continue to increase in the foreseeable future. Idaho Power hasalso expects that existing and sustained growth in recent years supported State of Idaho-coordinated efforts to promote economic development with an emphasis on attracting industrialcustomers and commercial customers to its service area.

In August 2018,peak demand for electricity will require Idaho Power began preparingto continue to enhance its 2019 Integrated Resource Plan (IRP),capacity resources, transmission, and distribution infrastructure, including the Boardman-to-Hemingway and Gateway West transmission projects. That growth has resulted in the need for Idaho Power to procure additional new sources of energy and capacity to serve growing demand and to maintain system reliability, as noted above. Further, recent changes in the regional transmission markets have constrained the transmission system external to Idaho Power's long-term forecast of loadsservice area and resources. For more information onimpacted Idaho Power's ability to import energy from energy markets in the 2019 IRP, including the preliminarywestern United States during peak load forecast assumptions Idaho Power expects to use in its 2019 IRP, refer to "Resource Planning" in Item 1 - "Business" in this Form 10-K.periods.


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


Further, as Idaho Power's hydroelectrichydropower facilities comprise approximatelyover one-half of Idaho Power's nameplate generation capacity, precipitation levels impact the mix of Idaho Power's generation resources. When hydroelectrichydropower generation is reduced,decreases, Idaho Power must rely on more expensive generation sources and purchased power. When favorable hydroelectrichydropower generating conditions exist for Idaho Power, they also may exist for other Pacific Northwest hydroelectrichydropower facility operators, lowering regional wholesale market prices and impacting the revenue Idaho Power receives from wholesale energy sales of its excess power.sales. Much of the adverse or favorable impact of this volatility is addressed through the Idaho and Oregon power cost adjustment mechanisms.

Rate Base Growth For 2022, due to relatively low reservoir storage carryover combined with current and Infrastructure Investment: As noted above, the rates established by the IPUC and OPUC are determined with the intent to provide an opportunity forforecasted snowpack conditions, Idaho Power expects generation from its hydropower resources to recover authorized operating expenses and earn a reasonable return on “rate base.” Rate base is generally determined by referencebe in the range of 5.5 to 7.5 million MWh, compared with average total annual hydropower generation of approximately 7.7 million MWh over the original cost (net of accumulated depreciation) of utility plant in service and certain other assets, subject to various adjustments for deferred taxes and other items. Over time, rate base is increased by additions to utility plant in service and reduced by depreciation and retirement of utility plant and write-offs as authorized by the IPUC and OPUC. In recent years, Idaholast 30 years.

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Power has been pursuing significant enhancements to its utility infrastructure in an effort to maintain system reliability, ensure an adequate supply of electricity, and to provide service to new customers, including major ongoing transmission projects such as the Boardman-to-Hemingway and Gateway West projects. Idaho Power's existing hydroelectric and thermal generation facilities also require continuing upgrades and equipment replacement, and the company is undertaking a significant relicensing effort for the HCC, its largest hydroelectric 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.

•Mitigation of Impact of Fuel and Purchased Power Expense: In addition to hydroelectrichydropower generation, Idaho Power relies heavilysignificantly on natural gas and coal to fuel its generation facilities and on power purchases in the wholesale markets. Fuel costs are impacted by electricity sales volumes, the terms and conditions of contracts for fuel, Idaho Power's generation capacity, the availability of hydroelectrichydropower generation resources, transmission capacity, energy market prices, and Idaho Power's hedging program for managing fuel costs. Recently, low natural gas prices have made operation of Idaho Power's natural gas power plants more economical, resulting in increased operation of those plants and decreased operation of coal-fired plants. 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, and wholesale energy market prices. The Idaho and Oregon power cost adjustment mechanisms mitigate in large part the potential adverse impacts to Idaho Power of fluctuations in power supply costs to Idaho Power.
costs.


•Regulatory and Environmental Compliance Costs: Idaho Power is subject to extensive federal and state laws, policies, and regulations, as well as regulatory actions and audits by agencies and quasi-governmental agencies, including the FERC, the North American Electric Reliability Corporation, and the Western Electricity Coordinating Council. Compliance with these requirements directly influences Idaho Power's operating environment and affects Idaho Power's operating costs. Recently, energyEnergy industry regulators have issuedmay 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, and constructing new facilities,may require that Idaho Power install additional pollution control devices at existing generating plants, or may require that Idaho Power cease operating certain generation plants. Idaho Power expects to spend a considerable amountsignificant amounts on environmental compliance and controls in the next decade, and duedecade. Due to economic factors in part associated with the costs of compliance with environmental regulation, hasIdaho Power accelerated the retirement dates of certaindate of its jointly-owned coal-fired power plants.
generating plant in Valmy, Nevada (Valmy), ceasing operations at one unit in 2019. In 2021, the IPUC acknowledged that Idaho Power's year-end 2025 exit date from Valmy unit 2 is appropriate based on economics and reliability needs. 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 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 the "Regulatory Matters" section of this MD&A.
 
•Water Management and Relicensing of the Hells Canyon Hydroelectric Project: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 hydroelectrichydropower projects. Also, Idaho Power is involved in renewing its long-term federal licenselicenses for the HCC, its largest hydroelectrichydropower generation source, and for American Falls, its second largest hydropower generation source. Given the number of parties and issues involved, Idaho Power's relicensing costs have been and are expected to continue to be substantial. Idaho Power cannot currently determine the ultimate terms of, and costs associated with, any resulting long-term license.
licenses for the HCC or American Falls 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-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. Idaho Power has adopted a Wildfire Mitigation Plan (WMP) that outlines actions Idaho Power is taking or is working to implement in the future to reduce wildfire risk and to strengthen the resiliency of its transmission and distribution system to wildfires. Idaho Power's approach to achieve these objectives includes identifying areas subject to elevated risk; system hardening programs, vegetation management, and field personnel practices to mitigate wildfire risk; incorporating current and forecasted weather and field conditions into operational practices; public safety power shutoff protocols; and evaluating the performance and effectiveness of the strategies identified in the WMP through metrics and monitoring. In June 2021, the IPUC authorized Idaho Power to defer, for future amortization, the Idaho jurisdictional share of actual incremental O&M expenses and depreciation expense of certain capital investments necessary to implement the WMP. The WMP case with the IPUC is described in more detail in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.


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RESULTS OF OPERATIONS
 
This section of MD&A takes a closer look at the significant factors that affected IDACORP’s and Idaho Power’s earnings. In this analysis, the results for 20182021 are compared with 2017 and the results for 2017 are compared with 2016.2020.
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The table below presents Idaho Power’s energy sales and supply (in thousands of MWh) for the last threetwo years.
Year Ended December 31,
 20212020
Retail energy sales15,406 14,828 
Wholesale energy sales600 1,197 
Energy sales bundled with renewable energy credits739 690 
Total energy sales16,745 16,715 
Hydropower generation5,382 6,967 
Coal generation2,981 3,719 
Natural gas and other generation2,765 2,109 
Total system generation11,128 12,795 
Purchased power6,823 5,072 
Line losses(1,206)(1,152)
Total energy supply16,745 16,715 
  Year Ended December 31,
  2018 2017 2016
Retail energy sales 14,587
 14,571
 14,196
Wholesale energy sales 2,246
 1,934
 742
Bundled energy sales 617
 202
 444
Total energy sales 17,450
 16,707
 15,382
Hydroelectric generation 8,682
 8,900
 6,408
Coal generation 3,274
 3,284
 4,045
Natural gas and other generation 1,408
 1,504
 1,722
Total system generation 13,364
 13,688
 12,175
Purchased power 5,431
 4,242
 4,337
Line losses (1,345) (1,223) (1,130)
Total energy supply 17,450
 16,707
 15,382


For purposes of illustration, Boise, Idaho, weather-related information for the last threetwo years is presented in the table that follows.
 Year Ended December 31,  Year Ended December 31,
 2018 2017 2016 
Normal(2)
20212020
Normal(2)
Heating degree-days(1)
 4,984
 5,655
 4,807
 5,514
Heating degree-days(1)
4,856 4,999 5,516 
Cooling degree-days(1)
 1,116
 1,341
 1,001
 942
Cooling degree-days(1)
1,393 1,087 941 
Precipitation (inches) 10.6
 15.4
 8.7
 11.3
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 2018,2021, retail sales volumes were relatively flatincreased 4 percent compared with those of the prior year. Customeryear, primarily due to growth increased sales volumes during 2018 compared with 2017, within 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 growing by 2.3 percent.to use 6 percent more energy per customer to operate irrigation pumps during 2021 compared with 2020. During 2018,2021, usage per irrigationcommercial and industrial customer was approximately 93 percent higher compared with 2017. Precipitation in the Idaho Power service area during 2018prior year, due to a return to more normal economic activity compared with 2020, which was significantly less than in 2017, which increased usageaffected by irrigation customers in 2018.negative COVID-19-related business conditions. Usage per residential customer was approximately 61 percent lowerhigher in 2018 compared with 2017. The decrease in residential usage2021 than 2020, which was primarily due to milder weather during 2018 compared with 2017, which decreasedvariations that caused residential customers to use more energy for cooling in the use of electricity for heatingspring and cooling purposes.early summer, but less energy from August through December. Cooling degree-days in Boise, Idaho were 1728 percent higher during 2021 compared with 2020 and 48 percent above normal. Also, heating degree-days were 3 percent lower during 20182021 compared with 2017, but 18 percent above normal. Heating degree-days in Boise, Idaho were2020 and 12 percent lower than normal.

Wholesale energy sales volumes decreased 0.6 million MWh, or 50 percent, during 20182021 compared with 2017,2020, as lower system generation and 10 percent below normal. Also, bundledhigher retail sales volumes led to less energy sales (electric power combined with renewable energy certificates) volumes increased during 2018 compared with 2017. The solar generation projects under PURPA contracts that were initiated in 2017 generated an increased number of renewable energy credits to sell bundled with electricity.available for opportunistic market sales.


Total system generation decreased 213 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 20182021 compared with 2017. Hydroelectric2020, due primarily to lower reservoir storage carryover and weaker snowpack in the Snake River Basin. Coal-fired generation also decreased 220 percent during 2018 compared with 2017, but comprised 65 percent of Idaho Power's total system generation during both 2018 and 2017. In 2018, purchased power increased 28 percent compared with 20172021, due to an increase inmostly to economic displacement by power purchased from generation projects under mandatory PURPA contracts and an increasethe energy imbalance market in other purchased power resulting from favorable wholesale gas and electricity market conditionsthe western United States (Western EIM) and to a lesser extent transactions indue to the Western EIM, which commenced in
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April 2018. The availability of hydroelectric generation and an increase in purchased power during 2018 reduced thermal generation compared with 2017.

Wholesale energy sales volumes increased 312 thousand MWh, or 16 percent, during 2018 compared with 2017, due primarily to an increase in purchased power, both in market purchases and in purchases under PURPA contracts, resulting in increased energy available for wholesale energy sales. However, the high purchase price of power under federally mandated PURPA purchases is often in excessOctober 2020 closure of the price at which Idaho Power sellscoal-fired generation plant in Boardman, Oregon. Natural gas generation increased 31 percent due mostly to the powerdecrease in the wholesale energy markets.hydropower and coal-fired generation.


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 table below presents Idaho Power’s retail revenues (in thousands), MWh sales (in thousands), and number of customers for the last threetwo years.
 Year Ended December 31,Year Ended December 31,
 2018 2017 2016 20212020
Retail revenues:  
  
  Retail revenues:  
Residential (includes $34,625, $17,320, and $29,170, respectively, related to the FCA(1))
 $530,527
 $552,333
 $514,954
Commercial (includes $1,299, $876, and $1,087, respectively, related to the FCA(1))
 310,299
 319,195
 302,650
Residential (includes $34,835 and $34,409, respectively, related to the FCA(1))
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))
Commercial (includes $1,407 and $1,543, respectively, related to the FCA(1))
314,745 293,057 
Industrial 190,130
 195,124
 182,590
Industrial195,214 181,258 
Irrigation 158,001
 150,030
 156,505
Irrigation168,664 154,791 
Provision for sharing (5,025) —
 —
Provision for sharing(569)— 
Deferred revenue related to HCC relicensing AFUDC(2)
 (8,780) (10,706) (10,706)
Deferred revenue related to HCC relicensing AFUDC(2)
(8,780)(8,780)
Total retail revenues $1,175,152
 $1,205,976
 $1,145,993
Total retail revenues$1,252,335 $1,167,730 
Volume of Sales (MWh)  
  
  Volume of Sales (MWh)  
Residential 5,135
 5,355
 5,004
Residential5,645 5,463 
Commercial 4,105
 4,099
 3,999
Commercial4,164 4,009 
Industrial 3,371
 3,346
 3,243
Industrial3,471 3,369 
Irrigation 1,976
 1,771
 1,950
Irrigation2,126 1,987 
Total retail MWh sales 14,587
 14,571
 14,196
Total retail MWh sales15,406 14,828 
Number of retail customers at year-end  
  
  Number of retail customers at year-end  
Residential 464,670
 453,605
 444,431
Residential505,774 491,229 
Commercial 71,680
 70,411
 69,344
Commercial76,022 74,409 
Industrial 120
 119
 121
Industrial125 126 
Irrigation 21,175
 20,932
 20,638
Irrigation21,832 21,594 
Total customers 557,645
 545,067
 534,534
Total customers603,753 587,358 
      
(1) The FCA mechanism is an alternative revenue program and does not represent revenue from contracts with customers.
(2) As part of its January 30, 2009, general rate case order, theThe IPUC is allowingallows Idaho Power to recover a portion of the allowance for funds used during construction (AFUDC) on construction work in progress related to the HCC relicensing process, even though the relicensing process is not yet complete and the costs have not been moved to electric plant in service. Idaho Power is collecting approximately $8.8 million annually in the Idaho jurisdiction but is deferring revenue recognition of the amounts collected until the license is issued and the accumulated license costs approved for recovery are placed in service. Prior to the May 2018 Idaho Tax Reform Settlement Stipulation described in "Regulatory Matters" in this MD&A, Idaho Power was collecting $10.7 million annually.


Changes in rates, changes in customer demand, and changes in FCA mechanism revenues are the primary reasons for fluctuations in retail revenues from period to period. See "Regulatory Matters" in this MD&A for a list of rate changes implemented over the last threetwo 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
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based on higher levels of usage. The seasonal and tiered rate structures contribute to seasonal fluctuations in revenues and earnings.


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Retail Revenues - 2018 Compared with 2017: Retail revenues decreased $30.8increased $84.6 million in 20182021 compared with 2017.2020. The primary factors affecting retail revenues during the period were the following:


•Rates: Rate changesCustomer rates, excluding collections of amounts related to the power cost adjustment mechanisms, decreased retail revenues by $39.0$6.4 million in 20182021 compared with 2017. As a direct result2020. 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 settlement stipulations approved byall Boardman power plant investments after ceasing coal-fired operations at the IPUC and OPUC during the second quarter of 2018 relating to income tax reform described furtherBoardman power plant in "Regulatory Matters" in this MD&A, Idaho Power's revenues decreased approximately $22 million in 2018 compared with 2017. The timing of the revenue reductions may not align with decreases in income tax expense in any given period due to the method and timing of customer rate reductions provided for in the settlement stipulations, the nature and timing of income tax accruals, discrete items, and other items discussed in this MD&A. TheOctober 2020. Customer rates also include collection of amountsadjustments related to the PCA mechanism, which decreasedincreased revenues by $15.4$42.0 million in 20182021 compared with 2017.2020. The collection of amountsadjustments related to the PCA mechanism in rates has nodo not have a significant effect on operating income as a corresponding amount is recorded asin expense in the same period it is collected through rates.
period.


•Customers: Customer growth of 2.32.8 percent increased retail revenues by $13.5$22.0 million in 20182021 compared with 2017.
2020.


•Usage: LowerHigher usage (on a per customer basis), primarily by residential customers, decreasedin all customer classes, increased retail revenues by $18.0$27.2 million during 20182021 compared with 2017. Decreased usage was primarily the result of more mild temperatures2020. Less precipitation in Idaho Power's service area during 2018the spring and early summer of 2021 compared with 2017, whichthe same time period in 2020 led agricultural irrigation customers to decreaseduse 6 percent more 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 residential customers for heating and cooling. For 2018,both customer classes approximately 3 percent on a 6 percent decrease in usageper-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 2017 was partially offset by a 92020, but less energy from August through December. Cooling degree-days in Boise, Idaho were 28 percent increasehigher during 2021 compared to 2020 and 48 percent above normal. Also, heating degree-days in usage per irrigation customer. Precipitation in Idaho Power's servicethat area were 3 percent lower during 2018 was significantly less2021 compared to 2020 and 12 percent lower than 2017, which led to increased usage by irrigation customers.
normal.


Idaho FCA Revenue: The FCA mechanism, applicable to Idaho residential and small commercial customers, adjusts revenue each year to accrue, or defer, the difference between the authorized fixed-cost recovery amount per customer and the actual fixed costs per customer recovered by Idaho Power through volume-based rates during the year. Lower usage (on a per customer basis) by residential and small general service customers during 2018 increased the amount of FCA revenue accrued by $17.7 million compared with 2017.

•Sharing: During 2018,2021, Idaho Power recorded $5.0$0.6 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 June 2019.2022. Idaho Power did not record any provision for sharing in 2017.2020. 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 October 2014May 2018 Idaho Earnings Support and SharingTax Reform Settlement Stipulation. The October 2014May 2018 Idaho Earnings Support and SharingTax Reform Settlement Stipulation is described further in "Regulatory Matters" in this MD&A and in Note 3 - "Regulatory-"Regulatory Matters" to the consolidated financial statements included in this report.


Retail Revenues - 2017 Compared with 2016: Retail revenues increased $60.0 million in 2017 compared with 2016. The factors affecting retail revenues during the period are discussed below:

Rates: Rate changes, including the revenue accruals provided for in the Valmy settlement stipulation, increased retail revenues by $39.8 million for 2017 compared with 2016. In the second quarter of 2017, the IPUC and OPUC each approved settlement stipulations related to Idaho Power’s plan to end its participation in coal-fired operations at the Valmy Plant by the end of 2025, which increased retail revenues collections and retail revenues accruals for 2017 compared with 2016. Colder winter temperatures in early 2017 and warmer summer temperatures during the third quarter of 2017 resulted in residential sales making up a larger portion of the sales mix and led to a greater proportion of residential sales in higher rate categories in Idaho Power's tiered rate structure in 2017 compared with 2016.

Customers: Customer growth of 2.0 percent increased retail revenues by $12.1 million in 2017 compared with 2016.

Usage: Higher usage (on a per customer basis), primarily by residential, industrial, and commercial customers increased retail revenues by $20.1 million in 2017 compared with 2016. Increased usage was primarily the result of warmer summer temperatures and colder winter temperatures in Idaho Power's service area, which increased usage by residential customers for cooling and heating. Cooling degree days and heating degree days were significantly higher in 2017 compared with 2016. These increases in usage were partially offset by an 11 percent decrease in usage per irrigation customer due to increased precipitation in Idaho Power's service area during 2017 compared with 2016,
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particularly in the first six months of 2017. Greater customer participation in energy efficiency programs, resulting in decreased usage, partially offset the increase in total usage during 2017 compared with 2016.

Idaho FCA Revenue: The FCA mechanism, applicable to Idaho residential and small commercial customers, adjusts revenue each year to accrue, or defer, the difference between the authorized fixed-cost recovery amount per customer and the actual fixed costs per customer recovered by Idaho Power through volume-based rates during the year. Higher usage (on a per customer basis) by residential and small general service customers during 2017 decreased the amount of FCA revenue accrued by $12.1 million compared with 2016. Idaho Power accrued $18.2 million of FCA revenue in 2017 compared with $30.3 million of FCA revenue in 2016.

Wholesale Energy Sales: Wholesale energy sales consist primarily of long-term sales contracts, opportunity sales of surplus system energy, and sales into the Western EIM,energy imbalance market in the western United States, and do not include derivative transactions. The table below presents Idaho Power’s wholesale energy sales for the last threetwo years (in thousands, except for MWh amounts). 
 Year Ended December 31,Year Ended December 31,
 2018 2017 2016 20212020
Wholesale energy revenues $52,845
 $24,790
 $11,900
Wholesale energy revenues$40,839 $33,656 
Wholesale MWh sold 2,246
 1,934
 742
Wholesale MWh sold600 1,197 
Wholesale energy revenues per MWh $23.53
 $12.82
 $16.04
Wholesale energy revenues per MWh$68.07 $28.12 
 
Wholesale Energy Sales - 2018 Compared with 2017: In 2018,2021, wholesale energy revenue increased by $28.1$7.2 million, or 11321 percent, compared with 2017.2020, as higher average wholesale energy prices more than offset a decrease in volumes sold. Wholesale energy prices were higher compared with 2020 as extreme summer weather resulted in higher demand and lower supply of energy to the wholesale markets in the region. Wholesale energy sales volumes increased 16decreased 50 percent in 20182021 compared with 2017,2020, as lower system generation and the average price of wholesale energyhigher retail sales was 84 percent higher for 2018 compared with 2017. During the fourth quarter of 2018, a natural gas pipeline ruptured in British Columbia, Canada, disrupting natural gas flowsvolumes led to the Pacific Northwest and Western Canada, driving up energy and natural gas prices in the region, including in Idaho Power's service area. An increase in purchased power, both in market purchases and in purchases under PURPA contracts, resulted in additionalless energy available for wholesale energy salesopportunistic market sales.

Transmission Wheeling-Related Revenues: Revenue related to transmission wheeling increased $16.4 million in 20182021 compared with 2017. However, the high purchase price of power under federally mandated PURPA purchases is often in excess of the price at which Idaho Power sells the power2020, as warmer, drier spring and summer weather in the wholesale energy markets. The increase in wholesale energy sales volumes and sales prices during 2018 comparedwestern United States, along with 2017 was also due to transactions in the Western EIM, which commencedtwo new long-term wheeling agreements that began in April 2018. Under the Western EIM, participating parties enable their systems to interact for automated intra-hour economic dispatch of generation from committed resources to serve loads.

Wholesale Energy Sales - 2017 Compared with 2016: For 2017, wholesale energy sales revenue2021, increased by $12.9 million, or 108 percent compared with 2016 as generation fromwheeling volumes. In addition, Idaho Power's hydroelectric plantsOATT rates increased due to significantly greater precipitation in 2017 compared with 2016. The increase in hydroelectric generation resulted in more energy available for wholesale energy sales in 2017 compared with 2016. The average price of wholesale energy sales was 20approximately 10 percent lower for 2017 compared with 2016, as an increase in output from hydroelectric resources in the northwest United States region due to increased precipitation during the period as well as additional output from new wind and solar projects throughout the region, increased surplus power available for sale and decreased wholesale power market prices.

Transmission Wheeling Revenues: Revenue from transmission wheeling increased $15.1 million, or 34 percent, in 2018October 1, 2020, to September 30, 2021, as compared with 2017, largely duethe rates in effect from October 1, 2019, to Idaho Power's OATT rate that increased in October 2017 and, to a lesser extent, an increase in wheeling volumes. In October 2017,September 30, 2020. Also, Idaho Power's OATT rate increased from $25.52 per kW-year to $34.90 per kW-year. In4 percent in October 2018, the rate decreased to $31.25 per kW-year.2021. Refer to "Regulatory Matters" in this MD&A for more information on Idaho Power's OATT rate. Revenue from transmission wheeling increased $11.5 million, or 35 percent, in 2017 compared with 2016, largely due to an increase in wheeling volumes, an increase in Idaho Power's OATT rate, and a new long-term wheeling agreement that became effective in July 2016.

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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, 2018,2021, Idaho Power's energy efficiency rider balances were a $5.3$6.9 million regulatory liabilityasset in the Idaho jurisdiction and a $1.4$0.7 million regulatory asset 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.


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Operating Expenses


Purchased Power: The table below presents Idaho Power’s purchased power expenses and volumes for the last threetwo years (in thousands, except for 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 
  Year Ended December 31,
  2018 2017 2016
Expense      
PURPA contracts $189,722
 $169,788
 $153,665
Other purchased power (including wheeling) 104,092
 79,162
 92,099
Total purchased power expense $293,814
 $248,950
 $245,764
MWh purchased      
PURPA contracts 3,045
 2,800
 2,314
Other purchased power 2,386
 1,442
 2,023
Total MWh purchased 5,431
 4,242
 4,337
Cost per MWh from PURPA contracts $62.31
 $60.64
 $66.41
Cost per MWh from other sources $43.63
 $54.90
 $45.53
 Weighted average - all sources $54.10
 $58.69
 $56.67


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 hydroelectrichydropower and fossil fuel-fired generation resources and may be required to sell its excess power in the wholesale power market at a significant loss. TheAlthough 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.


Purchased Power - 2018 Compared with 2017: Purchased power expense increased $44.9$96.3 million, or 1832 percent, in 20182021 compared with 2017,2020. The increase was primarily due to a 6591 percent increase in the volume of other non-PURPA power purchases and a 9 percent increase in the volume of power purchases from generation projects under PURPA contracts. Other purchased power volumes increased during 2018 compared with 2017 due to wholesale gas and electricity market conditions and due to transactions in the Western EIM, which commenced in April 2018. These volume increases were partially offset by decreases in cost per MWh of power purchased from sources other than PURPA contracts.

Purchased Power - 2017 Compared with 2016: Purchasedcontracts as power expense increased $3.2 million, or 1 percent,purchased from the Western EIM economically displaced coal-fired generation at greater volumes in 20172021 compared with 2016, primarily due to an increase in generation provided by PURPA solar contracts. The increase in PURPA volumes was partially offset by decreases in costs per MWh. Other purchased power expense decreased $12.9 million, or 14 percent, as abundant hydroelectric generation in 2017 compared with 2016 reduced the need for market purchases to meet load requirements.2020.


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Fuel Expense: The table below presents Idaho Power’s fuel expenses and thermal generation for the last threetwo years (in thousands, except per MWh amounts).
 Year Ended December 31,Year Ended December 31,
 2018 2017 2016 20212020
Expense  
  
  Expense  
Coal $115,524
 $107,894
 $137,689
Coal$95,324 $119,678 
Natural gas(1)
 17,674
 37,935
 41,802
Natural gas(1)
85,226 53,062 
Total fuel expense $133,198
 $145,829
 $179,491
Total fuel expense$180,550 $172,740 
MWh generated  
  
  MWh generated  
Coal 3,274
 3,284
 4,045
Coal2,981 3,719 
Natural gas(1)
 1,408
 1,504
 1,722
Natural gas(1)
2,765 2,109 
Total MWh generated 4,682
 4,788
 5,767
Total MWh generated5,746 5,828 
Cost per MWh - Coal $35.29
 $32.85
 $34.04
Cost per MWh - Coal$31.98 $32.18 
Cost per MWh - Natural gas $12.55
 $25.22
 $24.28
Cost per MWh - Natural gas$30.82 $25.16 
Weighted average, all sources $28.45
 $30.46
 $31.12
Weighted average, all sources$31.42 $29.64 
      
(1) Includes a negligible amount of expense and generation related to the Salmon diesel-fired generation plant.


The majority of the fuel for Idaho Power’s jointly-owned coal-fired plants is purchased through long-term contracts, including purchases from BCC, a one-third owned joint venture of IERCo. The price of coal from BCC is subject to fluctuations in mine operating expenses, geologic conditions, and production levels. BCC supplies up to two-thirds of the coal used by the Jim Bridger plant. Natural gas is mainly purchased on the regional wholesale spot market at published index prices. In addition to commodity (variable) costs, both natural gas and coal 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 - 2018 Compared with 2017: Fuel expense decreased $12.6increased $7.8 million, or 95 percent, in 20182021 compared with 2017. In October 2018,2020, primarily due to a 31 percent increase in natural gas pipeline rupturedgeneration and a 22 percent increase in British Columbia, Canada, which disruptedthe average cost per natural gas distributionMWh generated primarily from higher natural gas market prices. These increases were partially offset by a decrease in coal-fired generation due to economic displacement by power purchased from the Pacific Northwest regionWestern EIM.

Included in fuel expense are losses and Western Canada, and drove up energy prices in the region. In accordance with its ongoing risk management policies, Idaho Power held a number ofgains on settled financial gas hedges at the time of the rupture. Fuel expenseentered into in the fourth quarter of 2018 included $23.3 million inaccordance with Idaho Power's energy risk management policy. In 2021, gains on financial gas hedges whichof $12.1 million reduced natural gas fuel expense. Idaho Power was able to meetexpense, while in 2020, losses on financial gas hedges of $4.8 million increased natural gas needs by purchasing physical gas from sources unaffected by the rupture.fuel expense. Most of these realized hedging gains will be a benefitand losses are passed on to customers through the power cost adjustment mechanisms described below.


Fuel Expense - 2017 Compared with 2016: Fuel expense decreased $33.7 million, or 19 percent, in 2017 compared with 2016, due primarily to increased output from Idaho Power's hydroelectric plants, which reduced utilization of gas and coal generation. Generation from the hydroelectric plants increased 39 percent during 2017 compared with 2016.

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 hydroelectrichydropower 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. Because of the power cost adjustment mechanisms, the primary financial impacts of power supply cost variations is that cash is paid out but recovery from customers does not occur until a future period, or cash that is collected is refunded to customers in a future period, resulting in fluctuations in operating cash flows from year to year.


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The table below presents the components of the Idaho and Oregon power cost adjustment mechanisms for the last threetwo years (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)
  Year Ended December 31,
  2018 2017 2016
Power supply cost accrual (deferral) $41,535
 $14,658
 $(43,841)
Amortization of prior year authorized balances 571
 37,366
 38,511
Total power cost adjustment expense $42,106
 $52,024
 $(5,330)


The power supply (deferrals) accruals represent the portion of the power supply cost fluctuations (deferred) accrued under the power cost adjustment mechanisms. When actual power supply costs are lower than the amount forecasted in power cost adjustment rates, which was the case for 2018 and 2017, most of the difference is accrued.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, which was the case for 2016, most of the difference is deferred.deferred as an increase to a regulatory asset or decrease to a regulatory liability. During 2021, higher purchased power costs led to higher actual power supply costs compared with the forecasted amount, which resulted in a significant increase in the amount of power supply costs deferred by the mechanism. 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).
Power Cost Adjustment Mechanisms - 2018 Compared with 2017: Actual net power supply costs decreased in 2018 relative to forecasted costs, resulting in a change of $26.9 million—from accruals of $14.7 million to accruals of $41.5 million. The increase in accruals is due in part to lower natural gas fuel costs and purchased power, as explained above, combined with more surplus sales than forecasted. In addition, Idaho Power recorded $0.6 million of amortization of the prior-year authorized balances in 2018, compared with $37.4 million of amortization in 2017.

Power Cost Adjustment Mechanisms - 2017 Compared with 2016: Actual net power supply costs decreased in 2017 relative to forecasted costs, resulting in a change of $58.5 million—from deferrals of $43.8 million to accruals of $14.7 million. The change from deferrals in 2016 to accruals in 2017 is due in part to the lower fuel costs and purchased power, combined with more surplus sales than forecasted. The $37.4 million of amortization of prior year authorized balances in 2017 offsets the collection from customers of prior years' deferrals.

Other Operations and Maintenance Expenses: The changes in other O&M expenses for the periods presented are discussed below.

O&M - 2018 Compared with 2017: Other O&M expenses increased $17.8$9.2 million, or 53 percent, in 20182021 compared with 2017. As provided2020, primarily due to a return to more normal levels of purchased services and maintenance costs compared with 2020, which was affected by the settlement stipulation approved byCOVID-19 public health crisis. In 2020, the IPUC relatedresponse to recent income tax reform,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 2018 also included $4.0 million of non-cash amortization expense of regulatory deferrals that would otherwise be a future liability of Idaho customers. In 2018,2021, compared with 2017, higher maintenance service costs led to a $4.2 million increase in transmission and distribution asset maintenance expenses, and higher variable employee-related costs led to an $8.4 million increase in labor and benefit expenses.2020.
O&M - 2017 Compared with 2016: Other O&M expense decreased by $2.2 million in 2017 compared with 2016, primarily due to a $2.4 million decrease related to previously expensed energy efficiency rider-funded costs deemed to be prudently incurred and a $2.7 million decrease in thermal O&M expenses due to lower generation at thermal plants. These decreases in O&M were partially offset by a $2.5 million increase in O&M related to a settlement stipulation in Idaho that established the reasonableness of the HCC relicensing costs incurred through December 2015 as further discussed in "Regulatory Matters" in this MD&A.


Income Taxes


IDACORP's and Idaho Power's 2018 income tax expense decreased $31.3 million and $33.0 million, respectively, when
compared with 2017. The decrease was primarily due to: (1) the Tax Cut and Jobs Act’s reduction of the federal corporate tax rate from 35 percent to 21 percent that became effective January 1, 2018, (2) the remeasurement of deferred income tax balances related to IDACORP’s 2017 consolidated income tax return filings, and (3) a flow-through income tax benefit at Idaho Power related to the tax deduction for a bond make-whole premium that was paid in 2018.

IDACORP's and Idaho Power's 20172021 income tax expense increased $12.2$8.2 million and $14.1$7.7 million, respectively, when
compared with 2016.2020. The increase wasincreases were primarily due to higher pre-tax earnings at Idaho Power in 2017, and the $5.6 million
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flow-through benefit of a tax deductible make-whole premium that Idaho Power paid in connection with the early redemption of long-term debt in 2016. There were no early redemptions of long-term debt in 2017. These increases inother plant-related income tax expense
were partially offset by greater net flow-through income tax itemsreturn adjustments at Idaho Power.

For additional information relating to IDACORP's and Idaho Power's income taxes, the effects of the Tax Cuts and Jobs Act, and the availability of tax credit carryforwards, 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 hydroelectrichydropower and thermal generation facilities also require continuing upgrades and component replacement. Idaho Power's cashCash capital expenditures, for property, plant, and equipment, excluding AFUDC and excluding net costs of removing assets from service, were $268$288 million in 2018, $2772021 and $299 million in 2017, and $287 million in 2016.2020. Idaho Power expects these substantialan increase in capital expenditures to continue,over the next several years, with estimated total capital expenditures of approximately $1.5up to $2.8 billion expected over the period from 20192022 through 2023.2026.


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 15, 2019,11, 2022, IDACORP's and Idaho Power's access to debt, equity, and credit arrangements included:


•their respective $100 million and $300 million revolving credit facilities;facilities (Credit Facilities);
•IDACORP's shelf registration statement filed with the SECU.S. Securities and Exchange Commission (SEC) on May 20, 2016,17, 2019, which may be used for the issuance of debt securities and common stock;
•Idaho Power's shelf registration statement filed with the SEC on May 20, 2016,17, 2019, which may be used for the issuance of first mortgage bonds and debt securities; $280$190 million is available for issuance pursuant to state regulatory authority; and
•IDACORP's and Idaho Power's issuance of commercial paper, which may be issued up to an amount equal to the available credit capacity under their respective credit facilities.Credit Facilities.


Based on planned capital expenditures and operating and maintenance expenses for 2019, the companies believe they will be able to meet capital requirements and fund corporate expenses during 2019 with a combination
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Table of existing cash and operating cash flows generated by Idaho Power's utility business, together with proceeds from either draws on credit facilities or Idaho Power's issuance of debt securities. IDACORP and Idaho Power believe they could meet any short-term cash shortfall with existing credit facilities and expect to continue to manage short-term liquidity through commercial paper markets.Contents

IDACORP and Idaho Power monitor capital markets with a view toward opportunistic debt and equity transactions, taking into account current and potential future long-term needs. As a result, IDACORP may issue debt securities or common stock, and Idaho Power may issue debt securities, 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. To that end, in March 2018, Idaho Power issued $220 million in principal amount

Based on planned capital expenditures and O&M expenses, the companies believe they will be able to meet capital and debt service requirements and fund corporate expenses during the next twelve months with a combination of 4.20% first mortgage bonds, Series K, maturing on March 1, 2048. In April 2018, Idaho Power redeemed, prior to its maturity, its $130 million in principal amount of 4.50% first mortgage bonds, Series H, due March 2020. In accordance with the redemption provisions of the original terms of the notes, the redemption includedexisting cash, operating cash flows generated by Idaho Power's payment of a make-whole premium of $4.6 million, the cost of which provided a flow-through tax deduction. Idaho Power used a portion of the net proceeds of the March 2018 sale of first mortgage bonds, medium term-notesutility business, availability under existing Credit Facilities, and access to effect the redemption.commercial paper and long-term debt markets.


IDACORP and Idaho Power seek to maintain capital structures of approximately 50 percent debt and 50 percent equity, and maintaining this ratio influences IDACORP's and Idaho Power's debt and equity issuance decisions. As of December 31, 2018,2021, IDACORP's and Idaho Power's capital structures, as calculated for purposes of applicable debt covenants, were as follows:
IDACORPIdaho Power
Debt43%45%
Equity57%55%
  IDACORP Idaho Power
Debt 44% 46%
Equity 56% 54%
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IDACORP and Idaho Power generally maintain their cash and cash equivalents in highly liquid investments, such as U.S. Treasury Bills, money market funds, and bank deposits. 


Operating Cash Flows
 
IDACORP's and Idaho Power's 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 pension 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 20182021 were $492$363 million and $418$323 million, respectively, an increasedecreases of $57$25 million and $30 million for IDACORP and a $1 million increase for Idaho Power, respectively, when compared with 2017.2020. Significant items that affected the companies' operating cash flows in 20182021 relative to 20172020 were as follows:
•an $8 million and a $14 million increase and $16$10 million increase in IDACORP and Idaho Power net income, respectively;
•changes in regulatory assets and liabilities, mostly related to the relative amounts of power supply and fixed costs accrued or deferred and refunded or collected under the Idaho ratePCA and energy efficiency program cost mechanisms, decreasedincreased operating cash inflows by $9$3 million;
•changes in deferred taxes and in taxes accrued and receivable combined to decrease cash flows by $22 millionIDACORP and increaseIdaho Power cash flows by $28 million at IDACORP and Idaho Power,$37 million, respectively; and
Idaho Power received $29 million of distributions from IERCo's investment in BCC for 2018, compared with $23 million in 2017. Changes in distributions from year to year are primarily driven by changes in the timing of cash needs associated with BCC; and
•changes in working capital balances due primarily to timing, including fluctuations in accounts receivable, accounts payable, other current assets, accounts payable, and other current liabilities, as follows:
◦timing of collections of accounts receivable balances increased
◦timing of collections of accounts receivable balances decreased operating cash flows by $6 million for Idaho Power. IDACORP collected an $8 million receivable in 2017 from a legal settlement, offsetting the increase in 2018;
◦the changes in other current assets increased cash flows by $10 million, which was primarily due to a decrease in fuel stock as an increase in coal-fired generation in the fourth quarter of 2018 compared with 2017 decreased the related coal inventory; and
◦timing of accounts payable payments increased operating cash flows by $47 million for IDACORP and decreased operating cash flows by $64 million for Idaho Power (the difference relates to the timing of estimated income tax payments from Idaho Power to IDACORP).

IDACORP's and Idaho Power's operating cash inflows in 2017 were $435 million and $417 million, respectively, an increase of $91 million for IDACORP and $110$3 million for Idaho Power when compared with 2016. Significant items that affected the companies'Power;
◦timing of accounts payable payments increased operating cash flows by $18 million for IDACORP and Idaho Power;
◦the changes in 2017 relative to 2016 were as follows:

a $15other current assets decreased operating cash flows by $13 million increase and $17 million increase infor IDACORP and Idaho Power, net income, respectively,which was primarily due to the timing of purchases and consumption of coal at Idaho Power's jointly-owned coal-fired generating plants, offset partially by fluctuations in the balance in accrued unbilled revenues; and
◦the changes in other current liabilities, which includes a $19 million increase in non-cash depreciationnon-incentive compensation, customer deposits, accrued interest, and amortization at both companies;
changes in regulatory assets andother miscellaneous liabilities, mostly related to the relative amounts of power supply and fixed costs deferred and collected under the Idaho rate mechanisms, increaseddecreased operating cash inflows by $63 million. The increase is mostly related to the relative amounts of power supply and fixed costs deferred and collected under the Idaho power cost adjustment and FCA mechanisms, partially offset by revenues accrued in excess of collections from the Valmy Plant settlement stipulation that will be collected in future periods;
changes in deferred taxes and in taxes accrued and receivable combined to increase cash flows by $1$5 million and decrease cash flows by $23 million atfor IDACORP and Idaho Power, respectively;Power.
changes in working capital balances due primarily to timing, including fluctuations in accounts receivable, other current assets, and accounts payable, as follows:
◦timing of collections of accounts receivable balances increased operating cash flows by $7 million for IDACORP and decreased operating cash flows by $6 million for Idaho Power. IDACORP collected an $8 million receivable in 2017 from a legal settlement;
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◦the changes in other current assets increased cash flows by $14 million, which was primarily due to fluctuations in the balance in accrued unbilled revenues as energy sales near the end of the respective periods were impacted by weather; and
◦timing of accounts payable payments decreased operating cash flows by $31 million for IDACORP and increased operating cash flows by $25 million for Idaho Power (the difference relates to a $55 million payable from Idaho Power to IDACORP relating to estimated income tax payments).

Investing Cash Flows
 
Investing activities consist primarily of capital expenditures related to new construction of and improvements to Idaho Power’s generation,power supply, transmission, and distribution facilities. Idaho Power's constructioncapital expenditures, including AFUDC, were $278 million, $285$300 million and $297$311 million in 2018, 2017,2021 and 2016,2020, respectively. These capital expenditures were primarily for construction of utility infrastructure needed to address Idaho Power’s aging plant and equipment, customer growth, and environmental and regulatory compliance requirements. As discussed in "Capital Requirements" below, Idaho Power received $22$6 million and $6$3 million in 20182021 and 20172020, respectively, from Boardman-to-Hemingway project joint permitting participants relating to a portion of these constructionpermitting expenditures.


Idaho Power's investing cash inflows include $14 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 available-for-saleequity securities of $11$16 million in both 20182021 and 2017, and $15$33 million in 2016.2020. Idaho Power received $5$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 the salesmaturities of available-for-sale securities in both 2018short-term investments. During 2021 and 2017, and $16 million in 2016. Idaho Power did not use any of these proceeds to acquire company-owned life insurance in 2018 and 2017 but used $102020, IDACORP's investing cash outflows included $25 million of the proceedspurchases of short-term investments in addition to acquire company-owned life insurance$15 million and $14 million, respectively, of tax credit investments in 2016.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.
 
Financing Cash Flows
 
Financing activities provide supplemental cash for both day-to-day operations and capital requirements as needed. Idaho Power funds liquidity needs for capital investment, working capital, managing commodity price risk, 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, capital contributions to Idaho Power, and non-utility operating expenses through cash flows from operations, commercial paper markets, sales of common stock, and credit facilities. The following are significant items and transactions that affected financing cash flows in 2018, 2017,2021 and 2016:2020:


on March 16, 2018,•in April 2020, Idaho Power issued $220$230 million in principal amount of 4.20%its 4.20 percent first mortgage bonds, secured
medium term notes, Series K, maturing March 1, 2048;2048. The bonds were issued at a reoffer yield of 3.422 percent,
on April 17, 2018,which resulted in a net premium of 13.0 percent 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, $130 million of its 4.50% first mortgage bonds, Series H, due March 1, 2020, and paid a related make-whole premium of $4.6 million;
on March 10, 2016, Idaho Power issued $120$75 million in principal amount of 4.05%2.95 percent first mortgage
bonds, medium-term notes, Series J, maturing on March 1, 2046;H due in April 2022. In accordance with the redemption provisions of the notes, the
on April 11, 2016,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 prior to maturity, $100 million in principal amount of 6.15%3.40 percent first mortgage bonds Series H, due April 1, 2019,in
November 2020; and paid a related make-whole premium of $14 million;
•IDACORP and Idaho Power paid dividends of approximately $121 million, $113$146 million and $105$138 million in 2018, 2017,2021 and 2016, respectively;2020, respectively.
IDACORP's net change in commercial paper borrowings used cash of $22 million and provided cash of $2 million in 2017 and 2016, respectively; and
Idaho Power borrowed $22 million in commercial paper in December 2016, which was paid off in January of 2017.


Financing Programs and Available Liquidity


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

Idaho Power First Mortgage Bonds: Idaho Power's issuance of long-term indebtedness is subject to the approval of the IPUC, OPUC, and Wyoming Public Service Commission (WPSC). In April and May 2016,2019, Idaho Power received orders from the IPUC, OPUC, and WPSC authorizing Idaho Powerthe company to issue and sell from time to time up to $500 million in aggregate principal amount of debt securities and first mortgage bonds, subject to conditions specified in the orders. Following the June 2020 issuance of Series L medium-term notes and the April 2020 issuance of Series K medium-term notes described above, $190 million of debt securities remains available for issuance under the orders. Authority from the IPUC is effective through May 31, 2019,
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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.


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On September 27, 2016,In May 2019, Idaho Power entered intofiled a selling agency agreement with seven banks named in the agreement in connectionshelf registration statement with the potential issuanceSEC, which became effective upon filing for the offer and sale from time to time of up to $500 million in aggregatean unspecified principal amount of its first mortgage bonds, secured medium term notes, Series K (Series K Notes), under Idaho Power’s Indenture of Mortgage and Deed of Trust, dated as of October 1, 1937, as amended and supplemented (Indenture). At the same time, Idaho Power entered into the Forty-eighth Supplemental Indenture, dated as of September 1, 2016, to the Indenture (Forty-eighth Supplemental Indenture). The Forty-eighth Supplemental Indenture provides for, among other items, (a) the issuance of up to $500 million in aggregate principal amount of Series K Notes pursuant to the Indenture and (b) the increase of the maximum amount of obligations to be secured by the Indenture to $2.5 billion (which maximum amount may be further increased or decreased by Idaho Power without the consent of the holders of first mortgage bonds). As of the date of this report, Idaho Power has $280 million available for the issuance of first mortgage bonds, including Series K Notes, or debt securities under the selling agency agreement.

bonds. The issuance of first mortgage bonds requires that Idaho Power meet interest coverage and security provisions set forth in the Indenture.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, 2018,2021, was limited to approximately $669$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, 2018,2021, Idaho Power could issue approximately $1.9$2.1 billion of additional first mortgage bonds based on retired first mortgage bonds and total unfunded property additions.


Refer to Note 5 - “Long-Term Debt” to the consolidated financial statements included in this report for more information regarding long-term financing arrangements.

IDACORP and Idaho Power Credit Facilities: In November 2015,The IDACORP and Idaho Power entered into credit agreements for $100 million and $300 million credit facilities, respectively. These facilities replaced IDACORP's and Idaho Power's existing Second Amended and Restated Credit Agreements, dated October 26, 2011, as amended. Each of the credit facilitiesFacility, which may be used for general corporate purposes and commercial paper back-up. IDACORP's facility permits borrowings underbackup, consists of a revolving line of credit of upnot to $100 millionexceed 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, at any time and letters of credit in an aggregate principle amount at any time outstanding not to exceed $50 million at any time. IDACORP's facilitymillion. The Idaho Power Credit Facility, which may be increased, subject to specified conditions, to $150 million. Idaho Power's facility permits borrowingsused 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, of upnot to $300 millionexceed the aggregate principle 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, at any one time and letters of credit in an aggregate principal amount at any time outstanding not to exceed $100$50 million. IDACORP and Idaho Power have the right to request an increase in the aggregate principal amount of the facilities to $150 million at any time. Idaho Power's facility may be increased,and $450 million, respectively, in each case subject to specified conditions, to $450 million.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 LIBORLondon 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 percent.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 agreements. TheUnder their respective credit facilities, the companies also 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 the Credit Facilities 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 a maturity date of December 6, 2025, the credit agreements grant IDACORP and Idaho Power the right to request up to two-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,
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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, 2018,2021, the leverage ratios for IDACORP and Idaho Power were 4443 percent and 4645 percent, respectively. IDACORP's and Idaho Power's ability to utilize the credit facilities is conditioned upon their continued compliance with the leverage ratio covenants included in the credit facilities. There are additional covenants, subject to exceptions, that prohibit certain mergers, acquisitions, and investments, restrict the creation of certain liens, and prohibit entering into any agreements restricting dividend payments from any material subsidiary. At December 31, 2018,2021, IDACORP and Idaho Power believe they were in compliance with all facility covenants. Further, as of the date of this report, IDACORP and Idaho Power do not believe they will be in violation or breach of their respective debt covenants during 2019.2022.

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


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

While the credit facilities provide for an original maturity date of November 6, 2020, the credit agreements grant IDACORP and Idaho Power the right to request up to two one-year extensions, in each case subject to certain conditions. On November 7, 2016, IDACORP and Idaho Power executed the first extension agreement and on November 7, 2017, executed the second extension agreement with the consent of all the lenders, extending the maturity date under both credit agreements to November 4, 2022. No other terms of the credit facilities, including the amount of permitted borrowing under the credit agreements, were affected by the extensions.


Without additional approval from the IPUC, the OPUC, and the WPSC, the aggregate amount of short-term borrowings by Idaho Power at any one time outstanding may not exceed $450 million. Idaho Power has obtained approval of the state public utility commissions of Idaho, Oregon, and Wyoming for the issuance of short-term borrowings through November 2022.December 2026.


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


Available Short-Term Borrowing Liquidity


The following table outlines available short-term borrowing liquidity as of the dates specified (in thousands):
 December 31, 2021December 31, 2020
 
IDACORP(2)
Idaho Power
IDACORP(2)
Idaho Power
Revolving credit facility$100,000 $300,000 $100,000 $300,000 
Commercial paper outstanding— — — — 
Identified for other use(1)
— (24,245)— (24,245)
Net balance available$100,000 $275,755 $100,000 $275,755 
(1) Port of Morrow and American Falls bonds that Idaho Power could be required to purchase prior to maturity under the optional or mandatory purchase provisions of the bonds, if the remarketing agent for the bonds were unable to sell the bonds to third parties.
(2) Holding company only.
  December 31, 2018 December 31, 2017
  
IDACORP(2)
 Idaho Power 
IDACORP(2)
 Idaho Power
Revolving credit facility $100,000
 $300,000
 $100,000
 $300,000
Commercial paper outstanding —
 —
 —
 -
Identified for other use(1)
 —
 (24,245) —
 (24,245)
Net balance available $100,000
 $275,755
 $100,000
 $275,755
(1) Port of Morrow and American Falls bonds that Idaho Power could be required to purchase prior to maturity under the optional or mandatory purchase provisions of the bonds, if the remarketing agent for the bonds were unable to sell the bonds to third parties.
(2) Holding company only.

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The table below presents additional information about short-termIDACORP and Idaho Power had no short term commercial paper borrowingoutstanding during the years ended December 31, 20182021 and 2017:
  December 31, 2018 December 31, 2017
  
IDACORP(1)
 Idaho Power 
IDACORP(1)
 Idaho Power
Commercial paper:        
Year end:        
Amount outstanding $—
 $—
 $—
 $—
Weighted average interest rate —% —% —% —%
Daily average amount outstanding during the year $—
 $—
 $588
 $839
Weighted average interest rate during the year —% —% 1.42% 1.12%
Maximum month-end balance $—
 $—
 $2,425
 $—
(1) Holding company only.
2020. At February 15, 2019,11, 2022, neither IDACORP nor Idaho Power had no loans outstanding under itstheir credit facilityfacilities and no commercial paper outstanding, and Idaho Power neither
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had no loans outstanding under its credit facility and no 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 Service and Standard & Poor’s Ratings Services as of the date of this report:
IDACORPIdaho Power
Moody's Investors Service:
Rating OutlookNegativeNegative
Long-Term Issuer RatingBaa1A3
First Mortgage BondsNoneA1
Senior Secured DebtNoneA1
Commercial PaperP-2P-2
IDACORPIdaho Power
Moody's Investors Service:
Rating OutlookStableStable
Long-Term Issuer RatingBaa1A3
First Mortgage BondsNoneA1
Senior Secured DebtNoneA1
Commercial PaperP-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. AnyThere 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, any rating can be revised upward or downward or withdrawn at any time by a rating agency if it decides that the circumstances warrant the change. In June 2021, 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, 2018,2021, Idaho Power had no performance assurance collateral posted. Should Idaho Power experience a reduction in its credit rating on its unsecured debt to below investment grade, Idaho Power could be subject to requests by its wholesale counterparties to post additional performance assurance collateral, and counterparties to derivative instruments and other forward contracts could request immediate payment or demand immediate ongoing full daily collateralization on derivative instruments and contracts in net liability positions. Based upon Idaho Power’s current energy and fuel portfolio and market conditions as of December 31, 2018,2021, the amount of additional collateral that could be requested upon a downgrade to below investment grade is approximately $10.5$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.
 
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Capital Requirements
 
Idaho Power's cash constructioncapital expenditures, excluding AFUDC,were $268$288 million during the year ended December 31, 2018.2021. The cash expenditure amount excludes net costs of removing assets from service. The table below presents Idaho Power's estimated accrual-basis expendituresadditions to electric plant for construction for 20192022 through 20232026 (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, given 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 capital expenditures could be significantly affected by Idaho Power’s ability to timely obtain labor
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  2019 2020 2021-2023
Expected capital expenditures (excluding AFUDC) $280-290 $285-300 $875-925
or materials at reasonable costs, supply chain disruptions and delays, inflationary pressures, 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 owning those resources it would decrease Idaho Power's expected capital expenditures.

 202220232024-2026
Expected capital expenditures (excluding AFUDC)$480-500$690-715$1,450-1,550

Infrastructure Projects: A significant portion of expected capital expenditures included in the five-year forecast above relate to a large number of small projects as Idaho Power continues to add to its system to accommodate growth and improvemaintain reliability and operational effectiveness. These projects involve significant capital expenditures. Examples of anticipated system enhancements planned for 20192022 through 20232026 and estimated costs include the following:


•$35-40-$6570 million per year for construction and replacement of transmission lines and stations other than the Boardman-to-Hemingway and Gateway West projects;
•$85-125-$105170 million per year for construction and replacement of distribution lines and stations, including replacement of underground distribution cables;
•$20-10-$4080 million per year for ongoing improvements and replacements at coal- and natural gas-firedthermal plants;
•$50-70-$70110 million per year for hydroelectrichydropower plant improvement programs, including relicensing costs; and
•$40-50-$6075 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.


Resource Additions to Address Projected Energy and Capacity Deficits: As noted previously, existing and sustained growth in customers and peak demand for electricity, transmission constraints, and Idaho Power’s planned exit from coal-fired generation, will also require Idaho Power to acquire significant generation 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 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 in capital expenditures from 2022 through 2025 for resource additions to help meet the projected capacity deficits noted above.

Boardman-to-Hemingway Transmission Line:The Boardman-to-Hemingway line, a proposed 300-mile, 500-kVhigh-voltage transmission project between a stationsubstation near Boardman, Oregon, and the Hemingway stationsubstation near Boise, Idaho, would provide transmission service to meet future resource needs. In January 2012, Idaho Power entered into a joint funding agreement with PacifiCorp and the Bonneville Power Administration (BPA) to pursue permitting of the project. The joint funding agreement providesprovided that Idaho Power's interest in the permitting phase of the project would be approximately 21 percent, and that during future negotiations relating to construction of the transmission line, Idaho Power would seek to retain that percentage interest in the completed project.percent. Total cost estimates for the project are between $1.0 billion and $1.2 billion, including Idaho Power's AFUDC. This cost estimate is preliminary and excludes the impacts of inflation and price changes of materials and labor resources that may occur following the date of the estimate. Idaho Power's share of the permitting phase of the project (excluding AFUDC) is included in the capital requirements table above, in addition to approximately $50 million of Idaho Power's share of costs related to early construction efforts, which are primarily included in the period 2021-2023. These preliminary estimates of Idaho Power’s share of early construction costs could significantly change as the construction timeline nears and as the project participants further align on future activities and estimates.


Approximately $100$125 million, including AFUDC, has been expended on the Boardman-to-Hemingway project through December 31, 2018.2021. Pursuant to the terms of the joint funding arrangements, Idaho Power has received $70$81 million in reimbursement as of December 31, 2018, due2021, from project participantsco-participants for their share of costs. As of the date of this report, no material participantco-participant reimbursements are outstanding. Joint permitting participants are obligated to reimburse Idaho Power for their share of any future project permitting expenditures or agreed upon early construction expenditures incurred by Idaho Power.Power under the terms of the joint funding agreement.


The permitting phase of the Boardman-to-Hemingway project is subject to federal review and approval by the BLM,U.S. Bureau of Land Management (BLM), the U.S. Forest Service, the Department of the Navy, and certain other federal agencies. The BLM issued its record of decision for the project in November 2017, approving a right-of-way grant for the project to cross approximately 86 miles of BLM-administered land. The U.S. Forest Service issued its record of decision in November 2018 authorizing the project to cross approximately seven miles of National Forest lands. Idaho Power expects the U.S. Forest Service to issue its right-of-way easement in 2019. Idaho Power expectsIn September 2019, the Department of the Navy to issueissued its record of decision on whether to approveauthorizing the project to cross approximately seven miles of Department of the Navy lands in the first quarter of 2019.lands.
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In November 2019, third parties filed a lawsuit in the federal district court of Oregon challenging the BLM and U.S. Forest Service records of decision for the Boardman-to-Hemingway project on several grounds. In 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.


In the separate State of Oregon state permitting process, in September 2018, Idaho Power's application for site certificate was deemed complete by the Oregon Department of Energy (ODOE) issued a Proposed Order in July 2020 that recommends approval of the project to the state's Energy Facility Siting Council (EFSC). The ODOEproject permit is expectedactively undergoing the EFSC administrative process, and Idaho Power currently expects the EFSC to issue a draft proposedfinal order on the application in the firstsecond half of 2019 providing2022.

As the ODOE's recommendationcurrent 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 Idaho Power's interest to approximately 45 percent, and Idaho Power would deliver transmission service to BPA's customers across Southern Idaho.

The capital requirements table above includes approximately $380 million of Idaho Power's share of estimated costs 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 of construction costs could significantly change as the construction timeline nears and as the project participants further align on whether to issue a site certificatefuture cost estimates.

In July 2021, Idaho Power awarded contracts for constructiondetailed design, geotechnical investigation, land surveying, and right-of-way option acquisition; and work commenced in Oregon.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 towill be in 2026 or beyond.no earlier than 2026.


Gateway West Transmission Line: Idaho Power and PacifiCorp are pursuing the joint development of the Gateway West project, a 500-kVhigh-voltage transmission lines project between a stationsubstation located near Douglas, Wyoming, and the Hemingway stationsubstation 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 $38$48 million, including Idaho Power's AFUDC, for its share of the permitting phase of the project through December 31, 2018.2021. As of the date of this report, Idaho Power estimates the total cost for its share of the project (including both permitting and construction) to be between $250 million and $450 million, including AFUDC. Idaho Power's estimated share of ongoing expenditures for the permitting phase of the project (excluding AFUDC) is included in the capital requirements table above. Idaho Power's share of potential early construction costs are excluded from the capital requirements table above because the timing of construction of Idaho Power's portion of the project is uncertain.


The permitting phase of the Gateway West project was subject to review and approval of the BLM. The BLM released its record of decision in November 2013 for eight of the ten transmission line segments. In May 2017, a federal bill was signed into law that issued a right-of-way for certain portions of the remaining Gateway West segments. In April 2018, the BLMhas published its recordrecords of decision for the outstanding portionsall segments of the remaining segments.transmission line. PacifiCorp recently constructed and commissioned a 140-mile segment of their portion of the project in Wyoming. Idaho Power and PacifiCorp continue to coordinate the timing of next steps to best meet customer and system needs.


Hells Canyon Complex Relicensing: The HCC, located on the Snake River where it forms the border between Idaho and Oregon, provides approximately 6870 percent of Idaho Power's hydroelectrichydropower generating nameplate capacity and 3236 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. The past and anticipated future costs associated with obtaining a new long-term license for the HCC are significant. 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 million to $40 million until issuance of the license. The FERC could issue the license whichas early as 2023, but as of the date of this report Idaho Power estimates will occur no earlier than 2022.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 compliancecompliance with the terms and conditions of the long-term license could also be substantial, but the company is currently unable to estimate those costs in light of the uncertainty surrounding the ultimate terms and conditions that may be included in the license.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 December 2017, Idaho Power filed withApril 2018, the IPUC issued an order approving a settlement stipulation signed by Idaho Power, the
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IPUC staff, and a third partythird-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. As a result of filing the settlement stipulation, Idaho Power recorded a $5.0 million pre-tax charge in 2017, which included $4.3 million for costs incurred through 2015 as well as $0.7 million related to associated costs incurred in 2016 and 2017. Of the $5.0 million pre-tax charge in 2017, $2.5 million was recorded as Other O&M expense and $2.5 million was recorded as a reduction to AFUDC. In April 2018, the IPUC issued an order approving the settlement stipulation as filed with IPUC and determined the associated costs to be reasonably and prudently incurred.


Jim Bridger Plant Selective Catalytic Reduction Equipment: Idaho Power and the plant co-owners completed installation of selective catalytic reduction (SCR) equipment to reduce nitrogen dioxide (NO2) emissions at the Jim Bridger power plant, in order to comply with regional haze rules. The regional haze rules provided for installation of SCR on unit 3 and unit 4. The rules provide for an equivalent technology for NO2 reductions on unit 2 by 2021 and unit 1 by 2022.The unit 3 SCR was operating as of November 2015, and the unit 4 SCR was operating as of November 2016. In light of the substantial estimated cost of SCR installation, as of the date of this report, Idaho Power continues to assess whether to move forward with the installation of SCR on units 1 and 2 at the Jim Bridger power plant. The expected capital expenditures in the table above do not include any estimated expenditures relating to the installation of SCR on units 1 and 2.

Environmental Regulation Costs: Idaho Power anticipates that it will continue to incur significant expenditures for its compliance with environmental regulations related to the installationoperation of environmental controls at its coal-fired plantshydropower and thermal generation facilities. In addition, Idaho Power expects it will continue to incur significant expenditures for its hydroelectrichydropower 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
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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 June 2017. The 20172021. Idaho Power's 2021 IRP identified a preferred resource portfolio and action plan, which includesincluded the completionaddition of a 120-MW solar resource in late 2022, the Boardman-to-Hemingway transmission line by 2026,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 units 1 andplant unit 2 in 20192025, the completion of the Boardman-to-Hemingway transmission line in 2026, and 2025, respectively, andan end to Idaho Power's participation in the early retirement ofremaining two coal-fired units at the Jim Bridger units 1plant by the end of 2028. The 2021 IRP preferred resource portfolio and 2 in 2032action plan also includes a need to acquire significant generation and 2028, respectively, with no other new resource needs priorstorage resources to 2026. However, asmeet 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 20172021 IRP, there is considerable uncertainty surrounding the resource sufficiency estimates and project completion dates, including uncertainty around the timing and extent of third partythird-party development of renewable resources, fuel commodity prices, environmental requirements, the actual completion date of the Boardman-to-Hemingway transmission project, and the economics and logistics of coal-fired plant operationconversions and retirements. These uncertainties, as well as others, couldmay result in changes to the desirability of the preferred portfolio and adjustments to the timing and nature of anticipated and actual actions.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 information on Idaho Power's 20172021 IRP is included in Part I, Item 1 - "Business - Resource Planning" in this report.


Defined Benefit Pension Plan Contributions and Recovery


Idaho Power contributed $40 million to its defined benefit pension plan in each year in 2018, 2017,of 2021 and 2016.2020. Idaho Power estimates that it has no minimum required contribution requirement for 2019.to be made during 2022. Depending on market conditions and cash flow considerations, in 2019, Idaho Power could contribute up to $40 million to the pension plan during 2019.2022. 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 2019,2022, Idaho Power expects continuing significant contribution obligations under the pension plan. Refer to Note 12 - "Benefit Plans"– “Benefit Plans” to the consolidated financial statements included in this report and the section titled "Contractual Obligations" below in this MD&A 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, 20182021 and 2017,2020, Idaho Power's deferral balance associated with the Idaho jurisdiction was $148$234 million and $128$201 million, respectively. Deferred pension costs are expected to be 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. The IPUC has authorized Idaho Power to recover and amortize $17 million of deferred pension costs annually, and 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.

Income Tax Reform

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. The majority of the law changes, including the rate reductions, became effective on January 1, 2018. See "Regulatory Matters" in this MD&A for more Additional information on the regulatory assets related regulatory proceedingsto Idaho Power's pension and postretirement programs can be found in Note 3 - "Regulatory Matters" to the consolidated financial impacts.statements included in this report.
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Contractual Obligations


The following table presents IDACORP’s and Idaho Power’s contractual cash obligations as of December 31, 2018,2021, 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 10 – “Commitments” to the consolidated financial statements included in this report for the respective periods in which they are due:additional information relating to purchase obligations and other long-term liabilities.
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  Payments Due by Period
  Total 2019 2020-2021 2022-2023 Thereafter
  (millions of dollars)
Long-term debt(1)
 $1,855
 $—
 $100
 $150
 $1,605
Future interest payments(2)
 1,565
 85
 166
 159
 1,155
Purchase obligations:  
  
  
  
  
Maintenance and service agreements(3)
 131
 34
 26
 16
 55
FERC and other industry-related fees(3)
 128
 14
 25
 25
 64
Cogeneration and small power production 4,042
 239
 490
 508
 2,805
Fuel supply agreements 201
 43
 57
 17
 84
Other(3)(4)
 51
 3
 8
 8
 32
Pension and postretirement benefit plans(5)
 326
 11
 110
 153
 52
Other long-term liabilities - IDACORP only(3)
 2
 —
 —
 —
 2
Total $8,301
 $429
 $982
 $1,036
 $5,854
(1) For additional information, see Note 5 – “Long-Term Debt” to the consolidated financial statements included in this report.
(2) Future interest payments are calculated based on the assumption that all debt is outstanding until maturity. For debt instruments with variable rates, interest is calculated for all future periods using the rates in effect at December 31, 2018.
(3) Approximately $20 million of the amounts in maintenance and service agreements, $71 million of the amounts in FERC and other industry-related fees, $29 million of the amounts in other purchase obligations, and $2 million of the amounts in IDACORP only other long-term liabilities are 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.
(4) Other purchase obligations include right-of-way easements and the joint-operating agreement payments.
(5) Idaho Power estimates pension contributions based on actuarial data. As of the date of this report, Idaho Power cannot estimate pension contributions beyond 2023 with any level of precision, and amounts through 2023 are estimates only and are subject to change. For more information on pension and postretirement plans, refer to Note 12 – "Benefit Plans" to the consolidated financial statements included in this report.


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 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 5060 percent and 6070 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 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 2018, 2017,2021 and 2016,2020, IDACORP's board of directors voted to increase the quarterly dividend to $0.63 per share, $0.59$0.75 per share and $0.55$0.71 per share of IDACORP common stock, respectively. IDACORP's dividends during 20182021 were 53.559.4 percent of actual 20182021 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 7 – “Common Stock” to the consolidated financial statements included in this report.


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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


Through a self-bonding mechanism, Idaho Power guarantees its portion of reclamation activities and obligations at BCC, of which IERCo owns a one-third interest. This guarantee, which is renewed annually with the Wyoming Department of Environmental Quality (WDEQ), was $58.4$51.6 million at December 31, 2018,2021, representing IERCo's one-third share of BCC's total reclamation obligation of $175.2$154.7 million. BCC has a reclamation trust fund set aside and specifically for the purpose of paying these reclamation costs. At December 31, 2018,2021, the value of the reclamation trust fund totaled $101.9$211.2 million. During 2018,2021, the reclamation trust fund made $6.7$21.1 million inof distributions for reclamation activity costs associated with the BCC surface mine. BCC periodically assesses the adequacy of the reclamation trust fund and its estimate of future reclamation costs. To ensure that the reclamation trust fund maintains adequate reserves, BCC has the ability to, and does, add a per-ton surcharge to coal sales, all of which are made to the Jim Bridger plant. Because of the existence of the fund and the ability to apply a per-ton surcharge, the estimated fair value of this guarantee is minimal.


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

Between general rate cases, Idaho Power relies upon customer growth, a fixed cost adjustment mechanism, power cost adjustment mechanisms, tariff riders, and other mechanisms to reducemitigate 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 continues to assess the need and timing of filing ahas made since its last general rate case filed in its two retail jurisdictions, based on its consideration of the factors described above, but does not anticipate filing a2011, will increase and potentially accelerate Idaho Power’s need to file general rate case in 2019.cases.

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Notable Retail Rate Changes in Idaho and Oregon


Included in theThe table that follows arebelow presents notable regulatory developmentsrate changes during 2018, 2017,2021 and 20162020 that affected Idaho Power's results for the periods or that will likely affect future periods. Also refer to Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report foralso provides a description of regulatory mechanismmechanisms and associated orders of the IPUC and OPUC, whichand should be read in conjunction with the discussion of regulatory matters in this MD&A.
DescriptionEffective Date
Estimated Annualized Rate Impact (millions)(1)
2021 Idaho PCA6/1/2021$39 
2021 Idaho FCA6/1/20213 
Idaho Boardman plant closure1/1/2021(4)
2020 Idaho PCA6/1/202059 
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 from the prior year's filing.
Description Effective Date 
Estimated Annualized Rate Impact (millions)(1)
May 2018 Idaho Tax Reform Settlement Stipulation - Idaho base rates 6/1/2018  $(19)
May 2018 Idaho Tax Reform Settlement Stipulation - Idaho PCA(2)
 6/1/2018  (8)
2018 Idaho PCA 6/1/2018  (23)
2018 Idaho FCA 6/1/2018  (19)
Oregon Tax Reform Settlement Stipulation 6/1/2018  (1)
Oregon Valmy Plant Accelerated Depreciation Settlement Stipulation 6/1/2018  2
Oregon Valmy Plant Settlement Stipulation 7/1/2017  1
Idaho Valmy Plant Settlement Stipulation 6/1/2017  13
2017 Idaho PCA(3)
 6/1/2017  11
2017 Idaho FCA 6/1/2017  7
2016 Idaho PCA(4)
 6/1/2016  17
2016 Idaho FCA 6/1/2016  11
      
(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.
(2) 2018 Idaho PCA rates include $7.8 million decrease for the income tax benefits accrued from January 1 to May 31, 2018, and the income tax benefits related to Idaho Power's OATT rate. See "Income Tax Reform - Regulatory Treatment" below for more information.
(3) 2017 Idaho PCA rates reflect the application of $13.0 million of surplus Idaho energy efficiency rider funds.
(4) 2016 Idaho PCA rates reflect the application of (a) a customer rate credit of $3.2 million for sharing of revenues with customers for the year 2015 under the terms of an October 2014 settlement stipulation and (b) $4.0 million of surplus Idaho energy efficiency rider funds.


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, the IPUC issued an order approvingapproved a settlement stipulation that provided for an overall 7.86 percent authorized rate of return on an Idaho-jurisdiction rate base of approximately $2.36 billion. The settlement stipulation resulted in a $34.0 million overall increase in Idaho Power's annual Idaho-jurisdictional base rate revenues. Neither the IPUC's order nor the settlement stipulation specified an authorized rate of return on equity.



Effective March 1, 2012, Idaho Power implemented new Oregon base rates resulting from its receipt of an order from the 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.
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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 MarchOctober 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 application requestingactual 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 increase of approximately $106order 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 in the normalized or "base level" net power supply expense on a total-system basisreduction to be used to updateIdaho customer base rates and in(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 determinationextension of the PCA rateOctober 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 Junebeginning January 1, 2014. Approval2020, 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 order removedauthorized return on equity in the Idaho-jurisdictional portionnext general rate case. IDACORP and Idaho Power believe that the terms allowing amortization of those expenses (approximately $99 million) from collection viaadditional ADITC in the PCAMay 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.

Idaho Power recorded the following amounts for sharing with customers under the December 2011 and 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 and instead results in collecting that portion through base rates.preceding the December 2011 Idaho settlement stipulation.


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

Oregon Tax Reform Matters: In May 2018, the OPUC 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, related to income tax reform (May 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 federal 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.

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
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its application, Idaho Power requested authority to procure 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. As of the date of this report, the IPUC's decision in this matter is pending.

Valmy Base Rate Adjustment Settlement Stipulations

Stipulations: In May 2017, the IPUC approved a settlement stipulation, effective June 1, 2017, allowing accelerated depreciation and cost recovery for the North Valmy Plant.coal-fired power plant. The settlement stipulation provides for an increase in Idaho jurisdictional revenues of $13.3 million per year, and (1) levelized collections and associated cost recovery through December 2028, (2) accelerated depreciation on unit 1 through 2019 and unit 2 through 2025, and (3) Idaho Power to use prudent and commercially reasonable efforts to end its participation in the operation of unit 1 by the end of 2019 and unit 2 byno later than the end of 2025, and (4) a filing no later than December 31, 2019 that would include actual and planned incremental investments in unit 2, including updated financial analysis regarding the lowest costs options for unit 2. The costs intended to be recovered by the increased 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 savings.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 amounts 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 Plantplant investments through May 31, 2017, and (3) forecasted North Valmy plant decommissioning costs. The settlement stipulation providesprovided for an increase in the Oregon jurisdictional revenue requirement of $1.1 million, effective July 1, 2017, with yearly adjustments, if warranted. As part of theIn May 2018, Oregon Income Tax Reform Settlement Stipulation described below, 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, beginning June 1, 2018, and ending December 31, 2019, resulting in a $2.5 million annualized revenue requirement.

Other Notable Regulatory Matters

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 20112019 end of Idaho Earnings Support and Sharing Settlement Stipulation:Power's participation in coal-fired operations of North Valmy plant unit 1. In December 2011,September 2021, the IPUC issued an order separateacknowledging Idaho Power's year-end 2025 exit date from the then-pending Idaho general rate case proceeding, approving a settlement stipulation that allowedValmy unit 2 is appropriate based on economics and reliability needs.

Boardman Power Plant Filings: In October 2020, Idaho Power to, in certain circumstances, amortize additional accumulated deferred investment tax credits (ADITC) if Idaho Power's actual Idaho ROE for 2012, 2013, or 2014 was less than 9.5 percent, to help achieve a 9.5 percent Idaho ROE for the applicable year. Under theand co-owner Portland General Electric ceased coal-fired operations at their Boardman power plant. In December 2011 Idaho Earnings Support and Sharing Settlement Stipulation, when Idaho Power's actual Idaho ROE for any of those years exceeded 10.0 percent, Idaho Power was required to share a portion of its Idaho-jurisdiction earnings with Idaho customers.

October 2014 Idaho Earnings Support and Sharing Settlement Stipulation: In October 2014,2020, 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 an extension, with modifications, ofa $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 terms ofcustomer uses, the December 2011 settlement stipulation for the period from 2015 through 2019, or until the terms are otherwise modified or terminated by order of the IPUC or the full $45 million of additional ADITC contemplated by the settlement stipulation has been amortized. The more specific terms and conditions of the October 2014 settlement stipulation are described in Note 3 - "Regulatory Matters - Notable Idaho Regulatory Matters"energy goes back to the consolidated financial statements included in this report. IDACORPgrid and Idaho Power believe that the terms allowing amortization of additional ADITC in the October 2014 Idaho Earnings Support and Sharing Settlement Stipulation provide the companies withapplies a greater degree of earnings stability than would be possible without the terms of the stipulation in effect. The October 2014 Idaho Earning Support and Sharing Settlement Stipulation was modified and indefinitely extended, as described in "Income Tax Reform - Regulatory Treatment" below.

In 2018, Idaho Power recorded a $5.0 million provision against current revenue for sharing with customers, as its full-year Idaho ROE for 2018 was above 10.0 percent. In both 2017 and 2016, Idaho Power did not record any additional ADITC amortization or any provision for sharing with customers, as its Idaho ROE in both years was between 9.5 percent and 10.0 percent. Accordingly, at December 31, 2018, the full $45 million of additional ADITC remains available for future use under the terms of the October 2014 Idaho Earnings Support and Sharing Settlement Stipulation.
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Idaho Power recorded the following for sharing with customers under the December 2011 and October 2014 Idaho Settlement Stipulations (in millions):
Year Recorded as Refunds to Customers Recorded as a Pre-tax Charge to Pension Expense Total
2018 $5.0
 $—
 $5.0
2017 —
 —
 —
2016 —
 —
 —
2015 3.2
 —
 3.2
2014 8.0
 16.7
 24.7
2013 7.6
 16.5
 24.1
2012 7.2
 14.6
 21.8
2011(1)
 27.1
 20.3
 47.4
Total $58.1
 $68.1
 $126.2
       
(1) The 2011 sharing amounts were recorded pursuant to a regulatory mechanism preceding the December 2011 Idaho Earnings Support and Sharing Settlement Stipulation.

Income Tax Reform - Regulatory Treatment: In December 2017, the Tax Cuts and Jobs Act was signed into law, which, among other things, lowered the corporate federal income tax rate from 35 percent to 21 percent and modified or eliminated certain federal income tax deductions for corporations. In March 2018, Idaho House Bill 463 was signed into law reducing the Idaho state corporate income tax rate from 7.4 percent to 6.925 percent. In January 2018, the IPUC issued an order requiring utilities within its jurisdiction, including Idaho Power, to (1) record a regulatory liability for the estimated Idaho-jurisdictional share of financial benefits after January 1, 2018, from the changes in federal income tax law under the Tax Cuts and Jobs Act, and (2) file a report with the IPUC by March 30, 2018, identifying and quantifying the financial impact of the income tax changes on the utility, along with proposed tariff schedule changes that would adjust the utility's rates and corresponding revenues to reflect the utility's modified federal tax obligations under the Tax Cuts and Jobs Act. The IPUC order required Idaho Power to estimate the income tax reform changes by comparing actual 2017 federal income tax components with what those federal income tax components would have been if the Tax Cuts and Jobs Act had been effective for the full-year 2017.
In March 2018, Idaho Power made a filing with the IPUC providing the results of its pro forma analysis indicating pro forma annual income tax reform expense reductions, composed of a current income tax expense reduction and a deferred income tax expense reduction. In May 2018, the IPUC issued an order approving a settlement stipulation (May 2018 Idaho Tax Reform Settlement Stipulation) related to income tax reform. Beginning June 1, 2018, the settlement stipulation provides an annual (a) $18.7 million reduction to Idaho customer base rates and (b) $7.4 million amortization of existing regulatory deferrals for specified items or future amortization of other existing or future unspecified regulatory deferrals that would otherwise be a future liability recoverable from Idaho customers. Additionally, a one-time benefit of a $7.8 million rate reduction is being provided to Idaho customers through PCA mechanism rates for the period from June 1, 2018 through May 31, 2019, for the income tax reform benefits accrued from January 1, 2018 to May 31, 2018, and the income tax reform benefits related to Idaho Power's OATT rate. The amount provided via the PCA mechanism will decrease to $2.7 million on June 1, 2019, for income tax reform benefits related to Idaho Power's OATT rate and will cease on June 1, 2020, to reflect the impact of a full year of reduced OATT third-party transmission revenues.

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

Also in May 2018, the OPUC issued an order approving a settlement stipulation that provides for an annual $1.5 million reduction to Oregon customer base rates beginning June 1, 2018, through May 31, 2020, related to income tax reform. Unless resolved in a regulatory proceeding before, the settlement stipulation requires Idaho Power to file a deferral request with the OPUC by December 31, 2019, to begin tracking income tax reform benefits beginning January 1, 2020, at which time Idaho Power, the OPUC staff, and other interested parties will discuss the methodology to quantify potential future income tax reform benefits.

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

Customer-Owned Generation Filing:In July 2017, Idaho Power filed an application with the IPUC related to residential and small general service customers who install their own on-site generation, seeking to create two new customer classes, with no request to change pricing or compensation. customer’s bill. In May 2018, the IPUC issued an order authorizing the creation of thetwo new customer classes. Inclasses 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 filed petitions requestinghas initiated several cases with the IPUC open two new proceedingsrelated to studystudying the fixed-costscosts and benefits of providing electriccustomer-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 to 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 study(1) complete additional studies related to the costs and benefits of customer generation before changes to the compensation structure are implemented, and compensation of net excess energy supplied by customer(2) continue to allow customers with on-site generation respectively.prior to December 20, 2019, to be subject to the billing terms in place on that date until December 20, 2045. In November 2018,December 2020, the IPUC openedissued an order establishing a 25-year grandfathering term for CI&I customers, similar to the proceedings.terms approved for the residential and small commercial customer classes.
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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.

Jim Bridger Power Plant Rate Request: In June 2021, Idaho Power filed an application with the IPUC requesting authorization to (1) accelerate depreciation for the Jim Bridger plant, to allow the plant 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 in coal-fired operations at the Jim Bridger plant, and (3) adjust customer rates to recover 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 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 partiesIPUC Staff to suspend the procedural schedule in both proceedings are continuingIdaho Power's rate request case to assess new developments that impact 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.

Deferred Costs for COVID-19 Public Health Crisis:Idaho Power has incurred, and expects to continue to incur, costs associated 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 the procedural and substantive scope for each proceeding.

Western Energy Imbalance Market Costs:Idaho Power's participation in the Western EIM commenced on April 4, 2018. The Western EIM is intended to reduce the power supply costs to serve customers through more efficient dispatch within the hour ofratemaking treatment at a larger and more diverse pool of resources, to integrate intermittent power from renewable generation sources more effectively, and to enhance reliability. Financial benefits or costs resulting from participation in the Western EIM are subjectlater date. Subsequent to Idaho Power's PCAapplication, 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.

Wildfire Mitigation Cost Recovery: In June 2021, the IPUC authorized Idaho Power to defer for future amortization incremental O&M and depreciation expense of certain capital investments necessary to implement the company's WMP. The
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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 a deferral period of five years, or until rates go into effect after Idaho Power's next general rate case, whichever is first. As of December 31, 2021, Idaho Power’s deferral related to the WMP was $6.1 million. Idaho Power expects that it will continue to incur additional incremental costs from its enhanced wildfire mitigation efforts in future periods.

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

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) through customer rates. Idaho Power's power cost adjustment mechanisms in its Idaho and Oregon jurisdictions provide for annual adjustments to the rates charged to retail customers. The power cost adjustment mechanisms and associated financial impacts are described in "Results of Operations" in this MD&A and in Note 3 - "Regulatory Matters" to the 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 hydroelectrichydropower 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.

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The following table summarizes the change in deferred (accrued) net power supply costs over the prior two yearslast 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 
  Idaho Oregon Total
Balance at December 31, 2016 $53.5
 $0.4
 $53.9
Current period net power supply costs accrued (14.7) —
 (14.7)
Energy efficiency rider funds transferred to Idaho PCA mechanism (13.0) —
 (13.0)
Prior amounts recovered through rates (26.1) (0.5) (26.6)
Sulfur Dioxide (SO2) allowance and renewable energy certificate (REC) sales
 (2.1) (0.1) (2.2)
Interest and other 0.2
 0.1
 0.3
Balance at December 31, 2017 (2.2) (0.1) (2.3)
Current period net power supply costs accrued (41.5) —
 (41.5)
Tax reform revenue accrual to be refunded through Idaho PCA, net of amounts refunded (1.9) —
 (1.9)
Western EIM cost recovery to be collected through Idaho PCA 2.2
 —
 2.2
Prior amounts refunded through rates 4.2
 —
 4.2
SO2 allowance and REC sales
 (2.6) (0.1) (2.7)
Interest and other (0.3) —
 (0.3)
Balance at December 31, 2018 $(42.1) $(0.2) $(42.3)
 


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.FERC and allows Idaho Power to recover costs associated with its transmission system. In August 2018,September 2021, Idaho Power filed its 20182021 final transmission rate with the FERC, reflecting a transmission rate of $31.25$31.19 per kW-year, to be effectiveeffective for the period from October 1, 2018,2021, to September 30, 2019.2022. A "kW-year" is a unit of electrical capacity equivalent to 1 kilowatt of power used for 8,760 hours. Idaho Power's final rate was based on a net annual transmission revenue requirement of $123.1$127.3 million. The OATT rate in effect from October 1, 2017,2020, to September 30, 2018,2021, was $34.90$29.95 per kW-year based on a net annual transmission revenue requirement of $130.4 million.$117.7 million. The decreaseincrease in the OATT rate is largely attributable to an increase inincreased transmission plant as well as decreased short-term firm and non-firm transmission revenues in 2017,2020, which servesserve as an offset to the transmission revenue
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requirement. HistoricHistorical OATT rate information is included in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.


Relicensing of HydroelectricHydropower Projects
 
Overview: Idaho Power, like other utilities that operate non-federal hydroelectrichydropower projects on qualified waterways, obtains licenses for its hydroelectrichydropower 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. Costs for the relicensing of Idaho Power's hydroelectrichydropower 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 processprocess. 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 2016, submitted31, 2015, were reasonably and prudently incurred, and therefore should be eligible for inclusion in customer rates at a request for a determination of prudence of HCC relicensing costs, which is described below.later date. Relicensing costs of $297of $389 million (including(including AFUDC) for the HCC, Idaho Power's largest hydroelectrichydropower complex and a major relicensing effort, were included in construction work in progress at December 31, 2018.2021. 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. Prior to the May 2018 Tax Reform Settlement Stipulation described in Note 3 - "Regulatory Matters," Idaho Power was collecting $10.7 million annually. Collecting these amounts currently will reduce future collections when the HCC relicensing costs are approved for recovery in base rates. As of December 31, 2018,2021, Idaho Power's regulatory liability for collection of AFUDC relating to the HCC was $135$187.7 million. In addition to the discussion below, refer to "Environmental Matters" in this MD&A for a discussion of environmental compliance under FERC licenses for Idaho Power's hydroelectrichydropower generating plants.


Hells Canyon Complex: Complex Relicensing: The HCC, located on the Snake River where it forms the border between Idaho and Oregon, provides approximately 6870 percent of Idaho Power's hydroelectrichydropower generating nameplate capacity and 3236 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 entered into
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an interim agreement that addresses the effects of the ongoing operations of the HCC on Endangered Species Act (ESA) listed-listed species pending the relicensing of the project. In August 2007, the FERC Staff 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 an additional,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 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 which remain unresolved.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 has 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 project comply with applicable state water quality standards. Section 401 of the CWA requires that a state either approve or deny a Section 401 water quality certification application within one year of the filing of the application or the state may be considered to have waived its certification authority under the CWA. As a consequence, Idaho Power has been filingfiled and withdrawingwithdrew its Section 401 certification applications with Oregon and Idaho on an annual basis while it has beenwas working with the states to identify measures that will provide reasonable assurance that discharges from the HCC will adequately address applicable water quality standards. In the 2016 Section 401 certification application process, Oregon required Idaho Power to comply with fish passage and reintroduction conditions. Idaho's water quality certification, however, providesprovided that Idaho Power shall take no action that maymight result in the reintroduction or establishment of spawning populations of any fish species into Idaho's waters without consultation with and express approval of the State of Idaho. In November 2016, Idaho Power filed a petition with the FERC requesting that the FERC resolve the conflict between Oregon's and Idaho's conditions and declare that the Federal Power Act (FPA)FPA pre-empts the
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Oregon state law. In January 2017, the FERC issued an order denying Idaho Power’s petition, stating that the petition for a declaratory order was premature, cannot realistically be considered separately from the issue of the states’ certification authority under the CWA Section 401, and raises issues that are beyond the FERC’s authority to decide. In February 2017, Idaho Power sought rehearing before the FERC on the January 2017 order, which the FERC denied. In February 2018, Idaho Power filed an appeal of the FERC's January 2017 order with the D.C. Circuit Court, which is pending.


In April 2017, the governors of Oregon and Idaho jointly requested that Idaho Power withdraw and resubmit its Section 401 certification applications in both states to allow the states additional time to negotiate a potential resolution of the disputed issues. As of June 2018, the states had not resolved their differences, requiring Idaho Power to again withdraw and resubmit its Section 401 certification applications in both states. In December 2018,2019, the states of Idaho and Oregon, along with Idaho Power, reached a proposed 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. These measures are in exchange for Oregon removing the fish passage requirement from the Oregon 401 certification for at least the first 20 years after final license issuance. Idaho Power estimates that the combined cost of the mandated water quality improvements and expanded hatchery production is $20 million in aggregate over the termfirst 20 years of the new license.license term. In May 2019, Oregon and Idaho issued final CWA Section 401 certifications. These certifications have been submitted to the FERC as part of the relicensing process. In July 2019, three third-parties filed lawsuits against the Oregon Department of Environmental Quality in Oregon state court challenging the Oregon CWA Section 401 certification based on fish passage, water temperature, and mercury issues associated with the Snake River and the HCC. Two of the lawsuits were consolidated, and Idaho Power intervened in that lawsuit and the parties reached a settlement. The court dismissed the third challenge to the Oregon draftCWA 401 certifications were released for public comment incertification with prejudice. No parties challenged the Idaho CWA 401 certification. In December 2018. After the public comment period closes in February 2019, Idaho Power anticipates the states will evaluate the comments and draft final 401 certifications, which must be completed by June 2019 for the current cycle.

In September 2007, in connectionfiled an Offer of Settlement with the issuanceFERC 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 its final EIS,2020, the FERC notifiedreceived several comments opposing the NMFSOffer of Settlement, 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. Each of the NMFS and USFWS responded to the FERC that the conditionsdecision relating to the licensingOffer of Settlement is pending as of the HCC were not fully described or developed in the final EIS as the measures to address the water quality effectsdate of the project were yet to be fully defined by the Section 401 certification process. The NMFS and USFWS therefore recommended that formal consultation under the ESA be delayed until the Section 401 certification process is completed.this report.


Idaho Power continues to work with Idaho and Oregon in the development ofon measures to provide reasonable assurance that any discharges from the HCC will comply with applicable state water quality standards so that appropriate water qualityand associated measures identified in the final Section 401 certifications, can be issued for the project, and continues to cooperate with the USFWS, the NMFS, and the FERC in an effort to address ESA concerns. Idaho Power has begunMeasures identified in the final Section 401 certifications included construction of new aerated runners at the Brownlee project (part of the HCC) at an estimated cost of $59 million. Three of four units were installed by the end of 2018 and Idaho Power plans to install the final unit in 2019. Other measures that have been proposed or considered have included, modification of spillways at the three dams in the HCC to address total dissolved gas issues, and upstream watershed improvements or the installation of a temperature
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control structure to address water temperaturestemperature exceedances during a small portion of the year. If Idaho Power is required to take these orThese and any other additional measures to satisfy relicensing requirements it couldhave 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 incorporated the settlement agreement reached between Idaho and Oregon on the CWA Section 401 certifications and provided feedback on proposed modification of the 2007 final EIS for the HCC. The July 2020 filing also contained an updated cost analysis of the HCC and a request for the FERC to issue a 50-year license and initiate a supplemental National Environmental Policy Act (NEPA) process at the FERC. Idaho Power prepared draft biological assessments in consultation with the 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 the ESA. In December 2020, FERC staff issued six additional information requests (AIRs) from Idaho Power to help with the analysis and baseline for the project moving forward. Idaho Power has filed responses to all six of the AIRs with FERC. Subsequently, in September 2021 FERC issued ten additional AIRs 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 USFWS and the NMFS.

As of the date of this report, Idaho Power is unable to predict the exact timing of issuance bythat the FERC of anywill issue a new license order or the ultimate capital investment and ongoing operating and maintenance costs Idaho Power will incur in complying with any new license. However,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, but excluding costs expected to be incurred for complying with the license after issuance, are likely to range from $30 million to $40 million until issuance of the license. Subsequent to the issuance of a new license, which Idaho Power estimates will occur no earlier than 2022. In December 2016, Idaho Power filed an applicationexpects to incur increased annual operating and maintenance costs to comply with the IPUC requesting a determination thatrequirements of any new license.

American Falls Relicensing: In April 2020, the FERC formally initiated the relicensing proceeding for the American Falls hydropower facility, which is Idaho Power's expenditures of $220.8 million through year-end 2015 on relicensinglargest hydropower facility outside of the HCC, were prudently incurred, and thus eligible for future inclusion in retail rates inwith a future rate proceeding. In December 2017,generating capacity of 92.3 MW. Idaho Power filedowns the generation facility but not the structural dam itself, which is owned by the U.S. Bureau of Reclamation. The FERC recognized Idaho Power’s pre-application document, including a proposed process plan and schedule, and recognized Idaho Power’s intent to file an application for a license. A final license application is due to the FERC in 2023. The relicensing proceeding will begin the process of informal ESA Section 7 consultation with the IPUC a settlement stipulation signed byUSFWS and Section 106 of the National Historic Preservation Act consultation with the Idaho State Historic Preservation Office. American Falls' current
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license expires in 2025, and as of the date of this report, Idaho Power expects the IPUC Staff, andFERC to issue a third party intervenor recognizing that a total of $216.5 million in expenditures were reasonably incurred, and therefore should be eligiblenew license for inclusion in customer rates at a later date. As a result of filingthis facility prior to the settlement stipulation, Idaho Power recorded a $5.0 million pre-tax charge in 2017, which included $4.3 million for cost incurred through 2015, as well as $0.7 million related to associated costs incurred in 2016 and 2017. Of the $5.0 million pre-tax charge in 2017, $2.5 million was recorded as Other O&M expense and $2.5 million was recorded as a reduction to AFUDC. In April 2018, the IPUC issued an order approving the settlement stipulation as filed with the IPUC and determined the associated costs to be reasonably and prudently incurred.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, 2018, 2017,2021, and 2016,2020, Idaho Power's REC sales totaled $2.9 million, $2.3$4.7 million and $1.0$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.


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Renewable and Other Energy Contracts: Idaho Power has contracts for the purchase of electricity produced by third-party owned generation facilities, most of which produce energy with the use of renewable generation sources such as wind, solar, biomass, small hydroelectrichydropower, and geothermal. The majority of these contracts are entered into as mandatory purchases under PURPA. As of December 31, 2018,2021, Idaho Power had contracts to purchase energy from 127129 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, 2018,2021, the resource type and nameplate capacity of Idaho Power's signed agreements for energypower purchases from PURPA and non-PURPA generating facilities. These agreements have original contract terms ranging from one to 35 years.
Resource Type Total On-line (MW) Under Contract but not yet On-line (MW) Total Projects under Contract (MW)Resource TypeOn-line megawatts (MW)Under Contract but not yet On-line (MW)Total Projects under Contract (MW)
PURPA:      PURPA:
Wind 627
 —
 627
Wind627 — 627 
Solar 290
 27
 317
Solar316 74 390 
Hydroelectric 146
 2
 148
HydropowerHydropower150 1 151 
Other 56
 —
 56
Other44 — 44 
Total PURPA 1,119
 29
 1,148
Total PURPA1,137 75 1,212 
Non-PURPA:      Non-PURPA:
Wind 101
 —
 101
Wind101 — 101 
Geothermal 35
 —
 35
Geothermal35 — 35 
SolarSolar— 120 120 
Total non-PURPA 136
 —
 136
Total non-PURPA136 120 256 
 
The projects not yet on-line include one hydroelectricPURPA-qualifying facility hydropower project and five solar projects that are is scheduled to be on-line in 2019.2022, 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
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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's activities arePower 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, 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 threetwo 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 hydroelectrichydropower 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; or
•reduce the output from current generating facilities.facilities; or

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

Current and future environmental laws and regulations willcould 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 agree to cease operation of the Boardman coal-firedpower plant in which Idaho Power owns a 10 percent interest, by the end ofOctober 2020 was based in part on the significant future cost of compliance with environmental laws and regulations. The decision to pursue an end to participation in coal-fired operations at the North Valmy Plantplant was also based primarily on the economics of operating the plant. Additionally, in light of the uncertainty resulting from pending environmental regulation and the substantial estimated cost of selective catalytic reduction equipment
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(SCR) installation, Idaho Power continues to assess whether to move forward with the installation of SCR on units 1 and 2 at the Jim Bridger power plant. Beyond increasing costs generally, these environmental laws and regulations could affect IDACORP's and Idaho Power's results of operations and financial condition if the costs associated with these environmental requirements and early plant retirements cannot be fully recovered in rates on a timely basis.


Part I, Item 1 - “Business - Utility Operations - Environmental Regulation and Costs” in this report includes a summary of Idaho Power's expected capital and operating expenditures for environmental matters during the period from 20182022 to 2020.2024. Given the uncertainty of future environmental regulations and technological advances, there is uncertainty around near-term estimates, and Idaho Power is also unable to predict its environmental-related expenditures beyond 2020,2024, though they could be substantial. Furthermore, several executive orders issued insince 2017 and 2018 concerning environmental regulations, including executive orders issued by the current Presidential Administration in 2021, as described below, could result in significant changes in, and uncertainty with respect to, legislation, regulation, and government policy regarding environmental matters. For example, in August 2017, an executive order was issued to accelerate federal agencies' environmental review and permitting for major infrastructure projects. The outcome of federal agencies' review of regulations covered by executive orders and revocation of executive orders is difficult to predict. Changes to or elimination of regulations may lower Idaho Power's costs of operating and maintaining fossil fuel-fired generation plants and transmission lines, due to the reduction of potential environmental infrastructure upgrades or reduction or elimination of permitting requirements. Executive orders resulting in modifications to federalmore strict or robust regulations, could,or additional regulations, on the other hand, would likely increase Idaho Power's costs of operating and maintaining its facilities. 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.

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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, any future executive orders, and the implementation of these and any future executive orders may impact Idaho Power's business, results of operations and financial condition.

Endangered Species Act Matters


Overview: The listing of a species of fish, wildlife, or plants as threatened or endangered under the ESA may have an adverse impact on Idaho Power's ability to construct generation,power supply, transmission, or distribution facilities or relicense or operate its hydroelectrichydropower 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 February 2016, the USFWS and the NMFS issued a set of regulatory and policy changes relating to critical habitat and adverse modification determinations under the ESA. While the ultimate impact of implementation of those changes is yet to be determined, taken as a whole, Idaho Power believes that the changes could result in the applicable agencies having greater authority in making designations of critical habitat and could increase the likelihood of adverse modification determinations.


In July 2018, the USFWS and the NMFS issued three proposals to revise ESA regulations (2018 ESA Proposals) related to the process and standards for listing species and designating critical habitat, the process for consultations with federal agencies under Section 7 of the ESA (including the definition of "destructive or adverse modification" of designated critical habitat), and the scope of protection of threatened species. Idaho Power believes that if the 2018 ESA Proposals are promulgated, the regulations could reduce Idaho Power’s obligations for mitigation under the ESA related to various construction and relicensing projects. Furthermore, in November 2018, the U.S. Supreme Court held that an area is eligible for designation as a critical habitat under the ESA only if it is also "habitat" for the species as defined in the statute, which generally means the area can support the species without modification, and as part of the designation, the USFWS must also consider the costs compared 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.


In June 2021, in response to the January 2021 Executive Orders directing federal agencies to review certain environmental regulations, the USFWS and the NMFS released a plan to initiate rulemaking to revise, rescind, or reinstate five ESA regulations finalized by the prior administration. The agencies announced that they intend to rescind regulations that revised the USFWS's process for considering exclusions from critical habitat designations, rescind the regulatory definition 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 USFWS and NMFS proposed new rules to remove exclusions for certain territory subject to critical habitat designations and to rescind the prior administration's regulatory definition of habitat.

The construction of generation,power supply, transmission, or distribution facilities and the relicensing of Idaho Power's hydroelectrichydropower projects can be federally authorized actions that fall under the ESA. There are a number of threatened or endangered species within Idaho Power's service area and within or near proposed transmission line routes, including the slickspot peppergrass. 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 hydroelectrichydropower facilities, including fall Chinook salmon, bull
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trout, Bliss Rapids snail, and Snake River physa snail. 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 hydroelectrichydropower 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 hydroelectrichydropower 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.
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Developments in Regulation of Sage Grouse Habitat: In February 2016, a lawsuit was filed in the U.S. District Court of Idaho challenging the BLM's sage grouse resource management and land use plan revisions that became effective in 2015 under the Federal Land Policy and Management Act. The lawsuit challenges the plans and associated environmental impact statementsEISs across the sage grouse range and alleges that the plans fail to ensure that sage grouse populations and habitats will be protected and restored in accordance with the best available science and legal mandates. Further, the complaint challenges certain exemptions provided for the Boardman-to-Hemingway and Gateway West transmission line projects. Idaho Power has intervened in the proceedings in an effort to support the exemptions provided for in the BLM's plans. If the exemptions are overturned, Idaho Power may be required to 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 December 2018,March 2019, the BLM issued draft resource management plan amendments and a final environmental impact statements to modifyrecord of decision for six EISs that modified the 2015 sage grouse plans to better align the plan with state plans, conservation measures and the Department of the Interior and BLM policy. In October 2019, the U.S. District Court for Idaho placed a preliminary injunction on the implementation of the BLM's March 2019 plans. In order to address the concerns contained in the preliminary injunction, BLM initiated a supplemental EIS process that was completed in November 2020. A record of decision for the 2020 supplemental EIS was signed in January 2021. In November 2021, the BLM issued a notice of intent to address the management of sage grouse and sagebrush habitat on BLM-managed public lands in Idaho and Oregon, among other states, through a land use planning initiative. The BLM indicated that it will prepare an EIS to support the planning initiative, and will begin the scoping process to solicit public comments on the planning initiative by February 2022.

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.

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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. FormalIdaho Power prepared draft biological assessments in consultation has yet to be initiatedwith 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 continueand the NMFS to gather and consider information relative toissue their biological opinion as required under the effects of relicensing on relevant ESA listed species.ESA. Idaho Power continuesexpects the FERC to cooperateinitiate formal ESA consultation with the USFWS the NMFS, and the FERC in an effort to address ESA concerns. In December 2004, Idaho Power and eleven other parties, including 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.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 Section 7 of the ESA. The issuance of a final biological opinion during 20192022 is unlikely.


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

The USFWS has also indicated it intends to designate critical habitat forWashington ground squirrel inhabits various locations throughout two of the species. If critical habitat is designatedcounties within the vicinity ofproposed 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 line projects, Idaho Power expects that the designation could increase the cost of obtaining permits for the projectswould require additional permitting and would likely involve increased permitting costs and could further delay the in-service date of the projects.project.


Endangered Species Act and National Environmental Policy Act Developments: Lower Snake River Hydroelectric Projects: In May 2016, the United States District Court for the District of Oregon issued an opinion finding that in the context of hydroelectrichydropower 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, failing to consider adequately the impact of climate change on habitat conditions, 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 National Environmental Policy Act (NEPA)NEPA by failing to prepare a comprehensive environmental impact statementEIS 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
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result in considerable increases in cost beyond the cost of additional analysis in the NEPA process. In September 2016, federal agencies initiated an environmental impact statement processEIS to examine hydroelectrichydropower dams on the lower Snake River, which Idaho Power expectsRiver. In September 2020, the federal agencies signed a record of decision on the EIS that will take place over a five-year period.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 hydroelectrichydropower 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. NEPA applies to Idaho Power’s transmission and distribution lines that are located on federal land, as well as other company activities involving federal actions. Under Executive Order 13990 issued in January 2021, the current Presidential Administration’s CEQ was tasked with reviewing the 2020 NEPA Rule. In October 2021, the CEQ published a notice of proposed rulemaking to reverse the more narrow 2020 NEPA Rule, with minor modifications, which if promulgated as proposed could delay and increase the cost of Idaho Power’s transmission projects. The 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.

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Climate Change and the Regulation of Greenhouse Gas Emissions


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


•changes in temperature and precipitation could affect customer demand and energy loads;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 hydroelectrichydropower generation;
•legislative and/or regulatory developments related to climate change could affect plants and operations, including restrictions on the construction of new generationpower supply resources, the expansion of existing resources, or the operation of generationpower 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 COcarbon dioxide (CO2) emissions from coal, including carbon capture and storage, are still in the development stage and are not yet 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 plans to endended its participation in coal-fired operations at the Valmy Plant units 1 and 2 in 2019 and 2025, respectively, and to cease coal-fired operations at the Boardman power plant in October 2020 and the North Valmy plant unit 1 in December 2019, and plans to end its participation in the North Valmy plant unit 2 no later than December 31, 2020.the end of 2025. Idaho Power's 2021 IRP contemplates the conversion from coal to natural gas of two units at the Jim Bridger plant 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.


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 emission 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: Plan/Affordable Clean Energy Rule: The U.S. Environmental Protection Agency (EPA)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 June 2014,August 2015, the EPA released,promulgated the Clean Power Plan (CPP) under Section 111(d) of the CAA, a proposed rule for addressing GHG from existing fossil fuel-fired electric generating units (EGUs). The proposed rule was intended to achieve a 30 percent reduction in CO2 emissions from the power sector by 2030. In August 2015, the EPA released the final rule under Section 111(d) of the CAA, referred to as the Clean Power Plan (CPP), which required states to adopt plans to collectively reduce 2005 levels of power sector CO2 emissions by 32 percent by the year 2030. The final rule provided states until September 2018 to submit implementation plans, phasing in several compliance periods beginning in 2022 and achieving the final emissions goals by 2030. In August 2018,June 2019, the EPA proposedreleased 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
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utility generating units. The new proposed rule is limited to reduction and compliance measures that occur atvacated the physical location of each plant, removing the proposal to require reductions outside the boundaries of plants. The ACE rule also provides for more state-specific control over implementation ofwithout reinstating the rule to address greenhouse gas emissions from existing coal-fired power plants, with a focus on state evaluation of improvement potential, technical feasibility, applicability, and remaining useful life of each unit. Because the rule is premised on state implementation plans, the terms of which Idaho Power does not control, and due to the existing and potential changes in legislation, regulation, and government policy with respect to environmental matters as a result of the presidential administration's executive orders and the EPA's proposal to repeal and replace the CPP discussed above, asCPP. As of the date of this report, and in light of these executive actions, Idaho Power is uncertain whetherexpects to continue with its planned retirements and to what extent the replacement CPP may impact its operations in the near term.other planned upgrades at generating facilities.


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 coal-fired power plant located in Oregon, in which Idaho Power iswas a 10-percent owner, iswas subject to and in compliance with Oregon's GHG reporting requirements but is scheduled to ceaseceased coal-fired operations in 2020.


In Oregon, legislation referred to as the Oregon Clean Electricity and Coal Transition Plan was enacted in March 2016, and 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 emissionemissions reporting system. The Climate Registry is a collaboration aimed at developing and managing a common GHG emissionemissions 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), 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 provided that sources must be in compliance with emission limits by April 2015. Idaho Power and the plant co-owners have installed mercury continuous emission monitoring systems on all of the coal-fired units at the Jim Bridger Boardman, and North Valmy coal-fired generating plants, along with control technology to reduce mercury, acid gases, and particulate matter emissions for purposes of compliance with the MATS rule. Idaho Power believes that as of the date of this report, the coal-fired plants are in 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, andwhich does not expect the EPA’s review of the MATS rule to have a significantsignificantly impact on Idaho Power’s operations or financial results.


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, NOnitrogen dioxide (NO2), and SOsulfur dioxide (SO2). States are then required to develop emissionemissions 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 relevant to Idaho Power include the following:


•
NO2:In 2010, the EPA adopted a new NAAQS for NO2
•NO2:In 2010, the EPA adopted a new NAAQS for NO2 at a level of 100 parts per billion averaged over a 1-hour
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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, Oregon, and Wyoming where Idaho Power owns or has an interest in a natural gas or coal-fired power plant as “unclassifiable/attainment” for NO2. The

•SO2: In 2010, the EPA indicated it would reviewadopted a new NAAQS for SO2 at a level of 75 parts per billion averaged over a one-hour period. In 2011, the designations after 2015, when three yearsstates 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
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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 monitoring data are available, and may formally designatefor those states showed no violations of the counties as attainment or non-attainment2010 SO2 standard. Since January 2018, the EPA has finalized designations of “unclassifiable/attainment” for NOSO2. A designation of non-attainment may increase the likelihood that for all areas in which Idaho Power would be required to install costly pollution control technology at oneowns or more of its plants.has an interest in a natural gas or coal-fired power plant.

•
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 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 U.S.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 standards 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 four units at the Jim Bridger and the Boardman coal-fired plants. The RH BART rules would have required installation of a suite of emissions controls at the Boardman plant; however, in December 2010, the Oregon Environmental Quality Commission approved a plan to install a less costly suite of environmental controls and cease coal-fired operations at the Boardman power plant no later than December 31, 2020.plant.


In December 2009, the WDEQ issued a RH BART permit to PacifiCorp as the operator of the Jim Bridger plant. As part of the WDEQ's long term strategy for regional haze, the permit required that PacifiCorp install SCRselective 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 NOx controls at Jim Bridger unit 2 by 2021 and unit 1 by 2022, which was submitted in December 2017. Idaho Power is assessing whether to move forward with installation of SCR equipment at units 1 and 2. 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 on the EPA ultimately approving those portions of the Wyoming regional haze SIPstate implementation plan (SIP) that are consistent with the terms of the settlement agreement. In January 2014, the EPA approved Wyoming's regional haze SIP as to the Jim Bridger plant, with the NOx control compliance dates set forth in the settlement agreement. Several interested parties have appealed

In February 2019, PacifiCorp submitted a SIP revision to the EPA's decisions on Wyoming'sWDEQ as an alternative regional haze SIP on various grounds. Idaho Power has not appealed the EPA's decisions but has intervened in the proceedings to participate if and to the extentcompliance plan for the Jim Bridger plant could be affected.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. In May 2020, 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 State of Wyoming and PacifiCorp issued a Notice of Intent to sue the EPA for the EPA’s failure to act on the 2019 proposed SIP revision. The Notice of Intent was intended to allow PacifiCorp and Wyoming to bring a non-delegable duty suit against the EPA. On December 27, 2021, Wyoming Governor Gordon issued a temporary emergency suspension of Wyoming’s existing SIP that allows Jim Bridger unit 2 to continue to operate through the end of April 2022. On January 12, 2022, the EPA issued a proposed rule that, if adopted, would disapprove the 2019 proposed SIP revision, and the proposed rule was published in the Federal Register on January 18, 2022. Comments on the proposed disapproval are due by February 17, 2022, and as 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 PacifiCorp 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. As of the date of this report, the revised permit application and RFP are pending.


Clean Water Act Matters


Definition of “Waters of the United States” Under the CWA: OnIn August 28, 2015, the EPA'sEPA and U.S. Army Corps of Engineers'USACE final rule defining the phrase "waters of the United States" (WOTUS) under the CWA became effective (WOTUS Rule). Idaho Power believes that the final2015 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. The StateIn January 2020, the EPA and USACE finalized the first of Idaho,a two-part rule to repeal the WOTUS Rule and several other parties, challengedset new and more expansive standards for determining which waters are subject to the rule in North Dakota federal court. That court held that it had jurisdictionCWA, which substantially restored the definitions and enjoined the implementation ofguidance used prior to the WOTUS Rule. In February 2017, President Trump issued an executive order directingApril 2020, the EPA and USACE published the U.S. Army Corpssecond part of Engineersthe final rule to rescindreplace the WOTUS Rule. In July 2017,Rule
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with the EPA and the U.S. Army Corps of Engineers issued"Navigable Waters Protection Rule" that provides a notice of their intent to rescind and replace thefinal definition of "waters of the United States"States," which ultimately narrows the scope of waters subject to federal regulation under the CWA, which Idaho Power expects would reduce the number of watersCWA. The Navigable Waters Protection Rule became effective in Idaho Power's service area subjectJune 2020. In November 2021, in response to the WOTUS Rule. In November 2017,January 2021 Executive Orders, the EPA issuedand USACE announced the availability of a noticepre-publication version of a proposed rule that it will delayrestores the effectiveness of the WOTUS Rule until 2020
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while the U.S. Army Corps of Engineers considers a replacement rule. In January 2018, the U.S. Supreme Court issued a unanimous ruling that challengesprotections in place prior to the WOTUS Rule must begin with the federal district courts, effectively negatingand establishes a nationwide stay issued by the Sixth Circuit in 2016. However, because the State of Idaho remains a party to the federal court action in North Dakota, that court’s enjoinder remains in effect, meaning the WOTUS Rule currently does not apply to actions brought in Idaho. In July 2018, the EPA and the U.S. Army Corps of Engineers issued a supplemental notice seeking additional comment on their 2017 proposal to repeal the definition of the term WOTUS Rule under the CWA. In August 2018, the U.S. District Court for the District of South Carolina issued a nationwide injunction on the EPA’s suspension of the WOTUS Rule, resulting in the WOTUS Rule taking effect in twenty-two states and Washington D.C. The WOTUS Rule does not currently apply in twenty-eight states, including Idaho, and litigation over both the WOTUS Rule and the EPA’s suspension of the WOTUS Rule continues. In December 2018, the EPA and U.S. Army Corps of Engineers proposed a rule to significantly limit thenew expansive definition of "waters of the United States" under the CWA.States."


Idaho Power has analyzedbelieves 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 hydroelectrichydropower plants, Idaho Power does not expect this proposal toreinstatement would have a material benefit toimpact on Idaho Power's operations or financial condition.


CWA Matters Related to Hydroelectric Relicensing: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 is also addressing CWA issues associated with the relicensing of its HCC. See “Relicensing of Hydroelectric Projects” in this MD&A for additional information on the impactfiled 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 that relicensing effort.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. In December 2019, Idaho Power filed an Offer of Settlement with the FERC requesting specific language be included in the new HCC license based upon the fish settlement among Idaho, Oregon, and Idaho Power. During the first quarter of 2020, the FERC received several comments opposing the Offer of Settlement and its decision relating to the Offer of Settlement is pending as of the date of this report.

Review of Federal Coal Leases


In January 2016,July 2020, the SecretaryEPA published a rule amending regulations intended to implement the CWA Section 401 water quality certification process. The rule clarifies that a state must issue its water quality certification within a reasonable time period, up to one year from the certification request, and limits the scope of the certification to jurisdictional water quality matters. Further, the new regulations make clear that federal agencies, not the state departments of environmental quality, will enforce the certification conditions. This rule became effective in September 2020 (2020 CWA Section 401 Order). In October 2021, the U.S. DepartmentDistrict Court for the Northern District of the InteriorCalifornia issued an order directingremanding and vacating the BLM to prepare2020 CWA Section 401 Order, which order applies nationwide, and requires a Programmatic Environmental Impact Statement (PEIS) to analyze potential reformstemporary return to the federal coal lease program and placed a moratorium on new federal coal leasing, with limited exceptions, pending completionEPA's previous Section 401 of the PEIS. In January 2017,CWA in effect since 1979. While the SecretaryEPA finalizes a new certification rule, Idaho Power plans to continue to operate under the current CWA Section 401 regulations as described above.

Idaho Power expects the EPA to expand state and tribal authority over water quality certifications; however, such expanded authority would not likely impact the timing and cost of the HCC certification unless the FERC declines to adopt the Offer of Settlement, in which case Idaho Power would file new water quality certification applications in Idaho and Oregon with revisions necessary to address changes to the regulations, which Idaho Power cannot currently predict and could delay the timing of issuance and increase the cost of obtaining a license for the HCC.

CWA Permitting: Idaho Power's hydropower generation facilities are subject to compliance and permitting obligations under the CWA. Idaho Power has been engaged for several years with the EPA, and is now engaged with the Idaho Department of Environmental Quality (IDEQ), regarding Idaho Power's CWA permitting obligations and compliance status for those facilities. Idaho Power has in the Interior ordered a cessation of all work onpast, and expects in the PEISfuture, to incur costs and in March 2017 lifted the moratorium on new federal coal leases. Asexpenses associated with those permitting and compliance obligations, but as of the date of this report, Idaho Power believes that BCC has adequate reserves under existing leasesis unable to satisfyestimate with any reasonable certainty those costs and expenses. Idaho Power also expects to incur additional expenses associated with the relicensing of its coal delivery obligations to the Jim Bridger plant during the termhydroelectric facilities, as discussed elsewhere in this report.

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CRITICAL ACCOUNTING POLICIES AND ESTIMATES
 
When preparing financial statements in accordance with the accounting principles generally accepted in the United States of America (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 disclosure of contingent assets and liabilities.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 maymust 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 $1.2$1.5 billion of regulatory assets and $0.8 billion of regulatory liabilities at December 31, 2018.
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2021. 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.


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 planplans 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).
 
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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, 2018,2021, with maturities matching the projected cash outflows of the plans. Based on the results of this analysis, the discount rate used to calculate the 20192022 defined benefit plan pension expense will be increased to 4.553.05 percent from the 3.952.80 percent rate used in 2018.2021.
 
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 20192022 pension expense will be 7.57.4 percent, the same assumption as was used for 2018.in 2021.


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GrossTotal net periodic pension and other postretirement benefit cost for these plans totaled $51.2 million, $50.4$65.6 million and $51.8$53.8 million for the years ended December 31, 2018, 2017,2021 and 2016,2020, respectively, including amounts deferred as regulatory assets (see discussion below) and amounts allocated to capitalized labor. For 2019, gross2022, total net periodic pension costs and other postretirement benefit costs are expected to total approximately $51.4$45.4 million, which takes into account the change in the discount rate noted above.
 
Had different actuarial assumptions been used, net periodic pension expensecosts 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 expense:benefit costs:
  Discount rate Rate of return
  2019 2018 2019 2018
  (millions of dollars)
Effect of 0.5% rate increase on net periodic benefit cost $(7.0) $(7.9) $(3.5) $(3.7)
Effect of 0.5% rate decrease on net periodic benefit cost 7.8
 8.8
 3.4
 3.6
 Discount rateRate of return
 2022202120222021
 (millions of dollars)
Effect of 0.5% rate increase on total net periodic pension costs and other postretirement benefit costs$(10.9)$(10.7)$(5.0)$(4.6)
Effect of 0.5% rate decrease on total net periodic pension costs and other postretirement benefit costs12.1 12.3 5.1 4.5 
 
Additionally, a 0.5 percent increase in the plans' discount rates would have resulted in a $76.2$119.4 million decrease in the combined benefit obligations of the plans as of December 31, 2018.2021. A 0.5 percent decrease in the plans' discount rates would have resulted in an $85.7$135.9 million increase in the combined benefit obligations of the plans as of December 31, 2018.2021.


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, 2018,2021, a total of $148$234 million of expense was deferred as a regulatory asset. Approximately $23Idaho Power expects to defer approximately $16 million is expected to be deferredof expense in 2019.2022. Idaho Power recorded pension expense on its consolidated statements of income related to its tax-qualified defined benefit pension plan of approximately $19 million in 2018, 2017,2021 and 2016.2020.
 
Refer to Note 12 – “Benefit Plans” to the consolidated financial statements included in this report for additional information relating to pension and postretirement benefit plans.


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RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS


ForThere have been no recently issued accounting pronouncements that have had or are expected to have a listingmaterial impact on IDACORP's or Idaho Power's results of new and recently adopted accounting standards, seeoperations or financial condition. See Note 1 - "Summary“Summary of Significant Accounting Policies" to the notesPolicies” to the consolidated financial statements included in this report.report for a summary of significant accounting policies.



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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, 2018.2021. IDACORP and Idaho Power have not entered into any of these market-risk-sensitive instruments for trading purposes.
 
Interest Rate Risk
 
IDACORP and Idaho Power manage 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, 2018,2021, IDACORP and Idaho Power had no net floating rate debt, as the carrying value of short-term investments exceeded the carrying value of outstanding variable-rate debt.
Fixed Rate Debt: As of December 31, 2018,2021, Idaho Power had $13.9 million of net floating 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, both IDACORP and Idaho Power had $1.8$2.0 billion in fixed rate debt, with a fair market value of approximately $1.9$2.4 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 $276.8$234.7 million if market interest rates were to decline by one percentage point from their December 31, 2018,2021 levels.
 
Commodity Price Risk
 
IDACORP's exposure to changes in commodity prices is related to Idaho Power's ongoing utility operations that produce electricity to meet the demand of its retail electric customers. These effects of changes in commodity prices on Idaho Power are mitigated in large part by Idaho Power's Idaho and Oregon power cost adjustment mechanisms. To supplement its generationpower supply resources and balance its supply of power with the demand of its retail customers, Idaho Power participates in the wholesale marketplace. These purchasedPurchased 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 Power are mitigated in large part by Idaho Power's Idaho and Oregon power cost adjustment mechanisms.
 
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 aan energy risk management program, which 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 (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), comprises selectedcomposed of Idaho Power officers and other senior staff,managers, oversees the risk management program. The RMC is responsible for communicating the status of risk management activities to the Idaho PowerPower's Board of Directors and to the CAG, and Idaho Power’s Audit Committee is responsible for approving the Energy Risk Management
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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. 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 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 standards 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
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risk mitigating actions, including resource optimization and hedging strategies, dictated by the limits stated in the Energy Risk Management Policy and associated standards 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.


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, 2018,2021, Idaho Power had no 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 market conditions as of December 31, 2018,2021, the amount of collateral that could be requested upon a downgrade to below investment grade was approximately $10.5$25.7 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 12 - "Benefit Plans" to the consolidated financial statements included in this report.


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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA


Index to Financial Statements and Financial Statement Schedules


Consolidated Financial StatementsPage
Consolidated Financial StatementsIDACORP, Inc.:Page
IDACORP, Inc.:
Consolidated Statements of Income
7782
Consolidated Statements of Comprehensive Income
7883
Consolidated Balance Sheets
7984
Consolidated Statements of Cash Flows
8186
Consolidated Statements of Equity
8287
Idaho Power Company:
Consolidated Statements of Income
8388
Consolidated Statements of Comprehensive Income
8489
Consolidated Balance Sheets
8590
Consolidated Statements of Cash Flows
8792
Consolidated Statements of Retained Earnings
8893
Notes to the Consolidated Financial Statements
8994
Reports of Independent Registered Public Accounting Firm - Deloitte & Touche LLP (PCAOB ID No. 34)
130133
Supplemental Financial Information and Financial Statement Schedules
Supplemental Financial Information (unaudited)
132
Financial Statement Schedules:
IDACORP, Inc. - Schedule I - Condensed Financial Information of Registrant
146150
IDACORP, Inc. - Schedule II - Consolidated Valuation and Qualifying Accounts
148
Idaho Power Company - Schedule II - Consolidated Valuation and Qualifying Accounts
149152


All other schedules have been omitted because they are not required, not applicable, or the required information is otherwise included.
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IDACORP, Inc.

Consolidated Statements of Income


Year Ended December 31,
 202120202019
(thousands of dollars except for per share amounts)
Operating Revenues:
Electric utility revenues$1,455,410 $1,347,340 $1,342,940 
Other2,674 3,389 3,443 
Total operating revenues1,458,084 1,350,729 1,346,383 
Operating Expenses:
Electric utility:
Purchased power393,691 297,417 285,266 
Fuel expense180,550 172,740 156,872 
Power cost adjustment(49,844)(33,708)2,047 
Other operations and maintenance361,297 352,071 355,770 
Energy efficiency programs29,920 42,478 40,128 
Depreciation175,555 171,648 169,210 
Other electric utility operating expenses34,673 35,914 35,995 
Total electric utility expenses1,125,842 1,038,560 1,045,288 
Other2,591 2,648 2,769 
Total operating expenses1,128,433 1,041,208 1,048,057 
Operating Income329,651 309,521 298,326 
Nonoperating (Income) Expense:
Allowance for equity funds used during construction(31,537)(29,551)(27,112)
Earnings of unconsolidated equity-method investments(11,435)(11,513)(12,370)
Interest on long-term debt84,145 84,251 82,457 
Other interest14,546 14,753 14,721 
Allowance for borrowed funds used during construction(11,993)(11,578)(10,703)
Other (income) expense, net3,141 (3,509)(6,502)
Total nonoperating expense, net46,867 42,853 40,491 
Income Before Income Taxes282,784 266,668 257,835 
Income Tax Expense36,912 28,700 24,507 
Net Income245,872 237,968 233,328 
Adjustment for income attributable to noncontrolling interests(322)(551)(474)
Net Income Attributable to IDACORP, Inc.$245,550 $237,417 $232,854 
Weighted Average Common Shares Outstanding - Basic (000’s)50,599 50,538 50,502 
Weighted Average Common Shares Outstanding - Diluted (000’s)50,645 50,572 50,537 
Earnings Per Share of Common Stock:
Earnings Attributable to IDACORP, Inc. - Basic$4.85 $4.70 $4.61 
Earnings Attributable to IDACORP, Inc. - Diluted$4.85 $4.69 $4.61 
  Year Ended December 31,
  2018 2017 2016
  (thousands of dollars except for per share amounts)
Operating Revenues:      
Electric utility revenues $1,366,582
 $1,344,893
 $1,259,353
Other 4,170
 4,593
 2,667
Total operating revenues 1,370,752
 1,349,486
 1,262,020
       
Operating Expenses:      
Electric utility:      
Purchased power 293,814
 248,950
 245,764
Fuel expense 133,198
 145,829
 179,491
Power cost adjustment 42,106
 52,024
 (5,330)
Other operations and maintenance 364,456
 346,695
 349,290
Energy efficiency programs 35,703
 39,241
 33,754
Depreciation 165,190
 162,091
 143,661
Taxes other than income taxes 34,792
 34,089
 32,823
Total electric utility expenses 1,069,259
 1,028,919
 979,453
Other 4,571
 5,022
 (1,015)
Total operating expenses 1,073,830
 1,033,941
 978,438
Operating Income 296,922
 315,545
 283,582
Allowance for Equity Funds Used During Construction 24,353
 20,784
 22,031
Earnings of Unconsolidated Equity-Method Investments 12,449
 11,374
 12,871
Other Expense, Net (2,867) (2,109) (1,932)
Interest Expense:     
Interest on long-term debt 84,408
 81,198
 81,956
Other interest 11,691
 11,242
 10,273
Allowance for borrowed funds used during construction (10,151) (8,694) (10,194)
Total interest expense, net 85,948
 83,746
 82,035
Income Before Income Taxes 244,909
 261,848
 234,517
Income Tax Expense 17,386
 48,660
 36,429
Net Income 227,523
 213,188
 198,088
Adjustment for (income) loss attributable to noncontrolling interests (722) (769) 200
Net Income Attributable to IDACORP, Inc. $226,801
 $212,419
 $198,288
Weighted Average Common Shares Outstanding - Basic (000’s) 50,432
 50,361
 50,298
Weighted Average Common Shares Outstanding - Diluted (000’s) 50,510
 50,424
 50,373
Earnings Per Share of Common Stock:      
Earnings Attributable to IDACORP, Inc. - Basic $4.50
 $4.22
 $3.94
Earnings Attributable to IDACORP, Inc. - Diluted $4.49
 $4.21
 $3.94


The accompanying notes are an integral part of these statements.
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IDACORP, Inc.
Consolidated Statements of Comprehensive Income
 
Year Ended December 31,
 202120202019
(thousands of dollars)
Net Income$245,872 $237,968 $233,328 
Other Comprehensive Income:
Unfunded pension liability adjustment, net of tax
  of $1,150, $(2,452), and $(4,658)
3,318 (7,074)(13,440)
Total Comprehensive Income249,190 230,894 219,888 
Comprehensive income attributable to noncontrolling interests(322)(551)(474)
Comprehensive Income Attributable to IDACORP, Inc.$248,868 $230,343 $219,414 
  Year Ended December 31,
  2018 2017 2016
  (thousands of dollars)
       
Net Income $227,523
 $213,188
 $198,088
Other Comprehensive Income:      
Unfunded pension liability adjustment, net of tax
  of $2,815, $(1,555), and $253
 8,120
 (5,990) 394
Total Comprehensive Income 235,643
 207,198
 198,482
Comprehensive (income) loss attributable to noncontrolling interests (722) (769) 200
Comprehensive Income Attributable to IDACORP, Inc. $234,921
 $206,429
 $198,682


The accompanying notes are an integral part of these statements.
 
 


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IDACORP, Inc.
Consolidated Balance Sheets
 
December 31,
20212020
(in thousands)
Assets
Current Assets:
Cash and cash equivalents$215,243 $275,116 
Short-term investments— 25,000 
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 
Income taxes receivable14,770 2,164 
Accrued unbilled revenues74,843 72,461 
Materials and supplies (at average cost)77,552 64,941 
Fuel stock (at average cost)18,045 31,646 
Prepayments24,676 20,184 
Current regulatory assets71,223 63,407 
Other5,708 1,995 
Total current assets595,873 642,401 
Investments123,824 126,948 
Property, Plant and Equipment:
Utility plant in service6,509,316 6,283,790 
Accumulated provision for depreciation(2,298,951)(2,193,831)
Utility plant in service - net4,210,365 4,089,959 
Construction work in progress670,585 597,152 
Utility plant held for future use4,511 4,109 
Other property, net of accumulated depreciation16,361 18,290 
Property, plant and equipment - net4,901,822 4,709,510 
Other Assets:
Company-owned life insurance67,343 62,382 
Regulatory assets1,462,431 1,495,488 
Other59,222 58,515 
Total other assets1,588,996 1,616,385 
Total$7,210,515 $7,095,244 
  December 31,
  2018 2017
  (in thousands)
Assets    
     
Current Assets:    
Cash and cash equivalents $267,492
 $76,649
Receivables:    
Customer (net of allowance of $1,725 and $2,013, respectively) 77,178
 75,249
Other (net of allowance of $264 and $180, respectively) 7,476
 30,438
Income taxes receivable 4,356
 8,147
Accrued unbilled revenues 69,318
 75,120
Materials and supplies (at average cost) 54,987
 55,745
Fuel stock (at average cost) 47,979
 56,638
Prepayments 16,492
 16,984
Current regulatory assets 48,707
 48,613
Other 3,655
 18
Total current assets 597,640
 443,601
     
Investments 101,178
 115,698
     
Property, Plant and Equipment:    
Utility plant in service 6,103,856
 5,906,162
Accumulated provision for depreciation (2,210,781) (2,098,274)
Utility plant in service - net 3,893,075
 3,807,888
Construction work in progress 480,259
 452,424
Utility plant held for future use 4,751
 8,075
Other property, net of accumulated depreciation 17,650
 15,488
Property, plant and equipment - net 4,395,735
 4,283,875
     
Other Assets:    
Company-owned life insurance 59,852
 59,323
Regulatory assets 1,165,467
 1,083,483
Other 62,882
 59,425
Total other assets 1,288,201
 1,202,231
     
Total $6,382,754
 $6,045,405


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


 
December 31,
20212020
(in thousands)
Liabilities and Equity
Current Liabilities:
Accounts payable$145,980 $120,576 
Taxes accrued14,229 19,508 
Interest accrued23,959 24,030 
Accrued compensation55,666 52,245 
Current regulatory liabilities11,239 11,104 
Advances from customers43,472 29,341 
Other31,079 30,767 
Total current liabilities325,624 287,571 
Other Liabilities:
Deferred income taxes842,375 800,251 
Regulatory liabilities781,695 757,730 
Pension and other postretirement benefits521,462 634,070 
Other63,485 48,752 
Total other liabilities2,209,017 2,240,803 
Long-Term Debt2,000,640 2,000,414 
Commitments and Contingencies00
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 
Retained earnings1,833,580 1,734,103 
Accumulated other comprehensive loss(40,040)(43,358)
Total IDACORP, Inc. shareholders’ equity2,668,436 2,559,980 
Noncontrolling interests6,798 6,476 
Total equity2,675,234 2,566,456 
Total$7,210,515 $7,095,244 
The accompanying notes are an integral part of these statements.

85
  December 31,
  2018 2017
  (in thousands)
Liabilities and Equity    
     
Current Liabilities:    
Accounts payable $110,824
 $90,277
Taxes accrued 12,009
 11,075
Interest accrued 23,622
 22,379
Accrued compensation 55,121
 47,018
Current regulatory liabilities 25,883
 1,404
Advances from customers 20,037
 18,414
Other 11,096
 10,182
Total current liabilities 258,592
 200,749
     
Other Liabilities:    
Deferred income taxes 699,878
 660,940
Regulatory liabilities 738,994
 698,044
Pension and other postretirement benefits 431,475
 438,869
Other 43,216
 44,566
Total other liabilities 1,913,563
 1,842,419
     
Long-Term Debt 1,834,788
 1,746,123
     
Commitments and Contingencies 
 
     
Equity:    
IDACORP, Inc. shareholders’ equity:    
Common stock, no par value (120,000 shares authorized; shares issued 50,420) 863,593
 857,207
Retained earnings 1,531,543
 1,426,528
Accumulated other comprehensive loss (22,844) (30,964)
Treasury stock (27 and 28 shares at cost, respectively) (1,932) (1,386)
Total IDACORP, Inc. shareholders’ equity 2,370,360
 2,251,385
Noncontrolling interests 5,451
 4,729
Total equity 2,375,811
 2,256,114
     
Total $6,382,754
 $6,045,405
     
The accompanying notes are an integral part of these statements.

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IDACORP, Inc.
Consolidated Statements of Cash Flows


Year Ended December 31,
 202120202019
(thousands of dollars)
Operating Activities:
Net income$245,872 $237,968 $233,328 
Adjustments to reconcile net income to net cash provided by operating activities:  
Depreciation and amortization179,444 175,941 173,800 
Deferred income taxes and investment tax credits23,901 25,175 22,389 
Changes in regulatory assets and liabilities(33,705)(36,246)(4,310)
Pension and postretirement benefit plan expense33,817 28,970 27,804 
Contributions to pension and postretirement benefit plans(44,220)(45,161)(48,525)
Earnings of equity-method investments(11,435)(11,513)(12,370)
Distributions from equity-method investments11,711 14,477 21,800 
Allowance for equity funds used during construction(31,537)(29,551)(27,112)
Other adjustments to net income, net8,929 10,457 8,040 
Change in:  
Accounts receivable(6,697)(374)(5,996)
Accounts payable and other accrued liabilities17,700 (356)(9,526)
Taxes 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 
Net cash provided by operating activities363,264 388,131 366,625 
Investing Activities:   
Additions to property, plant and equipment(299,999)(310,938)(278,705)
Payments received from transmission project joint funding partners5,876 3,197 2,442 
Investments in affordable housing and other real estate tax credit projects(15,148)(14,338)(2,687)
Distributions from equity-method investments, return of investment14,439 1,073 — 
Purchase of equity securities(17,186)(33,382)(10,896)
Purchases of short-term investments(25,000)(25,000)— 
Maturities of short-term investments50,000 — — 
Proceeds from sale of equity securities11,328 25,795 5,080 
Other2,037 6,335 4,274 
Net cash used in investing activities(273,653)(347,258)(280,492)
Financing Activities:   
Issuance of long-term debt— 310,000 166,100 
Premium on issuance of long-term debt— 31,384 — 
Retirement of long-term debt— (175,000)(166,100)
Dividends on common stock(146,119)(137,813)(129,677)
Tax 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)— 
Debt 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)
Cash and cash equivalents at beginning of the year275,116 217,254 267,492 
Cash and cash equivalents at end of the year$215,243 $275,116 $217,254 
Supplemental Disclosure of Cash Flow Information:   
Cash paid during the year for:   
Income taxes$34,330 $9,975 $14,055 
Interest (net of amount capitalized)$83,499 $81,074 $85,260 
Non-cash investing activities:
Additions to property, plant and equipment in accounts payable$53,690 $45,004 $38,815 
  Year Ended December 31,
  2018 2017 2016
  (thousands of dollars)
Operating Activities:      
Net income $227,523
 $213,188
 $198,088
Adjustments to reconcile net income to net cash provided by operating activities:  
  
  
Depreciation and amortization 169,120
 165,933
 147,294
Deferred income taxes and investment tax credits 11,292
 33,245
 35,732
Changes in regulatory assets and liabilities 48,392
 57,131
 (5,650)
Pension and postretirement benefit plan expense 32,256
 28,911
 29,581
Contributions to pension and postretirement benefit plans (45,899) (46,589) (45,301)
Earnings of unconsolidated equity-method investments (12,449) (11,374) (12,871)
Distributions from unconsolidated equity-method investments 31,115
 24,975
 25,641
Allowance for equity funds used during construction (24,353) (20,784) (22,031)
Gain on sale of investments and assets (155) (131) (103)
Other non-cash adjustments to net income, net 9,152
 8,454
 5,108
Change in:  
  
  
Accounts receivable 729
 1,045
 (6,315)
Accounts payable and other accrued liabilities 29,666
 (17,208) 13,300
Taxes accrued/receivable 4,725
 4,361
 662
Other current assets 12,707
 2,814
 (10,887)
Other current liabilities 6,848
 1,017
 (3,283)
Other assets (7,488) (8,734) (3,764)
Other liabilities (1,555) (1,093) (1,006)
Net cash provided by operating activities 491,626
 435,161
 344,195
Investing Activities:  
  
  
Additions to property, plant and equipment (277,853) (285,488) (296,950)
Payments received from transmission project joint funding partners 21,587
 6,074
 7,586
Purchase of available-for-sale securities (11,390) (11,356) (14,917)
Proceeds from sale of available-for-sale securities 5,007
 4,989
 15,693
Purchase of life insurance investment —
 —
 (10,000)
Other 4,472
 5,340
 4,655
Net cash used in investing activities (258,177) (280,441) (293,933)
Financing Activities:  
  
  
Issuance of long-term debt 220,000
 —
 120,000
Retirement of long-term debt (130,000) (1,064) (101,064)
Dividends on common stock (121,421) (113,127) (104,984)
Net change in short-term borrowings —
 (21,800) 1,800
Acquisition of treasury stock (3,614) (3,212) (3,329)
Make-whole premium on retirement of long-term debt (4,607) —
 (13,895)
Other (2,964) (348) (2,112)
Net cash used in financing activities (42,606) (139,551) (103,584)
Net increase (decrease) in cash and cash equivalents 190,843
 15,169
 (53,322)
Cash and cash equivalents at beginning of the year 76,649
 61,480
 114,802
Cash and cash equivalents at end of the year $267,492
 $76,649
 $61,480
Supplemental Disclosure of Cash Flow Information:  
  
  
Cash paid during the year for:      
Income taxes $5,272
 $14,742
 $3,302
Interest (net of amount capitalized) $80,951
 $80,004
 $78,334
Non-cash investing activities:      
Additions to property, plant and equipment in accounts payable $29,528
 $33,220
 $34,603


The accompanying notes are an integral part of these statements.
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IDACORP, Inc.
Consolidated Statements of Equity
 
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 
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 year2,668,436 2,559,980 2,464,628 
Noncontrolling Interests:
Balance at beginning of year6,476 5,925 5,451 
Net income attributable to noncontrolling interests322 551 474 
Balance at end of year6,798 6,476 5,925 
Total equity at end of year$2,675,234 $2,566,456 $2,470,553 
  Year Ended December 31,
  2018 2017 2016
  (thousands of dollars)
Common Stock:      
Balance at beginning of year $857,207
 $851,833
 $849,112
Cumulative effect of change in accounting principle —
 —
 234
Share-based compensation expense 9,362
 7,384
 5,561
Treasury shares issued (3,068) (2,069) (3,143)
Other 92
 59
 69
Balance at end of year 863,593
 857,207
 851,833
       
Retained Earnings:      
Balance at beginning of year 1,426,528
 1,323,198
 1,230,105
Cumulative effect of change in accounting principle —
 4,092
 (234)
Net income attributable to IDACORP, Inc. 226,801
 212,419
 198,288
Common stock dividends ($2.40, $2.24, and $2.08 per share, respectively) (121,786) (113,181) (104,961)
Balance at end of year 1,531,543
 1,426,528
 1,323,198
       
Accumulated Other Comprehensive (Loss) Income:      
Balance at beginning of year (30,964) (20,882) (21,276)
Cumulative effect of change in accounting principle —
 (4,092) —
Unfunded pension liability adjustment (net of tax) 8,120
 (5,990) 394
Balance at end of year (22,844) (30,964) (20,882)
       
Treasury Stock:      
Balance at beginning of year (1,386) (243) (57)
Issued 3,068
 2,069
 3,143
Acquired (3,614) (3,212) (3,329)
Balance at end of year (1,932) (1,386) (243)
       
Total IDACORP, Inc. shareholders’ equity at end of year 2,370,360
 2,251,385
 2,153,906
       
Noncontrolling Interests:      
Balance at beginning of year 4,729
 3,960
 4,160
Net income (loss) attributable to noncontrolling interests 722
 769
 (200)
Balance at end of year 5,451
 4,729
 3,960
       
Total equity at end of year $2,375,811
 $2,256,114
 $2,157,866


The accompanying notes are an integral part of these statements.

87
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Idaho Power Company
Consolidated Statements of Income
 
Year Ended December 31,
 202120202019
(thousands of dollars)
Operating Revenues$1,455,410 $1,347,340 $1,342,940 
Operating Expenses:
Operation:
Purchased power393,691 297,417 285,266 
Fuel expense180,550 172,740 156,872 
Power cost adjustment(49,844)(33,708)2,047 
Other operations and maintenance361,297 352,071 355,770 
Energy efficiency programs29,920 42,478 40,128 
Depreciation175,555 171,648 169,210 
Other operating expenses34,673 35,914 35,995 
Total operating expenses1,125,842 1,038,560 1,045,288 
Operating Income329,568 308,780 297,652 
Nonoperating (Income) Expense:
Allowance for equity funds used during construction(31,537)(29,551)(27,112)
Earnings of unconsolidated equity-method investments(10,211)(10,102)(10,285)
Interest on long-term debt84,145 84,251 82,457 
Other interest14,511 14,716 14,658 
Allowance for borrowed funds used during construction(11,993)(11,578)(10,703)
Other (income) expense, net3,171 (2,739)(4,217)
Total nonoperating expense, net48,086 44,997 44,798 
Income Before Income Taxes281,482 263,783 252,854 
Income Tax Expense38,257 30,548 28,417 
Net Income$243,225 $233,235 $224,437 
  Year Ended December 31,
  2018 2017 2016
  (thousands of dollars)
       
Operating Revenues $1,366,582
 $1,344,893
 $1,259,353
       
Operating Expenses:      
Operation:      
Purchased power 293,814
 248,950
 245,764
Fuel expense 133,198
 145,829
 179,491
Power cost adjustment 42,106
 52,024
 (5,330)
Other operations and maintenance 364,456
 346,695
 349,290
Energy efficiency programs 35,703
 39,241
 33,754
Depreciation 165,190
 162,091
 143,661
Taxes other than income taxes 34,792
 34,089
 32,823
Total operating expenses 1,069,259
 1,028,919
 979,453
       
Income from Operations 297,323
 315,974
 279,900
       
Other Income (Expense):      
Allowance for equity funds used during construction 24,353
 20,784
 22,031
Earnings of unconsolidated equity-method investments 10,712
 9,267
 10,855
Other expense, net (5,851) (4,756) (4,547)
Total other income 29,214
 25,295
 28,339
       
Interest Charges:      
Interest on long-term debt 84,408
 81,198
 81,956
Other interest 11,634
 11,156
 10,050
Allowance for borrowed funds used during construction (10,151) (8,694) (10,194)
Total interest charges 85,891
 83,660
 81,812
       
Income Before Income Taxes 240,646
 257,609
 226,427
       
Income Tax Expense 18,312
 51,262
 37,185
       
Net Income $222,334
 $206,347
 $189,242


The accompanying notes are an integral part of these statements.
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Idaho Power Company
Consolidated Statements of Comprehensive Income
 
Year Ended December 31,
 202120202019
(thousands of dollars)
Net Income$243,225 $233,235 $224,437 
Other Comprehensive Income:
Unfunded pension liability adjustment, net of tax
  of $1,150, $(2,452), and $(4,658)
3,318 (7,074)(13,440)
Total Comprehensive Income$246,543 $226,161 $210,997 
  Year Ended December 31,
  2018 2017 2016
  (thousands of dollars)
       
Net Income $222,334
 $206,347
 $189,242
Other Comprehensive Income:      
Unfunded pension liability adjustment, net of tax
  of $2,815, $(1,555), and $253		 8,120
 (5,990) 394
Total Comprehensive Income $230,454
 $200,357
 $189,636


The accompanying notes are an integral part of these statements.
 
 


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Idaho Power Company
Consolidated Balance Sheets
 
December 31,
20212020
(in thousands)
Assets
Current Assets:
Cash and cash equivalents$60,075 $165,604 
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 
Income taxes receivable15,328 4,667 
Accrued unbilled revenues74,843 72,461 
Materials and supplies (at average cost)77,552 64,941 
Fuel stock (at average cost)18,045 31,646 
Prepayments24,558 20,057 
Current regulatory assets71,223 63,407 
Other5,708 1,995 
Total current assets440,285 510,061 
Investments77,108 87,848 
Property, Plant and Equipment:
Plant in service$6,509,316 $6,283,790 
Accumulated provision for depreciation(2,298,951)(2,193,831)
Plant in service - net4,210,365 4,089,959 
Construction work in progress670,585 597,152 
Plant held for future use4,511 4,109 
Other property3,647 5,123 
Property, plant and equipment, net4,889,108 4,696,343 
Other Assets:
Company-owned life insurance67,343 62,382 
Regulatory assets1,462,431 1,495,488 
Other54,564 53,988 
Total other assets1,584,338 1,611,858 
Total$6,990,839 $6,906,110 
  December 31,
  2018 2017
  (in thousands)
Assets    
     
Electric Plant:    
In service (at original cost) $6,103,856
 $5,906,162
Accumulated provision for depreciation (2,210,781) (2,098,274)
In service - net 3,893,075
 3,807,888
Construction work in progress 480,259
 452,424
Held for future use 4,751
 8,075
Electric plant - net 4,378,085
 4,268,387
     
Investments and Other Property 90,019
 99,904
     
Current Assets:    
Cash and cash equivalents 165,460
 44,646
Receivables:    
Customer (net of allowance of $1,725 and $2,013, respectively) 77,178
 75,249
Other (net of allowance of $264 and $180, respectively) 7,206
 30,274
Income taxes receivable 11,829
 26,492
Accrued unbilled revenues 69,318
 75,120
Materials and supplies (at average cost) 54,987
 55,745
Fuel stock (at average cost) 47,979
 56,638
Prepayments 16,374
 16,866
Current regulatory assets 48,707
 48,613
Other 3,655
 18
Total current assets 502,693
 429,661
     
Deferred Debits:    
Company-owned life insurance 59,852
 59,323
Regulatory assets 1,165,467
 1,083,483
Other 58,284
 54,677
Total deferred debits 1,283,603
 1,197,483
     
Total $6,254,400
 $5,995,435




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


 
December 31,
20212020
(in thousands)
Liabilities and Equity
Current Liabilities:
Accounts payable$145,871 $120,476 
Accounts payable to affiliates2,159 1,720 
Taxes accrued14,316 19,554 
Interest accrued23,959 24,030 
Accrued compensation55,491 52,036 
Current regulatory liabilities11,239 11,104 
Advances from customers43,472 29,341 
Other19,117 16,717 
Total current liabilities315,624 274,978 
Other Liabilities:
Deferred income taxes844,871 829,146 
Regulatory liabilities781,695 757,730 
Pension and other postretirement benefits521,462 634,070 
Other62,245 45,937 
Total other liabilities2,210,273 2,266,883 
Long-Term Debt2,000,640 2,000,414 
Commitments and Contingencies00
Equity:
Common stock, $2.50 par value (50,000 shares authorized; 39,151 shares outstanding)97,877 97,877 
Premium on capital stock712,258 712,258 
Capital stock expense(2,097)(2,097)
Retained earnings1,696,304 1,599,155 
Accumulated other comprehensive loss(40,040)(43,358)
Total equity2,464,302 2,363,835 
Total$6,990,839 $6,906,110 
The accompanying notes are an integral part of these statements.

91
  December 31,
  2018 2017
  (in thousands)
Capitalization and Liabilities    
     
Capitalization:    
Common stock equity:    
Common stock, $2.50 par value (50,000 shares authorized; 39,151 shares outstanding) $97,877
 $97,877
Premium on capital stock 712,258
 712,258
Capital stock expense (2,097) (2,097)
Retained earnings 1,409,245
 1,308,702
Accumulated other comprehensive loss (22,844) (30,964)
Total common stock equity 2,194,439
 2,085,776
Long-term debt 1,834,788
 1,746,123
Total capitalization 4,029,227
 3,831,899
     
Current Liabilities:    
Accounts payable 110,597
 89,978
Accounts payable to affiliates 2,088
 57,562
Taxes accrued 11,750
 10,904
Interest accrued 23,622
 22,379
Accrued compensation 54,910
 46,832
Current regulatory liabilities 25,883
 1,404
Advances from customers 20,037
 18,414
Other 10,198
 9,556
Total current liabilities 259,085
 257,029
     
Deferred Credits:    
Deferred income taxes 753,239
 725,942
Regulatory liabilities 738,994
 698,044
Pension and other postretirement benefits 431,475
 438,869
Other 42,380
 43,652
Total deferred credits 1,966,088
 1,906,507
     
Commitments and Contingencies 
 
     
Total $6,254,400
 $5,995,435
     
The accompanying notes are an integral part of these statements.

Table of Contents

Idaho Power Company
Consolidated Statements of Cash Flows


Year Ended December 31,
 202120202019
 (thousands of dollars)
Operating Activities:  
Net income$243,225 $233,235 $224,437 
Adjustments to reconcile net income to net cash provided by operating activities: 
Depreciation and amortization178,847 175,334 173,205 
Deferred income taxes and investment tax credits(7,682)1,149 14,889 
Changes in regulatory assets and liabilities(33,705)(36,246)(4,310)
Pension and postretirement benefit plan expense33,804 28,955 27,788 
Contributions to pension and postretirement benefit plans(44,207)(45,146)(48,509)
Earnings of equity-method investments(10,211)(10,102)(10,285)
Distributions from equity-method investments10,211 12,627 19,450 
Allowance for equity funds used during construction(31,537)(29,551)(27,112)
Other adjustments to net income, net346 3,041 (748)
Change in:  
Accounts receivable(5,607)(2,220)(4,724)
Accounts payable17,690 (292)(9,463)
Taxes 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 
Net cash provided by operating activities322,706 352,988 343,512 
Investing Activities:  
Additions to utility plant(299,972)(310,937)(278,707)
Payments received from transmission project joint funding partners5,876 3,197 2,442 
Distributions from equity-method investments, return of investment14,439 1,073 — 
Purchase of equity securities(15,823)(33,382)(10,896)
Proceeds from the sale of equity securities11,328 25,795 5,080 
Other2,231 6,305 4,117 
Net cash used in investing activities(281,921)(307,949)(277,964)
Financing Activities:  
Issuance of long-term debt— 310,000 166,100 
Premium on issuance of long-term debt— 31,384 — 
Retirement of long-term debt— (175,000)(166,100)
Dividends on common stock(146,076)(137,885)(129,877)
Make-whole premium on retirement of long-term debt— (3,305)— 
Other(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)
Cash and cash equivalents at beginning of the year165,604 98,950 165,460 
Cash and cash equivalents at end of the year$60,075 $165,604 $98,950 
Supplemental Disclosure of Cash Flow Information:  
Cash paid to IDACORP related to income taxes$64,003 $32,118 $19,856 
Cash paid for interest (net of amount capitalized)$83,464 $81,037 $85,198 
Non-cash investing activities:
Additions to property, plant and equipment in accounts payable$53,690 $45,004 $38,815 
  Year Ended December 31,
  2018 2017 2016
  (thousands of dollars)
Operating Activities:      
Net income $222,334
 $206,347
 $189,242
Adjustments to reconcile net income to net cash provided by operating activities:    
  
Depreciation and amortization 168,519
 165,337
 146,694
Deferred income taxes and investment tax credits (2,272) (10,875) 25,780
Changes in regulatory assets and liabilities 48,392
 57,131
 (5,651)
Pension and postretirement benefit plan expense 32,240
 28,894
 29,597
Contributions to pension and postretirement benefit plans (45,883) (46,573) (45,317)
Earnings of unconsolidated equity-method investments (10,712) (9,267) (10,855)
Distributions from unconsolidated equity-method investments 29,400
 23,000
 23,716
Allowance for equity funds used during construction (24,353) (20,784) (22,031)
Gain on sale of investments and assets (155) (131) (103)
Other non-cash adjustments to net income, net (210) 1,069
 (454)
Change in:  
  
  
Accounts receivable 633
 (5,282) (54)
Accounts payable (25,532) 38,111
 13,308
Taxes accrued/receivable 15,509
 (3,601) (17,299)
Other current assets 12,707
 2,812
 (10,902)
Other current liabilities 6,822
 996
 (3,322)
Other assets (7,488) (8,734) (3,764)
Other liabilities (1,476) (967) (829)
Net cash provided by operating activities 418,475
 417,483
 307,756
Investing Activities:  
  
  
Additions to utility plant (277,823) (285,471) (296,948)
Payments received from transmission project joint funding partners 21,587
 6,074
 7,586
Purchase of available-for-sale securities (11,390) (11,356) (14,917)
Proceeds from the sale of available-for-sale securities 5,007
 4,989
 15,693
Purchase of life insurance investment —
 —
 (10,000)
Other 4,320
 5,176
 4,511
Net cash used in investing activities (258,299) (280,588) (294,075)
Financing Activities:  
  
  
Issuance of long-term debt 220,000
 —
 120,000
Retirement of long-term debt (130,000) (1,064) (101,064)
Dividends on common stock (121,791) (113,284) (105,121)
Net change in short term borrowings —
 (21,800) 21,800
Make-whole premium on retirement of long-term debt (4,607) —
 (13,895)
Other (2,964) (241) (2,017)
Net cash used in financing activities (39,362) (136,389) (80,297)
Net increase (decrease) in cash and cash equivalents 120,814
 506
 (66,616)
Cash and cash equivalents at beginning of the year 44,646
 44,140
 110,756
Cash and cash equivalents at end of the year $165,460
 $44,646
 $44,140
Supplemental Disclosure of Cash Flow Information:  
  
  
Cash paid to IDACORP related to income taxes $63,914
 $12,444
 $29,341
Cash paid for interest (net of amount capitalized) $80,894
 $79,918
 $78,111
Non-cash investing activities:      
Additions to property, plant and equipment in accounts payable $29,528
 $33,220
 $34,603

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

Idaho Power Company
Consolidated Statements of Retained Earnings

  Year Ended December 31,
  2018 2017 2016
  (thousands of dollars)
       
Retained Earnings, Beginning of Year $1,308,702
 $1,211,547
 $1,127,426
Net Income 222,334
 206,347
 189,242
Dividends on Common Stock (121,791) (113,284) (105,121)
Cumulative Effect of Change in Accounting Principle —
 4,092
 —
Retained Earnings, End of Year $1,409,245
 $1,308,702
 $1,211,547


The accompanying notes are an integral part of these statements.
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Idaho Power Company

Consolidated Statements of Retained Earnings

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

The accompanying notes are an integral part of these statements.
93
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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). 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). Idaho Power is the parent of Idaho Energy Resources Co. (IERCo), a joint venturer in Bridger Coal Company (BCC), which mines and supplies coal to the Jim Bridger generating plant (Jim Bridger plant) owned in part by Idaho Power.
 
IDACORP’s other notable wholly-owned subsidiaries include IDACORP Financial Services, Inc. (IFS), an investor in affordable housing and other real estate tax credit investments, and Ida-West Energy Company (Ida-West), an operator of small hydroelectrichydropower generation projects that satisfy the requirements of the Public Utility Regulatory Policies Act of 1978 (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 entities (VIEs)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 variable interest entity (VIE),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, 2018,2021, Marysville had approximately $18$16.0 million of assets, primarily a hydroelectrichydropower plant, and approximately $8$2.3 million of intercompany long-term debt, which is eliminated in consolidation. 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 venture 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, Idaho Power is not the primary beneficiary. The carrying value of Idaho Power's investment in BCC was $49.9$22.7 million at December 31, 2018,2021, and Idaho Power's maximum exposure to loss is the carrying value, any additional future contributions to BCC, and a $58.4$51.6 million guarantee for mine reclamation costs, which is discussed further in Note 10 - "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 42 to 99100 percent and were acquired between 1996 and 2010.2021. 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 $3.4$35.0 million at December 31, 2018.2021.


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 15 - "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. 
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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 13 - "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) 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 maintenance 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 generally accepted accounting principles.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 one1 percent per month may be assessed on account balances after 30 days. An allowance is recorded for potential uncollectible accounts. The allowancemeasurement of expected credit losses on Idaho Power accounts receivable is reviewed periodicallybased on historical experience, current economic conditions, and adjustedforecasted 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, and an analysis of specific customer accounts.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
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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,
 20212020
Balance at beginning of period$4,766 $1,401 
Additions to the allowance2,017 5,222 
Write-offs, net of recoveries(2,284)(1,857)
Balance at end of period$4,499 $4,766 
Allowance for uncollectible accounts as a percentage of customer receivables5.4 %6.1 %

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, 20182021 and 2017.2020. Once a receivable is determined to be impaired, any further interest income recognized is fully reserved.

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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


On January 1, 2018, IDACORP and Idaho Power adopted Accounting Standards Update (ASU) 2014-09, Revenue from Contracts with Customers (Topic 606). The adoption did not change the timing or amounts of revenue recognized by IDACORP or Idaho Power. 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), 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 2.8 percent in 2018, 2.9 percent in 2017,2021, 2020, and 2.6 percent in 2016.2019.


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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, suchthese costs are expensed in the period such determination is made. Idaho Power may seek recovery of suchthese costs in customer rates, although there can be no guarantee such recovery would be granted.
 
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 2018, 2017,2021, 2020, or 2016.2019.
 
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) 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. Idaho Power’s weighted-average monthly AFUDC rate was 7.5 percent for 2021 and 2020, and 7.6 percent for 2018, 2017 and 2016.2019.


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
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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), 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 taxestax 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. Regulated enterprises are required to recognizeIdaho 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.
 
The state of Idaho allows a three percent investment tax credit on qualifying plant additions. Investment tax credits earned on regulated assets are deferred and amortized to income over the estimated service lives of the related properties. Credits earned on non-regulated assets or investments are recognized in the year earned.
 
Income taxes are discussed in more detail in Note 2 - "Income Taxes."


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Other Accounting Policies


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

Reclassifications

In these consolidated financial statements, certain amounts in prior periods’ consolidated financial statements have been reclassified to conform with current period presentation. On IDACORP's and Idaho Power's December 31, 2017, consolidated balance sheets, the "Long-term receivables" balances of $4.3 million and $0.5 million, respectively, which had previously been reported separately, were reclassified to "Other" within "Other Assets" and "Deferred Debits," respectively.


New and Recently Adopted Accounting Pronouncements


Recently Adopted Accounting Pronouncements

In May 2014, the Financial Accounting Standards Board (FASB)There have been no recently issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606). ASU 2014-09 is intendedaccounting pronouncements that have had or are expected to enable users of financial statements to better understand and consistently analyze an entity's revenue across industries, transactions, and geographies. Under the ASU, recognition of revenue occurs when a customer obtains control of promised goods or services. In addition, the ASU requires disclosure of the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The FASB amended certain aspects of ASU 2014-09 to clarify the implementation guidance, including clarifications related to principal versus agent considerations, licensing and identifying performance obligations, narrow scope improvements, and practical expedients. IDACORP and Idaho Power adopted ASU 2014-09 on January 1, 2018, using the modified-retrospective approach as provided for in the standard. The adoption did not change the timing or amounts of revenue currently recognized by the companies, so no cumulative-effect adjustment was required. The adoption did change presentation of revenues on the consolidated statements of income and also added disclosures. To conform with current period presentation, "Electric utility revenues" and "Operating Revenues" on
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IDACORP's and Idaho Power's consolidated statements of income, respectively, for the year ended December 31, 2018 and 2017, which had previously been reported separately as "General business," "Off-system sales," and "Other revenues," are no longer reported separately. See Note 4 - "Revenues" for additional information on the disaggregation of revenue and additional disclosures.

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

In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230) Classification of Certain Cash Receipts and Cash Payments, to reduce diversity in practice in how certain cash receipts and cash payments are classified in the statement of cash flows. The companies' classification of proceeds from the settlement of corporate-owned life insurance policies and related costs will be classified as investing activities under the new guidance. The new guidance did not affect the companies' presentation of debt prepayment and extinguishment costs, proceeds from the settlement of insurance claims (other than corporate-owned life insurance), and distributions received from equity-method investments. IDACORP andIDACORP's or Idaho Power adopted ASU 2016-15 on January 1, 2018, using the retrospective approach as provided for in the standard. To conform with current period presentation, the companies reclassified $3.0 million and $3.6 million of company-owned life insurance proceeds received, for the year ended December 31, 2017 and 2016, respectively, from "Change in accounts receivable" and $0.1 million and $0.1 million of prepaid insurance premiums paid, for the year ended December 31, 2017 and 2016, respectively, from "Change in other assets" (net reclassification of $2.9 million and $3.5 million, respectively) within "Operating Activities" to "Other" within "Investing Activities" on the consolidated statement of cash flows.

In March 2017, the FASB issued ASU 2017-07, Compensation -- Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, which requires employers to disaggregate the service cost component from other components of net periodic benefit costs and to disclose the amounts of net periodic benefit costs that are included in each income statement line item. The standard requires employers to present the service cost component in the same line item as other compensation costs and to present the other components of net periodic benefit cost (which include interest costs, expected return on plan assets, amortization of prior service cost or credits and actuarial gains and losses) separately and outside a subtotal of operating income. In addition, only the service cost component is eligible for capitalization. Idaho Power capitalizes amounts of pension or postretirement costs that are insignificant to thePower's consolidated financial statements. The amendments in ASU 2017-07 are effective for interim and annual reporting periods beginning after December 15, 2017. Entities must use (1) a retrospective transition method to adopt the requirement for separate presentation in the income statement of service costs and other components and (2) a prospective transition method to adopt the requirement to limit the capitalization of benefit costs to the service cost component. IDACORP and Idaho Power adopted ASU 2017-07 on January 1, 2018, and accordingly, have retrospectively adjusted prior periods to reflect the disaggregation of service cost from other components of net periodic benefit costs. The adoption did not have a material impact on the companies' financial statements nor did it affect net income for the year ended December 31, 2018. For IDACORP, for the year ended December 31, 2017 and 2016, $3.0 million and $2.6 million, respectively, were reclassified out of "Other operations and maintenance" and $8.2 million and $9.2 million, respectively, were reclassified out of "Other" operating expenses for a total of $11.2 million and $11.8 million, respectively, reclassified to "Other Expense, Net" to conform to current period presentation. For Idaho Power, for the year ended December 31, 2017 and 2016, $3.0 million and $2.6 million, respectively, was reclassified from "Other operations and maintenance" to "Other expense, net" to conform to current period presentation.


Recent Accounting Pronouncements Not Yet Adopted

In August 2018, the FASB issued ASU 2018-15, Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract, to provide guidance on implementation costs incurred in a cloud computing arrangement that is a service contract. ASU 2018-15 aligns the accounting for such costs with the guidance on capitalizing costs associated with developing or obtaining internal-use software. The new standard is effective for interim and annual reporting periods beginning after December 15, 2019, with early adoption permitted. IDACORP and Idaho Power are evaluating the impact of ASU 2018-15 on their respective financial statements.

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In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), intended to improve financial reporting about leasing transactions. The ASU requires lessees to recognize a right-of-use asset and lease liability on the balance sheet for most leases. In addition, the ASU revises the definition of a lease in regards to when an arrangement conveys the right to control the use of the identified asset under the arrangement, which may result in changes to the classification of an arrangement as a lease. ASU 2016-02 was effective on January 1, 2019, and IDACORP and Idaho Power will record any effects of the adoption in the first quarter of 2019. While IDACORP and Idaho Power are finalizing the assessment of the financial impacts of the adoption, the adoption of ASU 2016-02 will not have a material impact on their respective financial statements.

2. INCOME TAXES
 
A reconciliation between the statutory federal income tax rate and the effective tax rate is as follows:
 IDACORPIdaho Power
 202120202019202120202019
(thousands of dollars)
Federal income tax expense at statutory rate$59,317 $55,885 $54,046 $59,111 $55,394 $53,099 
Change in taxes resulting from:     
AFUDC(9,141)(8,637)(7,941)(9,141)(8,637)(7,941)
Capitalized interest1,077 1,044 976 1,077 1,044 976 
Investment tax credits(2,866)(2,906)(6,252)(2,866)(2,906)(6,252)
Removal costs(3,302)(3,148)(3,139)(3,302)(3,148)(3,139)
Capitalized overhead costs(8,190)(7,560)(7,140)(8,190)(7,560)(7,140)
Capitalized 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 benefit11,359 8,804 8,627 11,633 9,052 8,401 
Depreciation14,233 13,589 14,641 14,233 13,589 14,641 
Excess deferred income tax reversal(8,958)(4,885)(6,181)(8,958)(4,885)(6,181)
Income tax return adjustments3,169 (2,552)745 1,759 (2,508)993 
Real Estate-related tax credits(6,245)(5,315)(2,874)— — — 
Real Estate-related investment distributions(1,010)(13)(3,232)— — — 
Real Estate-related investment amortization4,095 3,754 1,825 — — — 
Other, net804 (154)(1,114)331 319 (560)
Total income tax expense$36,912 $28,700 $24,507 $38,257 $30,548 $28,417 
Effective tax rate13.1%10.8%9.5%13.6%11.6%11.2%
  IDACORP Idaho Power
  2018 2017 2016 2018 2017 2016
  (thousands of dollars)
Federal income tax expense at statutory rate $51,279
 $91,378
 $82,151
 $50,536
 $90,163
 $79,250
Change in taxes resulting from:  
  
  
    
  
AFUDC (7,246) (10,318) (11,278) (7,246) (10,318) (11,278)
Capitalized interest 928
 1,513
 2,000
 928
 1,513
 2,000
Investment tax credits (2,929) (3,081) (2,922) (2,929) (3,081) (2,922)
Removal costs (3,471) (6,280) (5,559) (3,471) (6,280) (5,559)
Capitalized overhead costs (6,720) (11,200) (10,500) (6,720) (11,200) (10,500)
Capitalized repair costs (17,850) (28,700) (28,000) (17,850) (28,700) (28,000)
Bond redemption costs (1,029) —
 (4,997) (1,029) —
 (4,997)
Remeasurement of deferred taxes (5,411) 1,690
 —
 (5,664) 1,970
 —
State income taxes, net of federal benefit 8,512
 8,153
 5,071
 8,532
 8,108
 4,880
Depreciation 13,110
 18,953
 18,673
 13,110
 18,953
 18,673
Excess deferred income tax reversal (7,289) —
 —
 (7,289) —
 —
Share-based compensation (894) (1,508) (1,614) (883) (1,483) (1,583)
Income tax return adjustments (5,076) (3,710) (3,539) (4,968) (3,601) (3,669)
Affordable housing tax credits (2,560) (2,559) (2,579) —
 —
 —
Affordable housing investment distributions (267) (1,124) (1,717) —
 —
 —
Affordable housing investment amortization 1,519
 1,271
 1,380
 —
 —
 —
Other, net 2,780
 (5,818) (141) 3,255
 (4,782) 890
Total income tax expense $17,386
 $48,660
 $36,429
 $18,312
 $51,262
 $37,185
Effective tax rate 7.1% 18.6% 15.5% 7.6% 19.9% 16.4%


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The items comprising income tax expense are as follows:
 IDACORPIdaho Power
 202120202019202120202019
(thousands of dollars)
Income taxes current:      
Federal$15,210 $7,800 $8,830 $40,525 $30,464 $25,338 
State6,630 3,215 4,865 12,932 6,409 (4,392)
Total21,840 11,015 13,695 53,457 36,873 20,946 
Income taxes deferred:      
Federal(1,787)11,543 9,486 (21,737)(4,905)(4,599)
State1,154 (1,414)1,159 (5,295)(4,241)10,054 
Total(633)10,129 10,645 (27,032)(9,146)5,455 
Investment tax credits:      
Deferred14,698 5,727 8,268 14,698 5,727 8,268 
Restored(2,866)(2,906)(6,252)(2,866)(2,906)(6,252)
Total11,832 2,821 2,016 11,832 2,821 2,016 
Real estate-related investments at IFS3,873 4,735 (1,849)— — — 
Total income tax expense$36,912 $28,700 $24,507 $38,257 $30,548 $28,417 
  IDACORP Idaho Power
  2018 2017 2016 2018 2017 2016
  (thousands of dollars)
Income taxes current:            
Federal $5,390
 $11,726
 $1,181
 $24,919
 $51,575
 $7,639
State 3,328
 5,418
 2,158
 (2,049) 10,562
 3,766
Total 8,718
 17,144
 3,339
 22,870
 62,137
 11,405
Income taxes deferred:  
  
  
  
  
  
Federal 1,649
 24,018
 33,205
 (15,388) (13,002) 27,506
State 30
 (154) 100
 5,425
 (5,298) (2,031)
Total 1,679
 23,864
 33,305
 (9,963) (18,300) 25,475
Investment tax credits:  
  
  
  
  
  
Deferred 8,334
 10,506
 3,227
 8,334
 10,506
 3,227
Restored (2,929) (3,081) (2,922) (2,929) (3,081) (2,922)
Total 5,405
 7,425
 305
 5,405
 7,425
 305
Affordable housing investments 1,584
 227
 (520) —
 —
 —
Total income tax expense $17,386
 $48,660
 $36,429
 $18,312
 $51,262
 $37,185


The components of the net deferred tax liability are as follows:
 IDACORPIdaho Power
 2021202020212020
 (thousands of dollars)
Deferred tax assets:    
Regulatory liabilities$96,880 $95,883 $96,880 $95,883 
Deferred compensation23,333 22,576 23,333 22,576 
Deferred revenue48,318 43,525 48,318 43,525 
Tax credits41,896 61,707 35,781 30,215 
Partnership investments12,265 10,189 11,949 7,211 
Retirement benefits110,997 142,864 110,997 142,864 
Other17,066 15,005 16,893 14,792 
Total350,755 391,749 344,151 357,066 
Deferred tax liabilities:  
Property, plant and equipment272,530 282,983 272,530 282,983 
Regulatory assets721,276 687,628 721,276 687,628 
Partnership investments2,824 3,257 — — 
Retirement benefits138,154 164,399 138,154 164,399 
Other58,346 53,733 57,062 51,202 
Total1,193,130 1,192,000 1,189,022 1,186,212 
Net deferred tax liabilities$842,375 $800,251 $844,871 $829,146 
  IDACORP Idaho Power
  2018 2017 2018 2017
  (thousands of dollars)
Deferred tax assets:  
  
  
  
Regulatory liabilities $98,042
 $98,744
 $98,042
 $98,744
Deferred compensation 21,871
 21,066
 21,826
 21,025
Deferred revenue 35,137
 31,086
 35,137
 31,086
Tax credits 100,041
 109,673
 44,532
 44,106
Partnership investments 4,200
 3,540
 1,086
 —
Retirement benefits 91,867
 94,493
 91,867
 94,493
Other 9,299
 8,636
 9,121
 8,435
Total 360,457
 367,238
 301,611
 297,889
Deferred tax liabilities:    
    
Property, plant and equipment 294,471
 306,002
 294,471
 306,002
Regulatory assets 614,144
 584,329
 614,144
 584,329
Fixed cost adjustment 10,940
 8,016
 10,940
 8,016
Partnership investments 3,875
 5,182
 —
 980
Retirement benefits 108,440
 103,407
 108,440
 103,407
Other 28,465
 21,242
 26,855
 21,097
Total 1,060,335
 1,028,178
 1,054,850
 1,023,831
Net deferred tax liabilities $699,878
 $660,940
 $753,239
 $725,942


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, 2018,2021, IDACORP had $60.5 million of general business credit carryforwards for federal income tax purposes and $39.5$41.9 million of Idaho investment tax credit carryforward. The general business credit carryforward period expirescarryforwards, which expire from 20272026 to 2038, and the Idaho investment tax credit expires from 2023 to 2032.2035.  


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Uncertain Tax Positions


IDACORP and Idaho Power believe that they have no material income tax uncertainties for 20182021 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 - U.S.United States federal and the State of Idaho. The open tax years for examination are 20182020-2021 for federal and 2014-20182016-2021 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 for IRS examination and issue resolution throughout the current year with the objective of return filings containing no contested items. In 2018, theThe IRS completed its examination of IDACORP's 2017 tax year with no unresolved income tax issues.

Income Tax Reform

In December 2017, the Tax Cuts and Jobs Act was signed into law, which significantly reforms the Internal Revenue Code of 1986, as amended. Effective January 1, 2018, the Tax Cuts and Jobs Act permanently lowers the corporate tax rate to 21 percentmoved IDACORP from the existing maximum ratemaintenance phase of 35 percent, provides for expanded bonus depreciation, limits the deductibility of interest expense, eliminates the alternative minimum tax, repeals the manufacturing deduction, and imposes additional limitations on the deductibility of executive compensation. Public utility companies, such as Idaho Power, retain the deductibility of interest expense and are excluded from the bonus depreciation provisions; however, traditional accelerated tax depreciation methods are still available.

DueCAP to the enactment ofbridge phase for both the Tax Cuts2020 and Jobs Act and following generally accepted accounting principles, at December 31, 2017, IDACORP and Idaho Power remeasured all deferred income2021 tax assets and liabilities. The effects of these adjustments resulted in a net tax expense for 2017, as shown in the rate reconciliation table above. Also, as shown above, in 2018, a net tax benefit was recognized for the remeasurement of deferred taxes for the adjustment of temporary differences as a result of IDACORP's 2017 consolidated income tax return filings.years.


Additionally, in 2017, the net deferred tax liabilities at both companies decreased by approximately $672 million. Idaho Power's regulatory asset deferred income tax liability item decreased as the related regulatory asset was reduced in two primary ways: (1) the decrease in the federal income tax rate decreased the future cost to customers for funding the net deferred income tax liabilities resulting from the cumulative impacts of using the flow-through income tax accounting method for regulatory purposes and (2) the decrease in the federal income tax rate also reduced the net-to-gross multiplier that increases the regulatory asset to a revenue requirement carrying value. The change in income tax law also reduced the deferred income tax liability for depreciation-related timing differences under the normalized tax accounting method. As this reduction will flow back to customers in the future under the statutorily prescribed average rate assumption method, it was recorded as a regulatory liability on the consolidated balance sheets of the companies.

On March 12, 2018, Idaho House Bill 463 was enacted which lowered the Idaho state corporate income tax rate from 7.4 percent to 6.925 percent effective January 1, 2018. The Idaho tax rate reduction did not have a material impact on IDACORP's and Idaho Power's 2018 income tax expense or deferred tax asset and liability balances.

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.


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The following table presents a summary of Idaho Power’s regulatory assets and liabilities (in thousands of dollars):
   As of December 31, 2018    As of December 31, 2021
 Remaining
Amortization Period		 
Earning a Return(1)
 Not Earning a Return Total as of December 31,Remaining
Amortization Period
Earning a Return(1)
Not Earning a ReturnTotal as of December 31,
Description 2018 2017Description20212020
Regulatory Assets:    
      Regulatory Assets:    
Income taxes(2)
   $—
 $614,144
 $614,144
 $584,329
Income taxes(2)
 $— $721,276 $721,276 $687,628 
Unfunded postretirement benefits(3)
   —
 278,674
 278,674
 280,166
Unfunded postretirement benefits(3)
 — 315,011 315,011 444,470 
Pension expense deferrals 
 126,811
 21,025
 147,836
 127,721
Energy efficiency program costs(4)
 1,398
 —
 1,398
 6,273
Power supply costs(5)
 
 —
 —
 —
 3,137
Fixed cost adjustment(5)
 2019-2020 34,502
 8,001
 42,503
 30,856
Valmy Plant settlements(5)
 2019-2028 77,512
 —
 77,512
 44,633
Asset retirement obligations(6)
   —
 17,655
 17,655
 15,767
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 
Asset retirement obligations(7)
Asset retirement obligations(7)
 — 22,585 22,585 19,035 
Wildfire Mitigation Plan deferral(6)
Wildfire Mitigation Plan deferral(6)
 — 6,075 6,075 — 
Long-term service agreement 2019-2043 16,095
 10,653
 26,748
 27,907
Long-term service agreement2022-204314,046 9,227 23,273 24,431 
Other 2019-2055 720
 6,984
 7,704
 11,307
Other2022-20552,846 14,204 17,050 10,844 
Total   $257,038
 $957,136
 $1,214,174
 $1,132,096
Total $397,987 $1,135,667 $1,533,654 $1,558,895 
Regulatory Liabilities:    
  
  
  
Regulatory Liabilities:     
Income taxes(7)(8)
   $—
 $98,042
 $98,042
 $98,744
 $— $96,880 $96,880 $95,883 
Depreciation-related excess deferred income taxes(8)(9)
 190,062
 —
 190,062
 193,991
170,039 — 170,039 178,997 
Removal costs(6)(7)
   —
 183,798
 183,798
 184,993
 — 184,670 184,670 182,334 
Investment tax credits   —
 92,790
 92,790
 87,385
Investment tax credits — 109,460 109,460 97,627 
Deferred revenue-AFUDC(9)
   95,660
 39,486
 135,146
 119,666
Energy efficiency program costs(4)
 5,259
 —
 5,259
 408
Deferred revenue-AFUDC(10)
Deferred revenue-AFUDC(10)
 141,450 46,267 187,717 169,095 
Power supply costs(5)(6)
 2019-2020 35,815
 6,507
 42,322
 5,443
— — — 15,009 
Settlement agreement sharing mechanism(5)(6)
 2019-2020 5,025
 —
 5,025
 —
2022-2023569 — 569 — 
Mark-to-market assets(10)
   —
 3,700
 3,700
 22
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 
Other 
 2,419
 6,314
 8,733
 8,796
Other4,697 5,799 10,496 11,001 
Total   $334,240
 $430,637
 $764,877
 $699,448
Total $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.
(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 12 - "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 representsincludes both the Idaho and Oregon jurisdiction balancebalances at December 31, 2021 and the liability represents the Idaho jurisdiction balance.2020.
(5)(6) This item is discussed in more detail in this Note 3 - "Regulatory Matters."
(6)(7) Asset retirement obligations and removal costs are discussed in Note 14 - "Asset Retirement Obligations.Obligations (ARO)."
(7)(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."
(8) The Tax Cuts and Jobs Act, enacted on December 22,(9) In 2017, income tax reform reduced the deferred income tax assets and liabilities. For depreciation-related timingtemporary differences under the normalized tax accounting method, this reductionthe resulting excess deferred taxes will flow back to customers ratably over the remaining regulatory lives of Idaho Power's plant assets under the statutorily prescribedalternative method provided in the statute. The average rate assumption method.method was used to compute this reversal for fiscal years 2018-2020.
(9)(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.
(10) Mark-to-market assets and liabilities are discussed in Note 17 - "Fair Value Measurements."(11) Represents amount accrued under the May 2018 Idaho Tax 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.


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
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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
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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, and the levels of Idaho Power's own generation. The Idaho deferral period or Idaho-jurisdiction power cost adjustment (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.prices.


Idaho Jurisdiction Power Cost Adjustment Mechanism: In the Idaho jurisdiction, the annual PCApower cost adjustment (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-up component, based on the difference between the previous year’s actual net power supply costs and the previous year’s forecast. The latter component also includes a balancing mechanism so that, over time, the actual collection or refund of authorized true-up dollars 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 shareholdersIdaho 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 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, the IPUC ordered Idaho Power to initiate a case to review the PCA mechanism and propose any modifications it determines are appropriate so the case may be processed before the filing of the 2022 PCA application in April 2022. In January 2022, the IPUC approved Idaho Power's proposed modifications to the PCA, which simplify the mechanism without impairing the intent or effectiveness of the PCA and have no material impact on overall cost recovery.

The table below summarizes the three most recent Idaho-jurisdiction PCA rate adjustments, all of which also include non-PCA-related rate adjustments as ordered by the IPUC:
Effective Date $ Change (millions) Notes
June 1, 2018 $(30.4) The $30.4 million total decrease in PCA rates includes a $7.8 million one-time benefit for income tax benefits accrued from January 1 to May 31, 2018, and the income taxes related to Idaho Power's open access transmission tariff (OATT) rate. See "Income Tax Reform - Regulatory Treatment" below for more information.
June 1, 2017 $10.6
 The net increase in PCA rates included an offsetting $13.0 million reduction for the refund of previously collected Idaho energy efficiency rider funds.
June 1, 2016 $17.3
 The net increase in PCA rates included the application of (a) a customer rate credit of $3.2 million for sharing of revenues with customers for the year 2015 under the terms of the October 2014 settlement stipulation, and (b) $4.0 million of surplus Idaho energy efficiency rider funds.
Effective Date$ Change (millions)Notes
June 1, 2021$39.1 The net increase in PCA revenues reflects a forecasted reduction in low-cost hydroelectric generation as well as higher costs associated with forecasted PURPA power purchases. The net increase in PCA revenues also reflects a smaller credit to customers thru 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.
 
In March 2014, the IPUC issued an order approving Idaho Power's application requesting an increase of approximately $106 million in the normalized or "base level" net power supply expense on a total-system basis to be used to update base rates and in the determination of the PCA rate that became effective June 1, 2014. Approval of the order removed the Idaho-jurisdictional portion of those expenses (approximately $99 million) from collection via the PCA mechanism and instead results in collecting that portion through base rates.

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 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. Under the PCAM, Idaho Power is subject to a portion of the business risk or benefit associated with this deviation through application of an asymmetrical deadband (or range of deviations) within which Idaho Power absorbs cost increases or decreases. For deviations in actual power supply costs outside of the deadband, the PCAM provides for 90/10 sharing of costs and benefits between customers and Idaho Power. However, collection by Idaho Power will occur only to the extent that Idaho Power’s actual Oregon-jurisdictional return on equity (Oregon ROE) for the year is at least 100 basis points below Idaho Power’s last authorized Oregon ROE. A refund to customers will occur only to the extent that Idaho Power’s actual Oregon ROE for that year is at least 100 basis points above Idaho Power’s last authorized Oregon ROE. Oregon jurisdiction power supply cost changes under the APCU and PCAM during each of 2018, 2017,2021, 2020, and 20162019 did not have a material impact on the companies' financial statements.
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Notable Idaho Regulatory Matters

Idaho Base Rate Changes: Adjustments

Idaho base rates were most recently established through a general rate case in 2012, and adjusted in 2014, 2017, 2018, and 2018. 2019.

January 2012 and June 2014 Idaho Base Rate Adjustments: Effective January 1, 2012, Idaho Power implemented new Idaho base rates resulting from IPUC approval of a settlement stipulation that provided for a 7.86 percent authorized overall 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 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 rates, effective July 1, 2012. The order also provided for a $335.9 million increase in Idaho rate base. Neither the settlement stipulation nor 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.


As noted above in this Note 3, theThe IPUC issued a March 2014 order approving Idaho Power's request for an increase in the normalized or "base level" net power supply expense to be used to update base rates and in the determination of the PCA rate that became effective June 1, 2014. In June 2018, the IPUC issued an order adjusting base rates for the impacts of income tax reform, as discussed below in "Income Tax Reform - Regulatory Treatment."


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 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 Sharing Settlement Stipulation are described in the table included under "Incomebelow.

May 2018 Idaho Tax Reform - Regulatory Treatment" below.

In 2018, Idaho Power recorded a $5.0 million provision against current revenue for sharing with customers, as its full-year return on year-end equity in the Idaho jurisdiction (Idaho ROE) for 2018 was above 10.0 percent. In both 2016 and 2017, Idaho Power did not record any additional ADITC amortization or any provision for sharing with customers, as its Idaho ROE in both years was between 9.5 percent and 10.0 percent. Accordingly, at December 31, 2018, the full $45 million of additional ADITC remains available for future use under the terms of the October 2014 Idaho Earnings Support and Sharing Settlement Stipulation. The October 2014 Idaho Earning Support and Sharing Settlement Stipulation was modified and indefinitely extended, as described in "Income Tax Reform - Regulatory Treatment" below.

Income Tax Reform - Regulatory Treatment: 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 January 2018, the IPUC issued an order requiring utilities within its jurisdiction, including Idaho Power, to file a report with the IPUC, identifying and quantifying the financial impact of the income tax reform changes on the utility, along with proposed tariff schedule changes that would adjust the utility's rates and corresponding revenues to reflect the utility's modified federal tax obligations under the Tax Cuts and Jobs Act. The IPUC order required Idaho Power to estimate the income tax reform changes by comparing actual 2017 federal income tax components with what those federal income tax components would have been if the Tax Cuts and Jobs Act had been effective for the full-year 2017.

In March 2018, Idaho Power made a filing with the IPUC providing the results of its pro forma analysis indicating pro forma annual income tax reform expense reductions, composed of a current income tax expense reduction and a deferred income tax expense reduction. In May 2018, the IPUC issued an order approving a settlement stipulation (May 2018 Idaho Tax Reform Settlement Stipulation) related to income tax reform. Beginning June 1, 2018, the settlement stipulation providesprovided 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 liabilityregulatory asset recoverable from Idaho customers. Additionally, a one-time benefit of a $7.8 million rate reduction is being provided to Idaho customers through the Idaho-jurisdiction power cost adjustment (PCA) mechanism for the period from June 1, 2018 through May 31, 2019, for the income tax reform benefits accrued from January 1, 2018 to May 31, 2018, and the income tax reform benefits related to Idaho Power's OATT rate. The amount provided via the PCA mechanism will decrease to $2.7 million on June 1, 2019, for income tax reform benefits related to Idaho Power's OATT rate and will cease on June 1, 2020, to reflect the impact of a full year of reduced OATT third-party transmission revenues.

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The May 2018 Idaho Tax Reform Settlement Stipulation also providesprovided for the indefinite extension, with modifications noted in the table below, of the October 2014 Idaho Earnings Support and Sharing Settlement Stipulation beyond its termination date of December 31, 2019.


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


Neither the October 2014 Idaho Earnings Support and Sharing Settlement Stipulation nor theThe May 2018 Idaho Tax Reform Settlement Stipulation did not impose a moratorium on Idaho Power filing a general rate case or other form of rate proceeding in Idaho during theirits respective terms.term.


Also in May 2018, the Public Utility Commission of Oregon (OPUC) issued an order approving a settlement stipulation that provides for an annual $1.5 million reduction to Oregon customer base rates beginning June 1, 2018, through May 31, 2020, related to income tax reform. Unless earlier resolved in a regulatory proceeding, the settlement stipulation requires Idaho Power to file a deferral request with the OPUC by December 31, 2019, to begin tracking income tax reform benefits beginning January 1, 2020, at which time Idaho Power, the OPUC staff, and other interested parties will discuss the methodology to quantify potential future income tax reform benefits.

Fixed Cost Adjustment: The Idaho jurisdiction fixed cost adjustment (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 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
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included in the variable kilowatt-hour charge, which may result in over-collection or under-collection of fixed costs. To return over-collection to customers or to collect under-collection from customers, the FCA mechanism allows Idaho Power to accrue, or defer, the difference between the authorized fixed-cost recovery amount per customer and the actual fixed costs per customer recovered by Idaho Power during the year. Any annual increase in the FCA recovery is capped at 3 percent of base revenue, with any excess deferred for collection in a subsequent year.

The following table summarizes FCA amounts approved for collection in the prior three FCA years:
FCA Year Period Rates in Effect Annual Amount
(in millions)
2017 June 1, 2018-May 31, 2019 $15.6
2016 June 1, 2017-May 31, 2018 $35.0
2015 June 1, 2016-May 31, 2017 $28.1

Hells Canyon Complex Relicensing Costs Settlement Stipulation:In December 2016, Idaho Power filed an application with the IPUC requesting a determination that Idaho Power's expenditures of $220.8 million through year-end 2015 on relicensing of the HCC were prudently incurred, and thus eligible for inclusion in retail rates in a future regulatory proceeding. In December 2017, Idaho Power filed with the IPUC a settlement stipulation signed by Idaho Power, the IPUC staff, and a third-party intervenor, recognizing that a total of $216.5 million in HCC relicensing expenditures and other related costs were reasonably incurred, and therefore should be eligible for inclusion in customer rates at a later date. As a result of filing the settlement stipulation,2021, Idaho Power recorded a $5.0 $0.6 million pre-tax chargeprovision against current revenue for sharing with customers, as its full-year return on year-end equity in the fourth quarter of 2017, which included $4.3 millionIdaho jurisdiction (Idaho ROE) exceeded 10.0 percent. In 2020, Idaho Power recorded no provision against current revenue for costs incurred through 2015,sharing with customers, as well as $0.7 million related to associated costs incurredits Idaho ROE was between 9.4 percent and 10.0 percent in 2016 and 2017. Of2020. Accordingly, at December 31, 2021, the $5.0 million pre-tax charge in 2017, $2.5 million was recorded as other operations and maintenance (O&M) expense and $2.5 million was recorded as a reduction to AFUDC. In April 2018, the IPUC issued an order approving the settlement stipulation as filed with the IPUC and determined the $216.5full $45 million of associated costs to be reasonably and prudently incurred.

Western Energy Imbalance Market Costs:Idaho Power's participation inadditional ADITC remained available for future use under the energy imbalance market implemented in the western United States (Western EIM) commenced on April 4, 2018. The Western EIM aims to reduce the power supply costs to serve customers through more efficient dispatch within the hour of a larger and more diverse pool of resources, to integrate intermittent power from renewable generation sources more effectively, and to enhance reliability.
In January 2017, in response to Idaho Power's request to match costs with benefits of Western EIM participation, the IPUC issued an order authorizing deferral accounting treatment for costs associated with joining the Western EIM. In November 2017, Idaho Power filed an application with the IPUC requesting authorization to establish an interim method of recovery for costs associated with participation in the Western EIM. Through March 2018, Idaho Power had deferred $1.0 million of incremental other O&M costs. In the second quarter of 2018, Idaho Power amortized those costs in accordance with the provisionsterms of the May 2018 Idaho Tax Reform Settlement Stipulation discussed above. In July 2018, the IPUC issued an order approving a settlement stipulation that provides for recovery of ongoing Western EIM-related costs through Idaho Power's PCA mechanism, beginning April 2018. The recovery mechanism provides for monthly incremental revenue, which includes a return on and return of Western EIM-related capital costs and recovery of ongoing Western EIM operating costs. As of April 1, 2018, Idaho Power ceased deferring incremental Western EIM participation O&M start-up costs, and began recognizing the monthly incremental revenue associated with Western EIM participation. From April through December 2018, Idaho Power recorded $2.2 million as a regulatory asset within the PCA balance per the stipulation in order to match the costs with the benefits of the Western EIM.Stipulation.


Valmy Base Rate Adjustment Settlement Stipulations

Stipulations: In May 2017, the IPUC approved a settlement stipulation allowing accelerated depreciation and cost recovery for Idaho Power’s jointly-owned North Valmy coal-fired power plant (Valmy Plant).plant. The settlement stipulation provides for an increase in Idaho jurisdictional revenues of $13.3 million per year, and (1) levelized collections and associated cost recovery through December 2028, (2) accelerated depreciation on unit 1 through 2019 and unit 2 through 2025, and (3) Idaho Power to use prudent and commercially reasonable efforts to end its participation in the operation of unit 1 by the end of 2019 and unit 2 byno later than the end of 2025, and (4) a filing no later than December 31, 2019 that would include actual and planned incremental investments in unit 2, including updated financial analysis regarding the lowest costs options for unit 2.2025. 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
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savings. 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
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difference between actual costs incurred (including accelerated depreciation expense on unit 1 through 2019 and unit 2 through 2025) compared with costs permitted to be recovered during the cost recovery period specified in the settlement stipulation (including depreciation expense through 2028). If actual costs incurred differ from forecasted amounts included in the settlement stipulation, collection or refund of any differences would be subject to regulatory approval.

In June 2017,February 2019, Idaho Power reached an agreement with NV Energy that facilitates the OPUC also approved a settlement stipulation allowing for accelerated depreciationplanned 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, the IPUC issued an order approving the North Valmy plant 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, 2025, cost recovery of incremental Valmy Plant investments through May 31, 2017, and forecasted decommissioning costs. The settlement stipulation provides for an increase in the Oregon jurisdictional revenue requirement of $1.1 million, effective July 1, 2017, with yearly adjustments, if warranted. As part of the May 2018 settlement stipulation associated with income tax reform described above, the OPUC also deemed prudent2028. In December 2019, as planned, Idaho Power's decision to pursue the end ofPower ended its participation in coal-fired operations of North Valmy plant unit 11. 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.

Other Notable Idaho Regulatory Matters

Fixed Cost Adjustment: The Idaho jurisdiction fixed cost adjustment (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 endrecovery of 2019fixed costs from the variable kilowatt-hour (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 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, 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.

The following table summarizes FCA amounts approved for collection in the prior three FCA years:
FCA YearPeriod Rates in EffectAnnual Amount
 (in millions)
2020June 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, the IPUC authorized Idaho Power to defer for future amortization incremental operations and maintenance (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. As of December 31, 2021, Idaho Power's deferral related to the WMP was $6.1 million.

Jim Bridger Power Plant Rate Request: In June 2021, 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 depreciated 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 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 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
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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 incremental accelerated depreciation relatinglevelized revenue requirement in the aggregate amount of $27.1 million, which included Idaho Power's share of all electric plant in service related to unit 1, beginning June 1, 2018, and ending December 31, 2019, resultingcoal-fired operations at the Jim Bridger plant. The proposed adjustment in a $2.5 million annualized revenue requirement.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 OPUCPublic Utility Commission of Oregon (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 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 provides for an increase in the Oregon jurisdictional revenue requirement of $1.1 million, with yearly adjustments, if warranted. In May 2018, the OPUC also issued an order adjusting basedeemed 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.

Other Notable Regulatory Matters

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, in each of the impactsIdaho and Oregon jurisdictions, Idaho Power and other stakeholders filed a joint motion for approval of income tax reform, as discussed abovea settlement stipulation adopting new depreciation rates and agreeing to no increase in "Income Tax Reform - Regulatory Treatment."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.FERC and allows Idaho
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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, 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 
Applicable Period OATT Rate (per kW-year)
October 1, 2018 to September 30, 2019 $31.25
October 1, 2017 to September 30, 2018 $34.90
October 1, 2016 to September 30, 2017 $25.52
October 1, 2015 to September 30, 2016 $23.43


Idaho Power's current OATT rate is based on a net annual transmission revenue requirement of $123.1$127.3 million, which represents the OATT formulaic determination of Idaho Power's net cost of providing OATT-based transmission service.


4. REVENUES
 
On January 1, 2018, IDACORP and Idaho Power adopted ASU 2014-09, Revenue from Contracts with Customers, using the modified retrospective method. The adoption did not change the timing or amounts of revenue recognized by IDACORP or Idaho Power and, therefore, the companies recorded no cumulative-effect adjustment. The following table provides a summary of electric utility operating revenues for IDACORP and Idaho Power (in thousands):
Year Ended December 31,
 202120202019
Electric utility operating revenues:
Revenue from contracts with customers$1,382,653 $1,286,637 $1,285,286 
Alternative revenue programs and derivative revenues72,757 60,703 57,654 
Total electric utility operating revenues$1,455,410 $1,347,340 $1,342,940 
  Year Ended December 31,
  2018 2017 2016
Electric utility operating revenues:      
Revenue from contracts with customers $1,312,112
 $1,320,004
 $1,216,796
Alternative revenue programs and other revenues 54,470
 24,889
 42,557
Total electric utility operating revenues $1,366,582
 $1,344,893
 $1,259,353

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Revenues from Contracts with Customers


Revenues from contracts with customers are primarily related to Idaho Power’s regulated tariff-based sales of energy or related services. Generally, tariff-based sales do not involve a written contract, but are classified as revenues from contracts with customers under ASU 2014-09, Revenue from Contracts with Customers.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. 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 
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  Year Ended December 31,
  2018 2017 2016
Revenues from contracts with customers:      
Retail revenues:      
 Residential (includes $34,625, $17,320 and $29,170, respectively, related to the FCA(1))
 $530,527
 $552,333
 $514,954
 Commercial (includes $1,299, $876 and $1,087, respectively, related to the FCA(1))
 310,299
 319,195
 302,650
Industrial 190,130
 195,124
 182,590
Irrigation 158,001
 150,030
 156,505
Provision for sharing (5,025) —
 —
Deferred revenue related to HCC relicensing AFUDC(2)
 (8,780) (10,706) (10,706)
Total retail revenues 1,175,152
 1,205,976
 1,145,993
Less: FCA mechanism revenues(1)
 (35,924) (18,196) (30,257)
Wholesale energy sales 52,845
 24,790
 11,900
Transmission wheeling revenues 59,094
 43,970
 32,496
Energy efficiency program revenues 35,703
 39,241
 33,754
Other revenues from contracts with customers 25,242
 24,223
 22,910
Total revenues from contracts with customers $1,312,112
 $1,320,004
 $1,216,796
       
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(1) The FCA mechanism is an alternative revenue program in the Idaho jurisdiction and does not represent revenue from contracts with customers.
(2) As part of its January 30, 2009, general rate case order, theThe IPUC is allowingallows 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. Prior to the May 2018 Idaho Tax Reform Settlement Stipulation described in Note 3 - "Regulatory Matters," Idaho Power was collecting $10.7 million annually.


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.


Credit losses recorded on receivables arising from Idaho Power’s contracts with customers were $3.6 million, $4.7 million, and $4.2 million for 2018, 2017, and 2016, respectively.

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


Commercial Customers: Most businesses are included in Idaho Power's commercial customer class, as well asare 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 can affect the timing and amounts of sales to irrigation customers, with increased precipitation generally resulting in decreased sales.


Provision for Sharing: Idaho Power's sharing mechanism is associated with the October 2014Power has regulatory settlement stipulations in Idaho Earnings Support and Sharing Settlement Stipulation that providesprovide for the potential sharing withbetween Idaho Power and its Idaho customers of a portionIdaho-jurisdictional earnings in excess of Idaho-jurisdiction earnings exceeding a 10.0 percent of Idaho ROE. Based on full-year 20182021 Idaho ROE, Idaho Power recorded a $5.0$0.6 million provision against current revenues for sharing of earnings with customers for 2018.2021. During 20172020 and 2016, Idaho Power recorded2019, no provision against current revenues for sharing of earnings with customers.customers was recorded. The October 2014 Idaho Earnings Support and Sharing Settlement Stipulation isregulatory settlement stipulations are described further in Note 3 - "Regulatory Matters."


Wholesale Energy Sales:As a public utility under the Federal Power Act (FPA), Idaho Power has the authority to charge market-based rates for wholesale energy sales under its FERC tariff. Idaho Power’s wholesale electricity sales are primarily to utilities and power marketers and are predominantly short-term and consist of a single performance obligation satisfied as
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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 either factorany of those factors may lead to lower wholesale energy sales.


Transmission WheelingWheeling-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. The reservationsReservations are predominantly short-term contracts or on-demand when available, but may be part of a long-term capacity contract, short-term contract, or on-demand when available.contract. Transmission wheelingwheeling-related revenues consist of a single performance obligation satisfied as capacity on Idaho Power’s transmission system is provided to the third party. Transmission wheelingwheeling-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 recordedrecognized in revenues, resulting in no net impact on earnings. EnergyFewer energy efficiency projects were completed in 2021 due mostly to impacts of the COVID-19 public health crisis which decreased energy efficiency program revenues are recognized in the period when the related costs of the energy efficiency program are incurred by Idaho Power.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, 2018,2021, Idaho Power's energy efficiency rider balances were a $5.3$6.9 million regulatory liabilityasset in the Idaho jurisdiction and a $1.4$0.7 million regulatory asset 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.


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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 rates billed to customers.customer rates. The Idaho FCA mechanism is described in detail 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 have been met.recognition. Revenue from contracts with customers excludes the portion of the tariff price representing FCA revenues that had beenIdaho Power initially recorded in prior periods when revenues met regulator-specified conditions were met.conditions. When Idaho Power includes those amounts are included in the price of utility service and billed to customers, Idaho Power records such amounts are recorded as recovery of the associated regulatory asset or liability and not as revenues.


Derivative revenues include gains from settled electricity swaps and sales of electricity under forward sales contracts that are bundled with renewable energy credits. Related to these forward sales, Idaho Power simultaneously enters into forward purchases of electricity for the same quantity at the same location, which are recorded in purchased power on the consolidated statements of income. For more information on settled electricity swaps, see Note 16 - "Derivative Financial Instruments."

The table below presents the FCA mechanism revenues and otherderivative revenues (in thousands):
Year Ended December 31,
 202120202019
Alternative revenue programs and derivative revenues:
FCA mechanism revenues$36,242 $35,952 $36,923 
Derivative revenues36,515 24,751 20,731 
Total alternative revenue programs and derivative revenues$72,757 $60,703 $57,654 
  Year Ended December 31,
  2018 2017 2016
Alternative revenue programs and other revenues:      
FCA mechanism revenues $35,924
 18,196
 $30,257
Derivative revenues 18,546
 6,693
 12,300
Total alternative revenue programs and other revenues $54,470
 $24,889
 $42,557


IDACORP's Other Operating Revenues


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

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5. LONG-TERM DEBT
 
The following table summarizes IDACORP's and Idaho Power's long-term debt at December 31 (in thousands of dollars):
 2018 201720212020
First mortgage bonds:    First mortgage bonds:
4.50% Series due 2020 $—
 $130,000
3.40% Series due 2020 100,000
 100,000
2.95% Series due 2022 75,000
 75,000
2.50% Series due 2023 75,000
 75,000
2.50% Series due 2023$75,000 $75,000 
1.90% Series due 20301.90% Series due 203080,000 80,000 
6.00% Series due 2032 100,000
 100,000
6.00% Series due 2032100,000 100,000 
5.50% Series due 2033 70,000
 70,000
5.50% Series due 203370,000 70,000 
5.50% Series due 2034 50,000
 50,000
5.50% Series due 203450,000 50,000 
5.875% Series due 2034 55,000
 55,000
5.875% Series due 203455,000 55,000 
5.30% Series due 2035 60,000
 60,000
5.30% Series due 203560,000 60,000 
6.30% Series due 2037 140,000
 140,000
6.30% Series due 2037140,000 140,000 
6.25% Series due 2037 100,000
 100,000
6.25% Series due 2037100,000 100,000 
4.85% Series due 2040 100,000
 100,000
4.85% Series due 2040100,000 100,000 
4.30% Series due 2042 75,000
 75,000
4.30% Series due 204275,000 75,000 
4.00% Series due 2043 75,000
 75,000
4.00% Series due 204375,000 75,000 
3.65% Series due 2045 250,000
 250,000
3.65% Series due 2045250,000 250,000 
4.05% Series due 2046 120,000
 120,000
4.05% Series due 2046120,000 120,000 
4.20% Series due 2048 220,000
 —
4.20% Series due 2048450,000 450,000 
Total first mortgage bonds 1,665,000
 1,575,000
Total first mortgage bonds1,800,000 1,800,000 
Pollution control revenue bonds:    Pollution control revenue bonds:
5.15% Series due 2024(1)
 49,800
 49,800
5.25% Series due 2026(1)
 116,300
 116,300
1.45% Series due 2024(1)
1.45% Series due 2024(1)
49,800 49,800 
1.70% Series due 2026(1)
1.70% Series due 2026(1)
116,300 116,300 
Variable Rate Series 2000 due 2027 4,360
 4,360
Variable Rate Series 2000 due 20274,360 4,360 
Total pollution control revenue bonds 170,460
 170,460
Total pollution control revenue bonds170,460 170,460 
American Falls bond guarantee 19,885
 19,885
American Falls bond guarantee19,885 19,885 
Unamortized issuance costs and discounts (20,557) (19,222)
Unamortized premium/discount and issuance costsUnamortized premium/discount and issuance costs10,295 10,069 
Total IDACORP and Idaho Power outstanding debt(2)
 1,834,788
 1,746,123
Total IDACORP and Idaho Power outstanding debt(2)
2,000,640 2,000,414 
Current maturities of long-term debt —
 —
Current maturities of long-term debt— — 
Total long-term debt $1,834,788
 $1,746,123
Total 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, 2018,2021, to $1.831$1.966 billion.
(2) At both December 31, 20182021 and 2017,2020, the overall effective cost rate of Idaho Power's outstanding debt was 4.83 percent and 4.87 percent, respectively.4.40 percent.


At December 31, 2018,2021, the maturities for the aggregate amount of IDACORP and Idaho Power long-term debt outstanding were as follows (in thousands of dollars):
 2019 2020 2021 2022 2023 Thereafter
 $—
 $100,000
 $—
 $75,000
 $75,000
 $1,605,345
20222023202420252026Thereafter
$— $75,000 $49,800 $19,885 $116,300 $1,729,360 
 
Long-Term Debt Issuances, Maturities, and AvailabilityRedemptions


In March 2018,April 2020, Idaho Power issued $220$230.0 million in principal amount of 4.20% first mortgage bonds, secured medium-termmedium term notes, Series K, maturing on 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.

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In April 2018,June 2020, Idaho Power issued $80.0 million in principal amount of 1.90% first mortgage bonds, secured medium term notes, Series L, maturing July 15, 2030. In July 2020, Idaho Power redeemed, prior to maturity, $130$75 million in principal amount of 4.50%2.95 percent first mortgage bonds, medium-term notes, Series H due March 2020.in April 2022. In accordance with the redemption provisions of the notes, the redemption included Idaho Power's payment of a make-whole premium of $4.6 million. Idaho
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Power used a portionto the holders of the net proceedsredeemed notes in the aggregate amount of the March 2018 sale of first mortgage bonds, medium-term notes to effect the redemption.$3.3 million.

In March 2016,August 2020, Idaho Power issued $120.0redeemed $100 million in principal amount of 4.05%3.40 percent first mortgage bonds secured medium-term notes, Series J, maturing on March 1, 2046. In April 2016, Idaho Power redeemed, prior to maturity, $100.0 milliondue in principal amount of 6.15% first mortgage bonds, secured medium-term notes, Series H, due April 2019. In accordance with the redemption provisions of the notes, the redemption included Idaho Power's payment of a make-whole premium of $14.0 million. Idaho Power used a portion of the net proceeds from the March 2016 sale of first mortgage bonds, medium-term notes to effect the redemption.November 2020.


Idaho Power First Mortgage Bonds: Bonds

Idaho Power's issuance of long-term indebtedness is subject to the approval of the IPUC, OPUC, and Wyoming Public Service Commission (WPSC). In April and May 2016,2019, Idaho Power received orders from the IPUC, OPUC, and WPSC authorizing Idaho Powerthe company to issue and sell from time to time up to $500 million in aggregate principal amount of debt securities and first mortgage bonds, subject to conditions specified in the orders. Authority from the IPUC is effective through May 31, 2019,2022, 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 all-in interest rate limit of 7.0 percent.


On September 27, 2016,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 sevensix 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 KL (Series KL Notes), under Idaho Power’s Indenture of Mortgage and Deed
of Trust, dated as of October 1, 1937, as amended and supplemented (Indenture). At the same time,Also in June 2020, Idaho Power
entered into the Forty-eighthForty-ninth Supplemental Indenture, dated effective as of September 1, 2016,June 5, 2020, to the Indenture.Indenture (Forty-ninth
Supplemental Indenture). The Forty-eighthForty-ninth Supplemental Indenture provides for, among other items, the issuance of up to $500
$500 million in aggregate principal amount of Series KL Notes pursuant to the Indenture. As of December 31, 2018, $280 million in principal amount of Series K Notes remained available for issuance 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 and clouds 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 five5 years that immediately follow or precede a particular year.


The Forty-eighth Supplemental Indenture increased the maximum amount of first mortgage bonds issuable by Idaho Power under the Indenture from $2.0 billion to $2.5 billion. Idaho Power may amend the Indenture and increase this amount without consent of the holders of the 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 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 two2 years or that are of an equal or higher interest rate, or prior lien bonds.


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As of December 31, 2018,2021, Idaho Power could issue under its Indenture approximately $1.9$2.1 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-eighthForty-ninth Supplemental Indenture. As a result, the maximum amount of first mortgage bonds Idaho Power could issue as of December 31, 20182021, was limited to approximately $669$534 million under the Indenture.




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6. NOTES PAYABLE
 
Credit Facilities
 
On November 6, 2015,The IDACORP and Idaho Power entered into Credit Agreements replacing the existing Second Amended and Restated Credit Agreements, dated October 26, 2011, to provide credit facilities thatfacility, which may be used for general corporate purposes and commercial paper backup. IDACORP's credit facilitybackup, 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'sPower 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 $100$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.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 LIBORLondon 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 percent.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 Moody's Investors Service, Inc., Standard and Poor's Ratings Services, and Fitch Rating Services, Inc.,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 NovemberDecember 6, 2020,2025, the credit agreements grant IDACORP and Idaho Power the right to request up to two2 one-year extensions, subject to certain conditions. On November 7, 2017, IDACORP and Idaho Power executed the second extension agreement with the consent of all the lenders, extending the maturity date under both credit agreements to November 4, 2022. No other terms of the credit facilities, included the amount of permitted borrowing under the credit agreements, were affected by the extensions.
 
At December 31, 2018,2021, no loans were outstanding under either IDACORP's or Idaho Power's facilities. At December 31, 2018,2021, Idaho Power had regulatory authority to incur up to $450 million in principal amount of short-term indebtedness at any one time outstanding. Balances (in thousandsoutstanding through December of dollars) and interest rates of2026. IDACORP’s and Idaho Power's short-term borrowings were as followszero at both December 31, 2018,2021 and December 31, 2017:
  IDACORP Idaho Power Total
  2018 2017 2018 2017 2018 2017
Commercial paper balances:            
At the end of year $—
 $—
 $—
 $—
 $—
 $—
Average during the year $—
 $588
 $—
 $839
 $—
 $1,427
Weighted-average interest rate            
At the end of the year —% —% —% —% —% —%
2020.
  
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7. COMMON STOCK
 
IDACORP Common Stock


The following table summarizes IDACORP common stock transactions during the last three years and shares reserved at December 31, 2018:2021:
 Shares issued Shares reserved Shares issuedShares reserved
 2018 2017 2016 December 31, 2018 202120202019December 31, 2021
Balance at beginning of year 50,420,017
 50,420,017
 50,352,051
  
Balance at beginning of year50,461,88550,420,01750,420,017 
Continuous equity program (inactive) —
 —
 —
 3,000,000
Continuous equity program (inactive)———3,000,000
Dividend reinvestment and stock purchase plan —
 —
 —
 2,576,723
Dividend reinvestment and stock purchase plan———2,840,117
Employee savings plan —
 —
 —
 3,567,954
Employee savings plan———3,567,954
Long-term incentive and compensation plan(1)
 —
 —
 67,966
 1,302,869
Long-term incentive and compensation plan(1)
54,59441,868—1,260,267
Balance at end of year 50,420,017
 50,420,017
 50,420,017
  
Balance at end of year50,516,47950,461,88550,420,017 
        
(1) During 20182021, 2020, and 2017,2019, IDACORP granted 75,76176,147, 75,030, and 72,39770,419 restricted stock unit awards, respectively, to employees and 12,95014,025, 10,296, and 12,0509,594 shares of common stock, respectively, to directors but made nodirectors. During 2021 and 2020, IDACORP issued 54,594 and 41,868 shares of common stock, respectively, using original issuances of shares of common stock pursuant to the IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan.Plan, including 12,784 and 8,938 shares of common stock, respectively, issued to members of the board of directors. During 2019, IDACORP made no original issuances of shares of common stock.


Restrictions on Dividends
 
Idaho Power’s ability to pay dividends on its common stock held by IDACORP and IDACORP’s ability to pay dividends on its common stock are limited to the extent payment of such dividends would violate the covenants in their respective credit facilities or Idaho Power’s Revised Code of Conduct. A covenant under IDACORP’s credit facility and Idaho Power’s credit facility requires IDACORP and Idaho Power to maintain leverage ratios of consolidated indebtedness to consolidated total capitalization, as defined therein, of no more than 65 percent at the end of each fiscal quarter. At December 31, 2018,2021, the leverage ratios for IDACORP and Idaho Power were 4443 percent and 4645 percent, respectively. Based on these restrictions, IDACORP’s and Idaho Power’s dividends were limited to $1.4$1.6 billion and $1.2$1.4 billion, respectively, at December 31, 2018.2021. 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, 2018,2021, 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, 2018,2021, Idaho Power's common equity capital was 5455 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. SHARE-BASED COMPENSATION
 
IDACORP has one share-based compensation plan — the 2000 Long-Term Incentive and Compensation Plan (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, 2018,2021, the maximum number of shares available under the LTICP was 720,408.443,663.
 
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Restricted Stock and Performance-Based Shares Awards


Restricted Stock awards have three-yearthree-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 Shares 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 dividend 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.


A summary of Restricted Stock and Performance-Based Shares award activity is presented below. Idaho Power share amounts represent the portion of IDACORP amounts related to Idaho Power employees:
IDACORPIdaho Power
 IDACORP Idaho PowerNumber of
Shares/Units		Weighted-Average
Grant Date
Fair Value		Number of
Shares/Units		Weighted-Average
Grant Date
Fair Value
 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, 2018 201,078
 $72.37
 199,652
 $72.39
Nonvested shares/units at January 1, 2021Nonvested shares/units at January 1, 2021157,035 $100.89 156,013 $100.90 
Shares/units granted 106,992
 79.28
 106,402
 79.29
Shares/units granted96,345 87.76 95,821 87.76 
Shares/units forfeited (5,179) 85.07
 (5,179) 85.07
Shares/units forfeited(2,210)98.72 (2,210)98.72 
Shares/units vested (96,856) 60.30
 (96,016) 60.31
Shares/units vested(75,914)87.24 (75,415)87.24 
Nonvested shares/units at December 31, 2018 206,035
 $81.31
 204,859
 $81.31
Nonvested shares/units at December 31, 2021Nonvested shares/units at December 31, 2021175,256 $99.61 174,209 $99.61 
 
The total fair value of shares vested was $8.3$6.7 million in 2018, $7.52021, $10.5 million in 2017,2020, and $8.3$9.4 million in 2016.2019. At December 31, 2018,2021, IDACORP had $8.0$7.5 million of total unrecognized compensation cost related to nonvested share-based compensation.compensation, nearly all of which was Idaho Power's share of this amount was $7.9 million.share. These costs are expected to be recognized over a weighted-average period of 1.7 years. IDACORP uses original issue and/or treasury shares for these awards.
 
In 2018,2021, a total of 12,95014,025 shares were awarded to directors at aan average grant date fair value of $81.05$86.24 per share. Directors elected to defer receipt of 3,2372,550 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 
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  IDACORP Idaho Power
  2018 2017 2016 2018 2017 2016
Compensation cost $9,362
 $7,384
 $5,561
 $9,276
 $7,304
 $5,494
Income tax benefit(1)
 2,410
 2,887
 2,174
 2,388
 2,856
 2,148
             
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(1) Due to the Tax Cuts and Jobs Act, the effective income tax rate was reduced in 2018 for both IDACORP and Idaho Power, which is described in Note 2 - "Income Taxes."


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. EARNINGS PER SHARE
 
The following table presents the computation of IDACORP’s basic and diluted earnings per share for the years ended December 31, 2018, 2017,2021, 2020, and 20162019 (in thousands, except for per share amounts):
Year Ended December 31,
 202120202019
Numerator:   
Net income attributable to IDACORP, Inc.$245,550 $237,417 $232,854 
Denominator:  
Weighted-average common shares outstanding - basic50,599 50,538 50,502 
Effect of dilutive securities463435
Weighted-average common shares outstanding - diluted50,645 50,572 50,537 
Basic earnings per share$4.85 $4.70 $4.61 
Diluted earnings per share$4.85 $4.69 $4.61 

  Year Ended December 31,
  2018 2017 2016
Numerator:  
  
  
Net income attributable to IDACORP, Inc. $226,801
 $212,419
 $198,288
Denominator:  
  
  
Weighted-average common shares outstanding - basic 50,432
 50,361
 50,298
Effect of dilutive securities 78
 63
 75
Weighted-average common shares outstanding - diluted 50,510
 50,424
 50,373
Basic earnings per share $4.50
 $4.22
 $3.94
Diluted earnings per share $4.49
 $4.21
 $3.94
       


10. COMMITMENTS
 
Purchase Obligations


At December 31, 2018,2021, Idaho Power had the following long-term commitments relating to purchases of energy, capacity, transmission rights, and fuel (in thousands of dollars):
 20222023202420252026Thereafter
Cogeneration and power production$298,867 $308,741 $311,968 $296,579 $293,508 $2,456,582 
Fuel62,287 19,328 8,663 8,362 8,354 58,355 
  2019 2020 2021 2022 2023 Thereafter
Cogeneration and power production $238,748
 $242,206
 $248,258
 $251,216
 $256,403
 $2,805,159
Fuel 43,163
 29,121
 28,010
 8,389
 8,379
 84,182


As of December 31, 2018,2021, Idaho Power had 1,119 MW1,137 megawatt (MW) nameplate capacity of PURPA-related projects on-line, with an additional 2975 MW nameplate capacity of projects projected to be on-line in 2019.by 2024. The power purchase contracts for these projects have original contract terms ranging from one to 35 years. Idaho Power's expenses associated with PURPA-related projects were approximately $190$200 million in 2018, $1702021, $194 million in 2017,2020, and $154$187 million in 2016.2019. 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.


Idaho Power also has the following long-term commitments (in thousands of dollars):
 2019 2020 2021 2022 2023 Thereafter 20222023202420252026Thereafter
Joint-operating agreement payments(1)
 $2,902
 $2,902
 $2,902
 $2,902
 $2,902
 $14,512
Joint-operating agreement payments(1)
$2,822 $2,822 $2,822 $2,822 $2,822 $14,110 
Easements and other payments 240
 1,321
 1,321
 1,331
 1,328
 16,831
Easements and other payments1,925 1,965 2,006 2,049 2,092 11,136 
Maintenance and service agreements(1)
 34,089
 15,694
 10,739
 11,713
 4,140
 54,927
Maintenance and service agreements(1)
97,847 13,522 10,134 6,319 6,592 46,764 
FERC and other industry-related fees(1)
 14,277
 12,714
 12,714
 12,714
 12,714
 63,568
FERC and other industry-related fees(1)
16,772 14,549 14,174 14,174 14,174 70,870 
            
(1) Approximately $29$28 million, $20$18 million, and $71$143 million of the obligations included in joint-operating agreement payments, maintenance and service 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.


At IDACORP, long-term purchase commitments of $3 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. At December 31, 2021, IDACORP had a commitment to invest an additional $8.5 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 2018, 2017,2021, 2020, and 2016.
2019.
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Guarantees
 
Through a self-bonding mechanism, Idaho Power guarantees its portion of reclamation activities and obligations at BCC, of which IERCo owns a one-third interest. This guarantee, which is renewed annually with the Wyoming Department of Environmental Quality (WDEQ),WDEQ, was $58.4$51.6 million at December 31, 2018,2021, representing IERCo's one-third share of BCC's total reclamation obligation of $175.2$154.7 million. BCC has a reclamation trust fund set aside specifically for the purpose of paying these reclamation costs. At December 31, 2018,2021, the value of the reclamation trust fund was $101.9$211.2 million. During 2018,2021, the reclamation trust fund made distributions$21.1 million of $6.7 milliondistributions for reclamation activity costs associated with the BCC surface mine. BCC periodically assesses the adequacy of the reclamation trust fund and its estimate of future reclamation costs. To ensure that the reclamation trust fund maintains adequate reserves, BCC has the ability to, and does, add a per-ton surcharge to coal sales, all of which are made to the Jim Bridger plant. Because of the existence of the fund and the ability to apply a per-ton surcharge, the estimated fair value of this guarantee is minimal.
 
IDACORP and Idaho Power enter into financial agreements and power purchase and sale agreements that include indemnification provisions relating to various forms of claims or liabilities that may arise from the transactions contemplated by these agreements. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnification provisions cannot be reasonably estimated. IDACORP and Idaho Power periodically evaluate the likelihood of incurring costs under such indemnities based on their historical experience and the evaluation of the specific indemnities. As of December 31, 2018,2021, 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. 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, 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. In recent years, Idaho Power has also regularly received claims by both governmental agencies and private landowners for damages for fires allegedly originating from Idaho Power’s transmission and distribution system. As of the date of this report, the companies believe that resolution of existing claims will not have a material adverse effect on their respective 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.


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12. 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.


Pension Plans


Idaho Power has two 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). 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.
 
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 2018, 2017, and 2016, 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.
The following table summarizes the changes in benefit obligations and plan assets of these plans (in thousands of dollars): 
 Pension PlanSMSP
 2021202020212020
 
Change in projected benefit obligation:    
Benefit obligation at January 1$1,337,395 $1,134,752 $134,791 $122,443 
Service cost54,202 42,987 813 213 
Interest cost37,317 40,013 3,557 4,350 
Actuarial (gain) loss(35,833)163,610 33 13,420 
Plan amendment— — — 130 
Benefits paid(46,551)(43,967)(6,182)(5,765)
Projected benefit obligation at December 311,346,530 1,337,395 133,012 134,791 
Change in plan assets:  
Fair value at January 1871,603 763,119 — — 
Actual return on plan assets119,412 112,451 — — 
Employer contributions40,000 40,000 — — 
Benefits paid(46,551)(43,967)— — 
Fair value at December 31984,464 871,603 — — 
Funded status at end of year$(362,066)$(465,792)$(133,012)$(134,791)
Amounts recognized in the balance sheet consist of:    
Other current liabilities$— $— $(6,226)$(6,154)
Noncurrent liabilities(362,066)(465,792)(126,786)(128,637)
Net amount recognized$(362,066)$(465,792)$(133,012)$(134,791)
Amounts recognized in accumulated other comprehensive income consist of:    
Net loss$322,908 $437,859 $51,365 $55,537 
Prior service cost43 49 2,687 2,983 
Subtotal322,951 437,908 54,052 58,520 
Less amount recorded as regulatory asset(1)
(322,951)(437,908)— — 
Net amount recognized in accumulated other comprehensive income$— $— $54,052 $58,520 
Accumulated benefit obligation$1,120,036 $1,115,923 $121,591 $119,517 
  Pension Plan SMSP
  2018 2017 2018 2017
   
Change in projected benefit obligation:  
  
  
  
Benefit obligation at January 1 $999,344
 $895,060
 $110,303
 $99,570
Service cost 37,836
 33,742
 (316) 759
Interest cost 38,833
 38,957
 4,248
 4,315
Actuarial (gain) loss (84,758) 67,758
 (7,050) 10,635
Benefits paid (39,398) (36,173) (4,867) (4,976)
Projected benefit obligation at December 31 951,857
 999,344
 102,318
 110,303
Change in plan assets:  
  
  
  
Fair value at January 1 697,683
 607,568
 —
 —
Actual (loss) return on plan assets (47,681) 86,288
 —
 —
Employer contributions 40,000
 40,000
 —
 —
Benefits paid (39,398) (36,173) —
 —
Fair value at December 31 650,604
 697,683
 —
 —
Funded status at end of year $(301,253) $(301,661) $(102,318) $(110,303)
Amounts recognized in the statement of financial position consist of:  
  
  
  
Other current liabilities $—
 $—
 $(5,158) $(5,010)
Noncurrent liabilities (301,253) (301,661) (97,160) (105,293)
Net amount recognized $(301,253) $(301,661) $(102,318) $(110,303)
Amounts recognized in accumulated other comprehensive income consist of:  
  
  
  
Net loss $278,720
 $277,052
 $30,496
 $41,333
Prior service cost 62
 68
 399
 498
Subtotal 278,782
 277,120
 30,895
 41,831
Less amount recorded as regulatory asset (278,782) (277,120) —
 —
Net amount recognized in accumulated other comprehensive income $—
 $—
 $30,895
 $41,831
Accumulated benefit obligation $814,549
 $850,763
 $94,630
 $100,222
(1) Changes in the funded status of the pension plan that would be recorded in accumulated other comprehensive income 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 gains reflected in the benefit obligations for the pension and SMSP plans in 2021 are due primarily to increases in the assumed discount rates of both plans from December 31, 2020, to December 31, 2021. The actuarial losses affecting the
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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. For more information on discount rates, see “Plan Assumptions” below in this Note 12.

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 recorded value of these investments was approximately $92.5$117.1 million and $85.7$108.8 million at December 31, 20182021 and 2017,2020, 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 benefitpension 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 Plan SMSP Pension PlanSMSP
 2018 2017 2016 2018 2017 2016 202120202019202120202019
Service cost $37,836
 $33,742
 $32,019
 $(316) $759
 $1,228
Service cost$54,202 $42,987 $34,061 $813 $213 $(181)
Interest cost 38,833
 38,957
 37,813
 4,248
 4,315
 4,275
Interest cost37,317 40,013 42,312 3,557 4,350 4,575 
Expected return on assets (52,302) (45,138) (42,081) —
 —
 —
Expected return on assets(64,090)(56,239)(48,623)— — — 
Amortization of net loss 13,558
 13,190
 13,331
 3,788
 2,963
 3,532
Amortization of net loss23,796 17,325 13,564 4,205 3,734 2,533 
Amortization of prior service cost 6
 28
 59
 98
 127
 168
Amortization of prior service cost6 6 6 296 290 96 
Net periodic pension cost 37,931
 40,779
 41,141
 7,818
 8,164
 9,203
Net periodic pension cost51,231 44,092 41,320 8,871 8,587 7,023 
Regulatory deferral of net periodic benefit cost(1)
 (36,153) (38,699) (39,335) —
 —
 —
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)
 17,154
 17,154
 17,154
 —
 —
 —
Previously deferred pension cost recognized(1)
17,154 17,154 17,154 — — — 
Net periodic benefit cost recognized for financial reporting(1)(2)
 $18,932
 $19,234
 $18,960
 $7,818
 $8,164
 $9,203
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 benefitpension costs for the pension plan are recognized for financial reporting based upon the authorization of each regulatory jurisdiction in which Idaho Power operates. Under IPUC order, the Idaho portion of net periodic benefitpension 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 benefitpension cost recognized for financial reporting $15.2$17.8 million, $16.2$15.9 million, and $16.4$15.1 million respectively, was recognized in "Other operations and maintenance" and $11.6 million, $11.2$10.5 million, and $11.8$11.9 million, and $11.0 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, 2018, 2017,2021, 2020, and 2016.2019.


The following table shows the components of other comprehensive (loss) income for the plans (in thousands of dollars):
 Pension PlanSMSP
 202120202019202120202019
Actuarial gain (loss) during the year$91,156 $(107,399)$(82,631)$(33)$(13,420)$(17,888)
Plan amendment service cost— — — — (130)(2,839)
Reclassification adjustments for:
Amortization of net loss23,796 17,325 13,564 4,205 3,734 2,533 
Amortization of prior service cost6 6 6 296 290 96 
Adjustment for deferred tax effects(29,590)23,184 17,776 (1,150)2,452 4,658 
Adjustment due to the effects of regulation(85,368)66,884 51,285 — — — 
Other comprehensive income (loss) recognized related to pension benefit plans$— $— $— $3,318 $(7,074)$(13,440)
  Pension Plan SMSP
  2018 2017 2016 2018 2017 2016
Actuarial (loss) gain during the year $(15,226) $(26,608) $(23,753) $7,049
 $(10,635) $(2,933)
Plan amendment service cost —
 —
 (81) —
 —
 (120)
Reclassification adjustments for:            
Amortization of net loss 13,558
 13,190
 13,331
 3,788
 2,963
 3,532
Amortization of prior service cost 6
 28
 59
 98
 127
 168
Adjustment for deferred tax effects 428
 1,744
 4,083
 (2,815) 1,555
 (253)
Adjustment due to the effects of regulation 1,234
 11,646
 6,361
 —
 —
 —
Other comprehensive income recognized related to pension benefit plans $—
 $—
 $—
 $8,120
 $(5,990) $394

In 2019, IDACORP and Idaho Power expect to recognize as components of net periodic benefit cost $16.5 million from amortizing amounts recorded in accumulated other comprehensive income (or as a regulatory asset for the pension plan) as of December 31, 2018, relating to the pension plan and SMSP. This amount consists of $13.9 million of amortization of net loss for the pension plan and $2.5 million of amortization of net loss and $0.1 million of amortization of prior service cost for the SMSP.


The following table summarizes the expected future benefit payments of these plans (in thousands of dollars):
 2019 2020 2021 2022 2023 2023-2028 202220232024202520262026-2030
Pension Plan $38,177
 $40,287
 $42,403
 $44,489
 $46,671
 $264,707
Pension Plan$45,239 $47,038 $48,890 $50,850 $52,855 $293,409 
SMSP 5,266
 5,716
 5,901
 6,071
 6,431
 31,867
SMSP6,226 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, and 2019, 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 December 31, 2018, IDACORP'sthe date of this report, IDACORP and Idaho Power'sPower have no estimated minimum required
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contributions to the pension plan are estimated to be zero in 2019.for 2022. Depending on market conditions and cash flow considerations in 2019,2022, Idaho Power could contribute up to
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$40 $40 million to the pension plan during 20192022 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.


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):
 2018 2017 20212020
Change in accumulated benefit obligation:  
  
Change in accumulated benefit obligation:  
Benefit obligation at January 1 $70,051
 $63,876
Benefit obligation at January 1$80,952 $71,029 
Service cost 1,051
 973
Service cost1,063 1,029 
Interest cost 2,643
 2,783
Interest cost2,059 2,493 
Actuarial (gain) loss (2,688) 5,769
Actuarial (gain) loss(5,805)9,359 
Benefits paid(1)
 (4,604) (3,562)
Benefits paid(1)
(4,194)(2,958)
Plan amendments —
 212
Benefit obligation at December 31 66,453
 70,051
Benefit obligation at December 3174,075 80,952 
Change in plan assets:  
  
Change in plan assets:  
Fair value of plan assets at January 1 38,294
 34,999
Fair value of plan assets at January 141,311 39,625 
Actual (loss) return on plan assets (1,330) 5,112
Actual return on plan assetsActual return on plan assets6,308 5,248 
Employer contributions(1)
 1,031
 1,745
Employer contributions(1)
(1,961)(604)
Benefits paid(1)
 (4,604) (3,562)
Benefits paid(1)
(4,194)(2,958)
Fair value of plan assets at December 31 33,391
 38,294
Fair value of plan assets at December 3141,464 41,311 
Funded status at end of year (included in noncurrent liabilities) $(33,062) $(31,757)Funded status at end of year (included in noncurrent liabilities)$(32,611)$(39,641)
    
(1) Contributions and benefits paid are each net of $3.1$3.0 million and $3.4 million of plan participant contributions for 20182021 and 2017,2020, respectively.


Amounts recognized in accumulated other comprehensive income consist of the following (in thousands of dollars):
 20212020
Net (gain) loss$(8,020)$6,434 
Prior service cost80 127 
Subtotal(7,940)6,561 
Less amount recognized in regulatory assets7,940 (6,561)
Net amount recognized in accumulated other comprehensive income$— $— 
  2018 2017
Net (loss) gain $(330) $2,777
Prior service cost 222
 269
Subtotal (108) 3,046
Less amount recognized in regulatory assets 108
 (3,046)
Net amount recognized in accumulated other comprehensive income $—
 $—

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

 2018 2017 2016 202120202019
Service cost $1,051
 $973
 $1,116
Service cost$1,063 $1,029 $853 
Interest cost 2,643
 2,783
 2,766
Interest cost2,059 2,493 2,989 
Expected return on plan assets (2,467) (2,307) (2,474)Expected return on plan assets(2,395)(2,404)(2,220)
Immediate recognition of loss from temporary deviation(1)
 4,216
 —
 —
Immediate recognition of loss from temporary deviation(1)
4,736 — — 
Amortization of prior service cost 47
 47
 26
Amortization of prior service cost47 47 48 
Net periodic postretirement benefit cost $5,490
 $1,496
 $1,434
Net periodic postretirement benefit cost$5,510 $1,165 $1,670 
      
(1) In 2018,2021, 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.


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The following table shows the components of other comprehensive income for the plan (in thousands of dollars):
202120202019
Actuarial gain (loss) during the yearActuarial gain (loss) during the year$9,718 $(6,515)$(249)
 2018 2017 2016
Actuarial loss during the year $(1,109) $(2,964) $(1,600)
Prior service cost arising during the year —
 (212) —
Reclassification adjustments for:      Reclassification adjustments for:
Immediate recognition of loss from temporary deviation(1)
 4,216
 —
 —
Immediate recognition of loss from temporary deviation(1)
4,736 — — 
Reclassification adjustments for amortization of prior service cost 47
 47
 26
Reclassification adjustments for amortization of prior service cost47 47 48 
Adjustment for deferred tax effects 270
 807
 615
Adjustment for deferred tax effects(2,514)1,665 52 
Adjustment due to the effects of regulation (3,424) 2,322
 959
Adjustment due to the effects of regulation(11,987)4,803 149 
Other comprehensive income related to postretirement benefit plans $—
 $—
 $—
Other comprehensive income related to postretirement benefit plans$— $— $— 
      
(1) In 2018,2021, 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):
  2019 2020 2021 2022 2023 2023-2027
Expected benefit payments $5,438
 $5,051
 $4,894
 $4,732
 $4,549
 $20,080
 202220232024202520262026-2029
Expected benefit payments$5,447 $5,241 $4,982 $4,790 $4,557 $19,841 
 
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 Plan SMSP 
Postretirement
Benefits
Pension PlanSMSPPostretirement
Benefits
 2018 2017 2018 2017 2018 2017 202120202021202020212020
Discount rate 4.55% 3.95% 4.60% 3.95% 4.60% 3.95%Discount rate3.05 %2.80 %3.00 %2.70 %2.95 %2.70 %
Rate of compensation increase(1)
 4.25% 4.17% 4.75% 4.75% —
 —
Rate of compensation increase(1)
4.49 %4.43 %4.75 %4.75 %— — 
Medical trend rate —
 —
 —
 —
 6.3% 6.8%Medical trend rate— — — — 6.3 %6.8 %
Dental trend rate —
 —
 —
 —
 4.0% 4.0%Dental trend rate— — — — 3.5 %4.0 %
Measurement date 12/31/2018
 12/31/2017
 12/31/2018
 12/31/2017
 12/31/2018
 12/31/2017
Measurement date12/31/202112/31/202012/31/202112/31/202012/31/202112/31/2020
            
(1) The 20182021 rate of compensation increase assumption for the pension plan includes an inflation component of 2.50%2.40% plus a 1.75%2.09% composite merit increase component that is based on employees' years of service. Merit salary increases are assumed to be 8.0% for employees in their first year of service and scale down to 0%0.6% 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 Plan SMSP 
Postretirement
Benefits
Pension PlanSMSPPostretirement
Benefits
 2018 2017 2016 2018 2017 2016 2018 2017 2016 202120202019202120202019202120202019
Discount rate 3.95% 4.45% 4.60% 3.95% 4.45% 4.60% 3.95% 4.45% 4.60%Discount rate2.80 %3.60 %4.55 %2.70 %3.65 %4.60 %2.70 %3.60 %4.60 %
Expected long-term rate of return on assets 7.50% 7.50% 7.50% —
 —
 —
 6.75% 6.75% 7.25%Expected long-term rate of return on assets7.40 %7.40 %7.50 %— — — 6.00 %6.50 %6.75 %
Rate of compensation increase 4.25% 4.17% 4.11% 4.75% 4.75% 4.50% —
 —% —%Rate of compensation increase4.49 %4.43 %4.37 %4.75 %4.75 %4.75 %— — %— %
Medical trend rate —
 —
 —
 —
 —
 —
 6.3% 6.8% 8.3%Medical trend rate— — — — — — 6.3 %6.8 %6.7 %
Dental trend rate —
 —
 —
 —
 —
 —
 4.0% 4.0% 5.0%Dental trend rate— — — — — — 3.5 %4.0 %4.0 %
  
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The assumed health care cost trend rate used to measure the expected cost of health benefits covered by the postretirement plan was 6.3 percent in 20182021 and is assumed to decrease to 5.7 percent in 2019,2022, 5.1 percent in 2020, 5.12023 and 2024, 5.0 percent in 20212025 and to gradually decrease to 4.13.9 percent by 2076.2074. The assumed dental cost trend rate used to measure the expected cost of dental benefits covered by the plan was 4.03.5 percent, or equal to the medical trend rate if lower, for all years. A one percentage point change in the assumed health care cost trend rate would have the following effects at December 31, 2018 (in thousands
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  One-Percentage-Point
  Increase Decrease
Effect on total of cost components $339
 $(247)
Effect on accumulated postretirement benefit obligation 3,222
 (2,483)


Plan Assets


Pension Asset Allocation Policy:The target allocation and actual allocations at December 31, 2018,2021, for the pension asset portfolio by asset class is set forth below:
Asset Class 
Target
Allocation
 
Actual
Allocation
December 31, 2018
Asset ClassTarget
Allocation		Actual
Allocation
December 31, 2021
Debt securities 24% 26%Debt securities24 %23 %
Equity securities 56% 56%Equity securities59 %61 %
Real estate 7% 6%Real estate9 %8 %
Other plan assets 13% 12%Other plan assets8 %8 %
Total 100% 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 bond allocations sufficient to cover approximately five years of benefit payments and cash allocations sufficient to cover the current year 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 equity funds, and cash and cash equivalents. With the exception of real estate holdings 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 2030 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.


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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 17 - "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
Assets at December 31, 2021    
Cash and cash equivalents$24,636 $— $— $24,636 
Intermediate bonds39,133 187,048 — 226,181 
Equity Securities: Large-Cap104,318 — — 104,318 
Equity Securities: Mid-Cap113,621 — — 113,621 
Equity Securities: Small-Cap85,244 — — 85,244 
Equity Securities: Micro-Cap42,915 — — 42,915 
Equity Securities: Global and International67,625 — — 67,625 
Equity Securities: Emerging Markets7,393 — — 7,393 
Plan assets measured at NAV (not subject to hierarchy disclosure)
Commingled Fund: Equity Securities: Global and International134,752 
Commingled Fund: Equity Securities: Emerging Markets47,332 
Real estate73,958 
Private market investments56,489 
Total$484,885 $187,048 $— $984,464 
Postretirement plan assets(1)
$2,391 $39,073 $— $41,464 
  Level 1 Level 2 Level 3 Total
Assets at December 31, 2018        
Cash and cash equivalents $9,717
 $—
 $—
 $9,717
Short-term bonds 20,644
 —
 —
 20,644
Intermediate bonds 20,595
 87,646
 —
 108,241
Long-term bonds —
 40,857
 —
 40,857
Equity Securities: Large-Cap 71,176
 —
 —
 71,176
Equity Securities: Mid-Cap 71,419
 —
 —
 71,419
Equity Securities: Small-Cap 53,401
 —
 —
 53,401
Equity Securities: Micro-Cap 30,387
 —
 —
 30,387
Equity Securities: International 7,104
 —
 —
 7,104
Equity Securities: Emerging Markets 6,519
 —
 —
 6,519
Plan assets measured at NAV (not subject to hierarchy disclosure)        
Equity Securities: Global and International 

 

 

 95,653
Equity Securities: Emerging Markets 

 

 

 29,757
Real estate 

 

 

 39,846
Private market investments 

 

 

 35,041
Commodities fund 

 

 

 30,842
Total $290,962
 $128,503
 $—
 $650,604
Postretirement plan assets(1)
 $758
 $32,633
 $—
 $33,391
         
Level 1Level 2Level 3Total
Assets at December 31, 2020Assets at December 31, 2020    
Cash and cash equivalentsCash and cash equivalents$25,008 $— $— $25,008 
 Level 1 Level 2 Level 3 Total
Assets at December 31, 2017  
  
  
  
Cash and cash equivalents $20,852
 $—
 $—
 $20,852
Short-term bonds 20,475
 —
 —
 20,475
Intermediate bonds 20,699
 82,923
 —
 103,622
Intermediate bonds34,455 163,000 — 197,455 
Long-term bonds —
 40,707
 —
 40,707
Equity Securities: Large-Cap 95,179
 —
 —
 95,179
Equity Securities: Large-Cap79,259 — — 79,259 
Equity Securities: Mid-Cap 81,127
 —
 —
 81,127
Equity Securities: Mid-Cap104,089 — — 104,089 
Equity Securities: Small-Cap 62,502
 —
 —
 62,502
Equity Securities: Small-Cap82,069 — — 82,069 
Equity Securities: Micro-Cap 32,753
 —
 —
 32,753
Equity Securities: Micro-Cap44,715 — — 44,715 
Equity Securities: International 6,774
 —
 —
 6,774
Equity Securities: Global and InternationalEquity Securities: Global and International69,687 — — 69,687 
Equity Securities: Emerging Markets 8,785
 —
 —
 8,785
Equity 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)
Equity Securities: International 

 

 

 83,589
Equity Securities: Emerging Markets 

 

 

 36,255
Commingled Fund: Equity Securities: Global and InternationalCommingled Fund: Equity Securities: Global and International116,223 
Commingled Fund: Equity Securities: Emerging MarketsCommingled Fund: Equity Securities: Emerging Markets50,019 
Real estate 

 

 

 38,435
Real estate54,630 
Private market investments 

 

 

 31,618
Private market investments37,875 
Commodities fund 

 

 
 35,010
Total $349,146
 $123,630
 $—
 $697,683
Total$449,856 $163,000 $— $871,603 
Postretirement plan assets(1)
 $567
 $37,727
 $—
 $38,294
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, 20182021 and 2017,2020, there were no material transfers into or out of Levels 1, 2, or 3.

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


Level 2 Bonds: These investments represent U.S.United States government, agency bonds, and corporate bonds. The U.S.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.


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
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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 the global, international and emerging markets equity securities and commodities fundare 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.


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 9 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: 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.


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 $8.2 million, $7.9 million, and $7.7 million $7.4 million,in 2021, 2020, and $7.5 million in 2018, 2017, and 2016,2019, respectively.
 
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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. 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
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liability for such benefits. The post-employment benefits included in other deferred credits on both IDACORP’s and Idaho Power’s consolidated balance sheets at December 31, 2018,2021 and 2017,2020, were approximately $2 million.


13. 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, 20182021 and 20172020 (in thousands of dollars):
 2018 2017 20212020
 Balance Avg Rate Balance Avg Rate BalanceAvg RateBalanceAvg Rate
Production $2,654,201
 3.10% $2,598,940
 3.07%Production$2,597,285 3.15 %$2,529,708 3.23 %
Transmission 1,201,092
 1.89% 1,163,240
 1.94%Transmission1,309,143 1.89 %1,272,360 1.88 %
Distribution 1,792,284
 2.24% 1,710,126
 2.44%Distribution2,058,819 2.25 %1,968,752 2.26 %
General and Other 456,279
 6.40% 433,856
 6.01%General and Other544,069 6.17 %512,970 6.17 %
Total in service 6,103,856
 2.84% 5,906,162
 2.87%Total in service6,509,316 2.85 %6,283,790 2.88 %
Accumulated provision for depreciation (2,210,781)  
 (2,098,274)  
Accumulated provision for depreciation(2,298,951) (2,193,831) 
In service - net $3,893,075
  
 $3,807,888
  
In service - net$4,210,365  $4,089,959  
 
At December 31, 2018,2021, Idaho Power's construction work in progress balance of $480.3$670.6 million included relicensing costs of $297.0$389.3 million for the HCC, Idaho Power's largest hydroelectrichydropower complex. In 2018, 2017,2021, 2020, and 2016, the2019, Idaho Power had IPUC authorized Idaho Powerauthorization to include in its Idaho jurisdiction rates $6.5 million annually ($8.8 million when grossed-up for the effect of income taxes in 2018 and $10.7 million when grossed-up for the effect of income taxes in 2017 and 2016 prior to income tax reform described in Note 2 - "Income Taxes")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, 2018,2021, Idaho Power's regulatory liability for collection of AFUDC relating to the HCC was $135.1$187.7 million.


Idaho Power's ownership interest in threetwo 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, 20182021 (in thousands of dollars): 
Name of Plant Location Utility Plant in Service 
Construction
Work in Progress
 
Accumulated
Provision for Depreciation
 Ownership % 
MW(1)
Name of PlantLocationUtility Plant in ServiceConstruction
Work in Progress		Accumulated
Provision for Depreciation		Ownership %
MW(1)(2)
Jim Bridger units 1-4 Rock Springs, WY $733,451
 $5,141
 $334,731
 33 771Jim Bridger units 1-4Rock Springs, WY$771,034 $7,775 $401,696 33775
Boardman Boardman, OR 82,459
 4
 74,748
 10 64
Valmy units 1 and 2 Winnemucca, NV 410,947
 248
 279,643
 50 284
North Valmy unit 2(2)
North Valmy unit 2(2)
Winnemucca, NV255,451 881 195,258 50145
(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 in BCC. Idaho Power’s coal purchases from the joint venture were $81.8$59.7 million in 2018, $86.42021, $68.3 million in 2017,2020, and $92.9$73.6 million in 2016.2019.
 
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 $9.7$8.2 million in 2018, $9.82021, $9.3 million in 2017,2020, and $7.8$8.6 million in 2016.2019.
 
IDACORP's consolidated VIE, Marysville, owns a hydroelectrichydropower plant with a net book value of $15.2$13.7 million and $15.7$14.2 million at December 31, 20182021 and 2017,2020, respectively.


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14. 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 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 of accretion, depreciation, and gains or losses, as approved by the IPUC. 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 arehave been exempted from such regulatory treatment as Idaho Power is now collectingcollected 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 removal of polychlorinated biphenyl-contaminated equipment at its distribution facilities and the reclamation and removal costs at its jointly-owned coal-fired generation facilities. In 2021, changes in estimates at the coal-fired generation facilities resulted in a net increase of $9.4 million in the recorded AROs. The increase is primarily related to revised cost estimates for the closure of a flue gas desulfurization pond at the Jim Bridger plant.


Idaho Power also has additional AROs associated with its transmission system hydroelectric facilities, natural gas-fired generation facilities, and jointly owned coal-fired 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 collectcollects 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, 20182021 and 2017.2020.
 
The following table presents the changes in the carrying amount of AROs (in thousands of dollars): 
 20212020
Balance at beginning of year$27,691 $28,191 
Accretion expense1,021 1,053 
Revisions in estimated cash flows9,415 193 
Liability settled(1,429)(1,746)
Balance at end of year$36,698 $27,691 
  2018 2017
Balance at beginning of year $26,415
 $26,257
Accretion expense 1,055
 1,015
Revisions in estimated cash flows (751) (791)
Liability incurred 129
 —
Liability settled (56) (66)
Balance at end of year $26,792
 $26,415


15. INVESTMENTS
 
The table below summarizes IDACORP’s and Idaho Power’s investments as of December 31 (in thousands of dollars): 
 2018 2017 20212020
Idaho Power investments:  
  
Idaho Power investments:  
Bridger Coal Company (equity method investment) $49,878
 $68,566
Bridger Coal Company (equity method investment)$22,677 $37,115 
Exchange traded short-term bond funds and cash equivalents 36,471
 30,249
Exchange traded short-term bond funds and cash equivalents54,078 50,531 
Executive deferred compensation plan investments 17
 17
Executive deferred compensation plan investments353 202 
Total Idaho Power investments 86,366
 98,832
Total Idaho Power investments77,108 87,848 
Investments in affordable housing (IDACORP Financial Services) 3,446
 5,521
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) 11,366
 11,345
Ida-West joint ventures (equity method investments)10,386 10,662 
Other investmentsOther investments1,363 — 
Total IDACORP investments $101,178
 $115,698
Total IDACORP investments$123,824 $126,948 
 
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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 dollars):
  2018 2017 2016
Bridger Coal Company (Idaho Power) $10,712
 $9,267
 $10,855
Ida-West joint ventures 1,737
 2,107
 2,016
Total $12,449
 $11,374
 $12,871
 202120202019
Bridger Coal Company (Idaho Power)$10,211 $10,102 $10,285 
Ida-West joint ventures1,224 1,411 2,085 
Total$11,435 $11,513 $12,370 
 
Investments in Equity Securities


Investments in securities classified as available-for-saleequity securities are reported at fair value. Any unrealized gains or losses on available-for-saleequity securities are included in income, as the fair value option has been elected for these instruments.income. Unrealized gains and losses on available-for-saleequity securities were immaterial at December 31, 20182021 and December 31, 2017.2020. The following table summarizes sales of available-for-saleequity securities (in thousands of dollars):
 202120202019
Proceeds from sales$11,328 $25,795 $5,080 
Gross realized gains from sales— — — 
  2018 2017 2016
Proceeds from sales $5,007
 $4,989
 $15,693
Gross realized gains from sales —
 —
 54


IDACORP Financial Services Investments
Investments in Affordable Housing


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 affordable housingreal 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. DERIVATIVE FINANCIAL INSTRUMENTS
 
Commodity Price Risk
 
Idaho Power is exposed to market risk relating to electricity, natural gas, and other fuel commodity prices, all of which are heavily influenced by supply and demand. Market risk may be influenced by market participants’ nonperformance of their contractual obligations and commitments, which affects the supply of or demand for the commodity. Idaho Power uses derivative instruments, such as physical and financial forward contracts, for both electricity and fuel to manage the risks relating to these commodity price exposures. The primary objectives of Idaho Power’s energy purchase and sale activity are to meet the demand of retail electric customers, maintain appropriate physical reserves to ensure reliability, and make economic use of temporary surpluses that may develop.
 
All of Idaho Power's derivative instruments have been entered into for the purpose of securing energy resources for future periods or economically hedging forecasted purchases and sales, though none of these instruments have been designated as cash flow hedges. Idaho Power offsets fair value amounts recognized on its balance sheet and applies collateral related to derivative instruments executed with the same counterparty under the same master netting agreement. Idaho Power does not offset a counterparty's current derivative contracts with the counterparty's long-term derivative contracts, although Idaho Power's master netting arrangements would allow current and long-term positions to be offset in the event of default. Also, in the event of default, Idaho Power's master netting arrangements would allow for the offsetting of all transactions executed under the master netting arrangement. These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, receivables and payables arising from settled positions, and other forms of non-cash collateral (such as letters of credit). These types of transactions are excluded from the offsetting presented in the derivative fair value and offsetting table below.


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The table below presents the gains and losses on derivatives not designated as hedging instruments for the years ended December 31, 2018, 2017,2021, 2020, and 20162019 (in thousands of dollars):
Location of Realized Gain/(Loss) on Derivatives Recognized in Income
Gain/(Loss) on Derivatives Recognized in Income(1)
202120202019
Financial swapsOperating revenues$1,046 $2,173 $904 
Financial swapsPurchased power1,959 (3,531)(2,183)
Financial swapsFuel expense12,180 (4,791)13,811 
Forward contractsOperating revenues1,966 421 285 
Forward contractsPurchased power(1,099)(384)(270)
Forward contractsFuel expense(194)(36)565 
  Location of Realized Gain/(Loss) on Derivatives Recognized in Income 
Gain/(Loss) on Derivatives Recognized in Income(1)
   2018 2017 2016
Financial swaps Operating revenues $1,316
 $902
 $1,405
Financial swaps Purchased power 7,828
 166
 586
Financial swaps Fuel expense 22,563
 701
 (1,947)
Financial swaps Other operations and maintenance 118
 (84) (161)
Forward contracts Operating revenues 41
 55
 (54)
Forward contracts Purchased power (54) (69) 86
Forward contracts Fuel expense (186) 4
 139
         
(1)Excludes unrealized gains or losses on derivatives, which are recorded on the balance sheet as regulatory assets or regulatory liabilities.
 
Settlement gains and losses on electricity swap contracts are recorded on the income statement in operating revenues from contracts with customers or purchased power depending on the forecasted position being economically hedged by the derivative contract. Settlement gains and losses on contracts for natural gas are reflected in fuel expense. Settlement gains and losses on diesel derivatives are recorded in other operations and maintenanceO&M expense. See Note 17 - "Fair Value Measurements" for additional information concerning the determination of fair value for Idaho Power’s assets and liabilities from price risk management activities.


Derivative Instrument Summary


The table below presents the fair values and locations of derivative instruments not designated as hedging instruments recorded on the balance sheets and reconciles the gross amounts of derivatives recognized as assets and as liabilities to the net amounts presented in the balance sheets at December 31, 20182021 and 20172020 (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 
    Asset Derivatives Liability Derivatives
  Balance Sheet Location Gross Fair Value Amounts Offset Net Assets Gross Fair Value Amounts Offset Net Liabilities
    
December 31, 2018              
Current:    
      
    
Financial swaps Other current assets $4,639
 $(984)
(1) 
$3,655
 $938
 $(938) $—
Financial swaps Other current liabilities —
 —
 —
 806
 —
 806
Forward contracts Other current liabilities —
 —
 —
 104
 —
 104
Long-term:    
          
Financial swaps Other liabilities —
 —
 —
 64
 —
 64
Total   $4,639
 $(984) $3,655
 $1,912
 $(938) $974
               
December 31, 2017              
Current:    
      
    
Financial swaps Other current assets $18
 $—
 $18
 $—
 $—
 $—
Financial swaps Other current liabilities 553
 (553) —
 1,971
 (748)
(2) 
1,223
Forward contracts Other current liabilities —
 —
 —
 2
 —
 2
Long-term:    
      
    
Financial swaps Other assets 4
 —
 4
 —
 —
 —
Total   $575
 $(553) $22
 $1,973
 $(748) $1,225
               
(1) Current asset derivative amounts offset include $45 thousand$2.0 millionof collateral payable for the period endingat December 31, 2018.2021.
(2) Current and long-term liability derivative amounts offset include $196$0.5 million and $16 thousandof collateral receivable for the period endingat December 31, 2017.2020, respectively.



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The table below presents the volumes of derivative commodity forward contracts and swaps outstanding at December 31, 20182021 and 20172020 (in thousands of units):
 December 31,December 31,
Commodity Units 2018 2017CommodityUnits20212020
Electricity purchases MWh 52
 312
Electricity purchasesMWh529 74 
Electricity sales MWh 39
 224
Electricity salesMWh129 — 
Natural gas purchases MMBtu 7,514
 7,028
Natural gas purchasesMMBtu11,740 7,923 
Natural gas sales MMBtu 446
 140
Natural gas salesMMBtu— 775 
 
Credit Risk
 
At December 31, 2018,2021, 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, 2018,2021, was $1.9$3.0 million. Idaho Power posted nodid not post any cash collateral related to this amount. If the credit-risk-related contingent features underlying these agreements were triggered on December 31, 2018,2021, Idaho Power would have been required to pay or post collateral to its counterparties up to an additional $7.8$7.6 million to cover open liability positions as well as completed transactions that have not yet been paid.


17. FAIR VALUE MEASUREMENTS
 
IDACORP and Idaho Power have categorized their financial instruments into a three-level fair value hierarchy, based on the priority of the inputs to the valuation technique. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). If the inputs used to measure the financial instruments fall within different levels of the hierarchy, the categorization is based on the lowest level input that is significant to the fair value measurement of the instrument.
 
Financial assets and liabilities recorded on the 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.
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•      Level 3: Financial assets and liabilities whose values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. These inputs reflect management’s own assumptions about the assumptions a market participant would use in pricing the asset or liability.
 
IDACORP’s and Idaho Power’s assessment of a particular input's significance to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy. An item recorded at fair value is reclassified among levels when changes in the nature of valuation inputs cause the item to no longer meet the criteria for the level in which it was previously categorized. There were no transfers between levels or material changes in valuation techniques or inputs during the years ended December 31, 20182021 and 2017.2020.


Certain instruments have been valued using net asset value (NAV) as a practical expedient. These instruments are similar to mutual funds; however, their NAV is generally not published and publicly available, nor are these instruments traded on an exchange. Instruments valued using NAV as a practical expedient are included in the fair value disclosures below; however, in accordance with 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, 20182021 and 20172020 (in thousands of dollars): 
 December 31, 2018 December 31, 2017December 31, 2021December 31, 2020
 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 TotalLevel 1Level 2Level 3TotalLevel 1Level 2Level 3Total
Assets:  
  
  
  
        Assets:    
Money market funds and commercial paper                Money market funds and commercial paper
IDACORP(1)
 $97,833
 $—
 $—
 $97,833
 $28,038
 $—
 $—
 $28,038
IDACORP(1)
$80,406 $— $— $80,406 $56,048 $— $— $56,048 
Idaho Power 79,228
 —
 —
 79,228
 10,260
 —
 —
 10,260
Idaho Power10,393 — — 10,393 40,038 — — 40,038 
Derivatives 3,655
 —
 —
 3,655
 22
 —
 —
 22
Derivatives6,596 2 — 6,598 1,995 — — 1,995 
Equity securities 36,488
 —
 —
 36,488
 30,266
 —
 —
 30,266
Equity securities54,431 — — 54,431 50,733 — — 50,733 
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:
Derivatives $870
 $104
 $—
 $974
 $1,223
 $2
 $—
 $1,225
Derivatives$34 $5,713 $— $5,747 $134 $10 $— $144 
                
(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 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 and Intercontinental Exchange 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 Rabbi trust.


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The table below presents the carrying value and estimated fair value of financial instruments that are not reported at fair value, as of December 31, 20182021 and 2017,2020, using available market information and appropriate valuation methodologies (in thousands).
 December 31, 2018 December 31, 2017 December 31, 2021December 31, 2020
 Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value Carrying AmountEstimated Fair ValueCarrying AmountEstimated Fair Value
 (thousands of dollars) (thousands of dollars)
IDACORP  
  
  
  
IDACORP    
Assets:  
  
  
  
Assets:    
Notes receivable(1)
 $3,804
 $3,804
 $3,804
 $3,804
Notes receivable(1)
$3,804 $3,804 $3,804 $3,804 
Liabilities:  
  
  
  
Liabilities:    
Long-term debt(1)
 1,834,788
 1,942,773
 1,746,123
 1,915,459
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 Power  
  
  
  
Idaho Power    
Liabilities:  
  
  
  
Liabilities:    
Long-term debt(1)
 $1,834,788
 $1,942,773
 $1,746,123
 $1,915,459
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 and long-term debt are categorized as Level 3 and Level 2, respectively, of the fair value hierarchy, as defined earlier in this Note 17 - "Fair Value Measurements."


Notes receivable are related to Ida-West and are valued based on unobservable inputs, including discountedforecasted cash flows, which are partially based on forecasted hydroelectricexpected hydropower conditions. Long-term debt is not traded on an exchange and is valued using quoted rates for similar debt in active markets. Carrying values for cash and cash equivalents, deposits, customer and other receivables, notes payable, accounts payable, interest accrued, and taxes accrued approximate fair value.
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18. SEGMENT INFORMATION
 
IDACORP’s only reportable segment is utility operations. The utility operations segment’s primary source of revenue is the regulated operations of Idaho Power. Idaho Power’s regulated operations include the generation, transmission, distribution, purchase, and sale of electricity. This segment also includes income from IERCo, a wholly-owned subsidiary of Idaho Power that is also subject to regulation and is a one-third owner of BCC, an unconsolidated joint venture.
 
IDACORP’s other operating segments are below the quantitative and qualitative thresholds for reportable segments and are included in the “All Other” category in the table below. This category is comprised of IFS’s investments in affordable housing developments and historic rehabilitationother real estate tax credit projects, Ida-West’s joint venture investments in small hydroelectrichydropower generation projects, and IDACORP’s holding company expenses.


The table below summarizes the segment information for IDACORP’s utility operations and the total of all other segments, and reconciles this information to total enterprise amounts (in thousands):
Utility
Operations		All
Other		EliminationsConsolidated
Total
 
Utility
Operations
 
All
Other
 Eliminations 
Consolidated
Total
2018        
20212021    
Revenues $1,366,582
 $4,170
 $—
 $1,370,752
Revenues$1,455,410 $2,674 $— $1,458,084 
Operating income 295,256
 1,666
 —
 296,922
Operating income329,568 83 — 329,651 
Other income, net 11,646
 (1) —
 11,645
Other income, net21,243 (138)— 21,105 
Interest income 8,923
 1,573
 (655) 9,841
Interest income7,123 216 (47)7,292 
Equity-method income 10,712
 1,737
 —
 12,449
Equity-method income10,211 1,224 — 11,435 
Interest expense 85,891
 712
 (655) 85,948
Interest expense86,663 82 (47)86,698 
Income before income taxes 240,646
 4,263
 —
 244,909
Income before income taxes281,482 1,302 — 282,784 
Income tax expense (benefit) 18,312
 (926) —
 17,386
Income tax expense (benefit)38,257 (1,345)— 36,912 
Income attributable to IDACORP, Inc. 222,334
 4,467
 —
 226,801
Income attributable to IDACORP, Inc.243,225 2,325 — 245,550 
Total assets 6,254,400
 163,540
 (35,186) 6,382,754
Total assets6,990,839 281,999 (62,323)7,210,515 
Expenditures for long-lived assets 277,823
 30
 —
 277,853
Expenditures for long-lived assets299,972 27 — 299,999 
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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 

  
Utility
Operations
 
All
Other
 Eliminations 
Consolidated
Total
2017        
Revenues $1,344,893
 $4,593
 $—
 $1,349,486
Operating income 313,602
 1,943
 —
 315,545
Other income, net 12,356
 191
 —
 12,547
Interest income 6,044
 295
 (211) 6,128
Equity-method income 9,267
 2,107
 —
 11,374
Interest expense 83,660
 297
 (211) 83,746
Income before income taxes 257,609
 4,239
 —
 261,848
Income tax expense (benefit) 51,262
 (2,602) —
 48,660
Income attributable to IDACORP, Inc. 206,347
 6,072
 —
 212,419
Total assets 5,995,435
 143,696
 (93,726) 6,045,405
Expenditures for long-lived assets 285,471
 17
 —
 285,488
         
2016        
Revenues $1,259,353
 $2,667
 $—
 $1,262,020
Operating income 277,297
 6,285
 —
 283,582
Other income, net 15,852
 6
 —
 15,858
Interest income 4,235
 127
 (121) 4,241
Equity-method income 10,855
 2,016
 —
 12,871
Interest expense 81,812
 344
 (121) 82,035
Income before income taxes 226,427
 8,090
 —
 234,517
Income tax expense (benefit) 37,185
 (756) —
 36,429
Income attributable to IDACORP, Inc. 189,242
 9,046
 —
 198,288
Total assets 6,236,744
 73,137
 (19,984) 6,289,897
Expenditures for long-lived assets 296,948
 2
 —
 296,950

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19. OTHER INCOME AND EXPENSE
 
The following table presents the components of IDACORP’s other expense,income (expense), net and Idaho Power's other expense,income (expense), net (in thousands of dollars):
IDACORP 2018 2017 2016IDACORP202120202019
Interest and dividend income, net $5,605
 $3,872
 $4,466
Interest and dividend income, net$1,408 $3,813 $8,181 
Carrying charges on regulatory assets 4,075
 2,310
 2,082
Carrying charges on regulatory assets5,034 7,063 5,494 
Pension and postretirement non-service costs(1)
 (15,781) (11,194) (11,806)
Pension and postretirement non-service costs(1)
(15,249)(11,865)(10,976)
Income from life insurance investments 2,779
 2,090
 2,588
Income from life insurance investments5,203 4,036 4,104 
Other income 455
 813
 738
Total other expense, net $(2,867) $(2,109) $(1,932)
Other income (expense)Other income (expense)463 462 (301)
Total other income (expense), netTotal other income (expense), net$(3,141)$3,509 $6,502 
      
Idaho Power      Idaho Power
Interest and dividend income, net $4,688
 $3,787
 $4,460
Interest and dividend income, net$1,241 $3,034 $5,898 
Carrying charges on regulatory assets 4,075
 2,310
 2,082
Carrying charges on regulatory assets5,034 7,063 5,494 
Pension and postretirement non-service costs(1)
 (15,781) (11,194) (11,806)
Pension and postretirement non-service costs(1)
(15,240)(11,862)(10,976)
Income from life insurance investments 2,779
 2,090
 2,588
Income from life insurance investments5,203 4,036 4,104 
Other expense (1,612) (1,749) (1,871)
Total other expense, net $(5,851) $(4,756) $(4,547)
Other income (expense)Other income (expense)591 468 (303)
Total other income (expense), netTotal other income (expense), net$(3,171)$2,739 $4,217 
      
(1) The 20182021 pension and postretirement non-service costs includes $4.2$4.7 million of expense for a temporary deviation from the cost-sharing provisions of the substantive postretirement plan as described in Note 12 - "Benefit Plans."


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20. 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), net of tax, during the years ended December 31, 2018, 2017,2021, 2020, and 20162019 (in thousands of dollars). Items in parentheses indicate reductions to AOCI.
Year Ended December 31,
202120202019
Defined benefit pension items
Balance 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 $6773,343 2,988 1,952 
Net current-period other comprehensive income3,318 (7,074)(13,440)
Balance at end of period$(40,040)$(43,358)$(36,284)
  Year Ended December 31,
  2018 2017 2016
Defined benefit pension items      
Balance at beginning of period $(30,964) $(20,882) $(21,276)
Other comprehensive income before reclassifications 5,234
 (7,872) (1,859)
Amounts reclassified out of AOCI to net income 2,886
 1,882
 2,253
Net current-period other comprehensive income 8,120
 (5,990) 394
Cumulative effect of change in accounting principle(1)
 —
 (4,092) —
Balance at end of period $(22,844) $(30,964) $(20,882)
       
(1) The cumulative effect of change in accounting principle relates to the 2017 adoption of ASU 2018-02, Income Statement—Reporting Comprehensive Income (Topic 220).
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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, 2018, 2017,2021, 2020, and 20162019 (in thousands of dollars). Items in parentheses indicate increases to net income.
Amount Reclassified from AOCI
Year Ended December 31,
202120202019
 Amount Reclassified from AOCI
 Year Ended December 31,
 2018 2017 2016
Amortization of defined benefit pension items(1)
      
Amortization of defined benefit pension items(1)
Prior service cost $98
 $127
 $168
Prior service cost$296 $290 $96 
Net loss 3,788
 2,963
 3,532
Net loss4,205 3,734 2,533 
Total before tax 3,886
 3,090
 3,700
Total before tax4,501 4,024 2,629 
Tax benefit(2)
 (1,000) (1,208) (1,447)
Tax benefit(2)
(1,158)(1,036)(677)
Net of tax 2,886
 1,882
 2,253
Net of tax3,343 2,988 1,952 
Total reclassification for the period $2,886
 $1,882
 $2,253
Total reclassification for the period$3,343 $2,988 $1,952 
      
(1) Amortization of these items is included in IDACORP's consolidated income statements in other operating expenses and in Idaho Power's consolidated income statements in other"Other (income) expense, net.
(2) The tax benefit is included in income tax expensenet" 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. 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 million in 2021, $0.7 million in both 2018 and 20172020, and $0.8 million in 2016.2019.


At December 31, 20182021 and 2017,2020, Idaho Power had a $1.9$2.0 million and $57.3$1.5 million payable to IDACORP, respectively, which was included in its accounts payable to affiliates balance on its consolidated balance sheets. In 2018, Idaho Power paid IDACORP certain estimated income taxes that had been accrued at December 31, 2017.
 
Ida-West:Idaho Power purchases all of the power generated by four of Ida-West’s hydroelectrichydropower projects located in Idaho. Idaho Power paid Ida-West $9.7purchased $8.2 million in 2018, $9.82021, $9.3 million in 2017,2020, and $7.8$8.6 million in 2016 for that power.2019 of power from Ida-West.


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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, 20182021 and 2017,2020, the related consolidated statements of income, comprehensive income, equity, and cash flows, for each of the three years in the period ended December 31, 2018,2021, 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, 20182021 and 2017,2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018,2021, 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, 2018,2021, 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 21, 2019,17, 2022, 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 auditsaudit 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), 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.

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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: (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 management to support its assertions about impacted account balances and disclosures and the degree 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 costs and (2) a refund to customers for amounts collected prior to costs being incurred. Given that management’s accounting judgments are based on assumptions about the outcome of future decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the uncertainty of future decisions by the Commissions and the application of flow-through accounting for income taxes included the following, among others:

•We tested the effectiveness of management’s controls over the evaluation 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 reduction in rates that should be reported as regulatory liabilities.

•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.

•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 21, 201917, 2022


We have served as the Company's auditor since 1932.

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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, 20182021 and 2017,2020, 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, 2018,2021, 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, 20182021 and 2017,2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018,2021, 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, 2018,2021, 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 21, 2019,17, 2022, 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 auditsaudit 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
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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: (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 management to support its assertions about impacted account balances and disclosures and the degree 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 costs and (2) a refund to customers for amounts collected prior to costs being incurred. Given that management’s accounting judgments are based on assumptions about the outcome of future decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the uncertainty of future decisions by the Commissions and the application of flow-through accounting for income taxes included the following, among others:

•We tested the effectiveness of management’s controls over the evaluation 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 reduction in rates that should be reported as regulatory liabilities.

•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.

•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 21, 201917, 2022


 We have served as the Company's auditor since 1932.
 
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SUPPLEMENTAL FINANCIAL INFORMATION, UNAUDITED
QUARTERLY FINANCIAL DATA
The following unaudited information is presented for each quarter of 2018 and 2017 (in thousands of dollars, except for per share amounts). In the opinion of each company, all adjustments necessary for a fair statement of such amounts for such periods have been included. The results of operations for the interim periods are not necessarily indicative of the results to be expected for the full year. Accordingly, earnings information for any three-month period should not be considered as a basis for estimating operating results for a full fiscal year. Amounts are based upon quarterly statements and the sum of the quarters may not equal the annual amount reported.
  Quarter Ended
  March 31 June 30 September 30 December 31
IDACORP, Inc.  
  
  
  
2018        
Revenues $310,107
 $339,952
 $408,801
 $311,892
Operating income 50,589
 82,835
 115,233
 48,265
Net income 36,111
 62,593
 102,591
 26,228
Net income attributable to IDACORP, Inc. 36,142
 62,288
 102,231
 26,140
Basic earnings per share $0.72
 $1.24
 $2.03
 $0.52
Diluted earnings per share $0.72
 $1.23
 $2.02
 $0.52
2017  
  
  
  
Revenues $302,544
 $333,006
 $408,324
 $305,612
Operating income(1)
 53,627
 81,907
 123,707
 56,304
Net income 33,006
 50,096
 91,076
 39,010
Net income attributable to IDACORP, Inc. 33,102
 49,831
 90,634
 38,852
Basic earnings per share $0.66
 $0.99
 $1.80
 $0.77
Diluted earnings per share $0.66
 $0.99
 $1.80
 $0.77
Idaho Power Company        
2018        
Revenues $309,461
 $338,699
 $407,355
 $311,067
Income from operations 51,120
 82,659
 114,963
 48,581
Net income 35,857
 60,637
 100,194
 25,646
2017  
  
  
  
Revenues $301,964
 $331,768
 $406,655
 $304,506
Income from operations(1)
 54,350
 81,777
 123,293
 56,554
Net income 32,482
 48,381
 88,329
 37,155
(1) Operating income in 2017 reflects the 2018 adoption of Accounting Standards Update 2017-07. Retrospective adjustments were made to prior periods to conform with current period presentation. For additional information, refer to Note 1 - "Summary of Significant Accounting Policies" to the consolidated financial statements included in this report.
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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.’s disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of December 31, 2018,2021, have concluded that IDACORP, Inc.’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, 2018.2021. 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, 2018,2021, 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, 20182021 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, 2018.2021.
 
February 21, 201917, 2022


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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, 2018,2021, 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, 2018,2021, 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 and financial statement schedules as of and for the year ended December 31, 20182021, of the Company and our report dated February 21, 201917, 2022, expressed an unqualified opinion on those financial statements and financial statement schedules.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 overOver 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 21, 201917, 2022


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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's disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of December 31, 2018,2021, have concluded that Idaho Power Company'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, 2018.2021. 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, 2018,2021, 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, 20182021, 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, 2018.2021.
 
February 21, 201917, 2022


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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, 2018,2021, 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, 2018,2021, 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 and financial statement schedule as of and for the year ended December 31, 20182021, of the Company and our report dated February 21, 201917, 2022, expressed an unqualified opinion on those financial statements and financial statement schedule.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 overOver 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 21, 201917, 2022


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Changes in Internal Control Over Financial Reporting - IDACORP, Inc. and Idaho Power Company
 
There have been no changes in IDACORP, Inc.’s or Idaho Power Company’s internal control over financial reporting during the quarter ended December 31, 20182021, that have materially affected, or are reasonably likely to materially affect, IDACORP, Inc.’s or Idaho Power Company’s internal control over financial reporting.
 


ITEM 9B. OTHER INFORMATION
 
None.


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,” “Section“Delinquent Section 16(a) Beneficial Ownership Reporting Compliance,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 20192022 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 20192022 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 20192022 annual meeting of shareholders is hereby incorporated by reference. The table below includes information as of December 31, 2018,2021, with respect to the IDACORP 2000 Long-Term Incentive and Compensation Plan (LTICP) pursuant to which equity securities of IDACORP may be issued.


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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.
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 shareholders 139,353
(1) 
$—
(2) 
720,408
(3) 
Equity compensation plans not approved by shareholders —
 $—
 —
 
Total 139,353
 $—
 720,408
 
 
(1) Represents shares subject to outstanding time-based restricted stock units and performance-based restricted stock units (at target).
(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. The number of shares listed in this column excludes (i) issued but unvested performance-based restricted shares and (ii) issued but unvested time-based restricted shares, in both cases as of December 31, 2018.
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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 20192022 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 20192022 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, 20182021 and 2017:2020:
  2018 2017
Audit fees $1,437,100
 $1,379,000
Audit-related fees(1)
 29,550
 39,400
Tax fees(2)
 26,125
 40,000
All other fees(3)
 1,895
 2,000
Total $1,494,670
 $1,460,400
     
(1)  Includes accounting-related consultation services.
(2) Includes fees for consultation related to tax planning and accounting.
(3) Accounting research tool subscription.
 20212020
Audit fees$1,526,750 $1,531,235 
Tax fees(1)
19,885 16,121 
All other fees(2)
12,050 1,895 
Total$1,558,685 $1,549,251 
(1) Includes fees for consultation related to tax planning and accounting.
(2) Accounting research tool subscription and fees for finance and accounting conference attendance.
 
Policy on Audit Committee Pre-Approval:
 
Idaho Power and the Audit 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 Committee has established and periodically reviews a pre-approval policy for audit and non-audit services. For 20182021 and 2017,2020, all audit and non-audit services and all fees paid in connection with those services were pre-approved by the 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 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 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;
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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. In addition, any proposed services exceeding pre-approved cost levels will require specific pre-approval by the Audit Committee. Under the pre-approval policy, the Audit Committee has delegated to the Chairman of the Audit Committee pre-approval authority for proposed services; however, the Chairman must report any pre-approval decisions to the Audit 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 Committee or the Audit Committee Chairman, as the case may be, for pre-approval.

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In determining whether to pre-approve the engagement of the independent public accounting firm, the Audit Committee or the Committee Chairman, 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, tax, and other services that have the general pre-approval of the Audit Committee. The term of any pre-approval is 12 months from the date of pre-approval, unless the Audit Committee specifically provides for a different period. The Audit 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 and Supplementary Data”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 thisIDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2021, 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 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
2
Agreement and Plan of Exchange between IDACORP, Inc. and Idaho Power Company, dated as of February 2, 1998
S-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 
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 
3.4
Articles of Share Exchange, as filed with the Secretary of State of Idaho on September 29, 1998
S-8 Post-Effective Amend. No. 133-56071-993(d)10/1/1998 
3.5
Articles of Amendment to Restated Articles of Incorporation of Idaho Power Company, as filed with the Secretary of State of Idaho on June 15, 2000
10-Q1-31983(a)(iii)8/4/2000 
3.6
Articles of Amendment to Restated Articles of Incorporation of Idaho Power Company, as filed with the Secretary of State of Idaho on January 21, 2005
8-K1-31983.31/26/2005 
3.7
Articles of Amendment to Restated Articles of Incorporation of Idaho Power Company, as amended, as filed with the Secretary of State of Idaho on November 19, 2007
8-K1-31983.311/19/2007 
Table of Contents

  Incorporated by Reference 
Exhibit No.Exhibit DescriptionFormFile No.Exhibit No.DateIncluded Herewith
3.8
Articles of Amendment to Restated Articles of Incorporation of Idaho Power Company, as amended, as filed with the Secretary of State of Idaho on May 18, 2012
8-K1-31983.145/21/2012 
3.9
Amended Bylaws of Idaho Power Company, amended on November 15, 2007 and presently in effect
8-K1-31983.211/19/2007 
3.10
Articles of Incorporation of IDACORP, Inc.
S-3333-647373.111/4/1998 
3.11
Articles of Amendment to Articles of Incorporation of IDACORP, Inc. as filed with the Secretary of State of Idaho on March 9, 1998
S-3 Amend. No. 1333-647373.211/4/1998 
3.12
Articles of Amendment to Articles of Incorporation of IDACORP, Inc. creating A Series Preferred Stock, without par value, as filed with the Secretary of State of Idaho on September 17, 1998
S-3 Post-Effective Amend. No. 1333-00139-993(b)9/22/1998 
3.13
Articles of Amendment to Articles of Incorporation of IDACORP, Inc., as amended, as filed with the Secretary of State of Idaho on May 18, 2012
8-K1-144653.135/21/2012 
3.14
Amended and Restated Bylaws of IDACORP, Inc., amended on October 29, 2014 and presently in effect
10-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 Trustees 2-3413*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*
 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*
Table of Contents

  Incorporated by Reference 
Exhibit No.Exhibit DescriptionFormFile No.Exhibit No.DateIncluded Herewith
 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
4.3
Instruments relating to Idaho Power Company American Falls bond guarantee (see Exhibit 10.16)
10-Q1-31984(b)8/4/2000 
4.4Agreement of Idaho Power Company to furnish certain debt instrumentsS-333-65720*4(f)7/7/1993 
4.5
Agreement of IDACORP, Inc. to furnish certain debt instruments
10-Q1-144654(c)(ii)11/6/2003 
4.6Agreement 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 
4.7
Indenture for Senior Debt Securities dated as of February 1, 2001, between IDACORP, Inc. and Deutsche Bank Trust Company Americas (formerly known as Bankers Trust Company), as trustee
8-K1-144654.12/28/2001 
4.8
First Supplemental Indenture dated as of February 1, 2001 to Indenture for Senior Debt Securities dated as of February 1, 2001 between IDACORP, Inc. and Deutsche Bank Trust Company Americas (formerly known as Bankers Trust Company), as trustee
8-K1-144654.22/28/2001 
4.9
Indenture for Debt Securities dated as of August 1, 2001 between Idaho Power Company and Deutsche Bank Trust Company Americas (formerly known as Bankers Trust Company), as trustee
S-3333-677484.138/16/2001 
4.10
Idaho Power Company Instrument of Further Assurance relating to Mortgage and Deed of Trust, dated as of August 3, 2010
10-Q1-31984.128/5/2010 
10.1
Amended and Restated Agreement for the Operation of the Jim Bridger Project, dated December 11, 2014, between Idaho Power Company and PacifiCorp
10-K1-14465, 1-319810.42/19/2015 
10.2
Amended and Restated Agreement for the Ownership of the Jim Bridger Project, dated December 11, 2014, between Idaho Power Company and PacifiCorp
10-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 
Table of Contents

  Incorporated by Reference 
Exhibit No.Exhibit DescriptionFormFile No.Exhibit No.DateIncluded Herewith
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 
10.6
Settlement Agreement, dated March 25, 2009, between the State of Idaho and Idaho Power Company relating to the agreement filed as Exhibit 10.3
10-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 
10.8
Credit Agreement, dated November 6, 2015, 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 Union Bank, N.A., as documentation agents and LC Issuers, and Wells Fargo Securities, LLC, J.P. Morgan Securities LLC, Keybanc Capital Markets Inc., and MUFG Union Bank, N.A. as joint lead arrangers and joint book runners, and the other lenders named therein
8-K1-14465, 1-319810.111/9/2015 
10.9
Credit Agreement, dated November 6, 2015, among Idaho Power Company, 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 Union Bank, N.A., as documentation agents and LC Issuers, and Wells Fargo Securities, LLC, J.P. Morgan Securities LLC, Keybanc Capital Markets, Inc., and MUFG Union Bank, N.A. as joint lead arrangers and joint book runners, and the other lenders named therein
8-K1-14465, 1-319810.211/9/2015 
10.10
Letter Agreement, effective as of November 7, 2016, 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 Union Bank, N.A., as documentation agents and LC Issuers, and Wells Fargo Securities, LLC, J.P. Morgan Securities LLC, Keybanc Capital Markets Inc., and MUFG Union Bank, N.A. as joint lead arrangers and joint book runners, and the other lenders named therein, extending term of Credit Agreement
10-K1-14465, 1-319810.202/23/2017 
10.11
Letter Agreement, effective as of November 7, 2016, among Idaho Power Company, 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 Union Bank, N.A., as documentation agents and LC Issuers, and Wells Fargo Securities, LLC, J.P. Morgan Securities LLC, Keybanc Capital Markets, Inc., and MUFG Union Bank, N.A. as joint lead arrangers and joint book runners, and the other lenders named therein, extending term of Credit Agreement
10-K1-14465, 1-319810.212/23/2017 
10.12
Letter Agreement, effective as of November 7, 2017, 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 Union Bank, N.A., as documentation agents and LC Issuers, and Wells Fargo Securities, LLC, J.P. Morgan Securities LLC, Keybanc Capital Markets, Inc. and MUFG Union Bank, N.A. as joint lead arrangers and joint book runners, and the other lenders named therein, extending the term of the Credit Agreement
10-K1-14465, 1-319810.122/22/2018 
Table of Contents

  Incorporated by Reference 
Exhibit No.Exhibit DescriptionFormFile No.Exhibit No.DateIncluded Herewith
10.13
Letter Agreement, effective as of November 7, 2017, among Idaho Power Company, 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 Union Bank, N.A., as documentation agents and LC Issuers, and Wells Fargo Securities, LLC, J.P. Morgan Securities LLC, Keybanc Capital Markets, Inc. and MUFG Union Bank, N.A. as joint lead arrangers and joint book runners, and the other lenders named therein, extending the term of the Credit Agreement
10-K1-14465, 1-319810.132/22/2018 
10.14
Loan Agreement, dated October 1, 2006, between Sweetwater County, Wyoming and Idaho Power Company
8-K1-319810.110/10/2006 
10.15Guaranty Agreement, dated February 10, 1992, between Idaho Power Company and New York Life Insurance Company, as Note Purchaser, relating to $11,700,000 Guaranteed Notes due 2017 of Milner Dam Inc.S-333-65720*10(m)(i)7/7/1993 
10.16
Guaranty Agreement, dated April 11, 2000, between Idaho Power Company and Bank One Trust Company, N.A., as Trustee, relating to $19,885,000 American Falls Replacement Dam Refinancing Bonds of the American Falls Reservoir District, Idaho
10-Q1-319810(c)8/4/2000 
10.171
Idaho Power Company Security Plan for Senior Management Employees I, amended and restated effective December 31, 2004, and as further amended November 20, 2008
10-K1-14465, 1-319810.152/26/2009 
10.181
Amendment, dated September 19, 2012, to the Idaho Power Company Security Plan for Senior Management Employees I
10-Q1-14465, 1-319810.6211/1/2012 
10.191
Idaho Power Company Security Plan for Senior Management Employees II, as amended and restated February 8, 2017
10-K1-14465, 1-319810.312/23/2017 
10.201
Amendment to the Idaho Power Company Security Plan for Senior Management Employees II, as amended May 17, 2017
10-Q1-14465, 1-319810.18/3/2017 
10.211
Idaho Power Company Security Plan for Board of Directors - a non-qualified deferred compensation plan, as amended and restated effective July 20, 2006
10-Q1-14465, 1-319810(h)(viii)11/2/2006 
10.221
IDACORP, Inc. Non-Employee Directors Stock Compensation Plan, as amended November 16, 2017
10-K1-14465, 1-319810.222/22/2018 
10.231
Form of Officer Indemnification Agreement between IDACORP, Inc. and Officers of IDACORP, Inc. and Idaho Power Company, as amended July 20, 2006
10-Q1-14465, 1-319810(h)(xix)11/2/2006 
10.241
Form of Director Indemnification Agreement between IDACORP, Inc. and Directors of IDACORP, Inc., as amended July 20, 2006
10-Q1-14465, 1-319810(h)(xx)11/2/2006 
10.251
Form of Amended and Restated Change in Control Agreement between IDACORP, Inc. and Officers of IDACORP and Idaho Power Company (senior vice president and higher), approved November 20, 2008
10-K1-14465, 1-319810.242/26/2009 
10.261
Form of Amended and Restated Change in Control Agreement between IDACORP, Inc. and Officers of IDACORP and Idaho Power Company (below senior vice president), approved November 20, 2008
10-K1-14465, 1-319810.252/26/2009 
10.271
Form of Amended and Restated Change in Control Agreement between IDACORP, Inc. and Officers of IDACORP, Inc. and Idaho Power Company, approved March 17, 2010
8-K1-14465, 1-319810.13/24/2010 
10.281
IDACORP, Inc. and/or Idaho Power Company Executive Officers with Amended and Restated Change in Control Agreements chart, as of February 19, 2019
    X
10.291
IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan, as amended and restated February 9, 2017
10-K1-14465, 1-319810.412/23/2017 
10.301
IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan - Form of Restricted Unit Award Agreement (Time Vesting)
    X
Table of Contents

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
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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*
144
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
145
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
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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
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Incorporated by Reference
Exhibit No.Exhibit DescriptionFormFile No.Exhibit No.DateIncluded Herewith
10.311
X
10.321
IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan - Form of Performance Unit Award Agreement (Performance with Cumulative Earnings Per Share Goal)
10-K1-14465, 1-319810.322/21/2019X
10.3310.321
10-K1-14465, 1-319810.422/23/2017
10.341
IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan - Form of Performance Unit Award Agreement (Performance with Total Shareholder Return Goal) (For 2017 and 2018 Outstanding Awards)
10-K1-14465, 1-319810.432/23/2017
10.351
IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan - Form of Performance Unit Award Agreement (Performance with Cumulative Earnings Per Share Goal) (For 2017 and 2018 Outstanding Awards)
10-K1-14465, 1-319810.442/23/2017
10.361
IDACORP, Inc. Executive Incentive Plan, as amended and restated November 14, 2018
10-K1-14465, 1-319810.362/21/2019X
10.3710.331
10-K1-14465, 1-319810.322/26/2009
10.3810.341
X
10.3910.351
10-K1-14465, 1-319810.462/26/2009
10.4010.361
10-K1-14465, 1-319810.472/26/2009
10.4110.371
10-K1-14465, 1-319810.482/26/2009
10.4210.381
10-K1-14465, 1-319810.492/26/2009
10.4310.391
10-K1-14465, 1-319810.502/26/2009
10.4410.401
10-K1-14465, 1-319810.512/26/2009
10.4510.411
10-K1-14465, 1-319810.522/26/2009
10.4610.421
10-K1-14465, 1-319810.532/26/2009
10.4710.431
10-K1-14465, 1-319810.592/18/2016
10.4810.441
10-K1-14465, 1-319810.612/23/2017
10.4910.451
10-Q1-14465, 1-319810.111/2/2017
10.5010.461
10-Q1-14465, 1-319810.45/3/2018
21.1
10.471
10-Q1-14465, 1-319810.110/31/2019
10.481
10-K1-14465, 1-319810.492/18/21
21.1X
23.1X
23.2X
31.1X
31.2X
31.3X
31.4X
32.1X
32.2X
32.3X
32.4X
95.1X
101.SCHInline XBRL Taxonomy Extension Schema DocumentX
148
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Incorporated by Reference
Exhibit No.Exhibit DescriptionFormFile No.Exhibit No.DateIncluded Herewith
32.1101.CAL
IDACORP, Inc. Section 1350 CEO certification
X
32.2
IDACORP, Inc. Section 1350 CFO certification
X
32.3
Idaho Power Section 1350 CEO certification
X
32.4
Idaho Power Section 1350 CFO certification
X
95.1
Mine Safety Disclosures
X
101.INSXBRL Instance DocumentX
101.SCHXBRL Taxonomy Extension Schema DocumentX
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 Commission in paper format and as such, a hyperlink is not available.
(1) Management contract or compensatory plan or arrangement

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IDACORP, INC.
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT


CONDENSED STATEMENTS OF COMPREHENSIVE INCOME
 Year Ended December 31,
 202120202019
 (thousands of dollars)
Income:  
Equity in income of subsidiaries$245,591 $237,233 $231,534 
Investment income148 748 2,214 
Total income245,739 237,981 233,748 
Expenses:   
Operating expenses679 692 816 
Interest expense82 534 831 
Other expenses192 145 30 
Total expenses953 1,371 1,677 
Income Before Income Taxes244,786 236,610 232,071 
Income Tax Benefit(764)(807)(783)
Net Income Attributable to IDACORP, Inc.245,550 237,417 232,854 
Other comprehensive (loss) income3,318 (7,074)(13,440)
Comprehensive Income Attributable to IDACORP, Inc.$248,868 $230,343 $219,414 
The accompanying note is an integral part of these statements.
  Year Ended December 31,
  2018 2017 2016
  (thousands of dollars)
Income:    
  
Equity in income of subsidiaries $226,567
 $211,974
 $198,061
Investment income 865
 26
 3
Total income 227,432
 212,000
 198,064
Expenses:  
  
  
Operating expenses 668
 708
 716
Interest expense 713
 294
 333
Other expenses —
 30
 45
Total expenses 1,381
 1,032
 1,094
Income Before Income Taxes 226,051
 210,968
 196,970
Income Tax Benefit (750) (1,451) (1,318)
Net Income Attributable to IDACORP, Inc. 226,801
 212,419
 198,288
Other comprehensive income (loss) 8,120
 (5,990) 394
Comprehensive Income Attributable to IDACORP, Inc. $234,921
 $206,429
 $198,682
       
The accompanying note is an integral part of these statements.

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

150
  Year Ended December 31,
  2018 2017 2016
  (thousands of dollars)
Operating Activities:  
  
  
Net cash provided by operating activities $197,185
 $113,849
 $139,077
Investing Activities:  
  
  
Net cash provided by (used in) investing activities —
 —
 —
Financing Activities:  
  
  
Dividends on common stock (121,421) (113,127) (104,985)
Decrease in short-term borrowings —
 —
 (20,000)
Change in intercompany notes payable (2,867) 17,097
 2,421
Other (3,614) (3,321) (3,422)
Net cash used in financing activities (127,902) (99,351) (125,986)
Net increase in cash and cash equivalents 69,283
 14,498
 13,091
Cash and cash equivalents at beginning of year 29,617
 15,119
 2,028
Cash and cash equivalents at end of year $98,900
 $29,617
 $15,119
       
The accompanying note is an integral part of these statements.

Table of Contents

IDACORP, INC.
CONDENSED BALANCE SHEETS
 December 31,
 20212020
Assets(thousands of dollars)
Current Assets:  
Cash and cash equivalents$153,025 $106,589 
Short-term investments— 25,000 
Receivables2,050 1,604 
Other102 107 
Total current assets155,177 133,300 
Investments2,570,150 2,468,955 
Other Assets: 
Deferred income taxes5,004 23,859 
Other299 312 
Total other assets5,303 24,171 
Total assets$2,730,630 $2,626,426 
Liabilities and Shareholders’ Equity 
Current Liabilities: 
Taxes accrued$850 $2,745 
Other777 928 
Total current liabilities1,627 3,673 
Other Liabilities: 
Intercompany notes payable59,928 62,049 
Other639 724 
Total other liabilities60,567 62,773 
IDACORP, Inc. Shareholders’ Equity2,668,436 2,559,980 
Total Liabilities and Shareholders' Equity$2,730,630 $2,626,426 
The accompanying note is an integral part of these statements.
  December 31,
  2018 2017
Assets (thousands of dollars)
Current Assets:  
  
Cash and cash equivalents $98,900
 $29,617
Receivables 2,046
 52,359
Other 98
 98
Total current assets 101,044
 82,074
Investment in subsidiaries 2,294,464
 2,189,017
Other Assets:    
Deferred income taxes 17,593
 34,040
Other 277
 374
Total other assets 17,870
 34,414
Total assets $2,413,378
 $2,305,505
Liabilities and Shareholders’ Equity    
Current Liabilities:    
Accounts payable $—
 $17
Taxes accrued 8,354
 17,423
Other 899
 626
Total current liabilities 9,253
 18,066
Other Liabilities:    
Intercompany notes payable 32,929
 35,140
Other 836
 914
Total other liabilities 33,765
 36,054
IDACORP, Inc. Shareholders’ Equity 2,370,360
 2,251,385
Total Liabilities and Shareholders' Equity $2,413,378
 $2,305,505
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, 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. Therefore, these financial statements should be read in conjunction with the consolidated financial statements and related notes included in the 20182021 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 $124$149 million, $116$141 million, and $108$133 million in 2018, 2017,2021, 2020, and 2016,2019, respectively.


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IDACORP, INC. AND IDAHO POWER COMPANY
SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31,2018, 2017, 2021, 2020, and 20162019
 
    Additions    
      Charged    
  Balance at Charged (Credited)   Balance at
  Beginning to to Other   End
Classification of Year Income Accounts 
Deductions(1)
 of Year
  (thousands of dollars)
2018:          
Reserves deducted from applicable assets:          
Reserve for uncollectible accounts $2,193
 $3,363
 $392
 $3,959
 $1,989
Reserve for uncollectible notes 402
 —
 —
 —
 402
Other Reserves:          
Injuries and damages 1,469
 855
 —
 447
 1,877
2017:        
  
Reserves deducted from applicable assets:        
  
Reserve for uncollectible accounts $1,132
 $5,753
 $324
 $5,016
 $2,193
Reserve for uncollectible notes 402
 —
 —
 —
 402
Other Reserves:    
  
  
  
Injuries and damages 1,792
 687
 —
 1,010
 1,469
2016:  
  
  
  
  
Reserves deducted from applicable assets:        
  
Reserve for uncollectible accounts $1,355
 $3,917
 $263
 $4,403
 $1,132
Reserve for uncollectible notes 552
 —
 —
 150
 402
Other Reserves:  
  
  
  
  
Injuries and damages 1,874
 848
 —
 930
 1,792
           
  Additions  
   Charged  
 Balance atCharged(Credited) Balance at
 Beginningtoto OtherEnd
Classificationof YearIncomeAccounts
Deductions(1)
of Year
 (thousands of dollars)
2021:
Reserve 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 accounts$1,744 $5,239 $438 $2,158 $5,263 
Injuries and damages1,748 1,203 — 467 2,484 
2019:     
Reserve for uncollectible accounts$1,989 $2,381 $227 $2,853 $1,744 
Injuries and damages1,877 390 — 519 1,748 
(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.
Table of Contents




IDAHO POWER COMPANY
SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31, 2018, 2017, and 2016

    Additions    
      Charged    
  Balance at Charged (Credited)   Balance at
  Beginning to to Other   End
Classification of Year Income Accounts 
Deductions(1)
 of Year
  (thousands of dollars)
2018:        
  
Reserves deducted from applicable assets:          
Reserve for uncollectible accounts $2,193
 $3,363
 $392
 $3,959
 $1,989
Other Reserves:          
Injuries and damages 1,469
 855
 —
 447
 1,877
2017:        
  
Reserves deducted from applicable assets:        
  
Reserve for uncollectible accounts $1,132
 $5,753
 $324
 $5,016
 $2,193
Other Reserves:    
  
  
  
Injuries and damages 1,792
 687
 —
 1,010
 1,469
2016:        
  
Reserves deducted from applicable assets:        
  
Reserve for uncollectible accounts $1,355
 $3,917
 $263
 $4,403
 $1,132
Other Reserves:  
  
  
  
  
Injuries and damages 1,874
 848
 —
 930
 1,792
           
(1) Represents deductions from the reserves for purposes for which the reserves were created. In the case of uncollectible accounts, includes reversals of amounts previously reserved.

Table of Contents

ITEM 16. FORM 10-K SUMMARY

None.


152
Table of Contents
SIGNATURES
 
Pursuant to the requirements of Section 13 and 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 21, 201917, 2022IDACORP, INC.
DateDate
By:/s/ Darrel T. AndersonLisa A. Grow
Darrel T. AndersonLisa A. Grow
President and Chief Executive Officer

Table of Contents

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/ Robert A. TinstmanRichard J. DahlChairman of the BoardFebruary 21, 201917, 2022
Robert A. TinstmanRichard J. Dahl
/s/ Darrel T. AndersonLisa A. Grow(Principal Executive Officer)February 21, 201917, 2022
Darrel T. AndersonLisa A. Grow
President and Chief Executive Officer and Director
/s/ Steven R. Keen(Principal Financial Officer)February 21, 201917, 2022
Steven R. Keen
Senior Vice President and Chief Financial Officer
Officer, and Treasurer
/s/ Kenneth W. Petersen(Principal Accounting Officer)February 21, 201917, 2022
Kenneth W. Petersen
Vice President, Controller, and Chief Accounting Officer and Treasurer
/s/ Darrel T. AndersonDirectorFebruary 17, 2022
Darrel T. Anderson
/s/ Odette BolanoDirectorFebruary 17, 2022
Odette Bolano
/s/ Thomas CarlileDirectorFebruary 21, 201917, 2022
Thomas Carlile
/s/ Richard J. DahlDirectorFebruary 21, 2019
Richard J. Dahl
/s/ Annette G. ElgDirectorFebruary 21, 201917, 2022
Annette G. Elg
/s/ Ronald W. JibsonDirectorFebruary 21, 201917, 2022
Ronald W. Jibson
/s/ Judith A. JohansenDirectorFebruary 21, 201917, 2022
Judith A. Johansen
/s/ Dennis L. JohnsonDirectorFebruary 21, 201917, 2022
Dennis L. Johnson
/s/ Christine KingDirectorFebruary 21, 2019
Christine KingJeff C. Kinneeveauk
/s/ Richard J. NavarroDirectorFebruary 21, 201917, 2022
Richard J. Navarro
/s/ Dr. Mark T. PetersDirectorFebruary 17, 2022
Dr. Mark T. Peters
153
Table of Contents

SIGNATURES
 
Pursuant to the requirements of Section 13 and 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 21, 201917, 2022Idaho Power Company
Date
By:/s/ Darrel T. AndersonLisa A. Grow
Darrel T. AndersonLisa 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. DahlChairman of the BoardFebruary 17, 2022
Richard J. Dahl
/s/ Lisa A. Grow(Principal Executive Officer)February 17, 2022
Lisa A. Grow
President and Chief Executive Officer and Director
/s/ Steven R. Keen(Principal Financial Officer)February 17, 2022
Steven R. Keen
Senior Vice President and Chief Financial Officer
/s/ Kenneth W. Petersen(Principal Accounting Officer)February 17, 2022
Kenneth W. Petersen
Vice President, Chief Accounting Officer and Treasurer
SignatureTitleDate
/s/ Robert A. TinstmanChairman of the BoardFebruary 21, 2019
Robert A. Tinstman
/s/ Darrel T. Anderson(Principal Executive Officer)DirectorFebruary 21, 201917, 2022
Darrel T. Anderson
President and Chief Executive Officer and Director
/s/ Odette BolanoDirectorFebruary 17, 2022
/s/ Steven R. KeenOdette Bolano(Principal Financial Officer)February 21, 2019
Steven R. Keen
Senior Vice President, Chief Financial
Officer, and Treasurer
/s/ Kenneth W. Petersen(Principal Accounting Officer)February 21, 2019
Kenneth W. Petersen
Vice President, Controller, and Chief Accounting Officer
/s/ Thomas CarlileDirectorFebruary 21, 201917, 2022
Thomas Carlile
/s/ Richard J. DahlDirectorFebruary 21, 2019
Richard J. Dahl
/s/ Annette G. ElgDirectorFebruary 21, 201917, 2022
Annette G. Elg
/s/ Ronald W. JibsonDirectorFebruary 21, 201917, 2022
Ronald W. Jibson
/s/ Judith A. JohansenDirectorFebruary 21, 201917, 2022
Judith A. Johansen
/s/ Dennis L. JohnsonDirectorFebruary 21, 201917, 2022
Dennis L. Johnson
/s/ Christine KingDirectorFebruary 21, 2019
Christine KingJeff C. Kinneeveauk
/s/ Richard J. NavarroDirectorFebruary 21, 201917, 2022
Richard J. Navarro
/s/ Dr. Mark T. PetersDirectorFebruary 17, 2022
Dr. Mark T. Peters

152154