UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
| ☒ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF | |||||||
| THE SECURITIES EXCHANGE ACT OF 1934 | ||||||||
| For the fiscal year ended | December 31, 2021 | |||||||
OR
| ☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF | ||||
| THE SECURITIES EXCHANGE ACT OF 1934 | |||||
For the transition period from ................... to .................................................................
| Exact name of registrants as specified in | IRS Employer | |||||||||||||
| Commission File Number | their charters, address of principal executive offices, zip code and telephone number | Identification Number | ||||||||||||
| 1-14465 | IDACORP, Inc. | 82-0505802 | ||||||||||||
| 1-3198 | Idaho Power Company | 82-0130980 | ||||||||||||
| 1221 W. Idaho Street | ||||||||||||||
| Boise, | ID | 83702-5627 | ||||||||||||
| (208) | 388-2200 | |||||||||||||
| State of incorporation: | Idaho | |||||||||||||
Securities registered pursuant to Section 12(b) of the Securities Exchange Act of 1934
| Title of each class | Trading Symbol(s) | Name of each exchange on which registered | ||||||
| Common Stock, without par value | IDA | New York Stock Exchange | ||||||
Securities registered pursuant to Section 12(g) of the Securities Exchange Act of 1934
| 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 | ☒ | No | ☐ | Idaho Power Company | Yes | ☐ | No | ☒ | ||||||||||||||||||||
Indicate by check mark if the registrants are not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
| IDACORP, Inc. | Yes | ☐ | No | ☒ | Idaho Power Company | Yes | ☐ | No | ☒ | ||||||||||||||||||||
Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes (X) No ( )
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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 | ☒ | No | ☐ | Idaho Power Company | Yes | ☒ | No | ☐ | ||||||||||||||||||||
Indicate by check mark whether the registrants are large accelerated filers, accelerated filers, non-accelerated filers, smaller reporting companies, or emerging growth companies. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.
IDACORP, Inc.:
Large accelerated filer X Accelerated filer __ Non-accelerated filer __
Smaller reporting company ☐
Emerging growth company ☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange
Act. __
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 Company | Yes | ☒ | No | ☐ | ||||||||||||||||||||
Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Act).
| IDACORP, Inc. | Yes | ☐ | No | ☒ | Idaho Power Company | Yes | ☐ | No | ☒ | ||||||||||||||||||||
Aggregate market value of voting and non-voting common stock held by non-affiliates (June 30, 2021):
| IDACORP, Inc.: | $ | 4,876,126,808 | Idaho Power Company: | None | ||||||||||
| Number of shares of common stock outstanding as of February 11, 2022: | ||||||||
| IDACORP, Inc.: | 50,523,810 | |||||||
| Idaho Power Company: | 39,150,812 | , all held by IDACORP, Inc. | ||||||
| Documents Incorporated by Reference: | |||||
| Part III, Items 10 - 14 | Portions of IDACORP, Inc.’s definitive proxy statement to be filed pursuant to Regulation 14A for the 2022 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 | ||||||||
| Page | ||||||||
| Commonly Used Terms | ||||||||
| Cautionary Note Regarding Forward-Looking Statements | ||||||||
| Part I | ||||||||
| Item 1 | Business | |||||||
| Information about our Executive Officers | ||||||||
| Item 1A | Risk Factors | |||||||
| Item 1B | Unresolved Staff Comments | |||||||
| Item 2 | Properties | |||||||
| Item 3 | Legal Proceedings | |||||||
| Item 4 | Mine Safety Disclosures | |||||||
| Part II | ||||||||
| Item 5 | Market for Registrant's Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities | |||||||
| Item 6 | Reserved | |||||||
| Item 7 | Management's Discussion and Analysis of Financial Condition and Results of Operations | |||||||
| Item 7A | Quantitative and Qualitative Disclosures About Market Risk | |||||||
| Item 8 | Financial Statements | |||||||
| Item 9 | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure | |||||||
| Item 9A | Controls and Procedures | |||||||
| Item 9B | Other Information | |||||||
| Item 9C | Disclosure Regarding Foreign Jurisdiction that Prevent Inspections | |||||||
| Part III | ||||||||
| Item 10 | Directors, Executive Officers and Corporate Governance* | |||||||
| Item 11 | Executive Compensation* | |||||||
| Item 12 | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters* | |||||||
| Item 13 | Certain Relationships and Related Transactions, and Director Independence* | |||||||
| Item 14 | Principal Accountant Fees and Services* | |||||||
| Part IV | ||||||||
| Item 15 | Exhibits and Financial Statement Schedules | |||||||
| Item 16 | Form 10-K Summary | |||||||
| Signatures | ||||||||
| * 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 2022 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: | ||||||||||||||||||||
| 2021 Annual Report | - | IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2021 | kWh | - | Kilowatt-hour | |||||||||||||||
| ADITC | - | Accumulated Deferred Investment Tax Credits | LTICP | - | IDACORP 2000 Long-Term Incentive and Compensation Plan | |||||||||||||||
| AFUDC | - | Allowance for Funds Used During Construction | MATS | - | Mercury and Air Toxics Standards | |||||||||||||||
| AOCI | - | Accumulated Other Comprehensive Income | MD&A | - | Management’s Discussion and Analysis of Financial Condition and Results of Operations | |||||||||||||||
| APCU | - | Annual Power Cost Update | MMBtu | - | Million British Thermal Units | |||||||||||||||
| BCC | - | Bridger Coal Company, a joint venture of IERCo | MW | - | Megawatt | |||||||||||||||
| BLM | - | U.S. Bureau of Land Management | MWh | - | Megawatt-hour | |||||||||||||||
| CAA | - | Clean Air Act | NAAQS | - | National Ambient Air Quality Standards | |||||||||||||||
CO2 | - | Carbon Dioxide | NEPA | - | National Environmental Policy Act | |||||||||||||||
| CWA | - | Clean Water Act | NMFS | - | National Marine Fisheries Service | |||||||||||||||
| EIS | - | Environmental Impact Statement | NOAA Fisheries | - | National Oceanic and Atmospheric Administration's National Marine Fisheries Service | |||||||||||||||
| EPA | - | U.S. Environmental Protection Agency | NO2 | - | Nitrogen Dioxide | |||||||||||||||
| ESA | - | Endangered Species Act | NOx | - | Nitrogen Oxide | |||||||||||||||
| FASB | - | Financial Accounting Standards Board | O&M | - | Operations and Maintenance | |||||||||||||||
| FCA | - | Idaho Fixed Cost Adjustment | OATT | - | Open Access Transmission Tariff | |||||||||||||||
| FERC | - | Federal Energy Regulatory Commission | OPUC | - | Public Utility Commission of Oregon | |||||||||||||||
| FPA | - | Federal Power Act | PCA | - | Idaho-jurisdiction Power Cost Adjustment | |||||||||||||||
| GAAP | - | Generally Accepted Accounting Principles | PCAM | - | Oregon Power Cost Adjustment Mechanism | |||||||||||||||
| GHG | - | Greenhouse Gas | PURPA | - | Public Utility Regulatory Policies Act of 1978 | |||||||||||||||
| HCC | - | Hells Canyon Complex | REC | - | Renewable Energy Certificate | |||||||||||||||
| IDACORP | - | IDACORP, Inc., an Idaho Corporation | RH BART | - | Regional haze - best available retrofit technology | |||||||||||||||
| Idaho Power | - | Idaho Power Company, an Idaho Corporation | RPS | - | Renewable Portfolio Standard | |||||||||||||||
| Idaho ROE | - | Idaho-jurisdiction return on year-end equity | SEC | - | U.S. Securities and Exchange Commission | |||||||||||||||
| Ida-West | - | Ida-West Energy Company, a subsidiary of IDACORP, Inc. | SMSP | - | Security Plan for Senior Management Employees | |||||||||||||||
| IERCo | - | Idaho Energy Resources Co., a subsidiary of Idaho Power Company | SO2 | - | Sulfur Dioxide | |||||||||||||||
| IFS | - | IDACORP Financial Services, Inc., a subsidiary of IDACORP, Inc. | USACE | - | U.S. Army Corps of Engineers | |||||||||||||||
| IPUC | - | Idaho Public Utilities Commission | USFWS | - | U.S. Fish and Wildlife Service | |||||||||||||||
| IRP | - | Integrated Resource Plan | Western EIM | - | Energy imbalance market implemented in the western United States | |||||||||||||||
| IRS | - | U.S. Internal Revenue Service | WDEQ | - | Wyoming Department of Environmental Quality | |||||||||||||||
| Jim Bridger plant | - | Jim Bridger generating plant | WPSC | - | 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 elimination of Idaho Power's regulatory cost recovery mechanisms;
•the ongoing impacts of COVID-19 and its variants, and government mandates related to COVID-19 vaccines, masking, and testing, on the global and regional economy and on Idaho Power’s employees, customers, contractors, and suppliers, including on loads and revenues, uncollectible accounts, transmission revenues, supply chain availability, attrition of skilled workers, and other aspects of the economy and the companies’ business;
•changes in residential, commercial, and industrial growth and demographic patterns within Idaho Power’s service area, 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, supply costs, population growth or decline in Idaho Power’s service area, changes in customer demand for electricity, revenue from sales of excess power, credit quality of counterparties and suppliers, and the collection of receivables;
•the ability to obtain debt and equity financing or refinance existing debt when necessary and on favorable terms, which can be affected by factors such as credit ratings, volatility or disruptions in the financial markets, interest rate fluctuations, decisions by the Idaho or Oregon public utility commissions, and the companies’ past or projected financial performance;
•the ability to enter into financial and physical commodity hedges with creditworthy counterparties to manage price and commodity risk for fuel, power, and transmission, and the failure of any such risk management and hedging strategies to work as intended;
•changes in actuarial assumptions, changes in interest rates, increasing health care costs, and the actual and projected return on plan assets for pension and other post-retirement plans, which can affect future pension and other postretirement plan funding obligations, costs, and liabilities and the companies’ cash flows;
•the assumptions underlying the coal mine reclamation obligations at Bridger Coal Company and related funding and bonding requirements, and the remediation costs associated with planned exits from participation in Idaho Power’s co-owned coal plants;
•the ability to continue to pay dividends and achieve target-payout ratios based on financial performance, and in light of credit rating considerations, contractual covenants and restrictions, and regulatory limitations; and
•adoption of or changes in accounting policies and principles, changes in accounting estimates, and new Securities and Exchange Commission or New York Stock Exchange requirements, or new interpretations of existing requirements.
Any forward-looking statement speaks only as of the date on which such statement is made. New factors emerge from time to time and it is not possible for management to predict all such factors, nor can it assess the impact of any such factor on the business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement. IDACORP and Idaho Power disclaim any obligation to update publicly any forward-looking information, whether in response to new information, future events, or otherwise, except as required by applicable law.
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PART I
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.
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 hydropower 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 IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2021 (2021 Annual Report).
UTILITY OPERATIONS
Background
Idaho Power provided electric utility service to approximately 604,000 retail customers in southern Idaho and eastern Oregon as of December 31, 2021. Approximately 506,000 of these customers are residential. Idaho Power’s principal commercial and industrial customers are involved in food processing, electronics and general manufacturing, agriculture, health care, government, and education. Idaho Power also provides irrigation customers with electric utility service to operate irrigation pumps during the agricultural growing season. Idaho Power holds franchises, typically in the form of right-of-way arrangements, in 72 cities in Idaho and 7 cities in Oregon and holds certificates from the respective public utility regulatory authorities to serve all or a portion of 25 counties in Idaho and 3 counties in Oregon. Idaho Power's service area is shaded in the illustration on the following page and covers approximately 24,000 square miles with an estimated population of 1.3 million.
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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, hydropower project relicensing, and system reliability, among other items.
Regulatory Accounting
Idaho Power meets the requirements under accounting principles generally accepted in the United States of America (GAAP) to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation, with the impacts of rate regulation reflected in its financial statements. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant, and equipment; regulatory assets and liabilities; operating revenues; other operations and maintenance expense; depreciation expense; and income tax expense. 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 tax expense or benefit for certain income tax temporary differences and instead recognizes the tax impact currently (commonly referred to as flow-through accounting) for rate making and financial reporting. Therefore, Idaho Power's effective income tax rate is impacted as these differences arise and reverse. Idaho Power recognizes such adjustments as regulatory assets or liabilities if it is probable that the amounts will be recovered from or returned to customers in future rates.
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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 its core business, as Idaho Power's regulated utility operations are the primary driver of IDACORP's operating results. IDACORP’s strategy is focused on four areas: 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 has reviewed and affirmed IDACORP’s long-term strategy. In executing on these four strategic cornerstones, IDACORP seeks to balance the interests of shareowners, Idaho Power customers, employees, and other stakeholders. Idaho Power is committed to working for strong, sustainable financial results by continuing to provide reliable, affordable, clean energy to its customers from diversified generation resources.
Rates and Revenues
Idaho Power generates revenue primarily through the sale of electricity to retail and wholesale customers and the provision of transmission service. The prices that the IPUC, the OPUC, and the FERC authorize Idaho Power to charge for electric power and services are critical factors in determining IDACORP's and Idaho Power's results of operations and financial condition. In addition to the discussion below, for more information on Idaho Power's regulatory framework and rate regulation, 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 when the costs are incurred.
In addition to general rate case filings, ratemaking proceedings can involve charges or credits related to specific costs, programs, or activities, as well as the recovery or refund of amounts deferred or accrued under specific authorization from the IPUC or OPUC. Deferred amounts are generally collected from, and accrued amounts are generally refunded to, retail customers through the use of base rates or supplemental tariffs. Outside of base rates, three of the most significant mechanisms for recovery of costs are the power cost adjustment mechanisms, FCA mechanism, and energy efficiency riders. For more information on these mechanisms, see Note 3 – “Regulatory Matters” and Note 4 - “Revenues” to the consolidated financial statements included in this report
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. Availability of water and extreme temperatures during the agricultural growing season impact electricity sales to customers who use electricity to operate irrigation pumps. Alternative methods of generation, including customer-owned solar and other forms of distributed generation, have the potential to decrease Idaho Power sales to existing customers. Also, development of new technologies and services to help energy consumers manage energy in new ways could continue to alter demand for Idaho Power's electric energy. Approximately 95 percent of Idaho Power’s retail revenue originates from customers located in Idaho, with the remainder originating from customers located in Oregon. Idaho Power’s operations, including information on energy sales, are discussed further in Part II, Item 7 - MD&A - "Results of Operations - Utility Operations.”
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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, | ||||||||||||||||||||
| 2021 | 2020 | 2019 | ||||||||||||||||||
| 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 | |||||||||||||||||
| Industrial | 195,214 | 181,258 | 181,372 | |||||||||||||||||
| Irrigation | 168,664 | 154,791 | 135,850 | |||||||||||||||||
| Provision for sharing | (569) | — | — | |||||||||||||||||
Deferred revenue related to HCC relicensing AFUDC(2) | (8,780) | (8,780) | (8,780) | |||||||||||||||||
| Total retail revenues | 1,252,335 | 1,167,730 | 1,130,611 | |||||||||||||||||
| Wholesale energy sales | 40,839 | 33,656 | 71,198 | |||||||||||||||||
| Transmission wheeling-related revenues | 67,997 | 51,592 | 53,828 | |||||||||||||||||
| Energy efficiency program revenues | 29,920 | 42,478 | 40,128 | |||||||||||||||||
| Other revenues | 64,319 | 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)): | ||||||||||||||||||||
| Residential | 5,645 | 5,463 | 5,273 | |||||||||||||||||
| Commercial | 4,164 | 4,009 | 4,092 | |||||||||||||||||
| Industrial | 3,471 | 3,369 | 3,412 | |||||||||||||||||
| Irrigation | 2,126 | 1,987 | 1,760 | |||||||||||||||||
| Total retail energy sales | 15,406 | 14,828 | 14,537 | |||||||||||||||||
| Wholesale energy sales | 600 | 1,197 | 2,171 | |||||||||||||||||
| Energy sales bundled with renewable energy credits | 739 | 690 | 680 | |||||||||||||||||
| Total energy sales | 16,745 | 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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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.
Power Supply
Overview: Idaho Power primarily relies on company-owned hydropower, coal-fired, and gas-fired generation facilities and long-term power purchase agreements to supply the energy needed to serve customers, and 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.”
Various external and internal factors impact power supply costs; such as, weather, load demand, economic conditions, fuel costs, and availability of generation resources. Idaho Power’s annual hydropower generation varies depending on water conditions in the Snake River Basin. Drought conditions and increased peak load demand cause a greater reliance on potentially more expensive energy sources to meet load requirements. Conversely, favorable hydropower generation conditions increase production at Idaho Power’s hydropower generating facilities and reduce the need for thermal generation and wholesale market purchased power. Economic conditions, weather, supply constraints, and governmental regulations can affect the market price of natural gas and coal, which impact fuel expense and market prices for purchased power. Idaho Power's power cost adjustment mechanisms mitigate in large part the 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 3,751 megawatts (MW) on 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 Supply | Percent of Total Generation | |||||||||||||||||||||||||||||||||||||
| 2021 | 2020 | 2019 | 2021 | 2020 | 2019 | |||||||||||||||||||||||||||||||||
| (thousands of MWh) | ||||||||||||||||||||||||||||||||||||||
| Hydropower plants | 5,382 | 6,967 | 8,294 | 48 | % | 54 | % | 62 | % | |||||||||||||||||||||||||||||
| Coal-fired plants | 2,981 | 3,719 | 3,012 | 27 | % | 29 | % | 22 | % | |||||||||||||||||||||||||||||
| Natural gas-fired plants | 2,765 | 2,109 | 2,114 | 25 | % | 17 | % | 16 | % | |||||||||||||||||||||||||||||
| Total system generation | 11,128 | 12,795 | 13,420 | 100 | % | 100 | % | 100 | % | |||||||||||||||||||||||||||||
Purchased power - cogeneration and small power production | 3,040 | 3,087 | 2,983 | |||||||||||||||||||||||||||||||||||
| Purchased power - other | 3,783 | 1,985 | 2,217 | |||||||||||||||||||||||||||||||||||
| Total purchased power | 6,823 | 5,072 | 5,200 | |||||||||||||||||||||||||||||||||||
| Total power supply | 17,951 | 17,867 | 18,620 | |||||||||||||||||||||||||||||||||||
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Hydropower Generation: Idaho Power operates 17 hydropower projects located on the Snake River and its tributaries. Together, these hydropower facilities provide a total nameplate capacity of 1,799 MW and have averaged total annual generation of approximately 7.7 million MWh over the last 30 years. The amount of water available for hydropower generation depends on several factors—the amount of snowpack in the mountains upstream of Idaho Power’s hydropower facilities, upstream reservoir storage, springtime precipitation and temperatures, main river and tributary base flows, the condition of the Eastern Snake Plain Aquifer and its spring flow impact, summertime irrigation withdrawals and returns, and upstream reservoir regulation. Idaho Power actively participates in collaborative work groups focused on water management issues in the Snake River Basin, with the goal of preserving the long-term availability of water for use at Idaho Power’s hydropower projects on the Snake River.
In 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 8.3 million MWh of hydropower generation. During low water years, when stream flows into Idaho Power’s hydropower projects are reduced, Idaho Power’s hydropower generation is reduced, resulting in a greater reliance on other generation resources and wholesale power purchases. For 2022, Idaho Power estimates annual generation from its hydropower facilities will be between 5.5 million MWh and 7.5 million MWh.
Idaho Power obtains licenses for its hydropower projects from the FERC, similar to other utilities that operate nonfederal hydropower projects on qualified waterways. The licensing process includes an extensive public review process and involves numerous natural resource and environmental agencies. The licenses last from 30 to 50 years depending on the size, complexity, and cost of the project. Idaho Power is actively pursuing the FERC relicensing of the HCC, its largest hydropower generation source, and American Falls, its second largest hydropower resource. Idaho Power also has Oregon licenses for the HCC under the Oregon Hydroelectric Act. For further information on relicensing activities, see Part II, Item 7 – MD&A – "Regulatory Matters – Relicensing of Hydropower Projects.”
Idaho Power is subject to the provisions of the FPA as a “public utility” and as a “licensee” by virtue of its hydropower operations. As a licensee under Part I of the FPA, Idaho Power and its licensed hydropower projects are subject to conditions described in the FPA and related FERC regulations. These conditions and regulations include, among other items, provisions relating to condemnation of a project upon payment of just compensation, amortization of project investment from excess project earnings, and possible takeover of a project after expiration of its license upon payment of net investment and severance damages.
Coal-Fired Generation: Idaho Power co-owns the following coal-fired power plants in operation:
•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.
BCC supplies coal to the Jim Bridger power plant. IERCo, a wholly-owned subsidiary of Idaho Power, owns a one-third interest in BCC and PacifiCorp owns a two-third interest in BCC and is the operator of the Bridger Coal Mine. The mine operates under a long-term sales agreement that provides for delivery of coal through 2024. Idaho Power believes that BCC has sufficient reserves to provide coal deliveries for at least the term of the sales agreement. Idaho Power also has a coal supply contract providing for annual deliveries of coal through April 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. Idaho Power expects to meet 2022 and future fuel requirements through existing inventory and new or existing coal supply contracts. Idaho Power has an established process approved by the IPUC and OPUC for recovery of non-fuel costs related to Idaho Power’s plan to end its participation in coal-fired operations at the North Valmy plant. Idaho Power ended its participation in unit 1 of the North Valmy plant in December 2019, as planned, and plans to end its participation in unit 2 no later than the end of 2025.
In October 2020, Idaho Power and co-owner Portland General Electric ceased coal-fired operations at their Boardman power plant, as planned.
Natural Gas-fired Generation: Idaho Power owns and operates the Langley Gulch natural gas-fired combined-cycle combustion turbine power plant and the Danskin and Bennett Mountain natural gas-fired simple-cycle combustion turbine power plants. All three plants are located in Idaho.
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.
As of December 31, 2021, Idaho Power had approximately 10.6 million MMBtu of natural gas financially hedged for physical delivery, primarily for the operational dispatch of the Langley Gulch plant through 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 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 guidelines, and unit availability. Depending on availability of excess power or generation capacity, pricing, and opportunities in the markets, Idaho Power also sells power in the wholesale markets. During 2021 and 2020, Idaho Power purchased 3.2 million MWh and 1.4 million MWh, respectively, of power through wholesale market purchases at an average cost of $40.65 per MWh and $27.91 per MWh, respectively. During 2021 and 2020, Idaho Power sold 0.6 million MWh and 1.2 million MWh of power in wholesale market sales, respectively, with an average price of $68.07 per MWh and $28.12 per MWh, respectively.
Idaho Power has two firm multi-year wholesale purchased power contracts to address increased demand during summer months. These agreements total approximately 150 MW per hour during peak summer periods through 2024.
Long-term Power Purchase and Exchange Arrangements: In addition to its wholesale market purchases, Idaho Power has 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 hydropower project in southern Idaho in exchange for energy from Idaho Power's system or power purchased at the Mid-Columbia trading hub. The contract term ends in 2025.
•Raft River Energy I, LLC - for up to 13 MW (estimated average annual output) from its Raft River Geothermal Power Plant Unit #1 located in southern Idaho. The contract term ends in 2033.
•Jackpot Holdings LLC - a 20-year power purchase agreement to purchase the output from a planned 120-MW solar facility, with a scheduled in-service date in late 2022.
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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, 2021, Idaho Power had contracts with on-line PURPA qualifying facilities with a total of 1,137 MW of nameplate generation capacity, with an additional 75 MW nameplate capacity of projects projected to be on-line through 2024. The energy sales agreements for these qualifying facilities have original contract terms ranging from one to 35 years. The expense and volume of purchases from PURPA qualifying facilities during the last three years is included in the following table:
| Year Ended December 31, | ||||||||||||||||||||
| 2021 | 2020 | 2019 | ||||||||||||||||||
| PURPA contracts expense (in thousands) | $ | 199,517 | $ | 194,380 | $ | 187,344 | ||||||||||||||
| MWh purchased under PURPA contracts (in thousands) | 3,040 | 3,087 | 2,983 | |||||||||||||||||
| Average cost per MWh from PURPA contracts | $ | 65.63 | $ | 62.97 | $ | 62.80 | ||||||||||||||
Pursuant to the requirements of PURPA, the IPUC and OPUC have each issued orders and rules regulating Idaho Power’s purchase of power from qualifying facilities that meet the requirements 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, subject to some exceptions such as adverse impacts on system reliability.
•The Idaho jurisdictional portion of the costs associated with PURPA contracts is fully recovered through base rates and the Idaho-jurisdiction power cost adjustment (PCA) mechanism, and the Oregon jurisdictional portion is recovered through base rates and an Oregon power cost adjustment mechanism. Thus, the primary impact of high power purchase costs under PURPA contracts is on customer rates.
•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 energy 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 using an avoided cost methodology based on 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 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 using an avoided cost methodology based on OPUC regulations.
Participation in Western Energy Imbalance Market: Idaho Power participates in an energy imbalance market in the western United States (Western EIM) under which the participating parties enable their systems to interact for automated intra-hour economic dispatch of generation from committed resources to serve loads. The Western EIM is intended to reduce the power supply costs to serve customers through more efficient dispatch of a larger and more diverse pool of resources, to integrate intermittent power from renewable generation sources more effectively, and to enhance reliability. Participation in the Western EIM is voluntary and available to all balancing authorities in the western United States.
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 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 project is a proposed 300-mile, high-voltage transmission line between a station near Boardman, Oregon and the Hemingway station near Boise, Idaho. The Gateway West project is a proposed 1,000-mile, high-voltage transmission line 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 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 transmission resource options, and identifies potential near-term, mid-term, and long-term actions. The four primary goals of the IRP are to:
•identify sufficient resources to reliably serve the growing demand for energy within Idaho Power's service area throughout the 20-year planning period;
•ensure the selected resource portfolio balances cost and risk, while including environmental considerations;
•give balanced treatment to supply-side and demand-side measures; and
•involve the public in the planning process in a meaningful way.
During the time between IRP filings, the public and regulatory oversight of the activities identified in the IRP allows for discussion and adjustment of the IRP as warranted. Idaho Power makes periodic adjustments and corrections to the resource plan to reflect economic conditions, anticipated resource development, changes in technology, and regulatory requirements.
The load forecast assumptions Idaho Power used in its 2021 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 Forecasted Annual Growth Rate | 20-Year Forecasted Annual Growth Rate | |||||||||||||||||||
| Retail Sales (Billed MWh) | Annual Peak (Peak Demand) | Retail Sales (Billed MWh) | Annual Peak (Peak Demand) | |||||||||||||||||
| 2021 IRP | 2.6% | 2.1% | 1.4% | 1.4% | ||||||||||||||||
| 2019 IRP | 1.3% | 1.4% | 1.0% | 1.2% | ||||||||||||||||
| 2017 IRP | 1.1% | 1.6% | 0.9% | 1.4% | ||||||||||||||||
Idaho Power's 2021 IRP identified a preferred resource portfolio and action plan, which included the addition of a 120-MW solar resource in late 2022, the conversion from coal to natural gas of two units at the Jim Bridger plant in 2024, the end to Idaho Power's participation in coal-fired operations at the North Valmy plant unit 2 in 2025, the completion of the Boardman-to-Hemingway transmission line in 2026, and an end to Idaho Power's participation in the remaining two coal-fired units at the Jim Bridger plant by the end of 2028. The 2021 IRP preferred resource portfolio and action plan also includes a need to acquire significant generation and storage resources to meet energy and capacity needs. Including the resources noted above, over the next 20 years the IRP plans for the addition of 1,685 MW of storage capacity, 1,405 MW of solar capacity, 700 MW of wind capacity, 500 MW of transmission capacity, and 400 MW of capacity from demand response. As noted in the 2021 IRP, there is uncertainty surrounding the resource sufficiency estimates and project completion dates, including uncertainty around the timing and extent of third-party development of renewable resources, fuel commodity prices, 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 uncertainties, as 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 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 24 programs. The energy efficiency programs target energy savings across the entire year, while the demand response programs target system demand reduction in the summer at times of peak loads. The programs are offered to all customer segments and emphasize the wise use of energy, especially during periods of high demand. This energy and demand reduction can reduce or delay the need for new generation and transmission infrastructure. Idaho Power’s programs include:
•financial incentives for irrigation customers for either improving the energy efficiency of an irrigation system or installing new energy efficient systems;
•energy efficiency programs for new and existing homes including electric heating, ventilation and cooling equipment, as well as energy efficient building techniques, air duct sealing, and energy efficient lighting;
•incentives to industrial and commercial customers for acquiring energy efficient equipment, and using energy efficiency techniques for operational and management processes;
•demand response programs to reduce peak summer demand through the voluntary cycling of central air conditioners for residential customers, interruption of irrigation pumps, and reduction of commercial and industrial demand through actions taken by business owners and operators; and
•participation in the Northwest Energy Efficiency Alliance, which supports market transformation efforts across the region.
In 2021, Idaho Power’s energy efficiency programs reduced energy usage by approximately 138,000 MWh compared with 195,000 MWh in 2020. For 2021, Idaho Power had a demand response available capacity of approximately 379 MW. In 2021, 2020, and 2019, Idaho Power expended approximately $38 million, $51 million, and $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 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 the 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 release annual ESG reports and the most current report is located on Idaho Power’s website, together with other information on ESG issues relevant to Idaho Power, including short-, medium-, and long-term carbon dioxide (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 ESG reports, CDP filing, and related website content are not incorporated by reference into this 2021 Annual Report. IDACORP’s and Idaho Power’s ESG initiatives include:
•establishing responsible management goals and long-term strategies related to the companies’ impact on the environment; such as
◦the "Clean Today, 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. In 2017 and 2018, the IPUC and OPUC approved settlement stipulations allowing accelerated depreciation and cost recovery for the North Valmy plant in connection with Idaho Power's plan to end its participation in the operation of units 1 and 2. Idaho Power ended its participation in the operation of unit 1 in December 2019, as planned, and plans to end its participation in unit 2 no later than the end of 2025. In October 2020, Idaho Power and co-owner Portland General Electric ceased coal-fired operations at 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 end-of-year 2030. In September 2021, the co-owner and operator of the Jim Bridger plant submitted its integrated resource plan to the IPUC that contemplates ceasing coal-fired generation in units 1 and 2 in 2023 and converting those units to natural gas generation by 2024. The status of Idaho Power's application is described more fully in Part II, Item 7 – MD&A – "Regulatory Matters."
As of the date of 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 further Snake River shading and in-stream river enhancement projects. Idaho Power also plans for the social and economic impacts of climate change by furthering its carbon emissions intensity reduction goal, continuing efforts to achieve its path away from coal generation, increasing the integration of renewable energy, and enhancing outage communication efforts.
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Additionally, to plan for the potential regulatory impacts of climate change, Idaho Power emphasizes climate-related impacts in planning efforts, plans and 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.
Environmental Regulation and Costs
Idaho Power's activities are subject to a broad range of federal, state, regional, and local laws and regulations designed to protect, restore, and enhance the quality of the environment. Environmental regulation impacts Idaho Power’s operations due to the cost of installation and operation of equipment and facilities required for compliance with environmental regulations, the modification of system operations to accommodate environmental regulations, and the cost of acquiring and complying with permits and licenses. In addition to generally applicable regulations, Idaho Power's jointly-owned coal-fired power plants, natural gas combustion turbine power plants, and hydropower generating plants are subject to a broad range of environmental requirements, including those related to air and water quality, waste materials, and endangered species. For a more detailed discussion of these and other environmental issues, refer to Part II - Item 7 - MD&A - "Environmental Matters" in this report.
Environmental Expenditures: Idaho Power’s environmental compliance expenditures will remain significant for the foreseeable future, particularly given the volume of existing and proposed regulations at the federal level. Idaho Power estimates its environmental expenditures, based upon present environmental laws and regulations, will be as follows for the periods indicated, excluding AFUDC (in millions of dollars):
| 2022 | 2023-2024 | |||||||||||||
| Capital expenditures: | ||||||||||||||
| License compliance and relicensing efforts at hydropower facilities | $ | 21 | $ | 68 | ||||||||||
| Investments in equipment and facilities at thermal plants | 10 | 11 | ||||||||||||
| Total capital expenditures | $ | 31 | $ | 79 | ||||||||||
| Operating expenses: | ||||||||||||||
| Operating costs for environmental facilities - hydropower | $ | 21 | $ | 43 | ||||||||||
| Operating costs for environmental facilities - thermal | 10 | 21 | ||||||||||||
| 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 "Our Commitment to Each Other" initiative on its website, which promotes an inclusive company environment as follows:
At Idaho Power, we are committed to an inclusive environment where we are all valued, respected and given equal consideration for our contributions. We believe that to be successful as a company we must be able to innovate and adapt, which only happens when we seek out and value diverse backgrounds, opinions and perspectives. Our collaborative environment thrives when we are engaged, feel we belong and are empowered to do our best work. We are a stronger company when we stand together and embrace our differences.
As of December 31, 2021, 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. At December 31, 2021, the unamortized amount of IFS’s portfolio was approximately $35 million ($118 million in gross tax credit investments, net of $83 million of accumulated amortization). IFS generated tax credits of $6.2 million in 2021, $5.3 million in 2020, and $2.9 million in 2019. In 2021 and 2019, IFS received distributions related to fully-amortized real estate tax credit investments that reduced IDACORP's income tax expense by $1.0 million and $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 hydropower projects that have a total nameplate capacity of 44 MW. Four of the projects are located in Idaho and five are in northern California. All nine projects are “qualifying facilities” under PURPA. Idaho Power purchased all of the power generated by Ida-West’s four Idaho hydropower projects at a cost of approximately $8 million in 2021 and $9 million in both 2020 and 2019.
INFORMATION ABOUT OUR EXECUTIVE OFFICERS
The names, ages, and positions of the executive officers of IDACORP and Idaho Power are listed below (in alphabetical order), along with their business experience during at least the past five years. There are no family relationships among these officers, nor is there any arrangement or understanding between any officer and any other person pursuant to which the officer was appointed.
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RYAN N. ADELMAN, 47
•Vice President of Power Supply of Idaho Power Company, August 2020 - present
•Vice President of Transmission & Distribution, Engineering and Construction of Idaho Power Company, October 2019 - August 2020
•Regional Manager for the Southeast Region of Idaho Power Company, January 2018 - October 2019
•Transmission & Distribution Projects Senior Manager of Idaho Power Company, January 2015 - December 2017
BRIAN R. BUCKHAM, 43*
•Senior Vice President and General Counsel of IDACORP, Inc. and Idaho Power Company, February 2017 - present
•Vice President and General Counsel of IDACORP, Inc. and Idaho Power Company, April 2016 - February 2017
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, June 2020 - present
•President of Idaho Power Company, October 2019 - June 2020
•Senior Vice President and Chief Operating Officer of Idaho Power Company, April 2016 - October 2019
JAMES BO D. HANCHEY, 46
•Vice President of Customer Operations and Chief Safety Officer of Idaho Power Company, October 2019 - present
•Customer Service Senior Manager of Idaho Power Company, February 2018 - October 2019
•Regional Manager of Southern Region of Idaho Power Company, May 2014 - February 2018
STEVEN R. KEEN, 61*
•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 - March 2020
JEFFREY L. MALMEN, 54
•Senior Vice President of Public Affairs of IDACORP, Inc. and Idaho Power Company, April 2016 - present
KEN W. PETERSEN, 58
•Vice President, Chief Accounting Officer and Treasurer of IDACORP, Inc. and Idaho Power Company, March 2020 - present
•Vice President, Controller and Chief Accounting Officer of IDACORP, Inc. and Idaho Power Company, January 2014 - March 2020
ADAM J. RICHINS, 43
•Senior Vice President and Chief Operating Officer of Idaho Power Company, October 2019 - present
•Vice President of Customer Operations and Business Development of Idaho Power Company, March 2017 - October 2019
•General Manager of Customer Operations, Engineering and Construction, January 2014 - February 2017
*As previously reported to the SEC on Form 8-K on November 19, 2021, Mr. Buckham will succeed Mr. Keen as Chief Financial Officer of IDACORP, Inc. and Idaho Power, and 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
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 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 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 expects to incur increasing costs, which is likely to occur before the IPUC, OPUC, or FERC approve the recovery of those costs, such as construction costs for new facilities and transmission resources, changes in the long-term cost-effectiveness or changes to the operating conditions of Idaho Power's assets that could result in early retirements of utility facilities, the costs of compliance with legislative and regulatory requirements, increased funding levels of Idaho Power's defined benefit pension plan, and the costs of damage from fires, climate change and weather-related events, and natural disasters. 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.
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. In the past, Idaho Power has been denied recovery, or required to defer recovery pending the next general rate case, including denials or deferrals related to capital expenditures for long-term project expenses. Adverse outcomes in regulatory proceedings, or significant regulatory lag, may cause Idaho Power to incur increased or unrecovered project costs or result in cancellation of projects, or to record an impairment of its assets or otherwise adversely affect cash flows and earnings. This may also result in lower credit ratings, reduced access to capital, higher financing costs, and reductions or delays in planned capital expenditures.
For additional information relating to Idaho Power's state and federal regulatory framework and regulatory matters, see Part I - Item 1 - "Business - Utility Operations," Part II - Item 7 - "Management’s Discussion and Analysis of Financial Condition and
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Results of Operations - Regulatory Matters," and Note 3 - "Regulatory Matters" to the consolidated financial statements of Part II - Item 8 in this report.
Idaho Power's regulatory cost recovery mechanisms may not function as intended and are subject to change or elimination, which may adversely affect IDACORP's and Idaho Power's financial condition and results of operations. Idaho Power has power cost adjustment mechanisms in its Idaho and Oregon jurisdictions and a fixed cost 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 hydropower 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, 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 that allows Idaho Power to charge Idaho residential and small commercial customers when it recovers less than the base level of fixed costs per customer that the IPUC authorized for recovery in the most recent general rate case. 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. 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 1,042 kilowatt-hour (kWh) in 2011 to 945 kWh in 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 to modify or eliminate 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 unanticipated changes in loads exceed the incremental revenue received from the sales to the new customers, and Idaho Power is unable to secure timely and full rate relief to recover those increased costs, the resulting imbalance could have an adverse effect on IDACORP's and Idaho Power's financial condition, results of operations, and cash flows.
Changes in weather conditions, severe weather, and the impacts of climate change can adversely affect IDACORP's and Idaho Power's operating results and cause them to fluctuate seasonally. Idaho Power's electric power sales are seasonal, with demand in Idaho Power's service area peaking during the hot summer months, with a secondary peak during the cold winter months. Electric power demands by irrigation customers in Idaho Power's service area, which are impacted by temperatures and the timing and amount of precipitation, can also create significant seasonal changes in usage. Seasonality of revenues may be further impacted by Idaho Power's tiered rate structure, under which rates charged to customers are often higher during higher-load periods, such as hot summers and cold winters. Market prices for power also often increase significantly during these peak periods, at times when Idaho Power is required to purchase power in the wholesale markets to meet customer demand. While Idaho Power has regulatory mechanisms to help mitigate the impact of weather on power supply costs, there is no assurance that it will continue to receive such regulatory protection in the future. By contrast, when temperatures are relatively mild or where precipitation supplants irrigation systems, loads are often lower as customers are not using electricity for heating and air conditioning or irrigation purposes. Thus, weather conditions and the timing and extent of precipitation can cause IDACORP's and Idaho Power's results of operations and financial condition to fluctuate seasonally, quarterly, and from year to year.
Climate change could also have significant physical effects in Idaho Power’s service area, such as increased frequency and severity of storms, lightning, high winds, icing events, droughts, heat waves, fires, floods, snow loading, and other extreme weather events. These extreme weather events and their associated impacts could damage transmission, distribution, and generation facilities, causing service interruptions and extended or mass outages, increasing costs, and limiting Idaho Power's ability to meet customer energy demand. Sustained drought conditions or decreased snow pack due to reduced precipitation or higher temperatures are likely to decrease power generation from hydropower plants.
Idaho Power's customers' energy needs vary with weather and to the extent weather conditions are affected by climate change, customers' energy use could increase or decrease. Increased energy use due to weather changes may require Idaho Power to invest in generating assets and transmission and distribution infrastructure, while decreased energy use due to weather changes may result in decreased revenues. Extreme weather conditions creating high energy demand may raise wholesale electricity prices for power that Idaho Power purchases to serve customers, increasing the cost of energy Idaho Power provides to its customers, and at the same time can increase the revenues Idaho Power receives for wholesale market sales of excess generation during regional extreme weather events. Variations in hydropower generation that increase Idaho Power's reliance on market purchases may lead to more costly power supply sources for its customers and reduce benefits from selling surplus hydropower in the wholesale market. The price of power in the wholesale energy markets tends to be higher during periods of high regional demand that tends to occur with weather extremes, which may cause Idaho Power to purchase power in the wholesale market during peak price periods, increasing power supply costs. Idaho Power has in place mechanisms to help mitigate the effects of energy market price volatility, but there is no assurance these mechanisms will continue to be in place or function as intended.
The costs of repairing and replacing infrastructure or liability for personal injury, loss of life, and property damage from utility equipment that fails, including as a result of significant weather and weather-related events and the increasing threat of fires, may not be covered in full by insurance. Costs incurred in connection with such events might also not be recovered through customer rates if the costs incurred are greater than those allowed for recovery by regulators.
In addition, state and federal legislation and regulations have been proposed in recent years and may be implemented in the future, intended to limit the severity and impact of climate change. Proposals have included imposing mandatory reductions in GHG emissions, which could increase Idaho Power’s power supply and compliance costs or require generation facilities to be retired early, resulting in potential stranded costs and write-downs or write-offs if Idaho Power is unable to fully recover investments in such facilities. If financial markets increasingly view climate change or GHG emissions as a financial or investment risk for electric utilities, it could negatively affect IDACORP's and Idaho Power's ability to access debt and equity
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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 Discussion and Analysis of Financial Condition and Results of Operations - Environmental Matters” in this report.
New advances in power generation, energy efficiency, alternative energy sources, or other technologies that impact the power utility industry could decrease customer energy demand and revenues, which could have implications for generation and system planning. Advances in technology and changes in customer demand and preferences in the electric utility industry have encouraged the development of new technologies for power generation, renewable energy, energy storage, customer-owned generation, and energy efficiency. In particular, in recent years the net cost of solar and wind generation and storage technology has decreased significantly, and there are federal and state regulations, laws, and other incentives in place to help further reduce the net cost of solar and wind facilities. There is potential that customer-owned solar power generation systems, could become sufficiently cost-effective and efficient that an increasing number of Idaho Power's customers choose to install such systems on their homes or businesses, which in turn could require changes in the way Idaho Power builds and manages its distribution systems and substantial grid infrastructure costs, and at the same time reduce the demand for and sale of energy. Additionally, considerable emphasis has been placed on energy efficiency, such as LED lighting and high-efficiency appliances. Energy efficiency programs, including programs sponsored by Idaho Power under a directive from state regulatory commissions, are designed to reduce energy use and demand. The introduction of new technologies could pose risks in the form of reduced sales and new business models for energy services. These changes in technology could also alter the channels through which customers buy or utilize energy, including the potential formation of community-based, cooperative ownership or municipal structures, which could reduce Idaho Power's revenues or impact Idaho Power's expenses. A reduction in load, however, would not necessarily reduce Idaho Power's need for ongoing investments in its infrastructure to reliably serve its customers. If Idaho Power is unable to adjust its rate design or maintain adequate regulatory mechanisms allowing for timely cost recovery, declining usage from customer-owned generation sources and energy efficiency could result in under-recovery of Idaho Power's costs and investment in infrastructure, and reduce revenues, which would impact IDACORP's and Idaho Power's financial condition and results of operations.
Acts or threats of terrorism, acts of war, social unrest, cyber or physical security attacks, and other malicious acts of individuals or groups seeking to disrupt Idaho Power's operations or the electric power grid or compromise data could adversely impact IDACORP's and Idaho Power's business, financial condition, and results of operations. Idaho Power operates in an industry that requires the continuous use and operation of sophisticated information technology and increasingly complex operational technology systems and network infrastructure. Idaho Power's generation and transmission facilities and its grid operations are potential targets for terrorist acts and threats, acts of war, social unrest, cyber and physical security attacks, and other disruptive activities of individuals or groups, including by nation states or nation state-sponsored groups. There have been cyber and physical attacks within the energy industry on energy infrastructure such as electric substations and 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 be subject to, attempts to gain unauthorized access to systems and confidential information, or to disrupt operations. As noted by the U.S. Department of Homeland Security, the utility industry is continuing to experience an increase in the frequency and sophistication of cybersecurity incidents.
Some of Idaho Power's facilities are deemed "critical infrastructure" under federal standards, in that incapacity or destruction of the facilities could have a debilitating impact on security, reliability or operability of the bulk electric power system, national economic security, and public health and safety. The fact that infrastructure facilities, such as power generation facilities and electric transmission or distribution facilities, are direct targets of, or potential indirect casualties of, an act of terror or cyber or physical attack (whether originating internal to Idaho Power or externally), may affect Idaho Power's operations by limiting the ability to generate, purchase, or transmit power. Idaho Power's electric transmission systems are part of an interconnected regional grid, and therefore, it faces the risk of causing or being subject to a long-term power outage due to grid disturbances or disruptions on a neighboring interconnected grid system. Cyber and physical threats and attacks can have cascading impacts that unfold with increasing speed across networks, information systems, and other technologies. Network, information systems, and technology-related events, including those caused by IDACORP or Idaho Power through process breakdowns, human error, security architecture or design vulnerabilities, or by third parties through cyber or physical security attacks, could result in a degradation or disruption in the energy grid and the services of the companies, as well as the ability to record, process, and report customer, business, and financial information. Physical or cyber attacks against key suppliers or service providers could have a similar effect on Idaho Power.
Idaho Power's business operations require the continuous availability of information technology systems and network infrastructure, and in the normal course of business, Idaho Power or its vendors collect and store sensitive and confidential customer and employee information and proprietary information of Idaho Power. Idaho Power’s technology systems are
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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. Despite the steps Idaho Power may take to detect, mitigate, or eliminate threats and respond to security incidents, the techniques used by those who seek to obtain unauthorized access, and possibly disable or sabotage systems or abscond with information and data, change frequently and Idaho Power may not be able to protect against all such actions. Idaho Power actively monitors developments in the area of cybersecurity and is involved in various related government and industry groups, and the company’s board receives security updates at least quarterly. Although Idaho Power continues to make investments in its cybersecurity program, including personnel, technologies, cyber insurance and training of personnel, there can be no assurance that these systems or their expected functionality will be implemented, maintained, or expanded effectively; nor can security measures completely eliminate the possibility of a cybersecurity breach. Further, the implementation of security guidelines and measures has resulted in and Idaho Power expects to continue to result in increased costs. Idaho Power maintains insurance related to many forms of cyber and physical security events; however, such insurance is subject to exclusions and may be insufficient in amount to offset any losses, costs, or damage experienced, particularly given the potential significant magnitude of a security incident like those reported broadly in the media, and further, any such insurance may become unreasonably expensive or unavailable in the future.
Terrorist attacks, acts of war, social unrest, cyber and physical security attacks, and similar incidents can also have indirect impacts by creating political, economic, social, or financial market instability, and can cause damage to or interference with Idaho Power’s operating assets, customers, or suppliers. This may result in business interruption, lost revenue, higher commodity prices, disruption in fuel supplies, lower energy consumption, and unstable commodity and financial markets, particularly with respect to electricity and natural gas, any of which may materially adversely affect Idaho Power. These events, and governmental actions in response, could result in a material decrease in revenues and increase costs to protect, repair, and insure Idaho Power's assets and operate its infrastructure, systems, and business.
Changes in capital expenditures for infrastructure and the risks associated with permitting and construction of utility infrastructure can significantly affect IDACORP's and Idaho Power's financial condition and results of operations. Idaho Power’s business is capital intensive and requires significant investments in power supply, transmission, and distribution infrastructure. A significant portion of Idaho Power’s facilities were constructed many years ago, and thus require periodic upgrades and frequent maintenance. Also, short-term and long-term anticipated increases in both the number of customers and the demand for energy require expansion and reinforcement of that infrastructure as described in Idaho Power's 2021 IRP. Idaho Power is not only in the permitting process for two high-voltage transmission line projects, but has issued requests for proposals for new capacity resources, and utility-scale battery storage, which are intended to help meet increasing customer energy demands. Idaho Power expects significant investment in capital improvements and expenditures for infrastructure projects that are subject to usual permitting and construction risks that can adversely affect project costs and the completion time. These risks include, as examples:
•the ability to timely obtain labor or materials at reasonable costs;
•defaults and delays by suppliers and contractors, including delays for specialty equipment that require significant lead times;
•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;
•the ability to obtain approval from local, state, or federal regulatory and governmental bodies and to comply with permits and land use rights, and environmental constraints; and
•delays and costs associated with disputes and litigation with third parties.
The occurrence of any of these risks could cause Idaho Power to operate at reduced capacity levels, which in turn could reduce revenues and reliability, increase expenses, or cause Idaho Power to incur penalties. If Idaho Power is unable to complete the permitting or construction of a project, or incurs costs that regulators do not deem prudent, it may be unable to recover its costs in full through rates or on a timely basis. Further, if Idaho Power is unable to secure permits or joint funding commitments to develop transmission infrastructure necessary to serve loads or if other resources become more economical, it may terminate those projects and, as alternatives, seek to develop additional generation facilities within areas where Idaho Power has available transmission capacity or pursue other more costly options to serve loads. To limit the timing-related risks of these projects, Idaho Power may enter into purchase orders and construction contracts and incur engineering and design service costs in advance of receiving necessary regulatory approvals or permits. If any of the projects are canceled for any reason, including Idaho Power's failure to receive necessary regulatory approvals or permits or because the project is no longer economical, Idaho Power could incur significant cancellation penalties under purchase orders or construction contracts. Additionally, termination of a project carries with it the potential for impairment of the associated asset if regulators deny full recovery of project costs. Thus, termination of a project could negatively affect IDACORP's and Idaho Power's financial condition and results of operations.
Demand for power during peak periods could exceed forecasted supply, resulting in deliverability risks and increased costs for 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. 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. Under the current Presidential Administration, Idaho Power expects laws, regulations, and policies relating to environmental compliance to continue to change and require IDACORP and Idaho Power and some of their customers to modify their business strategy or restrict activities and projects, potentially subjecting them to increased compliance costs. For example, in January 2021, the United States rejoined the Paris Agreement on climate change that requires commitments related to GHG emissions, among other things, and the Presidential Administration has announced ambitious clean energy initiatives. Many states and localities may continue to pursue climate policies in addition to federal mandates. The state of Oregon, for instance, has been pursuing cap-and-trade legislation for GHG emissions. Failure to comply with environmental laws and regulations, even if such non-compliance is caused by factors outside of Idaho Power's control, may result in the assessment of civil or criminal penalties or fines, or government enforcement actions. Idaho Power could also become subject to climate change lawsuits and an adverse outcome could require substantial expenditures and could possibly require payment of damages. IDACORP and Idaho Power expect federal, state, and local governmental authorities to implement various recent and expected future executive orders from the Presidential Administration and are unable to predict whether and to what extent such actions will meaningfully change existing legislative and regulatory environments relevant to the companies, or if any such changes would have a net positive or negative impact on the companies. Idaho Power is unable to estimate the costs of complying with such legislative or regulatory changes due to the uncertainties associated with the nature and implementation of the changes, and may not be able to recover the associated costs. To the extent that such changes have a negative impact on the companies or Idaho Power’s customers, including as a result of related uncertainty, these changes may materially and adversely impact IDACORP’s and Idaho Power’s business, financial condition, results of operations, and cash flows.
Changes in income tax laws and regulations, or differing interpretation or enforcement of applicable laws by the U.S. Internal Revenue Service or other taxing jurisdictions, could have a material adverse impact on IDACORP’s or Idaho Power’s financial condition and results of operations. IDACORP and Idaho Power must make judgments and interpretations about the application of the law when determining the provision for income taxes. Amounts of income tax-related assets and liabilities involve judgments and estimates of the timing and probability of recognition of income, deductions, and tax credits, which are subject to challenge by taxing authorities. These judgments may include estimates for potential outcomes regarding tax positions that may be subject to challenge by the taxing authorities. Disputes over interpretations of tax laws may be settled with the taxing authority in examination, upon appeal, or through litigation. In recent years, state regulatory mechanisms with income tax-related provisions (such as Idaho Power's May 2018 Idaho tax reform settlement stipulation approved by the IPUC), have significantly impacted IDACORP's and Idaho Power's results of operations. Due to the current Presidential Administration, IDACORP and Idaho Power expect tax reform legislation could be enacted that may increase the companies' federal and state tax rates and reporting obligations. The outcome of potential future income tax proceedings or laws, or the state public utility commissions' treatment of those outcomes, could differ materially from the amounts IDACORP and Idaho Power record prior to conclusion of those proceedings, and the difference could negatively affect IDACORP’s and Idaho Power’s earnings and cash flows. Further, in some instances, the treatment from a ratemaking perspective of any net income tax expense (including from increased tax rates) or benefit could be different than IDACORP or Idaho Power anticipate or request from applicable state regulatory commissions, which could have a negative effect on their financial condition and results of operations. In addition, Idaho Power uses the regulatory flow-through income tax accounting method as described in Note 1 - "Summary of Significant Accounting Policies" to the consolidated financial statements included in this report, and potential changes in income tax laws or interpretations may impact IDACORP's and Idaho Power's income taxes and reporting obligations differently than most other companies.
IDACORP's and Idaho Power’s businesses are subject to an extensive set of environmental laws, rules, and regulations, which could impact their operations and costs of operations, potentially rendering some generating units uneconomical to maintain or operate, and could increase the costs and alter the timing of major projects. IDACORP's and Idaho Power's operations are subject to a number of federal, state, and local environmental statutes, rules, and regulations relating to climate change, air and water quality, natural resources, endangered species and wildlife, renewable energy, and health and safety. Many of these laws and regulations are described in Part II - Item 7 - “Management’s Discussion and Analysis of Financial
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Condition and Results of Operations - Environmental Matters” in this report. These laws and regulations generally require IDACORP and Idaho Power to obtain and comply with a wide variety of environmental licenses, permits, and other approvals, including through substantial investment in pollution controls, and may be enforced by both public officials and private individuals. Some of these regulations are pending, changing, or subject to interpretation, and failure to comply may result in penalties, mandatory operational changes, and other adverse consequences, including costs associated with defending against claims by governmental authorities or private parties and complying with new operating requirements. Idaho Power devotes significant resources to environmental monitoring, pollution control equipment, and mitigation projects to comply with existing and anticipated environmental regulations. However, it is possible that federal, state and local authorities could attempt to enforce more stringent standards, stricter regulation, and more expansive application of environmental regulations.
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 utility industry is also facing increasing stakeholder scrutiny related to its environmental, social, and governance (ESG) programs. Recently, Idaho Power has seen a rise in certain stakeholders, such as investors, customers, employees, and lenders placing increasing importance on the impact and social cost of their investments. Emissions of GHGs, including, most significantly CO2, could be further restricted in the future in response to additional state and federal regulatory requirements, increased scrutiny and changing stakeholder expectations with respect to environmental and climate change programs, judicial decisions and international accords. If new emissions reduction rules were to become effective, they could result in significant additional compliance costs that would affect Idaho Power's future financial position, results of operations, and cash flows if such costs are not timely recovered through regulated rates. Moreover, the possibility exists that stricter laws, regulations, or enforcement policies could significantly increase compliance costs and the cost of any remediation that may become necessary.
In addition, some environmental regulations are currently subject to litigation and not yet final. As a result of this uncertainty, approaches to comply with the regulations, including available control technologies or other allowed compliance measures, are unpredictable and Idaho Power cannot foresee the potential impacts these regulations would have on Idaho Power's operations or financial condition. In 2019, Idaho Power announced its 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 of costs associated with environmental regulations, environmental compliance, its clean energy initiatives, plant closures, or clean-up of contamination. If there is a delay in obtaining any required environmental regulatory approval or if Idaho Power fails to obtain, maintain, or comply with any such approval, construction and/or operation of Idaho Power's generation or transmission facilities could be delayed, halted, terminated, or subjected to additional costs. For further discussion of environmental matters that may affect Idaho Power, see "Environmental Matters" in Item 7 - “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in this report.
Obligations imposed in connection with hydropower license renewals and permitting may require large capital expenditures, increase operating costs, reduce hydropower generation, and negatively affect IDACORP's or Idaho Power's results of operations and financial condition. For the last several years, Idaho Power has been engaged in an effort to renew its federal license for its largest hydropower generation source, the HCC. Relicensing and ongoing permitting requirements include an extensive public review process that involves numerous natural resource issues and environmental conditions. The existence of endangered and threatened species in the watershed may result in major operational changes to the region’s hydropower projects, which may be reflected in hydropower licenses, including for the HCC and the American Falls facility. In addition, new interpretations of existing laws and regulations could be adopted or become applicable to hydropower facilities, which could further increase required expenditures for marine life recovery and endangered species protection and reduce the amount of hydropower generation available to meet Idaho Power’s generation requirements. Idaho Power cannot predict the requirements that might be imposed during the relicensing and permitting process, the financial impact of those requirements,
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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 and permitting processes could result in Idaho Power incurring significant capital expenditures, increase operating costs (including power purchase costs), and reduce hydropower generation, which could negatively affect results of operations and financial condition.
Idaho Power could be subject to penalties, reputational harm, and operational changes if it violates mandatory reliability and security requirements, which could adversely impact IDACORP's and Idaho Power's results of operations and financial condition. As an owner and operator of a bulk power transmission system, Idaho Power is subject to mandatory reliability and security standards issued by the FERC and other regulators. The standards are based on the functions that need to be performed to ensure the bulk power system operates reliably and are guided by reliability, security, and market interface principles. Compliance with reliability standards subjects Idaho Power to higher operating costs and increased capital expenditures. Idaho Power has received in recent years notices of violations from, and regularly self-reports reliability standard compliance issues to, the FERC, the North American Electric Reliability Corporation, and the Western Electricity Coordinating Council. Potential monetary and non-monetary penalties for a violation of FERC regulations may be substantial, and in some circumstances monetary penalties may exceed $1.4 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 other 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 view the companies in a favorable light; and may cause Idaho Power to be subject to less favorable legislative and regulatory outcomes or increased regulatory oversight. The imposition of any of the foregoing on Idaho Power for its actual or alleged failure to comply with reliability and security requirements could also have a negative effect on its and IDACORP’s results of operations and financial condition.
IDACORP and Idaho Power are subject to costs and other effects of legal and regulatory proceedings, disputes, and claims. From time to time in the normal course of business, IDACORP and Idaho Power are subject to various lawsuits, regulatory proceedings, disputes, and claims that could result in adverse judgments or settlements, fines, penalties, injunctions, or other adverse consequences. These matters are subject to a number of uncertainties, and management is often unable to predict the outcome of such matters; resulting liabilities could exceed amounts currently reserved or insured against with respect to such matter. The legal costs and final resolution of matters in which IDACORP or Idaho Power are involved could have reputational impact and a short- or long-term negative effect on their financial condition and results of operations. Addressing any adverse publicity or governmental scrutiny could be time consuming and expensive, regardless of the basis of the assertions being made, and could impact Idaho Power's relationship with employees, stakeholders, and regulators. Further, the terms of resolution could require the companies to change their operational practices and procedures, which could also have a negative effect on their financial positions and results of operations.
Changes in accounting standards or rules may impact IDACORP's and Idaho Power's financial results and disclosures. The Financial Accounting Standards Board (FASB) and the SEC have made and may continue to make changes to accounting standards that impact presentation and disclosures of financial condition and results of operations. Further, new accounting orders issued by the FERC could significantly impact IDACORP's and Idaho Power's reported financial condition. IDACORP and Idaho Power do not have any control over the impact these changes may have on their financial conditions or results of operations nor the timing of such changes. Idaho Power meets the requirements under 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.
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 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.
Idaho Power’s energy risk management policy and programs relating to economically hedging commodity exposures and credit risk may not always perform as intended, and as a result, IDACORP and Idaho Power may suffer economic losses. Idaho Power enters into transactions to buy and sell power, natural gas, and transmission service, enters into transactions to hedge its positions in coal, natural gas, power, and other commodities, and enters into 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. Idaho Power is a participant in the energy markets, including the Western EIM, and engages in direct and indirect power purchase and sale transactions in connection with that participation. The Western EIM has collateral posting requirements based on established credit criteria, but there is no assurance the collateral will be sufficient to cover obligations that counterparties may owe each other in the Western EIM and any such credit losses could be socialized to all Western EIM participants, including Idaho Power. A significant failure of a participant in the Western EIM to make payments when due on its obligations could have a ripple effect on various Idaho Power counterparties in the power, gas, and derivative markets if those counterparties experience ancillary liquidity issues, and could generally result in a decline in the ability of Idaho Power’s counterparties to perform on their obligations.
The performance of pension and postretirement benefit plan investments, increasing health care costs, and other factors impacting plan costs and funding obligations could adversely affect IDACORP's and Idaho Power's financial condition and results of operations - primarily cash flows and liquidity. Idaho Power provides a noncontributory defined benefit pension plan covering most employees, as well as a defined benefit postretirement benefit plan (consisting of health care and death benefits) that covers eligible retirees. Costs of providing these benefits are based in part on the value of the plans' assets and, therefore, adverse investment performance for these assets or the failure to maintain sustained growth in pension investments over time could increase Idaho Power’s plan costs and funding requirements related to the plans. Idaho Power's self-insured costs of health care benefits for eligible employees and retirees have increased in recent years and Idaho Power believes that future legislative changes related to the provision of health care benefits and other external market conditions and factors, could cause such costs to continue to rise. As benefit costs continue to rise, there is no assurance that the IPUC and OPUC will continue to allow recovery.
The key actuarial assumptions that affect pension funding obligations are the expected long-term return on plan assets and the discount rate used in determining future benefit obligations. Idaho Power evaluates the actuarial assumptions on an annual basis, taking into account changes in market conditions, trends, and future expectations. Estimates of future investment market performance, changes in interest rates, and other factors Idaho Power and its actuary firms use to develop the actuarial assumptions are inherently uncertain, and actual results could vary significantly from the estimates. Changes in demographics, including timing of retirements or changes in life expectancy assumptions, may also increase Idaho Power's plan costs and funding requirements. Future pension funding requirements and the timing of funding payments are also subject to the impacts of changes in legislation. Depending on the timing of contributions to the plans and Idaho Power's ability to recover costs through rates, cash contributions to the plans could reduce the cash available for the companies' businesses and payment of dividends. For additional information regarding Idaho Power's funding obligations under its benefit plans, see Note 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.
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 composed of 17 hydropower generating plants located in southern Idaho and eastern Oregon, three natural gas-fired plants in southern Idaho, and interests in two coal-fired steam electric generating plants located in Wyoming and Nevada. In October 2020, Idaho Power and co-owner Portland General Electric ceased coal-fired operations at their Boardman power plant, as planned. As of December 31, 2021, the system also includes approximately 4,843 pole-miles of high-voltage transmission lines, 23 step-up transmission substations located at power plants, 21 transmission substations, 10 switching stations, 30 mixed-use transmission and distribution substations, 187 energized distribution substations (excluding mobile substations and dispatch centers), and approximately 28,570 pole-miles of distribution lines.
Idaho Power holds Federal Energy Regulatory Commission (FERC) licenses for all of its hydropower projects that are subject to federal licensing. Relicensing of Idaho Power’s hydropower projects is discussed in Part II - Item 7 - "Management’s Discussion and Analysis of Financial Condition and Results of Operations – Regulatory Matters – Relicensing of Hydropower Projects" in this report.
IDACORP's and Idaho Power's headquarters are located in Boise, Idaho. The corporate headquarters campus consists of approximately 305,741 square feet of owned office space. Excluding Idaho Power's power generation facilities and substations, Idaho Power owns an additional 1,129,222 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 and coal leases near the Jim Bridger generating plant in Wyoming from which coal is mined and supplied to the plant. Ida-West Energy Company holds 50-percent interests in nine hydropower plants that have a total nameplate capacity of 44 MW. These plants are located in Idaho and California.
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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.
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 11, 2022, there were 7,747 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 - "Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity 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 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, 2016, with beginning-of-period weighting of the peer group indices (based on market capitalization) and monthly compounding of returns.
Source: Bloomberg and EEI
| 2016 | 2017 | 2018 | 2019 | 2020 | 2021 | |||||||||||||||||||||||||||||||||
| IDACORP | $ | 100.00 | $ | 116.43 | $ | 121.74 | $ | 143.27 | $ | 132.57 | $ | 161.01 | ||||||||||||||||||||||||||
| S&P 500 | 100.00 | 121.82 | 116.47 | 153.14 | 181.30 | 233.30 | ||||||||||||||||||||||||||||||||
| EEI Electric Utilities Index | 100.00 | 111.72 | 115.82 | 145.69 | 144.00 | 168.65 | ||||||||||||||||||||||||||||||||
The foregoing performance graph and data shall not be deemed “filed” as part of this Form 10-K for purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liabilities of that section and shall not be deemed incorporated by reference into any other filing of IDACORP or Idaho Power under the Securities Act of 1933 or the Securities Exchange Act
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of 1934, except to the extent IDACORP or Idaho Power specifically incorporates it by reference into such filing.
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 hydropower 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 2021 include:
•IDACORP achieved net income growth for a fourteenth consecutive year;
•IDACORP increased its quarterly common stock dividend to $0.75 per share from $0.71 per share, as a part of a 150 percent increase in quarterly dividends approved over the last ten years. The increase keeps IDACORP within its current target payout ratio of between 60 and 70 percent of sustainable IDACORP earnings, annualizing the most recently declared quarterly dividend;
•Idaho Power's customer count grew 2.8 percent in 2021. On June 30, 2021, Idaho Power set a new all-time system peak demand of 3,751 megawatts (MW), exceeding the previous high of 3,422 MW set on July 7, 2017. The previous high from July 2017 was exceeded multiple times during the heat wave in Idaho Power's service area in June and July of 2021;
•Idaho Power continued its strong safety performance in 2021, tying its previous record for lowest number of Occupational Safety and Health Administration (OSHA) recordable incidents in Idaho Power's history. In January 2022, in recognition of Idaho Power's nontraditional approach of combining psychological safety and behavioral safety with practical application of human performance principles, the Edison Electric Institute (EEI) presented Idaho Power with the inaugural Thomas F. Farrell, II Safety Leadership and Innovation Award; and
•In December 2021, 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, and distribution operations, as of the date of this report, continues largely uninterrupted.
In March 2020, in consideration of COVID-19, Idaho Power temporarily suspended disconnections and late fees for late payment or non-payment. As approved by the IPUC in July 2020, Idaho Power resumed disconnections and accruing late fees for customers in its Idaho service area beginning in early August 2020. In recognition of the economic impact of the COVID-19 public health crisis, Idaho Power continues to carry a higher allowance for uncollectible receivables compared with historical levels. Idaho Power's allowance for estimated uncollectible receivables was $4.5 million at December 31, 2021, $4.8 million at December 31, 2020, and $1.4 million at December 31, 2019.
In 2020, the IPUC and OPUC issued orders granting Idaho Power the authority to defer unanticipated, emergency-related expenses due to COVID-19, net of any cost savings, for possible recovery through future rates. As of December 31, 2021, Idaho Power had recorded an immaterial regulatory asset for its estimate of unanticipated, emergency-related expenses, including higher bad debt expense, net of estimated savings.
In September 2021, the Presidential Administration issued an executive order announcing new U.S. Department of Labor’s OSHA requirements that all employers with more than 100 employees ensure their workforce is fully vaccinated or require any workers who remain unvaccinated to undergo weekly testing before coming to work. In January 2022, the Presidential Administration withdrew the OSHA requirements. If the requirements are reinstated or if there are new requirements imposed that are applicable to Idaho Power's workforce, vendors, or suppliers, Idaho Power is uncertain to what extent the requirements could disrupt the supply chain or result in Idaho Power losing skilled or specialized employees or limit Idaho Power’s ability to attract and retain skilled or specialized employees who are unwilling to obtain a vaccine or subject themselves to weekly testing or other new requirements. Idaho Power, based on discussions with employees, does believe that attrition of skilled workers could result from application of the mandate for COVID-19 vaccines and testing or other requirements to Idaho Power's workforce. If Idaho Power loses key portions of its skilled or specialized workforce, or significant supply chain disruptions occur, those events could adversely impact Idaho Power's ability to provide reliable service to its customers and its business and results of operations.
As of the date of this report, Idaho Power is uncertain how long the COVID-19 public health crisis will last and how significantly it will ultimately impact its business operations, results of operations, cash flows, financial condition, or capital resources. For a discussion of certain risks IDACORP and Idaho Power are confronting as a result of the public health crisis, see Part II - Item 1A - "Risk Factors" in this report.
Summary of 2021 Financial Results
The following is a summary of Idaho Power's net income, net income attributable to IDACORP, and IDACORP's earnings per diluted share for the years ended December 31, 2021, 2020, and 2019 (in thousands, except earnings per share amounts):
| Year Ended December 31, | ||||||||||||||||||||
| 2021 | 2020 | 2019 | ||||||||||||||||||
| 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 | ||||||||||||||
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The table below provides a reconciliation of net income attributable to IDACORP for the year ended December 31, 2021, from the year ended December 31, 2020 (items are in millions and are before tax unless otherwise noted):
| 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 mechanisms | 16.0 | |||||||||||||
| Usage per retail customer, net of associated power supply costs and power cost adjustment mechanisms | 13.4 | |||||||||||||
| Retail revenues per MWh, net of associated power supply costs and power cost adjustment mechanisms | (13.4) | |||||||||||||
| Transmission wheeling-related revenues | 16.4 | |||||||||||||
| 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 mechanism | 21.4 | |||||||||||||
| Provision for sharing with customers | (0.6) | |||||||||||||
| Increase in Idaho Power operating income | 20.8 | |||||||||||||
| Non-operating expense, net | (3.1) | |||||||||||||
| Income tax expense | (7.7) | |||||||||||||
| Total increase in Idaho Power net income | 10.0 | |||||||||||||
| Other IDACORP changes (net of tax) | (1.8) | |||||||||||||
| Net income attributable to IDACORP, Inc. - December 31, 2021 | $ | 245.6 | ||||||||||||
IDACORP's net income increased $8.2 million for 2021 compared with 2020, due primarily to higher net income at Idaho Power.
Idaho Power's customer growth of 2.8 percent added $16.0 million to Idaho Power's operating income compared with 2020. Higher sales volumes on a per-customer basis increased operating income by $13.4 million in 2021 compared with 2020, due mostly to warmer and drier weather in the spring and early summer that caused irrigation customers to use more energy for irrigation pumps and residential customers to use more energy for cooling in 2021 compared with 2020. The increase in usage per residential customer from the spring and early summer was mostly offset by lower usage per residential customer from August through December 2021 compared with those same months in 2020 due to milder temperatures. Also, a return to more normal economic conditions for commercial and industrial customers in 2021 compared with 2020 increased sales volumes on a per-customer basis, as 2020 was affected by negative COVID-19-related business conditions.
The net decrease in retail revenues per megawatt-hour (MWh) reduced operating income by $13.4 million in 2021 compared with 2020, primarily due to higher power supply costs. During the summer of 2021, higher wholesale energy market prices due to a heat wave in the western United States and higher energy usage by Idaho Power customers increased Idaho Power's net power supply expenses. The increase in the amount of net power supply expenses that were not deferred through Idaho Power's power cost adjustment mechanisms contributed to the negative variance in net retail revenues per MWh between the comparison periods. Also, Idaho Power decreased annual Idaho customer rates an estimated $3.9 million on January 1, 2021, and decreased annual Oregon customer rates an estimated $0.3 million on November 1, 2020, to reflect full depreciation of all Boardman power plant investments after ceasing coal-fired operations at the Boardman power plant in October 2020.
During 2021, transmission wheeling-related revenues increased $16.4 million compared with 2020, as the warmer and drier weather in the western United States in the spring and early summer, along with two new long-term wheeling agreements which began in April 2021, increased wheeling volumes. Colder winter weather in the southwest United States during the first quarter of 2021 also contributed to increased wheeling volumes in 2021 compared with 2020. In addition, Idaho Power's open access transmission tariff (OATT) rates increased approximately 10 percent during the period from October 1, 2020, to September 30, 2021, as compared with the rates in effect from October 1, 2019, to September 30, 2020. The rate increased an additional four percent on October 1, 2021.
Other O&M expenses increased $9.2 million in 2021 compared with 2020, primarily due to a return to more normal levels of purchased services and maintenance activity compared with 2020, which was affected by the COVID-19 public health crisis. Also, labor-related other O&M expenses increased slightly in 2021 compared with 2020.
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In 2021, Idaho Power recorded $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) mechanism pursuant to a settlement stipulation approved by the IPUC as described in "Regulation of Rates and Cost Recovery" below.
Non-operating expense, net, increased $3.1 million in 2021 compared with 2020, primarily due to increased costs of an Idaho Power postretirement medical plan that are not expected to recur.
The $7.7 million increase in Idaho Power income tax expense in 2021 compared with 2020 was primarily due to greater 2021 pre-tax income and other plant-related income tax return adjustments.
2022 Initiatives and Strategy
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 has reviewed and affirmed IDACORP’s long-term strategy. In executing on these four strategic cornerstones, IDACORP seeks to balance the interests of shareowners, Idaho Power customers, employees, and other stakeholders. Idaho Power is committed to working for strong, sustainable financial results by continuing to provide reliable, affordable, clean energy to its customers from diversified generation 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 prices that Idaho Power is authorized to charge for its electric and transmission service is a critical factor in determining IDACORP's and Idaho Power's results of operations and financial condition. Those rates are established by state regulatory commissions and the FERC and are intended to
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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 prudent management of expenses and investments. Idaho Power has a regulatory settlement stipulation in Idaho that includes provisions for the accelerated amortization of certain tax credits to help achieve a minimum 9.4 percent Idaho-jurisdiction return on year-end equity (Idaho ROE). The settlement stipulation also provides for the potential sharing between Idaho Power and its Idaho customers of Idaho-jurisdictional earnings in excess of 10.0 percent of Idaho ROE. The settlement stipulation has no expiration date but the minimum Idaho ROE would revert back to 95 percent of the allowed return on equity in the next general rate case. The specific terms of the settlement stipulation are described in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report. With Idaho Power’s anticipated significant infrastructure investments that are intended to help meet projected near-term capacity deficits, Idaho Power’s evaluations indicate that the appropriate time to file general rate cases in both Idaho and Oregon is approaching. The resulting expected increase in rate-base eligible assets as these projects are placed into service, along with the significant amounts of capital expenditures Idaho Power has made since its last general rate case filed in 2011, will increase and potentially accelerate Idaho Power’s need to file general rate cases. In Idaho, Idaho Power is required to file a notice of its intent to file a general rate case with the IPUC at least 60 days before filing an application for a general rate case, and Idaho Power expects the processing of a general rate case in Idaho would span at least seven months before new rates would be in effect. In Oregon, Idaho Power expects that processing of a general rate case would take approximately ten months.
•Economic Conditions and Loads: Economic conditions impact consumer demand for energy, revenues, collectability of accounts, the volume of wholesale energy sales, and the need to construct and improve infrastructure, purchase power, and implement programs to meet customer load demands. In recent years, Idaho Power has seen significant growth in the number of customers in its service area. In 2021, Idaho Power's customer count grew by 2.8 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 in June and July of 2021. Idaho Power expects its number of customers to continue to increase in the foreseeable future. Idaho Power also expects that existing and sustained growth in customers and peak demand for electricity will require Idaho Power to continue to enhance its 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 service area and impacted Idaho Power's ability to import energy from energy markets in the western United States during peak load 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 residential and small commercial customers is mitigated through the Idaho 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 hydropower facilities comprise over one-half of Idaho Power's nameplate generation capacity, precipitation levels impact the mix of Idaho Power's generation resources. When hydropower generation decreases, Idaho Power must rely on more expensive generation sources and purchased power. When favorable hydropower generating conditions exist for Idaho Power, they also may exist for other Pacific Northwest hydropower facility operators, lowering regional wholesale market prices and impacting the revenue Idaho Power receives from wholesale energy sales. Much of the adverse or favorable impact of this volatility is addressed through the Idaho and Oregon power cost adjustment mechanisms. For 2022, due to relatively low reservoir storage carryover combined with current and forecasted snowpack conditions, Idaho Power expects generation from its hydropower resources to be 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 last 30 years.
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•Mitigation of Impact of Fuel and Purchased Power Expense: In addition to hydropower generation, Idaho Power relies significantly on natural gas and coal to fuel its generation facilities and on power purchases in the wholesale markets. Fuel costs are impacted by electricity sales volumes, the terms and conditions of contracts for fuel, Idaho Power's generation capacity, the availability of hydropower generation resources, transmission capacity, energy market prices, and Idaho Power's hedging program for managing fuel costs. Purchased power costs are impacted by the terms and conditions of contracts for purchased power, the rate of expansion of alternative energy generation sources such as wind or solar energy, and wholesale energy market prices. The Idaho and Oregon power cost adjustment mechanisms mitigate in large part the potential adverse impacts to Idaho Power of fluctuations in power supply costs.
•Regulatory and Environmental Compliance Costs: Idaho Power is subject to extensive federal and state laws, policies, and regulations, as well as regulatory actions and audits by agencies and quasi-governmental agencies, including the FERC, the North American Electric Reliability Corporation, and the Western Electricity Coordinating Council. Compliance with these requirements directly influences Idaho Power's operating environment and affects Idaho Power's operating costs. Energy industry regulators may issue substantial penalties for utilities alleged to have violated reliability and critical infrastructure protection requirements. Moreover, environmental laws and regulations, in particular, may increase the cost of constructing new facilities, may increase the cost of operating generation plants, including Idaho Power's jointly-owned coal-fired generating plants, may require that Idaho Power install additional pollution control devices at existing generating plants, or may require that Idaho Power cease operating certain generation plants. Idaho Power expects to spend significant amounts on environmental compliance and controls in the next decade. Due to economic factors in part associated with the costs of compliance with environmental regulation, Idaho Power accelerated the retirement date of its jointly-owned coal-fired generating plant in Valmy, Nevada (Valmy), 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 Hydropower Projects: Because of Idaho Power's reliance on stream flow in the Snake River and its tributaries, Idaho Power participates in numerous proceedings and venues that may affect its water rights, seeking to preserve the long-term availability of its rights for its hydropower projects. Also, Idaho Power is involved in renewing its long-term federal licenses for the HCC, its largest hydropower generation source, and for American Falls, its second largest hydropower generation source. Given the number of parties involved, Idaho Power's relicensing costs have been and are expected to continue to be substantial. Idaho Power cannot currently determine the ultimate terms of, and costs associated with, any resulting long-term licenses 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.
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 2021 are compared with 2020.
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The table below presents Idaho Power’s energy sales and supply (in thousands of MWh) for the last two years.
| Year Ended December 31, | ||||||||||||||
| 2021 | 2020 | |||||||||||||
| Retail energy sales | 15,406 | 14,828 | ||||||||||||
| Wholesale energy sales | 600 | 1,197 | ||||||||||||
| Energy sales bundled with renewable energy credits | 739 | 690 | ||||||||||||
| Total energy sales | 16,745 | 16,715 | ||||||||||||
| Hydropower generation | 5,382 | 6,967 | ||||||||||||
| Coal generation | 2,981 | 3,719 | ||||||||||||
| Natural gas and other generation | 2,765 | 2,109 | ||||||||||||
| Total system generation | 11,128 | 12,795 | ||||||||||||
| Purchased power | 6,823 | 5,072 | ||||||||||||
| Line losses | (1,206) | (1,152) | ||||||||||||
| Total energy supply | 16,745 | 16,715 | ||||||||||||
For purposes of illustration, Boise, Idaho, weather-related information for the last two years is presented in the table that follows.
| Year Ended December 31, | ||||||||||||||||||||
| 2021 | 2020 | Normal(2) | ||||||||||||||||||
Heating degree-days(1) | 4,856 | 4,999 | 5,516 | |||||||||||||||||
Cooling degree-days(1) | 1,393 | 1,087 | 941 | |||||||||||||||||
| Precipitation (inches) | 12.3 | 14.5 | 11.7 | |||||||||||||||||
(1) Heating and cooling degree-days are common measures used in the utility industry to analyze the demand for electricity and indicate when a customer would use electricity for heating and air conditioning. A degree-day measures how much the average daily temperature varies from 65 degrees. Each degree above 65 degrees is counted as one cooling degree-day, and each degree below 65 degrees is counted as one heating degree-day. While Boise, Idaho weather conditions are not necessarily representative of weather conditions throughout Idaho Power's service area, the greater Boise area has the majority of Idaho Power's customers.
(2) Normal heating degree-days and cooling degree-days elements are, by convention, the arithmetic mean of the elements computed over 30 consecutive years. The annual normal amounts are the sum of the 12 monthly normal amounts. These normal amounts are computed by the National Oceanic and Atmospheric Administration.
Sales Volume and Generation: In 2021, retail sales volumes increased 4 percent compared with the prior year, primarily due to growth in the number of Idaho Power customers and warmer and drier spring and early summer weather that caused customers to use more energy for cooling and irrigation. The number of Idaho Power customers grew by 2.8 percent in 2021. Less precipitation in Idaho Power's service area during the spring and early summer of 2021 compared with the same time period in 2020 led agricultural irrigation customers to use 6 percent more energy per customer to operate irrigation pumps during 2021 compared with 2020. During 2021, usage per commercial and industrial customer was approximately 3 percent higher compared with the prior year, due to a return to more normal economic activity compared with 2020, which was affected by negative COVID-19-related business conditions. Usage per residential customer was approximately 1 percent higher in 2021 than 2020, which was primarily due to weather variations that caused residential customers to use more energy for cooling in the spring and early summer, but less energy from August through December. Cooling degree-days in Boise, Idaho were 28 percent higher during 2021 compared with 2020 and 48 percent above normal. Also, heating degree-days were 3 percent lower during 2021 compared with 2020 and 12 percent lower than normal.
Wholesale energy sales volumes decreased 0.6 million MWh, or 50 percent, during 2021 compared with 2020, as lower system generation and higher retail sales volumes led to less energy available for opportunistic market sales.
Total system generation decreased 13 percent in 2021 compared with the prior year, due primarily to lower hydropower generation and coal-fired generation, partially offset by increased natural gas generation. Hydropower generation decreased 23 percent during 2021 compared with 2020, due primarily to lower reservoir storage carryover and weaker snowpack in the Snake River Basin. Coal-fired generation also decreased 20 percent during 2021, due to mostly to economic displacement by power purchased from the energy imbalance market in the western United States (Western EIM) and to a lesser extent due to the
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October 2020 closure of the coal-fired generation plant in Boardman, Oregon. Natural gas generation increased 31 percent due mostly to the decrease in 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 two years.
| Year Ended December 31, | |||||||||||||||||
| 2021 | 2020 | ||||||||||||||||
| Retail revenues: | |||||||||||||||||
Residential (includes $34,835 and $34,409, respectively, related to the FCA(1)) | $ | 583,061 | $ | 547,404 | |||||||||||||
Commercial (includes $1,407 and $1,543, respectively, related to the FCA(1)) | 314,745 | 293,057 | |||||||||||||||
| Industrial | 195,214 | 181,258 | |||||||||||||||
| Irrigation | 168,664 | 154,791 | |||||||||||||||
| Provision for sharing | (569) | — | |||||||||||||||
Deferred revenue related to HCC relicensing AFUDC(2) | (8,780) | (8,780) | |||||||||||||||
| Total retail revenues | $ | 1,252,335 | $ | 1,167,730 | |||||||||||||
| Volume of Sales (MWh) | |||||||||||||||||
| Residential | 5,645 | 5,463 | |||||||||||||||
| Commercial | 4,164 | 4,009 | |||||||||||||||
| Industrial | 3,471 | 3,369 | |||||||||||||||
| Irrigation | 2,126 | 1,987 | |||||||||||||||
| Total retail MWh sales | 15,406 | 14,828 | |||||||||||||||
| Number of retail customers at year-end | |||||||||||||||||
| Residential | 505,774 | 491,229 | |||||||||||||||
| Commercial | 76,022 | 74,409 | |||||||||||||||
| Industrial | 125 | 126 | |||||||||||||||
| Irrigation | 21,832 | 21,594 | |||||||||||||||
| Total customers | 603,753 | 587,358 | |||||||||||||||
(1) The FCA mechanism is an alternative revenue program and does not represent revenue from contracts with customers.
(2) The IPUC allows Idaho Power to recover a portion of the allowance for funds used during construction (AFUDC) 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.
Changes in rates, changes in customer demand, and changes in FCA mechanism revenues are the primary reasons for fluctuations in retail revenues from period to period. See "Regulatory Matters" in this MD&A for a list of rate changes implemented over the last two years. The primary influences on customer demand for electricity are weather, economic conditions, and energy efficiency. Extreme temperatures increase sales to customers who use electricity for cooling and heating, while mild temperatures decrease sales. Precipitation levels and the timing of precipitation during the agricultural growing season also affect sales to customers who use electricity to operate irrigation pumps. Rates are also seasonally adjusted, providing for higher rates during summer peak load periods, and residential customer rates are tiered, providing for higher rates based on higher levels of usage. The seasonal and tiered rate structures contribute to seasonal fluctuations in revenues and earnings.
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Retail Revenues: Retail revenues increased $84.6 million in 2021 compared with 2020. The primary factors affecting retail revenues during the period were the following:
•Rates: Customer rates, excluding collections of amounts related to the power cost adjustment mechanisms, decreased retail revenues by $6.4 million in 2021 compared with 2020. Idaho Power decreased annual Idaho customer rates an estimated $3.9 million on January 1, 2021, and decreased annual Oregon customer rates an estimated $0.3 million on November 1, 2020, to reflect full depreciation of all Boardman power plant investments after ceasing coal-fired operations at the Boardman power plant in October 2020. Customer rates also include adjustments related to the PCA mechanism, which increased revenues by $42.0 million in 2021 compared with 2020. The adjustments related to the PCA mechanism in rates do not have a significant effect on operating income as a corresponding amount is recorded in expense in the same period.
•Customers: Customer growth of 2.8 percent increased retail revenues by $22.0 million in 2021 compared with 2020.
•Usage: Higher usage (on a per customer basis), in all customer classes, increased retail revenues by $27.2 million during 2021 compared with 2020. Less precipitation in Idaho Power's service area during the spring and early summer of 2021 compared with the same time period in 2020 led agricultural irrigation customers to use 6 percent more energy per customer to operate irrigation pumps during 2021. A return to more normal economic conditions in 2021 for commercial and industrial customers increased usage by both customer classes approximately 3 percent on a per-customer basis, as 2020 was affected by negative COVID-19-related business conditions. Usage per residential customer was approximately 1 percent higher than 2020, which was primarily due to weather variations that caused residential customers to use more energy at home for cooling in the spring and early summer of 2021, compared with 2020, but less energy from August through December. Cooling degree-days in Boise, Idaho were 28 percent higher during 2021 compared to 2020 and 48 percent above normal. Also, heating degree-days in that area were 3 percent lower during 2021 compared to 2020 and 12 percent lower than normal.
•Sharing: During 2021, Idaho Power recorded $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 2022. Idaho Power did not record any provision for sharing in 2020. This revenue sharing arrangement, which requires Idaho Power to share with Idaho customers a portion of Idaho-jurisdiction earnings exceeding a 10.0 percent Idaho ROE, is related to the May 2018 Idaho Tax Reform Settlement Stipulation. The May 2018 Idaho Tax Reform Settlement Stipulation is described further in "Regulatory Matters" in this MD&A and Note 3 -"Regulatory Matters" to the consolidated financial statements included in this report.
Wholesale Energy Sales: Wholesale energy sales consist primarily of long-term sales contracts, opportunity sales of surplus system energy, and sales into the energy imbalance market in the western United States, and do not include derivative transactions. The table below presents Idaho Power’s wholesale energy sales for the last two years (in thousands, except for MWh amounts).
| Year Ended December 31, | ||||||||||||||
| 2021 | 2020 | |||||||||||||
| Wholesale energy revenues | $ | 40,839 | $ | 33,656 | ||||||||||
| Wholesale MWh sold | 600 | 1,197 | ||||||||||||
| Wholesale energy revenues per MWh | $ | 68.07 | $ | 28.12 | ||||||||||
In 2021, wholesale energy revenue increased by $7.2 million, or 21 percent, compared with 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 decreased 50 percent in 2021 compared with 2020, as lower system generation and higher retail sales volumes led to less energy available for opportunistic market sales.
Transmission Wheeling-Related Revenues: Revenue related to transmission wheeling increased $16.4 million in 2021 compared with 2020, as warmer, drier spring and summer weather in the western United States, along with two new long-term wheeling agreements that began in April 2021, increased wheeling volumes. In addition, Idaho Power's OATT rates increased approximately 10 percent during the period from October 1, 2020, to September 30, 2021, as compared with the rates in effect from October 1, 2019, to September 30, 2020. Also, Idaho Power's OATT rate increased 4 percent in October 2021. Refer to "Regulatory Matters" in this MD&A for more information on Idaho Power's OATT rate.
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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, 2021, Idaho Power's energy efficiency rider balances were a $6.9 million regulatory asset in the Idaho jurisdiction and a $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.
Operating Expenses
Purchased Power: The table below presents Idaho Power’s purchased power expenses and volumes for the last two years (in thousands, except for MWh amounts).
| Year Ended December 31, | ||||||||||||||
| 2021 | 2020 | |||||||||||||
| 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 contracts | 3,040 | 3,087 | ||||||||||||
| Other purchased power | 3,783 | 1,985 | ||||||||||||
| Total MWh purchased | 6,823 | 5,072 | ||||||||||||
| Cost per MWh from PURPA contracts | $ | 65.63 | $ | 62.97 | ||||||||||
| Cost per MWh from other sources | $ | 51.33 | $ | 51.91 | ||||||||||
Weighted average - all sources | $ | 57.70 | $ | 58.64 | ||||||||||
Idaho Power is required by federal law to purchase power from some PURPA generation projects at a specified price regardless of the then-current load demand or wholesale energy market prices. The intermittent, non-dispatchable nature of most PURPA generation increases the likelihood that Idaho Power will at times be required to reduce output from its lower-cost hydropower and fossil fuel-fired generation resources and may be required to sell its excess power in the wholesale power market at a significant loss. Although it was not the case in 2021, the other purchased power cost per MWh often exceeds the wholesale energy sales revenue per MWh because Idaho Power generally needs to purchase more power during heavy load periods than during light load periods, and conversely has less energy available for wholesale energy sales during heavy load periods than light load periods. Market energy prices are typically higher during heavy load periods than during light load periods. Also, in accordance with Idaho Power's energy risk management policy, Idaho Power may purchase or sell energy several months in advance of anticipated delivery. The regional energy market price is dynamic and additional energy transactions that Idaho Power makes at current market prices may be noticeably different than the advance transaction prices. Most of the non-PURPA purchased power and substantially all of the PURPA power purchase costs are recovered through base rates and Idaho Power's power cost adjustment mechanisms.
Purchased power expense increased $96.3 million, or 32 percent, in 2021 compared with 2020. The increase was primarily due to a 91 percent increase in MWh purchased from sources other than PURPA contracts as power purchased from the Western EIM economically displaced coal-fired generation at greater volumes in 2021 compared with 2020.
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Fuel Expense: The table below presents Idaho Power’s fuel expenses and thermal generation for the last two years (in thousands, except per MWh amounts).
| Year Ended December 31, | ||||||||||||||
| 2021 | 2020 | |||||||||||||
| Expense | ||||||||||||||
| Coal | $ | 95,324 | $ | 119,678 | ||||||||||
Natural gas(1) | 85,226 | 53,062 | ||||||||||||
| Total fuel expense | $ | 180,550 | $ | 172,740 | ||||||||||
| MWh generated | ||||||||||||||
| Coal | 2,981 | 3,719 | ||||||||||||
Natural gas(1) | 2,765 | 2,109 | ||||||||||||
| Total MWh generated | 5,746 | 5,828 | ||||||||||||
| Cost per MWh - Coal | $ | 31.98 | $ | 32.18 | ||||||||||
| Cost per MWh - Natural gas | $ | 30.82 | $ | 25.16 | ||||||||||
| Weighted average, all sources | $ | 31.42 | $ | 29.64 | ||||||||||
(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 increased $7.8 million, or 5 percent, in 2021 compared with 2020, primarily due to a 31 percent increase in natural gas generation and a 22 percent increase in the average cost per natural gas MWh 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 Western EIM.
Included in fuel expense are losses and gains on settled financial gas hedges entered into in accordance with Idaho Power's energy risk management policy. In 2021, gains on financial gas hedges of $12.1 million reduced natural gas fuel expense, while in 2020, losses on financial gas hedges of $4.8 million increased natural gas fuel expense. Most of these realized hedging gains and losses are passed on to customers through the power cost adjustment mechanisms described below.
Power Cost Adjustment Mechanisms: Idaho Power's power supply costs (primarily purchased power and fuel expense, less wholesale energy sales) can vary significantly from year to year. Volatility of power supply costs arises from factors such as weather conditions, wholesale market prices, volumes of power purchased and sold in the wholesale markets, Idaho Power's hydropower and thermal generation volumes and fuel costs, generation plant availability, and retail loads. To address the volatility of power supply costs, Idaho Power's power cost adjustment mechanisms in the Idaho and Oregon jurisdictions allow Idaho Power to recover from customers, or refund to customers, most of the fluctuations in power supply costs. In the Idaho jurisdiction, the PCA includes a cost or benefit sharing ratio that allocates the deviations in net power supply expenses between customers (95 percent) and Idaho Power (5 percent), with the exception of PURPA power purchases and demand response program incentives, which are allocated 100 percent to customers. The Idaho deferral period, or PCA year, runs from April 1 through March 31. Amounts deferred during the PCA year are primarily recovered or refunded during the subsequent June 1 through May 31 period. 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 two years (in thousands).
| Year Ended December 31, | ||||||||||||||
| 2021 | 2020 | |||||||||||||
| 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) | ||||||||||
The power supply (deferrals) accruals represent the portion of the power supply cost fluctuations (deferred) accrued under the power cost adjustment mechanisms. When actual power supply costs are lower than the amount forecasted in power cost adjustment rates, most of the difference is accrued as an increase to a regulatory liability or decrease to a regulatory asset. When actual power supply costs are higher than the amount forecasted in power cost adjustment rates, most of the difference is deferred as an increase to a regulatory asset or decrease to a regulatory liability. During 2021, 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).
Other Operations and Maintenance Expenses: Other O&M expenses increased $9.2 million, or 3 percent, in 2021 compared with 2020, primarily due to a return to more normal levels of purchased services and maintenance costs compared with 2020, which was affected by the COVID-19 public health crisis. In 2020, the response to the COVID-19 public health crisis affected the availability and performance of some of Idaho Power's service providers, contractors and vendors, which resulted in lower other O&M expenses. Also, labor-related other O&M expenses increased slightly in 2021, compared with 2020.
Income Taxes
IDACORP's and Idaho Power's 2021 income tax expense increased $8.2 million and $7.7 million, respectively, when compared with 2020. The increases were primarily due to higher pre-tax earnings and other plant-related income tax return adjustments at Idaho Power. For additional information relating to IDACORP's and Idaho Power's income taxes, see Note 2 - “Income Taxes” to the consolidated financial statements included in this report.
LIQUIDITY AND CAPITAL RESOURCES
Overview
Idaho Power continues to pursue significant enhancements to its utility infrastructure in an effort to ensure an adequate supply of electricity, to provide service to new customers, and to maintain system reliability. Idaho Power's existing hydropower and thermal generation facilities also require continuing upgrades and component replacement. Cash capital expenditures, excluding AFUDC and excluding net costs of removing assets from service, were $288 million in 2021 and $299 million in 2020. Idaho Power expects an increase in capital expenditures over the next several years, with estimated total capital expenditures of up to $2.8 billion over the period from 2022 through 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 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 (Credit Facilities);
•IDACORP's shelf registration statement filed with the U.S. Securities and Exchange Commission (SEC) on May 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 17, 2019, which may be used for the issuance of first mortgage bonds and debt securities; $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.
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IDACORP and Idaho Power monitor capital markets with a view toward opportunistic debt and equity transactions, taking into account current and potential future long-term needs. As a result, IDACORP may issue debt securities or common stock, and Idaho Power may issue debt securities, if the companies believe terms available in the capital markets are favorable and that issuances would be financially prudent. Idaho Power also periodically analyzes whether partial or full early redemption of one or more existing outstanding series of first mortgage bonds is desirable, and in some cases, may refinance indebtedness with new indebtedness.
Based on planned capital expenditures and 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 existing cash, operating cash flows generated by Idaho Power's utility business, availability under existing Credit Facilities, and access to commercial paper and long-term debt markets.
IDACORP and Idaho Power seek to maintain capital structures of approximately 50 percent debt and 50 percent equity, maintaining this ratio influences IDACORP's and Idaho Power's debt and equity issuance decisions. As of December 31, 2021, IDACORP's and Idaho Power's capital structures, as calculated for purposes of applicable debt covenants, were as follows:
| IDACORP | Idaho Power | |||||||||||||
| Debt | 43% | 45% | ||||||||||||
| Equity | 57% | 55% | ||||||||||||
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 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 2021 were $363 million and $323 million, respectively, decreases of $25 million and $30 million for IDACORP and Idaho Power, respectively, when compared with 2020. Significant items that affected the companies' operating cash flows in 2021 relative to 2020 were as follows:
•an $8 million and a $10 million increase in IDACORP and Idaho Power net income, respectively;
•changes in regulatory assets and liabilities, mostly related to the relative amounts of costs deferred and collected under the Idaho PCA and energy efficiency program cost mechanisms, increased operating cash inflows by $3 million;
•changes in deferred taxes and in taxes accrued and receivable combined to decrease IDACORP and Idaho Power cash flows by $28 million and $37 million, respectively; and
•changes in working capital balances due primarily to timing, including fluctuations in accounts receivable, accounts payable, other current assets, and other current liabilities, as follows:
◦timing of collections of accounts receivable balances decreased operating cash flows by $6 million for IDACORP and $3 million for Idaho Power;
◦timing of accounts payable payments increased operating cash flows by $18 million for IDACORP and Idaho Power;
◦the changes in other current assets decreased operating cash flows by $13 million for IDACORP and Idaho Power, 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 non-incentive compensation, customer deposits, accrued interest, and other miscellaneous liabilities, decreased operating cash flows by $5 million for IDACORP and Idaho Power.
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Investing Cash Flows
Investing activities consist primarily of capital expenditures related to new construction of and improvements to Idaho Power’s power supply, transmission, and distribution facilities. Idaho Power's capital expenditures, including AFUDC, were $300 million and $311 million in 2021 and 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 $6 million and $3 million in 2021 and 2020, respectively, from Boardman-to-Hemingway project joint permitting participants relating to a portion of these permitting 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 equity securities of $16 million in 2021 and $33 million in 2020. Idaho Power received $11 million and $26 million of proceeds in the Rabbi trust from the sales of equity securities in 2021 and 2020, respectively.
During 2021, IDACORP's investing cash inflows also included $50 million of proceeds from maturities of short-term investments. During 2021 and 2020, IDACORP's investing cash outflows included $25 million of purchases of short-term investments in addition to $15 million and $14 million, respectively, of tax credit investments in affordable housing and other real estate, which provide a return principally by reducing federal and state income taxes through tax credits and accelerated tax depreciation benefits.
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 2021 and 2020:
•in April 2020, Idaho Power issued $230 million in principal amount of its 4.20 percent first mortgage bonds, secured
medium term notes, Series K, maturing March 1, 2048. The bonds were issued at a reoffer yield of 3.422 percent,
which resulted in a net premium of 13.0 percent and net proceeds to Idaho Power of $260 million;
•in June 2020, Idaho Power issued $80 million in principal amount of its 1.90 percent first mortgage bonds, secured
medium term notes, Series L, maturing July 15, 2030;
•in July 2020, Idaho Power redeemed, prior to maturity, $75 million in principal amount of 2.95 percent first mortgage
bonds, medium-term notes, Series H due in April 2022. In accordance with the redemption provisions of the notes, the
redemption included Idaho Power's payment of a make-whole premium to the holders of the redeemed notes in the
aggregate amount of $3 million;
•in August 2020, Idaho Power redeemed $100 million in principal amount of 3.40 percent first mortgage bonds due in
November 2020; and
•IDACORP and Idaho Power paid dividends of approximately $146 million and $138 million in 2021 and 2020, respectively.
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 2019, Idaho Power received orders from the IPUC, OPUC, and WPSC authorizing the company to issue and sell from time to time up to $500 million in aggregate principal amount of debt securities and first mortgage bonds, subject to conditions specified in the orders. 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,
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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.
In May 2019, Idaho Power filed a shelf registration statement with the SEC, which became effective upon filing for the offer and sale of an unspecified principal amount of its first mortgage bonds. The issuance of first mortgage bonds requires that Idaho Power meet interest coverage and security provisions set forth in Idaho Power's Indenture of Mortgage and Deed of Trust dated as of October 1, 1937, as amended and supplemented from time to time (Indenture). Future issuances of first mortgage bonds are subject to satisfaction of covenants and security provisions set forth in the Indenture, market conditions, regulatory authorizations, and covenants contained in other financing agreements.
In June 2020, Idaho Power entered into a selling agency agreement with six banks named in the agreement in
connection with the potential issuance and sale from time to time of up to $500 million aggregate principal amount of first
mortgage bonds, secured medium term notes, Series L (Series L Notes), under Idaho Power’s Indenture of Mortgage and Deed
of Trust, dated as of October 1, 1937, as amended and supplemented (Indenture). Also in June 2020, Idaho Power
entered into the Forty-ninth Supplemental Indenture, dated effective as of June 5, 2020, to the Indenture (Forty-ninth
Supplemental Indenture). The Forty-ninth Supplemental Indenture provides for, among other items the issuance of up to
$500 million in aggregate principal amount of Series L Notes pursuant to the Indenture.
The Indenture limits the amount of first mortgage bonds at any one time outstanding to $2.5 billion, and as a result, the maximum amount of additional first mortgage bonds Idaho Power could issue as of December 31, 2021, was limited to approximately $534 million. Idaho Power may increase the $2.5 billion limit on the maximum amount of first mortgage bonds outstanding by filing a supplemental indenture with the trustee as provided in the Indenture of Mortgage and Deed of Trust. Separately, the Indenture also limits the amount of additional first mortgage bonds that Idaho Power may issue to the sum of (a) the principal amount of retired first mortgage bonds and (b) 60 percent of total unfunded property additions, as defined in the Indenture. As of December 31, 2021, Idaho Power could issue approximately $2.1 billion of additional first mortgage bonds based on retired first mortgage bonds and total unfunded property additions.
IDACORP and Idaho Power Credit Facilities: The IDACORP Credit Facility, which may be used for general corporate purposes and commercial paper backup, consists of a revolving line of credit not to exceed the aggregate principal amount at any one time outstanding of $100 million, including swingline loans in an aggregate principal amount at any time outstanding not to exceed $10 million, and letters of credit in an aggregate principle amount at any time outstanding not to exceed $50 million. The Idaho Power Credit Facility, which may be used for general corporate purpose and commercial paper backup, consists of a revolving line of credit, through the issuance of loans and standby letters of credit, not to exceed the aggregate 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, and letters of credit in an aggregate principal amount at any time outstanding not to exceed $50 million. IDACORP and Idaho Power have the right to request an increase in the aggregate principal amount of the facilities to $150 million and $450 million, respectively, in each case subject to certain conditions.
The IDACORP and Idaho Power Credit Facilities have similar terms and conditions. The interest rates for any borrowings under the facilities are based on either (1) a floating rate that is equal to the highest of the prime rate, federal funds rate plus 0.5 percent, or London interbank offered rate (LIBOR) Market Index rate plus 1.0 percent, or (2) the LIBOR Market Index rate, plus, in each case, an applicable margin, provided that the federal funds rate and LIBOR rate will not be less than zero. The Secured Overnight Financing Rate (SOFR) plus a defined benchmark adjustment would replace the LIBOR Market Index rate during any period in which the LIBOR rate is unavailable or unascertainable. If during any period both the LIBOR and SOFR rates are unavailable or unascertainable, an alternate benchmark rate selected by the administrative agent and the borrower would apply. The applicable margin is based on IDACORP's or Idaho Power's, as applicable, senior unsecured long-term indebtedness credit rating by rating agencies, as set forth on a schedule to the credit 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 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, 2021, the leverage ratios for IDACORP and Idaho Power were 43 percent and 45 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, 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 2022.
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.
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 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, 2021 | December 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. | ||||||||||||||||||||||||||
IDACORP and Idaho Power had no short term commercial paper outstanding during the years ended December 31, 2021 and 2020. At February 11, 2022, neither IDACORP nor Idaho Power had loans outstanding under their credit facilities and neither
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had commercial paper outstanding.
Impact of Credit Ratings on Liquidity and Collateral Obligations
IDACORP’s and Idaho Power’s access to capital markets, including the commercial paper market, and their respective financing costs in those markets, depends in part on their respective credit ratings. The following table outlines the ratings of Idaho Power’s and IDACORP’s securities, and the ratings outlook, by Moody’s Investors Service and Standard & Poor’s Ratings Services as of the date of this report:
| IDACORP | Idaho Power | |||||||||||||
| Moody's Investors Service: | ||||||||||||||
| Rating Outlook | Negative | Negative | ||||||||||||
| Long-Term Issuer Rating | Baa1 | A3 | ||||||||||||
| First Mortgage Bonds | None | A1 | ||||||||||||
| Senior Secured Debt | None | A1 | ||||||||||||
| Commercial Paper | P-2 | P-2 | ||||||||||||
| Standard & Poor's Rating Services: | ||||||||||||||
| Corporate Credit Rating | BBB | BBB | ||||||||||||
| Rating Outlook | Stable | Stable | ||||||||||||
| Short-Term Rating | A-2 | A-2 | ||||||||||||
| Senior Secured Debt | None | A- | ||||||||||||
These security ratings reflect the views of the ratings agencies. An explanation of the significance of these ratings may be obtained from each rating agency. Such ratings are not a recommendation to buy, sell, or hold securities. There have been no changes to IDACORP's or Idaho Power's ratings by Standard & Poor’s Ratings Services (S&P) or Moody’s Investors Service (Moody's) from those included in the 2020 Annual Report. However, 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, 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, 2021, the amount of additional collateral that could be requested upon a downgrade to below investment grade is approximately $25.7 million. To minimize capital requirements, Idaho Power actively monitors its portfolio exposure and the potential exposure to additional requests for performance assurance collateral through sensitivity analysis.
Capital Requirements
Idaho Power's cash capital expenditures, excluding AFUDC, were $288 million during the year ended December 31, 2021. The cash expenditure amount excludes net costs of removing assets from service. The table below presents Idaho Power's estimated accrual-basis additions to electric plant for 2022 through 2026 (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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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.
| 2022 | 2023 | 2024-2026 | |||||||||||||||||||||||||||
| 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 maintain reliability and operational effectiveness. These projects involve significant capital expenditures. Examples of anticipated system enhancements planned for 2022 through 2026 and estimated costs include the following:
•$40-$70 million per year for construction and replacement of transmission lines and stations other than the Boardman-to-Hemingway and Gateway West projects;
•$125-$170 million per year for construction and replacement of distribution lines and stations, including replacement of underground distribution cables;
•$10-$80 million per year for ongoing improvements and replacements at thermal plants;
•$70-$110 million per year for hydropower plant improvement programs, including relicensing costs; and
•$50-$75 million per year for general plant improvements, such as land and buildings, vehicles, information technology, and communication equipment.
Other Major Infrastructure Projects: Idaho Power has recently completed or is engaged in the development of a number of significant projects and has entered into arrangements with third parties for joint development of infrastructure projects. The most notable projects are described below.
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, high-voltage transmission project between a substation near Boardman, Oregon, and the Hemingway substation near Boise, Idaho, would provide transmission service to meet future resource needs. In January 2012, Idaho Power entered into a joint funding agreement with PacifiCorp and the Bonneville Power Administration (BPA) to pursue permitting of the project. The joint funding agreement provided that Idaho Power's interest in the permitting phase of the project would be approximately 21 percent. Total cost estimates for the project are between $1.0 billion and $1.2 billion, including Idaho Power's AFUDC.
Approximately $125 million, including AFUDC, has been expended on the Boardman-to-Hemingway project through December 31, 2021. Pursuant to the terms of the joint funding arrangements, Idaho Power has received $81 million in reimbursement as of December 31, 2021, from project co-participants for their share of costs. As of the date of this report, no material co-participant reimbursements are outstanding. Joint permitting participants are obligated to reimburse Idaho Power for their share of any future project permitting expenditures or agreed upon early construction expenditures incurred by Idaho Power under the terms of the joint funding agreement.
The permitting phase of the Boardman-to-Hemingway project is subject to federal review and approval by the U.S. Bureau of Land Management (BLM), the U.S. Forest Service, the Department of the Navy, and certain other federal agencies. The BLM issued its record of decision for the project in November 2017, approving a right-of-way grant for the project to cross approximately 86 miles of BLM-administered land. The U.S. Forest Service issued its record of decision in November 2018 authorizing the project to cross approximately seven miles of National Forest lands. In September 2019, the Department of the Navy issued its record of decision authorizing the project to cross approximately seven miles of Department of the Navy lands.
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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 permitting process, the Oregon Department of Energy (ODOE) issued a Proposed Order in July 2020 that recommends approval of the project to the state's Energy Facility Siting Council (EFSC). The project permit is actively undergoing the EFSC administrative process, and Idaho Power currently expects the EFSC to issue a final order in the second half of 2022.
As the current joint funding agreement covers primarily permitting activities, which are nearing completion, Idaho Power and its co-participants have been exploring several scenarios of ownership, asset, and service arrangements aimed at maximizing the value of the project to each of the co-participants' customers. Under the current joint funding agreement, Idaho Power has an approximate 21 percent interest, BPA has an approximate 24 percent interest, and PacifiCorp has an approximate 55 percent interest in the permitting phase. In January 2022, the participants executed a non-binding term sheet regarding the ownership structure that would be addressed through amended or new funding agreements for the future phases of the project. The term sheet contemplates that Idaho Power would acquire BPA's ownership interest, which would increase 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 future cost estimates.
In July 2021, Idaho Power awarded contracts for detailed design, geotechnical investigation, land surveying, and right-of-way option acquisition; and work commenced in the third quarter of 2021. Given the status of ongoing permitting activities and the construction period, Idaho Power expects the in-service date for the transmission line will be no earlier than 2026.
Gateway West Transmission Line: Idaho Power and PacifiCorp are pursuing the joint development of the Gateway West project, a high-voltage transmission lines project between a substation located near Douglas, Wyoming, and the Hemingway substation located near Boise, Idaho. In January 2012, Idaho Power and PacifiCorp entered a joint funding agreement for permitting of the project. Idaho Power has expended approximately $48 million, including Idaho Power's AFUDC, for its share of the permitting phase of the project through December 31, 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 has published its records of decision for all segments of the transmission line. PacifiCorp recently constructed and commissioned a 140-mile segment of their portion of the project in Wyoming. Idaho Power and PacifiCorp continue to coordinate the timing of next steps to best meet customer and system needs.
Hells Canyon Complex Relicensing: The HCC, located on the Snake River where it forms the border between Idaho and Oregon, provides approximately 70 percent of Idaho Power's hydropower generating nameplate capacity and 36 percent of its total generating nameplate capacity. Idaho Power has been engaged in the process of obtaining from the FERC a new long-term license for the HCC. 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 as early as 2023, but as of the date of this report Idaho Power believes issuance is more likely in 2024 or thereafter. Upon issuance of a long-term license, Idaho Power expects that the annual capital expenditures and operating and maintenance expenses associated with compliance with the terms and conditions of the long-term license could also be substantial. Idaho Power intends to seek recovery of those relicensing and compliance costs in rates through the regulatory process. In December 2016, Idaho Power filed an application with the IPUC requesting a determination that Idaho Power's expenditures of $220.8 million through year-end 2015 on relicensing of the HCC were prudently incurred, and thus eligible for future inclusion in retail rates in a future rate proceeding. In April 2018, the IPUC issued an order approving a settlement stipulation signed by Idaho Power, the
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IPUC staff, and a third-party intervenor recognizing that a total of $216.5 million in expenditures were reasonably incurred, and therefore should be eligible for inclusion in customer rates at a later date.
Environmental Regulation Costs: Idaho Power anticipates that it will continue to incur significant expenditures for its compliance with environmental regulations related to the operation of its hydropower and thermal generation facilities. In addition, Idaho Power expects it will continue to incur significant expenditures for its hydropower relicensing efforts. The near-term cost estimates for environmental matters are summarized in Part I, Item 1 - "Business - Environmental Regulation and Costs" of this report. The capital portion of these amounts is included in the Capital Requirements table above but does not include costs related to possible changes in current or new environmental laws or regulations and enforcement policies that may be enacted in response to issues such as climate change and emissions from coal-fired and gas-fired generation plants.
Long-Term Resource Planning: The IPUC and OPUC require that Idaho Power prepare biennially an IRP. The IRP seeks to forecast Idaho Power's loads and resources for a 20-year period, analyzes potential supply-side, demand-side, and transmission options, and identifies potential near-term, mid-term, and long-term actions. Idaho Power filed its most recent IRP with the IPUC and OPUC in 2021. Idaho Power's 2021 IRP identified a preferred resource portfolio and action plan, which included the addition of a 120-MW solar resource in late 2022, the conversion from coal to natural gas of two units at the Jim Bridger plant in 2024, the end to Idaho Power's participation in coal-fired operations at the North Valmy plant unit 2 in 2025, the completion of the Boardman-to-Hemingway transmission line in 2026, and an end to Idaho Power's participation in the remaining two coal-fired units at the Jim Bridger plant by the end of 2028. The 2021 IRP preferred resource portfolio and action plan also includes a need to acquire significant generation and storage resources to meet energy and capacity needs. Including the resources noted above, over the next 20 years the IRP plans for the addition of 1,685 MW of storage capacity, 1,405 MW of solar capacity, 700 MW of wind capacity, 500 MW of transmission capacity, and 400 MW of capacity from demand response. As noted in the 2021 IRP, there is uncertainty surrounding the resource sufficiency estimates and project completion dates, including uncertainty around the timing and extent of third-party development of renewable resources, fuel commodity prices, the actual completion date of the Boardman-to-Hemingway transmission project, and the economics and logistics of coal-fired plant conversions and retirements. These uncertainties, as well as others, may result in changes to the desirability of the preferred portfolio and adjustments to the timing and nature of anticipated and actual actions in the 2021 IRP. As of the date of this report, proceedings relating to the 2021 IRP are pending at the IPUC and OPUC. Additional information on Idaho Power's 2021 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 of 2021 and 2020. Idaho Power estimates that it has no minimum required contribution to be made during 2022. Depending on market conditions and cash flow considerations, Idaho Power could contribute up to $40 million to the pension plan during 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 2022, Idaho Power expects continuing significant contribution obligations under the pension plan. Refer to Note 12 – “Benefit Plans” to the consolidated financial statements included in this report for information relating to those obligations.
Idaho Power defers its Idaho-jurisdiction pension expense as a regulatory asset until recovered from Idaho customers. At December 31, 2021 and 2020, Idaho Power's deferral balance associated with the Idaho jurisdiction was $234 million and $201 million, respectively. Deferred pension costs are amortized to expense to match the revenues received when contributions are recovered through rates. Idaho Power only records a carrying charge on the unrecovered balance of cash contributions. 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. Additional information on the regulatory assets related to Idaho Power's pension and postretirement programs can be found in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.
Contractual Obligations
IDACORP’s and Idaho Power’s contractual cash obligations as of December 31, 2021, 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 additional information relating to purchase obligations and other long-term liabilities.
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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 60 percent and 70 percent of sustainable IDACORP earnings, with the flexibility to achieve that payout ratio over time and to adjust the payout ratio or to deviate from the target payout ratio from time to time based on the various factors that drive IDACORP's board of 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 2021 and 2020, IDACORP's board of directors voted to increase the quarterly dividend to $0.75 per share and $0.71 per share of IDACORP common stock, respectively. IDACORP's dividends during 2021 were 59.4 percent of actual 2021 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.
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
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 $51.6 million at December 31, 2021, representing IERCo's one-third share of BCC's total reclamation obligation of $154.7 million. BCC has a reclamation trust fund set aside and specifically for the purpose of paying these reclamation costs. At December 31, 2021, the value of the reclamation trust fund totaled $211.2 million. During 2021, the reclamation trust fund made $21.1 million of distributions for reclamation activity costs associated with the BCC surface mine. BCC periodically assesses the adequacy of the reclamation trust fund and its estimate of future reclamation costs. To ensure that the reclamation trust fund maintains adequate reserves, BCC has the ability to, and does, add a per-ton surcharge to coal sales, all of which are 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 filings taking into consideration short-term and long-term needs for rate relief and several other factors that can affect the structure and timing of those filings. These factors include in-service dates of major capital investments, the timing and magnitude of changes in major revenue and expense items, and customer growth rates, as well as other factors. Idaho Power's most recent general rate cases in Idaho and Oregon were filed during 2011, and in 2012, large single-issue rate cases for the Langley Gulch power plant resulted in the resetting of base rates in both Idaho and Oregon. Idaho Power also reset its base-rate power supply expenses in the Idaho jurisdiction for purposes of updating the collection of costs through retail rates in 2014 but without a resulting net increase in rates. The IPUC and OPUC have also approved base rate changes in single-issue 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 mitigate the impact of regulatory lag, which refers to the period of time between making an investment or incurring an expense and recovering that investment or expense and earning a return. Management's regulatory focus in recent years has been largely on regulatory settlement stipulations and the design of rate mechanisms. With Idaho Power’s anticipated significant infrastructure investments that are intended to help meet projected near-term capacity deficits, Idaho Power’s evaluations indicate that the appropriate time to file general rate cases in both Idaho and Oregon is approaching. The resulting expected increase in rate-base eligible assets as these projects are placed into service, along with the significant amounts of capital expenditures Idaho Power has made since its last general rate case filed in 2011, will increase and potentially accelerate Idaho Power’s need to file general rate cases.
Notable Retail Rate Changes in Idaho and Oregon
The table below presents notable rate changes during 2021 and 2020 that affected Idaho Power's results for the periods or that will likely affect future periods. Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report also provides a description of regulatory mechanisms and associated orders of the IPUC and OPUC, and should be read in conjunction with the discussion of regulatory matters in this MD&A.
| Description | Effective Date | Estimated Annualized Rate Impact (millions)(1) | |||||||||||||||
| 2021 Idaho PCA | 6/1/2021 | $ | 39 | ||||||||||||||
| 2021 Idaho FCA | 6/1/2021 | 3 | |||||||||||||||
| Idaho Boardman plant closure | 1/1/2021 | (4) | |||||||||||||||
| 2020 Idaho PCA | 6/1/2020 | 59 | |||||||||||||||
| 2020 Idaho FCA | 6/1/2020 | 1 | |||||||||||||||
| Oregon North Valmy plant Exit Framework Settlement Stipulation | 1/1/2020 | (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. | |||||||||||||||||
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 approved 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 October 2014, the IPUC issued an order approving an extension, with modifications, of the terms of a December 2011 Idaho settlement stipulation that allowed Idaho Power to, in certain circumstances, amortize additional accumulated deferred investment tax credits (ADITC) if Idaho Power's actual Idaho ROE was less than 9.5 percent, to help achieve a 9.5 percent Idaho ROE for the applicable year (October 2014 Idaho Earnings Support and Sharing Settlement Stipulation). Under the October 2014 Idaho Earnings Support and Sharing Settlement Stipulation, when Idaho Power's actual calendar-year Idaho ROE exceeded 10.0 percent, Idaho Power was required to share a portion of its calendar-year Idaho-jurisdiction earnings with Idaho customers for the period from 2015 through 2019. The more specific terms and conditions of the October 2014 Idaho Earnings Support and Sharing Settlement Stipulation are described in Note 3 - "Regulatory Matters - Notable Idaho Regulatory Matters" to the consolidated financial statements included in this report. The October 2014 Idaho Earning Support and Sharing Settlement Stipulation was modified and indefinitely extended, as described in "May 2018 Idaho Tax Reform Settlement Stipulation" of this MD&A.
May 2018 Idaho Tax Reform Settlement Stipulation: In December 2017, the Tax Cuts and Jobs Act was signed into law, which, among other things, lowered the corporate federal income tax rate from 35 percent to 21 percent and modified or eliminated certain federal income tax deductions for corporations. In March 2018, Idaho House Bill 463 was signed into law reducing the Idaho state corporate income tax rate from 7.4 percent to 6.925 percent. In May 2018, the IPUC issued an order approving a settlement stipulation (May 2018 Idaho Tax Reform Settlement Stipulation) related to income tax reform. Beginning June 1, 2018, the settlement stipulation provides an annual (a) $18.7 million reduction to Idaho customer base rates and (b) $7.4 million amortization of existing regulatory deferrals for specified items or future amortization of other existing or future unspecified regulatory deferrals that would otherwise be a future regulatory asset recoverable from Idaho customers.
The May 2018 Idaho Tax Reform Settlement Stipulation provides for the extension of the October 2014 Idaho Earnings Support and Sharing Settlement Stipulation described above beyond the initial termination date of December 31, 2019, with modified terms related to the ADITC and revenue sharing mechanism that became effective beginning January 1, 2020, with no defined end date. The May 2018 Idaho Tax Reform Settlement Stipulation does not impose a moratorium on Idaho Power filing a general rate case or other form of rate proceeding in Idaho during its term and includes provisions for the accelerated amortization of ADITC to help achieve a minimum 9.4 percent (9.5 percent prior to 2020) Idaho ROE. In addition, under the May 2018 Idaho Tax Reform Settlement Stipulation, minimum Idaho ROE would revert back to 95 percent of the authorized return on equity in the next general rate case. IDACORP and Idaho Power believe that the terms allowing amortization of additional ADITC in the May 2018 Idaho Tax Reform Settlement Stipulation provide the companies with a greater degree of earnings stability than would be possible without the terms of the stipulation in effect. In 2021, Idaho Power recorded a $0.6 million provision against current revenue for sharing with customers, as its full-year Idaho ROE exceeded 10.0 percent. Idaho Power recorded no provision against current revenue for sharing with customers in 2020, as its full-year ROE was between 9.4 percent and 10.0 percent. At December 31, 2021, the full $45 million of additional ADITC remained available for future use under the terms of the May 2018 Idaho Tax Reform Settlement Stipulation.
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):
| Year | Recorded as Refunds to Customers | Recorded as a Pre-tax Charge to Pension Expense | Total | |||||||||||||||||
| 2021 | $ | 0.6 | $ | — | $ | 0.6 | ||||||||||||||
| 2020 | — | — | — | |||||||||||||||||
| 2019 | — | — | — | |||||||||||||||||
| 2018 | 5.0 | — | 5.0 | |||||||||||||||||
2011(1) - 2017 | 53.1 | 68.1 | 121.2 | |||||||||||||||||
| Total | $ | 58.7 | $ | 68.1 | $ | 126.8 | ||||||||||||||
(1) The 2011 sharing amounts were recorded pursuant to a regulatory mechanism preceding the December 2011 Idaho settlement stipulation.
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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: In May 2017, the IPUC approved a settlement stipulation, effective June 1, 2017, allowing accelerated depreciation and cost recovery for the North Valmy 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 no later than the end of 2025. The settlement stipulation also provides for the regulatory accrual or deferral of the difference between actual revenue requirements and levelized collections, and provides for the regulatory accrual or deferral of the difference between actual costs incurred (including accelerated depreciation expense on unit 1 through 2019 and unit 2 through 2025) compared with costs permitted to be recovered during the cost recovery period specified in the settlement stipulation (including depreciation expense through 2028). If actual costs incurred differ from forecasted 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 plant investments through May 31, 2017, and (3) forecasted North Valmy plant decommissioning costs. The settlement stipulation provided for an increase in the Oregon jurisdictional revenue requirement of $1.1 million, with yearly adjustments, if warranted. In May 2018, the OPUC also deemed prudent Idaho Power's decision to pursue the end of its participation in coal-fired operations of unit 1 by the end of 2019 and approved Idaho Power's request to recover annual incremental accelerated depreciation relating to unit 1, ending December 31, 2019, resulting in a $2.5 million annualized revenue requirement. In October 2019, the OPUC approved the North Valmy plant exit agreement and authorized Idaho Power to adjust customer rates in Oregon, effective January 1, 2020, to reflect a decrease in the annual levelized revenue requirement of $3.2 million, which mostly relates to the decrease in depreciation expense and other costs associated with the December 2019 end of Idaho Power's participation in coal-fired operations of North Valmy plant unit 1. In September 2021, the IPUC issued an order acknowledging Idaho Power's year-end 2025 exit date from Valmy unit 2 is appropriate based on economics and reliability needs.
Boardman Power Plant Filings: In October 2020, Idaho Power and co-owner Portland General Electric ceased coal-fired operations at their Boardman power plant. In December 2020, the IPUC issued an order authorizing a determination that all actual Boardman power plant investments made through June 30, 2020, were prudently incurred and decreasing Idaho customer rates $3.9 million to reflect full depreciation of all Boardman power plant investments, effective January 1, 2021. In October 2020, the OPUC issued a similar order approving a $0.3 million decrease in Oregon customer rates, effective November 1, 2020.
Customer-Owned Generation Filing: Customer-owned generation allows customers to install solar panels or other on-site energy-generating resources and connect them to Idaho Power’s grid. If a customer requires more energy than its system generates, it utilizes energy supplied by Idaho Power’s grid. If a customer's system generates more energy than the customer uses, the energy goes back to the grid and Idaho Power applies a corresponding kilowatt-hour credit to the customer’s bill. In May 2018, the IPUC issued an order authorizing the creation of two new customer classes for residential and small commercial customers who install their own on-site generation, with no change to pricing or compensation. Since October 2018, Idaho Power has initiated several cases with the IPUC related to studying the costs and benefits of customer-owned generation on Idaho Power’s system, and exploring whether, and to what extent, there should be modifications to the customer-owned generation pricing structure for residential and small general service customers, and large commercial, industrial, and irrigation customers (CI&I). The IPUC issued orders in one of the residential and small commercial cases during December 2019 and February 2020 directing Idaho Power to (1) complete additional studies related to the costs and benefits of customer generation before changes to the compensation structure are implemented, and (2) continue to allow customers with on-site generation prior to December 20, 2019, to be subject to the billing terms in place on that date until December 20, 2045. In December 2020, the IPUC issued an order establishing a 25-year grandfathering term for CI&I customers, similar to the terms approved for the residential and small commercial customer classes.
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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 IPUC Staff to suspend the procedural schedule in Idaho 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 ratemaking treatment at a later date. Subsequent to Idaho Power's application, the IPUC opened a general docket to address the issue. In July 2020, the IPUC issued an order authorizing Idaho Power and other utilities to account for unanticipated, emergency-related expenses incurred due to the COVID-19 public health crisis by recording the expenses as regulatory assets for possible recovery through future rates. The order also requires utilities to account for the decreases in expenses resulting from the COVID-19 public health crisis, such as reduced employee travel and training, and apply these reductions in expenses to offset the deferral account balance. Additionally, the order addressed potential reductions in revenue due to the COVID-19 public health crisis, allowing utilities to track reduced revenues from customer classes not included in an FCA-type mechanism for possible movement to the regulatory asset account at a later date. Idaho Power resumed assessing late fees and disconnections in early August 2020 in its Idaho service area. In October 2020, the OPUC issued an order authorizing Idaho Power to defer certain COVID-19-related costs for the 12-month period beginning March 24, 2020. In March 2021, Idaho Power requested that the OPUC re-authorize such deferral for an additional 12-month period. As of December 31, 2021, Idaho Power had recorded an immaterial regulatory asset for its estimate of unanticipated, emergency-related expenses, including higher bad debt expense, net of estimated savings.
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.
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 hydropower generation conditions, market energy prices and the volume of wholesale energy sales, power purchase costs from renewable energy projects, income tax reform, and revenue sharing under Idaho regulatory settlement stipulations. From year to year, these factors can vary significantly, which can result in significant accruals and deferrals under the power cost adjustment mechanisms. The power cost adjustment rate changes reflected in the table under the heading "Notable Retail Rate Changes in Idaho and Oregon" in this MD&A are illustrative of the volatility of net power supply costs and the impact on power cost adjustment rates.
The following table summarizes the change in deferred (accrued) net power supply costs over last year (in millions):
| Idaho | Oregon | Total | ||||||||||||||||||
| Balance at December 31, 2020 | $ | (14.7) | $ | (0.3) | $ | (15.0) | ||||||||||||||
| Current period net power supply costs deferred | 22.0 | — | 22.0 | |||||||||||||||||
| Prior amounts refunded through rates | 27.6 | 0.2 | 27.8 | |||||||||||||||||
SO2 allowance and renewable energy certificate (REC) sales | (4.2) | (0.2) | (4.4) | |||||||||||||||||
| Interest and other | 3.1 | — | 3.1 | |||||||||||||||||
| Balance at December 31, 2021 | $ | 33.8 | $ | (0.3) | $ | 33.5 | ||||||||||||||
Open Access Transmission Tariff Rate Proceedings
Idaho Power uses a formula rate for transmission service provided under its OATT, which allows transmission rates to be updated annually based primarily on actual financial and operational data Idaho Power files with the FERC and allows Idaho Power to recover costs associated with its transmission system. In September 2021, Idaho Power filed its 2021 final transmission rate with the FERC, reflecting a transmission rate of $31.19 per kW-year, effective for the period from October 1, 2021, to September 30, 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 $127.3 million. The OATT rate in effect from October 1, 2020, to September 30, 2021, was $29.95 per kW-year based on a net annual transmission revenue requirement of $117.7 million. The increase in the OATT rate is largely attributable to increased transmission plant as well as decreased short-term firm and non-firm transmission revenues in 2020, which serve as an offset to the transmission revenue
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requirement. Historical OATT rate information is included in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.
Relicensing of Hydropower Projects
Overview: Idaho Power, like other utilities that operate non-federal hydropower projects on qualified waterways, obtains licenses for its hydropower projects from the FERC. These licenses have a term of 30 to 50 years depending on the size, complexity, and cost of the project. The expiration dates for the FERC licenses for each of the facilities are included in Part I - Item 2 - "Properties" in this report. Costs for the relicensing of Idaho Power's hydropower projects are recorded in construction work in progress until new multi-year licenses are issued by the FERC, at which time the charges are transferred to electric plant in service. Idaho Power expects to seek recovery of relicensing costs and costs related to a new long-term license through the regulatory process. In April 2018, the IPUC approved a settlement stipulation signed by Idaho Power, the IPUC Staff, and a third-party intervenor and determined that $216.5 million in expenditures incurred for relicensing through December 31, 2015, were reasonably and prudently incurred, and therefore should be eligible for inclusion in customer rates at a later date. Relicensing costs of $389 million (including AFUDC) for the HCC, Idaho Power's largest hydropower complex and a major relicensing effort, were included in construction work in progress at December 31, 2021. As of the date of this report, the IPUC authorizes Idaho Power to include in its Idaho jurisdiction rates approximately $8.8 million annually of AFUDC relating to the HCC relicensing project. Collecting these amounts currently will reduce future collections when the HCC relicensing costs are approved for recovery in base rates. As of December 31, 2021, Idaho Power's regulatory liability for collection of AFUDC relating to the HCC was $187.7 million. 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 hydropower generating plants.
Hells Canyon Complex Relicensing: The HCC, located on the Snake River where it forms the border between Idaho and Oregon, provides approximately 70 percent of Idaho Power's hydropower generating nameplate capacity and 36 percent of its total generating nameplate capacity. In July 2003, Idaho Power filed an application with the FERC for a new license in anticipation of the July 2005 expiration of the then-existing license. Since the expiration of that license, Idaho Power has been operating the project under annual licenses issued by the FERC. In December 2004, Idaho Power and eleven other parties, including National Marine Fisheries Service (NMFS) and U.S. Fish and Wildlife Service (USFWS), involved in the HCC relicensing process entered into an interim agreement that addresses the effects of the ongoing operations of the HCC on Endangered Species Act (ESA)-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 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 on the licensing of the HCC. Both the NMFS and USFWS responded to the FERC that the conditions relating to the licensing of the HCC were not fully described or developed in the final EIS as the measures to address the water quality effects of the project were yet to be fully defined by the Section 401 certification process. The NMFS and USFWS each therefore recommended that formal consultation under the ESA be delayed until the Section 401 certification process is completed.
In connection with its relicensing efforts, Idaho Power filed 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 filed and withdrew its Section 401 certification applications with Oregon and Idaho on an annual basis while it was 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, provided that Idaho Power take no action that might result in the reintroduction or establishment of spawning populations of any fish species into Idaho's waters without consultation with and express 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 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 2019, the states of Idaho and Oregon, along with Idaho Power, reached a settlement pertaining to the CWA Section 401 certification that requires Idaho Power, among other measures, to increase the number of Chinook salmon it releases each year through expanded hatchery production. Additionally, Idaho Power is required to fund a total of $12 million of research and water quality improvements in the HCC over a 20-year period following the issuance of the license. Idaho Power estimates that the combined cost of the mandated water quality improvements and expanded hatchery production is $20 million in aggregate over the first 20 years of the new license term. In May 2019, Oregon and Idaho issued final CWA Section 401 certifications. These certifications have been submitted to the FERC as part of the relicensing process. In July 2019, three third-parties filed lawsuits against the Oregon Department of Environmental Quality in Oregon state court challenging the Oregon CWA Section 401 certification based on fish passage, water temperature, and mercury issues associated with the Snake River and the HCC. Two of the lawsuits were consolidated, and Idaho Power intervened in that lawsuit and the parties reached a settlement. The court dismissed the third challenge to the Oregon CWA 401 certification with prejudice. No parties challenged the Idaho CWA 401 certification. In December 2019, Idaho Power filed an Offer of Settlement with the FERC requesting specific language be included in the new HCC license based upon the settlement among Idaho, Oregon, and Idaho Power. During the first quarter of 2020, the FERC received several comments opposing the Offer of Settlement, and its decision relating to the Offer of Settlement is pending as of the date of this report.
Idaho Power continues to work with Idaho and Oregon on measures to provide reasonable assurance that any discharges from the HCC will comply with applicable state water quality standards and associated measures identified in the final Section 401 certifications, and continues to cooperate with the USFWS, the NMFS, and the FERC in an effort to address ESA concerns. Measures identified in the final Section 401 certifications included construction of aerated runners at the Brownlee project (part of the HCC), modification of spillways at the three dams in the HCC to address total dissolved gas issues, and upstream watershed improvements to address water temperature exceedances during a small portion of the year. These and any other additional measures to satisfy relicensing requirements have added and will continue to add substantially to project costs.
In July 2020, Idaho Power submitted to the FERC its supplement to the final license application that 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 that the FERC will issue a new license order or the ultimate capital investment and ongoing operating and maintenance costs Idaho Power will incur in complying with any new license. The FERC could issue an HCC license as early as 2023, but as of the date of this report Idaho Power believes issuance is more likely in 2024 or thereafter. Idaho Power estimates that the annual costs it will incur to obtain a new long-term license for the HCC, including AFUDC, are likely to range from $30 million to $40 million until issuance of the license. Subsequent to the issuance of a new license, Idaho Power expects to incur increased annual operating and maintenance costs to comply with the requirements of any new license.
American Falls Relicensing: In April 2020, the FERC formally initiated the relicensing proceeding for the American Falls hydropower facility, which is Idaho Power's largest hydropower facility outside of the HCC, with a generating capacity of 92.3 MW. Idaho Power owns the generation facility but not the structural dam itself, which is owned by the U.S. Bureau of Reclamation. The FERC recognized Idaho Power’s pre-application document, including a proposed process plan and schedule, and recognized Idaho Power’s intent to file an application for a license. A final license application is due to the FERC in 2023. The relicensing proceeding will begin the process of informal ESA Section 7 consultation with the USFWS and Section 106 of the National Historic Preservation Act consultation with the Idaho State Historic Preservation Office. American Falls' current
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license expires in 2025, and as of the date of this report, Idaho Power expects the FERC to issue a new license for this facility prior to the existing license's expiration.
Renewable Energy Standards and Contracts
Renewable Portfolio Standards: Many states have enacted legislation that would require electric utilities to obtain a specified percentage of their electricity from renewable sources. These requirements are commonly referred to as a "renewable portfolio standard" or "RPS." However, as of the date of this report no State of Idaho RPS is in effect. Idaho Power will be required to comply with either a five- or ten-percent RPS in Oregon beginning in 2025 (depending on loads at that time), and Idaho Power expects to meet either RPS requirement with RECs obtained from the purchase of energy from the Elkhorn Valley wind project.
Pursuant to an IPUC order, Idaho Power is selling its near-term RECs and returning to customers their share (shared 95 percent with customers in the Idaho jurisdiction) of those proceeds through the PCA. For the years ended December 31, 2021, and 2020, Idaho Power's REC sales totaled $4.7 million and $5.2 million, respectively.
Were Idaho Power to be subject to additional RPS legislation, it may cease in full or in part the sale of RECs it receives, seek to obtain RECs from additional projects, generate RECs from any REC-generating facilities it owns or may be required to construct in light of an RPS, or purchase RECs in the market. Historically, Idaho Power has generally not received the RECs associated with PURPA projects. However, an order issued by the IPUC in 2012 provides that Idaho Power will own a portion of the RECs generated by some PURPA projects. The required purchase of additional RECs to meet RPS requirements would increase Idaho Power's costs, which Idaho Power expects would be wholly or largely passed on to customers through rates and the power cost adjustment mechanisms.
Renewable and Other Energy Contracts: Idaho Power has contracts for the purchase of electricity produced by third-party owned generation facilities, most of which produce energy with the use of renewable generation sources such as wind, solar, biomass, small hydropower, and geothermal. The majority of these contracts are entered into as mandatory purchases under PURPA. As of December 31, 2021, Idaho Power had contracts to purchase energy from 129 on-line PURPA projects. An additional three contracts are with on-line non-PURPA projects, including the Elkhorn Valley wind project with a 101-MW nameplate capacity.
The following table sets forth, as of December 31, 2021, the resource type and nameplate capacity of Idaho Power's signed agreements for power purchases from PURPA and non-PURPA generating facilities. These agreements have original contract terms ranging from one to 35 years.
| Resource Type | On-line megawatts (MW) | Under Contract but not yet On-line (MW) | Total Projects under Contract (MW) | |||||||||||||||||
| PURPA: | ||||||||||||||||||||
| Wind | 627 | — | 627 | |||||||||||||||||
| Solar | 316 | 74 | 390 | |||||||||||||||||
| Hydropower | 150 | 1 | 151 | |||||||||||||||||
| Other | 44 | — | 44 | |||||||||||||||||
| Total PURPA | 1,137 | 75 | 1,212 | |||||||||||||||||
| Non-PURPA: | ||||||||||||||||||||
| Wind | 101 | — | 101 | |||||||||||||||||
| Geothermal | 35 | — | 35 | |||||||||||||||||
| Solar | — | 120 | 120 | |||||||||||||||||
| Total non-PURPA | 136 | 120 | 256 | |||||||||||||||||
The projects not yet on-line include one PURPA-qualifying facility hydropower project that is scheduled to be on-line in 2022, two PURPA-qualifying facility solar projects scheduled to be on-line in 2023, and one PURPA-qualifying facility solar project scheduled to be on-line in 2024. The non-PURPA solar project is scheduled to be on-line in late 2022.
In July 2020, the FERC issued Order No. 872, which could affect how states determine PURPA project avoided cost rates for purchases of power generated from qualifying facilities (QF), which facilities are eligible for QF status, whether and when
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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 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 two co-owned coal-fired power plants and three wholly-owned natural gas-fired combustion turbine power plants are subject to many of these regulations. Idaho Power's 17 hydropower projects are also subject to a number of water discharge standards and other environmental requirements.
Compliance with current and future environmental laws and regulations may:
•increase the operating costs of generating plants;
•increase the construction costs and lead time for new facilities;
•require the modification of existing generating plants, which could result in additional costs;
•require the curtailment, fuel-switching, or shut-down of existing generating plants;
•reduce the output from current generating facilities; or
•require the acquisition of alternative sources of energy or storage technology, increased transmission wheeling, or require construction of additional generating facilities, which could result in higher costs.
Current and future environmental laws and regulations could significantly increase the cost of operating fossil fuel-fired generation plants and constructing new generation and transmission facilities, in large part through the substantial cost of permitting activities and the required installation of additional pollution control devices. In many parts of the United States, some higher-cost, high-emission coal-fired plants have ceased operation or the plant owners have announced a near-term cessation of operation, as the cost of compliance makes the plants uneconomical to operate. The decision to cease operation of the Boardman power plant in October 2020 was based in part on the significant cost of compliance with environmental laws and regulations. The decision to pursue an end to participation in coal-fired operations at the North Valmy plant was also based primarily on the economics of operating the plant. Beyond increasing costs generally, these environmental laws and regulations could affect IDACORP's and Idaho Power's results of operations and financial condition if the costs associated with these environmental requirements and early plant retirements 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 2022 to 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 2024, though they could be substantial. Furthermore, several executive orders issued since 2017 concerning environmental regulations, including executive orders issued by the current Presidential Administration in 2021, as described below, could result in significant changes in, and uncertainty with respect to, legislation, regulation, and government policy regarding environmental matters. The outcome of federal agencies' review of regulations covered by executive orders and revocation of executive orders is difficult to predict. 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 more strict or robust regulations, 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 power supply, transmission, or distribution facilities or relicense or operate its hydropower facilities. When a species is added to the federal list of threatened and endangered species, it is protected from “take,” which is defined to include harming the species. The ESA directs that, concurrent with a designation of a threatened or endangered species, and where prudent and determinable, the applicable agencies also designate “any habitat of such species which is then considered to be critical habitat.” The ESA also provides that each federal agency must ensure that any action they authorize, fund, or carry out is not likely to jeopardize the continued existence of a listed species or result in the destruction or adverse modification of its critical habitat. If an action is determined to result in adverse modification of critical habitat, the federal agency must adopt changes to the proposed action to avoid the adverse modification. These changes are often quite extensive and can affect the size, scope, and even the feasibility of a project moving forward.
In November 2018, 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 power supply, transmission, or distribution facilities and the relicensing of Idaho Power's hydropower projects can be federally authorized actions that fall under the ESA. There are a number of threatened or endangered species within Idaho Power's service area and within or near proposed transmission line routes, including the slickspot peppergrass. In December 2020, the USFWS announced that although it will not yet list the black and orange monarch butterfly as threatened or endangered, it will continue to monitor this species for future determination in 2024, which Idaho Power believes could potentially impact right-of-way maintenance for its transmission line routes. Further, there are a number of ESA-listed fish and other aquatic species located in waterways in which Idaho Power has hydropower facilities, including fall Chinook salmon, bull
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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 hydropower facilities. However, the ongoing relicensing of the HCC presents endangered species and fisheries issues that may require operational adjustments and could adversely impact the amount of output from hydropower dams, potentially causing Idaho Power to rely on more expensive sources for power generation or market purchases. These ESA regulations could impact the timing and feasibility of the HCC relicensing project and the Gateway West and Boardman-to-Hemingway transmission projects and other infrastructure projects, which could lead to substantially higher construction, permitting, and licensing costs and could delay construction.
Developments in Regulation of Sage Grouse Habitat: In February 2016, a lawsuit 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 EISs across the sage grouse range and alleges that the plans fail to ensure that sage grouse populations and habitats will be protected and restored in accordance with the best available science and legal mandates. Further, the complaint challenges certain exemptions provided for the Boardman-to-Hemingway and Gateway West transmission line projects. Idaho Power has intervened in the proceedings in an effort to support the exemptions provided for in the BLM's plans. If the exemptions are overturned, Idaho Power may be required to re-route the projects, which could lead to substantially higher construction and permitting costs and could delay construction.
In May 2016, a separate lawsuit was filed in the U.S. District Court of North Dakota, challenging the BLM's sage grouse resource management and land use plan revisions, including the exemptions provided for the Boardman-to-Hemingway and Gateway West transmission line projects. In October 2016, the plaintiffs amended their complaint to no longer challenge the exemptions; however, in December 2016, the North Dakota court transferred claims challenging certain Idaho land use plan amendments to the U.S. District Court for the District of Columbia. Idaho Power is participating in the proceedings in an effort to protect its interests.
In June 2017, the Secretary of the Interior issued an order directing the BLM to review the 2015 sage grouse resource management and land use plan revisions and to identify provisions that may require modification or rescission to address energy and other development of public lands. In March 2019, the BLM issued a record of decision for six EISs that modified the 2015 sage grouse plans to better align the plan with state plans, conservation measures and the Department of the Interior and BLM policy. In October 2019, the U.S. District Court for Idaho placed a preliminary injunction on the implementation of the BLM's March 2019 plans. In order to address the concerns contained in the preliminary injunction, BLM initiated a supplemental EIS process that was completed in November 2020. A record of decision for the 2020 supplemental EIS was signed in January 2021. In November 2021, the BLM issued a notice of intent to address the management of sage grouse and sagebrush habitat on BLM-managed public lands in Idaho and Oregon, among other states, through a land use planning initiative. 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. Idaho Power prepared draft biological assessments in consultation with the USFWS and the NMFS and filed those with the FERC in October 2020. The draft biological assessments are intended to provide the necessary information to the USFWS and the NMFS to issue their biological opinion as required under the ESA. Idaho Power expects the FERC to initiate formal ESA consultation with the USFWS and the NMFS. At the conclusion of formal consultation and with the issuance of biological opinions by the NMFS and the USFWS and an operating license by the FERC, Idaho Power may be required to implement additional measures or further modify or adjust operations to comply with Section 7 of the ESA. The issuance of a final biological opinion during 2022 is unlikely.
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 under the ESA. In July 2020, the USFWS published a revised proposed rule designating critical habitat for the species, most of which are located on federal land. Idaho Power expects the listing of the slickspot peppergrass and its existence within or near the proposed route for the Gateway West transmission line project and other transmission and distribution lines to increase the cost and timing of permitting and construction of the projects, as it requires an ESA Section 7 consultation and potential mitigation. As of the date of this report, Idaho Power is uncertain whether such increases will be significant.
The Washington ground squirrel inhabits various locations throughout two of the counties within the proposed routes for Boardman-to-Hemingway. It is not listed under the federal ESA, but it is considered endangered under Oregon law and the Boardman-to-Hemingway project will need to avoid ground squirrel colonies during construction. If colonies are found within the proposed site boundary during pre-construction surveys, re-siting the transmission would require additional permitting and would likely involve increased permitting costs and could further delay the in-service date of the project.
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 hydropower facilities owned and operated by the U.S. Army Corps of Engineers (USACE) and located on the lower Snake River, National Oceanic and Atmospheric Administration's National Marine Fisheries Service (NOAA Fisheries) violated the ESA by using improper standards, 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 NEPA by failing to prepare a comprehensive EIS on implementation of the conservation measures ordered by NOAA Fisheries, including analysis of the measures directed by NOAA Fisheries and other reasonable alternatives. The court’s opinion and its emphasis on a climate change-driven analysis element, if generalized to other situations, could require ESA-driven avoidance, minimization, and compensatory mitigation efforts to incorporate surplus measures to ensure species’ protection, which could result in considerable increases in cost beyond the cost of additional analysis in the NEPA process. In September 2016, federal agencies initiated an EIS to examine hydropower dams on the lower Snake River. In September 2020, the federal agencies signed a record of decision on the EIS that will guide the operation of those dams and may expedite projects and reduce the number of actions subject to NEPA review. None of Idaho Power’s hydropower facilities are included in the studies.
Changes to NEPA: In July 2020, the previous Presidential Administration's Council on Environmental Quality (CEQ) announced its final rule to narrow federal agencies' NEPA obligations (2020 NEPA Rule), which had the potential to expedite and reduce the cost of Idaho Power's permitting and right-of-way processes. 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 for electric power;
•extreme weather events, wildfires, drought, and other natural phenomena and natural disasters could increase service interruptions, outages, maintenance costs, system damage, personal property damage, personal injuries and loss of life, legal liability, and the need for additional backup systems, and can affect the supply of, and demand for, electricity and natural gas, which may impact the price of those and other commodities;
•changes in the amount and timing of snowpack and other precipitation and stream flows could affect hydropower generation;
•legislative and/or regulatory developments related to climate change could affect plants and operations, including restrictions on the construction of new power supply resources, the expansion of existing resources, or the operation of power supply resources; and
•consumer preference for, and resource planning decisions requiring, renewable or low GHG-emitting sources of energy could impact usage of existing generation sources and require significant investment in new generation and transmission infrastructure.
Federal and state regulations pertaining to GHG emissions under the CAA have raised uncertainty about the future viability of fossil fuels, most notably coal, as an economical energy source for new and existing electric generation facilities because many new technologies for reducing carbon dioxide (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 ended its participation in coal-fired operations at the Boardman power plant in October 2020 and the North Valmy plant unit 1 in December 2019, and plans to end its participation in the North Valmy plant unit 2 no later than 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/Affordable Clean Energy Rule: The EPA has been active in the regulation of GHGs. The EPA's endangerment finding in 2009 that GHGs threaten public health and welfare resulted in the enactment of a series of EPA regulations to address GHG emissions.
In May 2010, the EPA issued the “Tailoring Rule,” which set thresholds for GHG emissions that define when permits are required for new and existing industrial facilities. While the rule is complex, Idaho Power believes that its owned and co-owned fossil fuel-fired generation plants are, as of the date of this report, in compliance with the GHG Tailoring Rule.
In August 2015, the EPA promulgated the Clean Power Plan (CPP) under Section 111(d) of the CAA, which required states to adopt plans to collectively reduce 2005 levels of power sector CO2 emissions by 32 percent by the year 2030. In June 2019, the EPA released 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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vacated the ACE rule without reinstating the CPP. As of the date of this report, Idaho Power expects to continue with its planned retirements and 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 power plant located in Oregon, in which Idaho Power was a 10-percent owner, was subject to and in compliance with Oregon's GHG reporting requirements but ceased coal-fired operations in 2020.
In Oregon, legislation referred to as 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 emissions reporting system. The Climate Registry is a collaboration aimed at developing and managing a common GHG emissions reporting system across states, provinces, and tribes to track GHG emissions nationally. All states for which Idaho Power has traditional fuel generating plants (i.e. Idaho, Oregon, Wyoming, and Nevada) are members of the Climate Registry. Idaho Power is engaged in voluntary GHG emissions intensity reduction efforts, which is discussed in Part I, Item 1 - “Business - Utility Operations - Environmental Regulation and Costs."
Other Clean Air Act Matters
Overview: In addition to the CAA developments related to GHG emissions described above, several other regulatory programs developed under the CAA apply to Idaho Power. These include the final Mercury and Air Toxics Standards (MATS), National Ambient Air Quality Standards (NAAQS), 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 and North Valmy coal-fired generating plants, along with control technology to reduce mercury, acid gases, and particulate matter emissions for purposes of compliance with the MATS rule. Legal challenges relating to the MATS rule, to which Idaho Power is not a party and pursuant to which the EPA is performing a court-mandated cost analysis for the rule, are pending. In August 2018, the EPA began reconsidering the justification behind the MATS rule and reviewing the regulations emissions standards. In December 2018, the EPA determined that it is not appropriate and necessary to regulate hazardous air pollutant emissions from power plants under Section 112 of the CAA. The emissions standards and other requirements of the MATS rule, however, remain in place. Idaho Power believes that as of the date of this report, its jointly-owned coal-fired plants are in compliance with the MATS rule, which does not significantly impact Idaho Power’s operations or financial results.
National Ambient Air Quality Standards: The CAA requires the EPA to set ambient air quality standards for six "criteria" pollutants considered harmful to public health and the environment. These six pollutants are carbon monoxide, lead, ozone, particulate matter, nitrogen dioxide (NO2), and sulfur dioxide (SO2). States are then required to develop emissions reduction strategies through State Implementation Plans, or SIPs, based on attainment of these ambient air quality standards. Recent developments and pending actions related to certain of those items relevant to Idaho Power include the following:
•NO2: In 2010, the EPA adopted a new NAAQS for NO2 at a level of 100 parts per billion averaged over a one-hour period. In connection with the new NAAQS, in February 2012 the EPA issued a final rule designating all of the counties in Idaho, Nevada, and Wyoming where Idaho Power owns or has an interest in a natural gas or coal-fired power plant as “unclassifiable/attainment” for NO2.
•SO2: In 2010, the EPA adopted a new NAAQS for SO2 at a level of 75 parts per billion averaged over a one-hour period. In 2011, the states of Idaho, Nevada, Oregon, and Wyoming sent letters to the EPA recommending that all counties in these states be classified as "unclassifiable" under the new one-hour SO2 NAAQS because of a lack of
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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 data for those states showed no violations of the 2010 SO2 standard. Since January 2018, the EPA has finalized designations of “unclassifiable/attainment” for SO2 for all areas in which Idaho Power owns or has an interest in a natural gas or coal-fired power plant.
•Ozone: In late 2014, the EPA issued a proposed rule that would update the ozone standard under the CAA, from 75 parts per billion over an eight-hour period to 65 to 70 parts per billion over an eight-hour period. In October 2015, the EPA issued a final rule lowering the national ozone standard under the CAA to 70 parts per billion. The EPA stated that the vast majority of United States counties will meet the standards by 2025 with federal and state rules and programs now in place or underway. Since January 2018, the EPA has finalized designations for all of the counties in which Idaho Power owns or has an interest in a natural gas or coal-fired power plant and determined that they meet the standard.
As of the date of this report and based on the EPA designations described above, Idaho Power does not expect these 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 units at the Jim Bridger 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 selective catalytic reduction equipment for nitrogen oxide (NOx) control at Jim Bridger units 3 and 4 by December 31, 2015, and December 31, 2016, respectively, which has been completed, and submit an application by December 31, 2017, to install add-on NOx controls at Jim Bridger unit 2 by 2021 and unit 1 by 2022, which was submitted in December 2017. 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 state 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.
In February 2019, PacifiCorp submitted a SIP revision to the WDEQ as an alternative regional haze compliance plan for the Jim Bridger plant that includes a reduced plant-wide monthly limit on emissions for NOx and SO2 and an annual total emissions cap for NOx and SO2 for units 1-4. 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: In August 2015, the EPA and USACE final rule defining the phrase "waters of the United States" (WOTUS) under the CWA became effective (WOTUS Rule). Idaho Power believes that the 2015 rule potentially expanded federal jurisdiction under the CWA beyond traditional navigable waters, interstate waters, territorial seas, tributaries, and adjacent wetlands, to a number of other waters, including waters with a "significant nexus" to those traditional waters. The WOTUS Rule was widely challenged in both federal district and circuit courts. In January 2020, the EPA and USACE finalized the first of a two-part rule to repeal the WOTUS Rule and set new and more expansive standards for determining which waters are subject to the CWA, which substantially restored the definitions and guidance used prior to the WOTUS Rule. In April 2020, the EPA and USACE published the second part of the final rule to replace the WOTUS Rule
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with the "Navigable Waters Protection Rule" that provides a final definition of "waters of the United States," which ultimately narrows the scope of waters subject to federal regulation under the CWA. The Navigable Waters Protection Rule became effective in June 2020. In November 2021, in response to the January 2021 Executive Orders, the EPA and USACE announced the availability of a pre-publication version of a proposed rule that restores the protections in place prior to the WOTUS Rule and establishes a new expansive definition of "waters of the United States."
Idaho Power believes the repeal rule, the WOTUS Rule, the Navigable Waters Protection Rule, and the proposed new rule will continue to be challenged in court, but expects that, even if the WOTUS Rule is reinstated in Idaho or the expansive proposed new rule is enacted and should the revised definition take effect in Idaho, while it may cause Idaho Power to incur additional permitting, regulatory requirements, and other costs associated with the rule, the aggregate amount of increased costs is unlikely to have a material adverse effect on Idaho Power's operations or financial condition, in part due to the relatively arid climate of Idaho Power's service area. Similarly, because the CWA, as interpreted even prior to the WOTUS Rule, applies to most of Idaho Power's facilities, including its hydropower plants, Idaho Power does not expect reinstatement would have a material impact on Idaho Power's operations or financial condition.
Section 401 Water Quality Certification: As described more fully under “Relicensing of Hydropower Projects” in the "Regulatory Matters" section of this MD&A, Idaho Power filed water quality certification applications, required under Section 401 of the CWA, with the states of Idaho and Oregon requesting that each state certify that any discharges from the HCC comply with applicable state water quality standards. The states issued final certifications in May 2019, after reaching a settlement with Idaho Power on fisheries-related matters. The Oregon certification, however, was challenged in state court by third parties. Idaho Power intervened in one of those lawsuits and is closely monitoring the other. In December 2019, Idaho Power filed an Offer of Settlement with the FERC requesting specific language be included in the new HCC license based upon the fish settlement among Idaho, Oregon, and Idaho Power. During the first quarter of 2020, the FERC received several comments opposing the Offer of Settlement and its decision relating to the Offer of Settlement is pending as of the date of this report.
In July 2020, the EPA published a rule amending regulations intended to implement the CWA Section 401 water quality certification process. 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. District Court for the Northern District of California issued an order remanding and vacating the 2020 CWA Section 401 Order, which order applies nationwide, and requires a temporary return to the EPA's previous Section 401 of the CWA in effect since 1979. While the EPA finalizes a new certification rule, Idaho Power plans to continue to operate under the current CWA Section 401 regulations as described above.
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 past, and expects in the future, to incur costs and expenses associated with those permitting and compliance obligations, but as of the date of this report, Idaho Power is unable to estimate with any reasonable certainty those costs and expenses. Idaho Power also expects to incur additional expenses associated with the relicensing of its hydroelectric 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 disclosures. These estimates often involve judgment about factors that are difficult to predict and are beyond management’s control. Management adjusts these estimates based on historical experience and on other assumptions and factors that are believed to be reasonable under the circumstances. Actual amounts could materially differ from the estimates. Management believes the accounting policies and estimates discussed below are the most critical to the portrayal of their financial condition and results of operations and require management’s most difficult, subjective, or complex judgments, often as a result of the need to make estimates about the effect of matters that are inherently uncertain and may change in subsequent periods.
Accounting for Rate Regulation
Entities that meet specific conditions are required by GAAP to reflect the impact of regulatory decisions in their consolidated financial statements and to defer certain costs as regulatory assets until matching revenues can be recognized. Similarly, certain items must be deferred as regulatory liabilities. Idaho Power must satisfy three conditions to apply regulatory accounting: (1) an independent regulator must set rates; (2) the regulator must set the rates to cover specific costs of delivering service; and (3) the service area must lack competitive pressures to reduce rates below the rates set by the regulator.
Idaho Power has determined that it meets these conditions, and its financial statements reflect the effects of the different rate-making principles followed by the jurisdictions regulating Idaho Power. The primary effect of this policy is that Idaho Power had recorded approximately $1.5 billion of regulatory assets and $0.8 billion of regulatory liabilities at December 31, 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 plans for certain senior management employees and directors called the Security Plan for Senior Management Employees I and Security Plan for Senior Management Employees II (together, SMSP), and a postretirement benefit plan (consisting of health care and death benefits).
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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, 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 2022 defined benefit plan pension expense will be increased to 3.05 percent from the 2.80 percent rate used in 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 2022 pension expense will be 7.4 percent, the same assumption as used in 2021.
Total net periodic pension and other postretirement benefit cost for these plans totaled $65.6 million and $53.8 million for the years ended December 31, 2021 and 2020, respectively, including amounts deferred as regulatory assets (see discussion below) and amounts allocated to capitalized labor. For 2022, total net periodic pension costs and other postretirement benefit costs are expected to total approximately $45.4 million, which takes into account the change in the discount rate noted above.
Had different actuarial assumptions been used, net periodic pension costs and other postretirement benefit costs could have varied significantly. The following table reflects the sensitivities associated with changes in the discount rate and rate-of-return on plan assets actuarial assumptions on historical and future net periodic pension costs and other postretirement benefit costs:
| Discount rate | Rate of return | |||||||||||||||||||||||||
| 2022 | 2021 | 2022 | 2021 | |||||||||||||||||||||||
| (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 costs | 12.1 | 12.3 | 5.1 | 4.5 | ||||||||||||||||||||||
Additionally, a 0.5 percent increase in the plans' discount rates would have resulted in a $119.4 million decrease in the combined benefit obligations of the plans as of December 31, 2021. A 0.5 percent decrease in the plans' discount rates would have resulted in an $135.9 million increase in the combined benefit obligations of the plans as of December 31, 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, 2021, a total of $234 million of expense was deferred as a regulatory asset. Idaho Power expects to defer approximately $16 million of expense in 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 2021 and 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
There have been no recently issued accounting pronouncements that have had or are expected to have a material impact on IDACORP's or Idaho Power's results of operations or financial condition. See Note 1 - “Summary of Significant Accounting Policies” to the consolidated financial statements included in this report for a summary of significant accounting policies.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
IDACORP and Idaho Power are exposed to market risks, including changes in interest rates, changes in commodity prices, credit risk, and equity price risk. The following discussion summarizes these risks and the financial instruments, derivative instruments, and derivative commodity instruments sensitive to changes in interest rates, commodity prices, and equity prices that were held at December 31, 2021. 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, 2021, IDACORP had no net floating rate debt, as the carrying value of short-term investments exceeded the carrying value of outstanding variable-rate debt. As of December 31, 2021, Idaho Power had $13.9 million of net 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 $2.0 billion in fixed rate debt, with a fair market value of approximately $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 $234.7 million if market interest rates were to decline by one percentage point from their December 31, 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. To supplement its power supply resources and balance its supply of power with the demand of its retail customers, Idaho Power participates in the wholesale marketplace. Purchased power arrangements allow Idaho Power to respond to fluctuations in the demand for electricity and variability in generating plant operations. Idaho Power also enters into arrangements for the purchase of fuel for natural gas and coal-fired generating plants. These contracts for the purchase of power and fuel expose Idaho Power to commodity price risk. The effects of changes in commodity prices on Idaho 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 an 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 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), composed of Idaho Power officers and senior managers, oversees the risk management program. The RMC is responsible for communicating the status of risk management activities to Idaho Power's 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 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, 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, 2021, the amount of collateral that could be requested upon a downgrade to below investment grade was approximately $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
Index to Financial Statements and Financial Statement Schedules
| Consolidated Financial Statements | Page | ||||
| IDACORP, Inc.: | |||||
| Consolidated Statements of Income | |||||
| Consolidated Statements of Comprehensive Income | |||||
| Consolidated Balance Sheets | |||||
| Consolidated Statements of Cash Flows | |||||
| Consolidated Statements of Equity | |||||
| Idaho Power Company: | |||||
| Consolidated Statements of Income | |||||
| Consolidated Statements of Comprehensive Income | |||||
| Consolidated Balance Sheets | |||||
| Consolidated Statements of Cash Flows | |||||
| Consolidated Statements of Retained Earnings | |||||
| Notes to the Consolidated Financial Statements | |||||
Reports of Independent Registered Public Accounting Firm - Deloitte & Touche LLP (PCAOB ID No. 34) | |||||
| Financial Statement Schedules | |||||
| IDACORP, Inc. - Schedule I - Condensed Financial Information of Registrant | |||||
| IDACORP, Inc. and Idaho Power Company - Schedule II - Consolidated Valuation and Qualifying Accounts | |||||
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
Consolidated Statements of Income
| Year Ended December 31, | ||||||||||||||||||||
| 2021 | 2020 | 2019 | ||||||||||||||||||
| (thousands of dollars except for per share amounts) | ||||||||||||||||||||
| Operating Revenues: | ||||||||||||||||||||
| Electric utility revenues | $ | 1,455,410 | $ | 1,347,340 | $ | 1,342,940 | ||||||||||||||
| Other | 2,674 | 3,389 | 3,443 | |||||||||||||||||
| Total operating revenues | 1,458,084 | 1,350,729 | 1,346,383 | |||||||||||||||||
| Operating Expenses: | ||||||||||||||||||||
| Electric utility: | ||||||||||||||||||||
| Purchased power | 393,691 | 297,417 | 285,266 | |||||||||||||||||
| Fuel expense | 180,550 | 172,740 | 156,872 | |||||||||||||||||
| Power cost adjustment | (49,844) | (33,708) | 2,047 | |||||||||||||||||
| Other operations and maintenance | 361,297 | 352,071 | 355,770 | |||||||||||||||||
| Energy efficiency programs | 29,920 | 42,478 | 40,128 | |||||||||||||||||
| Depreciation | 175,555 | 171,648 | 169,210 | |||||||||||||||||
| Other electric utility operating expenses | 34,673 | 35,914 | 35,995 | |||||||||||||||||
| Total electric utility expenses | 1,125,842 | 1,038,560 | 1,045,288 | |||||||||||||||||
| Other | 2,591 | 2,648 | 2,769 | |||||||||||||||||
| Total operating expenses | 1,128,433 | 1,041,208 | 1,048,057 | |||||||||||||||||
| Operating Income | 329,651 | 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 debt | 84,145 | 84,251 | 82,457 | |||||||||||||||||
| Other interest | 14,546 | 14,753 | 14,721 | |||||||||||||||||
| Allowance for borrowed funds used during construction | (11,993) | (11,578) | (10,703) | |||||||||||||||||
| Other (income) expense, net | 3,141 | (3,509) | (6,502) | |||||||||||||||||
| Total nonoperating expense, net | 46,867 | 42,853 | 40,491 | |||||||||||||||||
| Income Before Income Taxes | 282,784 | 266,668 | 257,835 | |||||||||||||||||
| Income Tax Expense | 36,912 | 28,700 | 24,507 | |||||||||||||||||
| Net Income | 245,872 | 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 | ||||||||||||||
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, | ||||||||||||||||||||
| 2021 | 2020 | 2019 | ||||||||||||||||||
| (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 Income | 249,190 | 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 | ||||||||||||||
The accompanying notes are an integral part of these statements.
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IDACORP, Inc.
Consolidated Balance Sheets
| December 31, | ||||||||||||||
| 2021 | 2020 | |||||||||||||
| (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 receivable | 14,770 | 2,164 | ||||||||||||
| Accrued unbilled revenues | 74,843 | 72,461 | ||||||||||||
| Materials and supplies (at average cost) | 77,552 | 64,941 | ||||||||||||
| Fuel stock (at average cost) | 18,045 | 31,646 | ||||||||||||
| Prepayments | 24,676 | 20,184 | ||||||||||||
| Current regulatory assets | 71,223 | 63,407 | ||||||||||||
| Other | 5,708 | 1,995 | ||||||||||||
| Total current assets | 595,873 | 642,401 | ||||||||||||
| Investments | 123,824 | 126,948 | ||||||||||||
| Property, Plant and Equipment: | ||||||||||||||
| Utility plant in service | 6,509,316 | 6,283,790 | ||||||||||||
| Accumulated provision for depreciation | (2,298,951) | (2,193,831) | ||||||||||||
| Utility plant in service - net | 4,210,365 | 4,089,959 | ||||||||||||
| Construction work in progress | 670,585 | 597,152 | ||||||||||||
| Utility plant held for future use | 4,511 | 4,109 | ||||||||||||
| Other property, net of accumulated depreciation | 16,361 | 18,290 | ||||||||||||
| Property, plant and equipment - net | 4,901,822 | 4,709,510 | ||||||||||||
| Other Assets: | ||||||||||||||
| Company-owned life insurance | 67,343 | 62,382 | ||||||||||||
| Regulatory assets | 1,462,431 | 1,495,488 | ||||||||||||
| Other | 59,222 | 58,515 | ||||||||||||
| Total other assets | 1,588,996 | 1,616,385 | ||||||||||||
| Total | $ | 7,210,515 | $ | 7,095,244 | ||||||||||
The accompanying notes are an integral part of these statements.
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IDACORP, Inc.
Consolidated Balance Sheets
| December 31, | ||||||||||||||
| 2021 | 2020 | |||||||||||||
| (in thousands) | ||||||||||||||
| Liabilities and Equity | ||||||||||||||
| Current Liabilities: | ||||||||||||||
| Accounts payable | $ | 145,980 | $ | 120,576 | ||||||||||
| Taxes accrued | 14,229 | 19,508 | ||||||||||||
| Interest accrued | 23,959 | 24,030 | ||||||||||||
| Accrued compensation | 55,666 | 52,245 | ||||||||||||
| Current regulatory liabilities | 11,239 | 11,104 | ||||||||||||
| Advances from customers | 43,472 | 29,341 | ||||||||||||
| Other | 31,079 | 30,767 | ||||||||||||
| Total current liabilities | 325,624 | 287,571 | ||||||||||||
| Other Liabilities: | ||||||||||||||
| Deferred income taxes | 842,375 | 800,251 | ||||||||||||
| Regulatory liabilities | 781,695 | 757,730 | ||||||||||||
| Pension and other postretirement benefits | 521,462 | 634,070 | ||||||||||||
| Other | 63,485 | 48,752 | ||||||||||||
| Total other liabilities | 2,209,017 | 2,240,803 | ||||||||||||
| Long-Term Debt | 2,000,640 | 2,000,414 | ||||||||||||
| Commitments and Contingencies | ||||||||||||||
| 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 earnings | 1,833,580 | 1,734,103 | ||||||||||||
| Accumulated other comprehensive loss | (40,040) | (43,358) | ||||||||||||
| Total IDACORP, Inc. shareholders’ equity | 2,668,436 | 2,559,980 | ||||||||||||
| Noncontrolling interests | 6,798 | 6,476 | ||||||||||||
| Total equity | 2,675,234 | 2,566,456 | ||||||||||||
| Total | $ | 7,210,515 | $ | 7,095,244 | ||||||||||
| 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, | ||||||||||||||||||||
| 2021 | 2020 | 2019 | ||||||||||||||||||
| (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 amortization | 179,444 | 175,941 | 173,800 | |||||||||||||||||
| Deferred income taxes and investment tax credits | 23,901 | 25,175 | 22,389 | |||||||||||||||||
| Changes in regulatory assets and liabilities | (33,705) | (36,246) | (4,310) | |||||||||||||||||
| Pension and postretirement benefit plan expense | 33,817 | 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 investments | 11,711 | 14,477 | 21,800 | |||||||||||||||||
| Allowance for equity funds used during construction | (31,537) | (29,551) | (27,112) | |||||||||||||||||
| Other adjustments to net income, net | 8,929 | 10,457 | 8,040 | |||||||||||||||||
| Change in: | ||||||||||||||||||||
| Accounts receivable | (6,697) | (374) | (5,996) | |||||||||||||||||
| Accounts payable and other accrued liabilities | 17,700 | (356) | (9,526) | |||||||||||||||||
| Taxes accrued/receivable | (17,885) | 8,950 | 742 | |||||||||||||||||
| Other current assets | (8,327) | 4,910 | (8,820) | |||||||||||||||||
| Other current liabilities | 3,102 | 7,996 | (799) | |||||||||||||||||
| Other assets | (10,764) | (5,546) | (4,375) | |||||||||||||||||
| Other liabilities | 3,358 | 2,034 | 555 | |||||||||||||||||
| Net cash provided by operating activities | 363,264 | 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 partners | 5,876 | 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 investment | 14,439 | 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 investments | 50,000 | — | — | |||||||||||||||||
| Proceeds from sale of equity securities | 11,328 | 25,795 | 5,080 | |||||||||||||||||
| Other | 2,037 | 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 year | 275,116 | 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 | ||||||||||||||
The accompanying notes are an integral part of these statements.
86
IDACORP, Inc.
Consolidated Statements of Equity
| Year Ended December 31, | ||||||||||||||||||||
| 2021 | 2020 | 2019 | ||||||||||||||||||
| (thousands of dollars) | ||||||||||||||||||||
| Common Stock: | ||||||||||||||||||||
| Balance at beginning of year | $ | 869,235 | $ | 868,307 | $ | 863,593 | ||||||||||||||
| Share-based compensation expense | 8,583 | 7,416 | 8,788 | |||||||||||||||||
| Tax withholdings on net settlements of share-based awards | (3,031) | (4,641) | — | |||||||||||||||||
| Treasury shares issued | — | (1,920) | (4,172) | |||||||||||||||||
| Other | 109 | 73 | 98 | |||||||||||||||||
| Balance at end of year | 874,896 | 869,235 | 868,307 | |||||||||||||||||
| Retained Earnings: | ||||||||||||||||||||
| Balance at beginning of year | 1,734,103 | 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 year | 1,833,580 | 1,734,103 | 1,634,525 | |||||||||||||||||
| Accumulated Other Comprehensive (Loss) Income: | ||||||||||||||||||||
| Balance at beginning of year | (43,358) | (36,284) | (22,844) | |||||||||||||||||
| Unfunded pension liability adjustment (net of tax) | 3,318 | (7,074) | (13,440) | |||||||||||||||||
| Balance at end of year | (40,040) | (43,358) | (36,284) | |||||||||||||||||
| Treasury Stock: | ||||||||||||||||||||
| Balance at beginning of year | — | (1,920) | (1,932) | |||||||||||||||||
| Issued | — | 1,920 | 4,172 | |||||||||||||||||
| Acquired | — | — | (4,160) | |||||||||||||||||
| Balance at end of year | — | — | (1,920) | |||||||||||||||||
| Total IDACORP, Inc. shareholders’ equity at end of year | 2,668,436 | 2,559,980 | 2,464,628 | |||||||||||||||||
| Noncontrolling Interests: | ||||||||||||||||||||
| Balance at beginning of year | 6,476 | 5,925 | 5,451 | |||||||||||||||||
| Net income attributable to noncontrolling interests | 322 | 551 | 474 | |||||||||||||||||
| Balance at end of year | 6,798 | 6,476 | 5,925 | |||||||||||||||||
| Total equity at end of year | $ | 2,675,234 | $ | 2,566,456 | $ | 2,470,553 | ||||||||||||||
The accompanying notes are an integral part of these statements.
87
Idaho Power Company
Consolidated Statements of Income
| Year Ended December 31, | ||||||||||||||||||||
| 2021 | 2020 | 2019 | ||||||||||||||||||
| (thousands of dollars) | ||||||||||||||||||||
| Operating Revenues | $ | 1,455,410 | $ | 1,347,340 | $ | 1,342,940 | ||||||||||||||
| Operating Expenses: | ||||||||||||||||||||
| Operation: | ||||||||||||||||||||
| Purchased power | 393,691 | 297,417 | 285,266 | |||||||||||||||||
| Fuel expense | 180,550 | 172,740 | 156,872 | |||||||||||||||||
| Power cost adjustment | (49,844) | (33,708) | 2,047 | |||||||||||||||||
| Other operations and maintenance | 361,297 | 352,071 | 355,770 | |||||||||||||||||
| Energy efficiency programs | 29,920 | 42,478 | 40,128 | |||||||||||||||||
| Depreciation | 175,555 | 171,648 | 169,210 | |||||||||||||||||
| Other operating expenses | 34,673 | 35,914 | 35,995 | |||||||||||||||||
| Total operating expenses | 1,125,842 | 1,038,560 | 1,045,288 | |||||||||||||||||
| Operating Income | 329,568 | 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 debt | 84,145 | 84,251 | 82,457 | |||||||||||||||||
| Other interest | 14,511 | 14,716 | 14,658 | |||||||||||||||||
| Allowance for borrowed funds used during construction | (11,993) | (11,578) | (10,703) | |||||||||||||||||
| Other (income) expense, net | 3,171 | (2,739) | (4,217) | |||||||||||||||||
| Total nonoperating expense, net | 48,086 | 44,997 | 44,798 | |||||||||||||||||
| Income Before Income Taxes | 281,482 | 263,783 | 252,854 | |||||||||||||||||
| Income Tax Expense | 38,257 | 30,548 | 28,417 | |||||||||||||||||
| Net Income | $ | 243,225 | $ | 233,235 | $ | 224,437 | ||||||||||||||
The accompanying notes are an integral part of these statements.
88
Idaho Power Company
Consolidated Statements of Comprehensive Income
| Year Ended December 31, | ||||||||||||||||||||
| 2021 | 2020 | 2019 | ||||||||||||||||||
| (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 | ||||||||||||||
The accompanying notes are an integral part of these statements.
89
Idaho Power Company
Consolidated Balance Sheets
| December 31, | ||||||||||||||
| 2021 | 2020 | |||||||||||||
| (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 receivable | 15,328 | 4,667 | ||||||||||||
| Accrued unbilled revenues | 74,843 | 72,461 | ||||||||||||
| Materials and supplies (at average cost) | 77,552 | 64,941 | ||||||||||||
| Fuel stock (at average cost) | 18,045 | 31,646 | ||||||||||||
| Prepayments | 24,558 | 20,057 | ||||||||||||
| Current regulatory assets | 71,223 | 63,407 | ||||||||||||
| Other | 5,708 | 1,995 | ||||||||||||
| Total current assets | 440,285 | 510,061 | ||||||||||||
| Investments | 77,108 | 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 - net | 4,210,365 | 4,089,959 | ||||||||||||
| Construction work in progress | 670,585 | 597,152 | ||||||||||||
| Plant held for future use | 4,511 | 4,109 | ||||||||||||
| Other property | 3,647 | 5,123 | ||||||||||||
| Property, plant and equipment, net | 4,889,108 | 4,696,343 | ||||||||||||
| Other Assets: | ||||||||||||||
| Company-owned life insurance | 67,343 | 62,382 | ||||||||||||
| Regulatory assets | 1,462,431 | 1,495,488 | ||||||||||||
| Other | 54,564 | 53,988 | ||||||||||||
| Total other assets | 1,584,338 | 1,611,858 | ||||||||||||
| Total | $ | 6,990,839 | $ | 6,906,110 | ||||||||||
The accompanying notes are an integral part of these statements.
90
Idaho Power Company
Consolidated Balance Sheets
| December 31, | ||||||||||||||
| 2021 | 2020 | |||||||||||||
| (in thousands) | ||||||||||||||
| Liabilities and Equity | ||||||||||||||
| Current Liabilities: | ||||||||||||||
| Accounts payable | $ | 145,871 | $ | 120,476 | ||||||||||
| Accounts payable to affiliates | 2,159 | 1,720 | ||||||||||||
| Taxes accrued | 14,316 | 19,554 | ||||||||||||
| Interest accrued | 23,959 | 24,030 | ||||||||||||
| Accrued compensation | 55,491 | 52,036 | ||||||||||||
| Current regulatory liabilities | 11,239 | 11,104 | ||||||||||||
| Advances from customers | 43,472 | 29,341 | ||||||||||||
| Other | 19,117 | 16,717 | ||||||||||||
| Total current liabilities | 315,624 | 274,978 | ||||||||||||
| Other Liabilities: | ||||||||||||||
| Deferred income taxes | 844,871 | 829,146 | ||||||||||||
| Regulatory liabilities | 781,695 | 757,730 | ||||||||||||
| Pension and other postretirement benefits | 521,462 | 634,070 | ||||||||||||
| Other | 62,245 | 45,937 | ||||||||||||
| Total other liabilities | 2,210,273 | 2,266,883 | ||||||||||||
| Long-Term Debt | 2,000,640 | 2,000,414 | ||||||||||||
| Commitments and Contingencies | ||||||||||||||
| 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 | 1,696,304 | 1,599,155 | ||||||||||||
| Accumulated other comprehensive loss | (40,040) | (43,358) | ||||||||||||
| Total equity | 2,464,302 | 2,363,835 | ||||||||||||
| Total | $ | 6,990,839 | $ | 6,906,110 | ||||||||||
| The accompanying notes are an integral part of these statements. | ||||||||||||||
91
Idaho Power Company
Consolidated Statements of Cash Flows
| Year Ended December 31, | ||||||||||||||||||||
| 2021 | 2020 | 2019 | ||||||||||||||||||
| (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 amortization | 178,847 | 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 expense | 33,804 | 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 investments | 10,211 | 12,627 | 19,450 | |||||||||||||||||
| Allowance for equity funds used during construction | (31,537) | (29,551) | (27,112) | |||||||||||||||||
| Other adjustments to net income, net | 346 | 3,041 | (748) | |||||||||||||||||
| Change in: | ||||||||||||||||||||
| Accounts receivable | (5,607) | (2,220) | (4,724) | |||||||||||||||||
| Accounts payable | 17,690 | (292) | (9,463) | |||||||||||||||||
| Taxes accrued/receivable | (15,899) | 12,685 | 2,281 | |||||||||||||||||
| Other current assets | (8,336) | 4,919 | (8,821) | |||||||||||||||||
| Other current liabilities | 3,133 | 8,072 | (870) | |||||||||||||||||
| Other assets | (10,809) | (5,588) | (4,280) | |||||||||||||||||
| Other liabilities | 3,443 | 2,116 | 584 | |||||||||||||||||
| Net cash provided by operating activities | 322,706 | 352,988 | 343,512 | |||||||||||||||||
| Investing Activities: | ||||||||||||||||||||
| Additions to utility plant | (299,972) | (310,937) | (278,707) | |||||||||||||||||
| Payments received from transmission project joint funding partners | 5,876 | 3,197 | 2,442 | |||||||||||||||||
| Distributions from equity-method investments, return of investment | 14,439 | 1,073 | — | |||||||||||||||||
| Purchase of equity securities | (15,823) | (33,382) | (10,896) | |||||||||||||||||
| Proceeds from the sale of equity securities | 11,328 | 25,795 | 5,080 | |||||||||||||||||
| Other | 2,231 | 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 year | 165,604 | 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 | ||||||||||||||
The accompanying notes are an integral part of these statements.
92
Idaho Power Company
Consolidated Statements of Retained Earnings
| Year Ended December 31, | ||||||||||||||||||||
| 2021 | 2020 | 2019 | ||||||||||||||||||
| (thousands of dollars) | ||||||||||||||||||||
| Retained Earnings, Beginning of Year | $ | 1,599,155 | $ | 1,503,805 | $ | 1,409,245 | ||||||||||||||
| Net Income | 243,225 | 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
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 hydropower 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 entity (VIE) for which the respective company is the primary beneficiary. Investments in VIEs for which the companies are not the primary beneficiaries, but have the ability to exercise significant influence over operating and financial policies, are accounted for using the equity method of accounting.
IDACORP also consolidates one VIE, Marysville Hydro Partners (Marysville), which is a joint venture owned 50 percent by Ida-West and 50 percent by Environmental Energy Company (EEC). At December 31, 2021, Marysville had approximately $16.0 million of assets, primarily a hydropower plant, and approximately $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 $22.7 million at December 31, 2021, and Idaho Power's maximum exposure to loss is the carrying value, any additional future contributions to BCC, and a $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 2 to 100 percent and were acquired between 1996 and 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 $35.0 million at December 31, 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.
94
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 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 one percent per month may be assessed on account balances after 30 days. An allowance is recorded for potential uncollectible accounts. The measurement of expected credit losses on Idaho Power accounts receivable is based on historical experience, current economic conditions, and forecasted information that may affect collections on the outstanding balance. Generally, this includes adjustments based upon a combination of historical write-off experience, aging of accounts receivable, an analysis of specific customer accounts, and an evaluation of whether there are current or forecasted economic conditions that might cause variation in collection from the historical experience. Adjustments are charged to income. Customer accounts receivable balances that remain outstanding after reasonable collection efforts are written off.
In response to the COVID-19 public health crisis, Idaho Power provided certain relief to customers, including temporarily suspending disconnections for customers and temporarily waiving late fees. This relief as well as the economic conditions
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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, | ||||||||||||||
| 2021 | 2020 | |||||||||||||
| Balance at beginning of period | $ | 4,766 | $ | 1,401 | ||||||||||
| Additions to the allowance | 2,017 | 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 receivables | 5.4 | % | 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, 2021 and 2020. Once a receivable is determined to be impaired, any further interest income recognized is fully reserved.
Derivative Financial Instruments
Financial instruments such as commodity futures, forwards, options, and swaps are used to manage exposure to commodity price risk in the electricity and natural gas markets. All derivative instruments are recognized as either assets or liabilities at fair value on the balance sheet unless they are designated as normal purchases and normal sales. With the exception of forward contracts for the purchase of natural gas for use at Idaho Power's natural gas generation facilities and a nominal number of power transactions, Idaho Power’s physical forward contracts are designated as normal purchases and normal sales. Because of Idaho Power’s regulatory accounting mechanisms, Idaho Power records the unrealized changes in fair value of derivative instruments related to power supply as regulatory assets or liabilities.
Revenues
Operating revenues are generally recorded when service is rendered or energy is delivered to customers. Idaho Power accrues estimated unbilled revenues for electric services delivered to customers but not yet billed at year-end. Idaho Power does not report any collections of franchise fees and similar taxes related to energy consumption on the income statement. In addition, regulatory mechanisms in place in Idaho and Oregon affect the reported amount of revenue. The effects of applying these regulatory mechanisms are discussed in more detail in Note 4 - "Revenues."
Property, Plant and Equipment and Depreciation
The cost of utility plant in service represents the original cost of contracted services, direct labor and material, allowance for funds used during construction (AFUDC), and indirect charges for engineering, supervision, and similar overhead items. Repair and maintenance costs associated with planned major maintenance are expensed as the costs are incurred, as are maintenance and repairs of property and replacements and renewals of items determined to be less than units of property. For utility property replaced or renewed, the original cost plus removal cost less salvage is charged to accumulated provision for depreciation, while the cost of related replacements and renewals is added to property, plant and equipment.
All utility plant in service is depreciated using the straight-line method at rates approved by regulatory authorities. Annual depreciation provisions as a percent of average depreciable utility plant in service approximated 2.9 percent in 2021, 2020, and 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, these costs are expensed in the period such determination is made. Idaho Power may seek recovery of these costs in customer rates, although there can be no guarantee such recovery would be granted.
Long-lived assets are periodically reviewed for impairment when events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If the sum of the undiscounted expected future cash flows from an asset is less than the carrying value of the asset, impairment is recognized in the financial statements. There were no material impairments of long-lived assets in 2021, 2020, or 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 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 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 tax expense or benefit for certain income tax temporary differences and instead recognizes the tax impact currently (commonly referred to as flow-through accounting) for rate making and financial reporting. Therefore, Idaho Power's effective income tax rate is impacted as these differences arise and reverse. Idaho Power recognizes such adjustments as regulatory assets or liabilities if it is probable that such amounts will be recovered from or returned to customers in future rates.
IDACORP and Idaho Power use judgment, estimation, and historical data in developing the provision for income taxes and the reporting of tax-related assets and liabilities, including development of current year tax depreciation, capitalized repair costs, capitalized overheads, and other items. Income taxes can be impacted by changes in tax laws and regulations, interpretations by taxing authorities, changes to accounting guidance, and actions by federal or state public utility regulators. Actual income taxes could vary from estimated amounts and may result in favorable or unfavorable impacts to net income, cash flows, and tax-related assets and liabilities.
In compliance with the federal income tax requirements for the use of accelerated tax depreciation, Idaho Power records deferred income taxes related to its plant assets for the difference between income tax depreciation and book depreciation used for financial statement purposes. Deferred income taxes are recorded for other temporary differences unless accounted for using flow-through.
Investment tax credits earned on regulated assets are deferred and amortized to income over the estimated service lives of the related properties.
Income taxes are discussed in more detail in Note 2 - "Income Taxes."
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Other Accounting Policies
Debt discount, expense, and premium are deferred and amortized over the terms of the respective debt issuances. Losses on reacquired debt and associated costs are amortized over the life of the associated replacement debt, as allowed under regulatory accounting.
New and Recently Adopted Accounting Pronouncements
There have been no recently issued accounting pronouncements that have had or are expected to have a material impact on IDACORP's or Idaho Power's consolidated financial statements.
2. INCOME TAXES
A reconciliation between the statutory federal income tax rate and the effective tax rate is as follows:
| IDACORP | Idaho Power | |||||||||||||||||||||||||||||||||||||
| 2021 | 2020 | 2019 | 2021 | 2020 | 2019 | |||||||||||||||||||||||||||||||||
| (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 interest | 1,077 | 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 benefit | 11,359 | 8,804 | 8,627 | 11,633 | 9,052 | 8,401 | ||||||||||||||||||||||||||||||||
| Depreciation | 14,233 | 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 adjustments | 3,169 | (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 amortization | 4,095 | 3,754 | 1,825 | — | — | — | ||||||||||||||||||||||||||||||||
| Other, net | 804 | (154) | (1,114) | 331 | 319 | (560) | ||||||||||||||||||||||||||||||||
| Total income tax expense | $ | 36,912 | $ | 28,700 | $ | 24,507 | $ | 38,257 | $ | 30,548 | $ | 28,417 | ||||||||||||||||||||||||||
| Effective tax rate | 13.1% | 10.8% | 9.5% | 13.6% | 11.6% | 11.2% | ||||||||||||||||||||||||||||||||
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The items comprising income tax expense are as follows:
| IDACORP | Idaho Power | |||||||||||||||||||||||||||||||||||||
| 2021 | 2020 | 2019 | 2021 | 2020 | 2019 | |||||||||||||||||||||||||||||||||
| (thousands of dollars) | ||||||||||||||||||||||||||||||||||||||
| Income taxes current: | ||||||||||||||||||||||||||||||||||||||
| Federal | $ | 15,210 | $ | 7,800 | $ | 8,830 | $ | 40,525 | $ | 30,464 | $ | 25,338 | ||||||||||||||||||||||||||
| State | 6,630 | 3,215 | 4,865 | 12,932 | 6,409 | (4,392) | ||||||||||||||||||||||||||||||||
| Total | 21,840 | 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) | ||||||||||||||||||||||||||||||||
| State | 1,154 | (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: | ||||||||||||||||||||||||||||||||||||||
| Deferred | 14,698 | 5,727 | 8,268 | 14,698 | 5,727 | 8,268 | ||||||||||||||||||||||||||||||||
| Restored | (2,866) | (2,906) | (6,252) | (2,866) | (2,906) | (6,252) | ||||||||||||||||||||||||||||||||
| Total | 11,832 | 2,821 | 2,016 | 11,832 | 2,821 | 2,016 | ||||||||||||||||||||||||||||||||
| Real estate-related investments at IFS | 3,873 | 4,735 | (1,849) | — | — | — | ||||||||||||||||||||||||||||||||
| Total income tax expense | $ | 36,912 | $ | 28,700 | $ | 24,507 | $ | 38,257 | $ | 30,548 | $ | 28,417 | ||||||||||||||||||||||||||
The components of the net deferred tax liability are as follows:
| IDACORP | Idaho Power | |||||||||||||||||||||||||
| 2021 | 2020 | 2021 | 2020 | |||||||||||||||||||||||
| (thousands of dollars) | ||||||||||||||||||||||||||
| Deferred tax assets: | ||||||||||||||||||||||||||
| Regulatory liabilities | $ | 96,880 | $ | 95,883 | $ | 96,880 | $ | 95,883 | ||||||||||||||||||
| Deferred compensation | 23,333 | 22,576 | 23,333 | 22,576 | ||||||||||||||||||||||
| Deferred revenue | 48,318 | 43,525 | 48,318 | 43,525 | ||||||||||||||||||||||
| Tax credits | 41,896 | 61,707 | 35,781 | 30,215 | ||||||||||||||||||||||
| Partnership investments | 12,265 | 10,189 | 11,949 | 7,211 | ||||||||||||||||||||||
| Retirement benefits | 110,997 | 142,864 | 110,997 | 142,864 | ||||||||||||||||||||||
| Other | 17,066 | 15,005 | 16,893 | 14,792 | ||||||||||||||||||||||
| Total | 350,755 | 391,749 | 344,151 | 357,066 | ||||||||||||||||||||||
| Deferred tax liabilities: | ||||||||||||||||||||||||||
| Property, plant and equipment | 272,530 | 282,983 | 272,530 | 282,983 | ||||||||||||||||||||||
| Regulatory assets | 721,276 | 687,628 | 721,276 | 687,628 | ||||||||||||||||||||||
| Partnership investments | 2,824 | 3,257 | — | — | ||||||||||||||||||||||
| Retirement benefits | 138,154 | 164,399 | 138,154 | 164,399 | ||||||||||||||||||||||
| Other | 58,346 | 53,733 | 57,062 | 51,202 | ||||||||||||||||||||||
| Total | 1,193,130 | 1,192,000 | 1,189,022 | 1,186,212 | ||||||||||||||||||||||
| Net deferred tax liabilities | $ | 842,375 | $ | 800,251 | $ | 844,871 | $ | 829,146 | ||||||||||||||||||
IDACORP's tax allocation agreement provides that each member of its consolidated group compute its income taxes on a separate company basis. Amounts payable or refundable are settled through IDACORP and are reported as taxes accrued or income taxes receivable, respectively, on the consolidated balance sheets of Idaho Power. See Note 1 - "Summary of Significant Accounting Policies" for further discussion of accounting policies related to income taxes.
Tax Credit Carryforwards
As of December 31, 2021, IDACORP had $41.9 million of Idaho investment tax credit carryforwards, which expire from 2026 to 2035.
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Uncertain Tax Positions
IDACORP and Idaho Power believe that they have no material income tax uncertainties for 2021 and prior tax years. Both companies recognize interest accrued related to unrecognized tax benefits as interest expense and penalties as other expense.
IDACORP and Idaho Power are subject to examination by their major tax jurisdictions - United States federal and the State of Idaho. The open tax years for examination are 2020-2021 for federal and 2016-2021 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. The IRS moved IDACORP from the maintenance phase of CAP to the bridge phase for both the 2020 and 2021 tax years.
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, 2021 | ||||||||||||||||||||||||||||||||
| Remaining Amortization Period | Earning a Return(1) | Not Earning a Return | Total as of December 31, | |||||||||||||||||||||||||||||
| Description | 2021 | 2020 | ||||||||||||||||||||||||||||||
| Regulatory Assets: | ||||||||||||||||||||||||||||||||
Income taxes(2) | $ | — | $ | 721,276 | $ | 721,276 | $ | 687,628 | ||||||||||||||||||||||||
Unfunded postretirement benefits(3) | — | 315,011 | 315,011 | 444,470 | ||||||||||||||||||||||||||||
Pension expense deferrals(4) | 197,623 | 36,814 | 234,437 | 200,686 | ||||||||||||||||||||||||||||
Energy efficiency program costs(5) | 7,622 | — | 7,622 | 13,225 | ||||||||||||||||||||||||||||
Power supply costs(6) | 2022-2023 | 42,940 | (9,411) | 33,529 | — | |||||||||||||||||||||||||||
Fixed cost adjustment(6) | 2022-2023 | 35,058 | 19,886 | 54,944 | 55,491 | |||||||||||||||||||||||||||
North Valmy plant settlements(6) | 2022-2028 | 97,852 | — | 97,852 | 103,085 | |||||||||||||||||||||||||||
Asset retirement obligations(7) | — | 22,585 | 22,585 | 19,035 | ||||||||||||||||||||||||||||
Wildfire Mitigation Plan deferral(6) | — | 6,075 | 6,075 | — | ||||||||||||||||||||||||||||
| Long-term service agreement | 2022-2043 | 14,046 | 9,227 | 23,273 | 24,431 | |||||||||||||||||||||||||||
| Other | 2022-2055 | 2,846 | 14,204 | 17,050 | 10,844 | |||||||||||||||||||||||||||
| Total | $ | 397,987 | $ | 1,135,667 | $ | 1,533,654 | $ | 1,558,895 | ||||||||||||||||||||||||
| Regulatory Liabilities: | ||||||||||||||||||||||||||||||||
Income taxes(8) | $ | — | $ | 96,880 | $ | 96,880 | $ | 95,883 | ||||||||||||||||||||||||
Depreciation-related excess deferred income taxes(9) | 170,039 | — | 170,039 | 178,997 | ||||||||||||||||||||||||||||
Removal costs(7) | — | 184,670 | 184,670 | 182,334 | ||||||||||||||||||||||||||||
| Investment tax credits | — | 109,460 | 109,460 | 97,627 | ||||||||||||||||||||||||||||
Deferred revenue-AFUDC(10) | 141,450 | 46,267 | 187,717 | 169,095 | ||||||||||||||||||||||||||||
Power supply costs(6) | — | — | — | 15,009 | ||||||||||||||||||||||||||||
Settlement agreement sharing mechanism(6) | 2022-2023 | 569 | — | 569 | — | |||||||||||||||||||||||||||
| Mark-to-market liabilities | — | 8,581 | 8,581 | 1,995 | ||||||||||||||||||||||||||||
Tax reform accrual for future amortization(11) | — | 24,522 | 24,522 | 16,893 | ||||||||||||||||||||||||||||
| Other | 4,697 | 5,799 | 10,496 | 11,001 | ||||||||||||||||||||||||||||
| 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 includes both the Idaho and Oregon jurisdiction balances at December 31, 2021 and 2020.
(6) This item is discussed in more detail in this Note 3 - "Regulatory Matters."
(7) Asset retirement obligations and removal costs are discussed in Note 14 - "Asset Retirement Obligations (ARO)."
(8) Represents the tax gross-up related to the depreciation-related excess deferred income taxes and investment tax credits included in this table and has a corresponding deferred tax asset disclosed in Note 2 - "Income Taxes."
(9) In 2017, income tax reform reduced deferred income tax assets and liabilities. For depreciation-related temporary differences under the normalized tax accounting method, the resulting excess deferred taxes will flow back to customers ratably over the remaining regulatory lives of Idaho Power's plant assets under the alternative method provided in the statute. The average rate assumption method was used to compute this reversal for fiscal years 2018-2020.
(10) Idaho Power is collecting revenue in the Idaho jurisdiction for AFUDC on HCC relicensing costs but is deferring revenue recognition of the amounts collected until the license is issued and the asset is placed in service under the new license.
(11) Represents amount accrued under the May 2018 Idaho Tax Reform Settlement 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 mechanisms compare Idaho Power's actual net power supply costs (primarily fuel and purchased power less wholesale energy sales) against net power supply costs being recovered in Idaho Power's retail rates. Under the power cost adjustment mechanisms, certain differences between actual net power supply costs incurred by Idaho Power and costs being recovered in retail rates are recorded as a deferred charge or credit on the balance sheets for future recovery or refund. The power supply costs deferred primarily result from changes in the levels of Idaho Power's own hydroelectric generation, changes in contracted power purchase prices and volumes, changes in wholesale market prices and transaction volumes, and changes in fuel prices.
Idaho Jurisdiction Power Cost Adjustment Mechanism: In the Idaho jurisdiction, the annual power cost adjustment (PCA) 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 Idaho Power (5 percent), with the exceptions of expenses associated with PURPA power purchases and demand response incentive payments, which are allocated 100 percent to customers; and
•a sales-based adjustment intended to ensure that power supply expense recovery resulting solely from sales 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, which also include non-PCA-related rate adjustments as ordered by the IPUC:
| 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. | |||||||||||
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. Oregon jurisdiction power supply cost changes under the APCU and PCAM during each of 2021, 2020, and 2019 did not have a material impact on the companies' financial statements.
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Notable Idaho Base Rate Adjustments
Idaho base rates were most recently established through a general rate case in 2012, and adjusted in 2014, 2017, 2018, and 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.
The 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.
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 below.
May 2018 Idaho Tax Reform Settlement Stipulation: In December 2017, the Tax Cuts and Jobs Act was signed into law, which, among other things, lowered the corporate federal income tax rate from 35 percent to 21 percent and modified or eliminated certain federal income tax deductions for corporations. In March 2018, Idaho House Bill 463 was signed into law reducing the Idaho state corporate income tax rate from 7.4 percent to 6.925 percent.
In May 2018, the IPUC issued an order approving a settlement stipulation (May 2018 Idaho Tax Reform Settlement Stipulation) related to income tax reform. Beginning June 1, 2018, the settlement stipulation provided an annual (a) $18.7 million reduction to Idaho customer base rates and (b) $7.4 million amortization of existing regulatory deferrals for specified items or future amortization of other existing or future unspecified regulatory deferrals that would otherwise be a future regulatory asset recoverable from Idaho customers. The May 2018 Idaho Tax Reform Settlement Stipulation also provided for the indefinite extension, with modifications noted in the table below, of the 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 became applicable 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 January 1, 2020, with no defined end date) | |||||||
If Idaho Power's actual annual Idaho ROE in any year is less than 9.5 percent, then Idaho Power may record additional ADITC amortization up to $25 million to help achieve a 9.5 percent Idaho ROE for that year, and may record additional ADITC amortization up to a total of $45 million over the 2015 through 2019 period. If the $45 million of ADITC are completely amortized, the revenue sharing provisions below would no longer be applicable. | If Idaho Power's actual annual Idaho ROE in any year is less than 9.4 percent, then Idaho Power may amortize up to $25 million of additional ADITC to help achieve a 9.4 percent Idaho ROE for that year, so long as the cumulative amount of ADITC used does not exceed $45 million (Idaho Power will have available and may continue to use any unused portion of the $45 million of additional ADITC from the October 2014 Idaho Earnings Support and Sharing Settlement Stipulation); however, Idaho Power may seek approval from the IPUC to replenish the total amount of ADITC it is permitted to amortize. If there are no remaining amounts of ADITC authorized to be amortized, the revenue sharing provisions below would not be applicable until ADITC is replenished. | |||||||
If Idaho Power's annual Idaho ROE in any year exceeds 10.0 percent, the amount of earnings exceeding a 10.0 percent Idaho ROE and up to and including a 10.5 percent Idaho ROE will be allocated 75 percent to Idaho Power's Idaho customers as a rate reduction to be effective at the time of the subsequent year's PCA, and 25 percent to Idaho Power. | If Idaho Power's annual Idaho ROE in any year exceeds 10.0 percent, the amount of earnings exceeding a 10.0 percent Idaho ROE and up to and including a 10.5 percent Idaho ROE will be allocated 80 percent to Idaho Power's Idaho customers as a rate reduction to be effective at the time of the subsequent year's PCA, and 20 percent to Idaho Power. | |||||||
If Idaho Power's annual Idaho ROE in any year exceeds 10.5 percent, the amount of earnings exceeding a 10.5 percent Idaho ROE will be allocated 50 percent to Idaho Power's Idaho customers as a rate reduction to be effective at the time of the subsequent year's PCA, 25 percent to Idaho Power's Idaho customers in the form of a reduction to the pension regulatory asset balancing account (to reduce the amount to be collected in the future from Idaho customers), and 25 percent to Idaho Power. | If Idaho Power's annual Idaho ROE in any year exceeds 10.5 percent, the amount of earnings exceeding a 10.5 percent Idaho ROE will be allocated 55 percent to Idaho Power's Idaho customers as a rate reduction to be effective at the time of the subsequent year's PCA, 25 percent to Idaho Power's Idaho customers in the form of a reduction to the pension regulatory asset balancing account (to reduce the amount to be collected in the future from Idaho customers), and 20 percent to Idaho Power. | |||||||
In the event the IPUC approves a change to Idaho Power's allowed annual Idaho ROE as part of a general rate case proceeding before December 31, 2019, the Idaho ROE thresholds will be adjusted on a prospective basis as follows: (a) the Idaho ROE under which Idaho Power will be permitted to amortize an additional amount of ADITC will be set at 95 percent of the newly authorized Idaho ROE, (b) sharing with customers on an 75 percent basis as a customer rate reduction will begin at the newly authorized Idaho ROE, and (c) sharing with customers on a 75 percent basis but allocated 50 percent to a rate reduction, and 25 percent to a pension expense deferral regulatory asset, will begin at 105 percent of the newly authorized Idaho ROE. | In the event the IPUC approves a change to Idaho Power's allowed annual Idaho ROE as part of a general rate case proceeding effective on or after January 1, 2020, the Idaho ROE thresholds will be adjusted on a prospective basis as follows: (a) the Idaho ROE under which Idaho Power will be permitted to amortize an additional amount of ADITC will be set at 95 percent of the newly authorized Idaho ROE, (b) sharing with customers on an 80 percent basis as a customer rate reduction will begin at the newly authorized Idaho ROE, and (c) sharing with customers on an 80 percent basis but allocated 55 percent to a rate reduction, and 25 percent to a pension expense deferral regulatory asset, will begin at 105 percent of the newly authorized Idaho ROE. | |||||||
The May 2018 Idaho Tax Reform Settlement Stipulation did not impose a moratorium on Idaho Power filing a general rate case or other form of rate proceeding in Idaho during its respective term.
In 2021, Idaho Power recorded a $0.6 million provision against current revenue for sharing with customers, as its full-year return on year-end equity in the Idaho jurisdiction (Idaho ROE) exceeded 10.0 percent. In 2020, Idaho Power recorded no provision against current revenue for sharing with customers, as its Idaho ROE was between 9.4 percent and 10.0 percent in 2020. Accordingly, at December 31, 2021, the full $45 million of additional ADITC remained available for future use under the terms of the May 2018 Idaho Tax Reform Settlement Stipulation.
Valmy Base Rate Adjustment Settlement 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. 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 no later than the end of 2025. The costs intended to be recovered by the increased jurisdictional revenues include current investments as of May 31, 2017, in both units, forecasted unit 1 investments from 2017 through 2019, and forecasted decommissioning costs for unit 1 and unit 2, offset by forecasted operation and maintenance costs
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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 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 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, 2028. In December 2019, as planned, Idaho Power ended its participation in coal-fired operations of North Valmy plant unit 1. In September 2021, the IPUC issued an order acknowledging Idaho Power's year-end 2025 exit date from Valmy unit 2 is appropriate based on economics and reliability needs.
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 recovery of fixed 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 Year | Period Rates in Effect | Annual Amount (in millions) | ||||||||||||
| 2020 | June 1, 2021-May 31, 2022 | $38.3 | ||||||||||||
| 2019 | June 1, 2020-May 31, 2021 | $35.5 | ||||||||||||
| 2018 | June 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 levelized revenue requirement in the aggregate amount of $27.1 million, which included Idaho Power's share of all electric plant in service related to coal-fired operations at the Jim Bridger plant. The proposed adjustment in this application would result in an overall rate increase of 2.12 percent in Idaho. As of the date of this report, the case remains pending at the IPUC.
Notable Oregon Regulatory Matters
Oregon Base Rate Changes: Oregon base rates were most recently established in a general rate case in 2012. In February 2012, the Public Utility Commission of Oregon (OPUC) 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 deemed prudent Idaho Power's decision to pursue the end of its participation in coal-fired operations of unit 1 by the end of 2019 and approved Idaho Power's request to recover annual incremental accelerated depreciation relating to unit 1, ending December 31, 2019, resulting in a $2.5 million annualized revenue requirement. In October 2019, the OPUC approved the North Valmy plant agreement and authorized Idaho Power to adjust customer rates in Oregon, effective January 1, 2020, to reflect a decrease in the annual levelized revenue requirement of $3.2 million, which mostly relates to the decrease in depreciation expense and other costs associated with the December 2019 end of Idaho Power's participation in coal-fired operations of North Valmy plant unit 1.
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 Idaho and Oregon jurisdictions, Idaho Power and other stakeholders filed a joint motion for approval of a settlement stipulation adopting new depreciation rates and agreeing to no increase in the jurisdictional revenue requirement and no change in customer rates. In December 2021 and January 2022, respectively, the IPUC and OPUC approved Idaho Power's requests, which were effective January 1, 2022.
Federal Regulatory Matters - Open Access Transmission Tariff Rates
Idaho Power uses a formula rate for transmission service provided under its OATT, which allows transmission rates to be updated annually based primarily on actual financial and operational data Idaho Power files with the FERC and allows Idaho
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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 Period | OATT 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 | ||||||
Idaho Power's current OATT rate is based on a net annual transmission revenue requirement of $127.3 million, which represents the OATT formulaic determination of Idaho Power's net cost of providing OATT-based transmission service.
4. REVENUES
The following table provides a summary of electric utility operating revenues for IDACORP and Idaho Power (in thousands):
| Year Ended December 31, | ||||||||||||||||||||
| 2021 | 2020 | 2019 | ||||||||||||||||||
| Electric utility operating revenues: | ||||||||||||||||||||
| Revenue from contracts with customers | $ | 1,382,653 | $ | 1,286,637 | $ | 1,285,286 | ||||||||||||||
| Alternative revenue programs and derivative revenues | 72,757 | 60,703 | 57,654 | |||||||||||||||||
| Total electric utility operating revenues | $ | 1,455,410 | $ | 1,347,340 | $ | 1,342,940 | ||||||||||||||
Revenues from Contracts with Customers
Revenues from contracts with customers are primarily related to Idaho Power’s regulated tariff-based sales of energy or related services. Generally, tariff-based sales do not involve a written contract, but are classified as revenues from contracts with customers. Idaho Power assesses revenues on a contract-by-contract basis to determine the nature, amount, timing, and uncertainty, if any, of revenues being recognized. The following table presents revenues from contracts with customers disaggregated by revenue source (in thousands):
| Year Ended December 31, | ||||||||||||||||||||
| 2021 | 2020 | 2019 | ||||||||||||||||||
| 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 | |||||||||||||||||
| Industrial | 195,214 | 181,258 | 181,372 | |||||||||||||||||
| Irrigation | 168,664 | 154,791 | 135,850 | |||||||||||||||||
| Provision for sharing | (569) | — | — | |||||||||||||||||
Deferred revenue related to HCC relicensing AFUDC(2) | (8,780) | (8,780) | (8,780) | |||||||||||||||||
| Total retail revenues | 1,252,335 | 1,167,730 | 1,130,611 | |||||||||||||||||
Less: FCA mechanism revenues(1) | (36,242) | (35,952) | (36,923) | |||||||||||||||||
| Wholesale energy sales | 40,839 | 33,656 | 71,198 | |||||||||||||||||
| Transmission wheeling-related revenues | 67,997 | 51,592 | 53,828 | |||||||||||||||||
| Energy efficiency program revenues | 29,920 | 42,478 | 40,128 | |||||||||||||||||
| Other revenues from contracts with customers | 27,804 | 27,133 | 26,444 | |||||||||||||||||
| Total revenues from contracts with customers | $ | 1,382,653 | $ | 1,286,637 | $ | 1,285,286 | ||||||||||||||
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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) The IPUC allows Idaho Power to recover a portion of the AFUDC on construction work in progress related to the HCC relicensing process, even though the relicensing process is not yet complete and the costs have not been moved to electric plant in service. Idaho Power is collecting $8.8 million annually in the Idaho jurisdiction but is deferring revenue recognition of the amounts collected until the license is issued and the accumulated license costs approved for recovery are placed in service.
Retail Revenues: Idaho Power’s retail revenues primarily relate to the sale of electricity to customers based on regulated tariff-based prices. Idaho Power recognizes retail revenues in amounts for which it has the right to invoice the customer in the period when energy is delivered or services are provided to customers. The total energy price generally has a fixed component related to having service available and a usage-based component related to the demand, delivery, and consumption of energy. The revenues recognized reflect the consideration Idaho Power expects to be entitled to in exchange for energy and services. Retail customers are classified as residential, commercial, industrial, or irrigation. Approximately 95 percent of Idaho Power's retail revenue originates from customers located in Idaho, with the remainder originating from customers located in Oregon. Idaho Power’s retail customer rates are based on Idaho Power’s cost of service and are determined through general rate case proceedings, settlement stipulations, and other filings with the IPUC and OPUC. Changes in rates and changes in customer demand are typically the primary causes of fluctuations in retail revenue from period to period. The primary influences on changes in customer demand for electricity are weather, economic conditions (including growth in the number of Idaho Power customers), and energy efficiency. Idaho Power's utility revenues are not earned evenly during the year.
Retail revenues are billed monthly based on meter readings taken throughout the month. Payments for amounts billed are generally due from the customer within 15 days of billing. Idaho Power accrues estimated unbilled revenues for energy or related services delivered to customers but not yet billed at period-end based on actual meter readings at period-end and estimated rates.
Residential Customers: Idaho Power’s energy sales to residential customers typically peak during the winter 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 are small industrial companies, and public street and highway lighting accounts. Idaho Power’s commercial customers are less influenced by weather conditions than residential customers, although weather does still affect commercial customer energy use. Economic conditions, including manufacturing activity levels, and energy efficiency initiatives also affect energy use of commercial customers. In 2021, a return to more normal economic conditions for commercial customers compared with 2020 increased sales volumes on a per customer basis, as 2020 was affected by negative COVID-19-related business conditions.
Industrial Customers: Industrial customers consist of large industrial companies, including special contract customers. Energy use of industrial customers is primarily driven by economic conditions, with weather having little impact on this customer class. In 2021, a return to more normal economic conditions for industrial customers compared with 2020 increased sales volumes on a per customer basis, as 2020 was affected by negative COVID-19-related business conditions.
Irrigation Customers: Irrigation customers use electricity to operate irrigation pumps, primarily during the agricultural growing season. The amount and timing of precipitation as well as temperature levels affect the timing and amounts of sales to irrigation customers, with increased precipitation generally resulting in decreased sales.
Provision for Sharing: Idaho Power has regulatory settlement stipulations in Idaho that provide for the potential sharing between Idaho Power and its Idaho customers of Idaho-jurisdictional earnings in excess of 10.0 percent of Idaho ROE. Based on full-year 2021 Idaho ROE, Idaho Power recorded $0.6 million provision against current revenues for sharing of earnings with customers for 2021. During 2020 and 2019, no provision against current revenues for sharing of earnings with customers was recorded. The regulatory settlement stipulations are described further in Note 3 - "Regulatory Matters."
Wholesale Energy Sales: As a public utility under the Federal Power Act (FPA), 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 any of those factors may lead to lower wholesale energy sales.
Transmission Wheeling-Related Revenues: As a public utility under the FPA, Idaho Power has the authority to provide cost-based wholesale and retail access transmission services under its OATT. Services under the OATT are offered on a nondiscriminatory basis such that all potential customers have an equal opportunity to access the transmission system. Idaho Power’s transmission revenue is primarily related to third parties reserving capacity on Idaho Power’s transmission system to transmit electricity through Idaho Power’s service area. Reservations are predominantly short-term contracts or on-demand when available, but may be part of a long-term capacity contract. Transmission wheeling-related revenues consist of a single performance obligation satisfied as capacity on Idaho Power’s transmission system is provided to the third party. Transmission wheeling-related revenues are affected by changes in Idaho Power’s OATT rate and customer demand. Demand for transmission services can be affected by regional market factors, such as loads and generation of utilities in Idaho Power’s region.
Energy Efficiency Program Revenues: Idaho Power collects most of its energy efficiency program costs through an energy efficiency rider on customer bills. The rider collections are deferred until expenditures are incurred. Energy efficiency program expenditures funded through the rider are reported as an operating expense with an equal amount recognized in revenues, resulting in no net impact on earnings. Fewer energy efficiency projects were completed in 2021 due mostly to impacts of the COVID-19 public health crisis which decreased energy efficiency program revenues compared with prior years. The cumulative variance between expenditures and amounts collected through the rider is recorded as a regulatory asset or liability. A liability balance indicates that Idaho Power has collected more than it has spent, and an asset balance indicates that Idaho Power has spent more than it has collected. At December 31, 2021, Idaho Power's energy efficiency rider balances were a $6.9 million regulatory asset in the Idaho jurisdiction and a $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.
Alternative Revenue Programs and Other Revenues
While revenues from contracts with customers make up most of Idaho Power’s revenues, the IPUC has authorized the use of an additional regulatory mechanism, the Idaho FCA mechanism, which may increase or decrease tariff-based customer rates. The Idaho FCA mechanism is described in Note 3 - "Regulatory Matters." The FCA mechanism revenues include only the initial recognition of FCA revenues when they meet the regulator-specified conditions for recognition. Revenue from contracts with customers excludes the portion of the tariff price representing FCA revenues that Idaho Power initially recorded in prior periods when revenues met regulator-specified conditions. When Idaho Power includes those amounts in the price of utility service and billed to customers, Idaho Power records such amounts as recovery of the associated regulatory asset or liability and not as revenues.
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 derivative revenues (in thousands):
| Year Ended December 31, | ||||||||||||||||||||
| 2021 | 2020 | 2019 | ||||||||||||||||||
| Alternative revenue programs and derivative revenues: | ||||||||||||||||||||
| FCA mechanism revenues | $ | 36,242 | $ | 35,952 | $ | 36,923 | ||||||||||||||
| Derivative revenues | 36,515 | 24,751 | 20,731 | |||||||||||||||||
| Total alternative revenue programs and derivative revenues | $ | 72,757 | $ | 60,703 | $ | 57,654 | ||||||||||||||
IDACORP's Other Operating Revenues
Other operating revenues on IDACORP's consolidated statements of income are primarily comprised of revenues from IDACORP’s subsidiary, Ida-West. Ida-West operates small hydropower generation projects that satisfy the requirements of PURPA.
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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):
| 2021 | 2020 | |||||||||||||
| First mortgage bonds: | ||||||||||||||
2.50% Series due 2023 | $ | 75,000 | $ | 75,000 | ||||||||||
1.90% Series due 2030 | 80,000 | 80,000 | ||||||||||||
6.00% Series due 2032 | 100,000 | 100,000 | ||||||||||||
5.50% Series due 2033 | 70,000 | 70,000 | ||||||||||||
5.50% Series due 2034 | 50,000 | 50,000 | ||||||||||||
5.875% Series due 2034 | 55,000 | 55,000 | ||||||||||||
5.30% Series due 2035 | 60,000 | 60,000 | ||||||||||||
6.30% Series due 2037 | 140,000 | 140,000 | ||||||||||||
6.25% Series due 2037 | 100,000 | 100,000 | ||||||||||||
4.85% Series due 2040 | 100,000 | 100,000 | ||||||||||||
4.30% Series due 2042 | 75,000 | 75,000 | ||||||||||||
4.00% Series due 2043 | 75,000 | 75,000 | ||||||||||||
3.65% Series due 2045 | 250,000 | 250,000 | ||||||||||||
4.05% Series due 2046 | 120,000 | 120,000 | ||||||||||||
4.20% Series due 2048 | 450,000 | 450,000 | ||||||||||||
| Total first mortgage bonds | 1,800,000 | 1,800,000 | ||||||||||||
| Pollution control revenue bonds: | ||||||||||||||
1.45% Series due 2024(1) | 49,800 | 49,800 | ||||||||||||
1.70% Series due 2026(1) | 116,300 | 116,300 | ||||||||||||
| Variable Rate Series 2000 due 2027 | 4,360 | 4,360 | ||||||||||||
| Total pollution control revenue bonds | 170,460 | 170,460 | ||||||||||||
| American Falls bond guarantee | 19,885 | 19,885 | ||||||||||||
| Unamortized premium/discount and issuance costs | 10,295 | 10,069 | ||||||||||||
Total IDACORP and Idaho Power outstanding debt(2) | 2,000,640 | 2,000,414 | ||||||||||||
| Current maturities of long-term debt | — | — | ||||||||||||
| 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, 2021, to $1.966 billion.
(2) At both December 31, 2021 and 2020, the overall effective cost rate of Idaho Power's outstanding debt was 4.40 percent.
At December 31, 2021, the maturities for the aggregate amount of IDACORP and Idaho Power long-term debt outstanding were as follows (in thousands of dollars):
| 2022 | 2023 | 2024 | 2025 | 2026 | Thereafter | ||||||||||||||||||||||||||||||
| $ | — | $ | 75,000 | $ | 49,800 | $ | 19,885 | $ | 116,300 | $ | 1,729,360 | ||||||||||||||||||||||||
Long-Term Debt Issuances, Maturities, and Redemptions
In April 2020, Idaho Power issued $230.0 million in principal amount of 4.20% first mortgage bonds, secured medium term notes, Series K, maturing March 1, 2048. The bonds were issued at a reoffer yield of 3.422 percent, which resulted in a net premium of 13.0 percent and net proceeds to Idaho Power of $259.9 million. After this offering the aggregate principal amount of the 4.20% first mortgage bonds is $450 million.
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In 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, $75 million in principal amount of 2.95 percent first mortgage bonds, medium-term notes, Series H due in April 2022. In accordance with the redemption provisions of the notes, the redemption included Idaho Power's payment of a make-whole premium to the holders of the redeemed notes in the aggregate amount of $3.3 million.
In August 2020, Idaho Power redeemed $100 million in principal amount of 3.40 percent first mortgage bonds due in November 2020.
Idaho Power First Mortgage Bonds
Idaho Power's issuance of long-term indebtedness is subject to the approval of the IPUC, OPUC, and Wyoming Public Service Commission (WPSC). In April and May 2019, Idaho Power received orders from the IPUC, OPUC, and WPSC authorizing the company to issue and sell from time to time up to $500 million in aggregate principal amount of debt securities and first mortgage bonds, subject to conditions specified in the orders. Authority from the IPUC is effective through May 31, 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 interest rate limit of 7.0 percent.
In May 2019, Idaho Power filed a shelf registration statement with the SEC, which became effective upon filing, for the offer and sale of an unspecified principal amount of its first mortgage bonds. The issuance of first mortgage bonds requires that Idaho Power meet interest coverage and security provisions set forth in Idaho Power's Indenture of Mortgage and Deed of Trust, dated as of October 1, 1937, as amended and supplemented from time to time (Indenture). Future issuances of first mortgage bonds are subject to satisfaction of covenants and security provisions set forth in the Indenture, market conditions, regulatory authorizations, and covenants contained in other financing agreements.
In June 2020, Idaho Power entered into a selling agency agreement with six banks named in the agreement in
connection with the potential issuance and sale from time to time of up to $500 million aggregate principal amount of first
mortgage bonds, secured medium term notes, Series L (Series L Notes), under Idaho Power’s Indenture of Mortgage and Deed
of Trust, dated as of October 1, 1937, as amended and supplemented (Indenture). Also in June 2020, Idaho Power
entered into the Forty-ninth Supplemental Indenture, dated effective as of June 5, 2020, to the Indenture (Forty-ninth
Supplemental Indenture). The Forty-ninth Supplemental Indenture provides for, among other items, the issuance of up to
$500 million in aggregate principal amount of Series L Notes pursuant to the Indenture.
The mortgage of the Indenture secures all bonds issued under the Indenture equally and ratably, without preference, priority, or distinction. First mortgage bonds issued in the future will also be secured by the mortgage of the Indenture. The lien constitutes a first mortgage on all the properties of Idaho Power, subject only to certain limited exceptions including liens for taxes and assessments that are not delinquent and minor excepted encumbrances. Certain of the properties of Idaho Power are subject to easements, leases, contracts, covenants, workmen's compensation awards, and similar encumbrances and minor defects common to properties. The mortgage of the Indenture does not create a lien on revenues or profits, or notes or accounts receivable, contracts or choses in action, except as permitted by law during a completed default, securities, or cash, except when pledged, or merchandise or equipment manufactured or acquired for resale. The mortgage of the Indenture creates a lien on the interest of Idaho Power in property subsequently acquired, other than excepted property, subject to limitations in the case of consolidation, merger, or sale of all or substantially all of the assets of Idaho Power. The Indenture requires Idaho Power to spend or appropriate 15 percent of its annual gross operating revenues for maintenance, retirement, or amortization of its properties. Idaho Power may, however, anticipate or make up these expenditures or appropriations within the 5 years that immediately follow or precede a particular year.
The Forty-eighth Supplemental Indenture 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 2 years or that are of an equal or higher interest rate, or prior lien bonds.
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As of December 31, 2021, Idaho Power could issue under its Indenture approximately $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-ninth Supplemental Indenture. As a result, the maximum amount of first mortgage bonds Idaho Power could issue as of December 31, 2021, was limited to approximately $534 million under the Indenture.
6. NOTES PAYABLE
Credit Facilities
The IDACORP credit facility, which may be used for general corporate purposes and commercial paper backup, consists of a revolving line of credit not to exceed the aggregate principal amount at any one time outstanding of $100 million, including swingline loans in an aggregate principal amount at any time outstanding not to exceed $10 million, and letters of credit in an aggregate principal amount at any time outstanding not to exceed $50 million. The Idaho Power credit facility, which may be used for general corporate purpose and commercial paper backup, consists of a revolving line of credit, through the issuance of loans and standby letters of credit, not to exceed the aggregate principal amount at any one time outstanding of $300 million, including swingline loans in an aggregate principal amount at any time outstanding not to exceed $30 million, and letters of credit in an aggregate principal amount at any time outstanding not to exceed $50 million. IDACORP and Idaho Power have the right to request an increase in the aggregate principal amount of the facilities to $150 million and $450 million, respectively, in each case subject to certain conditions.
The IDACORP and Idaho Power credit facilities have similar terms and conditions. The interest rates for any borrowings under the facilities are based on either (1) a floating rate that is equal to the highest of the prime rate, federal funds rate plus 0.5 percent, or London interbank offered rate (LIBOR) Market Index rate plus 1.0 percent, or (2) the LIBOR Market Index rate, plus, in each case, an applicable margin, provided that the federal funds rate and LIBOR rate will not be less than zero. The Secured Overnight Financing Rate (SOFR) plus a defined benchmark adjustment would replace the LIBOR Market Index rate during any period in which the LIBOR rate is unavailable or unascertainable. If during any period both the LIBOR and SOFR rates are unavailable or unascertainable, an alternate benchmark rate selected by the administrative agent and the borrower would apply. The applicable margin is based on IDACORP's or Idaho Power's, as applicable, senior unsecured long-term indebtedness credit rating by rating agencies, as set forth on a schedule to the credit facility agreements. Under their respective credit facilities, the companies pay a facility fee on the commitment based on the respective company's credit rating for senior unsecured long-term debt securities. In December 2021, IDACORP and Idaho Power amended their outstanding credit agreements to extend the termination dates of each facility to December 6, 2025, and provided additional information on potential alternatives, successors or replacement rates for LIBOR in the event it is no longer available as of the date of borrowing, among other things. While the credit facilities provide for an original maturity date of December 6, 2025, the credit agreements grant IDACORP and Idaho Power the right to request up to two one-year extensions, subject to certain conditions.
At December 31, 2021, no loans were outstanding under either IDACORP's or Idaho Power's facilities. At December 31, 2021, Idaho Power had regulatory authority to incur up to $450 million in principal amount of short-term indebtedness at any one time outstanding through December of 2026. IDACORP’s and Idaho Power's short-term borrowings were zero at both December 31, 2021 and 2020.
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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, 2021:
| Shares issued | Shares reserved | |||||||||||||||||||||||||
| 2021 | 2020 | 2019 | December 31, 2021 | |||||||||||||||||||||||
| Balance at beginning of year | 50,461,885 | 50,420,017 | 50,420,017 | |||||||||||||||||||||||
| Continuous equity program (inactive) | — | — | — | 3,000,000 | ||||||||||||||||||||||
| Dividend reinvestment and stock purchase plan | — | — | — | 2,840,117 | ||||||||||||||||||||||
| Employee savings plan | — | — | — | 3,567,954 | ||||||||||||||||||||||
Long-term incentive and compensation plan(1) | 54,594 | 41,868 | — | 1,260,267 | ||||||||||||||||||||||
| Balance at end of year | 50,516,479 | 50,461,885 | 50,420,017 | |||||||||||||||||||||||
(1) During 2021, 2020, and 2019, IDACORP granted 76,147, 75,030, and 70,419 restricted stock unit awards, respectively, to employees and 14,025, 10,296, and 9,594 shares of common stock, respectively, to directors. During 2021 and 2020, IDACORP issued 54,594 and 41,868 shares of common stock, respectively, using original issuances of shares pursuant to the IDACORP, Inc. 2000 Long-Term Incentive and Compensation 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, 2021, the leverage ratios for IDACORP and Idaho Power were 43 percent and 45 percent, respectively. Based on these restrictions, IDACORP’s and Idaho Power’s dividends were limited to $1.6 billion and $1.4 billion, respectively, at December 31, 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, 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, 2021, Idaho Power's common equity capital was 55 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, 2021, the maximum number of shares available under the LTICP was 443,663.
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Restricted Stock and Performance-Based Shares Awards
Restricted Stock awards have -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:
| IDACORP | Idaho Power | |||||||||||||||||||||||||
| Number of Shares/Units | Weighted-Average Grant Date Fair Value | Number of Shares/Units | Weighted-Average Grant Date Fair Value | |||||||||||||||||||||||
| Nonvested shares/units at January 1, 2021 | 157,035 | $ | 100.89 | 156,013 | $ | 100.90 | ||||||||||||||||||||
| Shares/units granted | 96,345 | 87.76 | 95,821 | 87.76 | ||||||||||||||||||||||
| Shares/units forfeited | (2,210) | 98.72 | (2,210) | 98.72 | ||||||||||||||||||||||
| Shares/units vested | (75,914) | 87.24 | (75,415) | 87.24 | ||||||||||||||||||||||
| Nonvested shares/units at December 31, 2021 | 175,256 | $ | 99.61 | 174,209 | $ | 99.61 | ||||||||||||||||||||
The total fair value of shares vested was $6.7 million in 2021, $10.5 million in 2020, and $9.4 million in 2019. At December 31, 2021, IDACORP had $7.5 million of total unrecognized compensation cost related to nonvested share-based compensation, nearly all of which was Idaho Power's share. These costs are expected to be recognized over a weighted-average period of 1.7 years. IDACORP uses original issue shares for these awards.
In 2021, a total of 14,025 shares were awarded to directors at an average grant date fair value of $86.24 per share. Directors elected to defer receipt of 2,550 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):
| IDACORP | Idaho Power | |||||||||||||||||||||||||||||||||||||
| 2021 | 2020 | 2019 | 2021 | 2020 | 2019 | |||||||||||||||||||||||||||||||||
| Compensation cost | $ | 8,583 | $ | 7,416 | $ | 8,788 | $ | 8,497 | $ | 7,339 | $ | 8,639 | ||||||||||||||||||||||||||
| Income tax benefit | 2,209 | 1,909 | 2,262 | 2,187 | 1,889 | 2,224 | ||||||||||||||||||||||||||||||||
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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, 2021, 2020, and 2019 (in thousands, except for per share amounts):
| Year Ended December 31, | ||||||||||||||||||||
| 2021 | 2020 | 2019 | ||||||||||||||||||
| Numerator: | ||||||||||||||||||||
| Net income attributable to IDACORP, Inc. | $ | 245,550 | $ | 237,417 | $ | 232,854 | ||||||||||||||
| Denominator: | ||||||||||||||||||||
| Weighted-average common shares outstanding - basic | 50,599 | 50,538 | 50,502 | |||||||||||||||||
| Effect of dilutive securities | 46 | 34 | 35 | |||||||||||||||||
| Weighted-average common shares outstanding - diluted | 50,645 | 50,572 | 50,537 | |||||||||||||||||
| Basic earnings per share | $ | 4.85 | $ | 4.70 | $ | 4.61 | ||||||||||||||
| Diluted earnings per share | $ | 4.85 | $ | 4.69 | $ | 4.61 | ||||||||||||||
10. COMMITMENTS
Purchase Obligations
At December 31, 2021, Idaho Power had the following long-term commitments relating to purchases of energy, capacity, transmission rights, and fuel (in thousands of dollars):
| 2022 | 2023 | 2024 | 2025 | 2026 | Thereafter | |||||||||||||||||||||||||||||||||
| Cogeneration and power production | $ | 298,867 | $ | 308,741 | $ | 311,968 | $ | 296,579 | $ | 293,508 | $ | 2,456,582 | ||||||||||||||||||||||||||
| Fuel | 62,287 | 19,328 | 8,663 | 8,362 | 8,354 | 58,355 | ||||||||||||||||||||||||||||||||
As of December 31, 2021, Idaho Power had 1,137 megawatt (MW) nameplate capacity of PURPA-related projects on-line, with an additional 75 MW nameplate capacity of projects projected to be on-line by 2024. The power purchase contracts for these projects have original contract terms ranging from to 35 years. Idaho Power's expenses associated with PURPA-related projects were approximately $200 million in 2021, $194 million in 2020, and $187 million in 2019. In February 2022, Idaho Power entered into a 20-year power purchase agreement with a planned 40 MW solar facility expected to be in service in 2023 which increased Idaho Power's contractual purchase obligations by approximately $78 million over the term of the contract.
Idaho Power also has the following long-term commitments (in thousands of dollars):
| 2022 | 2023 | 2024 | 2025 | 2026 | Thereafter | |||||||||||||||||||||||||||||||||
Joint-operating agreement payments(1) | $ | 2,822 | $ | 2,822 | $ | 2,822 | $ | 2,822 | $ | 2,822 | $ | 14,110 | ||||||||||||||||||||||||||
| Easements and other payments | 1,925 | 1,965 | 2,006 | 2,049 | 2,092 | 11,136 | ||||||||||||||||||||||||||||||||
Maintenance and service agreements(1) | 97,847 | 13,522 | 10,134 | 6,319 | 6,592 | 46,764 | ||||||||||||||||||||||||||||||||
FERC and other industry-related fees(1) | 16,772 | 14,549 | 14,174 | 14,174 | 14,174 | 70,870 | ||||||||||||||||||||||||||||||||
(1) Approximately $28 million, $18 million, and $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 2021, 2020, and 2019.
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Guarantees
Idaho Power guarantees its portion of reclamation activities and obligations at BCC, of which IERCo owns a one-third interest. This guarantee, which is renewed annually with the WDEQ, was $51.6 million at December 31, 2021, representing IERCo's one-third share of BCC's total reclamation obligation of $154.7 million. BCC has a reclamation trust fund set aside specifically for the purpose of paying these reclamation costs. At December 31, 2021, the value of the reclamation trust fund was $211.2 million. During 2021, the reclamation trust fund made $21.1 million of distributions for reclamation activity costs associated with the BCC surface mine. BCC periodically assesses the adequacy of the reclamation trust fund and its estimate of future reclamation costs. To ensure that the reclamation trust fund maintains adequate reserves, BCC has the ability to, and does, add a per-ton surcharge to coal sales, all of which are made to the Jim Bridger plant. Because of the existence of the fund and the ability to apply a per-ton surcharge, the estimated fair value of this guarantee is minimal.
IDACORP and Idaho Power enter into financial agreements and power purchase and sale agreements that include indemnification provisions relating to various forms of claims or liabilities that may arise from the transactions contemplated by these agreements. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnification provisions cannot be reasonably estimated. IDACORP and Idaho Power periodically evaluate the likelihood of incurring costs under such indemnities based on their historical experience and the evaluation of the specific indemnities. As of December 31, 2021, 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. Idaho Power has also regularly received claims by governmental agencies and private landowners for damages for fires allegedly originating from Idaho Power’s transmission and distribution system. As of the date of this report, the companies believe that resolution of existing claims will not have a material adverse effect on their respective consolidated financial statements.
Idaho Power is also actively monitoring various pending environmental regulations and executive orders related to environmental matters that may have a significant impact on its future operations. Given uncertainties regarding the outcome, timing, and compliance plans for these environmental matters, Idaho Power is unable to estimate the financial impact of these regulations.
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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 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.
The following table summarizes the changes in benefit obligations and plan assets of these plans (in thousands of dollars):
| Pension Plan | SMSP | |||||||||||||||||||||||||
| 2021 | 2020 | 2021 | 2020 | |||||||||||||||||||||||
| Change in projected benefit obligation: | ||||||||||||||||||||||||||
| Benefit obligation at January 1 | $ | 1,337,395 | $ | 1,134,752 | $ | 134,791 | $ | 122,443 | ||||||||||||||||||
| Service cost | 54,202 | 42,987 | 813 | 213 | ||||||||||||||||||||||
| Interest cost | 37,317 | 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 31 | 1,346,530 | 1,337,395 | 133,012 | 134,791 | ||||||||||||||||||||||
| Change in plan assets: | ||||||||||||||||||||||||||
| Fair value at January 1 | 871,603 | 763,119 | — | — | ||||||||||||||||||||||
| Actual return on plan assets | 119,412 | 112,451 | — | — | ||||||||||||||||||||||
| Employer contributions | 40,000 | 40,000 | — | — | ||||||||||||||||||||||
| Benefits paid | (46,551) | (43,967) | — | — | ||||||||||||||||||||||
| Fair value at December 31 | 984,464 | 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 cost | 43 | 49 | 2,687 | 2,983 | ||||||||||||||||||||||
| Subtotal | 322,951 | 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 | ||||||||||||||||||
(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 $117.1 million and $108.8 million at December 31, 2021 and 2020, respectively, and is reflected in Investments and in company-owned life insurance on the consolidated balance sheets.
The following table shows the components of net periodic pension cost for these plans (in thousands of dollars). For purposes of calculating the expected return on plan assets, the market-related value of assets is equal to the fair value of the assets.
| Pension Plan | SMSP | |||||||||||||||||||||||||||||||||||||
| 2021 | 2020 | 2019 | 2021 | 2020 | 2019 | |||||||||||||||||||||||||||||||||
| Service cost | $ | 54,202 | $ | 42,987 | $ | 34,061 | $ | 813 | $ | 213 | $ | (181) | ||||||||||||||||||||||||||
| Interest cost | 37,317 | 40,013 | 42,312 | 3,557 | 4,350 | 4,575 | ||||||||||||||||||||||||||||||||
| Expected return on assets | (64,090) | (56,239) | (48,623) | — | — | — | ||||||||||||||||||||||||||||||||
| Amortization of net loss | 23,796 | 17,325 | 13,564 | 4,205 | 3,734 | 2,533 | ||||||||||||||||||||||||||||||||
| Amortization of prior service cost | 6 | 6 | 6 | 296 | 290 | 96 | ||||||||||||||||||||||||||||||||
| Net periodic pension cost | 51,231 | 44,092 | 41,320 | 8,871 | 8,587 | 7,023 | ||||||||||||||||||||||||||||||||
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 | — | — | — | ||||||||||||||||||||||||||||||||
Net periodic pension cost recognized for financial reporting(1)(2) | $ | 19,423 | $ | 19,204 | $ | 19,095 | $ | 8,871 | $ | 8,587 | $ | 7,023 | ||||||||||||||||||||||||||
(1) Net periodic pension costs for the pension plan are recognized for financial reporting based upon the authorization of each regulatory jurisdiction in which Idaho Power operates. Under IPUC order, the Idaho portion of net periodic pension cost is recorded as a regulatory asset and is recognized in the income statement as those costs are recovered through rates.
(2) Of total net periodic pension cost recognized for financial reporting $17.8 million, $15.9 million, and $15.1 million respectively, was recognized in "Other operations and maintenance" and $10.5 million, and $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, 2021, 2020, and 2019.
The following table shows the components of other comprehensive (loss) income for the plans (in thousands of dollars):
| Pension Plan | SMSP | |||||||||||||||||||||||||||||||||||||
| 2021 | 2020 | 2019 | 2021 | 2020 | 2019 | |||||||||||||||||||||||||||||||||
| 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 loss | 23,796 | 17,325 | 13,564 | 4,205 | 3,734 | 2,533 | ||||||||||||||||||||||||||||||||
| Amortization of prior service cost | 6 | 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) | ||||||||||||||||||||||||||
The following table summarizes the expected future benefit payments of these plans (in thousands of dollars):
| 2022 | 2023 | 2024 | 2025 | 2026 | 2026-2030 | |||||||||||||||||||||||||||||||||
| Pension Plan | $ | 45,239 | $ | 47,038 | $ | 48,890 | $ | 50,850 | $ | 52,855 | $ | 293,409 | ||||||||||||||||||||||||||
| SMSP | 6,226 | 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 the date of this report, IDACORP and Idaho Power have no estimated minimum required
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contributions to the pension plan for 2022. Depending on market conditions and cash flow considerations in 2022, Idaho Power could contribute up to $40 million to the pension plan during 2022 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):
| 2021 | 2020 | |||||||||||||
| Change in accumulated benefit obligation: | ||||||||||||||
| Benefit obligation at January 1 | $ | 80,952 | $ | 71,029 | ||||||||||
| Service cost | 1,063 | 1,029 | ||||||||||||
| Interest cost | 2,059 | 2,493 | ||||||||||||
| Actuarial (gain) loss | (5,805) | 9,359 | ||||||||||||
Benefits paid(1) | (4,194) | (2,958) | ||||||||||||
| Benefit obligation at December 31 | 74,075 | 80,952 | ||||||||||||
| Change in plan assets: | ||||||||||||||
| Fair value of plan assets at January 1 | 41,311 | 39,625 | ||||||||||||
| Actual return on plan assets | 6,308 | 5,248 | ||||||||||||
Employer contributions(1) | (1,961) | (604) | ||||||||||||
Benefits paid(1) | (4,194) | (2,958) | ||||||||||||
| Fair value of plan assets at December 31 | 41,464 | 41,311 | ||||||||||||
| Funded status at end of year (included in noncurrent liabilities) | $ | (32,611) | $ | (39,641) | ||||||||||
(1) Contributions and benefits paid are each net of $3.0 million and $3.4 million of plan participant contributions for 2021 and 2020, respectively.
Amounts recognized in accumulated other comprehensive income consist of the following (in thousands of dollars):
| 2021 | 2020 | |||||||||||||
| Net (gain) loss | $ | (8,020) | $ | 6,434 | ||||||||||
| Prior service cost | 80 | 127 | ||||||||||||
| Subtotal | (7,940) | 6,561 | ||||||||||||
| Less amount recognized in regulatory assets | 7,940 | (6,561) | ||||||||||||
| Net amount recognized in accumulated other comprehensive income | $ | — | $ | — | ||||||||||
The net periodic postretirement benefit cost was as follows (in thousands of dollars):
| 2021 | 2020 | 2019 | ||||||||||||||||||
| Service cost | $ | 1,063 | $ | 1,029 | $ | 853 | ||||||||||||||
| Interest cost | 2,059 | 2,493 | 2,989 | |||||||||||||||||
| Expected return on plan assets | (2,395) | (2,404) | (2,220) | |||||||||||||||||
Immediate recognition of loss from temporary deviation(1) | 4,736 | — | — | |||||||||||||||||
| Amortization of prior service cost | 47 | 47 | 48 | |||||||||||||||||
| Net periodic postretirement benefit cost | $ | 5,510 | $ | 1,165 | $ | 1,670 | ||||||||||||||
(1) In 2021, a loss associated with a temporary deviation from the cost-sharing provisions of the substantive plan was recognized in "Other (income) expense, net" on the consolidated statements of income of the companies.
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The following table shows the components of other comprehensive income for the plan (in thousands of dollars):
| 2021 | 2020 | 2019 | ||||||||||||||||||
| Actuarial gain (loss) during the year | $ | 9,718 | $ | (6,515) | $ | (249) | ||||||||||||||
| Reclassification adjustments for: | ||||||||||||||||||||
Immediate recognition of loss from temporary deviation(1) | 4,736 | — | — | |||||||||||||||||
| Reclassification adjustments for amortization of prior service cost | 47 | 47 | 48 | |||||||||||||||||
| Adjustment for deferred tax effects | (2,514) | 1,665 | 52 | |||||||||||||||||
Adjustment due to the effects of regulation | (11,987) | 4,803 | 149 | |||||||||||||||||
Other comprehensive income related to postretirement benefit plans | $ | — | $ | — | $ | — | ||||||||||||||
(1) In 2021, a loss associated with a temporary deviation from the cost-sharing provisions of the substantive plan was recognized in "Other (income) expense, net" on the consolidated statements of income of the companies.
The following table summarizes the expected future benefit payments of the postretirement benefit plan (in thousands of dollars):
| 2022 | 2023 | 2024 | 2025 | 2026 | 2026-2029 | |||||||||||||||||||||||||||||||||
| 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 | ||||||||||||||||||||||||||||||||||||
| 2021 | 2020 | 2021 | 2020 | 2021 | 2020 | |||||||||||||||||||||||||||||||||
| Discount rate | 3.05 | % | 2.80 | % | 3.00 | % | 2.70 | % | 2.95 | % | 2.70 | % | ||||||||||||||||||||||||||
Rate of compensation increase(1) | 4.49 | % | 4.43 | % | 4.75 | % | 4.75 | % | — | — | ||||||||||||||||||||||||||||
| Medical trend rate | — | — | — | — | 6.3 | % | 6.8 | % | ||||||||||||||||||||||||||||||
| Dental trend rate | — | — | — | — | 3.5 | % | 4.0 | % | ||||||||||||||||||||||||||||||
| Measurement date | 12/31/2021 | 12/31/2020 | 12/31/2021 | 12/31/2020 | 12/31/2021 | 12/31/2020 | ||||||||||||||||||||||||||||||||
(1) The 2021 rate of compensation increase assumption for the pension plan includes an inflation component of 2.40% plus a 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 0.6% 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 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
| 2021 | 2020 | 2019 | 2021 | 2020 | 2019 | 2021 | 2020 | 2019 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Discount rate | 2.80 | % | 3.60 | % | 4.55 | % | 2.70 | % | 3.65 | % | 4.60 | % | 2.70 | % | 3.60 | % | 4.60 | % | ||||||||||||||||||||||||||||||||||||||
Expected long-term rate of return on assets | 7.40 | % | 7.40 | % | 7.50 | % | — | — | — | 6.00 | % | 6.50 | % | 6.75 | % | |||||||||||||||||||||||||||||||||||||||||
| Rate of compensation increase | 4.49 | % | 4.43 | % | 4.37 | % | 4.75 | % | 4.75 | % | 4.75 | % | — | — | % | — | % | |||||||||||||||||||||||||||||||||||||||
| Medical trend rate | — | — | — | — | — | — | 6.3 | % | 6.8 | % | 6.7 | % | ||||||||||||||||||||||||||||||||||||||||||||
| Dental trend rate | — | — | — | — | — | — | 3.5 | % | 4.0 | % | 4.0 | % | ||||||||||||||||||||||||||||||||||||||||||||
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 2021 and is assumed to decrease to 5.7 percent in 2022, 5.1 percent in 2023 and 2024, 5.0 percent in 2025 and to gradually decrease to 3.9 percent by 2074. The assumed dental cost trend rate used to measure the expected cost of dental benefits covered by the plan was 3.5 percent, or equal to the medical trend rate if lower, for all years.
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Plan Assets
Pension Asset Allocation Policy: The target allocation and actual allocations at December 31, 2021, for the pension asset portfolio by asset class is set forth below:
| Asset Class | Target Allocation | Actual Allocation December 31, 2021 | ||||||||||||
| Debt securities | 24 | % | 23 | % | ||||||||||
| Equity securities | 59 | % | 61 | % | ||||||||||
| Real estate | 9 | % | 8 | % | ||||||||||
| Other plan assets | 8 | % | 8 | % | ||||||||||
| Total | 100 | % | 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. 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 30 years when interest rates were generally much higher.
Idaho Power’s asset modeling process also utilizes historical market returns to measure the portfolio’s exposure to a “worst-case” market scenario, to determine how much performance could vary from the expected “average” performance over various time periods. This “worst-case” modeling, in addition to cash flow matching and diversification by asset class and investment style, provides the basis for managing the risk associated with investing portfolio assets.
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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 1 | Level 2 | Level 3 | Total | |||||||||||||||||||||||
| Assets at December 31, 2021 | ||||||||||||||||||||||||||
| Cash and cash equivalents | $ | 24,636 | $ | — | $ | — | $ | 24,636 | ||||||||||||||||||
| Intermediate bonds | 39,133 | 187,048 | — | 226,181 | ||||||||||||||||||||||
| Equity Securities: Large-Cap | 104,318 | — | — | 104,318 | ||||||||||||||||||||||
| Equity Securities: Mid-Cap | 113,621 | — | — | 113,621 | ||||||||||||||||||||||
| Equity Securities: Small-Cap | 85,244 | — | — | 85,244 | ||||||||||||||||||||||
| Equity Securities: Micro-Cap | 42,915 | — | — | 42,915 | ||||||||||||||||||||||
| Equity Securities: Global and International | 67,625 | — | — | 67,625 | ||||||||||||||||||||||
| Equity Securities: Emerging Markets | 7,393 | — | — | 7,393 | ||||||||||||||||||||||
| Plan assets measured at NAV (not subject to hierarchy disclosure) | ||||||||||||||||||||||||||
| Commingled Fund: Equity Securities: Global and International | 134,752 | |||||||||||||||||||||||||
| Commingled Fund: Equity Securities: Emerging Markets | 47,332 | |||||||||||||||||||||||||
| Real estate | 73,958 | |||||||||||||||||||||||||
| Private market investments | 56,489 | |||||||||||||||||||||||||
| 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, 2020 | ||||||||||||||||||||||||||
| Cash and cash equivalents | $ | 25,008 | $ | — | $ | — | $ | 25,008 | ||||||||||||||||||
| Intermediate bonds | 34,455 | 163,000 | — | 197,455 | ||||||||||||||||||||||
| Equity Securities: Large-Cap | 79,259 | — | — | 79,259 | ||||||||||||||||||||||
| Equity Securities: Mid-Cap | 104,089 | — | — | 104,089 | ||||||||||||||||||||||
| Equity Securities: Small-Cap | 82,069 | — | — | 82,069 | ||||||||||||||||||||||
| Equity Securities: Micro-Cap | 44,715 | — | — | 44,715 | ||||||||||||||||||||||
| Equity Securities: Global and International | 69,687 | — | — | 69,687 | ||||||||||||||||||||||
| Equity Securities: Emerging Markets | 10,574 | — | — | 10,574 | ||||||||||||||||||||||
| Plan assets measured at NAV (not subject to hierarchy disclosure) | ||||||||||||||||||||||||||
| Commingled Fund: Equity Securities: Global and International | 116,223 | |||||||||||||||||||||||||
| Commingled Fund: Equity Securities: Emerging Markets | 50,019 | |||||||||||||||||||||||||
| Real estate | 54,630 | |||||||||||||||||||||||||
| Private market investments | 37,875 | |||||||||||||||||||||||||
| Total | $ | 449,856 | $ | 163,000 | $ | — | $ | 871,603 | ||||||||||||||||||
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, 2021 and 2020, there were no material transfers into or out of Levels 1, 2, or 3.
Fair Value Measurement of Level 2 Plan assets and Plan assets measured at NAV:
Level 2 Bonds: These investments represent United States government, agency bonds, and corporate bonds. The United States government and agency bonds, as well as the corporate bonds, are not traded on an exchange and are valued utilizing market prices for similar assets or liabilities in active markets.
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 global, international and emerging markets equity securities are measured at NAV, are not publicly traded, and therefore no publicly quoted market price is readily available. The values of the commingled funds are presented at estimated fair value, which is determined based on the unit value of the fund. The values of these investments are calculated by the custodian for the fund company on a monthly or more frequent basis, and are based on market prices of the assets held by each of the commingled funds divided by the number of fund shares outstanding for the respective fund. The investments in commingled funds have redemption limitations that permit monthly redemption following notice requirements of 5 to 7 days.
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 in 2021, 2020, and 2019, respectively.
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, 2021 and 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, 2021 and 2020 (in thousands of dollars):
| 2021 | 2020 | |||||||||||||||||||||||||
| Balance | Avg Rate | Balance | Avg Rate | |||||||||||||||||||||||
| Production | $ | 2,597,285 | 3.15 | % | $ | 2,529,708 | 3.23 | % | ||||||||||||||||||
| Transmission | 1,309,143 | 1.89 | % | 1,272,360 | 1.88 | % | ||||||||||||||||||||
| Distribution | 2,058,819 | 2.25 | % | 1,968,752 | 2.26 | % | ||||||||||||||||||||
| General and Other | 544,069 | 6.17 | % | 512,970 | 6.17 | % | ||||||||||||||||||||
| Total in service | 6,509,316 | 2.85 | % | 6,283,790 | 2.88 | % | ||||||||||||||||||||
| Accumulated provision for depreciation | (2,298,951) | (2,193,831) | ||||||||||||||||||||||||
| In service - net | $ | 4,210,365 | $ | 4,089,959 | ||||||||||||||||||||||
At December 31, 2021, Idaho Power's construction work in progress balance of $670.6 million included relicensing costs of $389.3 million for the HCC, Idaho Power's largest hydropower complex. In 2021, 2020, and 2019, Idaho Power had IPUC authorization to include in its Idaho jurisdiction rates $6.5 million annually ($8.8 million when grossed-up for the effect of income taxes) of AFUDC relating to the HCC relicensing project. Collecting these amounts will reduce the amount collected in the future once the HCC relicensing costs are approved for recovery in base rates. At December 31, 2021, Idaho Power's regulatory liability for collection of AFUDC relating to the HCC was $187.7 million.
Idaho Power's ownership interest in two jointly-owned generating facilities is included in the table above. Under the joint operating agreements for these facilities, each participating utility is responsible for financing its share of construction, operating, and leasing costs. Idaho Power's proportionate share of operating expenses for each facility is included in the Consolidated Statements of Income. These jointly-owned facilities, including balance sheet amounts and the extent of Idaho Power’s participation, were as follows at December 31, 2021 (in thousands of dollars):
| Name of Plant | Location | Utility Plant in Service | Construction Work in Progress | Accumulated Provision for Depreciation | Ownership % | MW(1)(2) | ||||||||||||||||||||||||||||||||
| Jim Bridger units 1-4 | Rock Springs, WY | $ | 771,034 | $ | 7,775 | $ | 401,696 | 33 | 775 | |||||||||||||||||||||||||||||
North Valmy unit 2(2) | Winnemucca, NV | 255,451 | 881 | 195,258 | 50 | 145 | ||||||||||||||||||||||||||||||||
(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 $59.7 million in 2021, $68.3 million in 2020, and $73.6 million in 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 $8.2 million in 2021, $9.3 million in 2020, and $8.6 million in 2019.
IDACORP's consolidated VIE, Marysville, owns a hydropower plant with a net book value of $13.7 million and $14.2 million at December 31, 2021 and 2020, respectively.
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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 have been exempted from such regulatory treatment as Idaho Power collected amounts related to the decommissioning of Boardman in rates. In October 2020, Idaho Power and co-owner Portland General Electric ceased coal-fired operations at their Boardman power plant. As of December 31, 2021 and 2020, Idaho Power has recorded a liability for estimated costs of decommissioning and retirement of Boardman plant assets, which is included in the amounts in the table below.
Idaho Power’s recorded AROs relate to the reclamation and removal costs at its jointly-owned coal-fired generation facilities. In 2021, 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 and generation facilities; however, due to the indeterminate removal date, the fair value of the associated liabilities currently cannot be estimated and no amounts are recognized in the consolidated financial statements.
Idaho Power also collects removal costs in rates for certain assets that do not have associated AROs. Idaho Power is required to classify these removal costs as regulatory liabilities, see Note 3 - "Regulatory Matters" for the removal costs recorded as regulatory liabilities on IDACORP’s and Idaho Power’s consolidated balance sheets as of December 31, 2021 and 2020.
The following table presents the changes in the carrying amount of AROs (in thousands of dollars):
| 2021 | 2020 | |||||||||||||
| Balance at beginning of year | $ | 27,691 | $ | 28,191 | ||||||||||
| Accretion expense | 1,021 | 1,053 | ||||||||||||
| Revisions in estimated cash flows | 9,415 | 193 | ||||||||||||
| Liability settled | (1,429) | (1,746) | ||||||||||||
| Balance at end of year | $ | 36,698 | $ | 27,691 | ||||||||||
15. INVESTMENTS
The table below summarizes IDACORP’s and Idaho Power’s investments as of December 31 (in thousands of dollars):
| 2021 | 2020 | |||||||||||||
| Idaho Power investments: | ||||||||||||||
| Bridger Coal Company (equity method investment) | $ | 22,677 | $ | 37,115 | ||||||||||
| Exchange traded short-term bond funds and cash equivalents | 54,078 | 50,531 | ||||||||||||
| Executive deferred compensation plan investments | 353 | 202 | ||||||||||||
| Total Idaho Power investments | 77,108 | 87,848 | ||||||||||||
| IFS investments in real estate tax credit projects, such as affordable housing developments | 34,967 | 28,438 | ||||||||||||
| Ida-West joint ventures (equity method investments) | 10,386 | 10,662 | ||||||||||||
| Other investments | 1,363 | — | ||||||||||||
| 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):
| 2021 | 2020 | 2019 | ||||||||||||||||||||||||
| Bridger Coal Company (Idaho Power) | $ | 10,211 | $ | 10,102 | $ | 10,285 | ||||||||||||||||||||
| Ida-West joint ventures | 1,224 | 1,411 | 2,085 | |||||||||||||||||||||||
| Total | $ | 11,435 | $ | 11,513 | $ | 12,370 | ||||||||||||||||||||
Investments in Equity Securities
Investments in equity securities are reported at fair value. Any unrealized gains or losses on equity securities are included in income. Unrealized gains and losses on equity securities were immaterial at December 31, 2021 and December 31, 2020. The following table summarizes sales of equity securities (in thousands of dollars):
| 2021 | 2020 | 2019 | ||||||||||||||||||||||||
| Proceeds from sales | $ | 11,328 | $ | 25,795 | $ | 5,080 | ||||||||||||||||||||
| Gross realized gains from sales | — | — | — | |||||||||||||||||||||||
IDACORP Financial Services Investments
IFS invests primarily in real estate tax credit projects, such as affordable housing developments, which provide a return principally by reducing federal and state income taxes through tax credits and accelerated tax depreciation benefits. IFS has focused on a diversified approach to its investment strategy in order to limit both geographic and operational risk, with most of IFS’s investments having been made through syndicated funds. IDACORP accounts for its equity-method investments in qualified real estate projects using the proportional amortization method and recognizes the net investment performance in the consolidated statements of income as a component of income tax expense.
16. 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, 2021, 2020, and 2019 (in thousands of dollars):
| Location of Realized Gain/(Loss) on Derivatives Recognized in Income | Gain/(Loss) on Derivatives Recognized in Income(1) | |||||||||||||||||||||||||
| 2021 | 2020 | 2019 | ||||||||||||||||||||||||
| Financial swaps | Operating revenues | $ | 1,046 | $ | 2,173 | $ | 904 | |||||||||||||||||||
| Financial swaps | Purchased power | 1,959 | (3,531) | (2,183) | ||||||||||||||||||||||
| Financial swaps | Fuel expense | 12,180 | (4,791) | 13,811 | ||||||||||||||||||||||
| Forward contracts | Operating revenues | 1,966 | 421 | 285 | ||||||||||||||||||||||
| Forward contracts | Purchased power | (1,099) | (384) | (270) | ||||||||||||||||||||||
| Forward contracts | Fuel expense | (194) | (36) | 565 | ||||||||||||||||||||||
(1) Excludes unrealized gains or losses on derivatives, which are recorded on the balance sheet as regulatory assets or regulatory liabilities.
Settlement gains and losses on electricity swap contracts are recorded on the income statement in operating revenues or purchased power depending on the forecasted position being economically hedged by the derivative contract. Settlement gains and losses on contracts for natural gas are reflected in fuel expense. Settlement gains and losses on diesel derivatives are recorded in other O&M expense. See Note 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, 2021 and 2020 (in thousands of dollars):
| Asset Derivatives | Liability Derivatives | |||||||||||||||||||||||||||||||||||||||||||
| Balance Sheet Location | Gross Fair Value | Amounts Offset | Net Assets | Gross Fair Value | Amounts Offset | Net Liabilities | ||||||||||||||||||||||||||||||||||||||
| December 31, 2021 | ||||||||||||||||||||||||||||||||||||||||||||
| Current: | ||||||||||||||||||||||||||||||||||||||||||||
| Financial swaps | Other current assets | $ | 10,599 | $ | (4,893) | (1) | $ | 5,706 | $ | 2,910 | $ | (2,910) | $ | — | ||||||||||||||||||||||||||||||
| Financial swaps | Other current liabilities | — | — | — | 20 | — | 20 | |||||||||||||||||||||||||||||||||||||
| Forward contracts | Other current assets | 6 | (4) | 2 | 4 | (4) | — | |||||||||||||||||||||||||||||||||||||
| Forward contracts | Other current liabilities | — | — | — | 1,970 | — | 1,970 | |||||||||||||||||||||||||||||||||||||
| Long-term: | ||||||||||||||||||||||||||||||||||||||||||||
| Financial swaps | Other assets | 899 | (9) | 890 | 9 | (9) | — | |||||||||||||||||||||||||||||||||||||
| Financial swaps | Other liabilities | — | — | — | 14 | — | 14 | |||||||||||||||||||||||||||||||||||||
| Forward contracts | Other liabilities | — | — | — | 3,743 | — | 3,743 | |||||||||||||||||||||||||||||||||||||
| Total | $ | 11,504 | $ | (4,906) | $ | 6,598 | $ | 8,670 | $ | (2,923) | $ | 5,747 | ||||||||||||||||||||||||||||||||
| December 31, 2020 | ||||||||||||||||||||||||||||||||||||||||||||
| Current: | ||||||||||||||||||||||||||||||||||||||||||||
| Financial swaps | Other current assets | $ | 2,028 | $ | (36) | $ | 1,992 | $ | 36 | $ | (36) | $ | — | |||||||||||||||||||||||||||||||
| Financial swaps | Other current liabilities | 187 | (187) | — | 786 | (652) | (2) | 134 | ||||||||||||||||||||||||||||||||||||
| Forward contracts | Other current assets | 5 | (2) | 3 | 2 | (2) | — | |||||||||||||||||||||||||||||||||||||
| Forward contracts | Other current liabilities | 3 | (3) | — | 13 | (3) | 10 | |||||||||||||||||||||||||||||||||||||
| Long-term: | ||||||||||||||||||||||||||||||||||||||||||||
| Financial swaps | Other liabilities | 40 | (40) | — | 56 | (56) | (2) | — | ||||||||||||||||||||||||||||||||||||
| Total | $ | 2,263 | $ | (268) | $ | 1,995 | $ | 893 | $ | (749) | $ | 144 | ||||||||||||||||||||||||||||||||
(1) Current asset derivative amounts offset include $2.0 million of collateral payable at December 31, 2021.
(2) Current and long-term liability derivative amounts offset include $0.5 million and $16 thousand of collateral receivable at December 31, 2020, respectively.
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The table below presents the volumes of derivative commodity forward contracts and swaps outstanding at December 31, 2021 and 2020 (in thousands of units):
| December 31, | ||||||||||||||||||||
| Commodity | Units | 2021 | 2020 | |||||||||||||||||
| Electricity purchases | MWh | 529 | 74 | |||||||||||||||||
| Electricity sales | MWh | 129 | — | |||||||||||||||||
| Natural gas purchases | MMBtu | 11,740 | 7,923 | |||||||||||||||||
| Natural gas sales | MMBtu | — | 775 | |||||||||||||||||
Credit Risk
At December 31, 2021, Idaho Power did not have material credit risk exposure from financial instruments, including derivatives. Idaho Power monitors credit risk exposure through reviews of counterparty credit quality, corporate-wide counterparty credit exposure, and corporate-wide counterparty concentration levels. Idaho Power manages these risks by establishing credit and concentration limits on transactions with counterparties and requiring contractual guarantees, cash deposits, or letters of credit from counterparties or their affiliates, as deemed necessary. Idaho Power’s physical power contracts are commonly under WSPP, Inc. agreements, physical gas contracts are usually under North American Energy Standards Board contracts, and financial transactions are usually under International Swaps and Derivatives Association, Inc. contracts. These contracts typically contain adequate assurance clauses requiring collateralization if a counterparty has debt that is downgraded below investment grade by at least one rating agency.
Credit-Contingent Features
Certain of Idaho Power's derivative instruments contain provisions that require Idaho Power's unsecured debt to maintain an investment grade credit rating from Moody's Investors Service and Standard & Poor's Ratings Services. If Idaho Power's unsecured debt were to fall below investment grade, it would be in violation of these provisions, and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions. The aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a liability position at December 31, 2021, was $3.0 million. Idaho Power did not post any cash collateral related to this amount. If the credit-risk-related contingent features underlying these agreements were triggered on December 31, 2021, Idaho Power would have been required to pay or post collateral to its counterparties up to an additional $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. There were no transfers between levels or material changes in valuation techniques or inputs during the years ended December 31, 2021 and 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, 2021 and 2020 (in thousands of dollars):
| December 31, 2021 | December 31, 2020 | |||||||||||||||||||||||||||||||||||||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||||||||||||||||||||||||||
| Assets: | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Money market funds and commercial paper | ||||||||||||||||||||||||||||||||||||||||||||||||||
IDACORP(1) | $ | 80,406 | $ | — | $ | — | $ | 80,406 | $ | 56,048 | $ | — | $ | — | $ | 56,048 | ||||||||||||||||||||||||||||||||||
| Idaho Power | 10,393 | — | — | 10,393 | 40,038 | — | — | 40,038 | ||||||||||||||||||||||||||||||||||||||||||
| Derivatives | 6,596 | 2 | — | 6,598 | 1,995 | — | — | 1,995 | ||||||||||||||||||||||||||||||||||||||||||
| Equity securities | 54,431 | — | — | 54,431 | 50,733 | — | — | 50,733 | ||||||||||||||||||||||||||||||||||||||||||
IDACORP assets measured at NAV (not subject to hierarchy disclosure)(1) | — | — | — | 1,363 | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||
| Liabilities: | ||||||||||||||||||||||||||||||||||||||||||||||||||
| 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, 2021 and 2020, using available market information and appropriate valuation methodologies (in thousands).
| December 31, 2021 | December 31, 2020 | |||||||||||||||||||||||||
| Carrying Amount | Estimated Fair Value | Carrying Amount | Estimated Fair Value | |||||||||||||||||||||||
| (thousands of dollars) | ||||||||||||||||||||||||||
| IDACORP | ||||||||||||||||||||||||||
| Assets: | ||||||||||||||||||||||||||
Notes receivable(1) | $ | 3,804 | $ | 3,804 | $ | 3,804 | $ | 3,804 | ||||||||||||||||||
| Liabilities: | ||||||||||||||||||||||||||
Long-term debt (including current portion)(1) | 2,000,640 | 2,381,172 | 2,000,414 | 2,466,967 | ||||||||||||||||||||||
| Idaho Power | ||||||||||||||||||||||||||
| Liabilities: | ||||||||||||||||||||||||||
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 forecasted cash flows, which are partially based on expected 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.
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 other real estate tax credit projects, Ida-West’s joint venture investments in small hydropower generation projects, and IDACORP’s holding company expenses.
The table below summarizes the segment information for IDACORP’s utility operations and the total of all other segments, and reconciles this information to total enterprise amounts (in thousands):
| Utility Operations | All Other | Eliminations | Consolidated Total | |||||||||||||||||||||||
| 2021 | ||||||||||||||||||||||||||
| Revenues | $ | 1,455,410 | $ | 2,674 | $ | — | $ | 1,458,084 | ||||||||||||||||||
| Operating income | 329,568 | 83 | — | 329,651 | ||||||||||||||||||||||
| Other income, net | 21,243 | (138) | — | 21,105 | ||||||||||||||||||||||
| Interest income | 7,123 | 216 | (47) | 7,292 | ||||||||||||||||||||||
| Equity-method income | 10,211 | 1,224 | — | 11,435 | ||||||||||||||||||||||
| Interest expense | 86,663 | 82 | (47) | 86,698 | ||||||||||||||||||||||
| Income before income taxes | 281,482 | 1,302 | — | 282,784 | ||||||||||||||||||||||
| Income tax expense (benefit) | 38,257 | (1,345) | — | 36,912 | ||||||||||||||||||||||
| Income attributable to IDACORP, Inc. | 243,225 | 2,325 | — | 245,550 | ||||||||||||||||||||||
| Total assets | 6,990,839 | 281,999 | (62,323) | 7,210,515 | ||||||||||||||||||||||
| Expenditures for long-lived assets | 299,972 | 27 | — | 299,999 | ||||||||||||||||||||||
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| Utility Operations | All Other | Eliminations | Consolidated Total | |||||||||||||||||||||||
| 2020 | ||||||||||||||||||||||||||
| Revenues | $ | 1,347,340 | $ | 3,389 | $ | — | $ | 1,350,729 | ||||||||||||||||||
| Operating income | 308,780 | 741 | — | 309,521 | ||||||||||||||||||||||
| Other income, net | 22,555 | (8) | — | 22,547 | ||||||||||||||||||||||
| Interest income | 9,733 | 1,275 | (496) | 10,512 | ||||||||||||||||||||||
| Equity-method income | 10,102 | 1,411 | — | 11,513 | ||||||||||||||||||||||
| Interest expense | 87,389 | 533 | (496) | 87,426 | ||||||||||||||||||||||
| Income before income taxes | 263,783 | 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 assets | 6,906,110 | 253,060 | (63,926) | 7,095,244 | ||||||||||||||||||||||
| Expenditures for long-lived assets | 310,937 | 1 | — | 310,938 | ||||||||||||||||||||||
| 2019 | ||||||||||||||||||||||||||
| Revenues | $ | 1,342,940 | $ | 3,443 | $ | — | $ | 1,346,383 | ||||||||||||||||||
| Operating income | 297,652 | 674 | — | 298,326 | ||||||||||||||||||||||
| Other income, net | 20,362 | 1 | — | 20,363 | ||||||||||||||||||||||
| Interest income | 10,968 | 3,052 | (769) | 13,251 | ||||||||||||||||||||||
| Equity-method income | 10,285 | 2,085 | — | 12,370 | ||||||||||||||||||||||
| Interest expense | 86,412 | 832 | (769) | 86,475 | ||||||||||||||||||||||
| Income before income taxes | 252,854 | 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 assets | 6,494,159 | 220,620 | (73,578) | 6,641,201 | ||||||||||||||||||||||
| Expenditures for long-lived assets | 278,707 | (2) | — | 278,705 | ||||||||||||||||||||||
19. OTHER INCOME AND EXPENSE
The following table presents the components of IDACORP’s other income (expense), net and Idaho Power's other income (expense), net (in thousands of dollars):
| IDACORP | 2021 | 2020 | 2019 | |||||||||||||||||
| Interest and dividend income, net | $ | 1,408 | $ | 3,813 | $ | 8,181 | ||||||||||||||
| Carrying charges on regulatory assets | 5,034 | 7,063 | 5,494 | |||||||||||||||||
Pension and postretirement non-service costs(1) | (15,249) | (11,865) | (10,976) | |||||||||||||||||
| Income from life insurance investments | 5,203 | 4,036 | 4,104 | |||||||||||||||||
| Other income (expense) | 463 | 462 | (301) | |||||||||||||||||
| Total other income (expense), net | $ | (3,141) | $ | 3,509 | $ | 6,502 | ||||||||||||||
| Idaho Power | ||||||||||||||||||||
| Interest and dividend income, net | $ | 1,241 | $ | 3,034 | $ | 5,898 | ||||||||||||||
| Carrying charges on regulatory assets | 5,034 | 7,063 | 5,494 | |||||||||||||||||
Pension and postretirement non-service costs(1) | (15,240) | (11,862) | (10,976) | |||||||||||||||||
| Income from life insurance investments | 5,203 | 4,036 | 4,104 | |||||||||||||||||
| Other income (expense) | 591 | 468 | (303) | |||||||||||||||||
| Total other income (expense), net | $ | (3,171) | $ | 2,739 | $ | 4,217 | ||||||||||||||
(1) The 2021 pension and postretirement non-service costs includes $4.7 million of expense for a temporary deviation from the cost-sharing provisions of the substantive postretirement plan as described in Note 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, 2021, 2020, and 2019 (in thousands of dollars). Items in parentheses indicate reductions to AOCI.
| Year Ended December 31, | ||||||||||||||||||||
| 2021 | 2020 | 2019 | ||||||||||||||||||
| 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 $677 | 3,343 | 2,988 | 1,952 | |||||||||||||||||
| Net current-period other comprehensive income | 3,318 | (7,074) | (13,440) | |||||||||||||||||
| Balance at end of period | $ | (40,040) | $ | (43,358) | $ | (36,284) | ||||||||||||||
The table below presents the effects on net income of amounts reclassified out of components of AOCI and the income statement location of those amounts reclassified during the years ended December 31, 2021, 2020, and 2019 (in thousands of dollars). Items in parentheses indicate increases to net income.
| Amount Reclassified from AOCI | ||||||||||||||||||||
| Year Ended December 31, | ||||||||||||||||||||
| 2021 | 2020 | 2019 | ||||||||||||||||||
Amortization of defined benefit pension items(1) | ||||||||||||||||||||
| Prior service cost | $ | 296 | $ | 290 | $ | 96 | ||||||||||||||
| Net loss | 4,205 | 3,734 | 2,533 | |||||||||||||||||
| Total before tax | 4,501 | 4,024 | 2,629 | |||||||||||||||||
Tax benefit(2) | (1,158) | (1,036) | (677) | |||||||||||||||||
| Net of tax | 3,343 | 2,988 | 1,952 | |||||||||||||||||
| Total reclassification for the period | $ | 3,343 | $ | 2,988 | $ | 1,952 | ||||||||||||||
(1) Amortization of these items is included in "Other (income) expense, net" in the consolidated income statements of both IDACORP and Idaho Power.
(2) The tax benefit is included in "Income tax expense" in the consolidated income statements of both IDACORP and Idaho Power.
21. 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 2020, and $0.8 million in 2019.
At December 31, 2021 and 2020, Idaho Power had a $2.0 million and $1.5 million payable to IDACORP, respectively, which was included in its accounts payable to affiliates balance on its consolidated balance sheets.
Ida-West: Idaho Power purchases all of the power generated by four of Ida-West’s hydropower projects located in Idaho. Idaho Power purchased $8.2 million in 2021, $9.3 million in 2020, and $8.6 million in 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, 2021 and 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, 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, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 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, 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 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 audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Regulation of Utility Operations - Refer to Notes 1 and 3 to the financial statements
Critical Audit Matter Description
Idaho Power Company (Idaho Power), 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 17, 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, 2021 and 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, 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, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 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, 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 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 audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Regulation of Utility Operations - Refer to Notes 1 and 3 to the financial statements
Critical Audit Matter Description
The Company is subject to rate regulation by the Federal Energy Regulatory Commission (FERC) and the Idaho and Oregon Public Utility Commissions (the “Commissions”), which have jurisdiction with respect to the rates of electric distribution companies in Idaho and Oregon. Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant, and equipment; regulatory assets and liabilities; operating revenues; operation and maintenance expense; depreciation expense; and income tax expense.
The Company’s rates are subject to regulatory rate-setting processes. Regulatory decisions can have an impact on the recovery of costs, the rate of return earned on investment, and the timing and amount of assets to be recovered by rates. The
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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 17, 2022
We have served as the Company's auditor since 1932.
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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, 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, 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, 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, 2021 and issued a report, which appears on the next page and expresses an unqualified opinion on the effectiveness of IDACORP’s internal control over financial reporting as of December 31, 2021.
February 17, 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, 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, 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 as of and for the year ended December 31, 2021, of the Company and our report dated February 17, 2022, expressed an unqualified opinion on those financial statements.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ DELOITTE & TOUCHE LLP
Boise, Idaho
February 17, 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, 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, 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, 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, 2021, and issued a report which appears on the next page and expresses an unqualified opinion on the effectiveness of Idaho Power’s internal control over financial reporting as of December 31, 2021.
February 17, 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, 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, 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 as of and for the year ended December 31, 2021, of the Company and our report dated February 17, 2022, expressed an unqualified opinion on those financial statements.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ DELOITTE & TOUCHE LLP
Boise, Idaho
February 17, 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, 2021, 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,” “Delinquent Section 16(a) Reports,” “Board of Directors - Committees of the Board of Directors - Audit Committee,” “Corporate Governance at IDACORP - Codes of Business Conduct,” and "Corporate Governance at IDACORP - Certain Relationships and Related Transactions" to be filed pursuant to Regulation 14A for the 2022 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 2022 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 2022 annual meeting of shareholders is hereby incorporated by reference. The table below includes information as of December 31, 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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| 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 | 211,519 | (1) | $ | — | (2) | 443,663 | (3) | ||||||||||||||||
Equity compensation plans not approved by shareholders | — | $ | — | — | |||||||||||||||||||
| Total | 211,519 | $ | — | 443,663 | |||||||||||||||||||
(1) Represents shares subject to outstanding time-based restricted stock units, performance-based restricted stock units (at target), and deferred director stock unit awards, all under the LTICP. Restricted stock unit awards and director deferred stock unit awards may be settled only for shares of common stock on a one-for-one basis. | |||||||||||||||||||||||
| (2) Time-based restricted stock units and performance-based restricted stock units have no exercise price. | |||||||||||||||||||||||
| (3) Shares under the LTICP may be issued in connection with stock options, stock appreciation rights, restricted stock, restricted stock units, performance units, performance shares, or other equity-based awards. | |||||||||||||||||||||||
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The portions of IDACORP’s definitive proxy statement appearing under the captions “Certain Relationships and Related Transactions” and “Corporate Governance at IDACORP – Director Independence and Executive Sessions” to be filed pursuant to Regulation 14A for the 2022 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 2022 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, 2021 and 2020:
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 2021 and 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.
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” for a complete listing of consolidated financial statements and financial statement schedules.
(3) Exhibits. Note Regarding Reliance on Statements in Agreements: The agreements filed as exhibits to IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2021, 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 Description | Form | File No. | Exhibit No. | Date | Included Herewith | ||||||||||||||
| 2 | S-4 | 333-48031 | A | 3/16/1998 | ||||||||||||||||
| 3.1 | Restated Articles of Incorporation of Idaho Power Company as filed with the Secretary of State of Idaho on June 30, 1989 | S-3 Post-Effective Amend. No. 2 | 33-00440* | 4(a)(xiii) | 6/30/1989 | |||||||||||||||
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144
145
| Incorporated by Reference | ||||||||||||||||||||
| Exhibit No. | Exhibit Description | Form | File No. | Exhibit No. | Date | Included Herewith | ||||||||||||||
| 4.9 | 10-Q | 1-3198 | 4.12 | 8/5/2010 | ||||||||||||||||
| 4.10 | 10-K | 1-14465, 1-3198 | 4.10 | 2/18/21 | ||||||||||||||||
| 10.1 | 10-K | 1-14465, 1-3198 | 10.4 | 2/19/2015 | ||||||||||||||||
| 10.2 | 10-K | 1-14465, 1-3198 | 10.5 | 2/19/2015 | ||||||||||||||||
| 10.3 | Framework 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 rights | S-3 | 33-65720* | 10(h) | 7/7/1993 | |||||||||||||||
| 10.4 | Agreement, dated October 25, 1984, between the State of Idaho and Idaho Power Company, relating to the agreement filed as Exhibit 10.3 | S-3 | 33-65720* | 10(h)(i) | 7/7/1993 | |||||||||||||||
| 10.5 | Contract to Implement, dated October 25, 1984, between the State of Idaho and Idaho Power Company, relating to the agreement filed as Exhibit 10.3 | S-3 | 33-65720* | 10(h)(ii) | 7/7/1993 | |||||||||||||||
| 10.6 | 10-Q | 1-14465* | 10.58 | 5/7/2009 | ||||||||||||||||
| 10.7 | Agreement 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 Limited | S-3 | 33-65720* | 10(m) | 7/7/1993 | |||||||||||||||
| 10.8 | 8-K | 1-14465, 1-3198 | 10.1 | 11/9/2015 | ||||||||||||||||
| 10.9 | 8-K | 1-14465, 1-3198 | 10.2 | 11/9/2015 | ||||||||||||||||
| 10.10 | 8-K | 1-14465, 1-3198 | 10.1 | 12/10/2019 | ||||||||||||||||
| 10.11 | 8-K | 1-14465, 1-3198 | 10.2 | 12/10/2019 | ||||||||||||||||
146
| Incorporated by Reference | ||||||||||||||||||||
| Exhibit No. | Exhibit Description | Form | File No. | Exhibit No. | Date | Included Herewith | ||||||||||||||
| 10.12 | 8-K | 1-14465, 1-3198 | 10.1 | 12/3/2021 | ||||||||||||||||
| 10.13 | 8-K | 1-14465, 1-3198 | 10.2 | 12/3/2021 | ||||||||||||||||
| 10.14 | 8-K | 1-3198 | 10.1 | 10/10/2006 | ||||||||||||||||
| 10.15 | 10-Q | 1-3198 | 10(c) | 8/4/2000 | ||||||||||||||||
10.161 | 10-K | 1-14465, 1-3198 | 10.15 | 2/26/2009 | ||||||||||||||||
10.171 | 10-Q | 1-14465, 1-3198 | 10.62 | 11/1/2012 | ||||||||||||||||
10.181 | 10-K | 1-14465, 1-3198 | 10.31 | 2/23/2017 | ||||||||||||||||
10.191 | 10-Q | 1-14465, 1-3198 | 10.1 | 8/3/2017 | ||||||||||||||||
10.201 | 10-Q | 1-14465, 1-3198 | 10(h)(viii) | 11/2/2006 | ||||||||||||||||
10.211 | X | |||||||||||||||||||
10.221 | 10-Q | 1-14465, 1-3198 | 10(h)(xix) | 11/2/2006 | ||||||||||||||||
10.231 | 10-Q | 1-14465, 1-3198 | 10(h)(xx) | 11/2/2006 | ||||||||||||||||
10.241 | 10-K | 1-14465, 1-3198 | 10.24 | 2/26/2009 | ||||||||||||||||
10.251 | 10-K | 1-14465, 1-3198 | 10.25 | 2/26/2009 | ||||||||||||||||
10.261 | 8-K | 1-14465, 1-3198 | 10.1 | 3/24/2010 | ||||||||||||||||
10.271 | 10-K | 1-14465, 1-3198 | 10.25 | 2/18/21 | ||||||||||||||||
10.281 | 10-K | 1-14465, 1-3198 | 10.41 | 2/23/2017 | ||||||||||||||||
10.291 | 10-K | 1-14465, 1-3198 | 10.30 | 2/21/2019 | ||||||||||||||||
10.301 | 10-K | 1-14465, 1-3198 | 10.31 | 2/21/2019 | ||||||||||||||||
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| Incorporated by Reference | ||||||||||||||||||||
| Exhibit No. | Exhibit Description | Form | File No. | Exhibit No. | Date | Included Herewith | ||||||||||||||
10.311 | 10-K | 1-14465, 1-3198 | 10.32 | 2/21/2019 | ||||||||||||||||
10.321 | 10-K | 1-14465, 1-3198 | 10.36 | 2/21/2019 | ||||||||||||||||
10.331 | 10-K | 1-14465, 1-3198 | 10.32 | 2/26/2009 | ||||||||||||||||
10.341 | X | |||||||||||||||||||
10.351 | 10-K | 1-14465, 1-3198 | 10.46 | 2/26/2009 | ||||||||||||||||
10.361 | 10-K | 1-14465, 1-3198 | 10.47 | 2/26/2009 | ||||||||||||||||
10.371 | 10-K | 1-14465, 1-3198 | 10.48 | 2/26/2009 | ||||||||||||||||
10.381 | 10-K | 1-14465, 1-3198 | 10.49 | 2/26/2009 | ||||||||||||||||
10.391 | 10-K | 1-14465, 1-3198 | 10.50 | 2/26/2009 | ||||||||||||||||
10.401 | 10-K | 1-14465, 1-3198 | 10.51 | 2/26/2009 | ||||||||||||||||
10.411 | 10-K | 1-14465, 1-3198 | 10.52 | 2/26/2009 | ||||||||||||||||
10.421 | 10-K | 1-14465, 1-3198 | 10.53 | 2/26/2009 | ||||||||||||||||
10.431 | 10-K | 1-14465, 1-3198 | 10.59 | 2/18/2016 | ||||||||||||||||
10.441 | 10-K | 1-14465, 1-3198 | 10.61 | 2/23/2017 | ||||||||||||||||
10.451 | 10-Q | 1-14465, 1-3198 | 10.1 | 11/2/2017 | ||||||||||||||||
10.461 | 10-Q | 1-14465, 1-3198 | 10.4 | 5/3/2018 | ||||||||||||||||
10.471 | 10-Q | 1-14465, 1-3198 | 10.1 | 10/31/2019 | ||||||||||||||||
10.481 | 10-K | 1-14465, 1-3198 | 10.49 | 2/18/21 | ||||||||||||||||
| 21.1 | X | |||||||||||||||||||
| 23.1 | X | |||||||||||||||||||
| 23.2 | X | |||||||||||||||||||
| 31.1 | X | |||||||||||||||||||
| 31.2 | X | |||||||||||||||||||
| 31.3 | X | |||||||||||||||||||
| 31.4 | X | |||||||||||||||||||
| 32.1 | X | |||||||||||||||||||
| 32.2 | X | |||||||||||||||||||
| 32.3 | X | |||||||||||||||||||
| 32.4 | X | |||||||||||||||||||
| 95.1 | X | |||||||||||||||||||
| 101.SCH | Inline XBRL Taxonomy Extension Schema Document | X | ||||||||||||||||||
148
149
IDACORP, INC.
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME
| Year Ended December 31, | ||||||||||||||||||||
| 2021 | 2020 | 2019 | ||||||||||||||||||
| (thousands of dollars) | ||||||||||||||||||||
| Income: | ||||||||||||||||||||
| Equity in income of subsidiaries | $ | 245,591 | $ | 237,233 | $ | 231,534 | ||||||||||||||
| Investment income | 148 | 748 | 2,214 | |||||||||||||||||
| Total income | 245,739 | 237,981 | 233,748 | |||||||||||||||||
| Expenses: | ||||||||||||||||||||
| Operating expenses | 679 | 692 | 816 | |||||||||||||||||
| Interest expense | 82 | 534 | 831 | |||||||||||||||||
| Other expenses | 192 | 145 | 30 | |||||||||||||||||
| Total expenses | 953 | 1,371 | 1,677 | |||||||||||||||||
| Income Before Income Taxes | 244,786 | 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) income | 3,318 | (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. | ||||||||||||||||||||
IDACORP, INC.
CONDENSED STATEMENTS OF CASH FLOWS
| Year Ended December 31, | ||||||||||||||||||||
| 2021 | 2020 | 2019 | ||||||||||||||||||
| (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 investments | 50,000 | — | — | |||||||||||||||||
| Net cash provided by (used in) investing activities | 23,637 | (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 equivalents | 46,436 | (8,552) | 16,241 | |||||||||||||||||
| Cash and cash equivalents at beginning of year | 106,589 | 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. | ||||||||||||||||||||
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IDACORP, INC.
CONDENSED BALANCE SHEETS
| December 31, | ||||||||||||||
| 2021 | 2020 | |||||||||||||
| Assets | (thousands of dollars) | |||||||||||||
| Current Assets: | ||||||||||||||
| Cash and cash equivalents | $ | 153,025 | $ | 106,589 | ||||||||||
| Short-term investments | — | 25,000 | ||||||||||||
| Receivables | 2,050 | 1,604 | ||||||||||||
| Other | 102 | 107 | ||||||||||||
| Total current assets | 155,177 | 133,300 | ||||||||||||
| Investments | 2,570,150 | 2,468,955 | ||||||||||||
| Other Assets: | ||||||||||||||
| Deferred income taxes | 5,004 | 23,859 | ||||||||||||
| Other | 299 | 312 | ||||||||||||
| Total other assets | 5,303 | 24,171 | ||||||||||||
| Total assets | $ | 2,730,630 | $ | 2,626,426 | ||||||||||
| Liabilities and Shareholders’ Equity | ||||||||||||||
| Current Liabilities: | ||||||||||||||
| Taxes accrued | $ | 850 | $ | 2,745 | ||||||||||
| Other | 777 | 928 | ||||||||||||
| Total current liabilities | 1,627 | 3,673 | ||||||||||||
| Other Liabilities: | ||||||||||||||
| Intercompany notes payable | 59,928 | 62,049 | ||||||||||||
| Other | 639 | 724 | ||||||||||||
| Total other liabilities | 60,567 | 62,773 | ||||||||||||
| IDACORP, Inc. Shareholders’ Equity | 2,668,436 | 2,559,980 | ||||||||||||
| Total Liabilities and Shareholders' Equity | $ | 2,730,630 | $ | 2,626,426 | ||||||||||
| The accompanying note is an integral part of these statements. | ||||||||||||||
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 2021 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 $149 million, $141 million, and $133 million in 2021, 2020, and 2019, respectively.
151
IDACORP, INC. AND IDAHO POWER COMPANY
SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31, 2021, 2020, and 2019
| 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) | ||||||||||||||||||||||||||||||||
| 2021: | ||||||||||||||||||||||||||||||||
| Reserve for uncollectible accounts | $ | 5,263 | $ | 2,083 | $ | 640 | $ | 2,970 | $ | 5,016 | ||||||||||||||||||||||
| Injuries and damages | 2,484 | 2,032 | — | 736 | 3,780 | |||||||||||||||||||||||||||
| 2020: | ||||||||||||||||||||||||||||||||
| Reserve for uncollectible accounts | $ | 1,744 | $ | 5,239 | $ | 438 | $ | 2,158 | $ | 5,263 | ||||||||||||||||||||||
| Injuries and damages | 1,748 | 1,203 | — | 467 | 2,484 | |||||||||||||||||||||||||||
| 2019: | ||||||||||||||||||||||||||||||||
| Reserve for uncollectible accounts | $ | 1,989 | $ | 2,381 | $ | 227 | $ | 2,853 | $ | 1,744 | ||||||||||||||||||||||
| Injuries and damages | 1,877 | 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.
ITEM 16. FORM 10-K SUMMARY
None.
152
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 17, 2022 | IDACORP, INC. | |||||||||||||
| Date | ||||||||||||||
| By: | /s/ Lisa A. Grow | |||||||||||||
| Lisa A. Grow | ||||||||||||||
| President and Chief Executive Officer | ||||||||||||||
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
| Signature | Title | Date | |||||||||||||||||||||
| /s/ Richard J. Dahl | Chairman of the Board | February 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 | |||||||||||||||||||||||
| /s/ Darrel T. Anderson | Director | February 17, 2022 | |||||||||||||||||||||
| Darrel T. Anderson | |||||||||||||||||||||||
| /s/ Odette Bolano | Director | February 17, 2022 | |||||||||||||||||||||
| Odette Bolano | |||||||||||||||||||||||
| /s/ Thomas Carlile | Director | February 17, 2022 | |||||||||||||||||||||
| Thomas Carlile | |||||||||||||||||||||||
| /s/ Annette G. Elg | Director | February 17, 2022 | |||||||||||||||||||||
| Annette G. Elg | |||||||||||||||||||||||
| /s/ Ronald W. Jibson | Director | February 17, 2022 | |||||||||||||||||||||
| Ronald W. Jibson | |||||||||||||||||||||||
| /s/ Judith A. Johansen | Director | February 17, 2022 | |||||||||||||||||||||
| Judith A. Johansen | |||||||||||||||||||||||
| /s/ Dennis L. Johnson | Director | February 17, 2022 | |||||||||||||||||||||
| Dennis L. Johnson | |||||||||||||||||||||||
| Director | |||||||||||||||||||||||
| Jeff C. Kinneeveauk | |||||||||||||||||||||||
| /s/ Richard J. Navarro | Director | February 17, 2022 | |||||||||||||||||||||
| Richard J. Navarro | |||||||||||||||||||||||
| /s/ Dr. Mark T. Peters | Director | February 17, 2022 | |||||||||||||||||||||
| Dr. Mark T. Peters | |||||||||||||||||||||||
153
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 17, 2022 | Idaho Power Company | |||||||||||||
| Date | ||||||||||||||
| By: | /s/ Lisa A. Grow | |||||||||||||
| Lisa A. Grow | ||||||||||||||
| President and Chief Executive Officer | ||||||||||||||
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
| Signature | Title | Date | |||||||||||||||||||||
| /s/ Richard J. Dahl | Chairman of the Board | February 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 | |||||||||||||||||||||||
| /s/ Darrel T. Anderson | Director | February 17, 2022 | |||||||||||||||||||||
| Darrel T. Anderson | |||||||||||||||||||||||
| /s/ Odette Bolano | Director | February 17, 2022 | |||||||||||||||||||||
| Odette Bolano | |||||||||||||||||||||||
| /s/ Thomas Carlile | Director | February 17, 2022 | |||||||||||||||||||||
| Thomas Carlile | |||||||||||||||||||||||
| /s/ Annette G. Elg | Director | February 17, 2022 | |||||||||||||||||||||
| Annette G. Elg | |||||||||||||||||||||||
| /s/ Ronald W. Jibson | Director | February 17, 2022 | |||||||||||||||||||||
| Ronald W. Jibson | |||||||||||||||||||||||
| /s/ Judith A. Johansen | Director | February 17, 2022 | |||||||||||||||||||||
| Judith A. Johansen | |||||||||||||||||||||||
| /s/ Dennis L. Johnson | Director | February 17, 2022 | |||||||||||||||||||||
| Dennis L. Johnson | |||||||||||||||||||||||
| Director | |||||||||||||||||||||||
| Jeff C. Kinneeveauk | |||||||||||||||||||||||
| /s/ Richard J. Navarro | Director | February 17, 2022 | |||||||||||||||||||||
| Richard J. Navarro | |||||||||||||||||||||||
| /s/ Dr. Mark T. Peters | Director | February 17, 2022 | |||||||||||||||||||||
| Dr. Mark T. Peters | |||||||||||||||||||||||
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