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, 2023 | |||||||
OR
| ☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF | ||||
| THE SECURITIES EXCHANGE ACT OF 1934 | |||||
For the transition period from _________ to ________________________________
 |  | |||||||
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 if 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 ☒ No ☐
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Indicate by check mark whether the registrants have submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrants were required to submit such files).
| IDACORP, Inc. | Yes | ☒ | 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 Securities Exchange Act of 1934.
| Large accelerated filer | Accelerated filer | Non-accelerated filer | Smaller reporting company | Emerging growth company | |||||||||||||
| IDACORP, Inc.: | ☒ | ☐ | ☐ | ☐ | ☐ | ||||||||||||
| Idaho Power Company: | ☐ | ☐ | ☒ | ☐ | ☐ | ||||||||||||
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange
Act.
| IDACORP, Inc. | ☐ | Idaho Power Company | ☐ | |||||||||||||||||||||||||||||
Indicate by check mark whether the registrants have filed a report on and attestation to its management's assessment of the effectiveness of its internal control over financial reporting under Sections 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.
| IDACORP, Inc. | Yes | ☒ | No | ☐ | Idaho Power Company | Yes | ☒ | No | ☐ | ||||||||||||||||||||
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements.
| IDACORP, Inc. | ☐ | Idaho Power Company | ☐ | |||||||||||||||||||||||||||||
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b).
| IDACORP, Inc. | ☐ | Idaho Power Company | ☐ | |||||||||||||||||||||||||||||
Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Act).
| IDACORP, Inc. | Yes | ☐ | No | ☒ | Idaho Power Company | Yes | ☐ | No | ☒ | ||||||||||||||||||||
Aggregate market value of voting and non-voting common stock held by non-affiliates (as of June 30, 2023):
| IDACORP, Inc.: | $ | 5,170,636,474 | Idaho Power Company: | None | ||||||||||
Number of shares of common stock outstanding as of February 9, 2024:
| IDACORP, Inc.: | 50,628,079 | 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 2024 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 1C | Cybersecurity | |||||||
| 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 Jurisdictions 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 2024 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: | ||||||||||||||||||||
| 2023 IRP | - | 2023 Integrated Resource Plan | MATS | - | Mercury and Air Toxics Standards | |||||||||||||||
| ADITC | - | Accumulated Deferred Investment Tax Credits | MD&A | - | Management’s Discussion and Analysis of Financial Condition and Results of Operations | |||||||||||||||
| AFUDC | - | Allowance for Funds Used During Construction | MMBtu | - | Million British Thermal Units | |||||||||||||||
| AOCI | - | Accumulated Other Comprehensive Income | Moody's | - | Moody’s Investors Service | |||||||||||||||
| BCC | - | Bridger Coal Company, a jointly-owned investment of IERCo | MW | - | Megawatt | |||||||||||||||
| BLM | - | U.S. Bureau of Land Management | MWh | - | Megawatt-hour | |||||||||||||||
| BPA | - | Bonneville Power Administration | NAAQS | - | National Ambient Air Quality Standards | |||||||||||||||
| CAA | - | Clean Air Act | NAV | - | Net Asset Value | |||||||||||||||
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 | NOx | - | Nitrogen Oxide | |||||||||||||||
| ESA | - | Endangered Species Act | O&M | - | Operations and Maintenance | |||||||||||||||
| ESG | - | Environmental, Social, and Governance | OATT | - | Open Access Transmission Tariff | |||||||||||||||
| Exchange Act | - | U.S. Securities Exchange Act of 1934, as amended | OPUC | - | Public Utility Commission of Oregon | |||||||||||||||
| FCA | - | Idaho Fixed Cost Adjustment | PCA | - | Idaho-jurisdiction Power Cost Adjustment | |||||||||||||||
| FERC | - | Federal Energy Regulatory Commission | PSPS | - | Public safety power shutoff | |||||||||||||||
| FPA | - | Federal Power Act | PURPA | - | Public Utility Regulatory Policies Act of 1978 | |||||||||||||||
| GAAP | - | Generally Accepted Accounting Principles | REC | - | Renewable Energy Credit | |||||||||||||||
| GHG | - | Greenhouse Gas | RFP | - | Request for proposals | |||||||||||||||
| HCC | - | Hells Canyon Complex, composed of the Brownlee, Oxbow, and Hells Canyon facilities | RPS | - | Renewable Portfolio Standard | |||||||||||||||
| IDACORP | - | IDACORP, Inc., an Idaho Corporation | SEC | - | U.S. Securities and Exchange Commission | |||||||||||||||
| Idaho Power | - | Idaho Power Company, an Idaho Corporation | SIP | - | State Implementation Plan | |||||||||||||||
| Idaho ROE | - | Idaho-jurisdiction return on year-end equity | SMSP | - | Security Plans for Senior Management Employees I and II | |||||||||||||||
| Ida-West | - | Ida-West Energy Company, a subsidiary of IDACORP, Inc. | SOFR | - | Secured Overnight Financing Rate administered by the Federal Reserve Bank of New York | |||||||||||||||
| IDEQ | - | Idaho Department of Environmental Quality | SO2 | - | Sulfur Dioxide | |||||||||||||||
| IERCo | - | Idaho Energy Resources Co., a subsidiary of Idaho Power Company | USACE | - | U.S. Army Corps of Engineers | |||||||||||||||
| IFS | - | IDACORP Financial Services, Inc., a subsidiary of IDACORP, Inc. | USFWS | - | U.S. Fish and Wildlife Service | |||||||||||||||
| IPUC | - | Idaho Public Utilities Commission | Western EIM | - | Energy imbalance market implemented in the western United States | |||||||||||||||
| IRP | - | Integrated Resource Plan | WDEQ | - | Wyoming Department of Environmental Quality | |||||||||||||||
| Jim Bridger plant | - | Jim Bridger power plant | WMP | - | Wildfire Mitigation Plan | |||||||||||||||
| kWh | - | Kilowatt-hour | WOTUS | - | Waters of the United States | |||||||||||||||
| LTICP | - | IDACORP 2000 Long-Term Incentive and Compensation Plan | WPSC | - | Wyoming Public Service Commission | |||||||||||||||
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| CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS | ||||||||
In addition to the historical information contained in this report, this report contains (and oral communications made by IDACORP and Idaho Power may contain) statements that relate to future events and expectations, such as statements regarding projected or future financial performance, cash flows, capital expenditures, regulatory filings, dividends, capital structure or ratios, load forecasts, strategic goals, challenges, objectives, and plans for future operations. Such statements constitute forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Any statements that express, or involve discussions as to, expectations, beliefs, plans, objectives, assumptions, or future events or performance, often, but not always, through the use of words or phrases such as "anticipates," "believes," "could," "estimates," "expects," "intends," "potential," "plans," "predicts," "preliminary," "projects," "targets," "may," "may result," "may continue," or similar expressions, are not statements of historical facts and may be forward-looking. Forward-looking statements are not guarantees of future performance, involve estimates, assumptions, risks, and uncertainties, and may differ materially from actual results, performance, or outcomes. In addition to any assumptions and other factors and matters referred to specifically in connection with such forward-looking statements, factors that could cause actual results or outcomes to differ materially from those contained in forward-looking statements include those factors set forth in Part I, Item 1A - "Risk Factors" and Part II, Item 7 - MD&A of this report, subsequent reports filed by IDACORP and Idaho Power with the SEC, and the following important factors:
•decisions by the Idaho and Oregon public utilities commissions and the FERC that impact Idaho Power's ability to recover costs and earn a return on investment;
•changes to or the elimination of Idaho Power's regulatory cost recovery mechanisms;
•expenses and risks associated with capital expenditures for, and the permitting and construction of, utility infrastructure projects that Idaho Power may be unable to complete or that may not be deemed prudent by regulators for cost recovery or return on investment;
•expenses and risks associated with supplier and contractor delays and failure to satisfy project quality and performance standards on utility infrastructure projects, and the potential impacts of those delays and failures on Idaho Power's ability to serve customers;
•power demand exceeding supply, and the rapid addition of new industrial and commercial customer load and the volatility of such new load demand, resulting in increased costs for purchasing energy and capacity in the market, if available, or acquiring or constructing additional generation and transmission resources and battery storage facilities;
•impacts of economic conditions, including an inflationary or recessionary environment and increasing interest rates, on items such as operations and capital investments, supply costs and delivery delays, supply scarcity and shortages, population growth or decline in Idaho Power's service area, changes in customer demand for electricity, revenue from sales of excess power, credit quality of counterparties and suppliers and their ability to meet financial and operational commitments, and collection of receivables;
•changes in residential, commercial, and industrial growth and demographic patterns within Idaho Power's service area, and the associated impacts on loads and load growth;
•employee workforce factors, including the operational and financial costs of unionization or the attempt to unionize all or part of the companies’ workforce, the cost and ability to attract and retain skilled workers and third-party contractors and suppliers, the cost of living and the related impact on recruiting employees, and the ability to adjust to fluctuations in labor costs;
•changes in, failure to comply with, and costs of compliance with laws, regulations, policies, orders, and licenses including those relating to reliability and security, the environment, climate change, natural resources, and threatened and endangered species, and associated mitigation requirements, which may result in penalties and fines, increase compliance and operational costs, and impact recovery associated with increased costs through rates;
•abnormal or severe weather conditions (including conditions and events associated with climate change), wildfires, droughts, earthquakes, and other natural phenomena and natural disasters, which affect customer sales, hydropower generation, 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 introduce operational vulnerabilities to the power grid;
•variable hydrological conditions and over-appropriation of surface and groundwater in the Snake River Basin, which may impact the amount of power generated by Idaho Power's hydropower facilities and power supply costs;
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•ability to acquire fuel, power, equipment, and transmission capacity on reasonable terms and prices, particularly in the event of unanticipated or abnormally high resource demands, price volatility, lack of physical availability, transportation constraints, outages due to maintenance or repairs to generation or transmission facilities, disruptions in the supply chain, or reduced credit quality or lack of counterparty and supplier credit;
•disruptions or outages of Idaho Power’s generation or transmission systems or of any interconnected transmission systems, which can result in liability for Idaho Power, increase power supply costs and repair expenses, and reduce revenues;
•accidents, electrical contacts, fires (either affecting or caused by Idaho Power facilities or infrastructure), explosions, infrastructure failures, general system damage or dysfunction, and other unplanned events that may occur while operating and maintaining assets, which can cause unplanned outages; reduce generating output; damage company assets, operations, or reputation; subject Idaho Power to third-party claims for property damage, personal injury, or loss of life; or result in the imposition of fines and penalties;
•acts or threats of terrorism, acts of war, social unrest, cyber or physical security attacks, and other malicious acts of individuals or groups seeking to disrupt Idaho Power's operations or the electric power grid or compromise data, or the disruption or damage to the companies’ business, operations, or reputation resulting from such events;
•increased purchased power costs and operational and reliability 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 resulting exposure to regional economic conditions and regional legislation and regulation;
•unaligned goals and positions with co-owners of Idaho Power’s generation and transmission assets;
•changes in tax laws or related regulations or interpretations of applicable laws or regulations by federal, state, or local taxing jurisdictions, and the availability of tax credits;
•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;
•ability to obtain debt and equity financing or refinance existing debt when necessary and on satisfactory terms, which can be affected by factors such as credit ratings, reputational harm, volatility or disruptions in the financial markets, interest rate fluctuations, decisions by the Idaho, Oregon, or Wyoming public utility commissions, and the companies' past or projected financial performance;
•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, and the potential losses the companies may incur on those hedges, which can be affected by factors such as the volume of hedging transactions and degree of price volatility;
•changes in actuarial assumptions, changes in interest rates, increasing health care costs, and the actual and projected return on plan assets for pension and other post-retirement plans, which can affect future pension and other postretirement plan funding obligations, costs, and liabilities and the companies' cash flows;
•remediation costs associated with planned cessation of coal-fired operations at Idaho Power’s co-owned coal plants and conversion of the plants to natural gas;
•ability to continue to pay dividends and achieve target dividend payout ratios based on financial performance and capital requirements, and in light of credit rating considerations, contractual covenants and restrictions, and regulatory limitations;
•adoption of or changes in accounting policies and principles, changes in accounting estimates, and new SEC or New York Stock Exchange requirements or new interpretations of existing requirements; and
•changing market dynamics due to the emergence of day ahead or other energy and transmission markets in the West.
Any forward-looking statement speaks only as of the date on which such statement is made. New factors emerge from time to time and it is not possible for the companies to predict all such factors, nor can they 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 is a holding company incorporated in 1998 under the laws of the state of Idaho. Its principal operating subsidiary is Idaho Power. IDACORP is subject to the provisions of the Public Utility Holding Company Act of 2005, which provides the 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 IERCo, a joint-owner of BCC, which mines and supplies coal to the 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 IFS, an investor in affordable housing and other real estate tax credit investments, and Ida-West, an operator of small hydropower generation projects that satisfy the requirements of the 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 Exchange Act as soon as reasonably practicable after the reports are electronically filed with or furnished to the 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 this report.
UTILITY OPERATIONS
Background
Idaho Power provided electric utility service to approximately 633,000 retail customers in southern Idaho and eastern Oregon as of December 31, 2023. Approximately 532,000 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 1.4 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 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 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, the FERC has jurisdiction over Idaho Power's sales of transmission capacity and wholesale electricity, hydropower project relicensing, and system reliability and security, among other items.
Regulatory Accounting
Idaho Power meets the requirements under accounting principles generally accepted in the United States of America 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. 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 customer rates, based on regulatory orders or other available evidence.
Consistent with orders and directives of the IPUC, unless contrary to applicable income tax guidance, Idaho Power does not provide deferred income tax expense or benefit for certain income tax temporary differences and instead recognizes the tax impact currently (commonly referred to as flow-through accounting) for rate making and financial reporting. Therefore, Idaho Power's effective income tax rate is impacted as these differences arise and reverse. Idaho Power recognizes such adjustments as regulatory assets or liabilities if it is probable that the amounts will be recovered from or returned to customers in future rates.
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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: keeping employees safe and engaged, growing financial strength, improving Idaho Power's core business, and enhancing Idaho Power’s brand. IDACORP's board of directors has reviewed and affirmed IDACORP’s long-term strategy. In executing on these four strategic cornerstones, IDACORP seeks to balance the interests of shareowners, Idaho Power customers, employees, and other stakeholders. Idaho Power is committed to working for strong, sustainable financial results by continuing to safely provide reliable, affordable, clean energy to its customers from diversified generation resources.
Rates and Revenues
Idaho Power generates revenue primarily through the sale of electricity to retail and wholesale customers and the provision of transmission service. The prices that the IPUC, the OPUC, and the FERC authorize Idaho Power to charge for electric power and services are critical factors in determining IDACORP's and Idaho Power's results of operations and financial condition. In addition to the discussion below, more information on Idaho Power's regulatory framework and rate regulation can be found in the “Regulatory Matters” section of Part II, Item 7 – 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 an opportunity for Idaho Power to earn a reasonable return on investment as authorized by regulators, after recovery of allowable operating expenses, including depreciation on capital investments. Idaho Power regularly evaluates the need to request changes in its retail electricity price structure through the use of general rate cases, power cost adjustment mechanisms in Idaho and Oregon, an FCA mechanism in Idaho, balancing accounts, and also uses tariff riders, and subject-specific filings to recover its costs of providing service and to earn a return on investment. Retail prices are generally determined through formal ratemaking proceedings that are conducted under established procedures and schedules before the issuance of a final order. Participants in these proceedings include Idaho Power, the staffs of the IPUC or OPUC, and other interested parties. The IPUC and OPUC are charged with ensuring that the prices and terms of service are fair, are non-discriminatory, and provide Idaho Power an opportunity to recover its prudently incurred or allowable costs and expenditures and earn a reasonable return on investment. The ability to request rate changes does not, however, ensure that Idaho Power will recover all of its costs or earn a specified rate of return, or that its costs will be recovered in advance of or at the same time when the costs are incurred.
In addition to general rate case filings, ratemaking proceedings can involve charges or credits related to specific costs, programs, or activities, as well as the recovery or refund of amounts deferred or accrued under specific authorization from the IPUC or OPUC. Deferred amounts are generally collected from, and accrued amounts are generally refunded to, retail customers through the use of base rates or supplemental tariffs. Outside of base rates, three of the most significant mechanisms for recovery of costs are the power cost adjustment mechanisms, FCA mechanism, and energy efficiency riders. For more information on these mechanisms, see Note 3 – “Regulatory Matters” and Note 4 – “Revenues” to the consolidated financial statements included in this report.
Retail Energy Sales: Weather, seasonal customer demand, energy efficiency, customer generation, customer growth, and economic conditions all impact the amount of electricity that Idaho Power sells as well as the costs it incurs to provide that electricity. Idaho Power's utility revenues are not earned, and associated expenses are not incurred, evenly during the year. Idaho Power’s retail energy sales typically peak during the summer irrigation and cooling season, with a lower peak during the winter heating season. Extreme temperatures increase sales to customers who use electricity for cooling and heating, and mild temperatures decrease sales. Availability of water and variations in temperatures and precipitation during the agricultural growing season impact electricity sales to customers who use electricity to operate irrigation pumps. Alternative methods of generation, including customer-owned solar and other forms of distributed generation, have the potential to decrease Idaho Power sales to 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, | ||||||||||||||||||||
| 2023 | 2022 | 2021 | ||||||||||||||||||
| Retail revenues (thousands of dollars): | ||||||||||||||||||||
Residential (includes $37,233, $22,595, and $34,835, respectively, related to the FCA) | $ | 684,649 | $ | 645,236 | $ | 583,061 | ||||||||||||||
Commercial (includes $1,338, $922, and $1,407, respectively, related to the FCA) | 378,330 | 347,970 | 314,745 | |||||||||||||||||
| Industrial | 244,538 | 217,368 | 195,214 | |||||||||||||||||
| Irrigation | 173,929 | 170,964 | 168,664 | |||||||||||||||||
| Provision for sharing | — | — | (569) | |||||||||||||||||
Deferred revenue related to HCC relicensing AFUDC(1) | (8,780) | (8,780) | (8,780) | |||||||||||||||||
| Total retail revenues | 1,472,666 | 1,372,758 | 1,252,335 | |||||||||||||||||
| Wholesale energy sales | 63,421 | 66,519 | 40,839 | |||||||||||||||||
| Transmission wheeling-related revenues | 80,357 | 80,527 | 67,997 | |||||||||||||||||
| Energy efficiency program revenues | 31,948 | 33,197 | 29,920 | |||||||||||||||||
| Other revenues | 114,502 | 88,039 | 64,319 | |||||||||||||||||
| Total electric utility operating revenues | $ | 1,762,894 | $ | 1,641,040 | $ | 1,455,410 | ||||||||||||||
| Energy sales (thousands of MWh): | ||||||||||||||||||||
| Residential | 5,903 | 6,056 | 5,645 | |||||||||||||||||
| Commercial | 4,269 | 4,306 | 4,164 | |||||||||||||||||
| Industrial | 3,538 | 3,510 | 3,471 | |||||||||||||||||
| Irrigation | 1,805 | 1,950 | 2,126 | |||||||||||||||||
| Total retail energy sales | 15,515 | 15,822 | 15,406 | |||||||||||||||||
| Wholesale energy sales | 840 | 427 | 600 | |||||||||||||||||
| Energy sales bundled with RECs | 1,255 | 892 | 739 | |||||||||||||||||
| Total energy sales | 17,610 | 17,141 | 16,745 | |||||||||||||||||
(1) 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.
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 program 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. Idaho Power's wholesale energy sales depend largely on the availability of generation resources above the amount necessary to serve customer loads as well as market power prices at the time when those resources are available. A reduction in either factor leads to lower wholesale energy sales.
Idaho Power also provides energy transmission services through its OATT. The OATT rate is revised each year based primarily on financial and operational data Idaho Power files annually with the FERC in its Form 1. The FERC oversees mandatory transmission and network reliability standards, as well as power and transmission markets, including protection against market manipulation. These mandatory transmission and reliability standards were developed by the North American Electric Reliability Corporation and the Western Electricity Coordinating Council, which have responsibility for compliance and enforcement of transmission, reliability, and security standards.
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.
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Idaho Power also participates in the wholesale energy markets and in the electricity transmission markets. Generally, these wholesale markets are regulated by the FERC, which requires electric utilities to transmit power to or for wholesale purchasers and sellers and make available transmission capacity, on a non-discriminatory basis, 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 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 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 to make power sales into the wholesale markets. Market purchases and sales are used to supplement Idaho Power's generation and balance supply and demand throughout the year. Idaho Power’s generating plants and their capacities are listed in Part I, Item 2 - “Properties.”
Various external and internal factors impact power supply costs, such as weather, load demand, economic conditions, fuel costs, and availability of generation resources. Idaho Power’s annual hydropower generation varies depending on water conditions in the Snake River Basin. Drought conditions and increased peak load demand cause a greater reliance on potentially more expensive energy sources to meet load requirements. Conversely, favorable hydropower generation conditions increase production at Idaho Power’s hydropower generating facilities and reduce the need for thermal generation and wholesale market purchased power. Weather also affects the generation of projects with which Idaho Power has contracts to purchase power. Economic conditions, weather, supply constraints, and governmental regulations can affect the market price of natural gas and coal, which impact fuel expense and market prices for purchased power. Idaho Power's power cost adjustment mechanisms mitigate in large part the earnings 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 MW on June 30, 2021. Idaho Power's highest all-time winter peak demand of 2,719 MW occurred on January 16, 2024. During these and other similar 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 | |||||||||||||||||||||||||||||||||||||
| 2023 | 2022 | 2021 | 2023 | 2022 | 2021 | |||||||||||||||||||||||||||||||||
| (thousands of MWh) | ||||||||||||||||||||||||||||||||||||||
| Hydropower plants | 6,548 | 5,347 | 5,382 | 55 | % | 48 | % | 48 | % | |||||||||||||||||||||||||||||
| Coal-fired plants | 2,473 | 3,657 | 2,981 | 21 | % | 32 | % | 27 | % | |||||||||||||||||||||||||||||
| Natural gas-fired plants | 2,917 | 2,319 | 2,765 | 24 | % | 20 | % | 25 | % | |||||||||||||||||||||||||||||
| Total system generation | 11,938 | 11,323 | 11,128 | |||||||||||||||||||||||||||||||||||
| Purchased power | 7,027 | 7,178 | 6,823 | |||||||||||||||||||||||||||||||||||
| Total power supply | 18,965 | 18,501 | 17,951 | |||||||||||||||||||||||||||||||||||
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 1,818 MW and have averaged total annual generation of approximately 7.6 million MWh over the last 30 years. The amount of water available for hydropower generation depends on several factors—the amount of snowpack in the mountains upstream of Idaho Power’s hydropower facilities, upstream reservoir storage, springtime precipitation and temperatures, main river and tributary base flows, the condition of the Eastern Snake Plain Aquifer and its spring flow impact, summertime irrigation withdrawals and returns, and upstream reservoir regulation. Idaho Power actively participates in collaborative work groups focused on water management issues in the Snake River Basin, with the goal of preserving the long-term availability of water for use at Idaho Power’s hydropower projects on the Snake River.
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In 2023, hydropower generation was 6.5 million MWh, an increase from the prior two years, due to above-normal snow accumulation throughout most of the Snake River basin. In 2022 and 2021, below-normal snow accumulation and drought conditions resulted in lower than average hydropower generation of 5.3 million and 5.4 million MWh, respectively. Idaho Power's 2024 estimate of annual generation from its hydropower facilities is 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:
•Jim Bridger, located in Wyoming, in which Idaho Power has a one-third interest; and
•North Valmy, located in Nevada, in which Idaho Power has a 50 percent interest.
PacifiCorp is the operator of the Jim Bridger plant. BCC supplies coal to the Jim Bridger 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. BCC has reserves to provide coal deliveries through the current term of the agreement, as well as reserves available to allow for an extension of the term agreement. Idaho Power has an established process approved by the IPUC for recovery of non-fuel, coal-related costs related to Idaho Power’s plan to end its participation in coal-fired operations at the Jim Bridger plant. The conversion from coal to natural gas of two generating units at the Jim Bridger plant is in progress and is expected to be completed in the spring of 2024.
NV Energy is the operator of the North Valmy plant. Idaho Power expects to meet 2024 and future fuel requirements through existing inventory and new or existing coal supply contracts. Idaho Power has an established process approved by the IPUC and OPUC for recovery of non-fuel costs related to Idaho Power’s plan to end its participation in coal-fired operations at the North Valmy plant. Idaho Power ended its participation in coal-fired operations at unit 1 of the North Valmy plant in December 2019, as planned.
Idaho Power's 2023 IRP identified a preferred resource portfolio and action plan that includes the conversion from coal to natural gas of two units at the Jim Bridger plant in 2024, the two units at the North Valmy plant in 2026, and the remaining two units at the Jim Bridger plant in 2030. For more information on the 2023 IRP, refer to "Resource Planning" in this Item 1 – "Business." Idaho Power expects to seek approval from the IPUC and OPUC for any necessary adjustments to plant retirement dates to align with its current resource plan.
Natural Gas-fired Generation: Idaho Power owns and operates the Langley Gulch natural gas-fired combined-cycle combustion turbine power plant and the Danskin and Bennett Mountain natural gas-fired simple-cycle combustion turbine power plants. All three plants are located in Idaho. As noted previously, in the spring of 2024, the conversion of two units at the Jim Bridger plant from coal to natural gas-fired steam turbines is expected to be completed.
Idaho Power operates the Langley Gulch plant as a baseload unit and the Danskin and Bennett Mountain plants to serve load and meet peak supply needs. The natural-gas-fired units at the Jim Bridger plant will operate to serve load and meet peak supply needs. The plants are also used to take advantage of wholesale market opportunities. Natural gas for all facilities is purchased based on system requirements and dispatch efficiency. The natural gas is transported through Idaho Power's long-term gas transportation service agreements with the Williams-Northwest Pipeline for 55,584 MMBtu per day and Williams-Mt. West Overthrust Pipeline for 89,000 MMBtu per day. These transportation agreements vary in contract length but generally contain the right for Idaho Power to extend the term. In addition to the long-term gas transportation service agreements, Idaho
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Power has entered into long-term storage service agreements with Northwest Pipeline and Spire Inc. for 131,453 MMBtu and 1 billion cubic feet, respectively, of total storage capacity. The firm storage contract with Northwest Pipeline expires in 2043, while the contract with Spire begins in 2025 and ends in 2035. Idaho Power purchases and stores natural gas with the intent of fulfilling needs as identified for seasonal peaks or to meet system requirements.
As of February 9, 2024, Idaho Power had approximately 24.5 million MMBtu of natural gas financially hedged for physical delivery, primarily for the operational dispatch of the Langley Gulch plant through September 2025. Idaho Power plans to manage the procurement of additional natural gas for the peaking units primarily on the daily spot market or from storage inventory as necessary to meet system requirements and fueling strategies.
Purchased Power: Idaho Power purchases power in the wholesale market as well as pursuant to long-term power purchase contracts and exchange agreements. The table below presents Idaho Power’s purchased power expenses and volumes for the last three years ended December 31 (in thousands, except for per MWh amounts). Transmission costs, purchases from the Western EIM, and costs from demand response programs are included with wholesale market purchases in the table.
| Year Ended December 31, | ||||||||||||||||||||
| 2023 | 2022 | 2021 | ||||||||||||||||||
| Expense | ||||||||||||||||||||
| Wholesale market purchases | $ | 243,319 | $ | 306,263 | $ | 142,248 | ||||||||||||||
| Long-term agreements (including PURPA) | 258,212 | 238,082 | 251,443 | |||||||||||||||||
| Total purchased power expense | $ | 501,531 | $ | 544,345 | $ | 393,691 | ||||||||||||||
| MWh purchased | ||||||||||||||||||||
| Wholesale market purchases | 3,278 | 3,823 | 3,168 | |||||||||||||||||
| Long-term agreements (including PURPA) | 3,749 | 3,355 | 3,655 | |||||||||||||||||
| Total MWh purchased | 7,027 | 7,178 | 6,823 | |||||||||||||||||
| Cost per MWh from wholesale market purchases | $ | 74.23 | $ | 80.11 | $ | 44.90 | ||||||||||||||
| Cost per MWh from long-term agreement purchases | $ | 68.87 | $ | 70.96 | $ | 68.79 | ||||||||||||||
| Weighted average cost per MWh - all sources | $ | 71.37 | $ | 75.84 | $ | 57.70 | ||||||||||||||
Wholesale Market: 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 program 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.
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: 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 required by federal law under PURPA. For PURPA energy sales agreements, Idaho Power is required to purchase all of the output delivered from the contracted qualifying facilities. The Idaho jurisdictional portion of the costs associated with PURPA contracts is fully recovered through base rates and the PCA mechanism, and the Oregon jurisdictional portion is recovered through base rates and an Oregon power cost adjustment mechanism. Thus, the primary impact of power purchase costs under PURPA contracts is on customer rates and the timing of cash flows.
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The following table sets forth, as of the date of this report, the resource type and nameplate capacity of Idaho Power's signed agreements for power purchases from PURPA and non-PURPA generating facilities. These agreements have contract terms ranging from one to 35 years.
| Resource Type | Non-PURPA Online (MW) | PURPA Online (MW) | Total Online (MW) | Under Contract but not yet Online (MW) | Total Projects under Contract (MW) | |||||||||||||||||||||||||||
| Wind | 101 | 625 | 726 | — | 726 | |||||||||||||||||||||||||||
| Solar | 160 | 316 | 476 | 428 | 904 | |||||||||||||||||||||||||||
| Hydropower | — | 152 | 152 | — | 152 | |||||||||||||||||||||||||||
| Other | 35 | 43 | 78 | — | 78 | |||||||||||||||||||||||||||
| Total Long-term Projects | 296 | 1,136 | 1,432 | 428 | 1,860 | |||||||||||||||||||||||||||
Idaho Power has one agreement with a PURPA-qualifying facility solar project expected to be online in 2024. Idaho Power has agreements with three non-PURPA solar projects for 100 MW, 200 MW, and 125 MW, which are scheduled to be online in 2024, 2025, and 2026, respectively.
Battery Storage: Idaho Power utilizes batteries primarily to store power generated during periods of lower customer demand and deliver that power to serve customers during peak hours, especially early summer evenings when irrigation pumps and air conditioners drive up electrical demand. In 2023, 131 MW of company-owned battery storage were installed. In April 2023, Idaho Power entered into a 20-year agreement to utilize the storage capacity from a 150-MW battery storage facility scheduled to be online in June 2025. Idaho Power intends for this capacity to supplement a total of 304 MW of company-owned storage that it expects to be online by the end of 2025.
Participation in Energy Markets: Idaho Power participates in the 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. Idaho Power is participating with other stakeholders in different regional forums discussing the potential for developing other energy markets in the western U.S., including development of a potential day-ahead wholesale centralized market, which Idaho Power believes could provide additional benefits through the centralized economic dispatch of resources of participating utilities.
Transmission Services
Electric transmission systems deliver energy from electric generation facilities to distribution systems for final delivery to customers. Transmission systems are designed to move electricity over long distances because generation facilities can be located hundreds of miles away from customers. Idaho Power’s generating facilities are interconnected through its integrated transmission system and are operated on a coordinated basis to achieve maximum capability and reliability. Idaho Power’s transmission system is directly interconnected with the transmission systems of the BPA, Avista Corporation, PacifiCorp, NorthWestern Energy, and NV Energy. These interconnections, coupled with transmission line capacity made available under agreements with some of those entities, permit the interchange, purchase, and sale of power among entities in the Western Interconnection, the transmission grid covering much of western North America. Idaho Power provides wholesale transmission service for eligible transmission customers on a non-discriminatory basis. Idaho Power is a member of the Western Electricity Coordinating Council, the Western Power Pool, NorthernGrid, and the North American 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 access transmission services under the terms of a FERC-approved OATT. Services under the OATT are offered on a non-discriminatory basis such that all potential customers, including Idaho Power, have an equal opportunity to access the transmission system. As required by FERC standards of conduct, Idaho Power's transmission function is operated independently from Idaho Power's energy marketing function.
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Idaho Power is jointly working with various partners on the development of two significant transmission projects. The Boardman-to-Hemingway project is a proposed 300-mile, high-voltage transmission line between a substation near Boardman, Oregon, and the Hemingway substation near Boise, Idaho. The Gateway West project is a high-voltage transmission line project between a substation located near Douglas, Wyoming, and the Hemingway substation. Both projects are intended to meet future anticipated resource needs and are discussed in Part II, Item 7 – MD&A - "Liquidity and Capital Resources - Capital Requirements" in this report.
Resource Planning
Integrated Resource Planning: The IPUC and OPUC require that Idaho Power prepare biennially an IRP. Idaho Power filed its most recent 2023 IRP with the IPUC and OPUC in September 2023. Each IRP seeks to forecast Idaho Power's loads and resources for a 20-year period, analyzes potential supply-side, demand-side, and transmission resource options, and identifies potential near-term, mid-term, and long-term actions. The four primary goals of the IRP are to:
•identify sufficient resources to reliably serve the growing demand for energy within Idaho Power's service area throughout the 20-year planning period;
•ensure the selected resource portfolio balances cost and risk, while including environmental considerations;
•give balanced treatment to supply-side and demand-side measures; and
•involve the public in the planning process in a meaningful way.
During the time between IRP filings, the public and regulatory oversight of the activities identified in the IRP allows for discussion and adjustment of the IRP as warranted. Idaho Power makes periodic adjustments and corrections to the resource plan to reflect economic conditions, anticipated resource development, changes in technology, and regulatory requirements.
The load forecast assumptions Idaho Power used in its 2023 IRP are included in the table below, together with the average annual growth rate assumptions used in the prior two IRPs. While assumptions are estimates only and subject to change based on actual customer load ramp-rates, the 2023 IRP assumptions include significant large commercial and industrial additions in the 5-year forecasted annual growth rate, including potential load from new facilities under development by Meta Platforms, Inc. and Micron Technology, Inc. The rate of load growth can impact the timing and extent of development of resources, such as new generation plants or transmission infrastructure, to serve those loads.
| 5-Year Forecasted Annual Growth Rate | 20-Year Forecasted Annual Growth Rate | |||||||||||||||||||
| Retail Sales (Billed MWh) | Annual Peak (Peak Demand) | Retail Sales (Billed MWh) | Annual Peak (Peak Demand) | |||||||||||||||||
| 2023 IRP | 5.5% | 3.7% | 2.1% | 1.8% | ||||||||||||||||
| 2021 IRP | 2.6% | 2.1% | 1.4% | 1.4% | ||||||||||||||||
| 2019 IRP | 1.3% | 1.4% | 1.0% | 1.2% | ||||||||||||||||
The 2023 IRP preferred resource portfolio and action plan adds 8,436 MW of resource capacity partially offset by retirements of 841 MW of coal-fired generation and 706 MW of natural gas generation over the next 20 years to meet energy and capacity needs. The additions to resource capacity include 3,325 MW of solar, 1,800 MW of wind, 1,453 MW of storage, 360 MW of additional energy efficiency, 340 MW of hydrogen, 160 MW from demand response, and 30 MW of geothermal. In addition, the preferred resource portfolio includes Idaho Power's complete exit from coal-fired generation by 2030 and the conversions of multiple jointly-owned coal-fired generation units to add 968 MW of natural gas generation capacity. Of the additional natural gas generation capacity, 706 MW are expected to be retired in 2038, resulting in a net addition of 261 MW of natural gas generation capacity through 2043. To support these resource additions, the preferred portfolio also includes the Boardman-to-Hemingway transmission line in 2026 and three Gateway West transmission line segments phased in with in-service dates from 2028 through 2040. However, as noted in the 2023 IRP, there is considerable uncertainty surrounding the resource sufficiency estimates and project completion dates, including uncertainty around the timing and extent of third-party development of renewable resources, fuel commodity prices, and the actual completion date and ownership allocations of the transmission projects. These uncertainties, as well as others, could result in changes to the desirability of the preferred portfolio and adjustments to the timing and nature of anticipated and actual actions.
Energy Efficiency and Demand Response Programs: Idaho Power’s energy efficiency and demand response portfolio is comprised of 22 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
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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 2023, Idaho Power’s energy efficiency programs reduced energy usage by approximately 140,000 MWh compared with 141,000 MWh in 2022. For 2023, Idaho Power had a demand response available capacity of approximately 312 MW. In both 2023 and 2022, Idaho Power expended approximately $42 million and expended $38 million in 2021 on both energy efficiency and demand response programs. Funding for these programs is provided through a combination of the Idaho and Oregon energy efficiency tariff riders, base rates, and the power cost adjustment mechanisms. Energy efficiency program expenditures funded through the riders are reported as an operating expense with an equal amount of revenues recorded in other revenues, resulting in no net impact on earnings.
Environmental, Social, and Governance Initiatives
Overview: IDACORP’s and Idaho Power’s corporate governance and nominating committee, with considerable focus from the board of directors, is primarily responsible for the oversight of the companies’ ESG initiatives and both are regularly informed of the goals, measures, and results of the companies' ESG programs. Each committee of the board of directors is assigned a portion of the oversight of the companies' ESG programs. Idaho Power has established an internal ESG steering committee led by senior management and composed of a cross-functional team of key employees from multiple 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 and financial condition.
IDACORP and Idaho Power publicly release annual ESG reports and the most current report is located on Idaho Power’s website, together with other information on ESG issues relevant to Idaho Power, including short-, medium-, and long-term CO2 emission reduction targets. IDACORP's and Idaho Power's 2022 ESG Report released in April 2023 incorporated elements of the Task Force on Climate-Related Financial Disclosures guidelines and the Sustainability Accounting Standards Board reporting framework, as well as the Edison Electric Institute (EEI) ESG reporting template. Additionally, in 2023 Idaho Power responded to the Climate Disclosure Project (CDP) annual questionnaire, providing emissions data and management plans to address risks associated with climate change. The ESG reports, CDP filing, and related website content are not incorporated by reference into this 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 has issued RFPs for additional energy resources, including renewables or natural gas resource convertible to hydrogen gas power, and to-date has procured solar power and battery storage as a result of those RFPs;
◦continuing various environmental stewardship programs along the Snake River, including fish habitat preservation, water temperature reduction, and fish and plant restoration;
◦wildfire mitigation planning and actions;
◦wildlife habitat, archaeological and cultural resource, and raptor protection stewardship;
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•operational excellence in safely providing reliable, affordable, 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;
•building strong community partnerships for healthy, sustainable economic development in Idaho Power’s service area; and
•publicly releasing Idaho Power's annual EEO-1 statement to report its board and employee demographic workforce data.
Reducing Carbon Emissions Intensity: Carbon emissions intensity is a measure of the pounds of CO2 emitted per MWh of energy generated. Idaho Power tracks carbon emissions intensity to measure the impact of its efforts to reduce carbon emissions relative to growing power demand in its service area. Idaho Power has actively engaged in voluntary carbon emissions intensity reduction over the past decade with an original short-term goal to reduce emissions 10-15 percent from the baseline year of 2005 levels. Idaho Power increased the short-term goal to reduce carbon emission intensity by at least 15-20 percent for the period from 2010-2020, and exceeded this goal with an estimated average reduction of 29 percent over that period compared with 2005. In 2020, IDACORP’s and Idaho Power’s boards of directors approved an increased short-term goal to reduce carbon emission intensity by 35 percent for the period from 2021-2025 compared with 2005. In 2022, Idaho Power posted its emissions reduction report on its website that established short-, medium-, and long-term targets for further CO2 reductions. This report also includes target annual power generation levels and associated CO2 emissions and emissions intensity for the 2021-2040 period. The emissions reduction report is not incorporated in this report. Idaho Power has significantly reduced its CO2 emissions since the 2005 baseline year, primarily by decreasing its coal generation levels, including terminating coal generation at the North Valmy Unit 1 in 2019 and at the Boardman plant in 2020, and also by upgrading its hydropower facilities, and through its energy efficiency, demand-side management, and cloud-seeding programs. Idaho Power plans to continue to reduce CO2 emissions in future years, including a medium-term goal with a targeted 86 percent reduction in annual CO2 emissions tons by 2030, compared with the 2005 baseline year. In 2019, Idaho Power announced its long-term goal to provide 100 percent clean energy by 2045.
Reduction in Coal-Fired Generation: Idaho Power monitors environmental requirements and assesses whether environmental control measures are or remain economically appropriate. In 2017 and 2018, the IPUC and OPUC approved settlement stipulations allowing accelerated depreciation and cost recovery for the North Valmy plant in connection with Idaho Power's plan to end its participation in the coal-fired operation of units 1 and 2. Idaho Power ended its participation in the coal-fired operation of unit 1 in December 2019, as planned, and regulatory orders from the IPUC and OPUC provide for Idaho Power to end its participation in coal-fired operations of unit 2 no later than the end of 2025. In October 2020, Idaho Power and co-owner Portland General Electric ceased coal-fired operations at the Boardman plant, as planned.
In June 2022, the IPUC approved Idaho Power's amended application requesting, among other things, authorization to allow the Jim Bridger plant to be fully depreciated and recovered by end-of-year 2030. The details of the IPUC's order relating to the Jim Bridger plant are described more fully in Part II, Item 7 – MD&A – "Regulatory Matters."
Regulatory orders from the IPUC and OPUC provide for Idaho Power to cease coal-fired operations at all jointly-owned coal-fired generation plants by the end of 2028. However, as noted previously, Idaho Power's 2023 IRP identified a preferred resource portfolio and action plan that includes the conversion from coal to natural gas of two units at the Jim Bridger plant in 2024, the two units at the North Valmy plant in 2026, and the remaining two units at the Jim Bridger plant in 2030. For more information on the 2023 IRP, refer to "Resource Planning" in this Item 1 – "Business." Idaho Power expects to seek approval from the IPUC and OPUC for any necessary adjustments to plant retirement dates to align with its current resource plan.
Climate Change Adaptation: Idaho Power believes its practice of in-depth planning and prudent preparation helps the company adapt to and address the risks of climate change. For more than 100 years, Idaho Power has adapted to changes in temperatures, water conditions, economic impacts, and regulatory requirements. In recent years, Idaho Power has proactively addressed risks associated with climate change through preventative measures. To address the physical impacts of climate change, Idaho Power conducts cloud-seeding operations, implements a WMP, enhances grid resiliency and reliability, and continues to further Snake River shading and in-stream river enhancement projects. Idaho Power also plans for the social and economic impacts of climate change by moving forward toward its carbon emissions reduction goals, continuing efforts to achieve its path away from coal generation, increasing the integration of renewable energy, and enhancing customer and stakeholder communication. Additionally, to plan for the potential regulatory impacts of climate change, Idaho Power considers climate-related impacts in planning efforts, plans and advocates for additional transmission capacity to integrate additional renewable energy onto its
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system, identifies and investigates new technologies, including battery storage, hydrogen generation, and modular nuclear reactor technology, and evaluates modifications to its pricing structure it believes will help ensure fair pricing for all customers.
Environmental Regulation and Costs
Idaho Power's activities are subject to a broad range of federal, state, regional, and local laws and regulations designed to protect, restore, and enhance the quality of the environment. Environmental regulation impacts Idaho Power’s operations due to the cost of installation and operation of equipment and facilities required for compliance with environmental regulations, the modification of system operations to accommodate environmental regulations, and the cost of acquiring and complying with permits and licenses. In addition to generally applicable regulations, Idaho Power's jointly-owned coal-fired power plants, natural gas combustion turbine power plants, and hydropower generating plants are subject to a broad range of environmental requirements, including those related to air and water quality, waste materials, and endangered species. For a more detailed discussion of these and other environmental issues, refer to Part II - Item 7 - MD&A - "Environmental Matters" in this report.
Environmental Expenditures: Idaho Power’s environmental compliance expenditures will remain significant for the foreseeable future, particularly given the volume of existing and proposed regulations at the federal level. Idaho Power estimates its environmental expenditures, based upon present environmental laws and regulations, will be as follows for the periods indicated, excluding AFUDC (in millions of dollars):
| 2024 | 2025-2026 | |||||||||||||
| Capital expenditures: | ||||||||||||||
| License compliance and relicensing efforts at hydropower facilities | $ | 27 | $ | 91 | ||||||||||
| Investments in equipment and facilities at thermal plants | 2 | 3 | ||||||||||||
| Total capital expenditures | $ | 29 | $ | 94 | ||||||||||
| Operating expenses: | ||||||||||||||
| Operating costs for environmental facilities - hydropower | $ | 25 | $ | 49 | ||||||||||
| Operating costs for environmental facilities - thermal | 9 | 21 | ||||||||||||
| Total other O&M | $ | 34 | $ | 70 | ||||||||||
Idaho Power anticipates that finalization, implementation, or modification of a number of federal and state rulemakings and other proceedings addressing, among other things, GHGs and endangered species, could result in substantial changes in operating and compliance costs, but Idaho Power is unable to estimate those changes in costs given the uncertainty associated with existing and potential future regulations. Idaho Power expects that it would seek to recover increases in costs through the ratemaking process. Beyond increasing costs generally, these environmental laws and regulations could affect IDACORP's and Idaho Power's results of operations and financial condition if the costs associated with these environmental requirements and potential early plant retirements cannot be fully recovered in rates on a timely basis.
Idaho Power is actively pursuing the relicensing of the HCC, its largest hydropower generation source. As of the date of this report, although Idaho Power believes issuance of a new HCC license by the FERC is likely in 2025 or thereafter, Idaho Power is unable to predict the exact timing of issuance by the FERC of any license order or the ultimate capital investment and ongoing operating and maintenance costs Idaho Power will incur in complying with any new license. However, Idaho Power estimates that the annual costs it will incur to obtain a new long-term license for the HCC, including AFUDC, are likely to range from $35 million to $45 million until issuance of the license. Subsequent to the issuance of a new license, Idaho Power expects to incur increased annual capital expenditures and operating and maintenance costs to comply with the requirements of any new license.
Human Capital
Overview: Idaho Power's purpose is powering lives by safely providing reliable, affordable, 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 objectives, Idaho Power’s human capital programs are designed to attract, retain, and develop high quality employees, without regard to race, color, religion, national origin, sex (including pregnancy), age, sexual orientation, gender identity, genetic information, veteran status, physical or mental disability, or marital status. Idaho Power believes it maintains a good relationship with its employees due to a strong safety culture, a respectful and inclusive environment, opportunities for
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development, and competitive compensation and benefits. Idaho Power regularly conducts employee engagement surveys to seek feedback from its employees on a variety of topics, including safety reporting, support for development, understanding of the company’s objectives, communication, being treated with respect, and feeling valued. Idaho Power shares the survey results with employees, and senior management incorporates the results of the surveys in their action plans in order to respond to the feedback and improve employee relations.
As of December 31, 2023, IDACORP had 2,100 full-time employees, 2,092 of whom were employed by Idaho Power and 8 of whom were employed by Ida-West. IDACORP had 12 part-time employees, 9 of whom were employed by Idaho Power. Of IDACORP's full-time employees, 49 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: The companies’ management updates the full board of directors and its committees regularly on safety metrics, compensation 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, general labor issues, diversity, equity, and inclusion, and safety issues. The audit committee is responsible for overseeing risk management, including compliance with the code of business conduct, physical security risks relating to employees, and environmental compliance. The corporate governance and nominating committee is responsible for overseeing risks associated with governance, lobbying and government relations, political contributions, and social issues associated with employees as part of its ESG risk oversight function.
Safety: Idaho Power is committed to the safety of its employees, customers, and the communities it serves. Idaho Power believes that safe, engaged, and effective employees are critical to the company’s success and that the company’s record of safety helps keep its service reliable and affordable. Idaho Power consistently ranks in the top 30 percent of all United States utilities in safety performance.
Compensation: Idaho Power provides its employees with competitive pay and benefits, based in large part on salary studies and market data. Idaho Power utilizes a structured compensation schedule and regularly conducts compensation analyses that helps mitigate the potential for gender, race, or ethnicity-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. 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 financial performance, power system reliability, and customer satisfaction reflective of broad stakeholder interests and each employee's contribution.
Idaho Power delivers a variety of training opportunities and continuous learning and development opportunities to all employees. Idaho Power's talent development programs, overseen by a talent development team in the Human Resources department, are designed to help employees achieve their career goals, build management skills, and lead their organizations.
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, 2023, 44 percent of Idaho Power’s senior management were women, 29 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 participation in science, technology, engineering, and mathematics education and careers, training to minimize bias and ensure a respectful and inclusive workplace, with a mindset of unity, community outreach across the communities Idaho Power serves, and partnerships with multiple diversity-focused organizations.
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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, 2023, the unamortized amount of IFS’s portfolio was approximately $57 million ($127 million in gross tax credit investments, net of $70 million of accumulated amortization). IFS generated tax credits of $6.9 million in 2023, $6.4 million in 2022, and $6.2 million in 2021. IFS received distributions related to fully-amortized real estate tax credit investments that reduced IDACORP's income tax expense by $0.5 million in 2023, $0.8 million in 2022, and $1.0 million in 2021.
IDA-WEST ENERGY COMPANY
Ida-West operates and has a 50 percent ownership interest in nine hydropower projects that have a total nameplate capacity of 44 MW. Four of the projects are located in Idaho and five are in northern California. All nine projects are “qualifying facilities” under PURPA. Idaho Power purchased all of the power generated by Ida-West’s four Idaho hydropower projects at a cost of approximately $9 million in 2023 and $8 million in both 2022 and 2021.
INFORMATION ABOUT OUR EXECUTIVE OFFICERS
The names, ages, and positions of the executive officers of IDACORP and Idaho Power are listed below (in alphabetical order), along with their business experience during at least the past five years. There are no family relationships among these officers, nor is there any arrangement or understanding between any officer and any other person pursuant to which the officer was appointed.
RYAN N. ADELMAN, 49
•Vice President of Power Supply of Idaho Power Company, August 2020 - present
•Vice President of Transmission & Distribution, Engineering and Construction of Idaho Power Company, October 2019 - August 2020
•Regional Manager for the Southeast Region of Idaho Power Company, January 2018 - October 2019
BRIAN R. BUCKHAM, 44
•Senior Vice President, Chief Financial Officer, and Treasurer of IDACORP, Inc. and Idaho Power Company, January 2024 - present
•Senior Vice President and Chief Financial Officer of IDACORP, Inc. and Idaho Power Company, March 2022 - December 2023
•Senior Vice President and General Counsel of IDACORP, Inc. and Idaho Power Company, February 2017 - March 2022
MITCH COLBURN, 40
•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
SARAH E. GRIFFIN, 54
•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, 58
•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, 48
•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
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JULIA A. HILTON, 46
•Vice President and General Counsel of IDACORP, Inc. and Idaho Power Company, March 2023 - present
•Deputy General Counsel and Director of Legal of Idaho Power Company, October 2019 - March 2023
•Senior Counsel of Idaho Power Company, January 2016 - October 2019
JEFFREY L. MALMEN, 56
•Senior Vice President of Public Affairs of IDACORP, Inc. and Idaho Power Company, April 2016 - present
ADAM J. RICHINS, 45
•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
AMY I. SHAW, 44
•Vice President of Finance, Compliance, and Risk of IDACORP, Inc. and Idaho Power Company, January 2024 - present
•Director of Investor Relations, Compliance, and Risk of IDACORP, Inc. and Idaho Power Company, August 2023 - December 2023
•Director of Compliance, Risk, and Security of Idaho Power Company, May 2017 - August 2023
ITEM 1A. RISK FACTORS
IDACORP and Idaho Power operate in a highly regulated industry and business environment that involves significant risks, many of which are beyond the companies' control. The circumstances and factors set forth below should not be considered a complete list of potential risks that the companies may encounter. These risk factors, as well as additional risks and uncertainties either not known as of the date of this report or that are currently believed to not be material to the business, may have a material impact on the business, financial condition, or results of operations of IDACORP and Idaho Power and could cause actual results or outcomes to differ materially from those discussed in any forward-looking statements. These risk factors, as well as other information in this report, including without limitation, in the "Cautionary Note Regarding Forward-Looking Statements" and Part II - Item 7 - MD&A, and in other reports the companies file with the SEC, should be considered carefully when making any investment decisions relating to IDACORP or Idaho Power.
Below are certain important utility-specific regulatory, operational, legal and compliance, financial and investment, and general business risks that may cause IDACORP's and Idaho Power's future business results to be different than anticipated as of the date of this report.
Utility-Specific Regulatory Risks
Utility-specific regulatory risk includes the risks that federal, state, or local regulators may impose additional requirements and costs on Idaho Power and the utility industry, reduce authorized rates of return or otherwise adversely affect recovery of costs and the opportunity to earn a return on investments, or require Idaho Power as a utility to make adverse changes to its business models, strategies, and practices.
State or federal regulators may not approve customer rates that provide timely or sufficient recovery of Idaho Power's costs or allow Idaho Power to earn a reasonable rate of return, which could adversely affect IDACORP's and Idaho Power's financial condition and results of operations. 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 time between when Idaho Power incurs costs and when Idaho Power recovers those costs in customers’ rates (often called "regulatory lag" in the utility industry), and differences between the costs included in rates and the amount of actual costs incurred. Idaho Power expects to incur increasing costs, which is likely to occur before the IPUC, OPUC, or FERC approve the recovery of those costs, such as construction costs for new facilities and transmission resources, costs associated with changes in the long-term cost-effectiveness or operating conditions of Idaho Power's assets that could result in early retirements of utility facilities, costs of compliance with legislative and regulatory requirements, fuel and wholesale power costs, and increased funding levels of Idaho Power's defined benefit pension plan. The IPUC, OPUC, and FERC may not allow Idaho Power to recover some or all of those costs or costs that have already been deferred as regulatory assets if they find Idaho Power did not reasonably or prudently incur those costs or for other reasons. The IPUC and OPUC may adopt different methods
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of calculating the allocation of the total utility costs in their respective jurisdictions, resulting in certain costs excluded in both states. Ratemaking has generally been premised on estimates of historic costs based on a test year, so if a given year’s actual costs are higher than historic costs, rates may not be sufficient to cover actual costs. While rate regulation is also premised on the assumption that rates established are fair, just, and reasonable, regulators have considerable discretion in applying this standard.
Economic, political, legislative, public policy, or regulatory pressures may lead stakeholders to seek rate reductions or refunds, limits on rate increases, or lower allowed rates of return on investments for Idaho Power. The ratemaking process typically involves multiple intervening parties, including governmental bodies, consumer advocacy groups, and customers, generally with the common objective of limiting rate increases or even reducing rates. While Idaho Power reached a settlement stipulation for its 2023 general rate case in Idaho that was approved by the IPUC, with the large amount of ongoing investments and the associated regulatory lag in cost recovery, Idaho Power has filed a general rate case in Oregon and on February 14, 2024, Idaho Power provided notice to the IPUC of its intent to file a general rate case or limited issue rate proceeding in Idaho on or after June 1, 2024. There can be no assurance that any rate case filed by Idaho Power will result in an outcome that is satisfactory for Idaho Power. In the past, Idaho Power has been denied recovery, or required to defer recovery pending the next general rate case, including denials or deferrals related to capital expenditures for long-term project expenses. Adverse outcomes in regulatory proceedings, or significant regulatory lag, may cause Idaho Power to incur 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 - MD&A - "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 FCA mechanism in Idaho. The power cost adjustment mechanisms track Idaho Power’s actual net power supply costs (primarily fuel and purchased power less wholesale energy sales) and compare these amounts to net power supply costs being recovered in retail rates. A majority of the differences between these two amounts is deferred for future recovery from, or refund to, customers through rates. Volatility in power supply costs continues to be significant, in large part due to fluctuations in hydropower generation conditions, fuel cost variability from factors including supply chain disruptions and inflation, supply and demand economics for fuel and power, the impact of high costs to purchase renewable energy under mandatory long-term contracts, and market price variability for power purchases from third parties based on seasonal demands and transmission system constraints. Changes in market dynamics due to the emergence of day ahead or other energy and transmission markets in the West could also increase the volatility of power supply costs. While the power cost adjustment mechanisms function to mitigate the potentially adverse impact on net income of power supply cost volatility, the mechanisms do not eliminate the cash flow impact of that volatility. When power costs rise above the level recovered in current retail rates, Idaho Power incurs the costs but recovery of those costs is deferred to a subsequent collection period, which can adversely affect operating cash flow and liquidity until those costs are recovered. The FCA 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. The power cost adjustment and FCA 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.
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.
Changes in customer growth and customer usage may negatively affect IDACORP's and Idaho Power's business, financial condition, and results of operations. Changes in the number of customers and customers' use of electricity are affected by a number of factors, such as population growth or decline in Idaho Power's service area, expansion or loss of service area, changes in customer needs and expectations, changes to customer rates, adoption rates of energy efficiency measures, customer-generated power such as from solar panels and gas-fired generators, demand-side management requirements, regulation or deregulation, and adverse economic conditions. Continued inflationary pressures, or an economic downturn or recession, could also negatively impact customer use and reduce revenues and cash flows, thus adversely affecting results of operations. Many electric utilities, including Idaho Power, have experienced a long-term decline in usage per customer, in part attributable to
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energy efficiency activities. State or federal regulations may be enacted to encourage or require mandatory energy conservation or technological advances that increase energy efficiency, which could further reduce usage per customer. Also, changing customer needs and expectations, increased customer rates as a result of the 2023 Idaho general rate case and any future rate cases, and increased competition from customer-owned generation could lead to lower customer satisfaction, reduced loyalty, difficulty in obtaining rate increases, legislation to deregulate electric service, and customers seeking alternative sources of energy and electric service. If customers choose to generate their own energy, discontinue a portion or all service from Idaho Power, or replace electric power for heating with natural gas, demand for Idaho Power's energy may decline and adversely impact the affordability of its services for remaining customers. While Idaho Power has recently experienced a net growth in usage due to an increase in the number of customers, when adjusted for the impacts of weather, the average monthly usage on a per customer basis for Idaho Power's residential customers has declined from 1,032 kWh in 2012 to 922 kWh in 2023. There is also no guarantee that Idaho Power will continue to experience an increase in the number of customers at the current rate of growth or at all. Rate mechanisms, such as the Idaho FCA for residential and small commercial customers, are designed to address the financial disincentive associated with promoting energy efficiency activities, but there is no assurance that the mechanism will result in full or timely collection of Idaho Power's fixed costs, which are currently collected in large part through the company's volume-based energy rates that are based on historical sales volume. Any undercollection of fixed costs would adversely impact revenues, earnings, and cash flows. The formation of municipal utilities or similar entities for distribution systems within Idaho Power's service area could also result in a load decrease. The loss of loads resulting from some of these events may result in excess infrastructure and stranded costs and require IDACORP and Idaho Power to modify or eliminate large generation, storage, or transmission projects. This could in turn result in reduced revenues as well as write-downs or write-offs if regulators determine that the costs of the projects were incurred imprudently, which could have a material adverse impact on IDACORP's and Idaho Power's financial condition, results of operations, and cash flows.
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 2023 IRP preferred resource portfolio and action plan included a need to acquire significant generation and storage resources to meet forecasted increasing energy and capacity needs. There can be no assurance that these energy and capacity needs will not change or that the resources will be adequate to meet load demands, in which case Idaho Power would need to rely on wholesale power purchases and would be subject to the volatility of wholesale markets. If the incremental costs associated with unanticipated changes in loads exceed the incremental revenue received from the sales to the new customers, and Idaho Power is unable to secure timely and full rate relief to recover those increased costs, the resulting imbalance could have an adverse effect on IDACORP's and Idaho Power's financial condition, results of operations, and cash flows.
Changes in weather conditions, severe weather, and the impacts of climate change can affect IDACORP's and Idaho Power's operating results and cause them to fluctuate seasonally. Idaho Power's electric power sales are seasonal, with demand in Idaho Power's service area peaking during the hot summer months, with a secondary peak during the cold winter months. Electric power demands by irrigation customers in Idaho Power's service area, which are impacted by temperatures and the timing and amount of precipitation, can also create significant seasonal changes in usage. Seasonality of revenues may be further impacted by Idaho Power's tiered rate structure, under which rates charged to customers are often higher during higher-load periods, such as hot summers and cold winters. Market prices for power also often increase significantly during these peak periods, at times when Idaho Power is required to purchase power in the wholesale markets to meet customer demand. While Idaho Power has regulatory mechanisms to help mitigate the impact of weather on power supply costs, there is no assurance that it will continue to receive such regulatory protection in the future. By contrast, when temperatures are relatively mild or where precipitation supplants irrigation systems, loads are often lower as customers are not using electricity for heating and air conditioning or irrigation purposes. Thus, weather conditions and the timing and extent of precipitation can cause IDACORP's and Idaho Power's results of operations and financial condition to fluctuate seasonally, quarterly, and from year to year.
Climate change could also have significant physical effects in Idaho Power’s service area, such as increased frequency and severity of storms, lightning, high winds, icing events, droughts, heat waves, fires, floods, snow loading, and other extreme weather events. These extreme weather events and their associated impacts could damage transmission, distribution, and generation facilities, causing service interruptions and extended or mass outages, increasing costs, and limiting Idaho Power's ability to meet customer energy demand. Sustained drought conditions or decreased snow pack due to reduced precipitation or higher temperatures are likely to decrease power generation from hydropower plants. Prolonged periods of unfavorable wind or solar conditions will temporarily reduce or eliminate the availability of power from wind and solar facilities, respectively. This could limit Idaho Power's ability to meet customer demand for those periods.
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The costs of repairing and replacing infrastructure or any costs related to Idaho Power liability for personal injury, loss of life, and property damage from utility equipment that fails, including as a result of significant weather and weather-related events and the increasing threat of fires, may not be covered by insurance. Costs incurred in connection with such events might also not be recovered through customer rates if the costs incurred are greater than those allowed for recovery by regulators.
Idaho Power's customers' energy needs vary with weather and to the extent weather conditions are affected by climate change, customers' energy use could increase or decrease. Increased energy use due to weather changes may require Idaho Power to invest in generating assets and transmission and distribution infrastructure, while decreased energy use due to weather changes may result in decreased revenues. Extreme weather conditions creating high energy demand may raise wholesale electricity prices for power that Idaho Power purchases to serve customers, increasing the cost of energy Idaho Power provides to its customers, and at the same time can increase the revenues Idaho Power receives for wholesale market sales of excess generation during regional extreme weather events. Variations in hydropower generation that increase Idaho Power's reliance on market purchases may lead to more costly power supply sources for its customers and reduce benefits from selling surplus hydropower in the wholesale market. The price of power in the wholesale energy markets tends to be higher during periods of high regional demand that tends to occur with weather extremes, which may cause Idaho Power to purchase power in the wholesale market during peak price periods, increasing power supply costs. Idaho Power has in place mechanisms to help mitigate the effects of energy market price volatility, but there is no assurance these mechanisms will continue to be in place or function as intended.
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 capital markets on favorable terms. For additional information relating to legislation, regulations, and legal proceedings related to environmental matters, see Part II - Item 7 - MD&A - "Environmental Matters” in this report.
Liability from fires could adversely impact IDACORP's and Idaho Power's business, financial condition, and results of operations, and Idaho Power's WMP and other protocols may not prevent such liability. Fires alleged to have been caused by Idaho Power's transmission, distribution, or generation infrastructure, or that allegedly result from Idaho Power’s or its contractors’ operating or maintenance practices, could expose Idaho Power to claims for fire suppression and clean-up costs, evacuation costs, fines and penalties, and liability for economic damages, personal injury, loss of life, property damage, and environmental pollution, whether based on claims of negligence, trespass, or otherwise. The risk of wildfires is exacerbated in forested areas where beetle infestations and rising tree mortality rates have caused a significant increase in the quantity of standing dead and dying timber, increasing the risk that such trees may fall from either inside or outside Idaho Power's right-of-way into a powerline igniting a fire and increasing the severity of fires. A significant number of urban-wildland interfaces in and near Idaho Power's service area, and commonly hot, dry summer conditions that may worsen as a result of climate change, increase the likelihood and magnitude of damages that may be caused by fires burning into or allegedly originating from utility equipment. Further, there has been an increasing trend in the degree of annual destruction from wildfires in the western United States, as well as utility companies facing claims for significant damages resulting from wildfires. Idaho Power maintains insurance coverage for such risks, but insurance coverage is subject to terms and limitations and may not be sufficient to cover Idaho Power’s ultimate liability. Coverage limits within wildfire insurance policies could result in material self-insured costs due to self-insured retention amounts under the terms of Idaho Power’s insurance policies. Idaho Power or its contractors and customers could also experience coverage reductions and increased wildfire insurance costs in future years. Idaho Power may be unable to recover costs in excess of insurance through customer rates or regulatory mechanisms and, even if such recovery is possible, it could take several years to collect. If the amount of insurance is insufficient or otherwise unavailable, and if Idaho Power is unable to fully recover in rates the costs of uninsured losses, IDACORP’s and Idaho Power’s business, financial condition, and results of operations could be materially affected.
Idaho Power spends significant resources on initiatives designed to mitigate wildfire risks, including through its WMP, but there is no assurance that the WMP and protocols such as the PSPS will be successful or effective in reducing wildfire-related losses. Idaho Power will face a higher likelihood of wildfires in its service area if it cannot effectively implement its WMP. There also can be no assurance that the WMP and protocols such as the PSPS will be effective. For instance, a wildfire may be ignited and spread even in conditions that do not trigger a PSPS event. Idaho Power's inspections of vegetation near its assets may not detect structural weaknesses within a tree or other issues. If Idaho Power's WMP and protocols are not effective, a wildfire could be ignited and spread. To the extent Idaho Power’s criteria for implementing a PSPS are not sufficient to mitigate the risk of wildfires, Idaho Power does not fully implement a PSPS when criteria are met, due to other overriding factors, or
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Idaho Power’s regulators mandate changes to, or restrictions on, its criteria or other operational PSPS practices, Idaho Power will face a higher likelihood of wildfires in its service area during high-risk weather conditions.
New advances in power generation, energy efficiency, alternative energy sources, or other technologies that impact the power utility industry could decrease customer energy demand and revenues, which could have implications for generation and system planning. Advances in technology and changes in customer demand and preferences in the electric utility industry have encouraged the development of new technologies for power generation, renewable energy, energy storage, customer-owned generation, and energy efficiency. In particular, in recent years the net cost of solar and wind generation and storage technology has decreased significantly, and there are federal and state regulations, laws, and other incentives in place to help further reduce the net cost of solar, wind, and energy storage facilities. There is potential that customer-owned solar power generation systems, could become sufficiently cost-effective and efficient that an increasing number of Idaho Power's customers choose to install such systems on their homes or businesses, which in turn could require changes in the way Idaho Power builds and manages its distribution systems and substantial grid infrastructure costs, and at the same time reduce the demand for and sale of energy. Additionally, considerable emphasis has been placed on energy efficiency, such as LED lighting and high-efficiency appliances. Energy efficiency programs, including programs sponsored by Idaho Power under a directive from state regulatory commissions, are designed to reduce energy use and demand. The introduction of new technologies could pose risks in the form of reduced sales and new business models for energy services. These changes in technology could also alter the channels through which customers buy or utilize energy, including the potential formation of community-based, cooperative ownership or municipal structures, which could reduce Idaho Power's revenues or impact Idaho Power's expenses. A reduction in load, however, would not necessarily reduce Idaho Power's need for ongoing investments in its infrastructure to reliably serve its customers. If Idaho Power is unable to adjust its rate design or maintain adequate regulatory mechanisms allowing for timely cost recovery, declining usage from customer-owned generation sources and energy efficiency could result in under-recovery of Idaho Power's costs and investment in infrastructure, and reduce revenues, which would impact IDACORP's and Idaho Power's financial condition and results of operations.
Acts or threats of terrorism, acts of war, social unrest, cyber or physical security attacks, and other malicious acts of individuals or groups seeking to disrupt Idaho Power's operations or the electric power grid or compromise data could adversely impact IDACORP's and Idaho Power's business, financial condition, and results of operations. Idaho Power operates in an industry that requires the continuous use and operation of sophisticated information technology and increasingly complex operational technology systems and network infrastructure. Idaho Power's generation and transmission facilities and its grid operations are potential targets for terrorist acts and threats, acts of war, social unrest, cyber and physical security attacks, and other disruptive activities of individuals or groups, including by nation states or nation state-sponsored groups. There have been cyber and physical attacks within the energy industry on energy infrastructure such as electric substations and fuel pipelines in the past with notable reports in the media of electric industry infrastructure specifically being targeted for and impacted by physical attacks more recently, and there are likely to be additional attacks in the future. Idaho Power and its vendors have been subject to, and will likely continue to be subject to, attempts to gain unauthorized access to systems and confidential information, or to disrupt operations. As noted by the U.S. Department of Homeland Security, the utility industry is continuing to experience an increase in the frequency and sophistication of cybersecurity incidents.
Some of Idaho Power's facilities are deemed "critical infrastructure" under federal standards, in that incapacity or destruction of the facilities could have a debilitating impact on security, reliability, or operability of the bulk electric power system, national economic security, and public health and safety. The fact that infrastructure facilities, such as power generation facilities and electric transmission or distribution facilities, are direct targets of, or potential indirect casualties of, an act of terror or war or cyber or physical attack (whether originating internal to Idaho Power or externally), may affect Idaho Power's operations by limiting the ability to generate, purchase, or transmit power. Idaho Power's electric transmission systems are part of an interconnected regional grid, and therefore, it faces the risk of causing or being subject to a long-term power outage due to grid disturbances or disruptions on a neighboring interconnected grid system. Cyber and physical threats and attacks can have cascading impacts that unfold with increasing speed across networks, information systems, and other technologies. Network, information systems, and technology-related events, including those caused by IDACORP or Idaho Power through process breakdowns, human error, security architecture or design vulnerabilities, or by third parties through cyber or physical security attacks, could result in a degradation or disruption in the energy grid and the services of the companies, as well as the ability to record, process, and report customer, business, and financial information. Physical or cyber attacks against key suppliers or service providers could have a similar effect on Idaho Power.
Idaho Power's business operations require the continuous availability of information technology systems and network infrastructure, and in the normal course of business, Idaho Power or its vendors collect and store sensitive and confidential customer and employee information and proprietary information of Idaho Power. Idaho Power’s technology systems are
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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. All information technology systems are vulnerable to being disabled, unauthorized access, unintentional defects, user error, errors in system changes, and cybersecurity incidents. Idaho Power is in the process of pursuing complex business system upgrades, and these significant changes increase the risk of system interruption. Any data security breaches, such as misappropriation, misuse, leakage, falsification or accidental release or loss of information maintained in Idaho Power's information technology systems or on third-party systems, including customer or employee data, could result in violations of privacy and other laws and associated litigation and liability for damages, fines, and penalties; financial loss to Idaho Power or to its customers; customer dissatisfaction or diminished customer confidence; and damage to Idaho Power’s reputation, all of which could materially affect Idaho Power's financial condition and results of operations.
No security measures can completely shield Idaho Power's systems, infrastructure, and data from vulnerabilities to cyber attacks, human error, intrusions, or other catastrophic events that could result in their failure or reduced functionality, and ultimately the potential loss of sensitive information or the loss of Idaho Power's ability to fulfill critical business functions and provide reliable electric power to customers. Despite the steps Idaho Power may take to detect, mitigate, or eliminate threats and respond to security incidents, the techniques used by those who seek to obtain unauthorized access, and possibly disable or sabotage systems or abscond with information and data, change frequently and Idaho Power may not be able to protect against all such actions. Idaho Power actively monitors developments in 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, 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.
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 2023 IRP. Idaho Power is not only in the permitting process for two high-voltage transmission line projects, but has also entered into contracts to purchase, own, and operate 304 megawatts of battery storage assets as well as issued RFPs for new resources, 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;
•increases in price and limitations on availability of commodities, materials, and equipment;
•imposition of tariffs on commodities, materials, and equipment sourced by foreign providers;
•equipment, engineering, and design failures;
•credit quality of counterparties and suppliers and their ability to meet financial and operational commitments;
•unexpected environmental and geological problems;
•the effects of adverse weather conditions;
•catastrophic events, natural disasters, epidemics, pandemics and other public health or disruptive events that could result in supply chain disruptions, as well as permitting and construction delays;
•availability of financing;
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•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 could exceed supply, resulting in deliverability risks and increased costs for, or difficulty in, purchasing capacity in the market or acquiring or constructing additional generation resources and battery storage facilities. Idaho Power's 2023 IRP identified a low-cost preferred resource portfolio and action plan for the next 20-year period that includes adding substantial renewable resources and the conversion from coal to natural gas of two units at the Jim Bridger plant in 2024, the two units at the North Valmy plant in 2026, and the remaining two units at the Jim Bridger plant in 2030. As Idaho Power implements the IRP's action plan, it remains obligated to provide reliable and affordable energy to its customers, but there are certain potential deliverability and cost risks associated with implementation. These risks include, but are not limited to, (1) the failure to timely obtain or construct additional resources to meet forecast needs related to load growth, (2) increased renewable energy generation presenting risks of uncertainty and variability that could be further compounded as neighboring systems transition towards increasing levels of renewable resources, and (3) increased potential resource volatility due to changes in the energy market. During peak periods, power demand could exceed, and on occasion has exceeded, Idaho Power’s available generation capacity, particularly if Idaho Power’s power plants are not performing as anticipated and additional resources and battery storage are not available 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 2023 and 2022, 55 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 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
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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. Idaho Power's current coal supply arrangements are under long-term contracts for coal originating in Wyoming, Utah, and Colorado, and thus Idaho Power is exposed to risk of disruption of coal production in, or transportation from, those regions. Idaho Power may from time to time enter into new, or renegotiate, these contracts but can provide no assurance that such contracts will be negotiated or renegotiated on satisfactory terms, or at all. There also can be no assurance that counterparties to the natural gas or coal supply agreements will fulfill their obligations to supply natural gas or coal, and they may experience regulatory, financial, or technical problems or unforeseeable events that inhibit their ability to deliver natural gas or coal. Disruptions in transportation of fuel and defaults by coal and natural gas suppliers may cause Idaho Power to seek alternative, and potentially more costly, sources of fuel or rely on other generation sources or wholesale market power purchases. Idaho Power's failure to provide service due to such disruptions may also result in fines, penalties, or cost disallowances through the regulatory process. Idaho Power may not be able to fully or timely recover these increased costs through rates and power cost adjustment mechanisms, which may adversely affect IDACORP's and Idaho Power's financial condition and results of operations.
Idaho Power’s power supply, transmission, and distribution facilities are subject to numerous operational risks unique to it and its industry, including circumstances causing power outages, injuries and property damage, loss of life, and fires. Operating risks associated with Idaho Power's power supply, transmission, and distribution facilities include equipment failures, volatility in fuel and transportation pricing, interruptions in fuel supplies, increased regulatory compliance costs, changes necessitated by environmental legislation or litigation, labor disputes or attrition, accidents and workforce safety matters, environmental damage, property damage, wildfires, acts of terrorism or war or sabotage (both cyber and asset-based), the loss of cost-effective disposal options for solid waste such as coal ash, operator error, and the occurrence of catastrophic events at the facilities. Idaho Power maintains business continuity and disaster recovery plans, but such plans may be inadequate or not function as anticipated, which could result in delayed recovery after any such events. Diminished availability or performance of those facilities could result in reduced customer satisfaction, reputational harm, liability to third parties (including tort liability), and regulatory inquiries and fines. Operation of Idaho Power's owned and co-owned generating stations below expected capacity levels, or unplanned outages at these stations, could cause reduced energy output and lower efficiency levels and result in lost revenues and increased expenses for alternative fuels or wholesale market power purchases. Further, during high-load periods the transmission system in Idaho Power's service area is constrained, limiting the ability to transmit electric energy within the service area and access electric energy from outside the service area. Idaho Power's transmission facilities are also interconnected with those of third parties, and thus operation of Idaho Power's and third-parties' facilities could be adversely affected by unexpected or uncontrollable events. These transmission constraints and events could result in failure to provide reliable service to customers and the inability to deliver energy from generating facilities to the power grid, and the inability to access lower cost sources of electric energy. Idaho Power also enters into agreements with third-party contractors to perform work on its power supply, transmission, and distribution facilities, and may in some circumstances retain liability for the quality and completion of those contractors’ work, potentially subjecting Idaho Power to penalties, liability for personal injury, loss of life, or property damage, reputational harm, or enforcement actions or liability if a contractor violates applicable laws, rules, regulations, or orders.
Accidents, acts of terrorism or war, electrical contacts, fires, explosions, catastrophic failures, general system damage or dysfunction, intentional acts of destruction, uncontrolled release of water from hydropower dams, and other unplanned events related to Idaho Power's infrastructure would increase repair costs and may expose Idaho Power to liability for personal injury, loss of life, and property damage. Idaho Power maintains insurance coverage for such operating and event risks, but insurance coverage is subject to terms and limitations and may not be sufficient to cover Idaho Power’s ultimate liability. Idaho Power may be unable to recover costs in excess of insurance through customer rates or regulatory mechanisms and, even if such recovery is possible, it could take several years to collect. If the amount of insurance is insufficient or otherwise unavailable, and if Idaho Power is unable to fully recover in rates the costs of uninsured losses, IDACORP’s and Idaho Power’s financial condition, results of operations, or cash flows could be materially affected.
Purchases of power mandated by PURPA from renewable energy projects may increase costs and adversely affect Idaho Power's and IDACORP's results of operations and financial condition. Under PURPA, Idaho Power is generally obligated 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, 2023, Idaho Power had contracts mandated under PURPA to purchase energy from 130 online projects with third parties. Absent a need for this generation, these contracts increase the likelihood and frequency that Idaho Power will be required to reduce output from its lower-cost generation resources, which in turn increases power purchase costs and customer rates and impacts Idaho Power's ability to invest in
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additional generation and earn a reasonable return on rate base in the future. 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 nearly all of IDACORP's operations, and Idaho Power's business is concentrated solely in the electric power industry. Furthermore, Idaho Power's provision of electric service to retail customers is conducted exclusively in its southern Idaho and eastern Oregon service area. As a result, IDACORP's and Idaho Power's future performance, revenues, and collectability of revenues, as well as expenses, will be affected by regional economic conditions, regulatory and legislative activity, weather conditions, and other events and conditions in its service area and in the electric power industry.
The impacts of a retiring workforce with specialized utility-specific functions and the inability to hire qualified third-party vendors could increase costs and adversely affect IDACORP's and Idaho Power's financial condition and results of operations. Idaho Power’s operations require a skilled workforce to perform specialized utility functions. Many of these positions, such as linemen, grid operators, engineering and design personnel, and generation plant operators, require extensive, specialized training. Idaho Power does not have employment contracts with its officers or key employees and cannot guarantee that any member of its management or any key employee at the IDACORP parent or any subsidiary level will continue to serve in any capacity for any particular period of time. Employee retention and recruitment may also be negatively impacted by more flexible remote work opportunities, higher pay offered by other employers, or lower cost of living in other areas. The loss of skills and institutional knowledge of experienced employees, the failure to foster an innovative, inclusive, equitable, and diverse environment in order to hire appropriately qualified employees, the costs associated with attracting, training, and retaining such employees to replace an aging and skilled workforce or the inability to do so, and the operational and financial costs of unionization or the attempt to unionize all or part of the companies’ workforce, could have a negative effect on IDACORP's and Idaho Power's financial condition and results of operations. Idaho Power could incur increased costs as a result of such turnover due to a loss of knowledge, errors due to inexperienced employees, substantial training time, loss of productivity, and increased safety and compliance issues.
Idaho Power also hires third-party vendors to assist in performing a variety of ordinary business functions, such as power plant maintenance, data warehousing and management, software development and licensing, electric transmission and distribution operations, billing and metering processes, and vegetation management, among other things. In recent years, Idaho Power has experienced increased competition and rising prices for many forms of third-party vendor services. While Idaho Power does not rely entirely on third-party vendors for many of these business functions, the unavailability of such vendors could adversely affect the quality and cost of Idaho Power's electric service and negatively impact its results of operation.
Co-owners of Idaho Power’s generation and transmission assets may have unaligned goals and positions due to the effects of legislation, regulations, capital requirements, load growth amounts, changes in our industry, or other factors, which could at times adversely impact Idaho Power’s ability to construct and operate those facilities in a manner most suitable to Idaho Power. Idaho Power owns certain of its generation and transmission assets jointly with other owners, with varying ownership interests in such facilities, and Idaho Power plans to develop and own assets jointly in the future. While there are advantages to joint ownership of resources, there are also restrictions imposed by the joint ownership and operating agreements for those facilities that provide rights, but also restrictions, on when and how the facilities are constructed and on how they are operated. Changes in the nature of Idaho Power’s industry and the economic viability of certain plants and facilities, including impacts resulting from types and availability of other resources, fuel costs, and legislation and regulation, together with timing considerations related to expiration of permits or leases or other agreements for such facilities and other factors, could result in unaligned positions among co-owners. While Idaho Power negotiates and enforces its rights and obligations thoughtfully, differences in the co-owners’ willingness or ability to continue their participation or the timing of facility construction, modification, or decommissioning could lead to restrictions and disruptions to operations, adverse financial impacts to Idaho Power, and/or uncertainty related to the resulting cost recovery of such assets.
Legal and Compliance Risks
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, environment, health, and safety, and potential changes in legal requirements.
Changes in legislation, regulation, and government policy may have a material adverse effect on IDACORP’s and Idaho Power’s business in the future. Specific legislative and regulatory proposals and recently enacted legislation that could have a
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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. 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 - MD&A - "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.
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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 could 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.
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 long-term goal to serve customers with 100 percent clean energy by 2045, and Idaho Power has short-term and medium-term goals for CO2 emission reductions, which could impact infrastructure resource decisions and costs. Idaho Power's ability to achieve these targets are subject to a number of risks and uncertainties, including the company's regulatory obligation to serve its customers, the availability and cost of new generation resources, legal and permitting requirements, system operation and energy integration, and grid balancing, among others. Additionally, Idaho Power is not guaranteed timely or full recovery through customer rates of costs associated with environmental regulations, environmental compliance, its clean energy initiatives, plant closures, or clean-up of contamination. If there is a delay in obtaining any required environmental regulatory approval or if Idaho Power fails to obtain, maintain, or comply with any such approval, construction and/or operation of Idaho Power's generation or transmission facilities could be delayed, halted, terminated, or subjected to additional costs. For further discussion of environmental matters that may affect Idaho Power, see "Environmental Matters" in Item 7 - MD&A in this report.
Obligations imposed in connection with hydropower license renewals and permitting may require large capital expenditures, increase operating costs, reduce hydropower generation, and negatively affect IDACORP's or Idaho Power's results of operations and financial condition. Since 2003, Idaho Power has been engaged in an effort to renew its federal license for its largest hydropower generation source, the HCC. Relicensing and ongoing permitting requirements include an extensive public review process that involves numerous natural resource issues and environmental conditions. The existence of endangered and threatened species in the watershed may result in major operational changes to the region’s hydropower projects, which may be reflected in hydropower licenses, including for the HCC and the American Falls facility. Federal land use agencies may also impose conditions under the FPA that could impact costs and operations if FERC deems them necessary for the adequate protection and utilization of the public lands and reservations of the United States. In addition, new agency requirements and new interpretations of existing laws and regulations could be adopted or become applicable to hydropower facilities, which could further increase required expenditures for flood control, marine life recovery and endangered species protection and may reduce the amount of hydropower generation available to meet Idaho Power’s generation requirements. Idaho Power cannot predict the requirements that might be imposed during the relicensing and permitting process, the financial impact of those requirements, 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 $1.5 million per day per violation. As a utility with a large customer base, Idaho Power is subject to adverse publicity focused on the reliability of its services and the speed with which it is able to respond to electric outages caused by storm damage or other unanticipated events. Adverse publicity could harm the reputations of IDACORP and
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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 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 accounting principles generally accepted in the United States of America to reflect the impact of regulatory decisions in its financial statements and to defer certain costs as regulatory assets until those costs are collected in rates, and to defer some items as regulatory liabilities. If recovery of these amounts ceases to be probable, if Idaho Power determines that it no longer meets the criteria for applying regulatory accounting or if accounting rules change to no longer provide for regulatory assets and liabilities, Idaho Power could be required to eliminate some or all of those regulatory assets or liabilities. Any of these circumstances could result in write-offs and have a material effect on IDACORP's and Idaho Power’s financial condition and results of operations.
Financial and Investment Risks
Financial and investment risks relate to IDACORP's and Idaho Power's ability to meet financial obligations and mitigate exposure to market risks, including liquidity risks and the ability to raise capital and cost of funding, risks related to credit ratings, credit risk, liquidity, interest rates, and commodity prices.
Volatility or disruptions in the financial markets, failure of IDACORP or Idaho Power to satisfy conditions necessary for obtaining loans or issuing debt securities, and denial of regulatory authority to issue debt or equity securities, may negatively affect IDACORP’s and Idaho Power’s ability to access capital and/or increase their cost of borrowing and ability to execute on their strategic plans. IDACORP and Idaho Power use credit facilities, commercial paper markets, long-term debt, and equity securities as significant sources of liquidity and funding for operating and capital requirements and debt maturities not satisfied by operating cash flow. 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, commercial paper, and equity securities is subject to the availability of purchasers willing to purchase the securities under reasonable terms or at all. Because of these limitations, IDACORP and Idaho Power may be unable to issue commercial paper, short-term or long-term debt, or equity securities on reasonable 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
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manner to permit them to finance their operations, capital expenditures, and debt maturities. IDACORP's and Idaho Power's credit facilities consist of revolving lines of credit not to exceed an aggregate principal amount outstanding at any one time of $100 million and $400 million, respectively (Credit Facilities). Each of the Credit Facilities includes a financial covenant that limits 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 requests 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.
Stakeholder actions and increased regulatory activity related to ESG matters, particularly global climate change and reducing GHG emissions, could negatively impact IDACORP and Idaho Power. The power and gas utility industry is facing increasing stakeholder scrutiny related to ESG matters. Recently, Idaho Power has seen a rise in certain stakeholders, such as investors, customers, suppliers, employees, and lenders, placing increasing importance on the impact and social cost associated with climate change. Customers, suppliers, or other stakeholders could pursue, and in some cases have pursued, alternatives to Idaho Power's services or business as a result of their ESG-related expectations. GHG emissions, including, most significantly CO2, could be further restricted in the future in response to additional state and federal regulatory requirements, increased scrutiny, and changing stakeholder expectations with respect to environmental and climate change programs, judicial decisions, and international accords. If new emissions reduction rules were to become effective, they could result in significant additional compliance costs that could negatively impact Idaho Power's future financial position, results of operations, and cash flows if such costs are not timely recovered through regulated rates. Moreover, the possibility exists that stricter laws, regulations, or enforcement policies could significantly increase compliance costs and the cost of any remediation that may become necessary. In addition, the increasing focus on climate change and stricter regulatory and legal requirements may result in Idaho Power facing adverse reputational risks associated with certain of its operations producing GHG emissions. If Idaho Power is unable to satisfy the increasing climate-related expectations of certain stakeholders, IDACORP and Idaho Power may suffer reputational harm, which could cause IDACORP’s stock price to decrease or cause certain investors and financial institutions not to purchase the companies’ debt or equity securities or otherwise provide the companies with capital or credit on favorable terms, which may cause IDACORP’s and Idaho Power’s cost of capital to increase.
Idaho Power’s energy risk management policy and programs relating to economically hedging commodity exposures and credit risk may not always perform as intended, and as a result, IDACORP and Idaho Power may suffer 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 economic hedge transactions to mitigate in part exposure to variable commodity prices. IDACORP and Idaho Power could recognize 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 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
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commodity prices that lead to the posting of collateral with counterparties negatively impact liquidity, and downgrades in Idaho Power's credit ratings may lead to additional collateral posting requirements. In 2023, Idaho Power recorded losses on economic hedges of $16.2 million, compared with $68.5 million of gains in 2022. At times, Idaho Power’s energy risk management policy results in Idaho Power entering into economic hedges in an environment where prices are high, and if prices are lower at the time the economic hedge settles, Idaho Power will record losses on the economic hedges. Depending on the volume of economic hedges and the degree of price volatility, those losses can be substantial, and the power cost adjustment mechanisms generally provide that Idaho Power will incur a portion of those losses. Forecasts of future fuel needs and loads and available resources to meet those loads are inherently uncertain and may cause Idaho Power to over- or under-hedge actual resource needs, exposing the company to market risk on the over- or under-hedged position. To the extent that commodity markets are illiquid, Idaho Power may not be able to execute its risk management strategies, which could result in undesired over-exposure to unhedged positions that Idaho Power may not be able to collect in customer rates. The FERC may take action to limit volatility in the energy market by imposing price limits or other market restrictions to control market-based rate sales, which could adversely affect the companies' financial results. As a result, risk management actions, or the failure or inability to manage commodity availability and price and counterparty risk, may adversely affect IDACORP’s and Idaho Power’s financial condition and results of operations. Idaho Power has additional indirect credit exposures to financial institutions in the form of letters of credit provided as security by power suppliers under various purchased power contracts and by vendors for infrastructure development projects. If any of the credit ratings of the letter of credit issuers were to drop below investment grade, the vendor or supplier would need to replace the security with an acceptable substitute, which may be impracticable and may expose Idaho Power to losses resulting from a vendor or supplier default. If the security were not replaced, the party could be in default under the contract and Idaho Power's remedies for default may be inadequate to fully compensate Idaho Power for its losses. Further, the bankruptcy or insolvency of a counterparty to commodity or other transactions could impair Idaho Power’s ability to collect amounts receivable from those counterparties, potentially including the ability to collect or retain collateral posted by a counterparty.
Idaho Power is a participant in the energy markets, including the Western EIM, and engages in direct and indirect power purchase and sale transactions in connection with that participation. The Western EIM has collateral posting requirements based on established credit criteria, but there is no assurance the collateral will be sufficient to cover obligations that counterparties may owe each other in the Western EIM and any such credit losses could be socialized to all Western EIM participants, including Idaho Power. A significant failure of a participant in the Western EIM to make payments when due on its obligations could have a ripple effect on various Idaho Power counterparties in the power, gas, and derivative markets if those counterparties experience ancillary liquidity issues, and could generally result in a decline in the ability of Idaho Power’s counterparties to perform on their obligations.
The performance of pension and postretirement benefit plan investments, increasing health care costs, and other factors impacting plan costs and funding obligations could adversely affect IDACORP's and Idaho Power's financial condition and results of operations - primarily cash flows and liquidity. Idaho Power provides a noncontributory defined benefit pension plan covering most employees, as well as a defined benefit postretirement benefit plan (consisting of health care and death benefits) that covers eligible retirees. Costs of providing these benefits are based in part on the value of the plans' assets and, therefore, adverse investment performance for these assets or the failure to maintain sustained growth in pension investments over time could increase Idaho Power’s plan costs and funding requirements related to the plans. Idaho Power's self-insured costs of health care benefits for eligible employees and retirees have increased in recent years and Idaho Power believes that future legislative changes related to the provision of health care benefits and other external market conditions and factors, could cause such costs to continue to rise. As benefit costs continue to rise, there is no assurance that the IPUC and OPUC will continue to allow recovery.
The key actuarial assumptions that affect pension funding obligations are the expected long-term return on plan assets and the discount rate used in determining future benefit obligations. Idaho Power evaluates the actuarial assumptions on an annual basis, taking into account changes in market conditions, trends, and future expectations. Estimates of future investment market performance, changes in interest rates, and other factors Idaho Power and its actuary firms use to develop the actuarial assumptions are inherently uncertain, and actual results could vary significantly from the estimates. Changes in demographics, including timing of retirements or changes in life expectancy assumptions, may also increase Idaho Power's plan costs and funding requirements. Future pension funding requirements and the timing of funding payments are also subject to the impacts of changes in legislation. Depending on the timing of contributions to the plans and Idaho Power's ability to recover costs through rates, cash contributions to the plans could reduce the cash available for the companies' businesses and payment of dividends. For additional information regarding Idaho Power's funding obligations under its benefit plans, see Note 11 - "Benefit Plans" to the consolidated financial statements included in this report.
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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. BCC, an indirect jointly-owned investment of Idaho Power located in the state of Wyoming, uses surface mining to extract coal to be used for power generation at the Jim Bridger 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 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 6 - "Common Stock" to the consolidated financial statements included in this report for a further description of restrictions on IDACORP's and Idaho Power's payment of dividends.
The market price of IDACORP's common stock may be volatile. The market price of IDACORP's common stock could be subject to significant fluctuations in response to factors such as the following, some of which are beyond its control:
•variations in IDACORP and Idaho Power's quarterly operating results;
•operating results that vary from the expectations of management, securities analysts, and investors and other impacts from the risks identified in this "Risk Factors" section and elsewhere in this report;
•changes in expectations as to future financial performance, including financial estimates by securities analysts or investors;
•developments generally affecting IDACORP and Idaho Power's industry;
•announcements by IDACORP and Idaho Power of significant contracts, acquisitions, joint ventures, or capital commitments;
•announcements by third parties of significant claims or proceedings against IDACORP or Idaho Power;
•favorable or adverse regulatory or legislative developments;
•IDACORP's dividend policy;
•change in IDACORP or Idaho Power's management;
•future sales of IDACORP's equity or equity-linked securities; and
•general domestic and international economic conditions.
In addition, the stock market in general has experienced volatility that has often been unrelated to the operating performance of a particular company. These broad market fluctuations may adversely affect the market price of IDACORP's common stock.
IDACORP's charter and bylaws and Idaho law could delay or prevent a change in control that shareholders may favor. The terms of some of the provisions in IDACORP's articles of incorporation and bylaws and provisions of Idaho law could delay or prevent a change in control that shareholders may favor or may impede the ability of shareholders to change IDACORP's management. In particular, the provisions of IDACORP's articles of incorporation and bylaws authorize issuance of up to 20,000,000 shares of preferred stock without further action by shareholders; limit the shareholders’ right to remove directors, fill vacancies and change the number of directors; regulate how shareholders may present proposals or nominate directors for election at shareholders’ meetings; and require a supermajority vote of shareholders to amend certain provisions. IDACORP is also subject to the provisions of the Idaho Control Share Acquisition Act and the Idaho Business Combination Act, which provide for certain procedures and restrictions in connection with acquisitions or business combinations.
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Statutory and regulatory factors will limit another party’s ability to acquire IDACORP and could deprive shareholders of the opportunity to gain a takeover premium for their shares of common stock. Even if IDACORP's board of directors favors a sale of the company, a sale would require approval of a number of federal and state regulatory agencies, including the FERC, the IPUC, the OPUC, and the WPSC. The approval process could be lengthy and the outcome uncertain, which may deter otherwise interested parties from proposing or attempting a business combination.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 1C. CYBERSECURITY
Assessing, identifying, managing, and mitigating risks from cybersecurity threats that may affect Idaho Power's systems and service are essential to its business. IDACORP's and Idaho Power's board of directors oversees risks from cybersecurity threats through the audit committee and the executive committee. The audit committee assists the board in the oversight of Idaho Power's major cybersecurity risk exposures, including oversight of management’s information security activities. Those activities include briefing the audit committee and the board on information security matters several times a year in their regular meetings and on an ad hoc basis, conducting an annual security training program, and arranging for external security assessments. Together with the audit committee, the board's executive committee assists the board in monitoring management’s risk management framework for cybersecurity on a regular basis.
IDACORP and Idaho Power include risks from cybersecurity threats, including from use of third-party service providers, as part of the companies' enterprise risk assessment process. The companies have utilized and continue to utilize recognized third-party cybersecurity standards such as those published by the Center for Internet Security and the U.S. National Institute of Standards and Technology in developing their risk management framework for cybersecurity, their cybersecurity processes, controls, and procedures, and risk identification. The companies engage with consultants and other third parties as necessary to design, enhance, and implement appropriate cybersecurity measures in seeking to mitigate risks from cybersecurity threats. As part of the companies' strategy to manage risks from cybersecurity threats with third-party service providers, the companies seek to include appropriate security clauses in their contracts with those providers, including incident reporting requirements.
A dedicated cybersecurity team lead by a cybersecurity manager oversees the assessment and management of risks from cybersecurity threats on a day-to-day basis at IDACORP and Idaho Power. The cybersecurity manager reports to Idaho Power's corporate security senior manager. The cybersecurity team has a range of expertise including architecture, forensics, cloud, incident response, auditing/logging, and software administration, with several industry-recognized certifications among the team, including Certified Information Systems Security Professional and Certified Information Security Manager.
The cybersecurity team monitors and reviews threat intelligence feeds from various sources, including security vendors and U.S. federal and state agencies, to determine potential risks to the companies' information and control systems. Additionally, the team utilizes a defense-in-depth approach to cybersecurity that provides layers of defenses and monitoring/alerting to which the team responds. The team also monitors the companies' third-party service providers for risks related to the confidentiality, availability, and integrity of the companies' data and services hosted through those third parties.
The companies have an established cybersecurity incident response plan to provide structure and guidance when responding to cybersecurity incidents. In appropriate cases, an incident response team is activated to lead the companies' response. The team is composed of individuals from the cybersecurity team and other departments within the companies with relevant expertise, as well as third-party contractors and vendors.
As of the date of this report, IDACORP and Idaho Power believe that no risks from known cybersecurity incidents have materially affected or are reasonably likely to materially affect IDACORP or Idaho Power, including their business strategy, results of operations, and financial condition. However, the companies can provide no assurance that there will not be cybersecurity threats or incidents in the future or that they will not materially affect the companies, including their business strategy, results of operations, or financial condition. For more information regarding the risks the companies face from cybersecurity threats, see Item 1A. “Risk Factors” included in this report.
ITEM 2. PROPERTIES
Idaho Power's properties consist of the physical assets necessary to support its utility operations, which include generation and battery storage, transmission, and distribution facilities. 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
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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. As of December 31, 2023, the system also includes approximately 4,762 linear miles of high-voltage transmission lines, 23 step-up transmission substations located at power plants, 21 transmission substations, 11 switching stations, 30 mixed-use transmission and distribution substations, 186 energized distribution substations (excluding mobile substations and dispatch centers), approximately 29,714 linear miles of distribution lines, and 131 MW of battery storage.
IDACORP's and Idaho Power's headquarters are located in Boise, Idaho. The corporate headquarters campus consists of approximately 305,741 square feet of owned office space. Excluding Idaho Power's power generation facilities and substations, Idaho Power owns an additional 1,218,813 square feet of office, warehouse, and industrial space to support its operations in Idaho and Oregon.
Idaho Power owns all of its interests in principal plants and other important units of real property, except for portions of certain projects licensed under the 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 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 10 – “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, which is incorporated herein by reference.
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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 under the trading symbol "IDA". On February 9, 2024, there were 7,127 holders of record of IDACORP common stock. The outstanding shares of Idaho Power’s common stock, $2.50 par value, are held by IDACORP and are not traded. IDACORP became the holding company of Idaho Power on October 1, 1998.
For information regarding IDACORP's dividend policy, see Part II - Item 7 - MD&A - "Liquidity and Capital Resources - Dividends" in this report. For information relating to restrictions on dividends, see Note 6 - "Common Stock" to the consolidated financial statements in this report.
IDACORP did not repurchase any shares of its common stock during the fourth quarter of 2023.
Performance Graph
The graph below shows a comparison of the five-year cumulative total shareholder return for IDACORP common stock, the S&P 500 Index, and the EEI Electric Utilities Index. The data assumes that $100 was invested on December 31, 2018, with beginning-of-period weighting of the peer group indices (based on market capitalization) and monthly compounding of returns.
Source: Bloomberg and EEI
| 2018 | 2019 | 2020 | 2021 | 2022 | 2023 | |||||||||||||||||||||||||||||||||
| IDACORP | $ | 100.00 | $ | 117.69 | $ | 108.90 | $ | 132.26 | $ | 129.53 | $ | 121.81 | ||||||||||||||||||||||||||
| S&P 500 | 100.00 | 131.48 | 155.66 | 200.30 | 163.99 | 207.05 | ||||||||||||||||||||||||||||||||
| EEI Electric Utilities Index | 100.00 | 125.79 | 124.33 | 145.62 | 147.29 | 134.48 | ||||||||||||||||||||||||||||||||
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 Exchange Act 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 Exchange Act, except to the extent IDACORP or Idaho Power specifically incorporates it by reference into such filing.
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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
In 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 2022 compared with 2021 can be found in their Annual Report on Form 10-K for the year ended December 31, 2022. See Part II - Item 7 - MD&A in that 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 IPUC, OPUC, and 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 IERCo, a joint-owner of BCC, which mines and supplies coal to the Jim Bridger plant owned in part by Idaho Power. IDACORP’s other notable subsidiaries include IDACORP Financial Services, Inc., an investor in affordable housing and other real estate tax credit investments; and Ida-West Energy Company, an operator of small hydropower generation projects that satisfy the requirements of the PURPA.
EXECUTIVE OVERVIEW
IDACORP is committed to its focus on competitive total returns and generating long-term value for shareholders. IDACORP’s business strategy emphasizes Idaho Power as IDACORP’s core business, since Idaho Power’s regulated electric utility operations are the primary driver of IDACORP’s operating results. This strategy is described in Part I, Item 1 - "Business - Business Strategy" of this report. Examples of IDACORP's and Idaho Power's achievements, notable events, milestones, and recognitions during 2023 include:
•IDACORP achieved net income growth for a sixteenth consecutive year. Idaho Power achieved a 9.4 percent return on year-end equity in the Idaho jurisdiction without the need to amortize additional ADITCs available under its Idaho regulatory mechanism, described in Note 3 – “Regulatory Matters” to the consolidated financial statements included in this report.
•Idaho Power continues to focus on timely recovery of costs and earning a reasonable return on investment. In December 2023, the IPUC approved a settlement stipulation publicly filed by Idaho Power, the Staff of the IPUC, and intervening parties (2023 Settlement Stipulation) related to the Idaho general rate case that Idaho Power had filed in June 2023. Also, in December 2023 Idaho Power filed a general rate case with the OPUC. The general rate case filings and 2023 Settlement Stipulation are described more fully in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report and in "Regulatory Matters" in this MD&A.
•Idaho Power's customer count grew 2.4 percent in 2023 and Idaho Power's MWh sales to retail customers in 2023 were the second highest in its history, only behind 2022.
•In 2023, Idaho Power’s reliability metrics continued to be among the best in company history, as Idaho Power provided uninterrupted service to its retail customers 99.97 percent of the time.
•In September 2023, Idaho Power filed its 2023 IRP with the IPUC and OPUC. The 2023 IRP preferred resource portfolio plans for a significant increase in energy and capacity resources over the next 20 years to meet growing demand, primarily solar, wind, and battery resource additions. In addition, the preferred resource portfolio includes conversions of multiple jointly-owned coal-fired generation units to natural gas-fired generation units. To support the resource additions, the preferred portfolio also includes the Boardman-to-Hemingway transmission line with an in-service date in 2026 and three Gateway West transmission line segments phased in with in-service dates from 2028 through 2040.
•In September 2023, IDACORP's board of directors approved a 5.1 percent increase in the regular quarterly cash dividend on IDACORP’s common stock from $0.79 per share to $0.83 per share, as a part of a 177 percent increase in quarterly dividends approved over the last twelve years.
•In March 2023, Idaho Power executed an agreement with the BPA to transfer BPA's 24 percent interest in the Boardman-to-Hemingway transmission line project to Idaho Power, bringing Idaho Power's interest in the project to
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45 percent. In June 2023, both the IPUC and OPUC granted certificates of public convenience and necessity (CPCNs) related to the construction of the Boardman-to-Hemingway transmission line, and Idaho Power plans to begin construction in 2024.
•In April 2023, Idaho Power entered into a 20-year agreement to utilize the storage capacity from a 150-MW battery storage facility scheduled to be online in June 2025. Idaho Power intends for this capacity to supplement 304 MW of company-owned storage that it expects to be online by the end of 2025. In 2023, 131 MW of company-owned battery storage were installed.
•Idaho Power issued a formal RFP in April 2023, soliciting bids for new energy and capacity resources as well as energy that can be delivered via transmission, beginning in 2026. At the time of the RFP issuance, Idaho Power’s long-range planning process had identified a potential need in 2026 and 2027 of approximately 350 MW of peak capacity, which could be met by approximately 1,100 MW of variable energy resources. RFP procurement decisions will be based on the most up-to-date energy and capacity need information. The RFP provides that a portion of these resources may be transmitted via the Boardman-to-Hemingway transmission line project, which Idaho Power plans to have in-service as early as late 2026. Idaho Power anticipates completing the RFP process in the first half of 2024.
Summary of 2023 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, 2023, 2022, and 2021 (in thousands, except earnings per share amounts):
| Year Ended December 31, | ||||||||||||||||||||
| 2023 | 2022 | 2021 | ||||||||||||||||||
| Idaho Power net income | $ | 256,810 | $ | 254,867 | $ | 243,225 | ||||||||||||||
| Net income attributable to IDACORP, Inc. | $ | 261,195 | $ | 258,982 | $ | 245,550 | ||||||||||||||
| Average outstanding shares – diluted (000’s) | 50,806 | 50,699 | 50,645 | |||||||||||||||||
| IDACORP, Inc. earnings per diluted share | $ | 5.14 | $ | 5.11 | $ | 4.85 | ||||||||||||||
The table below provides a reconciliation of net income attributable to IDACORP for the year ended December 31, 2023, from the year ended December 31, 2022 (items are in millions and are before tax unless otherwise noted):
| Net income attributable to IDACORP, Inc. - December 31, 2022 | $ | 259.0 | ||||||||||||
| Increase (decrease) in Idaho Power net income: | ||||||||||||||
| Customer growth, net of associated power supply costs and power cost adjustment mechanisms | 15.7 | |||||||||||||
| Usage per retail customer, net of associated power supply costs and power cost adjustment mechanisms | (31.3) | |||||||||||||
| Idaho FCA revenues | 15.1 | |||||||||||||
| Retail revenues per MWh, net of associated power supply costs and power cost adjustment mechanisms | 11.0 | |||||||||||||
| Transmission wheeling-related revenues | (0.2) | |||||||||||||
| Other O&M expenses | (0.5) | |||||||||||||
| Depreciation expense | (25.3) | |||||||||||||
| Other changes in operating revenues and expenses, net | 1.7 | |||||||||||||
| Decrease in Idaho Power operating income | (13.8) | |||||||||||||
| Non-operating expense, net | 4.7 | |||||||||||||
| Income tax expense | 11.0 | |||||||||||||
| Total increase in Idaho Power net income | 1.9 | |||||||||||||
| Other IDACORP changes (net of tax) | 0.3 | |||||||||||||
| Net income attributable to IDACORP, Inc. - December 31, 2023 | $ | 261.2 | ||||||||||||
IDACORP's net income increased $2.2 million for 2023 compared with 2022, due primarily to higher net income at Idaho Power.
Idaho Power's customer growth of 2.4 percent added $15.7 million to Idaho Power's operating income in 2023 compared with 2022. Lower sales volumes on a per-customer basis among all customer classes, but more significantly among residential and
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irrigation customers, decreased operating income by $31.3 million in 2023 compared with 2022. More moderate temperatures and greater precipitation in Idaho Power's service area during 2023, compared with 2022, led residential customers to use less energy per customer for cooling and heating and agricultural irrigation customers to use less energy per customer to operate irrigation pumps. The negative revenue impact of the decrease in sales volumes per residential and small commercial customer was partially offset by the FCA mechanism, which increased revenues in 2023 by $15.1 million compared with 2022.
The net increase in retail revenues per MWh, net of associated power supply costs and power cost adjustment mechanisms, increased operating income by $11.0 million in 2023 compared with 2022. The net increase in retail revenues per MWh was primarily due to the June 1, 2022, rate increase for Idaho Power’s Idaho retail customers related to an order from the IPUC that authorized Idaho Power to accelerate the depreciation on and recover through 2030 the net book value of coal-related assets at Idaho Power's jointly-owned Jim Bridger plant, as of December 31, 2020, plus forecasted plant investments (Bridger Order).
Other O&M expenses were relatively flat in 2023 compared with 2022, as inflationary pressures on labor-related costs were mostly offset by lower expenses from scheduled cyclical plant maintenance projects, as well as the timing of regulatory deferrals and payment credits received related to a jointly-funded infrastructure project.
Depreciation expense increased $25.3 million due partially to an increase in plant-in-service. In addition, the increase was partially due to the impacts of the Bridger Order. The Bridger Order resulted in Idaho Power recording the deferral of certain depreciation expense in the second quarter of 2022, reducing depreciation expense in that year.
Non-operating expense, net, decreased $4.7 million in 2023 compared with 2022. AFUDC increased as the average construction work in progress balance was higher throughout 2023 compared with 2022. Also, interest and investment income increased due to higher interest rates and higher average cash and cash equivalents balances. These increases were partially offset by higher interest expense on long-term debt and other liabilities in 2023 compared with 2022.
The $11.0 million decrease in Idaho Power income tax expense in 2023 compared with 2022 was primarily due to plant-related tax adjustments at Idaho Power.
2024 Initiatives and Strategy
IDACORP’s strategy is focused on four areas: keeping employees safe and engaged, growing financial strength, improving Idaho Power's core business, and enhancing Idaho Power’s brand. IDACORP's directors have reviewed and affirmed IDACORP’s long-term strategy. In executing on these four strategic cornerstones, IDACORP seeks to balance the interests of shareowners, Idaho Power customers, employees, and other stakeholders. Idaho Power is committed to working for strong, sustainable financial results by continuing to safely provide reliable, affordable, clean energy to its customers from diversified generation resources, including an increasingly clean portfolio of generation as Idaho Power works toward its “Clean Today. Cleaner Tomorrow.®” goal of 100% clean energy by 2045. More specific information on IDACORP’s strategy is included in Item 1 – “Business,” in this report.
Overview of General Factors and Trends Affecting Results of Operations and Financial Condition
IDACORP's and Idaho Power's results of operations and financial condition are affected by a number of factors, and the impact of those factors is discussed in more detail below in this MD&A. To provide context for the discussion elsewhere in this report, some of the more notable factors include the following:
•Regulation of Rates and Cost Recovery; General Rate Case Filings: The prices that Idaho Power is authorized to charge for its electric and transmission service are a critical factor in determining IDACORP's and Idaho Power's results of operations and financial condition. Those rates are established by state regulatory commissions and the FERC and are intended to allow Idaho Power an opportunity to recover its expenses and earn a reasonable return on investment. Idaho Power focuses on the prudent management of expenses and investments and on the timely recovery of its costs through filings with its regulators.
In December 2023, the IPUC approved the 2023 Settlement Stipulation between Idaho Power, the Staff of the IPUC, and intervening parties related to the Idaho general rate case filed by Idaho Power in June 2023. New tariff schedules resulting from the 2023 Settlement Stipulation are designed to increase annual Idaho-jurisdictional retail revenue by $54.7 million, or 4.25 percent, and became effective January 1, 2024. The $54.7 million of additional annual revenue is net of a PCA rate decrease of $168.3 million and a reduction to annual energy efficiency rider collection of $3.5 million, each of which was transferred into base rates. The 2023 Settlement Stipulation also included a 9.6
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percent return on equity and a 7.247 percent authorized rate of return based on a non-specified cost of debt and capital structure, applied to an Idaho-jurisdictional rate base of approximately $3.8 billion, excluding coal-related assets at the Jim Bridger plant and North Valmy plant which are recovered under separate regulatory mechanisms. Idaho Power also made a general rate case filing in Oregon in December 2023 and expects the full processing of that general rate case will take approximately ten months. The general rate case filings and the 2023 Settlement Stipulation are described more fully in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report and in "Regulatory Matters" in this MD&A. Several factors impacted Idaho Power’s need to file its general rate cases including the increase in depreciation expense from plant in service, the significant amounts of capital expenditures Idaho Power made since its last general rate case filed in 2011, the financing costs for capital expenditures in a higher interest-rate environment, and, to a lesser extent, inflationary pressures on other O&M expenses. Due to the continuing impact of many of these same factors and the effect of regulatory lag, on February 14, 2024, Idaho Power provided notice to the IPUC of its intent to file a general rate case or limited issue rate proceeding in Idaho on or after June 1, 2024.
•Rate Base Growth and Infrastructure Investment: The rates established by the IPUC, OPUC, and FERC 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 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 Idaho Power is undertaking a significant relicensing effort for the 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, but the company incurs the cash requirements of constructing and the costs of financing those resources before they are in rates and customer revenues.
Idaho Power expects its capital expenditures on infrastructure investments in the next five years or more will be considerable as it works to address projected energy and capacity deficits. For more information about forecasted capital expenditures and expected rate base growth, see the "Liquidity and Capital Resources" section of this MD&A.
•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 2023, Idaho Power's customer count grew by 2.4 percent. While recessionary or volatile economic conditions could slow the rate of customer growth in the near-term, Idaho Power expects its number of customers and, to a greater extent its load due to anticipated commercial and industrial customer growth, to increase in the foreseeable future.
Idaho Power filed its most recent IRP with the IPUC and OPUC in September 2023. The 2023 IRP assumes a forecasted annual growth in retail MWh sales of 5.5 percent and a forecasted annual growth in peak-hour demand of 3.7 percent over the upcoming 5-year period. For more information on the 2023 IRP, refer to "Resource Planning" in Item 1 – "Business." Customer growth has contributed to increases in peak loads experienced in recent years. For example, Idaho Power's highest all-time winter peak demand of 2,719 MW occurred on January 16, 2024. Idaho Power believes that existing and sustained growth in customers, load, and peak demand for electricity, along with changes in the regional transmission markets that have constrained the availability of transmission outside Idaho Power’s service area to import energy during peak load periods, require that Idaho Power increase its investment in capacity resources, transmission, and distribution infrastructure. This includes the Boardman-to-Hemingway and Gateway West transmission projects, along with other capacity, energy, and transmission resources. This includes those contemplated by the resource procurements described in the "Liquidity and Capital Resources" in this MD&A.
•Weather Conditions: Weather and agricultural growing conditions have a significant impact on Idaho Power's energy sales. Relatively low and high temperatures result in greater energy use for heating and cooling, respectively. During the agricultural growing season, which in large part occurs during the second and third quarters of each year, irrigation customers use electricity to operate irrigation pumps, and weather conditions can impact the timing and extent of use
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of those pumps. Idaho Power also has tiered rates and seasonal rates, which contribute to increased revenues during higher-load periods, most notably during the third quarter of each year when overall customer demand is highest. Much of the adverse or favorable impact of weather on sales of energy to residential and small commercial customers is mitigated through the Idaho FCA mechanism, which is described in Note 3 - "Regulatory Matters" to the 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 resources 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, which lessen the potential earnings benefit or detriment of volatile hydrological conditions and their impact on overall power supply costs. For 2024, Idaho Power expects generation from its hydropower resources to be in the range of 5.5 million to 7.5 million MWh, compared with 6.5 million MWh in 2023 and average total annual hydropower generation of approximately 7.6 million MWh over the last 30 years.
•Mitigation of Impact of Fuel and Purchased Power Expense: In addition to hydropower generation, Idaho Power relies significantly on natural gas and coal to fuel its generation facilities, long-term power purchase agreements (including PURPA agreements), and 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, generation resource maintenance outages, wholesale energy market prices, transmission availability, and the outcome of Idaho Power’s hedging programs. The Idaho and Oregon power cost adjustment mechanisms mitigate in large part the potential adverse earnings impacts to Idaho Power of fluctuations in power supply costs. However, collection from customers or return to customers of most of the difference between actual power supply costs compared with those included in retail rates is deferred to a subsequent period, which can affect Idaho Power’s operating cash flow and liquidity until those costs are recovered from or returned to customers.
•Regulatory and Environmental Compliance Costs; Coal Plant Retirements: Idaho Power is subject to extensive federal and state laws, policies, and regulations, as well as regulatory actions and audits by agencies and quasi-governmental agencies, including the FERC, the North American Electric Reliability Corporation, and the Western Electricity Coordinating Council. Compliance with these requirements directly influences Idaho Power's operating environment and affects Idaho Power's operating costs. Moreover, environmental laws and regulations may increase the cost of constructing new facilities, may increase the cost of operating generation plants, may require that Idaho Power install additional pollution control devices at existing generating plants, may result in penalties for non-compliance, even where inadvertent, or may require that Idaho Power curtail or cease operating certain generation plants. Idaho Power expects to spend significant amounts on environmental compliance and controls for the foreseeable future. Due to economic factors in part associated with the costs of compliance with environmental regulation, Idaho Power accelerated the retirement date of its jointly-owned coal-fired generating plant in North Valmy, Nevada (North Valmy plant), ceasing coal-fired operations at one unit in 2019 and planning to cease its participation in coal-fired operations at the remaining unit by year-end 2025. Idaho Power's jointly-owned coal plant in Boardman, Oregon, ceased operations as planned in October 2020. In 2022, the IPUC approved Idaho Power's request to allow the coal-related assets at the Jim Bridger plant to be fully depreciated and recovered by end-of-year 2030. Idaho Power's 2023 IRP identified a preferred resource portfolio and action plan that includes the conversion from coal to natural gas of two units at the Jim Bridger plant in 2024, the two units at the North Valmy plant in 2026, and the remaining two units at the Jim Bridger plant in 2030. For more information on the 2023 IRP, refer to "Resource Planning" in Item 1 – "Business" of this report.
•Water Management and Relicensing of Hydropower Projects: Because of Idaho Power's reliance on stream flow in the Snake River and its tributaries, Idaho Power participates in numerous proceedings and venues that may affect its water rights, seeking to preserve the long-term availability of its rights for its hydropower projects. Also, Idaho Power is involved in renewing its long-term federal licenses for the HCC, its largest hydropower generation source, and for American Falls, its second largest hydropower generation source. Given the number of parties involved, Idaho Power's relicensing costs have been and are expected to continue to be substantial. Idaho Power cannot currently determine the
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ultimate terms of, and costs associated with, any resulting long-term licenses for the HCC or American Falls hydroelectric facilities.
•Wildfire Mitigation Efforts: In recent years, the western United States has experienced an increasing trend in the degree of annual destruction from wildfires. A variety of factors have contributed 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 and elsewhere in the western United States, Idaho Power is taking a proactive approach to wildfire threat in its service area and transmission corridors. Idaho Power has adopted a 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; PSPS protocols; and evaluating the performance and effectiveness of the strategies identified in the WMP through metrics and monitoring. Idaho Power has a regulatory mechanism which allows the company to defer, for future amortization, the Idaho jurisdictional share of actual incremental O&M expenses necessary to implement the WMP. The WMP regulatory deferral is described in more detail in the "Regulatory Matters" section of this MD&A.
RESULTS OF OPERATIONS
This section of MD&A takes a closer look at the significant factors that affected IDACORP’s and Idaho Power’s earnings. In this analysis, the results for 2023 are compared with 2022.
The table below presents Idaho Power’s energy sales and supply (in thousands of MWh) for the last two years ended December 31.
| 2023 | 2022 | |||||||||||||
| Retail energy sales | 15,515 | 15,822 | ||||||||||||
| Wholesale energy sales | 840 | 427 | ||||||||||||
| Energy sales bundled with RECs | 1,255 | 892 | ||||||||||||
| Total energy sales | 17,610 | 17,141 | ||||||||||||
| Hydropower generation | 6,548 | 5,347 | ||||||||||||
| Coal-fired generation | 2,473 | 3,657 | ||||||||||||
| Natural gas-fired and other generation | 2,917 | 2,319 | ||||||||||||
| Total system generation | 11,938 | 11,323 | ||||||||||||
| Purchased power | 7,027 | 7,178 | ||||||||||||
| Line losses | (1,355) | (1,360) | ||||||||||||
| Total energy supply | 17,610 | 17,141 | ||||||||||||
For purposes of illustration, Boise, Idaho weather-related information for the last two years ended December 31 is presented in the table that follows.
| 2023 | 2022 | Normal(2) | ||||||||||||||||||
Heating degree-days(1) | 5,042 | 5,797 | 5,321 | |||||||||||||||||
Cooling degree-days(1) | 1,342 | 1,401 | 1,045 | |||||||||||||||||
| Precipitation (inches) | 13.8 | 12.7 | 11.5 | |||||||||||||||||
(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.
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Sales Volume and Generation: In 2023, retail sales volumes decreased 2 percent compared with the prior year, primarily due to weather variations that caused lower usage per customer. Greater precipitation and more moderate temperatures in Idaho Power's service area during 2023 led agricultural irrigation customers to use less energy per customer to operate irrigation pumps and residential and commercial customers to use less energy per customer for cooling and heating purposes compared with 2022. The decrease in usage per customer was partially offset by customer growth, as the number of Idaho Power customers grew by 2.4 percent in 2023. For more information on the changes in sales volume, see the "Operating Revenues" section below in this MD&A.
Total system generation increased 5 percent in 2023 compared with 2022, due primarily to higher natural gas generation and hydropower generation, partially offset by decreased coal-fired generation. For more information on the changes in sales volume, see the "Operating Expenses" section below in this MD&A.
The financial impacts of fluctuations in wholesale energy sales, purchased power, fuel expense, and other power supply-related expenses are addressed in Idaho Power's Idaho and Oregon power cost adjustment mechanisms, which are described below in "Power Cost Adjustment Mechanisms."
Operating Revenues
Retail Revenues: The tables below present Idaho Power’s retail revenues (in thousands), MWh sales (in thousands), and number of retail customers for the last two years ended December 31.
| 2023 | 2022 | |||||||||||||
| Retail revenues: | ||||||||||||||
Residential (includes $37,233 and $22,595, respectively, related to the FCA(1)) | $ | 684,649 | $ | 645,236 | ||||||||||
Commercial (includes $1,338 and $922, respectively, related to the FCA(1)) | 378,330 | 347,970 | ||||||||||||
| Industrial | 244,538 | 217,368 | ||||||||||||
| Irrigation | 173,929 | 170,964 | ||||||||||||
Deferred revenue related to HCC relicensing AFUDC(2) | (8,780) | (8,780) | ||||||||||||
| Total retail revenues | $ | 1,472,666 | $ | 1,372,758 | ||||||||||
(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 approximately $8.8 million annually in the Idaho jurisdiction but is deferring revenue recognition of the amounts collected until the license is issued and the accumulated license costs approved for recovery are placed in service.
| MWh Sales | Retail Customers | |||||||||||||||||||||||||
| 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||||||
| Residential | 5,903 | 6,056 | 531,885 | 518,490 | ||||||||||||||||||||||
| Commercial | 4,269 | 4,306 | 78,586 | 77,306 | ||||||||||||||||||||||
| Industrial | 3,538 | 3,510 | 132 | 128 | ||||||||||||||||||||||
| Irrigation | 1,805 | 1,950 | 22,333 | 22,071 | ||||||||||||||||||||||
| Total | 15,515 | 15,822 | 632,936 | 617,995 | ||||||||||||||||||||||
Changes in rates, changes in customer demand, and changes in FCA mechanism revenues are the primary reasons for fluctuations in retail revenues from period to period. See "Regulatory Matters" in this MD&A for a list of rate changes implemented over the last two years. The primary influences on customer demand for electricity are weather, economic conditions, and energy efficiency. Extreme temperatures increase sales to customers who use electricity for cooling and heating, while mild temperatures decrease sales. Precipitation levels and the timing of precipitation during the agricultural growing season also affect sales to customers who use electricity to operate irrigation pumps. Rates are also seasonally adjusted, providing for higher rates during summer peak load periods, and residential customer rates are tiered, providing for higher rates based on higher levels of usage. The seasonal and tiered rate structures contribute to seasonal fluctuations in revenues and earnings.
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Retail Revenues: Retail revenues increased $99.9 million in 2023 compared with 2022. The primary factors affecting retail revenues during the period were the following:
•Rates: Customer rates, excluding collections of amounts related to the power cost adjustment mechanisms, increased retail revenues by $11.0 million in 2023 compared with 2022, due primarily to the June 1, 2022 rate increase for Idaho Power’s Idaho retail customers related to the Bridger Order. Customer rates also include the collection from customers of amounts related to the power cost adjustment mechanisms, which increased revenues by $98.5 million in 2023 compared with 2022. The adjustments related to the Idaho-jurisdiction PCA in rates do not have a significant effect on operating income as a corresponding amount is recorded in expense in the same period it is collected through rates.
•Customers: Customer growth of 2.4 percent increased retail revenues by $26.7 million in 2023 compared with 2022.
•Usage: Decreased usage (on a per customer basis) in all customer classes decreased retail revenues by $51.4 million during 2023 compared with 2022. Milder temperatures during 2023, compared with temperatures during 2022, led retail customers to use less energy per customer for cooling and heating. More precipitation during the spring and late summer of 2023, compared with the same period of 2022, led agricultural irrigation customers to use 7 percent less energy per customer to operate irrigation pumps during 2023. Heating degree-days in Boise, Idaho, were 13 percent lower during 2023 compared with 2022, and 5 percent lower than normal. Also, cooling degree-days in Boise, Idaho, were 4 percent lower during 2023 compared with 2022 and 28 percent above normal.
•Idaho FCA Revenues: The FCA mechanism, applicable to Idaho residential and small commercial customers, adjusts revenue each year to accrue, or defer, the difference between the authorized fixed-cost recovery amount per customer and the actual fixed costs per customer recovered by Idaho Power through volume-based rates during the year. Lower usage (on a per customer basis) by residential and small commercial customers during 2023 increased the amount of FCA revenue accrued by $15.1 million, compared with 2022.
Wholesale Energy Sales: Wholesale energy sales consist primarily of long-term sales contracts, opportunity sales of surplus system energy, and sales into the western EIM, and do not include derivative transactions. The table below presents Idaho Power’s wholesale energy sales for the last two years ended December 31 (in thousands, except for revenue per MWh amounts).
| 2023 | 2022 | |||||||||||||
| Wholesale energy revenues | $ | 63,421 | $ | 66,519 | ||||||||||
| Wholesale MWh sold | 840 | 427 | ||||||||||||
| Wholesale energy revenues per MWh | $ | 75.50 | $ | 155.78 | ||||||||||
In 2023, wholesale energy revenue decreased by $3.1 million, or 5 percent, compared with 2022, as higher wholesale energy sales volumes were more than offset by lower wholesale market prices. The increase in wholesale energy volumes sold during 2023, was partially due to energy originally purchased under derivative forward contracts to be bundled with RECs, but the energy was ultimately sold in the wholesale markets. Those sales increased wholesale energy revenues by $16.7 million in 2023, and a corresponding amount was recorded in purchased power on the consolidated statements of income. The financial impacts of fluctuations in wholesale energy sales are largely mitigated by Idaho Power's Idaho and Oregon power cost adjustment mechanisms, which are described below in "Power Cost Adjustment Mechanisms" in this MD&A.
Energy Efficiency Program Revenues: In both Idaho and Oregon, energy efficiency riders fund energy efficiency program expenditures. Expenditures funded through the riders are reported as an operating expense with an equal amount recorded in revenues, resulting in no net impact on earnings. The cumulative variances between expenditures and amounts collected through the riders are recorded as regulatory assets or liabilities. A liability balance indicates that Idaho Power has collected more than it has spent and an asset balance indicates that Idaho Power has spent more than it has collected. At December 31, 2023, Idaho Power's energy efficiency rider balances were a $0.7 million regulatory liability in the Idaho jurisdiction and a $0.8 million regulatory liability in the Oregon jurisdiction.
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Operating Expenses
Purchased Power: The table below presents Idaho Power’s purchased power expenses and volumes for the last two years ended December 31 (in thousands, except for per MWh amounts).
| 2023 | 2022 | |||||||||||||
| Purchased power expense | $ | 501,531 | $ | 544,345 | ||||||||||
| MWh purchased | 7,027 | 7,178 | ||||||||||||
| Average cost per MWh | $ | 71.37 | $ | 75.84 | ||||||||||
Purchased power expense decreased $42.8 million, or 8 percent, in 2023 compared with 2022. The decrease in purchased power expense in 2023 is primarily due to lower wholesale energy market prices as milder summer and winter weather resulted in lower demand and lower fuel costs (natural gas and coal) in the wholesale markets in the region. For further information on purchased power activities, see Part I, Item 1 – Utility Operations – "Power Supply – Purchased Power."
Fuel Expense: The table below presents Idaho Power’s fuel expenses and thermal generation for the last two years ended December 31 (in thousands, except for per MWh amounts).
| Fuel Expense | MWh Generated | Cost per MWh | ||||||||||||||||||||||||||||||||||||
| 2023 | 2022 | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||||||||||||||||
| Coal | $ | 95,499 | $ | 105,552 | 2,473 | 3,657 | $ | 38.62 | $ | 28.86 | ||||||||||||||||||||||||||||
Natural gas(1) | 179,906 | 124,658 | 2,917 | 2,319 | $ | 61.68 | $ | 53.76 | ||||||||||||||||||||||||||||||
| Total/Weighted average, all | $ | 275,405 | $ | 230,210 | 5,390 | 5,976 | $ | 51.10 | $ | 38.52 | ||||||||||||||||||||||||||||
(1) Includes a negligible amount of expense and generation related to the Salmon diesel-fired generation plant.
The majority of the fuel for Idaho Power’s jointly-owned coal-fired plants is purchased through long-term contracts, including purchases from BCC, a one-third owned investment of IERCo. The price of coal from BCC is subject to fluctuations in mine operating expenses, geologic conditions, and production levels. BCC supplies the majority of the coal used by the Jim Bridger plant and BCC does not have significant sales to third parties. Natural gas is mainly purchased on the regional wholesale spot market at published index prices. In addition to commodity (variable) costs, both natural gas and coal expenses include costs that are more fixed in nature for items such as capacity charges, transportation, and fuel handling. Period to period variances in fuel expense per MWh are noticeably impacted by these fixed charges when generation output is substantially different between the periods.
Fuel expense increased $45.2 million, or 20 percent, in 2023 compared with 2022, despite lower total thermal generation. The increase in fuel expense was primarily due to higher coal purchase prices and higher natural gas market prices in 2023, which resulted in an increase in the average cost per MWh of coal and natural gas generation. The mix of Idaho Power's thermal generation between natural gas and coal in 2023 compared with 2022 was affected by fluctuations in natural gas prices and coal supply constraints.
Included in fuel expense are losses and gains on settled financial gas hedges entered into in accordance with Idaho Power's energy risk management policy. In 2023, losses on financial gas hedges of $16.2 million increased natural gas fuel expense. In 2022, gains on financial gas hedges of $68.5 million reduced natural gas fuel expense. Most of these realized hedging losses and gains are passed on to customers through the power cost adjustment mechanisms described below.
Power Cost Adjustment Mechanisms: Idaho Power's power supply costs (primarily purchased power and fuel expense, less wholesale energy sales) can vary significantly from year to year. Volatility of power supply costs arises from factors such as weather conditions, wholesale market prices, volumes of power purchased and sold in the wholesale markets, Idaho Power's hydropower and thermal generation volumes and fuel costs, generation plant availability, and retail loads. To address the volatility of power supply costs, Idaho Power's power cost adjustment mechanisms in the Idaho and Oregon jurisdictions allow Idaho Power to recover from customers, or refund to customers, most of the fluctuations in power supply costs. In the Idaho jurisdiction, the PCA includes a cost or benefit sharing ratio that allocates the deviations in net power supply expenses between customers (95 percent) and Idaho Power (5 percent), with the exception of PURPA power purchases and demand response program incentives, which are allocated 100 percent to customers. The Idaho deferral period, or PCA year, runs from April 1 through March 31. Amounts deferred during the PCA year are primarily recovered or refunded during the subsequent June 1 through May 31 period. However, the IPUC directed Idaho Power to spread recovery of the March 31, 2023, PCA deferral
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balance over a two-year period from June 1, 2023, to May 31, 2025. Because of the power cost adjustment mechanisms, the primary financial impacts of power supply cost variations is that cash is paid out but recovery from customers does not occur until a future period, or cash that is collected is refunded to customers in a future period, resulting in fluctuations in operating cash flows from year to year.
The table below presents the components of the Idaho and Oregon power cost adjustment mechanisms for the last two years ended December 31 (in thousands).
| 2023 | 2022 | |||||||||||||
| Idaho power supply cost deferral | $ | (66,728) | $ | (116,994) | ||||||||||
| Oregon power supply cost accrual (deferral) | 1,169 | (1,079) | ||||||||||||
| Amortization of prior year authorized balances | 72,444 | 17,414 | ||||||||||||
| Total power cost adjustment (income statement) | $ | 6,885 | $ | (100,659) | ||||||||||
The power supply (deferrals) accruals represent the portion of the power supply cost fluctuations (deferred) accrued under the power cost adjustment mechanisms. When actual power supply costs are lower than the amount forecasted in power cost adjustment rates, most of the difference is accrued as an increase to a regulatory liability or decrease to a regulatory asset. When actual power supply costs are higher than the amount forecasted in power cost adjustment rates, most of the difference is deferred as an increase to a regulatory asset or decrease to a regulatory liability. During 2023, higher fuel costs partially offset by lower purchased power expense led to higher actual power supply costs compared with the forecasted amount, which resulted in the deferral of power supply costs. The amortization of the prior year’s balances represents the offset to the amounts being collected or refunded in the current power cost adjustment year that were deferred or accrued in the prior power cost adjustment year (the true-up component of the power cost adjustment mechanism).
Other Operations and Maintenance Expenses: Other O&M expenses increased $0.5 million in 2023 compared with 2022, as inflationary pressures on labor-related costs were mostly offset by lower expenses from scheduled cyclical plant maintenance projects as well as the timing of regulatory deferrals and payment credits received related to a jointly funded infrastructure project.
Income Taxes
IDACORP's and Idaho Power's 2023 income tax expense decreased $10.5 million and $11.0 million, respectively, when compared with 2022. The decreases were primarily due to plant-related tax 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 net costs of removing assets from service, were $591 million in 2023 and $419 million in 2022. Idaho Power expects an increase in capital expenditures over the next several years, with estimated total capital expenditures of up to $4.4 billion over the period from 2024 through 2028.
Idaho Power funds its liquidity needs for capital expenditures through cash flows from operations, debt offerings, commercial paper markets, credit facilities, and capital contributions from IDACORP.
As of February 9, 2024, IDACORP's and Idaho Power's access to debt, equity, and credit arrangements included:
•their respective $100 million and $400 million revolving Credit Facilities;
•IDACORP's shelf registration statement filed with the SEC on May 16, 2022, which may be used for the issuance of debt securities and common stock;
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•Idaho Power's shelf registration statement filed with the SEC on May 16, 2022, which may be used for the issuance of first mortgage bonds and debt securities; $280 million remains available for issuance pursuant to state regulatory authority;
•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; and
•IDACORP's forward sale agreements (FSA), which may be physically settled with common stock in exchange for net proceeds, which as of February 9, 2024, would be approximately $291 million.
In March 2023, Idaho Power issued the following long-term debt with the proceeds being used for general corporate purposes, including repaying outstanding commercial paper and long-term debt and funding Idaho Power's capital projects:
•$60 million of 5.06% first mortgage bonds, secured medium-term notes, Series N, maturing in March 2043;
•$62 million of 5.20% first mortgage bonds, secured medium-term notes, Series N, maturing in March 2053; and
•$400 million of 5.50% first mortgage bonds, secured medium-term notes, Series M, maturing in March 2053.
During March through May 2023, a portion of the proceeds from the March 2023 issuances was used to repay outstanding commercial paper, $150 million in principal amount from a March 2022 term loan agreement, and $75 million in principal amount of maturing 2.50% first mortgage bonds, Series I.
In September 2023, Idaho Power issued $350 million of 5.80% first mortgage bonds, secured medium-term notes, Series M, maturing in April 2054 with the proceeds used for general corporate purposes, including funding its capital projects.
In November 2023, IDACORP entered into FSAs in connection with a completed $299 million public offering of approximately 3.2 million shares of its common stock. IDACORP may settle the agreements at any time up to the maturity date of November 7, 2024. Depending on settlement timing, if IDACORP elects to physically settle by delivering shares of common stock, cash proceeds are expected to be approximately $290 million to $295 million. The proceeds are expected to be used for general corporate purposes, including funding Idaho Power's capital projects. For more detailed information about IDACORP's FSAs, see Note 6 - "Common Stock" to the consolidated financial statements included in this report.
IDACORP and Idaho Power monitor capital markets with a view toward favorable debt and equity transactions, taking into account current and potential future long-term needs. As a result, IDACORP may issue debt securities or common stock, and Idaho Power may issue debt securities or first mortgage bonds, if the companies believe terms available in the capital markets are favorable and that issuances would be financially prudent. Idaho Power also periodically analyzes whether partial or full early redemption of one or more existing outstanding series of first mortgage bonds is desirable, and in some cases, may refinance indebtedness with new indebtedness. In January 2024, IDACORP began using original issuances of shares for its dividend reinvestment and stock purchase plan and also intends to use original issuances of IDACORP shares for share purchases within Idaho Power's employee savings plan going forward. IDACORP may discontinue using original issuances of shares for its dividend reinvestment and stock purchase plan and/or the employee savings plan at any time.
Based on planned capital expenditures and other O&M expenses, the companies believe they will be able to meet capital and debt service requirements and fund corporate expenses during at least the next twelve months and thereafter for the foreseeable future with a combination of existing cash, operating cash flows generated by Idaho Power's utility business, availability under existing credit facilities, access to commercial paper, short-term, and long-term debt markets, and equity issuances.
IDACORP and Idaho Power generally 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, 2023, IDACORP's and Idaho Power's capital structures, as calculated for purposes of applicable debt covenants, were as follows:
| IDACORP | Idaho Power | |||||||||||||
| Debt | 50% | 51% | ||||||||||||
| Equity | 50% | 49% | ||||||||||||
IDACORP and Idaho Power generally maintain their cash and cash equivalents in highly liquid investments, such as U.S. Treasury Bills, money market funds, and bank deposits.
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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 2023 were $267 million and $207 million, respectively, a decrease of $84 million and $174 million for IDACORP and Idaho Power, respectively, when compared with 2022. With the exception of cash flows related to income taxes, IDACORP's operating cash flows are principally derived from operating cash flows from Idaho Power. Significant items that affected the companies' operating cash flows in 2023 when compared with 2022 were as follows:
•a $2 million increase in IDACORP and Idaho Power net income, respectively;
•changes in regulatory assets and liabilities, mostly related to the relative amounts of costs deferred and collected under the Idaho PCA, FCA, and wildfire mitigation, increased operating cash inflows by $75 million;
•changes in deferred taxes and taxes accrued and receivable combined to increase operating cash flows for IDACORP and Idaho Power by $32 million and $38 million, respectively;
•contributions to pension and postretirement benefits plans decreased IDACORP and Idaho Power cash flows by $11 million;
•changes in distributions from equity-method investments, primarily related to IERCo, a wholly-owned subsidiary of Idaho Power, decreased IDACORP and Idaho Power cash flows by $9 million and $10 million, respectively; and
•changes in working capital balances due primarily to timing, including fluctuations in accounts receivable and unbilled revenues, materials, supplies, and fuel stock, accounts and wages payable, and other assets and liabilities, as follows:
◦the timing of collections of accounts receivable and unbilled revenues increased operating cash flows by $64 million for IDACORP and $63 million for Idaho Power;
◦the changes in materials, supplies, and fuel stock decreased operating cash flows by $42 million for IDACORP and Idaho Power, which was primarily due to an increase in material and supply inventory offset by the timing of purchases and consumption of coal at Idaho Power's jointly-owned coal-fired generating plants;
◦the changes in accounts and wages payable decreased operating cash flows by $194 million for IDACORP and $288 million for Idaho Power, which was primarily due to an increase in power supply costs and associated timing of payments, and includes a $94 million difference between IDACORP and Idaho Power related to intercompany estimated tax payments; and
◦the changes in other assets and liabilities, which includes accrued paid time off and leave, customer deposits, accrued interest, and other miscellaneous liabilities, decreased operating cash flows by $12 million for IDACORP and Idaho Power.
Investing Cash Flows
Investing activities consist primarily of capital expenditures related to new construction of, and improvements to, Idaho Power’s power supply, transmission, and distribution facilities. IDACORP's and Idaho Power's net investing cash outflows for 2023 were $590 million and $582 million, respectively. Investing cash outflows for 2023 and 2022 were primarily for construction of utility infrastructure needed to address Idaho Power’s customer growth, aging plant and equipment, and environmental and regulatory compliance requirements. Significant items and transactions that affected investing cash flows in 2023 and 2022 included:
•$611 million and $433 million, respectively, of additions to property, plant and equipment, including $112 million spent on battery storage projects, and at December 31, 2023, $31 million was accrued in accounts payable on their consolidated balance sheets related to battery payments;
•$27 million and $18 million, respectively, from Boardman-to-Hemingway project joint permitting participants relating to a portion of the permitting expenditures;
•$3 million and $10 million, respectively, of tax credit investments in affordable housing and other real estate, which provide a return principally by reducing federal and state income taxes through tax credits and accelerated tax depreciation benefits at IDACORP;
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•$8 million in 2022 related to return of investment from IERCo, a wholly-owned subsidiary of Idaho Power;
•$11 million and $44 million in purchases of equity securities, respectively, $2 million and $31 million in purchases of held-to-maturity securities, respectively, and $9 million and $64 million in sales of equity securities, respectively, held in a rabbi trust, which is designated to provide funding for obligations related to Idaho Power's SMSP; and
•$25 million in 2022 of both purchases and sales of short-term investments at IDACORP.
Financing Cash Flows
Financing activities provide supplemental cash for both day-to-day operations and capital requirements as needed. IDACORP's and Idaho Power's net financing cash inflows for 2023 were $473 million and $538 million, respectively. Idaho Power funds liquidity needs for capital investment, working capital, managing commodity price risk, dividends, and other financial commitments through cash flows from operations, debt offerings, commercial paper markets, credit facilities, and capital contributions from IDACORP. IDACORP funds its cash requirements, such as payment of taxes, payment of dividends, capital contributions to Idaho Power, and non-utility expenses allocated to IDACORP, through cash flows from operations, commercial paper markets, sales of common stock, and credit facilities. Significant items and transactions that affected financing cash flows in 2023 were as follows:
•in 2023, Idaho Power issued $872 million in aggregate principal amount of first mortgage bonds, secured medium-term notes, as described above in this "Liquidity and Capital Resources" section;
•in 2023, Idaho Power repaid the entire $150 million in principal amount of a March 2022 term loan agreement and $75 million in principal amount of first mortgage bonds, secured medium-term notes at maturity, each as described above in this "Liquidity and Capital Resources" section; and
•IDACORP and Idaho Power paid dividends of $164 million and $102 million in 2023, respectively.
Financing Programs and Available Liquidity
IDACORP Equity Programs: IDACORP issued no equity securities in 2023 other than under its equity compensation plans. As described elsewhere in this MD&A, IDACORP has significant planned capital expenditures in the near-term, and the company plans to issue approximately 3.2 million shares of common stock during 2024 under the FSAs. See Note 6 - "Common Stock" to the consolidated financial statements included in this report. Depending on market conditions, its financial and regulatory strategy, and other factors, IDACORP could determine to issue additional equity securities in 2024.
Term Loan Credit Agreement: In March 2022, Idaho Power entered into a term loan credit agreement (Term Loan Facility). The Term Loan Facility was a two-year senior unsecured term loan facility in the aggregate principal amount of $150 million. On March 31, 2023, Idaho Power repaid $100 million and on May 17, 2023, repaid $50 million principal amount to fully repay the Term Loan Facility.
Idaho Power First Mortgage Bonds: Idaho Power's issuance of long-term indebtedness is subject to the approval of the IPUC, OPUC, and WPSC. In May and June 2022, Idaho Power received orders from the IPUC, OPUC, and WPSC authorizing the company to issue and sell from time to time up to $1.2 billion in aggregate principal amount of debt securities and first mortgage bonds, subject to conditions specified in the orders. At December 31, 2023, $280 million remains available for debt issuance under the regulatory orders. In January 2024, Idaho Power submitted applications to the IPUC, OPUC, and WPSC requesting authorization to issue and sell from time to time up to $1.2 billion in aggregate principal amount of debt securities and first mortgage bonds, which if approved will replace the $280 million remaining on the 2022 orders. For more detailed information about Idaho Power First Mortgage Bonds, see Note 5 - "Long-term Debt" to the consolidated financial statements included in this report.
In December 2022, Idaho Power entered into a Bond Purchase Agreement with certain institutional purchasers, relating to the sale by the Idaho Power of $170 million in aggregate principal amount of first mortgage bonds, secured medium-term notes, Series N (Series N Notes). Also in December 2022, Idaho Power entered into the Fifty-second Supplemental Indenture, dated December 20, 2022, to the Indenture (Fifty-second Supplemental Indenture). The Fifty-second Supplemental Indenture provides for, among other items, the issuance of Series N Notes pursuant to the Indenture. The Series N Notes consist of four tranches of bonds, due in 2032, 2042, 2043, and 2053, respectively. The first two tranches were issued on December 22, 2022, and the third and fourth tranches were issued on March 8, 2023, each under the Indenture. Idaho Power used the proceeds of the sale of the Series N Notes for general corporate purposes, primarily related to the construction of a battery storage project. At December 31, 2023, $170 million in principal amount of Series N Notes had been issued and was outstanding. For more detailed information about the Series N Notes, see Note 5 - "Long-term Debt" to the consolidated financial statements included in this report.
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IDACORP and Idaho Power Credit Facilities (Credit Facilities): In December 2023, IDACORP and Idaho Power entered into Credit Agreements for $100 million and $400 million Credit Facilities, respectively. These facilities replaced IDACORP's and Idaho Power's existing credit agreements, dated November 18, 2022, as amended. The IDACORP Credit Facility, which may be used for general corporate purposes, 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 purposes, 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 $400 million, including swingline loans in an aggregate principal amount at any time outstanding not to exceed $50 million, and letters of credit in an aggregate principal amount at any time outstanding not to exceed $50 million. IDACORP and Idaho Power have the right to request an increase in the aggregate principal amount of the facilities to $150 million and $600 million, respectively, in each case subject to certain conditions.
The IDACORP and Idaho Power Credit Facilities have similar terms and conditions. The interest rates for any borrowings under the facilities are based on either (1) a floating rate that is equal to the highest of the prime rate, federal funds rate plus 0.5 percent, or Adjusted Term SOFR plus 1.0 percent, or 1.0 percent, or (2) the Adjusted Term SOFR, plus, in each case an applicable margin, provided that the Adjusted Term SOFR will not be less than 0.0 percent. If during any period the SOFR rate is unavailable or unascertainable, an alternate benchmark rate selected by the administrative agent and the borrower would apply. The applicable margin is based on IDACORP's or Idaho Power's, as applicable, senior unsecured long-term indebtedness credit rating by rating agencies, as set forth on a schedule to the credit agreements. Under their respective Credit Facilities, the companies pay a facility fee on the commitment based on the respective company's credit rating for senior unsecured long-term debt. Both the IDACORP and Idaho Power Credit Facilities mature on December 8, 2028, and each contains the rights 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, 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, 2023, the leverage ratios for IDACORP and Idaho Power were 50 percent and 51 percent, respectively. IDACORP's and Idaho Power's ability to utilize their respective 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, 2023, IDACORP and Idaho Power believe they were in compliance with all of their respective Credit Facility covenants and, as of the date of this report, do not believe they will be in violation or breach of such covenants during 2024.
The events of default under the Credit Facilities include, without limitation, non-payment of principal, interest, or fees; materially false representations or warranties; breach of covenants; bankruptcy or insolvency events; condemnation of property; cross-default to certain other indebtedness; failure to pay certain judgments; change of control; failure of IDACORP to own free and clear of liens the voting stock of Idaho Power; the occurrence of specified events or the incurring of specified liabilities relating to benefit plans; and the occurrence of certain events related to the environment, subject, in certain instances, to cure periods.
Upon any event of default relating to the voluntary or involuntary bankruptcy of IDACORP or Idaho Power or the appointment of a receiver, the obligations of the lenders to make loans under the applicable facility and to issue letters of credit will automatically terminate and all unpaid obligations will become due and payable. Upon any other event of default, the lenders holding greater than 50 percent of the outstanding loans or greater than 50 percent of the aggregate commitments (required lenders), or the administrative agent with the consent of the required lenders, may terminate or suspend the obligations of the lenders to make loans under the facility and to issue letters of credit under the facility and/or declare the obligations to be due and payable. During an event of default under the facilities, the lenders may, at their option, increase the applicable interest rates then in effect and the letter of credit fee by 2.0 percentage points per annum. A ratings downgrade would result in an increase in the cost of borrowing but would not result in a default or acceleration of the debt under the facilities. However, if Idaho Power's ratings are downgraded below investment grade, Idaho Power must extend or renew its authority for borrowings under its IPUC and OPUC regulatory orders.
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In November and December 2023, Idaho Power obtained approval from the IPUC, the OPUC, and the WPSC for unsecured short-term borrowings at any one time outstanding not to exceed $600 million through December 2030, subject to certain requirements under the order.
IDACORP and Idaho Power Commercial Paper: IDACORP and Idaho Power have commercial paper programs under which they issue unsecured commercial paper notes up to a maximum aggregate amount outstanding at any time not to exceed the available capacity under their respective Credit Facilities, 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, 2023 | December 31, 2022 | |||||||||||||||||||||||||
IDACORP(2) | Idaho Power | IDACORP(2) | Idaho Power | |||||||||||||||||||||||
| Revolving credit facility | $ | 100,000 | $ | 400,000 | $ | 100,000 | $ | 300,000 | ||||||||||||||||||
| Commercial paper outstanding | — | — | — | — | ||||||||||||||||||||||
Identified for other use(1) | — | (19,885) | — | (19,885) | ||||||||||||||||||||||
| Net balance available | $ | 100,000 | $ | 380,115 | $ | 100,000 | $ | 280,115 | ||||||||||||||||||
| (1) American Falls bonds that Idaho Power could be required to purchase prior to maturity under the optional or mandatory purchase provisions of the bonds, if the remarketing agent for the bonds were unable to sell the bonds to third parties. | ||||||||||||||||||||||||||
| (2) Holding company only. | ||||||||||||||||||||||||||
At February 9, 2024, IDACORP and Idaho Power had no loans outstanding under their respective revolving Credit Facilities and no commercial paper outstanding. The table below presents additional information about short-term commercial paper borrowing during the year ended December 31 (in thousands).
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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 and Standard & Poor’s Ratings Services as of the date of this report:
| Moody's | Standard & Poor's | |||||||||||||||||||||||||
| IDACORP | Idaho Power | IDACORP | Idaho Power | |||||||||||||||||||||||
| Rating Outlook | Stable | Stable | Stable | Stable | ||||||||||||||||||||||
| Issuer Rating/Corporate | Baa2 | Baa1 | BBB | BBB | ||||||||||||||||||||||
| First Mortgage Bonds | None | A2 | ||||||||||||||||||||||||
| Senior Secured Debt | None | A2 | None | A- | ||||||||||||||||||||||
| Commercial Paper/Short-Term | P-2 | P-2 | A-2 | A-2 | ||||||||||||||||||||||
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. Any rating can be revised upward or downward or withdrawn at any time by a rating agency if it decides that the circumstances warrant the change.
Idaho Power maintains margin agreements relating to its wholesale commodity contracts that allow performance assurance collateral to be requested of and/or posted with certain counterparties, which are discussed further in Part II - Item 7A "Quantitative and Qualitative Disclosures About Market Risk" included in this report.
Capital Requirements
Idaho Power's cash capital expenditures, excluding AFUDC, were $591 million during the year ended December 31, 2023. The cash expenditure amount excludes net costs of removing assets from service. The table below presents Idaho Power's estimated accrual-basis additions to property, plant, and equipment for 2024 through 2028 (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. 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 constructed projects and capital expenditures could be affected by Idaho Power’s ability to timely obtain labor or materials at reasonable costs, supply chain disruptions and delays, regulatory determinations, inflationary pressures, macroeconomic conditions, or other issues, including those described below.
| 2024 | 2025 | 2026-2028 | |||||||||||||||||||||||||||
| Expected capital expenditures (excluding AFUDC) | $ | 925-975 | $ | 850-950 | $ | 2,000-2,500 | |||||||||||||||||||||||
Infrastructure Projects: A significant portion of expected capital expenditures included in the five-year forecast above relate to a large number of relatively small projects as Idaho Power continues to add to its system to accommodate growth and maintain reliability and operational effectiveness. These projects involve significant capital expenditures in the aggregate. Examples of anticipated system enhancements planned for 2024 through 2028 and estimated costs include the following:
•$140-$250 million per year for construction and replacement of transmission lines and stations other than the Boardman-to-Hemingway and Gateway West projects;
•$130-$175 million per year for construction and replacement of distribution lines and stations, including replacement of underground distribution cables;
•$10-$50 million per year for ongoing improvements and replacements at thermal plants;
•$80-$150 million per year for hydropower plant improvement programs, including relicensing costs; and
•$60-$75 million per year for general plant improvements, such as land and buildings, vehicles, information technology, and communication equipment.
Other Major Infrastructure Projects: Idaho Power has recently completed or is engaged in the development of a number of significant projects and has entered into arrangements with third parties for joint development of infrastructure projects. The most notable projects are described below.
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Resource Additions to Address Projected Energy and Capacity Deficits: As noted previously, Idaho Power's existing and sustained growth in customers, load, and peak demand for electricity, along with transmission constraints, has created the need for Idaho Power to acquire significant generation, transmission, and storage resources to meet energy and capacity needs over the next several years. To help meet peak needs from 2023 through 2025, Idaho Power entered into contracts to purchase, own, and operate 304 MW of battery storage assets with expected useful lives of approximately 20 years, entered into a 20-year agreement to purchase the storage capacity from a 150-MW battery storage facility, and also entered into three power purchase agreements for the combined 340 MW output of planned third-party solar facilities with 20- and 25-year terms. As described in “Regulatory Matters” of this MD&A, Idaho Power plans to sell the output of two of these solar power purchase agreements totaling 240 MW exclusively to two large industrial customers under agreements modeled after Idaho Power’s Clean Energy Your Way program. The capital requirements table above includes capital expenditures of more than $220 million in the years 2024 through 2025 for resource additions to address projected energy and capacity deficits in those years. To help address the additional capacity deficits projected for 2026 through 2027, Idaho Power has issued an RFP for additional resources. The table above does not currently include any amounts for possible company-owned resources from the RFP to address projected deficits in 2026 or 2027. Depending on factors such as RFP results, the timing of project in-service dates, estimated load and resource balances and customer growth, the nature and quantity of resources owned versus acquired under power purchase agreements or similar agreements, and the outcome of regulatory proceedings, actual expenditures and their timing could deviate substantially from Idaho Power's expected expenditures.
Boardman-to-Hemingway Transmission Line: The Boardman-to-Hemingway line, a planned 300-mile, high-voltage transmission project between a substation near Boardman, Oregon, and the Hemingway substation near Boise, Idaho, is expected to provide transmission service to meet future resource needs. Material procurement and construction subcontract bid events are in progress. As a result of delays in issuing Notices to Proceed from state and federal agencies and obtaining right-of-way grants, Idaho Power expects construction will begin in 2024. Given the status of ongoing activities and the construction period, Idaho Power expects the in-service date for the transmission line will be no earlier than late 2026.
Until recently, Idaho Power had a joint funding agreement with PacifiCorp and BPA to pursue permitting of the project, with Idaho Power having an approximate 21 percent interest, BPA having an approximate 24 percent interest, and PacifiCorp having an approximate 55 percent interest in the permitting phase of the project. In March 2023, BPA, PacifiCorp, and Idaho Power signed various agreements to facilitate certain asset transfers and other coordination efforts among the parties as the transmission line moves toward construction. In particular, an agreement between Idaho Power and BPA transferred BPA’s total interest in the project to Idaho Power, increasing Idaho Power's interest to approximately 45 percent, and provided that Idaho Power will deliver long-term transmission service to BPA's customers across southern Idaho. The agreement also required BPA to make a $10 million security payment to Idaho Power. On Idaho Power's consolidated balance sheet, the agreement increased construction work in progress by $31 million for the acquired permitting interest, cash and cash equivalents by $10 million for the additional security payment, and other non-current liabilities by $41 million for Idaho Power's obligation to pay for the permitting interest and to return the security deposit to BPA. Payments to BPA for the permitting interest are expected to be made over a 15-year period beginning 10 years after energization of the transmission line project, while the security deposit is due to be returned to BPA upon energization.
Idaho Power has spent approximately $215 million, including Idaho Power's AFUDC, on the Boardman-to-Hemingway project through December 31, 2023. Pursuant to the terms of the joint funding arrangements, Idaho Power has received $124 million in reimbursement as of December 31, 2023, from project co-participants for their share of costs (including $31 million related to BPA's share, which was transferred to Idaho Power in March 2023 as part of the agreement described above) and continues to receive reimbursement as costs are incurred. PacifiCorp is obligated to reimburse Idaho Power for its share of any future project permitting expenditures or agreed upon early construction expenditures incurred by Idaho Power under the terms of the joint funding agreement. In June 2023, Idaho Power and PacifiCorp executed a construction funding agreement and filed it with the FERC. The agreement became fully effective in September 2023.
The permitting phase of the Boardman-to-Hemingway project was subject to federal review and approval by various federal agencies. Federal agency records of decision have been received and all lawsuits challenging the federal rights-of-way have been resolved. In the separate State of Oregon permitting process, the state's Energy Facility Siting Council (EFSC) approved Idaho Power's site certificate in September 2022. The Oregon Department of Energy subsequently issued a final order and site certificate. Idaho Power is pursuing multiple amendments to the site certificate to accommodate route changes and enhance constructability. In September 2023, EFSC approved Idaho Power's first amendment request. One party filed in Union County Circuit Court contesting the EFSC’s approval of the first amendment, which Idaho Power is seeking to remove to the appropriate venue to expedite review. Idaho Power submitted its preliminary request for a second amendment in June 2023,
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which remains pending. During the second quarter of 2023, the IPUC, OPUC, and WPSC granted Idaho Power and PacifiCorp their respective CPCNs related to the construction of the Boardman-to-Hemingway project.
Total cost estimates for the project are between $1.5 billion and $1.7 billion, including Idaho Power's AFUDC. The capital requirements table above includes approximately $550 million of Idaho Power's share of estimated costs (excluding AFUDC) related to the remaining permitting phase, design, material procurement, and construction phases of the project. Actual construction costs could differ from Idaho Power's estimates based upon Idaho Power’s or its contractors ability to timely obtain labor or materials at reasonable costs, supply chain disruptions and delays, inflationary pressures, macroeconomic conditions, or other issues.
Gateway West Transmission Line: Idaho Power and PacifiCorp are pursuing the joint development of the Gateway West project, a high-voltage transmission lines project between a substation located near Douglas, Wyoming, and the Hemingway substation located near Boise, Idaho. In 2012, Idaho Power and PacifiCorp entered a joint funding agreement for permitting of the project. Idaho Power has expended approximately $60 million, including Idaho Power's AFUDC, for its share of the permitting phase of the project through December 31, 2023. As of the date of this report, Idaho Power estimates the total cost for its share of the project (including both permitting and construction) to be between $900 million and $1.1 billion, including Idaho Power's AFUDC. The estimated cost range is based on assumptions about Idaho Power participation levels in the construction of certain project segments and any changes in those assumptions or in Idaho Power's actual participation could affect future estimates and actual project costs. The capital requirements table above includes approximately $425 million of Idaho Power's share of estimated costs (excluding AFUDC) for the permitting phase of the project and early construction costs, based on Idaho Power's current estimate that it may commence construction of applicable segments during that time period. Actual construction costs could differ from Idaho Power's estimates based upon the ability of Idaho Power, PacificCorp, or their respective contractors to timely obtain labor or materials at reasonable costs, supply chain disruptions and delays, inflationary pressures, macroeconomic conditions, or other issues.
The permitting phase of the Gateway West project was subject to review and approval of the BLM. The BLM has published its records of decision for all segments of the transmission line. In late 2020, PacifiCorp completed construction and commissioned a 140-mile segment of its portion of the project in Wyoming. In March 2023, PacifiCorp initiated the pre-construction phase of 620 miles of 500-kV transmission line from the Populus substation near Downey, Idaho, to the Hemingway substation near Boise, Idaho. Idaho Power and PacifiCorp continue to coordinate the timing of next steps to best meet customer and system needs including potentially modifying the ownership structure of a few segments of the project.
Hells Canyon Complex Relicensing: The HCC, located on the Snake River where it forms the border between Idaho and Oregon, provides approximately 70 percent of Idaho Power's hydropower generating nameplate capacity and 36 percent of its total generating nameplate capacity. Idaho Power has been engaged in the process of obtaining a new long-term license for the HCC from the FERC. The past and anticipated future costs associated with obtaining a new long-term license for the HCC are significant. Costs for the relicensing of Idaho Power's hydropower projects are recorded in construction work in progress until new multi-year licenses are issued by the FERC, at which time the charges are transferred to electric plant in service. Idaho Power expects to seek recovery of relicensing costs and costs related to a new long-term license through the regulatory process.
Relicensing costs of $460 million (including AFUDC) for the HCC, Idaho Power's largest hydropower complex and a major relicensing effort, were included in construction work in progress at December 31, 2023. As of the date of this report, the IPUC has authorized Idaho Power to include in its Idaho jurisdiction rates approximately $8.8 million annually of AFUDC relating to the HCC relicensing project. Collecting these amounts currently will reduce future collections when the HCC relicensing costs are approved for recovery in base rates. As of December 31, 2023, Idaho Power's regulatory liability for collection of AFUDC relating to the HCC was $229 million.
As of the date of this report, Idaho Power believes issuance of a new HCC license by the FERC will be in 2025 or thereafter. Idaho Power is unable to predict the exact timing that the FERC will issue a new license order or the ultimate capital investment and ongoing operating and maintenance costs Idaho Power will incur in complying with a new license. As of the date of this report, Idaho Power estimates that the annual costs it will incur to obtain a new long-term license for the HCC, including AFUDC but excluding costs expected to be incurred for complying with the license after issuance, are likely to range from $35 million to $45 million until issuance of the license. 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. In December 2016, Idaho Power filed an application with the IPUC requesting a determination that Idaho Power's expenditures of $220.8 million through year-end 2015 on relicensing of the HCC were prudently incurred, and thus eligible for future inclusion in retail rates in a future rate proceeding. In April 2018, the IPUC issued an order approving a settlement stipulation signed by Idaho Power, the IPUC staff, and a third-party intervenor
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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 2023. Information on Idaho Power's 2023 IRP is included in Part I, Item 1 - "Business - Resource Planning" in this report.
Defined Benefit Pension Plan Contributions and Recovery
Idaho Power contributed $48 million in 2023 and $40 million in 2022 to its defined benefit pension plan. Idaho Power estimates that it has no minimum required contribution to be made during 2024. Depending on market conditions and cash flow considerations, Idaho Power could contribute up to $30 million to the pension plan during 2024. Idaho Power's contributions are made in a continued effort to balance the regulatory collection of these expenditures with the amount and timing of contributions to mitigate the cost of being in an underfunded position. Beyond 2024, Idaho Power expects continuing contributions under the pension plan could be significant. Refer to Note 11 – “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, 2023 and 2022, Idaho Power's deferral balance associated with the Idaho jurisdiction was $255 million and $250 million, respectively. Deferred pension costs are amortized to expense to match the revenues received when contributions are recovered through rates. Idaho Power only records a carrying charge on the unrecovered balance of cash contributions. In December 2023, the IPUC authorized Idaho Power to increase its annual recovery and amortization of deferred pension costs in 2024 from $17 million to $35 million annually. Idaho Power has applied $68 million against the deferred amount under its Idaho sharing mechanisms since 2011. The primary impact of pension contributions is on the timing of cash flows, as cost recovery lags behind the timing of contributions. Additional information on the regulatory assets related to Idaho Power's pension and postretirement programs can be found in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.
Contractual Obligations
IDACORP’s and Idaho Power’s contractual cash obligations as of December 31, 2023, include long-term debt, interest payments, purchase obligations, pension and post-retirement benefit plans, and other long-term liabilities specific to IDACORP, most of which are discussed throughout this MD&A. Refer to Note 9 – “Commitments” to the consolidated financial statements included in this report for additional information relating to purchase obligations and other long-term liabilities.
Dividends
The amount and timing of dividends paid on IDACORP’s common stock are within the discretion of IDACORP’s board of directors. IDACORP's board of directors reviews the dividend rate periodically to determine its appropriateness in light of IDACORP’s current and long-term financial position and results of operations, capital requirements, rating agency considerations, contractual and regulatory restrictions, legislative and regulatory developments affecting the electric utility industry in general and Idaho Power in particular, competitive conditions, and any other factors the board of directors deems relevant. The ability of IDACORP to pay dividends on its common stock is generally dependent upon dividends paid to it by its subsidiaries, primarily Idaho Power.
IDACORP has a dividend policy that provides for a target long-term dividend payout ratio of between 60 percent and 70 percent of sustainable IDACORP earnings, with the flexibility to achieve that payout ratio over time and to adjust the payout ratio or to deviate from the target payout ratio from time to time based on the various factors that drive IDACORP's board of
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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 2023 and 2022, IDACORP's board of directors voted to increase the quarterly dividend to $0.83 per share and $0.79 per share of IDACORP common stock, respectively. IDACORP's dividends during 2023 were 62.3 percent of actual 2023 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 6 – “Common Stock” to the consolidated financial statements included in this report.
Contingencies and Proceedings
IDACORP and Idaho Power are involved in a number of litigation, alternative dispute resolution, and administrative proceedings, and are subject to claims and legal actions arising in the ordinary course of business that could affect their future results of operations and financial condition. In many instances IDACORP and Idaho Power are unable to predict the outcomes of the matters or estimate the impact the proceedings may have on their financial positions, results of operations, or cash flows.
Idaho Power is also actively monitoring various environmental regulations that may have a significant impact on its future operations. Given uncertainties regarding the outcome, timing, and compliance plans for these environmental matters, Idaho Power is unable to determine the financial impact of potential new regulations but does believe that future capital investment for infrastructure and modifications to its electric generating facilities to comply with these regulations could be significant.
Off-Balance Sheet Arrangements
IDACORP’s and Idaho Power’s off-balance sheet arrangements as of December 31, 2023, include guarantees of Idaho Power's portion of reclamation activities and obligations at BCC, of which IERCo owns a one-third interest. See Note 9 – “Commitments” to the consolidated financial statements included in this report for additional information relating to off-balance sheet arrangements.
REGULATORY MATTERS
Introduction
Idaho Power is under the jurisdiction (as to rates, service, accounting, and other general matters of utility operation) of the IPUC, the OPUC, and the FERC. The IPUC and OPUC determine the rates that Idaho Power is authorized to charge to its retail customers. Idaho Power is also under the regulatory jurisdiction of the IPUC, the OPUC, and the WPSC as to the issuance of debt and equity securities. As a public utility under the 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, the FERC has jurisdiction over Idaho Power's sales of transmission capacity and wholesale electricity, hydropower project relicensing, and system reliability, among other items.
Idaho Power develops its regulatory filings taking into consideration short-term and long-term needs for rate relief and several other factors that can affect the structure and timing of those filings. These factors include in-service dates of major capital investments, the timing and magnitude of changes in major revenue and expense items, and customer growth rates, as well as other factors. In recognition of Idaho Power’s current and anticipated significant infrastructure investments, including those that are intended to help meet projected near-term capacity deficits, Idaho Power filed a general rate case in Idaho in June 2023. The 2023 Settlement Stipulation was filed for that rate case in October 2023, and the IPUC approved the 2023 Settlement Stipulation on December 28, 2023, with rates effective January 1, 2024. Idaho Power filed a general rate case in Oregon on December 15, 2023. With the large amount of ongoing investments and the associated regulatory lag in cost recovery, on February 14, 2024, Idaho Power provided notice to the IPUC of its intent to file a general rate case or limited issue rate proceeding in Idaho on or after June 1, 2024.
Between general rate cases, Idaho Power relies upon customer growth, a FCA mechanism, power cost adjustment mechanisms, WMP cost deferrals, project-specific cases, tariff riders, and other mechanisms to mitigate the impact of regulatory lag, which refers to the period of time between making an investment or incurring an expense and recovering that investment or expense and earning a return.
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Notable Retail Rate Changes in Idaho and Oregon
The table below presents notable rate changes during 2023 and 2022 that affected Idaho Power's results for the periods or that will likely affect future periods. Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report also provides a description of regulatory mechanisms and associated orders of the IPUC and OPUC, and should be read in conjunction with the discussion of regulatory matters in this MD&A. The table does not include the changes to rates effective January 1, 2024, resulting from the 2023 Settlement Stipulation.
Idaho and Oregon General Rate Cases
As noted above, on December 28, 2023, the IPUC approved the 2023 Settlement Stipulation in connection with Idaho Power's general rate case. The 2023 Settlement Stipulation provides for revised tariff schedules designed to increase annual Idaho-jurisdictional retail revenue by $54.7 million, or 4.25 percent, effective January 1, 2024, net of an Idaho-jurisdiction PCA rate decrease of $168.3 million and a reduction to annual energy efficiency rider collection of $3.5 million, each of which was transferred into base rates. The 2023 Settlement Stipulation also provides for a 9.6 percent return on equity and a 7.247 percent authorized rate of return based on a non-specified cost of debt and capital structure, applied to an Idaho-jurisdictional rate base of approximately $3.8 billion. For more information on the Idaho general rate case and related 2023 Settlement Stipulation, see Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.
At December 31, 2023, Idaho Power estimates that it had $86 million of deferred credits for future use under the ADITC and Revenue Sharing mechanism. Under the modified ADITC and Revenue Sharing mechanism, Idaho Power may seek approval from the IPUC to replenish the total amount of additional ADITC it is permitted to amortize and if there are no remaining amounts of additional ADITC authorized to be amortized, the remainder of the revenue sharing provisions would not be applicable until additional ADITC is replenished.
In December 2023, Idaho Power filed a general rate case with the OPUC. Previously, effective March 1, 2012, Idaho Power implemented new Oregon base rates resulting from its receipt of an order from the OPUC approving a settlement stipulation in its general rate case proceedings that provided for a $1.8 million base rate revenue increase, a rate of return on equity of 9.9 percent, and an overall rate of return of 7.757 percent in the Oregon jurisdiction. Oregon base rates were subsequently adjusted again in 2012 and 2020.
Idaho Power is unable to predict the outcome of the Oregon general rate case, but anticipates that new rates, if approved by the OPUC, would become effective in October 2024 or later. For more information on Oregon general rate changes, see Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.
Other Notable Regulatory Matters
May 2018 Idaho Tax Reform Settlement Stipulation: In May 2018, the IPUC issued an order approving a settlement stipulation (2018 Settlement Stipulation) related to income tax reform. In 2023, Idaho Power recorded no amounts for sharing with customers under this stipulation. For the years 2011 through 2022, Idaho Power recorded $58.7 million as a refund to customers and $68.1 million as a pre-tax charge to pension expense cumulatively under the 2018 Settlement Stipulation and its predecessors.
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For more information on the provisions of the 2018 Settlement Stipulations, see Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.
North Valmy Base Rate Adjustment Settlement Stipulations: Idaho Power has settlement stipulations in place in Idaho and Oregon related to the planned early retirement of both units of its jointly-owned North Valmy coal-fired power plant. The settlement stipulations are described more fully in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.
Jim Bridger Power Plant Rate Base Adjustment and Recovery: In June 2022, the IPUC issued an order (Bridger Order) approving, with modifications, Idaho Power’s amended application related to adjustment and recovery of the Jim Bridger Power Plant rate base. The Bridger Order and associated accounting are described in Note 3 – “Regulatory Matters” to the consolidated financial statements included in this report. Regulatory orders from the IPUC and OPUC provide for Idaho Power to cease coal-fired operations at the Jim Bridger plant by the end of 2028. However, as noted previously, Idaho Power's 2023 IRP identified a preferred resource portfolio and action plan that includes the conversion from coal to natural gas of two units at the Jim Bridger plant in 2024 and the remaining two units at the Jim Bridger plant in 2030. Idaho Power expects to seek approval from the IPUC and OPUC for any necessary adjustments to plant retirement dates to align with its current resource plan.
Wildfire Mitigation Cost Deferral: Beginning in 2021, the IPUC has authorized Idaho Power to defer for future amortization certain expenses necessary to implement the company's WMP. The wildfire mitigation cost deferral is described more fully in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.
Fixed Cost Adjustment: The FCA mechanism, applicable to Idaho residential and small commercial customers, is designed to remove a portion of Idaho Power’s financial disincentive to invest in energy efficiency programs by separating (or decoupling) the recovery of fixed costs from the variable kWh charge and linking it instead to a set amount per customer. The FCA mechanism is described more fully in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.
Integrated Resource Plan and Resource Procurement Filings: Idaho Power filed its most recent IRP with the IPUC and OPUC in September 2023, as described in Part 1, Item 1 - "Business - Resource Planning" in this report.
The State of Oregon has competitive bidding rules regarding a public utility's procurement of resources. However, as allowed by the rules in certain cases, Idaho Power is pursuing exceptions for its identified 2024 and 2025 resource needs. In July 2023, following review by an independent evaluator appointed by the OPUC, OPUC staff, and other intervening parties, the OPUC issued an order approving issuance of Idaho Power's final RFP to procure resources for its anticipated energy and capacity needs in 2026 and 2027.
Customer-Owned Generation Filing: Customer-owned generation enables customers to install solar panels or other on-site energy-generating resources and connect them to Idaho Power’s grid. If a customer requires more energy than its system generates, it uses energy supplied by Idaho Power’s grid and infrastructure. If a customer's system generates more energy than the customer uses, the energy is transferred to the grid and Idaho Power applies a corresponding kWh credit to the customer’s bill. The IPUC issued an order in February 2020 directing Idaho Power to continue to allow residential and small commercial customers with on-site generation installed prior to December 20, 2019, to be subject to the compensation and billing structure in place on that date until December 20, 2045. In December 2020, the IPUC issued an order establishing a 25-year grandfathering term for large commercial, industrial, and irrigation customers, similar to the terms approved for the residential and small commercial customer classes.
In June 2022, as directed by the IPUC, Idaho Power filed a comprehensive study on the costs and benefits of on-site generation based on the IPUC’s study framework findings and conclusions, and in December 2022, the IPUC issued an order that directed Idaho Power to file a new case requesting to implement changes to the structure and design of its on-site generation program. In May 2023, Idaho Power filed a new case as directed by the IPUC, requesting to implement changes for non-grandfathered customers starting January 1, 2024, including: (1) a change from net monthly to real-time net billing, which would better measure customers’ actual reliance on the grid; (2) a change in the excess exported energy credit from a kWh credit ranging in value of 5 to 12 cents, depending on the customer class, to a time-differentiated financial bill credit ranging from approximately 5 to 20 cents per kWh that would be updated annually; and (3) a modification to the eligibility cap for large commercial, industrial, and irrigation customers. On December 29, 2023, the IPUC approved Idaho Power's filing, with certain modifications, including an adjustment to the financial bill credit rates to a range from 5 to 17 cents as well as other administrative modifications.
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Large Customer Rate Proceedings
Clean Energy Your Way Program: In August 2023, the IPUC approved Idaho Power's application to expand optional customer clean energy offerings through its new Clean Energy Your Way Program. Specifically, Idaho Power received authority to: (1) rename its existing green power program; (2) maintain and expand procurement options for the RECs; (3) establish a regulatory framework for a future voluntary subscription green power service program; (4) offer a tailored renewable option for Idaho Power's largest customers; and (5) procure the associated additional resources outside of the IPUC's current competitive procurement requirements.
Brisbie, LLC (Brisbie) Data Center: In April 2023, the IPUC approved an arrangement, modeled after the Clean Energy Your Way program under which a new large load customer, Brisbie, LLC (Brisbie), a wholly-owned subsidiary of Meta Platforms, Inc., would purchase from Idaho Power energy for a new 960,000 square-foot enterprise data center. The energy to be purchased by Brisbie is anticipated to be generated by a to-be-constructed 200-MW solar facility pursuant to a long-term power purchase agreement between Idaho Power and a third party, as well as additional renewable resource projects to be developed. The 200-MW solar facility is scheduled to begin operating as early as March 2025. In January 2024, Idaho Power filed for IPUC approval of an additional contract with a 125-MW solar project to be online in December 2026.
In May 2023, the IPUC issued an order approving, with modifications, a special contract for electric service for Brisbie for the new data center. Idaho regulations require any utility customer with an average load exceeding 20 MW to enter into a special contract with its electric provider. Brisbie, in addition to its large load service requirements in excess of 20 MW, has a sustainability objective to support 100 percent of its operations with new renewable resources. Under the special contract, Idaho Power expects to procure enough renewable resources to support 100 percent of Brisbie's operations on an annual basis with new renewable resources. The modified special contract and related rate schedule were approved by the IPUC in October 2023.
Micron Dedicated Renewable Resource: In August 2022, the IPUC issued an order approving, with modifications, Idaho Power's application for a revised special contract for electric service between Idaho Power and Micron. The application was modeled after the Clean Energy Your Way program and included an arrangement under which Micron would purchase from Idaho Power energy generated by a to-be-constructed 40-MW solar facility pursuant to a 20-year power purchase agreement between Idaho Power and a third party. The solar facility began operating in May 2023.
In April 2023, the IPUC issued an order approving Idaho Power's compliance filing of revised electric service rates for Micron that include new energy rates that incorporate the solar generation and compensation for capacity value and excess renewable energy generation.
Lamb Weston, Inc. Special Contract: In September 2023, the IPUC issued an order approving Idaho Power's special contract for electric service for an existing large load customer, Lamb Weston, Inc. (Lamb Weston). Idaho Power anticipates Lamb Weston's large load service requirements to exceed 20 MW in the near future.
Speculative High-Density Load: In June 2022, the IPUC approved Idaho Power's application to create a new customer class that would be applicable to commercial and industrial cryptocurrency mining operations, or any other speculative high-density load customers of less than 20 MW. Idaho Power believes new system resources may be necessary to serve this speculative customer load, which could create a financial risk for Idaho Power and its customers if the underlying economics of cryptocurrency mining change. Idaho Power believes that the financial and system risks of speculative high-density load could be mitigated through use of a rate design for this customer class that prices energy at a marginal rate, and through a requirement that speculative high-density load customers be interruptible at Idaho Power's discretion from June 15 through September 15, Idaho Power's summer peak season. As subsequently required by the IPUC, in December 2022, Idaho Power filed an application proposing the interruption compensation for Schedule 20 customers. In August 2023, the IPUC approved interim interruption compensation rates until a rate can be designed using sufficient data from actual Schedule 20 customers.
Deferred 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 or refund through customer rates.
Idaho Power's power cost adjustment mechanisms in its Idaho and Oregon jurisdictions address the volatility of power supply costs and provide for annual adjustments to the rates charged to retail customers. The power cost adjustment mechanisms and
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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, 2022 | $ | 128.7 | $ | 0.6 | $ | 129.3 | ||||||||||||||
| Current period net power supply costs deferred/(accrued) | 66.7 | (1.2) | 65.5 | |||||||||||||||||
| Prior amounts collected through rates | (72.2) | (0.2) | (72.4) | |||||||||||||||||
| REC sales | (13.2) | (0.6) | (13.8) | |||||||||||||||||
| Interest and other | 5.6 | 0.1 | 5.7 | |||||||||||||||||
Balance at December 31, 2023 | $ | 115.6 | $ | (1.3) | $ | 114.3 | ||||||||||||||
Open Access Transmission Tariff Rate
Idaho Power uses a formula rate for transmission service provided under its OATT, which allows transmission rates to be updated annually based primarily on financial and operational data Idaho Power files with the FERC. In October 2023, Idaho Power filed its 2023 final transmission rate with the FERC, reflecting a transmission rate of $30.74 per "kW-year," to be effective for the period from October 1, 2023, to September 30, 2024. A "kW-year" is a unit of electrical capacity equivalent to 1 kW of power used for 8,760 hours. Idaho Power's final rate was based on a net annual transmission revenue requirement of $135.7 million. The OATT rate in effect from October 1, 2022 to September 30, 2023, was $31.42 per kW-year based on a net annual transmission revenue requirement of $132.7 million.
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. See Note 12 - "Property, Plant and Equipment and Jointly-Owned Projects" to the consolidated financial statements included in this report for information regarding relicensing costs for the HCC. In addition to the discussion below, refer to “Hells Canyon Complex Relicensing” in “Liquidity and Capital Resources” in this MD&A for a discussion of the costs and expected timing of a HCC license and "Environmental Matters" in this MD&A for a discussion of environmental compliance under FERC licenses for Idaho Power's hydropower generating plants.
Hells Canyon Complex Relicensing: 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 involved in the HCC relicensing process, including NMFS and USFWS, entered into an interim agreement that addresses the effects of the ongoing operations of the HCC on ESA-listed species pending the relicensing of the project. The FERC staff issued a final EIS in August 2007.
In connection with its relicensing efforts, Idaho Power filed annual water quality certification applications, required under Section 401 of the CWA, with the states of Idaho and Oregon requesting that each state certify that any discharges from the HCC comply with applicable state water quality standards. Challenges regarding how to meet water temperature standards below the HCC dam for spawning fall Chinook salmon, and a conflict in laws between Oregon and Idaho regarding the reintroduction and passage of fish above the HCC, delayed the issuance of the states' 401 certifications for several years. In November 2016, Idaho Power filed a petition with the FERC requesting that the FERC resolve the conflict between Oregon's and Idaho's conditions and declare that the FPA pre-empts the Oregon state law requiring reintroduction and passage, which the
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FERC denied in January 2017. In February 2018, Idaho Power appealed the FERC's January 2017 order with the United States Court of Appeals for the District of Columbia Circuit, 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. In May 2019, Oregon and Idaho issued final CWA Section 401 certifications which have been submitted to the FERC as part of the relicensing process. 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. The FERC's decision relating to the Offer of Settlement is pending as of the date of this report.
In July 2020, Idaho Power submitted to the FERC its supplement to the final license application, incorporating the settlement agreement reached between Idaho and Oregon on the CWA Section 401 certifications. The supplement included feedback on proposed modifications of the 2007 final EIS for the HCC, as well as an updated cost analysis of the HCC and a request that the FERC issue a 50-year license and initiate a supplemental NEPA process at the FERC. In June 2022, the FERC issued a notice of intent to prepare a supplemental EIS in accordance with NEPA. The FERC also reinstated informal consultation with the USFWS and the NMFS under section 7 of the ESA. In October 2023, the FERC issued a notice revising the schedule for completing the supplemental EIS. Under the revised schedule, the draft supplemental EIS is targeted to be published in February 2024 and the final supplemental EIS in November 2024.
American Falls Relicensing: In April 2020, the FERC formally initiated the relicensing of the American Falls hydropower facility, which is Idaho Power's largest hydropower facility outside of the HCC, with a generating capacity of 92.3 MW. Idaho Power owns the generation facility but not the structural dam itself, which is owned by the U.S. Bureau of Reclamation. In February 2023, following the filing of a draft license application and public comment period, Idaho Power filed a final license application with the FERC. In July 2023, the FERC accepted Idaho Power’s final license application for filing and solicited motions to intervene and protest. In September 2023, the FERC issued a request for comments to determine the resource issues that should be addressed in the environmental analysis and identify reasonable alternatives to the proposed action that the FERC should evaluate under the NEPA framework. In January 2024, the FERC indicated that it planned to issue a Notice of Ready for Environmental Analysis, the next major milestone in the relicensing process, in February 2024. The relicensing has begun the process of informal ESA Section 7 consultation with the USFWS and Section 106 of the National Historic Preservation Act consultation with the Idaho State Historic Preservation Office.
In September 2023, Idaho Power filed an application for CWA Section 401 water quality certification with the IDEQ. The IDEQ informed Idaho Power that it anticipates preparing a draft certification and will seek public comment once the draft is complete. American Falls' current license expires in 2025, and as of the date of this report, Idaho Power expects the FERC to issue a new license for this facility concurrent with or prior to the existing license's expiration.
ENVIRONMENTAL MATTERS
Overview
Idaho Power is subject to a broad range of federal, state, regional, and local laws and regulations designed to protect, restore, and enhance the environment, including the CAA, 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
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•require the acquisition of alternative sources of energy or storage technology, increased transmission wheeling, or 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 2020 was based in part on the significant cost of compliance with environmental laws and regulations. The decision to end participation in coal-fired operations at the North Valmy plant was also based in part on the economics of continuing coal-fired generation at the plant. Beyond increasing costs generally, these environmental laws and regulations could affect IDACORP's and Idaho Power's results of operations and financial condition if the costs associated with these environmental requirements and early plant retirements cannot be fully recovered in rates on a timely basis.
Part I, Item 1 - “Business - Utility Operations - Environmental Regulation and Costs” in this report includes a summary of Idaho Power's expected capital and operating expenditures for environmental matters during the period from 2024 to 2026. Given the uncertainty of future environmental regulations and technological advances, there is uncertainty around near-term estimates, and Idaho Power is also unable to predict its environmental-related expenditures beyond 2026, though they could be substantial. Furthermore, several executive orders issued since 2017 concerning environmental regulations, including executive orders issued by the current Presidential Administration to establish new federal environmental mandates, revoke several existing executive orders, and require agencies to review environmental regulations issued by the previous Presidential Administration, could result in significant changes in, and uncertainty with respect to, legislation, regulation, and government policy regarding environmental matters. The outcome of federal agencies' review of regulations covered by executive orders and revocation of executive orders is difficult to predict. Additionally, the court system has become more active in reviewing agency actions, resulting in even less certainty as to the outcome and durability of rules that are administratively implemented. Changes to or elimination of regulations may lower Idaho Power's costs of operating and maintaining fossil fuel-fired generation plants and transmission lines, due to the reduction of potential environmental infrastructure upgrades or conversions, or reduction or elimination of permitting requirements. 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, and could impact Idaho Power's plans and pre-construction activities related to its major transmission projects, which could lead to substantially higher construction and permitting costs and could delay construction. Executive orders may be affected by Congressional action and challenged in court. Further, state and local governmental authorities could choose to challenge or replace the federal regulations or bolster or undermine environmental compliance and enforcement efforts at the local level. Therefore, 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 orders, any future executive orders, and the implementation of these and any future executive orders could affect its business, results of operations, and financial condition. Idaho Power will continue to monitor actions associated with or resulting from executive orders.
Endangered Species Act Matters
Overview: The listing of a species of fish, wildlife, or plants as threatened or endangered under the ESA may have an adverse impact on Idaho Power's ability to construct power supply, transmission, or distribution facilities or relicense or operate its hydropower facilities.
Over the past few years and as a result of changes in Presidential Administrations, regulatory developments and executive orders have called into question the existing requirements under the ESA. Subsequent federal court decisions have in some cases undermined the effectiveness of those regulations and orders. The uncertainty in the regulatory landscape makes it difficult to predict the scope, timing and complexity of project-related ESA matters to be addressed.
In May 2023, the USFWS published a revised Mitigation Policy and a revised ESA Compensatory Mitigation Policy (Revised Policies) which together establish fundamental mitigation principles and compensatory mitigation standards and application guidance through implementation of the ESA. The Revised Policies scale back the mitigation goal from the previous policies by including a nexus and proportionality principle to reinforce that government-required mitigation measures must have a clear connection with the anticipated effects of the proposed land use. As of the date of this report, Idaho Power is uncertain to what extent the Revised Policies may impact its obligations in permitting infrastructure, including relicensing its hydropower facilities, and transmission lines.
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There are a number of threatened or endangered species within Idaho Power's service area located in waterways in which Idaho Power has hydropower facilities, and within or near proposed transmission line routes. To date, efforts to protect these 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 2016, a group of lawsuits were filed in federal court to challenge the BLM's sage grouse resource management and land use plan revisions that became effective in 2015 under the Federal Land Policy and Management Act. The lawsuits challenge the plans and associated EISs across the sage grouse range, including in Idaho and North Dakota, and allege that the plans fail to ensure that sage grouse populations and habitats will be protected and restored in accordance with the best available science and legal mandates. Further, the lawsuits challenge certain exemptions provided for the Boardman-to-Hemingway and Gateway West transmission line projects. Idaho Power has intervened in the proceedings in an effort to support the exemptions provided for in the BLM's plans. If the exemptions are overturned, Idaho Power may be required to re-route the projects, which could lead to substantially higher construction and permitting costs and could delay construction.
In 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. Following a series of interim measures, in February 2022, the BLM issued a notice of intent to amend its land use plans regarding sage grouse conservation and prepare associated EISs, soliciting public comments on the planning initiative. It is unclear when the BLM will issue the applicable draft land use plan amendments and associated EISs.
As of the date of this report, the above lawsuits are stayed as the parties and the courts have agreed that the processes initiated by the BLM may result in further administrative actions that could remove the need for the lawsuits.
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. In June 2022, the FERC issued a notice of intent to prepare a draft supplemental EIS and a final supplemental EIS in accordance with NEPA. The FERC also reinstated informal consultation with the USFWS and NMFS under section 7 of the ESA. As of the date of this report, Idaho Power anticipates that the final biological opinions will likely be issued after the FERC issues a final supplemental EIS, which is scheduled for November 2024 according to the FERC's revised notice of intent.
Gateway West and Boardman-to-Hemingway Transmission Projects and Other Infrastructure - Slickspot Peppergrass Designation: 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.
National Environmental Policy Act Matters
NEPA is a federal law that requires federal agencies to consider the environmental impacts of their actions and decisions. NEPA applies to Idaho Power’s transmission and distribution lines that are located on federal land, as well as other company activities involving federal actions. In April 2022, the current Presidential Administration’s Council on Environmental Quality (CEQ) published a final rule that restores a prior NEPA requirement, eliminated under the previous Administration, that federal agencies consider all indirect and cumulative environmental impacts of infrastructure projects in their decision-making, among other things, which could delay and increase the cost of Idaho Power’s infrastructure projects. In July 2023 the CEQ proposed a
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second round of NEPA reform to revise regulations for implementing NEPA. Key changes in the Phase 2 rule relate to the definition of “reasonably foreseeable effects,” how the agency interprets a reasonable range of alternatives, what constitutes a major federal action, and the incorporation of environmental justice into the NEPA analysis. The CEQ is now working on finalizing the rule.
Climate Change and the Regulation of Greenhouse Gas Emissions
Overview: Ongoing climate change could significantly affect Idaho Power's business in a variety of ways, including:
•changes in temperature and precipitation could affect customer demand for electric power;
•extreme weather events, wildfires, drought, and other natural phenomena and natural disasters could increase service interruptions, outages, maintenance costs, system damage, personal property damage, personal injuries and loss of life, legal liability, and the need for additional backup systems, and can affect the supply of, and demand for, electricity and natural gas, which may impact the price of those and other commodities;
•changes in the amount and timing of snowpack and other precipitation and stream flows could affect hydropower generation;
•legislative and/or regulatory developments related to climate change could affect power/generation plants and operations, including restrictions on the construction or addition of new power supply resources, the expansion of existing resources, or the operation of power supply resources; and
•consumer preference for, and resource planning decisions requiring, renewable or low GHG-emitting sources of energy could impact usage of existing generation sources and require significant investment in new generation and transmission infrastructure.
Federal and state regulations pertaining to GHG emissions under the CAA have raised uncertainty about the future viability of fossil fuels, most notably coal, as an economical energy source for new and existing electric generation facilities because many new technologies for reducing 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. Idaho Power's 2023 IRP identifies a preferred resource portfolio and action plan that anticipates (1) converting North Valmy plant units 1 and 2 to natural gas by summer 2026; (2) converting units 1 and 2 at the Jim Bridger plant from coal to natural gas in 2024; and (3) converting units 3 and 4 at the Jim Bridger plant from coal to natural gas in 2030.
A variety of factors contribute to the financial, regulatory, and logistical uncertainties related to GHG reductions. These include the specific GHG emissions limits imposed, the timing of implementation of these limits, the level of emissions allowances allocated and the level that must be purchased, the purchase price of emissions allowances, the development and commercial availability of technologies for renewable energy and for the reduction of emissions, the degree to which offsets may be used for compliance, provisions for cost containment (if any), the impact on coal and natural gas prices, and the timing and amount of cost recovery through rates. Accordingly, Idaho Power cannot predict the effect on its results of operations, financial condition, or cash flows of any GHG emissions 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 issued 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 repealed the CPP and replaced it with the Affordable Clean Energy (ACE) rule under Section 111(d) of the CAA for existing
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electric utility generating units. In subsequent litigation, the ACE rule was vacated without reinstating the CPP and the case is pending further legal proceedings.
In May 2023, the EPA released a proposed rule under Section 111 of the CAA to regulate GHG emissions from fossil fuel-fired power plants. The proposed rule would impose significant GHG emissions reductions on new and existing natural gas-fired generating units and coal plants expected to be operational in 2040 and beyond. The proposed rule would require states to submit plans to the EPA to implement standards for existing sources within 24 months of the effective date of the emission guidelines. In August 2023, Idaho Power submitted comments to the EPA requesting it to maintain certain jurisdictional limits published in the rule and create flexibility for state plans to account for system reliability. In November 2023, the EPA finalized a portion of the Section 111 rule related to existing fossil fuel-fired power plants, but deferred action on new sources, pending additional comments and information related to reliability. As of the date of this report, Idaho Power continues to evaluate the specific impacts the rule could have on its operations at its three natural gas facilities, as well as the North Valmy and Jim Bridger plants. Idaho Power anticipates that the GHG emissions reductions may under certain circumstances only be achievable by reducing unit runtimes.
State GHG Initiatives and Idaho Power’s Voluntary GHG Reduction Initiative: In 2007, Oregon 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 also established its Oregon Clean Electricity and Coal Transition Plan in 2016, which 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.
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. The Climate Registry is a voluntary collaboration aimed at developing and managing a common GHG emissions reporting system across states, provinces, and tribes to track GHG emissions nationally. All states for which Idaho Power has traditional fuel generating plants (i.e. Idaho, 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
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 MATS, NAAQS, New Source Review / Prevention of Significant Deterioration Rules, and the Regional Haze Rule.
The MATS rule under the CAA provides that sources must comply with emission limits by April 2015. Idaho Power and the co-owners of Jim Bridger and North Valmy coal-fired generating plants have installed mercury continuous emission monitoring systems on all coal-fired units at the plants, along with control technology to reduce mercury, acid gases, and particulate matter emissions for purposes of compliance with the MATS rule. Idaho Power believes that as of the date of this report, its jointly-owned coal-fired plants are in compliance with the MATS rule.
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, and SO2. States are then required to develop emissions reduction strategies through SIPs, based on attainment of these ambient air quality standards. Recent developments and pending actions related to certain of those items are relevant to Idaho Power. However, as of the date of this report, Idaho Power does not expect the recent changes in the NAAQS to significantly impact its operations or materially increase Idaho Power’s capital and operating costs.
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, which are subject to regulation by both EPA and WDEQ.
In June 2023, the EPA published the final rule under the CAA called the Federal "Good Neighbor Plan" for the 2015 Ozone NAAQS (Good Neighbor Plan), which took effect on August 4, 2023. The Good Neighbor Plan establishes NOx emissions budgets requiring fossil fuel-fired power plants to participate in an allowance-based ozone season trading program. The EPA's final rule temporarily excluded power plants located in Wyoming, while the EPA reevaluated the proposed disapproval of the
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Wyoming SIP. In August 2023, the EPA published a proposed approval of the Wyoming SIP, finding that the EPA’s updated modeling demonstrated that Wyoming’s determination that no additional controls are required to address interstate transport for the 2015 zone NAAQSs was reasonable. In December 2023, the EPA finalized the approval of the Wyoming SIP, removing it from the federal implementation plan. The Wyoming SIP does not have additional requirements for the Jim Bridger facility under the Good Neighbor Plan.
In July 2023, the Ninth Circuit Court of Appeals issued a stay halting application of the Good Neighbor Plan in Nevada pending a hearing on the merits of an appeal challenging the EPA's disapproval of Nevada's SIP. In light of the court's ruling, in September 2023, the EPA issued an interim final rule indefinitely suspending the implementation of the Good Neighbor Plan in Nevada. As of the date of this report, Idaho Power continues to evaluate the specific impacts the Good Neighbor Plan could have on its operations at the North Valmy plant. If the Good Neighbor Plan is implemented in Nevada, Idaho Power anticipates that, under certain conditions, it could reduce the ability to use the full available output, or require the purchase of allowances in order to utilize the full available output, at the North Valmy plant during the EPA defined ozone season (May through September).
Clean Water Act Matters
Definition of “Waters of the United States” Under the CWA: The definition of "waters of the United States" is fundamental to the application of the CWA because only those bodies of water designated as WOTUS are protected from unlawful discharge of pollutants under the CWA. In May 2023, the U.S. Supreme Court issued a decision defining WOTUS under the CWA and providing nationwide clarity of the federal government’s jurisdiction over WOTUS. The decision restricts the federal government's ability to regulate wetlands that do not have a continuous surface connection with a navigable water. While not addressed in the opinion, ephemeral streams and other water bodies that are not relatively permanent would also not be jurisdictional under the May 2023 decision. The new definition of WOTUS from the Supreme Court should not alter how the CWA applies to most of Idaho Power's facilities, including its hydropower plants. As a result, Idaho Power does not expect the new definition to materially impact 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 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. In September 2023, Idaho Power filed a water quality certification application with Idaho for the American Falls facility, that is pending with the IDEQ.
In July 2020, the EPA published a rule amending regulations intended to implement the CWA Section 401 water quality certification process. The rule has been subject to various legal challenges. In September 2023, the EPA finalized a new Section 401 Water Quality Certification Rule and repealed the 2020 rule.
The EPA’s new rule expands state and tribal authority over water quality certifications; however, such expanded authority will not likely impact the timing and cost of the HCC certification under the current approval process. Idaho Power is still evaluating the impact the new rule will have on the American Falls application.
CWA Permitting: Idaho Power's hydropower generation facilities are subject to compliance and permitting obligations under the CWA. Idaho Power has been engaged for several years with the EPA, and is now engaged with the 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 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. Idaho Power also expects to incur additional costs associated with the relicensing of its hydropower facilities, as discussed elsewhere in this report.
In June 2022, Idaho Power and the IDEQ entered into a consent judgment in the Idaho state district courts to resolve a National Pollutant Discharge Elimination System permitting issue related to 15 of Idaho Power’s hydropower projects that required Idaho Power to pay a $1.1 million fine, implement interim measures for compliance, and ultimately submit applications for new permits at each of the dams subject to the consent judgment. Due to a misinterpretation of law, the EPA cancelled water discharge permits in the mid-1990’s, which Idaho Power subsequently determined were applicable for operation of the dams. Idaho Power believes that the dams would have been in compliance with the earlier permits had they remained in place. As of the date of this report, Idaho Power has submitted new permit applications for twelve of the dams and anticipates completing all submissions by June 2024.
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Invasive Species Management
Quagga mussels are an invasive species which have not been present in the Snake River system historically. Quagga mussel infestations can foul up irrigation, hydropower, and water delivery facilities and increase the costs to maintain such facilities. In September 2023, a larval form of quagga mussels and one adult quagga mussel were detected in the mid-Snake River near Twin Falls in Idaho Power's service area by the Idaho State Department of Agriculture (ISDA). As a result, in October 2023, ISDA treated approximately six miles of the Snake River, which includes Idaho Power's Twin Falls and Shoshone Falls hydropower facilities, using a copper-based, EPA-approved treatment called Natrix to eradicate quagga mussels. Initial ISDA sample results indicated that the treatment impacted larvae and adult quagga mussel populations. However, it is premature to conclude complete eradication at this stage. The ISDA will resume sampling in spring 2024 once water temperatures warm. The ISDA expects to implement ongoing surveying to determine the success of treatment.
If the treatment was unsuccessful, and a quagga mussel infestation occurs, it may result in increased other O&M expenses for mitigation efforts and other adverse impacts for Idaho Power's operation of its hydropower facilities in any infested areas. As of the date of this report, Idaho Power cannot predict the extent to which the Natrix treatment will be successful in eradicating quagga mussels from the Snake River, the extent of the treatment’s impact to the river and its inhabitants, or the potential increase in other O&M expenses related to quagga mussel mitigation efforts.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
When preparing financial statements in accordance with 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 $1.7 billion of regulatory assets and $0.9 billion of regulatory liabilities at December 31, 2023. Idaho Power expects to recover these regulatory assets from customers through rates and refund these regulatory liabilities to customers through rates, but recovery or refund is subject to final review by the regulatory bodies. If future recovery or refund of these amounts ceases to be probable, or if Idaho Power determines that it no longer meets the criteria for applying regulatory accounting, or if accounting rules change to no longer provide for regulatory assets and liabilities, Idaho Power could be required to eliminate those regulatory assets or liabilities, which could have a material effect on Idaho Power’s financial condition or results of operations.
Refer to Note 3 - “Regulatory Matters” to the consolidated financial statements included in this report for additional information relating to regulatory matters.
Income Taxes
IDACORP and Idaho Power use judgment and estimation in developing the provision for income taxes and the reporting of tax-related assets and liabilities. 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.
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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, and a postretirement benefit plan (consisting of health care and death benefits).
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, 2023, with maturities matching the projected cash outflows of the plans. Based on the results of this analysis, the discount rate used to calculate the 2024 defined benefit plan pension expense decreased to 5.10 percent from the 5.45 percent rate used in 2023.
Rate-of-return projections for plan assets are based on historical risk/return relationships among asset classes. The primary measure is the historical risk premium each asset class has delivered versus the yield on the Moody's AA Corporate Bond Index. This historical risk premium is then added to the current yield on the Moody's AA Corporate Bond Index, and Idaho Power believes the result provides a reasonable prediction of future investment performance. Additional analysis is performed to measure the expected range of returns, as well as worst-case and best-case scenarios. The long-term rate of return used to calculate the 2024 pension expense will be 7.4 percent, the same assumption as used in 2023.
Total net periodic pension and other postretirement benefit cost for these plans totaled $28.5 million and $42.3 million for the years ended December 31, 2023 and 2022, respectively, including amounts deferred as regulatory assets (see discussion below) and amounts allocated to capitalized labor. For 2024, total net periodic pension costs and other postretirement benefit costs are expected to total approximately $26.3 million, which takes into account the change in the discount rate noted above.
Had different actuarial assumptions been used, net periodic pension costs and other postretirement benefit costs could have varied significantly. The following table reflects the sensitivities associated with changes in the discount rate and rate-of-return on plan assets actuarial assumptions on historical and future net periodic pension costs and other postretirement benefit costs:
| Discount rate | Rate of return | |||||||||||||||||||||||||
| 2024 | 2023 | 2024 | 2023 | |||||||||||||||||||||||
| (millions of dollars) | ||||||||||||||||||||||||||
| Effect of 0.5% rate increase on total net periodic pension costs and other postretirement benefit costs | $ | (3.0) | $ | (2.4) | $ | (4.7) | $ | (4.3) | ||||||||||||||||||
| Effect of 0.5% rate decrease on total net periodic pension costs and other postretirement benefit costs | 8.1 | 6.1 | 4.7 | 4.3 | ||||||||||||||||||||||
Additionally, a 0.5 percent increase in the plans' discount rates would have resulted in a $76.2 million decrease in the combined benefit obligations of the plans as of December 31, 2023. A 0.5 percent decrease in the plans' discount rates would have resulted in an $85.4 million increase in the combined benefit obligations of the plans as of December 31, 2023.
The IPUC has authorized Idaho Power to account for its defined benefit pension plan expense on a cash basis, and to defer and account for accrued pension expense as a regulatory asset. The IPUC acknowledged that it is appropriate for Idaho Power to seek recovery in its revenue requirement of reasonable and prudently incurred pension expense based on actual cash contributions. In 2007, Idaho Power began deferring pension expense to a regulatory asset account to be matched with revenue when future pension contributions are recovered through rates. At December 31, 2023, a total of $255 million of expense was deferred as a regulatory asset. Idaho Power expects net amortization of the regulatory asset of approximately $19 million in 2024. Idaho Power recorded pension expense on its consolidated statements of income related to its tax-qualified defined benefit pension plan of approximately $18 million in 2023 and $19 million in 2022.
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Refer to Note 11 – “Benefit Plans” to the consolidated financial statements included in this report for additional information relating to pension and postretirement benefit plans.
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
For discussion of new and recently adopted accounting pronouncements, see Note 1 - "Summary of Significant Accounting Policies" to the notes to the consolidated financial statements included in this report.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
IDACORP and Idaho Power are exposed to market risks, including changes in interest rates, changes in commodity prices, credit risk, and equity price risk. The following discussion summarizes these risks and the financial instruments, derivative instruments, and derivative commodity instruments sensitive to changes in interest rates, commodity prices, and equity prices that were held at December 31, 2023. Neither IDACORP nor Idaho Power have entered into any of these market-risk-sensitive instruments for speculative purposes.
Interest Rate Risk
IDACORP and Idaho Power manages interest expense and short- and long-term liquidity through a combination of fixed rate and variable rate debt. Generally, the amount of each type of debt is managed through market issuance, but interest rate swap and cap agreements with highly-rated financial institutions may be used to achieve the desired combination.
Variable Rate Debt: As of December 31, 2023, IDACORP and Idaho Power had no net variable rate debt, as the carrying value of short-term investments exceeded the carrying value of outstanding variable rate debt.
Fixed Rate Debt: As of December 31, 2023, both IDACORP and Idaho Power had $2.8 billion in fixed rate debt, with a fair value of approximately $2.7 billion. These instruments are fixed rate and, therefore, do not expose the companies to a loss in earnings due to changes in market interest rates. However, the fair value of these instruments would increase by approximately $343 million if market interest rates were to decline by one percentage point from their December 31, 2023 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's net income are mitigated in large part by Idaho Power's Idaho and Oregon power cost adjustment mechanisms. However, collection from customers or return to customers of most of the difference between actual power supply costs compared with those included in retail rates is deferred to a subsequent period, which can affect Idaho Power’s operating cash flow and liquidity until those costs are recovered from or returned to customers.
A number of factors associated with the structure and operation of the energy markets influence the level and volatility of prices for energy commodities and related derivative products. The weather is a major uncontrollable factor affecting the local and regional demand for electricity and the availability and cost of power generation. Other factors include the occurrence and timing of demand peaks due to seasonal, daily, and hourly power demand; power supply; power transmission capacity; changes in federal and state regulation and compliance obligations; fuel supplies; and market liquidity.
The primary objectives of Idaho Power’s energy purchase and sale activity are to meet the demand of retail electric customers, to maintain appropriate physical reserves to ensure reliability, and to make economic use of temporary surpluses that may develop. Idaho Power has adopted an energy risk management program, overseen by the risk management committee (RMC), and described in Idaho Power’s Energy Risk Management Policy and associated standards (ERMP). The ERMP has been reviewed and accepted by the IPUC, designed to reduce exposure to power supply cost-related uncertainty, further mitigating commodity price risk. The 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. In its energy risk management process, Idaho Power considers both demand-side and supply-side options consistent with its IRP. The primary tools for risk mitigation are physical and financial forward power transactions and fueling alternatives
72
for utility-owned generation resources. Idaho Power only engages in a nominal amount of trading activity for non-retail purposes.
The ERMP 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 ERMP 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 ERMP.
Credit Risk
IDACORP is subject to credit risk based on Idaho Power's activity with market counterparties. Idaho Power is exposed to this risk to the extent that a counterparty may fail to fulfill a contractual obligation to provide energy, purchase energy, or complete financial settlement for market activities. Idaho Power mitigates this exposure by actively establishing credit limits; measuring, monitoring, and reporting credit risk using appropriate contractual arrangements; and transferring of credit risk through the use of financial guarantees, cash, or letters of credit. Idaho Power maintains a current list of acceptable counterparties and credit limits.
The use of performance assurance collateral in the form of cash, letters of credit, or guarantees is common industry practice. Idaho Power maintains margin agreements relating to its wholesale commodity contracts that allow performance assurance collateral to be requested of and/or posted with certain counterparties. As of December 31, 2023, Idaho Power posted $53 million of performance assurance collateral related to these contracts. Should Idaho Power experience a reduction in its credit rating on Idaho Power’s unsecured debt to below investment grade, Idaho Power could be subject to requests by its wholesale counterparties to post additional performance assurance collateral. Counterparties to derivative instruments and other forward contracts could request immediate payment or demand immediate ongoing full daily collateralization on derivative instruments and contracts in net liability positions. Based upon Idaho Power’s energy and fuel portfolio and then existing market conditions as of December 31, 2023, the amount of additional collateral that could have been requested upon a downgrade to below investment grade was approximately $23 million. To minimize capital requirements, Idaho Power actively monitors the portfolio exposure and the potential exposure to additional requests for performance assurance collateral calls through sensitivity analysis.
Idaho Power is obligated to provide service to all electric customers within its service area. Credit risk for Idaho Power’s retail customers is managed by credit and collection policies that are governed by rules issued by the IPUC or OPUC. Idaho Power records a provision for uncollectible accounts, based upon historical experience, to provide for the potential loss from nonpayment by these customers. Idaho Power continuously monitors levels of nonpayment from customers and makes any necessary adjustments to its provision for uncollectible accounts accordingly.
Idaho utility customer relations rules prohibit Idaho Power from terminating electric service during the months of December through February to any residential customer who declares that he or she is unable to pay in full for utility service and whose household includes children, elderly, or infirm persons. Idaho Power’s provision for uncollectible accounts could be affected by changes in future prices as well as changes in IPUC or OPUC regulations.
Equity Price Risk
IDACORP is exposed to price fluctuations in equity markets, primarily through Idaho Power's defined benefit pension plan assets, a mine reclamation trust fund owned by an equity-method investment of Idaho Power, and other equity security investments at Idaho Power. The equity securities held by the pension plan and in such accounts are diversified to achieve broad market participation and reduce the impact of any single investment, sector, or geographic region. Idaho Power has established asset allocation targets for the pension plan holdings, which are described in Note 11 - "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, | ||||||||||||||||||||
| 2023 | 2022 | 2021 | ||||||||||||||||||
| (thousands of dollars except for per share amounts) | ||||||||||||||||||||
| Operating Revenues: | ||||||||||||||||||||
| Electric utility revenues | $ | 1,762,894 | $ | 1,641,040 | $ | 1,455,410 | ||||||||||||||
| Other | 3,462 | 2,941 | 2,674 | |||||||||||||||||
| Total operating revenues | 1,766,356 | 1,643,981 | 1,458,084 | |||||||||||||||||
| Operating Expenses: | ||||||||||||||||||||
| Electric utility: | ||||||||||||||||||||
| Purchased power | 501,531 | 544,345 | 393,691 | |||||||||||||||||
| Fuel expense | 275,405 | 230,210 | 180,550 | |||||||||||||||||
| Power cost adjustment | 6,885 | (100,659) | (49,844) | |||||||||||||||||
| Other operations and maintenance | 399,855 | 399,375 | 361,297 | |||||||||||||||||
| Energy efficiency programs | 31,948 | 33,197 | 29,920 | |||||||||||||||||
| Depreciation | 195,341 | 170,077 | 175,555 | |||||||||||||||||
| Other electric utility operating expenses | 38,550 | 37,325 | 34,673 | |||||||||||||||||
| Total electric utility expenses | 1,449,515 | 1,313,870 | 1,125,842 | |||||||||||||||||
| Other | 3,364 | 2,933 | 2,591 | |||||||||||||||||
| Total operating expenses | 1,452,879 | 1,316,803 | 1,128,433 | |||||||||||||||||
| Operating Income | 313,477 | 327,178 | 329,651 | |||||||||||||||||
| Nonoperating (Income) Expense: | ||||||||||||||||||||
| Allowance for equity funds used during construction | (43,221) | (37,285) | (31,537) | |||||||||||||||||
| Earnings of unconsolidated equity-method investments | (12,426) | (11,511) | (11,435) | |||||||||||||||||
| Interest on long-term debt | 116,216 | 87,259 | 84,145 | |||||||||||||||||
| Other interest | 20,253 | 16,030 | 14,546 | |||||||||||||||||
| Allowance for borrowed funds used during construction | (20,012) | (13,914) | (11,993) | |||||||||||||||||
| Other (income) expense, net | (36,522) | (10,805) | 3,141 | |||||||||||||||||
| Total nonoperating expense, net | 24,288 | 29,774 | 46,867 | |||||||||||||||||
| Income Before Income Taxes | 289,189 | 297,404 | 282,784 | |||||||||||||||||
| Income Tax Expense | 27,296 | 37,844 | 36,912 | |||||||||||||||||
| Net Income | 261,893 | 259,560 | 245,872 | |||||||||||||||||
| Adjustment for income attributable to noncontrolling interests | (698) | (578) | (322) | |||||||||||||||||
| Net Income Attributable to IDACORP, Inc. | $ | 261,195 | $ | 258,982 | $ | 245,550 | ||||||||||||||
| Weighted Average Common Shares Outstanding - Basic (000’s) | 50,717 | 50,658 | 50,599 | |||||||||||||||||
| Weighted Average Common Shares Outstanding - Diluted (000’s) | 50,806 | 50,699 | 50,645 | |||||||||||||||||
| Earnings Per Share of Common Stock: | ||||||||||||||||||||
| Earnings Attributable to IDACORP, Inc. - Basic | $ | 5.15 | $ | 5.11 | $ | 4.85 | ||||||||||||||
| Earnings Attributable to IDACORP, Inc. - Diluted | $ | 5.14 | $ | 5.11 | $ | 4.85 | ||||||||||||||
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, | ||||||||||||||||||||
| 2023 | 2022 | 2021 | ||||||||||||||||||
| (thousands of dollars) | ||||||||||||||||||||
| Net Income | $ | 261,893 | $ | 259,560 | $ | 245,872 | ||||||||||||||
| Other Comprehensive Income: | ||||||||||||||||||||
Unfunded pension liability adjustment, net of tax of $(1,477), $9,399, and $1,150 | (4,262) | 27,118 | 3,318 | |||||||||||||||||
| Total Comprehensive Income | 257,631 | 286,678 | 249,190 | |||||||||||||||||
| Comprehensive income attributable to noncontrolling interests | (698) | (578) | (322) | |||||||||||||||||
| Comprehensive Income Attributable to IDACORP, Inc. | $ | 256,933 | $ | 286,100 | $ | 248,868 | ||||||||||||||
The accompanying notes are an integral part of these statements.
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IDACORP, Inc.
Consolidated Balance Sheets
| December 31, | ||||||||||||||
| 2023 | 2022 | |||||||||||||
| (in thousands) | ||||||||||||||
| Assets | ||||||||||||||
| Current Assets: | ||||||||||||||
| Cash and cash equivalents | $ | 327,429 | $ | 177,577 | ||||||||||
| Receivables: | ||||||||||||||
Customer (net of allowance of $4,869 and $5,034, respectively) | 107,256 | 114,173 | ||||||||||||
Other (net of allowance of $716 and $512, respectively) | 44,661 | 51,179 | ||||||||||||
| Income taxes receivable | 24,574 | 13,734 | ||||||||||||
| Accrued unbilled revenues | 90,521 | 84,862 | ||||||||||||
| Materials and supplies (at average cost) | 140,515 | 92,461 | ||||||||||||
| Fuel stock (at average cost) | 19,952 | 14,762 | ||||||||||||
| Prepayments | 22,840 | 24,517 | ||||||||||||
| Current regulatory assets | 226,235 | 80,049 | ||||||||||||
| Other | 71 | 40,339 | ||||||||||||
| Total current assets | 1,004,054 | 693,653 | ||||||||||||
| Investments | 163,971 | 121,352 | ||||||||||||
| Property, Plant, and Equipment: | ||||||||||||||
| Utility plant in service | 7,291,532 | 6,828,467 | ||||||||||||
| Accumulated provision for depreciation | (2,557,744) | (2,465,279) | ||||||||||||
| Utility plant in service - net | 4,733,788 | 4,363,188 | ||||||||||||
| Construction work in progress | 985,502 | 785,706 | ||||||||||||
| Utility plant held for future use | 9,511 | 7,130 | ||||||||||||
| Other property, net of accumulated depreciation | 16,429 | 16,946 | ||||||||||||
| Property, plant, and equipment - net | 5,745,230 | 5,172,970 | ||||||||||||
| Other Assets: | ||||||||||||||
| Company-owned life insurance | 82,038 | 73,944 | ||||||||||||
| Regulatory assets | 1,426,815 | 1,421,912 | ||||||||||||
| Other | 53,810 | 59,427 | ||||||||||||
| Total other assets | 1,562,663 | 1,555,283 | ||||||||||||
| Total | $ | 8,475,918 | $ | 7,543,258 | ||||||||||
The accompanying notes are an integral part of these statements.
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IDACORP, Inc.
Consolidated Balance Sheets
| December 31, | ||||||||||||||
| 2023 | 2022 | |||||||||||||
| (in thousands) | ||||||||||||||
| Liabilities and Equity | ||||||||||||||
| Current Liabilities: | ||||||||||||||
| Current maturities of long-term debt | $ | 49,800 | $ | — | ||||||||||
| Accounts payable | 308,504 | 292,719 | ||||||||||||
| Taxes accrued | 6,854 | 8,565 | ||||||||||||
| Interest accrued | 38,292 | 24,060 | ||||||||||||
| Accrued compensation | 64,645 | 59,265 | ||||||||||||
| Current regulatory liabilities | 7,952 | 63,957 | ||||||||||||
| Advances from customers | 104,297 | 72,222 | ||||||||||||
| Other | 53,732 | 27,777 | ||||||||||||
| Total current liabilities | 634,076 | 548,565 | ||||||||||||
| Other Liabilities: | ||||||||||||||
| Deferred income taxes | 882,724 | 873,916 | ||||||||||||
| Regulatory liabilities | 874,601 | 796,644 | ||||||||||||
| Pension and other postretirement benefits | 233,965 | 238,037 | ||||||||||||
| Other | 160,019 | 77,336 | ||||||||||||
| Total other liabilities | 2,151,309 | 1,985,933 | ||||||||||||
| Long-Term Debt | 2,775,790 | 2,194,145 | ||||||||||||
| Commitments and Contingencies | ||||||||||||||
| Equity: | ||||||||||||||
| IDACORP, Inc. shareholders’ equity: | ||||||||||||||
Common stock, no par value (120,000 shares authorized; 50,615 and 50,562 shares issued, respectively) | 888,615 | 882,189 | ||||||||||||
| Retained earnings | 2,036,138 | 1,937,972 | ||||||||||||
| Accumulated other comprehensive loss | (17,184) | (12,922) | ||||||||||||
| Total IDACORP, Inc. shareholders’ equity | 2,907,569 | 2,807,239 | ||||||||||||
| Noncontrolling interests | 7,174 | 7,376 | ||||||||||||
| Total equity | 2,914,743 | 2,814,615 | ||||||||||||
| Total | $ | 8,475,918 | $ | 7,543,258 | ||||||||||
| 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, | ||||||||||||||||||||
| 2023 | 2022 | 2021 | ||||||||||||||||||
| (thousands of dollars) | ||||||||||||||||||||
| Operating Activities: | ||||||||||||||||||||
| Net income | $ | 261,893 | $ | 259,560 | $ | 245,872 | ||||||||||||||
| Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||||||||||||||
| Depreciation and amortization | 199,908 | 173,555 | 179,444 | |||||||||||||||||
| Deferred income taxes and investment tax credits | 39,613 | (511) | 23,901 | |||||||||||||||||
| Changes in regulatory assets and liabilities | (4,748) | (79,693) | (33,705) | |||||||||||||||||
| Pension and postretirement benefit plan expense | 27,155 | 29,286 | 33,817 | |||||||||||||||||
| Contributions to pension and postretirement benefit plans | (55,337) | (44,192) | (44,220) | |||||||||||||||||
| Earnings of equity-method investments | (12,426) | (11,511) | (11,435) | |||||||||||||||||
| Distributions from equity-method investments | 2,950 | 11,586 | 11,711 | |||||||||||||||||
| Allowance for equity funds used during construction | (43,221) | (37,285) | (31,537) | |||||||||||||||||
| Other non-cash adjustments to net income, net | 8,414 | 14,892 | 8,929 | |||||||||||||||||
| Change in: | ||||||||||||||||||||
| Accounts receivable and unbilled revenues | (17,628) | (81,545) | (9,434) | |||||||||||||||||
| Prepayments | (3,220) | (2,156) | (6,581) | |||||||||||||||||
| Materials, supplies, and fuel stock | (53,243) | (11,626) | 991 | |||||||||||||||||
| Accounts and wages payable | (81,244) | 112,602 | 17,700 | |||||||||||||||||
| Taxes accrued/receivable | (12,551) | (4,628) | (17,885) | |||||||||||||||||
| Other assets and liabilities | 10,712 | 22,951 | (4,304) | |||||||||||||||||
| Net cash provided by operating activities | 267,027 | 351,285 | 363,264 | |||||||||||||||||
| Investing Activities: | ||||||||||||||||||||
| Additions to property, plant and equipment | (611,137) | (432,589) | (299,999) | |||||||||||||||||
| Payments received from transmission project joint funding partners | 26,501 | 17,778 | 5,876 | |||||||||||||||||
| Investments in affordable housing and other real estate tax credit projects | (2,533) | (9,881) | (15,148) | |||||||||||||||||
| Distributions from equity-method investments, return of investment | — | 8,489 | 14,439 | |||||||||||||||||
| Purchase of equity securities | (12,235) | (45,572) | (17,186) | |||||||||||||||||
| Purchases of held-to-maturity securities | (1,617) | (31,224) | — | |||||||||||||||||
| Proceeds from sale of equity securities | 8,921 | 63,857 | 11,328 | |||||||||||||||||
| Purchases of short-term investments | — | (25,000) | (25,000) | |||||||||||||||||
| Maturities of short-term investments | — | 25,000 | 50,000 | |||||||||||||||||
| Other | 2,153 | 4,875 | 2,037 | |||||||||||||||||
| Net cash used in investing activities | (589,947) | (424,267) | (273,653) | |||||||||||||||||
| Financing Activities: | ||||||||||||||||||||
| Issuance of long-term debt | 872,000 | 198,000 | — | |||||||||||||||||
| Discount on issuance of long-term debt | (7,006) | — | — | |||||||||||||||||
| Retirement of long-term debt | (225,000) | (4,360) | — | |||||||||||||||||
| Dividends on common stock | (163,545) | (154,287) | (146,119) | |||||||||||||||||
| Tax withholdings on net settlements of share-based awards | (3,274) | (3,111) | (3,031) | |||||||||||||||||
| Debt issuance costs and other | (403) | (926) | (334) | |||||||||||||||||
| Net cash provided by (used in) financing activities | 472,772 | 35,316 | (149,484) | |||||||||||||||||
| Net increase (decrease) in cash and cash equivalents | 149,852 | (37,666) | (59,873) | |||||||||||||||||
| Cash and cash equivalents at beginning of the year | 177,577 | 215,243 | 275,116 | |||||||||||||||||
| Cash and cash equivalents at end of the year | $ | 327,429 | $ | 177,577 | $ | 215,243 | ||||||||||||||
| Supplemental Disclosure of Cash Flow Information: | ||||||||||||||||||||
| Cash paid during the year for: | ||||||||||||||||||||
| Income taxes | $ | 6,200 | $ | 45,885 | $ | 34,330 | ||||||||||||||
| Interest (net of amount capitalized) | $ | 97,742 | $ | 85,985 | $ | 83,499 | ||||||||||||||
| Non-cash investing activities: | ||||||||||||||||||||
| Additions to property, plant and equipment in accounts payable | $ | 185,400 | $ | 84,324 | $ | 53,690 | ||||||||||||||
The accompanying notes are an integral part of these statements.
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IDACORP, Inc.
Consolidated Statements of Equity
| Year Ended December 31, | ||||||||||||||||||||
| 2023 | 2022 | 2021 | ||||||||||||||||||
| (thousands of dollars) | ||||||||||||||||||||
| Common Stock: | ||||||||||||||||||||
| Balance at beginning of year | $ | 882,189 | $ | 874,896 | $ | 869,235 | ||||||||||||||
| Share-based compensation expense | 9,578 | 10,279 | 8,583 | |||||||||||||||||
| Tax withholdings on net settlements of share-based awards | (3,274) | (3,111) | (3,031) | |||||||||||||||||
| Other | 122 | 125 | 109 | |||||||||||||||||
| Balance at end of year | 888,615 | 882,189 | 874,896 | |||||||||||||||||
| Retained Earnings: | ||||||||||||||||||||
| Balance at beginning of year | 1,937,972 | 1,833,580 | 1,734,103 | |||||||||||||||||
| Net income attributable to IDACORP, Inc. | 261,195 | 258,982 | 245,550 | |||||||||||||||||
Common stock dividends ($3.20, $3.04, and $2.88 per share, respectively) | (163,029) | (154,590) | (146,073) | |||||||||||||||||
| Balance at end of year | 2,036,138 | 1,937,972 | 1,833,580 | |||||||||||||||||
| Accumulated Other Comprehensive (Loss) Income: | ||||||||||||||||||||
| Balance at beginning of year | (12,922) | (40,040) | (43,358) | |||||||||||||||||
| Unfunded pension liability adjustment (net of tax) | (4,262) | 27,118 | 3,318 | |||||||||||||||||
| Balance at end of year | (17,184) | (12,922) | (40,040) | |||||||||||||||||
| Total IDACORP, Inc. shareholders’ equity at end of year | 2,907,569 | 2,807,239 | 2,668,436 | |||||||||||||||||
| Noncontrolling Interests: | ||||||||||||||||||||
| Balance at beginning of year | 7,376 | 6,798 | 6,476 | |||||||||||||||||
| Net income attributable to noncontrolling interests | 698 | 578 | 322 | |||||||||||||||||
| Distributions to noncontrolling interests | (900) | — | — | |||||||||||||||||
| Balance at end of year | 7,174 | 7,376 | 6,798 | |||||||||||||||||
| Total equity at end of year | $ | 2,914,743 | $ | 2,814,615 | $ | 2,675,234 | ||||||||||||||
The accompanying notes are an integral part of these statements.
80
Idaho Power Company
Consolidated Statements of Income
| Year Ended December 31, | ||||||||||||||||||||
| 2023 | 2022 | 2021 | ||||||||||||||||||
| (thousands of dollars) | ||||||||||||||||||||
| Operating Revenues | $ | 1,762,894 | $ | 1,641,040 | $ | 1,455,410 | ||||||||||||||
| Operating Expenses: | ||||||||||||||||||||
| Operation: | ||||||||||||||||||||
| Purchased power | 501,531 | 544,345 | 393,691 | |||||||||||||||||
| Fuel expense | 275,405 | 230,210 | 180,550 | |||||||||||||||||
| Power cost adjustment | 6,885 | (100,659) | (49,844) | |||||||||||||||||
| Other operations and maintenance | 399,855 | 399,375 | 361,297 | |||||||||||||||||
| Energy efficiency programs | 31,948 | 33,197 | 29,920 | |||||||||||||||||
| Depreciation | 195,341 | 170,077 | 175,555 | |||||||||||||||||
| Other operating expenses | 38,550 | 37,325 | 34,673 | |||||||||||||||||
| Total operating expenses | 1,449,515 | 1,313,870 | 1,125,842 | |||||||||||||||||
| Operating Income | 313,379 | 327,170 | 329,568 | |||||||||||||||||
| Nonoperating (Income) Expense: | ||||||||||||||||||||
| Allowance for equity funds used during construction | (43,221) | (37,285) | (31,537) | |||||||||||||||||
| Earnings of unconsolidated equity-method investments | (10,540) | (10,211) | (10,211) | |||||||||||||||||
| Interest on long-term debt | 116,216 | 87,259 | 84,145 | |||||||||||||||||
| Other interest | 19,913 | 15,693 | 14,511 | |||||||||||||||||
| Allowance for borrowed funds used during construction | (20,012) | (13,914) | (11,993) | |||||||||||||||||
| Other (income) expense, net | (34,713) | (9,147) | 3,171 | |||||||||||||||||
| Total nonoperating expense, net | 27,643 | 32,395 | 48,086 | |||||||||||||||||
| Income Before Income Taxes | 285,736 | 294,775 | 281,482 | |||||||||||||||||
| Income Tax Expense | 28,926 | 39,908 | 38,257 | |||||||||||||||||
| Net Income | $ | 256,810 | $ | 254,867 | $ | 243,225 | ||||||||||||||
The accompanying notes are an integral part of these statements.
81
Idaho Power Company
Consolidated Statements of Comprehensive Income
| Year Ended December 31, | ||||||||||||||||||||
| 2023 | 2022 | 2021 | ||||||||||||||||||
| (thousands of dollars) | ||||||||||||||||||||
| Net Income | $ | 256,810 | $ | 254,867 | $ | 243,225 | ||||||||||||||
| Other Comprehensive Income: | ||||||||||||||||||||
Unfunded pension liability adjustment, net of tax of $(1,477), $9,399, and $1,150 | (4,262) | 27,118 | 3,318 | |||||||||||||||||
| Total Comprehensive Income | $ | 252,548 | $ | 281,985 | $ | 246,543 | ||||||||||||||
The accompanying notes are an integral part of these statements.
82
Idaho Power Company
Consolidated Balance Sheets
| December 31, | ||||||||||||||
| 2023 | 2022 | |||||||||||||
| (in thousands) | ||||||||||||||
| Assets | ||||||||||||||
| Current Assets: | ||||||||||||||
| Cash and cash equivalents | $ | 271,791 | $ | 108,933 | ||||||||||
| Receivables: | ||||||||||||||
Customer (net of allowance of $4,869 and $5,034, respectively) | 107,256 | 114,173 | ||||||||||||
Other (net of allowance of $716 and $512, respectively) | 44,335 | 50,754 | ||||||||||||
| Income taxes receivable | 22,926 | 13,108 | ||||||||||||
| Accrued unbilled revenues | 90,521 | 84,862 | ||||||||||||
| Materials and supplies (at average cost) | 140,515 | 92,461 | ||||||||||||
| Fuel stock (at average cost) | 19,952 | 14,762 | ||||||||||||
| Prepayments | 22,710 | 24,396 | ||||||||||||
| Current regulatory assets | 226,235 | 80,049 | ||||||||||||
| Other | 71 | 40,339 | ||||||||||||
| Total current assets | 946,312 | 623,837 | ||||||||||||
| Investments | 93,037 | 78,791 | ||||||||||||
| Property, Plant, and Equipment: | ||||||||||||||
| Plant in service | 7,291,532 | 6,828,467 | ||||||||||||
| Accumulated provision for depreciation | (2,557,744) | (2,465,279) | ||||||||||||
| Plant in service - net | 4,733,788 | 4,363,188 | ||||||||||||
| Construction work in progress | 985,502 | 785,706 | ||||||||||||
| Plant held for future use | 9,511 | 7,130 | ||||||||||||
| Other property | 4,310 | 4,558 | ||||||||||||
| Property, plant, and equipment, net | 5,733,111 | 5,160,582 | ||||||||||||
| Other Assets: | ||||||||||||||
| Company-owned life insurance | 82,038 | 73,944 | ||||||||||||
| Regulatory assets | 1,426,815 | 1,421,912 | ||||||||||||
| Other | 42,218 | 52,038 | ||||||||||||
| Total other assets | 1,551,071 | 1,547,894 | ||||||||||||
| Total | $ | 8,323,531 | $ | 7,411,104 | ||||||||||
The accompanying notes are an integral part of these statements.
83
Idaho Power Company
Consolidated Balance Sheets
| December 31, | ||||||||||||||
| 2023 | 2022 | |||||||||||||
| (in thousands) | ||||||||||||||
| Liabilities and Equity | ||||||||||||||
| Current Liabilities: | ||||||||||||||
| Current maturities of long-term debt | $ | 49,800 | $ | — | ||||||||||
| Accounts payable | 307,538 | 292,616 | ||||||||||||
| Accounts payable to affiliates | 16,456 | 56,338 | ||||||||||||
| Taxes accrued | 6,834 | 9,101 | ||||||||||||
| Interest accrued | 38,292 | 24,060 | ||||||||||||
| Accrued compensation | 64,408 | 58,959 | ||||||||||||
| Current regulatory liabilities | 7,952 | 63,957 | ||||||||||||
| Advances from customers | 104,297 | 72,222 | ||||||||||||
| Other | 44,907 | 26,199 | ||||||||||||
| Total current liabilities | 640,484 | 603,452 | ||||||||||||
| Other Liabilities: | ||||||||||||||
| Deferred income taxes | 881,050 | 870,692 | ||||||||||||
| Regulatory liabilities | 874,601 | 796,644 | ||||||||||||
| Pension and other postretirement benefits | 233,965 | 238,037 | ||||||||||||
| Other | 135,468 | 76,471 | ||||||||||||
| Total other liabilities | 2,125,084 | 1,981,844 | ||||||||||||
| Long-Term Debt | 2,775,790 | 2,194,145 | ||||||||||||
| 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 | 1,991,319 | 1,836,547 | ||||||||||||
| Accumulated other comprehensive loss | (17,184) | (12,922) | ||||||||||||
| Total equity | 2,782,173 | 2,631,663 | ||||||||||||
| Total | $ | 8,323,531 | $ | 7,411,104 | ||||||||||
| The accompanying notes are an integral part of these statements. | ||||||||||||||
84
Idaho Power Company
Consolidated Statements of Cash Flows
| Year Ended December 31, | ||||||||||||||||||||
| 2023 | 2022 | 2021 | ||||||||||||||||||
| (thousands of dollars) | ||||||||||||||||||||
| Operating Activities: | ||||||||||||||||||||
| Net income | $ | 256,810 | $ | 254,867 | $ | 243,225 | ||||||||||||||
| Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||||||||||||||
| Depreciation and amortization | 199,307 | 172,976 | 178,847 | |||||||||||||||||
| Deferred income taxes and investment tax credits | 35,080 | (11,744) | (7,682) | |||||||||||||||||
| Changes in regulatory assets and liabilities | (4,748) | (79,693) | (33,705) | |||||||||||||||||
| Pension and postretirement benefit plan expense | 27,138 | 29,269 | 33,804 | |||||||||||||||||
| Contributions to pension and postretirement benefit plans | (55,319) | (44,175) | (44,207) | |||||||||||||||||
| Earnings of equity-method investments | (10,540) | (10,211) | (10,211) | |||||||||||||||||
| Distributions from equity-method investments | 650 | 10,211 | 10,211 | |||||||||||||||||
| Allowance for equity funds used during construction | (43,221) | (37,285) | (31,537) | |||||||||||||||||
| Other non-cash adjustments to net income, net | (1,143) | 4,493 | 346 | |||||||||||||||||
| Change in: | ||||||||||||||||||||
| Accounts receivable and unbilled revenues | (17,882) | (81,163) | (8,345) | |||||||||||||||||
| Prepayments | (3,212) | (2,153) | (6,589) | |||||||||||||||||
| Materials, supplies, and fuel stock | (53,243) | (11,626) | 991 | |||||||||||||||||
| Accounts and wages payable | (121,609) | 166,635 | 17,690 | |||||||||||||||||
| Taxes accrued/receivable | (12,085) | (2,995) | (15,899) | |||||||||||||||||
| Other assets and liabilities | 10,776 | 22,876 | (4,233) | |||||||||||||||||
| Net cash provided by operating activities | 206,759 | 380,282 | 322,706 | |||||||||||||||||
| Investing Activities: | ||||||||||||||||||||
| Additions to utility plant | (610,913) | (432,430) | (299,972) | |||||||||||||||||
| Payments received from transmission project joint funding partners | 26,501 | 17,778 | 5,876 | |||||||||||||||||
| Distributions from equity-method investments, return of investment | — | 8,489 | 14,439 | |||||||||||||||||
| Purchase of equity securities | (11,233) | (43,953) | (15,823) | |||||||||||||||||
| Purchases of held-to-maturity securities | (1,617) | (31,224) | — | |||||||||||||||||
| Proceeds from the sale of equity securities | 8,921 | 63,857 | 11,328 | |||||||||||||||||
| Other | 6,198 | 7,605 | 2,231 | |||||||||||||||||
| Net cash used in investing activities | (582,143) | (409,878) | (281,921) | |||||||||||||||||
| Financing Activities: | ||||||||||||||||||||
| Issuance of long-term debt | 872,000 | 198,000 | — | |||||||||||||||||
| Discount on issuance of long-term debt | (7,006) | — | — | |||||||||||||||||
| Retirement of long-term debt | (225,000) | (4,360) | — | |||||||||||||||||
| Dividends on common stock | (101,790) | (114,447) | (146,076) | |||||||||||||||||
| Other | 38 | (739) | (238) | |||||||||||||||||
| Net cash provided by (used in) financing activities | 538,242 | 78,454 | (146,314) | |||||||||||||||||
| Net increase (decrease) in cash and cash equivalents | 162,858 | 48,858 | (105,529) | |||||||||||||||||
| Cash and cash equivalents at beginning of the year | 108,933 | 60,075 | 165,604 | |||||||||||||||||
| Cash and cash equivalents at end of the year | $ | 271,791 | $ | 108,933 | $ | 60,075 | ||||||||||||||
| Supplemental Disclosure of Cash Flow Information: | ||||||||||||||||||||
| Cash paid to IDACORP related to income taxes | $ | 51,815 | $ | 2,532 | $ | 64,003 | ||||||||||||||
| Cash paid for interest (net of amount capitalized) | $ | 97,402 | $ | 85,648 | $ | 83,464 | ||||||||||||||
| Non-cash investing activities: | ||||||||||||||||||||
| Additions to property, plant and equipment in accounts payable | $ | 185,400 | $ | 84,324 | $ | 53,690 | ||||||||||||||
The accompanying notes are an integral part of these statements.
85
Idaho Power Company
Consolidated Statements of Retained Earnings
| Year Ended December 31, | ||||||||||||||||||||
| 2023 | 2022 | 2021 | ||||||||||||||||||
| (thousands of dollars) | ||||||||||||||||||||
| Retained Earnings, Beginning of Year | $ | 1,836,547 | $ | 1,696,304 | $ | 1,599,155 | ||||||||||||||
| Net Income | 256,810 | 254,867 | 243,225 | |||||||||||||||||
| Dividends on Common Stock | (102,038) | (114,624) | (146,076) | |||||||||||||||||
| Retained Earnings, End of Year | $ | 1,991,319 | $ | 1,836,547 | $ | 1,696,304 | ||||||||||||||
The accompanying notes are an integral part of these statements.
86
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 and 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 FERC. Idaho Power is the parent of IERCo, a joint-owner of BCC, which mines and supplies coal to the Jim Bridger plant owned in part by Idaho Power.
IDACORP’s other notable wholly-owned subsidiaries include IFS, an investor in affordable housing and other real estate tax credit investments, and Ida-West, an operator of small hydropower generation projects that satisfy the requirements of the 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, 2023 and 2022, Marysville had approximately $14.9 million of primarily hydropower plant assets. EEC has borrowed amounts from Ida-West to fund a portion of its required capital contributions to Marysville. The loans are payable from EEC’s share of distributions from Marysville and are secured by the stock of EEC and EEC’s interest in Marysville. Ida-West is identified as the primary beneficiary because the combination of its ownership interest in the joint venture with the intercompany note and the EEC note result in Ida-West's ability to control the activities of the joint venture.
The BCC investment 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-owner, Idaho Power is not the primary beneficiary. The carrying value of Idaho Power's investment in BCC was $24.1 million at December 31, 2023, and Idaho Power's maximum exposure to loss is the carrying value, any additional future contributions to BCC, and a $47.6 million guarantee for mine reclamation costs. BCC has a reclamation trust fund set aside specifically for the purpose of paying the reclamation costs, the market value of which exceeded the total estimated reclamation obligation at December 31, 2023. The guarantee, reclamation obligation, and reclamation trust are discussed further in Note 9 - "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 4 to 100 percent and were acquired between 2003 and 2023. As a limited partner, IFS does not control these entities and they are not consolidated. IFS’s maximum exposure to loss in these developments is limited to its net carrying value, which was $57.3 million at December 31, 2023.
Ida-West's other investments in PURPA facilities, Idaho Power's investment in BCC, and IFS's investments are accounted for under the equity method of accounting (see Note 14 - "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.
87
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 12 - "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 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; O&M expense; depreciation expense; and income tax expense. The application of accounting principles related to regulated operations sometimes results in Idaho Power recording expenses and revenues in a different period than when an unregulated enterprise would record such expenses and revenues. In these instances, the amounts are deferred or accrued as regulatory assets or regulatory liabilities on the balance sheet. Regulatory assets represent incurred costs that have been deferred because it is probable they will be recovered from customers through future rates. Regulatory liabilities represent obligations to make refunds to customers for previous collections, or represent amounts collected in advance of incurring an expense. The effects of applying these regulatory accounting principles to Idaho Power’s operations are discussed in more detail in Note 3 - "Regulatory Matters."
Management Estimates
Management makes estimates and assumptions when preparing financial statements in conformity with GAAP. These estimates and assumptions include those related to rate regulation, retirement benefits, contingencies, asset impairment, income taxes, unbilled revenues, and bad debt. These estimates and assumptions affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. These estimates involve judgments with respect to, among other things, future economic factors that are difficult to predict and are beyond management’s control. Accordingly, actual results could differ from those estimates.
System of Accounts
The accounting records of Idaho Power conform to the Uniform System of Accounts prescribed by the FERC and adopted by the public utility commissions of Idaho, Oregon, and Wyoming.
Cash and Cash Equivalents
Cash and cash equivalents include cash on-hand and highly liquid temporary investments that mature within 90 days of the date of acquisition.
Receivables and Allowance for Uncollectible Accounts
Customer receivables are recorded at the invoiced amounts and do not bear interest. A late payment fee of 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.
88
The following table provides a rollforward of the allowance for uncollectible accounts related to customer receivables (in thousands of dollars):
| Year Ended December 31, | ||||||||||||||
| 2023 | 2022 | |||||||||||||
| Balance at beginning of period | $ | 5,034 | $ | 4,499 | ||||||||||
| Additions to the allowance | 3,617 | 3,265 | ||||||||||||
| Write-offs, net of recoveries | (3,782) | (2,730) | ||||||||||||
| Balance at end of period | $ | 4,869 | $ | 5,034 | ||||||||||
| Allowance for uncollectible accounts as a percentage of customer receivables | 4.3 | % | 4.2 | % | ||||||||||
Other receivables, primarily notes receivable from business transactions, are also reviewed for impairment periodically, based upon transaction-specific facts. When it is probable that IDACORP or Idaho Power will be unable to collect all amounts due according to the contractual terms of the agreement, an allowance is established for the estimated uncollectible portion of the receivable and charged to income.
There were no impaired receivables without related allowances at December 31, 2023 and 2022. Once a receivable is determined to be impaired, any further interest income recognized is fully reserved.
Derivative Financial Instruments
Financial instruments such as commodity futures, forwards, options, and swaps are used to manage exposure to commodity price risk in the electricity and natural gas markets. All derivative instruments are recognized as either assets or liabilities at fair value on the balance sheet unless they are designated as normal purchases and normal sales. With the exception of forward contracts for the purchase of natural gas for use at Idaho Power's natural gas generation facilities and a nominal number of power transactions, Idaho Power’s physical forward contracts are designated as normal purchases and normal sales. Because of Idaho Power’s regulatory accounting mechanisms, Idaho Power records the unrealized changes in fair value of derivative instruments related to power supply as regulatory assets or liabilities.
Revenues
Operating revenues are generally recorded when service is rendered or energy is delivered to customers. Idaho Power accrues estimated unbilled revenues for electric services delivered to customers but not yet billed at year-end. Idaho Power does not report any collections of franchise fees and similar taxes related to energy consumption on the income statement. In addition, regulatory mechanisms in place in Idaho and Oregon affect the reported amount of revenue. The effects of applying these regulatory mechanisms are discussed in more detail in Note 4 - "Revenues."
Property, Plant, and Equipment and Depreciation
The cost of utility plant in service represents the original cost of contracted services, direct labor and material, 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 2023, 2.7 percent in 2022, and 2.9 percent in 2021.
During the period of construction, costs expected to be included in the final value of the constructed asset, and depreciated once the asset is complete and placed in service, are classified as construction work in progress on the consolidated balance sheets. If the project becomes probable of being abandoned, these costs are expensed in the period such determination is made. Idaho Power may seek recovery of these costs in customer rates, although there can be no guarantee such recovery would be granted.
89
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 2023, 2022, or 2021.
Allowance for Funds Used During Construction
AFUDC represents the cost of financing construction projects with borrowed funds and equity funds. With one exception, for the 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 nonoperating expense, net. Idaho Power’s weighted-average monthly AFUDC rate was 7.4 percent for 2023 and 2022, and 7.5 percent for 2021.
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 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."
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.
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New and Recently Adopted Accounting Pronouncements
Recently Adopted Accounting Pronouncements
There have been no recently adopted accounting pronouncements that have had a material impact on IDACORP's or Idaho Power's consolidated financial statements.
Recent Accounting Pronouncements Not Yet Adopted
In November 2023, the Financial Standards Accounting Board (FASB) issued Accounting Standards Update (ASU) 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures which expands annual and interim disclosure requirements for reportable segments, primarily through enhanced disclosures about significant segment expenses. This ASU is effective for annual periods beginning after December 15, 2023, and for interim periods beginning after December 15, 2024, with early adoption permitted. The amendments in this ASU will be applied retrospectively. IDACORP and Idaho Power are currently evaluating the impact that adoption of this ASU will have on their notes to the consolidated financial statements.
In December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures which expands the disclosure requirements for income taxes, specifically related to the rate reconciliation and income taxes paid. This ASU is effective for annual periods beginning after December 15, 2024, with early adoption permitted. The amendments in this ASU will be applied prospectively and may be applied retrospectively. IDACORP and Idaho Power are currently evaluating the impact that adoption of this ASU will have on their notes to the consolidated financial statements.
There have been no other recent accounting pronouncements not yet adopted that are expected to have a material impact on IDACORP's or Idaho Power's consolidated financial statements.
2. INCOME TAXES
A reconciliation between the statutory federal income tax rate and the effective tax rate is as follows:
| IDACORP | Idaho Power | |||||||||||||||||||||||||||||||||||||
| 2023 | 2022 | 2021 | 2023 | 2022 | 2021 | |||||||||||||||||||||||||||||||||
| (thousands of dollars) | ||||||||||||||||||||||||||||||||||||||
| Federal income tax expense at statutory rate | $ | 60,583 | $ | 62,333 | $ | 59,317 | $ | 60,005 | $ | 61,903 | $ | 59,111 | ||||||||||||||||||||||||||
| Change in taxes resulting from: | ||||||||||||||||||||||||||||||||||||||
| AFUDC | (13,279) | (10,752) | (9,141) | (13,279) | (10,752) | (9,141) | ||||||||||||||||||||||||||||||||
| Capitalized interest | 3,097 | 1,633 | 1,077 | 3,097 | 1,633 | 1,077 | ||||||||||||||||||||||||||||||||
| Investment tax credits | (5,451) | (3,119) | (2,866) | (5,451) | (3,119) | (2,866) | ||||||||||||||||||||||||||||||||
| Removal costs | (6,312) | (4,900) | (3,302) | (6,312) | (4,900) | (3,302) | ||||||||||||||||||||||||||||||||
| Capitalized overhead costs | (2,100) | (3,150) | (8,190) | (2,100) | (3,150) | (8,190) | ||||||||||||||||||||||||||||||||
| Capitalized repair costs | (24,360) | (19,320) | (17,430) | (24,360) | (19,320) | (17,430) | ||||||||||||||||||||||||||||||||
| State income taxes, net of federal benefit | 15,802 | 18,139 | 11,359 | 16,081 | 18,352 | 11,633 | ||||||||||||||||||||||||||||||||
| Depreciation | 18,041 | 11,897 | 14,233 | 18,041 | 11,897 | 14,233 | ||||||||||||||||||||||||||||||||
| Excess deferred income tax reversal | (10,684) | (11,405) | (8,958) | (10,684) | (11,405) | (8,958) | ||||||||||||||||||||||||||||||||
| Income tax return adjustments | (8,229) | (2,692) | 3,169 | (7,732) | (2,827) | 1,759 | ||||||||||||||||||||||||||||||||
| Real Estate-related tax credits | (6,869) | (6,362) | (6,245) | — | — | — | ||||||||||||||||||||||||||||||||
| Real Estate-related investment distributions | (507) | (812) | (1,010) | — | — | — | ||||||||||||||||||||||||||||||||
| Real Estate-related investment amortization | 5,570 | 4,355 | 4,095 | — | — | — | ||||||||||||||||||||||||||||||||
| Other, net | 1,994 | 1,999 | 804 | 1,620 | 1,596 | 331 | ||||||||||||||||||||||||||||||||
| Total income tax expense | $ | 27,296 | $ | 37,844 | $ | 36,912 | $ | 28,926 | $ | 39,908 | $ | 38,257 | ||||||||||||||||||||||||||
| Effective tax rate | 9.5% | 12.7% | 13.1% | 10.1% | 13.5% | 13.6% | ||||||||||||||||||||||||||||||||
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The items comprising income tax expense are as follows:
| IDACORP | Idaho Power | |||||||||||||||||||||||||||||||||||||
| 2023 | 2022 | 2021 | 2023 | 2022 | 2021 | |||||||||||||||||||||||||||||||||
| (thousands of dollars) | ||||||||||||||||||||||||||||||||||||||
| Income taxes current: | ||||||||||||||||||||||||||||||||||||||
| Federal | $ | (13,253) | $ | 31,668 | $ | 15,210 | $ | (4,757) | $ | 37,696 | $ | 40,525 | ||||||||||||||||||||||||||
| State | 5,634 | 5,474 | 6,630 | 3,627 | 11,715 | 12,932 | ||||||||||||||||||||||||||||||||
| Total | (7,619) | 37,142 | 21,840 | (1,130) | 49,411 | 53,457 | ||||||||||||||||||||||||||||||||
| Income taxes deferred: | ||||||||||||||||||||||||||||||||||||||
| Federal | (18,419) | (13,696) | (1,787) | (19,086) | (13,127) | (21,737) | ||||||||||||||||||||||||||||||||
| State | (3,269) | 4,087 | 1,154 | (1,051) | (2,202) | (5,295) | ||||||||||||||||||||||||||||||||
| Total | (21,688) | (9,609) | (633) | (20,137) | (15,329) | (27,032) | ||||||||||||||||||||||||||||||||
| Investment tax credits: | ||||||||||||||||||||||||||||||||||||||
| Deferred | 55,644 | 8,945 | 14,698 | 55,644 | 8,945 | 14,698 | ||||||||||||||||||||||||||||||||
| Restored | (5,451) | (3,119) | (2,866) | (5,451) | (3,119) | (2,866) | ||||||||||||||||||||||||||||||||
| Total | 50,193 | 5,826 | 11,832 | 50,193 | 5,826 | 11,832 | ||||||||||||||||||||||||||||||||
| Real estate-related investments at IFS | 6,410 | 4,485 | 3,873 | — | — | — | ||||||||||||||||||||||||||||||||
| Total income tax expense | $ | 27,296 | $ | 37,844 | $ | 36,912 | $ | 28,926 | $ | 39,908 | $ | 38,257 | ||||||||||||||||||||||||||
The components of the net deferred tax liability are as follows:
| IDACORP | Idaho Power | |||||||||||||||||||||||||
| 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||||||
| (thousands of dollars) | ||||||||||||||||||||||||||
| Deferred tax assets: | ||||||||||||||||||||||||||
| Regulatory liabilities | $ | 108,641 | $ | 94,946 | $ | 108,641 | $ | 94,946 | ||||||||||||||||||
| Deferred compensation | 24,288 | 24,495 | 24,288 | 24,495 | ||||||||||||||||||||||
| Deferred revenue | 58,860 | 53,418 | 58,860 | 53,418 | ||||||||||||||||||||||
| Tax credits | 52,010 | 44,727 | 49,734 | 44,727 | ||||||||||||||||||||||
| Partnership investments | 12,652 | 15,259 | 12,652 | 15,259 | ||||||||||||||||||||||
| Retirement benefits | 44,803 | 38,687 | 44,803 | 38,687 | ||||||||||||||||||||||
| Other | 26,537 | 19,657 | 26,416 | 19,526 | ||||||||||||||||||||||
| Total | 327,791 | 291,189 | 325,394 | 291,058 | ||||||||||||||||||||||
| Deferred tax liabilities: | ||||||||||||||||||||||||||
| Property, plant and equipment | 266,992 | 249,452 | 266,992 | 249,452 | ||||||||||||||||||||||
| Regulatory assets | 774,672 | 739,689 | 774,672 | 739,689 | ||||||||||||||||||||||
| Power cost adjustment | 29,742 | 33,116 | 29,742 | 33,116 | ||||||||||||||||||||||
| Partnership investments | 3,593 | 3,355 | — | — | ||||||||||||||||||||||
| Retirement benefits | 94,231 | 80,777 | 94,231 | 80,777 | ||||||||||||||||||||||
| Other | 41,285 | 58,716 | 40,807 | 58,716 | ||||||||||||||||||||||
| Total | 1,210,515 | 1,165,105 | 1,206,444 | 1,161,750 | ||||||||||||||||||||||
| Net deferred tax liabilities | $ | 882,724 | $ | 873,916 | $ | 881,050 | $ | 870,692 | ||||||||||||||||||
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, 2023, IDACORP had $52.0 million of Idaho investment tax credit carryforward, which expire from 2029 to 2037.
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Uncertain Tax Positions
IDACORP and Idaho Power believe that they have no material income tax uncertainties for 2023 and prior tax years. Both companies recognize interest accrued related to unrecognized tax benefits as interest expense and penalties as other expense.
IDACORP and Idaho Power are subject to examination by their major tax jurisdictions - United States federal and the State of Idaho. The open tax years for examination are 2020-2021 and 2023 for federal and 2022-2023 for Idaho. 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. In 2023, the IRS completed its examination of IDACORP’s 2022 tax year with no unresolved income tax issues.
3. REGULATORY MATTERS
IDACORP’s and Idaho Power’s financial statements reflect the effects of the different ratemaking principles followed by the jurisdictions regulating Idaho Power. Included below is a summary of Idaho Power's regulatory assets and liabilities, as well as a discussion of notable regulatory matters.
Regulatory Assets and Liabilities
The application of accounting principles related to regulated operations sometimes results in Idaho Power recording some expenses and revenues in a different period than when an unregulated enterprise would record those expenses and revenues. Regulatory assets represent incurred costs that have been deferred because it is probable they will be recovered from customers through future rates. Regulatory liabilities represent obligations to make refunds to customers for previous collections, or represent amounts collected in advance of incurring an expense.
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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, 2023 | ||||||||||||||||||||||||||||||||
| Remaining Amortization Period | Earning a Return(1) | Not Earning a Return | Total as of December 31, | |||||||||||||||||||||||||||||
| Description | 2023 | 2022 | ||||||||||||||||||||||||||||||
| Regulatory Assets: | ||||||||||||||||||||||||||||||||
Income taxes(2) | $ | — | $ | 774,672 | $ | 774,672 | $ | 739,689 | ||||||||||||||||||||||||
Unfunded postretirement benefits(3) | — | 87,318 | 87,318 | 70,254 | ||||||||||||||||||||||||||||
Pension expense deferrals(4) | 253,744 | 1,500 | 255,244 | 249,503 | ||||||||||||||||||||||||||||
Energy efficiency program costs(5) | — | — | — | 3,767 | ||||||||||||||||||||||||||||
Power supply costs(6) | 2024-2025 | 134,816 | (19,291) | 115,525 | 129,309 | |||||||||||||||||||||||||||
Fixed cost adjustment(6) | 2024-2025 | 36,037 | 15,248 | 51,285 | 41,901 | |||||||||||||||||||||||||||
North Valmy plant settlements(6) | 2024-2028 | 82,917 | — | 82,917 | 90,747 | |||||||||||||||||||||||||||
Jim Bridger plant settlement(6) | 2024-2030 | 108,376 | 15,256 | 123,632 | 80,531 | |||||||||||||||||||||||||||
Wildfire Mitigation Plan deferral(6) | — | 51,329 | 51,329 | 27,078 | ||||||||||||||||||||||||||||
Asset retirement obligations(7) | — | 35,270 | 35,270 | 28,780 | ||||||||||||||||||||||||||||
| Long-term service agreement | 2024-2043 | 12,679 | 8,276 | 20,955 | 22,114 | |||||||||||||||||||||||||||
| Other | 2024-2056 | 2,330 | 52,573 | 54,903 | 18,288 | |||||||||||||||||||||||||||
| Total | $ | 630,899 | $ | 1,022,151 | $ | 1,653,050 | $ | 1,501,961 | ||||||||||||||||||||||||
| Regulatory Liabilities: | ||||||||||||||||||||||||||||||||
Income taxes(8) | $ | — | $ | 108,641 | $ | 108,641 | $ | 94,946 | ||||||||||||||||||||||||
Depreciation-related excess deferred income taxes(9) | 147,950 | — | 147,950 | 158,634 | ||||||||||||||||||||||||||||
Removal costs(7) | — | 175,369 | 175,369 | 180,087 | ||||||||||||||||||||||||||||
| Investment tax credits | — | 165,479 | 165,479 | 115,285 | ||||||||||||||||||||||||||||
Deferred revenue-AFUDC(10) | 177,884 | 50,787 | 228,671 | 207,528 | ||||||||||||||||||||||||||||
Energy efficiency program costs(5) | 1,507 | — | 1,507 | 154 | ||||||||||||||||||||||||||||
Power supply costs(6) | 1,240 | — | 1,240 | — | ||||||||||||||||||||||||||||
| Mark-to-market liabilities | — | 88 | 88 | 59,544 | ||||||||||||||||||||||||||||
Tax reform accrual for future amortization(11) | — | 40,891 | 40,891 | 32,793 | ||||||||||||||||||||||||||||
| Other | 8,383 | 4,334 | 12,717 | 11,630 | ||||||||||||||||||||||||||||
| Total | $ | 336,964 | $ | 545,589 | $ | 882,553 | $ | 860,601 | ||||||||||||||||||||||||
(1) Earning a return includes either interest or a return on the investment as a component of rate base at the allowed rate of return. The interest rate on deferral accounts is published annually by the IPUC and OPUC. The applicable rates for 2023 were 2% and 4.5%, respectively.
(2) Represents flow-through income tax accounting differences which have a corresponding deferred tax liability disclosed in Note 2 - "Income Taxes."
(3) Represents the unfunded obligation of Idaho Power’s pension and postretirement benefit plans, which are discussed in Note 11 - "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 and liability represent the separate Idaho and Oregon jurisdiction balances at December 31, 2022, and December 31, 2023, respectively. During 2023, the balances changed from an asset to a liability in the Idaho jurisdiction.
(6) This item is discussed in more detail in this Note 3 - "Regulatory Matters."
(7) Asset retirement obligations and removal costs are discussed in Note 13 - "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.
(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.
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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 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 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 balancing component that trues up the difference between the previous year’s actual net power supply costs and the costs collected in the previous year's forecast component. The latter component ensures that, over time, the actual collection or refund of net power supply costs matches the amounts authorized. The PCA mechanism includes:
•a cost or benefit sharing ratio that allocates the deviations in net power supply expenses between customers (95 percent) and Idaho Power (5 percent), with the exceptions of expenses associated with PURPA power purchases and demand response incentive payments, which are allocated 100 percent to customers; and
•a sales-based adjustment intended to ensure that power supply expense recovery resulting solely from sales volume changes does not distort the results of the mechanism.
The Idaho deferral period or Idaho-jurisdiction PCA year runs from April 1 through March 31. Amounts deferred during the PCA year are primarily recovered or refunded during the subsequent June 1 through May 31 period. In May 2023, the IPUC approved recovery of an incremental $200.2 million of Idaho-jurisdiction PCA revenues, but directed Idaho Power to spread recovery of the $190.2 million deferral balance component of the PCA over a two-year period from June 1, 2023 to May 31, 2025, resulting in a total PCA increase of $105.1 million, effective for the PCA collection period from June 1, 2023 to May 31, 2024. The order deferred collection of $95.1 million of deferred PCA costs to the subsequent annual PCA collection period from June 1, 2024, to May 31, 2025. The net increase in PCA revenues reflects higher market energy and natural gas prices, combined with lower-than-expected hydropower generation and limited coal supply in the prior April 2022 to March 2023 PCA period. The net increase also reflects an expectation of continued elevated market energy and natural gas prices in the April 2023 to March 2024 forecast period.
The table below summarizes the three most recent Idaho-jurisdiction PCA rate adjustments, which also include non-PCA-related rate adjustments as ordered by the IPUC:
| Effective Date | $ Change (millions) | Notes | ||||||||||||
| June 1, 2023 | $ | 105.1 | The $105.1 million increase in PCA rates reflects higher market energy and natural gas prices, combined with lower-than-expected low-cost hydropower generation and limited coal supply. The increased rate also reflects an expectation of continued elevated market energy prices and natural gas prices in the forecast period. | |||||||||||
| June 1, 2022 | $ | 94.9 | The increase in PCA rates reflected a forecasted reduction in low-cost hydroelectric generation as well as higher costs associated with market energy prices and natural gas prices. The rate also reflected $0.6 million of 2021 earnings shared with customers under the 2018 Settlement Stipulation described below. | |||||||||||
| June 1, 2021 | $ | 39.1 | The net increase in PCA rates reflected a forecasted reduction in low-cost hydroelectric generation as well as higher costs associated with forecasted PURPA power purchases. The net increase in PCA rates also reflected a smaller credit to customers through the true-up component. | |||||||||||
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
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Power to reestablish its Oregon base net power supply costs annually, separate from a general rate case, and to forecast net power supply costs for the upcoming water year. The PCAM is a true-up filed annually in February. The filing calculates the deviation between actual net power supply expenses incurred for the preceding calendar year and the net power supply expenses recovered through the APCU for the same period. Actual 2023 Oregon-jurisdiction power supply costs were less than the amount recovered through the APCU, resulting in a $0.9 million refund due to customers, while in 2022, Oregon jurisdiction power supply cost exceeded the amount recovered through the APCU, resulting in a $1.1 million deferral of costs for future recovery. Variances during 2023 and 2022 did not have a material impact on the companies' financial statements. Idaho Power's annual June 1 APCU rate changes were $7.7 million, $4.0 million, and $2.4 million in 2023, 2022, and 2021, respectively.
Notable Idaho Base Rate Adjustments
Idaho base rates were most recently established through a general rate case in 2023, with rate changes effective January 1, 2024. Previously, base rates were established in a general rate case in 2012 and adjusted in 2014, 2017, 2018, and 2019.
2023 Idaho General Rate Case: In June 2023, Idaho Power filed a general rate case with the IPUC. In December 2023, the IPUC issued an order approving a settlement stipulation among parties (2023 Settlement Stipulation) settling the general rate case.
The Order and the 2023 Settlement Stipulation contains the following significant terms, among other items:
•Idaho Power will implement revised tariff schedules designed to increase annual Idaho-jurisdictional retail revenue by $54.7 million, or 4.25 percent, effective January 1, 2024. The $54.7 million of additional annual revenue is net of an Idaho-jurisdiction PCA rate decrease of $168.3 million and a reduction to annual energy efficiency rider collection of $3.5 million, each of which was transferred into base rates;
•A 9.6 percent return on equity and a 7.247 percent authorized rate of return based on a non-specified cost of debt and capital structure, applied to an Idaho-jurisdictional rate base of approximately $3.8 billion;
•Modifications to the Idaho-jurisdiction PCA including establishment of a new level of base net power supply expense of $484.9 million, which includes the transfer of $168.3 million from current PCA rates to base rates;
•Modifications to the energy efficiency rider to support the transfer of $3.5 million of energy efficiency labor-related cost collection from the annual energy efficiency rider into base rates, warranting a decrease in the energy efficiency rider rate from 3.1 percent to 2.35 percent;
•Modifications to the Idaho-jurisdiction FCA mechanism to support Idaho Power’s rate designs and to reflect updated fixed costs;
•Continued deferral of incremental vegetation management and insurance costs, as measured from 2022 actual costs, through the earlier of Idaho Power’s next Idaho general rate case or 2025;
•An annual $18 million increase in collection of Idaho Power’s regulatory asset associated with its defined benefit pension plan contributions;
•Modifications to Idaho Power’s ADITC and revenue sharing mechanism beginning in 2024 to (1) include an additional amount of investment tax credits equal to the incremental investment tax credits generated from Idaho Power’s investment in 2023 battery storage projects; (2) remove the existing $25 million annual cap on the amount of accelerated amortization of ADITCs; (3) establish a minimum specified Idaho ROE of 9.12 percent for additional amortization of ADITCs; (4) establish a 9.6 percent Idaho ROE as the threshold for revenue sharing of Idaho-jurisdiction earnings between Idaho Power and Idaho customers; and (5) implement all revenue sharing through the PCA rather than a portion offsetting customer-funded pension obligations;
•Agreement that Idaho Power’s capital expenditures through year-end 2022 were prudently incurred;
•Deferral and amortization of annual differences between certain periodic maintenance costs at Idaho Power’s natural gas-fired power plants; and
•A residential price modernization plan and updated rate designs.
Under the modified ADITC and Revenue Sharing mechanism, if Idaho Power's annual Idaho ROE in any year exceeds 9.6 percent, the amount of earnings exceeding 9.6 percent will be allocated 80.0 percent to Idaho Power's Idaho customers as a rate reduction to be effective at the time of the subsequent year's PCA, and 20.0 percent to Idaho Power.
In 2023, Idaho Power recorded no amortization of ADITC. Accordingly, at December 31, 2023, the full amount of ADITC remained available for future use under the terms of the 2023 Settlement Stipulation and the 2018 Settlement Stipulation described below.
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May 2018 Idaho Tax Reform Settlement Stipulation: In May 2018, the IPUC issued an order approving a settlement stipulation (2018 Settlement Stipulation) related to income tax reform. Beginning June 1, 2018, the 2018 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 2018 Settlement Stipulation also provided for the indefinite extension, with modifications, of a previous 2014 settlement stipulation beyond its termination date of December 31, 2019, with modified terms related to the ADITC and revenue sharing mechanism that became effective January 1, 2020.
The 2018 Settlement Stipulation provided Idaho Power the ability to earn a minimum Idaho ROE of 9.4 percent by amortizing up to $25 million of additional ADITC in any calendar year. If Idaho Power’s annual Idaho ROE in any year exceeded 10.0 percent, the amount of earnings exceeding 10.0 percent and up to and including 10.5 percent would be allocated 80 percent to Idaho Power’s Idaho customers as a rate reduction to be effective at the time of the subsequent year’s PCA, and 20 percent to Idaho Power. Idaho Power’s ADITC and revenue sharing mechanism was modified by the 2023 Settlement Stipulation.
North Valmy Base Rate Adjustment Settlement Stipulations: Idaho Power has settlement stipulations in place in Idaho and Oregon related to the planned end of its participation in coal-fired operations of both units of its jointly-owned North Valmy power plant. Idaho Power ceased coal-fired operations at unit 1 in 2019, as planned, and these settlement stipulations provide for Idaho Power to cease coal-fired operations at unit 2 in 2025. The IPUC-approved settlement stipulation provides for (1) accelerated depreciation for the North Valmy plant to allow the coal-related plant assets to be fully depreciated and recovered by December 31, 2028, (2) Idaho Power to use prudent and commercially reasonable efforts to end its participation in coal-fired operations at North Valmy as described above, (3) a balancing account to track the incremental costs, benefits, and required regulatory accounting associated with ceasing participation in coal-fired operations at the North Valmy plant, and (4) increased customer rates related to the associated incremental annual levelized revenue requirement. If actual costs incurred differ from forecasted amounts included in the settlement stipulation, collection or refund of any differences would be subject to regulatory approval.
Jim Bridger Power Plant Rate Base Adjustment and Recovery: In June 2022, the IPUC issued an order approving, with modifications, Idaho Power’s amended application requesting authorization to (1) accelerate depreciation for the Jim Bridger plant to allow the coal-related plant assets to be fully depreciated and recovered by December 31, 2030, (2) establish a balancing account to track the incremental costs, benefits, and required regulatory accounting associated with ceasing participation in coal-fired operations at the Jim Bridger plant, and (3) increase customer rates related to the associated incremental annual levelized revenue requirement (Bridger Order).
The Bridger Order allows for regulatory accounting entries and establishes balancing accounts (recorded as regulatory assets or liabilities on Idaho Power’s and IDACORP’s consolidated balance sheets) to track differences between amounts recovered in rates and actual incremental costs and benefits associated with Idaho Power’s plan at the time of the Bridger Order to cease its participation in coal-fired operations at the Jim Bridger plant by the end of 2028. The incremental costs and benefits include the revenue requirement associated with the incremental Jim Bridger plant coal-related investments made from 2012 through the end of 2020, forecasted coal-related investments, and near-term decommissioning costs, offset by other O&M cost savings. The Bridger Order deemed all coal-related investments at the Jim Bridger plant from 2012 through 2020 to be prudent for recovery.
In the Bridger Order, the IPUC reduced Idaho Power's requested rate increase from 2.1 percent in its amended filing to 1.5 percent, a reduction from a requested $27.1 million to $18.8 million annually. The Bridger Order provides that any uncollected amount resulting from the reduction in the rate increase will be recorded in the balancing account for future recovery with no carrying charge. The uncollected amounts tracked in this balancing account were included for recovery in the 2023 Settlement Stipulation. Idaho Power anticipates making future filings with the IPUC that may result in periodic adjustments to rates to true up variances between revenue collections and actual revenue requirement amounts. The Bridger Order allows Idaho Power to earn a return on and recover through 2030 the net book value of coal-related assets at the Jim Bridger plant as of December 31, 2020, as well as forecasted coal-related investments.
Other Notable Idaho Regulatory Matters
Fixed Cost Adjustment: The 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 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
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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 2023, the IPUC issued an order approving a $10.1 million decrease in recovery from the FCA from $35.2 million to $25.1 million for the 2022 FCA deferral, with new rates effective for the period from June 1, 2023, to May 31, 2024. Beginning with the 2024 FCA deferral, the 2023 Settlement Stipulation updates the authorized fixed-cost recovery amount per customer and modifies parts of the FCA mechanism to support Idaho Power's proposed rate designs, as noted above.
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) | ||||||||||||
| 2022 | June 1, 2023-May 31, 2024 | $25.1 | ||||||||||||
| 2021 | June 1, 2022-May 31, 2023 | $35.2 | ||||||||||||
| 2020 | June 1, 2021-May 31, 2022 | $38.3 | ||||||||||||
Wildfire Mitigation Cost Recovery: In June 2021 and March 2023, the IPUC issued orders authorizing Idaho Power to defer for future amortization incremental O&M and depreciation expense for certain capital investments necessary to implement Idaho Power's WMP. As of December 31, 2023, Idaho Power’s deferral balance of Idaho-jurisdiction costs related to the WMP was $51.3 million. As a result of the 2023 Settlement Stipulation, Idaho Power will recover and amortize its WMP deferral balance through 2022 of $26.7 million, beginning January 1, 2024.
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 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.
The OPUC has also approved settlement stipulations that provide for the accelerated cost recovery of jointly-owned North Valmy unit 1 through 2019 and unit 2 through 2025. The net rate impact of the Oregon settlement stipulations is immaterial.
In December 2023, Idaho Power filed a general rate case with the OPUC. The filing was based on a 2024 test year and requested an overall annual rate increase of $10.7 million, or 19.28 percent. The filing requested, among other items, a 10.4 percent authorized rate of return on equity and an approximate $188.9 million Oregon-jurisdiction retail rate base. The $188.9 million of rate base excludes rate base associated with Idaho Power's jointly-owned North Valmy coal facilities, the costs of which are recovered under the separate rate mechanism noted above. In its application, Idaho Power proposed a capitalization structure of 49 percent long-term debt and 51 percent common stock equity. Idaho Power included an average cost of debt of 5.104 percent and an overall cost of capital of 7.807 percent. If approved by the OPUC, new rates for Oregon-jurisdiction customers would become effective in October 2024 or later.
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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 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, 2023 to September 30, 2024 | $ | 30.74 | ||||||
| October 1, 2022 to September 30, 2023 | $ | 31.42 | ||||||
| October 1, 2021 to September 30, 2022 | $ | 31.19 | ||||||
| October 1, 2020 to September 30, 2021 | $ | 29.95 | ||||||
Idaho Power's current OATT rate is based on a net annual transmission revenue requirement of $135.7 million, which represents the OATT formulaic determination of Idaho Power's net cost of providing OATT-based transmission service.
4. REVENUES
The following table provides a summary of electric utility operating revenues for IDACORP and Idaho Power (in thousands):
| Year Ended December 31, | ||||||||||||||||||||
| 2023 | 2022 | 2021 | ||||||||||||||||||
| Electric utility operating revenues: | ||||||||||||||||||||
| Revenue from contracts with customers | $ | 1,639,612 | $ | 1,557,974 | $ | 1,382,653 | ||||||||||||||
| Alternative revenue programs and derivative revenues | 123,282 | 83,066 | 72,757 | |||||||||||||||||
| Total electric utility operating revenues | $ | 1,762,894 | $ | 1,641,040 | $ | 1,455,410 | ||||||||||||||
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.
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The following table presents revenues from contracts with customers disaggregated by revenue source (in thousands):
| Year Ended December 31, | ||||||||||||||||||||
| 2023 | 2022 | 2021 | ||||||||||||||||||
| Revenues from contracts with customers: | ||||||||||||||||||||
| Retail revenues: | ||||||||||||||||||||
Residential (includes $37,233, $22,595, and $34,835, respectively, related to the FCA(1)) | $ | 684,649 | $ | 645,236 | $ | 583,061 | ||||||||||||||
Commercial (includes $1,338, $922, and $1,407, respectively, related to the FCA(1)) | 378,330 | 347,970 | 314,745 | |||||||||||||||||
| Industrial | 244,538 | 217,368 | 195,214 | |||||||||||||||||
| Irrigation | 173,929 | 170,964 | 168,664 | |||||||||||||||||
| Provision for sharing | — | — | (569) | |||||||||||||||||
Deferred revenue related to HCC relicensing AFUDC(2) | (8,780) | (8,780) | (8,780) | |||||||||||||||||
| Total retail revenues | 1,472,666 | 1,372,758 | 1,252,335 | |||||||||||||||||
Less: FCA mechanism revenues(1) | (38,571) | (23,517) | (36,242) | |||||||||||||||||
| Wholesale energy sales | 63,421 | 66,519 | 40,839 | |||||||||||||||||
| Transmission wheeling-related revenues | 80,357 | 80,527 | 67,997 | |||||||||||||||||
| Energy efficiency program revenues | 31,948 | 33,197 | 29,920 | |||||||||||||||||
| Other revenues from contracts with customers | 29,791 | 28,490 | 27,804 | |||||||||||||||||
| Total revenues from contracts with customers | $ | 1,639,612 | $ | 1,557,974 | $ | 1,382,653 | ||||||||||||||
(1) The FCA mechanism is an alternative revenue program in the Idaho jurisdiction and does not represent revenue from contracts with customers.
(2) The IPUC allows Idaho Power to recover a portion of the AFUDC on construction work in progress related to the HCC relicensing process, even though the relicensing process is not yet complete and the costs have not been moved to electric plant in service. Idaho Power is collecting $8.8 million annually in the Idaho jurisdiction but is deferring revenue recognition of the amounts collected until the license is issued and the accumulated license costs approved for recovery are placed in service.
Retail Revenues: Idaho Power’s retail revenues primarily relate to the sale of electricity to customers based on regulated tariff-based prices. Idaho Power recognizes retail revenues in amounts for which it has the right to invoice the customer in the period when energy is delivered or services are provided to customers. The total energy price generally has a fixed component related to having service available and a usage-based component related to the demand, delivery, and consumption of energy. The revenues recognized reflect the consideration Idaho Power expects to be entitled to in exchange for energy and services. Retail customers are classified as residential, commercial, industrial, or irrigation. Approximately 95 percent of Idaho Power's retail revenue originates from customers located in Idaho, with the remainder originating from customers located in Oregon. Idaho Power’s retail customer rates are based on Idaho Power’s cost of service and are determined through general rate case proceedings, settlement stipulations, and other filings with the IPUC and OPUC. Changes in rates and changes in customer demand are typically the primary causes of fluctuations in retail revenue from period to period. The primary influences on changes in customer demand for electricity are weather, economic conditions (including growth in the number of Idaho Power customers), and energy efficiency. Idaho Power's utility revenues are not earned evenly during the year.
Retail revenues are billed monthly based on meter readings taken throughout the month. Payments for amounts billed are generally due from the customer within 15 days of billing. Idaho Power accrues estimated unbilled revenues for energy or related services delivered to customers but not yet billed at period-end based on actual meter readings at period-end and estimated rates.
Residential Customers: Idaho Power’s energy sales to residential customers typically peak during the summer cooling season and winter heating season. Extreme temperatures increase sales to residential customers who use electricity for cooling and heating, compared with normal temperatures. Idaho Power's rate structure provides for higher rates during the summer when overall system loads are at their highest, and includes tiers such that rates increase as a customer's consumption level increases. These seasonal and tiered rate structures contribute to the seasonal fluctuations in revenues and earnings. Economic and demographic conditions can also affect residential customer demand; strong job growth and population growth in Idaho Power’s service area have led to higher customer growth 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.
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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.
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.
Irrigation Customers: Irrigation customers use electricity to operate irrigation pumps, primarily during the agricultural growing season. The amount and timing of precipitation as well as temperature levels affect the timing and amounts of sales to irrigation customers, with increased precipitation during the agricultural growing season generally resulting in decreased sales.
Provision for Sharing: Idaho Power has regulatory settlement stipulations in Idaho that provide for the potential sharing between Idaho Power and its Idaho customers of Idaho-jurisdictional earnings in excess of 10.0 percent of Idaho ROE (in excess of 9.6 percent of Idaho ROE beginning in 2024). Based on full-year 2023 Idaho ROE, Idaho Power recorded no provision against current revenues for sharing of earnings with customers for 2023. During 2022, no provision was recorded and in 2021, $0.6 million of sharing of earnings with customers was recorded. The regulatory settlement stipulations are described further in Note 3 - "Regulatory Matters."
Wholesale Energy Sales: As a public utility under the 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 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. 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, 2023, Idaho Power's energy efficiency rider balances were a $0.7 million regulatory liability in the Idaho jurisdiction and a $0.8 million regulatory liability in the Oregon jurisdiction.
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.
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Derivative revenues include gains from settled electricity swaps and sales of electricity under forward sales contracts that are bundled with RECs. Related to these forward sales, Idaho Power simultaneously enters into forward purchases of electricity for the same quantity at the same location, which are recorded in purchased power on the consolidated statements of income. For more information on settled electricity swaps, see Note 15 - "Derivative Financial Instruments."
The table below presents the FCA mechanism revenues and derivative revenues (in thousands):
| Year Ended December 31, | ||||||||||||||||||||
| 2023 | 2022 | 2021 | ||||||||||||||||||
| Alternative revenue programs and derivative revenues: | ||||||||||||||||||||
| FCA mechanism revenues | $ | 38,571 | $ | 23,517 | $ | 36,242 | ||||||||||||||
| Derivative revenues | 84,711 | 59,549 | 36,515 | |||||||||||||||||
| Total alternative revenue programs and derivative revenues | $ | 123,282 | $ | 83,066 | $ | 72,757 | ||||||||||||||
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):
| 2023 | 2022 | |||||||||||||
| First mortgage bonds: | ||||||||||||||
2.50% Series due 2023 | $ | — | $ | 75,000 | ||||||||||
1.90% Series due 2030 | 80,000 | 80,000 | ||||||||||||
6.00% Series due 2032 | 100,000 | 100,000 | ||||||||||||
4.99% Series due 2032 | 23,000 | 23,000 | ||||||||||||
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 | ||||||||||||
5.06% Series due 2042 | 25,000 | 25,000 | ||||||||||||
5.06% Series due 2043 | 60,000 | — | ||||||||||||
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 | ||||||||||||
5.20% Series due 2053 | 62,000 | — | ||||||||||||
5.50% Series due 2053 | 400,000 | — | ||||||||||||
5.80% Series due 2054 | 350,000 | — | ||||||||||||
| Total first mortgage bonds | 2,645,000 | 1,848,000 | ||||||||||||
| Pollution control revenue bonds: | ||||||||||||||
1.45% Series due 2024(1) | 49,800 | 49,800 | ||||||||||||
1.70% Series due 2026(1) | 116,300 | 116,300 | ||||||||||||
| Total pollution control revenue bonds | 166,100 | 166,100 | ||||||||||||
| Floating Rate Term Loan Facility due 2024 | — | 150,000 | ||||||||||||
| American Falls Variable Rate bond guarantee due 2025 | 19,885 | 19,885 | ||||||||||||
| Unamortized premium/discount and issuance costs | (5,395) | 10,160 | ||||||||||||
Total IDACORP and Idaho Power outstanding debt(2) | 2,825,590 | 2,194,145 | ||||||||||||
| Current maturities of long-term debt | (49,800) | — | ||||||||||||
| Total long-term debt | $ | 2,775,790 | $ | 2,194,145 | ||||||||||
(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, 2023, to $2.811 billion.
(2) At December 31, 2023 and 2022, the overall effective cost rate of Idaho Power's outstanding debt was 4.98 percent and 4.60 percent, respectively.
At December 31, 2023, the maturities for the aggregate amount of IDACORP and Idaho Power long-term debt outstanding were as follows (in thousands of dollars):
| 2024 | 2025 | 2026 | 2027 | 2028 | Thereafter | ||||||||||||||||||||||||||||||
| $ | 49,800 | $ | 19,885 | $ | 116,300 | $ | — | $ | — | $ | 2,645,000 | ||||||||||||||||||||||||
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Long-Term Debt Issuances, Maturities, and Redemptions
On September 11, 2023, under the shelf registration statement with the SEC, Idaho Power issued $350 million in aggregate principal amount of 5.80% first mortgage bonds, secured medium-term notes, Series M, maturing on April 1, 2054.
On April 1, 2023, Idaho Power repaid $75 million in aggregate principal amount of maturing 2.50% first mortgage bonds due 2023, Series I.
On March 14, 2023, under the shelf registration statement with the SEC, Idaho Power issued $400 million in aggregate principal amount of 5.50% first mortgage bonds, secured medium-term notes, Series M, maturing on March 15, 2053.
On March 8, 2023, pursuant to the Bond Purchase Agreement defined below, Idaho Power issued $60 million in aggregate principal amount of 5.06% first mortgage bonds, secured medium-term notes, Series N, maturing on March 8, 2043; and $62 million in aggregate principal amount of 5.20% first mortgage bonds, secured medium-term notes, Series N, maturing on March 8, 2053.
On December 22, 2022, Idaho Power entered into a Bond Purchase Agreement (Bond Purchase Agreement) with certain institutional purchasers relating to the sale by Idaho Power of $170 million of first mortgage bonds secured medium-term-term notes, Series N (Series N Notes), as described in more detail below.
On December 1, 2022, Idaho Power redeemed at par $4.36 million in principal amount of variable-rate pollution control revenue bonds due in 2027.
On March 4, 2022, Idaho Power entered into a floating rate term loan credit agreement (Term Loan Facility). The Term Loan Facility was a two-year senior unsecured term loan facility in the aggregate principal amount of $150 million. On March 31, 2023, Idaho Power repaid $100 million and on May 17, 2023, repaid $50 million principal amount to fully repay the Term Loan Facility. At December 31, 2023, there was no remaining outstanding principal balance of the Term Loan Facility.
Idaho Power First Mortgage Bonds
Idaho Power's issuance of long-term indebtedness is subject to the approval of the IPUC, OPUC, and WPSC. In May and June 2022, Idaho Power received orders from the IPUC, OPUC, and WPSC authorizing the company to issue and sell from time to time up to $1.2 billion in aggregate principal amount of debt securities and first mortgage bonds, subject to conditions specified in the orders. Authority from the IPUC is effective through May 31, 2025, subject to extensions upon request to the IPUC. The OPUC's and WPSC's orders do not impose a time limitation for issuances, but the OPUC order does impose a number of other conditions, including a requirement that the interest rates for the debt securities or first mortgage bonds fall within either (a) designated spreads over comparable U.S. Treasury rates or (b) a maximum interest rate limit of 8.0 percent. At December 31, 2023, $280 million remains available for debt issuance under the regulatory orders. In January 2024, Idaho Power submitted applications to the IPUC, OPUC, and WPSC requesting authorization to issue and sell from time to time up to $1.2 billion in aggregate principal amount of debt securities and first mortgage bonds, which if approved will replace the $280 million remaining under the existing regulatory orders. On February 8, 2024, Idaho Power received an order from OPUC authorizing its request. As of the date of this report, approvals from the IPUC and WPSC are still pending.
In May 2022, Idaho Power filed a shelf registration statement with the SEC, which became effective upon filing, for the offer and sale of an unspecified principal amount of its first mortgage bonds. The issuance of first mortgage bonds requires that Idaho Power meet interest coverage and security provisions set forth in Idaho Power's Indenture of Mortgage and Deed of Trust, dated as of October 1, 1937, as amended and supplemented from time to time (Indenture). Future issuances of first mortgage bonds are subject to satisfaction of covenants and security provisions set forth in the Indenture, market conditions, regulatory authorizations, and covenants contained in other financing agreements.
In June 2022, Idaho Power entered into a selling agency agreement with six banks named in the agreement in connection with the potential issuance and sale from time to time of up to $1.2 billion aggregate principal amount of first mortgage bonds, secured medium term notes, Series M (Series M Notes), under Idaho Power’s Indenture. Also in June 2022, Idaho Power entered into the Fiftieth Supplemental Indenture, dated effective as of June 30, 2022, to the Indenture (Fiftieth Supplemental Indenture). The Fiftieth Supplemental Indenture provides for, among other items, the issuance of up to $1.2 billion in aggregate principal amount of Series M Notes pursuant to the Indenture. In October 2022, Idaho Power entered into the Fifty-first Supplemental Indenture to increase the limit of the amount of first mortgage bonds at any one time outstanding to $3.5 billion as provided in the Indenture. The amount issuable is also restricted by property, earnings, and other provisions of the Indenture and supplemental indentures to the Indenture. The Indenture requires that Idaho Power's net earnings be at least twice the
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annual interest requirements on all outstanding debt of equal or prior rank, including the bonds that Idaho Power may propose to issue. Under certain circumstances, the net earnings test does not apply, including the issuance of refunding bonds to retire outstanding bonds that mature in less than two years or that are of an equal or higher interest rate, or prior lien bonds.
In December 2022, Idaho Power entered into the Bond Purchase Agreement with certain institutional purchasers, relating to the sale by Idaho Power of $170 million in aggregate principal amount of Series N Notes. Also in December 2022, Idaho Power entered into the Fifty-second Supplemental Indenture, dated effective as of December 30, 2022, to the Indenture (Fifty-second Supplemental Indenture). The Fifty-second Supplemental Indenture provides for, among other items, the issuance of Series N Notes pursuant to the Indenture. The Series N Notes consist of:
•$23 million in aggregate principal amount of Idaho Power’s 4.99% first mortgage bonds due 2032, Series N Notes, Tranche 1 (Tranche 1 Bonds);
•$25 million in aggregate principal amount of Idaho Power’s 5.06% first mortgage bonds due 2042, Series N Notes, Tranche 2 (Tranche 2 Bonds);
•$60 million in aggregate principal amount of Idaho Power’s 5.06% first mortgage bonds due 2043, Series N Notes, Tranche 3 (Tranche 3 Bonds); and
•$62 million in aggregate principal amount of Idaho Power’s 5.20% first mortgage bonds due 2053, Series N Notes, Tranche 4 (Tranche 4 Bonds).
The Tranche 1 Bonds and Tranche 2 Bonds were issued on December 22, 2022, and the Tranche 3 Bonds and Tranche 4 Bonds were issued on March 8, 2023, each under the Indenture.
The mortgage of the Indenture secures all bonds issued under the Indenture equally and ratably, without preference, priority, or distinction. First mortgage bonds issued in the future will also be secured by the mortgage of the Indenture. The lien constitutes a first mortgage on all the properties of Idaho Power, subject only to certain limited exceptions including liens for taxes and assessments that are not delinquent and minor excepted encumbrances. Certain of the properties of Idaho Power are subject to easements, leases, contracts, covenants, workmen's compensation awards, and similar encumbrances and minor defects common to properties. The mortgage of the Indenture does not create a lien on revenues or profits, or notes or accounts receivable, contracts or choses in action, except as permitted by law during a completed default, securities, or cash, except when pledged, or merchandise or equipment manufactured or acquired for resale. The mortgage of the Indenture creates a lien on the interest of Idaho Power in property subsequently acquired, other than excepted property, subject to limitations in the case of consolidation, merger, or sale of all or substantially all of the assets of Idaho Power. The Indenture requires Idaho Power to spend or appropriate 15 percent of its annual gross operating revenues for maintenance, retirement, or amortization of its properties. Idaho Power may, however, anticipate or make up these expenditures or appropriations within the 5 years that immediately follow or precede a particular year.
As of December 31, 2023, the maximum amount of additional first mortgage bonds Idaho Power could issue approximately $700 million, though as of the date of this report the amount is limited to the $280 million amount authorized by the IPUC, OPUC, and WPSC. Separately, the Indenture 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, 2023, Idaho Power could issue approximately $1.9 billion of additional first mortgage bonds based on retired first mortgage bonds and total unfunded property additions.
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6. COMMON STOCK
IDACORP Common Stock
The following table summarizes IDACORP common stock transactions during the last three years and shares reserved at December 31, 2023:
| Shares issued | Shares reserved | |||||||||||||||||||||||||
| 2023 | 2022 | 2021 | December 31, 2023 | |||||||||||||||||||||||
| Balance at beginning of year | 50,561,892 | 50,516,479 | 50,461,885 | |||||||||||||||||||||||
| Forward sale agreements | — | — | — | 3,221,982 | ||||||||||||||||||||||
| Continuous equity program (inactive) | — | — | — | 3,000,000 | ||||||||||||||||||||||
| Dividend reinvestment and stock purchase plan | — | — | — | 2,841,702 | ||||||||||||||||||||||
| Employee savings plan | — | — | — | 3,567,954 | ||||||||||||||||||||||
Long-term incentive and compensation plan(1) | 53,345 | 45,413 | 54,594 | 1,161,509 | ||||||||||||||||||||||
| Balance at end of year | 50,615,237 | 50,561,892 | 50,516,479 | |||||||||||||||||||||||
(1) During 2023, 2022, and 2021, IDACORP granted 75,295, 73,131, and 76,147 restricted stock unit awards, respectively, to employees and 12,459, 12,021, and 14,025 shares of common stock, respectively, to directors. During 2023, 2022, and 2021, IDACORP issued 53,345, 45,413, and 54,594 shares of common stock, respectively, using original issuances of shares pursuant to the LTICP, including 13,842, 8,674, and 12,784 shares of common stock, respectively, issued to members of the board of directors.
Equity Forward Sale Agreements
On November 7, 2023, IDACORP announced a registered public offering of 2,801,724 shares of its common stock at a public offering price of $92.80 per share, for an issuance amount of $260.0 million. In conjunction with this offering, IDACORP granted the underwriters an option to purchase up to 420,258 additional shares, which was subsequently exercised in full on November 8, 2023, for an additional issuance amount of $39.0 million. The 3,221,982 shares were sold under FSAs which provide for settlement on a settlement date or dates to be specified at IDACORP’s discretion, but which is expected to occur on or prior to November 7, 2024.
The FSAs will be physically settled with common shares issued by IDACORP, unless IDACORP elects to settle the agreements in net cash or net shares, subject to certain conditions. On a settlement date or dates, if IDACORP decides to physically settle the FSAs, IDACORP will issue shares of common stock to the forward purchaser at the then-applicable forward sale price and receive issuance proceeds at that time. The forward sale price was initially $90.016 per share and is subject to certain adjustments in accordance with the terms of the FSAs through the date of settlement.
At December 31, 2023, IDACORP could have settled the FSAs with physical delivery of 3,221,982 shares of common stock to the counterparty in exchange for cash of $291.9 million. The FSAs could have also been settled at December 31, 2023, with delivery of approximately $23.9 million of cash or approximately 0.2 million shares of common stock to the counterparty, if IDACORP had elected to net cash or net share settle, respectively.
The FSAs have been classified as an equity transaction because they are indexed to IDACORP’s common stock and the other requirements necessary for equity classification are met. As a result of the equity classification, no gain or loss will be recognized within earnings due to subsequent changes in the fair value of the FSAs.
Prior to settlement, the potentially issuable shares pursuant to the FSAs will be reflected in IDACORP’s diluted earnings per share calculations using the treasury stock method. Under this method, the number of shares of IDACORP’s common stock used in calculating diluted earnings per share for a reporting period would be increased by the number of shares, if any, that would be issued upon physical settlement of the FSAs less the number of shares that could be purchased by IDACORP in the market with the proceeds received from issuance (based on the average market price during that reporting period). Share dilution occurs when the average market price of IDACORP’s stock during the reporting period is higher than the then-applicable forward sale price as of the end of the reporting period. As of December 31, 2023, 34,131 incremental shares were included in the calculation of diluted EPS related to the securities under the FSAs. See Note 8 - "Earnings Per Share" for additional information concerning IDACORP's diluted earnings per share.
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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, 2023, the leverage ratios for IDACORP and Idaho Power were 50 percent and 51 percent, respectively. Based on these restrictions, IDACORP’s and Idaho Power’s dividends were limited to $1.4 billion and $1.2 billion, respectively, at December 31, 2023. There are additional facility covenants, subject to exceptions, that prohibit or restrict the sale or disposition of property without consent and any agreements restricting dividend payments to IDACORP and Idaho Power from any material subsidiary. At December 31, 2023, IDACORP and Idaho Power were in compliance with those covenants.
Idaho Power’s Revised Policy and Code of Conduct relating to transactions between and among Idaho Power, IDACORP, and other affiliates, which was approved by the IPUC in April 2008, provides that Idaho Power will not pay any dividends to IDACORP that will reduce Idaho Power’s common equity capital below 35 percent of its total adjusted capital without IPUC approval. At December 31, 2023, Idaho Power's common equity capital was 50 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.
7. SHARE-BASED COMPENSATION
IDACORP has one share-based compensation plan — the LTICP. The LTICP (for officers, key employees, and directors) permits the grant of stock options, restricted stock and restricted stock units, performance shares and performance-based units, and several other types of share-based awards. At December 31, 2023, the maximum number of shares available under the LTICP was 244,938.
Restricted Stock Unit and Performance-Based Unit Awards
Restricted stock unit awards have -year vesting periods, entitle the recipients to dividend equivalents, and 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 unit awards have three-year vesting periods and 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. Dividend equivalents 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.
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A summary of restricted stock units and performance-based units award activity is presented below. Idaho Power unit amounts represent the portion of IDACORP amounts related to Idaho Power employees:
| IDACORP | Idaho Power | |||||||||||||||||||||||||
| Number of Units | Weighted-Average Grant Date Fair Value | Number of Units | Weighted-Average Grant Date Fair Value | |||||||||||||||||||||||
| Nonvested units at January 1, 2023 | 188,468 | $ | 99.92 | 187,816 | $ | 99.91 | ||||||||||||||||||||
| Units granted | 94,580 | 103.98 | 94,118 | 103.98 | ||||||||||||||||||||||
| Units forfeited | (2,604) | 99.37 | (2,604) | 99.37 | ||||||||||||||||||||||
| Units vested | (70,344) | 113.07 | (70,106) | 113.07 | ||||||||||||||||||||||
| Nonvested units at December 31, 2023 | 210,100 | $ | 97.35 | 209,224 | $ | 97.34 | ||||||||||||||||||||
The total fair value of shares vested was $7.5 million in 2023, $6.9 million in 2022, and $6.7 million in 2021. At December 31, 2023, IDACORP had $8.0 million of total unrecognized compensation cost related to nonvested share-based compensation, nearly all of which was Idaho Power's share. These costs are expected to be recognized over a weighted-average period of 1.6 years. IDACORP uses original issue shares for these awards.
In 2023, a total of 12,459 shares were awarded to directors at an average grant date fair value of $103.48 per share. Directors elected to defer receipt of 4,640 of these shares, which are being held as deferred stock units with dividend equivalents reinvested in additional stock units.
Compensation Expense: The following table shows the compensation cost recognized in income and the tax benefits resulting from the LTICP, as well as the amounts allocated to Idaho Power for those costs associated with Idaho Power’s employees (in thousands of dollars):
| IDACORP | Idaho Power | |||||||||||||||||||||||||||||||||||||
| 2023 | 2022 | 2021 | 2023 | 2022 | 2021 | |||||||||||||||||||||||||||||||||
| Compensation cost | $ | 9,578 | $ | 10,279 | $ | 8,583 | $ | 9,508 | $ | 10,204 | $ | 8,497 | ||||||||||||||||||||||||||
| Income tax benefit | 2,465 | 2,646 | 2,209 | 2,447 | 2,627 | 2,187 | ||||||||||||||||||||||||||||||||
No equity compensation costs have been capitalized. These costs are primarily reported within "Other operations and maintenance" expense on the consolidated statements of income.
8. EARNINGS PER SHARE
The following table presents the computation of IDACORP’s basic and diluted earnings per share for the years ended December 31, 2023, 2022, and 2021 (in thousands, except for per share amounts):
| Year Ended December 31, | ||||||||||||||||||||
| 2023 | 2022 | 2021 | ||||||||||||||||||
| Numerator: | ||||||||||||||||||||
| Net income attributable to IDACORP, Inc. | $ | 261,195 | $ | 258,982 | $ | 245,550 | ||||||||||||||
| Denominator: | ||||||||||||||||||||
| Weighted-average common shares outstanding - basic | 50,717 | 50,658 | 50,599 | |||||||||||||||||
Effect of dilutive securities(1) | 89 | 41 | 46 | |||||||||||||||||
| Weighted-average common shares outstanding - diluted | 50,806 | 50,699 | 50,645 | |||||||||||||||||
| Basic earnings per share | $ | 5.15 | $ | 5.11 | $ | 4.85 | ||||||||||||||
| Diluted earnings per share | $ | 5.14 | $ | 5.11 | $ | 4.85 | ||||||||||||||
(1) The effect of dilutive securities amount includes 34,131 incremental shares related to FSAs as of December 31, 2023. See Note 6 - "Common Stock" for additional information concerning IDACORP's FSAs.
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9. COMMITMENTS
Purchase Obligations
At December 31, 2023, Idaho Power had the following long-term commitments relating to purchases of energy, capacity, transmission rights, and fuel (in thousands of dollars):
| 2024 | 2025 | 2026 | 2027 | 2028 | Thereafter | |||||||||||||||||||||||||||||||||
Cogeneration and power production(1) | $ | 324,738 | $ | 336,702 | $ | 358,113 | $ | 371,980 | $ | 345,740 | $ | 2,999,760 | ||||||||||||||||||||||||||
| Fuel | 155,474 | 25,672 | 15,271 | 15,439 | 15,507 | 84,004 | ||||||||||||||||||||||||||||||||
(1) As of December 31, 2023, Idaho Power had a $431 million commitment related to an agreement to utilize the storage capacity of a 150 MW battery storage facility, over a 20-year term, scheduled to be online in June 2025.
As of December 31, 2023, Idaho Power had power purchase obligations with respect to 1,432 MW nameplate capacity of online PURPA and non-PURPA projects, with an additional 428 MW nameplate capacity of projects that are scheduled to be online through 2026. The agreements for these projects have original contract terms ranging from to 35 years. Idaho Power's purchased power expense associated with long-term agreements (including PURPA) was approximately $258 million in 2023, $238 million in 2022, and $251 million in 2021.
Idaho Power also has the following long-term commitments (in thousands of dollars):
| 2024 | 2025 | 2026 | 2027 | 2028 | Thereafter | |||||||||||||||||||||||||||||||||
Joint-operating agreement payments(1) | $ | 2,834 | $ | 2,834 | $ | 2,834 | $ | 2,834 | $ | 2,834 | $ | 14,172 | ||||||||||||||||||||||||||
Easements and other payments(1) | 2,119 | 2,163 | 2,209 | 2,255 | 2,302 | 12,258 | ||||||||||||||||||||||||||||||||
Maintenance, service, and materials agreements(1)(2) | 321,776 | 29,042 | 11,273 | 13,386 | 3,450 | 41,118 | ||||||||||||||||||||||||||||||||
FERC and other industry-related fees(1) | 18,514 | 17,020 | 16,830 | 16,780 | 15,949 | 83,032 | ||||||||||||||||||||||||||||||||
(1) Approximately $28 million, $1 million, $20 million, and $166 million of the commitments included in joint-operating agreement payments, easements and other payments, maintenance, service, and materials agreements, and FERC and other industry-related fees, respectively, have contracts that do not specify terms related to expiration. As these contracts are presumed to continue indefinitely, ten years of information, estimated based on current contract terms, has been included in the table for presentation purposes.
(2) As of December 31, 2023, Idaho Power had a remaining $115 million commitment related to four contracts to acquire and own battery storage assets with in-service dates through 2025.
At IDACORP, long-term purchase commitments of $34.7 million are mostly comprised of other long-term liabilities at Ida-West and IFS. At December 31, 2023, IDACORP had a commitment to invest an additional $5.9 million into a private market investment fund, which is expected to occur over the next few years. IDACORP’s expense for operating leases was not material for the years ended 2023, 2022, and 2021.
Acquisition of Additional Interest in Boardman-to-Hemingway Transmission Project
In March 2023, Idaho Power executed a purchase, sale, and security agreement with the BPA to transfer BPA's 24 percent interest in the Boardman-to-Hemingway transmission line project to Idaho Power, bringing Idaho Power's interest in the project to approximately 45 percent. Pursuant to the agreement, Idaho Power has a commitment to provide long-term transmission service to BPA. The agreement also required BPA to make a $10 million security payment to Idaho Power. On Idaho Power's consolidated balance sheet, the agreement increased construction work in progress by $31.4 million for the acquired permitting interest, cash and cash equivalents by $10.0 million for the additional security payment, and other non-current liabilities by $41.4 million for Idaho Power's obligation to pay for the permitting interest and to return the security deposit to BPA. Payments to BPA for the permitting interest are expected to be made over a 15-year period beginning 10 years after energization of the transmission line project, while the security deposit is due to be returned to BPA upon energization.
Guarantees
Idaho Power guarantees its portion of reclamation activities and obligations at BCC, of which IERCo owns a one-third interest. This guarantee, which is renewed annually with the WDEQ, was $47.6 million at December 31, 2023, representing IERCo's one-third share of BCC's total reclamation obligation of $142.9 million. BCC has a reclamation trust fund set aside specifically for the purpose of paying these reclamation costs. At December 31, 2023, the value of the reclamation trust fund was $253.3 million. During 2023, the reclamation trust fund made $6.0 million of distributions for reclamation activity costs associated with the BCC surface mine. BCC periodically assesses the adequacy of the reclamation trust fund and its estimate of
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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, 2023, management believes the likelihood is remote that IDACORP or Idaho Power would be required to perform under such indemnification provisions or otherwise incur any significant losses with respect to such indemnification obligations. Neither IDACORP nor Idaho Power has recorded any liability on their respective consolidated balance sheets with respect to these indemnification obligations.
10. CONTINGENCIES
IDACORP and Idaho Power have in the past and expect in the future to become involved in various claims, controversies, disputes, and other contingent matters, some of which involve litigation and regulatory or other contested proceedings. The ultimate resolution and outcome of litigation and regulatory proceedings is inherently difficult to determine, particularly where (a) the remedies or penalties sought are indeterminate, (b) the proceedings are in the early stages or the substantive issues have not been well developed, or (c) the matters involve complex or novel legal theories or a large number of parties. In accordance with applicable accounting guidance, IDACORP and Idaho Power, as applicable, establish an accrual for legal proceedings when those matters proceed to a stage where they present loss contingencies that are both probable and reasonably estimable. If the loss contingency at issue is not both probable and reasonably estimable, IDACORP and Idaho Power do not establish an accrual and the matter will continue to be monitored for any developments that would make the loss contingency both probable and reasonably estimable. As of the date of this report, IDACORP's and Idaho Power's accruals for loss contingencies are not material to their financial statements as a whole; however, future accruals could be material in a given period. IDACORP's and Idaho Power's determination is based on currently available information, and estimates presented in financial statements and other financial disclosures involve significant judgment and may be subject to significant uncertainty. For matters that affect Idaho Power's operations, Idaho Power intends to seek, to the extent permissible and appropriate, recovery through the ratemaking process of costs incurred, although there is no assurance that such recovery would be granted.
IDACORP and Idaho Power are parties to legal claims and legal, tax, and regulatory actions and proceedings in the ordinary course of business and, as noted above, record an accrual for associated loss contingencies when they are probable and reasonably estimable. In connection with its utility operations, Idaho Power is subject to claims by individuals, entities, and governmental agencies for damages for alleged personal injury, property damage, and economic losses, relating to the company’s provision of electric service and the operation of its power supply, transmission, and distribution facilities. Some of those claims relate to electrical contacts, service quality, property damage, and wildfires. In recent years, utilities in the western United States have been subject to significant liability for personal injury, loss of life, property damage, trespass, and economic losses, and in some cases, punitive damages and criminal charges, associated with wildfires that originated from utility property, most commonly transmission and distribution lines. Idaho Power has also regularly received claims by governmental agencies and private landowners for damages for fires allegedly originating from Idaho Power’s transmission and distribution system. As of the date of this report, the companies believe that resolution of existing claims will not have a material adverse effect on their respective consolidated financial statements.
Idaho Power is also actively monitoring various pending environmental regulations and executive orders related to environmental matters that may have a significant impact on its future operations. Given uncertainties regarding the outcome, timing, and compliance plans for these environmental matters, Idaho Power is unable to estimate the financial impact of these regulations.
11. BENEFIT PLANS
Idaho Power sponsors defined benefit and other postretirement benefit plans that cover the majority of its employees. Idaho Power also sponsors a defined contribution 401(k) employee savings plan and provides certain post-employment benefits.
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Pension Plans
Idaho Power has a noncontributory defined benefit pension plan (pension plan) and two nonqualified defined benefit plans for certain senior management employees, the 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 | |||||||||||||||||||||||||
| 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||||||
| Change in projected benefit obligation: | ||||||||||||||||||||||||||
| Benefit obligation at January 1 | $ | 953,769 | $ | 1,346,530 | $ | 99,976 | $ | 133,012 | ||||||||||||||||||
| Service cost | 29,843 | 52,025 | 612 | 1,185 | ||||||||||||||||||||||
| Interest cost | 51,277 | 39,670 | 5,322 | 3,897 | ||||||||||||||||||||||
| Actuarial loss (gain) | 41,539 | (438,297) | 6,518 | (32,009) | ||||||||||||||||||||||
| Plan amendment | — | — | 11 | — | ||||||||||||||||||||||
| Benefits paid | (48,412) | (46,159) | (6,630) | (6,109) | ||||||||||||||||||||||
| Projected benefit obligation at December 31 | 1,028,016 | 953,769 | 105,809 | 99,976 | ||||||||||||||||||||||
| Change in plan assets: | ||||||||||||||||||||||||||
| Fair value at January 1 | 839,728 | 984,464 | — | — | ||||||||||||||||||||||
| Actual return on plan assets | 78,197 | (138,577) | — | — | ||||||||||||||||||||||
| Employer contributions | 48,000 | 40,000 | — | — | ||||||||||||||||||||||
| Benefits paid | (48,412) | (46,159) | — | — | ||||||||||||||||||||||
| Fair value at December 31 | 917,513 | 839,728 | — | — | ||||||||||||||||||||||
| Funded status at end of year | $ | (110,503) | $ | (114,041) | $ | (105,809) | $ | (99,976) | ||||||||||||||||||
| Amounts recognized in the balance sheet consist of: | ||||||||||||||||||||||||||
| Other current liabilities | $ | — | $ | — | $ | (6,608) | $ | (6,514) | ||||||||||||||||||
| Noncurrent liabilities | (110,503) | (114,041) | (99,201) | (93,462) | ||||||||||||||||||||||
Net amount recognized | $ | (110,503) | $ | (114,041) | $ | (105,809) | $ | (99,976) | ||||||||||||||||||
| Amounts recognized in AOCI consist of: | ||||||||||||||||||||||||||
| Net loss | $ | 108,334 | $ | 83,263 | $ | 21,074 | $ | 15,127 | ||||||||||||||||||
| Prior service cost | 31 | 37 | 2,200 | 2,408 | ||||||||||||||||||||||
| Subtotal | 108,365 | 83,300 | 23,274 | 17,535 | ||||||||||||||||||||||
Less amount recorded as regulatory asset(1) | (108,365) | (83,300) | — | — | ||||||||||||||||||||||
| Net amount recognized in AOCI | $ | — | $ | — | $ | 23,274 | $ | 17,535 | ||||||||||||||||||
| Accumulated benefit obligation | $ | 892,325 | $ | 837,377 | $ | 99,786 | $ | 93,995 | ||||||||||||||||||
(1) Changes in the funded status of the pension plan that would be recorded in AOCI for an unregulated entity are recorded as a regulatory asset for Idaho Power as Idaho Power believes it is probable that an amount equal to the regulatory asset will be collected through the setting of future rates.
The actuarial losses reflected in the benefit obligations for the pension and SMSP plans in 2023 are due primarily to decreases in the assumed discount rates of both plans from December 31, 2022, to December 31, 2023. The actuarial gains reflected in the benefit obligations for the pension and SMSP plans in 2022 are due primarily to increases in the assumed discount rates of both plans from December 31, 2021, to December 31, 2022. For more information on discount rates, see “Plan Assumptions” below in this Note 11.
As a non-qualified plan, the SMSP has no plan assets. However, Idaho Power has a Rabbi trust designated to provide funding for SMSP obligations. The Rabbi trust holds investments in marketable securities and corporate-owned life insurance. The
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recorded value of these investments was approximately $146.2 million and $134.2 million at December 31, 2023 and 2022, 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 | |||||||||||||||||||||||||||||||||||||
| 2023 | 2022 | 2021 | 2023 | 2022 | 2021 | |||||||||||||||||||||||||||||||||
| Service cost | $ | 29,843 | $ | 52,025 | $ | 54,202 | $ | 612 | $ | 1,185 | $ | 813 | ||||||||||||||||||||||||||
| Interest cost | 51,277 | 39,670 | 37,317 | 5,322 | 3,897 | 3,557 | ||||||||||||||||||||||||||||||||
| Expected return on assets | (61,728) | (72,348) | (64,090) | — | — | — | ||||||||||||||||||||||||||||||||
| Amortization of net loss | — | 12,273 | 23,796 | 570 | 4,229 | 4,205 | ||||||||||||||||||||||||||||||||
| Amortization of prior service cost | 6 | 6 | 6 | 219 | 279 | 296 | ||||||||||||||||||||||||||||||||
| Net periodic pension cost | 19,398 | 31,626 | 51,231 | 6,723 | 9,590 | 8,871 | ||||||||||||||||||||||||||||||||
Regulatory deferral of net periodic pension cost(1) | (18,553) | (30,197) | (48,962) | — | — | — | ||||||||||||||||||||||||||||||||
Previously deferred pension cost recognized(1) | 17,154 | 17,154 | 17,154 | — | — | — | ||||||||||||||||||||||||||||||||
Net periodic pension cost recognized for financial reporting(1)(2) | $ | 17,999 | $ | 18,583 | $ | 19,423 | $ | 6,723 | $ | 9,590 | $ | 8,871 | ||||||||||||||||||||||||||
(1) Net periodic pension costs for the pension plan are recognized for financial reporting based upon the authorization of each regulatory jurisdiction in which Idaho Power operates. Under an IPUC order, the Idaho portion of net periodic pension cost is recorded as a regulatory asset and is recognized in the income statement as those costs are recovered through rates.
(2) Of total net periodic pension cost recognized for financial reporting $18.2 million, $19.0 million, and $17.8 million respectively, was recognized in "Other operations and maintenance" and $6.5 million, $9.2 million, and $10.5 million respectively, was recognized in "Other (income) expense, net" on the consolidated statements of income of the companies for the twelve months ended December 31, 2023, 2022, and 2021.
The following table shows the components of other comprehensive income (loss) for the plans (in thousands of dollars):
| Pension Plan | SMSP | |||||||||||||||||||||||||||||||||||||
| 2023 | 2022 | 2021 | 2023 | 2022 | 2021 | |||||||||||||||||||||||||||||||||
| Actuarial (loss) gain during the year | $ | (25,071) | $ | 227,372 | $ | 91,156 | $ | (6,517) | $ | 32,009 | $ | (33) | ||||||||||||||||||||||||||
| Plan amendment service cost | — | — | — | (11) | — | — | ||||||||||||||||||||||||||||||||
| Reclassification adjustments for: | ||||||||||||||||||||||||||||||||||||||
| Amortization of net loss | — | 12,273 | 23,796 | 570 | 4,229 | 4,205 | ||||||||||||||||||||||||||||||||
| Amortization of prior service cost | 6 | 6 | 6 | 219 | 279 | 296 | ||||||||||||||||||||||||||||||||
| Adjustment for deferred tax effects | 6,452 | (61,686) | (29,590) | 1,477 | (9,399) | (1,150) | ||||||||||||||||||||||||||||||||
Adjustment due to the effects of regulation | 18,613 | (177,965) | (85,368) | — | — | — | ||||||||||||||||||||||||||||||||
| Other comprehensive income (loss) recognized related to pension benefit plans | $ | — | $ | — | $ | — | $ | (4,262) | $ | 27,118 | $ | 3,318 | ||||||||||||||||||||||||||
The following table summarizes the expected future benefit payments of these plans (in thousands of dollars):
| 2024 | 2025 | 2026 | 2027 | 2028 | 2029-2033 | |||||||||||||||||||||||||||||||||
| Pension Plan | $ | 49,316 | $ | 50,736 | $ | 52,275 | $ | 53,777 | $ | 55,322 | $ | 303,171 | ||||||||||||||||||||||||||
| SMSP | 6,608 | 6,761 | 6,847 | 6,887 | 6,975 | 36,320 | ||||||||||||||||||||||||||||||||
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 2023, 2022, and 2021, Idaho Power elected to contribute more than the minimum required amounts in order to bring the pension plan to a more funded position, to reduce future required contributions, and to reduce Pension Benefit Guaranty Corporation premiums. As of the date of this report, IDACORP and Idaho Power have no estimated minimum required contributions to the pension plan for 2024. Depending on market conditions and cash flow considerations in 2023, Idaho Power could contribute up to $30 million to the pension plan during 2024 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.
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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):
| 2023 | 2022 | |||||||||||||
| Change in accumulated benefit obligation: | ||||||||||||||
| Benefit obligation at January 1 | $ | 59,099 | $ | 74,075 | ||||||||||
| Service cost | 658 | 1,071 | ||||||||||||
| Interest cost | 2,980 | 2,112 | ||||||||||||
| Actuarial gain | (2,004) | (21,845) | ||||||||||||
Benefits paid(1) | (4,669) | (4,379) | ||||||||||||
| Plan amendments | — | 8,065 | ||||||||||||
| Benefit obligation at December 31 | 56,064 | 59,099 | ||||||||||||
| Change in plan assets: | ||||||||||||||
| Fair value of plan assets at January 1 | 28,565 | 41,464 | ||||||||||||
| Actual return on plan assets | 7,219 | (6,586) | ||||||||||||
Employer contributions(1) | 690 | (1,934) | ||||||||||||
Benefits paid(1) | (4,670) | (4,379) | ||||||||||||
| Fair value of plan assets at December 31 | 31,804 | 28,565 | ||||||||||||
| Funded status at end of year (included in noncurrent liabilities) | $ | (24,260) | $ | (30,534) | ||||||||||
(1) Contributions and benefits paid are each net of $2.6 million and $2.9 million of plan participant contributions for 2023 and 2022, respectively.
Amounts recognized in AOCI consist of the following (in thousands of dollars):
| 2023 | 2022 | |||||||||||||
| Net gain | $ | (27,231) | $ | (20,896) | ||||||||||
| Prior service cost | 6,184 | 7,849 | ||||||||||||
| Subtotal | (21,047) | (13,047) | ||||||||||||
| Less amount recognized in regulatory assets | 21,047 | 13,047 | ||||||||||||
| Net amount recognized in AOCI | $ | — | $ | — | ||||||||||
The net periodic postretirement benefit cost was as follows (in thousands of dollars):
| 2023 | 2022 | 2021 | ||||||||||||||||||
| Service cost | $ | 658 | $ | 1,071 | $ | 1,063 | ||||||||||||||
| Interest cost | 2,980 | 2,112 | 2,059 | |||||||||||||||||
| Expected return on plan assets | (1,650) | (2,351) | (2,395) | |||||||||||||||||
Immediate recognition of loss from temporary deviation(1) | — | — | 4,736 | |||||||||||||||||
| Amortization of net loss | (1,237) | (31) | — | |||||||||||||||||
| Amortization of prior service cost | 1,665 | 295 | 47 | |||||||||||||||||
| Net periodic postretirement benefit cost | $ | 2,416 | $ | 1,096 | $ | 5,510 | ||||||||||||||
(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):
| 2023 | 2022 | 2021 | ||||||||||||||||||
| Actuarial gain during the year | $ | 7,572 | $ | 12,908 | $ | 9,718 | ||||||||||||||
| Prior service cost arising during the year | — | (8,065) | — | |||||||||||||||||
| Reclassification adjustments for: | ||||||||||||||||||||
| Amortization of net loss | (1,237) | (31) | — | |||||||||||||||||
| Amortization of prior service cost | 1,665 | 295 | 47 | |||||||||||||||||
Immediate recognition of loss from temporary deviation(1) | — | — | 4,736 | |||||||||||||||||
| Adjustment for deferred tax effects | (2,059) | (1,315) | (2,514) | |||||||||||||||||
Adjustment due to the effects of regulation | (5,941) | (3,792) | (11,987) | |||||||||||||||||
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):
| 2024 | 2025 | 2026 | 2027 | 2028 | 2028-2032 | |||||||||||||||||||||||||||||||||
| Expected benefit payments | $ | 4,909 | $ | 4,734 | $ | 4,556 | $ | 4,386 | $ | 4,277 | $ | 19,988 | ||||||||||||||||||||||||||
Plan Assumptions
The following table sets forth the weighted-average assumptions used at the end of each year to determine benefit obligations for all Idaho Power-sponsored pension and postretirement benefits plans:
| Pension Plan | SMSP | Postretirement Benefits | ||||||||||||||||||||||||||||||||||||
| 2023 | 2022 | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||||||||||||||||
| Discount rate | 5.10 | % | 5.45 | % | 5.20 | % | 5.50 | % | 5.15 | % | 5.45 | % | ||||||||||||||||||||||||||
Rate of compensation increase(1) | 4.43 | % | 4.49 | % | 4.75 | % | 4.75 | % | — | — | ||||||||||||||||||||||||||||
| Medical trend rate | — | — | — | 7.1 | % | 6.7 | % | |||||||||||||||||||||||||||||||
| Dental trend rate | — | — | — | 3.5 | % | 3.5 | % | |||||||||||||||||||||||||||||||
| Measurement date | 12/31/2023 | 12/31/2022 | 12/31/2023 | 12/31/2022 | 12/31/2023 | 12/31/2022 | ||||||||||||||||||||||||||||||||
(1) The 2023 rate of compensation increase assumption for the pension plan includes an inflation component of 2.40% plus a 2.03% composite merit increase component that is based on employees' years of service. Merit salary increases are assumed to be 10.6% for employees in their first year of service and scale down to 3.4% for employees in their fortieth year of service and beyond.
The following table sets forth the weighted-average assumptions used to determine net periodic benefit cost for all Idaho Power-sponsored pension and postretirement benefit plans:
| Pension Plan | SMSP | Postretirement Benefits | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
| 2023 | 2022 | 2021 | 2023 | 2022 | 2021 | 2023 | 2022 | 2021 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Discount rate | 5.45 | % | 3.05 | % | 2.80 | % | 5.50 | % | 3.00 | % | 2.70 | % | 5.45 | % | 2.95 | % | 2.70 | % | ||||||||||||||||||||||||||||||||||||||
Expected long-term rate of return on assets | 7.40 | % | 7.40 | % | 7.40 | % | — | — | — | 6.00 | % | 6.00 | % | 6.00 | % | |||||||||||||||||||||||||||||||||||||||||
| Rate of compensation increase | 4.49 | % | 4.49 | % | 4.49 | % | 4.75 | % | 4.75 | % | 4.75 | % | — | — | % | — | % | |||||||||||||||||||||||||||||||||||||||
| Medical trend rate | — | — | — | — | — | — | 6.7 | % | 5.8 | % | 6.3 | % | ||||||||||||||||||||||||||||||||||||||||||||
| Dental trend rate | — | — | — | — | — | — | 3.5 | % | 3.5 | % | 3.5 | % | ||||||||||||||||||||||||||||||||||||||||||||
The assumed health care cost trend rate used to measure the expected cost of health benefits covered by the postretirement plan was 6.7 percent in 2023 and is assumed to increase to 7.1 percent in 2024, 6.5 percent in 2025, decrease to 5.8 percent in 2026,
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and to gradually decrease to 3.8 percent by 2074. The assumed dental cost trend rate used to measure the expected cost of dental benefits covered by the plan was 3.5 percent, or equal to the medical trend rate if lower, for all years.
Plan Assets
Pension Asset Allocation Policy: The target allocation and actual allocations at December 31, 2023, for the pension asset portfolio by asset class is set forth below:
| Asset Class | Target Allocation | Actual Allocation December 31, 2023 | ||||||||||||
| Debt securities | 25 | % | 24 | % | ||||||||||
| Equity securities | 56 | % | 60 | % | ||||||||||
| Real estate | 8 | % | 8 | % | ||||||||||
| Other plan assets | 11 | % | 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 debt security allocations sufficient to cover approximately five years of benefit payments. Idaho Power then utilizes growth instruments (equities, real estate, venture capital) to fund the longer-term liabilities of the plan; and
•maintain a prudent risk profile consistent with ERISA fiduciary standards.
Allowable plan investments include stocks and stock funds, investment-grade bonds and bond funds, real estate funds, private infrastructure funds, private direct lending funds, private equity funds, and cash and cash equivalents. With the exception of real estate holdings, private infrastructure holdings, private direct lending loans, and private equity, investments must be readily marketable so that an entire holding can be disposed of quickly with only a minor effect upon market price.
Rate-of-return projections for plan assets are based on historical risk/return relationships among asset classes. The primary measure is the historical risk premium each asset class has delivered versus the yield on the Moody's AA Corporate Bond Index. This historical risk premium is then added to the current yield on the Moody's AA Corporate Bond Index. Additional analysis is performed to measure the expected range of returns, as well as worst-case and best-case scenarios. Based on the current 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 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 16 - "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, 2023 | ||||||||||||||||||||||||||
| Cash and cash equivalents | $ | 28,830 | $ | — | $ | — | $ | 28,830 | ||||||||||||||||||
| Intermediate bonds | 35,747 | 182,280 | — | 218,027 | ||||||||||||||||||||||
| Equity Securities: Large-Cap | 93,879 | — | — | 93,879 | ||||||||||||||||||||||
| Equity Securities: Mid-Cap | 105,700 | — | — | 105,700 | ||||||||||||||||||||||
| Equity Securities: Small-Cap | 75,596 | — | — | 75,596 | ||||||||||||||||||||||
| Equity Securities: Micro-Cap | 37,759 | — | — | 37,759 | ||||||||||||||||||||||
| Equity Securities: Global and International | 58,401 | — | — | 58,401 | ||||||||||||||||||||||
| Equity Securities: Emerging Markets | 7,850 | — | — | 7,850 | ||||||||||||||||||||||
| Plan assets measured at NAV (not subject to hierarchy disclosure) | ||||||||||||||||||||||||||
| Commingled Fund: Equity Securities: Global and International | 131,921 | |||||||||||||||||||||||||
| Commingled Fund: Equity Securities: Emerging Markets | 40,398 | |||||||||||||||||||||||||
| Direct Lending Fund: Fixed Income | 2,970 | |||||||||||||||||||||||||
| Real estate | 74,426 | |||||||||||||||||||||||||
| Private market investments | 41,756 | |||||||||||||||||||||||||
| Total | $ | 443,762 | $ | 182,280 | $ | — | $ | 917,513 | ||||||||||||||||||
Postretirement plan assets(1) | $ | 1,726 | $ | 30,078 | $ | — | $ | 31,804 | ||||||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||||||
Assets at December 31, 2022 | ||||||||||||||||||||||||||
| Cash and cash equivalents | $ | 11,679 | $ | — | $ | — | $ | 11,679 | ||||||||||||||||||
| Intermediate bonds | 33,305 | 166,530 | — | 199,835 | ||||||||||||||||||||||
| Equity Securities: Large-Cap | 85,617 | — | — | 85,617 | ||||||||||||||||||||||
| Equity Securities: Mid-Cap | 90,049 | — | — | 90,049 | ||||||||||||||||||||||
| Equity Securities: Small-Cap | 65,505 | — | — | 65,505 | ||||||||||||||||||||||
| Equity Securities: Micro-Cap | 33,438 | — | — | 33,438 | ||||||||||||||||||||||
| Equity Securities: Global and International | 52,876 | — | — | 52,876 | ||||||||||||||||||||||
| Equity Securities: Emerging Markets | 6,964 | — | — | 6,964 | ||||||||||||||||||||||
| Plan assets measured at NAV (not subject to hierarchy disclosure) | ||||||||||||||||||||||||||
| Commingled Fund: Equity Securities: Global and International | 117,631 | |||||||||||||||||||||||||
| Commingled Fund: Equity Securities: Emerging Markets | 42,119 | |||||||||||||||||||||||||
| Real estate | 83,676 | |||||||||||||||||||||||||
| Private market investments | 50,339 | |||||||||||||||||||||||||
| Total | $ | 379,433 | $ | 166,530 | $ | — | $ | 839,728 | ||||||||||||||||||
Postretirement plan assets(1) | $ | 2,009 | $ | 26,556 | $ | — | $ | 28,565 | ||||||||||||||||||
(1) The postretirement benefits assets are primarily life insurance contracts.
For the years ended December 31, 2023 and 2022, there were no material transfers into or out of Levels 1, 2, or 3.
Fair Value Measurement of Level 2 Plan assets and Plan assets measured at NAV:
Level 2 Bonds: These investments represent United States government, agency bonds, and corporate bonds. The United States government and agency bonds, as well as the corporate bonds, are not traded on an exchange and are valued utilizing market prices for similar assets or liabilities in active markets.
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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 equal to the insurance contract's proportionate share of the market value of an associated investment account held by the insurer. The investments held by the insurer's investment account are all instruments traded on exchanges with readily determinable market prices.
Commingled Funds: These funds, made up of global, international and emerging markets equity securities are measured at NAV, are not publicly traded, and therefore no publicly quoted market price is readily available. The values of the commingled funds are presented at estimated fair value, which is determined based on the unit value of the fund. The values of these investments are calculated by the custodian for the fund company on a monthly or more frequent basis, and are based on market prices of the assets held by each of the commingled funds divided by the number of fund shares outstanding for the respective fund. The investments in commingled funds have redemption limitations that permit monthly redemption following notice requirements of 5 to 7 days.
Direct Lending Funds: Direct lending strategies are closed-end funds that provide senior secured loans primarily to private, non-investment-grade companies. Direct lending fund investments are valued by the fund companies, or an independent external advisor based on the estimated fair value of the underlying loans divided by the fund shares outstanding. These direct lending funds also furnish annual audited financial statements that are used to further validate the information provided. These closed-end funds are formed with a stated life of 6 to 10 years, which can be further extended with the approval of the limited partners. There are generally no redemption rights associated with these funds. The limited partner must hold the fund for the life of the fund or find a third-party buyer.
Real Estate: Real estate holdings represent investments in open-end and closed-end commingled real estate funds. As the property interests held in these real estate funds are not frequently traded, establishing the market value of the property interests held by the fund, and the resulting unit value of fund shareholders, is based on unobservable inputs including property appraisals by the fund companies, property appraisals by independent appraisal firms, analysis of the replacement cost of the property, discounted cash flows generated by property rents and changes in property values, and comparisons with sale prices of similar properties in similar markets. These real estate funds also furnish annual audited financial statements that are also used to further validate the information provided. Redemptions on the open-end funds are generally available on a quarterly basis, with 10 to 35 days written notice, depending on the individual fund. If the fund has sufficient liquidity, the redemption will be processed at the fund NAV or the fund’s estimate of fair value at the end of the quarter. If the fund does not have sufficient liquidity to honor the full redemption, the remainder will be set for redemption the following quarter on a pro-rata basis with other redemption requests. This same process will repeat until the redemption request has been completed. To protect other fund holders, real estate funds have no duty to liquidate or encumber funds to meet redemption requests. The closed-end funds are formed for a stated life of 7 to 10 years. The fund can be further extended with the approval of the limited partners. There are generally no redemption rights associated with these funds. The limited partner must hold the fund for the life of the fund or find a third-party buyer.
Private Market Investments: Private market investments represent two categories: venture capital funds and fund of hedge funds. 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. Venture capital fund investments are valued by the fund companies based on estimated fair value of the underlying fund holdings divided by the fund shares outstanding. Some venture capital investments have progressed to the point that they have readily available exchange-based market valuations. Early stage venture investments are valued based on unobservable inputs including cost, operating results, discounted cash flows, the price of recent funding events, or pending offers from other viable entities. These private market investments furnish annual audited financial statements that are also used to further validate the information provided. These funds are formed for a stated life of 10 to 15 years. The general partner can extend the fund life for 2 or 3 one-year periods. The fund can be further extended with the approval of the limited partners. There are generally no redemption rights associated with these funds. The limited partner must hold the fund for the life of the fund or find a third-party buyer. The value of the fund of hedge funds investment is the residual value of an immaterial non-liquid position in a single fund of hedge funds.
Employee Savings Plan
Idaho Power has a defined contribution plan designed to comply with Section 401(k) of the Internal Revenue Code and that covers substantially all employees. Idaho Power matches specified percentages of employee contributions to the plan. Matching annual contributions were approximately $9.8 million, $8.8 million, and $8.2 million in 2023, 2022, and 2021, respectively.
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Post-employment Benefits
Idaho Power provides certain benefits to former or inactive employees, their beneficiaries, and covered dependents after employment but before retirement, in addition to the health care benefits required under the Consolidated Omnibus Budget Reconciliation Act (COBRA). These benefits include salary continuation, health care and life insurance for those employees found to be disabled under Idaho Power’s disability plans, and health care for surviving spouses and dependents. Idaho Power accrues a liability for such benefits. The post-employment benefits included in other liabilities on both IDACORP’s and Idaho Power’s consolidated balance sheets at December 31, 2023 and 2022, were approximately $3 million and $2 million.
12. PROPERTY, PLANT AND EQUIPMENT AND JOINTLY-OWNED PROJECTS
The following table presents the major classifications of Idaho Power’s utility plant in service, annual depreciation provisions as a percent of average depreciable balance, and accumulated provision for depreciation for the years ended December 31, 2023 and 2022 (in thousands of dollars):
| 2023 | 2022 | |||||||||||||||||||||||||
| Balance | Avg Rate | Balance | Avg Rate | |||||||||||||||||||||||
| Production | $ | 2,794,534 | 3.50 | % | $ | 2,700,494 | 2.89 | % | ||||||||||||||||||
| Transmission | 1,392,338 | 1.90 | % | 1,346,463 | 1.91 | % | ||||||||||||||||||||
| Distribution | 2,454,458 | 2.18 | % | 2,192,135 | 2.15 | % | ||||||||||||||||||||
| General and Other | 650,202 | 5.21 | % | 589,375 | 5.36 | % | ||||||||||||||||||||
| Total in service | 7,291,532 | 2.89 | % | 6,828,467 | 2.66 | % | ||||||||||||||||||||
| Accumulated provision for depreciation | (2,557,744) | (2,465,279) | ||||||||||||||||||||||||
| In service - net | $ | 4,733,788 | $ | 4,363,188 | ||||||||||||||||||||||
At December 31, 2023, Idaho Power's construction work in progress balance of $985.5 million included relicensing costs of $459.8 million for the HCC, Idaho Power's largest hydropower complex. In 2023, 2022, and 2021, Idaho Power had IPUC authorization to include in its Idaho jurisdiction rates $6.5 million annually ($8.8 million when grossed-up for the effect of income taxes) of AFUDC relating to the HCC relicensing project. Collecting these amounts will reduce the amount collected in the future once the HCC relicensing costs are approved for recovery in base rates. At December 31, 2023, Idaho Power's regulatory liability for collection of AFUDC relating to the HCC was $228.7 million.
Idaho Power's ownership interest in two jointly-owned generating facilities is included in the table above. Under the joint operating agreements for these facilities, each participating utility is responsible for financing its share of construction, operating, and leasing costs. Idaho Power's proportionate share of operating expenses for each facility is included in the Consolidated Statements of Income. These jointly-owned facilities, including balance sheet amounts and the extent of Idaho Power’s participation, were as follows at December 31, 2023 (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 | $ | 770,179 | $ | 12,891 | $ | 500,685 | 33 | 775 | |||||||||||||||||||||||||||||
North Valmy unit 2(2) | Winnemucca, NV | 262,544 | 2,237 | 225,147 | 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.
IERCo, Idaho Power’s wholly-owned subsidiary, is a joint-owner of BCC. Idaho Power’s coal purchases from BCC were $67.9 million in 2023, $60.4 million in 2022, and $59.7 million in 2021.
13. ASSET RETIREMENT OBLIGATIONS (ARO)
The guidance relating to accounting for AROs requires that legal obligations associated with the retirement of property, plant, and equipment be recognized as a liability at fair value when incurred and when a reasonable estimate of the fair value of the liability can be made. Under the guidance, when a liability is initially recorded, the entity increases the carrying amount of the related long-lived asset to reflect the future retirement cost. Over time, the liability is accreted to its estimated settlement value
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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 defers accretion, depreciation, and gains or losses as regulatory assets, as approved by the IPUC, until such ARO costs are included in customer rates for collection. The regulatory assets recorded under this order do not earn a return on investment.
Idaho Power’s recorded AROs relate to the reclamation and removal costs at its jointly-owned coal-fired generation facilities. In 2023, changes in estimates at the coal-fired generation facilities resulted in a net increase of $11.3 million in the recorded AROs. The increase is primarily related to cost estimates for a flue gas desulfurization pond placed in-service during 2023 at the Jim Bridger plant.
Idaho Power also has additional AROs associated with its transmission system and generation facilities; however, due to the indeterminate removal date, the fair value of the associated liabilities currently cannot be estimated and no amounts are recognized in the consolidated financial statements.
Idaho Power also collects removal costs in rates for certain assets that do not have associated AROs. Idaho Power is required to classify these removal costs as regulatory liabilities, see Note 3 - "Regulatory Matters" for the removal costs recorded as regulatory liabilities on IDACORP’s and Idaho Power’s consolidated balance sheets as of December 31, 2023 and 2022.
The following table presents the changes in the carrying amount of AROs (in thousands of dollars):
| 2023 | 2022 | |||||||||||||
| Balance at beginning of year | $ | 37,557 | $ | 36,698 | ||||||||||
| Accretion expense | 1,176 | 1,106 | ||||||||||||
| Revisions in estimated cash flows | 11,348 | 1,412 | ||||||||||||
| Liability settled | (1,084) | (1,659) | ||||||||||||
| Balance at end of year | $ | 48,997 | $ | 37,557 | ||||||||||
14. INVESTMENTS
The table below summarizes IDACORP’s and Idaho Power’s investments as of December 31 (in thousands of dollars):
| 2023 | 2022 | |||||||||||||
| Idaho Power investments: | ||||||||||||||
| Bridger Coal Company (equity method investment) | $ | 24,078 | $ | 14,187 | ||||||||||
| Exchange traded short-term bond funds and cash equivalents | 36,617 | 33,687 | ||||||||||||
| Held-to-Maturity securities | 31,639 | 30,475 | ||||||||||||
| Executive deferred compensation plan investments | 703 | 442 | ||||||||||||
| Total Idaho Power investments | 93,037 | 78,791 | ||||||||||||
| IFS investments in real estate tax credit projects, such as affordable housing developments | 57,286 | 29,454 | ||||||||||||
| Ida-West joint ventures (equity method investments) | 9,897 | 10,311 | ||||||||||||
| Other investments | 3,751 | 2,796 | ||||||||||||
| Total IDACORP investments | $ | 163,971 | $ | 121,352 | ||||||||||
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
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dollars):
| 2023 | 2022 | 2021 | ||||||||||||||||||||||||
| Bridger Coal Company (Idaho Power) | $ | 10,540 | $ | 10,211 | $ | 10,211 | ||||||||||||||||||||
| Ida-West joint ventures | 1,886 | 1,300 | 1,224 | |||||||||||||||||||||||
| Total | $ | 12,426 | $ | 11,511 | $ | 11,435 | ||||||||||||||||||||
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, 2023 and 2022. The following table summarizes sales of equity securities (in thousands of dollars):
| 2023 | 2022 | 2021 | ||||||||||||||||||||||||
| Proceeds from sales | $ | 8,921 | $ | 63,857 | $ | 11,328 | ||||||||||||||||||||
| Gross realized gains from sales | — | — | — | |||||||||||||||||||||||
Held-to-Maturity Securities
Idaho Power has a rabbi trust designated to provide funding for obligations related to the SMSP. During 2023 and 2022, the rabbi trust purchased $1.6 million and $31.2 million, respectively of held-to-maturity investments in corporate fixed-income and asset-backed debt securities. Substantially all of these debt securities mature between 2027 and 2037. Held-to-maturity investments are carried at amortized cost, reflecting Idaho Power’s ability and intent to hold the securities to maturity. Held-to-maturity investments are adjusted for the amortization or accretion of premiums or discounts, which are amortized or accreted over the life of the related held-to-maturity security. Such amortization and accretion are included in the “Other income, net” line in the consolidated statements of income. Due to increases in market interest rates in 2023 and 2022, all held-to-maturity securities were in a gross unrealized holding loss position totaling $3.3 million and $5.0 million at December 31, 2023 and December 31, 2022, respectively. Based on ongoing credit evaluations of these holdings, Idaho Power does not expect material payment defaults or delinquencies and has not recorded an allowance for credit losses for these securities as of December 31, 2023 and 2022.
IDACORP Financial Services Investments
IFS invests primarily in real estate tax credit projects, such as affordable housing developments, which provide a return principally by reducing federal and state income taxes through tax credits and accelerated tax depreciation benefits. IFS has focused on a diversified approach to its investment strategy in order to limit both geographic and operational risk, with most of IFS’s investments having been made through syndicated funds. IDACORP accounts for its equity-method investments in qualified real estate projects using the proportional amortization method and recognizes the net investment performance in the consolidated statements of income as a component of income tax expense.
15. DERIVATIVE FINANCIAL INSTRUMENTS
Commodity Price Risk
Idaho Power is exposed to market risk relating to electricity, natural gas, and other fuel commodity prices, all of which are heavily influenced by supply and demand. Market risk may be influenced by market participants’ nonperformance of their contractual obligations and commitments, which affects the supply of or demand for the commodity. Idaho Power uses derivative instruments, such as physical and financial forward contracts, for both electricity and fuel to manage the risks relating to these commodity price exposures. The primary objectives of Idaho Power’s energy purchase and sale activity are to meet the demand of retail electric customers, maintain appropriate physical reserves to ensure reliability, and make economic use of temporary surpluses that may develop.
All of Idaho Power's derivative instruments have been entered into for the purpose of securing energy resources for future periods or economically hedging forecasted purchases and sales, though none of these instruments have been designated as cash flow hedges. Idaho Power offsets fair value amounts recognized on its balance sheet and applies collateral related to derivative instruments executed with the same counterparty under the same master netting agreement. Idaho Power does not offset a counterparty's current derivative contracts with the counterparty's long-term derivative contracts, although Idaho Power's master
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netting arrangements would allow current and long-term positions to be offset in the event of default. Also, in the event of default, Idaho Power's master netting arrangements would allow for the offsetting of all transactions executed under the master netting arrangement. These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, receivables and payables arising from settled positions, and other forms of non-cash collateral (such as letters of credit). These types of transactions are excluded from the offsetting presented in the derivative fair value and offsetting table that follows.
The table below presents the gains and losses on derivatives not designated as hedging instruments for the years ended December 31, 2023, 2022, and 2021 (in thousands of dollars):
| Location of Realized Gain/(Loss) on Derivatives Recognized in Income | Gain/(Loss) on Derivatives Recognized in Income(1) | |||||||||||||||||||||||||
| 2023 | 2022 | 2021 | ||||||||||||||||||||||||
| Financial swaps | Operating revenues | $ | 4,216 | $ | (6,249) | $ | 1,046 | |||||||||||||||||||
| Financial swaps | Purchased power | (8,542) | 2,373 | 1,959 | ||||||||||||||||||||||
| Financial swaps | Fuel expense | (16,209) | 68,489 | 12,180 | ||||||||||||||||||||||
| Forward contracts | Operating revenues | 2,280 | 1,090 | 1,966 | ||||||||||||||||||||||
| Forward contracts | Purchased power | (4,035) | (2,994) | (1,099) | ||||||||||||||||||||||
| Forward contracts | Fuel expense | (866) | (136) | (194) | ||||||||||||||||||||||
(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 16 - "Fair Value Measurements" for additional information concerning the determination of fair value for Idaho Power’s assets and liabilities from price risk management activities.
Credit Risk
At December 31, 2023, Idaho Power did not have material credit risk exposure from financial instruments, including derivatives. Idaho Power monitors credit risk exposure through reviews of counterparty credit quality, corporate-wide counterparty credit exposure, and corporate-wide counterparty concentration levels. Idaho Power manages these risks by establishing credit and concentration limits on transactions with counterparties and requiring contractual guarantees, cash deposits, or letters of credit from counterparties or their affiliates, as deemed necessary. Idaho Power’s physical power contracts are commonly under WSPP, Inc. agreements, physical gas contracts are usually under North American Energy Standards Board contracts, and financial transactions are usually under International Swaps and Derivatives Association, Inc. contracts. These contracts typically contain adequate assurance clauses requiring collateralization if a counterparty has debt that is downgraded below investment grade by at least one rating agency.
Credit-Contingent Features
Certain of Idaho Power's derivative instruments contain provisions that require Idaho Power's unsecured debt to maintain an investment grade credit rating from Moody's and Standard & Poor's Ratings Services. If Idaho Power's unsecured debt were to fall below investment grade, it would be in violation of these provisions, and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions. The aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a liability position at December 31, 2023, was $63.9 million. Idaho Power posted $53.3 million cash collateral related to this amount. If the credit-risk-related contingent features underlying these agreements were triggered on December 31, 2023, Idaho Power would have been required to pay or post collateral to its counterparties up to an additional $14.2 million to cover open liability positions as well as completed transactions that have not yet been paid.
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Derivative Instrument Summary
The table below presents the fair values and locations of derivative instruments not designated as hedging instruments recorded on the balance sheets and reconciles the gross amounts of derivatives recognized as assets and as liabilities to the net amounts presented in the balance sheets at December 31, 2023 and 2022 (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, 2023 | ||||||||||||||||||||||||||||||||||||||||||||
| Current: | ||||||||||||||||||||||||||||||||||||||||||||
| Financial swaps | Other current assets | $ | 241 | $ | (169) | $ | 72 | $ | 169 | $ | (169) | $ | — | |||||||||||||||||||||||||||||||
| Financial swaps | Other current liabilities | 1,476 | (1,476) | — | 41,977 | (38,045) | (1) | 3,932 | ||||||||||||||||||||||||||||||||||||
| Forward contracts | Other current liabilities | — | — | — | 2,000 | — | 2,000 | |||||||||||||||||||||||||||||||||||||
| Long-term: | ||||||||||||||||||||||||||||||||||||||||||||
| Financial swaps | Other assets | 106 | (89) | 17 | 89 | (89) | — | |||||||||||||||||||||||||||||||||||||
| Financial swaps | Other liabilities | 376 | (376) | — | 2,123 | (2,123) | (2) | — | ||||||||||||||||||||||||||||||||||||
| Total | $ | 2,199 | $ | (2,110) | $ | 89 | $ | 46,358 | $ | (40,426) | $ | 5,932 | ||||||||||||||||||||||||||||||||
| December 31, 2022 | ||||||||||||||||||||||||||||||||||||||||||||
| Current: | ||||||||||||||||||||||||||||||||||||||||||||
| Financial swaps | Other current assets | $ | 72,548 | $ | (32,609) | (3) | $ | 39,939 | $ | 13,982 | $ | (13,982) | $ | — | ||||||||||||||||||||||||||||||
| Financial swaps | Other current liabilities | 132 | (132) | — | 1,577 | (132) | 1,445 | |||||||||||||||||||||||||||||||||||||
| Forward contracts | Other current assets | 400 | — | 400 | — | — | — | |||||||||||||||||||||||||||||||||||||
| Forward contracts | Other current liabilities | — | — | — | 2,071 | — | 2,071 | |||||||||||||||||||||||||||||||||||||
| Long-term: | ||||||||||||||||||||||||||||||||||||||||||||
| Financial swaps | Other assets | 622 | (43) | 579 | 43 | (43) | — | |||||||||||||||||||||||||||||||||||||
| Financial swaps | Other liabilities | 644 | (644) | — | 2,136 | (644) | 1,492 | |||||||||||||||||||||||||||||||||||||
| Forward contracts | Other liabilities | — | — | — | 1,780 | — | 1,780 | |||||||||||||||||||||||||||||||||||||
| Total | $ | 74,346 | $ | (33,428) | $ | 40,918 | $ | 21,589 | $ | (14,801) | $ | 6,788 | ||||||||||||||||||||||||||||||||
(1) Current liability derivative amounts offset include $36.6 million of collateral receivable at December 31, 2023.
(2) Long-term liability derivative amounts offset include $1.7 million of collateral receivable at December 31, 2023.
(3) Current asset derivative amounts offset include $18.6 million of collateral payable at December 31, 2022.
The table below presents the volumes of derivative commodity forward contracts and swaps outstanding at December 31, 2023 and 2022 (in thousands of units):
| December 31, | ||||||||||||||||||||
| Commodity | Units | 2023 | 2022 | |||||||||||||||||
| Electricity purchases | MWh | 440 | 898 | |||||||||||||||||
| Electricity sales | MWh | 57 | 32 | |||||||||||||||||
| Natural gas purchases | MMBtu | 24,593 | 26,773 | |||||||||||||||||
| Natural gas sales | MMBtu | — | 310 | |||||||||||||||||
16. FAIR VALUE MEASUREMENTS
IDACORP and Idaho Power have categorized their financial instruments into a three-level fair value hierarchy, based on the priority of the inputs to the valuation technique. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). If the inputs used to measure the financial instruments fall within different levels of the hierarchy, the categorization is based on the lowest level input that is significant to the fair value measurement of the instrument.
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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 or using quoted price which may be in non-active markets.
• Level 3: Financial assets and liabilities whose values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. These inputs reflect management’s own assumptions about the assumptions a market participant would use in pricing the asset or liability.
IDACORP’s and Idaho Power’s assessment of a particular input's significance to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy. There were no transfers between levels or material changes in valuation techniques or inputs during the years ended December 31, 2023 and 2022.
Certain instruments have been valued using NAV as a practical expedient. The NAV is generally not published and publicly available, nor are these instruments traded on an exchange. Instruments valued using NAV as a practical expedient are included in the fair value disclosures below; however, in accordance with GAAP are not classified within the fair value hierarchy levels.
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, 2023 and 2022 (in thousands of dollars):
| December 31, 2023 | December 31, 2022 | |||||||||||||||||||||||||||||||||||||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||||||||||||||||||||||||||
| Assets: | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Money market funds and commercial paper | ||||||||||||||||||||||||||||||||||||||||||||||||||
IDACORP(1) | $ | 32,472 | $ | — | $ | — | $ | 32,472 | $ | 16,505 | $ | — | $ | — | $ | 16,505 | ||||||||||||||||||||||||||||||||||
| Idaho Power | 230,600 | — | — | 230,600 | 34,468 | — | — | 34,468 | ||||||||||||||||||||||||||||||||||||||||||
| 89 | — | — | 89 | 40,518 | 400 | — | 40,918 | |||||||||||||||||||||||||||||||||||||||||||
| Equity securities | 37,320 | — | — | 37,320 | 34,129 | — | — | 34,129 | ||||||||||||||||||||||||||||||||||||||||||
IDACORP assets measured at NAV (not subject to hierarchy disclosure)(1) | — | — | — | 3,751 | — | — | — | 2,796 | ||||||||||||||||||||||||||||||||||||||||||
| Liabilities: | ||||||||||||||||||||||||||||||||||||||||||||||||||
| $ | 3,932 | $ | 2,000 | $ | — | $ | 5,932 | $ | 2,937 | $ | 3,851 | $ | — | $ | 6,788 | |||||||||||||||||||||||||||||||||||
(1) Holding company only. Does not include amounts held by Idaho Power.
Idaho Power’s derivatives are contracts entered into as part of its management of loads and resources. Electricity swap derivatives are valued on the Intercontinental Exchange (ICE) with quoted prices in an active market. Electricity forward contract derivatives are valued using a blend of two electricity exchanges, adjusted for location basis, as specified in the forward contract. Natural gas and diesel derivatives are valued using New York Mercantile Exchange (NYMEX) and ICE 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, 2023 and 2022, using available market information and appropriate valuation methodologies (in thousands of dollars).
| December 31, 2023 | December 31, 2022 | |||||||||||||||||||||||||
| Carrying Amount | Estimated Fair Value | Carrying Amount | Estimated Fair Value | |||||||||||||||||||||||
| (thousands of dollars) | ||||||||||||||||||||||||||
| IDACORP | ||||||||||||||||||||||||||
| Assets: | ||||||||||||||||||||||||||
Notes receivable(1) | $ | 3,038 | $ | 3,038 | $ | 3,871 | $ | 3,871 | ||||||||||||||||||
Held-to-maturity securities(1) | 31,639 | 28,341 | 30,475 | 25,452 | ||||||||||||||||||||||
| Liabilities: | ||||||||||||||||||||||||||
Long-term debt (including current portion)(1) | 2,825,590 | 2,684,278 | 2,194,145 | 1,953,470 | ||||||||||||||||||||||
| Idaho Power | ||||||||||||||||||||||||||
| Assets: | ||||||||||||||||||||||||||
Held-to-maturity securities(1) | $ | 31,639 | $ | 28,341 | $ | 30,475 | $ | 25,452 | ||||||||||||||||||
| Liabilities: | ||||||||||||||||||||||||||
Long-term debt (including current portion)(1) | 2,825,590 | 2,684,278 | 2,194,145 | 1,953,470 | ||||||||||||||||||||||
(1) Notes receivable are categorized as Level 3 and held-to-maturity securities and long-term debt are categorized as Level 2 of the fair value hierarchy, as defined earlier in this Note 16 - "Fair Value Measurements."
Notes receivable are related to Ida-West and are valued based on unobservable inputs, including forecasted cash flows, which are partially based on expected hydropower conditions. Held-to-maturity securities are held in a rabbi trust and are generally valued using quoted prices, which may be in non-active markets. Long-term debt is not traded on an exchange and is valued using quoted rates for similar debt in active markets. Carrying values for cash and cash equivalents, deposits, customer and other receivables, notes payable, accounts payable, interest accrued, and taxes accrued approximate fair value.
17. SEGMENT INFORMATION
IDACORP’s only reportable segment is utility operations. The utility operations segment’s primary source of revenue is the regulated operations of Idaho Power. Idaho Power’s regulated operations include the generation, transmission, distribution, purchase, and sale of electricity. This segment also includes income from IERCo, a wholly-owned subsidiary of Idaho Power that is also subject to regulation and is a one-third owner of BCC, an unconsolidated investment.
IDACORP’s other operating segments are below the quantitative and qualitative thresholds for reportable segments and are included in the “All Other” category in the table below. This category is comprised of IFS’s investments in affordable housing and other real estate tax credits, Ida-West’s joint venture investments in small hydropower generation projects, and IDACORP’s holding company expenses.
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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 | |||||||||||||||||||||||
| 2023 | ||||||||||||||||||||||||||
| Revenues | $ | 1,762,894 | $ | 3,462 | $ | — | $ | 1,766,356 | ||||||||||||||||||
| Operating income | 313,379 | 98 | — | 313,477 | ||||||||||||||||||||||
| Other income, net | 51,424 | (46) | — | 51,378 | ||||||||||||||||||||||
| Interest income including carrying charges on regulatory assets | 26,509 | 4,688 | (2,832) | 28,365 | ||||||||||||||||||||||
| Equity-method income | 10,540 | 1,886 | — | 12,426 | ||||||||||||||||||||||
| Interest expense | 116,117 | 3,172 | (2,832) | 116,457 | ||||||||||||||||||||||
| Income before income taxes | 285,736 | 3,453 | — | 289,189 | ||||||||||||||||||||||
| Income tax expense (benefit) | 28,926 | (1,630) | — | 27,296 | ||||||||||||||||||||||
| Net Income attributable to IDACORP, Inc. | 256,810 | 4,385 | — | 261,195 | ||||||||||||||||||||||
| Total assets | 8,323,531 | 228,681 | (76,294) | 8,475,918 | ||||||||||||||||||||||
| Expenditures for long-lived assets | 610,913 | 224 | — | 611,137 | ||||||||||||||||||||||
| 2022 | ||||||||||||||||||||||||||
| Revenues | $ | 1,641,040 | $ | 2,941 | $ | — | $ | 1,643,981 | ||||||||||||||||||
| Operating income | 327,170 | 8 | — | 327,178 | ||||||||||||||||||||||
| Other income, net | 33,876 | (187) | — | 33,689 | ||||||||||||||||||||||
| Interest income including carrying charges on regulatory assets | 12,556 | 2,776 | (931) | 14,401 | ||||||||||||||||||||||
| Equity-method income | 10,211 | 1,300 | — | 11,511 | ||||||||||||||||||||||
| Interest expense | 89,038 | 1,268 | (931) | 89,375 | ||||||||||||||||||||||
| Income before income taxes | 294,775 | 2,629 | — | 297,404 | ||||||||||||||||||||||
| Income tax expense (benefit) | 39,908 | (2,064) | — | 37,844 | ||||||||||||||||||||||
| Net Income attributable to IDACORP, Inc. | 254,867 | 4,115 | — | 258,982 | ||||||||||||||||||||||
| Total assets | 7,411,104 | 245,762 | (113,608) | 7,543,258 | ||||||||||||||||||||||
| Expenditures for long-lived assets | 432,430 | 159 | — | 432,589 | ||||||||||||||||||||||
| 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 including carrying charges on regulatory assets | 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 | ||||||||||||||||||||||
| Net 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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18. OTHER INCOME AND EXPENSE
The following table presents the components of IDACORP’s other income (expense), net and Idaho Power's other income (expense), net (in thousands of dollars):
| IDACORP | 2023 | 2022 | 2021 | |||||||||||||||||
| Interest and dividend income, net | $ | 15,266 | $ | 5,952 | $ | 1,408 | ||||||||||||||
| Carrying charges on regulatory assets | 13,099 | 7,032 | 5,034 | |||||||||||||||||
Pension and postretirement non-service costs(1) | (6,513) | (9,196) | (15,249) | |||||||||||||||||
| Income from life insurance investments | 8,384 | 7,107 | 5,203 | |||||||||||||||||
| Other income (expense) | 6,286 | (90) | 463 | |||||||||||||||||
| Total other income (expense), net | $ | 36,522 | $ | 10,805 | $ | (3,141) | ||||||||||||||
| Idaho Power | ||||||||||||||||||||
| Interest and dividend income, net | $ | 13,410 | $ | 4,094 | $ | 1,241 | ||||||||||||||
| Carrying charges on regulatory assets | 13,099 | 7,032 | 5,034 | |||||||||||||||||
Pension and postretirement non-service costs(1) | (6,513) | (9,196) | (15,240) | |||||||||||||||||
| Income from life insurance investments | 8,384 | 7,012 | 5,203 | |||||||||||||||||
| Other income (expense) | 6,333 | 205 | 591 | |||||||||||||||||
| Total other income (expense), net | $ | 34,713 | $ | 9,147 | $ | (3,171) | ||||||||||||||
(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 11 - "Benefit Plans."
19. CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME
Comprehensive income includes net income and amounts related to the SMSP. The table below presents changes in components of AOCI, net of tax, during the years ended December 31, 2023, 2022, and 2021 (in thousands of dollars). Items in parentheses indicate reductions to AOCI.
| Year Ended December 31, | ||||||||||||||||||||
| 2023 | 2022 | 2021 | ||||||||||||||||||
| Defined benefit pension items | ||||||||||||||||||||
| Balance at beginning of period | $ | (12,922) | $ | (40,040) | $ | (43,358) | ||||||||||||||
Other comprehensive income before reclassifications, net of tax of $(1,680), $8,239, and $(8) | (4,848) | 23,770 | (25) | |||||||||||||||||
Amounts reclassified out of AOCI to net income, net of tax of $203, $1,160, and $1,158 | 586 | 3,348 | 3,343 | |||||||||||||||||
| Net current-period other comprehensive income | (4,262) | 27,118 | 3,318 | |||||||||||||||||
| Balance at end of period | $ | (17,184) | $ | (12,922) | $ | (40,040) | ||||||||||||||
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The table below presents the effects on net income of amounts reclassified out of components of AOCI and the income statement location of those amounts reclassified during the years ended December 31, 2023, 2022, and 2021 (in thousands of dollars). Items in parentheses indicate increases to net income.
| Amount Reclassified from AOCI | ||||||||||||||||||||
| Year Ended December 31, | ||||||||||||||||||||
| 2023 | 2022 | 2021 | ||||||||||||||||||
Amortization of defined benefit pension items(1) | ||||||||||||||||||||
| Prior service cost | $ | 219 | $ | 279 | $ | 296 | ||||||||||||||
| Net loss | 570 | 4,229 | 4,205 | |||||||||||||||||
| Total before tax | 789 | 4,508 | 4,501 | |||||||||||||||||
Tax benefit(2) | (203) | (1,160) | (1,158) | |||||||||||||||||
| Net of tax | 586 | 3,348 | 3,343 | |||||||||||||||||
| Total reclassification for the period | $ | 586 | $ | 3,348 | $ | 3,343 | ||||||||||||||
(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.
20. RELATED PARTY TRANSACTIONS
IDACORP: Idaho Power performs corporate functions such as financial, legal, and management services for IDACORP and its subsidiaries. Idaho Power charges IDACORP for the costs of these services based on service agreements and other specifically identified costs. For these services, Idaho Power billed IDACORP $1.1 million in 2023, $0.9 million in 2022, and $0.8 million in 2021.
At December 31, 2023 and 2022, Idaho Power had a $16.2 million and $56.2 million payable to IDACORP, respectively, which was included in its accounts payable to affiliates balance on its consolidated balance sheets, primarily related to income tax payments. At IDACORP, the receivable from Idaho Power is eliminated in consolidation.
Ida-West: Idaho Power purchases all of the power generated by four of Ida-West’s 50 percent owned PURPA qualifying hydropower projects located in Idaho. Idaho Power purchased $9.1 million in 2023, $7.9 million in 2022, and $8.2 million in 2021 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, 2023 and 2022, the related consolidated statements of income, comprehensive income, equity, and cash flows, for each of the three years in the period ended December 31, 2023, and the related notes and the schedules listed in the Index at Item 8 (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 15, 2024, expressed an unqualified opinion on the Company’s internal control over financial reporting.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Regulation of Utility Operations - Refer to Notes 1 and 3 to the financial statements
Critical Audit Matter Description
Idaho Power Company ("Idaho Power"), the principal operating subsidiary of the Company, is subject to rate regulation by the Federal Energy Regulatory Commission 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. 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 complexity in applying the specialized rules to account for the effects of cost-based rate regulation and the recording of regulatory assets and liabilities. Given that complexity, performing audit procedures to evaluate the Company’s application of the specialized rules to account for the effects of cost-based rate regulation and the recording of regulatory assets and liabilities required specialized knowledge of accounting for rate regulation and the rate-setting process.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the specialized rules to account for the effects of cost-based rate regulation, including the application of flow-through accounting for income taxes included the following, among others:
•We tested the effectiveness of management’s controls over the recording of regulatory assets and liabilities in accordance with specialized rules to account for the effects of cost-based rate regulation.
•We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
•For selected regulatory assets and liabilities, we evaluated whether management had determined such amounts in accordance with regulatory orders and whether it was probable that such amounts will be recovered from or returned to customers in future rates.
•With the assistance of income tax specialists, we evaluated whether management had appropriately identified the income tax timing differences eligible for flow-through accounting and recorded such differences as adjustments to income tax expense and regulatory assets.
/s/ DELOITTE & TOUCHE LLP
Boise, Idaho
February 15, 2024
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, 2023 and 2022, the related consolidated statements of income, comprehensive income, retained earnings, and cash flows, for each of the three years in the period ended December 31, 2023, and the related notes and the schedule listed in the Index at Item 8 (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 15, 2024, expressed an unqualified opinion on the Company’s internal control over financial reporting.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Regulation of Utility Operations - Refer to Notes 1 and 3 to the financial statements
Critical Audit Matter Description
The Company is subject to rate regulation by the Federal Energy Regulatory Commission 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. 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 complexity in applying the specialized rules to account for the effects of cost-based rate regulation and the recording of regulatory assets and liabilities. Given that complexity, performing audit procedures to evaluate the Company's application of the specialized rules to account for the effects of cost-based rate regulation and the recording of regulatory assets and liabilities required specialized knowledge of accounting for rate regulation and the rate-setting process.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the specialized rules to account for the effects of cost-based rate regulation, including the application of flow-through accounting for income taxes, included the following, among others:
•We tested the effectiveness of management’s controls over the recording of regulatory assets and liabilities in accordance with specialized rules to account for the effects of cost-based rate regulation.
•We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
•For selected regulatory assets and liabilities, we evaluated whether management had determined such amounts in accordance with regulatory orders and whether it was probable that such amounts will be recovered from or returned to customers in future rates.
•With the assistance of income tax specialists, we evaluated whether management had appropriately identified the income tax timing differences eligible for flow-through accounting and recorded such differences as adjustments to income tax expense and regulatory assets.
/s/ DELOITTE & TOUCHE LLP
Boise, Idaho
February 15, 2024
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, based on their evaluation of IDACORP’s disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of December 31, 2023, have concluded that IDACORP’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 Exchange Act 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, 2023. In making this assessment, the company’s management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework (2013).
Based on its assessment, management concluded that, as of December 31, 2023, IDACORP’s internal control over financial reporting is effective based on those criteria.
IDACORP’s independent registered public accounting firm has audited the financial statements included in this Annual Report on Form 10-K for the year ended December 31, 2023, 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, 2023.
February 15, 2024
132
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, 2023, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2023, of the Company and our report dated February 15, 2024, expressed an unqualified opinion on those financial statements.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ DELOITTE & TOUCHE LLP
Boise, Idaho
February 15, 2024
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Disclosure Controls and Procedures - Idaho Power Company
The Chief Executive Officer and Chief Financial Officer of Idaho Power, based on their evaluation of Idaho Power's disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of December 31, 2023, have concluded that Idaho Power'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 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 Exchange Act 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, 2023. In making this assessment, the company’s management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework (2013).
Based on its assessment, management concluded that, as of December 31, 2023, Idaho Power’s internal control over financial reporting is effective based on those criteria.
Idaho Power’s independent registered public accounting firm has audited the financial statements included in this Annual Report on Form 10-K for the year ended December 31, 2023, and issued a report which appears on the next page and expresses an unqualified opinion on the effectiveness of Idaho Power’s internal control over financial reporting as of December 31, 2023.
February 15, 2024
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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, 2023, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2023, of the Company and our report dated February 15, 2024, expressed an unqualified opinion on those financial statements.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ DELOITTE & TOUCHE LLP
Boise, Idaho
February 15, 2024
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Changes in Internal Control Over Financial Reporting - IDACORP, Inc. and Idaho Power Company
There have been no changes in IDACORP’s or Idaho Power’s internal control over financial reporting during the quarter ended December 31, 2023, that have materially affected, or are reasonably likely to materially affect, IDACORP’s or Idaho Power’s internal control over financial reporting.
ITEM 9B. OTHER INFORMATION
During the three months ended December 31, 2023, none of IDACORP's or Idaho Power's directors or officers (as defined in
Rule 16a-1(f) of the Exchange Act) adopted, terminated, or modified a Rule 10b5-1 trading arrangement or
non-Rule 10b5-1 trading arrangement (as such terms are defined in Item 408 of Regulation S-K).
ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS
Not applicable.
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE
The portions of IDACORP’s definitive proxy statement appearing under the captions “Proposal No. 1: Election of Directors,” “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 2024 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 2024 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 2024 annual meeting of shareholders is hereby incorporated by reference. The table below includes information as of December 31, 2023, with respect to the LTICP pursuant to which equity securities of IDACORP may be issued.
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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The portions of IDACORP’s definitive proxy statement appearing under the captions “Certain Relationships and Related Transactions” and “Corporate Governance at IDACORP – Director Independence and Executive Sessions” to be filed pursuant to Regulation 14A for the 2024 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 2024 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, 2023 and 2022:
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 2023 and 2022, 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 Chair of the audit committee pre-approval authority for proposed services; however, the Chair 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 Chair, as the case may be, for pre-approval.
In determining whether to pre-approve the engagement of the independent public accounting firm, the audit committee or the committee Chair, as the case may be, must consider, among other things, the pre-approval policy, applicable rules and regulations, and whether the nature of the engagement and the related fees are consistent with the following principles:
• the independent public accounting firm cannot function in the role of management of Idaho Power; and
• the independent public accounting firm cannot audit its own work.
The pre-approval policy and separate supplements to the pre-approval policy describe the specific audit, audit-related, 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, 2023, are filed to provide information regarding their terms and are not intended to provide any other factual or disclosure information about IDACORP, Inc., Idaho Power Company, or the other parties to the agreements. Some of the agreements contain statements, representations, and warranties by each of the parties to the applicable agreement. These representations and warranties have been made solely for the benefit of the other parties to the applicable agreement and (a) in all instances should not be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties to the agreement if those statements prove to be inaccurate; (b) have been qualified by disclosures that were made to the other party, which disclosures are not necessarily reflected in the agreement; (c) may apply standards of materiality in a way that is different from what may be viewed as material to investors; and (d) were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement and are subject to more recent developments. Accordingly, readers should not rely upon the statements, representations, or warranties made in the agreements.
| Incorporated by Reference | ||||||||||||||||||||
| Exhibit No. | Exhibit 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 | |||||||||||||||
138
139
140
| Incorporated by Reference | ||||||||||||||||||||
| Exhibit No. | Exhibit Description | Form | File No. | Exhibit No. | Date | Included Herewith | ||||||||||||||
| 4.7 | 8-K | 1-14465 | 4.2 | 2/28/2001 | ||||||||||||||||
| 4.8 | S-3 | 333-67748 | 4.13 | 8/16/2001 | ||||||||||||||||
| 4.9 | 10-Q | 1-3198 | 4.12 | 8/5/2010 | ||||||||||||||||
| 4.10 | X | |||||||||||||||||||
| 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 | 12/11/2023 | ||||||||||||||||
| 10.9 | 8-K | 1-14465, 1-3198 | 10.2 | 12/11/2023 | ||||||||||||||||
| 10.10 | 8-K | 1-14465 | 10.1 | 11/9/2023 | ||||||||||||||||
| 10.11 | 8-K | 1-14465 | 10.2 | 11/9/2023 | ||||||||||||||||
| 10.12 | 8-K | 1-3198 | 10.1 | 10/10/2006 | ||||||||||||||||
| 10.13 | 10-Q | 1-3198 | 10(c) | 8/4/2000 | ||||||||||||||||
10.141 | 10-K | 1-14465, 1-3198 | 10.15 | 2/26/2009 | ||||||||||||||||
10.151 | 10-Q | 1-14465, 1-3198 | 10.62 | 11/1/2012 | ||||||||||||||||
141
| Incorporated by Reference | ||||||||||||||||||||
| Exhibit No. | Exhibit Description | Form | File No. | Exhibit No. | Date | Included Herewith | ||||||||||||||
10.161 | 10-K | 1-14465, 1-3198 | 10.31 | 2/23/2017 | ||||||||||||||||
10.171 | 10-Q | 1-14465, 1-3198 | 10.1 | 8/3/2017 | ||||||||||||||||
10.181 | 10-Q | 1-14465, 1-3198 | 10(h)(viii) | 11/2/2006 | ||||||||||||||||
10.191 | 10-K | 1-14465, 1-3198 | 10.21 | 2/17/2022 | ||||||||||||||||
10.201 | 10-Q | 1-14465, 1-3198 | 10(h)(xix) | 11/2/2006 | ||||||||||||||||
10.211 | 10-Q | 1-14465, 1-3198 | 10(h)(xx) | 11/2/2006 | ||||||||||||||||
10.221 | 10-K | 1-14465, 1-3198 | 10.24 | 2/26/2009 | ||||||||||||||||
10.231 | 10-K | 1-14465, 1-3198 | 10.25 | 2/26/2009 | ||||||||||||||||
10.241 | 8-K | 1-14465, 1-3198 | 10.1 | 3/24/2010 | ||||||||||||||||
10.251 | X | |||||||||||||||||||
10.261 | 10-K | 1-14465, 1-3198 | 10.41 | 2/23/2017 | ||||||||||||||||
10.271 | X | |||||||||||||||||||
10.281 | X | |||||||||||||||||||
10.291 | X | |||||||||||||||||||
10.301 | 10-K | 1-14465, 1-3198 | 10.36 | 2/21/2019 | ||||||||||||||||
10.311 | 10-K | 1-14465, 1-3198 | 10.32 | 2/26/2009 | ||||||||||||||||
10.321 | 10-K | 1-14465, 1-3198 | 10.34 | 2/17/2022 | ||||||||||||||||
10.331 | 10-K | 1-14465, 1-3198 | 10.46 | 2/26/2009 | ||||||||||||||||
10.341 | 10-K | 1-14465, 1-3198 | 10.47 | 2/26/2009 | ||||||||||||||||
10.351 | 10-K | 1-14465, 1-3198 | 10.48 | 2/26/2009 | ||||||||||||||||
10.361 | 10-K | 1-14465, 1-3198 | 10.49 | 2/26/2009 | ||||||||||||||||
10.371 | 10-K | 1-14465, 1-3198 | 10.50 | 2/26/2009 | ||||||||||||||||
142
143
IDACORP, INC.
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME
| Year Ended December 31, | ||||||||||||||||||||
| 2023 | 2022 | 2021 | ||||||||||||||||||
| (thousands of dollars) | ||||||||||||||||||||
| Income: | ||||||||||||||||||||
| Equity in income of subsidiaries | $ | 262,081 | $ | 258,540 | $ | 245,591 | ||||||||||||||
| Investment income | 1,932 | 1,795 | 148 | |||||||||||||||||
| Total income | 264,013 | 260,335 | 245,739 | |||||||||||||||||
| Expenses: | ||||||||||||||||||||
| Operating expenses | 553 | 444 | 679 | |||||||||||||||||
| Interest expense | 3,171 | 1,267 | 82 | |||||||||||||||||
| Other expenses | 200 | 250 | 192 | |||||||||||||||||
| Total expenses | 3,924 | 1,961 | 953 | |||||||||||||||||
| Income Before Income Taxes | 260,089 | 258,374 | 244,786 | |||||||||||||||||
| Income Tax Benefit | (1,106) | (608) | (764) | |||||||||||||||||
| Net Income Attributable to IDACORP, Inc. | 261,195 | 258,982 | 245,550 | |||||||||||||||||
| Other comprehensive (loss) income | (4,262) | 27,118 | 3,318 | |||||||||||||||||
| Comprehensive Income Attributable to IDACORP, Inc. | $ | 256,933 | $ | 286,100 | $ | 248,868 | ||||||||||||||
| The accompanying note is an integral part of these statements. | ||||||||||||||||||||
IDACORP, INC.
CONDENSED STATEMENTS OF CASH FLOWS
| Year Ended December 31, | ||||||||||||||||||||
| 2023 | 2022 | 2021 | ||||||||||||||||||
| (thousands of dollars) | ||||||||||||||||||||
| Operating Activities: | ||||||||||||||||||||
| Net cash provided by operating activities | $ | 154,190 | $ | 77,048 | $ | 174,209 | ||||||||||||||
| Investing Activities: | ||||||||||||||||||||
| Purchase of investments | (1,002) | (26,620) | (26,363) | |||||||||||||||||
| Maturities of investments | — | 25,000 | 50,000 | |||||||||||||||||
| Net cash (used in) provided by investing activities | (1,002) | (1,620) | 23,637 | |||||||||||||||||
| Financing Activities: | ||||||||||||||||||||
| Dividends on common stock | (162,646) | (154,287) | (146,119) | |||||||||||||||||
| Change in intercompany notes payable | (282) | (3,811) | (2,167) | |||||||||||||||||
| Other | (3,533) | (3,184) | (3,124) | |||||||||||||||||
| Net cash used in financing activities | (166,461) | (161,282) | (151,410) | |||||||||||||||||
| Net (decrease) increase in cash and cash equivalents | (13,273) | (85,854) | 46,436 | |||||||||||||||||
| Cash and cash equivalents at beginning of year | 67,171 | 153,025 | 106,589 | |||||||||||||||||
| Cash and cash equivalents at end of year | $ | 53,898 | $ | 67,171 | $ | 153,025 | ||||||||||||||
| The accompanying note is an integral part of these statements. | ||||||||||||||||||||
144
IDACORP, INC.
CONDENSED BALANCE SHEETS
| December 31, | ||||||||||||||
| 2023 | 2022 | |||||||||||||
| Assets | (thousands of dollars) | |||||||||||||
| Current Assets: | ||||||||||||||
| Cash and cash equivalents | $ | 53,898 | $ | 67,171 | ||||||||||
| Receivables | 16,397 | 56,446 | ||||||||||||
| Income taxes receivable | 1,551 | 1,098 | ||||||||||||
| Other | 107 | 98 | ||||||||||||
| Total current assets | 71,953 | 124,813 | ||||||||||||
| Investments | 2,893,353 | 2,739,616 | ||||||||||||
| Other Assets: | ||||||||||||||
| Deferred income taxes | 1,919 | 131 | ||||||||||||
| Other | 422 | 286 | ||||||||||||
| Total other assets | 2,341 | 417 | ||||||||||||
| Total assets | $ | 2,967,647 | $ | 2,864,846 | ||||||||||
| Liabilities and Shareholders’ Equity | ||||||||||||||
| Noncurrent Liabilities: | ||||||||||||||
| Intercompany notes payable | $ | 59,598 | $ | 57,048 | ||||||||||
| Other | 480 | 559 | ||||||||||||
| Total noncurrent liabilities | 60,078 | 57,607 | ||||||||||||
| IDACORP, Inc. Shareholders’ Equity | 2,907,569 | 2,807,239 | ||||||||||||
| Total Liabilities and Shareholders' Equity | $ | 2,967,647 | $ | 2,864,846 | ||||||||||
| 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 SEC, the unconsolidated condensed financial statements of IDACORP do not reflect all of the information and notes normally included with financial statements prepared in accordance with GAAP. Therefore, these financial statements should be read in conjunction with the consolidated financial statements and related notes included in the 2023 Form 10-K, Part II, Item 8.
Accounting for Subsidiaries: IDACORP has accounted for the earnings of its subsidiaries under the equity method of accounting in these unconsolidated condensed financial statements. Included in net cash provided by operating activities in the condensed statements of cash flows are dividends that IDACORP subsidiaries paid to IDACORP of $105 million, $117 million, and $149 million in 2023, 2022, and 2021, respectively.
145
IDACORP, INC. AND IDAHO POWER COMPANY
SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31, 2023, 2022, and 2021
| 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) | ||||||||||||||||||||||||||||||||
| 2023: | ||||||||||||||||||||||||||||||||
| Reserve for uncollectible accounts | $ | 5,546 | $ | 3,527 | $ | 975 | $ | 4,463 | $ | 5,585 | ||||||||||||||||||||||
| Injuries and damages | 2,802 | 974 | — | 501 | 3,275 | |||||||||||||||||||||||||||
| 2022: | ||||||||||||||||||||||||||||||||
| Reserve for uncollectible accounts | $ | 5,016 | $ | 3,294 | $ | 540 | $ | 3,304 | $ | 5,546 | ||||||||||||||||||||||
| Injuries and damages | 3,780 | 2,495 | — | 3,473 | 2,802 | |||||||||||||||||||||||||||
| 2021: | ||||||||||||||||||||||||||||||||
| Reserve for uncollectible accounts | $ | 5,263 | $ | 2,083 | $ | 640 | $ | 2,970 | $ | 5,016 | ||||||||||||||||||||||
| Injuries and damages | 2,484 | 2,032 | — | 736 | 3,780 | |||||||||||||||||||||||||||
(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.
146
SIGNATURES
Pursuant to the requirements of Section 13 or 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 15, 2024 | IDACORP, INC. | |||||||||||||
| Date | ||||||||||||||
| By: | /s/ Lisa A. Grow | |||||||||||||
| Lisa A. Grow | ||||||||||||||
| President and Chief Executive Officer | ||||||||||||||
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
| Signature | Title | Date | |||||||||||||||||||||
| /s/ Richard J. Dahl | Chair of the Board | February 15, 2024 | |||||||||||||||||||||
| Richard J. Dahl | |||||||||||||||||||||||
| /s/ Lisa A. Grow | (Principal Executive Officer) | February 15, 2024 | |||||||||||||||||||||
| Lisa A. Grow | |||||||||||||||||||||||
| President and Chief Executive Officer and Director | |||||||||||||||||||||||
| /s/ Brian R. Buckham | (Principal Financial Officer) | February 15, 2024 | |||||||||||||||||||||
| Brian R. Buckham | |||||||||||||||||||||||
| Senior Vice President, Chief Financial Officer, and Treasurer | |||||||||||||||||||||||
| /s/ Amy I. Shaw | (Principal Accounting Officer) | February 15, 2024 | |||||||||||||||||||||
| Amy I. Shaw | |||||||||||||||||||||||
| Vice President of Finance, Compliance, and Risk | |||||||||||||||||||||||
| /s/ Odette C. Bolano | Director | February 15, 2024 | |||||||||||||||||||||
| Odette C. Bolano | |||||||||||||||||||||||
| /s/ Annette G. Elg | Director | February 15, 2024 | |||||||||||||||||||||
| Annette G. Elg | |||||||||||||||||||||||
| /s/ Ronald W. Jibson | Director | February 15, 2024 | |||||||||||||||||||||
| Ronald W. Jibson | |||||||||||||||||||||||
| /s/ Judith A. Johansen | Director | February 15, 2024 | |||||||||||||||||||||
| Judith A. Johansen | |||||||||||||||||||||||
| /s/ Dennis L. Johnson | Director | February 15, 2024 | |||||||||||||||||||||
| Dennis L. Johnson | |||||||||||||||||||||||
| /s/ Nate R. Jorgensen | Director | February 15, 2024 | |||||||||||||||||||||
| Nate R. Jorgensen | |||||||||||||||||||||||
| /s/ Jeff C. Kinneeveauk | Director | February 15, 2024 | |||||||||||||||||||||
| Jeff C. Kinneeveauk | |||||||||||||||||||||||
| /s/ Susan D. Morris | Director | February 15, 2024 | |||||||||||||||||||||
| Susan D. Morris | |||||||||||||||||||||||
| /s/ Richard J. Navarro | Director | February 15, 2024 | |||||||||||||||||||||
| Richard J. Navarro | |||||||||||||||||||||||
| /s/ Dr. Mark T. Peters | Director | February 15, 2024 | |||||||||||||||||||||
| Dr. Mark T. Peters | |||||||||||||||||||||||
147
SIGNATURES
Pursuant to the requirements of Section 13 or 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 15, 2024 | Idaho Power Company | |||||||||||||
| Date | ||||||||||||||
| By: | /s/ Lisa A. Grow | |||||||||||||
| Lisa A. Grow | ||||||||||||||
| President and Chief Executive Officer | ||||||||||||||
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
| Signature | Title | Date | |||||||||||||||||||||
| /s/ Richard J. Dahl | Chair of the Board | February 15, 2024 | |||||||||||||||||||||
| Richard J. Dahl | |||||||||||||||||||||||
| /s/ Lisa A. Grow | (Principal Executive Officer) | February 15, 2024 | |||||||||||||||||||||
| Lisa A. Grow | |||||||||||||||||||||||
| President and Chief Executive Officer and Director | |||||||||||||||||||||||
| /s/ Brian R. Buckham | (Principal Financial Officer) | February 15, 2024 | |||||||||||||||||||||
| Brian R. Buckham | |||||||||||||||||||||||
| Senior Vice President, Chief Financial Officer, and Treasurer | |||||||||||||||||||||||
| /s/ Amy I. Shaw | (Principal Accounting Officer) | February 15, 2024 | |||||||||||||||||||||
| Amy I. Shaw | |||||||||||||||||||||||
| Vice President of Finance, Compliance, and Risk | |||||||||||||||||||||||
| /s/ Odette C. Bolano | Director | February 15, 2024 | |||||||||||||||||||||
| Odette C. Bolano | |||||||||||||||||||||||
| /s/ Annette G. Elg | Director | February 15, 2024 | |||||||||||||||||||||
| Annette G. Elg | |||||||||||||||||||||||
| /s/ Ronald W. Jibson | Director | February 15, 2024 | |||||||||||||||||||||
| Ronald W. Jibson | |||||||||||||||||||||||
| /s/ Judith A. Johansen | Director | February 15, 2024 | |||||||||||||||||||||
| Judith A. Johansen | |||||||||||||||||||||||
| /s/ Dennis L. Johnson | Director | February 15, 2024 | |||||||||||||||||||||
| Dennis L. Johnson | |||||||||||||||||||||||
| /s/ Nate R. Jorgensen | Director | February 15, 2024 | |||||||||||||||||||||
| Nate R. Jorgensen | |||||||||||||||||||||||
| /s/ Jeff C. Kinneeveauk | Director | February 15, 2024 | |||||||||||||||||||||
| Jeff C. Kinneeveauk | |||||||||||||||||||||||
| /s/ Susan D. Morris | Director | February 15, 2024 | |||||||||||||||||||||
| Susan D. Morris | |||||||||||||||||||||||
| /s/ Richard J. Navarro | Director | February 15, 2024 | |||||||||||||||||||||
| Richard J. Navarro | |||||||||||||||||||||||
| /s/ Dr. Mark T. Peters | Director | February 15, 2024 | |||||||||||||||||||||
| Dr. Mark T. Peters | |||||||||||||||||||||||
148