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

☒ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
| THE SECURITIES EXCHANGE ACT OF 1934
| For the fiscal year ended | December 31, 2025

OR

☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
| THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _________ to ________________________________

Commission File Number | Exact name of registrants as specified in their charters, address of principal executive offices, zip code and telephone number | I.R.S. Employer Identification No.
1-14465 | IDACORP, Inc. | 82-0505802
1-3198 | Idaho Power Company | 82-0130980
| 1221 W. Idaho Street |
| Boise, | ID | 83702-5627 |
| (208) | 388-2200 |
State of incorporation: Idaho

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

Title of each class | Trading Symbol(s) | Name of each exchange on which registered
Common Stock, without par value | IDA | New York Stock Exchange

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

Idaho Power Company: | Preferred Stock

Indicate by check mark 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 ☐
1

Table of Contents
Indicate by check mark whether the registrants have submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrants were required to submit 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, 2025):

IDACORP, Inc.: | $ | 6,209,260,280 |  |  | Idaho Power Company: | None

Number of shares of common stock outstanding as of February 13, 2026:

IDACORP, Inc.: | 54,899,034 |  | 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 2026 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 | 4
Cautionary Note Regarding Forward-Looking Statements | 5
Available Information | 7
Part I |  |
Item 1 | Business | 8
| Information about our Executive Officers | 20
Item 1A | Risk Factors | 21
Item 1B | Unresolved Staff Comments | 35
Item 1C | Cybersecurity | 35
Item 2 | Properties | 36
Item 3 | Legal Proceedings | 37
Item 4 | Mine Safety Disclosures | 38
Part II |  |
Item 5 | Market for Registrant's Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities | 39
Item 6 | [Reserved] | 40
Item 7 | Management's Discussion and Analysis of Financial Condition and Results of Operations | 40
Item 7A | Quantitative and Qualitative Disclosures About Market Risk | 73
Item 8 | Financial Statements | 76
Item 9 | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure | 139
Item 9A | Controls and Procedures | 139
Item 9B | Other Information | 143
Item 9C | Disclosure Regarding Foreign Jurisdictions that Prevent Inspections | 143
Part III |  |
Item 10 | Directors, Executive Officers, and Corporate Governance* | 143
Item 11 | Executive Compensation* | 143
Item 12 | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters* | 143
Item 13 | Certain Relationships and Related Transactions, and Director Independence* | 144
Item 14 | Principal Accountant Fees and Services* | 144
Part IV |  |
Item 15 | Exhibits and Financial Statement Schedules | 145
Item 16 | Form 10-K Summary | 154
Signatures | 155
* 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 2026 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 Settlement Stipulation | - | The settlement stipulation for Idaho Power's 2023 Idaho general rate case |  | IPUC | - | Idaho Public Utilities Commission
2024 Idaho Limited-Issue Rate Case | - | A limited-issue rate case Idaho Power filed with the IPUC in May 2024 |  | IRP | - | Integrated Resource Plan
2024 Oregon Settlement Stipulations | - | Settlement stipulations approved by the OPUC in September 2024 settling Idaho Power's general rate case filed with the OPUC in December 2023 |  | Jim Bridger plant | - | Jim Bridger power plant
2025 IRP | - | 2025 Integrated Resource Plan |  | kWh | - | Kilowatt-hour
2025 Settlement Stipulation | - | The settlement stipulation for Idaho Power's 2025 Idaho general rate case |  | LTICP | - | IDACORP 2000 Long-Term Incentive and Compensation Plan
ADITC | - | Accumulated Deferred Investment Tax Credits |  | MATS Rule | - | Mercury and Air Toxics Standards
AFUDC | - | Allowance for Funds Used During Construction |  | MD&A | - | Management’s Discussion and Analysis of Financial Condition and Results of Operations
AOCI | - | Accumulated Other Comprehensive Income |  | MMBtu | - | Million British Thermal Units
APCU | - | Annual power cost update |  | Moody's | - | Moody’s Investors Service
ATM | - | At-the-market offering program |  | MW | - | Megawatt
B2H | - | Boardman-to-Hemingway, a high-voltage transmission line project |  | MWh | - | Megawatt-hour
BCC | - | Bridger Coal Company, a jointly-owned investment of IERCo |  | NAV | - | Net Asset Value
BLM | - | U.S. Bureau of Land Management |  | NEPA | - | National Environmental Policy Act
BPA | - | Bonneville Power Administration |  | NMFS | - | National Marine Fisheries Service
CAA | - | Clean Air Act |  | NPSE | - | Net power supply expense
CO 2 | - | Carbon Dioxide |  | North Valmy plant | - | Idaho Power’s jointly-owned gas-fired generating plant in Valmy, Nevada
CPCN | - | Certificate of Public Convenience and Necessity |  | O&M | - | Operations and Maintenance
CWA | - | Clean Water Act |  | OATT | - | Open Access Transmission Tariff
EIS | - | Environmental Impact Statement |  | OPUC | - | Public Utility Commission of Oregon
EPA | - | U.S. Environmental Protection Agency |  | Oregon Sale | - | The sale of Idaho Power's Oregon electric distribution business and certain Oregon transmission assets to OTEC
ESA | - | Endangered Species Act |  | OTEC | - | Oregon Trail Electric Consumers Cooperative, Inc.
Exchange Act | - | U.S. Securities Exchange Act of 1934, as amended |  | PCA | - | Idaho-jurisdiction Power Cost Adjustment
FCA | - | Idaho Fixed Cost Adjustment |  | PPA | - | Power purchase agreement
FERC | - | Federal Energy Regulatory Commission |  | PURPA | - | Public Utility Regulatory Policies Act of 1978
FPA | - | Federal Power Act |  | REC | - | Renewable Energy Credit
FSA | - | Forward sale agreement |  | RFP | - | Request for proposals
GAAP | - | Accounting principles generally accepted in the United States of America |  | SEC | - | U.S. Securities and Exchange Commission
GHG | - | Greenhouse Gas |  | SIP | - | State Implementation Plan
GWW | - | Gateway West, a high-voltage transmission line project |  | SMSP | - | Security Plans for Senior Management Employees I and II
HCC | - | Hells Canyon Complex, composed of the Brownlee, Oxbow, and Hells Canyon facilities |  | SWIP-N | - | Southwest Intertie Project-North, a planned high-voltage transmission line project
IDACORP | - | IDACORP, Inc., an Idaho Corporation |  | USFWS | - | U.S. Fish and Wildlife Service
Idaho Power | - | Idaho Power Company, an Idaho Corporation |  | Western EIM | - | Energy imbalance market implemented in the western United States
Ida-West | - | Ida-West Energy Company, a subsidiary of IDACORP, Inc. |  | WMP | - | Wildfire Mitigation Plan
IERCo | - | Idaho Energy Resources Co., a subsidiary of Idaho Power Company |  | WPSC | - | Wyoming Public Service Commission
IFS | - | IDACORP Financial Services, Inc., a subsidiary of IDACORP, Inc. |  |  |  |

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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, power generation, 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," 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 or actions 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 and contractual obligations for, and the permitting and construction of, utility infrastructure projects that Idaho Power may be unable to complete, are delayed, have cost increases due to tariffs, supply chain constraints, or other factors, 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, including as a result of tariffs, supply chain constraints, permitting requirements and limitations, and the potential impacts of those delays and failures on Idaho Power's ability to serve customers and generate revenues;
•the rapid addition of new industrial customer load and the volatility and timing of such new load demand, resulting in increased risks and costs of power demand potentially exceeding Idaho Power's available generation capacity and of revenue volatility;
•the potential financial impacts of industrial customers not meeting forecasted power usage ramp rates or volumes;
•impacts of economic conditions, including an inflationary or recessionary environment and 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 on the timing and extent of counterparties' power usage, and collection of receivables;
•changes in residential, commercial, irrigation, 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, 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, wildfires, droughts, earthquakes, and other natural phenomena and natural disasters, which affect customer sales, hydropower generation, repair costs, service interruptions, p ublic safety power shutoffs and de-energization, liability for damage caused by utility property, and the availability and cost of fuel for generation plants or purchased power to serve customers;
•advancement and adoption 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;
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•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;
•ability to acquire equipment, materials, fuel, power, and transmission capacity on reasonable terms and prices, particularly in the event of unanticipated or abnormally high resource demands, price volatility (including as a result of new or increased tariffs), 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;
•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;
•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, increased power supply costs and repair expenses, and reduced 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;
•Idaho Power’s concentration in 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 existing and planned generation and transmission assets that may adversely impact Idaho Power's ability to construct and operate those facilities in a manner most suitable to Idaho Power;
•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 expected tax credits or other tax benefits;
•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 rates, decisions by the state 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 and cash flow impacts the companies may incur on those hedges;
•changes in actuarial assumptions, changes in interest rates, 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, cash flows, and regulatory limitations; and
•adoption of or changes in accounting policies and principles, changes in accounting estimates, and new SEC or New York Stock Exchange requirements or new interpretations of existing requirements.
Any forward-looking statement speaks only as of the date on which such statement is made. N ew 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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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.
Investors and others should note that IDACORP and Idaho Power announce material information about their business through a variety of means, including filings with the SEC, press releases, public conference calls, and webcasts. The companies use these channels to achieve broad, non-exclusionary distribution of information to the public and for complying with their disclosure obligations under Regulation FD. Therefore, IDACORP and Idaho Power encourage investors, the media, and others interested in the companies to review the information the companies make available through such channels.
Investors, the media, and others interested in IDACORP and Idaho Power may also wish to refer to the websites of the IPUC and OPUC at puc.idaho.gov and oregon.gov/puc, respectively, to review documents filed by IDACORP, Idaho Power, and third parties with, and issued by, the respective commissions. No information on the IPUC and OPUC websites is incorporated by reference into this report or into IDACORP's or Idaho Power's other SEC filings.
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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 PURPA-qualifying hydropower generation projects.
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.
UTILITY OPERATIONS
Background
Idaho Power provided electric utility service to approximately 664,000 retail customers in southern Idaho and eastern Oregon as of December 31, 2025. Approximately 561,000 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, education, and information technology. 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 69 cities in Idaho and 9 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. On February 13, 2026, Idaho Power entered into a definitive agreement to sell its Oregon electric distribution business and associated distribution assets, as well as certain Oregon transmission assets to OTEC. For further information regarding the proposed transaction, see Note 22 - "Sale of Oregon Assets" to the consolidated financial statements included in this report.
The following figure represents Idaho Power's current service area without regard to the Oregon Sale.
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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, OPUC, and 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, OPUC, and WPSC as to the issuance of debt and equity securities. As a public utility under the FPA, Idaho Power has been granted the 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 sale 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 GAAP to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation, with the impacts of rate regulation reflected in its financial statements. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures. 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 and affordable 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, OPUC, and 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, 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 near the 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,
|  | 2025 |  | 2024 |  | 2023
Retail revenues (thousands of dollars): |  |  |  |  |  |
Residential (includes $3,972, $(2,686), and $37,233, respectively, related to the FCA) |  | $ | 708,126 |  |  | $ | 700,586 |  |  | $ | 684,649 |
Commercial (includes $(76), $(170), and $1,338, respectively, related to the FCA) |  | 394,313 |  |  | 397,385 |  |  | 378,330 |
Industrial |  | 270,571 |  |  | 267,211 |  |  | 244,538 |
Irrigation |  | 198,468 |  |  | 196,401 |  |  | 173,929 |
Deferred revenue related to HCC relicensing AFUDC(1) |  | (15,120) |  |  | (8,803) |  |  | (8,780) |
Total retail revenues |  | 1,556,358 |  |  | 1,552,780 |  |  | 1,472,666 |
Wholesale energy sales |  | 55,989 |  |  | 73,908 |  |  | 63,421 |
Transmission wheeling-related revenues |  | 72,231 |  |  | 79,173 |  |  | 80,357 |
Energy efficiency program revenues |  | 30,480 |  |  | 27,581 |  |  | 31,948 |
Other revenues |  | 94,551 |  |  | 89,523 |  |  | 114,502 |
Total electric utility operating revenues |  | $ | 1,809,609 |  |  | $ | 1,822,965 |  |  | $ | 1,762,894 |
Energy sales (thousands of MWh): |  |  |  |  |  |
Residential |  | 6,010 |  |  | 5,964 |  |  | 5,903 |
Commercial |  | 4,348 |  |  | 4,332 |  |  | 4,269 |
Industrial |  | 3,775 |  |  | 3,680 |  |  | 3,538 |
Irrigation |  | 2,044 |  |  | 1,995 |  |  | 1,805 |
Total retail energy sales |  | 16,177 |  |  | 15,971 |  |  | 15,515 |
Wholesale energy sales |  | 1,381 |  |  | 1,412 |  |  | 840 |
Energy sales bundled with RECs |  | 1,516 |  |  | 1,406 |  |  | 1,255 |
Total energy sales |  | 19,074 |  |  | 18,789 |  |  | 17,610 |

(1) The IPUC allows Idaho Power to recover a portion of the AFUDC on construction work in progress related to the HCC relicensing process in its Idaho jurisdiction, even though the relicensing process is not yet complete and the costs have not been moved to utility plant in service. Effective October 1, 2025, Idaho Power began collecting $38.5 million annually. Prior to October 1, 2025, Idaho Power collected $8.8 million annually. For more information refer to Note 3 - "Regulatory Matters" to the consolidated financial statements in this report. Amounts collected in the Idaho jurisdiction are recognized as deferred revenue 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 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 reliability and security standards.
Competition: Idaho Power's electric utility business has historically been recognized as a regulated monopoly. However, 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, gas-fired, and coal-fired generation facilities, energy storage, and long-term PPAs 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 3,793 MW on July 22, 2024. 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
|  | 2025 |  | 2024 |  | 2023 |  | 2025 |  | 2024 |  | 2023
|  | (thousands of MWh) |  |
Hydropower plants |  | 7,021 |  |  | 7,203 |  |  | 6,548 |  |  | 52 | % |  | 54 | % |  | 55 | %
Jointly-owned thermal plants(1) |  | 2,906 |  |  | 2,474 |  |  | 2,473 |  |  | 21 | % |  | 18 | % |  | 21 | %
Natural gas-fired plants |  | 3,685 |  |  | 3,843 |  |  | 2,917 |  |  | 27 | % |  | 28 | % |  | 24 | %
Total system generation |  | 13,612 |  |  | 13,520 |  |  | 11,938 |  |  |  |  |  |  |
Purchased power |  | 6,783 |  |  | 6,541 |  |  | 7,027 |  |  |  |  |  |  |
Total power supply |  | 20,395 |  |  | 20,061 |  |  | 18,965 |  |  |  |  |  |  |

(1) "Jointly-owned thermal plants" are composed of generation from plants that are fueled by only coal or by both coal and natural gas.
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 7.3 million MWh over the last 20 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 2025, hydropower generation was 7.0 million MWh, a decrease from 2024 and an increase from 2023, due to changes in snow accumulation and reservoir storage throughout most of the Snake River basin. In 2024, average snowpack conditions paired with above average reservoir storage upstream of Idaho Power's hydropower projects resulted in hydropower generation of 7.2 million MWh. In 2023, snow accumulation was well above normal but reservoir storage upstream of Idaho Power's hydropower projects was well below normal, causing much of the spring season runoff to fill reservoirs above Idaho Power's hydropower system and resulted in lower than average hydropower generation of 6.5 million MWh. Idaho Power's 2026 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.
Jointly-Owned Thermal Generation: Idaho Power co-owns the following coal and gas-fired steam generation 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 generating units 3 and 4 at 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 2027. 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 generating units 1 and 2 at the Jim Bridger plant was completed in the spring of 2024.
NV Energy is the operator of the North Valmy plant. Idaho Power has an established process approved by the IPUC and OPUC for recovery of non-fuel costs related to Idaho Power’s completed exit from 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 and unit 2 of the North Valmy plant in December 2025.
Idaho Power's 2025 IRP identified a preferred resource portfolio and action plan that included the conversion from coal to natural gas of both units at the North Valmy plant in 2026 and the remaining two units at the Jim Bridger plant in 2030. The conversion of North Valmy unit 1 has been completed and the unit was placed in-service in December 2025 and the conversion of North Valmy unit 2 is expected to be completed by mid-2026. For more information on the 2025 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 was completed. In addition, the conversion of unit 1 at North Valmy has been completed and the unit was placed in-service in December 2025 and the conversion of unit 2 is expected to be completed by mid-2026. In September 2025, Idaho Power filed an application with the IPUC for a CPCN for 167 MW of natural gas-fueled generating capacity next to the existing Bennett Mountain power plant in 2028, as discussed further in Part II, Item 7 – MD&A – "Regulatory Matters."
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 and North Valmy plant 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
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facilities is purchased based on system requirements and dispatch efficiency. The natural gas supplying the Idaho, Wyoming, and Nevada plants is transported through Idaho Power's long-term gas transportation service agreements with the Williams-Northwest Pipeline for 150,763 MMBtu per day, the Williams-Mt. West Overthrust Pipeline for 89,000 MMBtu per day, and the Tallgrass-Ruby Pipeline for 39,000 MMBtu per day. The Tallgrass-Ruby Pipeline transport capacity will increase to 78,000 MMBtu per day in May 2026. These transportation agreements vary in contract length but generally contain the right for Idaho Power to extend the term. In addition to the long-term gas transportation service agreements, Idaho Power has entered into 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 began 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 13, 2026, Idaho Power had approximately 75.72 million MMBtu of natural gas financially hedged for physical delivery, primarily for the operational dispatch of Langley Gulch, Danskin, Bennett, Jim Bridger, and North Valmy power plants through January 2029. 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 of dollars and MWh, 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,
|  | 2025 |  | 2024 |  | 2023
Expense |  |  |  |  |  |
Wholesale market purchases |  | $ | 86,419 |  |  | $ | 131,562 |  |  | $ | 243,319 |
Long-term agreements (including PURPA) |  | 306,043 |  |  | 293,520 |  |  | 258,212 |
Total purchased power expense |  | $ | 392,462 |  |  | $ | 425,082 |  |  | $ | 501,531 |
MWh purchased |  |  |  |  |  |
Wholesale market purchases |  | 2,315 |  |  | 2,508 |  |  | 3,278 |
Long-term agreements (including PURPA) |  | 4,468 |  |  | 4,033 |  |  | 3,749 |
Total MWh purchased |  | 6,783 |  |  | 6,541 |  |  | 7,027 |
Cost per MWh from wholesale market purchases |  | $ | 37.33 |  |  | $ | 52.46 |  |  | $ | 74.23 |
Cost per MWh from long-term agreement purchases |  | $ | 68.50 |  |  | $ | 72.78 |  |  | $ | 68.87 |
Weighted average cost per MWh - all sources |  | $ | 57.86 |  |  | $ | 64.99 |  |  | $ | 71.37 |

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 generating 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.
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 |  | 460 |  |  | 316 |  |  | 776 |  |  | 625 |  |  | 1,401 |  |  |
Hydropower |  | — |  |  | 144 |  |  | 144 |  |  | — |  |  | 144 |  |  |
Other |  | 35 |  |  | 43 |  |  | 78 |  |  | — |  |  | 78 |  |  |
Total |  | 596 |  |  | 1,128 |  |  | 1,724 |  |  | 625 |  |  | 2,349 |  |  |

Idaho Power has agreements with non-PURPA solar projects for 125 MW and 500 MW, expected to be online in 2026 and 2027, respectively. While Idaho Power previously had an agreement with a non-PURPA wind project for 300 MW scheduled to come online in 2027, that agreement was terminated in September 2025.
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. Through 2025, 307 MW of company-owned battery storage were installed, with another 250 MW expected to be in service by the end of 2026. Idaho Power commenced a 20-year agreement to utilize the storage capacity from a 150 MW battery storage facility that came online in May 2025 and has a 20-year agreement to utilize the storage capacity from a 100 MW battery storage facility scheduled to be online in April 2027. Idaho Power intends for this capacity to supplement a total of 557 MW of company-owned storage that it expects to be online by the end of 2026.
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.
Idaho Power is jointly working with various partners on the development of three significant transmission projects. The B2H project is a 300-mile, high-voltage transmission line between a substation near Boardman, Oregon, and the Hemingway
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substation near Boise, Idaho. The GWW project is a high-voltage transmission line project between a substation located near Douglas, Wyoming, and the Hemingway substation. The SWIP-N project is a planned 285-mile, high-voltage transmission line between the Robinson Summit substation near Ely, Nevada, and the Midpoint substation near Jerome, Idaho. The 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 biennially prepare an IRP. Idaho Power filed its most recent 2025 IRP with the IPUC and OPUC in June 2025. 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 2025 IRP are included in the table below, together with the average annual growth rate assumptions used in the prior two IRPs. The 2025 IRP assumptions include significant large commercial and industrial additions in the 5-year forecasted annual growth rate. 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)
2025 IRP |  | 8.3% | 5.1% |  | 2.7% | 1.9%
2023 IRP |  | 5.5% | 3.7% |  | 2.1% | 1.8%
2021 IRP |  | 2.6% | 2.1% |  | 1.4% | 1.4%

The 2025 IRP preferred resource portfolio provided for 4,071 MW of additional resource capacity. The identified resources included 1,161 MW of natural gas generation over the next 20 years to meet energy and capacity needs, including the conversion of 484 MW of coal to natural gas generation. The additions to resource capacity also included 1,445 MW of solar, 700 MW of wind, 885 MW of storage, 344 MW of additional energy efficiency, and 20 MW from demand response. In addition, the preferred resource portfolio included Idaho Power's complete conversion from coal to natural gas generation by 2030. To support these resource additions, the preferred portfolio also included the B2H transmission line in 2027, the SWIP-N transmission project in 2028, and GWW transmission line segments phased in with in-service dates from 2028 through 2040. However, as noted in the 2025 IRP, there is considerable uncertainty surrounding 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 comprises 20 programs. The energy efficiency programs target energy savings across the entire year, while the demand response programs target system demand reduction in the summer at times of peak loads. The programs are offered to all customer segments and emphasize the wise use of energy, especially during periods of high demand. This energy and demand reduction can reduce or delay the need for new generation and transmission infrastructure. Idaho Power’s programs include:
•financial incentives for irrigation customers for either improving the energy efficiency of an irrigation system or installing new energy efficient systems;
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•energy efficiency programs for new and existing homes including electric heating, ventilation and cooling equipment, as well as energy efficient building techniques;
•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 2025, Idaho Power’s energy efficiency programs reduced energy usage by approximately 145,000 MWh compared with 138,000 MWh in 2024. For 2025, Idaho Power had a demand response available capacity of approximately 329 MW. Idaho Power expended approximately $43 million and $40 million in 2025 and 2024, respectively, on both energy efficiency and demand response programs. Funding for these programs is provided through a combination of the Idaho and Oregon energy efficiency tariff riders, base rates, and the power cost adjustment mechanisms. Energy efficiency program expenditures funded through the riders are reported as an operating expense with an equal amount of revenues recorded in other revenues, resulting in no net impact on earnings.
Corporate Responsibility
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’ corporate responsibility initiatives and both are regularly informed of the goals, measures, and results of the companies' corporate responsibility programs. Each committee of the board of directors is assigned a portion of the oversight of the companies' corporate responsibility programs. Idaho Power has established an internal steering committee led by senior management and composed of a cross-functional team of key employees from multiple departments to oversee corporate responsibility activities and inform leadership and the board of directors on related activities and matters it identifies as material to the company's operations and financial condition.
IDACORP and Idaho Power publicly release an annual corporate responsibility report and the most current report is located on Idaho Power’s website, together with other information on corporate responsibility issues relevant to Idaho Power. IDACORP's and Idaho Power's 2024 Corporate Responsibility Report released in April 2025 incorporated elements of the Sustainability Accounting Standards Board repor ting framework, as well as the Edison Electric Institute (EEI) environmental, social, governance, and sustainability reporting template. The Corporate Responsibility Report and related website content are not incorporated by reference into this report. IDACORP’s and Idaho Power’s corporate responsibility initiatives include:
•promoting a culture of safety, integrity, and respect for all employees;
•establishing responsible management goals and long-term strategies related to the companies’ impact on the environment;
•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); and
•building strong community partnerships for sustainable economic development in Idaho Power’s service area.
Reducing Carbon Emissions Intensity: Carbon emissions intensity is a measure of the pounds of CO 2 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 for over a decade. Idaho Power has significantly reduced its CO 2 emissions since 2005, primarily by decreasing its coal generation levels, including terminating its participation in coal generation at the North Valmy Unit 1 in 2019 and North Valmy Unit 2 in 2025 and at the Boardman plant in 2020 and converting two units at the Jim Bridger plant from coal to natural gas in 2024, by upgrading it s hydropower facilities, and through its energy efficiency, demand-side management, and cloud-seeding programs. The Corporate Responsibility Report contains further information regarding Idaho Power's goals and plans to reduce CO 2 emissions in future years.
Operational Resilience: For more than 100 years, Idaho Power has adapted to changes in temperatures, water conditions, economic conditions, and regulatory requirements. To address the physical impacts of a changing climate, Idaho Power conducts cloud-seeding operations, implements a WMP, enhances grid resiliency and reliability, and continues to further Snake
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River shading and in-stream river enhancement projects. Idaho Power considers climate-related impacts in planning efforts, plans and advocates for additional transmission capacity to integrate additional renewable energy onto its system, and identifies and investigates new technologies, including battery storage, hydrogen generation, and modular nuclear reactor technology.
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 thermal 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. Idaho Power estimates its environmental expenditures at its hydropower and thermal facilities, based upon present environmental laws and regulations, will be as follows for the periods indicated, excluding AFUDC (in millions of dollars):

|  | 2026 |  | 2027-2028
Capital expenditures: |  |  |  |
License compliance and relicensing efforts at hydropower facilities |  | $ | 29 |  |  | $ | 114 |
Investments in equipment and facilities at thermal plants |  | 1 |  |  | 19 |
Total capital expenditures |  | $ | 30 |  |  | $ | 133 |
Operating expenses: |  |  |  |
Operating costs for environmental facilities - hydropower |  | $ | 35 |  |  | $ | 79 |
Operating costs for environmental facilities - thermal |  | 10 |  |  | 29 |
Total other O&M |  | $ | 45 |  |  | $ | 108 |

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 any increases in costs through the ratemaking process. Beyond changes in 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 cannot be fully recovered in rates on a timely basis.
Idaho Power is actively pursuing the relicensing of the HCC, its largest hydropower generation source. As of the date of this report, Idaho Power believes issuance of a new HCC license by the FERC will be as early as 2027; however, 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. 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 Management
Overview: Idaho Power’s human capital management 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 environment, opportunities for 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
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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, 2025, IDACORP had 2,174 full-time employee s, 2,166 of wh om were employed by Idaho Power and 8 of whom were employed by Ida-West. IDACORP had 11 part-time employee s, 8 of whom were employed by Idaho Power and 3 of whom were employed by Ida-West. Of IDACORP's full-time employees, 48 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 company culture 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, company culture, 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 corporate responsibility risk oversight function. The executive committee assists the board of directors in fulfilling its oversight responsibilities with respect to enterprise risk management processes generally.
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.
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.
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, 2025, the unamortized amount of IFS’s portfolio was approximately $50 million ($132 million in gross tax credit investments, net of $82 million of accumulated amortization). IFS generated tax credits of $7.8 million in 2025, $7.5 million in 2024, and $6.9 million in 2023. IFS received distributions related to fully-amortized real estate tax credit investments that reduced IDACORP's income tax expense by $0.7 million in 2025, $1.6 million in 2024, and $0.5 million in 2023.
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 2025, $10 million in 2024, and $9 million in 2023.
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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, 51
•Vice President of Power Supply of Idaho Power Company, August 2020 - present
BRIAN R. BUCKHAM, 47
•Executive Vice President, Chief Financial Officer, and Treasurer of IDACORP, Inc. and Idaho Power Company, February 2026 - present
•Senior Vice President, Chief Financial Officer, and Treasurer of IDACORP, Inc. and Idaho Power Company, January 2024 - February 2026
•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, 42
•Vice President of Planning, Engineering and Construction of Idaho Power Company, August 2020 - present
SARAH E. GRIFFIN, 56
•Vice President of Human Resources of Idaho Power Company, October 2019 - present
LISA A. GROW, 60
•President and Chief Executive Officer of IDACORP, Inc. and Idaho Power Company, June 2020 - present
JAMES BO D. HANCH EY, 50
•Vice President of Customer Operations and Chief Safety Officer of Idaho Power Company, October 2019 - present
JULIA A. HILTON, 48
•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
JEFFREY L. MALMEN, 58
•Senior Vice President of Public Affairs of IDACORP, Inc. and Idaho Power Company, April 2016 - present
ADAM J. RICHINS, 47
•Executive Vice President and Chief Operating Officer of Idaho Power Company, February 2026 - present
•Senior Vice President and Chief Operating Officer of Idaho Power Company, October 2019 - February 2026
AMY I. SHAW, 46
•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
TIMOTHY E. TATUM, 52
•Vice President of Regulatory Affairs of Idaho Power Company, March 2016 - present
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ITEM 1A. RISK FACTORS
IDACORP and Idaho Power operate in a highly regulated industry and business environment that involves significant risks, many of which are beyond the companies' control. The circumstances and factors set forth below should not be considered a complete list of potential risks that the companies may encounter. These risk factors, as well as additional risks and uncertainties either not known as of the date of this report or that are currently believed to not be material to the business, may have a material impact on the business, financial condition, or results of operations of IDACORP and Idaho Power and could cause actual results or outcomes to differ materially from those discussed in any forward-looking statements. These risk factors, as well as other information in this report, including without limitation, in 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 for construction of new facilities and transmission resources, O&M, compliance with legal and regulatory requirements, and pension contributions, among others, which is likely to occur before the IPUC, OPUC, or FERC approve the recovery of those costs. 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 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. With the large amount of ongoing and projected investments and the associated regulatory lag in cost recovery, Idaho Power filed rate cases in Idaho in 2023, 2024, and 2025, and Oregon in 2023 and expects that it will likely file rate cases or seek other types of regulatory relief on a regular basis in the next few years. 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.
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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 an 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, 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 western United States could also increase the volatility of power supply costs. While the power cost adjustment mechanisms function to mitigate adverse impacts 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, expansion or loss of service area, changes in customer needs and expectations, customer rates, energy efficiency measures, customer-generated power, demand-side management requirements, regulation or deregulation, and economic conditions. Inflationary pressures, including as a result of new or increased tariffs or other trade restrictions, or a n economic downturn, 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 energy efficiency activities. State or federal regulations may be enacted to encourage or require energy conservation or technological advances that increase energy efficiency, which could further reduce usage per customer. Also, changing customer needs and expectations, such as a desire for increased renewable or low GHG-emitting sources of energy, increased customer rates, 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 2025. 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. 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.
Idaho Power is experiencing a rapid addition of new industrial customer load, but if the new load does not meet forecasted power usage ramp rates or amounts, the loss of load may result in excess infrastructure and stranded costs and require Idaho Power to modify or eliminate large generation, storage, or transmission projects. This could in turn result in reduced revenues, earnings, and cash flows, as well as write-downs or write-offs if regulators determine that the costs of the projects were incurred
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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 2025 IRP preferred resource portfolio included a need to ac quire 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 additional 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 s ales 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 summer months and a secondary peak during the 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.
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.
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. 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 these mechanisms may not 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
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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. 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, have exposed, and in the future 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, inverse condemnation, and environmental pollution. The risk of wildfires is exacerbated in forested areas with standing dead and dying timber, increasing the risk that such trees may fall 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. 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 other protocols will be successful or effective in reducing wildfire-related losses. 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 Idaho Power's wildfire insurance policies could result in material self-insured costs. In the past, Idaho Power has experienced coverage reductions and increased wildfire insurance costs and may continue to do so 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.
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 have been federal and state regulations, laws, and other incentives 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 resulting 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 adversely 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'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 on energy infrastructure within the energy industry and on Idaho Power specifically in the past, and there are likely to be additional attacks in the future on Idaho Power, its vendors, and other utilities. The utility industry is continuing to experience an increase in the frequency and sophistication of cybersecurity incidents.
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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. Infrastructure facilities, such as power generation facilities and electric transmission or distribution facilities, could be 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), which might 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 Idaho Power or by third parties, 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 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 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; 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 adversely 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 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. There can be no assurance that Idaho Power's cybersecurity measures will be effective, nor can security measures completely eliminate the possibility of a cybersecurity breach. Further, the implementation of security 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 2025 IRP. Idaho Power is participating in three high-voltage transmission line projects, has applied for a CPCN for additional gas-fueled generating capacity next to an existing gas power plant, and has also entered into contracts to purchase, own, and utilize, 1,400 MWh of new battery storage assets expected to come online from 2026 to 2028, as well as issued RFPs for new resources, which are intended to help meet increasing customer energy demands. The level of investments that Idaho Power expects to make in capital improvements and expenditures for infrastructure projects over the next five years is over $1.2 billion per year
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on average. These projects 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 requires significant lead times;
•increases in price and limitations on availability of commodities, materials, and equipment;
•imposition of tariffs or other trade restrictions on commodities, materials, and equipment;
•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;
•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 Idaho Power's available generation capacity, particularly in light of the rapid addition of new industrial and commercial customer load, 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 2025 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 the two units at the North Valmy plant by mid-2026 and the remaining two units at the Jim Bridger plant in 2030. As Idah o 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) the rapid addition of new industrial and commercial customer load and the volatility of such new load demand, (3) 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 (4) 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 2025 and 2024, 52 percent and 54 percent, respectively, o f Idaho Power's electric power from Idaho Power-owned generation was from hydropower facilities. Due to Idaho Power’s heavy reliance on hydropower
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generation, the impacts of factors such as precipitation and snowpack, the timing of run-off, requirements for flood control, 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 any 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. A s 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 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, and changes in technology. Natural gas transportation to Idaho Power's three natural gas plants in Idaho is limited to one primary p ipeline, and natural gas transportation to each of the Jim Bridger plant and the North Valmy plant is also limited to a separate, single pipeline for each plant, 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, and Idaho Power is exposed to risk of disruption of coal production in, or transportation from, its coal suppliers. 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. When the conversion of North Valmy plant unit 2 to gas firing is completed, approximately 40 percent of Idaho Power's generation resources, measured by nameplate capacity, will be fueled by natural gas. Any disruptions in transportation of fuel and defaults by natural gas and coal 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, if available. 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), disruptions in supply chains or price increases resulting in the inability to obtain needed equipment or materials on reasonable terms or at all, 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, 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 and other extraordinary events such as wildfires, the transmission system servicing Idaho Power's service area in the past has been, and in the future may be, constrained, limiting the ability to transmit electric energy within the service area and access electric energy from outside the service area. 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
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life, or property damage, reputational harm, or enforcement actions or liability if a contractor violates applicable laws, rules, regulations, or orders.
Accidents, 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 adversely affected.
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 and, following completion of the Oregon Sale, will be conducted exclusively in its southern Idaho 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 turnover in a 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, lower cost of living in other areas, or other factors. The loss of skills and institutional knowledge of experienced employees, the failure to foster an innovative, welcoming, and respectful company culture in order to hire appropriately qualified employees, the costs associated with attracting, training, and retaining such employees to replace skilled individuals who retire or leave Idaho Power or the inability to do so, a nd the operational and financial costs of unionization or the attempt to unionize all or part of the companies’ workforce, could hav e 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, increased compliance issues, and other factors.
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 at a reasonable cost or at all 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 its industry, or other factors, which could adversely impact Idaho Power’s ability to construct and operate those facilities in a manner most suitable to Idaho Power. Idaho Power owns some 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
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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. Legislative and regulatory proposals and recently enacted legislation that could have a material impact on IDACORP and Idaho Power include, but are not limited to, changes in tax policy or 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, several laws, regulations, executive orders, and policies relating to environmental compliance, tax, and other matters have changed from those of the previous Presidential Administration, with further changes proposed. These changes, in some cases, have required, and may in the future require, IDACORP and Idaho Power and some of their customers to modify their business strategy, activities, and projects. 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. Idaho Power is unable to estimate the costs of complying with recent legislative and 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, these changes may materially and adversely impact IDACORP’s and Idaho Power’s business, financial condition, results of operations, and cash flows.
Changes in 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. The unavailability of expected tax credits or other tax benefits, whether due to a change in law, interpretation, or otherwise, could also have an adverse impact on the economic viability of certain of Idaho Power's planned or existing facilities. 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.
Changes in U.S. trade policy and the impact of tariffs could have an adverse effect on Idaho Power's business and results of operations. The U.S. government has implemented and may continue to implement significant trade policy and tariff actions, including but not limited to tariffs on imported steel and aluminum products, tariffs on certain imports from China, Canada, and Mexico, and baseline tariffs on imports from many other countries. If regulators do not deem prudent the increased costs for Idaho Power's projects or maintenance of its existing facilities resulting from tariffs or other trade policy, Idaho Power may be unable to recover those increased costs through rates in full or at all or on a timely basis. Any inability of Idaho Power to recover increased costs could result in impairment or otherwise materially adversely affect IDACORP's and Idaho Power's financial condition and results of operations. Further, if as a result of increased costs due to tariffs or other trade policies, other resources become more economical, Idaho Power may terminate uneconomical projects and seek to develop those other
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resources. If any projects are canceled because they are no longer economical, Idaho Power could incur significant cancellation penalties under purchase orders or construction contracts.
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 air and water quality, natural resources, endangered species and wildlife, renewable energy, climate change, 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.
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 or other uncertainty, including due to changes instituted by the current Presidential Administration. As a result, 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. Idaho Power has announced long-term, medium-term, and short-term goals for CO 2 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
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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 mi llion per day per violation. As a utility with a large customer base, Idaho Power is subject to adverse publicity focused on the reliability of its services and the speed with which it is able to respond to electric outages caused by storm damage or other unanticipated events. Adverse publicity could harm the reputations of IDACORP and Idaho Power; may make state legislatures, utility commissions, and other regulatory authorities less likely to view the companies in a favorable light; and may cause Idaho Power to be subject to less favorable legislative and regulatory outcomes or increased regulatory oversight. The imposition of any of the foregoing on Idaho Power for its actual or alleged failure to comply with reliability and security requirements could also have a negative effect on its and IDACORP’s results of operations and financial condition.
IDACORP and Idaho Power are subject to costs and other effects of legal and regulatory proceedings, disputes, and claims. From time to time in the normal course of business, IDACORP and Idaho Power are subject to various lawsuits, regulatory proceedings, disputes, and claims that could result in adverse judgments or settlements, fines, penalties, injunctions, or other adverse consequences. These matters are subject to a number of uncertainties, and management is often unable to predict the outcome of such matters. Resulting liabilities could exceed amounts currently reserved or insured against with respect to such matter. The legal costs and final resolution of matters in which IDACORP or Idaho Power are involved could have reputational impact and a short- or long-term negative effect on their financial condition and results of operations. Addressing any adverse publicity or governmental scrutiny could be time consuming and expensive, regardless of the basis of the assertions being made, and could impact Idaho Power's relationship with employees, stakeholders, and regulators. Further, the terms of resolution could require the companies to change their operational practices and procedures, which could also have a negative effect on their financial positions and results of operations.
Changes in accounting standards or rules may impact IDACORP's and Idaho Power's financial results and disclosures. The Financial Accounting Standards Board and the SEC have made and may continue to make changes to accounting standards that impact presentation and disclosures of financial condition and results of operations. Further, new accounting orders issued by the FERC could significantly impact IDACORP's and Idaho Power's reported financial condition. IDACORP and Idaho Power do not have any control over the impact these changes may have on their financial conditions or results of operations nor the timing of such changes. Idaho Power meets the requirements under GAAP to reflect the impact of regulatory decisions in its financial statements and to defer certain costs as regulatory assets until those costs are collected in rates, and to defer some items as regulatory liabilities. If recovery of these amounts ceases to be probable, if Idaho Power determines that it no longer meets the criteria for applying regulatory accounting or if accounting rules change to no longer provide for regulatory assets and liabilities, Idaho Power could be required to eliminate some or all of those regulatory assets or liabilities. Any of these circumstances could result in write-offs and have a material adverse 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
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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. IDACORP has over $600 million of FSAs outstanding from forward sales of its common stock. Settlement of those FSAs is subject to the conditions specified in the FSAs, and there is a risk that the counterparties to the FSAs may not perform their obligations under the FSAs. 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 IDACORP's 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 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 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, increase borrowing costs under the Credit Facilities, 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 regulatory activity related to sustainability matters, particularly global climate change and reducing GHG emissions, could negatively impact IDACORP and Idaho Power. The power and gas utility industry faces stakeholder scrutiny related to sustainability matters. Certain stakeholders, such as investors, customers, suppliers, and lenders focus 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 sustainability-related expectations. GHG emissions, including, most significantly CO 2, 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 laws, regulations, or enforcement policies were to
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become effective, they could result in significant additional compliance and remediation 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. In addition, the focus on climate change and 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 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 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 2025, Idaho Power recorded losses on economic hedges of $37.7 million, compared with $63.3 million of losses in 2024. 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, which could be substantial. 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 rates in market-based 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, by vendors for infrastructure development projects, and by customers or potential customers. If any of the credit ratings of the letter of credit issuers were to drop below investment grade, the vendor, supplier, customer, or potential customer would need to replace the security with an acceptable substitute, which may be impracticable and may expose Idaho Power to losses resulting from a default of the counterparty. If the security were not replaced, the counterparty 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
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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 such costs could continue to rise. As benefit costs continue to rise, there is no assurance that the IPUC and OPUC will continue to allow recovery.
The key actuarial assumptions that affect pension funding obligations are the expected long-term return on plan assets and the discount rate used in determining future benefit obligations. Idaho Power evaluates the actuarial assumptions on an annual basis, taking into account changes in market conditions, trends, and future expectations. Estimates of future investment market performance, changes in interest rates, and other factors Idaho Power and its actuary firms use to develop the actuarial assumptions are inherently uncertain, and actual results could vary significantly from the estimates. Changes in demographics, including timing of retirements or changes in life expectancy assumptions, may also increase Idaho Power's plan costs and funding requirements. Future pension funding requirements and the timing of funding payments are also subject to the impacts of changes in legislation. Depending on the timing of contributions to the plans and Idaho Power's ability to recover costs through rates, cash contributions to the plans could reduce the cash available for the companies' businesses and payment of dividends. For additional information regarding Idaho Power's funding obligations under its benefit plans, see Note 12 - "Benefit Plans" to the consolidated financial statements included in this report.
If the assumptions underlying coal mine reclamation at BCC 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 and legal 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, divestitures, 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;
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•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 various legal and regulatory factors 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 or Oregon 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. In addition, Oregon law requires shareholders to obtain advance approval from the OPUC before acquiring 5% stock ownership in an Oregon public utility, which law Idaho Power expects to apply to it until such time, if any, as the Oregon Sale is consummated. Any of the above provisions could delay or prevent a change in control of Idaho Power. Even if IDACORP's board of directors were to favor a sale of the company, a sale would require approval of a number of federal and state regulatory agencies, including the FERC, the IPUC, OPUC, and 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.
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 and director of security oversee 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 director of security. 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
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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. Under the plan, 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.
Utilities are the operators of critical infrastructure and maintain sensitive information, and as such the industry has been subject to, and will likely continue to be subject to, attempts to gain unauthorized access to systems and confidential information to disrupt operations or for monetary gain. Idaho Power, like other entities in the utility industry, is experiencing an increase in the frequency and sophistication of these attempts. For the year ended December 31, 2025, and the subsequent period to 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 any such threat or incident 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, 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 southern Idaho and eastern Oregon, three natural gas-fired plants in southern Idaho, and interests in a coal-fired and natural gas-fired steam generating plant located in Wyoming and a gas-fired steam generating plant in Nevada. As of December 31, 2025, the system also includes approximately 4,730 pole miles of high-voltage transmission lines, 23 step-up transmission substations located at power plants, 21 transmission substations, 12 switching stations, 31 mixed-use transmission and distribution substations, 188 energized distribution substations (excluding mobile substations and dispatch centers), approximately 30,020 linear miles of distribution lines, and a capacity of 1,228 MWh of battery storage, comprised of 9 facilities, located in southern Idaho and eastern Oregon. As part of the Oregon Sale, Idaho Power expects to sell to OTEC substantially all of its Oregon distribution lines and several substations and certain other assets located in Oregon.
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 IERCo, Idaho Power owns a one-third interest in BCC and coal leases near the Jim Bridger plant in Wyoming from which coal is mined and supplied to generating units 3 and 4 of the plant. Ida-West 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.

Project |  | Nameplate Capacity (Kilowatt (kW))(1) |  | License Expiration
Hydropower Projects: |  |  |  |  |
Properties Subject to Federal Licenses:(2) |  |  |  |  |
Lower Salmon |  | 60,000 |  |  | 2034 |
Bliss |  | 75,038 |  |  | 2034 |
Upper Salmon |  | 34,500 |  |  | 2034 |
Shoshone Falls |  | 14,729 |  |  | 2040 |
CJ Strike |  | 82,800 |  |  | 2034 |
Upper Malad - Lower Malad |  | 21,770 |  |  | 2035 |
HCC: Brownlee, Oxbow, and Hells Canyon |  | 1,276,076 |  |  | 2005 | (3)
Swan Falls |  | 27,170 |  |  | 2042 |
American Falls |  | 92,340 |  |  | 2025 | (3)
Cascade |  | 12,420 |  |  | 2031 |
Milner |  | 59,448 |  |  | 2038 |
Twin Falls |  | 52,898 |  |  | 2040 |
Other Hydropower: |  |  |  |  |
Clear Lake - Thousand Springs |  | 9,300 |  |  |  |
Total Hydropower |  | 1,818,489 |  |  |  |
Steam and Other Generating Plants: |  |  |  |  |
Jim Bridger Units 1 and 2 (gas-fired)(4)(5) |  | 388,008 |  |  |  |
Jim Bridger Units 3 and 4 (coal-fired)(4)(5) |  | 387,278 |  |  |  |
North Valmy Unit 1 (gas-fired)(4)(6) |  | 138,600 |  |  |  |
North Valmy Unit 2 (gas-fired)(4)(6) |  | 144,900 |  |  |  |
Danskin (gas-fired) |  | 270,900 |  |  |  |
Langley Gulch (gas-fired) |  | 318,453 |  |  |  |
Bennett Mountain (gas-fired) |  | 172,800 |  |  |  |
Salmon (diesel-internal combustion) |  | 5,000 |  |  |  |
Total Steam and Other |  | 1,825,939 |  |  |  |
Total Generation |  | 3,644,428 |  |  |  |
(1) Actual generation capacity from a facility may be greater or less than the rated nameplate generation capacity.
(2) Idaho Power holds FERC licenses for all of its hydropower projects that are subject to federal licensing. Relicensing of Idaho Power’s hydropower projects is discussed in Part II - Item 7 - MD&A - "Regulatory Matters – Relicensing of Hydropower Projects" in this report.
(3) Licensed on an annual basis while the application for a new multi-year license is pending.
(4) Idaho Power’s ownership interests are one-third for Jim Bridger and 50 percent for North Valmy. Amounts shown represent Idaho Power’s share.
(5) The conversion of two generating units from coal to natural gas at the Jim Bridger plant was completed in the spring of 2024. Idaho Power's 2025 IRP identified a preferred resource portfolio and action plan that includes the conversion of the two remaining generating units from coal to natural gas at the Jim Bridger plant in 2030.
(6) Pursuant to an agreement with NV Energy, Idaho Power ceased participation in coal-fired operations of North Valmy in December 2019 at unit 1 and December 2025 at unit 2. Idaho Power's 2025 IRP identified a preferred resource portfolio and action plan that includes the conversion of the two generating units at the North Valmy plant from coal to natural gas by mid-2026. The conversion of unit 1 has been completed and was placed in-service in December 2025, and the conversion of unit 2 is expected to be completed by mid-2026.

ITEM 3. LEGAL PROCEEDINGS
Refer to Note 11 – “Contingencies” to the consolidated financial statements included in this report. SEC regulations require IDACORP and Idaho Power to disclose certain information about proceedings arising under federal, state or local environmental provisions if the companies reasonably believe that such proceedings may result in monetary sanctions above a stated threshold. Pursuant to the SEC regulations, the companies use a threshold of $1 million or more for purposes of determining whether disclosure of any such proceedings is required.
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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 13, 2026, there were 6,413 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 2025.
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, 2020, with beginning-of-period weighting of the peer group indices (based on market capitalization) and monthly compounding of returns.
Source: Bloomberg and EEI

|  | 2020 |  | 2021 |  | 2022 |  | 2023 |  | 2024 |  | 2025
IDACORP |  | $ | 100.00 |  |  | $ | 121.45 |  |  | $ | 118.95 |  |  | $ | 111.86 |  |  | $ | 128.57 |  |  | $ | 153.24 |
S&P 500 |  | 100.00 |  |  | 128.68 |  |  | 105.35 |  |  | 133.02 |  |  | 166.27 |  |  | 195.96 |
EEI Electric Utilities Index |  | 100.00 |  |  | 117.12 |  |  | 118.47 |  |  | 108.16 |  |  | 128.82 |  |  | 143.83 |

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 6. [RESERVED]
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
In this MD&A section of 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 2024 compared with 2023 can be found in their Annual Report on Form 10-K for the year ended December 31, 2024. See Part II - Item 7 - MD&A in that report for further information on the companies' prior period results of operations. While reading this 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 section 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. On February 13, 2026, Idaho Power entered into a definitive agreement to sell its Oregon electric distribution business and associated distribution assets, as well as certain Oregon transmission assets, to OTEC. The closing of the transaction is subject to various conditions, including approvals of the OPUC, IPUC, and FERC. For further information regarding the proposed transaction, see Note 22 - "Sale of Oregon Assets" to the consolidated financial statements included in this report.
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 IFS, an investor in affordable housing and other real estate tax credit investments; and Ida-West, an operator of small PURPA-qualifying hydropower generation projects.
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, and milestones during 2025 include the following:
•IDACORP achieved net income growth for an eighteenth consecutive year in 2025.
•Idaho Power continues to focus on timely recovery of costs and earning a reasonable return on investment. In December 2025, the IPUC approved a settlement stipulation (2025 Settlement Stipulation) related to the Idaho general rate case that Idaho Power had filed in May 2025, with new rates effective January 1, 2026. The 2025 Settlement Stipulation is 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 2.3 percent in 2025 and Idaho Power's MWh sales to retail customers in 2025 were the highest in its history, surpassing the previous record set in 2024, reflecting continued growth in its service area.
•In 2025, 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.
•Idaho Power’s residential and business customer satisfaction remain strong – in 2025, it was the highest ranked utility among peers in the segment for overall customer satisfaction in a third-party survey, and was the second highest in the segment for business customer satisfaction, and the second highest in the segment for residential customer satisfaction in a separate third-party survey.
•In September 2025, IDACORP's board of directors approved an increase in the regular quarterly cash dividend on IDACORP’s common stock from $0.86 per share to $0.88 per share, as a part of a 193 percent increase in quarterly dividends approved over the last fourteen years.
•To help meet growing capacity and energy needs in 2027 and beyond, Idaho Power entered into the following transactions in 2025:
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◦an agreement to purchase the output of a 100 MW solar facility, coupled with a 100 MW battery energy storage agreement, with a scheduled online date of June 2027;
◦an agreement to acquire an ownership interest in 250 MW and for rights to an additional 250 MW of northbound capacity on SWIP-N, a planned 285-mile high-voltage transmission line; and
◦an agreement to purchase the output of an 80 MW solar facility, with a scheduled online date of June 2027.
•During 2025, several key projects achieved notable milestones, underscoring significant progress towards Idaho Power addressing peak capacity and energy needs in 2025 and beyond, including the following:
◦Idaho Power commenced construction on the B2H transmission line, with an expected in-service date of late 2027;
◦Idaho Power began receiving power under a 20-year agreement to utilize storage capacity from a third-party 150 MW battery storage facility;
◦80 MW of company-owned battery storage facilities came online, with another 250 MW of company-owned battery storage commencing construction; and
◦Idaho Power filed a CPCN request with the IPUC for 167 MW of natural gas-fueled generating capacity next to the existing Bennett Mountain power plant, with an expected in-service date in 2028.
•In June 2025, Idaho Power filed with the Idaho and Oregon public utility commissions its 2025 IRP, its forecast of load and resources for the next 20 years, including the preferred portfolio of resources necessary to meet predicted demands.
•Idaho Power's estimate of capital expenditures from 2026 to 2030 is in the range of $6.3 billion to $7.2 billion. Part of the magnitude of capital expenditures is driven by Idaho Power's need to acquire additional power supply and transmission resources to meet growing demand.
Summary of 2025 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, 2025, 2024, and 2023 (in thousands of dollars and shares, except earnings per share amounts):

|  | Year Ended December 31,
|  | 2025 |  | 2024 |  | 2023
Idaho Power net income |  | $ | 315,862 |  |  | $ | 280,605 |  |  | $ | 256,810 |
Net income attributable to IDACORP, Inc. |  | $ | 323,472 |  |  | $ | 289,174 |  |  | $ | 261,195 |
Weighted average outstanding shares – diluted |  | 54,806 |  |  | 52,615 |  |  | 50,806 |
IDACORP, Inc. earnings per diluted share |  | $ | 5.90 |  |  | $ | 5.50 |  |  | $ | 5.14 |

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The table below provides a reconciliation of net income attributable to IDACORP for the year ended December 31, 2025, from the year ended December 31, 2024 (items are in millions of dollars and are before tax unless otherwise noted):

Net income attributable to IDACORP, Inc. - December 31, 2024 |  |  |  | $ | 289.2 |
Increase (decrease) in Idaho Power net income: |  |  |  |
Retail revenues per MWh, net of power cost adjustment mechanisms |  | 49.6 |  |  |
Customer growth, net of associated power supply costs and power cost adjustment mechanisms |  | 25.2 |  |  |
Usage per retail customer, net of associated power supply costs and power cost adjustment and FCA mechanisms |  | (6.5) |  |  |
Other O&M expenses |  | (9.6) |  |  |
Depreciation and amortization expense |  | (27.7) |  |  |
Other changes in operating revenues and expenses, net |  | (3.8) |  |  |
Increase in Idaho Power operating income |  | 27.2 |  |  |
Non-operating expense, net |  | (22.8) |  |  |
Additional ADITC amortization |  | 10.5 |  |  |
Income tax expense, excluding additional ADITC amortization |  | 20.4 |  |  |
Total increase in Idaho Power net income |  |  |  | 35.3 |
Other IDACORP changes (net of tax) |  |  |  | (1.0) |
Net income attributable to IDACORP, Inc. - December 31, 2025 |  |  |  | $ | 323.5 |

IDACORP's net income increased $34.3 million for 2025 compared with 2024, due primarily to higher net income at Idaho Power.
The net increase in retail revenues per MWh, net of power cost adjustment mechanisms, increased operating income by $49.6 million in 2025 compared with 2024. This benefit was primarily due to an overall increase in Idaho base rates, effective January 1, 2025, from the outcome of the 2024 Idaho Limited-Issue Rate Case. For more information on the 2024 Idaho Limited-Issue Rate Case, see Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.
Idaho Power's customer growth of 2.3 percent added $25.2 million to Idaho Power's operating income in 2025 compared with 2024. Usage per retail customer, net of associated power supply costs and power cost adjustment and FCA mechanisms, decreased operating income by $6.5 million in 2025 compared with 2024. During 2025, usage per customer decreased for most customer classes. Milder temperatures during the year reduced the demand for both space heating and air conditioning. This decrease was partially offset by an increase in irrigation usage per customer, as lower precipitation during the summer led irrigation customers to run irrigation pumps more frequently. Partially offsetting the revenue impact of decreased usage per customer, a decrease in the deferral of residential and small commercial customer revenues through the FCA mechanism positively impacted retail revenues by $6.8 million.
Other O&M expenses in 2025 were $9.6 million higher than in 2024. This increase was primarily driven by inflationary pressures on labor-related costs, professional services, and increases in statutory fees assessed by regulators.
Depreciation and amortization expense increased $27.7 million in 2025 compared with 2024, due primarily to an increase in plant-in-service. Additionally, the start of operations at a leased battery storage facility in the second quarter of 2025 contributed modestly to the increase through amortization of a related right-of-use asset.
Other changes in operating revenues and expenses, net, decreased operating income by $3.8 million in 2025 compared with 2024, due primarily to the successful conclusion of multi-year litigation efforts challenging Idaho and Oregon property tax valuations, which resulted in refunds of prior year taxes being finalized in 2024, which did not reoccur in 2025. In addition, the timing of recording and adjusting regulatory accruals and deferrals positively impacted 2024 results, but did not reoccur in 2025. These decreases were partially offset by recovery of costs of a new finance lease through Idaho Power's power cost adjustment mechanism rates and a decrease in net power supply expenses that were not deferred for future recovery in rates through Idaho Power's power cost adjustment mechanisms.
Non-operating expense, net, increased $22.8 million in 2025 compared with 2024. Higher long-term debt balances and an increase in transmission customer deposits, on which Idaho Power must pay interest to the customer, led to an increase in interest expense. Interest on a new finance lease also contributed to the increased interest expense compared with 2024. This
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increase was partially offset by an increase in AFUDC during 2025 compared with 2024, as the average construction work in progress balance was higher.
Idaho Power recorded $40.3 million of additional ADITC amortization under its Idaho regulatory settlement stipulation during 2025, compared with $29.8 million in 2024. The $20.4 million decrease in income tax expense, excluding additional ADITC amortization, in 2025 compared with 2024 was primarily due to income tax return adjustments for state taxes and plant-related flow-through items.
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:
•Regulatory 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 is focused on timely recovery of its costs through filings with its regulators and prudent management of expenses and investments.
To address the regulatory lag in recovery of costs primarily associated with Idaho Power’s current and anticipated significant infrastructure investments, in May 2025 Idaho Power filed a general rate case in Idaho and in October 2025 Idaho Power, the IPUC Staff, and intervening parties filed the 2025 Settlement Stipulation with the IPUC. In December 2025, the IPUC approved the 2025 Settlement Stipulation. The IPUC order related to the 2025 Settlement Stipulation is described more fully in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report. The 2025 general rate case followed a limited-scope rate case that Idaho Power filed in Idaho in 2024, as well as general rate cases that Idaho Power filed in Oregon and Idaho in 2023. In light of the regulatory lag in recovery of costs within Idaho Power's substantial capital expenditures to address growth, maintain system reliability, and ensure an adequate supply of electricity, Idaho Power is evaluating its potential rate case filings for 2026.
•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 B2H, GWW, and SWIP-N 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 2025, Idaho Power's customer count grew by 2.3 percent. While recessionary or volatile economic conditions could slow the rate of customer growth, Idaho Power expects its number of customers and, to a greater extent its load due to anticipated commercial and industrial customer growth, to increase for the foreseeable future.
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Idaho Power filed its 2025 IRP, its 20-year forecast of load and power supply resource options, with the IPUC and OPUC in June 2025. Included in the below table are the load forecast assumptions the company used in the 2025 IRP and, for comparison purposes, the analogous average annual growth rates Idaho Power used in the prior two IRPs.

|  | 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)
2025 IRP |  | 8.3% |  | 5.1% |  | 2.7% |  | 1.9%
2023 IRP |  | 5.5% |  | 3.7% |  | 2.1% |  | 1.8%
2021 IRP |  | 2.6% |  | 2.1% |  | 1.4% |  | 1.4%

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, and on July 22, 2024, Idaho Power reached a new all-time summer peak demand of 3,793 MW. Idaho Power believes that existing and sustained growth in customers, load, and peak demand for electricity, the obligation to maintain a safe and reliable system, 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 Idaho Power to increase its investment in capacity resources, transmission, and distribution infrastructure. This includes the B2H, GWW, and SWIP-N transmission projects, along with other capacity, energy, and transmission resource procurements, described in "Liquidity and Capital Resources" in this MD&A. Idaho Power has begun preparation of its 2027 IRP and expects to prepare an updated load forecast during 2026 as the basis for the 2027 IRP, which Idaho Power expects to file in the summer of 2027.
•Weather Conditions: Weather and agricultural growing conditions have a significant impact on Idaho Power's energy sales. Relatively low and high temperatures result in greater energy use for heating and cooling, respectively. During the agricultural growing season, which in large part occurs during the second and third quarters of each year, irrigation customers use electricity to operate irrigation pumps, and weather conditions can impact the timing and extent of use of those pumps. Idaho Power also has tiered rates and seasonal rates, which contribute to increased revenues during higher-load periods, most notably during the third quarter of each year when overall customer demand is highest. Much of the adverse or favorable impact of weather on sales of energy to residential and small commercial customers is mitigated through the Idaho FCA mechanism, which is described in Note 3 - "Regulatory Matters" to the 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 mitigate in large part the impact on earnings. For 2026, Idaho Power expects generation from its hydropower resources to be in the range of 5.5 million to 7.5 million MWh, compared with 7.0 million MWh in 2025 and average total annual hydropower generation of approximately 7.3 million MWh over the last 20 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 PPAs (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
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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.
•Wildfire Mitigation Efforts: In recent years, the western United States has experienced severe wildfires. A variety of factors have contributed to this trend including increased wildland-urban interfaces, historical land management practices, climate change, and overall wildland and forest health. Idaho Power is taking a proactive approach to wildfire risk in its service area and transmission corridors. Several years ago, Idaho Power adopted a WMP that outlines actions Idaho Power is taking or is working to implement to reduce wildfire risk and to strengthen the resiliency of its transmission and distribution system to wildfires, and Idaho Power has refined that WMP over time. Idaho Power's approach to wildfire mitigation includes identifying areas subject to elevated risk; system hardening programs, vegetation management, and field personnel practices to mitigate wildfire risk; incorporating current and forecasted weather and field conditions into operational practices; public safety power shutoff protocols; and evaluating the performance and effectiveness of its approach through metrics and monitoring. Idaho Power has regulatory authorization in both Idaho and Oregon to defer, for potential future amortization, certain actual incremental O&M expenses necessary to implement the WMP. The WMP regulatory deferrals are described in more detail in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report. In July 2025, the Wildfire Standard of Care Act became effective in Idaho. In October 2025, Idaho Power filed a new WMP with the IPUC in accordance with Idaho's Wildfire Standard of Care Act. As of the date of this report, the IPUC's decision on the filing is pending. See "Other Matters - Idaho's Wildfire Standard of Care Act" for additional details.
RESULTS OF OPERATIONS
This section of MD&A takes a closer look at the significant factors that affected IDACORP’s and Idaho Power’s financial results of operations for 2025, compared with 2024.
The table below presents Idaho Power’s energy sales and supply (in thousands of MWh) for the last two years ended December 31.

|  | 2025 |  | 2024
Retail energy sales |  | 16,177 |  |  | 15,971 |
Wholesale energy sales |  | 1,381 |  |  | 1,412 |
Energy sales bundled with RECs |  | 1,516 |  |  | 1,406 |
Total energy sales |  | 19,074 |  |  | 18,789 |
Hydropower generation |  | 7,021 |  |  | 7,203 |
Jointly-owned thermal generation(1) |  | 2,906 |  |  | 2,474 |
Natural gas-fired and other generation |  | 3,685 |  |  | 3,843 |
Total system generation |  | 13,612 |  |  | 13,520 |
Purchased power |  | 6,783 |  |  | 6,541 |
Line losses |  | (1,321) |  |  | (1,272) |
Total energy supply |  | 19,074 |  |  | 18,789 |

(1) "Jointly-owned thermal generation" is composed of generation from steam plants that are fueled by only coal or by both coal and natural gas.
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For purposes of illustration, Boise, Idaho weather-related information for the last two years ended December 31 is presented in the table that follows.

|  | 2025 |  | 2024 |  | Normal(2)
Heating degree-days(1) |  | 4,639 |  |  | 4,844 |  |  | 5,321 |
Cooling degree-days(1) |  | 1,255 |  |  | 1,432 |  |  | 1,045 |
Precipitation (inches) |  | 11.8 |  |  | 15.6 |  |  | 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.
Sales Volume and Generation: In 2025, retail sales volumes increased 1 percent compared with the prior year, primarily due to growth in the number of Idaho Power customers. The number of Idaho Power customers grew by 2.3 percent in 2025. For more information on the changes in sales volume, see the "Operating Revenues" section below in this MD&A.
Total system generation increased 1 percent in 2025 compared with 2024, due primarily to higher jointly-owned thermal generation, mostly offset by lower natural gas generation and hydropower 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 of dollars), MWh sales (in thousands of MWh), and number of retail customers for the last two years ended December 31.

|  | 2025 |  | 2024
Retail revenues: |  |  |  |
Residential (includes $3,972 and ($2,686), respectively, related to the FCA(1)) |  | $ | 708,126 |  |  | $ | 700,586 |
Commercial (includes ($76) and ($170), respectively, related to the FCA(1)) |  | 394,313 |  |  | 397,385 |
Industrial |  | 270,571 |  |  | 267,211 |
Irrigation |  | 198,468 |  |  | 196,401 |
Deferred revenue related to HCC relicensing AFUDC(2) |  | (15,120) |  |  | (8,803) |
Total retail revenues |  | $ | 1,556,358 |  |  | $ | 1,552,780 |

(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 in its Idaho jurisdiction, even though the relicensing process is not yet complete and the costs have not been moved to utility plant in service. Effective October 1, 2025, Idaho Power began collecting $38.5 million annually. Prior to October 1, 2025, Idaho Power collected $8.8 million annually. For more information refer to Note 3 - "Regulatory Matters" to the consolidated financial statements in this report. Amounts collected in the Idaho jurisdiction are recognized as deferred revenue until the license is issued and the accumulated license costs approved for recovery are placed in service.
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|  | MWh Sales | Retail Customers |
|  | 2025 |  | 2024 |  | 2025 |  | 2024 |
Residential |  | 6,010 |  |  | 5,964 |  |  | 560,606 |  |  | 547,010 |  |
Commercial |  | 4,348 |  |  | 4,332 |  |  | 80,832 |  |  | 79,496 |  |
Industrial |  | 3,775 |  |  | 3,680 |  |  | 149 |  |  | 145 |  |
Irrigation |  | 2,044 |  |  | 1,995 |  |  | 22,627 |  |  | 22,554 |  |
Total |  | 16,177 |  |  | 15,971 |  |  | 664,214 |  |  | 649,205 |  |

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.
Retail Revenues: Retail revenues increased $3.6 million in 2025 compared with 2024. The primary factors affecting retail revenues during the period were the following:
•Rates: Customer rates, excluding revenues related to power cost adjustment mechanisms, increased retail revenues by $49.6 million in 2025 compared with 2024, due primarily to an overall increase in Idaho base rates, effective January 1, 2025, from the outcome of the 2024 Idaho Limited-Issue Rate Case. Customer rates also include the collection from customers of amounts related to the power cost adjustment mechanisms, which decreased revenues by $71.2 million in 2025 compared with 2024. 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 2.3 percent increased retail revenues by $39.4 million in 2025 compared with 2024.
•Usage: Lower usage (on a per customer basis) in most customer classes decreased retail revenues by $20.9 million during 2025 compared with 2024, primarily due to weather variations that caused lower usage per customer. Milder temperatures during the year reduced the demand for both space heating and air conditioning. This decrease was partially offset by an increase in irrigation usage per customer, as lower precipitation during the summer led irrigation customers to run irrigation pumps more frequently.
•FCA Mechanism: A decrease in the deferral of residential and small commercial customer revenues through the FCA mechanism positively affected retail revenues by $6.8 million in 2025 compared with 2024.
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 of dollars and MWh, except for revenue per MWh amounts).

|  | 2025 |  | 2024
Wholesale energy revenues |  | $ | 55,989 |  |  | $ | 73,908 |
Wholesale MWh sold |  | 1,381 |  |  | 1,412 |
Wholesale energy revenues per MWh |  | $ | 40.54 |  |  | $ | 52.34 |

In 2025, wholesale energy revenue decreased by $17.9 million, or 24 percent, compared with 2024, due primarily to lower wholesale market prices. Wholesale energy prices were lower during 2025 compared with 2024 as more moderate winter and summer weather resulted in lower natural gas fuel costs in the wholesale markets in the region. The financial impacts of
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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, 2025, Idaho Power's energy efficiency rider balances were a $13.4 million regulatory liability in the Idaho jurisdiction and a $3.1 million regulatory liability in the Oregon jurisdiction.
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 of dollars and MWh, except for per MWh amounts).

|  | 2025 |  | 2024
Purchased power expense |  | $ | 392,462 |  |  | $ | 425,082 |
MWh purchased |  | 6,783 |  |  | 6,541 |
Average cost per MWh |  | $ | 57.86 |  |  | $ | 64.99 |

Purchased power expense decreased $32.6 million, or 8 percent, in 2025 compared with 2024. The decrease in purchased power expense in 2025 is primarily due to lower wholesale energy market prices as milder winter and summer weather resulted in 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 of dollars and MWh, except for per MWh amounts).

|  | Fuel Expense |  | MWh Generated |  | Cost per MWh
|  | 2025 |  | 2024 |  | 2025 |  | 2024 |  | 2025 |  | 2024
Jointly-owned thermal(1) |  | $ | 115,924 |  |  | $ | 97,427 |  |  | 2,906 |  |  | 2,474 |  |  | $ | 39.89 |  |  | $ | 39.38 |
Natural gas(2) |  | 137,312 |  |  | 161,777 |  |  | 3,685 |  |  | 3,843 |  |  | 37.26 |  |  | 42.10 |
Total/Weighted average, all |  | $ | 253,236 |  |  | $ | 259,204 |  |  | 6,591 |  |  | 6,317 |  |  | $ | 38.42 |  |  | $ | 41.03 |

(1) "Jointly-owned thermal" is composed of expenses and generation from steam plants that are fueled only by coal or by both coal and natural gas.
(2) 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 thermal plants is purchased through long-term contracts, including coal 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 decreased $6.0 million, or 2 percent, in 2025 compared with 2024. In 2025, jointly-owned thermal generation increased 17 percent to serve load and provide power for wholesale energy sales compared with 2024. The impact of this generation increase on fuel expense was more than offset during 2025 by lower natural gas market prices compared with 2024.
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 2025 and 2024, losses on financial gas hedges of $37.7 million and $63.3 million, respectively, increased 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.
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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, export credit mechanisms, a battery storage lease, 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 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 of dollars).

|  | 2025 |  | 2024
Idaho power supply cost accrual (deferral) |  | $ | 25,448 |  |  | $ | (5,606) |
Oregon power supply cost (deferral) accrual |  | (2,787) |  |  | 1,954 |
Amortization of prior year authorized balances |  | 2,336 |  |  | 93,409 |
Total power cost adjustment (income statement) |  | $ | 24,997 |  |  | $ | 89,757 |

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 2025, purchased power costs led to lower actual power supply costs compared with the forecasted amount, which resulted in an accrual of power supply costs by the mechanism. In 2024, higher purchased power expense and fuel costs 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 $9.6 million in 2025 compared with 2024. This increase was primarily driven by inflationary pressures on labor-related costs, professional services, and increases in statutory fees assessed by regulators.
Income Taxes
IDACORP and Idaho Power's income tax expense decreased $28.8 million and $30.9 million, respectively, when compared with 2024. The changes were primarily due to income tax return adjustments for state taxes and plant-related flow-through items, and increased ADITC amortization at Idaho Power under its Idaho regulatory mechanism, described in Note 3 - “Regulatory Matters” to the consolidated financial statements included in this report. The decreases were offset partially by an increase in income taxes due to higher income before income taxes. 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 $1.1 billion in 2025 and $981 million in 2024. Idaho Power
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expects an increase in capital expenditures over the next several years, with estimated total capital expenditures of up to $7.2 billion over the period from 2026 through 2030.
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 13, 2026, IDACORP's and Idaho Power's access to debt, equity, and credit arrangements included the following:
•their respective $100 million and $400 million revolving Credit Facilities;
•their issuance of commercial paper, with program sizes of $100 million and $300 million, respectively. Idaho Power's commercial paper program may be increased up to the $400 million capacity of its credit facility;
•IDACORP's shelf registration statement filed with the SEC on February 21, 2025, which may be used for the issuance of debt securities and common stock, including a remaining aggregate gross sales price of up to $155 million in shares of IDACORP common stock available for issuance through its ATM offering program;
•IDACORP's executed FSAs under its ATM offering program, which may be physically settled with common stock in exchange for net proceeds, which as of February 13, 2026, would have been approximately $52 million;
•IDACORP's FSAs, independent of the ATM offering program, which may be physically settled with common stock in exchange for net proceeds, which as of February 13, 2026, would have been approximately $558 million; and
•Idaho Power's shelf registration statement filed with the SEC on February 21, 2025, which may be used for the issuance of first mortgage bonds and other debt securities; $500 million remains available for issuance pursuant to state regulatory authority.
IDACORP uses original issuances of shares for the IDACORP, Inc. Dividend Reinvestment and Stock Purchase Plan and also intends to potentially use original issuances for share purchases within the Idaho Power Company Employee Savings Plan beginning in the first half of 2026. IDACORP may discontinue using original issuances of shares for these plans at any time.
In March 2025, IDACORP executed FSAs under its ATM offering program with various counterparties at an aggregate gross sales price of $52 million. Additionally, in May 2025, IDACORP executed FSAs, independent of the ATM offering program, with various counterparties at an aggregate gross sales price of $575 million. IDACORP may settle the FSAs at any time up to their respective maturity dates. As of February 13, 2026, if IDACORP had elected to physically settle by delivering shares of common stock, aggregate cash proceeds from all outstanding FSAs would have been approximately $610 million.
As described in the "Financing Cash Flows" section below, during 2025, IDACORP physically settled FSAs under its ATM offering program with shares of common stock in exchange for cash proceeds and contributed a portion of the net proceeds to Idaho Power. For more detailed information about IDACORP's and Idaho Power's equity transactions, see Note 6 - "Common Stock" to the consolidated financial statements included in this report. Further, during 2025, Idaho Power issued first mortgage bonds and repaid maturing variable rate bonds. For more detailed information about Idaho Power's long-term debt transactions, see Note 5 - "Long-Term Debt" 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 first mortgage bonds or other debt securities, if the companies believe terms available in the capital markets are favorable and that issuances would be financially prudent. IDACORP may also elect to issue common stock, from time to time, under its ATM offering program, depending on market conditions and capital needs. Idaho Power also periodically analyzes whether partial or full early redemption of one or more existing outstanding series of first mortgage bonds is desirable, and in some cases, may refinance indebtedness with new indebtedness.
Based on planned capital expenditures and other O&M expenses, the companies believe they will be able to meet capital and debt service requirements and fund corporate expenses during at least the next twelve months 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, 2025, IDACORP's and Idaho Power's capital structures, as calculated for purposes of applicable debt covenants, with no impact to equity from unsettled FSAs, were as follows:
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|  | IDACORP |  | Idaho Power
Debt |  | 52% |  | 52%
Equity |  | 48% |  | 48%

IDACORP and Idaho Power generally maintain their cash and cash equivalents in highly liquid investments, such as U.S. Treasury Bills, money market funds, and bank deposits.
Operating Cash Flows
IDACORP's and Idaho Power's principal sources of cash flows from operations are Idaho Power's sales of electricity and transmission capacity. Significant uses of cash flows from operations include the purchase of fuel and power, other operating expenses, interest, income taxes, and plan contributions. Operating cash flows can be significantly influenced by factors such as weather conditions, rates and the outcome of regulatory proceedings, and economic conditions. As fuel and purchased power are significant uses of cash, Idaho Power has regulatory mechanisms in place that provide for the deferral and recovery of the majority of the fluctuation in those costs. However, if actual costs rise above the level currently allowed in retail rates, deferral balances increase (reflected as a regulatory asset), negatively affecting operating cash flows until such time as those costs, with interest, are recovered from customers.
IDACORP’s and Idaho Power’s operating cash inflows in 2025 were $602 million and $568 million, respectively, an increase in cash flows from operations of $7 million for IDACORP and Idaho Power, when compared with the same period in 2024. With the exception of cash flows related to income taxes, IDACORP's operating cash flows are principally derived from the operating cash flows from Idaho Power. Significant items that affected the companies' operating cash flows in 2025 when compared with the same period in 2024 were as follows:
•a $34 million and $35 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 PCA and FCA mechanisms, decreased IDACORP and Idaho Power operating cash flows by $84 million;
•changes in deferred taxes and taxes accrued and receivable combined to decrease operating cash flows for IDACORP and Idaho Power by $19 million; and
•changes in working capital balances due primarily to timing, including fluctuations as follows:
◦the timing of collections of accounts receivable and unbilled receivables decreased operating cash flows by $22 million for IDACORP and $23 million for Idaho Power;
◦the changes in materials, supplies, and fuel stock increased operating cash flows by $103 million for IDACORP and Idaho Power, which was primarily due to the timing of purchases and consumption of materials and supplies inventory at Idaho Power and coal at Idaho Power's jointly-owned coal-fired generating plants;
◦the changes in accounts and wages payable decreased operating cash flows by $33 million for IDACORP and Idaho Power, which was primarily due to timing of payments and higher quarterly cutoff accruals; and
◦the changes in other assets and liabilities increased operating cash flows by $5 million for IDACORP and Idaho Power, primarily due to a third-party deposit and a deferred termination payment.
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 2025 was $1.0 billion, increasing cash outflow by $111 million for IDACORP and by $98 million for Idaho Power when compared with the same period in 2024. Investing cash outflows for 2025 and 2024 were primarily for construction of utility infrastructure needed to address Idaho Power’s customer growth and peak resource needs, aging plant and equipment, and environmental and regulatory compliance requirements. Significant items and transactions that affected investing cash flows in 2025 and 2024 included:
•$1.2 billion and $1.0 billion, respectively, of additions to property, plant, and equipment;
•$152 million and $84 million, respectively, from B2H project joint permitting participants relating to a portion of the permitting expenditures;
•$16 million and $4 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; and
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•IDACORP and Idaho Power paid $11 million and $8 million in 2025, respectively, and $12 million and $11 million in 2024, respectively, for purchases of equity securities, $3 million in 2025 and $2 million in 2024 for purchases of held-to-maturity securities, and received $12 million in 2025 and $11 million in 2024 from sales of equity securities, held in a rabbi trust, which is designated to provide funding for obligations related to Idaho Power's SMSP.
Financing Cash Flows
Financing activities primarily 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 2025 were $274 million and $376 million, respectively, a decrease of $91 million for IDACORP and an increase of $104 million for Idaho Power, when compared with the same period in 2024. 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 2025 and 2024 were as follows:
•in 2025 and 2024, Idaho Power issued $400 million and $300 million, respectively, in aggregate principal amount of first mortgage bonds;
•in 2025 and 2024, Idaho Power repaid $20 million in principal amount of maturing variable rate bonds and $50 million in principal amount of pollution control revenue bonds, respectively;
•in 2025, IDACORP received $92 million of aggregate cash proceeds from the settlement of FSAs under its ATM offering program;
•in 2024, IDACORP received $292 million of aggregate cash proceeds from the settlement of FSAs, independent of the ATM offering program;
•in 2025 and 2024, Idaho Power received $195 million and $200 million, respectively, of capital contributed from IDACORP; and
•IDACORP and Idaho Power paid dividends of $188 million each in 2025, and $177 million and $176 million, respectively, in 2024.
Financing Programs and Available Liquidity
IDACORP Equity Programs: As of February 13, 2026, IDACORP's cumulative aggregate gross sales price of executed and outstanding FSAs under its ATM offering program was $52 million, and $155 million in shares of IDACORP’s common stock remained available for issuance. If IDACORP had elected to physically settle the FSAs under its ATM offering program as of February 13, 2026, by delivering shares of common stock, cash proceeds would have been approximately $52 million. IDACORP may settle the FSAs under its ATM offering program at any time, up to their respective maturity dates of March 31, 2026.
In May 2025, IDACORP executed FSAs, independent of the ATM offering program, with various counterparties in connection with a completed $575 million registered public offering of approximately 5.2 million shares of its common stock. If IDACORP had elected to physically settle these FSAs as of February 13, 2026, by delivering shares of its common stock, cash proceeds would have been approximately $558 million. IDACORP may settle these FSAs at any time, up to their maturity date of November 9, 2026.
As described elsewhere in this MD&A, IDACORP has significant planned capital expenditures in the near-term, and the company may settle the FSAs at any time up to the maturity date. See Note 6 - "Common Stock" to the consolidated financial statements included in this report for more information on IDACORP's equity programs. Depending on market conditions, its financial and regulatory strategy, and other factors, IDACORP could determine to issue additional equity securities in 2026.
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 February and March 2024, 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, 2025, $500 million remained available for debt issuance under the regulatory 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.
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IDACORP and Idaho Power 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 then existing credit agreements. 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 conditi ons. 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 Term Secured Overnight Financing Rate (SOFR) plus 1.0 percent, or 1.0 percent, or (2) the Term SOFR, plus, in each case an applicable margin, provided that the Term SOFR will not be less than 0.0 percent. If during any period the Term 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. In December 2025, IDACORP and Idaho Power entered into an extension and amendment to each credit agreement, extending the maturity date under both credit agreements to December 6, 2030, and providing for two additional one-year extensions, in each case 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, 2025, the leverage ratios for IDACORP and Idaho Power were 52 percent. 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, 2025, 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 2026.
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, OPUC, and 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 table below outlines available short-term borrowing liquidity as of the dates specified (in thousands of dollars):

|  | December 31, 2025 |  | December 31, 2024
|  | IDACORP(1) |  | Idaho Power |  | IDACORP(1) |  | Idaho Power
Revolving credit facility |  | $ | 100,000 |  |  | $ | 400,000 |  |  | $ | 100,000 |  |  | $ | 400,000 |
Commercial paper outstanding |  | — |  |  | — |  |  | — |  |  | — |
Identified for other use(2) |  | — |  |  | — |  |  | — |  |  | (19,885) |
Net balance available |  | $ | 100,000 |  |  | $ | 400,000 |  |  | $ | 100,000 |  |  | $ | 380,115 |
(1) Holding company only.
(2) American Falls bonds that Idaho Power could have been 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. The bonds were repaid at maturity in February 2025.

At February 13, 2026, IDACORP and Idaho Power had no loans outstanding under their respective revolving credit facilities and had no commercial paper outstanding. The table below presents additional information about short-term commercial paper borrowing during the year ended December 31 (in thousands of dollars, except percentages).

|  | 2025 |  | 2024
|  | IDACORP(1) |  | Idaho Power |  | IDACORP(1) |  | Idaho Power
Commercial Paper: |  |  |  |  |  |  |  |
Period end: |  |  |  |  |  |  |  |
Amount outstanding |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |
Weighted average interest rate |  | — | % |  | — | % |  | — | % |  | — | %
Daily average amount outstanding during the period |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | 191 |
Weighted average interest rate during the period |  | — | % |  | — | % |  | — | % |  | 5.62 | %
Maximum month-end balance |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | 10,000 |
(1) Holding company only.

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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, depend 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 |  | Negative |  | Negative |  | 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 $1.1 billion during the year ended December 31, 2025. 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 2026 through 2030 (in billions 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. Actual expenditures and timing may differ substantially from the estimates in the table due to factors such as 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.

|  | 2026 |  | 2027 |  | 2028-2030
Expected capital expenditures (excluding AFUDC), in billions of dollars |  | $ | 1.3 - 1.5 |  | $ | 1.4 - 1.6 |  | $ | 3.6 - 4.1

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 2026 through 2030 and estimated costs include the following:
•$220-$310 million per year for construction and replacement of transmission lines and stations other than the B2H, GWW, and SWIP-N projects discussed below;
•$230-$325 million per year for construction and replacement of distribution lines and stations;
•$20-$60 million per year for ongoing improvements and replacements at thermal plants;
•$115-$150 million per year for hydropower plant improvement programs, including relicensing costs; and
•$75-$100 million per year for general plant improvements, such as land and buildings, vehicles, information technology, and communication equipment.
Other Major Infrastructure Projects: Idaho Power is developing a number of significant infrastructure projects, including some developed jointly with third parties. The most notable projects are described below.
Resource Additions to Address Projected Energy and Capacity Deficits: 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
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acquire significant generation, transmission, and storage resources to meet energy and capacity needs in recent years and continuing over the next several years. In addition to resources already placed in service through 2025, Idaho Power has undertaken the following efforts to help meet peak needs in 2026 and beyond:
•entered into contracts or plans to construct, own, and operate 250 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 100 MW battery storage facility;
•entered into an energy and capacity market purchase agreement with an energy marketer giving Idaho Power the right to acquire 200 MW on a daily basis during summer months beginning in 2026 for a term of at least five years;
•entered into four PPAs for a combined 625 MW output of planned third-party solar facilities. Idaho Power plans to sell the output of two of these solar PPAs totaling 445 MW exclusively to a large industrial customer pursuant to an agreement under Idaho Power’s Clean Energy Your Way program; and
•submitted an application to the IPUC for a CPCN for 167 MW of natural gas-fueled generating capacity next to the existing Bennett Mountain power plant in 2028.
The capital requirements table above includes capital expenditures of more than $1.7 billion from 2026 through 2030 for resource additions to address projected energy and capacity deficits in those years and beyond. Included in this amount are estimates of costs of resource additions for which Idaho Power has received CPCNs or has entered into significant financial commitments and expects to request a CPCN for the resource in the near future. Idaho Power continues to evaluate resource needs and outstanding RFPs. Actual expenditures and their timing could deviate substantially from Idaho Power's expected expenditures 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 PPAs or similar agreements, and the outcome of regulatory proceedings.
B2H Transmission Line: The B2H line, a 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. Idaho Power began construction in June 2025 and, based on the anticipated construction schedule as of the date of this report, expects the in-service date for the transmission line will be by late 2027.
In 2023, Idaho Power entered an agreement with BPA to transfer BPA's 21 percent ownership interest in the project to Idaho Power, increasing Idaho Power's interest to approximately 45 percent. PacifiCorp's ownership interest in the project is approximately 55 percent. Idaho Power has spent approximately $671 million, including Idaho Power's AFUDC, on the B2H project through December 31, 2025. Pursuant to the terms of joint funding arrangements, Idaho Power has received $360 million in reimbursement as of December 31, 2025, from project co-participants for their share of costs and continues to receive reimbursement as costs are incurred. PacifiCorp is obligated to reimburse Idaho Power for its share of any future project expenditures incurred by Idaho Power under the terms of the joint funding agreement. Idaho Power and PacifiCorp operate under a construction funding agreement filed with the FERC.
The permitting phase of the B2H 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, Oregon's Energy Facility Siting Council approved Idaho Power's site certificate in 2022 followed by a final order and two amendments to the site certificate, both contested but upheld in subsequent judicial proceedings. In 2023, the IPUC, OPUC, and WPSC granted Idaho Power and PacifiCorp their respective CPCNs related to the construction of the B2H project. In June 2025, three parties filed complaints with the OPUC seeking reconsideration of the CPCN granted for B2H, but in November 2025, the OPUC upheld the B2H CPCN. Those parties have now filed three complaints in the Baker County and Union County Circuit Courts challenging the OPUC decision. These cases remain pending. In addition, in September 2025, two parties filed complaints in Morrow County Circuit Court alleging that the Oregon Department of Energy and the Oregon Energy Facility Siting Council improperly modified the Fire Protection and Suppression Plan. Idaho Power has moved to dismiss that claim, and the case remains pending.
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 $415 million of Idaho Power's share of estimated costs (excluding AFUDC) related to the remaining material procurement and construction of the project.
GWW Transmission Line: Idaho Power and PacifiCorp are pursuing the joint development of the GWW project, a high-voltage transmission line 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
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has expended approximately $91 million, including Idaho Power's AFUDC, for its share of the project costs through December 31, 2025.
The permitting phase of the GWW 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 2020 and 2024, PacifiCorp completed construction and commissioned segments of its portion of the project in Wyoming. In March 2023, PacifiCorp initiated the pre-construction phase of approximately 620 miles of 500-kV transmission line from the Populus substation near Downey, Idaho, to the Hemingway substation near Boise, Idaho. Idaho Power has ownership interest in four segments within this area, totaling approximately 330 miles of new line.
Current permitting and pre-construction activities are focused on the segment of line between the Hemingway substation and the Midpoint substation, near Jerome, Idaho. Idaho Power is the majority owner of the approximately 130-mile segment, and, as of the date of this report, Idaho Power estimates the total cost for its share of this segment and the associated substation work to be between $900 million and $1.1 billion, including Idaho Power's AFUDC. The capital requirements table above includes approximately $790 million of Idaho Power's share of estimated costs (excluding AFUDC) for the permitting and construction phases of the project based on Idaho Power's assumption that it may commence construction of this segment during that time period. Idaho Power expects the in-service date for this segment of line or a portion of this segment will be 2028 or later. Idaho Power and PacifiCorp continue to coordinate the timing of next steps of the remaining co-owned segments to best meet customer and system needs, including potentially modifying the ownership structure of those segments of the project.
SWIP-N: In February 2025, Idaho Power entered into a commitment to become a partial owner of SWIP-N, a planned 285-mile, high-voltage transmission line between the Robinson Summit Substation near Ely, Nevada, and the Midpoint Substation near Jerome, Idaho. Upon the project being placed into service, the applicable agreements provide that Idaho Power will purchase an approximate 11 percent ownership interest in the project, entitling Idaho Power to approximately 11 percent of the total capacity of the SWIP-N line. In addition, Idaho Power entered into a capacity entitlement agreement entitling Idaho Power to approximately 11 percent of additional capacity on the SWIP-N line over a 40-year term commencing upon the project being placed in service. Idaho Power expects construction of the project to commence in 2026 and to be completed in 2028 or thereafter. Idaho Power is responsible for approximately 11 percent of the total costs to develop and construct the project. The capital requirements table above includes Idaho Power's share of the costs to develop and construct the project. The project agreements do not require Idaho Power to incur any costs to purchase its ownership interest or begin paying for capacity under the capacity entitlement agreement until the line is in service. Idaho Power has an option to purchase the ownership interest associated with such capacity entitlement upon expiration of the 40-year term. On December 12, 2025, the IPUC issued its order approving a CPCN for the project. SWIP-N has received various required governmental approvals, including from the FERC and the Public Utilities Commission of Nevada, while certain other approvals and permits remain in process.
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 $536 million (including AFUDC) for the HCC were included in construction work in progress at December 31, 2025. As of the date of this report, the IPUC authorizes Idaho Power to include in its Idaho jurisdiction rates approximately $38.5 million of AFUDC annually relating to the HCC relicensing project. Collecting these amounts currently will reduce future collections when HCC relicensing costs are approved for recovery in base rates. As of December 31, 2025, Idaho Power's regulatory liability for collection of AFUDC relating to the HCC was $281 million. As discussed in Note 3 – “Regulatory Matters – Notable Idaho Base Rate Adjustments – Recovery of Incremental AFUDC Associated with HCC" to the consolidated financial statements included in this report, in March 2025, Idaho Power filed an application with the IPUC to increase the annual cash collection of AFUDC associated with relicensing of the HCC project from $8.8 million to $38.5 million. In September 2025, the IPUC approved Idaho Power's proposed increase in annual cash collection to recover AFUDC associated with relicensing of the HCC project, effective October 1, 2025.
As of the date of this report, Idaho Power anticipates that the FERC could issue a new HCC license in 2027 or thereafter. However, the exact timing, as well as the total capital investment and ongoing operating and maintenance costs required to comply with the new license remain uncertain. Idaho Power estimates that annual costs to obtain a new long-term license, including AFUDC but excluding post-issuance compliance cost, will range from $35 million to $45 million until t he license is
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issued. Upon issuance of a long-term license, Idaho Power expects that the annual capital expenditures and operating and maintenance expenses to meet the long-term license's terms and conditions could also be significant. Following Idaho Power's application, the IPUC issued an order in April 2018 approving a settlement stipulation among the parties recognizing that a total of $216.5 million in expenditures were prudently incurred and, therefore, should be eligible for inclusion in customer rates in a future rate proceeding.
In December 2025, Idaho Power filed an application with the IPUC requesting a determination that $305 million of additional costs between January 1, 2016 and September 30, 2025, to relicense the HCC were also prudently incurred. Idaho Power plans to file a supplemental application in this case in 2026 for the inclusion of additional costs incurred during the final three months of 2025. This case remains pending.
Jackalope Wind Project: In October 2024, Idaho Power entered into agreements with a counterparty and certain of its affiliates to develop the Jackalope Wind Project, which consisted of (i) a 35-year PPA between Jackalope Wind, LLC and Idaho Power, supplying a capacity of approximately 300 MW of generation to Idaho Power's system from a wind-powered generation facility located in Sweetwater County, Wyoming, and (ii) a co-located wind turbine generator power plant to be owned by Idaho Power, providing a capacity of 300 MW of generation. In September 2025, due to permitting delays and uncertainty around federal land use policies, Idaho Power, the counterparty, and applicable affiliates of the counterparty terminated the agreements for the project.
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.
Defined Benefit Pension Plan Contributions and Recovery
Idaho Power contributed $20 million in 2025 and 2024 to its defined benefit pension plan. Idaho Power estimates that it has no minimum required contribution to be made during 2026. Depending on market conditions and cash flow considerations, Idaho Power expects that it could contribute up to $30 million to the pension plan during 2026. 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 2026, Idaho Power expects continuing contributions under the pension plan could be significant. Refer to Note 12 – “Benefit Plans” to the consolidated financial statements included in this report for information relating to those obligations.
Idaho Power defers its Idaho-jurisdiction pension expense as a regulatory asset until recovered from Idaho customers. At December 31, 2025 and 2024, Idaho Power's deferral balance associated with the Idaho jurisdiction was $247 million and $252 million, respectively. Deferred pension costs are amortized to expense to match the revenues received when contributions are recovered through rates. Idaho Power only records a carrying charge on the unrecovered balance of cash contributions. The IPUC has authorized Idaho Power to recover and amortize $35 million of deferred pension costs annually. 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, 2025, include long-term debt, interest payments, purchase obligations, leases, 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
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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 directors' dividend decisions. In September 2025, IDACORP adjusted the near-term target payout ratio to between 50 percent and 60 percent of IDACORP earnings, considering Idaho Power's financing needs to fund its capital investments and ongoing operations. Notwithstanding IDACORP's dividend policy, the dividends IDACORP pays remain in the discretion of the board of directors, which, when evaluating the dividend amount, will continue to take into account the factors above, among others. In September 2025 and 2024, IDACORP's board of directors voted to increase the quarterly dividend to $0.88 per share and $0.86 per share of IDACORP common stock, respectively. IDACORP's dividends during 2025 were 58.6 percent of actual 2025 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, 2025, 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, OPUC, and 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, OPUC, and WPSC as to the issuance of debt and equity securities. As a public utility under the FPA, Idaho Power has been granted the 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. Idaho Power filed a general rate case in Idaho in 2025, which was resolved by the 2025 Settlement Stipulation, as approved by the IPUC in December 2025. The 2025 Settlement Stipulation provided for Idaho Power to implement revised tariff schedules designed to increase annual Idaho-jurisdictional retail revenue by approximately $110.0 million, or 7.48 percent, effective January 1, 2026. In light of the regulatory lag in recovery of costs within Idaho Power's substantial capital
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expenditures to address growth, maintain system reliability, and ensure an adequate supply of electricity, Idaho Power is evaluating its potential rate case filings for 2026.
Previously, Idaho Power filed the 2024 Idaho Limited-Issue Rate Case in May 2024, focused on revenue requirements for 2024 incremental plant additions and incremental ongoing labor costs, which was resolved by an IPUC order in December 2024. Idaho Power also filed general rate cases in Idaho and Oregon in 2023, which were resolved by the 2023 Settlement Stipulation in Idaho and the 2024 Oregon Settlement Stipulations in Oregon.
Between general rate cases, Idaho Power relies upon customer growth, an FCA mechanism in Idaho, power cost adjustment mechanisms, limited-issue rate cases, 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.
Notable Retail Rate Changes in Idaho and Oregon
The table below presents notable recent retail rate changes that affected Idaho Power's results for the periods of this report or that will likely affect future periods. Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report also provides a description of regulatory mechanisms and associated orders of the IPUC and OPUC, and should be read in conjunction with the discussion of regulatory matters in this MD&A.

Description |  | Effective Date |  | Estimated Annualized Rate Impact (in millions of dollars)(1)
2025 Idaho general rate case |  | 1/1/2026 |  |  | $ | 110.0 |
2025 Oregon rate adjustment |  | 1/1/2026 |  |  | (0.6) |
2025 Idaho PCA |  | 6/1/2025 |  |  | (94.8) |
2025 Idaho FCA |  | 6/1/2025 |  |  | (39.8) |
2024 Idaho limited-issue rate case |  | 1/1/2025 |  |  | 50.1 |
2023 Oregon general rate case |  | 10/15/2024 |  |  | 6.7 |
2024 Idaho PCA |  | 6/1/2024 |  |  | (35.7) |
2024 Idaho FCA |  | 6/1/2024 |  |  | 11.7 |
2023 Idaho general rate case |  | 1/1/2024 |  |  | 54.7 |
(1) The annual amount collected or refunded in rates is typically not recovered or refunded on a linear basis (i.e., 1/12th per month), and is instead recovered or refunded in proportion to retail sales volumes. The rate changes for the Idaho PCA and FCA are applicable only for one-year periods and represent the net change to the deferral balance from the prior year's filing, as well as a forecast component for the PCA.

Idaho and Oregon Rate Cases
As noted above, in December 2025, the IPUC issued an order approving the 2025 Settlement Stipulation, which resolved the Idaho general rate case Idaho Power had filed in May 2025. The 2025 Settlement Stipulation provided for Idaho Power to implement revised tariff schedules designed to increase annual Idaho-jurisdictional retail revenue by approximately $110.0 million, or 7.48 percent, effective January 1, 2026. The approximate $110.0 million of additional annual revenue is inclusive of a PCA rate increase of $13.1 million. The ADITC and Revenue Sharing mechanism was updated as part of the 2025 Settlement Stipulation. At December 31, 2025, Idaho Power estimates that it had $167.8 million of deferred credits available for future use under the updated ADITC and Revenue Sharing mechanism.
In December 2024 and January 2025, the IPUC issued an order and subsequent errata in connection with Idaho Power's 2024 Idaho Limited-Issue Rate Case, providing for Idaho Power to implement revised tariff schedules designed to increase annual Idaho-jurisdictional retail revenue by $50.1 million, or 3.7 percent, effective January 1, 2025.
The 2023 Settlement Stipulation in connection with Idaho Power's 2023 Idaho general rate case provided 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.
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In December 2023, Idaho Power filed a general rate case with the OPUC. In September 2024, the OPUC issued an order approving the 2024 Oregon Settlement Stipulations to settle the general rate case. The OPUC order and the 2024 Oregon Settlement Stipulations provided for revised tariff schedules designed to increase annual Oregon-jurisdiction revenue by $6.7 million, or 12.14 percent, effective October 15, 2024.
For more information on these rate cases, see Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.
Other Notable Regulatory Matters
Integrated Resource Plan and Resource Procurement Filings: Idaho Power filed its most recent IRP with the IPUC and OPUC in June 2025, as described in Part 1, Item 1 - "Business - Resource Planning" in this report. The 2025 IRP identified the need for resources to meet projected capacity deficits in the near-term. The OPUC and the IPUC acknowledged the 2025 IRP in December 2025 and February 2026, respectively.
In August 2024, the OPUC issued an order approving Idaho Power's RFP to procure resources for its anticipated energy and capacity needs in 2028 and beyond. Idaho Power issued the RFP in August 2024 soliciting resources with a commercial operation date (COD) no later than April 1, 2028 (2028 bids), as well as bids with a COD after April 1, 2028. In March 2025, the OPUC acknowledged the final shortlist of 2028 bids, subject to certain conditions. In July 2025, Idaho Power filed a request for acknowledgement from the OPUC for the final shortlist of bids with a COD no later than June 1, 2029 (2029 bids). Bids from Idaho Power are included in the final shortlist of 2029 bids. In August 2025, the OPUC acknowledged the final shortlist of 2029 bids, subject to certain conditions.
In December 2024, Idaho Power filed an application with the IPUC for the Jackalope Wind Project, consisting of (i) a 35-year PPA between Jackalope Wind, LLC and Idaho Power, supplying a capacity of 300 MW of generation to Idaho Power's system, and (ii) a wind turbine generator power plant to be owned by Idaho Power, providing a capacity of 300 MW of generation. In its application, Idaho Power requested that the IPUC approve the PPA and grant a CPCN for the wind turbine generator power plant. In June 2025, the IPUC approved the PPA and granted the CPCN. However, due to the termination of the agreements for the Jackalope Wind Project following a delay in the planned commercial operation date of the Project, in September 2025, Idaho Power filed a petition with the IPUC to withdraw the CPCN and approval of the PPA for the Project. In December 2025, the IPUC issued an order withdrawing the CPCN and approval of the PPA for the Project.
Also in December 2024, Idaho Power filed an application with the IPUC to grant a CPCN for Idaho Power to acquire and own two battery storage facilities with a total of 100 MW of operating capacity to address Idaho Power's identified capacity deficiency in 2026. In October 2025, the IPUC granted the CPCN.
In March 2025, Idaho Power filed an application with the IPUC to grant a CPCN for Idaho Power to acquire an ownership interest, including the rights to 250 MW of northbound capacity, in SWIP-N, a planned 285-mile, high-voltage transmission line between the Robinson Summit Substation near Ely, Nevada, and the Midpoint Substation near Jerome, Idaho. In its application, Idaho Power also requested that the IPUC approve the company's utilization of an additional 250 MW of rights to northbound capacity on SWIP-N. In December 2025, the IPUC granted the CPCN and approved the request to utilize northbound capacity on SWIP-N.
In March 2025, Idaho Power filed an application with the IPUC for an order (1) approving the 20-year PPA with Crimson Orchard Solar LLC supplying 100 MW of output to Idaho Power, (2) approving the 20-year energy storage agreement (SA) with Crimson Orchard Solar for 100 MW of dispatchable energy storage capacity, and (3) acknowledging the lease accounting necessary to facilitate the transaction and that the resulting expenses associated with both the PPA and the SA are prudently incurred for ratemaking purposes. In August 2025, Idaho Power also filed with the IPUC for approval of amendments to the PPA and SA for Crimson Orchard Solar. In December 2025 and February 2026, the IPUC issued an order and subsequent clarification approving the PPA, the SA, and the amendments and acknowledging that the SA may require the application of lease accounting, in each case subject to certain conditions.
In September 2025, Idaho Power filed an application with the IPUC for an order (1) approving the 25-year PPA with Blacks Creek Energy Center, LLC supplying 80 MW of output to Idaho Power and (2) acknowledging that the resulting expenses associated with the PPA are prudently incurred for ratemaking purposes. As of the date of this report, the case remains pending.
In September 2025, Idaho Power filed an application with the IPUC for a CPCN for 167 MW of natural gas-fueled generating capacity next to the existing Bennett Mountain power plant to meet an identified capacity deficit in 2028, as well as
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confirmation and approval by the IPUC of Idaho Power's accrual of AFUDC in connection with the project. As of the date of this report, the case remains pending.
Filing for Approval of Conversion of North Valmy Plant to Natural Gas: In January 2025, Idaho Power filed an application with the IPUC to grant approval of an agreement between Idaho Power and the co-owner of the North Valmy plant, NV Energy, to convert the two coal-fired units at the North Valmy plant to natural gas-fired steam turbines by mid-2026. In July 2025, the IPUC approved the agreement with NV Energy for the conversion of the two coal-fired units at the North Valmy plant to natural gas.
Filing for Approval of Wildfire Mitigation Plan: In October 2025, Idaho Power filed an application with the IPUC for approval of the Company's WMP in accordance with Idaho's Wildfire Standard of Care Act, which became effective in 2025. In December 2025, Idaho Power filed an application with the OPUC for approval of the company's 2026-2028 WMP. As of the date of this report, both cases remain pending.
Idaho Oversight Process for the Acquisition of Large Supply-Side Electrical Resources: In January 2026, the IPUC issued an order (1) rescinding its prior order requiring Idaho Power to comply with Oregon’s RFP guidelines, and (2) adopting an IPUC procedure for electric utilities to solicit large supply-side resources.
For more information on other notable regulatory matters, see Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.
Large Customer Rate Proceedings
Micron Fab Special Contract: In December 2024, Idaho Power filed an application with the IPUC for approval of a special contract for electric service for Micron Idaho Semiconductor Manufacturing (Triton) LLC, a subsidiary of Micron Technology, Inc. (Micron), for electric service for Micron's new memory manufacturing fabrication complex located in Boise, Idaho. The special contract anticipates a significant increase in load on Idaho Power's system that will ramp over a number of years beginning in 2026. As of the date of this report, the case remains pending.
Brisbie, LLC (Brisbie) Data Center and Clean Energy Your Way Special Contract: In May 2023, the IPUC approved a special contract (Brisbie Special Contract) between Idaho Power and a large load customer, Brisbie, a wholly-owned subsidiary of Meta Platforms, Inc., for service to a new enterprise data center. The Brisbie Special Contract allows Idaho Power to procure enough renewable resources to provide Brisbie with 100 percent renewable energy on an annual basis for Brisbie's facility. In November 2024, Idaho Power filed for IPUC approval of a PPA for Brisbie with a 320 MW solar project to be online as early as December 2027. Idaho Power will assign the cost and renewable attributes of the energy from the solar facility to Brisbie in accordance with the Brisbie Special Contract. In April 2025, the IPUC approved the PPA.
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 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, and income tax reform. From year to year, these factors can vary significantly, which can result in significant accruals and deferrals under the power cost adjustment mechanisms. The power cost adjustment rate changes reflected in the table under the heading "Notable Retail Rate Changes in Idaho and Oregon" in this MD&A are illustrative of the volatility of net power supply costs and the impact on power cost adjustment rates.
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The following table summarizes the change in deferred (accrued) net power supply costs during 2025 (in millions of dollars):

|  | Idaho |  | Oregon |  | Total
Balance at December 31, 2024 |  | $ | 18.5 |  |  | $ | (3.9) |  |  | $ | 14.6 |
Current period net power supply costs (accrued) deferred |  | (25.4) |  |  | 2.8 |  |  | (22.6) |
Prior amounts (collected) refunded through rates |  | (3.2) |  |  | 0.9 |  |  | (2.3) |
REC sales |  | (28.2) |  |  | (1.2) |  |  | (29.4) |
Interest and other |  | (2.7) |  |  | — |  |  | (2.7) |
Balance at December 31, 2025 |  | $ | (41.0) |  |  | $ | (1.4) |  |  | $ | (42.4) |

Open Access Transmission Tariff Rate
Idaho Power uses a formula rate for transmission service provided under its OATT, which provides that transmission rates will be updated annually based primarily on financial and operational data that Idaho Power files with the FERC. In September 2025, Idaho Power filed its 2025 final transmission rate with the FERC, reflecting a transmission rate of $34.16 per kilowatt-year (kW-year), to be effective for the period from October 1, 2025 to September 30, 2026. Idaho Power's final rate was based on a net annual transmission revenue requirement of $148.5 million. The OATT rate in effect from October 1, 2024 to September 30, 2025, was $31.55 per kW-year based on a net annual transmission revenue requirement of $137.9 million. A kW-year is a unit of electrical capacity equivalent to 1 kW of power used for 8,760 hours.
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 13 - "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 an 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 2003, Idaho Power filed an application with the FERC for a new license in anticipation of the 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 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 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 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 401 certifications from the states for several years. In 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 FERC denied in 2017. In 2018, Idaho Power appealed the FERC's 2017 order with the United States Court of Appeals for the District of Columbia Circuit, which is pending.
In 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 implement a 20-year program to study the success of non-volitional passage of non-ESA listed anadromous fish into Pine Creek, an Oregon tributary to Hells Canyon Reservoir, and increase the number of Chinook salmon it releases each year through expanded hatchery production. In 2019, Oregon and Idaho issued final CWA Section 401 certifications which have been submitted to the FERC as part of the relicensing process. Also in 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.
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In 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 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 April 2025, the FERC issued an updated schedule for the supplemental EIS with target dates for issuance of the draft and final supplemental EIS of September 2025 and May 2026, respectively. The FERC issued the draft supplemental EIS on January 14, 2026, which initiated a comment period until March 2, 2026. Idaho Power is reviewing the draft supplemental EIS. As part of issuing the draft supplemental EIS, the FERC also requested that USFWS and NMFS initiate formal consultation under section 7 of the ESA, indicating that it considered the draft supplemental EIS its biological assessment.
In February 2025, Idaho Power submitted to the FERC, to be included in the final HCC license, agreed-upon language between Idaho Power and the U.S. Army Corps of Engineers regarding flood control requirements applicable to the HCC.
American Falls Relicensing: In 2020, Idaho Power filed with the FERC a notice of intent to file an application to relicense the American Falls hydropower facility, which is Idaho Power's largest hydropower facility outside of the HCC, with a nameplate generating capacity of 92.3 MW and FERC authorized installed capacity of 67.5 MW. Idaho Power owns the generation facility but not the structural dam or reservoir, which are owned by the U.S. Bureau of Reclamation. Idaho Power filed the final relicensing application with the FERC in February 2023. In September 2024, the Idaho Department of Environmental Quality issued a final CWA Section 401 water quality certification. The FERC released its environmental assessment in accordance with NEPA in January 2025. Three parties commented on the environmental assessment, and Idaho Power has responded to those comments.
Idaho Power's previous license at American Falls expired in February 2025. In March 2025, the FERC issued Idaho Power an annual license on the same terms and conditions as its prior license. The annual license is effective until February 28, 2026, or until the FERC issues a new license for the American Falls facility. As of the date of this report, Idaho Power anticipates the FERC will issue a new license for this facility in 2026.
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 co-owned coal- and gas-fired power plant, its co-owned gas-fired power plant, and its three wholly-owned natural gas-fired combustion turbine power plants are subject to many of these regulations. Idaho Power's hydropower projects are also subject to a number of water discharge standards and other environmental requirements.
Compliance with current and future environmental laws and regulations may:
•increase the operating costs of generating plants;
•increase the construction costs and lead time for new facilities;
•require the modification of existing generating plants, which could result in additional costs;
•require the curtailment, fuel-switching, or shut-down of existing generating plants;
•reduce the output from current generating facilities; or
•require the acquisition of alternative sources of energy or storage technology, increased transmission wheeling, or 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 or conversion to natural gas, as the cost of compliance makes coal plants uneconomical to operate. The
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decision to end coal-fired operations at the North Valmy plant was 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 2026 to 2028. 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 2028, though they could be substantial. Changes in Presidential Administrations and Congressional elections since 2017 have resulted, and in the future could result, in significant changes in, and uncertainty with respect to, legislation, regulation, and government policy regarding environmental matters. Executive orders that could be issued by the current Presidential Administration and the outcome of U.S. federal agencies' review of regulations covered by executive orders and revocation of executive orders is difficult to predict.
In addition, 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 current executive 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 and new or revised legislation or regulation.
EPA Proposed Regulatory Actions
In March 2025, the EPA announced a set of proposed regulatory actions relating to environmental laws and regulations, many of which will impact Idaho Power if they are implemented. The proposed regulatory actions relate to the following laws and regulations, among others: the EPA's 2009 endangerment finding regarding six greenhouse gases; the Clean Air Act Section 111 rulemaking for new and existing generation units (also known as the Clean Power Plan 2.0); the MATS Rule; the Greenhouse Gas Reporting Program; effluent limitations guidelines and standards for the Steam Electric Power Generating Industry; the National Ambient Air Quality Standards for Particulate Matter (PM2.5); the Regional Haze Program; the “Good Neighbor Plan” and related State Implementation Plans; the coal ash program; and the definition of "Waters of the United States," which impacts applicability of the CWA to certain wetlands and water bodies.
The EPA has published proposed rules for several of the items mentioned in its March 2025 announcement, including the following:
•in June 2025, the EPA proposed rules to repeal greenhouse gas emissions standards for fossil fuel-fired power plants and to repeal certain amendments to the MATS Rule, including the revised filterable particulate matter (fPM) emission standard; the revised fPM emission standard compliance demonstration requirements; and the revised mercury emission standard for lignite-fired electric utility steam generating units;
•in September 2025, the EPA proposed revisions to the greenhouse gas reporting program to remove program obligations for most source categories, including for electric power generation;
•in November 2025, the EPA and the U.S. Department of the Army proposed revisions to the CWA, including the definition of "Waters of the United States"; and
•in January 2026, the EPA proposed to approve the SIPs of eight states, including Nevada.
The proposals are subject to public comment and remain pending as of the date of this report. In February 2026, the EPA finalized a rule rescinding the EPA's 2009 greenhouse gas endangerment finding The EPA has not yet taken official action on the other items mentioned in its March 2025 announcement. Idaho Power will continue to actively monitor these proposals and any other pending or potential environmental regulations related to environmental matters that may have an impact on its future
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operations. Given uncertainties regarding the outcome and timing for these EPA proposals, Idaho Power is unable to estimate the impact on Idaho Power of any such proposals.
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. The Council on Environmental Quality (CEQ) under previous Presidential Administrations had issued guidance to federal agencies in issuing their own regulations regarding the implementation of NEPA for projects under their jurisdiction. However, a CEQ interim final rule effective in April 2025 removed all CEQ NEPA implementing regulations.
In addition, the U.S. Supreme Court clarified in the Seven County Infrastructure Coalition v. Eagle County, Colorado case in May 2025 that NEPA imposes no substantive environmental obligations or restrictions, but rather is a procedural statute that requires federal agencies to weigh environmental consequences as the agency reasonably sees fit under its governing statute and any relevant substantive environmental laws.
In July 2025, a number of federal agencies, including the Department of the Interior, the Department of Energy, the Army Corps of Engineers, and the Department of Transportation, issued interim final rules revising their procedures for implementing NEPA. These interim final rules were issued in response to the Supreme Court's Seven County decision, the removal of the CEQ's NEPA implementing regulations, and the current Presidential Administration's executive orders regarding the energy industry.
These actions may result in significant changes to the way federal environmental laws and regulations are enforced, but as of the date of this report, Idaho Power is unable to predict the ultimate impact of these actions on Idaho Power and its operations.
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.
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 GWW transmission project and other infrastructure projects, which could lead to substantially higher construction, permitting, and licensing costs and could delay or prevent construction.
Definition of "Harm" under the ESA: In April 2025, the U.S. Fish and Wildlife Service and the National Marine Fisheries Service issued a proposed rule to rescind the definition of "harm" under the ESA in their respective regulations. If adopted, the proposed rescission of the definition of harm would likely have the effect of reducing the applicability of the ESA in some contexts. As of the date of this report, Idaho Power is unable to estimate the impact on Idaho Power of the proposed rule.
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 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 B2H and GWW transmission line projects. Idaho Power has intervened in the proceedings 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
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could lead to substantially higher construction and permitting costs and could delay construction. 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.
In June 2017, the Secretary of the Interior directed 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, and in November 2024, the BLM issued a proposed resource management plan amendment and final EIS. Idaho Power protested the 2024 plan amendment and EIS. In December 2025, the BLM published an updated resource management plan amendment and record of decision for Idaho and various other states. As of the date of this report, Idaho Power is unable to estimate the impact on Idaho Power of the updated resource management plan amendment and record of decision.
Revocation of "Blanket Rule" for Threatened Species and Revisions to Critical Habitat Designation Process: The listing of a species, or changes to the critical habitat designations, of fish, wildlife, or plants as threatened or endangered under the ESA and the associated mitigation policies 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. In March 2024, the USFWS published a final rule which, among other items, reinstated the “blanket rule” that allows the USFWS to treat threatened species the same (or similar) as endangered species under Section 4(d) of the ESA. Subsequently, in November 2025, the USFWS and NMFS jointly published proposed rules, among other items, to revoke the "blanket rule" for threatened species and revise the process for designation of critical habitat. Based on ESA listings as of the date of this report, Idaho Power anticipates that the proposed changes will have limited or no impact on its projects.
ESA Issues Related to Specific Projects:
Hells Canyon Relicensing Project: In December 2004, Idaho Power and eleven other parties, including the NMFS and the USFWS, entered into an interim agreement that addresses the effects of the ongoing operations of the HCC on ESA listed species pending the relicensing of the project. In 2007, the FERC requested initiation of formal consultation under the ESA with the NMFS and the USFWS regarding potential effects of HCC relicensing on several listed aquatic and terrestrial species. Idaho Power prepared draft biological assessments in consultation with the USFWS and the NMFS and filed those with the FERC in October 2020; the biological assessments were subsequently updated in July 2025. 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 May 2026 according to the FERC's updated schedule for issuance of the supplemental EIS. The FERC issued the draft supplemental EIS on January 14, 2026, which initiated a comment period until March 2, 2026. Idaho Power is reviewing the draft supplemental EIS.
GWW and B2H Transmission Projects and Other Infrastructure - Slickspot Peppergrass Designation: In 2016, the USFWS re-instated the threatened species status of slickspot peppergrass under the ESA. In 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 GWW 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.
Climate Change and the Regulation of Greenhouse Gas Emissions
Overview: 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 CO 2 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 cessation of operation, as the cost of compliance makes the plants uneconomical to operate. As a result, Idaho Power ended its participation in coal-fired operations at the North Valmy plant unit 1 in 2019 and unit 2 in 2025. Idaho Power's 2025 IRP
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identified a preferred resource portfolio and action plan that anticipates (1) converting North Valmy plant units 1 and 2 to natural gas by mid-2026; and (2) 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. As noted above, in August 2025, the EPA proposed a rule to reconsider the EPA's 2009 greenhouse gas endangerment finding. In February 2026, the EPA finalized a rule rescinding the 2009 endangerment finding. Idaho Power does not expect any near-term impact on its plans or operations as a result but will continue to monitor any potential effects.
In 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 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 CO 2 emissions by 32 percent by 2030. In 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 electric utility generating units. In subsequent litigation, the ACE rule was vacated without reinstating the CPP.
In April 2024, the EPA released a final rule under Section 111 of the CAA (New Section 111 Rule) that regulates CO 2 emissions from coal- and natural gas-fired electric generating units. Under the final rule, applicable standards of emission reduction vary based upon the retirement date of coal units and the capacity factor of existing and new natural gas units. The EPA based some of its requirements on carbon capture and storage technology. Idaho Power, among many other parties, filed suit in May 2024 in the U.S. Court of Appeals, D.C. Circuit, to challenge the New Section 111 Rule. Idaho Power's suit was consolidated with other similar suits, and the proceedings were placed on hold in February 2025 at the request of the EPA and remain on hold pending finalization of EPA's new Section 111 rules. As noted above, in June 2025, the EPA proposed to repeal all GHG emissions standards for fossil fuel-fired power plants. If the EPA's repeal of GHG emissions standards becomes effective, this will eliminate the New Section 111 Rule and any impacts it may have had on Idaho Power's coal- and natural gas-fired plants.
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 has enacted legislation to regulate GHG emissions of utilities serving over 10,000 electric customers in Wyoming, which does not apply to Idaho Power. Nevada has not enacted legislation to regulate GHG emissions and does not have a reporting requirement, but it does prepare a greenhouse gas emissions inventory for the state of Nevada. 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 Rule and the Good Neighbor Plan.
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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 sulfur dioxide. 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.
Regional Haze / Good Neighbor Plan: In June 2023, the EPA published the final rule under the CAA called the Federal "Good Neighbor Plan" for the 2015 Ozone National Ambient Air Quality Standards (Good Neighbor Plan), which took effect in August 2023. The Good Neighbor Plan establishes nitrogen oxides (NO x) 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 Wyoming SIP. In December 2023, the EPA approved the Wyoming SIP, removing it from the Federal Implementation Plan (FIP).
In April 2024, the EPA proposed to approve revisions to the Wyoming Regional Haze SIP for the first planning period of 2008-2018. The proposed SIP replaces Wyoming’s previously approved source-specific NO x determination for Idaho Power’s jointly-owned Jim Bridger plant. Operations at the Jim Bridger plant have previously been modified to comply in advance with the proposed SIP. Accordingly, Idaho Power does not expect the proposed SIP, if approved, to require any additional changes to current operations at the Jim Bridger plant. As of the date of this report, the EPA's approval of the Wyoming SIP for the first planning period is pending.
In August 2024, the EPA proposed to approve in part and disapprove in part the proposed Wyoming Regional Haze SIP for the second planning period of 2018-2028. The public comment period for the EPA's proposed action ended in September 2024. Idaho Power submitted comments requesting that the EPA approve in full Wyoming's Regional Haze SIP for the second planning period. In December 2024, EPA published its final partial disapproval of Wyoming’s Regional Haze SIP for the second planning period based in part on Wyoming’s failure to consider the four statutory factors for the Jim Bridger plant. In January 2025, Idaho Power filed a petition with the EPA for reconsideration of its final partial disapproval and also filed suit in the 10th Circuit Court of Appeals to challenge the EPA's final partial disapproval, both of which remain pending. In May 2025, the EPA notified Idaho Power that the EPA would voluntarily reconsider its partial approval and disapproval of the Wyoming SIP for the second planning period.
On June 27, 2024, the U.S. Supreme Court issued an opinion in Ohio v. EPA that granted an application to stay the EPA’s FIP promulgated under the Good Neighbor Provision of the CAA. This action puts a hold on any related compliance obligations for the North Valmy plant, which is co-owned by Idaho Power and NV Energy and operated by NV Energy. The stay is expected to remain in place until the U.S. Court of Appeals, D.C. Circuit, reaches a decision on the applicants' challenge to the FIP.
In October 2025, the EPA issued a request for comment on how the EPA can revise the Regional Haze rules to streamline regulatory requirements. Further, in December 2025, the EPA finalized an extension of the due date for the third planning period of SIPs from 2028 to 2031.
In January 2026, the EPA proposed to approve the SIPs of eight states, including Nevada, and withdraw proposed SIP disapprovals of five other states under the 2015 Ozone National Ambient Air Quality Standards. The proposal is subject to a comment period and remains pending.
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 January 2026 proposal to approve the Nevada SIP is finalized, Idaho Power anticipates that the Nevada SIP would not affect the current operations of the North Valmy plant.
Mercury and Air Toxic Standards: The MATS Rule in Section 112 of the CAA for coal-fired power plants provides that sources must comply with certain emission limits. Idaho Power and the co-owner of the Jim Bridger coal-fired generating plant 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.
In April 2024, EPA finalized updated standards for coal-fired power plants under the MATS Rule. As applicable to Idaho Power, the MATS Rule amends the filterable particulate matter (fPM) surrogate emission standard for non-mercury metal hazardous air pollutants to existing coal-fired power plants and the fPM emission standard compliance demonstration requirements. For coal-fired units at the Jim Bridger plant, the MATS Rule would require additional monitoring equipment and possibly other equipment upgrades. However in June 2025, as noted above, the EPA proposed amendments to the MATS Rule which, if finalized, would revise the fPM emission standard, the revised fPM emission standard compliance demonstration
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requirements, and the revised mercury emission standard for lignite-fired electric utility steam generating units. Idaho Power will continue to monitor developments with respect to the MATS Rule for possible impact to Idaho Power's operations.
CAA Section 111 New Source Performance Standards: In January 2026, the EPA finalized its “New Source Performance Standards Review for Stationary Combustion Turbines and Stationary Gas Turbines” under CAA Section 111. This rule applies to affected sources constructed, modified, or reconstructed after December 13, 2024. The rule established NO x emissions standards for several subcategories of new, modified, and reconstructed stationary combustion turbines and stationary gas turbines based on the size, rate of utilization, design efficiency, and fuel type of these turbines equivalent to the application of selective catalytic reduction (SCR) for large, high-utilization natural gas-fired turbines, and establishes various levels of combustion controls as the “Best System of Emissions Reduction” for smaller and lower-utilization turbines. Idaho Power is analyzing the rule and how it may impact Idaho Power's proposed addition of natural gas-fueled generating capacity next to its Bennett Mountain power plant and any future gas-fired projects.
Clean Water Act Matters
CWA Permitting: Idaho Power's hydropower generation facilities are subject to compliance and permitting obligations under the CWA. Idaho Power has been engaged for several years with the EPA, and is now engaged with the Idaho Department of Environmental Quality (IDEQ), regarding Idaho Power's CWA permitting obligations and compliance status for those facilities. Idaho Power has in the past, and expects in the future, to incur costs 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 January 2026, the EPA proposed a rule that could simplify certain requirements under Section 401 of the CWA for water quality certifications. If finalized, the proposed rule may streamline the process for Idaho Power to receive future Section 401 certifications.
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 the dams would have been in compliance had the earlier permits remained in place. As of the date of this report, Idaho Power has submitted new permit applications for all 15 dams.
Resource Conservation and Recovery Act Matters
Under the Resource Conservation and Recovery Act, EPA finalized changes to the coal combustion residual (CCR) regulations for inactive surface impoundments at inactive electric utilities. EPA is establishing groundwater monitoring, corrective action, closure and post closure care requirements for these areas and in July 2025, extended certain deadlines for these areas. In addition, in August 2025, the EPA announced a proposal to approve Wyoming's CCR permit program, which would operate in lieu of the federal CCR program. If finalized, the proposed approval will streamline the permitting and monitoring requirements for the Jim Bridger plant landfill and flue gas desulfurization ponds. Idaho Power continues to work with the co-owners of the Jim Bridger plant and the North Valmy plant to evaluate the potential impacts of these regulations, which could affect the amount of asset retirement obligations recorded in Idaho Power's consolidated balance sheets.
Invasive Species Management
Quagga mussels are an invasive species that were first detected in the Snake River system in 2023 in the mid-Snake River near Twin Falls, Idaho, in Idaho Power's service area. Quagga mussel infestations can clog and damage irrigation, hydropower, and water delivery facilities and increase the costs to maintain such facilities. The Idaho State Department of Agriculture (ISDA) treated the affected area in 2023 and 2024 with a copper-based, EPA-approved treatment. ISDA sampling in 2025 detected the continued presence of quagga mussels. As a result, the ISDA performed additional treatments in September and October 2025 in an effort to eradicate quagga mussels in the affected area. As of the date of this report, Idaho Power cannot predict the extent to which the additional treatments will be successful in eradicating quagga mussels from the Snake River or the potential increase in other O&M expenses related to quagga mussel mitigation efforts. If a quagga mussel infestation occurs, it may result in increased other O&M costs for mitigation efforts and other adverse impacts for Idaho Power's operation of its hydropower facilities in any infested areas.
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OTHER MATTERS
One Big Beautiful Bill Act
On July 4, 2025, the One Big Beautiful Bill Act (OBBB) was signed into law. Among its key provisions, the OBBB updates renewable energy tax incentives originally established under the Inflation Reduction Act of 2022, including the Clean Electricity Production Tax Credit and the Investment Tax Credit. Under the new law, solar and wind facilities that begin construction by July 4, 2026, will remain eligible for the credits, consistent with existing guidance on construction start dates. Projects that commence construction after this deadline must be placed in service by the end of 2027 to qualify. For certain other eligible technologies, a gradual phase-out of the credits will begin in 2034, with no credits available for projects that begin construction after 2035. The OBBB also introduces new restrictions for facilities that receive material support from a prohibited foreign entity as well as other corporate-related income tax law changes. IDACORP and Idaho Power do not anticipate material impacts from the OBBB to projects for which Idaho Power has already executed agreements to own generation resources.
Executive Orders of the Current Presidential Administration
Beginning in January 2025, the current Presidential Administration has released several executive orders that may impact Idaho Power. These executive orders include, but are not limited to, orders regarding tariffs, the electric grid, the coal industry, revocation of executive orders of prior Presidential Administrations, federal grantmaking, and other orders intended to regulate international trade, strengthen the U.S. energy industry, and/or promote deregulation, including with respect to environmental and energy-related regulations. The outcome of these executive orders and U.S. federal agencies' review of regulations covered by executive orders is generally difficult to predict. However, in some instances, federal grants which Idaho Power has been awarded have been delayed or withdrawn, and other federal grants to Idaho Power may experience similar treatment in the future.
In addition, the court system has become more active in reviewing Presidential and 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 constructing 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, such as tariffs on supplies and materials that Idaho Power purchases, 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 construction activities related to its capital projects, which could lead to substantially higher costs and delays in construction.
Executive orders may be affected by Congressional action. 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 in this MD&A, Idaho Power is uncertain whether and to what extent the executive 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 and new or revised legislation or regulation.
Idaho's Wildfire Standard of Care Act
In April 2025, Idaho enacted the Wildfire Standard of Care Act (Idaho Code § 61-1801 through 1808), which became effective in July 2025. The Act requires Idaho electric public utilities to prepare wildfire mitigation plans annually to mitigate wildfire risk, submit the plans to the IPUC for review and approval, and implement the plans upon IPUC approval. An electric utility's wildfire mitigation plan approved by the IPUC establishes the utility's duty to its shareholders and the public with respect to wildfire risk. On September 30, 2025, the IPUC issued an order establishing a filing schedule permitting Idaho Power to file its WMP with the IPUC no earlier than October 1, 2025. Idaho Power filed its WMP with the IPUC on October 10, 2025. The Act provides up to six months for the IPUC to review and approve a WMP after it is filed. As of the date of this report, the IPUC's decision is pending.
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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 $1.6 billion of regulatory assets and $1.1 billion of regulatory liabilities at December 31, 2025. 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.
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, 2025, with maturities matching the projected cash outflows of
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the plans. Based on the results of this analysis, the discount rate used to calculate the 2026 defined benefit plan pension expense increased to 5.75 percent from the 5.70 percent rate used in 2025.
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 2026 pension expense will be 7.4 percent, the same assumption as used in 2025.
Total net periodic pension and other postretirement benefit cost for these plans totaled $28.2 million and $31.0 million for the years ended December 31, 2025 and 2024, respectively, including amounts deferred as regulatory assets (see discussion below) and amounts allocated to capitalized labor. For 2026, total net periodic pension costs and other postretirement benefit costs are expected to total approximately $26.5 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
|  | 2026 |  | 2025 |  | 2026 |  | 2025
|  | (millions of dollars)
Effect of 0.5% rate increase on total net periodic pension costs and other postretirement benefit costs |  | $ | (2.9) |  |  | $ | (2.7) |  |  | $ | (5.1) |  |  | $ | (4.9) |
Effect of 0.5% rate decrease on total net periodic pension costs and other postretirement benefit costs |  | 3.2 |  |  | 3.4 |  |  | 5.2 |  |  | 4.7 |

Additionally, a 0.5 percent increase in the plans' discount rates would have resulted in a $73.4 million decrease in the combined benefit obligations of the plans as of December 31, 2025. A 0.5 percent decrease in the plans' discount rates would have resulted in an $82.1 million increase in the combined benefit obligations of the plans as of December 31, 2025.
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, 2025, a total of $247 million of expense was deferred as a regulatory asset. Idaho Power expects net amortization of the regulatory asset of approximately $19 million in 2026. Idaho Power recorded pension expense on its consolidated statements of income related to its tax-qualified defined benefit pension plan of approximately $36 million in 2025 and $36 million in 2024.
Refer to Note 12 – “Benefit Plans” to the consolidated financial statements included in this report for additional information relating to pension and postretirement benefit plans.
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
For discussion of new and recently adopted accounting pronouncements, see Note 1 - "Summary of Significant Accounting Policies" 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, 2025. Neither IDACORP nor Idaho Power have entered into any of these market-risk-sensitive instruments for speculative purposes.
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Interest Rate Risk
IDACORP and Idaho Power manage interest expense and short- and long-term liquidity through a combination of fixed rate and variable rate debt. Generally, the amount of each type of debt is managed through market issuance, but interest rate swap and cap agreements with highly-rated financial institutions may be used to achieve the desired combination.
Variable Rate Debt: As of December 31, 2025, both IDACORP and Idaho Power had no variable rate debt.
Fixed Rate Debt: As of December 31, 2025, both IDACORP and Idaho Power had $3.5 billion in fixed rate debt, with a fair value of approximately $3.3 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 $388 million if market interest rates were to decline by one percentage point from their December 31, 2025 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; market liquidity; and tariffs and other cross-border considerations.
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 energy 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 for utility-owned generation resources. Idaho Power only engages in a nominal amount of trading activity for non-retail purposes.
The ERMP requires monitoring monthly volumetric electricity position and total monthly dollar (net power supply cost) exposure on a rolling 36-month forward view. The resource planning group 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 hedging and operational actions initiated by the power supply operational groups for consistency and compliance with the ERMP.
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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, bonds, 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, bonds, 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, 2025, Idaho Power posted $45 million of cash 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, 2025, the amount of additional collateral that could have been requested upon a downgrade to below investment grade was approximately $48 million. To minimize capital requirements, Idaho Power actively monitors the portfolio exposure and the potential exposure to additional requests for performance assurance collateral calls through sensitivity analysis.
Idaho Power is obligated to provide service to all electric customers within its service area. Credit risk for Idaho Power’s retail customers is managed by credit and collection policies that are governed by rules issued by the IPUC or OPUC. Idaho Power records a provision for uncollectible accounts, based upon historical experience, to provide for the potential loss from nonpayment by these customers. Idaho Power continuously monitors levels of nonpayment from customers and makes any necessary adjustments to its provision for uncollectible accounts accordingly.
Idaho utility customer relations rules prohibit Idaho Power from terminating electric service during the months of December through February to any residential customer who declares that he or she is unable to pay in full for utility service and whose household includes children, elderly, or infirm persons. Idaho Power’s provision for uncollectible accounts could be affected by changes in future prices as well as changes in IPUC or OPUC regulations.
Equity Price Risk
IDACORP is exposed to price fluctuations in equity markets, primarily through Idaho Power's defined benefit pension plan assets, a mine reclamation trust fund owned by an equity-method investment of Idaho Power, and other equity security investments at Idaho Power. The equity securities held by the pension plan and in such accounts are diversified to achieve broad market participation and reduce the impact of any single investment, sector, or geographic region. Idaho Power has established asset allocation targets for the pension plan holdings, which are described in Note 12 - "Benefit Plans" to the consolidated financial statements included in this report.
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ITEM 8. FINANCIAL STATEMENTS
Index to Financial Statements and Financial Statement Schedules

Consolidated Financial Statements | Page
IDACORP, Inc.: |
Consolidated Statements of Income | 77
Consolidated Statements of Comprehensive Income | 78
Consolidated Balance Sheets | 79
Consolidated Statements of Cash Flows | 81
Consolidated Statements of Equity | 82
Idaho Power Company: |
Consolidated Statements of Income | 83
Consolidated Statements of Comprehensive Income | 84
Consolidated Balance Sheets | 85
Consolidated Statements of Cash Flows | 87
Consolidated Statements of Retained Earnings | 88
Notes to Consolidated Financial Statements | 89
Reports of Independent Registered Public Accounting Firm - Deloitte & Touche LLP (PCAOB ID No. 34) | 135
Financial Statement Schedules |
IDACORP, Inc. - Schedule I - Condensed Financial Information of Registrant | 152
IDACORP, Inc. and Idaho Power Company - Schedule II - Consolidated Valuation and Qualifying Accounts | 154

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

|  | Year Ended December 31,
|  | 2025 |  | 2024 |  | 2023
|  | (thousands of dollars, except for per share amounts)
Operating Revenues: |  |  |  |  |  |
Electric utility revenues |  | $ | 1,809,609 |  |  | $ | 1,822,965 |  |  | $ | 1,762,894 |
Other |  | 3,388 |  |  | 3,668 |  |  | 3,462 |
Total operating revenues |  | 1,812,997 |  |  | 1,826,633 |  |  | 1,766,356 |
Operating Expenses: |  |  |  |  |  |
Electric utility: |  |  |  |  |  |
Purchased power |  | 392,462 |  |  | 425,082 |  |  | 501,531 |
Fuel expense |  | 253,236 |  |  | 259,204 |  |  | 275,405 |
Power cost adjustment |  | 24,997 |  |  | 89,757 |  |  | 6,885 |
Other operations and maintenance |  | 470,537 |  |  | 460,951 |  |  | 399,855 |
Energy efficiency programs |  | 30,480 |  |  | 27,580 |  |  | 31,948 |
Depreciation and amortization |  | 251,072 |  |  | 223,410 |  |  | 195,341 |
Other electric utility operating expenses, net |  | 31,408 |  |  | 8,798 |  |  | 38,550 |
Total electric utility expenses |  | 1,454,192 |  |  | 1,494,782 |  |  | 1,449,515 |
Other |  | 4,829 |  |  | 4,012 |  |  | 3,364 |
Total operating expenses |  | 1,459,021 |  |  | 1,498,794 |  |  | 1,452,879 |
Operating Income |  | 353,976 |  |  | 327,839 |  |  | 313,477 |
Nonoperating (Income) Expense: |  |  |  |  |  |
Allowance for equity funds used during construction |  | (62,489) |  |  | (53,238) |  |  | (43,221) |
Earnings of unconsolidated equity-method investments |  | (4,922) |  |  | (4,539) |  |  | (12,426) |
Interest on long-term debt and finance leases |  | 174,929 |  |  | 139,196 |  |  | 116,216 |
Other interest |  | 29,473 |  |  | 24,454 |  |  | 20,253 |
Allowance for borrowed funds used during construction |  | (36,211) |  |  | (27,785) |  |  | (20,012) |
Other income, net |  | (57,222) |  |  | (55,253) |  |  | (36,522) |
Total nonoperating expense, net |  | 43,558 |  |  | 22,835 |  |  | 24,288 |
Income Before Income Taxes |  | 310,418 |  |  | 305,004 |  |  | 289,189 |
Income Tax (Benefit) Expense |  | (13,715) |  |  | 15,053 |  |  | 27,296 |
Net Income |  | 324,133 |  |  | 289,951 |  |  | 261,893 |
Adjustment for income attributable to noncontrolling interests |  | (661) |  |  | (777) |  |  | (698) |
Net Income Attributable to IDACORP, Inc. |  | $ | 323,472 |  |  | $ | 289,174 |  |  | $ | 261,195 |
Weighted Average Common Shares Outstanding - Basic (000’s) |  | 54,235 |  |  | 52,543 |  |  | 50,717 |
Weighted Average Common Shares Outstanding - Diluted (000’s) |  | 54,806 |  |  | 52,615 |  |  | 50,806 |
Earnings Per Share of Common Stock: |  |  |  |  |  |
Earnings Attributable to IDACORP, Inc. - Basic |  | $ | 5.96 |  |  | $ | 5.50 |  |  | $ | 5.15 |
Earnings Attributable to IDACORP, Inc. - Diluted |  | $ | 5.90 |  |  | $ | 5.50 |  |  | $ | 5.14 |

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,
|  | 2025 |  | 2024 |  | 2023
|  | (thousands of dollars)
Net Income |  | $ | 324,133 |  |  | $ | 289,951 |  |  | $ | 261,893 |
Other Comprehensive Income: |  |  |  |  |  |
Unfunded pension liability adjustment, net of tax of $(145), $1,245, and $(1,477), respectively |  | (1,352) |  |  | 3,592 |  |  | (4,262) |
Total Comprehensive Income |  | 322,781 |  |  | 293,543 |  |  | 257,631 |
Comprehensive income attributable to noncontrolling interests |  | (661) |  |  | (777) |  |  | (698) |
Comprehensive Income Attributable to IDACORP, Inc. |  | $ | 322,120 |  |  | $ | 292,766 |  |  | $ | 256,933 |

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

|  | December 31,
|  | 2025 |  | 2024
|  | (thousands of dollars)
Assets |  |  |  |
Current Assets: |  |  |  |
Cash and cash equivalents |  | $ | 215,718 |  |  | $ | 368,865 |
Receivables: |  |  |  |
Customer (net of allowance of $3,788 and $5,071, respectively) |  | 97,724 |  |  | 114,824 |
Other (net of allowance of $637 and $628, respectively) |  | 37,764 |  |  | 29,627 |
Income taxes receivable |  | 8,669 |  |  | 13,932 |
Accrued unbilled receivables |  | 79,931 |  |  | 97,711 |
Materials and supplies (at average cost) |  | 201,896 |  |  | 201,064 |
Fuel stock (at average cost) |  | 24,455 |  |  | 43,656 |
Prepayments |  | 30,579 |  |  | 29,461 |
Current regulatory assets |  | 136,665 |  |  | 89,315 |
Other |  | 3 |  |  | — |
Total current assets |  | 833,404 |  |  | 988,455 |
Investments |  | 155,002 |  |  | 161,340 |
Property, Plant, and Equipment: |  |  |  |
Utility plant in service |  | 8,249,106 |  |  | 7,957,763 |
Accumulated provision for depreciation |  | (2,599,465) |  |  | (2,714,706) |
Utility plant in service - net |  | 5,649,641 |  |  | 5,243,057 |
Construction work in progress |  | 1,740,809 |  |  | 1,244,559 |
Finance lease right-of-use assets |  | 219,612 |  |  | — |
Utility plant held for future use |  | 19,781 |  |  | 13,211 |
Other property, net of accumulated depreciation |  | 18,103 |  |  | 16,491 |
Property, plant, and equipment - net |  | 7,647,946 |  |  | 6,517,318 |
Other Assets: |  |  |  |
Company-owned life insurance |  | 105,306 |  |  | 92,062 |
Regulatory assets |  | 1,427,793 |  |  | 1,418,057 |
Other |  | 55,986 |  |  | 62,131 |
Total other assets |  | 1,589,085 |  |  | 1,572,250 |
Total |  | $ | 10,225,437 |  |  | $ | 9,239,363 |

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

|  | December 31,
|  | 2025 |  | 2024
|  | (thousands of dollars)
Liabilities and Equity |  |  |  |
Current Liabilities: |  |  |  |
Current maturities of long-term debt |  | $ | 116,300 |  |  | $ | 19,885 |
Accounts payable |  | 344,870 |  |  | 307,133 |
Taxes accrued |  | 7,532 |  |  | 6,981 |
Interest accrued |  | 49,547 |  |  | 42,681 |
Accrued compensation |  | 77,245 |  |  | 70,548 |
Current regulatory liabilities |  | 21,089 |  |  | 7,523 |
Advances from customers |  | 201,743 |  |  | 165,229 |
Other |  | 79,509 |  |  | 80,821 |
Total current liabilities |  | 897,835 |  |  | 700,801 |
Other Liabilities: |  |  |  |
Deferred income taxes |  | 802,885 |  |  | 822,231 |
Regulatory liabilities |  | 1,031,062 |  |  | 976,803 |
Pension and other postretirement benefits |  | 137,406 |  |  | 165,992 |
Finance lease liabilities |  | 216,695 |  |  | — |
Other |  | 229,830 |  |  | 181,804 |
Total other liabilities |  | 2,417,878 |  |  | 2,146,830 |
Long-Term Debt |  | 3,331,038 |  |  | 3,053,777 |
Commitments and Contingencies |  |  |  |
Equity: |  |  |  |
IDACORP, Inc. shareholders’ equity: |  |  |  |
Common stock, no par value (120,000 shares authorized; 54,859 and 53,962 shares issued, respectively) |  | 1,301,907 |  |  | 1,194,998 |
Retained earnings |  | 2,284,911 |  |  | 2,149,548 |
Accumulated other comprehensive loss |  | (14,944) |  |  | (13,592) |
Total IDACORP, Inc. shareholders’ equity |  | 3,571,874 |  |  | 3,330,954 |
Noncontrolling interests |  | 6,812 |  |  | 7,001 |
Total equity |  | 3,578,686 |  |  | 3,337,955 |
Total |  | $ | 10,225,437 |  |  | $ | 9,239,363 |
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,
|  | 2025 |  | 2024 |  | 2023
|  | (thousands of dollars)
Operating Activities: |  |  |  |  |  |
Net income |  | $ | 324,133 |  |  | $ | 289,951 |  |  | $ | 261,893 |
Adjustments to reconcile net income to net cash provided by operating activities: |  |  |  |  |  |
Depreciation and amortization |  | 258,402 |  |  | 228,091 |  |  | 199,908 |
Deferred income taxes and investment tax credits |  | (31,491) |  |  | (17,592) |  |  | 39,613 |
Changes in regulatory assets and liabilities |  | 31,229 |  |  | 115,026 |  |  | (4,748) |
Pension and postretirement benefit plan expense |  | 45,214 |  |  | 45,800 |  |  | 27,155 |
Contributions to pension and postretirement benefit plans |  | (27,613) |  |  | (25,463) |  |  | (55,337) |
Earnings of equity-method investments |  | (4,922) |  |  | (4,539) |  |  | (12,426) |
Distributions from equity-method investments |  | 9,225 |  |  | 7,850 |  |  | 2,950 |
Allowance for equity funds used during construction |  | (62,489) |  |  | (53,238) |  |  | (43,221) |
Other non-cash adjustments to net income, net |  | 8,547 |  |  | 10,443 |  |  | 8,414 |
Change in: |  |  |  |  |  |
Accounts receivable and unbilled receivables |  | 9,688 |  |  | 31,434 |  |  | (17,628) |
Prepayments |  | (3,666) |  |  | (8,931) |  |  | (3,220) |
Materials, supplies, and fuel stock |  | 18,370 |  |  | (84,261) |  |  | (53,243) |
Accounts and wages payable |  | (16,168) |  |  | 16,939 |  |  | (81,244) |
Taxes accrued/receivable |  | 5,814 |  |  | 10,769 |  |  | (12,551) |
Other assets and liabilities |  | 37,565 |  |  | 32,138 |  |  | 10,712 |
Net cash provided by operating activities |  | 601,838 |  |  | 594,417 |  |  | 267,027 |
Investing Activities: |  |  |  |  |  |
Additions to property, plant and equipment, net |  | (1,179,327) |  |  | (1,009,279) |  |  | (611,137) |
Payments received from transmission project joint funding partners |  | 151,880 |  |  | 83,708 |  |  | 26,501 |
Investments in affordable housing and other real estate tax credit projects |  | (16,494) |  |  | (3,814) |  |  | (2,533) |
Purchase of equity securities |  | (10,871) |  |  | (11,642) |  |  | (12,235) |
Purchases of held-to-maturity securities |  | (2,896) |  |  | (1,845) |  |  | (1,617) |
Proceeds from sale of investment securities |  | 12,398 |  |  | 10,641 |  |  | 8,921 |
Other |  | 16,406 |  |  | 14,570 |  |  | 2,153 |
Net cash used in investing activities |  | (1,028,904) |  |  | (917,661) |  |  | (589,947) |
Financing Activities: |  |  |  |  |  |
Issuance of long-term debt |  | 400,000 |  |  | 300,000 |  |  | 872,000 |
Discount on issuance of long-term debt |  | (3,072) |  |  | (186) |  |  | (7,006) |
Retirement of long-term debt |  | (19,885) |  |  | (49,800) |  |  | (225,000) |
Payments on finance lease liabilities |  | (3,762) |  |  | — |  |  | — |
Dividends on common stock |  | (188,482) |  |  | (176,565) |  |  | (163,545) |
Issuance of common stock |  | 97,777 |  |  | 298,450 |  |  | — |
Tax withholdings on net settlements of share-based awards |  | (3,336) |  |  | (3,782) |  |  | (3,274) |
Debt issuance costs and other |  | (5,321) |  |  | (3,437) |  |  | (403) |
Net cash provided by financing activities |  | 273,919 |  |  | 364,680 |  |  | 472,772 |
Net (decrease) increase in cash and cash equivalents |  | (153,147) |  |  | 41,436 |  |  | 149,852 |
Cash and cash equivalents at beginning of the year |  | 368,865 |  |  | 327,429 |  |  | 177,577 |
Cash and cash equivalents at end of the year |  | $ | 215,718 |  |  | $ | 368,865 |  |  | $ | 327,429 |
Supplemental Disclosure of Cash Flow Information: |  |  |  |  |  |
Cash paid for interest (net of amount capitalized) |  | $ | 139,277 |  |  | $ | 109,067 |  |  | $ | 97,742 |
Non-cash investing activities: |  |  |  |  |  |
Additions to property, plant and equipment in accounts payable |  | $ | 222,340 |  |  | $ | 168,107 |  |  | $ | 185,400 |
Right-of-use asset obtained in exchange for finance lease liability |  | $ | 226,618 |  |  | $ | — |  |  | $ | — |

The accompanying notes are an integral part of these statements.
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IDACORP, Inc.
Consolidated Statements of Equity

|  | Year Ended December 31,
|  | 2025 |  | 2024 |  | 2023
|  | (thousands of dollars)
Common Stock: |  |  |  |  |  |
Balance at beginning of year |  | $ | 1,194,998 |  |  | $ | 888,615 |  |  | $ | 882,189 |
Issuance |  | 97,777 |  |  | 298,450 |  |  | — |
Share-based compensation expense |  | 12,505 |  |  | 11,708 |  |  | 9,578 |
Tax withholdings on net settlements of share-based awards |  | (3,336) |  |  | (3,782) |  |  | (3,274) |
Other |  | (37) |  |  | 7 |  |  | 122 |
Balance at end of year |  | 1,301,907 |  |  | 1,194,998 |  |  | 888,615 |
Retained Earnings: |  |  |  |  |  |
Balance at beginning of year |  | 2,149,548 |  |  | 2,036,138 |  |  | 1,937,972 |
Net income attributable to IDACORP, Inc. |  | 323,472 |  |  | 289,174 |  |  | 261,195 |
Common stock dividends ($3.46, $3.35, and $3.20 per share, respectively) |  | (188,109) |  |  | (175,764) |  |  | (163,029) |
Balance at end of year |  | 2,284,911 |  |  | 2,149,548 |  |  | 2,036,138 |
Accumulated Other Comprehensive Loss: |  |  |  |  |  |
Balance at beginning of year |  | (13,592) |  |  | (17,184) |  |  | (12,922) |
Unfunded pension liability adjustment (net of tax) |  | (1,352) |  |  | 3,592 |  |  | (4,262) |
Balance at end of year |  | (14,944) |  |  | (13,592) |  |  | (17,184) |
Total IDACORP, Inc. shareholders’ equity at end of year |  | 3,571,874 |  |  | 3,330,954 |  |  | 2,907,569 |
Noncontrolling Interests: |  |  |  |  |  |
Balance at beginning of year |  | 7,001 |  |  | 7,174 |  |  | 7,376 |
Net income attributable to noncontrolling interests |  | 661 |  |  | 777 |  |  | 698 |
Distributions to noncontrolling interests |  | (850) |  |  | (950) |  |  | (900) |
Balance at end of year |  | 6,812 |  |  | 7,001 |  |  | 7,174 |
Total equity at end of year |  | $ | 3,578,686 |  |  | $ | 3,337,955 |  |  | $ | 2,914,743 |

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

|  | Year Ended December 31,
|  | 2025 |  | 2024 |  | 2023
|  | (thousands of dollars)
Operating Revenues |  | $ | 1,809,609 |  |  | $ | 1,822,965 |  |  | $ | 1,762,894 |
Operating Expenses: |  |  |  |  |  |
Operation: |  |  |  |  |  |
Purchased power |  | 392,462 |  |  | 425,082 |  |  | 501,531 |
Fuel expense |  | 253,236 |  |  | 259,204 |  |  | 275,405 |
Power cost adjustment |  | 24,997 |  |  | 89,757 |  |  | 6,885 |
Other operations and maintenance |  | 470,537 |  |  | 460,951 |  |  | 399,855 |
Energy efficiency programs |  | 30,480 |  |  | 27,580 |  |  | 31,948 |
Depreciation and amortization |  | 251,072 |  |  | 223,410 |  |  | 195,341 |
Other operating expenses, net |  | 31,408 |  |  | 8,798 |  |  | 38,550 |
Total operating expenses |  | 1,454,192 |  |  | 1,494,782 |  |  | 1,449,515 |
Operating Income |  | 355,417 |  |  | 328,183 |  |  | 313,379 |
Nonoperating (Income) Expense: |  |  |  |  |  |
Allowance for equity funds used during construction |  | (62,489) |  |  | (53,238) |  |  | (43,221) |
Earnings of unconsolidated equity-method investments |  | (2,984) |  |  | (2,671) |  |  | (10,540) |
Interest on long-term debt and finance leases |  | 174,929 |  |  | 139,196 |  |  | 116,216 |
Other interest |  | 29,035 |  |  | 24,105 |  |  | 19,913 |
Allowance for borrowed funds used during construction |  | (36,211) |  |  | (27,785) |  |  | (20,012) |
Other income, net |  | (49,548) |  |  | (49,710) |  |  | (34,713) |
Total nonoperating expense, net |  | 52,732 |  |  | 29,897 |  |  | 27,643 |
Income Before Income Taxes |  | 302,685 |  |  | 298,286 |  |  | 285,736 |
Income Tax (Benefit) Expense |  | (13,177) |  |  | 17,681 |  |  | 28,926 |
Net Income |  | $ | 315,862 |  |  | $ | 280,605 |  |  | $ | 256,810 |

The accompanying notes are an integral part of these statements.
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Idaho Power Company
Consolidated Statements of Comprehensive Income

|  | Year Ended December 31,
|  | 2025 |  | 2024 |  | 2023
|  | (thousands of dollars)
Net Income |  | $ | 315,862 |  |  | $ | 280,605 |  |  | $ | 256,810 |
Other Comprehensive Income: |  |  |  |  |  |
Unfunded pension liability adjustment, net of tax of $(145), $1,245, and $(1,477), respectively |  | (1,352) |  |  | 3,592 |  |  | (4,262) |
Total Comprehensive Income |  | $ | 314,510 |  |  | $ | 284,197 |  |  | $ | 252,548 |

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

|  | December 31,
|  | 2025 |  | 2024
|  | (thousands of dollars)
Assets |  |  |  |
Current Assets: |  |  |  |
Cash and cash equivalents |  | $ | 119,111 |  |  | $ | 188,916 |
Receivables: |  |  |  |
Customer (net of allowance of $3,788 and $5,071, respectively) |  | 97,724 |  |  | 114,824 |
Other (net of allowance of $637 and $628, respectively) |  | 37,108 |  |  | 28,874 |
Income taxes receivable |  | 1,294 |  |  | 11,811 |
Accrued unbilled receivables |  | 79,931 |  |  | 97,711 |
Materials and supplies (at average cost) |  | 201,896 |  |  | 201,064 |
Fuel stock (at average cost) |  | 24,455 |  |  | 43,656 |
Prepayments |  | 30,447 |  |  | 29,328 |
Current regulatory assets |  | 136,665 |  |  | 89,315 |
Other |  | 3 |  |  | — |
Total current assets |  | 728,634 |  |  | 805,499 |
Investments |  | 89,103 |  |  | 92,921 |
Property, Plant, and Equipment: |  |  |  |
Plant in service |  | 8,249,106 |  |  | 7,957,763 |
Accumulated provision for depreciation |  | (2,599,465) |  |  | (2,714,706) |
Plant in service - net |  | 5,649,641 |  |  | 5,243,057 |
Construction work in progress |  | 1,740,809 |  |  | 1,244,559 |
Finance lease right-of-use assets |  | 219,612 |  |  | — |
Plant held for future use |  | 19,781 |  |  | 13,211 |
Other property |  | 6,715 |  |  | 4,858 |
Property, plant, and equipment, net |  | 7,636,558 |  |  | 6,505,685 |
Other Assets: |  |  |  |
Company-owned life insurance |  | 105,306 |  |  | 92,062 |
Regulatory assets |  | 1,427,793 |  |  | 1,418,057 |
Other |  | 49,502 |  |  | 52,744 |
Total other assets |  | 1,582,601 |  |  | 1,562,863 |
Total |  | $ | 10,036,896 |  |  | $ | 8,966,968 |

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

|  | December 31,
|  | 2025 |  | 2024
|  | (thousands of dollars)
Liabilities and Equity |  |  |  |
Current Liabilities: |  |  |  |
Current maturities of long-term debt |  | $ | 116,300 |  |  | $ | 19,885 |
Accounts payable |  | 342,501 |  |  | 305,248 |
Accounts payable to affiliates |  | 3,555 |  |  | 3,403 |
Taxes accrued |  | 7,532 |  |  | 6,981 |
Interest accrued |  | 49,547 |  |  | 42,681 |
Accrued compensation |  | 76,912 |  |  | 70,319 |
Current regulatory liabilities |  | 21,089 |  |  | 7,523 |
Advances from customers |  | 201,743 |  |  | 165,229 |
Other |  | 64,209 |  |  | 61,309 |
Total current liabilities |  | 883,388 |  |  | 682,578 |
Other Liabilities: |  |  |  |
Deferred income taxes |  | 800,939 |  |  | 829,446 |
Regulatory liabilities |  | 1,031,062 |  |  | 976,803 |
Pension and other postretirement benefits |  | 137,406 |  |  | 165,992 |
Finance lease liabilities |  | 216,695 |  |  | — |
Other |  | 224,375 |  |  | 167,775 |
Total other liabilities |  | 2,410,477 |  |  | 2,140,016 |
Long-Term Debt |  | 3,331,038 |  |  | 3,053,777 |
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 |  | 1,107,258 |  |  | 912,258 |
Capital stock expense |  | (2,097) |  |  | (2,097) |
Retained earnings |  | 2,223,899 |  |  | 2,096,151 |
Accumulated other comprehensive loss |  | (14,944) |  |  | (13,592) |
Total equity |  | 3,411,993 |  |  | 3,090,597 |
Total |  | $ | 10,036,896 |  |  | $ | 8,966,968 |
The accompanying notes are an integral part of these statements.

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Idaho Power Company
Consolidated Statements of Cash Flows

|  | Year Ended December 31,
|  | 2025 |  | 2024 |  | 2023
|  | (thousands of dollars)
Operating Activities: |  |  |  |  |  |
Net income |  | $ | 315,862 |  |  | $ | 280,605 |  |  | $ | 256,810 |
Adjustments to reconcile net income to net cash provided by operating activities: |  |  |  |  |  |
Depreciation and amortization |  | 257,794 |  |  | 227,480 |  |  | 199,307 |
Deferred income taxes and investment tax credits |  | (48,505) |  |  | (15,151) |  |  | 35,080 |
Changes in regulatory assets and liabilities |  | 31,229 |  |  | 115,026 |  |  | (4,748) |
Pension and postretirement benefit plan expense |  | 45,190 |  |  | 45,763 |  |  | 27,138 |
Contributions to pension and postretirement benefit plans |  | (27,589) |  |  | (25,427) |  |  | (55,319) |
Earnings of equity-method investments |  | (2,984) |  |  | (2,671) |  |  | (10,540) |
Distributions from equity-method investments |  | 7,150 |  |  | 5,750 |  |  | 650 |
Allowance for equity funds used during construction |  | (62,489) |  |  | (53,238) |  |  | (43,221) |
Other non-cash adjustments to net income, net |  | (3,941) |  |  | (1,502) |  |  | (1,143) |
Change in: |  |  |  |  |  |
Accounts receivable and unbilled receivables |  | 9,466 |  |  | 32,702 |  |  | (17,882) |
Prepayments |  | (3,668) |  |  | (8,927) |  |  | (3,212) |
Materials, supplies, and fuel stock |  | 18,370 |  |  | (84,261) |  |  | (53,243) |
Accounts and wages payable |  | (16,798) |  |  | 15,781 |  |  | (121,609) |
Taxes accrued/receivable |  | 11,068 |  |  | (2,850) |  |  | (12,085) |
Other assets and liabilities |  | 37,620 |  |  | 32,171 |  |  | 10,776 |
Net cash provided by operating activities |  | 567,775 |  |  | 561,251 |  |  | 206,759 |
Investing Activities: |  |  |  |  |  |
Additions to utility plant, net |  | (1,178,990) |  |  | (1,009,138) |  |  | (610,913) |
Payments received from transmission project joint funding partners |  | 151,880 |  |  | 83,708 |  |  | 26,501 |
Purchase of equity securities |  | (8,452) |  |  | (10,991) |  |  | (11,233) |
Purchases of held-to-maturity securities |  | (2,896) |  |  | (1,845) |  |  | (1,617) |
Proceeds from sale of investment securities |  | 12,013 |  |  | 10,641 |  |  | 8,921 |
Other |  | 13,151 |  |  | 12,249 |  |  | 6,198 |
Net cash used in investing activities |  | (1,013,294) |  |  | (915,376) |  |  | (582,143) |
Financing Activities: |  |  |  |  |  |
Issuance of long-term debt |  | 400,000 |  |  | 300,000 |  |  | 872,000 |
Discount on issuance of long-term debt |  | (3,072) |  |  | (186) |  |  | (7,006) |
Retirement of long-term debt |  | (19,885) |  |  | (49,800) |  |  | (225,000) |
Payments on finance lease liabilities |  | (3,762) |  |  | — |  |  | — |
Dividends on common stock |  | (187,806) |  |  | (175,772) |  |  | (101,790) |
Capital contribution from parent |  | 195,000 |  |  | 200,000 |  |  | — |
Other |  | (4,761) |  |  | (2,992) |  |  | 38 |
Net cash provided by financing activities |  | 375,714 |  |  | 271,250 |  |  | 538,242 |
Net (decrease) increase in cash and cash equivalents |  | (69,805) |  |  | (82,875) |  |  | 162,858 |
Cash and cash equivalents at beginning of the year |  | 188,916 |  |  | 271,791 |  |  | 108,933 |
Cash and cash equivalents at end of the year |  | $ | 119,111 |  |  | $ | 188,916 |  |  | $ | 271,791 |
Supplemental Disclosure of Cash Flow Information: |  |  |  |  |  |
Cash paid for interest (net of amount capitalized) |  | $ | 138,839 |  |  | $ | 108,718 |  |  | $ | 97,402 |
Non-cash investing activities: |  |  |  |  |  |
Additions to utility plant in accounts payable |  | $ | 222,340 |  |  | $ | 168,107 |  |  | $ | 185,400 |
Right-of-use asset obtained in exchange for finance lease liability |  | $ | 226,618 |  |  | $ | — |  |  | $ | — |

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

|  | Year Ended December 31,
|  | 2025 |  | 2024 |  | 2023
|  | (thousands of dollars)
Retained Earnings, Beginning of Year |  | $ | 2,096,151 |  |  | $ | 1,991,319 |  |  | $ | 1,836,547 |
Net Income |  | 315,862 |  |  | 280,605 |  |  | 256,810 |
Dividends on Common Stock |  | (188,114) |  |  | (175,773) |  |  | (102,038) |
Retained Earnings, End of Year |  | $ | 2,223,899 |  |  | $ | 2,096,151 |  |  | $ | 1,991,319 |

The accompanying notes are an integral part of these statements.
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IDACORP, INC. AND IDAHO POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
This Annual Report on Form 10-K is a combined report of IDACORP 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, sale, and purchase of electric energy and capacity with a service area covering approximately 24,000 square miles in southern Idaho and eastern Oregon. On February 13, 2026, Idaho Power signed an asset purchase agreement with OTEC for the sale of Idaho Power's electric distribution business and certain transmission assets in the state of Oregon. Refer to Note 22 - "Sale of Oregon Assets" for additional information regarding the Oregon Sale. 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 subsidiaries include IFS, an investor in affordable housing and other real estate tax credit investments, and Ida-West, an operator of small PURPA-qualifying hydropower generation projects.
Principles of Consolidation
IDACORP’s and Idaho Power’s consolidated financial statements include the assets, liabilities, revenues, and expenses of each company and its 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, 2025, Marysville had approximately $14.2 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 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 $16.8 million at December 31, 2025, and Idaho Power's maximum exposure to loss is the carrying value, any additional future contributions to BCC, and a $50.1 million guarantee for mine reclamation costs. BCC has a reclamation trust fund set aside specifically for the purpose of paying the reclamation costs. At December 31, 2025, the value of BCC's reclamation trust fund exceeded the guarantee requirement for the total reclamation obligation. 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 7 to 100 percent and were acquired between 2004 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 $50.4 million at December 31, 2025.
Ida-West's other investments in PURPA facilities, Idaho Power's investment in BCC, and IFS's investments are accounted for under the equity method of accounting (see Note 15 - "Investments").
Except for amounts related to sales of electricity by Ida-West's PURPA projects to Idaho Power, all intercompany transactions and balances have been eliminated in consolidation.
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The accompanying consolidated financial statements include Idaho Power's proportionate share of utility plant and related operations resulting from its interests in jointly-owned plants (see Note 13 - "Property, Plant and Equipment and Jointly-Owned Projects").
Regulation of Utility Operations
As a regulated utility, many of Idaho Power's fundamental business decisions are subject to the approval of governmental agencies, including the prices that Idaho Power is authorized to charge for its electric service. These approvals are a critical factor in determining IDACORP's and Idaho Power's results of operations and financial condition.
Idaho Power meets the requirements under 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 and amortization 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 entity 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, among others, those related to rate regulation, retirement benefits, contingencies, asset impairment, income taxes, unbilled receivables, and the allowance for uncollectible accounts. 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 and 2.4 percent in Idaho Power's Idaho and Oregon jurisdictions, respectively, may be assessed per month 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.
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The following table provides a rollforward of the allowance for uncollectible accounts related to customer receivables (in thousands of dollars):

|  | Year Ended December 31,
|  | 2025 |  | 2024
Balance at beginning of period |  | $ | 5,071 |  |  | $ | 4,869 |
Additions to the allowance |  | 3,004 |  |  | 4,523 |
Write-offs, net of recoveries |  | (4,287) |  |  | (4,321) |
Balance at end of period |  | $ | 3,788 |  |  | $ | 5,071 |
Allowance for uncollectible accounts as a percentage of customer receivables |  | 3.7 | % |  | 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, 2025 and 2024. 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 receivables 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 3.2 percent in 2025, 3.1 percent in 2024, and 2.9 percent in 2023.
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.
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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 2025, 2024, or 2023.
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. AFUDC is included as a reduction to total nonoperating expense, net, on the consolidated statements of income. Idaho Power’s weighted-average monthly AFUDC rate was 7.2 percent for both 2025 and 2024, and 7.4 percent for 2023.
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
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 are required to be applied prospectively and are allowed to be applied retrospectively. IDACORP and Idaho Power adopted this ASU on January 1, 2025, for annual periods. The amendments in this ASU have been applied retrospectively. See Note 2 - "Income Taxes" for expanded disclosure required by this ASU.
There have been no other 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 2024, the FASB issued ASU 2024-03, Income Statement (Subtopic 220-40): Disaggregation of Income Statement Expenses which requires disclosure of certain disaggregated income statement expense categories on an annual and interim basis. This ASU is effective for annual periods beginning after December 15, 2026, and for interim periods beginning after December 15, 2027, with early adoption permitted. The amendments in this ASU are required to be applied prospectively and are allowed to be applied retrospectively. IDACORP and Idaho Power are currently evaluating the impact that adoption of this ASU will have on the notes to their respective consolidated financial statements.
In September 2025, the FASB issued ASU 2025-06, Intangibles (Subtopic 350-40): Targeted Improvements to the Accounting for Internal-Use Software which amends certain aspects of the accounting for and disclosure of software costs. This ASU is effective for annual and interim periods beginning after December 15, 2027, with early adoption permitted. The amendments in this ASU are required to be applied prospectively and may be applied either retrospectively or using a modified prospective transition method. IDACORP and Idaho Power are currently evaluating the impact that adoption of this ASU will have on their respective 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.
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2. INCOME TAXES
Reconciliations between the statutory federal income tax rate and the effective tax rate for the years ended December 31 are presented below (in thousands of dollars, except percentages):

|  | IDACORP |
|  | 2025 |  | 2024 |  | 2023 |
Income before income taxes(1) |  | $ | 309,757 |  |  |  |  | $ | 304,227 |  |  |  |  | $ | 288,491 |  |  |  |
US federal income tax expense at statutory rate |  | 65,049 |  |  | 21.0 | % |  | 63,888 |  |  | 21.0 | % |  | 60,583 |  |  | 21.0 | % |
State income taxes, net of federal income tax effect(2) |  | 12,480 |  |  | 4.0 | % |  | 14,420 |  |  | 4.7 | % |  | 13,675 |  |  | 4.7 | % |
Flow-through accounting and other effects of rate regulation: |  |  |  |  |  |  |  |  |  |  |  |  |
AFUDC |  | (20,727) |  |  | (6.7) | % |  | (17,015) |  |  | (5.6) | % |  | (13,279) |  |  | (4.6) | % |
Capitalized interest |  | 7,721 |  |  | 2.5 | % |  | 5,493 |  |  | 1.8 | % |  | 3,097 |  |  | 1.1 | % |
Removal costs |  | (5,707) |  |  | (1.8) | % |  | (5,109) |  |  | (1.7) | % |  | (6,312) |  |  | (2.2) | % |
Capitalized overhead costs |  | (2,100) |  |  | (0.7) | % |  | (2,100) |  |  | (0.7) | % |  | (2,100) |  |  | (0.7) | % |
Capitalized repair costs |  | (24,150) |  |  | (7.8) | % |  | (19,320) |  |  | (6.4) | % |  | (24,360) |  |  | (8.4) | % |
Depreciation |  | 22,001 |  |  | 7.1 | % |  | 18,705 |  |  | 6.1 | % |  | 18,041 |  |  | 6.3 | % |
Excess deferred income tax reversal |  | (9,723) |  |  | (3.1) | % |  | (10,047) |  |  | (3.3) | % |  | (10,684) |  |  | (3.7) | % |
Income tax return adjustments |  | (8,046) |  |  | (2.6) | % |  | 1,844 |  |  | 0.6 | % |  | (8,229) |  |  | (2.9) | % |
State related |  | 324 |  |  | 0.1 | % |  | 6,043 |  |  | 2.0 | % |  | 2,127 |  |  | 0.7 | % |
Other, net |  | (808) |  |  | (0.3) | % |  | 776 |  |  | 0.3 | % |  | 1,874 |  |  | 0.6 | % |
Tax credits: |  |  |  |  |  |  |  |  |  |  |  |  |
Investment tax credits - federal |  | (7,208) |  |  | (2.3) | % |  | (4,480) |  |  | (1.5) | % |  | (2,344) |  |  | (0.8) | % |
Investment tax credits - Idaho |  | — |  |  | — | % |  | (3,791) |  |  | (1.2) | % |  | (3,107) |  |  | (1.1) | % |
Accumulated deferred investment tax credits - federal |  | (7,017) |  |  | (2.3) | % |  | (8,712) |  |  | (2.9) | % |  | — |  |  | — | % |
Accumulated deferred investment tax credits - Idaho |  | (33,319) |  |  | (10.8) | % |  | (21,119) |  |  | (6.9) | % |  | — |  |  | — | % |
Real estate-related tax credits - federal |  | (7,790) |  |  | (2.5) | % |  | (7,499) |  |  | (2.5) | % |  | (6,869) |  |  | (2.4) | % |
Nontaxable or nondeductible items |  | (229) |  |  | (0.1) | % |  | (516) |  |  | (0.2) | % |  | 120 |  |  | — | % |
Other Items: |  |  |  |  |  |  |  |  |  |  |  |  |
Real estate-related investment distributions |  | (670) |  |  | (0.2) | % |  | (1,611) |  |  | (0.5) | % |  | (507) |  |  | (0.2) | % |
Real estate-related investment amortization |  | 6,204 |  |  | 2.0 | % |  | 5,203 |  |  | 1.7 | % |  | 5,570 |  |  | 1.9 | % |
Total income tax (benefit) expense and effective tax rate |  | $ | (13,715) |  |  | (4.4) | % |  | $ | 15,053 |  |  | 4.9 | % |  | $ | 27,296 |  |  | 9.5 | % |

(1) Net of adjustment for income attributable to noncontrolling interests.
(2) State taxes in Idaho made up the majority (greater than 50%) of the tax effect in this category.
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|  | Idaho Power
|  | 2025 |  | 2024 |  | 2023
Income before income taxes |  | $ | 302,685 |  |  |  |  | $ | 298,286 |  |  |  |  | $ | 285,736 |  |  |
US federal income tax expense at statutory rate |  | 63,564 |  |  | 21.0 | % |  | 62,640 |  |  | 21.0 | % |  | 60,005 |  |  | 21.0 | %
State income taxes, net of federal income tax effect(1) |  | 12,195 |  |  | 4.0 | % |  | 14,139 |  |  | 4.7 | % |  | 13,544 |  |  | 4.7 | %
Flow-through accounting and other effects of rate regulation: |  |  |  |  |  |  |  |  |  |  |  |
AFUDC |  | (20,727) |  |  | (6.8) | % |  | (17,015) |  |  | (5.7) | % |  | (13,279) |  |  | (4.6) | %
Capitalized interest |  | 7,721 |  |  | 2.6 | % |  | 5,493 |  |  | 1.8 | % |  | 3,097 |  |  | 1.1 | %
Removal costs |  | (5,707) |  |  | (1.9) | % |  | (5,109) |  |  | (1.7) | % |  | (6,312) |  |  | (2.2) | %
Capitalized overhead costs |  | (2,100) |  |  | (0.7) | % |  | (2,100) |  |  | (0.7) | % |  | (2,100) |  |  | (0.7) | %
Capitalized repair costs |  | (24,150) |  |  | (8.0) | % |  | (19,320) |  |  | (6.5) | % |  | (24,360) |  |  | (8.5) | %
Depreciation |  | 22,001 |  |  | 7.3 | % |  | 18,705 |  |  | 6.3 | % |  | 18,041 |  |  | 6.3 | %
Excess deferred income tax reversal |  | (9,723) |  |  | (3.2) | % |  | (10,047) |  |  | (3.4) | % |  | (10,684) |  |  | (3.7) | %
Income tax return adjustments |  | (8,581) |  |  | (2.8) | % |  | 1,794 |  |  | 0.6 | % |  | (7,732) |  |  | (2.7) | %
State related |  | 684 |  |  | 0.2 | % |  | 6,361 |  |  | 2.1 | % |  | 2,537 |  |  | 0.9 | %
Other, net |  | (577) |  |  | (0.2) | % |  | 759 |  |  | 0.3 | % |  | 1,499 |  |  | 0.5 | %
Tax credits: |  |  |  |  |  |  |  |  |  |  |  |
Investment tax credits - federal |  | (7,208) |  |  | (2.4) | % |  | (4,480) |  |  | (1.5) | % |  | (2,344) |  |  | (0.8) | %
Investment tax credits - Idaho |  | — |  |  | — | % |  | (3,791) |  |  | (1.3) | % |  | (3,107) |  |  | (1.1) | %
Accumulated deferred investment tax credits - federal |  | (7,017) |  |  | (2.3) | % |  | (8,712) |  |  | (2.9) | % |  | — |  |  | — | %
Accumulated deferred investment tax credits - Idaho |  | (33,319) |  |  | (11.0) | % |  | (21,119) |  |  | (7.1) | % |  | — |  |  | — | %
Nontaxable or nondeductible items |  | (233) |  |  | (0.1) | % |  | (517) |  |  | (0.2) | % |  | 121 |  |  | — | %
Total income tax (benefit) expense and effective tax rate |  | $(13,177) |  | (4.4) | % |  | $17,681 |  | 5.9 | % |  | $28,926 |  | 10.1 | %

(1) State taxes in Idaho made up the majority (greater than 50%) of the tax effect in this category.
The items comprising income tax expense for the years ended December 31 are presented below (in thousands of dollars):

|  | IDACORP |  | Idaho Power
|  | 2025 |  | 2024 |  | 2023 |  | 2025 |  | 2024 |  | 2023
Income taxes current: |  |  |  |  |  |  |  |  |  |  |  |
Federal |  | $ | 13,684 |  |  | $ | 19,252 |  |  | $ | (13,253) |  |  | $ | 27,816 |  |  | $ | 20,447 |  |  | $ | (4,757) |
State |  | 5,754 |  |  | 15,750 |  |  | 5,634 |  |  | 8,128 |  |  | 12,674 |  |  | 3,627 |
Total |  | 19,438 |  |  | 35,002 |  |  | (7,619) |  |  | 35,944 |  |  | 33,121 |  |  | (1,130) |
Income taxes deferred: |  |  |  |  |  |  |  |  |  |  |  |
Federal |  | (28,931) |  |  | (73,565) |  |  | (18,419) |  |  | (35,697) |  |  | (67,549) |  |  | (19,086) |
State |  | (16,431) |  |  | (15,608) |  |  | (3,269) |  |  | (18,826) |  |  | (12,735) |  |  | (1,051) |
Total |  | (45,362) |  |  | (89,173) |  |  | (21,688) |  |  | (54,523) |  |  | (80,284) |  |  | (20,137) |
Investment tax credits: |  |  |  |  |  |  |  |  |  |  |  |
Deferred |  | 52,946 |  |  | 102,946 |  |  | 55,644 |  |  | 52,946 |  |  | 102,946 |  |  | 55,644 |
Restored |  | (47,544) |  |  | (38,102) |  |  | (5,451) |  |  | (47,544) |  |  | (38,102) |  |  | (5,451) |
Total |  | 5,402 |  |  | 64,844 |  |  | 50,193 |  |  | 5,402 |  |  | 64,844 |  |  | 50,193 |
Real estate-related investments at IFS |  | 6,807 |  |  | 4,380 |  |  | 6,410 |  |  | — |  |  | — |  |  | — |
Total income tax (benefit) expense |  | $ | (13,715) |  |  | $ | 15,053 |  |  | $ | 27,296 |  |  | $ | (13,177) |  |  | $ | 17,681 |  |  | $ | 28,926 |

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The components of the net deferred tax liability as of December 31 are presented below (in thousands of dollars):

|  | IDACORP |  | Idaho Power
|  | 2025 |  | 2024 |  | 2025 |  | 2024
Deferred tax assets: |  |  |  |  |  |  |  |
Regulatory liabilities |  | $ | 121,489 |  |  | $ | 127,634 |  |  | $ | 121,489 |  |  | $ | 127,634 |
Deferred compensation |  | 24,483 |  |  | 24,782 |  |  | 24,483 |  |  | 24,782 |
Deferred revenue |  | 70,326 |  |  | 64,592 |  |  | 70,326 |  |  | 64,592 |
Tax credits |  | 70,854 |  |  | 66,783 |  |  | 67,930 |  |  | 53,859 |
Partnership investments |  | 24,157 |  |  | 18,450 |  |  | 24,157 |  |  | 18,450 |
Retirement benefits |  | 19,533 |  |  | 26,495 |  |  | 19,533 |  |  | 26,495 |
Other |  | 37,884 |  |  | 24,869 |  |  | 37,831 |  |  | 24,826 |
Total |  | 368,726 |  |  | 353,605 |  |  | 365,749 |  |  | 340,638 |
Deferred tax liabilities: |  |  |  |  |  |  |  |
Property, plant and equipment |  | 235,849 |  |  | 243,454 |  |  | 235,849 |  |  | 243,454 |
Regulatory assets |  | 821,346 |  |  | 811,054 |  |  | 821,346 |  |  | 811,054 |
Partnership investments |  | 4,309 |  |  | 4,613 |  |  | — |  |  | — |
Retirement benefits |  | 65,214 |  |  | 75,716 |  |  | 65,214 |  |  | 75,716 |
Wildfire mitigation plan deferral |  | 22,252 |  |  | 16,272 |  |  | 22,252 |  |  | 16,272 |
Other |  | 22,641 |  |  | 24,727 |  |  | 22,027 |  |  | 23,588 |
Total |  | 1,171,611 |  |  | 1,175,836 |  |  | 1,166,688 |  |  | 1,170,084 |
Net deferred tax liabilities |  | $ | 802,885 |  |  | $ | 822,231 |  |  | $ | 800,939 |  |  | $ | 829,446 |

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.
Supplemental Disclosure of Cash Flow Information
Supplemental cash flow information related to cash paid for income taxes for the years ended December 31 are presented below (in thousands of dollars):

|  | IDACORP
|  | 2025 |  | 2024 |  | 2023
Federal |  | $ | 18,000 |  |  | $ | 14,000 |  |  | $ | — |
Idaho |  | 5,600 |  |  | 10,300 |  |  | 5,300 |
Other |  | 892 |  |  | 900 |  |  | 900 |
Total cash paid for income taxes |  | $ | 24,492 |  |  | $ | 25,200 |  |  | $ | 6,200 |

|  | Idaho Power
|  | 2025 |  | 2024 |  | 2023
Federal |  | $ | 18,382 |  |  | $ | 30,615 |  |  | $ | 34,604 |
Idaho |  | 7,522 |  |  | 5,598 |  |  | 15,765 |
Other |  | 841 |  |  | 905 |  |  | 1,446 |
Total cash paid to IDACORP related to income taxes |  | $ | 26,745 |  |  | $ | 37,118 |  |  | $ | 51,815 |

Tax Credit Carryforwards
As of December 31, 2025, IDACORP had $70.9 million of Idaho investment tax credit carryforward which expires from 2034 to 2039.
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Uncertain Tax Positions
IDACORP and Idaho Power believe that they have no material income tax uncertainties for 2025 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 2023 through 2025 for federal and 2022 through 2025 for Idaho. In May 2009, IDACORP formally entered the U.S. Internal Revenue Service Compliance Assurance Process (CAP) program for its 2009 tax year and has remained in the CAP program for all subsequent years.
3. REGULATORY MATTERS
IDACORP’s and Idaho Power’s financial statements reflect the effects of the different ratemaking principles followed by the jurisdictions regulating Idaho Power. Included below is a summary of Idaho Power's regulatory assets and liabilities, as well as a discussion of notable regulatory matters affecting customer rates.
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, 2025 |  |  |  |
|  | Remaining Amortization Period |  | Earning a Return(1) |  | Not Earning a Return |  | Total as of December 31,
Description |  |  |  |  | 2025 |  | 2024
Regulatory Assets: |  |  |  |  |  |  |  |  |  |
Income taxes(2) |  |  |  | $ | — |  |  | $ | 821,346 |  |  | $ | 821,346 |  |  | $ | 811,054 |
Pension expense deferrals(3) |  |  |  | 245,508 |  |  | 1,832 |  |  | 247,340 |  |  | 252,197 |
Mark-to-market assets(4) |  |  |  | — |  |  | 49,520 |  |  | 49,520 |  |  | 28,118 |
Unfunded postretirement benefits(5) |  |  |  | — |  |  | — |  |  | — |  |  | 18,824 |
Power supply costs(6) |  |  |  | — |  |  | — |  |  | — |  |  | 18,507 |
Fixed cost adjustment(6) |  | 2026-2027 |  | 8,205 |  |  | (1,350) |  |  | 6,855 |  |  | 17,761 |
North Valmy plant settlements(6) |  | 2026-2033 |  | 83,941 |  |  | — |  |  | 83,941 |  |  | 80,767 |
Jim Bridger plant settlement(6) |  | 2026-2030 |  | 151,739 |  |  | 12,921 |  |  | 164,660 |  |  | 147,451 |
Wildfire Mitigation Plan deferral(6) |  |  |  | — |  |  | 91,670 |  |  | 91,670 |  |  | 63,966 |
Asset retirement obligations(7) |  |  |  | — |  |  | 62,166 |  |  | 62,166 |  |  | 37,842 |
Long-term service agreement |  | 2026-2043 |  | 11,313 |  |  | 7,326 |  |  | 18,639 |  |  | 19,796 |
Other |  | 2026-2056 |  | 4,596 |  |  | 13,725 |  |  | 18,321 |  |  | 11,089 |
Total |  |  |  | $ | 505,302 |  |  | $ | 1,059,156 |  |  | $ | 1,564,458 |  |  | $ | 1,507,372 |
Regulatory Liabilities: |  |  |  |  |  |  |  |  |  |
Income taxes(8) |  |  |  | $ | — |  |  | $ | 121,489 |  |  | $ | 121,489 |  |  | $ | 127,634 |
Depreciation-related excess deferred income taxes(9) |  |  |  | 128,180 |  |  | — |  |  | 128,180 |  |  | 137,903 |
Removal costs(7) |  |  |  | — |  |  | 162,652 |  |  | 162,652 |  |  | 166,181 |
Investment tax credits |  |  |  | — |  |  | 235,724 |  |  | 235,724 |  |  | 230,322 |
Deferred revenue-AFUDC(10) |  |  |  | 224,083 |  |  | 56,896 |  |  | 280,979 |  |  | 250,942 |
Energy efficiency program costs |  |  |  | 16,493 |  |  | — |  |  | 16,493 |  |  | 9,277 |
Power supply costs(6) |  | 2026-2027 |  | 42,419 |  |  | — |  |  | 42,419 |  |  | 3,949 |
Unfunded postretirement benefits(5) |  |  |  | — |  |  | 11,785 |  |  | 11,785 |  |  | — |
Tax reform accrual for future amortization(11) |  |  |  | — |  |  | 44,423 |  |  | 44,423 |  |  | 42,266 |
Other |  |  |  | 4,168 |  |  | 3,839 |  |  | 8,007 |  |  | 15,852 |
Total |  |  |  | $ | 415,343 |  |  | $ | 636,808 |  |  | $ | 1,052,151 |  |  | $ | 984,326 |

(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 2025 were 5.0% 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) 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.
(4) This item is discussed in more detail in Note 16 - "Derivative Financial Instruments."
(5) Represents the unfunded obligation of Idaho Power’s pension and postretirement benefit plans, which are discussed in Note 12 - "Benefit Plans."
(6) This item is discussed in more detail in this Note 3 - "Regulatory Matters."
(7) Asset retirement obligations and removal costs are discussed in Note 14 - "Asset Retirement Obligations (ARO)."
(8) Represents the tax gross-up related to the depreciation-related excess deferred income taxes and investment tax credits included in this table and has a corresponding deferred tax asset disclosed in Note 2 - "Income Taxes."
(9) 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 accrued as a credit on the balance sheets for future recovery or refund. The power supply costs deferred or accrued 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 Idaho-jurisdiction PCA year runs from April 1 through March 31. Amounts deferred or accrued during the PCA year are primarily recovered or refunded during the subsequent June 1 through May 31 period. 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, export credit mechanisms, a battery storage lease, 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.
Beginning April 1, 2024, the difference between actual and base-level third-party transmission wheeling revenues are tracked and incorporated into the balancing component of the PCA, as authorized by the IPUC in March 2025. In May 2025, the IPUC issued an order approving a $94.8 million net decrease in PCA revenues as compared with the prior collection period, effective for the PCA collection period from June 1, 2025, to May 31, 2026. The net decrease in PCA revenues reflected a decrease in the balancing adjustment, which was due primarily to the completed recovery of the 2023 deferred PCA costs, which were recovered over a two-year period as ordered by the IPUC. The 2025 Settlement Stipulation, described in more detail below, modified PCA collection effective January 1, 2026, to account for the new system base level NPSE of $468.8 million.
The table below summarizes the three most recent Idaho-jurisdiction PCA rate adjustments from Idaho Power's annual PCA filings, which also include non-PCA-related rate adjustments as ordered by the IPUC:

Effective Date |  | $ Change (millions) |  | Notes
June 1, 2025 |  | $ | (94.8) |  |  | The $94.8 million net decrease in PCA rates reflects a decrease in the balancing adjustment, which is due primarily to the completed recovery of the 2023 balancing adjustment, which was recovered over two years.
June 1, 2024 |  | $ | (35.7) |  |  | The $35.7 million net decrease in PCA rates reflected forecasted improved hydropower generation during the April 2024 to March 2025 PCA deferral period.
June 1, 2023 |  | $ | 105.1 |  |  | The $105.1 million increase in PCA rates reflected higher market energy and natural gas prices, combined with lower than-expected low-cost hydropower generation and limited coal supply. The increased rate also reflected an expectation of continued elevated market energy prices and natural gas prices in the forecast period.

Oregon Jurisdiction Power Cost Adjustment Mechanism: Idaho Power’s power cost recovery mechanism in Oregon has two components: an APCU and a power cost adjustment mechanism (PCAM). The APCU allows Idaho Power to reestablish its Oregon base net power supply costs annually, separate from a general rate case, and to forecast net power supply costs for the
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upcoming water year. The PCAM is a true-up filed annually in February. The PCAM 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. In May 2025, the OPUC approved a settlement stipulation between Idaho Power and intervening parties for its APCU in Oregon. The settlement resulted in an overall rate decrease of $1.8 million in Oregon-jurisdictional rates effective June 1, 2025. Idaho Power's 2024 and 2023 June 1 APCU rate changes were a decrease of $6.9 million, and an increase of $7.7 million, respectively.
Notable Idaho Base Rate Adjustments
Idaho base rates were most recently established through a general rate case in 2025, which was resolved by the 2025 Settlement Stipulation, with rate changes effective January 1, 2026. Previously, base rates were established in the 2024 Idaho Limited-Issue Rate Case and in a general rate case in 2023, which was resolved by the 2023 Settlement Stipulation.
2025 Idaho General Rate Case: In May 2025, Idaho Power filed a general rate case with the IPUC. The general rate case was resolved in December 2025, when the IPUC issued an order (the Order) approving the 2025 Settlement Stipulation, entered into by Idaho Power, the Staff of the IPUC, and several of the intervening parties.
The 2025 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 approximately $110.0 million, or 7.48 percent, effective January 1, 2026. The approximate $110.0 million of additional annual revenue is inclusive of a PCA rate increase of $13.1 million;
•a 9.6 percent return on equity and a 7.41 percent authorized rate of return based on the filed cost of debt and capital structure, applied to an Idaho-jurisdictional rate base of approximately $4.9 billion (which is largely based on the average of monthly average plant balances for January through December 2025);
•a base level NPSE of approximately $468.8 million, a decrease of $16.1 million from the currently approved base level NPSE;
•updates to the FCA mechanism rates to reflect approved fixed costs and Idaho Power’s proposed rate designs;
•continued deferral of certain wildfire mitigation related costs, including incremental vegetation management and insurance costs, as measured primarily from 2024 actual costs, through the earlier of Idaho Power's next general rate case or 2027;
•modifications to Idaho Power’s ADITC and revenue sharing mechanism: (1) to include an additional amount of investment tax credits equal to the total of existing ADITCs not currently eligible for accelerated amortization under the mechanism and all investment tax credits generated through the end of calendar-year 2028; (2) to establish an annual cap of $55 million on the amount of accelerated amortization of ADITCs for calendar year 2026 and thereafter; (3) to re-affirm the existing minimum specified Idaho-jurisdiction return on year-end equity (Idaho ROE) of 9.12 percent for additional amortization of ADITCs; (4) to re-affirm the existing 9.6 percent Idaho ROE as the threshold for revenue sharing of Idaho-jurisdiction earnings between Idaho Power and Idaho customers; and (5) to continue to implement all revenue sharing through the PCA; and
•agreement that Idaho Power’s share of capital expenditures at jointly-owned coal-fired plants through year-end 2024 are included for recovery in the stipulated revenue requirement.
At the time of the 2025 Settlement Stipulation, Staff of the IPUC had completed its prudence review of capital projects included in the test year rate base through July 2025. The IPUC Staff will address the prudence of investments placed in service after July 2025 in Idaho Power’s next Idaho general rate case. Neither the Order nor the 2025 Settlement Stipulation precludes Idaho Power from filing another general rate case in Idaho at any time in the future.
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 2025, Idaho Power recorded amortization of $40.3 million of ADITC. Accordingly, at December 31, 2025, $167.8 million of ADITC remained available for future use under the terms of the 2025 Settlement Stipulation, the 2023 Settlement Stipulation, and the 2018 Settlement Stipulation described below.
2024 Idaho Limited-Issue Rate Case: Idaho Power filed the 2024 Idaho Limited-Issue Rate Case in May 2024, focused on revenue requirements for 2024 incremental plant additions and incremental ongoing labor costs. On December 31, 2024, the IPUC issued its order in the 2024 Idaho Limited-Issue Rate Case, providing that Idaho Power implement revised tariff schedules designed to increase annual Idaho-jurisdictional retail revenue by $50.6 million, or 3.7 percent, effective January 1,
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2025. The order was subsequently modified by an errata issued on January 21, 2025, which reduced the revenue increase called for under the order to $50.1 million. The order did not adjust the overall rate of return approved in the 2023 Settlement Stipulation or make changes to Idaho regulatory mechanisms such as the PCA, FCA, and energy efficiency rider.
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 the 2023 Settlement Stipulation settling the general rate case. The order and the 2023 Settlement Stipulation provided for the following significant terms, among other items:
•Implementation of 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 was 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 PCA including establishment of a new level of base net power supply expense of $484.9 million, which included the transfer of $168.3 million from then-current PCA rates to base rates;
•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, among other items, (1) establish a minimum specified Idaho ROE of 9.12 percent for additional amortization of ADITCs; and (2) establish a 9.6 percent Idaho ROE as the threshold for revenue sharing of Idaho-jurisdiction earnings between Idaho Power and Idaho customers; and
•Agreement that Idaho Power’s capital expenditures through year-end 2022 were prudently incurred.
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. Idaho Power’s base rates and ADITC and revenue sharing mechanism were modified by the 2025 Settlement Stipulation and the 2023 Settlement Stipulation, as described above.
North Valmy Base Rate Adjustment Settlement Stipulations: Idaho Power has settlement stipulations in place in Idaho and Oregon related to the end of its participation in coal-fired operations of both units of its jointly-owned North Valmy plant. Idaho Power ceased participation in coal-fired operations at unit 1 in 2019, and coal-fired operations at unit 2 ceased at the end of 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 the North Valmy plant 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. The 2025 Settlement Stipulation made modifications to the Idaho North Valmy settlement stipulation, including updated coal-related investments through 2024 and investment forecasts through 2025. On December 31, 2025, the accelerated depreciation associated with coal-related investments at the North Valmy plant was completed and the amounts removed from Oregon customer rates.
Jim Bridger Power Plant Rate Base Adjustment and Recovery: In 2022, the IPUC authorized Idaho Power 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 its plan to cease participation in coal-fired operations at the Jim Bridger plant in 2028, and (3) increase customer rates related to the associated incremental annual levelized revenue requirement (Bridger Recovery Mechanism). The 2025 Settlement Stipulation made modifications to the Bridger Recovery Mechanism, including updated coal-related investments through 2024, updated investment forecasts through 2028, and the inclusion of total other O&M expenses associated with operations of the Jim Bridger plant. The Bridger Recovery Mechanism 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, 2024, as well as forecasted coal-related investments.
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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.
Recovery of Incremental AFUDC Associated with HCC: In March 2025, Idaho Power filed an application with the IPUC requesting an order authorizing an increase of $29.7 million in the annual cash collection of incremental financing costs, or AFUDC, associated with relicensing of the HCC project. In September 2025, the IPUC approved Idaho Power's proposed increase in annual cash collection to recover AFUDC associated with relicensing of the HCC project, effective October 1, 2025.
Other Notable Idaho Regulatory Matters Affecting Customer Rates
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 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 2025, the IPUC issued an order approving a $39.8 million decrease in recovery from the FCA from $36.8 million to negative $3.1 million for the 2024 FCA deferral, reflecting a refund to residential and small commercial customers of the 2024 FCA deferral balance of $3.1 million, with new rates effective for the period from June 1, 2025 to May 31, 2026. Beginning with the 2026 FCA deferral, the 2025 Settlement Stipulation updated the authorized fixed-cost recovery amount per customer and per unit of energy within the FCA mechanism to support Idaho Power's proposed rate designs, as noted above.
The following table summarizes FCA amounts approved for (refund) or collection in the prior three FCA years:

FCA Year |  | Period Rates in Effect |  | Annual Amount (in millions of dollars)
2024 |  | June 1, 2025 to May 31, 2026 |  | $(3.1)
2023 |  | June 1, 2024 to May 31, 2025 |  | $36.8
2022 |  | June 1, 2023 to May 31, 2024 |  | $25.1

Wildfire Mitigation Cost Recovery: In September 2025, the IPUC granted Idaho Power's request to defer for future recovery an estimated $22.2 million of newly identified incremental O&M costs expected to be incurred in 2025 associated with expanded wildfire mitigation efforts. The IPUC also authorized the continued deferral of incremental insurance costs above the 2022 base established in the 2023 Settlement Stipulation. The 2025 Settlement Stipulation authorized Idaho Power to defer incremental O&M and insurance costs above the 2024 base through the earlier of the next general rate case or 2027. As of December 31, 2025, Idaho Power’s deferral balance of Idaho-jurisdiction costs related to the WMP was $88.2 million, of which $73.9 million is approved to be amortized and collected in Idaho rates.
Hells Canyon Complex Relicensing Costs: In December 2025, Idaho Power filed an application with the IPUC requesting a determination that Idaho Power's expenditures from January 1, 2016 through year-end 2025 on relicensing of the HCC, including approximately $305 million incurred from January 1, 2016 through September 30, 2025, were prudently incurred, and thus eligible for inclusion in retail rates in a future regulatory proceeding. As of the date of this report, the case remains pending.
Notable Oregon Regulatory Matters Affecting Customer Rates
Oregon Base Rate Changes: Oregon base rates were most recently established in a general rate case that Idaho Power filed with the OPUC in December 2023 and a separate case approved by the OPUC in December 2025 described below. In September 2024, the OPUC issued an order approving the 2024 Oregon Settlement Stipulations, which are settlement stipulations among Idaho Power and intervening parties settling the general rate case.
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The OPUC order and the 2024 Oregon Settlement Stipulations contain the following significant terms, among other items:
•Implementation of revised tariff schedules designed to increase annual Oregon-jurisdiction revenue by $6.7 million, or 12.14 percent; and
•A 9.5 percent Oregon-jurisdiction return on year-end equity and a 7.302 percent Oregon-jurisdiction authorized rate of return based on a 5.104 percent cost of debt and capital structure of 50 percent debt and 50 percent equity, applied to an Oregon-jurisdictional rate base of approximately $188.9 million. 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.
Rate changes from the 2024 Oregon Settlement Stipulations became effective on October 15, 2024. The 2024 Oregon Settlement Stipulations do not preclude Idaho Power from filing another general rate case or other limited issue proceeding in Oregon at any time in the future.
In December 2025, the OPUC issued an order approving a decrease in Oregon rates reflecting three offsetting adjustments: a decrease in rates of $1.2 million due to the removal of coal-related costs at the North Valmy plant, a decrease in rates of $0.1 million to return an outstanding regulatory liability related to the former Boardman plant, and an increase in rates of $0.7 million to recover the amortization of deferred 2023 wildfire mitigation costs. The combined result was an overall rate decrease of $0.6 million or 0.9 percent, effective January 1, 2026.
Wildfire Mitigation Cost Recovery: In December 2025, Idaho Power filed its 2026-2028 WMP with the OPUC along with an application requesting authorization to defer for future recovery an estimated $3.1 million of newly identified incremental costs expected to be incurred in 2026 associated with expanded wildfire mitigation efforts. As of the date of this report, the case remains pending. As of December 31, 2025, Idaho Power’s deferral balance of Oregon-jurisdiction costs related to the WMP was $3.5 million, of which $0.7 million is approved to be amortized and collected in Oregon rates.
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:

Period Rates in Effect |  | OATT Rate (per kW-year)
October 1, 2025 to September 30, 2026 |  | $ | 34.16 |
October 1, 2024 to September 30, 2025 |  | $ | 31.55 |
October 1, 2023 to September 30, 2024 |  | $ | 30.74 |
October 1, 2022 to September 30, 2023 |  | $ | 31.42 |

Idaho Power's current OATT rate is based on a net annual transmission revenue requirement of $148.5 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 of dollars):

|  | Year Ended December 31,
|  | 2025 |  | 2024 |  | 2023
Electric utility operating revenues: |  |  |  |  |  |
Revenue from contracts with customers |  | $ | 1,746,972 |  |  | $ | 1,768,881 |  |  | $ | 1,639,612 |
Alternative revenue programs and derivative revenues |  | 62,637 |  |  | 54,084 |  |  | 123,282 |
Total electric utility operating revenues |  | $ | 1,809,609 |  |  | $ | 1,822,965 |  |  | $ | 1,762,894 |

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Revenues from Contracts with Customers
Revenues from contracts with customers are primarily related to Idaho Power’s regulated tariff-based sales of energy or related services. Generally, tariff-based sales do not involve a written contract, but are classified as revenues from contracts with customers. Idaho Power assesses revenues on a contract-by-contract basis to determine the nature, amount, timing, and uncertainty, if any, of revenues being recognized.
The following table presents revenues from contracts with customers disaggregated by revenue source (in thousands of dollars):

|  | Year Ended December 31,
|  | 2025 |  | 2024 |  | 2023
Revenues from contracts with customers: |  |  |  |  |  |
Retail revenues: |  |  |  |  |  |
Residential (includes $3,972, $(2,686), and $37,233, respectively, related to the FCA(1)) |  | $ | 708,126 |  |  | $ | 700,586 |  |  | $ | 684,649 |
Commercial (includes $(76), $(170), and $1,338, respectively, related to the FCA(1)) |  | 394,313 |  |  | 397,385 |  |  | 378,330 |
Industrial |  | 270,571 |  |  | 267,211 |  |  | 244,538 |
Irrigation |  | 198,468 |  |  | 196,401 |  |  | 173,929 |
Deferred revenue related to HCC relicensing AFUDC(2) |  | (15,120) |  |  | (8,803) |  |  | (8,780) |
Total retail revenues |  | 1,556,358 |  |  | 1,552,780 |  |  | 1,472,666 |
Less: FCA mechanism revenues(1) |  | (3,896) |  |  | 2,856 |  |  | (38,571) |
Wholesale energy sales |  | 55,989 |  |  | 73,908 |  |  | 63,421 |
Transmission wheeling-related revenues |  | 72,231 |  |  | 79,173 |  |  | 80,357 |
Energy efficiency program revenues |  | 30,480 |  |  | 27,581 |  |  | 31,948 |
Other revenues from contracts with customers |  | 35,810 |  |  | 32,583 |  |  | 29,791 |
Total revenues from contracts with customers |  | $ | 1,746,972 |  |  | $ | 1,768,881 |  |  | $ | 1,639,612 |

(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 in its Idaho jurisdiction, even though the relicensing process is not yet complete and the costs have not been moved to utility plant in service. Effective October 1, 2025, Idaho Power began collecting $38.5 million annually. Prior to October 1, 2025, Idaho Power collected $8.8 million annually. For more information refer to Note 3 - "Regulatory Matters." Amounts collected in the Idaho jurisdiction are recognized as deferred revenue 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
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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.
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.
Wholesale Energy Sales: As a public utility under the FPA, Idaho Power has been granted 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 been granted 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, 2025, Idaho Power's energy efficiency rider balances were a $13.4 million regulatory liability in the Idaho jurisdiction and a $3.1 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 FCA mechanism, which may increase or decrease tariff-based retail customer rates. The 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 16 - "Derivative Financial Instruments."
The table below presents the FCA mechanism revenues and derivative revenues (in thousands of dollars):

|  | Year Ended December 31,
|  | 2025 |  | 2024 |  | 2023
Alternative revenue programs and derivative revenues: |  |  |  |  |  |
FCA mechanism revenues |  | $ | 3,896 |  |  | $ | (2,856) |  |  | $ | 38,571 |
Derivative revenues |  | 58,741 |  |  | 56,940 |  |  | 84,711 |
Total alternative revenue programs and derivative revenues |  | $ | 62,637 |  |  | $ | 54,084 |  |  | $ | 123,282 |

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 PURPA-qualifying hydropower generation projects.
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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):

|  | 2025 |  | 2024
First mortgage bonds: |  |  |  |
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 |
5.20% Series due 2034 |  | 300,000 |  |  | 300,000 |
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 |  |  | 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 |  |  | 62,000 |
5.50% Series due 2053 |  | 400,000 |  |  | 400,000 |
5.80% Series due 2054 |  | 350,000 |  |  | 350,000 |
5.70% Series due 2055 |  | 400,000 |  |  | — |
Total first mortgage bonds |  | 3,345,000 |  |  | 2,945,000 |
Pollution control revenue bonds: |  |  |  |
1.70% Series due 2026(1) |  | 116,300 |  |  | 116,300 |
Total pollution control revenue bonds |  | 116,300 |  |  | 116,300 |
American Falls Variable Rate bond guarantee due 2025 |  | — |  |  | 19,885 |
Unamortized premium/discount and issuance costs |  | (13,962) |  |  | (7,523) |
Total IDACORP and Idaho Power outstanding debt(2) |  | 3,447,338 |  |  | 3,073,662 |
Current maturities of long-term debt |  | (116,300) |  |  | (19,885) |
Total long-term debt |  | $ | 3,331,038 |  |  | $ | 3,053,777 |

(1) Sweetwater County Pollution Control Revenue Bonds are secured by the first mortgage bonds, bringing the total first mortgage bonds outstanding at December 31, 2025, to $3.461 billion.
(2) At December 31, 2025 and 2024, the overall effective cost rate of Idaho Power's outstanding debt was 5.13 percent and 5.03 percent, respectively.
At December 31, 2025, the maturities for the aggregate amount of IDACORP and Idaho Power long-term debt outstanding were as follows (in thousands of dollars):

| 2026 |  | 2027 |  | 2028 |  | 2029 |  | 2030 |  | Thereafter
| $ | 116,300 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | 80,000 |  |  | $ | 3,265,000 |

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Long-Term Debt Issuances, Maturities, and Redemptions
On March 13, 2025, Idaho Power issued $400 million in aggregate principal amount of 5.70% first mortgage bonds, secured medium-term notes, Series O, maturing on March 15, 2055.
On February 3, 2025, Idaho Power repaid $19.9 million in aggregate principal amount of maturing variable rate American Falls Bonds.
On December 2, 2024, Idaho Power repaid $49.8 million in aggregate principal amount of maturing 1.45% Humboldt County Pollution Control Revenue Bonds.
On August 12, 2024, Idaho Power issued $300 million in aggregate principal amount of 5.20% first mortgage bonds, secured medium-term notes, Series M, maturing on August 15, 2034.
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 February and March 2024, 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 December 31, 2026, 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 percent. At December 31, 2025, $500 million remained available for debt issuance under the regulatory orders.
In February 2025, 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 February 2025, Idaho Power entered into a selling agency agreement with seven banks named in the agreement in connection with the potential issuance and sale from time to time of up to $2.1 billion aggregate principal amount of first mortgage bonds, secured medium-term notes, Series O (Series O Notes), under the Indenture. Also in February 2025, Idaho Power entered into the Fifty-third Supplemental Indenture, dated effective as of February 26, 2025, to the Indenture (Fifty-third Supplemental Indenture). The Fifty-third Supplemental Indenture provides for, among other items, the issuance of up to $2.1 billion in aggregate principal amount of Series O Notes pursuant to the Indenture and increased the limit of the amount of first mortgage bonds at any one time outstanding to $5.5 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 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.
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.
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The Indenture 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, 2025, the maximum amount of additional first mortgage bonds Idaho Power could issue under this test was approximately $2.3 billion. The Indenture also imposes a fixed cap of $5.5 billion on the aggregate amount of first mortgage bonds that may be outstanding under the Indenture, which cap may be amended under certain conditions. As of December 31, 2025, Idaho Power could issue approximately $2.0 billion of additional first mortgage bonds based on that aggregate cap.
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, 2025:

|  | Shares issued |  | Shares reserved
|  | 2025 |  | 2024 |  | 2023 |  | December 31, 2025
Balance at January 1 |  | 53,962,300 |  | 50,615,237 |  | 50,561,892 |  |
Dividend reinvestment and stock purchase plan |  | 49,569 |  | 63,084 |  | — |  | 2,729,049
Employee savings plan |  | — |  | — |  | — |  | 3,567,954
At-the-market offering program(1) |  | 801,914 |  | — |  | — |  | See table note (1)
Equity forward sale agreements |  | — |  | 3,221,982 |  | — |  | 5,180,180
Long-term incentive and compensation plan(2) |  | 45,348 |  | 61,997 |  | 53,345 |  | 2,154,164
Continuous equity program (inactive) |  | — |  | — |  | — |  | 3,000,000
Balance at December 31 |  | 54,859,131 |  | 53,962,300 |  | 50,615,237 |  |

(1) During 2024, IDACORP reserved shares of its common stock through the ATM offering program, up to an aggregate gross sales price of $300 million. At December 31, 2025, $155.5 million in shares of IDACORP’s common stock remained reserved. For more details, see "At-the-Market Offering Program" below in this Note 6.
(2) During 2025, 2024, and 2023, IDACORP granted 82,344, 103,771, and 75,295 restricted stock unit awards, respectively, to employees and 11,268, 15,616, and 12,459 shares of common stock, respectively, to directors. During 2025, 2024, and 2023, IDACORP issued 45,348, 61,997, and 53,345 shares of common stock, respectively, using original issuances of shares pursuant to the LTICP, including 9,273, 10,571, and 13,842 shares of common stock, respectively, issued to members of the board of directors.
Dividend Reinvestment and Stock Purchase Plan: Effective January 1, 2024, IDACORP instructed the plan administrator of the IDACORP, Inc. Dividend Reinvestment and Stock Purchase Plan to use original issuance of common stock from IDACORP, as opposed to market purchases of IDACORP common stock, to acquire shares of IDACORP common stock for the plan. However, IDACORP may determine at any time to resume market purchases of common stock under the plan.
Employee Savings Plan: As directed by IDACORP, the plan administrator of the Idaho Power Company Employee Savings Plan used market purchases of IDACORP common stock to acquire shares of IDACORP common stock for the plan.
At-the-Market Offering Program: On May 20, 2024, IDACORP entered into an Equity Distribution Agreement (EDA) pursuant to which it may issue, offer, and sell, from time to time, up to an aggregate gross sales price of $300 million of shares of its common stock through an ATM offering program, which includes the ability to enter into FSAs. At December 31, 2025, $155.5 million in shares of IDACORP’s common stock remained available for issuance through its ATM offering program.
IDACORP executed FSAs under its ATM offering program with various counterparties who borrowed and sold 452,256 shares in 2025 and 801,914 shares in 2024 of IDACORP’s common stock at an aggregate gross sales price of $52.2 million in 2025 and $92.4 million in 2024. This included approximately $0.7 million in 2025 and $1.2 million in 2024 in commissions and fees payable by IDACORP to the counterparties upon settlement.
At December 31, 2025, IDACORP had the following FSAs outstanding under its ATM offering program (in thousands of dollars, except for shares and forward price amounts):
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Maturity Date |  | Shares |  | Net Proceeds Available |  | Forward Price
March 31, 2026 |  | 198,086 |  | $ | 22,789 |  | $ | 115.05
March 31, 2026 |  | 254,170 |  | 28,970 |  | 113.98
Total / Weighted Average Forward Price |  | 452,256 |  | $ | 51,759 |  | $ | 114.45

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 elects to physically settle the FSAs, IDACORP will issue shares of common stock to the various counterparties at the then-applicable forward sale price and receive issuance proceeds at that time.
At December 31, 2025, IDACORP could have settled all its outstanding FSAs under the ATM offering program with physical delivery of 452,256 shares of common stock to the counterparties in exchange for cash of $51.8 million. At December 31, 2025, IDACORP could have settled the FSAs with net delivery to various counterparties of approximately $7.2 million of cash or approximately 54,968 shares of common stock, 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.
During 2025, IDACORP settled the following FSAs under its ATM offering program (in thousands of dollars, except for settlement shares and forward settlement price amounts):

Settlement Date |  | Settlement Shares |  | Net Cash Proceeds(1) |  | Forward Settlement Price
November 12, 2025 |  | 500,000 |  | $ | 56,924 |  | $ | 113.85
December 19, 2025 |  | 301,914 |  | 34,793 |  | 115.24
Total / Weighted Average Forward Settlement Price |  | 801,914 |  | $ | 91,717 |  | $ | 114.37

(1) Settlement of the FSAs are reflected in IDACORP’s equity.
Equity Forward Sale Agreements (2025 Series): On May 8, 2025, IDACORP announced a registered public offering of 4,504,505 shares of its common stock at a public offering price of $111.00 per share, for an aggregate amount of $500.0 million. In conjunction with this offering, underwriters exercised an option to purchase 675,675 additional shares for an additional aggregate amount of $75.0 million. The 5,180,180 shares were sold by IDACORP to the underwriters 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 9, 2026. The forward sale price was initially $107.67 per share and is subject to certain adjustments in accordance with the terms of the FSAs through the date or dates of settlement.
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 elects to physically settle the FSAs, IDACORP will issue shares of common stock to the various counterparties at the then-applicable forward sale price and receive issuance proceeds at that time.
At December 31, 2025, IDACORP could have settled the FSAs with physical delivery of 5,180,180 shares of common stock to the counterparties in exchange for cash of $560.9 million. The FSAs could have also been settled at December 31, 2025, with delivery of approximately $113.8 million of cash or approximately 874,426 shares of common stock to the counterparties, 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.
Equity Forward Sale Agreements (2023 Series): 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
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3,221,982 shares were sold by the counterparty to the underwriters under FSAs. The forward sale price was initially $90.016 per share and was subject to certain adjustments in accordance with the terms of the FSAs through the date of settlement.
On May 14, 2024, IDACORP partially settled the FSAs with physical delivery of 2,542,442 shares of common stock to the counterparty in exchange for cash of $230.0 million. On November 4, 2024, IDACORP settled the remainder of the FSAs with physical delivery of 679,540 shares of common stock to the counterparty in exchange for cash of $62.2 million. Settlement of the FSAs are reflected in IDACORP’s equity.
FSA Earnings Per Shares Dilution: 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, 2025, 2024, and 2023, approximately 490,000, 47,000, and 34,000 incremental shares, respectively, were included in the calculation of diluted earnings per share related to the securities under the FSAs. See Note 8 - "Earnings Per Share" for additional information concerning IDACORP's diluted earnings per share.
Idaho Power Common Stock
During 2025 and 2024, IDACORP contributed $195 million and $200 million, respectively, of additional capital to Idaho Power. During 2025 and 2024, no additional shares of Idaho Power common stock were issued.
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 Statement of Policy and 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, 2025, the leverage ratios for IDACORP and Idaho Power were 52 percent. Based on these restrictions, IDACORP’s and Idaho Power’s dividends were limited to $1.5 billion and $1.3 billion, respectively, at December 31, 2025. 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, 2025, IDACORP and Idaho Power were in compliance with those covenants.
Idaho Power’s Statement of 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, 2025, Idaho Power's common equity capital was 48 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, 2025, the maximum number of shares available under the LTICP was 1,119,104.
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Restricted Stock Unit and Performance-Based Unit Awards
Restricted stock unit awards have three-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.
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, 2025 |  | 234,809 |  |  | $ | 94.73 |  |  | 233,577 |  |  | $ | 94.73 |
Units granted |  | 82,344 |  |  | 107.76 |  |  | 81,973 |  |  | 107.76 |
Units forfeited |  | (3,504) |  |  | 94.87 |  |  | (2,962) |  |  | 94.28 |
Units vested |  | (65,727) |  |  | 102.52 |  |  | (65,116) |  |  | 102.53 |
Nonvested units at December 31, 2025 |  | 247,922 |  |  | $ | 96.99 |  |  | 247,472 |  |  | $ | 97.00 |

The total fair value of shares vested was $7.4 million in 2025, $8.5 million in 2024, and $7.5 million in 2023. At December 31, 2025, IDACORP had $11.5 million of total unrecognized compensation cost related to nonvested share-based compensation, all of which was Idaho Power's share. These costs are expected to be recognized over a weighted-average period of 1.7 years. IDACORP uses original issue shares for these awards.
In 2025, a total of 11,268 shares were awarded to directors at an average grant date fair value of $117.98 per share. Directors elected to defer receipt of 5,532 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
|  | 2025 |  | 2024 |  | 2023 |  | 2025 |  | 2024 |  | 2023
Compensation cost |  | $ | 12,505 |  |  | $ | 11,708 |  |  | $ | 9,578 |  |  | $ | 12,419 |  |  | $ | 11,608 |  |  | $ | 9,508 |
Income tax benefit |  | 3,130 |  |  | 3,014 |  |  | 2,465 |  |  | 3,108 |  |  | 2,988 |  |  | 2,447 |

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No equity compensation costs have been capitalized. These costs are primarily reported within "Other operations and maintenance" expense on the consolidated statements of income.
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 (in thousands of dollars and shares, except for per share amounts):

|  | 2025 |  | 2024 |  | 2023
Numerator: |  |  |  |  |  |
Net income attributable to IDACORP, Inc. |  | $ | 323,472 |  |  | $ | 289,174 |  |  | $ | 261,195 |
Denominator: |  |  |  |  |  |
Weighted-average common shares outstanding - basic |  | 54,235 |  |  | 52,543 |  |  | 50,717 |
Effect of dilutive securities(1) |  | 571 |  |  | 72 |  |  | 89 |
Weighted-average common shares outstanding - diluted |  | 54,806 |  |  | 52,615 |  |  | 50,806 |
Basic earnings per share |  | $ | 5.96 |  |  | $ | 5.50 |  |  | $ | 5.15 |
Diluted earnings per share |  | $ | 5.90 |  |  | $ | 5.50 |  |  | $ | 5.14 |

(1) Includes the effect of dilutive securities related to FSAs. See Note 6 - "Common Stock" for additional information concerning IDACORP's FSAs.
9. COMMITMENTS
Purchase Obligations
At December 31, 2025, Idaho Power had the following long-term commitments relating to purchases of energy, capacity, transmission rights, and fuel (in thousands of dollars):

|  | 2026 |  | 2027 |  | 2028 |  | 2029 |  | 2030 |  | Thereafter
Cogeneration, power production, battery storage, and transmission rights |  | $ | 350,046 |  |  | $ | 383,878 |  |  | $ | 427,829 |  |  | $ | 428,270 |  |  | $ | 425,584 |  |  | $ | 3,710,029 |
Fuel |  | 191,035 |  |  | 159,806 |  |  | 96,773 |  |  | 45,314 |  |  | 46,063 |  |  | 498,929 |

As of December 31, 2025, Idaho Power had power purchase obligations with respect to 1,724 MW nameplate capacity of online PURPA and non-PURPA projects, with an additional 625 MW nameplate capacity of projects that are scheduled to be online in 2026 and 2027. The agreements for these projects have original contract terms ranging from one to 35 years. Idaho Power's purchased power expense associated with long-term agreements (including PURPA) was approximately $306 million in 2025, $294 million in 2024, and $258 million in 2023.
Subsequent to December 31, 2025, through the date of this report, Idaho Power entered into an energy and capacity market purchase agreement with an energy marketer that provides Idaho Power the right to acquire 100 MW on a daily basis during the winter months, subject to regulatory approval, which increased Idaho Power's contractual obligations by approximately $14.4 million over an approximate 3-year term commencing in November 2028.
Idaho Power also has the following long-term commitments (in thousands of dollars):

|  | 2026 |  | 2027 |  | 2028 |  | 2029 |  | 2030 |  | Thereafter
Joint-operating agreement payments(1) |  | $ | 2,983 |  |  | $ | 2,983 |  |  | $ | 2,983 |  |  | $ | 2,983 |  |  | $ | 2,983 |  |  | $ | 14,914 |
Easements and other payments(1) |  | 2,322 |  |  | 2,371 |  |  | 2,421 |  |  | 2,472 |  |  | 2,523 |  |  | 13,435 |
Maintenance, service, and materials agreements(1)(2) |  | 479,388 |  |  | 110,347 |  |  | 312,155 |  |  | 36,558 |  |  | 8,327 |  |  | 41,237 |
FERC and other industry-related fees(1) |  | 17,898 |  |  | 17,106 |  |  | 16,962 |  |  | 16,908 |  |  | 17,391 |  |  | 85,255 |

(1) Approximately $30 million, $1 million, $16 million, and $170 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, 2025, Idaho Power had a remaining $481 million commitment related to contracts to acquire and own transmission and generation resources with in-service dates in 2028 and 2030.
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At IDACORP, long-term purchase commitments of $21.4 million are mostly comprised of other long-term liabilities at Ida-West and IFS. At December 31, 2025, IDACORP had a commitment to invest an additional $2.8 million into a private market investment fund, which is expected to occur over the next few years.
Guarantees
Idaho Power guarantees its portion of reclamation activities and obligations at BCC, of which IERCo owns a one-third interest. This guarantee, which is renewed annually with the Wyoming Department of Environmental Quality (WDEQ), was $50.1 million at December 31, 2025, representing IERCo's one-third share of BCC's total reclamation obligation of $150.2 million. BCC has a reclamation trust fund set aside specifically for the purpose of paying these reclamation costs. At December 31, 2025, the value of BCC's reclamation trust fund exceeded WDEQ's guarantee requirement for the total reclamation obligation. BCC periodically assesses the adequacy of the reclamation trust fund and its estimate of future reclamation costs. To ensure that the reclamation trust fund maintains adequate reserves, BCC has the ability to, and does, add a per-ton surcharge to coal sales 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, 2025, 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. LEASES
Recognition of Lease Assets and Liabilities
A lease exists when an arrangement allows the lessee to control the use of an identified asset for a stated period in exchange for payments. Idaho Power determines if an arrangement is a lease and its classification at the lease commencement date. All leases must be recognized as a lease right-of-use (ROU) asset and a lease liability on the balance sheet of the lessee. The ROU asset represents the right to use an underlying asset for the lease term, and lease liabilities represent the obligation to make lease payments. Idaho Power has elected the practical expedient to not separate non-lease components from lease components and instead account for both as a single lease component.
Lease ROU assets and lease liabilities are estimated and recognized at the lease commencement date based on the net present value of fixed lease payments over the lease term. Variable lease payments are expensed as incurred. If the lease does not provide an implicit rate, Idaho Power uses its collateralized incremental borrowing rate based on the information available at the commencement date to determine the present value of fixed lease payments. The implicit rate is used when it is readily determinable. Idaho Power recovers 100 percent of the Idaho-jurisdiction portion of lease payments on all existing arrangements classified as finance leases through the PCA, and recovers the Oregon-jurisdiction portion of lease payments through the APCU. Idaho Power recognizes lease expenses consistent with regulatory cost recovery, so lease expenses in excess of amounts recovered through the PCA and APCU are deferred as a regulatory asset.
IDACORP does not record leases with a term of 12 months or less in the consolidated balance sheets. Total short-term lease expense was not material for the years ended 2025, 2024, and 2023.
Finance Leases
Finance leases are included in finance lease ROU assets, other current liabilities, and finance lease liabilities recognized on the consolidated balance sheets upon the lease commencement date. Amortization of the lease ROU asset is included in depreciation and amortization, and the interest expense associated with the finance lease liabilities is included in interest on long-term debt and finance leases on the consolidated statements of income. Variable lease payments are not recognized on the consolidated balance sheets and are recorded as incurred in other O&M expense on the consolidated statements of income and
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in operating activities in the consolidated statements of cash flows. Idaho Power’s finance lease ROU assets and liabilities relate to the lease discussed below.
Kuna BESS: On April 26, 2023, Idaho Power executed an Energy Storage Agreement with Kuna BESS LLC to utilize the storage capacity of a 150 MW battery storage facility over a 20-year term. The term began May 19, 2025, and has been classified as a finance lease.
The following table provides a summary of the components of total lease cost included in the consolidated statements of income for the year ended December 31 (in thousands of dollars):

|  | 2025 |  |  |  |
Finance lease cost: |  |  |  |  |  |
Amortization of ROU asset (Depreciation and amortization) |  | $ | 3,762 |  |  |  |  |
Interest on lease liabilities (Interest on long-term debt and finance leases)(1) |  | 8,586 |  |  |  |  |
Total finance lease cost |  | 12,348 |  |  |  |  |
Variable lease cost (Other O&M) |  | 973 |  |  |  |  |
Total lease cost |  | $ | 13,321 |  |  |  |  |

(1) Included in operating activities in the consolidated statements of cash flows as cash paid for amounts included in the measurement of lease liabilities.
The following table presents the classification of certain lease amounts included in the consolidated balance sheets as of December 31 (in thousands of dollars):

|  | 2025
Finance leases: |  |
Other current liabilities |  | $ | 6,161 |

The following table presents the weighted-average remaining lease term and weighted-average discount rate as of December 31:

|  | 2025
Finance leases: |  |
Weighted average remaining lease term |  | 19.38 years
Weighted average discount rate |  | 6.17 | %

The following table presents the maturities of future fixed lease payments and a reconciliation of undiscounted cash flows to lease liabilities recognized on the consolidated balance sheets as of December 31, 2025 (in thousands of dollars):
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|  | Finance Leases
2026 |  | $ | 19,751 |
2027 |  | 19,751 |
2028 |  | 19,751 |
2029 |  | 19,751 |
2030 |  | 19,751 |
Thereafter |  | 283,907 |
Total future fixed lease payments |  | 382,662 |
Less: amounts representing interest |  | (159,806) |
Total present value of lease liabilities |  | 222,856

11. CONTINGENCIES
IDACORP and Idaho Power have in the past and expect in the future to become involved in various claims, controversies, disputes, and other contingent matters, some of which involve litigation and regulatory or other contested proceedings. The ultimate resolution and outcome of litigation and regulatory proceedings is inherently difficult to determine, particularly where (a) the remedies or penalties sought are indeterminate, (b) the proceedings are in the early stages or the substantive issues have not been well developed, or (c) the matters involve complex or novel legal theories or a large number of parties. In accordance with applicable accounting guidance, IDACORP and Idaho Power, as applicable, establish an accrual for legal proceedings when those matters proceed to a stage where they present loss contingencies that are both probable and reasonably estimable. If the loss contingency at issue is not both probable and reasonably estimable, IDACORP and Idaho Power do not establish an accrual and the matter will continue to be monitored for any developments that would make the loss contingency both probable and reasonably estimable. As of the date of this report, IDACORP's and Idaho Power's accruals for loss contingencies are not material to their financial statements as a whole; however, future accruals could be material in a given period. IDACORP's and Idaho Power's determination is based on currently available information, and estimates presented in financial statements and other financial disclosures involve significant judgment and may be subject to significant uncertainty. For matters that affect Idaho Power's operations, Idaho Power intends to seek, to the extent permissible and appropriate, recovery through the ratemaking process of costs incurred, although there is no assurance that such recovery would be granted.
IDACORP and Idaho Power are parties to legal claims and legal, tax, and regulatory actions and proceedings in the ordinary course of business and, as noted above, record an accrual for associated loss contingencies when they are probable and reasonably estimable. In connection with its utility operations, Idaho Power is subject to claims by individuals, entities, and governmental agencies for damages for alleged personal injury, property damage, and economic losses, relating to the company’s provision of electric service and the operation of its 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.
12. BENEFIT PLANS
Idaho Power sponsors defined benefit and other postretirement benefit plans that cover the majority of its employees. Idaho Power also sponsors a defined contribution 401(k) employee savings plan and provides certain post-employment benefits.
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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
|  | 2025 |  | 2024 |  | 2025 |  | 2024
Change in projected benefit obligation: |  |  |  |  |  |  |  |
Benefit obligation at January 1 |  | $ | 998,166 |  |  | $ | 1,028,016 |  |  | $ | 102,318 |  |  | $ | 105,809 |
Service cost |  | 31,774 |  |  | 33,992 |  |  | 1,172 |  |  | 1,051 |
Interest cost |  | 56,151 |  |  | 52,181 |  |  | 5,640 |  |  | 5,332 |
Actuarial loss (gain) |  | 5,237 |  |  | (65,972) |  |  | 2,401 |  |  | (3,321) |
Plan amendment |  | — |  |  | — |  |  | 7 |  |  | 15 |
Benefits paid |  | (52,309) |  |  | (50,051) |  |  | (6,900) |  |  | (6,568) |
Projected benefit obligation at December 31 |  | 1,039,019 |  |  | 998,166 |  |  | 104,638 |  |  | 102,318 |
Change in plan assets: |  |  |  |  |  |  |  |
Fair value at January 1 |  | 951,142 |  |  | 917,513 |  |  | — |  |  | — |
Actual return on plan assets |  | 104,542 |  |  | 63,680 |  |  | — |  |  | — |
Employer contributions |  | 20,000 |  |  | 20,000 |  |  | — |  |  | — |
Benefits paid |  | (52,309) |  |  | (50,051) |  |  | — |  |  | — |
Fair value at December 31 |  | 1,023,375 |  |  | 951,142 |  |  | — |  |  | — |
Funded status at end of year |  | $ | (15,644) |  |  | $ | (47,024) |  |  | $ | (104,638) |  |  | $ | (102,318) |
Amounts recognized in the balance sheet consist of: |  |  |  |  |  |  |  |
Other current liabilities |  | $ | — |  |  | $ | — |  |  | $ | (6,855) |  |  | $ | (6,827) |
Noncurrent liabilities |  | (15,644) |  |  | (47,024) |  |  | (97,783) |  |  | (95,491) |
Net amount recognized |  | $ | (15,644) |  |  | $ | (47,024) |  |  | $ | (104,638) |  |  | $ | (102,318) |
Amounts recognized in AOCI consist of: |  |  |  |  |  |  |  |
Net loss |  | $ | 13,142 |  |  | $ | 43,516 |  |  | $ | 18,154 |  |  | $ | 16,442 |
Prior service cost |  | 18 |  |  | 24 |  |  | 1,780 |  |  | 1,995 |
Subtotal |  | 13,160 |  |  | 43,540 |  |  | 19,934 |  |  | 18,437 |
Less amount recorded as regulatory asset(1) |  | (13,160) |  |  | (43,540) |  |  | — |  |  | — |
Net amount recognized in AOCI |  | $ | — |  |  | $ | — |  |  | $ | 19,934 |  |  | $ | 18,437 |
Accumulated benefit obligation |  | $ | 895,190 |  |  | $ | 863,705 |  |  | $ | 99,105 |  |  | $ | 96,487 |

(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 2025 are due primarily to actual demographic experience varying from assumed for both plans, and a decrease in the assumed discount rate of the SMSP plan and partially offset by an increase in the assumed discount rates of the pension plan from December 31, 2024 to December 31, 2025. The actuarial gains reflected in the benefit obligations for the pension and SMSP plans in 2024 are due primarily to increases in the assumed discount rates of both plans from December 31, 2023 to December 31, 2024. For more information on discount rates, see “Plan Assumptions” below in this Note 12.
As a non-qualified plan, the SMSP has no plan assets. However, Idaho Power has a rabbi trust designated to provide funding for SMSP obligations. The rabbi trust holds investments in marketable securities and corporate-owned life insurance. The recorded
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value of these investments was approximately $172.1 million and $159.1 million at December 31, 2025 and 2024, 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
|  | 2025 |  | 2024 |  | 2023 |  | 2025 |  | 2024 |  | 2023
Service cost |  | $ | 31,774 |  |  | $ | 33,992 |  |  | $ | 29,843 |  |  | $ | 1,172 |  |  | $ | 1,051 |  |  | $ | 612 |
Interest cost |  | 56,151 |  |  | 52,181 |  |  | 51,277 |  |  | 5,640 |  |  | 5,332 |  |  | 5,322 |
Expected return on assets |  | (68,931) |  |  | (66,533) |  |  | (61,728) |  |  | — |  |  | — |  |  | — |
Amortization of net loss |  | — |  |  | 1,700 |  |  | — |  |  | 690 |  |  | 1,312 |  |  | 570 |
Amortization of prior service cost |  | 6 |  |  | 6 |  |  | 6 |  |  | 221 |  |  | 220 |  |  | 219 |
Net periodic pension cost |  | 19,000 |  |  | 21,346 |  |  | 19,398 |  |  | 7,723 |  |  | 7,915 |  |  | 6,723 |
Regulatory deferral of net periodic pension cost(1) |  | (18,159) |  |  | (20,425) |  |  | (18,553) |  |  | — |  |  | — |  |  | — |
Previously deferred pension cost recognized(1) |  | 35,182 |  |  | 35,182 |  |  | 17,154 |  |  | — |  |  | — |  |  | — |
Net periodic pension cost recognized for financial reporting(1)(2) |  | $ | 36,023 |  |  | $ | 36,103 |  |  | $ | 17,999 |  |  | $ | 7,723 |  |  | $ | 7,915 |  |  | $ | 6,723 |

(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 $37.8 million, $35.9 million, and $18.2 million respectively, was recognized in "Other operations and maintenance" and $6.0 million, $8.1 million, and $6.5 million respectively, was recognized in "Other income, net" on the consolidated statements of income of the companies for the twelve months ended December 31, 2025, 2024, and 2023.
The following table shows the components of other comprehensive income (loss) for the plans (in thousands of dollars):

|  | Pension Plan |  | SMSP
|  | 2025 |  | 2024 |  | 2023 |  | 2025 |  | 2024 |  | 2023
Actuarial gain (loss) during the year |  | $ | 30,374 |  |  | $ | 63,119 |  |  | $ | (25,071) |  |  | $ | (2,401) |  |  | $ | 3,320 |  |  | $ | (6,517) |
Plan amendment service cost |  | — |  |  | — |  |  | — |  |  | (7) |  |  | (15) |  |  | (11) |
Reclassification adjustments for: |  |  |  |  |  |  |  |  |  |  |  |
Amortization of net loss |  | — |  |  | 1,700 |  |  | — |  |  | 690 |  |  | 1,312 |  |  | 570 |
Amortization of prior service cost |  | 6 |  |  | 6 |  |  | 6 |  |  | 221 |  |  | 220 |  |  | 219 |
Adjustment for deferred tax effects |  | (7,604) |  |  | (16,686) |  |  | 6,452 |  |  | 145 |  |  | (1,245) |  |  | 1,477 |
Adjustment due to the effects of regulation |  | (22,776) |  |  | (48,139) |  |  | 18,613 |  |  | — |  |  | — |  |  | — |
Other comprehensive income (loss) recognized related to pension benefit plans |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | (1,352) |  |  | $ | 3,592 |  |  | $ | (4,262) |

The following table summarizes the expected future benefit payments of these plans (in thousands of dollars):

|  | 2026 |  | 2027 |  | 2028 |  | 2029 |  | 2030 |  | 2031-2035
Pension Plan |  | $ | 53,000 |  |  | $ | 54,713 |  |  | $ | 56,371 |  |  | $ | 58,110 |  |  | $ | 59,898 |  |  | $ | 331,936 |
SMSP |  | 6,855 |  |  | 6,883 |  |  | 7,079 |  |  | 7,360 |  |  | 7,438 |  |  | 37,939 |

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 2025, 2024, and 2023, 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 2026. Depending on market conditions and cash flow considerations in 2025, Idaho Power expects that it may contribute up to $30 million to the pension plan during 2026 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):

|  | 2025 |  | 2024
Change in accumulated benefit obligation: |  |  |  |
Benefit obligation at January 1 |  | $ | 54,604 |  |  | $ | 56,064 |
Service cost |  | 672 |  |  | 698 |
Interest cost |  | 2,973 |  |  | 2,824 |
Actuarial loss (gain) |  | 1,976 |  |  | (778) |
Benefits paid(1) |  | (4,714) |  |  | (4,204) |
Benefit obligation at December 31 |  | 55,511 |  |  | 54,604 |
Change in plan assets: |  |  |  |
Fair value of plan assets at January 1 |  | 31,128 |  |  | 31,804 |
Actual return on plan assets |  | 4,381 |  |  | 4,669 |
Employer contributions(1) |  | 736 |  |  | (1,141) |
Benefits paid(1) |  | (4,714) |  |  | (4,204) |
Fair value of plan assets at December 31 |  | 31,531 |  |  | 31,128 |
Funded status at end of year (included in noncurrent liabilities) |  | $ | (23,980) |  |  | $ | (23,476) |

(1) Contributions and benefits paid are each net of $2.3 million and $2.3 million of plan participant contributions for 2025 and 2024, respectively.
Amounts recognized in AOCI consist of the following (in thousands of dollars):

|  | 2025 |  | 2024
Net gain |  | $ | (28,207) |  |  | $ | (29,353) |
Prior service cost |  | 3,262 |  |  | 4,636 |
Subtotal |  | (24,945) |  |  | (24,717) |
Less amount recognized in regulatory assets |  | 24,945 |  |  | 24,717 |
Net amount recognized in AOCI |  | $ | — |  |  | $ | — |

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

|  | 2025 |  | 2024 |  | 2023
Service cost |  | $ | 672 |  |  | $ | 698 |  |  | $ | 658 |
Interest cost |  | 2,973 |  |  | 2,824 |  |  | 2,980 |
Expected return on plan assets |  | (1,786) |  |  | (1,831) |  |  | (1,650) |
Amortization of net loss |  | (1,765) |  |  | (1,494) |  |  | (1,237) |
Amortization of prior service cost |  | 1,374 |  |  | 1,548 |  |  | 1,665 |
Net periodic postretirement benefit cost |  | $ | 1,468 |  |  | $ | 1,745 |  |  | $ | 2,416 |

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The following table shows the components of other comprehensive income for the plan (in thousands of dollars):

|  | 2025 |  | 2024 |  | 2023
Actuarial gain during the year |  | $ | 619 |  |  | $ | 3,616 |  |  | $ | 7,572 |
Reclassification adjustments for: |  |  |  |  |  |
Amortization of net loss |  | (1,765) |  |  | (1,494) |  |  | (1,237) |
Amortization of prior service cost |  | 1,375 |  |  | 1,548 |  |  | 1,665 |
Adjustment for deferred tax effects |  | (57) |  |  | (945) |  |  | (2,059) |
Adjustment due to the effects of regulation |  | (172) |  |  | (2,725) |  |  | (5,941) |
Other comprehensive income related to postretirement benefit plans |  | $ | — |  |  | $ | — |  |  | $ | — |

The following table summarizes the expected future benefit payments of the postretirement benefit plan (in thousands of dollars):

|  | 2026 |  | 2027 |  | 2028 |  | 2029 |  | 2030 |  | 2031-2035
Expected benefit payments |  | $ | 4,855 |  |  | $ | 4,715 |  |  | $ | 4,620 |  |  | $ | 4,580 |  |  | $ | 4,511 |  |  | $ | 21,157 |

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
|  | 2025 |  | 2024 |  | 2025 |  | 2024 |  | 2025 |  | 2024
Discount rate |  | 5.75 | % |  | 5.70 | % |  | 5.65 | % |  | 5.70 | % |  | 5.60 | % |  | 5.70 | %
Rate of compensation increase(1) |  | 4.42 | % |  | 4.43 | % |  | 4.75 | % |  | 4.75 | % |  | — |  |  | — |
Medical trend rate |  | — |  |  | — |  |  | — |  |  | — |  |  | 7.0 | % |  | 6.3 | %
Dental trend rate |  | — |  |  | — |  |  | — |  |  | — |  |  | 4.0 | % |  | 3.5 | %
Measurement date |  | 12/31/2025 |  | 12/31/2024 |  | 12/31/2025 |  | 12/31/2024 |  | 12/31/2025 |  | 12/31/2024

(1) The 2025 rate of compensation increase assumption for the pension plan includes an inflation component of 2.40% plus a 2.02% 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
|  | 2025 |  | 2024 |  | 2023 |  | 2025 |  | 2024 |  | 2023 |  | 2025 |  | 2024 |  | 2023
Discount rate |  | 5.70 | % |  | 5.10 | % |  | 5.45 | % |  | 5.70 | % |  | 5.20 | % |  | 5.50 | % |  | 5.70 | % |  | 5.15 | % |  | 5.45 | %
Expected long-term rate of return on assets |  | 7.40 | % |  | 7.40 | % |  | 7.40 | % |  | — |  |  | — |  |  | — |  |  | 6.00 | % |  | 6.00 | % |  | 6.00 | %
Rate of compensation increase |  | 4.42 | % |  | 4.43 | % |  | 4.49 | % |  | 4.75 | % |  | 4.75 | % |  | 4.75 | % |  | — |  |  | — | % |  | — | %
Medical trend rate |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 6.2 | % |  | 7.1 | % |  | 6.7 | %
Dental trend rate |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 4.0 | % |  | 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 6.2 percent in 2025 and is assumed to increase to 7.0 percent in 2026, decrease to 6.2 percent in 2027, decrease to 5.5 percent in 2028, and to gradually decrease to 3.8 percent by 2074. For 2025 and beyond, the assumed dental cost trend rate used to measure the expected cost of dental benefits covered by the plan was 4.0 percent, or equal to the medical trend rate if lower.
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Plan Assets
Pension Asset Allocation Policy: The target allocation and actual allocations at December 31, 2025, for the pension asset portfolio by asset class is set forth below:

Asset Class |  | Target Allocation |  | Actual Allocation December 31, 2025
Debt securities |  | 25 | % |  | 25 | %
Equity securities |  | 56 | % |  | 59 | %
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, private real estate funds, private infrastructure funds, private direct lending funds, private equity funds, and cash and cash equivalents. With the exception of private 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 17 - "Fair Value Measurements." The following table presents the fair value of the plans' investments by asset category (in thousands of dollars).

|  | Level 1 |  | Level 2 |  | Level 3 |  | Total
Assets at December 31, 2025 |  |  |  |  |  |  |  |
Cash and cash equivalents |  | $ | 11,625 |  |  | $ | — |  |  | $ | — |  |  | $ | 11,625 |
Intermediate bonds |  | 42,326 |  |  | 204,129 |  |  | — |  |  | 246,455 |
Equity Securities: Large-Cap |  | 54,168 |  |  | — |  |  | — |  |  | 54,168 |
Equity Securities: Mid-Cap |  | 106,437 |  |  | — |  |  | — |  |  | 106,437 |
Equity Securities: Small-Cap |  | 85,047 |  |  | — |  |  | — |  |  | 85,047 |
Equity Securities: Micro-Cap |  | 43,752 |  |  | — |  |  | — |  |  | 43,752 |
Equity Securities: Global and International |  | 63,998 |  |  | — |  |  | — |  |  | 63,998 |
Equity Securities: Emerging Markets |  | 3,433 |  |  | — |  |  | — |  |  | 3,433 |
Plan assets measured at NAV (not subject to hierarchy disclosure) |  |  |  |  |  |  |  |
Commingled Fund: Equity Securities: Large-Cap |  |  |  |  |  |  |  | 52,830 |
Commingled Fund: Equity Securities: Global and International |  |  |  |  |  |  |  | 146,047 |
Commingled Fund: Equity Securities: Emerging Markets |  |  |  |  |  |  |  | 52,305 |
Direct Lending Fund: Fixed Income |  |  |  |  |  |  |  | 8,377 |
Real estate |  |  |  |  |  |  |  | 77,141 |
Other Private market investments |  |  |  |  |  |  |  | 71,760 |
Total |  | $ | 410,786 |  |  | $ | 204,129 |  |  | $ | — |  |  | $ | 1,023,375 |
Postretirement plan assets(1) |  | $ | 1,224 |  |  | $ | 30,307 |  |  | $ | — |  |  | $ | 31,531 |

|  | Level 1 |  | Level 2 |  | Level 3 |  | Total
Assets at December 31, 2024 |  |  |  |  |  |  |  |
Cash and cash equivalents |  | $ | 24,946 |  |  | $ | — |  |  | $ | — |  |  | $ | 24,946 |
Intermediate bonds |  | 40,177 |  |  | 184,528 |  |  | — |  |  | 224,705 |
Equity Securities: Large-Cap |  | 49,848 |  |  | — |  |  | — |  |  | 49,848 |
Equity Securities: Mid-Cap |  | 103,117 |  |  | — |  |  | — |  |  | 103,117 |
Equity Securities: Small-Cap |  | 82,932 |  |  | — |  |  | — |  |  | 82,932 |
Equity Securities: Micro-Cap |  | 38,871 |  |  | — |  |  | — |  |  | 38,871 |
Equity Securities: Global and International |  | 58,767 |  |  | — |  |  | — |  |  | 58,767 |
Equity Securities: Emerging Markets |  | 6,093 |  |  | — |  |  | — |  |  | 6,093 |
Plan assets measured at NAV (not subject to hierarchy disclosure) |  |  |  |  |  |  |  |
Commingled Fund: Equity Securities: Large-Cap |  |  |  |  |  |  |  | 54,346 |
Commingled Fund: Equity Securities: Global and International |  |  |  |  |  |  |  | 124,559 |
Commingled Fund: Equity Securities: Emerging Markets |  |  |  |  |  |  |  | 41,590 |
Direct Lending Fund: Fixed Income |  |  |  |  |  |  |  | 5,479 |
Real estate |  |  |  |  |  |  |  | 72,913 |
Other Private market investments |  |  |  |  |  |  |  | 62,976 |
Total |  | $ | 404,751 |  |  | $ | 184,528 |  |  | $ | — |  |  | $ | 951,142 |
Postretirement plan assets(1) |  | $ | 3,054 |  |  | $ | 28,074 |  |  | $ | — |  |  | $ | 31,128 |

(1) The postretirement benefits assets are primarily life insurance contracts.
For the years ended December 31, 2025 and 2024, there were no material transfers into or out of Levels 1, 2, or 3.
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Fair Value Measurement of Level 2 Plan assets and Plan assets measured at NAV:
Level 2 Bonds: These investments represent United States government, agency bonds, and corporate bonds. The United States government and agency bonds, as well as the corporate bonds, are not traded on an exchange and are valued utilizing market prices for similar assets or liabilities in active markets.
Level 2 Postretirement Asset: This asset represents an investment in a life insurance contract and is recorded at fair value, which is the cash surrender value, less any unpaid expenses. The cash surrender value of this insurance contract is contractually 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 1 to 15 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.
Other Private Market Investments: Private market investments represent three categories: venture capital funds, private infrastructure 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 private infrastructure fund investment is valued by the fund manager through a process involving an independent third-party external valuator on a quarterly basis, with each investment undergoing a full independent valuation at least once per year. Redemption on the infrastructure fund are available on a quarterly basis beginning in April of 2027 with 90
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days written notice. If the fund has sufficient liquidity, the redemption will be processed at the fund NAV 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. 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 $10.9 million, $10.4 million, and $9.8 million in 2025, 2024, and 2023, respectively.
Post-employment Benefits
Idaho Power provides certain benefits to former or inactive employees, their beneficiaries, and covered dependents after employment but before retirement, in addition to the health care benefits required under the Consolidated Omnibus Budget Reconciliation Act. These benefits include salary continuation, health care and life insurance for those employees found to be disabled under Idaho Power’s disability plans, and health care for surviving spouses and dependents. Idaho Power accrues a 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, 2025 and 2024, were approximately $1 million and $3 million.
13. PROPERTY, PLANT AND EQUIPMENT AND JOINTLY-OWNED PROJECTS
The following table presents the major classifications of Idaho Power’s utility plant in service, annual depreciation provisions as a percent of average depreciable balance, and accumulated provision for depreciation for the years ended December 31 (in thousands of dollars):

|  | 2025 |  | 2024
|  | Balance |  | Avg Rate |  | Balance |  | Avg Rate
Production |  | $ | 2,675,671 |  |  | 4.02 | % |  | $ | 2,858,678 |  |  | 3.90 | %
Transmission |  | 1,653,490 |  |  | 1.91 | % |  | 1,534,474 |  |  | 1.89 | %
Energy Storage(1) |  | 509,740 |  |  | 5.06 | % |  | 393,012 |  |  | 3.61 | %
Distribution(1) |  | 2,658,849 |  |  | 2.17 | % |  | 2,465,423 |  |  | 2.16 | %
General and Other |  | 751,356 |  |  | 5.27 | % |  | 706,176 |  |  | 5.18 | %
Total in service |  | 8,249,106 |  |  | 3.18 | % |  | 7,957,763 |  |  | 3.06 | %
Accumulated provision for depreciation |  | (2,599,465) |  |  |  |  | (2,714,706) |  |  |
In service - net |  | $ | 5,649,641 |  |  |  |  | $ | 5,243,057 |  |  |

(1) The presentation of the major classifications of Idaho Power's utility plant in service in the table above has been modified to separately report the energy storage balance for the years ended December 31, 2025 and 2024. The prior year energy storage balance, which had previously been classified in the distribution balance, has been reclassified to conform with the current year presentation. This change reflects a shift from one acceptable presentation to another to enhance transparency.
At December 31, 2025, Idaho Power's construction work in progress balance of $1.7 billion included relicensing costs of $536.1 million for the HCC, Idaho Power's largest hydropower complex. The IPUC allows Idaho Power to collect a portion of AFUDC relating to the HCC relicensing project in its Idaho jurisdiction rates. For more information, refer to Note 3 - "Regulatory Matters." 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, 2025, Idaho Power's regulatory liability for collection of AFUDC relating to the HCC was $281.0 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
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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, 2025 (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 |  | $ | 777,096 |  |  | $ | 780 |  |  | $ | 575,151 |  |  | 33 |  | 775
North Valmy units 1 & 2(2) |  | Winnemucca, NV |  | 42,113 |  |  | 21,118 |  |  | (128) |  |  | 50 |  | 284

(1) Idaho Power’s share of nameplate capacity.
(2) Pursuant to an agreement with NV Energy, Idaho Power ceased participation in coal-fired operations of North Valmy in December 2019 at unit 1 and December 2025 at unit 2. Idaho Power's 2025 IRP identified a preferred resource portfolio and action plan that includes the conversion of the two generating units at the North Valmy plant from coal to natural gas by mid-2026. The conversion of Unit 1 has been completed and the unit was placed in-service in December 2025, and conversion of Unit 2 is expected to be completed by mid-2026.
IERCo, Idaho Power’s wholly-owned subsidiary, is a joint-owner of BCC. Idaho Power’s coal purchases from BCC were $54.4 million in 2025, $51.6 million in 2024, and $67.9 million in 2023.
14. ASSET RETIREMENT OBLIGATIONS (ARO)
The guidance relating to accounting for AROs requires that legal obligations associated with the retirement of property, plant, and equipment be recognized as a liability at fair value when incurred and when a reasonable estimate of the fair value of the liability can be made. Under the guidance, when a liability is initially recorded, the entity increases the carrying amount of the related long-lived asset to reflect the future retirement cost. Over time, the liability is accreted to its estimated settlement value and paid, and the capitalized cost is depreciated over the useful life of the related asset. If, at the end of the asset’s life, the recorded liability differs from the actual obligations paid, a gain or loss would be recognized. As a rate-regulated entity, Idaho Power 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 thermal generation facilities. In 2025, changes in estimates at the jointly-owned thermal generation facilities resulted in a net increase of $21.6 million in the recorded AROs. The increase is primarily related to updated post-closure cost estimates for a flue gas desulfurization pond at the Jim Bridger plant which was retired in December 2025.
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, 2025 and 2024.
The following table presents the changes in the carrying amount of AROs (in thousands of dollars):

|  | 2025 |  | 2024
Balance at January 1 |  | $ | 51,126 |  |  | $ | 48,997 |
Accretion expense |  | 2,457 |  |  | 1,895 |
Revisions in estimated cash flows |  | 21,642 |  |  | 842 |
Liability settled |  | (1,249) |  |  | (608) |
Balance at December 31 |  | $ | 73,976 |  |  | $ | 51,126 |

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15. INVESTMENTS
The table below summarizes IDACORP’s and Idaho Power’s investments as of December 31 (in thousands of dollars):

|  | 2025 |  | 2024
Idaho Power investments: |  |  |  |
BCC (equity method investment) |  | $ | 16,833 |  |  | $ | 20,998 |
Exchange traded short-term bond funds and cash equivalents |  | 37,232 |  |  | 38,873 |
Held-to-maturity securities |  | 33,822 |  |  | 32,151 |
Executive deferred compensation plan investments |  | 1,216 |  |  | 899 |
Total Idaho Power investments |  | 89,103 |  |  | 92,921 |
IFS investments in real estate tax credit projects, such as affordable housing developments |  | 50,422 |  |  | 54,654 |
Ida-West joint ventures (equity method investments) |  | 9,529 |  |  | 9,666 |
Other investments |  | 5,948 |  |  | 4,099 |
Total IDACORP investments |  | $ | 155,002 |  |  | $ | 161,340 |

Equity Method Investments
Idaho Power, through its subsidiary IERCo, is a 33 percent owner of BCC. Ida-West, through separate subsidiaries, owns 50 percent of three electric generation projects that are accounted for using the equity method: South Forks Joint Venture, Hazelton/Wilson Joint Venture, and Snow Mountain Hydro LLC. All projects are reviewed periodically for impairment. The table below presents IDACORP’s and Idaho Power’s earnings of unconsolidated equity-method investments (in thousands of dollars):

|  | 2025 |  | 2024 |  | 2023
BCC (Idaho Power) |  | $ | 2,984 |  |  | $ | 2,671 |  |  | $ | 10,540 |
Ida-West joint ventures |  | 1,938 |  |  | 1,868 |  |  | 1,886 |
Total |  | $ | 4,922 |  |  | $ | 4,539 |  |  | $ | 12,426 |

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, 2025 and 2024. There were no gross realized gains or losses from the sale of equity securities in 2025, 2024, and 2023.
Held-to-Maturity Securities
Idaho Power has a rabbi trust designated to provide funding for obligations related to the SMSP. During 2025 and 2024, the rabbi trust purchased $2.9 million and $1.8 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 2025 and 2024, all held-to-maturity securities were in a gross unrealized holding loss position totaling $1.4 million and $2.7 million at December 31, 2025 and 2024, 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, 2025 and 2024.
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
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qualified real estate projects using the proportional amortization method and recognizes the net investment performance in the consolidated statements of income as a component of income tax expense.
16. DERIVATIVE FINANCIAL INSTRUMENTS
Commodity Price Risk
Idaho Power is exposed to market risk relating to electricity, natural gas, and other fuel commodity prices, all of which are heavily influenced by supply and demand. Market risk may be influenced by market participants’ nonperformance of their contractual obligations and commitments, which affects the supply of or demand for the commodity. Idaho Power uses derivative instruments, such as physical and financial forward contracts, for both electricity and fuel to manage the risks relating to these commodity price exposures. The primary objectives of Idaho Power’s energy purchase and sale activity are to meet the demand of retail electric customers, maintain appropriate physical reserves to ensure reliability, and make economic use of temporary surpluses that may develop.
All of Idaho Power's derivative instruments have been entered into for the purpose of securing energy resources for future periods or economically hedging forecasted purchases and sales, though none of these instruments have been designated as cash flow hedges. Idaho Power offsets fair value amounts recognized on its balance sheet and applies collateral related to derivative instruments executed with the same counterparty under the same master netting agreement. Idaho Power does not offset a counterparty's current derivative contracts with the counterparty's long-term derivative contracts, although Idaho Power's master netting arrangements would allow current and long-term positions to be offset in the event of default. Also, in the event of default, Idaho Power's master netting arrangements would allow for the offsetting of all transactions executed under the master netting arrangement. These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, receivables and payables arising from settled positions, and other forms of non-cash collateral (such as letters of credit). These types of transactions are excluded from the offsetting presented in the derivative fair value and offsetting table that follows.
The table below presents the gains and losses on derivatives not designated as hedging instruments for the years ended December 31 (in thousands of dollars):

|  | Location of Realized Gain/(Loss) on Derivatives Recognized in Income |  | Gain/(Loss) on Derivatives Recognized in Income(1)
|  |  | 2025 |  | 2024 |  | 2023
Financial swaps |  | Operating revenues |  | $ | 559 |  |  | $ | 5,189 |  |  | $ | 4,216 |
Financial swaps |  | Purchased power |  | (3,967) |  |  | (7,101) |  |  | (8,542) |
Financial swaps |  | Fuel expense |  | (37,659) |  |  | (63,380) |  |  | (16,209) |
Forward contracts |  | Operating revenues |  | 917 |  |  | 1,885 |  |  | 2,280 |
Forward contracts |  | Purchased power |  | (1,017) |  |  | (3,742) |  |  | (4,035) |
Forward contracts |  | Fuel expense |  | (1,457) |  |  | (2,510) |  |  | (866) |

(1) Excludes unrealized gains or losses on derivatives, which are recorded on the balance sheet as regulatory assets or regulatory liabilities.
Settlement gains and losses on electricity swap contracts are recorded on the income statement in operating revenues or purchased power depending on the forecasted position being economically hedged by the derivative contract. Settlement gains and losses on contracts for natural gas are reflected in fuel expense. Settlement gains and losses on diesel derivatives are recorded in other O&M expense. See Note 17 - "Fair Value Measurements" for additional information concerning the determination of fair value for Idaho Power’s assets and liabilities from price risk management activities.
Credit Risk
At December 31, 2025, 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, bonds, 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.
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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, 2025, was $55.8 million. As of December 31, 2025, Idaho Power posted $45.1 million of cash collateral related to this amount. If the credit-risk-related contingent features underlying these agreements were triggered on December 31, 2025, Idaho Power would have been required to pay or post collateral to its counterparties up to an additional $34.0 million to cover open liability positions as well as completed transactions that have not yet been paid.
Derivative Instrument Summary
The table below presents the fair values and locations of derivative instruments not designated as hedging instruments recorded on the balance sheets and reconciles the gross amounts of derivatives recognized as assets and as liabilities to the net amounts presented in the balance sheets (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, 2025 |  |  |  |  |  |  |  |  |  |  |  |  |  |
Current: |  |  |  |  |  |  |  |  |  |  |  |  |  |
Financial swaps |  | Other current liabilities |  | 2,535 |  |  | (2,535) |  |  | — |  |  | 34,486 |  |  | (29,394) |  | (1) | 5,092 |
Forward contracts |  | Other current assets |  | 3 |  |  | — |  |  | 3 |  |  | — |  |  | — |  |  | — |
Forward contracts |  | Other current liabilities |  | — |  |  | — |  |  | — |  |  | 1,009 |  |  | — |  |  | 1,009 |
Long-term: |  |  |  |  |  |  |  |  |  |  |  |  |  |
Financial swaps |  | Other liabilities |  | 1,444 |  |  | (1,444) |  |  | — |  |  | 7,479 |  |  | (4,385) |  | (2) | 3,094 |
Forward contracts |  | Other liabilities |  | — |  |  | — |  |  | — |  |  | 10,524 |  |  | — |  |  | 10,524 |
Total |  |  |  | $ | 3,982 |  |  | $ | (3,979) |  |  | $ | 3 |  |  | $ | 53,498 |  |  | $ | (33,779) |  |  | $ | 19,719 |
December 31, 2024 |  |  |  |  |  |  |  |  |  |  |  |  |  |
Current: |  |  |  |  |  |  |  |  |  |  |  |  |  |
Financial swaps |  | Other current liabilities |  | 3,072 |  |  | (3,072) |  |  | — |  |  | 18,092 |  |  | (14,931) |  | (3) | 3,161 |
Forward contracts |  | Other current liabilities |  | — |  |  | — |  |  | — |  |  | 1,291 |  |  | — |  |  | 1,291 |
Long-term: |  |  |  |  |  |  |  |  |  |  |  |  |  |
Financial swaps |  | Other assets |  | 1,939 |  |  | (1,939) |  | (4) | — |  |  | 409 |  |  | (409) |  |  | — |
Financial swaps |  | Other liabilities |  | 177 |  |  | (177) |  |  | — |  |  | 1,019 |  |  | (177) |  |  | 842 |
Forward contracts |  | Other liabilities |  | — |  |  | — |  |  | — |  |  | 10,965 |  |  | — |  |  | 10,965 |
Total |  |  |  | $ | 5,188 |  |  | $ | (5,188) |  |  | $ | — |  |  | $ | 31,776 |  |  | $ | (15,517) |  |  | $ | 16,259 |

(1) Current liability derivative amounts offset include $26.9 million of collateral receivable at December 31, 2025.
(2) Long-term liability derivative amounts offset include $2.9 million of collateral receivable at December 31, 2025.
(3) Current liability derivative amounts offset include $11.9 million of collateral receivable at December 31, 2024.
(4) Long-term asset derivative amounts offset include $1.5 million of collateral payable at December 31, 2024.
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The table below presents the volumes of derivative commodity forward contracts and swaps outstanding at December 31 (in thousands of units):

Commodity |  | Units |  | 2025 |  | 2024
Electricity purchases |  | MWh |  | 200 |  |  | 161 |
Electricity sales |  | MWh |  | 33 |  |  | 16 |
Natural gas purchases |  | MMBtu |  | 131,863 |  |  | 88,330 |

17. FAIR VALUE MEASUREMENTS
IDACORP and Idaho Power have categorized their financial instruments into a three-level fair value hierarchy, based on the priority of the inputs to the valuation technique. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). If the inputs used to measure the financial instruments fall within different levels of the hierarchy, the categorization is based on the lowest level input that is significant to the fair value measurement of the instrument.
Financial assets and liabilities recorded on the consolidated balance sheets are categorized based on the inputs to the valuation techniques as follows:
• Level 1: Financial assets and liabilities whose values are based on unadjusted quoted prices for identical assets or liabilities in an active market that IDACORP and Idaho Power have the ability to access.
• Level 2: Financial assets and liabilities whose values are based on the following:
a) quoted prices for similar assets or liabilities in active markets;
b) quoted prices for identical or similar assets or liabilities in non-active markets;
c) pricing models whose inputs are observable for substantially the full term of the asset or liability; and
d) pricing models whose inputs are derived principally from or corroborated by observable market data through correlation or other means for substantially the full term of the asset or liability.
IDACORP and Idaho Power Level 2 inputs for derivative instruments are based on quoted market prices adjusted for location using corroborated, observable market data 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, 2025 and 2024.
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.
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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 (in thousands of dollars):

|  | 2025 |  | 2024
|  | Level 1 |  | Level 2 |  | Level 3 |  | Total |  | Level 1 |  | Level 2 |  | Level 3 |  | Total
Assets: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Money market funds and commercial paper |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
IDACORP(1) |  | $ | 62,012 |  |  | $ | — |  |  | $ | — |  |  | $ | 62,012 |  |  | $ | 146,308 |  |  | $ | — |  |  | $ | — |  |  | $ | 146,308 |
Idaho Power |  | 110,602 |  |  | — |  |  | — |  |  | 110,602 |  |  | 158,999 |  |  | — |  |  | — |  |  | 158,999 |
Derivatives |  | — |  |  | 3 |  |  | — |  |  | 3 |  |  | — |  |  | — |  |  | — |  |  | — |
Equity securities |  | 38,448 |  |  | — |  |  | — |  |  | 38,448 |  |  | 39,772 |  |  | — |  |  | — |  |  | 39,772 |
IDACORP assets measured at NAV (not subject to hierarchy disclosure)(1) |  | — |  |  | — |  |  | — |  |  | 5,948 |  |  | — |  |  | — |  |  | — |  |  | 4,099 |
Liabilities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Derivatives |  | $ | 8,186 |  |  | $ | 11,533 |  |  | $ | — |  |  | $ | 19,719 |  |  | $ | 4,003 |  |  | $ | 12,256 |  |  | $ | — |  |  | $ | 16,259 |

(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.
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, using available market information and appropriate valuation methodologies (in thousands of dollars).

|  | 2025 |  | 2024
|  | Carrying Amount |  | Estimated Fair Value |  | Carrying Amount |  | Estimated Fair Value
IDACORP |  |  |  |  |  |  |  |
Assets: |  |  |  |  |  |  |  |
Notes receivable(1) |  | $ | 1,507 |  |  | $ | 1,507 |  |  | $ | 2,155 |  |  | $ | 2,155 |
Held-to-maturity securities(1) |  | 33,822 |  |  | 32,468 |  |  | 32,151 |  |  | 29,428 |
Liabilities: |  |  |  |  |  |  |  |
Long-term debt (including current portion)(1) |  | 3,447,338 |  |  | 3,270,200 |  |  | 3,073,662 |  |  | 2,807,803 |
Idaho Power |  |  |  |  |  |  |  |
Assets: |  |  |  |  |  |  |  |
Held-to-maturity securities(1) |  | $ | 33,822 |  |  | $ | 32,468 |  |  | $ | 32,151 |  |  | $ | 29,428 |
Liabilities: |  |  |  |  |  |  |  |
Long-term debt (including current portion)(1) |  | 3,447,338 |  |  | 3,270,200 |  |  | 3,073,662 |  |  | 2,807,803 |

(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 17 - "Fair Value Measurements."
Notes receivable are related to Ida-West and are valued based on unobservable inputs, including forecasted cash flows, which are partially based on expected hydropower conditions. 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.
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18. SEGMENT INFORMATION
IDACORP’s only reportable segment is utility operations. The utility operations segment’s primary source of revenue is the regulated operations of Idaho Power. Idaho Power’s regulated operations include the generation, transmission, distribution, purchase, and sale of electricity. This segment also includes income from IERCo, a wholly-owned subsidiary of Idaho Power that is also subject to regulation and is a one-third owner of BCC, an unconsolidated 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.
The President and Chief Executive Officer of IDACORP and Idaho Power is the companies' chief operating decision maker (CODM). The CODM uses net income, compared with historical results and forecasted expectations, to monitor the utility segment's results, monitor and plan utility-specific regulatory strategy, allocate capital investments, and inform financing decisions.
The CODM is regularly provided with segment expense information for utility operations at the same level of detail as presented in Idaho Power's consolidated statements of income.
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 of dollars):

|  | Utility Operations |  | All Other |  | Eliminations |  | Consolidated Total
2025 |  |  |  |  |  |  |  |
Revenues |  | $ | 1,809,609 |  |  | $ | 3,388 |  |  | $ | — |  |  | $ | 1,812,997 |
Depreciation and amortization |  | 251,072 |  |  | — |  |  | — |  |  | 251,072 |
Operating income |  | 355,417 |  |  | (1,441) |  |  | — |  |  | 353,976 |
Other income, net |  | 76,700 |  |  | (184) |  |  | — |  |  | 76,516 |
Interest income, including carrying charges on regulatory assets |  | 35,337 |  |  | 10,829 |  |  | (2,971) |  |  | 43,195 |
Equity-method income |  | 2,984 |  |  | 1,938 |  |  | — |  |  | 4,922 |
Interest expense |  | 167,753 |  |  | 3,409 |  |  | (2,971) |  |  | 168,191 |
Income before income taxes |  | 302,685 |  |  | 7,733 |  |  | — |  |  | 310,418 |
Income tax benefit |  | (13,177) |  |  | (538) |  |  | — |  |  | (13,715) |
Net Income attributable to IDACORP, Inc. |  | 315,862 |  |  | 7,610 |  |  | — |  |  | 323,472 |
Total assets |  | 10,036,896 |  |  | 261,518 |  |  | (72,977) |  |  | 10,225,437 |
Expenditures for long-lived assets |  | 1,178,990 |  |  | 337 |  |  | — |  |  | 1,179,327 |

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2024 |  |  |  |  |  |  |  |
Revenues |  | $ | 1,822,965 |  |  | $ | 3,668 |  |  | $ | — |  |  | $ | 1,826,633 |
Depreciation and amortization |  | 223,410 |  |  | — |  |  | — |  |  | 223,410 |
Operating income |  | 328,183 |  |  | (344) |  |  | — |  |  | 327,839 |
Other income, net |  | 64,309 |  |  | (303) |  |  | — |  |  | 64,006 |
Interest income, including carrying charges on regulatory assets |  | 38,639 |  |  | 9,090 |  |  | (3,244) |  |  | 44,485 |
Equity-method income |  | 2,671 |  |  | 1,868 |  |  | — |  |  | 4,539 |
Interest expense |  | 135,516 |  |  | 3,593 |  |  | (3,244) |  |  | 135,865 |
Income before income taxes |  | 298,286 |  |  | 6,718 |  |  | — |  |  | 305,004 |
Income tax expense (benefit) |  | 17,681 |  |  | (2,628) |  |  | — |  |  | 15,053 |
Net Income attributable to IDACORP, Inc. |  | 280,605 |  |  | 8,569 |  |  | — |  |  | 289,174 |
Total assets |  | 8,966,968 |  |  | 350,287 |  |  | (77,892) |  |  | 9,239,363 |
Expenditures for long-lived assets |  | 1,009,138 |  |  | 141 |  |  | — |  |  | 1,009,279 |
2023 |  |  |  |  |  |  |  |
Revenues |  | $ | 1,762,894 |  |  | $ | 3,462 |  |  | $ | — |  |  | $ | 1,766,356 |
Depreciation and amortization |  | 195,341 |  |  | — |  |  | — |  |  | 195,341 |
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 |

19. OTHER INCOME AND EXPENSE
The following table presents the components of IDACORP’s other income, net and Idaho Power's other income, net (in thousands of dollars):

IDACORP |  | 2025 |  | 2024 |  | 2023
Interest and dividend income, net |  | $ | 23,872 |  |  | $ | 22,577 |  |  | $ | 15,266 |
Carrying charges on regulatory assets |  | 19,323 |  |  | 21,908 |  |  | 13,099 |
Pension and postretirement non-service costs |  | (5,986) |  |  | (8,077) |  |  | (6,513) |
Income from life insurance investments |  | 13,244 |  |  | 10,186 |  |  | 8,384 |
Other income |  | 6,769 |  |  | 8,659 |  |  | 6,286 |
Total other income, net |  | $ | 57,222 |  |  | $ | 55,253 |  |  | $ | 36,522 |
Idaho Power |  |  |  |  |  |
Interest and dividend income, net |  | $ | 16,014 |  |  | $ | 16,731 |  |  | $ | 13,410 |
Carrying charges on regulatory assets |  | 19,323 |  |  | 21,908 |  |  | 13,099 |
Pension and postretirement non-service costs |  | (5,986) |  |  | (8,077) |  |  | (6,513) |
Income from life insurance investments |  | 13,244 |  |  | 10,186 |  |  | 8,384 |
Other income |  | 6,953 |  |  | 8,962 |  |  | 6,333 |
Total other income, net |  | $ | 49,548 |  |  | $ | 49,710 |  |  | $ | 34,713 |

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20. CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME
Comprehensive income includes net income and amounts related to the SMSP. The table below presents changes in components of AOCI, net of tax, during the years ended December 31 (in thousands of dollars). Items in parentheses indicate reductions to AOCI.

|  | 2025 |  | 2024 |  | 2023
Defined benefit pension items |  |  |  |  |  |
Balance at beginning of period |  | $ | (13,592) |  |  | $ | (17,184) |  |  | $ | (12,922) |
Other comprehensive income before reclassifications, net of tax of $(374), $851, and $(1,680) |  | (2,034) |  |  | 2,454 |  |  | (4,848) |
Amounts reclassified out of AOCI to net income, net of tax of $229, $394, and $203 |  | 682 |  |  | 1,138 |  |  | 586 |
Net current-period other comprehensive income |  | (1,352) |  |  | 3,592 |  |  | (4,262) |
Balance at end of period |  | $ | (14,944) |  |  | $ | (13,592) |  |  | $ | (17,184) |

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 (in thousands of dollars). Items in parentheses indicate increases to net income.

|  | Amount Reclassified from AOCI
|  | 2025 |  | 2024 |  | 2023
Amortization of defined benefit pension items(1) |  |  |  |  |  |
Prior service cost |  | $ | 221 |  |  | $ | 220 |  |  | $ | 219 |
Net loss |  | 690 |  |  | 1,312 |  |  | 570 |
Total before tax |  | 911 |  |  | 1,532 |  |  | 789 |
Tax benefit(2) |  | (229) |  |  | (394) |  |  | (203) |
Net of tax |  | 682 |  |  | 1,138 |  |  | 586 |
Total reclassification for the period |  | $ | 682 |  |  | $ | 1,138 |  |  | $ | 586 |

(1) Amortization of these items is included in "Other (income) expense, net" in the consolidated income statements of both IDACORP and Idaho Power.
(2) The tax benefit is included in "Income tax expense" in the consolidated income statements of both IDACORP and Idaho Power.
21. RELATED PARTY TRANSACTIONS
IDACORP: Idaho Power performs corporate functions such as financial, legal, and management services for IDACORP and its subsidiaries. Idaho Power charges IDACORP for the costs of these services based on service agreements and other specifically identified costs. For these services, Idaho Power billed IDACORP $1.5 million in 2025, $1.1 million in 2024, and $1.1 million in 2023.
At December 31, 2025 and 2024, Idaho Power had a $3.3 million and $3.2 million payable to IDACORP, respectively, which was included in its accounts payable to affiliates balance on its consolidated balance sheets. 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 $9.5 million in 2025, $9.6 million in 2024, and $9.1 million in 2023 of power from Ida-West.
22. SALE OF OREGON ASSETS
On February 13, 2026, Idaho Power executed a definitive agreement to sell its Oregon electric distribution business as well as certain Oregon transmission assets to OTEC. The base purchase price to be paid by OTEC for the Oregon Sale is $154 million, and is subject to certain adjustments at the closing of the transaction. Idaho Power has agreed to operate its Oregon electric distribution business and applicable transmission assets in the ordinary course of business and subject to certain operating covenants during the period between the date of the asset purchase agreement and the completion of the proposed transaction. The Oregon Sale is subject to various closing conditions, including approvals of the OPUC, IPUC, and FERC, as well as certain
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price adjustment and termination provisions. Any gain or loss resulting from the Oregon Sale is expected to be immaterial to the consolidated financial statements of both IDACORP and Idaho Power.
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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, 2025 and 2024, the related consolidated statements of income, comprehensive income, equity, and cash flows, for each of the three years in the period ended December 31, 2025, 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, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, 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, 2025, 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 19, 2026, 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.
•We read relevant regulatory orders issued by the Commissions for Idaho Power and evaluated whether such orders were appropriately reflected in the Company's financial statements.
•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 19, 2026
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, 2025 and 2024, 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, 2025, 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, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, 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, 2025, 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 19, 2026, 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.
•We read relevant regulatory orders issued by the Commissions for the Company and evaluated whether such orders were appropriately reflected in the Company's financial statements.
•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 19, 2026
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, 2025, 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, 2025. 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, 2025, 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, 2025, 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, 2025.
February 19, 2026
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholders and the Board of Directors of IDACORP, Inc.
Opinion on Internal Control over Financial Reporting
We have audited the internal control over financial reporting of IDACORP, Inc. and subsidiaries (the “Company”) as of December 31, 2025, 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, 2025, 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, 2025, of the Company and our report dated February 19, 2026, 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 19, 2026
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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, 2025, 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, 2025. 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, 2025, 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, 2025, 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, 2025.
February 19, 2026
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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, 2025, 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, 2025, 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, 2025, of the Company and our report dated February 19, 2026, 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 19, 2026
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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, 2025, 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, 2025, none of IDACORP's or Idaho Power's directors or officers (as defined in
Rule 16a-1(f) of the Exchange Act) adopted, terminated, or modified a Rule 10b5-1 trading arrangement or non-Rule 10b5-1 trading arrangement (as such terms are defined in Item 408 of Regulation S-K).
ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS
Not applicable.
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE
The portions of IDACORP’s definitive proxy statement appearing under the captions “Proposal No. 1: Election of Directors,” “Delinquent Section 16(a) Reports,” “Board of Directors - Committees of the Board of Directors - Audit Committee,” “Corporate Governance at IDACORP - Codes of Business Conduct,” “Corporate Governance at IDACORP - Insider Trading Policy,” and "Corporate Governance at IDACORP - Certain Relationships and Related Transactions" to be filed pursuant to Regulation 14A for the 2026 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 2026 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 More than Five-Percent Shareholders” to be filed pursuant to Regulation 14A for the 2026 annual meeting of shareholders is hereby incorporated by reference. The table below includes information as of December 31, 2025, with respect to the LTICP pursuant to which equity securities of IDACORP may be issued.
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Plan Category |  | (a) Number of securities to be issued upon exercise of outstanding options, warrants and rights |  | (b) Weighted-average exercise price of outstanding options, warrants and rights |  | (c) Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) |
Equity compensation plans approved by shareholders |  | 298,732 |  | (1) | $ | — |  | (2) | 1,119,104 |  | (3)
Equity compensation plans not approved by shareholders |  | — |  |  | $ | — |  |  | — |  |
Total |  | 298,732 |  |  | $ | — |  |  | 1,119,104 |  |
(1) Represents shares subject to outstanding time-based restricted stock units, performance-based restricted stock units (at target), and deferred director stock unit awards, all under the LTICP. Such awards may be settled only for shares of common stock on a one-for-one basis.
(2) None of the outstanding awards included in column (a) have an exercise price.
(3) Shares under the LTICP may be issued in connection with stock options, stock appreciation rights, restricted stock, restricted stock units, performance units, performance shares, or other equity-based awards.

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 2026 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 2026 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 expected to be billed to Idaho Power for the fiscal years ended December 31:

|  | 2025 |  | 2024
Audit fees |  | $ | 1,906,630 |  |  | $ | 1,794,973 |
Audit-related fees(1) |  | — |  |  | — |
Tax fees(1) |  | 12,450 |  |  | — |
All other fees(2) |  | 5,445 |  |  | 4,415 |
Total |  | $ | 1,924,525 |  |  | $ | 1,799,388 |
(1) Includes fees for consultation related to tax planning and accounting.
(2) Accounting research tool subscription and fees for finance and accounting conference attendance.

Policy on Audit Committee Pre-Approval:
Idaho Power and the audit committee are committed to ensuring the independence of the independent registered public accounting firm, both in fact and in appearance. In this regard, the audit committee has established and periodically reviews a pre-approval policy for audit and non-audit services. For 2025 and 2024, 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; attest services related to financial reporting that are not required by statute or regulation, and accounting consultations and
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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, 2025, 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 | Agreement and Plan of Exchange between IDACORP, Inc. and Idaho Power Company, dated as of February 2, 1998 | S-4 | 333-48031 | A | 3/16/1998 |
3.1 | Restated Articles of Incorporation of Idaho Power Company as filed with the Secretary of State of Idaho on June 30, 1989 | S-3 Post-Effective Amend. No. 2 | 33-00440* | 4(a)(xiii) | 6/30/1989 |

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|  | Incorporated by Reference |
Exhibit No. | Exhibit Description | Form | File No. | Exhibit No. | Date | Included Herewith
3.2 | Statement of Resolution Establishing Terms of Flexible Auction Series A, Serial Preferred Stock, Without Par Value (cumulative stated value of $100,000 per share) of Idaho Power Company, as filed with the Secretary of State of Idaho on November 5, 1991 | S-3 | 33-65720* | 4(a)(ii) | 7/7/1993 |
3.3 | Statement of Resolution Establishing Terms of 7.07% Serial Preferred Stock, Without Par Value (cumulative stated value of $100 per share) of Idaho Power Company, as filed with the Secretary of State of Idaho on June 30, 1993 | S-3 | 33-65720* | 4(a)(iii) | 7/7/1993 |
3.4 | Articles of Share Exchange, as filed with the Secretary of State of Idaho on September 29, 1998 | S-8 Post-Effective Amend. No. 1 | 33-56071-99 | 3(d) | 10/1/1998 |
3.5 | Articles of Amendment to Restated Articles of Incorporation of Idaho Power Company, as filed with the Secretary of State of Idaho on June 15, 2000 | 10-Q | 1-3198 | 3(a)(iii) | 8/4/2000 |
3.6 | Articles of Amendment to Restated Articles of Incorporation of Idaho Power Company, as filed with the Secretary of State of Idaho on January 21, 2005 | 8-K | 1-3198 | 3.3 | 1/26/2005 |
3.7 | Articles of Amendment to Restated Articles of Incorporation of Idaho Power Company, as amended, as filed with the Secretary of State of Idaho on November 19, 2007 | 8-K | 1-3198 | 3.3 | 11/19/2007 |
3.8 | Articles of Amendment to Restated Articles of Incorporation of Idaho Power Company, as amended, as filed with the Secretary of State of Idaho on May 18, 2012 | 8-K | 1-3198 | 3.14 | 5/21/2012 |
3.9 | Amended Bylaws of Idaho Power Company, amended on November 15, 2007 and presently in effect | 8-K | 1-3198 | 3.2 | 11/19/2007 |
3.10 | Articles of Incorporation of IDACORP, Inc. | S-3 Amend. No. 1 | 333-64737 | 3.1 | 11/4/1998 |
3.11 | Articles of Amendment to Articles of Incorporation of IDACORP, Inc. as filed with the Secretary of State of Idaho on March 9, 1998 | S-3 Amend. No. 1 | 333-64737 | 3.2 | 11/4/1998 |
3.12 | Articles of Amendment to Articles of Incorporation of IDACORP, Inc. creating A Series Preferred Stock, without par value, as filed with the Secretary of State of Idaho on September 17, 1998 | S-3 Post-Effective Amend. No. 1 | 333-00139-99 | 3(b) | 9/22/1998 |
3.13 | Articles of Amendment to Articles of Incorporation of IDACORP, Inc., as amended, as filed with the Secretary of State of Idaho on May 18, 2012 | 8-K | 1-14465 | 3.13 | 5/21/2012 |
3.14 | Amended and Restated Bylaws of IDACORP, Inc., effective as of November 16, 2023 and presently in effect | 8-K | 1-14465, 1-3198 | 3.1 | 11/22/2023 |
4.1 | Mortgage and Deed of Trust, dated as of October 1, 1937, between Idaho Power Company and Deutsche Bank Trust Company Americas (formerly known as Bankers Trust Company) and R. G. Page, as Trustees |  | 2-3413* | B-2 |  |
| Idaho Power Company Supplemental Indentures to Mortgage and Deed of Trust: |  |  |  |  |
4.2.1 | File number 1-MD, as Exhibit B-2-a, First, July 1, 1939*
4.2.2 | File number 2-5395, as Exhibit 7-a-3, Second, November 15, 1943*
4.2.3 | File number 2-7237, as Exhibit 7-a-4, Third, February 1, 1947*
4.2.4 | File number 2-7502, as Exhibit 7-a-5, Fourth, May 1, 1948*
4.2.5 | File number 2-8398, as Exhibit 7-a-6, Fifth, November 1, 1949*
4.2.6 | File number 2-8973, as Exhibit 7-a-7, Sixth, October 1, 1951*
4.2.7 | File number 2-12941, as Exhibit 2-C-8, Seventh, January 1, 1957*
4.2.8 | File number 2-13688, as Exhibit 4-J, Eighth, July 15, 1957*
4.2.9 | File number 2-13689, as Exhibit 4-K, Ninth, November 15, 1957*
4.2.10 | File number 2-14245, as Exhibit 4-L, Tenth, April 1, 1958*
4.2.11 | File number 2-14366, as Exhibit 2-L, Eleventh, October 15, 1958*
4.2.12 | File number 2-14935, as Exhibit 4-N, Twelfth, May 15, 1959*
4.2.13 | File number 2-18976, as Exhibit 4-O, Thirteenth, November 15, 1960*

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|  | Incorporated by Reference |
Exhibit No. | Exhibit Description | Form | File No. | Exhibit No. | Date | Included Herewith
4.2.14 | File number 2-18977, as Exhibit 4-Q, Fourteenth, November 1, 1961*
4.2.15 | File number 2-22988, as Exhibit 4-B-16, Fifteenth, September 15, 1964*
4.2.16 | File number 2-24578, as Exhibit 4-B-17, Sixteenth, April 1, 1966*
4.2.17 | File number 2-25479, as Exhibit 4-B-18, Seventeenth, October 1, 1966*
4.2.18 | File number 2-45260, as Exhibit 2(c), Eighteenth, September 1, 1972*
4.2.19 | File number 2-49854, as Exhibit 2(c), Nineteenth, January 15, 1974*
4.2.20 | File number 2-51722, as Exhibit 2(c)(i), Twentieth, August 1, 1974*
4.2.21 | File number 2-51722, as Exhibit 2(c)(ii), Twenty-first, October 15, 1974*
4.2.22 | File number 2-57374, as Exhibit 2(c), Twenty-second, November 15, 1976*
4.2.23 | File number 2-62035, as Exhibit 2(c), Twenty-third, August 15, 1978*
4.2.24 | File number 33-34222, as Exhibit 4(d)(iii), Twenty-fourth, September 1, 1979*
4.2.25 | File number 33-34222, as Exhibit 4(d)(iv), Twenty-fifth, November 1, 1981*
4.2.26 | File number 33-34222, as Exhibit 4(d)(v), Twenty-sixth, May 1, 1982*
4.2.27 | File number 33-34222, as Exhibit 4(d)(vi), Twenty-seventh, May 1, 1986*
4.2.28 | File number 33-00440, as Exhibit 4(c)(iv), Twenty-eighth, June 30, 1989*
4.2.29 | File number 33-34222, as Exhibit 4(d)(vii), Twenty-ninth, January 1, 1990*
4.2.30 | File number 33-65720, as Exhibit 4(d)(iii), Thirtieth, January 1, 1991*
4.2.31 | File number 33-65720, as Exhibit 4(d)(iv), Thirty-first, August 15, 1991*
4.2.32 | File number 33-65720, as Exhibit 4(d)(v), Thirty-second, March 15, 1992*
4.2.33 | File number 33-65720, as Exhibit 4(d)(vi), Thirty-third, April 1, 1993*
4.2.34 | File number 1-3198, Form 8-K, filed on 12/20/93, as Exhibit 4, Thirty-fourth, December 1, 1993*
4.2.35 | Thirty-fifth, November 1, 2000 | 8-K | 1-3198 | 4 | 11/21/2000 |
4.2.36 | Thirty-sixth, October 1, 2001 | 8-K | 1-3198 | 4 | 10/1/2001 |
4.2.37 | Thirty-seventh, April 1, 2003 | 8-K | 1-3198 | 4 | 4/16/2003 |
4.2.38 | Thirty-eighth, May 15, 2003 | 10-Q | 1-3198 | 4(a)(iii) | 8/7/2003 |
4.2.39 | Thirty-ninth, October 1, 2003 | 10-Q | 1-3198 | 4(a)(iv) | 11/6/2003 |
4.2.40 | Fortieth, May 1, 2005 | 8-K | 1-3198 | 4 | 5/10/2005 |
4.2.41 | Forty-first, October 1, 2006 | 8-K | 1-3198 | 4 | 10/10/2006 |
4.2.42 | Forty-second, May 1, 2007 | 8-K | 1-3198 | 4 | 6/4/2007 |
4.2.43 | Forty-third, September 1, 2007 | 8-K | 1-3198 | 4 | 9/26/2007 |
4.2.44 | Forty-fourth, April 1, 2008 | 8-K | 1-3198 | 4 | 4/3/2008 |
4.2.45 | Forty-fifth, February 1, 2010 | 10-K | 1-3198 | 4.10 | 2/23/2010 |
4.2.46 | Forty-sixth, June 1, 2010 | 8-K | 1-3198 | 4 | 6/18/2010 |
4.2.47 | Forty-seventh, July 1, 2013 | 8-K | 1-3198 | 4.1 | 7/12/2013 |
4.2.48 | Forty-eighth, September 1, 2016 | 8-K | 1-3198 | 4.1 | 9/27/2016 |
4.2.49 | Forty-ninth, June 5, 2020 | 8-K | 1-3198 | 4.1 | 6/8/2020 |
4.2.50 | Fiftieth, June 30, 2022 | 8-K | 1-3198 | 4.1 | 6/30/2022 |
4.2.51 | Fifty-first, October 14, 2022 | 10-Q | 1-3198 | 4.1 | 11/3/2022 |
4.2.52 | Fifty-second, December 20, 2022 | 8-K | 1-3198 | 4.1 | 12/22/2022 |
4.2.53 | Fifty-third, February 26, 2025 | 8-K | 1-3198 | 4.1 | 2/26/2025 |
4.3 | Agreement of Idaho Power Company to furnish certain debt instruments | S-3 | 33-65720* | 4(f) | 7/7/1993 |
4.4 | Agreement and Plan of Merger dated March 10, 1989, between Idaho Power Company, a Maine corporation, and Idaho Power Migrating Corporation | S-3 Post-Effective Amend. No. 2 | 33-00440* | 2(a)(iii) | 6/30/1989 |
4.5 | Indenture for Senior Debt Securities dated as of February 1, 2001, between IDACORP, Inc. and Deutsche Bank Trust Company Americas (formerly known as Bankers Trust Company), as trustee | 8-K | 1-14465 | 4.1 | 2/28/2001 |
4.6 | First Supplemental Indenture dated as of February 1, 2001 to Indenture for Senior Debt Securities dated as of February 1, 2001 between IDACORP, Inc. and Deutsche Bank Trust Company Americas (formerly known as Bankers Trust Company), as trustee | 8-K | 1-14465 | 4.2 | 2/28/2001 |

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|  | Incorporated by Reference |
Exhibit No. | Exhibit Description | Form | File No. | Exhibit No. | Date | Included Herewith
4.7 | Indenture for Debt Securities dated as of August 1, 2001 between Idaho Power Company and Deutsche Bank Trust Company Americas (formerly known as Bankers Trust Company), as trustee | S-3 | 333-67748 | 4.13 | 8/16/2001 |
4.8 | Idaho Power Company Instrument of Further Assurance relating to Mortgage and Deed of Trust, dated as of August 3, 2010 | 10-Q | 1-3198 | 4.12 | 8/5/2010 |
4.9 | Description of the Registrant's Securities | 10-K | 1-14465, 1-3198 | 4.10 | 2/15/2024 |
10.1 | Amended and Restated Agreement for the Operation of the Jim Bridger Project, dated December 11, 2014, between Idaho Power Company and PacifiCorp | 10-K | 1-14465, 1-3198 | 10.4 | 2/19/2015 |
10.2 | Amended and Restated Agreement for the Ownership of the Jim Bridger Project, dated December 11, 2014, between Idaho Power Company and PacifiCorp | 10-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 | Settlement Agreement, dated March 25, 2009, between the State of Idaho and Idaho Power Company relating to the agreement filed as Exhibit 10.3 | 10-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 | Credit Agreement, dated December 8, 2023, among IDACORP, Inc., Wells Fargo Bank, National Association, as administrative agent, swingline lender, and LC issuer, JPMorgan Chase Bank, N.A., as syndication agent and LC issuer, and the other lenders named therein | 8-K | 1-14465, 1-3198 | 10.1 | 12/11/2023 |
10.9 | Extension Agreement, dated December 9, 2024, among IDACORP, Inc., Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto | 10-K | 1-14465, 1-3198 | 10.9 | 2/20/2025 |
10.10 | Extension and First Amendment to Credit Agreement, dated December 8, 2025, among IDACORP, Inc., Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto |  |  |  |  | X
10.11 | Credit Agreement, dated December 8, 2023, among Idaho Power Company, Wells Fargo Bank, National Association, as administrative agent, swingline lender, and LC issuer, JPMorgan Chase Bank, N.A., as syndication agent and LC issuer, and the other lenders named therein | 8-K | 1-14465, 1-3198 | 10.2 | 12/11/2023 |
10.12 | Extension Agreement, dated December 9, 2024, among Idaho Power Company, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto | 10-K | 1-14465, 1-3198 | 10.11 | 2/20/2025 |
10.13 | Extension and First Amendment to Credit Agreement, dated December 8, 2025, among Idaho Power Company, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto |  |  |  |  | X
10.14 | Forward Sale Agreement between IDACORP, Inc. and Morgan Stanley & Co. LLC dated as of May 8, 2025 | 8-K | 1-14465 | 10.1 | 5/12/2025 |
10.15 | Forward Sale Agreement between IDACORP, Inc. and JPMorgan Chase Bank, National Association, New York Branch dated as of May 8, 2025 | 8-K | 1-14465 | 10.2 | 5/12/2025 |
10.16 | Forward Sale Agreement between IDACORP, Inc. and Wells Fargo Bank, National Association dated as of May 8, 2025 | 8-K | 1-14465 | 10.3 | 5/12/2025 |

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|  | Incorporated by Reference |
Exhibit No. | Exhibit Description | Form | File No. | Exhibit No. | Date | Included Herewith
10.17 | Additional Forward Sale Agreement between IDACORP, Inc. and Morgan Stanley & Co. LLC dated as of May 9, 2025 | 8-K | 1-14465 | 10.4 | 5/12/2025 |
10.18 | Additional Forward Sale Agreement between IDACORP, Inc. and JPMorgan Chase Bank, National Association, New York Branch dated as of May 9, 2025 | 8-K | 1-14465 | 10.5 | 5/12/2025 |
10.19 | Additional Forward Sale Agreement between IDACORP, Inc. and Wells Fargo Bank, National Association dated as of May 9, 2025 | 8-K | 1-14465 | 10.6 | 5/12/2025 |
10.20 | Equity Distribution Agreement, dated May 20, 2024 | 8-K | 1-14465, 1-3198 | 1.1 | 5/20/2024 |
10.21 | Form of Master Forward Sale Confirmation | 8-K | 1-14465, 1-3198 | 1.2 | 5/20/2024 |
10.22 | Loan Agreement, dated October 1, 2006, between Sweetwater County, Wyoming and Idaho Power Company | 8-K | 1-3198 | 10.1 | 10/10/2006 |
10.23 1 | Idaho Power Company Security Plan for Senior Management Employees I, amended and restated effective December 31, 2004, and as further amended November 20, 2008 | 10-K | 1-14465, 1-3198 | 10.15 | 2/26/2009 |
10.24 1 | Amendment, dated September 19, 2012, to the Idaho Power Company Security Plan for Senior Management Employees I | 10-Q | 1-14465, 1-3198 | 10.62 | 11/1/2012 |
10.25 1 | Idaho Power Company Security Plan for Senior Management Employees II, as amended and restated February 8, 2017 | 10-K | 1-14465, 1-3198 | 10.31 | 2/23/2017 |
10.26 1 | Amendment to the Idaho Power Company Security Plan for Senior Management Employees II, as amended May 17, 2017 | 10-Q | 1-14465, 1-3198 | 10.1 | 8/3/2017 |
10.27 1 | Idaho Power Company Security Plan for Board of Directors - a non-qualified deferred compensation plan, as amended and restated effective July 20, 2006 | 10-Q | 1-14465, 1-3198 | 10(h)(viii) | 11/2/2006 |
10.28 1 | IDACORP, Inc. Non-Employee Directors Stock Compensation Plan, as amended | 10-Q | 1-14465, 1-3198 | 10.1 | 10/30/2025 |
10.29 1 | Form of Officer Indemnification Agreement between IDACORP, Inc. and Officers of IDACORP, Inc. and Idaho Power Company, as amended July 20, 2006 | 10-Q | 1-14465, 1-3198 | 10(h)(xix) | 11/2/2006 |
10.30 1 | Form of Director Indemnification Agreement between IDACORP, Inc. and Directors of IDACORP, Inc., as amended July 20, 2006 | 10-Q | 1-14465, 1-3198 | 10(h)(xx) | 11/2/2006 |
10.31 1 | Form of Amended and Restated Change in Control Agreement between IDACORP, Inc. and Officers of IDACORP and Idaho Power Company (senior vice president and higher), approved November 20, 2008 | 10-K | 1-14465, 1-3198 | 10.24 | 2/26/2009 |
10.32 1 | Form of Amended and Restated Change in Control Agreement between IDACORP, Inc. and Officers of IDACORP and Idaho Power Company (below senior vice president), approved November 20, 2008 | 10-K | 1-14465, 1-3198 | 10.25 | 2/26/2009 |
10.33 1 | Form of Amended and Restated Change in Control Agreement between IDACORP, Inc. and Officers of IDACORP, Inc. and Idaho Power Company, approved March 17, 2010 | 8-K | 1-14465, 1-3198 | 10.1 | 3/24/2010 |
10.34 1 | IDACORP, Inc. and/or Idaho Power Company Executive Officers with Amended and Restated Change in Control Agreements chart |  |  |  |  | X
10.35 1 | IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan, as amended and restated M ay 15, 2025 | 14A | 1-14465 | App. A | 4/1/2025 |
10.36 1 | IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan - Form of Restricted Unit Award Agreement (Time Vesting) | 10-K | 1-14465, 1-3198 | 10.27 | 2/15/2024 |
10.37 1 | IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan - Form of Performance Unit Award Agreement (Performance with Total Shareholder Return Goal) | 10-K | 1-14465, 1-3198 | 10.28 | 2/15/2024 |
10.38 1 | IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan - Form of Performance Unit Award Agreement (Performance with Cumulative Earnings Per Share Goal) | 10-K | 1-14465, 1-3198 | 10.29 | 2/15/2024 |
10.39 1 | IDACORP, Inc. Executive Incentive Plan, as amended and restated November 14, 2018 | 10-K | 1-14465, 1-3198 | 10.36 | 2/21/2019 |

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|  | Incorporated by Reference |
Exhibit No. | Exhibit Description | Form | File No. | Exhibit No. | Date | Included Herewith
10.40 1 | Idaho Power Company Executive Deferred Compensation Plan, effective November 15, 2000, as amended November 20, 2008 | 10-K | 1-14465, 1-3198 | 10.32 | 2/26/2009 |
10.41 1 | IDACORP, Inc. and Idaho Power Company Compensation for Non-Employee Directors of the Board of Directors, effective January 1, 2024 | 10-K | 1-14465, 1-3198 | 10.33 | 2/20/2025 |
10.42 1 | Form of IDACORP, Inc. Director Deferred Compensation Agreement, as amended November 20, 2008 | 10-K | 1-14465, 1-3198 | 10.46 | 2/26/2009 |
10.43 1 | Form of Amendment to IDACORP, Inc. Director Deferred Compensation Agreement, as amended November 20, 2008 | 10-K | 1-14465, 1-3198 | 10.48 | 2/26/2009 |
10.44 1 | Form of Termination of IDACORP, Inc. Director Deferred Compensation Agreement, as amended November 20, 2008 | 10-K | 1-14465, 1-3198 | 10.49 | 2/26/2009 |
10.45 1 | Form of Idaho Power Company Director Deferred Compensation Agreement, as amended November 20, 2008 | 10-K | 1-14465, 1-3198 | 10.50 | 2/26/2009 |
10.46 1 | Form of Amendment to Idaho Power Company Director Deferred Compensation Agreement, as amended November 20, 2008 | 10-K | 1-14465, 1-3198 | 10.52 | 2/26/2009 |
10.47 1 | Form of Termination of Idaho Power Company Director Deferred Compensation Agreement, as amended November 20, 2008 | 10-K | 1-14465, 1-3198 | 10.53 | 2/26/2009 |
10.48 1 | Idaho Power Company Restated Employee Savings Plan, as restated as of January 1, 2016 | 10-K | 1-14465, 1-3198 | 10.59 | 2/18/2016 |
10.49 1 | First Amendment, dated effective December 1, 2016, to the Idaho Power Company Restated Employee Savings Plan, as restated as of January 1, 2016 | 10-K | 1-14465, 1-3198 | 10.61 | 2/23/2017 |
10.50 1 | Second Amendment to the Idaho Power Company Employee Savings Plan, as amended January 1, 2018 | 10-Q | 1-14465, 1-3198 | 10.1 | 11/2/2017 |
10.51 1 | Third Amendment to the Idaho Power Company Employee Savings Plan, as amended April 26, 2018 | 10-Q | 1-14465, 1-3198 | 10.4 | 5/3/2018 |
10.52 1 | Fourth Amendment to the Idaho Power Company Employee Savings Plan, executed October 24, 2019 and effective January 1, 2020 | 10-Q | 1-14465, 1-3198 | 10.1 | 10/31/2019 |
10.53 1 | Fifth Amendment to the Idaho Power Company Employee Savings Plan, executed December 21, 2020 and effective January 1, 2020 | 10-K | 1-14465, 1-3198 | 10.49 | 2/18/2021 |
10.54 1 | Sixth Amendment to the Idaho Power Company Employee Savings Plan, executed March 7, 2022 and effective January 1, 2020 | 10-Q | 1-14465, 1-3198 | 10.1 | 5/5/2022 |
10.55 1 | Seventh Amendment to the Idaho Power Company Employee Savings Plan, executed May 16, 2024 and effective April 1, 2024 | 10-Q | 1-14465, 1-3198 | 10.1 | 8/1/2024 |
10.56 1 | Eighth Amendment to the Idaho Power Company Employee Savings Plan, executed December 2, 2024 and effective January 1, 2025 | 10-Q | 1-14465, 1-3198 | 10.2 | 5/1/2025 |
19.1 | IDACORP, Inc. Insider Trading and Transactions in Company Securities Standard |  |  |  |  | X
21.1 | Subsidiaries of IDACORP, Inc. |  |  |  |  | X
23.1 | Consent of Registered Independent Accounting Firm |  |  |  |  | X
23.2 | Consent of Registered Independent Accounting Firm |  |  |  |  | X
31.1 | IDACORP, Inc. Rule 13a-14(a) CEO certification |  |  |  |  | X
31.2 | IDACORP, Inc. Rule 13a-14(a) CFO certification |  |  |  |  | X
31.3 | Idaho Power Rule 13a-14(a) CEO certification |  |  |  |  | X
31.4 | Idaho Power Rule 13a-14(a) CFO certification |  |  |  |  | X
32.1 | IDACORP, Inc. Section 1350 CEO certification |  |  |  |  | X
32.2 | IDACORP, Inc. Section 1350 CFO certification |  |  |  |  | X
32.3 | Idaho Power Section 1350 CEO certification |  |  |  |  | X
32.4 | Idaho Power Section 1350 CFO certification |  |  |  |  | X
95.1 | Mine Safety Disclosures |  |  |  |  | X

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|  | Incorporated by Reference |
Exhibit No. | Exhibit Description | Form | File No. | Exhibit No. | Date | Included Herewith
97.1 | IDACORP, Inc. Incentive Compensation Recovery Policy | 10-K | 1-14465, 1-3198 | 97.1 | 2/15/2024 |
101.SCH | Inline XBRL Taxonomy Extension Schema Document |  |  |  |  | X
101.CAL | Inline XBRL Taxonomy Extension Calculation Linkbase Document |  |  |  |  | X
101.LAB | Inline XBRL Taxonomy Extension Label Linkbase Document |  |  |  |  | X
101.PRE | Inline XBRL Taxonomy Extension Presentation Linkbase Document |  |  |  |  | X
101.DEF | Inline XBRL Taxonomy Extension Definition Linkbase Document |  |  |  |  | X
104 | Cover Page Interactive Data File (formatted as inline XBRL with applicable taxonomy extension information contained in Exhibits 101.) |  |  |  |  | X
* Exhibit originally filed with the SEC in paper format and as such, a hyperlink is not available.
(1) Management contract or compensatory plan or arrangement

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

|  | Year Ended December 31,
|  | 2025 |  | 2024 |  | 2023
|  | (thousands of dollars)
Income: |  |  |  |  |  |
Equity in income of subsidiaries |  | $ | 321,927 |  |  | $ | 289,689 |  |  | $ | 262,081 |
Investment income |  | 7,539 |  |  | 3,976 |  |  | 1,932 |
Total income |  | 329,466 |  |  | 293,665 |  |  | 264,013 |
Expenses: |  |  |  |  |  |
Operating expenses |  | 930 |  |  | 621 |  |  | 553 |
Interest expense |  | 3,307 |  |  | 3,593 |  |  | 3,171 |
Other expenses |  | 2,000 |  |  | 1,300 |  |  | 200 |
Total expenses |  | 6,237 |  |  | 5,514 |  |  | 3,924 |
Income Before Income Taxes |  | 323,229 |  |  | 288,151 |  |  | 260,089 |
Income Tax Benefit |  | (243) |  |  | (1,023) |  |  | (1,106) |
Net Income Attributable to IDACORP, Inc. |  | 323,472 |  |  | 289,174 |  |  | 261,195 |
Other comprehensive (loss) income |  | (1,352) |  |  | 3,592 |  |  | (4,262) |
Comprehensive Income Attributable to IDACORP, Inc. |  | $ | 322,120 |  |  | $ | 292,766 |  |  | $ | 256,933 |
The accompanying note is an integral part of these statements.

IDACORP, INC.
CONDENSED STATEMENTS OF CASH FLOWS

|  | Year Ended December 31,
|  | 2025 |  | 2024 |  | 2023
|  | (thousands of dollars)
Operating Activities: |  |  |  |  |  |
Net cash provided by operating activities |  | $ | 215,505 |  |  | $ | 194,597 |  |  | $ | 154,190 |
Investing Activities: |  |  |  |  |  |
Contributions to subsidiaries |  | (195,000) |  |  | (200,000) |  |  | — |
Purchase of investments |  | (2,419) |  |  | (651) |  |  | (1,002) |
Maturities of investments |  | 385 |  |  | — |  |  | — |
Net cash used in investing activities |  | (197,034) |  |  | (200,651) |  |  | (1,002) |
Financing Activities: |  |  |  |  |  |
Issuance of common stock |  | 97,777 |  |  | 298,450 |  |  | — |
Dividends on common stock |  | (187,633) |  |  | (175,615) |  |  | (162,646) |
Change in intercompany notes payable |  | (7,952) |  |  | 11,430 |  |  | (282) |
Other |  | (3,625) |  |  | (4,015) |  |  | (3,533) |
Net cash (used in) provided by financing activities |  | (101,433) |  |  | 130,250 |  |  | (166,461) |
Net (decrease) increase in cash and cash equivalents |  | (82,962) |  |  | 124,196 |  |  | (13,273) |
Cash and cash equivalents at beginning of year |  | 178,094 |  |  | 53,898 |  |  | 67,171 |
Cash and cash equivalents at end of year |  | $ | 95,132 |  |  | $ | 178,094 |  |  | $ | 53,898 |
The accompanying note is an integral part of these statements.

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IDACORP, INC.
CONDENSED BALANCE SHEETS

|  | December 31,
|  | 2025 |  | 2024
Assets |  | (thousands of dollars)
Current Assets: |  |  |  |
Cash and cash equivalents |  | $ | 95,132 |  |  | $ | 178,094 |
Receivables |  | 1,923 |  |  | 2,646 |
Income taxes receivable |  | 7,091 |  |  | 2,350 |
Other |  | 103 |  |  | 107 |
Total current assets |  | 104,249 |  |  | 183,197 |
Investments |  | 3,534,519 |  |  | 3,210,209 |
Other Assets: |  |  |  |
Deferred income taxes |  | 2,363 |  |  | 11,829 |
Other |  | 381 |  |  | 397 |
Total other assets |  | 2,744 |  |  | 12,226 |
Total assets |  | $ | 3,641,512 |  |  | $ | 3,405,632 |
Liabilities and Shareholders’ Equity |  |  |  |
Noncurrent Liabilities: |  |  |  |
Intercompany notes payable |  | $ | 69,291 |  |  | $ | 74,272 |
Other |  | 347 |  |  | 406 |
Total noncurrent liabilities |  | 69,638 |  |  | 74,678 |
IDACORP, Inc. Shareholders’ Equity |  | 3,571,874 |  |  | 3,330,954 |
Total Liabilities and Shareholders' Equity |  | $ | 3,641,512 |  |  | $ | 3,405,632 |
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 2025 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 $193 million, $177 million, and $105 million in 2025, 2024, and 2023, respectively.
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IDACORP, INC. AND IDAHO POWER COMPANY
SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31, 2025, 2024, and 2023

|  |  |  | 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)
2025: |  |  |  |  |  |  |  |  |  |
Reserve for uncollectible accounts |  | $ | 5,699 |  |  | $ | 3,009 |  |  | $ | 471 |  |  | $ | 4,754 |  |  | $ | 4,425 |
Injuries and damages |  | 3,627 |  |  | 799 |  |  | — |  |  | 1,473 |  |  | 2,953 |
2024: |  |  |  |  |  |  |  |  |  |
Reserve for uncollectible accounts |  | $ | 5,585 |  |  | $ | 4,523 |  |  | $ | 1,302 |  |  | $ | 5,711 |  |  | $ | 5,699 |
Injuries and damages |  | 3,275 |  |  | 992 |  |  | — |  |  | 640 |  |  | 3,627 |
2023: |  |  |  |  |  |  |  |  |  |
Reserve for uncollectible accounts |  | $ | 5,546 |  |  | $ | 3,527 |  |  | $ | 975 |  |  | $ | 4,463 |  |  | $ | 5,585 |
Injuries and damages |  | 2,802 |  |  | 974 |  |  | — |  |  | 501 |  |  | 3,275 |

(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.
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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 19, 2026 |  | 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/ Dennis L. Johnson |  | Chair of the Board |  | February 19, 2026
Dennis L. Johnson |  |  |  |
/s/ Lisa A. Grow |  | (Principal Executive Officer) |  | February 19, 2026
Lisa A. Grow |  |  |  |
President and Chief Executive Officer and Director |  |  |  |
/s/ Brian R. Buckham |  | (Principal Financial Officer) |  | February 19, 2026
Brian R. Buckham |  |  |  |
Executive Vice President, Chief Financial Officer, and Treasurer |  |  |  |
/s/ Amy I. Shaw |  | (Principal Accounting Officer) |  | February 19, 2026
Amy I. Shaw |  |  |  |
Vice President of Finance, Compliance, and Risk |  |  |  |
/s/ Odette C. Bolano |  | Director |  | February 19, 2026
Odette C. Bolano |  |  |  |
/s/ Annette G. Elg |  | Director |  | February 19, 2026
Annette G. Elg |  |  |  |
/s/ Nate R. Jorgensen |  | Director |  | February 19, 2026
Nate R. Jorgensen |  |  |  |
/s/ Michael J. Kennedy |  | Director |  | February 19, 2026
Michael J. Kennedy |  |  |  |
/s/ Scott W. Madison |  | Director |  | February 19, 2026
Scott W. Madison |  |  |  |
/s/ Susan D. Morris |  | Director |  | February 19, 2026
Susan D. Morris |  |  |  |
/s/ Dr. Mark T. Peters |  | Director |  | February 19, 2026
Dr. Mark T. Peters |  |  |  |

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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 19, 2026 |  | 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/ Dennis L. Johnson |  | Chair of the Board |  | February 19, 2026
Dennis L. Johnson |  |  |  |
/s/ Lisa A. Grow |  | (Principal Executive Officer) |  | February 19, 2026
Lisa A. Grow |  |  |  |
President and Chief Executive Officer and Director |  |  |  |
/s/ Brian R. Buckham |  | (Principal Financial Officer) |  | February 19, 2026
Brian R. Buckham |  |  |  |
Executive Vice President, Chief Financial Officer, and Treasurer |  |  |  |
/s/ Amy I. Shaw |  |  | (Principal Accounting Officer) |  | February 19, 2026
Amy I. Shaw |  |  |  |  |  |  |
Vice President of Finance, Compliance, and Risk |  |  |  |  |  |  |
/s/ Odette C. Bolano |  | Director |  | February 19, 2026
Odette C. Bolano |  |  |  |
/s/ Annette G. Elg |  | Director |  | February 19, 2026
Annette G. Elg |  |  |  |
/s/ Nate R. Jorgensen |  | Director |  | February 19, 2026
Nate R. Jorgensen |  |  |  |
/s/ Michael J. Kennedy |  | Director |  | February 19, 2026
Michael J. Kennedy |  |  |  |
/s/ Scott W. Madison |  | Director |  | February 19, 2026
Scott W. Madison |  |  |  |
/s/ Susan D. Morris |  | Director |  | February 19, 2026
Susan D. Morris |  |  |  |
/s/ Dr. Mark T. Peters |  | Director |  | February 19, 2026
Dr. Mark T. Peters |  |  |  |

156